Waste Management of Cuttings, Drilling Fluids, Hydrofrack Water and Produced Water

Cuttings and Drilling Fluids/Muds

When a well is drilled, the ‘cuttings’ of drilled rock need to be removed from the well bore. The cuttings, the drilling fluid or mud (to lubricate the drill and help remove the cuttings), and water in the bore hole are brought to the surface where the cuttings are then separated from the fluid, which will be reused in the drilling process. The cuttings and remaining fluids are generally stored in a drilling pit. In New York State, there are specifications regarding the construction of these pits, including a requirement that all pits be lined with plastic to avoid polluted water in the pit entering the soil and shallow groundwater. As mentioned in the Runoff section, it appears that the dSGEIS does not require that all drilling waste (including drilling muds, cuttings and flowback waters) be fully contained on site. Rather, drilling waste and possibly flowback waters can apparently be stored in open, lined pits on site except on floodplains and the NYC watershed. It is not clear why full containment should not be required for all sites.

Drilling muds will be used in drilling in the Marcellus shale zone. According to the Oil and Gas Accountability Project, “drilling fluids or muds are made up of a base fluid (water, diesel or mineral oil, or a synthetic compound); weighting agents (most frequently barite is used); bentonite clay to help remove cuttings from the well and to form a filter cake on the walls of the hole; chrome lignosulfonates and lignites to keep the mud in a fluid state; and various additives that serve specific functions, such as biocides, diesel lubricants and chromate corrosion inhibitors….Drilling muds that circulate through the well and return to the surface may contain dissolved and suspended contaminants including cadmium, arsenic, and metals such as mercury, copper and lead; hydrocarbons; hydrogen sulfide and natural gas, as well as drilling mud additives, many of which contain potentially harmful chemicals (e.g., chromate, barite).” (http://www.earthworksaction.org/pubs/OGAPMarcellusShaleReport-6-12-08.pdf)

Drill cuttings consist of a mixture of the different types of rocks through which the well is bored. As horizontal drilling will occur through the Marcellus shale, the cuttings from this shale will make up a reasonable portion of the total cuttings. These cuttings may be acidic and have the potential to mobilize metals in the cuttings or the soil to which they will be potentially exposed. Additionally, the Marcellus shale contains naturally occurring radioactive materials (NORMs), including radium. A 1999 investigation of NORMs in oil and gas wells found that the concentrations of NORMs on oil and gas production equipment and wastes pose no threat to the public health and the environment. (http://www.dec.ny.gov/docs/materials_minerals_pdf/normrpt.pdf). More recently, the DEC measured radiation from various Marcellus shale sources and concluded that NORMS “do not indicate an exposure concern for workers or the general public associate with Marcellus shale cuttings” (dSGEIS, 5-31).

Hydrofracking Fluids

Hydrofracking fluids are injected into wells under pressure in order to create cracks or fractures in the rock formation. These cracks accelerate gas flow out of the rock and into the well. Hydrofracking fluids are created by adding a proppant (commonly sand) to water. The role of the proppant is to keep the cracks from resealing once the hydrofracking fluid is withdrawn from the well. In addition to the proppant, several types of chemicals are added to the hydrofracking fluid to serve a number of purposes.

• A friction reducer is added to reduce the friction pressure during pumping operations.
• A surfactant is used to increase the recovery of injected water into a well.
• A biocide is used to inhibit the growth of organisms that could produce gases (particularly hydrogen sulfide) that could be dangerous as well as contaminate the methane gas.
• Scale inhibitors are used to control the precipitation of carbonates and sulfates.

There is considerable controversy about the possible effects of the chemicals added to the hydrofracking fluids. On the one hand, the gas industry indicates that the chemicals they use are commonly used in other industries (see, for example, (http://www.fortunaenergy.com/upload/media_element/26/01/microsoft-word---chemical-descriptions-for-marcellus-shale-wells-fortuna-_2_.pdf) . On the other hand, included in the list in the dSGEIS of over 200 chemicals that may be used in hydrofracking are at least two known carcinogens: benzene and formaldehyde. For other compounds, such as xylene and to a lesser extent monoethanolamine, some information suggests carcinogenic activity, but the literature is not in agreement. Table 6-13 of the dSGEIS also lists heavy naptha as a material likely to be used. Heavy naptha is not a unique compound, but rather a mixture of many hydrocarbons, including several that are carcinogenic. Benzene is a high-risk carcinogen and was found in nearly half of all flowback waters (Table 5-9) from Pennsylvania and West Virginia (14/29 samples) at concentrations ranging from 15.7 to 1950 µg/L, with an average of 479.5 µg/L. This average number is nearly 100 times the maximum contaminant level (5 µg/L) established by the EPA. The maximum concentration was nearly 400 times higher. Even if one considers a dilution or attenuation factor, as is done at superfund sites, of as much as 100, it is possible that mishandling of flowback water could contaminate nearby aquifers or groundwater at levels that could exceed a Maximum Contaminant Level (MCL) established by the EPA.

Other compounds of concern in fracking fluids are nonylphenol and octylphenol ethoxylate surfactants which can be degraded by microbes to become endocrine disruptors that mimic estrogen and may adversely affect the health of terrestrial and aquatic wildlife. The ethoxylate portion of these compounds are easily removed by microbes and result in the formation of nonylphenol and octylphenol which are both weakly estrogenic. Normal monitoring of the parent compounds used in fracking fluids would not pick up the presence of these degradation products. Based on the similarity to other environmental exposure scenarios, it is reasonable to expect them to be present any time the parent surfactants are used in the environment. Exposure to these compounds, even at extremely low concentrations (µg/L) can cause feminization of fish.

Requiring the use of less hazardous alternative compounds (aka substitution) is a well accepted method of risk mitigation. Many drilling companies phased out the use of benzene in the 1990s so it should be possible for those working in the Marcellus Shales to do the same. In order to reduce the risk of contamination associated with spills or storage failure, the use of benzene and other petroleum distillates in drilling fluids should be disallowed since functional alternatives exist. Alternative surfactants to nonylphenol and octylphenol ethoxylate exist so banning these compounds should not pose an undue burden on drilling companies.

Flowback

After hydrofracking, the hydrofracking fluid is withdrawn from the well, and to the extent possible, from the formation. Currently in Pennsylvania, about 15% of the hydrofracking fluid returns to the surface within 2 to 8 weeks (http://www.srbc.net/programs/docs/ProjectReviewMarcellusShale(NEW)(1_2010).pdf); this is referred to as flowback water. The rest of the water is presumably strongly absorbed by the shale and will only slowly return to the surface, primarily as water vapor, over the life of the gas well. The flowback water can be reused in hydrofracking other wells or disposed of as waste water.

The Marcellus shale is of marine origin and naturally contains high levels of salt and NORMS, some of which will dissolve in the hydrofracking fluid and be brought to the surface in the flowback water. This waste water will likely contain high levels of total dissolved solids (mostly salt or sodium chloride) and NORMS, as well as added chemicals and/or their degradation products. There are three ways this water, now considered industrial waste water can be disposed: 1) underground injection, 2) municipal sewage treatment facilities (POTWs) that have an approved pretreatment program for industrial waste, and 3) private industrial waste treatment facilities. The sites available for underground injection of waste water are limited, and there are concerns that in certain locations underground injection may induce seismicity. POTWs must pretreat the waste water to the extent that the waste stream does not damage the sewage treatment system and does not exceed its permitted capacity to release pollutants to receiving waters. POTWs are generally not effective in removing salts from waste water, so there is concern that individual and cumulative releases to surface waters from treated, yet salt enriched, waste water could, from individual or cumulative releases, disrupt freshwater ecosystems. Currently, there are no private industrial waste treatment facilities for handling Marcellus shale flowback water in New York State.

The issue of NORMS, primarily radium, in the flowback water needs to be considered as well. Radium in flowback water may be reduced during treatment to acceptable levels to discharge into surface waters through being retained in the solid waste. This raises the issue of where to dispose of the radium enriched solid waste from pre-treatment of flowback water or flowback water treated in private facilities. Both Louisiana and Texas regulate disposal of NORMS in solid waste from exploration and production of natural gas. It appears that NYS has this authority under NYCRR Part 360 (or 380 p7-102). However, reference is only made to standards for discharges in effluent; it is not clear whether standards exist for discharge in solid waste.

A 1999 report prepared for the Department of Energy (Smith et al. 1999. An Assessment of the Disposal of Petroleum Industry NORM in nonhazardous Landfills, DOE/BC/W-31-109-ENG-38-8), considered the risks of disposing of NORMs in nonhazardous landfills. The study used a scenario of 2,000 cubic meters of solid waste with 50 picoCurries (pCi) per gram disposed in a landfill and found negligible harm to landfill workers, nearby residents, and future recreational users of the landfill property. It did note that higher levels could lead to increased risks. As shown in Appendix 13 of the dSGEIS, production brine from previously sampled wells drilled into the Marcellus Shale could have radium concentrations of upwards of 5000 pCi per liter. Assuming a pretreatment process removes solids that comprise 1% of the effluent volume including all the radium, this generates a solid with approximately 500 pCi per gram, 10 times the concentration used in the prior study. Although just a rough estimate, it highlights the potential for NORM levels above those even typically considered in other states when dealing with land disposal options.

Produced Water

As gas is pumped out of a well, water contained in the Marcellus shale formation may be withdrawn as well. This water is often called produced water. The volume of water produced is not expected to be great; one estimate is 42 gallons of water per million cubic feet (MMcf) of gas produced. At the end of the first year, a typical horizontal well in the Marcellus shale is not expected to produce more than 1 MMcf of gas per day; so produced water is not likely to exceed 300 gallons per week.