Advancements in horizontal hydraulic fracturing technologies combined with the exploration of vast unconventional shale resources have led to an energy boom that is rapidly transcending economics of the Appalachian region. Unfortunately, shale development activities are progressing at a rate that is driving new regulatory policies before the possible detrimental effects of these techniques on water resource sustainability are understood. The biological, physical, and chemical properties of the hydrofracking fluids will govern their interaction with pore structures and formation fluids. Understanding the fate and longevity of these fluids is critical to framing our understanding of the risks of these activities to potable water supplies. The objective of this research is to better characterize the biophysiochemical properties of fluids relevant to unconventional shale development, and formulate a risk-based flow and transport model for solving their spatiotemporal distribution in the subsurface. The investigators will examine the physical properties and biodegradability potential of fracking and flowback fluids, and measure the governing physical characteristics of rock cores from unconventional shale and surrounding formations in order to quantitate the constitutive relationships that describe how fluids move through media. The investigators will combine experimentally-derived properties with industry knowledge and a probabilistic fracture hydraulic conductivity to formulate a risk-based flow and transport model capable of predicting fluid movement from shale formations to groundwater aquifers.
This research will help quantify the likelihood that hydrofracking processes occurring at depth could migrate to shallower groundwater aquifers that serve industrial, commercial, or domestic water supplies within a foreseeable time frame. It should also provide insight into how long the fracking fluid compounds would persist in the subsurface environment if they were mobilized from the unconventional shale formations. By integrating experimentally-derived properties with expert knowledge and a transport modeling approach, this research will both advance our understanding of fluid properties used during energy development activities and provide a new tool for practitioners to assess migration risk under a range of hydrogeologic scenarios. The research undertaken in this project will be communicated to a broad range of stakeholders through participation in extension meetings and ongoing workshop forums on shale energy development in the Appalachian region.
This research investigated the biodegradation potential of organic additives used in horizontal hydraulic fracturing fluids for shale energy development. It also evaluated changes in physical characteristics for fluids produced from unconventional shale wells. The biodegradation rate and extent of organic additives was influenced by its concentration and fluid salinity under idealized (oxygenated) conditions. Microbial degradation removed between 51% to more than 90% of added organic carbon in about a week, with higher removal efficiency with more dilute fracturing fluid concentrations and lower removal at higher concentrations. Minimal difference was observed in carbon removal extent between wastewater sludge microorganisms as compared with microorganisms derived from lake water. Higher salinities greatly inhibited overall biodegradation rates and extents. Two common alcohols in these fluids, isopropanol and octanol, were biodegraded to levels below analytical detection limits, while the solvent acetone accumulated through time as an incomplete biotransformation product. These data indicate that some organic compounds in a complex hydraulic fracturing fluid are readily degraded by typical environmental microbes while other compounds may be incompletely degraded in the natural environment if accidentally released to surface waters. Fate and transport models are commonly used to evaluate the migration of fluids in the subsurface to drinking water receptors. Models used to evaluate migration from shale formations to the shallow subsurface currently lack data on certain key physical parameters, such as density and viscosity, that govern fluid movement. Using samples collected from three hydraulic fractured Marcellus shale wells in Pennsylvania, U.S.A., we found fluid densities increased 9.8% and viscosities increased 26.5% over a period of 11 months after hydraulic fracturing. Fluid density and viscosity rapidly increased during the first two weeks after fluid injection due to greater concentrations of dissolved inorganic ions coming from the shale formation, then plateaued about two months after hydraulic fracturing. Densities and viscosity depend upon temperature, and are therefore influenced by warmer temperatures found in deep shale formations. When experimentally subjected to Marcellus shale relevant temperatures, mean density decreased by 2.7% while viscosity decreased 44% between 20 and 60°C. These measurements are now being used to improve flow and transport models predicting the migration of hydraulic fracturing fluid in the subsurface.
