Direct Process Monitoring Needed

The work of Woda et al. (1) and similar forensic studies (e.g., refs. 3 and 4) speak to the need for direct monitoring of the shale drilling, fracturing, and gas production processes. Forensic analysis is not an efficient or direct approach to improve understanding of the environmental risks of shale gas development so that such risks can be managed better. While there are regulatory requirements and company best practices (5) for pre- and postfracturing testing of water wells and surface waters in the vicinity of shale gas development activity, such monitoring is designed to detect only impact and usually will provide little or no insight into the specific mechanisms leading to the impact. Rather than after-action forensic analysis by geochemical and hydrogeological investigations, a more proactive approach of designed monitoring before, during, and after development of shale gas resources would make possible more direct observations of the level of control achieved under different operational and field conditions.

The US Department of Energy National Energy Technology Laboratory, in partnership with a number of industrial and academic partners, has established the Marcellus Shale Energy and Environment Laboratory (MSEEL), a shale gas production field site instrumented to provide for study of new technology to improve not only recovery efficiency in unconventional hydrocarbon development but also understanding and management of environmental impacts (6). The MSEEL includes logged and instrumented horizontal production wells, a microseismic observation well, and surface geophysical and environmental monitoring stations (7). The analyses reported to date pertaining to surface and near-surface environmental effects have focused on chemistry of the produced water from the production wells (8). From the MSEEL published research to date (6), it does not appear that any studies of methane migration have been conducted.

Field studies to monitor and understand methane migration in hydraulic fracture zones and overlying formations are needed. Jackson et al. (9) identified two areas in particular need of field research: (i) baseline geochemical mapping with time series sampling from a sufficient network of groundwater monitoring wells, and (ii) field investigation of the potential mechanisms and pathways by which hydrocarbon gases and saline fluids from hydraulic fracturing zones migrate into and contaminate useable groundwater. Soeder (10) made similar recommendations and emphasized the importance of highly characterized field test sites and dedicated monitoring wells with multilevel sampling capability.

Cahill et al. (11) presented the results of studies of methane migration in a shallow unconfined sand aquifer at the aquifer research facility in Borden, Ontario, Canada. Methane was injected into the well-characterized Borden aquifer, with subsequent subsurface monitoring across a dense network of multilevel monitoring wells. Results from the field experiments showed rapid lateral migration of the injected methane along bedding features of the aquifer, as well as buoyancy-driven upward migration, yielding an extensive dispersed zone of dissolved methane and changes in the chemistry of the groundwater. Through monitoring of the chemistry and microbial community in the groundwater system, Cahill et al. (11) observed biogeochemical changes in the groundwater system similar to those hypothesized by Woda et al. (1). Further, the results of Cahill et al. (11) show that subtle variations in aquifer properties can have a major impact on the distribution of migrating methane, and that surface flux to the atmosphere is not indicative of the lateral extent of methane-induced groundwater-quality impacts. Overall, the field studies of Cahill et al. (11) make clear the level of resolution required in research-grade subsurface monitoring to understand processes.

Direct monitoring of gas migration from the deep subsurface environment to overlying aquifers is challenging, but development of methods is proceeding via research on detection of CO₂ leakage from reservoirs for geological carbon storage. Monitoring schemes under consideration include monitoring wells both above and adjacent to the storage reservoir, together with instrumentation that can detect changes in pressure, temperature, saline fluid presence, or geochemistry (12). Most of these methods involve a combination of subsurface scenario modeling and measurements to determine which scenarios are most consistent with the data. Target variables include aquifer geochemistry and seismic wave speed, surface flux measurements, and chemical and isotopic tracers (e.g., refs. 13, 14). Methods have also been proposed for combining evidence from different types of monitoring (15, 16).

The work of Woda et al. and similar forensic studies speak to the need for direct monitoring of the shale drilling, fracturing, and gas production processes.

Similar studies have begun to appear for identifying methane leakage from shale gas development, using either conceptual or numerical models to assess transport pathways and geochemical outcomes (17, 18). Models and monitoring programs are often synergistic: Monitoring is necessary to calibrate, verify, and refine the conceptual and parametric representation of the subsurface embodied by the model, while the modeling helps to identify the sampling needs that are most important for reducing the uncertainties that matter most for both ongoing model improvements and management decisions.

Shale gas development companies collect various kinds of data and information related to safe and effective installation and operation of wells. These data could be engaged at the regional (or larger) scale to advance the reduction and management of environmental risk in unconventional hydrocarbon development. Issues of proprietary technology, economic competition, and legal liability make sharing of such data difficult (2, 10, 19). Nonetheless, opportunities for government–industry–university partnering in research, such as has been achieved with the MSEEL, merit continuing effort.

Geophysical 3D seismic surveying is typically done before drilling wells to assess the economics of a project and to minimize operational risk. These surveys provide information about the target shale resource and geological features (2). While repeat seismic surveys to assess subsurface changes resulting from production are not common due to the cost involved, ongoing geophysical monitoring has been performed at some sites. Such seismic data and analysis can provide valuable insight into time evolution of subsurface conditions and how operations can be adjusted to minimize the potential for migration of methane and saline fluids from the target shale unit.

Other data collected during shale gas development include well pressures during drilling, fracturing, and production, as well as borehole geophysical testing such as temperature logs, borehole geometry logs, and well-cement bond logs to monitor integrity of annular cement seals. While these measurements provide only indirect information about processes occurring in the subsurface, they can be useful in detecting problems with well integrity and, in combination with other monitoring information, can help provide insight into gas and saline fluid migration and other phenomena.

Government–Industry–Academic Research Partnerships

The environmental forensic analysis of Woda et al. (1), part of a growing effort to try to discern and evaluate the extent and import of environmental impacts of shale gas development, speaks to the need for more research that directly involves the production process. Government–industry–academic partnerships such as the MSEEL (6) and the Energy Research Program at the Health Effects Institute (20) are needed to conduct field research in the regions where unconventional hydrocarbon development is taking place. Such partnerships and research will be critical to advancing knowledge and methods for management of environmental risks in a cost-effective manner.