Thursday, June 20, 2013

MEC reports MAY2-JUNE6

We are so lucky to have folks take time out of their lives to go to these meetings and take notes like Diane and Therese . Please read and share !

Note:  The four standing Committees are meeting more often to craft rules.  These notes cover meetings on May 2, May 31, and June 6.  Since the discussions now focus on rule content, the notes summarize key provisions and relevant presentations.
 
 
No injection wells coming to coastal NC, disposing of well drilling waste and waste water; NC company shares expertise in gas well construction in PA, Well Construction rules and Stakeholder recommendations; No diesel fuels allowed in fracking, Baseline and follow-up testing of all (or portion) of water wells within 5,000-ft of well head, Lee County gets new Air Quality monitoring station; water acquisition and management rules
 
(1) Water and Waste Management Committee; Chair, Vik Rao
(a) Injection wells in NC coastal plain?  Early version of Senate Bill 76 included a provision that would overturn the 1973 state law that prohibits injection wells; but it has now been removed.  Rao contended that it was too far to transport the fracking chemicals and, because of depth of water aquifers, only one location in Brunswick County might be viable, and it is close to a nuclear plant. 
 
(b) Draft rule on waste disposal of flowback and produced water.  The Committee’s first draft rule on “Water Acquisition and Management” has been sent to the Rules Committee. The second rule, “Exploration and Production Waste Management” considers how waste will be managed, stored, reused, removed from the site, and how in-ground water pits are constructed (Note: might be changed to above-ground open storage...called “corrals” in gas industry).  MEC member Amy Pickle mentioned “pits” are not well perceived in NC because of animal waste “lagoons;”covered tanks would be preferable.  Setbacks for tanks or pit storage must be sufficient to protect water bodies; pits must maintain two-foot freeboard (not expecting any hurricanes?) and operators must take action to prevent spills.  Other pits could hold drill cuttings that may also contain polluting substances and fluids.  The bottom of pit shall be at least 20-inches above”seasonal high groundwater table,” and have leak detection zones, flexible liners, and berm around it to keep stormwater out.  Can used unlined pits for drill cuttings, if DENR approves process.  Drill cuttings can be reused on site or hauled to permitted landfill.  Water can be reused, but at end of production phase, water would be taken offsite and (a) land applied after pretreatment [working on what that means], or (b) disposed in an approved wastewater treatment facility.  All spills and releases shall be reported.  Volumes greater than 20 barrels must be reported within 24 hours of discovery; a spill threatening to impact a surface water intake it must be reported within 2 hours of discovery. Transportation shall be to permitted facilities, monitoring and reporting.  Staff is making another round of revisions.
 
(2) Administration of Oil and Gas Committee; Chair, Charles Holbrook and Vice Chair, Jane Lewis-Raymond
(a) NC company in gas/oil business. Holbrook invited Kleinfelder, Inc. an NC gas well construction firm in business for 25 years, to discuss NC challenges.  Jeff Crisp said they are working on gathering lines in the Utica shale.  Kleinfelder provides engineering design, environmental permitting for things like stormwater control and endangered species; construction/decommissioning; operations and compliance.  Says in Marcellus shale, the “compressor station” covers about 65 acres in the gathering complex.  In OH, 30-miles of liquid gathering pipeline feed into a compressor station.  There are 300 miles of pipe routing in PA and OH.  Said “compressor stations” have a huge noise impact; they can do ambient noise testing, but it is costly to mitigate noise.  “Compressor stations” can serve numerous well heads.  NC could do either a state permit or the “Nationwide 12” permit for utility crossings for streets and pipelines in the gathering infrastructure, and Army Corps of Engineers 404 permits for crossing wetlands.  The horizontal direction drill (HDD) is part of the gathering lines. Encouraged use of water and filter bags for pipeline.  NC challenges:  unknown supply quality and quantity; relatively SMALL play; how to control for environmental impacts (PA went from 74 pages to 500 pages in their documentation covering erosion control).  PA is also now requiring background tests for groundwater before drilling begins; drill casing should protect the aquifers.  Didn’t have any info on surface spills/accidents in PA.  PA and WV have above-ground “corrals” with liners for frack water retention, instead of in-ground impoundments.  Could also lay more water pipelines if reusing frack water.  PA missteps: Local Townships manage their roads and many are not paved; PA did not have riparian buffers until last year; did not estimate traffic; and poor zoning codes for this infrastructure.
 
(b) Draft Well Construction standards.  This rule covers the specifics of construction, including multiple steel casings, cement standards and verification of the cement bonds to the casings, blowout prevention and testing, and record keeping.  DENR’s Stakeholder group met twice to consider the proposed rules.  Their first meeting on well construction considered each of the casing stages (conductor, surface, intermediate, production) and need for cementing each one so that this special cement either (i) reaches the surface, or (ii) overlaps the previous casing by 200-feet; and verify the adhesion/strength of the cement through pressure tests or continuous “cement bond logs.” Stakeholders want the operator to give 48 hour notice so a DENR inspector can be onsite during the cementing operation(s).  The stakeholders recommended that a qualified individual (certified by industry training) be on site 24-hours day at the wellsite.  The stakeholders reviewed and made recommendations on proposed wellhead standards, pressure rating and safety, signage, fencing and setbacks.  Many stakeholder recommendations were incorporated into the draft rule set.  Not to leave the industry out, Holbrook invited Mr. Thom Alexander, Southwestern Energy, TX to review the proposed standard.  He disagreed with requiring continuous “cement bond logs,”since collecting the logs at intervals was sufficient, based on his experience.  He said there are other ways to evaluate the surface casing using pressure readings rather than waiting 8-12 hours for cement test results.  He said operator will conduct a “leak-off” test anyway.  Alexander said verifying cement to surface for “intermediate” casing was OK, but the production casing, the deepest one, is more problematic. Holbrook mentioned that drilling in the NC shale will be shallow and therefore might not need intermediate casing at all, so must verify cement to surface with production casing.  The surface casing must extend 100-ft below the water table, so it would likely be at a depth of 650-ft.   Holbrook was concerned with isolating coal seams and methane, and making sure surface casing reaches “competent rock.”  This committee moved the draft to the Rules Committee for review, questions, and formatting even though a few sections remain to be written: well stimulation, chemical treatment, wellhead requirements, well maintenance, completion reports, plugging and abandonment, record keeping.
 
(3) Environmental Standards Committee; Chair, George Howard; Vice Chair, Ray Covington
(a) Prohibited Chemicals and Constituents rule.  Ryan Channell (DENR) drafted rule to prohibit diesel products from use in fracking fluids, following guidance from the Environmental Protection Agency. The rule was moved to the Rules Committee.
 
(b) Draft Baseline and Subsequent Testing Requirements rule.  This rule establishes how all groundwater wells (household, domestic, livestock, irrigation, public, commercial) will be tested within 5,000-ft. of a proposed wellhead to establish the baseline BEFORE drilling activities begin.  This rule will eclipse all other states since it covers the largest area and greatest number of constituents.  All tests shall be analyzed by a certified laboratory, and include pH, specific conductance, total dissolved solids (TDS), turbidity, alkalinity, calcium, chloride, magnesium, potassium, sodium, sulfate, arsenic, barium, bromide, chromium, iron, manganese, selenium,  benzene, toluene, ethyl benzene, xylenes, diesel range organics (DRO), dissolved methane, gasoline range organics (GRO), radium isotopes, strontium isotopes. Tests can be no earlier than 12 months but no later than 30 days prior to drilling activities, and would apply to the first well drilled on the pad.  Question is which of these chemicals need to be tested in the subsequent samplings, 6 to 12 months AFTER completion of all wells on the well pad, and again at 18 to 24 months.  The draft rule indicates ALL wells should be retested, but there was discussion of which specific chemicals act as the “canary list,” that could form a testing subset that would result in reliable data about contamination.  The second draft limited the subsequent sampling and testing to pH, specific conductance, TDS, dissolved methane, chloride and divalent cations.  Well operators must fully test all constituents if evidence of contamination is found, AND replace any contaminated water supplies.  Calculation of NC baseline tests within 5,000 ft. is estimated at $1,718/per well; if the same chemicals are tested in all the same wells both at 12 months and 24 months after production, the estimated cost to the operator is almost $107,000 if there are 42 wells in area.  The rule will be discussed one more time before being finalized.
 
DENR’s Ryan Channell had further discussion about “indicator parameters” for subsequent water well testing (or the canary list) and what might signal problems.  Looked at academic papers for guidance: chloride, divalent cations, and TDS are most reliable indicators when found in high concentrations in groundwater.  In surface waters, high concentrations of sodium, calcium, chloride, strontium, barium, and bromides could indicate problems.  Ken Taylor asked what is the threshold of increase for each indicator, so it can be differentiated from “white noise.”  Amy Pickle said we want a reliable indicator checklist from chemistry and is in favor of retesting all wells, unless a step-down approach is sufficient.  Womack suggested MEC get Duke University opinion on a step-down approach.
 
(c) Air Quality and Baseline Testing.  It was noted in the May 2 public comment session that the air quality testing section in Baseline Sampling rule was minimal and did not cover the chemicals commonly associated with this industry. The chair invited a presentation from DENR’s Div. of Air Quality, Mike Araczinskas, who said there is no special permit required for fracking since they do not come under “stack” (source-oriented) emission rules.  However, the Division will establish an additional permanent ambient air quality monitoring station in Lee County, to add to the network of 60 North Carolina stations. The current monitoring stations in Wake County (northeast of Lee Co) and Montgomery County (southwest of Lee Co) will provide upwind/downwind readings.  By establishing the Lee County station now, this will provide a baseline of monitoring the same 89 compounds for a year, including ozone, fine particles, nitrogen dioxide and sulfur dioxide.  The tests at the Wake Co and Montgomery Co sites will be measured on the same day.  The one-year testing covers all seasonal patterns.  He mentioned that the EPA only comes into play when an area reaches “non-attainment” for air quality under federal rules.  Amy Pickel asked whether this industry could push the Piedmont into “non-attainment.”  Ken Taylor mentioned that Wyoming got out of control and reached EPA’s non-attainment designation with this industry.
 
(d) Setbacks.  All committees are working with setbacks.  Take up at June 27 committee meeting.
 
(4) Rules Committee; Chair Amy Pickle
This committee focuses on language consistency, rule structure and content clarification, where needed, in each rule. 
 
(a) The first rule to complete the process, submitted by Water and Waste Management Committee, is Water Acquisition and Management Rules for Oil and Gas Operators.  Highlights of rule:  The Water Management Plan must include detailed application criteria that ID property for source of waters to be used, maximum daily water withdrawals; total quantity of water for project; proposed structures for transport/storage of water; maps of proposed water sources (could be water wells, streams, springs, wetlands, and areas of known contamination); proposed utility rights of way associated with project; alternative water sources such as flowback or produced water; alternative sources in times of drought; and monitoring/reporting.  The Water Management Plan is a section of the comprehensive oil and gas permit application, and could address future water use for multiple well pads.  No water use activity can proceed until the water management plan is approved by DENR
 
The rule requires water source documentation that indicates all surface water sources (with topo maps) showing withdrawal locations, proposed start and ending date of withdrawals, proposed average and maximum daily withdrawals in millions-of-gallons-per-day (mgd), land owners where withdrawal takes place; calculates the 7Q10 flow [historic lowest stream flow recorded over 7 days in a 10-yr. period] at each surface water intake in order to know, in times of drought, when cumulative maximum withdrawals must be reduced to 20% of 7Q10; conduct a Natural Heritage Survey to determine presence of protected species that will be affected, and, identify and prevent the spread of invasive species.  On groundwater sources, applicant must provide topos showing location of wells, proposed maximum daily withdrawals in mgd, and expected total withdrawal; if drill new well for purpose of water withdrawal, must get a well construction permit; results of aquifer pump test for each well to show rate of water recovery; map showing extent of “area of influence” determined by aquifer pump test and location of all water wells and surface waters within that area; and drought-indicator wells to know when water levels are at or below 5th percentile of historic water level measurements (Div of Water Resources) and when that is reached, withdrawals shall CEASE.  For purchased water sources, applicants shall ID the water supplier, have a letter of commitment (or contract), type of water to be provided (potable water, treated wastewater, reclaimed water, raw water); proposed average and max amount of water to be provided daily in mgd; expected total maximum amount to be used; and proposed method of transport of water from supplier.  Section on alternative water sources, such as using flowback or produced water, and applicant must answer WHY these methods are rejected, if not in plan.  Section on monitoring and reporting, including the metering of daily water pumping schedules, amount of stored water, quantities of flowback for recycling/reuse to be stored onsite; and all is reported annually to DENR.   Surface-owners must be notified 30 days before operator enters property for land-disturbing activity.
This rule has been referred to full MEC for consideration at its June 28 meeting.
 
(b) The second rule, Chemical Disclosure Requirements, was pushed back to MEC for further discussion.  Jim Womack (MEC chair) is working on a second “version” of the rule because he was unhappy with Trade Secret provisions after Halliburton (big player in this industry) expressed their concerns.  Amy Pickle had reviewed the initial rule as submitted by the Environmental Standards Committee and made technical corrections regarding format and citations, but does not want Rules Committee to use its time in discussion of various provisions until the full MEC hears the substance of the second version being “written” by Womack, not the Environmental Standards Committee.  She directed DENR staff to incorporate her technical changes as identified and submit to MEC for full discussion.  This rule will solidify the types of disclosure, who it is made to, and various responsibilities (including emergency response), who keeps records, and WHAT chemicals need to be disclosed, or protected as Trade Secrets, and disclosure (or not) to health professionals, and court appeals. Pearl:  George Howard, chair of Environmental Standards Committee, said MEC should not be surprised since Womack needed “input” from the Legislature, DENR and Halliburton on Chemical Disclosure.
 
(c) The third rule, Prohibited Chemicals and Constituents, from the Environmental Standards Committee, was reviewed.  This rule prohibits using diesel, kerosene, and petroleum distillates, and crude oil in fracturing activities, based on EPA guidelines.
This rule has been referred to full MEC for consideration at its June 28 meeting.
 
Diana Hales, retired
 
 

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