1. Winter 2010/2011
Enhanced Oil Recovery
Arctic Operations
Oil Shale
OilfieldReview

2. 11-OR-0001

3. The global imbalance between supply and demand for oil
and gas is growing. This trend is pointed out in studies
from numerous organizations that watch the E&P industry,
including the International Energy Agency, Cambridge
Energy Research Associates and the World Petroleum
Council. Some studies indicate that the decline rate of
existing oil fields is increasing significantly over time, so
additional production is becoming progressively more cru-
cial to bridge the supply and demand gap.
In my opinion, neither we, as professionals in the oil and
gas industry, nor the resource owners can be satisfied with
recovery factors that average well below 40%. We need to
do better. Enhanced oil recovery (EOR) is a vital means to
achieve additional production and recovery from new and
existing fields. In addition, several sizable resources, such
as extra-heavy oil fields, cannot be developed without EOR
techniques. The high capital investments for offshore and
deepwater projects warrant a reassessment of development
philosophies because production options once considered
tertiary now need to be considered as possibilities in initial
development stages.
EOR techniques employ fundamental physical and chem-
ical rock and fluid interactions to improve reservoir sweep
and reduce residual oil saturations (see “Has the Time Come
for EOR?” page 16). Of the three basic EOR processes—
thermal, gas injection and chemical—used to achieve
these ends, thermal and gas injection are the most mature.
Chemical EOR is advancing rapidly in the use of mobility
improvements (polymer and steam), residual saturation
reducers (surfactants and designer waterflooding) or com-
binations thereof (alkali-surfactant-polymer flooding).
Extensive customization, fundamental to ensure that an
EOR process will be successful for a specific field, contrib-
utes significantly to the complexity and cost of EOR projects.
This customization usually includes detailed laboratory
studies, field trials, pilots and phased developments, all
needed to reduce project risk before sanction. Unfortunately,
this also leads to quite long development times and higher
up-front investment, hence, longer payback times. Faster
maturation workflows are required, which can be enabled
by technological solutions to speed up appraisal and devel-
opment. The fiscal regimes that work well for primary and
secondary developments in several countries stand in the
way of economic EOR projects, thus change of the fiscal
frameworks is required as well.
Enhanced recovery comes at a price. The technical costs
in dollars per barrel produced are notably higher than
those of primary or secondary recovery methods. In addi-
tion, the environmental footprint of some EOR techniques
Enhanced Oil Recovery: Here to Stay
1
can be significant and necessitates mitigation, also adding
to the costs. EOR processes developed in the past are not
necessarily the solutions we need for today and tomorrow.
We therefore need continued investment in EOR technology
development, from the processes and fundamental concepts,
to new engineering solutions, to surveillance techniques
that improve sweep efficiency.
Recent research efforts have greatly advanced the funda-
mental understanding of the rock and fluid interface in
chemical EOR. This understanding has opened up new
opportunities that have lower costs and higher recovery
efficiencies. It has also increased the scope for recovery to
domains that were previously thought to be unattractive
as targets for EOR. However, more work is required. If we
want to reduce the EOR technology timeline and deploy
projects earlier, we must encourage wider cooperation
between industry, academia and resource holders. There
must be sharing of risk, data and knowledge while address-
ing and overcoming potential blocks such as intellectual
property ownership and other commercial aspects.
I am therefore pleased that Schlumberger and Shell
have recently agreed to start a significant landmark
research partnership. The research is aimed at discovering
and developing new methodologies and technologies for
enhancing recovery, with the aim of addressing many of
the challenges mentioned above. Enhanced oil recovery is
here to stay.
Jeroen Regtien
Vice President, Hydrocarbon Recovery Technologies
Innovation, Research & Development
Shell International Exploration and Production
Jeroen Regtien leads the improved oil recovery/enhanced oil recovery, smart
field, CO2 storage and rock and fluid science research and development
activities in the Shell Projects and Technology Group. His extensive career in
the upstream oil and gas industry has included roles as technical manager,
chief petroleum engineer, manager of strategy and planning, head of geother-
mal energy, asset manager and development manager during assignments in
Brunei, Australia, Oman, the USA and The Netherlands. He is a member of
the World Petroleum Council and International Advisory Board of the Oman
Research Council. Jeroen is an experimental physicist with an MSc degree
from the University of Groningen, The Netherlands.

4. www.slb.com/oilfieldreview
Schlumberger
Oilfield Review
1 Enhanced Oil Recovery: Here to Stay
Editorial contributed by Jeroen Regtien, Vice President, Hydrocarbon Recovery Technologies
Innovation, Research & Development; Shell International Exploration and Production
4 Coaxing Oil from Shale
Oil shale contains copious amounts of immature organic
material. Heating the rock accelerates the normal maturation
process to generate oil and gas. Historically, oil shales were
mined, crushed and heated at the surface, but companies are
finding it may be more efficient to access these formations
through boreholes, heat the subsurface and bring the oil to
the surface.
16 Has the Time Come for EOR?
Enhanced oil recovery (EOR) methods are designed to
produce additional oil beyond what is obtainable through
traditional methods of pressure depletion and simple
pressure maintenance. EOR techniques include miscible
gasflooding, chemical flooding and thermal recovery.
This article describes the basics of these methods; field
examples illustrate their application.
Executive Editor
Mark A. Andersen
Advisory Editor
Lisa Stewart
Senior Editors
Matt Varhaug
Rick von Flatern
Editors
Vladislav Glyanchenko
Tony Smithson
Contributing Editors
Rana Rottenberg
Ginger Oppenheimer
Design/Production
Herring Design
Steve Freeman
Illustration
Chris Lockwood
Mike Messinger
George Stewart
Printing
Wetmore Printing Company
Curtis Weeks
Oilfield Review is published quarterly and
printed in the USA.
Visit www.slb.com/oilfieldreview for
electronic copies of articles in multiple
languages.
© 2011 Schlumberger. All rights reserved.
Reproductions without permission are
strictly prohibited.
For a comprehensive dictionary of oilfield
terms, see the Schlumberger Oilfield
Glossary at www.glossary.oilfield.slb.com.
About Oilfield Review
Oilfield Review, a Schlumberger journal,
communicates technical advances in
finding and producing hydrocarbons
to employees, clients and other oilfield
professionals. Contributors to articles
include industry professionals and experts
from around the world; those listed with
only geographic location are employees
of Schlumberger or its affiliates.
On the cover:
Engineers prepare a slim tube for a test
of minimum miscibility pressure at the
Schlumberger Reservoir Fluids Center in
Houston. The sand-filled metal coil
provides sufficient length for a multiple-
contact miscibility condition to develop
between a crude oil in the coil and an
injected gas. Miscible gas injection is
one of several enhanced oil recovery
methods used to sweep post-waterflood
residual oil from a reservoir (inset).
2

5. Winter 2010/2011
Volume 22
Number 4
ISSN 0923-1730
50 Contributors
52 New Books and Coming in Oilfield Review
54 Annual Index
3
36 Petroleum Potential of the Arctic:
Challenges and Solutions
Although constituting only about 6% of the Earth’s surface,
the Arctic potentially contains a significant portion of the
world’s undiscovered petroleum resources and, thus, is
attracting the growing attention of oil and gas companies.
However, this region poses numerous challenges, including a
harsh climate, short operational season, complex surface and
shallow-subsurface conditions and increasing environmental
restrictions. Operators and service companies are improving
existing technologies and developing new ones to address the
unique challenges of this remote region.
Abdulla I. Al-Kubaisy
Saudi Aramco
Ras Tanura, Saudi Arabia
Dilip M. Kale
ONGC Energy Centre
Delhi, India
Roland Hamp
Woodside Energy Ltd.
Perth, Australia
George King
Apache Corporation
Houston, Texas, USA
Richard Woodhouse
Independent consultant
Surrey, England
Advisory Panel
Editorial correspondence
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6. 4 Oilfield Review
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
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.
Oil shale is the term given to very fine-grained
sedimentary rock containing relatively large
amounts of immature organic material, or kero-
gen. 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 gen-
erate oil. But the process can be accelerated by
heating the kerogen-rich rock more quickly and
to higher temperatures, generating liquid hydro-
carbons in much shorter time: from a matter of
minutes to a few years.
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.

7. Winter 2010/2011 5
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 hun-
dreds 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 short-
ages 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 innova-
tive applications of oilfield technology for evaluat-
ing oil shale deposits and assessing their richness.
Oil Shale Formation
Oil shales form in a variety of depositional envi-
ronments, including freshwater and saline lakes
and swamps, near-shore marine basins and
subtidal shelves.1
They may occur as minor sedi-
mentary layers or as giant accumulations hun-
dreds of meters thick, covering thousands of
square kilometers (above right).
As with other sedimentary rocks, composi-
tions 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, gen-
erate additional CO2 that must be considered in
any oil shale development program. Many depos-
its also contain valuable minerals and metals
such as alum, nahcolite, sulfur, vanadium, zinc,
copper and uranium, which may themselves be
targets of mining operations.
> 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.)
Oilfield Review
Winter 10
Oil Shale Fig. 1
ORWIN10-OilShl Fig. 1
> 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.)
Clay
Minerals
Calcite and Dolomite
Siliceous
dolomite
Eagle Ford
Niobrara
Calcareous
or dolomitic
mudstone
Argillaceous
marlstone
Siliceous
marlstone
Argillaceous
mudstone
(traditional shale)
Siliceous
mudstone
Monterey
Montney
MuskwaBarnett
Bakken
Haynesville
Lower
Marcellus
Siliceous shale
Monterey
porcellanite
Bazhenov
Average shale
Garden Gulch Member
Parachute Creek Member
Gas shales from Poland
Quartz and
Feldspar
Various other locations

8. 6 Oilfield Review
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
remains of lacustrine and marine algae, and con-
tains 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 geo-
chemists (left).
The thermally immature kerogens in oil
shales have undergone low-temperature diagen-
esis 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, achiev-
ing full maturity and expelling their oil and natu-
ral 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
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 applica-
tions, 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 practitio-
ners in what is now Austria touted its healing
properties. By the late 1600s, several municipali-
ties 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 commer-
cial 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 carbon-
ate 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 alternat-
ing 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 coun-
try’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 min-
ing as well, with shale oil production beginning in
the 1920s. In the Fushun area, extensive shale lay-
ers 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 esti-
mated 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),
> 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.
Oilfield Review
Winter 10
Oil Shale Fig. 3
ORWIN10-OilShl Fig. 3
1.5
Hydrogen/carbonratio
1.0
0.5
0 0.1 0.2
Type I
Type II
Type III
Type IV
Oxygen/carbon ratio
Dry gas
Increasing
maturation
CO2, H2O
Oil
Wet gas
No hydrocarbon
potential
Products Given
off from Kerogen
Maturation
> 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.)
Minedshale,millionmetrictons
40
50
30
20
10
0
1880 1900 1920 1940 1960 1980 20001890 1910 1930 1950 1970 1990
Year
2010
Germany
China
Brazil
Scotland
Russia
Estonia

9. Winter 2010/2011 7
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 sur-
face mining or through underground mining
using the room-and-pillar method associated
with coal mining. After mining, oil shale is trans-
ported to a facility—a retort—where a heating
process converts kerogen to oil and gas and sepa-
rates the hydrocarbon fractions from the mineral
fraction. This mineral waste, which contains sub-
stantial 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, cool-
ing 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
The world’s oil shale deposits are widely distrib-
uted; 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 explora-
tion efforts—resources of the world’s shale oil total
about5.1×1011 m3 [3.2 trillionbbl].11
Itisestimated
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 recover-
able oil requires information on oil shale proper-
ties, such as organic content and grade, which can
vary widely within a deposit. Traditionally, for the
purposes of surface retorting, oil shale grade is
determinedbythemodifiedFischerassaymethod,
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
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).
> 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.)
Oilfield Review
Winter 10
Oil Shale Fig. 5
ORWIN10-OilShl Fig. 5
Brazil (4)
82
Canada (11)
15
United States (1)
2,085
France (12)
7
Italy (5)
73
Russia (2)
247
China (10)
16
Democratic
Republic of
Congo (3)
100
Australia (8)
31
Shale oil resource,
billion bbl
(global ranking)
Morocco (6)
53
Egypt (13)
5.7
Estonia (9)
16
Israel (14)
4
Jordan (7)
34
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.

10. 8 Oilfield Review
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, pro-
pane, butane, hydrogen, H2S and CO2, can have
significant energy content, but are not individu-
ally specified. Also, some retort methods, espe-
cially 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 Reuil-
Malmaison, 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.
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 pro-
cessing, 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 prod-
uct quality and quantity while minimizing pro-
duction 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 require-
ments 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 sub-
surface 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
weredepositedoverthecourseof10 millionyearsin
EarlyandMiddleEocenetime,inseverallargelakes
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]ofshaleoil.TheGreenRiverareahas
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 fol-
lowed 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 inter-
est 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
> 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.
Oilfield Review
Winter 10
Oil Shale Fig. 6
ORWIN10-OilShl Fig. 6
Shaleoil,degreeAPIgravity
20
24
28
32
36
40
1101001,00010,000100,000
Heating rate, °C/d
ICP LLNL
> 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.)
Red Pinnacle
thermal conduction test
Mahogany field
experiment
Mahogany demonstration
project
Mahogany demonstration
project, South
Deep heater test
Mahogany isolation test
Freeze wall test
Project Name Primary Purpose Dates Heater
Holes
Total
Holes
Depth,
ft
ICP field demonstration
ICP field demonstration
ICP field demonstration,
recovery
ICP field demonstration,
recovery
Heaters
Freeze wall
Freeze wall
1996 to 1998
1981 to 1982
1998 to 2005
2003 to 2005
2001 to present
2002 to 2004
2005 to present
3
6
38
16
21
2
0
14
26
101
27
45
53
233
20
130
600
400
700
1,400
1,700
Oilfield Review
Winter 10
Oil Shale Fig. 9
ORWIN10-OilShl Fig. 9

11. Winter 2010/2011 9
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 viabil-
ity 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 pro-
cess (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 dewa-
tering (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.
. 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.)
Oilfield Review
Winter 10
Oil Shale Fig. 8
ORWIN10-OilShl Fig. 8
Sandstone, siltstone and some
marlstone and lean oil shale
Oil shale
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
Clay-bearing oil shale
Interbedded halite, nahcolite and oil shale
Nahcolite and oil shale A-groove
R-8 zone
Mahogany
zone
B-groove
R-6 zone
R-5 zone
R-4 zone
R-3 zone
L-5 zone
L-4 zone
L-3 zone
L-2 zone
R-2 zone
L-1 zone
R-1 zone
L-0 zone
R-0 zone
0 20 40 60 80 100
Shale oil yield,
galUS/tonUS
Anvil Points
Member
0
500
1,000
1,500
2,000
2,500
3,000
GardenGulch
MemberParachuteCreekMember
GreenRiverFormation
Generalized
LithologyDepth, ft
Rich oil shale zones, carbonate rich
Rich oil shale zones, clay rich
Lean oil shale zones, carbonate rich
Lean oil shale zones, clay rich
UintaFormation
(withtonguesofGreenRiverFormation)
Shale Oil Resources
109 tonUS
Total
Mahogany
Zone
147.17
No data
1,008.10
No data
109 bbl
No data
No data
No data
No data
115.35
10.70
53.07
20.08
58.38
18.72
107.78
60.85
178.72
52.42
159.09
172.94
R-1
L-1
R-2
L-2
R-3
L-3
R-4
L-4
R-5
L-5
R-6
R-8
L-0
R-0
16.84
1.56
7.75
2.93
8.52
2.73
15.74
8.88
26.09
7.65
23.23
25.25
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.

12. 10 Oilfield Review
The ICP method uses closely spaced down-
hole electric heaters to gradually and evenly heat
the formation to the conversion temperature of
about 650°F [340°C]. Depending on heater spac-
ing 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 low-
value 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 commercial-
scale project is expected to have an energy
gain close to 3, meaning the energy value of the
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 prod-
ucts, 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 ground­
water. 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 pro-
duced and the residual shale is cleaned of con-
taminants by flushing with clean water. The
recovered oil in one test had 40 degree API grav-
ity, 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 cir-
cle (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 chill-
ing 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 con-
version. 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 pro-
duced by conventional methods. Calcined petro-
leum coke, a granular form of relatively pure
carbon, is being tested as the Electrofrac conduc-
tant. 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 diffu-
sion. A potential advantage of the Electrofrac pro-
cess 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 com-
pared 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.
> 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.
Oilfield Review
Winter 10
Oil Shale Fig. 10
ORWIN10-OilShl Fig. 10
Plan View
Side View
22 ft
50 ft
8 ft
1,400-ft
freeze
interval
430-ft
heated
interval
Inside monitor (8)
Freeze (18)
Producer (1)
Heater (2)
Wells

13. Winter 2010/2011 11
> 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.
Oilfield Review
Winter 10
Oil Shale Fig. 11
ORWIN10-OilShl Fig. 11
A
B
C
Oilfield Review
Winter 10
Oil Shale Fig. 11
ORWIN10-OilShl Fig. 11
A
B
C
Plan View
Side View
Test
Section B
1,700-ft
freeze
interval
Test
Sections
A and C
1,500-ft
freeze
interval
224 ft
Freeze well8 ft
B
C
A
> 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.)
20/40 Mesh Proppant
Calcined Coke
Toe connector well Production wells Electrofrac process
heater wells
Conductive heating and
oil shale conversion
Hydraulic fracture
with electrically
conductive material

14. 12 Oilfield Review
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:
• That the conductant in the fracture can main-
tain its electrical continuity while the surround-
ing rock is heated to conversion temperatures.
• That oil and gas generated by the process are
expelled from oil shale, not only at surface con-
ditions, but also under in situ stress conditions.
• That 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 cre-
ated two Electrofrac fractures at Colony by drill-
ing horizontally into the oil shale and pumping a
slurry of calcined petroleum coke, water and
portland cement at pressures sufficient to break
the rock. The larger of the two Electrofrac frac-
tures 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 low-
temperature 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 elec-
trically 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 pro-
cess 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 bot-
tom 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 pro-
duced 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 produc-
tion 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 pro-
cessing methods.29
Meanwhile, the aromatic
portions of kerogen tend to stay in the rock
matrix as coke. More than enough gas is copro-
duced 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 deliv-
ery by convection and conduction is much more
effective than by conduction alone. The CCR pro-
cess is estimated to give a total energy gain
between 4 and 5, counting all the surface facility
requirements, including an oxygen plant for pro-
ducing 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.
> 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.
Depth,ft
1,000
0
500
1,500
2,000
Low-salinity water
High-salinity water
Mahogany zone
Nahcolitic oil shale caprock
Illitic oil shale
Heating well
Production well
2,000 ft
Boiling oil
Vapor
Condensate
Condensate
Heating well
Rubble-
filled
retort
Production well
Oilfield Review
Winter 10
Oil Shale Fig. 13
ORWIN10-OilShl Fig. 13
> 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.
200ft
2,000ft
2,000ft
2,000 ft
Panel being drilled
Panel being retorted

15. Winter 2010/2011 13
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 trans-
lates into about 1 billion bbl [1.6 × 108 m3] of oil
to be produced from an 8-mi2 [20.8-km2] lease.
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 log-
ging 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 reso-
nance responses. In a formation with porosity
that is filled with both kerogen and water, the
density porosity measurement does not distin-
guish 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 vol-
ume 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 mag-
netic 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.
> 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.
X,000
X,050
X,100
X,150
X,200
Depth,
ft6 16in.
Caliper
0 10
PEF
0 200gAPI
Gamma
Ray
0.2 2,000ohm.m
10-in. Array
0.2 2,000ohm.m
20-in. Array
0.2 2,000ohm.m
30-in. Array
0.2 2,000ohm.m
60-in. Array
0.2 2,000ohm.m
90-in. Array
Resistivity
NMR Porosity
45 % –15
Density Porosity
45 % –15
Porosity
0 % 50
TOM Log
0 % 50
Core Fischer Assay
Total Organic MatterKerogen
Illite
Montmorillonite
Orthoclase
Pyrite
Dawsonite
Nahcolite
Albite
Quartz
Calcite
Dolomite
Bound water
Kerogen
Water
Oilfield Review
Winter 10
Oil Shale Fig. 15
ORWIN10-OilShl Fig. 15

16. 14 Oilfield Review
results on Green River shales, researchers com-
puted an estimated Fischer assay log based on
the wireline logging measurements (above). The
estimated Fischer assay values show excellent
agreement with those from laboratory measure-
ments 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], cal-
cium [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 concen-
tration, some carbon is inorganic and some
organic. The inorganic carbon combines with cal-
cium and other elements to form calcite and
dolomite, along with lesser-known minerals,
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 car-
bon. 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 inde-
pendently 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, effi-
cient means to characterize shale oil yield with-
out having to resort to core measurements.
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 aban-
doned 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 radio-
frequency (RF) transmitters, has also been mod-
eled 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 effi-
ciency, 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 produc-
tion. Operators are still working to optimize their
heating technologies. For a given oil shale, the
> 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 ρk of the kerogen, bulk density of the formation
ρb and the difference between density porosity φD and magnetic resonance
porosity φMR. 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).
Oilfield Review
Winter 10
Oil Shale Fig. 16
ORWIN10-OilShl Fig. 16
Fischerassay,galUS/tonUS
20
0
40
60
80
X,000 X,050 X,100 X,150 X,200
Depth, ft
Core-measured Fischer assay values
Well log Fischer assay estimate
TOM = φD φMR
ρk
ρb
( – )
Total organic matter
as fraction of ore weight
Totalorganicmatter(TOM),%
0
10
20
30
40
20 40 600
Modified Fischer assay, galUS/tonUS
TOM = φD φMR
ρk
ρb
( – )
Total organic matter
as fraction of ore weight
> Fischer yield from TOC. Fischer assay estimates
(black) from the TOC log exhibit an excellent
correlation with core Fischer assay results (red).
Oilfield Review
Winter 10
Oil Shale Fig. 19
ORWIN10-OilShl Fig. 19
Depth,ft
X,200
X,000
X,400
X,600
X,800
Y,000
Y,200
Y,400
0 20 40 60
Shale oil yield, galUS/tonUS
TOC converted to
Fischer assay yield
Core Fischer assay

17. Winter 2010/2011 15
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 thermo-
mechanical 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 compac-
tion 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 mineral-
ization 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.
Work also remains to understand the kerogen-
maturation process. To optimize heating pro-
grams, operators would like to know when the
shale has been heated enough and if the subsur-
face volume has been heated uniformly. To this
end, scientists are conducting laboratory experi-
ments to monitor the products of kerogen pyroly-
sis.35
To understand when the process should be
modified or stopped, researchers plan to analyze
the composition of an oil shale and its hydrocar-
bons 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
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
> 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.
0 20 40
Total carbon, weight percent
Depth,ft
X,000
X,200
X,400
X,600
X,800
Y,000
Y,200
Y,400
0 10 20
Inorganic carbon, weight percent
0 20 40
0 20 4010 30Organic carbon, weight percent
TOC, weight percent
150-ftinterval
Oilfield Review
Winter 10
Oil Shale Fig. 18
ORWIN10-OilShl Fig. 18
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.

18. 16 Oilfield Review
Has the Time Come for EOR?
For twenty years, much of the E&P industry turned away from the term enhanced oil
recovery. Yet, during that period, field successes through flooding with steam and
carbon dioxide continued. Decreasing production levels in maturing fields have
revived interest in enhanced recovery techniques in many parts of the world.
Improved technologies for understanding and accessing reservoirs have increased
the possibilities for successful EOR implementation.
Rifaat Al-Mjeni
Shell Technology Oman
Muscat, Oman
Shyam Arora
Pradeep Cherukupalli
John van Wunnik
Petroleum Development Oman
Muscat, Oman
John Edwards
Muscat, Oman
Betty Jean Felber
Consultant
Sand Springs, Oklahoma, USA
Omer Gurpinar
Denver, Colorado, USA
George J. Hirasaki
Clarence A. Miller
Rice University
Houston, Texas, USA
Cuong Jackson
Houston, Texas
Morten R. Kristensen
Abingdon, England
Frank Lim
Anadarko Petroleum Corporation
The Woodlands, Texas
Raghu Ramamoorthy
Abu Dhabi, UAE
Oilfield Review Winter 2010/2011: 22, no. 4.
Copyright © 2011 Schlumberger.
CHDT, CMR-Plus, Dielectric Scanner, ECLIPSE, FMI, MDT,
MicroPilot and Sensa are marks of Schlumberger.
A tantalizingly large source of additional oil sits
within reach of existing oilfield infrastructure.
Operating companies know where it is, and they
have a good idea how much is there. This resource
is oil left in reservoirs after traditional recovery
methods, such as primary production and water-
flooding, have reached their economic limits.
The percentage of original oil remaining var-
ies from field to field, but a study of 10 US oil-
producing regions found that about two-thirds of
the original oil in place (OOIP) remained after
traditional recovery methods were exhausted.1
The study found that about 23% of the oil remain-
ing in those regions could be produced using
established CO2 flood technologies. That techni-
cally recoverable resource of almost 14 billion m3
[89 billion bbl] of oil could, by itself, supply more
than a decade of US consumption at current
rates. Interest in methods to recover those
resources has increased in recent years.2
Worldwide, the number of mature fields will
continue to grow, with more passing their produc-
tion peak each year. Operators work to optimize
recovery from these fields, and in the past 20
years tremendous advances have been made that
help access the remaining resource. Bypassed oil
can be located with advanced logging tools, 4D
seismic evaluations, crosswell imaging technolo-
gies, 3D geomodeling and other state-of-the-art
software systems. The industry has made strides
in understanding clastic sedimentary structures
and carbonate petrophysics to construct models
and in reservoir geomechanics to plan well paths.
Today, the industry can drill more-complex wells
and precisely reach multiple targets containing
untapped oil. Completions can be designed to bet-
ter monitor and control production and injection
downhole and to measure fluid properties both in
situ and at the surface. Tailored chemicals can be
designed to improve recovery, and advanced
research is looking at the use of nanoparticles to
mobilize remaining oil. In addition, the world is
now more environmentally aware, presenting the
opportunity to use depleted reservoirs for storage
of CO2 while also increasing recovery factors.
Methods for recovering oil are referred to
by several terms.3
An early concept described
sequential phases of production using the
terms primary (pressure depletion, including
natural water or gas drive), secondary (mostly
1. Hartstein A, Kusskraa V and Godec M: “Recovering
‘Stranded Oil’ Can Substantially Add to U.S. Oil Supplies,”
Project Fact Sheet, US Department of Energy Office of
Fossil Energy (2006), http://fossil.energy.gov/programs/
oilgas/publications/eor_co2/C_-_10_Basin_Studies_
Fact_Sheet.pdf (accessed November 8, 2010).
2. For a recent review of enhanced recovery methods:
Manrique E, Thomas C, Ravikiran R, Izadi M, Lantz M,
Romero J and Alvarado V: “EOR: Current Status and
Opportunities,” paper SPE 130113, presented at the SPE
Improved Oil Recovery Symposium, Tulsa, April 24–28, 2010.
For results of a biennial survey of activity: Moritis G:
“Special Report: EOR/Heavy Oil Survey: CO2 Miscible,
Steam Dominate Enhanced Oil Recovery Processes,”
Oil & Gas Journal 108, no. 14 (April 19, 2010): 36–53.
Moritis G: “EOR Oil Production Up Slightly,” Oil & Gas
Journal 96, no. 16 (April 1998): 49–77, http://www.ogj.
com/index/current-issue/oil-gas-journal/volume-96/
issue-16.html (accessed February 7, 2011).
3. A proposal made to the SPE in 2003 to clarify the
definitions was not implemented. See Hite JR, Stosur G,
Carnahan NF and Miller K: “IOR and EOR: Effective
Communication Requires a Definition of Terms,” Journal
of Petroleum Technology 55, no. 6 (June 2003): 16.

19. Winter 2010/2011 17

20. 18 Oilfield Review
water- or gasflooding, including pressure main-
tenance) and tertiary (everything else).
However, with advances in reservoir modeling,
engineers sometimes found that waterflooding
should occur before pressure decline, or that a
tertiary method should be used in place of a
waterflood, or that potential recovery by a ter-
tiary method might be lost due to reservoir
damage from earlier activities. The terms lost
their original sense of a chronological order.
Engineers today often include methods for-
merly termed tertiary as part of the field devel-
opment plan from the beginning.
Another distinction that has been difficult to
define is that between improved oil recovery
(IOR)—which had essentially the same defini-
tion as secondary recovery—and enhanced oil
recovery (EOR), which included more-exotic
recovery methods. Over the years, a few EOR pro-
cesses were commercially successful in many
applications, and some companies began refer-
ring to them as a form of IOR instead. This rela-
beling process accelerated after many companies
severely cut or stopped funding EOR research
during the era of low crude-oil prices in the 1980s
and 1990s.4
Regardless of the labels used, the range of
activities applied to increase recovery from reser-
voirs is wide. Waterflooding is common as an eco-
nomical way to displace oil and provide pressure
support. Methods that improve physical access to
oil include infill drilling, horizontal drilling,
hydraulic fracturing and installation of certain
types of completion hardware. Conformance con-
trol improves recovery by blocking off high-
permeability zones either by mechanical means,
such as inflow control devices, or by injecting flu-
ids, such as foam or polymer, that plug those
zones; these activities improve recovery from
lower-permeability zones. Thermal processes are
common to decrease viscosity of heavy oils and to
mobilize light oils.
Finally, injecting chemicals and effective
recovery gases—such as CO2—can change certain
physical properties of the crude oil-brine-rock
(COBR) system. These methods alter inter­facial
tension (IFT), mobility, viscosity or wettability,
swell the oil or alter its phase composition.
The specific method or combination of EOR
methods applied to recover oil is typically based
on an engineering study of each reservoir. In
most cases, the objective is to achieve the most
economical return on investment, but some
national oil companies have different goals, such
as maximizing ultimate recovery. Operators
examine several risk factors, including oil price,
need for a long-term program to achieve satisfac-
tory return on investment, large upfront capital
investments and cost of drilling additional wells
and running pilots.
Many oil-recovery techniques depend on pore-
level interactions involving COBR-system proper-
ties. Most projects begin by screening EOR
candidates against field parameters such as tem-
perature, pressure, salinity and oil composition.5
Many companies have established screening
criteria for EOR projects, but since these are
changing as new technologies are introduced, this
article does not present a specific set of criteria.6
EOR techniques that pass initial screening
are further evaluated based on laboratory studies
of the rock and fluids and on simulation studies
that use field properties. If laboratory tests have
positive results, the operator might next perform
field-level tests, ranging from single-well to
multiple-pattern pilots. If the early steps indicate
likelihood of a positive economic result, full-field
implementation can follow.
EOR technology has even resurrected signifi-
cant levels of production after abandonment. The
Pru Fee property in Midway-Sunset field, San
Joaquin basin, California, USA, produced about
2.4 million bbl [380,000 m3] of heavy oil between
start of production in the early 1900s and
abandonment in 1986.7
Cyclic steam injection
had been partially successful in increasing pro-
duction, but by the time of abandonment, the oil
rate was less than 10 bbl/d [1.6 m3/d] for the
entire field.
In 1995, The US Department of Energy (DOE)
selected the Pru Fee property for a demonstra-
tion EOR project. After cyclic steamflooding in
several old wells at the center of the site demon-
strated good production levels, the project team
added 11 new producers, 4 injectors and 3 tem-
perature-observation wells, obtaining production
rates in the range of 363 to 381 bbl/d/well [57.7 to
60.6 m3/d/well]. In 1999, operator Aera Energy
added 10 steamflood patterns.8
By 2009, the site
had produced an additional 4.3 million bbl
[684,000 m3] of oil after original abandonment.9
This article describes a broad range of recov-
ery methods, but focuses on techniques tradition-
ally considered EOR—and referred to as
such—including miscible and immiscible gas-
flooding, chemical flooding and thermal technol-
ogies. A case study for a Gulf of Mexico field
evaluated its gasflooding potential. An extensive
laboratory evaluation indicates how to tailor a
chemical combination for EOR injection. Another
case, from Oman, describes the first use of a
method for performing rapid single-well, in situ
evaluations of injection to demonstrate the effi-
ciency of a flooding process.
Displacement Efficiency
Waterflooding in oil fields was first legalized in
the US in the state of New York in 1919, but so-
called unintentional waterflooding was recorded
as early as 1865, near Pithole City, Pennsylvania,
USA.10
Less than a decade after waterflooding
became legal, inventors proposed means to
improve flood recovery by adding surfactant to
lower interfacial tension or by injecting alkali to
generate surfactant in situ—both now accepted
EOR methods.11
A boom of activity in EOR techniques came
after the oil-price rise of the 1970s, but the bust
in the late 1980s led many companies to abandon
marginal and uneconomic projects (above left).
A sustained period of higher crude-oil prices in
> EOR project history. The number of ongoing EOR field projects in the US
peaked in 1986, then declined for nearly 20 years. Since 2004, the number of
projects has been rising again. Currently, miscible gas EOR projects (green)
dominate, followed by thermal projects (pink). At present, only a few
chemical floods (blue) are underway. [Data from Moritis (1998 and 2010),
reference 2.]
Oilfield Review
Winter 10
EOR Fig. 1
ORWIN10-EOR Fig. 1
NumberofUSprojects
600
500
400
300
200
100
1978
Data from Oil & Gas Journal surveys
Chemical
Thermal
Gas
1982 1986 1990
Year
1994 1998 2002 2006 2010
0

21. Winter 2010/2011 19
the past 10 years has revived operator interest in
some of these techniques and encouraged intro-
duction of new ones. That interest has survived
the more recent price volatility.
Many techniques aimed at improving recov-
ery are designed to increase the efficiency of oil
displacement using injected water or other flu-
ids. Some methods address the macroscopic dis-
placementefficiency,alsocalledsweepefficiency.
Other recovery methods focus on microscopic, or
pore-scale, displacement efficiency. The overall
displacement efficiency is the product of both
macroscopic and microscopic efficiencies.
Macroscopic displacement—At the scale of
interwell distances, oil is bypassed because of lat-
eral or vertical formation heterogeneity, well-
pattern inefficiencies or low-viscosity injection
fluids. Improving sweep efficiency is typically one
of the goals of reservoir engineering and model-
ing. Although the efficiency of well patterns such
as five- or nine-spots can be determined for a uni-
form reservoir, reservoir heterogeneities affect
flow paths (above left). If these are unknown or
not compensated for by adjusting the pattern,
then sweep efficiency suffers.
Advances in seismic acquisition, processing
and interpretation have given reservoir engi-
neers new tools to locate faults and layer changes.
Some companies have applied 4D seismic meth-
ods to follow a flood front through a reservoir,
allowing their engineers to update models based
on observed flow geometries. Pattern sweep effi-
ciency can be improved by infill drilling or the
use of horizontal or extended-reach wells and by
creating zones within well intervals using down-
hole flow-control devices.12
Sweep is also affected by vertical variations in
properties (above right). In particular, a high-
permeability, or thief, zone will be swept by a
waterflood before adjacent low-permeability
zones are swept. Techniques can be applied to
equalize the flow in the zones, most commonly
by decreasing thief-zone permeabilities. If there
is little or no communication between zones,
the thief zone can be shut off near the injection
site, but if the zones communicate throughout
the reservoir, it may be necessary to design an
injectant that will block the zone all the way to
the producing well. For both near-well and far-
field solutions, engineers use foams and polymers
for this purpose.
Viscous fingering is another concern of macro-
scopic displacement efficiency. If the displacing
fluid—typically water—is significantly less vis-
cous than the oil it is displacing, the flood front
can become unstable. Rather than being linear or
radially symmetric, the leading edge of the front
4. One indication of the rise and fall of the term EOR is the
naming of the biennial meeting sponsored by the SPE in
Tulsa. The first five meetings, spanning 1969 through
1978, were called the SPE Improved Oil Recovery
Symposia. From 1980 through 1992, the US Department of
Energy jointly sponsored the conferences, and they were
called the SPE/DOE Enhanced Oil Recovery Symposia. In
1994, the conferences returned to sole sponsorship by
SPE, and again became the SPE Improved Oil Recovery
Symposia, which they remain today. Throughout this
31-year period, conference papers covered topics
typically considered both IOR and EOR.
5. Lake LW, Schmidt RL and Venuto PB: “A Niche for
Enhanced Oil Recovery in the 1990s,” Oilfield Review 4,
no. 1 (January 1992): 55–61.
6. For an overview of EOR engineering, including criteria to
consider: Green DW and Willhite GP: Enhanced Oil
Recovery. Richardson, Texas, USA: Society of Petroleum
Engineers, SPE Textbook Series, vol. 6, 1998.
> Areal displacement efficiency. Oil can be bypassed
because of inefficiencies in macroscopic sweep.
A pattern flood can be affected by a heterogeneous
formation (such as the presence of sealing faults)
or by fingering of a less viscous injectant into
the oil.
Sealing
fault
Viscous fingers
Injectant
Injection well Production well
Pattern Flood
> Vertical displacement efficiency. Vertical sweep can be affected by viscous
fingering, as well as by preferential movement of fluids along a high-
permeability thief zone or by gravity override of injection gas (as indicated
here) or underride of injection water.
Vertical Profile
Gravity
override
Barrier
Barrier
High permeability
Low permeability
For another set of criteria: Taber JJ, Martin FD and
Seright RS: “EOR Screening Criteria Revisited—Part 1:
Introduction to Screening Criteria and Enhanced
Recovery Field Projects,” SPE Reservoir Engineering 12,
no. 3 (August 1997): 189–198.
Taber JJ, Martin FD and Seright RS: “EOR Screening
Criteria Revisited—Part 2: Applications and Impact of
Oil Prices,” SPE Reservoir Engineering 12, no. 3
(August 1997): 199–205.
7. Schamel S: “Reactivation of the Idle Pru Lease of
Midway-Sunset Field, San Joaquin Basin, CA,” The Class
Act: DOE’s Reservoir Class Program Newsletter 7, no. 2
(Summer 2001): 1–6, www.netl.doe.gov/technologies/
oil-gas/publications/newsletters/ca/casum2001.pdf
(accessed November 10, 2010).
8. Schamel S and Deo M: “Role of Small-Scale Variations in
Water Saturation in Optimization of Steamflood Heavy-Oil
Recovery in the Midway-Sunset Field, California,”
SPE Reservoir Evaluation & Engineering 9, no. 2
(April 2006): 106–113.
9. State of California Department of Conservation Division
of Oil, Gas and Geothermal Resources, Online
Production and Injection database, http://opi.consrv.
ca.gov/opi (accessed December 3, 2010).
10. Blomberg JR: “History and Potential Future of Improved
Oil Recovery in the Appalachian Basin,” paper SPE
51087, presented at the SPE Eastern Regional Meeting,
Pittsburgh, Pennsylvania, USA, November 9–11, 1998.
11. Uren LC and Fahmy EH: “Factors Influencing the
Recovery of Petroleum from Unconsolidated Sands
by Water-Flooding,” Transactions of the AIME 77
(1927): 318–335.
Atkinson H: “Recovery of Petroleum from Oil Bearing
Sands,” US Patent No. 1,651,311 (November 29, 1927).
12. Ellis T, Erkal A, Goh G, Jokela T, Kvernstuen S, Leung E,
Moen T, Porturas F, Skillingstad T, Vorkinn PB and
Raffn AG: “Inflow Control Devices—Raising Profiles,”
Oilfield Review 21, no. 4 (Winter 2009/2010): 30–37.

22. 20 Oilfield Review
forms waves that transition to fingers extending
farther into the oil. Eventually, water fingers reach
the producing well. At that point, additional
injected water will preferentially follow the water-
filled paths. Engineers avoid this by increasing
water viscosity through methods such as adding
polymer or foam to it.
Microscopic displacement—At the other end
of the size scale, small blobs of oil can be trapped
within a pore or a connected group of pores
(above). Oil at this scale is trapped because vis-
cous or gravity-drive forces within the pore space
are insufficient to overcome capillary forces.
The amount of oil trapped within pore spaces
depends on a variety of physical properties of
the COBR system. One of these properties is
wettability.13
In a strongly water-wet rock, water
preferentially coats the pore walls. Conversely,
strongly oil-wet surfaces within a pore are pref-
erentially contacted by oil. In an intermediate-
wetting condition, the pore surfaces do not have
a strong preference for either water or oil.
Most reservoir rocks have a mix of wetting
conditions: The smaller pores and spaces near
grain contacts are generally strongly water wet-
ting, while the surfaces bounding the larger pore
bodies may range from less water wetting to oil
wetting. Thus, the wettability of the bulk material
is between the two extremes. Although measures
of wettability, such as Amott-Harvey or US Bureau
of Mines (USBM) wettability tests, may result in
similar index numbers for intermediate and
mixed-wet rocks, the two are distinct wetting
conditions. Intermediate wettability applies to
rocks with all surfaces of neutral wetting prefer-
ence, while mixed wetting applies to rocks with
surfaces of markedly different wettability.
Optimalrecoveryfromwaterfloodingisobtained
in mixed-wet material that is slightly water wet-
ting.14
The reason for this can be made clear by a
discussion of pore-level oil-trapping mechanisms.
Most reservoirs were water-wet formations
before oil accumulated. Oil migrating into a for-
mation must overcome the rock’s wetting forces
before it can enter the pores. This resistance is the
rock’s capillary entry pressure, which is the pres-
sure difference between the water and oil phases
needed to overcome wetting forces in small open-
ings. The capillary entry pressure is inversely pro-
portional to the radius of the opening, or pore
throat, through which the oil must pass.
Since rocks have a variety of pore throat
sizes, any given rock will have a distribution of
capillary entry pressures. Pores having the larg-
est throats are the first to be invaded by the
nonwetting phase, and those with progressively
smaller pore throats are invaded at progres-
sively higher pressure differences between the
phases. Thus, a rock will have a capillary pres-
sure curve indicating the degree of invasion—
represented by the remaining water
saturation—at each capillary pressure (left).
In a reservoir, the source of the pressure dif-
ference between the phases is their density dif-
ference. The depth in the reservoir at which the
water- and oil-phase pressures are the same is
the free-water level.15
The product of the height
above the free-water level, the acceleration of
gravity and the density difference between
phases gives the pressure difference for that
height. That pressure difference supplies the
capillary pressure, resulting in decreasing water
saturation with height above the free-water level
based on the pore throat distribution in the rock.
This is seen in some reservoirs as a transition
zone, where the water saturation changes with
depth in a rock with uniform properties.16
In addition to providing insight into the ini-
tial saturation distribution in a reservoir, capil-
lary pressure is also important for flow dynamics.
The capillary behavior of a formation influences
the irreducible water saturation after water-
flooding. Thus, one of the most important quanti-
ties to know about a reservoir, the maximum
amount of oil that can be recovered by water-
flooding, is strongly influenced by the pore-level
physics of wetting.
If the oil in a pore contains surface-active
components, it can displace a thin layer of water
and contact the rock surface. Thus, the oil in
pores can alter the wettability of the pore sur-
face, making it less strongly water wetting or
even oil wetting. However, the tight spaces in
pores, such as near grain-to-grain contacts,
retain their water coatings and remain strongly
water wetting. This is thought to be the origin of
the mixed-wetting character of most reservoirs.17
When oil is displaced either through a natural
or forced waterdrive, water can encroach into
pore spaces in three ways. It can follow existing
paths of continuous water in the smallest nooks
and crannies of the pore structure and slowly
increase the thickness of that water film.
However, the relative permeability for water flow-
ing along that path is vanishingly small outside
13. For more on wettability: Abdallah W, Buckley JS,
Carnegie A, Edwards J, Herold B, Fordham E, Graue A,
Habashy T, Seleznev N, Signer C, Hussain H, Montaron B
and Ziauddin M: “Fundamentals of Wettability,” Oilfield
Review 19, no. 2 (Summer 2007): 44–61.
14. Jadhunandan PP and Morrow NR: “Effect of Wettability
on Waterflood Recovery for Crude-Oil/Brine/Rock
Systems,” SPE Reservoir Engineering 10, no. 1
(February 1995): 40–46.
15. Free-water level may not correspond to the oil/water
contact because of the filling history of the reservoir.
16. A change in distribution of pore throats, such as occurs
in a sand-shale sequence, also results in an abrupt
saturation change because the rocks have different
capillary pressure curves. Filling and depletion history
can also influence the saturation distribution.
17. Mixed wettability can also occur because different
minerals present in the rock have different affinities for
water and oil.
18. Seccombe J, Lager A, Jerauld G, Jhaveri B, Buikema T,
Bassler S, Denis J, Webb K, Cockin A and Fueg E and
Paskvan F: “Demonstration of Low-Salinity EOR at
Interwell Scale, Endicott Field, Alaska,” paper SPE
129692, presented at the SPE Improved Oil Recovery
Symposium, Tulsa, April 24–28, 2010.
> Microscopic displacement. At the microscopic
scale, oil can be trapped in the middle of pores
(for example, top right) when water flows around
the oil in a water-wet formation. Oil that is
connected to flow paths (bottom right) continues
to be displaced.
Oilfield Review
Winter 10
EOR Fig. 3
ORWIN10-EOR Fig. 3
Oil
Water
Grain
> Capillary pressure curves. Formations have
different capillary pressure relationships,
depending on the distribution of pore throats in the
rock. Starting fully saturated with water, the rock
is exposed to oil at increasing capillary pressures,
and the capillary pressure curve indicates the
degree of saturation at each capillary pressure.
A clean, uniform sandstone (pink) with large pore
throats will have a low capillary entry pressure
Pce1 and a rapid decline in water saturation as the
capillary pressure increases. In contrast, a poorly
sorted sandstone (blue) can have a high capillary
entry pressure Pce2 and a slow decrease in
saturation as the capillary pressure increases.
Water saturation, %
Pce2
Pce1
0 100
Capillarypressure

23. Winter 2010/2011 21
the transition zone because the water layers are
so thin. Alternatively, if the formation is strongly
water wetting, the rock’s affinity for imbibing
water will force oil out of the smaller pore spaces
first, then from increasingly larger pores as the
flood progresses. The flood water connects with
the thin layers of water present on the grains.
Finally, in an oil-wet or mixed-wet formation of
the type described above, water invades the large
pores as the nonwetting phase if the water-phase
pressure is sufficient to overcome the capillary
entry pressure.
In all three cases, as the waterflood pro-
gresses, oil can become trapped within pores as
water finds easier flow paths around it. Once the
water breaks the connection between an oil blob
and the oil sweeping out ahead of the waterfront,
the blob becomes much more difficult to move
(right). This disconnected oil has to move
through pore throats that probably were never
altered from strongly water wetting (even in a
mixed-wet formation), but the only drive force is
the pressure difference between the water
upstream and that downstream of the blob.
One of the reasons that maximum oil recovery
occurs in mixed-wet systems is that oil in contact
with the more oil-wetting (or less water-wetting)
pore surfaces can remain continuous at lower oil
saturations than in a water-wet system. More of
the oil can drain from the pores before it becomes
trapped by water on all sides.
However, in a strongly oil-wetting formation,
remaining oil is trapped in the smaller pores and
its relative permeability gets vanishingly small
as water fills the larger pores. The waterflood
residual oil recovery for a formation that is
strongly oil wetting is less than that of a mixed-
wetting formation.
Flooding Methodologies
Traditionally, many EOR techniques target the oil
remaining after waterflooding. Most methods fall
into one of three general categories: gasflooding,
chemical flooding and thermal techniques. Each
of these has a variety of forms, and they can be
combined to achieve specific results (below).
Waterflooding is generally not considered an
EOR method unless it is combined with some
other flooding method. However, over the past
15 years, the oil industry has investigated low-
salinity waterflooding, which, in some situations,
does recover additional oil following a typical,
high-salinity waterflood.18
Although the oil-
recovery mechanism is not universally accepted,
> Comparison of forces. Capillary forces can trap isolated oil in the pore
space. Typically, capillary forces are overcome by either viscous or gravity
forces. Two dimensionless numbers are used to compare these forces. The
capillary number Nc (left) is a ratio of viscous to capillary forces. To mobilize
the oil, either the brine velocity must be increased or the oil/water IFT must
be brought near zero, which produces a large value of the capillary number.
In a system where gravity is more important, such as gravity stabilized flow,
the relevant quantity to maximize is the Bond (also called the Eötvös) number
Nb (right). In most cases, the wettability is taken as strongly water-wet, with a
contact angle near zero.
Nc =
v µW
σOW cos θ
Nb =
∆ρgL2
σOW cos θ
Viscous forces
= brine velocity
= brine viscosity
Capillary number: Bond number:
v
µW
= oil/water interfacial tension
= contact angle
σOW
θ
Capillary forces
Gravity forces
= oil/water density difference
= acceleration of gravity
= characteristic length (size of oil blob)
∆ρ
g
L
> Physical effects of EOR methods. EOR methods generate various physical effects that help recover remaining oil (shaded boxes). The incremental
recovery factor (right) has a large range of values when compared with waterflooding, which is typically not considered an EOR method.
Waterflood Waterflood Base case2
Low
Low
Moderate
Moderate
Moderate
High
High
Very high
High
Highest
High
High
High
Engineered water
Hydrocarbon
Hydrocarbon
Hydrocarbon WAG
Steam
High-pressure air
Polymer
Surfactant
ASP
IFT = interfacial tension
WAG = water-alternating-gas
ASP = alkali-surfactant-polymer
1. Change of composition of liquid hydrocarbon.
2. Waterflooding provides the base case for comparison of other methods.
3. Oil stripping occurs as miscibility develops.
4. Condensing and vaporizing exchange.
Nitrogen or flue gas
CO2
CO2
CO2 WAG
EOR Method
Pressure
Support
Sweep
Improvement
IFT
Reduction
Wettability
Alteration
Viscosity
Reduction
Oil
Swelling
Hydrocarbon
Single Phase
Incremental
Recovery Factor
Gasflood:
immiscible
Gasflood:
miscible
Thermal
Chemical
Compositional
Change1
3 3
4
4

24. 22 Oilfield Review
most researchers think there is a COBR interac-
tion that liberates additional oil (see “On the
Road to Recovery,” page 34).
Gasflooding—Historically, gasflooding has
often been classified as a secondary or IOR
method. It can be a preferred disposal or storage
method for associated natural gas when there is
no available market, or seasonally when gas
demand is lower than supply. But it can also be
applied after waterflooding, or in combination
with a waterflood, in which case it is considered
an EOR method. When performed in conjunction
with waterflooding, injection typically alternates
between gas and water. The water-alternating-
gas (WAG) cycles improve sweep efficiency by
increasing the viscosity of the combined flood
front (above). In addition, with some fluid com-
positions and in situ conditions, foam may form,
which can further improve the viscosity-related
sweep efficiency.
Depending on the pressure, temperature and
composition of the gas and oil, injection can be
under either immiscible or miscible conditions.
In an immiscible flood, gas and oil remain dis-
tinct phases. Gas invades the rock as a nonwet-
ting phase, displacing oil from the largest pores
first. However, when they are miscible, gas and oil
form one phase. This mixing typically causes the
oil volume to swell while lowering the interfacial
tension between the oil phase and water.
Displacement by miscible-gas injection can be
highly efficient for recovering oil.
The rock wettability also has an impact on oil
recovery by miscible flooding. In a laboratory
core study, the best waterflood oil recovery was in
mixed-wet rocks, followed by intermediate-wet
and water-wet rocks, with oil-wet rocks having
the least waterflood oil recovery.19
For a miscible
gasflood after waterflooding, the greatest amount
of remaining oil was recovered from the oil-wet
core, suggesting that the miscible process could
be considered in place of a waterflood.20
Both the
intermediate-wet and mixed-wet rocks had high
overall recovery from the combined waterflood
and miscible gasflood.
Under some conditions, the fluids are termed
multiple-contact miscible. In this case, when
they first contact one another, gas and oil are not
miscible. However, light components from the oil
enter the gas phase, and the heavy, long-chain
hydrocarbons from the gas enter the liquid phase.
As the front contacts fresh oil, more components
are exchanged, until the gas and the oil reach
compositions that are miscible.21
Various gases are used as EOR injectants.
Natural gas—produced from the same or a neigh-
boring field—has already been mentioned as one
source. Methane or methane enriched with light
ends is also used. A local supply of flue gas, such
as exhaust gas from a power plant, can be utilized
if the transport costs are low enough. Nitrogen,
> Miscible water-alternating-gas (WAG) process. In a miscible WAG process, an injected gas—CO2 in this case—mixes with reservoir oil and creates an oil
bank ahead of the miscible zone. The gas is followed by a slug of water, which improves the mobility ratio of the displacing fluids to avoid fingering. The cycle
of gas and water injection can be repeated many times, until a final waterdrive flushes the remaining hydrocarbon, now mixed with CO2, from the reservoir.
Formation heterogeneities, such as a higher permeability streak (darker layer), affect the shapes of the flood fronts.
Injection well
Injection fluids Oil
Drive fluid
(water)
Water Miscible zone Additional
oil recovery
CO2 CO2 Oil bank
Production well
High-permeability layer
Fault