The Life of an Alberta Oil Well: From Licence to Reclamation

Before the drill: rights, geology and the licence

A well starts on paper. Before any equipment moves, a company needs the right to produce the oil, evidence that oil is there, a spot on the surface and a licence. The AER regulates every energy project through four stages: initiate, construct, operate and close ^[10].

Mineral rights

In Alberta the oil usually belongs to the public, not the landowner. Companies lease Crown rights at public offerings or negotiate private leases with freehold owners, as our guide Who owns Alberta's oil? explains. The licence ties back to those rights: the deepest formation a well is licensed to reach must be one the company has the right to produce, and drilling more than 15 metres below its base requires the mineral owner's permission ^[11].

Geology and seismic

Geologists pick targets from the records of nearby wells, rock cores and seismic surveys. A seismic crew sends energy into the ground, either from explosives loaded into shot holes typically 6 to 15 metres deep or from truck-mounted vibrators (vibroseis), and records the echoes with geophones. Most operators now run three-dimensional (3D) surveys, laying out a grid of source and receiver lines rather than a single 2D line ^[12].

Seismic work needs an exploration licence and AER approval of each program under the Exploration Regulation and Exploration Directive; the AER estimates about 10 business days per decision ^[13]. In settled areas, residents within 400 metres of a seismic line must be notified at least 48 hours before work starts, and the company must obtain written consent to enter private land. If a landowner refuses, the operator has no appeal (carbon storage projects are the exception), and the maximum fine for exploring without consent is $25,000 ^[12].

Well spacing

Under the Oil and Gas Conservation Rules the standard drilling spacing unit is one quarter section for an oil well and one section for a gas well, and an oil well's target area must sit at least 100 metres inside the boundaries of its quarter section ^[14]. Since April 9, 2021, the rules no longer prescribe a fixed number of wells per unit; there is no limit on well density unless the AER orders one ^[15][14]. Contiguous units under common ownership can be developed as a block, constrained only by the target area along the block's outer edge, which is what allows a single horizontal well to run under several quarter sections ^[14].

Participant involvement and the licence application

Directive 056 sets the requirements for well, pipeline and facility applications. Before filing, an applicant must hold a business associate code from Petrinex (the industry's shared reporting system), be declared an eligible licensee under Directive 067, and complete a participant involvement program ^[11].

The size of that program depends on the well's category, which is set by its hydrogen sulphide (H2S) content, release rate and proximity to the public ^[11]. For a sweet well (no H2S), the company must personally consult landowners and occupants of the well site and access road and residents within 0.2 kilometres, or 0.3 kilometres for a single oil well with continuous flaring. It must also notify local authorities, holders of Crown dispositions, urban authorities within 1.5 kilometres and nearby airports ^[11]. Sour wells require wider consultation, out to the emergency planning zone for the most hazardous categories ^[11]. Involvement continues through the life of the development ^[11], and anyone who may be directly and adversely affected can file a statement of concern ^[10]. These requirements apply to First Nations and Métis communities that may be affected ^[11], alongside the Crown's own consultation process described in our ownership guide.

Applications go through OneStop, the AER's application review system. It runs a baseline automated check on every application, and lower-risk applications can be approved automatically "within minutes"; others are routed to AER technical staff ^[16]. A well licence can be issued for a one-year or two-year term, and it expires if construction has not started by then ^[11]. New well data can be held confidential for one year from the date drilling finishes ^[11].

On private land the company negotiates a surface lease with the landowner; on public land it needs AER approval under the Public Lands Act ^[10].

How many wells?

The AER issued 6,055 well licences in 2025, about 6% more than the 5,701 issued in 2024. Of those, 2,893 were for bitumen, 1,877 for crude oil and 1,285 for natural gas; 98% of the crude oil licences and 99% of the gas licences were for horizontal wells ^[1]. Licensing slowed in early 2026: the AER issued 1,118 licences in the first quarter, about 20% fewer than a year earlier ^[17].

A licence is not a well. The province counted about 8,419 wells spudded (started) in 2025, 63% of them in the oil sands, and notes that spud data are revised after the fact ^[1]. The AER's own drilling statistics recorded 9,592 successful wells and legs drilled in 2025, totalling about 26.7 million metres of hole ^[18][19]. The series define a "well" differently, so check which one a headline uses.

Building the lease and bringing in the rig

Once the licence is in hand, a construction crew builds the lease: the flat, gravelled pad the rig will stand on, plus an access road. Topsoil is stripped and stockpiled first, because Alberta's reclamation rules require companies to salvage, store and later replace soil ^[20]. The lease must also have somewhere to hold drilling waste, such as tanks, sumps or bermed storage built to Directive 050 ^[21]. Many modern leases are multiwell pads: the AER notes that drilling several wells or lateral legs from one pad spreads the cost and lowers the cost per unit of output ^[22]. Where well control requires it, a short conductor pipe is set 20 to 30 metres into competent ground and cemented along its full length before the rig drills deeper ^[23][4].

The drilling rig and its crew

A land rig is a hoist wrapped around a pumping system. The mast carries the pulleys; the drawworks, a powered cable drum, raises and lowers the drill string and controls the weight on the bit; a top drive turns the pipe. Mud pumps circulate drilling fluid, shale shakers screen out cuttings, and the blowout preventer (BOP) stack on the wellhead can seal the well if pressure gets out of control, to equipment standards in Directive 036 ^[24].

The crew runs the rig around the clock. Alberta's career information service describes the positions from junior to senior ^[25]:

• Leasehand: entry-level housekeeping, such as clearing ice from walkways and putting tools away.
• Floorhand: works on the rig floor, operating power tongs to connect pipe and catching circulation samples.
• Motorhand: maintains engines, transmissions, generators and hydraulic systems.
• Derrickhand: operates and maintains the drilling fluid system and pumps, and climbs the mast to handle pipe when it is pulled from the hole ^[26].
• Driller: runs the drawworks, rotary equipment and pumps and supervises the crew on shift.

Above them, the rig manager (often called the toolpush) is in complete charge of the rig, and the derrickhand's platform sits about 25 metres above the floor; most crews have six primary positions and work 12-hour shifts, typically 14 days on and a week off ^[26]. The AER requires the licensee to have its own on-site representative plus a rig manager, and the driller must hold a valid blowout prevention or well control certificate ^[24]. Alberta also offers a Rig Technician apprenticeship for rig crews ^[25].

Rig counts

Using Baker Hughes data, Alberta's government reports that the province averaged 129 active drilling rigs per week in 2025, about 3% fewer than the 132 of 2024, while Canada as a whole averaged 177 ^[1]. Activity was higher in the first quarter of 2026, when Alberta averaged 155 rigs per week ^[17]. Drilling is seasonal: it drops sharply each spring as operators avoid the environmental damage that moving heavy equipment can cause during the thaw ^[1].

The Canadian Association of Energy Contractors (CAOEC) says its members operate 365 drilling rigs and 693 service rigs. It counted 5,548 wells drilled in Canada in 2025 using 58,256 rig operating days, and forecasts 5,709 wells in 2026; each active drilling rig supports about 21 direct jobs ^[27].

Drilling: spud, surface casing and well control

Drilling starts with the spud, the moment the bit first turns in the ground ^[1]. The AER summarizes the process: a bit on the end of drill pipe cuts into the rock, drilling fluid is pumped down to control pressure and carry the cuttings up, and at planned depths the crew runs steel casing and cements it in place ^[28].

The surface hole and groundwater

The first section drilled is the surface hole, and its main jobs are well control and groundwater protection. Directive 008 sets the minimum depth of surface casing: it is sized so that a 3 m³ influx of gas or fluid (a "kick") can be circulated out without fracturing the rock at the casing shoe, and it must reach at least 25 metres below the deepest water well within 200 metres ^[23]. Surface casing set shallower than 650 metres true vertical depth needs no separate AER application ^[23].

Protection does not rely on surface casing alone. The AER's base of groundwater protection marks the bottom of formations likely to hold nonsaline water (under 4,000 mg/L of total dissolved solids), and it is mapped to a maximum depth of 600 metres ^[3]. Directive 009 requires surface casing to be cemented along its full length, and where the surface casing is set shallower than 180 metres or shallower than the base of groundwater protection, the next casing string must also be cemented all the way to surface ^[4]. Oil-based drilling fluids and other potentially toxic additives are banned while drilling above the base of groundwater protection ^[24].

Blowout prevention

A blowout is an uncontrolled flow of oil, gas or water that the wellhead and BOP equipment cannot stop ^[29]. Directive 036 classifies wells by depth, from class I (no surface casing) through class VI (deeper than 6,000 metres true vertical depth), and scales the required BOP equipment to match ^[24]. The BOP is pressure tested before the crew drills out of each casing shoe. Each crew must run a BOP drill before drilling out the surface, intermediate or production casing shoe and then every seven days on the same well, and if a crew is not properly trained, operations must stop until it is ^[24].

Drilling mud and waste

Drilling fluid, usually water with additives, cools the bit, lifts cuttings and holds back formation pressure ^[28]. Used mud and cuttings are managed under Directive 050, which allows land disposal methods such as landspraying, pump-off and mix-bury-cover, with soil limits aligned to Alberta's Tier 1 remediation guidelines so that sites can later be reclaimed ^[21]. Waste returned to land must meet the AER's toxicity thresholds ^[28]. Licensees must file summary drilling data with the AER within 30 days ^[29].

Steering sideways: directional and horizontal wells

Most Alberta wells today start vertical, bend through a curve and then run sideways through the target rock, shaped like the letter L ^[30]. For the AER's statistics, a well counts as horizontal once its path reaches 80 degrees from vertical ^[18]. Natural Resources Canada counts more than 10,000 Alberta wells completed with horizontal drilling and multistage fracturing since 2008 ^[31]; by 2024, more than 99% of new crude oil wells were horizontal ^[2].

The lengths have grown quickly. Dividing the AER's 2025 totals by well counts gives a rough average of about 3,300 metres of hole per horizontal crude oil development well and about 6,000 metres per horizontal gas well, measured along the wellbore ^[18]. CAOEC's 2025 figures work out to about 10.5 rig operating days per well across Canada ^[27]. Depths and lengths vary by play:

The Duvernay shows how fast designs have changed. In the first quarter of 2024 Veren drilled what was reported as the longest onshore well in Canadian history: 9,017 metres of measured depth, including about 5,400 metres of lateral, in a single bit run ^[33]. Whitecap, now the largest Kaybob Duvernay operator by the Daily Oil Bulletin's account, planned 4,000-metre laterals on its next pads ^[33] and reports net pay of 50 to 70 metres in parts of its acreage ^[39].

The Clearwater represents a different design. Instead of one long lateral that is cased and fractured, operators drill open-hole multilateral wells: several legs branch from one vertical wellbore to contact as much of the thin, porous sandstone as possible ^[38]. The AER counts each branch as a separate "drill leg" ^[29]. The Alberta Geological Survey reports average legs of about 1,500 metres spaced about 45 metres apart, and says Clearwater production grew from almost nothing in 2017 to about 150,000 barrels per day in 2025, with heavy oil multilaterals as a group reaching about 230,000 barrels per day ^[38]. Industry data show 1,142 Clearwater legs drilled in the first half of 2025 alone, with the Mannville's Waseca and Sparky members adding 1,218 more ^[40].

Casing, cement and well integrity

A finished well is a set of nested steel pipes, each cemented to the rock. From the outside in:

• Conductor pipe: a short, large pipe set 20 to 30 metres deep where needed for well control ^[23].
• Surface casing: the first full string, protecting groundwater and anchoring the wellhead and blowout preventer ^[23].
• Intermediate casing: used on deeper or more complex wells to seal off troublesome zones, such as high-pressure or unstable rock, before drilling on; Directive 010 treats protective intermediate casing as its own category ^[41].
• Production casing or liner: the final string, run through the target zone so it can later be perforated; Directive 010 sets separate design factors for it ^[41].

Directive 010 sets minimum design factors for burst, collapse and tension, including loads from fracturing and temperature over the well's life ^[41]. Directive 009 governs the cement. The cement volume must be based on a caliper log of the hole plus at least 20% extra, blends with fillers must reach 3,500 kPa of compressive strength within 48 hours, and centralizers must hold the casing in the middle of the hole at productive zones and at least every 50 metres ^[4]. The required height of cement behind intermediate and production casing is set by township; in one example it is 100 metres above the top of the Viking Formation or any shallower zone that might hold hydrocarbons ^[4]. If cement does not return to surface when it should, the operator must run a log to find the cement top and file it, with a repair plan, within 60 days of rig release ^[4]. Wells licensed to produce bitumen must use thermal cement that keeps its strength above 360°C ^[4].

Cement and steel are the barriers that keep fluids in the zone they came from. Directive 087, most recently updated on August 10, 2026, sets the testing and repair rules for when those barriers leak ^[42]. It distinguishes a surface casing vent flow (gas or liquid escaping up the surface casing annulus) from gas migration (flow detectable at surface outside the outermost casing). Every well must be tested for vent flow within 90 days of rig release, and leaks classed as "serious" must be repaired on a deadline ^[42].

Completion: perforating and hydraulic fracturing

When the drill bit reaches total depth, the AER says, the operation switches to completion and the drilling rig is normally replaced with a completion rig ^[28]. Completion connects the wellbore to the reservoir. In a cased well, perforating guns shoot holes through the production casing and cement into the rock. In tight rock, that is not enough, and the well is hydraulically fractured.

Multi-stage fracturing

Hydraulic fracturing pumps fluid down the well at enough pressure to crack the rock, carrying a proppant, usually sand, that holds the cracks open so oil and gas can flow ^[30]. The AER says the technique has been used in more than 180,000 Alberta wells since the 1950s ^[30]. In a modern horizontal well, the lateral is fractured in many separate stages from the toe back toward the heel. The scale has grown with lateral length: an average Montney well used about 5,000 tonnes of proppant in recent years, and some areas approached 8,000 tonnes ^[35].

Directive 083 governs the subsurface side of fracturing ^[43]. Before a job, the operator must define a fracture planning zone, identify every offset well within it, assess each one's integrity and risk, prepare well-control plans for offset wells at risk of communication, and notify their licensees, including the Orphan Well Association when an offset well is an orphan ^[43]. Fracturing is banned between the surface and 100 metres below the top of bedrock, and within a 200-metre radius of a water well at depths within 100 metres of the water well's total depth; operations less than 100 metres below the base of groundwater protection need a specific risk assessment ^[43]. The AER also requires fracturing fluids used above the base of groundwater protection to be nontoxic and prohibits releasing any fracturing fluid into a natural water body ^[30].

Water

In 2024, Alberta operators used about 30 million m³ of make-up water for fracturing; 99% of the make-up water was nonsaline, and only about 2% of all fracturing water was recycled ^[5]. Fracturing operators used about 20% of their nonsaline water allocation that year, and wells fractured in 2024 used about 0.65 barrels of nonsaline water for every barrel of oil equivalent they produced ^[5]. Because the water is used up front, that ratio falls to about 0.08 for the average fractured well after ten years of production ^[44]. Operators must report where their fracturing water came from, including its location, water body or geologic zone and supplier ^[29].

Disclosure

Under Directive 059, a licensee must report each fracture job's fluid composition, volumes and water sources within 30 days ^[29]. The AER treats the composition data as public; companies may withhold ingredients they identify as trade secrets, but the AER can demand full details at any time ^[29]. The data appear in an AER dashboard, updated daily, that replaced the old FracFocus.ca reports ^[45].

Induced seismicity

Fracturing can trigger earthquakes. After persistent seismic activity near Fox Creek, including events above magnitude 4.0 in January 2015, the AER issued Subsurface Order No. 2 on February 19, 2015 ^[46]. It requires Duvernay operators in the area to assess seismic risk, monitor during fracturing and follow a "traffic light": report any event of magnitude 2.0 or greater and invoke a response plan, and stop fracturing at magnitude 4.0 or greater until the AER consents to restart ^[46]. It was reissued as Subsurface Order No. 2A on November 6, 2024 ^[47]. A stricter order for the Red Deer area, issued December 9, 2019, sets the reporting threshold at magnitude 1.0 and the stop threshold at 3.0 and bans Duvernay fracturing within 5 kilometres of the Dickson Dam ^[48][47]. A third order covers the Brazeau area ^[47].

Flowback and first tests

After fracturing, the well flows back fluid and sand until it cleans up. Directive 060 limits flaring, incinerating and venting during cleanup, completion and testing to 72 hours per zone for crude oil and gas wells, and expects operators to test into pipelines ("in-line testing") where possible ^[49]. The AER calls an accurate initial pressure "probably the most important pressure taken in a well," and Directive 040 sets when initial and annual pressure tests are required ^[50].

Production: flowing wells, artificial lift and measurement

Early in its life, a well may flow on its own, pushed by reservoir pressure. As pressure falls, most wells need help. Artificial lift adds energy to lift fluids when the reservoir can no longer do it economically, and SLB notes that the great majority of the world's roughly one million active oil wells use some form of it ^[51]. The main types are:

• Beam pumps (pumpjacks): a motor rocks a beam that moves a string of sucker rods up and down, working valves in a downhole pump. They are reliable, easily serviced and among the cheapest options, which makes them common on marginal land wells ^[51].
• Progressing cavity pumps (PCPs): a corkscrew-shaped rotor turning inside a stator, usually driven by rods from surface ^[51]. They cope well with thick, sandy heavy oil ^[52].
• Electric submersible pumps (ESPs): stacked centrifugal pump stages driven by a downhole electric motor on a power cable, suited to high fluid volumes ^[51].
• Gas lift: gas injected into the tubing lightens the fluid column so reservoir pressure can push it to surface ^[51].
• Plunger lift: a free-travelling piston, driven by the well's own gas pressure, that periodically pushes accumulated liquid out of gassy wells ^[51].

Alberta's heavy oil shows how lift technology can change a play. Progressing cavity pumps arrived in the 1980s and won wide acceptance in the 1990s; they removed the rate limits of beam pumps, and operators began deliberately producing sand with the oil, lifting well productivity above the traditional 4 to 5 m³ per day ^[52]. Licensees must report each well's artificial lift details, including pump type ^[29].

Separation and measurement

At surface, the well stream goes to a battery, the separators and tanks that split oil, gas and water. Every volume that affects royalties is measured to standards set in Directive 017, the latest edition of which took effect on September 28, 2026 ^[53]. Those standards trace back to a 1972 board decision that set pool-level accuracy targets of 2% for oil, 3% for gas and 5% for water, and sales points face the strictest requirements because they set royalties ^[53]. Where several wells share a battery, each well's share is worked out from regular well tests: a well producing more than 30 m³ of oil a day must be tested three times a month, while a stripper well producing 2 m³ or less needs one test per quarter ^[53].

The results flow monthly into Petrinex, a shared online database used by industry, the AER and the Ministry of Energy and Minerals. Operators report monthly, by a deadline usually between the 18th and 22nd of the month, and the data are used to calculate and verify royalties and to build the province's production statistics ^[54]. Alberta's conventional crude oil output was about 84,200 m³ per day (530,000 barrels per day) in 2024 ^[22].

Produced water does not disappear. Much of it is recycled into enhanced recovery schemes to maintain reservoir pressure ^[55]; the rest typically goes to disposal wells regulated under Directive 051, most recently updated on July 30, 2026 ^[56].

Maintenance, workovers and enhanced recovery

Pumps wear out, rods break, sand fills the wellbore and some oils deposit wax (paraffin) or mineral scale. A service rig, smaller than a drilling rig and crewed by floorhands, a derrickhand and an operator, pulls and runs tubing and rods to fix these problems ^[25]. CAOEC members operate 693 service rigs, which logged about 1 million operating hours in Canada in 2025 by the association's count ^[27].

A workover is a remedial job on a producing well intended to increase production. Examples include sand cleanouts, casing repairs, sidetracking around damage and plugging back to shut off a zone ^[57]. A scraper can remove deposits such as scale or paraffin from tubing or casing ^[58]. Operators report these "reconditioning" operations to the AER ^[29]. When a packer or casing fails an integrity test, Directive 087 generally requires repair and a passing retest within 90 days ^[42]. Some older horizontal wells are fractured again (refracs); any new fracturing falls under the same Directive 083 rules as the original job ^[43].

Enhanced recovery

Primary production can leave most of the oil in place: some Alberta heavy oil fields had recovered only 4% to 6% of their original oil before newer methods arrived ^[52]. Enhanced oil recovery (EOR) injects fluids to maintain pressure and push oil toward producing wells ^[55]. Water is the most common injection fluid. In 2024 Alberta had 853 EOR schemes, 679 of which injected water; together they used more than 185 million m³ of water, 94% of it recycled, to produce about 100 million barrels of oil equivalent ^[55]. Waterflooding has spread even to new plays: the Alberta Geological Survey reports significant recovery gains from waterfloods in the Clearwater since initial tests in 2021 ^[38]. Carbon dioxide is also used. The 240-kilometre Alberta Carbon Trunk Line, completed in 2020, carries captured CO2 to depleted oil reservoirs near Clive and has capacity for up to 14.6 million tonnes a year ^[59]; the CO2 is injected into the Clive reservoir both to produce more oil and for permanent storage ^[60]. EOR schemes need AER approval under Directive 065 ^[14].

Decline curves: why every well fades

Every well's production falls over time. As fluid is removed, reservoir pressure drops and less oil flows into the wellbore. In tight rock the effect is sharp: the Canada Energy Regulator notes that tight oil wells typically produce a large amount of oil in their first month and then decline quickly, so new wells must be added constantly just to hold production flat ^[61].

The AER builds these declines into its forecasts. Its 2025 outlook assumes that new horizontal crude oil wells lose between 32% and 56% of their output in the first year in most regions (14% in the northeast), with declines easing to between 1% and 10% a year by year 10 ^[6].

Source: AER forecast assumptions for new wells, Alberta Energy Outlook 2025 ^[6].

The best new wells also start high. The AER forecast that a new horizontal well in the Foothills Front would start at about 17.2 m³ per day (roughly 108 barrels per day) in 2025, compared with 6.4 m³ per day in Central Alberta ^[6]. The AER reports that more fracturing stages per well and multiple lateral legs have raised production and slowed declines ^[22]. Even so, it forecasts that Alberta's conventional crude oil output will peak around 2027 and then drift lower because new wells will not offset the decline of existing ones; that is a projection, not a certainty ^[22].

What does an operator watch? The oil rate against the expected decline curve, the water cut (share of water in the stream), the gas-oil ratio, pump performance and pressures from the tests required under Directives 017 and 040 ^[53][50]. A well that falls below its curve may need a workover; a well whose revenue no longer covers its operating costs heads toward suspension. Low-rate wells also pay lower royalties under Alberta's royalty framework, as our ownership guide explains.

Suspension, abandonment and reclamation

The last stages of a well's life can outlast the company that drilled it, so the rules for them are detailed.

Inactive and suspended wells

A well becomes inactive when it reports no production, injection or disposal for 12 consecutive months, or six months for a critical sour well ^[62]. Within 12 months of that date, the licensee must suspend it to Directive 013 standards ^[62]. The directive sorts inactive wells into low, medium and high risk. Low-risk wells, such as non-flowing oil wells with little H2S, need periodic pressure readings; medium-risk wells, such as flowing oil wells, must be plugged downhole and pressure tested at 7,000 kPa every three or five years; high-risk wells, such as critical sour and acid gas wells, face the strictest rules ^[62]. Depending on the method, the wellbore is filled with fresh water or a noncorrosive fluid, with the top two metres filled with a fluid that will not freeze ^[62]. A suspended well can be reactivated once its wellhead and equipment are inspected, serviced and pressure tested and the AER is notified ^[63]. Liability rules for inactive and orphan wells are covered in our ownership guide.

Abandonment: plugging, cutting and capping

Abandonment permanently seals a well; the AER's liability reports now call it decommissioning ^[64]. Directive 020, updated on July 27, 2026, sets the rules ^[65]. The company plans the job, cleans the wellbore, repairs any leaks, and isolates every oil and gas zone and groundwater zone with cement plugs so nothing can travel up the hole ^[9]. A common method is a permanent bridge plug set within 15 metres above the completed interval, pressure tested at 7,000 kPa for 10 minutes and capped with at least 8 vertical metres of class G cement or an approved alternative ^[65]. The well is then filled with fresh water or another noncorrosive fluid ^[9]. The well must pass tests for vent flow and gas migration before surface work begins ^[65][42].

Surface abandonment, the "cut and cap," must follow within 12 months of the downhole work. The casing strings are cut at least one metre below the final ground level (two metres in areas with deep tillage, drainage works or peat, or within 15 kilometres of an urban development), a vented cap is placed on top, and surface equipment and debris must be removed within 12 months ^[65]. The landowner and occupant must be told before the work begins ^[65]. Afterward, nothing may be built on top of an abandoned well, and Directive 079 requires a setback of at least 5 metres around it ^[66]. The AER says about 170,000 abandoned wells, 37% of all wells in the province, already exist ^[9].

Reclamation to equivalent land capability

Reclamation returns the surface to use. Alberta's standard is equivalent land capability, defined in regulation as land able to support uses similar to those it supported before the activity, though not necessarily identical ^[67]. The process includes removing infrastructure, a Phase 1 environmental site assessment (and a Phase 2 if contamination is suspected), remediation of any contamination, replacing soil, restoring drainage and revegetating ^[68]. The finished site is assessed against the province's reclamation criteria for its land type: forest, native grassland, cultivated land or peatland ^[68]. It can take many years, even decades, depending on the land and how much the soil was disturbed ^[20].

The company then applies through OneStop for a reclamation certificate, with professional sign-off and a copy to the landowner. The application is posted publicly for 30 days, and anyone directly and adversely affected can file a statement of concern ^[68]. A certificate lets the company end its surface lease ^[20]. It is not a final release: the company stays responsible for surface problems such as topography, vegetation, soil texture and drainage for 25 years and remains permanently responsible for contamination and any infrastructure left underground ^[68]. The AER audits reclaimed sites every year and can cancel certificates ^[68].

Closure by the numbers

The AER's most recent performance report covers 2024 ^[7]. That year licensees reported $900 million in eligible closure spending, 28% more than the required $700 million, and the industry-funded Orphan Well Association spent a further $119 million, for more than $1 billion in total ^[7]. In 2024, 6,271 wells and facilities were decommissioned and 3,817 were reclaimed ^[64]. The inactive well count fell from about 91,000 in 2021 to 78,000 in 2024, a 14% drop ^[7].

These quotas replaced the voluntary Area-Based Closure program (2019 to 2021), which encouraged large-scale, efficient closure work; in 2021 its participants abandoned 8,537 licences, reclaimed 2,061 and reported $550 million in closure spending ^[69]. Mandatory quotas began in 2022 at $422 million, rose to $700 million in 2023 and 2024, and have been set at $750 million for 2025, 2026 and 2027 ^[8][70]. The AER itself notes that closure did not keep pace with drilling for years, so inactive infrastructure grew about 5% a year before the trend reversed around 2020 ^[64]. Whether today's pace is fast enough is contested. For how liability is assigned, what happens when a company goes bankrupt and how the Orphan Well Association is funded, see our ownership guide.

The lifecycle at a glance

FAQ

How long does it take to drill an oil well in Alberta? Usually days to a few weeks. CAOEC's 2025 figures, 58,256 rig operating days for 5,548 wells drilled in Canada, work out to about 10.5 days per well ^[27]. Completion and tie-in add more time before first production.

How deep are Alberta oil wells? It depends on the play. The top of the Duvernay lies 1,700 to 5,000 metres below surface ^[32]. Horizontal crude oil wells averaged about 3,300 metres of total hole in 2025 ^[18], and a record Kaybob Duvernay well reached 9,017 metres ^[33].

How many oil and gas wells are drilled in Alberta each year? In 2025 the AER issued 6,055 well licences and about 8,419 wells were spudded, more than half of them in the oil sands ^[1]. Early 2026 licensing was about 20% below the same period of 2025 ^[17].

Does hydraulic fracturing contaminate groundwater in Alberta? The rules are designed to prevent it: surface casing and full-length cement protect groundwater, fracturing is barred near water wells and shallow bedrock, and fluids used above the base of groundwater protection must be nontoxic ^[4][43][30]. The risks the rules target are loss of well integrity and communication with nearby wells ^[43][42]; fracturing can also trigger earthquakes, managed through traffic-light orders ^[46]. Two related questions remain live: how much fresh water fracturing draws, about 30 million m³ of make-up water in 2024, and the fact that companies may withhold trade-secret ingredients from public disclosure ^[5][29].

What happens to an oil well when it stops producing? After 12 months without production (six for critical sour wells) it becomes inactive and must be suspended to Directive 013 standards within a year ^[62]. Eventually it is abandoned under Directive 020, cut and capped at least one metre underground, and the site is reclaimed and certified ^[65][68].

Can a landowner refuse a seismic crew or a well? A seismic crew needs the landowner's written consent to enter private land, and a refusal cannot be appealed except for carbon storage projects ^[12]. A licensed well is different: if a surface lease cannot be negotiated, the operator can seek a right-of-entry order, as our ownership guide explains.

Who pays to clean up an old well? The licensee does. The AER sets an annual closure quota, $750 million a year for 2025 through 2027, shared among companies with inactive liability ^[8]. When no solvent owner remains, the industry-funded Orphan Well Association steps in; it spent $119 million on closure work in 2024 ^[7].

How fast does oil production from a new well decline? Fast at first. The AER assumes new horizontal oil wells lose 32% to 56% of their production in the first year in most regions, and about 14% in the heavy-oil northeast, with the decline easing in later years ^[6].