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FAQ: Oil and Gas Rules

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Environment, Great Lakes, and Energy

FAQ: Oil and Gas Rules

The Oil and Gas Rules below answer questions in regards to the current Legislation. Learn more about the Michigan Legislature at

  • What Defines Public or Private Occupancy?
     The phrase "structure used for public or private occupancy" is defined in R324.103(j) as "a residential dwelling or place of business, place of worship, school, hospital, government building, or other building where people are present at least 4 hours per day." Seasonal use structures such as hunting cabins or summer cottages are considered to be a residential dwelling and therefore included in this definition.

    Define Residential Zoning
    The definition of "zoned residential" is established in R324.103(r) as "a geographic area that was zoned by a local unit of government before January 8,1993, as an area designated principally for permanent or recreation residences."


    • Who can be a permittee?
      The permittee can be an owner or an authorized representative pursuant to 324.61525 of the statute. When the permittee ceases to be an owner or an authorized representative of the owner then the permit must be transferred.
    • Can an applicant for a Permit to Drill and Operate move a surface location while in the application process?
      Yes. A new survey, plot, revised EIA, and other pertinent documents must be submitted, amending the application. The amendment must meet the provisions in R 324.201.
    • What is a "directional well"? Does it include a sidetrack? (Rule 201, 202, 206(5), 421, 613)
      A directional well means a well purposely deviated from the vertical using controlled angles to reach an objective location. It does not include a "sidetrack" where a hole is deviated a nominal distance to avoid a downhole obstruction. Horizontal drainholes are directionally drilled wells. Horizontal drainholes drilled as a redrill are permitted pursuant to either Rule 206(5) or 202.
    • Is a new survey required when re-entering and re-drilling an abandoned well?
      Yes, even if it conflicts with existing records. The redrilling of an abandon well requires a new permit therefore R 324.201(2)(a) may be applicable.
    • Will the need to acquire other permits hold up drilling permits?
      A permittee can apply simultaneously for all necessary permits. The drilling permit may be issued without other required permits but activities may be restricted until permits are obtained per R 324.201(2)(f). For example, a permittee may be required to obtain all other permits prior to developing the well site or access road. The applicant must detail what additional permits are being sought within the Environmental Impact Assessment Form (EQP 7200-19).
    • Does R324.201(2)(j)(iii) apply to gas storage injection wells?
      Yes. Rule 201(2)(k)(iii) requires the submission of plugging records of all abandoned wells and casing, sealing, and completion records of all other wells within 1,320 feet of a proposed injection well. The rule also requires the applicant to submit a plan which outlines the steps or modifications needed to prevent proposed injected fluids from migrating up, into, or through inadequately plugged, sealed, or completed wells.
    • Additional plats are required for injection wells, does that include gas storage?
      Yes. Additional information is required on a supplemental plat in R324.201(2)(k) for all injection wells, including gas storage wells. The information which must be shown on the plat includes the location and total depth of the proposed well, each abandoned, producing, or drilling well and dry hole within 1,320 feet of the proposed injection well, the identification of the surface owner on which the injection well is to be located and each operator of a producing leasehold within 1,320 feet of the proposed injection well, and all fresh water, irrigation, and public water supply wells with 1,320 feet of the proposed injection well.
    • What happens if permit is not issued within time frame in rules and statute?
      According to Act 325 of 2004, OGMD is mandated 30 days for making an administratively completeness determination and an additional 20 days for processing. So, in total 50 days may be used to process administratively complete permit applications. If OGMD fails to process an administratively complete application within that timeframe, 15% of the permit fee shall be refunded to the applicant.
    • How do deepening permits differ from permits for horizontal drain holes?
      If the horizontal drain hole is proposed in the application for Permit to Drill and Operate then it is part of the Permit to Drill and Operate. R324.206(4) and (5) are applicable subrules in determining if a deepening permit or a change of well status is appropriate: A deepening permit is needed if the horizontal drain hole or a new target in a straight hole is below the existing permitted stratigraphic horizon. If the horizontal drain hole is initiated and completed in the same stratigraphic horizon as permitted it is considered to be a continuation of drilling and a Change of Well Status application must be submitted. If the hole is plugged back above the permitted stratigraphic horizon and then reentered for a horizontal drainhole it is a directional redrill and requires a new permit and fee. If the horizontal drain hole is up hole from the permitted stratigraphic horizon a Change of Well Status Permit is needed for the plug back operations. The horizontal drain hole is a directional redrill, requiring a new permit and fee. Field staff will consult with Permits and Bonding Unit staff to review spacing and drilling units for any Change of Well Status or new permits required for a horizontal drainhole.
    • Does the current permittee need to sign off on a request to transfer a permit?
      Yes. R 324.206(6) indicates that both the current permittee of record (seller) and the new permittee (acquirer) must sign the Request for Transfer of Permit form (EQP-7200-7). If the current permittee does not exist, as in the case of Orphan Wells, the Supervisor of Wells may transfer the well with evidence that the acquiring person is the owner as defined in 324.61501(I). The owner is "the person who has the right to drill a well into a pool, to produce from a pool, and to receive and distribute the value of the production from the pool for himself or herself either individually or in combination with others."
    • A permit shall not be transferred for a well under notice for unsatisfactory conditions until the permittee has completed the necessary corrections or the acquiring person has entered into a written agreement to correct all unsatisfactory conditions. Is a letter from the acquiring operator with a "compliance schedule" sufficient under R 324.207?
      No. A written agreement in the form of an executed Consent Agreement/Order is required prior to transfer of the permit.
    • When do deepening permits terminate? Permits to drill and operate?
      A deepening permit is a Permit to Drill and Operate. Permits to Drill and Operate issued on or after September 20, 1995, terminate two years from the date of issuance pursuant to R 324.208. However, should the permittee provide a written request to extend the permit at least 30 days before the scheduled termination date, then the termination date may be extended for up to 2 additional years.
    • Can assets reported in a statement of financial responsibility include stocks and bonds?
      Yes. R324.210 describes the statement of financial responsibility option for conformance bonding.
    • Can the supervisor suspend operations at a well be for improper bonding?
      Yes. R324.210(7) allows the supervisor to suspend all operations when there is a reasonable belief that the statement of financial responsibility requirements are no longer being met. R 324.213(2) allows for suspension of operations when there is not a proper conformance bond from a surety company.
    • Can additional bonding be required with approval of extended Temporary Abandonment status to assure compliance with Part 615?
      Yes. R324.210(8) allows for the supervisor to require additional conformance bonding to ensure compliance with orders of the supervisor. However, if the aggregate bonding amount of $250,000 has been reached, additional conformance bonds can not be required.
    • Can surety bonds on file prior to the effective date of the new rules be canceled by the surety company? Can they be replaced?
      R324.210(9) indicates that bonds in effect before the effective date of the rules shall remain in effect under the conditions upon which they were filed and accepted, therefore they can not be canceled. Surety bonds in effect prior to the effective date of the new rules may be replaced by one of the bonding options under the new rules including a statement of financial responsibility.
    • How will we deal with financial assurance fraud?
      If the supervisor suspects that the information contained in the statement of financial responsibility is fraudulent, he/she may require an independent review, suspend operations and pursue criminal prosecution under Section 324.61522 of Part 615.
    • Who will be the lead on Soil Erosion and Sedimentation Control issues regulated pursuant to Part 91, Soil Erosion and Sedimentation Control, Natural Resources and Environmental Protection Act, 1994 PA 451, as amended?
      The OGMD is the lead agency for most of the issues related to soil erosion and sedimentation control at sites permitted pursuant to Part 615. A memorandum of understanding has been completed which delineates the authority of the DEQ (EGLE) and the County Enforcement Agencies (CEA). There has also been specific direction provided to oil and gas operators in a memorandum from Harold R. Fitch, dated December 17, 1996, which should be referred to for more complete information.

    A person applying for a Permit to Drill and Operate under Part 615 must make provisions for soil erosion and sedimentation control using one of the following options:

    • Option 1: The applicant may obtain a Soil Erosion and Sedimentation Control Permit from the appropriate CEA. The applicant must provide a copy of the local permit to the OGMD prior to the issuance of the Permit to Drill and Operate.
    • Option 2. The applicant may submit a Soil Erosion and Sedimentation Control Plan ("Plan") as part of the application for a Permit to Drill and Operate. If the "Plan" is approved, the permittee is exempted from the requirement to obtain a separate local soil erosion and sedimentation control permit and bond. The applicant must also submit a copy of the "Plan" to the CEA at the same time as, or prior to, submitting the application to the OGMD.
    • How are Soil and Sedimentation Erosion Control requirements to be incorporated in an Application for a Permit to Drill and Operate?
      "Plans" under option 2 above must be on a prescribed form (EQP 7200-18) and submitted as part of the EIA. The "Plan" must cover all proposed earth changes at well pads, surface facilities, flow lines, and access roads.

    • The rules require 300' setbacks between the regulated well and surface facilities drilled and constructed after the effective date of the rules and occupied structures and existing water wells. Can the OGMD prevent encroachment?
      No. OGMD does not regulate construction of buildings or installation of water wells used for public consumption. Setbacks are evaluated at the time the Permit to Drill and Operate is issued. Encroachment after the Permit is issued will not affect the permittee's right to operate the well under Part 615.
    • What part of the well do you use to determine the hardline constraints on a directional hole?
      The standard drilling unit and prescribed location for a well within the drilling unit is established by R324.301(1). The standard drilling unit is commonly referred to as the "general rule". Spacing under the "general rule" requires a 40-acre tract built from the governmental surveyed quarter-quarter section of land with the "producing interval" of the wellbore allowed anywhere 330 feet or greater from the drilling unit boundary. The "producing interval" is defined as any section of the wellbore that is open to, or intended to be open to, a formation or part of a formation that is intended to produce or is capable of producing oil or gas, or both, after well completion operations.
      Exceptions can be sought via R324.301(4), R324.302 or R324.303.
    • Is the exception for permitting a well on an incomplete drilling unit still valid?
      There is an exception for allowing permits to be issued on a drilling unit that is not totally leased, pooled, or communitized for wells subject to "general rule" spacing (SEE R 324.301(1)(d)) and for special spacing orders such as Special Order 1-73, Special Order 1-86, and Supervisors Order 18-2007. In such instances, before the well is placed on regular production a pooled drilling unit must be formed by voluntary agreement or statutory pooling pursuant to R 324.304.
    • Can you voluntarily pool properties without hearing?
      Yes. R 324.303 provides a means for voluntary pooling without a hearing.
    • Drilling fluids must be capable of sealing off and protecting each oil, gas, brine, or fresh water stratum above the producing horizon and controlling subsurface pressures. Does this prohibit drilling under balanced in horizontal drain holes?
      This does not prevent drilling under balance as long as the intent of R 324.405 is achieved. This should be outlined in the application as special condition.
    • If the established zoning is multiple use such as residential/agricultural or rural residential versus exclusively residential will in-ground pits be prohibited?
      If an area is designated principally for permanent or recreational residences the R 324.407 will apply, prohibiting in-ground pits. The zoning order may have to be reviewed to make that determination.
    • Is brine based drilling mud and salt cuttings allowed in lined reserve pits?
      No. Brine based drilling muds are not allowed to go into the reserve pit. When a crossover from fresh water to brine based mud is done, a closed loop system is required at that point. Also, no solid salt cuttings are allowed in the reserve pit. Solid salt cuttings shall be collected in the shale shaker and either diverted to a device that will result in dissolving of the solid salt cuttings and proper disposal of the resulting brines pursuant to R 324.703 or removed from the drilling site to a licensed disposal facility.
    • In accordance with R 324.407(7)(b)(iv) on September 20, 1998, cuttings and the solid fraction of drilling muds generated or utilized while drilling below the base of the Detroit River Anhydrite must be free of liquids as determined by a US EPA paint filter liquids test, method 9095, to be placed in a lined reserve pit. Who does the paint filter tests? Does it have to be coordinated through the District Geologist?
      It is the permittee's responsibility to conduct the test, prior to placing the material in the lined reserve pit. It does not have to be coordinated through the District Geologist unless specifically requested by OGMD.
      Machine oil is prohibited in reserve pits but in practice this may happen during course of drilling.
    • What actions should be taken by the permittee?
      The permittee must remove the prohibited material as soon as possible in accordance with R324.407(7)(d).
    • Can shallow pits be used (vs. tanks) and then removed to off-site location?
      Yes, provided the base of the liner does not intercept the water table and has approval of the District Geologist.
    • How do you define fresh water strata as used in R 324.408 requiring surface casing to be set 100 feet below the base of the glacial drift into competent bedrock and 100 feet below all fresh water strata?
      Fresh water strata are those rock layers with fresh water in the pore spaces. Fresh water is defined in rules as "water which is free of contamination in concentrations that may cause disease or harmful physiological effects and which is safe for human consumption."
    • How do we determine depth to last freshwater strata as required in R 324.408(1)? Is this tied to TDS requirement of an Underground Source of Drinking Water (USDW)?
      Two factors will be used to make this determination:1)A representative sample of water from the strata, or2)A review of the hydrogeologic setting must be completed. The area water well records may be reviewed to determine the deepest strata currently used for fresh water supply. The area water well records establishes the possible minimum depth to the last freshwater zone.
    • Does used casing have to be certified to verify integrity?
      No. The casing must meet the requirements in R 324.410(3).
    • Does R 324.411 require tension to be held on surface casing for 12 hours after cementing? If so permittee will not be able to nipple up on BOP's while waiting on cement.
      R 324.411 does require tension to be held on all casing for 12 hours after cementing. If the casing can be tacked to the conductor pipe, holding the surface casing in tension, then the BOP's can be nippled up while waiting on cement. If this is not possible the BOP's cannot be nippled up while waiting on cement for 12 hours. In the case where the casing is buoyant the permittee must wait on cement for twelve hours but will not hold the casing in tension.
    • If confidentiality is requested pursuant to R 324.416 (3), what type of information is kept from disclosure?
      R 324.416 (3) allows well data and samples to be held confidential for 90 days after drilling completion upon written request of the permittee. "Drilling Completion" is defined as the time when a well has reached its permitted depth or the supervisor has determined drilling has ceased. All Information and documents required under Part 615 within the permit application process is in the public domain and is not subject to confidentiality.
    • Drill cutting samples must be taken from all wells; does the company have to store these for any specific length of time?
      R 324.417(1) requires that drill cuttings be taken from the base of the drift to the total depth and shall be preserved for the duration of the drilling. Unless specifically requested by the supervisor, the permittee does not have to retain the cuttings after drilling completion.
    • R 324.421 has the phrase "100-foot interval", should this be measured depth or vertical depth?
      The interval is the measured depth for the survey points in a directionally drilled well. If rules do not specifically state true vertical depth then measured depth should be used.
    • R 324.421 requires a permittee to conduct a directional well survey on each directionally drilled well, with survey points at a maximum of 100-foot intervals from the point of deviation to total depth as approved by the supervisor or authorized representative. If a well is plugged and abandoned immediately upon drilling completion, the supervisor shall approve survey points at more than 100-foot intervals, but not more than 500-foot intervals. How are exceptions processed? Can this be included in the permit application?
      Requests for exceptions to the requirement for survey points at a maximum of 100-foot intervals can be made as part of the permit application or as an amendment to the Permit to Drill and Operate. The authorized representative of the supervisor for this exception is the District Geologist. The general guidance to the District Geologist is that well bores near hard lines should have more frequent survey points and a 500-foot interval is the maximum distance to be approved between survey points.
    • We normally do not run directional surveys while in the Brown Niagaran, due to a possibility of differential sticking. Will we be required to run a multi-shot or gyro afterwards?
      The intent is to have the hole surveyed at regular intervals. It may require running a multi-shot or gyro after drilling completion.
    • Does the phrase "existing areas maintained for public recreation" in R 324.504(2)(c) include State Game Areas and Forests?
      It includes "developed areas" within State Game areas and State Forests such as campgrounds, day use areas, etc. It does not mean the entire area included inside boundary lines of State Game Areas or State Forests.
    • Do withdrawal wells for gas storage require tubing?
      No. R 324.507 indicates that tubing is not required for gas storage withdrawal wells.
    • Can any fluids be produced up the back-side (tubing-casing annulus)?
      R 324.507 requires that all oil and gas well be tubed. All oil must be tested and produced through tubing. Gas storage injection wells are exempt.
    • Is a Change of Wells Status application needed for acid or other stimulation treatment as indicated in R 324.511(1)?
      No. A comma was inadvertently added to the rule which eliminated the exception for Change of Well Status applications when conducting acid or other stimulation treatments. Applications for Change of Well Status are required for high volume hydraulic fracturing re-completions.
    • How long is the test period for exploration wells during completion?
      Special Order 2-71 (Amended) provides for a 30 day test program for all wells not subject to a specific proration order for a designated area. If there is a specific proration order then R 324.606 is applicable and production tests are not to exceed the prorated allowable.
    • R 324.705 allows for the conveyance of brine to be used for ice and dust control effective 12 months from the effective date of the rules. Will road brines be used for dust or ice control in the interim?
      Yes. In the interim, we will continue to implement the program in accordance with Special Order 1-85 and the Consent Agreement.
    • Will the EPA form satisfy OGMD reporting requirements in R 324.808 for mechanical integrity tests or will industry have to file separate forms with the EPA and the OGMD?
      OGMD will accept EPA forms if they match our informational needs as indicated in the rules and EGLE form EQP 7606, Annular Pressure Test. This information (form) is to be submitted to the OGMD's Lansing Office as shown on EQP 7606.
    • MIT's are required every five years in R 324.808(2). If a test was done two years ago does it have to be retested or can records be submitted?
      Records can be submitted.
    • Can the EPA monthly reports be submitted for compliance with R 324.810 Monitoring and filing records and reports?
      Yes, if all provisions of Rule 810 are met.
    • Are daily injection reports required?
      R 324.810 establishes the injection reporting requirements. Brine disposal injection wells shall be monitored and the data recorded on a weekly basis. Reports must be filed monthly. Secondary recovery wells are monitored monthly with the data reported annually. Gas storage injection wells are exempt. R 324.810 requires monitoring and filing of records for various injection wells and activities.
    • Are existing injection wells provided a "grandfather" exception?
      There is no "grandfather clause", all injection wells must comply with this rule.
    • Who do we report Mechanical Integrity Test failures, significant pressure changes, or other incidents indicating the presence of a leak to?
      Rules 324.811(1) and (2) require permittees to provide notification of any pressure test failure, significant pressure changes, or other evidence of a leak within 24 hours of the event. Permittees shall provide written notice by email to: or provide verbal notice by phone at (517) 243-5402. Written notice to the email address satisfies both the internal notification and written notice requirements. When using email notifications, permittees should indicate in the subject line of the email the well name/number and permit number - and also indicate in the body of the email the reason that the loss of MI was suspected or determined.
    • Do state officials have to be present at a MIT?
      No. R 324.806 is patterned to be similar to federal law. The test does not have to be witnessed by state officials.
    • Does R 324.812 which requires a permittee to request temporary abandonment status for injection wells which have ceased operation for 1 year apply to gas storage wells?
      Yes. Gas storage wells are required to seek temporary abandonment status in accordance with R324.812 and R324.209.
    • Do you recognize dual completion of wells for both injection and production? These wells cannot be pressure tested.
      Dual completion wells which are completed for both injection and production with two strings of casing can be pressure tested. Combination wells, such as those completed in the Antrim, which are used for both disposal and production cannot be pressure tested. They will be handled similar to EPA.
    • When setting the bottom hole plug in a former producing well, where is the plug to be set in relationship to the perforations?
      The plug should be set near or across the perforations but will be evaluated on a case by case basis in the plugging instructions issued pursuant to R 324.902.
    • Can a bridge plug be set with 50 sacks of cement above perforations without squeezing cement into the perforations?
      R 324.902 sets minimum requirements for plugging of wells. This will be considered on a case by case basis and addressed in plugging instructions.
    • If a cement retainer is set in a producing well, does the bottom hole plug have to be tagged?
      No. If a mechanical bridge plug or other approved bridge is set with a minimum of 50 feet of cement placed on the bridge the plug does not have to be tagged pursuant to R 324.902(5).
    • How does R 324.1002 Secondary Containment Requirements and Construction Standards apply to gas storage wells, facilities and compressor stations?
      Rule 1002 does apply to gas storage field operations except as provided for in sub-rule (3) (m). Injection wells for gas storage are exempt from the requirement for secondary containment at the wellhead. Surface facilities including compressor stations are not exempt if there is storage of hydrocarbons or brine.
    • The secondary containment rules (specifically R 324.1002(3)(d)(ii)) specify that containment for only hydrocarbon storage tanks must be constructed pursuant to R 29.2301 et seq. What is R 29.2301?
      R 29.2301 et seq. has been superseded by 1992 AASC, R 29.4101 et seq. These are the rules on storage and handling of flammable and combustible liquids, enforced by the Fire Marshal. Our Rule 1002 specifies that the containment volume must meet that specified in the Fire Marshal Rules - which is 100% of the volume of the largest enclosed tank handling flammable and combustible liquids. Brine storage requirements and secondary containment construction requirements are not addressed in the Fire Marshal Rules but standards are established in other portions of R324.1002.
    • R 324.1002(7) requires an automatic shutdown system if the throughput of liquids in a 24-hour period exceeds the containment volume of the secondary containment volume. Does that mean the throughput through the tanks, separators or both?
      This only applies to the throughput in the tanks.
    • Does R 324.1008 eliminate the need to file a monthly report indicating that there were "no spills"?
      Yes. Permittees must only submit reports for reportable losses in accordance with Rule 1008. The monthly report form has been eliminated.
    • R324.1008(7) requires reporting of other chemicals used in association with oil and gas activities. Is this intended to mean "reportable quantities" as described in CERCLA?
      Yes. These types of spills must be reported in accordance with Code of Federal Regulations, Title 40 (40 CFR), Part 302.
    • When will the supervisor request flow line removal other than at final completion (abandonment)? Does this apply to Antrim flow lines?
      R 324.1011 allows the supervisor to require that a line be removed or abandoned if not utilized for a period of 1 year. This will be done on a case by case basis. If there is not a demonstrated need for the flow line then the supervisor may require it to be to be removed or abandoned. This rule applies to all flow lines and vessels including storage tanks.
    • Is there a form to be used to report when flow lines and vessels are purged?
      No, a phone call to the District Office will suffice. Permittees should maintain a record of purging in their files.
    • Does the new information required in R 324.1012 need to go on identification signs (ID signs) immediately?
      The Rule does not provide for a grace period for the addition of the permit number, the name of the permittee, the well number and an emergency telephone number for well ID signs and the placement of ID signs at surface facilities. However, permittees will be encouraged to submit a replacement schedule to make the transition to the new requirements. The schedule should be submitted to the District Geologist.
    • Does R 324.1013 (Nuisance Odors) apply to "sweet" wells?
      The nuisance odor rules applies to all oil and gas operations. The same modeling process described in R324.1129 will be followed to determine if a nuisance odor exists.
    • Will old compressors be grandfathered for noise?
      R 324.1016 establishes the construction standards for noise abatement at compressors associated with surface facilities. This rule applies to installations or substantial reconstruction activities completed after September 20, 1996.
      R 324.1015 prohibits nuisance noise caused in the production, handling, or use of oil, gas, or brine or in the handling of any product associated with the production or use of oil, gas, or brine. This rule applies to compressors regardless of the date of construction.
    • The permittee must notify the appropriate emergency preparedness coordinator 24 hours before commencement of drilling a H2S well. This notification must be done by certified mail and include the location of the drilling site, the fact that the well is expected to contain H2S and the fact that a contingency plan is available on-site. Does the notification have to be sent or received 24 hours before drilling commences?
      R 324.1113 requires the notification to be received 24 hours before commencement of drilling.
    • Who can request a hearing and what is the process to do so?
      R 324.1201 states that hearings may be held to receive evidence pertaining to the need or desirability of an action or an order by the supervisor and may be scheduled at the initiative of the supervisor or by the supervisor upon receipt of a petition from an owner, producer, lessee, lessor, or other person interested in the matter proposed for hearing. For some prospective actions, such as secondary recovery and statutory pooling, a hearing is required under the respective administrative rules; while for other actions, such as spacing exceptions, whether or not the issue is appropriate for hearing would be determined by the supervisor. R 324.1202 lays out the requirements for a petition for hearing.
    • How can I contest the action requested in a Notice of Hearing?
      R 324.1204 states that an interested person shall file an answer with the supervisor (and copy to Petitioner) no less than 5 days before the scheduled hearing. The answer should contain the person's interest in the proposed action and reasons for supporting or objecting to it. The answer preserves the interested person's right to testify and cross examine witnesses at the hearing.
    • Can I appeal an Order of the Supervisor?
      R 324.1212 provides that an owner or producer may appeal an order within 28 days to the director of the EGLE.
    • High Volume Hydraulic Fracturing (HVHF) is well completion operation that uses a total volume of 100,000 gallons or more of primary carrier fluid. What if the primary carrier fluid is a gas at prevailing temperatures and pressures, how then is the volume calculated?
      The volumes of a gas should be converted to the total fluid in the liquid phase. Should the liquid phase of the gas volume be 100,000 gallons or greater, then the HVHF portions of the rules will apply.
    • Does a well stimulation completion that uses an acid treatment considered hydraulic fracturing?
      According to the definition of hydraulic fracturing, hydraulic fracturing does not include stimulation completion techniques such as treatments that do not use proppants. Acid stimulations and treatments do not use proppants and are used to remove near well formation mud damage and enhance the interconnection of pore spaces by dissolving the carbonate matrix thereby improving deliverability of hydrocarbons to the wellbore.
    • Is the Water Withdrawal Assessment Tool (WWAT) required for all HVHF well completions?
      Only those well completions that propose an associated Large Volume Water Withdrawal (LVWW) require specific approval from the Supervisor, including running the WWAT. A LVWW includes water withdrawals that re intended to produce a cumulative total of over 100,000 gallons of water per day when averaged over a 30-day period (i.e. 3,000,000 gallons of water or more needed for well completions operations).
    • Is a monitoring well required for all HVHF well completions?
      According to R 324.1403, only those well completions that propose an associated Large Volume Water Withdrawal (LVWW) and have the proposed water withdrawal well(s) within 1,320 feet of a fresh water well require the installation of a monitoring well. The purpose of this monitoring well is to measure the water level drawdown that occurs from the water withdrawal. The monitoring well must be completed in the same aquifer as the water withdrawal well.
    • There are fresh water wells nearby a HVHF well site. Do those water wells need to be sampled prior to initiating drilling?
      According to R 324.1404, if any available water sources are within 1,320 feet of the proposed HVHF well site, those water wells must be sampled for a variety of baseline water quality parameters. The sampling must be conducted new fewer than 7 days and no more than 6 months before drilling a new well or re-completing an existing well.
    • What chemical disclosures are necessary for wells that utilize High Volume Hydraulic Fracturing?
      According to R 324.201(2)(c), any applications to drill (either new wells or Applications to change well status (ACOWS) that propose HVHF) require a pre-disclosure submittal of the proposed chemical additives. Specifically the applicant must provide the specific identity and the associated CAS number of each chemical constituent. For trade secret claimed chemical additives the applicant must provide the chemical family or similar description. According to R 324.1406 within 30 days of well completion of a HVHF operation, the permittee must provide a detailed list of chemical additives used to the internet-based FracFocus Chemical Disclosure Registry.
    • Naturally Occurring Radioactive Materials (NORM)
    • How is the regulation of NORM being addressed?
      Supervisor Of Wells
      Order No. 3-6-92 remains in effect