(225 ILCS 732/1-70)

Sec. 1-70. Well preparation, construction, and drilling.

(a) This Section shall apply to all horizontal wells that are to be completed using high volume horizontal hydraulic fracturing operations under a high volume horizontal hydraulic fracturing permit. The requirements of this Section shall be in addition to any other laws or rules regarding wells and well sites.

(b) Site preparation standards shall be as follows:

(1) The access road to the well site must be located in accordance with access rights identified in the Illinois Oil and Gas Act and located as far as practical from occupied structures, places of assembly, and property lines of unleased property.

(2) Unless otherwise approved or directed by the Department, all topsoil stripped to facilitate the construction of the well pad and access roads must be stockpiled, stabilized, and remain on site for use in either partial or final reclamation. In the event it is anticipated that the final reclamation shall take place in excess of one year from drilling the well the topsoil may be disposed of in any lawful manner provided the operator reclaims the site with topsoil of similar characteristics of the topsoil removed.

(3) Piping, conveyances, valves, and tanks in contact with hydraulic fracturing fluid, hydraulic fracturing flowback, or produced water must be constructed of materials compatible with the composition of the hydraulic fracturing fluid, hydraulic fracturing flowback, and produced water.

(4) The improvement, construction, or repair of a publicly owned highway or roadway, if undertaken by the owner, operator, permittee, or any other private entity, shall be performed using bidding procedures outlined in the Illinois Department of Transportation rules governing local roads and streets or applicable bidding requirements outlined in the Illinois Procurement Code as though the project were publicly funded.

(c) Site maintenance standards shall be as follows:

(1) Secondary containment is required for all fueling tanks.

(2) Fueling tanks shall be subject to Section 1-25 of this Act.

(3) Fueling tank filling operations shall be supervised at the fueling truck and at the tank if the tank is not visible to the fueling operator from the truck.

(4) Troughs, drip pads, or drip pans are required beneath the fill port of a fueling tank during filling operations if the fill port is not within the secondary containment required by paragraph (1) of this subsection.

(d) All wells shall be constructed, and casing and cementing activities shall be conducted, in a manner that shall provide for control of the well at all times, prevent the migration of oil, gas, and other fluids into the fresh water and coal seams, and prevent pollution or diminution of fresh water. In addition to any of the Department's casing and cementing requirements, the following shall apply:

(1) All casings must conform to the current industry standards published by the American Petroleum Institute.

(2) Casing thread compound and its use must conform to the current industry standards published by the American Petroleum Institute.

(3) Surface casing shall be centralized at the shoe, above and below a stage collar or diverting tool, if run, and through usable-quality water zones. In non-deviated holes, pipe centralization as follows is required: a centralizer shall be placed every fourth joint from the cement shoe to the ground surface or to the bottom of the cellar. All centralizers shall meet specifications in, or equivalent to, API Spec 10D, Specification for Bow-Spring Casing Centralizers; API Spec 10 TR4, Technical Report on Considerations Regarding Selection of Centralizers for Primary Cementing Operations; and API RP 10D-2, Recommended Practice for Centralizer Placement and Stop Collar Testing. The Department may require additional centralization as necessary to ensure the integrity of the well design is adequate. All centralizers must conform to the current industry standards published by the American Petroleum Institute.

(4) Cement must conform to current industry standards published by the American Petroleum Institute and the cement slurry must be prepared to minimize its free water content in accordance with the current industry standards published by the American Petroleum Institute; the cement must also:

(A) secure the casing in the wellbore;

(B) isolate and protect fresh groundwater;

(C) isolate abnormally pressured zones, lost circulation zones, and any potential flow zones including hydrocarbon and fluid-bearing zones;

(D) properly control formation pressure and any pressure from drilling, completion and production;

(E) protect the casing from corrosion and degradation; and

(F) prevent gas flow in the annulus.

(5) Prior to cementing any casing string, the borehole must be circulated and conditioned to ensure an adequate cement bond.

(6) A pre-flush or spacer must be pumped ahead of the cement.

(7) The cement must be pumped at a rate and in a flow regime that inhibits channeling of the cement in the annulus.

(8) Cement compressive strength tests must be performed on all surface, intermediate, and production casing strings; after the cement is placed behind the casing, the operator shall wait on cement to set until the cement achieves a calculated compressive strength of at least 500 pounds per square inch, and a minimum of 8 hours before the casing is disturbed in any way, including installation of a blowout preventer. The cement shall have a 72-hour compressive strength of at least 1,200 psi, and the free water separation shall be no more than 6 milliliters per 250 milliliters of cement, tested in accordance with current American Petroleum Institute standards.

(9) A copy of the cement job log for any cemented casing string in the well shall be maintained in the well file and available to the Department upon request.

(10) Surface casing shall be used and set to a depth of at least 200 feet, or 100 feet below the base of the deepest fresh water, whichever is deeper, but no more than 200 feet below the base of the deepest fresh water and prior to encountering any hydrocarbon-bearing zones. The surface casing must be run and cemented as soon as practicable after the hole has been adequately circulated and conditioned.

(11) The Department must be notified at least 24 hours prior to surface casing cementing operations. Surface casing must be fully cemented to the surface with excess cements. Cementing must be by the pump and plug method with a minimum of 25% excess cement with appropriate lost circulation material, unless another amount of excess cement is approved by the Department. If cement returns are not observed at the surface, the operator must perform remedial actions as appropriate.

(12) Intermediate casing must be installed when necessary to isolate fresh water not isolated by surface casing and to seal off potential flow zones, anomalous pressure zones, lost circulation zones and other drilling hazards.

Intermediate casing must be set to protect fresh water if surface casing was set above the base of the deepest fresh water, if additional fresh water was found below the surface casing shoe, or both. Intermediate casing used to isolate fresh water must not be used as the production string in the well in which it is installed, and may not be perforated for purposes of conducting a hydraulic fracture treatment through it.

When intermediate casing is installed to protect fresh water, the operator shall set a full string of new intermediate casing at least 100 feet below the base of the deepest fresh water and bring cement to the surface. In instances where intermediate casing was set solely to protect fresh water encountered below the surface casing shoe, and cementing to the surface is technically infeasible, would result in lost circulation, or both, cement must be brought to a minimum of 600 feet above the shallowest fresh water zone encountered below the surface casing shoe or to the surface if the fresh water zone is less than 600 feet from the surface. The location and depths of any hydrocarbon-bearing zones or fresh water zones that are open to the wellbore above the casing shoe must be confirmed by coring, electric logs, or testing and must be reported to the Department.

In the case that intermediate casing was set for a reason other than to protect strata that contains fresh water, the intermediate casing string shall be cemented from the shoe to a point at least 600 true vertical feet above the shoe. If there is a hydrocarbon-bearing zone capable of producing exposed above the intermediate casing shoe, the casing shall be cemented from the shoe to a point at least 600 true vertical feet above the shallowest hydrocarbon-bearing zone or to a point at least 200 feet above the shoe of the next shallower casing string that was set and cemented in the well (or to the surface if less than 200 feet).

(13) The Department must be notified prior to intermediate casing cementing operations. Cementing must be by the pump and plug method with a minimum of 25% excess cement. A radial cement bond evaluation log, or other evaluation approved by the Department, must be run to verify the cement bond on the intermediate casing. Remedial cementing is required if the cement bond is not adequate for drilling ahead.

(14) Production casing must be run and fully cemented to 500 feet above the top perforated zone, if possible. The Department must be notified at least 24 hours prior to production casing cementing operations. Cementing must be by the pump and plug method with a minimum of 25% excess cement.

(15) At any time, the Department, as it deems necessary, may require installation of an additional cemented casing string or strings in the well.

(16) After the setting and cementing of a casing string, except the conductor casing, and prior to further drilling, the casing string shall be tested with fresh water, mud, or brine to no less than 0.22 psi per foot of casing string length or 1,500 psi, whichever is greater but not to exceed 70% of the minimum internal yield, for at least 30 minutes with less than a 5% pressure loss, except that any casing string that will have pressure exerted on it during stimulation of the well shall be tested to at least the maximum anticipated treatment pressure. If the pressure declines more than 5% or if there are other indications of a leak, corrective action shall be taken before conducting further drilling and high volume horizontal hydraulic fracturing operations. The operator shall contact the Department's District Office for any county in which the well is located at least 24 hours prior to conducting a pressure test to enable an inspector to be present when the test is done. A record of the pressure test must be maintained by the operator and must be submitted to the Department on a form prescribed by the Department prior to conducting high volume horizontal hydraulic fracturing operations. The actual pressure must not exceed the test pressure at any time during high volume horizontal hydraulic fracturing operations.

(17) Any hydraulic fracturing string used in the high volume horizontal hydraulic fracturing operations must be either strung into a production liner or run with a packer set at least 100 feet below the deepest cement top and must be tested to not less than the maximum anticipated treating pressure minus the annulus pressure applied between the fracturing string and the production or immediate casing. The pressure test shall be considered successful if the pressure applied has been held for 30 minutes with no more than 5% pressure loss. A function-tested relief valve and diversion line must be installed and used to divert flow from the hydraulic fracturing string-casing annulus to a covered watertight steel tank in case of hydraulic fracturing string failure. The relief valve must be set to limit the annular pressure to no more than 95% of the working pressure rating of the casings forming the annulus. The annulus between the hydraulic fracturing string and casing must be pressurized to at least 250 psi and monitored.

(18) After a successful pressure test under paragraph (16) of this subsection, a formation pressure integrity test must be conducted below the surface casing and below all intermediate casing. The operator shall notify the Department's District Office for any county in which the well is located at least 24 hours prior to conducting a formation pressure integrity test to enable an inspector to be present when the test is done. A record of the pressure test must be maintained by the operator and must be submitted to the Department on a form prescribed by the Department prior to conducting high volume horizontal hydraulic fracturing operations. The actual hydraulic fracturing treatment pressure must not exceed the test pressure at any time during high volume horizontal hydraulic fracturing operations.

(e) Blowout prevention standards shall be set as follows:

(1) The operator shall use blowout prevention equipment after setting casing with a competent casing seat. Blowout prevention equipment shall be in good working condition at all times.

(2) The operator shall use pipe fittings, valves, and unions placed on or connected to the blow out prevention systems that have a working pressure capability that exceeds the anticipated pressures.

(3) During all drilling and completion operations when a blowout preventer is installed, tested, or in use, the operator or operator's designated representative shall be present at the well site and that person or personnel shall have a current well control certification from an accredited training program that is acceptable to the Department. The certification shall be available at the well site and provided to the Department upon request.

(4) Appropriate pressure control procedures and equipment in proper working order must be properly installed and employed while conducting drilling and completion operations including tripping, logging, running casing into the well, and drilling out solid-core stage plugs.

(5) Pressure testing of the blowout preventer and related equipment for any drilling or completion operation must be performed. Testing must be conducted in accordance with current industry standards published by the American Petroleum Institute. Testing of the blowout preventer shall include testing after the blowout preventer is installed on the well but prior to drilling below the last cemented casing seat. Pressure control equipment, including the blowout preventer, that fails any pressure test shall not be used until it is repaired and passes the pressure test.

(6) A remote blowout preventer actuator, that is powered by a source other than rig hydraulics, shall be located at least 50 feet from the wellhead and have an appropriate rated working pressure.

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