NOTE: Please do not cite these comments verbatum. Please use these only as a guide for writing your own comments.
January 4, 2013
Attn: Draft HVHF Regulations Comments
New York State Department of Environmental Conservation
625 Broadway
Albany, NY 12233-6510
Dear Commissioner Martens,
I submit the following comments on the draft HVHF regulations, but first I must protest the process by which these draft regulations have been released for comment without a credible health impact study and before the revised SGEIS is finalized, required by law to inform the drafting of regulations. The DEC has also placed undue burden on citizens, organizations, and municipalities to prepare comments on highly technical regulations with a minimal 30 days over the holidays, thereby squelching meaningful public participation. Due to the inherent risks to health, the environment, economies, and community character, hydrofracking must not be permitted in New York anytime in the foreseeable future. Notwithstanding this, I submit the following:
1. CHEMICALS AND DISCLOSURE
Sections 560.3(d) Hydraulic Fracturing Fluid Disclosure and 560.3(h) Hydraulic Fracturing Fluid Disclosure Following Well Completion fail to require full disclosure of all chemicals used in the fracking process. The draft regulations allow applicants to withhold identification of chemicals asserted to be "trade secrets". This provision, combined with disclosure exemptions granted by the EPA, puts New York's citizens at risk of exposure to dangerous unknown chemicals. In addition, by failing to require a comprehensive registry of all chemicals used without exception, the regulations block access to critical information by medical professionals investigating causes of illness and trying to treat their patients who may become sick due to industrial chemicals exposure. The DEC should establish a clear regulatory requirement that all chemicals used in the fracking process--without exception--be disclosed in a registry readily accessible to the public.
Chemical additives make up only 2% of frack fluid, yet the total volume of water estimated per well is 2.4 - 7.8 million gallons. At 1,600 wells annually, 76.8 million to 249.6 million gallons of chemicals would be used per year. Several are known carcinogens, endocrine disruptors, or are otherwise dangerous. Since wastewater treatment facilities in New York are not equipped to remove many of the chemicals that return to the surface as flowback, these will accumulate in the environment and pose an increasing threat to public health. Filtering systems used by public water supplies are not be capable of removing these chemicals either.
Despite growing evidence, not a single carcinogen or toxic chemical has been deemed unsafe in the regulations. Certain chemicals like benzene, dangerous at even very low concentrations, should be prohibited. In communities where fracking occurs, scientific studies tracking the effects of chemicals have shown increases in childhood leukemia, neural tube birth defects, and childhood asthma. The regulations should be revised to prohibit the use of BTEX chemicals and other toxic additives in the fracking process.
The above underscores failure of the proposed regulations to protect human health and the critical need for an independent Comprehensive Health Impact Study.
2. DISPOSAL OF FRACKING WASTE
I submit the following comments relating to one of many problems with the draft regulations, specifically the management of process wastes from oil and gas production in New York.
6 NYCRR Part 364.1 (e): Waste Transporter Permits: Exceptions
Paragraph (1) of this section states: "Rail, water and air carriers are exempt from the requirements of this Part."
This paragraph should be repealed with respect to oil and gas development wastes, particularly for rail and water transport.
6 NYCRR Part 371.1 (e) (2): Identification and Listing of Hazardous Wastes: Exclusions
Exclusions from being listed as hazardous wastes include paragraph (v): "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy", regardless of whether they contain substances which are defined as hazardous in 6 NYCRR Parts 371 and 597 – and many of them do. This contradiction-introducing paragraph should be repealed.
6 NYCRR Part 550.3: Definitions
"Subdivisions (a) through (g) of Section 550.3 are unchanged."
This segment of unchanged language includes §550.3 (f), which states: "Brine is synonymous with salt water." The related definition of salt water, formerly §550.3 (at) but now re-designated (av), states: "Salt water shall mean any water containing more than 250 parts per million of sodium chloride or 1,000 parts per million of total dissolved solids." These two sentences constitute the only descriptions of flowback fluids, production brines, organic chemical condensates, or any other process wastes in the entire canon of definitions in Section 550.3. Indeed, "waste", formerly listed as §550.3 (ax), but now designated (bb), is defined as follows:
"Waste shall mean:
(1) physical waste, as that term is generally understood in the oil and gas industry;
(2) the inefficient, excessive, or improper use of, or the unnecessary dissipation of reservoir energy;
(3) the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well or wells in a manner which causes, or tends to cause, reduction in the quantity of oil or gas ultimately recoverable from a pool under prudent and proper operations, or which causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas;
(4) the inefficient storing of oil or gas;
(5) the flaring of gas produced from an oil or condensate well after the department has found that the utilization thereof, on terms that are just and reasonable is, or will be within a reasonable time, economically feasible."
This definition for "waste" clearly has no relationship to oil or gas industrial process wastes. And one does not need to be a chemist to understand that the two definitions which are given for brine and salt water do not begin to describe the materials which flow as by-products from oil and gas wells developed in New York or any other place. In fact, they are so simplistic as to be negligently misleading. Therefore, NO WORKING DEFINITIONS FOR PROCESS WASTES RELATED TO OIL AND GAS PRODUCTION EXIST IN THIS SECTION OF NEW YORK REGULATIONS. I am surprised that permits for petroleum extraction projects or the disposition of their process wastes could have been legally approved with such weak regulatory constructs in place. Moreover, improved language to address these issues is sequestered in the new Part 560.2, paragraphs (2), (3), (6), (8), (12), (13), (22) and (23), where it has no practical effect on industrial activity not defined as "high volume". Therefore, even though the DEC acknowledges a need for regulation of chemicals disclosure and definition of process wastes, the changes proposed are worthless for conventional oil and gas projects targeting "tight" rock formations, which utilize chemicals indistinguishable from high-volume projects except for by the quantities consumed and disposed. The DEC should adopt regulations on chemical disclosure and the definition of process wastes that will apply to all wells, not just HVHF wells.
6 NYCRR Part 554.1 (c): Prevention of pollution and migration
The new language of Paragraph (1) includes references to drilling mud, flowback water and production brine, which have no antecedents in Part 550.3: Definitions, as stated above. The new language requires owners or operators to state that they will maximally reuse or recycle used drilling, flowback and production fluids, without any consideration that the means of recycling or re-use involve the applications of heat (for facilitated evaporation) and pressure (for reverse osmosis), which promote chemical reactions that, given the complex mixtures involved, have never been studied. Again, one need not be a chemist to grasp that this simplistic requirement is a recipe for disaster. Revised regulatory language should require public reporting on the products resulting from the attempted reuse or recycling of waste fluids prior to acceptance of any disposal plan.
The new language also mentions the importance of noting the history of other drilling operations in the area, but makes no mention of an even more important factor: the regulatory compliance history of the applicant. This paragraph should be revised to ensure that the compliance history of the applicant is evaluated for each owner / operator who submits an application.
Paragraph (4) of Part 554.1 opens the possibility of beneficial re-use of drill cuttings as solid wastes, as specified in 6 NYCRR Part 360-1.15: Beneficial Use Determinations. However, certain drill cuttings, including some of those from the Marcellus Shale formation, are too radioactive or otherwise environmentally toxic to be safely re-used in any context. The re-use (road-spreading, asphalt manufacture, etc.) of oil and gas process wastes should be prohibited.
6 NYCRR Part 560.2: Definitions
Conspicuously absent from the definitions in this section and from Part 550.3 are any references to by-products and wastes released primarily to the air, or the major pieces of equipment responsible for such releases, such as chemical processing facilities using glycol dehydrators, and compressor facilities. At a minimum, the following terms should be defined in this section and in Part 550.3: diesel exhaust particulates, ozone, silica dust, and volatile organic compounds (VOC) including benzene, toluene, ethylbenzene, xylenes (BTEX), and polycyclic aromatic hydrocarbons (PAH).
6 NYCRR 560.5 (f): Drilling and Production Waste Tracking Form
As mentioned above, the proposed regulations contain no mention of wastes released primarily to the air by oil and gas development projects. Since they can negatively impact the health of humans and other organisms nearby, waste products released to the air must be monitored and reported. The Drilling and Production Waste Tracking Form should be modified to include measurements of diesel exhaust particulates, ozone, silica dust, and volatile organic compounds which are released from each project site. Measuring equipment should be required to be fixed in place and continuously operational at various points, so as to be capable of monitoring substance releases in varying wind conditions. This section should also require the reporting of any releases of aerosols or powders which are not on this list.
6 NYCRR 560.7: Waste Management and Reclamation
Paragraphs (a) and (b) prescribe the timely removal of fluids and other materials from pits. Overall, the use of pits for oil and gas production is very vaguely described and poorly organized. Whether and how they may be used for flowback fluids and production brines in projects requiring less than 300,000 gallons of completion fluids remains unclear, but it appears that they may be so used for such projects. Whether they could be used as contingency receivers in HVHF projects (as has happened in other states) is also unclear. The use of open pits for oil and gas development in New York should be summarily prohibited—regardless of fracking fluid volume.
Paragraphs (c), (d) and (e) prescribe conditions for on-site burial (encapsulation) of certain drill cuttings. On-site burial of drill cuttings should be summarily prohibited. In the event that the DEC disagrees with this assessment, the specific place where any cuttings are encapsulated underground should be mapped and marked for future reference.
Paragraph (i) prescribes the testing of flowback fluids and production brines for radioactivity. This paragraph should be revised to include a standard or maximum contaminant level, and to clarify that certain parties (landfills, treatment centers, general public) will have access to the test results.
6 NYCRR Part 750-3.2 Definitions
The new definitions in this Division of Water section, especially (5), (7), (8), (14), (15), (18), (19), (20), (30), (31), (33), (38), (39), (40), (41), (42), (45), (51) and (52) should be harmonized with the Division of Solid Waste definitions section (Part 360-1.2), and the Division of Mineral Resources definitions sections (Part 550.3 and 560.2). That this has not been done is emblematic of a larger problem: the lack of inter-divisional coherence which currently exists in the New York Code of Rules and Regulations.
6 NYCRR Part 750-3.11: HVHF General Permit
Paragraph (c) clarifies that "An HVHF general permit does not authorize the discharge of hazardous substances (as listed in Part 597) or petroleum." Because of the heavy reliance of Part 597 on Part 371, it is critical for the contradictory language of Part 371.1 (e) (2) titled Exclusions to be repealed, as noted earlier in this letter.
6 NYCRR Part 750-3.12: Disposal of HVHF Wastewater
Paragraph (b) leaves open the possibility of beneficial use determinations (BUD) for flowback fluids by the Division of Solid Waste under Part 360-1.15. Given the difficulties of assessing and updating the chemical composition of these fluids, this loophole should be eliminated.
Paragraph (c) prescribes requirements for acceptance, treatment and disposal of HVHF wastewater at publically owned waste treatment works (POTW's). These facilities are not designed to process industrial wastes, particularly those with such disparate components as radioisotopes, biocides, oil- and polymer-based lubricants, endocrine-disrupting compounds, resin-coated proppant materials and toxic heavy metals. Therefore, flowback fluids and production brines from oil and gas projects should not be accepted at these facilities; this paragraph should be replaced by a prohibition on this treatment option.
Paragraph (d) prescribes requirements for acceptance, treatment and disposal of HVHF wastewater at privately owned industrial treatment facilities. This is an appropriate destination of these wastes, but a new provision should be added that aggregates the combined effluent limits for individual facilities within a watershed in setting these limits.
Paragraph (f) describes requirements for deep well injection of HVHF wastewater, which is primarily regulated by the Federal EPA's Underground Injection Program. Sub-paragraph (5) provides that the DEC "may propose additional monitoring, recording and reporting requirements in a State Pollution Discharge Elimination System (SPDES) permit". In view of the 5-year update cycle imposed by the USEPA, within which changes or anomalies may not be reported, the DEC should replace the language of (f) (5) "may propose" to "shall propose", and shorten the update period to 12 months or less.
Overall, I find that the proposed regulations regarding process wastes from oil and gas production in New York are riddled with deficiencies which include lack of harmonization among sections overseen by different Divisions of the DEC, lack of comprehension of the similarity of conventional and HVHF oil and gas productions technologies (except for scale), lack of rigor in defining the responsibilities of industry operators, and lack of appreciation for how problematic the disposal of oil and gas process wastes is likely to become. Thank you for your attention to these comments.
3. DRINKING WATER SUPPLIES
Sections 560.4(a)(5) and 750.3-3(a)(4) contain similar requirements for 2000ft setbacks from reservoirs, lakes, manmade drinking water supply sources, public supply wells and springs. The setback is half of the more stringent 4000ft requirement which applies to NYC and Syracuse watersheds. According to the rdSGEIS, this is because New York state public water supplies outside of New York City and Syracuse have not been granted Filtration Avoidance Determination exemptions by the EPA. However, none of the filtering systems used by New York State municipalities are designed to remove the chemicals in fracturing fluid or drilling waste. The rdSGEIS notes that filtering dissolved chemicals from the fracturing and drilling process is virtually impossible, or prohibitively expensive. The claim that public water supplies outside of New York City and Syracuse are "filtered" is therefore irrelevant.
Further, the 4000ft setback granted to New York City and Syracuse applies to their entire watersheds—i.e. not only specific water bodies serving as storage, but also all tributaries and surfaces that drain to those supplies. For the rest of New York State, the regulations prohibit well pads within 2000 ft of water supply intakes or within 1000 ft of tributaries one mile upstream. Based on outdated and inadequate provisions of Section 553.2, just beyond this one mile distance, DEC would require no more than 50 ft of separation between a well and the same waterway.
DEC implies that any pollutants from a well-site found in a tributary would naturally remove themselves from the water column during their one mile journey downstream, a very different approach than the one granting whole watershed protection to New York City. And no explanation is given for the 1000ft separation between a well pad and tributary, compared to the 2000ft or 4000ft distances above. These arbitrary thresholds suggests the DEC believes the physical properties of water, fracking chemicals, and their solubility are different upstate and downstate.
Also, provisions of Section 750-3.3(a)(5) differ from the DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing," specifying 500ft setbacks to tributaries of surface public water drinking supplies without a one-mile limitation. Since these provisions apply only to HVHF wells, DEC could permit a well using 299,999 gallons of fracking fluid right next to a municipal drinking water supply, limited only by the 50ft minimum requirement provided by Section 553.2 of the old regulation.
The regulations also don't address other activities/infrastructure present at the well site or within the spacing unit, including storage of HVHF materials, tanks, trucks, parking areas, and pipelines. Because these industrial features are potential sources of leaks or contamination, they should be prohibited within appropriately defined setbacks too.
Since current public filtration systems can't remove frack fluid and flowback chemicals, all public water supplies should receive the same level of protection as the New York City and Syracuse watersheds. The regulations should be revised to require a 4000ft setback from all public drinking water supplies and their tributaries.
The regulations must require setbacks for tanks, chemicals, material storage, pipelines, access roads, parking or other ancillary gas development activities equal to those for public drinking water supplies, whether such features are located on the well pads or elsewhere at a well site or within a spacing unit.
4. ECOLOGICAL IMPACTS
The DEC has failed to adequately address the significant negative large-scale and cumulative impacts relating to loss of biodiversity, habitat fragmentation, wildlife disturbance, and disruption of functional ecosystems that will result from the widespread proliferation of industrial drilling and related infrastructure. There is growing evidence of significant impacts to wildlife and habitat from gas development, such as in Wyoming where Mule deer and pronghorn populations have dropped substantially in areas of heavy fracking, and in Pennsylvania where a USGS report concluded that gas drilling is contributing to fragmentation and loss of habitat. In a 2011 study of potential impacts from fracking in Tioga County, the New York chapter of The Nature Conservancy determined that disturbance of key forest areas would be extensive in a high development scenario, further recommending that the state make the reduction of well pad sitings in forest land a priority.
Some of these topics were discussed generally in the 2011 draft SGEIS, however DEC proposed only miniscule measures described vaguely as potential "permit conditions" that would apply in very few places. In fact none of the forests in Tioga County, the focus of TNC's recent study, would receive any protection despite the fact that 61% of the county is forested. Reflecting a flawed understanding of cumulative impacts, the "mitigation" measures discussed by DEC (which only appear to require documentation and monitoring of birds) are woefully inadequate, lacking any concrete avoidance requirements or parameters with which to gauge compliance. Moreover, they are not even referenced in the draft regulations. Simply put, if New York State is subjected to the scale of gas development that has begun in Pennsylvania, DEC's proposed regulatory structure will not be nearly enough to prevent large scale collapse of forests, grasslands, or other ecosystems important to the Southern Tier and other areas where fracking could become widespread.
Addressing the large scale ecological impacts of shale gas development is fundamentally not possible through a permitting program that neglects infrastructure and only considers the impacts of one well at a time. The only way of effectively managing large regional landscapes to ensure that ecological integrity can be maintained is through a coordinated program that considers reasonably anticipated build-out with attention to the cumulative impacts of multiple drilling pads and infrastructure. With the advent of high-volume fracking, in order to meet its statutory obligation of protecting natural resources, DEC would need to develop a comprehensive regulatory program that is very different from how it has historically regulated the gas industry or is now proposing to do so through the current set of draft regulations. Such a program would need to holistically oversee all aspects of gas development, be adequately staffed, and committed to enforcement.
To protect the ecological integrity of regions exposed to fracking, DEC should develop a comprehensive regulatory program that includes the following elements:
A comprehensive phase-in and phase-out schedule of production areas to identify where and when gas development may be permitted, thus preventing the simultaneous widespread proliferation of well pads and infrastructure over very large regions. This would require analysis by experts in GIS modeling and large landscape ecology to determine a configuration of gas production areas where fracking could be temporarily authorized (active phase) while ensuring that lands outside of those areas persist as large intact blocks of habitat connected by contiguous forested corridors several miles wide--free of well pads, infrastructure, and other activities associated with shale gas development.
A strict requirement that all drilling, fracking, construction of infrastructure, and partial reclamation activities be completed (dormant phase) before drilling is authorized in the next scheduled area. Any refracking that occurs would have to wait until adjacent areas are no longer active.
Prohibition of gas development within certain premium habitats, including but not limited to "forest focus areas" and "grassland focus areas" identified in the 2011 revised draft SGEIS. (These areas by definition contain the highest quality habitat with greatest biodiversity.) The regulations should require the use of multi-well pads located at least one mile apart in all forests.
A restoration plan, bonded to ensure completion, for all areas impacted by gas development and related infrastructure (not just the well pad); and a meaningful mitigation program to compensate for habitat loss or degradation that cannot be avoided. (Such a program could involve the fee-simple dedication of land for preservation, assignment of conservation easements, or contribution to a natural land acquisition program.)
A rigorous monitoring system involving the participation of not only industry personnel, but also DEC field staff with biological expertise to ensure that protection efforts are enforced and successful. Vague measures described in the 2011 revised draft SGEIS and proposed Environmental Assessment Form (appendix 6) are insufficient.
Regulations relating to the application and permitting process should be revised to require that the applicant submit an entire project as a package for review, rather than piecemeal, one well or spacing unit at a time. The aforementioned package should contain written descriptions and maps depicting all proposed well pads, spacing units, and property boundaries within the project area, in addition to all related infrastructure including gathering lines, compressor stations, access roads, pits, water impoundments, quarries, camps, and mitigation areas (if applicable). As part of the application process, the applicant should provide a comprehensive assessment of all impacts within boundaries of the project, as well as off-site impacts and influences such as water inflow/outflow, habitat connectivity, wildlife corridors, and air movement.
In addition to requiring approval by DEC, the regulations should clearly require that any project, regardless of size, be consistent with local laws and receive approval by the governing body of the local municipality in which it is proposed.
Well sites and well pads where high-volume hydraulic fracturing takes place are areas of intense industrial activity, involving the use of dangerous machinery and toxic chemicals. These areas must remain secure during all stages of the drilling and fracking process. The 2011 revised draft SGEIS discusses fencing to prevent livestock access, but only for "active pastures" located in designated Agricultural Districts and only for operations that disturb more than 2.5 acres. This fails to protect people, livestock outside of designated Agricultural Districts, and wildlife. Furthermore, DEC has only contemplated fencing as a possible permit condition, failing to include any requirement for this in the draft regulations.
To adequately protect people, wildlife, and livestock, the regulations should be revised to clearly require appropriate security measures and fencing, without exception, around all well pads or portions of the well site that contain drilling equipment, tanks, pits, chemicals, or garbage, regardless of the location or size of the disturbed area.
6. FINANCIAL SECURITY DEEPER WELLS
I offer the following comments with regard to the amount of financial security for wells deeper than 6,000 feet.
The DEC has correctly required that "The owner of an oil, gas or solution mining, storage stratigraphic, geothermal or disposal well that exceeds or is expected to exceed 6,000 feet in true measured depth must file financial security for that well in an amount based on the anticipated costs of plugging and abandoning that well to the satisfaction of the department in accordance with Part 555 of this Title." It is very clear in this sentence that the amount of security must cover the cost for that specific well. This sentence meets the stated purpose of the regulation as per the last sentence on page 9 of the Revised Regulatory Impact Statement, which states: "The Department proposes to remove the cap to require operators to post financial security in an amount that reflects the true costs of plugging a deep well. Although this change will increase costs to the regulated community, it is necessary to have adequate financial security in place to advance the public policy goals of ensuring that wells are properly plugged and abandoned to prevent such wells from becoming a pathway to contamination." (Emphasis added) This intent is commendable.
However, the very next sentence in Part 551.6 opens up the possibility that DEC might limit the total amount of financial security an owner might be required to establish to less than the sum of the financial security that would be required for all of an owner's wells: "However, the owner is not required to file financial security under this section exceeding an amount specified by the department, regardless of the number of wells described in this section that an owner may have." Any limit on the total amount of financial security below the amount that would be required to properly plug and abandon every single well that an operator is permitted to drill, flies in the face of the stated intent of Part 551.6. If the full total cost of plugging and abandoning all of an operator's wells is not covered by financial security, New York taxpayers face the uncovered cost or the very risk of contamination that Part 551.6 is intended to avoid.
The second sentence of Part 551.6 should be deleted or modified to make clear that the total of an owner's financial security must equal the sum of the individual financial security requirements for all of that owner's wells.
In addition, the Department should adjust financial security requirements annually to account for any anticipated increase in the cost of plugging wells. This adjustment is needed to protect the taxpayers and residents of New York from the expense of plugging cost escalation over the period from when the well is drilled until it is plugged.
7. FINANCIAL SECURITY SHALLOWER WELLS
I offer the following comments regarding the amount of financial security for wells less than 6,000 feet deep.
The provisions Part 555.5(a)(1 through 5) on the method of plugging wells apply to all wells covered by Parts 550 through 556 and 560 without regard to the depth of the well.
In the first sentence of the revised Part 551.6 the Department has required "The owner of an oil, gas or solution mining, storage stratigraphic, geothermal or disposal well that exceeds or is expected to exceed 6,000 feet in true measured depth must file financial security for that well in an amount based on the anticipated costs of plugging and abandoning that well to the satisfaction of the department in accordance with Part 555 of this Title."
This requirement of Part 551.6 assures that the Department can require financial security sufficient to cover the cost of plugging the well. However, Part 551.5 Amount of financial security: wells up to 6,000 feet deep requires fixed amounts per well with no relationship to the anticipated plugging costs. It also puts a total dollar limit on the amount of financial security that an owner would have to provide, so that the total amount of security for several wells may be less than the total cost of plugging all of those wells. This provides owners with a volume discount on the amount of security they have to provide, so that the total amount of security may be significantly less than the actual total cost of plugging the same number of wells. Such a weak system of financial security exposes New York taxpayers to the cost of plugging wells—an expense that is rightfully the responsibility of the owner—or to the risk of unplugged wells.
Part 551.5 should be rewritten to provide that financial security for all wells up to 6,000 feet (True Measured Depth) must have financial security sufficient to cover the anticipated cost of plugging each well such that all wells are to have the full amount of financial security. Alternatively, Parts 551.5 and 551.6 could be combined with these same security provisions.
In addition, the Department should adjust financial security requirements annually to account for any anticipated increase in the cost of plugging wells. This adjustment is needed to protect the taxpayers and residents of New York from the expense of plugging cost escalation over the period from when the well is drilled until it is plugged.
8. FINDING UNPLUGGED WELLS
It has been estimated that there are tens of thousands of old unplugged, abandoned oil or gas wells in New York State. Each of these pose a threat of serving as a conduit for the transmission of methane, fracking fluid and chemicals to the aquifer or surface if fracking occurs nearby. In fact this was recently documented to have occurred in Tioga County, Pennsylvania where hydraulic fracking led to the eruption of gas and water from an abandoned well drilled in 1932. (http://stateimpact.npr.org/pennsylvania/2012/10/09/perilous-pathways-how-drilling-near-an-abandoned-well-produced-a-methane-geyser/) The 2011 revised draft SGEIS (appendix 11) also acknowledges that communication between fracking and old unplugged wells can occur, stating "an undetected and unplugged wellbore could exist that directly connects the hydraulic fracture zone to an aquifer."
Section 552.1(b) and Section 556.2(b)(8) of the draft regulations requires identification of old abandoned wells within the spacing unit or within one mile of a well to be fracked. However, nowhere in the draft regulations does there appear to be any requirement that old wells be plugged before fracking commences. This is a baffling omission. The draft regulations should specifically require that all unplugged wells located within the proposed spacing unit or within one mile of the surface location of the well to be fracked are properly plugged and abandoned before high-volume hydrofracking is permitted.
9. FOREST FRAGMENTATION
Fragmentation caused by the widespread proliferation of fracking is a major threat to forest ecosystems in New York. The 2011 revised draft SGEIS (Section 6.4.1) acknowledge this in stating: "As forests are the most common cover type, it is reasonable to assume that development of the Marcellus Shale would have a substantial impact on forest habitats and species." However despite this admission and a relatively good description of how ecosystems could be impacted, DEC failed to discuss meaningful concrete action to avoid forest fragmentation. Instead of limiting fracking in forests, the rdSGEIS proposed to only consider impacts in a very small percentage of New York forest land described as "forest focus areas". This was based on the DEC's misinterpretation of a study performed in 2003 by The Nature Conservancy (TNC) involving the assessment of large forest matrix blocks. As addressed in comments submitted on the 2011 rdSGEIS by TNC, it is invalid to limit attention to just these areas. According to the rdSGEIS, over half (57%) of the entire area overlain by the Marcellus shale is forested, however only a very small fraction of this is located within designated focus areas. In fact, outside of the Catskill Park, only 6% of the area over the Marcellus shale is within a Forest Focus Area according to the rdSGEIS. This has enormous adverse implications to forest ecology of New York State since DEC's approach neglects almost all of the Southern Tier's extensive forested landscape. For example, in a recent study of potential impacts from fracking in Tioga County, TNC determined that disturbance of key forest areas would be extensive in a high development scenario, further recommending that the state make the reduction of well pad sitings in forest land a priority ("An Assessment of Potential Impacts of High Volume Hydraulic Fracturing on Forest Resources", C. Lee, et al; Dec 19, 2011). Shockingly, based on the DEC's approach involving a small number of "focus areas", none of the forests in Tioga County—which represents 61% of the county's land area—would be protected.
In addition to excluding the vast majority of forest land from consideration, the DEC failed to identify any concrete requirements to avoid fragmentation, even within the very small percentage of forests that it recognizes to be of value. Rather than prohibiting fracking in designated "focus areas", the 2011 rdSGEIS stated only that applicants should perform an ecological assessment, recommend their own "mitigation" to DEC, and monitor impacts. No specific requirements were identified by DEC to avoid fragmentation or siting of wells and infrastructure in forests; no objective criteria were included for measuring acceptable levels of impact; and no substantive mitigation to actually compensate for adverse impacts to forest ecology was proposed. Furthermore, DEC only stated that the applicant's "ecological assessment" should occur in areas meeting a 150 acre threshold and consider effects on forest dwelling birds. A recent publication titled "Hydraulic Fracturing Threats to Species with Restricted Geographic Ranges in the Eastern United States"(J. Gillen, E. Kiviat, Environmental Practices, Dec 2012) which studied the potential impacts of fracking on 15 species (included mammal, salamanders, butterflies, and plants) concluded that a wide variety of species endemic to the Utica and Marcellus shale areas could be adversely impacted by effects of habitat loss, fragmentation, and increased soil salinity in forests. DEC's approach ignores these species entirely.
DEC's approach neglects the vast majority of forests potentially impacted by fracking, fails to consider the biodiversity of forest life that could be impacted, and lacks substantive requirements to avoid or minimize fragmentation and its effects. Moreover, the vague measures described by DEC in the 2011 rDSGEIS are only suggested as potential "permit conditions", none of which appear in the draft regulations, even by reference. If New York State is exposed to the scale of gas development that has begun in Pennsylvania, DEC's regulatory program will be unable to ensure that large scale collapse of forest ecosystems does not occur in the Southern Tier and other areas where fracking could become widespread. Several programmatic and regulatory measures should be taken by the DEC to address this serious environmental issue:
First, DEC should perform a GIS-based build-out analysis of gas development that can be reasonably anticipated in areas where fracking may be permitted. This analysis should consider a typical configuration of well pads and infrastructure (pipelines, access roads, compressor stations, etc). Such a build-out analysis is necessary to adequately assess cumulative effects on large-landscape level ecology.
DEC should adopt policies that specifically discourage drilling, fracking, and related infrastructure impacts within forests. Based on competent data and analysis including the expertise of professional conservation organizations like TNC, DEC should identify forests of high quality or unique ecological value that should be off-limits to drilling. Forest land qualifying for this higher level of protection may include but are not limited to the "forest focus areas" previously identified and lands ecologically linked to Catskill State Park.
Where drilling is allowed within forests, DEC should establish a managed phase-in and phase-out schedule of active production areas to control where and when gas development occurs. This is necessary to prevent the simultaneous widespread proliferation of well pads and infrastructure that could decimate wildlife populations and functional ecosystems, and to facilitate effective forest recovery. Based on large landscape analysis involving the expertise of professional conservation organizations like TNC, this would entail establishing a configuration of phase areas where fracking could be temporarily authorized while ensuring that lands outside of those areas persist as large undisturbed blocks of habitat connected by contiguous forested corridors several miles wide. All drilling, fracking, construction of infrastructure, and reclamation would have to be completed in one phase before drilling is authorized in another, and any refracking would have to wait until adjacent phases are no longer active. The regulations should require adherence to this phased plan.
The regulations should require that for any gas development that occurs within forests, well pads must be located at least one mile apart and disturb an area of no more than five acres. Ancillary surface features of gas development (for example compressor stations and processing equipment) should be consolidated and located outside of forests to the greatest extent possible. To ensure that forest impacts are minimized, DEC should require that applications be submitted as whole projects, detailing all wells pads and infrastructure proposed.
DEC should codify in the regulations specific Best Management Practices for minimizing forest fragmentation and degradation of habitat, including attention to wildlife management, edge effects, noise, and light.
The regulations should require a restoration plan, bonded to ensure completion, for all areas impacted by gas development and related infrastructure (not just the well pad).
A comprehensive "true mitigation" program should be created to compensate for habitat loss or degradation that cannot be avoided, including degradation caused by fragmentation, edge effects, and surface impacts. Such a program could involve the fee-simple dedication of land for preservation, assignment of conservation easements, or contribution to a natural land acquisition program. The parameters of this program should be adequately described in the regulations and adherence required, with references to other permit or regulatory procedures included.
DEC should establish a rigorous monitoring system involving the participation of not only industry personnel, but also DEC field staff with biological expertise to ensure that forest protection efforts are enforced and successful.
10. FRACKING VOLUME LOOPHOLE
I offer the following comments with regard to oil and gas wells using less than 300,000 gallons of base fracturing fluid in New York State.
Part 560.2(b)(14) states "(14), 'high-volume hydraulic fracturing' shall mean the stimulation of a well using 300,000 gallons or more of water as the base fluid in the hydraulic fracturing fluid per well completion. In determining whether the 300,000 gallon threshold has been met, the department will take into consideration the sum of all water-based fluids, including fresh water, and recycled flowback water used in all high-volume hydraulic fracturing stages." Under this definition the regulations would not apply to wells using less than 300,000 gallons of water as the base fracturing fluid. Such wells would fall under the 1992 GEIS and the regulations that were based on the 1992 GEIS.
The 2011 revised draft SGEIS (rdSGEIS) provides no rationale for defining wells using 300,000 gallons or more of fracturing water as "high–volume hydraulic fracturing" wells. 1992 GEIS envisioned fracturing water volumes in the 20,000- to 80,000-gallon range. 300,000 gallons would be an almost fourfold increase. The 1992 GEIS was not written to cover this new type of drilling and fracturing. No plausible rationale exists for the DEC's proposal to issue permits for wells using less than 300,000 gallons of fracturing water under the 1992 GEIS and regulations. Fracturing in tight shale formations with less than 300,000 gallons of water is much more closely related to fracturing in tight shale formations using larger volumes of water than it is to fracturing in the more conventional formations that were the targets of drilling when the 1992 GEIS was completed.
Under the DEC's proposal, wells using less than 300,000 gallons of fracturing water would not be required to use closed containers and secondary containment for fracturing additives, drilling fluids and other chemicals and fuels. Open pits and less safe casing would be permitted. Setbacks would be only 100 feet from dwellings, 150 feet from a public building or 50 feet from a public stream, river or other body of water. Less stringent emissions requirements would be allowed. All these and other unsafe procedures would apply to wells that are otherwise virtually identical to wells using more fracturing fluid. Furthermore, the application for wells under 300,000 gallons of fracking water would include the woefully inadequate two-page form included as Appendix 5 Environmental Assessment Form (EAF) For Well Permitting in the 2011 rdSGEIS, in which the applicant checks a few boxes and provides little substantive information. Even the rdSGEIS—which is still inadequate—requires far more comprehensive information in regard to wells over 300,000 gallons (Appendix 6 PROPOSED Environmental Assessment Form Addendum). Landowners and local governments would have no way of knowing whether drilling operations with less than 300,000 gallons of hydraulic fracturing water might be coming to their area, other than to constantly monitor permits issued by the DEC
Any or all of the above-mentioned inconsistencies could result in adjacent wells being regulated under two significantly different protocols. This is absurd. The final regulations should apply to all oil and gas wells, regardless of the volume of hydraulic fracturing fluid used.
11. FRESHWATER BUFFERS
Sections 560.4(a) and 750-3.3(a) of the draft regulations for high-volume horizontal fracking only establish minimum setbacks for surface waters that are public drinking water supplies. Freshwater lakes, ponds, or streams, or natural springs that are not presently part of or contribute to a public drinking water supply are afforded no minimum standard of protection. This omission is a major failure of the DEC's proposed regulatory program for high-volume fracking. By potentially allowing a well pad to be located next to a lake, river, or natural springs, DEC jeopardizes not only flora and fauna endemic to freshwater systems, but also potential recreational or scenic amenities that contribute to upstate New York's outdoor-based tourism economy. Moreover, an approach that considers only bodies of water that currently serve as drinking water supplies is incredibly and unconscionably short-sighted. By allowing impacts that could contaminate freshwater bodies of the state, DEC may be permanently sacrificing important future sources of clean water necessary to sustain growing populations, agriculture, and business.
Section 750-3.11(d) states that HVHF operations cannot be authorized within 300 feet of a perennial or intermittent stream, storm drain, lake, or pond under a HVHF General Permit, but allows for an exception to this through an individual SPDES permit. (Note, however, that this differs from the DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing," which appears to allow a well pad to be located as close as 150 feet from a perennial or intermittent stream, storm drain, lake, or pond (table within Part I.D.4, page 8) and implies that well pads could perhaps even be permitted inside of this with a separate SPDES permit.) In its prior comments to DEC on the proposed regulations, the U.S. Fish and Wildlife Service requested a minimum 300ft buffer to aquatic systems including lakes, ponds and streams, consistent with 2011 Delaware River Basin Commission (DRBC) recommendations for HVHF. Creating procedural loopholes to allow the circumvention of this will undermine critical environmental protection.
Based on older existing regulations, the only other regulatory provision that appears to potentially apply is in Section 553.2 which states that no "well" shall be located "nearer than 50 feet from any public stream, river, or body of water." However this too is ambiguous since the provision applies only to a well (not the well pad) and seems to depend on the meaning of the word "public". Such a setback is woefully inadequate for any type of gas well. These minimalistic distances are also strangely inconsistent with subsection 560.6(b)(1)(ii) of the proposed draft regulations which state: "For any well, fueling tanks must not be placed within 500 feet of a perennial or intermittent stream, storm drain, regulated wetland, lake or pond." Comparing DEC's scattered set of rules and procedures, it appears that a permit could be issued for a gas well next to a stream where the accidental release of fracking fluid, flowback, or production brine could readily contaminate freshwater systems, while fueling tanks would be required to remain a much safer distance of 500 ft away. This defies understanding. The lack of a clear standard from DEC should be a concern of not only environmental organizations and agencies, but also industry.
It is noteworthy that the DEC increased the setback distance to 500 ft from homes or places of assembly because doing so was recognized as necessary to address the potential for more significant spills associated with HVHF operations. This would suggest that in order to protect freshwater lakes, ponds, or streams from contamination in the event of an accidental spill at a HVHF site, this same 500ft requirement ought to apply.
Section 560.4(a) and Section 750-3.3(a) of the draft regulations should be modified to enumerate a setback of 500ft from freshwater systems including but not limited to lakes, ponds, streams, and springs that do not contribute to a surface drinking water supply. Alternatively, the draft regulations should require a strict setback of 300ft, consistent with U.S. Fish and Wildlife Service and DRBC recommendations. Exemptions to this should not be permitted. (With this change, Section 750-3.11(d) can be revised so that alternate individual SPDES review would be applicable only for wells proposed between 500ft and 300ft from freshwater systems, or for lesser water setbacks from man-made features such as storm drains.)
Subsection 560.6(b)(1)(ii) of the draft regulations should be revised to prohibit the location of fueling tanks, equipment, and any other infrastructure or gas development activities within 500ft of freshwater systems including but not limited to lakes, ponds, streams, and springs that do not contribute to a surface drinking water supply.
Due to the chemicals present in fracking fluid and salinity of flowback, the draft regulations should be revised to prohibit the discharge of runoff from a well pad or any other HVHF activity into freshwater systems, including but not limited to lakes, ponds, streams, and springs.
The DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing" should be revised consistent with the above. (Until this happens, including a wetland setback in Sections 560.4(a) and 750-3.3(a) ought to ensure implementation as controlling provisions over SPDES permitting.)
12. GAS VENTING AND FLARING
The draft regulations fail to sufficiently prohibit venting and flaring of gas well emissions. Methane is a greenhouse gas at least twenty-five times more potent than carbon dioxide in trapping heat. Furthermore, data from the EPA indicates that natural gas production is now the largest source of methane pollution in the United States. Although flaring burns off methane and consumes hydrogen sulfide, doing so also generates large amounts of carbon dioxide, another greenhouse gas, and sulphur dioxide, which contributes to acid rain. Venting and flaring are major sources of air pollution where fracking occurs and represent a known threat to human health, generating ground-level ozone that causes skin, eye, and nasal irritation or bleeding, and releasing chemicals like formaldehyde and benzene, which are human carcinogens.
Subsection 556.2(b) of the draft regulations appears to allow gas from a well pad to escape into the air for at least 48 hours after drilling completion. This constitutes a tremendous amount of greenhouse gas, especially considering DEC estimates that 1,600 wells or more could be drilled per year in New York State. In addition, the text as written is confusing since the definition of "gas" in Section 550.3(q) refers to hydrocarbons. This could be interpreted to mean that flaring, which produces carbon dioxide, could be permitted indefinitely. Regardless, Subsections 556.2(c) and 556.2(g)(5) also provide for the extension of flaring for an unspecified amount of time. The EPA and industry are both moving toward greater control of greenhouse gas emissions during the well completion process, so there is no reason for such a lax requirement. Consistent with the Governor's initiative to combat global warming, New York State should lead the way by requiring that all gas emissions be captured. The regulations should be rewritten to require immediate compliance with the EPA's Green Completion Rules, including immediate compliance with those provisions of the Green Completion Rules that are not scheduled to go into effect until 2015.
13. LIABILITY FOR ACCIDENTS
The revised regulations require that financial security be established to assure that funds are available to cover costs associated with plugging wells. However, there is nothing in the revised regulations or the Proposed Permit Conditions of the rdSGEIS of 2011 which requires owners/operators to establish liability insurance or a security reserve to cover damages that may occur to others as a result of activities under a well permit. There have been numerous reports of such damages in other states.
The Department should require owners/operators to provide financial security to cover damages to the State and to individuals by the same methods provided for well plugging financial security in Part 551.4 or by requiring that a certificate of insurance be kept continuously in force. The total amount of liability security or insurance for each owner/operator should be equal to the largest amount of damages that have been incurred from accidents or negligence for any onshore well in the United States.
The 2011 rdSGEIS states "Local and regional planning documents are important in defining a community's character and are a principal way of managing change within a community. These plans are used to guide development and provide direction for land development regulations (e.g., zoning, noise control, and subdivision ordinances) and designation of special districts for economic development, historic preservation, and other reasons". The 2011 rdSGEIS recommended a flawed certification process that fails to embrace these words. The HVHF regulations are completely silent on the subject of local government authority, a critical issue affecting many towns that have bans or moratoria against fracking or are looking to adopt zoning restrictions on industrial activity including gas development.
The flawed process would allow drillers to self-certify whether a permit application conflicts with local comprehensive plans or land use laws. It would be near impossible for towns to track drilling applications submitted to DEC and verify that information contained in those applications is accurate. The DEC should instead require certification by local governments to ensure consistency with the local comprehensive plan and land use laws before an application is submitted. Rather than respecting towns' decisions to prohibit or limit fracking, the rdSGEIS appears to give DEC unprecedented authority to override local government decisions, saying that if there is an inconsistency with local land use law, DEC would "determine whether this inconsistency raises significant adverse environmental impacts that have not been addressed in the SGEIS ". Besides neglecting key issues like community character, the fact that DEC could approve a gas well permit despite inconsistency with local law is directly counter to home-rule verdicts in both the Dryden and Middlefield cases upholding the authority of local governments to adopt zoning rules affected gas development.
In addition, the DEC's flawed definition of HVHF means the certification process would only apply to wells drilled with more than 300,000 gallons of fluid. Yet, a well using less fluid could be just as inconsistent with comprehensive plans or land use law, so local government consent should not restricted by this parameter.
The DEC did not address local government consent at all in the regulations. So, what exactly will DEC do if it receives an application for HVHF in a town that has prohibited fracking? Since the application violates local law, will DEC reject the request outright? Or since the regulations contain no requirement that an application be consistent with local law or receive prior consent from local government, will DEC continue to process the application—thus forcing the town to pursue injunctive relief or other legal action against the driller, DEC, or both? Considering that Home Rule is enshrined in the NY constitution and is of considerable interest to communities throughout New York, it is intolerable for the regulations proposed to ignore this issue.
The regulations must require that as part of the permit application, an official letter be included from the local government(s) certifying the permit request is consistent with local comprehensive plan and land use laws, or that no such plan or laws exist. This requirement should apply to any gas well, regardless of type or fracking volume.
15. OPEN PITS
First, the regulations fail to prohibit open pits for flowback in all circumstances. Because HVHF has been improperly defined as operations using at least 300,000 gallons of water, the prohibition on open pits for flowback in Section 560.6(c)(27) does not apply for fracking with 299,999 gallons or less. This loophole must be closed and all flowback captured in closed tanks regardless of fracking volume.
Second, the regulations do not prohibit open pits for drilling fluids, drilling mud, and cuttings. As written, open pits are only required for drilling fluid and cuttings associated with horizontal drilling in the Marcellus shale formation and this can also be exempted if an "acid rock drainage mitigation plan" exists, in which case cuttings might even be left onsite. According to Section 560.6(a)(4), open pits holding up to 250,000 or 500,000 gallons could actually be permitted and requirements regarding their construction would only apply to those used on multiple wells. It is also disturbing that DEC removed a requirement to maintain two feet of freeboard since the last draft of the proposed regulations; thus allowing open pits to be filled to the brim. This constitutes a further weakening of the regulations, and virtually guarantees the overflow of contaminates if any rainfall occurs.
With the exception of freshwater impoundments and regardless of the gas-bearing formation, regulations should clearly prohibit the use of open pits during the drilling or fracking of any well.
16. OPERATOR QUALIFICATIONS
Dear Commissioner Martens:
I am writing to comment on the revised HVHF regulations. My comments are given under protest, as I am convinced that the issuance of the revised regulations by the DEC without the prior publication of the final SGEIS is a severely flawed procedure. I reserve the right to comment again on the draft regulations after the final SGEIS has been issued. Notwithstanding, I offer the following comments with regard to Part 551.1 (a)(1) through (7).
Each person who is a principal or acts as an agent for another in any of the following activities within the State must file an organizational report on a form the department prescribes:
solution mining;
drilling, deepening, plugging back or converting oil, gas, solution mining or storage well or wells, or drilling, deepening, plugging back or converting stratigraphic, geothermal or disposal well or wells greater than a true vertical depth of 500 feet;
the production in the State of oil and gas;
the first purchase of oil and gas produced in the State;
the underground storage in the State of gas;
the practice of well abandonment and salvage of oil and gas subsurface equipment; or
the first transportation of oil and gas produced in the State.
That information is gathered on form 85-15-12 (6/07)-28b which requires little more than the name, address and phone number of the entity and agent, as well as names and titles of director and officers and names of persons authorized to sign submittals to the Department.
There is no requirement for such information from persons engaged in hydro-fracturing activities.
There is no place in the revised regulations or the proposed permitting conditions of the rdSGEIS of 2011 where information is gathered on the qualifications or experience of persons or entities engaged in any of these activities.
There is no place in the revised regulations or the proposed permitting conditions of the rdSGEIS of 2011 where information is gathered by the Department on the safety record of persons or entities engaged in any of these activities.
The Department should include hydro-fracturing in the activities on which data is collected. The Department should expand the information collected so as to assure that persons or entities conducting these activities in New York State have adequate prior experience. The Department should require sufficient information on previous safety-related incidents to assure that persons or entities conducting these activities in New York State have not been cited for safety violations.
17. PACE OF DEVELOPMENT
The rdSGEIS states, "Through its permitting process, the DEC will monitor the pace and concentration of development throughout the state to mitigate adverse impacts at the local and regional levels. The Department will consult with local jurisdictions, as well as applicants, to reconcile the timing of development with the needs of the communities. Where appropriate the DEC would impose specific construction windows within well construction permits in order to ensure that drilling activity and its cumulative adverse socioeconomic effects are not unduly concentrated in a specific geographic area." (Revised Draft SGEIS 2011Section 7.8, Pages 7-120/121)
This is critical to avoid some of the most serious environmental and socioeconomic impacts of drilling and related activities. Unless the DEC ensures such activities are not overly concentrated in a specific geographic area, communities will be overwhelmed by a sudden influx of drilling and related activities such as pipelines and processing plants. The revised regulations do not provide DEC with the information necessary to implement this protection.
The DEC's permit procedure requires an application for one well at a time. There is no process established in the regulations; in the Proposed Environmental Assessment Form of the rdSGEIS; or in the Proposed Supplementary Permit Conditions for High-Volume Hydraulic Fracturing in the rdSGEIS, whereby DEC can obtain the information required to ensure cumulative adverse environmental and socioeconomic effects are not concentrated in one area.
There is nothing in the regulations or the rdSGEIS to require owner/operators to provide any information on what additional wells or infrastructure are planned in the same timeframe as the individual well covered by a permit application. Further, there is no procedure for DEC to get information from other owner/operators planning wells in the same area at the same time, nor is there is any procedure to gather information on infrastructure, including pipelines, processing plants and compressor stations, that might be planned in the same time period.
The DEC must build into its permitting process enough information-gathering to ensure the objectives of rdSGEIS section 7.8 are met, including clear requirements that owner/operators must provide:
A listing of all of a driller's planned wells within 25 miles of the permit application well for the next 2 years;
A listing of all planned access roads, water impoundments, gathering systems, pipelines, treatment plants, compression stations, laydown yards, man camps, etc. (whether or not owned/operated by the driller) in association with the planned wells. This should include copies of any application or submission to the Public Service Commission with regard to such infrastructure.
A listing of any facilities that the owner/operator plans to own, operate or use in conjunction with other owner/operators within 25 miles of the permit application well.
The DEC should develop a procedure to assure that all owners/operators who plan to operate in the same or overlapping geographic areas provide enough information about their forward plans to enable implementation of the intent of Section 7.8 of the rdSGEIS. The DEC should also develop procedures for rejecting or requiring modification of plans to prevent adverse environmental or socioeconomic impacts.
18. PERMIT CONIDTIONS I submit the following relating specifically to the over-reliance on ambiguous "permit conditions".
Rather than promulgating a robust set of regulations structured to avoid or mitigate the adverse impacts of fracking, the DEC has taken an approach that essentially perpetuates its current hands-off method of regulating the gas industry. The draft regulations focus almost exclusively on operational aspects of the drilling or fracking process, ignoring the broad set of direct and cumulative impacts on the surrounding environment, people, and communities. Although the 2011 revised draft SGEIS discusses some of these concerns, it inappropriately proposes to handle the vast majority as "permit conditions", resulting in regulations that are woefully incomplete. The New York Chapter of The Nature Conservancy discussed this systemic problem in its comments on the 2011 rdSEIS, stating: "Much of the proposed regulatory framework still falls within the realm of permits rather than regulations. This leaves the industry uncertain about the agencies' expectations and the public uneasy about the adequacy of protection for resources that may be at risk. Recommendations and proposals in the RDSGEIS may not be implemented, as many of the proposed mitigations are not codified in regulation and remain at the discretion on the agencies. The long term use of permit conditions in place of regulations provides significantly weaker regulatory and public oversight, as permits are by their nature handled on a discretionary, individualized basis and are not subject to public review. This lack of clarity and transparency, coupled with the probability of limited resources for enforcement and monitory, does not add up to a sufficient oversight and management framework." (Page 3, Comments on RDSGEIS (letter to Eugene Leff, NYSDEC); The Nature Conservancy; January 4, 2012)
An appropriate response to this would have been for DEC to produce regulations that contain specific requirements relating to issues previously proposed as permit conditions, such as well-pad activities affecting wildlife, noise and lighting, avoidance of fragmentation caused by well pads and infrastructure, among others. However DEC appears to have done the exact opposite, not only failing to add substance to the draft regulations, but largely failing to even identify the need to follow Best Management Practices (BMPs). The only two instances where BMPs are mentioned in the draft regulations are for the control of invasive plants (560.3(a)(16)) and restoration of native plants during site reclamation (560.3(a)(17)), and neither of these references cite an actual document or enumerate specific BMPs to follow. Regarding the reduction of impact on terrestrial wildlife and habitat, well-site monitoring measures, and a Greenhouse Gas Mitigation Plan, the draft regulations are completely silent. This creates tremendous uncertainty with respect to what permit conditions can or would be enforced by DEC.
DEC should understand that these deficiencies will not be solved by simply adding vague provisions into the regulations for the applicant to prepare their own BMPs regarding the above. To fulfill its statutory purpose as an agency protective of the New York's environment, DEC should develop meaningful regulations to address the following:
Sections 560.3(a)(16) and 560.3(a)(17) refer to BMPs that the operator should submit as part of the application process for invasive plants and native plant restoration; however no objective standard has been provided for what these must include. Sections 560.3(a)(16) and 560.3(1)17) of the draft regulations should be revised to codify specific requirements that must be followed or reference a published set of approved BMPs. (These should reflect protocols described by TNC in its January 4, 2012 comments on the rdSEIS.) Any proposed use of alternative BMPs should be accompanied by a written justification within the application and require approval by DEC.
The 2011 rdSGEIS (Section 7.4.1.1) discusses requirements that could be implemented as "permit conditions" at well sites; however these are neither sufficient, nor are they mentioned in the draft regulations (even by reference). The draft regulations should be revised to codify specific well site requirements that must be followed. In addition to topics identified as potential "permit conditions" in Section 7.4.1.1 of the 2011 rdSGEIS, these should include specific measures to avoid the siting of well pads in forests, limiting the total amount of disturbed area (including for infrastructure), requiring the use of existing utility corridors, and limiting noise and light impacts. In addition, BMPs should be developed for specific species and groups of species, and an expanded set of BMPs implemented for site reclamation (for example like those developed by the Appalachian Regional Reforestation Initiative).
The 2011 rdSGEIS (Section 7.4.1.3) discusses monitoring measures that could be required as "permit conditions" in a subset of forest focus areas and grassland focus areas, concluding that with such measures in place "the significant adverse impacts on habitat from high-volume hydraulic fracturing would be partially mitigated". This is inaccurate since monitoring is only the documentation of changes, and thus not mitigation per se. Furthermore, DEC specifies no criteria for what is to be monitored (except for inappropriately limiting the applicant's review to bird impacts) and defers to the applicant to suggest any additional mitigation. Since no criteria for monitoring or measuring wildlife or habitat impacts that would trigger action by DEC were identified in the rdSGEIS or the proposed Environmental Assessment Form (EAF), these measures are of little value. Furthermore, no mention of them is even made in the draft regulations, suggesting that DEC may have decided to ignore such issues altogether. The draft regulations should be revised to identify specific avoidance measures intended to reduce impact within forests and other ecologically sensitive areas. Monitoring requirements should be spelled out in the regulations or an appropriate document referenced and thresholds of acceptable impact defined. For impacts that exceed acceptable parameters, the regulations should specify true mitigation requirements (for example onsite/offsite mitigation, fee-simple dedication of land, conservation easements, or contribution to a habitat acquisition fund).
The 2011 rdSGEIS (Section 7.6.8) proposes to require that an operator develop a Greenhouse Gas Emissions Impacts Mitigation Plan; however this is absent from the draft regulations. The draft regulations should be revised to codify minimum requirements of this plan, including compliance with EPA Natural Gas Star BMPs.
The 2011 rdSGEIS (Section 7.7.2) states that DEC proposes to require, as permit conditions or regulations, radiation surveys at specific time intervals on all accessible well piping, tanks, or other equipment that could contain NORM buildup. The draft regulation, however, simply state in Section 560.7(k) that radiation surveys of the well head, piping, and tanks must be performed using instrumentation and a schedule prescribed by the DEC. Parts of the Marcellus Shale are known to be highly radioactive. Radiation surveys are an important activity for all gas wells, so the draft regulations should be revised to include actual requirements for monitoring, reporting and corrective action.
The 2011 rdSGEIS (Section 7.1.2) describe BMPs associated with SPDES stormwater permitting. The measures should be codified in the draft regulations or SPDES permitting program.
19. PLUGGING WELLS
Dear Commissioner Martens,
I am writing to comment on the revised HVHF regulations. My comments are given under protest, as I am convinced that the issuance of the revised regulations by the DEC without the prior publication of the final SGEIS is a severely flawed procedure. I reserve the right to comment on the draft regulations again after the final SGEIS has been issued.
Plugging oil or gas wells generally receives little attention because it comes at the end of the productive life of the well. Without strict regulations and very careful inspections, it can be a slipshod process that provides little long-term protection. Part 555.5(a)(1) through (5) provides what appear to be several improvements in plugging procedures. However, DEC has given no discussion of the changes in plugging procedures in the 2011 rdSGEIS to indicate what alternative plugging procedures were investigated, why this particular set of procedures was chosen, or how effective these procedures might be over the many centuries or millennia that they must protect the aquifers, air and New York citizens. It is impossible to comment fully on this part of the regulations without that information. Nevertheless, the following comments are provided:
No minimum quality is specified for cement used in plugging. The regulations must specify a minimum quality of cement free of materials that would be unsafe if in contacted with fresh water. The regulations must also specify that cement quality will be revised as necessary to reflect the best and safest technology available.
The language in Part 555.5(a)(5) gives no assurance that the materials used in the gelled fluid will be safe if they come into contact with drinking water aquifers. It also gives no assurance that any "other department-approved fluid" will have at least the density and gel-shear strength specified. The regulations must specify that all materials used in gel fluid must be safe for contact with drinking water aquifers. They must also specify that any other DEC-approved fluid must have no less density and gel-shear strength.
Without proper plugging, the migration of fluids or methane gas into drinking water aquifers and/or the surface is virtually assured at some point in time well into the future. No plugging should take place unless a DEC representative, qualified to assure correct procedures, is onsite for the entire process.
Even with the best procedures, many plugged wells still leak. The DEC should establish a schedule of periodic inspections of all plugged wells to monitor their integrity and to ensure that remedial action is taken if migration of fluids or methane gas to aquifers or the surface is identified.
Plugged wells must remain safe forever. The owner/operator should not be able to reap the financial benefits of drilling and leave New York citizens with the cost of cleaning up abandoned wells. The financial security that is required to assure plugging of wells should remain in effect in perpetuity. Alternatively, a plugging repair fund should be established to defray the cost of repairing plugged and abandoned wells whenever required.
Dear Commissioner Martens:
I am writing to comment on the Revised Express Terms 6 NYCRR Parts 550 through 556 and 560. My comments are given under protest, as I am convinced that the issuance of the revised regulations by the DEC without the prior publication of the final SGEIS is a severely flawed procedure. I reserve the right to comment on the draft regulations again after the final SGEIS has been issued. Notwithstanding this reservation, I offer the following comments with regard to the protection of Principal and Primary Aquifers in New York State.
A definition is provided for a primary aquifer in Part 560.2(b)(20): " 'primary aquifer' shall mean a highly productive aquifer presently being utilized as a source of water supply by a major municipal supply system." A similar definition for a principal aquifer is provided in Part 560.2(b)(21): " 'principal aquifer' shall mean an aquifer known to be highly productive or whose geology suggests abundant potential water supply, but which is not intensively used as a source of water supply by a major municipal system at the present time."
The only real distinction between primary and principal aquifers as defined in the regulations is whether they presently supply a 'major municipal water system', for which no definition is provided in the regulations or in the rdSGEIS of 2011, or in the Department of Health regulation's Public Water System Definitions provided in Table 2.4 of the rdSGEIS of 2011. However, section 2.4.4.1 of the rdSGEIS clearly states that the Department of Health identified the primary aquifers in 1981. "In order to enhance regulatory protection in areas where ground water resources are most productive and most vulnerable, the NYSDOH, in 1981, identified 18 Primary Water Supply Aquifers (also referred to simply as Primary Aquifers) across the State." (Emphasis added.) That was more than thirty years ago, long before the advent of High Volume Hydraulic Fracturing, so that the potential vulnerability of the aquifers to contamination from HVHF activities could not possibly have been considered.
A comparison of the map of Primary Aquifers and the map of Primary and Principal Aquifers on the DEC web site shows both types of aquifers in and around population centers of similar sizes, ranging from hamlets to cities, throughout the potential gas drilling areas identified by the Department. The Department has presented no evidence that the 1981 identifications of primary and principal aquifers have been updated to consider the vulnerability of aquifers to HVHF activities, which was part of the stated original purpose of making a distinction. The department has failed to consider the total numbers of people who use water supplies on a temporary basis as summer and weekend residents or as tourists throughout most of the potential drilling area. The department has also failed to provide any justification for providing weaker protections to people whose water supplies come from one aquifer versus those whose water supplies come from another.
The revised regulations, in Part 560.4(a)(3) provides that "No well pad or portion of a well pad may be located within a primary aquifer and a 500 feet buffer from the boundary of a primary aquifer. This Part of the revised regulations provides no such protection for principal aquifers. In Part 750-3.3(a)(2) states that well pads for HVHF operations are prohibited, and no SPEDES permit will be issued authorizing any such activity or discharge "within 500 feet of, and including, a primary aquifer". However, this section of the revised regulations makes no similar provision for a principal aquifer.
The only partial protection of principal aquifers appears in Part 750-3.11(d) "HVHF operations within certain distances of specific surface or ground waters may be ineligible for coverage under an HVHF general permit and would require authorization under an individual SPEDES permit. At a minimum, HVHF operations sited within the following buffers cannot be authorized by an HVHF GP (calculated from the closest edge of the well pad): Principal Aquifer 500 feet". Thus the department may permit well pads within 500 feet of principal aquifers under Individual SPEDES permits.
A study by researchers from Duke University (Methane Contamination of Drinking Water Accompanying Gas-Well Drilling and Hydraulic Fracturing, Osborne et al. 2011) showed methane migration to water wells that were located 3000 feet from active producing gas wells. The methane has to reach aquifers before it can reach water wells. Thus, this study is also relevant to primary and principal aquifers. The rdSGEIS (7.1.11.1) attempted to discredit this study by pointing to a single gas well in Otsego County where there were no unusual levels of methane detected in nearby water wells. However, the well in question, Ross 1 in the Town of Maryland, was permitted for 80,000 gallons of fracturing (below the Department's cutoff for HVHF), was never connected to a gathering system, was never an active producing well and has been plugged and abandoned (DECs on-line well data). That gas well never should have been included in the data. The rest of the data using active producing wells in other states showed a very high probability of migration of methane from gas wells to water wells up to 3000 feet away. The DEC should reevaluate that study, eliminating the erroneous data point. Even if that erroneous data point is not eliminated, when the average of all wells in the study is considered, the probability of methane migration from gas wells to water wells is very high. The data currently available indicates that a setback of 3000 feet would reduce but not eliminate the danger of methane migration.
Protection for both principal and primary aquifers should be the same and Parts 560.4(a)(3) and 750-3.3(a)(2) should be revised to include principal aquifers. With those changes, the reference to principal aquifers in Part 750-11(d) can be eliminated.
The 500-foot setback of well pads from primary and principal aquifers is insufficient and should be increased significantly. Until better information is available on methane migration a precautionary setbacks of 3000 feet should be established.
21. PROCEDURAL ISSUES
The manner and timing with which the revised regulations were released for comment causes the entire process to be fatally flawed for the following reasons:
The findings of the final SGEIS should have been made available before or simultaneously with the revised regulations, with sufficient time for the public and the industry to read and understand the final SGEIS plus sufficient time to comment on the revised regulations.
Even if the public and the industry had the benefit of a final SGEIS, thirty days during a period with two major holidays is simply insufficient time to comment properly on regulations that are based on several years' worth of submissions and draft documents.
Without the findings contained in the final SGEIS, the public and the industry has no way of knowing what the New York State Department of Environmental Conservation (the Department) has covered in the SGEIS; what additions, deletions or changes will be made from the revised draft SGEIS; or what specific areas of the SGEIS the Department intends to include in permitting conditions. This makes intelligent commenting on the revised regulations virtually impossible. Comments must be based on guesses about findings that may or may not be contained in the final SGEIS.
Without having the findings of the final SGEIS, it is impossible for the public and the industry to put forth reasons that some items should be codified in the regulations and not left for permit conditions.
The draft SGEIS of 2009 and the revised draft SGEIS of 2011 had the same topic mentioned in more than one place. It is not known whether the final SGEIS will have similar areas of ambiguity. Without a final SGEIS, the public and the industry have no basis to propose clarifying some of those topics in the regulations.
Without a final SGEIS, the public and the industry have no way to determine whether there are any gaps between the 1992 GEIS and the final SGEIS and therefore no basis to comment about how such gaps might be addressed in the revised regulations.
By receiving comments on the revised regulations before the final SGEIS is published, the Department has given itself the opportunity to review public comments on the revised regulations, accept those that it wishes, and "adjust" the final SGEIS to support those changes in the revised regulations that the department wishes to accept. Any procedure that would not protect against such manipulation is fatally flawed.
For the foregoing reasons, the revised regulations should be withdrawn and reissued for comments after a final SGEIS has been published.
22. SEISMIC FAULTS
The draft regulations completely ignore the potential for natural faults existing in gas-bearing formations to act as conduits for the migration of fracking fluids and methane to drinking water aquifers, the surface, and atmosphere. This deficiency is reflected in the 2011 revised draft SGEIS, which included an antiquated map (figure 4.13) depicting only limited geological faulting through the likely Marcellus and Utica shale drilling areas. Compiled in 1977, this map obscures critical information. Later maps by other authors (e.g., R. G. Jacobi, 2002) show many more faults throughout New York State. Although the 2011 revised draft SGEIS appeared to acknowledge the potential for abandoned gas wells to transmit methane and chemicals, geological faults can provide even larger channels to the surface, so the DEC's ignoring of this issue defies understanding.
An additional section should be added to the draft regulations to address faults. At a minimum, regulations should require that the applicant definitely demonstrate by a certified professional using seismic testing and best available data that no faults exist beneath the proposed spacing unit or up to one-half mile outside of the spacing unit. If a fault is determined to exist beneath the spacing unit or up to one-half mile outside of the spacing unit, the applicant should be required to reconfigure the spacing unit to avoid the fault by a margin of at least one-half mile, or maintain a lateral setback between the wellbore and fault of least one-half mile.
The 2011 revised draft SGEIS also attempts to downplay the potential for induced seismic activity by citing historic data for when there was no high-volume horizontal hydrofracking in the state. Recently there have been reports of earthquakes in Oklahoma, Ohio, and in the United Kingdom linked directly to hydrofracking activity, both in location and time. The DEC needs to investigate these incidents and determine the probability of similar occurrences in New York if high-volume hydrofracturing were to proceed. Until this has occurred and additional regulatory measures are enacted to avoid induced seismic activity, high-volume hydrofracking should not be permitted.
23. SETBACK -- Dwellings
I offer the following comments with regard to the setbacks and variances for setbacks in Part 560.4(a)(1) and (2) and Part 560.4(c).
The revised regulations specify a setback distance of 500 feet from inhabited dwellings. Numerous localities in other states require greater setbacks, and some have been increased since oil and gas drilling using high volume hydro-fracturing in shale began. The following are a few examples taken from readily available public information.
Houses Places Of Assembly Others
Flower Mound, TX 1500' 1500' 750' from property line
Midland, TX 1320' 1320'
Southlake, TX 1000' 1000' 1000' from property line
Colleyville, TX 1000' 1000'
Lewisville, TX 800' 800'
Santa Fe County, NM 750' 750' 600' from property line
Rio Arriba County, NM 650' 1000'
Common sense alone says that 500 feet from an inhabited dwelling to a well pad is totally inadequate. The revised draft SGEIS of 2011 describes in detail many of the industrial activities that occur at a well pad, including the large numbers of trucks required for each well; the noise and light pollution; the handling of many chemical additives; and the use of high pressure equipment. All or portions of these activities may continue for long periods of time. The Department's attempts to mitigate these and other dangers may not be successful in all cases. Substantial setback distances are required to assure the health and safety of those who must live near a well pad. The people of New York State deserve as much protection as people who live in Texas and New Mexico.
The Department should significantly increase the setbacks of well pads from inhabited dwellings to at least 1,000 feet. 1,500 feet would be better.
The revised regulations also specify a setback distance of "500 feet from a residential water well, a domestic supply spring or water well or a water well or spring used as a water supply for livestock or crops". Such water supplies in proximity to a well pad are subject to the impact of all of the industrial activities that occur at a well pad, including the large numbers of trucks required for each well, the handling of many chemical additives, and emissions of volatile hydrocarbons and other gasses. Again, all or some of these activities may continue for long periods of time. Consequently, substantial setback distances are critical, both for persons living in a dwelling served by a domestic water supply and for the protection of the ultimate consumers of meat or produce from the area served by a well or spring used as a water supply for livestock and crops.
The Department should increase the setbacks of well pads from a residential water well, domestic supply spring or water well, or spring used as a water supply for livestock or crops to at least 1,000 feet. 1,500 feet would be better.
The variances in Part 560.4(c) would apply to setback distances from domestic water supplies and water supplies for livestock and crops; and to setback distances from inhabited dwellings (or places of assembly, which I intend to cover in a separate comment letter). It is critical that safe distances be maintained between these places and all activities associated with site preparation through partial reclamation after drilling. The Department, in the revised regulations, proposes to allow the landowner of such places (with the consent of all tenants in a dwelling) to agree to a waiver reducing the setback distances. The landowner's consent to a waiver is likely to be obtained through monetary inducements from the well owner/operator. In the cases of an occupied dwelling and its domestic water supplies, a waiver of the setback distance could subject persons who are not owners or tenants, including other family members, long-term guests, minor children, or persons who are not competent to make decisions in such matters, to increased risks through exposure to drilling-related activities. In the case of water supplies for livestock and crops, there is no way for the ultimate consumer of meat, dairy products or produce from the livestock or crops to deny consent to a waiver of the setback distance which would expose the food they consume to the impacts of drilling related activities.
The Department should specify that waivers of setback distances for dwellings that will remain inhabited be allowed only if all inhabitants, whether or not they are owners or tenants, are competent and of legal age and agree to the waiver in writing.
In the case of domestic water supplies to dwellings that will remain inhabited, the Department should specify that waivers of setback distances be allowed only if all inhabitants are competent and of legal age and agree to the waiver in writing.
The Department should remove from the revised regulations the provision for waivers of setbacks from a water well or spring used as a water supply for livestock or crops.
Section 560.4(a)(4) and Section 750-3.3(a)(3) of the draft regulations prohibits the location of a well pad within a 100-year floodplain. This provision is inadequate for several reasons. The 100-year flood standard has been breached three times in upstate New York over the last five years, indicating that currently designated floodplain maps are sorely out of date. This clear trend toward more flooding and extreme flooding events in watersheds of the Delaware River and Susquehanna River poses an enormous risk if drilling is allowed. Without accurate floodplain maps, the DEC could permit drilling in areas that are now effectively floodplains, based on the 2006, 2010, and 2011 events. The DEC even notes in the 2011 revised draft SGEIS that the 100-year floodplain maps need to be updated. By failing to require that this happen before drilling is authorized, the DEC is consciously condoning the use of bad data and thus putting people, the environment, land, and livelihood in serious jeopardy.
The 2011 rdSGEIS (Section 6.2) acknowledges that flooding is one of the ways in which uncontrolled release of drilling brine and flowback fluids can occur. In addition, any chemicals or fuels that are stored on a well pad or elsewhere on a well site could potentially be released into the environment if flooding takes place. Although well pads are prohibited in the 100-year floodplain, the draft regulations fail to address other gas development activities or infrastructure that may be present at the well site or within the spacing unit, such as storage of HVHF materials, equipment, tanks, trucks, vehicle parking areas, and pipelines. These industrial features could negatively impact floodplains; and if flooding occurs, infrastructure, storage tanks, and equipment could be damaged, resulting in leaks or contamination.
DEC should make it a priority to update floodplain maps wherever drilling may be authorized. (More accurate maps have been prepared for Broome County using LiDAR technology, but this has not yet occurred in other potential drilling areas.) Where updated floodplain maps are not available, drilling should not be permitted.
Where updated floodplain maps are available, the draft regulations should require that either the 500-year floodplain be used, or a permanent safety buffer of at least 500 feet be established around updated 100-year floodplains to provide greater assurance that floodwaters will not come into contact with fracking material.
The draft regulations should be revised to explicitly prohibit tanks, chemicals, material storage, pipelines, access roads, parking or other ancillary gas development activities in floodplains, whether such features are located on the well pads or elsewhere at a well site or within a spacing unit
25. SETBACK -- Public Assembly
I offer the following comments with regard to the setbacks from a place of assembly and variances to that setback in Parts 560.4(a)(2) and(c).
In the case of places of assembly, most occupants, visitors and users are not the landowner. They may be patients in hospitals; occupants of nursing homes; children in school or on playgrounds and sports fields; families using parks; visitors to libraries; parishioners in churches; workers in factories, offices, public buildings and stores; customers in stores or at farmer's markets; visitors to public buildings; or people in many similar places.
The Department should clarify that "places of assembly" includes all locations, whether privately or publicly owned, whether indoors or outdoors, at which people assemble for any reason.
The revised regulations specify a setback distance of 500 feet from a place of assembly. Numerous localities in other states require greater setbacks, and some have been increased since fracking in shale began. The following are some examples taken from readily available public information.
Houses Place of Assembly Others
Flower Mound, TX 1500' 1500' 750' from property line
Midland, TX 1320' 1320'
Southlake, TX 1000' 1000' 1000' from property line
Colleyville, TX 1000' 1000'
Lewisville, TX 800' 800'
Santa Fe County, NM 750' 750' 600' from property line
Rio Arriba County, NM 650' 1000'
Valencia County NM 1000'
Common sense says that 500 feet from a place of assembly to a gas well pad is totally inadequate. The people of New York deserve as much protection as people who live in Texas and New Mexico. The Department should increase the setbacks of well pads from places of public assembly to at least 1,000 feet. 1,500 feet would be better.
In Part 560.4(c), the Department proposes to allow the landowner of places of assembly to agree to a waiver reducing the setback distance. The landowner's consent to a waiver is likely to be obtained through monetary inducements from the well owner/operator of a proposed oil or gas well. In many cases the occupants or visitors to places of assembly (a few of which are noted above) have little or no choice about the location or time of their presence. Under the proposed regulations, none of the people who use the many different types of places of assembly, except for the landowner, would have an opportunity to deny consent to the additional exposure to drilling and hydro-fracturing-related activities to which a waiver of the setback distance might subject them.
The Department should remove from the revised regulations the provision for waivers of setbacks of well pads from places of assembly.
I offer the following comments with regard to the variances for setbacks in Part 560.4(c).
The variances in this part would apply to setback distances from domestic water supplies and water supplies for livestock and crops; and setback distances from inhabited dwellings or places of assembly. It is critical that safe distances be maintained between these places and all activities associated with site preparation through partial reclamation after drilling. The Department, in the revised regulations, proposes to allow the landowner of such places (with the consent of all tenants in a dwelling) to agree to a waiver reducing the setback distances. The landowner's consent to a waiver is likely to be obtained through payment of monetary inducements from the well owner/operator. In the cases of an occupied dwelling and its domestic water supplies, a waiver of the setback distance could subject the following persons (and possibly others), who are neither owners nor tenants, to increased risks through exposure to drilling related activities: other family members, long term guests, minor children, and persons who are not competent to make decisions about waivers.
In the case of dwellings that will remain inhabited, the Department should specify that waivers of setback distances will be allowed only if all inhabitants, whether or not they are owners or tenants, are competent and of legal age and agree to the waiver in writing. In the case of domestic water supplies to dwellings that will remain inhabited, the Department should specify that waivers of setback distances will be allowed only if all inhabitants are competent and of legal age and agree to the waiver in writing.
In the case of water supplies for livestock and crops, a distributor or consumer has no way of knowing that a farmer or grower has consented to a setback waiver, and that the water supplies for meat or produce have been subjected to possibly dangerous exposure to drilling-related activities. In the case of a water well or spring used as a water supply for livestock or crops, the Department should remove from the revised regulations the provision for waivers of setbacks.
In the case of places of assembly, many occupants are not the landowner and are not tenants. They may be patients in hospitals, occupants of nursing homes, children in school or on playgrounds and sports fields, families using parks, visitors to libraries, parishioners in churches, workers in factories, workers in offices, workers in stores, customers at stores, visitors to public buildings and possibly many other citizens. In many of these cases the occupants or visitors have little or no choice regarding the location or time of their presence. None of these people, with the exception of the landowner, would have an opportunity to deny consent to the exposure to drilling- related activities which would result from a waiver of the setback distance.
In the case of places of assembly, the Department should remove from the revised regulations the provision for waivers of setbacks of well pads from places of assembly.
In addition, the Department should clarify that places of assembly include all locations, whether privately or publicly owned, whether indoors or outdoors, at which members of the public assemble for any reason.
At the outset, I wish to protest the process by which these regulations have been released for final public comment prior to completion of the revised SGEIS, which by law is required to inform the subsequent development of regulations. Furthermore, the burden that DEC has placed upon individuals, organizations, and local governments to submit final comment on regulations within 30 days over the holiday season discourages meaningful public participation. Because of the inherent risks to public health, the environment, sustainable economies, and communities, in addition to programmatic deficiencies within the DEC, high-volume hydraulic fracturing should not be permitted in the state of New York anytime in the foreseeable future. Notwithstanding the above objection, I submit the following comments relating to one of many problems with the draft regulations, specifically the failure to protect state lands.
State lands represent the natural heritage and history of New York, the legacy of past generations and a sacred gift to our children. State lands help sustain wildlife and habitat, biodiversity, water resources, and clean air. Parks, trails, and campgrounds provide outdoor recreation where families can experience the beauty of our state, and historic preservation sites reveal our rich history and culture.
The draft regulations fail to protect state-owned land by permitting subsurface access for drilling and fracking beneath them. This means that drilling rigs could be constructed immediately outside of the boundary of a state park or historic area, completely encircling the park and fracking the earth below. In fact this is very likely to occur because drillers seeking to maximize subsurface access will wish to locate rigs as close to the boundary of state land as possible. Edge effects caused by the clearing of adjacent well sites would degrade the value of habitat for hundreds of feet inside state conservation land. However, noise and light from industrial drilling activity would penetrate much deeper, disrupting ecosystem functions and wildlife behavior, including breeding, feeding, and denning. Many of the state parks in New York comprise relatively small patches of only a few hundred acres, so drilling activity next to these could completely devastate interior ecosystems. Furthermore, fragmentation caused by the concentration of impacts along the perimeter of state land threatens to ecologically isolate otherwise protected core habitat from surrounding natural areas.
Since the draft regulations fail to require any property line setback, state land would also be highly vulnerable to contamination from spills and air pollution. Furthermore, since the draft regulations do not prevent drilling beneath rivers, streams or ponds, natural water bodies inside of state land would be vulnerable to methane and chemical contamination from fracking below. For everyone who appreciates New York state lands, the adverse impacts would be profound. With the noise, odors, and gas flares of industrial activity nearby, possibly next to entrances, campgrounds, or picnic areas, families will no longer be able to relax and enjoy the outdoors. Likewise, those who hike, hunt, and bird watch will no longer see wildlife as in the past. Where fracking becomes widespread, impacts would be severe, and for smaller parks with greatest exposure, they would be catastrophic. Visitation to state park and recreation areas would likely plummet as a result.
The draft regulations should be revised as follows to avoid harm from fracking immediately next to and under state lands:
Section 52.3 and Section 190.8 of the draft regulations should be revised to prohibit any surface or subsurface disturbance to state lands from fracking. The horizontal drilling of gas wells beneath state lands should be prohibited.
The regulations should require a minimum property line setback of at least 1000ft between any well pad and state lands.
In addition to the above, the draft regulations do not clearly prohibit fracking within all state lands. As written, the term "state land" used in Section 52.3 only applies to property administered by the Division of Fish, Wildlife, and Mineral Resources. (This is based on the definition of "state land" contained in Section 52.1.) Similarly, draft text which has been added to Section 190.8 is limited in scope by subsection 190.0(a) to include only lands administered by the Division of Lands and Forest and Division of Operations. Nowhere in the draft regulations does there appear to be a clear prohibition on fracking—including the siting of gas wells or other surface impacts—on lands administered by the Office of Parks, Recreation, and Historic Preservation (OPRHP). (It should be noted that this omission was also identified as a problem by the Environmental Defense Fund in comments on the 2011 rdSGEIS.) The 178 state parks and 38 historic preservation areas of New York State are irreplaceable treasures that demand the greatest degree of protection. Other lands under the auspices of OPRHP include lakes, golf courses, camp sites, nature centers, and trails—all recreational amenities enjoyed by people throughout the state and the nation. Fracking would permanently diminish or destroy these places of immeasurable natural, scenic, historic, and recreational value. The fact that administrative authority over state parks is with OPRHP does not change the fact that regulatory authority for fracking still resides with the DEC.
The regulations should be revised to clearly prohibit fracking on any state land, including State Forests, Wildlife Management Areas, and State Parks.
28. THREATENED AND ENDANGERED SPECIES
The draft regulations barely address the subject of threatened and endangered species. Section 750-3.11(f)(3)) states only that HVHF operations that adversely affect a listed or proposed to be listed endangered or threatened species or its critical habitat require an individual SPDES (State Pollutant Discharge Elimination System) permit.
This provision does not ensure that threatened and endangered species will be protected. It only states that a different permit is required. The regulations fail to require any specific action as part of an independent SPDES permit to ensure that listed species are not harmed. Further, the regulations fail to describe minimum survey requirements for determining if threatened or endangered species are present at a well site or within a spacing unit, fail to define what constitutes "adversely affected", and fail to identify who actually decides whether drilling poses a significant threat.
If high-volume hydrofracturing is authorized in New York State, tens of thousands of permits for gas wells and related infrastructure could be issued over time, resulting in an enormous negative impact upon biodiversity, natural communities, and wildlife including listed species. DEC admits as much in the 2011 rdSGEIS, stating "Significant adverse impacts to habitats, wildlife, and biodiversity from site disturbance associated with high-volume hydraulic fracturing in the area underlain by the Marcellus Shale in New York will be unavoidable…"(Section 7.4.1) This is not only a terrible statement conceding failure by DEC to protect New York's unique natural resources (while also ignoring impacts to areas where other gas bearing formations exist). Relative to threatened and endangered species, it is also an abandonment of DEC's obligation under federal and state law. DEC must exercise its authority to adopt and enforce meaningful regulations to ensure that the ecological integrity of New York State is protected and that listed species do not perish in the face of fracking.
The draft regulation should be revised to clearly require as part of the application process, a site-specific field survey of natural communities, rare plants, and wildlife—including species listed at the state or federal level as threatened, endangered, or of special concern. This should be a four-season survey performed by a qualified biologist at the proposed well site and within the spacing unit. DEC biology staff should conduct field verification as necessary to ensure compliance.
The aforementioned survey should be coupled with a request for screening by the New York Natural Heritage program to see if species missed by the applicant appear in that database. This however should NOT be in lieu of actual field surveys. (It is well known that the Natural Heritage Program database is incomplete. Most of its data is for state lands, not private property.) Also self-screening using the DEC's Nature Explorer and Environmental Resource Mapper web based tools do not provide adequate site-specific resolution. (The 2011 rdSGEIS incorrectly identified these as sufficient methods of determining the presence or absence of threatened and endangered species.)
Regulations should specifically require that the above information be assembled into an ecological report depicting and discussing the location of natural communities and wildlife relative to features within the spacing unit such as the well pad, equipment, and infrastructure including gathering lines and access roads. The report should assess impacts to natural communities and wildlife, including listed species. If the application is part of a larger project consisting of multiple wells and spacing units or abuts other approved or planned drilling units or infrastructure, the report should assess cumulative impacts to natural communities and wildlife, including listed species, over the affected area.
Regulations should specifically require that if listed species or protected natural communities are present, the applicant will seek a determination from DEC (or appropriate federal agent with jurisdiction) as to whether or not the adverse impact is significant. If the impact can be avoided by modifying the location or configuration of development, then the applicant shall be required to do so. Incidental take permits should only be granted as a last resort if mitigation is provided to fully compensate for impacts. An incidental take permit should NOT be approved if compensating mitigation is not provided or doing so puts survival of the species or protected natural community at greater risk.
It is disturbing that DEC would consider the limited set of water testing requirements described in the draft regulations to be sufficient, especially in light of tremendous concern that has been voiced by the public about the dangers of groundwater contamination and growing evidence of harm in Pennsylvania and other parts of the country where fracking has occurred.
Despite the fact that HVHF wells can extend a mile or more laterally, the proposed regulations require water testing only within 1000ft of the gas well pad (or within 2000ft of the pad if there are no water wells within 1000ft). A study by researchers from Duke University ("Methane contamination of drinking water accompanying gas-well drilling and hydraulic fracturing", Osborne et al. 2011) has shown methane migration to water wells that were 3000ft from active producing gas wells. DEC should therefore at least require testing this far. Also, the regulations only require that the owner/operator make "reasonable attempts" to contact landowners with water wells for permission. What constitutes a "reasonable attempt" is not defined. Interestingly, DEC requires record keeping regarding attempts to deliver tests results to landowners, but not of attempts to seek permission to actually perform water tests. Testing should continue for at least ten years after plugging and abandonment because uneconomical gas wells could be abandoned after a very short period of production, in which case chemicals or methane gas might not reach a water well until after plugging occurs.
The draft regulations should be revised to require testing of all residential water wells and springs within 3000ft of the well pad or within the spacing unit, whichever is larger, before and after fracking occurs. The above requirement should not be limited to residential water wells, domestic supply springs and water wells and springs used for livestock and crops, but should instead include any testable wells or natural springs. If no testable water well or spring exists within the aforementioned area, DEC should require the owner/operator to drill one or more test water wells for monitoring purposes.
In addition to testing subsurface water quality, the regulations should require testing of all surface waters, such as lakes, ponds, rivers, or streams within the aforementioned area before and after fracking occurs.
The regulations should require continued annual testing for each of the above features until at least ten years after the associated gas well (or in the case of a multi-well pad, every well on the pad) is permanently plugged and abandoned or has been included in a post-abandonment monitoring program.
The draft regulations should require that the owner/operator document all attempts to contact landowners, tenant, or residents for permission to perform testing and that such attempts include registered mail.
Test results should be made available to the landowner, tenant, or resident within no less than five days of the owner/operator's receipt of results. Any person that uses the water well or spring tested should be provided access to test results.
All of the aforementioned testing requirements should apply to any oil or gas well operation, not just those operations using 300,000 gallons of fracking fluid.
If hydrofracking is permitted in the state of New York, it is essential that DEC make every effort to learn as much as possible from each gas well. In the interest of science and to ensure that the public has accurate information, both DEC and industry should welcome a robust set of water monitoring requirements.
The last version of the revised draft SGEIS which the public has seen suggests that surface impacts of HVHF development such as habitat loss, fragmentation, or interference with agriculture would be limited because of spacing units anticipated to be 640 acres in size with wells drilled laterally beneath the ground from a single pad. These stated advantages, however, are defeated if the size of a spacing unit is smaller, if wells are drilled outside of a single pad, or if other activities and infrastructure can be scattered within the spacing unit. Nothing is written in the draft regulations to prevent this from occurring. Rather than establishing a strict spacing unit size, the draft regulations rely on a myriad of spacing configurations for different circumstances and formations (Section 553(a)(1)-(13)). The smallest of these is 40 acres in size. Furthermore Section 553(c) as revised would allow DEC to approve any other size or wellbore distance from a unit boundary. As drafted, the regulations also fail to clearly stipulate that drilling must occur from a single pad within a spacing unit, referring to infill wells which appear to be permissible either on or outside of the original pad. It is understood that operators are likely to seek drilling locations where gas reserves exist in more than one formation (the "triple play" being Marcellus, Sandstone, and Utica). Thus the potential overlay of non-aligned spacing units for different formations ranging in size from 40 to 640 acres, combined with the potential drilling of multiple pads or infill wells scattered throughout larger units creates a scenario in which there is no assurance that surface impacts will be limited.
With horizontal drilling technology, it is possible to drill over a mile from a single location, thereby making any position within a 640 acre spacing unit accessible. This being so and recognizing that the desire to maximize extraction must be balanced with the protection of surface ecology and protection of other land uses, if high volume fracking is permitted, drillers should either use lateral lines from a single pad or forego outlying reserves.
In order to limit surface impacts, the regulations should be significantly rewritten to accomplish the following:
Require the largest spacing unit size possible, with no spacing unit less than 160 acres in size for any HVHF well.
Within all forests, a spacing unit of at least 640 acres should be required and well pads located at least one mile apart, regardless of the type of well.
Require that once approved, a spacing unit and its boundaries apply to all gas bearing formations beneath the unit.
Require that all drilling and staging activities within the spacing unit be restricted to a single pad, not to exceed five acres in size.
Require that any future gas well within the spacing unit, regardless of type or volume of fracking fluid uses, be drilled from the original pad.
Variances granted on the aforementioned well spacing should be limited to very rare circumstances and subject to a scheduled hearing with adequate public notice. Changes proposed to Section 553.4(a) and new text in Section 553.4(b) improperly eliminate the requirement to show "good and sufficient" reason for variances, shift the burden to outside parties to show that a variance should not be granted, and stifle public input. These changes should not be enacted. A formal hearing should continue to be required for all variances, and a public comment period of at least 60 days should be provided. Only minor variances to the size of a spacing unit should be permitted.
31. WELL SITE IMPACTS
High-volume hydraulic fracturing is a major industrial activity involving a tremendous amount of water, toxic chemicals, trucks traffic, and noise—all of which have great potential to harm the environment and disrupt agricultural, business and residential uses where drilling occurs. The scope and content of draft regulations relating to well site and well pad activities are wholly inadequate to address these issues.
The draft regulations fail to limit the number of well pads that may be constructed within a spacing unit. Although the 2011 revised draft SGEIS acknowledges that it is desirable for wells to be concentrated on a single well pad, nothing has been stipulated in the regulations to require this. To limit surface impacts, the regulations should require that all wells (including infill wells) be built and drilled from a single multi-well pad within the spacing unit, and any future drilling to other formations within the boundaries of the spacing unit should be required to use this same pad, once established.
The draft regulations fail to limit the size of well pads. The regulations should require that well pads be no more than five acres in size to limit surface impacts.
The draft regulations fail to confine all drilling and fracking related activities strictly to the well pad. The definitions of "well pad" in 560.2(b)(30) and "well site" in 560.2(b)(31) both refer to "directly" disturbed or impacted areas, leading to ambiguous interpretations and a potential for scattering of impacts throughout the spacing unit. Regulations should be revised to require that staging activities associated with drilling, including the assembly of trucks or tanks containing water and additives, must be located in a compact formation inside the boundaries of a well pad area. Similarly all pits containing any liquid, cuttings, or other material (with the exception of freshwater impoundments) should be located inside the boundaries of the well pad area.
The draft regulations fail to require the applicant to identify and depict all areas that could be impacted by gas development. Section 560.3(c)(2) states that a topographic map should be produced that depicts certain features such as tanks and pits within 2,640 ft of the well, but this does not necessarily include all gas development activities in the spacing unit. The regulations should be strengthened to require the identification of all features and equipment associated with gas development operations in the entire spacing unit, including but not limited to those listed, as well as any other chemical containers, equipment, storage, staging areas, and water impoundments. Any transmission or processing infrastructure, such as compressor stations and gathering lines should also be identified. The regulations should require that all impacts be consolidated to the greatest extent possible to minimize impacts within the spacing unit and to surround area.
The draft regulations fail to require the identification of all natural and human features that could be impacted by gas development within the spacing unit. Section 560.3(a) "Application Requirements" requires the identification of distances between the well pad and domestic springs, water wells, aquifers, streams, and dwelling for which specific setbacks apply, but does not require the identification or mapping of any other environmental features. Similarly the regulations require that a list of invasive species found on site be prepared along with BMPs, but does not require the identification of natural communities or wildlife, including rare and non-rare species, or BMPs regarding them. It is not possible to ensure that environmental impacts are minimized without this information. The draft regulations should be strengthened to require the identification and mapping of all natural and human features within the spacing unit where fracking is planned. This includes all natural surface features, including but not limited to topography, waters, wetlands, springs, floodplains, vegetation, natural communities, and wildlife. Also included should be all subsurface features including aquifers, karst areas, faults, and old wells. Property lines should be identified and mapped, along with existing land uses (including agriculture) and development such as homes, schools, barns, businesses, roads, and transmission lines. All information supplied should be documented by certified biologists, engineers, or other experts as applicable and an assessment prepared to demonstrate that adverse community, property, and environmental impacts have been avoided or minimized. An applicant pursuing a project involving multiple well sites and spacing units should be required to submit all of the above for the entire project along with an assessment of impacts, direct and cumulative within the project area and affected by the project area. Finally the regulation should clearly state that DEC has authority to require revisions to plans submitted to ensure that impacts are avoided or minimized.
The draft regulations contain no specific site requirements regarding wildlife and habitat or the avoidance of habitat fragmentation. Although some Best Management Practices (BMPs) are discussed in the 2011 revised draft SGEIS as possible "permit conditions", no indication has been given regarding which, if any, of these will actually be required. Unlike, for example, BMPs to control invasive species, well-site BMPs relating to wildlife, natural habitat, and fragmentation are not even referenced in the draft regulations, suggesting that DEC has little intention of addressing these impacts or their avoidance. This also raises the question of what, if anything, can or will be enforced. The draft regulations should be revised to include specific requirements to protect wildlife and habitat, and to avoid habitat fragmentation. BMPs should be codified as regulatory requirements or clearly referenced in the regulations as mandatory. The 2011 revised draft SGEIS failed to identify any specific concrete restrictions or avoidance measures to prevent forest fragmentation. The only actions (erroneously described as "mitigation") in the rdSGEIS involved the documentation and monitoring of effects within focus areas representing a very small percentage of forests where fracking is anticipated to occur. To limit forest fragmentation, the regulations should require the use of multi-well pads and require that all well pads, regardless of type, be located at least one mile apart in all forests.
The draft regulations fail to address periods or hours of operation, noise, and lighting. This means that large-scale incompatible industrial activity could be permitted within 500 ft of a home, zero distance from a park, or zero distance from the property line of non-leased land without any meaningful requirements to protect adjacent neighborhoods, communities, businesses, or natural areas from disturbance—24 hours a day, seven days a week. The regulations should be revised to address each of these issues with meaningful, enforceable requirements that will protect communities, businesses, and natural areas. With respect to lighting in particular, the regulations should require the use of "full-cutoff" fixtures to direct light downward at all times to protect dark skies. (The 2011 revised draft SGEIS only suggests this during times of bird migration.)
The draft regulations fail to address sanitation and the proper handling of food and garbage. This is not only important for human health, but to avoid wildlife problems. The regulations should specify minimum requirements regarding sanitation, garbage and disposal of human waste.
32. WETLANDS
The draft regulations fail to provide a consistent, rational standard for protecting wetlands from the adverse impacts of fracking. In Sections 560.4(a) and 750-3.3(a), the draft regulations require that well pads maintain specific distances from water-dependent features including aquifers, lakes, river, springs, and floodplains. However no explicit setback has been required in these two sections for wetlands—also a water dependent feature. Elsewhere, in Section 750-3.11(d) the draft regulations state that HVHF operations cannot be authorized within 300 feet of a wetland operating under a HVHF General Permit, but could potentially be permitted under an individual SPDES permit. (Note, however, that this differs from the DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing," which appears to allow well pads to be located as close as 100 feet from a wetland (table within Part I.D.4, page 8) and implies that well pads could perhaps even be permitted inside of this with a separate SPDES permit. Additionally, the same document seems to suggest that runoff from well pads could be allowed to discharge into wetlands.) In its prior comments to DEC on the proposed regulations, the U.S. Fish and Wildlife Service requested a minimum 300ft buffer for wetlands to protect water quality and aquatic systems, consistent with 2011 Delaware River Basin Commission (DRBC) recommendations for HVHF. Creating procedural loopholes to allow the circumvention of this will undermine critical environmental protection.
It should also be noted that the distances above are strangely inconsistent with subsection 560.6(b)(1)(ii) of the proposed draft regulations which state: "For any well, fueling tanks must not be placed within 500 feet of a perennial or intermittent stream, storm drain, regulated wetland, lake or pond." (emphasis added) Comparing these scattered set of requirements, it appears that DEC could potentially allow a well pad to be located next from a wetland or maybe even inside a wetland (since doing so is not strictly prohibited), thereby creating a situation where fracking fluid, flowback, or production brine could readily contaminate that wetland. However fueling tanks for fracking the very same well would be required to maintain a safer distance of 500 ft. There is no rationale for this. The lack of a clear, predictable standard from DEC should be a concern of not only environmental organizations and agencies, but also industry.
Wetlands are characterized by vegetation that grows in a moist environment, and are typically subject to inundation by water on a permanent or ephemeral basis. Moisture can occur through various processes, including but not limited to surface water flows, proximity to waterways or water bodies, rainfall inside a contained basin, springs, or groundwater seepage. However regardless of the source of water, wetlands—like floodplains— can provide a path for contaminates to enter the environment. Moreover, because wetlands serve as important habitat and feeding areas for wildlife, they are particularly sensitive features in the natural landscape. Even ephemeral wetlands and isolated wetlands (including those below the 12.4 acre regulatory threshold) are often important to the life cycle of various species, including amphibians. Maintaining an undisturbed area around wetlands is also beneficial for natural communities and wildlife prevalent within wetland/upland ecotones (transitional areas). Wetland delineations do not always coincide with or fall within designated floodplains, and thus are not necessarily protected by floodplain boundaries. Because wetlands are fragile biological features, a separate setback requirement is needed.
In addition to potential contamination from toxic chemicals contained in fracking fluid, flowback and production brine released following the fracking process can alter the salinity of freshwater systems, resulting in negative impacts to wetlands and wetland-dependent species. In a recent report titled "Hydraulic Fracturing Threats to Species with Restricted Geographic Ranges in the Eastern United States" (J. Gillen ad E. Kiviat, Environmental Reviews and Case Studies, Dec 2012), eight of fifteen species studied with home ranges coinciding with the Marcellus Shale region were salamanders—amphibians that are highly sensitive to chemicals and changes in salinity. According to the report, data from Pennsylvania indicates that water conductivity became higher and biotic diversity (including salamanders) lower where fracking occurred. The report determined that reduced water quality, along with fragmentation and other impacts of fracking, could lead to the decline or loss of salamander species over large areas.
It is noteworthy that the DEC increased the setback distance to 500 ft from homes or places of assembly because doing so was recognized as necessary to address the potential for more significant spills associated with HVHF operations. This would suggest that in order to protect wetlands from contamination in the event of an accidental spill at a HVHF site, this same 500ft requirement ought to apply. For all of the above reasons, wetlands should receive no less protection from gas drilling activities than other water-dependent features.
Section 560.4(a) and Section 750-3.3(a) of the draft regulations should be modified to enumerate a setback of 500ft from wetlands. Alternatively, the draft regulations should require a strict setback of 300ft, consistent with U.S. Fish and Wildlife Service and DRBC recommendations. Exemptions should not be permitted. (With this change, the reference to wetlands in Part 750-11(d) can be eliminated or revised so that alternate individual SPDES review would be applicable only for well pads proposed between 500ft and 300ft from a wetland.)
Subsection 560.6(b)(1)(ii) of the draft regulations should be revised to prohibit the location of fueling tanks, equipment, and any other infrastructure or gas development activities within 500ft of wetlands.
Due to the chemicals present in fracking fluid and salinity of flowback, the draft regulations should be revised to prohibit the discharge of runoff from a well pad or any other HVHF activity into wetlands.
Since many state wetland maps are inaccurate or may not show smaller isolated wetlands, the draft regulations should be revised to require site-specific delineation of all wetlands, regardless of size, for all well site and related infrastructure plans. The regulations should require avoidance of all wetlands, including those below the 12.4 acre regulatory threshold.
The DEC proposed regulation titled "SPDES General Permit for Stormwater Discharges from High-Volume Hydraulic Fracturing" should be revised consistent with the above. (Until this happens, including a wetland setback in Sections 560.4(a) and 750-3.3(a) ought to ensure implementation as controlling provisions over SPDES permitting.)
--
--
May you, and all beings
be happy and free from suffering :)
-- ancient Buddhist Prayer (Metta)
No comments:
Post a Comment