The well suspension deadline date will be 12 months after the inactive status date. Contradicts Section 8 of Directive 13: Inactive wells must be suspended according to the requirements of this directive within 60 days after the one year anniversary of no production or injection. I would recommend aligning Section 8 with the rest of the document & the timelines explored in Directive 13 & IWCP FAQ (in particular Q1.9 Q1.11). https://www.aer.ca/documents/directives/directive013iwcp FAQs.pdf There is no section 8 in the revision of. A revised version of is aligned with the Inactive Program FAQs document (http://www.aer.ca/rules regulations/directives/directive 013). 28 Mar Arlo Sutherl Production Engineer Shell Ltd. OK.Company has 24 months from shut in to achieve suspension compliance. That is correct. 29 Mar Abonment Excellent anniversary dates seems hard to find when the current producer has bought an old asset that hasn t been maintained for years. 10 Mar Michael Beck President owner Surface Solutions Section 1 states Pressure testing low risk type 1 wells not required for purpose of initial suspension nor at ongoing inspections however still stated on Table 1 as being required. Which is correct? Section 1 is correct. Table 1 has been corrected accordingly. 2 Mar Ferne McDonald Sr. Eng. Technologist Broadview Energy Ltd. 1a 1) The method through which compliance deadlines are calculated in section 2.1 would be changed. a. The well suspension deadline date will be 12 months after the inactive status date. This is a suggestion for an additional revision rather than feedback on one of the proposed revisions: It would be very beneficial for the AER industry at large if the new Directive 13 clarified the conditions needed for a when a SCVF test is performed. Specifically, I m referring to cold weather wells without vent assemblies installed, (although the same issue can occur on wells with vent assemblies as they freeze as well). Bulletin 2011 35 mentions that when the surface casing stub is not exposed that atmospheric conditions must be suitable for drawing a detection sample that the ability to detect leaks drops significantly when used in ambient temperatures below 10 C. Interim Directive 2003 01 says that Guide/Directive 20 outlines the SCVF/GM testing procedures. However, the only place that it is mentioned in Directive 20, ( Testing is to be done only in frost free months ) is only in reference to testing for gas migration. In the case of wells without vent assemblies you are effectively performing a gas migration test but this leaves a grey area. All of the cross references between the Directive, a Bulletin an Interim Directive make this an even greyer area leaving room for industry to not properly test for a surface casing vent flow. What I propose is that in the new Directive 13 the following changes be made: The requirements for testing repairing SCVF/GM are outlined in Interim Directive 2003 01 are outside of the current scope of revisions to. However, this suggestion will be documented for future revisions. 8 Mar Justin MacDonald Thermal Completions Superintendent Athabasca Oil Corp. Section 2.3.2 head Requirements: It is recommended that a surface casing vent flow (SCVF) test be conducted in accordance with Directive 020. If there is no vent assembly as required in OGCR section 6.100, the licensee should refer to Bulletin 2011 35. Testing is to be done only in frost free months. Table 1. Suspension requirements for all inactive wells: Surface casing vent flows: Testing is to be done only in frost free months. Good news. 24 Mar Jen Kuhn Drilling Analyst Suncor Energy
Section 2.1 General Requirements a. The well suspension deadline date will be 12 months after the inactive status date. Feedback/Suggested Changes Within the Example provided it states Therefore, the inspection requirements must be completed reported in the DDS system by December 31, 2017. Please confirm / clarify when the AER states completed this applies to the inspection not any repairs or monitoring which may be required? Please confirm the AER expect industry to complete the inspection by the inactive status date but enter the details into the AER DDS system by year end? Please clarify the AER s expectations. For the purpose of, Completed means all the work required under, including all the repairs, is conducted. In the event the repairs of the GM or SCVF require monitoring, the extension or deferral to repair must be issued by the AER under ID 2003 01. Provided that the approval of such extension or deferral is granted, the inspection outcome should indicate Repair Deferred will be deemed compliant with for the time of the approval. Please refer to the Inactive Program FAQs document, Q1.21, Q1.38, Q2.15 (http://www.aer.ca/rules regulations/directives/directive 013). Devon Items 1a through 7 are acceptable, there are a number of other good upgrades in the document Blair Temple Subsurface Engineering Imperial Oil Resources OK.Inspection deadlines in the year are consistently managed to the December 31st time frame based on calculation. That is correct. Please also refer to the Inactive Program FAQs document, Q4.13 (http://www.aer.ca/rules regulations/directives/directive 013). 29 Mar Abonment Very good idea, being that winter access can be an inspection / remediation issue. 10 Mar Michael Beck President owner Surface Solutions 1b 1) The method through which compliance deadlines are calculated in section 2.1 would be changed. b. The inspection deadline will be calculated based on the inspection due date in the Digital Data Submission System (DDS) moved from a specific date to the end of that calendar year. Section 1 The licensee must (last item) ensure that all wellheads are conspicuously marked or fenced. However the next paragraph states the licensee must ensure the wellhead is marked secured. Which is it? or or? In other words if you have a fence the wellhead doesn t have to be marked or vice versa? Or if you have the wellhead marked you don t have to have a fence? Please clarify. In OGCR Section 8.192 is states ensure that the wellhead is conspicuously marked OR fenced. However in Dir 13 as shown above you quote the OGCR as..ensure wellhead is marked AND secured. Please again clarify. This may become difficult in some areas where access is limited to winter work. Section 2.1 General Requirements b. The inspection deadline will be calculated based on the inspection due date in the Digital Data Submission System (DDS) moved from a specific date to the end of that calendar year. No feedback or suggested changes. For the purpose of compliance with the answer is Or, which is part of OGCR 8.192. The second paragraph in, section 2.3.2 has the following removed: ensure the wellhead is marked secured in accordance with OGCR section 8.193, This change is made to allow licensees additional time flexibility to plan execute ongoing inspections. The work can be conducted any time during the entire calendar year in which inspection is due. Therefore, it is the licensee s responsibility to appropriately schedule work for winter access areas to meet the deadlines. 2 Mar 24 Mar Ferne McDonald Jen Kuhn Sr. Eng. Technologist Drilling Analyst Broadview Energy Ltd. Suncor Energy Devon Administrative Changes The change to yearly submission of re inspections is a positive step that allows companies to plan execute cost effective work plans. The additional time to report after suspension is also a welcome change. Orest Kotelko Natural Resources Limited (CNRL) 2 The requirements for changing a highrisk well to medium OK..Clarified process to change from high risk. 29 Mar
or low risk in section 2.2 have been updated to clarify an existing process. More clarification is need for SAGD wells (Injector / Producer). D13 D51 should align in the future. The definition of risk category for SAGD wells was outside of the scope for this update to will be considered in future revisions of this directive. 24 Mar Jen Kuhn Abonment Drilling Analyst Suncor Energy Section 2.2 Changing Risk Category The requirements for changing a high risk well to medium or low risk in section 2.2 have been updated to clarify an existing process. No feedback or suggested changes. Devon It mentions in Directive 20 Surface abonment must be completed within 12 months after downhole abonment operations (section 8). In the draft directive 13 it states if all zones are aboned ( the well has not been surface aboned), the shallowest completion must be used to classify the risk category of the well (section 2.2). As a result a well, after a down hole abonment, can stay suspended but in compliance to directive 13 if the appropriate testing is completed. This would enable wells with down hole abonment to remain for future opportunities (e.g. Side track up hole completions). Recommend that Directive 20 be updated to reflect this. The update to Directive 020 is outside of the scope of. Future revisions to Directive 020 will ensure alignment with. 31 Mar Clayton Dubyk Environment Coordinator Shell Limited Imperial has concerns with some of the other changes that are not highlighted here Any changes that were not within the scope of this update to will have to be addressed with the next revision of. Blair Temple Subsurface Engineering Imperial Oil Resources 2.2 Changing Risk Category if all zones are aboned or declassified critical sour wells ( the well has not yet been surface aboned), the shallowest completion must be used to classify the risk category for the well. the well risk category is low risk Type 1. (Comment: All non critical sour wells that are zonally aboned should be included pursuant to the 5th paragraph on page 3) Paragraph 5 on page 3: Pressure testing low risk type 1 wells (cased hole wells that are not critical sour have no perforations, which also includes low risk wells with all zones properly aboned in accordance with Directive 020: Abonment) is not required for the purpose of initial suspension nor at the time of ongoing inspections. Aboning or declassifying critical sour wells does not meet the conditions of a type 1 well. The shallowest completion must be used to classify the risk category. If the critical sour zone is the shallowest completion, the well must be suspended as per medium risk requirements (that would include pressure test). To remove Critical Sour status, a declassification request must be sent to welloperations@aer.ca in accordance with Interim Directive 90 01: Completion Servicing of Sour s, section 5.2. If the approval is granted, the licensee would receive a declassification letter the electronic record of the well will be updated to Declassified Critical Sour. (Comment: AER should consolidate their various lists of critical sour wells to ensure they are consistent the published one is accurate) s in a particular risk category may also be suspended in accordance with the requirements of any higher risk category; however, the well must meet the initial suspension ongoing inspection requirements based on the higher risk category. (Comment: Placing a tubing plug in the packer of a low risk well should not require pressure testing. The goal is to have the right suspension in the field with the appropriate inspections not penalizing an error in reporting that does not alter the real risk of a well) Proper zonal abonment will substitute for a bridge plug suspension method when required; all the inspection requirements must be met accordingly. The list of critical sour wells is produced by the AER Information Service. Not all critical sour wells are inactive listed on the inactive well licence list. If a licensee chooses to suspend the well under the higher risk category report it as such, to remain compliant with the suspension work reporting must be maintained as per the risk category. The licensee may suspend at a higher risk category report it as the lower risk level, which would address your concern. Aaron M. Miller Manager of Closure & Northern Association of Petroleum Producers (CAPP)
For wells with multiple zones the well must be classified based on the highest risk zone in the wellbore that has not been aboned, in accordance with Directive 020: Abonment; if all zones are aboned critical sour wells have been declassified ( the well has not yet been surface aboned), the shallowest completion must be used to classify the risk category for the well the well risk category is low risk Type 1. (Comment: All non Critical Sour wells that are zonally aboned should be included as per the 5th paragraph on page 3) Same response as previously stated above. OK...Cavern wells are unique require a non routine application to establish site specific suspension criteria. 29 Mar Abonment 3 For inactive cavern wells, the licensee would submit a nonroutine application to the AER for suspension of storage disposal caverns related wells (section 3.2). Being that cavern wells have a special circumstance would observation wells also get special inspection circumstance, injection, gas storage? I would like these special circumstance to have testing procedures included in the regulation. When you go to test the special circumstance it would be good to know WHY how to approach the special circumstance remember that inactive wells are rarely on the radar in terms of awareness. With today s employee turnover there is less less knowledge about aging assets inside the oil companies. The economic factor around completing a inspection makes the inspection often completed by summer students / service companies that are doing the inspection at a low cost, which can mean a lower risk tolerance. Any regulator education that can be databased will help future inspections go safely. Section 3.2 Medium Risk s For inactive cavern wells, the licensee would submit a nonroutine application to the AER for suspension of storage disposal caverns related wells (section 3.2). No feedback or suggested changes. Feedback: It is not clear which parts of D013 apply to inactive cavern wells. Does the nonroutine application to AER resulting approval from AER supersede the rest of D013 for cavern well suspension? Cavern wells have unique operational requirements that are currently addressed through cavern scheme approval terms conditions. Observation wells are excluded from. Injection gas storage requirements are already in (medium risk type 4). Additional information regarding special circumstances is difficult, as each situation needs to be reviewed. That is correct the nonroutine suspension approval for the cavern wells will supersede the requirements of. 10 Mar Michael Beck President owner Surface Solutions Devon What should be changed: The requirements for suspending inactive cavern wells should either be clarified within D013 or it should be written that the AER non routine approval for suspension will specify the suspension requirements for the well associated cavern. The AER has developed a draft cavern directive that will eventually contain suspension requirements for cavern wells. 31 Mar Marcella Fiorillo dejong EH&S Manager Dow Chemical ULC Why it should be changed: For example, It is inappropriate to install a bridge plug or packer tubing plug on a cavern well to suspend, but this is listed in Table 1 for medium risk wells any well that has been inactive for more than 10 years is considered medium risk. This is confusing.
This is also a good time to incorporate other upgrades to Directive 13 that are needed or would provide additional clarity Any changes that were not within the scope of this update to will have to be addressed in the next revision of the. Blair Temple Subsurface Engineering Imperial Oil Resources The changes make sense but please consider topping 2m with air as an option. Most of our wells are minimum disturbance we prefer to avoid the use of chemicals as well based on our experience we ve never had corrosion or failure on that depth using air as yet. For compliance purposes with the use of the air is sufficient. The Inactive Program FAQs document (http://www.aer.ca/rules regulations/directives/directive 013) will be updated accordingly. 7 Mar Maria Nerier Completions Engineer Ember Resources 4a 4) The amendment of suspension requirements for wellbore fluids, lowrisk well pressure testing, low risk wells inactive for more than 10 years (section 3) would be changed to provide consistency between well risk types to align with Directive 020: Abonment requirements. a. Nonsaline water or inhibited (noncorrosive) fluid is to be used in the wellbore, the top two metres of the wellbore must be filled with a nonfreezing liquid (sections 3.1.1, 3.2.1, 3.3.1). Table 1 allows for a non freezing fluid (air is a fluid) the revision summary above specifies non freezing liquid. a. Nonsaline water or inhibited (noncorrosive) fluid is to be used in the wellbore, the top two meters of the wellbore must be filled with a nonfreezing liquid (sections 3.1.1, 3.2.1, 3.3.1). Q1.14 of the FAQ recommends to use non compressible nonfreezing fluid that would prevent damaging the wellhead in winter. Using air may increase a potential of casing corrosion subsequent failure at the air to fluid contact depth. Explain recognize if air, diesel, or non fluid alternatives are acceptable otherwise the requirement should specify the need to obtain a dispensation. Being that many horizontal wells are now drilled with intermediate casing strings, there is no allowance in the old regulation for an integrity test of any kind on the newly created barrier. Directive 13 needs to account for some sort of vent test or hydro test to make sure the barrier is performing like it should. Being that the working valves on the intermediate string are below the production casing wings valves not tied in they are often buried like a surface casing vent line. The SCVent line is to be open 60 cm above the ground; if the intermediate casing is to serve any emergency well control function such as the SCVent it should be made accessible at All times. I believe D 13 was originally written before the advent of intermediate barriers as such the barriers (that are not open to a producing zone, need to have the pressure monitored/ tested same as the surface casing vent because they would have a similar purpose the wellbore. By completing vent testing on these strings you can eliminate the discussion around groundwater contamination /or identify the root of any external migration from the producing bore into the surface casing. This is a great revision long overdue. Thank you for making it. Clarification needed for low risk wells regarding nonsaline water or inhibited (noncorrosive) fluid. Information on page 3 9 is conflicting, whereas Table 1 shows no wellbore fluid requirements. For compliance purposes the use of the air is sufficient. The Inactive Program FAQs document (http://www.aer.ca/rules regulations/directives/directive 013) will be updated accordingly. The testing of the annulus between production casing intermediate casing is outside of the scope for this revision of will be considered in future revisions of this directive. Page 3 is missing For downhole suspension at the beginning of the sentence: For downhole suspension a nonsaline water or inhibited (noncorrosive) fluid must be used in the wellbore, the top two metres of the wellbore must be filled with nonfreezing fluid. This has been corrected. 29 Mar 10 Mar 8 Mar 24 Mar Michael Beck Justin MacDonald Jen Kuhn Abonment President owner Thermal Completions Superintendent Drilling Analyst Surface Solutions Athabasca Oil Corp. Suncor Energy Section 3 Risk Based Suspension Requirements a. Nonsaline water or inhibited (noncorrosive) fluid is to be used in the wellbore, the top two metres of the wellbore must be filled with a nonfreezing liquid (sections 3.1.1, 3.2.1, 3.3.1). Feedback/Suggested Changes a. Nonsaline water or inhibited (noncorrosive) fluid is to be used in the suspended Comment with respect to bullet a is accepted has been corrected accordingly. With the new revision of, the low risk type 1 wells do not require pressure testing at the time of either initial suspension or the ongoing inspection. However, after 10 years of inactivity, low risk type 1 wells will have to be pressure tested suspended in accordance with the medium risk requirements. Both changes are designed to provide Devon
wellbore, the top two metres of the wellbore must be filled with a nonfreezing liquid (sections 3.1.1, 3.2.1, 3.3.1). Type 6: Low risk wells inactive for more than 10 years should exclude Type 1 wells Imperial has provided a marked up copy of the Draft Directive noting these items that is attached for your reference. A Microsoft Word version of this document can be provided if needed. consistency for each risk category help to balance operational cost. In addition, the wells that were never perforated after 12 years from the final drill date should be more economic to abon under Directive 020 than to keep suspended. This would not only reduce licensees deemed liabilities, it would also contribute to addressing a growing inventory of inactive wells to ensure a lifecycle orderly development. Blair Temple Subsurface Engineering Imperial Oil Resources 1.2 Nonsaline water or inhibited (noncorrosive) fluid must be used in the wellbore that is suspended downhole, the top two metres of the wellbore must be filled with nonfreezing fluid. (Comment: wells with open perfs cannot support a full column of fluid) Comment accepted has been corrected accordingly. Aaron M. Miller Manager of Closure & Northern Association of Petroleum Producers (CAPP) Nonsaline water or inhibited (noncorrosive) fluid must be used in the wellbore for downhole suspension, the top two metres of the wellbore must be filled with nonfreezing fluid or the fluid level dropped below the frost line. (Comment: to clarify that this is not intended for wells with open perforations that cannot support a full column of fluid) 3.1.1 Initial Suspension Requirements bore Fluid There are no requirements for fluid in the wellbore; however, if there is fluid in the wellbore that is placed for well suspension a nonsaline water or inhibited (noncorrosive) fluid may be used the top two metres (m) of the wellbore must be filled with a nonfreezing fluid or the fluid level dropped below the frost line. (Comment: Wording change to ensure wells with open perforations are not included in this requirement. For example type 5 wells, which have some fluid in the wellbore but will not support a column of fluid, should not be included in this requirement.) Comment regarding For downhole suspension is accepted Directive 013 has been corrected accordingly. or the fluid level dropped below the frost line. is an unnecessary clarification; as for compliance purposes with, the use of the air is sufficient. The Inactive Program FAQs document (http://www.aer.ca/rules regulations/directives/directive 013) will be updated accordingly. Comment regarding that is placed for well suspension is accepted has been corrected accordingly. Orest Kotelko Natural Resources Limited (CNRL) 4b 4) The amendment of suspension requirements for wellbore fluids, lowrisk well pressure testing, low risk wells inactive for more than 10 years (section 3) would be changed to provide consistency between well risk types to align with Directive 020: Abonment requirements. b. Pressure testing of low risk type 1 wells is not required for the purpose of initial suspension I think we re missing downhole requirements for type 1 low risk that is turning to medium risk. Also during DDS submission to upgrade this wells to medium risk selecting none for downhole requirements is not possible. Lastly, well type of preset wells are not defined in the suspension requirements. Initial suspension ongoing inspection requirements in Table 1 of Directive 13 should be consistent with the changes to section 3.1.1 to indicate there are no requirements to pressure test for a Type 1 in the low risk well category as stated in the revision. Remove the specification for pressure testing Type 1 low risk well in Table 1. Also, Table 1 should be consistent with section 3.1.2 describing the requirement to only measure SICP SITP (if applicable). Add Type 1 to Type 2,3,4,5 in Table 1. I can appreciate not pressure testing these well bores, however along with recording a pressure a fluid level to calculate a bottom hole pressure. If there is pressure on the type 1 low risk gathering a carbon isotope gas sample will help identify the source if the casing is leaking, where the problem is. This may sound like a large step, but I feel that while a suspended well inspection is being done it should be done completely. Please also look into factors such as unintended wellbore communication on suspended wellbores. A low risk type 1, or any inactive wellbore for that matter should be closely monitored in accordance with Directive 83. (Aboned cut capped wells are monitored for gas migration post frac according to D 83) Comment is accepted table 1 has been updated accordingly. If pressure is found on the well that has no perforations (low risk type 1) the failure must be investigated repaired accordingly (e.g., ID 2003 01). The repair requirements are outside of the scope of. Please refer to the Inactive Program FAQs document, Q1.11, Q3.8, Q3.11 (http://www.aer.ca/rules regulations/directives/directive 013). 8 Mar 29 Mar 10 Mar Maria Nerier Michael Beck Completions Engineer Abonment President owner Ember Resources Surface Solutions
nor at the time of ongoing inspections (section 3.1.1). 1) Table 1 still includes the Pressure Testing of Low Risk Type 1 wells. Comment is accepted table 1 has been updated accordingly. 9 Mar Good news. 24 Mar Jody Wilson Jen Kuhn Environment & Drilling Analyst ARC Resources Ltd. Suncor Energy Section 3 Risk Based Suspension Requirements b. Pressure testing of low risk type 1 wells is not required for the purpose of initial suspension nor at the time of ongoing inspections (section 3.1.1). Feedback/Suggested Changes Table 1. Suspension requirements for all inactive wells Section 3 of (DRAFT) speaks to pressure testing (as well as other areas). Devon is looking for guidelines regarding pass / fail for pressure testing similar to that identified in AER ID 2003 01, Section 1.6 Recommended Test Procedures In general, the EUB will accept, as a maximum, a 3 per cent pressure decline over a 10 minute interval as a successful packer isolation test. Comment regarding Recommended Test Procedures is accepted the Inactive Program FAQs document (http://www.aer.ca/rules regulations/directives/directive 013) will be updated accordingly. Devon Table 1 still shows that a Low Risk Type 1 well requires pressure testing at initial suspension ongoing inspections Table 1 has been updated accordingly. Lindsay Jakab Suspended s Reporting Husky Energy Initial suspension ongoing inspection requirements outlined in D 13 Table 1 should be consistent with changes in section 3.1.1, stating there is no requirement to pressure test for type 1 low risk wells. Remove the requirement for pressure testing low risk wells in Table 1 Table 1 has been updated accordingly. 31 Mar Paul Bothwell Senior Pengrowth Energy Pressure Testing We fully support the elimination of pressure testing Low Type 1 wells. In addition, we have found that the integrity of a wellbore, wells that have a bridge plug or a packer with a tubing plug, can be verified with the recording of SITP, SICP a fluid level (instead of pressure testing to 7 mpa). There should be no pressure the fluid level should not change in wells that have casing bridge plug/packer integrity. If there is pressure on the tubing or casing that would be an indication that the well should be pressure tested (possibly pressure was not bled off after the last pressure test) repaired. In addition, a falling fluid level would indicate that wellbore fluids are leaking into a formation the leak should be investigated. A constant fluid level is indicative of a stable wellbore fluid situation, nothing is entering or leaving the casing. Fluid level test, SICP, SITP are not adequate means of verifying wellbore integrity for medium high risk wells. A 7 Mpa/10 min pressure test is required for the medium high risk wells under. Orest Kotelko Natural Resources Limited (CNRL) 5a 5) Reactivation criteria on inactive wells in section 4 would be changed to provide operational flexibility to align with the inactive well licence list process. a. For a well to attain active status to be reactivated on DDS, it would report volumetric activity Criteria will be assessed on the hours reported field of at least one hour per month for three consecutive months. Does this mean that as a minimum the reported volume must be 0.1 or greater during the month to accept the reported hours as valid? Q1.19. from the FAQ suggests a volume of 0.049 is rounded to 0.0 not reportable. I m unsure why the well license would not be reactivated when the well status has been changed to producing (ie. well status is changed from suspended to producing license reactivated as of the first day that production is recorded). There are a number of instances where wells that are produced intermittently aren t economic to produce after just a short two or three week production cycle are consequently shut back in. To restart a well twice in the two months following a short cycle for 1 hour of production seems unnecessary, costly, detrimental to pipeline integrity. My biggest concern here is compromising pipeline integrity when it is unwarranted, just for the purpose of recording 1 hour of production so the well can be removed from an inactive well list. That is correct; minimum reported volume is defined by Petrinex. Licensees have several options for being in compliance: Suspend the well (temporary condition of the well when it s not operational not completely aboned in accordance with Directive 020 but is maintained to address public environmental safety risks). 29 Mar status is reported in Petrinex is not linked to the AER well licence status in the Digital Data Submission (DDS) system. For more details please refer to the Inactive Program FAQs document, Q1.1, Q2.4, Q2.20 (http://www.aer.ca/rules regulations/directives/directive 013). 11 Mar Keith Baron Abonment Production Engineer Husky Energy
for at least one hour per month for three consecutive months. Reactivate the well if operationally needed (for the purpose of a commercial gain). Abon the well in accordance with Directive 020 if the well or associated infrastructure is no longer economical to be operated. The wells should not be reactivated or kept operational for the purpose of avoiding suspension requirements subsequent operational costs. In the event that a licensee chooses to avoid suspension by nominally meeting the definition of the active well, all work associated with operating the minimum number of hours must be addressed accordingly. This work would substitute for maintaining the wells in a safe manner for the purpose of public environmental safety. Good news. 24 Mar Jen Kuhn Drilling Analyst Suncor Energy Section 4 Reactivating Suspended s a. For a well to attain active status to be reactivated on DDS, it would report volumetric activity for at least one hour per month for three consecutive months. No feedback or suggested changes. Devon Are you able to clarify what we do if we have an inactive well that requires a suspension but it has not been completed/reported it then meets the reactivation requirements? Do we still have to suspend the well then reactivate? Or will it just become active again automatically? The wellhead must be chained locked for a suspended well, but when we are trying to operate the well to meet the reactivation requirements the well cannot remain physically suspended. If the AER were to visit this particular suspended well, it would appear that we are noncompliant when in fact we are working to reactivate the well. Can you clarify that in the Directive? If the well has met the reactivation criteria, it will automatically fall off the inactive well licence list (updated daily). No historical suspension record followed by reactivation report is required to be submitted. The licensee will be required to provide a response to the AER indicating volumetric activity being reported to Petrinex during the time when the well hasn t met the reactivation criteria. Lindsay Jakab Suspended s Reporting Husky Energy This is a good change as low deliverability wells on artificial lift have had issues in the past of achieving 360 hrs of production in a month. 31 Mar Clayton Dubyk Environment Coordinator Shell Limited For a well to attain active status to be reactivated on DDS, it must report volumetric activity. for at least one hour per month for three consecutive months. (Comment: This is related to Timely abonment so it should be removed.) Report reactivation of well on DDS Petrinex within 30 days after it attained an active status retain records. (Comment: reactivation should be done on one government website not two) A well attains active status after it reports volumetric activity. for at least one hour per month for three consecutive months. (Comment: This is requirement is used to support the 10 year rule which is part of the timely abonment focus should be removed) Flaring is not considered to be a volumetric activity. (Comment: testing up hole zones is part of actively managing wells. This is related to Timely abonment so it should be removed) A reactivation criterion is not related to timely abonment. Petrinex is an interprovincial system designed to track volumetric activity is not specific to Alberta. A well licence reactivation report is based on the reactivation criteria must be submitted through DDS. Flaring is not considered to be production therefore is not accepted as a volumetric activity. Orest Kotelko Natural Resources Limited (CNRL) 5b 5) Reactivation criteria on inactive Just to confirm, this only pertains to wells classified as medium during initial suspension? Pertains to both medium high risk wells. 10 Mar Maria Nerier Completions Engineer Ember Resources
wells in section 4 would be changed to provide operational flexibility to align with the inactive well licence list process. b. Pressure testing casing or tubing for the reactivation of a well is not required if the initial well suspension was completed less than 12 months ago. What is the effective date of the initial well suspension? Clarify if 12 months from suspension deadline date is the extent of the valid reactivation period where a pressure test is not required for a reactivation. Testing the intermediate AND surface casing for volumetric flow fracture gradient assurance needs to be included into the re activation process in order to achieve complete compliance well head accountability. I believe this is important because with recent discussion about carbon capture greenhouse emissions, this testing gives the producer one more, quick look at an inactive property (some very poorly managed in the instances of activations after an asset sale) an opportunity for mitigation is achieved. The initial well suspension is the date the work was completed on the well. The pressure test is valid for 12 months after it is conducted. If this is within the reactivation period, another pressure test is not required. Requirements for identifying monitoring of annular flow are outlined in ID 2003 01 are outside the current scope of. Good news. 24 Mar Section 4 Reactivating Suspended s b. Pressure testing casing or tubing for the reactivation of a well is not required if the initial well suspension was completed less than 12 months ago. No feedback or suggested changes. 29 Mar 10 Mar Michael Beck Jen Kuhn Abonment President owner Drilling Analyst Surface Solutions Suncor Energy Devon What is the effective date of the initial well suspension, should clarify if 12 months from suspension deadline date would also be considered the time frame when pressure test is not required for reactivation The initial well suspension is the date the work was completed on the well. The pressure test is valid for 12 months after it is conducted. If this is within the reactivation period, another pressure test is not required. 31 Mar Paul Bothwell Senior Pengrowth Energy Pressure testing casing or tubing for the reactivation of a well is not required if the initial well suspension was completed less than 12 months prior to reactivationago. (Comment: adds clarity on meaning) Accepted, changes incorporated into the directive. Orest Kotelko Natural Resources Limited (CNRL) OK..automatically updated daily. 29 Mar Abonment 6 The inactive well licence list would be available to all stakeholders on the page of the AER website. It would include all inactive wells in accordance with, it is automatically updated daily. I would like to see AER inspection reports also on the AER website. As a citizen of the province, I would feel comfortable seeing that producers are clearing off their deficiencies in a timely manner. This public data would also help keep producers compliant they in turn, can be confident that they are being accountable when they say they are taking steps to be accountable to the public environment. Publication of inspection reports is outside the scope of. Good news. 24 Mar The inactive well licence list would be available to all stakeholders on the Directive 013 page of the AER website. It would include all inactive wells in accordance with, it is automatically updated daily. Feedback/Suggested Changes Per AER FAQ Q3.16/A3.16 It is recommended to use the Inactive License List (see section 2 of these FAQs) as it is correct contains all the wells that are currently inactive under. Accepted, will be included in the next updates to the inactive well licence list. 10 Mar Michael Beck Jen Kuhn President owner Drilling Analyst Surface Solutions Suncor Energy Devon Devon requests or recommends to include within the Inactive License List two columns from the View/Edit Suspension List which are titled Operational Type, Downhole Operation, Last Inspection Date if removing or not keeping
current the View/Edit Suspension List within the AER DDS System. Unclear conflicting definitions text would be clarified (sections 1.2, 3.1 3.2) Need to clarify reference to Table 1. Ongoing inspection requirements: Update Table 1 to reflect sections 3.1.1 3.1.2. Table 1 is a summary is for reference purposes only. The requirements are outlined in the text. Comment is accepted has been updated accordingly. Qualify fresh water wellbore fluid a two meter air cap for freeze protection as an acceptable practice based on the D13 requirements. Section 2.3.2 wellhead requirements are to ensure there are no wellhead leaks. Ongoing Inspection Requirements for all risk types state the wellhead must be maintained tested in accordance with Section 2.3. Table 1 is a summary of the requirements does specify for wellhead maintenance that wellheads require servicing pressure testing of sealing elements. These details are generalized in Section 2.3 by the requirement to ensure there are no wellhead leaks. In practice the wellheads are checked to ensure there are no internal seal leaks by confirming containment pressure isolation on the production casing annulus no vent flow on the surface casing. Tubing/Casing isolation is also confirmed on wells with packers. head checks to confirm no wellhead leaks are validated further during any required casing pressure test surface casing vent flow check. 29 Mar Abonment 7 Unclear conflicting definitions text would be clarified (sections 1.2, 3.1 3.2). In practice, the extent of servicing pressure testing of sealing elements depends on whether the sealing elements are suspect require further investigation. The head Maintenance summary in Table 1 should clarify the requirements in practice or remove requirement? Often times the reason something need clarity on a regulation is that the regulation falls out of relevance. This document revision is an excellent example. Since directive 13 was introduced complexities have arose to push the AER to review act accordingly. What often gets left behind are items such as the intermediate casing strings that are a relatively new stard of well bore construction as such need to be included in regulatory discussions. A solid case in point is; directive 13 will have direct impact on 2003 01 in terms of surface casing vent testing yet 2003 01 is over ten years old. Sweeping changes to the way one looks at inactive wells, needs to take into effect how we maintain our active assets. No question to respond to. 10 Mar Michael Beck President owner Surface Solutions Unclear conflicting definitions text would be clarified (sections 1.2, 3.1 3.2). Feedback/Suggested Changes Additional definitions are set out in appendix 3. Repair Deferred within AER DDS Inspection Outcome please provide a definition Repair Required within AER DDS Inspection Outcome please provide a definition Satisfactory within AER DDS Inspection Outcome please provide a definition This terminology is used in the DDS system, details are provided in the Inactive Program FAQs document (http://www.aer.ca/rules regulations/directives/directive 013). Devon The downhole options in Table 1 are not reflective of the downhole options in DDS ie: cement plug, cement squeeze. These options should be added to the directive as well. Cement plugs / cement squeezes are chosen when the zones are aboned under Directive 020; the appropriate update has been made to (section 2.2). Lindsay Jakab Suspended s Reporting Husky Energy 7 High Risk heads: I think the AER should include reference to critical wellhead requirements beyond the stards referenced in OGCR s, i.e. ID 90 01 ARP 2 Changes have been made to section 2.3.2 to indicate other references for critical wellheads ID 90 01 ARP 2. 31 Mar Paul Bothwell Senior Pengrowth Energy
Table 1. Suspension requirements for all inactive wells Medium Risk well Type six has changed from Completed Low risk wells suspended longer than 10 years to Low risk wells inactive longer than 10 years. Reading over the draft it doesn t look like the requirements of the directive have changed but the change can easily be misinterpreted. Suggest some clarity in the definition of an inactive well if it does or doesn t include all suspended wells that are Directive 13 compliant. The example of the long term suspension in the current Directive 13 is clearer than the example in the Draft Directive 13. The example provided in the revised version of reflects the updated timelines clarifies how the deadlines are calculated. For more information, please refer to the Inactive Program FAQs document, Q1.11 Q4.13 (http://www.aer.ca/rules regulations/directives/directive 013). Also, please refer to appendix 3 for the differences between the definitions of inactive well suspended well. 31 Mar Clayton Dubyk Environment Coordinator Shell Limited 2.3.3 Associated Infrastructure The licensee must is recommended to leave all single well facility equipment associated with a suspended well in a secure state. The licensee must manage discontinue or abon pipelines associated with the suspended well in accordance with Pipeline Rules, part 10, section 82. (Comment: The requirement for pipeline work should only be detailed in the pipeline regulations) All the matory requirements are addressed through the must statement. 2.4 Repair Requirements Casing failures must be reported repaired in accordance with ID 2003 01. All other well integrity failures (example, leaking casing patch, remedial perforations, leaking plugs, etc.) must be reported through DDS repaired within 90 days in accordance with the timelines established for packer failures in ID 2003 01. (Comment: Adding requirements to ID 2003 01 through D 13 is not optimal approach) Comment regarding within 90 days is accepted has been updated accordingly. 2.5 Reporting Requirements Licensees are responsible to ensure both the well status (Petrinex) the License Status (AER DDS system) are updated aligned with one another.(note: such alignment is not always possible) bore Fluid There are no requirements for fluid in the wellbore; however, if there is fluid used for suspension in the wellbore a nonsaline water or inhibited (noncorrosive) fluid may be used the top two metres (m) of the wellbore must be flled with a nonfreezing fluid Please refer to the page of the AER website for the matrix on how the status should be aligned. Also, for the purpose of assessing compliance with, the well licence suspension report is being used. Accepted has been updated accordingly. Aaron M. Miller Manager of Closure & Northern Association of Petroleum Producers (CAPP) Definitions: Suspended well: A well that has had a DDS submission to change the status to suspended. is in compliance with. (Comment: What is a well that is suspended in DDS but has not submitted a re inspection by the due date? It is not compliant, so is it not suspended?) The definition of a suspended well is based on the regulatory requirements. The well that is inactive missing the inspection is not a suspended well under requirements. Zonal abonment: The abonment of a completed or open hole interval in a cased well in accordance with Directive 020. (Comment: What is well aboned to stard of the day but not in accordance with the current version of D 20?) Directive 020 clarifies the conditions for when which previous zonal abonments are grfathered. CAPP also believes an additional definition is needed for: Repair Deferred Such an additional definition inserted in this section will serve to differentiate with Repair Required provide needed clarity Accepted will be added to the Inactive Program FAQs document (http://www.aer.ca/rules regulations/directives/directive 013) accordingly.
Low Type 1 Definition We welcome the definition of Low Type 1 to include all non Critical Sour wells that are zonally aboned. That reflects the true risk of these types of wells. However, there is no need to then change the risk to Medium Type 6 after 10 years, there is no change to the downhole requirements it is an administrative complication with no benefit. With the new revision of, the low risk type 1 wells do not require pressure testing at the time of either initial suspension or the ongoing inspection. However, after 10 years of inactivity, low risk type 1 wells will have to be pressure tested suspended in accordance with the medium risk requirements. Both changes are designed to provide consistency for each risk category to help balance operational cost. In addition, the wells that were never perforated after 12 years from the final drill date should be more economic to abon under Directive 020 than to keep suspended. This would not only reduce licensees deemed liabilities, it would also contribute to addressing the growing inventory of inactive wells to ensure a lifecycle orderly development. 3.1 Low Risk s Low risk well is defined as one of the following: Type 1. Cased hole wells that are not critical sour have no perforations or all perforation have been aboned in accordance with Directive 020 (Comment: to be consistent with paragraph 5 on page 3) Type 2. Gas wells less than 28 000 m 3 /day that are low risk (see appendix 1) Type 3. Water source wells Type 4. Nonflowing Class 2 3 injectors plus all Class 4 injectors (see Directive 051, section 2) (Comment: Injectors that are not capable of flowing back are low risk) Type 5. Nonflowing3 oil wells with an H 2 S content less than or equal to 50 moles per kilomole (mol/kmol) Paragraph 5 on page 3: Pressure testing low risk type 1 wells (cased hole wells that are not critical sour have no perforations, which also includes low risk wells with all zones properly aboned in accordance with Directive 020: Abonment) is not required for the purpose of initial suspension nor at the time of ongoing inspections. Aboning or declassifying critical sour wells does not meet the conditions of a type 1 well. The shallowest completion must be used to classify the risk category. If the critical sour zone is the shallowest completion, the well must be suspended in accordance with medium risk requirements (that would include pressure test). Orest Kotelko Natural Resources Limited (CNRL) Proper zonal abonment will substitute for a bridge plug suspension method when required; all the inspection requirements must be met accordingly. The type 2 definition is outside the scope of this revision of. Suspended well A well that has had a DDS submission to change the status to suspended. is in compliance with. (Comment: What is a well that is suspended in DDS but has not submitted a re inspection by the due date? It is not compliant, so is it not suspended even if the license status is suspended? The definition of a suspended well is based on regulatory requirements. A well that is inactive missing the inspection is not a suspended well under requirements. Zonal abonment The abonment of a completed or open hole interval in a cased well in accordance with Directive 020 the stards of the day. (Comment: What is well aboned to the stard of the day but not in accordance with the current version of D020? According to this definition a waiver under Directive 020 would be required for a well with a zone that had 20% H2S that was aboned with a bridge plug 8m of cement in 1980 but has a shallower sweet zone perforated subsequently aboned in accordance with Directive 020 before it qualifies as zonally aboned.) Please refer to Directive 020, which clarifies the conditions for when which previous zonal abonments are grfathered. other 2) On the Table 1, can we add Pressure Testing in with the Initial Suspension & Ongoing Inspection Requirements? Maybe to read this Initial Suspension & Ongoing Inspection/Pressure Testing Requirements. 3) A bit of confusion with risk classification for disposal wells. Can we amend the wording of the Low Risk Type 4 to read Class 4 Injector & Disposal s Med Risk Type 4 Class 2 & 3 Injection & Disposal,.... Table 1 is a summary is for reference purposes only. The requirements are outlined in the text. Pressure testing is not required for low risk wells. Accordingly, to avoid any confusion the naming will remain. Definitions of class 4 injector wells are provided in Directive 051 are outside of the scope of. 9 Mar Jody Wilson Environment & ARC Resources Ltd.