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Coaxing oil from shale
Article in Oilfield Review · December 2010
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Coaxing Oil from Shale
Oil shale is plentiful, but producing its petroleum can be complicated. Since the
1800s, these rocks have been mined and fed into surface facilities where liquid
hydrocarbons were extracted. Now, operators are developing methods to heat the
rock in situ and pipe the liberated oil to the surface. They are also adapting oilfield
technology to evaluate these deposits and estimate their fluid yields.
Pierre Allix
Total
Pau, France
Alan Burnham
American Shale Oil LLC
Rifle, Colorado, USA
Tom Fowler
Shell International Exploration and Production
Houston, Texas, USA
Oil shale is the term given to very fine-grained
sedimentary rock containing relatively large
amounts of immature organic material, or kerogen. It is essentially potential source rock that
would have generated hydrocarbons if it had
been subjected to geologic burial at the requisite
temperatures and pressures for a sufficient time.
In nature, it can take millions of years at
burial temperatures between 100°C and 150°C
[210°F and 300°F] for most source rocks to generate oil. But the process can be accelerated by
heating the kerogen-rich rock more quickly and
to higher temperatures, generating liquid hydrocarbons in much shorter time: from a matter of
minutes to a few years.
Michael Herron
Robert Kleinberg
Cambridge, Massachusetts, USA
Bill Symington
ExxonMobil Upstream Research Company
Houston, Texas
Oilfield Review Winter 2010/2011: 22, no. 4.
Copyright © 2011 Schlumberger.
For help in preparation of this article, thanks to Neil Bostrom,
Jim Grau, Josephine Mawutor Ndinyah, Drew Pomerantz
and Stacy Lynn Reeder, Cambridge, Massachusetts; John
R. Dyni, US Geological Survey, Denver; Martin Kennedy,
University of Adelaide, South Australia, Australia; Patrick
McGinn, ExxonMobil Corporation, Houston; Eric Oudenot,
London; Kenneth Peters, Mill Valley, California, USA; and
Carolyn Tucker, Shell Oil, Denver.
ECS and RST are marks of Schlumberger.
CCR is a mark of American Shale Oil LLC.
Electrofrac is a mark of ExxonMobil.
Rock-Eval is a mark of the Institut Français du Pétrole.
1. Dyni JR: “Geology and Resources of Some World
Oil-Shale Deposits,” Reston, Virginia, USA: US Geological
Survey Scientific Investigations, Report 2005-5294, 2006.
Smith MA: “Lacustrine Oil Shales in the Geologic
Record,” in Katz BJ (ed): Lacustrine Basin Exploration:
Case Studies and Modern Analogs. Tulsa: The American
Association of Petroleum Geologists, AAPG Memoir 50
(1990): 43–60.
4
Oilfield Review
Forcing petroleum products from immature
formations is one of the more difficult ways to
extract energy from the Earth, but that has not
kept people from trying. From prehistoric times
to the present, oil shale, like coal, has been
burned as fuel. Methods for coaxing oil from the
rock to produce liquid fuels have existed for hundreds of years. The earliest such ventures mined
oil shale and heated it in processing facilities on
the surface to obtain liquid shale oil and other
petroleum products. More recently, methods
have been tested to heat the rock in situ and
extract the resulting oil in a more conventional
way: through boreholes. These approaches are
being developed, but the world’s oil shale
resources remain largely untapped.
Current estimates of the volumes recoverable
from oil shale deposits are in the trillions of
barrels, but recovery methods are complicated
and expensive. However, with today’s sustained
high prices and predictions of future oil shortages in the coming decades, producing oil from
shale may soon become economically viable.
Therefore, several companies and countries are
working to find practical ways to exploit these
unconventional resources.
This article explains how oil shales form, how
they have been exploited in various parts of the
world and which techniques are currently being
developed for tapping the energy they contain.
Examples from the western US illustrate innovative applications of oilfield technology for evaluating oil shale deposits and assessing their richness.
Oil Shale Formation
Oil shales form in a variety of depositional environments, including freshwater and saline lakes
and swamps, near-shore marine basins and
subtidal shelves.1 They may occur as minor sedimentary layers or as giant accumulations hundreds of meters thick, covering thousands of
square kilometers (above right).
As with other sedimentary rocks, compositions of shales containing organic material range
from mostly silicates to mostly carbonates, with
varying amounts of clay minerals (right). Mineral
composition has little effect on oil yield, but it
can impact the heating process. Clay minerals
contain water, which may affect the amount of
heat required to convert the organic material to
petroleum. Carbonate shales, upon heating, generate additional CO2 that must be considered in
any oil shale development program. Many deposits also contain valuable minerals and metals
such as alum, nahcolite, sulfur, vanadium, zinc,
copper and uranium, which may themselves be
targets of mining operations.
Winter 2010/2011
> Outcropping oil shales. The oil shale of the Green River Formation in the Piceance Creek basin in
Colorado covers about 3,100 km2 [1,200 mi2]. The inset (top) shows a hand specimen from that region,
with dark layers of rich oil shale interbedded with pale layers of lean shale. The white scale bar is
7.2 cm [2.8 in.] long. (Outcrop photograph courtesy of Martin Kennedy, University of Adelaide. Inset
photograph courtesy of John R. Dyni, US Geological Survey, Denver.)
Calcite and Dolomite
Calcareous
or dolomitic
mudstone
Siliceous
dolomite
Gas shales from Poland
Parachute Creek Member
Garden Gulch Member
Various other locations
Eagle Ford
Siliceous
marlstone
Niobrara
Argillaceous
marlstone
Monterey
Montney
Haynesville
Argillaceous
mudstone
(traditional shale)
Clay
Minerals
Average shale
Lower
Marcellus
Barnett
Bakken
Bazhenov
Muskwa
Siliceous
mudstone
Siliceous shale
Monterey
porcellanite
Quartz and
Feldspar
> Shale mineralogy. Worldwide average shale composition regardless of organic content (black
diamond) is high in clay minerals and contains some quartz and feldspar with little or no calcite or
dolomite. Organic-rich shales (other diamonds and dots) tend to have a wider variety of compositions.
Oil shales from the Green River Formation are highlighted in dotted blue ovals. Those from the
Parachute Creek Member (green squares) have low clay-mineral content, while oil shales from the
Garden Gulch Member (red dots) are richer in clay minerals. Gray lines subdivide the triangle into
compositional regions. (Adapted from Grau et al, reference 32.)
5
Interspersed between the grains of these
rocks is kerogen—insoluble, partially degraded
organic material that has not yet matured enough
to generate hydrocarbons. The kerogen in oil
shale has its origins predominantly in the
Products Given
off from Kerogen
Maturation
CO2, H2O
Oil
Wet gas
Dry gas
Type I
Type II
Hydrogen/carbon ratio
1.5
No hydrocarbon
potential
Increasing
maturation
Type III
1.0
Type IV
0.5
0
0.1
0.2
Oxygen/carbon ratio
> Kerogen maturation. The Type I and Type II
kerogens in most oil shales are not yet mature
enough to generate hydrocarbons. As these
kerogens mature—usually through geologic burial
and the increased heat associated with it—they
transform into oil, and then with more heat, to gas.
Methods that accelerate the maturation process
attempt to control heat input, thereby producing
only the desired type of hydrocarbon.
remains of lacustrine and marine algae, and contains minor amounts of spores, pollen, fragments
of herbaceous and woody plants and remnants of
other lacustrine, marine and land flora and
fauna. The type of kerogen has a bearing on what
kind of hydrocarbon it will produce as it matures
thermally.2 The kerogens in oil shale fall into the
Type I and Type II classifications used by geochemists (left).
The thermally immature kerogens in oil
shales have undergone low-temperature diagenesis but no further modifications.3 Some other
organic-rich shales may have reached thermal
maturity but not yet expelled all of their liquid
petroleum products. To distinguish them from oil
shales, for the purposes of this article, mature,
organic-rich shales that have not expelled all of
their oil are called oil-bearing shales. Examples
of these are the Bakken, Monterey and Eagle
Ford shales, which currently produce oil in the
US. Other organic-rich shales are more thermally
mature or of different kerogen type and contain
gas instead of oil, such as the Barnett, Fayetteville
and Marcellus shales, also in the US.4
Many shales attain source-rock status, achieving full maturity and expelling their oil and natural gas, which then migrate, and under the proper
conditions, accumulate and become trapped
until discovered and produced. Some such shales
can manifest in several ways. For example, the
Kimmeridge Clay Formation is the main source
rock for the oil fields of the North Sea, but where
it outcrops in England it is an oil shale. Similarly,
the Green River shale, which is presumed to be
50
Mined shale, million metric tons
40
Germany
Scotland
China
Russia
Brazil
Estonia
30
20
10
0
1880
1890
1900
1910
1920
1930
1940
1950
1960
1970
1980
1990
2000
2010
Year
> More than a century of commercial oil shale mining. Tonnage of mined shale rose dramatically in the
1970s when oil prices were also rising; it peaked in 1980, but declined as oil prices made shale oil
noncompetitive. Several countries continue to mine oil shale as a source of heat, electricity, liquid fuel
and chemical feedstock. Since 1999, mined shale tonnage has started to increase again. (Data from
1880 to 1998 from Dyni, reference 1.)
6
the source rock for the oil produced from the
Red Wash field in Utah, USA, outcrops in the
same region. It also contains the world’s largest
reserves of shale oil.
Oil Shales in Time and Space
The earliest use of oil shale was as fuel for heat,
but there is also evidence of weaponry applications, such as flaming, oil shale–tipped arrows
shot by warriors in 13th-century Asia.5 The first
known use of liquid petroleum derived from shale
dates to the mid-1300s, when medical practitioners in what is now Austria touted its healing
properties. By the late 1600s, several municipalities in Europe were distilling oil from shale for
heating fuel and street lighting. In the 1830s,
mining and distillation activities began in France,
and reached commercial levels there and in
Canada, Scotland and the US by the mid-1800s.
The country with the longest history of commercial shale oil production is Scotland, where mines
operated for more than 100 years, finally closing
in 1962.6
Fuel shortages during the two World Wars
encouraged other countries to exploit their oil
shale resources. Tapping a kerogen-rich carbonate sequence, Estonia began mining oil shale
from a deposit about 20 to 30 m [65 to 100 ft]
thick that covers hundreds of square kilometers
in the northern part of the country. The operation
continues today.
The shale, which occurs as 50 or so beds of
organic-rich shallow marine sediments alternating with biomicritic limestone, is produced from
open-pit mines at depths to 20 m. Where the shale
is buried deeper than that, down to 70 m [230 ft],
it is accessed by underground mines. Roughly
three-quarters of the mined rock supplies fuel for
electric power plants, providing 90% of the country’s electricity. The remainder is used for heating
and as feedstock for petrochemicals. In the past
90 years, 1 × 109 metric tons [1 × 109 Mg, or
1.1 billion tonUS] of oil shale has been mined
from the primary Estonia deposit (left).7
China has a significant history of oil shale mining as well, with shale oil production beginning in
the 1920s. In the Fushun area, extensive shale layers 15 to 58 m [49 to 190 ft] thick are mined along
with coal, both from Eocene lacustrine deposits.
The total resource of oil shale at Fushun is estimated at 3.3 × 109 Mg [3.6 billion tonUS].8 As of
1995, Fushun’s petroleum production capacity
from shale was 66,000 m3/yr [415,000 bbl/yr].
Brazil began developing an oil shale mining
and processing industry in the 1960s. The national
oil company, Petróleo Brasileiro SA (Petrobras),
Oilfield Review
Russia (2)
247
United States (1)
2,085
Canada (11)
15
France (12)
7
Morocco (6)
53
Brazil (4)
82
Shale oil resource,
billion bbl
(global ranking)
Estonia (9)
16
Italy (5)
73
Israel (14)
4
Egypt (13)
Jordan (7)
5.7
34
China (10)
16
Democratic
Republic of
Congo (3)
100
Australia (8)
31
> Significant oil shale deposits. Most of the known high-quality shale oil resources are in these 14 countries. (Data from Knaus et al, reference 11.)
established the Shale Industrialization Business
Unit (SIX) to exploit the country’s several
large oil shale deposits. The Irati Formation,
which outcrops extensively in southern Brazil,
contains reserves of more than 1.1 × 108 m3
[700 million bbl] of oil and 2.5 × 1010 m3 [880 Bcf]
of gas.9 Surface facilities at São Mateus do Sul, in
the state of Paraná, are capable of processing
7,100 Mg [7,800 tonUS] of shale per day to produce
fuel oil, naphtha, liquefied petroleum gas (LPG),
shale gas, sulfur and asphalt additives.
To date, almost all the oil extracted from the
world’s oil shale has been from rock that was
mined and then processed at surface facilities.
Mining is typically performed either through surface mining or through underground mining
using the room-and-pillar method associated
with coal mining. After mining, oil shale is transported to a facility—a retort—where a heating
process converts kerogen to oil and gas and separates the hydrocarbon fractions from the mineral
fraction. This mineral waste, which contains substantial amounts of residual kerogen, is called
spent shale. After retorting, the oil must be
upgraded by further processing before being sent
to a refinery.
Mining operations require handling massive
volumes of rock, disposing of spent shale and
upgrading the heavy oil. The environmental
impact can be significant, causing disruption of
the surface and requiring substantial volumes of
water. Water is needed for controlling dust, cooling spent shale and upgrading raw shale oil.
Estimates of water requirements range from 2 to
5 barrels of water per barrel of oil produced.10
2. Tissot BP: “Recent Advances in Petroleum Geochemistry
Applied to Hydrocarbon Exploration,” AAPG Bulletin 68,
no. 5 (May 1984): 545–563.
3. For more on diagenesis: Ali SA, Clark WJ, Moore WR
and Dribus JR: “Diagenesis and Reservoir Quality,”
Oilfield Review 22, no. 2 (Summer 2010): 14–27.
4. Boyer C, Kieschnick J, Suarez-Rivera R, Lewis RL and
Waters G: “Producing Gas from Its Source,” Oilfield
Review 18, no. 3 (Autumn 2006): 36–49.
5. Moody R: “Oil & Gas Shales, Definitions and Distributions
in Time & Space,” presented at the Geological Society’s
History of Geology Group Meeting, Weymouth, England,
April 20–22, 2007, http://www.geolsoc.org.uk/gsl/cache/
offonce/groups/specialist/hogg/pid/3175;jsessionid=
4CC09ACD6572AE54454755DE4A9077DC (accessed
September 14, 2010).
6. Shale Villages: “A Very Brief History of the Scottish Shale
Oil Industry,” http://www.almondvalley.co.uk/V_
background_history.htm (accessed September 24, 2010).
7. Sabanov S, Pastarus J-R and Nikitin O: “Environmental
Impact Assessment for Estonian Oil Shale Mining
Systems,” paper rtos-A107, presented at the
International Oil Shale Conference, Amman, Jordan,
November 7–9, 2006.
8. Dyni, reference 1.
9. Petrobras SIX Shale Industrialization Business Unit:
“Shale in Brazil and in the World,” http://www2.
petrobras.com.br/minisite/refinarias/petrosix/ingles/oxisto/
oxisto_reservas.asp (accessed November 10, 2010).
10. Bartis JT, LaTourrette T, Dixon L, Peterson DJ and
Cecchine G: Oil Shale Development in the United States:
Prospects and Policy Issues. Santa Monica, California,
USA: The RAND Corporation, Monograph MG-414, 2005.
11. Knaus E, Killen J, Biglarbigi K and Crawford P: “An
Overview of Oil Shale Resources,” in Ogunsola OI,
Hartstein AM and Ogunsola O (eds): Oil Shale: A
Solution to the Liquid Fuel Dilemma. Washington, DC:
American Chemical Society, ACS Symposium
Series 1032 (2010): 3–20.
12. Dyni, reference 1.
13. Screen mesh of –8 means the particles can pass
through a wire screen with 8 openings per linear inch.
Winter 2010/2011
The world’s oil shale deposits are widely distributed; hundreds of deposits occur in more than 30
countries (above). Many formations are at depths
beyond mining capabilities or in environmentally
fragile settings. In these areas, heating the rocks in
place may offer the best method to hasten kerogen
maturation. If ways can be found to do this safely,
efficiently and cost effectively, the potential prize is
immense. By conservative estimate—because oil
shales have not been the target of modern exploration efforts—resources of the world’s shale oil total
about 5.1 × 1011 m3 [3.2 trillion bbl].11 It is estimated
that more than 60% of this amount—roughly
3 × 1011 m3 [2 trillion bbl]—is located in the US.
Converting Oil Shale to Shale Oil
Translating volume of rock to volume of recoverable oil requires information on oil shale properties, such as organic content and grade, which can
vary widely within a deposit. Traditionally, for the
purposes of surface retorting, oil shale grade is
determined by the modified Fischer assay method,
which measures the oil yield of a shale sample in
a laboratory retort.12 A 100-g [0.22-lbm] sample is
crushed and sieved through a 2.38-mm [–8] mesh
screen, heated in an aluminum retort to 500°C
[930°F] at a rate of 12°C/min [22°F/min] and
then held at that temperature for 40 min.13 The
resulting distilled vapors of oil, gas and water are
condensed and then separated by centrifuge. The
quantities delivered are weight percentages of oil,
water and shale residue and the specific gravity of
the oil. The difference between the weight of the
products and that of the starting material is
7
Shale oil, degree API gravity
40
Project Name
Primary Purpose
Dates
Heater
Holes
Total
Holes
Depth,
ft
Red Pinnacle
thermal conduction test
ICP field demonstration
1981 to 1982
3
14
20
32
28
Mahogany field
experiment
ICP field demonstration
1996 to 1998
6
26
130
Mahogany demonstration
project
ICP field demonstration,
recovery
1998 to 2005
38
101
600
Mahogany demonstration
project, South
ICP field demonstration,
recovery
2003 to 2005
16
27
400
Deep heater test
Heaters
2001 to present
21
45
700
Mahogany isolation test
Freeze wall
2002 to 2004
2
53
1,400
Freeze wall test
Freeze wall
2005 to present
0
233
1,700
36
ICP
LLNL
10
1
24
20
100,000 10,000
1,000
100
Heating rate, °C/d
> Improved oil quality with slow heating. Data
from the Shell in situ conversion process (ICP)
and Lawrence Livermore National Laboratory
(LLNL), in California, show a clear increase in oil
API gravity as heating rate decreases. The red
endpoint represents the results of typical
laboratory pyrolysis.
recorded as “gas plus loss.” The oil yield is
reported in liters per metric ton (L/Mg) or gallons
per short ton (galUS/tonUS) of raw shale.
Commercially attractive oil shale deposits yield at
least 100 L/Mg [24 galUS/tonUS], and some reach
300 L/Mg [72 galUS/tonUS].14
The Fischer assay method does not measure
the total energy content of an oil shale because
the gases, which include methane, ethane, propane, butane, hydrogen, H2S and CO2, can have
significant energy content, but are not individually specified. Also, some retort methods, especially those that heat at a different rate or for
different times, or that crush the rock more finely,
may produce more oil than that produced by
the Fischer assay method. Therefore, the method
only approximates the energy potential of an oil
shale deposit.15
Another method for characterizing organic
richness of oil shale is a pyrolysis test developed
by the Institut Français du Pétrole, in ReuilMalmaison, France, for analyzing source rock.16
The Rock-Eval test heats a 50- to 100-mg
[0.00011- to 0.00022-lbm] sample through several
temperature stages to determine the amounts of
hydrocarbon and CO2 generated. The results can
be interpreted for kerogen type and potential for
oil and gas generation. The method is faster than
the Fischer assay and requires less sample material.
The reactions that convert kerogen to oil and
gas are understood generally, but not in precise
molecular detail.17 The amount and composition
of generated hydrocarbons depend on the heating
conditions: the rate of temperature increase, the
duration of exposure to heat and the composition
of gases present as the kerogen breaks down.
8
> Shell’s thermal conduction pilot projects. Shell has performed seven field pilots using the in situ
conversion process (ICP) to heat oil shale to conversion temperature. (Adapted from Fowler and
Vinegar, reference 24.)
Generally, surface-based retorts heat the
shale rapidly. The time scale for retorting is
directly related to the particle size of the shale,
which is why the rock is crushed before being
heated in surface retorts. Pyrolysis of particles on
the millimeter scale can be accomplished in
minutes at 500°C; pyrolysis of particles tens of
centimeters in size takes hours.
In situ processes heat the shale more slowly.
It takes a few years to heat a block tens of meters
wide. However, slow heating has advantages.
Retorting occurs at a lower temperature so less
heat is needed. Also, the quality of the oil
increases substantially (above left). Coking and
cracking reactions in the subsurface tend to
leave the heavy, undesirable components in the
ground. As a result, compared with surface processing, in situ heating can produce lighter liquid
hydrocarbons with fewer contaminants.
During in situ conversion, the subsurface acts
as a large reactor vessel in which pressure and
heating rate may be designed to maximize product quality and quantity while minimizing production cost. In addition to generating a superior
product relative to surface processing, in situ
methods have a reduced environmental impact in
terms of surface disturbance, water requirements and waste management.
Several companies have developed methods
for heating oil shale in situ to generate shale oil.
They are testing these techniques in the rich subsurface deposits of the western US.
The Epitome of Oil Shales
The Green River Formation at the intersection of
the states of Colorado, Utah and Wyoming, USA,
contains the most bountiful oil shale beds in the
world. Estimates of the recoverable shale oil
in this area range from 1.2 to 1.8 trillion bbl
[1.9 to 2.9 × 1011 m3]. Nearly 75% of the resources
lie under land managed by the US Department of
the Interior.
The fine-grained sediments of this formation
were deposited over the course of 10 million years in
Early and Middle Eocene time, in several large lakes
covering up to 25,000 mi2 [65,000 km2]. The warm
alkaline waters provided conditions for abundant
growth of blue-green algae, which are believed to be
the main component of the organic matter in the oil
shale.18 The formation is now about 1,600 ft [500 m]
thick and in places has shale layers that contain
more than 60 galUS/tonUS [250 L/Mg] of oil (next
page).19 A particularly rich and widespread layer,
called the Mahogany zone, reaches a thickness of
50 ft [15 m]. It contains an estimated 173 billion bbl
[2.8 × 1010 m3] of shale oil. The Green River area has
been well studied, with more than 750,000 assay
tests performed on samples from outcrops, mines,
boreholes and core holes.20
Settlers and miners began retorting oil from
the shale in the 1800s. The region experienced
mining and exploration booms from 1915 to 1920
and again from 1974 to 1982, each period followed by busts.21 In 1980, Unocal built a major
plant for mining, retorting and upgrading oil
shale in the Piceance Creek basin in Colorado; it
operated until 1991. During that time, the
company produced 4.4 million bbl [700,000 m3]
of shale oil.22
Recently, oil price volatility and growing
energy needs have combined to again focus interest on the region. In 2003, the US Bureau of Land
Management initiated an oil shale development
program and solicited applications for research,
development and demonstration (RD&D) leases.
Several companies applied for and received
lease awards to develop in situ heating techniques
on public lands, and some are testing methods
Oilfield Review
Generalized
Lithology
Depth, ft
Sandstone, siltstone and some
marlstone and lean oil shale
Oil shale
500
Marlstone and low-grade oil shale
Leached oil shale; contains open solution
cavities and marlstone solution breccias
Nahcolite-bearing oil shale; contains nodules,
scattered crystals and beds of nahcolite
1,000
Clay-bearing oil shale
Interbedded halite, nahcolite and oil shale
Lean oil shale zones, carbonate rich
Lean oil shale zones, clay rich
Mahogany
zone
109 bbl
R-8
Mahogany
R-6
L-5
R-5
L-4
R-4
L-3
R-3
L-2
R-2
L-1
R-1
L-0
R-0
No data
25.25
23.23
7.65
26.09
8.88
15.74
2.73
8.52
2.93
7.75
1.56
16.84
No data
No data
No data
172.94
159.09
52.42
178.72
60.85
107.78
18.72
58.38
20.08
53.07
10.70
115.35
No data
No data
1,008.10
2,000
B-groove
R-6 zone
L-5 zone
R-5 zone
L-4 zone
R-4 zone
L-3 zone
R-3 zone
2,500
L-2 zone
R-2 zone
L-1 zone
3,000
Garden Gulch
Member
Zone
109 tonUS
Parachute Creek Member
Shale Oil Resources
147.17
Rich oil shale zones, clay rich
A-groove
1,500
Total
Rich oil shale zones, carbonate rich
R-8 zone
Nahcolite and oil shale
Green River Formation
. Lithology (center) and
grade (right) of the Green
River Formation. Oil shales in
the Parachute Creek Member
are carbonate rich, and the
underlying shales of the
Garden Gulch Member are
clay rich. High-grade (blue)
oil shales are interspersed
with lean layers (pink). Oil
yield from Fischer assay
measurement is plotted in
red. Total shale oil resources
contained in the various
layers are shown in the chart
(bottom left). (Lithology and
shale oil resources from
Dyni, reference 1; shale
grade from Johnson et al,
reference 19.)
Uinta Formation
(with tongues of Green River Formation)
0
Anvil Points
Member
R-1 zone
L-0 zone
R-0 zone
0
20
40
60
80 100
Shale oil yield,
galUS/tonUS
on privately held land. Examples from three
companies—Shell, ExxonMobil and American
Shale Oil LLC (AMSO)—show the range of
concepts being applied to the challenges of in situ
retorting in the Green River oil shale.
Shell has done extensive laboratory and field
work in efforts to demonstrate commercial viability of in situ retorting using downhole electric
heaters.23 The process follows a method developed
in Sweden during World War II—a technique used
until 1960, when cheaper supplies of imported oil
became available.
Shell participated in early mining and surface
retort attempts in the Green River area, but chose
to withdraw from those in the mid-1990s to focus
on an in situ method.24 Years of laboratory testing,
thermal simulations and field pilots contributed to
the development of Shell’s in situ conversion process (ICP). Through seven field pilot tests, Shell
has investigated a variety of heating methods—
including injected steam and downhole heaters—
and well configurations with patterns of wells of
varying depths for heating, producing and dewatering (previous page, top right).
14. Knaus et al, reference 11.
15. Dyni JR, Mercier TJ and Brownfield ME: “Chapter 1—
Analyses of Oil Shale Samples from Core Holes and
Rotary-Drilled Wells from the Green River Formation,
Southwestern Wyoming,” in US Geological Survey Oil
Shale Assessment Team (ed): “Fischer Assays of
Oil-Shale Drill Cores and Rotary Cutting from the
Greater Green River Basin, Southwestern Wyoming,”
US Geological Survey, Open-File Report 2008-1152,
http://pubs.usgs.gov/of/2008/1152/downloads/Chapter1/
Chapter1.pdf (accessed October 8, 2010).
16. Pyrolysis is the controlled heating of organic matter in
the absence of oxygen to yield organic compounds such
as hydrocarbons.
Peters KE: “Guidelines for Evaluating Petroleum Source
Rock Using Programmed Pyrolysis,” AAPG Bulletin 70,
no. 3 (March 1986): 318–329.
Espitalie J, Madec M, Tissot B, Mennig JJ and Leplat P:
“Source Rock Characterization Method for Petroleum
Exploration,” paper OTC 2935, presented at the Offshore
Technology Conference, Houston, May 2–5, 1977.
17. Burnham AK: “Chemistry and Kinetics of Oil Shale
Retorting,” in Ogunsola OI, Hartstein AM and Ogunsola O
(eds): Oil Shale: A Solution to the Liquid Fuel Dilemma.
Washington, DC: American Chemical Society, ACS
Symposium Series 1032 (2010): 115–134.
18. Dyni, reference 1.
19. Johnson RC, Mercier TJ, Brownfield ME, Pantea MP
and Self JG: “Assessment of In-Place Oil Shale
Resources of the Green River Formation, Piceance
Basin, Western Colorado,” Reston, Virginia, USA: US
Geological Survey, Fact Sheet 2009-3012, March 2009.
20. US Department of Energy: “Secure Fuels from Domestic
Resources,” http://www.unconventionalfuels.org/
publications/reports/SecureFuelsReport2009FINAL.pdf
(accessed November 12, 2010).
21. Hanson JL and Limerick P: “What Every Westerner
Should Know About Oil Shale: A Guide to Shale
Country,” Center of the American West, Report no. 10,
June 17, 2009, http://oilshale.centerwest.org (accessed
August 4, 2010).
22. Dyni, reference 1.
23. Ryan RC, Fowler TD, Beer GL and Nair V: “Shell’s In Situ
Conversion Process—From Laboratory to Field Pilots,”
in Ogunsola OI, Hartstein AM and Ogunsola O (eds):
Oil Shale: A Solution to the Liquid Fuel Dilemma.
Washington, DC: American Chemical Society,
ACS Symposium Series 1032 (2010): 161–183.
24. Fowler TD and Vinegar HJ: “Oil Shale ICP—Colorado
Field Pilots,” paper SPE 121164, presented at the SPE
Western Regional Meeting, San Jose, California,
March 24–26, 2009.
Winter 2010/2011
9
Plan View
Wells
Heater (2)
Producer (1)
Freeze (18)
Inside monitor (8)
8 ft
22 ft
50 ft
Side View
1,400-ft
freeze
interval
430-ft
heated
interval
> Shell freeze wall isolation test. Using a technique dating to the 1880s, Shell
constructed a circular freeze wall 1,400 ft [430 m] deep by circulating
coolant in 18 freeze wells for 5 months. A 430-ft [130-m] interval of the
enclosed formation was then heated to generate shale oil. The test verified
that the freeze wall could confine produced fluids.
The ICP method uses closely spaced downhole electric heaters to gradually and evenly heat
the formation to the conversion temperature of
about 650°F [340°C]. Depending on heater spacing and the rate of heating, the time projected to
reach conversion temperature in a commercial
project ranges from three to six years. Tests have
demonstrated liquid-recovery efficiencies greater
than 60% of Fischer assay value, with the lowvalue kerogen components left in the ground. The
resulting oil is of 25 to 40 degree API gravity. The
gas contains methane [CH4], H2S, CO2 and H2.
Taking into account the oil equivalence
of the gas generated, the recovery efficiency
approaches 90% to 100% of Fischer assay value.
From results of the pilot testing, a commercialscale project is expected to have an energy
gain close to 3, meaning the energy value of the
10
products is three times the energy input to
obtain them.
Commercialization of the ICP process
requires a method that prevents water influx to
the heated volume and contains the fluid products, thereby maximizing recovery and protecting
local aquifers.25 The Shell ICP process makes use
of a freeze wall, created by circulating coolants,
to isolate the heated formation from groundwater. Use of a freeze wall is a relatively common
practice in some underground mining operations.
Inside the freeze wall, water is pumped from the
formation. The formation is heated, the oil is produced and the residual shale is cleaned of contaminants by flushing with clean water. The
recovered oil in one test had 40 degree API gravity, similar to modeling results for oil produced at
heating rates of 1°C/h [0.5°F/h] and 27 MPa.
Pilot testing of the freeze wall began in 2002
with 18 freeze wells arranged in a circle 50 ft
across. One producer, two heating wells and eight
monitor wells were located within the freeze circle (left). After five months of cooling, the freeze
wall was complete. This pilot showed that a
freeze wall could be established and could isolate
fluids inside the circle from those outside.
Shell tested the freeze wall concept on a larger
scale starting in 2005, with an ambitious project
involving 157 freeze wells at 8-ft [2.4-m] intervals
to create a containment volume 224 ft [68 m]
across (next page, top). The operator began chilling in 2007 by circulating an ammonia-water
solution—initially at shallow depth and gradually
deepening. As of July 2009, the freeze wall was
continuing to form in the deeper zones, down to
1,700 ft [520 m]. The test is designed to evaluate
the integrity of the freeze wall, and will not involve
heating, or production of hydrocarbons.
ExxonMobil is also pursuing research and
development of a process for in situ oil shale conversion. The company’s Electrofrac process
hydraulically fractures the oil shale and fills the
fractures with an electrically conductive material,
creating a resistive heating element.26 Heat is
thermally conducted into the oil shale, converting
the kerogen into oil and gas, which are then produced by conventional methods. Calcined petroleum coke, a granular form of relatively pure
carbon, is being tested as the Electrofrac conductant. By pumping this material into vertical
hydraulic fractures, ExxonMobil hopes to create a
series of parallel planar electric heaters (next
page, bottom). As in the Shell ICP method, the
resistive heat reaches the shale by thermal diffusion. A potential advantage of the Electrofrac process is that, compared with line sources, the
greater surface area of planar fracture heaters will
permit fewer heaters to be used to deliver heat to
the subsurface volume. The use of planar heaters
should also reduce surface disturbance when compared with line sources or wellbore heaters.
25. Ryan et al, reference 23.
26. Symington WA, Kaminsky RD, Meurer WP, Otten GA,
Thomas MM and Yeakel JD: “ExxonMobil’s Electrofrac™
Process for In Situ Oil Shale Conversion,” in Ogunsola
OI, Hartstein AM and Ogunsola O (eds): Oil Shale: A
Solution to the Liquid Fuel Dilemma. Washington, DC:
American Chemical Society, ACS Symposium Series 1032
(2010): 185–216.
Symington WA, Olgaard DL, Otten GA, Phillips TC,
Thomas MM and Yeakel JD: “ExxonMobil’s Electrofrac
Process for In Situ Oil Shale Conversion,” presented at
the AAPG Annual Convention, San Antonio, Texas, USA,
April 20–23, 2008.
Oilfield Review
Plan View
C
C
Freeze well
8 ft
B
A
A
B
224 ft
Side View
Test
Section B
1,700-ft
freeze
interval
Test
Sections
A and C
1,500-ft
freeze
interval
> Large-scale freeze wall test. In a step toward
supporting commercial viability of the ICP, Shell is
testing a large-scale freeze wall for isolation and
containment. In addition to the freeze wells shown
in the plan view (left) there are 27 observation
holes for geomechanical, pressure, fluid level and
temperature measurements; 30 special-use holes
for venting, squeezing, water reinjection, water
production and hydraulic fracturing; and 40
groundwater monitoring holes. An artist’s
rendering (right) depicts the freeze wall in 3D.
20/40 Mesh Proppant
Toe connector well
Production wells
Electrofrac process
heater wells
Calcined Coke
Hydraulic fracture
with electrically
conductive material
Conductive heating and
oil shale conversion
> The ExxonMobil Electrofrac process. Horizontal wells penetrate the oil shale. The horizontal sections are hydraulically
fractured (left) and filled with electrically conductive proppant made of calcined coke (bottom right). A 20/40 mesh proppant (top
right) is displayed for scale. Field testing has shown it is possible to create an electrically conductive fracture and heat it for
several months. The plus and minus signs indicate electric charge applied to heat the fractures. (Illustration and photographs
courtesy of ExxonMobil.)
Winter 2010/2011
11
0
Heating well
Low-salinity water
Nahcolitic oil shale caprock
2,000
Vapor
High-salinity water
1,500
Condensate
Mahogany zone
1,000
Condensate
Depth, ft
Production well
Production well
500
Rubblefilled
retort
Illitic oil shale
Boiling oil
Heating well
2,000 ft
> The AMSO CCR conduction, convection and reflux process. Two horizontal wells target the illitic oil
shale beneath a nahcolitic caprock. The heating well is at the base and the production well is at the
top of the shale (left). As heat causes the kerogen to decompose, the lighter products rise and
condense (right), efficiently heating a large volume of rock. Hydrocarbon fluids are produced via the
production well.
s 4HAT A COMPLETION STRATEGY CAN BE DESIGNED TO
create fractures that deliver heat effectively.
Based on these results, ExxonMobil advanced
to field research to test the Electrofrac method in
situ.27 The test site is at the company-owned
Colony oil shale mine in northwest Colorado. The
Colony mine provides a large, highly accessible
volume of rock for testing. ExxonMobil has created two Electrofrac fractures at Colony by drilling horizontally into the oil shale and pumping a
2,0
00
ft
Panel being retorted
20
0f
t
Prior to embarking on field research,
ExxonMobil conducted modeling and laboratory
studies addressing several important technical
issues for the Electrofrac process. These included
establishing the following:
s 4HAT THE CONDUCTANT IN THE FRACTURE CAN MAINtain its electrical continuity while the surrounding rock is heated to conversion temperatures.
s 4HAT OIL AND GAS GENERATED BY THE PROCESS ARE
expelled from oil shale, not only at surface conditions, but also under in situ stress conditions.
Panel being drilled
2,0
2,000 ft
00
ft
> The AMSO concept for commercial-scale production. By using long
horizontal wells concentrated in a 200-ft corridor, drilling should impact
less than 10% of the surface area. While one 2,000-ft square panel is being
heated and converted in situ, wells will be drilled in an adjacent panel. The
operation is projected to produce about 1 billion bbl of shale oil over a
25-year period.
12
slurry of calcined petroleum coke, water and
portland cement at pressures sufficient to break
the rock. The larger of the two Electrofrac fractures has been heavily instrumented to measure
temperature, voltage, electrical current and
rock movement. As a preliminary test of the
Electrofrac process, the fracture was heated
to relatively low temperatures. This lowtemperature experiment was not intended to
generate oil or gas. To date, the results of this
field program have been encouraging. They
demonstrate that it is possible to create an electrically conductive hydraulic fracture, to make
power connections to the fracture and to operate
it, at least at low temperature, for several months.
AMSO, 50% owned by Total, proposes to use
the CCR conduction, convection and reflux process to recover shale oil. By focusing the heating
effort on shales beneath an impermeable shale
caprock, this method isolates production zones
from protected sources of groundwater.28
The company plans to drill two horizontal
wells—a heater below a producer—in the bottom of the illite shale at the base of the Green
River Formation (above left). Heat is delivered by
a downhole burner that eventually runs on produced gas. As the kerogen decomposes, the
lighter products—hot vapors—rise and reflux.
Heat is distributed through the formation by the
refluxing oil; thermomechanical fracturing, or
spalling, creates permeability for the convective
heat transfer.
The concept for commercial-scale production uses an array of horizontal wells about
2,000 ft [600 m] long at 100-ft [30-m] intervals
(left). The formation is heated slowly, yielding
oil with lower concentrations of heteroatoms
and metals than that generated by surface processing methods.29 Meanwhile, the aromatic
portions of kerogen tend to stay in the rock
matrix as coke. More than enough gas is coproduced to provide the energy required to operate
a self-sustaining commercial retorting process,
and it is likely that most of the propane and
butane produced can be exported to market.
Computational studies show that heat delivery by convection and conduction is much more
effective than by conduction alone. The CCR process is estimated to give a total energy gain
between 4 and 5, counting all the surface facility
requirements, including an oxygen plant for producing pure CO2 from the downhole burner. The
method is projected to use less than one barrel of
water per barrel of oil produced. No water is
needed to clean spent retorts because they
remain isolated from usable groundwater.
Oilfield Review
AMSO’s initial RD&D pilot test is currently
under construction and will begin in mid-2011.
Heating will take up to 200 days. The operation
will retort a formation volume equivalent to
4,000 tonUS [3,600 Mg] of oil shale and produce
up to 2,000 bbl [320 m3] of shale oil. Development
of a commercial operation will proceed in steps
up to 100,000 bbl/d [16,000 m3/d], with plans to
sustain that production for 25 years. That translates into about 1 billion bbl [1.6 × 108 m3] of oil
to be produced from an 8-mi2 [20.8-km2] lease.
Resistivity
90-in. Array
0.2
ohm.m
2,000
60-in. Array
Gamma
Ray
0.2
0 gAPI 200
0.2
PEF
0
ohm.m
20-in. Array
10
0.2
Caliper
6
ohm.m
2,000
Porosity
30-in. Array
Depth,
ft
in. 16
0.2
ohm.m
Density Porosity
2,000 45
10-in. Array
ohm.m
Total Organic Matter
Kerogen
2,000
2,000 45
%
–15 0
Core Fischer Assay
%
NMR Porosity
TOM Log
%
%
–15 0
50
50
Illite
Montmorillonite
Orthoclase
Pyrite
Dawsonite
Nahcolite
Albite
Quartz
Calcite
Dolomite
Bound water
Kerogen
Water
X,000
Evaluating Oil Shales
Companies are looking at ways to assess oil shale
richness and other formation properties without
having to take core samples and perform Fischer
assay analysis. Methods that show promise
include integration of several conventional logging measurements, such as formation density,
magnetic resonance, electrical resistivity and
nuclear spectroscopy.
One way of quantifying kerogen content is by
combining density porosity and magnetic resonance responses. In a formation with porosity
that is filled with both kerogen and water, the
density porosity measurement does not distinguish between kerogen- and water-filled porosity.
However, the magnetic resonance measurement
sees the kerogen as a solid, similar to the grains
of the rock, and so senses a lower porosity. The
difference between the magnetic resonance and
density readings gives kerogen volume.30 The volume of kerogen can be related empirically to
Fischer assay values for oil shales in the region.
The method was tested in an AMSO oil shale
well in the Green River basin. Kerogen content
was calculated from density porosity and magnetic resonance logs (right). Using a correlation
between kerogen content and Fischer assay
27. Symington WA, Burns JS, El-Rabaa AM, Otten GA,
Pokutylowicz N, Spiecker PM, Williamson RW and
Yeakel JD: “Field Testing of Electrofrac™ Process
Elements at ExxonMobil’s Colony Mine,” presented at
the 29th Oil Shale Symposium, Colorado School of
Mines, Golden, Colorado, USA, October 19–21, 2009.
28. Burnham AK, Day RL, Hardy MP and Wallman PH:
“AMSO’s Novel Approach to In-Situ Oil Shale Recovery,”
in Ogunsola OI, Hartstein AM and Ogunsola O (eds):
Oil Shale: A Solution to the Liquid Fuel Dilemma.
Washington, DC: American Chemical Society,
ACS Symposium Series 1032 (2010): 149–160.
29. Heteroatoms are atoms of elements other than hydrogen
and carbon—the components of pure hydrocarbons.
They commonly consist of nitrogen, oxygen, sulfur, iron
and other metals.
30. Kleinberg R, Leu G, Seleznev N, Machlus M, Grau J,
Herron M, Day R, Burnham A and Allix P: “Oil Shale
Formation Evaluation by Well Log and Core
Measurements,” presented at the 30th Oil Shale
Symposium, Colorado School of Mines, Golden,
Colorado, October 18–22, 2010.
Winter 2010/2011
X,050
X,100
X,150
X,200
> Kerogen content from porosity measurements in Green River oil shales. Neither gamma ray (Track 1,
dashed green) nor resistivity measurements (Track 2) show much correlation with kerogen content, but
porosity measurements are more useful. The difference between density porosity (Track 3, red) and
nuclear magnetic resonance (NMR) porosity (green) represents kerogen-filled porosity (gray). The
kerogen values can also be depicted as a log (Track 4) of total organic matter (TOM, red), which
compares favorably with laboratory Fischer assay results on core samples (black dots). Mineralogical
analysis incorporating ECS elemental capture spectroscopy measurements (Track 5) indicates the high
levels of calcite and dolomite in these shales, as well as the presence of rare minerals such as
dawsonite (light gray) and nahcolite (solid pink) in some intervals.
13
40
TOC converted to
Fischer assay yield
Core Fischer assay
30
X,200
20
X,400
Total
Totalorganic
organicmatter
matter
as
asfraction
fractionofofore
oreweight
weight
ρρk
TOM
)
TOM== ρρbk (φ( φDD––φφMR
MR )
10
X,600
Depth, ft
Total organic matter (TOM), %
X,000
b
X,800
0
0
20
40
60
Modified Fischer assay, galUS/tonUS
Y,000
Fischer assay, galUS/tonUS
80
Well log Fischer assay estimate
Core-measured Fischer assay values
60
Y,200
40
20
Y,400
0
X,000
X,050
X,100
X,150
X,200
Depth, ft
> Fischer assay estimates from wireline logs. Core measurements on Green
River shales show a strong correlation between total organic matter (TOM),
or kerogen, and Fischer assay values (top). Total organic matter is
calculated using the density lk of the kerogen, bulk density of the formation
lb and the difference between density porosity qD and magnetic resonance
porosity qMR. Researchers computed a kerogen log from the difference
between density and NMR porosity, then used this linear correlation to
convert the kerogen log to a Fischer assay log (bottom). The log-based
Fischer assay estimates (black) show excellent agreement with values from
laboratory Fischer assay measurements on cores (red).
results on Green River shales, researchers computed an estimated Fischer assay log based on
the wireline logging measurements (above). The
estimated Fischer assay values show excellent
agreement with those from laboratory measurements on cores from the same interval.
Another approach distinguishes mineral from
organic content using spectroscopy data. The ECS
elemental capture spectroscopy sonde measures
concentrations of silicon [Si], aluminum [Al], calcium [Ca], iron [Fe], sulfur [S], potassium [K],
sodium [Na], magnesium [Mg], titanium [Ti] and
gadolinium [Gd].31 Grain mineralogy is computed
from these element concentrations.
The total carbon concentration comes from
the RST reservoir saturation tool. Of this concentration, some carbon is inorganic and some
organic. The inorganic carbon combines with calcium and other elements to form calcite and
dolomite, along with lesser-known minerals,
14
20
40
60
Shale oil yield, galUS/tonUS
0
such as nahcolite [NaH(CO3)] and dawsonite
[NaAl(CO3)(OH2)], which are common in Green
River shales. The ECS concentrations of Ca, Mg
and Na are used to compute the inorganic carbon. The remainder, called total organic carbon
(TOC), makes up the kerogen.
Using this spectroscopy method, researchers
computed a TOC log for an AMSO well in the
Green River basin, showing a good match between
log-based results and core measurements (next
page).32 The TOC log was converted to a Fischer
assay yield log using a correlation derived independently by AMSO scientists. The Fischer assay
log exhibited excellent agreement with Fischer
assay tests performed on cores (above right). This
technique employing geochemical logs, along
with the complementary method using nuclear
magnetic resonance logs, provides reliable, efficient means to characterize shale oil yield without having to resort to core measurements.
> Fischer yield from TOC. Fischer assay estimates
(black) from the TOC log exhibit an excellent
correlation with core Fischer assay results (red).
Heating Elements
One of the most fundamental issues for oil shale
retorting is how to get the heat into the oil shale.
After early testing, steam injection was abandoned as other, more efficient techniques were
discovered. In situ combustion has also been
tried, but is difficult to control. Electric heaters,
electrically conductive proppant and downhole
gas burners have all been evaluated and reported
to be effective with varying degrees of efficiency.
Another concept, heating by downhole radiofrequency (RF) transmitters, has also been modeled and has undergone laboratory testing.33
Advantages of the RF method are that it heats the
interior of the formation instead of the borehole,
and it can be controlled to customize heating rate.
But like all electrical methods, it sacrifices efficiency, losing about half the heating value of the
fuel originally burned to produce the electricity.
It is important to note that all the current
projects to produce shale oil by in situ heating
methods are in test and pilot stages; none have
demonstrated large-scale commercial production. Operators are still working to optimize their
heating technologies. For a given oil shale, the
Oilfield Review
X,000
X,200
X,400
Depth, ft
X,600
X,800
150-ft interval
Y,000
Y,200
Y,400
0
20
40
Total carbon, weight percent
0
10
20
Inorganic carbon, weight percent
0
20
40
Organic carbon, weight percent
0
10
20
30
40
TOC, weight percent
> Organic and inorganic carbon from logs and cores. Total carbon (left) is made up of inorganic and organic carbon, the latter of
which resides in kerogen. The inorganic carbon is present in mineral form, such as in carbonates and some exotic minerals
sometimes found in oil shales. Estimates of inorganic (middle left) and organic carbon (middle right) based on nuclear
measurements (black) correlate extremely well with laboratory measurements on cores (red). An expanded section (right) shows
the quality of the match across the bottom 150-ft interval.
heating history—how much heat and for how
long—determines the amount and content of the
resulting fluids. By controlling the heat input,
companies can fine-tune the output, essentially
designing a shale oil of desired composition.
Beyond heating methods, there are other
aspects of oil shale operations that have yet to
be fully addressed. Mechanical stability of the
heated formation is not well understood. All the
in situ heating techniques rely on some thermomechanical fracturing within the shale to
release matured organic material and create
additional permeability for the generated fluids
to escape the formation. With many oil shales
containing 30% or more kerogen, most of which
leaves the rock after in situ retorting, treated
formations may not be able to support their
newfound porosity. Overburden weight can help
drive production, but may also cause compaction and subsidence, which in turn can affect
wellbore stability and surface structures.
It is also unclear how to deal with the CO2
generated along with other gases. Companies
retorting oil shale in situ may need to investigate
ways to capture and use the CO2 for enhanced oil
recovery or sequester it in deep storage zones. An
alternative, being explored by AMSO, is mineralization of CO2 in the spent shale formation.34 This
option exploits the chemical properties of the
heat-treated shale. AMSO scientists expect the
depleted formation to have sufficient porosity to
accommodate all the generated and reinjected
CO2 as carbonate minerals.
31. Barson D, Christensen R, Decoster E, Grau J, Herron M,
Herron S, Guru UK, Jordán M, Maher TM, Rylander E
and White J: “Spectroscopy: The Key to Rapid, Reliable
Petrophysical Answers,” Oilfield Review 17, no. 2
(Summer 2005): 14–33.
32. Grau J, Herron M, Herron S, Kleinberg R, Machlus M,
Burnham A and Allix P: “Organic Carbon Content of the
Green River Oil Shale from Nuclear Spectroscopy Logs,”
presented at the 30th Oil Shale Symposium, Colorado
School of Mines, Golden, Colorado, October 18–22, 2010.
33. Burnham AK: “Slow Radio-Frequency Processing of
Large Oil Shale Volumes to Produce Petroleum-Like Shale
Oil,” Livermore, California: Lawrence Livermore National
Laboratory, Report UCRL-ID-155045, August 20, 2003.
Raytheon: “Radio Frequency/Critical Fluid Oil Extraction
Technology,” http://www.raytheon.com/businesses/
rtnwcm/groups/public/documents/datasheet/rtn_bus_
ids_prod_rfcf_pdf.pdf (accessed November 16, 2010).
34. Burnham et al, reference 28.
35. Bostrom N, Leu G, Pomerantz D, Machlus M, Herron M
and Kleinberg R: “Realistic Oil Shale Pyrolysis Programs:
Kinetics and Quantitative Analysis,” presented at the
29th Oil Shale Symposium, Colorado School of Mines,
Golden, Colorado, October 19–21, 2009.
Winter 2010/2011
View publication stats
Work also remains to understand the kerogenmaturation process. To optimize heating programs, operators would like to know when the
shale has been heated enough and if the subsurface volume has been heated uniformly. To this
end, scientists are conducting laboratory experiments to monitor the products of kerogen pyrolysis.35 To understand when the process should be
modified or stopped, researchers plan to analyze
the composition of an oil shale and its hydrocarbons as they evolve with time. In the future, it
may be possible to control and monitor oil shale
heating and production to obtain oil and gas of
desired compositions.
—LS
15