Gas Over Bitumen – Regulatory Appeal
In this decision, the AER varied its approval of application 1909395 from Canadian Natural Resources Limited (“Canadian Natural”) and issued the amended approval 11475EE (the “Amended Approval”) by way of additional conditions.
Introduction and Background
In application 1909395, Canadian Natural applied to amend scheme approval 11475 for the recovery of crude bitumen from the Wabiskaw-McMurray deposit by adding a seventh steam-assisted gravity drainage (“SAGD”) box at surface location 01-075-09W4M (the “KN06 Box”) to its Kirby North project. The proposed amendments related to bitumen extraction from the McMurray Formation, drainage box location, well pad design, and well placement, intended to maximize bitumen recovery using SAGD technology. ISH Energy Ltd (“ISH”) filed a statement of concern concerning this application.
ISH was granted its request for regulatory appeal, based on the claim that the amendment granted to Canadian Natural could have an adverse effect on ISH’s interest in the natural gas resource (gas over bitumen zone, or “GOB”) that overlies the KN06 Box.
In Energy Utilities Board (“EUB”) Decision 2005-122 (the “GOB Decision”), the EUB relied on conclusions of the regional geological study of the Athabasca-area Wabiskaw-McMurray deposit (“RGS”) and evidence of the participants in the proceeding, and ordered individual gas wells to be shut in.
Presence/Absence of an Effective Barrier, and its Relevant Characteristics
An issue of the proceeding was the existence of an effective barrier to steam between the bitumen-bearing McMurray Formation and the gas-bearing Wabiskaw B, and, if present, its characteristics near the KN06 Box.
The parties provided what they identified as barrier/sealing intervals and the intervals’ physical characteristics.
(a) The A2 Mudstone
The parties agreed on the existence of the regional McMurray A2 mudstone (“A2 mudstone”) around the KN06 box. The RGS found that where it is present, the A2 mudstone formed an effective barrier or sealing layer in the context of maintaining pressure separation between a bitumen reservoir and an overlying gas reservoir. The parties agreed that the A2 mudstone is not present over the northwest corner of the KN06 Box, but did not agree on the size of the area where the mudstone was missing.
The AER identified a lateral offset in aromatic-hydrocarbon concentrations between different geologic compartments. The more abrupt and marked the offset, the greater the probability that a barrier and not a baffle separated the compartments. The AER determined that the gas chromatography-mass spectrometry (“GCMS”) data from the type well supported that, where present, the A2 mudstone separated the upper-B1 and McMurray A2 reservoirs.
The AER determined that, because the A2 mudstone had been eroded and was absent over a portion of the KN06 Box, the A2 mudstone on its own could not be considered an effective barrier to steam between the bitumen-bearing McMurray Formation and the gas-bearing Wabiskaw B over the KN06 Box.
(b) The B1 Intervals Other than the Mid-B1 Mudstone
The parties agreed that the B1 sequence included two intervals separated by the B1 mudstone but did not agree on the exact thickness and other characteristics. Based on the evidence provided, the AER could not conclude that the upper and lower B1, as interpreted by Canadian Natural, or the upper B1 and regional B2, as interpreted by ISH, formed an effective barrier to steam on their own.
(c) The Mid-B1 Mudstone
ISH submitted that it interpreted the mid-B1 mudstone to range in thickness in the KN06 Box, between 0 m and 0.7 m. ISH further submitted that, where it thins, the mid-B1 mudstone could not remain as an effective barrier to steam over time.
Referring to digital core photos and well logs as well as GCMS data, the AER found that the mid-B1 mudstone probably extended across the KN06 Box, and is more likely than not an effective barrier to steam.
(d) Post-B2 Non-Reservoir Units
The parties disagreed on the exact placement of the base of the B2 non-reservoir inclined heterolithic stratification (“IHS”). They also disagreed about whether it could prevent steam from moving from the McMurray reservoir to the Wabiskaw B.
The AER found that neither party had provided evidence to develop an IHS sequence model of the KN06 Box. The AER determined that the GCMS data, relied upon by Canadian Natural showed one barrier at the interface between the McMurray B2 reservoir and the post-B2 non-reservoir IHS. Within the post-B2 non-reservoir interval in the GCMS data, the data pattern more closely matched the characteristics of baffles. The AER found that based on Canadian Natural’s operational experience to date and the GCMS data, there was more likely than not a barrier between the McMurray B2 reservoir and the post-B2 non-reservoir interval. It also determined that the post-B2 non-reservoir interval could be expected to act as a baffle to steam movement, but not a barrier.
(e) Combination of the Post-B2 Non-reservoir Interval, the B1 Sequence, and the A2 Mudstone
The AER concluded that, in combination, the post-B2 non-reservoir interval, the entire B1 sequence, and the A2 mudstone, where present, should effectively confine the movement of steam to geologic strata below the Wabiskaw B in the KN06 Box.
The Risk of Fractures or Other Breach of the Barrier / Top Seal, If It Is Present, Resulting from Canadian Natural’s Operations in the KN06 Box
(a) Risk Posed by Existing Faulting and Fracturing
There was significant disagreement between the parties about small-scale fractures or fracture systems in the KN06 Box that could breach containment layers.
The AER noted that the digital core photos supplied came from vertical wellbores. As a result, there could be vertical or non-vertical fracturing not intersected by the wells from which the cores had been taken. The AER noted a lack of vertical fracturing in the digital core photos in evidence. Therefore, the AER found that there was likely no significant small-scale fracturing in the relevant geological layers that would pose a risk to the integrity of the identified potential barriers or the combination of layers that were identified as an effective barrier to steam.
The AER also found that the submissions did not provide enough evidence to establish the existence and potential distribution of fault, fracture systems, or networks. However, the pressures in the Kirby Upper Mannville II Pool at the 10-01 well, recorded shortly before the proceeding, demonstrated that there could be a previously undetected issue or issues that could include undetected fracture or small-scale fault-related communication with the Kirby Upper Mannville II Pool.
(b) Risk of Inducing Fracturing at Start-Up with a Maximum Operating Pressure of 7 MPa
ISH argued that a maximum operating pressure (“MOP”) of 7 MPa at start-up would create a risk of induced fracturing of containment layers between the McMurray and the Wabiskaw B.
The AER concluded that start-up induced fracturing was not unlikely in the McMurray. However, the AER concluded that the evidence supported that any fracture induced at start-up, even at 7 MPa, would likely not extend beyond the mid-B1 mudstone, as long as operational parameters were respected.
The AER found that Canadian Natural’s commitment to make numerous “enhancements” to its start-up process at the KN06 Box, to further educate its personnel, and to further include experts in its procedures lowered the risk of pressure-induced fracturing during start-up.
(c) The 10-01 Well
ISH stated that the 10-01 well is 150 m from the KN05 box. Questions about potential wellbore integrity or other issues at the 10-01 well arose during this proceeding’s information request process.
ISH stated that monitoring data from the 10-01 well, provided in this proceeding, showed that the Kirby Upper Manville II Pool had been compromised. ISH submitted that this was probably the result of a workover of the 10-01 well, completed in 2015 by Canadian Natural.
The AER was concerned by the 10-01 plot having shown that the pressure in the Wabiskaw B as of July 30, 2020, appeared higher than when the pressure and temperature gauges were installed and stabilized in March 2019. While the Wabiskaw B had been losing pressure over five years, the data showed that this trend had reversed. The AER noted that it did not have enough evidence to determine the source but noted that existing communication between the Wabiskaw B at the 10-01 well and another zone in either the KN06 or the KN05 box was a real possibility that needed to be addressed before SAGD operations could begin in the KN06 Box. The AER determined that the 10-01 well could be a pathway for steam from the McMurray to the Wabiskaw B.
Need for an Observation Well – Other Mitigation Measures
The AER found that a gas-monitoring well could provide information to show that risk was imminent where there was, for example, an unexplained increase in temperature or pressure. To be useful for monitoring and mitigation, Canadian Natural would have to promptly act on such information. The AER decided that, if the 10-01 well was to be used as a gas-monitoring well, the cause of the temperature and pressure anomalies seen in the 10-01 plot must be investigated further to rule out the possibility of an integrity issue with that well. The investigation would further be necessary to confirm that the monitoring data obtained from that well was a reliable source of information about the risk of encroachment of steam that may impact the Wabiskaw B.
In the circumstances, the AER determined that Canadian Natural’s proposed start-up measure enhancements were effective measures for risk mitigation. It further found that ongoing monitoring after start-up during the operational life of the KN06 Box using existing gas wells and such 4D seismic as Canadian Natural acquired to optimize bitumen recovery was also practicable, appropriate, and cost-effective.
The AER varied CNRL’ s proposed operations in the KN06 Box, establishing new conditions that included an investigation of the temperature and pressure anomalies observed in the 10-01 Well, submission of a monitoring strategy to the AER, conditions regarding bottom-hole injection pressures, and monitoring.