Bibliography - Benjamin Court
- Bandilla, K. W., Benjamin Court, Thomas R. Elliot, and Michael Celia, February 2012: Comparison of Brine Production Scenarios for Geologic Carbon Sequestration Operations. Carbon Management Technology Conference, doi:10.7122/151250-MS
[ Abstract ]Large volumes of CO2 will have to be stored in the subsurface for carbon capture and geological sequestration to have a significant impact on the reduction of carbon emissions. Injection of large volumes of CO2 into deep saline formations can lead to significant pressure increases within that formation. The increased pressure can be a limiting factor for injection rates; it can also drive vertical brine migration through leakage pathways (e.g., abandoned wells) that could contaminate sources of drinking water. Production of brine from the injection formation can reduce the pressure increase while also limiting the spatial extent of the pressure increase.
The impact of brine extraction is investigated using a hypothetical injection domain conditioned by parameters from the Illinois Basin. The domain contains one injection well and encompasses several aquifers connected through diffusive brine leakage. A vertically-integrated approach is used to model the injection formation and overlying aquifers. A set of production scenarios illustrates the impact of brine production on injection rates and vertical brine movement. The scenarios include production with surface disposal and production with reinjection into overlying formations (with and without desalinization).
The results show that brine production can reduce the pressure buildup in the injection formation, leading to an increase in injectivity and a concomitant reduction in fresh water contamination risk by reducing the area of potential impact. While reinjection of brine into an overlying aquifer solves the disposal problem, it also reduces the effectiveness of brine production by increasing the pressure. Injection of a smaller amount of more concentrated brine resulting from desalinization reduces the impact of reinjection and acts as an additional source of fresh water, but increases the cost of the injection operation.
Based on the results from these numerical experiments pressure management through brine production should be considered for industrial-scale CO2 injection operations, as it increases injectivity and reduces the size of the area of potential impact. However, the brine disposal problem needs to be solved for brine production to be a useful endeavor.
- Buscheck, Thomas A., Yunwei Sun, Mingjie Chen, Yue Hao, Thomas J. Wolery, William L. Bourcier, Benjamin Court, Michael Celia, S. Julio Friedmann, and Roger D. Aines, 2012: Active CO2 reservoir management for carbon storage: Analysis of operational strategies to relieve pressure buildup and improve injectivity. International Journal of Greenhouse Gas Control, Elsevier, 6, doi:10.1016/j.ijggc.2011.11.007 230-245
[ Abstract ]For industrial-scale CO2 injection in saline formations, pressure buildup can limit storage capacity and security. Active CO2 Reservoir Management (ACRM) combines brine production with CO2 injection to
relieve pressure buildup, increase injectivity, manipulate CO2 migration, and constrain brine leakage. By limiting pressure buildup, in magnitude, spatial extent, and duration, ACRM can reduce CO2 and brine leakage, minimize interactions with neighboring subsurface activities, allowing independent assessment
and permitting, reduce the Area of Review and required duration of post-injection monitoring, and reduce cost and risk. ACRM provides benefits to reservoir management at the cost of extracting brine. The added cost must be offset by the added benefits to the storage operation and/or by creating new, valuable uses that can reduce the total added cost. Actual net cost is expected to be site specific, requiring detailed analysis that is beyond the scope of this paper, which focuses on the benefits to reservoir management. We investigate operational strategies for achieving an effective tradeoff between pressure relief/improvedinjectivity and delayed CO2 breakthrough at brine producers. For vertical wells, an injection-only strategy
is compared to a pressure-management strategy with brine production from a double-ring 9-spot pattern.
Brine production allows injection to be steadily ramped up while staying within the pressure-buildup
target, while injection-only requires a gradual ramp-down. Injector/producer horizontal/well pairs were
analyzed for a range of well spacings, storage-formation thickness and area, level and dipping formations, and for homogeneous and heterogeneous permeability. When the producer is downdip of the injector, the combined influence of buoyancy and heterogeneity can delay CO2 breakthrough. Both vertical and horizontal wells can achieve pressure relief and improved CO2 injectivity, while delaying CO2 breakthrough. Pressure buildup and CO2 breakthrough are sensitive to storage-formation permeability and insensitive to all other hydrologic parameters except caprock-seal permeability, which only affects pressure buildup
for injection-only cases.
- Court, Benjamin, K. W. Bandilla, Michael Celia, Thomas A. Buscheck, Jan M. Nordbotten, M. Dobossy, and Adam Janzen, 2012: Initial evaluation of advantageous synergies associated with simultaneous brine production and CO2 geological sequestration. International Journal of Greenhouse Gas Control, Elsevier, 8, doi:10.1016/j.ijggc.2011.12.009 90-100
[ Abstract ]Mitigation of global atmospheric carbon emissions requires a worldwide ramping up of CO2 capture and sequestration (CCS) implementation in the next decades. While CCS could be deployed in isolation, there is also the possibility to consider CO2 injection within a much broader framework of reservoir and resource management including active water (brine) management. The goal of this study is to provide an initial analysis of three identified synergies related to active brine management in CCS operations. The potential advantages of coupling simultaneous brine production to a large-scale CO2 geological sequestration operation are explored through three separate modeling studies. Our results demonstrate that brine production can provide important pressure-control benefits, including increased injectivity potential through reduction of the injection well pressure, significant reduction of the extent of the Area of Review, within which operators must procure property rights and monitor and remediate potential leakage pathways, and reduction in the risk of CO2 and brine leakage. The latter is especially important in reservoirs, like many in North America, where a significant number of potential leakage pathways, particularly abandoned wells, may exist within the Area of Review. We also observe that brine production has minimal impact on the overall shape of the CO2 plume, with plume shape and extent strongly governed
by formation parameters.
- Nogues, J. P., Benjamin Court, M. Dobossy, Jan M. Nordbotten, and Michael Celia, 2012: A methodology to estimate maximum probable leakage along old wells in a geological sequestration operation. International Journal of Greenhouse Gas Control, Elsevier, 7, doi:10.1016/j.ijggc.2011.12.003 39-47
[ Abstract ]This study presents a computational methodology to estimate the maximum probable leakage of CO2 along old wells in a geological sequestration operation. The methodology quantifies the maximum probable CO2 leakage as a function of the statistical characterization of existing wells. We use a Monte Carlo approach based on a computationally efficient simulator to run many thousands of realizations. Results from the Monte Carlo simulations are used to determine maximum leakage rates at 95% confidence. Uncertainty in the analysis is due to leaky well parameters, which are known to be highly uncertain. We consider a wide range of parameter values, with our focus on assignment of effective well permeability
values and the correlation of those values along individual wells. We use a specific location in Alberta,
Canada, to demonstrate the methodology using a hypothetical injection and an assumed probability
structure for the well permeabilities. We show that for a wide range of parameter values, the amount of
leakage is within the bounds suggested as acceptable for climate change mitigation.
- Celia, Michael, Jan M. Nordbotten, Benjamin Court, M. Dobossy, and S. Bachu, 2011: Field-scale application of a semi-analytical model for estimation of CO2 and brine leakage along old wells. International Journal of Greenhouse Gas Control, Elsevier, (5), doi:10.1016/j.ijggc.2010.10.005
[ Abstract ]Carbon capture and geological storage (CCS) operations will require an environmental risk analysis to
determine, among other things, the risk that injected CO2 or displaced brine will leak from the injection
formation into other parts of the subsurface or surface environments. Such an analysis requires site characterization
including identification of potential leakage pathways. In North America, the century-long
legacy of oil and gas exploration and production has left millions of oil and gas wells, many of which are
co-located with otherwise good geological storage sites. Potential leakage along existing wells, coupled
with layered stratigraphic sequences and highly uncertain parameters, makes quantitative analysis of
leakage risk a significant computational challenge. However, new approaches to modeling CO2 injection,
migration, and leakage allow for realistic scenarios to be simulated within a probabilistic framework.
Using a specific field site in Alberta, Canada, we perform a range of computational studies aimed at risk
analysis with a focus on CO2 and brine leakage along old wells. The specific calculations focus on the injection
period, when risk of leakage is expected to be largest. Specifically, we simulate 50 years of injection
of supercritical CO2 and use a Monte Carlo framework to analyze the overall system behavior. The simulations
involve injection, migration, and leakage over the 50-year time horizon for domains of several
thousand square kilometers having multiple layers in the sedimentary succession and several thousand
old wells within the domain. Because we can perform each simulation in a few minutes of computer time,
we can run tens of thousands of simulations and analyze the outputs in a probabilistic framework. We
use these kinds of simulations to demonstrate the importance of residual brine saturations, the range of
current options to quantify leaky well properties, and the impact of depth of injection and how it relates
to leakage risk.
- Court, Benjamin, Thomas R. Elliot, J.A. Dammel, Thomas A. Buscheck, J. Rohmer, and Michael Celia, 2011: Promising synergies to address water, sequestration, legal, and public acceptance issues associated with large-scale implementation of CO2 sequestration. The Journal for Mitigation and Adaption Strategies for Global Change, Springer, doi:10.1007/s11027-011-9314-x
[ Abstract ]Stabilization of CO2 atmospheric concentrations requires practical strategies to
address the challenges posed by the continued use of coal for baseload-electricity production.
Over the next two decades, CO2 capture and sequestration (CCS) demonstration projects
would need to increase several orders of magnitude across the globe in both size and scale.
This task has several potential barriers which will have to be accounted for. These barriers
include those that have been known for a number of years including safety of subsurface
sequestration, pore-space competition with emerging activities like shale gas production, legal
and regulatory frameworks, and public acceptance and technical communication. In addition
water management is a new challenge that should be actively and carefully considered across
all CCS operations. A review of the new insights gained on these previously and newly
identified challenges, since the IPCC special report on CCS, is presented in this paper. While
somewhat daunting in scope, some of these challenges can be addressed more easily by
recognizing the potential advantageous synergies that can be exploited when these challenges
are dealt with in combination. For example, active management of water resources, including
brine in deep subsurface formations, can provide the additional cooling-water required by the
CO2 capture retrofitting process while simultaneously reducing sequestration leakage risk and furthering efforts toward public acceptance. This comprehensive assessment indicates that water, sequestration, legal, and public acceptance challenges ought to be researched individually, but must also be examined collectively to exploit the promising synergies identified herein. Exploitation of these synergies provides the best possibilities for successful large-scale implementation of CCS.
- Court, Benjamin, Michael Celia, Jan M. Nordbotten, and Thomas R. Elliot, 2010: Active and Integrated Management of Water Resources Throughout CO2 Capture and Sequestration Operations. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
[ Abstract ]Most projected climate change mitigation strategies will require a significant expansion of CO2 Capture and Sequestration (CCS)
in the next two decades. Four major categories of challenges are being actively researched: CO2 capture cost, geological
sequestration safety, legal and regulatory barriers, and public acceptance. Herein we propose an additional major challenge
category across all CCS operations: water management. For example a coal-fired power plant retrofitted for CCS requires twice
as much cooling water as the original plant. This increased demand may be accommodated by brine extraction and treatment,
which would concurrently function as large-scale pressure management and a potential source of freshwater. At present the
interactions among freshwater extraction, CO2 injection, and brine management are being considered too narrowly -in the case of
freshwater almost completely overlooked- in the technical and regulatory CCS community. This paper presents an overview of
each of these challenges and potential integration opportunities. Active management of CCS operations through an integrated
approach -including brine production, treatment, use for cooling, and partial reinjection- can address challenges simultaneously
with several synergistic advantages. The paper also considers the related potential impacts of pore space competition (with future
groundwater use, gas storage and shale gas) on CCS expansion. Freshwater and brine must become key decision making inputs
throughout CCS operations, building on existing successful industrial-scale integrations.
- Celia, Michael, Jan M. Nordbotten, , M. Dobossy, and Benjamin Court, 2009: Risk of Leakage versus Depth of Injection in Geological Storage. Energy Procedia, 1(1), doi:10.1016/j.egypro.2009.02.022 2573-2580
[ Abstract ]One of the outstanding challenges for large-scale CCS operations is to develop reliable quantitative
risk assessments with a focus on leakage of both injected CO2 and displaced brine. A critical leakage
pathway is associated with the century-long legacy of oil and gas exploration and production, which has
led to many millions of wells being drilled. Many of those wells are in locations that would otherwise be
excellent candidates for CCS operations, especially across many parts of North America. Quantitative
analysis of the problem requires special computational techniques because of the unique challenges associated with simulation of injection and leakage in systems that include hundreds or thousands of existing wells over domains characterized by layered structures in the vertical direction and very large horizontal extent. An important feature of these kinds of systems is the depth of each well, and the fact that the number of wells penetrating different formations decreases as a function of depth. As such, one might reasonably expect the risk of leakage to decrease with depth of injection. With the special computational models developed to simulate injection and leakage along multiple wells, in layered
systems with multiple formations, quantitative assessment of risk reduction as a function of injection
depth can be made. An example of such a system corresponds to the Wabamun Lake area southwest of
Edmonton, Alberta, Canada, where several large coal-fired power plants are located. Use of information
about both the existing wells and the local stratigraphy allows a realistic model to be constructed.
Leakage along existing wells is assumed to follow Darcy’s Law, and is characterized by a set of effective
permeability values. These values are assigned stochastically, using several different methods, within a Monte Carlo simulation framework. Computational results show the clear trade-off between depth of
injection and risk of leakage. The results also show how properties within the different formations affect
the risk profiles. In the Wabamun Lake area, one of the formations has the highest injectivity, by far,
while having a moderate number of existing wells. Its moderate risk of leakage, as compared to injections
in formations above and below, shows some of the key factors that are likely to influence injection design
for large-scale CCS operations.
Direct link to page: http://cmi.princeton.edu/bibliography/results.php?author=3501
