Energy Tribune  [Printer-friendly version]
March 19, 2008


By Xina Xie

The amount of carbon dioxide used in enhanced oil recovery projects
indicates the number of wells needed for large-scale sequestration
projects. And that number is huge.

Carbon dioxide sequestration has become part of the lexicon in the
media, in government proclamations, and even in professional papers.
What is real, what is realistic, and what is practical? Candidates for
geological sequestration can be oil and gas reservoirs and deep saline
formations. Although each kind of formation is different, their
suitability can basically be assessed by injectivity, storage
capacity, and containment. Injection depth is recommended at intervals
between 800 and 3,300 meters to insure the safety of potable water
aquifers, to keep the carbon dioxide at supercritical states (CO2
critical point: 1,071 psi and 87.9 deg. F), to optimize storage capacity,
and to keep compression costs reasonable. The ability to inject
liquefied carbon dioxide is primarily a function of the reservoir
permeability, its formation thickness, and the injection pressure. The
injection rate is also controlled by the technical limits of the
compression equipment.

The petroleum industry has been injecting carbon dioxide for enhanced
oil recovery (E.O.R.) for over 30 years. Thus, the injection rates for
E.O.R. may provide the approximate ranges for sequestration.

According to the Energy Information Administration, fossil-fuel
related carbon dioxide emissions in the U.S. totaled 5,005 million
metric tons in 1990 and 5,945 MMt in 2005. By 2030, the E.I.A. expects
carbon dioxide emissions will increase by about 2,005 MMt, to 7,950
MMt. If the Kyoto Protocol emission standard (5 percent below the 1990
emission level) is executed, or if emissions are kept at the 2005
level, enormous amounts of carbon dioxide will have to be injected,
requiring thousands of wells to be drilled.

Table 1 shows the CO2 injection rates for two CO2-EOR units, SACROC
Unit and Wasson Denver Unit in the Permian Basin (Stevens et al.,
1998; Kinder Morgan "FlashNews," 2004), and a case study for potential
CO2-EOR and sequestration for the Grieve field in Wyoming (Wo et al.,
2008). Permeability of 10 millidarcies is used as a cutoff for
selection of suitable sequestration sites. The average injection rates
at the Wasson Denver Unit can be used as the lower limit for
evaluation. The Grieve field has exceptionally high permeability and
low reservoir pressure, providing an optimistic example of the upper
limit for carbon dioxide injection rates.

Table 1

These parameters were used to calculate the number of wells needed in
the U.S. for carbon dioxide injection if it were to meet the Kyoto
Protocol emission requirement and to keep total carbon emissions at
2005 levels, assuming that carbon dioxide emissions increase linearly
between 2005 and 2030 (Table 2).

Table 2

To inject all of the additional gas and thus keep total emissions at
2005 levels, the U.S. will need to drill 100,830 more wells (assuming
the permeabilities and pressures found in the Wasson Denver Unit) to
dispose of the additional 2,005 MMt per year of carbon dioxide. For
comparison, about 40,000 oil and gas wells are drilled annually in the
United States.

A serious problem for geologic carbon sequestration is the decrease of
injectivity over time, because of the scaling induced by reactions
between CO2 and the surrounding rock and/or other formation damage
factors. For instance, the injection rate at the SACROC unit decreased
by about two-thirds over a 24-year period. Furthermore, the estimates
in Table 2 are for CO2 injection that is accompanied by the production
of oil and gas. In that scenario, about two-thirds of the injected CO2
returns to the surface with the oil and gas, and thus the hydrocarbon
formation is allowed to maintain a near-steady state in terms of
pressure maintenance. Permanent CO2 injection in deep saline
formations will be far more difficult because of the formation
pressure build-up during the injection. Given the problems of pressure
build-up, at least triple the number of wells cited here will be
needed if injectivity doesnt decrease. And as soon as the reservoir
capacity is reached, new reservoirs must be located and new wells

Thus, if 302,490 wells are need for injection and we assume an average
of $10 million to drill and complete each well, along with the
ancillary piping, storage, valves, and other equipment, by 2030 the
total cost of the injection wells alone will exceed $3 trillion. But
the number and cost of the injection wells are just two of many
factors in the carbon dioxide geological sequestration process. Before
injection, carbon dioxide has to be separated from flue gas, which
contains only 8 to 13 percent carbon dioxide. The separation cost
alone is about $150 per ton, according to the Department of Energys
2006 estimate. This translates into some $300 billion per year just
for the separation (and assumes only the costs associated with
treating the 2,005 MMt of incremental carbon dioxide cited above).
Estimates for compression and transportation vary considerably. But
all told, the total cost of such an ambitious carbon dioxide
geo-sequestration effort could easily surpass $1.5 trillion per year,
based on calculations I have done in collabation with Michael J.

An aspect of geologic sequestration that is seldom discussed is the
management scenario once a given well has reached its carbon dioxide
limit. Ensuring that the carbon dioxide doesnt leak from the formation
requires monitoring, and any leakage could present legal problems to
the sequestration wells owners.

Whether, when, and how much carbon dioxide sequestration will ever
occur on a commercial scale remains in question, and to achieve it
will be expensive and problematic. The proposition has yet to be
properly addressed in either a real or a practical context.


Xina Xie is a senior research engineer at the University of Wyoming
who specializes in enhanced oil recovery.