Introduction to the Athabasca Oil Sands and Devonian Carbonate Heavy Oil 2

Introduction to the Athabasca Oil Sands and Devonian Carbonate Heavy Oil Deposits

Canadian oil sands occur in Cretaceous age deposits of northeastern Alberta, and underlie an area >140,000 km2 (over 54,000 square miles). There are four major oil sand regions in the Athabasca oil sands province: the Athabasca area itself, Wabasca, Cold Lake, and Peace River (Fig. 1). Total Athabasca area oil sand resources are estimated to be more than 1.7 trillion barrels. Proved reserves amount to 174 billion bbls, putting Canada third in the world in crude reserves behind Venezuela and Saudi Arabia. In 2010, Alberta produced 49.7 million m3 (313 million barrels) from the mineable area and 43.8 million m3 (276 million barrels) from the in situ area, totaling 93.5 million m3 (589 million barrels). This amounts to about 256.3 thousand m3 (1.6 million barrels) per day. Total raw bitumen production is projected to reach 549.6 thousand m3 (3.5 million barrels) per day by 2020. Production from in situ bitumen projects is projected to surpass that of bitumen from mining projects by 2015 (Energy Resources Conservation Board, June 2011). Fig. 1. Location map of the Athabasca, Cold Lake, Peace River, and Wabasca oil sands deposits.

The oil sands occur in layers at different depths in each deposit.

Each grain of sand is surrounded by a layer of water and a film of bitumen.

Fig. 2. Composition of oil sands.

Source: Canadian Centre for Energy Information

In 2001, Alberta's production of raw bitumen and synthetic crude oil surpassed that for conventional crude oil for the first time, accounting for 53% of Alberta's oil production. This trend is expected to increase to be about 80% of Alberta's oil production by 2013. Heavy oil accumulations are also found in older Devonian carbonates beneath the sands, mostly within the Grosmont Formation, but this bitumen has not yet been commercially produced. The Devonian carbonate heavy oil occurrence is reviewed later. Oil sands are a mixture of bitumen (soluble organic matter, nearly solid at room temperature), sediment, and water. The Alberta Oil Sands are hydrophilic or "water wet." Each grain of sand is surrounded by an envelope of water which, in turn, is surrounded by oil (Fig. 2). More than 10% bitumen is considered rich oil sand, from 6% to 10% moderate, and less than 6% lean. The crude bitumen within the sands is a naturally occurring viscous mixture of heavy hydrocarbons, often with sulphur compounds, that will not flow to a well bore in its natural state. The oil sands of Alberta are largely unconsolidated, held together by the pore-filling bitumen. Bitumen is a natural, soluble, organic, tar-like mixture of hydrocarbons, that when heated has a consistency of molasses. In its natural state, bitumen (API density range of 8-12°) will not flow to a well bore. The major challenge of recovering bitumen from depth is to overcome its high viscosity to allow it to flow to the well bore. To do this, thermal in-situ methods are used, most commonly Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) (see Fig. 9 below).

Athabasca Oil Sands Alberta's largest and most accessible reserve of bitumen is contained in the Athabasca Oil Sands which underlie an area of 16,000 square miles and hold an estimated 812 billion barrels of bitumen in place, mostly in the Mannville McMurray formation. The deposit has three layers of thick, rich, oil-bearing sand separated by beds of silt, sand, and shale. They are generally covered by over-burden up to 2,500 feet deep, consisting of muskeg, glacial tills, sandstones, and shales. About 20% of the deposit lies under less than 150 feet of over-burden, making it accessible by surface mining techniques. An estimated 35 billion barrels of established bitumen reserves can be recovered by present mining methods, and 98 billion barrels with in-situ methods. Wabasca Oil Sands While the Wabasca Oil Sand deposit is usually indicated on maps as part of the Athabasca reserve it is not connected to its larger neighbor. It is at a higher stratigraphic level, but under a greater depth of overburden than the mineable portion of the Athabasca reserves. This reserve contains the most viscous bitumen and its potential is the least known. The reservoirs are thinner and more deeply buried, on average about 7 feet thick, under 490 - 1,500 feet of overburden. With an estimated 13% oil saturation, Wabasca holds in place 42.5 billion barrels of bitumen. Because of the depth, none of this is available to existing surface mining methods and the reserves are not currently counted as established recoverable (i.e., “proven”). Peace River Oil Sands In the Peace River deposit, bitumen occurs at depths from 1,000 to 2,500 feet in the Bluesky and Gething Formations. In an area of 3,000 square miles there are an estimated 71.7 billion barrels of bitumen in place. Peace River crude is contained in a layer of sand about 50 feet thick on the average. In the richer areas, this layer can reach a thickness of 120 feet. Cold Lake Oil Sands There are four separate reservoirs in the Cold Lake oil sands area; the McMurray, Clearwater, Lower Grand Rapids, and upper Grand Rapids formations. The bitumen is contained within thick, loosely-consolidated sandstone beds. This, along with depth, which varies from 984 to almost 2,000 feet, prohibits surface mining but makes deposits suitable for in situ extraction methods. The crude bitumen in these deposits is the least viscous of any oil sand but still denser than the heavy oils located to the south. Approximately 8,200 square miles in area, the Cold Lake sands hold an estimated 177.8 billion barrels of bitumen in place and it could potentially yield 28 billion barrels of synthetic crude oil. Lloydminster Heavy Oil The Lloydminster area of Alberta and Saskatchewan has been the focal point of heavy oil production from Mannville Group sediments for many years, with the entire suite of Mannville facies being prospective targets. These may contain 101.7 billion barrels of oil in place.

General Geologic Setting The Western Canada Sedimentary Basin was formed during two compressional events; the Columbian Orogeny and the Laramide Orogeny, which occurred from the middle Jurassic to the latest Cretaceous and into the early Eocene. The older Columbian and younger Laramide orogenies in the northern Rockies and Canadian Cordillera are characterized by extensive, large-scale, eastward movement of huge blocks of crust that terminate in thrust faults and folds. The Lewis Overthrust in Waterton, British Columbia, and Glacier Park, Montana, for example, began about 170 million years ago and pushed a slab of 1.6 billion year old rocks several kilometers thick and several hundred kilometers wide more than 80 km over and on top of Cretaceous age sediments that had been accumulating to the east of its advancing front. The basin is a northwest-southeast trending asymmetric basin culminating at the Precambrian Canadian Shield as it is exposed in the northeastern most corner of Alberta. This basin geometry is reflected in the gentle southwest dips of the Paleozoic units and the subcropping edges of the Devonian carbonates in the greater Athabasca area. Most of the bitumen resources in the Athabasca oil sands area are found within the Lower Cretaceous McMurray and Wabiskaw sections. The Wabiskaw Member of the Clearwater Formation unconformably overlies the McMurray Formation. The McMurray is the lowest part of the Mannville Group in Alberta, where it rests unconformably on Devonian carbonates (see Fig. 3). In the eastern outcrop portion of the Athabasca deposit the underlying carbonates are the Christina and Moberly limestone of the Beaverhill Lake Group. In the central portion of the oil sand area, however, the underlying formation is primarily the Grosmont. The Grosmont is an important heavy-oil resource itself (see below). The Mannville sediments containing the Athabasca Oil Sands lie on an angular unconformity that truncates Devonian strata (Fig. 3 and Fig. 11). The oil-bearing McMurray Formation was deposited on an old erosional surface (unconformity) of ridges and valleys, and varies in thickness from being absent on some Devonian carbonate paleohighs to over 130 m thick at the northern end of the outcrop belt. In general, the McMurray Formation accumulated in incised valleys that were formed by fluvial processes and subsequently transgressed by marginal-marine environments during an early Cretaceous sea-level rise. Reservoir facies represent mainly fluvial-estuarine channel/point bar deposits. Locally, especially in the more northern outcrops along the Athabasca River, barrier island, back-bay lagoon, and coastal plain sediments occur. Because of the changing depositional environment through time, the McMurray displays a continuum of sedimentary facies, from fluvial in the lower parts, to estuarine in the middle, to marine shoreface (beach) near the top. This lends a tripartite aspect to the stratigraphy that forms the basis for subdivision of the McMurray Formation, although the subdivisions have not been formalized.

Fig. 3. Generalized Stratigraphy of the Oil Sands Region. Green shows bitumen occurrences. http://www.laricinaenergy.com/uploads/images/stratigraphy.jpg

Although individual units vary in physical aspect from place to place, the Lower, Middle, and Upper McMurray do have some consistent lithological expressions: The Lower McMurray is generally medium- to coarse-grained, massive-appearing to crudely cross-bedded, and contains no ichnofossils (trace fossils – trails, tracks, burrows, etc.). These beds are most commonly interpreted as forming in a fluvial environment. Middle McMurray deposits are dominated by inclined heterolithic stratification (HIS - see Fig. 5 below) that is interpreted to represent deposition on tidally influenced point bars. Upper McMurray deposits are variable, but generally reflect comparatively open marine conditions. These strata are normally interpreted as shallow, low-energy shoreface deposits and small deltaic complexes.

Depositional History and Reservoirs of the McMurray Formation The oil sand deposits display complex facies relationships and a fragmentary stratigraphic record. Determination of the relationship of different sedimentary packages to one another, proximal to distal variations, and the identification of systems tracts boundaries has been difficult. Nonetheless, much is known about the sedimentology and stratigraphy of these important unconventional reservoirs. The McMurray sediments were deposited within a karstic ridge and valley system (e.g., surface- and cave-collapse landscape) developed on the regional sub-Cretaceous unconformity (Fig. 4).

Fig. 4. Facies model for pre-McMurray sedimentation along the karstic sub-Cretaceous unconformity.

http://emd.aapg.org/members_only/oil_sands/field_guide/images/fig6-1a_r2_c2.jpg The Lower McMurray deposits represent a terrestrial fluvial system of braided bar and channel complexes, largely infilling lows on the unconformity. Associated coals, lacustrine marls, rooted overbank fines, and paleosols are preserved on top of carbonate paleohighs and within some of the karstic sinkholes along the sub-Cretaceous unconformity (Fig. 5). There is evidence of a disconformity or unconformity separating the Lower and Middle/Upper McMurray. During transgression, some of the lower fluvial facies was eroded and reworked into fluvial-estuarine channel and point bar complexes of the initial Middle/Upper McMurray succession.

Through time, with continued overall transgression, paleotopographic features became blanketed, and by late Upper McMurray time more nearshore coastal plain conditions prevailed. By the time of deposition of the top of the Wabiskaw Member, conditions were fully marine.

Fig. 5. Facies model for initial Middle/Upper McMurray fluvial-estuarine and overbank sedimentation.

http://emd.aapg.org/members_only/oil_sands/field_guide/images/fig6-1c_r3_c2.jpg In terms of paleoenvironments, the interpretation of the Lower McMurray as fluvial is well accepted. However, the proportion of the Middle/Upper McMurray represented by estuarine channel and point bar units changes both in time and space. Comparisons with modern barrier islands and bays show that much of what was previously interpreted as estuarine channel and point bar successions can be reinterpreted as barrier island (beach), crevasse/washover channel, and bay fill deposits. Facies models for these types of environments are significantly different from those for estuarine systems, with the most important differences seen in channel sand continuity versus bay-fill shale continuity. In areas of reduced accommodation space not all the environments are preserved, and recognition of the proper paleoenvironmental setting is critical for prediction of reservoir heterogeneity. Bitumen reservoirs occur in stratigraphic and/or structural traps, especially in areas susceptible to salt-dissolution tectonics associated with removal of salts from the underlying Middle Devonian Prairie Evaporite units. The north-south thickness trend in the McMurray generally correlates with the salt dissolution front. In the Wabiskaw-McMurray, bitumen reservoirs occur mainly within fluvial or fluvial-estuarine channel and bar complexes. In the upper parts of the Wabiskaw-McMurray succession, gas- and water-reservoirs may be associated with the bitumen.

Sedimentology of Channel Complexes Unraveling the complex geology of the bitumen reservoirs relies on the recognition that the fluvial-estuarine deposits are “multi-story” complexes. The preserved successions are a result of multiple transgressive and regressive pulses superimposed upon an overall transgressive phase from the Lower McMurray fluvial low-stand deposits (terrestrial), to high-stand (marine) Wabiskaw deposits (Fig. 6). To understand the complex reservoir geometry, we need to have a model that describes the basic building block of the stratigraphy of the bitumen reservoirs. Based on the classic point bar model for a meandering stream, sediments associated with a McMurray channel complex in the fluvial dominated part of the estuary would include the bottom channel, point bar lateral accretion (Inclined Heterolithic Stratification, or “IHS”), and vertical accretion, associated overbank levee, crevasse splay, and floodplain sediments.

Fig. 6. Stratigraphic model for preserved successions of A) Single-story fluvial-estuarine

channel complex; B) Multi-story stacked fluvial-estuarine channel complexes. http://emd.aapg.org/members_only/oil_sands/field_guide/07sed_channelcomplexes.cfm

Detailed reconstruction of these facies associations may not be relevant in surface mining operations, but can be critical for in-situ recovery methods. Even a short lateral borehole may encounter multiple facies and may pass from a good reservoir (channel sand) into an adjacent floodplain shale (poor reservoir) very quickly. Origin and Accumulation of the Bitumen Most, if not all, of the Mannville Group heavy oils in Alberta have an Exshaw Formation source from the deep subsurface west of Calgary (Fig. 7). It is generally accepted that the bitumen in the oil sands and heavy oils represents biodegraded mature oil.

Fig. 7. Canada’s Oil Sands, 3rd edition, November 2011 http://www.centreforenergy.com/shopping/uploads/12.pdf

The oil sands and heavy oils in both the Cretaceous and Devonian reservoirs have a similar source rock, which is also the same source as that of the majority of conventional oil accumulations in Mississippian and Lower Cretaceous reservoirs throughout the Western Canadian Sedimentary Basin. The Late Devonian Bakken and Early Mississippian Exshaw formations comprise a continuum of regionally correlated, organic-rich (up to 35% total organic carbon), black shales covering much of the Western Canada sedimentary basin. These black shales are regionally significant hydrocarbon source rocks (and local reservoirs).

The source rock with most similar biomarker characteristics to these hydrocarbons is the Exshaw Formation (Mississippian age). This is also the only major source rock with the areal extent to be able to source oils that show similar biomarker characteristics found in reservoirs that range from northeast British Columbia to northern Montana. In the absence of suitable traps along the migration fairway, much of the oil continued to migrate updip eastwards, from the source area, until it reached the surface in the area of the Athabasca and other oil sand deposits (Fig. 7). The Mannville reservoirs probably were not buried very deeply when migration occurred, since they show little diagenetic effects (i.e., cementation). Oil sands from the Athabasca area are often just loose quartz grains cemented by bitumen which, after extraction of the bitumen, resemble beach sand. In west-central Alberta, thick successions of Upper Paleozoic and Lower Mesozoic (Triassic) strata were deposited and preserved, which resulted in earlier onset of hydrocarbon generation from the Exshaw in this region. Peak hydrocarbon generation occurred between about 107 Ma and 87 Ma. Migration of Exshaw oil would have been occurring at about the same time as deposition of the Upper Mannville strata in eastern Alberta. In the more southern oil sand regions, Upper Paleozoic strata are thinner, and Triassic strata are absent, and as a result peak hydrocarbon generation did not occur there until the time of the Laramide Orogeny (Paleocene – Eocene). There, the Exshaw did not achieve peak hydrocarbon generation until about 56 Ma. The later episode of hydrocarbon generation and migration may account for the generally lower levels of biodegradation observed in these fields. It is also consistent with the more consolidated nature of the host reservoir rocks, which were lithified prior to filling, unlike stratigraphically equivalent oil sands reservoirs to the north. Oil Sands Extraction and Processing In the Athabasca area, mining operations are used to recover solid hydrocarbons from near-surface sands. At Cold Lake, Wabasca, and Peace River, Cyclic Steam Injection (CSS) and Steam Assisted Gravity Drainage techniques (SAGD) are used to recover very heavy crudes. About 20% of the oil sand reserves in Alberta is recoverable by surface mining; in-situ technologies need to be used for the remaining 80% of the oil sands that are buried at depths exceeding 50 - 75 m. Today, oil sands are recovered in open-pit mines near Fort McMurray by truck-and-shovel operations. Before the oil sand can be mined, roughly 1 to 3 m of organic deposits are removed and stockpiled for reclamation purposes. Over 25 meters of overburden is removed, which includes glacial deposits and any bedrock that lacks oil sands. The oil sand deposit itself is approximately 50 m thick.

The hydraulic/electric shovels used for mining oil sands are the biggest in the world - digging 80 tons of material with each scoop (Fig. 8). The haul trucks at Athabasca, like the Caterpillar 797 shown in Fig. 8, for example, are the largest in the world. These are 3,550 horsepower trucks (comparable to modern railroad diesel locomotives!) and can carry almost 400 tons of payload.

Fig. 8. A Bucyrus 495HF Electric Shovel Fills the World's Largest Mining Truck, a 400-ton Caterpillar 797B, with Just Five Passes at Shell’s Muskeg River Mine Site.

Once the oil sand is mined, the trucks transport and deposit it into double-roll crushers to break up big lumps of oil sand and rock. The oil sand is then conveyed to a mixing operation that combines the oil sand with hot water to create a slurry that is pumped via pipeline to the extraction plant. Temperatures in this process range from 35°C to as high as 80°C. Finally, the separated bitumen is diluted with lighter hydrocarbons and upgraded to Synthetic Crude Oil (SCO) - a mixture of pentanes and heavier hydrocarbons. In-situ technologies, such as Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are used in commercial field-scale operations for the more deeply buried deposits. Canada's largest in-situ bitumen recovery project uses CSS at Cold Lake. Steam injected down the well bore into the reservoir heats the bitumen. This is followed by a soak time, and then the same well bore is used to pump fluids to the surface. At Cold Lake about 3,200 wells are currently operating from multiple pads, with two above ground pipelines, one to deliver steam and the other to transport fluids back to the processing plant.

At Athabasca, the SAGD technology is used (Fig. 9). Horizontal well pairs (700 m long with 5 m vertical separation) are drilled from surface pads to intersect the bitumen pay. Steam from the upper injector well expands, reducing the viscosity of the bitumen, allowing the bitumen to flow into the return well bore.

Fig. 9. Steam Assisted Gravity Drainage (SAGD). http://www.conocophillips.com/EN/susdev/ethics/oilsands/Pages/index.aspx

Continuing challenges for economic in-situ bitumen recovery involve water and gas requirements for steam generation, reclamation, and emission controls of greenhouse gases. Generally, it takes 28 m3 (1000 ft3) of natural gas and from 2.5 to 4 barrels of water to produce one barrel of bitumen. Reclamation of mining sites is done to return the strata to at least the equivalent of their previous biological productivity.

Devonian Carbonate (Grosmont) Heavy Oil Accumulations The Upper Devonian Grosmont platform in Alberta, Canada, is the world’s largest heavy oil reservoir in carbonate rocks. The Grosmont Formation is the carbonate host to approximately 64 billion m3 (about 406 billion barrels) of low-gravity (API ~5° to ~9°) bitumen (Energy Resources Conservation Board, June 2011), at an average depth of about 250 – 400 m. The Grosmont Formation is a dolomitized, shallow marine and tidal flat carbonate complex characterized by high bitumen saturation, extensive vertical fracturing, karsting, and high permeability. Grosmont-hosted bitumen is more biodegraded, and of lower quality, than that of the overlying Cretaceous oil sands.

The Grosmont forms an areally-extensive northwest-southeast trending carbonate complex 150 km wide and at least 600 km in length in northern Alberta (Fig. 10).

Fig. 10: Map of the Grosmont Carbonate Platform.

http://www.geoconvention.com/uploads/2012abstracts/core/264_GC2012_Controlling_Chaos.pdf

Stratigraphy and Depositional Setting The Grosmont Formation is time-equivalent to portions of the Leduc, Duvernay, and Ireton formations and consists of a series of stacked east to west progradational carbonate ramp depositional cycles. The sub-Cretaceous unconformity is the boundary between the Devonian units and the overlying Cretaceous siliciclastics (Fig. 11). This angular unconformity represents over 200 million years of earth history, during which time multiple erosional and karsting events, combined with subtle structural movements and the development of the foreland basin, acted to produce a porous and irregular paleo-depositional surface. The Cretaceous flat-lying Wabiskaw-McMurray marine and fluvial siliciclastics were deposited directly over the porous carbonates.

Fig. 11. Stratigraphic Relationships in the Grosmont Area. http://www.ags.gov.ab.ca/conferences/grosmont_part1.pdf

Establishment of the unconformity directly influenced and contributed to the development of the Grosmont as a highly porous and permeable hydrocarbon reservoir (see Fig. 12). The various lithologies within the Grosmont reflect deposition in a spectrum of shallow water carbonate facies on a broad carbonate ramp. Facies range from lower ramp mudstones through upper ramp skeletal grainstones, and inner ramp peritidal wackestones to mudstones. Layers of anhydrite and related solution-collapse breccias occur at several stratigraphic levels. These evaporites are referred to as the Hondo Formation or Member.

Subsequently, these rocks were dolomitized, buried to a depth of about one kilometer, and then exhumed at the surface no later than the Early Cretaceous. Meteoric water influx caused selective dissolution and leaching, and resulted in the development of paleokarst features, such as sinkholes and caverns. Distinguishing characteristics of the carbonate reservoir facies are pervasive irregular vugs (.5 – 1.5 cm diameter) commonly connected by short, sub-vertical fractures (Fig. 12). Cavernous porosity occurs locally – these zones can exceed 35% porosity and 10 Darcy perm. Most of the present porosity and permeability is due to fracturing and karstification.

Fig. 12. Karsted Vuggy Dolomite, Grosmont Fm., with Bitumen Bleeding from the Developed Vug/Fracture Network.

http://www.laricinaenergy.com/uploads/tech/choa_11_10_08.pdf Diagenesis and Reservoir Development After deposition, the Grosmont went through five stages that led to the development of its remarkable reservoir characteristics. Throughout a history of repeated subsidence, uplift, and erosion, the Grosmont platform was affected by many diagenetic processes that partially overlapped in time and space. The processes that most affected the current reservoir characteristics on a regional scale were dolomitization with partial subsequent recrystallization, fracturing, karstification, migration of light hydrocarbons, and oil degradation to bitumen.

Dolomitization Dolomitization by density-driven reflux was the first pervasive diagenetic process. The Cooking Lake platform and the Leduc reefs are completely dolomitized, as are the upper parts of the Grosmont. Stratigraphically lower units in the Grosmont are only partially dolomitized and contain significant amounts of limestone. Petrologic and geochemical data suggest that there were at least two dolomitization events caused by fluids of differing composition and hydrologic systems. Dolomitization resulted in locally abundant vuggy and coarsely-crystalline inter-crystalline porosity. Fracturing The Grosmont reservoir is heavily fractured. A dense fracture network was created in three or four phases. Most fractures probably originated from collapse following subsurface salt dissolution and/or from Laramide tectonics far to the west. Dissolution of the underlying Middle Devonian evaporites resulted in the first widespread episode of fracturing in the Grosmont platform. This phase was driven by meteoric water invasion and salt dissolution during the Late Jurassic-Early Cretaceous that also karstified the overlying Upper Devonian carbonates. Tectonic fracturing was induced by crustal loading in the fold-and-thrust belt. Laramide orogenesis created a migrating bulge in the Grosmont region that progressed eastward through multiple pulses of basin-wide crustal flexing. The axis of the crustal bulge was situated directly under the Grosmont platform during the latest Cretaceous to Paleocene/Eocene, stressing and fracturing the brittle dolomites (Fig. 13).

Fig. 13. Fracture and Karst-Breccia Fabric in Grosmont Dolomite Cores. http://www.geoconvention.com/uploads/2012abstracts/008_The_Grosmont.pdf

Karsting In addition to fracturing, the Grosmont reservoir is extensively karstified as well. Individual karst features range in scale from tens of meters (caves) to sub-micrometers. Karsting was polyphase and polygenetic, in that dissolution affected the platform multiple times and was driven by more than one process. At the large scale, the most prominent karst features are circular to oval sinkholes, between 30 and 150 m in diameter. They are found right below the regional sub-Cretaceous unconformity, and can be recognized on seismic lines. Smaller karst structures can be recognized on neutron density and caliper logs. In core, karst can be identified as solution-collapse breccias and intra-formational breccia infills (Fig. 12 and 13). Some breccia units appear to be stratiform and can be correlated over several townships. These breccias probably originated from evaporite dissolution and collapse under a sedimentary overburden. A prolonged and widespread period of karstification that affected east-central Alberta occurred during the Late Jurassic - Early Cretaceous. The timing of this karst development in the Grosmont region is provided by incised valleys and the numerous sinkholes along the regional sub-Cretaceous unconformity, which is overlain by Lower Cretaceous clastics. This episode of surface dissolution and cave collapse (see Fig. 4) reflects the generally warm climate in what is now Alberta during a time of relatively warm global climate, as well as Alberta’s location at relatively low latitudes during this same time. Oil migration and emplacement Several recent studies have evaluated the most likely source rocks, their maturation, timing of oil migration and emplacement, and the relative contributions of each source rock to the updip reservoirs. Organic geochemical studies suggest that the bitumens in the Cretaceous oil sands and in the Grosmont reservoir are similar in composition, suggesting a common origin. Specifically, biomarker characteristics of the Grosmont bitumen resemble those of the Carboniferous Exshaw source rock, implying that the Grosmont was sourced from the Exshaw. At least one recent study, though, proposed source rocks in the Jurassic Fernie Group rather than from Devonian or Carboniferous sources. The time of hydrocarbon emplacement in the reservoir has been determined to be between 90-40 m.y. ago, with the bulk of oil emplacement having taken place in the window of 70-50 m.y. ago. Some of the Paleozoic source rock contribution may have migrated to the Grosmont region as early as 118-108 m.y. ago.

Biodegradation Bitumens in the Grosmont are strongly to severely biodegraded. Biomarker comparisons of the bitumen with the Exshaw source rock affirm the severe degree of biodegradation in the Grosmont. Biodegradation occurred through bacterial action associated with fresh-water, meteoric influx. The extra-heavy nature and high viscosity of the bitumen actually impedes reservoir development because it reduces effective permeability. Development The Grosmont bitumen reservoir represents a massive resource with no proven recovery technology. There have been earlier attempts to investigate the effectiveness of various production methods. Unocal conducted several pilot tests from 1975 to 1979, and from 1980 – 1986 Unocal conducted a vertical well cyclic steam stimulation (CSS) pilot at the Buffalo Creek site in township 88-19W4. Chevron performed steam pilot tests from 1984 to1985. The development of the Grosmont has remained largely dormant over the past two decades, overshadowed by the intense activity in the Alberta oil sands clastic formations, and discouraged by low commodity prices. The transition from exploration to pilot project to commercialization requires extensive modeling combined with real-world testing of competing methods. With the current state of technology development within the oil sands, there is a renewed interest in the Grosmont as a significant exploitation target. Several companies are taking inventory of the deposit through intensive core-delineation well programs, and some are proceeding with pilot programs. Laricina Energy is conducting tests at their Saleski pilot test site with a carbonate project currently in operation using Steam Assisted Gravity Drainage (SAGD). They are expecting commercial-scale production by 2014. Osum Oil Sands Corp. is proceeding with a project they describe as “Subway to the Wellhead.” They are attempting to exploit the Grosmont with massive vertical borings and a network of tunnels and chambers with SAGD wells installed underground. The outlook for successful production is good and possibly even near-term. However, development of the Grosmont bitumen is still in its infancy and many technical issues still need to be addressed. References used in this report Guide to the Athabasca Oil Sands Area, 1973. Information Series 65. Carrigy, M. A., ed. Canadian Society of Petroleum Geologists Oil Sands Symposium, 211 pgs.

Regional Geologic Framework, Depositional Models and Resource Estimates of the Oil Sands of Alberta, Canada, 2008. F. J. Hein and R. A. Marsh. Proceedings for the World Heavy Oil Congress, 2008. PAPER 2008-320. Accessed April 10, 2012. http://emd.aapg.org/members_only/oil_sands/WHOC08HeinMarsh2008-32001_18.pdf Field Trip Guide. Regional Sedimentology and Processes of Deposition of the Athabasca Oil Sands, NE Alberta, 2005, F.J. Hein and D.K. Cotterill. AAPG/EMD Field Guide. Accessed April 10, 2012. http://emd.aapg.org/members_only/oil_sands/field_guide/index.cfm Origin of the Athabasca Tar Sands, 2000. Fowler, M. and Riediger, C., in Barson, D., et al, Hydrogeology of Heavy Oil and Tar Sand Deposits, GeoCanada 2000, The Millennium Geoscience Summit, Field Trip Guidebook No. 14, p. 117-127. Geological Review and Bitumen Resource Appraisal of the Grosmont Formation within the Athabasca Oil Sands Area. Elaine Wo, Laifeng Song, Travis Hurst, and Nina Sitek. Search and Discovery Article #80130 (2011). Document accessed April 10, 2012. http://www.searchanddiscovery.com/documents/2011/80130wo/ndx_wo.pdf Geology of the Upper Devonian Grosmont Carbonate Bitumen Deposit, Northern Alberta, Canada. M. Buschkuele and M. Grobes. Website accessed 10 April 2012. http://www.ags.gov.ab.ca/conferences/grosmont_part1.pdf Stratigraphy and Sedimentology of the Upper Devonian Grosmont Formation, Northern Alberta, 1983. W.G. Cutler. Bulletin of Canadian Petroleum Geology, v.31 (4), p. 282-325. Regional Stratigraphy of the Upper Devonian Grosmont Formation, Northern Alberta. Open File Report 1986-02. Accessed April 10, 2012. http://www.ags.gov.ab.ca/publications/abstracts/OFR_1986_02.html A Look at the Grosmont Carbonate Reservoir. Accessed April 10, 2012. http://www.osumcorp.com/blog/2011/a-look-at-the-grosmont-carbonate-reservoir/ Saleski Grosmont Carbonates Accessed April 10, 2012. http://www.osumcorp.com/about-osum/project-areas/saleski/ Numerical modeling of reflux dolomitization in the Grosmont platform complex (Upper Devonian), Western Canada sedimentary basin, 2003. Gareth D. Jones, et al, AAPG Bulletin, August 2003, v. 87, no. 8, p. 1273-1298. The Grosmont: a complex dolomitized, fractured and karstified heavy oil reservoir in a Devonian carbonate-evaporite platform. GeoConvention 2012. Accessed April 10, 2012. http://www.geoconvention.com/uploads/2012abstracts/008_The_Grosmont.pdf