Commingling Initiative - Q&A's
Updated - May 17, 2007

Development Entity and Self-Declared Commingling Processes

Question 1. Would industry be able to drive the development of new DEs and the extension of DEs?

Answer: There will not be an application process for industry to establish new DEs or amendments to existing DEs, but the EUB will establish new DEs proactively where appropriate and expand existing DEs as development occurs outside the boundaries of a DE.

A DE will be established where commingled production of multiple pools over a large area is already occurring, there is adequate understanding of the resource and associated development risks, and there is minimal risk that unsegregated production will negatively affect conservation or the environment.

The EUB will monitor industry's activity and development around existing DEs and expand the DEs when appropriate.

Question 2. Does the EUB have plans for other DEs?

Answer: The EUB will monitor development and operations within the current DEs to ensure that compliance is being met before establishing new DEs. The EUB will consider other DEs in the future and will establish new DEs proactively where appropriate and expand existing DEs as development occurs on the boundaries of a DE.

Question 3. Can a well retain confidentiality within a DE?

Answer: Well confidentiality within a DE is handled in the same manner as for all wells in the province, in accordance with Section 12.150 of the Oil and Gas Conservation Regulations; however, all data relating to control wells become publicly available at the time of designation.

Question 4. Can a control well retain confidentiality?

Answer: Designation of a control well results in all data relating to control wells becoming publicly available at the time of designation.

Question 5. Are operators required to maintain an audit package for wells that have been commingled through the DE or SD process?

Answer: There are no requirements for operators to maintain an audit package, but it may be beneficial for operators to maintain records to support commingling using the DE or SD process should a perceived noncompliance situation be identified by the EUB.

Question 6. Is the Basal Belly River included in DE 1?

Answer: Yes, the Basal Belly River Formation is included as part of DE 1 stratigraphic definition.

Question 7. Are there any control well requirements for wells completed solely in conventional sand pools within the DEs?

Answer: No.

Question 8. For wells within DE 2, are operators required to collect initial reservoir pressures from the zones proposed for commingling?

Answer: No. However, if data are collected or needed to support any DE criteria (i.e., if the reservoir pressure in any of the pools or intervals proposed for commingling exceeds 90 per cent of the fracture pressure in any other pools proposed for commingling), the operator must submit these data to the EUB.

Question 9. Are operators required to notify offset mineral lessees of commingling with a DE?

Answer: No, notification to mineral lessees is not required. However, notification must be sent, at a minimum, to

• all Freehold mineral lessor/owners, and
• all licensees of all wells, other than abandoned wells

within the standard drilling spacing unit (DSU) and in the 8 standard DSUs offsetting the well where commingling is proposed, in accordance with Section 3.1.3.1 of Directive 065.

Question 10. If an operator has commingled the Edmonton and Belly River Formations within a well in DE 1, does the operator have to notify the deep rights Freehold mineral lessors (i.e., Freehold mineral lessor of the Leduc) in the offsetting surrounding eight sections?

Answer: Yes, a well licensee that has commingled production using the DE process must provide notice of the commingling, at the minimum, to the well licensees of all wells (other than abandoned wells) and all Freehold mineral lessors in the section to be commingled and the eight sections immediately offsetting the section in which commingling has occurred.

Question 11. How does the DE process relate to the testing requirements for the deep gas royalty holiday program (DGRHP)?

Answer: There are no segregated testing requirements within the DEs; consequently, proven pay will be assigned solely using petrophysical analysis. Should petrophysical analysis of the perforated interval qualifying for the DGRHP not support proven pay, segregated test data would be required to validate that the zone is capable of production.

Question 12. Would the EUB consider replacing the requirements for initial and annual reservoir pressure measurements with requirements for wellhead pressures and accurate daily production rates? 

Answer: This matter will need to be considered in an overall review of Directive 040. At present there is no requirement to submit daily rates and wellhead pressures to the EUB beyond the standard production reporting and pressure testing and reporting requirement.

Question 13. If an operator has a new well completed in three high-rate (>50 10 3 m3/d) pools at depths ranging from shallow to deep, would commingling be permitted to proceed under the self-declared (SD) process provided that all of the SD criteria and testing requirements have been met?

Answer: Yes, the commingling reference above would be allowed to proceed through the SD process, with the licensee ensuring that the SD criteria are met and that the required data are collected and submitted on each pool.

Question 14. Would the fracture pressure be the likely limitation in these cases?

Answer: Yes, the fracture pressure of one or more of the shallower pools completed for production could be a limiting factor if the pools to be commingled are vertically separated by a significant distance in the wellbore and are therefore likely to be at significantly different pressures. It is the company's responsibility to perform the required testing and analyses to confirm that the fracture pressure and all other requirements are met.

Question 15. When commingling DE formations with formations that are not part of a DE, how should an operator proceed?

Answer: When considering commingled production for formations that are within a DE with formations that are not within a DE, an operator should determine if the specific well targeted for commingling meets the requirements of the self-declared commingling in Section 3.1 of Directive 065. If it does not, the operator must submit a Directive 065 application for commingling with all the required data and information and receive approval prior to commencing commingled production.

Question 16. If a well does not meet the requirements for commingling through the DE or SD commingling process, what procedure are well licensees to follow?

Answer: If a situation for a well does not meet the criteria for commingling of production through the DE or SD process, approval for commingling must be obtained through a Directive 065 application. The pools proposed for commingling must remain segregated until the EUB grants approval to commingle.

Question 17. If segregated gas analyses for zones in a well proposed for commingling through the DE process are collected, must a combined gas analysis still be collected?

Answer: Yes, commingled gas analysis is required for wells commingled through the DE process; however, an operator may apply for an exemption from the commingled gas analysis requirement if segregated gas analyses for all zones proposed for commingling will be collected. The exemption request must be made to the EUB prior to commingling a well through the DE process.

Question 18. If a well has segregated flow and pressure buildup tests on two zones in which the total combined flow will be less than 50 103 m3/d and production is proposed to be commingled using the SD process, is a company still required to conduct and submit commingled pressure test data?

Answer: Yes, commingled flow and pressure test data are required for wells commingling through the SD process when the total combined flow rate will be less than 50 103 m3/d; however, an operator may apply for an exemption from the commingled flow and pressure test data requirement if segregated flow and pressure test data for all zones proposed for commingling will be collected. The exemption request must be made to the EUB prior to commingling a well through the SD process.

Question 19. If there are no initial or annual pressure requirements for wells drilled within a DE, are there pressure requirements for wells completed within a single zone within a DE?

Answer: No, there are no initial or annual pressure requirements for wells within a DE; however, any data collected from wells within a DE must be submitted to the EUB.

Question 20. When determining if the reservoir pressure in any of the pools or intervals proposed for commingling exceeds 90 per cent of the fracture pressure of any of the other pools or intervals proposed for commingling, does an operator use the fracture closure pressure, fracture propagation pressure, or fracture breakdown pressure of the pools or intervals?

Answer: If the lower-pressured zone(s) have been fracture stimulated, operators should use the fracture closure pressure. If the zone has not been stimulated, operators should use the fracture breakdown pressure.

Issues Regarding Base of Groundwater Protection (BGWP)

Question 21. Who must be notified if a well has perforations above the BGWP and production volumes above 5 m3/month?

Answer: Refer to Directive 044 for EUB contact information and process.

Question 22. Will the enforcement of failing to perform a proper self-audit of wells with water production, as described in Directive 044, be High Risk or Low Risk?

Answer: High Risk.

Question 23. When considering the following water well radius requirement, must an operator consider abandoned water wells?
"Are there any water wells within a 600 m radius with a total depth less than 25 m from the top of the perforations of the well proposed for commingling?"

Answer: No. When considering the water well requirement, all active and/or registered water wells must be considered, but abandoned water wells do not need to be considered.

Question 24. After a gas well is already in place, is any action required of the licensee of a commingled gas well with perforations above the BGWP if a water well is drilled within a 600 m radius with a total depth less than 25 m from the top of the perforations of the gas well?

Answer: The EUB has no requirements of the licensee of a gas well if a water well is drilled within a 600 m radius with a total depth less than 25 m from the top of the perforations of the gas well after a gas well has been drilled and completed.

Question 25. If a well has no completion interval above the BGWP and one of the zones proposed for commingling produces water, is commingling permitted?

Answer: Yes, provided that the water is saline.

Question 26. What are the water testing requirements for wells within winter-access-only areas?

Answer: The licensees of wells within a winter-access-only area must audit their wells on a continuous basis and notify the EUB immediately if wells have been identified as not operating within requirements of Directive 044. The EUB will assess situations on a case-by-case basis and work with companies that demonstrate proactive surveillance.

Question 27. If a well with completions above the base of the BGWP produces 6 m3/month of water and it is determined that 1 m3 of the water is from a zone completed above the BGWP and 5 m3 of the water is from a zone below the BGWP, does the operator need to report this well to the EUB?

Answer: Yes.

Question 28. If a well is completed for segregated production from one zone above the BGWP and one zone below the BGWP, is surveillance required?

Answer: Yes, all wells with completions above the BGWP must be monitored for water production monthly in order to identify if there is a change in production, i.e., commencement or increase in water production.

Question 29. What kind of water production measurements are required for wells commingling through the DE process?

Answer: The EUB's expectation is that all companies must employ accurate water measuring and reporting practices. This applies not only to DEs, but to the entire province.

Question 30. If water is produced below BGWP and the well is completed for segregated production with a zone above the BGWP, is surveillance required?

Answer: Yes, any well with completions above the BGWP requires surveillance by the licensee.

Question 31. If well has one zone above the BGWP completed and one zone below the BGWP completed and water sampling is required, is it necessary to sample from both zones?

Answer: Yes. If the well is completed for commingled production from one zone above the BGWP and one zone below the BGWP and there is water production from the well, the licensee of the well must collect representative water samples from each zone. Directive 044 requires that the water composition and the source be identified. Therefore, a segregated water test from each zone completed for production is required.

Control Wells

Question 32. May a licensee change its CBM pressure and flow control well?

Answer: CBM pressure and flow control well obligations continue for the life of the CBM development that the control well supports. If a pressure and flow control well can no longer be used due to operational problems and there is still CBM production in the area, the licensee of the well must submit an alternative location to be validated by the EUB for the same coal zones.

Question 33. Is a 14-day buildup sufficient for the pressure data requirement of CBM pressure and flow control wells? Is there a cutoff point to the buildup time for a segregated pressure test of a coal zone?

Answer: CBM pressure and flow control wells must be tested in accordance with Section 5.1 of Directive 040, as described below:

The pressure data collected from coal zones in the pressure and flow control wells should be stabilized. For most purposes, a "stabilized reservoir pressure" is defined as a pressure that does not increase over 2 kPa/hour during a 6-hour period.

The following four methods, in order of preference, are acceptable for obtaining pressures representative of stabilized shut-in reservoir pressures.

1) Measure sufficient transient data to reliably extrapolate to a stabilized reservoir pressure (PR). Note that for a flow and buildup test, the shut-in should be four times the flow period.
2) Measure pressure buildup until the change in pressure is less than or equal to 2 kPa/hour over a 6-hour period.
3) Measure a static pressure after a shut-in sufficient to reach a stabilized pressure, as determined from previous transient data on this well. If previous transient data indicate that a shut-in in excess of 14 days is required to reach a stabilized pressure, the EUB expects the licensee/operator to use the appropriate shut-in. The time required for pressure buildup is inversely proportionate to permeability. In general, whenever a reasonable estimate of the stabilized reservoir pressure can be obtained within a 14-day shut-in period (using buildup or static pressure measurements), the basic pressure requirements apply. A measured or extrapolated pressure that is at least 95 per cent of the fully built-up pressure is considered adequate for most reservoir management.
4) Measure a static pressure after a shut-in time of at least 14 days if no transient data are available.

Question 34. May control wells be used by offsetting licensees?

Answer: Yes, if offsetting licensees have control wells in place, the coal zones that you are developing are validated in the control wells, and your wells are within the prescribed radiuses, then the offsetting licensees' control wells may be used to meet the control well requirements.

Question 35. May desorption control well requirements be met by offsetting wells?

Answer: Yes, if offsetting operators have collected core and/or cuttings and performed desorption analysis on coal and/or shale zones that are planned for development and the well from which the samples were collected is within the prescribed radius for a desorption control well, this may be used to meet control well requirements.

Question 36. What are the desorption, pressure, and flow data collected from CBM control wells being used for?

Answer: The EUB calculates reserves on a provincial basis. Therefore, the desorption, pressure, and flow data collected from CBM control wells are used in statistical analysis and deposit style modelling to establish trends of gas content and recovery factors of coal zones. The EUB also uses the CBM-only flow data to determine production splits for wells producing commingled from conventional sands, CBM, and other lithologies.

Question 37. What geophysical logs would the EUB prefer be collected on potential control wells?

Answer: The EUB would prefer that an open-hole neutron density porosity log with gamma ray and a resistivity log be collected on potential control wells.

Question 38. What is a licensee required to do if a pressure and flow control well is depleted and abandoned?

Answer: Data from a control well that has been depleted are useful to the EUB. The operator of the pressure and flow control well will need to collect a final set of pressure tests and flow metre logs prior to abandoning the control well. If CBM development is active or ongoing in the area, a replacement control well must be validated prior to abandoning the original control well.

Question 39. May CBM pressure and flow control wells be standing for a time within the first year of production if the well(s) are not tied in for production?

Answer: The expectation is that pressure and flow control wells must remain on production for the majority of the time. Well downtimes for servicing or plant turnaround are acceptable.

Question 40. Will the pressure and flow control well annual testing requirements be listed on the EUB annual pressure survey schedule?

Answer: The EUB does not have a survey schedule for pressure and flow control well testing at this time, but this is targeted in the development plans. At present, the onus is on companies to be aware of their testing obligations for control wells.

Question 41. If a shallow CBM pool was not initially perforated or tested in a control well, may it be perforated and tested at a later date, since it will still have representative initial pressure?

Answer: The EUB does not require operators to complete every coal zone present in a well when initially having zones validated for control well status. There may be a staggered validation of zones in a well as companies elect to pursue additional coal zones in an area.

Question 42. May a control well retain confidentiality?

Answer: Designation of a control well results in all data relating to control wells becoming publicly available at the time of designation.

Other

Question 43. How does an operator rescind an existing MU or MISC Order?

Answer: The EUB does not intend to rescind MU Orders at this time, as they are field-based orders. A holder of a MISC Order may make an application to rescind a MISC Order for commingling of CBM or CBM and conventional gas production, but must also confirm that the appropriate control wells are in place to support the CBM development.

Question 44. When will the EUB develop plans for the oil shale and its development?

Answer: Oil shale was considered during the commingling initiative, and specific guidelines and requirements will be established as interest in the resource grows.