Appalachian Basin

New York Confirms Safety and Benefits of Hydraulic Fracturing

“We’ve deliberated, we’ve considered the comments, we have looked at what’s gone on in other states…And at the end of this stage of the deliberations, we’ve concluded that high-volume hydrofracking can be undertaken safely, along with strong and aggressive regulations.”  – New York DEC Commissioner, Joe Martens

The New York Department of Environmental Conservation (NYDEC) recently released a preliminary Draft Supplemental Generic Environmental Impact Statement (dSGEIS) regarding the future development of the vast shale gas resources in the state, which includes portions of the massive Marcellus Shale formation. NYDEC confirms that shale gas production, including the use of hydraulic fracturing, can strengthen the economy while protecting drinking water supplies and local habitats.

But you already knew all of that. So let’s get to the meat, shall we? Below (after the jump) are key excerpts pulled directly from the report.

Strengthening the Economy

  • “Increased production of domestic natural gas resources from deep underground shale deposits in other parts of the country has dramatically altered future energy supply projections and has the promise of lowering costs for users and purchasers of this energy commodity.” (Executive Summary, p. 1)
  • “The Final report concludes that an increase in natural gas supplies would place downward pressure on natural gas prices, improve system reliability and result in lower energy costs for New Yorkers. In addition, natural gas extraction would create jobs and increase wealth to upstate landowners, and increase State revenue from taxes and landowner leases and royalties.” (Chapter 2, p. 2-6)
  • “The Department finds that the no action alternative would not result in any of the significant adverse impacts identified herein, but would also not result in the significant economic and other benefits identified with natural gas drilling by this method. The Department believes that this alternative is not preferable because significant adverse impacts from HVHF operations can be fully or partially mitigated.” (Executive Summary, p. 24)
  • “[E]conomic and technological considerations favor the use of horizontal drilling for shale gas development.” (Chapter 5, p. 5-17)

Protecting the Environment and Minimizing Impacts

  • “Therefore, in areas developed by horizontal drilling using multi-well pads, it is expected that fewer access roads as a function of the number of wells would be constructed. Industry estimates that 90% of the wells used to develop the Marcellus Shale would be horizontal wells located on multi-well pads. This method provides the most flexibility to avoid environmentally sensitive locations within the acreage to be developed. (Executive Summary, p. 7)
  • “Overall, there clearly is a smaller total area of land disturbance associated with horizontal wells for shale gas development than that for vertical wells.” (Executive Summary, p. 7)
  • “Industry estimates the average size of a multi-well pad for the drilling and fracturing phase of operations at 3.5 acres.11 Average production pad size, after partial reclamation, is estimated at 1.5 acres for a multi-well pad.” (Chapter 5, p. 5-11)
  • No significant adverse impacts are identified with regard to the disposal of liquid wastes.” (Executive Summary, p. 12)
  • “Horizontal extraction of gas resources underneath State lands from well pads located outside this area would not significantly impact this valuable habitat on forested State lands.” (Executive Summary, p. 19)
  • “Although the options include vertical drilling and single-well pad horizontal drilling, the Department anticipates that multi-well pad horizontal drilling (which results in the lowest density and least land disturbance) will be the predominant approach.” (Chapter 5, p. 5-16)
  • “This method [multi-well pads with horizontal drilling] provides the most flexibility to avoid environmentally sensitive locations within the acreage to be developed and significantly reduces the number of needed well pads and associated roads.” (Chapter 5, p. 5-23)
  • “Subsequent to drilling and fracturing operations, associated equipment is removed. Any pits used for those operations must be reclaimed and the site must be re-graded and seeded to the extent feasible to match it to the adjacent terrain. Department inspectors visit the site to confirm full restoration of areas not needed for production.” (Chapter 5, p. 5-134)

Protecting Water Supplies and Using Resources Responsibly

  • “Chapters 5 and 6 contain analyses that demonstrate that no significant adverse impact to water resources is likely to occur due to underground vertical migration of fracturing fluids. (Executive Summary, p. 11)
  • “A supporting study for this dSGEIS concludes that it is highly unlikely that groundwater contamination would occur by fluids pumped into a wellbore for hydraulic fracturing. (Executive Summary, p. 11)
  • “[T]here is no likelihood of significant adverse impacts from the underground migration of fracturing fluids.” (Executive Summary, p. 12)
  • “The HVHF process involves the controlled use of water and chemical additives, pumped under pressure into the cased and cemented wellbore. Hydraulic fracturing occurs after the well is cased and cemented to protect fresh water zones and isolate the target hydrocarbon-bearing zone, and after the drilling rig and its associated equipment are removed.” (Executive Summary, p. 8 )
  • “[A]t peak activity high-volume hydraulic fracturing would result in increased demand for fresh water in New York of 0.24%. Thus, water usage for HVHF represents a very small percentage of water usage throughout the state.” (Executive Summary, p. 9-10)
  • “Horizontal extraction of gas resources underneath Primary Aquifers from well pads located outside this area [500-foot buffer zone] would not significantly impact this valuable water resource.” (Executive Summary, p. 18)
  • “Based on this data, between approximately 84 and 90 percent of the fracturing fluid is water; between approximately 8 and 15 percent is proppant [i.e. sand]; the remainder, typically less than 1 percent consists of chemical additives.” (Chapter 5, p. 5-50)
  • “The Department’s staff reviews the proposed casing and cementing plan for each well prior to permit issuance. Permits are not issued for improperly designed wells, and in the case of HVHF, the as-built wellbore construction would be verified before the operation is allowed to proceed.” (Executive Summary, p. 22)
  • “Hydraulic fracturing occurs after the well is cased and cemented to protect fresh water zones and isolate the target hydrocarbon-bearing zone, and after the drilling rig and its associated equipment have been removed.” (Chapter 5, p. 5-88)
  • “Current water withdrawal volumes when compared to withdrawal volumes associated with current natural gas drilling indicates that the historical percentage of withdrawn water that goes to natural gas drilling is very low. The amount of water withdrawn specifically for high-volume hydraulic fracturing also is projected to be relatively low when compared to existing overall levels of water use.” (Chapter 6, p. 6-12)

Click the image below to see the projected water demands for production in New York

Fresh Water Use in New York (millions of gallons)

(Chapter 6, p. 6-15)

  • “Industry projects a potential peak annual drilling rate in New York of 2,462 wells, a level of drilling that is projected to be at the very high end of activity…Based on this calculation, at peak activity high-volume hydraulic fracturing would result in increased demand for fresh water in New York of 0.24%.” (Chapter 6, p. 6-12)
  • “[R]egulatory officials from 15 states have recently testified that groundwater contamination from the hydraulic fracturing procedure is not known to have occurred despite the procedure’s widespread use in many wells over several decades.” (Chapter 6, p. 6-51)
  • “ICF’s conclusion is that ‘hydraulic fracturing does not present a reasonably foreseeable risk of significant adverse environmental impacts to potential freshwater aquifers’.” (Chapter 6, p. 6-52)
  • “[T]he developable shale formations are vertically separated from potential freshwater aquifers by at least 1,000 feet of sandstones and shales of moderate to low permeability…[M]ost of the bedrock formations above the Marcellus Shale are other shales. That shales must be hydraulically fractured to produce fluids is evidence that these rocks do not readily transmit fluids. The high salinity of native water in the Marcellus and other Devonian shales is evidence that fluid has been trapped in the pore spaces for a significant length of time, implying that there is no mechanism for discharge.” (Chapter 6, p. 6-53)
  • “All of the above factors that inhibit vertical fracturing fluid migration would also inhibit horizontal migration beyond the fracture zone for the distances required to impact potable water wells in the Marcellus and other shales from high-volume hydraulic fracturing under the conditions specified by ICF.” (Chapter 6, p. 6-54)
  • Existing construction and cementing practices and permit conditions to ensure the protection and isolation of fresh water would remain in use, and would be enhanced by Permit Conditions for high-volume hydraulic fracturing.” (Chapter 7, p. 7-42)
  • “As detailed in this document, potential impacts to ground water from the high-volume hydraulic fracturing procedure itself are, in most cases, not anticipated.” (Chapter 7, p. 7-58)
  • “The presence of 1,000 feet of low-permeability rocks between the fracture zone and a drinking water source serves as a natural or inherent mitigation measure that protects against groundwater contamination from hydraulic fracturing.” (Chapter 7, p. 7-60)
  • “[O]nsite treatment of flowback water for purposes of reuse is currently being used in Pennsylvania and other states…The use of onsite treatment and reuse facilities reduces the demand for fresh water and provides effective mitigation of potential adverse impacts.” (Chapter 7, p. 7-67)

Minimizing Emissions and Protecting Air Quality

  • “If no gathering line exists, well testing necessitates that produced gas be flared. However, operators have reported that for Marcellus Shale development in the northern tier of Pennsylvania, flaring is minimized by construction of the gathering system ahead of well completion. Flaring is necessary during the initial 12 to 24 hours of flowback operations while the well is producing a high ratio of flowback water to gas, but no flow testing that requires an extended period of flaring is conducted.” (Chapter 5, p. 5-132)
  • “Flowback water is routed through separation equipment to separate water, gas, and sand. Initially, only a small amount of gas is vented for a period of time. Once the flow rate of gas is sufficient to sustain combustion in a flare, the gas is flared for a short period of time for testing purposes. Recovering the gas to a sales gas line is called a “reduced emissions completion (REC).” See Section 6.6.8 for further discussion of RECs. Normally the flowback gas is flared when there is insufficient pressure to enter a sales line, or if a sales line is not available.” (Chapter 6, p. 6-101)
  • “Thus, total HAPs emissions from a well pad would be much less than even the major source threshold of 10 TPY for a single HAP.” (Chapter 6, p. 6-107)
  • “It should be noted that no emissions of criteria pollutants resulting from uncontrolled venting of the gas are expected.” (Chapter 6, p. 6-112)
  • “The results indicate that all of the ambient standards and PSD increments would be met by the multiple well drilling activities at a single pad, with the exception of the 24-hour PM10 and PM2.5 impacts. In fact, the 3 hour (and very likely the annual) SO2 impacts are below the corresponding significant impact levels.” (Chapter 6, p. 6-130)
    • “[O]ne practical measure to alleviate the PM10 and PM2.5 standard exceedances is to raise the stacks on the rig and hydraulic fracturing engines and/or erect a fence at a distance surrounding the pad area in order to preclude public access. Without further modifications to the industry stack heights, a fence out to 500m would be required, but this distance could be reduced to 150m with the taller stacks and a redefinition of the background levels. Alternately, there is likely control equipment which could significantly reduce particulate emissions.” (Chapter 6, p. 6-131)
  • “Thus, the relative percent of Marcellus well drilling emissions to the existing baseline is highly likely to be substantially less than the value above using the worst case estimates.” (Chapter 6, p. 6-171)
  • “The results show that the total NOx and VOC emissions [from truck traffic] are estimated to be 687 and 70 tons/year, respectively, and are expected to increase the existing baseline emissions by 0.66 and 0.17 percent. The maximum increase for any pollutant is 0.8 percent. These increases are deemed very small.” (Chapter 6, p. 6-173)
  • “Vented sources are defined as releases resulting from normal operations. Vented emissions of CH4 can result from the venting of natural gas encountered during drilling operations, flow from the flare stack during the initial stage of flowback, pneumatic device vents, dehydrator operation, and compressor start-ups and blowdowns.” (Chapter 6, p. 6-185)
  • “[R]elative to combustion and process emissions, fugitive CH4 and CO2 contributions are insignificant.” (Chapter 6, p. 6-186)

Protecting Against Methane Leaks

  • “Well construction associated with HVHF presents no new significant adverse impacts with regard to potential gas migration. Gas migration is a result of poor well construction (i.e., casing and cement problems).” (Executive Summary, p. 11)
  • “Methane contamination of groundwater is often mistakenly attributed to or blamed on natural gas well drilling and hydraulic fracturing. There are a number of other, more common, reasons that well water can display sudden changes in quality and quantity.” (Chapter 4, Pg. 4-40)
  • “In April 2011 researchers from Duke University (Duke) released a report on the occurrence of methane contamination of drinking water associated with Marcellus and Utica Shale gas development…The analysis showed minimal amounts of methane in this sample group, with concentrations significantly below the minimum methane action level (10 mg/L) to maintain the safety of structures and the public, as recommended by the U.S. Department of the Interior, Office of Surface Mining. The water well located in the active gas extraction area had 5 to 10 times less methane than the wells located in the inactive areas.” (Chapter 4, p. 4-41)
  • “The dSGEIS acknowledges that migration of naturally-occurring methane from wetlands, landfills and shallow bedrock can also contaminate water supplies independently or in the absence of any nearby oil and gas activities.” (Executive Summary, p. 11)
  • “Section 4.7 of this document explains how the natural occurrence of shallow methane in New York can affect water wells, which needs to be considered when evaluating complaints of methane migration that are perceived to be related to natural gas development.” (Chapter 6, p. 6-41)
  • Hydraulic fracturing is not known to cause wellbore failure in properly constructed wells.” (Chapter 6, p. 6-51)

Protecting Workers and the General Public

  • “[B]ased on the analytical results from field-screening and gamma ray spectroscopy performed on samples of Marcellus Shale NORM [naturally occurring radioactive material] levels in cuttings are not significant because the levels are similar to those naturally encountered in the surrounding environment.” (Executive Summary, p. 13)
  • “[T]he results [of gamma ray spectroscopy tests], which indicate levels of radioactivity that are essentially equal to background values, do not indicate an exposure concern for workers or the general public associated with Marcellus cuttings.” (Chapter 5, p. 5-34)
  • “Based upon currently available information it is anticipated that flowback water would not contain levels of NORM of significance, whereas production brine could contain elevated NORM levels. Although the highest concentrations of NORM are in produced waters, it does not present a risk to workers because the external radiation levels are very low.” (Executive Summary, p. 16-17)

Continually Improving Efficiency

  • “Service companies design hydraulic fracturing procedures based on the rock properties of the prospective hydrocarbon reservoir. For any given area and formation, hydraulic fracturing design is an iterative process, i.e., it is continually improved and refined as development progresses and more data is collected.” (Chapter 5, p. 5-84)
  • “More people are present to monitor operations at the site during high-volume hydraulic fracturing and flowback operations than at any other time period in the life of the well pad. Therefore, any surface spills during these operations are likely to be quickly detected and addressed rather than continue undetected for a lengthy time period.” (Chapter 7, p. 7-76)

The Truth about Earthquakes and Seismic Activity

  • “Information reviewed indicates that there is essentially no increased risk to the public, infrastructure, or natural resources from induced seismicity related to hydraulic fracturing… [N]o significant adverse impacts from induced seismicity are expected to result from HVHF operations.” (Executive Summary, p. 17)
  • “The microseisms created by hydraulic fracturing are too small to be felt, or to cause damage at the ground surface or to nearby wells.” (Chapter 6, p. 6-213)
  • “[S]tudies in Texas also indicate that hydraulic fracturing is not likely the source of the earthquakes.” (Chapter 6, p. 6-213)
  • “[A]n independent pre-drilling seismic survey probably is unnecessary in most cases because of the relatively low level of seismic risk in the fairways of the Marcellus and Utica shales.” (Chapter 6, p. 6-213)
  • “Wells are designed to withstand deformation from seismic activity. The steel casings used in modern wells are flexible and are designed to deform to prevent rupture. The casings can withstand distortions much larger than those caused by earthquakes, except for those very close to an earthquake epicenter. The magnitude 6.8 earthquake event in 1983 that occurred in Coalinga, California, damaged only 14 of the 1,725 nearby active oilfield wells, and the energy released by this event was thousands of times greater than the microseismic events resulting from hydraulic fracturing.” (Chapter 6, p. 6-212)

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