Geology of bitumen and heavy oil: An overview

Author’s Accepted Manuscript Geology of Bitumen and Heavy Oil: An Overview Frances J. Hein

www.elsevier.com/locate/petrol

PII: DOI: Reference:

S0920-4105(16)31043-9 http://dx.doi.org/10.1016/j.petrol.2016.11.025 PETROL3754

To appear in: Journal of Petroleum Science and Engineering Received date: 8 August 2016 Revised date: 3 November 2016 Accepted date: 17 November 2016 Cite this article as: Frances J. Hein, Geology of Bitumen and Heavy Oil: An O v e r v i e w , Journal of Petroleum Science and Engineering, http://dx.doi.org/10.1016/j.petrol.2016.11.025 This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting galley proof before it is published in its final citable form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

Geology of Bitumen and Heavy Oil: An Overview Frances J. Hein Alberta Geological Survey, Alberta Energy Regulator Suite 1000, 250 – 5th Street SW Calgary, Alberta, Canada T2P 0R4 [email protected]

Abstract On a world-wide basis there is an estimated 5.6 trillion barrels of bitumen and heavy-oil resources which occur in over 70 different countries, with most of the heavy-oil in Venezuela and most of the bitumen in Canada. The most common plate-tectonic settings in which the heavy-oil and bitumen are found are in continental multi-cyclic marginal basins and in continental rift basins. Heavy oil and bitumen resources are largely a result of natural degradation of formerly conventional oil accumulations. The natural degradation for most is biologic in origin, with the result that the majority of heavy-oil and bitumen deposits is characteristically in younger rocks (Cretaceous and younger) and at shallow depths (usually < 200 m, up to 2,000 m maximum). At a deposit-scale it is necessary for communication to have been established between the surface and subsurface to facilitate the biologic contamination of the pre-existing light petroleum reservoirs. Communication is through loss of caprock integrity, associated with major erosion (creation of unconformities), faulting, fracturing; and, for carbonate host-rocks, karstification. Two cases are discussed to illustrate these geologic processes: 1) the influence of the subCretaceous unconformity on the Cretaceous oil-sands in the Western Canada Sedimentary Basin; and, 2) the influence of faulting, fracturing and karstification on the Grosmont carbonatebitumen deposit of northeastern Alberta.

Keywords: Geology overview, bitumen, heavy oil

1. Introduction As conventional petroleum energy resources become depleted and more difficult to find, greater reliance is being placed upon unconventional oil resources to fill existing and future global energy needs, until anticipated transitions are complete to a globally-sustainable low-carbon energy system. It is clear from a number of analyses that this transition period will take a long time; and, until alternative sources are found for petroleum products (including non-energy uses, such as medical-plastics and other plastics industries), the demand for hydrocarbons will continue.

1

The purpose of this paper is to give an overview of the geologic characteristics of the major bitumen and heavy oil occurrences – their basin settings; the host rocks; and other commonalities related to early and later diagenesis of both the host rocks and the reservoir fluids. Such a review gives context for understanding some of the natural and engineering challenges associated with production of hydrocarbons from these important unconventional energy resources.

2. Background On a world-wide basis there is an estimated 5.6 trillion barrels of bitumen and heavy-oil resources which occur in over 70 different countries (Hein, 2006; Hein et al., 2013; Meyer and Attanasi, 2003; Meyer et al., 2007; Schamel et al., 2015; Zou, 2013). Most of the bitumen and heavy-oil (~ 70%) is hosted within three countries in the Western Hemisphere – Venezuela, Canada and the U.S.A. Other areas with important combined bitumen and heavy-oil deposits include: the Middle East (heavy-oil), Asia (mainly China), Africa, and Russia (Table 1, Figure 1) Table 1. Major world heavy-oil and bitumen estimated remaining technically-recoverable reserves (see Figure 1, data from Alberta Energy Regulator, 2016; Hein, 2006; Kashirtsev and Hein, 2013; Hills et al., in press; Meyer and Freeman, 2006; Meyer et al., 2007; Humphries, 2008). Note: breakdown of numbers is given only for the U.S.A., with the totals given in bold; differences in the Canada (Alberta) numbers from those in Kashirtsev and Hein (2013) relate to bitumen production and reassessments by the Alberta Energy Regulator (2016) (also see McGlade, 2012). Region Africa Asia Canada (Alberta) Europe Middle East Russia Venezuela U.S.A. Total Alabama Alaska California Texas Utah Other States Grand Total

Heavy Oil (bbl)

Bitumen (bbl) 7.2 29.6

Total (bbl) 43 50.2 42.8 72.4

Heavy Oil (%) 1.5 6.17

Bitumen Total (%) (%) 11.91 5.97 11.86 8.61

2.71 4.9 78.2 13.4 265.7 78.33 0 0.14 62.85 11.84 0.06 3.44

165 0.2 0 33.7 0.1 76.19 6.36 19 5.34 5.44 32.33 7.72

167.71 5.1 78.2 47.1 265.8 154.52 6.36 19.14 68.19 17.28 32.39 11.16

0.565 1.02 16.29 2.79 55.35 16.32 0 0.029 13.09 2.47 0.012 0.716

45.71 0.055 0 9.34 0.027 21.11 1.76 5.26 1.48 1.5 8.96 2.14

19.94 0.606 9.29 5.6 31.6 18.37 0.756 2.28 8.11 2.05 3.85 1.33

480.04

360.99

841.03

100

100

99.99

Despite the 2016 continued decline in world oil prices, global interest continued in bitumen and heavy-oil resources, particularly in the Western Canada Sedimentary Basin. This was aided, in 2

part, by the declining Canadian dollar (which is tied to West Texas Intermediate (WTI) oil prices) and the reduction in operating costs by producers (Curran, 2016). In addition, many bitumen- and heavy-oil projects have a very long lead- and production time, with commonly 30 to 40 years from initial start-up to shut-down and remediation (Hein et al., in press). Figure 1. Pie charts of major world heavy-oil and bitumen estimated remaining technically-recoverable reserves: A) Heavy Oil; B) Bitumen; C) Bitumen and Heavy Oil; n= total billion barrels of oil (see Table 1, data from Alberta Energy Regulator, 2016; Hein, 2006; Kashirtsev and Hein, 2013; Meyer and Freeman, 2006; Meyer et al., 2007; Humphries, 2008). Heavy-oil and bitumen are distinguished from each other, and from conventional light (“normal”) oil by their viscosity, with the main distinction that extra-heavy and heavy-oil will flow to a wellbore under natural reservoir conditions; whereas bitumen is too viscous at reservoir temperature and pressure to flow to the wellbore, without artificial stimulation (such as steam or steam with solvent). Heavy-oil has a specific gravity near water, with API gravity between 10o and 22.3o (1 g/cc to 0.92 g/cc); and oil viscosity between 100 cP and 10,000 cP (Figure 2). Bitumen is denser than water, with a minimum viscosity similar to honey or molasses, with a gas-free viscosity > 10,000 cP; and, in general, an API gravity < 10o. In addition to reservoir temperature and pressure, the viscosity of heavy-oil and bitumen is influenced by a wide range of factors, including molecular-chain length and composition and natural dissolved gas content; thus, there is not a direct (absolute) correlation between oil viscosity and density (Mehrotra and Svrcek, 1986; Masliyah et al., 2011, Schamel et al., 2015). Heavy oil and bitumen resources are largely a result of natural degradation of formerly conventional oil accumulations, with relatively minor accumulations due to immature oil being expelled directly from source rocks (Meyer et al., 2007; Schamel et al., 2015). Most of the heavy-oil and bitumen deposits are within younger (Cretaceous and Neogene-Paleogene) rocks at shallow depths (< 200 m to 2,000 m) (Hein, 2006; Zou et al., 2013). The heavy-oil and bitumen reservoirs are (or were at one time) in contact with the atmosphere, shallow groundwater or deeper formation-water aquifers. Bitumen and heavy-oil deposits may be associated with water-, oil- and “tar”1 springs and “tar” lakes, oil seeps, and/or mud volcanoes, which are commonly near faults and unconformities. Rarely bitumen and heavy-oil accumulations occur in areas of igneous rocks (near Tampico, Mexico, Tiratsoo, 1973; and West Rozel Point, Utah, USA, Bortz, 1987). In areas with reservoir temperatures below the pasteurization temperature (~ 80 oC) most of the alteration of the oil is due to biodegradation, in which anaerobic and/or aerobic bacteria remove the lighter hydrocarbons (Adams et al., 2013; Bata et al., 2016; Larter et al., 2003, 2006). Biodegradation leaves a highly-viscous residuum, commonly enriched in heavy and base metals, and larger molecular components such as oxygen, sulfur and nitrogen (Blanc and Connan, 1994; Gruson, 2005; Head et al., 2003; Meyer and Freeman, 2006). In other cases, rare earth elements (REE) and other relatively rare elements are at enriched concentrations within heavy-oil and bitumen. These include vanadium, nickel, titanium, selenium and tellurium (Majid and Sparks, 1

Note: the usage of the word “tar” to refer to bitumen and/or heavy-oil is a misnomer. Tar is an artificial, man-made substance, which, by definition, is produced through the distillation of organic material (Masliyah et al., 2011).

3

1999; Parnell et al., 2014). The natural enrichment of some of the larger compounds (i.e. sulphur, oxygen and nitrogen) presents particular technical and environmental challenges in the production, refinement and transport of hydrocarbons from these nonconventional resources. Because much of the natural degradation is biological (along with some water-washing, Figure 2. Cross-plot of oil density (API o oil gravity) versus oil viscosity (cP) showing the characteristics of the nonconventional bitumen, extra-heavy and heavy-oils versus the conventional “normal” light oil. Properties are from producing oil-sand accumulations, data from Oil & Gas Journal, April 2, 2012) (from American Association of Petroleum Geologists, Energy Minerals Division, 2015; Schamel et al., 2015; prepared by Steven Schamel; data from Oil and Gas Journal, April 2, 2012). and subsurface. This communication oxidation and evaporation), many of the heavy-oil and bitumen resources occur in areas where there was enhanced communication between the surface provides a conduit(s) for biologic contamination of the trapped light-oil reservoirs. Such conduits include: shallow “bedrock valley” groundwater aquifers; faults and fractures; unconformities on the land (or paleo-land) surface; and, slippage surfaces associated with local landslides and other mass-wasting features. For these reasons, many of the major heavy-oil and bitumen accumulations are in areas of uplift, faulting, karstification, and/or occur along major unconformities associated with the shallow, updip margins of petroleum basins (Hein, 2006; Meyer et al., 2007).

3. Large-Scale Geologic Basin Settings . Meyer et al. (2007) in their world overview of heavy oil and natural bitumen occurrences classified the occurrences according to a description of the petroleum basins and their general geological and tectonic features, using what has become known as the Klemme Basin Classification (St. John et al., 1984; Klemme, 1984; summarized in Meyer et al., 2007). In this analysis it was found that most (by number) of the heavy-oil and bitumen accumulations were in two main types of geological basins: the II.Continental Multicyclic Basins (IIA, IIB, IIC, total= 45%) and III. Continental Rifted Basins (IIIA, IIIB, IIIC, total = 48%) (Table 2; Figure 3). Type II. Continental Multicyclic Basins form on cratonic continental margins with a more complex geologic history than the Type I. Cratonic Interior Basins (Table 2). The continental multicyclic basins are complex sags on the margins of the cratons, which for the Type IIA begin as sags that evolve into foredeeps; and for the Type IIB start out as rift basins, which may change into sag basins through time. Both have similar architectures – they tend to be linear, with asymmetric profiles. The bitumen in the Type IIA basins accounts for over 2,623 billion barrels, or ~ 48%) of the world bitumen resource, with the largest volumes of bitumen in the Western Canada Sedimentary Basin. By contrast only moderate resources of heavy oil are contained within the Type IIA basins. The Type IIA host about 158 billion barrels of heavy-oil in place, mainly within three basins – the Western Canada Sedimentary Basin; the Putumayo Basin, Colombia and Ecuador, S. A.; and, the Volga-Ural Basin, Russia. Type IIC basins are similar to the Type IIA basins, being generally linear and asymmetrical in profile; but, in contrast to the Type IIA type, they form in areas of plate-tectonic collision (convergent margins). The Type IIC basins host 1,610 billion barrels of heavy oil in place, including the Eastern Venezuela Basin and 4

the Zagros and Arabian basins of the Middle East, which in total account for ~ 95% of the total world heavy-oil in place (Meyer et al., 2007). The largest extra-heavy/bitumen accumulation is in southern part of the Eastern Venezuela Basin, within the Orinoco heavy-oil belt. The structural setting of the Orinoco heavy-oil belt is very similar to the bitumen deposits of the Western Canada Sedimentary Basin, which occur in the updip margins of a foredeep basin where it laps onto the continental craton (Martinius et al., 2013). Of the Type III rift basins, most of the heavy-oil and bitumen deposits occur within the Type IIIB Rifted Convergent Margins. The basins in this plate-tectonic setting tend to be small and linear with irregular profiles. Wrench tectonics and oceanic crust consumption are important in their overall geologic evolution. Although the Type IIIB basins are small, and they tend to host relatively smaller volumes of heavy-oil and bitumen, such accumulations are very important for local industries. Some of the important Type IIIB rift-basins that contain heavy-oil and bitumen include the Bone Gulf Basin, Indonesia and other basins in the Java-Sumatra collision zone. In the Western Hemisphere heavy-oil along with bitumen is commonly hosted in the Type IIIB basins of the California Continental Borderland (Hein, 2013), with the largest heavy-oil accumulation in the Maracaibo Basin of Venezuela and Colombia, S. A. (Meyer et al., 2007). In their assessment Meyer et al. (2007) indicate a high tendency of larger (by volume) heavy-oil and bitumen accumulations in those basins of the Klemme Type IICa. These are the continental interior multicyclic basin, which occur in close proximity to collision zones or paleo-plate margins. Tectonics is convergent, the basins tend to be large and elongate, with asymmetrical profiles. Regional source rocks are common, with large traps and basins, and fractured reservoirs, along with high geothermal gradients. Traps for the petroleum reservoirs are basement uplifts, arches and fault blocks. The only other Klemme basin type that had a high predisposition for bitumen accumulation (but a low tendency for heavy-oil) is the Type IIA, Continental Multicyclic Basins, and Craton Margin Composite. These basins tend to have moderate to large, circular to elongate shapes, with asymmetrical basin profiles. Traps are basement uplifts, mostly arches or blocks; however, in contrast to the Type IICa, the Craton Margin Composite basins have low geothermal gradients. What is common to both the Type IICa and IIA is the moderate to large size of the basins, which given sufficient total organic carbon contents, have the potential for large-scale oil migration from vast source rocks. Both also experience tectonics (faulting, uplift, fracturing) at different stages, and in particular, at later, post-emplacement periods at shallow depths, to allow for biodegradation of the petroleum reservoirs. Table 2. Number and per cent of major world heavy-oil and bitumen contained within different types of petroleum basins, using the Klemme Basin Classification scheme (data from Meyer et al., 2007). See Figure 3. Klemme Basin #

Basin Description

Basin Form

Basin Examples

# Basins

% Basins

9

4.2

I

I. Cratonic Interior Basins

Sag

Illinois, USA; Tunguska, Siberia

II

II. Continental Multicyclic Basins

1. Platform or Sag; 2. Foredeep

Western Canada Sedimentary Basin, Canada;

5

IIA

A. Craton Margin Composite

IIB

B. Craton Accreted Margin Complex

1. Rift; 2. Sag

C. Crustal Collission Zone - Convergent Plate Margin

1. Platform or Sag; 2. Foredeep

IIC IICa

a. Closed

IICb

b. Trough

IICc

c. Open

III IIIA

IIIB IIIBa

III. Continental Rifted Basins

a. Back Arc

38

17.76

West Siberia and TimanPechora, Russia

18

8.41

Arabian, Middle East; Eastern Venezuela, Venezuela, Trinidad & Tobago; Zagros, Iran and Iraq Caltanisetta, Italy and Malta; Durres, Albania

14

6.54

14

6.54

Campeche and Tampico, Mexico; North Slope, Alaska; East Texas, Gulf Coast, Mississippi and South Texas Salt Domes, USA

13

6.07

Bohai Gulf, China; Gulf of Suez, Middle East; Northern North Sea, , Norway, United Kingdom

29

13.53

Akita, Japan; Barito, Indonesia; Beibu Gulf, China; Central Sumatra, Indonesia; Cook Inlet, Alaska, USA; Tonga, Tonga; Sunda, Indonesia; East China, China and Taiwan

19

8.88

Rift/Sag

A. Craton and Accreted Zone Rift

B. Rifted Convergent Margin - Oceanic Consumption

Putumayo, Colombia & Ecuador; Volga-Ural, Russia; Uinta, Utah, USA

Rift/Sag Rift/Wrench

IIIBb

b. Transform

Continental Border- land, California, USA; North Sakhalm, Russia

14

6.54

IIIBc

c. Median

Maracaibo, Venezuela and Colombia; Middle Magdalena, Colombia

11

5.14

IIIC

C. Rifted Passive Margin - Divergent

1. Rift; 2. Sag ; and 3.Rift/Drift

Otway, Australia; Pearl River, China; Mukalla, Yemen; Espirito-Santo, Brazil; Ghana, Ghana and Nigeria; Krishna, India

29

13.55

IV

IV. Delta Basins - Tertiary to Recent

Modified Sag

MacKenzie, Canada; Niger Delta, Cameroon, Equatorial Guinea, and Nigeria; Nile Delta, Egypt

3

1.4

6

V

V. Fore-Arc Basins

Subduction

Barbados, Barbados; Gulf of Alaska and Shumagin, Alaska, USA

Total

3

1.4

214

99.96

Figure 3. Pie chart of the per cent of major world heavy-oil and bitumen accumulations contained within different types of petroleum basins, using the Klemme Basin Classification scheme (data from Meyer et al., 2007). See Table 2.

4. Other Geologic Factors In addition to the overall geologic basin type, ultimately it is the other smaller-scale (< basinsize) geologic factors that are important to form heavy-oil and bitumen at the deposit- and reservoir-scale. The main smaller-scale geologic factors are those that allow for communication between the atmosphere, surface- and/or aquifers, with the originally underlying light hydrocarbon reservoirs. These include: faults, fractures, major erosion surfaces, such as unconformities (including bedrock glacial valleys) and karst features in carbonate host rocks. Most heavy-oil and bitumen accumulations are in combination structural-stratigraphic traps; although, at the updip margin of foreland basins, many of the traps are stratigraphic (Hein, 2006). It is also the loss of caprock integrity through faulting, fracturing, subsidence, and erosion that allows for vertical communication to subsurface petroleum reservoirs. The association of such features with the different geologic basins accounts for the tendency of heavy-oil and bitumen to occur more commonly in the Type II and III (by number) and the Type IICa and IIA (by volume) basins. Two examples are given illustrating these important geologic factors. These include: A) the subCretaceous unconformity in the Western Canada Sedimentary Basin; and, B) the karsted Grosmont carbonate-bitumen of north-central Alberta. 4.1 Sub-Cretaceous Unconformity, Western Canada Sedimentary Basin The world’s largest heavy-oil and bitumen accumulation is located in northeastern Alberta at the updip edge of the foreland basin, where the Cretaceous oil-sands unconformably overlie older sedimentary successions, which, in turn, are unconformable upon the Precambrian crystalline (igneous) basement (Figures 4, 5). Cretaceous fluvial-estuarine and nearshore clastics were emplaced upon a previously eroded landscape of older Devonian carbonates and younger (preCretaceous) clastics. Much of the deposition and preservation of the Cretaceous sands that host the heavy-oil and bitumen was affected directly by the pre-existing topography (accommodation space) that existed along the sub-Cretaceous unconformity (Barton, 2016a, b; Hathway, 2016; Hauck et al., 2016; Schneider et al., 2014). Provenance of the large, continental-scale, fluvial drainage systems that supplied material to the oil-sands areas extended as far southeast as the Appalachian Mountains (for Athabasca and Cold Lake); to the Western Cordillera, and at least as far southwest as the Alberta- Montana, U.S.A. border (for Peace River) (Benyon et al., 2014, 2016; Blum, 2015; Cant and Abrahamson, 1995, 1996).

7

Increased accommodation was along the trend of a regional SE-NW trending salt-dissolution front extending from SE Alberta/SW Saskatchewan to NE and north-central Alberta, into which the Cretaceous sand reservoirs of Athabasca, Cold Lake and Lloydminster areas were emplaced. Relief along the sub-Cretaceous unconformity was significant, increasing up to nearly 500 metres from southeast Alberta to the marine-influenced basin to the north (Schneider et al., 2014). In the Peace River area, further to the west, clastics were directly affected by forelandbasin tectonics/subsidence. In the Peace River oil-sands area, heavy-oil and bitumen accumulated mainly along the western margins of eroded and dissected carbonate highlands. Here accommodation was much greater than the more-shallow Athabasca oil-sands area, with a greater thickness of stratigraphic section deposited and preserved in the Peace River oil-sands. Less common are bitumen and heavy-oil deposits along the northern and eastern margins of the carbonate highlands (Alberta Energy Regulator, 2016), which have some connections to western and northwestern Athabasca oil-sands. Petroleum was expelled from source rocks located deep (> 5.5 km) in the subsurface west of Calgary and north of Grand Prairie, AB (Figure 4). Hydrocarbons migrated up dip for 100’s km to become trapped along the sub-Cretaceous unconformity beneath regional seals of the Cretaceous Mannville and Colorado Group shales (Figure 5). Where petroleum reservoirs onlapped the Precambrian basement rocks at shallow depths, later subsidence and down-faulting of underlying Devonian carbonate and evaporite rocks caused fracturing and local faulting of the regional seals. At shallower depths this resulted in contamination of the petroleum reservoirs, in which biologic and physical processes of oxidation, evaporation and local water-washing, degraded the original light conventional oils to bitumen in the Peace River, Athabasca and Cold Lake areas; and to heavy-oil in the Lloydminster area of the Alberta and Saskatchewan subsurface (Figure 4). Sediment in the Peace River oil-sands area was buried to much greater depths, which in the western and southwestern limits of the deposit, exceeded the pasteurization temperature. Downdip of the paleotemperature pasteurization isotherm (~ 80oC) petroleum fluids were not subject to biodegradation; updip of the isotherm, biodegradation was pronounced (Adams et al., 2013). These factors contrast with the Athabasca and Cold Lake oil- sands areas where burial and geothermal gradients were less, and in-situ reservoir paleotemperature was less than the pasteurization temperature, allowing for biodegradation proceeding without sterilization effects. The overall result is an increasing level of biodegradation; and a concomitant trend of Figure 4. Alberta oil sands, Canada, with bitumen pay-thickness in metres for the Peace River, Athabasca and Cold Lake oil-sands areas. In areas of thin overburden (Surface Mineable area) bitumen is recovered by truck and shovel; in areas of thick overburden (Insitu Recoverable), bitumen is recovered using largely thermal technologies, including Steam-Assisted Gravity Drainage (SAGD, mainly in Athabasca) and Cyclic Steam Stimulation (CSS, mainly in Cold Lake). Figure 5. Schematic SW-NE cross section of the Alberta foreland basin, Western Canada Sedimentary Basin (from Hein et al., 2013, modified from Head et al., 2003). increasingly more viscous and degraded oil from West Peace River (22o – 27o API)  Peace River/Cold Lake (6o – 13o API)  North Athabasca (6o – 9o API) oil-sands areas (Adams et al., 2013). 8

Once initial contamination of the petroleum reservoirs occurs, then a number of other biogeochemical and hydrological processes become important to account for the viscosity variation seen within heavy-oil and bitumen deposits (Adams et al., 2007, 2013; Barson et al., 2000; Fustic et al., 2011, 2013). Observed viscosity variation is related to the mass balance and mixing of new charge oil into the petroleum reservoirs coupled with the degradation due to biologic processes, largely dependent upon elevation (basal, lateral or top) and hydrodynamic charge of water legs within the reservoirs (Barson et al., 2000, 2001). Such hydrodynamic features, coupled with in-situ reservoir temperatures (related to local geothermal gradients); and, in particular, the bounding in-situ pasteurization reservoir paleotemperature, account for much of the viscosity variation seen within and between heavy-oil and bitumen reservoirs in the Alberta basin (Adams et al., 2007, 2013; Larter et al., 2003, 2006). In the Athabasca and Cold Lake oil-sands areas, there is a gas over bitumen issue that is unique to these bitumen-producing regions of the Province. This is because the natural gas and bitumen rights can be leased separately by Alberta Energy. The problem occurs when natural gas pools are in association with underlying or adjacent bitumen pools, particularly in shallow areas, with reduced reservoir in-situ pressures and thin overburden (Alberta Energy and Utilities Board, 2003). Production of natural gas in these areas may lower in-situ pressures, such that the ultimate recovery of the underlying (or associated) bitumen is compromised, resulting in ‘sterilization’ of the resource. After nearly a decade of inquiries and hearings, the Alberta Energy and Utilities Board shut-in over 900 gas wells which were in communication with underlying economic bitumen reservoirs, while, at the same time, allowing co-production in nearly 300 gas wells, which were not in communication with the bitumen reservoirs (Hein and Parks, in press). On a reservoir- and project-scale relief on the unconformity (with resultant accommodation space) during deposition of the sand reservoirs focused those areas where the thickest channel and valley-fill sands were deposited. Locally, there was subsidence related to karstification along the unconformity surface in northeastern Alberta, which, in addition to increasing accommodation space, also created porosity within the underlying Devonian carbonates, for later petroleum charging and infilling of reservoirs. In some cases, where paleotopographic lows on the unconformity were below the level of influx of petroleum during charging, basal waterbearing zones were never replaced by oil, and remained as basal water legs. Bottom pressures within the basal water legs may affect the maximum operating pressures for in-situ thermal recoveries and may be local thief zones to steam injection. In some cases, basal water-bearing zones may be interconnected between reservoirs and between development projects; such that there may be loss of steam to other subsurface areas; there may be inefficient recovery of oil from the steamed reservoirs; and, ultimately, there may be a reduction in pay-zone thicknesses both within individual reservoirs and within project areas (Jo and Ha, 2013a, b). 4.2 Karstic Carbonate-Bitumen, Western Canada Sedimentary Basin In addition to the Cretaceous bitumen and heavy-oil deposits, Alberta also hosts the world’s largest accumulation of carbonate-bitumen within the Devonian rocks beneath the subCretaceous unconformity. The largest of these, the Grosmont Formation carbonate-bitumen, underlies the western and northwestern part of the Athabasca oil sands (Figure 6). 9

The Upper Devonian Grosmont Formation (Woodbend Group) occurs in a broad area (> 100,000 km2) in north-central Alberta (Figure 6a). The Grosmont succession is mainly fossiliferous limestone and dolomite, originally deposited as a shallow-shelf carbonate platform, which was extensively affected by multiple periods of karstification, early and late diagenesis, and fracturing (Buschkuehle et al., 2007; Machel et al., 2012). Evaporites are locally developed in the Hondo Member of the Grosmont Formation, mainly in the subsurface southwest of Fort McMurray (Figure 6d, pink). The Grosmont Formation is the world’s largest low-gravity (API 5o – 9o) bitumen deposit that is hosted within carbonates, with an estimated minimal original oil inplace (OOIP) volume of ~ 400 billion barrels (Energy Resources Conservation Board. 2013; Hein and Marsh, 2008; Wo et al., 2011). Of this original oil in place volume, operators estimated that 318 billion barrels of bitumen are potentially recoverable from the Grosmont Formation (Barrett and Cimolai, 2008). In addition to these vast bitumen reserves, gas occurs within the Grosmont Formation at the updip erosional edge along the eastern and northeastern extent for the formation, with a downdip (WSW) transition into a regional aquifer (Anfort et al., 2001; Bachu et al., 1993), as the Grosmont succession changes into the fine-grained Ireton Formation (light green, Figure 6d) . Within the carbonate-bitumen deposit the total thickness of the Grosmont Formation varies from 10 m to 200 m (McDougall et al., 2008). Bitumen is hosted within separate reservoirs (LG, UGM1-3) separated from each other by the regional shale ‘breaks’ or marls, which are internal aquitards or aquicludes (Figure 6d). In the subsurface the Grosmont Formation limestone was largely replaced by dolomite (up to 98% or 100% replacement locally). Due to the postdepositional effects of dolomitization, fracturing and karstification, porosity and permeability is very heterogeneous in the formation. Porosity varies from 7 – 30%; permeabilities from nanoFigure 6. Grosmont carbonate-bitumen, northeast Alberta, Canada: a) Isopach bitumen Upper map of the Grosmont Platform succession, with outlines (blue, green and red) indicating various development; Lower schematic SW-NE cross section of the Grosmont carbonate platform, showing the unconformity between the Devonian carbonate and evaporites and the overlying Cretaceous oil-sands successions (McMurray Formation, Wabiskaw Member, Clearwater Formation). (Upper map modified from Alberta Energy Regulator, 2015; Lower cross section from Buschkuehle et al., 2007). Darcies to >> 5 Darcies. Porosity/permeability distributions are: original, diagenetic (related to karstification and dolomitization), and fracture-related (Figures 7 and 8) (Barrett et al., 2008). Hydrocarbon-potential in the Grosmont Formation is controlled by the porosity and permeability distributions at the time of hydrocarbon charging, by reservoir capping and containment, and by biodegradation of the original hydrocarbon reservoirs. The porosity and permeability distributions of the reservoir and cap rocks are a function of the original depositional lithofacies and of the later diagenetic effects. The Grosmont Formation is extensively and pervasively fractured and karstified along the updip subcrop edge, at its unconformable contact with the overlying McMurray Formation. The diagenetic history of the Grosmont Formation is complex and multigenerational, including karstification, carbonate-and evaporite-dissolution, dolomitization of limestone; disaggregation of dolomite, several stages cementation and 10

fracturing. Outside of the fracturing history, it is beyond the scope of this overview to discuss the complex diagenetic history of the Grosmont Formation. The reader is referred to the following references for this description (Barrett, 2016; Buschkuehle et al., 2007; de Joussineau et al., 2016; Machel, 2012). Fractures were created in three or four main phases, including an early (PennsylvanianCretaceous) phase that formed before the first major stage of karstification; intermediate (Early Cretaceous) stage associated with salt solution and collapse tectonics; late (Late Cretaceous) phase due to fore-bulge tectonics; and, recent stage due to glacial loading and modern collapse due to ongoing karstification. The fractures provide fluid pathways for thermal recovery; increase permeability within the reservoir; and may locally affect cap-rock integrity of units that overlie the carbonate-bitumen deposit. Early fractures facilitated the placement of hydrocarbons that were later biodegraded to bitumen; whereas later and recent fracturing may have caused leak off of hydrocarbons into the overlying McMurray Formation, if internal barriers or cap rocks were breached. Cores show a fracture complex of mixed karst-breccia clasts (some of which are faulted and bitumen-stained) and wall rock (Figure 8a), with scales of fractures varying from a few cm in crackle breccia (Figure 8d), to decimeters along contacts between wall rock and cave breccia (Figure 8a), to > 5+ m in core or interpreted on FMI logs. Similar scale features, ranging from 5 to10+ m in height, have also been observed in outcrop, on LIDAR images, and/or from seismic imaging and digital elevation modeling of the subsurface. Karst processes are both beneficial as well as detrimental to oil-trapping. A large flux of groundwater and deeper formation water fluids may dissolve and/or precipitate minerals, depending upon the local porewater geochemistry. With the creation of large vugs and caves, there may be subsidence, roof collapse, and propagation of faults and fractures, which may compromise regional seals and affect local cap rock integrity. The Grosmont carbonate bitumen underlies the western part of the Athabasca oil-sands area, in which there was shut-in of Grosmont gas due to its potential harmful impact on ultimate recovery of overlying bitumen in the Wabiskaw Formation (Energy Resources Conservation Board, 2011). In these hearings, the Board concluded that: 1) gas in the pools is in communication with the associated bitumen; 2) the bitumen is potentially recoverable using current and near-future technologies; and, 3) that continued production of natural gas from the pools presented proved to be an unacceptable risk to ultimate bitumen recovery from the Athabasca Wabiskaw deposit. In its final decision the Board concluded that all of the wells requested for interim shut-in should be permanently shut-in. Of the nearly 1300 shut-in gas intervals, the host reservoirs were evenly split between Cretaceous clastic (Wabiskaw Member and McMurray Formation, 48.4%) and Devonian carbonate (51.6%) reservoirs. Of the carbonate-gas intervals that were shut-in most were in the Grosmont (~75%), followed by the Nisku (~ 13%), Leduc (~ 9%), and Upper Ireton (~ 3%) formations (Energy Resources Conservation Board, 2011).

5. Reservoir Geology and Engineering Challenges for In-Situ Thermal Recovery At a local (field-scale) reservoir geology characterization is necessary to assess engineering challenges that may be faced regarding in-situ, largely thermal, development of heavy-oil and 11

bitumen that are too deep for recovery by surface mining. In Alberta, and elsewhere, the most commonly used in-situ technologies are Steam-Assisted Gravity Drainage (or SAGD, with or without solvent) or Cyclic Steam Stimulation (CSS) for bitumen; and, for heavy oil, primary or cold production, or cold heavy-oil production with sand (CHOPS) (Hein et al., 2013). Much of Figure 7. Core photograph of the Grosmont Formation carbonate-bitumen, with fracture (F), moldic (M), and vuggy (V) and porosity, well 00/04-28-089-20W4, depth 1077 feet (from Asgar-Deen et al., 2008). this in-situ technology was initially developed for the heavy-oil in California, and then further advanced in the Alberta oil-sands and heavy-oil areas. What distinguishes the Alberta oil-sands, in particular, is that the bitumen sands are “water-wet” – that is, a thin film of water coats the sand grains, and the bitumen (or heavy-oil) then infills the porosity between the sand grains (cf. Kapadia et al., 2015). By contrast, in oil-wet deposits, oil (including bitumen and heavy-oil) is in direct contact with the sand grains. As discussed by Hills et al. (in press), the in-situ (largely thermal) technologies developed and advanced in the “waterwet” Alberta deposits may not be as efficient or effective in recovery of oil from bitumen and heavy-oil deposits which are “oil-wet.” This is particularly true for many of the deposits in the U.S.A., notably for those of Alabama and Utah, for which technologies are only now being piloted. For example, in Utah it has been noted that development of the “tar sands” have been “commercially challenged.” Most recently, in 2015, a commercial demonstration project was Figure 8. Core photographs of fractured Grosmont Formation: Fracture/fault (or cave) with wall rock on the left side and intraformational breccia (or cave infill) on the right. Note differential oil stain within clasts and in wall rock. Some clasts were fractured before being deposited in the breccia. Many clasts are bitumen-stained whereas the matrix is not, indicating that oil migration and saturation occurred before the clasts were resedimented here. B) Bitumen seeping out of a vertical hairline fracture, which is common after cores have been stored in unrefrigerated facilities after a few years. C, D) Irregular ‘crackle breccia” fracture network (from Machel et al., 2012a, b). planned to produce oil from surface-mined oil-sand material using a “closed-loop solvent extraction” process (Jacobs, 2015; Schamel et al., 2015). To date, it is not known if this demonstration project was successful. On a micro- to macroscopic scale within the reservoir, it is important to know the composition of the grain components both within the framework and within the matrix. For example, quartz is fairly stable, even at high temperatures, and is relatively resistant to artificial diagenesis. This is in contrast with those reservoirs that are dominantly lithic rock fragments or feldspathic in composition, which are much more reactive under high-temperatures (Putnam and Pedskalny, 1983). Matrix is often clay – both in composition and in grain size. Clays occur as pore-lining, pore-filling and grain-coating phases within the grain framework. It is important to know whether the clays are water-sensitive (swelling, such as smectite, montmorillonite; and/or mixedlayer clays) and if there is potential for migration of fines or occluding permeability (such as 12

with booklets of kaolinite, or hairs of illite) within the reservoir during steaming (McKay and Longstaffe, 1997, 2013). Understanding the diagenetic (paragenetic) sequence that naturally occurred in the reservoirs could help predict the artificial reactions that may be associated with steaming or use of solvents within the reservoirs (Abercrombie et al., 1989). Other geologic challenges exist for the commercial recovery of oil and bitumen. In the Alberta oil-sands and heavy-oil areas, most of the bitumen and heavy-oil is hosted within fluvial-toestuarine and tidal marginal-marine deposits. These reservoirs are notorious for the amount of small-scale interbedding of mudstone with the oil-bearing sands and silts. Mudstone occurs both as intraclasts (Figure 9A) and as more continuous beds, at the base of coarsening-upwards marine-influenced parasequences (Figure 9C) (Alberta Energy and Utilities Board, 2003; Fustic et al., 2013; McCrimmon and Arnott, 2002; Pouderoux et al., in press). Local mudstone intraclasts may impede the upward flow of steam, affect steam conformance down a well-pair, and may serve as local baffles, that directly affect the efficiency of bitumen recovery within a SAGD operation. The more continuous mudstone beds at the base of the upper, tidal and marineinfluenced parasequences, are barriers that locally compartmentalize bitumen reservoirs (Fustic et al., 2011), with the potential that there may be stranded bitumen left in the reservoir after steaming. Within bitumen and heavy-oil reservoirs, estuarine channel-and-point bar successions are very common, which locally have low-angle inclined mudstone beds. These mudstone interbeds are intimately interbedded with the sand reservoirs, and are part of the lateral-accretion deposits associated with point-bar migration within tidal-influenced estuaries (with high mud contents), This type of interbedding is called ‘inclined heterolithic stratification’ (or I.H.S.) (Figure 9B) (see Thomas et al., 1987). Depending upon the orientation of the SAGD or CSS wells with respect to these mudstone beds, bitumen and heavy-oil production may be impeded or diminished (Putnam et al., in press; Strobl, 2013; Su et al., 2014). By contrast, those bitumen and heavy-oil reservoirs that are hosted within continental, fluvial-dominated, channel sequences tend to lack the common occurrence of mudstone intraclasts and the more continuous mudstone beds, more typical of tidal- and marine-influenced successions. In these cases, it is expected that there would be less hindrance to oil recovery due to natural heterogeneities in the reservoirs associated with low-permeability zones. Exceptions would be those continental deposits which are capped or laterally-grade into continuous cemented zones, associated with disconformities or unconformities, which may occur near the base or top of continental, fluvial successions. In some cases, abandonment-fill mudstones of both continental fluvial and estuarine settings may be local lean zones, decreasing oil-recovery from the bitumen and heavy-oil reservoirs (Gray et al., 2006). In all cases, documentation of reservoir heterogeneity, tied to porosity and permeability distributions, and modelled in 2- and 3-D within the reservoir should be part of the workflow process (Bellman and Connelly, 2010; Deutsch, 2013; Durkin, 2016; Fustic et al., 2008; Manchuk et al., 2015; Gray et al., 2006). In some cases, technology sequencing of different in-situ processes may aid in recovery of these typically, heterogeneous reservoirs (Dusseault, 2013; Villarroel et al., 2013; Zhao and Gates, 2015; Zhao et al., 2015).

6. Summary & Discussion

13

As conventional hydrocarbon resources become depleted, the world energy market is looking to other unconventional energy sources to fill the gap. Two of the unconventional energy commodities that are being exploited and explored for are heavy-oil and bitumen. Most of the known heavy-oil and bitumen resources occur in the Western Hemisphere, with the largest heavy-oil accumulation in Venezuela and the largest bitumen in northeastern Alberta, Canada. On a world-basis most of the heavy-oil and bitumen reservoirs are located in younger deposits (Cretaceous and younger), at shallow depths (< 200 m to a maximum of 2,000 m); and are more prevalent in two types of plate-tectonic settings: 1) Multicyclic continental margins; and 2) Rifted continental basins. On a deposit scale, most of the heavy-oil and bitumen deposits are a result of biodegradation (with some oxidation, water-washing and evaporation) of former light crude-oil reservoirs. What is needed for this degradation to occur is breaching of regional seals or loss of caprock integrity. Geological processes that contribute to loss of caprock integrity include: erosion, fracturing and faulting of clastics and carbonates; weathering and karstification of carbonate host rocks. The heavy-oil and bitumen resources are naturally degraded petroleum, in which there is enrichment in heavies, including large molecules, such as oxygen, nitrogen, sulphur and others. It is this natural residuum that presents challenges for production, refinement and transportation of products derived from heavy-oil and bitumen. The biggest issue regards sustainable development in light of reduction of greenhouse-gas emissions; and social license for this development regarding these emissions and other environmental concerns. Future development of the world bitumen and heavy-oil resources depend not only on understanding the geological framework and engineering/technological developments, but also the geopolitical, cultural and social-license issues related to development of unconventional resources (Gehman et al., in press; Hein et al., in press; Hills et al., in press). These issues have been discussed for a long time, ever since the first government oversight on development of the oil-sands in Alberta (Page, 1974). Other more recent overviews and analysis are in a number of books addressing the broader concerns related to energy development of these unconventional resources (Banerjee, 2012; Czarnecki et al., 2013; Kelly, 2009; Masliyah, 2011; Patel, 2012, among others). What is of interest, in particular, for future development is how to balance unconventional energy-resource development with reduction of greenhouse gas emissions, and other environmental concerns (Bernar et al., 2008). It is beyond the scope of this paper to review the effects of a potential decarbonized energy system on future production of bitumen and heavy oil, but the reader is referred to the Gates and Larter (2014), McGlade and Ekins (2014) and Nduagu and Gates (2015a, b) discussions of this topic. McGlade and Ekins (2014) claim that unless alternative energy sources (such as shallow geothermal, nuclear electricity, biomass, coal) are used for production and refinement of bitumen and heavy oil; and further, that processes of upgrading are linked to carbon-capture and storage (CSS), that it will be impossible to meet future targets of GHG emissions without major technological breakthroughs in the production and refinement of heavy crude and bitumen resources. It is clear, that now and into the future, “nontraditional” skill sets and data will have to be used and assessed by multidisciplinary teams to fully understand the subsurface processes of bitumen- and heavy-oil production, and the surface effects, on both an engineering (human) and geologic time-scale. Figure 9. Core photographs of the McMurray Formation oil-sands, showing dark brown to black, bitumen-stained sand, with muds (light gray): A) Mudstone clast breccia, with angular, rounded and deformed intraclasts set within a bitumen-saturated sand matrix; B) 14

Sandy inclined heterolithic stratification (or I.H.S.), with alternating layers of black to dark brown, bitumen-saturated sand, and light gray mudstone. The irregular mottling pattern is due to bioturbation; C) Thicker more regional, coarsening-upward sequence of shaley mudstone (left)  sandy silty mudstone (middle)  interbedded, bioturbated sand and mudstone (right), interpreted as either a large-abandonment fill or a tidally-influenced, marginal marine parasequence (Well AA/03-12-081-06W4, each core slat is 0.75 m long; scale card (white box) on core marks are each one-cm long.

Acknowledgements Thanks are given to Andrew Beaton and Kevin Parks for their reviews. Support to publish is acknowledged from the Alberta Energy Regulator. Any use of trade, product or firm names is for descriptive purposes only and does not imply endorsement by the Alberta Energy Regulator or by the Alberta government. Note: if there is any discrepancy between what is written here and the official records, the latter stands. Two anonymous reviewers suggested comments, which improved this manuscript. Any errors are the sole responsibility of the author.

References Abercrombie, H., Shevalier, M., and Hutcheon, I. E., 1989, Natural diagenesis: A model for artificial diagenesis during steam-assisted recovery of heavy oil, Cold Lake, Alberta, in: Miles, D. L., ed., 6th International Symposium on Water-Rock Interaction, Proceedings, Balkema, Rotterdam, p. 1-4 [extended abstract]. Adams, J., Bennett, B., Huang, H., Koksalan, T., Jiang, D., Fay, M., Gates, I., and Larter, S., 2007, Controls on the variability of fluid properties of heavy oils and bitumens in foreland basins: A case study from the Albertan oil sands, in: Suter, J., Leckie, D., and Larter, S., eds., Heavy oil and bitumen in foreland basins: From processes to products: American Association of Petroleum Geologists Hedberg Research Conference, Banff, September 30-October 3, Proceedings, 5 p. Adams, J., Larter, S. Bennett, B., Huang, H., Westrich, J., and van Kruisdijk, C., 2013, The dynamic interplay of oil mixing, charge timing, and biodegradation in forming the Alberta oil sands: Insights from geologic modeling and biogeochemistry, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 23-102. Alberta Energy and Utilities Board, 2003, Athabasca Wabiskaw-McMurray regional geological study, Report 2003-a, 187 p. and CD-ROM. Alberta Energy Regulator, 2015, Alberta’s Energy Reserves 2014 and Supply/Demand Outlook 2015-2024, Alberta Energy Regulator, Statistical Series, ST98-2016, p. 1 to F-7 (various pagination, http://aer.ca/data-and-publications/statistical-reports/archives

15

American Association of Petroleum Geologists, Energy Minerals Division, 2015, Unconventional Energy Resources: 2015 Review: Natural Resources Research, 65 p. published online: 25 November 2015; doi:10.1007/s11053-015-9228-6. Anfort, S. J., Bachu. S., and Bentley, L. R., 2001, Regional scale hydrogeology of the Upper Devonian – Lower Cretaceous sedimentary succession, south-central Alberta basin, Canada: American Association of Petroleum Geologists, Bulletin, v. 85, p. 637-660. Asgar-Deen, M., Brown, L., Browning, M., Davison, J., Eisinger, C., Fefchak, C., Gibson, G., Graham, C., Hill, S., Kaspers, M., Kellough, E., and Walter, S., 2008, Towards economic production of Grosmont Formation bitumen: Assessing the relative influence of reservoir porosity and permeability, versus bitumen quality, on production potential: Canadian Society of Petroleum Geologists, Canadian Society of Exploration Geophysicists, and Canadian Well Logging Society (CSPG-CSEG-CWLS), Joint Convention, Proceedings, p. 969-972 [extended abstract]. Bachu, S., Undershultz, J. R., Hitchon, B., and Cotterill, D. K., 1993, Regional-scale subsurface hydrogeology in northeastern Alberta: Alberta Research Council Bulletin 61, 44 p. Banerjee, D. K., 2012, Oil sands, heavy oil and bitumen: From recovery to refinery: Tulsa, OK, PennWell Corporation, 185 p. Barrett, K.R., 2016, Reservoir geology of the Grosmont Formation bitumen steam pilot, Saleski, Alberta: Bulletin of Canadian Petroleum Geology, 64 (2), p. 147-165. Barrett, K. and Cimolai, M., 2008, Geology and bitumen recovery potential of the Grosmont Formation, Saleski, Alberta: Canadian Heavy Oil Association (CHOA), Reservoir and Production Technical Luncheon Talk, PowerPoint presentation. Barrett, K. R., Hopkins, J. C., Wilde, K. N., and Connelly, M. E., 2008, The origin of matrix and fracture mega-porosity in a carbonate bitumen reservoir, Grosmont Formation, Saleski, Alberta: World Heavy Oil Congress, Edmonton, AB, 10 – 12 March, Proceedings, Paper #2008-344, 11 p. Barson, D., Bartlett, R., Hein, F., Fowler, M., Grasby, S., Riediger, C., and Underschultz, J., 2000, Hydrogeology of heavy oil and tar sand deposits: Waterflow and supply, migration and degradation: Field Trip Notes, GeoCanada 2000 Field Trip Guidebook 14, 163 p., also Geological Survey of Canada Open File #3946. Barson, D., Bachu, S., and Esslinger, P., 2001, Flow systems in the Mannville Group in the eastcentral Athabasca area and implications for steam-assisted gravity drainage (SAGD) operations for in-situ bitumen production: Bulletin of Canadian Petroleum Geology, v. 49, p. 376-392, doi:10.2113/49.3.376.

16

Barton, M., 2016 a, The architecture and variability of valley-fill deposits within the Cretaceous McMurray Formation, Shell Albian Sands Lease, northeast Alberta: Bulletin of Canadian Petroleum Geology, v. 64 (2), p. 166-198. Barton, M., 2016 b, Impact of the Prairie Evaporite dissolution collapse on McMurray stratigraphy and depositional patterns, Shell Albian Sands Lease 13, northeast Alberta: Bulletin of Canadian Petroleum Geology, 25 p (in press). Bata, T., Parnell, J., Bowden, S., and Boyce, A., 2016, Origin of heavy oil in Cretaceous petroleum reservoirs: Bulletin of Canadian Petroleum Geology, v. 64 (2), p. 106-118. Bellman, L.W. and Connelly, M. E., 2010, 3D reservoir characterization in the Grand Rapids oil sands: American Association of Petroleum Geologists, Search and Discovery Article #40678, 5 p. Benyon, C., Leier, A., Leckie, D. A., Webb, A., Hubbard, S. M., and Gehrels, G., 2014, Provenance of the Cretaceous Athabasca oil sands, Canada: Implications for continental-scale sediment transport: Journal of Sedimentary Research, v. 84, p.136-143, doi:10.2110/jsr2014.16. Benyon, C. Leier, A. L., Leckie, D. A., Hubbard, S. M., and Gehrels, G. E., 2016, Sandstone provenance and insights in the paleogeography of the McMurray Formation from detrital zircon geochronology, Athabasca oil sands, Canada: American Association of Petroleum Geologists, Bulletin, v. 100, no. 2, p. 269-287, doi:10.1306/10191515029. Bernar, R., Fischer, A., Lennox, A., Brunelle, P., Kresnyak, S., Lee, W., and Sims, S., 2008, Zero emissions and water friendly SAGD projects: World Heavy Oil Congress, Proceedings, 10 – 12 March, Edmonton, AB, Canada, Paper 2008-359, 9 p. Blanc, P. and Connan, J., 1994, Preservation, degradation, and destruction of trapped oil, in: Magoon, L. B. and Dow, W. G. (eds.), The petroleum system – From source to trap: American Association of Petroleum Geologists, Memoir 60, p. 237-247. Blum, M., 2015, Scaling relationships in fluvial systems: Implications for the Mannville Group, Alberta foreland basin: American Association of Petroleum Geologists, Search and Discovery Article #51132, 22 p. (posted September 7, 22015). Bortz, L. C., 1987, Heavy-oil deposit, Great Salt Lake, Utah, in: Meyer, R. F., ed., Exploration of heavy crude oil and natural bitumen: American Association of Petroleum Geologists, Studies in Geology 25, p. 555-563. Buschkuehle, B. E., Hein, F. J., and Grobe, M., 2007, An overview of the geology of the Upper Devonian Grosmont carbonate deposit, northern Alberta, Canada: Natural Resources Research, v. 16, p. 3-15. Cant, D. J. and Abrahamson, B., 1995, Isopach of transgressive system – Mannville Group: Geological Survey of Canada, Open File 3090, 1 map, scale 1:2 million.

17

Cant, D. J. and Abrahamson, B., 1996, Regional distribution and internal stratigraphy of the lower Mannville: Bulletin of Canadian Petroleum Geology, v. 45, p. 141-154. Curran, R., 2016, Special Focus: 2016 Forecast – Canadian E&P: Tough times lie ahead for Canada’s oil patch: World Oil (February 2016), p. 67-69. Czarnecki, J., Masliyah, J., Xu, Z., and Dabros, M., 2013, Handbook on theory and practices of bitumen recovery from Athabasca oil sands: Volume II. Industrial practice, Kingsley Knowledge Publishing and Alberta Innovates – Energy and Environment Solutions, 715 p. de Joussineau, G., Barrett, K. R., Allesandroni, M., and Le Maux, T., 2016, Organization, flow impact and modeling of natural fracture networks in a karstified carbonate bitumen reservoir: An example in the Grosmont Formation of the Athabasca Saleski leases, Alberta, Canada: Bulletin of Canadian Petroleum Geology, v. 64 (2), p. 291-308. Deutsch, C., 2013, Multiple-scale geologic models for heavy oil reservoir characterization, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 531-543. Durkin, P. R., 2016, The evolution of meander belts and their product in the rock record: Ph. D. thesis [unpublished], The University of Calgary, Calgary, AB, Canada (April, 2016). Dusseault, M. B., 2013, Screening criteria and technology sequencing for in-situ viscous oil production, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oilsand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 655-667. Energy Resources Conservation Board, 2011, Sunshine Oilsands Ltd., Athabasca Oil Sands Corp., Total E&P Canada Ltd., and Perpetual Energy Operating Corp. Applications and a request for the shut-in and production of gas, Liege field, Athabasca oil sands area: Decision 2011-035 (December 13, 2011), 31 p. Energy Resources Conservation Board, 2013, Alberta’s energy reserves 2012 and supply/demand outlook 2013-2022, Report ST98-2013, p. 1-1 to F-7. Fustic, M., Bennett, B., Adams, J. J., Huang, H., MacFarlane, B., Leckie, D., and Larter, S. R., 2011, Bitumen geochemistry: A tool for distinguishing barriers from baffles in oil sands reservoirs: Bulletin of Canadian Petroleum Geology, v. 59, p. 295-316. Fustic, M., Bennett, B., Hubbard, S. M., Huang, H., Oldenburg, T., and Larter, S., 2013, Impact of reservoir heterogeneity and geohistory on the variability of bitumen properties and on the distribution of gas- and water-saturated zones in the Athabasca oil sands, Canada, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 163-205. 18

Fustic, M., Skulski, L., Hanson, W., Vanhooren, D., Bessette, B., Hinks, D., Bellman, L., and Leckie, D., 2008, Geological mapping and reservoir characterization of oil sands reservoir by integrating 3D seismic, dipmeter, core descriptions, and analogs in the McMurray Formation, NE Alberta: American Association of Petroleum Geologists, Search and Discovery Article #40281, 7 p. Gates, I. D. and Larter, S. R., 2014, Energy efficiency and emissions intensity of SAGD: Fuel, v. 115, p. 706-713. Gehman, J., Lefsrud, L., Lounsbury, M., and Lu, C., in press, Perspectives on energy and environment risks with implications for Canadian energy development: Bulletin of Canadian Petroleum Geology (July, 2016 issue),19 p. Gray, F. D., Anderson, F. P., and Gunderson A. J., 2006, Prediction of shale plugs between wells in heavy oil sands using seismic attributes, Natural Resources Research, Vol. 15, No. 2, p. 103110. Gruson, J. F., 2005, Prospective analysis of the potential nonconventional world oil supply: Tar sands, oil shales and nonconventional liquid fuels from coal and gas: European Commission Directorate – General Joint Research Center, Institute for Prospective Technological Studies, Technical Report EUR22168EN, 77 p., http://www.jrc.es. Hathway, B., 2016, Regional subsurface mapping of the Clearwater Formation, Lower Cretaceous, northeast Alberta: American Association of Petroleum Geologists, Annual Convention and Exhibition, Calgary, poster presentation, on-line posting as follows: ags.aer.ca/document/Presentations/2016_AAPG_Poster_Hathway.pdf Hauck, T., Peterson, J., Hathway, B., Grobe, M., and MacCormack, K., 2016, Regional-scale modeling of the Paleozoic succession beneath the Athabasca and Cold Lake oil sands areas: Devonian paleogeography, evaporite dissolution, and controls on Cretaceous depositional patterns on the sub-Cretaceous unconformity: American Association of Petroleum Geologists, Annual Convention and Exhibition, Calgary, poster presentation, on-line posting as follows: ags.aer.ca/document/Presentations/2016_AAPG_Poster_Hauck.pdf Head, I. M., Jones, D. M., and Larter, S. R., 2003, Biological activity in the deep subsurface and the origin of heavy oil: Nature, v. 426, p. 344-352, doi:10.1038/nature02134. Hein, F.J., 2006, Heavy oil and oil (tar) sands in North America: An overview and summary of contributions: Natural Resources Research, v. 15, no. 2, p. 67-84. Hein, F. J., 2013, Overview of heavy oil, seeps and oil (tar) sands, California, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 407-436.

19

Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R., 2013, Heavy oil and bitumen petroleum systems in Alberta and beyond: The future is unconventional and the future is now, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 1-21. Hein, F. J. and Marsh, R. A., 2008, Regional geologic framework, depositional models and resource estimates of the oil sands of Alberta, Canada: World Heavy Oil Congress, Edmonton 10-12 March, Proceedings, Paper 2008-320, 9 p. Hein, F. J. and Parks, K. P., in press, The role of the regulator in Alberta’s oil-sands development: A historical retrospective 1960-2010: Bulletin of Canadian Petroleum Geology (July, 2016 issue), 63 p. Hein, F. J., Parks, K. P., Leckie, D. A., and Seibel, C., in press, Foreword: Oil-sands and heavyoil deposits: Local to global multidisciplinary collaboration: Bulletin of Canadian Petroleum Geology (July, 2016 issue), 24 p. Hills, D. J., Hooks, C. H., McIntyre-Redden, M. R., Crooke, L. A., and Tew, B. H., Jr., in press, Oil sands in Alabama, USA: A fresh look at an emerging potential resource: Bulletin of Canadian Petroleum Geology (July, 2016 issue), 37 p. Humphries, M., 2008, North American oil sands: History of development prospects for the future – Report for Congress, Washington, D.C., Congressional Research Service, 27 p. Jacobs, T., 2015, New oil sands technology debuts in Utah, promises low environmental impact: Journal of Petroleum Technology (January), p. 46-48. Jo, H. R. and Ha, C. G., 2013a, Stratigraphic architecture of fluvial deposits of the Cretaceous McMurray Formation, Athabasca oil sands, Alberta, Canada: Geosciences Journal, v. 17, no. 4, p. 417-427. Jo, H. R. and Ha, C. G., 2013b, Basal water-bearing zone of the oil-sands deposits of the Cretaceous McMurray Formation at Christina Lake, Alberta, Canada: Geosciences Journal, v. 17, no. 4, p. 445-453. Kapadia, P. R., Kalls, M. S., and Gates, I. D., 2015, A review of pyrolysis, aquathermolysis, and oxidation of Athabasca bitumen: Fuel Processing Technology, v. 131, p. 270-289. Kashirtsev, V. A. and Hein, F. J., 2013, Overview of natural bitumen fields of the Siberian Platform, Olenek Uplift, Eastern Siberia, Russia, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 509-528. Kelly, G., 2009, The oil sands: Canada’s path to clean energy? Altona, MB, Canada, Friesens, and Kingsley Publishing Services, 324 p. 20

Klemme, H.D., 1984, Table 2. Klemme basin classification, in: St. John, B., Bally, A.W. and Klemme, H. D., 1984, Sedimentary provinces of the world-hydrocarbon productive and nonproductive [text to accompany map: Sedimentary Provinces of the World]: American Association of Petroleum Geologists, 35 p. Larter, S., Huang, H., Adams, J., Bennett, B., Jokanola, O., Oldenburg, T., Jones, M., Head, I., Riediger, C., and Fowler, M., 2006, The controls in the compositions of biodegraded oils in the deep subsurface -- part II. Geological controls on subsurface biodegradation fluxes and constraints on reservoir-fluid property prediction: American Association of Petroleum Geologists, Bulletin, v. 90, no. 6, p. 921-938. Larter, S., Whilhelms, A., Head, I., Koopmans, M., Aplin, A., di Primio, R. Zwach, C., Erdmann, M., and Telnaes, N., 2003, The controls on the composition of biodegraded oils in the deep subsurface – part I. Biodegradation rates in petroleum reservoirs: Organic Geochemistry, v. 34, no. 3, p. 601-613. Machel, H. G., Borrero, M. L., Dembicki, E., Huebscher, H., Ping, L., and Zhao, Y., 2012a, The Grosmont: The World’s largest unconventional oil reservoir hosted in carbonates rocks, in: Garland, J., Neilson, J. E., Laubach, S. E., and Whidden, K. J., eds., Advances in carbonate exploration and reservoir analysis: Geological Society, London, Special Publication 370, p. 4981, url: http://dx.doi.org/10.1144/SP370.11. Machel, H. G., Borrero, M. L., Dembicki, E., Huebscher, H., Ping, L., and Zhao, Y., 2012b, The Grosmont: A complex dolomitized, fractured and karstified heavy oil reservoir in a Devonian carbonate-evaporite platform, in GeoConvention, 2012: Vision, Program with Abstracts, 24 p. [extended abstract]. Majid, A. and Sparks, B. D., 1999, Potential applications of oil sands industry wastes: Journal of Canadian Petroleum Technology, v. 38, no. 11, p. 29-33. Manchuk, J. G., Garner, D. L., and Deutsch, C. V., 2015, Estimation of permeability in the McMurray Formation using high-resolution data sources: Petrophysics, v. 56, no. 2, p. 125-138. Martinius, A. W., Hegner, J., Kaas, I., Bejarano, C., Mathieu, X., and Mjøs, R., 2013, Geologic reservoir characterization and evaluation of the Petrocedeño field, Early Miocene Oficina Formation, Orinoco heavy oil belt, Venezuela, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 103-132. Masliyah, J. H., Czarnecki, J., and Xu, Z., 2011, Handbook on theory and practices of bitumen recovery from Athabasca oil sands: Volume 1. Theoretical basis, Kingsley Knowledge Publishing, 468 p.

21

McCrimmon, G. G. and Arnott, R. W. C., 2002, The Clearwater Formation, Cold Lake, Alberta: A world class hydrocarbon reservoir hosted in a complex succession of tide-dominated deltaic deposits, Bulletin of Canadian Petroleum Geology, v. 50, no. 3, p. 370-392. McDougall, J., Isaacs, E., and Alvarez, J. M., 2008, Alberta carbonates – The third trillion, in: 19th Word Petroleum Congress, Spain, Forum 06: Carbonate reservoirs, Proceedings, 10 p. McGlade, C. E., 2012, A review of the uncertainties in estimates of global oil resources: Energy, v. 47, p. 262-270. McGlade, C. and Ekins, P., 2014, Un-burnable oil: An examination of oil resource utilization in a decarbonized energy system: Energy Policy, v. 64, p. 102-112. McKay, J. L and Longstaffe, F. J., 1997, Diagenesis of the Lower Cretaceous Clearwater Formation, Primrose area, northeastern Alberta, in: Pemberton, S. G. and James, D. P., eds., Petroleum geology of the Cretaceous Mannville Group, Western Canada: Canadian Society of Petroleum Geologists, Memoir 18, p. 392-412. McKay, J. L. and Longstaffe, F. J., 2013, Tracking fluid movement during cyclic steam stimulation of Clearwater Formation oil sands using stable isotope variations of clay minerals: Clay and Clay Minerals, v. 61, no. 5, p. 440-460. Mehrotra, A. K. and Svrcek, W. Y., 1986, Viscosity of compressed Athabasca bitumen: The Canadian Journal of Chemical Engineering, v. 64 (October), p. 844-847. Meyer, R. F. and Attanasi, E. D., 2003, Heavy oil and natural bitumen strategic petroleum resources: U. S. Geological Survey, Fact Sheet 70-3, August 2003, and online version 1.0: http://pubs.usgs/fs/fs070-03/fs070-03.html Meyer, R. F. and Freeman, P. A., 2006, Siberian platform: Geology and natural bitumen resources: U. S. Geological Survey, Open-File Report 2006-1316, 24 p., http://pubs.usgs.gov/of/2006/1316/ Meyer, R. F., Attanasi, E. D., and Freeman, P. A., 2007, Heavy oil and natural bitumen resources in geological basins of the world: U.S. Geological Survey, Open File Report 2007-1084, 36 p.: http://pubs.usgs.gov/of/2007/1084/OF2007-1084v.1.pdf Nduagu, E. I and Gates, I. D., 2015a, Unconventional heavy oil growth and global greenhouse gas emissions: Environmental Science and Technology, v. 49, no. 14, p. 8824-8832. Nduagu, E. and Gates, I. D., 2015b, Process analysis of a low emissions hydrogen and steam generation technology for oil sands operations: Applied Energy, v. 146, p. 184-195. Page, H. V., 1974, The environmental impacts of Alberta’s tar sands industry, in: Hills, L. V., ed., Oil sands fuel of the future: Canadian Society of Petroleum Geologists, Memoir 3, p. 222233. 22

Parnell, J., Bellis, D., Feldmann, J., and Bata, T., 2014, Selenium and tellurium enrichment in palaeo-oil reservoirs: Journal of Geochemical Exploration, heep://dex.doi.org/10.1016/j.gexplo.2014.09.006 Patel, S., 2012, The future of oil: A straight story of the Canadian oil sands: Altona, MB, Canada, Friesens, simultaneously published in Maharashtra, India, CreatiVentures Publishing, 242 p. Pouderoux, H., Coderre, A. B., Pedersen, P. K., and Cronkwright, D. J., in press, Characterization, architecture and controls of Cold Lake marginal-marine oil sands: The Grand Rapids Formation (Upper Mannville) of east-central Alberta, Canada.: Bulletin of Canadian Petroleum Geology (July, 2016 issue), 46 p. Putnam, P. E. and Pedskalny, M. A., 1983, Provenance of Clearwater Formation reservoir sandstone, Cold Lake, Alberta, with comments on feldspar composition: Bulletin of Canadian Petroleum Geology, v. 31, no. 3, p. 148-160. Putnam, P., Russel-Houston, J., and Christensen, S. L., in press, Comparison of McMurray Formation (Lower Cretaceous) and Grosmont Formation (Upper Devonian) bitumen reservoirs with some speculations, from a geological perspective, on the future of Canadian thermal recovery: Bulletin of Canadian Petroleum Geology (July, 2016 issue), 58 p. Schamel, S., Overland, S., and Ibatullin R., 2015, Bitumen and Heavy Oil Committee Commodity Report (May 2015), American Association of Petroleum Geologists, Energy Minerals Division, Annual Reports, 55 p. Schneider, C. L., Mei, S., Haug, K., and Grobe, M., 2014, The sub-Cretaceous unconformity and the Devonian subcrop in the Athabasca oil sands area, townships 87-99, ranges 1-13 west of the Fourth Meridian: Alberta Energy Regulator, Alberta Geological Survey, AER/AGS Open File Report 2014-07, 32 p. St. John, B., Bally, A.W. and Klemme, H. D., 1984, Sedimentary provinces of the worldhydrocarbon productive and nonproductive [text to accompany map: Sedimentary Provinces of the World]: American Association of Petroleum Geologists, 35 p. Strobl, R., 2013, Integration of steam-assisted gravity drainage fundamentals with reservoir characterization to optimize production, , in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 639-653. Su, Y., Wang, J., and Gates, I.D., 2014, Orientation of a pad of SAGD well pairs in an Athabasca point bar deposit affects performance. Marine and Petroleum Geology, v. 54, p. 37-46.

23

Thomas, R. G., Smith, D. G., Wood, J. M., Visser, J., Calverley-Range, E. A., and Koster, E. H., 1987, Inclined heterolithic stratification – Terminology, description, interpretation, and significance: Sedimentary Geology, v. 53, no. 1, p. 123-179. Tiratsoo, E. N., 1973, Oilfields of the World, Mexico, Chapter 10: Beaconsfield, England, Scientific Press Ltd., p. 290-295. Villarroel, T., Zambrano, A., and Garcia, R., 2013, New progress and technological challenges in the integral development of the Faja Petrolifera del Orinoco, Venezuela, in: Hein, F. J., Leckie, D. A., Larter, S., and Suter, J. R. (eds.), Heavy-oil and oil-sand petroleum systems in Alberta and beyond: American Association of Petroleum Geologists, Studies in Geology 64, p. 669-687. Wo, E., Song, L., Hurst, T., and Sitek, N., 2011, Geological review and bitumen resource appraisal of the Grosmont Formation within the Athabasca oil sands area: American Association of Petroleum Geologists, Search and Discovery Article #80130, 5 p Zhao, D. and Gates, I. D., 2015, on hot water flooding strategies for thin heavy oil reservoirs: Fuel, v. 153, p. 559-568. Zhao, D., Wang, J., and Gates, I. D., 2015, An evaluation of enhanced oil recovery strategies for a heavy oil reservoir after cold production with sand: International Journal of Energy Research, doi:10.1002/er.3337. Zou, C., Zhu, R., Tao, S., Hou, L., Yuan, Z., Song, Y., Niu, J., Dong, D., Liu, S., Jiang, L., Wang, S., Zhang, G., et al., 2013, Unconventional Petroleum Geology, Petroleum Industry Press, Elsevier Inc., 373 p.

24

25

26

27

28

29

30

31

32

33