§ 1-75 — High volume horizontal hydraulic fracturing operations

Illinois § 1-75

• Jurisdiction: Illinois
• Topic: REGULATION
• Ch. 225: PROFESSIONS, OCCUPATIONS, AND BUSINESS OPERATIONS
• Act 225 ILCS 732/: Hydraulic Fracturing Regulatory Act.
• Art.: Article 1 - Hydraulic Fracturing Regulatory Act

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(a) General. (1) During all phases of high volume horizontal hydraulic fracturing operations, the permittee shall comply with all terms of the permit. (2) All phases of high volume horizontal hydraulic fracturing operations shall be conducted in a manner that shall not pose a significant risk to public health, life, property, aquatic life, or wildlife. (3) The permittee shall notify the Department by phone, electronic communication, or letter, at least 48 hours prior to the commencement of high volume horizontal hydraulic fracturing operations. (b) Integrity tests and monitoring. (1) Before the commencement of high volume horizontal hydraulic fracturing operations, all mechanical integrity tests required under subsection (d) of Section 1-70 and this subsection must be successfully completed. (2) Prior to commencing high volume horizontal hydraulic fracturing operations and pumping of hydraulic fracturing fluid, the injection lines and manifold, associated valves, fracture head or tree and any other wellhead component or connection not previously tested must be tested with fresh water, mud, or brine to at least the maximum anticipated treatment pressure for at least 30 minutes with less than a 5% pressure loss. A record of the pressure test must be maintained by the operator and made available to the Department upon request. The actual high volume horizontal hydraulic fracturing treatment pressure must not exceed the test pressure at any time during high volume horizontal hydraulic fracturing operations. (3) The pressure exerted on treating equipment including valves, lines, manifolds, hydraulic fracturing head or tree, casing and hydraulic fracturing string, if used, must not exceed 95% of the working pressure rating of the weakest component. The high volume horizontal hydraulic fracturing treatment pressure must not exceed the test pressure of any given component at any time during high volume horizontal hydraulic fracturing operations. (4) During high volume horizontal hydraulic fracturing operations, all annulus pressures, the injection pressure, and the rate of injection shall be continuously monitored and recorded. The records of the monitoring shall be maintained by the operator and shall be provided to the Department upon request at any time during the period up to and including 5 years after the well is permanently plugged or abandoned. (5) High volume horizontal hydraulic fracturing operations must be immediately suspended if any anomalous pressure or flow condition or any other anticipated pressure or flow condition is occurring in a way that indicates the mechanical integrity of the well has been compromised and continued operations pose a risk to the environment. Remedial action shall be undertaken immediately prior to recommencing high volume horizontal hydraulic fracturing operations. The permittee shall notify the Department within 1 hour of suspending operations for any matters relating to the mechanical integrity of the well or risk to the environment. (c) Fluid and waste management. (1) For the purposes of storage at the well site and except as provided in paragraph (2) of this subsection, hydraulic fracturing additives, hydraulic fracturing fluid, hydraulic fracturing flowback, and produced water shall be stored in above-ground tanks during all phases of drilling, high volume horizontal hydraulic fracturing, and production operations until removed for proper disposal. For the purposes of centralized storage off site for potential reuse prior to disposal, hydraulic fracturing additives, hydraulic fracturing fluid, hydraulic fracturing flowback, and produced water shall be stored in above-ground tanks. (2) In accordance with the plan required by paragraph (11) of subsection (b) of Section 1-35 of this Act and as approved by the Department, the use of a reserve pit is allowed for the temporary storage of hydraulic fracturing flowback. The reserve pit shall be used only in the event of a lack of capacity for tank storage due to higher than expected volume or rate of hydraulic fracturing flowback, or other unanticipated flowback occurrence. Any reserve pit must comply with the following construction standards and liner specifications: (A) the synthetic liner material shall have a minimum thickness of 24 mils with high puncture and tear strength and be impervious and resistant to deterioration; (B) the pit lining system shall be designed to have a capacity at least equivalent to 110% of the maximum volume of hydraulic fracturing flowback anticipated to be recovered; (C) the lined pit shall be constructed, installed, and maintained in accordance with the manufacturers' specifications and good engineering practices to prevent overflow during any use; (D) the liner shall have sufficient elongation to cover the bottom and interior sides of the pit with the edges secured with at least a 12 inch deep anchor trench around the pit perimeter to prevent any slippage or destruction of the liner materials; and (E) the foundation for the liner shall be free of rock and constructed with soil having a minimum thickness of 12 inches after compaction covering the entire bottom and interior sides of the pit. (3) Fresh water may be stored in tanks or pits at the election of the operator. (4) Tanks required under this subsection must be above-ground tanks that are closed, watertight, and will resist corrosion. The permittee shall routinely inspect the tanks for corrosion. (5) Hydraulic fracturing fluids and hydraulic fracturing flowback must be removed from the well site within 60 days after completion of high volume horizontal fracturing operations, except that any excess hydraulic fracturing flowback captured for temporary storage in a reserve pit as provided in paragraph (2) of this subsection must be removed from the well site within 7 days. (6) Tanks, piping, and conveyances, including valves, must be constructed of suitable materials, be of sufficient pressure rating, be able to resist corrosion, and be maintained in a leak-free condition. Fluid transfer operations from tanks to tanker trucks must be supervised at the truck and at the tank if the tank is not visible to the truck operator from the truck. During transfer operations, all interconnecting piping must be supervised if not visible to transfer personnel at the truck and tank. (7) Hydraulic fracturing flowback must be tested for volatile organic chemicals, semi-volatile organic chemicals, inorganic chemicals, heavy metals, and naturally occurring radioactive material prior to removal from the site. Testing shall occur once per well site and the analytical results shall be filed with the Department and the Agency, and provided to the liquid oilfield waste transportation and disposal operators. Prior to plugging and site restoration, the ground adjacent to the storage tanks and any hydraulic fracturing flowback reserve pit must be measured for radioactivity. (8) Hydraulic fracturing flowback may only be disposed of by injection into a Class II injection well that is below interface between fresh water and naturally occurring Class IV groundwater. Produced water may be disposed of by injection in a permitted enhanced oil recovery operation. Hydraulic fracturing flowback and produced water may be treated and recycled for use in hydraulic fracturing fluid for high volume horizontal hydraulic fracturing operations. (9) Discharge of hydraulic fracturing fluids, hydraulic fracturing flowback, and produced water into any surface water or water drainage way is prohibited. (10) Transport of all hydraulic fracturing fluids, hydraulic fracturing flowback, and produced water by vehicle for disposal must be undertaken by a liquid oilfield waste hauler permitted by the Department under Section 8c of the Illinois Oil and Gas Act. The liquid oilfield waste hauler transporting hydraulic fracturing fluids, hydraulic fracturing flowback, or produced water under this Act shall comply with all laws, rules, and regulations concerning liquid oilfield waste. (11) Drill cuttings, drilling fluids, and drilling wastes not containing oil-based mud or polymer-based mud may be stored in tanks or pits. Pits used to store cuttings, fluids, and drilling wastes from wells not using fresh water mud shall be subject to the construction standards identified in paragraph (2) of this subsection (c). Drill cuttings not contaminated with oil-based mud or polymer-based mud may be disposed of onsite subject to the approval of the Department. Drill cuttings contaminated with oil-based mud or polymer-based mud shall not be disposed of onsite. Annular disposal of drill cuttings or fluid is prohibited. (12) Any release of hydraulic fracturing fluid, hydraulic fracturing additive, or hydraulic fracturing flowback, used or generated during or after high volume horizontal hydraulic fracturing operations shall be immediately cleaned up and remediated pursuant to Department requirements. Any release of hydraulic fracturing fluid or hydraulic fracturing flowback in excess of 1 barrel, shall be reported to the Department. Any release of a hydraulic fracturing additive shall be reported to the Department in accordance with the appropriate reportable quantity thresholds established under the federal Emergency Planning and Community Right-to-Know Act as published in the Code of Federal Regulations (CFR), 40 CFR Parts 355, 370, and 372, the federal Comprehensive Environmental Response, Compensation, and Liability Act as published in 40 CFR Part 302, and subsection (r) of Section 112 of the federal Clean Air Act as published in 40 CFR Part 68. Any release of produced water in excess of 5 barrels shall be cleaned up, remediated, and reported pursuant to Department requirements. (13) Secondary containment for tanks required under this subsection and additive staging areas is required. Secondary containment measures may include, as deemed appropriate by the Department, one or a combination of the following: dikes, liners, pads, impoundments, curbs, sumps, or other structures or equipment capable of containing the substance. Any secondary containment must be sufficient to contain 110% of the total capacity of the single largest container or tank within a common containment area. No more than one hour before initiating any stage of the high volume horizontal hydraulic fracturing operations, all secondary containment must be visually inspected to ensure all structures and equipment are in place and in proper working order. The results of this inspection must be recorded and documented by the operator, and available to the Department upon request. (14) A report on the transportation and disposal of the hydraulic fracturing fluids and hydraulic fracturing flowback shall be prepared and included in the well file. The report must include the amount of fluids transported, identification of the company that transported the fluids, the destination of the fluids, and the method of disposal. (15) Operators operating wells permitted under this Act must submit an annual report to the Department detailing the management of any produced water associated with the permitted well. The report shall be due to the Department no later than April 30th of each year and shall provide information on the operator's management of any produced water for the prior calendar year. The report shall contain information relative to the amount of produced water the well permitted under this Act produced, the method by which the produced water was disposed, and the destination where the produced water was disposed in addition to any other information the Department determines is necessary by rule. (d) Hydraulic fracturing fluid shall be confined to the targeted formation designated in the permit. If the hydraulic fracturing fluid or hydraulic fracturing flowback are migrating into the freshwater zone or to the surface from the well in question or from other wells, the permittee shall immediately notify the Department and shut in the well until remedial action that prevents the fluid migration is completed. The permittee shall obtain the approval of the Department prior to resuming operations. (e) Emissions controls. (1) This subsection applies to all horizontal wells that are completed with high volume horizontal hydraulic fracturing. (2) Except as otherwise provided in paragraph (8) of this subsection (e), permittees shall be responsible for managing gas and hydrocarbon fluids produced during the flowback period by routing recovered hydrocarbon fluids to one or more storage vessels or re-injecting into the well or another well, and routing recovered natural gas into a flow line or collection system, re-injecting the gas into the well or another well, using the gas as an on-site fuel source, or using the gas for another useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere. (3) If it is technically infeasible or economically unreasonable to minimize emissions associated with the venting of hydrocarbon fluids and natural gas during the flowback period using the methods specified in paragraph (2) of this subsection (e), the permittee shall capture and direct the emissions to a completion combustion device, except in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact waterways. Completion combustion devices must be equipped with a reliable continuous ignition source over the duration of the flowback period. (4) Except as otherwise provided in paragraph (8) of this subsection (e), permittees shall be responsible for minimizing the emissions associated with venting of hydrocarbon fluids and natural gas during the production phase by: (A) routing the recovered fluids into storage vessels and (i) routing the recovered gas into a gas gathering line, collection system, or to a generator for onsite energy generation, providing that gas to the surface owner of the well site for use for heat or energy generation, or (ii) using another method other than venting or flaring; and (B) employing sand traps, surge vessels, separators, and tanks as soon as practicable during cleanout operations to safely maximize resource recovery and minimize releases to the environment. (5) If the permittee establishes that it is technically infeasible or economically unreasonable to minimize emissions associated with the venting of hydrocarbon fluids and natural gas during production using the methods specified in paragraph (4) of this subsection (e), the Department shall require the permittee to capture and direct any natural gas produced during the production phase to a flare. Any flare used pursuant to this paragraph shall be equipped with a reliable continuous ignition source over the duration of production. In order to establish technical infeasibility or economic unreasonableness under this paragraph (5), the permittee must demonstrate, for each well site on an annual basis, that taking the actions listed in paragraph (4) of this subsection (e) are not cost effective based on a site-specific analysis. Permittees that use a flare during the production phase for operations other than emergency conditions shall file an updated site-specific analysis annually with the Department. The analysis shall be due one year from the date of the previous submission and shall detail whether any changes have occurred that alter the technical infeasibility or economic unreasonableness of the permittee to reduce their emissions in accordance with paragraph (4) of this subsection (e). (6) Uncontrolled emissions exceeding 6 tons per year from storage tanks shall be recovered and routed to a flare that is designed in accordance with 40 CFR 60.18 and is certified by the manufacturer of the device. The permittee shall maintain and operate the flare in accordance with manufacturer specifications. Any flare used under this paragraph must be equipped with a reliable continuous ignition source over the duration of production. (7) The Department may approve an exemption that waives the flaring requirements of paragraphs (5) and (6) of this subsection (e) only if the permittee demonstrates that the use of the flare will pose a significant risk of injury or property damage and that alternative methods of collection will not threaten harm to the environment. In determining whether to approve a waiver, the Department shall consider the quantity of casinghead gas produced, the topographical and climatological features at the well site, and the proximity of agricultural structures, crops, inhabited structures, public buildings, and public roads and railways. (8) For each wildcat well, delineation well, or low pressure well, permittees shall be responsible for minimizing the emissions associated with venting of hydrocarbon fluids and natural gas during the flowback period and production phase by capturing and directing the emissions to a completion combustion device during the flowback period and to a flare during the production phase, except in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device or flare may negatively impact waterways. Completion combustion devices and flares shall be equipped with a reliable continuous ignition source over the duration of the flowback period and the production phase, as applicable. (9) On or after July 1, 2015, all flares used under paragraphs (5) and (8) of this subsection (e) shall (i) operate with a combustion efficiency of at least 98% and in accordance with 40 CFR 60.18; and (ii) be certified by the manufacturer of the device. The permittee shall maintain and operate the flare in accordance with manufacturer specifications. (10) Permittees shall employ practices for control of fugitive dust related to their operations. These practices shall include, but are not limited to, the use of speed restrictions, regular road maintenance, and restriction of construction activity during high-wind days. Additional management practices such as road surfacing, wind breaks and barriers, or automation of wells to reduce truck traffic may also be required by the Department if technologically feasible and economically reasonable to minimize fugitive dust emissions. (11) Permittees shall record and report to the Department on an annual basis the amount of gas flared or vented from each high volume horizontal hydraulic fracturing well. Three years after the effective date of the first high volume horizontal hydraulic fracturing well permit issued by the Department, and every 3 years thereafter, the Department shall prepare a report that analyzes the amount of gas that has been flared or vented and make recommendations to the General Assembly on whether steps should be taken to reduce the amount of gas that is being flared or vented in this State. (f) High volume horizontal hydraulic fracturing operations completion report. Within 60 calendar days after the conclusion of high volume horizontal hydraulic fracturing operations, the operator shall file a high volume horizontal hydraulic fracturing operations completion report with the Department. A copy of each completion report submitted to the Department shall be provided by the Department to the Illinois State Geological Survey. The completion reports required by this Section shall be considered public information and shall be made available on the Department's website. The high volume horizontal hydraulic fracturing operations completion report shall contain the following information: (1) the permittee name as listed in the permit application; (2) the dates of the high volume horizontal hydraulic fracturing operations; (3) the county where the well is located; (4) the well name and Department reference number; (5) the total water volume used in the high volume horizontal hydraulic fracturing operations of the well, and the type and total volume of the base fluid used if something other than water; (6) each source from which the water used in the high volume horizontal hydraulic fracturing operations was drawn, and the specific location of each source, including, but not limited to, the name of the county and latitude and longitude coordinates; (7) the quantity of hydraulic fracturing flowback recovered from the well; (8) a description of how hydraulic fracturing flowback recovered from the well was disposed and, if applicable, reused; (9) a chemical disclosure report identifying each chemical and proppant used in hydraulic fracturing fluid for each stage of the hydraulic fracturing operations including the following: (A) the total volume of water used in the hydraulic fracturing treatment of the well or the type and total volume of the base fluid used in the hydraulic fracturing treatment, if something other than water; (B) each hydraulic fracturing additive used in the hydraulic fracturing fluid, including the trade name, vendor, a brief descriptor of the intended use or function of each hydraulic fracturing additive, and the Material Safety Data Sheet (MSDS), if applicable; (C) each chemical intentionally added to the base fluid, including for each chemical, the Chemical Abstracts Service number, if applicable; and (D) the actual concentration in the base fluid, in percent by mass, of each chemical intentionally added to the base fluid; (10) all pressures recorded during the high volume horizontal hydraulic fracturing operations; and (11) any other reasonable or pertinent information related to the conduct of the high volume horizontal hydraulic fracturing operations the Department may request or require by administrative rule.

Legislative History

(Source: P.A. 98-22, eff. 6-17-13; 98-756, eff. 7-16-14.)