Earthquakes and Water- the Earth’s Plumbing System

In the throes of the worst California drought in recent history rivers and streams across California had been flowing at record low level and some streams were completely dry. Then late August a magnitude 6.0 earthquakes hit the South Napa Valley and a funny thing happened; water began to flow again in some previously dry creaks, rivers and streams. For decades scientists have noted that there is a hydrogeologic response to earthquakes, but understanding of this response is still very limited. In the case of the South Napa Earthquake the flow of springs and groundwater to some streams appears to has increased. Scientists at the U.S. Geological Survey (USGS) predict that based on the experience in previous earthquakes the stream and sprig flows will decline again over the next several months if the rains do not return to California.

from USGS

Hydro-geologic responses to earthquakes have been observed to occur both in the area of the earthquake and thousands of miles from the earthquake epicenter. Earthquakes impact groundwater the most commonly observed impact is to water wells. Some well have been observed to become turbid or muddy, some have run dry or had an increase in flow or water level. New springs have formed and the quality of groundwater and surface water has changed. Some of these changes are transitory others appear to be permanent and only time can tell the difference between them. In addition, there have also been surface water responses to earthquakes. Surface-water responses to earthquakes include changes in chemistry, wave oscillations in lakes, increases and sometime decreases in stream, spring, and seep discharge, instances of springs going dry or the appearance of new springs.

According to the USGS the water-level fluctuates in wells in response to seismic waves. The occurrence and size of the water level response of water wells to earthquakes are influenced by a variety of factors such as the magnitude and depth of the earthquake, the distance of the well from the epicenter, the geology surrounding the well, the depth of the well, whether the aquifer is confined or unconfined and the well construction. The most common observed groundwater response to an earthquake is an instantaneous water level offset or step up. An instantaneous increase or decrease in water level. This response is commonly observed because there are hundreds of wells used to monitory water levels nationally. The change and recovery in water level can be so rapid that it is barely detectable, or it may take minutes, hours, days, or months for a well to return to previous water levels. There have also been instances where the well never returned to pre-earthquake levels.

Lots of things can impact the response of a well to a seismic event and scientists cannot predict which wells will be impacted and whether the impact is permanent or transitory. The USGS reports that within 3 months of the 1998 magnitude 5.2 earthquake in northwestern Pennsylvania that over a hundred private water wells in the area went permanently dry. The 2002 Alaskan Denali Fault earthquake which was a magnitude 7.9 caused a 2-foot water-level rise in a well in Wisconsin, more than a thousand miles from the epicenter. That rise also appears to be permanent.

From USGS

What is clear is that groundwater aquifers systems are mechanically connected to the rocks and sediments in which they exist. In addition to hydrogeologic responses to earthquakes, hydrogeologic changes may cause earthquakes or volcanic events. Earthquakes can be induced by the filling of surface reservoirs, or by annual or shorter-term fluctuations in reservoir levels. In addition, earthquakes can be induced by the deep well injection (or withdrawal) of fluids as has been seen in the disposals in the 1960’s at the Rocky Mountain Arsenal and more recently in disposal of the waste fracking fluid from hydraulic fracking.

The USGS says that water level offsets in the area of an earthquake because the earthquake “subjects the earth’s crust and its aquifer systems, to stress and permanent strain (deformation). This deformation process results in altered fluid pressure within the aquifer systems, and consequently, a step like change in water level would be expected.” The USGS cites various mechanisms for well water responses based on type of geology. For increased water level in shallow wells, the USGS suggests that compaction of overlying alluvium similar to liquefaction may be the mechanism producing the offset. Fluid-pressure declines are suggested to be caused by the escape of small amounts of dissolved gas from pore spaces in the aquifer in response to seismic waves. In a fractured rock system like the one here and in northwestern Pennsylvania where the wells went dry, permeability of the ground may be changed by the unclogging, widening, or narrowing of fractures, or the creation of new fractures. Similarly, an increase in ground-water discharge though springs, seeps, or to streams could be caused by an increase in the subsurface fluid pressure or permeability of the geologic formation.

There have also been several instances of reported changes in water levels in well before an earthquake. Many of these documented cases come from seismically active Japan where they continue to search for predictors of earthquakes. Many scientists do not believe that groundwater and well response can be used to predict earthquakes; they believe that there are too many other explanations for well water changes. Truthfully in the last couple of years (in my volunteer work with the VAMWON) I’ve seen several instance of what I think of as transitory benign well response where a well level falls dramatically and then recovers seemingly unconnected to precipitation and use. I have also seen transitory turbidity that just seems to pass through and then the well returns to normal. There are many potential explanations for these observations, so I simply note them and test the water quality when it returns to normal to make sure it is safe to drink.

However these episodes make you think about how interconnected the groundwater system is to the earth. Recently Dr. Robert Jackson et al. published an analysis of all the peer reviewed research done on hydraulic fracking. Though there has been documented impact to groundwater from improperly constructed wells, there has been no confirmed impact to groundwater from fracking itself. Rather than testing for direct chemical contamination in areas surrounding a hydraulic fracking maybe scientist should be looking for changes in water quality and quantity in nearby groundwater wells and systems that are more typical in seismic events.


For more information on stream flow and water well responses to earthquakes and discussion of potential mechanisms see research from Department of Earth and Planetary Science, University of California, at Berkeley by Chi-Yuen Wang, Michael Manga and others.

Carbon Capture- Will It Save Us?

Last week a three-judge panel of the U.S. Court of Appeals in Washington ruled that the U.S. Environmental Protection Agency, EPA, had “substantial record evidence” that greenhouse gases probably caused the climate to warm over the past several decades, the EPA had concluded that greenhouse gases are pollutants that endanger human health in 2009.  Opponents to that determination had essentially asked the Court to re-weigh the scientific evidence before EPA and reach their own conclusion. However, the three judge panel wrote in the opinion for the case that. “(t)his is not our role.”

 Back in  December 2009,  the EPA officially found that greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations the agency,  and started on the path to regulate carbon dioxide, CO2, after the  "American Clean Energy and Security Act”, also known as the Waxman-Markley energy bill was defeated in the Senate. After collecting CO2 emission data from industry the EPA “found” in 2012 that the largest carbon dioxide generators are the largest stationary combustion sources. It was no surprise that the largest (coal) electrical generation and industrial plants in the nation- big furnaces generate more CO2. For the past decade electrical generation has accounted for approximately 40% of the carbon dioxide emissions in the United States and worldwide. At the end of March 2012, the EPA proposed the first Clean Air Act standard for CO2 rule targeted at power plants.  The agency plans to phase in industrial facilities covered by the carbon rules through 2016. Under the new rule, new power plants will have to emit no more than 1,000 tons of CO2 per megawatt-hour of energy produced. That standard effectively changes the fuel of choice for all future power capacity additions to natural gas, nuclear, or the renewable category (with government subsidies). All existing plants and currently permitted and built in the next 12 months will be grandfathered and exempt from this new rule for now.

Coal electrical generation plants currently produce about 1,800 pounds of carbon dioxide per megawatt-hour of electricity. EPA says the CO2 rule that requires new plants to produce no more than 1,000 pounds of CO2 per megawatt-hour as creating “a path forward for new technologies to be deployed at future facilities that will allow companies to burn coal, while emitting less carbon pollution.” The EPA in their new regulations and Department of Energy, DOE, in their research grants are pushing forward on the development of Carbon Capture. In June the International Energy Agency, IEA, released its preliminary 2011 estimates of world CO2 emissions from fossil fuel combustion. World CO2 emissions rose by 1 billion metric tons, a 3.2 % increase over last year to reach 31.6 billion metric tons. The worldwide level of CO2 is now higher than the worst-case scenario outlined by climate experts just five years ago and within 1 billion metric tons of the IEA point of no return. (That is the point where mankind cannot hold global warming at 2 degrees Celsius.)

 

 In 2011 the top four world generators of CO2 emission from fossil fuels were (from highest to lowest) China, the United States, the European Union and India who edged out Russia to take the number four slot. China increased emissions contributed almost three quarters of the global increase, with its emissions rising by 720 million metric tons, or 9.3% to 8.46 billion metric tons of CO2, primarily due to higher coal consumption. India’s emissions rose by 140 million metric tons or 8.7% to 1.75 billion metric tons. Since 2000, China has more than tripled its installed capacity of coal power plants, while India’s capacity has increased by 50%. Neither country has used the most efficient designs and technologies available for those plants and those plants will continue to operate 24/7 for decades to come.

CO2 emissions in the United States, in contrast, fell by 92 million metric tons in 2011, or 1.7% to an estimated 5.32 billion metric tons. The European Union increased their CO2 emissions from fossil fuel by 69 million metric tons to approximately 3.56 billion metric tons. Japan’s CO2 emissions increased by 28 million metric tons, or 2.4% to approximately 1.19 billion metric tons, as a result of a substantial increase in the use of fossil fuels in power generation post-Fukushima tsunami. Russia and Canada reportedly remained fairly stable from the previous year. Nonetheless, the IEA still believes that it is still possible to prevent the earth’s temperature from rising more than 2 degrees Celsius if “timely and significant government policy action is taken, and a range of clean energy technologies are developed and deployed globally.” One of the key technologies according to the IEA is carbon capture.

In 2009 DOE supported eleven projects to conduct site characterization of geological formations for CO2 storage. Carbon capture is really three activities: Gathering or capturing of CO2 from point sources (power plants, industrial plants, and refineries), transporting the captured CO2 to a geological storage site, and injecting the CO2 into the ground for permanent storage and monitoring the site for eternity. Capturing and transporting CO2 from industrial plants is technologically possible but is currently prohibitively expensive, though DOE’s National Energy Technology Laboratory and several universities are exploring ways to bring down the costs or raise the costs of other energy sources.  A significant portion of the CO2 generated in the United States and the world is not generated from large stationary point sources, but from cars, homes, and smaller sites. Only about a quarter of the CO2 generated from fossil fuel combustion annually is generated at large point sources the only possible capture points. Storing even a portion of this amount of CO2 would require capturing the gas at many locations around the country and transporting it to facilities that could inject the CO2 into appropriate subsurface rock formations. According to the researchers efficient underground storage of CO2 requires that it be in the supercritical (liquid) phase to minimize required storage volume.

In order for CO2 to remain in a supercritical phase, the pressure in the storage reservoir must be greater than about 68 atmospheres and at temperatures above 31.1°C. (Sminchak et al., 2001). These conditions require that the CO2 be injected at high pressures, which can only be achieved at depths greater than about 2,600 feet below the earth’s surface. The supercritical CO2 will be injected into the geologic formations that are overlain by appropriate sealing formations and geologic traps that will prevent the CO2 from escaping as the CO2 injection well remains in continuous operation for years or decades. The volumes of supercritical CO2 envisioned for carbon capture are huge. A recent U.S. National Research Council report suggests that carbon capture and deep earth sequestering could potentially induce earthquakes because significant volumes of fluids are injected underground over long periods of time. However, insufficient data exists at this time to evaluate this risk. An IPCC Special Report on CO2 capture and storage suggests that between 73 and 183 million metric tons of CO2 could be captured and stored worldwide from both coal and natural gas energy plants each year (Metz, 2005).  The IPCC envision that carbon capture and well injection would take place at a number of locations, ideally places near to power plants that produce CO2 to avoid long transportation distances under pressure.

American Electric Power, AEP, participated in three DOE funded projects to advance CCS technologies. All were conducted at the Mountaineer Plant in New Haven, West Virginia (from which some of my power is supplied within the PMJ Interconnection). AEP planned to replace its pilot demonstration CO2 capture plant with a larger $668 million Carbon Capture and Storage facility, which would have buried more than 1 million metric tons of CO₂ a year, splitting construction costs evenly with the DOE, but failed to obtain the consumer rate increases necessary to fund the experiment. The project has been discontinued. In 2010 there were almost 1,400 coal fired electrical generating units in the United States if each were to be converted to carbon capture operation the total cost would be almost a trillion dollars in construction costs (assuming no cost over runs) and capture 1.4 billion metric tons of CO2 per year. This would represent 26% of the net annual CO2 emissions of the United States and increase average electrical rates 25% nationally for just building the units. Electrical rates would have to increase more if there were any annual operating costs of the Carbon Capture unit. Actual rate increases would be regional.  

The AEP projects were demonstrations of Alstom’s Chilled Ammonia Process for Post-Combustion CO2 Capture. The process uses ammonium carbonate to absorb CO2 and create ammonium bicarbonate. This resulting ammonium bicarbonate is converted back to ammonium carbonate in a regenerator and is reused to repeat the process. The flue gas, cleaned of CO2, but with the tell-tale smell of the ammonia reaction, flows back to the stack and the captured CO2 is sent for storage. Once captured, the CO2 is compressed into a liquid state and is injected 1.5 miles beneath the earth’s surface. Several major pilot projects, in Europe have also been cancelled in the last few years because of doubts over their financial and technical viability. Some are still under consideration for EU and government funding, but the need to rescue the Euro and European Banks has taken the financial resources of the European Union. Ayrshire Power in Scotland, blamed their cancelled plans for a new carbon-capture power station at Hunterston on the recession and anxieties about winning funding from the government and the same reasons were given for the cancellation of the Longannet power station in Fife.

 Globally, only a few, small-scale commercial carbon capture projects are in operation. The oil and gas fields in the North Sea are the site of the world’s first offshore commercial CO2 capture and storage project. Carbon dioxide is captured at a plant located on the offshore natural gas platforms and is stored underground in a sandstone well approximately 2,600 feet below the sea bed. The CO2 tax levied on offshore oil and gas operations by the Norwegian government made the project worthwhile and the drilling rig and available aquifer made it possible. CO2 is removed from the natural gas produced at the Sleipner field in the North Sea and re-injected it into a very porous, permeable sandstone and saline aquifer above the oil and gas reserves. Approximately 1 million metric tons of CO2 have been stored each year since 2000 when the system went into operation. This is just a small fraction of the 31.5 billion metric tons of CO2 released into the atmosphere each year.  It appears as if the United States has passed the point of peak CO2, but the atmosphere of the earth is interconnected and China and India appear to be increasing their CO2 emissions by 860 million metric tons a year. It matters what kind and how efficient a power plant is installed in China or India since they will be sending particulates and CO2 into the atmosphere for decades. Nonetheless, we have no control over the growth in India and China’s coal fired power supply, nor in the abandonment of nuclear power by Germany, Belgium, Switzerland and Japan in the next decade in response to the damage to the nuclear reactors that occurred in the Japanese Fukushima tsunami. 

Hydraulic Fracking Poses Almost No Risk for Causing Earthquakes

The latest word from the NationalResearch Council is hydraulic fracking whether in shale deposits or as a secondary stimulation for a traditional gas or oil well has very low risk for inducing earthquakes that can be felt by people, but underground injection of wastewater produced by hydraulic fracturing and geothermal wells have a somewhat higher risk of causing earthquakes.  Although the vast majority of earthquakes that occur in the world each year have natural causes, earthquakes can be created by mankind.  Induced earthquakes have been documented since at least the 1920s when the first man-made large reservoirs were created behind dams. Other activities that can create (and have created) earthquakes are; controlled explosions used in mining or construction, underground nuclear tests, and energy technologies that involve injection or withdrawal of fluids from the subsurface can also create earthquakes. Man-made earthquakes are caused by changes in pore pressure within the rock due to the impounding of billions of gallons of water or injecting or extracting fluid from a well that may change the stress acting on a nearby fault. This change in stress may result in slip or movement along that fault creating a seismic event.

Historically man-made earthquakes have not been very large nor have they resulted in significant structural damage, but our ability to cause seismic events has increased over time as our technology to drill, pump and explode has advanced. To quantify the hazard and risk from man-made earthquakes requires probability assessments, which may either be statistical (based on data) or analytical (based on scientific and engineering models). Although the general mechanisms that create induced seismic events are well understood, current computer modeling techniques cannot fully address the complexities of natural rock systems in large part because the models generally lack information on local crustal stress, rock properties, fault locations and properties, and the shape and size of the reservoir into which fluids are injected or withdrawn. Geology cannot be simplified or generalized to model earthquake probability which is very specific.

So the National Research Council Board of Life and Earth Studies report titled: Induced Seismicity Potential in Energy Technologies is a data based analysis of earthquakes induced by mankind. This study compiling and analyzing all the data available was requested by the Energy and Natural Resources Committee of the U.S. Senate to assess the potential to cause earthquakes by energy production and related activities after small seismic events reported in Alabama, Arkansas, California, Colorado, Illinois, Louisiana, Mississippi, Nebraska, Nevada, New Mexico, Ohio, Oklahoma and Texas, appeared to be related to hydraulic fracturing, energy development and (true) geothermal energy production. The National Research Council is a nonprofit based in Washington that provides scientific information for government decision-makers under the auspices of the National Academy of Sciences, the National Academy of Engineering and the Institute of Medicine. Its reports are based on data and analysis gathering and scientific analysis of the information gathered.

The report examines the potential for energy technologies -- including shale gas recovery using fracking, carbon capture and storage, geothermal energy production, and conventional oil and gas development -- to cause earthquakes. Hydraulic fracturing, commonly known as fracking, extracts natural gas by injecting huge volume of water mixed with sand, and chemicals in short bursts at very high pressure into deep underground wells. The process cracks the shale rock formation and allows natural gas to escape and flow up the well, along with some wastewater. The wastewater can be discarded in several ways, including injection of the wastewater at a separate disposal well. True geothermal energy harnesses natural heat from within the Earth by capturing steam or hot water from underground. The basic mechanisms that can induce earthquakes from these wells are fluid injection and extraction that are presently well understood. The report examined the data from over 35,000 fractured wells, 108,000 secondary oil and gas recovery wells, 13,000 tertiary oil and gas recovery wells, 6,000 hydrocarbon withdrawal wells, 30,000 waste water disposal wells, 23 liquid dominated geothermal well fields and 1 vapor dominated geothermal field.

Analysis of the data collected at all these sites showed that the net fluid balance (total balance of fluid injected and withdrawn) appears to have the most direct impact on changing pore pressure within the ground. Oil, gas and geothermal wells are typically designed to maintain a balance between the amount of fluid being injected and the amount of fluid being withdrawn to prevent not only earthquakes, but to maximize the well life.  Geothermal wells appeared most likely to induce earthquakes especially the wells in the vapor dominated Geysers site which had 300-400 earthquakes per year (it is in California). In fluid geothermal wells maintaining a constant fluid balance results in a fairly constant reservoir pressure, reducing the number of induced earthquakes significantly. The 23 fluid dominated geothermal well locations experienced 10-40 earthquakes per year.

Only a very small fraction of the hundreds of thousands of oil and gas wells in the United States have induced earthquakes at levels that are noticeable to the public. An increase of  rock pore pressure above ambient levels due to injection of fluids or a decrease in pore pressure below ambient levels due to extraction of oil and gas have the potential to produce earthquakes. However, analysis of the data showed that to create an earthquake, a combination of conditions has to exist simultaneously:

    A. Significant change in net pore pressure in a reservoir,

    B. A pre-existing near-critical state of stress along a fracture or fault, and

    C. Fault rock susceptible to brittle failure.

Oil and gas wells are designed to maintain a balance between the amount of fluid being injected and the amount of fluid being withdrawn to extend the life of the well. This fluid balance helps to maintain fairly constant reservoir pressure and reduces the potential for induced earthquakes. In a conventional oil or gas reservoir the hydrocarbon fluids and associated aqueous fluids in the pore spaces of the rock are usually under significant natural pressure. Fluids in the oil or gas reservoir flow to the surface when penetrated by a well bore aided by pumping once the well is fully developed. The well or wells will produce until reservoirs reach a point when insufficient pressure, even with pumping, exists to allow the wells to continue to produce at commercial volume. To extend the life of a spent well various secondary and tertiary recovery technologies referred to as enhanced oil recovery technologies can be used to extract some of the remaining oil and gas. Secondary recovery and enhanced oil recovery technologies both involve injection of fluids into the subsurface to push more of the trapped hydrocarbons out of the pore spaces in the reservoir and to maintain reservoir pore pressure. Secondary recovery often uses water injection or “water flooding” and tertiary technologies often inject carbon dioxide (CO2). Of the 108,000 oil and gas wells that used water flooding only 18 have had one or more earthquakes. Of the 13,000 CO2 injected sites none have experienced earthquakes.

Shale formations can also contain hydrocarbons either gas or oil or both depending on the formation. The extremely low permeability of these rocks has trapped the hydrocarbons as they developed in the rock and largely prevented them from migrating out of the rock over geologic time. These unconventional gas and oil reservoirs are developed by drilling wells horizontally through the rock and using hydraulic fracturing techniques to create new fractures in the reservoir to allow the hydrocarbons to migrate up the well bore. The water used to fracture the well is quickly released from the reservoir and does not impact the fluid balance. About 35,000 hydraulically fractured shale gas wells exist in the United States; only one instance of an induced earthquake has been identified in which fracking to access the shale gas is suspected, but not confirmed, as the cause.

Overall, hydraulic fracturing or fracking and traditional oil and gas well have a very low risk of creating earthquakes. The waste water disposal wells associated with fracking and secondary well development have been associated with 8 known earthquakes, though there are a total of about 30,000 disposal wells in use, but these earthquakes have captured the headlines and public concern. Wells used only for the purpose of waste water disposal normally do not have a detailed geologic review performed prior to injection and the data are often not available to make a detailed review of these sites possible.  The overall risk turns out to be small, but limited knowledge about the geology prevents modeling. Attempts at modeling of pore pressure, temperature, and rock stress changes induced by injection and extraction to predict producing earthquakes have not been successful except where detailed knowledge of stress changes, pore-pressure changes, and fault characteristics are available for input and that data is almost always not available for disposal wells. The permanent addition of fluid to the subsurface without any fluid removal and the heat gradient associated with geothermal appears to have the most direct impact on changing pore pressure in the subsurface over time and the creation of earthquakes.

Ohio Fracking and Earthquakes

A series of eleven small earthquakes ranging in magnitude from 2.1 and 4.0 have taken place beneath Youngstown Ohio since March 2010. Each earthquake is reported to have had their epicenters near the Ohio Works Drive injection well used by D&L Energy Inc. to dispose of waste water from nearby hydro fracking jobs. D&L began injecting the waste water from the fracking jobs, referred to as brine, into its Ohio Works well in December 2010.

The earthquakes early in the spring led the Ohio Department of Natural Resources, ODNR, to have Columbia University Lamont-Doherty Earth Observatory install seismic monitoring equipment in the area to determine whether there was any relationship between fracking or water disposal activity and the earthquakes. A report is expected in the near future, but after the earthquakes, on December 30th and 31st, use of the disposal well has been halted. ODNR has halted deep well disposal of fracking waste water in the D&L Ohio Works Drive injection well and four other injection wells in the Youngstown area pending analysis of the data collected by the Lamont-Doherty scientists.

In hydraulic fracking on average 2.8 million gallons of chemicals and water is pumped into the shale formation at 9,000 pounds per square inch and literally cracks the shale or breaks open existing cracks and allows the trapped natural gas to flow. While geologists and engineers believe that there is little risk that the fracking “water,” a mix chemicals and water, will somehow infiltrate through the shale and the thousands of feet to reach the groundwater reserves though a fissure created by the fracking, there are other routes of contamination and impact. An now concern is focused in Ohio on the disposal of the flowback water that is not absorbed into the rock formations.

The water that is absorbed into the rock formations may change the formations in ways we do not yet understand, it is the disposal of the flowback that is the focus of this investigation. Though the water in the hydro frack is exempted from the clean water act (by a 2005 act of congress), the flowback which contains “proprietary” chemicals and contaminates from the geological formation is not and must be disposed under state regulations. This is not the first study of earthquakes associated with the disposal of fracking water.

Researchers of the University of Texas at Austin were part of a team of researchers who studied a series of small earthquakes that struck near Dallas, Texas in 2008 and 2009, in an area where natural gas companies had used fracking. The epicenter of the quakes turned out to be about half a mile from a deep injection disposal well under the Dallas-Fort Worth International Airport used to dispose of the fracking fluid. The largest earthquake of the series measured 3.3 on the Richter scale, a very small earthquake. In a study that was published in the Bulletin of the Seismological Society of America, the researchers also reviewed records from US Geological Survey seismic-recording stations in Oklahoma and Dallas. It was concluded by the researchers that the fracking did not cause the earthquakes, but there seemed to be a relationship to the deep well injection of the fracking fluid to the earthquakes.

Columbia's Lamont-Doherty Earth Observatory scientists have the advantage of having placed seismic monitoring equipment in the area before the last few quakes which included the strongest of the series at 4.0 on the Richter scale on New Year’s Eve. The location of the earthquake epicenter is expected to be in the area of the Ohio Works Drive injection well an area of no previous seismic activity. It has been speculated that the earthquakes were triggered by the fluid injected into the well that permeated a previously unknown fault.

Our ability to recover natural gas buried a mile or more beneath the earth has increased. Advances in horizontal drilling which allows a vertically drilled well to turn and run thousands of feet laterally through the earth combined with advances in hydraulic fracking, the pumping of millions of gallons of water and laced with thousands of gallons of chemicals into shale at high pressure have increased our ability to recover natural gas from shale ahead of our knowledge of the consequences of the fracking and disposal of the waste water. Wastewaters from the hydraulic fracturing process must be disposed of safely, and deep injecting wells had been the favored method. There are 177 similar injection wells around the state of Ohio that will remain in use. The Youngstown-area well has been the only site with seismic activity, according to the ODNR. Only five Youngstown area wells have been shut down.

Environmental Impacts from Fracking

The oil and gas industries’ ability to pull, push or otherwise draw hydrocarbons from the earth has exceeded our knowledge of geology and groundwater and gotten ahead of our regulations which were created for traditional oil and gas wells. In the lingering Texas drought the oil and gas industry finds itself competing for the millions of gallons of water necessary to hydro fracture a well with other users -towns and ranches. In some areas ranchers are selling water rights while in other areas drillers are being limited in how much water they can draw from the aquifer. The portion of the water used to hydro fracture a well that can be recovered and reused for other fracking jobs is determined by flowback and how the water is treated or disposed of. Flowback from fracking is determined by geology and the amount of water absorbed by the rock formations, before the rest needs to flow out of the well to allow the released gas to flow.

In Texas groundwater is being used to frack wells at an unsustainable rate. In Texas groundwater belongs to the landowner and governed by the rule of capture, which grants landowners the right to capture the water beneath their property. The landowners have a right to pump and capture whatever water is available, regardless of the effects of that pumping on neighboring wells. Any single landowner in a watershed could in effect sell all the groundwater quite legally taking their neighbor’s water. Groundwater should not be used beyond its recharge rate or ultimately it will be depleted leaving communities without adequate water to support them.

The water that is absorbed into rock formations may change the formations in ways we do not understand. Though the water in the hydro frack is exempted from the clean water act (by a 2005 act of congress), the flowback is not and must be disposed under state regulations. The flowback water itself is a problem, it contains “proprietary” chemicals and contaminates from the geological formation. Researchers of the University of Texas at Austin were part of a team of researchers who studied a series of small earthquakes that struck near Dallas, Texas in 2008 and 2009, in an area where natural gas companies had used fracking. The epicenter of the quakes turned out to be about half a mile from a deep injection disposal well under the Dallas-Fort Worth International Airport used to dispose of the fracking fluid. The largest earthquake of the series measured 3.3 on the Richter scale, a very small earthquake. In a study that was published in the Bulletin of the Seismological Society of America, the researchers also reviewed records from US Geological Survey seismic-recording stations in Oklahoma and Dallas. It was concluded by the researchers that the fracking did not cause the earthquakes, but there seemed to be a relationship to the deep well injection of the fracking fluid to the earthquakes.

For years the US Geological Survey has been studying the factors that impact the response of groundwater wells to earthquakes, including the magnitude and depth of the earthquake, distance from the epicenter, and the type of rock that surrounds the groundwater. The depth of the well, whether the aquifer is confined or unconfined, and well construction also influence the degree of water-level fluctuations in wells in response to seismic waves. It has been suggested that some aquifers may even act as resonators, which may amplify the response. Even a small earthquake is not without consequences to the groundwater in the surrounding area. Fracking may also have impacts on nearby water wells. Water injected into a previously dry formation may act as a resonator or lubricant to allow the formation to slide.

Local geology determines the danger of fracking to the water table. In Wyoming where the water table is deep and the gas shallow the drinking water has been impacted. The Environmental Protection Agency, EPA, announced last Thursday that glycols, alcohols, methane and benzene found in a well the EPA drilled to the drinking water aquifer in Wyoming within the Pavillion field were consistent with gas production and hydraulic fracturing fluids and likely due to fracking. The oil company responsible for these wells claims that the results are inconclusive because methane can naturally seep into groundwater wells that provide drinking water. This is a rare occurrence that is usually confined to deeper water wells in the coal-producing areas, but these were deeper wells in a coal producing area. Benzene also occurs in nature, but I can find no instances where benzene was introduced into drinking water by purely natural action; though it could have been introduced into the water by previous generations of oil and gas development. Benzene, glycols and alcohols were all common substances in fracking fluids. In 2004 when EPA first looked at hydro fracking they coordinated a voluntary agreement with the three largest fracking contractors (Halliburton, BJ Services, and Schlumberger), to stop using diesel fuel in hydro fracking. Until 2004 diesel had been commonly used in hydro fracking coal bed gas and the deeper shale gas. Diesel contains benzene, so it seemed likely to the investigators they were introduced by fracking.

EPA constructed two deep monitoring wells to sample water in the aquifer, and tested private and public drinking water wells in the community. The samples were consistent with chemicals identified in earlier EPA results released in 2010 and are within established health and safety standards for most substances, but not for benzene. Sampling found up to 246 micrograms of benzene per liter of water was found in one well, far above the safe drinking water standard of 5 micrograms per liter. The geology of Pavillion, Wyoming is unusual for shale gas formations. The shale is much shallower than in the Haynesville shale and the Marcellus shale, though there is a shallow area of the Fayetteville shale. The fracturing in Wyoming took place both within the water table and a few hundred feet below the drinking water aquifer close to drinking water wells.

In hydraulic fracking on average 2-5 million gallons of chemicals and water are pumped into the shale formation at 9,000 pounds per square inch and literally cracks the shale or breaks open existing cracks and allows the trapped natural gas to flow. While geologists and engineers believe that in hydraulic fracturing the intervening layers of rock prevent a fissure from extending into the water table, they base this on the “typical” geology where there are thousands of feet between the water table and the fracking location and does not account for any potential impacts on the hydraulic balance in a watershed. The problems seen in drinking water wells near hydro fracking jobs typically occur when fracking fluid seeps into drinking water wells through improperly sealed or abandoned drilling wells (a large number of the problems have occurred in older coal bed areas). However, in Pavillion the groundwater is within a few hundred of the gas reserves the groundwater is more easily directly impacted by fracking. In addition, there had been previous development of the oil and gas resources opening the possibility for improperly abandoned or sealed wells. In Pavillion, Wyoming they used hydro fracking within the water table near the drinking water wells. It is not at all surprising that they contaminated the water supply. What is surprising is that the business and the regulator allowed this to happen. They did it without thinking about the potential consequences because it was legal.

The oil and gas industry has outpaced regulators, knowledge of the consequences and it seems common sense. It is essential to determine the vertical and horizontal separation that is necessary to protect the drinking water aquifers from fracking and what impact new rounds of hydraulic fracturing can have on previous developed areas with old abandoned wells before watersheds are destroyed. Then increase oversight to ensure that this separation is maintained (despite inevitable requests for waivers), improve well-design requirements and ensure their consistent implementation and require the appropriate treatment and recycling of drilling waste water. Use of waste water treatment plants that were designed to address biological solids to treat millions of gallons of water used for hydraulic fracturing or ponding the waste is short sighted and imprudent. The deep well injection commonly used in Texas may have consequences beyond small earthquakes.

Drilling requires large amounts of water to create a circulating mud that cools the bit and carries the rock cuttings out of the borehole. After drilling, the shale formation is then stimulated by hydro fracking, using 2-5 million gallons of water. For gas to flow out of the shale, all of the water not absorbed by the formation during fracking must be recovered and disposed of. Though less than 0.5% by volume, the proprietary chemicals represent 15,000 gallons in the waste water recovered from the typical hydro fracking job. The chemicals serve to increases the viscosity of the water to a gel-like consistency so that it can carry the propping agent (typically sand) into the fractures to hold them open so that the gas can flow. Determining the proper methods for the safe disposal of the large quantities of this fracking fluid that may also contain contaminants from the geological formation including brines, heavy metals, radionuclides and organic contaminants and monitoring the impact from this disposal must also be done. The impact of so much waste water on our water resources must be monitored and addressed.

While most states require drillers to dispose of fracking waste water in deep wells below impermeable rock layers, Pennsylvania that has no deep wells has allowed drillers to discharge their fracking waste water through sewage treatment plants into rivers. Sewage treatment plants are designed to separate solids and use bacteria to treat biological waste. They are not equipped to remove or neutralize the contaminants in used hydro fracking fluid. In 2009 and 2010, public sewage treatment plants in Pennsylvania directly upstream from drinking-water intake facilities accepted wastewater that contained radionuclides at levels hundred even thousands of times the drinking-water standard despite the fact that these plants (and most sewage plants) were exempt from monitoring for radiation. Local regulators and gas producers believed the waste was not a threat because it would be diluted by treatment in the sewage treatment plants or the river itself, without sampling. They guessed at the environmental impact.

Finally, care must be taken to avoid degradation of watersheds and streams from the industry itself as large quantities of heavy equipment and supplies are moved on rural roads and placed on concrete pads. The watersheds must be monitored. And recent incidents and reports of potential contamination of drinking water supplies from fracking, the waste water from the fracking process underscore the dangers.The New York Times brought to light a 1987 E.P.A. report to congress titled “Management of Wastes from the Exploration, Development and Production of Crude Oil, Natural Gas and Geothermal Energy.” Corroborating documentation was obtained from state archives or from the EPA’s library by the New York Times.It appears that though seemingly forgotten, EPA had been aware of at least one well documented case of drinking water well contamination from fracking for 25 years. In addition, there are reports from several states noting contamination of drinking water wells in association with fracking, though no definitive proof because of lack of adequate testing and difficulties in understanding groundwater, the full extent to which hydro fracking fluids have contaminated or might in the future contaminate groundwater is unknown. However, many cases of associated contamination have been confirmed.

Fracking in Ohio

The U.S. Forest Service has withdrawn more than 3,200 acres of forest land from a federal oil and gas lease sale scheduled for Wednesday, December 7, 2011. The acreage in Athens, Gallia, and Perry counties was to be included in a broader sale of leases for 20,949 acres of federal land in Ohio, Mississippi and Louisiana. This land was to be auctioned for Hydraulic Fracturing. The Buckeye Forest Council, an environmental coalition, opposed the sale stating that the environmental statement was outdated because it did not mention hydraulic fracturing. In addition, they feel that Ohio does not have the regulatory framework to deal safely with fracking. The auction plan is on hold pending the review of the environmental impact statement which could take up to six months and lead to required revisions in the 2006 environmental impact statement which could delay the auction further. The 3,200 acres currently have nearly 1,300 shallow gas wells.

Our ability to recover natural gas buried a mile or more beneath the earth has increased. Advances in horizontal drilling which allows a vertically drilled well to turn and run thousands of feet laterally through the earth combined with advances in hydraulic fracking, the pumping of millions of gallons of water and laced with thousands of gallons of chemicals into shale at high pressure have increased our ability to recover natural gas from shale. Hydraulic fracking is a technology that was unknown 60 years ago. Until recently there was no economically feasible way to extract this gas.

Thought industry executives say fracking has been widely used for decades without problems, hydraulic fracturing has changed, the type of hydraulic fracturing the industry executives are talking about is coal bed formation fracturing. The volume of water needed for hydraulic fracturing varies by site and type of formation. Fifty thousand to 350,000 gallons of water may be required to fracture one well in a coal bed formation while two to five million gallons of water may be necessary to fracture one horizontal well in a shale formation. Water used for fracturing fluids is acquired from surface water or groundwater in the local area. Wastewaters from the hydraulic fracturing process must be disposed of and several ways have been used. Several of the techniques tried have been to dispose of the water underground using injection wells, discharged to surface waters after treatment in a waste water treatment plant designed to remove only solids and biological contaminants, or applied to land surfaces where it can seep into the water table.

The millions of gallons of water used for fracking shale contain up to 15,000 gallons of chemical additives. The chemicals serve to increases the viscosity of the water to a gel-like consistency so that it can carry the propping agent (typically sand) into the fractures to hold them open so that the gas can flow. Determining the proper methods for the safe disposal of the large quantities of this fracking fluid that may also contain contaminants from the geological formation including brines, heavy metals, radionuclides and organic contaminants is essential. The deep well injection of the waste in Texas is believed by scientists to have triggered the earthquakes near the Dallas airport. The impact of so much waste water on our water resources must be measured and monitored. Finally, care must be taken to avoid degradation of watersheds and streams from the industry itself as large quantities of heavy equipment and supplies are moved on rural roads and placed on concrete pads.

There are many possible routes to contamination from fracking. Errors in natural gas well construction or spills during injection can occur and lead to drinking water contamination. Drinking water wells contaminated by methane and potassium chloride have been reported. In Pennsylvania, flammable levels of methane in drinking water wells and potassium chloride levels high enough to salinize a drinking water aquifer have been reported in the vicinity of some gas wells. Fracking fluids can spill before they are injected and fluids recovered from fracturing can contaminate surface waters. The EPA estimates that 15-80% of the volume of fracking fluids injected will be recovered. The amount of fluid recovered depends on the site geology. Additionally, drilling into the subsurface through the water table can create pathways for fracking fluids or natural gas to find its way into water supplies and wells, if grouting isn’t properly done and the gas well properly constructed. The horizontal sections of the wells are not cased in cement and, introduce a potential point where fracking fluids can reach the outside of the grouting during flowback.

Hydraulic fracturing should continue slowly. A limited number of wells should be installed with careful monitoring of local and regional groundwater supplies as well as verification of proper well construction and wastewater recycling. Limiting fracking to a small area of the federal and state forest lands would allow the development of experience, knowledge and data, and could ensure careful restoration of the area. Instead of leaving unwary homeowners to the “land men” and their leases written entirely to favor and protect the drilling and gas companies, allow the state governments to develop standard language for the gas leases and the federal government to collect real time data in a secluded area away from residential impact.

Currently, the US Environmental Protection Agency (EPA) is studying the impact of hydraulic fracturing on water resources, but they are only focusing on the potential to directly pollute the drinking aquifer, not looking at potential changes in the groundwater hydrology. The geological impact of Hydraulic Fracturing should be examined by the U.S. Geological Survey. No one has ever looked at what the long term implications are for the hydraulic balance when fracking occurs. The removal of millions of gallons of water, the fracturing of the geological formations, and the injection of contaminants even at low concentrations into the subsurface could cause significant changes in groundwater flow and quality.

The current regulatory framework concerning hydraulic fracturing has a number of gaps that need to be addressed before unlimited fracking takes place. There were several recommendations made in the report of the Shale Gas Subcommittee of the Secretary of Energy Advisory Board. The report had a rational approach to regulation recommending disclosure, testing, evaluation and modification of regulation and practices based on the information and data obtained. It assumes information and data will be gathered and analyzed. That is not yet being done. The data needs to be collected on a state level and provided to the US Geological Survey and US EPA to consolidate on a national level.

In the past decade the advances in drilling and fracking technology have been adapted to exploit gas in the Barnett shale in the Fort Worth Basin in Texas and applied to a series of major shale gas deposits that could not have been viable without the advances in drilling and fracking. The Fayetteville shale, the Haynesville shale, the Marcellus shale reserves all in the United States and the Horn River shale reserves in Canada are now accessible. At the current rate of natural gas consumption North America is reported to have a 100-year supply of proven, producible reserves and even with expanded use of natural gas, there is more than a generation of currently accessible reserves. We need to treat both the earth and its resources with respect.

In truth we have no viable option to hydrocarbon fuel. When the oil and gas is gone it will be a poorer future without airplanes, freighters and trucks. Sailing ships will not transport raw materials and finished goods around the earth. Solar and wind power will produce unreliable power supplies and mankind will adapt (not happily) or discover new sources of fuel. Before that future world arrives, the shale gas and oil sands and whatever else is discovered will be exploited. There is no urgency, but you cannot permanently stop that trend. These deposits will become more valuable over time as the world becomes more desperate for energy. Now is the time to carefully develop and study the methods to exploit these resources without destroying or further damaging the earth.