Act 13 Frequently Asked Questions
The purpose of this FAQ is to highlight changes in the new law. This FAQ should not be used in lieu of reference to the law itself. The information in this guidance is solely advisory and does not represent a legal interpretation by the department. Nothing in this summary shall affect any statutory requirements.
1. Where can I view Act 13?
Act 13 became law when Governor Corbett signed House Bill 1950 on Feb. 14, 2012.
To view the legislation, click here.
2. What is a conventional gas well?
A conventional gas well, also known as a traditional well, is a well that produces oil or gas from a conventional formation. Conventional formations are variable in age, occurring both above and below the Elk Sandstone. While a limited number of such gas wells are capable of producing sufficient quantities of gas without stimulation by hydraulic fracturing, most conventional wells require this stimulation technique due to the reservoir characteristics in Pennsylvania. Stimulation of conventional wells, however, generally does not require the volume of fluids typically required for unconventional wells.
3. What is an unconventional gas well?
An unconventional gas well is a well that is drilled into an unconventional formation, which is defined as a geologic shale formation below the base of the Elk Sandstone or its geologic equivalent where natural gas generally cannot be produced except by horizontal or vertical well bores stimulated by hydraulic fracturing.
To view a rock correlation diagram of formations in Pennsylvania, please click here.
Unconventional formations that are currently being targeted or that may possibly be targeted for oil and gas development in Pennsylvania include, but are not limited to, the Marcellus, Utica, Mandata, Huron, Rhinestreet, and miscellaneous Upper Devonian formations such as the Dunkirk, Pipe Creek, Middlesex, Geneseo, and Burkett. There are some shale formations, specifically the Huron, that are younger than the base of the Elk Sandstone or its' geologic equivalent and, therefore, does not meet the Act 13 definition of an "unconventional formation."
See Harper, J.A., Subsurface rock correlation diagram, Allegheny Plateau, Pennsylvania. Pennsylvania Geologic Survey, 4th ser., Open-File Report OF-79-01.
4. What is a stripper well?
A stripper well is an unconventional gas well incapable of producing more than 90,000 cubic feet of gas per day.
5. What does 'spud' mean?
Act 13 defines "spud" as the actual start of drilling of an unconventional well. DEP considers a well to be spud when the drilling bit penetrates the surface of the land. Therefore, any well with conductor pipe or any other casing is a spud well. Well sites with only a cellar would not be considered to have a spud well.
6. I am a county, municipality or oil and gas operator and disagree with the spud data that is included on the spud report that DEP provided to the PUC. Who can I contact to resolve this matter?
Act 13 required DEP, within 14 days of passage of the Act, to provide a report to the PUC that identifies all spud unconventional gas wells that received a drilling permit from DEP. DEP met this commitment and all spud reports that DEP submitted to the PUC are available for review on DEP's website. If you are a county, municipality or oil and gas operator and disagree with any of the data that appears on a spud report that DEP supplied to the PUC, contact DEP via e-mail at email@example.com. You will be contacted by DEP to discuss the matter and, if necessary, the Department will correct or update its database and report this information to the PUC.
7. Does Act 13 provide additional financial resources to assist DEP's regulatory oversight?
Yes. Act 13 is projected to provide $6 million annually from impact fee revenues to the department for the administration of its oil and gas program and for enforcing clean air and clean water laws.
8. How does Act 13 affect local zoning of oil and gas activities?
For more information on Act 13's effect on local zoning of oil and gas activities, please visit the Public Utility Commission's website.
9. I am a conventional driller. How does Act 13 affect me?
Act 13 provides for enhanced environmental protections for the development of unconventional wells and for the collection and imposition of an impact fee for the development of unconventional wells. Operators of conventional gas wells are not subject to the impact fee provisions contained in Act 13.
The new bonding fee schedule implemented by the Act applies to all oil and gas wells. (Please see §3225 of the Act)
All permit applicants must notify host and adjacent municipalities of their intent to drill and list these municipalities on the permit application. The Act establishes that the department may deny a permit on the basis of the operator's compliance history. The department may also revoke or suspend a permit based on compliance. (Please see §3211 of the Act)
All operators must post the well permit on site prior to construction. Spud notifications must be submitted to DEP electronically. (Please see §3211 of the Act)
All operators must abide by the corrosion control requirements set forth in the Act, where applicable. (Please see §3218.4 of the Act)
The siting restrictions for development in floodplains, as discussed in question 18, also apply to conventional wells. (Please see §3215 of the Act)
All oil and gas operators are required to submit well records within 30 days of drilling a well and completion reports within 30 days of completing a well. The new additions to those reports, as discussed in questions 13 and 14, apply to all operators. (Please see §3222 of the Act)
Any oil and gas operator may petition the department for an extension of the time requirement to restore a well site. Currently, sites must be restored nine months after completion of drilling a well. Should an operator demonstrate through a plan the conditions outlined in question 20, the department may extend the time requirement by up to two years. (Please see §3216 of the Act)
The rebuttable presumption of liability provisions for diminution or contamination of water supplies due to oil and gas activity remains the same for conventional well operations. Any operator, conventional or unconventional, found to have impacted water supplies must restore or replace the water supplies to either Safe Drinking Water Standards or pre-existing water quality standards, whichever is of greater quality. Operators found to have impacted a water supply within the time and distance provisions of the presumption of liability must supply temporary potable water until the supply is restored or replaced. (Please see §3218 of the Act)
Permitting, notifications, bonding and reporting
1. Does Act 13 change how operators report spudding a well to DEP?
Yes. All operators must provide 24 hours' notice of the date that drilling will commence to the department electronically via the department's online oil and gas reporting application. Click here to access the online reporting application. (Please see § 3211(f) of the Act)
2. Does Act 13 change how DEP issues permits?
Yes. The department will be amending its well permit application and associated materials to address the changes in the requirements.Please refer to the department's website for the most up-to-date application materials.
The timeframe for reviewing permit applications is largely unchanged. The department must issue a permit within 45 days of submission of a permit application unless for the reasons outlined in § 3211(e.1), except the department may extend the review period for 15 days. Act 13 now allows the department to extend this review period up to an additional 15 days (for a total of 75 days) if the applicant seeks a variance or waiver request of the well location restrictions. (Please see §§ 3215(a) and (b)(4) of the Act)
Additionally, Act 13 also provides additional bases for permit denial. The department may now deny issuing a permit to an applicant if the applicant, parent or subsidiary is in continuing violation of applicable state laws and regulations, or the application has failed to pay the required impact fee or file a report under § 2303.
3. How do municipalities and gas storage reservoir operators comment on proposed drilling activity?
Municipalities where an unconventional well is proposed to be drilled may submit written comments to the Department describing the local conditions or circumstances which the municipality determines should be considered by the department.
Operators of gas storage reservoirs may comment on the proposed drilling of unconventional wells within 3,000 feet, measured from the well bore, of a gas storage reservoir. Gas storage reservoirs are the portion of a subsurface geological stratum into which gas is, or may be, injected for storage purposes or to test suitability of the stratum for storage. Storage operators may submit written comments to the department describing circumstances which the storage operator determines should be considered by the department.
Comments shall be submitted within 15 days of receipt of the notice of the plat to the department as well as all parties entitled to receive notification of the well permit application.
Written responses to a municipality or gas storage reservoir operator's comments shall be submitted by the applicant to the department within 10 days of receipt of comments. The department may consider any comments or responses it receives in its review of a permit application. (Please see §3212.1(a)-(b) of the Act)
4. Who must obtain a water management plan?
Any person who withdraws or uses water for drilling or hydraulic fracture stimulation of any natural gas well completed in an unconventional gas formation must submit and have approved a water management plan, which includes a water reuse plan, prior to withdrawing the water. The plan's requirements shall be presumed to have been met if the proposed water withdrawal has been approved by the appropriate River Basin Commission and is operated in accordance with conditions established by the Susquehanna River Basin Commission, the Delaware River Basin Commission or the Great Lakes Commission, as applicable. The department may establish additional requirements as necessary to comply with the laws of the Commonwealth. Compliance with the water management plan shall be a condition of any permit issued by the department. (Please see §3211(m) of the Act)
5. Have bonding amounts changed?
Yes. Act 13 increases well bonding requirements, which are currently established at $2,500 per well or $25,000 for a blanket bond. Bond amounts shall be established based on well-bore length and number of wells operated, as follows*:
For wells with total well bore lengths less than 6,000 feet:
• For up to 50 wells - $4,000/well not to exceed $35,000
• For 51-150 wells - $35,000 plus $4,000/well not to exceed $60,000
• For 151-250 wells - $60,000 plus $4,000/well not to exceed $100,000
• For more than 250 wells - $100,000 plus $4,000/well not to exceed $250,000
For wells with total well bore lengths 6,000 feet or greater:
• For up to 25 wells - $10,000/well not to exceed $140,000
• For 26-50 wells - $140,000 plus $10,000/well not to exceed $290,000
• For 51-150 wells - $290,000 plus $10,000/well not to exceed $430,000
• For more than 150 wells - $430,000 plus $10,000/well not to exceed $600,000
Bond amounts may be adjusted every two years by the Environmental Quality Board. (Please see §3225 of the Act)
*Note: The department will be establishing an administrative implementation schedule and is in the process of developing new bonding forms. Prior to securing a bond, please consult with the department for the latest information.
6. Have well record reporting requirements changed?
Yes. A well operator must file with the department a well record within 30 days of drilling a well. In addition to previous regulatory requirements defining what must be included in the well record, Act 13 requires the operator to identify true vertical depths at which methane was encountered, other than in the target formation; and the country of origin and manufacture of the tubular steel products used in well construction. The department is developing new forms for this information.
7. Have completion reporting requirements changed?
Yes. A well operator must file with the department a completion report within 30 days after completion of the well, when the well is capable of production.
Act 13 specifies that the completion report must contain the operator's stimulation record. The stimulation record must include:
• A descriptive list of the chemical additives used.
• The trade name, vendor, and intended use of each chemical additive
• A list of chemicals used
• The percent by mass of each chemical used
• The total volume
• List of water sources
• Pump rates, pressures, total volume used to stimulate a well
• Total volume of recycled water used
An operator may designate portions of the stimulation record as containing trade secret or confidential proprietary information and the department shall prevent disclosure to the extent permitted by the Pennsylvania Right to Know Law or other applicable law.
8. Does Act 13 change the method for providing notice of the plat to certain parties as part of the well permit application process?
No, section 3211(b)(2) of the new law did not alter the method for providing notice of the plat – notice must still be provided to the listed parties via certified mail through the United States Postal Service. In accordance with the statute, the Department will not accept mail slips from commercial vendors such as UPS or FedEx. The Department will return any such submissions to the applicant and consider the permit application administratively incomplete.
9. Does Act 13 change the persons required to be provided notice of the plat via certified mail as part of the well permit application process?
As part of the well permit application parties, certain persons have to be notified.
Act 13 identified additional persons who must receive notice of the plat via certified mail as part of the well permit application process. These additional persons include:
• the municipality in which the tract of land upon which the well to be drilled is located
• each municipality within 3,000 feet of the proposed unconventional vertical well bore
• the municipalities adjacent to the well
• all surface landowners and water purveyors whose water supplies are within 3,000 feet of a proposed unconventional well bore
• gas storage operators within 3,000 feet of the proposed unconventional vertical well bore
Act 13 does not change the requirement that the following persons must continue be notified:
• the surface landowner
• all surface landowners and water purveyors, whose water supplies are within 1,000 feet of a proposed conventional well location
• the owner and lessee of any coal seams
• each coal operator required to be identified on the well permit application.
10. Which municipalities are considered to be "adjacent" for purposes of providing notice of the plat via certified mail as part of the well permit application process?
"Adjacent municipalities" are all those municipalities sharing a common border with the municipality in which the tract of land upon which the well to be drilled is located. In addition, municipalities located within 3,000 feet of the proposed unconventional well bore also must receive notice of the plat via certified mail, whether or not they share a common border with the municipality in which the tract of land upon which the well to be drilled is located.
Environmental protections and setbacks
1. When do the environmental provisions set forth by the law become effective?
The environmental protection provisions set for by the law are effective as of April 16, 2012.
2. Do the provisions of Act 13 change disclosure requirements of hydraulic fracturing chemicals?
Yes. By signing Act 13 into law, Governor Corbett enacted one of the most aggressive and transparent hydraulic fracturing disclosure laws in the country. The law is based in large part on the success of similar disclosure requirements enacted by the state of Colorado. Colorado's requirements, upon which much of this Act's disclosure requirements were based, were hailed by progressive industry representatives, environmental organizations and many other groups as a model for other states.
Unconventional well operators must complete a chemical disclosure registry form for publication on FracFocus.org in addition to the reporting required to be submitted to the department. The use of FracFocus.org was recommended and supported by a Department of Energy advisory panel's report on hydraulic fracturing.
Texas A&M released a free new web training program addressing how to properly register and submit hydraulic fracturing chemical data to www.FracFocus.org. To access training click here: http://www.teex.org/eu/flash/player.html (requires Flash Player).
Because the registry must be used for all hydraulic fracturing of unconventional wells performed on or after April 16, 2012, the Department expects all operators to be registered with FracFocus.org and be prepared to begin using the registry. Within 60 days of the conclusion of hydraulic fracturing, operators must complete and post the chemical registry disclosure form on the registry.
Act 13 provides for immediate, verbal communication of any proprietary information to emergency responders to ensure the necessary care or treatment is delivered to anyone who may have been affected. The Act states that nothing shall prevent the department, a public health official, an emergency manager or a responder to a spill, release or complaint from a person who may have been aggrieved by the spill or release from obtaining information needed upon written request. (Please see §3222.1 of the Act)
3. Are there new setback provisions?
Yes. Act 13 extends the setback distance for unconventional wells from 200 feet to 500 feet from existing buildings or water wells, unless consented to by the owner of the building or water well.
This Act establishes a 1,000-foot setback for an unconventional well from a water supply extraction point used by a water purveyor, unless written consent is obtained from the water purveyor.
The department shall grant a variance from these distance restrictions if the operator submits a plan identifying additional measures, facilities or practices to be employed during well site construction, drilling and operations that is approved by the department. The variance, if granted, shall include any necessary additional terms and conditions of the permit ensure the safety and protection of affected persons and property.
Act 13 also extends the setback distance for unconventional wells from 100 feet to 300 feet from any solid blue lined stream, spring, or body of water or wetland greater than one acre in size as identified on the most recent 7 ½ minute topographic quadrangle map of the United States Geological Survey.
Unconventional well site pads must also maintain a setback of 100 feet between the edge of disturbance and any stream, spring, body of water or wetland greater than one acre in size.
The department shall grant a waiver for these setback requirements if the operator submits a plan identifying additional measures, facilities or practices to be employed during well site construction, drilling and operations that is approved by the department. Any waiver shall contain additional terms and conditions as necessary to protect the waters of the Commonwealth.
4. How does Act 13 affect development of well sites in floodplains?
Act 13 prohibits the preparation of any well site or drilling of any well within a floodplain if the site will include a pit or impoundment containing drilling cuttings, flowback water, produced water, hazardous materials, chemicals or wastes located within the floodplain; or a tank containing hazardous materials, chemicals, condensate, wastes, flowback or produced water within the floodway. Please consult the Act and appropriate regulation for definitions of these terms.
The Department may issue a waiver to these restrictions upon approval of a plan identifying additional measures, facilities or practices to be employed. The department may impose terms and conditions on the waiver necessary to protect the waters of the commonwealth.
Floodplain boundaries referenced are those indicated on maps and flood insurance studies provided by the Federal Emergency Management Agency. In an area where no FEMA maps or studies have defined the boundary of the floodplain, refer to defaults in § 3215(f)(5).
5. Are any well pad sites "grandfathered" from the new well location requirements?
Yes. Siting restrictions will not apply to a new permit application for a well at an existing well site that has at least one currently valid well permit issued prior to April 16, 2012. (Please see §3215(g) of the Act)
6. When must operators restore a well site?
All operators must restore the land surface within the area disturbed in siting, drilling, completing and producing the well. Within nine months after completion of drilling the well, the operator shall restore the well site, remove or fill all pits used to contain produced fluids or industrial wastes and remove all drilling supplies and equipment not needed for production, unless consent is obtained from the surface landowner. An operator may request to extend the timeframe by up to an additional two years upon a determination that (a) the extension will result in less earth disturbance, increased water reuse or more efficient development OR (b) site restoration cannot be achieved due to adverse weather conditions or a lack of essential fuel, equipment or labor.
To demonstrate that the extension will result in less earth disturbance, increased water reuse or more efficient development of the resource, the operator must provide a site restoration plan that provides for the timely removal or fill of all pits used to contain fluids or industrial wastes; the removal of all drilling supplies and equipment not needed for production; the stabilization of the well site, including post-construction storm water management best management practices; or other measures to minimize accelerated erosion and sedimentation. The plan must also provide for returning portions of the site not occupied by production or equipment to approximate original contours capable of supporting pre-drilling existing uses. (Please see §3216 of the Act)
7. What happens if drilling impacts water supplies?
A well operator who affects a public or private water supply by pollution or diminution must restore or replace the affected water supply with an alternate source of water adequate in quality and quantity for the purposes served by the supply. This replaced or restored water supply must meet to the greater of pre-existing water quality standards or water quality standards established by the Pennsylvania Safe Drinking Water Act.
Act 13 increased the presumption of liability for water supply contamination for unconventional wells. Unless rebutted, the Act presumes that an operator is responsible for pollution of a water supply if the affected water supply is 2,500 feet from an unconventional well and that pollution occurred within 12 months of the later of completion, drilling, stimulation or alteration of the unconventional well.
Operators found to have impacted water supplies within the time and distance provisions of the presumption of liability must provide temporary potable water until the supplies are restored or replaced.
Unconventional well operators must provide written notice to landowners or water purveyors that the rebuttable presumption may be void if the landowner or water purveyor refuses the operator access to conduct a pre-drilling or pre-alteration survey.
8. What are the new corrosion control requirements?
All buried metallic pipelines shall be installed and placed in operation in accordance with federal corrosion protection requirements (49 CFR Part. 192 Subpart. I).
Permanent aboveground and underground tanks must comply with applicable corrosion control requirements in the department's storage tank regulations.
The Environmental Quality Board will promulgate corrosion control regulations for all other buried metallic structures, such as well casings, as determined as necessary.
Corrosion control procedures must be carried out under the direction of a qualified person. A pipeline operator of new, replaced, relocated or otherwise changed pipeline must comply with these requirements as of April 16, 2012. (Please see §3218.4 of the Act)
9. Are there new containment requirements?
Yes. Unconventional well sites must be designed and constructed to prevent spills to the ground surface or off the well site. Containment practices must be in place during both drilling and hydraulic fracturing operations and must be sufficiently impervious and able to contain spilled materials, and be compatible with the waste material or waste stored within the containment. Containment plans must be submitted to the department and describe any equipment that is to be kept onsite to prevent a spill from leaving the well pad.
Containment systems shall be used wherever drilling mud, hydraulic oil, diesel fuel, drilling mud additives, hydraulic fracturing additives, and/or hydraulic fracturing flowback are stored. Containment areas must be sufficient to hold the volume of the largest container stored in the area plus ten percent. (Please see §3218.2 of the Act)
10. Do unconventional well operators have to keep records concerning the transportation of waste?
Yes. Unconventional well operators that transport wastewater fluids must maintain for five years records of fluids transported and make such records available to the department upon request. The records must include the number of gallons of wastewater fluids produced during drilling, stimulation or alteration of the well; the name of the person or company that transported wastewater fluids; the location where wastewater fluids were disposed of or transported and the volumes disposed of at the well location; and the method of disposal.
Inspections and enforcements
1. Does Act 13 change how DEP responds to well control emergencies?
Yes. The department may enter into contracts with well control specialists to provide adequate response services in the event of a well control emergency. Well control specialists under contract with the Department shall be immune from civil liability for good faith response actions, except for breach of contract, intentional tort or gross negligence.
A person liable for a well control emergency is responsible for all response costs incurred by the department. (Please see §3219.1 and §3254.1 of the Act)
2. Are there any changes to penalties?
Act 13 increases penalties for criminal violations from up to $300 to up to $1,000 per offense. Civil penalties have increased for unconventional gas well operators from $25,000 plus $1,000 per day to $75,000 plus $5,000 per day. (Please see §3256 of the Act)
Containment for unconventional wells
1. If an operator employs overall well site containment, is localized containment still necessary?
Yes, an unconventional well operator must contain spills as close to the source, or potential source, of contamination as possible, as well as making efforts to design the pad using containment systems and practices that prevent spills to the ground surface and from leaving the pad and polluting or threatening the waters of the Commonwealth.
2. When does the drilling operation officially begin for the purposes of this section?
Drilling operations are considered to begin when any equipment and/or chemicals are brought onto the well site that will be used for any phase of drilling, casing, or cementing of the well.
3. When does the drilling operation officially end for the purposes of this section?
The drilling operation is considered to end whenever all equipment and/or chemicals that were used for any phase of drilling, casing, or cementing of the well are removed from the well site.
4. When does the hydraulic fracturing operation officially begin for the purposes of this section?
Hydraulic fracturing operation is considered to begin whenever any equipment and/or chemicals that are to be used for any phase of the hydraulic fracturing of the well are brought onto the well site.
5. When does the hydraulic fracturing operation officially end for the purposes of this section?
The hydraulic fracturing operation is considered to end whenever all equipment and/or chemicals that were used for any phase of hydraulic fracturing are removed from the well site AND the 30-day flowback period of the well has concluded.
6. Would containment need to be provided on the unconventional well site for plugging operations?
In most cases, containment would not need to be provided for a plugging operation unless the process of plugging a particular well involved drilling (drilling out old casing and/or cement)
7. What specifically does "sufficiently impervious" mean?
All containment systems for the purposes of this section must have a coefficient of permeability of no greater than 1 x 10-10 cm/sec.
QA/QC testing documentation from the manufacturer that certifies the coefficient of permeability should be included in the containment plan.
8. What are the specific compatibility standards for containment systems?
The physical and chemical characteristics of all liners, coatings or any other materials used for containment that could potentially come into direct contact with the waste material being contained shall be compatible with the waste material and be resistant to physical, chemical and other failure during handling, installation and use.
Liner compatibility shall satisfy ASTM Method D5747 Compatibility Test for Wastes and Membrane Liners or other standards as approved by the Department. The operator shall produce documentation of the liner's physical and chemical characteristics compatibility with the waste contained upon request of the Department.
9. Will a comprehensive containment plan have to be submitted for each individual well site or will operators be able to submit a master containment plan?
Operators must submit a Master Containment Plan to each of the Department's Regional Oil & Gas Offices that have jurisdiction over the areas where an operator intends to drill and/or hydraulically fracture unconventional shale wells. These Master Containment Plans shall include general well site construction plans showing the expected placement of the various containment systems and describe the overall containment practice that will be utilized. Detailed plans showing the installation, utilization, integration and maintenance plan of all potentially used containment systems shall be included, as well as manufacturer's specifications on materials used, installation directions, maintenance requirements, chemical compatibility, warranted uses and reuse/disposal considerations.
The Master Containment Plan shall have a list of all equipment that may be onsite during drilling or hydraulic fracturing of unconventional shale wells that could be used to prevent a spill from leaving the well site. Master Containment Plans must contain the name, address and contact information of the companies contracted by the operator that may assist with spill responses, containment and remediation. The Master Containment Plan shall serve as the Department's Regional reference resource for all containment systems that may be used as part of an operator's containment practice for any well site within that Oil & Gas Region where drilling and hydraulic fracturing shall occur.
Additionally, an appendix shall be attached to each unconventional well site's PPC plan to serve as a site specific containment plan. This appendix shall include a general drawing of the well site showing the locations of all containment systems, including their GPS coordinates. A brief description of each containment system used at the well site shall be included along with a cross reference to the Master Containment Plan for additional details. Names and contact information of all companies that are contracted for the well site to assist with the spill response, containment and remediation shall be included. The appendix along with the corresponding PPC plan shall be made available to the Department upon request.
10. Will the Department approve containment plans? When should the containment plan be submitted?
The Master Containment Plans will not be approved or disapproved by the Department but will only be reviewed in order to ensure that containment plan meets the minimum requirements of the 2012 Oil and Gas Act ("Act"). The Department may make appropriate recommendations for changes as necessary to the operator to ensure that the plan meets the minimum requirements of the Act. The Master Containment Plan must be sent into the appropriate regional office with the first unconventional well permit on or after Oct. 14, 2012.
11. What minimum requirements must the containment plan contain?
The containment plans must identify specific containment practices and specific containment systems to provide adequate containment for drilling muds, hydraulic oil, diesel fuel, drilling mud additives, hydraulic fracturing additives and hydraulic fracturing flowback.
12. What is the difference between a containment system and a containment practice?
A system is a type of containment method. Two examples of containment systems are a well pad lining system or a manifolded pallet-style secondary containment system.
A practice is the specific way in which a containment system is used. For example, will a well pad liner (system) be used just under the drilling rig as localized containment (practice) or is the liner (system) installed to cover the entire well site for complete containment (practice)?
13. What are some specific examples of containment systems?
Containment systems would include but would not be limited to:
• Diking (Diking Fields)
• Curbing or berming
• Double-walled tanks
• Open-top tanks and containers
• Manifold containment tanking systems
• Portable collapsible containment systems
• Liquid transfer containment kits
• Modular spill decks
• Pipe sleeves
• Surface liners
• Sub-surface liners
• Permitted centralized impoundments
• Pits and impoundments that meet the design standards in 78.56 and 78.62 for the containment of pollutional substances
• Spill kits, booms, and absorbent pads, mats, pillows and socks
14. What are some examples of containment practices?
Two major categories of practices that an operator's required Master Containment Plan could follow:
• Localized well site containment
• Complete well site containment
Example of a containment practice utilizing Localized Well Pad Site Containment Systems:
• These include containment deployed only at the site of the reservoir (tanks), such as secondary containment of diesel fuel tanks, chemical tanks (not just chemicals used for hydraulic fracturing), roll offs, drilling rigs and trucking transfer stations. These systems may also include using a spill deck under all chemical storage tanks of a certain size or deploying a collapsible portable containment system around all diesel fuel tanks.
• These could also consist of any impermeable container made of a material that is compatible with the waste stored or used within the containment. Such possibilities include HDPE, stainless steel or aluminum. Any containment material that meets the coefficient of permeability of no greater than 1 x 10-10 cm/sec and has supporting documentation of the permeability, chemical compatibility and other applicable QA/QC standards, is acceptable for use for containment.
• Subsurface liners are protected from activities that may damage them, and they eliminate the "slip, trip and fall" hazards that are associated with surface liners. If localized subsurface liners are used, departmental staff can require that sections of the liner be removed for inspection and sampling if a spill occurred. This is to ensure that the liner prevented a release onto the ground or into the waters of the Commonwealth.
Example of a containment practice utilizing a Containment Plan for Complete Well Pad Site Containment System
• This would be containment that is deployed under the entire well pad site. When employing this type of system, the plan must::
1) State whether or not the liner system is a surface or subsurface liner system. If it is a subsurface liner, the plan must specify what type of stone will be used.
2) Be durable and be able to support the weight of heavy equipment, such as drilling rigs and trucks.
3) Ensure that the liner will be constructed from a synthetic material with a coefficient of permeability of no greater than 1 x 10-10 cm/sec and with sufficient strength and thickness to maintain the integrity of the liner.
4) Identify the type and thickness of the material.
5) Identify the installation procedures to be used.
6) Ensure the liner be designed, constructed and maintained so that the physical and chemical characteristics of the liner are not adversely affected by the waste and the liner is resistant to physical, chemical and other failure during transportation, handling, installation and use. ASTM Method D5747 Compatibility Testing results from the manufacturer must be submitted as proof of chemical compatibility for any component of the containment system when requested.
7) Ensure that adjoining sections of liners be sealed together to prevent leakage in accordance with the manufacturer's directions.
8) Ensure that liner systems must be designed to allow spilled material or waste to be collected and removed efficiently.
9) Ensure that if a modular system is employed, panels must overlap and interlock or utilize a welded thermal fusion seam in order to provide a water-tight seal that meets the maximum permeability coefficient. A QA/QC plan will be used to ensure proper installation.
10) Ensure that the site be graded in a manner that, should a spill occur, allows the waste to collect in a common conveyance channel system to capture both spills and run off water. The site must be designed to handle large spills and to also manage runoff that occurs on the well site. Supporting calculations may be required by the Department.
11) Ensure that the collection system must be designed to handle both contaminated and uncontaminated runoff on the well site. Contaminated runoff must be controlled. One example of adequate control would be collecting runoff and conveying it into a properly constructed and permitted centralized waste water impoundment or a pit that meets the design standards outlined in section 78.56 (suitable to contain pollutional substances).
12) Ensure that all complete well site containment plans include berming of the entire pad that meets the permeability standard.
13) Ensure that if the liner is to be recycled onsite, then an OG-71 Request for Approval of Alternative Waste Management Practices including a detailed account of the onsite liner processing practice, is submitted to the appropriate regional office.
14) Ensure that only clean stone may be reused. A plan for evaluating and inspecting stone for reuse will need to be submitted, as well as plans to properly dispose of contaminated stone as a residual waste.
Containment Plan Inspection and Maintenance Plan - The Containment Plan must include an inspection and maintenance plan for ensuring the timely and quality repair of damage that is caused to any containment systems including, but not limited to: tears, punctures or any condition that compromises the maximum permeability requirements of the liner system.
15. Do the containment requirements of this section apply to drilling pits, frac pits or impoundments, or centralized impoundments?
The containment requirements of Section 3218.2 are satisfied if the following requirements are met:
1) Pits or impoundments that contain pollutional substances are in compliance with this section provided they meet all requirements in section 78.56 of Pennsylvania's Oil and Gas regulation; AND
2) Centralized wastewater impoundments utilize a double liner system as part of their permit requirements.
The double liner system qualifies as individual secondary containment.
16. What are the capacity requirements for containment areas, pits and impoundments?
According to section 3218.2 subsection (d), containment areas must be sufficient to contain the "volume of the largest container stored in the area plus 10% to allow for precipitation, unless the container is equipped with individual secondary containment." For example, a containment area around a single 100,000-gallon aboveground storage tank must contain 110,000 gallons of fluid. A containment area around two 50,000-gallon aboveground storage tanks would only be required to contain 55,000 gallons of fluid. In either scenario, if the tanks are double-walled, then the containment is provided by the second wall of the tank itself.
For pits or impoundments, compliance with the two feet of freeboard requirements insections 78.56(a)(2) and (a)(4)(v) of the Department's regulations is required.