Well Construction Standards FAQ
Well Construction Standards FAQ
Background Information
This website was developed to assist operators, service companies, and any supporting industries/businesses whose operations are directly affected by the regulations under 25 Pa. Code Chapters 78 (Statutory Authority: Act 223) and 79 (Statutory Authority: Act 359), and the Coal and Gas Resource Coordination Law (Act 214). It was specifically designed to address questions and develop policy and/or technical guidance concerning substantial revisions to Subchapter D (Well Drilling, Operation, and Plugging) of Chapter 78, which became effective February 5, 2011. As such, most topics presented below are germane to subsurface activities with an emphasis on casing and cementing.
Please feel free to submit additional questions or comments relevant to subsurface activities and the February 5, 2011 regulatory package to DEP Oil and Gas using the subject line Reg Q&A. The index that follows is organized by regulatory citation. Other useful information not specific to individual citations under the Chapter 78 regulations is also included and arranged alphabetically by subject.
FAQ Index
Questions and Responses Arranged by Chapter 78 Section:
Regulatory Citation(s):
Section 78.52. Predrilling or prealteration survey.
(d) An operator electing to preserve its defenses under section 208(d)(1) of the act shall provide a copy of the results of the survey to the Department and the landowner or water purveyor within 10-business days of receipt of the results. Test results not received by the Department within 10 business days may not be used to preserve the operator's defenses under section 208(d)(1) of the act.
Question:
As operators become more pro-active in delineating background groundwater conditions, more incidents of elevated methane in the groundwater and/or in the headspace of water wells may be recognized. Background concentrations may be related to natural conditions, a legacy problem, or recent activity by another operator. What is the Department's position regarding reporting if an operator discovers methane while conducting their background analyses?
Response:
The new regulations require operators to provide the Department with their pre-drill survey data within 10 days of receipt from the lab. The operator is not required to call the Department's attention to "anomalous" occurrences of methane. Further, there is no obligation for the operator to conduct any kind of further investigation envisioned by Section 78.89 if they discover "anomalous" gas readings during the pre-drill survey. If, however, the operator receives a complaint about gas in a water well, they must respond and cannot use the pre-drill survey as a defense regarding the obligations imposed by Section 78.89. To the extent Department staff are available and aware of "anomalous" occurrences of methane, they will investigate the possible sources of the gas.
(1) Location of Additional Controls for Operation of BOP Equipment with a Pressure Rating of 3,000 psi or Higher: Section 78.72(c)
Regulatory Citation(s):
78.72. Use of safety devices – blow-out prevention equipment.
(c) Controls for the blow-out preventer shall be accessible to allow actuation of the equipment. Additional controls for a blow-out preventer with a pressure rating of greater than 3,000 psi, not associated with the rig hydraulic system, shall be located at least 50 feet away from the drilling rig so that the blow-out preventer can be actuated if control of the well is lost.
Question:
What is the actual point of reference for locating the remote BOP controls? Is there a standard location from which the 50-foot distance should be measured?
Response:
For deeper wells likely to encounter higher pressures, it is not uncommon to utilize more than one rig type during drilling operations and drill rig configurations have the potential to vary substantially when all supporting systems (closed-loop mud system, power supply equipment, etc.) are considered. Because of this, the Department considers the well location to be the most consistent reference point for determining the location of additional BOP controls. Therefore, the remote BOP system should be located a minimum of 50 feet from the well that is currently being drilled. (2) Daily Testing of Pipe and Blind Rams: Section 78.72(f)
Regulatory Citation(s):
78.72. Use of safety devices – blow-out prevention equipment.
(f) When the equipment is in service, the operator shall visually inspect blow-out prevention equipment during each tour of drilling operation and during actual drilling operations test the pipe rams for closure daily and the blind rams for closure on each round trip. When more than one round trip is made in a day, one daily closure for blind rams is sufficient. Testing shall be conducted in accordance with American Petroleum Institute publication API RP53…
Question:
API RP53 only requires function testing of rams once per week. Some operators have expressed concern that more frequent function testing will cause excessive equipment wear.
Response:
The Department's testing program for rams is more rigorous than API's in terms of testing frequency. By stating that testing should be conducted in accordance with API RP53, the regulations indicate that the procedural aspects of the recommended practice document that are relevant to function testing of rams should be followed, NOT the testing frequency recommendation.
The concern that daily testing may cause premature wear on ram-type BOP equipment will be considered in future regulation changes. (3) IADC Accredited BOP Schools: Section 78.72(h)
Regulatory Citation(s):
78.72. Use of safety devices – blow-out prevention equipment.
(h) When a blowout preventer is installed or required under subsection (a), there shall be present on the well site an individual with a current certification from a well control course accredited by the International Association of Drilling Contractors (IADC) or other organization approved by the Department.
Question:
What organizations/companies provide the necessary IADC accredited well control course?
Response:
The link below provides all the information currently available on this matter. US schools can be accessed by selecting the link titled "United States/Canada. (PDF)"
IADC Website
(1) Pressure Test to Demonstrate that all Fluids will be Contained within the Well when Surface Casing is used as Production Casing: Section 78.83(a)(2)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(a)(2) The operator demonstrates that the pressure in the well is no greater than the pressure permitted under 78.83(c), demonstrates through a pressure test or other method approved by the Department that all gas and fluids will be contained within the well…
Question:
What type of pressure testing is required?
Response:
Various procedures exist for conducting pressure testing to ensure well integrity. Some information regarding testing procedures used by EPA under the UIC Program can be found by selecting the links that follow this response. It is important to note that modifications would be necessary, if utilized, as the procedures applied under the UIC Program pressure up annular spaces, whereas the pressure testing referenced under 78.83(a)(2) would involve applying pressure inside the surface casing string. It is also important to note that the maximum pressures applied must consider several factors that are detailed in the proceeding paragraph.
Surface casing used as production casing must not be exposed to pressures in excess of 80% of the hydrostatic pressure at the casing seat during the operating lifetime of the well. Therefore, that is the minimum pressure that a well would need to be tested to in order to ensure that produced fluids are contained within the well. However, operators must ensure that produced fluids are contained within the well during drilling activities as well, so the pressure test may need to expose the casing to a higher pressure in certain instances. For example, the highest pressure surface casing could potentially be exposed to is likely associated with the pressure imparted by drilling fluid needed to control kicks encountered after drilling out the shoe and extending the wellbore to total depth.
Links to EPA Pressure Testing Technical Guidance (note that these are provided just as one general reference and that modifications would be necessary if used to test the integrity of the surface casing seat under Section 78.83(a)(2)):
EPA Pressure Testing Technical Guidance (Reference 1)
EPA Pressure Testing Technical Guidance (Reference 2)
(2) Surface Casing Set Depth: Section 78.83(c)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(c) The operator shall drill to approximately 50 feet below the deepest fresh groundwater or at least 50 feet into consolidated rock, whichever is deeper, and immediately set and permanently cement a string of surface casing to that depth. Except as provided in subsection (f), the surface casing may not be set more than 200 feet below the deepest fresh groundwater except if necessary to set the casing in consolidated rock.
Question:
How deep below the deepest fresh groundwater do you have to set surface casing, 50 or 200 feet?
Response:
Surface casing must be set at least 50 but no more than 200 feet below the deepest fresh groundwater formation unless it is necessary to drill deeper to set the casing in competent bedrock.
(3) Surface Casing Set Depth for Wells where Pipe was Ordered in Consideration of Old Regulations: Section 78.83(c)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(c) The operator shall drill to approximately 50 feet below the deepest fresh groundwater or at least 50 feet into consolidated rock, whichever is deeper, and immediately set and permanently cement a string of surface casing to that depth. Except as provided in subsection (f), the surface casing may not be set more than 200 feet below the deepest fresh groundwater except if necessary to set the casing in consolidated rock.
Question:
An operator planned to use a two-string (not including conductor) well design with a surface string more than 200 feet below the deepest fresh groundwater, but the new regulations require a surface casing set depth of no more than 200 feet beyond the deepest fresh groundwater formation, so they will change to a three-string design (surface/intermediate/production). The operator must order new pipe to transition to a three-string design. Regional technical staff indicate the Department may wish to be flexible in this situation, especially where operators have already set and cemented conductor pipe. The diameter of the conductor essentially dictates the number/O.D. of all inner strings. The alternative would be to have operators rip out all cemented conductor in order to reinstall larger conductor pipe.
Response:
It is acceptable to be flexible and allow the original well design only if the conductor pipe was cemented at the time the regulations were finalized. (4) Necessity to Order Centralizers for Surface, Coal Protective, or Water Protective Casing Currently Being Run Under Old Regulations: Section 78.83(c)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(c) When drilling a new well or redrilling an existing well, the operator shall install at least one centralizer in intervals no greater than every 150 feet above the first centralizer (surface casing string).
(f) The operator shall install at least one centralizer within 50 feet of the casing seat and then install a centralizer at intervals no greater than, if possible, every 150 feet above the first centralizer (additional water protective casing string).
(g) The operator shall install at least two centralizers. One centralizer shall be within 50 feet of the casing seat and the second centralizer shall be within 100 feet of the surface (coal protective casing string installed through workable coal seam).
(i) The operator shall install at least one centralizer within 50 feet of the casing seat and then install a centralizer at intervals no greater than, if possible, every 150 feet above the first centralizer (additional water protective casing string extending below coal protective string).
Question:
An operator is currently running surface, coal protective, or water protective casing. The new regulations require centralizers placed in certain locations and specify a minimum installation frequency. Do they need to order more centralizers and wait?
Response:
If they are currently running casing, they do not need to order more centralizers and postpone well construction activities. However, for any casing installations that were scheduled to start after the effective date of the new regulations (February 5, 2011), an appropriate number of centralizers must be ordered prior to running the casing and installed in accordance with the regulations. (5) Surface Casing Set Depth and Use of Multiple Water Protective Casing Strings: Section 78.83(c)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(j) If it is anticipated that cement used to permanently cement the surface casing cannot be circulated to the surface a cement basket may be installed immediately above the depth of the anticipated lost circulation zone. The casing shall be permanently cemented by the displacement method. Additional cement may be added above the cement basket, if necessary, by pumping through a pour string from the surface to fill the annular space. Filling the annular space by this method does not constitute permanently cementing the surface or coal protective casing under Section 78.83b (relating to casing and cementing-lost circulation).
Question:
In instances where no surface returns are observed, does filling the annulus of the surface or coal protective casing using a pour string render that casing string permanently cemented?
Response:
The regulatory citation above clearing indicates that filling the annular space of a surface or coal protective string using a pour string does not render the casing string permanently cemented in circumstances where no returns were observed during the primary cementing operation: Filling the annular space by this method does not constitute permanently cementing the surface or coal protective casing under Section 78.83b (relating to casing and cementing-lost circulation). (6) Use of Detergents When Drilling Surface or Coal Protective Hole: Section 78.83(c)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(c) The surface hole shall be drilled using air, freshwater, or freshwater-based drilling fluid.
Question:
Is injecting detergent into the air stream permissible when drilling the surface or coal protective hole?
Response:
Detergents are most commonly used to reduce surface tension and facilitate the removal of cuttings. They also enable faster penetration rates and lower pressure while drilling. These benefits contribute toward a cleaner hole, which is critical during cementing operations. Since detergents are typically additives associated with tophole operations, using them is permissible when drilling the surface or coal protective hole as long as they are a standard formulation and used in a conventional manner.
(7) Use of Manufactured Versus Fabricated Centralizers: Sections 78.83(c), (f), (g), and (i)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(c) When drilling a new well or redrilling an existing well, the operator shall install at least one centralizer within 50 feet of the casing seat and then install a centralizer in intervals no greater than every 150 feet above the first centralizer.
(f) The operator shall install at least one centralizer within 50 feet of the casing seat and then install a centralizer in intervals no greater than, if possible, every 150 feet above the first centralizer.
(g) The operator shall install at least two centralizers. One centralizer shall be within 50 feet of the casing seat and the second centralizer shall be within 100 feet of the surface.
(i) The operator shall install at least one centralizer within 50 feet of the casing seat and then, if possible, install a centralizer in intervals no greater than every 150 feet above the first centralizer.
Question:
Do operators need to use store-bought centralizers or can they make their own?
Response:
The regulations do not specify whether centralizers must be purchased from an established manufacturer or if they can be fabricated by the driller/operator. Therefore, any centralizers can be used provided they function effectively as centralizers, i.e., they are capable of keeping the casing string centralized within the wellbore, do not impede flow or cause bridging of cement, and are sufficiently durable that they will not malfunction when casing is being run or cemented.
(8) Cementing from Surface Using a Pour String and Cement Basket and Definition of Permanently Cemented Casing: Section 78.83(j)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(j) If it is anticipated that cement used to permanently cement the surface casing cannot be circulated to the surface a cement basket may be installed immediately above the depth of the anticipated lost circulation zone. The casing shall be permanently cemented by the displacement method. Additional cement may be added above the cement basket, if necessary, by pumping through a pour string from the surface to fill the annular space. Filling the annular space by this method does not constitute permanently cementing the surface or coal protective casing under Section 78.83b (relating to casing and cementing-lost circulation).
Question:
In instances where no surface returns are observed, does filling the annulus of the surface or coal protective casing using a pour string render that casing string permanently cemented?
Response:
The regulatory citation above clearing indicates that filling the annular space of a surface or coal protective string using a pour string does not render the casing string permanently cemented in circumstances where no returns were observed during the primary cementing operation: Filling the annular space by this method does not constitute permanently cementing the surface or coal protective casing under Section 78.83b (relating to casing and cementing-lost circulation).
(9) Use of Back-up Cement Baskets: Section 78.83(j)
Regulatory Citation(s):
78.83. Surface and coal protective casing and cementing procedures.
(j) If it is anticipated that cement used to permanently cement the surface casing cannot be circulated to the surface a cement basket may be installed immediately above the depth of the anticipated lost circulation zone.
Question:
If an operator wishes to install a back-up cement basket in the event that the uppermost basket fails, what are appropriate set depths for each basket used?
Response:
Cement baskets are attached to the casing at pipe joints, and so the location of the first basket should be placed at the pipe joint immediately above the zone of lost circulation. The second cement basket should be no more than one pipe section above the lowermost basket. Placing a cement basket near the surface and leaving long sections of the surface or coal protective casing exposed to the formation is not recommended.
(1) Need to Implement Lost Circulation Contingencies when Surface Returns are Observed During Surface or Coal Protective Casing Cementing but Fall-Back Occurs: Section 78.83b.
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
If cement is seen at the surface but it falls back, is it OK to drill out and determine the TOC later?
Response:
Cement returns observed at the surface waive the lost-circulation requirements of Section 73.83b., even in the event of cement fall-back. If cement returns are observed at the surface, the casing string is considered permanently cemented. Deviating from engineered pumping rates or any other recommended cementing practices during cementing operations should not be undertaken in an attempt to realize surface returns. Special care must always be taken to avoid scenarios where the combined effect of hydrostatic pressure and friction pressure in the annulus exceeds the breakdown pressure of the formation (i.e., concept of equivalent circulating density (ECD)).
(2) Running Cement Bond Log (CBL) to Determine Top of Cement: Section 78.83b.(a)
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
How long does an operator have to wait before running a CBL? Can they start drilling in 8 hours and complete the log prior to setting the next string of casing?
Response:
A CBL may be useful for determining the top of cement in situations where surface returns are recommended or expected but not achieved. Other logging methods may also be helpful in such a scenario.
The United States EPA states that cement should be allowed to develop full compressive strength prior to running CBL. They suggest 72 hours as a conservative rule-of-thumb. Running such a log prior to allowing the cement to achieve full compressive strength may show poor bonding (Ground Water Section Guidance No. 34). The Department currently must authorize continued drilling, so an operator may not start drilling until the Department is notified and approval to continue operations is granted.
One risk of drilling out casing and extending the wellbore prior to running a cement bond log is that if cement integrity is compromised, extending the wellbore may expose defective cement to natural open flow pressures and other formational fluids.
(3) Drilling Out in the Absence of Surface Returns: Section 78.83b.(a)
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
What are operators supposed to do in the evenings and on weekends to avoid job delays? Is the notification/approval requirement something that can be pre-approved in a casing and cementing plan (i.e., actions to be taken in the event of no cement returns)? Can a pressure test completed after the shoe is drilled out that shows the cement and casing will hold pressure substitute for the cement log until the well is drilled, at which time the operator can define the cement top by running their usual suite of logs? This will prevent them from having to rig down and accommodate a logging truck.
This requirement seems potentially problematic based on the amount of loggers available, time to schedule the log, the cost for two log jobs, rig down time, and trying to contact the Department after hours. Getting a logging truck to the site to determine the top of cement may take up to a few days and result in drilling delays. Some shallow oil operators that may or may not produce gas don't see surface returns on surface strings 50% of the time. Oftentimes the cement does not fall back too far in these cases based on Department inspector experience.
Response:
Operators are not permitted to drill out prior to determining the top of cement and getting approval from the Department to proceed. If the cement is defective and drilling continues, more widespread problems may result. Additionally, the new regulations require a zone of critical cement for the surface casing over the bottom 300 feet of this string (Section 78.85(b)). If the surface string is less than 300 feet long, the entire length must be cemented with higher strength, lower free water type cement. Because of this, the Department does not agree that establishing an area of alternative methods under Section 78.75 is appropriate, as it would essentially undermine regulations tailored for the most critical cemented length of casing in oil and gas wells from an environmental perspective – that which is designed to protect fresh groundwater.
(4) Determining if TOC is Sufficient to Continue Drilling: Section 78.83b.(a)
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
In cases where cement returns are not realized for the surface casing, what criteria should be used to determine if drilling can continue or if the operator must plug and skid? Is there a cemented interval length/percentage benchmark that, if not achieved, would classify the cement job as a "catastrophic failure?" What is the appropriate course of action when cement returns are not achieved in terms of additional cementing?
Response:
After the top of cement is determined, the Department inspector or Regional Office should apply their discretion to decide if the cement sheath is sufficient for long term well integrity. This decision should be based on planned wellbore depths, expected subsurface conditions beyond the surface casing seat – including characteristics of any hydrocarbon-bearing zones likely to be encountered, characteristics of the formation(s) over the portion of the tophole section that is not isolated behind cement, the necessary support for any BOP apparatus that will be mounted on the surface casing string, and other considerations. Additionally, groundwater must be protected through the isolation of freshwater bearing zones from produced fluids or surface infiltration.
To prevent the infiltration of surface liquids, some type of surface seal/wellhead apparatus must be put in place at a minimum. A cement top job is not necessarily the recommended practice for establishing a surface seal, as in the event of casing corrosion/deterioration over the uncemented interval, a direct conduit for produced fluids to enter the zone of fresh groundwater may develop and the ability to vent the annular space or attempt repairs will be limited. Additionally, groundwater may enter the wellbore through corroded sections of casing resulting in additional pressure at the casing seat in circumstances where producing back pressures associated with gas are already causing pressure at the surface casing seat.
One of the options in Section 78.83b.(a)(1)-(5) or some other approved action under Section 78.75 must always be implemented when cement surface returns are not observed.
(5) Contacting the Department After Hours or on Weekends in Order to Continue Drilling in Cases where Lost Circulation Occurs: Section 78.83b.(a)
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
How do operators proceed on weekends if they can't contact the Department to report no returns?
Response:
Once the top of cement is determined, the Department should be contacted and operations should not proceed until approval is granted. If notification takes place on a weekend or after hours, there may be some delay in operations at the well site. It is recommended that operators establish a pre-approved course of action in areas of operation where lost-circulation problems are expected and effective methods for countering these problems have been developed. This will help avoid any unnecessary down time on weekends or after normal business hours.
(6) Determining TOC Using Cement Head Displacement Pressure Prior to Drilling Out: Section 78.83b.(a)
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
All the companies want to know if they can calculate the cement top with the cement displacement pressure to comply with 78.83b.(a)?
Displacement methodology proposed (summarized through discussions with operators):
• Pressure reading is acquired at the wellhead
• Must shut down prior to landing second wiper plug that isolates cement column from chaser water and let pressure stabilize
• Once cement is pumped, a positive pressure will exist at the wellhead
• Cement will be in annular space, and water will be inside surface casing when pressure reading is acquired
• Back pressure on cement head is measured once the column stabilizes – this is essentially a hydrostatic calculation that considers cement density
• Process takes about 5 to 10 minutes (similar to mud balance determination process)
Response:
The Department does not currently view this method as an acceptable means for determining the top of cement in the event of lost circulation. Although there are scenarios where the method could result in an accurate determination of the top of cement, there are also many situations in which the calculation would not be sufficient for achieving this end. The main issue arises as a consequence of multiple fluids occurring in the annular space that are of different densities, e.g., cement and a spacer or gel water. Under such conditions, there are many combinations of cement and the other fluids that could result in the same pressure reading (see chart below). This limits the ability of the operator to accurately estimate the column of cement in the annular space based solely on a pressure measurement.
(7) Need to Run Additional Casing when Multiple Water Protective or Coal Protective Casing Strings are Installed: Section 78.83b.(a)
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
If multiple coal protective or water protective strings are run in a single wellbore and circulation is lost on any one of these strings, is it necessary to install at least one additional casing string needed if the operator intends to produce gas?
Response:
Any lost circulation zones encountered during the cementing of any water or coal protective casing string which prevent surface returns necessitate the installation of at least one additional casing string unless only oil will be produced at the well location and the annulus between the tubing and the surface casing is vented. It should be noted that the coal protective strings installed in areas where the coal seam has been mined have a specific installation protocol described under Section 78.83(h). This protocol is intended to minimize the potential for lost circulation.
(8) Implementing Methods that Deviate from Section 78.83b.(a)(1) – (4) or Changing Method Initially Selected under Section 78.83b.(a)(1) – (4): Section 78.83b.(a)(1) – (4)
Regulatory Citation(s):
78.83b. Casing and cementing – lost circulation.
(a) If cement used to permanently cement the surface or coal protective casing is not circulated to the surface despite pumping a volume of cement equal to or greater than 120% of the calculated annular space, the operator shall determine the top of the cement, notify the Department, and meet one of the following requirements as approved by the Department.
Question:
Section 78.83b.(a)(1) – (4) provides four specific casing options in the event that lost circulation is encountered over the surface casing interval. Are operators allowed to select one method preliminarily but change to another method later? Can subtle variations of these methods be implemented if deemed acceptable by the appropriate Regional contact and how should these procedures be documented?
Response:
Operators have the flexibility to deviate from their initial plan and select from any of the other available options under the referenced section of the regulations provided the rationale for doing so is deemed acceptable and the selected method does not introduce any environmental or well integrity concerns associated with the lost circulation zone or other site-specific conditions. The change in methods and Department approval should be documented in all cases.
Other reasonable and technically sound methods for addressing lost circulation may also be implemented even if they vary from Section 78.83b.(a)(1) – (4). However, they must be approved by the appropriate Regional staff prior to implementation and should be documented using the methods available under Section 78.75 either prior to or after execution of the alternate casing and cementing procedure.
(1) Shoe Test Requirement for Shallow Operators that Must Now Run Two Strings to Isolate Brines Above Target Reservoir (Includes Example of Alternate Method that May be Used for Production Casing Installation): Section 78.83c.(b) and (c)
Regulatory Citation(s):
78.83c. Intermediate and production casing.
(b) If the well is to be equipped with an intermediate casing, centralizers shall be used and the casing shall be cemented to the surface by the displacement method. Gas may be produced off the intermediate casing if a shoe test demonstrates that all gas will be contained within the well and a relief valve is installed at the surface that is set less than the shoe test pressure. The shoe test pressure shall be recorded in the completion report.
Question:
Due to the new regulations preventing a long surface string through both fresh groundwater and brackish groundwater, shallow operators who historically set one string through fresh groundwater and the permeable Clarion Sand, which produces a significant amount of brine, are now forced to set two strings. In a typical scenario, they will run 300 feet of surface casing and 500 feet of intermediate casing in a 1000 foot well. If they wish to produce off of the intermediate string, what does the shoe test entail?
Response:
In this case, the second string would actually be considered production casing and not intermediate casing. By virtue of the definition, intermediate casing must be surrounded by a larger diameter string – oftentimes the surface string – and it must surround a smaller diameter string – the production string or another intermediate string. Since only two strings aside from conductor pipe are described in the scenario above, the second string by definition is production casing and the shoe pressure test is not required.
Although regulations dictating the installation of production casing can be found in Section 78.83c., an alternate method under Section 78.75 is considered acceptable for addressing this specific scenario. An example of the alternate method (PDF) is provided for reference.
(2) Use of Manufactured Versus Fabricated Centralizers: Sections 78.83c.(b) and (c)
Regulatory Citation(s):
78.83c. Intermediate and production casing.
(b) If the well is to be equipped with an intermediate casing, centralizers shall be used…
(c) If the production casing is cemented in place, centralizers shall be used…
Question:
Do operators need to use store-bought centralizers or can they make their own?
Response:
The regulations do not specify whether centralizers must be purchased from an established manufacturer or if they can be fabricated by the driller/operator. Therefore, any centralizers can be used provided they function effectively as centralizers, i.e., they are capable of keeping the casing string centralized within the wellbore, do not impede or cause bridging of cement, and are sufficiently durable that they will not malfunction when casing is being run or cemented.
(1) Need to Pressure Test Used Intermediate Casing Installed Under Old Regulations Prior to Running Production Casing: Section 78.84(c)
Regulatory Citation(s):
78.84. Casing standards.
(c) Used casing may be approved for use as surface, intermediate, or production casing but shall be pressure tested after cementing and before continuation of drilling. A passing pressure test is holding the anticipated maximum pressure to which it will be exposed for 30 minutes with not more than a 10% decrease in pressure.
Question:
Used casing was installed and cemented for the intermediate string of a well under the old regulations. No pressure testing was conducted because this requirement was not in place under the old regulations. The operator just drilled the production hole and is now running production pipe. Do they need to conduct the pressure test?
Response:
Pressure testing of the intermediate casing must be conducted.
(2) Need to Pressure Test Welded or Used Surface Casing for Wells Where Surface Casing is Used as Production Casing and No Gas-Bearing Zones are Present: Section 78.84(c) and (d)(1)
Regulatory Citation(s):
78.84. Casing standards.
(c) Used casing may be approved for use as surface, intermediate, or production casing but shall be pressure tested after cementing and before continuation of drilling. A passing pressure test is holding the anticipated maximum pressure to which it will be exposed for 30 minutes with not more than a 10% decrease in pressure.
(d) New or used plain end casing, except when being used as conductor pipe, that is welded together for use must meet the following requirements:
(1) The casing must pass a pressure test by holding the anticipated maximum pressure to which the casing will be exposed for 30 minutes with not more than 10% decrease in pressure. The operator shall notify the Department at least 24 hours before conducting the test. The test results shall be entered on the drilling log.
Question:
Is pressure testing for used or welded surface casing necessary when surface casing will be used as production casing and no gas pressure is anticipated?
Response:
The intent of the above regulatory citations is to prevent produced fluids (i.e., gas and brines) from entering the surrounding formation through casing breaches, which are more likely to occur in used and welded casing sections. In a scenario where no gas-bearing formations will be encountered over the open hole interval of the well, casing integrity problems will result in the infiltration of fresh groundwater into the surface casing rather than the escape of gas beyond the footprint of the well. Although this poses a problem with regard to efficient operation of the well, it does not result in significant environmental risks and, therefore, the maximum anticipated pressure in this case is considered 0 psi and pressure testing is not required. At their discretion, an operator may wish to pressure test the casing to a pressure equivalent to the hydrostatic pressure at the surface casing seat to ensure that welded joints and used casing sections will prevent fresh groundwater from entering the wellbore and affecting operations.
(3) Need to Pressure Test Welded Casing: Section 78.84(d)(1)
Regulatory Citation(s):
78.84. Casing standards.
(d) New or used plain end casing, except when being used as conductor pipe, that is welded together for use must meet the following requirements:
(1) The casing must pass a pressure test by holding the anticipated maximum pressure to which the casing will be exposed for 30 minutes with not more than 10% decrease in pressure. The operator shall notify the Department at least 24 hours before conducting the test. The test results shall be entered on the drilling log.
Question:
Is pressure testing for welded surface casing necessary when a second string of casing is run?
Response:
All welded casing strings, aside from the conductor pipe, must be pressure tested. Well construction details have no bearing on this requirement.
(4) Welding Certification: Section 78.84(d)(3)
Regulatory Citation(s):
78.84. Casing standards.
(d) New or used plain end casing, except when being used as conductor pipe, that is welded together for use must meet the following requirements:
(3) The casing shall be welded by a person trained and certified in the applicable American Petroleum Institute, American Society of Mechanical Engineers, American Welding Society, or equivalent standard for welding casing and pipe or an equivalent training and certification as approved by the Department. The certification requirements of this paragraph shall take effect August 5, 2011. A person with 10 or more years of experience welding casing as of February 5, 2011, who registers with the Department by November 7, 2011, is deemed to be certified.
Question:
Is welding certification or registration required for welders working on equipment around the wellhead?
Response:
The regulation only prescribes welding certification requirements for personnel welding new or used plain end casing. The wellhead is not covered/addressed under this regulation.
(5) Pressure Testing of Intermediate Casing to which a 3,000 psi or Greater BOP will be Attached: Section 78.84(f)
Regulatory Citation(s):
78.84. Casing standards.
(f) Casing which is attached to a blow-out preventer with a pressure rating of greater than 3,000 psi shall be pressure tested after cementing. A pressure test must be holding the anticipated maximum pressure to which casing will be exposed for 30 minutes with not more than a 10% decrease. Certification of the pressure test shall be confirmed by entry and signature of the person performing the test on the driller's log.
Question:
Regarding the pressure testing of intermediate casing that will be equipped with a 3000 psi or larger BOP: How long do operators have to wait before completing the pressure test? If the pressure test is conducted within the first 8 hours following cement placement, will it jeopardize the cement in the annulus or cause a micro annulus? How do operators determine what the anticipated pressure is going to be? Are they to set a plug above the intermediate casing shoe so the pressure is not against the casing shoe?
Response:
According to API RP65 – Part 2, pressure testing of casing should be done before significant gel strength has developed in the cement. This pressure testing will ultimately be limited by the pressure ratings of plugs, floats, cementing heads, and other equipment. Pressure testing after the cement has set can result in microannulus formation or damage to the cement sheath. The pressure should only ever be held for the shortest amount of time required to achieve the objectives of the test. Mechanical stress modeling is one way to determine the optimal time for conducting pressure testing (Section 4.10.2 of API RP65 – Part 2).
Standard tests for determining gel strength can be found in API 10B-6/ISO 10426-6. Service companies have expertise in estimating gel strength based on expected wellbore conditions (Section 4.7.8 of API RP65 – Part 2).
Prior to drilling, minimizing encounters with potential flow zones can be achieved by accurate review and analysis of available shallow and deep hazards data, and proper interpretation of this information. One way to determine anticipated pressures is to rely on data gathered at offset wells. Shallow and deep hazard identification and evaluation can also both be accomplished through the use of seismic surveys. Shallow seismic surveys over potential wellsites may be helpful and should be supplemented with shallow seismic data collected at offset wells or from adjacent fields where shallow flows occurred. The supplemental data will assist in verification of expected conditions at the proposed well site. Deeper subsurface hazards can often be identified through seismic interpretation and/or analysis of offset wells or fields. If available, it is recommended that deep seismic data from offset wells or adjacent fields be analyzed to aid in the prediction of flow zones (API RP65 – Part 2, Annex B).
(1) Alternatives to "Gas Block" Additives: Section 78.85(a)(5)
Regulatory Citation(s):
78.85. Cementing standards.
(a) When cementing surface casing or coal protective casing, the operator shall use cement that meets or exceeds the ASTM International C 150, Type I, II, or III Standard or API Specification 10. The cement must also:
(5) Prevent gas flow in the annulus. In areas of known shallow gas producing zones, gas block additives and low fluid loss slurries shall be used.
Question:
A well service company contacted the Department concerning the use of gas block additives and low fluid loss slurries to prevent annular flow in areas of known shallow gas producing zones. If the blend they use prevents annular flow without using "gas block" additives, is the mix design recognized as meeting the requirement? Is there a performance demonstration that must be executed to demonstrate that the blend meets this standard?
Response:
If the specific cement blend, or mix design, is formulated to prevent gas flow in the annulus, then in concept it could meet the substantive requirement of the referenced citation. However, information from the well service company that details how the blend accomplishes the gas blocking function should be requested.
There is currently no written "performance standard" to demonstrate that a specific blend meets this regulatory requirement, but in practice a performance standard would be known cement jobs where the blend was used and achieved surface returns while also successfully preventing the occurrence of annular flow attributable to the failure of the cement to prevent gas intrusion/cutting.
(2) Necessity to Reformulate Cement Mix Design for Zone of Critical Cement when Cement Formulation was Developed in Consideration of Old Regulations: Section 78.85(b)
Regulatory Citation(s):
78.85. Cementing standards.
(b) After the casing cement is place behind surface casing, the operator shall permit the cement to set to a minimum designed compressive strength of 350 pounds per square inch (psi) at the casing seat. The cement placed at the bottom 300 feet of the surface casing must constitute a zone of critical cement and achieve a 72-hour compressive strength of 1,200 psi and the free water separation may be no more than 6 milliliters per 250 milliliters of cement. If the surface casing is less than 300 feet, the entire cemented string constitutes a zone of critical cement.
Question:
Regulations are finalized while the operator is finishing drilling the surface hole with a tophole rig and a service company will be cementing the surface casing soon. Materials have been ordered and the service company contract is in place. New cement standards require a zone of critical cement which may require new materials, cement vendor testing, etc. Although it is relatively easy in many circumstances to quickly have the service company change/reformulate the cement blend, depending on timing and how soon the surface casing is to be cemented, there may be situations where it might not be practical to comply with the new regulations.
Response:
Reasonable accommodation to allow cement as prescribed under the old regulations is permissible. However, the new regulations requiring cement returns to the surface or notice to the Department in the event that surface returns are not achieved are still required.
(3) Availability of Cement Job Log: Section 78.85(f)
Regulatory Citation(s):
78.85. Cementing standards.
(f) A copy of the cement job log shall be available at the well site for inspection by the Department during drilling operations. The cement job log must include…
Question:
Must operators provide the log for all cement jobs already performed, or just for those that had not yet been completed by February 5, 2011?
Response:
Cement job logs need only be available for cement jobs completed after February 5, 2011.
(1) Start Date for Quarterly Inspections: Section 78.88(a) and (e)
Regulatory Citation(s):
78.88. Mechanical integrity of operating wells.
(a) Except for wells regulated under Subchapter H (relating to underground gas storage) and wells that have been granted inactive status, the operator shall inspect each operating well at least quarterly to ensure it is in compliance with the well construction and operating requirements of this chapter and the act. The results of the inspections shall be recorded and retained by the operator for at least 5 years and be available for review by the Department and the coal owner or operator.
(e) The operator shall submit an annual report to the Department identifying the compliance status of each well with the mechanical integrity requirements of this section. The report shall be submitted on forms prescribed by, and available from, the Department or in a similar manner approved by the Department.
Question:
The draft Department form is not yet finalized. If an operator is ready to conduct the inspection, will they be granted a one-quarter grace/transition period? Operators are uncertain regarding the specifics of the mechanical integrity demonstration that will be required on the to-be-finalized form which went out for Regional comments on February 4, 2011 and has also been circulated among operators via TAB and industry trade groups.
Response:
The start date for the mechanical integrity monitoring program is the first full quarter following finalization of the form.
(1) Running Cement Bond Log (CBL) to Assess Adjacent Oil or Gas Wells: Section 78.89(e)(3)
Regulatory Citation(s):
78.89. Gas migration response.
(e) The Department may require the operator to take the following additional actions:
(3) Conduct an immediate evaluation of the operator's adjacent oil or gas wells to determine well cement and casing integrity and to evaluate the potential mechanism of migration. This evaluation may include assessing pressures for all casing intervals, reviewing records for indications of defective casing or cement, application of cement bond logs, ultrasonic imaging tools, geophysical logs, and other mechanical integrity tests as required. The initial area of assessment must include wells within a radius of 2,500 feet and may be expanded if required by the Department.
Question:
How long does an operator have to wait before running a CBL? Can they start drilling in 8 hours and complete the log prior to setting the next string of casing?
Response:
Running a CBL is not a required component of casing installation and cementing, but may be useful in certain situations including scenarios where surface returns are recommended or expected but not achieved. It is only referenced one time in Chapter 78 in the context of stray gas migration investigations under Section 78.89. The excerpted citation from Chapter 78 that mentions CBL can be found above.
The United States EPA states that cement should be allowed to develop full compressive strength prior to running CBL. They suggest 72 hours as a conservative rule-of-thumb. Running such a log prior to allowing the cement to achieve full compressive strength may show poor bonding (Ground Water Section Guidance No. 34).
One risk of drilling out casing and extending the wellbore prior to running a cement bond log is that if cement integrity is compromised, extending the wellbore may expose defective cement to natural open flow pressures and other formational fluids.
(1) Location of Cement Plugs for Contracts Established Prior to 2/5/11: Sections 78.92(a)(1), 78.93(a)(1), 78.94(a)(1), 78.95(a)(1)
Regulatory Citation(s):
78.92. Wells in coal areas – surface or coal protective casing is cemented.
(a) In a well underlain by a workable coal seam, where the surface casing or coal protective casing is cemented and the production casing is not cemented or the production casing is not present, the owner or operator shall plug the well as follows:
(1) The well shall be filled with non-porous material from the total depth or attainable bottom of the well, to a point 50 feet below the lowest stratum bearing or having borne oil, gas, or water. At this point there shall be placed a plug of cement, which shall extend for at least 50 feet below this formation to a point 50 feet above this formation.
78.93. Wells in coal areas – surface or coal protective casing anchored with a packer or cement.
(a) In a well where the surface casing or coal protective casing and production casing are anchored with a packer or cement, the owner or operator shall plug the well as follows:
(1) The well shall be filled with non-porous material from the total depth or attainable bottom of the well, to a point 50 feet below the lowest stratum bearing or having borne oil, gas, or water. At this point there shall be placed a plug of cement, which shall extend for at least 50 feet below this formation to a point 50 feet above this formation.
78.94. Wells in noncoal areas – surface casing is not cemented or not present.
(a) The owner or operator shall plug a noncoal well, where the surface casing and production casing are not cemented, or is not present as follows:
(1) The well shall be filled with non-porous material from the total depth or attainable bottom of the well, to a point 50 feet below the lowest stratum bearing or having borne oil, gas, or water. At this point there shall be placed a plug of cement, which shall extend for at least 50 feet below this formation to a point 50 feet above this formation.
78.95. Wells in noncoal areas – surface casing is cemented.
(a) The owner or operator shall plug a well, where the surface casing is cemented and the production casing is not cemented or not present, as follows:
(1) The well shall be filled with non-porous material from the total depth or attainable bottom of the well, to a point 50 feet below the lowest stratum bearing or having borne oil, gas, or water. At this point there shall be placed a plug of cement, which shall extend for at least 50 feet below this formation to a point 50 feet above this formation.
Question:
When currently plugging wells under an existing contract, must the plugging contractor place the plug in a manner consistent with the prior regulations, or move the location of the cement plug to across the producing formation(s) as prescribed in the new regulations? Altering plugging techniques in mid-contract would be inconsistent with the technical specifications established under the executed contract.
Response:
Plugging revisions only apply to new contracts, not existing contracts. This also applies to other operators plugging.
(2) Manual Backoff Method for Attempting to Remove Casing During Well Plugging: Sections 78.92(a)(1), 78.92(b)(3), 78.93(a)(1), 78.93(a)(3), 78.94(a)(1), 78.94(a)(3), and 78.95(a)(1)
Regulatory Citation(s):
78.92. Wells in coal areas – surface or coal protective casing is cemented.
(a) In a well underlain by a workable coal seam, where the surface casing or coal protective casing is cemented and the production casing is not cemented or the
(1) The retrievable production casing shall be removed by applying a pulling force at least equal to the casing weight plus 5,000 pounds or 120% whichever is greater. If this fails, an attempt shall be made to separate the casing by cutting, ripping, shooting or other method approved by the Department, and making a second attempt to remove the casing by exerting a pulling force equal to the casing weight plus 5,000 pounds or 120% of the casing weight, whichever is greater.
(b) The owner or operator shall plug the well, where the surface casing, coal protective casing and production casing are cemented, as follows:
(3) Following the plugging of the cemented portion of the production casing, the uncemented portion of the production casing shall be separated from the cemented portion and retrieved by applying a pulling force at least equal to the casing weight plus 5,000 pounds or 120% whichever is greater. If this fails, an attempt shall be made to separate the casing by cutting, ripping, shooting or other method approved by the Department, and making a second attempt to remove the casing by exerting a pulling force equal to the casing weight plus 5,000 pounds or 120% of the casing weight, whichever is greater.
78.93. Wells in coal areas – surface or coal protective casing anchored with a packer or cement.
(a) In a well where the surface casing or coal protective casing and production casing are anchored with a packer or cement, the owner or operator shall plug the well as follows:
(1) The retrievable production casing shall be removed by applying a pulling force at least equal to the casing weight plus 5,000 pounds or 120% whichever is greater. If this fails, an attempt shall be made to separate the casing by cutting, ripping, shooting or other method approved by the Department, and making a second attempt to remove the casing by exerting a pulling force equal to the casing weight plus 5,000 pounds or 120% of the casing weight, whichever is greater.
(3) After it has been established that the surface casing or coal protective casing is free and can be retrieved, the surface or coal protective casing shall be retrieved by applying a pulling force at least equal to the casing weight plus 5,000 pounds or 120% whichever is greater. If this fails, an attempt shall be made to separate the casing by cutting, ripping, shooting or other method approved by the Department, and making a second attempt to remove the casing by exerting a pulling force equal to the casing weight plus 5,000 pounds or 120% of the casing weight, whichever is greater.
78.94. Wells in noncoal areas – surface casing is not cemented or not present.
(a) The owner or operator shall plug a noncoal well, where the surface casing and production casing are not cemented, or is not present as follows:
(1) The retrievable production casing shall be removed by applying a pulling force at least equal to the casing weight plus 5,000 pounds or 120% whichever is greater. If this fails, an attempt shall be made to separate the casing by cutting, ripping, shooting or other method approved by the Department, and making a second attempt to remove the casing by exerting a pulling force equal to the casing weight plus 5,000 pounds or 120% of the casing weight, whichever is greater.
(3) After setting the uppermost 50-ffot plug, the retrievable surface casing shall be removed by applying a pulling force at least equal to the casing weight plus 5,000 pounds or 120% whichever is greater. If this fails, an attempt shall be made to separate the casing by cutting, ripping, shooting or other method approved by the Department, and making a second attempt to remove the casing by exerting a pulling force equal to the casing weight plus 5,000 pounds or 120% of the casing weight, whichever is greater.
78.95. Wells in noncoal areas – surface casing is cemented.
(a) The owner or operator shall plug a well, where the surface casing is cemented and the production casing is not cemented or not present, as follows:
(1) The retrievable production casing shall be removed by applying a pulling force at least equal to the casing weight plus 5,000 pounds or 120% whichever is greater. If this fails, an attempt shall be made to separate the casing by cutting, ripping, shooting or other method approved by the Department, and making a second attempt to remove the casing by exerting a pulling force equal to the casing weight plus 5,000 pounds or 120% of the casing weight, whichever is greater.
Question:
Is the "manual backoff" method considered acceptable before attempting to pull the casing a second time?
Response:
The inspector's or other Regional Office staff's discretion should be applied as to whether or not the "manual backoff method" constitutes another "Department approved method" on a case-by-case basis.
(1) Production Reporting Deadlines, Submissions, and Use of 26R Form: Section 78.121(a)-(b)
Regulatory Citation(s):
78.121. Production Reporting.
(a) The well operator shall submit an annual production and status report for each permitted or registered well on an individual basis, on or before February 15 of each year. The operator of a well permitted to produce gas from the Marcellus shale formation shall submit a production and status report for each well on an individual basis, on or before February 15 and August 15 of each year. Production shall be reported for the preceding calendar year or in the case of a Marcellus shale well, for the preceding 6 months. When the production data is not available to the operator on a well basis, the operator shall report production on the most well-specific basis available. The annual production report must include information on the amount and type of waste produced and the method of waste disposal or reuse. Waste information submitted to the Department in accordance with this subsection is deemed to satisfy the residual waste biennial reporting requirements of Section 287.52 (relating to biennial report).
(b) The production report shall be submitted electronically to the Department through its web site.
Question:
In reviewing the Annual Well and Waste Production Report instructions, it seems that if an operator reports the waste volumes and disposal mechanism (in this case for produced water) on the Wellsite Restoration Report that these volumes/disposal methods do not need to be reported again on the Annual Well and Waste Production Report. Additionally, the only volumes of produced water that need to be reported on the Annual Well and Waste Production Report appear to be volumes produced post-restoration. Is this correct?
Also, if an operator reports volumes/disposal method in either the Wellsite Restoration Report or the Annual Well and Waste Production Report, would these volumes/disposal methods need to be reported on the 26R Form?
Response:
The form that those instructions were written for is no longer in use. We now require operators to file their Production and Waste Report electronically with the Department through our website at the following location:
Oil and Gas Production and Waste Reporting Website
It is still necessary to file the Well Site Restoration Report form with the applicable Regional Office, but the waste reported on that form should be included in the operator's annual or 6-month Production and Waste Report at the above website. Reporting for Marcellus production is required every 6 months and is due February 15 and August 15 of each year. Other wells are reported annually by February 15.
The volumes reported on the Site Restoration and the Annual Production and Waste Report should have a 26R Form for each load of waste taken off the well site. A copy of the 26 R Form is to be retained by the generator, transporter, and disposal contractor for 5 years. Other Information Arranged Alphabetically:
Accessing API Standards Online:
Chapter 78 regulations occasionally incorporate API standards by reference. Numerous API standards are available for online viewing at the following web address:
API Standards
It is necessary to register at the site by providing an email address. The viewing software must also be downloaded and installed.
Applicability of Chapter 78 Versus Chapter 79:
Question 1:
Do the new regulations affect conservation wells as far as production/intermediate casing and BOPs? The sections pertaining to preventing waste differ slightly in Chapter 79 and the Conservation Law. There is nothing to indicate that the new Chapter 78 regulations supersede requirements in Chapter 79.
Response 1:
The intent of the new Chapter 78 regulations is to enhance these standards for all wells. Conservation regulations were somewhat more prescriptive when initially developed, but now may appear to be less so. However, since conservation wells are generally deeper than non-conservation wells, they should be regulated at least as stringently.
Considering the reference to Section 79.12, where it states that the intermediate string must run "sufficient" cement, the new Chapter 78 regulations now require cement to surface. Where the language in Chapter 79 is more generic, we would now interpret "sufficient" to mean to the surface, as per the new Chapter 78 regulations. Generally speaking, in instances where Chapter 79 is less conservative than Chapter 78 from an environmental protection or well safety standpoint and it is not prescriptive, Chapter 78 should apply.
Question 2:
If a well is permitted as a conservation well but doesn't penetrate the Onondaga, which Chapter applies?
Response 2:
Generally speaking, in instances where Chapter 79 is less conservative than Chapter 78 from an environmental protection or well safety standpoint and it is not prescriptive, Chapter 78 should apply. It should be noted that in the SW Region, operators have been given the option to apply for conservation well status when they penetrate the Onondaga and plug back, or when they tag the Onondaga over the directional leg of the wellbore.
Availability of New Regulations:
Question:
When are the regulations going to be merged and clarified on the BOGM website?
Response:
Comprehensive, current Chapter 78 regulations can now be accessed through the BOGM website or directly at pacode.com. The version of the regulations available at this location includes unrevised, revised, and new sections which became effective on February 5, 2011.
Due Diligence for Drilling a Well:
Question:
Section 601.201.(j) (Well Permits) of the Oil and Gas Act states that well permits issued for drilling of wells covered by the act shall expire one year after issuance unless operations for drilling the well are commenced within such period and pursued with "due diligence" or unless the permit is renewed in accordance with regulations of the Department. Many operators will spud the well and set conductor pipe or drill a portion of the well prior to expiration of the permit, but will not actually complete drilling to total depth for an extended period of time. How does the Department define "due diligence" under the Act, i.e., how long does an operator have to complete drilling to total depth after issuance of the permit?
Response:
In all cases an operator must commence drilling prior to expiration of the permit, or within one year of permit issuance. Further, the well must be drilled to total depth within 16 months of the permit issuance date, or no later than 4 months after expiration of the permit. The only exception to this is in cases where permits are renewed in accordance with standard Department procedures.
Training Information:
Question:
When is training scheduled for industry and Regional Office staff?
Response:
The Resources Management and Well Development Division has scheduled several Industry Training Workshops which will include a 75-minute session on the new Chapter 78, Subchapter D regulations. These sessions will only provide a brief introduction to the new or modified sections of the regulations and Well Plugging and Subsurface Activities Division staff will not necessarily be available during the sessions to answer specific questions. The submission of specific questions relevant to Subchapter D should be coordinated through appropriate Regional contacts. A link to the Industry Training Workshop agenda can be found below and is followed by the 2011 schedule.
Industry Training Workshop Agenda (PDF)
2011 Industry Training Workshop Schedule (PDF)
|
 |
|
|
|
