Alberta's Great Oil Fields: An Atlas

Alberta's geology in one sweep

Almost all of Alberta's oil and gas sits in the Western Canada Sedimentary Basin (WCSB), a wedge of sedimentary rock that runs from the Rocky Mountains in the west to the Canadian Shield in the east. It is roughly 6 kilometres thick under the Rockies and thins to nothing at its eastern edge ^[87][88]. Because the wedge is lopsided, source rocks on the deep western side were heated enough to generate oil and gas. Those hydrocarbons then moved up and east, into the large conventional pools and the bitumen deposits of the oil sands ^[89].

Three groups of rock account for most of the fields in this atlas.

Devonian reefs. In the Devonian, warm shallow seas covered what is now Alberta, and reef-building organisms grew thick limestone and dolomite build-ups. The Woodbend and Winterburn strata alone reach more than 850 metres thick in places. They include large reef complexes and some of the basin's richest source rocks ^[17]. The Leduc Formation reefs (Late Devonian, Frasnian stage) hold the oil at Leduc-Woodbend and Redwater ^[16][17]. The slightly older Swan Hills reefs of the Beaverhill Lake Group hold it at Swan Hills and Judy Creek ^[30]. The Middle Devonian Keg River pinnacle reefs hold it at Rainbow and Zama ^[40][45]. The Duvernay shale formed in the deeper water between the Leduc reefs and is the source rock for much of their oil ^[60].

Mississippian carbonates. In the foothills, thrust faulting pushed Mississippian limestone up into folded structures. That is the geology of Turner Valley ^[2].

Cretaceous sandstones. As the Rockies rose, rivers and shorelines spread sand eastward across the basin. The Cardium sandstone at Pembina, the Clearwater sands that hold heavy oil and bitumen, and the McMurray, Clearwater and Bluesky oil sands all date from this time ^{[25][68][75][80]}.

Shale and tight plays. From the 2000s, horizontal drilling and multi-stage hydraulic fracturing opened rock that had been too tight to produce economically. The main examples are the Triassic Montney siltstone, the Devonian Duvernay shale and the tight edges of old conventional fields such as the Cardium ^[26][50][60].

At a glance: comparison table

Turner Valley

Location. Southwest of Calgary, at the eastern edge of the Rocky Mountain foothills, around the towns of Turner Valley, Black Diamond and Longview ^[2][9].

Discovery. On May 14, 1914, Calgary Petroleum Products Company's Dingman No. 1 well, near the Sheep River, struck wet gas. The well was named for the company's general manager, A.W. "Archie" Dingman ^[5][93]. The discovery depth is reported as about 820 metres verify ^[6]. The company separated naphtha from the gas and sold it locally ^[6]. After a fire and explosion in 1920, Imperial Oil took the company over in 1921 and ran it through a subsidiary, Royalite ^[5].

Geology and trap. The field is a structural trap: a folded and faulted thrust sheet at the leading edge of the Foothills Belt, with Mississippian carbonates at its base ^[2]. On October 14, 1924, Royalite No. 4 was deepened into that Mississippian limestone and found high-pressure sour gas carrying light liquids. That changed the field's prospects ^[1][2]. The reservoir unit belongs to the Mississippian Rundle Group ^[2].

What makes it notable. For about three decades, Turner Valley was the largest oil and gas producer in the British Empire ^[6] verify. On June 16, 1936, Turner Valley Royalties No. 1 found crude oil lower down on the structure's flank, flowing about 850 barrels a day of 39-degree API oil ^[2][3]. Oil output peaked at about 27,000 barrels a day in 1942. At that point the field supplied roughly 97 per cent of Canada's domestic oil production ^[2].

The field also taught Alberta about waste. Producers separated the liquids and flared the gas, much of it in a ravine locals called Hell's Half Acre. The practice drained the reservoir pressure that pushed the oil out ^[4]. In July 1938, the province created the Alberta Petroleum and Natural Gas Conservation Board to enforce conservation. By then an estimated 28 billion cubic metres of gas had been wasted ^[4]. The board is a forerunner of today's provincial regulator ^[96].

Current status. The Turner Valley oilfield is a National Historic Site of Canada ^[90]. The Turner Valley Gas Plant processed gas from 1914 until 1985, when it was decommissioned as uneconomic. It is now a provincial and national historic site ^[5][91].

Leduc-Woodbend

Location. Southwest of Edmonton, between the city of Leduc and the town of Devon ^[11][12].

Discovery. Imperial Oil had drilled 133 dry holes in the years before Leduc ^[10]. It sent drilling superintendent Vern "Dry Hole" Hunter to a site on Mike Turta's farm, about 15 km west of Leduc, where geologists had identified a subsurface anomaly ^[10][12]. Leduc No. 1 came in on February 13, 1947, at a depth of about 1,536 metres. Imperial lit the flare in front of invited officials and reporters ^[12].

Geology and trap. The well found oil in the Devonian Nisku Formation and confirmed the prolific Leduc Formation reef below it ^[18]. Both are Late Devonian (Frasnian) carbonates of the Woodbend and Winterburn interval ^[16][17]. The trap is a porous reef build-up sealed by the surrounding shale. The field has two major pools at different depths, known as the D-2 (Nisku) and D-3 (Leduc) (verify pool naming) ^[13].

What makes it notable. Leduc gave explorers the geological key to Alberta's most productive conventional oil: Devonian reefs. It set off a boom across Western Canada. Oil and gas replaced farming as Alberta's main industry ^[10]. Parks Canada designated the Leduc-Woodbend Oilfield a National Historic Site in 1990. The designation notes that the discovery moved the industry's focus north from Turner Valley to the central plains, made Edmonton a petrochemical centre and moved Canada toward self-sufficiency in oil ^[11]. Imperial Oil began building the planned town of Devon in 1949 to house field workers verify ^[13].

The field also produced one of Alberta's most famous accidents. Atlantic No. 3 blew out in March 1948, caught fire on September 6, 1948, and burned until crews brought it under control ^[14][15]. The site is recorded as Alberta's most dramatic oilfield disaster. It led to tighter regulations and better well-control technology and training ^[14].

Production. Leduc No. 1 produced about 317,000 barrels of oil before it was decommissioned in 1974 verify ^[12][81]. The whole field has produced more than 300 million barrels verify ^[12]. The Alberta Geological Survey lists an initial established oil in place of about 818 million cubic metres (roughly 5.1 billion barrels) for Woodbend Group pools as a whole, the group that includes the Leduc reefs (verify scope) ^[18].

Current status. The field is mature but still producing. A 2025 AAPG Bulletin paper describes a revival of the Leduc-Woodbend Nisku pool (verify details) ^[18].

Redwater

Location. Next to the town of Redwater, about 50 to 64 km northeast of Edmonton, in the Industrial Heartland ^[19][20].

Discovery. Imperial Oil found oil on Hilton Cook's farm in October 1948 ^[21]. It was another Leduc-age Devonian reef, but shallower than Leduc, and it went on to produce more oil ^[19].

Geology and trap. The Redwater Leduc D-3 pool is a large, isolated Late Devonian reef. Oil is trapped at the top of the porous carbonate, and a much larger body of water sits beneath it ^[20][22]. The field turned out to be about 32 km long and 6.5 km wide ^[19].

What makes it notable. Redwater grew quickly. By 1953 it had 926 wells and produced almost 30 per cent of Alberta's oil ^[19]. Conifer Energy puts production that year at about 21,000 barrels a day from more than 900 wells ^[20]. The Canadian Encyclopedia calls it Canada's most prolific oil field, holding four times as much oil as Leduc ^[21]. The town's population rose from 160 to more than 4,000 at the height of the boom, and Redwater incorporated as a town in 1950 ^[21]. Researchers describe the pool as Canada's third-largest conventional oil pool, with about 1.32 billion barrels of original oil in place verify ^[22].

The same reef makes Redwater a carbon storage candidate. The Heartland Area Redwater Project studied storing captured CO2 in the reef's water leg. Early estimates put its capacity on the order of one gigatonne ^[22].

Current status. Conifer Energy operates the field. It reports about 2,650 boe/d, 92 per cent oil, from 280 wells under waterflood ^[20]. Conifer says it built a CO2 enhanced oil recovery demonstration, with an injection well and a monitoring well, aiming to start injecting in summer 2025 ^[20].

Pembina (Cardium)

Location. Centred on the town of Drayton Valley, about 113 km southwest of Edmonton, in west-central Alberta ^[23][24].

Discovery. Seaboard Oil and Socony-Vacuum Exploration (later Mobil) explored the area in partnership. Drilling of the Socony-Seaboard Pembina No. 1 well began in February 1953 ^[23][24]. The well found oil not in a Devonian reef but in Cardium sandstone ^[23]. The Town of Drayton Valley tells the discovery story locally ^[28].

Geology and trap. The Cardium Formation dates from the late Turonian of the Late Cretaceous, about 90 million years ago. It is interbedded marine sandstone, mudstone and conglomerate deposited along the western shore of the Western Interior Seaway ^[25]. At Pembina the trap is stratigraphic: the reservoir sandstone grades into shale up-dip, which seals the oil in place ^[25]. Pembina is the largest stratigraphic oil trap in western Canada apart from the McMurray oil sands ^[24].

What makes it notable. Pembina is Canada's largest conventional oil field by area and by oil in place ^[23][24]. It covers about 1,554 square kilometres and was expected to support about 6,000 wells. It was producing 100,000 barrels a day by 1956 ^[23]. Estimates of oil in place at discovery are about 7.8 billion barrels. Original proven recoverable reserves are about 1.81 billion barrels from 66 pools, of which the Cardium accounts for 1.56 billion ^[24].

The field has been a testing ground for several technologies. From 2005 to 2008, the Alberta government-supported Penn West Pembina Cardium CO2 monitoring pilot injected about 75,000 tonnes of CO2 into the Cardium at about 1,650 m depth ^[27]. In 2008, the first horizontal, multi-stage fractured well in the Pembina field started a tight-oil revival. The new wells reach the lower-permeability "halo" around the old high-quality pools ^[26].

Current status. Pembina is still active. The AER counts more than 2,700 horizontal oil wells in its Pembina Cardium assessment area ^[26].

Swan Hills

Location. In the forested Swan Hills of north-central Alberta, about 200 km northwest of Edmonton, around the town of Swan Hills ^[29][33].

Discovery. Home Oil's Home Regent Swan Hills 8-11-68-10W5 well found the field in spring 1957. It hit 12 feet of pay in the lower Beaverhill Lake Group. A confirmation well drilled that fall, 6 miles to the southwest, found 141 feet of net pay ^[29]. Other operators found neighbouring pools. The town of Swan Hills credits Amoco Canada and British American with the first well of the South Swan Hills Unit in 1959 ^[33].

Geology and trap. The reservoir is the Swan Hills Formation, a Devonian carbonate bioherm (reef) in the Beaverhill Lake Group. It contains at least seven major porous zones ^[30][92]. The trap is the porous reef build-up itself.

What makes it notable. Swan Hills is described as the largest conventional carbonate oil field in Canada ^[29]. The 1957 finds revived interest in Alberta exploration after a lull ^[31]. The Alberta government's heritage history puts the combined Swan Hills-area fields at about 926 million barrels of crude (verify basis) ^[31]. A 1978 study gave the main Swan Hills pool 1.9 billion stock-tank barrels of original oil in place, 81.6 per cent of it inside Swan Hills Unit No. 1 ^[30]. The unit was formed in January 1963 and began water injection that August. Steady production had started in January 1959, once a pipeline was available ^[30]. A later estimate gives the unit 1,413 million barrels in place and about 540 million barrels produced (verify date) ^[29].

Swan Hills was also a new kind of town. It was incorporated on September 1, 1959, as one of Alberta's first government-planned resource towns, built jointly by the province and oil companies ^[33][32].

Current status. The field is mature and producing under waterflood. Conifer Energy operates five legacy Beaverhill Lake pools in the wider Swan Hills region. It reports about 6,350 boe/d, 64 per cent light sweet oil, from those pools, and is studying CO2 enhanced oil recovery ^[34].

Judy Creek

Location. In the wooded Swan Hills area, about 100 miles (160 km) northwest of Edmonton ^[35]. Conifer Energy places its Swan Hills-region pools, including Judy Creek, between 15 and 90 km north of Whitecourt ^[34].

Discovery. Imperial Oil found the Judy Creek Beaverhill Lake pool in February 1959, two years after Home Oil's Swan Hills discovery a few miles to the north ^[35].

Geology and trap. The Judy Creek Beaverhill Lake "A" pool is an atoll-like reef limestone complex in the Swan Hills Formation of Late Devonian age ^[36][38]. Like Swan Hills, it is a reef trap. Researchers have used the reef complex as a model for mapping facies in carbonate reservoirs ^[38].

Why this field. Judy Creek shows the full life of an Alberta reef pool. The field has produced since 1960 ^[37]. Operators added pattern waterflooding and then a water-alternating-gas hydrocarbon miscible flood from 1985 to 2016 ^[37]. The miscible flood was expected to recover about 100 million barrels more than waterflooding alone (verify which pool this estimate covers) ^[36]. One published figure gives the reef about 890 million barrels of original oil in place verify ^[36]. A provincially supported project also tested acid-gas injection into the pool ^[97].

Current status. Conifer Energy operates Judy Creek under waterflood. A 2024 GeoConvention study found the pool has strong potential for carbon capture, utilization and storage because of its large pore volume, detailed geological data and existing solvent-injection facilities ^[37]. Conifer has run a CO2 pilot there ^[34][37]. The field is a working example of the question facing many old reef pools: whether the next barrels come from CO2 injection and whether that also stores carbon permanently.

Rainbow Lake and Zama

Location. Far northwestern Alberta, around the town of Rainbow Lake and the hamlet of Zama City, near the British Columbia and Northwest Territories borders. Rainbow Lake is about 900 km northwest of Edmonton by road (verify distance) ^[41].

Discovery. In February 1965, the Banff-Aquitaine Rainbow 7-32-109-8W6 exploration well found a 435-foot oil column in a Keg River reef ^[39][40]. Banff Oil and Aquitaine Company of Canada were partners. Within two years they had confirmed 29 separate oil- and gas-bearing reefs around Rainbow Lake and Zama Lake ^[39].

Geology and trap. The reservoirs are Middle Devonian Keg River reefs. Many are pinnacle reefs: tall and thick, but covering very small areas, isolated and sealed by thick, nearly impermeable anhydrite ^[40][43][45]. The Keg River B pool, an atoll reef, is the largest accumulation at Rainbow ^[44]. Finding such small targets took a very large amount of seismic data ^[40].

What makes it notable. The Alberta government's heritage history calls Rainbow-Zama the last major conventional oil discovery in Alberta ^[39]. A later industry review counted about 300 wells drilled in the area and an estimated 45 reef reservoirs, adding more than 1 billion barrels of recoverable oil to Alberta's reserves (verify date and basis) ^[40]. The province created the Town of Rainbow Lake effective September 1, 1966, to serve the new field ^[42]. Operators started secondary recovery in the early 1970s ^[41]. Hydrocarbon miscible flooding was used on the Keg River B pool ^[44].

At Zama, Apache Canada and the U.S. Plains CO2 Reduction (PCOR) Partnership injected acid gas from the Zama gas plant into the Keg River F pinnacle reef at about 1,500 m. The gas was roughly 80 per cent CO2 and 20 per cent hydrogen sulphide. The project recovered more oil, stored CO2 and let the plant shut down its sulphur-recovery unit ^[43].

Current status. A mature producing area. Current operator and production figures were not confirmed for this edition verify.

Alberta Bakken (southern Alberta)

Location. Southern Alberta, south of Lethbridge toward the Montana border ^[47][49]. The play is usually described as southern Alberta rather than the southeast.

Geology. The Exshaw Formation and the shale at the base of the Banff Formation are the same age as the Bakken of the Williston Basin in Saskatchewan, North Dakota and Montana. Industry calls the interval the "Alberta Bakken" ^[46]. Along with the Big Valley and upper Stettler carbonates beneath it, it became a tight-oil target once horizontal wells and hydraulic fracturing arrived ^[46]. The interval straddles the Devonian-Mississippian boundary verify. Production depends on low-permeability rock being fractured rather than on a large conventional trap.

Discovery and development. In 2010 to 2012, Crescent Point, Murphy Oil, Shell, Nexen and several juniors bought land and drilled in southern Alberta and northern Montana, hoping to repeat the Williston Basin's success ^[49]. DeeThree Exploration drilled the discovery wells in 2012 that established the Upper Bakken as a commercial oil reservoir in Alberta ^[47]. Its Lethbridge-area discovery well came in at about 415 barrels a day ^[49]. The pool produces 30 to 32 degree API oil. In 2013 the company started a gas-injection enhanced oil recovery scheme, which later grew to cover most of the core pool ^[47].

Current status. DeeThree reorganized in 2015 into two companies, and the Bakken pool went to Granite Oil ^[98]. International Petroleum Corporation acquired Granite in 2020 ^[48]. The play is small next to the Montney or Duvernay, but it shows the Williston Basin model working in part on the Alberta side of the border. It also shows how gas injection can slow the fast decline typical of tight-oil wells ^[47].

Montney (Alberta side)

Location. West-central Alberta, around Grande Prairie, Kakwa, Karr and Wapiti, and continuing into northeastern British Columbia ^[51][55].

Geology. The Montney is an Early Triassic formation, more than 247 million years old verify, made mainly of siltstone with some coquina and turbidite beds ^[50][51]. In the east it was laid down as a shoreface and in the west as offshore deposits ^[51]. Its fluids change with depth. Deep areas hold dry gas. Toward the basin edge the fluids become gas condensate and then light oil ^[51]. The whole formation is an unconventional reservoir: production depends on horizontal wells with many hydraulic-fracture stages rather than on a discrete trap.

Discovery and development. Conventional Montney pools were drilled from the 1950s. The modern play started in July 2005, when the first successful multi-stage fractured horizontal well was drilled near Dawson Creek, British Columbia. Its production rates were four to five times those of vertical wells ^[54]. The model then spread to the Alberta side.

Size. In 2013, the National Energy Board (now the Canada Energy Regulator), the BC Oil and Gas Commission and the AER jointly assessed the Montney across both provinces. They estimated marketable resources of 449 trillion cubic feet of gas, 14,521 million barrels of natural gas liquids and 1,125 million barrels of oil ^[52]. A 2012 ERCB and AGS study of Alberta's shales put the Alberta Montney's oil in place at about 136 billion barrels (verify figure and source) ^[53]. In-place figures are far larger than what can be recovered. The AER's current reserves assessment for the unconventional Alberta Montney is about 64.5 trillion cubic feet of gas, 0.41 billion barrels of oil and 2.9 billion barrels of condensate, or 14.1 billion boe in total ^[50].

Current status. Very active. Condensate from the Kakwa and Karr area now ranks among Alberta's top oil and condensate producers. In August 2024, ARC Resources had 11 of the 15 best-producing oil and condensate wells in the province, all in that area ^[55]. ARC says it is the largest pure-play Montney producer in Canada ^[56]. In 2025 it bought further condensate-rich Kakwa assets from Strathcona Resources ^[57].

Duvernay

Location. The Duvernay underlies nearly 20 per cent of Alberta, from just south of Grande Prairie to north of Calgary and east of Edmonton ^[59]. The most active area is Kaybob, around Fox Creek, about 260 km northwest of Edmonton ^[64]. The AER splits the play into Kaybob, Edson-Willesden Green and Innisfail assessment areas ^[60].

Geology. The Duvernay is an Upper Devonian organic-rich shale. It was deposited on the sea floor around the Leduc reefs, which are the same age, and it is absent where those reefs grew ^[60]. For decades it was known mainly as the source rock that charged the Leduc reefs with oil. Unlike most Alberta formations, it is both source and reservoir, and it produces directly through fractured horizontal wells ^[60].

Discovery and development. The play took off in 2010 and 2011, when companies spent more than $2 billion on Duvernay land at provincial sales ^[63]. It has been developed with horizontal multi-stage fracturing since 2011 ^[59][60]. Most early activity targeted the overpressured condensate window, with later work moving into the volatile-oil window at Kaybob ^[65].

Size. The 2017 NEB and AGS assessment estimated that the Duvernay could produce 3.4 billion barrels of marketable crude oil, 76.6 trillion cubic feet of marketable gas and 6.3 billion barrels of natural gas liquids ^[58][59]. The 2012 ERCB and AGS study estimated about 61.7 billion barrels of oil in place verify ^[53].

Induced seismicity. Earthquakes near Fox Creek rose sharply from December 2013, linked to hydraulic fracturing ^[62]. On February 19, 2015, the AER issued Subsurface Order No. 2. It requires operators fracturing the Duvernay near Fox Creek to monitor and report seismicity within 5 km of their wells ^[61]. Research published in Science linked the number of induced earthquakes to the volume of fluid injected ^[62].

Current status. Active development at Kaybob. Crescent Point (since renamed Veren, verify) planned about 50,000 boe/d from its Kaybob Duvernay assets in 2024 ^[65][99].

Clearwater heavy oil play

Location. North-central Alberta near the town of Slave Lake, in areas known as Marten Hills and Nipisi. Development has since spread west to Peavine and Seal in the Peace River region ^{[67][74][100]}.

Geology. The heavy-oil Clearwater reservoirs are Lower Cretaceous (Albian) shallow-marine sands. They sit just above the sub-Cretaceous unconformity ^[68]. The same formation holds bitumen at Cold Lake, but in the Marten Hills and Nipisi areas the oil is mobile enough to flow without heat ^[67][75]. Permeability ranges from about 1 to 900 millidarcies, and the oil is 14 to 24 degrees API ^[67].

Technology. The Clearwater is known for multilateral wells. One vertical section branches into four to eight or more horizontal legs, all produced through a single string. That reaches a large volume of reservoir cheaply, without hydraulic fracturing, steam-assisted gravity drainage (SAGD) or cyclic steam ^[67]. In 2019, wells cost about $1.24 million to $1.7 million each ^[67]. The AGS has published an overview of heavy-oil multilateral projects ^[66].

Discovery and boom. Deltastream Energy began drilling Clearwater heavy oil at Marten Hills in 2016 ^[70]. Output went from almost nothing in late 2016 to more than 14,000 barrels a day by mid-2019 ^[67]. Citing an AER assessment by McDaniel & Associates, industry press reports that multilateral Clearwater production grew from about 30,000 barrels a day in 2017 to about 230,000 in 2025, making it Canada's fastest-growing oil resource play. The same assessment puts recoverable oil at about 1.6 billion barrels ^[69][71].

Current status. Rapid growth, with drilling licences at a decade high in 2026 ^[69]. Tamarack Valley Energy's Clearwater assets produced 50,049 boe/d in the fourth quarter of 2025 ^[72]. On September 8, 2026, Tamarack and Headwater Exploration announced an all-stock combination to create the largest public producer focused on the Clearwater ^[73]. Baytex works with the Peavine Métis Settlement and expects to bring about 26 net multilateral wells onstream there in 2026 ^[74].

Cold Lake heavy oil (oil sands)

Location. East-central Alberta, around the city of Cold Lake near the Saskatchewan border. It is one of Alberta's three oil sands areas, alongside Athabasca and Peace River. Together they cover about 142,200 square kilometres verify ^[94].

Discovery and geology. Imperial Oil acquired Cold Lake leases in the 1950s and estimated about 44 billion barrels of bitumen in place. The bitumen sits roughly 500 m underground ^[75]. It is in the Lower Cretaceous Clearwater Formation, the same unit that produces cold heavy oil farther west ^[75]. At that depth the bitumen cannot be mined, and it is too viscous to flow unaided.

What makes it notable. Cold Lake pioneered commercial cyclic steam stimulation (CSS). Wells inject steam, let the reservoir soak and then produce the heated bitumen through the same well. Imperial ran pilots between 1964 and 1975 and began commercial production in 1985 ^[75].

Current status. Imperial's Cold Lake operations averaged about 148,000 barrels a day in 2024 ^[76]. In 2024 its Grand Rapids project, which uses a lower-emission, solvent-assisted steam process verify, produced first oil. It targets 15,000 gross barrels a day at up to 40 per cent lower emissions intensity than existing technology ^[77]. See the oil sands section of this site for how in situ methods work.

Peace River heavy oil (oil sands)

Location. Northwestern Alberta, near the town of Peace River. It is the smallest of Alberta's three oil sands areas, and its bitumen lies deeper than the larger Athabasca deposit ^[101].

Geology. Bitumen occurs mainly in the Lower Cretaceous Bluesky and Gething formations. The area covers more than 29,000 square kilometres ^[80]. The reservoir conditions are difficult, with very viscous oil and water at the base of the reservoir ^[79].

History. With half its costs paid by the Alberta Oil Sands Technology and Research Authority, Shell started the Peace River In Situ Pilot Project in 1979. Gas-fired boilers raised steam that was injected in cycles ^[78]. The pilot's success led to the Peace River Expansion Project in 1986 ^[78].

Current status. Canadian Natural Resources owns and operates the Peace River thermal facility. It is the only commercial thermal operation in the region and the only in situ facility producing from the Bluesky, with capacity of about 12,500 barrels a day using CSS ^[79][80]. The same region now also hosts the Clearwater multilateral activity at Peavine and Seal, where operators produce heavy oil without steam ^[74].

Where to see it

Canadian Energy Museum, home of Leduc No. 1 (near Devon). The museum stands on the Leduc No. 1 well site, southwest of Edmonton on Highway 60. The well was decommissioned in 1974, and the museum opened on the site in 1997 ^[81]. Visitors can see drilling rigs and the Leduc No. 1 derrick, watch films, use a learning lab, take interpretive tours led by oil patch veterans and visit the gift shop. The site also has a campground with 20 serviced RV stalls ^[82][83]. The Leduc-Woodbend Oilfield National Historic Site designation gives the wider historical context ^[11]. Pictures and biographies of Canadian Petroleum Hall of Fame inductees have been displayed at the site (verify current display) ^[95]. Check the museum's website for seasonal hours and admission ^[81].

Turner Valley Gas Plant National and Provincial Historic Site (Turner Valley). The plant is about 40 km southwest of Calgary. It is an industrial complex of 22 metal buildings and related equipment built from the 1920s to the 1970s. It was the first petroleum processing plant in western Canada and operated from 1914 to 1985 ^[5][9]. The Government of Alberta acquired it in 1988 and carried out extensive reclamation to make it safe for visitors ^[9]. In summer, guided tours cover the grounds, the exhibit hall and some historic buildings. Recent listings give tour times of 11:00 a.m., 12:30 p.m., 2:00 p.m. and 3:30 p.m., with cash-only admission and no cash machine on site ^[7][8]. Confirm times before visiting.

Oil Sands Discovery Centre (Fort McMurray). The centre, a provincial facility at 515 MacKenzie Boulevard, explains the history, science and technology of the Athabasca oil sands ^[84][85]. It has the Clark Exhibit Hall, the Robert Fitzsimmons Theatre, a children's activity area and the outdoor J. Howard Pew Industrial Equipment Garden ^[85]. The garden includes "Cyrus," an 850-tonne bucketwheel excavator and one of the largest land-based artifacts in Canada; the outdoor area closes in winter ^[86]. Staff run hot-water extraction demonstrations of how bitumen is separated from sand, and there are school programs ^[85][86].

FAQ

What was the first major oil discovery in Alberta? Turner Valley came first. The Dingman No. 1 gas discovery in 1914 made it the British Empire's leading oil and gas field for decades ^[5][6]. The discovery that made Alberta a major oil province was Imperial Oil's Leduc No. 1, on February 13, 1947 ^[10][11].

What is the largest conventional oil field in Canada? Pembina, in the Cretaceous Cardium sandstone around Drayton Valley. It covers about 1,554 square kilometres and held about 7.8 billion barrels of oil in place at discovery ^[23][24]. The oil sands contain far more oil but are counted separately as unconventional deposits.

Why are Devonian reefs so important in Alberta? Porous Devonian reef build-ups, sealed by surrounding shale and tight rock, trapped oil generated by nearby source rocks such as the Duvernay. Leduc-Woodbend, Redwater, Swan Hills, Judy Creek and Rainbow are all reef fields ^{[17][29][39][60]}.

Is the Clearwater play part of the oil sands? The formation is the same one that holds Cold Lake bitumen. But the Clearwater play at Marten Hills, Nipisi and Peavine produces heavy oil that flows without heat, using multilateral wells ^[67][75].

What is the difference between the Montney and the Duvernay? The Montney is an Early Triassic siltstone that is especially rich in gas and condensate in west-central Alberta and northeastern B.C. ^[50][52]. The Duvernay is an Upper Devonian shale that is both the source rock and the reservoir, with oil and condensate windows at Kaybob and elsewhere ^[58][60]. Both need horizontal wells with multi-stage fracturing.

What was Alberta's last big conventional oil discovery? The Rainbow-Zama Keg River reef trend, found by Banff-Aquitaine in 1965 in far northwestern Alberta ^[39][40].

Can you visit Leduc No. 1? Yes. The Canadian Energy Museum near Devon stands on the original well site and displays the derrick ^[81][82].