Alberta and Saskatchewan thermal oil sands — state of the union
Every commercial thermal oil-sands project in Alberta and Saskatchewan, 47 in all, profiled from the
operators' own AER Directive 054 filings and from our production and well records.
Compiled 25 September 2026; revised 28 September 2026.
How to read the sources
A bare year in parentheses, for example (2025), means the operator's Directive 054 performance
presentation filed in that year, which reports on the previous calendar year. (records) means the
AER ST37 well data, ST53 scheme production and Petrinex volumes behind this dataset, current to June 2026. (public) means an operator disclosure or press item, named in section 7 where it carries
weight.
Each project carries seven sections: name, history, well pair development, CPF, reservoir, future
development plans, and anything else material.
What you should know before reading any entry
Recovery factors need their denominator. Every deck in the corpus headlines a recovery factor
against the active well-pattern volume — the ground actually under development — and almost none
says so. Against the project area the same figures collapse: Sunrise headlines 42% and is at 2.3% of
its project area, an eighteenfold difference; West Ells headlines 22.6% and is at 0.75%, thirty-fold.
Every recovery figure in this document states its denominator and scope.
In-place volumes are not one measure. Eight bases appear across 29 decks — OBIP, PBIP, POIP, EBIP,
SBIP, GBIP, SOIP and OOIP. Athabasca Oil's GBIP is explicitly gross, including lean zone with no
saturation constraint, so its recoveries read low against everyone else's. Harvest's volumes are
third-party GLJ estimates rather than the operator's own. Each figure below names its basis.
No deck publishes per-pad performance. Across 29 filings not one prints a per-pad oil rate, steam
rate or SOR as running text. Pad-level performance here comes from our records and says so. The single
exception proves the value: PetroChina publishes per-pad SOR, and its scheme figure of 5.76 conceals a
range from 4.1 to 14.6 across its own pads. A scheme SOR describes no pad.
Scheme rates come from ST53, not from our pad roll-up. Summing pad-attributed volumes gives a subset
of a scheme, and the first edition of this document put the shortfall down to wells not matched to a pad.
Most of it was something else: Petrinex rows our ingest dropped because a well's identifier differed from
ours only in its event-sequence digit, 44,700 rows in all, recovered on 28 September 2026. For 2024 the
roll-up now sits within 2.5% of ST53 at 19 of 23 full-year Alberta schemes. Foster Creek (3.4% under) and
Lindbergh (4.0%) still carry wells that are on no pad. At Hangingstone 8788 (28% under) and Peace River
(21%) Petrinex itself holds less than ST53, a cause not yet found. ST53 is not a ceiling either: MEG's
Christina Lake reads 2.3% above it in Petrinex, and MEG's battery, royalty and deck figures agree with the
higher number. Scheme-level rates below are ST53; pad-level rates are the roll-up, labelled as such.
Nineteen of the 47 projects have no filing at all. Saskatchewan has no public performance-filing
regime, so its 17 projects are written from records alone, and Narrows Lake and Pike are Alberta
schemes that have never filed. Those entries are short by necessity. Where a fact is unavailable this
document says so in plain words rather than filling the space.
Cenovus Energy
Foster Creek, Cenovus Energy, OSCA 8623, SAGD, Cold Lake region, Alberta.
Decks: 2021, 2024, 2025 (bare years below); no 2022 or 2023 filing on the AER index; records to June 2026.
2. Project history
AEC steamed pilot pairs at Foster Creek in the mid-1990s; the commercial scheme, Alberta's first SAGD project, came on production in the autumn of 2001 as the B, C, E and D pads started up (records; public). AEC merged into EnCana in 2002; ConocoPhillips held half the project through the FCCL partnership from 2007 until Cenovus, split out of EnCana at the end of 2009, bought it back in May 2017 (public). Cenovus labels its plant history in phases A to G but dates none in the text (2025); the pad records date the field: east from 2006, west from 2010, north from 2016 and again from 2023 (records). The history chart also marks a curtailment and a run of treating and off-spec problems, undated (2025); 52 of the 61 pads on our records had come on production by the end of 2024 (records).
3. Well pair development
Foster Creek's 948 wells split at June 2026 into 379 producing, 376 injecting, 43 suspended and 150 abandoned (records). ST53 puts the scheme at 193,500 bbl/d in 2024, and the pad roll-up gives an instantaneous SOR of 2.34 on the pad-attributed volumes (records); the 2025 deck shows cumulative SOR only as a chart series. The scheme ran 186,700 bbl/d in 2022, 183,200 bbl/d in 2023 and 206,200 bbl/d in 2025 (records). E02 first produced in October 2001, the rest of the east pads from June 2006, the west from August 2010 and the north from N11 in March 2016 (records). N23, N27, N28, E05, W10S, W24, W41 and W42 all first produced after 2024, and W12's five injectors have no production on record (records). N25, on production from November 2024, averaged 22,700 bbl/d from July 2025 to June 2026, or 1,700 bbl/d from each of the thirteen wells that recorded bitumen in that window (records; pad rate over those thirteen wells). N13 averaged 20,600 bbl/d over the same twelve months and W34 10,800 bbl/d, the next two largest (records). Ten older pads have no 2026 bitumen: E17 stopped in September 2023, E42 in August 2024, E19, E07 and E25 from September 2024 to April 2025, and E10, W02, E14, W01 and W18 from September to December 2025 (records). E42's three injectors on record have taken only NCG since January 2022 (records). W19 carries 37 wells of which 16 are abandoned, and W10N 30 of which 11 are, the heaviest abandonment counts on the scheme (records). The 25 east pads have recovered 68% of their pattern OBIP, the 25 west pads 48% and the three north pads in the deck's table 11% (2025). E15 EW has produced 120% of its POIP estimate and 100% of its OBIP, the highest of the east pads, while W09 and E28, both started in 2024, stand at 1% of pattern OBIP (2025). Cenovus co-injects NCG on or supports 40 pads, cuts steam in 25% increments, and injects produced gas on D pad and E14 pad at 100% gas mol fraction (2025). Cenovus registered three well-pair addition applications in 2024, on W15, on E02 and E11 and on W21, plus four trajectory updates covering W41/W42, W12/W24, NP6 and N28/N30/N32 (2025). Redrill wells "have helped to maintain production rates" on operating pads until new sustaining pads were ready to steam, and inflow control devices "have shown mixed performance" (2025).
4. CPF
The site is three plants, FC1, FC2 and FC3 (2025); steam comes from once-through generators (2025) and two cogeneration units, COGEN 1 and 2, named in the compliance tables (2021; 2024), and no vintage mentions a drum boiler. Stated steam capacity has moved between 76,750 m3/d (2021), 77,400 Sm3/d (2024) and 76,500 Sm3/d (2025); 2024 throughput averaged 71,637 Sm3/d, 93.6% of capacity (2025). Oil capacity rose from 190,200 bbl/d (2021) to 219,000 bbl/d after Phase H Area 3, one FWKO, two treaters and fifteen exchangers in FC3, in 2023 (2024), then to 235,000 bbl/d, 82% used in 2024 (2025; records). Make-up water is brackish, from twelve Lower Grand Rapids and four McMurray wells, and 2024 logic changes shifted the draw toward the McMurray; disposal is into the McMurray at the ED1, ED2 and ED3 pads through 23 active wells (2025). The recorded plant troubles are FC1 OTSG repair outages and feedwater hardness that cut steam in 2020 (2021), and in 2024 an FC1 treater cleaning that found "large volumes of solids" plus a major outage on two skim tanks (2025). Under construction at the end of 2024 were the H Phase debottleneck and an amine-Claus sulphur unit due in 2026, joining the NSRU 1 and NSRU 2 units on the history chart (2025).
5. Reservoir
The SAGD target is the McMurray, with a separate Clearwater development area outlined inside the scheme boundary and carried in the pattern table as the W19 W23 CLWTR pad (2025). Reservoir depth is 180 to 225 m subsea across all four areas, and average SAGD pay thickness is given only as "Up to 30+" m, a ceiling rather than an average (2025). The pay cutoffs are gamma below 60 API, porosity above 27% and Rt above 20 ohm-m, which Cenovus equates to So above 50% (2025). Porosity is 34% in the area table and 29% to 34% across the 67 pad patterns, oil saturation is about 85% against about 15% water, and original pressure is about 2700 kPa at 12 degrees Celsius (2025). Horizontal permeability runs up to 10 D in the West and Central areas and up to 8 D in the East and North, vertical up to 8 D and up to 6 D (2025). OBIP is 1031 MMm3 over the project area, 694 MMm3 over the development area and 258 MMm3 over the combined active well patterns (2025). Cumulative production to 31 December 2024 was 147,888 Mm3, which is 57% of that active-well-pattern OBIP and 72% of pattern POIP, but 14% of the project-area OBIP (2025). Estimated ultimate recovery of 179,316 Mm3 is 69% of active-well-pattern OBIP and 87% of POIP (2025). Bottom water is mapped as a McMurray isopach with no thickness stated, and the West cross-section carries five oil-water contact picks (2025). The 2025 deck does not state top gas, top water, lean zones, thief zones or a mapped fault. InSAR heave monitoring was deferred on an average vertical displacement of +3.5 cm, and the AER approved the deferral in 2018 under Scheme Approval No. 8623UUU (2025). In its place Cenovus runs an observation-well network, wellhead and bottom-hole injection pressure monitoring and repeat 4D seismic, which was shot in 2024 while no new 3D was acquired (2025). Mini-frac and DFIT testing at eight wells from 2009 to 2020 produced 27 results, from the Westgate Shale down through the T31, T21 and Wabiskaw T11 caprocks to the McMurray Sand (2025, read from the page image). Only one is post-steam: 15-18-70-3, tested in 2018 on the T31 caprock at 419.25 m TVD, first closure gradient 19.56 kPag/m (2025, read from the page image).
6. Future development plans
Cenovus lists two potential future applications, a Clearwater development and a North area well pad amendment (2025). Planned plant activity is the full Phase H expansion, FC3 boiler feedwater heat dump valves in the F and G phases, and an FC1 brackish facility debottleneck (2025). The 2025 deck does not state a planned pad count, a well-pair count or a drilling schedule, and 2026 is the only future date in it. The planned development map colours pads producing, drilled or locked down, and its pad labels are illegible as filed (2025). Cenovus states that "No pad abandonments are currently planned at Foster Creek" (2025).
7. Anything else
The 2025 deck's 2024 oil rate, 196,321 bbl/d, does not follow from the 29,627 Sm3/d figure printed beside it, which at the deck's own conversion is 186,350 bbl/d (2025). That m3 figure is the number the 2024 deck gave for calendar 2022, and the deck's bbl figure sits 1.4% above the records average used in section 3 (records; arithmetic). That 2024 deck also labels its oil line "Calendar year 2022" beside a steam line labelled 2023. Our records carry a Foster Creek pad E17, four wells now all suspended, that produced 863 m3 in 2022 and 1,776 m3 in 2023 (records). The name E17 appears in none of the 2021, 2024 or 2025 filings. Cenovus is "currently tracking 44 separate SCVF events across Foster Creek (FC) and Christina Lake", a combined figure for two schemes (2025). The well integrity programme reports mitigation in place for surface casing exterior and for surface casing interior and intermediate casing exterior, and an "Investigation on-going" on pack-off corrosion (2025). It also reports no wellhead failures, seven strain-monitoring wells on the W20, E26, W33, W32/35 and North pads, and an application for potassium silicate coating on surface casing (2025). Two solvent pilots are described: an N pad propane SAP pilot at 3 to 10 wt%, last injected in December 2021, and the W06 pad propane pilot at 60 to 80 wt% (2025). That W06 pilot is experimental scheme 13030 and has its own filing, yet the same deck's innovations slide says "No pilots conducted during 2024" (2025). On co-injection Cenovus states that it "does not expect material impact to ultimate recovery due to co-injection", and that no impacts on wellbore integrity or the aquifer have been seen (2025). Fourteen non-compliances were reported for 2024, dominated by CEMS analyzer failures on FC3-B-0205 and FC3-B-0201 that drove sub-90% monthly uptime in January, February and April to July (2025). The rest are two land trespasses, two raw sewage overflows of about 8 m3 and 3 m3 at the Kodiak Den plant, three level-logger failures and one missed produced-gas sample (2025). The pattern tables head POIP, OBIP and cumulative oil in "Mm3" and estimated ultimate recovery in "m3", though the recovery percentages printed beside it hold only if that column is also Mm3 (2025; arithmetic). The East table prints "2%" in the ultimate-recovery-as-percent-of-POIP column for E07 and E14 against current recoveries of 94% and 77% (2025). Two disposal wells, WD23 and WD25, are both listed as 100/16-19-069-03W4, and a facility slide headed "FC1 Steam" describes heat dump valves added in FC3 (2025).
Christina Lake, Cenovus Energy, OSCA 8591, SAGD, Athabasca region, Alberta.
Decks: 2021, 2024, 2025 (bare years below); no 2022 or 2023 filing on the AER index; records to June 2026. Three schemes are called Christina Lake and this is Cenovus's 8591, not MEG's 10773 or MEG's experimental 12528.
2. Project history
EnCana brought Christina Lake on production in 2002, the year the deck's history chart opens, and the chart's phase callouts A through G carry no dates (2025). ConocoPhillips held half of the project through the FCCL partnership from 2007 until Cenovus bought the interest back in May 2017 (public). Records date the pads instead: B02 from October 2006, the rest of the B series from 2008 to 2022, the J and L series from 2016, and the M series from December 2023 (records). The chart marks three turnarounds and a run of warm lime softener and treater cleaning, all undated (2025); every pad on our records was producing by mid-2024, the last of them M01 in June (records).
3. Well pair development
Christina Lake peaked in 2022 at 246,500 bbl/d, eased to 237,300 bbl/d in 2023 and 229,600 bbl/d in 2025, against a 2019 low of 194,800 bbl/d (records). ST53 puts the scheme at 234,200 bbl/d in 2024, and the pad roll-up gives an instantaneous SOR of 2.09 on the pad-attributed volumes (records). The 2025 deck shows cumulative SOR only as a chart series; no value is stated. Its 893 wells on 43 pads include 30 infills, and at June 2026 393 were producing, 371 injecting, 7 suspended and 122 abandoned (records). Pad start-ups run in three waves: B02 and the early B pads to 2014, the F, J, L and H series from 2015 to 2019, and B15 through M01 from December 2022 to June 2024 (records). L19, on production from February 2023, averaged 17,300 bbl/d from July 2025 to June 2026, 1,400 bbl/d from each of the twelve wells that recorded bitumen in that window (records; pad rate divided by those wells). L04 averaged 15,400 bbl/d and M17 14,400 bbl/d over the same twelve months (records). B19 returned the highest per-well figure on the scheme, 1,800 bbl/d from six wells, and G05 1,500 bbl/d from nine, on the same divisor (records). B09 last produced in November 2024 and J03 in November 2025, the only two pads off production (records). The infills sit on six of the oldest pads, nine of them on B06 and six on B02 (records); the word infill appears nowhere in the deck. Per pattern the deck gives J03 at 103% of POIP and 85% of OBIP, and L05 at 106% and 68%, the two past their POIP estimate (2025). At the other end M01 is at 1% of pattern OBIP after six months, L04 at 5% and B15, drilled into thin pay, at 13% against an 85% ultimate estimate (2025). Cenovus injects NCG into 26 pads and into three individual wells, 6-15, 7-14 and 14-12, and injects produced gas on B08 pad at 100% gas mol fraction (2025). Six regulatory applications were approved in 2024, two of them the H11 depressurization and injection project on drainage patterns D23 and D65 (2025). The others are a B02/M01 produced emulsion application, a trajectory update for B21, G12 and H05, a skim tank blower replacement and a physical tagging exemption (2025).
4. CPF
Steam system capacity is 84,500 t/d against a Phase A to H approved capacity of 92,618 t/d, and 2024 throughput averaged 77,614 t/d, 92% of the built figure (2025). Oil system capacity is 44,835 Sm3/d, or 282,000 bbl/d, against an approved Phase A to H bitumen capacity of 310,000 bbl/d, and the 2024 records rate is 83% of the built figure (2025; records). Steam comes from once-through generators, which the deck names only for the FG phase, and the 2024 compliance tables carry seven CEMS-monitored fired units, B-2100, B-2360, B-2500, B-3160, B-3360, B-3460 and B-3500 (2025). No vintage says drum boiler or gives an OTSG count, and two gas turbines, GT-2900 and GT-2950, appear under steam generation and utilities though the 2025 deck does not state cogeneration (2025). Water comes from two Empress fresh wells, eleven brackish Clearwater B wells at 4,300 to 13,200 mg/L TDS and McMurray wells at 8,400 to 18,600 mg/L, with disposal to RD1's six wells and RD2's seven (2025). The plant year was an A-to-E turnaround, four glycol aerial coolers against cooling limits that leave phases A to G "constrained due to gas/sulphur limitations, and cooling limitations", plus SRU cleaning and a new steam record (2025).
5. Reservoir
The McMurray is split into an Upper Zone and a Main Zone, each mapped as its own SAGD pay isopach at a 4 m contour interval, a division Foster Creek's filings do not make (2025). Reservoir depth is 170 to 245 m subsea, and the pay cutoffs are gamma below 60 API, porosity above 27% and Rt above 20 ohm-m, equated to So above 50% (2025). Average SAGD pay thickness is given as "Up to 45+" m in the Christina Lake project area, "Up to 25+" m in the Kirby East project area and "Up to 35+" m in the approved development area (2025). Porosity is 31%, 29% and 30% across those three columns, against 26% to 34% over the pattern rows (2025). Horizontal permeability runs up to 10 D and vertical up to 7 D, oil saturation is about 80% against about 20% water, and original pressure is about 2500 kPa at 12 degrees Celsius (2025). OBIP is 761 MMm3 over the project area, 746 MMm3 over the development area, which is almost the same ground, and 300 MMm3 over the combined active well patterns (2025). Cumulative production to 31 December 2024 was 142,867 Mm3, which is 48% of that active-well-pattern OBIP and 63% of pattern POIP, but 19% of the project-area OBIP (2025). Estimated ultimate recovery of 186,538 Mm3 is 62% of active-well-pattern OBIP and 82% of POIP; the table heads that column "m3", but only Mm3 yields its printed percentages (2025; arithmetic). Three top gas pockets are mapped at a 2 m contour interval and named: "Sec 15" centred over Section 15, "11-14" centred over Section 11 and "Southern" centred over Section 2 (2025). A McMurray water isopach is mapped at 4 m and the cross-sections pick a water top below SAGD base, so the water is basal (2025); the 2025 deck does not state a thickness, top water or lean zones. One DFIT result appears in this filing, from CVE FCCL A10 HARDY 10-10-77-6W4, drilled in 2024 and tested at 305.74 m with a closure pressure of 17.4 kPa/m against a T21 caprock (2025). That well is at Narrows Lake, and the same slide states "No new DFIT wells drilled at Christina Lake" (2025). InSAR heave monitoring was deferred on an average vertical displacement of +6.9 cm, approved by the AER in 2018 under Scheme Approval No. 8591GGG (2025). No 3D seismic was acquired in the project area in 2024, while 4D coverage rose to 11.12 mi2 from 4.7 mi2 in 2023 across fifteen pads (2025).
6. Future development plans
Cenovus lists one potential future application, well pad trajectory amendments for future B, F and N well pads, and the N series appears nowhere else in the deck (2025). Planned plant activity is the Narrows Lake tie-back at "First Steam 2025" and a CDE blower replacement project in 2025 (2025). The planned development map's legend counts seven planned pads, none listed in text, and the 2025 deck does not state a planned well-pair count or a drilling schedule (2025). Cenovus states that "No pad abandonments are currently planned at Christina Lake" (2025). Phase H is recorded as "not constructed" and "on hold" (2025).
7. Anything else
The pattern table has 44 rows while the scheme map's legend reads "Producing (43)", and the deck never reconciles the two (2025). Average permeability is printed as 6.0 D on every one of those 44 rows, so it is an assumption carried into the volumetric model rather than a per-pad measurement (2025). The 2025 deck carries no well integrity content, no casing corrosion table, no SCVF slide and no strain monitoring. The only SCVF disclosure covering this scheme is the combined Foster Creek and Christina Lake count carried in the 8623 filing (2025). Twenty-one non-compliances were reported for 2024, twelve of them CEMS uptime, RATA, cylinder-gas-audit or late-reporting items across the seven fired units (2025). The rest are four phosphorus exceedances at the Martins Point wastewater plant, one AER well site inspection, one effluent contravention at Elks Point Lodge and two ambient H2S exceedances at AMS 26 (2025). On both H2S entries Cenovus records that the "Source of H2S was not able to be determined" (2025). One further entry is a Directive 060 exceedance: overall vent gas at the Christina Lake Thermal Plant "was recorded at 31.3e3Sm3", above the section 8.3(1) limit (2025). Two of the 2024 entries describe October and November 2023 events and are dated by report date (2025). The table prints US-style dates such as 1/1/2024 under a header reading yyyy-mm-dd, and the same unit appears as B-3500, B3500 and "B-35OO" (2025). Cenovus states "No solvent injection at CL, currently", in contrast to the two propane pilots at Foster Creek, and the 2024 pilots and surface failures slides both read "None to report" (2025). The reservoir properties table carries a Kirby East column and the maps draw a CL/KE boundary, and the deck does not say whether approval 8591 covers that acreage (2025). Daily recovery of injected NCG fluids "ranges from 50%-80%", which fluctuates with daily operations (2025).
Sunrise Thermal Project, Cenovus Energy, OSCA 10419, SAGD, Athabasca region, Alberta.
Decks: 2021 (filed by Husky Oil Operations Limited), 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Sunrise took first steam on 12 December 2014 and first production on 8 March 2015, producing 7 to 9 degree API bitumen from the McMurray under OSCA scheme 10419 (2025). Husky Oil Operations Limited filed the 2021 performance report (2021); Cenovus "acquired the remaining 50% working interest of Sunrise from BP on August 31, 2022" and now holds the project outright (2025). The production plot annotates the Fort McMurray fires, a turndown due to low oil prices, turnarounds in 2021 and 2024 and an NCG-off trial, none of them dated on the slide (2025). Fifteen of the eighteen pads on our records were on production by the end of 2024 (records).
3. Well pair development
Sunrise's pad roll-up SOR rose in every year on record, from 2.96 in 2022 and 3.08 in 2023 to 3.31 in 2024 and 3.63 in 2025, while ST53 production rose from 47,600 to 53,800 bbl/d (records). ST53 puts 2024 at 49,600 bbl/d, and at June 2026 the scheme's 285 wells split into 123 producing, 113 injecting, one suspended and 48 abandoned (records). The 2025 deck plots instantaneous and cumulative SOR only as chart series; no value is stated. Pad K01 first produced in December 2023, S01 in May 2024, U01 in June 2024, T01 in February 2025 and V01 in November 2025 (records). V02's eight injectors have no production on record (records). Pad N averaged 7,000 bbl/d from July 2025 to June 2026, 900 bbl/d from each of the eight wells that recorded bitumen in that window and the highest per-well figure on the scheme (records; pad rate divided by those wells). T01 averaged 5,300 bbl/d over the same twelve months, B 4,800 bbl/d and G 4,700 bbl/d (records). Abandonments concentrate on the oldest ground: nine of B's 28 wells, eight of E's 17 and five of N's 17 (records). Recovery per drainage pattern, cumulative to 31 December 2023, tops out at 61% of pattern PBIP on B 16-08 (D) and 59% on B 13-08 (B) and B 14-08 (C) (2025). At the young end it is 3% on B 06-20 (K), 1% on S01 and 0.2% on U01 (2025). Three pattern pairs, (G) with (L), (H) with (M) and (N) with (Q), share a single ultimate recovery estimate because Cenovus does not estimate them separately (2025). Cenovus maps 2024 redevelopment wells, redrill wells and gas injection wells on three separate legend entries (2025), and the 2025 deck does not state a count for any of them. Maximum operating pressure dominates the 2024 application list, with temporary exceedances approved for B 06-20 (K) and for S01 and U01, an MOP modification for S01, U01 and T01, and a redevelopment-well temporary MOP increase (2025). Cenovus reports that Well Pad K01 "encountered challenges with initial injectivity during startup" through pressure interactions with the Development Area 1 well pads (2025).
4. CPF
Steam system capacity is 35,292 m3/d and the January to December 2024 average flowrate was 25,786 m3/d, 73% of capacity (2025). Bitumen system capacity is 11,305 m3/d built against an approved 11,765 m3/d, and the 2024 records rate is 70% of the built figure (2025; records). The 2025 deck does not state whether Sunrise raises steam in once-through generators or drum boilers, and does not state cogeneration; the only fired-unit tags in 41 pages are 70-B-500 and 70-B-501, both in the non-compliance table (2025). The 2025 deck does not state a water source, a disposal well or a water treatment process. Five facilities each carry a plot plan, the Central Processing Facility, CPF 1A, CPF 1B, and the West and East Casing Gas Cooling Facilities, all five unreadable as filed (2025). The two 2024 facility modifications were the West Casing Gas Cooling Facility commissioned in Q1 2024 and a sludge centrifuge commissioned in Q3 2024 (2025).
5. Reservoir
The McMurray pay at Sunrise is bracketed by two mapped surfaces the deck defines on the slide: the base of the inclined heterolithic strata above the reservoir, and the base of McMurray Unconformity 2 (2025). Cenovus describes that second surface as "a surface of tidal/fluvial erosion marking the base of the main McMurray reservoir interval" (2025). Pattern height runs 17.5 m on S01 to 43.3 m on B 15-16 (N) and averages 29.0 m (2025); the 2025 deck does not state a net pay cutoff. Porosity runs 29% to 33% across the fifteen patterns, averaging 31%, and oil saturation 66% to 81%, averaging 75% (2025). Average permeability is printed as a constant 7.0 D on every pattern row (2025), and the 2025 deck does not state original reservoir pressure or original reservoir temperature. The in-place basis is PBIP, calculated "from 2m below Producer Grid to SAGD Pay Top", and the deck then asserts that "In Sunrise, PBIP = OBIP" (2025). At project scale the deck gives 165,111,708 m2 holding 1,070,588 thousand m3 of OBIP, with Development Areas 1, 2 and 3 holding 67,283, 28,793 and 178,525 over 9,652,335, 3,979,931 and 31,017,594 m2 (2025). The fifteen drainage patterns cover 8,413,254 m2 and hold 58,393 Mm3 of PBIP, against cumulative oil of 24,253 Mm3 to 31 December 2023 (2025). That cumulative volume is 42% of pattern PBIP, 8.8% of the three development areas' combined 274,601 and 2.3% of the project area's OBIP, against an estimated ultimate recovery of 39,242 Mm3, or 67% of pattern PBIP (2025). The 2025 deck shows top gas only as an isopach map; no value is stated and no pocket is named. The 2025 deck does not state bottom water, top water or lean zones; a thief zone is acknowledged once, in the caveat that the NCG recycle ratio "does not account for thief zone influence" (2025). The 2025 deck does not name the caprock unit at Sunrise, where the Foster Creek filing names four caprock intervals and Christina Lake names T21. No 3D or 4D seismic was acquired during the reporting period (2025). Four DFIT wells were drilled in 2023 and 2024, stresses estimated by the G-function tangent method, final results reported for 102/07-22-095-07W400 under application 1948860, and no closure pressure stated for any of the four (2025). Sunrise runs the surface heave monitoring that Foster Creek and Christina Lake deferred, with corner reflectors and a cumulative heave map dated 28 October 2024 (2025).
6. Future development plans
Cenovus targets a boiler feedwater bypass to disposal for Q2 2025 and NCG injection on Pad B13-08 (B) and Pad B13-16 (M) for Q3 2025 (2025). A West Casing Gas Compression Facility and an East Casing Gas Cooling and Separation facility are both targeted for Q4 2025, and one further application is anticipated, for Central Processing Facility heat integration (2025). Cenovus states that "Approved Well Pads V02, V03, V04 and V05 are the next pads to be developed", omitting V01, which the maps draw and which carried an approved 2024 application (2025). Cenovus reports "No pad abandonments during the reporting period" (2025). Development options for Development Areas 3 and 4 are under evaluation, and the DA4 amendment application was submitted on 3 August 2024 (2025). That DA4 row is the only one in either approvals table without an approval date, and DA4 is drawn on no map in the deck (2025).
7. Anything else
Cenovus's NCG co-injection pilot started on 8 November 2019 on Pad B13-09 (E), into all six injection wells (2025). Stage 1 ran 15 E3m3/d of NCG at 0.6 volume percent for six months and Stage 2 ran 19 E3m3/d at 0.9 volume percent for six months, against a 2024 average of about 29.5 E3m3/d (2025). Cumulative gas injection to 31 December 2024 was 63,386 E3m3 against 19,294 E3m3 produced, leaving 44,092 E3m3 net retained, a current recycle ratio of 37% and a cumulative ratio of 30% (2025). Cenovus reports reduced SOR without a bottomhole pressure decrease, no observed impact on aquifers or wellbore integrity, and no NCG into well ES05-1 since late 2023 (2025). The reservoir table's cumulative oil column is dated to 31 December 2023 inside a report on calendar 2024, while the NCG pilot figures on the next slide are dated to 31 December 2024 (2025). The deck does not explain the difference, so the pattern recovery factors are not year-end-2024 values. The pattern rows' ultimate recovery values sum to 39,293 Mm3 against the printed total given in section 5, a gap rounding does not explain (2025). The label B 13-16 is used for two different patterns, (M) and (R), with different areas and different properties (2025). T01 appears on three maps and in an approved application but has no row in the pattern table (2025). The PDF's own title metadata reads "Cenovus Energy Inc. Foster Creek In-situ Progress Report Scheme 8623 2018 update", so a pipeline keyed on metadata will file this deck as Foster Creek. The 2025 deck carries no well integrity content of any kind. The facility performance slide repeats the same seventeen-word no-downtime sentence under each of five area headings, in the year of the turnaround noted in section 2 (2025). Six non-compliances were reported for 2024, four of them measurement or monitoring failures (2025). The largest by character is AER Inspection ID 548535, a "Low Risk Notice of Non-Compliance due to continuous black smoke emitted during planned flare event" (2025).
W06 Enhanced Solvent Injection Project, Cenovus Energy, OSCA experimental scheme 13030, propane and steam co-injection, Cold Lake region, Alberta.
Scheme 13030 is not a project in the ordinary sense: it is a single-well-pair solvent test inside Cenovus's Foster Creek commercial scheme 8623. The operator places it at "the W06 PAD and well pair 8 at Foster Creek", and its plant, steam supply and capacity facts belong to 8623 (2025). Our records carry no separate scheme entry for 13030, the W06 pad reporting under Foster Creek (records). Decks: 2022, 2023, 2024, 2025 (bare years below); no 2021 filing; records to June 2026.
2. Project history
The pilot's whole chronology reaches the filing as undated callouts on a performance chart, in this order: W06P01 to P06 started, W06P08 started, W06P08 propane injection started, W06P07 started (2025). The remaining callouts are W06P08 propane injection ended, W06 co-injection started, W06P08 failed liner, and W06P08 shut in for abandonment and redrill (2025). The chart's x-axis runs from March 2014 to December 2024, and the records date the pad's first production to 16 June 2014 (2025; records). Propane injection has ended, W06P08 has been re-drilled and 2025 is a blowdown year, so 13030 is no longer an operating solvent injection (2025).
3. Well pair development
The pad carries eight well pairs, W06P01 through W06P08, and the solvent test is W06P08 alone (2025). Records give the pad 22 wells, 8 producing and 7 injecting, with 7 abandoned, averaging 3,800 bbl/d from July 2025 to June 2026 (records). That is 400 bbl/d from each of the nine wells that recorded bitumen in that window (records; pad rate divided by those wells). Cenovus kept the test isolated, reporting that propane injection in W06P08 "has had a limited impact on neighboring wells due to our intentional operating strategy" (2025). The pad aggregate is therefore seven SAGD pairs plus one quarantined pilot pair, and no chart or table in the deck shows W06P08 alone (2025). The 2025 deck does not state an oil rate, a steam rate or an SOR for the pilot pair. The only quantified results are relative: bitumen rates down 71% and instantaneous SOR up 110% from peak SAGD by the end of the solvent period (2025). Cenovus adds that "Natural SAGD decline rates were not factored into the computations", so both figures overstate the solvent's effect (2025). Pump and well failures during the steam injection period cut produced oil rates, and Cenovus lists redevelopments on P01, P05 and P08 without dates (2025). Cumulative injection on the pad is 7.55 Mt of steam, with 0.052 Mt of propane injected and 0.045 Mt produced back, for 0.007 Mt net injected (2025).
4. CPF
Scheme 13030 has no facility of its own, and the 2025 deck does not state a steam capacity, an oil capacity, a steam generation type or a utilisation for it. Its only surface content is a pad plot plan on which a steam lateral enters W06 from the Foster Creek central plant (2025).
5. Reservoir
The W06 pattern covers 762,639 m2 at an average height of 20 m, 5.5 D permeability, 31% porosity and 89% oil saturation (2025). Its POIP is 3,642 Mm3 and its OBIP 4,514 Mm3, against cumulative oil of 2,338 Mm3 to 31 December 2024, which is 64% of pad POIP and 52% of pad OBIP (2025). Estimated ultimate recovery of 2,653 Mm3 is 73% of pad POIP and 59% of pad OBIP (2025). Pay is cut at gamma below 60 API, porosity above 27% and Rt above 20 ohm-m, mapped at a 2 m contour interval (2025). The 2025 deck does not name the formation. The West Area properties on the following slide are a different scope and disagree with the pad row (2025). They give depth 175 to 220 m subsea, porosity 34%, oil saturation about 85%, horizontal permeability up to 10 D, vertical up to 8 D, pressure about 2700 kPa and temperature 12 degrees Celsius (2025). Bottom water sits around W06, "separated from main SAGD zone by above 10m thick extensive mud and muddy lats" (2025). Gas is "very localized in this area" (2025). The 2025 deck does not state top water, lean zones, a caprock, a maximum operating pressure, any geomechanical test or any heave monitoring. The 3D baseline survey dates from 1999, and 4D surveys were shot in 2017, 2018, 2019, 2020 and 2022, with none in 2023 or 2024 (2025).
6. Future development plans
Cenovus plans a 2025 solvent blowdown, co-injecting NCG "to test solvent recovery post SDP" (2025). Commercial implementation is "currently being evaluated" and is the only potential future application listed (2025). The 2025 deck does not state a date, a volume, a pad count or an application number for it. The re-drilled W06P08 returns to SAGD mode after about six months of that blowdown (2025).
7. Anything else
Cenovus reports that "There was no incremental oil production during the SDP period" (2025). The stated cause is that "Asphaltenes were rejected in-situ as solvent concentration and pilot duration increased", offsetting any production gain (2025). Raising steam injection after the solvent period reversed the SOR trend as expected "but also the degree of upgrading (not expected)" (2025). Those findings sit directly below the line "The pilot has performed largely as predicted", and the deck does not say whether zero incremental oil was the prediction (2025). About 87% of the propane injected on the pad came back, the ratio of the produced to the injected tonnage in section 3 (2025; arithmetic). The design intent was co-injection of propane and steam at up to 80 wt% solvent, running on the pad at 60 to 80 wt% (2025). Cenovus sought lower SOR and greenhouse gas intensity "while achieving some degree of in-situ upgrading", with solvent used to drive lateral steam chamber growth (2025). There were no non-compliance events and no regulatory applications for the W06 pad in 2024 (2025). The PDF's title metadata reads "Cenovus Energy Inc. Foster Creek In-situ Progress Report Scheme 8623 2018 update" (2025). The pattern table heads POIP, OBIP and cumulative oil in "Mm3" and ultimate recovery in "m3", though its percentages hold only if both are Mm3 (2025; arithmetic). Its second row is the whole of Foster Creek, 42,396,867 m2 and 258,312 Mm3 of OBIP, present for context and not attributable to 13030 (2025).
Christina Lake Regional Project, MEG Energy Corp., OSCA 10159 and 10773, SAGD, Athabasca region, Alberta.
This is MEG's Christina Lake, not Cenovus's Christina Lake 8591 on the adjoining acreage and not MEG's own experimental scheme 12528 inside it. Our records carry the scheme under approvals 10159 and 10773 while every MEG filing names Commercial Scheme Approval No. 10773 alone (records; 2025). The report on calendar 2024 was submitted by "Cenovus Energy Inc., on behalf of MEG Energy Corp." and is dated 3 February 2026 (2025). Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
MEG's Phase 1 was approved in February 2005 for 477 m3/d, or 3,000 bbl/day, and sustained steaming started in March 2008 (2025). Phase 2 was approved in March 2007 for 3,975 m3/d, or 25,000 bbl/day, with first steam in Q3 2009, and Phase 2B in March 2009 for 9,540 m3/d, with first steam in Q3 2013 (2025). Phases 3A, 3B, 3C and 3D were approved in February 2012 for 33,390 m3/d, and Phase 2B4X in June 2014 to relocate Phase 3B to the Phase 2 and 2B central plant (2025). Cenovus acquired MEG in 2025 (public), the filing now writes the operator as "MEG (now Cenovus)", and 35 of the 38 pads on our records were on production by the end of 2024 (2025; records).
3. Well pair development
MEG reports a 2024 average of 102,012 bbl/day at an SOR of 2.39, and our Petrinex well total, 101,700 bbl/d at an instantaneous SOR of 2.40, is within 0.3% of it (2025; records). ST53 reads 99,400 bbl/d, 2.3% below the Petrinex total, while the battery's well-level total of 102,029 bbl/d and the royalty program's 102,035 bbl/d match MEG's figure; the difference is unexplained (records). At June 2026 the scheme's 745 wells split into 424 producing, 304 injecting, 8 suspended and 9 abandoned (records). The scheme ran 77,000 bbl/d in 2017 and 77,500 bbl/d in 2020, climbed to 92,800 bbl/d in 2022 and 98,700 bbl/d in 2023, and eased to 96,600 bbl/d in 2025 (records). Pad A first produced in January 2007, the B to F group from August 2009, and the J, K, M, N, T, U and V patterns from 2012 to 2014 (records). AP followed in December 2013, L and AT in 2018, DC and DD in May 2019, AH in December 2020 and DE in June 2021 (records). DG came on in June 2022, DA in August 2023, MCE in June 2024 and MD in September 2024 (records). MD averaged 15,500 bbl/d from July 2025 to June 2026, 1,300 bbl/d from each of the twelve wells that recorded bitumen in that window (records; pad rate divided by those wells). DA averaged 7,800 bbl/d from ten such wells over the same twelve months, MCE 7,600 bbl/d from eight, and AT 7,900 bbl/d from twenty, 400 bbl/d each (records). At the other end pad J returned 39 bbl/d from two wells, pad A last produced in November 2023, BB in August 2024 and F in October 2024 (records). Sixteen SAGD producers, one SAGD injector and thirteen infill producers were suspended over the reporting period, eleven wells were abandoned to meet the AER mandatory liability-reduction spend, and no pattern was abandoned or in active blowdown (2025). Recovery to date per pattern runs from 66% of pattern OBIP on the Phase 2 group of B, C, D, E and F, through 57% on A and AN, down to 9% on MC and 0% on MD (2025). MEG operates one elevated cross-pattern injector, AP14I, which took steam only from January 2022 at 300 t/d and occasionally 450 t/d (2025). It was drilled about 10 m above the existing injectors to heat bypassed pay between AP4P and AN6N, and the wells beneath it have produced about 1.4 MM bbl since (2025). That is about 4.5% of the SOIP at a pattern cSOR of 1.5 as of December 2024, though MEG cannot isolate AP14I's contribution because of redrilling and nearby steam, and drilled no new cross-pattern injectors in 2024 (2025).
4. CPF
Phase 2B runs a drum boiler and a once-through generator, OTSG A, both CEMS units in the 2024 compliance table, beside a Phase 2 cogeneration unit and a Phase 2B gas turbine with a heat recovery steam generator (2025). The 2025 deck shows bitumen treatment and steam generation throughput against design only as charts; no capacity value and no utilisation figure is stated. Plant work in 2024 was cleaning the west process pond, commissioning a casing gas pipeline and building a parallel 24 inch steam pipeline on the North Leg, and MEG "Optimized the produced water disposal system" (2025). AER approval 1955696 relocated skim tank T-113B from Phase 2B4X to Phase 2B and construction is underway, while engineering started on a further skim tank, a third de-oiling train and a fifth OTSG (2025). Class Ib disposal into the Basal McMurray bottom water aquifer runs under AER Approval 10659, whose Clause 3 requires continuous pressure monitoring; 07-16 disposal was halted when Pad L started steaming in April 2018 and restarted in December 2023 (2025). Approval 10659F superseded 10659E on 21 November 2025, replacing the 06-16 piezometer, which stopped recording at the end of May 2017 on a mechanical failure, with piezometers at 12-14 and 02-21 (2025).
5. Reservoir
The reservoir is the McMurray and MEG states that there are no known geomechanical anomalies in the development area (2025). Development area parameters are an average pay height of 24 m, porosity of 0.30 to 0.36 and water saturation of 0.15 to 0.40 (2025). Average horizontal permeability is 5.0 D and vertical 2.5 D, with an initial reservoir pressure of 2,100 kPag at 13 degrees Celsius (2025). This is the one filing in the Cenovus set that prints recovery at all three scopes on the same table, in barrels (2025). OBIP is 4,208,583,000 bbl over the project area, 2,427,150,000 bbl over the development area and 936,559,000 bbl over the combined active well pattern area (2025). Cumulative production of 396,668,000 bbl to 31 December 2024 is 42% of active-well-pattern OBIP, 16% of development-area OBIP and 9% of project-area OBIP, each printed beside its own denominator (2025). Those OBIP figures are qualified by a minimum reservoir thickness of 10 m (2025). Per pattern, net pay runs 14.8 m on MC to 34.7 m on M, porosity 30.8% to 33.1% and oil saturation 68.0% to 81.5% (2025). Permeability is given per pattern as a 2 to 5 D or 3 to 6 D range rather than a single value (2025). MEG also reports against SBIP, which it defines as the bitumen above the producer amenable to SAGD recovery and equates to producible bitumen in place (2025). Recovery on that denominator runs a few points higher on every pattern, and estimated ultimate recovery is given as a band, mostly 50 to 60% or 60 to 70% of OBIP (2025). The 2025 deck shows net pay, associated gas in communication with pay, net basal water and seismic acquisition only as maps; no value is stated for any of them. The 2025 deck does not state top water or lean zones, and the cross section is the only place formation tops, pay intervals and gas and water intervals appear. Basal McMurray pressures are corrected to a 185 masl datum and used to set NCG injection rates on nearby pads, keeping chamber pressure balanced against the aquifer (2025).
6. Future development plans
Approved well pad well pairs will be drilled over the next reporting period, Well Pads and Patterns MG and ME will undergo earthworks and construction, and applications for MM and ML were to be submitted in 2025 (2025). A new 24 inch casing gas pipeline is planned to bring gas from the further well pads into the central plant, and a seventh and eighth disposal well are planned at the 07-16 location (2025). The additional skim tank, third de-oiling train and fifth OTSG move to detailed engineering in 2025 with a regulatory application planned for early 2025, and a carbon capture plant application will be finalised (2025). MEG will also take a Phase 2B central plant turnaround in Q2 2025, start production from Well Pad MD/MH, start drilling on Well Pad AJ, and upgrade the Phase 2B gas turbine and heat recovery steam generator (2025). Two amendment applications were approved in November 2024, adding patterns MG West, MG East, ME South and ME North on the 21st and patterns AW and AX on the 22nd (2025). A gas cap re-pressurization application submitted on 20 December 2024 was still pending at the filing date (2025).
7. Anything else
Approval 10159, which our records carry for this scheme alongside 10773, appears in no ST53 production row at all (records). MEG's eMSAGP process, its "enhanced Modified Steam and Gas Push", combines NCG injection with infill wells to cut the steam needed for the remaining bitumen (2025). MEG reports that "75-80% of the injected gas is produced back from the reservoir and recovered", requiring extra sweetening and re-compression capacity (2025). MEG states that "No negative impacts to well integrity due to co-injection have been observed", and the deck carries no other well integrity content (2025). Twelve reportable incidents and contraventions were logged for 2024, two of them exceedances of the 63.3 kg/hr one-hour NOx limit on the Phase 2 cogeneration unit (2025). Four more are cylinder-gas-audit failures with sub-90% CEMS availability across the Phase 2B drum boiler, OTSG A and the cogeneration unit (2025). The releases are 20 m3 of produced water to grade inside the plant from a frozen exchanger and 9 m3 of brine to secondary containment (2025). Three smaller ones follow: 0.27 m3 of diesel, 3 L from a tipped truck and 0.0005 m3 of steam condensate (2025). The twelfth is tree clearing outside disposition over about 0.09 hectares (2025). MEG reports no unaddressed non-compliances for 2024 and no voluntary self disclosures (2025). The PDFs of MEG's reports on 2022, 2023 and 2024 were built in December 2023, October 2024 and February 2026, the last a day after its cover date (2023; 2024; 2025). The pattern table's footnote excludes inventory wells not yet started and wells offline for early life operational issues from the G, H and K rows (2025). Those three rows are therefore not on the same basis as the other twenty-four. The eMVAPEX solvent patterns AP1 to AP10 are not reported in this filing; they sit in experimental scheme 12528, whose most recent report covers 2022.
Christina Lake Regional Project eMVAPEX pilot, MEG Energy Corp., OSCA experimental scheme 12528, propane and NCG co-injection on SAGD well pairs, Athabasca region, Alberta.
Scheme 12528 is not a project in the ordinary sense: it is an experimental solvent overlay on ten well pairs, AP1 to AP10, inside MEG's Christina Lake Regional Project 10773. It shares its name with that scheme and with Cenovus's separate Christina Lake 8591. Its only filing reports calendar 2022 and states that "Experimental Scheme No. 12528E has been extended through to September 2023 (Application No. 1933352)" (2023). Whether the scheme still exists cannot be established from anything in this corpus. Decks: 2023 only, reporting calendar 2022; no 2024 or 2025 filing on the AER index; records to June 2026 carry no pads, no wells and no production under 12528, because its well pairs report under 10773.
2. Project history
Phase 1 began operation in November 2016, limited to well pair AP2 and infills AP1N and AP2N, and Phase 2 expanded in August 2017 to AP1, AP2 and AP3 with infills AP0N through AP3N (2023). Phase 3 started in the second half of 2018, adding further well pairs and infills and a propane recycle facility, with propane injected into nine injector wells (2023). Make-up propane purchases were paused in January 2021 and only recycled propane has been injected since, while AP5 and AP6 started on recycled propane and NCG in February 2021 (2023). Nine of the ten patterns were injecting propane at the end of December 2022 (2023).
3. Well pair development
The scheme covers ten SAGD well pairs at 100 m spacing, AP1 to AP10, with infill wells AP0N to AP9N plus AQ1N sited between the pairs (2023). The phase matrix shows AP2 on propane in Phase 1, AP1 to AP3 in Phase 2 and all ten in Phase 3 (2023). The same slide's footnote puts nine of ten on propane at the end of 2022, so the Phase 3 diagram is the approval envelope rather than the operating state (2023). The 2023 deck plots bitumen, water, steam, propane, NCG and SOR only as chart series, and for two grouped sets of patterns at that; no rate and no SOR value is stated. The 2023 deck does not state AP5 or AP6 performance. The 2023 deck does not state a well count by year, a redrill, a new infill or any 2022 drilling, and there are no pads in it, only patterns and wells. Injectors AP1I, AP2I and AP3I run 13 3/8 inch surface casing, 9 5/8 inch intermediate casing, a 7 inch slotted liner and 7, 4.5 and 3.5 inch tubing (2023). Steam or solvent can be injected into both long and short tubing, with blanket gas on the annulus (2023). Producers AP1P, AP2P and AP3P carry an electric submersible pump, a bubble tube landed near the pump and a 1.25 inch instrument string carrying thermocouples (2023). They also carry a sliding-sleeve inflow control device held closed until late in the well's life, and an always-open upset production port at the 4.5 to 3.5 inch crossover (2023). Propane is injected under a Class III co-injection approval at a rate "not exceeding 200 m3/d (standard liquid volume) per well", the only hard regulatory limit in the filing (2023).
4. CPF
Scheme 12528 has no facility of its own, and the 2023 deck does not state a steam capacity, an oil capacity, a steam generation type, a turnaround or a water treatment process for it. It names a propane recycle facility and the Christina Lake central processing facility as the destination for produced propane, and describes neither (2023).
5. Reservoir
The filing's entire geology is one structural cross section between wells 1AA/12-12-77-06W4 and 102/06-12-77-06W4 (2023). It labels Clearwater C, a cap rock, the Wabiskaw Marker, Wabiskaw C sand, Wabiskaw D, Wabiskaw D valley fill and the top of the McMurray, with SAGD pay and non-reservoir lithofacies picked inside the McMurray (2023). The 2023 deck does not state pay thickness, porosity, oil saturation, permeability, depth, original reservoir pressure or original reservoir temperature. The in-place basis is SOIP, which the deck neither defines nor quantifies in m3 (2023). The only two recovery figures in fifteen pages are 53% of SOIP for the AP1-4 patterns and 56% for AP7-9, both current to the end of 2022 (2023). Those are pattern-group figures for long-produced, infilled SAGD patterns, not a scheme or project recovery factor, and no estimated ultimate recovery is given anywhere (2023). The caprock is named once, as a label on that cross section, with no thickness, no integrity discussion and no maximum operating pressure (2023). The 2023 deck does not state top gas, top water, bottom water or lean zones. Viscosity appears only as process theory, benchmarked against UTF pure propane, N-Solv pure butane and Cenovus butane co-injection, with no reservoir viscosity stated for Christina Lake (2023).
6. Future development plans
The objectives slide is undated: improve SOR to allow production growth, maintain or increase bitumen production and recovery, and measure injected and produced solvent-oil ratio and solvent recovery (2023). The remaining objectives are to "Enhance oil quality" and "Optimize propane recycle facility design and operation", to cut per-barrel greenhouse gas intensity and water use intensity, and to use existing infrastructure within the current footprint (2023). The 2023 deck does not state a 2023 operating plan, a drilling plan, an expansion, a commercialisation timeline or an application list, and its Phase 3 update slide is retrospective. The only forward statement with a date is the extension to September 2023, and nothing in this corpus reports on the scheme after it.
7. Anything else
MEG runs SAGD for two to three years to put heat into the reservoir, then injects cold propane that takes its heat from the rock (2023). The switch comes at about 20 to 30% recovery, with the remaining oil at about 60 to 100 degrees Celsius (2023). The SAGD producer keeps running with little or no steam and the infill well produces the diluted oil, which MEG brands DARUMA, for "Diluted, Asphaltene Reduced, Upgraded, Metal Abated" (2023). MEG names the obstacle: "solvent retention in reservoir and cost of solvent are critical factors" preventing commercial application of solvent in in-situ recovery (2023). The 2023 deck shows propane recovery only as a chart, and its three series, gas, liquid and a central-plant estimate, disagree with one another without the deck saying which is authoritative. The 2023 deck has no compliance, flaring, incident, well integrity, measurement, heave monitoring or abandonment content, and none of the 4.1 to 4.4 section structure the rest of the corpus uses (2023). Every page is stamped Confidential, and the PDF was built on 24 May 2023 against a June 2023 cover date (2023). An eleventh infill well, AQ1N, appears once in the Phase 3 list and nowhere else (2023). MEG holds Canadian patent 2,912,159 on the process (2023).
Canadian Natural and Suncor
Canadian Natural and Suncor thermal schemes
Eight entries: Primrose and Wolf Lake 9140, Jackfish 10097, Kirby 11475, Peace River 8143,
Cold Lake 12812, Kirby SE-SAGD 12810, Firebag 8870, MacKay River 8668. Pike 12301 is written
elsewhere.
Primrose and Wolf Lake
1. Project name
Primrose and Wolf Lake, Canadian Natural Resources, OSCA 9140, cyclic steam stimulation with SAGD and steamflood, Cold Lake region, Alberta.
Decks: 2022, 2023, 2024, 2025 (bare years below); no 2021 filing in this corpus; records to June 2026.
2. Project history
BP steamed the first vertical-well pilot in the Wolf Lake C3 Sand in 1966, and the development-history table names Dome, BP, Amoco, Suncor and Canadian Natural as operators of record across the seven sands (2025). Canadian Natural's own entries in that table begin with the 1999-2000 Phase E2 and N horizontal CSS and the 2000 Phase 21 horizontal CSS (2025). The steam-start annotations on the production plots run Z8 November 1988, HWP October 1993, E2 October 2000, Z13 November 2005, S1B and MC1 August 2011, Z8 steamflood January 2016 and SC07_B June 2024 (2025). The AER granted Primrose a lifecycle approval on 28 May 2021, and the property today works 57 named well patterns across four operating areas, Wolf Lake, Primrose South, Primrose North and Primrose East (2025; records).
3. Well pair development
Primrose steams by cyclic stimulation, steamflood and SAGD at once, and in June 2026 our records held 594 of its 932 wells as producing, 174 as injecting, 137 as suspended and 27 as abandoned (records). Scheme oil ran 69,300, 82,500, 80,300 and 89,500 bbl/d in 2022 to 2025 on the AER scheme series, at steam-oil ratios of 6.56, 5.39, 5.82 and 5.30 on the same series (records). The first five months of 2026 averaged 74,900 bbl/d, a partial year (records). The 2025 deck shows cumulative SOR only as a chart; no value is stated. The two newest pads now lead the property, Pad 71 with twenty wells from November 2024 and Pad 162 with twenty-five from March 2025 (records). Each averaged 7,100 bbl/d over the twelve months to June 2026, which is 360 bbl/d per producing well at Pad 71 and 310 at Pad 162, pad rate divided by producing wells (records). Behind them sit Pad 93 at 5,200 bbl/d from eighteen producers, Pad 161 at 4,100 bbl/d from twenty-five, Wolf Lake SC07 at 4,100 bbl/d from twenty-four and Pad 72 at 3,800 bbl/d from sixty-one (records). The Burnt Lake pattern has recovered 71% of its 1,516 e3m3 pattern OBIP, the highest on the property, while Pad 51 stands at 11% against a stated 13-26% potential range (2025). The 2025 deck does not state a cycle number for any pad or say which patterns have converted to steamflood. Canadian Natural re-drilled Pads 74, 77, 78 and 90 in 2024 and added a CSS re-drill plus a buffer well at Pad 160, saying the Pad 90 originals "were placed low in muddier pay with reduced vertical permeability" (2025). Four patterns went permanently to zero on either side of the performance year, Phase 17 in August 2023, Phase 60 in November 2023, Phase 64 in August 2024 and Phase 25 in October 2024 (records). Five more stopped a year later: Pads 51, 61, 65 and 26 each produced a last barrel in October 2025, and Wolf Lake Phase N in September 2025 (records).
4. CPF
Bitumen design capacity is 23,000 m3/d in every vintage from 2022 to 2025 (2022; 2025). Steam design fell from 90,800 m3/d (2022; 2024) to 89,264 m3/d (2025) as the Wolf Lake line dropped from 9,000 to 8,000 m3/d and the 500 m3/d Burnt Lake line was removed. In 2024 the plants ran 13,020 m3/d of bitumen, 57% of design, and 83,836 m3/d of steam, 94%, split as Primrose South 30,093, Primrose East 25,642, Primrose North 21,437 and Wolf Lake 6,665 m3/d (2025). The AER scheme series gives 74,300 m3/d of steam for 2024, 11% below the deck's figure, while the two agree on oil within 2%; the difference is unexplained (records; 2025). The 2025 deck does not state the steam generation type; its one mention of an HRSG is among the uptime contraventions in section 7. Plant work in 2024 was confined to the Wolf Lake CPF: water disposal well 12, commissioned in January 2024, and a wet-style acid tank vent scrubber and second acid tank on Unit 11 (2025).
5. Reservoir
The Clearwater, Grand Rapids and McMurray formations carry the bitumen, worked through nine named sands including Orange, Blue (CS30), Yellow (CS60), Valley Fill, C3, B8 and Sparky D, B10 and General Petroleum, Sparky C and McMurray (2025). Pay cut-offs run above 6% bitumen by weight in the regional Clearwater and above 8% in the Grand Rapids B10, the McMurray and the Sparky C and D, with net pay above 10 m needed for development (2025). Development-area averages are 12 m of pay, 0.32 porosity and 0.61 oil saturation at Primrose and 19 m, 0.34 and 0.55 at Wolf Lake (2025). Clearwater permeability runs 1 to 4 Darcies, and the Wolf Lake Sparky C is the richest sand at 0.84 oil saturation, 16 m of maximum net pay, 0.33 porosity and 5,300 mD horizontal against 4,200 mD vertical permeability (2025). Dead-oil viscosity at 20 degrees Celsius spans 180,000 cP in that Sparky C to 600,000 cP in the Wolf Lake McMurray (2025). The deck notes in three places that PBIP equals OBIP here, so its in-place volumes carry no producibility discount (2025). OBIP is 1,577 e6m3 over the project area, 1,368 e6m3 over the development area and 467 e6m3 over the combined active well pattern area (2025). Cumulative recovery is 10% of development-area OBIP at Primrose and 2% at Wolf Lake, against 22% and 33% of active-well-pattern OBIP for the same two areas (2025). Top gas sits in localised, sealed Clearwater gas pools tied to the CS30A20 facies, and the 2024 drainage boxes were set back 150 m from them (2025). Bottom water is mapped in the McMurray below a 6 ohm-m cut-off and in the Sparky C, and the B8 carries 1 to 3 m of it outside the immediate development area (2025). A confined differential compaction feature within a pre-Clearwater intrastratal Devonian karst at 06-069-04W4 carries a caprock assessment and monitoring plan approved in May 2023 and a 200 m buffer (2025). The 2024 3D survey found a second compaction feature inside conceptual drainage box 167, and a caprock plan is to be submitted before that box is developed (2025). Heave is tracked by GPS over Primrose North CSS cycles 5 and 6 and Primrose East cycles 1 and 2, with fibre vertical strain measured at 6-34 (2025). A 2024 pumping test put the radius of influence in the Lower Grand Rapids basal water sand at 975 m over pads 71C and 162, against 1,190 m for 160-161 and 850 m for 93N (2025).
6. Future development plans
Three Primrose North pads, 163, 164 and 165, are under evaluation at 20 to 32 development wells each, with Primrose East 93X and five SAGD well pairs at Wolf Lake SC07 Phase C (2025). Delineation covers three strat wells and one observation well at Wolf Lake and nine observation wells at Primrose, all in the first quarter of 2025, plus Primrose North 3D and 4D seismic acquisition (2025). The five-year map carries conceptual drainage boxes 163, 164, 165 and 166, with box 167 gated on its caprock plan (2025). Applications listed for 2025 are a Burnt Lake decommissioning plan update, a Wolf Lake SC05 SAGD application, a Pad 97 CSS application at Primrose East, an EPEA approval renewal and a Primrose CSS lifecycle amendment (2025). Every item on that list is qualified "Pending favorable economic conditions" (2025).
7. Anything else
The 2024 filing, covering calendar 2023, states "No well patterns suspended or abandoned during the reporting period" (2024). Phase 17 and Phase 60 both produced their last barrel inside that period, on the dates in section 3 (records). The 2025 deck deleted the sentence rather than correcting it, and its suspension and abandonment slide lists four Burnt Lake injector UWIs and nothing else (2025). The 2024 filing had said Canadian Natural was "Planning to abandon the three Burnt Lake injectors in 2024"; the 2025 slide reports four (2024; 2025). Twelve casing failures came in 2024, eight intermediate impairments via MTD and four intermediate failures via PIT, all out of zone, all at the casing connection and all on steamflood wells (2025). All twelve sat below 5.0 MPa bottomhole pressure, and the deck states that no casing failure has occurred during CSS operations since 2020 (2025). Canadian Natural completed twelve slimhole repairs in 2024 at a stated potential saving of $200K per well and inspected 21 wells for external corrosion (2025). The development-area OBIP in section 5 does not reconcile with its own split of 965 e6m3 at Primrose and 345 e6m3 at Wolf Lake, which sums 4% short (2025). The "60%+" potential recovery range is booked alike on Pads 71 and 162, at 1% and 0% of pad OBIP, and on Pads 74, 75, 77 and 78, producing since 2008-09 and at 38 to 55% (2025; records). The fault slides state that no new geomechanical anomalies were identified in 2024 and do not mention the box 167 compaction feature in section 5 (2025). The filing was submitted on 10 December 2025, so its applications table lists 2025 items already approved in February, April and May 2025 (2025). NCG co-injection runs on two Wolf Lake SAGD pads, MC1 from 22 February 2023 and SD9 from 29 January 2023, at 0.5 to 1.0 mol% against a target steam re-allocation of 0 to 10% (2025). Class II disposal scheme 9108A, reported inside this filing, has taken nothing since 2017 and carries 1,021,115 m3 of remaining voidage with no plans to restart (2025). Four reportable releases in 2024 measured 45.0, 3.0, 160.0 and 5.0 m3, all contained on lease (2025). Three voluntary self-disclosures cover a Wolf Lake CPF monthly vent gas exceedance on 13 December 2024 and two pressures above the maximum BHIP set by clause 34 of the approval, at 18A74 RD and 22A92 (2025). Environmental contraventions were four instances of a CEMS or HRSG unit missing its 90% uptime requirement, plus one late submission (2025).
Jackfish
1. Project name
Jackfish, Canadian Natural Resources, OSCA 10097, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Devon Energy built Jackfish in three plants, taking scheme approval for Jackfish 1 in November 2004 and first steam in August 2007 (2025). Jackfish 2 was approved in September 2008 and first steamed in May 2011; Jackfish 3 was approved in November 2011 alongside amalgamation of the approvals and first steamed in July 2014 (2025). Canadian Natural has operated the scheme since buying Devon's Canadian business in 2019, an event no vintage of the deck mentions (public). The East and West Expansion approvals were granted in 2018 and 2019 and remain undeveloped (2025).
3. Well pair development
Jackfish's 33 pads feed three separate plants, and in June 2026 our records counted 224 of their 528 wells as producing, 237 as injecting, 27 as suspended and 40 as abandoned (records). Scheme oil ran 117,200, 113,400, 119,700 and 118,200 bbl/d in 2022 to 2025 on the AER scheme series, at steam-oil ratios of 2.45, 2.57, 2.39 and 2.45 on the same series (records). The first five months of 2026 averaged 99,400 bbl/d, a partial year (records). The 2025 deck shows iSOR and cSOR only as chart curves on the three plant plots; no value is stated. Pad XX, on production since October 2023, leads at 15,900 bbl/d over the twelve months to June 2026, or 1,330 bbl/d from each of twelve producers, pad rate divided by producing wells (records). Pad TT follows at 9,200 bbl/d from eight producers first on production in March 2025, then Pad S at 7,400 bbl/d from seven started in January 2024 and Pad EEE at 6,700 bbl/d from ten (records). Pad KK is lowest at 44 bbl/d per producer, 220 bbl/d from five (records). Pad A has recovered 93% of its pad OBIP against a 90-95% ultimate range, while Pad XX, the largest pad at 1,115,331 m2, stands at 12% and Pad S at 5% (2025). Canadian Natural re-drilled eleven laterals in 2024, B2, B6, E6 and E7 at Jackfish 1, AA2, AA5 and OO2 at Jackfish 2 and K2, K3, K4 and K6 at Jackfish 3, all close to the parent lateral (2025). The deck credits flow control devices with improved conformance and production rates, and re-drills with a lower iSOR (2025). Pad FF produced into Jackfish 3 for November 2024 with its volumes reported under Jackfish 2, which breaks any plant-to-plant rate comparison for that month (2025).
4. CPF
Jackfish's approved bitumen production capacity is 19,080 m3/d on an annual average basis (2024; 2025). The Directive 056 licence limits of the three plants, 6,757, 7,950 and 7,950 m3/d of bitumen and 15,971, 15,971 and 15,990 Sm3/d of steam, are the same in every vintage from 2021 to 2025 (2021; 2025). In 2024 Jackfish 1, 2 and 3 produced 5,626, 7,337 and 6,058 m3/cd, together 99.7% of the approved capacity, and injected 15,210, 15,586 and 14,584 Sm3/d, 95% of the steam limits (2025). The 2025 deck does not state the steam generation type. The Jackfish 1 sulphur removal unit took a new compressor and contactor package, processing gas from 11 December 2024, and emulsion, field gas and steam interconnects joined Jackfish 3 to Jackfish 2 in July 2024 (2025). The 2024 reliability work listed "Steam generator reliability improvements and material upgrades", a steam generator throughput trial, a hot lime softener sludge recirculation system and coating work on the weak acid cation exchange unit (2025).
5. Reservoir
Jackfish produces the McMurray, with the Clearwater as caprock, the Wabiskaw above and the Devonian unconformity below, all labelled on the cross-sections (2025). Bitumen Pay is defined at oil saturation above 50% and is split into Bitumen Pay and Bitumen 2 Pay wherever IHS separates the two (2025). Area runs 17,094 Ha over the project, 10,300 Ha over the development area and 1,889 Ha over the active well patterns (2025). Average thickness is 14, 18 and 32 m across those three scopes, oil saturation 74, 75 and 78%, and porosity 33, 34 and 34% (2025). OBIP and PBIP are 571, 464 and 163 e6m3 across the same three scopes, with a further 75 and 63 e6m3 when Bitumen 2 is included (2025). Cumulative oil under the active patterns is 78 e6m3, or 48% of active-well-pattern OBIP (2025). Average maximum permeability is 5,400 mD and vertical permeability 1,200 to 2,000 mD (2025). The deck states "No major gas intervals in communication with pay at Jackfish" (2025). Bottom water is labelled on every cross-section, and water-contact-to-Paleozoic isopachs are mapped for the developed area and both expansion areas (2025). The 2025 deck does not state a caprock thickness, any caprock integrity work or any lean zone. No heave monitoring was done in 2024, the deck giving as its reason that it observes "no significant geomechanical issues" at Jackfish and operates a low pressure SAGD process (2025).
6. Future development plans
The twelve-month list has four items, circulation at Pad TT forecast for the first quarter of 2025, re-drill programs, 4D seismic acquisition and disposal infrastructure, all qualified "Pending favorable economic conditions" (2025). The five-year plan is a polygon labelled a 5 Year Potential Development Area, with no pad list, no well count and no timeline (2025). The deck says the area defines only where development "MAY be developed within the next 5 years" (2025). Three applications are listed with blank approval dates, a Jackfish redrill program for the second quarter of 2025, a Jackfish lifecycle application for June 2025 and a blowdown application for Pads EE, FF and VV for July 2025 (2025). That blowdown application is the only forward statement in the deck that names specific pads as reaching end of life (2025). Approved future pads are drawn on the drainage-box map in the Jackfish 1 and 2 areas and as thirteen pads apiece in the East and West expansion areas, none with a date (2025).
7. Anything else
Pad TT is drawn on the drainage-box map and starred as coming on production in 2025, yet it carries no row in any volumetrics table (2025). The PDF's internal Title field reads as the Kirby 11475 presentation, because the deck was built from the Kirby template (2025). SCVF and gas migration testing covered 270 wells in 2024, producing four new serious vent flows at C2I, D1I, K5I and RR4I with repairs deferred to 30 November 2025 and six non-serious results (2025). 39 wells sit in the DDS register with serious vent flows, against 45 DDS records in 2024 of which 10 were deleted and 4 were new (2025). Surface casing testing covered 34 wells in 2024 for six failures, an 18% failure rate, against 299 wells and 37 failures to date, a 12% rate (2025). NCG co-injection covers 25 pads at 1 to 5 mol%, with a 20% target steam re-allocation and an estimated 30 to 70% recycle recovery; the deck reports improved SOR, increased WSR and no McMurray aquifer or well integrity impact (2025). McMurray source water of about 350 m3/d from 3-15 began disposal on 24 August 2024, with a further 2,150 m3/d planned to reach 2,500 m3/d and a second well starting in January 2025 (2025). The 2024 Directive 081 calculated disposal limit was 25.8% against actual disposal of 9.8% (2025). Compliance was two reportable releases, 0.03 m3 on 17 June 2024 and a 3 m3 glycol leak on 17 November 2024 (2025). Two voluntary self-disclosures cover exceedances of the approved 25 m3/d start-up net injection rate on Pads XX and OOO, and two CEMS uptime contraventions are reported (2025). Reference number 20241447 is attached both to the 17 June 2024 release and to a NOx CEMS uptime contravention dated 31 January 2024 (2025).
Kirby
1. Project name
Kirby, Canadian Natural Resources, OSCA 11475, SAGD, Athabasca region, Alberta. Two Alberta schemes carry the Kirby name; the other is experimental approval 12810, profiled below, which was amalgamated into 11475 in January 2024.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Kirby South took scheme approval in September 2006 and first steam in October 2013, and Kirby Expansion, which the deck also calls Kirby North, took approval in May 2014 and first steam in May 2019 (2025). Canadian Natural built Kirby itself, and no predecessor operator appears in any vintage of the deck. The Kirby South Pad Add Extension, named Ipiatik, was approved in November 2021, and the Kirby East Pad Add Extension in December 2023, neither yet carrying named drainage boxes (2025). The AER approved the expiry of experimental scheme 12810 and its amalgamation into this approval on 23 January 2024 (2024).
3. Well pair development
Kirby is two developments under one approval, Kirby South producing since 2013 and Kirby North since 2019; in June 2026 their 18 pads held 140 of 329 wells producing, 151 injecting, 27 suspended and 11 abandoned (records). Scheme oil ran 54,000, 58,800, 64,200 and 58,600 bbl/d in 2022 to 2025 on the AER scheme series, at steam-oil ratios of 3.38, 3.71, 3.48 and 3.86 on the same series (records). The first five months of 2026 averaged 57,700 bbl/d, a partial year (records). The 2025 deck shows cSOR, iSOR and cWSR only as chart curves on the two area plots; no value is stated. Kirby South G Pad is the largest producer at 8,300 bbl/d over the twelve months to June 2026 from fifteen producers, 550 bbl/d per producing well, pad rate divided by producing wells (records). KS21W follows at 6,100 bbl/d from nine producers and KS22 at 5,900 bbl/d from eleven, on production since May 2023 and December 2022 (records). Pad A, on production since 2013, still makes 730 bbl/d per producer from seven, 5,100 bbl/d in all, while Pads C and F share the lowest Kirby South figure, 200 bbl/d per producer (records). At Kirby North, KN07 and KN06 came on in 2023 and now run 3,900 and 3,800 bbl/d (records). Pad-level recovery is filed against drainage-area OBIP, and the deck states "in Kirby, PBIP=OBIP" (2025). Kirby South C is furthest along at 65% of its drainage-area OBIP, Kirby South 21 at 9% and KN07 at 6%, and every drainage area carries the same 50-70% ultimate range (2025). Canadian Natural re-entered E6P at Kirby South and KN03-12P and KN04-10P at Kirby North in 2024, and drilled the step-out pair KN02-13P and KN02-13I (2025). NCG injection started at Pad D in the first quarter of 2024 and at Pads B and C in the second, and a steam-additive pilot started on two KN07 well pairs at the end of October 2024 (2025). The deck reports that 2023-2024 SAGD start-ups tend to run hotter in the toe half of the lateral and that "Liner deployed inflow control devices (ICDs) are preferred for new development" (2025). Our records split KS21 into KS21W and KS21E and KN05 into KN05W and KN05E, while the deck's volumetrics table reports 21 and 22 whole and its map splits each into A and B boxes (records; 2025).
4. CPF
Kirby's two plants hold Directive 056 licence limits of 7,532 m3/d of bitumen at Kirby South and 8,368 m3/d at Kirby North, with 18,720 Sm3/d of steam at each, unchanged in every vintage from 2021 to 2025 (2021; 2025). The approved bitumen production capacity across both is 22,260 m3/d on an annual average basis (2024; 2025). In 2024 the plants produced 5,537 and 4,663 m3/cd, together 46% of that approved capacity, while steam ran 18,347 and 17,155 Sm3/d, 98% and 92% of the limits (2025). The 2025 deck does not state the steam generation type; it reports refractory work on "Boiler #2, #4, and #5" at Kirby South and CEMS lapses on the "3-H-100 steam generator", and both plants treat water with evaporators (2025). A disposal water pipeline joining the two facilities and the MCM07 disposal well both came into service in the third quarter of 2024, and the SR1 solvent recovery facility in the second (2025). Boiler control logic at Kirby South was automated to use process and ambient conditions, and the deck says the plant has consistently met its facility design stream-day volume since (2025).
5. Reservoir
Kirby produces the McMurray at both areas and the Wabiskaw D as a separate approved drainage-box set at Kirby North (2025). Pay is defined at oil saturation above 50%, encompasses all brecciated intervals and may include minimal IHS (2025). The Kirby South combined active well pattern carries 25 m of pay, 74% oil saturation, 33% porosity, 4.7 D permeability and 41 e6m3 of OBIP, of which 44% has been recovered (2025). The Kirby North combined active well pattern carries 24 m, 79%, 33%, 5.2 D and 32 e6m3, of which 33% has been recovered (2025). Approved development areas hold 54 e6m3 at Kirby South, 78 e6m3 in the Kirby North McMurray and 44 e6m3 in the Kirby North Wabiskaw D, inside an approved project area of 273 e6m3 (2025). The McMurray basal aquifer is the scheme's stated risk, and the deck reports a "Strong bottom water connection" between the Kirby SW pads and the regional McMurray basal aquifer system (2025). Bottom-water isopachs are mapped for all four areas, and a gas isopach only for the Kirby North Wabiskaw D (2025). The Clearwater A shale is labelled as regional caprock on the cross-sections, and the 2025 deck does not state a caprock thickness or report any caprock integrity study. No geomechanical anomalies were identified since the last reporting period, and no heave monitoring or seismic was done in 2024 (2025). Disposal at 1-17-074-08W4 has lifted pressure about 500 kPa above an original static of 2,600 kPa and stabilised at 3,000 to 3,100 kPa (2025). At Kirby North the rise is about 300 kPa at the 08-26 observation well west of the Paleozoic high and about 225 kPa at 07-29 to the east (2025).
6. Future development plans
Kirby North is to take three KN02 re-drills in the second quarter of 2025, and Kirby South re-drills and re-entries at A8, A9 and D2 in the first quarter (2025). G-pad step-out drilling at G12 through G16 is planned for the first and second quarters of 2025, and NCG co-injection is to start on the A and E pads during the year (2025). Everything on that list is qualified "Pending favourable economic conditions" (2025). KN08 and KN09 were approved for development in May 2024 and for NCG and SE-SAGD co-injection in December 2024, and neither has a row in any volumetrics table (2025). Applications running into 2025 cover NCG on KS21, KS22 and Pad E, an Upper Mannville gas baseline sample for KN08 and KN09, and two Kirby North Clearwater disposal well amendments (2025). Three more follow in mid-2025: diluent co-injection on Kirby South Pad G, a Kirby South disposal well application and a revised surface pad location for KN25 (2025).
7. Anything else
The light hydrocarbon work at KN06 is the deck's headline technical result, reported as a "SOR reduction of approximately 30%, trending towards target" and "Light hydrocarbon recovery reached 80% in reservoir with bottom water" (2025). Asphaltene precipitation in the solvent recovery train is reported as an operating problem alongside it (2025). The filing was submitted on 9 December 2025 for calendar 2024, so the first-quarter 2025 drilling it lists as "under evaluation" was scheduled before the filing date (2025). Compliance was one reportable release, FIS 20240822 on 22 March 2024 at an estimated 7 m3, five EPEA contraventions including a November CEMS uptime of 78.8% for flow and NOx, two Water Act contraventions and no voluntary self-disclosures (2025). SCVF and gas migration testing covered 52 wells at Kirby North and 51 at Kirby South in 2024 (2025). It found one serious flow at KS G8I with repair deferred to 30 November 2025, one non-serious flow at KN01-7I and two wells with possible casing impairments, both suspended (2025). Surface casing testing covered 18 Kirby South wells in 2024 for two failures, an 11.1% rate, against 89 wells and six failures to date, a 6.7% rate (2025). Actual disposal in 2024 was 48% of the 2024 disposal limit (2025). The McMurray observation well chemistry on the groundwater slide dates from January 2020, sampling not being required in 2024 (2025). Application 1952579, to correct an error on the Kirby North development-area map, was submitted on 11 July 2024 and approved on 15 July 2024 (2025).
Peace River
1. Project name
Peace River, Canadian Natural Resources, OSCA 8143, SAGD, CSS and steamflood, Peace River region, Alberta. The deck's own page footer names the operating entity Canadian Natural Upgrading Limited.
Decks: 2022, 2023, 2024, 2025 (bare years below); no 2021 filing in this corpus; records to June 2026.
2. Project history
Shell developed the Peace River in-situ pilots, and the abandoned PRISP, PREP and HWDP wells the deck names as dead pads are on our record with first production from 1979 to 1987 (2025; records). The production plot dates commissioning of Pads 19, 20 and 21 to 1996-1998 and of Pads 30 to 33, 40 and 41 to 2000-2001; a third label, "2004- 2005: Commisioning of Pads", names none (2025, read from the page image). Canadian Natural has held the scheme since acquiring Shell's Peace River thermal assets in 2017, and 281 of the 426 wells on the record are now abandoned, more than at any other scheme in this file (public; records).
3. Well pair development
Beside the abandoned majority counted in section 2, Peace River carried 53 producing wells, 21 injecting and 54 suspended in June 2026 (records). Oil on the AER scheme series fell from 5,300 bbl/d in 2022 to 3,800, 3,000 and 2,100 bbl/d over the next three years, while the steam-oil ratio rose from 2.63 to 3.13, 6.70 and 11.45 (records). January to May 2026 averaged 3,200 bbl/d, a partial year (records). The 2025 deck shows cSOR and iSOR only as a chart; no value is stated. Steam rose from 1,878 to 3,187 m3/d between 2023 and 2024 while oil fell by a fifth (records). Canadian Natural started a CSS steam cycle on Pads 32 and 33 in 2024, the deck's only reported event for the year, and drilled no new wells (2025). Our pads here are geometric clusters with no operator alias, placed onto the deck's pad map, so per-pad attribution is uncertain (records; 2025). On that basis the four live thermal pads, the deck's Pads 33, 32, 30 and 31, ran 770, 490, 430 and 390 bbl/d over the twelve months to June 2026 (records). The Pad 33 group makes 70 bbl/d per producing well from eleven and the Pad 32 group 33 bbl/d from fifteen, pad rate divided by producing wells (records). Pad-level recovery is filed against pad OBIP, which the deck sets equal to PBIP (2025). The first Pad 20 row reads 38% recovered against a 38% ultimate and the first Pad 21 row 31% against 31%, while Pad 32 stands at 14% against 18% and Pad 33 at 11% against 14% (2025). The suspension and abandonment slide states that no well pattern was suspended or abandoned in 2024 and that none was in active blow down (2025). Thirteen of the twenty-two wells in our Pad 19 satellite group carry AER suspended status, two of them dated 30 April and 1 May 2024, inside the reporting period (records).
4. CPF
Peace River's plant holds a Directive 056 facility licence of 2,000 m3/sd of bitumen and a steam design of 8,000, stated in t/d from 2022 to 2024 and in m3/d CWE in 2025 (2022; 2024; 2025). Its 2024 output was 375 m3/cd of bitumen, a calendar-day figure against a stream-day limit that yields no utilisation, and 3,200 m3/d CWE of steam including utility steam, 40% of design (2025). The 2025 deck does not state the steam generation type. The production plot marks "Declining steam generation since 2007", "Curtailments" and "Plant Turnaround", none dated (2025, read from the page image). The 2024 modifications were a pump minimum recycle valve upstream of the tank to hold tank level and reduce blanketing, and a switch of the raw water tank SV-4.05 blanketing from natural gas to nitrogen (2025).
5. Reservoir
Peace River produces the Bluesky at 550 to 600 m TVD, with Upper Bluesky sitting on the Debolt unconformity and Lower Bluesky filling lows in the Debolt (2025). Pay runs 15 to 30 m, porosity 0.25 to 0.30, oil saturation 0.70 to 0.85, horizontal air permeability 0.1 to 10 D and kv over kh 0.3 to 0.9 (2025). Dead-oil viscosity spans 10,000 to 1,000,000 cP (2025). Net pay is mapped at water saturation below 30%, and the reservoir base is picked at the same 30% cut-off, equivalent to about 40 ohm-m (2025). OBIP equals PBIP here, at 441 e6m3 over the project area, 220 e6m3 over the development area and 57 e6m3 over the active well pattern area, the last excluding well pads 106 and 107 (2025). Cumulative recovery is 15% of active-well-pad-area OBIP, against 24% booked as ultimate across the pad table (2025). Water is mapped as a combined thickness of a basal transition zone at 30 to 50% water saturation and a basal water zone above 50% (2025). A Basal Lean Zone is labelled on the structural cross-section below the base of pay (2025). The deck states that no major gas intervals are in communication with pay in the project area (2025). No known geomechanical anomalies were identified since the last reporting period, no heave monitoring was done in 2024 because it is not a condition of approval, and no new 3D seismic was acquired (2025). Primary caprock is the Wilrich Member of the Spirit River Formation at about 80 m, inside a minimum continuous Spirit River thickness of about 240 m (2025).
6. Future development plans
The twelve-month activity list has a single item, replacing the emergency generator and upgrading the associated diesel supply tanks from single-walled to double-walled, qualified "Pending favourable economic conditions" (2025). The five-year slide is a map with a development-area polygon and one caveat, that five-year development "will be contingent on the outcome of subsurface trials, internal approval and market conditions" (2025). The upcoming applications slide names no application, saying only that Canadian Natural continues to evaluate future development opportunities (2025). An electrocoagulation trial is under evaluation to test whether the technology suits produced water treatment at the plant (2025).
7. Anything else
The pattern volumetrics table prints Pad 20 and Pad 21 twice each, once as a component row and once as a subtotal, with nothing on the slide distinguishing them (2025). Pad 20 at 2,041 e3m3 plus Pad 20i at 1,503 e3m3 gives the second Pad 20 row, 3,544 e3m3, and Pad 21 at 2,345 e3m3 plus Pad 21i at 1,524 e3m3 gives the second Pad 21 row, 3,869 e3m3 (2025). Summing all thirteen printed rows gives 64,564 e3m3, 13% above the printed table total, while the nine non-duplicated rows sum to that total exactly and their cumulative oil to the printed 8,757 e3m3 (2025). The deck books remaining recovery on the two pads it declares suspended: Pad 40 carries 8,794 e3m3 of OBIP at 10% current and 26% ultimate recovery, and Pad 41 carries 5,994 e3m3 at 8% and 23% (2025). Both produce nothing and all seventeen of their wells carry suspended status (records). The commissioning annotations in section 2 do not match our first-production record, which puts Pads 30 and 31 in 2001, Pads 40 and 41 in 2002 and Pads 32 and 33 not until 2006 (2025; records). The 2023 and 2024 decks' plant bitumen figures, 844 and 600 m3/cd, equal the AER scheme series for 2022 and 2023 to the cubic metre (2023; 2024; records). For 2024 the deck's 375 m3/cd matches our Petrinex pad roll-up of 2,352 bbl/d within 0.3%, while the AER scheme series in section 3 is 27% higher at 475 m3/d; the difference is unexplained (2025; records). Compliance was two reportable releases, 1.98 m3 on 26 August 2024 and 5.04 m3 on 14 December 2024, plus an uncontrolled release of 300 m3 of clean surface water through a berm breach on 19 June 2024 (2025). One contravention was 363 m3 of sour blanket gas vented from a pressure vacuum relief valve on slop tank SV607 on 14 January 2024, while a frozen transmitter was being worked on (2025). The other was surface water released from pads 19-3, 19-4 and 22 on 2, 27 and 30 July 2024 with field-tested chlorides above the 500 ppm limit (2025). No thermal or utility well had a casing failure in 2024, and Canadian Natural ran ultrasonic thickness scans on all 32 wells of Pads 32 and 33 (2025). The block steaming strategy on Pads 32 and 33 is credited with reducing pressure leak-off between columns, and scab liners with targeting steam to lower depleted reservoir (2025).
Cold Lake conductive heating pilot
1. Project name
Cold Lake Clear Water Hydrocarbon Conductive Heating Project, Canadian Natural Resources, experimental scheme approval 12812, conductive heating with primary recovery, Cold Lake region, Alberta.
This is not a SAGD or CSS project. Approval 12812 covered three horizontal wells testing an electric heater cable against continuous hot fluid circulation against an unheated control well, with no steam injected, no well pairs, no SOR, no pads beyond one and no central processing facility (2025). The scheme expired on 1 March 2024 and the final deck's reporting period is the two months from 1 January 2024, not a calendar year (2025).
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); the 2025 deck is the final report and carries no cover date; our records hold no production rows for this approval.
2. Project history
Canadian Natural applied for the experimental scheme in 2018 and the deck names the three wells from that application (2025). Production charts begin on 1 January 2019, though the deck states no first-production, drilling or construction date (2025). Power cable theft at 102/8-34 and 103/8-34 forced the installation of hydraulic drives on engine skids in May 2023, and 102/10-34 was shut in that July after repeated theft of the power supply cable at its wellhead (2025). The scheme expired at the end of that two-month reporting period with no application to extend and no follow-on scheme (2025).
3. Well development
The pilot is three horizontal wells on one pad and nothing else, so well pairs, injectors, infills, re-drills and cycle counts do not apply (2025). The wells are the heater cable well 102/10-34-062-06W4, the hot emulsion circulation well 103/08-34-062-06W4 and the control well 102/08-34-062-06W4 (2025). Cumulative production to 1 March 2024 was 10,798 m3 from the cable well, 4,453 m3 from the circulation well and 4,064 m3 from the control (2025). All three ran progressing cavity pumps, high-temperature at first and conventional later, and the circulation well carried vacuum insulated tubing and a line heater that failed and was bypassed (2025). The 2025 deck shows per-well oil, water and gas rates only as charts; no value is stated. The cross-section spaces the three logged wells about 389 m and 377 m apart (2025). The lead well has produced nothing since July 2023, and the deck reports suspension and abandonment activity as "Not Applicable" (2025).
4. CPF
Approval 12812 has no central processing facility and no steam plant (2025). No steam is injected anywhere in the scheme; the heat sources are an electric heater cable and a line heater for hot fluid circulation (2025). The 2025 deck does not state a design rate, a capacity, a modification, a turnaround or any water treatment. The whole surface facility is a plot plan for Pad 15-27, showing three wellheads, propane tanks, secondary containment, buried power supply cables and a tank rack (2025). The plot plan carries a 168.3 mm Husky pipeline under AER licence 27139 across the site (2025).
5. Reservoir
The pilot targets the Clearwater, mapped as Upper Clearwater and Upper-Middle Clearwater, with no depth stated (2025). Net pay is drawn at a 60% oil saturation cut-off and runs 9 to 10 m thick (2025). Initial pressure is 2,800 kPag at a reservoir temperature of 16 degrees Celsius, with 38% average porosity and 66% average oil saturation (2025). Average vertical permeability is printed as 1,875 mD against 1,306 mD horizontal, with a kv over kh ratio printed as 0.7 (2025). Oil viscosity at 20 degrees Celsius runs 50,000 to 210,000 cP, density 970 to 996 kg/m3 and gravity 10 to 14 degrees API (2025). The in-place basis is OOIP, and each of the three wells is assigned the same estimated drainage volume of 237 e3m3 (2025). Recovery against that assumed per-well OOIP to 1 March 2024 is 4.56% for the cable well, 1.89% for the circulation well and 1.71% for the control, and no ultimate recovery is given (2025). The 2025 deck does not state a caprock, a lean zone or any geomechanical work, and no seismic was interpreted (2025). Gas isopachs are mapped for both Clearwater intervals and the deck states there is no major water interval, though the log cross-section labels an oil-water contact below the base of pay (2025).
6. Future development plans
No further pilot activities are planned for the upcoming twelve months, the deck giving the expiry of the experimental scheme as the reason (2025). No regulatory approvals were submitted in 2024 in connection with the scheme (2025). No commercialisation plan, follow-on scheme or extension application appears anywhere in the deck (2025). Canadian Natural gives two reasons for stopping, that power cost and supply infrastructure in the Manatokan East area are "challenging commercialization of electrical heating", and the theft of cable and equipment (2025).
7. Anything else
The learnings slide carries the pilot's one transferable finding, that "Primary recovery accelerated about twice the rate by utilizing VIT tubing" (2025). The deck explains the mechanism as heat distribution from toe to heel, against non-insulated tubing that heats only the heel region (2025). Because all three wells share the same OOIP denominator in section 5, the three recovery percentages compare cumulative production alone (2025). The printed kv over kh of 0.7 is the inverse of the two permeabilities in section 5, since dividing the smaller by the larger gives 0.70 and the reverse gives 1.44 (2025). The PDF's internal Title field names a different project and a different approval, the Light Hydrocarbon-Enhanced Steamflood pilot under experimental scheme 13013 (2025). No reportable incidents, voluntary self-disclosures or contraventions were associated with the pilot (2025). The learnings slide names the heat cable well 103/10-34, a UWI that appears nowhere else in the deck, where every other slide has 102/10-34 (2025). The plot plan labels the same three wells 7D2/07-34, 8C2/08-34 and 8C3/08-34, placing the heater cable well at 07-34 rather than 10-34 (2025).
Kirby SE-SAGD pilot
1. Project name
Kirby SE-SAGD Pilot, Canadian Natural Resources, experimental scheme approval 12810, solvent-enhanced SAGD using butane, Athabasca region, Alberta.
This is not a project in the sense a reader assumes. Approval 12810 covered two well pairs, G9 and G10, on the G Pad of Kirby South inside commercial approval 11475, and the Kirby South plant is not described in it (2024). The approval expired on 31 March 2024 and was amalgamated into Kirby 11475, so the 2024 filing is a final report (2024).
Decks: 2021, 2022, 2023, 2024 (bare years below); no 2025 filing and none will follow, so the one-to-two-year lag behind the current reporting cycle is benign; our records hold no production rows for this approval.
2. Project history
The AER approved experimental scheme 12810 on 22 October 2018 on application 1911685, submitted that July (2024). Solvent injection began at G10 on 12 June 2019 and at G9 on 28 August 2019 and ran to 6 November and 10 December 2020, after which both operated as normal SAGD pairs (2024). The pump skid and pilot surface facilities were decommissioned in October 2022 and butane production monitoring was suspended at the end of that year (2024). Canadian Natural applied on 15 December 2023 to expire the scheme and amalgamate it with approval 11475, and the AER approved that on 23 January 2024 (2024).
3. Well pair development
The scheme is two well pairs and there was no drilling, no infill, no re-drill and no change to pilot activity in 2023 or 2024 (2024). Suspension and abandonment activity is reported as "Not Applicable" (2024). Steam was cut to a target of 40 to 50% of the SAGD rate and butane was injected to hold chamber pressure (2024). The 2024 deck shows steam, oil, water, fluid, solvent injection and iSOR only as a single two-pair chart; no value is stated. Cumulative bitumen production over the solvent period was consistent with baseline SAGD while using less steam, though vapour interference with ESP operation was seen in both wells (2024). G10 reached 80% steady-state solvent recovery, while G9 recovered less because solvent leaked off to adjacent SAGD well pairs, and no figure is given for G9 (2024). The deck's headline claim is that the pilot "achieved 40-50% SOR reduction and maintained similar SAGD oil rate", which describes the injection period and not the wells' later state (2024). Both pairs have reported under approval 11475 since March 2024 (2024).
4. CPF
The pilot took steam from the Kirby South Central Processing Facility, which serves the whole of approval 11475 and is not described here, so the steam generation question belongs to that filing (2024). The deck states the pilot was small enough to have "no impact on the fluid handling capacity of the Kirby South Central Processing Facility" (2024). What is described is the solvent train: solvent bullets, two 50% solvent injection pumps and a 4-inch solvent pipeline injecting butane with the high-pressure steam (2024). Casing vapours were cooled, condensed and pumped into the emulsion pipeline, and vapours flashed at the plant were cooled and recycled into the process stream (2024). New construction was a Hydra-cell pump skid at the central plant, since decommissioned, an underground pipeline to G pad, and on the pad a butane injection flow control module, an aerial cooler and a multiphase pump (2024).
5. Reservoir
The pilot produces the McMurray, with the Clearwater Shale labelled as caprock, the Wabiskaw between, and the Paleozoic below (2024). The resource cut-off is defined only by reference to the Kirby 11475 definition, which the deck does not reproduce, so no porosity, saturation or pay cut-off can be stated from this filing (2024). The 2024 deck does not state depth, initial pressure, initial temperature, viscosity, density or a kv and kh split. The G9 and G10 drainage area covers 149,824 m2 with 20.9 m of average pay, 33% porosity, 83% oil saturation and 5.7 D average permeability (2024). OBIP and PBIP are both 0.9 e6m3, the deck stating "in Kirby, PBIP=OBIP", so the figure carries no producibility discount (2024). Total recovery to 31 March 2024 is 53% of original bitumen in place and ultimate recovery is booked at 70% of the same volume, which is not comparable with a PBIP-based ultimate carrying a producibility discount (2024). The volumetric method is area within the drainage box boundary and the 10 m contour multiplied by SAGD thickness, average oil saturation and average porosity, with no formation volume factor (2024). No water or gas intervals are in direct communication with pay within the pilot area (2024). No known geomechanical anomalies were identified since the last reporting period (2024). Pad G has full 3D seismic coverage, acquired in 2000, with 4D surveys in 2015 and February 2021 and none in the reporting period (2024).
6. Future development plans
No further pilot activities are planned for the upcoming twelve months because the scheme expired in March 2024 (2024). Canadian Natural states that the pilot "achieved all KPIs" without listing a KPI or a target, that the process patent CA 3,079,710 has been granted, and that the process is being integrated into its business plan (2024). The one forward commitment is a single bullet, a pad-scale demonstration project at Kirby North described as under construction, with no approval number, well count, capacity or date attached (2024).
7. Anything else
Oil density improved by up to 1.5 API from in situ upgrading, and the existing artificial lift handled the extra vapour, most of the produced butane coming up the annulus (2024). No reportable incidents, voluntary self-disclosures or contraventions were associated with the pilot through its whole duration (2024). Butane production continued after butane injection stopped (2024). Two operability failures are published: asphaltene precipitated when emulsion was inadvertently introduced into the butane-rich annulus gas system on surface, and the butane supply can contain water and freeze (2024).
Firebag
1. Project name
Firebag, Suncor Energy, OSCA 8870, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Suncor's Firebag project has produced since 2003 and sits 70 km northeast of Fort McMurray (2025). Suncor has operated Firebag from start-up, and the filing records no ownership change (2025). The 2025 deck shows the four stages only as annotations on the production chart; no dates are stated. By June 2026 the property carried 56 pads (records).
3. Well pair development
Firebag produces more oil than any other scheme in this file, and in June 2026 our records held 381 of its 767 wells as producing, 357 as injecting, 24 as suspended and 4 as abandoned (records). Oil on the AER scheme series climbed every year from 198,700 bbl/d in 2022 to 217,800, 233,900 and 244,600 bbl/d, and January to May 2026 averaged 211,600 bbl/d (records). Suncor states a 2024 steam-oil ratio of 2.62, and the same series gives 2.72, 2.71, 2.61 and 2.54 for 2022 to 2025 (2025; records). The 2025 deck shows cSOR and WSR only as charts; no value is stated. Pads 123 and 126 lead at 11,400 bbl/d each over the twelve months to June 2026, followed by Pad 131 at 10,300, Pad 121 North at 8,400, Pad 119 at 8,300 and Pad 129 at 7,700 (records). Pad 131 returns 1,290 bbl/d per producing well from eight and Pad 123 1,270 from nine, pad rate divided by producing wells (records). Pad 101 has recovered 86% of its pad EBIP against a 98% expected ultimate and now makes 4,700 bbl/d across its north and south halves (2025; records). Pad 119, fifth on the rate list above, stands at 6% of its EBIP recovered against an 80% ultimate (2025). Pad 129 stands at 0% against a 72% ultimate, having started up during the reporting year (2025). Suncor drilled three pads in 2024, Pad 113 with 9 well pairs, Pad 120 with 10 and Pad 133 with 7, and started up Pad 129 with 11 pairs (2025). Start-up at Pad 129 combined circulation with bullheading, the deck saying bullheading "requires less cumulative steam to achieve the same reservoir heating as air circulation" (2025). Six wells were suspended during 2024, carrying remaining reserves of 534,060, 494,485, 478,456, 400,590 and 246,079 m3 and one at zero, the first justified as a marginal producer (2025).
4. CPF
Firebag's stated design rate rose from 203 kbbl/d (2021; 2022) to 34,182 m3/d, or 215 kbbl/d, at a 2.8 SOR (2023), with steam injection design capacity at 104,760 m3/d (2022; 2023). The 2024 and 2025 decks show both capacities only as chart lines; no value is stated, and Suncor says its internal reassessment of design capacity will finish in the second quarter of 2026 (2025). Against the 2023 figures, 2024 bitumen of 37,165 m3/d ran 9% above the design rate and steam of 97,303 m3/d at 93% of injection capacity (2023; 2025). The 2025 deck does not state the steam generation type; its compliance tables name four available cogeneration units, one of them the 193F-5000 COGEN unit (2025). The same tables name Plants 91 to 94, Plant 92 evaporators, a warm lime softener, weak acid cation vessels, clarifiers, an amine stripping unit and a sulphur recovery unit (2025). A debottlenecking application was submitted on 5 November 2024 and approved on 21 March 2025 (2025).
5. Reservoir
Firebag produces the McMurray, and the fracture-closure table names the lower McMurray 3 sand, the middle McMurray sand, the middle McMurray mudstone, the middle McMurray IHS and the Wabiskaw and lower Clearwater as the tested intervals (2025). Continuous reservoir is picked at the base on a bulk mass fraction of oil cut-off of 6%, with less than 3 m of more than 50% mud or breccia in the lower portion (2025). The top is picked at 2 m of mudstone with no saturation or porosity cut-off applied (2025). Suncor states that "EBIP at Firebag/Mackay River is the same as the Original Bitumen in Place (OBIP)" and that EBIP is the preferred term on site (2025). The combined active well pattern area averages 35.2 m of continuous reservoir, 0.32 porosity, 4,048.2 mD horizontal and 2,475.5 mD vertical permeability and 0.74 oil saturation (2025). It holds 329,800 e3m3 of EBIP, of which 48% has been recovered against an 83% expected ultimate (2025). The development area holds 700,783 e3m3 of EBIP at 35.00 m and 0.73 oil saturation, and the project area 1,323,100 e3m3 at 30.50 m and 0.71, with no recovery figure given for either (2025). Suncor states that "No top or bottom water zones have been identified" within the Firebag development area, and that upper and middle lean zones are present in parts of it (2025). It adds that "Thief zone potential is unknown at this time but is being assessed" (2025). The gas isopach carries an explicit dismissal of gas as a development risk (2025). InSAR from 2013 to 2024 gives a maximum heave of 541 mm at Pad 105 and the greatest average heave, 230 mm, at Pad 116 (2025). Three new caprock cores were collected during the reporting period and no new micro-frac wells were drilled (2025). The 28 fracture-closure tests run from 2012 to 2023 give closure pressures of 3,775.3 to 6,871.0 kPag and gradients of 15.1 to 23.8 kPag/mGL, limited to an overburden gradient of about 21.5 kPag/mGL (2025). Suncor concludes that operating at the approved maximum operating pressure "does not impact Firebag caprock integrity" (2025). 4D seismic was acquired in 2024 over Pads 109, 110W, 116, 117, 122 and 131 (2025).
6. Future development plans
Suncor plans 25 sidetrack wells in 2025, then Pads 138, 139 and 140 at 9 well pairs each in 2027 and Pad 142 at 12 well pairs in 2028 (2025). First steam is planned for Pad 132 in the second quarter of 2025, Pad 130 in the third quarter of 2025, Pads 120 and 113 in the third quarter of 2026 and Pad 133 in 2027 (2025). An ES-SAGD amendment is planned for Pads 138, 139, 140 and 142, extending the diluent co-injection now running on Pad 131 (2025). Two further pads, 143 and 144, are named in the activity table and are drawn on no map (2025).
7. Anything else
The pad table omits five pads that the drainage-pattern map draws as drilled, 113, 120, 130, 132 and 133, three of which were drilled during the reporting year and none of which carries any reservoir property (2025). The column headed "Hydrocarbon area (m2)" is in thousands of m2: the combined row's 38,831, times the section 5 thickness, porosity and saturation, reproduces the printed EBIP only when read as thousands (2025). Pad 131 has had all eight well pairs co-injecting hydrotreated make-up diluent since February 2023 at a target concentration of 10 vol%, against a SAGD baseline of March 2022 to January 2023 (2025). The chart annotation claims an oil uplift of 40%, with a range of plus 2 and minus 14 points (2025). NCG co-injection has run since May 2018 on what Suncor calls "10 mature pads (Pads 101-109, 116)", and it typically starts "when the estimated ultimate recovery has exceeded 65% through normal SAGD operations" (2025). Two integrity deferrals are open: a plug at 311.5 mKB in 4P10, pressure tested at 7,000 kPa for 20 minutes, and a casing failure at 12.80 mKB in 14P10, deferred since 17 August 2022 (2025). The file in the corpus is dated 30 June 2025 on the cover but was created on 24 November 2025, and its internal Title reads "Directive 54 Template Overhaul Review", as MacKay River's does (2025). Compliance for 2024 runs to about thirty itemised events: eight venting contraventions over ten minutes, eight approval violations, thirteen reportable spills, one unauthorized-construction contravention and one voluntary self-disclosure for late reporting of a casing failure on P3P8 (2025). Among them are a NOx hourly average of 111.73 kg/hr during AESO-requested peak firing on 2 April 2024 and disposal pH of 12.7 and 12.51 against a limit below 12.5 (2025). Industrial make-up water diversion also went above the 2,280 m3/day maximum on 16 and 17 May 2024 (2025). Two measurement problems are disclosed, an incorrectly calculated SO2 365-day rolling average from May 2023 to March 2024 and a downhole gauge set in the wrong formation (2025).
MacKay River
1. Project name
MacKay River, Suncor Energy, OSCA 8668, SAGD, Athabasca region, Alberta. Two other Alberta schemes carry near-identical names, PetroChina's MacKay River 11715 and Greenfire's ceased McKay River 11461; none of their figures belongs here.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Petro-Canada built MacKay River, which has produced since September 2002 from a site 60 km northwest of Fort McMurray (2025). Every well on the record carries the DOVER field name and the older ones a PC prefix, the only trace of the original operator anywhere in the filing (records; 2025). Suncor has held the scheme since its merger with Petro-Canada completed on 1 August 2009, an event the deck does not mention (public). The existing-operations table dates growth pad by pad from Phase 1 in 2002 to Phase 9 in 2024, covering 119 well pairs (2025).
3. Well pair development
MacKay River has moved off its 2002 patterns: in June 2026 its first two, A and C, produced nothing, while our records held 126 of 295 wells on 21 pads producing, 128 injecting and 41 suspended (records). Oil on the AER scheme series has stayed between 32,300 and 33,600 bbl/d since 2022, at 32,300 bbl/d in 2024 and 33,300 in 2025, and January to May 2026 averaged 34,900 bbl/d (records). Suncor states a 2024 steam-oil ratio of 3.01, and the same series gives 2.80, 3.19, 2.99 and 3.02 for 2022 to 2025 (2025; records). The 2025 deck shows cSOR, iSOR and iWSR only as whole-field charts; no value is stated. Pad 826 leads at 5,900 bbl/d over the twelve months to June 2026 from six producers, 980 bbl/d per producing well, pad rate divided by producing wells (records). Pad 819 follows at 5,000 bbl/d from nine producers, then 750N at 3,500, 751W at 3,200 and the NN pattern at 3,100 (records). Pattern-level recovery is filed against pattern EBIP, and Suncor books no further recovery on its two oldest patterns: Pattern C stands at 87% recovered with expected ultimate also 87%, and Pattern A at 51% against 51% (2025). Pattern 826, first steamed in 2024, stands at 0% against a 51% ultimate (2025). Suncor suspended 14 wells during 2024, covering every remaining Pattern A and Pattern C producer, justified as "High recovery factor, lack of productivity, no good sidetrack opportunities" (2025). Pattern C last produced in September 2022 and its producers were suspended in July and August 2024, 23 months later (records; 2025). Suncor drilled three well pairs at Pad 819 in 2024 and partially drilled Pad 829 with 12 producers and 11 injectors, and first steam went to Pad 826 with 6 pairs (2025). Seven sidetracks were drilled in 2024, F7P, OO5P, OO7P, NN1P, QQ2I, QQ4P and H3P, and Suncor says annual sidetrack drilling "has continued to be effective in improving oil recovery" (2025).
4. CPF
MacKay River's plant carried a stated design rate of 6,041 m3/d, or 38,000 bbl/d, at a 2.8 SOR and a steam injection design rate of 18,432 Sm3/d in every vintage from 2021 to 2023 (2021; 2023). The 2024 and 2025 decks show the bitumen production capacity and steam injection limit only as chart lines; no value is stated. Against the 2023 figures, 2024 bitumen of 5,133 m3/d ran at 85% of design and steam of 15,449 m3/d at 84% (2023; 2025). The 2025 deck does not state the steam generation type; its one mention of cogen is a note that water disposal during the autumn 2025 cogen maintenance will let production rise through the outage (2025). Suncor states there were no modifications to the plant during the reporting period requiring an AER application approval (2025). The regular turnaround ran from 3 September to 2 October 2024 with no issues noted, and the records show September oil at 2,700 bbl/d, against 35,700 in August and 33,600 in October (2025; records).
5. Reservoir
MacKay River produces the McMurray, with Wabiskaw C, Wabiskaw D and Clearwater above it (2025). Continuous reservoir is picked at the base on a bulk mass fraction of oil cut-off of 6%, with less than 3 m of more than 50% mud or breccia in the lower portion (2025). The top is picked at the first 2 m of non-reservoir facies (2025). Upper lean, middle lean and gas zones are included in the volume with no thickness cut-offs, which is the only place lean zones appear in the deck (2025). The combined active well pattern area covers 10,517,188 m2 at 24.5 m of continuous reservoir, 0.34 porosity and 0.78 oil saturation, holding 69,492 e3m3 of EBIP of which 50% has been recovered against a 70% expected ultimate (2025). Project area and development area are the same polygon, holding 321,817 e3m3 of EBIP at 20.5 m and 0.72 oil saturation with 11% recovered, so the deck offers no wider regional resource figure (2025). Basal water is mapped below a cut-off of 0.02 bulk mass fraction of oil and 60 API gamma at a 1 m contour interval, which distinguishes MacKay River from Firebag (2025). The gas isopach uses a 0.03 gas saturation cut-off and carries an explicit dismissal (2025). Maximum heave is about 93 cm, measured by manual monuments with plus or minus 5 mm of uncertainty (2025). One new caprock core was taken in the reporting period and no microfrac tests were run (2025). The 21 fracture-closure tests span the Clearwater, Wabiskaw D, Wabiskaw C and McMurray with gradients of 19.0 to 24.3 kPa/m (2025). Maximum operating pressure is set from a 21 kPa/m fracture gradient at the base of the Wabiskaw D caprock in each pattern, with an 80% safety factor (2025). No new 3D seismic was acquired in 2024, but 4D seismic was shot across Pad 819 (2025).
6. Future development plans
Suncor plans a well length extension at Pad 828 in the first quarter of 2026 and a 2025 sidetrack program across Pads 24, 25 and 750 in the third quarter of 2025 (2025). First steam is planned for Pad 819 and for Pad 829, the latter at 23 wells in the second quarter of 2026 (2025). Development of the South Dover well pads 754, 755, 759 and 760 is listed with no date (2025). The five-year outlook gives 2 sidetrack wells in 2025 and Pad 828 at 6 well pairs in 2026, with first steam at Pad 828 in the first quarter of 2028 (2025). A regulatory boundaries amendment submitted on 4 November 2024 was still pending at the filing date (2025).
7. Anything else
The deck contradicts itself on Pad 819 first steam, the activity table giving the third quarter of 2025 and the five-year outlook the first quarter, two pages apart; our records put the pad's first production in April 2025 (2025; records). It also contradicts itself on sidetracks, the five-year outlook listing two wells for 2025 against an activity table naming a three-pad program (2025). The heave slide places C Pattern on Pad 21 while the operations table assigns C to Pad 20 and B and D to Pad 21; one of the two is wrong (2025). C4P, whose abandonment application the AER approved on 1 May 2024, still carries suspended status dated 23 July 2021 on the AER well list (2025; records). Pads 819, 829, 828 and the four South Dover pads appear in no volumetrics table, so the deck's authoritative pad list depends on which slide is read (2025). The pattern volumetrics table is internally consistent, its areas, EBIP and recovery-to-date each summing to the printed combined row within rounding (2025). Its "Hydrocarbon area (m2)" column really is in m2, unlike the identically headed column in Suncor's Firebag deck (2025). Our records carry no injector against patterns 750S, 751N and 751S, which cannot be right, so those are total wells and no per-well figure is derived for them (records). NCG co-injection has run in phases since May 2016 and typically starts "when the estimated ultimate recovery has exceeded 50%", a threshold 15 points below Firebag's (2025). Phase 5 added Pad 824 and the NN, OO and QQ patterns in 2024, and Phase 6 covering Pads 750 and 751 was planned in service for late 2025 (2025). The cover date is 30 June 2025 and the PDF was created on 28 November 2025, the same five-month pattern as the Firebag file (2025). A diversion-lagoon fluid disposal pilot injected 99.75 m3 into well DW1 in November 2024, meeting the class 1b specification under Directive 051 (2025). The HOLLER trial required by condition 27 of approval 8668LLL "did not proceed and there are currently no plans to proceed" (2025). Compliance runs to twelve entries, among them an HCl spill of 0.5 m3 and an uncontrolled steam release at the Pad 22 E7 injector carrying about one litre of bitumen (2025). Others are an AER notice of non-compliance at the MacKay River bridge, an OO6P casing failure with repair deferred to April 2026, and a voluntary self-disclosure for missing the 90-day SCVF repair window (2025). A Water Licence section 4.8 contravention was traced to vendor datalogger reporting (2025).
Strathcona, Athabasca Oil, Greenfire and others
Strathcona, Athabasca Oil, Greenfire and others — thirteen schemes
Lindbergh, Strathcona Resources, OSCA 6410, SAGD, Cold Lake region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Murphy Oil piloted and commercialised cyclic steam stimulation in the Lloydminster and Rex formations from 1972, and approval 6410 was granted in May 1991 (2021; 2025). Pengrowth bought Murphy's Lindbergh interests in 2004 (2021; public); Cona Resources, a Waterous Energy Fund company, completed its purchase of Pengrowth on 7 January 2020, and WEF announced Cona's amalgamation with Strath Resources as Strathcona on 14 August 2020 (public). The SAGD pilot's two pairs took steam circulation in February 2012, and twenty wells on Pads D02, D03 and D05 took first steam in December 2014 once the Phase 1 CPF was built (2025). Pad campaigns followed through D08, first steamed in January 2023, and D01-West, on production from March 2026 (2025; records).
3. Well pair development
Lindbergh had 143 wells on seven pads at June 2026, 75 of them producing, 56 injecting and 12 suspended (records). Oil averaged 19,100 bbl/d in 2024 at an SOR of 3.03, against 17,800 bbl/d at 2.85 in 2019 and 14,900 bbl/d at 3.44 in 2022 (records). Cona ran a Q2 2020 ramp-down "due to low commodity price environment", shutting in infills to keep pairs operating (2021). Output fell to 16,600 bbl/d at 3.73 in 2025 and 14,500 bbl/d at 4.85 over January to May 2026 (records). The pad records account for 18,300 bbl/d of the 2024 total, 4% under ST53 (records). D01 took first steam in June 2017 with one pair and two infills, D04 from September 2017 with nine wells and D05 eight infills in July 2018 (2025). D03 added one pair and seven infills in September 2020, and D02 four pairs and five infills in October 2021 (2025). The pad table counts 48 well pairs and 22 infills over six pads (2025). Recovery of each pad's own OBIP at 31 December 2024 is D03 70%, D01 68%, D05 64%, D04 44%, D02 39% and D08 5% (2025). The estimated ultimate ranges against the same denominator are 80-90% for D03, 70-80% for D01 and D05, 60-70% for D04 and D02 and 50-60% for D08 (2025). Over the twelve months to June 2026 D04 carried 4,400 bbl/d from 14 producing wells, 300 bbl/d each, and D02 3,100 bbl/d from 12, 300 bbl/d each (records; per-well is pad rate divided by producing wells). D08 made 2,700 bbl/d, D03 1,500 and D01 and D05 1,100 each, D05 at 100 bbl/d from each of 15 producers (records). D01-West, filed for first steam in Q4 2025, first produced in March 2026 and reached 6,000 bbl/d from eight producers in June 2026 (2025; records). Strathcona started NCG injection in August 2024 at up to 5.5 e3m3/d of gas with steam per well into high-recovery wells on Pads D01 to D05, leaving D08 out (2025).
4. CPF
Approved production capacity rose from 12,500 bbl/d at the Phase 1 CPF in August 2012 to 30,000 bbl/d in May 2016 and 40,000 bbl/d in June 2017 (2025). The 2025 deck shows current oil and steam capacity only as charts; no value is stated. Steam injection averaged 9,200 m3/d in 2024 (records). A separate Pilot CPF raises steam in once-through generators, and an OTSG addition there, titled "Addition of 103 KW OTSG", was approved on 6 November 2024 (2025). The main CPF's plot plan labels a "Boilers" block beside an evaporator train and two buildings "Cogens", and Pengrowth's scheme amendment 6410T for a cogeneration addition dates from September 2019 (2025, read from the page image; 2021). The 2024 work was a 96-inch sulphur recovery unit for an SO2 requirement, a produced-water disposal pump, a third strong acid cation vessel, a G4 burner in H-710 and removal of the HipVap unit (2025).
5. Reservoir
Lindbergh produces from the Lloydminster Formation at 500 m, with pay of 17 to 21 m, 34% porosity and 80% oil saturation on every row of the pad table (2025). Horizontal permeability is 2 to 6 Darcies at a Kv:Kh of 0.4 to 0.8, initial temperature 20 °C and initial pressure 2.7 MPa (2025). The bitumen is 10 to 11 °API at 14% average bitumen weight and 300,000 cP at 16 °C (2025). Strathcona's log cutoffs are a 50% sand gamma-ray cutoff, 24% density porosity in sandstone and 6 ohms (2025). OBIP is 23 MMm3 over the combined active well pattern, 66.15 MMm3 over the development area and 147.2 MMm3 over the project area (2025). Cumulative recovery of 9.31 MMm3 is the 41% the deck headlines, which is 41% of active-pattern OBIP, 14.1% of development-area OBIP and 6.3% of project-area OBIP (2025; arithmetic on the three stated volumes). A pay isopach and a basal water isopach are mapped for the Lloydminster, and the cross-section carries the footnote "No gas cap present" (2025). The 2025 deck does not state a caprock formation, a caprock thickness or a maximum operating pressure. Surface heave monitoring is not a condition of approval 6410 and was discontinued in 2014 after data confirmed heave was minimal under SAGD (2025). Seismic coverage is 55 2D lines totalling 338 km and 102 km2 of 3D; a third 4D monitor in March 2024 took 4D coverage from 1.32 km2 to 16 km2 (2025).
6. Future development plans
Strathcona's five-year plan covers 2025, 2026 and a single item in 2030 (2025). Planned for 2025 were three re-drill wells on Pad D04 and one on D01 at first steam in Q2, and the eight D01-West pairs at first steam in Q4 (2025). The Pilot CPF's OTSG expansion was to raise steam capacity in Q4 2025, and the main CPF's steam capacity increase is set against 2030 with no volume attached (2025). For 2026 the plan is additional re-drills, sub-producer drilling on existing pads and "Optimized NCG injection", with no counts given (2025). Future pad applications are D05-South and D01-Extension, both to be submitted in 2025, plus Pad D13 and D06-North with no submission year (2025).
7. Anything else
Strathcona quantifies the co-injection trade both ways: pad steam reductions of up to 20% and an iSOR reduction of up to 0.5 m3/m3 against more produced gas at a lower heating value that "decreases boiler burner efficiency" (2025). Its only well-integrity statement is the co-injection bullet "No wellbore integrity issues observed" (2025). The history line says seven D04 infills took first steam between January and March 2024, while the pad table gives D04 nine well pairs and no infills, so the deck's well roll-up is either 70 or 77 (2025). A pad labelled D04-6 is drawn on the pattern map east of D01 and appears in no table, history line or plan (2025). The 2025 filing has no cover date and empty metadata, and the cogeneration buildings, evaporators and boiler block appear only on the plot-plan images (2025). The lifespan chart carries an undated "SO2 Curtailment" annotation, and no non-compliance is disclosed (2025). Three remediated reportable incidents are disclosed for 2024: a sample station overfill, a drilling mud release and a pipeline flange leak remediated to Tier 1 (2025).
Orion, Strathcona Resources, OSCA 10103, SAGD, Cold Lake region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
BlackRock Ventures ran the Hilda Lake pilot from 1997 to 2006 under pilot approval 8093, and commercial approval 10103 was issued in January 2005 (2024). Shell Canada bought BlackRock, completing on 11 July 2006, merged the pilot and commercial approvals, and took first steam at the commercial CPF in August 2007 (2024; public). Osum completed its C$325 million purchase of Orion from Shell on 31 July 2014, and WEF closed the amalgamation of Osum into Strathcona on 11 June 2021 (public). The 2024 deck names each of those owners; the 2025 deck keeps the heading "Historic Project Ownership" and names only Strathcona (2024; 2025, read from the page image).
3. Well pair development
Orion had 152 wells on six pad clusters at June 2026, 74 of them producing, 62 injecting and one suspended (records). Oil averaged 20,700 bbl/d in 2024 at an SOR of 3.54, the same rate as 2023 at 3.41 and 2025 at 3.47 (records). The low point was 2022 at 15,800 bbl/d and 4.03, after 19,200 bbl/d at 2.86 in 2020, and January to May 2026 ran 22,300 bbl/d at 3.12 (records). The pad table lists 59 well pairs on the Pilot and twelve pads, started from September 1997 to August 2022, plus seven lower drainage wells on Pads 105 and 103 (2025, read from the page image). Recovery of pad OBIP at December 2024 runs from 83% at Pad 103 and 76% at 105 and the Pilot to 18% at 205, 14% at G5 and 9% for the lower drainage wells (2025, read from the page image). Our records group the wells into clusters that do not match the deck's pads (records). In the twelve months to June 2026 the largest, labelled P204, made 7,400 bbl/d from 17 producers and P001 7,200 bbl/d from 22, about 400 and 300 bbl/d a well (records; pad rate divided by producing wells). A third made 5,000 bbl/d from 18 producers, and the two smallest producing clusters 1,400 and 1,200 bbl/d (records). The P3 pilot pair's producer last recorded oil in September 2024, while its injector was still taking steam in May 2026 (records). In 2024 Strathcona re-drilled an injector at 204-13R, converted the existing injector there to a producer and put three new Pad 103 lower drainage wells on production in September (2025, read from the page image). It also won approval to re-drill 204-12I and 204-13P (2025, read from the page image). Four McLaren pairs on Pad G4 were drilled and completed for first steam in Q1 2025 (2025, read from the page image). Three steam injectors, 106-I4, 105-I3 and 107-I1, were downhole abandoned in 2024 for "casing integrity issues", after injector 107-2I in 2023 (2024; 2025, read from the page image). Rotoliptic and Mantl metal-to-metal progressing-cavity pumps were trialled in Q2 2024 (2025, read from the page image).
4. CPF
Approved average daily production is 3,975 m3/d, printed as 25,000 bbl/d (2024). The plot plan captions the steam block "Boilers", and the compliance tables call units H4100 and H4200 steam generators without naming a type (2024; 2025, read from the page image). The 2025 deck shows steam design throughput only as a chart; no value is stated. Steam injection averaged 11,700 m3/d in 2024 (records). Strathcona started the sulphur recovery unit in Q1 2024, had the reverse osmosis system under way at year end and started the Organic Rankine Cycle waste-heat unit (2025, read from the page image). An 11.4 MW glycol heater was replaced with a hot water boiler package under a joint application approved on 4 November 2024 (2025, read from the page image).
5. Reservoir
Orion produces from the Clearwater and the Upper Grand Rapids, whose productive member the deck calls the McLaren (2024). The Clearwater sits at 425 m with 16 to 25 m of pay, 34% porosity, 70% oil saturation, 2 to 6 D permeability at a Kv:Kh of 0.02 to 0.2, and 223,000 cP viscosity at 16 °C (2024). The Upper Grand Rapids sits at 330 m with 8 to 23 m of pay, 34% porosity, 76% oil saturation, 3 to 10 D at 0.3 to 0.6, and 65,000 cP (2024). Initial pressure is 3.2 MPa in the Clearwater and 2.2 to 2.5 MPa in the Upper Grand Rapids, at 15 °C in both (2024). Log cutoffs are 24% density porosity, 10 ohm-m resistivity and 50% sand on gamma ray (2024). OBIP is 27.5 MMm3 over the combined active well pattern and 69.9 MMm3 over the development area (2025, read from the page image). The project area was 129 MMm3 in the 2024 deck and 71.7 MMm3 in the 2025 deck; the difference is unexplained (2024; 2025, read from the page image). Cumulative recovery of 10.5 MMm3 is 38% of active-pattern OBIP and 14.6% of project-area OBIP (2025, read from the page image; arithmetic). Estimated ultimate recovery of pad OBIP is above 80% for Pads 103 and 105 and 70-80% for the Pilot, 104 and 107 (2025, read from the page image). It is 60-70% for 108, 109, 204, 206 and G5, 50-60% for 205, 40-50% for 106 and 20-40% for the lower drainage wells (2025, read from the page image). Gas caps are mapped in both reservoirs and a basal water isopach in the Clearwater only (2024). No seismically resolvable faults offset the Clearwater or UGR30 caprock, and no Devonian collapse structures have been observed (2024). The Moore Lake Channel, "up to 1000 m wide and approximately 40 m depth", does not incise either caprock (2024). Surface heave monitoring was discontinued in June 2015 (2024). Seismic runs from a 1.8 km2 Hilda 3D in 2005 to a 6.6 km2 Orion 4D in 2023 and three trade 2D lines in 2024 (2025, read from the page image).
6. Future development plans
Forty-five approved wells remain undrilled: five Clearwater pairs and ten lower drainage wells from existing pads, 20 Clearwater pairs from new Pads A and B, and ten Upper Grand Rapids pairs (2025, read from the page image). They sit under approvals 10103U, 10103V, 10103BB and 10103FF with no year attached, and "timing and number will depend on performance and declines of currently operating well pairs" (2024; 2025, read from the page image). The 2024 deck had counted 14 remaining Upper Grand Rapids pairs where the 2025 deck counts ten (2024; 2025, read from the page image). Strathcona proposes an undated transition of the Phase 1 pairs to "a terminal gas injection phase (no steam injection)" (2024). Two Directive 023 applications are named, a project-area expansion into Sections 8 and 9 and Clearwater pairs between drainage box 105/HLP and 107 (2025, read from the page image).
7. Anything else
Strathcona reports eleven exceedances of the 12.1 kg/hr hourly NOx limit on steam generator H4200 in April, July and September 2024, and one on H4100 on 6 October at 12.2 kg/hr (2025, read from the page image). It attributes them to the new sulphur unit raising fuel gas temperatures, and states that "Operations aggressively cut production to bring emissions under the limit" (2025, read from the page image). Five more contraventions cover NOx and SO2 analyser availability below 90% on H4200 and H4400, and one calibration-gas audit date is printed as September 17, 2025 inside the 2024 narrative (2025, read from the page image). Static charge on vented gas set skim tank T2001 on fire, its relief valve having been nickel coated in 2015, and a portable generator caught fire from mechanical failure (2025, read from the page image). Methane is co-injected into the Pilot and Pads 103, 105 and 107, 55 e6m3 in 2024 at 1.1 mol%, with about 70% of the injected gas recovered (2025, read from the page image). The 2025 deck has no text layer, and its figures here were read from the rendered pages. The deck states that "Orion had no active pilot programs or technical innovation programs in the reporting period" on one slide and reports the pump trial on another (2025, read from the page image). Its per-pad OBIP column sums to 29.49 MMm3 against the 27.5 MMm3 stated for the same active pattern (2025, read from the page image). The 2023 incidents were an off-site horizontal-drilling frac-out during the brackish water pipeline installation and a wastewater disposal pipeline failure (2024).
Tucker, Strathcona Resources, OSCA 9835, SAGD, Cold Lake region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Husky steamed Tucker from 20 August 2006 and took first production on 29 November 2006 (2021). Cenovus announced the close of its combination with Husky on 4 January 2021 and, on 16 December 2021, the sale of Tucker for $800 million (public). Cenovus filed the 2022 deck in its own name and records Tucker as divested on 31 January 2022, the day Strathcona "acquires administrative control" (2022; 2023). Eleven patterns started between 2006 and 2017, H East followed in 2023, and C South and the D-East lower drainage wells in 2024 (2024; 2025, read from the page image).
3. Well pair development
Tucker had 284 wells on fifteen pad clusters at June 2026: 127 producing, 80 injecting and 65 suspended (records). Oil averaged 19,700 bbl/d in 2024 at an SOR of 4.79, then 24,000 bbl/d at 3.64 in 2025 and 24,400 bbl/d at 3.99 over January to June 2026 (records). The earlier arc runs 23,700 bbl/d at 3.83 in 2019, 18,400 bbl/d at 4.04 in 2020, 19,600 bbl/d at 4.29 in 2022 and 18,400 bbl/d at 4.89 in 2023 (records). Husky curtailed production from April to June 2020 "due to low oil price" (2021). The 2025 pattern table lists 130 operating well pairs in fourteen rows, plus seven infills on the Colony (CN) pattern (2025, read from the page image). Recovery of each pattern's own OBIP at December 2024 was CN 80%, A 43%, GA 42%, C East and D East 41% each and D North 30% (2025, read from the page image). B stood at 22%, C West and D West 21% each, B North 20%, C North 7%, H East 4% and C South 0.1%.1% (2025, read from the page image). Every pattern gained one to five points over 2024: C North went from 6% to 7% and CN from 75% to 80% (2024; 2025, read from the page image). In the twelve months to June 2026 C South made 4,700 bbl/d and H 3,700 bbl/d, about 600 and 500 bbl/d from each of their eight producers (records; per-well is pad rate divided by producing wells). Of the legacy ground, which our records group into numbered clusters, P003 and P004 made 3,600 and 3,400 bbl/d from 19 and 18 producers (records). P002 made 2,300 bbl/d from 15 producers with 25 of its 48 wells suspended, and P001 2,100 bbl/d from 23 producers (records). Strathcona reactivated the last five suspended wellbores on C West in 2022, original wells "drilled lower in section" that conductive heating had brought to readiness, and extended the campaign in 2023 (2023; 2024). C South's eight pairs circulated from October 2024 and went to SAGD in December, and the D-East lower drainage wells, drilled in August, came on in December (2025, read from the page image). Two of those are fishbone multilaterals with total leg lengths of 3,397 and 3,276 m (2025, read from the page image).
4. CPF
Strathcona replaced the convection boxes on three of Tucker's six once-through generators in 2023, raising steam quality from 75% to 85% on those three (2024). It did "the remaining two" in 2024, with 85% quality then on four of six (2025, read from the page image). The decks show design oil and steam throughput only as charts; no value is stated (2021 to 2024; 2025, read from the page image). Steam injection averaged 15,000 m3/d in 2024 (records). A temporary sulphur removal unit went in at the central field separation facility in 2023 and a permanent one with a booster compressor at the CPF in 2024 (2024; 2025, read from the page image). Husky took a plant turnaround in September and October 2020 (2021), and the 2022 compliance table names generators B-7300 and B-7800, whose emissions monitors missed the 90% uptime requirement (2023).
5. Reservoir
Tucker produces from the Clearwater at 470 m with 33.7 m of pay, 34% porosity and 66% oil saturation (2024). The Lower Grand Rapids Sparky sits at 390 m with 27.4 m, 34% and 67%, and the Upper Grand Rapids Colony at 320 m with 12.9 m, 33% and 80% (2024). Strathcona has restated OBIP in each of its filings: the project area at 98, 143 and 91 MMm3 and the combined active patterns at 38.1, 46.7 and 53 MMm3 (2023; 2024; 2025, read from the page image). The 2025 figures are footnoted "Volumes in table are 2P (proved + probable)" (2025, read from the page image). Cumulative recovery was stated as 17.9 MMm3 or 47.1% (2023), then 13.1 MMm3 or 28% (2024); the fall between the two filings is unexplained. The 2025 figure, 14.3 MMm3, is 27% of active-pattern OBIP and 15.7% of project-area OBIP (2025, read from the page image; arithmetic). Estimated ultimate recovery of each pattern's OBIP is above 90% for CN and 50-60% for A, C East, D East, GA and H East (2025, read from the page image). It is 40-50% for D West, D North and C South, 30-40% for B and C West, and 20-30% for B North (2025, read from the page image). C North's four 710 m pairs sit on 1.2 MMm3 of OBIP, and Strathcona booked the pattern at 10% ultimate recovery (2023; 2024), then 10-20% (2025, read from the page image). Caprock shale sits at 305 m over CN, 357 m over GA and 426 m over the main pads, with fracture gradients of 20.0, 19.9 and 21.8 kPa/m, all horizontal (2024). Top gas is labelled on the Clearwater and Colony sections, basal water is mapped under the Clearwater and Sparky, and the B/C Valley and D Valley incisions cut the Clearwater (2024). At observation well 103/02-28, inside an active drainage area, the temperature below the caprock is "nearing 110ºC" (2025, read from the page image). Strathcona gives 110 °C as the cement-disintegration temperature for non-thermal wells, and the well being guarded sits 150 m east of the drainage area (2025, read from the page image). Surface heave monitoring is not an approval condition and "has not been implemented since Project initiation" (2024). Seismic covers 27.5 km2 of 3D and 15.77 km2 of 4D, with five monitor surveys from March 2010 to January 2022 (2024).
6. Future development plans
Strathcona heads its plan "Planned Activity (Timing & #WP's subject to change)" (2025, read from the page image). For 2025 it lists a winter delineation program, a full-field NCG injection compressor, blowdown of the Colony pad, and debottleneck scoping at the CPF and field separation facility (2025, read from the page image). For 2026 it lists start-up of seven lower drainage wells on C East and eight on A, plus a 4D seismic acquisition (2025, read from the page image). For 2027 to 2030 it lists Pad F with ten wells, a D-West subproducer group of eight wells, and D-North stepouts and lower drainage wells totalling four pairs and two wells (2025, read from the page image). Future applications are an Organic Rankine Cycle waste-heat project and Directive 023 amendments for Pad F, a "Tucker Brownfield Optimization" of lower drainage wells, infills and subproducers, and the D-North stepouts (2025, read from the page image).
7. Anything else
Husky started methane co-injection at D32S, D34S and D36S in November 2020 (2021), and Strathcona halted it on 15 February 2022 "to try and remove excess gas from chambers" (2023). Methane went into Colony wells 2, 4, 6, 8, 10 and 12 from August 2023, when CN had recovered about 72% of its OBIP (2024). In 2024 Strathcona injected 37,029 e3sm3, at 6.9 mol% on CN and 0.3 mol% on three C East, three D East and six A wells, and recovered about 87% of the Colony methane (2025, read from the page image). On the other three pads it reports "C1/CO2 ratio decreased after commencing NCGi, indicating no NCG recovery" (2025, read from the page image). In 2023 Strathcona abandoned two observation wells, one with a production casing leak near surface found on a pressure test and one whose casing proved impaired during saturation logging (2024). The 2025 filing is built from Type 3 fonts with no usable text layer, so its figures here were read from the rendered pages. Two unit headers are wrong in every Strathcona vintage (2023; 2024; 2025, read from the page image). Reservoir pressure is headed MPa over kPa values of 3,200, 2,600 and 2,400, and horizontal permeability Darcies over millidarcy values of 4,400, 1,800 and 4,500 (2024). Reportable incidents were a frozen steam drain line in December 2021 (2022) and emulsion releases at wells A5 in 2022 and CN10P in 2023, the latter year also bringing a disposal pipeline failure (2023; 2024). In 2024 there were two fuel gas leaks from externally corroded above-ground pipeline (2025, read from the page image).
Hangingstone, Athabasca Oil Corporation, OSCA 11888, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026. Two other schemes in this document are called Hangingstone, Greenfire's 8788 and Greenfire's Hangingstone Expansion 11910; this is Athabasca Oil's, 20 km south of Fort McMurray.
2. Project history
Athabasca Oil took first steam at Hangingstone in March 2015, and its five pads came on production between 23 March and 7 April 2015 (2025; records); the filings name no other operator. The production chart carries seven undated callouts (2025). They mark a wildfire outage, a curtailment for price differentials, a temporary suspension for market conditions, NCG co-injection start, a toe NCG trial, scheduled maintenance and Pad AA expansion circulation (2025). The two pairs drilled in 2024 were the first drilled at Hangingstone since 2014 (2025).
3. Well pair development
Hangingstone had 54 wells on five pads at June 2026, 27 producing and 27 injecting, with none suspended or abandoned (records). Athabasca Oil counts the same 27 pairs, five on each of Pads AA, AB, AC, AD and AE plus two on the Pad AA expansion (2025). Oil averaged 7,400 bbl/d in 2024 at an SOR of 3.38, the 3.4 the deck calls its lowest annual SOR (records; 2025). The scheme made 8,500 bbl/d at 4.67 in 2019, 4,500 bbl/d at 4.77 in 2020 and 8,900 bbl/d at 3.79 in 2022 (records). It reached 8,500 bbl/d at 3.46 in 2025 and 9,000 bbl/d at 3.43 over January to May 2026 (records). Lateral lengths are 850 m at AA, 640 at AB, 750 at AC, 670 at AD and 830 at AE (2025). Recovery of each pad's GBIP at 31 December 2024 is AB 43%, AD 28%, AA 26%, AE 24%, AC 20%, the expansion pairs zero, and 26% across all six rows (2025). AB and AC carry five pairs each on near-identical reservoir properties, and the deck gives no reason for their 43% and 20% (2025). Over the twelve months to June 2026 Pad AA carried 3,500 bbl/d from seven producers, about 500 bbl/d each, and AD 1,900 bbl/d from five, about 400 each (records; per-well is pad rate divided by producing wells). AB, AE and AC made 1,200, 1,200 and 1,100 bbl/d, about 200 bbl/d from each producer (records). The two 2024 wells are extended-reach pairs on Pad AA of about 1,400 m, completed with liner-deployed flow control devices, circulated from Q4 2024 and on production in Q1 2025 (2025). Athabasca Oil reports IP90 rates of about 130 to 150 m3/d per well, which it converts to 820 to 950 bbl/d (2025).
4. CPF
The 2025 deck does not state the steam generation type. It shows oil and steam design throughput only as chart lines; no capacity value is stated (2025). Steam injection averaged 3,982 m3/d in 2024 (records). The one surface image is a satellite photo labelling the CPF, a substation, a laydown area, a borrow pit, a utility corridor to the pads and the road to Highway 63 (2025). Fuel gas comes from TransCanada, dilbit goes to the Enbridge Cheecham Terminal and diluent comes from Inter Pipeline (2025). Athabasca Oil made no CPF modifications in 2024 that required an AER application, and the only maintenance evidence is the undated "SCHEDULED MAINTENANCE" callout (2025).
5. Reservoir
Hangingstone produces from the McMurray at a typical producer depth of 191 m TVD, 258 m above sea level (2025). Initial reservoir pressure is 600 kPaa at 190 m TVD, initial temperature 8 °C and bitumen viscosity above 1 million cP at that temperature (2025). The in-place basis is GBIP, defined on the slide as "gross oil volume between base and top of pay inclusive of Lean Zone without saturation constraint" (2025). Reservoir criteria are facies F1 to F4 plus less than 1 m of F5, total porosity of 27% or more and total water saturation of 50% or less (2025). Per-pad net pay runs 19.3 to 29.4 m, porosity 0.34 to 0.36, oil saturation 0.71 to 0.75, horizontal permeability 4.5 to 5.3 D and vertical 2.9 to 3.7 D (2025). Pad GBIP totals 16.8 e6m3 over 2,327 e3m2 of pattern area, against 22.9 e6m3 over the 7.3 km2 development area and 23 e6m3 over the 7.81 km2 project area (2025). The 4.3 e6m3 produced is 26% of pad GBIP and 19% of development-area GBIP (2025; arithmetic on the stated volumes). Estimated ultimate recovery is a single 50-70% band of GBIP for all six pad rows, including the two 2024 wells (2025). Bottom water is "Localized and not in direct contact with bitumen; separated by MIHS and/or basal mud" (2025). Top gas is mapped in the middle McMurray with minimal thickness and limited distribution within the development area, and the lean zone sits inside the GBIP volume rather than being mapped (2025). One caprock core was taken across the project area, and the deck carries no caprock thickness or maximum operating pressure value (2025). Data density is 33 McMurray cored wells and 35 image logs, with cross-section GBIP thicknesses of 24.1 to 44.2 m (2025). The 3D was shot in 2011 and 2012 and merged to about 98 km2, the 2D totals about 450 km, and 3.72 km2 of 4D was last acquired in 2015 to 2017 (2025).
6. Future development plans
Athabasca Oil planned two observation wells and a 4D seismic acquisition for Q1 2025 (2025). It will continue developing the AG drainage area "in accordance with production decline" and will file a surface disposition application for Pad AG (2025). Two well pairs are proposed for 2027 drilling with two more to follow (2025). Application 1952251, a Directive 023 Category 3 filed on 14 June 2024, sought expansion of the project and development areas and twelve added drainage areas, and the AER approved it in June 2025 (2025). Well patterns on the east side are being evaluated for development after Pad AG (2025).
7. Anything else
NCG co-injection started in Q4 2020 and now runs on all pads for pressure management and SOR reduction, with "no wellbore integrity issues" reported (2025). The AER approved two temporary increases of the reservoir maximum operating pressure in 2024, application 1951916 on 15 May and application 1955919 on 25 November, and the deck quantifies neither the increases nor the base MOP (2025). Innovation is limited to extended-reach laterals in shallow reservoirs, steam splitters and flow control devices on new pairs and an evaluation of re-drills, with "No immediate plan for future pilots" (2025). The copy in this corpus is a Foxit re-print created on 17 November 2025 behind a JUNE 2025 cover (2025). Athabasca Oil reports no non-compliance and no reportable spills for 2024, and three AER inspections with no unsatisfactory findings (2025).
Leismer, Athabasca Oil Corporation, OSCA 10935, SAGD, Athabasca region, Alberta.
Decks: 2022, 2023, 2024, 2025 (bare years below); no 2021 filing for this scheme in the corpus; records to June 2026.
2. Project history
Statoil, which entered the Kai Kos Dehseh leases by buying North American Oil Sands Corporation in 2007, took first steam at Leismer in September 2010 and first oil on 27 January 2011 (2025; public). Athabasca Oil closed its purchase of Leismer, the Corner lease and regional infrastructure from Statoil on 31 January 2017 for $431 million cash and 100 million shares (public). The production chart carries three undated annotations: third-party outages and wildfires, maintenance and a turnaround, and the start of NCG for pressure and SOR management (2025). Athabasca Oil sanctioned a flexible progressive expansion to 40,000 bbl/d in 2024 and reached about 28,000 bbl/d in June of that year (2025).
3. Well pair development
Leismer had 136 wells on nine pads at June 2026, 69 producing, 58 injecting and 9 suspended (records). The deck gives nine drainage areas with 58 well pairs, 21 infills and 9 re-drills in its inventory, and eight producing areas in 2024 with 54 pairs, 21 infills and 3 re-drills (2025). Oil averaged 26,100 bbl/d in 2024 at an SOR of 3.28, up from 17,600 bbl/d at 3.88 in 2019, 20,100 bbl/d at 2.93 in 2022 and 22,500 bbl/d at 3.14 in 2023 (records). 2025 rose to 27,400 bbl/d at 3.14, and January to May 2026 fell to 22,200 bbl/d at 3.33 (records). Recovery of each drainage area's GBIP at 31 December 2024 is L2 65%, L1 64%, L3 58%, L4 50%, L5 43%, L6 42%, L7 40%, L8 16%, L10 South zero and 38% over all nine rows (2025). Over the twelve months to June 2026 L8 carried 12,500 bbl/d from 14 producers, about 900 bbl/d each, and L10 3,200 bbl/d from four, about 800 each (records; per-well is pad rate divided by producing wells). L7 made 2,900 bbl/d from ten producers (records). The first four pads made 700 bbl/d at L1 from ten producers, 400 at L4, 360 at L2 and 180 bbl/d at L3 from five (records). Athabasca Oil started three L4 re-drills with about 650 m laterals in Q2 2024 and four L8 pairs in Q3, and drilled four L10 pairs and five observation wells (2025). It also drilled six extended-reach re-drills of up to about 1,600 m from the L1 surface facilities into the L1, L3 and L4 drainage boxes (2025). They target "up to 9 m of by-passed pay" left by original producers placed with higher standoff to bottom water (2025). The six came on in Q1 2025 at IP90 rates of about 60 to 150 m3/d, 375 to 950 bbl/d, and Athabasca Oil "Did not steam the wells due to elevated temperatures" (2025). Wells L1N5 and L4P5 were suspended in 2024 for flow instability (2025).
4. CPF
Approved processing capacity is 40,000 bbl/d; the 2025 deck shows steam capacity only as a chart line, and no value is stated (2025). Steam comes from once-through generators: EPEA approval 241311 of 22 April 2024 is to "Modify capacity and emissions for two OTSGs", and the plot plan labels OTSG 6 and OTSG 7 (2025). Steam injection averaged 13,600 m3/d in 2024 (records). Feedwater is softened by weak-acid-cation primary and polisher vessels, and disposal runs under Class 1B approval 11479D into two Basal McMurray and three Clearwater B wells (2025). A sulphur removal unit design was approved on 1 October 2024 with an SO2 emissions rate increase during installation (2025). Athabasca Oil took no turnaround in 2024; fuel gas comes from TransCanada and dilbit and diluent move through the Enbridge Cheecham Terminal (2025).
5. Reservoir
Leismer produces from the McMurray at 390 to 487 m TVD, at an initial reservoir pressure of 2,300 to 2,600 kPa and an initial temperature of 14 °C (2025). The 2025 deck does not state a bitumen viscosity or density. The in-place basis is GBIP, gross bitumen in place at total porosity of 27% or more and total water saturation of 50% or less, without the lean-zone clause Athabasca Oil's Hangingstone footnote carries (2025). Per-area porosity is 0.33 to 0.35, oil saturation 0.80 to 0.84, horizontal permeability 4.7 to 6.6 D, vertical 3.4 to 5.2 D and net pay 18.6 to 35.3 m (2025). Pad GBIP totals 39.7 e6m3 over 5,348 e3m2, with 15.1 e6m3 produced (2025). Whole-area volumes are about 140 e6m3 over the 38 e6m2 development area and about 340 e6m3 over the 262 e6m2 project area (2025). Estimated ultimate recovery, defined as recovery "of Producible Bitumen within GBIP", is 65-75% for L1, L2, L5, L6 and L7 and 55-65% for L3, L4, L8 and L10 South (2025). The deck's remark that "Pad 1 and 4 recovery factors are greater than 50%" is on the GBIP basis, a recovery factor it defines as "The ratio of recoverable bitumen reserves to GBIP" (2025). Bottom water is mapped at a 5 m contour interval with no text on the slide (2025). Athabasca Oil states that "GAS IS WITHIN THE MCMURRAY, BUT NOT IN DIRECT CONTACT WITH THE GBIP RESERVOIR INTERVAL" (2025). The 2025 deck does not state a caprock formation, thickness or maximum operating pressure. Data density is 164 cored wells and 271 image logs over the 38 km2 development area (2025). The last 4D was 7.1 km2 over L1 to L6 in 2020 and 2.7 km2 over L7 and L9 in 2022 (2025).
6. Future development plans
Athabasca Oil is raising oil capacity to 40,000 bbl/d through CPF modifications and new drainage areas over 2024 to 2027 (2025). For 2025 it planned to bring the four L10 wells on in the second half and spud five observation wells and six pairs at L11 (2025). It also planned the L10 looping pipeline, the L11 corridor and pad, and 4D over L8 (2025). Three suspensions were planned for 2025, L2P7, L6P3 and L6P5 (2025). Approved but undrilled inventory is 41 well pairs, four at L9, eleven at L10, ten at L11, nine at L12 and seven at L13 (2025). L10 first produced in June 2025, matching the filed second-half target (records).
7. Anything else
NCG co-injection "is applied in mature areas for pressure support when additional heat is not required", and Athabasca Oil states that "Without NCG co-injection, SOR would be considerably higher" (2025). It started on L1 to L4 in 2019, L5 and L6 in 2021 and L7 in 2024, and winter surface limits constrain it (2025). Four compliance events are reported for 2024: a one-hour NOx exceedance on steam generator 4, an exceeded water diversion daily limit, and a well control event that cost a polish rod and a wellhead valve (2025). The fourth, separated surface casing cement on injector L3I5, was repaired within 90 days under an AER-approved Directive 087 plan (2025). L9 appears in the approved inventory and the 2022 seismic entry but has no recovery row and no 2024 activity (2025). L8 is four pairs started in Q3 on one slide, four L8S pairs converted to production on another, and a single fourteen-pair row in the table (2025). The copy in this corpus was created on 3 December 2025 behind a JUNE 2025 cover (2025). The AER completed eight inspections in 2024 with one low-risk finding, and no reportable spills occurred (2025).
Hangingstone Demonstration, Greenfire Resources, OSCA 8788, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2024, 2025 (bare years below); no 2023 filing on the AER index; records to June 2026. This is the demonstration scheme 60 km south of Fort McMurray, not Athabasca Oil's Hangingstone 11888 and not Greenfire's Hangingstone Expansion 11910.
2. Project history
Japan Canada Oil Sands, a JAPEX subsidiary, started SAGD pilot production here in 1999, and Greenfire dates the project "in operation since 1999" with an approved capacity of 1,760 m3/d (public; 2025). JACOS agreed on 4 April 2018 to sell the demonstration area's wells and facilities to Greenfire Hangingstone Operating Corporation, whose oil sands assets Greenfire Acquisition Corporation announced it had acquired on 6 April 2021 (public). Greenfire's operating history gives operation to May 2016, voluntary suspension to September 2018, operation to April 2020, a second suspension from May to December 2020, and production again from March 2021 (2025). Our records also carry fourteen Petro-Canada wells in the same footprint, first on production in June 1990 and all abandoned in 1997 and 1998 (records).
3. Well pair development
Hangingstone 8788 had 64 wells across nine clusters at June 2026, 15 producing, 23 injecting, three suspended and eighteen abandoned (records). Oil averaged 3,000 bbl/d in 2024 at an SOR of 6.83, against 3,700 bbl/d at 6.25 in 2022 and 3,800 bbl/d at 6.30 in 2023 (records). It rose to 5,400 bbl/d at 4.62 in 2025 and 5,900 bbl/d at 4.16 over January to May 2026 (records). The well-level records account for 2,100 bbl/d of the 2024 total, 28% under ST53, and for under half of 2025; the shortfall is in Petrinex itself and its cause is open (records). Greenfire's pattern table runs six pads named by their well letters, Pad 1 ABM, Pad 2 CDE, Pad 3 HIJKLN, Pad 4 OPQZ, Pad 5 RSTUVW and Pad 6 XY (2025). Recovery of each pad's OBIP is Pad 3 66.5%, Pad 1 60.6%, Pad 2 46.0%, Pad 4 42.4%, Pad 5 27.0% and Pad 6 13.4%, with the operating area at 44.8% (2025). Against producible bitumen in place the same pads read 75.4%, 69.9%, 53.0%, 46.5%, 29.4% and 16.1% (2025). The deck states that "There were no suspensions or abandonments of production wells or patterns for the reporting period" (2025). Our well records show no bitumen from Pad 1 in 2024 and none from Pad 6 between January 2022 and January 2026, zeros the Petrinex shortfall leaves unconfirmed (records). Pad 6's X and Y pairs were re-drilled and came on production in February 2026 (records). Greenfire continued a refill and re-drill programme at Pad 5 for producers U, V and W under email approval (2025). Over the twelve months to June 2026 the largest cluster in our records carried 1,300 bbl/d from two producers (records).
4. CPF
Licensed nameplate is 1,760 m3/d of oil, and steam design is 4,919 tonnes/day at 80% quality (2025). The 2024 average of 3,000 bbl/d in section 3 is 470 m3/d, 27% of nameplate (records; arithmetic). The 2025 deck does not state the steam generation type. The one modification completed in 2024 was the tie-in of a second on-site disposal well (2025). Greenfire lists as a success that it "Maintained partial operations during a plant turnaround", and its bitumen chart footnotes a partial plant outage in October 2024 (2025). Evaporator blower mechanical issues and disposal well plugging are the two facility challenges disclosed, both marked as working on resolution (2025).
5. Reservoir
Hangingstone 8788 produces from the McMurray on net pay criteria of gamma ray below 60 API, porosity above 27%, resistivity above 20 ohm-m for oil saturation above 50%, shale volume below 30% and muds under 1 m (2025). Greenfire computes OBIP as rock volume times porosity times one minus initial water saturation times a formation volume factor of 1.001 (2025). Reservoir parameters are a single set for the project: oil saturation 85%, porosity 30%, average SAGD pay 24 m, vertical permeability 5,132 mD and horizontal 5,774 mD (2025). OBIP is 14.9 e6m3 over the operating area and 27.0 e6m3 over the development and project areas, which the scheme approval defines as the same area (2025). Cumulative production of 6.7 e6m3 is 44.9% of operating-area OBIP and 24.8% of development-area OBIP (2025). Estimated ultimate recovery of OBIP is 75-85% for Pads 1 and 3, 70-80% for Pad 2 and the operating area, 65-75% for Pads 4 and 5 and 60-70% for Pad 6 (2025). The 2025 deck does not state a reservoir depth, initial pressure, initial temperature or bitumen viscosity. Greenfire reports no change in its caprock integrity analysis since August 2018, with original injection pressures set by mini-frac tests in the 1980s (2025). It cites mini-frac tests at its Hangingstone Expansion about 3 km away in 2010, and monitors reservoir pressure through blanket gas readings in the casing annulus (2025).
6. Future development plans
Greenfire states that "There are no major development programs planned in 2025" (2025). Its one 2025 item is an evaluation of CPF and well pad "debottlenecking opportunities that could improve the overall performance of the scheme" (2025). The five-year plan is a single statement that Greenfire is "evaluating various development strategies over the next five years", with no wells, volumes or dates attached (2025).
7. Anything else
The project is approved for full-field co-injection of pipeline fuel gas at up to 50 mole percent with steam, and averaged 6,010 m3/d of NCG in 2024, 2,193,800 m3 for the year (2025). The largest per-well rates were well R at 1,168 m3/d, U at 1,048, V at 830 and M at 713, the last on Pad 1 with 260,082 m3 cumulative for the year (2025). Wells X and Y on Pad 6 and N on Pad 3 show zero injection (2025). Greenfire's production exhibits are field aggregates, with no per-pad rate plot (2025). Two regulatory approvals amend Directive 065 disposal scheme 13122, application 1950248 adding a Class Ib disposal well and application 1953890 updating the Grand Rapids monitoring plan (2025). One reportable incident is disclosed for 2024, an on-lease spill under FIS 20242934, fully cleaned up (2025).
Hangingstone Expansion, Greenfire Resources, OSCA 11910, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2024, 2025 (bare years below); no 2023 filing on the AER index; records to June 2026. Our pad records do not cover approval 11910, so the rates below are ST53 scheme totals and no per-pad rate appears.
2. Project history
Japan Canada Oil Sands operated the Hangingstone Expansion with 75%, alongside CNOOC International with 25%, and took first steam in April 2017 and first bitumen in August 2017 (2021). Greenfire Acquisition Corporation announced on 20 September 2021 that it had closed its purchase of JACOS, including the 75% interest and operatorship, and renamed the operating company Greenfire Resources Operating Corporation (public). The approved capacity is 4,800 m3/d, which the deck prints as about 30,000 bbl/d (2025). The project sits about 65 km south of Fort McMurray, apart from Athabasca Oil's Hangingstone at 20 km and Greenfire's demonstration scheme at 60 km (2025).
3. Well pair development
The well list carries 74 wells under approval 11910, 55 with crude bitumen status and ten observation wells (records). Oil averaged 21,800 bbl/d in 2024 at an SOR of 3.33, against 26,000 bbl/d at 2.41 in 2019, 22,400 bbl/d at 3.01 in 2022 and 18,400 bbl/d at 3.72 in 2023 (records). It fell to 14,300 bbl/d at 4.15 in 2025 and 10,800 bbl/d at 5.71 over January to May 2026 (records). The 2025 deck does not state an SOR value. Greenfire's location map shows Pads 1 to 7 plus BP1 and BP2, and its pattern table has three rows, one lumping Pads 1, 2, 4 and 5 and one each for Pads 3 and 6 (2025). Recovery of each row's OBIP is 66% for Pads 1, 2, 4 and 5 together, 21% for Pad 3 and 38% for Pad 6, and against producible bitumen in place 69%, 23% and 41% (2025). Estimated ultimate recovery of OBIP is banded at 70-80%, 55-65% and 60-70% for the same rows (2025). Pattern areas are 445,154 m2 for the four lumped pads, 295,421 m2 for Pad 3 and 254,952 m2 for Pad 6, with average net pay of 21.5, 17.5 and 30.6 m (2025). A producer re-drill was carried out at Pads 1 and 4 under email approval, with no count, length or rate given (2025). Greenfire reports no suspensions, abandonments or patterns in blowdown for 2024 (2025).
4. CPF
Licensed nameplate is 4,800 m3/d of oil, and steam design is 11,440 tonnes/day at 80% quality (2025). The 2024 average in section 3 is 3,460 m3/d, 72% of nameplate (records; arithmetic). Greenfire lists as a success that it "Used mixed gas as a fuel source at all four Once Through Steam Generators", one of which lost steam output to back pressure in its convection box (2025). The plant took a turnaround in September and October 2024 with partial operations maintained (2025). A second source water well, a quench water pipeline from the CPF to Pad 2 and a second on-site disposal well under scheme 13122 were completed in 2024 (2025). Greenfire lists an "Overall shortage of cooling at CPF" among its challenges, and drilled the supply and return wells of a Pad 5 open-loop ground-source cooling system that was "not operational during the reporting period" (2025).
5. Reservoir
The Hangingstone Expansion produces from the McMurray on net pay criteria of gamma ray below 60 API, porosity above 27%, resistivity above 20 ohm-m for oil saturation above 50%, shale volume below 30% and muds under 1 m (2025). One parameter set covers the project: oil saturation 81%, porosity 33%, average SAGD pay 22 m, vertical permeability 4,050 mD and horizontal 5,800 mD (2025). OBIP is 15.5 e6m3 over the operating area, 64.7 e6m3 over the development area and 248.0 e6m3 over the project area (2025). Cumulative production of 9.0 e6m3 is 57.9% of operating-area OBIP, 13.9% of development-area OBIP and 3.6% of project-area OBIP (2025). The 2025 deck does not state a reservoir depth, initial pressure, initial temperature, bitumen viscosity, caprock or maximum operating pressure. It does not mention top gas, top water, bottom water or lean zones (2025). Greenfire derives its injection pressure limit from mini-frac tests in the 1980s confirmed by 2010 testing, and monitors reservoir pressure through blanket gas readings in the casing annulus (2025).
6. Future development plans
The 2025 list is CPF and well pad debottlenecking, operation of the second disposal well, a sulphur removal unit, development of Pad 7 and a winter delineation program for sustaining pads (2025). Sustaining Pad 9 was added by application 1952178 and updated by application 1955763 (2025). The five-year plan is a single statement that Greenfire is "evaluating various development strategies over the next five years", with no wells, volumes or dates (2025). The infrastructure map of future pads is the previous operator's, and Greenfire "is evaluating these plans and may adjust them if deemed necessary" (2025).
7. Anything else
That inherited map names pads W01 to W26, with W09 absent, plus BE-North, BE-South and B1, while Greenfire's operating names are Pad 1 to Pad 7, BP1 and BP2, and the deck does not reconcile the two (2025). The project is approved for full-field co-injection of pipeline fuel gas up to 25 e3m3/d per well, and averaged 374 e3m3/d in 2024 (2025). Average injection by well was 18.6 e3m3/d on Pad 5, 15.8 on Pad 1, 9.2 on Pad 4, 9.0 on Pad 6, 6.1 on Pad 3 and 4.6 on Pad 2 (2025). Greenfire intends to continue co-injection "pending market conditions" (2025). Four of five AER reportable items for 2024 are measurement or monitoring failures: missed CEMS drift checks, a software fault and low operating hours on the B-525 CEMS unit, and a data download failure at groundwater well DQ05-05 (2025). The pattern table's three rows sum to 995,527 m2 against a printed operating area of 2,606,175 m2, while its OBIP column sums to the printed total (2025). The fifth reportable item is containment: the process pond primary liner exceeded its allowable leakage rate, with the secondary liner intact and no loss of containment (2025).
McKay River Thermal Project, Greenfire Resources, OSCA 11461, SAGD, Athabasca region, Alberta; permanently ceased.
Decks: 2021, 2022, 2025 (bare years below); no 2023 or 2024 filing on the AER index; records to June 2026. The 2022 deck is Everest Canadian Resources' 67-page report on performance year 2021 and is the only substantive source on this project; the 2025 filing is four pages confirming cessation.
2. Project history
The AER approved the project in November 2010 and Southern Pacific Resources built and operated it as STP-McKay (2022). Southern Pacific was granted protection under the CCAA in January 2015 and entered receivership in June 2015; production was shut in and the receiver completed a warm-hibernation program by August 2015 (2022). The project was transferred to Everest Canadian Resources in February 2019 and Greenfire acquired it in Q1 2024 (2022; 2025). Greenfire received AER approval to permanently cease operations at the project on 20 November 2024 under application 1954124 (2025).
3. Well pair development
Production stopped in February 2023 and both pads have been at zero since; all 22 wells on Pads 101 and 102 carry a suspended status at June 2026 (records). The project made 1,700 bbl/d in 2022 and 1,300 bbl/d over January and February 2023, at SORs of 7.79 and 7.68 (records). Everest reported twelve well pairs drilled and eleven producing, five on Pad 101 at 800 to 825 m and six on Pad 102 at about 1,000 to 1,100 m (2022). Its monthly chart ran bitumen from 159 to 245 m3/d, with instantaneous SOR between 6.3 and 19.4 and cumulative SOR falling from 11.0 to 9.2 (2022). The 2025 filing states that the project "has permanently ceased operations" and that there are no updates to subsurface development or resource production aspects.
4. CPF
Steam came from a steam drum boiler and a heat-recovery steam generator on a cogeneration unit, named on the facility schematic, and it is the only drum boiler named anywhere in this corpus (2022). Water treatment was falling film evaporators feeding an evaporator feed tank from the raw water and produced water tanks, housed in an evaporator and crystallizer building beside separate steam generation, cogeneration and glycol buildings (2022). Process facility capacity was 12,000 bbl/d of oil and 37,400 bbl/d of steam (2022). The 2025 filing states that there are no updates to surface development aspects.
5. Reservoir
The reservoir was the McMurray under a Clearwater shale caprock, with a Wabiskaw sand and shale between, and the named risk was the Basal Unit non-pay facies under Pad 101 (2022). Approval area OBIP was 92.1 x 10^6 m3 over 10.5 sections, or 27 km2, and the two operating pads held 6,016 e3m3 of OBIP against 233 e3m3 produced by the end of 2021 (2022). The AER approved a maximum operating pressure of 2,450 kPa in 2011, against a minimum horizontal stress at the base of the Clearwater caprock of about 2,860 to 3,020 kPa from mini-fracs at two wells (2022).
6. Future development plans
The forward plan is decommissioning. Greenfire submitted a Decommissioning and Land Reclamation Plan as an EPEA amendment application on 20 May 2025 after the AER directed it to do so (2025).
7. Anything else
The 2025 filing states that "There have been no operational changes to the Project as it ceased operating in 2022" (2025). Our records show about 98,500 m3 of bitumen produced in 2022 and production into February 2023 (records). Greenfire has identified 24 wells with Directive 013 compliance requirements, 22 low risk and 2 medium risk (2025). There were no wellhead integrity failures and no non-compliances in 2024 because the project did not operate (2025). The EPEA approval number is inconsistent inside the four-page filing, 255145-01-01 on the cover against 255245-01-01 in the body, and Everest's filings support 255245 as the root (2025; 2022). Greenfire cites the scheme as 11461K where Everest cites bare 11461 (2025; 2022). The Everest deck, created on 2 February 2023, still describes ramp-up "throughout 2021" and twelve future infill wells on Pads 101 and 102 (2022). Everest reported its own well-pair count four ways in one deck, twelve drilled on the completions slide, eleven producing on the volumetrics and rate slides, and twelve on the facility schematic (2022). Everest also disclosed two reportable releases in July 2021 and eight distinct contraventions (2022). They cover missing signage, unlocked groundwater monitoring wells and no ambient air quality station until 1 October 2021 (2022). The rest are non-functioning test-separator flow meters, no flare or vent logs and missed tank inspections (2022). Everest stated that production was prorated from bulk scheme production using intermittent test-separator data, so its per-well rates were allocations (2022). Everest did not conduct heave or other surface monitoring for 2021 and reported 2012 to 2015 corner-reflector results instead (2022).
Long Lake and Kinosis, CNOOC Petroleum North America, OSCA 9485, SAGD with an upgrader, Athabasca region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026. Kinosis is a development area inside approval 9485, not a separate scheme.
2. Project history
Commercial approvals came in 2003, a SAGD pilot ran from 2003 to 2007, and commercial bitumen production started in 2007, with the upgrader following in 2009 (2025). Nexen bought a further 15% from partner OPTI Canada on 27 January 2009 to hold 65% as sole operator (public). CNOOC completed its purchase of OPTI and its 35% in November 2011, and of Nexen on 25 February 2013; the operator now files as CNOOC Petroleum North America, "formerly Nexen Energy ULC" (public; 2025). A 2015 pipeline leak ceased production at Kinosis K1A, and in 2016 a hydrocracker incident and a wildfire shut Long Lake for about two months (2025).
3. Well pair development
Long Lake had 426 wells on 31 pads at June 2026, 222 producing, 196 injecting and six suspended (records). Oil averaged 71,900 bbl/d in 2024 at an SOR of 2.96, against 46,300 bbl/d at 2.77 in 2019, 31,600 bbl/d at 2.91 in 2020 and 47,600 bbl/d at 3.04 in 2022 (records). It rose to 75,400 bbl/d at 3.07 in 2025 and 77,100 bbl/d at 3.28 over January to May 2026 (records). Design SORs are 3.3 for the Long Lake facility and 3.0 for K1A, and the 2025 deck shows achieved SOR only as a chart (2025). CNOOC's pad table counts 152 wells at the Long Lake pads, 26 at LLSW, 38 at K1A and 6 at LLNW, without saying whether they are pairs, producers or wellbores (2025). Recovery against each area's SAGDable bitumen in place is 50% for the Long Lake pads, 14% for LLSW, 5% for K1A and zero for LLNW (2025). By pad, LL-005 has recovered 84% of its SBIP from ten wells and LL-014N 13% from six (2025). Over the twelve months to June 2026 Pad 18N carried 7,000 bbl/d from nine producers and the Kinosis K1S cluster 6,100 bbl/d from nine, about 800 and 700 bbl/d each (records; per-well is pad rate divided by producing wells). Pads 17, 16S and K2S followed at 5,200, 5,100 and 4,400 bbl/d, and Pad 19 made 4,200 bbl/d from eight producers (records). Among the core pads, Pad 13 made 2,500 bbl/d from fifteen producers and Pad 09NE 290 bbl/d from four (records). Pad 19 took first steam in July 2024 and first oil in October 2024 (2025). CNOOC reports that it "executed over 30 brownfield wells & achieved first oil for 27 wells adding > 10,000 bopd" in 2024 (2025). Eleven wells were abandoned in 2024, nine for mineral expiry, and no horizontal production or injection well was among them (2025).
4. CPF
Design bitumen is 11,130 m3/d at the Long Lake facility and 3,180 m3/d at K1A, and design steam 37,000 and 9,540 m3/d (2025). The 2024 average of 11,400 m3/d was 80% of the combined 14,310 m3/d, and steam injection of 33,800 m3/d 73% of the combined 46,540 m3/d (records; 2025; arithmetic). Steam comes from once-through generators, named only in the compliance tables as K1A OTSG 1, OTSG C and E, and OTSG 'C' 8403; cogeneration output is charted without values (2025). Kinosis raises steam on site from boiler feed water piped from the Long Lake CPF and sends its emulsion back there for processing (2025). OrCrude started in March 2023 and processes 30,000 bbl/d, while the "Upgrader was only able to run its full cracking process for 5 months in 2024 due to rotating equipment issues" (2025). SRU train 2 was shut down with tail gas recycled to train 1 to meet minimum turndown, and a debottleneck lets the upgrader take wet dilbit straight from the free water knockout (2025).
5. Reservoir
Long Lake produces from the Wabiskaw-McMurray about 40 km southeast of Fort McMurray (2025). CNOOC reports SBIP and EBIP rather than OBIP, footnoting SAGDable bitumen in place as "representative of OBIP" (2025). Reservoir rock is sand, breccia and IHS below 30% shale volume, with a minimum of 3 m3/m2 of hydrocarbon pore volume height, equal to 12 m of EBIP pay (2025). The base of EBIP is the producer depth or a 3 m stand-off from the SBIP base, widened to 5 m where bottom water at least 2 m thick is in contact (2025). The Long Lake development area holds 131 e6m3 of SBIP and 105 e6m3 of EBIP at 22 m average thickness, 31% porosity and 32% effective water saturation (2025). LLSW holds 37 e6m3 of SBIP, Kinosis 239 e6m3 and LLNW 7.9 e6m3 (2025). Recovery against those development-area volumes is 25%, 8%, 0.5% and zero, beside the 50% the pad table gives for the Long Lake pads (2025). Top gas is trapped at the top of the McMurray channel and communicates with the SBIP where sand meets sand or the separation is under 2 m (2025). Top water, including a "Fizzy Water" interval, is mapped, and bottom water is mapped at a 5 m contour interval (2025). In May 2022 CNOOC observed a 4D seismic time delay in and above the caprock beside the Pad 11 build sections, where wells are 40 m apart (2025). In 2024 it saw "no significant observation well pressure or temperature variance", and "Logging and testing results did not identify any clear risk to caprock integrity" (2025). 4D seismic was acquired over the Long Lake East pads in 2024, with none over Kinosis (2025).
6. Future development plans
CNOOC's 2025 programme is to ramp up LLNW Pad 19, start K1B drilling in Q3 2025 and Pad 16 expansion pairs in Q4 2025, and raise the operating pressure of K1A Drainage Area A (2025). It will continue the re-drill and brownfield programme, prepare Long Lake Pads 20 and 21, and run a winter corehole and delineation program (2025). For K1B, "the pad, pipelines and associated facilities have not yet been constructed" (2025). Planned applications are Directive 023 filings for Pads 20 and 21, the Pad 16 expansion pairs and a Kinosis Pad 3 subsurface revision, plus Water Act renewals and a ten-year EPEA renewal (2025). Beyond 2025 the plan exists only as a map whose title block predates Pad 19's first oil (2025).
7. Anything else
The compliance tables run to roughly 35 contraventions over ten pages, most of them overall vent gas against a limit of 15.0 E3m3 per month (2025). January 2024 came in at 72.6 E3m3, April at 48.2 and May at 46.9, and CNOOC traces the exceedances to tank venting off free water knockout C dirty-water dumps and upgrader upsets (2025). CNOOC received a letter of non-compliance on 4 September 2024 under clause 10(2) of scheme 9485TTT on its sulphur balance, which the AER closed in June 2025 "with additional items requiring follow-up" (2025). A bellows rupture on the K1A boiler feed water pump suction on 19 April 2024 forced a full shutdown of the Kinosis steam generation facility (2025). Co-injection runs under three approvals: Pad 7E under 9485R, reinstated in March 2022; Pad 7N under 9485CC, reinstated in June 2021; and the field-wide 9485PPP from Q4 2022 (2025). The field-wide programme has 43 wells lined out, with injection on Pads 2 to 10 from Q4 2023 and Pads 12 to 15 from Q2 2024 (2025). CNOOC reports "no negative impacts observed at this time on bitumen rates or recovery" and records "Pilots: None. Major Technical Innovations: None" for 2024 (2025). The 2025 copy carries a June 30, 2025 cover still bearing the template strings "TITLE GOES HERE" and "Date goes here" (2025). In the pad table LL-004 shows EBIP of 0.7 e6m3 above an SBIP of 0.2 e6m3, and LL-015S carries zero wells with 0.3 e6m3 produced and 34% recovery (2025).
MacKay River Commercial Project, PetroChina Canada, OSCA 11715, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026. Not Suncor's MacKay River 8668 and not Greenfire's McKay River 11461.
2. Project history
PetroChina bought 60% of Athabasca Oil Sands' MacKay River and Dover projects for $1.9 billion in 2009 and took the remaining 40% for $680 million when Athabasca exercised a put option, reported on 3 January 2012 (public). The operating company, Dover Operating Corp., renamed itself Brion Energy in May 2013 (public), and the project now files as PetroChina Canada (2025). Its first pads came on production in December 2016 and January 2017, and Phase 1, the only phase built of a planned 150,000 bbl/d, has a bitumen capacity of 35,000 bbl/d (records; 2025). Gas cap pressurization through vertical well 05-13 started in September 2018, gas co-injection on Pads AH, AE and AD in January 2019, and the vertical injector was abandoned in 2023 (2025).
3. Well pair development
MacKay River had 94 wells on eight pads at June 2026, 47 producing, 43 injecting and four suspended (records). PetroChina counts 42 initial well pairs plus four infill pairs on Pad AA and two on AF, 48 in all: AA 10, AB 5, AC 4, AD 5, AE 6, AF 8, AH 5 and AJ 5 (2025). Oil averaged 9,700 bbl/d in 2024 at an SOR of 5.76, matching the deck's "approximately 1,541 m3/d (9,691 bpd)" and its stated 5.76 (records; 2025). The scheme made 12,200 bbl/d at 5.06 in 2021, then 9,500 bbl/d at 5.72 in 2025 and 7,000 bbl/d at 5.76 over January to May 2026 (records). PetroChina prints SOR by pad: cumulative from 4.1 at AC to 14.6 at AH, instantaneous from 3.2 at AF to 15.7 at AD (2025). Its account is that "The higher SORs experienced at Pads AD, AE, AH, and AJ are primarily due to gas cap contact and/or slightly larger, lower transition zone leak off" (2025). Recovery of each pad's OBIP to 31 December 2024 is AA 26%, AC 25%, AF 20%, AB 15%, AD 12%, AE 9%, AJ 9% and AH 4%, with 16% across the eight (2025). Over the twelve months to June 2026 Pad AF carried 2,600 bbl/d from eight producers and AC 1,200 bbl/d from four, about 300 bbl/d a well each (records; per-well is pad rate divided by producing wells). AA made 1,600 bbl/d from ten producers and AH 330 bbl/d from five, about 200 and 100 bbl/d a well (records). Infill pairs AF11 and AF12 were drilled and completed by August 2023 and converted to SAGD by early February 2024 (2025). Well pair AJ05 was suspended in 2024 for a confirmed lack of communication between injector and producer, thick interbedded mud having compromised SAGD development (2025). PetroChina calls it "non-SAGD-able and not producible with current technologies" after 1,780 m3 of production (2025). Completions carry electric submersible pumps, fibre optic temperature coils and inflow control devices (2025).
4. CPF
Phase 1 bitumen capacity is the 35,000 bbl/d in section 2, and the 2025 deck shows steam design capacity only as a chart line, with no value stated (2025). The plot plan labels a block "UNIT 03 (STEAM GENERATION)" with no equipment, unit count or type, beside bitumen treating, water treating, a hydrocarbon tank farm and utilities (2025). Steam injection averaged 8,800 m3/d in 2024 (records). The one 2024 change was a 33 m3 chelant tank replacing chemical totes in water treatment, approved on 28 November 2024 (2025). No turnaround was taken in 2024; the last was in 2020 and the next is planned for Q2 2026 (2025). Water comes from the Empress Channel Aquifer under licence 00266369-03-01 at an approved 2,116,964 m3 a year from four wells, and PetroChina prepared an application to reduce that volume (2025).
5. Reservoir
MacKay River produces from the McMurray beneath the Wabiskaw and the Clearwater (2025). Across the development area the reservoir runs from 176 to 197 m TVD, with net pay of 21.3 m, porosity 0.34 and bitumen saturation 0.79 (2025). Initial pressure is 220 kPaa at the top of the reservoir and 400 kPaa at the base, and the original temperature is 6 °C (2025). OBIP is 27.6 x 10^6 m3 over the development area and 459.6 x 10^6 m3 over the project area, the latter on a 12.8 m net pay with no recovery factor stated against it (2025). Per-pad OBIP runs 2.66 to 4.69 x 10^6 m3 at horizontal permeability of 2.2 to 2.7 D and vertical 0.9 to 1.1 D (2025). Estimated ultimate recovery of each pad's OBIP runs from 48% at AH to 63% at AC, and is 56% for the eight pads together, with no method given (2025). Net pay is cut at 10 m, and PetroChina reports the "Majority of 8 drainage boxes are in >15m bitumen pay" (2025). Top gas of about 0 to 3 m is present in the upper McMurray across the development area (2025). The upper transition zone is under 1.5 m over most of the Phase 1 drainage boxes and the lower under 1.0 m (2025). The Clearwater caprock is "a thick (greater than 21 m), and laterally continuous, consistent, clay-rich caprock" (2025). The Wabiskaw sand above the reservoir, the early-warning target, ran 988 to 1,834 kPag in 2024 against an initial 918 to 1,508, and 7 to 71 °C against 6 to 43 (2025). The Clearwater sand above the caprock stayed at 839 to 933 kPag and 4 to 5 °C, its pre-development conditions (2025). InSAR on 104 corner reflectors shows cumulative heave from 2014 to 2024 of 8.6 cm at Pad AH to 21.8 cm at Pad AA, with a maximum of 42.7 cm at Pad AJ (2025). Seismic is 96 km of 2D and 58.4 km2 of 3D, with 4D in 2018, 2019 and 2020 and none since (2025).
6. Future development plans
For 2025 PetroChina planned no delineation wells and no seismic, and listed producer sidetracks, solvent washes for liner plugging, inflow control devices and conversions from submersible to progressing cavity pumps (2025). Amendment 11715V was approved on 25 March 2024 for the ABA drainage area with two long lateral pairs, ABA10 and ABA11, and Pad AB is to be expanded in late 2025 to take them (2025). Sustaining candidates are AF09 and AF10 at 850 m, AB06 at 850 m, AB10 and AB11 as 1,700 m sidetracks, and wells north of Pad AF (2025). PetroChina is considering infills on Pads AF and AB and may apply for more drainage boxes inside the development area (2025). The long-range slide has 4D seismic acquired over two to three drainage boxes a year, against the 2025 slide's no seismic (2025).
7. Anything else
Amendment 11715W was approved on 24 July 2024 to allow a higher maximum operating pressure for circulating SAGD wells (2025). Co-injection has carried pressure support since the vertical injector, which had taken 75,600 e3Sm3, was abandoned with mechanical issues (2025). Typical rates are 2,400 to 4,100 Sm3/d per well against an AER maximum of 5,000, at 0.5 to 2.0 mole percent, with 98,362 e3Sm3 injected by December 2024 (2025). PetroChina names 26 co-injecting pairs, down from 30 in early 2024, and reports produced gas at 14% of co-injected volumes (2025). Five compliance events are disclosed, including repairs to liner piling boots and a missed runoff sample dated July 2025 inside the 2024 summary (2025). The eight per-pad OBIP rows sum to 27,598,239 m3 against a printed total of 27,058,824 m3; the 27.6 x 10^6 m3 the other two tables give matches the rows (2025). The 2025 PDF's title metadata reads "An Introduction to PetroChina Canada" (2025). Both fugitive vapour gas compressors failed on 24 September 2024 and vented from the water treating unit, a system PetroChina says "was required to be in operation under the approval" (2025).
BlackGold, Harvest Operations Corp., OSCA 11387, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026.
2. Project history
Korea National Oil Corporation completed its purchase of Harvest on 22 December 2009, and Harvest bought the BlackGold project from KNOC in 2010 (public). Harvest received Initial Phase commercial approval in 2010 and Expansion Phase approval in 2013, and the Expansion Phase "has not yet received final investment decision (FID)" (2025). BlackGold took first steam in June 2018 (2025). The lifespan chart carries nine event callouts, none dated in text: five maintenance outages, a boiler repair, operations "constrained due to oil price" and two trucking curtailments (2025).
3. Well pair development
BlackGold had 35 wells at June 2026, one producer and one injector on each of seventeen patterns, sixteen producers active and one suspended (records). Oil averaged 7,300 bbl/d in 2024 at an SOR of 2.81, against 8,600 bbl/d at 2.91 in 2021 and 7,700 bbl/d at 3.09 in 2023 (records). 2025 averaged 7,700 bbl/d at 2.55, with September 2025 down to 64 m3/d on ST53, and January to May 2026 10,600 bbl/d at 2.43 (records). The 2025 deck does not state a recovery factor per well pattern. Well Pad 101 carries patterns 101-01 to 101-05 and Well Pad 102 carries 102-01 to 102-12, split geologically into an East and a West Area (2025). Over the twelve months to June 2026 the strongest patterns were 102-10 at 1,000 bbl/d, 102-06 at 900, 102-07 at 850, 101-02 at 810 and 102-11 at 760, each from a single producer (records). The weakest were 102-02 at 180 bbl/d, 102-01 at 94, 102-09 at 45 and 102-08 at 24; 102-09 last produced in August 2025 and 102-08 in November 2025 (records). The AER agreed on 22 March 2024 that a six-well sidetrack programme needed no Directive 023 amendment, and Harvest re-drilled 101-P3, 102-P7 and 102-P10 in 2024 (2025). Harvest noted "the lack of sand control on the pulled liner", and re-drilled by liner pull and whipstock with wire-wrapped screen liners (2025). All three re-drilled patterns were back on production by August 2024, and 102-10 has been the field's strongest pattern since (records). The 101-02 pair was rebuilt after a remedial repair on 101I2-R in December 2023 and an AER-approved Directive 087 slimhole repair, circulated in mid-2024 and came on in Q4 2024 (2025). Harvest reports 11 ESP failures in 2024 and no well at the ramp-down or blowdown stage (2025). The WP-102 expansion of two well pairs started up in May 2024 (2025), and the two newest Pad 102 patterns, 102-11 and 102-12, first produced in August 2024 and February 2025 (records).
4. CPF
Approved capacity is 1,590 m3/d of bitumen on an annual average basis for the Initial Phase, with a further 3,180 m3/d approved for the Expansion Phase, 4,770 m3/d in total (2025). The 2025 deck does not state whether steam generation is once-through or drum; it shows steam capacity and licensed bitumen rate only as chart lines, with no value stated. Steam injection averaged 3,266 m3/d in 2024 by ST53 and 3,469 m3/d summed over the well records, which would put the SOR at 3.00; the difference is unexplained (records). Harvest made 24 minor management-of-change improvements in 2024 and signed a Pipeline Transportation Agreement with Inter Pipeline for dilbit and diluent, with construction and in-service in 2025 (2025). Source water comes from two main Clearwater wells with two backups, and Harvest's 2024 analyses of it show no total dissolved solids below 4,000 mg/L (2025). The plant took a maintenance outage in April 2024 and another in May 2025, and "The next scheduled turnaround is taking place in May 2026" (2025).
5. Reservoir
The stratigraphy runs Clearwater, Wabiskaw, Wabiskaw D Sand, McMurray and Beaverhill Lake, and two reservoirs are quantified, the developed McMurray and an undeveloped Wabiskaw (2025). SAGDable net pay is resistivity at or above 20 ohm-metres, density porosity at or above 27%, more than 10 m continuous and no break over 1 m (2025). The volumes are GLJ year-end 2024 2P estimates, and produced volumes come from a commercial database at 31 December 2024 (2025). The McMurray development area covers 2,946 hectares with 69.7 MMm3 of OBIP, 3.8% recovered and 48.8% ultimate recoverable (2025). Developed East covers 101.2 hectares with 7.59 MMm3 of OBIP, 25% recovered against 63.1% ultimate, and Developed West 52.4 hectares with 3.72 MMm3, 23.1% against 41.4% (2025). The two developed areas are 153.6 hectares, about 5% of the development area (2025; arithmetic on the stated areas). The undeveloped Wabiskaw holds 17.68 MMm3 of OBIP with no wells and is credited with 42% ultimate recovery (2025). The 2025 deck does not state a reservoir depth, initial pressure, initial temperature or bitumen viscosity. Harvest reports "No McMurray formation top gas identified" and maps Wabiskaw top gas and top water at 1 m contours (2025). It describes bottom water as "generally localized and thin" and states that "No producing wells intersect bottom water" (2025). The Quaternary channel does not incise the Clearwater shale or the Wabiskaw caprock, and there is no karsting or salt dissolution in the project area (2025). Seismic is 23 km2 of 3D shot in 2007 and 4.5 km2 of 4D with a 2012 baseline, a 2020 monitor and a 2025 monitor in progress (2025). Heave monitoring over 8.67 km2 from a December 2017 baseline gave 2024 corner-reflector uplift of 2 mm at Pad 101 and 5 mm at Pad 102 West (2025).
6. Future development plans
Harvest's 2025 plan is to sidetrack or re-drill the 102-08 and 101-05 producers, take a major project turnaround and build Pad 103 (2025). Two applications were expected in 2025, for the Inter Pipeline connection to the CPF and for additional heave monitoring over Pad 103 (2025). The five-year list is re-drill pairs on Pads 101 and 102, infills and new pairs as required, observation wells and sustaining pairs on Pad 103, more 3D and 4D seismic, and an investment decision on the Expansion Phase (2025). It ends with cogeneration, NCG co-injection, solvent co-injection and technology to cut SOR, none with a date, capacity or volume (2025). The 101-05 sidetrack came on in October 2025 and ran 500 bbl/d in its first two full months, 170 bbl/d by June 2026 (records).
7. Anything else
On 22 April 2024 injector 102-I3 on Well Pad 102 released "approximately 600 m3 of oil emulsion and 405 m3 of steam condensate", reported to the AER as FIS incident 20241029 (2025). "The well was shut in and contained the evening of 27 April 2024", five days later (2025). The AER inspector wrote on 22 April that "Steam release remains uncontrolled. The wellhead is removed and there is no well controls" (2025). The inspector added that the fire master could not assess the well because it was too hot and water could not push the steam (2025). Harvest hauled 14,874.94 tonnes of contaminated soil, mulched vegetation and ash to approved facilities between 15 May 2024 and 12 January 2025, and part of Pad 103 was cleared in that cleanup (2025). The production chart footnotes April 2024 as a maintenance outage and does not connect it to the incident (2025). On 18 June 2024 the ground around the surface casing of injectors 101-I5 and 101-I4 was exposed and new surface casing stubs were welded on (2025). Slimhole casing went into "A couple of wells" to stop gas migration and a surface casing vent leak (2025). A 17 September 2024 inspection found that "Harvest did not demonstrate they conducted a periodic review of the leak detection program" (2025). Ultrasonic testing of oil effluent pipeline 55237 in May 2025 found minor material loss, and pipelines 55237 and 52672 are to be re-inspected for stress corrosion cracking at the May 2026 turnaround (2025). The pad modules are equipped for co-injection but "Pad 101 and Pad 102 are not ready for NCG Co injection" (2025). The well list carries 101-P4 as suspended from 1 January 2024, yet volumes are recorded against it every month since, 120 bbl/d over the twelve months to June 2026; the difference is unexplained (records). For January to May 2026 ST53 gives 10,600 bbl/d and the summed well records 8,700 bbl/d; the difference is unexplained (records). The copy in this corpus has a June 25, 2025 cover, a PDF creation date of 9 January 2026 and an embedded title ending "V2 - No Names" (2025). The sidetrack approval table names producer 102-7 on four of its six lines while the bracketed well names differ, and the development-area recovery does not close: 2.76 over 69.7 MMm3 is 3.96% against the 3.8% printed (2025). Harvest writes that "Operational challenges at the plant persist in achieving and maintaining full capacity and stable performance" (2025).
Blackrod, International Petroleum Corporation, OSCA 11522 (pilot approval 11522H) and commercial scheme 12491, SAGD, Athabasca region, Alberta; the only filing is the pilot's.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026. Every deck under 11522 reports the pilot only; the 60-well commercial phase under approval 12491, pads A1 and B, has never filed a Directive 054 presentation and is reported nowhere in the corpus.
2. Project history
BlackPearl Resources built the pilot facility and started Well Pair 1 in 2011, commissioned the WP2 expansion in 2013 and shut WP1 in in 2015 (2025). International Petroleum Corporation announced the closing of its combination with BlackPearl on 14 December 2018, and on 7 February 2023 sanctioned Blackrod Phase 1, targeting first oil in late 2026 and 30,000 boe/d by 2028 (public). WP3 was drilled in 2019 and started in 2020 as WP2 was shut in, and has run alone since (2025). Commercial construction began in 2024, the 60 wells on pads A1 and B were drilled between September and December 2024, and both pads took first production in late December 2025 (2025; records).
3. Well pair development
The pilot has one operating SAGD well pair and has had three drilled in fourteen years, never more than two on stream at once (2025). Blackrod had 66 wells at June 2026 in four groups: the pilot's four, two suspended wells from the earliest pairs, pad A1's 32 and pad B's 28 (records). Scheme oil averaged 470 bbl/d in 2024 at an SOR of 4.25, down from 800 bbl/d at 2.53 in 2022 and 600 bbl/d at 3.23 in 2023, and 640 bbl/d at 3.32 in 2025 (records). January to May 2026 averaged 740 bbl/d while steam injection rose to 3,100 m3/d (records). The pilot pair averaged 720 bbl/d over the twelve months to June 2026 (records). In June 2026 pad B made 1,100 bbl/d from 12 producing wells and pad A1 520 bbl/d from 14, up from about 100 bbl/d each in May (records). Recovery of each pair's OBIP is WP1 17%, WP2 39.3% and WP3 29.8%, with the three pilot pairs together at 29.3% and the development area at 1.77% (2025). Estimated ultimate recovery is a flat 55% of OBIP on every row, including the undeveloped development area (2025). The lifespan chart records an acid job on WP1, a scab liner pull on WP2 and two ESP replacements on WP3 (2025).
4. CPF
Pilot facility design is 440 m3/d of steam and 160 m3/d of bitumen (2025). The plot plan lists a steam generator building Q-440, a steam separator package SK-470 and a water softener package PK-330 with a brine tank, and no evaporator (2025). Steam injection averaged 320 m3/d in 2024, 73% of the 440 m3/d design (records; arithmetic). A main power generation package Q-910 is listed, and source water comes from a brackish well at 15-25 (2025). IPC made no modifications requiring an AER application in 2024 (2025). The two plot plans are BlackPearl drawings revised in 2011 and 2013 (2025).
5. Reservoir
Blackrod targets the Lower Grand Rapids Unit 1 at 300 m (2025). Initial reservoir pressure is 1,700 kPa and initial temperature 13 °C (2025). Net pay cutoffs are gamma ray below 75 API, resistivity above 20 ohm-m and porosity above 33% (2025). Pattern areas are 56,000 m2 at WP1, 73,500 at WP2 and 100,000 at WP3, with net pay of 22 to 25 m, porosity 34 to 35% and oil saturation 59 to 63% (2025). Horizontal permeability of 3,450 mD and vertical of 3,024 mD are footnoted as the development-area average, not measured per pair (2025). OBIP is 1,205 thousand m3 over the three pilot patterns against 353 thousand m3 produced, and 19,972 thousand m3 over the 3,804,190 m2 development area (2025). Bottom water is mapped in Lower Grand Rapids Unit 3 (2025). IPC states that there are "No major gas intervals in communication with pay within the development area" (2025). The 2025 deck does not state a caprock thickness, maximum operating pressure or bitumen viscosity. IPC collects no heave data, saying that "With only one well pair operational at a time, no relevant heave data would be collected" (2025).
6. Future development plans
Approved commercial scheme 12491B covers 80,000 bbl/d, printed as 12,720 m3/d, in phases, the first two at 30,000 bbl/d and a third of 20,000 bbl/d (2025). IPC describes the Phase 1 Full Development Area as "14 Well patterns, Drilled from 10 surface locations" at 50 m spacing and about 192 well pairs (2025). No timeline, first-steam date, pad name or capital plan accompanies it in the filing (2025). For the pilot, IPC expected no applications in 2024 and no activity that would alter scheme performance (2025).
7. Anything else
The filing reports the pilot only; the commercial pads in our records, A1 and B with 60 wells, are not named in its 23 pages (2025; records). The deck's one commercial count, about 192 well pairs, is not bridged to the 60 wells drilled (2025; records). The reservoir table heads its OBIP, PBIP and cumulative columns Mm3 over values in thousand m3, which the recovery percentages confirm (2025). Producible bitumen is 75% of OBIP for WP2 and 79% for WP3, against the flat 55% ultimate recovery on the same rows (2025). IPC reports "No Co-Injection has been implemented" and "Steady operation throughout 2024, no failures or lessons learned" (2025). Ten of the 23 pages have no text layer, including every slide title (2025). IPC reports no reportable incidents, self-disclosures or contraventions under approval 11522H (2025).
Algar and Great Divide, Connacher Oil and Gas, OSCA 10587 and 11253, SAGD, Athabasca region, Alberta.
Decks: 2021, 2022, 2023, 2024, 2025 (bare years below); records to June 2026. The filing reports under 10587, cited as 10587DD; approval 11253 folds into the same scheme in our records and has no separate filing.
2. Project history
Connacher's Pod One pads 101 and 102 came on production in September 2007, the Algar pads 201 to 203 in May 2010, when steam injection there began, and Pad 104 in September 2013 (records; 2025). The two sub-areas each have a plant, Pod One west of Highway 63 and Algar east of it, about 80 km south of Fort McMurray (2025). Connacher swapped about C$1.0 billion of debt for shares on 8 May 2015, sought CCAA protection in May 2016, and on 30 September 2019 its first-lien lenders acquired all of its shares under the court-sanctioned plan (public). Solvent co-injection was commissioned in 2022 and field-wide NCG approval came in March 2022 (2025).
3. Well pair development
Great Divide had 159 wells across fifteen pattern groups at June 2026, 78 producing, 60 injecting and fourteen suspended (records). Connacher counts 28 active well pairs and 15 infills at Pod One on Pads 101, 102, 104 and 105, and 28 pairs and 14 infills at Algar on Pads 201, 202, 203 and 232 (2025). Oil averaged 15,700 bbl/d in 2024 at an SOR of 3.64, the deck's 15,674 bbl/d and 3.64 (records; 2025). The scheme made 10,900 bbl/d at 4.84 in 2019 and 13,900 bbl/d at 3.81 in 2022, then 17,800 bbl/d at 3.36 in 2025 and 18,800 bbl/d at 3.08 over January to May 2026 (records). Recovery of each pattern's OBIP at 31 December 2024 is 71% at Pad 104, 68% at 101S, 61% at 102W and 57% at 102S, patterns on production since 2007 and 2013 (2025; records). The 2010 Algar patterns stand at 59% for 202, 58% for 203 and 53% for 201 (2025). The patterns started since 2022 read 104E 25%, 104W 19%, 105W 7%, 202NE 5% and 232 zero, while 101N stands at 18% and 203W at 11% (2025; records). Over the twelve months to June 2026 the 104E group carried 3,500 bbl/d from five producers and the 105 group 3,400 bbl/d from four, about 700 and 800 bbl/d each (records; per-well is pad rate divided by producing wells). A Pod One pad on production from August 2024 made 2,600 bbl/d from five producers, and 104W 2,300 bbl/d from three (records). 102W made 150 bbl/d from seven producers and 102S 170 bbl/d from five (records). Pad 232 first produced in April 2025, inside the filed Q2 2025 target, and made 1,200 bbl/d from four producers over the twelve months (records; 2025). Two wells were downhole abandoned in 2024, 101 P05 on 4 February and 201 INF03 on 29 June, and a merged re-drill of 203-P07 and 201-INF03 was filed as application 1950730 (2025).
4. CPF
Directive 56 licence rates are 1,950 m3/d of bitumen and 5,950 m3/d of steam at the Pod One CPF and 1,600 and 4,800 m3/d at the Algar CPF (2025). The 2024 average of 2,490 m3/d was 70% of the 3,550 m3/d of licensed bitumen, and steam of 9,060 m3/d 84% of the 10,750 m3/d licensed (records; 2025; arithmetic). The 2025 deck does not state the steam generation type; Connacher calls the units boilers, tags two at Pod One H-801 and H-802, and names evaporators in its vent collection tie-ins (2025). A lease automated custody transfer unit and a dilbit sales line went into service in October 2024, and the K-613 compressor failed repeatedly through the year (2025). The NOx limits on H-801 and H-802 were raised from 8.9 to 12.0 kg/hr each by EPEA application (2025). Connacher made no modifications to either CPF in 2024 (2025).
5. Reservoir
The reservoir tables do not name the producing formation (2025). Thickness is 10 to 30 m, averaging 22 m at Pod One and 25 m at Algar, at an average depth to top of 475 m and 485 m (2025). Net pay averages 21 m at Pod One and 22 m at Algar, oil saturation 80% and 76%, and porosity 33% at both (2025). Initial temperature is 13 °C at both, initial pressure 2,850 kPa at Pod One and 2,500 kPa at Algar, bitumen density 1,018 kg/m3 and viscosity above 1 million cP (2025). The 2025 deck does not state a caprock formation, thickness or maximum operating pressure. OBIP is 28.1 e6m3 over the active pads, 67.0 e6m3 over the development area and 196.9 e6m3 over the project area, and Connacher prints recovery of 11.5 e6m3 against each: 41%, 17% and 6% (2025). Estimated ultimate recovery of pattern OBIP runs from 81% at Pad 104 to 59% at 202NE, and 101N is booked at 18%, equal to its current recovery (2025). Top gas had an original pressure of 2,027 kPa in 1988 and a lowest recorded post-depletion pressure of 746 kPa in 2003 (2025). Connacher is repressurizing it toward 2,800 to 3,200 kPa, injecting into 100/9-17-82-12W4 at 10 e3 sm3/d and 115/2-17-82-12W4 at 70 e3 sm3/d at year-end 2024 (2025). A lean zone sits above the bitumen pay over Pads 104, 104W, 104E, 105W and 105E, mapped with the gas cap and bottom water in direct contact with bitumen (2025). IHS thickens in the upper reservoir at Pod One Pad 101N, and IHS and breccia lie north of Algar Pad 203 (2025).
6. Future development plans
Connacher planned to drill and start the final four pairs on Pad 232 in Q2 2025 and three pairs and two infills at Pod One in mid-2025 (2025). Wells 105W-03, 104-11, 104-12, 104F07 and 104F10 were drilled for 2025 production (2025). Directive 023 sustaining pad applications and a development area expansion were expected in 2025, with minor debottlenecking at both CPFs and Clearwater disposal near Pod One (2025). The 2026 programme is "still in development and subject to budget approval" (2025).
7. Anything else
Solvent went into Pad 203W from December 2022 at 5 to 10 vol% of the steam rate, and into 202NE intermittently in 2023 because of metering issues (2025). Connacher reports solvent recovery of about 76% cumulative and a two-year cumulative SOR 20 to 35% better on 203W than on the legacy Algar pads (2025). SORs rose on 203W in 2024 "due to pad-to-pad pressure management difficulties" when Pad 203 lost pressure during a re-drill (2025). Field-wide NCG approval carries no limit on rate or concentration, and Connacher injects 80 to 90 e3m3 of fuel-gas methane, reallocating about 1,600 t/d of steam and recovering about 90% (2025). Concentration rises from 3 to 5 mol% to 100% NCG at pads in full blowdown, and "Generally, blowdown is implemented when patterns reach 50% OBIP" (2025). The pattern table heads its OBIP and producible-bitumen columns Mm3 over values in thousand m3 (2025). Pad 105E is named in the top-gas list and has no recovery row, and the June 2025 cover sits on a PDF created on 13 November 2025 (2025). Compliance is a 34-row flaring and venting table, a 100 L bitumen release at Pad 203-F06 from a rod pump packing failure on 4 October 2024, and a missed wildlife sweep on 11 January 2024 (2025).
Saskatchewan, and the projects that have never filed
Our Saskatchewan production series is Petrinex Saskatchewan data from January 2022, so no rate below reaches a scheme's start, and pad rates are averages over the trailing twelve months, July 2025 to June 2026 (records). Pad labels of the form P001, P002 are our records' own numbering, because the Saskatchewan well data carries no operator pad names; lettered pads such as SA or 1A carry names found in the well data (records). Until 28 September 2026 our pad records put every Saskatchewan well in a producing or injecting role, including 205 wells the provincial well list gives as abandoned, downhole abandoned or suspended (records). That ingest defect was fixed on 28 September 2026, and the pad counts below carry the well list's status (records). Cenovus's eight Saskatchewan schemes, and Vawn, were Husky Energy's until Cenovus's combination with Husky closed on 1 January 2021 (public).
Cardinal, Cardinal Energy Ltd., no provincial approval number in our records, SAGD, Twp 37 Rge 19 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Cardinal Energy took first steam at its Reford 1 SAGD project on 21 August 2025 (public), and the twelve wells of our Cardinal scheme carry on-production dates of 20 to 24 August 2025 (records). The scheme is one pad, P001, and has not been extended since start-up (records).
3. Well pair development
Cardinal's single pad holds six producers and six injectors, all on production since August 2025 (records). Production over the five recorded months of 2025 averaged 2,300 bbl/d at an iSOR of 3.98, and 2026 to date averages 6,600 bbl/d at 2.47 (records). No per-pad recovery figure exists in our records. Over the trailing twelve months the pad averaged 4,300 bbl/d, 710 bbl/d for each of its six producers (records; the per-well figure is pad rate divided by producing wells).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Cardinal gives Reford 1 a nameplate oil capacity of 6,000 bbl/d (public). Records show steam injection averaging 2,600 m3/d in 2026 to date against 1,500 m3/d over the five recorded months of 2025, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime. Cardinal places Reford 1 in a Waseca channel (public).
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime. Cardinal has raised the nameplate of Reford 2, a separate project 10 km north of Reford 1, from 4,250 to 6,000 bbl/d and expects first steam in the summer of 2027 (public).
7. Anything else
Cardinal is the only Saskatchewan scheme here whose whole producing life falls inside our production series (records).
Celtic, Cenovus Energy Inc., no provincial approval number in our records, SAGD, Twp 52-53 Rge 23-24 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Husky's January 2014 project table dates thermal production at Bolney/Celtic to 1996 (public). The oldest well in our Celtic records, a Husky horizontal injector on the five-well pad P012, carries an on-production date of 17 April 1997 (records). The well list names Husky on the 78 wells put on production to October 2017, under the Celtic and Bolney field names (records). Pads have been added through the window, the most recent being P009 from 1 October 2024 (records).
3. Well pair development
Celtic spreads 152 wells across 31 pads, more pads than any other Saskatchewan scheme here: 82 producing, 51 injecting and 19 abandoned (records). The scheme averaged 12,100 bbl/d at an iSOR of 3.47 in 2022, fell to 9,400 bbl/d at 4.17 in 2024, and recovered to 10,600 bbl/d at 3.84 in 2025 and 11,000 bbl/d at 3.52 in 2026 to date (records). Twenty-one pads produced during the trailing twelve months and together averaged 10,400 bbl/d (records). The recovery after 2024 tracks one pad: P009, whose six wells entered the series in December 2024, averaged 2,300 bbl/d over the trailing twelve months, 22% of the scheme (records). That is 770 bbl/d for each of its three producers, against 230 bbl/d at P002 and 28 bbl/d at the M pad, which came on in November 2012 (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. Ten pads stopped producing before the end of the record, the earliest in March 2022 and the latest, CM, in May 2026 (records). None of Celtic's eight single-well pads produced in the window: four producers stopped between March 2022 and May 2025, and the other four hold two injectors and two abandoned wells (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection across the scheme averaging 6,500 m3/d in 2025, with a peak annual figure of 6,900 m3/d in 2023, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime. Saskatchewan's Ministry of Energy and Resources approved a Cenovus expansion at Bolney, reported in September 2025 without scope or timing (public).
7. Anything else
Two names, S and CF, each label two pads (records).
Dee Valley, Cenovus Energy Inc., no provincial approval number in our records, SAGD, Twp 48 Rge 23 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Husky announced first production at Dee Valley on 26 August 2019 (public). The well list dates the two original pads, P001 and P002, to 27 June 2019, two months before that announcement (records). A third pad, P003, came on production on 5 May 2025 and is now the largest producer at the scheme (records).
3. Well pair development
Dee Valley is 65 wells on three pads, and 23 of them are abandoned, the largest abandoned share of any Saskatchewan scheme here; the rest are 21 producers and 21 injectors (records). Dee Valley averaged 9,500 bbl/d at an iSOR of 3.28 in 2022, dropped to 6,500 bbl/d at 3.06 in 2024, and reached 13,600 bbl/d at 2.21 in 2026 to date, the lowest iSOR in its record (records). All three pads produced through the trailing twelve months, averaging 13,200 bbl/d between them (records). P003 carried 8,300 bbl/d of that, 63% of the scheme, while P001 carried 3,400 bbl/d and P002 1,500 bbl/d (records). Per producing well that is 1,200 bbl/d at P003, 340 bbl/d at P001 and 360 bbl/d at P002 (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. The abandoned wells are all on the 2019 pads, twelve of P001's 30 wells and eleven of P002's 19 (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Husky built Dee Valley as one of six 10,000 bbl/d thermal projects (public). Records show steam injection averaging 4,500 m3/d in 2025 and a peak annual 5,500 m3/d in 2023, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
The 2024 dip of 2,800 bbl/d below 2023 came with steam down by 2,300 m3/d, so the scheme cut steam and oil together in that year (records).
Edam, Cenovus Energy Inc., no provincial approval number in our records (records id sk-cenovus-edam; a separate Edam scheme is operated by Strathcona Resources Ltd.), SAGD, Twp 48 Rge 19-21 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
The oldest pads at Cenovus's Edam are EA and EB, both on production from 26 February 2016, with WA following that June (records). The well list names Husky on 40 of the 42 wells those three pads received to July 2019 (records). Five pads have come on since, P005 in 2019, P007 in 2020, P001 in March 2021, P008 in January 2023 and P006 in November 2023 (records).
3. Well pair development
Cenovus's Edam holds 109 wells on eight pads: 41 producing, 36 injecting and 32 abandoned, thirteen of the abandoned wells on EA (records). The scheme made 13,800 and 13,900 bbl/d in 2022 and 2023 at iSORs of 3.56 and 3.41, then stepped up to 21,900 bbl/d at 2.23 in 2024 and has held 20,300 bbl/d and 20,500 bbl/d since (records). All eight pads produced in the trailing twelve months, averaging 20,600 bbl/d together (records). P006 alone carried 7,600 bbl/d of that, 37% of the scheme, and P001 5,800 bbl/d (records). Per producing well the newer pads run ahead: 1,300 bbl/d at P006 and 800 bbl/d at P008, against 100 bbl/d at EA and 110 bbl/d at EB (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. P007, an eight-well pad on production from February 2020, stopped in November 2025 after averaging 82 bbl/d over the trailing twelve months (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection flat between 7,500 and 7,800 m3/d in every year from 2022, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime. Saskatchewan's Ministry of Energy and Resources approved a Cenovus expansion at Edam, reported in September 2025 without scope or timing (public).
7. Anything else
The 2024 step up of 8,000 bbl/d came with 200 m3/d more steam than 2023, so the scheme added that volume on the plant it had (records). Strathcona Resources operates a second Edam scheme in the same township and range, so only the operator separates the two in our records (records).
Edam, Strathcona Resources Ltd., no provincial approval number in our records (records id sk-strathcona-edam; a separate Edam scheme is operated by Cenovus Energy Inc.), SAGD, Twp 48 Rge 19 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
The oldest pad at Strathcona's Edam, P002, came on production on 4 February 2016, and the well list names Serafina on its sixteen original wells (records). P001 followed in December 2016 (records). Strathcona bought Edam with Serafina Energy in 2022 (public). Two pads have been added inside the window, P003 in May 2022 and P004 in May 2025 (records).
3. Well pair development
Strathcona's Edam is 73 wells on four pads: 44 producing, 24 injecting, one suspended and four abandoned, the last five all on P002 (records). Output ran 7,700 bbl/d at an iSOR of 2.62 in 2022, 6,600 bbl/d at 3.27 in 2023, 7,400 bbl/d at 3.00 in 2025 and 6,400 bbl/d at 3.43 in 2026 to date (records). All four pads produced in the trailing twelve months for a combined 6,900 bbl/d (records). P003 carried 4,000 bbl/d of that, 58% of the scheme, and P004 carried 1,600 bbl/d (records). Per producing well that is 400 bbl/d at P003 and 270 bbl/d at P004, against 71 bbl/d at the 25-well P001 (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. The oldest pad, P002, averaged 56 bbl/d over the trailing twelve months from eleven producers and stopped in May 2026 (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection rising from 3,200 m3/d in 2022 to 3,500 m3/d in 2025 and holding there, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime. Strathcona says Edam and its Vawn project share the same Lloydminster reservoir (public).
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
Cenovus operates a second Edam scheme in the same township and range, so only the operator separates the two in our records (records). Strathcona's Vawn plant sits two kilometres from the Edam plant (public).
Kerr, Northern Hawk Energy Ltd., no provincial approval number in our records, SAGD, Twp 32-33 Rge 23-24 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
The earliest on-production date at Kerr is 1 April 2013, on the two-well pad P004, and the well list names Baytex on that first well (records). P001 followed in September 2018 (records). Two pads came on inside the window, P003 in September 2022 and P002 in August 2023, the latter now carrying three quarters of the scheme (records).
3. Well pair development
Kerr's 22 wells sit on four pads: eleven producing, nine injecting, one suspended and one abandoned (records). The scheme averaged 1,800 bbl/d at an iSOR of 4.01 in 2022, 2,400 bbl/d at 3.38 in 2024 and 2,500 bbl/d at 3.40 in 2025, with 2026 to date at 2,100 bbl/d and 3.80 (records). All four pads produced through the trailing twelve months for 2,200 bbl/d between them (records). P002 carried 1,700 bbl/d of that from three producers and three injectors, against 350 bbl/d from the ten-well P001 (records). No per-pad recovery figure exists in our records. Per producing well the figures are 560 bbl/d at P002, 78 bbl/d at the one-producer P003, 72 bbl/d at P004 and 69 bbl/d at P001 (records; per-well figures are pad rate divided by producing wells).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection averaging 1,300 m3/d in each year from 2023, against 1,100 m3/d in 2022, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
Northern Hawk Energy operates no other scheme in this document (records).
Meota, Strathcona Resources Ltd., no provincial approval number in our records, SAGD, Twp 46 Rge 16-18 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Meota's oldest pads, P003 and P004, came on production in April and December 2018, P001 and P005 followed in November 2019, and P006 and P007 in March 2021 (records). Strathcona bought Meota with Serafina Energy in 2022, and press coverage of the deal dated Meota West 1 to 2016, two years before any well in our Meota records (public; records). Six pads have been added since the start of 2022, the last of them P009 on 14 February 2025 (records).
3. Well pair development
Meota carries 196 wells across twelve pads, the largest well count of the seventeen Saskatchewan schemes: 106 producing, 76 injecting and 14 abandoned (records). The scheme averaged 26,400 bbl/d at an iSOR of 2.98 in 2022 and fell each year to 19,000 bbl/d at 4.34 in 2024 (records). It recovered to 21,600 bbl/d at 4.09 in 2025 and sits at 20,300 bbl/d at 4.34 in 2026 to date (records). All twelve pads produced during the trailing twelve months, averaging 22,000 bbl/d between them (records). P009 leads at 5,300 bbl/d from five producers and five injectors, P002 follows at 4,300 bbl/d from 24 wells, and the two oldest pads sit at opposite ends, P003 at 2,100 bbl/d and P004 at 160 bbl/d (records). Per producing well that is 1,100 bbl/d at P009, 360 bbl/d at P002, 230 bbl/d at P003 and 11 bbl/d at P004 (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. Nine of P003's 22 wells are abandoned, and P004 and P011 both stopped producing in May 2026, the only pads at the scheme to do so (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection rising from 12,500 m3/d in 2022 to 14,000 m3/d in 2025 and holding there through 2026 to date, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
Meota is the clearest case in the Saskatchewan set of steam rising while oil falls: steam gained 1,500 m3/d between 2022 and 2025 while the rate lost 4,800 bbl/d, and the iSOR moved by 1.11 over the same span (records).
Onion Lake, IPC Canada Ltd., no provincial approval number in our records, SAGD, Twp 56 Rge 27 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
The oldest well in the Onion Lake list, named for Pearl, carries 1 September 2007, and the wells that followed to 2019 carry BlackPearl's BPRI prefix, so the scheme's first wells predate its thermal phases (records). BlackPearl's first thermal phase came on commercial production in 2015 and its second took steam in the first quarter of 2018 (public). International Petroleum Corp. (IPC) closed its acquisition of BlackPearl on 14 December 2018 (public). Three pads have come on inside the window, P022 in July 2022, P001 in July 2023 and P021 in May 2025 (records).
3. Well pair development
Onion Lake carries 153 wells across 27 pads and is the only Saskatchewan scheme here with more injectors than producers: 87 injecting, 47 producing, 15 suspended and four abandoned (records). The scheme is the flattest in the set: 12,700 bbl/d at an iSOR of 3.33 in 2022, 13,200 bbl/d at 3.23 in 2023 and 11,500 bbl/d at 3.69 in 2026 to date (records). Nine pads produced in the trailing twelve months, averaging 12,200 bbl/d between them, and the other eighteen have no production in the window (records). P001 leads at 2,900 bbl/d from nine producers and eight injectors, 1A follows at 2,000 bbl/d and 1B at 1,700 bbl/d (records). Per producing well that is 530 bbl/d at the two-well P021, 380 bbl/d at the single-well P022, 320 bbl/d at P001 and 100 bbl/d at the pad at 3C15-5/2C15-5-56-27 (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. The fifteen suspended wells are spread over ten pads, four of them on the injection pad 3B4-4-3B4-4-56-27 (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. BlackPearl built Onion Lake as two 6,000 boe/d phases and reached the combined 12,000 boe/d nameplate in late September 2018 (public). Records show steam injection between 6,600 and 6,900 m3/d in every year from 2022, with the highest annual figure in 2025, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
BlackPearl's first phase paired 13 horizontal producers on two pads with 35 vertical steam injectors (public). Our pad records put those injectors on pads of their own, so 18 of the 27 pads show no production and the per-well figures above count producers only (records).
Paradise Hill, Cenovus Energy Inc., no provincial approval number in our records, SAGD, Twp 53 Rge 24 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Husky dated Paradise Hill's start to mid-2012 (public), and the older pad, P002, carries an on-production date of 1 May 2012 (records). The well list names Husky on the ten wells put on production to July 2016 (records). P001 followed on 7 July 2017 (records).
3. Well pair development
Paradise Hill is two pads: P001 with eleven producers and twelve injectors, and P002 with seven producers, three injectors, two suspended and two abandoned wells (records). Output held within 120 bbl/d of 3,000 bbl/d in every full year of the record, at iSORs between 3.36 and 3.81, and then fell to 2,100 bbl/d at 4.94 in 2026 to date, the worst ratio in its record (records). Both pads produced through the trailing twelve months for 2,500 bbl/d between them, P001 1,600 bbl/d and P002 830 bbl/d (records). Per producing well that is 150 bbl/d at P001 and 120 bbl/d at P002 (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. P002 has no production in our series before October 2022, nine months into the window, and produced in every month after that (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection peaking at 1,750 m3/d in 2023 and holding between 1,620 and 1,660 m3/d since, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
The 2026 fall of 900 bbl/d on unchanged steam is the whole of the change in the iSOR (records).
Pikes Peak, Cenovus Energy Inc., no provincial approval number in our records, SAGD, Twp 48-49 Rge 23-24 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Husky dated steam production at Pikes Peak to 1981 and its Pikes Peak South project to mid-2012 (public). The well list holds no well older than a Husky Lashburn well on production from 17 April 2004, on a two-well pad, and the scheme predates it (records). The 41 wells put on production to December 2016 carry Husky names, and Cenovus has added two pads inside the window, P009 in August 2023 and P005 in August 2024 (records).
3. Well pair development
Pikes Peak carries 110 wells across twelve pads: 55 producing, 33 injecting and 22 abandoned, six of those on the M pad (records). The scheme has risen in every year of the record, from 12,400 bbl/d at an iSOR of 2.47 in 2022 to 14,200 bbl/d at 2.23 in 2024 (records). It reached 18,200 bbl/d at 1.80 in 2025 and 19,700 bbl/d at 1.72 in 2026 to date, the lowest annual iSOR of any Saskatchewan scheme in this document (records). Eleven pads produced in the trailing twelve months, averaging 19,800 bbl/d between them (records). P005 carried 8,100 bbl/d of that, 41% of the scheme from six producers and six injectors, and P009 a further 3,500 bbl/d from three producers (records). Per producing well that is 1,300 bbl/d at P005 and 1,200 bbl/d at P009, against 480 bbl/d at P001 and 56 bbl/d at the N pad (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. Four pads stopped producing during the record, P011 in August 2024, the 2004 pad in August 2025, RE in October 2025 and L in November 2025 (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection between 4,900 and 5,400 m3/d in every year from 2022, the highest figure being 2026 to date, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
The scheme added 7,300 bbl/d between 2022 and 2026 to date on an extra 500 m3/d of steam, which is why its iSOR fell by 0.75 over the same span (records). Three pads carry names describing a role or a direction, INJ, EAST and RE, and INJ holds five producers alongside its six injectors (records).
Plover, Strathcona Resources Ltd., no provincial approval number in our records, SAGD, Twp 35 Rge 26 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Plover's first pad, P001, came on production on 7 July 2014, and the well list names NBRI on its six original wells (records). The two-well P002 followed on 23 April 2019, and nothing has been added since (records).
3. Well pair development
Plover's fourteen wells are eight producers and six injectors on two pads, none of them suspended or abandoned (records). Output rose from 880 bbl/d at an iSOR of 5.35 in 2022 to 1,300 bbl/d at 3.91 in 2023 (records). It has since held at 1,100 bbl/d at 4.47 in 2024, 1,000 bbl/d at 5.16 in 2025 and 1,200 bbl/d at 4.73 in 2026 to date (records). Both pads produced through the trailing twelve months for 1,100 bbl/d between them (records). P001 carried 900 bbl/d of that from seven producers and five injectors, and P002 210 bbl/d from its single producer (records). Per producing well that is 130 bbl/d at P001, and P002's pad rate is its well rate (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. Plover's iSOR has not fallen below its 2023 figure in any year of the record, the highest floor in the Saskatchewan set after Tangleflags (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection climbing from 740 m3/d in 2022 to 870 m3/d in 2026 to date, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime. Strathcona puts oil initially in place at Plover Lake at about 500 MMbbl, a figure that includes lands bought from Cenovus in 2025 (public).
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime. Strathcona plans to expand Plover Lake to 17,000 bbl/d in 2028, followed longer-term by a 14,000 bbl/d expansion at Plover Lake West (public).
7. Anything else
Plover and Cardinal are the only Saskatchewan schemes here whose well list shows no suspended or abandoned well (records).
Rush Lake, Cenovus Energy Inc., no provincial approval number in our records, SAGD, Twp 47-48 Rge 21 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Husky dated its Rush Lake pilot to 2011 and planned the commercial project for the second half of 2015 (public); the oldest pad carries 17 June 2011 and the A1 and B pads 20 May 2015 (records). Cenovus shut Rush Lake 1 and 2 on 9 May 2025 after a casing failure in a steam injection well on P-pad caused an uncontrolled release to surface (public). Operations restarted from 2 December 2025 with the approval of Saskatchewan's Ministry of Energy and Resources, and the failed P-pad is to be permanently abandoned (public). The newest pad, P007, came on production on 13 March 2026 (records).
3. Well pair development
Rush Lake carries 90 wells across ten pads: 36 producing, 37 injecting and 17 abandoned (records). The scheme averaged 24,600 bbl/d at an iSOR of 2.41 in 2022 and 21,800 bbl/d at 3.07 in 2024 (records). It fell to 6,800 bbl/d at 3.20 in 2025 and 4,100 bbl/d at 9.32 in 2026 to date, the highest annual iSOR in the Saskatchewan set (records). Oil ran below 800 bbl/d from June to December 2025 and steam was nil from June to November 2025; by June 2026 the scheme was back to 8,100 bbl/d on 8,700 m3/d of steam (records). All ten pads produced in the trailing twelve months, together averaging 2,100 bbl/d (records). P007 made 4,300 bbl/d from three producers in June 2026, over half the scheme, though its twelve-month average is 700 bbl/d (records). No per-pad recovery figure exists in our records. P005 averaged 88 bbl/d and A1 48 bbl/d per producing well, against 11 bbl/d at the eighteen-well P001, which stopped producing in November 2025 (records; per-well figures are pad rate divided by producing wells).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Husky built the commercial Rush Lake project for 10,000 bbl/d (public). Records show steam injection peaking at 10,800 m3/d in 2023, which bounds steam capacity from below, against 3,400 m3/d in 2025 and 6,000 m3/d in 2026 to date (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
P001 and P002, both on production from 18 July 2018, carry six abandoned wells each, the most of any Rush Lake pad (records).
Sandall, Cenovus Energy Inc., no provincial approval number in our records, SAGD, Twp 51 Rge 24 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Husky reported Sandall steaming in January 2014 with first production expected that quarter (public). The well list gives the SA and SB pads on-production dates of 29 November and 21 December 2013, and SC followed in September 2016 (records). One pad has been added inside the window, P004 on 1 March 2023, and it now carries two thirds of the scheme (records).
3. Well pair development
Sandall is 36 wells on four pads: 13 producing, 14 injecting and nine abandoned, three each on SA, SB and SC (records). The scheme rose from 3,500 bbl/d at an iSOR of 3.25 in 2022 to 5,400 bbl/d at 2.08 in 2024, held 5,300 bbl/d at 2.10 in 2025 and stands at 4,400 bbl/d at 2.41 in 2026 to date (records). All four pads produced through the trailing twelve months, averaging 4,800 bbl/d between them (records). P004 carried 3,200 bbl/d of that from three producers and three injectors, ahead of SC at 960 bbl/d, SB at 500 bbl/d and SA at 150 bbl/d (records). No per-pad recovery figure exists in our records. Per producing well that is 1,100 bbl/d at P004 against 190 bbl/d at SC, 170 bbl/d at SB and 74 bbl/d at SA (records; per-well figures are pad rate divided by producing wells).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Husky built Sandall as a 3,500 bbl/d project (public). Records show steam injection holding between 1,700 and 1,830 m3/d in every year from 2022, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime. Saskatchewan's Ministry of Energy and Resources approved a Cenovus expansion at Sandall, reported in September 2025 without scope or timing (public).
7. Anything else
Sandall gained 1,900 bbl/d between 2022 and 2024 on steam that did not move outside a 100 m3/d range, which is the whole of the fall in its iSOR over those years (records).
Senlac, Canadian Natural Resources Limited, no provincial approval number in our records, SAGD, Twp 40 Rge 26 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
SAGD at Senlac began in 1996 with three Phase A well pairs of 500 m (public). EnCana sold Senlac in November 2009 to Southern Pacific Resource Corp., which sold it to Canadian Natural on 3 December 2015 (public). The well list holds no well older than 20 December 2011, a Southern Pacific well on a three-well pad that stopped producing in June 2025, and the scheme predates it (records). The scheme now produces from one pad, P001, on production from 26 May 2020 (records).
3. Well pair development
Five of Senlac's 16 wells are suspended, the largest suspended share in the Saskatchewan set; the rest are five producers, four injectors and two abandoned wells, on three pads (records). The rate has moved by more than 40% between every pair of consecutive years in the record (records). It ran 1,900 bbl/d at an iSOR of 3.37 in 2022, 690 bbl/d at 4.74 in 2023, 2,100 bbl/d at 3.47 in 2024, 3,500 bbl/d at 3.02 in 2025 and 1,700 bbl/d at 4.51 in 2026 to date (records). Only P001 produced during the trailing twelve months, averaging 2,500 bbl/d, 620 bbl/d for each of its four producers (records; the per-well figure is pad rate divided by producing wells). No per-pad recovery figure exists in our records. The other two pads have stopped, P003 in April 2023 and the 2011 pad in June 2025, and all three of P003's wells are suspended (records). Two producers and two injectors added to P001 in April and May 2024 made 71% of Senlac's 2025 oil (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. EnCana described the plant in 2003 as three 14.65 MW boilers generating 2,000 m3/d of wet steam, scrubbed to 1,550 m3/d of injection-quality steam (public). Records show steam injection of 1,700 m3/d in 2025 against 520 m3/d in 2023, so the 2025 figure bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime. The reservoir is the Dina/Cummings, a thin channel sand about 750 m deep holding 12° API oil, with bottom water under parts of the field (public).
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
Steam and oil rise and fall together at Senlac in every year of the record (records).
Spruce Lake, Cenovus Energy Inc., no provincial approval number in our records, SAGD, Twp 53 Rge 21 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
In August 2019 Husky scheduled three Spruce Lake projects, Central for the second half of 2020, North for about the end of 2020 and East for about the end of 2021 (public). The first two pads in our records, P001 and P003, came on production on 12 June 2020 (records). Three pads came on in 2022, in March, June and July, and a sixth, P006, on 1 June 2025 (records).
3. Well pair development
Spruce Lake carries 93 wells on six pads: 40 producing, 41 injecting and 12 abandoned, eight of the abandoned wells on P001 (records). The scheme has grown in every year of the record, from 10,100 bbl/d at an iSOR of 3.87 in 2022 to 22,600 bbl/d at 3.04 in 2024 (records). The 2026 figure to date, 27,400 bbl/d at 2.74, is the highest annual rate of any Saskatchewan scheme in this document (records). All six pads produced through the trailing twelve months, averaging 26,000 bbl/d between them (records). The three pads that came on in 2022 carry three quarters of that, P004 at 6,600 bbl/d, P005 at 6,500 bbl/d and P002 at 6,300 bbl/d, with P001 at 3,900 bbl/d and P003 at 910 bbl/d (records). Per producing well that is 1,100 bbl/d at P002, 830 bbl/d at P004 and 810 bbl/d at P005, against 550 bbl/d at P001 and 110 bbl/d at P003 (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. P006, a year into production, averaged 1,700 bbl/d over the trailing twelve months, 570 bbl/d for each of its three producers (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection rising from 6,200 m3/d in 2022 to 11,900 m3/d in 2026 to date, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime. Saskatchewan's Ministry of Energy and Resources approved a Cenovus expansion at Spruce Lake, reported in September 2025 without scope or timing (public).
7. Anything else
P001 and P003 came on production on the same day and now differ by a factor of five in rate per producing well (records).
Tangleflags, Canadian Natural Resources Limited, no provincial approval number in our records, hybrid steam recovery, Twp 52 Rge 25 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
The first horizontal producer at Tangleflags North made 2.5 million bbl between 1988 and 1998, and by 2001 the project had 13 producing wells served by vertical injectors (public). Canadian Natural took the project with Sceptre Resources, whose holders voted in August 1996 to exchange their shares for Canadian Natural's (public). The well list holds no well older than an injector dated 15 July 1992, and the scheme predates it; four more pads came on between September 1995 and December 1996 (records). The newest pad, P005, came on production on 14 January 2017, and nothing has been added since (records).
3. Well development
Our records class Tangleflags as hybrid, matching its horizontal producers and vertical injectors, so the unit here is wells per pad (records; public). The scheme is 31 wells across fourteen pads: 20 producing, six injecting and five suspended, and seven producing pads carry no injector (records). The scheme has declined in every year of the record, from 950 bbl/d at an iSOR of 6.37 in 2022 to 830 bbl/d at 7.79 in 2024 (records). It stands at 680 bbl/d at 8.86 in 2026 to date, the highest iSOR of any Saskatchewan scheme here bar Rush Lake's 2026 figure (records). Ten pads produced during the trailing twelve months, averaging 720 bbl/d between them, which makes Tangleflags the smallest producer in the Saskatchewan set (records). The three-well pad at 7A15-23-52-25 leads at 180 bbl/d, a quarter of the scheme, ahead of the four-well P001 at 160 bbl/d (records). No per-pad recovery figure exists in our records. Per producing well that is 59 bbl/d and 40 bbl/d, and the lowest active pad, one of the two called MURPHY, runs a single producer at 6 bbl/d (records; per-well figures are pad rate divided by producing wells).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Records show steam injection between 960 and 1,030 m3/d in every year from 2022, flat while the rate fell, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime.
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime.
7. Anything else
Two pads share the name MURPHY, and four of the fourteen pad entries are single wells (records). Tangleflags is the one scheme in this set where steam has held flat through a continuous decline, so its iSOR has risen by 2.49 across the record without any change in injection (records).
Vawn, Strathcona Resources Ltd., no provincial approval number in our records, SAGD, Twp 47-48 Rge 19 W3, Saskatchewan.
Decks: none; Saskatchewan has no performance-filing regime. Records (Petrinex wells and production) to June 2026; public history where cited.
2. Project history
Husky sanctioned Vawn in January 2014 for first oil in 2016 (public), and its VA and VB pads came on production on 1 May 2016 (records). Vawn passed to Cenovus with Husky in January 2021, and Strathcona Resources announced on 1 December 2025 that it had closed its purchase of Vawn from Cenovus (public). Two pads came on before that sale, P004 in September 2019 and P003 in January 2022, and a fifth, P005, started on 1 April 2026 (records).
3. Well pair development
Vawn carries 83 wells on five pads: 39 producing, 29 injecting and 15 abandoned (records). The scheme fell in every year from 8,400 bbl/d at an iSOR of 3.52 in 2022 to 5,300 bbl/d at 4.42 in 2025 (records). 2026 to date is back to 6,300 bbl/d but at 4.96, the worst ratio in its record (records). All five pads produced in the trailing twelve months, averaging 6,000 bbl/d between them (records). P003 carried 3,600 bbl/d of that, 60% of the scheme from seven producers and seven injectors, while VB carried 1,100 bbl/d and VA 150 bbl/d (records). Per producing well the spread runs from 510 bbl/d at P003 to 180 bbl/d at P004, 140 bbl/d at VB and 11 bbl/d at VA (records; per-well figures are pad rate divided by producing wells). No per-pad recovery figure exists in our records. P005 entered the series in May 2026 and made 1,900 bbl/d from its five producers in June 2026 (records).
4. CPF
Not filed; Saskatchewan has no performance-filing regime. Strathcona gives Vawn a nameplate of about 10,000 bbl/d against a peak of about 12,000 bbl/d (public). Records show steam injection falling from 4,700 m3/d in 2022 to 3,700 m3/d in 2025 and then rising to 5,000 m3/d in 2026 to date, the highest in the record, which bounds steam capacity from below (records).
5. Reservoir
Not filed; Saskatchewan has no performance-filing regime. Strathcona puts about 48 MMbbl of remaining recoverable resource at Vawn in the Lloydminster and Waseca formations (public).
6. Future development plans
Not filed; Saskatchewan has no performance-filing regime. Strathcona plans to join the Vawn and Edam plants, two kilometres apart, by a short pipeline from 2027 (public).
7. Anything else
The 2026 recovery of 1,000 bbl/d came with 1,300 m3/d more steam, which is why the iSOR worsened in a year when the rate improved (records). VA and VB came on the same day and now differ by a factor of thirteen in rate per producing well (records).
Narrows Lake, Cenovus Energy Inc., approval 11798 (11798N in the well list), SAGD, Athabasca region, Alberta.
Decks: none filed as of September 2026; records to June 2026.
2. Project history
Narrows Lake's first wells came on production on 26 April and 2 May 2025, on the X05 and X06 pads, and volumes enter our monthly series in July 2025 (records). Cenovus sanctioned the scheme as a tie-back to its Christina Lake plant rather than a stand-alone development, with first oil guided for 2025 (public). X02 followed on 25 July 2025 and X01 on 2 December 2025, so all four producing pads started inside eight months (records). Approval 11798 is its own scheme and is not part of Cenovus Christina Lake 8591 (records).
3. Well pair development
Narrows Lake carries 103 wells across five pads: 33 producing, 31 injecting, 37 observation and two pending (records). Production over the six recorded months of 2025 averaged 19,000 bbl/d at an iSOR of 3.76, and 2026 to date averages 58,100 bbl/d at 2.14 (records). Four pads produced during the trailing twelve months, averaging 38,400 bbl/d between them (records). X06 carried 15,000 bbl/d of that, 39% of the scheme, ahead of X02 at 10,700 bbl/d and X05 at 9,900 bbl/d (records). Per producing well that is 1,500 bbl/d at X06, 1,300 bbl/d at X02 and 1,200 bbl/d at X05 (records; per-well figures are pad rate divided by producing wells). X01, producing only from January 2026, averaged 2,700 bbl/d over the twelve months and made 9,500 bbl/d in June 2026 (records). No per-pad recovery figure exists in our records. The fifth pad, 11798-P001, holds one injector that has taken steam since July 2025 and six observation wells, and has produced nothing (records).
4. CPF
No Directive 054 presentation has been filed for this scheme as of September 2026. Cenovus has said the scheme produces to the Christina Lake plant through a tie-back rather than to a plant of its own (public). Records show steam injection averaging 19,800 m3/d in 2026 to date against 11,400 m3/d over the six recorded months of 2025, which bounds steam capacity from below (records).
5. Reservoir
No Directive 054 presentation has been filed for this scheme as of September 2026. The AER well list places the scheme in the Athabasca oil sands area, Wabiskaw-McMurray deposit (records).
6. Future development plans
No Directive 054 presentation has been filed for this scheme as of September 2026.
7. Anything else
Pad labels X01 to X06 carry the names in the well data, while 11798-P001 is our records' own numbering, and no pad is numbered X03 or X04 in our data (records).
Pike, Canadian Natural Resources Limited, approval 12301 (12301F in the well list), SAGD, Athabasca region, Alberta.
Decks: none filed as of September 2026; records to June 2026.
2. Project history
Pike's first wells came on production on 13 August 2025, on the PK101 pad, and volumes enter our monthly series that September (records). PK102 followed on 19 December 2025 and entered the series in the same month (records). Seven further pads hold one abandoned well each and carry neither a date nor any production in our records (records).
3. Well pair development
Pike carries 62 wells across nine pads: 19 producing and 20 injecting on PK101 and PK102, sixteen observation wells and seven abandoned (records). Production over the four recorded months of 2025 averaged 2,600 bbl/d at an iSOR of 6.77, and 2026 to date averages 35,200 bbl/d at 1.90 (records). PK101 averaged 15,700 bbl/d over the trailing twelve months, 1,300 bbl/d for each of its twelve producers (records; the per-well figure is pad rate divided by producing wells). No per-pad recovery figure exists in our records. PK102, producing only from December 2025, averaged 2,700 bbl/d over the twelve months and made 11,700 bbl/d from seven producers in June 2026 (records).
4. CPF
No Directive 054 presentation has been filed for this scheme as of September 2026. Records show steam injection averaging 10,700 m3/d in 2026 to date against 2,800 m3/d over the four recorded months of 2025, which bounds steam capacity from below (records).
5. Reservoir
No Directive 054 presentation has been filed for this scheme as of September 2026. The AER well list puts every Pike well in the Wabiskaw-McMurray deposit of the Athabasca oil sands area (records).
6. Future development plans
No Directive 054 presentation has been filed for this scheme as of September 2026.
7. Anything else
Pike's iSOR fell by 4.87 between its four months of 2025 and 2026 to date, the steepest fall among the nineteen schemes here (records). PK101 and PK102 carry the names in the well data, six of the abandoned-well pads are labelled by location and one is our records' own numbering (records).