Hydraulic fracturing (also called fracking) involves pressurized injection of a liquid consisting of water, sand and chemical additives into the ground. The fluid injection creates fissures or cracks in the underground formations and forces release of oil and gas that would often not be recoverable by other means.
Oil and gas recovery by hydraulic fracturing (fracking) technologies is not a new idea. Fracking was introduced in the 1940s, and by 1955, 100,000 hydraulic fracturing projects had been applied. The numbers have grown rapidly particularly because of the introduction of horizontal drilling techniques, which allow formerly inaccessible rock formations to be reached and tapped for hydrocarbons. This method has grown and been successful in the U.S. and other countries for extracting hydrocarbons for fuel and other uses.
Since some fracking projects are relatively small-volume producers and costly, the application is sensitive to economic conditions and world oil and gas prices. In 2007, 1,000,000 total oil and gas wells were active in the U.S. including traditional wells and hydraulically fractured and non-fractured wells.
The principal environmental concerns associated with hydraulic fracturing projects are water and soil contamination that can result from the processes and handling of the fluids as well as the large quantities of water necessary to undertake fracking and seismic activity that might be induced. Large volumes of water are withdrawn from surface or groundwaters and mixed with sand and chemical additives including biocides, hydrochloric acid, corrosion inhibitors, borate salts, friction reducers, gelling agents, potassium chloride, oxygen scavengers, scale inhibitors and surfactants.
Hundreds of thousands of gallons of water may be injected and withdrawn per site, and great volumes of flowback and produced waters are generated. Flowback waters are those that return to the surface after the pressure is released. They consist of hydrolytic fracturing fluids, water from the natural formation, chemical additives that were injected and the recovered hydrocarbons from the deep formations.
Apart from the chemical additives to be managed, the natural water that is surfaced may contain very high levels of dissolved solids (salts), toxic metals, radionuclides and hydrocarbons. Total dissolved solids (TDS) values may range from less than 1,000 milligrams per liter (mg/L) to hundreds of thousands of mg/L (sea water typically contains about 35,000 to 40,000 mg/L ). In addition to the predominant sodium and chloride, the salts content can include elevated concentrations of bromide, bicarbonate, sulfate, calcium, magnesium, barium, strontium, radium, organic chemicals and heavy metals. The management challenge is to safely dispose, treat, or reuse those waters without damaging the local groundwater or downstream surface waters and potential drinking water sources.
Wastewater management & treatment
The wastewater management procedures utilized are consistent with the contaminants to be managed as well as the economics of the options available by regulations and guidelines that apply at the project site. Among the possible approaches are disposal by deep-well injection, treatment on site, several reuse possibilities, including as an injection fluid, and transport to a centralized wastewater treatment facility (CWTF) or a publicly owned treatment works (POTW).
Disposal of treatment concentrates creates another management issue. There are applicable controlling national regulations under the Clean Water Act and Underground Injection Control provisions under the Safe Drinking Water Act, but states are actually even more active in determining the acceptable environmental protection requirements and options.
When possible, underground injection is the primary method for management and disposal of wastewaters from oil and gas producing facilities. These are regulated by the Underground Injection Control provisions of the 1974 Safe Drinking Water Act and implemented by states along with their additional provisions. Enhanced oil recovery, disposal and hydrocarbon storage are covered in the Class II well designations. Class II fluids are primarily brines (salt water) that are generated while producing oil and gas.
Deep underground injection of brines in formations isolated from underground sources of drinking water prevents soil and ground and surface water contamination. These are usually the formations in which the brines originated or similar formations. Deep-well injection is usually the least expensive management strategy unless trucking is needed to transport the brine to a disposal well. Over 2 billion gallons of brine are injected underground in the United States every day, mostly in Texas, California, Oklahoma and Kansas. About 27,000 Class IID disposal wells are in use exclusively to inject fluids from oil and gas production. Because of the geology and other restrictions, relatively few Class IID wells are operative in the Marcellus Shale areas of the northeastern U.S..
More than 98008 percent of an estimated 882 billion gallons of produced water from oil and gas extraction facilities in 2007 was managed by some form of underground injection with 40 percent in Class II wells. Average disposal rates per well are somewhat regionally diverse and range from about 1,750 gallons per day per well (GPD/well) in Illinois, to over 50,000 GPD/well in Texas and Colorado, to 182,000 GPD/well in the North Slope basin in Arkansas. There have been indications of seismic activity, in Oklahoma, for example, which could result in greater restrictions on underground injection.
Reuse of wastewater brines in the hydraulic fracturing process would be an ideal practice, and it is increasing, especially in the Marcellus Shale region, because no or minimal treatment might be necessary, and the amounts of fresh water needed are reduced as well as less total wastewater to be treated and disposed of at the surface. However, repeated use may accumulate the contaminants to ultimately be managed either by treatment, injection or disposal.
Other kinds of reuse that are allowed in some jurisdictions depend upon the composition and concentrations of the brines and state regulations and may or may not require some level of pretreatment depending upon the intended end use. These can include land application, road spreading for dust control and de-icing, livestock watering, irrigation, and even stream flow augmentation, fire protection, and industrial uses.
Total dissolved solids, inorganics & radionuclides
High concentrations of TDS in brines will require some level of treatment if disposal will be above ground or by transport to a treatment facility. Treatment processes used by POTWs and centralized wastewater treatment facilities are not generally amenable to significant removals of salts. High-strength wastes will disrupt biological processes in POTWs. Those options are in decline because of the expense of transport and the frequent need for some kind of pretreatment before the wastewater is acceptable to the treatment works — so it will not disrupt its system performance and so the facility will be able to meet its own NPDES permit discharge requirements.
Standard processes include:
- Media filtration
- Separation of oil and grease
- Biological and aerated filters
Membrane processes may include:
- Microfiltration, ultrafiltration, nanofiltration and reverse osmosis
- Distillation (e.g., vapor compression)
- Evaporation ponds
- Chemical precipitation
- Evaporation ponds
- Anion and cation exchange processes
- Electrocoagulation (emerging process)
Some types of contaminants create unique problems. Radionuclides, such as radium, are common in deep groundwaters in some regions. When surfaced in flowback and produced waters their presence restricts opportunities for discharges to treatment plants and surface waters and some of the potential end uses.
Radium is removable by cation exchange, RO membranes and co-precipitation with barium. However, the concentrates then create another disposal problem and might require disposal in radioactive waste landfills.
Bromide is a common anion, but it is usually not present in significant amounts in surface waters. It is not easily removed by technologies other than RO membranes. When the concentration in surface streams is increased by conventionally treated brine discharges, the concentrations of brominated disinfection by-products will be increased in downstream drinking waters that chlorinate. Chlorine oxidizes bromide to brominating species that react with natural organic chemicals also present in the water. There are some concerns that brominated organics may be the more hazardous fractions of the disinfection by-products in drinking water.
Organic chemicals in fracking wastewater can include: light petroleum hydrocarbons, diesel range organics, oil and grease, volatile organics like benzene and toluene, and semivolatile organics as well as chemical additives that are formulated in the hydraulic fracturing injection fluids. Treatment processes are available to manage those chemicals including: adsorption, biological treatment, conventional coagulation, flocculation, flotation, skimming and several others depending upon the specific chemical types and their physical and chemical properties.
As stated, residuals management is an important factor in fracking wastewater management. Some residuals are concentrated toxins like radionuclides, and some are regulated inorganic species or just highly saline brines that require additional reuse or disposal limitations.
Hydraulic fracturing wastewaters are complex saline and organic chemical mixtures, and they create treatment and disposal challenges that can, however, be met when economics permit. This very brief summary is derived extensively from the USEPA’s 600-page draft report along with hundreds of pages of Appendices of the Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources (External Review Draft, EPA/600/R-15/047, June 2015) from the process that was initiated in 2009.
The draft report generally concluded that it did not find evidence of “widespread systemic impacts on drinking water resources in the United States.” The longstanding federal and state control requirements, as well as increased sensitivity by drillers, are principal reasons why that statement can be made.
EPA’s Science Advisory Board (SAB) produced a 160-page review that was partly in disagreement and particularly asked for more analyses and quantitative support for the draft report’s conclusions, including more discussion of local impacts, carrying out of prospective case studies, probabilities and risks of failure scenarios, chemical and toxicity and hazards, more characteristics of fracking fluid composition, and several other assessments. Some members filed dissenting opinions that disagreed with the SAB’s majority recommendations.
The government’s issue is whether to produce additional regulations. The SAB review encouraged anti-fracking organizations and certainly will extend the time frame for reaching some kind of technical and political conclusion on the issue, if it ever occurs. In the meantime, it will always be necessary to manage and treat the wastewaters generated from the fracking and other drilling processes and to try to minimize the quantities of good surface and groundwaters that are injected.
Dr. Joe Cotruvo is president of Joseph Cotruvo and Associates LLC, water, environment and public health consultants and technical editor of Water Technology. He is a former director of