Virginia Law

Article 5. Technical Standards

4VAC25-150-230. Commencement of activity.

A. Gas, oil or geophysical activity commences with ground-disturbing activity.

B. A permittee shall notify the division at least 48 hours prior to commencing ground-disturbing activity, drilling a well or corehole, completing or recompleting a well or plugging a well or corehole. The permittee shall notify the division, either orally or in writing, of the operation name and the date and time that the work is scheduled to commence. Should activities not commence as first noticed, the permittee shall make every effort to update the division and reschedule the commencement of activity, indicating the specific date and time the work will be commenced.

C. For dry holes and in emergency situations, the operator shall notify the division, orally or in writing, within 48 hours of commencing plugging activities.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.23, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-240. Signs.

A. Temporary signs. Each permittee shall keep a sign posted at the point where the access road enters the permitted area of each well or corehole being drilled or tested, showing the name of the well or corehole permittee, the well name and the permit number, the telephone number for the Division of Gas and Oil and a telephone number to use in case of an emergency or for reporting problems.

The sign shall be posted from the commencement of construction until:

1. The well is completed;

2. The dry hole or corehole is plugged;

3. The site is stabilized; or

4. The permanent sign is posted.

B. Permanent signs. Each permittee shall keep a permanent sign posted in a conspicuous place on or near every producing well or well capable of being placed into production and on every associated facility. For any well drilled or sign replaced after September 25, 1991, the sign shall:

1. Be a minimum of 18 inches by 14 inches in size;

2. Contain, at a minimum, the permittee's name, the well name and the permit number, the Division of Gas and Oil phone number and the telephone number to use in case of an emergency or for reporting problems;

3. Contain lettering a minimum of 1-1/4 inches high; and

4. For a well, be located on the well or on a structure such as a meter house or pole located within 50 feet of the well head.

C. Signs designating red zone areas within the permit boundary are to be maintained in good order, include reflective material or be lighted so to be visible at night, and located as prescribed by the operator's red zone safety plan internal to the operations plan.

D. All signs shall be maintained or replaced as necessary to be kept in a legible condition.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.24, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-250. Blasting and explosives.

A. Applicability. This section governs all blasting on gas, oil or geophysical sites, except for:

1. Blasting being conducted as part of seismic exploration where explosives are placed and shot in a borehole to generate seismic waves; or

2. Use of a device containing explosives for perforating a well.

B. Certification.

1. All blasting on gas, oil and geophysical sites shall be conducted by a person who is certified by the department, the Board of Coal Mining Examiners, or by the Virginia Department of Housing and Community Development.

2. The director may accept a certificate issued by another state in lieu of the certification required in subdivision B 1 of this section, provided the department, the Board of Coal Mining Examiners, or the Department of Housing and Community Development has approved reciprocity with that state.

C. Blasting safety. Blasting shall be conducted in a manner as prescribed by 4VAC25-110, Regulations Governing Blasting in Surface Mining Operations, designed to prevent injury to persons, and damage to features described in the operations plan under 4VAC25-150-100 B.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.25, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-260. Erosion, sediment control and reclamation.

A. Applicability. Permittees shall meet the erosion and sediment control standards of this section whenever there is a ground disturbance for a gas, oil or geophysical operation. Permittees shall reclaim the land to the standards of this section after the ground-disturbing activities are complete and the land will not be used for further permitted activities.

B. Erosion and sediment control plan. Applicants for a permit shall submit an erosion and sediment control plan as part of their operations plan. The plan shall describe how erosion and sedimentation will be controlled and how reclamation will be achieved.

C. Erosion and sediment control standards. Whenever ground is disturbed for a gas, oil or geophysical operation, the following erosion and sediment control standards shall be met.

1. All trees, shrubs and other vegetation shall be cleared as necessary before any blasting, drilling, or other site construction, including road construction, begins.

a. Cleared vegetation shall be either removed from the site, properly stacked on the permitted site for later use, burned, or placed in a brush barrier if needed to control erosion and sediment control. Only that material necessary for the construction of the permitted site shall be cleared. When used as a brush barrier, the cleared vegetation shall be cut and windrowed below a disturbed area so that the brush barrier will effectively control sediment migration from the disturbed area. The material shall be placed in a compact and uniform manner within the brush barrier and not perpendicular to the brush barrier. Brush barriers shall be constructed so that any concentrated flow created by the barrier is released into adequately protected outlets and adequate channels. Large diameter trunks, limbs, and stumps that may render the brush barrier ineffective for sediment control shall not be placed in the brush barrier.

b. During construction, soil sufficient to provide a suitable growth medium for permanent stabilization with vegetation shall be used to stabilize the site in accordance with the standards of subdivisions C 2 and C 3 of this section.

2. Except as provided for in subdivisions C 5 and C 12 c of this section, permanent or temporary stabilization measures shall be applied to denuded areas within 30 days of achievement of final grade on the site unless the area will be redisturbed within 30 days.

a. If no activity occurs on a site for a period of 30 consecutive days then stabilization measures shall be applied to denuded areas within seven days of the last day of the 30-day period.

b. Temporary stabilization measures shall be applied to denuded areas that may not be at final grade but will be left inactive for one year or less.

c. Permanent stabilization measures shall be applied to denuded areas that are to be left inactive for more than one year.

3. A permanent vegetative cover shall be established on denuded areas to achieve permanent stabilization on areas not otherwise permanently stabilized. Permanent vegetation shall not be considered established until a ground cover is uniform, mature enough to survive and will inhibit erosion.

4. Temporary sediment control structures such as basins, traps, berms or sediment barriers shall be constructed prior to beginning other ground-disturbing activity and shall be maintained until the site is stabilized.

5. Stabilization measures shall be applied to earthen structures such as sumps, diversions, dikes, berms and drainage windows within 30 days of installation.

6. Sediment basins.

a. Surface runoff from disturbed areas that is composed of flow from drainage areas greater than or equal to three acres shall be controlled by a sediment basin. The sediment basin shall be designed and constructed to accommodate the anticipated sediment loading from the ground-disturbing activity. The spillway or outfall system design shall take into account the total drainage area flowing through the disturbed area to be served by the basin.

b. If surface runoff that is composed of flow from other drainage areas is separately controlled by other erosion and sediment control measures, then the other drainage area is not considered when determining whether the three-acre limit has been reached and a sediment basin is required.

7. Cut and fill slopes shall be designed and constructed in a manner that will minimize erosion. No trees, shrubs, stumps or other woody material shall be placed in fill.

8. Concentrated runoff shall not flow down cut or fill slopes unless contained within an adequate temporary or permanent channel, flume or slope drain structure.

9. Whenever water seeps from a slope face, adequate drainage or other protection shall be provided.

10. All storm sewer inlets that are made operable during construction shall be protected so that sediment-laden water cannot enter the conveyance system without first being filtered or otherwise treated to remove sediment.

11. Before newly constructed stormwater conveyance channels or pipes are made operational, adequate outlet protection and any required temporary or permanent channel lining shall be installed in both the conveyance channel and receiving channel.

12. Live watercourses.

a. When any construction required for erosion and sediment control, reclamation or stormwater management must be performed in a live watercourse, precautions shall be taken to minimize encroachment, control sediment transport and stabilize the work area. Nonerodible material shall be used for the construction of causeways and cofferdams. Earthen fill may be used for these structures if armored by nonerodible cover materials.

b. When the same location in a live watercourse must be crossed by construction vehicles more than twice in any six-month period, a temporary stream crossing constructed of nonerodible material shall be provided.

c. The bed and banks of a watercourse shall be stabilized immediately after work in the watercourse is completed.

13. If more than 500 linear feet of trench is to be open at any one time on any continuous slope, ditchline barriers shall be installed at intervals no more than the distance in the following table and prior to entering watercourses or other bodies of water.

14. Where construction vehicle access routes intersect a paved or public road, provisions, such as surfacing the road, shall be made to minimize the transport of sediment by vehicular tracking onto the paved surface. Where sediment is transported onto a paved or public road surface, the road surface shall be cleaned by the end of the day.

15. The design and construction or reconstruction of roads shall incorporate appropriate limits for grade, width, surface materials, surface drainage control, culvert placement, culvert size, and any other necessary design criteria required by the director to ensure control of erosion, sedimentation and runoff, and safety appropriate for their planned duration and use. This shall include, at a minimum, that roads are to be located, designed, constructed, reconstructed, used, maintained and reclaimed so as to:

a. Control or prevent erosion and siltation by vegetating or otherwise stabilizing all exposed surfaces in accordance with current, prudent engineering practices;

b. Control runoff to minimize downstream sedimentation and flooding; and

c. Use nonacid or nontoxic substances in road surfacing.

16. Unless approved by the director, all temporary erosion and sediment control measures shall be removed within 30 days after final site stabilization or after the temporary measures are no longer needed. Trapped sediment and the disturbed soil areas resulting from the disposition of temporary measures shall be permanently stabilized within the permitted area to prevent further erosion and sedimentation.

D. Final reclamation standards.

1. All equipment, structures or other facilities not required for monitoring the site or permanently marking an abandoned well or corehole shall be removed from the site, unless otherwise approved by the director.

2. Each gathering line abandoned in place, unless otherwise agreed to be removed under a right-of-way or lease agreement, shall be disconnected from all sources and supplies of natural gas and petroleum, purged of liquid hydrocarbons, depleted to atmospheric pressure, and cut off three feet below ground surface, or at the depth of the gathering line, whichever is less, and sealed at the ends. The operator shall provide to the division documentation of the methods used, the date and time the pipeline was purged and abandoned.

3. If final stabilization measures are being applied to access roads or ground-disturbed pipeline rights-of-way, or if the rights-of-way will not be redisturbed for a period of 30 days, water bars shall be placed across them at 30-degree angles at the head of all pitched grades and at intervals no more than the distance in the following table:

4. The permittee shall notify the division when the site has been graded and seeded for final reclamation in accordance with subdivision C 3 of this section. Notice may be given orally or in writing. The vegetative cover shall be successfully maintained for a period of two years after notice has been given before the site is eligible for bond release.

5. If the land disturbed during gas, oil or geophysical operations will not be reclaimed with permanent vegetative cover as provided for in subsection C of this section, the permittee or applicant shall request a variance to these reclamation standards and propose alternate reclamation standards and an alternate schedule for bond release.

E. The director may waive or modify any of the requirements of this section that are deemed inappropriate or too restrictive for site conditions. A permittee requesting a variance shall, in writing, document the need for the variance and describe the alternate measures or practices to be used. Specific variances allowed by the director shall become part of the operations plan. The director shall consider variance requests judiciously, keeping in mind both the need of the applicant to maximize cost effectiveness and the need to protect off-site properties and resources from damage.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.26, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-270. Stormwater management.

A. This section shall apply whenever an applicant or permittee must complete an erosion and sediment control plan under 4VAC25-150-260. The erosion and sediment control plan shall also describe how stormwater runoff will be managed in accordance with the standards of this section.

B. Areas downstream from permitted sites shall be protected from sediment disposition, erosion and damage due to increases in volume, velocity and peak flow rates of stormwater runoff for the stated frequency storm of 24-hour duration in accordance with the following:

1. Increased volumes of sheet flows or concentrated flows that may cause erosion and sedimentation on adjacent property shall be diverted to a stable outlet, adequate channel or a sediment control, detention or retention facility.

2. Adequacy of all channels and pipes shall be verified in the following manner:

a. The applicant shall demonstrate that the total drainage area to the point of analysis within the channel is 100 times greater than the contributing drainage area of the site in question; or

b. The receiving channel or pipe shall be analyzed as follows:

(1) Natural channels shall be analyzed using data for a two-year storm to verify that stormwater will not overtop channel banks or cause erosion of the channel bed or banks.

(2) All previously constructed man-made channels shall be analyzed using data for a 10-year storm to verify that stormwater will not overtop its banks and using data for a two-year storm to demonstrate that stormwater will not cause erosion of the channel bed or banks.

(3) Pipes and storm sewer systems shall be analyzed using data from a 10-year storm to verify that stormwater will be contained within the pipe or system. A downstream stability analysis at the outfall of the pipe or storm sewer system shall also be performed.

3. All hydrologic analyses shall be based on the existing watershed characteristics and the ultimate development condition of the site.

4. If the applicant chooses an option that includes stormwater detention or retention, then the plan must provide for maintenance of the detention or retention facilities. The plan shall set forth the maintenance requirements of the facility and the person responsible for performing the maintenance.

5. Outflows from a sediment basin, stormwater management facility or other concentrated runoff leaving a permitted site shall be discharged into an adequate channel.

C. Stormwater runoff which has been contaminated by or come into contact with overburden, raw material, intermediate products, finished products, byproducts or wastes from gas, oil or geophysical operations located on the permitted site shall be managed in accordance with a plan approved by the director.

D. The director may waive or modify any of the requirements of this section that are deemed inappropriate or too restrictive for site conditions. The permittee's written request for a variance shall document the need for the variance and describe the alternate measures or practices to be used. Specific variances allowed by the director shall be documented in the operations plan. The director shall consider variance requests judiciously, keeping in mind both the need of the applicant to maximize cost effectiveness and the need to protect off-site properties and resources from damage.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.27, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998.

4VAC25-150-280. Logs and surveys.

A. Each permittee drilling a well or corehole shall complete a driller's log, a gamma ray log, or other log showing the top and bottom points of geologic formations and any other log required under this section. The driller's log shall state, at a minimum, the character, depth, and thickness of geological formations encountered, including groundwater-bearing strata, coal seams, mineral beds, and gas-bearing or oil-bearing formations.

B. When a permittee or the director identifies that a well or corehole is to be drilled or deepened in an area of the Commonwealth that is known to be underlain by coal seams, the following shall be required:

1. The vertical location of coal seams in the well or corehole shall be determined and shown in the driller's log and gamma ray log or other log.

2. The horizontal location of the well or corehole in coal seams shall be determined through an inclination survey from the surface to the lowest known coal seam. Each inclination survey shall be conducted as follows:

a. The first survey point shall be taken at a depth not greater than the most shallow coal seam; and

b. Thereafter shot points shall be taken at each coal seam or at intervals of 200 feet, whichever is less, to the lowest known coal seam.

3. Prior to drilling any well or corehole within 500 feet of a coal seam in which there are active workings, the permittee shall conduct an inclination survey to determine whether the deviation of the well or corehole exceeds one degree from true vertical. If the well or corehole is found to exceed one degree from vertical, then the permittee shall:

a. Immediately cease operations;

b. Immediately notify the coal owner and the division;

c. Conduct a directional survey to drilled depth to determine both horizontal and vertical location of the well or corehole; and

d. Unless granted a variance by the director, correct the well or corehole to within one degree of true vertical.

4. Except as provided for in subdivision B 3 of this section, if the deviation of the well or corehole exceeds one degree from true vertical at any point between the surface and the lowest known coal seam, then the permittee shall:

a. Correct the well or corehole to within one degree of true vertical; or

b. Conduct a directional survey to the lowest known coal seam and notify the coal owner of the actual well or corehole location.

5. The director may grant a variance to the requirements of subdivisions B 3 and B 4 of this section only after the permittee and coal owners have jointly submitted a written request for a variance stating that a directional survey or correction to the well or corehole is not needed to protect the safety of any person engaged in active coal mining or to the environment.

6. If the director finds that the lack of assurance of the horizontal location of the well or corehole to a known coal seam poses a danger to persons engaged in active coal mining or the lack of assurance poses a risk to the public safety or the environment, the director may, until 30 days after a permittee has filed the completion report required in 4VAC25-150-360, require that a directional survey be conducted by the permittee.

7. The driller's log shall be updated on a daily basis. The driller's log and results of any other required survey shall be kept at the site until drilling and casing or plugging a dry hole or corehole are completed.

C. Each permittee completing a well shall complete a cement bond log for the water protection string. Permittees may petition the director to submit alternative documentation that demonstrates effective bond between the casing and the formation.

Statutory Authority

§§ 45.1-161.3, 45.1-361.4, and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.28, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013; Volume 33, Issue 7, eff. December 28, 2016.

4VAC25-150-290. Actual well or corehole location.

A. The actual horizontal surface location of the well shall be within three feet of the permitted location designated on the well plat, except where an operator has stated that the location may vary up to 10 feet in the notice as required in § 45.2-1632 of the Code of Virginia.

B. The permittee shall survey the actual location of the well which may be made from a minimum of two temporary points not disturbed during development of the well or site and shown on the plat submitted with the permit application. The permittee shall submit an updated plat, certified by a licensed land surveyor or licensed professional engineer, showing the actual well location certified to be within three feet of the permitted location, or within 10 feet as provided for in subsection A of this section. This updated plat shall be included with the drilling report submitted in accordance with 4VAC25-150-360.

Statutory Authority

§ 45.2-103 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.29, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 38, Issue 13, eff. March 31, 2022.

4VAC25-150-300. Pits.

A. General requirements.

1. Pits are to be temporary in nature and are to be reclaimed when the operations using the pit are complete. All pits shall be reclaimed within 180 days unless a variance is requested and granted by the field inspector.

2. Pits may not be used as erosion and sediment control structures or stormwater management structures, and surface drainage may not be directed into a pit.

3. Pits shall have a properly installed and maintained liner or liners made of 10 mil or thicker high-density polyethylene or its equivalent.

4. Pits shall be constructed of sufficient size and shape to contain all fluids and maintain a two-foot freeboard.

5. Pits shall be enclosed by adequate fencing to secure the site from access by the public and wildlife.

B. Operational requirements.

1. The integrity of lined pits and their enclosures shall be maintained until the pits are reclaimed or otherwise closed. Upon failure of the lining or pit, the operation shall be shut down until the liner and pit are repaired or rebuilt. The permittee shall notify the division, by the quickest available means, of any pit leak.

2. Motor oil and, to the extent practicable, crude oil shall be kept out of the pit. Oil shall be collected and disposed of properly. Litter and other solid waste shall be collected and disposed of properly and not thrown into the pit.

3. At the conclusion of drilling and completion operations or after a dry hole, well, or corehole has been plugged, the pit shall be drained in a controlled manner and the fluids disposed of in accordance with 4VAC25-150-420. If the pit is to be used for disposal of solids, then the standards of 4VAC25-150-430 shall be met.

Statutory Authority

§§ 45.1-161.3, 45.1-361.4, and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.30, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013; Volume 33, Issue 7, eff. December 28, 2016.

4VAC25-150-310. Tanks.

A. All tanks installed on or after September 25, 1991, shall be designed and constructed to contain the fluids to be stored in the tanks and prevent unauthorized discharge of fluids.

B. All tanks shall be maintained in good condition and repaired as needed to ensure the structural integrity of the tank.

C. Every permanent tank or battery of tanks shall have secondary containment achieved by constructing a dike or firewall with a capacity of 1-1/2 times the volume of the largest tank when plumbed at the top, or all tanks when plumbed at the bottom, utilizing a double wall tank or another method approved by the division.

D. Dikes and firewalls shall be maintained in good condition, and the reservoir shall be kept free from brush, water, oil or other fluids.

E. Permittees shall inspect the structural integrity of tanks and tank installations, at a minimum, annually. The report of the annual inspection shall be maintained by the permittee for a minimum of three years and be submitted to the director upon request.

F. Load lines shall be properly constructed and operated on the permitted area.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.31, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-320. Blowout prevention.

A. Applicability. All wells shall be equipped to control formation pressure during drilling and servicing as follows:

1. Blowout prevention equipment is required when formation pressures of 1,000 pounds or greater are encountered or are expected to be encountered, or when drilling in an area where there is no prior knowledge of the formation pressures to be encountered.

2. A diverter system is required when formation pressures are expected to be less than 1,000 pounds.

B. All blowout preventers, diverters, choke lines, kill lines and manifolds shall be installed above ground level. Casing heads and optional spools may be installed below ground level provided they are readily accessible.

C. The diverter, chokelines and kill lines shall be anchored, tied or otherwise secured to prevent whipping resulting from pressure surges.

D. Pressure ratings.

1. All pipe fittings, valves and unions placed on or connected with the well or corehole, as well as blowout prevention equipment, casing, casing head, drill pipe, or tubing, shall have a minimum working pressure rating of 110% of the maximum anticipated pressure that the material will be exposed to and shall be in good working condition.

2. All ram type blowout preventers and related equipment shall be tested to 110% of the maximum anticipated formation pressure, not to exceed 70% of the rated burst pressure of the casing that the blowout preventers are connected to before being placed in service. Annular type blowout preventers shall be tested in conformance with the manufacturer's published instructions, or those of a licensed professional engineer, prior to use.

E. While in service, blowout prevention equipment shall be visually inspected daily. A preventer operating test shall be performed at least once on all the blowout prevention equipment except the blind rams which shall be tested on each round trip.

F. All employees on the rig shall be trained, knowledgeable and able to properly operate the blowout preventer system. In addition, when blowout prevention equipment is installed, at least one person who is certified in blowout prevention and well control procedures by a school of blowout prevention acceptable to the director shall be responsible for the proper testing and operations of the blowout preventers and related equipment.

G. When repairs or other work must be performed to the blowout prevention equipment, drilling and servicing operations must stop until the blowout prevention equipment is returned to service.

H. A record of all tests on the equipment shall be kept at the rig for inspection by the director until drilling or servicing operations have been completed.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.32, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998.

4VAC25-150-330. Swabbing, perforating and wireline operations.

A. All wells and coreholes shall be cleaned into properly constructed pits or containers at a safe distance from the rig floor and from any potential fire hazard.

B. Possible sources of ignition, such as all engines and motors not essential to the swabbing operation, shall be shut down while swabbing operations are being conducted.

C. Swabbing operations shall be conducted only during daylight hours or with adequate illumination.

D. Swabbing shall be conducted so that fluids are routed through a closed-flow system to the maximum extent possible.

E. All oil savers shall be of the type that do not require a person to be near the lubricator or wellhead to control the oil saver.

F. All swabbing lines, blow down lines or flow lines to pits or tanks shall be securely anchored. Whenever hydrocarbons or other volatile fluids may be expected, these lines shall extend a safe distance from the well and away from any other source of ignition.

G. On wells where there is a possibility of flow during swabbing or other wireline operations, a lubricator shall be used that will allow the removal of the swabbing or other tools without venting gas from the well.

H. There shall be no radio or radio-phone transmitters operated where perforating operations are in progress. Warning signs shall be conspicuously placed at entrances to work sites, which shall be at a minimum, 200 feet from the operation where perforating is being done.

I. Upon the conclusion of perforating operations, the work area shall be inspected and all explosive material and scraps shall be placed in containers and removed from the site.

J. Electrical grounding between the well head, service unit, and rig structure shall be made prior to operating tools using explosives.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.33, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998.

4VAC25-150-340. Drilling fluids.

A. Operations plan requirements. Applicants for a permit shall provide, prior to commencing drilling, documentation that the water meets the requirements of subsection B of this section, and a general description of the additives and muds to be used in all stages of drilling. Providing that the requirement in subsection C of this section is met, variations necessary because of field conditions may be made with prior approval of the director and shall be documented in the driller's log.

B. Water quality in drilling.

1. Before the water-protection string is set, permittees shall use one of the following sources of water in drilling:

a. Water that is from a water well or spring located on the drilling site; or

b. Conduct an analysis of groundwater within a one-quarter-mile radius of the drilling location, and use:

(1) Water which is of equal or better quality than the groundwater; or

(2) Water which can be treated to be of equal or better quality than the groundwater. A treatment plan must be included with the application if water is to be treated.

(3) If, after a diligent search, a groundwater source (such as a well or spring) cannot be found within a one-quarter-mile radius of the drilling location, the applicant may use water meeting the parameters listed in the Department of Environmental Quality's "Ground water criteria," 9VAC25-280-70. The analysis shall include, but is not limited to, the following items:

(a) Chlorides;

(b) Total dissolved solids;

(c) Hardness;

(d) Iron;

(e) Manganese;

(f) PH;

(g) Sodium; and

(h) Sulfate.

(4) Drilling water analysis shall be taken within a one-year period preceding the drilling application.

2. After the water-protection string is set, permittees may use waters that do not meet the standards of subdivision B 1 of this section.

C. Drilling muds. No permittee may use an oil-based drilling fluid or other fluid which has the potential to cause acute or chronic adverse health effects on living organisms unless a variance has been approved by the director. Permittees must explain the need to use such materials and provide the material data safety sheets. In reviewing the request for the variance, the director shall consider the concentration of the material, the measures to be taken to control the risks, and the need to use the material. Permittees shall also identify what actions will be taken to ensure use of the additives will not cause a lessening of groundwater quality.

Statutory Authority

§§ 45.1-161.3, 45.1-361.4, and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.34, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013; Volume 33, Issue 7, eff. December 28, 2016.

4VAC25-150-350. Gas, oil or geophysical operations in hydrogen sulfide areas.

A. Applicability. This section shall apply to every permittee who drills or operates a well or drills a corehole:

1. In areas of unknown hydrogen sulfide conditions;

2. Below the base of the devonian shale; or

3. In areas where the hydrocarbons contain gas with a concentration of 100 parts per million (ppm) or greater of hydrogen sulfide as a constituent of the gas.

B. Permittees shall not remove hydrocarbons with a hydrogen sulfide concentration of 100 parts per million or greater from the well site where they were produced unless:

1. The hydrocarbons have been cleaned on-site so that the hydrogen sulfide concentration is less than 100 parts per million; or

2. The permittee has received a variance from the director.

C. General requirements.

1. Each permittee subject to this section shall determine the hydrogen sulfide concentration in the hydrocarbons by a test approved by the director such as a test in accordance with ASTM Standard D-2385-66, or GPA Plant Operation Test Manual C-1, GPA Publication 2265-68.

2. Automatic hydrogen sulfide detection and alarm equipment that will warn of the presence of hydrogen sulfide gas shall be utilized at the site.

D. Materials and equipment.

1. For new construction or modification of facilities, including materials and equipment to be used in drilling and workover operations, permittees shall only use metal components, approved by the director, which have been selected and manufactured so as to be resistant to hydrogen sulfide stress cracking under the operating conditions for which their use is intended. This requirement may be met by use of components that satisfy the requirements of NACE Standard MR-01-75 and API RP-14E, §§ 1.7(c), 2.1(c) and 4.7. The handling and installation of materials and equipment used in hydrogen sulfide service are to be performed in such a manner so as not to induce susceptibility to sulfide stress cracking.

2. Other materials and equipment, including materials and equipment used in drilling and workover operations, may be used for hydrogen sulfide service provided such materials and equipment are proved, as the result of advancements in technology or as the result of control and knowledge of operating conditions such as temperature and moisture content, suitable for the use intended and where such usage is technologically acceptable as good engineering practice, and the director has approved a variance for the materials and equipment for the specific uses.

3. In the event of a failure of any element of an existing system as the result of hydrogen sulfide stress cracking, the compliance status of the system shall be determined by the director after the operator has submitted a detailed written report on the failure to the director.

E. Reporting. The permittee shall report the hydrogen sulfide concentrations of the hydrocarbon in any well or corehole where the hydrogen sulfide concentration is equal to or exceeds 100 parts per million with the drilling report under 4VAC25-150-360 or with the plugging affidavit for coreholes under 4VAC25-150-460.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.35, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998.

4VAC25-150-360. Drilling, completion, and other reports.

A. Each permittee conducting drilling shall file, electronically or on a form prescribed by the director, a drilling report within 90 days after a well reaches total depth.

B. Each permittee drilling a well shall file, electronically or on a form prescribed by the director, a completion report within 90 days after the well is completed. All completion reports shall include the cement bond log required in subsection C of 4VAC25-150-280. Subject to the approval of the director, permittees may submit alternative documentation that demonstrates effective bond between the casing and the formation.

C. The permittee shall file the driller's log, the results of any other log or survey required to be run in accordance with this chapter or by the director, and the plat showing the actual location of the well with the drilling report, unless they have been filed earlier.

D. The permittee shall, within 90 days of reaching total depth, file with the division the results of any gamma ray, density, neutron, induction, and cement bond logs, or their equivalent, that have been conducted on the wellbore in the normal course of activities that have not previously been required to be filed.

Statutory Authority

§§ 45.1-161.3, 45.1-361.4, and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.36, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013; Volume 33, Issue 7, eff. December 28, 2016.

4VAC25-150-365. Disclosure of well stimulation fluids.

A. In addition to other requirements that may be prescribed by the director, each completion report required in 4VAC25-150-360 shall also contain the following disclosures:

The operator of the well shall complete the Chemical Disclosure Registry form and upload the form on the Chemical Disclosure Registry, including:

a. The operator name;

b. The date of completion of the hydraulic fracturing treatment or treatments;

c. The county in which the well is located;

d. The American Petroleum Institute (API) number for the well;

e. The well name and number;

f. The longitude and latitude of the wellhead;

g. The total vertical depth of the well;

h. The total volume of water used in the hydraulic fracturing treatment or treatments of the well or the type and total volume of the base fluid used in the hydraulic fracturing treatment or treatments, if something other than water;

i. Each additive used in the hydraulic fracturing treatments and the trade name, supplier, and a brief description of the intended use or function of each additive in the hydraulic fracturing treatment or treatments;

j. Each chemical ingredient used in the hydraulic fracturing treatment or treatments of the well that is subject to the requirements of 29 CFR 1910.1200(g)(2), as provided by the chemical supplier or service company or by the operator, if the operator provides its own chemical ingredients;

k. The actual or maximum concentration of each chemical ingredient listed under subdivision j of this subsection in percent by mass;

l. The CAS number for each chemical ingredient listed, if applicable; and

m. A supplemental list of all chemicals, their respective CAS numbers, and the proportions thereof not subject to the requirements of 29 CFR 1910.1200(g)(2), that were intentionally included in and used for the purpose of creating the hydraulic fracturing treatments for the well.

B. The department shall obtain and maintain data submitted to the Chemical Disclosure Registry. If the Chemical Disclosure Registry is temporarily inoperable, the operator of a well on which hydraulic fracturing treatment or treatments were performed shall supply the department with the required information and upload the information on the registry when it is again operable. The information required shall also be filed as an attachment to the completion report for the well, which shall be posted, along with all attachments, on the department's website, except that information determined to be subject to trade secret protection shall not be posted.

C. All information related to the specific identity or CAS number or amount of any additive or chemical ingredient used in hydraulic fracturing shall be submitted to the department and shall be available to the public unless the department determines that information supplied by the operator and claimed to be a trade secret is entitled to such protection. All information claimed as a trade secret shall be identified as such at the time of submission of the appropriate report. The department shall treat as confidential in accordance with law, information that meets the criteria specified in law for a trade secret and is contained on such forms and filings as is required under this chapter. Such criteria shall include a demonstration by the claimant that the information derives independent economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use, and is the subject of efforts that are reasonable under the circumstances to maintain its secrecy.

Should the department determine that information is protected as a trade secret, the operator of the well shall indicate on the Chemical Disclosure Registry or the supplemental list that the additive or chemical ingredient or their amounts are entitled to trade secret protection. If a chemical ingredient name or CAS number is entitled to trade secret protection, the chemical family or other similar description associated with such chemical ingredient shall be provided. The operator of the well on which hydraulic fracturing was performed shall provide the contact information, including the name, authorized representative, mailing address, and phone number of the business organization for which trade secret protection exists. Unless the information is entitled to protection as a trade secret, information submitted to the department or uploaded on the Chemical Disclosure Registry is public information.

D. The operator understands that the director may disclose information regarding the specific identity of a chemical, the concentration of a chemical, or both the specific identity and concentration of a chemical claimed to be a trade secret to additional department staff to the extent that such disclosure is necessary to assist the department in responding to an emergency resulting in an order pursuant to subsection D of § 45.2-1629 of the Code of Virginia provided that such individuals shall not disseminate the information further. In addition, the director may disclose such information to any relevant state or local government official to assist in responding to the emergency. Any information so disclosed shall at all times be considered confidential and shall not be construed as publicly available. The director shall notify the trade secret claimant or holder of disclosures made to relevant state or local government officials as soon as practicable after such disclosure is made.

E. An operator may not withhold information related to chemical ingredients used in hydraulic fracturing, including information identified as a trade secret, from any health professional or emergency responder who needs the information for diagnostic, treatment, or other emergency response purposes subject to procedures set forth in 29 CFR 1910.1200(i). An operator shall provide directly to a health professional or emergency responder, all information in the person's possession that is required by the health professional or emergency responder, whether or not the information may qualify for trade secret protection under this section. The person disclosing information to a health professional or emergency responder shall include with the disclosure, as soon as circumstances permit, a statement of the health professional's confidentiality obligation. In an emergency situation, the operator shall provide the information immediately upon request to the person who determines that the information is necessary for emergency response or treatment. The disclosures required by this subsection shall be made in accordance with the procedures in 29 CFR 1910 with respect to a written statement of need and confidentiality agreements, as applicable.

Statutory Authority

§ 45.2-103 of the Code of Virginia.

Historical Notes

Derived from Virginia Register Volume 33, Issue 7, eff. December 28, 2016; amended, Virginia Register Volume 38, Issue 13, eff. March 31, 2022.

4VAC25-150-370. Wellhead equipment.

A. All wellhead connections and equipment, including but not limited to pipe fittings, valves and unions placed on or connected with a well, well casing, casing head, drill pipe, or tubing shall have a working pressure rating of a minimum of 110% of the maximum anticipated pressure that the material will be exposed to, and shall be in good working condition.

B. Adequate and proper wellhead equipment shall be installed and maintained in good working order on every well that is not permanently abandoned and plugged, so that pressure measurements may be obtained at any time. Valves shall be installed so that pressures can be separately obtained from each production string.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.37, eff. September 25, 1991.

4VAC25-150-380. Incidents, spills and unpermitted discharges.

A. Incidents. A permittee shall, by the quickest available means, notify the division in the event of any unplanned off-site disturbance, fire, blowout, pit failure, hydrogen sulfide release, unanticipated loss of drilling fluids, or other incident resulting in serious personal injury or an actual or potential imminent danger to a worker, the environment, or public safety. The permittee shall take immediate action to abate the actual or potential danger. The permittee shall submit a written or electronic report within seven days of the incident containing:

1. A description of the incident and its cause;

2. The date, time and duration of the incident;

3. A description of the steps that have been taken to date;

4. A description of the steps planned to be taken to prevent a recurrence of the incident; and

5. Other agencies notified.

B. On-site spills.

1. A permittee shall take all reasonable steps to prevent, minimize, or correct any spill or discharge of fluids on a permitted site which has a reasonable likelihood of adversely affecting human health or the environment. All actions shall be consistent with the requirements of an abatement plan, if any has been set, in a notice of violation or closure, emergency or other order issued by the director.

2. A permittee shall orally report on-site spills or unpermitted discharges of fluids which are not required to be reported in subsection A of this section to the division within 24 hours. The oral report shall provide all available details of the incident, including any adverse effects on any person or the environment. A written report shall be submitted within seven days of the spill or unpermitted discharge. The written report shall contain:

a. A description of the incident and its cause;

b. The period of release, including exact dates and times;

c. A description of the steps to date; and

d. A description of the steps to be taken to prevent a recurrence of the release.

C. Off-site spills. Permittees shall submit a written report of any spill or unpermitted discharge of fluids that originates off of a permitted site with the monthly report under 4VAC25-150-210. The written report shall contain:

1. A listing of all agencies contacted about the spill or unpermitted discharge; and

2. All actions taken to contain, clean up or mitigate the spill or unpermitted discharge.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.38, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-390. Shut-in wells.

A. If a well is shut-in or otherwise not produced for a period of 12 consecutive months, the permittee shall measure the shut-in pressure on the production string or strings and report such pressures to the division annually. If the well is producing on the backside or otherwise through the casing, the permittee shall measure the shut-in pressure on the annular space.

B. A report of the pressure measurements on the nonproducing well shall be maintained and reported to the director annually by the permittee for a maximum period of two years.

C. Should the well remain in a nonproducing status for a period of two years, the permittee shall submit a plan for future well production to the director. A nonproducing well shall not remain unplugged for more than a three-year period unless approved by the director.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.39, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-400. Measurement of gas and oil.

A. Natural gas.

1. Each producer shall measure all gas produced from each well, or as prescribed by the director, using a method permitting the computation of volumes, in Mcf. This requirement may be met by use of the standards in:

a. "Orifice Metering of Natural Gas," ANSI/API 2530, American Gas Association, 1978;

b. "AGA Gas Measurement Manual, Part 2: Displacement Measurement," American Gas Association, 1977; or

c. "AGA Gas Measurement Manual, Part 3: Gas Turbine Metering," American Gas Association, 1989.

2. The director may require use of meters at designated places to obtain accurate records of the production of gas.

B. Oil. Each permitted oil operation shall use sufficient tanks or meters to measure the volume of oil produced. In no case shall meters be the sole means of measuring oil, unless such metering is conducted in accordance with a method approved by the director such as the API Manual of Petroleum Measurement Standards, 1981, Chapter 6.1, LACT Systems. A permittee may request a variance from the director to use a gauge tank to check the readings of meters.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.40, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998.

4VAC25-150-410. Venting and flaring of gas; escape of oil.

A. It shall be unlawful for any permittee to allow crude oil or natural gas to escape from any well, gathering pipeline or storage tank except as provided for in this section or in an approved operations plan. The permittee shall take all reasonable steps to shut in the gas or oil in the well, or make the necessary repairs to the well, gathering pipeline or storage tank to prevent the escape. All actions shall be consistent with the requirements of an abatement plan, if any has been set, in a notice of violation or closure, emergency or other order issued by the director.

B. A permittee shall drill or repair a well with special diligence so that waste of gas or oil from the well shall not continue longer than reasonably necessary under the following circumstances:

1. When, during drilling, gas or oil is found in the well and the permittee desires to continue to search for gas or oil by drilling deeper; or

2. When making repairs to any well producing gas or oil, commonly known as cleaning out.

C. No gas shall be flared or vented from a well for more than seven days after completion of the well except in these circumstances:

1. When a well must be blown to remove accumulated formation fluid which has restricted efficient production, or the well must be otherwise cleaned out as provided for in subsection B of this section;

2. For the safety of mining operations;

3. For any activity excluded in the definition of "waste" under § 45.2-1600 of the Act; or

4. For any other operational reason approved in advance by the director.

D. In all cases where both gas and oil are found and produced from the same stratum, the permittee shall use special diligence to conserve and save as much of the gas as is reasonably possible.

E. Venting shall only be used when flaring is not safe or not feasible.

Statutory Authority

§ 45.2-103 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.41, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 38, Issue 13, eff. March 31, 2022.

4VAC25-150-420. Disposal of pit and produced fluids.

A. Applicability. All fluids from a well, pipeline or corehole shall be handled in a properly constructed pit, tank or other type of container approved by the director.

A permittee shall not dispose of fluids from a well, pipeline or corehole until the director has approved the permittee's plan for permanent disposal of the fluids. Temporary storage of pit or produced fluids is allowed with the approval of the director. Other fluids shall be disposed of in accordance with the operations plan approved by the director.

B. Application and plan. The permittee shall submit an application for either on-site or off-site permanent disposal of fluids on a form prescribed by the director. Maps and a narrative describing the method to be used for permanent disposal of fluids must accompany the application if the permittee proposes to land apply any fluids on the permitted site. The application, maps, and narrative shall become part of the permittee's operations plan.

C. Removal of free fluids. Fluids shall be removed from the pit to the extent practical so as to leave no free fluids. In the event that there are no free fluids for removal, the permittee shall report this on the form provided by the director.

D. On-site disposal. The following standards for on-site land application of fluids shall be met:

1. Fluids to be land-applied shall meet the parameters listed in the Department of Environmental Quality's "Ground water criteria," (9VAC25-280-70), following criteria:

Acidity: <alkalinity

Alkalinity: >acidity

Chlorides: <5,000 mg/l

Iron: <7 mg/l

Manganese: <4 mg/l

Oil and Grease: < 15 mg/l

pH: 6-9 Standard Units

Sodium Balance: SAR of 8-12

2. Land application of fluids shall be confined to the permitted area.

3. Fluids shall be applied in a manner which will not cause erosion or runoff. The permittee shall take into account site conditions such as slope, soils and vegetation when determining the rate and volume of land application on each site. As part of the application narrative, the permittee shall show the calculations used to determine the maximum rate of application for each site.

4. Fluid application shall not be conducted when the ground is saturated, snow-covered or frozen.

5. The following buffer zones shall be maintained unless a variance has been granted by the director:

a. Fluid shall not be applied closer than 25 feet from highways or property lines not included in the acreage shown in the permit.

b. Fluid shall not be applied closer than 50 feet from surface watercourses, wetlands, natural rock outcrops, or sinkholes.

c. Fluid shall not be applied closer than 100 feet from water supply wells or springs.

6. The permittee shall monitor vegetation for two years after the last fluid has been applied to a site. If any adverse effects are found, the permittee shall report the adverse effects in writing to the division.

7. The director may require monitoring of groundwater quality on sites used for land application of fluids to determine if the groundwater has been degraded.

E. Off-site disposal of fluids.

1. Each permittee using an off-site facility for disposal of fluids shall submit:

a. A copy of a valid permit for the disposal facility to be used; and

b. Documentation that the facility will accept the fluids.

2. Each permittee using an off-site facility for disposal of fluids shall use a waste-tracking system to document the movement of fluids off of a permitted site to their final disposition. Records compiled by this system shall be reported to the division annually and available for inspection on request. Such records shall be retained until such time the injection well is reclaimed and has passed bond release.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.42, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2, eff. November 11, 1998; Volume 29, Issue 3, eff. November 8, 2012; Volume 30, Issue 1, eff. October 10, 2013.

4VAC25-150-430. Disposal of solids.

A. Applicability. All drill cuttings and solids shall be disposed of in the on-site pit as provided in subsection C of this section or as approved by the director. All other solid waste from gas, oil or geophysical operations shall be disposed of in a facility permitted to accept that type of waste.

B. Plan. Each operator shall submit a description of how drill cuttings and solids will be disposed of in the operations plan.

C. Disposal in a pit. Drill cuttings and solids may be disposed of on-site in an approved pit, without testing of the material.

The drill cuttings and solids shall be covered with a liner meeting the standards of 4VAC25-150-300, or a low-permeability clay cap, and shall be covered by soil. The combination of soil and liner or cap shall be at least four feet thick, capable of shielding the cuttings and solids remaining in the pit, suitable for supporting vegetation, and sloped to prevent ponding.

Statutory Authority

§§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Historical Notes

Derived from VR480-05-22.1 § 1.43, eff. September 25, 1991; amended, Virginia Register Volume 15, Issue 2. eff. November 11, 1998.