NATURAL GAS, Part 2

Fracks from Fiction

Gas & the Environment

Oil and gas drilling was never benign; it has become even more invasive with the widespread adoption of slickwater hydraulic fracturing or “fracking.” This technique employs high-pressure water and chemicals (many of them dangerous), and occasionally explosives, to fracture earth saturated with oil and gas that is accessed through deep horizontal wells.  Since almost half of all domestic oil and over half of all domestic gas in 2015 were extracted by fracking, and since gas is the most likely conventional fuel that will be used to balance renewable energy intermittency in Texas, its environmental effects need to be considered in detail.

1. Water Consumption

In 2011, one of the driest years in the recorded history of Texas, about a quarter of water consumption in Dimmit County was used for fracking.

The fracking cocktail generally consists of about 90% water, 9.5% quartz sand (called “proppants” because it “props up” or holds the fissures open), and 0.5% or less of chemicals.¹  Though water consumption ranges depending on the geology, between 2005 and 2014, the median water use per fracking well in the U.S. was 3.3 million gallons.²  Each well pad can be used for as many as 10 wells that go in different directions.  Depending on geology, each well can be refracked several times.  By comparison, conventional drilling only uses an average of 255,000 gallons per well.³

Between 2011 and 2014, an estimated total of 42 to 48 billion gallons of water was used annually for fracking oil and gas in the U.S.⁴  Depending on how you look at it, this amount is either outrageous, or barely noticeable.  In the entire of 2014, Austin’s water utility consumed about 45 billion gallons.  However, this same amount is only 3 hours of water consumption for the U.S.⁵

A better benchmark to evaluate excessive water use is to look at the region it is drawn from.  Between January 2011 and May 2013, about half the water used in U.S. fracking occurred in Texas, and about half of that Texas water was in the Eagle Ford Shale region in South Texas.⁶

Several counties there have already seen their water tables drop 100 to 300 feet in the last 50 years.  In 2011, one of the driest years in the recorded history of Texas, about a quarter of water consumption in Dimmit County was used for fracking.⁷  About half the wells in both the U.S. and Texas were drilled in regions with high or extremely high water stress.

2. Underground Water Contamination

In the Barnett shale field in Texas, there was a drinking water well so contaminated with methane that water entering the plumbing contained as much as 7 times the concentration necessary to cause explosions. 

Fracking chemical mixtures are engineered to optimize “in situ” (in place) mining.  After a horizontal well is drilled, perforated casement is laid, and high-pressure water is injected to fracture the earth the casement pipe is in contact with. There are easily hundreds of chemicals used for fracking, with a large number of them being quite toxic.

• The first injected water is often laced with powerful acids (e.g., hydrochloric, hydrofluoric, acetic, formic) to clean fractures and disintegrate minerals in the extraction zone.

• Proppant sand is often coated with acrylonitrile, a poison and possible human carcinogen.

• Gels are used to increase the thickness of the water to better transport the sand.

• When the sand is delivered and inserted, other chemicals are injected to break down the gels to allow better extraction of oil and gas.

• Friction-reducing agents, including surfactants, and even kerosene and diesel oil, are added to create better flow.  Diesel contains BTEX chemicals (benzene, toluene, ethylbenzene, xylene), which are poisonous and carcinogenic.

• Antifreeze is added to winterize the chemical mixture stored at the surface.

• Biocides in the mix prevent bacteria from growing on the hydrocarbons and clogging the well.

• Anti-corrosion and anti-scaling agents protect the piping and casement.

An assessment of chemicals identified in fracking mixtures in 2013 found that at least one-third of all wells employed at least one chemical that was carcinogenic, including naphthalene, benzyl chloride, and formaldehyde.⁸  The same study demonstrated that 90% of wells used at least one chemical that was a suspected carcinogen. Other chemicals in some of the mixtures, such as hydrochloric and hydrofluoric acids, are highly and acutely toxic if inhaled or ingested, and extremely hazardous if they come in contact with skin and eyes.

Between 4 and 28 unique chemicals are used in each well.⁹  While these chemicals, on average, only make up about 0.5% of the mixture, in an average 3.3 million gallon well, this amounts to 16,500 gallons.

About two-thirds of the fracking mix stays underground after the operation, and there have conservatively been hundreds of cases of groundwater contamination from the chemicals or methane itself.¹⁰  There have been cases where homes or wells near these homes have been damaged by explosions from the gas in the groundwater, and other cases where domestic water supplies could literally catch fire.

In addition to flowback from injected fracking water, wells emit produced water.  All oil and gas wells pump naturally occurring ground water, which is often 10 times more briny than water in the world’s oceans.  This is further contaminated by BTEX chemicals, heavy metals, methane, and naturally-occurring radioactive isotopes in the earth or the oil and gas the water is in contact with.  Produced water is also often treated as toxic waste.

There are at least 3 direct pathways for chemical contamination from oil and gas wells.

2A. Faulty Wells – The most likely avenues for fracking fluids and methane to contaminate ground water is drinking water and casement leaks in the underground oil and gas pipes and chemical leaks at the surface.  Despite requirements and standards requiring that casements that draw up oil and gas are not supposed to come in contact with drinking water aquifers, a certain percentage of them are either installed improperly or deteriorate.  Recently, at least 7% of wells in Pennsylvania were found to have defective casings that could contaminate drinking water aquifers.¹¹

2B. Accidents – Carelessness and accidents also cause spills at or near the well pad, with the chemicals spilling on the ground to infiltrate into the ground water, or to run off with rains into nearby surface water.  They can also evaporate, causing general harm to air quality, and possibly, acute hazards to workers.

Estimates of spill frequency in 3 states ranged from 1 to 12 per hundred wells.¹²  The median volume of chemicals or fracking fluids spilled was 420 gallons per event, which did not include spills of produced water.¹³

2C. Geologic Communication – A third avenue of contamination is for fracking fluids and methane delivered below a groundwater aquifer to migrate up to the groundwater through communication between geologic strata.

Probably the largest documented group of cases surrounding water contamination from fracking in the U.S. was conducted by the non-profit news organization Public Herald.  In an investigation of public records, the Herald uncovered 280 confirmed cases of well contamination by the Pennsylvania Dept. of Environmental Protection (DEP) in shale-producing counties in the state between December of 2007 and June of 2016.¹⁴  These were just the complaints that were confirmed; 1,275 water-related complaints were actually lodged.

In Texas, groundwater problems have been documented in the Barnett shale formation west of Ft. Worth.  One of the highest profile cases involved a landowner whose water well was so contaminated after oil and gas wells were sited near his home that methane was entering his domestic water plumbing as high as 7 times the concentration necessary to cause explosions.¹⁶ Several of his neighbors experienced similar problems.  Though some research has ascribed this to naturally occurring gas, at least one study specifically tracked the chemical signature of the methane to oil and gas drilling.¹⁶

Information of well contamination in the region was also shown in a 2015 study with Zacariah Hildenbrand at UT-Arlington as lead author.  It tracked trace chemicals related to oil and gas drilling in groundwater in the Barnett shale region, included BTEX, cyclohexane, ethanol, and methanol in a large share of samples.¹⁷  While these chemicals were not conclusively caused by drilling, they were associated with it, and further monitoring was encouraged.

3. Wastewater Holding Ponds

Between 2011 and 2014, an estimated 41 billion gallons of flowback and produced water was extracted annually from U.S. oil and gas wells.

After fracking, much of the injected water as well as produced water come to the surface as “flowback.”  Depending on the geology and well, this wastewater can exceed the original volume injected.  Between 2012 and 2014, an estimated 41 billion gallons of flowback and produced water was extracted annually from U.S. oil and gas wells.¹⁸

While some of this was recycled, the largest percentage was treated as toxic waste, injected deep underground in special disposal wells.  While a well is waiting for this water to be recycled or disposed of, it is stored in ponds on site, leading to more pathways for environmental damage.

3A. Water Leaks – Chemically-laced water can leak through poor or broken linings to contaminate groundwater or spill into nearby surface waters.

3B. Air Emissions – Harmful volatile organic compounds (VOCs) in the chemically-laced water can evaporate, contaminating air quality, both locally and regionally.  VOCs are also ozone-causing chemicals that can affect the health of major population centers far away from the source.  For instance, emissions from the Eagle Ford shale region in South Texas can migrate to San Antonio.

3C. Wildlife Mortality – Wildlife that mistake the ponds for fresh water are also frequently poisoned.

4. Drilling Wastes

Well waste pits are so toxic that some would qualify as Superfund sites, but drilling wastes are exempted from hazardous waste laws through loopholes given to the industry.

In 2008, about 273 million barrels of drilling waste was stored and disposed of onsite at U.S. oil and gas wells.¹⁹  This waste included drilling cuttings, drilling muds, lubricating fluids in these muds (which sometimes included diesel oil), produced sands, completion fluids, debris, filter media, and tank-bottom sludge.

These wastes are generally retained in oil pits (“reserves”), a bermed hole often as large as an Olympic swimming pool.  Some of the hazardous substances found in them include hydrochloric acid, surfactants, rig wash, diesel fuel, glycols, waste oil from machinery, heavy brine, heavy metals (arsenic, chromium, lead), and radioactive materials. Sometimes produced water, oil, and oil condensate that are not properly separated from this produced water also end up in these pits.

These pits can be so toxic that some would qualify as Superfund sites for hazardous material remediation if they came from another source.²⁰  However, oil and gas drilling wastes are specifically exempted from hazardous waste regulations through loopholes given to the oil industry.²¹

These pits require liners, but frequently leak due to tears. In New Mexico alone, the state Environmental Bureau recorded more than 6,700 cases of pit contamination to soil and water between the mid-1980s and 2003.²²

Like frack-water holding ponds, they are easily accessible to birds and other animals, which can easily mistake them for water holes and ponds.  Besides hazards to them from the chemicals, oil can also coat the feathers of birds, rendering the insulation quality of the feathers useless, and causing the animals to freeze. It has been estimated that hundreds of thousands, and perhaps millions, of animals die each year due to exposure to these pits. In many states, pits are required to have exclusion devices, including nets, to keep birds and animals away. However, many do not have them, or the barriers have fallen into disrepair.

At the end of a well’s life, pit remediation is required, which adds to the cost of production. Usually, this is accomplished through onsite burial after pit fluids have evaporated.  While fumes from the evaporation themselves can sometimes be hazardous, there is also danger that the dried toxins will leach into the ground and ground water over time.

5. Deep Injection of Wastewater

Before 2009, prior to large-scale wastewater injection associated with fracking, there were an average of less than 2 earthquakes in Oklahoma above Magnitude 3.0 per year.  In 2015, there were 907.  Virtually all of this was attributed to deep injection of oil and gas wastewater.

5A. Leaks of Class II Wells – Flowback water and produced water from conventional and fracked wells are often pressure-injected deep (several miles) in underground aquifers as a means of toxic waste disposal.  The rationales for this practice are: 1) these aquifers are so deep that they will never cross-contaminate drinking water aquifers closer to the surface; and 2) these Class II aquifers are so deep and briny that they will never be tapped for human consumption.  Both assumptions are questionable.

In a roughly three-year period between late 2007 and 2010, an analysis conducted by the non-profit investigative news organization ProPublica discovered 17,000 well integrity violations nationally, one for every six it examined.²³  More than 7,000 were leaking.  The same analysis showed that in Texas in 2010, one leak was discovered for every 3 examined.  Most often the violations were for cracks or holes in the wells and casings, which can allow the wastewater to seep into the earth and eventually contaminate groundwater.

Wells can also cause problems even if the well structure is sound if water is injected too fast or too hard (under too much pressure).  Old oil wells and natural fissures in the earth can convey this dangerous wastewater back to the surface or into drinking water aquifers.

There have been numerous instances of leaks from deep injection wells into water wells or other oil wells, probably due to more-than-expected pressure in the injection wells, unexpected cracks in the injection well casing, or unexpected fissures between aquifers allowing transfer of the waste fluid to uncontaminated groundwater.  Sometimes the pressure was so strong that the contaminated water was even pushed to the surface.

While most leaks are caught before they cause harm, between 2008 and 2011, regulators in various states recorded 150 incidents of alleged contamination from injection wells.²⁴  In a Texas study of high-salinity soil, it was determined that 29 brine injection wells were the likely cause.²⁵

Texas leads all other states in the collective number of Class I (industrial waste) and Class II (oil and gas waste) injection wells.

5B. Frackquakes – The sheer quantities of flowback and produced water injected into Class II wells is causing earthquakes in eight states, including Oklahoma, Texas, and Ohio.  The volume and frequency of injections is creating man-made pressure on earthquake fault zones in the vicinity of the wells.

In 2014 and 2015, Oklahoma exceeded all other states, including California, in earthquake frequency.  Before 2009, there were an average of less than 2 earthquakes above Magnitude (M) 3.0 in the whole state per year.²⁶  In 2015, there were 907.²⁷  In 2016, it fell to 623, probably due in part to state government action to limit injection water disposal in vulnerable geologic formations.²⁸  While some see the decrease in numbers as a sign that mitigation is working, the quakes in 2016 became stronger, with 3 of the 5 strongest in the state’s recorded history occurring that year.²⁹  There is no way to know how many years it will take before the danger completely subsides, or if the quakes will go on at reduced levels in spite of continued mitigation efforts.

On occasion, they have caused minor damage to property, but (as yet) no loss of life, and as yet, no disasters.  On November 5, 2011, the most severe earthquake in Oklahoma’s recorded history to date, at M 5.6, was centered 44 miles east of Oklahoma City.  It delivered minor injuries to 2 people, and damaged 14 homes as well as a building on a college campus.  Part of the state highway near the quake buckled.³⁰  Tremors from the event could be measured all the way from South Texas to South Wisconsin.³¹

The most common concerns about continuing occurrences are: 1) the effects of many small quakes can weaken structures over time; and 2) just because a disaster has not happened yet does not prohibit one in the future.

Damage in Oklahoma could be particularly calamitous, and ironic, in that the Cushing oil storage center, an important national distribution point for oil storage and transport, is in one of the worst parts of the state threatened by the quakes.  Major damage in its vicinity could have financial and even energy security implications for a noticeable part of the U.S.

To a lesser, but still worrisome extent, these quakes have also occurred in Texas, particularly in the Dallas/Ft. Worth Metroplex area.  There have been 114 events between October of 2008 and June of 2016 in the Dallas/Ft. Worth area.  None of them were major, though 32 of these were above Magnitude 3; one (near Venus, TX) reached M 4.³²

The number of events has become so ominous that, in 2016, the United States Geologic Survey released its first-ever map predicting earthquake damage that includes induced (manmade) seismicity.  The 2017 update predicted a 1 to 12% chance of damage in a large part of Oklahoma.³³

Based on these concerns, the Federal Emergency Management Agency has analyzed the effect that an M 5.6 earthquake would have on West and downtown sections of Dallas.  While pegged at less than a 1% chance in 2016, the damage to 80,000 buildings, as well as levees and dams, could amount to as much as $9.5 billion.³⁴

6. Toxic Air Emissions

In 2013, oil and gas wells in the state of Texas flared or vented enough gas to supply electricity to the entire city of Austin.

Both conventional and fracking oil and gas extraction cause dangerous air emissions.  These include criteria pollutants such as nitrogen oxide and carbon monoxide, VOCs such as formaldehyde, hazardous air products (HAPS) such as benzene and toluene, and the highly toxic gas hydrogen sulfide.  These also include leaks of natural gas itself.

There are several production pathways for environmental exposure, which are discussed below.

6A. The Well – In 2012, inspectors from the Texas Commission for Environmental Quality were investigating a complaint from a well site.³⁵  They found levels of VOCs so dangerous that they evacuated the site.  Unfortunately, they did not warn residents near the distressed site to take similar action.

Wells, particularly oil wells, produce excess gas, which is “stranded” because it is not deemed cost effective to build a gas pipeline to markets.  This gas is either flared or vented directly into the atmosphere, wasting valuable energy while causing onsite and regional pollution. Even wells that only produce natural gas vent some of it into the atmosphere through leaks in the infrastructure.

Vented gas sends methane, a powerful greenhouse gas, into the atmosphere, and often includes other harmful substances such as VOCs like benzene and formaldehyde, polycyclic aromatic hydrocarbons, soot, and hydrogen sulfide.  While many VOCs are poisons in their own right, they will also combine with nitrogen oxides to form ozone, an airborne corrosive chemical that causes asthma and other lung disease.  Ozone concentrations near the fracking fields of rural Utah and Wyoming have become so bad that they rival the levels seen in major cities such as Los Angeles.³⁶

Flared gas produces criteria pollutants (sulfur dioxide, nitrogen oxides, carbon monoxide, particulates), carbon dioxide, heavy metals, and reduced but measurable levels of VOCs and hydrogen sulfide.

“Glycol dehydrators” at well sites remove water from the gas and then vent the water vapor, as well as toxic gases, into the atmosphere.

Drilling equipment and other machinery often operate on diesel fuel, with its own emissions of criteria pollutants.

In 2013, wells and gas processing plants in Texas flared or vented enough gas to supply more electricity than Austin Energy customers consumed (if the gas had been consumed in an efficient generator).³⁷

6B. The Pipeline and Metering Stations – In 2015, the U.S maintained over 2.7 million miles of gas gathering lines, major pipelines, and gas utility lines.³⁸  Leaks are ubiquitous in this infrastructure.

6C. Compressor Stations – Compressors that transport gas through these lines are themselves fueled by natural gas, which creates exhaust emissions, and when over-pressurized, compressors leak gas directly into the air.

6D. Processing Plants – In 2014, there were 551 gas processing plants nationwide, with 181 of them in Texas.³⁹  These remove impurities not already extracted or emitted at the well site or through leaks in the pipeline infrastructure.  Impurities include water, CO2, hydrogen sulfide, VOCs, HAPs, as well as heavier hydrocarbon gases such as ethane and propane that are extracted for other chemical or fuel use.

7. Nuisance Factors

It can take thousands of truck trips down poorly built country roads in front of rural homesteads to drill one new fracking well.

A 2013 study by the Wall Street Journal concluded that about 15.3 million people in the U.S. lived within a mile of an oil or gas well – that was 1 out of 20 Americans.⁴⁰  It will come as no comfort to them that fracking wells generally do not make good neighbors.

Even ignoring the hazards of local air and water pollution, the noise, dust, glaring lights, traffic, risk of traffic accidents, odors, and invasions of privacy by workers near rural homesteads and farms from fracking wells and infrastructure have, by now, likely created thousands of resentful families whose quality of life has been violated.  In some cases, their property has been rendered effectively worthless by the damage done to air, water, and scenery.

Living next to a fracking site is akin to living next to an industrial operation.  By one study, 3,950 large truck trips (18-wheelers) and 2,840 small truck trips per well are needed to haul construction material, supplies and frack water into the site and wastewater away from the site.⁴¹  This is about twice the number needed for conventional drilling.  These trucks wear down the poorly built rural roads they drive on, while creating dust and noise 24/7.  This is not to mention the incessant exhaust, dust, and noise from the drilling machines operating at 3,500 horsepower.  This process can last for as long as 3 months at a time, and can continue if the same well is refracked.  Even after one well has played out, more wells can be fracked at the same site – as many as 10 wells can be drilled on each well pad.

After the well is retired, it can take years (sometimes a generation) for the land to recover (assuming that there is an adequate remediation plan in place).  Between 2005 and 2012, the land damaged from fracking oil and gas wells in the U.S. amounted to 360,000 acres.⁴²  This pales compared to the amount of land leased by 70 of the country’s largest oil and gas companies for further drilling, equal to the combined land area of the states of California and Florida.⁴³

8. Methane Global Warming

Methane can be 86 times more potent as a global warming gas than carbon dioxide in the first 20 years after its release.

The majority of unprocessed natural gas is methane.  Compared to carbon dioxide, it is a more potent global warming chemical, trapping more heat in the earth’s atmosphere in short-term time frames.  While methane eventually degrades into carbon dioxide, it can be 86 times more potent in the first 20 years after release, and 34 times as potent in the first 100 years of release.

While theoretically methane originating from gas wells would be burned and emit CO2, leaks in the gas infrastructure emit methane directly into the atmosphere.  Mining coal also produces methane, though not nearly as much per unit of energy as natural gas.  So on balance, methane emissions reduce the global warming benefits of converting from coal to natural gas.

Assuming a 2.1% methane leakage rate in the U.S. natural gas system and a methane multiplier for coal, this would mean that an efficient natural gas plant would produce 54% less carbon dioxide-equivalent emissions compared to Austin’s Fayette coal plant in the first 20 years, and 64% less equivalent emissions in a 100-year time frame. While the savings is substantial, it is less than what would be assumed by looking at CO2 emissions alone (without methane), a 69% reduction in a 100-year time frame.⁴⁴

Mitigating Drilling Risks

Best Management Practices

There is no way to remove all of the environmental problems inherent in oil and gas drilling.  It is, by its very nature, an invasive process.  There are, however, techniques and technologies to mitigate its effect on local neighbors and the environment.  Some of these are employed at certain drilling sites now, though it is doubtful that any single one of them is universally employed in the drilling industry, and highly unlikely they are employed together as part of a Best Management Practices package.

Such a package could raise the price of gas.  Even so, environmental mitigation costs are the price we pay for living in a more civilized society.

Alternatives to Water Used for Fracking – Various alternative technologies and strategies have been developed as a partial or complete alternative to water-based fracking.

Nitrogen and/or carbon dioxide gas can partially or totally replace water and chemicals.  (The proportion of water depends on the geology.)  One of the world’s largest oil service companies, Baker-Hughes, markets a system trade-named VaporFrac™, which has developed a niche market in some water-poor drilling regions.  In shallower shale formations, it combines alternative gases with ultra-lightweight sand.  The lack of water often yields more gas because water has a tendency to block gas flow by closing some of the fracked fissures in the well.

In deeper wells, these gases can also be used in combination with water.  This greatly reduces, but does not eliminate, water and chemical use.

Reduction of Hazardous Chemical Use and Water Use – Various drilling companies and their service providers have devised technologies and strategies to reduce hazardous chemicals in water used for fracking, or to eliminate the use of freshwater in their operations.

The mega-giant oil service firm Halliburton is marketing a group of 3 more benign fracking technologies trade-named CleanSuite™.  This includes: CleanStim®, which uses food-grade chemicals to enhance the water; CleanStream®, which uses water treatment from UV light to replace biocides; and CleanWave®, which purifies wastewater through electrocoagulation to replace freshwater used in fracking.

In the Permian Basin region of Texas, companies such as Apache Corporation and Fasken Oil & Ranch have eliminated freshwater use for fracking operations.  They use a combination of brackish water undrinkable without expensive treatment, and recycled flowback and produced water from their oil and gas wells that has been upgraded.

Recycling not only lowers the cost of water supply, but it also eliminates the steep cost of transportation and deep injection disposal.  In one region where Apache was operating, recycled water was 29¢/barrel, compared to $2.25/barrel for offsite disposal.

Other companies in Texas with innovative strategies that save water include Pioneer Energy Services, which uses evaporation control covers at water storage sites, and Anadarko Petroleum Corporation, which has built roads with limestone to reduce water use for dust suppression.

Air-Emissions Control – Air emissions occur at every stage of natural gas extraction and processing.  A comprehensive group of strategies needs to be implemented to reduce emissions and improve oil and gas recovery.⁴⁵

• Cleaner fuel sources need to be employed to operate machinery.  Electricity is preferred, followed by natural gas.  Diesel should be eliminated whenever possible.

• Gas leak detection and repair should be pursued at all stages of the fuel chain on a routine basis.

• Oil and condensate storage tanks should install vapor recovery units, which can also add to fuel recovery.

• Onsite air emission devices should be installed and maintained for polluting equipment such as glycol dehydrators (that remove water from raw gas).  Adjusting circulation of the glycol fluid can also reduce air pollutants.

• Pneumatic valves, pumps, and other equipment work off gas pressure, and leak by design.  They need to be replaced with low–leak or no-leak equipment.

Outright flaring and venting of gas should be discouraged with various strategies, including: 1) quick hook-ups of new wells to gathering field lines; and 2) portable gas-to-liquids conversion technologies and onsite electric generation supplied by the otherwise-wasted gas.

As an additional disincentive, all gas should be metered at the well site, and taxes and royalties should be paid on it.

Hazard Disclosures to Neighbors – Oil and gas wells have their share of emergency situations and chronic hazards to their neighbors.  If emergencies, such as hazardous air emissions, chemical spills, or other accidents occur, some type of alert or Reverse-911 system needs to be employed.

Disclosure of chemicals in fracking water is another key concern for residents using local groundwater.  While chemical use has become more transparent over time, some fracking formula manufacturers still guard some of their ingredients as trade secrets.

Closed Loop Waste Systems and Fluid Reuse Systems ­– Waste pits can largely be replaced by closed loop waste management systems that store the liquids in closed, double-walled tanks.  The liquid is often separated with a chemically-enhanced centrifuge; alternatively, it can be trucked to an offsite licensed oil field waste facility.

If cuttings (dirt and rock from the drilling process) are not contaminated by the drilling fluids, they can sometimes be used for other purposes, such as berms surrounding the tanks to contain unintended leaks that could contaminate soil and groundwater. If not, they can be buried onsite.  Closed systems also employ leak monitoring devices.    

Closed-loop systems can reduce water use for drilling and cementing by 80%, and overall waste from drilling pits by 90%.⁴⁶ 

Advanced water-recycling options also exist that can separate condensate, brine, methanol, and fresh water for reuse.  Gas condensate is recovered and sold. The methanol and brine are reused in drilling fluids. The purified water is either reused at other drilling sites or for the benefit of livestock and wildlife.

Least-Toxic Drilling Muds – Drilling muds are used to lubricate drill cuttings so that they will separate from the well and can be extracted, and to line the well’s sides.  Some muds contain diesel oil.   However, there are muds consisting of more benign materials including vegetable oil and least-toxic chemicals such as mineral oil.

Barriers for Noise, Light, and Dust – Some drilling companies erect temporary walls as high as 20 feet tall to mitigate sound, nighttime glare from work lights, and dust.  Such assemblies often consist of fiber or plastic blankets supported by steel beams.

Continue to Natural Gas, Part 3: The New Gas Plant and Race ->

Endnotes

1 Amerian Petroleum Institute, Freeing Up Energy, Washington, DC, 2010, p. 8.  Online at http://www.ela-iet.com/EMD/HYDRAULIC_FRACTURING_PRIMERAPI.pdf

2 Kondash, Andrew and Avner Vengosh, “Water Footprint of Hydraulic Fracturing,” Environmental Science and Technology Letters, 2015, v. 2, pp. 276−280.  (Weighted average of all wells in Table 2.)

3 Op. cit., Kondash, Andrew and Avner Vengosh, p. 279.

4 Water consumption from:

Low figure from Freyman, Monika, Hydraulic Fracturing & Water Stress, Boston, MS: Ceres, February 2014.  (Average between January 2011 and May 2013.)

High figure from op. cit., Kondash, Andrew and Avner Vengosh, p. 276.  (Average between 2012 and 2014.)

5 Maupin, M.A., et. al., Estimated use of water in the United States in 2010, Washington, DC: U.S. Geological Survey, Circular 1405, 2014. Online at http://dx.doi.org/10.3133/cir1405, 355 billion gallons a day used in the U.S. in 2010 means that 44 billion gallons per year was used in about 3 hours.

6 Op. cit., Freyman, Monika, p. 5.

7 Galbraith, Kate, “As Fracking Increases, So Do Fears About Water Supply,” New York Times, March 7, 2013.

8 Manthos, David, “Cancer-Causing Chemicals Used in 34% of Reported Fracking Operations,” Skytruth, Shepherdstown, WV, January 22, 2013.  Online at https://skytruth.org/2013/01/carcinogens-fracking

9 U.S. Environmental Protection Agency, Hydraulic Fracturing for Oil and Gas, Executive Summary, EPA-600-R-16-236ES, Washington, DC, December 2016, p. 16.  Online at http://www.epa.gov/hfstudy

10 Ibid., (main report), p. 7-8, Table 7.3.

11 Badges-Canning, Michael, et al., Shalefield Stories, Homestead, PA: Steel Valley Printers, January 2014, PDF p. 41.  Online at http://www.environmentamerica.org/sites/environment/files/reports/ShalefieldStoriesnp.pdf

12 Op. cit., U.S. Environmental Protection Agency, Hydraulic Fracturing, Appendix, p. C-37, Table C-8.

13 Op. cit., U.S. Environmental Protection Agency, Hydraulic Fracturing, p. ES-22.

14 Pribanic, Joshua & Melissa Troutman, “Public Herald 30-Month Report Finds DEP Fracking Complaint Investigations Are “Cooked” and Shredded,” Public Herald, September 15, 2015.

Pennsylvania Department of Environmental Protection, “Water Supply Determination Letters.  Online at http://files.dep.state.pa.us/OilGas/BOGM/BOGMPortalFiles/OilGasReports/Determination_Letters/Regional_Determination_Letters.pdf

15 Martyn, Amy, “Anti-Fracking Guy Has a Point, But the State Is Sticking With the Industry,” Dallas Observer, June 14, 2014.

16 Schlanger, Joe, “Fracking Wells Tainting Drinking Water in Texas and Pennsylvania, Study Finds,” Newsweek, September 15, 2014.

17 Hildenbrand, Zacariah, et al., “A Comprehensive Analysis of Groundwater Quality in The Barnett Shale Region,” Environmental Science and Technology, June 16, 2015.

18 Op. cit., Kondash, Andrew and Avner Vengosh, pp. 276-277.  Total flowback and produced water/year derived by percentage of water use to water produced (85% X 48 billions gallon/year in total water use).

19 Ramirez, Pedro, Reserve Pit Management, Cheyenne, Wyoming: U.S. Fish and Wildlife Service, September 2009, p. 6.

20 National Resources Defense Council, “Groups Sue EPA Over Dangerous Drilling and Fracking Waste,“ PRESS RELEASE, New York, NY, May 04, 2016.  Online at https://www.nrdc.org/media/2016/160504

21 U.S. Environmental Protection Agency, Drilling Waste Management Information System, “Federal Regulations: U.S. Environmental Protection Agency.”  Online at http://web.ead.anl.gov/dwm/regs/federal/epa/

22 Earthworks, “Pit Rule,” Washington, DC, accessed 1/31/17.  Online at https://www.earthworksaction.org/index.php/issues/detail/pit_rule#.WJE9fyMrLCQ

23 Lustgarten, Abrahm, “Injection Wells: The Poison Beneath Us,” ProPublica, June 21, 2012.  Online at http://www.propublica.org/article/injection-wells-the-poison-beneath-us

24 Ibid.

25 Ibid.

26 Jones, Corey, “Disposal volumes linked to man-made earthquakes drop 23 percent in 2016 from a year ago,” Tulsa World, January 9, 2017.

27 Ibid.

28 Ibid.

29 Strain, Mike, “Earthquake 101: What’s causing them? More concern for Cushing? How long will they continue?,” Tulsa World , November 13, 2016.

30 Dinger, Matt and Matt Patterson, “Record 5.6 magnitude earthquake shakes Oklahoma,” NewsOK, November 6, 2011.

31 Olafson, Steve, “Rare Oklahoma earthquake damages 14 buildings,” Christian Science Monitor, November 6, 2011.

32 USGS Earthquake Web site: http://earthquake.usgs.gov/earthquakes/search/

33 Petersen, Mark, et al., 2016 One-Year Seismic Hazard Forecast for the Central and Eastern United States from Induced and Natural Earthquakes, U.S. Geological Survey, Open-File Report 2016–1035, Version 1.1, June 2016, p. 39.

34 Associated Press, “USGS report looks at North Texas seismic, earthquake risks,” Fuelfix.com, March 27, 2016.  Online at http://fuelfix.com/blog/author/associatedpress/

35 Wilson, Sharon, et. al., Reckless Endangerment While Fracking the Eagle Ford, Earthworks Oil & Gas Accountability Project, Washington, DC, September 2013, p. 15.

36 Messick, Molly, “Rural Wyo. County’s Air Quality Rivals L.A.,” National Public Radio, Morning Edition, Washington, DC, April 5, 2011.  Online at http://www.npr.org/2011/04/05/135135548/rural-wyo-countys-air-quality-rivals-l-a

Gilman, Sarah, “The Uintah Basin’s tricky oil and gas ozone problem,” High Country News, Nov. 3, 2014.  Online at http://www.hcn.org/articles/officials-chisel-away-at-the-uintah-basins-tricky-ozone-problem

37 Gas flared (77 bcf) from Horwitt, Dusty, Up In Flames, Earthworks, Washington, DC, August 2014, p. 12.  Assumes gas is burned in 57% efficient combined cycle gas plants, for about 13 Twh.  In FY 2013, Austin Energy sales were 12.3 Twh.

38 Pipeline and Hazardous Materials Safety Administration, Annual Report Mileage for Gas Distribution Systems, Jan 3, 2017.

39 U.S. Energy Information Administration, Natural Gas Annual Respondent Query System, (EIA 191), data for 2015, September 2016.  Online at http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP9

40 Gold, Russell, and Tom McGinty, “Energy Boom Puts Wells in America’s Backyards,” Wall Street Journal, Oct. 25, 2013.  Online at http://www.wsj.com/articles/SB10001424052702303672404579149432365326304

41 New York Department of Environmental Conservation, High-Volume Hydraulic Fracturing in NYS, Final SGEIS 2015, December 2014,  Table 6.62, Page 6-306.  http://www.dec.ny.gov/docs/materials_minerals_pdf/fsgeis2015ch6b.pdf

42 Ridlington, Elizabeth, Fracking by the Numbers, Environment America, October 2013, p. 4.

43 Ibid., p. 26.

44 BTUs/kwh for natural gas combined cycled turbine: 5,964 high heat value (Spec for efficient combined cycle gas plant from General Electric, “H-CLASS 9HA.01/.02 Gas Turbine,” accessed 2/3/17.  Low Heat Value of Gas adjusted to High Heat Value by 1.108 multiplier.  Online at https://powergen.gepower.com/products/heavy-duty-gas-turbines/9ha-gas-turbine.html)

BTUs/kwh for Fayette coal plant for 2014: 10,400 high heat value (Derived from U.S. Environmental Proteciton Agency, “Air Markets Program Data,” Washington, DC, accessed 12/12/15.  Online at https://ampd.epa.gov/ampd/

Natural gas CO2 emissions per MMBTUs: 117 pounds (U.S. Environmental Protection Agency, “Carbon Dioxide Emissions Coefficients,” Washington, DC, February 2, 2016.)

Subbituminous Coal CO2 emissions per MMBTUs: 214 pounds (Ibid.)

Methane multiplier for 20-year Global Warming Potential: 86 (Myhre, Gunnar and Drew Shinde, “Anthropogenic and Natural Radiative Forcing,” Climate Change 2013, IPCC Working Group, Cambridge University Press: New York, NY, Chapter 8, Table 8.7, page 714.

Methane multiplier for 100-year Global Warming Potential: 34 (Ibid.)

Methane multiplier for 20-Year Global Warming Potential of Coal: 10% (Derived from U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990– 2014, April 15, 2016, Washington, DC, Table 1.4, pp. 1-17-18.

Methane multiplier for 100-Year Global Warming Potential of Coal: 4% (Ibid.)

Effective direct methane leakage rate from Barnett shale region: 1.6% (Ramon Alvarez, scientist with Environmental Defense Fund, July 29, 2016.)

Methane (in pounds per MMBTUs) for 1.6% methane leakage: 0.62, Ibid. (This is adjusted upward to 2.1% for upstream losses for the 20- and 100-year time frames.)

45 Fleischman, Lesley, et. al., Fossil Fumes, June 2016, pp. 16-17.  Online at http://www.catf.us/resources/publications/view/221

46 Earthworks, “Alternatives to Pits,” Washington, DC, accessed 1/30/17.  Online at https://www.earthworksaction.org/issues/detail/alternatives_to_pits#.WI-V3iMrJjO