Every well and facility associated with the production, transportation, purchasing, storage, treating, or processing of oil, gas, and water except plugged wells shall be identified by a sign.
The sign shall be of durable construction and the lettering thereon shall be kept in a legible condition. The wells on each lease or property shall be numbered in nonrepetitive sequence, unless some other system of numbering was adopted by the owner prior to the adoption of this chapter.
Each sign must show the facility name or well name and number (which shall be different or distinctive for each well or facility), the name of the operator, current emergency phone number, file or facility number (if applicable), and the location by quarter-quarter, section, township, and range.
History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000; April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
In the construction of a well site, saltwater handling facility, treating plant, access road, and all associated facilities, the topsoil shall be removed, stockpiled, and stabilized or otherwise reserved for use when the area is reclaimed. "Topsoil" means the suitable plant growth material on the surface; however, in no event shall this be deemed to be more than the top twelve inches [30.48 centimeters] of soil or deeper than the depth of cultivation, whichever is greater. Soil stabilization materials, liners, fabrics, and other materials to be used onsite, on access roads or associated facilities, must be reported on a sundry notice (form 4) to the director within thirty days after application. The reclamation plan for such materials shall also be included.
When necessary to prevent pollution of the land surface and freshwaters, the director may require the site to be sloped and diked.
Sites shall not be located in, or hazardously near, bodies of water, nor shall they block natural drainages. Sites and associated facilities shall be designed to divert surface drainage from entering the site.
Sites or appropriate parts thereof shall be fenced if required by the director.
Within six months after the completion of a well or construction of a saltwater handling facility or treating plant, the portion of the site not used for operations shall be reclaimed, unless waived by the director. Operators shall file a sundry notice (form 4) detailing the work that was performed and a current site diagram, which identifies the stockpiled topsoil location and its volume. Sites shall be stabilized to prevent erosion.
History: Amended effective March 1, 1982; January 1, 1983; May 1, 1992; July 1, 2002; January 1, 2008; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
During the drilling of any well, all oil, gas, and water strata must be sealed or separated where necessary in order to prevent their contents from passing into other strata.
All freshwaters and waters of present or probable value for domestic, commercial, or stock purposes must be confined to their respective strata and must be adequately protected by methods approved by the director. Special precautions must be taken in drilling and plugging wells to guard against any loss of artesian water from the strata in which it occurs and the contamination of artesian water by objectionable water, oil, or gas.
All water must be shut off and excluded from the various oil-bearing and gas-bearing strata which are penetrated. Water shutoffs ordinarily must be made by cementing casing or landing casing with or without the use of mud-laden fluid.
History: Amended effective May 1, 1992; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
All wells drilled shall be constructed with strings of casing which must be properly cemented at sufficient depths to adequately protect and isolate all formations containing water, oil, or gas or any combination of these; protect the pipe through salt sections encountered; and isolate the uppermost sand of the Dakota group.
Drilling of the surface hole must be with freshwater-based drilling mud or other method approved by the director which will protect all freshwater-bearing strata. This includes water used during the cementing of surface casing for displacement. The surface casing must consist of new or reconditioned pipe that has been previously tested to one thousand pounds per square inch [6900 kilopascals]. The surface casing must be set and cemented at a point not less than fifty feet [15.24 meters] below the base of the Fox Hills formation. Sufficient cement must be used on surface casing to fill the annular space behind the casing to the bottom of the cellar, if any, or to the surface of the ground. If the annulus space is not adequately filled with cement, the director must be notified immediately. The operator shall diligently perform remedial work after obtaining approval from the director. All strings of surface casing must stand cemented under pressure for at least twelve hours before drilling the plug. The term "under pressure" as used herein must be complied with if one float valve is used or if pressure is otherwise held. Cementing must be by the pump and plug method while the drilling rig is on the well or other methods approved by the director. An appropriate accurate gauge must be maintained on the surface casing of any well, not properly plugged and abandoned, to detect any buildup of pressure caused by the migration of fluids. Surface casing pressure must be monitored and maintained to keep the hydrostatic pressure at the surface casing shoe below the pressure the formation integrity test was performed at.
Surface casing strings must be allowed to stand under pressure until the tail cement has reached a compressive strength of at least five hundred pounds per square inch [3450 kilopascals]. All filler cements utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within twenty-four hours and at least three hundred fifty pounds per square inch [2415 kilopascals] within seventy-two hours. All compressive strengths on surface casing cement must be calculated at a temperature of eighty degrees Fahrenheit [26.67 degrees Celsius].
Production or intermediate casing strings must consist of new or reconditioned pipe that has been previously tested to two thousand pounds per square inch [13800 kilopascals]. Such strings must be allowed to stand under pressure until the tail cement has reached a compressive strength of at least five hundred pounds per square inch [3450 kilopascals]. All filler cements utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within twenty-four hours and at least five hundred pounds per square inch [3450 kilopascals] within seventy-two hours, although in any horizontal well performing a single stage cement job from a measured depth of greater than thirteen thousand feet [3962.4 meters], the filler cement utilized must reach a compressive strength of at least two hundred fifty pounds per square inch [1725 kilopascals] within forty-eight hours and at least five hundred pounds per square inch [3450 kilopascals] within ninety-six hours. All compressive strengths on production or intermediate casing cement must be calculated at a temperature found in the Mowry formation using a gradient of 1.2 degrees Fahrenheit per one hundred feet [30.48 meters] of depth plus eighty degrees Fahrenheit [26.67 degrees Celsius]. At a formation temperature at or in excess of two hundred thirty degrees Fahrenheit [110 degrees Celsius], cement blends must include additives to address compressive strength regression.
Each surface casing string must be tested by application of pump pressure of at least one thousand pounds per square inch [6900 kilopascals] and each other casing string shall be tested by application of pump pressure of at least one thousand five hundred pounds per square inch [10350 kilopascals] immediately after cementing, while the cement is in a liquid state, or the casing string must be pressure tested after all cement has reached five hundred pounds per square inch [3450 kilopascals] compressive strength. If, at the end of thirty minutes, this pressure has dropped more than ten percent, the casing must be repaired after receiving approval from the director. Thereafter, the casing again must be tested in the same manner. Further work may not proceed until a satisfactory test has been obtained. The casing in a horizontal well may be tested by use of a mechanical tool set near the casing shoe after the horizontal section has been drilled.
All flowing wells must be equipped with tubing. A tubing packer must also be utilized unless a waiver from the director is obtained after demonstrating the casing will not be subjected to excessive pressure or corrosion. The packer must be set as near the producing interval as practicable, but in all cases must be above the perforations.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1, 1997; September 1, 2000; July 1, 2002; May 1, 2004; January 1, 2006; April 1, 2010; April 1, 2012; April 1, 2020; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
In any well that appears to have defective casing or cementing, the operator shall conduct a mechanical integrity test, unless deemed unnecessary by the director, and report the test and defect to the director on a sundry notice (form 4).
Prior to attempting remedial work on any casing, the operator must obtain approval from the director and proceed with diligence to conduct tests, as approved or required by the director, to properly evaluate the condition of the well bore and correct the defect. The director is authorized to require subsequent pressure tests to verify casing integrity if its competence is questionable. The director may allow the wellbore condition to remain if correlative rights can be protected without endangering potable waters. The well shall be properly plugged if requested by the director.
Any well with open perforations above a packer shall be considered to have defective casing.
History: Amended effective January 1, 1983; May 1, 1992; September 1, 2000; July 1, 2002; May 1, 2004; January 1, 2008; April 1, 2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
1. Prior to performing any hydraulic fracture stimulation, including refracs, through a frac string
run inside the casing string:
- a. Remedial work must be performed on all casing strings deemed defective pursuant to
section 43-02-03-22 prior to performance at the discretion of the director. - b. The frac string must be either stung into a liner with the hanger/packer located in
cemented casing or run with a packer set at a minimum depth of one hundred feet [30.48
meters] below the top of cement or a minimum depth of one hundred feet [30.48 meters]
below the top of the Inyan Kara formation, whichever is deeper. - c. The casing-frac string annulus must be pressurized and monitored during frac
operations. If there is a suspected frac string or casing failure, the operator of the well
shall verbally notify the director as soon as practicable. - d. An adequately sized, function tested pressure relief valve must be utilized on the treating
lines from the pumps to the wellhead, with suitable check valves to limit the volume of
flowback fluid should the relief valve open. The relief valve must be set to limit line
pressure to no more than eighty-five percent of the internal yield pressure of the frac
string. - e. An adequately sized, function tested pressure relief valve and an adequately sized
diversion line must be utilized to divert flow from the casing to a pit or containment vessel
in case of frac string failure. The relief valve must be set to limit annular pressure to no
more than eighty-five percent of the lowest internal yield pressure of the casing string or
no greater than the pressure test on the intermediate casing, less one hundred pounds
per square inch gauge, whichever is less. - f. The surface casing must be fully open and connected to a diversion line rigged to a pit or
containment vessel. - g. An adequately sized, function tested remote operated frac valve must be utilized at a
location on the christmas tree that provides isolation of the well bore from the treating line
and must be remotely operated from the edge of the location or other safe distance. - h. Notify the director within twenty-four hours after the commencement of hydraulic fracture
stimulation operations, in an electronic format approved by the director, identifying the
subject well and verifying a frac string was run in the well. - i. Within sixty days after the hydraulic fracture stimulation is performed, the owner,
operator, or service company shall post on the fracfocus chemical disclosure registry all
elements made viewable by the fracfocus website.
2. Prior to performing any hydraulic fracture stimulation, including refracs, through a casing
string:
- a. Remedial work must be performed on all casing strings deemed defective pursuant to
section 43-02-03-22 prior to performance at the discretion of the director. - b. The maximum treating pressure may not be greater than eighty-five percent of the
American petroleum institute rating of the affected casing string. - c. Casing evaluation tools to verify adequate wall thickness of any affected casing string
must be run from the wellhead to a depth as close as practicable to one hundred feet
[30.48 meters] above the completion formation and a visual inspection with photographs
shall be made of the top joint of the casing and the wellhead flange. The visual inspection
and photograph requirement may be waived by the director for good cause.
If the casing evaluation tool or visual inspection indicates wall thickness is below the
American petroleum institute minimum or a lighter weight of casing than the well design
called for, calculations must be made to determine the reduced pressure rating. If the
reduced pressure rating is less than the anticipated treating pressure, a frac string must
be run inside the casing. - d. Cement evaluation tools to verify adequate cementing of each casing string shall be run
from the wellhead to a depth as close as practicable to one hundred feet [30.48 meters]
above the completion formation.
(1) If the cement evaluation tool indicates defective casing or cementing, a frac string
must be run inside the casing.
(2) If the cement evaluation tool indicates the casing string cemented in the well fails to
satisfy section 43-02-03-21, a frac string must be run inside the casing.
- e. Each affected casing string and the wellhead must be pressure tested for at least thirty
minutes with less than five percent loss to a pressure equal to or in excess of the
maximum frac design pressure. - f. If the pressure rating of the wellhead does not exceed the maximum frac design
pressure, a wellhead and blowout preventer protection system must be utilized during the
frac. - g. An adequately sized, function tested pressure relief valve must be utilized on the treating
lines from the pumps to the wellhead, with suitable check valves to limit the volume of
flowback fluid should be the relief valve open. The relief valve must be set to limit line
pressure to no greater than the test pressure of the casing, less one hundred pounds per
square inch [689.48 kilopascals]. - h. The surface casing value must be fully open and connected to a diversion line rigged to a
pit or containment vessel. - i. An adequately sized, function tested remote operated frac valve must be utilized
between the treating line and the wellhead. - j. If there is a suspected casing failure, the operator of the well shall verbally notify the
director as soon as practicable. - k. Notify the director within twenty-four hours after the commencement of hydraulic fracture
stimulation operations, in an electronic format approved by the director, identifying the
subject well and verifying all logs and pressure tests have been performed as required. - l. Within sixty days after the hydraulic fracture stimulation is performed, the owner,
operator, or service company shall post on the fracfocus chemical disclosure registry all
elements made viewable by the fracfocus website.
3. If during the stimulation, the pressure in the casing-surface casing annulus exceeds three
hundred fifty pounds per square inch [2413 kilopascals] gauge, the owner or operator shall
verbally notify the director as soon as practicable but no later than twenty-four hours following
the incident.
History: Effective April 1, 2012; amended effective April 1, 2014; April 1, 2020; April 1, 2022; April 1,
2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
During drilling operations all oil wells must be cleaned into a pit or tank, not less than forty feet [12.19 meters] from the derrick floor and one hundred fifty feet [45.72 meters] from any fire hazard.
All flowing oil wells must be produced through an approved oil and gas separator or emulsion treater of ample capacity and in good working order.
No boiler, electric generator, flare, or treater may be placed nearer than one hundred fifty feet [45.72 meters] to any producing well or oil tank that is not an oil processing vessel as defined in American Society of Mechanical Engineers (ASME) section VIII.
Placement as close as one hundred twenty-five feet [38.10 meters] may be allowed if a spark or flame arrestor is utilized on the equipment. Placement of an oil processing vessel as defined in ASME section VIII as close as fifty feet [15.24 meters] may be allowed if approved by the director.
The required distances above must be measured horizontally from closest vessel edge to closest edge of the boiler, generator, flare, or treater or closest vessel edge to flame arrestor or burner air inlet edge.
Any rubbish or debris that might constitute a fire hazard must be removed to a distance of at least one hundred fifty feet [45.72 meters] from the vicinity of wells and tanks. All waste must be burned or disposed of in such manner as to avoid creating a fire hazard. All vegetation must be removed to a safe distance from any production or injection equipment to eliminate a fire hazard.
The director may require remote operated or automatic shutdown equipment to be installed on, or shut in for no more than forty days, any well that is likely to cause a serious threat of pollution or injury to the public health or safety.
Surface casing may not be plumbed into the production flow line to relieve pressure without approval from the director.
No well shall be drilled nor production or injection equipment installed nor saltwater handling facility or treating plant constructed less than five hundred feet [152.40 meters] from an occupied dwelling unless agreed to in writing by the owner of the dwelling or authorized by order of the commission.
Subsurface pressure must be controlled during all drilling, completion, and well-servicing operations with appropriate fluid weight and pressure control equipment. The operator conducting any well hydraulic fracture stimulation shall give prior written notice, up to thirty-one days and not less than twenty-one days, to any operator of a well completed in the same or adjacent pool, if publicly available information indicates or if the operator is made aware, if the completion intervals are within two thousand six hundred and forty feet [804.67 meters] of one another.
Notice must include twenty-four-hour emergency contact information, planned start and end dates, and contact information for scheduling updates.
History: Amended effective January 1, 1983; May 1, 1990; September 1, 2000; January 1, 2006; January 1, 2008; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2020; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
Wellhead and lease equipment with a working pressure at least equivalent to the calculated or known pressure to which the equipment may be subjected shall be installed and maintained. Equipment on producing wells shall be installed to facilitate gas-oil ratio tests, and static bottom hole or other pressure tests. Valves shall be installed and maintained in good working order to permit pressure readings to be obtained on both casing and tubing.
All newly constructed underground gas gathering pipelines must be devoid of leaks and constructed of materials resistant to external corrosion and to the effects of transported fluids. All such pipelines installed in a trench must be installed in a manner that minimizes interference with agriculture, road and utility construction, the introduction of secondary stresses, the possibility of damage to the pipe, and tracer wire shall be buried with any nonconductive pipes installed. When a trench for an underground gas gathering pipeline is backfilled, it must be backfilled in a manner that provides firm support under the pipe and prevents damage to the pipe and pipe coating from equipment or from the backfill material.
1. The operator of any underground gas gathering pipeline placed into service on August 1, 2011, to June 30, 2013, shall file with the director, by January 1, 2015, a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of the pipeline centerline. The operator of any underground gas gathering pipeline placed into service after June 30, 2013, shall file with the director, within one hundred eighty days of placing into service, a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of all compressor sites, buried drip tanks, and the pipeline centerline. An affidavit of completion shall accompany each layer containing the following information:
- a. A statement that the pipeline was constructed and installed in compliance with section 43-02-03-29.
- b. The outside diameter, minimum wall thickness, composition, internal yield pressure, and maximum temperature rating of the pipeline, or any other specifications deemed necessary by the director.
- c. The anticipated operating pressure of the pipeline.
- d. The type of fluid that will be transported in the pipeline and direction of flow.
- e. Pressure to which the pipeline was tested prior to placing into service.
- f. The minimum pipeline depth of burial.
- g. In-service date.
- h. Leak detection and monitoring methods that will be utilized after in-service date.
- i. Pipeline name.
- j. Accuracy of the geographical information system layer.
2. When an underground gas gathering pipeline or any part of such pipeline is abandoned, the operator shall leave such pipeline in a safe condition by conducting the following:
- a. Disconnect and physically isolate the pipeline from any operating facility or other pipeline.
- b. Cut off the pipeline or the part of the pipeline to be abandoned below surface at pipeline level.
- c. Purge the pipeline with fresh water, air, or inert gas in a manner that effectively removes all fluid.
- d. Remove cathodic protection from the pipeline.
- e. Permanently plug or cap all open ends by mechanical means or welded means.
3. Within one hundred eighty days of completing the abandonment of an underground gas gathering pipeline the operator of the pipeline shall file with the director a geographical information system layer utilization North American datum 83 geographic coordinate system (GCS) and in an environmental systems research institute (Esri) shape file format showing the location of the pipeline centerline and an affidavit of completion containing the following information:
- a. A statement that the pipeline was abandoned in compliance with section 43-02-03-29.
- b. The type of fluid used to purge the pipeline.
4. Aboveground pipeline markers must be placed and maintained over each buried underground gas gathering pipeline or portion thereof at the discretion of the director when necessary to protect public health and safety. The markers must contain at least the following on a background of sharply contrasting color: the word "Warning", "Caution", or "Danger" followed by the fluid transported pipeline, the name of the operator, and current emergency phone number.
The requirement to submit a geographical information system layer is not to be construed to be required on buried piping utilized to connect flares, tanks, treaters, or other equipment located entirely within the boundary of a well site or production facility.
History: Amended effective January 1, 1983; January 1, 2006; April 1, 2014; October 1, 2016; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
All persons controlling or operating any well, pipeline and associated aboveground equipment, receiving tank, storage tank, facility, treating plant, or any other receptacle or production facility associated with oil, gas, or water production, injection, processing, or well servicing shall verbally notify the director immediately and follow up utilizing the online initial notification report within twenty-four hours after discovery of any fire, leak, spill, blowout, or release of fluid.
The initial report must include the name of the reporting party, including telephone number and address, date and time of the incident, location of the incident, type and cause of the incident, estimated volume of release, containment status, waterways involved, immediate potential threat, and action taken. If any such incident occurs or travels offsite of a facility, the persons, as named above, responsible for proper notification shall within a reasonable time also notify the surface owners upon whose land the incident occurred or traveled.
Notification requirements prescribed by this section do not apply to any leak or spill involving only freshwater or to any leak, spill, or release of crude oil, produced water, or natural gas liquid that is less than one barrel total volume and remains onsite of a site where any well thereon was spud before September 2, 2000, or on a facility that was constructed before September 2, 2000, and do not apply to any leak or spill or release of crude oil, produced water, or natural gas liquid that is less than ten barrels total volume cumulative over a fifteen-day time period, and remains onsite of a site where all wells thereon were spud after September 1, 2000, or on a facility that was constructed after September 1, 2000.
The initial notification must be followed by a written report within ten days after cleanup of the incident, unless deemed unnecessary by the director. Such report must include the following information: the operator and description of the facility, the legal description of the location of the incident, date of occurrence, date of cleanup, amount and type of each fluid involved, amount of each fluid recovered, steps taken to remedy the situation, root cause of the incident unless deemed unnecessary by the director, and action taken to prevent reoccurrence, and if applicable, any additional information pursuant to subdivision e of subsection 1 of North Dakota Century Code section 37-17.1-07.1. The name, title, and telephone number of the company representative must be included on such report.
The persons, as named above, responsible for proper notification shall within a reasonable time also provide a copy of the written report to the surface owners upon whose land the incident occurred or traveled.
The commission, however, may impose more stringent spill reporting requirements if warranted by proximity to sensitive areas, past spill performance, or careless operating practices as determined by the director.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; July 1, 1996; January 1, 2008; April 1, 2010; April 1, 2014; October 1, 2016; April 1, 2018; April 1, 2020; April 1, 2022.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
43-02-03-30
All persons controlling or operating any well, pipeline and associated aboveground equipment, receiving tank, storage tank, facility, treating plant, or any other receptacle or production facility associated with oil, gas, or water production, injection, processing, or well servicing shall verbally notify the director immediately and follow up utilizing the online initial notification report within twenty-four hours after discovery of any fire, leak, spill, blowout, or release of fluid.
The initial report must include the name of the reporting party, including telephone number and address, date and time of the incident, location of the incident, type and cause of the incident, estimated volume of release, containment status, waterways involved, immediate potential threat, and action taken. If any such incident occurs or travels offsite of a facility, the persons, as named above, responsible for proper notification shall within a reasonable time also at no time shall any spill or leak be allowed to flow over, pool, or rest on the surface of the land or infiltrate the soil.
Discharged fluids must be properly removed and may not be allowed to remain standing within or outside of diked areas, although the remediation of such fluids may be allowed onsite if approved by the director. Operators and responsible parties must respond with appropriate resources to contain and clean up spills.
A sundry notice (form 4) must be submitted within ten days after cleanup of any spill or leak in which fluids are not properly removed or appropriate resources are not utilized to contain and clean up the spill unless deemed unnecessary by the director. The notice must include the date of the occurrence, date of cleanup, amount and type of each fluid involved, identification of the site affected, root cause of the incident, and explanation of how the volume was determined.
History: Effective April 1, 2012; amended effective October 1, 2016; April 1, 2018.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
43-02-03-30.1
Pending arrangements for disposition for some useful purpose, all vented casinghead gas shall be burned. Each flare shall be equipped with an automatic ignitor or a continuous burning pilot, unless waived by the director for good reason. The estimated volume of gas used and flared shall be reported to the director on a gas production report (form 5b) on or before the fifth day of the second month succeeding that in which gas is produced.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; September 1, 2000.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
Storage of oil in underground or partially buried tanks or containers is prohibited. Surface oil tanks and production equipment must be devoid of leaks and constructed of materials resistant to the effects of produced fluids or chemicals that may be contained therein. Unused tanks and production equipment must be removed from the site or placed into service, within a reasonable time period, not to exceed one year.
Dikes must be erected around oil tanks, flowthrough process vessels, and recycle pumps at any new production facility prior to completing any well. Dikes must be erected and maintained around oil tanks at all facilities unless a waiver is granted by the director. Dikes as well as the base material under the dikes and within the diked area must be constructed of sufficiently impermeable material to provide emergency containment. Dikes around oil tanks must be of sufficient dimension to contain the total capacity of the largest tank plus one day's fluid production. Dikes around flowthrough process vessels must be of sufficient dimension to contain the total capacity of the vessel. The required capacity of the dike may be lowered by the director if the necessity therefor can be demonstrated to the director's satisfaction.
Within one hundred eighty days from the date the operator is notified by the commission, a perimeter berm, at least six inches [15.24 centimeters] in height, must be constructed and maintained. The berm must be constructed of sufficiently impermeable material to provide emergency containment and to divert surface drainage away from the site around all storage facilities and production sites that include storage tanks, have a daily throughput of more than one hundred barrels of fluid per day, and include production equipment or load lines that are not contained within secondary containment dikes. The director may consider an extension of time to implement these requirements if conditions prevent timely construction, or a modification of these requirements if other factors are present that provide sufficient protection from environmental impacts. Prior to removing any perimeter berm, the operator or owner shall obtain approval by the director.
Numbered weather-resistant security seals shall be properly utilized on all oil access valves and access points to secure the tank or battery of tanks.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1992; September 1, 2000; July 1, 2002; May 1, 2004; April 1, 2010; April 1, 2012; October 1, 2016; April 1, 2018; April 1, 2020.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
1. The removal of production equipment or the failure to produce oil or gas for one year
constitutes abandonment of the well. The removal of production equipment or the failure to
produce water from a source well for one year constitutes abandonment of the well. The
removal of injection equipment or the failure to use an injection well for one year constitutes
abandonment of the well. The removal of monitoring equipment from or the failure to use a
subsurface observation well for one year constitutes abandonment of the well. The failure to
plug a stratigraphic test hole within one year of reaching total depth constitutes abandonment
of the well. The removal of treating plant equipment or the failure to use a treating plant for
one year constitutes abandonment of the treating plant. The removal of saltwater handling
facility equipment or the failure to use a saltwater handling facility for one year constitutes
abandonment of the saltwater handling facility. An abandoned well must be plugged and its
site must be reclaimed, an abandoned treating plant must be removed and its site must be
reclaimed, and an abandoned saltwater handling facility must be removed and its site must be
reclaimed, pursuant to sections 43-02-03-34 and 43-02-03-34.1. A well not producing oil or
natural gas in paying quantities for one year may be placed in abandoned-well status pursuant
to subsection 1 of North Dakota Century Code section 38-08-04. If an injection well is inactive
for extended periods of time, the commission may, after notice and hearing, require the
injection well to be plugged and abandoned. If an underground gathering pipeline is inactive
for seven years, the commission may, after notice and hearing, require the pipeline to be
properly abandoned pursuant to sections 43-02-03-29 and 43-02-03-29.1.
2. The director may waive for one year the requirement to plug and reclaim an abandoned well
by giving the well temporarily abandoned status for good cause. If a well is given temporarily
abandoned status, the well's perforations must be isolated, the integrity of its casing must be
proven, and its casing must be sealed at the surface, all in a manner approved by the director.
The director may extend a well's temporarily abandoned status and each extension may be
approved for up to one year. A fee of one hundred dollars shall be submitted for each
application to extend the temporary abandonment status of any well. A surface owner may
request a hearing to review a well temporarily abandoned for at least seven years pursuant to
subsection 1 of North Dakota Century Code section 38-08-04. Temporarily abandoned status
for oil and gas wells may be given only to wells that are to be used for purposes related to the
production of oil and gas within the next seven years.
3. The director may approve an oil well for enhanced oil recovery potential status if the subject oil
well was completed with surface casing set and cemented to properly isolate the Fox Hills
formation, additional strings of casing are properly cemented to adequately protect and isolate
all formations containing water, oil, or gas or any combination of these, protect the pipe
through salt sections encountered, and isolate the uppermost sand of the Dakota group, and
the director has deemed the subject well to have a potential use in an enhanced oil recovery
project. If a well is given enhanced oil recovery potential status, the well's perforations must be
isolated, the integrity of its casing must be proven, and its casing must be sealed at the
surface, all in a manner approved by the director. A surface owner may request a hearing to
review a well that has been on enhanced oil recovery potential status for at least twelve years,
pursuant to subsection 1 of North Dakota Century Code section 38-08-04.
4. In addition to the waiver in subsection 2, the director may also waive the duty to plug and
reclaim an abandoned well for any other good cause found by the director. If the director
exercises this discretion, the director shall set a date or circumstance upon which the waiver
expires.
5. The director may approve suspension of the drilling of a well. If suspension is approved, a
plug must be placed at the top of the casing to prevent any foreign matter from getting into the
well. When drilling has been suspended for thirty days, the well, unless otherwise authorized
by the director, must be plugged and its site reclaimed pursuant to sections 43-02-03-34 and
43-02-03-34.1.
History: Amended effective April 30, 1981; January 1, 1983; May 1, 1990; May 1, 1992; August 1,
1999; January 1, 2008; April 1, 2010; April 1, 2012; April 1, 2014; October 1, 2016; April 1, 2018; April 1,
2020; April 1, 2022; April 1, 2024.
General Authority: NDCC 38-08-04
Law Implemented: NDCC 38-08-04
1. Prior to commencing operations, the operator of a new injection well must demonstrate the mechanical integrity of the well. Prior to performing any workover project on an existing well, during which the packer or other means of annular isolation could be affected, the operator shall obtain approval from the director. All existing injection wells must demonstrate continual mechanical integrity and be tested at least once every five years. Following the completion of any remedial work, the operator shall demonstrate the mechanical integrity of the well. The director may require further mechanical integrity tests or other remedial work to ensure the mechanical integrity of the well to prevent the movement of fluid into an underground source of drinking water or an unauthorized zone. Mechanical integrity pressure tests must be performed at one thousand pounds per square inch [6900 kilopascals] for a minimum of fifteen minutes. A mechanical integrity test pressure of less than one thousand pounds per square inch [6900 kilopascals] may be approved by the director. Once an injection well is determined to lack mechanical integrity, within ninety days of the determination, it must be repaired and retested or plugged and abandoned.
An injection well has mechanical integrity if:
- a. There is no significant leak in the casing, tubing, or packer; and
- b. There is no significant fluid movement into an underground source of drinking water or an unauthorized zone through vertical channels adjacent to the injection bore.
2. One of the following methods must be used to evaluate the absence of significant leaks:
- a. Pressure test with liquid or gas.
- b. Monitoring of positive annulus pressure following a valid pressure test.
- c. Radioactive tracer survey.
3. One of the following methods must be used to establish the absence of significant fluid movement:
- a. A log from which cement can be determined or well records demonstrating the presence of adequate cement to prevent such migration.
- b. Radioactive tracer survey, temperature log, or noise log.
4. The operator of an injection well immediately shall shut-in the well if mechanical failure indicates fluids are, or may be, migrating into an underground source of drinking water or an unauthorized zone, or if so directed by the director.
History: Effective November 1, 1982; amended effective May 1, 1990; July 1, 1996; May 1, 2004; October 1, 2016; April 1, 2020.
General Authority: NDCC 38-08-04(2)
Law Implemented: NDCC 38-08-04(2)