4VAC25-150 Virginia Gas and Oil Regulation

REGULATIONS

Vol. 25 Iss. 26 - August 31, 2009

TITLE 4. CONSERVATION AND NATURAL RESOURCES

DEPARTMENT OF MINES, MINERALS AND ENERGY

Chapter 150

Proposed Regulation

Title of Regulation: 4VAC25-150. Virginia Gas and Oil Regulation (amending 4VAC25-150-10, 4VAC25-150-60, 4VAC25-150-80, 4VAC25-150-90, 4VAC25-150-100, 4VAC25-150-110, 4VAC25-150-120, 4VAC25-150-135, 4VAC25-150-140, 4VAC25-150-150, 4VAC25-150-160, 4VAC25-150-180, 4VAC25-150-190, 4VAC25-150-200, 4VAC25-150-210, 4VAC25-150-220, 4VAC25-150-230, 4VAC25-150-240, 4VAC25-150-250, 4VAC25-150-260, 4VAC25-150-280, 4VAC25-150-300, 4VAC25-150-310, 4VAC25-150-340, 4VAC25-150-360, 4VAC25-150-380, 4VAC25-150-390, 4VAC25-150-420, 4VAC25-150-460, 4VAC25-150-490, 4VAC25-150-500, 4VAC25-150-510, 4VAC25-150-520, 4VAC25-150-530, 4VAC25-150-550, 4VAC25-150-560, 4VAC25-150-590, 4VAC25-150-600, 4VAC25-150-610, 4VAC25-150-620, 4VAC25-150-630, 4VAC25-150-650, 4VAC25-150-660, 4VAC25-150-670, 4VAC25-150-680, 4VAC25-150-690, 4VAC25-150-700, 4VAC25-150-711, 4VAC25-150-720, 4VAC25-150-730, 4VAC25-150-740, 4VAC25-150-750).

Statutory Authority: §§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Public Hearing Information:

October 23, 2009 - 1 p.m. - Department of Mines, Minerals and Energy, 3405 Mountain Empire Road, Buchanan-Smith Building, Conference Room 219, Big Stone Gap, VA

Public Comments: Public comments may be submitted until 5 p.m. on October 30, 2009.

Agency Contact: Tabitha Hibbitts Peace, Policy Analyst, Department of Mines, Minerals and Energy, 3405 Mountain Empire Road, P.O. Drawer 900, Big Stone Gap, VA 24219, telephone (276) 523-8212, FAX [phone], TTY [phone], or email [e-mail].

Basis: The Department of Mines, Minerals and Energy (DMME) has authority to promulgate this regulation under the authority found in §§ 45.1-161.3 and 45.1-361.27 of the Code of Virginia.

Section 45.1-161.3 of the Code of Virginia empowers DMME, with the approval of the director, to promulgate regulations necessary or incidental to the performance of duties or execution of powers under Title 45.1 of the Code of Virginia.

Section 45.1-361.27 of the Code of Virginia empowers the director to promulgate and enforce rules, regulations, and orders necessary to ensure the safe and efficient development and production of gas and oil resources located in the Commonwealth.

Purpose: The Department of Mines, Minerals and Energy has determined the proposed regulatory amendments to various sections of 4VAC25-150 are necessary to protect the health, welfare, and safety of citizens, reduce workload, and increase efficiency for permit applicants. Technical corrections are necessary for accuracy and to provide clear language consistent with state law. These amendments will aid the gas and oil industry and the Virginia Gas and Oil Board in the approval and regulation of gas and oil permits.

Substance: As a result of periodic review, the Department of Mines, Minerals and Energy is amending 4VAC25-150, Virginia Gas and Oil Regulation. Sections of 4VAC25-150 will be amended to correct technical areas for accuracy, improve worker safety, and provide clarity. These amendments will aid the gas and oil industry and the Gas and Oil Board in the review and regulation of gas and oil permits.

Amending parts of 4VAC25-150-150 will reduce workload and increase efficiency for applicants by providing flexibility and economy to the permit process. 4VAC25-150-90 will be updated to include symbols that are consistent with current industry usage and available CAD technology.

Amendments to 4VAC25-150-80, 4VAC25-150-260, 4VAC25-150-300, 4VAC25-150-380, and 4VAC25-150-630 will protect the safety and health of oil and gas industry employees.

An amendment to 4VAC25-150-90 is being made to bring consistency to data submission requirements for the Division of Gas and Oil. The use of latitude and longitude and the Virginia Coordinate System of 1927 have been replaced by the Virginia Coordinate System of 1983 in other Division of Gas and Oil regulations. Current industry practice to use the more modern 1983 coordinate system for describing the locations of wells and core holes. Applicants for permits under this chapter must currently convert their coordinates back to the 1927 system, as required by the regulation, in order to submit them to the Department of Mines, Minerals and Energy’s Division of Gas and Oil. The amendment will allow applicants to use the updated 1983 coordinate system.

Issues: These regulatory actions are expected to provide technical corrections, improve clarity, increase efficiency, and to restore consistency with other chapters of regulation. These amendments regarding process will aid the gas and oil industry, as well as the Gas and Oil Board in the review and regulation of gas and oil permits. Reduced workload and increased efficiency for applicants will occur by providing flexibility and economy in the permit process.

The Department of Planning and Budget's Economic Impact Analysis:

Summary of the Proposed Amendments to Regulation. As a result of periodic review, the Department of Mines, Minerals and Energy (DMME) proposes numerous amendments to the Virginia Gas & Oil Regulations, including: 1) adding a definition for "red zone," 2) updating required symbols to the current industry standard CAD template, 3) adding a requirement that operations plan specify "red zone" areas, 4) increasing the application fee for transfer of permit rights from $65 to $75, 5) eliminating the requirement to mail pemit approvals to all persons given notice of the hearing, but maintaining the requirement to mail pemit denials to all persons given notice of the hearing, 6) extending reporting deadlines from 30 or 45 days to 90 days, 7) changing required notification of ground-disturbing activity from at least two working days prior to commencing ground-disturbing activity to at least 48 hours prior, 8) adding requirement for posting red zone signs, 9) reduce specificity of topsoil requirement so that any soil suitable for stabilizing the site with vegetation can be used, 10) allowing any form of variance request, 11) changing the specific circumstances under which an inclination survey must be performed, 12) adding a requirement that all pits be reclaimed within 90 days unless a variance is granted by the field inspector, and 13) adding a new section defining the length of time wells can remain shut in without a requirement for plugging.

Result of Analysis. The benefits exceed the costs for one or more proposed changes. There is insufficient data to accurately compare the magnitude of the benefits versus the costs for other changes.

Estimated Economic Impact. DMME proposes several amendments to these regulations merely reflect modern usage such as GPS, electronic communication, and the use of the current industry standard CAD template. Virginia’s gas and oil industry through the representation of the Virginia Gas and Oil Association (VGOA) has expressed approval of these changes and generally agrees that these types of changes are beneficial.

The proposed regulations define "red zone" as a zone in or contiguous to a permitted area that could have potential hazards to workers or to the public. Further, the proposed regulations require that operation plans identify red zone areas and that red zone signs be posted to alert the public and workers of the hazards in the area. VGOA estimates that this proposed requirement will add $1,000 to $2,000 of cost per plan and approximately $100 per sign, but agrees that it will potentially significantly reduce safety risks. Thus, these proposed changes likely produce a net benefit.

DMME proposes to increase the application fee for transfer of permit rights from $65 to $75. According to the agency even the proposed higher fee falls far short of covering their regulating expenses. VGOA does not oppose the fee increase.

Under the current regulations, in hearings on objections to permit applications the DMME director must mail his decision to all parties given notice of the hearing. DMME proposes to eliminate the requirement to mail pemit approvals to all persons given notice of the hearing, but to continue to require that pemit denials be sent to all persons given notice of the hearing. Parties directly involved would still be notified of permit approvals of course. The proposed change would reduce some small costs in time for DMME staff, but it is unclear whether the small reduction in time cost exceeds the reduced benefit in informing interested members of the public.

The current regulations include various reporting deadlines of either 30 days or 45 days which DMME proposes to extend to 90 days. The extra time will be beneficial for firms and DMME states that the extra time for reporting is unlikely to significantly affect health and safety. Thus, these proposed longer deadlines will likely produce a net benefit.

The agency proposes to change the required notification of ground-disturbing activity from at least two working days prior to commencing ground-disturbing activity to at least 48 hours prior. According to DMME, staff is available to receive notification on the weekends and 48 hours notice is sufficient to ensure safety. This proposed change allows firms to not have to proceed with work one or two days sooner at times without negatively affected safety. Consequently, this proposed change produces a net benefit for the Commonwealth.

DMME also proposes some additional options for satisfying requirements that will reduce costs for firms without compromising safety or the environment. Under the current regulations during construction topsoil sufficient to provide a suitable growth medium for permanent stabilization with vegetation must be used to stabilize the site. The agency proposes to permit the use of soil that is not necessarily topsoil, but which still can provide a suitable growth medium for permanent stabilization with vegetation. Also the timing for acceptance of variances is less restrictive under the proposed regulations.

The current regulations require that an inclination survey be performed prior to drilling into a coal seam where active mining is being conducted. DMME proposes to instead require that an inclination survey be performed prior to drilling within 500 feet of a coal seam where workers are assigned travel, etc. According to DMME their definition of active mining includes where coal workers are not currently working; and thus under the proposed language there will be fewer instances where inclination surveys are required. VGOA estimates that inclination surveys cost $2,000 to $3,000 per well. Since only instances where coal workers are not present will be eliminated from when an inclination survey is required, the proposed change should not negatively affect safety while saving $2,000 to $3,000 per instance where the inclination survey is no longer required.

The regulations state that "Pits are to be temporary in nature and are to be reclaimed when the operations using the pit are complete. DMME proposes to add that "All pits shall be reclaimed within 90 days unless a variance is granted by the field inspector." Reclamation concerns meeting water quality standards. According to VGOA, mandatory reclamation within 90 days can significantly add to costs. VGOA states that drought conditions can cause pits to not meet water quality standards that would meet the standards under non-drought conditions, causing firms to spend thousands of dollars which they could have avoided if they were not required to act within 90 days. The counter argument would be that there are environmental costs to the pits not meeting water quality standards and perhaps the benefits of improved environment are worth those costs.

Abandoned wells are required to be plugged to prevent environmental damage and safety risks from leaks. DMME proposes to require that permittees submit either a well plugging plan or a future well production plan for wells that have been in non-producing status for two years. Further, the agency proposes that "In no circumstance shall a non-producing well remain un-plugged for more than a three year period unless approved by the director (of DMME)." The intent of this proposal is to limit the existence of non-producing wells that may be producing environmental damage through leaks.

The proposed plugging requirement may produce large costs and could discourage natural gas production. According to VGOA it costs approximately $20,000 to plug a well, and from $350,000 to $500,000 to drill a new well. VGOA states that it is essentially not feasible to unplug a plugged well, and thus would cost another $350,000 to $500,000 to re-drill a well at the site of a plugged well. The proposed plugging requirement would discourage some natural gas production (according to VGOA) in that the time frame that a well could be used would be reduced and thus the potential benefits of drilling in new locations would be reduced. Thus it is not clear that the potential environmental benefits of requiring plugging within three years would exceed the costs.

Businesses and Entities Affected. According to the Department of Mines, Minerals and Energy, four companies drill most oil and gas wells in Virginia and an unknown number of other companies may also undertake such activities from time to time. None of these would be defined as small businesses.

Localities Particularly Affected. The proposed regulations particularly affect the City of Norton and the following counties: Buchanan, Dickenson, Lee, Russell, Scott, Tazewell, Washington and Wise.

Projected Impact on Employment. Most of the proposed amendments would not significantly affect employment. The proposal to require plugging for wells not used for three years might discourage some natural gas drilling and might have some negative impact on employment.

Effects on the Use and Value of Private Property. Several of the proposed amendments add moderate costs for oil and gas firms in order to improve public safety and the environment. These changes may have some moderate positive affect on the value of neighboring properties. Some of the proposed amendments reduce costs foe firms without compromising safety or the environment. These changes will provide some counterbalance to the aforementioned increased costs. The proposal to requiring plugging for wells not in use for three years may produce larger costs for private firms.

Small Businesses: Costs and Other Effects. According to DMME, none of the firms directly affected by the proposed regulations are small businesses. Small businesses that serve the large firms may be indirectly affected.

Small Businesses: Alternative Method that Minimizes Adverse Impact. According to DMME, none of the firms directly affected by the proposed regulations are small businesses.

Real Estate Development Costs. This regulation concerns the use of land for gas and oil acquisition. Several proposed changes that increase public safety or reduce environmental risk, such as requiring red zone signs, add moderate costs. Some proposed changes, such as permitting the use of soil that is not necessarily topsoil, but which still can provide a suitable growth medium for permanent stabilization with vegetation, moderately reduce land use costs.

Legal Mandate. The Department of Planning and Budget (DPB) has analyzed the economic impact of this proposed regulation in accordance with § 2.2-4007.04 of the Administrative Process Act and Executive Order Number 36 (06). Section 2.2-4007.04 requires that such economic impact analyses include, but need not be limited to, the projected number of businesses or other entities to whom the regulation would apply, the identity of any localities and types of businesses or other entities particularly affected, the projected number of persons and employment positions to be affected, the projected costs to affected businesses or entities to implement or comply with the regulation, and the impact on the use and value of private property. Further, if the proposed regulation has adverse effect on small businesses, § 2.2-4007.04 requires that such economic impact analyses include (i) an identification and estimate of the number of small businesses subject to the regulation; (ii) the projected reporting, recordkeeping, and other administrative costs required for small businesses to comply with the regulation, including the type of professional skills necessary for preparing required reports and other documents; (iii) a statement of the probable effect of the regulation on affected small businesses; and (iv) a description of any less intrusive or less costly alternative methods of achieving the purpose of the regulation. The analysis presented above represents DPB’s best estimate of these economic impacts.

Agency's Response to the Department of Planning and Budget's Economic Impact Analysis: The agency concurs with Department of Planning and Budget's economic impact analysis.

Summary:

As a result of periodic review, the Department of Mines, Minerals and Energy is amending 4VAC25-150, Virginia Gas and Oil Regulation. Sections within 4VAC25-150 will be amended to correct technical areas for accuracy, improve worker safety, and provide clarity. These amendments will aid the gas and oil industry and the Gas and Oil Board in the review and regulation of gas and oil permits. Amending 4VAC25-150-150 will reduce workload and increase efficiency for applicants by providing flexibility and economy to the permit process. 4VAC25-150-90 will be updated to include symbols that are consistent with current industry usage and available CAD technology. Amendments to 4VAC25-150-80, 4VAC25-150-260, 4VAC25-150-300, 4VAC25-150-380, and 4VAC25-150-630 will protect the safety and health of oil and gas industry employees. An amendment to 4VAC25-150-90 is being made to bring consistency to data submission requirements for the Division of Gas and Oil.

Part I
Standards of General Applicability

Article 1
General Information

4VAC25-150-10. Definitions.

The following words and terms, when used in this chapter, shall have the following meaning unless the context clearly indicates otherwise:

"Act" means the Virginia Gas and Oil Act of 1990, Chapter 22.1 (§ 45.1-361.1 et seq.) of Title 45.1 of the Code of Virginia.

"Adequate channel" means a watercourse that will convey the designated frequency storm event without overtopping its banks or causing erosive damage to the bed, banks and overbank sections.

"Applicant" means any person or business who files an application with the Division of Gas and Oil.

"Approved" means accepted as suitable for its intended purpose when included in a permit issued by the director or determined to be suitable in writing by the director.

"Berm" means a ridge of soil or other material constructed along an active earthen fill to divert runoff away from the unprotected slope of the fill to a stabilized outlet or sediment trapping facility.

"Board" means the Virginia Gas and Oil Board.

"Bridge plug" means an obstruction intentionally placed in a well at a specified depth.

"Cased completion" means a technique used to make a well capable of production in which production casing is set through the productive zones.

"Cased/open hole completion" means a technique used to make a well capable of production in which at least one zone is completed through casing and at least one zone is completed open hole.

"Casing" means all pipe set in wells except conductor pipe and tubing.

"Causeway" means a temporary structural span constructed across a flowing watercourse or wetland to allow construction traffic to access the area without causing erosion damage.

"Cement" means hydraulic cement properly mixed with water.

"Channel" means a natural stream or man-made waterway.

"Chief" means the Chief of the Division of Mines of the Department of Mines, Minerals and Energy.

"Coal-protection string" means a casing designed to protect a coal seam by excluding all fluids, oil, gas or gas pressure from the seam, except such as may be found in the coal seam itself.

"Cofferdam" means a temporary structure in a river, lake or other waterway for keeping the water from an enclosed area that has been pumped dry so that bridge foundations, pipelines, etc., may be constructed.

"Completion" means the process which results in a well being capable of producing gas or oil.

"Conductor pipe" means the short, large diameter string used primarily to control caving and washing out of unconsolidated surface formations.

"Corehole" means any shaft or hole sunk, drilled, bored or dug, that breaks or disturbs the surface of the earth as part of a geophysical operation solely for the purpose of obtaining rock samples or other information to be used in the exploration for coal, gas, or oil. The term shall not include a borehole used solely for the placement of an explosive charge or other energy source for generating seismic waves.

"Days" means calendar days.

"Denuded area" means land that has been cleared of vegetative cover.

"Department" means the Department of Mines, Minerals and Energy.

"Detention basin" means a stormwater management facility which temporarily impounds and discharges runoff through an outlet to a downstream channel. Infiltration is negligible when compared to the outlet structure discharge rates. The facility is normally dry during periods of no rainfall.

"Dike" means an earthen embankment constructed to confine or control fluids.

"Directional survey" means a well survey that measures the degree of deviation of a hole, or distance from the vertical and the direction of deviation from true vertical, and the distance and direction of points in the hole from vertical.

"Director" means the Director of the Department of Mines, Minerals and Energy or his authorized agent.

"Diversion" means a channel constructed for the purpose of intercepting surface runoff.

"Diverter" or "diverter system" means an assembly of valves and piping attached to a gas or oil well's casing for controlling flow and pressure from a well.

"Division" means the Division of Gas and Oil of the Department of Mines, Minerals and Energy.

"Erosion and sediment control plan" means a document containing a description of materials and methods to be used for the conservation of soil and the protection of water resources in or on a unit or group of units of land. It may include appropriate maps, an appropriate soil and water plan inventory and management information with needed interpretations, and a record of decisions contributing to conservation treatment. The plan shall contain a record of all major conservation decisions to ensure that the entire unit or units of land will be so treated to achieve the conservation objectives.

"Expanding cement" means any cement approved by the director which expands during the hardening process, including but not limited to regular oil field cements with the proper additives.

"Form prescribed by the director" means a form issued by the division, or an equivalent facsimile, for use in meeting the requirements of the Act or this chapter.

"Firewall" means an earthen dike or fire resistant structure built around a tank or tank battery to contain the oil in the event a tank ruptures or catches fire.

"Flume" means a constructed device lined with erosion-resistant materials intended to convey water on steep grades.

"Flyrock" means any material propelled by a blast that would be actually or potentially hazardous to persons or property.

"Gas well" means any well which produces or appears capable of producing a ratio of 6,000 cubic feet (6 Mcf) of gas or more to each barrel of oil, on the basis of a gas-oil ratio test.

"Gob well" means a coalbed methane gas well which is capable of producing coalbed methane gas from the de-stressed zone associated with any full-seam extraction of coal that extends above and below the mined-out coal seam.

"Groundwater" means all water under the ground, wholly or partially within or bordering the Commonwealth or within its jurisdiction, which has the potential for being used for domestic, industrial, commercial or agricultural use or otherwise affects the public welfare.

"Highway" means any public street, public alley, or public road.

"Inclination survey" means a well or corehole survey, using the surface location of the well or corehole as the apex, to determine the deviation of the well or corehole from the true vertical beneath the apex on the same horizontal subsurface plane survey taken inside a wellbore that measures the degree of deviation of the point of the survey from true vertical.

"Inhabited building" means a building, regularly occupied in whole or in part by human beings, including, but not limited to, a private residence, church, school, store, public building or other structure where people are accustomed to assemble except for a building being used on a temporary basis, on a permitted site, for gas, oil, or geophysical operations.

"Intermediate string" means a string of casing that prevents caving, shuts off connate water in strata below the water-protection string, and protects strata from exposure to lower zone pressures.

"Live watercourse" means a definite channel with bed and banks within which water flows continuously.

"Mcf" means, when used with reference to natural gas, 1,000 cubic feet of gas at a pressure base of 14.73 pounds per square inch gauge and a temperature base of 60°F.

"Mud" means any mixture of water and clay or other material as the term is commonly used in the industry a mixture of materials that creates a weighted fluid to be circulated down hole during drilling operations for the purpose of lubricating and cooling the bit, removing cuttings, and controlling formation pressures and fluid.

"Natural channel" or "natural stream" means nontidal waterways that are part of the natural topography. They usually maintain a continuous or seasonal flow during the year, and are characterized as being irregular in cross section with a meandering course.

"Nonerodible" means a material such as riprap, concrete or plastic that will not experience surface wear due to natural forces.

"Oil well" means any well which produces or appears capable of producing a ratio of less than 6,000 cubic feet (6 Mcf) of gas to each barrel of oil, on the basis of a gas-oil ratio test.

"Open hole completion" means a technique used to make a well capable of production in which no production casing is set through the productive zones.

"Person" means any individual, corporation, partnership, association, company, business, trust, joint venture or other legal entity.

"Petitioner" means any person or business who files a petition, appeal, or other request for action with the Division of Gas and Oil or the Virginia Gas and Oil Board.

"Plug" means the stopping sealing of, or a device or material used for the stopping sealing of, the flow of water, a gas or oil wellbore or casing to prevent the migration of water, gas, or oil from one stratum to another.

"Pre-development" means the land use and site conditions that exist at the time that the operations plan is submitted to the division.

"Produced waters" means water or fluids produced from a gas well, oil well, coalbed methane gas well or gob well as a byproduct of producing gas, oil or coalbed methane gas.

"Producer" means a permittee operating a well in Virginia that is producing or is capable of producing gas or oil.

"Production string" means a string of casing or tubing through which the well is completed and may be produced and controlled.

"Red shales" means the undifferentiated shaley portion of the bluestone Bluestone formation normally found above the Pride Shale Member of the formation, and extending upward to the base of the Pennsylvanian strata, which red shales are predominantly red and green in color but may occasionally be gray, grayish green and grayish red.

"Red zone" is a zone in or contiguous to a permitted area that could have potential hazards to workers or to the public.

"Retention basin" means a stormwater management facility which, similar to a detention basin, temporarily impounds runoff and discharges its outflow through an outlet to a downstream channel. A retention basin is a permanent impoundment.

"Sediment basin" means a depression formed from the construction of a barrier or dam built to retain sediment and debris.

"Sheet flow," also called overland flow, means shallow, unconcentrated and irregular flow down a slope. The length of strip for sheet flow usually does not exceed 200 feet under natural conditions.

"Slope drain" means tubing or conduit made of nonerosive material extending from the top to the bottom of a cut or fill slope.

"Special diligence" means the activity and skill exercised by a good businessman businessperson in his a particular specialty, which must be commensurate with the duty to be performed and the individual circumstances of the case; not merely the diligence of an ordinary person or nonspecialist.

"Stabilized" means able to withstand normal exposure to air and water flows without incurring erosion damage.

"Stemming" means the inert material placed in a borehole after an explosive charge for the purpose of confining the explosion gases in the borehole or the inert material used to separate the explosive charges (decks) in decked holes.

"Storm sewer inlet" means any structure through which stormwater is introduced into an underground conveyance system.

"Stormwater management facility" means a device that controls stormwater runoff and changes the characteristics of that runoff, including but not limited to, the quantity, quality, the period of release or the velocity of flow.

"String of pipe" or "string" means the total footage of pipe of uniform size set in a well. The term embraces conductor pipe, casing and tubing. When the casing consists of segments of different size, each segment constitutes a separate string. A string may serve more than one purpose.

"Sulfide stress cracking" means embrittlement of the steel grain structure to reduce ductility and cause extreme brittleness or cracking by hydrogen sulfide.

"Surface mine" means an area containing an open pit excavation, surface operations incident to an underground mine, or associated activities adjacent to the excavation or surface operations, from which coal or other minerals are produced for sale, exchange, or commercial use; and includes all buildings and equipment above the surface of the ground used in connection with such mining.

"Target formation" means the geologic gas or oil formation identified by the well operator in his application for a gas, oil or geophysical drilling permit.

"Temporary stream crossing" means a temporary span installed across a flowing watercourse for use by construction traffic. Structures may include bridges, round pipes or pipe arches constructed on or through nonerodible material.

"Ten-year storm" means a storm that is capable of producing rainfall expected to be equaled or exceeded on the average of once in 10 years. It may also be expressed as an exceedance probability with a 10% chance of being equaled or exceeded in any given year.

"Tubing" means the small diameter string set after the well has been drilled from the surface to the total depth and through which the gas or oil or other substance is produced or injected.

"Two-year storm" means a storm that is capable of producing rainfall expected to be equaled or exceeded on the average of once in two years. It may also be expressed as an exceedance probability with a 50% chance of being equaled or exceeded in any given year.

"Vertical ventilation hole" means any hole drilled from the surface to the coal seam used only for the safety purpose of removing gas from the underlying coal seam and the adjacent strata, thus, removing the gas that would normally be in the mine ventilation system.

"Water bar" means a small obstruction constructed across the surface of a road, pipeline right-of-way, or other area of ground disturbance in order to interrupt and divert the flow of water down the on a grade of the road and divert the water to provide for sediment control for the purpose of controlling erosion and sediment migration.

"Water-protection string" means a string of casing designed to protect groundwater-bearing strata.

4VAC25-150-60. Due dates for reports and decisions.

A. Where the last day fixed for (i) submitting a request for a hearing, holding a hearing or issuing a decision in an enforcement action under Article 3 (4VAC25-150-170 et seq.) of this part, (ii) submitting a monthly or annual report under Article 4 (4VAC25-150-210 et seq.) of this part, (iii) submitting a report of commencement of activity under 4VAC25-150-230, (iv) submitting a drilling report, a completion report or other report under 4VAC25-150-360, or (v) submitting a plugging affidavit under 4VAC25-150-460 or any required report falls on a Saturday, Sunday, or any day on which the Division of Gas and Oil office is closed as authorized by the Code of Virginia or the Governor, the required action may be done on the next day that the office is open.

B. All submittals to or notifications of the Division of Gas and Oil identified in subsection A of this section shall be made to the division office no later than 5 p.m. on the day required by the Act or by this chapter.

Article 2
Permitting

4VAC25-150-80. Application for a permit.

A. Applicability.

1. Persons required in § 45.1-361.29 of the Code of Virginia to obtain a permit or permit modification shall apply to the division on the forms prescribed by the director. All lands on which gas, oil or geophysical operations are to be conducted shall be included in a permit application.

2. In addition to specific requirements for variances in other sections of this chapter, any applicant for a variance shall, in writing, document the need for the variance and describe the alternate measures or practices to be used.

B. The application for a permit shall, as applicable, be accompanied by the fee in accordance with § 45.1-361.29 of the Code of Virginia, the bond in accordance with § 45.1-361.31 of the Code of Virginia, and the fee for the Orphaned Well Fund in accordance with § 45.1-361.40 of the Code of Virginia.

C. Each application for a permit shall include information on all activities, including those involving associated facilities, to be conducted on the permitted site. This shall include the following:

1. The name and address of:

a. The gas, oil or geophysical applicant;

b. The agent required to be designated under § 45.1-361.37 of the Code of Virginia; and

c. Each person whom the applicant must notify under § 45.1-361.30 of the Code of Virginia;

2. The certifications required in § 45.1-361.29 E of the Code of Virginia;

3. The proof of notice to affected parties required in § 45.1-361.29 E of the Code of Virginia, which shall be:

a. A copy of a signed receipt or electronic return receipt of delivery of notice by certified mail;

b. A copy of a signed receipt acknowledging delivery of notice by hand; or

c. If all copies of receipt of delivery of notice by certified mail have not been signed and returned within 15 days of mailing, a copy of the mailing log or other proof of the date the notice was sent by certified mail, return receipt requested;

4. If the application is for a permit modification, proof of notice to affected parties, as specified in subdivision C 3 of this section;

4. 5. Identification of the type of well or other gas, oil or geophysical operation being proposed;

5. 6. The plat in accordance with 4VAC25-150-90;

6. 7. The operations plan in accordance with 4VAC25-150-100;

7. 8. The information required for operations involving hydrogen sulfide in accordance with 4VAC25-150-350;

8. 9. The location where the Spill Prevention Control and Countermeasure (SPCC) plan is available, if one is required;

9. 10. The Department of Mines, Minerals and Energy, Division of Mined Land Reclamation's permit number for any area included in a Division of Mined Land Reclamation permit on which a proposed gas, oil or geophysical operation is to be located;

10. 11. For an application for a conventional well, the information required in 4VAC25-150-500;

11. 12. For an application for a coalbed methane gas well, the information required in 4VAC25-150-560;

12. 13. For an application for a geophysical operation, the information required in 4VAC25-150-670; and

13. 14. For an application for a permit to drill for gas or oil in Tidewater Virginia, the environmental impact assessment meeting the requirements of § 62.1-195.1 B of the Code of Virginia.

D. After July 1, 2009, all permit applications and plats submitted to the division shall be in electronic form or a format prescribed by the director.

4VAC25-150-90. Plats.

A. When filing an application for a permit for a well or corehole, the applicant also shall file an accurate plat certified by a licensed professional engineer or licensed land surveyor on a scale, to be stated thereon, of 1 inch equals 400 feet (1:4800). The scope of the plat shall be large enough to show the board approved unit and all areas within the greater of 750 feet or one half of the distance specified in § 45.1-361.17 of the Code of Virginia from the proposed well or corehole, or within a unit established by the board for the subject well. The plat shall be submitted on a form prescribed by the director.

B. The known courses and distances of all property lines and lines connecting the permanent points, landmarks or corners within the scope of the plat shall be shown thereon. All lines actually surveyed shall be shown as solid lines. Lines taken from deed or chain of title descriptions only shall be shown by broken lines. All property lines shown on a plat shall agree with surveys, deed descriptions, or acreages used in county records for tax assessment purposes.

C. A north and south line shall be given and shown on the plat, and point to the top of the plat.

D. Wells or coreholes shall be located on the plat as follows:

1. The proposed or actual surface elevation of the subject well or corehole shall be shown on the plat, within an accuracy of one vertical foot. The surface elevation shall be tied to either a government benchmark or other point of proven elevation by differential or aerial survey, or by trigonometric leveling, or by Global Positioning System (GPS) survey. The location of the government benchmark or the point of proven elevation and the method used to determine the surface elevation of the subject well or corehole shall be noted and described on the plat.

2. The proposed or actual horizontal location of the subject well or corehole determined by survey shall be shown on the plat. The proposed or actual well or corehole location shall be shown in accordance with the Virginia Coordinate System of 1983, as defined in Chapter 17 (§ 55-287 et seq.) of Title 55 of the Code of Virginia, also known as the State Plane Coordinate System.

3. The courses and distances of the well or corehole location from two permanent points or landmarks on the tract shall be shown; such landmarks shall be set stones, iron pipes, T-rails or other manufactured monuments, including mine coordinate monuments, and operating or abandoned wells which are platted to the accuracy standards of this section and on file with the division. If temporary points are to be used to locate the actual well or corehole location as provided for in 4VAC25-150-290, the courses and distances of the well or corehole location from the two temporary points shall be shown.

4. Any other well, permitted or drilled, within the distance specified in § 45.1-361.17 of the Code of Virginia or the distance to the nearest well completed in the same pool, whichever is less, or within the boundaries of a drilling unit established by the board around the subject well shall be shown on the plat or located by notation. The type of each well shall be designated by the following symbols as described in the Federal Geographic Data Committee (FGDC) Digital Cartographic Standard for Geologic Map Symbolization:

Symbols for additional features as required in 4VAC25-150-510, 4VAC25-150-590, and 4VAC25-150-680 should be taken from the FDGC standard where applicable.

E. Plats shall also contain:

1. For a conventional gas and oil or injection well, the information required in 4VAC25-150-510;

2. For a coalbed methane gas well, the information required in 4VAC25-150-590; or

3. For a corehole, the information required in 4VAC25-150-680.

F. Any subsequent application for a new permit or permit modification shall include an accurate copy of the well plat, updated as necessary to reflect any changes on the site, newly discovered data or additional data required since the last plat was submitted. Any revised plat shall be certified as required in subsection A of this section.

4VAC25-150-100. Operations plans.

A. Each application for a permit or permit modification shall include an operations plan, in a format approved by or on a form prescribed by the director. The operations plan and accompanying maps or drawings shall become part of the terms and conditions of any permit which is issued.

B. The applicant shall indicate how risks to the public safety or to the site and adjacent lands are to be managed, consistent with the requirements of § 45.1-361.27 B of the Code of Virginia, and shall provide a short narrative, if pertinent. The operations plan shall identify "red zone" areas.

4VAC25-150-110. Permit supplements and permit modifications.

A. Permit supplements.

1. Standard permit supplements. A permittee shall be allowed to submit a permit supplement when work being performed either:

a. Does not change the disturbance area as described in the original permit; or and

b. Involves activities previously permitted.

The permittee shall submit written documentation of the changes made to the permitted area within seven working no later than 30 days after completing the change. All other changes to the permit shall require a permit modification in accordance with § 45.1-361.29 of the Code of Virginia.

2. Emergency permit supplements. If a change must be implemented immediately for an area off the disturbance area as described in the original permit, or for an activity not previously permitted due to actual or threatened imminent danger to the public safety or to the environment, the permittee shall:

a. Take immediate action to minimize the danger to the public or to the environment;

b. Orally notify Notify the director as soon as possible of actions taken to minimize the danger and, if the director determines an emergency still exists and grants oral approval, commence additional changes if necessary; and

c. Submit a written supplement to the permit within seven working days of notifying the director with a written description of the emergency and action taken. The supplement shall contain a description of the activity which was changed, a description of the new activity, and any amended data, maps, plats, or other information required by the director. An incident report may also be required as provided for in 4VAC25-150-380.

Any changes to the permit are to be temporary and restricted to those that are absolutely necessary to minimize danger. Any permanent changes to the permit shall require a permit modification as provided for in subsection B of this section.

B. Permit modifications.

1. Applicability. All changes to the permit which do not fit the description contained in subsection A of this section shall require a permit modification in accordance with § 45.1-361.29 of the Code of Virginia.

2. Notice and fees. Notice of a permit modification shall be given in accordance with § 45.1-361.30 of the Code of Virginia. The application for a permit modification shall be accompanied, as applicable, by the fee in accordance with § 45.1-361.29 of the Code of Virginia and the bond in accordance with § 45.1-361.31 of the Code of Virginia.

3. Waiver of right to object. Upon receipt of notice, any person may, on a form approved by the director, waive the time requirements and their right to object to a proposed permit modification. The department shall be entitled to rely upon the waiver to approve the permit modification.

4. Permit modification. The permittee shall submit a written application for a permit modification on a form prescribed by the director. The permittee may not undertake the proposed work until the permit modification has been issued. The As appropriate, the application shall include, but not be limited to:

a. The name and address of:

(1) The permittee; and

(2) Each person whom the applicant must notify under § 45.1-361.30 of the Code of Virginia;

b. The certifications required in § 45.1-361.29 E of the Code of Virginia;

c. The proof of notice required in § 45.1-361.29 E of the Code of Virginia, as provided for in 4VAC25-150-80 C 3;

d. Identification of the type of work for which a permit modification is requested;

e. The plat in accordance with 4VAC25-150-90;

f. All data, maps, plats and plans in accordance with 4VAC25-150-100 necessary to describe the activity proposed to be undertaken;

g. When the permit modification includes abandoning a gas or oil well as a water well, a description of the plugging to be completed up to the water-bearing formation and a copy of the permit issued for the water well by the Virginia Department of Health;

h. The information required for operations involving hydrogen sulfide in accordance with 4VAC25-150-350 if applicable to the proposed operations;

i. The location where the Spill Prevention Control and Countermeasure (SPCC) plan is available, if one has been developed for the site of the proposed operations;

j. The Department of Mines, Minerals and Energy, Division of Mined Land Reclamation's permit number for any area included in a Division of Mined Land Reclamation permit; and

k. The information, as appropriate, required in 4VAC25-150-500, 4VAC25-150-560, or 4VAC25-150-670, or 4VAC25-150-720.

4VAC25-150-120. Transfer of permit rights.

A. Applicability.

1. No transfer of rights granted by a permit shall be made without prior approval from the director.

2. Any approval granted by the director of a transfer of permit rights shall be conditioned upon the proposed new operator complying with all requirements of the Act, this chapter and the permit.

B. Application. Any person requesting a transfer of rights granted by a permit shall submit a written application on a form prescribed by the director. The application shall be accompanied by a fee of $65 $75 and bond, in the name of the person requesting the transfer, in accordance with § 45.1-361.31 of the Code of Virginia. The application shall contain, but is not limited to:

1. The name and address of the current permittee, the current permit number and the name of the current operation;

2. The name and address of the proposed new operator and the proposed new operations name;

3. Documentation of approval of the transfer by the current permittee;

4. If the permit was issued on or before September 25, 1991, an updated operations plan, in accordance with 4VAC25-150-100, showing how all permitted activities to be conducted by the proposed new permittee will comply with the standards of this chapter;

5. If the permit was issued on or before September 25, 1991, for a well, a plat meeting the requirements of 4VAC25-150-90 updated to reflect any changes on the site, newly discovered data or additional data required since the last plat was submitted, including the change in ownership of the well; and

6. If the permit was issued on or before September 25, 1991, if applicable, the docket number and date of recordation of any order issued by the board for a pooled unit, pertaining to the current permit.

C. Standards for approval. The director shall not approve the transfer of permit rights unless when the proposed new permittee:

1. Has registered with the department in accordance with § 45.1-361.37 of the Code of Virginia;

2. Has posted acceptable bond in accordance with § 45.1-361.31 of the Code of Virginia; and

3. Has no outstanding debt pursuant to § 45.1-361.32 of the Code of Virginia.

D. The new permittee shall be responsible for any violations of or penalties under the Act, this chapter, or conditions of the permit after the director has approved the transfer of permit rights.

4VAC25-150-135. Waiver of right to object to permit applications.

Upon receipt of notice, any person may, on a form approved by the director, waive the time requirements and their right to object to a proposed permit application. The department division shall be entitled to rely upon the waiver to approve the permit application.

4VAC25-150-140. Objections to permit applications.

A. Objections shall be filed in writing, at the office of the Division division, in accordance with § 45.1-361.35 of the Code of Virginia. The director shall notify affected parties of an objection as soon as practicable.

B. If after the director has considered notice to be given under 4VAC25-150-130 B of this chapter, a person submits an objection with proof of receipt of actual notice within 15 days prior to submitting the objection, then the director shall treat the objection as timely.

C. Objections to an application for a new or modified permit shall contain:

1. The name of the person objecting to the permit;

2. The date the person objecting to the permit received notice of the permit application;

3. Identification of the proposed activity being objected to;

4. A statement of the specific reason for the objection;

5. A request for a stay to the permit, if any, together with justification for granting a stay; and

6. Any other information the person objecting to the permit wishes to provide.

D. When deciding to convene a hearing pursuant to § 45.1-361.35 of the Code of Virginia, the director shall consider the following:

1. Whether the person objecting to the permit has standing to object as provided in § 45.1-361.30 of the Code of Virginia;

2. Whether the objection is timely; and

3. Whether the objection meets the applicable standards for objections as provided in § 45.1-361.35 of the Code of Virginia.

E. If the director decides not to hear the objection, then he shall notify the person who objects and the permit applicant in writing, indicating his reasons for not hearing the objection, and shall advise the objecting person of his right to appeal the decision.

4VAC25-150-150. Hearing and decision on objections to permit applications.

A. In any hearing on objections to a permit application:

1. The hearing shall be an informal fact finding hearing in accordance with the Administrative Process Act, § 9-6.14:11 2.2-4019 of the Code of Virginia.

2. The permit applicant and any person with standing in accordance with § 45.1-361.30 of the Code of Virginia may be heard.

3. Any valid issue in accordance with § 45.1-361.35 of the Code of Virginia may be raised at the hearing. The director shall determine the validity of objections raised during the hearing.

B. The director shall, as soon after the hearing as practicable, issue his decision in writing and hand deliver or send the decision by certified mail to all parties to the hearing. The director shall mail the decision, or a summary of the decision, to all other persons given notice of the hearing. The decision shall include:

1. The subject, date, time and location of the hearing;

2. The names of the persons objecting to the permit;

3. A summary of issues and objections raised at the hearing;

4. Findings of fact and conclusions of law;

5. The text of the decision, including any voluntary agreement; and

6. Appeal rights.

C. Should the director deny the permit issuance and allow the objection, a written notice of the decision shall be sent to any person receiving notice of the permit.

4VAC25-150-160. Approval of permits and permit modifications.

A. Permits, permit modifications, permit renewals, and transfer of permit rights shall be granted in writing by the director.

B. The director may not issue a permit, permit renewal, or permit modification prior to the end of the time period for filing objections pursuant to § 45.1-361.35 of the Code of Virginia unless, upon receipt of notice, any person may, on a form approved by the director, waive the time requirements and their right to object to a proposed permit application or permit modification application. The department division shall be entitled to rely upon the waiver to approve the permit application or permit modification.

C. The director may not issue a permit to drill for gas or oil in Tidewater Virginia until he has considered the findings and recommendations of the Department of Environmental Quality, as provided for in § 62.1-195.1 of the Code of Virginia and, where appropriate, has required changes in the permitted activity based on the Department of Environmental Quality's recommendations.

D. The provisions of any order of the Virginia Gas and Oil Board that govern a gas or oil well permitted by the director shall become conditions of the permit.

4VAC25-150-180. Notices of violation.

A. The director may issue a notice of violation if he finds a violation of any of the following:

1. Chapter 22.1 (§ 45.1-361.1 et seq.) of Title 45.1 of the Code of Virginia;

2. This chapter;

3. 4VAC25 Chapter 160 (4VAC25-160-10 et seq.) entitled "The Virginia Gas and Oil Board Regulation";

4. Any board order; or

5. Any condition of a permit, which does not create an imminent danger or harm for which a closure order must be issued under 4VAC5-150-190.

B. A notice of violation shall be in writing, signed, and set forth with reasonable specificity:

1. The nature of the violation, including a reference to the section or sections of the Act, applicable regulation, order or permit condition which has been violated;

2. A reasonable description of the portion of the operation to which the violation applies, including an explanation of the condition or circumstance that caused the portion of the operation to be in violation, if it is not self-evident in the type of violation itself;

3. The remedial action required, which may include interim steps; and

4. A reasonable deadline for abatement, which may include a deadline for accomplishment of interim steps.

C. The director may extend the deadline for abatement or for accomplishment of an interim step, if the failure to meet the deadline previously set was not caused by the permittee's lack of diligence. An extension of the deadline for abatement may not be granted when the permittee's failure to abate has been caused by a lack of diligence or intentional delay by the permittee in completing the remedial action required.

D. If the permittee fails to meet the deadline for abatement or for completion of any interim steps, the director shall issue a closure order under 4VAC25-150-190.

E. The director shall terminate a notice of violation by written notice to the permittee when he determines that all violations listed in the notice of violation have been abated.

F. A permittee issued a notice of violation may request, in writing to the director, an informal fact-finding hearing to review the issuance of the notice. This written request should shall be made within 10 days of receipt of the notice. The permittee may request, in writing to the director, an expedited hearing.

G. A permittee is not relieved of the duty to abate any violation under a notice of violation during an appeal of the notice. A permittee may apply for an extension of the deadline for abatement during an appeal of the notice.

H. The director shall issue a decision on any request for an extension of the deadline for abatement under a notice of violation within five days of receipt of such request. The director shall conduct an informal fact-finding hearing, in accordance with the Administrative Process Act, § 9-6.14:11 2.2-4019 of the Code of Virginia, no later than 10 days after receipt of the hearing request.

I. The director shall affirm, modify, or vacate the notice in writing to the permittee within five days of the date of the hearing.

4VAC25-150-190. Closure orders.

A. The director shall immediately order a cessation of operations or of the relevant portion thereof, when he finds any condition or practice which:

1. Creates or can be reasonably expected to create an imminent danger to the health or safety of the public, including miners; or

2. Causes or can reasonably be expected to cause significant, imminent, environmental harm to land, air or water resources.

B. The director may order a cessation of operations or of the relevant portion thereof, when:

1. A permittee fails to meet the deadline for abatement or for completion of any interim step under a notice of violation;

2. Repeated notices of violations have been issued for the same condition or practice; or

3. Gas, oil or geophysical operations are being conducted by any person without a valid permit from the Division of Gas and Oil.

C. A closure order shall be in writing, signed and shall set forth with reasonable specificity:

1. The nature of the condition, practice or violation;

2. A reasonable description of the portion of the operation to which the closure order applies;

3. The remedial action required, if any, which may include interim steps; and

4. A reasonable deadline for abatement, which may include deadline for accomplishment of interim steps.

D. A closure order shall require the person subject to the order to take all steps the director deems necessary to abate the violations covered by the order in the most expeditious manner physically possible.

E. If a permittee fails to abate a condition or practice or complete any interim step as required in a closure order, the director shall issue a show cause order under 4VAC25-150-200.

F. The director shall terminate a closure order by written notice to the person subject to the order when he determines that all conditions, practices or violations listed in the order have been abated.

G. A person issued a closure order may request, in writing to the director, an informal fact-finding hearing to review the issuance of the order within 10 days of receipt of the order. The person may request, in writing to the director, an expedited hearing within three days of receipt of the order.

H. A person is not relieved of the duty to abate any condition under, or comply with, any requirement of a closure order during an appeal of the order.

I. The director shall conduct an informal fact-finding hearing, in accordance with the Administrative Process Act, § 9-6.14:11 2.2-4019 of the Code of Virginia, no later than 15 days after the order was issued, or in the case of an expedited hearing, no later than five days after the order was issued.

J. The director shall affirm, modify, or vacate the closure order in writing to the person the order was issued to no later than five days after the date of the hearing.

4VAC25-150-200. Show cause orders.

A. The director may issue a show cause order to a permittee requiring justification for why his permit should not be suspended or revoked whenever:

1. A permittee fails to abate a condition or practice or complete any interim step as required in a closure order;

2. A permittee fails to comply with the provisions of 4VAC25 Chapter 160 (4VAC25-160-10 et seq.) entitled "The Virginia Gas and Oil Board Regulation"; or

3. A permittee fails to comply with the provisions of an order issued by the Virginia Gas and Oil Board.

B. A show cause order shall be in writing, signed, and set forth with reasonable specificity:

1. The permit number of the operation subject to suspension or revocation; and

2. The reason for the show cause order.

C. The permittee shall have five days from receipt of the show cause order to request in writing an informal fact-finding hearing.

D. The director shall conduct an informal fact-finding hearing, in accordance with the Administrative Process Act, § 9-6.14:11 2.2-4019 of the Code of Virginia, no later than five days after receipt of the request for the hearing.

E. The director shall issue a written decision within five days of the date of the hearing.

F. If the permit is revoked, the permittee shall immediately cease operations on the permit area and complete reclamation within the deadline specified in the order.

G. If the permit is suspended, the permittee shall immediately commence cessation of operations on the permit area and complete all actions to abate all conditions, practices or violations, as specified in the order.

Article 4
Reporting

4VAC25-150-210. Monthly reports.

A. Each producer shall submit a monthly report, on a form prescribed by the director or in a format approved by the director to the division no later than 45 90 days after the last day of each month.

B. Reports of gas production.

1. Every producer of gas shall report in Mcf the amount of production from each well.

2. Reports shall be summarized by county or city.

3. Reports shall provide the date of any new connection of a well to a gathering pipeline or other marketing system.

C. Reports of oil production.

1. Every producer of oil shall report in barrels the amount of oil production, oil on hand and oil delivered from each well.

2. Reports shall be summarized county or city.

3. Reports shall provide the date of any new connection of a well to a gathering pipeline or other marketing system.

D. Reports of shut-in wells. If a well is shut-in or otherwise not produced during any month, it shall be so noted on the monthly report.

4VAC25-150-220. Annual reports.

A. Each permittee shall submit a calendar-year annual report to the division by no later than March 31 of the next year.

B. The annual report shall include as appropriate:

1. A confirmation of the accuracy of the permittee's current registration filed with the division or a report of any change in the information;

2. The name, address and phone number or numbers of the persons to be contacted at any time in case of an emergency;

3. Production of gas or oil on a well-by-well and county-by-county or city-by-city basis for each permit or as prescribed by the director and the average price received for each Mcf of gas and barrel of oil;

4. Certification by the permittee that the permittee has paid all severance taxes for each permit; and

5. When required, payment to the Gas and Oil Plugging and Restoration Fund as required in § 45.1-361.32 of the Code of Virginia.; and

6. Certification by the permittee that bonds on file with the director have not been changed.

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 two working days 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 permit number 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 may shall notify the division, orally or in writing, within two working days 48 hours of commencing plugging activities.

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 ¼ 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.

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

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 Board of Mineral Mining Examiners, 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 Board of Mineral Mining Examiners, 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, or and damage to features described in the operations plan under 4VAC25-150-100 B.

1. When blasting is conducted within 200 feet of a pipeline or high-voltage transmission line, the blaster shall take due precautionary measures for the protection of the pipeline or high-voltage transmission line, and shall notify the owner of the facility or his agent that such blasting is intended.

2. Flyrock shall not be allowed to fall farther from the blast than one-half the distance between the blast and the nearest inhabited building, and in no case outside of the permitted area.

3. When blasting near a highway, the blaster must ensure that all traffic is stopped at a safe distance from the blast. Blasting areas shall be posted with warning signs.

4. All blasting shall be conducted during daylight hours, one-half hour before sunrise to one-half hour after sunset, unless approved by the director.

5. Misfires.

a. The handling of a misfired blast shall be under the direct supervision of a certified blaster.

b. When a misfire occurs, the blaster shall wait for at least 15 minutes or the period of time recommended by the manufacturer of the explosives and the detonator, whichever is longer, before allowing anyone to return to the blast site.

6. Blasting signals.

a. Before a blast is fired, a warning signal audible to a distance of at least one-half mile shall be given by the blaster in charge, who shall make certain that all surplus explosives are in a safe place and that all persons are at a safe distance from the blast site or under sufficient cover to protect them from the effects of the blast.

b. A code of warning signals shall be established and posted in one or more conspicuous places on the permitted site, and all employees shall be required to conform to the code.

7. Explosives and detonators shall be placed in substantial, nonconductive, closed containers (such as those containers meeting standards prescribed by the Institute of Makers of Explosives) when brought on the permitted site. Explosives and detonators shall not be kept in the same container. Containers shall be posted with warning signs.

8. Storage of explosives and detonators on gas, oil or geophysical sites is allowed only with prior approval by the director.

9. The permittee shall report to the Division of Gas and Oil by the quickest means possible any theft or unaccounted-for loss of explosives. When reporting such a theft or loss, the permittee shall indicate other local, state and federal authorities contacted.

10. Damaged or deteriorated explosives and detonators shall be destroyed by a certified blaster in accordance with the manufacturer's recommendations.

D. Ground vibration.

1. The ground-vibration limits in this subsection shall not apply on surface property owned or leased by the permittee, or on property for which the surface owner gives a written waiver specifically releasing the operator from the limits.

2. Blasting without seismographic monitoring. Blasting may be conducted by a certified blaster without seismographic monitoring provided the maximum charge is determined by the formula W = (D/D_s)² where W is the maximum weight of explosive in pounds per delay (eight milliseconds or greater); D is the actual distance in feet from the blast location to the nearest inhabited building; and D_s is the scaled distance factor to be applied without seismic monitoring, as found in Table 1.25.D-1.

TABLE 1.25.D-1: MAXIMUM ALLOWABLE PEAK VELOCITY
Distance (D) from blasting site in feet	Maximum allowable peak particle velocity (Vmax) for ground vibration, in inches/second	Scaled Distance Factor (Ds) to be applied without seismic monitoring
0 to 300	1.25	50
301 to 5000	1.00	55
5001 and beyond	0.75	65

3. Blasting with seismographic monitoring.

a. A permittee may use the ground-vibration limits in Table 1.25.D-2 to determine the maximum allowable peak particle velocity. If Table 1.25.D-2 is used, a seismographic record including both particle velocity and vibration-frequency levels shall be provided for each blast. The method for the analysis of the predominant frequency contained in the blasting records shall be approved by the director before implementation of this alternative blasting level.

b. The permittee may choose to record every blast. As long as the seismographic records indicate particle velocities have remained within the limits prescribed in Tables 1.25.D-1 or 1.25.D-2, the permittee shall be considered to be in compliance with this subsection.

.§§

c. Ground vibration shall be measured as the particle velocity. Particle velocity shall be recorded in three mutually perpendicular directions. The maximum allowable peak particle velocity shall apply to each of the three measurements.

d. All seismic tests carried out for the purposes of this section shall be analyzed by a qualified seismologist.

e. All seismic tests carried out for the purposes of this section shall be conducted with a seismograph that has an upper-end flat frequency response of at least 200 Hz.

E. Airblast shall not exceed the maximum limits prescribed in Table 1.25.E-1 at the location of any inhabited building. The 0.1 Hz or lower, flat response or C-weighted, slow response shall be used only when approved by the director.

Table 1.25.E-1: AIRBLAST LIMITS
Lower Frequency Limit of measuring system, in Hz (+3db)		Measurement Level, in db
0.1 Hz or Lower	Flat Response	134 Peak
2 Hz or Lower	Flat Response	133 Peak
6 Hz or Lower	Flat Response	129 Peak
C-weighted	Slow Response	105 Peak

F. If the director concludes that blasting on a particular site has potential to create unsafe conditions, then he may:

1. Require the permittee to monitor ground vibration and airblast for all blasts on the site for a specified period of time;

2. Impose more stringent limits on ground vibration and airblast levels than those specified in this section. The director may order the permittee to obtain an evaluation of the blast site by a vibration consultant or a technical representative of the explosives manufacturer before imposing a more stringent limit. Blasting may not resume on the site being evaluated until the evaluation and recommendations are submitted to the director, and the director has given his approval.

G. Records.

1. The permittee shall keep records of all blasts, and these records shall contain the following:

a. Name of company or contractor;

b. Location, date, and time of the blast;

c. Name, signature, and certification number of the blaster in charge;

d. Type of material blasted;

e. Number of holes; their burden and spacing;

f. Diameter and depth of the holes;

g. Types of explosives used;

h. Total amount of explosives used per hole;

i. Maximum weight of explosives per delay period;

j. Method of firing and the type of circuit;

k. Direction and distance in feet to the nearest inhabited building;

l. Weather conditions (including wind directions, etc.);

m. Height or length of stemming;

n. Description of any mats or other protection used;

o. Type of detonators and delay periods used; and

p. Any seismograph reports, including:

(1) The name and signature of the person operating the seismograph;

(2) The name of the person analyzing the seismograph record;

(3) The exact location of the seismograph in relation to the blast;

(4) The date and time of the reading; and

(5) The seismograph reading.

2. The permittee shall retain all records of blasting, including seismograph reports, for at least three years. On request, the permittee shall make these records available for inspection by the director division.

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 of the project, topsoil, soil sufficient to provide a suitable growth medium for permanent stabilization with vegetation shall be segregated and stockpiled. Soil stockpiles shall be stabilized used to stabilize the site in accordance with the standards of subdivisions C 2 and C 3 of this section to prevent erosion and sedimentation.

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.

	Distance Barrier Spacing
	Percent of Grade	Spacing of Ditchline Barriers in Feet
	3–5	135
	6–10	80
	11–15	60
	16+	40

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 pipeline abandoned in place shall be disconnected from all sources of natural gas or produced fluids and purged. 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, and copies of any right of way or lease agreements that apply to the abandonment or removal.

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:

	Percent of Grade	Spacing of Water Bars in Feet
	3–5	135
	6–10	80
	11–15	60
	16+	40

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, in the operations plan, 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.

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- 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 which is known to be underlain by coal seams, the following shall be required:

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

2. The horizontal location of the borehole 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 borehole into well or corehole within 500 feet of a coal seam in which active mining is being conducted within 500 feet of where the borehole will penetrate the seam where workers are assigned or travel, as well as any connected sealed or gob areas, or where a mine plan is on file with the Division of Mines, the permittee shall conduct an inclination survey to determine whether the deviation of the bore hole well or corehole exceeds one degree from true vertical. If the borehole 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 borehole well or corehole; and

d. Unless granted a variance by the director, correct the borehole 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 borehole 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 borehole 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 borehole 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 borehole 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 bore of a 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.

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 90 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.

B. Technical requirements.

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

2. Pits shall be lined in accordance with the requirements for liners in subdivision A 3 of this section. If solids are not to be disposed of in the pit, the permittee may request a variance to the liner specifications.

C. B. Operational requirements.

1. The integrity of lined pits must 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.

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 be surrounded by a have secondary containment achieved by constructing a dike or firewall with a capacity of 1½ 1-1/2 times the volume of the single tank, or largest tank in a battery of tanks 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.

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 4VAC25-150-340 C 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 500 feet 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.

If, after a diligent search, a groundwater source (such as a well or spring) cannot be found within 500 feet of the drilling location, the applicant may use water meeting the parameters listed in the Department of Environmental Quality's "Water Quality Criteria for Groundwater," 9VAC25-260-230 et seq. The analysis shall include, but is not limited to, the following items:

(1) Chlorides;

(2) Total dissolved solids;

(3) Hardness;

(4) Iron;

(5) Manganese;

(6) PH;

(7) Sodium; and

(8) Sulfate.

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.

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 30 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 30 90 days after the well is completed.

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 two years 90 days of reaching total depth, file with the division the results of any gamma ray, density, neutron and induction 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.

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

A. Accidents. Incidents. A permittee shall, by the quickest available means, notify the director division in the event of any unplanned off-site disturbance, fire, blowout, pit failure, hydrogen sulfide release, unanticipated loss of drilling fluids, or other accident incident resulting in serious personal injury or an actual or potential imminent danger to a worker, the environment, or public safety or welfare. 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; and

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.

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 minimum maximum period of three two years and be submitted to the director upon request.

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

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 "Water Quality Criteria for Groundwater" (9VAC25-260-230 et seq.). 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

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.

4VAC25-150-460. Identifying plugged wells and coreholes; plugging affidavit.

A. Abandoned wells and coreholes shall be permanently marked in a manner as follows:

1. The marker shall extend not less than 30 inches above the surface and enough below the surface to make the marker permanent.

2. The marker shall indicate the permittee's name, the well name, the permit number and date of plugging.

B. A permittee may apply for a variance from the director to use alternate permanent markers. Such alternate markers shall provide sufficient information for locating the abandoned well or corehole. Provisions shall also be made to provide for the physical detection of the abandoned well or corehole from the surface by magnetic or other means including a certified map with the utilization of current GPS surveys.

C. When any well or corehole has been plugged or replugged in accordance with 4VAC25-150-435, two persons, experienced in plugging wells or coreholes, who participated in the plugging of a well or corehole, shall complete the plugging affidavit designated by the director, setting forth the time and manner in which the well or corehole was plugged and filled, and the permanent marker was placed.

D. One copy of the plugging affidavit shall be retained by the permittee, one shall be mailed to any coal owner or operator on the tract where the well or corehole is located, and one shall be filed with the division within 30 90 days after the day the well was plugged.

Part II
Conventional Gas and Oil Wells and Class II Injection Wells

4VAC25-150-490. Applicability, conventional gas and oil wells and Class II injection wells.

A. Part II of this chapter sets forth requirements unique to conventional gas and oil wells and wells classified as Class II injection wells by the United States, Environmental Protection Agency under 40 CFR Part 146, Section 146.5.

B. Permittees must comply with the standards of general applicability in Part I of this chapter and with the standards for conventional gas and oil and Class II injection wells in this part, except that whenever the Environmental Protection Agency imposes a requirement under the Underground Injection Control (UIC) Program, 40 CFR Part 146, Sections 146.3, 146.4, 146.5, 146.6, 146.7, 146.8, 146.22 and 146.23 that governs an activity also governed by this chapter, the Environmental Protection Agency requirement shall control and become part of the permit issued under this chapter.

C. An application for a permit for a Class II injection well which has not been previously drilled under a permit from the director shall be submitted as an application for a new permit. An application for a permit for conversion of a permitted gas or oil well to a Class II injection well shall be submitted as an application for a permit modification.

D. The director shall not issue a permit for a Class II injection well until after the Environmental Protection Agency has issued its permit for the injection well.

4VAC25-150-500. Application for a permit, conventional well or Class II injection well.

A. In addition to the requirements of 4VAC25-150-80 or 4VAC25-150-110, every application for a permit or permit modification for a conventional gas or oil well or a Class II injection well shall contain:

1. The approximate depth to which the well is proposed to be drilled or deepened, or the actual depth to which the well has been drilled;

2. The approximate depth and thickness, if applicable, of all known coal seams, known groundwater-bearing strata, and other known gas or oil strata between the surface and the depth to which the well is proposed to be drilled;

3. If casing or tubing is proposed to be or has been set, a description of the entire casing program, including the size of each string of pipe, the starting point and depth to which each string is to be or has been set, and the extent to which each string is to be or has been cemented; and

4. If the proposed work is for a Class II injection well, a copy of either the permit issued by, or the permit application filed with the Environmental Protection Agency under the Underground Injection Control Program.

5. An explanation of the procedures to be followed to protect the safety of persons working in and around an underground coal mine for any conventional well or Class II injection well to be drilled within 200 feet of areas where workers are assigned or travel, as well as any connected sealed or gob areas, or where a one-year mine plan is on file with the Division of Mines; which shall, at a minimum, require that notice of such drilling be given by the permittee to the mine operator and the Chief of the Division of Mines at least 10 working days prior to drilling.

B. In addition to the requirements of 4VAC25-150-80 and 4VAC25-150-110, every application for a permit or permit modification for a conventional gas or oil well or a Class II injection well may contain, if the proposed work is to drill, redrill or deepen a well, a plan showing the proposed manner of plugging the well immediately after drilling if the proposed well work is unsuccessful.

4VAC25-150-510. Plats, conventional wells or Class II injection wells.

A. In addition to the requirements of 4VAC25-150-90, every plat for a conventional gas or oil well shall show:

1. The boundaries of any drilling unit established by the board around the subject well;

2. The boundaries and acreage of the tract on which the well is located or is to be located;

3. The boundaries and acreage of all other tracts within one-half of the distance specified in § 45.1-361.17 of the Code of Virginia or within one-half of the distance to the nearest well completed in the same pool, whichever is less, or within the boundaries of a drilling unit established by the board around the subject well;

4. Surface owners on the tract to be drilled and on all other tracts within the unit where the surface of the earth is to be disturbed;

5. All gas, oil or royalty owners on any tract located within one half of the distance specified in § 45.1-361.17 of the Code of Virginia or within one-half of the distance to the nearest well completed in the same pool, whichever is less, or within the boundaries of a drilling unit established by the board around the subject well;

6. Coal owners and mineral owners on the tract to be drilled and on all other tracts located within 500 feet of the subject well location;

7. Coal operators who have registered operations plans with the department for activities located on the tract to be drilled, or who have applied for or obtained a coal mine license, coal surface mine permit or a coal exploration notice or permit from the department with respect to all tracts within 500 feet of a proposed gas or oil well;

8. Any inhabited building, highway, railroad, stream, permitted surface mine or permitted mine opening within 500 feet of the proposed well; and

9. If the plat is for an enhanced oil recovery injection well, any other well within 2,500 feet of the proposed or actual well location, which shall be presumed to embrace the entire area to be affected by an enhanced oil recovery injection well in the absence of a board order establishing units in the target pool of a different size or configuration.

B. If the well location is underlain by known coal seams, or if required by the director, the well plat shall locate the well and two permanent points or landmarks with reference to the mine coordinate system if one has been established for the area of the well location, and shall in any event show all other wells, surface mines and mine openings within the scope of the plat.

4VAC25-150-520. Setback restrictions, conventional wells or Class II injection wells.

No permit shall be issued for any well to be drilled closer than 200 feet from any inhabited building unless site conditions as approved by the director warrant the permission of a lesser distance and there exists a lease or agreement between the operator and the owner of the inhabited building. A copy of the lease or agreement shall accompany the application for a permit.

4VAC25-150-530. Casing requirements for conventional gas or oil wells.

A. Water-protection string.

1. Except as provided in subdivision A 5 of this section, the permittee shall set a water-protection string to a point at least 300 feet below the surface or 50 feet below the deepest known groundwater horizon, whichever is deeper, circulated and cemented in to the surface. If the cement does not return to the surface, every reasonable attempt shall be made to fill the annular space by introducing cement from the surface.

2. The operator shall test or require the cementing company to test the cement mixing water for pH and temperature prior to mixing the cement and to record the results on the cementing ticket.

3. After the cement is placed, the operator shall wait a minimum of eight hours and allow the cement to achieve a calculated compressive strength of 500 psi before drilling, unless the director approves a shorter period of time. The wait-on-cement (WOC) time shall be recorded within the records kept at the drilling rig while drilling is taking place.

4. When requested by the director, the operator shall submit copies of cement tickets or other documents that indicate the above specifications have been followed.

5. A coal-protection string may also serve as a water-protection string.

B. Coal-protection strings.

1. When any well penetrates coal seams that have not been mined out, the permittee shall, except as provided in subdivisions B 2 and B 3 of this section, set a coal-protection string. The coal-protection string shall exclude all fluids, oil, gas and gas pressure except that which is naturally present in each coal seam. The coal-protection string shall also exclude all injected material or disposed waste from the coal seams and the wellbore. The string of casing shall be set to a point at least 50 feet below the lowest coal seam, or as provided in subdivision B 3 of this section, and shall be circulated and cemented from that point to the surface or to a point not less than 50 feet into the water-protection string or strings which are cemented to the surface.

2. For good cause shown, either before or after the permit is issued, when the procedure specified in subdivision B 1 is demonstrated by the permittee as not practical, the director may approve a casing program involving the cementing of a coal-protection string in multiple stages, or the cementing of two or more coal-protection strings, or the use of other alternative casing procedures. The director may approve the program provided he is satisfied that the result will be operationally equivalent to compliance with the provisions of subdivision B 1 of this section for the purpose of permitting the subsequent safe mining through of the well or otherwise protecting the coal seams as required by this section. In the use of multiple coal-protection strings, each string below the topmost string shall be cemented at least 50 feet into the next higher string or strings that are cemented to the surface and be verified by a cement top log.

3. Depth of coal-protection strings:

a. A coal-protection string shall be set to the top of the red shales in any area underlain by them unless, on a showing by the permittee in the permit application, the director has approved the casing point of the coal-protection string at some depth less than the top of the red shales. In such event, the permittee shall conduct a gamma ray/density log survey on an expanded scale to verify whether the well penetrates any coal seam in the uncased interval between the bottom of the coal-protection string as approved and the top of the red shales.

b. If an unanticipated coal seam or seams are discovered in the uncased interval, the permittee shall report the discovery in writing to the director. The permittee shall cement the next string of casing, whether a part of the intermediate string or the production string, in the applicable manner provided in this section for coal-protection strings, from a point at least 50 feet below the lowest coal seam so discovered to a point at least 50 feet above the highest coal seam so discovered.

c. The gamma ray/density log survey shall be filed with the director at the same time the driller's log is filed under 4VAC25-150-360.

d. When the director believes, after reviewing documentation submitted by the permittee, that the total drilling in any particular area has verified the deepest coal seam higher than the red shales, so that further gamma ray/density logs on an expanded scale are superfluous for the area, he may waive the constructing of a coal-protection string or the conducting of such surveys deeper than 100 feet below the verified depth of the deepest coal seam.

C. Coal-protection strings of wells drilled prior to July 1, 1982. In the case of wells drilled prior to July 1, 1982, through coal seams without coal-protection strings substantially as prescribed in subsection B of this section, the permittee shall retain such coal-protection strings as were set. During the life of the well, the permittee shall, consistent with a plan approved by the director, keep the annular spaces between the various strings of casing adjacent to coal seams open to the extent possible, and the top ends of all such strings shall be provided with casing heads, or such other approved devices as will permit the free passage of gas or oil and prevent filling of the annular spaces with dirt or debris.

D. Producing from more than one stratum. The casing program for any well designed or completed to produce from more than one stratum shall be designed in accordance with the appropriate standard practices of the industry.

E. Casing through voids.

1. When a well is drilled through a void, the hole shall be drilled at least 30 feet below the void, the annular space shall be cemented from the base of the casing up to the void and to the surface from the top of the void, and every reasonable attempt shall be made to fill the annular space from the top of the void to the surface, or it shall be cemented at least 50 feet into the next higher string or strings of casing that are cemented to the surface and be verified by a cement top log.

2. For good cause shown, the director may approve alternative casing procedures proposed by the permittee, provided that the director is satisfied that the alternative casing procedures are operationally equivalent to the requirements imposed by subdivision E 1 of this section.

3. For good cause shown, the director may impose special requirements on the permittee to prevent communication between two or more voids.

F. A well penetrating a mine other than a coal mine. In the event that a permittee has requested to drill a well in such a location that it would penetrate any active mine other than a coal mine, the director shall approve the safety precautions to be followed by the permittee prior to the commencement of activity.

G. Reporting of lost circulation zones. The permittee shall report to the director as soon as possible when an unanticipated void or groundwater horizon is encountered that results in lost circulation during drilling. The permittee shall take every necessary action to protect the lost circulation zone.

Part III
Coalbed Methane Gas Wells

4VAC25-150-550. Applicability, coalbed methane wells.

Part III of this chapter sets forth requirements unique to coalbed methane gas wells. Permittees must comply with the standards of general applicability in Part I of this chapter and with the standards for coalbed methane gas wells in this part.

4VAC25-150-560. Application for a permit, coalbed methane well operations.

A. In addition to the requirements of 4VAC25-150-80 or 4VAC25-150-110, every application for a permit or permit modification for a coalbed methane gas well shall contain:

1. An identification of the category of owner or operator, as listed in § 45.1-361.30 A of the Code of Virginia, that each person notified of the application belongs to;

2. The signed consent required in § 45.1-361.29 of the Code of Virginia;

3. Proof of conformance with any mine development plan in the vicinity of the proposed coalbed methane gas well, when the Virginia Gas and Oil Board has ordered such conformance;

4. The approximate depth to which the well is proposed to be drilled or deepened, or the actual depth if the well has been drilled;

5. The approximate depth and thickness, if applicable, of all known coal seams, known groundwater-bearing strata, and other known gas or oil strata between the surface and the depth to which the well is proposed to be drilled;

6. If casing or tubing is proposed to be or has been set, a description of the entire casing program, including the size of each string of pipe, the starting point and depth to which each string is to be or has been set, and the extent to which each string is to be or has been cemented together with any request for a variance under 4VAC25-150-580;

7. An explanation of the procedures to be followed to protect the safety of persons working in and around an underground coal mine for any coalbed methane gas well to be drilled within 200 feet of or into any area of an active underground coal mine areas where workers are assigned or travel, as well as any connected sealed or gob areas, or where a one-year mine plan is on file with the Division of Mines; which shall, at a minimum, require that notice of such drilling be given by the permittee to the mine operator and the Chief of the Division of Mines at least two 10 working days prior to drilling within 200 feet of or into the mine; and

8. If the proposed work is for a Class II injection well, a copy of the Environmental Protection Agency permit, or a copy of the application filed with the Environmental Protection Agency under the Underground Injection Control Program.

B. In addition to the requirements of 4VAC25-150-80 or 4VAC25-150-110, every application for a permit or permit modification for a coalbed methane well or a Class II injection well may contain, if the proposed work is to drill, redrill or deepen a well, a plan showing the proposed manner of plugging the well immediately after drilling if the proposed well work is unsuccessful so that the well must be plugged and abandoned.

4VAC25-150-590. Plats, coalbed methane wells.

A. In addition to the requirements of 4VAC25-150-90, every plat for a coalbed methane gas well shall show:

1. Boundaries and acreage of any drilling unit established by the board around the subject well;

2. Boundaries and acreage of the tract on which the well is located or is to be located;

3. Boundaries and acreage of all other tracts within one-half of the distance specified in § 45.1-361.17 of the Code of Virginia or within one-half of the distance to the nearest well completed in the same pool, whichever is less, or within the boundaries of a drilling unit established by the board around the subject well;

4. Surface owners on the tract to be drilled and on all other tracts within the unit where the surface of the earth is to be disturbed;

5. All gas, oil or royalty owners on any tract located within one-half of the distance specified in § 45.1-361.17 of the Code of Virginia or within one-half of the distance to the nearest well completed in the same pool, whichever is less, or within the boundaries of a drilling unit established by the board around the subject well;

6. Coal owners and mineral owners on the tract to be drilled and on all other tracts located within 750 feet of the subject well location;

7. Coal operators who have registered operations plans with the department for activities located on the tract to be drilled, or who have applied for or obtained a coal mine license, coal surface mine permit or a coal exploration notice or permit from the department with respect to all tracts within 750 feet of a proposed gas or oil well; and

8. Any inhabited building, highway, railroad, stream, permitted surface mine or permitted mine opening within 500 feet of the proposed well.

B. The well plat shall locate the well and two permanent points or landmarks with reference to the mine coordinate system if one has been established for the area of the well location, and shall show all other wells within the scope of the plat.

4VAC25-150-600. Setback restrictions, coalbed methane wells.

No permit shall be issued for any well to be drilled closer than 200 feet from any inhabited building, unless site conditions as approved by the director warrant the permission of a lesser distance, and there exists a lease or agreement between the operator and the owner of the inhabited building. A copy of the lease or agreement shall accompany the application for a permit.

4VAC25-150-610. Casing requirements for coalbed methane gas wells.

A. Water protection string.

1. Except as provided in subdivision A 5 of this section, the permittee shall set a water-protection string set to a point at least 300 feet below the surface or 50 feet below the lowest deepest known groundwater horizon, whichever is deeper, circulated and cemented to the surface. If cement does not return to the surface, every reasonable effort shall be made to fill the annular space by introducing cement from the surface.

2. The operator shall test or require the cementing company to test the cement mixing water for pH and temperature prior to mixing the cement and to record the results on the cementing ticket.

3. After the cement is placed, the operator shall wait a minimum of eight hours and allow the cement to achieve a calculated compressive strength of 500 psi before drilling, unless the director approves a shorter period of time. The wait-on-cement (WOC) time shall be recorded within the records kept at the drilling rig while drilling is taking place.

4. When requested by the director, the operator shall submit copies of cement tickets or other documents that indicate the above specifications have been followed.

5. A coal-protection string may also serve as a water protection string.

B. Coal protection strings.

1. When any well penetrates coal seams that have not been mined out, the permittee shall, except as provided in subdivisions B 2 and B 3 of this section, set a coal-protection string. The coal-protection string shall exclude all fluids, oil, gas, and gas pressure, except that which is naturally present in each coal seam. The coal-protection string shall also exclude all injected material or disposed waste from the coal seams or the wellbore. The string of casing shall be set to a point at least 50 feet below the lowest coal seam, or as provided in subdivision B 3 of this section, and shall be circulated and cemented from that point to the surface, or to a point not less than 50 feet into the water-protection string or strings which are cemented to the surface.

2. For good cause shown, either before or after the permit is issued, when the procedure specified in subdivision B 1 is demonstrated by the permittee as not practical, the director may approve a casing program involving:

a. The cementing of a coal-protection string in multiple stages;

b. The cementing of two or more coal-protection strings; or

c. The use of other alternative casing procedures.

3. The director may approve the program, provided he is satisfied that the result will be operationally equivalent to compliance with the provisions of subdivision B 1 of this section for the purpose of permitting the subsequent safe mining through the well or otherwise protecting the coal seams as required by this section. In the use of multiple coal-protection strings, each string below the topmost string shall be cemented at least 50 feet into the next higher string or strings that are cemented to the surface and be verified by a cement top log.

4. Depth of coal-protection strings.

a. A coal-protection string shall be set to the top of the red shales in any area underlain by them unless, on a showing by the permittee in the permit application, the director has approved the casing point of the coal-protection string at some depth less than the top of the red shales. In such event, the permittee shall conduct a gamma-ray/density log survey on an expanded scale to verify whether the well penetrates any coal seam in the uncased interval between the bottom of the coal-protection string as approved and the top of the red shales.

b. If an unanticipated coal seam or seams are discovered in the uncased interval, the permittee shall report the discovery in writing to the director. The permittee shall cement the next string of casing, whether a part of the intermediate string or the production string, in the applicable manner provided in this section for coal-protection strings, from a point at least 50 feet below the lowest coal seam so discovered to a point at least 50 feet above the highest coal seam so discovered.

c. The gamma-ray/density log survey shall be filed with the director at the same time the driller's log is filed under 4VAC25-150-360.

d. When the director believes, after reviewing documentation submitted by the permittee, that the total drilling in any particular area has verified the deepest coal seam higher than the red shales, so that further gamma-ray/density logs on an expanded scale are superfluous for the area, he may waive the constructing of a coal-protection string or the conducting of such surveys deeper than 100 feet below the verified depth of the deepest coal seam.

C. Coal-protection strings of wells drilled prior to July 1, 1982. In the case of wells drilled prior to July 1, 1982, through coal seams without coal-protection strings as prescribed in subsection B of this section, the permittee shall retain such coal-protection strings as were set. During the life of the well, the permittee shall, consistent with a plan approved by the director, keep the annular spaces between the various strings of casing adjacent to coal seams open to the extent possible, and the top ends of all such strings shall be provided with casing heads, or such other approved devices as will permit the free passage of gas or oil and prevent filling of the annular spaces with dirt or debris.

D. Producing from more than one stratum. The casing program for any well designed or completed to produce from more than one stratum shall be designed in accordance with the appropriate standard practices of the industry.

E. Casing through voids.

1. When a well is drilled through a void, the hole shall be drilled at least 30 feet below the void. The annular space shall be cemented from the base of the casing up to the void, and to the surface from the top of the void every reasonable attempt shall be made to fill up the annular space from the top of the void to the surface; or it shall be cemented at least 50 feet into the next higher string or strings of casing that are cemented to the surface, and shall be verified by a cement top log.

2. For good cause shown, the director may approve alternate casing procedures proposed by the permittee, provided that the director is satisfied that the alternative casing procedures are operationally equivalent to the requirements imposed by subdivision E 1 of this section.

3. For good cause shown, the director may impose special requirements on the permittee to prevent communication between two or more voids.

F. A well penetrating a mine other than a coal mine. In the event that a permittee has requested to drill a well in such a location that it would penetrate any active mine other than a coal mine, the director shall approve the safety precautions to be followed by the permittee prior to the commencement of activity.

G. Production casing.

1. Unless otherwise granted in a variance from the director:

a. For coalbed methane gas wells with cased completions and cased/open hole completions, production casing shall be set and cemented from the bottom of the casing to the surface or to a point not less than 50 feet into the lowest coal-protection or water-protection string or strings which are cemented to the surface.

b. For coalbed methane gas wells with open hole completions, the base of the casing shall be set to not more than 100 feet above the uppermost coalbed which is to be completed open hole. The casing shall be cemented from the bottom of the casing to the surface or to a point not less than 50 feet into the lowest coal-protection or water-protection string or strings which are cemented to the surface.

2. A coal-protection string may also serve as production casing.

H. Reporting of lost circulation zones. The permittee shall report to the director as soon as possible when an unanticipated void or groundwater horizon is encountered that results in lost circulation during drilling. The permittee shall take every necessary action to protect the lost circulation zone.

4VAC25-150-620. Coalbed methane gas wellhead equipment.

Wellhead equipment and facilities installed on any gob well or on any coalbed methane gas well subject to the requirements of §§ 45.1-161.121 and 45.1-161.292 of the Code of Virginia addressing mining near or through a well shall include a safety precaution plan submitted to the director for approval. Such plans shall include, but are shall not be limited to, flame arrestors, back-pressure systems, pressure-relief systems, vent systems and fire-fighting equipment. The director may require additional safety precautions or equipment to be installed on a case-by-case basis.

4VAC25-150-630. Report of produced waters, coalbed methane wells.

All coalbed methane gas well operators are required to submit monthly reports of total produced waters withdrawn from coalbed methane gas wells, in barrels, on a well-by-well basis, with the monthly report submitted under 4VAC25-150-210 of this chapter. The report shall show monthly produced water withdrawals and cumulative produced water withdrawals. Such reports shall be available for inspection upon request and maintained electronically or by hard copy until the well is abandoned and reclaimed.

4VAC25-150-650. Abandonment through conversion Conversion of a coalbed methane well to a vertical ventilation hole.

A permittee wishing to abandon convert a coalbed methane gas well as to a vertical ventilation hole shall first obtain approval from the Chief of the Division of Mines and submit an application a written request to the division for a permit modification which includes approval from the chief of the Division of Mines release. The director shall consult with the chief, or his designated agent, before approving permit release.

Part IV
Ground-Disturbing Geophysical Exploration

4VAC25-150-660. Applicability, ground-disturbing geophysical activity.

Part IV (4VAC25-150-660 et seq.) of this chapter sets forth requirements unique to ground-disturbing geophysical exploration.

4VAC25-150-670. Application for a permit, geophysical activity or core holes.

A. In accordance with 4VAC25-150-80 and 4VAC25-150-110, a permit shall be required for ground-disturbing geophysical exploration.

B. In addition to the requirements of 4VAC25-150-80 or 4VAC25-150-110, every application for a corehole permit or permit modification under this part shall contain:

1. The approximate depth to which the corehole is proposed to be drilled or deepened, or the actual depth if the corehole has been drilled;

2. The approximate depth and thickness, if applicable, of all known coal seams, known groundwater-bearing strata, and other known gas or oil strata between the surface and the depth to which the corehole is proposed to be drilled;

3. If casing is proposed to be set, the entire casing program, including the diameter of each string of casing, the starting point and depth to which each string is to be set, whether or not the casing is to remain in the hole after the completion of drilling, and the extent to which each string is to be cemented, if applicable; and

4. A plan which shows the proposed manner of plugging or replugging the corehole.; and

5. An explanation of the procedures to be followed to protect the safety of persons working in and around an underground coal mine for any corehole to be drilled within 200 feet of areas where workers are assigned or travel, as well as any connected sealed or gob areas, or where a one-year mine plan is on file with the Division of Mines. Such procedures shall, at a minimum, require that notice of such drilling be given by the permittee to the mine operator and the Chief of the Division of Mines at least 10 working days prior to drilling.

4VAC25-150-680. Plats, core holes.

A. In addition to the requirements of 4VAC25-150-90, every plat for a corehole shall show:

1. The boundaries of the tract on which the corehole is located or is to be located;

2. Surface owners on the tract to be drilled and surface owners on the tracts where the surface is to be disturbed;

3. Coal owners and mineral owners on the tract to be drilled;

4. Coal operators who have registered operations plans with the department for activities located on the tract to be drilled; and

5. Any inhabited building, highway, railroad, stream, permitted surface mine or permitted mine opening within 500 feet of the proposed corehole.

B. If the corehole location is underlain by known coal seams, the plat shall locate the corehole and two permanent points or landmarks with reference to the mine coordinate system if one has been established for the area of the corehole location, and shall in any event show all other wells within the scope of the plat.

4VAC25-150-690. Operations plans, core holes.

In addition to the requirements of 4VAC25-150-100, every operations plan for a corehole shall describe the measures to be followed to protect water quality during the drilling, and the measures to be followed to protect any voids encountered during drilling.

4VAC25-150-700. Setback restrictions, core holes.

No permit shall be issued for any corehole to be drilled closer than 200 feet from an inhabited building, unless site conditions as approved by the director warrant the permission of a lesser distance, and there exists a lease or agreement between the operator and the owner of the inhabited building. A copy of the lease or agreement shall accompany the application for a permit.

4VAC25-150-711. Voids and lost circular circulation zones.

A. Casing through voids.

1. When a corehole is drilled through a void, the hole shall be drilled at least 30 feet below the void. The annular space shall be cemented from the base of the casing up to the void and to the surface from the top of the void every reasonable attempt shall be made to fill the annular space from the top of the void to the surface; or it shall be cemented at least 50 feet into the next higher string or strings of casing that are cemented to the surface and be verified by a cement top log.

2. For good cause shown, the director may approve alternate casing procedures proposed by the permittee, provided that the director is satisfied that the alternative casing procedures are operationally equivalent to the requirements imposed by this section.

3. For good cause shown, the director may impose special requirements on the permittee to prevent communication between two or more voids.

B. Reporting of lost circulation zones. The permittee shall report to the director as soon as possible when an unanticipated void or groundwater horizon is encountered that results in lost circulation during drilling. The permittee shall take every necessary action to protect the lost circulation zone.

Part V
Gathering Pipelines

4VAC25-150-720. Applicability, gathering pipelines.

A. Part V (4VAC25-150-720 et seq.) of this chapter sets forth requirements unique to gathering pipelines. Permittees must comply with the standards for gathering pipelines in this part and the following standards in Part I:

1. All of Article 1, "General Information"; except 4VAC25-150-50, "Gas or oil in holes not permitted as a gas or oil well";

2. All of Article 2, "Permitting"; except 4VAC25-150-90, "Plats";

3. All of the sections in Article 3, "Enforcement";

4. 4VAC25-150-220, "Annual reports,"; of Article 4, "Reporting";

5. 4VAC25-150-230, 4VAC25-150-240, 4VAC25-150-250, 4VAC25-150-260, 4VAC25-150-270, 4VAC25-150-310, 4VAC25-150-350, 4VAC25-150-380, 4VAC25-150-410, 4VAC25-150-420, and 4VAC25-150-430 of Article 5, "Technical Standards"; and

6. 4VAC25-150-470, "Release of bond,"; of Article 6, "Plugging and Abandonment.";.

B. A permit shall be required for installation and operation of every gathering pipeline and associated structures for the movement of gas or oil production from the wellhead to a previously permitted gathering line, a transmission or other line regulated by the United States Department of Transportation or the State Corporation Commission, to the first point of sale, or for oil, to a temporary storage facility for future transportation by a method other than a gathering pipeline.

C. Each gathering pipeline or gathering pipeline system may be permitted separately from gas or oil wells or may be included in the permit for the well being served by the pipeline.

4VAC25-150-730. General requirements for gathering pipelines.

A. Gathering pipelines shall be installed to be compatible with other uses of the area.

B. No permit shall be issued for a gathering pipeline to be installed closer than 50 100 feet from any inhabited building or railway, unless site conditions as approved by the director warrant the use of a lesser distance and there exists a lease or agreement between the operator, the inhabitants of the building and the owner of the inhabited building or railway. A copy of the lease or agreement shall accompany the application for a permit.

C. Materials used in gathering pipelines shall be able to withstand anticipated conditions. At a minimum this shall include:

1. All plastic gathering pipeline connections shall be fused, not coupled.

2. All buried gathering pipelines shall be detectable by magnetic or other remote means from the surface.

D. All new gathering pipelines shall be tested to maintain a minimum of 110% of anticipated pressure prior to being placed into service.

E. All gathering pipelines shall be maintained in good operating condition at all times.

4VAC25-150-740. Operations plans for gathering pipelines.

A. For a gathering pipeline, the operations plan shall be in a format approved by, or on a form prescribed by, the director.

B. On a form prescribed by the director, the operator shall indicate how risks to the public safety or to the site and adjacent lands are to be managed, and shall provide a short narrative, if pertinent.

4VAC25-150-750. Inspections for gathering pipelines.

Gathering pipelines shall be visually inspected annually by the permittee. The results of each annual inspection shall be maintained by the permittee for a minimum of three years and be submitted to the director upon request.

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