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Ministry of Energy, Mines and Petroleum Resources 1
exploring The FaTe oF Co
2
aT BriTish ColumBia’s planned
ForT nelson CarBon CapTure and sTorage projeCT
Peter Crockford
1
and Kevin Telmer
1
ABSTRACT
The geochemical reactions involved in injecting uids into reservoirs remain poorly understood, yet this
information is critical to the success of carbon capture and storage (CCS) projects. Remarkably, no
standard methodology exists to estimate storage capacity for CCS, largely because of the inadequacy of
thermo-kinetic databases needed to model geochemical processes at the pressures, temperatures, and
salinities of deep reservoir conditions. Thermodynamic and kinetic constants and coefcients, reactive
surface area estimates, and understanding of pore-scale physical processes that control geochemical
reactivity are particularly lacking. This information is required to predict long-term CO
2
trapping. The
University of Victoria is aiming to develop this information by performing high-quality research on a case-
by-case basis.
In collaboration with the Ministry of Energy, Mines and Petroleum Resources and Spectra Energy,
researchers at the University of Victoria are performing laboratory experimental work to measure empirical
and site-specic thermo-kinetic properties of reservoir materials from the planned Fort Nelson CCS project.
These results and a conceptual model based on eld data will be integrated into the project to produce a
reactive transport simulation to predict the fate of the injected CO
2
.
Crockford, P. and Telmer, K. (2009): Exploring the Fate of CO
2
at British Columbia’s planned Fort Nelson Carbon Capture and Storage
Project; Geoscience Reports 2009, BC Ministry of Energy, Mines and Petroleum Resources, pages 1–4.
1
University of Victoria
CCs in BriTish ColumBia: a viaBle
opTion To reduCe Co
2
emissions
There is broad understanding in the scientic commu-
nity that rising concentrations of anthropogenic greenhouse
gases will change our climate and produce an estimated
warming of the planet up to 4°C this century (IPCC 2007).
CO
2
is the most abundant greenhouse gas and is thought to
be responsible for 76.6% of the enhanced greenhouse effect
(IPCC 2007). In 2008, the province of British Columbia
emitted an estimated 70.3 Mt of CO
2
(Figure 1), represent-
ing nearly 9% of the 780 Mt of CO
2
estimated to have been
emitted by Canadians (Environment Canada 2005). While
the global energy market waits for development of renew-
able energy forms, CCS is a technology available to British
Columbia that can help the province to achieve it’s goal of
reducing emissions to 46.4 Mton CO
2
per year (Figure 1).
CCS lowers greenhouse gas emissions by capturing
CO
2
and other gases from point-source emitters such as
gas-red power plants and injecting them into the subsur-
face, where they remain for millennia. CCS is not new—it
has been used for a different purpose and at a smaller scale
for decades by the oil and gas industry to enhance oil re-
covery (a technology called EOR) and for the disposal of
acid gas (CO
2
and H
2
S). Because it is already available and
is cost effective, CCS has become an important component
to emission reduction strategies of governments and the
private sector all around the world. For British Columbia,
CCS has great potential to lower emissions because of the
presence of several large CO
2
point sources near its numer-
ous potentially good geological storage sites (Figure 2). In
particular, British Columbia’s natural gas industry, which
is expected to grow 50% to 200% over the next 10 to 15
years, is a good candidate for CCS because of its large and
relatively pure point sources of CO
2
, which are co-located
with suitable storage reservoirs (principally deep saline
formations).
Government, industry, and academia are cooperating to
take advantage of British Columbia’s CCS opportunities. A
large CCS project at Fort Nelson is in the feasibility stage.
It is a collaborative effort involving mainly the British Co-
lumbia Ministry of Energy, Mines and Petroleum Resources
and Spectra Energy, a natural gas producer. The Plains CO
2
Reduction Partnership (PCOR) and the University of Victo-
ria are also involved, bringing needed institutional capacity
and research expertise to the project. The target for the CCS
project is Spectra’s Fort Nelson sour-gas H
2
S processing
plant (Figure 2), which emits signicant volumes of CO
2
during the processing of raw gas.
The Fort Nelson area is an ideal location for CCS. This
area has a large number of candidate CCS sites with suit-
able stratigraphy—thick shaly aquitards, ideal for sealing in
CO
2
for the long term. Northeast British Columbia is also
2 Geoscience Reports 2009
Figure 1. Global measured CO
2
values up to 2003 along with the “Business As Usual” trend to 2020 and British Columbia’s 2020 reduction
target. Figure adapted from Hartling 2008.
Figure 2. Map of British Columbia showing the largest point source emitters. (Hartling 2008).
Ministry of Energy, Mines and Petroleum Resources 3
a tectonically stable area with a low probability of earth-
quakes that could fracture rocks and cause leakage.
If successful, the Fort Nelson project will inject about
1 Mt of CO
2
into the subsurface every year and become one
of the world’s largest CCS operation. This single project
could reduce British Columbia’s CO
2
emissions by a sig-
nicant 2.5% and play a pivotal role in British Columbia’s
reduction goal of 33% by 2020.
The ForT nelson CCs projeCT:
researChing The geoChemisTry
oF Co
2
in The deep aqueous
environmenT
Geochemical knowledge will assist in estimating the
storage capacity, limitations on injection rates and injection
methods, and contamination risks associated with leakage.
Storage capacity is controlled by porosity, permeability, and
the pressure and temperature eld of the reservoir. These,
however, are affected by geochemical reactions that cause
mineral precipitation and dissolution and shifts in gas solu-
bility that feedback on the pressure and temperature and
ultimately the potential CO
2
injection rate.
University of Victoria research is focusing on the
geochemistry of the saline formation environment during
and after CO
2
injection to determine which geochemical
reactions will occur and at what rates. This information
will be coupled with reservoir ow dynamics to estimate
where in the aquifer these reactions will be occurring.
Both experimental and computer modeling approaches
will be taken. Laboratory experiments will be performed
at the pressure and temperature range of the proposed CCS
location in the Fort Nelson area. These experiments will be
performed on brine and rock samples from the proposed
reservoir. The laboratory results will also be used to create
and rene physical constants in thermodynamic and kinetic
databases, which will dictate the accuracy of a mathemati-
cal model of the reservoir system.
Fieldwork will be performed at the drill site to collect
samples and perform measurements of parameters such as
temperature, pressure, and alkalinity of the formation brine.
These data can be used in follow-up studies that will track
the evolution of these parameters of the saline aquifer.
Samples will be analyzed and experiments run at the
School of Earth and Ocean Sciences, University of Vic-
toria. Using the new state-of-the-art laboratories, samples
of brine and rock will be placed under aquifer conditions.
An acid-gas mixture of supercritical CO
2
and H
2
S will be
introduced in a reaction vessel at the P-T conditions of the
Fort Nelson aquifer. The system will be sampled through
ports over a 90-day period to detect the rates of changes
in brine chemistry and alterations in the aquifer rock. The
rock will be analyzed for changes in porosity and perme-
ability, and the brine composition will be compared to the
initial composition before CO
2
introduction. Changes in
brine composition combined with petrological work on
rock materials will allow mineral precipitation and disso-
lution rates to be determined. By measuring samples over
several intervals, kinetic information will also be generated.
Some of this work will address some of the deciencies in
this eld today, such as quantication of reactive surface
area and geochemical interactions.
More research is required to gain information about
the reactivity of the CO
2
phase of the system. The injected
CO
2
does not always immediately dissolve into solution or
precipitate into minerals—for at least the injection period
(25 to 50 years). The majority of CO
2
may reside as a
separate phase on top of the formation brine because of its
lower density (Figure 3). The reactions that occur in this
part of the system are also very important to investigate.
Processes such as brine desiccation, where the H
2
O of the
brine evaporates into the CO
2
layer, and reactions between
the CO
2
phase and the rocks may also be important in es-
timating the overall storage capacity of the reservoir. The
university will be performing experiments to look at these
reactions as well.
To extrapolate results from the laboratory to the reser-
voir and from short time scales to long, reactive transport
modeling will be performed. Results from the laboratory
will be used to replace thermodynamic and kinetic terms
in modeling databases with site-specic data. This is es-
sential for developing a realistic and practical model. How-
ever, not all reactions that will occur in the aquifer can be
observed in the laboratory because of the slow kinetics of
Figure 3. Graphic depiction of CO
2
density changes with depth.
Figure taken from CO
2
CRC (2008).
4 Geoscience Reports 2009
some reactions (Figure 4). Modeling software will be used
to predict long-term products as they may be reasonably
estimated by chemical equilibrium—a task that software
is fairly good at, given the proper initial input chemistry.
Fluid dynamics at the aquifer scale are also not replicable in
the laboratory, and so scaling factors will be researched.
As well, when CO
2
is injected into the aquifer, gradi-
ents of CO
2
concentration and pH will be created around the
injection site. Such a chemical distribution cannot directly
be emulated in a laboratory reaction vessel and therefore
will require computer modeling. By using a model to deter-
mine where in the aquifer reactions will be occurring, we
will be able to better predict the long-term distribution of
CO
2
and the geochemical reactions participating in trapping
it in long-term storage.
Predicting the long-term fate of the injected CO
2
will
help the Fort Nelson CCS project transition from the plan-
ning stages to implementation. As well, the data collected
will be useful to the CCS community in implementing
projects globally.
ConClusions
CCS is a rapidly expanding technology that will be
a major player in the 21st century as a transitional solu-
tion in one of our greatest environmental challenges—the
reduction in greenhouse gases emitted into the atmosphere.
If implemented in the near future, the Fort Nelson CCS
project will be the largest of its kind globally and make
a signicant contribution to British Columbia’s efforts at
reducing carbon emissions. However, in order to ensure the
long-term viability of the project, it is important to charac-
terize the geochemical environment that will be used for
CO
2
storage to be able to estimate potential injection rates
and storage capacity. Laboratory and modeling work at the
University of Victoria has been designed to help quantify
these parameters.
reFerenCes
Benson, S., and Cook, P., eds. (2005): Underground geological
storage, in Carbon Dioxide Capture and Storage, Special Re-
port of the Intergovernmental Panel on Climate Change (IPCC),
Cambridge University Press, Cambridge, pages 195-276.
Environment Canada website http://www.ec.gc.ca/
Hartling, Alf (2008a): Carbon Capture and Storage in British
Columbia; in Geoscience reports 2008, BC Ministry of Energy,
Mines and Petroleum Resources, pages 25-31.
Hartling, Alf (2008b): Geological Aspects of CO2 Sequestra-
tion, Northeast British Columbia, Canada, Search and Dis-
covery, Article #80010, http://www.searchanddiscovery.com/
documents/2008/08073hartling/index.htm
IPCC (2007): Climate Change 2007, Synthesis report. An assess-
ment of the Intergovernmental Panel on Climate Change, A.
Allali, R. Bojariu, S. Diaz, I. Elgizouli, D. Griggs, D. Hawkins,
O. Hohmeyer, B. Pateh Jallow, L. Kajfez-Bogataj, N. Leary, H.
Lee & D. Wratt (eds), Cambridge University Press, Cambridge,
52 pages.
Price, Jeffrey, and Smith, Brian (2008): Geologic Storage of Car-
bon Dioxide – Staying Safely Underground, International En-
ergy Agency (IEA) Greenhouse Gas R & D Programme, Chel-
tenham, UK, 28 pages.
Figure 4. Dominant CO
2
trapping mechanisms over 1- to 10,000-
year timescales. Figure from Benson and Cook (2005).
100
0
1 10
Time Since Cessation of Injection ( Years)
% Trapping Contribu tion
100
Structural, Stratigraphic &
Hydrodynamic Trapping
Residual CO
2
Trapping
Increasing Storage Security
Solubility
Trapping
Mineral
Trapping
1, 000 10, 000
