Note: Descriptions are shown in the official language in which they were submitted.
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
ELECTRICALLY CONDUCTIVE METHODS FOR HEATING
A SUBSURFACE FORMATION TO CONVERT
ORGANIC MATTER INTO HYDROCARBON FLUIDS
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional Patent
Application 61/109,
369 filed 29-Oct-2008 entitled ELECTRICALLY CONDUCTIVE METHODS FOR
HEATING A SUBSURFACE FORMATION TO CONVERT ORGANIC MATTER INTO
HYDROCARBON FLUIDS, the entirety of which is incorporated by reference herein.
BACKGROUND
Technical Field
[0002] The present invention relates to the field of hydrocarbon recovery from
subsurface
formations. More specifically, the present invention relates to the in situ
recovery of
hydrocarbon fluids from organic-rich rock formations including, for example,
oil shale
formations, coal formations and tar sands formations. The present invention
also relates to
methods for heating a subsurface formation using electrical energy. This
application relates
to pending U.S. non-provisional patent Application No. 12/074,899, attorney
Docket Number
2007EM026, which was filed on March 7, 2008 and which is entitled "Granular
Electrical
Connections for In Situ Formation Heating" and is incorporated herein in its
entirety by
reference. U.S. Application No. 12/074,899 in turn claims the benefit of
pending U.S.
provisional patent Application No. 60/919,391, which was filed on March 22,
2007, which is
also entitled "Granular Electrical Connections for In Situ Formation Heating,"
and is
incorporated herein in its entirety by reference.
Discussion of Technolory
[0003] Certain geological formations are known to contain an organic matter
known as
"kerogen." Kerogen is a solid, carbonaceous material. When kerogen is imbedded
in rock
formations, the mixture is 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.
[0004] Kerogen is subject to decomposing upon exposure to heat over a period
of time.
Upon heating, kerogen molecularly decomposes to produce oil, gas, and
carbonaceous coke.
-1-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
Small amounts of water may also be generated. The oil, gas and water fluids
become mobile
within the rock matrix, while the carbonaceous coke remains essentially
immobile.
[0005] Oil shale formations are found in various areas world-wide, including
the United
States. Such formations are notably found in Wyoming, Colorado, and Utah. Oil
shale
formations tend to reside at relatively shallow depths and are often
characterized by limited
permeability. Some consider oil shale formations to be hydrocarbon deposits
which have not
yet experienced the years of heat and pressure thought to be required to
create conventional
oil and gas reserves.
[0006] The decomposition rate of kerogen to produce mobile hydrocarbons is
temperature dependent. Temperatures generally in excess of 270 C (518 F)
over the course
of many months may be required for substantial conversion. At higher
temperatures
substantial conversion may occur within shorter times. When kerogen is heated
to the
necessary temperature, 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 through surface mining has been
conducted in other
countries as well. Such countries include Australia, Brazil, China, Estonia,
France, Russia,
South Africa, Spain, and Sweden. However, the practice has been mostly
discontinued in
recent years because it has proven to be uneconomical or because of
environmental
constraints on spent shale disposal. (See 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 that
particular application to very shallow formations.
[0008] In the United States, the existence of oil shale deposits in
northwestern Colorado
has been known since the early 1900's. While research projects have been
conducted in this
area from time to time, no serious commercial development has been undertaken.
Most
research on oil shale production has been carried out in the latter half of
the 1900's. The
majority of this research was on shale oil geology, geochemistry, and
retorting in surface
facilities.
-2-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0009] In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom. 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. The
purpose of such in situ heating was to distill hydrocarbons and produce them
to the surface.
The `195 Ljungstrom patent is incorporated herein by reference.
[0010] 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 early
heat injection wells. The electrical heating elements in the heat injection
wells were placed
within sand or cement or other heat-conductive material to permit the heat
injection wells to
transmit heat into the surrounding oil shale while preventing the inflow of
fluid. According
to Ljungstrom, the "aggregate" was heated to between 5000 and 1,0000 C in some
applications.
[0011] 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
producing wells.
[0012] 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. (See G. Salamonsson, "The Ljungstrom In Situ Method
for Shale-
Oil Recovery," 2d 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.)
[0013] Additional in situ methods have been proposed. These methods generally
involve
the injection of heat and/or solvent into a subsurface oil shale formation.
Heat may be in the
form of heated methane (see U.S. Pat. No. 3,241,611 to J.L. Dougan), flue gas,
or
superheated steam (see U.S. Pat. No. 3,400,762 to D.W. Peacock). Heat may also
be in the
form of electric resistive heating, dielectric heating, radio frequency (RF)
heating (U.S. Pat.
No. 4,140,180, assigned to the ITT Research Institute in Chicago, Illinois) or
oxidant
injection to support in situ combustion. In some instances, artificial
permeability has been
created in the matrix to aid the movement of pyrolyzed fluids. Permeability
generation
methods include mining, rubblization, hydraulic fracturing (see U.S. Pat. No.
3,468,376 to
-3-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
M.L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel), explosive fracturing
(see U.S. Pat.
No. 1,422,204 to W. W. Hoover, et al.), heat fracturing (see U.S. Pat. No.
3,284,281 to R.W.
Thomas), and steam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).
[0014] 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, In. 50-54).
Despite this
declaration, it is noted that few, if any, commercial in situ shale oil
operations have occurred
other than Ljungstrom's enterprise. The `118 patent proposed controlling the
rate of heat
conduction within the rock surrounding each heat injection well to provide a
uniform heat
front.
[0015] As indicated above, resistive heating techniques for a subsurface
formation have
been considered. F.S. Chute and F.E. Vermeulen, Present and Potential
Applications of
Electromagnetic Heating in the In Situ Recovery of Oil, AOSTRA J. Res., v. 4,
p. 19-33
(1988) describes a heavy-oil pilot test where "electric preheat" was used to
flow electric
current between two wells to lower viscosity and create communication channels
between
wells for follow-up with a steam flood. It has been disclosed to run
alternating current or
radio frequency electrical energy between stacked conductive fractures or
electrodes in the
same well in order to heat a subterranean formation. See U.S. Pat. No.
3,149,672 titled
"Method and Apparatus for Electrical Heating of Oil-Bearing Formations;" U.S.
Pat. No.
3,620,300 titled "Method and Apparatus for Electrically Heating a Subsurface
Formation;"
U.S. Pat. No. 4,401,162 titled "In Situ Oil Shale Process;" and U.S. Pat. No.
4,705,108 titled
"Method for In Situ Heating of Hydrocarbonaceous Formations." U.S. Pat. No.
3,642,066
titled "Electrical Method and Apparatus for the Recovery of Oil," provides a
description of
resistive heating within a subterranean formation by running alternating
current between
different wells. Others have described methods to create an effective
electrode in a wellbore.
See U.S. Pat. No. 4,567,945 titled "Electrode Well Method and Apparatus;" and
U.S. Pat. No.
5,620,049 titled "Method for Increasing the Production of Petroleum From a
Subterranean
Formation Penetrated by a Wellbore." U.S. Pat. No. 3,137,347 titled "In Situ
Electrolinking
of Oil Shale," describes a method by which electric current is flowed through
a fracture
connecting two wells to get electric flow started in the bulk of the
surrounding formation.
-4-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
Heating of the formation occurs primarily due to the bulk electrical
resistance of the
formation.
[0016] Additional history behind oil shale retorting and shale oil recovery
can be found in
co-owned U.S. patent number 7,331,385 entitled "Methods of Treating a
Subterranean
Formation to Convert Organic Matter into Producible Hydrocarbons." The
Background and
technical disclosure of this patent is incorporated herein by reference.
[0017] A need exists for improved processes for the production of shale oil.
In addition,
a need exists for improved methods for heating a subsurface formation. Still
further, a need
exists for methods that facilitate an expeditious and effective subsurface
heater well
arrangement using an electrically conductive granular material placed within
an organic-rich
rock formation.
SUMMARY
[0018] In one embodiment, a method for heating a subsurface formation using
electrical
resistance heating is provided. In one aspect, the method includes providing
two or more
wellbores that penetrate an interval of solid organic-rich rock within the
subsurface
formation. Preferably, the organic-rich rock comprises oil shale.
[0019] At least one fracture is established in the organic-rich rock from at
least one of the
two or more wellbores. Preferably, the at least one fracture is formed
hydraulically. The
method also includes placing electrically conductive material in the at least
one fracture. In
this way electrical communication is provided between the two or more
wellbores. The
electrically conductive material comprises first portions placed in contact
with each of the
two or more wellbores, and a second portion intermediate the first portions
and around the
two or more wellbores. The first portions have a first bulk resistivity while
the second
portion has a second bulk resistivity.
[0020] The method also includes passing electric current through the fracture
such that
heat is generated by electrical resistivity within the electrically conductive
material sufficient
to pyrolyze at least a portion of the organic-rich rock into hydrocarbon
fluids. The heat
generated within the first portions of the electrically conductive material is
less than the heat
generated within the second portion of the electrically conductive material.
-5-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0021] In one embodiment, each of the two or more wellbores is completed
substantially
vertically, and the at least one fracture is substantially horizontal. In
another embodiment,
each of the two or more wellbores is completed substantially horizontally, and
the at least one
fracture is substantially vertical.
[0022] The electrically conductive material preferably comprises a proppant
material. In
one aspect, the first portions of the electrically conductive material
comprise granular metal,
metal coated particles, coke, graphite, or combinations thereof. In another
aspect, the second
portion of the electrically conductive material comprises granular metal,
metal coated
particles, coke, graphite, or combinations thereof.
[0023] As noted, the resistivity of the first portions is different than in
the second portion.
In one aspect, the resistivity of the material comprising the second portion
of the electrically
conductive material is about 10 to 100 times greater than the resistivity of
the material
comprising the first portions of the electrically conductive material. In one
example, and by
way of example only, the resistivity of the first portions of the electrically
conductive
material may be about 0.005 Ohm-meters. Alternatively, the resistivities of
the first portions
may be about 0.00005 Ohm-meters, or even as low as 0.00001 Ohm-Meters.
[0024] In another aspect, the first portions of the electrically conductive
material are
substantially non-conductive, and the second portion of the electrically
conductive material
contacts at least a portion of each of the two or more wellbores. Examples of
non-conductive
materials include silica, quartz, cement chips, sandstone, or combinations
thereof. In one
example, and by way of example only, the resistivity of the first portions of
the electrically
conductive material approaches infinity.
[0025] In one embodiment, the method also includes the step of continuing to
pass
electrical current through the first and second conductive portions of
electrically conductive
material. In this way pyrolysis of oil shale into hydrocarbon fluids occurs.
The hydrocarbon
fluids may then be produced from the subsurface formation to a surface
processing facility.
[0026] Another method for heating a subsurface formation using electrical
resistance
heating is provided herein. Preferably, the subsurface formation is an organic-
rich rock
formation. Preferably, the subsurface formation contains heavy hydrocarbons.
More
preferably, the subsurface formation is an oil shale formation.
-6-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0027] The method includes creating at least one passage in the subsurface
formation
between a first wellbore located at least partially within the subsurface
formation and a
second wellbore also located at least partially within the subsurface
formation. An
electrically conductive material is placed into the at least one passage to
form an electrical
connection. The electrical connection provides electrical communication
between the first
wellbore and the second wellbore. The electrically conductive material may be
a granular
material.
[0028] The method also includes providing a first electrically conductive
member in the
first wellbore so that the first electrically conductive member is in
electrical communication
with the electrical connection, and providing a second electrically conductive
member in the
second wellbore so that the second electrically conductive member is also in
electrical
communication with the electrical connection. In this way, an electrically
conductive flow
path comprised at least of the first electrically conductive member, the
electrical connection
and the second electrically conductive member is formed.
[0029] The method also includes establishing an electrical current through the
electrically
conductive flow path. This generates heat within the electrically conductive
flow path due to
electrical resistive heating. At least a portion of the generated heat
thermally conducts into
the subsurface formation. In accordance with this method, the generated heat
is comprised of
first heat generated in proximity to the first electrically conductive member
and the second
electrically conductive member, and second heat generated from the
electrically conductive
material intermediate the first electrically conductive member and the second
electrically
conductive member. The first heat is less than the second heat. Preferably,
the generated
heat causes pyrolysis of solid hydrocarbons within at least a portion of the
subsurface
formation.
[0030] In one embodiment, the electrically conductive material comprises (i)
first
portions in immediate proximity to the first electrically conductive member
and the second
electrically conductive member, respectively, and (ii) a second portion
intermediate the first
portions around the first and second electrically conductive members. A
resistivity of the
first portion is different than a resistivity of the second portion. In one
aspect, the first
portions of the electrically conductive material have a sufficiently low
electrical resistivity so
as to provide electrical conduction without substantial heat generation.
-7-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0031] For example, the first portions of the electrically conductive granular
material may
include less than or equal to 50 percent by dry weight of cement and 50
percent or more by
dry weight of graphite. The first portions of the electrically conductive
granular material may
include between 50 to 75 percent of granular metal, metal coated particles,
coke, graphite, or
combinations thereof.
[0032] In one general aspect, a method for heating a subsurface formation
using electrical
resistance heating includes providing two or more wellbores that penetrate an
interval of solid
organic-rich rock within the subsurface formation; establishing at least one
fracture in the
organic-rich rock from at least one of the two or more wellbores; and
providing electrically
conductive material in the at least one fracture so as to provide electrical
communication
between the two or more wellbores. The electrically conductive material
includes (i) first
portions placed in contact with each of the two or more wellbores and having a
first bulk
resistivity, and (ii) a second electrically conductive portion intermediate
the two or more
wellbores and having a second bulk resistivity. Electric current is passed
through the at least
one fracture such that resistive heat is generated within the electrically
conductive material
sufficient to pyrolyze at least a portion of the organic-rich rock into
hydrocarbon fluids,
wherein the generated heat is lower within the first portions of the
electrically conductive
material than in the second portion of the electrically conductive material.
[0033] Implementations of this aspect may include one or more of the following
features.
For example, the organic-rich rock may include oil shale. Each of the two or
more wellbores
may be completed substantially vertically and/or horizontally. The at least
one fracture may
be substantially horizontal, vertical, or some combination thereof. The
electrically
conductive material may include a granular material that serves as a proppant.
The first
portions of the electrically conductive material may include granular metal,
metal coated
particles, coke, graphite, and/or any combination thereof. The second portion
of the
electrically conductive material may include granular metal, metal coated
particles, coke,
graphite, and/or any combination thereof. The resistivity of the material
comprising the
second portion of the electrically conductive material may be about 10 to 100
times greater
than the resistivity of the material comprising the first portions of the
electrically conductive
material. The first portions of the electrically conductive material may be
substantially non-
conductive. The second portion of the electrically conductive material may
contact at least a
portion of each of the two or more wellbores. The first portions of the
electrically conductive
-8-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
material may include silica, quartz, cement chips, sandstone, and/or any
combination thereof.
The resistivity of the first portions of the electrically conductive material
may be about 0.005
Ohm-Meters. The resistivity of the first portions of the electrically
conductive material may
be between about 0.00001 Ohm-Meters and 0.00005 Ohm-Meters. The resistivity of
the first
portions of the electrically conductive material may approach infinity. The at
least one
fracture may be formed hydraulically. Electrical current may be continually or
intermittently
passed through the first and second portions of electrically conductive
material so as to cause
pyrolysis of oil shale into hydrocarbon fluids. Hydrocarbon fluids may be
produced from the
subsurface formation to a surface processing facility, e.g., with one or more
production wells.
[0034] In another general aspect, a method for heating a subsurface formation
using
electrical resistance heating includes creating at least one passage in the
subsurface formation
between a first wellbore located at least partially within the subsurface
formation and a
second wellbore also located at least partially within the subsurface
formation. An
electrically conductive material is provided into the at least one passage to
form an electrical
connection, the electrical connection providing electrical communication
between the first
wellbore and the second wellbore. A first electrically conductive member is
provided in the
first wellbore so that the first electrically conductive member is in
electrical communication
with the electrical connection. A second electrically conductive member is
provided in the
second wellbore, so that the second electrically conductive member is in
electrical
communication with the electrical connection, thereby forming an electrically
conductive
flow path comprised at least of the first electrically conductive member, the
electrical
connection and the second electrically conductive member. An electrical
current may be
established through the electrically conductive flow path, thereby generating
heat within the
electrically conductive flow path due to electrical resistive heating, with at
least a portion of
the generated heat thermally conducting into the subsurface formation, and
wherein the
generated heat is comprised of first heat generated in proximity to the first
electrically
conductive member and the second electrically conductive member, and second
heat
generated from the electrically conductive granular material intermediate the
first electrically
conductive member and the second electrically conductive member, with the
first heat being
less than the second heat.
[0035] Implementations of this aspect may include one or more of the following
features.
For example, the subsurface formation may be an organic-rich rock formation.
The
-9-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
subsurface formation may contain heavy hydrocarbons. The subsurface formation
may be an
oil shale formation. The electrically conductive material may include a
granular material.
The electrical connection may include a granular electrical connection. The
generated heat
causes pyrolysis of solid hydrocarbons within at least a portion of the
subsurface formation.
The electrically conductive granular material may include (i) first portions
in immediate
proximity to the first electrically conductive member and the second
electrically conductive
member, respectively, and (ii) a second portion intermediate the first
portions around the first
and second electrically conductive members. The resistivity of the first
portions may be
different than a resistivity of the second portion. The first portions of the
electrically
conductive granular material may have a sufficiently low electrical
resistivity so as to provide
electrical conduction without substantial heat generation. The first portions
of the electrically
conductive granular material may include granular metal, metal coated
particles, coke,
graphite, and/or any combination thereof. The second portion of the
electrically conductive
granular material may include granular metal, metal coated particles, coke,
graphite, and/or
any combination thereof. The resistivity of the material comprising the second
portion of the
electrically conductive granular material may be about 10 to 100 times greater
than the
resistivity of the material comprising the first portions of the electrically
conductive granular
material. The first portions of the electrically conductive granular material
may include less
than or equal to 50 percent by dry weight of cement and 50 percent or more by
dry weight of
graphite. The first portions of the electrically conductive granular material
may include
between 50 to 75 percent of granular metal, metal coated particles, coke,
graphite, and/or any
combination thereof. The first portions of the electrically conductive
granular material may
be substantially non-conductive; and the second portion of the electrically
conductive
granular material contacts at least a portion of each of the first and second
electrically
conductive members. The first portions of the electrically conductive granular
material may
include silica, quartz, cement chips, sandstone, and/or any combination
thereof. The
resistivity of the first portions of the electrically conductive granular
material may be about
0.005 Ohm-meters. The resistivity of the first portions of the electrically
conductive material
may approach infinity. The first wellbore and the second wellbore may each be
completed
substantially vertically; and the passage in the subsurface formation may
include a
substantially vertically fracture. The first wellbore and the second wellbore
may each be
completed substantially horizontally; and the at least one passage in the
subsurface formation
may include a first substantially vertical fracture. A third electrically
conductive member
may be provided in a third wellbore, such that the third electrically
conductive member is
-10-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
also in electrical communication with the electrical connection and is part of
the electrically
conductive flow path. The third wellbore may be completed substantially
horizontally. The
at least one passage in the subsurface formation may include a second
substantially vertical
fracture. The second wellbore may intersect both the first fracture and the
second fracture.
The material comprising at least a portion of the first electrically
conductive member, the
second electrically conductive member, or both may have an electrical
resistivity of less than
0.0005 Ohm-meters. An electrical current may be continually or intermittently
passed
through the electrical connection until the subsurface formation immediately
adjacent the
electrically conductive flow path reaches a selected temperature; and reducing
an amount of
current through the electrical connection.
[0036] In another general aspect, a system for in situ heating of a subsurface
formation
using electrical resistance heating includes a plurality of wellbores that
penetrate an interval
of solid organic-rich rock within the subsurface formation. At least one
fracture in the
organic-rich rock is established from at least one of the wellbores, wherein
the at least one
fracture includes electrically conductive material to provide electrical
communication
between at least two of the wellbores. The electrically conductive material
may include (i)
first portions placed in contact with at least two wellbores and having a
first bulk resistivity,
and (ii) a second electrically conductive portion intermediate the at least
two wellbores and
having a second bulk resistivity. At least one electrical conductor is
operatively connected to
the first portions of the electrically conductive material in each of the at
least two wellbores,
the at least one electrical conductor being configured to pass electric
current through the at
least one fracture such that resistive heat is generated within the
electrically conductive
material sufficient to pyrolyze at least a portion of the organic-rich rock
into hydrocarbon
fluids. The generated heat may be lower within the first portions of the
electrically
conductive material than in the second portion of the electrically conductive
material.
[0037] Implementations of this aspect may include one or more of the following
features.
For example, each of the two or more wellbores may be completed substantially
vertically,
horizontally, or some combination thereof. The at least one fracture may be
substantially
horizontal, vertical, or some combination thereof. The electrically conductive
material may
include a granular material that serves as a proppant. The first portions of
the electrically
conductive material may include granular metal, metal coated particles, coke,
graphite, and/or
any combination thereof. The second portion of the electrically conductive
material may
- 11 -
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
include granular metal, metal coated particles, coke, graphite, and/or any
combination
thereof. The resistivity of the material comprising the second portion of the
electrically
conductive material may be about 10 to 100 times greater than the resistivity
of the material
comprising the first portions of the electrically conductive material. The
first portions of the
electrically conductive material may be substantially non-conductive. The
second portion of
the electrically conductive material may contact at least a portion of each of
the two or more
wellbores. The first portions of the electrically conductive material may
include silica,
quartz, cement chips, sandstone, and/or any combination thereof. The
resistivity of the first
portions of the electrically conductive material may be about 0.005 Ohm-
Meters. The
resistivity of the first portions of the electrically conductive material may
be between about
0.00001 Ohm-Meters and 0.00005 Ohm-Meters. The resistivity of the first
portions of the
electrically conductive material may approach infinity. The at least one
fracture may be
formed hydraulically. The system may include one or more production wells for
producing
hydrocarbon fluids from the subsurface formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0038] So that the present invention can be better understood, certain
drawings, charts,
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.
[0039] Figure 1 is a cross-sectional isometric view of an illustrative
subsurface area. The
subsurface area includes an organic-rich rock matrix that defines a subsurface
formation.
[0040] Figure 2 is a flow chart demonstrating a general method of in situ
thermal
recovery of oil and gas from an organic-rich rock formation, in one
embodiment.
[0041] Figure 3 is a cross-sectional side view of an illustrative oil shale
formation that is
within or connected to groundwater aquifers, and a formation leaching
operation.
[0042] Figure 4 is a plan view of an illustrative heater well pattern. Two
layers of heater
wells are shown around respective production wells.
[0043] Figure 5 is a bar chart comparing one ton of Green River oil shale
before and after
a simulated in situ, retorting process.
-12-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0044] Figure 6 is a process flow diagram of exemplary surface processing
facilities for a
subsurface formation development.
[0045] Figure 7 is a perspective view of a hydrocarbon development area. A
subsurface
formation is being heated via resistive heating. A mass of conductive granular
material has
been injected into the formation between two adjacent wellbores.
[0046] Figure 8A is a perspective view of another hydrocarbon development
area. A
subsurface formation is once again being heated via resistive heating. A mass
of conductive
granular material has been injected into the formation from a plurality of
horizontally
completed wellbores. Corresponding wellbores are completed horizontally
through the
individual masses of conductive granular material.
[0047] Figure 8B is yet another perspective view of a hydrocarbon development
area. A
subsurface formation is once again being heated via resistive heating. A mass
of conductive
granular material has been injected into the formation from a pair of
horizontally completed
wellbores. A third wellbore is completed horizontally through the masses of
conductive
granular material.
[0048] Figure 9 is a perspective view of a core sample that has been opened
along its
longitudinal axis. Steel shot has been placed within a "tray" formed internal
to the core
sample.
[0049] Figure 10 shows the core sample of Figure 9 having been closed and
clamped for
testing. A current is run through the length of the core sample to create
resistive heating.
[0050] Figure 11 provides a series of charts wherein power, temperature and
resistance
are measured as a function of time during the heating of the core sample of
Figure 9.
[0051] Figure 12 demonstrates a flow of current through a geologic formation
that has
been fractured. Arrows demonstrate current increments in the x and y
directions for partial
derivative equations.
[0052] Figure 13 is a thickness-conductivity map showing a plan view of a
simulated
fracture. Two steel plates are positioned within surrounding conductive
granular proppant
within the fracture. The map is gray-scaled to show the product value of
conductivity
multiplied by the thickness of the conductive granular proppant across the
fracture.
-13-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0053] Figure 14 is another view of the thickness-conductivity map of Figure
13. The
map is gray-scaled in finer increments of conductivity multiplied by thickness
to distinguish
variations in proppant thickness.
[0054] Figure 15 is a representation of electric current moving into and out
of the fracture
plane of Figure 13. This representation is an electric current source map.
[0055] Figure 16 shows a voltage distribution within the fracture of Figure
13.
[0056] Figure 17 shows a heating distribution within the fracture of Figure
13.
[0057] Figure 18 is a thickness-conductivity map showing a plan view of a
simulated
fracture plane. Two steel plates are again positioned within surrounding
conductive granular
proppants within the fracture plane. The map is gray-scaled to show the
product value of
conductivity multiplied by the thickness of the conductive granular proppants
across the
fracture.
[0058] Figure 19 is another view of the thickness-conductivity map of Figure
18. The
map is gray-scaled in finer increments of conductivity multiplied by thickness
to distinguish
product values between the calcined coke, around the steel plates and a higher
conductivity
proppant, or "connector."
[0059] Figure 20 is another view of the thickness-conductivity map of Figure
18. The
map is gray-scaled in still further finer increments of conductivity times
thickness to
distinguish variations in conductivity between the calcined coke around the
steel plates and
the higher conductivity proppant.
[0060] Figure 21 is a representation of electric current moving into and out
of the fracture
plane of Figure 18. This representation is an electric current source map.
[0061] Figure 22 shows a voltage distribution within the fracture plane of
Figure 18.
[0062] Figure 23 shows a heating distribution within the fracture plane of
Figure 18.
[0063] Figure 24 is a thickness-conductivity map showing a plan view of a
simulated
fracture plane. Two steel plates are again positioned within surrounding
conductive granular
proppants within the fracture plane. The map is gray-scaled to show the
product value of
-14-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
conductivity multiplied by thickness for the conductive granular proppants
across the
fracture.
[0064] Figure 25 is another view of the thickness-conductivity map of Figure
24. The
map is gray-scaled in finer increments of conductivity multiplied by thickness
to distinguish
between calcined coke, or "connector," around the steel plates and a higher
conductivity
proppant.
[0065] Figure 26 is a representation of electric current moving into and out
of the fracture
plane of Figure 24. This representation is an electric current source map.
[0066] Figure 27 shows a voltage distribution within the fracture plane of
Figure 24.
[0067] Figure 28 shows a heating distribution within the fracture plane of
Figure 24.
Detailed Description
Definitions
[0068] As used herein, the term "hydrocarbon(s)" refers to organic material
with
molecular structures containing carbon bonded to hydrogen. Hydrocarbons may
also include
other elements such as, but not limited to, halogens, metallic elements,
nitrogen, oxygen,
and/or sulfur.
[0069] As used herein, the term "hydrocarbon fluids" refers to a hydrocarbon
or mixtures
of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may
include a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation
conditions, at
processing conditions or at ambient conditions (15 C and 1 atm pressure).
Hydrocarbon
fluids may include, for example, oil, natural gas, coal bed methane, shale
oil, pyrolysis oil,
pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in
a gaseous or
liquid state.
[0070] As used herein, the terms "produced fluids" and "production fluids"
refer to
liquids and/or gases removed from a subsurface formation, including, for
example, an
organic-rich rock formation. Production fluids may include, but are not
limited to, pyrolyzed
shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide,
hydrogen sulfide and
water (including steam). Produced fluids may include both hydrocarbon fluids
and non-
hydrocarbon fluids.
-15-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0071] As used herein, the term "condensable hydrocarbons" means those
hydrocarbons
that condense at 25 C and one atmosphere absolute pressure. Condensable
hydrocarbons
may include a mixture of hydrocarbons having carbon numbers greater than 4.
[0072] As used herein, the term "non-condensable hydrocarbons" means those
hydrocarbons that do not condense at 25 C and one atmosphere absolute
pressure. Non-
condensable hydrocarbons may include hydrocarbons having carbon numbers less
than 5.
[0073] As used herein, the term "heavy hydrocarbons" refers to hydrocarbon
fluids that
are highly viscous at ambient conditions (15 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 to 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 C.
[0074] 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.
[0075] As used herein, the term "formation hydrocarbons" refers to both heavy
hydrocarbons and solid hydrocarbons that are contained in an organic-rich rock
formation.
Formation hydrocarbons may be, but are not limited to, kerogen, oil shale,
coal, bitumen, tar,
natural mineral waxes, and asphaltites.
[0076] As used herein, the term "tar" refers to a viscous hydrocarbon that
generally has a
viscosity greater than about 10,000 centipoise at 15 C. The specific gravity
of tar generally
is greater than 1.000. Tar may have an API gravity less than 10 degrees. "Tar
sands" refers
to a formation that has tar in it.
[0077] 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.
-16-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0078] As used herein, the term "bitumen" refers to a non-crystalline solid or
viscous
hydrocarbon material that is substantially soluble in carbon disulfide.
[0079] As used herein, the term "oil" refers to a hydrocarbon fluid containing
a mixture
of condensable hydrocarbons.
[0080] As used herein, the term "subsurface" refers to geologic strata
occurring below the
earth's surface.
[0081] As used herein, the term "hydrocarbon-rich formation" refers to any
formation
that contains more than trace amounts of hydrocarbons. For example, a
hydrocarbon-rich
formation may include portions that contain hydrocarbons at a level of greater
than 5 volume
percent. The hydrocarbons located in a hydrocarbon-rich formation may include,
for
example, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.
[0082] As used herein, the term "organic-rich rock" refers to any rock matrix
holding
solid hydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but
are not
limited to, sedimentary rocks, shales, siltstones, sands, silicilytes,
carbonates, and diatomites.
Organic-rich rock may contain kerogen.
[0083] As used herein, the term "formation" refers to any finite subsurface
region. The
formation may contain one or more hydrocarbon-containing layers, one or more
non-
hydrocarbon containing layers, an overburden, and/or an underburden of any
subsurface
geologic formation. An "overburden" is geological material above the formation
of interest,
while an "underburden" is geological material below the formation of interest.
An
overburden or underburden may include 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). An overburden and/or an underburden may include a hydrocarbon-
containing
layer that is relatively impermeable. In some cases, the overburden and/or
underburden may
be permeable.
[0084] As used herein, the term "organic-rich rock formation" refers to any
formation
containing organic-rich rock. Organic-rich rock formations include, for
example, oil shale
formations, coal formations, and tar sands formations.
-17-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0085] As used herein, the term "pyrolysis" refers to the breaking of chemical
bonds
through 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. Pyrolysis may include modifying the nature of the compound by
addition of
hydrogen atoms which may be obtained from molecular hydrogen, water, carbon
dioxide, or
carbon monoxide. Heat may be transferred to a section of the formation to
cause pyrolysis.
[0086] 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(C03)(OH)2), or
combinations
thereof. Substantial solubility may require heated water and/or a non-neutral
pH solution.
[0087] As used herein, the term "formation water-soluble minerals" refers to
water-
soluble minerals that are found naturally in a formation.
[0088] As used herein, the term "subsidence" refers to a downward movement of
a
surface relative to an initial elevation of the surface.
[0089] As used herein, the term "thickness" of a layer refers to the distance
between the
upper and lower boundaries of a cross section of a layer, wherein the distance
is measured
normal to the average tilt of the cross section.
[0090] As used herein, the term "thermal fracture" refers to fractures created
in a
formation caused directly or indirectly by expansion or contraction of a
portion of the
formation and/or fluids within the formation, which in turn is 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.
[0091] As used herein, the term "hydraulic fracture" refers to a fracture at
least partially
propagated into a formation, wherein the fracture is created through injection
of pressurized
fluids into the formation. While the term "hydraulic fracture" is used, the
inventions herein
are not limited to use in hydraulic fractures. The invention is suitable for
use in any fracture
created in any manner considered to be suitable by one skilled in the art. The
fracture may be
artificially held open by injection of a proppant material. Hydraulic
fractures may be
-18-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
substantially horizontal in orientation, substantially vertical in
orientation, or oriented along
any other plane.
[0092] As used herein, the term "wellbore" refers to a hole in the subsurface
made by
drilling or insertion of a conduit into the subsurface. 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."
[0093] 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, such is intended to be illustrative
only and is not to
be construed as limiting the scope of the invention.
[0094] As discussed herein, some embodiments of the invention include or have
application related to 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, or 2NaHCO3), soda ash (sodium
carbonate, or
Na2CO3) and dawsonite (NaAl(C03)(OH)2).
[0095] Figure 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 subsurface formation 16 contains
formation
hydrocarbons (such as, for example, kerogen) and possibly 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 16 may be
permeable, semi-
permeable or essentially non-permeable. The present inventions are
particularly
-19-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
advantageous in oil shale development areas initially having very limited or
effectively no
fluid permeability.
[0096] In order to access formation 16 and recover natural resources
therefrom, a
plurality of wellbores is formed. Wellbores are shown at 14 in Figure 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 Figure 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
emanating
therefrom.
[0097] In the view of Figure 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. In some embodiments, a well
spacing of 15 to 25
feet is provided. Typically, the wellbores 14 are also completed at shallow
depths, being
from 200 to 5,000 feet at total depth. In some embodiments the oil shale
formation targeted
for in situ retorting is at a depth greater than 200 feet below the surface or
alternatively 400
feet below the surface. Alternatively, conversion and production occur at
depths between
500 and 2,500 feet.
[0098] The wellbores 14 will be selected for certain functions and may be
designated as
heat injection wells, water injection wells, oil production wells and/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 in designated sequences. Suitable tools
and equipment
may be sequentially run into and removed from the wellbores 14 to serve the
various
purposes.
[0099] A fluid processing facility 17 is also shown schematically. The fluid
processing
facility 17 is equipped to receive fluids produced from the organic-rich rock
formation 16
through one or more pipelines or flow lines 18. The fluid processing facility
17 may include
equipment suitable for receiving and separating oil, gas, and water produced
from the heated
formation. The fluid processing facility 17 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
-20-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
produced water recovered from the organic-rich rock formation 16. The
contaminants may
include, for example, aromatic hydrocarbons such as benzene, toluene, xylene,
and tri-
methylbenzene. The contaminants may also include 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.
[0100] In order to recover oil, gas, and sodium (or other) water-soluble
minerals, a series
of steps may be undertaken. Figure 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 Figure 2 may be
changed, and that
the sequence of steps is merely for illustration.
[0101] 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. Optionally, the oil shale
formation may
contain nahcolite or other sodium minerals. 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 core samples
from subsurface
rock. Rock samples may be analyzed to assess kerogen content and hydrocarbon
fluid
generating capability.
[0102] The kerogen content of the organic-rich rock formation may be
ascertained from
outcrop or core samples using a variety of data. Such data may include organic
carbon
content, hydrogen index, and 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.
[0103] 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
-21-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
formation step of box 115, only a portion of the wells need be completed
initially. For
instance, at the beginning of the project heat injection wells are needed,
while a majority of
the hydrocarbon production wells are not yet needed. Production wells may be
brought in
once conversion begins, such as after 4 to 12 months of heating.
[0104] 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.
[0105] Concerning heat injection wells, there are various methods for applying
heat to the
organic-rich rock formation 16. The present methods are not limited to the
heating technique
employed unless specifically so stated in the claims. 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.
[0106] The formation 16 is heated to a temperature sufficient to pyrolyze at
least a
portion of the oil shale in order to convert the kerogen to hydrocarbon
fluids. The bulk of the
target zone of the formation may be heated to between 270 C to 800 C.
Alternatively, the
targeted volume of the organic-rich formation is heated to at least 3500 C to
create production
fluids. The conversion step is represented in Figure 2 by box 135. 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, H2, C02,
CO, and NH3.
[0107] Conversion of the oil shale will create permeability in the oil shale
section in
rocks that were originally impermeable. Preferably, the heating and conversion
processes of
boxes 130 and 135, occur over a lengthy period of time. In one aspect, the
heating period is
from three months to four or more years. Also as an optional part of box 135,
the formation
16 may be heated to a temperature sufficient to convert at least a portion of
nahcolite, if
present, to soda ash. Heat applied 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) is
described
herein.
-22-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0108] In connection with the heating step 130, the rock formation 16 may
optionally be
fractured to aid heat transfer or later hydrocarbon fluid production. The
optional fracturing
step is shown in box 125. Fracturing may be accomplished by creating thermal
fractures
within the formation through application of heat. By heating the organic-rich
rock and
transforming the kerogen to oil and gas, the permeability of portions of the
formation are
increased via thermal fracture formation and subsequent production of a
portion of the
hydrocarbon fluids generated from the kerogen. Alternatively, a process known
as hydraulic
fracturing may be used. 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 in portions of the formation and/or be used to provide a planar
source for
heating.
[0109] International patent publication WO 2005/010320 entitled "Methods of
Treating a
Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons"
describes
one use of hydraulic fracturing, and is incorporated herein by reference in
its entirety. This
international patent publication teaches the use of electrically conductive
fractures to heat oil
shale. A heating element is constructed by forming wellbores and then
hydraulically
fracturing the oil shale formation around the wellbores. The fractures are
filled with an
electrically conductive material which forms the heating element. Calcined
petroleum coke
is an exemplary suitable conductant material. Preferably, the fractures are
created in a
vertical orientation extending from horizontal wellbores. Electricity may be
conducted
through the conductive fractures from the heel to the toe of each well. The
electrical circuit
may be completed by an additional horizontal well that intersects one or more
of the vertical
fractures near the toe to supply the opposite electrical polarity. The WO
2005/010320
process creates an "in situ toaster" that artificially matures oil shale
through the application of
electric heat. Thermal conduction heats the oil shale to conversion
temperatures in excess of
300 C, causing artificial maturation.
[0110] It is noted that U.S. Pat. No. 3,137,347 also describes the use of
granular
conductive materials to connect subsurface electrodes for the in situ heating
of oil shale. The
`347 patent envisions the granular material being a primary source of heat
until the oil shale
undergoes pyrolysis. At that point, the oil shale itself is said to become
electrically
conductive. Heat generated within the formation and heat conducted into the
surrounding
-23-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
formation due to the passing of current through the shale oil material itself
is claimed to
generate hydrocarbon fluids for production.
[0111] 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. In other instances, selected heater
wells are converted
to production wells.
[0112] 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), any water-soluble minerals, such as
nahcolite and
converted soda ash may 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
heat conversion
(box 135) within the formation. Thus, production fluids may contain not only
hydrocarbon
fluids, but also aqueous fluid containing water-soluble minerals. In such
case, the production
fluids may be separated into a hydrocarbon stream and an aqueous stream at a
surface
facility. Thereafter the water-soluble minerals and any migratory contaminant
species may
be recovered from the aqueous stream.
[0113] Box 150 presents an optional 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 with other species. The water may constitute
"brine," and may
include dissolved inorganic salts of chloride, sulfates and carbonates of
Group I and II
elements of The Periodic Table of Elements. Organic salts can also be present
in the aqueous
fluid. The water may alternatively be fresh water containing 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.
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
-24-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
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.
[0114] Next, optionally 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 155. 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.
[0115] 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. This step is shown in box 160. These wells may be
the same as
wells used to previously produce hydrocarbons or inject heat. These recovery
wells may be
used to 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).
[0116] 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 inside the heated zone from leaving the zone.
[0117] Figure 3 is a cross-sectional view of an illustrative oil shale
formation that is
within or connected to ground water aquifers and a formation leaching
operation. Four
separate oil shale formation zones are depicted (23, 24, 25 and 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 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 and 31) is shown
traversing vertically
-25-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
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.
[0118] Figure 3 shows diagrammatically water circulating 32 through an oil
shale
volume 33 that was heated, 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 may then be processed in a facility 34 wherein the water-soluble
minerals (e.g.
nahcolite or soda ash) and the migratory contaminants may be 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 more
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 and 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.
[0119] In some fields, formation hydrocarbons, such as oil shale, may exist in
more than
one subsurface formation. In some instances, the organic-rich rock formations
may be
separated by rock layers that are hydrocarbon-free or that otherwise have
little or no
commercial value. Therefore, it may be desirable for the operator of a field
under
hydrocarbon development to undertake an analysis as to which of the
subsurface, organic-
rich rock formations to target or in which order they should be developed.
[0120] The organic-rich rock formation may be selected for development based
on
various factors. One such factor is the thickness of the hydrocarbon
containing layer within
the formation. Greater pay zone thickness may indicate a greater potential
volumetric
production of hydrocarbon fluids. Each of the hydrocarbon containing layers
may have a
thickness that varies depending on, for example, conditions under which the
formation
hydrocarbon containing layer was formed. Therefore, an organic-rich rock
formation will
-26-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
typically be selected for treatment if that formation includes at least one
formation
hydrocarbon-containing layer having a thickness sufficient for economical
production of
produced fluids.
[0121] An organic-rich rock formation may also be chosen if the thickness of
several
layers that are closely spaced together is sufficient for economical
production of produced
fluids. For example, an in situ conversion process for formation hydrocarbons
may include
selecting and treating a layer within an organic-rich rock formation having a
thickness of
greater than about 5 meters, 10 meters, 50 meters, or even 100 meters. In this
manner, heat
losses (as a fraction of total injected heat) to layers formed above and below
an organic-rich
rock formation may be less than such heat losses from a thin layer of
formation
hydrocarbons. A process as described herein, however, may also include
selecting and
treating layers that may include layers substantially free of formation
hydrocarbons or thin
layers of formation hydrocarbons.
[0122] The richness of one or more organic-rich rock formations may also be
considered.
Richness may depend on many factors including the conditions under which the
formation
hydrocarbon containing layer was formed, an amount of formation hydrocarbons
in the layer,
and/or a composition of formation hydrocarbons in the layer. A thin and rich
formation
hydrocarbon layer may be able to produce significantly more valuable
hydrocarbons than a
much thicker, less rich formation hydrocarbon layer. Of course, producing
hydrocarbons
from a formation that is both thick and rich is desirable.
[0123] The kerogen content of an organic-rich rock formation may be
ascertained from
outcrop or core samples using a variety of data. Such data may include organic
carbon
content, hydrogen index, and modified Fischer assay analyses. The Fischer
Assay is a
standard method which involves heating a sample of a formation hydrocarbon
containing
layer to approximately 500 C in one hour, collecting fluids produced from the
heated sample,
and quantifying the amount of fluids produced.
[0124] Subsurface formation 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. Thus, an organic-rich rock
formation may be
chosen for development based on the permeability or porosity of the formation
matrix even if
the thickness of the formation is relatively thin.
-27-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0125] Other factors known to petroleum engineers may be taken into
consideration when
selecting a formation for development. Such factors include depth of the
perceived pay zone,
stratigraphic proximity of fresh ground water to kerogen-containing zones,
continuity of
thickness, and other factors. For instance, the assessed fluid production
content within a
formation will also effect eventual volumetric production.
[0126] In producing hydrocarbon fluids from an oil shale field, it may be
desirable to
control the migration of pyrolyzed fluids. In some instances, this includes
the use of injection
wells such as well 31, particularly around the periphery of the field. Such
wells may inject
water, steam, C02, heated methane, or other fluids to drive cracked kerogen
fluids inwardly
towards production wells. In some embodiments, physical barriers may be placed
around the
area of the organic-rich rock formation under development. One example of a
physical
barrier involves the creation of freeze walls. Freeze walls are formed by
circulating
refrigerant through peripheral wells to substantially reduce the temperature
of the rock
formation. This, in turn, prevents the pyrolyzation of kerogen present at the
periphery of the
field and the outward migration of oil and gas. Freeze walls will also cause
native water in
the formation along the periphery to freeze.
[0127] The use of subsurface freezing to stabilize poorly consolidated soils
or to provide
a barrier to fluid flow is known in the art. Shell Exploration and Production
Company has
discussed the use of freeze walls for oil shale production in several patents,
including U.S.
Pat. No. 6,880,633 and U.S. Pat. No. 7,032,660. Shell's `660 patent uses
subsurface freezing
to protect against groundwater flow and groundwater contamination during in
situ shale oil
production. Additional patents that disclose the use of so-called freeze walls
are U.S. Pat.
No. 3,528,252, U.S. Pat. No. 3,943,722, U.S. Pat. No. 3,729,965, U.S. Pat. No.
4,358,222,
U.S. Pat. No. 4,607,488, and WO Pat. No. 98996480.
[0128] As noted above, several different types of wells may be used in the
development
of an organic-rich rock formation, including, for example, an oil shale field.
For example, the
heating of the organic-rich rock formation may be accomplished through the 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 the use of
wells completed for the production of fluids. The injection of an aqueous
fluid may be
accomplished through the use of injection wells. Finally, the production of an
aqueous
solution may be accomplished through use of solution production wells.
-28-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0129] The different wells listed above may be used for more than one purpose.
Stated
another way, wells initially completed for one purpose may later be used for
another purpose,
thereby lowering project costs and/or decreasing the time required to perform
certain tasks.
For example, one or more of the production wells may also be used as injection
wells for later
injecting water into the organic-rich rock formation. Alternatively, one or
more of the
production wells may also be used as solution production wells for later
producing an
aqueous solution from the organic-rich rock formation.
[0130] In other aspects, production wells (and in some circumstances heater
wells) may
initially be used as dewatering wells (e.g., before heating is begun and/or
when heating is
initially started). In addition, in some circumstances dewatering wells can
later be used as
production wells (and in some circumstances heater wells). As such, the
dewatering wells
may be placed and/or designed so that such wells can be later used as
production wells and/or
heater wells. The heater wells may be placed and/or designed so that such
wells can be later
used as production wells and/or dewatering wells. The production wells may be
placed
and/or designed so that such wells can be later used as dewatering wells
and/or heater wells.
Similarly, injection wells may be wells that initially were used for other
purposes (e.g.,
heating, production, dewatering, monitoring, etc.), and injection wells may
later be used for
other purposes. Similarly, monitoring wells may be wells that initially were
used for other
purposes (e.g., heating, production, dewatering, injection, etc.). Finally,
monitoring wells
may later be used for other purposes such as water production.
[0131] It is desirable to arrange the various wells for an oil shale field in
a pre-planned
pattern. For instance, heater wells may be arranged in a variety of patterns
including, but not
limited to triangles, squares, hexagons, and other polygons. The pattern may
include a
regular polygon to promote uniform heating through at least the portion of the
formation in
which the heater wells are placed. The pattern may also be a line drive
pattern. A line drive
pattern generally includes a first linear array of heater wells, a second
linear array of heater
wells, and a production well or a linear array of production wells between the
first and second
linear array of heater wells. Interspersed among the heater wells are
typically one or more
production wells. The injection wells may likewise be disposed within a
repetitive pattern of
units, which may be similar to or different from that used for the heater
wells.
[0132] One method to reduce the number of wells is to use a single well as
both a heater
well and a production well. Reduction of the number of wells by using single
wells for
-29-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
sequential purposes can reduce project costs. One or more monitoring wells may
be disposed
at selected points in the field. The monitoring wells may be configured with
one or more
devices that measure a temperature, a pressure, and/or a property of a fluid
in the wellbore.
In some instances, a heater well may also serve as a monitoring well, or
otherwise be
instrumented.
[0133] Another method for reducing the number of heater wells is to use well
patterns.
Regular patterns of heater wells equidistantly spaced from a production well
may be used.
The patterns may form equilateral triangular arrays, hexagonal arrays, or
other array patterns.
The arrays of heater wells may be disposed such that a distance between each
heater well is
less than about 70 feet (21 meters). A portion of the formation may be heated
with heater
wells disposed substantially parallel to a boundary of the hydrocarbon
formation.
[0134] In alternative embodiments, the array of heater wells may be disposed
such that a
distance between each heater well may be less than about 100 feet, or 50 feet,
or 30 feet.
Regardless of the arrangement of or distance between the heater wells, in
certain
embodiments, a ratio of heater wells to production wells disposed within a
organic-rich rock
formation may be greater than about 5, 8, 10, 20, or more.
[0135] In one embodiment, individual production wells are surrounded by at
most one
layer of heater wells. This may include arrangements such as 5-spot, 7-spot,
or 9-spot arrays,
with alternating rows of production and heater wells. In another embodiment,
two layers of
heater wells may surround a production well, but with the heater wells
staggered so that a
clear pathway exists for the majority of flow away from the further heater
wells. Flow and
reservoir simulations may be employed to assess the pathways and temperature
history of
hydrocarbon fluids generated in situ as they migrate from their points of
origin to production
wells.
[0136] Figure 4 provides a plan view of an illustrative heater well
arrangement using
more than one layer of heater wells. The heater well arrangement is used in
connection with
the production of hydrocarbons from a shale oil development area 400. In
Figure 4, the
heater well arrangement employs a first layer of heater wells 410, surrounded
by a second
layer of heater wells 420. The heater wells in the first layer 410 are
referenced at 431, while
the heater wells in the second layer 420 are referenced at 432.
-30-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0137] A production well 440 is shown central to the well layers 410 and 420.
It is noted
that the heater wells 432 in the second layer 420 of wells are offset from the
heater wells 431
in the first layer 410 of wells, relative to the production well 440. The
purpose is to provide a
flowpath for converted hydrocarbons that minimizes travel near a heater well
in the first layer
410 of heater wells. This, in turn, minimizes secondary cracking of
hydrocarbons converted
from kerogen as hydrocarbons flow from the second layer of wells 420 to the
production
wells 440.
[0138] In the illustrative arrangement of Figure 4, the first layer 410 and
the second layer
420 each defines a 5-spot pattern. However, it is understood that other
patterns may be
employed, such as 3-spot or 6-spot patterns. In any instance, a plurality of
heater wells 431
comprising a first layer of heater wells 410 is placed around a production
well 440, with a
second plurality of heater wells 432 comprising a second layer of heater wells
420 placed
around the first layer 410.
[0139] The heater wells in the two layers also may be arranged such that the
majority of
hydrocarbons generated by heat from each heater well 432 in the second layer
420 are able to
migrate to a production well 440 without passing substantially near a heater
well 431 in the
first layer 410. The heater wells 431, 432 in the two layers 410, 420 further
may be arranged
such that the majority of hydrocarbons generated by heat from each heater well
432 in the
second layer 420 are able to migrate to the production well 440 without
passing through a
zone of substantially increasing formation temperature.
[0140] Another method for reducing the number of heater wells is to use well
patterns
that are elongated in a particular direction, particularly in a direction
determined to provide
the most efficient thermal conductivity. Heat convection may be affected by
various factors
such as bedding planes and stresses within the formation. For instance, heat
convection may
be more efficient in the direction perpendicular to the least horizontal
principal stress on the
formation. In some instances, heat convection may be more efficient in the
direction parallel
to the least horizontal principal stress. Elongation may be practiced in, for
example, line
drive patterns or spot patterns.
[0141] In connection with the development of a shale oil field, it may be
desirable that
the progression of heat through the subsurface in accordance with steps 130
and 135 be
uniform. However, for various reasons the heating and maturation of formation
hydrocarbons in a subsurface formation may not proceed uniformly despite a
regular
-31-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
arrangement of heater and production wells. Heterogeneities in the oil shale
properties and
formation structure may cause certain local areas to be more or less efficient
in terms of
pyrolysis. Moreover, formation fracturing which occurs due to the heating and
maturation of
the oil shale can lead to an uneven distribution of preferred pathways and,
thus, increase flow
to certain production wells and reduce flow to others. Uneven fluid maturation
may be an
undesirable condition since certain subsurface regions may receive more heat
energy than
necessary where other regions receive less than desired. This, in turn, leads
to the uneven
flow and recovery of production fluids. Produced oil quality, overall
production rate, and/or
ultimate recoveries may be reduced.
[0142] To detect uneven flow conditions, production and heater wells may be
instrumented with sensors. Sensors may include equipment to measure
temperature,
pressure, flow rates, and/or compositional information. Data from these
sensors can be
processed via simple rules or input to detailed simulations to reach decisions
on how to adjust
heater and production wells to improve subsurface performance. Production well
performance may be adjusted by controlling backpressure or throttling on the
well. Heater
well performance may also be adjusted by controlling energy input. Sensor
readings may
also sometimes imply mechanical problems with a well or downhole equipment
which
requires repair, replacement, or abandonment.
[0143] In one embodiment, flow rate, compositional, temperature and/or
pressure data are
utilized from two or more wells as inputs to a computer algorithm to control
heating rate
and/or production rates. Unmeasured conditions at or in the neighborhood of
the well are
then estimated and used to control the well. For example, in situ fracturing
behavior and
kerogen maturation are estimated based on thermal, flow, and compositional
data from a set
of wells. In another example, well integrity is evaluated based on pressure
data, well
temperature data, and estimated in situ stresses. In a related embodiment the
number of
sensors is reduced by equipping only a subset of the wells with instruments,
and using the
results to interpolate, calculate, or estimate conditions at uninstrumented
wells. Certain wells
may have only a limited set of sensors (e.g., wellhead temperature and
pressure only) where
others have a much larger set of sensors (e.g., wellhead temperature and
pressure, bottomhole
temperature and pressure, production composition, flow rate, electrical
signature, casing
strain, etc.).
-32-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0144] As noted above, there are various methods for applying heat to an
organic-rich
rock formation. For example, one method may include electrical resistance
heaters disposed
in a wellbore or outside of a wellbore. One such method involves the use of
electrical
resistive heating elements in a cased or uncased wellbore. Electrical
resistance heating
involves directly passing electricity through a conductive material such that
resistive losses
cause it to heat the conductive material. Other heating methods include the
use of 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 hot fluid may or may not be circulated.
[0145] One method for formation heating involves the use of electrical
resistors in which
an electrical current is passed through a resistive material which dissipates
the electrical
energy as heat. This method is distinguished from dielectric heating in which
a high-
frequency oscillating electric current induces electrical currents in nearby
materials and
causes them to heat. The electric heater may include an insulated conductor,
an elongated
member disposed in the opening, and/or a conductor disposed in a conduit. An
early patent
disclosing the use of electrical resistance heaters to produce oil shale in
situ is U.S. Pat. No.
1,666,488. The `488 patent issued to Crawshaw in 1928. Since 1928, various
designs for
downhole electrical heaters have been proposed. Illustrative designs are
presented in U.S.
Pat. No. 1,701,884, U.S. Pat. No. 3,376,403, U.S. Pat. No. 4,626,665, U.S.
Pat. No.
4,704,514, and U.S. Pat. No. 6,023,554).
[0146] A review of application of electrical heating methods for heavy oil
reservoirs is
given by R. Sierra and S.M. Farouq Ali, "Promising Progress in Field
Application of
Reservoir Electrical Heating Methods", Society of Petroleum Engineers Paper
69709, 2001.
The entire disclosure of this reference is hereby incorporated by reference.
[0147] Certain previous designs for in situ electrical resistance heaters
utilized solid,
continuous heating elements (e.g., metal wires or strips). However, such
elements may lack
the necessary robustness for long-term, high temperature applications such as
oil shale
maturation. As the formation heats and the oil shale matures, significant
expansion of the
rock occurs. This leads to high stresses on wells intersecting the formation.
These stresses
can lead to bending and stretching of the wellbore pipe and internal
components. Cementing
(e.g., U.S. Pat. No. 4,886,118) or packing (e.g., U.S. Pat. No. 2,732,195) a
heating element in
-33-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
place may provide some protection against stresses, but some stresses may
still be transmitted
to the heating element.
[0148] Although the above processes are applied in these examples to generate
hydrocarbons from oil shale, the idea may also be applicable to heavy oil
reservoirs, tar
sands, or gas hydrates. In these instances, the electrical heat supplied would
serve to reduce
hydrocarbon viscosity or to melt hydrates. U.S. Patent No. 6,148,911 discusses
the use of an
electrically conductive proppant to release gas from a hydrate formation. It
is also known to
apply a voltage across a formation using brine as the electrical conductor and
heating
element. However, it is believed that the use of formation brine as a heating
element is
inadequate for shale conversion as it is limited to temperatures below the in
situ boiling point
of water. Thus, the circuit fails when the water vaporizes.
[0149] The purpose for heating the organic-rich rock formation is to pyrolyze
at least a
portion of the solid formation hydrocarbons to create hydrocarbon fluids. The
solid
formation hydrocarbons may be pyrolyzed in situ by raising the organic-rich
rock formation,
(or zones within the formation), to a pyrolyzation temperature. In certain
embodiments, the
temperature of the formation may be slowly raised through the pyrolysis
temperature range.
For example, an in situ conversion process may include heating at least a
portion of the
organic-rich rock formation to raise the average temperature of the zone above
about 2700 C
at a rate less than a selected amount (e.g., about 100 C, 5C; 3C, 1C, 0.5C, or
0.1C) 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 C or, in some embodiments, less
than about
400 C. The formation may be heated such that a temperature within the
formation reaches
(at least) an initial pyrolyzation temperature, that is, a temperature at the
lower end of the
temperature range where pyrolyzation begins to occur.
[0150] The pyrolysis temperature range may vary depending on the types of
formation
hydrocarbons within the formation, the heating methodology, and the
distribution of heating
sources. For example, a pyrolysis temperature range may include temperatures
between
about 270 C and about 900 C. Alternatively, the bulk of the target zone of
the formation
may be heated to between 300 to 600 C. In an alternative embodiment, a
pyrolysis
temperature range may include temperatures between about 270 C to about 500
C.
[0151] 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
-34-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
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 C.
Preferably, the
bulk of the target zone of the formation is heated to between 300 to 600 C.
Alternatively,
the bulk of the target zone is ultimately heated to a temperature below 400 C
(752 F).
[0152] In the production of oil and gas resources, it may be desirable to use
the produced
hydrocarbons as a source of power for ongoing operations. This may be applied
to the
development of oil and gas resources from oil shale. In this respect, when
electrically
resistive heaters are used in connection with in situ shale oil recovery,
large amounts of
power are required.
[0153] Electrical power may be obtained from turbines that turn generators. It
may be
economically advantageous to power the gas turbines by utilizing produced gas
from the
field. However, such produced gas must be carefully controlled so not to
damage the turbine,
cause the turbine to misfire, or generate excessive pollutants (e.g., NOR).
[0154] One source of problems for gas turbines is the presence of contaminants
within
the fuel. Contaminants include solids, water, heavy components present as
liquids, and
hydrogen sulfide. Additionally, the combustion behavior of the fuel is
important.
Combustion parameters to consider include heating value, specific gravity,
adiabatic flame
temperature, flammability limits, autoignition temperature, autoignition delay
time, and flame
velocity. Wobbe Index (WI) is often used as a key measure of fuel quality. WI
is equal to
the ratio of the lower heating value to the square root of the gas specific
gravity. Control of
the fuel's Wobbe Index to a target value and range of, for example, 10% or 20%
can
allow simplified turbine design and increased optimization of performance.
[0155] Fuel quality control may be useful for shale oil developments where the
produced
gas composition may change over the life of the field and where the gas
typically has
significant amounts of C02, CO, and H2 in addition to light hydrocarbons.
Commercial scale
oil shale retorting is expected to produce a gas composition that changes with
time.
[0156] Inert gases in the turbine fuel can increase power generation by
increasing mass
flow while maintaining a flame temperature in a desirable range. Moreover
inert gases can
lower flame temperature and thus reduce NOR pollutant generation. Gas
generated from oil
shale maturation may have significant CO2 content. Therefore, in certain
embodiments of the
-35-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
production processes, the CO2 content of the fuel gas is adjusted via
separation or addition in
the surface facilities to optimize turbine performance.
[0157] Achieving a certain hydrogen content for low-BTU fuels may also be
desirable to
achieve appropriate burn properties. In certain embodiments of the processes
herein, the H2
content of the fuel gas is adjusted via separation or addition in the surface
facilities to
optimize turbine performance. Adjustment of H2 content in non-shale oil
surface facilities
utilizing low BTU fuels has been discussed in the patent literature (e.g.,
U.S. Pat. No.
6,684,644 and U.S. Pat. No. 6,858,049, the entire disclosures of which are
hereby
incorporated by reference).
[0158] As noted, the process of heating formation hydrocarbons within an
organic-rich
rock formation, for example, by pyrolysis, may generate fluids. The heat-
generated fluids
may include water which is vaporized within the formation. In addition, the
action of heating
kerogen produces pyrolysis fluids which tend to expand upon heating. The
produced
pyrolysis fluids may include not only water, but also, for example,
hydrocarbons, oxides of
carbon, ammonia, molecular nitrogen, and molecular hydrogen. Therefore, as
temperatures
within a heated portion of the formation increase, a pressure within the
heated portion may
also increase as a result of increased fluid generation, molecular expansion,
and vaporization
of water. Thus, some corollary exists between subsurface pressure in an oil
shale formation
and the fluid pressure generated during pyrolysis. This, in turn, indicates
that formation
pressure may be monitored to detect the progress of a kerogen conversion
process.
[0159] The pressure within a heated portion of an organic-rich rock formation
depends on
other reservoir characteristics. These may include, for example, formation
depth, distance
from a heater well, a richness of the formation hydrocarbons within the
organic-rich rock
formation, the degree of heating, and/or a distance from a producer well.
[0160] It may be desirable for the developer of an oil shale field to monitor
formation
pressure during development. Pressure within a formation may be determined at
a number of
different locations. Such locations may include, but may not be limited to, at
a wellhead and
at varying depths within a wellbore. In some embodiments, pressure may be
measured at a
producer well. In an alternate embodiment, pressure may be measured at a
heater well. In
still another embodiment, pressure may be measured downhole of a dedicated
monitoring
well.
-36-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0161] The process of heating an organic-rich rock formation to a pyrolysis
temperature
range not only will increase formation pressure, but will also increase
formation permeability.
The pyrolysis temperature range should be reached before substantial
permeability has been
generated within the organic-rich rock formation. An initial lack of
permeability may prevent
the transport of generated fluids from a pyrolysis zone within the formation.
In this manner,
as heat is initially transferred from a heater well to an organic-rich rock
formation, a fluid
pressure within the organic-rich rock formation may increase proximate to that
heater well.
Such an increase in fluid pressure may be caused by, for example, the
generation of fluids
during pyrolysis of at least some formation hydrocarbons in the formation.
[0162] Alternatively, pressure generated by expansion of pyrolysis fluids or
other fluids
generated in the formation may be allowed to increase. This assumes that an
open path to a
production well or other pressure sink does not yet exist in the formation. In
one aspect, a
fluid pressure may be allowed to increase to or above a lithostatic stress. In
this instance,
fractures in the hydrocarbon containing formation may form when the fluid
pressure equals
or exceeds the lithostatic stress. For example, fractures may form from a
heater well to a
production well. The generation of fractures within the heated portion may
reduce pressure
within the portion due to the production of produced fluids through a
production well.
[0163] Once pyrolysis has begun within an organic-rich rock formation, fluid
pressure
may vary depending upon various factors. These include, for example, thermal
expansion of
hydrocarbons, generation of pyrolysis fluids, rate of conversion, and
withdrawal of generated
fluids from the formation. For example, as fluids are generated within the
formation, fluid
pressure within the pores may increase. Removal of generated fluids from the
formation may
then decrease the fluid pressure within the near wellbore region of the
formation.
[0164] In certain embodiments, a mass of at least a portion of an organic-rich
rock
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. 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 Figure 5.
-37-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0165] Figure 5 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 F (about 400 C) on oil shale having a total organic
carbon content of
22 wt. % and a Fisher assay of 42 gallons/ton. Before the conversion, a total
of 16.5 ft3 of
rock matrix 52 existed. This matrix comprised 8.4 ft3 of mineral 53, i.e.,
dolomite, limestone,
etc., and 8.1 ft3 of kerogen 54 imbedded within the shale. As a result of the
conversion the
material expanded to 27.3 ft3 55. This represented 8.4 ft3 of mineral 56 (the
same number as
before the conversion), 6.6 ft3 of hydrocarbon liquid 57, 9.4 ft3 of
hydrocarbon vapor 58, and
2.9 ft3 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.
[0166] Figure 6 illustrates a schematic diagram of an embodiment of surface
facilities 70
that may be configured to treat a produced fluid. The produced fluid 85
produced from a
subsurface formation, shown schematically at 84, though a production well 71.
The produced
fluid 85 may include any of the produced fluids produced by any of the methods
as described
herein. The subsurface formation 84 may be any subsurface formation including,
for
example, an organic-rich rock formation containing any of oil shale, coal, or
tar sands for
example. In the illustrative surface facilities 70, the produced fluids are
quenched 72 to a
temperature below 300 F, 200 F, or even 100 F. This serves to separate out
condensable
components (i.e., oil 74 and water 75).
[0167] Produced fluids 85 from in situ oil shale production contain a number
of
components which may be separated in the surface facilities 70. The produced
fluids 85
typically contain water 78, noncondensable hydrocarbon alkane species (e.g.,
methane,
ethane, propane, n-butane, isobutane), noncondensable hydrocarbon alkene
species (e.g.,
ethene, propene), condensable hydrocarbon species composed of (alkanes,
olefins, aromatics,
and polyaromatics among others), C02, CO, H2, H2S, and NH3. In a surface
facility such as
facility 70, condensable components 74 may be separated from non-condensable
components
76 by reducing temperature and/or increasing pressure. Temperature reduction
may be
accomplished using heat exchangers cooled by ambient air or available water
72.
Alternatively, the hot produced fluids may be cooled via heat exchange with
produced
hydrocarbon fluids previously cooled. The pressure may be increased via
centrifugal or
reciprocating compressors. Alternatively, or in conjunction, a diffuser-
expander apparatus
may be used to condense out liquids from gaseous flows. Separations may
involve several
stages of cooling and/or pressure changes.
-38-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0168] In the arrangement of Figure 6, the surface facilities 70 include an
oil separator
73 for separating liquids, or oil 74, from hydrocarbon vapors, or gas 76. The
noncondensable
vapor components 76 are treated in a gas treating unit 77 to remove water 78
and sulfur
species 79. Heavier components are removed from the gas (e.g., propane and
butanes) in a
gas plant 81 to form liquid petroleum gas (LPG) 80. The LPG 80 may be placed
into a truck
or line for sale. Water 78 in addition to condensable hydrocarbons 74 may be
dropped out of
the gas 76 when reducing temperature or increasing pressure. Liquid water may
be separated
from condensable hydrocarbons 74 via gravity settling vessels or centrifugal
separators.
Demulsifiers may be used to aid in water separation.
[0169] The surface facilities also operate to generate electrical power 82 in
a power plant
88 from the remaining gas 83. The electrical power 82 may be used as an energy
source for
heating the subsurface formation 84 through any of the methods described
herein. For
example, the electrical power 82 may be fed at a high voltage, for example 132
kV, to a
transformer 86 and let down to a lower voltage, for example 6600 V, before
being fed to an
electrical resistance heater element 89 located in a heater well 87 in the
subsurface formation
84. In this way all or a portion of the power required to heat the subsurface
formation 84 may
be generated from the non-condensable portion 76 of the produced fluids 85.
Excess gas, if
available, may be exported for sale.
[0170] In an embodiment, heating a portion of an organic-rich rock formation
in situ to a
pyrolysis temperature may increase permeability of the heated portion. For
example,
permeability may increase due to formation of thermal 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. 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.
[0171] 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
-39-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
zone. Hydrocarbon fluids generated from pyrolysis may be produced from the
formation,
thereby further increasing the formation permeability.
[0172] 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 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.
[0173] In connection with the production of hydrocarbons from a rock matrix,
particularly those of shallow depth, a concern may exist with respect to earth
subsidence.
This is particularly true in the in situ heating of organic-rich rock where a
portion of the
matrix itself is thermally converted and removed. Initially, the formation may
contain
formation hydrocarbons in solid form, such as, for example, kerogen. The
formation may
also initially contain water-soluble minerals. Initially, the formation may
also be
substantially impermeable to fluid flow.
[0174] The in situ heating of the matrix pyrolyzes at least a portion of the
formation
hydrocarbons to create hydrocarbon fluids. This, in turn, creates permeability
within a
matured (pyrolyzed) organic-rich rock zone in the organic-rich rock formation.
The
combination of pyrolyzation and increased permeability permits hydrocarbon
fluids to be
produced from the formation. At the same time, the loss of supporting matrix
material also
creates the potential for subsidence relative to the earth surface.
[0175] In some instances, subsidence is sought to be minimized in order to
avoid
environmental or hydrogeological impact. In this respect, changing the contour
and relief of
the earth surface, even by a few inches, can change runoff patterns, affect
vegetation patterns,
and impact watersheds. In addition, subsidence has the potential of damaging
production or
-40-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
heater wells formed in a production area. Such subsidence can create damaging
hoop and
compressional stresses on wellbore casings, cement jobs, and equipment
downhole.
[0176] In order to avoid or minimize subsidence, it is proposed to leave
selected portions
of the formation hydrocarbons substantially unpyrolyzed. This serves to
preserve one or
more unmatured, organic-rich rock zones. In some embodiments, the unmatured
organic-rich
rock zones may be shaped as substantially vertical pillars extending through a
substantial
portion of the thickness of the organic-rich rock formation.
[0177] The heating rate and distribution of heat within the formation may be
designed
and implemented to leave sufficient unmatured pillars to prevent subsidence.
In one aspect,
heat injection wellbores are formed in a pattern such that untreated pillars
of oil shale are left
therebetween to support the overburden and prevent subsidence.
[0178] In some embodiments, compositions and properties of the hydrocarbon
fluids
produced by an in situ conversion process may vary depending on, for example,
conditions
within an organic-rich rock formation. Controlling heat and/or heating rates
of a selected
section in an organic-rich rock formation may increase or decrease production
of selected
produced fluids.
[0179] In one embodiment, operating conditions may be determined by measuring
at least
one property of the organic-rich rock formation. The measured properties may
be input into a
computer executable program. At least one property of the produced fluids
selected to be
produced from the formation may also be input into the computer executable
program. The
program may be operable to determine a set of operating conditions from at
least the one or
more measured properties. The program may also be configured to determine the
set of
operating conditions from at least one property of the selected produced
fluids. In this
manner, the determined set of operating conditions may be configured to
increase production
of selected produced fluids from the formation.
[0180] Certain heater well embodiments may include an operating system that is
coupled
to any of the heater wells such as by insulated conductors or other types of
wiring. The
operating system may be configured to interface with the heater well. The
operating system
may receive a signal (e.g., an electromagnetic signal) from a heater that is
representative of a
temperature distribution of the heater well. Additionally, the operating
system may be further
configured to control the heater well, either locally or remotely. For
example, the operating
-41-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
system may alter a temperature of the heater well by altering a parameter of
equipment
coupled to the heater well. Therefore, the operating system may monitor,
alter, and/or control
the heating of at least a portion of the formation.
[0181] In some embodiments, a heater well may be turned down and/or off after
an
average temperature in a formation may have reached a selected temperature.
Turning down
and/or off the heater well may reduce input energy costs, substantially
inhibit overheating of
the formation, and allow heat to substantially transfer into colder regions of
the formation.
[0182] Temperature (and average temperatures) within a heated organic-rich
rock
formation may vary, depending on, for example, proximity to a heater well,
thermal
conductivity and thermal diffusivity of the formation, type of reaction
occurring, type of
formation hydrocarbon, and the presence of water within the organic-rich rock
formation. At
points in the field where monitoring wells are established, temperature
measurements may be
taken directly in the wellbore. Further, at heater wells the temperature of
the immediately
surrounding formation is fairly well understood. However, it is desirable to
interpolate
temperatures to points in the formation intermediate temperature sensors and
heater wells.
[0183] In accordance with one aspect of the production processes of the
present
inventions, a temperature distribution within the organic-rich rock formation
may be
computed using a numerical simulation model. The numerical simulation model
may
calculate a subsurface temperature distribution through interpolation of known
data points
and assumptions of formation conductivity. In addition, the numerical
simulation model may
be used to determine other properties of the formation under the assessed
temperature
distribution. For example, the various properties of the formation may
include, but are not
limited to, permeability of the formation.
[0184] The numerical simulation model may also include assessing various
properties of
a fluid formed within an organic-rich rock formation under the assessed
temperature
distribution. For example, the various properties of a formed fluid may
include, but are not
limited to, a cumulative volume of a fluid formed in the formation, fluid
viscosity, fluid
density, and a composition of the fluid formed in the formation. Such a
simulation may be
used to assess the performance of a commercial-scale operation or small-scale
field
experiment. For example, a performance of a commercial-scale development may
be
assessed based on, but not limited to, a total volume of product that may be
produced from a
research-scale operation.
-42-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0185] In the present disclosure, methods for heating a subsurface formation
using
electrical resistance heating are provided. The resistive heat is generated
primarily from
electrically conductive material injected into the formation from wellbores.
An electrical
current is then passed through the conductive material so that electrical
energy is converted to
thermal energy. The thermal energy is transported to the formation by thermal
conduction to
heat the organic-rich rocks.
[0186] In one preferred embodiment of the current disclosure, conductive
granular
material is used as a downhole heating element. The granular heating element
is able to
withstand geomechanical stresses created during the formation heating process.
In this
respect, the granular material can readily change shape as needed without
losing electrical
connectivity. Thus, methods are provided herein for applying heat to a
subsurface formation
wherein a granular material provides a resistively conductive pathway between
electrically
conductive members within adjacent wellbores. However, non-granular conductive
material
such as conductive liquids that gel in place may be used.
[0187] Figure 7 is a perspective view of a hydrocarbon production area 700.
The
hydrocarbon production area 700 includes a subsurface formation 715. The
subsurface
formation 715 comprises organic-rich rock. In one instance the organic-rich
rock contains
kerogen.
[0188] A substantially vertical fracture 712 has been created within the
subsurface
formation 715. The fracture 712 is preferably hydraulically formed. The
fracture 712 is
propped with particles of an electrically conductive material (not shown in
Figure 7). In
accordance with the methods herein, an electrical current is sent through the
conductive
material to generate resistive heat within the formation 715.
[0189] Figure 7 demonstrates the heat 710 emanating from the fracture 712. In
order to
provide electrical current and generate the heat 710, a voltage 714 is applied
across two
adjacent wells 716 and 718. The fracture 712 intersects the wells 716, 718 so
that current
travels from a first well (such as well 716), through fracture 712, and to a
second well (such
as well 718).
[0190] Various ways of running current through the fracture 712 may be
arranged. In the
arrangement of Figure 7, an AC voltage 714 is preferred. This is because AC
voltage is
more readily generated and minimizes electrochemical corrosion as compared to
DC voltage.
-43-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
However, any form of electrical energy, including without limitation, DC
voltage, is suitable
for use in the methods herein.
[0191] In the example of Figure 7, a negative pole is set up at wellbore 716
while a
positive pole is set up at wellbore 718. Each wellbore 716, 718 has a
conductive member that
runs to the subsurface formation 715 to deliver current. An amount of
electrical current
sufficient to generate heat necessary to cause pyrolysis of solid hydrocarbons
is provided.
Kinetic parameters for Green River oil shale, for example, indicate that for a
heating rate of
100 C (180 F) per year, complete kerogen conversion will occur at a
temperature of about
324 C (615 F). Fifty percent conversion will occur at a temperature of about
291 C (555
F). Oil shale near the fracture will be heated to conversion temperatures
within months, but it
is likely to require several years to attain thermal penetration depths
required for generation
of economic reserves across a subsurface volume.
[0192] Within the fracture 712, the granular material acts as a heating
element. As
electric current is passed through the fracture 712, heat 710 is generated by
resistive heating.
Heat 710 is transferred by thermal conduction to the formation 715 surrounding
the fracture
712. As a result, the organic-rich rock within the formation 715 is heated
sufficiently to
convert kerogen to hydrocarbons. The generated hydrocarbons are then produced
using well-
known production methods.
[0193] In the arrangement of Figure 7, the formation 715 is shown primarily
along a
single vertical plane. Further, the heat 710 is shown emanating from the
fracture 712 within
that vertical plane. However, it is understood that the formation 715 is a
three-dimensional
subsurface volume, and that the heat 710 will conduct across a portion of that
volume.
[0194] As described above, Figure 7 depicts a heating process using a single
vertical
hydraulic fracture 712 and a pair of vertical wells 716, 718. In practice, a
number of wellbore
pairs 716, 718 would be completed with an intersecting fracture 712. However,
other
wellbore and completion arrangements may be provided. Examples include the use
of
horizontal wells and/or horizontal fractures. Commercial applications may
involve multiple
fractures with the placement of multiple wells in a pattern or line-drive
formation.
[0195] During the thermal conversion process, oil shale permeability is likely
to increase.
This may be caused by the increased pore volume available for flow as solid
kerogen is
converted to liquid or gaseous hydrocarbons. Alternatively, increased
permeability may
-44-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
result from the formation of fractures as kerogen converts to hydrocarbons and
undergoes a
substantial volume increase within a confined system. In this respect, if
initial permeability is
too low to allow release of the hydrocarbons, excess pore pressure will
eventually cause
fractures to develop. These are in addition to the hydraulic fractures
initially formed during
completion of the wellbores 716, 718.
[0196] Referring now to Figures 8A and 8B, alternate arrangements 800A, 800B
for
heating a subsurface formation are illustrated. First, Figure 8A shows a
hydrocarbon
production area 805A that includes a subsurface formation 815. The subsurface
formation
815 comprises organic-rich rock. An example of such an organic-rich rock is
oil shale.
[0197] In the arrangement of Figure 8A, a first plurality of wellbores 816 is
provided.
Each wellbore 816 has a vertical portion and a deviated, substantially
horizontal portion.
Heat is once again delivered via a plurality of hydraulic fractures propped
with particles of an
electrically conductive material. The fractures are shown at 812 and are
substantially
vertical. Each hydraulic fracture 812 is longitudinal (or runs along) the
horizontal portion of
the wells 816.
[0198] A separate second plurality of wells 818 is also provided in the
hydrocarbon
production area 800A. These wells 818 also have a substantially vertical
portion and a
substantially horizontal portion. The substantially horizontal portions of the
respective wells
818 intersect respective fractures 812.
[0199] In the arrangement of Figure 8A, a voltage is applied across pairs of
wells from
the first plurality 816 and the second plurality 818 of wells. The wells 816
in the first
plurality of wells comprise negative poles while the wells 818 in the second
plurality of wells
comprise positive poles. Of course, the reverse could also be established. A
voltage 814 is
applied across respective wells 816, 818 that penetrate the fractures 812.
Once again, an AC
voltage 814 is preferred. However, any form of electrical energy, including
without
limitation, DC voltage, is suitable for use in this invention.
[0200] The pairs of wells from the respective pluralities of wells 816, 818
make up
individual electrical circuits. The circuits are "completed" by placing
conductive granular
material within the fractures 812. This, in turn, generates heat via resistive
heating. This heat
is transferred by thermal conduction to organic-rich rock within the
subsurface formation
815. As a result, the organic-rich rock is heated sufficiently to convert
kerogen contained in
-45-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
the subsurface formation 815 to hydrocarbons. The generated hydrocarbons are
then
produced through production wells (not shown).
[0201] It is noted that the fractures 812 in Figure 8A are vertical.
Reciprocally, the
intersecting portion of the second plurality of wellbores 818 is horizontal.
However, it is
understood that this arrangement could be reversed. This means that the
fractures 812 may
be horizontal while the intersecting portion of the second plurality of
wellbores 818 is
vertical. In this latter arrangement it would not be necessary for the second
plurality of
wellbores 818 to be deviated. As a practical matter, the orientation of the
fractures may be
dependent on the depth of the subsurface formation. For example, some Green
River oil
shale formations completed at or above 1,000 feet tend to create horizontal
fractures while
formations completed below about 1,000 feet tend to create vertical fractures.
This, of
course, is highly dependent on the actual location and the geomechanical
forces at work.
[0202] Figure 8B shows a second hydrocarbon production area 805B that includes
a
subsurface formation 815. The subsurface formation 815 comprises organic-rich
rock which
may include kerogen. In the arrangement of Figure 8B, a first plurality of
wellbores 826 is
provided. Each wellbore 826 has a vertical portion and a deviated,
substantially horizontal
portion. Heat is once again delivered via a plurality of hydraulic fractures
propped with
particles of an electrically conductive material. The fractures are shown at
812 and are
substantially vertical. Each hydraulic fracture 812 is longitudinal (or runs
along) the
horizontal portion of the wells 826.
[0203] A separate second plurality of wells 828 is also provided in the
hydrocarbon
production area 800B. These wells 818 also have a substantially vertical
portion and a
substantially horizontal portion. The substantially vertical portions of the
respective wells
828 intersect respective fractures 812.
[0204] In the arrangement of Figure 8B, a voltage is applied across the first
plurality of
wells 826 to one of the second plurality of wells 828. The wells 826 in the
first plurality of
wells may comprise positive poles while the second well 828 may comprise a
negative pole.
Of course, the reverse could also be established. A voltage 824 is applied
across respective
wells 826, 828 that penetrate the fractures 812. Once again, an AC voltage 824
is preferred.
However, any form of electrical energy, including without limitation, DC
voltage, is suitable
for use in this invention.
-46-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0205] The wells 826, 828 work together to make up individual electrical
circuits. The
circuits are "completed" by placing conductive granular material within the
fractures 812.
This, in turn, generates heat via resistive heating. This heat is transferred
by thermal
conduction to organic-rich rock within the subsurface formation 815. As a
result, the
organic-rich rock is heated sufficiently to convert kerogen contained in the
subsurface
formation 815 to hydrocarbons. The generated hydrocarbons are then produced
through
production wells (not shown).
[0206] It is noted that the fractures 812 in Figure 8B are vertical.
Reciprocally, the
intersecting portion of the second plurality of wellbores 828 is horizontal.
In the production
area 800B, the horizontal portion of the second wellbores 828 intersect
fractures 812
associated with more than one fracture 812 from more than one horizontal
portion of the
respective first wellbores 826.
[0207] In either of production areas 800A, 800B, various materials may be used
as the
electrically conductive granular material. First, sands having a thin metal
coating may be
employed. Second, composite metal and ceramic materials may be used. Third,
carbon-
based materials may be employed. Each of these examples is not only conductive
but also
serves as a proppant. Several additional conductive materials may be used
which are less
desirable as proppants. One example is a conductive cement. Also, green or
black silicon
carbide, boron carbide, or calcined petroleum coke may be used as a proppant.
It is also
noted that combinations of the above materials may be utilized. In this
respect, the
electrically conductive material is not required to be homogeneous, but may
comprise a
mixture of two or more suitable electrically conductive materials. For
example, one or more
conductive materials that serve as proppants may be mixed with one or more
conductive
materials that are non-proppants in order to achieve a desired conductivity
while operating
within a designated budget.
[0208] Regardless of the composition, the conductive material preferably meets
several
criteria. First, the electrical resistivity of the granular material under
anticipated in situ
stresses is preferably high enough to provide resistive heating while also
being low enough to
conduct the planned electric current from one well to another. The granular
material also
preferably meets the usual criteria for fracture proppants, e.g., sufficient
strength to hold the
fracture open, and a low enough density to be pumped into the fracture.
Lastly, economic
-47-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
application of the process may set an upper limit on the cost of an acceptable
granular
material.
[0209] In each of production areas 800A, 800B, production wells are provided.
Illustrative production wells 840 are shown in Figure 8B. The production wells
840 are
completed in the subsurface formation 815 to transport hydrocarbon fluids to
the surface.
EXAMPLE
[0210] In order to demonstrate the transmission of current through a fracture
in an
organic-rich rock in order to generate resistive heat, a laboratory test was
conducted. Test
results showed that resistive heating using granular material successfully
transforms kerogen
in a laboratory specimen of rock into producible hydrocarbons.
[0211] Referring now to Figure 9 and Figure 10, a core sample 900 was taken
from a
kerogen-containing subterranean formation. The core sample 900 was a three-
inch long plug
of oil shale with a diameter of 1.39 inches. The bedding of the oil shale was
perpendicular to
the core 900 axis. As illustrated in Figure 9, core sample 900 was cut into
two portions 932
and 934. Upper face 936 lies on portion 932 while lower face 938 corresponds
to portion
934.
[0212] A tray 935 having a depth of about 0.25 mm ( 1/16 inch) was milled into
sample
portion 932 and a proxy proppant material 910 comprising #170 cast steel shot
having a
diameter of about 0.1 mm (0.02 inch) was placed in the tray 935. As
illustrated, a sufficient
quantity of conductive proppant material 910 to substantially fill tray 935
was used.
[0213] Electrodes 937 were placed at opposing ends of portion 932. The
electrodes 937
extend from outside the bounds of the core 900 into contact with proppant
material 910.
[0214] As shown in Figure 10, sample portions 932 and 934 were placed in
contact as if
to reconstruct the core sample 900. The core 900 was then placed in a
stainless steel sleeve
940 with portions 932 and 934 being held together with three stainless steel
hose clamps 942.
The hose clamps 942 were tightened to apply stress to the proxy proppant (seen
in Figure 9),
just as the proppant 910 would be required to support in situ stresses in a
real application.
The resistance between electrodes 937 was measured at 822 ohms before any
electrical
current was applied.
-48-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0215] A small hole (not shown) was drilled in one half of the sample 900 in
order to
accommodate a thermocouple. The thermocouple was used to measure the
temperature in the
core sample 900 during heating. The thermocouple was positioned roughly mid-
way
between tray 935 and the outer diameter of core sample 900.
[0216] The clamped core sample 900 was placed in a pressure vessel (not shown
in the
Figures) with a glass liner. The purpose of the glass liner was to collect
hydrocarbons
generated from the heating process. The pressure vessel was equipped with
electrical feeds.
The pressure vessel was evacuated and charged with Argon at 500 psi to provide
a
chemically inert atmosphere for the experiment. Electrical current in the
range of 18 to 19
amps was applied between electrodes 937 for 5 hours. The thermocouple in core
sample 900
measured a temperature of 268 C after about one hour, and thereafter tapered
off to about
250 C. The high temperature reached at the location of tray 935 was inferred
to be from
about 350 C to about 400 C.
[0217] After the experiment was completed and the core sample 900 had cooled
to
ambient temperature, the pressure vessel was opened. 0.15 ml of oil was
recovered from the
bottom of the glass liner in which the experiment was conducted. The core
sample 900 was
removed from the pressure vessel, and the resistance between electrodes 937
was again
measured. This post-experiment resistance measurement was 49 ohms.
[0218] During the heating period the power consumption, electrical resistance
and
temperature at the thermocouple embedded in the sample 900 were recorded.
Figure 11
provides graphs showing power consumption 1112, temperature 1122, and
electrical
resistance 1132 recorded as a function of time.
[0219] First, Figure 11 includes chart 1110. Chart 1110 has ordinate 1112
representing
the electrical power, in watts, consumed during the experiment. Chart 1110
also has abscissa
1114, which shows the elapsed time in minutes for the experiment. The total
time on the
abscissa 1114 was 5 hours (300 minutes). It can be seen from chart 1110 that
after one hour,
power applied to the core sample 900 ranged between 50 and 60 watts.
[0220] Next, Figure 11 includes chart 1120. Chart 1120 has ordinate 1122
representing
the temperature in degrees Celsius measured at the thermocouple in the core
sample 900
(Figures 9 and 10) throughout the experiment. Chart 1120 also has abscissa
1124 which
shows the elapsed time in minutes during the experiment. Again, the total time
is 5 hours. It
-49-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
is noted that the temperature 1122 reached a maximum value of 268 C during the
experiment. From this value it can be inferred that the temperature along the
tray 935 should
have reached a value of 350-400 C. This value is sufficient to cause
pyrolysis.
[0221] Finally, Figure 11 includes chart 1130. Chart 1130 has ordinate 1132
representing the resistance in ohms measured between electrodes 937 (Figures 9
and 10)
during the experiment. Chart 1130 also has abscissa 1134 which again shows the
elapsed
time in minutes during the experiment. Only resistance measurements made
during the
heating experiment are included in chart 1130. Of interest, after the initial
heat-up of the
sample 900, the resistance 1132 remained relatively constant between 0.15 and
0.2 ohms. At
no time during the experiment was a loss of electrical continuity observed.
The pre-
experiment and post-experiment resistance measurements (822 and 49 ohms) are
omitted.
[0222] After the core sample 900 cooled to ambient temperature, it was removed
from the
pressure vessel and disassembled. The conductive proppant material 910 was
observed to be
impregnated in several places with tar-like hydrocarbons or bitumen, which
were generated
from the oil shale during the experiment. A cross section was taken through a
crack that
developed in the core sample 900 due to thermal expansion during the
experiment. A
crescent shaped section of converted oil shale adjacent to the proxy proppant
910 was
observed.
[0223] Returning now to Figures 7, 8A and 8B, connections to the fracture
heating
element may be implemented in various ways. In each of these arrangements,
connection
points are provided between conductive metal devices along adjacent wellbores
to
intermediate conductive granular material within a fracture. Such point
connections are made
along vertical wellbores (Figure 7), at the heel of a horizontal wellbore
portion (Figure 8A),
at the toe of a horizontal wellbore portion (Figure 8B).
[0224] A concern arises with respect to each of these resistive heater-well
completion
arrangements 700, 800A, 800B. This concern relates to the potential for very
high electric
current density in the area where the wellbores intersect the conductive
granular material.
This concern applies to any of the completion arrangements of Figures 7, 8A
and 8B.
[0225] Electric current is an average quantity that describes the flow of
electrons along a
flow path. The SI unit for quantity of electricity or electrical charge is the
coulomb. The
coulomb is defined as the quantity of charge that has passed through the cross-
section of an
-50-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
electrical conductor carrying one ampere within one second. The symbol Q is
often used to
denote a quantity of electricity or charge.
[0226] Electric current may have a current density representing the electric
current per
unit area of cross section. In SI units, this may be expressed as Amperes/m2.
A current
density vector may be denoted as i and described mathematically:
i = ngVd = DVd
where i = current density vector (amperes/m2)
n = particle density in count per volume (M-3);
q = individual particles' charge (coulombs);
D = charge density (Coulombs/m3), or n q; and
vd = particles' average drift velocity (m/sec).
[0227] The presence of excessive current density at electrical contact points
downhole
may result in an inconsistent heat distribution within a subsurface formation
715 or 815. In
this respect, significant heating may occur primarily near the intersection of
the wellbores
with the granular material, leaving inadequate resistive heating within the
remainder of the
subsurface formation.
[0228] To address this issue, it is proposed herein to place a second type of
granular
material at or near the contact points downhole. This second type of granular
material has an
electrical conductivity that is different from the conductive granular
material in the bulk of
the fracture. Such an arrangement may operate in either of two ways. If the
second material
has a higher conductivity, it can operate by lowering the voltage drop across
a contact point
having a high current density. In this instance the high current density still
exists but it does
not lead to excessive local heat generation. Alternatively, if the second
material has a much
lower (even zero) conductivity, it can operate by changing the dominant
current pathways to
eliminate the area of high current density.
[0229] It is preferred to employ the first option wherein the second
conductive material
has a significantly higher conductivity than the conductive material in the
bulk of the
fracture. Preferably, the conductivity of the second conductive material is
about ten to 100
times higher than the conductivity of the granular material. In one aspect,
the bulk of a
-51-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
fracture is filled with calcined coke, while the conductive material
immediately at the
connection point comprises powdered metals, graphite, carbon black, or
combinations
thereof. Examples of powdered metals include powdered copper and steel.
[0230] For example, in an exemplary embodiment of the first option, e.g.,
where the
second conductive material has a significantly higher conductivity than the
conductive
material in the bulk of the fracture, the present inventors have determined
that granular
mixtures of graphite with up to 50% by weight cement produce suitable
resistivities. The
present inventors have determined that mixtures within this compositional
range are also 10 -
100 times more conductive than the granular proppant material. The present
inventors have
also determined that compositions with cement content above 50% by weight
increase
mixture resistivity above a preferred resistivity range. Water, which may be
added to control
the viscosity of the granular mixture, is typically added to the granular
mixture to aid in
adequate distribution of the conductive material into a proppant filled
fracture. The pack
thickness of the injected granular material may also be controlled by addition
or subtraction
of water to the granular mixture, e.g.,, more water will produce a thinner and
more widely
dispersed pack upon injection. Accordingly, the present inventors have
determined that the
granular mixtures within the aforementioned compositional ranges are
conductive enough to
not generate hot spots if used as the above-described second conductive
material.
[0231] For example, an exemplary composition for the above-described second
conductive material that has been determined to be suitable for use in the
vicinity of electrical
contact points downhole includes 10 g graphite (75% dry wt.), 3.3 g Portland
cement (25%
wt.), and 18 g water. In order to determine the differences in bulk
resistivity between a first
conductive material (representative of material within the fracture and
intermediate to any
electrical connections) and a second conductive material (the aforementioned
mixure of 10 g
graphite, 3.3 g Portland cement, and 18 g of water were injected between two
marble slabs
subjected to various loads and stress cured for 64 hours. The overall pack
thickness of the
second conductive material achieved was approximately 0.01" to approximately
0.028." The
resistivity of the second conductive material was approximately 0.1638 ohm cm,
which was
approximately 10-100 times more conductive than the surrounding proppant. The
resistivity
of two representative samples of the second conductive material are shown
below under
various loads in Table I. Sample A included a 25% by dry weight cement and 75%
by dry
weight graphite, and sample B included a 50% by dry weight cement and 50% by
dry weight
graphite. The resistivity of sample A was consistently lower than that of the
second sample
-52-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
across all subjected loads. While adequate resistivities were achieved in both
samples, a
preferred embodiment would include a mixture containing cement of less than or
equal to
50% by weight (dry), and equal to or greater than 50% by weight of graphite,
and more
preferably a mixture containing between 25-50% by weight (dry) of cement and
50-75% by
weight (dry) of graphite, or another electrically conductive material such as
granular metal,
metal coated particles, coke, graphite, and/or combinations thereof.
TABLE I
Resistivity (ohm cm)
load lbs load lbs load lbs load lbs load lbs load lbs
Sample ID 0 lbs 50 lbs 100 lbs 150 lbs 200 lbs 2501bs
A 0.11 0.09 0.08 0.07 0.07 0.07
B 0.45 0.19 0.14 0.12 0.10 0.10
[0232] In order to understand the utility of using a strategically placed
granular material
at the connection point, it is helpful to consider mathematical concepts
describing the flow of
current through a body. Figure 12 demonstrates a flow of current through a
fracture plane
1200 in a geological formation.. Arrows demonstrate current increments in the
x and y
directions for partial derivative equations. Arrow ix indicates electrical
current flowing in the
x direction while arrow iy indicates electrical current flowing in they
direction. Reference "t"
indicates the thickness of the fracture 1200 at a point (x, y).
[0233] In fracture plane 1200, current moves in the x direction from a first
point location
x to a second location x + dx. The current value changes from ix + dir.
Similarly, current
moves in the y direction from a first point location y to a second point
location y + dy. The
current value changes from iy to diy. If current enters or leaves the fracture
at the location (x,
y), this source term may be written as Q(x, y) and has units of Amperes/m2.
This represents a
source of current at a point in a fracture.
[0234] As current moves charge is conserved. Charge conservation is the
principle
that electric charge can neither be created nor destroyed; the quantity of
electric charge is
always conserved. According to the theory of conservation of charge, the total
electric
charge of an isolated system remains constant regardless of changes within the
system itself.
Conservation of charge may be expressed mathematically using partial
derivative equations:
-53-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
a(tix) a(tiy)
ax + ay = Q(x, Y)
wherein: ix = current in the x direction within the reservoir
iy = current in the y direction within the reservoir
t = thickness of a section of a reservoir
Q(x, y) = source of current at a point in a fracture
[0235] By Ohm's law:
-l aV -l aV
ix= P ax = iy P ay
wherein: p = resistivity of material in a reservoir
V = voltage of material
[0236] As noted, high heat generation may take place at the point connections
between
the metal conductors and the conductive granular material. A mathematical
process has been
developed for estimating the heat generation distribution for a fracture
having resistive heat.
This, in turn, allows for modeling of alternate methods for reducing heat
generation at the
downhole connection points.
[0237] A first step in this mathematical process is to provide a mapping of
the product of
conductivity and thickness. This may be expressed as:
t
P = conductivity x thickness
As will be graphically demonstrated below, this first mapping step is
conducted across the
plane of the fracture.
[0238] A next step in the process is to provide a mapping of the input and
output current.
These currents may be represented as:
Q(x, y)
-54-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
As will be graphically demonstrated below, this second mapping step is again
conducted
across the plane of the fracture.
[0239] The two mapping steps provide input maps. After the maps are created,
an
equation governing voltage can be solved based upon a voltage distribution in
the fracture.
An equation governing voltage may be expressed:
a t aV a t aV
ax (P ax) + ay (P ay) _ -Q(x, Y)
[0240] Once the voltage distribution has been calculated, a heating
distribution in the
fracture can be calculated. This is done from a heat generation equation, as
follows:
aV aV
h(x, y) t (ix ax + ix ay
[0241] Using the mathematical process described above, three different
examples or
"calculation scenarios" are provided herein to consider the problem of high
current density
around the power connections. The calculation scenarios involve an
approximately 90 foot
by 60 foot fracture filled with calcined coke as the granular conductant. The
fracture is 0.035
inches thick at its center, with its thickness decreasing toward its
periphery. Connections to
the granular material within the fracture are made with steel plates. The
current into and out
of the fracture is introduced through these plates.
[0242] Various figures are provided in connection with the three calculation
scenarios. In
some instances the figures include a legend which provides the resistivities
of the materials
used in the three calculations. In the legends, poke refers to the resistivity
of the bulk
proppant material used in all three scenarios; Pconnector refers to the
resistivity of the more
conductive material used around the connections in the second scenario; and
psteel, refers to
the resistivity of the steel plates. Of course, this is merely illustrative as
the plates could be
fabricated from conductive materials other than steel.
Simulation No. 1
[0243] As noted, a solution to the problem of high current density leading to
hot spots in
the formation is implemented by placing a first type of granular material in
the immediate
vicinity of the connection between the conductors and the conductive granular
material. To
demonstrate the efficacy of this approach, a first simulation was conducted in
which there
-55-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
was no intermediate material, meaning that the conductive granular material
was
homogeneous. Direct contact is provided between the steel plates and the
homogeneous
conductive material.
[0244] The results of the first simulation are demonstrated in Figures 13
through 17.
First, Figure 13 provides a thickness-conductivity map 1300 showing a plan
view of a
simulated fracture. The fracture is shown at 1310. The fracture 1310 is filled
with a
conductive proppant. In this simulation, coke is used as the conductive
proppant. The coke
has a resistivity (indicated at poke) of 0.001 ohm-m.
[0245] Two steel plates are shown at 1320 within the fracture 1310. These
represent a
left plate 1320L and a right plate 1320R. The plates 1320 are modeled as four
foot long
plates that are three inches wide by 1/2-inch thick. The coke surrounds and
immediately
contacts each of the steel plates 1320. The steel plates 1320 serve to deliver
current in the
fracture 1310 and through the coke. The resistivity of the plates 1320
(indicated at Psteei) is
0.0000005 ohm-m.
[0246] The map 1300 is gray-scaled to show the value of conductivity of the
granular
proppant multiplied by its thickness across the map 1300. This means that the
product of
conductivity and thickness (t / p) for the fracture 1310 is mapped across a
plan view of the
fracture 1320. The values are measured in amps/volt. The scale starts at 0 -
2,000 amps/volt,
and goes to 30,000 - 32,000 amps/volt. At this scale, the proppant in the
fracture 1310
entirely falls within the 0 - 2,000 amps/volt range. Stated another way, the
thickness-
conductivity product is consistent between 0 and 2,000 amps/volt.
[0247] The plates 1320 are highly conductive. Therefore, the thickness-
conductivity of
the plates 1320 shows in the 30,000 - 32,000 amps/volt range.
[0248] Figure 14 is another view of the thickness-conductivity map 1300 of
Figure 13.
The map 1300 is gray-scaled in finer increments of conductivity multiplied by
thickness to
distinguish variations in proppant conductivity-thickness within the fracture
1310. The scale
starts at 0.000 - 0.075 amps/volt, and goes to 1.125 - 1.200 amps/volt. At
this scale,
variations in the thickness-conductivity product within the fracture 1310
become evident. At
an outer ring, the thickness-conductivity product is within the smallest range
of the scale --
0.000 - 0.075 amps/volt. As one moves inward towards the center of the
fracture 1310,
-56-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
concentric bands of increasing thickness-conductivity product are seen. At the
center, the
thickness-conductivity value is about 0.825 to 0.900 amps/volt.
[0249] It is noted that the conductivity of the coke within the fracture 1310
is constant.
Therefore, the demonstrated variations are attributed to fracture thickness
variations. The
fracture 1310 is thin at the outer edge, and becomes increasingly thick
towards its center.
This tends to simulate actual fracture geometry.
[0250] The two steel plates 1320 are also seen in Figure 14. As noted in
connection with
Figure 13, the thickness-conductivity product of the plates 1320 falls in the
30,000 - 32,000
amps/volt range. Therefore, the plates 1320 are off of the chart in Figure 13
and simply
show up as being white.
[0251] Next, Figure 15 provides a current source map 1300. In this instance,
the map
1300 shows movement of current into and out of the fracture 1310. More
specifically,
Figure 15 shows the input and output current for the first simulation. As
indicated, the total
current into and out of the fracture 1310 is one ampere. In one aspect,
current goes into the
plate 1320L on the left, and leaves through the plate 1320R on the right.
[0252] Figure 15 includes a scale for current, in units of amps/ft2. The scale
runs from
-1.20 - -1.05 to 1.05 - 1.20. In between, the scale moves through -0.15 - 0.00
and 0.00 -
0.15. It can be seen that the current entering and leaving the fracture 1310
is 0.0 amps/ft2
except at the two steel plates 1320.
[0253] Figure 16 demonstrates a calculated voltage distribution in the
fracture 1310 from
the one ampere of total current. Lines with arrows are provided to indicate
the electrical
current flow, which follows the local voltage gradient. As indicated, the
total resistance of
the fracture 1310 between the two pieces of steel 1320 is 2.71 Ohms.
[0254] A scale is provided in Figure 16 measured in volts. The scale moves
from -1.6 -
-1.4 to 1.4 - 1.6. In between, the scale moves through -0.2 - 0.0 and 0.0 -
0.2 volts. It can
be seen that strongly negative voltage values exist immediately at the right
plate 1320R, and
strongly positive voltage values exist immediately at the left plate 1320L. It
can also be seen
that there is a higher concentration of current at the steel plates 1320.
[0255] Finally, Figure 17 demonstrates the resulting heating distribution in
the fracture
1310 from the first simulation. The units of the map 1300 are Watts/ft2. A
gray-scale is
-57-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
provided indicating values from 0 up to 16 Watts/ft2. As can be seen, the heat
distribution in
the map 1300 shows a total heat input of 1,000 Watts. 60 of the 1,000 Watts
(6% of the heat)
are generated within one foot of the ends of the plates 1320L, 1320R.
[0256] The heat generation in the simulated fracture 1310 declines rapidly
away from the
steel plates 1320. This indicates that much energy was lost at the plates 1320
without
generating sufficient heat to pyrolyze solid formation hydrocarbons that would
otherwise
reside in the formation. Six percent of the heat was generated in just 0.14%
of the fracture
area 1310. As a result, excessive heating was demonstrated to occur in the
immediate
vicinity of the steel plates 1320. Therefore, a modification is desired to
disperse heat away
from the plates 1320.
Simulation No. 2
[0257] A second simulation was conducted wherein an "intermediate material"
was
placed between the steel plates and the surrounding calcined coke. The
intermediate material
was a highly conductive material that was placed around the conductive
connections. The
"intermediate material" was simulated to have an electrical conductivity 100
times that of the
calcined coke, or a resistivity of 0.00001 Ohm-Meters. As will be shown, this
eliminated the
high voltage drop across the area of high current density around the
connection points,
effectively eliminating the excessive heating around the connection points.
[0258] The results of the second simulation are demonstrated in Figures 18
through 23.
First, Figure 18 provides a thickness-conductivity map 1800 showing a plan
view of a
simulated fracture. The fracture is shown at 1810. The fracture 1810 is again
filled with a
conductive proppant. In this simulation, coke is used as a primary conductive
proppant. The
coke again has a resistivity (indicated at pcoke) of 0.001 ohm-m.
[0259] Two steel plates are shown at 1820 within the fracture 1810. These
represent a
left plate 1820L and a right plate 1820R. The coke surrounds each of the steel
plates 1820.
The steel plates 1820 serve to deliver current in the fracture 1810 and
through the coke.
[0260] In this second simulation the coke does not immediately contact the
steel plates
1820; rather, a connecting granular material is used around the plates 1820.
The resistivity of
the connector material (indicated at peonnector) is 0.00001 ohm-m.
-58-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0261] The map 1800 is gray-scaled to show the value of conductivity of the
conductive
granular proppants 1820 multiplied by its thickness at various locations
across the map 1800.
This means that the product of conductivity and thickness (t / p) for the
fracture 1810 is
mapped across a plan view of the fracture 1820. The values are measured in
amps/volt. The
scale starts at 0 - 2,000 amps/volt, and goes to 30,000 - 32,000 amps/volt. At
this scale, the
proppants in the fracture 1810 entirely fall within the 0 - 2,000 amps/volt
range. Stated
another way, the thickness-conductivity product is consistent between 0 and
2,000 amps/volt.
[0262] The map 1800 of Figure 18 has been scaled to distinguish between the
conductive
granular proppant in the fracture 1810, and the two steel plates 1820 that
make up the
electrical connection. The legend in Figure 18 gives the resistivities of the
materials used in
the second simulation. The poke refers to the resistivity of the bulk proppant
material; the
Pconnector refers to the resistivity of the highly conductive material used
immediately around
the plates 1820L, 1820R; and, the psteel, refers to the resistivity of the
steel plates 1820.
[0263] The plates 1820 are once again modeled as four-foot-long, three-inch-
wide, and
/2-inch-thick plates. The plates 1820 are highly conductive, with the
thickness-conductivity
of the plates 1820 showing in the 30,000 - 32,000 amps/volt range. The plates
1820 show up
as being black.
[0264] Figure 19 is another view of the thickness-conductivity map 1800 of
Figure 18.
The map 1800 is gray-scaled in finer increments of conductivity multiplied by
thickness to
distinguish variations in proppant conductivity-thickness within the fracture
1810. The scale
starts at 0.00 - 2.50 amps/volt, and goes to 37.50 - 40.00 amps/volt. At this
scale, variations
in the thickness-conductivity product between the primary coke proppant and
the connector
proppant become evident. The conductivity-thickness product across most of the
fracture
1800 is within the smallest range of the scale -- 0.00 - 2.50 amps/volt.
However, concentric
rings of proppant having a higher conductivity-thickness product are visible
around the plates
1820L, 1820R. Immediately adjacent the plates 1820L, 1820R, the conductivity-
thickness
product is as high as 17.5 to 20.0 amps/volt. The rings dissipate away from
the plates 1820L,
1820R to about 7.5 to 10.0 amps/volt before dropping to the lowest range of
0.00 to 2.50
amps/volt within the coke.
[0265] Figure 20 is another view of the thickness-conductivity map 1800 of
Figure 18.
The map 1800 is gray-scaled in still further finer increments of conductivity
multiplied by
thickness to distinguish variations in proppant conductivity-thickness within
the primary
-59-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
proppant. The scale starts at 0.000 - 0.075 amps/volt, and goes to 1.125 -
1.200 amps/volt.
The conductivity-thickness product across the fracture 1810 is approximately
0.000 to 0.075
at the edge of the fracture 1810, and increases to about 0.675 to 0.750 at the
center of the
fracture 1810. However, concentric rings of proppant having a higher
conductivity-thickness
product are again visible. These rings show up white and are off the scale as
their
conductivity exceeds the highest range of 1.125 to 1.200.
[0266] In Figure 20 the plates 1820 cannot be distinguished from the
intermediate
proppant because they are "off the chart" as well, meaning the conductivity-
thickness product
is high.
[0267] It is noted that the conductivity of the coke within the fracture 1810
is constant.
Therefore, the demonstrated variations in conductivity-thickness product seen
in Figure 20
are attributed to fracture thickness variations. The fracture 1810 is thin at
the outer edge, and
becomes increasingly thick towards its center. This tends to simulate actual
fracture
geometry.
[0268] Next, Figure 21 provides a current source map 1800. In this instance,
the map
1800 shows movement of current into and out of the fracture 1810. More
specifically,
Figure 21 shows the input and output current for the second simulation. As
indicated, the
total current into and out of the fracture 1810 is one ampere. In one aspect,
current goes into
the plate 1820L on the left, and leaves through the plate 1820R on the right.
The current
entering and leaving the fracture 1810 is zero, except at the steel plates
1820R, 1820L.
[0269] Figure 21 includes a scale for current, in units of amps/ft2. The scale
runs from
-1.20 - -1.05 to 1.05 - 1.20. In between, the scale moves through -0.15 - 0.00
and 0.00 -
0.15. It can be seen that the current entering and leaving the fracture 1810
is 0.0 amps/ft2
except at the two steel plates 1820.
[0270] Figure 22 demonstrates a calculated voltage distribution in the
fracture 1810 from
the one ampere of total current. Lines with arrows are provided to indicate
the electrical
current flow, which follows the local voltage gradient. As indicated, the
total resistance of
the fracture 1810 between the two plates 1820 is 1.09 Ohms, indicating that
the higher
conductivity material around the plates 1820 has decreased the overall
resistance in the
fracture relative to the map 1300 of Figure 16.
-60-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0271] A scale is provided in Figure 22 measured in volts. The scale moves
from -0.64 -
-0.56 to 0.56 - 0.64. In between, the scale moves through -0.08 - 0.0 and 0.0 -
0.08 volts.
These ranges are lower than in the corresponding map 1300 of Figure 16. This
is because
total resistance in fracture plane 1810 is lower.
[0272] It can be seen in Figure 22 that negative voltage values exist
immediately at the
right plate 1820R, and positive voltage values exist immediately at the left
plate 1820L. Of
interest, current is still focused in the vicinity of the plates 1820, meaning
that there is a
higher concentration of current at the steel plates 1820. However, the current
pathways can
be seen to bend as they enter and leave the higher conductivity areas around
the plates 1820.
[0273] Finally, Figure 23 demonstrates the resulting heating distribution in
the fracture
1810 from the simulation. The units of the map 1800 are Watts/ft2. A gray-
scale is provided
indicating values from 0.0 - 0.2 up to 3.0 - 3.2 Watts/ft2. As can be seen,
the heat
distribution in the map 1800 shows a total heat input of 1,000 Watts. However,
only 3.3 of
the 1,000 Watts (0.33% of the heat) are generated within 1 foot of the ends of
the connecting
plates 1820L, 1820R. This is a substantial reduction in localized heat
generation over the
first simulation demonstrated in Figure 17, proving a more uniform heating of
the fracture
1810.
[0274] It is again noted that moderate heat is indicated at the respective
ends of the plates
1820L, 1820R. However, these heat areas do not reflect extensive heating
within the overall
fracture 1810 and provide no cause for concern.
Simulation No. 3
[0275] Next, a third simulation was conducted wherein a non-conductive
material was
used as the connecting granular material. The non-conductive material was
specifically
placed at the ends of the simulated steel plates. The non-conductive material
operates to
redirect current in the formation to mitigate excessive heating around the
steel connections.
This is another alternative method for eliminating the high heating in the
area of high current
density around the plates, effectively reducing the excessive heating
experienced in the first
simulation so that the fracture receives a more uniform heat distribution.
[0276] The results of the third simulation are demonstrated in Figures 24
through 28.
First, Figure 24 provides a conductivity map 2400 showing a plan view of a
simulated
fracture. The fracture is shown at 2410. The fracture 2410 is again filled
with a conductive
-61-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
proppant. In this simulation, coke is used as a primary conductive proppant.
The resistivity
of the coke (indicated at pcoke) is 0.001 ohm-m.
[0277] Two steel plates are shown at 2420 within the fracture 2410. These
represent a
left plate 2420L and a right plate 2420R. The coke surrounds each of the steel
plates 2420.
The steel plates 2420 serve to deliver current in the fracture 2410 and
through the coke.
[0278] In this third simulation the coke does not immediately contact all of
the steel
plates 2420; rather, an intermediate granular material is used around the
plates 2420 with
coke contacting the plates 2420 only at respective ends. In this instance, the
granular
material is substantially non-conductive. Thus, the resistivity of the coke is
0.001 ohm-m,
while the resistivity of the granular connector material (indicated at
peonneetor) is essentially
infinite.
[0279] The map 2400 is gray-scaled to show the value of conductivity of the
conductive
granular proppant multiplied by its thickness at various locations across the
map 2400. This
means that the product of conductivity and thickness (t / p) for the fracture
2410 is mapped
across a plan view of the fracture 2420. The values are measured in amps/volt.
[0280] The map 2400 of Figure 24 has been scaled to distinguish between the
coke in the
fracture 2410, and the two steel plates 2420 that make up the electrical
connection. The
legend in Figure 24 gives the resistivities of the materials used in all the
third simulation.
The peoke7 refers to the resistivity of the bulk proppant material; the
Pconnector refers to the
resistivity of the non-conductive granular material used around the connectors
2420L, 2420R
in the third simulation; and, the psteel, refers to the resistivity of the
steel plates 2420. The
scale starts at 0 - 2,000 amps/volt, and goes to 30,000 - 32,000 amps/volt. At
this scale, the
resistivity values for the proppant in the fracture 2410 (Pcoke) entirely fall
within the 0 - 2,000
amps/volt range. Stated another way, the thickness-conductivity product is
consistent
between 0 and 2,000 amps/volt.
[0281] In the third simulation, the plates 2420 are modeled as 27 feet long, 3
inches wide,
and 1/2-inch thick. Compared to the four-foot plates 1820 used in the second
simulation, the
plates 2420 of the third simulation are very long. This is because the
connecting granular
material used in the third simulation is substantially non-conductive. The
longer plates 2420
provide additional surface area through which current may travel into the
fracture 2410. The
plates 1820 are highly conductive, with the thickness-conductivity of the
plates 2420 showing
-62-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
in the 30,000 - 32,000 amps/volt range. The current into and out of the
fracture 2410 is
introduced through the plates 2420.
[0282] Figure 25 is another view of the conductivity map 2400 of Figure 24.
The map
2400 is gray-scaled in finer increments of conductivity multiplied by
thickness to distinguish
variations in proppant conductivity-thickness within the fracture 2410. The
scale starts at
0.000 - 0.075 amps/volt, and goes to 1.125 - 1.200 amps/volt. The conductivity-
thickness
product across the fracture 2410 is approximately 0.000 to 0.075 at the edge
of the fracture
2410, and increases to about 0.675 to 0.750 at the center of the fracture
1810. However,
concentric rings of substantially non-conductive proppant appear at ends of
the plates 2420L,
2420R. These rings show up almost white as their conductivity is zero.
[0283] The map 2400 of Figure 25 has been scaled to distinguish variations in
conductivity-thickness in the coke-filled bulk of the fracture 2410. The coke
proppant is
indicated at 2425. The conductivity of the coke proppant 2425 within the
fracture 2410 is
constant. Therefore, the demonstrated variations in conductivity-thickness
product are
attributed to fracture thickness variations. The fracture 2410 is thin at the
outer edge, and
becomes increasingly thick towards its center. This tends to simulate actual
fracture
geometry.
[0284] Figure 25 also shows where non-conductive material (t/p = 0) has been
emplaced
around the ends of the steel plates 2420L, 2420R. The non-conductive granular
material is
indicated at 2427. This non-conductive material 2427 interrupts the flow of
current from the
plates 2420L, 2420R to the bulk proppant 2425.
[0285] The plates 2420 are also visible in Figure 25. The extremely high
conductivity
plates 2420 show up in Figure 25 as white lines, indicating an off-scale
value.
[0286] Next, Figure 26 provides a current source map 2400. In this instance
the map
2400 shows movement of current into and out of the fracture 2410. More
specifically,
Figure 26 shows the input and output current for the third simulation. As
indicated, the total
current into and out of the fracture 2410 is one ampere. In one aspect,
current goes into the
connector 2420L on the left, and leaves through the connector 2420R on the
right. The
current entering and leaving the fracture 2410 is zero except at the steel
plates 2420R, 2420L.
-63-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
[0287] It is noted that the 27-foot length of the respective connectors 2420L
and 2420R
appears abbreviated in the view of Figure 26. This is because current is only
being supplied
near the ends of the plates 2420. It is noted that the exposed portion in each
of plate 2422L
and 2422R is shorter in Figure 26 than in Figure 25. This is indicative of
where the current
has been applied.
[0288] Figure 26 includes a scale for current, in units of amps/ft2. The scale
runs from -
1.20 - -1.05 to 1.05 - 1.20. In between, the scale moves through -0.15 - 0.00
and 0.00 -
0.15. It can be seen that the current entering and leaving the fracture 2410
is 0.0 amps/ft2
except at a portion of the two steel plates 2420 that are in contact with the
conductive
proppant.
[0289] Figure 27 demonstrates a calculated voltage distribution in the
fracture 2410 from
the one ampere of total current. Lines with arrows are provided to indicate
the electrical
current flow, which follows the local voltage gradient. As indicated, the
total resistance of
the fracture 2410 between the two plates 2420 is 2.39 Ohms. This is slightly
less than the
2.71 Ohms prevalent in Figure 16 from the first simulation. Thus, while the
non-conductive
connecting material 2427 around the ends of the plates 2420 should increase
the resistance
relative to the map 1300 of Figure 16, the steel plates are much longer, and
their impact is to
decrease the overall resistance of the fracture 2410.
[0290] A scale is provided in Figure 27 measured in volts. The scale moves
from -1.28 -
-1.12 to 1.12 - 1.28. In between, the scale moves through -0.16 - 0.0 and 0.0 -
0.16 volts.
[0291] It can be seen in Figure 27 that negative voltage values exist
immediately at the
right connector 2420R, and positive voltage values exist immediately at the
left connector
2420L. Of interest, current is still focused in the vicinity of the plates
2420, meaning that
there is a higher concentration of current at the steel plates 2420. However,
no current
pathways are seen in the areas where the non-conductive intermediate granular
material 2427
resides. The current must now go around the non-conductive material 2427,
effectively
mitigating the highly focused current of the first simulation.
[0292] Finally, Figure 28 demonstrates the resulting heating distribution in
the fracture
2410 from the simulation. The units of the map 2400 are measured in Watts/ft2.
A gray-
scale is provided indicating values from 0.0 - 0.2 up to 3.0 - 3.2 Watts/ft2.
As can be seen,
the heat distribution in the map 2400 in Figure 28 shows a total heat input of
1,000 Watts.
-64-
CA 02738873 2011-03-29
WO 2010/051093 PCT/US2009/055403
No areas of intense heat generation around the plates 2420L, 2420R are seen.
Indeed, heat
generation is essentially zero in the area where the non-conductive granular
material 2427 is
emplaced. However, the heating distribution is not nearly as uniform as the
heating
distribution seen in Figure 23 for the second simulation. For this reason, the
use of higher
conductivity material (as in the second simulation) rather than non-conductive
material (as in
the third simulation) is considered preferable.
[0293] The above-described processes may be of merit in connection with the
recovery of
hydrocarbons in the Piceance Basin of Colorado. Some have estimated that in
some oil shale
deposits 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. Overall, up to 1 trillion barrels of shale oil may exist in the
Piceance Basin alone.
[0294] 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.
[0295] 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.
-65-
