Abstract Global bitumen and heavy-oil resources are estimated to be 5.6 trillion bbl, with most of that occurring in the western hemisphere. In the past decade, significant advances in the development and production of these resources have occurred by way of the critical integration of geology, geophysics, engineering, modeling economics, and transportation. Bitumen and heavy-oil deposits are mainly unconsolidated sands bound together by biodegraded bitumen. In the case of the world's largest oil-sand and heavy-oil deposit, located in western Canada, the oil sands occur in deposits of low sedimentary accommodation on the distal side of a foreland basin. Hydrocarbons were derived from Mississippian Exshaw and/or Mesozoic source rocks. The hydrocarbons accumulated in tidally influenced fluvioestuarine sediments, midchannel bars, brackish bays, bay-hed deltas, and tidal flats. Elsewhere, in another major global heavy-oil resource, the Oficina Formation in Venezuela was similarly deposited in fluvioestuarine to deltaic settings. Current in-situ oil-sand development focuses on steam-assisted gravity drainage (SAGD) technology and, to a lesser degree, cyclic steam stimulation (CSS). Other emerging technologies being piloted include in-situ combustion, electrothermal dynamic stripping, and passive heating-assisted recovery methods.

Abstract Regional-, field-, and reservoir-scale studies of the petroleum geology, petroleum biogeochemistry, and oil fluid properties of the western Canada oil sands produce the first high-resolution model of oil charge systematics for the oil sands. The sources and alteration history of the Lower Cretaceous and underlying Mesozoic and late Paleozoic oil fields of north-central Alberta (Peace River Arch [PRA] area) were investigated using a very large database of public and in-house data to define the unaltered end-member oils that charged the oil sand reservoirs and to delineate the reservoirs in the study area that are still biologically active today. The complexity of the petroleum systems and variation in source organic facies observed in this study are probably typical of the extremely large petroleum accumjulations that dominate the world's petroleum occurrences.

Abstract More than 12 yr of field development and production at Petrocedeno (formerly Sincrudos de Oriente C.A.) in the Orinoco Heavy Oil belt, Venezuela, have generateda detailed picture of the three-dimensional (3-D) reservoir architecture, static and dynamic properties, and sedimentology of this important deposit. The Petrocedeno project is located along the foreland bulge on the south side of the eastern Venezuelan foredeep basin. Its hydrocarbon is derived mainly from marine source rocks from the early Paleocene to the Miocene; long-distance secondary migration occurred toward the foreland bulge. Traps are stratigraphic in nature, and lateral seal is provided by a combination of biodegraded hydrocarbons and increasingly immobile crude oil. A dense network of wells has enabled the construction of high-resolution static and dynamic models of the fluvial and deltaic reservoir units in the hydrocarbon-bearing lower member of the Oficina Formation.

Abstract Alberta’s oil sands hold almost all of Canada’s crude bitumen resources within one of the world’s largest deposits of extra heavy crude oil. Its established reserves of crude bitumen have been favorably compared with the conventional oil reserves of Saudi Arabia. Alberta’s oil-sand industry has been the source of large investments since the 1960s, but investment has been particularly strong in the past decade. Crude bitumen production in Alberta has more than doubled in this period and is expected to reach more than 3 million bbl per day during the next decade, as the pace of oil-sand development accelerates. This paper contains a forecast of the potential production from this vast resource, with consideration for reserves markets, and the economic viability of crude bitumen production within Alberta.

Abstract Four-dimensional petroleum system models within the Western Canada sedimentary basin were constructed using hydrous pyrolysis (HP) and Rock-Eval (RE) kinetic parameters for six of the major oil-prone source rocks in the basin. These source rocks include the Devonian Duvernay Member of the Woodbend Group; Devonian-Mississippian Exshaw Formation; Triassic Doig Formation; Gordondale Member; Poker Chip A shale, both of the Jurassic Fernie Group; and Ostracod Zone of the Lower Cretaceous Mannville Group. The Mannville Group coals also contributed oil to the oil sands (Higley et al., 2009) but are excluded herein because HP kinetics were used for both models with identical results. The locations of oil migration flowpaths are identical for the HP and RE models, with the exception of an earlier onset of generation and migration shown with the HP model. Both models show that the oil sands are located at focal points of the petroleum migration pathways. The principal differences between the models are the onset and extent of oil generation from the Jurassic Fernie source rocks (Gordondale Member and Poker Chip A shale) at about 85 Ma with the HP model and 65 Ma with the RE model. Earlier oil generation in the HP model is caused by the high sulfur content of the type IIS kerogen in the Jurassic source rocks. The influence of organic sulfur is accounted for in the HP kinetic parameters, but not the RE kinetic parameters. The cumulative volume of oil generated from the source rocks is 678 billion m 3 for the HP model and 444 billion m 3 for the RE model, or 65% of the HP volume. This difference is attributed to early generation from type IIS kerogen that resulted in much larger volumes of thermally mature source rocks for the Jurassic Fernie Group and consequently larger volumes of generated oil. The Gordondale Member in the HP model generated more than 550 times the volume of oil generated by the Gordondale Member in the RE model. The timing and generated volumes are comparable in the RE and HP models for source rocks that contain normal levels of organic sulfur (type II kerogen). The Duvernay is an exception because of the very low sulfur content of its type II kerogen. The result is higher HP kinetic than RE kinetic parameters, with associated greater thermal maturities required for HP than for RE oil generation. Consequently, there is less mature Duvernay source rock in the HP model than the RE model.

Abstract The Athabasca oil sand deposit, the world’s largest petroleum accumulation, contains an estimated 1.7 trillion bbl of heavily to severely biodegraded oil,with API gravities ranging from 6 to 10°. Although reservoir characterization has been the subject of many studies in the region, very little attention has been given to petroleum (bitumen) characterization and particularly to its reservoir-scale relationship with the host sediments. In this study, variation in the bitumen physical and chemical properties were measured on a suite of samples. These were obtained from numerous cores from various reservoir types and geographic areas of the Athabasca oil sand deposits. The variation in bitumen viscosities and changes in the hydrocarbon composition caused by varying levels of biodegradation were interpreted using molecular markers. These data were integrated into the reservoir facies framework and interpreted in the context of various reservoir configurations.

Abstract During the past 15 to 20 yr, detailed work conducted by the Alberta government, including the Alberta Geological Survey and the Energy Resources Conservation Board, allows for a better understanding of the Athabasca oil sand deposit, hosted primarily by the McMurray Formation in northeastern Alberta. Much of this work has relied on regional-scale mapping facilitated through lithofacies analysis of outcrops, cores, and well logs, along with petrographic, grain-size, and palynofacies analysis. In the past, the McMurray Formation has been informally subdivided into lower fluvial, middle estuarine, and upper coastal-plain successions. Results from regional lithofacies analysis and stratigraphic correlation and geologic modeling for the Athabasca oil sands show that much of the preserved stratigraphy is fragmented, that no clear distinctions can be made between the middle estuarine and upper coastal plain lithofacies associations, and that no single model applies to the total succession that is preserved. At least five major unconformities and disconformities separate different system tracts, and they should not be considered to be parts of a single entity or single depositional systems tract. Within each of the original systems tracts are preserved remnants of fluvial, estuarine, and bay-fill successions; some of which are amalgamated or juxtaposed to one another, making geologic interpretations and correlations difficult. In areas of reduced accommodation space, not all the paleoenvironments are preserved. This area of reduced accommodation space occurs in the central and southern parts of the Athabasca oil sand area, where most of the existing and future in-situ technologies will be used to produce the bitumen. Recognition of the proper paleoenvironmental setting is critical for the prediction of reservoir heterogeneity, including lateral and vertical segregation of bitumen from overlying gas and water reservoirs that may be thief zones to in-situ (mostly thermal) bitumen production. The development of a regional geologic framework, using the principles of sequence stratigraphy, allows regional mapping within the different time-transgressive systems to be integrated and allows for the full understanding of the geologic framework for the oil sands. This regional geologic framework is being used by the Energy Resources Conservation Board to assess applications for exploration and development of the oil sands and aids in assessing resources and reserves for the province.

Abstract Palynofloral assemblages associated with strata of the McMurray Formation, Wabiskaw Member, and Clearwater Formation can be placed into a classification scheme based primarily on dinocyst content. Although most of the palynofloral assemblages are dominated by terrestrially derived pollen and spores, the dinocysts can be used to characterize fresh water through a marine continuum in which to place these diverse paleoenvironments. Freshwater and slightly brackish paleoenvironments are most characteristic of the McMurray Formation, whereas stressed, shoreface, and nearshore paleoenvironments are most characteristic of the Wabiskaw Member and Clearwater Formation strata. Dinocyst assemblages from the McMurray Formation are characterized by the freshwater algae Hurlandsia rugara and rare Holmewoodinium sp., with varying abundances of Nyktericysta spp. group dinocysts. The relative abundance and diversity of these Nyktericysta spp. dinocysts can be correlated with increased brackish influence. Locally within the McMurray Formation, the presence of Vesperopsis spp. may indicate significant brackish influence.Within the overlying Wabiskaw Member and Clearwater Formation, dinocyst assemblages are indicative of the southward-transgressing Clearwater Sea. Assemblages may be dominated by species of Circulodinium (C. deflandrei and C. brevispinosum), Odontochitina operculata, Oligosphaeridium spp., Palaeoperidinium cretaceum plus a host of accessory taxa indicative of stressed paleoenvironments, including several new undescribed species. Significantly, the distribution and nature of the palynofloral assemblages do not validate the historic threefold division of the McMurray Formation into lower, middle, and uppermembers, nor do the palynofloral assemblages reflect a gradual upward increase in marine influence. Instead, the palynofloral assemblages indicate much more regionally diverse paleoenvironments, with brackish influence recognized throughout.

Abstract Canada’s largest bitumen resource is contained within the McMurray Formation, a complex deepening-upward fluvial-estuarine succession typified by abrupt facies changes, inclined stratal geometries, and high-relief unconformities. Within this succession, fluvial-estuarine point-bar reservoirs represent a significant fraction of the resource that can be developed through surface mining and in-situ thermal recovery processes such as steam-assisted gravity drainage (SAGD). At Syncrude Canada Ltd.’s Mildred Lakemine, closely spaced core-hole data are tied to high-wall exposures of a point-bar succession that is 55m (180 ft) thick and occupies an area of at least 15 km 2 (6 mi 2 ). Data are integrated using two 3-D visualization tools: light detection and ranging (LIDAR), a laser technology that produces high-resolution digital terrain models of the outcrop, and LogVu3D, an application that displays large sets of geophysical logs in a 3-D volume. The point-bar model developed here describes sand body dimensions, stratal stacking patterns, lithofacies distributions, and mudstone heterogeneity at a variety of scales. A conceptual model of steam chamber growth in a heterogeneous point bar is presented that has implications for steam chamber definition, resource assessment, reservoir modeling, and development well planning.

Abstract The McMurray Formation (Aptian) Ells River bitumen deposit is hosted by two to three superimposed wave-dominated shoreface sands distributed as giant longitudinal bars northwest of Fort McMurray, Athabasca oil sands deposit, northeastern Alberta. The multibillion-barrel Ells River steam-assisted gravity drainage (SAGD) bitumen reservoir is 15 to 40m (49–131 ft) thick, with up to 12 to 14% bitumen by weight. Significant bitumen deposits have been discovered in recent years, where thickened McMurray clastics accumulated at the junctions of secondary paleovalley tributaries with the main northward-flowing trunk system and within offset, detached, secondary paleovalleys such as at Ells River. The middle and upper McMurray bitumen sands at Ells River accumulated as wave-dominated shore-face sands that formed giant longitudinal bars at the mouth of a north-trending paleovalley. This developed as an embayment on the Devonian paleosurface to the west of the main Athabasca bitumen fairway. The Ells River clastics were sourced from the east by long shore drift emanating from the tide-dominated delta that fronted the Cretaceous seaway, north of the Fort McMurray mining area. These middle and upper McMurray shoreface sands transgressed westward along the shelf margin to the Ells River embayment and covered the lower McMurray bay-fill clastics and paleosols. The Ells River depositional model contrasts with the main Athabasca bitumen deposits that accumulated as fluvial and estuarine tidal-and point-bar channel sands along themain bitumen fairway and infilled the paleovalley trunk system. The northward-flowing trunk system was entrenched into the underlying Devonian paleotopographic surface and broadened into a tide dominated deltaic complex at the confluence with the Cretaceous seaway during the middle McMurray. These fluvioestuarine sands nowhost extensive minable oil sand deposits in the Fort McMurray area of northeastern Alberta. The Ells River reservoir-quality sands were deposited as tidal sand-wave complexes with large-scale cross bedding. Reservoir-quality sands are the upper shoreface sands, which are relatively clean and have low volumes of shale (Vsh ã 5%). Lower quality sands are the lower shoreface sands that have been locally modified by waves, as shown by reactivation structures and thin, discontinuous, clay-draped wave-ripples. At Ells River, a partially muddy maximum flooding surface (MFS) interval, strongly burrowed by Thalassinoides, separates the middle McMurray lower SAGD reservoir chamber from the overlying upper McMurray reservoir chamber. This horizon may impair vertical steam chamber growth between the lower and upper reservoir levels for some areas of the Ells River bitumen deposits. Additional operational challenges are thin to patchy lean bitumen zones (bulk oil weight, <6%) and/or water saturation (Sw ã 40%); potential influx of mobile water from zones overlying the midreservoir MFS baffle; the shallow overburden (<200 m; <656 ft) that necessitates use of low-pressure operations; and the presence of partially depleted top gas sand that may locally be a thief zone.

Abstract We integrated core, wire-line logs, a three-dimensional (3-D) seismic volume, and a seismic attribute-derived 3-D lithology volume to define the stratigraphy of the Lower Cretaceous Mannville Group for a small area in Saskatchewan. The lithology volume was generated by integrating the seismic data with wire-line logs through the use of a probabilistic neural network. The stratigraphic interpretation was an iterative process: first, based on wire-line logs and cores; then, based on the integration of well and 3-D seismic data; and finally, by integrating the attribute-derived lithology volume with the other data sets. Integration of the lithology volume into our stratigraphic interpretation, along with the exploitation of seismic-based visualization technologies, helped us to construct a better geologic model than what could have been constructed using only well data or conventional seismic-stratigraphic analysis techniques. Unfortunately, despite the high-frequency content (and good to excellent quality of the data), meter-scale variations of lithology in the primary reservoir interval could not be detected seismically because of the low acoustic-impedance contrasts between the various lithologies in this interval. Various types of noise in the seismic data also degraded the attribute-based property prediction.

Abstract Rock asphalt or lithified oil sand and heavy oil occurring in Mississippian and Pennsylvanian (Carboniferous) strata along the southern and southeastern edges of the Illinois Basin in Kentucky are of increasing interest in the early 21st century. An impetus for renewed interest in asphaltic materials as well as heavy oils and potentially conventional oil located in south-central Kentucky is understandable, considering an overall increase in product price and technological advances in proposed recovery methods. Discussion in this chapter focuses on the regional structural setting, geographic and stratigraphic distribution of heavy oil and asphalt rock, proposed source rocks, general migration pathways, reservoir rock characteristics, and properties of the hydrocarbon resource. Additionally reviewed are the storied history of heavy-end hydrocarbon extraction, a series of projects and ongoing development of unconventional resources, and the potential for refining these resources.

Abstract California has one of the largest reserves for heavy oil in the world, second only to Venezuela. Recent declines in conventional resources and reserves during the last decade have prompted other jurisdictions to examine their prospective unconventional resources, such as heavy oil and oil sands, in a more favorable technological and economic setting. However, this has not been done universally in the United States, where thermal enhanced oil-recovery technologies (mostly used to produce heavy oil) have experienced a decline in production, concomitant with the downturn in conventional production. In California, the seep and oil-sand deposits are mostly unconsolidated sands bound together by biodegraded bitumen. Source rocks for both modern seeps and oil sands and ancient heavy-oil deposits are mainly the Miocene Monterey diatomites and equivalent diatomaceous mudstones and organic shales. In California, most of the seeps and oil sands overlie or are updip from underlying heavy-oil reservoirs. The seep and oil-sand deposits occur in areas where cap-rock integrity was compromised for the underlying heavy-oil reservoirs, breeched mainly by faults or fractures. Hydrocarbons migrated updip into basin-marginal settings or in structural areas of compromised cap rock and then pooled to form the seeps, later hardening into oil-sand deposits. Hydrocarbons accumulated in a wide variety of depositional environments from deep-sea fans, lobes, and submarine channels to fluvial-lacustrine deltas and incised valleys and every other sedimentary environment in between. This makes it difficult to identify type examples for the California accumulations, although case examples are given. In the past, steam-flood, condensed water drive, cyclic steam stimulation (CSS), and fireflood were used to produce the California heavy-oil reservoirs. Currently, significant California CSS projects underway include Belridge, Cymric, and northern Midway Sunset fields to stimulate intermediate-gravity hydrocarbons in the Monterey, Reef Ridge, and Etchegoin diatomite lithologies. Elsewhere, for example, in Canada, in-situ bitumen and extra-heavy-oil sands are commonly developed using CSS or steam-assisted gravity drainage (SAGD). Combined application of CSS along with SAGD from horizontal wells may recover bypassed pay in heavy-oil reservoirs and may be used to recover bitumen from associated oil sands, and multistage multifracing technologies may recover oil from the deeper unconventional (Monterey) source rocks. These technological developments, along with improved computing techniques (i.e., three-dimensional [3-D] geologic modeling/visualization), allow for real-time exploration and development of unconventional reservoirs. A significant effort exists in California to improve recovery from Pleistocene, Pliocene, and Miocene heavy-oil deposits; for example, at present, 70 to 80% recovery from heavy-oil steam drives is seen in Pleistocene Tulare Formation fluvial and alluvial sands. Full 3-D models anchored by extensive coring and logging programs have reaped benefits in many older oil fields (e.g., South Belridge, Midway Sunset, Cymric, Lost Hills, Kern River). Bypassed pay and new production from associated shallow oil sands and deeper source rocks may ultimately be a key to attainment of increases in secure unconventional energy reserves in North America. In the future, full integration of new technologies, along with technology sequencing, may be applied to old California oil fields for production of bypassed pay in heavy-oil fields.

Abstract The Uinta Basin in northeastern Utah is one of the principal petroleum provinces of the Rocky Mountains, and interest has been increasingly converging on its large deposits of unconventional hydrocarbon resources. Despite their apparent abundance and shallow depths, however, the bitumens, heavy and extra-heavy oils of the Uinta Basin have hitherto resisted commercial exploitation. They are immobile and technically stranded and will require innovative applications of in-situ thermal recovery methods for commercial production to proceed. Moreover, although some individual oil samples have been intensely investigated, a coherent literature on the physical and chemical properties of the Uinta Basin’s unconventional oil resources is lacking. Nearly all of the exploration, laboratory research, and field trials on the Uinta Basin have concentrated on surface mining and retorting, producing a database that is heavily slanted toward mining methodologies. The occasional pilot studies of in-situ recovery have been very small and inconsequential. The information that does exist on Uinta’s immobile oils is scattered across obscure in-house industry or government reports, unpublished core logs in public files at the Utah Geological Survey, and an array of academic articles. This chapter assembles data from published and unpublished sources to document the variations in the immobile reservoired oils from one part of the basin to another. The focus of this chapter is the geologic setting, the character of the sandstone reservoirs, the properties of the reservoired oils, and the size of the unconventional oil accumulations of the Uinta Basin.

Abstract Alaska’s North Slope is a world-class petroleum basin, with some of the largest producing fields in North America. What is not widely known is that the North Slope also holds a vast resource of heavy oil that is mostly undeveloped. The Ugnu sands, with 12 to 18 billion bbl original oil in place, account for about one half of the heavy-oil resource and are the focus of appraisal activity to determine development potential. Core description of the Ugnu identified 10 facies associations that represent fluvialdeltaic, floodplain, delta-front, and offshore environments. The primary reservoir facies are fluvial-deltaic channel fills and sandsheets. The fluvial-deltaic sandstones were deposited by meandering channel systems based on paleoflow indicators from image logs and sinuous amplitudes from three-dimensional (3-D) seismic data. Palynological analysis defined five regional stratal surfaces (sequence boundaries and flooding surfaces) and revealed that lower delta-plain environments persisted during most of Ugnu deposition. Careful integration of log, core, and seismic data provided the basis for defining the reservoir architecture and depositional model. The primary reservoir zones are the Ugnu M sands that are subdivided into the M70, lower M80, and upper M80 subzones. The M70 and lower M80 zones are characterized by regionally extensive erosional unconformities and sequence boundaries at the base that are overlain by multistory channel-fill sandstones deposited in lower and upper delta-plain settings. The upper M80 is bound by a marine flooding surface at the base (where present). The interval cleans upward and becomes progressively sandy in the east, corresponding to a transition fromdelta-plain to delta-front environments. The Ugnu reservoirs were deposited by meandering rivers that transected a flat coastal plain. Regionally, the Ugnu fluvial-deltaic system prograded from southwest to northeast during the Late Cretaceous to the early Tertiary and was deposited during an overall, but phased, base level rise.

Abstract As conventional crude reserves approach their predicted peak production as early as 2030, unconventional resources such as heavy oil and bitumen are receiving increased interest and are driving the more abrupt development of exploration, in-situ technologies, and prospective markets. For the first time, the huge potential of Russia’s vast heavy-oil and bitumen reserves is beginning to undergo systematic assessment, particularly in the eastern Siberian platform. Siberia’s natural bitumen fields have historically been disregarded and continue to be underrepresented in production markets mostly because of the climatic and technological challenges associated with in-situ extraction from permafrost and their extreme geographic distances from existing production and transportation lines. Until recently, much of the Russian literature has not been readily available. The compilation of references from western literature of this chapter, along with U.S. Geological Survey collections of Russian translations, will hopefully renew the interest of western researchers in these unconventional hydrocarbons. Geochemical studies presented in this chapter point to a different model for the emplacement of hydrocarbons in the Olenek uplift, which suggests that hydrocarbons are likely derived from the paleo-Verhhoyansk Basin to the east. These refined geologic and geochemical models, along with improving infrastructure and the potential for integrated development of the unconventional resources, open up the possibility of significant future production in Eastern Siberia.

Abstract Numerical geologic models are built for many purposes. Models at a cubic-millimeter resolution are required to understand how small-scale heterogeneity observed in core photographs and image logs affects vertical permeability. Models at 1 dm 3 (0.001 m 3 ) resolution are required to understand the variability of properties within the grid blocks that will be used in the flow simulator. Models at a 1000 m 3 (3531 ft 3 ) resolution are required to understand the variability between grid blocks to model specific recovery processes. Models at the 1012 m 3 (3.53 to 1013 ft 3 ) scale are required to assess resources over large areas. No single numerical geologic model is fit for all purposes. Many of the same tools are used at different scales, but notable differences related to the use of categorical and/or continuous variables, the number of variables, and conditioning to different data types exist. Three important model types and the implemented choices are described: (1) large-scale multivariate mapping for resource and/or reserve assessment, (2) reservoir-scale three-dimensional (3-D) modeling for reservoir development planning, and (3) high-resolution modeling to understand effective flow parameters at the flow-simulation scale.