Reconciling shale gas development with environmental protection, landowner rights, and local community needs

Safe Drinking Water Act

The SDWA is the final federal law governing flowback water management. It establishes the Underground Injection Control (UIC) program, which regulates waste injections into six categories of wells. The UIC regulations are designed to ensure that injected gases and wastewater do not migrate upward and pollute groundwater. Class II wells are the most relevant to underground storage of flowback water (Figure 5.1). Other sections of the law, such as those that regulate water injected into the wellbore during the fracturing process, are discussed in Chapter 4.

Underground injection is a standard process for dealing with flowback water in other regions where shale gas occurs (such as the Barnett shale of Texas). However, injection well capacity in the Marcellus shale region is extremely limited. In Pennsylvania, for example, eight permitted disposal wells may each accept an average of 42,000 gallons per day.²⁵⁴ Due to limited capacity, underground injection is not expected to be a viable option for managing flowback water in the Marcellus play. There is little additional opportunity to dispose of flowback water other than to transport it to states outside of the Marcellus play.

State laws

In addition to the ECPRA, CWA, and SDWA, individual states may have their own water quality laws. Gas companies must comply with state and local laws and regulations when drilling.

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  Maryland prohibits any wastes that would be toxic to residents or impair navigation to be discharged into receiving waters.¹ In addition, Maryland expressly forbids any underground injection of wastes.²⁵⁵ The state’s expectations are that gas companies will transport their flowback water out of the state for disposal rather than find in-state solutions.²⁵⁶
  

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  New York prohibits discharge of radioactive waste into receiving waters through its Environmental Conservation Law ² Flowback water with high radium-226 levels could be regulated under the law.
  

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  Pennsylvania requires additional treatment for residual wastes under its Solid Waste Management Act. Drill cuttings from oil and gas mining are omitted, as long as they are disposed of properly at the rig.²⁵⁷
  

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  West Virginia does not have additional wastewater treatment or management laws beyond the CWA. However, West Virginia Department of Environmental Protection’s “Oil and Gas Industry Guidance” suggests that gas companies consider recycling flowback water as a means of dealing with waste.²⁵⁸
  

Figure 5.3: Recycled flowback water may need treatment.

Source: Guadlip, Tony, et al. 2008. Marcellus Shale Water Management Challenges in Pennsylvania. Paper for presentation at the 2008 Society of Petroleum Engineers Shale Gas Production Conference, Fort Worth, Texas, U.S.A., 16-18 November 2008.

• Reverse osmosis: The reverse osmosis process forces wastewater through a selective membrane, yielding high concentration and low concentration solutions. The low concentration solution may require finishing through pH stabilization or mineralization. The high concentration solution is a waste product and must be disposed.

• Nanofiltration: Nanofiltration is similar to reverse osmosis, but requires less energy. Approximately 75 to 90 percent of the feed water is recovered, so minor amounts of high concentration brine is produced.

• Electrodialysis: The electrodialysis process treats water as it flows between a stack of anion- and cation-exchange membranes. The membranes work together to systematically concentrate pollutants. System costs are high but recovery rates are significant, with nearly 90 percent of feed water consistently reclaimed.

Freeze thaw

The freeze thaw process begins when freezing water below 32F is sprayed into an ice pile. Runoff contains high TDS concentrations when the ambient temperature is freezing or below. Conversely, runoff contains low TDS concentrations when the ambient temperature is above freezing. The limiting factors to using freeze thaw technology are the climate of the region where it is used and the large area it requires. A 1,000 barrel per day facility would require tens of acres for treatment. An additional recycling option still in development would use acid mine drainage (AMD) as a source of water for hydrofracking. AMD is abundant in former coal-producing regions such as the northeast United States because it forms when coal mining exposes rainwater and groundwater to pyrite and other chemicals. The resulting fluid is high in sulfuric acid, iron hydroxide, sulfates, and suspended solids. If left untreated, runoff into water bodies causes metal oxides to form an impervious surface on the bed of receiving water. The impervious surface destroys the aquatic ecosystem.

Researchers at Carnegie Mellon University recently received a $1 million grant from the U.S. Department of Energy to explore using acid mine drainage to remove electrochemical cells to achieve minimum water quality requirements necessary to use for hydraulic fracturing.²⁶⁰ In addition, at least one water reclamation company, STW Resources, has adapted the large-scale acid mine drainage treatment process for use at drilling operations. Large treatment plants normally oxidize the acid mine drainage in lagoons and alter the pH level by adding lime and other base chemicals. The STW process completes the same process in a mobile unit. The unit can handle 360,000 gallons per day and costs are mitigated substantially by government grants and subsidies.²⁶¹

Evaporation In western states drillers often leave flowback water in a lined pit and allow it to evaporate naturally (Figure 5.5). The resulting solid residue is composed mostly of TDS and can be sold to local governments for cold weather road treatment or disposed of as a solid under applicable laws.

Figure 5.5: Evaporation pits are used to manage flowback water in Western states.