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					                              Enhanced Oil Recovery

The past and ongoing research into enhanced oil recovery (EOR) can be roughly divided
into four general areas (1) gas injection, including CO2, N2, NGL, flue; (2) Chemical,
including surfactant, surfactant with polymer, surfactant with foam, (3) thermal,
including convention steam, steam assisted gravity drainage, cyclic injection, and in-situ
combustion; and (4) conformance and related issues. Each area has its own history,
potential, technology, opportunities and obstacles. The obstacles can be categorized as
technical, economic and legal/regulatory. Each area is needed to maximize the production
potential of the domestic fields. The “prize” is quite large, however. According to the
U.S. Department of Energy (DOE), 175 billion barrels have been produced in the U.S.
(excluding the deep and ultra-deep water Gulf of Mexico). However, from those same
fields 400 billion barrels are “stranded” after traditional primary and secondary oil
recovery. This compares to an estimated 21 billion barrels of proven reserves, so the
opportunities are enormous.

Gas Injection
As a whole, EOR production in the U.S. is currently around 500 thousand barrels/day and
increasing, nearly 10% of the 5.31 million barrels/day produced in 2009. The increase is
due solely to the increase in enhanced oil production from gas injection, virtually all of
which is CO2. The number of CO2 projects and the production from those projects has
been steadily growing since the late 1970s. In 1986, production was 25,000 barrels/day.
By 2009, it was over 250,000 barrels/day from 101 CO2-EOR projects. The industry has
matured and the technology proven. There have been no CO2 related fatalities since
inception in the transportation, injection and processing of the gas.

Advanced Resources International (ARI) was commissioned by the DOE in 2006 to
perform ten basin studies to assess the potential for CO2 EOR using state of the art
injection and production technology and assuming CO2 was available for $45/tonne
(approximately 19 MCF). The reports of these studies are posted at http://www.fe.doe.
gov/programs/oilgas/eor/Ten_Basin-Oriented_CO2-EOR_Assessments.html. These
reports were recently summarized and updated in a 2008 report entitled “Storing CO2
with Enhanced Oil Recovery”
CO2%20w%20EOR_FINAL.pdf. This summary report covers 27 producing states and
offshore Louisiana. Assuming an oil price of $70/barrel, ARI determined that the
economically recoverable resource is 47.4 billion barrels, which if proven, would triple
the proved reserves in the U.S.

There has been a growing interest and research in the potential to expand conventional
CO2 floods to a residual oil zone (ROZ), found below the present oil-water contact or
transition zone in many reservoirs. These zones are similar to well swept waterflood
reservoirs as they were originally saturated with oil and over geologic time, the mobile
oil was displaced by water leaving the residual. Several CO2 floods in the Permian basin
are currently producing oil from the ROZ and others are planned. ARI modeled the ROZ
resource in three basins: Permian, Williston and Big Horn. Based on their analysis they
are estimating a total of 420 billion barrels of ROZ in place, 54 billion of which is
technically recoverable with today’s CO2 technology. So the size of the prize is growing.

The obstacles to recovering those billions of barrels of potential CO2 EOR are economic,
technical and regulatory/legal. The economic barriers are daunting. For a full scale
project a great deal of money must be spent to re-drill and rework producing and
injection wells, new corrosion flowlines must be installed, a gas processing plant built to
separate the CO2 from the produced stream, and a pipeline built to the CO2source.
Millions of dollars spent up front with a long term, unpredictable (price of oil) stream of
revenue to pay off the investment. The second economic barrier is the cost of a long-term
firm supply of CO2. While the cost of CO2 to the existing operators almost certainly falls
below the $45/tonne level, most of it is coming from the several underground sources,
which (1) are owned and controlled by two companies, and (2) the pipelines from those
sources are full and new pipelines would be very expensive. Most of the rest of the CO2
used in EOR is coming from several large gas processing plants and is a relatively clean
stream, once separated from the produced methane.

With today’s technology, the largest anthropogenic source, coal power generation, costs
considerably more to separate from the fuel or flue gas. To produce the 47 billion barrels
cited above (not counting the ROZ billions) would require over 500 billion MCF of CO2,
(26 billion tones). The total U.S. emissions from every source are in the 5 billion tonne
range with generation responsible for 40% of that. Clearly, separation technology will
have to evolve substantially to capture that quantity at a price that works for EOR.

It is the legal/regulatory barriers that are the least understood. The giant elephant in the
CO2 EOR room is the worldwide push to reduce the CO2 levels in the air through
conservation, technology and sequestration. Much of the U.S. DOE research budget is
devoted to Carbon Capture and Storage (CCS). On the plus side, this will accelerate the
maturity of the now very expensive separation technology, eventually driving the price
down. Also, if a price is placed on the carbon (say, via a cap and trade law) either the
party separating the CO2 or the party sequestering the CO2 (or some combination) would
get the financial credit. In any case, it would make more CO2 available for EOR at a
lower price. In addition, it would provide incremental work for the individuals and
companies currently involved in CO2 EOR as most of those skills and experience are
directly transferrable to geological sequestration, be it in a depleted oil zone or brine

On the negative side, it is clear that the rules for sequestration will be much more
involved than CO2 EOR, particularly in the extensive monitoring area. Most existing CO2
injection wells are permitted by the EPA as Class 2 under the Underground Injection
Program (UIC), the same as an injector in a waterflood. The several pilot sequestration
projects being performed by the Regional Partnership are permitted as Class 5, generally
used for waste disposal wells. The EPA, however, is in the process of writing new rules
for the full scale sequestration projects, perhaps a new Class 6. If the new rules, yet to be
released are imposed on the existing or future CO2 EOR wells, it could make all those
projects uneconomical due to the increased cost to install and operate. Other unresolved
issues surrounding sequestration involve determination of ownership of the pore space
and long term liability of monitor and mitigation.


Thermal enhanced oil recovery techniques are generally applied to relatively shallow
(less than 3,000 feet) very viscous heavy oil (generally defined as oil with API gravity
between 10 and 20 degrees). These techniques include conventional steam floods with
injectors and producers drilled in tight spacing patterns; cyclic production where the
steam is injected and allowed to “soak”, then produced out of the same well; steam
assisted gravity drainage where the steam is injected in one horizontal well and produced
from another lower horizontal well; and rarely in an in-situ combustion project. Heavy oil
typically has a viscosity between 100 and 10,000 cp and does not flow unless diluted with
a solvent or heated.

Thermal EOR has its own set of opportunities and obstacles. Although the daily
production from thermal methods, mainly in California has been in decline for the last
few years, there are still sizeable reserves, not only California, but also Alaska, North and
South Dakota, Wyoming, and Texas. Several successful in-situ combustion projects have
been established in South Dakota. In a study performed for the DOE, ARI has identified
100 billion barrels of heavy oil in place in the U.S. with 42 billion in California and 25
billion barrels in Alaska and that technically possible production could be increased from
the current level of 225 thousand barrels/day to as high as 500 thousand barrels/day. The
current production is based on current best practices and economics. New technology will
be required to address resources deeper than 3,000 feet and the more shallow, but
environmentally-sensitive Arctic resources.

The challenges of thermal EOR are economics and environmental. The conventional
steam flood is usually found in large fields, where economics of scale apply. The up front
capital costs are considerable, with wells drilled on 2 acre spacing, expensive steam
generation and production facilities and insulated flow lines. For environmental reasons,
most steam generators are fired with natural gas, making the operating expenses
considerably higher than convention production. The other economic issue relates to the
price of oil. The thermal EOR projects not only suffer the same effects of volatile oil
prices over time as all oil producers, but the heavy oil, which results in less higher end
products when refined, historically have been priced at a $10 to $15 discount to West
Texas Intermediate.

Environmental concerns present a considerable obstacle to current producing fields and
because of tighter regulatory requirements of new development, even more difficult for
new projects. The first issue is the surface use. With the tight spacing and considerable
steam generator, producing facility and flow lines, there is little else that the surface can
be used for. Obviously, a development of this sort would not be allowed where the
surface is residential or developed for other high end purposes. Also, for the steam
projects, some or all of the water will be supplied by the municipalities, competing with
human use for the quantities. In California in particular where much of the production is
from unconsolidated sand reservoirs, subsidence of the surface may have major effect on
surface infrastructure. Clean air can be an issue with the combustion products of the
steam generators, particularly if a fuel other than natural gas is used.

Other specialized technologies present other challenges. The in-situ projects require
special equipment to deal with the corrosion of sub-surface and surface equipment and
also require careful process of the produced combustion gas. And in Alaska, while the
production techniques are technically capable of developing the thermal projects, new
approaches are needed to allow production of the shallow Alaska North Slope resources
while protecting the permafrost.

The current research in thermal EOR seeks to improve the economics and environmental
issues of thermal production. They include more sophisticated modeling of the in-situ
combustion process, improving the performance of the steam assisted gravity drainage
process, and the use of polymers to improve the oil displacement.

Chemical EOR

There has been a big shift in the design of chemical EOR floods in the 1970’s as
conducted by the major oil companies and those of today. In those early lab analyses and
field demonstration projects of some combination of micellar (surfactant) chemicals and
polymers, they were demonstrated to effective in the lab, but in real applications it took
massive amounts of very expensive chemicals to produce a noticeable amount of oil. As
oil prices dropped, so did interest in chemical flooding. However, recent research has
shown that much smaller quantities of much cheaper chemicals can be effective in some

The 2008 Oil and Gas Journal Worldwide EOR Survey, April 21, only shows two
producing chemical floods, Alkali-Surfactant-Polymer (ASP) in Oklahoma and two
planned in Texas. However ASP or variations of ASP has shown promise at the
laboratory level and is receiving increasing interest in the field.

With ASP process, a very dilute concentration of the surfactant is sufficient to reduce the
interfacial tension between the residual oil and the injected fluid and the formation water
to a very low level. This low tension allows the alkali in the injected oil to move through
the formation and contact the oil. It interacts with the natural acidic components of the oil
to form an additional in-situ surfactant. The higher viscosity polymer component then
mobilizes the oil to push it to the producer.

An alternative process, Surfactant Polymer (SP) works in a somewhat similar manner
except the only surfactant is that that is injected. It is more effective in high salinity
brines and avoids the scale and polymer degradation that can reduce the effectiveness of
the ASP.

Surfactants have been also shown to be effective in improving the performance of
conventional waterfloods in very low permeability rocks. It increases injectivity by
reducing the interfacial tension. It can also be used without the polymer in tertiary
projects where the salinity is too high for the effective use of polymers.

And finally, foams have been shown to be effective in drilling, completion and EOR
production. They are generated using low concentration of surfactants. They can be used
for mobility control in SAG, steam floods, CO2 flood, hydrocarbon floods and Nitrogen

Water and Gas Conformance Control

This diverse group of technologies is generally used to (1) identify and understand the
movement of fluids in the reservoir, and (2) modify the fluids or the matrix permeability
to direct the hydrocarbons to the producing well, while minimizing the production of the
injected fluid.

The first step of conformance is to understand and identify the flow of the fluids. This is
done with careful and thorough reservoir characterization, with subsurface logs, cross
well tomography, petro-physical laboratory analysis, and 4-D seismic as part of that
analysis. Further information can be gained through by periodically conducting injection
and production tests, by zone if applicable. These tests can be conducted with or without
tracer chemicals.

If the reservoir characterization identifies fractures or other high permeability zones are
causing the injected fluid to bypass the oil in less permeable rocks, the high permeability
zone can be treated with any of a variety of polymers or gels. They are permanently (or at
least long term) placed to redirect the injected fluids to the lower permeability zones.

If the issue is that the relative viscosity of the hydrocarbon to the injected fluid results in
immobile oil, the viscosity of the injected fluid can be modified by the addition of
thickeners consisting of polymers and gels designed to resist degradation of the additive
to the reservoir temperature and salinity.

A substantial body of research has and is being done in the laboratories and field to
improve the characterization and to find more effective and less expensive chemicals to
alter the rock permeability or the viscosity of the injected fluid.

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