Guest Commentary pubs.acs.org/JPCL
Fracking: What Can Physical Chemistry Offer?
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of this technology requires addressing the public opinion using scientific data. The focus of this Commentary is on the fundamental scientific problems that arise in hydraulic fracturing. The National Science Foundation recently supported a workshop on hydraulic shale fracturing, which brought together scientists and engineers from academic, governmental, and industrial settings.7 This Commentary draws on the lectures given at that workshop and on a report written by the organizers,8 with an emphasis on the opportunities for fundamental research. The conclusions presented in this Commentary are, however, our own. We are convinced that addressing the physical chemistry questions described herein is likely to allow the industry to deploy the hydraulic fracturing technology economically while limiting its environmental impact. In Figure 1, we highlight with an alphabetical letter the research areas discussed in the text. Characterization of Shale Microstructure and Nanostructure (A in Figure 1). Although many different shale rocks exist, they have in common a very low permeability to gases and liquids, lower than that of concrete.9 The shale rock is typically very heterogeneous both chemically (kerogen, clay, calcite, and quartz) and in terms of pore size distribution and connectivity. A wide diversity in the structure and composition is observed in different shale formations. In order to understand the physical properties of fluids in shale, methods for the characterization of the shale microstructure and nanostructure are crucially needed. The structure of shale is typically characterized experimentally via SEM. The pores in shale are small, however, on the order of 10 nm, and new methods for the threedimensional physical and chemical characterization of shale would be immensely useful. Experimental characterization tools often used in fuel cells, which include small-angle neutron scattering, radiography, and reflectometry,10 might be extended to investigate shale rocks. This would be particularly important because the phenomena of interest (e.g., transport of hydrocarbons) depend on molecular details (e.g., short-ranged hydrocarbon−pore interactions). Methods that monitor changes in rock properties upon infiltration of fracturing fluids and/or depletion of hydrocarbons would also be extremely beneficial. These methods at present include seismic and electrical/electromagnetic tools. To fully take advantage of these emerging technologies, it is necessary to develop a quantitative understanding on how macroscopic rock properties (e.g., electrical conductivity, speed of sound) change upon varying the amount of fluid content and its composition. We point out a recent review regarding both experimental and simulation methods applied to investigate the properties of fluids (water as well as hydrocarbons) confined in narrow pores, in some cases representative of those that can be found in shale formations.11 Of particular interest is to quantify the effect of repeated fracturing on the microstructure of shale. Only about 10% of the water returns in the flow-back. Is the rest absorbed into the
ydraulic fracturing (“fracking” for the language purists, “fracing” for the practitioners) is the process where water (with some additives) is pumped into shale formations to fracture the rock and improve the extraction of crude oil and natural gas.1,2 Pressures up to over 20 000 psi are applied during one fracturing stage. Figure 1 reproduces a schematic of the process. A well is drilled vertically down into the soil (up to depths between 6000 and 10 000 feet − aquifers are usually at depths lower than ∼1000 feet3). Once the well reaches the payload, it is drilled horizontally much further (up to 10 000 feet) into the formation.4 Because of horizontal drilling, a surface pad of approximately 6 acres is sufficient for exploring and producing a subsurface formation that extends for up to 6000 acres.5 Within the shale formation, the well is lined with a metal casing that contains small apertures for fracturing. Water (with some additives) is then pumped into the well and goes through the apertures at high pressure, thus fracturing the rock. Once the hydraulic pressure is released, the “flow-back” water flows back into the well and is removed. Several fracturing stages (up to 30) can be performed within a single well, which becomes functional. Natural gas or oil, if present in the treated area, flows out and can be collected. Because of fracturing, the cost of one well can range from $1 to 7 million.2 The economic benefits of hydraulic fracturing are undeniable. Extraction from shale reserves has become economically feasible. The process has made domestic natural gas cheap and abundant6 and has increased even the domestic oil production. North Dakota, as an example, has become the #2 producer of crude oil in the country. The natural gas byproduct is in some cases wastefully burned off because the infrastructure to transport it does not exist. In other cases, the availability of economic natural gas (in particular, ethane) is triggering significant investments from the chemical industry to enhance domestic manufacturing. As another example, the American Chemical Council estimates that a 25% increase in ethane supply will generate $132 billion in new U.S. economic output. With continued growth in hydraulic fracturing, the U.S.A. could become self-sufficient in energy within the next 20 years, with obvious global socio-economic consequences. It is even expected that natural gas could be exported!
Methods for the characterization of the shale microstructure and nanostructure are crucially needed. Hydraulic fracturing has become a topic of political and sociological debate, in part, because many of the most promising deposits of shale are located in regions where people are suspicious of the oil and gas industry and where prior industrial developments have left deep scars in the environment and on the public confidence towards the industry. There is no doubt that the sustainable deployment © 2013 American Chemical Society
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Figure 1. Schematic representation of a hydraulically fractured well. On the left, we report, approximately, the depths at which potable water aquifers and shale formations are typically found. Note that the technology of hydraulic fracturing became economically beneficial for the development of shale formations when the industry managed to drill horizontal wells. These can explore wide shale formations even though the latter only extend vertically for as little as 80 feet (the average thickness of a shale formation is ∼450 feet). Horizontal wells can extend for up to 10 000 feet from the vertical well. In the figure, letters A, B, and C identify the location for some of the research opportunities discussed in the text.
shale formations? Experiments and computer simulations conducted for well-characterized shale samples would shed considerable light on these issues. A recent review focuses on some of the work already reported in the literature,11 but much remains to be done, especially because most of the existing work has been conducted on model porous materials, which differ substantially from typical shale rock formations. Despite the wide variability in rock properties, it would be desirable to achieve some generalized understanding of the properties of natural gas in shales. Equilibrium Partitioning of Salts (and Trace Metals) from Shale to Water (A and B in Figure 1). Some shale formations (e.g., those found in the Marcellus formation in the Northeastern part of the United States) do not contain significant amounts of mobile water. Although most of the water pumped into the formation does not come out immediately after a fracturing job is completed, the little flow-back water recovered (10−15% of the water used in the fracturing job) can have a very high salt concentration. Because no solid salt is detected by standard characterization techniques in the rock, the ions must come from the clay mineral surfaces (often Illite in the Marcellus region). What is the physical state of the clay−water−salt complexes? What is the nature of the equilibrium between the water and the clay deposits? Are osmotic effects responsible for the extraction of the salt from the shale formations? Can the fracturing fluid be designed so as to affect the partition of the salt (and trace metals) in order to reduce the amount extracted? Answering these fundamental questions is important not only for better engineering of the hydraulic fracturing process but also for understanding and preventing the risk of contamination. Flow Properties of Both the Fracturing Fluid and the Produced Hydrocarbons (A and B in Figure 1). The main component of the fracturing fluid is water, used at high pressure to create fractures. Among several additives, the main ones are polymeric drag reducers to improve the flow rate and “proppants” to keep the fractures open. What is the flow behavior of polymers in the
shale? The low permeability of shale to methane and water makes it unlikely that the excess water will flow to the groundwater. But how does repeated fracturing affect the permeability? How long will the fractures produced by the hydraulic pressure remain in place? Do the fluids at contact with the rocks affect the rocks response to mechanical solicitations?
Only about 10% of the water returns in the flow-back. Is the rest absorbed into the shale? How does repeated fracturing affect the permeability? How long will the fractures produced by the hydraulic pressure remain in place? Do the fluids at contact with the rocks affect the rocks’ response to mechanical solicitations? Adsorption Behavior of Natural Gas and Other Hydrocarbons (B in Figure 1). Natural gas exists as free gas in natural fractures, free gas in rock pores, and as adsorbed gas.12 While hydraulic fracturing is expected to extract, for the most part, free gas from rock pores, is there the possibility of extracting adsorbed gas? What are the interactions of the gas with the rock formations? How much gas is adsorbed and how strongly, and how does this depend on the nanoscale structure of the shale? Can the interactions between the gas and rock be altered by manipulating the physic-chemical properties of the shale? Is it possible to enhance the mobility of higher-molecular-weight hydrocarbons by appropriately designing the fracturing fluids? Can the hydrocarbons be recovered while undesired substances (salts but also radioactive elements) remain locked within the 688
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during the natural gas extraction) at the surface is becoming an economical burden, and new technologies are needed to allow fast processing and reuse of this valuable resource. It is also desirable, and required by the EPA,21 to limit the emissions of natural gas. It is certainly desirable to develop economical materials and processes for capturing natural gas and enabling its utilization, rather than dispersing it into the environment. Finally, because it is possible that natural gas and oil leaks from the well bore near the surface contaminate aquifers, it is necessary to develop materials for safe well casings.
complicated and chemically heterogeneous pore structures of the shale formation? How do both polymers and proppants exit the metal well casing and interact with the porous rock environment? How does the presence of nanometer and micrometer sized proppants change the flow properties of hydrocarbons? Can the transport models be enhanced to take into consideration changes in porosity due to subsequent fracturing jobs? Significant improvement has been made recently to develop models that predict the flow of fluids within the fractures created in a shale formation.13,14 One approach, known as the “Itasca” fracture network model, is a discrete-element method that allows scientists to describe even the intersection between multiple hydraulic fractures. Despite this progress, it remains a challenge to be able to describe simultaneously the slow dynamics expected for fluid transport within the narrow pores naturally present within the rocks and the faster movement observed within the wider fractures created by hydraulic pressure. Detailed modeling efforts might help overcome this hurdle. It appears also challenging to be able to simultaneously describe the fast flow of low-molecularweigh compounds (e.g., methane) and that of high-molecularweigh polymers and how the different compounds affect each other’s transport. Understanding in detail whether fluids, including hydrocarbons, can migrate in subsurface formations upon stimulation with hydraulic fracturing could help quantify the likelihood of contamination to drinking water due to the process of hydraulic fracturing, which remains a topic of great debate.15−20 Regarding the polymeric elements often used (i.e., hydrolyzed polyacrylamide), it is well-known that these are effective at low salt concentration, but they lose effectiveness as the salt concentration increases. What is the effect of salt on the conformational and flow properties of these polyelectrolytes? Can new materials be synthesized that are effective at high salt concentrations? Such materials would be extremely beneficial because they would allow the industry to use salty water as fracturing fluid, hence decreasing the demand for fresh water in new fracturing operations and reducing both economical and environmental impact. Physical Properties of Fracturing and Flow-Back Fluids (A and B in Figure 1). Surprisingly, there is very little data on the physical properties of fracturing and flow-back fluids. Although the conditions are not severe (no extreme temperatures or pressures), reliable measurements of the physical properties of the fluids (with high salt concentrations, polymers, and particles) are not widely available. Engineers resort to empirical correlations to predict these properties, correlations that have not been tested at the conditions of interest. There is a dearth of data on the surface tension of fluids, phase behavior of the natural gas−water mixtures, and chemical potential of the brine solutions. Understanding and predicting how the structure, dynamics, and thermophysical properties of various fluids change when confined within porous rocks is of great interest. Such understanding is required for the rational design of fracturing fluids that are efficient within a given shale formation (as the physic-chemical properties of shale rocks vary widely among different formations, it is possible that a single fracturing fluid is extremely effective in one formation while entirely disruptive for the economical development of another). Additional Research Opportunities near the Surface (C in Figure 1). More research is needed to reduce the environmental impact of hydraulic fracturing near the surface. For example, treating of flow-back and production water (water produced
The process of hydraulic fracturing involves several fundamental phenomena, the physical and surface properties of complex fluids, their behavior in connected and heterogeneous porous media, and the three-dimensional characterization of these rocks. These represent opportunities for fundamental research that can have a direct impact on an important and developing industrial process. In conclusion, every stage of the process of hydraulic fracturing poses fundamental scientific questions that are of interest to physical chemists. The fracturing fluid consists of water, polymers, and proppants. The flow properties of this fluid, especially under nanoscale confinement, are not well understood. The fracturing fluid enters the shale, the nanostructure of which is not well characterized. There is then, presumably, an equilibrium between the fracturing fluid and the rock formation, which results in the majority of water flowing somewhere (unknown) and a high concentration of salt ions partitioning to the flow-back water. The physical properties of the brine, the partitioning of the brine between rock/clay and water, and the effect of brine on other additives are not well understood. Once the fracturing fluid is removed from the shale formation, the efficiency of extraction of gas and oil is of interest, as is the effect of repeated fracturing. Computer simulations can play an important role in this endeavor. In particular, the development of coarse-grained models with a degree of transferability is of interest because the range of concentrations and components can be large. Of course, the applicability of simulation results will be enhanced when synergistically coupled with appropriate experimental data. It will be desirable to develop ad hoc strategies to merge theoretical studies at different time and length scales to enable the prediction from pore-level fluid properties to the well-level extraction economical potential. Despite the wide differences observed in shale rocks from different formations, it would be extremely beneficial to develop some generalized understanding for both the economical potential and the possible environmental impact related to drilling and producing a well. The process of hydraulic fracturing involves several fundamental phenomena, the physical and surface properties of complex fluids, their behavior in connected and heterogeneous porous media, and the three-dimensional character689
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Exchange Membrane Fuel Cells. J. Electrochem. Soc. 2008, 155, B427− B434. (11) Cole, D. R.; Ok, S.; Striolo, A.; Phan, A. Hydrocarbon Behavior at Nanoscale Interfaces. In Carbon in the Earth; Hazen, R. M., Hemley, R. J., Jones, A., Barross, J., Eds.; Reviews in Mineralogy and Geochemistry; 2013, 75; DOI: 10.2138/rmg.2013.75.16. (12) Cipolla, C.; Mack, M.; Maxwell, S. Reducing Exploration and Appraisal Risk in Low Permeability Reservoirs Using Microseismic Fracture Mapping Part 2; Presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Lima, Peru, December 1−3, 2010; SPE 138103, pp 1−24. (13) Nagel, N.; Gil, I.; Sanchez-Nagel, M.; Damjanac, B. Simulating Hydraulic Fracturing in Real Fractured Rocks − Overcoming the Limits of Pseudo3D Models; Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, U.S.A., January 24−26, 2011; SPE 140480, pp 1−15. (14) Weng, X.; Kresse, O.; Cohen, C.; Wu, R.; Gu, H. Schlumberger Modeling of Hydraulic-Fracture-Network Propagation in a Naturally Fractured Formation. SPE Prod. Oper. 2011, 26, 368−380. (15) Whittemore, D. O. Geochemical Differentiation of Oil and Gas Brine from Other Saltwater Sources Contaminating Water Resources: Case Studies from Kansas and Oklahoma. Environ. Geosci. 1995, 2, 15−31. (16) Davis, S. N.; Whittemore, D. O.; Fabryka-Martin, J. Uses of Chloride/Bromide Ratios in Studies of Potable Water. Ground Water 1998, 36, 338−350. (17) Osborn, S. G.; Vengosh, A.; Warner, N. R.; Jackson, R. B. Methane Contamination of Drinking Water Accompanying Gas-Well Drilling and Hydraulic Fracturing. Proc. Natl. Acad. Sci. U.S.A. 2011, 108, 8172−8176. (18) Davies, R. J. Methane Contamination of Drinking Water Caused by Hydraulic Fracturing Remains Unproven. Proc. Natl. Acad. Sci. U.S.A. 2011, 108, E871. (19) Schon, S. C. Hydraulic Fracturing Not Responsible for Methane Migration. Proc. Natl. Acad. Sci. U.S.A. 2011, 108, E664. (20) Myers, T. Potential Contaminant Pathways from Hydraulically Fractured Shale to Aquifers. Ground Water 2012, 50, 872−882. (21) Ternes, M. E. Regulatory Programs Governing Shale Gas Development. In Chemical Engineering Progress; AIChE Publication: New York, August 2012; Vol. 8, pp 60−64.
ization of these rocks. These represent opportunities for fundamental research that can have a direct impact on an important and developing industrial process. It is likely that multidisciplinary research teams will be able to secure success in this endeavor.
Arun Yethiraj*,† Alberto Striolo‡
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† Department of Chemistry, University of WisconsinMadison, Madison, Wisconsin 53706, United States ‡ School of Chemical, Biological and Materials Engineering, University of Oklahoma, Norman, Oklahoma 73069, United States
AUTHOR INFORMATION
Notes
Views expressed in this Guest Commentary are those of the authors and not necessarily the views of the ACS.
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ACKNOWLEDGMENTS A.S. is grateful for financial support from the National Science Foundation, Award Number CBET-1229931, which supported the workshop titled “Identification of Fundamental Interfacial and Transport Phenomena for the Sustainable Deployment of Hydraulic Shale Fracturing Role of Chemicals Used”. A.S. wishes to thank all participants to the workshop and, in particular, Dr. Bryndzia and Prof. Sondergeld for their patience in explaining some of the issues related to hydraulic fracturing at the workshop and via many private conversations.
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REFERENCES
(1) Arogundade, O.; Sohrabi, S. A Review of Recent Developments and Challenges in Shale Gas Recovery; Presented at the SPE Saudi Arabia Section Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, April 8−11, 2012; SPE 160869, pp 1−31. (2) Holditch, S. A. Getting the Gas out of the Ground. In Chemical Engineering Progress; AIChE Publication: New York, August 2012; pp 41−48. (3) Fisher, K. American Oil Gas Reporter 2010, 53, 30−33. (4) Warlick, D. Gas Shale and CBM Development in North America. Oil Gas Financ. J. 2006, 3, 1−5. (5) King, G. E. Hydraulic Fracturing 101: What Every Representative. Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventinal Gas and Oil Wells; Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, U.S.A., February 6−8, 2012; SPE 152596, pp 1−80. (6) Liss, W. Demand Outlook: A Golden Age of Natural Gas. In Chemical Engineering Progress; AIChE Publication: New York, August 2012; pp 35−40. (7) Workshop: Identification of Fundamental Interfacial and Transport Phenomena for the Sustainable Deployment of Hydraulic Shale Fracturing − Role of Chemicals Used; NSF grant number CBET-1229931; 2012. (8) Striolo, A.; Klaessig, F.; Cole, D. R.; Wilcox, J.; Chase, G. G.; Sondergeld, C. H.; Pasquali, M. Identification of Fundamental Interfacial and Transport Phenomena for the Sustainable Deployment of Hydraulic Shale Fracturing − Role of Chemicals Used; 2012. (9) Boyer, C.; Kieschnick, J.; Lewis, R. Oilfield Review. In Invierno; Schlumberger: Houston, TX, 2006−2007; pp 36−49. (10) Hickner, M. A.; Siegel, N. P.; Chen, K. S.; Hussey, D. S.; Jacobson, D. L.; Arif, M. In Situ High-Resolution Neutron Radiography of Cross-Sectional Liquid Water Profiles in Proton 690
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