Athabasca Area Research Articles

Climbing through Climate Change in the Canadian Rockies: Guides’ Experiences of Route Transformation on Mt. Athabasca

Mountain guides play an important role in the provision of nature-based tourism activities, such as mountaineering, in alpine environments around the world. However, these locales are uniquely sensitive to climate change, and despite extensive documentation of bio-geophysical changes, there are few studies evaluating the impacts of these changes on mountaineering routes and the livelihood of mountain guides. This constrains adaptation planning and limits awareness of potential loss and damage in the mountain tourism sector. In response, our study explored mountain guides’ lived experiences of working on Mt. Athabasca in Jasper National Park, Canada, to reveal the effects of climate change on mountaineering routes and implications for the mountain guiding community. To do this, we used a mixed methods approach that combined spatio-temporal trend analysis, repeat photography, and semi-structured interviews with mountain guides. We found that rising temperatures and changing precipitation regimes in the Mt. Athabasca area are driving glacial retreat and loss of semi-permanent snow and ice, which is impacting climbing conditions and objective hazards on mountaineering and guiding routes. Guides’ experiences of these changes varied according to socio-economic conditions (e.g., financial security, livelihood flexibility), with late-career guides tending to experience loss of guiding opportunities and early-career guides facing increased pressure to provide services in more challenging conditions. Our findings offer novel insights that identify salient issues and bolster support for actions in response to the concerns of the mountain guide community. This study also underscores the need for further research, as the underlying issues are likely present in mountaineering destinations globally.

Novel insights on the impact of top water on Steam-Assisted Gravity Drainage in a point bar reservoir

Summary As efforts are made to efficiently exploit and recover bitumen resources in Canada, increasingly more complex reservoirs in the Athabasca area continue to challenge the application of Steam-Assisted Gravity Drainage (SAGD) technology. Several studies have been done to investigate the impact of heterogeneities/complexities such as shale barriers, lean zones, and top and bottom water on the performance of the SAGD process. However, the literature is deficient for point bar deposits with top water zones, a common occurrence in oil sands systems. This study, by using thermal reservoir simulation, examines SAGD performance in a point bar deposit reservoir where an overlying top water and an inclined heterolithic strata (IHS) is present. The results show that where the top water is unconfined and steam injection pressure is higher than that of the top water zone, there is a loss of thermal energy, but the top water does not impact steam chamber development. At steam injection pressure lower than that of the top water zone, top water continuously drains into the reservoir and constrains the size of the chamber. However, the IHS zone helps to delay drainage of the top water into the chamber when steam is injected at underbalanced conditions. Finally, under proper steam injection pressure conditions, top water production can be considerably delayed.

Athabasca oil sands: Megatrap restoration and charge timing

The petroleum trap for the Athabasca oil sands has remained elusive because it was destroyed by flexural loading of the Western Canada Sedimentary Basin during the Late Cretaceous and Paleocene. The original trap extent is preserved because the oil was biodegraded to immobile bitumen as the trap was being charged during the Late Cretaceous. Using well and outcrop data, it is possible to reconstruct the Cretaceous overburden horizons beyond the limit of present-day erosion. Sequential restoration of the reconstructed horizons reveals a megatrap at the top of the Wabiskaw-McMurray reservoir in the Athabasca area at 84 Ma (late Santonian). The megatrap is a four-way anticline with dimensions 285 125 km (177 78 mi) and maximum amplitude of 60 m (197 ft). The southeastern margin of the anticline shows good conformance to the bitumen edge for 140 km (87 mi). To the northeast of the anticline, bitumen is present in a shallower trap domain in what is interpreted to be an onlap trap onto the Canadian Shield; leakage along the onlap edge is indicated by tarry bitumen outliers preserved in basement rocks farther to the northeast. Peripheral trap domains that lie below the paleospillpoint, in northern, southern, and southwestern Athabasca, and Wabasca, are interpreted to represent a late charge of oil that was trapped by bitumen already emplaced in the anticline and the northeastern onlap trap. This is consistent with kimberlite intrusions containing live bitumen, which indicate that the northern trap domain was charged not before 78 Ma. The trap restoration has been tested using bitumen-water contact well picks. The restored picks fall into groups that are consistent both with the trap domains determined from the top reservoir restoration and the conceptual charge model in which the four-way anticline was filled first, followed by the northeastern onlap trap, and then the peripheral trap domains.

Approach to Evaluating the CO2 Storage Capacity in Devonian Deep Saline Aquifers for Emissions from Oil Sands Operations in the Athabasca Area, Canada

Abstract The Province of Alberta is the largest CO 2 emitter in Canada, with annual emissions close to 250 Mt, of which about 55 Mt CO 2 originate from oil production from oil sands. Geological storage of CO 2 has been identified as the major component of the strategy for reducing greenhouse gas emissions from oil sands operations, which are located in the Athabasca area close to the shallow eastern edge of the Alberta basin. Therefore, CO 2 storage in deep Devonian saline aquifers, located westward of the oil sands operations, may constitute a solution for storing CO 2 from these operations. A regional-scale study of the potential for storing CO 2 in deep Devonian saline aquifers in an area covering ∼126,000 km2 has been undertaken with the aim of identifying suitable sites for CO 2 storage. The Devonian sedimentary succession consists of a succession of stacked sandstone and carbonate saline aquifers separated by intervening shaly and evaporitic aquitards and aquicludes. The approach taken in the study, illustrated in this paper, comprises 11 steps, including: 1) Geological mapping of 29 Devonian formations based on information from more than 34,000 wells; 2) Hydrostratigraphic delineation of the 13 deep saline aquifers identified in this succession; 3) Determination of hydraulic continuity between various aquifers, due to depositional or erosional events; 4) Determination of formation water salinity, which ranges from less than 4000 mg/L (the limit of protected groundwater in Alberta) to close to 440,000 mg/L; 5) Determination of pressures and temperatures in these aquifers, which vary, respectively, between 1 and 30 MPa and between 12 °C and 135 °C; 6) Determination of the CO 2 phase and density at the top of each aquifer, the latter varying between 2 is in gas phase to > 800 kg/m3 where CO 2 is in supercritical state; 7) Determination of well-scale porosity distribution in each aquifer, which varies between 1% and 40%, based on well logs in 8305 wells and core analyses in 5242 wells; 8) Determination of the areal distribution of CO 2 storage capacity in each aquifer, based on aquifer thickness and porosity, and CO 2 density; 10) Determination of the regions suitable for CO 2 storage in each aquifer based on legal and regulatory constraints and protection of hydrocarbon resources; 10) Determination of permeability distributions in each aquifer, which varies from 10 D, based on 214,194 core analyses in 5242 wells and 4318 drill stem tests in 3586 wells; and 11) Identification of target areas for CO 2 storage based on local storage capacity and permeability, both of which have to be high at the local scale. Eleven prospective areas in 10 deep saline aquifers, with a cumulative storage capacity of close to 4 Gt CO 2 , have been identified as a result of this process of evaluation, screening and selection.

Evaluation of CO2 storage capacity in Devonian hydrocarbon reservoirs for emissions from oil sands operations in the Athabasca area, Canada

Abstract Geological Storage of CO 2 has been identified by the provincial Alberta government as the major component of its strategy for reducing greenhouse gas emissions in the province. The issue of reducing atmospheric CO 2 emissions is particularly important for oil sands plants, whose emissions in 2013 were in the order of 55 Mt CO 2 eq. Unfortunately, the oil sands operations are located near the shallow edge of the Alberta basin, which is not suitable for CO 2 storage. However, CO 2 storage in deep Devonian oil and gas reservoirs located westward of the oil sands operations may constitute a solution for storing CO 2 from these operations. The volumetric CO 2 storage capacity in 1225 oil and gas reservoirs in 13 different Devonian formations in an area covering approximately 126,000 km2 was estimated using information from reserves and production databases. The CO 2 storage capacity has been calculated by reservoir type and by production stage. The aggregate CO 2 storage capacity in oil and gas reservoirs in the Devonian sedimentary succession in the study area is in the order of ∼700 Mt. However, most of the reservoirs have small storage capacity, and only 9 oil reservoirs and 10 gas reservoirs have CO 2 storage capacity greater than 5 Mt each, for a cumulative total of ∼447 Mt CO 2 . The strength of underlying aquifers was evaluated by performing material balance calculations for these 19 oil and gas reservoirs and it was found that they do not have a significant effect in reducing the CO 2 storage capacity of these reservoirs. The CO 2 storage capacity in the study area is bound to be greater if one considers the fact that, once the infrastructure, including pipelines, is built to bring CO 2 to any of these very large reservoirs, then smaller reservoirs in the same oil or gas field can be accessed with relatively minimal extra costs. The aggregate CO 2 storage capacity in the fields where the 19 very large oil and gas reservoirs are found has been considered as well, raising the CO 2 storage capacity in these fields to ∼491 Mt CO 2 . The storage capacity in oil reservoirs in the study area can be further increased by using CO 2 in enhanced oil recovery. Although 705 oil pools have been identified as being technically suitable for CO 2 -EOR, only 12 oil reservoirs have remaining oil in place greater than 60 million barrels that would economically justify implementation of CO 2 -EOR. Assuming various incremental recovery factors and net CO 2 utilization factors, the additional amount of CO 2 that may be stored in these 12 oil reservoirs varies between 31 and 412 Mt CO 2 , thus increasing the CO 2 storage capacity in these oil reservoirs. This evaluation shows that the potential CO 2 storage capacity in oil and gas reservoirs in Devonian strata west of the Athabasca oil sands area in Alberta is significant and has the potential to reduce the carbon footprint of the oil sands operations for several decades until other technological advances for reducing CO 2 emissions will come into being.

Geoscience of Climate and Energy 13. The Environmental Hydrogeology of the Oil Sands, Lower Athabasca Area, Alberta

Shallow fresh groundwater and deep saline groundwater are used together with surface water in the extraction of bitumen from the Athabasca Oil Sands both in the surface mining and in situ operations. However, increasing efficiencies in processing technologies have reduced water use substantially and currently at least 75% of the water used in most operations is recycled water. Much concern has been expressed regarding contamination of surface waters by seepage from tailings ponds, but hydrogeological studies indicate that this is not happening; that seepage capture design is effective. Oil sands mining and in situ project licensing and operation regulations include Environmental Impact Assessments that mandate considerable hydrogeological measurement and monitoring work. However, little of this is independently evaluated for accuracy or synthesized and interpreted for the public. Recent changes in Alberta environmental regulation, including the establishment of the Alberta Environmental Monitoring Management Board (in October 2012) are expected to bring new transparency to environmental management of Oil Sands operations.SOMMAIREOn utilise conjointement des eaux douce de faibles profondeur, des eaux souterraines salines profondes avec des eaux de surface dans l'extraction du bitume des sables bitumineux de l'Athabasca, tant dans le procédé d’extraction in situ qu’en surface. Par ailleurs, l’accroissement de l'efficacité des technologies de traitement a considérablement réduit la consommation d'eau et, à l’heure actuelle, au moins 75% de l'eau utilisée dans la majorité des opérations est de l'eau recyclée. Beaucoup d’inquiétude a été exprimée concernant la contamination des eaux de surface par la percolation des eaux des bassins de décantation des résidus, mais des études hydrogéologiques indiquent que ce n'est pas le cas, et que le concept de capture des infiltrations est efficace. L’octroi de permis d’exploitation ainsi que les procédés d’exploitation des sables bitumineux, par extraction en surface ou in situ, comportent des évaluations d’impact sur les milieux de vie, est assorti de mandats élaborés de mesures hydrologiques et de suivi. Cela dit, peu de ces mesures sont évaluées de manière indépendante quant à leur exactitude, leur mise en forme et leur interprétation pour le grand public. Les changements récents dans la réglementation environnementale en Alberta, y compris la mise en place du Alberta Environmental Monitoring Management Board (en Octobre 2012) devraient aboutir à une nouvelle transparence de la gestion environnementale de l'exploitation des sables bitumineux.DOI: http://dx.doi.org/10.12789/geocanj.2013.40.016

지구통계 기법을 이용한 오일샌드 저류층 해석 및 스팀주입중력법을 이용한 비투멘 회수 적지 선정 사전 연구

본 연구에서는 캐나다 아사바스카 지역의 맥머레이층에 대한 3차원 지구통계 모사를 실시하였으며 모사 결과를 바탕으로 심부지열회수방법을 통한 경제적 산출 가능 지역을 가늠하고자 하였다. 비투멘의 효율적인 생산을 위하여 SAGD 공법의 최적 입지를 선정하는데 있어 스팀챔버의 충분한 수직적 연장성을 확보하는 것은 중요한 사항이다. 연구지역에서 획득한 110개의 시추공 자료에 대하여 마르코프 전이 확률 기반의 분석을 실시하였으며 이를 바탕으로 맥머레이층 구성 암상에 대한 추계론적 예측을 실시하였다. 추계론적 모사를 통하여 획득한 다중재현을 기반으로 앙상블 확률 분포도를 제작하였으며 이는 각 암상이 분포 할 수 있는 포텐셜을 보여준다. 앙상블 확률 분포도를 이용하여 투수성 퇴적층(역질 퇴적층 및 사질 퇴적층)에 대한 누적 층후도를 구성하였으며 이를 바탕으로 SAGD 공법이 적용될 수 있는 최적 입지를 선정하였다. SAGD 최적 입지 선정을 위한 추가적인 분석을 실시하기 위하여 전이율을 바탕으로 한 단일 퇴적층의 평균적인 수직 및 수평적 연장성을 산정하였다. 투수성 퇴적층의 평균적인 수직적 연장성은 대체로 투수성 퇴적층에 대한 누적층후도 분포도와 유사한 분포 양상을 보이나 일부 누적 층후가 큰 위치에서 유사하지 않은 양상을 보인다. 이는 누적 층후도와 평균적인 수직적 연장성 분포 양상이 유사하지 않은 지역은 투수성 퇴적층과 다른 암상과의 교호성은 매우 크나 투수성 퇴적층의 수직적인 연장성은 좋지 않음을 의미한다. 따라서 누적층후도 뿐 만 아니라 투수성 퇴적층의 수직적 연장성 또한 충분히 고려하였을 때 건전한 SAGD 최적 입지를 선정하는데 충분히 신뢰성 있는 결론을 도출 할 것으로 판단된다. In the study, three-dimensional geostatistical simulations on McMurray Formation which is the largest oil sand reservoir in Athabasca area, Canada were performed, and the optimal site for steam assisted gravity drainage (SAGD) was selected based on the predictions. In the selection, the factors related to the vertical extendibility of steam chamber were considered as the criteria for an optimal site. For the predictions, 110 borehole data acquired from the study area were analyzed in the Markovian transition probability (TP) framework and three-dimensional distributions of the composing media were predicted stochastically through an existing TP based geostatistical model. The potential of a specific medium at a position within the prediction domain was estimated from the ensemble probability based on the multiple realizations. From the ensemble map, the cumulative thickness of the permeable media (i.e. Breccia and Sand) was analyzed and the locations with the highest potential for SAGD applications were delineated. As a supportive criterion for an optimal SAGD site, mean vertical extension of a unit permeable media was also delineated through transition rate based computations. The mean vertical extension of a permeable media show rough agreement with the cumulative thickness in their general distribution. However, the distributions show distinctive disagreement at a few locations where the cumulative thickness was higher due to highly alternating juxtaposition of the permeable and the less permeable media. This observation implies that the cumulative thickness alone may not be a sufficient criterion for an optimal SAGD site and the mean vertical extension of the permeable media needs to be jointly considered for the sound selections.

Athabasca oil sands: reservoir characterization and its impact on thermal and mining opportunities

Abstract The heavy oil deposits of Canada are a large resource with an estimated 1.7×10 12 barrels of bitumen in place. The Lower Cretaceous McMurray Formation in the Athabasca area of northern Alberta contains about 900×10 9 barrels of bitumen in place. This resource can be developed through surface mining and thermal in situ techniques. This paper examines the size of this resource in a global context and highlights its position relative to the North American market. The regional geology of the Western Canada Sedimentary Basin and the Athabasca area will also be reviewed. Understanding the regional reservoir distribution of the McMurray Formation is critical to understanding oil sands opportunities. Fluvial estuarine point bar reservoirs are a large portion of the resource that can be developed. Examples will be shown from the type outcrop location, where the stratigraphy can be organized into a hierarchy that subdivides channel-fills into bedsets, storeys, bars and barsets. Inclined heterolithic strata (IHS) surfaces can be identified. Considerable resource delineation drilling has occurred in the basin. The regulator for the Athabasca area specifies minimum drilling densities before project approvals are granted. Regional 2D seismic lines and project-specific 3D and 4D seismic datasets have also been acquired, to reduce the reservoir uncertainty and improve resource definition in this complex depositional environment. These techniques provide a unique opportunity to analyse a complex depositional system with abundant well and core control, outcrop data and seismic information. To determine preliminary deposition environments, software techniques have been successfully used to interpret large datasets quickly. Laser imaging of mine faces has also been used to record stratigraphy and determine the mined volume of ore. The importance of detailed reservoir characterization studies and their impact on thermal in situ recovery mechanisms will also be discussed. Understanding reservoir facies distributions and lateral relationships affects any recovery process, but has an even greater significance in a heavy oil reservoir.

Low Pressure SAGD Operations

Abstract In the last few years, there has been increased interest in low pressure SAGD operations, in part, due to the gas over bitumen resource conflict. In an earlier paper, it was predicted that low reservoir steam pressures had the effect of sharply reducing hydrogen sulphide and carbon dioxide production per barrel of oil. Likewise, particularly troublesome scales, such as the magnesium and calcium silicates, were less thermodynamically favoured than at high steam pressures. Further investigations into the fate of gases in SAGD have been undertaken, especially for the case where the virgin pressure of the reservoir is low. In such cases, the amount of solution gas is limited, and the bitumen at steam zone pressure is often undersaturated with respect to the available methane. The polar gases, hydrogen sulphide and carbon dioxide, on the other hand, are almost entirely produced via dissolution in the produced water. In the low virgin pressure case, the methane is entirely produced via dissolution in bitumen. This contrasts with initial reservoir pressures of, for example, 3,500 kPa, where more than half of the methane is also produced via the produced water. The other major difference is that, in the low virgin pressure case, very little gas is predicted to accumulate in the steam zone. This paper examines the scaling tendencies of minerals, and the fate and compositions of produced gases in both low pressure SAGD and SAGD in low virgin pressure reservoirs. Use is made of recent advances in gas-liquid solution thermodynamics. The implications of this work include a possible effect on simulation studies for bitumen production, as well as on cap gas production via the produced water. This may also be an equity issue in the Athabasca area where cap gas has been shut in by regulatory intervention. Introduction There has been considerable interest in the issue of SAGD steam zone pressure (or temperature) in recent years. The issue revolves around the range of pressures under which a given SAGD project might be operated, without serious adverse economic effects on the project. Chhina(1) is reported to have advocated the use of lower pressures in order to reduce steam-oil ratios (SOR), and therefore production costs. The issue has been further explored by Kisman(2), who defines low pressure SAGD as involving "pressures below what steam/gas lift can accommodate, and above pressures where low-pressure consequences, such as reduced oil rates and artificial lift difficulties, affect the viability of SAGD operations." One of Kisman's conclusions was that operation at reasonably low pressures provides savings due to reduced SOR, and the smaller production well liners and tubulars that are needed. While there are limited field data on low pressure SAGD at present, the issue has received more detailed attention in the last few months owing to the ongoing gas-bitumen resource conflict. A previous paper(3) explored a number of aspects of the engineering chemistry of SAGD, which are also dependent on the pressure (i.e., temperature) of the steam zone.

Geology and thermotectonic evolution of the western margin of the Trans-Hudson Orogen: evidence from the eastern sub-Athabasca basement, Saskatchewan

In the Cree Lake Zone of northern Saskatchewan, reworked Archean orthogneisses are overlain by a highly deformed supracrustal sequence, the Paleoproterozoic Wollaston Group. This package of rocks was deformed and metamorphosed during the ca. 1.8 Ga continent–continent collision of the Trans-Hudson Orogen (THO), forming the Wollaston fold–thrust belt that underlies the eastern Athabasca Basin. The Hudsonian structural, metamorphic, and magmatic evolution of the Wollaston fold-thrust belt in the eastern Athabasca area involved six major stages. (1) Early collisional stage, DP1 at 1860–1835 Ma, involved burial of Wollaston Group metasediments from surface to depths equivalent to 3–5vkbar (1 kbar = 100 MPa) by thrust-pile stacking or imbrication tectonics, prograde metamorphism with garnet growth and development of early leucosomes, and emplacement of ca. 1840 Ma grey granite suite. (2) Collisional stage, DP2a at 1835–1820 Ma, involved continued deeper burial of Wollaston Group metasediments along a prograde P–T–t (pressure–temperature–time) path at depths equivalent to peak pressures of 6–9 kbar and approaching peak temperatures (750–825 °C), mafic magma underplating in the lower crust, initiation of large-scale crustal melting, emplacement of 1835–1820 Ma tholeiitic to calc-alkaline intrusions, and initiation of strike-slip tectonics. (3) Oblique collisional stage, DP2b at 1820–1805 Ma, involved strong transpressional tectonics with NE–SW shearing and NW–SE shortening, partitioned high-strain ductile flow, kilometre-scale fold development, initiation of exhumation, attainment of peak temperatures (750–825 °C), and essentially isothermal decompression with decompressional melting and intrusion of the main pulse of leucogranites and granitic pegmatites. (4) Late oblique collisional stage, DP3 at 1805–1775 Ma, caused development of amphibolite-facies dextral strike-slip shear zones and retrograde movement of older shear zones. It included apparent rotation of the main shortening axis and development of accommodation features due to vertical uplift (i.e., extension). (5) Post-collisional stage, DP4 at 1775–1760 Ma, involved continued localized adjustments along an essentially isobaric cooling path and produced NNE-trending, sinistral, oblique-slip reverse faults with reactivation of older shear zones. (6) Late post-collisional stage, DP5, produced north- to northwest-trending sinistral faults, including the Tabbernor fault system. Extension and tectonic extrusion during DP4 and DP5 were significant and resulted in orogenic collapse and formation of the Athabasca Basin at ca. 1750–1680 Ma.

カナダオイルサンドの開発〜さらなる挑戦

Bitumen from oilsands that has been regarded only as an alternative resource for the next generation in Japan is recognized as what makes up production decline of conventional petroleum resources at the North American crude oil market. One third or more of the total oil production in Canada is from synthetic crude oil based on the bitumen or the diluted bitumen. Therefore, the bitumen has already shown its presence and will no longer be called unconventional.The order of Canadian oilsand in-place is equal to that of Saudi Arabia's. The Energy Resources Conservation Board (ERCB) estimated that Athabasca area has 1, 600 billion bbls of bitumen in-place and it has been regarded as one of the largest hydrocarbon reserves in the world. The amount of reserves is formally evaluated as 175 billion bbls by ERCB and the Alberta Energy Utilities Board (AEUB) at present.Major oil companies are positively involved in the Canadian oilsand development as oil business, positioning it as one of the important investment options for making balance against the investment risks in geopolitically unstable areas, so that it is included in their global portfolios from a viewpoint of stable oil supply. There is a prediction that the bitumen production will reach two thirds of the oil production in Canada within a decade and will also increase three times by 2017.The huge amount of the bitumen reserves will fill the gap between supply and demand of the North American oil market. Athabasca may become one of the main production centers and the oilsand bitumen may be in a global portfolio of oil companies as a long-life and stable resource. Solutions to problems such as total process establishment, stabilization of netback bitumen price and gas price, and expansion of the market are breakthrough points to make the story much more realistic.

Geological Sequestration of Anthropogenic Carbon Dioxide in the Western Canada Sedimentary Basin: Suitability Analysis

Abstract Geological sequestration of anthropogenic carbon dioxide is a potential solution to the release into the atmosphere of CO2, a greenhouse gas thought of as significantly contributing to the global warming trend observed since the beginning of the industrial revolution. Basically, CO2 can be sequestered in geological media:through enhanced oil recovery (EOR),by storage in depleted oil and gas reservoirs,through replacement by CO2 of methane in deep coal beds (ECBMR),by injection into deep saline aquifers, and by storage in salt caverns. Criteria in assessing the suitability of a sedimentary basin for CO2 sequestration are:tectonism and geology,the flow of formation waters and geothermal regime, andthe existence of storage media (hydrocarbon reservoirs, coal seams, deep aquifers and salt structures). Generally, the Western Canada Sedimentary Basin is suitable for CO2 sequestration by all means because it is tectonically stable, it has regional-scale aquifers confined by aquitards or aquicludes, and it has oil and gas reservoirs in various stages of depletion, uneconomic coal seams, and extensive salt beds. However, various regions in the basin have different degrees of suitability, ranging from not suitable along the eastern edge of the basin, to extremely suitable in southwestern and central Alberta. Most major CO2 producers, such as power plants and refineries around Edmonton, are found in regions that are unsuitable for CO2 sequestration in geological media; however, some, such as the oil sands plants in the Athabasca area, are in regions that are not suitable. This analysis of the suitability of the Western Canada Sedimentary Basin for CO2 sequestration in geological media should provide industry and governments with essential information needed for developing plans and policies in response to climate change effects of anthropogenic greenhouse gas emissions into the atmosphere. Introduction Human activity since the industrial revolution had the effect of increasing atmospheric concentrations of gases with a greenhouse effect, such as carbon dioxide (CO2) and methane (CH4), leading to climate warming and weather changes(1, 2). Because of its relative abundance compared with the other greenhouse gases, CO2 is by far the most important, being responsible for about 64% of the enhanced "greenhouse effect"(1). On a sectoral basis, the energy sector contributes globally the most (45%) to anthropogenic (produced by human activity) effects on climate change(3). The high use of fossil fuels (85% of the world's energy needs), foreseen to continue well into the future(2, 4), is the major contributor to increased emissions of CO2 into the atmosphere. Thus, a major challenge in mitigating anthropogenic (man-made) effects on climate change is the reduction of these emissions. Figure 1 shows Canada's profile in CO2 emissions by sector and by province. The profile of CO2 emissions in the Western Canada Sedimentary Basin is different from the national and other regions' profile because the basin is a major North American producer of fossil fuels.

Flow systems in the Mannville Group in the east-central Athabasca area and implications for steam-assisted gravity drainage (SAGD) operations for in situ bitumen production

ABSTRACT The Mannville Group in northeastern Alberta was deposited during the Early Cretaceous in a south- to north-trending valley system on the pre-Cretaceous unconformity surface. The Mannville Group overlies eroded Devonian carbonates and is overlain by the shale-dominated Colorado Group equivalent. Mannville Group strata are composed of fluvio-estuarine and marine siliciclastic sediments. Hydrostratigraphically, the Mannville succession can be subdivided into four aquifers separated by three intervening aquitards. The four aquifers are, from the base up, the basal McMurray, upper McMurray Wabiskaw, Clearwater and Grand Rapids sandstones. The intervening aquitards are the bitumen-saturated middle McMurray and the Wabiskaw and Clearwater shales. The flow of Mannville Formation water is driven by local topography from recharge at highlands in the southeast and at the Stony Mountain upland in the centre of the study area, to discharge along the valleys of the Athabasca, Clearwater and Christina rivers. In the southwest, the flow in the basal McMurray and upper McMurray-Wabiskaw aquifers is drawn toward the basin-scale drain formed by the underlying Devonian Grosmont aquifer. Vertical flow in the study area is downward, from the ground surface toward the pre-Cretaceous unconformity. Application of the Steam Assisted Gravity Drainage (SAGD) process for in situ bitumen extraction from the McMurray Formation raises several hydrogeological issues: sustaining the large volumes of water needed for steam production; safely disposing of any produced residual water; protecting energy and groundwater resources; and avoiding large-scale cross-formational flow. RESUME Le Groupe de Mannville du Nord-est de l'Alberta s'est sedimente durant le Cretace inferieur dans un systeme de vallees d'orientation nord-sud sur une surface de discordance pre-Cretace. Le Groupe de Mannville recouvre des carbonates du Devonien et est a son tour recouvert par l'equivalent du Groupe de Colorado a dominance de shale. Les strates du Groupe de Mannville sont composees de sediments siliciclastiques fluvio-estuariens et marins. Du point de vue hydrostratigraphique, les strates du Groupe de Mannville peuvent etre subdivisees en quatre aquiferes separes par trois aquitards intermediaires. Les quatre aquiferes sont, de la base vers le haut, les gres de McMurray de Base, de McMurray-Wabiskaw superieur, de Clearwater et de Grand Rapids. Les aquitards intermediaires sont les shales satures en bitume de McMurray moyen et les shales de Wabiskaw et de Clearwater. L'ecoulement des eaux de formation du Mannville est entraine par la topographie locale a partir d'une zone de recharge dans les hautes terres du sud-est et des hauteurs de Stony Mountain dans le centre de la region d'etude, pour se deverser le long des vallees des rivieres Athabasca, Clearwater et Christina. Au sud-ouest, l'ecoulement des aquiferes de McMurray de base et du McMurray-Wabiskaw superieur est entraine vers le drain d'echelle de bassin forme par l'aquifere sous-jacent de Grosmont du Devonien. L'ecoulement vertical dans la region d'etude se fait vers la base a partir d'une discordance du pre-Cretace. L'application d'un processus de drainage assiste par la vapeur ('SAGD') pour l'extraction in-situ de bitume a partir de la Formation de McMurray souleve plusieurs questions: maintenir les grands volumes d'eaux necessaires pour la production de vapeur, disposer de facon securitaire des eaux residuelles produites, proteger les ressources en energie et en eaux souterraines, et eviter des ecoulements de grande echelle entre les formations. Traduit par Lynn Gagnon End_Page 376------------------------

Francis Harper (1886-1972)

... Harper became an avid and well-rounded naturalist at an early age. In 1914, he received his B.A. degree from Cornell University and was employed as a zoologist on a Geological Survey of Canada expedition to the Lake Athabasca-Great Slave Lake region. The expedition, under the leadership of Charles Camsell, left Athabasca Landing on 18 May 1914 and returned there on 10 October of the same year. Most of June was spent on Lake Athabasca, while July and August were spent exploring the Tazin and Taltson River area, an unmapped region whose biology was at the time completely unknown. Harper gathered information on the plants, fishes, amphibians, reptiles, birds, and mammals encountered during the journey. ... Harper returned in 1920 to the Athabasca area, where he was in the field from early April to early November with Hamilton "Mack" Laing and J.A. Loring. ... Harper published a series of technical papers on the plants, fishes, reptiles and amphibians, mammals, and physiographic and faunal regions of the Lake Athabasca-Great Slave Lake area, based on his fieldwork of 1914 and 1920. ... Harper realized a dream of more than 30 years in 1947, when he undertook a biological reconnaissance of the Nueltin Lake area in the southern Keewatin. ... Harper arrived at the Windy River post, which was operated by the family of Fred Schweder Sr., on 31 May. He brought with him a young zoology student from the University of Toronto, Farley Mowat. ... Harper immediately began collecting specimens and natural history information on mollusks, spiders, fishes, birds, mammals, ectoparasites of birds and mammals, mosses, and vascular plants. For most of his stay, Harper remained near the Windy River camp, and he continued fieldwork until his departure by plane on 4 December 1947. ... In addition to providing Harper with a base of operations at Windy River, Fred Schweder Sr.'s sons - Charles and Fred Jr. - assisted him by collecting specimens and providing numerous faunal observations, which they had gathered during their years of travel and residence in the Nueltin Lake area. Mowat and Harper, however, did not get along well, and on 7 July Harper dismissed Mowat from the expedition. ... The split between Mowat and Harper was severe and permanent, as separate publications on the birds of the Nueltin Lake area by the two do not mention that they were once associated, while Harper gave no indication that anyone had accompanied him to Nueltin Lake in May. Harper returned from Nueltin Lake with a tremendous amount of information on the natural history of the area, including specimens of over 800 plants, 117 birds, and 113 mammals. ... Francis Harper is probably best considered a relatively minor figure among biologists who were active in the Canadian North during the first half of the twentieth century. ... his publications reflect his proclivity for collecting large amounts of observational information. ... Biologists contemplating quantitative studies in the region, particularly those related to birds or mammals, would be well advised to read Harper's relevant publications, since natural history remains the basis for all modern, well-designed ecological research projects.

Peter Pond: Map Maker of the Northwest (1740-1807)

... In addition to his contributions in charting the Northwest, Pond compiled vast amounts of data on the geography of the Great Lakes area through his travels in the Upper Mississippi and Detroit areas. He was responsible for providing information on the geography of the Great Lakes area to Benjamin Franklin that dictated the character of the Canadian-American boundary negotiations in 1782-83. Pond's character has been described as volatile, occasionally explosive, morose, suspicious, unsociable, proud, sensitive, sometimes impetuous, and intractable. Others have described him as a true adventurer, of sterling character, courageous, industrious, aggressive, and extremely competent. Although his memoirs suggest that he was largely unschooled, he apparently received a good "common education" and was literate in both English and French. His wit and good humour and his artistic sense show through in his writings. His own writings and detailed cartographic notations indicate a man with a high regard for knowledge, a keen sense of observation, and a desire to preserve information. Whatever may be said of his character and literacy abilities, there is no doubt that here was a man extremely capable of assembling, integrating, and interpreting vast amounts of verbal and visual geographical data and presenting them in amazingly accurate depictions of geography for which there was no precedent. As a result of his travels in the Athabasca area and contact with the resident Indians, Peter Pond compiled information on the geography of the region and prepared the first map of the north-central parts of Canada. Pond's cartographic assembly was aimed at the discovery of a route to the western sea. His knowledge of the Northwest, his vision of a passage to the Pacific Ocean, and his own desire to reach that ocean served as an inspiration for the epochal voyages of Alexander Mackenzie. Despite his unequivocal importance as a historical figure, Peter Pond has not been recognized for his accomplishments.

The vegatation, surface water chemistry and peat chemistry of moderate-rich fens in central Alberta, Canada

The non-forested fens of the Athabasca area in central Alberta, Canada are characterized by their surface water and peat chemistry. Correlations between vegetation and chemical gradients are examined. The primary vegetation gradient is from stands dominated byDrepanocladus vernicosus, Meesiatriquetra, Menyanthes trifoliata, andCarex chordorrhiza to those dominated byBrachythecium mildeanum, Drepanocladus aduncus, Carex aquatilis, andDrepanocladus polycarpus. This vegetation gradient reflects a chemical gradient of increasing pH, magnesium, sodium, sulphur, organic nitrogen, and phosphorus in the fen water and increasing magnesium, iron, and phosphorus in the fen peats. Potassium and sodium in the fen peats show a decreasing trend along the vegetation gradient. A second gradient from shrub-moss vegetation to sedge-moss vegetation is significantly correlated with microtopography and an increase in nitrate content in the spring (May) waters. The fen waters in this study are in the 5.3–7.1 pH range, with specific conductance of 18–240μS. The calcium contents of the waters averages 19.5–22.1 mg/l and that of magnesium averages 4.3–5.3 mg/l in spring and fall, respectively. The subsurface fen peats are characterized by mean calcium contents of 17,426 mg/kg and magnesium contents of 1,719 mg/kg. Organic nitrogen, nitrate, and ammonium content in the spring and fall waters average 1,967–2,395 μg/l, 3.1–9.8 μg/l, and 16.8–88.9 μg/l, respectively.

Incidence and Geographic Distribution of Sweet Clover Necrotic Mosaic Virus in Alberta

Incidence and Geographic Distribution of Sweet Clover Necrotic Mosaic Virus in Alberta

Stabilized dune ridges in northern Saskatchewan

Stabilized dune ridges occurring in northern Saskatchewan have previously been identified as variedly as "ice-crack moraines" and longitudinal dunes. Investigations of their morphological, structural, and sedimentary attributes reveal that they are, indeed, of eolian origin, but they form a particular group within the parabolic dune association, namely, the "Cree Lake type dune ridges." The ridges occur in association with other types of parabolic dunes and other eolian features, such as loess and wind-abraded glacial blocks and bedrock outcrops. The dunes and the associated eolian features were all formed by southeasterly paleowinds of uniform direction. The dune ridges developed from primary parabolic dunes of simple and composite types through the process of dune elongation. At the same time, exposed rock surfaces were abraded by the wind and loess was deposited downwind from the developing dune fields. The southeasterly direction of the paleowinds, which is almost directly opposite to the direction of the present-day winds affecting dunes in the Lake Athabasca area, was due to adiabatic air masses coming off the ice sheet from the east and affected eolian activity in quite a large region in northern Saskatchewan and Alberta. The somewhat cool and sufficiently dry adiabatic winds checked the vegetation on the dunes and in the areas around them. The development of the dune ridges came to an end when a sudden climatic change evoked the rapid stabilization of the dunes by vegetation but not before most of the ridges became partly deformed by southwesterly crosswinds resulting from the same climatic change. The period of eolian activity is estimated from the age of the local ice frontal positions to have been between 10 000 and 8800 years BP. Only one other region is known from North America, namely, the St. Lawrence Lowland in the east, where analogous eolian environment prevailed in the zone peripheral to the continental ice sheet and produced comparable eolian features.

Uranium in Canada

ABSTRACT Uranium ore deposits can be classified into three major types: detrital, hydrogenic and igneous-metamorphic. Although some igneous-metamorphic deposits formed as primary concentrations, detrital and hydrogenic deposits formed as secondary concentrations at or near the surface of the earth's crust -- the uranium having been initially exposed to the surficial environment in felsic intrusive and volcanic rocks in concentrations generally less than 50 ppm. The oldest economic uranium deposits are detrital paleo-placers which formed as heavy-mineral concentrations under an anoxic atmosphere. Following the oxyatmoversion in mid-Aphebian time, deposits of hydrogenic origin predominate. Of these, sandstone-type and shale deposits are first found in late Aphebian rocks, but become less important thereafter in Canada despite their preponderance in Phanerozoic rocks elsewhere. Classical veins and unconformity-veins are predominant in Helikian time and appear to have precipitated from downward or laterally migrating waters. The distribution pattern of igneous-metamorphic deposits is also systematic, but more complex than that of the other two major types. Canada is favoured with uranium ore reserves which are among the largest in the world -- these reserves are contained in all three types of deposit. The igneous-metamorphic type is represented by the Bancroft district of Ontario, where more than 11 million pounds U3O8 have been produced from pegmatites emplaced in granulite-facies metamorphic rocks. The detrital deposits at Elliot Lake, with production in excess of 190 million pounds of U3O8 by 1976, constitute one of the largest uranium ore districts in the world. The Elliot Lake deposits and a similar deposit at Agnew Lake occur in pyritic quartz pebble conglomerates which were deposited in paleo-stream channels. These deposits were derived from uranium-rich granitic rocks located north of the depositional area and concentrated mainly as detrital heavy minerals. Hydrogenic uranium deposits are represented in the Proterozoic of Canada in shales and several epigenetic types. The epigenetic deposits are generally characterized by pitchblende and hematite and are generally enriched in Ni, Co, Ag, Cu and As. Chemically favourable graphitic and (or) calcareous shelf-facies metasedimentary strata commonly form the host rocks. The Port Radium and Beaverlodge deposits are classical veins which exhibit strong structural control. Stratigraphic control appears more important in the recently discovered unconformity-veins which occur near the base of the Athabasca Sandstone in Saskatchewan. At the Rabbit, Key and Cluff Lake deposits most of the mineralization occurs in basement rocks within 100 m of the unconformity, but ore is also found within the regolith and overlying orthoquartzites. Production from the Athabasca area deposits will probably surpass that from the Elliot Lake district in the future.

Importance of Reservoir Description In Evaluating In-Situ Recovery Methods For Cold Lake Heavy Oil

Abstract The huge reserves of heavy oil in Alberta are found in a Variety of complex reservoir. Recovery, excluding mining, will require application of some form of in-situ method, primarily in the better reservoir. The proper selection of an in-situ method, applicable to the various reservoir type, requires a basic understanding of reservoir description, and the engineering aspect of the reservoirs. In Part 1 of this paper, reservoir description in the Cold Lake heavy oil deposits is discussed under three headings:rock properties;fluid saturation; andreservoir geometry. Based on these parameters, five selected reservoir types are discussed and compared. Part 2 considers the application of the reservoir description in evaluating in-situ methods. The significance of the reservoir parameters is discussed in general terms and related to the four most important in-situ recovery mechanism: steam stimulation, steam drive, combustion and solvent. The reservoir description is then used as the basis of comparison of the recovery mechanisms for each of the five Cold Lake reservoir types described in Part 1. Introduction OVER 900 BILLION BARRELS (143 × 109 m3) of heavy oil, known as the Alberta oil sands deposits, are found in a variety of complex reservoirs in sands of Lower Cretaceous age. Knowledge of the presence of these resources may be very comforting in these times of concern over Canada's future energy supplies. However, this oil is only of value if, and when, it can be recovered from the reservoirs. Recovery has started in the Athabasca area where oil is being extracted from the reservoir by 'surface mining methods. Great Canadian Oil Sands Ltd. has a mine and an upgrading plant in operation and Syncrude Canada Ltd. has the second extraction facility under construction. Mining methods, however, are applicable to but a small portion of the Athabasca areas and these methods may yield, as currently estimated, 38 billion barrels (6 × 109 m3) or 4% of the total oil in place in the deposits*. The remainder of the oil in place outside of the mineable area of Athabasca, the heavy oil deposits in the Cold Lake area and the other oil sands deposits will have to be extracted by in-situ recovery techniques. In-situ recovery processes basically consist of increasing the mobility of the oil and then driving the fluids to a production well. The successful application of any of these techniques depends on a profound knowledge of the characteristics of the reservoir. Part 1 of this paper discusses the nature of the oil sands in terms of rock properties, fluid saturations and reservoir geometry. Based on these parameters, five selected reservoir types in the Cold Lake area are identified and compared. In Part 2, those parameters are related to a number of in-situ recovery methods for heavy oil, with specific reference to application in the Cold Lake deposit. In the papers, no distinction is made among the terms "heavy-oil sands", "oil sands" or "tar sands".