DEPARTMENT OF ENVIRONMENTAL QUALITY

OIL, GAS, AND MINERALS DIVISION

OIL AND GAS OPERATIONS

(By authority conferred on the supervisor of wells and the director of the department

of environmental quality by section 61506 of the natural resources and environmental

protection act, 1994 PA 451, MCL 324.61506, sections 9 and 251 of the executive

organization act of 1965, 1965 PA 380, MCL 16.109 and 16.351, and Executive

Reorganization Order No. 1991-22, MCL 299.13).

PART 1. GENERAL PROVISIONS

R 324.101 Application of rules.

Rule 101. These rules govern oil and gas operations in the state of Michigan

and supersede all rules and regulations issued under the authority of Act No. 61 of the

Public Acts of 1939, as amended, being §319.1 et seq. of the Michigan Compiled Laws,

except for special well spacing and proration orders and determinations that have

application to specifically designated areas throughout Michigan.

History: 1996 AACS.

R 324.102 Definitions; A to M.

Rule 102. As used in these rules:

(a) “Act” means the natural resources and environmental protection act, 1994 PA

451, MCL 324.101 to 324.90106.

(b) “ANSI” means the American National Standards Institute.

(c) “API” means the American Petroleum Institute.

(d) Aquifer means a geological formation, group of formations, or part of a

formation that is capable of yielding a significant amount of water to a well or spring.

(e) “Authorized representative of the supervisor” means a department of

environmental quality employee who is charged with the responsibility for

implementation of the act or these rules.

(f) “Blowout prevention equipment” means a casinghead control device designed to

control the flow of fluids from the well bore by closing around the drill pipe or

production tubing or completely sealing the hole in the absence of drill pipe or production

tubing.

(g) “Bottom hole” means the terminus of a wellbore.

(h) “Brine” means all nonpotable water resulting, obtained, or produced from the

exploration, drilling, or production of oil or gas, or both.

(i) “Central production facility” means production equipment that has been

consolidated at a central location that provides for the commingling of oil or gas

production, or both, from 2 or more wells or production units of diverse ownership or

from 2 or more prorated wells or production units.

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(j) “Conformance bond” means a surety bond that has been executed by a surety

company authorized to do business in this state, cash, certificates of deposit, letters of

credit, or other securities that are filed by a person and accepted by the supervisor to

ensure compliance with the act, these rules, permit conditions, instructions, orders of the

supervisor, or an order of the department of environmental quality.

(k) “Directionally drilled well,” means a well purposely deviated from the vertical

using controlled angles to reach an objective location.

(l) “Drilling completion” means the time when a well has reached its permitted

depth or the supervisor has determined drilling has ceased.

(m) “Drilling operations” means all of the physical and mechanical aspects of

constructing a well for the exploration or production of oil or gas, or both, for injection of

fluids associated with the production of oil or gas, or both, or the storage of natural

hydrocarbons or liquefied petroleum gas derived from oil or gas, and includes all of the

following:

(i) Moving drilling equipment onto the drill site.

(ii) Penetration of the ground by the drill bit and drilling of the well bore.

(iii) Casing and sealing of the well bore.

(iv) Construction of well sites and access roads.

(n) “Drilling unit” means the area prescribed by an applicable well spacing rule or

order for the granting of a permit for the drilling and operation of an oil or gas well, or

both.

(o) “Facility piping” means piping that connects any of the following:

(i) Compressors.

(ii) Flares.

(iii) Loadouts.

(iv) Separators.

(v) Storage tanks.

(vi) Transfer pumps.

(vii) Treatment equipment.

(viii) Vents.

(p) “Fence” means a structure that is designed to deter access and consists of not less

than 2 strands of barbed wire, 1 strand being approximately 18 inches above the ground

and the other strand being approximately 42 inches above the ground, secured to

supporting posts or means an equivalent structure that deters access.

(q) “Final completion” means the time when locating, drilling, deepening,

converting, operating, producing, reworking, plugging, and proper site restoration have

been performed on a well in a manner approved by the supervisor, including the filing of

the mandatory records, and when the conformance bond has been released.

(r) “Flow line” means piping that connects a well or wells to a surface facility.

(s) “Fresh water” means water that contains less than 1000 milligrams per liter of

total dissolved solids.

(t) “Gas storage” means the use of a depleted oil or gas pool, salt cavern, or other

porous strata utilized for the purpose of injecting and withdrawing gas from the depleted

oil or gas pool, salt cavern, or other porous strata.

(u) “Gathering line” means a pipeline that transports natural gas from a surface

facility to a transmission pipeline.

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(v) “Geologist” means a person who is certified as a geologist by a credible

geological professional association or who, by reason of his or her knowledge of the

natural sciences, mathematics, and the principles of geology acquired by professional

education and practical experience, is qualified to engage in the practice of the science of

geology.

(w) “Groundwater” means water below the land surface in the zone of saturation.

(x) “Injection well” means a well used to dispose of, into underground strata, waste

fluids produced incidental to oil and gas operations or a well used to inject water, gas, air,

brine, or other fluids for the purpose of increasing the ultimate recovery of hydrocarbons

from a reservoir or for the storage of hydrocarbons.

(y) “Instruction” means a written statement of general applicability, that is issued by

the supervisor, conforms with the act and rules promulgated under the act, and clarifies or

explains the applicability of the act or rules to commonly recurring facts or

circumstances.

(z) “Mineral water” means water that contains 1000 milligrams per liter or more of

total dissolved solids.

(aa) “Multiple zone completion” means a well constructed and operated to

separately produce oil or gas, or both, from more than 1 reservoir through 1 well bore.

History: 1996 AACS; 2001 AACS; 2002 AACS; 2015 AACS; 2019 AACS.

R 324.103 Definitions; N to Z.

Rule 103. As used in these rules:

(a) “Nuisance odor” means an emission of any gas, vapor, fume, or mist, or

combination thereof, from a well or its associated surface facilities, in whatever

quantities, that causes, either alone or in reaction with other air contaminants, injurious

effects to human health or safety; unreasonable injurious effects to animal life, plant life

of significant value, or property; or unreasonable interference with the comfortable

enjoyment of life or property.

(b) “Oil and gas operations” means permitting activities required under R 324.201,

drilling operations, well completion operations, operation of oil and gas wells, plugging

operations, and site restoration.

(c) “Operation of oil and gas wells” means the process of producing oil or gas, or

both, or the storage of natural hydrocarbons or liquefied petroleum gas, including all of

the following:

(i) Production, pumping, and flowing.

(ii) Processing.

(iii) Gathering.

(iv) Compressing.

(v) Treating.

(vi) Transporting.

(vii) Conditioning.

(viii) Brine removal and disposal.

(ix) Separating.

(x) Storing.

(xi) Injecting.

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(xii) Testing.

(xiii) Reporting.

(xiv) Maintenance and use of surface facilities.

(xv) Secondary recovery.

(d) “Organization report” means a listing of all corporate officers, directors,

incorporators, partners, or shareholders who have the authority to make, or are

responsible for making, operational decisions, including the siting, drilling, operating,

producing, reworking, and plugging of wells.

(e) “Permit” means a permit to drill and operate an oil or gas well, or both, or an

injection well, including associated surface facilities and flow lines.

(f) “Plugging operations” means the sealing of the fluids in the strata penetrated by

an oil or gas well, or both, upon abandonment of the well or a portion of the well bore, so

that the fluid from one stratum will not escape into another or to the surface.

(g) “Ppm” means parts per million by volume.

(h) “Producing interval” means any section of a 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. The section of the

wellbore may be open to the formation or part of the formation by any means, and may

include but is not limited to, a section of a wellbore that is either uncased or has

perforated casing.

(i) “Psi” means pounds per square inch.

(j) “Psig” means pounds per square inch gauge.

(k) “Secondary recovery” means the introduction or utilization of fluid or energy

into or within a pool for the purpose of increasing the ultimate recovery of hydrocarbons

from the pool.

(l) “Shut-in” means an action by a permittee to close down a producing well, a well

capable of producing, or an injection well temporarily for any of the following reasons:

(i) Repair.

(ii) Cleaning out.

(iii) Building up reservoir pressure.

(iv) Planning for secondary recovery.

(v) Other injection projects.

(vi) While awaiting connection of a sales line.

(vii) Lack of a market.

(m) “Site restoration” means all of the following:

(i) The filling and leveling of all cellars, pits, and excavations.

(ii) The removal or elimination of all debris.

(iii) The elimination of all conditions that may create a fire or pollution hazard.

(iv) The minimization of erosion.

(v) The restoration of the well site as nearly as practicable to the original land

contour or to a condition approved by the supervisor.

(n) “Structure used for public or private occupancy,” means a residential dwelling or

place of business, place of worship, school, hospital, government building, or other

building where people are usually present at least 4 hours per day.

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(o) “Supervisor” means the director of the department of environmental quality or

his or her assistants as approved by the director of the department of environmental

quality.

(p) “Surface casing” means the casing string or strings used primarily for protecting

fresh water or mineralized water resources from potential contamination during the

drilling and operation of an oil or gas well, or both.

(q) “Surface facility” means a facility used in the injection of fluids or in the

production, processing, or treatment of oil or gas, or both, including any of the following:

(i) Pumping equipment.

(ii) Fluid disposal equipment.

(iii) Facility piping.

(iv) Load outs.

(v) Separators.

(vi) Storage tanks.

(vii) Treatment equipment.

(viii) Compressors.

(r) “Surface water” means a body of water, and the associated sediments, which has

a top surface that is exposed to the atmosphere and is not solely for wastewater

conveyance, treatment, or control. Surface water may be any of the following:

(i) A Great Lake or its connecting waters.

(ii) An inland lake or pond.

(iii) A river or stream, including intermittent streams.

(iv) An impoundment.

(v) An open drain.

(vi) A wetland.

(s) “Underground source of drinking water” means fresh water or mineral water

within an aquifer or portion of an aquifer that satisfies either of the following criteria:

(i) The aquifer or portion thereof supplies a public water system.

(ii) The aquifer or portion thereof contains a sufficient quantity of ground water to

supply a public water system and meets either of the following criteria:

(A) The aquifer or portion thereof currently supplies drinking water for human

consumption.

(B) The aquifer or portion thereof contains ground water that has fewer than

10,000 milligrams per liter total dissolved solids.

(t) “Well completion” means the time when a well has been tested and found to be

incapable of producing hydrocarbons in commercial quantities and has been plugged or

has been found capable of producing commercial quantities of hydrocarbons or when the

well has been equipped to perform the service for which it was intended.

(u) “Well completion operations” means work performed in an oil or gas well, or

both, after the well has been drilled to its permitted depth and the production string of

casing has been set, including perforating, artificial stimulation, and production testing.

(v) “Well location” means the surface location of a well.

(w) "Zoned residential” means a geographic area that was zoned by a local unit of

government before January 8, 1993, as an area designated principally for permanent or

recreational residences.

History: 1996 AACS; 2002 AACS; 2015 AACS; 2018 AACS.

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R 324.104 Terms defined in act.

Rule 104. Unless the context requires a different meaning, the trade words and other

words defined in the act have the same meanings when used in these rules.

History: 1996 AACS.

R 324.199 Rescission.

Rule 199. (1) R 299.251 to R 299.258 of the Michigan Administrative Code,

appearing on pages 1415 to 1417 of the 1979 Michigan Administrative Code, are

rescinded.

(2) R 299.1101 to R 299.1807, R 299.1809, R 299.1810, and R 299.1901 to R

299.2101 of the Michigan Administrative Code, appearing on pages 1466 to 1495 of the

1979 Michigan Administrative Code, and pages 206 to 217 of the 1987 Annual

Supplement to the Code, are rescinded.

History: 1996 AACS.

PART 2. PERMITS TO DRILL AND OPERATE

R 324.201 Application for permit to drill and operate requirements; issuance of

permit.

Rule 201. (1) Until a person has complied with the requirements of subrule (2) of

this rule, a person shall not begin the drilling or operation of a well for any of the

following:

(a) Oil or gas, or both.

(b) Injection for secondary recovery.

(c) Injection for the disposal of brine, oil or gas field waste, or other fluids

incidental to the drilling, producing, or treating of wells for oil or gas, or both, or the

storage of natural hydrocarbons or liquefied petroleum gas derived from oil or gas.

(d) Injection or withdrawal for the storage of natural dry gas or oil well gas.

(e) Injection or withdrawal for the storage of liquid hydrocarbons or liquefied

petroleum gas.

(2) A permit applicant shall comply with all of the following permit application

requirements:

(a) The exact well location shall be surveyed by a surveyor licensed in this state, a

readily visible stake or marker shall be set at the well location, and a flagged route shall

be established to the well location.

(b) The survey required by subdivision (a) of this subrule shall include a plat that

shows all of the following:

(i) The correct well location and bottom hole location description.

(ii) A flagged route or explanation of how the well location may be reached.

(iii) Footages from the nearest section, quarter section, and drilling unit lines.

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(iv) Information relative to the approximate distances and directions from the

stake or marker to special hazards or conditions, including all of the following:

(A) Surface waters and other environmentally sensitive areas within 1,320 feet

of the proposed well. Environmentally sensitive areas are identified by the department

pursuant to applicable state and federal laws and regulations.

(B) Floodplains associated with surface waters within 1,320 feet of the proposed

well.

(C) Wetlands, as identified by the provisions of sections 30301 to 30323 of the

act, within 1,320 feet of the proposed well.

(D) Natural rivers, as identified by the provisions of sections 30501 to 30515 of

the act, within 1,320 feet of the proposed well.

(E) Critical dune areas, as designated by the provisions of sections 35301 to

35326 of the act, within 1,320 feet of the proposed well.

(F) Threatened or endangered species, as identified by the provisions of sections

36501 to 36507 of the act, within 1,320 feet of the proposed well.

(G) All buildings, recorded fresh water wells and reasonably identifiable fresh

water wells utilized for human consumption, public roads, pipelines, and power lines that

lie within 600 feet of the proposed well location.

(H) All public water supply wells identified as type I and IIa that lie within 2,000

feet of the proposed well location and type IIb and III that lie within 800 feet of the

proposed well location, as defined in 1976 PA 399, MCL 325.1001 to 325.1023.

(I) Identification of the existing local zoning designation of the surface location

of the well.

(c) If the applicant intends to utilize high volume hydraulic fracturing, the

application shall include a list showing the specific identity and associated CAS number

of each chemical constituent the applicant anticipates will be added to the primary carrier

fluid, except that the specific identities and CAS numbers of trade secret chemicals may

be withheld under the provisions of paragraph (i) of this rule.

(i) If the specific identity of a chemical constituent and its associated CAS

number are a trade secret, the applicant may withhold the specific identity of the

chemical constituent and its associated CAS number, but shall list the chemical family

associated with the chemical constituent, or provide a similar description, and provide a

statement that a claim of trade secret protection has been made by the entity entitled to

make such a claim.

(ii) Listing of a chemical constituent under the requirements of this subdivision

does not preclude a permittee from utilizing other chemical constituents in a high volume

hydraulic fracturing operation; however, the chemical constituents actually used shall be

submitted under the requirements of rule 1406 of these rules.

(d) One signed and sealed copy of the survey, on a form prescribed by the

supervisor, shall be filed with an application for a permit to drill and operate or e-filed

using a procedure approved by the supervisor.

(e) A person applying to drill and operate a well shall completely and accurately

fill out, sign, and file a written application for a permit to drill on a form prescribed by

the supervisor or e-filed using a procedure approved by the supervisor. The application

shall be submitted to the supervisor at the offices of the Michigan Department of

Environmental Quality, Office of Oil, Gas, and Minerals, P.O. Box 30256, Lansing,

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Michigan 48909, and a copy of the first page of the permit application shall be mailed to

the clerk of the county and the surface owner of record of the land on which the well

location is to be located within 7 days of submitting the permit application by first-class

United States mail addressed to the surface owner's last known address as evidenced by

the current property tax roll records.

(f) When the proposed well location is in or adjacent to any areas described in

subdivision (b)(iv)(A) or (B) of this subrule, a person shall file for and obtain all

applicable permits from the department of environmental quality before developing the

well site or access to the well site or before drilling of the well. The person shall also file

for and obtain any additional permits that may be required before the installation of flow

lines or production equipment or before operating the well.

(g) A person shall file an environmental impact assessment as instructed by the

supervisor.

(h) A person shall file an organization report if a current organization report is not

on file with the supervisor.

(i) A person shall file a conformance bond or statement of financial responsibility

pursuant to R 324.210.

(j) A person shall pay the fee as specified by statute. A fee filed with an application

shall not be applied to a subsequent application. The fee shall be returned if a permit is

not issued.

(k) A person shall provide additional information as required in R 324.802 with an

application for a permit to drill and operate an injection well or to convert a previously

drilled well to an injection well.

(l) A person shall receive and post the permit in a conspicuous place at the well

location. The permit shall remain posted at the well location until well completion.

(3) A person who desires to directionally drill a well shall apply for and obtain a

permit to drill and operate as provided in this rule. The application to drill a directionally

drilled well shall include, in addition to the information specified in subrule (2) of this

rule, all of the following information:

(a) The depth at which deviation from vertical is planned.

(b) The angle and path of each deviation.

(c) The proposed horizontal distance and direction from the well location to the

bottom hole.

(d) The well's measured and true vertical depths.

(4) The supervisor shall process a permit application for a well and issue or deny a

permit to drill and operate pursuant to section 61525 of the act. Pursuant to R 324.205,

the supervisor shall not issue a permit to a person or an authorized representative of a

person if the person is not eligible for a permit.

History: 1996 AACS; 2015 AACS; 2018 AACS.

R 324.202 Directional redrilling.

Rule 202. (1) A permittee of a well who desires to directionally redrill an existing

well to a different bottom hole location shall file an application for a new permit. The

application shall set forth, in detail, the new bottom hole location and identify the plug-

back depth of the existing well and shall be filed under R 324.201(3). The directional

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redrilling shall not be commenced until the application has been approved by the

supervisor or authorized representative of the supervisor, except as provided in subrule

(2) of this rule. A new permit and an additional fee shall be required.

(2) A permittee of a well who desires to directionally redrill an existing permitted

drilling well to a different bottom hole location with the drilling rig then on location shall

obtain approval from the supervisor or authorized representative of the supervisor.

Approval to redrill shall be obtained by contacting the authorized representative of the

supervisor in person or by telephone and providing pertinent details of the proposed

directional redrilling. Approval may be granted immediately if all of the following

provisions are complied with:

(a) The existing drilled hole is plugged back before starting the new directional hole

under the provisions of these rules.

(b) The permittee provides an adequate description of the proposed directional

redrill, including the depth, angle, and path of the deviation, and the bottom hole location.

(c) The well has adequate bonding or a statement of financial responsibility has been

filed under R 324.210.

(3) If approval to directionally redrill is granted, a permittee of a well shall obtain a

new permit and pay an additional fee. The application for a new permit and additional fee

shall be filed within 10 days at the offices of the Michigan Department of Environmental

Quality, Office of Oil, Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909. In

addition to other enforcement actions, failure to comply with this subrule shall be cause

for immediate suspension of any or all components of the oil and gas operations on the

well.

(4) A well log and plugging record shall be filed on the plugged-back hole under

these rules.

History: 1996 AACS; 2002 AACS; 2015 AACS.

R 324.203 Lost holes.

Rule 203. (1) A permittee of a well shall obtain approval to skid a rig or move to

start a new hole when a hole has been lost. A new permit or additional fee is not required

if the new well location is within 165 feet of the lost hole and the drilling unit is not

changed.

(2) A permittee of a well may obtain approval for skidding a rig or moving to a new

well location because of a lost hole from the authorized representative of the supervisor

in person or by telephone. Approval may be granted immediately if all of the following

provisions are complied with:

(a) The lost hole shall be plugged before starting the replacement hole under the

provisions of these rules.

(b) The new well location shall be made at a safe distance from the lost hole.

(c) The permittee provides an adequate description of the new bottom hole location.

(d) The new well location shall not create surface waste.

(e) An amended application with corrected attachments and supplements shall be

filed within 5 business days at the offices of the Michigan Department of Environmental

Quality, Office of Oil, Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909. In

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addition to other enforcement actions, failure to comply with this subrule shall be cause

for suspension of any or all components of the oil and gas operations on the well.

(f) A well log and well plugging record shall be filed on all lost holes under the

provisions of these rules.

History: 1996 AACS; 2002 AACS; 2015 AACS.

R 324.204 Permits for oil and gas storage by conversion of operation.

Rule 204. If a well or underground operation developed for a non-oil and gas use

is converted for the storage of oil or gas or any of the natural hydrocarbons produced

from oil or gas, then the well or underground operation shall be classified as an oil or gas

storage operation and shall be subject to the provisions of these rules.

History: 1996 AACS.

R 324.205 Eligibility for permit.

Rule 205. The supervisor shall not issue or transfer a permit, other than as provided

by R 324.206(7) and (8), to a person who has been determined to be in violation of any

of the following:

(a) The act.

(b) These rules.

(c) Permit conditions.

(d) Instructions.

(e) Orders of the supervisor.

(f) An order of the department of environmental quality.

History: 1996 AACS.

R 324.206 Modification of permits; deepening permits; change of ownership.

Rule 206. (1) A permit shall not be transferred to a location outside of the drilling

unit.

(2) A permittee of a well who has not initiated drilling of a well shall not do either of

the following:

(a) Change the well location within the drilling unit without the prior approval of

the supervisor or authorized representative of the supervisor. To receive approval, a

permittee shall return the permit to the Lansing office of the supervisor together with a

revised application with corrected attachments and supplements. If the permittee requests

a change in the well location greater than 165 feet from the permitted location, then a

new permit and an additional fee are required. If the permittee requests a change in the

well location to a location less than 165 feet from the permitted location, then the change

will require a revised permit and no additional fee. A change of location for an injection

well, regardless of distance, requires a new permit and an additional fee. Drilling shall

not begin until the new permit or revised permit has been issued by the supervisor or

authorized representative of the supervisor and posted at the drilling site.

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(b) Change the method of drilling, casing and sealing programs, or other conditions

of the permit without the prior approval of the supervisor or authorized representative of

the supervisor. To receive approval, the permittee shall return the permit to the Lansing

office of the supervisor together with a revised application with corrected attachments

and supplements. If the permittee only requests a modification of the existing permit

conditions, then an additional fee is not required. Drilling shall not begin until the revised

permit has been approved by the supervisor or authorized representative of the supervisor

and posted at the drilling site.

(3) A permittee of a well who begins the drilling of a well and encounters drilling

problems or other drilling conditions that necessitate a change shall not do either of the

following:

(a) Change the well location within the drilling unit, other than as provided by

R 324.203, without the prior approval of the supervisor or authorized representative of

the supervisor. To receive approval to change the well location, the permittee shall return

the permit to the Lansing office of the supervisor together with a revised application with

corrected attachments and supplements. Drilling shall not begin at the new location until

the revised permit has been issued by the supervisor or authorized representative of the

supervisor.

(b) Change the method of drilling, casing and sealing programs, or other conditions

of the permit without the prior approval of the supervisor or authorized representative of

the supervisor. To receive approval to modify an existing permit condition only, the

permittee shall contact the supervisor or authorized representative of the supervisor by

letter, telephone, or visit and explain the drilling circumstances and request the necessary

changes to the permit. The supervisor or authorized representative of the supervisor may

give verbal approval to modify the permit with conditions for additional reporting

requirements by the permittee. If approval to modify an existing permit is granted, then

the revised permit and corrected attachments and supplements shall be filed, within 10

days, at the offices of the Michigan Department of Environmental Quality, Office of Oil,

Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909. An additional permit fee

is not required.

(4) A permittee of a well who desires to deepen a well below the permitted

stratigraphic or producing horizon where well completion has occurred shall file an

application for a deepening permit. The application shall set forth, in detail, the new

proposed total depth and the plan for casing and sealing off the oil, gas, brine, or fresh

water strata to be found, or expected to be found, in the deepening operation. The

deepening operation shall not be commenced until the application has been approved by

the supervisor or authorized representative of the supervisor. A deepening permit and an

additional fee are required.

(5) A permittee of a well who desires to continue the drilling of a well below the

permitted depth, but within the permitted stratigraphic or producing horizon where

drilling completion or well completion has occurred, shall file an application for change

of well status pursuant to R 324.511. The application shall set forth, in detail, the new

proposed total depth and the plan for casing and sealing off the oil, gas, brine, or fresh

water strata found, or expected to be found, when drilling is continued. The approval of

the change of well status shall serve to revise the permit to reflect the new permitted

depth. The continuation of drilling shall not be commenced until the application for

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change of well status has been approved by the supervisor or authorized representative of

the supervisor. To obtain approval to continue the drilling below the permitted depth, but

within the permitted stratigraphic or producing horizon with the drilling rig then on

location, the permittee shall contact the supervisor or authorized representative of the

supervisor by letter, telephone, or visit and explain the circumstances for the request to

continue the drilling. The supervisor or authorized representative may give verbal

approval to continue the drilling below the permitted depth, but within the permitted

stratigraphic or producing horizon. If approval to continue the drilling is granted, then the

permittee shall file the application for change of well status pursuant to R 324.511, within

10 days of approval, at the offices of the Michigan Department of Environmental Quality,

Office of Oil, Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909. An

additional permit fee is not required.

(6) If a permittee of a well conveys his or her rights as an owner of a well to another

person, or ceases to be the authorized representative of the owner of a well, before final

completion, then a request for the transfer of the permit to the acquiring person shall be

submitted by the acquiring person to the supervisor at the offices of the Michigan

Department of Environmental Quality, Office of Oil, Gas, and Minerals, P.O. Box 30256,

Lansing, Michigan 48909, on forms as prescribed by the supervisor. The transfer of the

permit may be approved upon receipt of a properly completed request, including the

signatures of the permittee of record and the acquiring person, and upon the filing by the

acquiring person of the conformance bond or a statement of financial responsibility as

required by R 324.210. Pending the transfer of the existing permit, the acquiring person

shall not operate the well. The acquiring person shall file an organization report pursuant

to R 324.201(2)(h).

(7) A permit for a well shall not be transferred to a person who has been determined

to be in violation of any of the following until the permittee has corrected the violation or

the supervisor has accepted a compliance schedule and a written agreement has been

reached to correct the violations:

(a) The act.

(b) These rules.

(c) Permit conditions.

(d) Instructions.

(e) Orders of the supervisor.

(f) An order of the department of environmental quality.

An additional conformance bond covering the period of the compliance schedule may

be required. The conformance bond is in addition to the conformance bonds filed

pursuant to R 324.212(a) or (b).

(8) If the permittee of a well is under notice because of unsatisfactory conditions at

the well site involved in the transfer, then the permit for a well shall not be transferred to

a person until the permittee has completed the necessary corrective actions or the

acquiring person has entered into a written agreement to correct all of the unsatisfactory

conditions.

History: 1996 AACS; 2015 AACS; 2018 AACS.

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R 324.207

permit.

Suspension of oil and gas operations due to failure to transfer

Rule 207. If a permittee of a well conveys his or her rights as an owner of a well to

another person, or ceases to be the authorized representative of the owner of a well, and

a request for transfer of the permit under R 324.206(6) has not been approved,

then, in addition to other enforcement actions, failure to comply shall be cause

for immediate suspension of any or all components of the oil and gas operations on

the well, including the removal or sale of oil, gas, or brine.

History: 1996 AACS; 2002 AACS.

R 324.208 Termination of permit.

Rule 208. (1) Subject to subrule (2) of this rule, a permit issued pursuant to

R 324.201(4), or transferred pursuant to R 324.206(6) or rules that were in effect before

the effective date of these rules, shall terminate 2 years after the date of issuance, unless

the drilling operation has reached a depth of not less than 100 feet below the ground

surface elevation and the drilling operation is diligently proceeding or the well is

otherwise being used for its permitted purpose.

(2) If a permit is subject to termination under this rule, the permittee may submit a

written request to the supervisor to extend the permit at least 30 days before the

scheduled termination date. Upon receipt of a request, the supervisor may extend the

permit for a period of up to 2 additional years provided there have been no significant

changes in the features or conditions described in R 324.201, or in requirements of these

rules or the act, that would require modifications of the permit.

(3) Terminated permits may not be reactivated or transferred and the permit fee shall

not be refunded.

History: 1996 AACS; 2018 AACS.

R 324.209 Temporary abandonment status.

Rule 209. (1) A permittee of a well that has not been used for its permitted

purpose during 12 consecutive months shall plug the well, unless the well is granted

temporary abandonment status. Temporary abandonment status shall be allowed only

upon written application to, and approval of, the supervisor or authorized representative

of the supervisor.

(2) The term of the initial temporary abandonment status shall not be more than

12 months, unless the well is shut-in awaiting the connection of a sales line. For a well

that is shut-in awaiting connection of a sales line, the term of the initial temporary

abandonment status shall be up to and including 60 months.

(3) Extensions for temporary abandonment status beyond the initial term provided

in subrule (2) of this rule may be granted by the supervisor if, after application by the

permittee, the supervisor determines that waste shall be prevented. When approving

the extensions, the supervisor may require special actions and monitoring by the

permittee to ensure the prevention of waste.

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History: 1996 AACS.

R 324.210

Conformance bond or statement of financial responsibility

requirements.

Rule 210. (1) A person who files an application for a permit to drill and operate a

well under R 324.201, or who acquires a well under R 324.206(6), shall file a

conformance bond with the supervisor on a form prescribed by the supervisor or shall

submit a statement of financial responsibility under subrule (2) of this rule.

(2) A statement of financial responsibility shall consist of all of the following:

(a) A written statement which is signed by the person, which lists data that show that

the person meets the criteria specified in subrule (3) of this rule, and which states that the

data are derived from an independently audited year-end financial statement.

(b) A copy of an independent certified public accountant’s report on examination of

the person’s financial statements for the latest completed fiscal year.

(c) A special report from the person’s independent certified public accountant

stating that the accountant has compared the data listed in the statement provided under

subdivision (a) of this subrule with the amounts in the corresponding year-end financial

statement and that nothing came to the attention of the accountant which caused the

accountant to believe that the financial records should be adjusted.

(3) When a person submits a statement of financial responsibility instead of a

conformance bond, a person shall meet the criteria of either subdivision (a) or (b) of this

subrule, as follows:

(a) A person required to file the statement of financial responsibility shall have all of

the following:

(i) Two of the following 3 ratios:

(A) A ratio of total liabilities to net worth of less than 2.0.

(B) A ratio of the sum of net income plus depreciation, depletion, and amortization

to total liabilities of more than 0.1.

(C) A ratio of current assets to current liabilities of more than 1.5. Projected oil and

gas reserves may be utilized in determining current assets only to the extent that the value

of the reserves exceeds the projected costs of development and production.

(ii) Net working capital and tangible net worth each of which is not less than 3 times

the amount of the conformance bond provided in R 324.212, if the person had elected to

file a conformance bond.

(iii) Total assets in this state that are not less than 3 times the amount of the

conformance bond provided in R 324.212, if the person had elected to file a conformance

bond. Projected oil and gas reserves may be utilized in determining current assets only to

the extent that the value of the reserves exceeds the projected costs of development and

production.

(iv) A written statement from a certified public accountant which states that no

matter came to the attention of the accountant which caused him or her to believe that the

financial records should be adjusted.

(b) A person required to file a statement of financial responsibility shall have all of

the following:

(i) A current rating for his or her most recent bond issuance of AAA, AA, A, or

BBB as issued by Standard and Poor’s or Aaa, Aa, A, or Baa as issued by Moody’s.

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(ii) A tangible net worth of not less than $2,000,000.00.

(iii) Total assets in this state that are not less than 3 times the amount of the

conformance bond provided in R 324.212, if the person had elected to file a conformance

bond. Projected oil and gas reserves may be utilized in determining current assets only to

the extent that the value of the reserves exceeds the projected costs of development and

production.

(4) A person shall submit a statement of financial responsibility to the supervisor not

less than 60 days before the date the financial assurance is scheduled to take effect.

(5) After the initial submission of a statement of financial responsibility, the person

shall send an updated statement of financial responsibility to the supervisor within 90

days after the close of each succeeding fiscal year.

(6) If a person no longer meets the requirements of subrule (3) of this rule, he or she

shall send notice to the supervisor of the intent to establish alternate financial assurance

by filing a conformance bond as specified in subrule (1) of this rule. The notice shall be

sent, by certified mail, within 90 days after the end of the fiscal year for which the year-

end review of the financial records shows that the person no longer meets the

requirements. The person shall provide the alternate financial assurance within 120 days

after the end of the fiscal year.

(7) The supervisor may, based on a reasonable belief that the person no longer meets

the requirements of subrule (3) of this rule, require a report at any time from the person in

addition to the information required by subrule (3) of this rule. If the supervisor finds, on

the basis of a review of the report or other information, that the person no longer meets

the requirements of subrule (3) of this rule, then the supervisor or authorized

representative of the supervisor shall notify and inform the person. Within 30 days of the

notification, the person shall provide alternate financial assurance by filing a

conformance bond as specified in subrule (1) of this rule or shall bring the well to final

completion. Failure to comply with this subrule shall be cause for immediate suspension

of any or all components of the oil and gas operations on the well.

(8) The supervisor may require additional conformance bonds to ensure compliance

with orders of the supervisor, excluding proration, statutory pooling, or spacing orders.

The conformance bond shall be in addition to the conformance bonds filed under

R 324.212(a), (b), or (c) and shall be required only if the supervisor determines that the

existing conformance bond is not adequate to cover the estimated cost of plugging the

well and conducting site restoration or other obligations of the permittee under the order.

A person is not required to file additional conformance bonds under this subrule if the

person has filed a blanket conformance bond or bonds in an aggregate amount of

$250,000.00 or more, under R 324.212(d). Subject to the provisions of R 324.213, the

additional conformance bond shall be released when the permittee has complied with all

provisions of the orders of the supervisor.

(9) Conformance bonds that were in effect before the effective date of these rules

shall remain in effect under the conditions upon which they were filed and accepted by

the supervisor. However, in place of conformance bonds that were in effect before the

effective date of these rules, a permittee may file conformance bonds or submit a

statement of financial responsibility under these rules for wells permitted under the act

before the effective date of these rules.

History: 1996 AACS; 2002 AACS; 2015 AACS.

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R 324.211 Liability on conformance bond.

Rule 211. (1) The liability on the conformance bond is conditioned upon

compliance with the act, these rules, permit conditions, instructions, or orders

of the supervisor. Subject to the provisions in R 324.213, liability shall cover all oil

and gas operations of the permittee as follows:

(a) Through transfer of the permit for the subject well under R 324.206(6).

(b) Through final completion approved by the supervisor of the subject well.

(c) Otherwise as approved by the supervisor.

(2) The supervisor shall look to the conformance bond for immediate

compliance with, and fulfillment of, the full conditions of the act, these rules, permit

conditions, instructions, or orders of the supervisor. All expenses incurred by the

supervisor in achieving compliance with, and fulfillment of, all conditions of the

act, these rules, permit conditions, instructions, or orders of the supervisor shall be

paid by the permittee or the surety or from cash or securities on deposit. The claim

shall be paid within 30 days of notification to the permittee or surety that expenses

have been incurred by the supervisor. If the claim is not paid within 30 days, the

supervisor, acting for and on behalf of the state, may bring suit for the payment of the

claim.

History: 1996 AACS; 2002 AACS.

R 324.212 Conformance bond amounts.

Rule 212. A person who drills or operates a well shall file a conformance bond with

the supervisor for the following amounts, as applicable:

(a) Single well conformance bonds shall be filed in the following amounts, as

applicable:

(i) $20,000.00 for wells up to and including 2,000 feet deep, true vertical depth.

(ii) $40,000.00 for wells deeper than 2,000 feet, but not deeper than 4,000 feet, true

vertical depth.

(iii) $50,000.00 for wells deeper than 4,000 feet, but not deeper than 7,500 feet,

true vertical depth.

(iv) $60,000.00 for wells deeper than 7,500 feet, true vertical depth.

(b) A person may file single well conformance bonds in an amount equal to 1/2 of

the amount specified in subdivision (a) of this rule for wells where well completion

operations have not commenced. A person shall not file single well conformance bonds

under this subdivision for more than 5 wells. A person shall file single well conformance

bonds in the full amount specified in subdivision (a) of this rule or file a blanket

conformance bond as specified in subdivision (c) of this rule or submit a statement of

financial responsibility pursuant to R 324.210 before the commencement of well

completion operations on any well.

(c) Blanket conformance bonds may be filed as an alternative to single well

conformance bonds. If a blanket conformance bond is utilized, then the permittee shall

provide the supervisor with a list of wells covered by the blanket conformance bond. A

maximum of 100 wells may be covered by a blanket conformance bond. If the permittee

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has more than 100 wells in a category, then the additional wells may be covered by single

well conformance bonds or additional blanket conformance bonds. Blanket conformance

bonds shall be filed in the following amounts, as applicable:

(i) $100,000.00 for wells up to and including 2,000 feet deep, true vertical depth.

(ii) $200,000.00 for wells deeper than 2,000 feet, but not deeper than 4,000 feet,

true vertical depth.

(iii) $250,000.00 for wells deeper than 4,000 feet, true vertical depth.

(d) A person shall not be required to file a blanket conformance bond or bonds in an

aggregate amount of more than $250,000.00. When the aggregate amount of the

conformance bonds is $250,000.00, the permittee may file 1 blanket conformance bond

of $250,000.00 to cover all of his or her wells.

History: 1996 AACS; 2018 AACS.

R 324.213 Cancellation of conformance bonds issued by a surety.

Rule 213. (1) A surety company may cancel a conformance bond acquired under

these rules upon 90 days' notice to the supervisor of the effective date of cancellation.

However, the surety company shall retain liability for all violations of the act, these

rules, permit conditions, instructions, or orders of the supervisor that occurred during

the time the conformance bond was in effect.

(2) Forty days before the effective date of cancellation, as provided in subrule

(1) of this rule, a permittee shall secure a conformance

bond from another surety

company authorized to do business in the state of Michigan, deposit cash or other

securities, or bring the well to final completion. Failure to comply with this subrule

shall be cause for the immediate suspension of any or all components of the oil and

gas operations on the well.

(3) A surety company shall remain liable until the

corrected and the corrections are accepted by the supervisor forall violations of the

act, these rules, permit conditions, instructions, or orders of the supervisor that

violations

have been

occurred at the well during the time the conformance bond was in effect before the

effective date of cancellation.

History: 1996 AACS; 2002 AACS.

R 324.214 Limitation of additional liability of blanket conformance bonds.

Rule 214. A surety company may refuse to accept liability for additional wells

under a blanket conformance bond by giving 10 days’ notice by registered mail to

the supervisor. Subject to the provisions of R 324.213, the blanket conformance bond

shall continue in full force and effect as to all other wells covered by the blanket

conformance bond for which permits were granted or transferred to the permittee

before the effective date of the notice.

History: 1996 AACS.

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R 324.215 Release of conformance bonds; release of well from blanket

conformance bond.

Rule 215. (1) A conformance bond shall be released or a well shall be released

from a blanket conformance bond, subject to the provisions of R 324.213, by the

supervisor or authorized representative of the supervisor if a permittee disposes of the

well and the permit for the well has been transferred to a new person pursuant to R

324.206(6) or if the well has been plugged and proper site restoration has been

performed pursuant to R 324.1003, including the filing of the mandatory records.

(2) The release of the conformance bond or the release of a well from a blanket

conformance bond does not release a permittee from liability for any violations of the

act, these rules, permit conditions, instructions, or orders of the supervisor which

occurred during the time the conformance bond was in effect and which have not

been corrected and accepted by the supervisor.

(3) A conformance bond filed to comply with a permit that has become

terminated shall be released if there is final completion.

History: 1996 AACS.

R 324.216 Notice of release of conformance bond or release of well from

blanket conformance bond.

Rule 216. (1) The supervisor or authorized representative of the supervisor

shall advise the surety company and the permittee when the conformance bond has

been released or a well has been released from a blanket conformance bond.

(2) The supervisor or authorized representative of the supervisor shall return cash

to the permittee or securities to the institution that provided the bonding instrument

when the conformance bond has been released.

History: 1996 AACS.

PART 3. SPACING AND LOCATION OF WELLS

R 324.301 Drilling unit; well location; exceptions.

Rule 301. (1) The following provisions specify requirements for the location and

spacing of wells to be drilled for oil or gas, or for wells for oil and gas where a change of

well status or stimulation of the well will result in changes to the producing interval,

except for injection wells and wells to be drilled in gas storage reservoirs, liquid

petroleum gas storage reservoirs, unitized areas, and other specifically designated areas

or geological formations where special spacing orders, rules, or determinations are in

effect:

(a) The drilling unit for wells for oil or gas shall be a legal subdivision of 40 acres,

more or less, defined as a governmental surveyed quarter-quarter section of land. The

drilling unit shall conform to 1 of the quarter-quarters of a governmental surveyed section

of land, with allowances being made for the differences in the size and shape of sections

as indicated by official governmental survey plats.

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(b) The producing interval of a well for oil or gas shall be not less than 330 feet from

the drilling unit boundary.

(c) For purposes of interpreting requirements for the location and spacing of wells

under these rules, the producing interval location of a well that is not intentionally drilled

directionally or horizontally shall be presumed to be directly beneath the well location.

(d) A permit may be issued on a drilling unit that is not totally leased, pooled, or

communitized subject to the following conditions:

(i) The application for permit shall be accompanied by a certified statement

establishing that a good faith effort had been made to obtain the lease or leases or to

obtain a communitization agreement to form a full drilling unit and that such effort failed.

(ii) No portion of the well bore shall transect any tract prior to such time as the tract

is leased, pooled, or communitized.

(iii) The permittee of the well shall not construct or operate any portion of the well,

drill pad, access road, pipeline, or other drilling operations or well completion operations

subject to the permit on any tract that is not leased unless the permittee has obtained the

necessary rights to construct or operate under a surface access agreement or other

applicable instrument.

(iv) Before the well is placed on regular production, a pooled drilling unit shall be

formed by voluntary agreement or statutory pooling pursuant to R 324.304.

(2) The well surface location and associated surface facilities for wells drilled and

constructed after September 20, 1996 shall be located not less than 300 feet from existing

recorded fresh water wells and reasonably identifiable fresh water wells utilized for

human consumption and existing structures used for public or private occupancy.

(3) The well separators, storage tanks, and treatment equipment installed or

constructed after September 20, 1996 shall be located not less than 2,000 feet from type I

and IIa public water supply wells and not less than 800 feet from type IIb and III public

water supply wells, as defined in the safe drinking water act, 1976 PA 399, MCL

325.1001 to 325.1023.

(4) Exceptions to the location and spacing of wells may be granted in the following

instances:

(a) The supervisor or authorized representative of the supervisor issues a permit for

an off-pattern or nonconforming drilling unit well after a hearing to determine the need or

desirability of issuing the permit. The wells shall be subject to the restricted or adjusted

allowables that the supervisor considers necessary to ensure that the owners shall be

afforded the opportunity to produce their just and equitable share of the oil and gas from

the reservoir and to prevent waste.

(b) The supervisor or authorized representative of the supervisor issues a permit for

a well where the surface location is closer than 300 feet from all existing recorded fresh

water wells and reasonably identifiable fresh water wells utilized for human consumption

and existing structures used for public or private occupancy upon presentation, to the

supervisor, of written consent signed by the owner or owners of all existing fresh water

wells and reasonably identifiable fresh water wells utilized for human consumption and

existing structures used for public or private occupancy.

(c) The supervisor determines the well surface location or location of associated

surface facilities will prevent waste, protect environmental values, and not compromise

public safety after a hearing pursuant to part 12 of these rules.

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(d) The supervisor approves an application to pool or communitize tracts or mineral

interests pursuant to R 324.303(2).

History: 1996 AACS; 2015 AACS.

R 324.302 Adoption of special spacing orders.

Rule 302. The development of an oil or gas field may warrant the adoption of

drilling units and well spacing patterns other than as specified in R 324.301(1). An

interested person may request, or the supervisor may schedule, a hearing pursuant to part

12 of these rules to consider the need or desirability of adopting a special spacing order to

apply to a designated area, field, pool, or geological strata. The drilling unit established

by the special spacing order may be smaller or larger than the basic 40-acre unit pursuant

to R 324.301(1)(a).

History: 1996 AACS; 2015 AACS.

R 324.303 Voluntary pooling.

Rule 303. (1) The lessees or lessors, or both, of separate tracts or mineral interests

that lie partially or wholly within an established drilling unit or larger area may pool or

communitize the tracts or interests to form full drilling units or multiples of full drilling

units and to develop the units pursuant to the provisions of these rules and the applicable

orders of the supervisor.

(2) Persons who pool or communitize the tracts or interests may submit an

application to the supervisor to abrogate spacing within the pooled or communitized area.

The application shall include a certified copy of the pooling or communitization

agreement and the plans for exploration or development. The supervisor may approve the

application if all of the following conditions are satisfied:

(a) Waste is prevented.

(b) The drilling of unnecessary wells is prevented.

(c) A producing interval of a well is not located closer than 330 feet from the pooled

or communitized area boundary.

(3) The lessees and lessors of separate tracts or mineral interests that lie partially or

wholly within an area encompassing 2 or more full drilling units may voluntarily pool the

tracts or interests to form a development unit for the purpose of receiving a permit for a

well as an exception to R 324.301(1) or special spacing orders adopted pursuant to

R 324.302, if the producing interval location of the well is found by the supervisor to

ensure each producer is afforded the opportunity to use his or her just and equitable share

of the reservoir energy and to prevent waste, including the drilling of unnecessary wells.

History: 1996 AACS; 2015 AACS.

R 324.304 Statutory pooling.

Rule 304. The supervisor may require the pooling of tracts or mineral interests

within a drilling unit when the owners of the tracts or mineral interests have not agreed,

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or do not agree, upon the pooling of the interests to form full drilling units pursuant to

these rules and the applicable spacing orders. The statutory pooling shall be done on a

basis which ensures that each owner of an interest within a drilling unit is afforded the

opportunity to receive his or her just and equitable share of the production from the unit.

Statutory pooling shall be adopted by the supervisor only after a hearing pursuant to part

12 of these rules.

History: 1996 AACS; 2015 AACS.

PART 4. DRILLING AND WELL CONSTRUCTION

R 324.401 Preventing waste.

Rule 401. A person who drills a well or wells as described in R 324.201(1) shall use

every reasonable precaution to prevent waste.

History: 1996 AACS.

R 324.402 Drilling notification.

Rule 402. Not less than 5 days before preparing the location and not less than 48

hours before moving drilling equipment on location, the permittee shall notify the

supervisor or authorized representative of the supervisor and the surface owner when

well construction is to begin. Notice may be given verbally or by first-class United

States mail.

History: 1996 AACS.

R 324.403 Construction of water wells used for drilling or surface facilities.

Rule 403. (1) A water well that is drilled and used for drinking water purposes

during the drilling of the well or retained after drilling completion or final completion

must be drilled pursuant to rules promulgated under part 127 of the public health code,

1978 PA 368, MCL 333.12701 to 333.12771.

(2) A water well that is not to be retained after drilling completion or final

completion must be completed and abandoned as instructed by the supervisor and must

meet all of the following minimum requirements:

(a) The well must be located not less than 50 feet from drilling mud pits, pipe racks,

salt and mud mixing sites, and the wellhead.

(b) The water used in the drilling fluid must be chlorinated fresh water that is free of

contamination in concentrations that may cause disease or harmful physiological effects.

(c) The well must be grouted pursuant to the well construction and grouting rules

contained in the well construction code promulgated under part 127 of the public health

code, 1978 PA 368, MCL 333.12701 to 333.12771.

(d) Geologic records must be filed with the supervisor on a form prescribed by the

supervisor.

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(e) The wellhead, including annulus, must be sealed and a check valve must be

installed in the surface discharge line to prevent contaminants from entering the well.

(f) The well must be abandoned and plugged pursuant to the plugging and

abandonment rules contained in the well construction code promulgated under part 127

of the public health code, 1978 PA 368, MCL 333.12701 to 333.12771.

History: 1996 AACS; 2019 AACS.

R 324.404 Use of surface water for drilling prohibited; exception.

Rule 404. Surface water shall not be used for drilling fluid, except for emergency

situations to protect the public health and safety.

History: 1996 AACS.

R 324.405 Drilling fluids generally.

Rule 405. The drilling fluid used for drilling wells described in R 324.201(1) m u st

be capable of sealing off and protecting each oil, gas, brine, or fresh water stratum

above the stratigraphic or producing horizon and controlling subsurface pressures. The

water or brines used in the drilling fluid must be from a source approved by the

supervisor or authorized representative of the supervisor, used pursuant to approved

safe drilling practice, and tested as instructed by the supervisor, except that the water

used in the drilling fluid for the drilling of the hole for the surface casing must be fresh

water that is free of contamination in concentrations that may cause disease or harmful

physiological effects.

History: 1996 AACS; 2019 AACS.

R 324.406 Blowout prevention equipment.

Rule 406. (1) All wells shall be equipped with the following equipment:

(a) A double ram blowout preventer, including pipe and blind rams, and an

annular-type blowout preventer or other equivalent control system as approved by the

supervisor or authorized representative of the supervisor.

(b) Accessible controls both on the rig floor and at a safe remote location.

(c) A kelly valve.

(d) A drill pipe safety valve.

(e) A flow line of the proper size and working pressure.

(f) Blowout prevention equipment that has a rated working pressure which equals

or exceeds the maximum anticipated surface pressure of the well.

(2) The blowout preventers shall be installed above ground level. The entire

control equipment shall be in good working condition at all times. All outlets, fittings,

and connections on the casing, blowout preventers, choke manifold, and auxiliary

wellhead equipment that may be subjected to wellhead pressure shall be of a material

and construction that will withstand the anticipated pressure. The lines from outlets on

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or below the blowout preventers shall be securely installed, anchored, and protected

from damage.

(3) Blowout preventers, accumulators, and pumps shall be certified as operable

under the product manufacturer's minimum operational specifications.

Certification shall include the proper operation of the closing unit valving, the

pressure gauges, and the manufacturer's recommended accumulator fluids. Certification

shall be obtained through an independent company that tests blowout preventers,

stacks, and casings. Certification shall be required annually and shall be posted on the

rig floor. In addition to the primary closing system, including an accumulator system,

the blowout preventers shall have a secondary system. A combination of any 2 of the

following secondary closing systems is acceptable:

(a) Electric-operated pump.

(b) Air-operated pump.

(c) Hand-operated pump.

(d) Nitrogen-operated pump.

Extensions that have hand wheels are not mandatory. Blowout preventer rams shall

be of a proper size for the drill pipe being used or production casing being run in the well

or shall be variable-type rams that are of the proper size range.

(4)

Blowout prevention equipment shall be tested to

a

pressure

commensurate with the expected formation pressure, but not less than 1,000 psig at

surface for not less than 20 minutes, before drilling the plug on the surface casing,

intermediate casing, and the production casing and before encountering all high-

pressure formations and at other intervals as approved or requested by the supervisor.

When requested, an authorized representative of the supervisor shall be notified before

the commencement of a test. A record of each test, including test pressures, times,

failures, and each mechanical test of the casings, blowout preventers, surface

connections, surface fittings, and auxiliary wellhead equipment shall be entered in the

logbook, signed by the driller, and kept available for inspection by the supervisor or

authorized representative of the supervisor.

(5) A trip tank, or an accurate drilling fluid monitoring system, and a gas buster

and flare system shall be in place when penetrating the A2 carbonate or any known

or suspected overpressurized formations.

Permission to change or modify the

requirements specified in this subrule may be granted by submitting a written request

to the supervisor or authorized representative of the supervisor. The requirements

may be changed or modified only after submission of a written request and receipt of

written approval from the supervisor or authorized representative of the supervisor.

(6) An exception to all or part of this rule may be granted by the supervisor or

authorized representative of the supervisor when drilling in shallow low-pressure

formations. The supervisor or authorized representative of the supervisor may grant an

exception upon receipt of an application for a permit that is accompanied by a written

request and supportive data.

History: 1996 AACS.

R 324.407 Drilling mud pits.

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Rule 407. (1) The supervisor shall prohibit the use of a drilling mud pit if it is

determined that the mud pit causes waste.

(2) Drill cuttings, muds, and fluids shall be confined by a pit, tank, or container

which is of proper size and construction and which is located as approved by the

supervisor or authorized representative of the supervisor.

(3) Only tanks shall be utilized while drilling a well that is located in an area zoned

residential before January 8, 1993. The supervisor may grant an exception if the applicant

or permittee makes a request for an exception as part of the written application for a

permit. The supervisor may grant an exception if an applicant or permittee satisfactorily

demonstrates that a municipal water system is utilized or required to be utilized.

(4) Drilling mud pits shall be located and plotted as instructed by the supervisor.

Before construction of the mud pit, a permittee shall demonstrate to the supervisor or

authorized representative of the supervisor that there is not less than 4 feet of vertical

isolation between the bottom of the pit and the uppermost groundwater level. The bottom

of the liner shall not be installed within the observed groundwater level as determined

while excavating the pit. If groundwater is encountered during or before construction of

the pit, then the permittee shall select 1 of the following options and obtain the approval

for the option from the supervisor or authorized representative of the supervisor:

(a) The pit shall be designed and constructed so the bottom of the pit is not less than

4 feet above the groundwater level.

(b) The pit shall be designed and constructed so the bottom of the pit is above the

groundwater level, but less than 4 feet above the groundwater level, and during

encapsulation the pit contents shall be solidified using a method approved by the

supervisor.

(c) The pit shall be relocated at the well site as approved by the supervisor or

authorized representative of the supervisor.

(d) Tanks shall be used, and drilling muds disposed of, at an approved off-site

location.

(5) Drilling mud pits shall be constructed as instructed by the supervisor and shall be

in compliance with both of the following minimum requirements:

(a) Pits shall be constructed with rounded corners and side slopes of not less than 20

degrees measured from the vertical.

(b) The bottom and sides of the pit shall be free of objects that could penetrate the

liner.

(6) Drilling mud pits shall be lined as instructed by the supervisor and shall be in

compliance with all of the following minimum requirements:

(a) Pits shall be lined with 20-mil virgin polyvinyl chloride liners as approved by the

supervisor or with other liners that meet or exceed the 20-mil virgin polyvinyl chloride

liner requirement.

(b) Ample liner material shall be installed in a manner to allow for sags and material

loading to reduce stress on the liner and allow for a minimum 10-foot flat apron on all

sides, including enough liner material to underlay the drilling mud tank, salt washer, and

shale shaker.

(c) The bottom of the lined pit shall be weighted with earthen material or water

before anchoring the ends of the liner on the surface or placing drilling muds in the pit.

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(d) Ripping, tearing, puncturing, or other destruction of a liner that may cause loss

of fluids is prohibited.

(e) Liner field seams are prohibited, except for liner field seams that result from

failures in the liner due to abrasion or accidental perforation, which shall be immediately

repaired in the field using the manufacturer's recommended procedures.

(7) Drilling mud pits shall be utilized as instructed by the supervisor and shall be in

compliance with all of the following minimum requirements:

(a) Solid salt cuttings shall not be released to inground drilling mud pits. Solid salt

cuttings obtained while drilling below the base of the Detroit River Anhydrite to the top

of the Amherstburg formation and while drilling through the formations in the Salina

Group shall be collected in a container at the shale shaker and either diverted to a device

that will result in the dissolving of the solid salt cuttings and the proper disposal of the

resultant brine pursuant to R 324.703 or removed from the drilling site to a licensed

disposal facility.

(b) Twenty-four months after the effective date of these rules, only the following

may be placed in a lined pit:

(i) Water-based drilling muds generated or utilized while drilling above the base of

the Detroit River Anhydrite.

(ii) Drilling fluids generated or utilized while drilling above the base of the Detroit

River Anhydrite.

(iii) Cuttings obtained while drilling above the base of the Detroit River Anhydrite.

(iv) Cuttings and the solid fraction of drilling muds generated or utilized while

drilling below the base of the Detroit River Anhydrite, other than drill cuttings prohibited

by subdivision (a) of this subrule, if the cuttings and the solid fraction of drilling muds do

not contain free liquids as determined by the United States environmental protection

agency, paint filter liquids test, method 9095, September 1986 edition, which is adopted

by reference in these rules. Copies are available for inspection at the Lansing office of the

office of oil, gas, and minerals of the department of environmental quality. Copies may

be obtained without charge as of the time of adoption of these rules from the Michigan

Department of Environmental Quality, Office of Oil, Gas, and Minerals, P.O. Box 30256,

Lansing, Michigan 48909, or from the United States Environmental Protection Agency,

Office of Research and Development, 26 West Martin Luther King Boulevard,

Cincinnati, Ohio 45268. A permittee shall provide the necessary equipment at the site of

the drilling rig to perform the paint filter liquids test.

(v) Water-based drilling muds and entrained cuttings, other than drill cuttings

prohibited by subdivision (a) of this subrule, which are generated or utilized while

drilling below the base of the Detroit River Anhydrite, which contain weighting materials

or lost circulation materials, and which cannot reasonably be treated to eliminate free

liquids as determined by the paint filter liquids test identified in paragraph (iv) of this

subdivision, if approved by the supervisor or authorized representative of the supervisor.

(vi) Native soils.

(vii) Cementing materials.

(viii) Stiffening or solidification materials approved by the supervisor.

(c) During the initial 24 months after the effective date of these rules, only the

following may be placed in a lined pit:

(i) Water-based drilling muds.

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(ii) Drilling fluids.

(iii) Cuttings that are not prohibited by subdivision (a) of this subrule.

(iv) Native soils.

(v) Cementing materials.

(vi) Stiffening or solidification materials approved by the supervisor.

(d) Machine oil, refuse, completion and test fluids, liquid hydrocarbons, or other

materials may not be placed in a lined pit.

(e) A permittee of a well shall, before encapsulation, test the fluids and cuttings

remaining in the pit to determine the concentrations of benzene, ethylbenzene, toluene,

and xylene and provide certification to the supervisor or authorized representative of the

supervisor of the test results, except that a permittee is not required to test the fluids and

cuttings remaining in the pit for benzene, ethylbenzene, toluene, and xylene if the well

was drilled with water from a source approved by the supervisor and if, during the

drilling operation, liquid hydrocarbons were not encountered.

(8) If a drilling mud pit is not closed immediately after reaching drilling completion,

then a permittee of a well shall fence the perimeter of the drilling mud pit as soon as

practical after drilling completion, but not later than 30 days after drilling completion, to

prevent public access.

(9) A permittee of a well shall close a drilling mud pit as instructed by the supervisor

and be in compliance with all of the following minimum requirements:

(a) All free liquids above the solids in the pit shall be removed to the maximum

extent practical and disposed of in an approved disposal well or used in a manner

approved by the supervisor.

(b) All drilling mud pits shall be stiffened before encapsulation, except as provided

in subrule (4)(b) of this rule. Earthen materials shall be mixed with the pit contents to

stiffen the pit contents sufficiently to provide physical stability and support for the pit

cover. An alternative pit stiffening process approved by the supervisor may be used at the

option of a permittee or if required by the supervisor.

(c) The drilling mud pit shall be carefully encapsulated and buried as soon as

practical after drilling completion, but not more than 6 months after drilling completion.

(d) Apron edges of the liner shall be folded over the pit proper.

(e) The drilling mud pit shall be totally covered with a separate piece of material that

meets or exceeds the specifications of a 20-mil virgin polyvinyl chloride cover as

approved by the supervisor. The cover shall extend beyond the outer edges of the pit to

cover and entirely encapsulate the pit and shall be sloped to provide surface drainage

away from the pit.

(f) The drilling mud pit shall be buried not less than 4 feet below the original ground

grade level.

History: 1996 AACS; 2015 AACS.

R 324.408 Surface casing.

Rule 408. (1) Surface casing shall be set a minimum of 100 feet below the base of

the glacial drift into competent bedrock and 100 feet below all fresh water strata.

(2)

Surface casing shall be cemented pursuant to R 324.411 and shall be

circulated to the surface. If the cement falls back or fails to circulate to the surface, then

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the open annulus space shall be sealed with cement or other equivalent materials

approved by the supervisor or authorized representative of the supervisor before

resuming drilling.

History: 1996 AACS.

R 324.409 Wells drilled with cable tools.

Rule 409. Wells drilled with cable tools shall have the innermost string of casing

equipped with a high-pressure master gate valve, flow line assembly, control head

with oil saver, bottle with hydraulic lubricator, or other combination of equipment

approved by the supervisor or authorized representative of the supervisor. All of the

equipment shall be anchored to the surface casing or another casing string before drilling

into or through a stratum known to contain or likely to contain oil or gas. The

wellhead

equipment and casing to be installed to keep a well under control shall be pressure-

tested commensurate to formation pressures, shall be in good working order when

installed, shall be maintained in good working order throughout its use on the well, and

shall be capable of being equipped with a bottle or lubricator, or both, when this method

of control is necessary. The annulus shall be sealed with a bradenhead or other approved

equipment that has a connection and valve for monitoring.

History: 1996 AACS.

R 324.410 Casing other than surface casing.

Rule 410. (1) A person who drills a well or causes a well to be drilled pursuant to

R 324.201 or rules that were in effect before the effective date of these rules shall case

the well in a manner approved by the supervisor to prevent waste.

(2) In addition to the surface casing, the supervisor may require or order a string

of casing to be run to seal off any of the following:

(a) A potentially productive oil or gas zone, or both.

(b) A lost circulation zone.

(c) A utilized natural brine or mineral zone.

(d) A storage field.

(e) A high-pressure zone.

(f) A reservoir undergoing secondary recovery.

(3) All casing, except for casing set pursuant to R 324.413, shall be of sufficient

weight, grade, and condition to have a designed minimum internal yield of 1.2 times the

greatest expected well bore pressure to be encountered.

(4) For the purpose of proper sealing of wells and the prevention of waste, the

minimum hole size for a given casing shall be as shown in table 410:

Table 410

Minimum Hole Size

Casing size

Minimum hole

size

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outside diameter (O.D.)-inches

Up to 7 O.D.

outside diameter -

Casing O.D. +

inches

1 1/2

More than 7 O.D.

2

3

More than 10 3/4 O.D.

An exception to the minimum hole size as shown in table 410 may be granted by the

supervisor or authorized representative of the supervisor, upon a written request by the

permittee or applicant, if it is determined that the proposal provides proper sealing of

the well. The supervisor or authorized representative of the supervisor may require

a larger hole size for the surface hole than the size shown in table 410 in order to

prevent waste.

History: 1996 AACS.

R 324.411 Cementing.

Rule 411. Well casing shall be cemented by the pump and plug method or by a

method approved by the supervisor and allowed to set undisturbed at static balance with

the casing in tension, with surface pressure released, and with no backflow until the tail-

in slurry reaches 500 psi compressive strength, but for not less than 12 hours; however, if

backflow occurs, then the surface pressure shall not be released. The cement mixture

shall be of a composition and volume approved by the supervisor or authorized

representative of the supervisor. The casing shall be pressure-tested before the cement

plugs are drilled or the casing perforated. The pressure at the top of the cement shall be

equal to the expected operating pressure of the well; however, the test pressure shall not

exceed the API specification for hydrostatic test pressure for new casing, API

specification 5CT, specification for casing and tubing, July 2011, ninth edition, which is

adopted by reference in these rules. Copies are available for inspection at the Lansing

office of the office of oil, gas, and minerals of the department of environmental quality.

Copies may be obtained from the Michigan Department of Environmental Quality, Office

of Oil, Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909, at a cost as of the

time of adoption of these rules of $237.00 each, and from the American Petroleum

Institute, 1220 L Street NW, Washington, DC 20005, at a cost as of the time of adoption

of these rules of $237.00 each.

History: 1996 AACS; 2015 AACS.

R 324.412 Stripping of casing.

Rule 412. (1) A permittee of a well shall not pull or strip a string of casing from a

well, except under the following circumstances:

(a) When provision is made for the removal of casing in the casing and sealing

program specified in the application for permission to drill and operate.

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(b) When casing is pulled and reset in the same stratum to obtain a satisfactory

casing seat.

(c) When a well is being plugged back or is being plugged to the surface under the

change of well status provided in R 324.511 or the plugging instructions set forth in

R 324.902.

(2) A permittee of a well shall seal the annular space left open and the stratum

exposed by the approved pulling and stripping of casing in a manner approved by the

supervisor or authorized representative of the supervisor.

History: 1996 AACS.

R 324.413 Drilling to strata beneath gas storage reservoirs.

Rule 413. Except when special orders have been adopted for specific reservoirs,

areas, or practices, all of the following provisions about drilling to strata beneath gas

storage reservoirs shall apply:

(a) The applicant shall send a copy of the entire drilling permit application and all

revisions to the gas storage operator when the application and revisions are submitted to

the supervisor. The gas storage operator shall have 10 business days to provide written

comments to the supervisor.

(b) Drilling operations shall proceed through gas storage zones only when the gas

storage reservoir pressure exerts a pressure gradient of not more than 0.50 psig per foot of

true vertical depth to the top of the gas storage zone.

(c) Drilling rigs for wells drilled through gas storage reservoirs shall use rotary tools

and shall have blowout prevention equipment pursuant to R 324.406. Complete

operational checks of the well control appliances shall be made every 8 hours, with the

well control system initially checked by pressure testing and checked again before

drilling into the gas storage reservoir. The 8-hour checks shall be recorded in the daily

driller's log.

(d) Surface casing and any other protective casing string required above the gas

storage reservoir shall be new casing manufactured in compliance with the API

specifications for casing and tubing as adopted by reference in R 324.411, the properties

and design of which have been approved by the supervisor or authorized representative of

the supervisor. Surface casing and any other protective casing string shall be designed to

withstand the required test pressures as set forth in R 324.410(3). Surface casing shall be

set pursuant to R 324.408. Surface casing shall be cemented to the surface and not

disturbed for a period of 18 hours after completion of cementing. Cement shall attain a

minimum compressive strength of 500 psi before disturbing the casing or resuming

drilling. Surface casing, other protective casing strings, and blowout preventers shall be

tested pursuant to R 324.406(4) before drilling out the cement, unless otherwise specified

by the supervisor or authorized representative of the supervisor.

(e) Drilling fluid shall be circulated and conditioned at a point not less than 100 feet

above the gas storage reservoir and shall be maintained with the following characteristics

until the gas storage reservoir is cased off:

(i) Drilling fluid density shall be sufficient to provide a hydrostatic pressure of not

less than 100 psig above the anticipated bottom hole pressure of the gas storage reservoir.

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(ii) When drilling through the storage reservoir, the drilling fluid shall have a

maximum fluid loss of 15 cubic centimeters or less as specified by the API standard

procedure for testing drilling fluids, API RP 13B-1, entitled “Recommended Practice for

Field Testing Water-Based Drilling Fluids,” March, 2009, fourth edition, which is

adopted by reference in these rules. Copies are available for inspection at the Lansing

office of the office of oil, gas, and minerals of the department of environmental quality.

Copies may be obtained from the Michigan Department of Environmental Quality, Office

of Oil, Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909, at a cost as of the

time of adoption of these rules of $165.00 each, and from the American Petroleum

Institute, 1220 L Street NW, Washington, DC 20005, at a cost as of the time of adoption

of these rules of $165.00 each.

(f) Hole size shall be large enough to allow the running of a separate intermediate

casing, which shall be set through each gas storage reservoir. The casing shall be new and

conform to the API specification and performance properties for casing, tubing, and drill

pipe, API BULL 5C3, entitled “Bulletin on Formulas and Calculations for Casing,

Tubing, Drill Pipe, and Line Pipe Properties, October 1, 1994,” sixth edition, which is

adopted by reference in these rules. Copies are available for inspection at the Lansing

office of the office of oil, gas, and minerals of the department of environmental quality.

Copies may be obtained from the Michigan Department of Environmental Quality, Office

of Oil, Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909, at a cost as of the

time of adoption of these rules of $206.00 each, and from the American Petroleum

Institute, 1220 L Street NW, Washington, DC 20005, at a cost as of the time of adoption

of these rules of $206.00 each. The gas storage operator shall be allowed to review the

intermediate casing design and cementing program before implementation. Intermediate

casing shall be set in competent stratum approximately 100 feet below the base of the gas

storage reservoir or set as required by the supervisor or authorized representative of the

supervisor. Intermediate casing shall be designed for the maximum gas storage reservoir

operating pressure using a minimum collapse design factor of 1.125, a minimum burst

design factor of 1.25, and a minimum tension design safety factor of 1.6. The minimum

hole size for a given size casing shall be pursuant to R 324.410(4). The hole shall be

properly conditioned before running casing by circulating the drilling fluid at a rate equal

to the drilling circulating rate and by utilizing a circulating time equivalent of not less

than twice the hole displacement. Casing shall be equipped with a sufficient number of

centralizers and scratchers to ensure good cement distribution and shall include

centralizers above and below the gas storage reservoir. All centralizers shall conform to

the API for casing centralizers, API specification 10D, entitled “Specification for Bow-

Spring Casing Centralizers,” March 6, 2002, sixth edition, which is adopted by reference

in these rules. Copies are available for inspection at the Lansing office of the office of oil,

gas, and minerals of the department of environmental quality. Copies may be obtained

from the Michigan Department of Environmental Quality, Office of Oil, Gas, and

Minerals, P.O. Box 30256, Lansing, Michigan 48909, at a cost as of the time of adoption

of these rules of $89.00 each, and from the American Petroleum Institute, 1220 L Street

NW, Washington, DC 20005, at a cost as of the time of adoption of these rules of $89.00

each. Casing shall include float equipment that will prevent movement after the

cementing operation is completed. If conditions allow, casing shall be rotated or

reciprocated slowly during cementing. The mill varnish shall be removed from the casing

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shoe to a point 100 feet above the storage reservoir. An acceptable spacer that is at least

as dense as the drilling fluid shall precede the cement to aid in removing the drilling

fluid. Cement mix water shall be tested before the cementing operation to ensure

compatibility with the cement. The casing shall be cemented using a sufficient cement

volume to circulate cement to the surface. Multistage cementing operations and external

casing packers may be used only with the approval of the supervisor or authorized

representative of the supervisor. Cemented casing shall not be disturbed for a period of

18 hours. Cement shall also attain a minimum compressive strength of 500 psi based on

cement tables before disturbing the casing or resuming drilling. Absent backflow, the

internal casing pressure shall be relieved after the cementing operation. Intermediate

casing and the blowout preventers shall be tested to a pressure of not less than 1,500 psig

at the surface or as otherwise specified by the supervisor or authorized representative of

the supervisor, and the pressure shall be held for not less than 20 minutes before drilling

out the cement.

(g) When additional intermediate casing is run inside the innermost storage zone

casing, below the base of the Detroit river group, the intermediate casing string and

cementing shall be pursuant to these rules and the orders and instructions issued by the

supervisor.

(h) A centralized cement bond evaluation log or equivalent test approved by the

supervisor shall be performed on the storage zone casing before running subsequent

casing or plugging the hole, but not sooner than 48 hours after cementing the storage

zone intermediate casing. A description of problems occurring while running or

cementing casing shall be recorded in the daily driller's log. If unsatisfactory conditions

are indicated, including unsatisfactory cement bonding, gas to the surface in the cellar

area, or gas pressure on the surface or intermediate casing string annulus, and additional

testing does not provide sufficient proof the unsatisfactory condition does not exist, then

the permittee shall initiate remedial action before additional casing is installed.

(i) Wellhead equipment and assemblies shall conform to the API specification for

wellhead equipment, and shall include slip and seal assemblies for all casings, unless an

exception is approved by the supervisor or authorized representative of the supervisor.

The API specification for wellhead equipment is specification 6A, entitled “Specification

for Wellhead and Christmas Tree Equipment,” October, 2010, twentieth edition, which is

adopted by reference in these rules. Copies are available for inspection at the Lansing

office of the office of oil, gas, and minerals of the department of environmental quality.

Copies may be obtained from the Michigan Department of Environmental Quality, Office

of Oil, Gas, and Minerals, P.O. Box 30256, Lansing, Michigan 48909, at a cost as of the

time of adoption of these rules of $260.00 each, and from the American Petroleum

Institute, 1220 L Street NW, Washington, DC 20005, at a cost as of the time of adoption

of these rules of $260.00 each. The wellhead shall be assembled to allow the monitoring

of the pressure of each annulus at the surface.

(j) The permittee shall notify the gas storage operator before moving personnel or

equipment, or both, onto the well location to ensure all of the following:

(i) That the proposed well location does not endanger gas storage facilities or

storage operations.

(ii) That the movement of drilling rigs, related trucks, and equipment does not

endanger gas storage facilities or storage operations.

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(iii) That the gas storage operator is allowed to witness drilling operations that

impact the gas storage reservoir.

History: 1996 AACS; 2015 AACS.

R 324.414 Requests for exceptions to R 324.406 through R 324.413.

Rule 414. If a permittee of a well demonstrates alternative methods that are in

compliance with the requirements of these rules, then the request for an exception to the

provisions of R 324.406 through R 324.413 and the rationale for the alternate

methods shall be included in the application for permission to drill or shall be submitted

in writing to the supervisor.

History: 1996 AACS.

R 324.415 Elevations; well depth measurements.

Rule 415. (1) Drilling reference elevations of the kelly bushing or rig floor and a

described point on the production casing shall be measured, recorded, and filed

pursuant to R 324.418.

(2) The depth of the top of key geologic strata shall be accurately determined

and shall be entered in the drilling log book and become a part of the record and log of

the well. Additional requirements for directional drilled wells are contained in R

324.421.

History: 1996 AACS.

R 324.416 Well records; service company records; confidentiality.

Rule 416. (1) A person who drills, deepens, changes well status, or completes a

well under R 324.201, R 324.420, R 324.511, or rules that were in effect before the

effective date of these rules shall keep and preserve at the well, during drilling,

deepening, changes in well status, or completion operations, accurate records recording

all geologic strata penetrated, casing and cement used, and other information as may be

required by the supervisor in connection with the drilling of the well.

(2) When requested by the supervisor or authorized representative of the

supervisor, a permittee of a well shall file a copy of service company records,

including records of all of the following:

(a) Mudding, cementing, and squeeze operations.

(b) Acidizing.

(c) Perforating.

(d) Fracturing.

(e) Shooting.

(f) Temperature surveys.

(g) Bond logs.

(h) Caliper surveys.

(i) Wireline borehole and strata evaluation logs.

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The supervisor may request the records directly from the service company.

(3) A permittee of a well shall make all records and information available to the

supervisor or authorized representative of the supervisor at all times. A permittee

shall protect the records from damage or destruction due to a preventable cause. All well

data and samples provided to the supervisor or authorized representative of the supervisor

as required by these rules shall be held confidential commencing with the receipt of a

written request of the permittee and shall remain confidential for 90 days after drilling

completion. Information on volumes, concentrations, and times of releases, spills, or

leaks of gas, brine, crude oil, oil or gas field waste, or products and chemicals used

in association with oil and gas exploration, production, disposal, or development is not

subject to confidentiality.

History: 1996 AACS; 2001 AACS.

R 324.417 Samples of drill cuttings and cores.

Rule 417. (1) A person who drills a well pursuant to R 324.201 or rules that were

in effect before the effective date of these rules shall take and preserve, for the duration

of the drilling, properly identified samples of the drill cuttings taken from the base of

the drift to the total depth.

(2) A permittee of a well shall take and preserve drift samples when specifically

requested by the supervisor or authorized representative of the supervisor. The samples

shall be available to the supervisor upon request.

(3) When requested before the commencement of drilling, a permittee of a well

shall deliver 1 complete set of drill cutting samples, washed and dried, to the supervisor

within 90 days after drilling completion. Samples not requested may be disposed of in

a manner approved by the supervisor upon drilling completion.

(4) When a permittee of a well obtains whole cores or core samples during the

drilling of a well, the permittee shall provide the supervisor with a minimum of 90

days’ notification of his or her intention to dispose of or destroy the whole cores or

core samples. When requested by the supervisor, pursuant to the notification, the

permittee shall deliver the whole cores or core samples to the supervisor within 90 days

of the request.

History: 1996 AACS.

R 324.418 Filing of well records.

Rule 418. A permittee of a well who drills a well shall file all of the following

records with the supervisor:

(a) Within 60 days after drilling completion, a complete written geologic description

log or record of the well, certified by the permittee, on forms prescribed by the

supervisor, including all of the following information:

(i) Elevations pursuant to R 324.415.

(ii) Depth to, and thickness of, water-bearing sands and gravels in the glacial drift as

determined by a geologist, including fill-up and volumes of the water, if available.

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(iii) The measured and true vertical depth to geologic strata penetrated, and accurate

and complete lithologic descriptions, including color, hardness, and the character of the

rock as determined by a geologist.

(iv) A record of all shows of oil or gas, or both, encountered.

(v) A record of all lost circulation zones encountered.

(vi) A record of all hole sizes, casings, and liners used, including the size, weight,

grade, amount, and depth set for each casing string.

(vii) The amount of cement used and the calculated elevation of the top of the

cement, unless the supervisor or authorized representative of the supervisor requests the

elevation to be measured.

(viii) Data on all drill stem tests. The minimum education and experience

requirements for a geologist to determine the information required in this subrule are

graduation from a university or college that has an accredited 4-year curriculum in a

geological science, receipt of a 4-year degree in a geological science, and 2 years of

practical experience providing geological services, including consultation, investigation,

evaluation, planning, or responsible supervision of geological activities requiring the

application of geologic principles and techniques.

(b) Within 60 days after well completion operations, data on all perforating,

acidizing, fracturing, shooting, and testing, except that information on chemical additives

used in a high volume hydraulic fracturing operation shall be submitted as required under

R 324.1406.

(c) Within 60 days of plugging the well, all of the following information:

(i) Accurate and complete descriptions of cores.

(ii) Data on all bridge plugs set, make and type of plug, depth set, whether left in

place or removed, and details of plug-back operations below the bridge plug.

(iii) The amount of casing stripped from the well.

History: 1996 AACS; 2015 AACS.

R 324.419 Borehole and strata evaluation logging.

Rule 419. (1) A permittee of a well shall file a copy of all borehole and geologic

strata evaluation logs or other logs with the supervisor within 30 days after conducting

the logging run.

(2) Upon the request of the supervisor or authorized representative of the

supervisor, a logging service company shall provide a listing of all borehole and

geologic strata evaluation logs or other logs run.

History: 1996 AACS.

R 324.420 Continuation of drilling; deepening operations.

Rule 420. (1) A permittee of a well who desires to continue the drilling of a well

below the permitted depth, but within the permitted stratigraphic or producing horizon

where drilling completion has occurred, shall file an application for change of well

status pursuant to R 324.511.

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(2) A permittee of a well who desires to deepen a well below the permitted

stratigraphic or producing horizon where well completion has occurred shall file an

application for a deepening permit pursuant to R 324.206(4).

(3) A permittee of a well shall save samples of the drill cuttings and cores during

the continuation of drilling or deepening operations pursuant to R 324.417.

(4) A permittee of a well shall file records of the continuation of drilling or

deepening operations with the supervisor pursuant to R 324.418, R 324.419, and R

324.511.

History: 1996 AACS.

R 324.421 Survey of directionally drilled well.

Rule 421. A permittee of a well shall conduct a directional well survey on each

directionally drilled well, with actual survey points taken at a maximum of 100-foot

intervals from the point of deviation to total depth and including the end point of the

borehole or at an interval as approved by the supervisor or authorized representative of

the supervisor. However, for a well that is to be 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. All information

obtained during and after the survey shall be available to the supervisor or

authorized representative of the supervisor. A permittee shall file a certified copy

of the survey with the supervisor within 30 days after drilling completion. A well

shall not be produced until the survey has been filed with the supervisor.

History: 1996 AACS.

R 324.422 Sealing of cellars and rat and mouse holes.

Rule 422. (1) A permittee of a well shall seal and set into the earth rat and mouse

hole casings and cellars in a manner to prevent the migration of the drilling fluid and

other foreign fluids into the groundwater.

(2) Immediately after drilling completion, a permittee of a well shall fill rat and

mouse holes on all rotary-drilled wells solidly from bottom to top with cement or other

suitable material approved by the supervisor.

History: 1996 AACS.

PART 5. COMPLETION AND OPERATION

R 324.501 Responsibility for oil and gas operations.

Rule 501. A permittee of a well is responsible for the oil and gas operations of

his or her well.

History: 1996 AACS; 2002 AACS.

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R 324.502 Oil, brine, or associated oil or gas field waste; storage.

Rule 502. A permittee of a well shall not store or retain oil, brine, or associated oil

or gas field waste in earthen reservoirs or open receptacles.

History: 1996 AACS.

R 324.503 Well completion operations.

Rule 503. (1) A permittee of a well shall use proper well control measures to avoid an

uncontrolled flowing of the well. All fluids from well completion operations, including

flowback fluid, acid, load water, chemicals, and associated hydrocarbons, shall be

produced or swabbed back to approved containers. A permittee of a well shall not use

earthen pits or reservoirs to contain fluids produced from the well.

(2) A permittee shall notify the supervisor or authorized representative of the

supervisor when a well completion operation starts.

History: 1996 AACS; 2015 AACS.

R 324.504 Well sites and surface facilities.

Rule 504.

(1) A person shall use every reasonable precaution to stop and

prevent waste. All wells, surface facilities, gathering lines, and flow lines shall be

constructed and operated so that the materials contained in the facilities do not cause

waste. An oil and gas operation shall not be commenced or continued at a location

where it is likely that a substance may escape in a quantity sufficient to pollute the air,

soil, surface waters, or groundwaters or to cause unnecessary endangerment of public

health, safety,

or welfare until the permittee has complied with the methods and means to prevent

pollution or eliminate the unnecessary endangerment of public health, safety, or welfare

as specified by the supervisor.

(2) The surface facilities shall be located not less than 300 feet from all of the

following:

(a) Existing recorded freshwater wells and reasonably identifiable freshwater wells

utilized for human consumption.

(b) Existing structures used for public or private occupancy.

(c) Existing areas maintained for public recreation.

(d) The edge of the traveled portion of an existing interstate, United States, or

state highway. Pump jacks are exempt from this requirement.

(3) Surface facilities may be located closer than 300 feet from existing recorded

freshwater wells and reasonably identifiable freshwater wells utilized for human

consumption and existing structures used for public or private occupancy under either

of the following conditions:

(a) Upon presentation to the supervisor of a written consent signed by the owner or

owners of all existing recorded freshwater wells and reasonably identifiable

freshwater wells utilized for human consumption and existing structures used for

public or private occupancy.

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(b) After a hearing under part 12 of these rules, the supervisor determines that the

surface facility location will prevent waste, protect environmental values, and not

compromise public safety.

(4) A permittee of a well shall not begin the installation of a surface facility or

flow line without approval of the supervisor or authorized representative of the

supervisor. A permittee shall make a written request for approval to construct and

operate or to substantially reconstruct and operate a surface facility or flow line and

shall file the request with the supervisor. The request may be filed with the application

for a permit to drill and operate a well. The request shall have a detailed description

and plan of the proposed facility, which shall include all of the following information:

(a) An environmental impact assessment if the surface facility is located more than

300 feet from the well or wells it serves.

(b) The location of the proposed surface facility or flow line.

(c) Identification of the well or wells to be connected to the surface facility or

flow line.

(d) Reasonable and necessary measures to protect environmental values

associated with existing adjacent land uses, including berming, screening, and access

road location.

(e) Information relative to the approximate distances and directions from the

surface facility or flow line to special hazards or conditions identified in R

324.201(2)(b)(iv).

(5) Upon receipt of a written request for approval to construct and operate or to

substantially reconstruct and operate a surface facility or flow line under subrule (4) of

this rule, other than a request to construct and operate a surface facility or flow line made

as part of an application for permit to drill and operate a well, the supervisor or

authorized representative of the supervisor shall have up to 30 days to review the request

to determine if the request is accurate and complete. If the request is determined to

be inaccurate or incomplete, the supervisor or authorized representative of the supervisor

shall provide, within the 30?day period, to the person making the request, a notice that

the request is inaccurate or incomplete and what changes or additional information

shall be submitted. Upon receipt of the requested information, the supervisor or

authorized representative of the supervisor shall have up to an additional 15 days to

review the information to determine if the request is accurate and complete. Upon

completion of the review process, the supervisor or authorized representative of the

supervisor shall approve or deny the request within 10 business days. A request shall be

approved if the supervisor determines that construction and operation of the proposed

surface facility or flow line will prevent waste, protect environmental values, and not

compromise public safety. Upon approval by the supervisor or authorized representative

of the supervisor, a request made under this rule shall become part of, and subject to,

the provisions of the permit to drill and operate the well or wells served by the surface

facility.

(6) A person or permittee of a well shall not install a gathering line, carrying gas

with more than 300 ppm hydrogen sulfide or a flow line or facility piping carrying

gas from a class I H2S well and that is subject to a maximum working pressure of more

than 125 psig that does not meet the construction requirements in R 324.1130.

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(7) Surface facilities constructed after November 15, 1989, shall have secondary

containment under R 324.1002.

(8) If discharges to the air, surface waters, or groundwater of the state are likely to

occur at a surface facility, then a permittee shall apply for and obtain all necessary state

and federal discharge permits before operating the surface facility.

History: 1996 AACS; 2001 AACS; 2002 AACS.

R 324.505 Pump jacks in residential areas.

Rule 505. In areas zoned residential before January 8, 1993, if pumps or pump

jacks are installed after the effective date of these rules, then a permittee of a well

shall comply with the following conditions:

(a) Electrically driven pumps shall be utilized or, if judged impractical by the

supervisor, pumps may be driven by other power sources that have hospital-type

mufflers or the equivalent.

(b) Pump jacks within 600 feet of structures used for public or private occupancy

shall be fenced to prevent public access.

History: 1996 AACS.

R 324.506 Flare stacks and surface facilities in residential areas.

Rule 506. (1) In areas zoned residential before January 8, 1993, a permittee of

an oil or gas well, or both, which contains 300 ppm or more of hydrogen sulfide and

which reaches drilling completion after March 1, 1987, shall not locate surface facilities

and associated flare stacks within a residentially zoned area, unless either of the

following provisions is satisfied:

(a) The supervisor receives written notice from the local government that has

zoning jurisdiction that the local government does not object to the location of the

facility within the residentially zoned area.

(b) The applicant or permittee is granted a variance from the supervisor pursuant

to a hearing before the supervisor. The petitioner shall notify the local governmental

body of the hearing and has the burden of demonstrating to the supervisor that the

planned surface facility and associated flare stacks would have minimum impacts upon

existing or proposed structures used for public or private occupancy.

(2) The supervisor may grant an exception to permit flaring in a residentially

zoned area for testing the production characteristics of a well for a period of not more

than 15 days, unless a longer period is authorized by the supervisor. The permittee shall

submit a written application to the supervisor for the exception detailing the time period

of, and the equipment to be used for, the testing.

(3) If the oil or gas well, or both, reached drilling completion between March 1,

1987, and January 8, 1993, and the area was not zoned residential at the time the well

reached drilling completion, the well is not subject to this rule.

History: 1996 AACS.

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R 324.507 Tubing.

Rule 507. A permittee of a well shall tube a producible oil and gas well.A permittee

of a well shall test and produce all oil through the tubing.Injection wells utilized for gas

storage are exempt from this rule.

History: 1996 AACS.

R 324.508 Multiple zone completions.

Rule 508. The supervisor or authorized representative of the supervisor may allow

multiple zone completions upon written application to, and approval by, the supervisor.

History: 1996 AACS.

R 324.509 Commingling of oil and gas.

Rule 509. The supervisor or authorized representative of the supervisor may allow

commingling in the well bore of oil and gas from 2 or more pools upon written

application to, and approval by, the supervisor.

History: 1996 AACS.

R 324.510 Central production facility.

Rule 510. (1) A permittee of a well shall not begin the operation of a central

production facility without the approval of the supervisor or authorized

representative of the supervisor. A permittee of a well shall make a written request for

approval to operate a central production facility and shall file the request with the

supervisor. The supervisor or authorized representative of the supervisor shall approve or

deny the request within 30 days of receipt. The request shall have a detailed description

and plan of the proposed facility, which shall include all of the following information:

(a) The location of the proposed central production facility.

(b) Identification of the wells or production units to be connected to the central

production facility.

(c) Identification of the fluid streams that will be commingled.

(d) A schematic of the flow schemes, including the location of all of the following:

(i) Individual gas, oil, condensate, and water meters.

(ii) Facility and sales gas, oil, condensate, and water meters.

(iii) Fuel use and artificial lift meters.

(iv) On-site surface equipment.

(e) The method proposed for measurement or allocation of fluid volumes, if

individual and facility meters are not used. The method proposed for measurement

may include allocation of production to each well using a molal balance scheme.

(f) Identification of the type and model of the gas, oil, condensate, and water

meters that are proposed.

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(g) Quality assurance procedures, including calibration and proofing, that will be

implemented to maintain the accuracy of the meters.

(h) The procedure or method proposed for allocation of each commingled fluid

stream.

(i) If production from production units or unitized areas is included in the central

production facility, a copy of the pooling or communitization agreement filed pursuant

to R 324.303(2) or the unitization agreement developed pursuant to sections 61701 to

61738 of the act.

(2) A permittee of a well shall obtain the approval of the supervisor or authorized

representative of the supervisor before implementing a subsequent addition, alteration, or

change to the central production facility that affects flow measurement or reporting

methods.

(3) A permittee of a well shall submit monthly reports of meter readings, metered

production, and allocated production on forms approved by the supervisor.

History: 1996 AACS.

R 324.511 Change of well status.

Rule 511. (1) A permittee of a well who desires to change the status of a well by an

oil and gas operation, including temporary abandonment or high volume hydraulic

fracturing, except as allowed by R 324.704 and additional acid or other stimulation

treatment, shall file an application for change of well status with the supervisor. The

application shall set forth, in detail, the kind of oil and gas operation to be accomplished

and the plan for protecting all oil, gas, brine, or fresh water strata the well has penetrated.

In addition, an application to change the status of a well by utilizing high volume

hydraulic fracturing shall include the information specified in rule 201(2)(c) of these

rules. A permittee shall not begin the oil and gas operation until he or she has received

approval from the supervisor or authorized representative of the supervisor and provided

notification to the supervisor or authorized representative of the supervisor of the date the

oil and gas operation will commence.

(2) A permittee of a well who changes the status of a well shall file, with the

supervisor, within 60 days, a complete change of well status record on forms prescribed

by the supervisor, except that a record shall not be filed when the change of well status

operation is for temporary abandonment purposes.

History: 1996 AACS; 2002 AACS; 2015 AACS.

PART 6. PRODUCTION AND PRORATION

R 324.601 Proration of oil and gas wells and fields.

Rule 601. (1) The supervisor may prorate production from wells or fields, or both,

to conserve reservoir energy, to maximize oil and gas recovery, to ensure that the

owners shall be afforded the opportunity to produce their just and equitable share of

the oil and gas from the reservoir, and to prevent waste by setting allowable

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production rates. The prorated allowables shall be established by order of the supervisor

after a hearing pursuant to part 12 of these rules.

(2) The proration order shall specify the maximum amount of oil or gas,

or both, that may be produced in a 24-hour day.

History: 1996 AACS.

R 324.602 Tolerance from regularly calculated production.

Rule 602. (1) A permittee of a well shall be allowed to make up

underproduction of oil and gas if the underproduction is not more than 3 days'

allowable production from each well for a calendar month. The underproduction of

oil and gas from each well shall be adjusted by the

permittee during the next calendar month.

(2) If in a reservoir under multiple ownership an emergency condition arises

which is beyond the control of the permittee of the well and which prevents the

permittee from producing his or her regularly scheduled allowable production or

prevents the purchaser from running his or her regularly scheduled amounts of oil or

gas during a calendar month and the underproduction is more than 3 days' allowable

production, then the permittee may apply in writing to the supervisor for permission

to make up the underages. The supervisor or authorized representative of the

supervisor may grant the request if reservoir waste does not occur.

(3) In a well that has produced over its daily oil allowable by more than 3 days or

its daily gas allowable by more than 30 days, the permittee of the well shall cease

producing the well or further limit the oil or gas production as approved by the

supervisor or authorized representative of the supervisor until the overage is made up.

History: 1996 AACS.

R 324.603 Transfer of allowables between wells prohibited.

Rule 603. A permittee of a well shall not produce oil or gas from a well

above the allowables pursuant to R 324.602 to make up for the failure of

another well or wells to produce a full allowable or allowables.

History: 1996 AACS.

R 324.604 Well hookups to tanks or separators, or both, for prorated wells.

Rule 604. A permittee of a well shall ensure that well is hooked up or connected

to separators or stock tanks, or both, so that the well’s oil, gas, and brine production

entrained in the oil or gas may be segregated from all other wells and so that individual

measurements of daily oil, gas, and brine production of each well may be made.

Exceptions to this rule may be granted if the supervisor or authorized representative of

the supervisor approves an alternative measurement and allocation method pursuant to R

324.510.

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History: 1996 AACS.

R 324.605 Capacity tests for prorated wells.

Rule 605. (1) The supervisor or authorized representative of the supervisor

may require capacity tests, including test requirements and reporting on wells

subject to proration. The supervisor may amend or abrogate a previously adopted

test requirement, or set up new test requirements, when necessary to adapt to

changing field conditions.

(2) A wide open capacity test of a well shall not be made if the test will create

waste or result in the coning of gas or water. All gauges and tests shall be made by

methods and at times that will result in a determination of the true productive

capacity of the wells under normal operating conditions. Reports submitted to the

supervisor or authorized representative of the supervisor shall be certified by the

permittee or an authorized representative of the permittee.

History: 1996 AACS.

R 324.606 Production tests for newly completed or change of status wells

subject to proration.

Rule 606. A permittee of a well shall conduct production tests, not to exceed the

prorated allowable, on a newly completed well. On a previously tested well, when a

change of well status or the stimulation of the well may have resulted in changes in

producing capacity, the tests shall be commenced within 10 days after well completion,

change of well status, or production stimulation treatments. A permittee shall report

the results of all production tests to the supervisor or authorized representative of

the supervisor within 30 days after completion of the tests and shall certify the results on

forms prescribed by the supervisor.

History: 1996 AACS.

R 324.607 Special capacity tests.

Rule 607. (1) The supervisor or authorized representative of the supervisor

may, at any time, require the permittee of a well, either with or without previous notice,

to perform a special producing capacity test or supply production data for a well or

wells. The supervisor or authorized representative of the supervisor may witness,

direct, or make measurements during the test, subject to proper safety supervision by

the permittee.

(2) A producer who wishes to gather data to determine the maximum

efficiency rate of a well may conduct tests as approved by the supervisor or authorized

representative of the supervisor.

History: 1996 AACS.

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R 324.608 Responsibility for regulating production.

Rule 608. A permittee of a well shall be responsible for controlling production

from wells so that an individual well does not produce more oil or gas than allowed.

History: 1996 AACS.

R 324.609 Reservoir evaluation tests.

Rule 609. The supervisor or authorized representative of the supervisor may

require that subsurface pressures, gas-oil ratios, and other tests on wells be conducted

and submitted at least once per year so that reservoir data may be maintained.

History: 1996 AACS.

R 324.610 Reports of oil and gas produced, purchased, or transported.

Rule 610. A person who is producing, purchasing, or transporting oil or gas in a

field shall be required by the supervisor or authorized representative of the

supervisor to report, within 45 days after the end of the month of production, the

amount of oil or gas, or both, produced, purchased, or transported during the calendar

month of production, unless an extension of time or an exemption from monthly

reporting is granted by the supervisor. The reports shall be certified by the person who

is producing, purchasing, or transporting oil or gas in a field on forms prescribed by, or

acceptable to, the supervisor or authorized representative of the supervisor.

History: 1996 AACS.

R 324.611 Petition for change in field allowables.

Rule 611. A permittee of a well who believes proration allowables have ceased to

prevent waste may petition the supervisor for a change in field allowables. The

petition shall include all of the information specified in part 12 of these rules. The

supervisor shall schedule a meeting to consider the petition. The permittee shall furnish

a copy of the notice of the meeting to all owners of record, operators, lessees, and

lessors of the oil and gas mineral interests underlying the lands directly affected by

the proposed action. If the proposed action is contested by an interested party, then a

hearing is required pursuant to part 12 of these rules. After a review and evaluation of the

data presented, either administratively or by hearing, the supervisor shall issue an order

of determination.

History: 1996 AACS.

R 324.612 Secondary oil recovery projects; hearings; records.

Rule 612. (1) A person desiring to inject water, gas, or other fluid into a producing

formation or use other technology for the purpose of increasing the ultimate recovery of

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hydrocarbons from a reservoir shall file a petition for hearing pursuant to part 12 of these

rules.

(2) The operator of a secondary recovery project shall keep accurate records of

all oil, gas, and brine produced, volumes of fluids injected, and injection pressures. The

operator shall file reports of the data and other data as may be required with the

supervisor at regular intervals, as specified.

History: 1996 AACS.

R 324.613 Production from directionally drilled wells.

Rule 613. (1) An allowable production rate shall not be assigned or production

permitted from a directionally drilled well until a certified well survey has been furnished

by the permittee of a well to the supervisor. A directionally drilled well with a producing

interval that is contrary to the established boundary setback of the drilling unit or pooled

or communitized area shall be limited or restricted in the same manner as provided for

regularly drilled wells located contrary to the boundary setback of the drilling unit or

pooled or communitized area.

(2) The production from directionally drilled wells that can be produced contrary to

the established boundary setback of the drilling unit or pooled or communitized area shall

be limited or restricted in the same manner pursuant to R 324.301(4)(a) for regularly

drilled wells located contrary to the applicable boundary setback of the drilling unit or

pooled or communitized area. A permittee of a well shall not conduct production testing

from a directionally drilled well until a certified well survey has been furnished to, and

approved by, the supervisor or authorized representative of the supervisor pursuant to

R 324.421. Injection wells utilized for gas storage are exempt from this subrule.

History: 1996 AACS; 2015 AACS.

PART 7. DISPOSAL OF OIL OR GAS FIELD WASTE, OR BOTH

R 324.701 Prevention of pollution, contamination, or damage.

Rule 701. The storage, transportation, or disposal of brine, crude oil, or oil or gas

field waste that results in, or that the supervisor determines may result in, pollution is

prohibited. A permittee of a well shall ensure that wastes are stored, transported, and

disposed of in a manner approved by the supervisor and consistent with all applicable

state and federal laws and regulations.

History: 1996 AACS.

R 324.702 Pit disposal prohibited; exception.

Rule 702. Except as provided in R 324.407(2), a permittee of a well shall not

dispose of oil or gas field waste, or both, in earthen pits.

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History: 1996 AACS.

R 324.703 Disposal of oil or gas field fluid wastes, or both.

Rule 703. A permittee of a well shall inject oil or gas field fluid wastes, or both, into

an approved underground formation through an approved Class II well in a manner that

prevents waste. The injection interval shall be isolated from underground sources of

drinking water by a confining interval.

History: 1996 AACS; 2018 AACS.

R 324.704 Use of annular space for disposal prohibited; temporary exception.

Rule 704. A permittee of any well, including Class II wells, shall not dispose of fluid

wastes in the annular space between strings of casing. The supervisor may grant a

temporary exception to the prohibition if the supervisor determines that annular disposal

will not damage underground sources of drinking water, oil, gas, or other minerals.

History: 1996 AACS; 2018 AACS.

R 324.705 Disposition of brine.

Rule 705. (1) A permittee of a well is responsible for the proper disposal of all

brines produced in association with oil or gas production, or both, or brines accumulated

in drilling mud pits or tanks and shall ensure that waste, as defined in section 61501(q) of

the act, will not occur. A permittee may convey or transfer brines for other purposes if the

brines are in compliance with the conditions provided in subrule (3) of this rule. A

permittee shall be required to maintain records on the disposition of all brines pursuant to

subrule (4) of this rule, and a permittee shall not have continuing liability relative to the

transport or application of the brines after the brines are properly conveyed or transferred.

(2) Upon the effective date of these rules, a permittee of a well shall not use brines

produced in association with drilling for oil and gas, or both, and accumulated in drilling

mud pits for ice or dust control purposes.

(3) Twelve months after the effective date of these rules, a permittee shall dispose of

all brines as provided in R 324.703 or shall use the brines in a manner approved by the

supervisor; however, some brines may be conveyed or transferred and used for ice and

dust control and road stabilization if all of the following conditions are satisfied:

(a) Brines shall not be used for ice and dust control and road stabilization if the

brines are obtained from wells containing more than 20 ppm hydrogen sulfide in the gas

stream, unless it can be shown that there is less than a 500-ppm-hydrogen sulfide

concentration present in the brine.

(b) The brines shall contain a 20,000-milligrams-per-liter or more concentration of

calcium.

(c) The brines shall contain less than a 1,000-micrograms-per-liter concentration of

each of the following aromatic hydrocarbons:

(i) Benzene.

(ii) Ethylbenzene.

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(iii) Toluene.

(iv) Xylene.

(d) Only brines that have been approved by the supervisor or authorized

representative of the supervisor may be exempt from the disposal requirements of

R 324.703. For a permittee to obtain approval to exempt brine from the disposal

requirements of R 324.703, all of the following conditions shall be satisfied:

(i) The brine shall be tested annually within 90 days of January 1 of each year by the

person seeking authorization to utilize the brine for other purposes. The brine shall be

tested using any of the following procedures:

(A) Method 200.7 ICP-AES, entitled “Method for Trace Element Analysis of Water

and Wastes, Methods for Chemical Analysis of Water and Wastes,” March 1983 edition.

(B) Method 6010A, entitled “Inductively Coupled Plasma, Test Methods for

Evaluating Solid Waste, Physical/Chemical Methods,” 1984 edition 3.

(C) Method 602, entitled “Purgeable Aromatics, Guidelines Establishing Test

Procedures for the Analysis of Pollutants,” 40 C.F.R. part 136, appendix A, revised July

1990.

(D) Method 8020A, “Aromatic Volatile Organics by Gas Chromatography,

Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” 1984 edition 3.

(E) Method 8240A, entitled “Volatile Organic Compounds by Gas

Chromatography/Mass Spectrometry: Packed Column Technique, Test Methods for

Evaluating Solid Waste, Physical/Chemical Methods,” 1984 edition 3.

(F) Method 8260A, entitled “Volatile Organic Compounds by Gas

Chromatography/Mass Spectrometry: Capillary Column Technique,” 1984 edition 3.

(G) Method 325.3, entitled “Chloride (Colorimetric, Automated Ferricyanide),

Guidelines Establishing Test Procedures for the Analysis of Pollutants,” 40 C.F.R. part

136, appendix A, revised July 1990.

(H) Method 4500-CLE, entitled “Chloride, Methods for the Determination of

Organic Compounds in Drinking Water” and supplement I, December 1988 and July

1990 editions.

The testing methods are adopted by reference in these rules and copies are available

for inspection at the Lansing office of the office of oil, gas, and minerals of the

department of environmental quality. Copies may be obtained without charge from the

Michigan Department of Environmental Quality, Office of Oil, Gas, and Minerals, P.O.

Box 30256, Lansing, Michigan 48909, or from the United States Environmental

Protection Agency, Office of Research and Development, 26 West Martin Luther King

Boulevard, Cincinnati, Ohio 45268.

(ii) The sample of brine used for analysis shall be obtained from the point of loading

of the storage tank where the brine is first separated from the production stream.

(iii) A chemical analysis of each brine source showing the concentrations of all of

the following shall be submitted to the supervisor or authorized representative of the

supervisor within 30 days of the completion of the analysis:

(A) Chloride.

(B) Hydrogen sulfide.

(C) Calcium.

(D) Benzene.

(E) Ethylbenzene.

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(F) Toluene.

(G) Xylene.

(iv) The chemical analysis shall include all of the following information:

(A) The well name.

(B) Permit number.

(C) Permittee.

(D) Location of the individual well.

(E) If the brine is obtained from a tank battery or central production facility, the

name, number, permittee, and location of the tank battery or central production facility.

(4) A permittee of a well shall maintain records for 2 years on the disposition of all

brines produced in association with oil or gas production, or both. The records shall

indicate dates, volumes, recipient, transporter, destination, and proof of delivery. If the

person authorized to utilize the brine for other purposes receives the brine at an

unattended loading site, then the person shall provide the permittee with a signed record

describing the date, volume, time, destination, and proof of delivery. A permittee of a

well shall make the records available for inspection by the supervisor or authorized

representative of the supervisor at all times. A permittee of a well shall protect the

records from damage or destruction due to preventable cause.

(5) A permittee of a well shall ensure that brine that is in compliance with the

conditions listed in subrule (3) of this rule is also in compliance with all applicable state

and federal laws and regulations.

History: 1996 AACS; 2015 AACS.

Editor's Note: An obvious error in R 324.705 was corrected at the request of the promulgating agency,

pursuant to Section 56 of 1969 PA 306, as amended by 2000 PA 262, MCL 24.256. The rule containing

the error was published in Annual Administrative Code Supplement, 2015. The memorandum requesting

the correction was published in Michigan Register, 2018 MR 10.

PART 8. INJECTION WELLS

R 324.801 Definitions.

Rule 801. As used in these rules:

(a) “Administrator” means the administrator of the USEPA.

(b) “Area of review” means that area within a fixed radius of 1320 feet around an

injection well.

(c) “Class II Well” means a well that does either of the following:

(i) Injects fluids under any of the following conditions:

(A) That are brought to the surface in connection with oil or natural gas

production and may be commingled with waste waters from gas plants which are an

integral part of production operations, unless those waters are classified as a hazardous

waste at the time of injection.

(B) For enhanced recovery of oil or natural gas.

(C) For storage of hydrocarbons that are liquid at standard temperature and

pressure.

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(ii) Utilizes diesel fuel as a component of hydraulic fracturing fluid.

(d) “Class II well operator” means the person having secured a permit for any of the

following:

(i) A new Class II well.

(ii) An existing Class II well.

(iii) A conversion of an existing well to a Class II well.

(iv) A rule authorized well in operation before the effective date of primacy.

(e) “Commercial disposal well” means a Class II well that is permitted to accept

wastes other than those generated by the owner or operator of the well.

(f) “Confining interval” means a geological formation, group of formations, or

part of a formation that is capable of limiting fluid movement above an injection interval.

(g) “Contaminant” means any physical, chemical, biological, or radiological

substance or matter in water.

(h) “Date of primacy” means the effective date of the administrator's approval

of the Michigan underground injection control program for Class II wells pursuant to

section 1425 of the safe drinking water act of 1974, 42 USC 300h-4.

(i) “Diesel fuel(s)” means fluids that are associated with 5 specific Chemical

Abstracts Services Registry Numbers (68334-30-5, 68476-34-6, 68476-30-2, 68476-31-3,

and 8008-20-6).

(j)“Endangerment to an underground source of drinking water” means that an

injection operation may result in the presence of any contaminant in an underground

source of drinking water, that supplies or may reasonably be expected to supply any

public water system, and the presence of that contaminant may result in violation of any

national primary drinking water regulation or may otherwise adversely affect the health

of persons.

(k) ”Enhanced Oil Recovery” or “Enhanced Recovery” means secondary recovery.

(l) “Existing Class II well” means a Class II well that has been approved,

constructed, or converted before the date of primacy.

(m) “Injection casing” means the long string of casing set into, through, or just

above the injection interval, in which the packer and tubing may be set.

(n) “Injection interval” means the geological formation or group of formations or

part of a formation receiving fluids through an injection well. There must be a confining

interval above the injection interval.

(o) “Karst” means a type of topography that is formed over limestone, dolomite, or

gypsum by solution of the rock and is characterized by closed depressions or sinkholes,

caves, and underground drainage.

(p) “Mechanical integrity” means a well condition that exists if there is no

significant leakage in the well’s casing, tubing, or packer and if there is no significant

fluid movement into an underground source of drinking water through vertical channels

adjacent to the injection well bore.

(q) “New Class II well” means a Class II well that is constructed or converted under

part 615 after date of primacy.

(r) “Oil or Gas Field Fluid Wastes” means liquid wastes resulting, obtained, or

produced from the exploration, drilling, or production of oil or gas, or both.

(s) “Part 615” means part 615 of the act, MCL 324.61501 to 324.61527.

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(t) “Rule authorized well” means a Class II well that was classified or treated, or

both, by the USEPA as an authorized by rule well on or after January 1, 1984.

(u) “USEPA” means the United States Environmental Protection Agency.

(v) “Waste” as defined in section 61501(q)(i) to (iii) of the act, MCL 324.61501,

includes endangerment to an underground source of drinking water.

History: 1996 AACS; 2015 AACS; 2018 AACS; 2019 AACS.

R 324.802 Application for permit to drill, convert, and operate injection well.

Rule 802. In addition to requirements in R 324.201, the following additional

information shall be submitted with an application for a permit to drill and operate an

injection well or to convert a previously drilled well to an injection well:

(a) Notification information including the following:

(i) The name and address of the permittee of each oil, gas, and injection well and

permitted location or locations within 1,320 feet of the proposed injection well location.

(ii) The name and address of the last surface owner or owners of record within

1,320 feet of a proposed Class II well location as reasonably determined by the records of

the register of deeds office or equalization records.

(b) Required plat pursuant to R 324.201, that also shows the following:

(i) The location and total depth of the proposed injection well.

(ii) Each oil, gas, injection, and abandoned well and permitted location or locations

within 1,320 feet of the proposed injection well location, including dry holes and wells

that have been plugged and abandoned.

(iii) The surface owner or owners of record of the land on which the proposed

injection well is to be located.

(iv) Each permittee of a well or permitted well location within 1,320 feet of the

proposed injection well.

(v) Fresh water, irrigation, and public water supply wells within 1,320 feet of the

proposed injection well.

(c) If a well is proposed to be converted to an injection well, all requirements of

R 324.201(1) and R 324.201(2) apply, and the applicant must submit a copy of the

completion report, together with the written geologic description log or record filed

pursuant to R 324.418(a) and borehole and stratum evaluation logs filed pursuant to

R 324.419(1). Pursuant to R 324.204 any well to be converted for liquid hydrocarbon

storage is a proposed Class II well and subject to this subdivision.

(d) Plugging records of all abandoned wells and casing, sealing, and completion

records of all other wells within 1,320 feet of the proposed injection well location. An

applicant shall also submit a plan reflecting the steps or modifications believed necessary

to prevent proposed injected fluids from migrating into an underground source of

drinking water through inadequately plugged, sealed, or completed wells.

(e) A schematic diagram of the proposed injection well that shows all of the

following information:

(i) The total depth or plug-back depth of the proposed injection well.

(ii) The geological formation name or names, true vertical depth, thickness, and

lithology of the injection interval, and the confining interval.

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(iii) The geological formation name or names and the top and bottom depths of all

underground sources of drinking water to be penetrated.

(iv) The depths of the top and bottom of the casing or casings and cement to be

used in the proposed injection well.

(v) The size of the casing and tubing and the estimated depth of the packer if

applicable.

(f) Information showing that injection of fluids into the proposed injection interval

will not exceed the injection interval fracture pressure gradient and information showing

that injection into the injection interval will not initiate new fractures or propagate

existing fractures in the overlying confining interval.

(g) For Class II wells, proposed operating data, including all of the following:

(i) The maximum anticipated daily injection rate expressed as barrels per day or

thousand cubic feet per day.

(ii) The types of fluids to be injected. Hydraulic fracturing utilizing diesel fuels in

the hydraulic fracturing fluid is subject to Class II regulations. Notwithstanding the

provisions of R 324.1406(2), the use of diesel fuels in a proposed hydraulic fracturing

fluid is not protected from disclosure.

(iii) Maximum anticipated injection pressure, expressed as psig at the well head,

and calculations used to derive that value.

(iv) A qualitative and quantitative analysis of a representative sample of fluids to

be injected. A chemical analysis shall be prepared for each type of fluid to be injected

showing specific conductance as an indication of the dissolved solids, specific gravity,

and a determination of the concentration of calcium, sodium, magnesium, chloride,

sulfate, sulfide, carbonate, total iron, barium, and bicarbonate. However, if the fluid to be

injected is fresh water, then an analysis is not required.

(v) The geological name of the injection interval and the vertical distance

separating the top of the injection interval from the base of the deepest underground

source of drinking water.

(h) For a proposed injection well to dispose of oil or gas field waste, or both, into an

interval that would likely constitute a producing oil or gas pool, a list of all offset

operators and certification that the person making application for an injection well has

notified all offset operators of the person’s intention by certified mail. If within 21 days

after the mailing date a substantive objection is filed with the supervisor by an offset

operator, then the application shall not be granted without a hearing pursuant to part 12 of

these rules. The supervisor may schedule a hearing to determine the need or desirability

of granting permission for the proposed injection well.

(i) Identification and description of all faults, structural features, karst, mines, and

lost circulation zones within the area of review that can influence fluid migration, well

competency, or induced seismicity. The applicant shall include a plan for mitigating risks

of identifiable features.

(j) A proposed plugging and abandonment plan and schematic.

(k) Information demonstrating that construction of the well will prevent the

movement of fluid that causes endangerment to an underground source of drinking water.

History: 1996 AACS; 2018 AACS.

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R 324.803 Class II well notification, public comment, and public hearing.

Rule 803. (1) Within 10 days after receipt of a Class II well permit application the

supervisor shall mail notice to each surface owner of record and well permittee of each

oil, gas, and injection well within 1,320 feet of the proposed injection well, to the

township supervisor or municipal manager where the well is located, and shall post the

notice on the department website concurrently with the weekly permit list publishing

which is posted on the department website and available by email list server. All of the

following information must be included on the notice:

(a) Date of notice.

(b) Applicant’s name and address.

(c) Proposed well location, listing the county, township, range, section, and

distance from nearest road intersections.

(d) Geological formation name and depth of injection interval.

(e) Maximum anticipated injection pressure, expressed as psig at the well head.

(f) Maximum anticipated daily injection rate expressed as barrels per day or

thousand cubic feet per day.

(g) Information on how to submit comments on the application to the supervisor.

(h) The following statement “Any comments or objections on an application, or a

request to obtain additional information about the application, must be received by the

supervisor within 30 days after the date of notice set forth herein.”

(i) If substantial compliance is achieved toward notification requirements,

inadvertent mistakes in noticing will not be a bar to processing of the permit.

(2) The supervisor shall receive public comments for 30 days following the date of

the notice and complete review of the application as follows:

(a) If no objections are received within the 30-day comment period, the supervisor

or authorized representative of the supervisor shall consider that no objections exist and

shall issue a permit within 10 days if it is determined that the application complies with

the law.

(b) If a comment or an objection to the application is received, the Supervisor or

authorized representative of the Supervisor shall, within 10 days after the end of the

comment period, determine the validity of the comment or objection. If, in the opinion of

the supervisor or authorized representative of the supervisor, it is determined the

comment or objection is not relevant to the issues of waste, public health or safety, or is

without substance, a permit shall be issued within 20 days after the end of the comment

period if it is determined that the application complies with the law.

(c) If, within the 10 day period set forth in (2)(b ), above, the supervisor or

authorized representative of the supervisor considers the comment or objection to be

relevant to the issues of waste, public health or safety, or is of substance, and the

commenter has requested a public hearing, then the supervisor shall provide notice of the

public hearing within 20 days after the end of the comment period and hold the public

hearing within 30 days after giving notice of the public hearing. The public hearing will

be held in the township or county of the proposed well, is for gathering public comment

on a proposed permit, and is not an evidentiary hearing pursuant to R 324.1201 to

R324.1205. The supervisor will provide a minimum of 20 days notice of the public

hearing. Notice will be made by posting the hearing on the department calendar, the

department website, and in one local newspaper.

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(d) If the supervisor or authorized representative of the supervisor determines, after

the hearing and upon consideration of comments and the application, that all of the

following conditions have been met, the application for a Class II well shall be approved

and a permit shall be issued within 30 days:

(i) The application complies with the requirements of these rules.

(ii) The method of injection proposed in the application complies with the law.

(iii) The proposed method of injection will not threaten public health or safety and

will not create waste or endanger an underground source of drinking water.

(e) Concurrently with the issuance or denial of a Class II permit application, the

supervisor or authorized representative of the supervisor shall post responses to the public

comments on the department website.

(3) The provisions of this rule are effective only upon the date of primacy.

History: 1996 AACS; 2018 AACS.

R 324.804 Construction and operation of injection wells.

Rule 804. (1) Injection of fluid into an injection well shall be through a combination

of casing, tubing, cement, and packer placement that isolates the injection interval and

prevents the movement of fluids into or between underground sources of drinking water,

including through vertical channels adjacent to the well bore, which has mechanical

integrity. Injection wells utilized for gas storage are not required to install tubing and/or a

packer. In addition to cementing requirements in this rule, well casing shall be cemented

pursuant to R 324.408, R 324.411, and R 324.413. The supervisor or authorized

representative of the supervisor shall review cement details and any logs required for the

applicant to demonstrate external mechanical integrity prior to authorization to inject.

One of the following methods that demonstrates external mechanical integrity and

prevention of fluid migration into or between underground sources of drinking water

shall be used:

(a) The results of a temperature log, or noise log, or cement bond log.

(b) Cementing records demonstrating the presence of adequate cement to prevent a

migration.

(c) Other methods suggested by the permittee and approved by the supervisor or

authorized representative of the supervisor.

(2) A permittee of a well shall ensure that the injection of fluid into a well is through

adequate tubing and packer. During injection operations, the permittee shall fill the

tubing to casing annulus with a noncorrosive liquid. For Class II wells, the packer shall

be set within 100 feet of the base of the injection casing or within 100 feet of the top

perforation of the injection interval, unless otherwise approved by the supervisor.

Injection wells utilized for gas storage are exempt from this subrule.

(3) A permittee of a well shall ensure that surface access to all casing annuli is

provided.

(4) A permittee of a well shall ensure that an injection well is constructed and

operated so that the injection of fluids is confined to injection interval or intervals

approved by the supervisor or authorized representative of the supervisor.

(5) In addition to R 324.408 surface casing requirements, surface casing must be set

a minimum of 100 feet below the base of the glacial drift into competent bedrock or 100

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feet below all underground sources of drinking water, whichever is deeper, for new Class

II wells. To convert a previously drilled well into a Class II well, where existing surface

casing is not 100 feet below underground source of drinking water, a demonstration of

the combination of casing and cement must be made to show protection of all

underground sources of drinking water.

(6) The injection casing must have a minimum of 250 feet of cement immediately

above the injection interval. If less than 250 feet of cement exists, remedial cementing

must occur at a point as near to the existing cement top as possible, as determined by the

supervisor or authorized representative of the supervisor. Injection wells utilized for gas

storage are exempt from this subrule.

(7) Class II wells must have injection casing in addition to the surface casing and

any additional casing that may be required under R 324.410.

(8) In addition to other provisions of these rules, the top of the injection interval

shall be a minimum of 500 feet below the deepest underground source of drinking water

for a new Class II well in an area of karst, unless a lesser separation is approved by the

supervisor based on a demonstration of protection of underground sources of drinking

water by the permittee. Within an area of karst, in addition to other requirements, all

casings except the injection casing shall be circulated to surface with cement. If not

possible to circulate cement to surface because of karst features or lost circulation zones,

the casing annulus shall have cement from at least 100 feet to the surface.

(9) Subrules R 324.804(1), (5), and (6) do not apply to Existing Class II wells or

Rule Authorized wells since they are permitted, constructed or converted prior to the date

of primacy.

History: 1996 AACS; 2018 AACS.

R 324.805 Temporary authority to inject.

Rule 805. The supervisor may grant a permittee of a well temporary authorization,

for a period of not more than 30 days, to inject fluid for the limited purpose of running

injectivity tests. Temporary authorization to inject will only be granted if there will be no

endangerment of underground sources of drinking water. Injection wells utilized for gas

storage are exempt from this rule.

History: 1996 AACS; 2018 AACS.

R 324.806. Testing and authorization to inject before operation of Class II

injection wells.

Rule 806. (1) Before injecting fluid into a new Class II well, a permittee of a well

shall provide for a test of the annulus between the innermost casing and the tubing above

the packer. The test shall be conducted by a qualified person and the test shall be at a

pressure of not less than 300 psig. The difference in pressure between the testing pressure

and the tubing pressure shall be not less than 100 psig at the time of the test. A

satisfactory test shall have a pressure change of not more than 5% over a period of 30

minutes.

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(2) A permittee of a well shall notify the supervisor or authorized representative of

the supervisor at least 5 days in advance of the date and time of the test.

(3) Within 14 days of completion of the test, the permittee shall submit, on a form

prescribed by the supervisor, a report of each mechanical integrity test to the supervisor

or authorized representative of the supervisor. The report shall contain test supporting

data, including, but not limited to, gauge calibration data, pressure recordings and charts,

tubing size, packer type, and packer depth. Approval of the test results will be based on

witnessing by supervisor or authorized representative of the supervisor, or review and

evaluation of test data submitted pursuant to this subrule.

(4) Before the commencement of injection, a permittee shall receive an authorization

to inject from the supervisor or authorized representative of the supervisor. Prior to

issuance of the authorization to inject, the supervisor or authorized representative shall

have witnessed the test or received the test data, reviewed the test data, and determined

that the permittee has demonstrated that the well has mechanical integrity. Authorization

to inject will be granted only after any applicable well records required by R 324.418

have been received and evaluated by the supervisor or authorized representative of the

supervisor. Verbal authorization from the supervisor or authorized representative is

acceptable to commence injection. Written authorization to inject from the supervisor or

authorized representative will be issued within 7 days of verbal authorization.

(5) Injection wells utilized for gas storage are exempt from this rule.

History: 1996 AACS; 2018 AACS.

R 324.807 Maximum injection pressure.

Rule 807. During Class II well injection operations, a permittee shall ensure that the

surface injection pressure does not exceed a pressure determined by the following

equation:

Pm = (fpg - 0.433 sg)d where

Pm = surface injection pressure

fpg = fracture pressure gradient of the injection interval (if unknown, assume 0.800)

sg = specific gravity of the injection liquid (if unknown, assume 1.2)

d = depth of the top of the injection interval in feet (true vertical depth).

The value for fpg may be determined by an instantaneous shut-in pressure or data

derived from step rate testing. Other information to derive fpg values may be used with

approval of the supervisor or authorized representative of the supervisor.

History: 1996 AACS; 2018 AACS.

R 324.808 Class II well operational testing requirements.

Rule 808. (1) A permittee of a Class II well shall provide for a pressure test that

meets the requirement of subrule (2) of this rule, by a qualified person, to determine the

mechanical integrity of the tubing, casing, and packer.

(2) The annulus between the innermost casing and the tubing above the packer shall

be tested at least once each 5 years at a pressure of not less than 300 psig. A satisfactory

test shall have a pressure change of not more than 5% over a period of 30 minutes. The

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difference in pressure between the testing pressure and the tubing pressure shall not be

less than 100 psig at the time of the test. At least 5 days before the test, the permittee

shall notify the supervisor or authorized representative of the supervisor of the date and

time of the test. This subrule applies to all Class II wells, including those with approved

temporary abandonment status.

(3) Within 14 days after the test, the permittee shall, on a form prescribed by the

supervisor, submit a report of each mechanical integrity test to the supervisor or

authorized representative of the supervisor. The report shall contain supporting data

including, but not limited to, gauge calibration data, pressure recordings and charts,

tubing size, packer type, and packer depth. Prior to an issuance of an authorization to

inject, the supervisor or authorized representative shall have witnessed the test or

received the test data, reviewed the test data, and determined that the permittee has

demonstrated the well has mechanical integrity.

(4) For a Class II well that has not been utilized for its intended purpose for a period

of greater than 2 years, the permittee shall, prior to resuming injection, demonstrate

mechanical integrity for the well and receive authorization to resume injection from the

supervisor or authorized representative of the supervisor.

History: 1996 AACS; 2018 AACS.

R 324.809 Testing requirements for wells utilized for gas storage.

Rule 809. Before injecting fluid into a newly drilled well or previously existing well

newly converted to an injection well to be utilized for gas storage, a permittee of an

injection well shall provide for a test of the mechanical integrity of the casing, by a

qualified person, utilizing either a pressure test at a bottom hole pressure of not less than

the maximum expected operating pressure of the gas storage field or an equivalent test

approved by the supervisor. Within 14 days of the test, the permittee shall, on a form

prescribed by the supervisor, submit a report of each mechanical integrity test to the

supervisor or authorized representative of the supervisor. Prior to issuance of an

authorization to inject, the supervisor or authorized representative shall have witnessed

the test or received the test data, reviewed the test data, and determined that the permittee

has demonstrated that the well has mechanical integrity.

History: 2018 AACS.

R 324.810. Monitoring and filing records and reports.

Rule 810. (1) A permittee of a Class II well not utilized for secondary recovery

shall, on a weekly basis, monitor and record the annulus pressure, injection pressure,

injection rate, and weekly cumulative volume of the fluid injected.

(2) A permittee of a Class II well utilized for secondary recovery injection well

shall, on a monthly basis, monitor and record the annulus pressure, injection pressure,

injection rate, and monthly cumulative volume of the fluid injected. A permittee of a

secondary recovery injection well may conduct the monitoring and recording, required by

this rule, on a field or project basis by manifold monitoring, rather than on an individual

well basis, if more than 1 secondary recovery injection well operates with a single

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manifold, and if the permittee demonstrates that manifold monitoring is comparable to

individual well monitoring.

(3) A permittee of an injection well not utilized for secondary recovery shall report

the data monthly to the supervisor, unless the supervisor requires a lesser frequency, on

forms prescribed by the supervisor.

(4) A permittee of a secondary recovery injection well shall report the monthly data

annually to the supervisor, on forms prescribed by the supervisor by March 1 of each year

for the previous year.

(5) In addition to other requirements within this rule, a permittee of a Class II

commercial disposal well shall submit a complete list of sources of disposed fluids on a

quarterly basis on a form prescribed by the supervisor within 45 days of the end of each

quarter. The provisions of this subrule are effective only upon the date of primacy.

(6) In addition to other requirements within this rule, a permittee of a Class II

commercial disposal well shall submit information on any new source to the supervisor,

and shall obtain approval of the source from the supervisor or authorized representative

of the supervisor, prior to injection of fluids from that source. The provisions of this

subrule are effective only upon the date of primacy.

(7) A permittee of a Class II well shall file on a quarterly basis the fluid loss or gain

in the tubing-casing annulus on a form prescribed by the supervisor within 45 days of the

end of each quarter. Rule authorized wells are exempt from this requirement. The

provisions of this subrule are effective only upon the date of primacy.

(8) The permittee of a Class II well shall submit an annual chemical analysis of the

injectate using same analytes as R 324.802(g)(iv) by March 1 of the following year, or

more frequently if there has been a change in sources or characteristics of the injectate.

(9) The permittee shall retain all records pertaining to a Class II injection well for a

period of 5 years.

(10) The permittee of any Class II well shall indicate on any submitted report

observed noteworthy anomalies or problems identified related to that data. The permittee

shall report exceedance of the Maximum Injection Pressure on injection monitoring

reports. The provisions of this subrule are effective only upon the date of primacy.

History: 2018 AACS.

R 324.811 Loss of mechanical integrity.

Rule 811. (1) A permittee of an injection well shall notify the supervisor or

authorized representative of the supervisor of any pressure test failure, significant

pressure changes, or other evidence of a leak in an injection well, within 24 hours of the

pressure test failure, significant pressure changes, or other evidence of a leak. For other

evidence of a leak received via logging, the notification shall occur within five working

days after the operator first determines that the condition exists from reading the log data,

but not later than 10 working days after the day the operator receives the log data. If there

is evidence that indicates an injection well is not, or may not be, directing the injected

fluid into the permitted injection interval, a permittee of an injection well shall

immediately cease injection.

(2) A permittee shall submit written notice of the pressure test failure, significant

pressure changes, or other evidence of a leak to the supervisor or authorized

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representative of the supervisor within 5 days of the occurrence, or within 10 days of

receiving well logging data, on a form prescribed by the supervisor. If injection has

ceased pursuant to subrule (1) of this rule, then a permittee shall not resume injection

until the permittee has tested or repaired the well, or both. If the repair requires a change

of well status pursuant to R 324.511, or a permit modification, then a plan shall be

submitted to, and approved by, the supervisor or authorized representative of the

supervisor. The repair or modification plan must demonstrate protection of any

underground sources of drinking water.

(3) Before resuming injection, a permittee must demonstrate the well has mechanical

integrity and receive an authorization to inject. Verbal authorization from the supervisor

or authorized representative of the supervisor is acceptable to commence injection.

Written authorization to inject from the supervisor or authorized representative will be

issued within 7 days of verbal authorization. Prior to issuance of an authorization to

inject, the supervisor or authorized representative shall have witnessed the test or

received the test data, reviewed the test data, and determined the permittee has

demonstrated that the well has mechanical integrity.

History: 2018 AACS.

R 324.812 Cessation of injection wells; request for temporary abandonment

status.

Rule 812. If an injection well ceases operating for the purpose for which it was

intended for 1 year, then a permittee shall plug the well or request temporary

abandonment status for the well in writing. The request for temporary abandonment

status shall be pursuant to R 324.511. The temporary abandonment status may be granted

by the supervisor if, after application and justification by the permittee, the supervisor

determines that waste will be prevented. When approving the temporary abandonment

status or subsequent extensions, the supervisor may require special actions and

monitoring by the permittee to ensure the prevention of waste and endangerment of

underground sources of drinking water. If temporary abandonment status is not granted,

then the permittee of the injection well shall plug the well. The permittee may petition

the supervisor for a hearing to show cause why the well should not be plugged. This rule

supersedes R 324.209 for injection wells.

History: 2018 AACS.

R 324.813 Suspension of Class II well operations due to threat to public health

and safety or underground sources of drinking water.

Rule 813. (1) The supervisor or authorized representative of the supervisor may

immediately require corrective action at a Class II well, including suspending any or all

components of the injection or disposal operations, if the supervisor determines either of

the following:

(a) The injection operations are in violation of the provisions of the act, these rules,

permit conditions, instructions, or orders of the supervisor.

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(b) The injection operations threaten the public health and safety or underground

sources of drinking water.

(2) A suspension of injection or disposal operations shall be in effect for not more

than 5 days or until the operation is in compliance and protection of the public health and

safety and underground sources of drinking water is ensured.

(3) Unless the permittee brings the operations into compliance as required pursuant

to subrule (1), the supervisor may issue an emergency order to continue the suspension of

injection or disposal operations beyond 5 days, and may schedule a hearing under part 12

of these rules. The total duration of the suspension of injection or disposal operations

under this provision shall not be more than 21 days, as provided in section 61516 of Part

615, MCL 324.61516.

(4) Unless the permittee brings the operations into compliance as required pursuant

to subrule (1) or (2) of this rule, the supervisor shall issue a new order following a

minimum of 10 day notice and public hearing as provided in section 61516 of Part 615,

MCL 324.61516(1) and R 324.1211, enter into an administrative consent agreement, or

enter other binding instrument to extend the suspension of injection or disposal

operations under this provision beyond 21 days. The order, administrative consent

agreement, or other binding instrument shall require corrective actions within specific

time limits to achieve compliance and protection of the public health and safety and

underground sources of drinking water, and shall remain in force until the operation is

brought into compliance.

(5) Authorization to resume injection shall not be given by the supervisor or

authorized representative of the supervisor until compliance and protection of the public

health and safety and underground sources of drinking water is achieved. The

authorization to inject will only be given when mechanical integrity is also demonstrated,

if applicable.

(6) This rule supersedes R 324.1014 for Class II wells.

History: 2018 AACS.

R 324.814 Class II primacy transitional requirements for supervisor and owner-

operators.

Rule 814. (1) Transitional requirements for the supervisor include all of the

following:

(a) Upon the date of primacy, the supervisor shall do the following:

(i) Accept all Class II well permits, including rule authorized wells, issued under

the authority of the USEPA administered underground injection control program. These

wells are currently permitted under Part 615, and are deemed to meet the requirements of

Part 615. Existing permit terms under Part 615 remain in effect.

(ii) Accept records from the USEPA of all Class II wells, including rule

authorized wells.

(iii) Accept maximum injection pressures established by permits issued by

USEPA including maximum injection pressures issued for rule authorized wells,

(iv) Accept mechanical integrity test data and test schedules for all existing Class

II wells and rule authorized wells.

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(b) Within 30 days following the date of primacy, an owner or operator shall do the

following:

(i) Transfer pending applications submitted for Class II wells under the USEPA

underground injection control program to the Michigan Department of Environmental

Quality, Oil, Gas, and Minerals Division, P.O. Box 30256, Lansing, Michigan 48909, for

final review and permitting decisions.

(ii) File or transfer a conformance bond pursuant to R 324.212.

History: 2018 AACS.

R 324.815 Class II permit modifications.

Rule 815. (1) Modifications to a Class II permit issued pursuant to R 324.206 may

be considered major modifications and subject to requirements of R 324.802 and

R 324.803. Minor modifications are not subject to requirements of R 324.802 and

R 324.803.

(2) Minor modifications include activities such as the following:

(a) Correcting typographical errors.

(b) Requiring more frequent monitoring or reporting by the permittee.

(c) Changing an interim compliance date in a schedule of compliance, provided the

new date is not more than 120 days after the date specified in the existing permit and

does not interfere with attainment of the final compliance date requirement.

(d) Change in ownership or operational control of a facility where the supervisor

determines that no other change in the permit is necessary.

(e) Changing quantities or types of fluids injected which are within the capacity of

the facility as permitted and, in the judgment of the supervisor, would not interfere with

the operation of the facility or its ability to meet conditions described in the permit and

would not change its classification.

(f) Changes in construction requirements approved by the supervisor or authorized

representative of the supervisor, including remedial cementing or adding perforations to

the approved injection interval.

(g) Amendment of a plugging and abandonment plan when approved by the

supervisor or authorized representative of the supervisor.

(3) The provisions of this rule are effective only upon the date of primacy.

History: 2018 AACS.

R 324.816 Class II Cross Reference

Rule 816. For Class II wells, the following rules are applicable: R 324.101 to

324.199, R 324.201 to 324.208, R 324.210 to 324.216, R 324.401 to 324.422, R 324.501

to 324.504, R 324.507, R 324.508, R 324.510, R 324.511, R 324.701 to 324.705, R

324.801 to 324.808, R 324.810 to 324.816, R 324.901 to 324.904, R 324.1001 to

324.1013, R 324.1015, R 324.1101 to 324.1130, R 324.1201 to 324.1212, R 324.1301,

and R 324.1401 to 324.1406.

History: 2018 AACS.

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PART 9. PLUGGING

R 324.901 Notification of intention to abandon and plug well.

Rule 901. A person shall not begin the plugging of a well until the permittee of

a well has notified the supervisor or authorized representative of the supervisor of his or

her intention to abandon the well and has received instructions for the plugging

operation. The notification shall provide all of the information requested by the

supervisor or authorized representative of the supervisor required to issue plugging

instructions.The notification may also include any of the following information:

(a) The present condition of the well.

(b) Casing and sealing information.

(c) The sizes and lengths of all casing strings.

(d) The depths of the top of all principal formations.

(e) The depths where oil, gas, and water were encountered.

(f) The method to be used to tag plugs.

(g) The proposed method for handling unusual or hazardous conditions.

(h) The date of the last production or operation.

History: 1996 AACS.

R 324.902 Plugging instructions; methods and materials.

Rule 902. (1) The supervisor or authorized representative of the supervisor shall

issue plugging instructions after receipt of notification pursuant to R 324.901. The

plugging instructions shall specify all of the following information:

(a) The type and amount of plugging material to be used.

(b) The depths at which bridges are to be set.

(c) The depths and lengths of cement plugs.

(d) The amount of casing to be pulled.

(e) Other requirements the supervisor determines are necessary for the proper

plugging of the well.

(2) A permittee of a well shall ensure that all oil, gas, brine, and fresh water is

confined to the strata in which the oil, gas, brine, and fresh water occur by using cement

plugs or other plugs approved by the supervisor. A permittee of a well shall ensure that

the well is plugged under static hole conditions at all times, unless otherwise approved

by the supervisor or authorized representative of the supervisor.

(3) A permittee of a well shall ensure that each cement plug, except for the bottom

hole plug required by subrule (5) of this rule, the plug to be set at the base of the surface

casing required by subrule (6) of this rule, and the surface plug required by subrule (7)

of this rule, is a minimum of 200 feet in length or contains 50 sacks of cement,

whichever is the greater volume of cement, unless otherwise approved by the

supervisor or authorized representative of the supervisor.

(4) A permittee of a well shall ensure that each cement plug, except for the bottom

hole plug required by subrule (5) of this rule and the plug to be set at the base of the

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surface casing required by subrule (6) of this rule, is allowed to set undisturbed for a

minimum of 1 hour and that the fluid level in the casing is continuously observed. If

the observed fluid level in the casing drops during the hour, then the cement plug shall

be tagged to ensure that the plug is still in place before setting the next plug uphole.If

the plug is found not to be in place, then the plug shall be reset.

(5) A permittee of a well shall ensure that the bottom hole cement plug is either:

(a) A minimum of 200 feet in length, is allowed to set undisturbed for a minimum

of 4 hours, has reached a compressive strength of 100 psi or more, and is tagged to

ensure that it is still in place before setting the next plug uphole; however, if the

bottom hole cement plug in a dry hole drilled by rotary methods is a minimum of 400 feet

in length and the fluid level in the hole is observed to remain static, then the bottom hole

plug is not required to be tagged.

(b) A mechanical bridge plug or other approved bridge has been set and a

minimum of 50 feet of cement has been placed on the bridge before setting the next plug

uphole.

(6) A permittee of a well shall set the plug at the base of the surface casing using

either of the following methods as approved by the supervisor or authorized

representative of the supervisor:

(a) In static hole conditions, a cement plug shall be set at a minimum of 100 feet

below the surface casing and shall extend a minimum of 100 feet into the surface casing.

The cement plug shall be allowed to set undisturbed a minimum of 4 hours, shall have

reached a compressive strength of 100 psi or more, and shall be tagged to ensure that it

is still in place before setting the next plug uphole. If the plug is found not to be in

place, then the plug shall be reset.

(b) A mechanical open hole bridge plug or other approved bridge shall be set a

minimum of 100 feet below the surface casing. A cement plug shall then be placed on

the mechanical open hole bridge plug or other approved bridge. The cement plug shall

extend a minimum of 100 feet into the surface casing,

unless otherwise approved by the supervisor or authorized representative of the

supervisor.

(7) A permittee of a well shall set a cement surface plug a minimum of 30 feet

below the surface and within 5 feet of the surface, unless otherwise approved by the

supervisor or authorized representative of the supervisor.

(8) If surface casing is not present, a permittee of a well shall set a mechanical

open hole bridge plug or other approved bridge a minimum of 100 feet below the base

of the glacial drift or 100 feet below the deepest fresh water stratum, whichever is the

greater depth, and shall circulate cement to within 5 feet of the surface.

(9) A permittee of a well shall ensure that the surface pipe or conductor pipe

abandoned with the hole is cut off at a point not less than 4 feet below grade, a 1/2-inch

steel welded plate or another type of seal approved by the supervisor or authorized

representative of the supervisor is placed across the top of the pipe or pipes, and the

permit number of the well is permanently affixed to the plate or approved seal at the

top of the well.

(10) A permittee shall file, within 60 days after plugging, the final plugging

forms and certified copies of the service company records, which shall include all of

the following information:

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(a) The type of cement and number of sacks used, including the additives and

percentages of the additives for each cement bridge plug.

(b) The type and volume of plugging material used if other than cement.

(c) The number of bridge plugs set in the hole and the depth and length of each

plug.

(d) Other materials left in the hole.

(e) Service companies’ records of cementing operations if requested by the

supervisor or authorized representative of the supervisor.

(f)

All available graphics, if requested by the supervisor or authorized

representative of the supervisor, showing the all of following information:

(i) Pumping.

(ii) Placement of cement.

(iii) Weights.

(iv) Times.

(v) Pump rates.

(vi) Other pertinent data dealing with the plugging operations.

(g) The amounts and type of mix water used for each sack of cement.

(h) The volume and types of spacers and flushes used.

(i) The operator’s daily plugging records.

(11) At a permittee's option, the well bore may be plugged from bottom to top with

a material approved by the supervisor if the hydrostatic pressure of the material used is

not allowed to exceed the fracturing pressure of the strata.

History: 1996 AACS.

R 324.903 Commencement of plugging operations.

Rule 903. (1) A permittee of a well shall commence plugging operations within

90 days after drilling completion or well completion as a dry hole, when the well has

not economically produced or has not been utilized for its permitted use for more than 12

consecutive months, when a change of well status has not been granted, or when the

permitted use has been suspended for more than 12 consecutive months. The supervisor

may require, or a permittee may submit, proof that is necessary to determine if the

well is being economically produced.

(2) After receiving a written request showing just cause why the well should not

be plugged, the supervisor or authorized representative of the supervisor may grant

temporary abandonment status pursuant to R 324.209 or require completion of the

plugging operations.

(3) A permittee may petition the supervisor for a hearing to show cause why the

well should not be plugged.

History: 1996 AACS.

R 324.904 Pulling of surface pipe and conductor pipe.

Rule 904. A permittee of a well shall ensure that surface pipe or conductor

pipe is not pulled at a location, unless it is required by the supervisor.

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History: 1996 AACS.

PART 10. WELL SITES AND SURFACE FACILITIES; PREVENTION OF

FIRES, POLLUTION, AND DANGER TO, OR DESTRUCTION OF, PROPERTY

OR LIFE

R 324.1001 Well sites and surface facilities; flammable and combustible

material.

Rule 1001. A permittee of a well shall ensure that the area around the well and

surface facilities is kept clear of flammable and combustible material stored within a

radius of 75 feet, or as approved by the supervisor, using the well or dike wall as the

point of measurement. The supervisor, if conditions warrant, may also require

construction of a fire line around the outer edge of the cleared area. A permittee of a

well shall ensure that the disposal of material resulting from the clearing operations is

consistent with all applicable state and federal laws and regulations.

History: 1996 AACS.

R 324.1002 Secondary containment requirements and construction standards.

Rule 1002. (1) All wellheads and pump jacks installed after the effective date of

these rules and surface facilities constructed for hydrocarbon, gas, brine injection, or

brine handling or surface facilities converted to brine injection or handling after

November 15, 1989, shall provide for secondary containment pursuant to the

requirements of this rule. A permittee of a well shall maintain all existing dikes or fire

walls approved before November 15, 1989, in a manner to form a reservoir that has a

capacity of 1 1/2 times the capacity of the enclosed tank or tank battery and shall keep the

reservoir free of oil, emulsions, tank bottoms, brine, water, vegetation, debris, or any

flammable or combustible material. The supervisor or authorized representative may

require surface facilities for hydrocarbon, gas, brine injection, or brine handling

constructed before November 15, 1989, to be upgraded to meet the requirements of this

rule if the facility is substantially reconstructed.

(2) A permittee of a well shall submit secondary containment plans to the supervisor

or authorized representative of the supervisor for approval before construction of the

facility. The secondary containment plans shall consist of a plot plan of the proposed

facility and cross sections showing construction details of the sidewalls and floor or

floors of all secondary containment areas, including the proposed overall dimensions of

the facility. The supervisor or authorized representative of the supervisor shall approve or

disapprove the secondary containment plans within 30 days of receipt of the plans.

(3) A permittee of a well shall comply with all of the following minimum

construction standards to meet the secondary containment requirements of this rule:

(a) A permittee shall be required to prepare a hydrogeological investigation of the

facility area to establish local background groundwater quality. The hydrogeological

investigation shall include all of the following:

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(i) Water quality sampling pursuant to the parameters established in

R 324.802(g)(iv).

(ii) A determination of the direction of groundwater flow and depth to the

groundwater in the uppermost aquifer.

(iii) A chemical analysis showing the concentrations of benzene, ethylbenzene,

toluene, and xylene.

(iv) A geologic description of earth materials, both horizontally and vertically, in

the immediate vicinity of the proposed facility.

(b) Each facility shall be required to have 1 of the following monitoring systems to

detect leakage from hydrocarbon or brine storage secondary containment areas:

(i) A minimum of 1 groundwater monitoring well downgradient which is in close

proximity to all hydrocarbon or brine storage secondary containment areas.

(ii) Tertiary containment underlying the secondary containment, which shall be

constructed and sealed in a manner to capture any hydrocarbons or brine that may leak or

seep through the secondary containment. A layer of permeable material and a monitoring

tube shall be placed between the secondary and tertiary containment to allow monitoring

to determine the presence of any leakage or seepage through the secondary containment.

(c) A vessel that contains hydrocarbons or brine, or both, shall be elevated and

placed on impervious pads or constructed so that any leakage can be easily detected. A

vessel that is to be used on-site for 30 days or less shall, at a minimum, be placed on leak-

resistant material.

(d) A hydrocarbon and brine storage vessel, including oil heating and treating

equipment, shall be located in a secondary containment area and the containment volume

shall be in compliance with the following minimum requirements, as applicable:

(i) Containment areas that have only brine storage vessels shall be constructed to

contain 150% of the largest storage vessel.

(ii) Containment areas with only hydrocarbon storage vessels shall be constructed

pursuant to R 29.2301 et seq.

(iii) Containment areas where both hydrocarbon and brine storage vessels are

located shall be in compliance with the volume requirements for the largest storage

vessels.

(iv) Precipitation shall be taken into consideration in the design of the secondary

containment area.

(e) The sidewalls and floor of the secondary containment and spill containment

areas shall be constructed and sealed in a manner to prevent the seepage of hydrocarbons

or brine, or both, into the surrounding soils, surface waters, or groundwater.

(f) A hydrocarbon and brine storage vessel shall not be erected, enclosed, or

maintained closer than 200 feet from any drilling or producing well.

(g) Oil heating or treating equipment shall not be erected, enclosed, or maintained

closer than 75 feet from any drilling or producing well or oil storage tank or tank battery.

(h) Dikes shall be maintained and the enclosure kept free of all of the following:

(i) Oil.

(ii) Emulsions.

(iii) Tank bottoms.

(iv) Brine.

(v) Water.

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(vi) Vegetation.

(vii) Debris.

(viii) Any flammable or combustible material.

(i) The hydrocarbon and brine truck loading and unloading areas located outside of

hydrocarbon or brine storage secondary containment areas shall have a spill containment

capacity equal to double the volume of the hoses used to connect the truck to the tanks,

but not less than a capacity of 5 barrels. The spill containment shall be constructed and

sealed in a manner that prevents the seepage of hydrocarbons or brine, or both, into the

surrounding soils, surface waters, or groundwater.

(j) Brine disposal well truck unloading areas and commercial brine truck loading

and unloading areas located outside of hydrocarbon or brine storage secondary

containment areas shall be constructed and sealed in a manner that prevents the seepage

of hydrocarbons or brine, or both, into the surrounding soils, surface waters, or

groundwater. In addition, a ramp shall be constructed to contain the unloading vehicle, its

hoses, and connections within the ramp area. The ramp area shall contain a sump and be

connected to a secondary containment area so that any spillage drains into the sump and

into the secondary containment area. The spill containment ramp and sump shall have a

combined capacity of not less than 20 barrels.

(k) Sumps shall be constructed of materials impervious to hydrocarbons and brines

and resistant to damage and deterioration during use. Sumps shall be connected to the

ramp area and the secondary containment area in a manner that prevents leakage.

(l) Surface facilities for hydrocarbon and brine handling shall be constructed to

meet all of the following minimum requirements:

(i) All transfer and injection pumps shall have leak containment.

(ii) All brine and hydrocarbon flow lines to a facility are considered part of that

facility and are subject to the following requirements:

(A) All flow lines shall be pressure tested pursuant to the provisions of

paragraph (iii)(A),(B),(C),(E), and (G) of this subdivision.

(B) A permittee may elect to not perform the pressure testing of the flow lines,

except flow lines that transport brine only, if the permittee performs visual inspections of

the entire flow line corridor every 3 months, except when impractical due to snow cover,

and reports the results of the inspections to the supervisor or authorized representative of

the supervisor annually by January 31 of each year for the previous calendar year.

(iii) All buried facility piping for the transport of liquids shall be pressure-tested

pursuant to the following provisions, as applicable:

(A) Piping made of noncorrodible or corrosion-protected material shall be

pressure-tested every 3 years.

(B) All piping other than piping specified in subparagraph (A) of this paragraph

shall be pressure-tested every 12 months.

(C) If buried piping is excavated for repair or relocation, then the disturbed

portion shall be pressure-tested immediately pursuant to subparagraphs (D) and (E) of

this paragraph.

(D) The pressure test shall be 100% of the normal oil and gas separator operating

pressure. The pressure shall be stabilized at 90% of test pressure, at a minimum, and shall

hold for a period of 15 minutes.

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(E) A permittee shall provide certification to the supervisor or authorized

representative of the supervisor, within 30 days of a pressure test, that a pressure test was

conducted and the facility piping passed the pressure test. If a facility’s piping does not

pass the pressure test, the supervisor or authorized representative of the supervisor shall

be notified by the permittee within 48 hours after the test. If the pressure test indicated

that the facility’s piping leaked, then the piping shall be repaired and retested before

putting the piping back in service. After the repair of the piping, the permittee shall report

the repair to the supervisor or authorized representative of the supervisor and provide

certification that the piping has been retested and is not leaking.

(F) Single-phase gas lines are not subject to the pressure test requirements if the

lines are protected by a liquid phase trap.

(G) The supervisor may approve or require other pressure testing or leak

detection methods in place of the pressure testing required in this paragraph.

(iv) At production or injection well facilities, all piping shall be routed above the

ground and kept within the secondary containment area where practical. Piping that

cannot be routed above the ground shall have its location marked with posts or with other

location-identifying markers approved by the supervisor or authorized representative of

the supervisor so that the buried piping can be easily located.

(v) Brine injection wells shall have a working check valve on the flow line at or

near the wellhead to avoid backflow.

(vi) All hydrocarbon and brine loading and unloading facility transfer lines that

are not in use shall be secured to prevent spillage. A shutoff valve shall be installed at the

truck connect point and at the storage vessels. At connect points, impermeable drip

containment vessels shall be used and shall be an adequate size to contain all spillage and

precipitation to avoid overflow.

(m) Wellheads, flare pits, vents, and flare stacks shall have secondary containment

and spill containment areas constructed in a manner to prevent the seepage of

hydrocarbons or brine, or both, into the surrounding soils, surface waters, or

groundwater. Secondary containment at the wellhead shall be constructed in a manner to

capture any leakage of liquid that may occur. In addition, if the wellhead is provided with

a pump jack or is converted to a pump jack equipped with a gasoline or diesel-powered

engine, then the engine shall also have secondary containment that is sufficient to prevent

the seepage of any machine oils or fuels into the surrounding soils, surface waters, or

groundwater. Injection wells utilized for gas storage are exempt from this subrule.

(4) Upon completion of the construction of the facility, but before its use, a

permittee of a well shall certify, to the supervisor or authorized representative of the

supervisor, that the secondary containment area was constructed according to the

approved plan. A permittee shall ensure that an approved spill or loss response and

remedial action plan is also on file with the supervisor or authorized representative of the

supervisor before a facility is used.

(5) Before any significant modification of the secondary containment area occurs, a

permittee of a well shall notify the supervisor or authorized representative of the

supervisor and receive approval before making the modification. The supervisor or

authorized representative of the supervisor shall approve or deny the request within 10

days of receipt of the request.

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(6) A permittee of a well shall perform inspections at the facility at a frequency that

is sufficient to ensure that the throughput of fluids in the system does not exceed the

primary and secondary containment capacity between inspections. The permittee shall

perform at least 1 inspection per week.

(7) The supervisor shall require the installation of an automatic facility shutdown

system if the facility has a throughput of liquids in a 24-hour period that exceeds the

containment volume of the secondary containment area. The automatic shutdown system

shall be designed to prevent liquids from overflowing the secondary containment area. A

facility shall be exempt from the requirement of an automatic shutdown system if the

facility has staff present 24 hours per day and is equipped with alarm systems on the tank

or tanks of the tank battery.

(8) The monitoring system required by R 324.1002(3)(b) shall be kept in a

functional condition so that water samples can be collected and water level measurements

can be taken every 6 months. The water samples shall be tested for specific conductance

as an indicator of dissolved solids, concentrations of chloride, and a chemical analysis

pursuant to subrule (3)(a)(iii) of this rule, except the chemical analysis provided by

subrule (3)(a)(iii) of this rule shall not be required at monitoring systems at surface

facilities where liquid hydrocarbons are not handled. If sampling indicates a possible

problem, then additional sampling for the water quality parameters established in

R 324.802(g)(iv) may be required. The results of the sample analysis shall be provided to

the supervisor or authorized representative of the supervisor as soon as the results are

available. If the samples taken by the permittee show substantial increases above

background water quality, then the permittee shall, at a minimum, increase monitoring. If

the samples confirm that hydrocarbons are present at levels above background, then the

permittee shall immediately take remedial action in the form of containment and removal.

(9) A permittee of a well shall provide a right of entry to the facility for monitoring

at all times to the supervisor or authorized representative of the supervisor.

History: 1996 AACS; 2018 AACS.

Editor's Note: An obvious error in R 324.1002 was corrected at the request of the promulgating

agency, pursuant to Section 56 of 1969 PA 306, as amended by 2000 PA 262, MCL 24.256. The rule

containing the error was published in Michigan Register, 2018 MR 11. The memorandum requesting the

correction was published in Michigan Register, 2018 MR 18.

R 324.1003 Restoration of well site; filling and leveling of cellars, pits, and

excavations; removal of debris.

Rule 1003. A permittee of a well shall fill and level the cellar and all pits and

excavations, remove or eliminate debris, minimize erosion, and restore the well site

as nearly as practicable to the original land contour or to a condition approved by the

supervisor or authorized representative of the supervisor as soon as practical after the

completion of plugging to the surface, but not more than 6 months after the completion of

plugging to the surface.

History: 1996 AACS.

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R 324.1004 Safety measures.

Rule 1004. If hazards to life or property, or both, exist, then a permittee of a

well shall post safety signs in conspicuous places around the well or surface facility. The

supervisor or authorized representative of the supervisor may require the installation of

fences, gates, or other safety measures.

History: 1996 AACS.

R 324.1005 Use of pits to collect waste oil and tank bottoms prohibited;

conveying, storing, or disposing of waste oil and tank bottoms.

Rule 1005. A permittee of a well shall not use earthen pits to collect waste oil and

tank bottoms. A permittee shall not convey, store, or dispose of waste oil and tank

bottoms in a manner that causes waste.

History: 1996 AACS.

R 324.1006 Cleanup and disposal of losses.

Rule 1006. A permittee of a well shall clean up and dispose of, in a manner

consistent with these rules and all applicable state and federal laws and regulations,

losses of oil, gas, or brine from wells, flow lines, and associated surface facilities.

History: 1996 AACS.

R 324.1007 Notice of serious accident; reporting.

Rule 1007. (1) A person shall immediately notify the supervisor or authorized

representative of the supervisor of a serious accident that has created, or may create, a

fire or other hazard that may cause waste. The notification shall be made within 8

hours of the accident, by telephone, and shall give the particulars of the accident. A

detailed written report shall be submitted to the supervisor or authorized representative

of the supervisor within 15 days of the accident.

(2) If a person cannot contact the supervisor or authorized representative

of the supervisor after an accident, then the person shall immediately telephone the

pollution emergency alerting system.

History: 1996 AACS.

R 324.1008 Reporting of losses, spills, and releases.

Rule 1008. (1) A permittee of a well shall, under this rule and instructions

issued by the supervisor and in compliance with all applicable state and federal laws

and regulations, promptly report and record all reportable losses, spills, and releases

of any of the following:

(a) Brine.

(b) Crude oil.

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(c) Oil or gas field waste.

(d) Natural gas.

(e) Products and chemicals used in association with oil and gas exploration,

production, disposal, or development.

(2) A permittee of a well shall promptly report, within 8 hours of a loss, release, or

spill discovery, by telephone or in person, to the supervisor or authorized representative

of the supervisor during normal business hours or to the department of environmental

quality, pollution emergency alerting system between 5 p.m. and 8 a.m. and on

weekends and holidays, all losses or releases of gas that result in, or may result in, a

nuisance odor or unnecessary endangerment of public health or safety, and all losses or

spills of 42 gallons or more of brine, crude oil, or oil and gas field waste. A permittee

shall provide all of the following minimum information, to the extent known, when

reporting the loss, spill, or release:

(a) The name of person reporting the loss, spill, or release.

(b) The name of permittee who has sustained the loss, spill, or release.

(c) The date and time of the loss, spill, or release.

(d) The date and time that the loss, spill, or release was discovered.

(e) The date and time cleanup commenced.

(f) The location of the loss, spill, or release, including all of the following

information:

(i) Well name.

(ii)Quarter-quarter-quarter section.

(iii)Section number.

(iv)Township.

(v) County.

(g) The material lost, spilled, or released.

(h) The volume of the loss, spill, or release.

(i) The volume of the loss, spill, or release recovered.

(j) The cleanup or recovery measures taken.

(k) The cause of the loss, spill, or release.

(l) Whether the loss, spill, or release contacted surface waters, groundwater, or

other environmentally sensitive resources.

(m) The approximate air temperature, wind direction, wind velocity, and

precipitation conditions at the time of the spill or release.

(3) A permittee of a well shall submit written notification of the losses, spills, and

releases to the supervisor or authorized representative of the supervisor by completing

all parts of the form provided by the supervisor within 10 days from the time the loss,

spill, or release was discovered.

(4) A permittee of a well shall report all losses or spills of less than 42 gallons of

brine, crude oil, or oil and gas field waste by completing only parts 1 and 3 of the form

provided by the supervisor if both of the following provisions apply:

(a) The loss or spill does not contact surface waters, groundwater, or other

environmentally sensitive resources.

(b) The loss or spill is completely contained and cleaned up within 48 hours from

the time the loss or spill was discovered.

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(5) If a loss or spill of less than 42 gallons of brine, crude oil, or oil and gas field

waste does contact surface waters, groundwater, or other environmentally sensitive

resources, or is not completely contained and cleaned up within 48 hours from the

time the loss or spill was discovered, then a permittee of a well shall report the loss or

spill as provided by subrule (2) of this rule and submit the written notification as

provided by subrule (3) of this rule.

(6) If the loss or spill is less than 42 gallons of brine, crude oil, or oil and gas field

waste, then the loss is not a reportable loss or spill if the loss or spill occurs while a

permittee or an authorized representative of the permittee is on-site and the loss or spill is

completely contained and cleaned up within 1 hour of the occurrence.

(7) A permittee of a well shall promptly report, within 8 hours of discovery of

the loss or spill, by telephone or in person, a loss or spill of other chemicals used in

association with oil and gas exploration, production, disposal, or development, shall

provide the information required in subrule (2)(a) through (l) of this rule, and shall

complete the form required in subrule (3) of this rule. A permittee shall report the

losses or spills under other applicable state and federal laws and regulations.

History: 1996 AACS; 2001 AACS.

R 324.1009 Smoking and open flame restrictions.

Rule 1009. A permittee of a well shall ensure that smoking and open flames shall

not occur where oil or gas, or both, constitutes a hazard of fire or explosion.

History: 1996 AACS.

R 324.1010 Gas burning, processing, or disposal.

Rule 1010. A permittee of a well shall ensure that all gas produced in the operation

or testing of wells that is not utilized is burned, processed, or disposed of in a manner

consistent with these rules and all applicable state and federal laws and regulations. The

gas shall not be burned closer than 100 feet from a well or storage tank or 300 feet

from structures used for public or private occupancy or from any other flammable

and combustible material.

History: 1996 AACS.

R 324.1011 Purging, removal, and abandonment of lines and vessels.

Rule 1011. A permittee of a well shall purge all flow lines and vessels, including

tanks, if the flow lines or vessels are not used for 1 year and shall provide notification of

the purging operation to the supervisor or authorized representative of the supervisor.

The supervisor may require the line to be removed or abandoned.

History: 1996 AACS.

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R 324.1012 Identification of wells and surface facilities.

Rule 1012.(1)A permittee of a well shall ensure that a well is identified by a sign

which is posted in a conspicuous place and which is not more than 20 feet from the well.

A sign shall be durably constructed, be kept in good condition, and the lettering shall be

not less than 1 1/2 inches high and legible under normal conditions at a distance of 25

feet. A sign shall show all of the following information:

(a) The permit number.

(b) The name of the permittee.

(c) The name of the lease and well number.

(d) The well location by quarter-quarter section, township, and range.

(e) A telephone number by which an authorized representative of the permittee

may be contacted at any time to respond to an emergency at the well.

(2) A surface facility shall be identified by a sign which is posted in a conspicuous

place and which is not more than 25 feet from the outside limits of the surface facility or

at a location prescribed by the supervisor or authorized representative of the

supervisor. A sign shall show all of the following information:

(a) The name of the permittee or owner.

(b) A telephone number by which an authorized representative of the permittee

may be contacted at any time to respond to an emergency at the facility.

(c) The location by quarter-quarter section, township, and range. If more than 1

facility is located at a common site, 1 identification sign is sufficient. A sign shall be

kept in good condition and the lettering shall be not less than 1 1/2 inches high and

legible under normal conditions at a distance of 25 feet.

History: 1996 AACS; 2001 AACS.

R 324.1013 Nuisance odors.

Rule 1013. A person shall not cause a nuisance odor in the exploration for, or in

the development, production, handling, or use of, oil, gas, or brine or in the handling of

any product associated with the exploration, development, production, or use of oil,

gas, or brine.

History: 1996 AACS.

R 324.1014 Suspension of OIL AND GAS operations due to threat to

public health and safety.

Rule 1014. (1) The supervisor or authorized representative of the supervisor

shall have the authority to immediately require corrective action, including suspending

any or all components of the oil and gas operations, if the oil and gas operations have

been determined by the supervisor to be in violation of the provisions of the act, these

rules, permit conditions, instructions, or orders of the supervisor and threatens the public

health and safety.

(2) A suspension of oil and gas operations shall be in effect for not more than 5

days or until the operation is in compliance and protection of the public health and

safety is ensured. To extend the suspension beyond 5 days, the supervisor shall issue an

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emergency order to continue the suspension of oil and gas operations and may schedule

a hearing under part 12 of these rules. The total duration of the suspension of oil and

gas operations shall not be more than 21 days, as provided in section 61516 of the act.

History: 1996 AACS; 2002 AACS.

R 324.1015 Nuisance noise; “decibel,” “decibels on the a-weighted network,”

“noise-sensitive area,” and “nuisance noise” defined.

Rule 1015. (1) A person shall not cause a nuisance noise 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.

(2) If the supervisor or authorized representative of the supervisor receives 1 or

more complaints of noise heard by the complainant at noise-sensitive areas that is

attributed to a surface facility, then the supervisor may require the permittee to collect

decibel readings to determine the sound levels at the noise-sensitive areas and at a

distance of 1,320 feet from the facility. If the sound level of the facility is more than 45

decibels

on

the

a-weighted

network

at

a

distance of 1,320 feet from the facility, then the supervisor or authorized representative of

the supervisor may find that a nuisance noise exists after considering all applicable

information, including the distance between the surface facility and the noise-sensitive

areas, the sound levels at the noise-sensitive areas, and sound attributable to sources other

than the surface facility. The supervisor or authorized representative of the supervisor

may require appropriate noise control measures to reduce the decibel levels. If noise

control measures are required, then the permittee shall submit, to the supervisor or

authorized representative of the supervisor, for approval, an abatement plan and schedule

for implementation within 30 days of a determination by the supervisor or authorized

representative of the supervisor that noise control measures are necessary.

(3) As used in this rule:

(a) “Decibel” means a unit of sound level on a logarithmic scale measured relative to

the threshold of audible sound by the human ear in compliance with the ANSI standard

1.1, entitled “Acoustical Terminology,” 1994 edition, which is adopted by reference in

these rules. Copies of the standard are available for inspection at the Lansing office of the

office of oil, gas, and minerals of the department of environmental quality. Copies may

be obtained from the Michigan Department of Environmental Quality, Office of Oil, Gas,

and Minerals, P.O. Box 30256, Lansing, Michigan 48909, at a cost as of the time of

adoption of these rules of $100.00 each, and from the American National Standards

Institute, 11 West 42nd Street, New York, NY 10036, at a cost as of the time of adoption

of these rules of $100.00 each.

(b) “Decibels on the a-weighted network” means decibels measured on the a-

weighted network of a sound level meter, as specified in the ANSI standard 1.4, entitled

“Specifications for Sound Level Meters,” 1983 edition, which is adopted by reference in

these rules. Copies of the standard are available for inspection at the Lansing office of the

office of oil, gas, and minerals of the department of environmental quality. Copies may

be obtained from the Michigan Department of Environmental Quality, Office of Oil, Gas,

and Minerals, P.O. Box 30256, Lansing, Michigan 48909, at a cost as of the time of

adoption of these rules of $70.00 each, and from the American National Standards

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Institute, 11 West 42nd Street, New York, NY 10036, at a cost as of the time of adoption

of these rules of $70.00 each.

(c) “Noise-sensitive area” means a residential dwelling, place of worship, school, or

a hospital and also means an existing site that is maintained for public recreation for

which quiet is a primary consideration in the use of the site.

(d) “Nuisance noise” means any noise from a well or its associated surface facilities

that causes injurious effects to human health or safety or the unreasonable interference

with the comfortable enjoyment of life or property.

History: 1996 AACS; 2015 AACS.

R 324.1016 Construction standards for noise abatement at compressors

associated with surface facilities.

Rule 1016. (1) This rule shall apply to compressors that have motors rated for

more than 150 horsepower.

(2) A permittee of a well who installs a compressor after the effective date of

these rules, or a permittee of a well who substantially reconstructs an enclosure for a

compressor after the effective date of these rules, shall comply with all of the following

provisions:

(a) The compressor, drive motor, and cooler shall be completely enclosed.

(b) The walls, doors, and roof of the enclosure shall be completely lined with

sound-absorbent material.

(c) The compressor drive motor shall be equipped with a hospital-type muffler or

the equivalent.

(d) Air intake and exhaust passages shall be constructed so as to include at least 1

right-angle turn between the point of air entrance or exit to or from the passage and the

main volume of the compressor enclosure. Air intake and exhaust passages shall be

completely lined with sound- absorbent material, unless the passages vent through the

roof.

(e) The compressor shall be capable of operating with the enclosure doors closed at

ambient air temperatures of 85 degrees Fahrenheit or lower."Doors" as used in this rule

shall not include necessary openings for air intake and exhaust passages.

(3) The supervisor or authorized representative of the supervisor may grant an

exception to the requirements of subrule (2) of this rule if a permittee designs and

constructs a compressor according to a plan submitted to, and approved by, the

supervisor or authorized representative of the supervisor. The plan shall provide for

sound abatement equal to or exceeding the sound abatement standard specified in subrule

(2)(a) of this rule.

(4) A compressor which is installed as a replacement for, and on the same site as, a

compressor that was installed before the effective date of these rules and which is an

equivalent size as the previous compressoris not subject to subrule (2) of this rule.

History: 1996 AACS.

PART 11. HYDROGEN SULFIDE MANAGEMENT

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R 324.1101 Definitions; B to M.

Rule 1101. As used in this part:

(a) "Briefing area" means a specified geographic area nearby where all personnel

can safely assemble in an emergency.

(b) "Colorimetric or length of stain tubes" means glass tubes that contain a

chemical which changes color upon exposure to a specified substance and which allow

the concentration of the specified substance to be read directly.

(c)

"Emergency preparedness coordinator" means an individual appointed

pursuant to Act No. 390 of the Public Acts of 1976, being §30.401 et seq.of the Michigan

Compiled Laws, to coordinate emergency planning or services within the county or

municipality.

(d) "Existing H2S well" means an H2S well that is drilled and completed before

September 2, 1987.

(e) "Existing process equipment" means equipment for the production of oil or

gas, or both, which was in existence, and through which oil or gas, or both, was being

produced, before September 2, 1987. Existing process equipment does not include gas

sweetening plants or stripping plants.

(f) "Flare" means a device for the burning of gasses in which the flame is exposed

to the atmosphere and burning takes place at a height of not less than 20 feet above the

ground.

(g) "H2S well" means a well that contains a hydrogen sulfide content in the gas of

not less than 300 ppm.

(h) "Incinerator" means a device specifically designed for the destruction, by

burning, of combustible gasses, in which the products of combustion are emitted to the

outer air by passing through a stack or chimney that opens to the outer air at a height of

not less than 20 feet above the ground.

(i) "Mcf" means 1,000 cubic feet of gas at standard conditions of 14.65 psi

absolute and at 60 degrees Fahrenheit.

History: 1996 AACS.

R 324.1102 Definitions; N to W.

Rule 1102. As used in this part:

(a) "NACE" means the national association of corrosion engineers.

(b) "New H2S well" means an H2S well that is drilled or completed after

September 2, 1987.

(c) "Radius of exposure" means the distance, in feet, that results when appropriate

values are substituted for the variables in the following equation:

RoE = (A x B x C) ^0.6258where

A = 1.589 for a 100-ppm radius of exposure.

B = the mole fraction concentration of hydrogen sulfide in the released gas.

C = the maximum volume of gas determined to be available for release in cubic

feet per 24 hours. The radius of exposure is the distance from a point of release at

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which a specified concentration of hydrogen sulfide would occur if gas of a known

concentration of hydrogen sulfide were released at a known rate.

(d) "Safety equipment" means, at a minimum, all of the following items:

(i) First aid kits.

(ii) Stretchers.

(iii) Blankets.

(iv) Portable dry chemical fire extinguishers.

(v) Ropes.

(vi) Flare guns and flares.

(vii) Battery-operated lanterns.

(viii) Portable electronic hydrogen sulfide detectors.

(ix) Warning signs that have the word "Danger" or "Caution" followed by the

words "Poison Gas."

(x) Two copies of the owner's contingency plan.

(xi) Not less than 2 portable, self-contained, pressure-demand breathing apparatus

that have a 30-minute air supply.

(xii) A supply of compressed breathable air or oxygen that is sufficient to recharge

each self-contained breathing apparatus at least once.

(e) "Well class" means the category into which an H2S well falls or, in the case of

an H2S well to be drilled, the category into which it is expected that the well will fall, as

follows:

(i) "Class I H2S well" means a well that has a 100-ppm radius of exposure of more

than 300 feet and a hydrogen sulfide content in the gas of not less than 300 ppm.

(ii) "Class II H2S well" means a well that has a 100-ppm radius of exposure of

not less than 100 feet and not more than 300 feet and a hydrogen sulfide content in the

gas of not less than 300 ppm.

(iii) "Class III H2S well" means a well that has a 100-ppm radius of exposure of

less than 100 feet and not less than 30 feet and a hydrogen sulfide content in the gas

of not less than 300 ppm.

(iv) "Class IV H2S well" means a well that has a 100-ppm radius of exposure

of less than 30 feet and a hydrogen sulfide content in the gas of not less than 300 ppm.

History: 1996 AACS.

R 324.1103 Metallic component standards.

Rule 1103. A permittee of a well shall ensure that metallic components of the well,

flow line, and associated surface facilities installed during the course of drilling,

completing, testing, producing, repair, workover, or servicing operations after September

2, 1987, where applicable, are in compliance with or exceed the standards for use in a

hydrogen sulfide environment set forth in the NACE standard MR0175-2000, 2000

edition, entitled “Sulfide Stress Cracking Resistant Metallic Material for Oil Field

Equipment,” which is adopted by reference in these rules. Copies may be inspected at the

Lansing office or field offices of the office of oil, gas, and minerals of the department of

environmental quality. Copies may be obtained from the Michigan Department of

Environmental Quality, Office of Oil, Gas, and Minerals, P.O. Box 30256, Lansing,

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Michigan 48909, at a cost as of the time of adoption of these rules of $50.00 each, and

from the National Association of Corrosion Engineers, P.O. Box 218340, Houston, Texas

77218, at a cost as of the time of adoption of these rules of $50.00 each.

History: 1996 AACS; 2001 AACS; 2015 AACS.

R 324.1104 Permittee compliance with this part and state and federal laws and

regulations.

Rule 1104. A permittee of a well shall comply with all of the provisions of this part.

Compliance with this part does not exempt a permittee from complying with all

applicable state and federal laws and regulations governing air pollution and

emissions.

History: 1996 AACS.

R 324.1105 Classification of H2S wells; applicability of rules to well classes.

Rule 1105.(1) An H2S well is considered a class I H2S well and is subject to the

requirements of R 324.1103, R 324.1104, R 324.1106 to R 324.1115(1) to

(5) and (7), and R 324.1116 to R 324.1130, unless a permittee can supply data

showing that the well is a class II H2S, class III H2S, or class IV H2S well.

(2) An H2S well that is considered to be a class II H2S well is subject to the

requirements of R 324.1103, R 324.1104, R 324.1106 to R 324.1115(1) to (5) and (7), R

324.1116 to R 324.1129, and R 324.1130(1),(3) and (4).

(3) An H2S well that is considered to be a class III H2S well is subject to the

requirements of R 324.1103, R 324.1104, R 324.1106 to R 324.1109, R 324.1111, R

324.1112, R 324.1114, R 324.1115(1) to (5) and (7), R 324.1116 to R 324.1129, and R

324.1130(1) and (4).

(4) An H2S well that is considered to be a class IV H2S well is subject to the

requirements of R 324.1103, R 324.1104, R 324.1106 to R 324.1109, R 324.1111, R

324.1112(2), R 324.1114, R 324.1115(6) and (7), R 324.1118 to R 324.1124, R

324.1126 to R 324.1129, and R 324.1130(1) and (4).

(5) If a well is being drilled through, but not completed in, a reservoir known to

contain hydrogen sulfide-bearing gas, then the well shall be in compliance with the

requirements of the H2S well class to which it would be assigned if it were completed in

the reservoir. Compliance shall continue until all hydrogen sulfide-bearing zones have

been cased off.

(6) The supervisor may require a permittee to provide the information necessary

to determine whether these rules apply to a well.

History: 1996 AACS; 2001 AACS.

R 324.1106 Location of H2S wells and associated surface facilities.

Rule 1106. (1) New H2S wells shall be located not less than 300 feet from existing

water wells, existing structures used for public or private occupancy, existing areas

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maintained for public recreation, or the edge of the traveled portion of an existing

interstate, United States, or state highway.

(2) Surface facilities associated with new H2S wells shall be located not less than

600 feet from existing water wells, existing structures used for public or private

occupancy, existing areas maintained for public recreation, or the edge of the traveled

portion of an existing interstate, United States, or state highway. The supervisor or

authorized representative of the supervisor may grant an exception to the setback

distance to not less than 450 feet for a class II H2S well and not less than 300 feet for a

class III H2S well and a class IV H2S well either upon presentation, to the supervisor or

authorized representative of the supervisor, of a consent form, provided by the

supervisor, signed by the owner or owners of all existing water wells, existing structures

used for public or private occupancy, or existing areas maintained for public recreation

located less than 600 feet from the proposed process equipment site or upon receipt of a

petition from the permittee for a hearing pursuant to part 12 of these rules.

(3) If existing process equipment is located less than 600 feet from existing

water wells, existing structures used for public or private occupancy, existing areas

maintained for public recreation, or a state, United States, or interstate highway, then

the supervisor or authorized representative of the supervisor may require relocation of

the facility if it

is substantially reconstructed after September 2, 1987.

(4) The supervisor shall not require relocation of an existing facility because of its

proximity to an existing water well, to a structure used for public or private occupancy,

to an area maintained for public recreation, or to a state, United States, or interstate

highway constructed or established after the installation of the facility or after

September 2, 1987.

History: 1996 AACS.

R 324.1107 Training.

Rule 1107.(1) A permittee of a well is responsible for ensuring that all agents,

employees, or other representatives of the permittee who are involved in drilling,

completing, testing, producing, repair, workover, or servicing operations on an H2S well

have received training from persons qualified in hydrogen sulfide safety. The training

shall include all of the following matters:

(a) The physical properties and physiological effects of hydrogen sulfide.

(b) The effects of hydrogen sulfide on metals and elastomers.

(c) Emergency escape procedures.

(d) The location and proper use of safety equipment.

(e) The locations of primary and secondary briefing areas.

(f) The location and operation of the hydrogen sulfide detection and warning

system.

(g) The corrective actions, shut-in

procedures,

H2S

well ignition

procedures, and procedures for notifying off-site public authorities listed in the

contingency plan to be followed in an emergency.

(h) The contents of the permittee's contingency plan.

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(2) Not less than 2 persons per crew shall be trained in emergency first aid

procedures, including

resuscitation.

red

cross-approved

techniques

of cardiopulmonary

(3) When a drilling contractor or other independent contractor is involved in

drilling, completing, testing, producing, repair, workover, or servicing operations on an

H2S well, a permittee of a well may rely on written certification obtained from the

contractor that the agents and employees of the contractor involved in the operations

have received the training required by this rule. A permittee shall retain the written

certification. Failure to ensure that employees receive adequate training and are

current in the training is sufficient cause for the suspension of any or all components of

the oil and gas operations on the well. A suspension shall continue as provided in R

324.1014(2).

History: 1996 AACS; 2002 AACS.

R 324.1108 Securing of nonproducing H2S wells.

Rule 1108. A permittee of a nonproducing H2S well shall ensure that the well is

secured to prevent a person other than authorized personnel from opening the well.

History: 1996 AACS.

R 324.1109 Warning signs; specifications.

Rule 1109. A permittee of a well shall ensure that warning signs have letters that

are not less than 1 1/2 inches in height and that are legible under normal conditions at a

distance of 25 feet.

History: 1996 AACS.

R 324.1110 Contingency plans for drilling and production.

Rule 1110.(1) A contingency plan for drilling shall be prepared by the applicant

to provide an organized plan of action for alerting and protecting personnel at an H2S

well site and the public. The contingency plan for drilling shall consist of 2 parts.

(2) Part 1 of the plan shall contain the general procedures that shall be followed in

the event of an emergency involving the possible release of hydrogen sulfide into the

atmosphere and shall include both of the following sections:

(a) A section that lists, by title, personnel to be contacted and their duties and

responsibilities. The list shall also include a delegation of duties and responsibilities

and shall specify who is responsible for ordering ignition of the H2S well if necessary.

The list shall be kept current by the applicant or permittee.

(b) A section that contains all of the following information:

(i) The emergency circumstances that cause the plan to be put into operation.

(ii)The initial procedures to be followed if the plan is activated.

(iii)The actions to be taken to ensure that all personnel known to be on the location

are accounted for and that nonessential personnel shall be safely removed.

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(iv)The actions to be taken to restrict access of nonessential personnel to the

location.

(v) The procedure for notifying the general public, public authorities, as listed in the

contingency plan, and safety agencies in the event of an emergency.

(vi)If evacuation of the public is necessary, the procedure for conducting the

evacuation.

(vii)The procedures for igniting the H2S well.

(3) Part 2 of the plan shall be site-specific and shall contain all of the following

information:

(a) An accurate map that shows the locations of all existing structures used for

public or private occupancy, areas maintained for public recreation, roads, and railroads

within a 1,300-foot radius of the drilling well in the case of a class I H2S well or within

a 500-foot radius of the drilling well in the case of a class II H2S well.

(b) A list of names, telephone numbers, and addresses of all of the following:

(i) Seasonal and permanent residents.

(ii)Private businesses.

(iii)Schools.

(iv)Places of worship.

(v) Hospitals.

(vi)Governmental offices.

(vii)Parties responsible for the areas maintained for public camping or gathering

identified on the map.

(c) A list of emergency telephone numbers, including the numbers of all of the

following:

(i) Representatives of the permittee.

(ii)Representatives of the drilling contractor.

(iii)The emergency preparedness coordinator.

(iv)Local ambulance services.

(v) Local hospitals.

(vi)Local fire departments.

(vii)The department of environmental quality.

(viii)The pollution emergency alerting system.

(4) An applicant shall submit part 1 of the contingency plan for drilling an H2S

well at the request of the supervisor or authorized representative of the supervisor. The

applicant shall submit part 2 of the contingency plan for drilling an H2S well with the

application for a drilling permit. The applicant shall submit a copy of part 2 of the

contingency plan to the local emergency preparedness coordinator at the time the

application is submitted to the supervisor. The supervisor or authorized representative

of the supervisor may require that contingency plans for producing H2S wells be updated

periodically.

(5) An applicant may request, from the

supervisor

or

authorized

representative of the supervisor, an exception to the requirement to prepare the map and

accompanying list of residences required in subrule (3) of this rule.

(6) A permittee shall prepare a contingency plan for production for any well,

surface facility, or flow line subject to this rule. A contingency plan shall contain all of

the following information:

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(a) Permittee name, well name, location, and permit number of the well or facility.

(b) An accurate map or site plan showing the location of all equipment carrying

or containing fluids with hydrogen sulfide.

(c) Names and contact information for local representatives of the permittee

who have knowledge of the equipment and authority to take corrective actions at

the well or facility in an emergency situation.

(d) Available information on hydrogen sulfide concentrations at the site.

(7) Every 3 years or as required by the supervisor, a permittee shall review

contingency plans and certify to the supervisor or authorized representative of the

supervisor and the local emergency preparedness coordinator that the contingency

plans are accurate. The permittee shall update the contingency plan under any of the

following conditions and submit a copy of the updated contingency plan to the

supervisor or authorized representative of the supervisor and the local emergency

preparedness coordinator:

(a) A change of the notification process or local representatives of the permittee.

(b) A substantial change in the site conditions or equipment noted on the plan.

(c) A change of the permittee.

(8) A permittee shall provide a contingency plan for production to the supervisor

or authorized representative of the supervisor and the local emergency preparedness

coordinator for all wells, surface facilities, and flow lines subject to this rule 6 months

after the effective date of these amendatory rules for all existing production facilities

and before the commencement of production for all production facilities completed after

the effective date of these amendatory rules.

History: 1996 AACS; 2001 AACS.

R 324.1111 Compliance with rules; time.

Rule 1111. A permittee of a well shall comply with R 324.1112 to R 324.1116

not later than the time at which drilling reaches a depth of 500 feet above the projected

top of the geological stratum suspected by a permittee or the supervisor or authorized

representative of the supervisor to contain hydrogen sulfide. Compliance shall continue

until all formations or strata suspected to contain hydrogen sulfide are cased off,

plugged, or drilled and proven not to be a potential problem.

History: 1996 AACS.

R 324.1112 Briefing areas.

Rule 1112. (1) A permittee of a well shall establish primary and secondary

briefing areas at the drilling site. A permittee shall ensure that safety equipment is

located at the primary briefing area.

(2) The supervisor or authorized representative of the supervisor may require

safety equipment, in addition to that listed in R 324.1102(d), if necessary for the safety

of the public or the workers.

History: 1996 AACS.

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R 324.1113 Emergency preparedness coordinator; contact by permittee.

Rule 1113. A permittee of a well shall contact the appropriate emergency

preparedness coordinator not less than 24 hours before the commencement of drilling

the H2S well.

History: 1996 AACS; 2001 AACS.

R 324.1114 Wind direction indicators.

Rule 1114. A permittee of a well shall install wind direction indicators at the

drilling site. the wind direction indicators shall be visible from all normal work stations

within the drilling site.

History: 1996 AACS.

R 324.1115 Equipment; electric or mechanical fan; hydrogen sulfide detection

and warning system; emergency escape self-contained breathing apparatus; rig

floor ventilation.

Rule 1115. (1) A permittee of a well shall install a hydrogen sulfide detection

and warning system that activates audible and visual alarms if hydrogen sulfide is

detected. Visual alarms shall be activated if a hydrogen sulfide concentration of 10 ppm

is detected. Audible alarms shall be activated if a hydrogen sulfide concentration of

20 ppm is detected.

(2) A permittee of a well shall locate hydrogen sulfide sensors as follows:

(a) For rotary rigs, at all of the following locations:

(i) The shale shaker or at the point of first release of gas from the returning

stream of drilling fluid.

(ii) On the rig floor.

(iii) In the substructure.

(iv) At the mud hopper.

(b) For cable tool rigs, at the point of first release of gas from the well bore and

on the rig floor.

(3) After the sensors are mounted, a permittee of a well shall calibrate the system

according to the manufacturer's instructions. The permittee shall test the detection and

warning system before drilling into the geological stratum suspected to contain

hydrogen sulfide. The permittee shall record the calibrations and tests in the

driller's log. The supervisor or authorized representative of the supervisor may

witness the testing and calibration.

(4) A permittee of a well shall ensure that an emergency escape self- contained

breathing apparatus is readily available to every member of the drilling crew at that

member's work station and to other personnel required to be on the rig floor during the

drilling operation.

(5) A permittee of a well shall ensure that the rig floor and substructure is

adequately ventilated to prevent the accumulation of gas.Forced-air ventilation shall be

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used when natural ventilation is inadequate. An electric or mechanical fan shall be

available on the drill site for ventilation.

(6) A permittee of a well shall ensure that the rig floor and

substructure of a class IV H2S well is adequately ventilated to prevent the

accumulation of gas and shall utilize either a hydrogen sulfide detector that has an

audible alarm or an electric or mechanical fan that operates constantly during the

operation if natural ventilation is inadequate to keep the wellhead area free from gas.

(7) A permittee of a well shall ensure that well safety equipment is the same

equipment that is required under R 324.1102(d) for class I H2S and class II H2S wells

and R 324.1102(d)(viii), (ix), and (xi) for class III H2S wells. Safety equipment shall be

located at the primary briefing areas for class I H2S and class II H2S wells and at the

well site for class III H2S and class IV H2S wells, if safety equipment is required for

class IV H2S wells, unless otherwise stated in this rule. The supervisor or authorized

representative of the supervisor may require the use of safety equipment, in addition to

the equipment listed in R 324.1102(d), if necessary for the safety of the public or the

workers.

History: 1996 AACS.

R 324.1116 Mud gas separator; burning of gas generated by mud gas separator;

incinerator

or

flare

installation;

hydrogen

sulfide

concentration

determination.

Rule 1116. (1) All of the following provisions apply to rotary drilling operations:

(a) If a gas kick occurs, all returning drilling fluid shall be circulated through

a mud gas separator.

(b) All gas separated from the drilling fluid by the mud gas separator shall be

routed to a properly engineered incinerator or flare that has an elevated discharge to the

atmosphere and shall be burned.

(c) When gas is being routed to the incinerator or flare from the mud gas separator,

the hydrogen sulfide content of the gas shall be determined by a permittee or the

permittee's representative. The determination shall be made using colorimetric or length

of stain tubes or other equipment designed to measure hydrogen sulfide

concentrations and shall utilize a procedure approved by the supervisor or authorized

representative of the supervisor. The results of the determination shall be entered into the

driller's log.

(2) Both of the following provisions apply to cable tool drilling:

(a) All gas separated from other fluids shall be routed to a properly engineered

flare or incinerator that has an elevated discharge to the atmosphere and shall be

burned.

(b) When gas is being routed to the incinerator or flare, the hydrogen sulfide

content of the gas shall be determined by a permittee or the permittee's

representative. The determination shall be made using colorimetric or length of

stain tubes or other equipment designed to measure hydrogen sulfide concentrations and

shall utilize a procedure approved by the supervisor or authorized representative of the

supervisor. The results of the determination shall be entered into the driller's log.

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History: 1996 AACS.

R 324.1117 Initial testing.

Rule 1117. (1) When initial testing of an H2S well is performed, in addition to

applicable air pollution control commission general rules, a permittee of a well shall

comply with all of the following requirements not later than the start of testing if

permanent surface facilities have not been installed:

(a) One or more wind direction indicators shall be installed and shall be visible

from all normal work stations within the test site of class I H2S and class II H2S wells.

(b) An incinerator or flare shall be installed for the purpose of burning all gas and

stock tank vapor produced during the test. The incinerator or flare shall be equipped

with a continuous pilot light or a pilot light outage detector that has an automatic

reignition system. The incinerator or flare shall be located not less than 75 feet from the

wellhead and test tanks and shall be positioned so that the prevailing winds carry

the combustion products away from the site.

(c) A flashback prevention system shall be installed between the incinerator

or flare and the test tanks.

(d) All of the following equipment shall be located at the test site:

(i) Not less than 2 self-contained, pressure-demand breathing apparatus that have

a 30-minute air supply for class I H2S and class II H2S wells.

(ii) A first aid kit for class I H2S and class II H2S wells.

(iii) A portable electronic hydrogen sulfide detector for class I H2S and class II

H2S wells.

(iv) An emergency escape self-contained breathing apparatus for each member

of the test crew for class I H2S and class II H2S wells.

(v) The supervisor or authorized representative of the supervisor may require the

use of safety equipment in addition to the equipment listed in R 324.1102(e) if necessary

for the safety of the public or the workers.

(e) Warning signs that have the word "Danger" or "Caution" followed by the

words "Poison Gas" shall be posted at the entrances to all access roads.

(f) The supervisor or authorized representative of the supervisor shall be notified

of the expected start-up date of the initial test.

(2) During the test period, a permittee of a well shall determine the hydrogen

sulfide content of the gas produced. Hydrogen sulfide content shall be determined on-site

using colorimetric or length of stain tubes or other equipment designed to measure

hydrogen sulfide concentrations utilizing a procedure approved by the supervisor or

authorized representative of the supervisor.

(3) All gas measurements made during the initial flow test shall be made using a

meter that allows all gas metered to be burned.

(4) Operations or procedures that require the use of a self-contained breathing

apparatus shall be performed only if not less than 2 people who are authorized by the

permittee of the well are on-site.

(5) The supervisor or authorized representative of the supervisor may grant

exceptions to this rule when compliance with the provisions of this rule is not

necessary to provide for the protection or safety of the public or workers or when the

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H2S well or associated surface facilities are not likely to constitute sources of

nuisance odors.

History: 1996 AACS.

R 324.1118 Gas analyses.

Rule 1118. (1) The supervisor or authorized representative of the supervisor

may require periodic gas analyses to determine hydrogen sulfide concentration.

(2) A permittee of a well shall make a second gas analysis 1 year after the date of

the initial analysis required in R 324.1117(2). Further gas analyses shall be required

only at the request of the supervisor or authorized representative of the supervisor.

(3) A permittee of a well shall notify the supervisor or authorized representative

of the supervisor before the sampling and analysis required in subrules (1) and (2) of this

rule.

(4) A permittee of a well shall report, in writing, the results of a gas analysis

required by the supervisor or authorized representative of the supervisor to the

supervisor within 1 month of the date of the analysis.The report shall state the methods of

sampling and analysis used.

History: 1996 AACS.

R 324.1119 Wellheads; painting requirements; warning signs.

Rule 1119. (1) A permittee of a well shall ensure that the valve or valves

necessary to shut off all fluid flow nearest the wellhead are painted yellow.

(2) A permittee of a well shall ensure that the power supply kill switch of an H2S

well that is produced by artificial lift is painted yellow. A permittee of a well shall

ensure that the power supply kill switch is conspicuously marked and readily

accessible.

(3) A permittee of a well shall ensure that a warning sign that has the word

"Danger" or "Caution" followed by the words "Poison Gas" is prominently displayed at

the wellhead.

History: 1996 AACS.

R 324.1120 Flow lines; markers; protection.

Rule 1120. (1) A permittee of a well shall ensure that the routes of flow lines that

are located before the point of sale and that are used for transporting fluids

containing hydrogen sulfide are marked. Markers shall be mounted not less than 4 feet

above ground level, shall consist of signs denoting the presence of a buried line

carrying hydrogen sulfide, and shall contain the name of the flow line owner and the

flow line owner's emergency telephone number. Markers shall be properly maintained

and shall be spaced

so that the route of the flow line can be easily traced. Routes shall be kept

sufficiently cleared to allow adjacent markers to be visible with the naked eye.

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(2) A permittee of a well shall ensure that flow lines constructed above ground

level are protected from accidental damage by vehicular traffic or other similar causes.

History: 1996 AACS.

R 324.1121

Heated vessels; installation of certain equipment required;

exhaust gas stack height.

Rule 1121. A permittee of a well shall ensure that heated vessels fueled with

natural gas that contains hydrogen sulfide are equipped with a system to prevent the

emission of the fuel gas to the atmosphere in the event of a pilot failure or flameout

and shall be in compliance with the emissions and operations requirements provided in

R 336.1403. The exhaust gas stack height shall be not less than 20 feet.

History: 1996 AACS.

R 324.1122 Vessels used for

storing

hydrogen

sulfide-bearing liquid

hydrocarbons or hydrogen sulfide-bearing brine; equipment requirements.

Rule 1122.(1) A permittee of a well shall ensure that a vessel which is located at

an H2S well site or in a central production facility serving an H2S well and which is

used for the storage of hydrogen sulfide-bearing liquid hydrocarbons or hydrogen sulfide-

bearing brine is equipped with a sealing, pressure-vacuum-type hatch, except that a

pressure-vacuum-type hatch is not required on a storage vessel if the venting of vapor

to the atmosphere is permitted under subrule (4) of this rule. A hatch shall be kept

closed when a tank is not being gauged.

(2) If a storage vessel described in subrule (1) of this rule releases a total 24-hour

volume of 5 mcf or more of vapors, then a permittee of a well shall ensure that the

vessel is equipped with a vent line for conveying released gasses and vapors to an

incinerator, flare, or vapor recovery system. A flashback prevention system shall be

installed on the line between a vessel and the incinerator or flare. If a vapor recovery

system is used to control tank vapor emissions, then a flare or incinerator

shall be available for standby or emergency use. Installing a vapor recovery

system does not exempt a flare or incinerator from being in compliance with the

requirements of R 324.1123.

(3) If a storage vessel described in subrule (1) of this rule releases a total daily

volume of 5 mcf or more of vapors, then a permittee of a well shall install a fence

around the vessel equipped with a gate. A fence shall be located not less than 20 feet

from the base of

a

storage vessel. A permittee shall ensure that warning signs

with the word "Danger" or "Caution" followed by the words "Poison Gas" are installed

on all sides of the fence.If the supervisor or authorized representative of the supervisor

finds that a threat to the public safety exists due to emissions of sulfur-bearing gas or

vapor, then fencing other than that specified in R 324.102(p) may be required.

(4) If a storage vessel described in subrule (1) of this rule releases a total daily

volume of 5 mcf or less of vapor, then it may be vented to the atmosphere if the vent is

located not less than 10 feet above the tank top and if the opening of the vent is within

the diked area or not less than 20 feet above the ground if the opening of the vent is

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outside the diked area. The supervisor may prohibit venting of vapor to the atmosphere

if a verified chronic nuisance odor results from the sulfur-bearing compounds being

vented.

(5) If the hydrogen sulfide concentration at the tank thief hatch is more than 500

ppm by volume, then a permittee of a well shall ensure that a tank has a latched gate at

the foot of the catwalk stairs. A permittee of a well shall ensure that a sign reading

"Self-contained Breathing Apparatus is Recommended Beyond This Point if Hatches

are to be Opened" is posted on the gate.

(6) The supervisor may require the use of a tank gauging system that does not

require the opening of the tank hatches if a verified chronic nuisance odor results

from tank gauging.

(7) A person or a permittee of a well shall not install a tank which is used for the

storage of hydrogen sulfide-bearing liquid hydrocarbons or brine from an H2S well if the

separator or treater immediately upstream of the tank has an operating pressure of more

than 250 psig unless an independent

registered engineer certifies that the facility is designed and constructed such that

any release of liquids or gas to the tank shall not cause a release of hydrogen sulfide to

the atmosphere.

History: 1996 AACS; 2001 AACS; 2002 AACS.

R 324.1123 Incinerators and flares; equipment and design requirements;

additional requirements.

Rule 1123.(1) A permittee of a well shall ensure that an incinerator or flare

installed under R 324.1117, R 324.1122, or R 324.1124 is designed and equipped to

prevent the release of unburned gas to the atmosphere. If the daily volume of gas

handled by the incinerator or flare contains 28 pounds or more of hydrogen sulfide, then a

permittee shall ensure that the incinerator or flare is equipped with a mechanism that

operates upon failure of the pilot light to shut off the flow of fluid from the wellhead.

(2) A permittee of a well shall ensure that an incinerator or flare required by R

324.1122 is fenced. A fence shall be located not less than 20 feet from the base of the

incinerator or flare. A permittee of

a

well shall ensure that warning signs that have

the word "Danger" or "Caution" followed by the words "Poison Gas" are posted on all

sides of the fence.If the supervisor or authorized representative of the supervisor finds

that a threat to the public safety still exists due to emissions of the incinerator or

flare, then fencing other than that specified in R 324.102(p) may be required.

(3) If the supervisor or authorized representative of the supervisor finds that a

threat to the public health or safety exists due to the emission of sulfur-bearing

gasses or vapors, then a flare stack or incinerator stack that is more than 20 feet

high, as specified in R 324.1101(f) and (h), may be required.

History: 1996 AACS; 2002 AACS.

R 324.1124 Emergency relief valves.

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Rule 1124. A permittee of a well shall ensure that an emergency relief valve on

process equipment is equipped with a line for conveying the released gasses or vapors to

an incinerator or flare. The supervisor or authorized representative of the supervisor

may grant an exception if the total daily volume of gas produced is less than 5 mcf.

History: 1996 AACS.

R 324.1125 Shut-in systems.

Rule 1125.(1)A permittee of a well shall ensure that an H2S well which produces

unattended and which has a stabilized producing tubing pressure of not less than 100

psig is equipped with a high-pressure and low-pressure shut-in system.

(2) A permittee of a well shall ensure that a class I H2S well drilled after the

effective date of these amendatory rules for which the 100 ppm radius of exposure

includes an existing structure used for public or private occupancy, existing area

maintained for public recreation, or the edge of the traveled portion of an existing

interstate, united states, or state highway, shall be equipped with the following:

(a) Hydrogen sulfide sensors located on four sides of the wellhead at a distance of

not more than 20 feet. The sensors shall be set to activate safety shutdown equipment as

specified in subdivisions (b) and (c) of this subrule when a hydrogen sulfide

concentration of 30 ppm is detected. A permittee of a well shall calibrate the sensor

system according to the manufacturer's instructions.

(b) For flowing class I H2S wells:

(i) Dual manual master valves.

(ii)A fail-closed wing safety valve automatically actuated by a low pressure

pilot sensor downstream of the valve and by the hydrogen sulfide sensors at the

wellhead.

(iii)Remote telemetry that alerts the well operator when the hydrogen sulfide

sensors detect a hydrogen sulfide concentration of 30 ppm.

(iv)An emergency access valve into the tubing spool.

(c) For pumped class I H2S wells:

(i) An emergency access valve into the tubing spool.

(ii)A fail-closed blowout preventer automatically actuated in the event the polish rod

breaks.

(iii)A fail-closed polish rod ram blowout preventer automatically actuated by the

hydrogen sulfide sensors at the wellhead.

(iv)Equipment that automatically shuts off the pump drive unit in the event of a

stuffing box failure.

(v) A safety shut down of the pump drive unit, which cannot be isolated from the

tubing pressure without unlocking a valve, automatically actuated by the high pressure

low pressure sensor and the hydrogen sulfide sensors at the wellhead.

History: 1996 AACS; 2001 AACS.

R 324.1126 Vehicle loading racks; vapor return lines required; vapor vent

lines permitted.

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Rule 1126. (1) Truck vapor return lines are required on the loading racks of the

surface facilities and shall be utilized when oil or condensate is loaded into the truck,

except as provided in this rule.

(2) Truck vapor vent lines are permitted if the point of emission is not less than 75

feet from the loading rack and not less than 600 feet from an existing water well and an

existing structure used for public or private occupancy. The allowance for truck vapor

vent lines may be rescinded in specific cases if the supervisor or authorized

representative of the supervisor determines that nuisance odors are caused by the use of

the vent lines.

History: 1996 AACS.

R 324.1127 Compliance with rules before production of new H2S well.

Rule 1127. (1) A permittee of a well shall comply with this rule and R 324.1119

to R 324.1126 before production of a new H2S well.

(2) The supervisor may grant exceptions to R 324.1119 to R 324.1123, R

324.1125, R 324.1126, and this rule when the rules are not necessary to provide for

the protection or safety of the public or workers or when the H2S well or associated

surface facilities are not likely to constitute sources of nuisance odors.

History: 1996 AACS.

R 324.1128 Servicing; requirements.

Rule 1128. Before commencing an operation that requires removing the seal

between the tubing and production casing, a permittee of a well shall meet all of the

following requirements:

(a) Blowout prevention equipment sized to accommodate the tubing and rework

drill pipe shall be installed and tested for class I H2S, class II H2S, and class III H2S

wells.

(b) Primary and secondary briefing areas shall be established for class I H2S and

class II H2S wells.

(c) The same safety equipment that is required under R 324.1102(d) is required

for class I H2S and class II H2S wells and under R 324.1102(d)(viii), (ix), and

(xi) is required for class III H2S wells. Safety equipment shall be located at the primary

briefing areas for class I H2S and class II H2S wells and at the well site for class III

H2S and class IV H2S wells if required for class IV H2S wells. The supervisor or

authorized representative of the supervisor may require the use of safety equipment, in

addition to the equipment listed in R 324.1102(d), if the equipment is necessary for

the safety of the public or the workers.

(d) An electric or mechanical fan shall be located at the well site for class I H2S,

class II H2S, and class III H2S wells. The fan shall be operated constantly during

the operation to keep the wellhead area free from gas if natural ventilation is inadequate.

(e) A hydrogen sulfide detection and warning system shall be installed and have

the detector located downwind from the well or in the direction in which the fan is

blowing. The detection and warning system shall activate visual alarms if a hydrogen

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sulfide concentration of 10 ppm is detected. Audible alarms shall be activated if a

hydrogen sulfide concentration of 20 ppm is detected; however, the use of a hydrogen

sulfide detection and warning system is optional for a class IV H2S well.

(f) Signs that have the word "Danger" or "Caution" followed by the words "Poison

Gas" shall be installed at the entrances of all access roads.

(g) The supervisor or authorized representative of the supervisor shall be notified

before the start of servicing operations for class I H2S, class II H2S, and class III H2S

wells.

(h) A revised and updated contingency plan shall be at the well site and shall be

reviewed with all workers for class I H2S and class II H2S wells.

History: 1996 AACS.

R 324.1129 Burning, processing, or disposing of hydrogen sulfide gas.

Rule 1129. (1) A permittee shall not release gas produced from an H2S well to the

environment, except as follows:

(a) By burning as fuel in a heated vessel in compliance with R 324.1121.

(b) By burning in a flare or incinerator that complies with R 324.1010.

(c) By injection into an approved underground formation under R 324.612 or R

324.703.

(d) By venting from tanks under R 324.1122(4) or R 324.1124.

(e) By disposal by other means as may be approved by the supervisor under a

specific request by the permittee, if the permittee demonstrates to the supervisor that

the manner of disposal prevents waste and does not cause unnecessary endangerment

of public health, safety, and welfare.

(2) If a well or its associated surface facilities produce hydrogen sulfide and the

supervisor or authorized representative of the supervisor receives 1 or more complaints

of odor regarding the facility, then the supervisor may require the permittee of a well to

perform numerical modeling to determine the concentration of hydrogen sulfide in the

ambient air. Numerical modeling shall utilize the distance from the potential point of

an uncontrolled release of gas at the well or its associated surface facilities to the

closest existing structure used for public or private occupancy, existing area

maintained for public recreation, or the edge of the traveled portion of an existing

interstate, United States, or state highway. A permittee shall have the opportunity to

provide, in addition to the numerical modeling, actual measurements of the

concentration of hydrogen sulfide in the ambient air taken at the closest existing

structure used for public or private occupancy, existing area maintained for public

recreation, or the edge of the traveled portion of an existing interstate, United States, or

state highway.The supervisor or authorized representative of the supervisor may

determine a nuisance odor exists based on all applicable information. The supervisor or

authorized representative of the supervisor may require appropriate emission control

measures consistent with the provisions of this rule and R 324.1101 to R 324.1128. If

emission control measures are required, then the permittee shall submit, within 30 days of

being determined to be necessary by the supervisor, for the approval of the supervisor

or authorized representative of the supervisor, a timetable for the installation of any

equipment required.

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History: 1996 AACS; 2001 AACS.

R 324.1130 Requirements for certain gathering lines, flow lines, and facility

piping.

Rule 1130. (1) A gathering line, installed after the effective date of these

amendatory rules carrying gas with more than 300 ppm hydrogen sulfide shall be

subject to the provisions for design, construction, testing, maintenance, and operation

as specified in administrative rules promulgated under Act No. 165 of the Public Acts of

1969, as amended, being §483.151 et seq. of the Michigan Compiled Laws.

(2) A flow line or facility piping, carrying gas from a class I H2S well and which is

subject to a maximum working pressure in excess of 125 psig shall be subject to the

provisions for design, construction, testing, maintenance, and operation as specified in

administrative rules promulgated under Act No. 165 of the Public Acts of 1969, as

amended, being §483.151 et seq. of the Michigan Compiled Laws.

(3) A person or a permittee shall not install a flow line or gathering line, carrying

gas from a class I H2S or class II H2S well, or modify an existing flow line or

gathering line to serve additional class I H2S or class II H2S wells, unless all of the

following provisions are met:

(a) The person or permittee shall calculate the 100 ppm radius of exposure, using

either the equation set forth in R 324.1102(c) or another dispersion model accepted by

the supervisor. The calculation shall be based upon the reasonably expected

concentration of hydrogen sulfide to be transported in the flow line or gathering line,

the maximum actual operating pressure, and the volume of gas that could be released

from the flow line or gathering line, accounting for any automatic shut-in systems and

blocking valves that will be utilized.

(b) If an existing structure used for public or private occupancy, an existing area

maintained for public recreation or the edge of the traveled portion of an existing

interstate, united states, or state highway falls within the 100 ppm radius of exposure,

the person or permittee shall prepare a construction and operation plan that incorporates

reasonable measures to reduce the potential for public exposure to hydrogen sulfide

from a release that might occur. The construction and operation plan shall consider

appropriate construction standards, routing alternatives, monitoring equipment,

automatic controls for source shut-in, or other available engineering methods. The

person or permittee shall submit the construction and operation plan to, and receive

the approval of the supervisor or authorized representative of the supervisor. The

supervisor or authorized representative of the supervisor shall have 30 days to approve

the plan or to require modifications or additional information.

(c) Repair and maintenance of an existing flow line or gathering line are exempt

from the provisions of this subrule.

(4) Gathering lines, flow lines, or facility piping are not subject to this rule if they

are subject to the issuance of a certificate of public convenience and necessity by

the Michigan public service commission under the provisions of Act 9 of the Public Acts

of 1929, as amended, being §483.101 et seq. of the Michigan Compiled Laws or are

subject to regulation by the Michigan public service commission under the provisions

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of Act No. 165 of the Public Acts of 1969, as amended, being §483.151 et seq. of the

Michigan Compiled Laws.

History: 2001 AACS.

PART 12. HEARINGS

R 324.1201 Hearing; purpose; scheduling; request or petition generally.

Rule 1201. Hearings may be held to receive evidence pertaining to the need or

desirability of an action or an order by the supervisor. A hearing may be scheduled at the

initiative of the supervisor or by the supervisor upon the receipt of a petition, which is

properly filed as specified in R 324.1202, from an owner, producer, lessee, lessor, or

other person interested in the matter proposed for hearing.

History: 1996 AACS.

R 324.1202 Petition for hearing; contents.

Rule 1202. (1) A proper written petition for a hearing, except for the material filed

pursuant to subdivisions (e) and (f) of this subrule, shall be filed on 8 1/2 by 11-inch

paper and shall contain at least all of the following information:

(a) The name and address of petitioner.

(b) A specific statement of the matters asserted or relief sought indicating the rule,

order, or section of the act applicable to the petition.

(c) Property descriptions, locations, sections, townships, and counties relating to the

matter to be heard.

(d) The names and last known addresses of the last record owners, lessees, lessors,

or other parties of record in the register of deeds office who own interests in the lands

that are the subject of the petition.

(e) A map of the area to be affected and of the contiguous property. Lease ownership

and well locations within 1,320 feet of the area to be affected shall be identified.

(f) Other maps, plats, and exhibits that may be useful in considering the matter to be

heard.

(g) The name and address of the newspaper circulated in the county or counties

where the affected lands are located.

(h) A copy of a permit application and attachments pertinent to the matters asserted

in the petition.

(i) The name, address, and telephone number of the representative or representatives

of the petitioner to whom inquiries can be made.

(2) All of the following additional information shall be filed with the petition when a

spacing or proration order is to be considered:

(a) The size, shape, and orientation of the proposed drilling unit.

(b) The well spacing pattern to be proposed.

(c) The surface geographic area to be included in the spacing order, and the geologic

formation or formations to be spaced or prorated.

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(d) Well production, testing history, and other applicable reservoir and geological

data.

(e) Proposed daily well allowables, if applicable.

(3) A petition to establish secondary recovery operations pursuant to R 324.612 shall

also include all of the following information:

(a) Applicable seismic lines, profiles, and interpretation showing seismic outlines or

boundaries of reservoir structure and the geologic structure and area to be impacted by

the operations.

(b) Appropriate geologic information, such as structural cross sections and

productive areas, thickness isopach, and other essential maps.

(c) Applicable reservoir engineering data, such as the following:

(i) Pressure versus time.

(ii) Pressure versus oil production.

(iii) Reservoir rock and fluid properties.

(iv) Primary production.

(v) An estimated forecast of oil recoveries.

(vi) Estimated economics of secondary recovery project.

(d) A plan that shows the locations of existing production wells, proposed

production wells, and proposed injection wells and a facilities plan that includes

schematics that show the locations of existing and proposed flow lines and wells and

associated surface facilities.

(e) If groundwater is to be injected, a hydrogeologic investigation report of the

source aquifer.

(4) The supervisor may return a petition that is not in conformance with these rules

and may include a list of the deficiencies of the petition.

(5) All of the following additional information shall be filed with the petition when

statutory pooling is to be considered:

(a) The ownership of oil and gas interests within the drilling unit and a specific

description of the nature and extent of the interests sought to be pooled.

(b) Sworn statements that indicate, in detail, what action the petitioner has taken to

obtain a voluntary unit.

(c) Whether or not the petitioner desires to drill or operate the unit, or both, and, if

not, the name of the party nominated as operator and the recommendation of the

petitioner as to the arrangements that are just and equitable to all owners within the

drilling unit.

(d) The estimated costs of drilling, completing, and equipping the well, on a form

provided by the supervisor, and additional compensation proposed for the risk associated

with the drilling and equipping of the well.

History: 1996 AACS; 2015 AACS.

R 324.1203 Hearings subject to the administrative procedures act of 1969.

Rule 1203. A hearing scheduled by the supervisor shall be conducted pursuant

to Act No. 306 of the Public Acts of 1969, as amended, being §24.201 et seq. of the

Michigan Compiled Laws, unless a different procedure is authorized by the act or

these rules. All hearings shall be conducted in a fair and impartial manner.

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History: 1996 AACS.

R 324.1204 Notice of hearing; service; answer.

Rule 1204. (1) The supervisor shall prepare and furnish the notice of hearing to the

petitioner, together with instructions for publication and service of the notice. Upon

receipt the petitioner shall serve copies of the notice of hearing on the last known

addresses of the last record owners, lessees, lessors, or other parties of record in the

register of deeds office or assessor's records, if appropriate, who own interests in the

lands that are the subject matter of the proposed action, unless otherwise provided in

these rules.

(2) If directed by the supervisor, the petitioner shall also serve copies of the notice of

hearing at the last known addresses of the last record owners, lessees, lessors, or other

parties of record in the register of deeds office who own interests in all or part of the

quarter-quarter sections of land directly and diagonally adjacent to the lands or areas that

are the subject matter of the proposed action.

(3) The notice of hearing shall be published by the petitioner in an oil and gas

industry publication circulated in this state and in a newspaper of general circulation in

the county or counties involved with the matter to be heard. Publication shall occur not

less than 21 days before the date of the hearing. Affidavits of proof of publication shall

be filed with the supervisor before the date of the hearing.

(4) The notices of hearing shall be mailed not less than 21 days before the date of

the hearing. Affidavits of proof of mailing by first-class mail or personal service shall be

filed with the supervisor before the date of the hearing. An affidavit of proof of mailing

shall state that the notice was deposited in the United States mail not less than 21 days

before the hearing date, first-class postage prepaid, addressed to each person so served at

his or her record address as set forth in the petition pursuant to R 324.1202. Each person

so served and his or her address of record shall be specifically identified in the affidavit.

The supervisor may require service by certified mail, return receipt requested.

(5) If a hearing is initiated by the supervisor, or if the scope of a hearing requested

by a petitioner is enlarged at the initiative of the supervisor, then the supervisor shall

publish the notice of hearing and may give additional notification of the hearing by

United States mail or personal service.

(6) An interested person shall not be permitted to participate as a party in a hearing

conducted pursuant to a petition unless the person files an answer in a timely manner

with the supervisor and serves the answer to the petition upon the petitioner. The answer

shall be in writing and shall set forth the interested person's positions with regard to the

representations made or relief sought in the petition. An interested person is responsible

for requesting a copy of the petition from the petitioner at the address set forth in the

notice of hearing. The petitioner shall mail or otherwise deliver a copy of the petition and

attachments to the interested person within 3 days after receipt of a written request.

Failure of the petitioner to mail or otherwise deliver a copy of the petition to an interested

person in a timely manner relieves the interested person of the obligation to file an

answer and the interested person shall not be precluded from presenting evidence or

cross-examining witnesses. An interested person may mail or otherwise deliver his or her

answer to the supervisor and the petitioner. To be considered timely an answer must be

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received by the supervisor and the petitioner not fewer than 5 days before the date set for

the hearing. Failure to file and serve an answer in a timely manner precludes an interested

person from presenting evidence at the hearing or cross-examining witnesses. However,

an interested person who does not file an answer in a timely manner may make a

nonevidentiary statement at the hearing.

(7) The notice of hearing shall contain the following statement:

You can obtain a copy of the written petition by requesting one in writing from the

petitioner at____________________________________________________. Take note

that if you wish to participate as a party in the hearing by presenting evidence or cross-

examining witnesses, you shall deliver to the petitioner and supervisor, not less than 5

days before the hearing date, an answer to the petition in the manner set forth in

R 324.1204(6). Proof of mailing or delivering the answer shall be filed with the

supervisor on or before the date of hearing. The answer shall state with specificity the

interested person's position with regard to the petition. Failure to prepare and serve an

answer in a timely manner shall preclude you from presenting evidence or cross-

examining witnesses at the hearing. If an answer to the petition is not filed, the supervisor

may elect to consider the petition and enter an order without oral hearing.

(8) Upon a showing that service of notice cannot reasonably be made as provided by

this rule, the supervisor may authorize service of the notice of hearing to be made in

another manner reasonably calculated to give the interested parties actual notice of the

proceeding and an opportunity to be heard. A request for this authorization shall be made

by verified motion. The motion shall set forth sufficient facts to establish that service

pursuant to subrules (1) to (7) of this rule cannot reasonably be made and shall suggest an

alternative method of service.

History: 1996 AACS; 2015 AACS.

Editor's Note: An obvious error in R 324.1204(7) was corrected at the request of the promulgating

agency, pursuant to Section 56 of 1969 PA 306, as amended by 2000 PA 262, MCL 24.256. The rule

containing the error was published in Michigan Register, 2015 MR 5. The memorandum requesting the

correction was published in Michigan Register, 2015 MR 6.

R 324.1205 Types of hearings.

Rule 1205. (1) Upon receipt of a petition, the supervisor, after finding the petition

to be complete, reasonable, and appropriate, shall determine whether the petition shall

be heard. The supervisor shall give each hearing 1 of the following designations:

(a) A supervisor’s evidentiary hearing to consider the adoption of an order having

field-wide or statewide application or ramifications.

(b) A supervisor's evidentiary hearing to consider matters of local concern in

the administration of these rules or the orders of the supervisor or to consider other

matters as may be referred to the supervisor.

(c) A supervisor’s uncontested evidentiary hearing to consider matters of local

concern in the administration of these rules or the orders of the supervisor or to

consider a petition to which an answer was not filed as provided in R 324.1204(6).

(2) If a timely answer is not filed to a petition or if oral hearing is waived by all

interested persons present at a hearing, then the supervisor may direct that a petition be

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processed under subrule (1)(c) of this rule. In these cases, proceedings pursuant to

subrule (1)(c) of this rule may be used if it appears that all issues of material fact may

be resolved by means of written materials and that the proceeding can be efficiently

handled without oral hearing. Where there is no oral hearing, all substantive

evidence shall be presented by verified statement. The supervisor may require

supplemental verified statements.

(3) Prehearing conferences may be held at the discretion of the supervisor. A

party may request a prehearing conference in his or her petition or in a responsive

pleading. A hearing may be converted to a prehearing conference to ensure an

orderly and expeditious hearing.

(4) The parties to a proceeding may, by stipulation in writing or entered on the

record, agree upon facts, law, or procedure involved in the matter. Stipulations of fact

shall be considered as evidence in the proceeding.

(5) The supervisor may, at any time during a proceeding, designate a hearings

officer to conduct an evidentiary hearing as provided for under either subrule (1)(a) or

subrule (1)(b) of this rule.

(6) The parties to a matter within the jurisdiction of the supervisor may agree to

dispose of all or a part of a matter at issue by stipulation and consent order. The

supervisor may enter the stipulation as a consent order, place the stipulation on public

notice as is appropriate, or reject the stipulation.

.

History: 1996 AACS.

R 324.1206 Final decision or order.

Rule 1206. (1) The supervisor shall issue a final decision or order as a result of a

hearing held under R 324.1205 or as a result of the procedure pursuant to

R 324.1205(1)(c) after giving due consideration to all of the following:

(a) The record.

(b) The supervisor's experience, technical competence, and specialized knowledge.

(c) The proposal for decision, if one is issued, and exceptions to the proposal for

decision, replies to exceptions, and, if permitted by the supervisor, oral arguments and

briefs.

(d) The advice or recommendations of the representative of the supervisor when

required or appropriate.

(e) The stipulations or agreements that the contesting parties have placed on the

record at a hearing or submitted in writing to the supervisor or the hearings officer.

(f) The act and rules.

(2) The final written decision or order of the supervisor shall be furnished to the

petitioner. The petitioner shall serve copies, by first-class mail, to all persons who were

mailed a notice of the hearing, who filed an appearance at the hearing, or who otherwise

requested a copy of the final written decision.

(3) When a hearing is scheduled at the initiative of the supervisor, the supervisor

shall serve copies of the final written decision or order, by first-class mail, to all persons

who filed an answer, who filed an appearance at the hearing, or who otherwise requested

a copy.

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(4) After the hearing on a petition for an order to pool and after thorough

consideration of the evidence and testimony submitted, the supervisor shall either rule

that pooling is not necessary to prevent waste or shall enter an order pooling the

separately owned tracts and interests within the drilling unit. The pooling order shall

authorize 1 of the owners within the affected unit to drill and operate the well within the

affected unit and provide that the well shall be commenced within 90 days if drilling of

the well has not already commenced, unless otherwise specified in the pooling order. The

pooling order is null and void as to all parties and interests with respect to any well that

has not commenced within 90 days after the date of the order. The order shall set forth

the terms and conditions under which each of the owners may share in the working

interest ownership of the well drilled or to be drilled on the pooled unit and for the

sharing of any production from the well. The order shall provide for conditions under

which each mineral or working interest owner who has not voluntarily agreed to pool all

of the owner's mineral or working interest in the pooled unit may share in the working

interest share of production or be compensated for the owner's working interest within the

pooled unit according to either of the following provisions:

(a) Pay to the party authorized to drill, or who has drilled, the well that owner's

proportionate share of the actual cost of drilling, completing, equipping, and operating

the well in the pooled unit that the owner elects to participate in, or give bond for the

payment of the share of the costs that have been, or are subsequently, actually incurred,

whether the well is drilled as a producer or a dry hole.

(b) As to each well that the owner does not elect to participate in as provided in

subdivision (a) of this subrule, if the well has been, or is subsequently, completed as a

producer, authorize the operator of the well to take out of the nonparticipatory interest's

share of production from the well the party's share of the cost of drilling, completing,

equipping, and operating the well, plus an additional percentage of the costs that the

supervisor considers appropriate compensation for the risks associated with drilling a dry

hole and the mechanical and engineering risks associated with the completion and

equipping of each well.

(5) Each nonparticipating owner who has not elected to participate in the drilling of

any well by agreeing to pay the owner's working interest share of the costs shall make an

election, within 10 days of receipt by the owner of the supervisor's certified mail copy of

the order, as to which alternative in subrule (4)(a) or (b) of this rule the owner will select.

If the nonparticipating party does not notify the supervisor in writing within 10 days of

the owner's election as to any well proposed for the pooled unit, then the owner shall be

considered to have elected the alternative in subrule (4)(b) of this rule. For the type of

statutory pooling order specified in this rule, the owner of an unleased mineral interest

shall be treated as a working interest owner to the extent of 100% of the interest owned in

the pooled unit. Each nonparticipating owner shall be considered to be subject to a 1/8

royalty interest, which shall be free of any withholding for payment of any costs of

drilling, completing, equipping, or operating the well to be drilled. All operations,

including, the commencement, drilling, completing, equipping, or operation of a well,

upon a portion of a drilling unit for which pooling has been ordered shall be considered

for all purposes to be the conducting of operations upon each separately owned tract in

the drilling unit. The portion of the production allocated to a separately owned tract or

separately owned interest included in a drilling unit shall, when produced, be considered

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for all purposes to have been actually produced from the separately owned tract or tracts

by a well drilled in the drilling unit.

History: 1996 AACS; 2015 AACS.

R 324.1207 Subpoenas; discovery.

Rule 1207. (1) At any time in a proceeding, the supervisor may order a party or

witness to attend and testify orally at the hearing. Subpoenas for attendance at a hearing

shall be issued by the supervisor upon application by a party. A subpoena may also

command the person to whom it is directed to produce the books, papers, documents, or

tangible things designated in the subpoena, which shall be specified in detail.

(2) A subpoena shall state the purpose or the title of the proceeding and shall

command each person to whom it is directed to attend and comply with the subpoena at

a time and place specified in the subpoena. The supervisor, upon a motion made at or

before the time specified in the subpoena for compliance with the subpoena, may do

either or both of the following:

(a) Quash or modify a subpoena or subpoena duces tecum if it is

unreasonable or oppressive or if it requires the production of evidence that is not relevant

or material to a matter in issue.

(b) Condition the subpoena, in the case of a subpoena duces tecum, upon the

advancement, by the person in whose behalf the subpoena is issued, of the reasonable

cost of producing the books, papers, documents, or tangible things, unless otherwise

provided by law.

(3) The supervisor may issue an order to take a deposition, interrogatory,

or other discovery either upon a motion by the supervisor or for good cause shown by

a party to a proceeding. If a deposition, interrogatory, or other discovery is

permitted, it shall be taken according to the rules for conducting discovery in circuit

court civil cases under the Michigan rules of court.

History: 1996 AACS.

R 324.1208 Continuance of hearing.

Rule 1208. A hearing, as provided in these rules, may be continued at the

discretion of the supervisor or the presiding officer until all required testimony is

submitted and all pertinent data and information are received. Further notice of the

continuance of the hearing is not required, other than the announcement at the hearing of

the date, time, and place of the continued hearing or service of written notice on those

persons who filed an appearance at the first hearing.

History: 1996 AACS.

R 324.1209 Failure to give notice of hearing.

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Rule 1209. Failure to give notice of the time of a hearing to a person entitled to

the notice shall not constitute a bar to conducting of the hearing if the petitioner can

demonstrate substantial compliance with the notice requirements.

History: 1996 AACS.

R 324.1210 Administrative complaint; notice of hearing.

Rule 1210. (1) The staff of the supervisor may file an administrative complaint

with the supervisor. An administrative complaint shall set forth the nature of the

violations complained of and shall specifically cite the provisions of the act, these

rules, permit conditions, instructions, or orders of the supervisor allegedly violated.

The supervisor shall select a date for the hearing and prepare a notice of hearing.

Upon request, the person alleged to be in violation shall provide, to the supervisor, a list

of the last known names and addresses of all persons of record with the register of deeds

who own oil and gas interests within the unit. The notice of hearing and

administrative complaint shall be served by certified mail, return receipt requested, on

the person alleged to be in violation, the operator, the surety, and other interested

persons as the supervisor shall consider necessary or appropriate. The notice shall be

served not less than 21 days before the hearing date. The hearing shall be a hearing

before the supervisor.

(2) A hearing held pursuant to an administrative complaint shall be a hearing

before the supervisor pursuant to R 324.1205.

History: 1996 AACS.

R 324.1211 Emergency orders and hearings.

Rule 1211. (1) When an emergency order is issued by the supervisor, the person

subject to the order shall be served with the order, either personally or by certified, return

receipt mail.

(2) An emergency hearing may be scheduled by the supervisor to consider matters

of urgency or as a result of the issuance of an emergency order. Notice of hearing shall

be served by certified mail, return receipt requested, not less than 10 days before the

hearing date, on other interested persons as the supervisor shall consider necessary and

appropriate.

History: 1996 AACS.

R 324.1212 Appeals to the director of the department of environmental

quality.

Rule 1212. (1) An owner or producer may file an appeal to the director of the

department of environmental quality pursuant to section 61503 of the act. The appeal

shall be in writing and filed with the director of the department of environmental quality.

The appeal shall set forth the basis for the filing of an appeal.

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(2) An appeal from an order of the supervisor that is issued after a hearing shall

be an appeal on the record. The appealing party shall order and file a transcript of

the proceeding before the supervisor. The supervisor shall prepare and file the record

of the proceeding.

(3) Upon receipt of an appeal from an order of the supervisor, the director of

the department of environmental quality shall set a schedule for the filing of briefs on

appeal. Oral argument, if requested, shall be scheduled after the filing of briefs. A

prehearing conference may be scheduled for the purpose of establishing a schedule for

the appeal.

(4) The producer or owner appealing an order, action, or inaction of the supervisor

shall file a petition of appeal to the director of the department of environmental quality.

The petition and notice requirements are the same requirements for petitions for a

hearing before the supervisor pursuant to R 324.1201 through R 324.1204.

(5) An appeal to the director of the department of environmental quality shall be

filed within 28 days of the order, action, inaction, or procedure as provided in section

61503(2) of the act.

History: 1996 AACS.

PART 13. ENFORCEMENT

R 324.1301 Authority of supervisor.

Rule 1301.The supervisor, under section 61506 of the act, may do any of the

following:

(a) Enforce all rules, issue orders, determinations, and instructions necessary

to enforce the rules and regulations, and do whatever may be necessary with respect

to the subject matter stated in these rules to carry out the purposes of these rules and

the act, whether or not the orders, determinations, or instructions are indicated,

specified, or enumerated in the act or rules.

(b) Order the suspension of any or all components of the oil and gas operations

when a violation exists. The suspension time shall continue until a correction is made

and a violation no longer exists under section 61516 of the act. The supervisor may

also prohibit the purchaser from taking oil, gas, or brine from the lease during the

required suspension time.

(c) Order a well plugged for a continuing violation of the act or these rules.

History: 1996 AACS; 2002 AACS.

PART 14. HIGH VOLUME HYDRAULIC FRACTURING

R 324.1401 Definitions.

Rule 1401. As used in these rules:

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(a) “Adverse resource impact,” “assessment tool,” “cold-transitional river system,”

“cool river system,” “site-specific review,” “warm river system,” “withdrawal,” “zone A

withdrawal,” “zone B withdrawal,” “zone C withdrawal,” and “zone D withdrawal,” have

the same meanings as in section 32701 of the act.

(b) “Available water source” means a reasonably identifiable fresh water well used

for human consumption for which the water well owner has given written consent for

sampling and testing and to having the sample data made a part of the department’s

public records.

(c) “Chemical Abstracts Service (CAS) Number” means the unique identification

number assigned to a chemical by the division of the American Chemical Society that is

the globally recognized authority for information on chemical substances.

(d) “Chemical additive” means a product composed of 1 or more chemical

constituents that is intentionally added to a primary carrier fluid to enhance the

characteristics of hydraulic fracturing fluid.

(e) “Chemical constituent” means a discrete chemical with its own specific name or

identity, such as a CAS number, that is contained in a chemical additive.

(f) “Chemical family” means a group of elements or compounds that have similar

physical and chemical characteristics and have a common general name.

(g) “Flowback fluid” means hydraulic fracturing fluid and brine recovered from a

well after completion of a hydraulic fracturing operation and before the conclusion of test

production under R 324.606.

(h) “High volume hydraulic fracturing" means a hydraulic fracturing well

completion operation that is intended to use a total volume of more than 100,000 gallons

of primary carrier fluid. If the primary carrier fluid consists of a base fluid with 2 or more

components, the volume shall be calculated by adding the volumes of the components. If

1 or more of the components is a gas at prevailing temperatures and pressures, the

volume of that component or components shall be calculated in the liquid phase.

(i) “Hydraulic fracturing” means a well completion operation that involves pumping

fluid and proppants into the target formation under pressure to create or propagate

artificial fractures, or enhance natural fractures, for the purpose of improving the

deliverability and production of hydrocarbons. Hydraulic fracturing does not include

other stimulation completion techniques such as treatments that do not use proppants.

(j) “Hydraulic fracturing fluid” means fluid at a well site that is prepared for

injection into a well to achieve a hydraulic fracturing operation, including primary carrier

fluid and additives.

(k) "Large volume water withdrawal" means a water withdrawal intended to produce

a cumulative total of over 100,000 gallons of water per day when averaged over a

consecutive 30-day period.

(l) “Primary carrier fluid” means the base fluid, such as water, into which chemical

additives are mixed to form the hydraulic fracturing fluid.

(m) “Proppant” means sand or any natural or man-made material that is used in a

hydraulic fracturing completion to prop open the artificially created or enhanced fractures

once the treatment is completed.

(n) “Trade secret” has the same meaning as defined in the uniform trade secrets act,

1998 PA 448, MCL 445.1901 to 445.1910.

History: 2015 AACS.

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R 324.1402 Permitting of high volume hydraulic fracturing for oil and gas

wells.

Rule 1402. (1) In addition to the requirements in R 324.201, a person applying for a

permit to drill and operate shall provide a statement as to whether high volume hydraulic

fracturing is expected to be utilized in completion of the proposed well.

(2) A permittee of a well shall not begin a large volume water withdrawal for a high

volume hydraulic fracturing operation without approval of the supervisor or authorized

representative of the supervisor. A permit applicant or permittee shall make a written

request for approval to conduct a large volume water withdrawal and shall file the request

with the supervisor at least 30 days before the permit applicant or permittee intends to

begin the withdrawal. The permittee may file the request with the application for a permit

to drill and operate a well or may provide the request separately to the supervisor or

authorized representative of the supervisor. The request shall include all of the following

information:

(a) A water withdrawal evaluation utilizing the assessment tool accessed at

http://www.miwwat.org/ or by a means approved by the supervisor under the conditions

described in subrule (6) of this rule.

(b) Information on the proposed withdrawal including all of the following:

(i) Proposed total volume of water needed for hydraulic fracturing well completion

operations.

(ii) Proposed number of water withdrawal wells.

(iii) Aquifer type (drift or bedrock).

(iv) Proposed depth of water withdrawal wells, in feet below ground surface.

(v) Proposed pumping rate and pumping schedule of each water withdrawal well.

(vi) Available well logs of all recorded fresh water wells and reasonably identifiable

fresh water wells within 1,320 feet of water withdrawal location.

(c) A supplemental plat of the well site showing all of the following:

(i) Proposed location of water withdrawal wells (latitude/longitude).

(ii) Location of all recorded fresh water wells and reasonably identifiable fresh

water wells within 1,320 feet of water withdrawal location or locations.

(iii) Proposed fresh water pit impoundment, containment, location, and dimensions.

(d) A contingency plan, if deemed necessary, to prevent or mitigate potential loss of

water availability in the fresh water wells identified under subdivision (b)(vi) of this

subrule.

(3) An application for change of well status for which a large volume water

withdrawal is expected to be utilized for high volume hydraulic fracturing shall include

the information required under subrule (1) of this rule.

(4) If the assessment tool designates the proposed withdrawal as a zone A

withdrawal, or a zone B withdrawal in a cool river system or a warm river system, the

supervisor shall approve the withdrawal.

(5) If the assessment tool designates the proposed withdrawal as a zone B

withdrawal in a cold-transitional river system, or a zone C or zone D withdrawal, the

permit applicant or permittee may submit to the supervisor a request for a site-specific

review. All of the following apply:

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(i) If the site-specific review determines that the proposed withdrawal is a zone A or

a zone B withdrawal, the supervisor shall approve the withdrawal.

(ii) If the site-specific review determines that the proposed withdrawal is a zone C

withdrawal, the supervisor shall not approve the withdrawal unless the permittee does

either of the following:

(A) Self certifies that he or she is implementing applicable environmentally sound

and economically feasible water conservation measures under MCL 324.32708a.

(B) Obtains a water withdrawal permit under MCL 324.32723.

(iii) If the site-specific review determines that the proposed withdrawal is a zone D

withdrawal or likely to cause an adverse resource impact, the supervisor shall not approve

the withdrawal unless the permittee has obtained a water withdrawal permit under MCL

324.32723.

(6) If the assessment tool is discontinued or replaced as a requirement for designated

water withdrawal evaluations under the act, a permittee shall perform a water withdrawal

evaluation utilizing an alternative method and criteria approved by the supervisor to

satisfy the requirements of subrules (2)(a), (4), and (5) of this rule.

History: 2015 AACS.

R 324.1403 Water supply monitoring and storage.

Rule 1403. (1) If 1 or more fresh water wells are present within 1,320 feet of a

proposed large volume water withdrawal, the permittee shall install a monitor well

between the water withdrawal well or wells and the nearest fresh water well before

beginning the water withdrawal. If more than 1 aquifer is delineated at the site, the

monitor well shall be completed in the same aquifer as the water withdrawal well. The

permittee shall measure and record the water level in the monitor well daily during water

withdrawal and weekly thereafter until the water level stabilizes. The permittee shall

report all water level data weekly to the supervisor or authorized representative of the

supervisor.

(2) Fresh water storage pits and impoundments shall be constructed as approved by

the supervisor and shall be in compliance with all of the following minimum

requirements:

(a) Berms shall be designed and constructed to prevent washouts or failures.

(b) Pits shall be constructed with rounded corners and side slopes of not less than 20

degrees measured from the vertical.

(c) Pits shall adhere to applicable soil erosion and sedimentation control measures

and may require fencing.

(3) Fresh water storage pits, impoundments, or tanks shall not remain on-site more

than 6 months after final completion of the well or wells for which the storage was

designed unless approved by the supervisor or authorized representative of the

supervisor.

History: 2015 AACS.

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R 324.1404

fracturing.

Ground water baseline sampling for high volume hydraulic

Rule 1404. (1) A permit applicant or permittee of an oil and gas well for which high

volume hydraulic fracturing is proposed shall collect baseline samples from all available

water sources, up to a maximum of 10, within a 1/4- mile radius of the well location. All

of the following apply:

(a) If more than 10 available water sources are present within a 1/4- mile radius of

the proposed well location, the permit applicant or permittee shall select 10 sampling

locations based on the following criteria:

(i) Available water sources closest to the proposed well location are preferred.

(ii) To the extent groundwater flow direction is known or reasonably can be inferred,

sample locations from both down gradient and up-gradient are preferred over cross-

gradient locations. Where groundwater flow direction is uncertain, sample locations

should be chosen in a radial pattern from a well.

(iii) Where multiple defined aquifers are present, sampling the deepest and

shallowest identified aquifers is preferred.

(b) Initial sampling shall be conducted not fewer than 7 days nor more than 6

months before initiation of drilling operations for a new well or in the case of a re-

completion of a well, high volume hydraulic fracturing using new or existing

perforations. However, initial sampling shall satisfy sampling requirements for

subsequent oil and gas wells on the same or contiguous drilling sites for a period of up to

3 years.

(c) Sampling and analysis shall be conducted at the expense of the permit applicant

or permittee and shall conform to all of the following procedures:

(i) Water samples shall be collected by a qualified professional utilizing proper

sampling protocol and analyzed by a laboratory certified by the department.

(ii) Samples shall be analyzed for the following minimum parameters using

laboratory methods approved by the United States Environmental Protection Agency:

(A) Benzene.

(B) Toluene.

(C) Ethylbenzene.

(D) Xylene.

(E) Total dissolved solids.

(F) Chloride.

(G) Methane.

(iii) The location of the sampled water sources shall be surveyed with a global

positioning system device or equivalent with 3 meter or higher accuracy. The latitude and

longitude coordinates shall be provided to the supervisor.

(iv) If free gas or a dissolved methane concentration greater than 1.0 milligram per

liter is detected in a water sample, gas compositional analysis and stable isotope analysis

of the methane (carbon and hydrogen – 12C, 13C, 1H and 2H) shall be performed to

identify gas origin.

(v) The permit applicant or permittee shall notify the supervisor immediately if

benzene, toluene, ethylbenzene, or xylenes are detected in a water sample.

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(2) The permittee shall provide copies of all final laboratory analytical results to the

supervisor and the water well owner or landowner within 45 days of collecting the

samples.

History: 2015 AACS.

R 324.1405

High volume hydraulic fracturing well completion operations;

notification, monitoring, reporting, and fluid containment requirements.

Rule 1405. (1) A permittee shall notify the supervisor or authorized representative of

the supervisor a minimum of 48 hours prior to the commencement of a high volume

hydraulic fracturing completion. If the well is an H2S well as defined in R 324.1101, a

permittee shall also notify the local emergency preparedness coordinator a minimum of

48 hours before the commencement of a high volume hydraulic fracturing completion.

(2) During high volume hydraulic fracturing operations, the permittee shall monitor

and record the injection pressure at the surface and the annulus pressure between the

injection string and the next string of casing unless the annulus is cemented to surface. If

intermediate casing has been set on the well to be stimulated, the pressure in the annulus

between the intermediate casing and the production casing shall also be monitored and

recorded. The permittee shall do both of the following:

(a) Submit a continuous record of the annulus pressure during the well stimulation

within 60 days of completing hydraulic fracturing operations.

(b) If during the hydraulic fracturing operation the injection pressures or annulus

pressures, or both, indicate a lack of well integrity, immediately cease hydraulic

fracturing operations and notify the supervisor or authorized representative of the

supervisor. The permittee of the well shall submit to the supervisor or authorized

representative of the supervisor the plan of action the permittee intends to take before

continuing hydraulic fracturing operations on the well. The permittee of the well shall not

continue hydraulic fracturing in the well until the supervisor or authorized representative

of the supervisor approves implementation of the plan of action. The supervisor or

authorized representative of the supervisor may require suitable mechanical integrity tests

of the casing or the casing tubing annulus or cement bond logs, or both. The permittee

shall submit a report containing all details pertaining to the incident, including corrective

actions taken, within 60 days of completing hydraulic fracturing operations.

(3) Flowback fluid shall be contained in tanks or in receptacles approved by the

supervisor or authorized representative of the supervisor. Flowback fluid shall not be

used for ice or dust control or road stabilization purposes. A permittee shall ensure that

handling and disposal of flowback fluid does not cause waste as defined in section

61501(q) of the act.

(4) A permittee shall submit a copy of the following service company records within

60 days after completing high volume hydraulic fracturing operations:

(a) The actual total well stimulation treatment volume pumped.

(b) Detail as to each fluid stage pumped, including actual volume by fluid stage,

proppant rate or concentration, actual chemical additive name, type, concentration or rate,

and amounts.

(c) The actual breakdown pressure as measured at the surface or producing interval.

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(d) The actual surface pressure and rate at the end of each fluid stage and the actual

flush volume, rate and final pump pressure.

(e) The instantaneous shut-in pressure and the actual 15- minute and 30-minute shut-

in pressures when these pressure measurements are available.

(5) A permittee shall report the following for a high volume hydraulic fracturing

operation within 60 days of completing hydraulic fracturing operations:

(a) The total volume of water utilized.

(b) The volume and source of the water withdrawn and the dates during which the

water was withdrawn.

History: 2015 AACS.

R 324.1406 Disclosure of hydraulic fracturing fluid chemical additives.

Rule 1406. (1) A permittee shall submit information on chemical additives used in a

high volume hydraulic fracturing operation using the internet-based FracFocus Chemical

Disclosure Registry that is maintained by the Ground Water Protection Council and the

Interstate Oil and Gas Compact Commission and is accessed at http://fracfocus.org. If the

FracFocus Chemical Disclosure Registry is no longer maintained or available, the

permittee shall submit the information on a form prescribed by the supervisor or by any

other means approved by the supervisor. A permittee shall submit the information within

30 days after completion of a high volume hydraulic fracturing operation. A contractor or

supplier performing a high volume hydraulic fracturing operation for a permittee or

providing supplies for a high volume hydraulic fracturing operation shall timely provide

to the permittee the information required for the permittee to comply with this rule. The

information shall include the following:

(a) A list of all chemical additives used during the treatment specified by general

type, such as acids, biocides, breakers, corrosion inhibitors, cross-linkers, demulsifiers,

friction reducers, gels, iron controls, oxygen scavengers, pH adjusting agents, scale

inhibitors, and surfactants.

(b) The specific trade name and supplier of each chemical additive.

(c) A list showing the specific identity of each chemical constituent intentionally

added to the primary carrier fluid and its associated CAS number, except that the specific

identities and CAS numbers of trade secret chemicals may be withheld under subrule (2)

of this rule.

(d) The maximum concentration of each chemical constituent listed expressed as a

percent by mass of the total volume of hydraulic fracturing fluids utilized.

(2) If the specific identity of a chemical constituent and its associated CAS number

or concentration are a trade secret, the permittee may withhold the specific identity of the

chemical constituent and its associated CAS number and concentration, but shall list the

chemical family associated with the chemical constituent, or provide a similar

description, and provide a statement that a claim of trade secret protection has been made

by the entity entitled to make such a claim. If an independent contractor or supplier

providing a chemical constituent to a permittee withholds any information required under

this rule under a claim of trade secret, the contractor or supplier shall provide the

information required for the permittee to timely comply with this subrule.

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(3) Nothing in this rule shall authorize any person to withhold information that is

required by state or federal law to be provided to a health care professional for the

purpose of diagnosis or treatment of a medical condition.

History: 2015 AACS.

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Courtesy of Michigan Administrative Rules