Regional campaigns, from heavy oil to storage and injection integrity
Research reviewed 9 October 2026. All areas remain visible with locks. Each opens with its assigned tier; existing named milestones still control progression. A Lloydminster producer counts as one of the two distinct Level 1 areas. Jeanne d’Arc producers count toward the two Level 6 offshore producers. The Saskatchewan storage contract and Brazeau-area injection contract never count as producers.
Level 1 — Lloydminster heavy oil
Two targets: Waseca and Sparky. Both are Lower Cretaceous Mannville sandstone packages. Waseca varies laterally in texture and composition; Sparky can be replaced by erosional silt/shale fill. Weak sands, aquifer isolation and uncertain net pay shape the scenarios. A paid lift and sand-handling package precedes the sustained production screen; heavy oil receives a lower simulated valuation than the generic light-oil model.
The Swan Hills target is mainly limestone, with local dolomitization. Coarse reef and fore-reef facies may preserve pores while lagoonal micrite is tight; Waterways shale/micrite surrounds the reef. Hard-rock wear and fracture-related losses are relevant drilling mechanisms. The sour-fluid-readiness decision is a precaution before penetration, not an invented H₂S analysis.
Parkman and Turner are different Cretaceous targets. Parkman records regression/transgression; Turner is a sandy interval in the Carlile marine succession. The game selects a low-permeability Turner pilot requiring horizontal contact and staged stimulation. Coal-bearing younger cover, shale balling and a local pressure review create three separate drilling decisions.
An onshore campaign targets Tyonek channel gas and Hemlock conglomeratic oil reservoirs. Fluvial sand, mud and coal create variable continuity; deeper coarse clasts add abrasion. Coal bands are placed in suitable Tyonek/Beluga-bearing cover, not arbitrarily inside every reservoir. This location does not reuse North Slope permafrost or offshore ice hazards.
This fictional contractor campaign drills into Prairie Evaporite salt and then models controlled solution mining, a brine-handling route, sonar geometry, integrity evidence and purchased-gas inventory. It is not a naturally cavernous carbonate reservoir, not a gas discovery and not affiliated with SaskEnergy or TransGas. Saskatchewan requires authorization before a storage project proceeds and cites CSA Z341 for design, construction, testing, operation, maintenance and repair. The game therefore makes authorization, independent review, geometry and repair/retest explicit gates.
SaskEnergy’s public description says water dissolves Prairie Evaporite salt, brine is removed and compressed natural gas is stored for seasonal demand. The game’s pressures, geometry, unitless inventory, timing and economics are simulated rather than operational instructions. Cushion and working gas are purchased inventory; withdrawal cannot manufacture gas or earn oil-production revenue.
This fictional contractor scenario appraises a depleted Nisku dolomite compartment for Class III acid-gas disposal. It is not a replica of a real well, a production project or an operating approval. The 2008 AGS study places the Nisku Q analogue at about 3,384 m and describes porous Zeta Lake dolomite with lateral carbonate/shale barriers, Calmar–Graminia and Wabamun cover, and Ireton shale below. It also identifies improperly completed or abandoned wells as potential artificial leakage paths. The game therefore requires a complete offset inventory, containment evidence, repair and monitored retesting rather than treating caprock as a blanket guarantee.
Current Alberta requirements supersede the historic approval context. AER Directive 051 (July 2026) addresses injection/disposal well classification, completion, logging, testing and monitoring; Directive 065 (March 2026) requires the resource-scheme application, and the AER’s Class III page identifies acid and sour gas as Class III fluids. The game’s compatibility, mechanical-integrity, injectivity and communication screens are deliberately unitless. It gives no real pressure, rate, composition or field-performance instruction and awards no oil/gas revenue or producer unlock credit.
Kee Scarp is a Devonian carbonate reef in the Ramparts succession, encased by shale. Reef-edge correlation and connected fractures matter; fractures can aid reservoir flow or take drilling fluid. This separate established-field analogue does not inherit the Mackenzie Delta game's blanket pipeline-wait condition. Remote logistics remain part of its operating challenge.
This Grand Banks appraisal is explicitly separate from the deeper-water Flemish Pass. The two Hibernia-inspired targets are Ben Nevis–Avalon and Hibernia sandstone. The operator’s development-plan amendment describes Ben Nevis–Avalon fluvial/estuarine and shoreface deposits with variable continuity and quality, heavily compartmentalized by faulting. It describes stacked Hibernia fluvial sandstones with internal shale baffles that affect vertical communication. These facts inform the game’s structure and evidence gates; its fault map, depth, pressure response, contact, costs and payout are synthetic.
The operator’s milestones show why thickness is not a discovery rule: O-35 encountered oil-bearing Ben Nevis–Avalon while Hibernia was water-bearing at that location, and G-55 was dry despite thick Ben Nevis–Avalon sandstone beside the Murre Fault. The fictional player must therefore tie the fault block, acquire local pressure stations and sealed fluid samples, and prove connected deliverability. A water-bearing or uncharged block can be appraised and secured, or the other drilled interval can be evaluated, without a producer award. Offshore iceberg surveillance and long-section hole cleaning remain regional operating scenarios. Displayed depth starts at the seabed; water depth is abstracted.
Realgrunnen and Kobbe sandstone targets sit in a segmented structure with thin gas caps. The actual analogue is relatively shallow; the game does not make all difficult offshore wells ultra-deep. Gas/water contact uncertainty, compartment depletion and subsea/weather readiness drive the challenge. Numbers in this game are not Goliat operating data.
A resource-exploration pilot, not an asserted new discovery. The 2026 USGS assessment identifies Ordovician tight gas in the Illizi Basin within a Silurian petroleum system. Ancient clastic reservoirs can have poor matrix permeability and abnormal pressure. The game adds hard-sand wear, water/logistics planning, horizontal contact and a staged-completion flow test. Assessment resources are not proved reserves.
Ignoring pressure evidence enters the kick-response chain. Ignoring a loss warning requires recovery; poor shale practice can create a persistent balling penalty. Aggressive drilling through abrasive rock costs bit condition. Ignored correlation uncertainty reduces the conventional production-test chance. Paying for a review manages uncertainty; it does not guarantee a commercial reservoir.