“We forget that the water cycle and the life cycle are one” – Jacques Cousteau
The first week of classes in August 2011 nearly knocked some of us off our feet literally. A 5.8 magnitude earthquake centered in Virginia could be felt by 1/3 of the US population and nearly everyone on the WVU campus except for myself. While I could not join in the storytelling fun of what it did to my computer screen, or what fell from my office wall; I could at least join in the speculation that followed. It was not uncommon to feel reverberations of a mine blast every once in a while, but this was different. Just like the case in my last post, everyone immediately suspected the natural gas industry. Was it a well explosion or a wastewater injection triggered earthquake?
In the end there was no evidence to support a link between the earthquake and the natural gas industry. This, however, was not the case in other states where hydraulic fracturing and deep well injection was practiced. In fact, scientists have known for years that wastewater injection can trigger tremors, with nearly 180 throughout Texas from 2008 – 2009 and 167 in Ohio from 2011 -2012. While there were nearly 200 injections wells in Ohio at the time, the quakes were tied to only one, Northstar 1. By the time the well closed, an average of 12 earthquakes had occurred each month and 495,622 barrels of wastewater was injected more than 9000 feet into the ground.
Industries have used geologic depths as a toxic dumping ground for years. They have injected more than 30 trillion gallons of toxic liquid over decades, with the assumption that the earth would “safely entomb the waste for millennia”. However, there have been injection accidents dating back to the 1960’s where toxic chemicals bubbled to the surface, leaked into aquifers and spilled during transport. However, risks are considered minimal and accidents rare. While there are treatment and reuse options for flowback and produced water, deep well injection is the least expensive and most expedient way to manage waste. One of the reasons for this is that the injection process for the oil and gas industry is exempt from many of the testing and inspections of hazardous waste.
Before I present the hazardous waste loophole afforded to the industry, let’s revisit the wastewater compounds in question and break it down in a little more detail. Wastewater from the hydraulic fracturing process consists of flowback water, the hydraulic fracturing solution that flows back to the surface after the fracture and produced water, which is naturally occurring water found in the geologic formation that flows to the surface throughout the well production. Flowback water consists of primarily water and sand with small amounts of chemical additives highlighted in the graphic below.
This water is easier and more economically affordable to treat for reuse in future fracturing operations. The produced water, is considered far more toxic, leaching out barium, calcium, iron and magnesium from the shale formation as well as hydrocarbons (sometimes referred to as salts) such as benzene, toluene, ethylbenzene and xylene (BTEX) and naturally occurring radioactive materials. Due to the toxicity of the water it is typically injected deep into the ground rather than treated.
Following the Safe Drinking Water Act in 1974, injection wells were subject to tough regulations and considered dangerous to drinking water. The EPA separated hazardous waste injection wells into two categories, Class 1 for chemical, pharmaceutical and industrial wastes and Class 2 for oil and gas. For many years in order to inject waste into a well, companies were required to complete geological modeling to ensure that the geology would prevent waste from escaping through fissures or fault lines. The regulation also mandated periodic well inspections to ensure they were not a conduit for contamination. Further regulations in the 80’s banned the injection of hazardous waste unless companies could prove that the chemicals posed no threat to human health and that their waste would not migrate underground for at least 10,000 years. The energy industry argued that this process would be “crippling to US oil and gas production” and that industry wastewater was mostly harmless brine.
In 1988, the EPA granted a landmark exemption to the oil and gas industry redefining a substance from drilling as “non-hazardous”. Nearly 70% of the waste injected into class 2 wells would be considered toxic if it were not for the loophole. The regulation essentially meant that benzene from the fertilizer industry was toxic, but benzene from the oil gas industry was not. Once the waste was defined as non-hazardous, the regulations for class 2 well injection began to unravel. Pressure testing, yearly well inspections, and seismic and geologic modeling were no longer required and the radius inspection for retired well migration potential was reduced from two miles to 400-feet. While the permitting process for a class 1 well inspection typically takes nearly a year, a class 2 permit can be obtained in as little as one day.
New regulations and the natural gas boom has led to a flurry of injection well permits. In 2011 North Dakota saw permit applications for well injection increase tenfold. This rise in well permits has had a significant impact on the quality of inspections. The following graphic highlights the number of injection wells per state and the link provides further data about contamination cases and violations.
Most states are significantly understaffed, which means that many wells remain uninspected for several years rather than the yearly goal. ProRepublica surveyed 220,000 wells in 2007 – 2010. They found 24,000 violations and 1400 cases of injections without a permit. Only one case was prosecuted and fines were minimal, with states such as Louisiana charging only $158 for a violation. Essentially, this makes it cheaper to pay fines rather than responsibly disposing of wastewater. According to a former EPA criminal investigator in Texas, “most of our environmental law requires self-reporting and requires honest people.”
Ultimately, the rise of injection well permitting has not kept pace with drilling permits. Many injection wells are reaching their capacity, which is typically achieved anywhere from 10 – 20 years. When this happens, companies are turned away and are forced to shut down operations until new injection sites are permitted. This scenario actually yields positive environmental benefits as companies are adopting treatment processes to reuse both flowback and produced water in future fracturing operations, significantly reducing the quantity of wastewater to deep well inject.
In order to reduce their reliance on outside deep well injection sites, many companies have started to inject their waste on the same site they are extracting gas from. While this significantly reduces truck traffic and risks of spills during transport there is risk associated with this process. Last week I visited an Anadarko site in Weld County. They currently had twelve operating wells, flowback water recycling, produced water storage and one injection well on site. They were injecting wastewater at 9,000 ft below the ground, with wells extending 10,000 ft. While this may carry a significant risk of waste migration, there are currently no rules that prohibit it or require larger setbacks. In fact, some oil and gas companies and regulators do not believe there is a problem if migration were to occur, because much of the drilling related waste is put into the same geologic formation in which the contaminants naturally occur. They argue that often water close to the natural gas wells is already undrinkable and therefore less protection should be required.
Extending beyond what is deemed hazardous and non-hazardous, federal official and many geologists maintain that deep well injection pose little risk to our drinking water supply. In a statement from the EPA “underground injection has been and continues to be a viable technique for subsurface storage and disposal of fluids when properly done.” However, many other experts argue that safe injection rests on science that has not kept pace with reality. According to a former engineer with the EPA injection program, the natural gas boom has brought a significant increase in punctured substrate, ultimately “changing the earth’s geology, adding man-made fractures that allow water and waste to flow more freely”.
So what did I learn from this investigation? While the arguments about whether the process is safe play out, everyone at least agrees that if done improperly there is potential for groundwater contamination, yet we have limited regulation in place to mitigate this. Essentially, not only is the natural gas boom outpacing science, but legislation and regulation is allowing the gap to grow. Continuing to claim that there is little risk, simply because of its past history is not grounded in present day realities or science as we have changed the system with increased practice. We need to be forward thinking and adaptive in order to find a balance between the health and safety of people, environmental protection and energy production. Might it be time to slow down, because in the end is it safe to fail?
Next week I will explore the risks and benefits of wastewater treatment as an alternative to deep well injection.