U.S. patent application number 13/866840 was filed with the patent office on 2013-11-07 for methods for containment and improved recovery in heated hydrocarbon containing formations by optimal placement of fractures and production wells.
The applicant listed for this patent is Lara E. Heister, Nazish Hoda, Michael W. Lin, William P. Meurer. Invention is credited to Lara E. Heister, Nazish Hoda, Michael W. Lin, William P. Meurer.
Application Number | 20130292114 13/866840 |
Document ID | / |
Family ID | 49511669 |
Filed Date | 2013-11-07 |
United States Patent
Application |
20130292114 |
Kind Code |
A1 |
Lin; Michael W. ; et
al. |
November 7, 2013 |
Methods For Containment and Improved Recovery in Heated Hydrocarbon
Containing Formations By Optimal Placement of Fractures and
Production Wells
Abstract
A method for containing and capturing liquids and gases
generated during in situ pyrolysis that migrate through pyrolysis
generated or natural fractures includes placing a row of horizontal
hydraulic fractures above and below the heated zone and completing
production wells within the horizontal hydraulic fractures. The
method serves at least two purposes: 1) provides a local zone of
weak mechanical strength to blunt the propagation of vertical
pyrolysis generated fractures and 2) provides a drainage point for
fluids to relieve pressure in the formation and improve recovery.
Preferably, the organic-rich rock formation is an oil shale
formation.
Inventors: |
Lin; Michael W.; (Houston,
TX) ; Heister; Lara E.; (Spring, TX) ; Hoda;
Nazish; (Houston, TX) ; Meurer; William P.;
(Pearland, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Lin; Michael W.
Heister; Lara E.
Hoda; Nazish
Meurer; William P. |
Houston
Spring
Houston
Pearland |
TX
TX
TX
TX |
US
US
US
US |
|
|
Family ID: |
49511669 |
Appl. No.: |
13/866840 |
Filed: |
April 19, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61642807 |
May 4, 2012 |
|
|
|
Current U.S.
Class: |
166/272.2 |
Current CPC
Class: |
E21B 43/2405
20130101 |
Class at
Publication: |
166/272.2 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method for producing hydrocarbon fluids from an organic-rich
rock formation, comprising: completing at least one heater well in
a heated zone in the organic-rich rock formation; completing a
production well; heating the heated zone of the organic-rich rock
formation from the at least one heater well, thereby pyrolyzing at
least a portion of the organic-rich rock into hydrocarbon fluids
and thereby creating thermal fractures in the organic-rich rock
formation due to thermal stresses created by heating; placing a
barrier to decrease the propagation of the thermal fractures
wherein placing the barrier comprises placing hydraulic horizontal
fractures above and/or below the heated zone from the production
well; and producing hydrocarbon fluids from the production
well.
2. The method of claim 1, wherein the organic-rich rock formation
is an oil shale formation.
3. The method of claim 2, wherein the thermal fractures are
substantially vertical.
4. The method of claim 2, further comprising: performing
geomechanical modeling to determine the direction and extent of
thermal fractures.
5. The method of claim 2, wherein the step of hydraulically
fracturing is performed before the step of heating the oil shale
formation.
6. The method of claim 2, wherein the step of hydraulically
fracturing is performed after the step of heating the oil shale
formation has begun, but before the substantial formation of
thermal fractures.
7. The method of claim 2, further comprising: determining a
distance from the production well in which to form the one or more
hydraulic fractures in order to provide fluid communication with
anticipated thermal fractures.
8. The method of claim 2, wherein the thermal fractures intersect
at least one of the hydraulically fractures within one year of
initiating heating.
9. The method of claim 2 wherein the step of heating results in at
least a portion of the oil shale formation reaching a temperature
of 270.degree. C. or greater.
10. The method of claim 2, further comprising introducing a
proppant material into one or more of the hydraulic fractures.
11. The method of claim 2, wherein the hydraulic fractures are
placed in the organic-rich rock formation.
12. The method of claim 2, wherein the hydraulic fractures are
placed in a formation above or below the organic-rich rock
formation.
13. The method of claim 2, wherein the production well is
horizontal.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the priority benefit of U.S.
Provisional Patent Application 61/642,807 filed 4 May 2012 entitled
Methods For Containment and Improved Recovery in Heated Hydrocarbon
Containing Formations By Optimal Placement of Fractures and
Production Wells, the entirety of which is incorporated by
reference herein.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to the field of hydrocarbon
recovery 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.
[0004] 2. Background of the Invention
[0005] Certain geological formations are known to contain an
organic matter known as "kerogen." Kerogen is a solid, carbonaceous
material. When kerogen is imbedded in 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.
[0006] 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. 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.
[0007] Oil shale formations are found in various areas world-wide,
including the United States. Oil shale formations tend to reside at
relatively shallow depths. In the United States, oil shale is most
notably found in Wyoming, Colorado, and Utah. These U.S. formations
are often characterized by limited permeability. A significant oil
shale formation is also located in Jordan; this formation is
characterized by a higher permeability than the U.S. formations.
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.
[0008] The decomposition rate of kerogen to produce mobile
hydrocarbons is temperature dependent. Temperatures generally in
excess of 270.degree. C. (518.degree. 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, 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.
[0009] 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 as Australia,
Brazil, China, Estonia, France, Russia, South Africa, Spain, and
Sweden. However, the practice has been mostly discontinued in
recent years because it proved to be uneconomical or because of
environmental constraints on spent shale disposal. (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 application to very shallow formations.
[0010] 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.
[0011] 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 to
distill and produce hydrocarbons. The '195 Ljungstrom patent is
incorporated herein by reference.
[0012] Ljungstrom coined the phrase "heat supply channels" to
describe bore holes drilled into the formation. The bore holes
received an electrical heat conductor which transferred heat to the
surrounding oil shale. Thus, the heat supply channels served as
heat injection wells. 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 500.degree. and 1,000.degree. C. in some
applications.
[0013] Along with the heat injection wells, fluid producing wells
were also completed in near proximity to the heat injection wells.
As kerogen was pyrolyzed upon heat conduction into the rock matrix,
the resulting oil and gas would be recovered through the adjacent
production wells.
[0014] 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," 2.sup.nd Oil Shale and Cannel Coal Conference, v. 2,
Glasgow, Scotland, Institute of Petroleum, London, p. 260-280
(1951), the entire disclosure of which is incorporated herein by
reference.
[0015] Additional in situ methods have been proposed. These methods
generally involve the injection of heat and/or solvent into a
subsurface oil shale. 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, Ill.)
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 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)
[0016] In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil
Company, the entire disclosure of which is incorporated herein by
reference. That patent, entitled "Conductively Heating a
Subterranean Oil Shale to Create Permeability and Subsequently
Produce Oil," declared that "[c]ontrary to the implications of . .
. prior teachings and beliefs . . . the presently described
conductive heating process is economically feasible for use even in
a substantially impermeable subterranean oil shale." (col. 6, ln.
50-54). Despite this declaration, it is noted that few, if any,
commercial in situ shale oil operations have occurred other than
Ljungstrom's application. The '118 patent proposed controlling the
rate of heat conduction within the rock surrounding each heat
injection well to provide a uniform heat front.
[0017] Additional history behind oil shale retorting and shale oil
recovery can be found in co-owned patent publication WO 2005/010320
entitled "Methods of Treating a Subterranean Formation to Convert
Organic Matter into Producible Hydrocarbons," and in patent
publication WO 2005/045192 entitled "Hydrocarbon Recovery from
Impermeable Oil Shales." The Background and technical disclosures
of these two patent publications are incorporated herein by
reference.
[0018] In situ oil shale processes involve heating a rock formation
to pyrolysis temperatures to convert kerogen in the oil shale to
oil and gas products. Containment of generated fluids in in situ
oil shale conversion processes is critical for preventing
contamination of sensitive areas and improving oil recovery. Fluids
can migrate from the heated zone through generated and natural
fractures. Fractures can be generated from thermal gradients that
develop in the rock formation from the heating process that create
tensile stress zones, thereby facilitating the initiation of
fractures. Fractures can also be generated or propagated by
increases in pore pressure in the system from the generated fluids.
Porous and permeable overburden and underburden rocks can also
facilitate the migration of generated fluids from the heated zone
and into sensitive areas, such as aquifers. Thus, it becomes
critical to develop methods to contain the fractures to prevent
contamination of sensitive areas and to improve product
recovery.
[0019] A need exists for improved processes for the production of
shale oil. In addition, a need exists for an improved method of
increasing shale oil recovery and to prevent contamination of
sensitive areas.
SUMMARY OF THE INVENTION
[0020] In one embodiment, the invention provides a method for
producing hydrocarbon fluids from an organic-rich rock formation.
Preferably, the organic rich rock formation comprises solid
hydrocarbons. More preferably, the organic rich rock formation is
an oil shale formation.
[0021] An embodiment of this invention is a method for containing
and capturing liquids and gases generated during in situ pyrolysis
that migrate through pyrolysis generated or natural fractures. The
pyrolysis generated fractures can be horizontal or vertical
depending on the heater configuration, in situ stress state,
reservoir properties, and other factors. In shallow reservoirs,
vertical fractures can be created and propagate to the surface
and/or to the underburden/overburden, potentially creating a
pathway for the contamination of the surface and aquifers. This
method involves placing a row of horizontal hydraulic fractures
above and below the heated zone and completing production wells
within the horizontal hydraulic fractures. The method serves at
least two purposes: 1) provides a local zone of weak mechanical
strength to blunt the propagation of vertical pyrolysis generated
fractures and 2) provides a drainage point for fluids to relieve
pressure in the formation and improve recovery.
[0022] As an additional step, a proppant material may be introduced
into one or more of the hydraulic fractures. As yet an additional
step, hydrocarbons fluids may be produced from the production
well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] So that the manner in which the features of the present
invention can be better understood, certain drawings, graphs and
flow charts are appended hereto. It is to be noted, however, that
the drawings illustrate only selected embodiments of the inventions
and are therefore not to be considered limiting of scope, for the
inventions may admit to other equally effective embodiments and
applications.
[0024] FIG. 1 is a cross-sectional view of an illustrative
subsurface area. The subsurface area includes an organic-rich rock
matrix that defines a subsurface formation.
[0025] FIG. 2 is a cross-sectional view of an illustrative
subsurface area. The subsurface area includes a heated zone in an
organic-rich rock matrix and illustrates vertical fractures
originating from the heated zone.
[0026] FIG. 3 is a cross-sectional view of the illustrative
subsurface area of FIG. 2 in which horizontal hydraulic fractures
have been created above and below the heated zone.
[0027] FIG. 4 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.
[0028] FIG. 5 is a graph illustrating vertical normal stress as a
function of distance from a heater in a thermal-mechanical
simulation.
[0029] FIG. 6 is thermal-mechanical simulation indicating tensile
stress zones of a core sample with a planar heater.
[0030] FIG. 7 is a cross-section showing induced thermal fractures
in a core sample with a planar heater.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0031] 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.
[0032] 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.degree. C. and 1 atm pressure). Hydrocarbon fluids may include,
for example, oil, natural gas, coalbed methane, shale oil,
pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and
other hydrocarbons that are in a gaseous or liquid state.
[0033] 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.
Produced fluids may include both hydrocarbon fluids and
non-hydrocarbon fluids. 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.
[0034] As used herein, the term "condensable hydrocarbons" means
those hydrocarbons that condense at 25.degree. C. and one
atmosphere absolute pressure. Condensable hydrocarbons may include
a mixture of hydrocarbons having carbon numbers greater than 4.
[0035] As used herein, the term "non-condensable hydrocarbons"
means those hydrocarbons that do not condense at 25.degree. C. and
one atmosphere absolute pressure. Non-condensable hydrocarbons may
include hydrocarbons having carbon numbers less than 5.
[0036] As used herein, the term "heavy hydrocarbons" refers to
hydrocarbon fluids that are highly viscous at ambient conditions
(15.degree. C. and 1 atm pressure). Heavy hydrocarbons may include
highly viscous hydrocarbon fluids such as heavy oil, tar, and/or
asphalt. Heavy hydrocarbons may include carbon and hydrogen, as
well as smaller concentrations of sulfur, oxygen, and nitrogen.
Additional elements may also be present in heavy hydrocarbons in
trace amounts. Heavy hydrocarbons may be classified by API gravity.
Heavy hydrocarbons generally have an API gravity below about 20
degrees. Heavy oil, for example, generally has an API gravity of
about 10-20 degrees, whereas tar generally has an API gravity below
about 10 degrees. The viscosity of heavy hydrocarbons is generally
greater than about 100 centipoise at 15.degree. C.
[0037] 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.
[0038] 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.
[0039] As used herein, the term "tar" refers to a viscous
hydrocarbon that generally has a viscosity greater than about
10,000 centipoise at 15.degree. C. The specific gravity of tar
generally is greater than 1.000. Tar may have an API gravity less
than 10 degrees. "Tar sands" refers to a formation that has tar in
it.
[0040] 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.
[0041] As used herein, the term "bitumen" refers to a
non-crystalline solid or viscous hydrocarbon material that is
substantially soluble in carbon disulfide.
[0042] As used herein, the term "oil" refers to a hydrocarbon fluid
containing a mixture of condensable hydrocarbons.
[0043] As used herein, the term "subsurface" refers to geologic
strata occurring below the earth's surface.
[0044] 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.
[0045] 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.
[0046] 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" and/or an
"underburden" is geological material above or 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.
[0047] 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.
[0048] 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.
[0049] As used herein, the term "water-soluble minerals" refers to
minerals that are soluble in water. Water-soluble minerals include,
for example, nahcolite (sodium bicarbonate), soda ash (sodium
carbonate), dawsonite (NaAl(CO.sub.3)(OH).sub.2), or combinations
thereof. Substantial solubility may require heated water and/or a
non-neutral pH solution.
[0050] As used herein, the term "formation water-soluble minerals"
refers to water-soluble minerals that are found naturally in a
formation.
[0051] As used herein, the term "migratory contaminant species"
refers to species that are both soluble and movable in water or an
aqueous fluid, and are considered to be potentially harmful or of
concern to human health or the environment. Migratory contaminant
species may include inorganic and organic contaminants. Organic
contaminants may include saturated hydrocarbons, aromatic
hydrocarbons, and oxygenated hydrocarbons. Inorganic contaminants
may include metal contaminants, and ionic contaminants of various
types that may significantly alter pH or the formation fluid
chemistry. Aromatic hydrocarbons may include, for example, benzene,
toluene, xylene, ethylbenzene, and tri-methylbenzene, and various
types of polyaromatic hydrocarbons such as anthracenes,
naphthalenes, chrysenes and pyrenes. Oxygenated hydrocarbons may
include, for example, alcohols, ketones, phenols, and organic acids
such as carboxylic acid. Metal contaminants may include, for
example, arsenic, boron, chromium, cobalt, molybdenum, mercury,
selenium, lead, vanadium, nickel or zinc. Ionic contaminants
include, for example, sulfides, sulfates, chlorides, fluorides,
ammonia, nitrates, calcium, iron, magnesium, potassium, lithium,
boron, and strontium.
[0052] As used herein, the term "cracking" refers to a process
involving decomposition and molecular recombination of organic
compounds to produce a greater number of molecules than were
initially present. In cracking, a series of reactions take place
accompanied by a transfer of hydrogen atoms between molecules. For
example, naphtha may undergo a thermal cracking reaction to form
ethene and H.sub.2 among other molecules.
[0053] As used herein, the term "sequestration" refers to the
storing of a fluid that is a by-product of a process rather than
discharging the fluid to the atmosphere or open environment.
[0054] As used herein, the term "subsidence" refers to a downward
movement of a surface relative to an initial elevation of the
surface.
[0055] 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.
[0056] 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.
[0057] 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. The fracture may be artificially held open by
injection of a proppant material. Hydraulic fractures may be
substantially horizontal in orientation, substantially vertical in
orientation, or oriented along any other plane.
[0058] As used herein, the term, "underburden" refers to the
sediments or earth materials underlying the formation containing
one or more hydrocarbon-bearing zones.
[0059] 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."
DESCRIPTION OF SPECIFIC EMBODIMENTS
[0060] 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.
[0061] 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 oil shale. In some embodiments of the
invention the natural resources may also include water-soluble
minerals, including, for example, nahcolite (sodium bicarbonate, or
2NaHCO.sub.3), soda ash (sodium carbonate, or Na.sub.2CO.sub.3) and
dawsonite (NaAl(CO.sub.3)(OH).sub.2).
[0062] An embodiment of this invention is a method for containing
and capturing liquids and gases generated during in situ pyrolysis
that migrate through pyrolysis generated or natural fractures. The
pyrolysis generated fractures can be horizontal or vertical
depending on the heater configuration, in situ stress state,
reservoir properties, and other factors. In shallow reservoirs,
vertical fractures can be created and propagate to the surface
and/or to the underburden/overburden, potentially creating a
pathway for the contamination of the surface and aquifers. This
method involves placing a row of horizontal hydraulic fractures
above and below the heated zone and completing production wells
within the horizontal hydraulic fractures. The method serves at
least two purposes: 1) provides a local zone of weak mechanical
strength to blunt the propagation of vertical pyrolysis generated
fractures and 2) provides a drainage point for fluids to relieve
pressure in the formation and improve recovery. A proppant material
may be introduced into the one or more hydraulic fractures.
[0063] The depth of the hydrocarbon containing formation plays a
role in the containment strategy. In shallow reservoirs, such as
oil shale reservoirs in Jordan and Rundle, Australia, the in situ
stress state will favor the creation of horizontal fractures for
containment. In deep reservoirs, such as the Piceance Basin, Colo.,
the stress state will favor the creation of vertical fractures.
Vertical fractures would not be ideal for containment as the areal
coverage would be limited. Instead, containment should involve
conventional methods to produce horizontal fractures in stress
states favoring vertical fractures, discussed in patent U.S. Pat.
No. 3,613,785 and incorporated by reference herein. An alternative
method would be to drill a horizontal production well and notch
and/or perforate from the horizontal well, as is known to one of
ordinary skill in the art, and thereby create a number of cavities
that may intersect the pyrolysis generated or natural fractures and
serve to blunt their propagation and/or provide a drainage point
for production of produced hydrocarbons.
[0064] The geology of the over- and underburden to the in situ
pyrolysis can also be taken into account by choosing a
stratigraphic interval that aids in the containment. For example,
the presence of relatively impermeable layers, such as, for example
shales, chert and basalt, that are just above the fractured horizon
will help to confine the fluid in the pyrolysis generated and/or
natural fracture(s). This confinement will act in concert with
production wells by limiting the ability of the liquids and gases
to migrate out of the production zone as they move toward the
producing well.
[0065] Sections of the stratigraphy might also be selected to
optimize the process of horizontal fracturing. This could be done
by selecting a horizon for fracturing that has a lithologic contact
between a relatively strong and weak rock types such as chert and
clay-rich mudstone. Alternatively, the hydraulic fractures might be
placed along a horizon that represents a substantial hiatus in
deposition and therefore limited mechanical bonding between the
rock packages above and below the hiatus.
[0066] Choosing an optimal lithologic setting can also be helpful
when a horizontal hydraulic fracture is to be generated in a stress
state were vertical fractures are favored. It is possible to define
settings that would respond favorably to either notching or
perforating efforts to create the horizontal barrier. For example,
notching geometry could be improved by initiating the notch in a
layer of rock that is readily notched (e.g., a weakly cemented
sandstone) but is bounded by layers that resist notching (e.g., a
carbonate mudstone).
[0067] FIG. 1 presents a perspective view of an illustrative oil
shale development area 10. A surface 12 of the development area 10
is indicated. Below the surface is an organic-rich rock formation
16. The illustrative 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
non-permeable. The present inventions are particularly advantageous
in oil shale development areas initially having very limited or
effectively no fluid permeability.
[0068] In order to access formation 16 and recover natural
resources therefrom, a plurality of wellbores is formed. Wellbores
are shown at 14 in FIG. 1. The representative wellbores 14 are
essentially vertical in orientation relative to the surface 12.
However, it is understood that some or all of the wellbores 14
could deviate into an obtuse or even horizontal orientation. In the
arrangement of FIG. 1, each of the wellbores 14 is completed in the
oil shale formation 16. The completions may be either open or cased
hole. The well completions may also include propped or unpropped
hydraulic fractures emanating therefrom.
[0069] In the view of FIG. 1, only seven wellbores 14 are shown.
However, it is understood that in an oil shale development project,
numerous additional wellbores 14 will most likely be drilled. The
wellbores 14 may be located in relatively close proximity, being
from 10 feet to up to 300 feet in separation. 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 of an oil shale
formation may occur at depths between 500 and 2,500 feet.
[0070] 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. Suitable tools
and equipment may be sequentially run into and removed from the
wellbores 14 to serve the various purposes.
[0071] 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 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.
[0072] Referring to FIGS. 2 and 3, illustrated is an exemplary
embodiment of hydrocarbon development area 200 containing formation
202 comprising an in situ heated zone 204. The heated zone 204 may
be heated by any type of in situ heating method, such as planar
electric resistive heaters, wellbore heaters, in situ combustion,
electric resistive heaters, etc., which may collectively be
referred to as heat injection wells. The in situ heating of the
hydrocarbon containing formation 202 has generated vertical
fractures 206 that extend through the hydrocarbon containing
formation and into the underburden 208 and overburden 210. The
generated vertical fractures 206 nearly extend into an aquifer 212
that is located below the underburden 208.
[0073] Referring to FIG. 3, illustrated is an exemplary embodiment
of the invention in which horizontal hydraulic fractures 214 and
216 have been created in the overburden 210 and underburden 208,
respectively. Horizontal hydraulic fractures 214 in the overburden
210 are shown in this embodiment to be created with vertical
wellbores 218. The hydraulic fractures 214 may be created with
other wellbore arrangements, including a single vertical wellbore,
or with the use of a deviated or horizontal wellbore. Horizontal
hydraulic fractures 216 in the underburden 208 are shown in this
embodiment to be created with horizontal wellbore 220, which in
this embodiment allows the vertical portion 222 of the horizontal
wellbore 220 to be placed outside of the heated zone 204. After
wellbores 218 and 220 create the horizontal hydraulic fractures,
the wellbores may later be used as production wells to produce
hydrocarbon fluids that have traveled through the generated
vertical fractures 206 to reach the horizontal hydraulic fractures.
This method of creating horizontal hydraulic fractures in the
overburden and/or underburden to intersect the generated vertical
fractures serves at least two purposes: 1) provides a local zone of
weak mechanical strength to blunt the propagation of vertical
pyrolysis generated fractures so that the vertical fractures do not
reach an aquifer, the surface, or other environmentally sensitive
area; and 2) provides a drainage point for fluids to relieve
pressure in the formation and improve recovery. A proppant material
may be introduced into the one or more hydraulic fractures.
[0074] In other embodiments, the hydraulic fractures 216 may be
created with other wellbore arrangements, including a single
vertical wellbore, or with the use of a deviated or horizontal
wellbore. For example, the hydraulic fractures in the underburden
could be created with vertical wellbores before the creation of a
heated zone, and then one or more of the vertical wellbores that
were used to create the hydraulic fractures could be converted to
either a producing well or a heater well. Furthermore, although the
horizontal fractures are indicated to be in the overburden and/or
the underburden, horizontal fractures could be placed either
alternatively or in addition to, in the hydrocarbon containing
formation, such as in an oil shale formation. In addition, in some
embodiments of the invention, it may be desirable to place
hydraulic vertical fractures to intersect possible horizontal or
vertical heat or pyrolysis generated fractures.
[0075] In order to recover oil, gas, and sodium (or other)
water-soluble minerals, a series of steps may be undertaken. FIG. 4
presents a flow chart demonstrating a method of in situ thermal
recovery of oil and gas from an organic-rich rock formation 400, in
one embodiment. It is understood that the order of some of the
steps from FIG. 4 may be changed, and that the sequence of steps is
merely for illustration. For convenience, use of some of the
terminology and reference numerals from FIG. 1 is provided in the
following discussion.
[0076] First, the oil shale (or other organic-rich rock) formation
16 is identified within the development area 10. This step is shown
in box 410. 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 fluid hydrocarbon-generating capability.
[0077] Based on the above study of the geology of the oil shale
formation and the overlying and underlying formations, the optimal
placement of the hydraulic fractures may be determined. For
example, determining the optimal placement of the hydraulic
fractures may be based on the anticipated extent of the heat or
pyrolysis generated fractures. This step is shown in box 412.
[0078] 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.
[0079] Next, a plurality of wellbores 14 is formed across the
targeted development area 10. This step is shown schematically in
box 415. The purposes of the wellbores 14 are set forth above and
need not be repeated. However, it is noted that for purposes of the
wellbore formation step of box 415, 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. It may be
desirable to also establish the hydraulic fractures prior to
heating the formation. Production wells may be brought in once
conversion begins, such as after 4 to 12 months of heating.
[0080] 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 420.
[0081] 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 430. Preferably, for in situ processes
the heating of a production zone takes place over a period of
months, or even four or more years.
[0082] 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.degree. C. to
800.degree. C. Alternatively, the targeted volume of the
organic-rich formation is heated to at least 350.degree. C. to
create production fluids. The conversion step is represented in
FIG. 4 by box 435. 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 naptha. Generated gases include light alkanes,
light alkenes, H.sub.2, CO.sub.2, CO, and NH.sub.3.
[0083] 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 430 and
435, 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 435 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.
[0084] In connection with the heating step 430, the rock formation
16 may create vertical and/or horizontal fractures that may aid
heat transfer or later hydrocarbon fluid production. As mentioned
above, these heat or pyrolysis generated fractures may also aid in
the transportation of contaminants to the surface or to aquifers in
the underburden and/or overburden. In order to prevent the heat or
pyrolysis generated vertical fractures from providing a pathway to
the surface or to aquifers in the underburden and/or overburden, a
hydraulic fracturing step provides horizontal fractures that will
intersect the heat or pyrolysis generated vertical fractures before
the vertical fractures reach an aquifer or the surface. This
hydraulic fracturing step is shown in box 425. 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. This method of creating horizontal hydraulic fractures in
the hydrocarbon containing formation, the overburden and/or the
underburden, to intersect the generated vertical fractures serves
at least two purposes: 1) the horizontal hydraulic fractures
provide a local zone of weak mechanical strength to blunt the
propagation of vertical pyrolysis generated fractures so that the
vertical fractures do not reach an aquifer, the surface, or other
environmentally sensitive area; and 2) the horizontal hydraulic
fractures provide a drainage point for fluids to relieve pressure
in the formation and improve recovery.
[0085] Pyrolysis or heat generated 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 is
increased via thermal fracture formation and subsequent production
of a portion of the hydrocarbon fluids generated from the
kerogen.
[0086] As part of the hydrocarbon fluid production process 400,
certain wells 14 may be designated as oil and gas production wells.
This step is depicted by box 440. 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 430) have been in
operation for a period of several weeks or months. Thus, box 440
may include the formation of additional wellbores 14. In other
instances, selected heater wells or hydraulic fracturing wells are
converted to production wells.
[0087] 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 445. At
this stage (box 445), 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 435) within the formation.
[0088] Box 450 presents an optional next step in the oil and gas
recovery method 400. 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 450 may include the drilling of yet additional wellbores 14 for
use as dedicated water injection wells. In this respect, it may be
desirable to complete water injection wells along a periphery of
the development area 10 in order to create a boundary of high
pressure.
[0089] 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 455. 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.
[0090] 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 460. 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 465. Alternatively, single wellbores may be used to both inject
water and then to recover a sodium mineral solution. Thus, box 465
includes the option of using the same wellbores 14 for both water
injection and solution production (box 465).
[0091] In connection with heating the organic-rich rock formation,
the organic-rich rock formation may fracture naturally by creating
thermal fractures within the formation through application of heat.
Thermal fracture formation is caused by thermal expansion of the
rock and fluids and by chemical expansion of kerogen transforming
into oil and gas. Thermal fracturing can occur both in the
immediate region undergoing heating, and in cooler neighboring
regions.
[0092] The thermal fracturing in the neighboring regions is due to
propagation of fractures and tension stresses developed due to the
expansion in the hotter zones. Thus, by both heating the
organic-rich rock and transforming the kerogen to oil and gas, the
permeability is increased not only from fluid formation and
vaporization, but also via thermal fracture formation. The
increased permeability aids fluid flow within the formation and
production of the hydrocarbon fluids generated from the
kerogen.
[0093] In addition, pressure generated by expansion of pyrolysis
fluids or other fluids generated in the formation may 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.
[0094] The generated fractures can be horizontal or vertical
depending on the heater configuration, in situ stress state, rock
properties (flow and mechanical), and other factors. FIG. 5
illustrates the results of a thermal-mechanical simulation of a
planar heater conducted in CMG STARS in the graph 500. The graph
500 has on the x-axis 502 the distance in feet from the planar
heater. On the y-axis 504 is the vertical normal stress in pounds
per square inch (psi). In this simulation, the baseline vertical
normal stress 506, on day zero without any heating is approximately
300 psi at the location of the heater and is constant as the
distance extends away from the heater. After heating for 15 days,
line 508 indicates that the vertical normal stress near the heater
has increased, but as the distance from the heater approaches ten
feet and up to fifteen feet from the heater there is a tensile
stress zone, or zone of negative normal stress. Tensile stress
zones, the negative vertical normal stresses indicated in zone 510,
develop as a result of the thermal gradient between the heated area
and the cold, unconverted rock. Because the thermal front will
continue to move with time, the tensile stress zone also moves,
thereby providing a means to initiate and propagate fractures. Line
512 represents the stress state after 30 days of heating, after
which the tensile stress zone has extended to over 20 feet from the
heater. Line 514 represents the stress state after 45 days of
heating, after which the tensile stress zone has extended to
approximately 30 feet from the heater.
[0095] FIGS. 6 and 7 illustrate a validation of the CMG STARS
models through core experiments. FIG. 6 illustrates a simulation
600 in CMG STARS of a core sample 602 with a planar heater 604
located in the center of the core sample 602. The simulation 600
predicted tensile stress zones 606 located to the right and left of
the planar heater 604 as indicated in the Figure. The simulation
600 predicted tensile stress zones 606 that are large enough to
develop fractures within these tensile stress zones 606 and in
which the fractures would be oriented approximately perpendicular
to the planar heater 604.
[0096] FIG. 7 shows a core sample 700 in which a planar heater 702
was placed within the core sample 700. After heating to a
sufficient temperature, fractures 704 were observed in the core
sample 700 that were in accordance with the location of the
fractures predicted in the simulation 600.
[0097] 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.
[0098] 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.
[0099] 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.
[0100] 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.,
hydraulic fracturing, 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., hydraulic fracturing, heating,
production, dewatering, injection, etc.). Finally, monitoring wells
may later be used for other purposes such as water production.
[0101] The wellbores for the various wells may be located in
relatively close proximity, being from 10 feet to up to 300 feet in
separation. Alternatively, the wellbores may be spaced from 30 to
200 feet or 50 to 100 feet. Typically, the wellbores are also
completed at shallow depths, being from 200 to 5,000 feet at total
depth. Alternatively, the wellbores may be completed at depths from
1,000 to 4,000 feet, or 1,500 to 3,500 feet. In some embodiments,
the oil shale formation targeted for in situ retorting is at a
depth greater than 200 feet below the surface. In alternative
embodiments, the oil shale formation targeted for in situ retorting
is at a depth greater than 500, 1,000, or 1,500 feet below the
surface. In alternative embodiments, the oil shale formation
targeted for in situ retorting is at a depth between 200 and 5,000
feet, alternatively between 1,000 and 4,000 feet, 1,200 and 3,700
feet, or 1,500 and 3,500 feet below the surface.
[0102] In connection with the development of an oil shale field, it
may be desirable that the progression of heat through the
subsurface in accordance with steps 430 and 435 be uniform.
However, for various reasons the heating and maturation of
formation hydrocarbons in a subsurface formation may not proceed
uniformly despite a regular 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
productive. 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.
[0103] 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.
[0104] 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.).
[0105] 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.
[0106] 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.
* * * * *