The Fluids & Energy Group (formerly the Storage Group) investigates challenges of storing CO2 below ground. The researchers use computer simulations, field studies, and laboratory experiments to study processes at molecular to basin scales. The PI’s of the Group are Michael Celia and Jean Prévost of Civil and Environmental Engineering, Pablo Debenedetti and Thanos Panagiotopoulos of Chemical and Biological Engineering, Howard Stone (Mechanical and Aerospace Engineering), and Jeroen Tromp (Geosciences and Applied and Computational Mathematics).
Innovative research this year has found a possible synergy between carbon capture and storage and geothermal energy, provided insights into suppression of viscous fingering in sub-surface fluids, and produced ground-breaking molecular simulations of methane hydrate formation.
- Vertical Interference Tests to infer effective permeability of cement outside of casing continue to give estimates several orders of magnitude larger than expected from intact cement.
Simulations of CO2 Storage
- Multi-scale models of underground CO2 storage continue to be developed and applied to a wide range of practical, large-scale problems, including two-phase flow dynamics, capillary effects, large-scale dissolution, and leakage along faults and old wells.
- Research on Carbon Capture, Utilization, and Storage (CCUS) and geothermal systems shows that produced brines may have an important role in heat extraction and that captured CO2 might be used in pressure support for geothermal production.
- A Dynaflow simulation suggests that injecting CO2 at cold temperatures may lead to caprock fracturing.
- An experimental study suggests that varying permeability gradients can suppress viscous fingering, a finding with implications for enhanced oil recovery.
- A physical model of leakage of buoyant material shows good agreement with theoretical predictions.
- Pore-scale modeling studies are providing insight into geochemical reactions and phase trapping in CO2 storage reservoirs.
- For the first time in a molecular simulation, methane hydrates have been formed in the absence of an interface.
- Simulations suggest that phase partitioning and interfacial properties of CO2-water-salt systems can be predicted with moderate accuracy using existing atomistic models, but point to the need for improved force fields.
One of the fruits of the partnership between CMI and BP has been the development of a technique called a “Vertical Interference Test” (VIT) to assess the effective permeability of existing wells. This test appears to be a very valuable field tool to estimate in situ permeability along existing wells.
Evaluation of well integrity
Both BP (through collaboration with Walter Crow) and Schlumberger (through collaboration with Princeton alumnus Andrew Duguid) have used Vertical Interference Tests to determine, in situ, the effective permeability of materials (mostly cements) outside of well casings. In 2012, the Celia group has continued collaborations with Andrew Duguid at Schlumberger (Andrew is a PhD alumnus of the CMI program) to analyze data from Vertical Interference Tests. The three most recent tests gave permeability estimates between about 1 milliDarcy and about 200milliDarcy. These fall within the range of other earlier measurements, and are several orders of magnitude larger than permeability of cement plugs retrieved from these locations. The latter observation points to annular flows as dominant along the boreholes.
Since the founding of CMI, the Celia group has developed a hierarchy of analytical, semi-analytical, and numerical models that allow simulation of CO2 injection and leakage, with a particular focus on leakage along old wells. Geared toward quantitative estimation of leakage on large scales, the group’s methods are very efficient and allow for simulations that include hundreds to thousands of leaky wells across many layers of geological formations.
This year, Michael Celia and colleagues continued to develop their models and apply them to a number of potential injection sites. These models now predict pressure buildup in the formation, movement of both CO2 and brine within the injection formation and across confining units into other formations, capillary trapping of CO2, and dissolution of CO2 into the brine phase (that is, solubility trapping – see Figure 15 for an example). In 2012, studies examined the impact of different modeling choices on practical simulations of CO2 fate and transport and the limitations of the Vertical Equilibrium (VE) assumption. A range of models, including the VE models, were also applied to several sedimentary basins that have practical importance, including the Illinois Basin, the Michigan Basin, and the Alberta Basin, as well as the Basal Aquifer of central North America. These simulations have focused on very large-scale systems at scales of injection that can have an impact on the climate problem.
The researchers have also developed a model which eliminates the Vertical Equilibrium assumption while still maintaining its essential computational efficiency – that model is based on dynamic reconstruction of the vertical pressure and saturation profiles, in the context of multi-scale modeling. Development of VE models in the context of multi-scale analysis allows this extension – the idea is described in detail in their recent textbook, Geological Storage of CO2: Modeling Approaches for Large- scale Simulation. The team is also developing a macro-scale percolation model with collaborators at Lawrence Berkeley National Laboratory. Collectively this suite of modeling approaches gives the group substantial flexibility in modeling different aspects of the CO2 problem.
Celia and colleagues also apply their models to consider ways to make carbon capture and storage more effective and economical. In a study of the potential advantages of brine production at CCS sites for the purpose of pressure control, the researchers found that brine production reduced pressure build-up at the CO2 injection well, thus substantially reducing the Area of Review for given injections as well as the risk of leakage, while possibly enabling higher injectivity.
They have also looked more broadly at possible CO2 utilization, in the context of Carbon Capture, Utilization, and Storage (CCUS). While produced brines can provide some benefits in terms of water usage, a potentially more important use is associated with heat extraction and the use of CO2 in pressure support for geothermal production. In conjunction with collaborators at the Lawrence Livermore National Laboratory, they have investigated how a CO2 injection operation could be integrated into a large-scale geothermal production system (Figure 16). As opposed to earlier studies, CO2 is not used as the heat-carrying fluid, but instead the injection is used in a pressure support role and the resident hot brines are produced as the working fluid. Eventual CO2 breakthrough in allowed and is accounted for in the overall analysis. The system may be promising in regions of the country with existing geothermal capacity.
The Prévost group develops simulation tools that capture the effects of coupling between fluid flow, thermal and geomechanical effects. Since the inception of CMI, the group’s Dynaflow model, which offers a modular, hierarchical approach for multiphysics simulations, has been adapted to simulate aquifer geochemistry and multiphase flow as well as to predict physical stresses induced by CO2 injection. The model has recently been applied to study CO2 injection impacts at BP’s In Salah facility in Algeria.
The Dynaflow model has unique capabilities to simulate fluid flow fully coupled with thermal and geomechanical effects, allowing prediction of the stresses induced in the caprock by continuous injection of CO2 in an aquifer. This year, the researchers showed that the temperature of injected CO2 significantly affects these stresses. Particularly when CO2 is injected at temperature 40-50°C below the ambient temperature, the stresses in the caprock become tensile and may overcome the tensile strength, causing fracturing of the caprock.
The initial length of fractures is relatively small. However, the team found that the fractures will propagate driven by the high fluid pressure in the aquifer. In collaboration with Howard Stone, Prévost and colleagues have developed an analytical model capable of predicting the resulting fracture length based on the pressure and stress data calculated by Dynaflow. They estimate the length of a hypothetical fracture at the In Salah site to be of the order of 25 - 35 m within 10 years after fracture initiation (Figure 17). On such a length scale there is a risk that a fracture may connect to a leaky fault and become a pathway for CO2 leakage.
If a CO2-brine mixture migrates upward, it reaches regions where the pressure and temperature are lower than that of the critical state. Therefore, the migrating mixture may start boiling. Current work is focused on implementing a flash calculations module for the CO2-water system. Including such a module in Dynaflow will allow the modeling of the flow of the boiling mixture.
Predicting the fate of CO2 injected underground for carbon storage or enhanced oil recovery requires understanding physical processes associated with the underground rearrangement of a buoyant material. This raises new questions regarding multiphase flows in porous media, which the Stone group is investigating with a combination of bench-scale laboratory experiments and theory.
In 2012, Howard Stone and colleagues completed an important study of viscous fingering in the presence of gradients of permeability in the direction of flow. The results were published in Nature Physics and also highlighted in Physics Today.
Using a modified Hele-Shaw cell, an experimental apparatus composed of two plates that are conventionally parallel, the team led by Talal Al-Housseiny simulated the displacement of a more viscous fluid by a less viscous fluid (analogous to water displacing oil) in a tapered channel. The researchers demonstrated that, though such an interface between these fluids is always unstable between parallel plates, a contracting geometry can stabilize the interface and allow the less-viscous fluid to “sweep” the more-viscous fluid more efficiently. Their results have implications for sweeping contaminants from sensors and cleaning of measuring devices used in applications, and also for enhanced oil recovery. The study suggests that to increase oil recovery in oil-wet reservoirs, injection and production wells might be positioned such that the sweep flow is driven in the direction of decreasing permeability or decreasing grain size to minimize viscous fingering and fluid breakthrough.
Recent experimental work in the physics community has shown that the presence of an elastic boundary can also facilitate the suppression of viscous fingering. Since real materials in nature can deform when stressed, as in the case of two-phase injection processes, the Stone group has examined this phenomenon by studying fluid displacement underneath a flexible membrane. The researchers analyzed this two-phase flow and demonstrated how the deflection of the membrane and surface tension at the gas-liquid interface provide the mechanism of suppression (Figure 18), and also determined the corresponding critical conditions.
Studies of underground CO2 storage require some understanding of possible failure modes, and the temporal and spatial rearrangements of the buoyant material in such cases. In order to describe fluid drainage behavior from porous media, Stone and colleagues have examined the fundamental problem of drainage from an edge, the extreme case when the vertical leakage pathway becomes infinitely permeable. Previous studies have only been theoretical, but this study used both theory and laboratory experiments in uniform Hele-Shaw cells and V-shaped cells to model gravity currents in both homogeneous reservoirs and those with varying permeability and porosity. In each case, a self-similar solution for the shape of these gravity currents was found and the mass remaining in the system is governed by power-law behavior. Measured profile shapes and the mass remaining in the cells agree well with model predictions (Figure 19). The study provides new insights into drainage processes that may occur in a variety of natural and industrial activities, including the geological storage of carbon dioxide.
In 2012, the Celia group continued to use pore-scale models to study additional issues relevant to CO2 storage, investigating geochemically reactive systems, trapping, and hysteresis. The geochemical modeling work includes explicit modeling of both precipitation and dissolution, with the associated changes in porosity and permeability tracked as the reactions proceed. The researchers also identify conditions under which unique relationships between porosity and permeability should be expected.
Pore-scale models also provide new insights into how nonwetting fluids are trapped in porous media, including underlying mechanisms and the extent to which continuum-scale trapping functions are hysteretic or path-dependent. The hysteretic nature of all multi-phase constitutive functions can be carried from the small scale to the large scale; a study published this year shows how this can be done for Vertical Equilibrium models, and the conditions under which hysteresis may be important at the large scale.
In 2010, a molecular modeling program was initiated within the Fluids & Energy Group. Pablo Debenedetti, Athanassios Panagiotopoulos, and Jeroen Tromp use molecular simulations to provide new insights into the behavior of CO2 and methane in subsurface environments.
The Debenedetti group is using state-of-the-art molecular modeling tools to gain insights into the mechanisms and rates of melting and formation of carbon dioxide and methane hydrates, as well as on their thermodynamic stability across broad ranges of temperature, pressure and salinity. The studies are relevant to CO2 sequestration (either in the solid form as a hydrate, or as pool of liquid CO2 below a cap of its hydrate), gas storage and transportation, climate change, and ocean stability.
In 2012, the Debenedetti team performed microsecond-long molecular dynamics simulations of homogeneous nucleation of methane hydrate in bulk water, the first time that such nucleation had been simulated in the absence of an interface. The calculations yielded novel insights into the nucleation mechanism, such as the transient appearance of 51263 (twelve pentagons and 3 hexagons per cage) and 51264 cages (twelve pentagons and four hexagons), which are not found in structure I (sI) hydrates; and the aggregation of sub-critical clusters over time scales spanning hundreds of nanoseconds (Figure 20).
The solid phase present at the end of microsecond-long simulations lacks long-range order, however, and is characterized by a ratio of large (51262)-to-small (512) cages that is significantly smaller than observed experimentally in sI crystals (ca. 1 vs. 3). This indicates that long molecular dynamics simulations, though valuable for providing phenomenological insight into nucleation and melting mechanisms, need to be supplemented by path-sampling techniques in order to yield quantitative information on actual rates of hydrate formation. The implementation of such path-sampling simulations is the focus of our ongoing work, which is being done in collaboration with Athanassios Panagiotopoulos (see next section).
In October 2011, a project was initiated within the Fluids & Energy group to develop molecular- based computational tools for predicting fundamental physicochemical characteristics required for understanding and rational design of CO2 separation processes and long-term CO2 storage in geological formations. This ongoing research is a collaboration between Athanassios Panagiotopoulos and Pablo Debenedetti, and Jeroen Tromp.
In the past year, the main focus of the project has been the use of atomistic simulations to obtain the phase behavior and interfacial tension of CO2-H2O-NaCl mixtures over a broad temperature and pressure range. The researchers demonstrated the applicability of interfacial molecular dynamics methods to the systems and properties of interest. Within the range of the temperature, pressure, salt concentration and system size in our study, they find no NaCl in the CO2-rich phase at phase coexistence. The work also highlighted the limitations of the existing force fields with fixed-charged, additive pair interactions in predicting phase equilibrium and interfacial properties of the mixtures of interest, suggesting an urgent research need for their improvement.
A PhD student in Chemical and Biological Engineering, Arun Prabhu, was recruited in January of 2012 to work jointly with Professors Debenedetti and Panagiotopoulos in the general area of the CMI project. Arun’s initial studies have focused on hydrate nucleation using bulk and interfacial molecular dynamics simulations, as detailed in Prof. Debenedetti’s section on “Molecular simulation of hydrate melting and formation.”
Al-Housseiny, T.T., P.A. Tsai and H.A. Stone. “Control of interfacial instabilities using flow geometry.” Nature Physics 8, 747-750. 2012.
Bandilla, K.W., M.A. Celia, T.R. Elliot, M. Person, K. Ellet, J. Rupp, C. Gable and M. Dobossy, “Modeling Carbon Sequestration in the Illinois Basin using a Vertically-integrated Approach”, to appear, Computing and Visualization in Science, 2013.
Bandilla, K.W., B. Court, T.R. Elliot and M.A. Celia, “Comparison of Brine Production Scenarios for Geologic Carbon Sequestration Operations”, Proc. Carbon Management Technology Conference, Orlando, February 2012.
Buscheck, T.A., M. Chen, C. Lu, Y. Sun, Y. Hao, M.A. Celia, T.R. Elliot, H. Choi and J.M. Bielicki, “Analysis of Operational Strategies for Utilizing CO2 for Geothermal Energy Production”, Proc. Thirty-eighth Workshop on Geothermal Reservoir Engineering, Stanford, California, February, 2013.
Buscheck, T.A., T.R. Elliot, M.A. Celia, M. Chen, Y. Sun, Y. Hao, C. Lu, T.J. Wolery and R.D. Aines, “Integrated Geothermal-CO2 Reservoir Systems: Reducing Carbon Intensity through Sustainable Energy Production and Secure CO2 Storage”, Proc. of the 11th International Conference on Greenhouse Gas Technologies (GHGT-11), Kyoto, Japan, November 2012b.
Buscheck, T.A., Y. Sun, M. Chen, Y. Hao, T.J. Wolery, W.L. Bourcier, B. Court, M.A. Celia, S.J. Friedmann and R.D. Aines, “Active CO2 Reservoir Management for Carbon Storage: Analysis of Operational Strategies to Relieve Pressure Buildup and Improve Injectivity”, International Journal of Greenhouse Gas Control, 6, 230-245, 2012a.
Court, B., K.W. Bandilla, M.A. Celia, A. Janzen, M. Dobossy, and J.M. Nordbotten. “Applicability of Vertical-equilibrium and Sharp-interface Assumptions in CO2 Sequestration Modeling”, International Journal for Greenhouse Gas Control, 10, 134-147, 2012a.
Court, B., K.W. Bandilla, M.A. Celia, T.A. Buscheck, J.M. Nordbotten, A. Janzen and M. Dobossy, “Initial Evaluation of Advantageous Synergies associated with Simultaneous Brine Production and CO2 Geological Sequestration”, International Journal for Greenhouse Gas Control, 8, 90-100, 2012c.
Court, B., T.R. Elliot, J.A. Dammel, T.A. Buscheck, J. Rohmer and M.A. Celia, “Promising Synergies to Address Water, Sequestration, Legal, and Public Acceptance Issues associated with Large-scale Implementation of CO2 Sequestration”, Mitigation and Adaptation Strategies for Global Change (Special Issue on Carbon Capture and Storage), 17(6), 569-599, 2012b.
Doster, F., J.M. Nordbotten and M.A. Celia, “Hysteretic Upscaled Constitutive Relationships for Vertically Integrated Porous Media”, to appear, Computing and Visualization in Science, 2013.
Duguid, A., R. Butsch, J.W. Carey, M. Celia, N. Chuganov, S. Gasda, T.S. Ramakrishnan, V. Stamp. J. Wang, “Pre-injection Baseline Data Collection to Establish Existing Wellbore Leakage Properties”, Proc. of the 11th International Conference on Greenhouse Gas Technologies (GHGT-11), Kyoto, Japan, November 2012.
Elliot, T.R. and M.A. Celia, “Potential Restrictions for CO2 Sequestration Sites due to Shale and Tight Gas Production”, Environmental Science and Technology, 46, 4223-4227, 2012.
Elliot, T.R., T.A. Buscheck and M.A. Celia, “Active CO2 Reservoir Management for Sustainable Geothermal Energy Extraction and Reduced Leakage”, to appear, Greenhouse Gases: Science and Technology, 2013.
Gasda, S.E., J.M. Nordbotten and M.A. Celia, “Application of Simplified Models to CO2 Migration and Immobilization in Large-scale Geological Systems”, International Journal of Greenhouse Gas Technologies, 9, 72-84, 2012a.
Gasda, S.E., M.A. Celia, J.Z. Wang and A. Duguid, “Wellbore Permeability Estimates from Vertical Interference Testing of Existing Wells”, Proc. of the 11th International Conference on Greenhouse Gas Technologies (GHGT-11), Kyoto, Japan, November 2012b.
Gor, G.Y., H.A. Stone, J.H. Prévost. “Fracture Propagation Driven by Fluid Outflow from a Low- permeability Aquifer”, Transport in Porous Media. http://arxiv.org/pdf/1203.4543 Submitted. 2013.
Gor, G.Y., J.H. Prévost. “Effect of CO2 Injection Temperature on Caprock Stability”, Energy Procedia, Proceedings of GHGT-11 Conference. Submitted. 2013.
Gor, G.Y., T.R. Elliot, J. H. Prévost. ”Effects of Thermal Stresses on Caprock Integrity During CO2 Storage”, International Journal of Greenhouse Gas Control, 2013, 12, p. 300-309. doi: 10.1016/j. ijggc.2012.11.020 Guo, B., K. Bandilla, and M. Celia, “Inclusion of Vertical Dynamics in Vertically Integrated Models for CO2 Storage”, Poster presented at the American Geophysical Union Meeting, December, 2012.
Huang, X., K. Bandilla, M.A. Celia, S. Bachu, D. Rebscher, Q. Zhou and J.T. Birkholzer, “Modeling Carbon Dioxide Storage in the Basal Aquifer of Canada”, Poster presented at the American Geophysical Union Meeting, December, 2012.
Joekar-Niasar, V., F. Doster and M.A. Celia, “Trapping and Hysteresis in Two-phase Flow in Porous Media: A Pore-network Study”, under revision, Water Resources Research, 2013.
Kang, M., J.M. Nordbotten, F. Doster, and M.A. Celia, “Vertical Flow Effects on Gravity Currents with Leakage through Faults”, in preparation, 2013.
Liu, Y., T.Lafitte, A.Z. Panagiotopoulos and P.G. Debenedetti. “Simulations of vapor-liquid phase equilibrium and interfacial tension in the CO2-H2O-NaCl system” AIChE Journal, accepted for publication January, 2013.
Nogues, J., “Investigations in Upscaling Transport and Geochemistry in Porous Media: Modeling CO2 at the Pore, Continuum, and Reservoir Scales”, PhD Dissertation, Department of Civil and Environmental Engineering, Princeton University, 2012.
Nogues, J.P., B. Court, M. Dobossy, J.M. Nordbotten and M.A. Celia, “A Methodology to Estimate Maximum Probable Leakage along Old Wells in a Geological Sequestration Operation”, International Journal for Greenhouse Gas Control, 7, 39-47, 2012.
Nogues, J.P., J.P. Fitts, M.A. Celia and C.A. Peters, “Permeability Evolution due to Dissolution and Precipitation of Carbonate Rocks using Reactive Transport Modeling in Pore Networks”, Water Resources Research. In Review. 2013.
Nordbotten, J.M. and M.A. Celia, Geological Storage of CO2: Modeling Approaches for Large-scale Simulation, John Wiley and Sons, Hoboken, NJ, 235 pages, 2012.
Nordbotten, J.M., B. Flemisch, S.E. Gasda, H.M. Nilsen, Y. Fan, G.E. Pickup, B. Wiese, M.A. Celia, H.K. Dahle, G.T. Eigestad and K. Pruess, “Uncertainties in Practical Simulation of CO2 Storage”, International Journal of Greenhouse Gas Technologies, 9, 234-242, 2012.
Person, M., M. Schlegel, Y. Zhang, J. Rupp, K. Ellett, B. Bowen, C. Gable, J. McIntosh, K. Bandilla and M. Celia, “Effects of Pleistocene Glaciations on the Distribution of Freshwater and Brines across the Illinois Basin, USA”, under review, Geofluids. 2013.
Sarupria S., P.G. Debenedetti. “Homogeneous Nucleation of Methane Hydrate in Microsecond Molecular Dynamics Simulations”, Journal of Physical Chemistry Letters, 3: 2942-2947 (2012) (DOI: 10.1021/jz3012113). Tsai, P.A., K. Riesing and H.A. Stone, “Density-driven convection enhanced by an inclined boundary: Implications for geological CO2 storage”, Physical Review E. 2013.
Zhang, Y., M. Person, J. Rupp, K. Ellett, M.A. Celia, C.W. Gable, B. Bowen, J. Evans, K. Bandilla, P. Mozley, T. Dewers, and T. Elliot, “Potential to Induce Seismicity in Crystalline Basement Rocks by Fluid Injection into Basal Reservoirs”, Geophysical Research Letters. In Review. 2013.
Zheng, Z., B. Soh, H. E. Huppert and H. A. Stone. “Fluid drainage from the edge of a porous reservoir”. American Physical Society Division of Fluid Dynamics Annual Meeting, San Diego, CA, November 2012
Zheng, Z., B. Soh, H.E. Huppert, and H.A. Stone. ”Fluid drainage from the edge of a porous reservoir”. Journal of Fluid Mechanics. To appear. 2013
Zheng,Z., B. Soh, H.E. Huppert and H. A. Stone. “Fluid drainage from a porous reservoir and possible application to CO2 storage”. First International Education Forum on Environmental and Energy Science, Kona, HI, December 2012