McMurray Formation Research Articles

Earliest Cretaceous Transgression of North America Recorded in Thick Coals: McMurray Sub-Basin, Canada

Strata of the Lower Cretaceous McMurray Formation in the McMurray Sub-Basin (MSB) of Alberta and Saskatchewan, Canada, comprise marginal marine, tidal-fluvial, fluvial and interfluve deposits. In the Firebag Tributary located in the northeastern portion of the sub-basin, a thick coal seam (up to >20 m) forms a semi-continuous bed at the top of the lowermost McMurray Fm deposits (herein referred to as Lower McMurray). In coastal plain settings, peat-forming mires are highly sensitive archives of base-level. We investigate the stratigraphic significance of coals in the Firebag Tributary by analyzing coal petrography (4 cores), coal geochemistry (2 cores), and coal distribution in ~4500 wells. Additionally, we record the first absolute age for the McMurray Fm through the dating of an ash layer within the coal seam.The petrographic character and distribution of coals in the northeastern part of the MSB suggest a complex history of base-level rise at the end of Lower McMurray deposition. Wetting-upward character coal seams record initial transgression of the Boreal Sea during a 4th order sea level rise (Milankovitch-scale) within lowstand to early transgressive systems tract conditions. Sea-level rise during Lower McMurray times was estimated based on temperate climate peat formation rates, as well as peat-to-coal compaction factors, and probably occurred on a scale of 0.5–3 mm a−1. Seam-internal wetting-upward cycles suggest that base-level rise was punctuated. Locally, compound and drying-upward character coals represent zones of high accommodation, wherein peat accumulation in mires was influenced by phases of syn-depositional subsidence and karst collapse. The thickest coals in the study area form an arc on a coastal plain as the Boreal Sea inundated east- to southeastward into the Firebag Tributary. Within the arc of thick coals, a north-south decrease in coal thickness is interpreted to reflect the general southward inundation of the Boreal Sea across the MSB. Exceptionally thick coals (>10 m) likely formed where basement processes (e.g., karsting in Devonian carbonates) provided preferential groundwater pathways.Chemical abrasion thermal ionization mass spectrometry dating of 5 sharply faceted zircons recovered from an ash bed within the coal provides the first absolute age (121.39 ± 0.2 Ma – Aptian) to the southward transgression of the Boreal Sea. We hypothesize that initial inundation of the MSB was related to tectonic activity in the Canadian Cordillera and the onset of magmatic flow in the western Coast Plutonic Complex.

The impact of Aptian glacio‐eustasy on the stratigraphic architecture of the Athabasca Oil Sands, Alberta, Canada

AbstractHigh‐frequency incised valley systems and subaerial exposure surfaces are prevalent in Aptian‐aged units, having been documented in numerous basins around the world. In light of a growing body of palynological, geochemical and sedimentological evidence, a glacio‐eustatic mechanism for their generation has been suggested, driven by the waxing and waning of polar ice caps. The densely‐penetrated McMurray Formation of north‐eastern Alberta, Canada, provides a unique opportunity to test for an Aptian glacio‐eustatic signal within the Western Canadian Foreland Basin. This study combines detailed drill core description with wireline log‐based stratigraphic analysis to map and evaluate a series of drainage networks located along the cratonic edge of the Western Canadian Foreland Basin. Four stratigraphically distinct composite channel‐form bodies are documented across an area >14 000 km2. Composite channel‐form bodies are up to 50 km wide and locally exceed 70 m thick, subtending from upward‐coarsening parasequence sets 2 to 12 m thick; bounding marine flooding surfaces are mappable over distances exceeding 280 km along the north–south trending basin. Detailed internal fill characterization of the four composite channel‐form bodies suggests that three represent tidal–fluvial incised valley networks, and one represents a deltaic distributary system. At least six cycles of transgression and regression are apparent within the McMurray Formation stratigraphy. Recent biostratigraphic assessment has constrained deposition of the McMurray Formation between ca 125 Ma and 118 Ma, and periods on the order of 0·7 to 1·7 Ma are estimated for the mapped transgressive–regressive cycles. The high frequency nature of these Aptian sequences suggests that the sea‐level oscillations recorded in McMurray Formation strata are consistent with a glacio‐eustatic driver. Linking the internal stratigraphic architecture of the McMurray Formation with interpreted global cooling events and sea‐level drops provides the first evidence of glacio‐eustasy within Early Cretaceous strata of western Canada.

Salt tectonism and distribution of brackish-water trace fossils in the Cretaceous McMurray Formation, Athabasca Oil Sands, Alberta Foreland Basin

A proposed salt tectonism-saline seep model provides a novel alternative to the two widely accepted but irreconcilable depositional models for middle McMurray Formation strata of the Lower Cretaceous Athabasca Oil Sands deposit. Established interpretations of a fluvial axial channel belt along the eastern Alberta Foreland Basin contrast with a hundreds-of-kilometres long estuarine marine–fluvial transition zone setting that was characterized by brackish-water trace fossil laden beds. The architecture of a highly sinuous fluvial meander channel belt with bank-full depths of 30–40 m furthermore is not compatible with an estuary having a tens-of-metres thick salt wedge extending hundreds-of-kilometres upstream. This new model proposes that the removal of the underlying 100 m thick Middle Devonian salt section occurred across thousands of square kilometres and resulted in voluminous saline seeps up-section into river channel fills of the middle McMurray Formation. Southward transgression by a Boreal Sea tongue terminated fluvial lower McMurray Formation deposition, and transported brackish-water larvae inland along the tide-impacted backwater length. This zoology was sustained along the fluvial channel belt by the saline seeps that elevated salinity levels in channel muds as the fluvial system dominance reasserted. Brackish-water macroinvertebrates rapidly adapted to new terrestrial food sources in these fluvial channels, precluding the necessity for a salt wedge to have extended inland for hundreds of kilometres. This research presents the first quantitative analysis of the McMurray Formation trace fossil distribution patterns. Quaternary saline surface seep trends are proposed to represent intermittent seepage up-section since the Early Cretaceous.

Gas generation potential and processes of Athabasca oil sand bitumen from gold tube pyrolysis experiments

Gold-tube pyrolysis experiments were conducted on two oil sand bitumens (OSBs) from the top and bottom of the McMurray Formation in the Athabasca oil sand region of Alberta, Canada. Temperatures ranging from 300 °C to 650 °C and a pressure of 50 MPa with heating rates of 2 °C/h were used to investigate the gas generation behavior of OSB. The extractable residual bitumen content decreased systematically with increasing heating temperatures resulting in a continuous increase in total hydrocarbon gas yields with the highest value of about 480 mg/g bitumen at 650 °C. Among hydrocarbon gases, the yields of methane (C1) increased consistently with experimental temperatures, while the yields of ethane (C2), propane (C3), butanes (i + n-C4) and pentanes (i + n-C5) increased initially to a critical pyrolysis temperature and then decreased at higher temperatures. Molecular indices (C1/C2, C2/C3, C2/i-C4, C3/C4, i-C4/n-C4, i-C5/n-C5 and C1/ΣC1-5) obtained in this work are different from typical primary thermogenic gases generated from kerogen or secondary thermogenic gases derived from thermal cracking of oil. Three stages of OSB thermal evolution were identified over a wide range of heating temperatures. The first stage (300–425 °C) reflects initial decomposition of thermally unstable moieties in resins and asphaltenes. Gas generated at this stage was dominated by carbon dioxide and hydrogen sulfide with minor amounts of hydrocarbon. Hydrocarbon gases were enriched in wet gas components with increasing heating temperatures. The second stage (425–525 °C) corresponds to liquid oil cracking and wet gas generation. While the yields of methane and ethane still increased with heating temperatures, yield of propane reached a maximum and yields of butane and pentane started to decline. The third stage (525–650 °C) reflects wet gas cracking and dry gas generation as indicated by the dramatic decrease of wet gas components and increase in gas dryness. Variations of gas yields and chemical compositions from two OSBs were partially caused by different levels of biodegradation. The top OSB has experienced less biodegradation influence than the bottom one as indicated by higher saturated and aromatic hydrocarbon contents and intact alkylphenanthrene distribution. Increased biodegradation of OSB yielded a higher concentration of polar compounds and an overall lower hydrogen content, which reduced the hydrocarbon gas generation potential. Slightly higher amounts of wet gas components were generated from the top OSB because of the relatively higher content of reactive moieties (mainly alkyl groups) at a lower biodegradation level, while a higher proportion of methane was observed from the bottom, severely biodegraded OSB that was enriched in cross linked ring structures.

캐나다 앨버타주 전기 백악기 맥머레이층의 유성이토 퇴적층

유성이토는 현생 염하구 환경에서 흔히 발달하지만, 고기의 퇴적층에서 보고되고 퇴적학적으로 연구된 예는 드물다. 캐나다 앨버타주의 전기 백악기 맥머레이층에서 시추한 염하구 하도 퇴적층 내의 여러 이암층들은 고농도부유점토류에 의한 퇴적특징을 보인다. 이러한 이암층들을 현미경으로 자세히 관찰하여 3개의 미퇴적상(microfacies, 1~25 mm 두께)으로 구분하였다. 미퇴적상 1은 무구조의 이암(structureless mudstone)으로 주로 점토 입자로 구성되고 무질서하게 분포하는 조립질 입자(조립질 실트~세립질 모래)들을 포함한다. 조립질입자들을 지지할 수 있는 양력을 지닌 점착성의 이토류, 즉 유성이토가 정지하여 미퇴적상 1이 퇴적된 것으로 해석된다(quasi-laminar plug flow). 미퇴적상 2는 실트엽층을 포함하는 이암(silt-streaked mudstone)으로 산재한 조립질 입자를 포함하는 이암으로 구성되며, 불연속적이고 매우 얇은 실트엽층을 포함한다. 미퇴적상 1과 유사한 조직을 보이므로, 미퇴적상 2도 점착성의 유성이토에 의해 퇴적된 것으로 해석된다. 하지만 불연속적인 실트엽층은 plug 아래에 간헐적이고 약한 난류운동이 있었음을 제시한다(upper transitional plug flow). 미퇴적상 3은 이질 엽층리의 이암(heterolithic laminated mudstone)으로 실트엽층과 점토엽층의 교호로 구성되며, 평행엽층리 또는 저각도 사엽층리를 보이고 간혹 낮은 기복의 연흔 형태를 보인다. 이질 엽층리는 점착성 plug 아래의 난류층에서 입자크기에 따른 분급작용이 일어났음을 지시하며, lower transitional plug flow 아래에서 발달하는 낮은 층면구조에 의해 형성되었을 것으로 해석된다. 이 미퇴적상들은 유속과 부유이토농도에 따라 달라지는 유성이토의 여러 가지 상을 나타낸다고 볼 수 있다. 다른 지역에서 유성이토층을 인지하고 이암의 퇴적작용을 보다 잘 이해하는데 본 연구의 결과가 중요한 지식을 제공하리라 생각된다.

An Improved Workflow for Permeability Estimation from Image Logs with Uncertainty Quantification

Production forecasts are extremely sensitive to the spatial distribution of certain reservoir parameters, especially permeability, which controls fluid flow and efficiency of many recovery methods. Modeling the heterogeneity in permeability distribution is challenging due to various reasons. First, proper sampling is difficult due to biased sampling, dilation effects and sample disturbance. Second, calibration of core-plug measurements with well test data is problematic because of their vast differences in scale; in the case of heavy oil reservoirs, conventional well tests are not feasible due to bitumen’s ultra-low mobility at initial conditions. Therefore, in addition to flow-based measurements, alternative static data including image logs and core photographs, which capture detailed high-resolution information regarding heterogeneities at the millimeter scale, may be integrated for reliable permeability estimation along the wellbore. This paper examines the existing technique for permeability prediction from image logs (or core photographs) and proposes a set of improvements. For example, automatic variogram modeling is performed over a set of moving windows to simulate the sand–shale indicators along the well trajectory, capturing the locally varying anisotropy in variogram model parameters. In addition, it presents a unified approach to properly quantify the uncertainty in the histogram of core measurements and well log data: Joint histogram uncertainty considering the correlations between variables is incorporated into the existing methodology. The millimeter-scale model is constructed and upscaled to the centimeter scale via steady-state flow-based upscaling. This step is repeated with the centimeter-scale model until the final flow-simulation scale is attained. The entire methodology is applied within individual facies with distinct spatial correlations. A field case study involving data from the McMurray Formation (Alberta, Canada) is presented, where the permeability distributions in five different facies are modeled. The results indicate that considering automatic variogram modeling may lead to more realistic representation of the orientation of certain heterogeneous features that are strongly influencing the permeability to flow; furthermore, incorporating histogram uncertainty enables the modeling of porosity and permeability with improved uncertainty.

Origin and hydrogeological setting of saline groundwater discharges to the Athabasca River: Geochemical and isotopic characterization of the hyporheic zone

Identifying impacts of oil sands development on aquatic ecosystems requires understanding of the natural background water quality. In the Athabasca Oil Sands Region of Alberta this is challenging because the Athabasca River is incised directly into bitumen saturated sands of the McMurray Formation, and other saline Cretaceous and Devonian formations. This study compares the geochemical and isotopic composition of porewater sampled from the alluvial sediment beneath the Athabasca River with regional groundwater data to identify the geological origin of these saline groundwaters, and improve characterization of natural background sources of solutes entering the Athabasca River. Terrain conductivity surveys conducted along the Athabasca River were used to identify areas with evidence of saline groundwater discharge. Porewater samples were obtained from the alluvial sediment using drive point piezometers installed between 1 and 3 m below the water-sediment interface and were analyzed for δ18O, δ2H, δ34SSO4, δ18OSO4, 87Sr/86Sr, δ13C-DIC, δ13C-DOC, 3H, and 14C. The porewater in the alluvial sediment showed variable degrees of mixing with the overlying Athabasca River water, but the geochemical and isotopic composition in zones 1, 3 and 5 are consistent with discharge of saline groundwater from Cretaceous or Devonian units. The low percentages of modern carbon, and δ18O, δ2H, δ34SSO4, δ18OSO4, and 87Sr/86Sr signatures in the deepest porewater samples from Zones 1, 3 and 5 indicate glaciogenic water with high total dissolved solids originating from Devonian sourced solutes. Theses saline groundwater discharge zones occur where higher horizontal hydraulic gradients coincide with areas of higher salinity in the adjacent Cretaceous and Devonian aquifers, and areas with vertical connectivity with underlying Devonian aquifers. The results of this study demonstrate the influence of groundwater-surface water interactions and saline bedrock formation water discharge to water quality along some reaches of the Athabasca River which need to be considered in monitoring and water management strategies.

Shortwave infrared (1.0–2.5 μm) hyperspectral imaging of the Athabasca West Grand Rapids Formation oil sands

Previous work on the reflectance spectroscopy of oil sands has focused exclusively on the McMurray Formation of the Athabasca deposit. However, as industrial development expands into other formations, spectral research on Alberta’s other bitumen reservoirs is warranted. This study presents the first investigation of shortwave infrared (SWIR; 1.0–2.5 μm) hyperspectral imaging of Grand Rapids Formation oil sands. Comparing the spectral properties of Grand Rapids oil sands to that of the McMurray Formation reveals some key differences. Grand Rapids oil sands have lower overall reflectance and deeper 1.4- and 1.9-μm absorption features than McMurray oil sands of the same ore grade. At ore grades greater than 10 wt. %, Grand Rapids oil sands also have shallower bitumen absorption features. These spectral differences may be attributed to the mineralogical differences between the two formations, namely, structural water in K-feldspar. Hyperspectral analysis techniques that have been previously developed for McMurray oil sands were tested on a Grand Rapids Formation core. Using contrast stretching and the three-band combination of R e 2.05 μm, G e 2.13 μm, and B e 2.28 μm (where R, G, and B refer to red, green, and blue channels), the visibility of sedimentological features was enhanced in SWIR imagery. With a simple recalibration, an established spectral model for the estimation of total bitumen content (TBC) produced results in close agreement with Dean–Stark analysis data (coefficient of determination [R2] e 0.92, ±1.1 wt. %) and of similar accuracy to what has been previously demonstrated for the McMurray Formation. The results of this study suggest that with minor adjustments, oil sands spectral analysis techniques are transferable between different geological formations.

Solvent diffusion and dispersion in partially saturated porous media: An experimental and numerical pore-level study

Recent research on unlocking the solvent dispersion as a physical blending process in porous media has been mainly focused on core-scale observations. Pore-level studies of multiphase displacements can help to develop models that correlate rock macro-scale characteristics with its small-scale features, particularly for unsaturated rocks where the intricate fluid arrangements cause dynamic events to be localized in preferential pathways. In this work, to draw new insights into the physics of pore-level interfaces and crystallize the role of small-scale phenomena on the efficiency of solvent-aided bitumen recovery processes, numerical simulations coupled with experiments are conducted in pore-level domains. We simulate fluid flow and transport phenomena through millimeter-sized three-dimensional slabs of consolidated and unconsolidated packings of grains representing the geological rock types of the McMurray formation. We propose a robust numerical workflow for simulation of miscible-floods in unsaturated porous media and investigate the impact of matrix heterogeneity, connate water, cementation, and injection velocity on the longitudinal dispersion coefficient. In particular, primary drainage is simulated at low capillary numbers resulting in two-phase fluid occupancies through pore space domains. Finite element simulations are then carried out in order to solve the mixing advection-diffusion equations within the water-free pore space, and lastly, the effluent history is analyzed to predict the dispersion coefficient in both fully- and partially-saturated conditions and evaluate the efficiency of miscible displacements in the presence of microheterogeneities. A new analytical model for calculation of dispersivity, together with the numerical simulation results, is utilized to adjust a general model for the prediction of longitudinal dispersion coefficient in unsaturated sandy porous media of either uniform or non-uniform grains. Moreover, miscible-flood experiments at low to high injection velocities are conducted in a transparent glass micromodel. According to the results, rock micro-heterogeneities and immobile water both increase the longitudinal dispersion coefficient, and two-phase equilibria control the velocity field by creating connected regions of brine and low resistance oil-filled channels and consequently influence the solute transport and mixing processes. The effect of viscosity contrast on the longitudinal dispersion coefficient is also noteworthy, as the viscous fingering at unfavorable viscosity ratios widens the mixing zone.

Mechanistic simulation study of expanding-solvent steam-assisted gravity drainage under reservoir heterogeneity

Expanding-solvent steam-assisted gravity drainage (ES-SAGD) is a potential method to reduce steam-oil ratio (SOR) of SAGD, which is a critical concern especially for highly-heterogeneous reservoirs. The main objective of this research is to investigate the flow characteristics of heterogeneous reservoirs in which solvent is more likely to lower SOR of SAGD.SAGD and ES-SAGD with normal hexane are simulated for fifty geostatistical realizations consisting of clean sand and shale, qualitatively representative of the middle member of the McMurray formation. Thermodynamic models are calibrated with experimental phase behavior data for reliable comparison between SAGD and ES-SAGD, including the water solubility in oil at elevated temperatures.Results show that the SOR reduction by steam-solvent coinjection is positively correlated with the increase in SAGD's SOR due to heterogeneity. Enhancement of bitumen flow by dilution is more important for lowering SOR for those reservoirs in which the permeability variation makes slow-flow regions during SAGD.Simulation results show that a larger amount of bitumen tends to be diluted by solvent in those reservoirs for which SAGD exhibits slow production of bitumen. Then, the observed results are analyzed by use of SAGD analytical equations that clarify several influential factors for bitumen flow beyond the edge of a steam chamber. It is shown that dilution of bitumen by solvent in steam-solvent coinjection becomes more significant where flow barriers limit the local bitumen flow under SAGD even at high temperatures. In such slow-flow regions, the bitumen flow rate can be substantially increased by accumulation of solvent in ES-SAGD, which reduces the oleic-phase viscosity and increases the oleic-phase saturation and, therefore, relative permeability. Solvent accumulation within a steam chamber can also reduce thermal losses because of lower operating-chamber temperatures.

Selenium and sulphur in Athabasca bituminous sands mineral and bitumen fractions

There is increasing environmental concern regarding the emission of selenium (Se) from mining and upgrading of bitumen extracted from the Athabasca bituminous sands (ABS) in northern Alberta, Canada. However, there remains a lack of high quality analytical data for Se in this massive hydrocarbon reserve. Accurate analytical determinations of Se in bitumen from ABS are an important first step toward understanding its potential to be emitted to the environment. This has been a challenge due to the low abundance of Se combined with the preponderance of entrained mineral material (sand, clay) and the generally inadequate sensitivity of analytical methods used in the past. To overcome these issues, samples of ABS ores (McMurray Formation) underwent a toluene extraction procedure under ultra-clean lab conditions to separate bitumen from mineral particles. Separated bitumen, residual mineral material, and bulk ores were then subjected to acid-digestion and analysis using inductively coupled plasma sector-field mass spectrometry (ICP-SFMS) as well as hydride generation atomic fluorescence spectroscopy (HG-AFS). Unlike many other potentially toxic trace elements (Ag, As, Be, Cd, Cu, Pb, Sb, Tl and Zn) which exist almost exclusively in the mineral fraction, Se was found primarily (ca. 80%) in the organic (bitumen) fraction. Sulphur was determined in the same acid digests using both ICP-SFMS and inductively coupled plasma-optical emission spectroscopy (ICP-OES) and it too, was found almost exclusively in the bitumen fraction. Despite the limited number of samples available to our study, the positive, linear correlation between Se and S concentrations in bitumen suggests that S concentrations can be used as a guide to estimate their Se content. Given that Se is found mainly in the organic fraction of the ABS, there is considerable potential for mobilization of this element during upgrading and refining. The analytical methods successfully employed here have sufficient sensitivity to support studies of Se contamination of environmental media in the ABS region.

Senlac, the Forgotten SAGD Project

Summary The Senlac steam-assisted-gravity-drainage (SAGD) project in Saskatchewan, Canada, does not have the same name recognition as its much bigger brothers in the Alberta Oil Sands, but it certainly deserves to be known better. Senlac was the first industrial SAGD project in Canada, back in 1997, and since then, it has been the site for other technological innovations such as the use of solvent in addition with steam to increase recovery and reduce the steam/oil ratio (SOR), as well as the testing of wedge wells—wells drilled between SAGD well pairs to benefit from the heat remaining in the reservoir. The reservoir in Senlac is the Dina-Cummings of the Lower Cretaceous, and is much smaller than the McMurray formation, the site of most large-scale oil-sands projects, but the oil is only 5,000 cp; thus, it is mobile at reservoir temperature. This is a significant difference that allows well pairs to achieve excellent production and recovery even though reservoir thickness is only 8 to 16 m, well below the standard cutoff for SAGD. The presence of bottomwater under parts of the field is an added challenge to the operations. The paper will present the field characteristics and production performances as well as the main technological developments such as the solvent-added process (SAP) and the use of wedge wells. The paper will present a complete case study of an SAGD project in a heavy-oil reservoir where oil is mobile. Most SAGD projects so far have been conducted in bitumen, but the paper will show the potential for this technology in thinner and smaller reservoirs.

Temporal and spatial trends in riverine suspended sediment and associated polycyclic aromatic compounds (PAC) within the Athabasca oil sands region

Bitumen-bearing suspended sediment (SS) eroded from the McMurray Formation (MF) are fine grained (silts and clays) and coated with natural hydrophobic oils. This results in poor settling and long range transport of associated contaminants. There was a longitudinal increase in polycyclic aromatic compound (PAC) concentrations for rivers that erode the MF from upstream to downstream regardless of time-of-year, while loads were substantially increased during high flow periods when the erosive forces are the greatest and the overland flow contribution is high. Within the MF, variation in PAC contributions is seen by the Ells River having higher loads than the Steepbank River. Using the Ells and Steepbank as examples, double plot PACs ratios suggest that the PAC concentrations and signatures vary spatially within the MF but that the weathering processes may be the same. Plots of the various homologs of PACs generally illustrated a normal distribution which suggests petrogenic origins. However, several PAC ratios suggested that both the parent material and the SS are pyrogenic in nature. While it is likely that some level of atmospheric deposition (anthropogenic or from forest fire) is incorporated into the SS of the rivers, it is likely to be limited relative to the proportion of naturally eroded MF sediments. Additional analysis will be needed to distinguish the relative risk of both anthropogenic (e.g., industrial operations) and natural sources (bitumen deposits, forest fire) of PACs to the SS and to long-range depositional environments, as they may have potential aquatic ecological effects.

Novel insights into freshwater hydrocarbon-rich sediments using metatranscriptomics: Opening the black box

Baseline biogeochemical surveys of natural environments is an often overlooked field of environmental studies. Too often research begins once contamination has occurred, with a knowledge gap as to how the affected area behaved prior to outside (often anthropogenic) influences. These baseline characterizations can provide insight into proposed bioremediation strategies crucial in cleaning up chemical spill sites or heavily mined regions. Hence, this study was conducted to survey the in-situ microbial activity within freshwater hydrocarbon-rich environments cutting through the McMurray formation - the geologic strata constituting the oil sands. We are the first to report in-situ functional variations among these freshwater microbial ecosystems using metatranscriptomics, providing insight into the in-situ gene expression within these naturally hydrocarbon-rich sites. Key genes involved in energy metabolism (nitrogen, sulfur and methane) and hydrocarbon degradation, including transcripts relating to the observed expression of methane oxidation are reported. This information provides better linkages between hydrocarbon impacted environments, closing knowledge gaps for optimizing not only oil sands mine reclamation but also enhancing microbial reclamation strategies in various freshwater environments. These finding can also be applied to existing contaminated environments, in need of efficient reclamation efforts.

Sedimentological and stratigraphic characterization of Cretaceous upper McMurray deposits in the southern Athabasca oil sands, Alberta, Canada

The Lower Cretaceous McMurray Formation located in northeastern Alberta, Canada, is host to one of the largest bitumen resources in the world. In this paper, we provide an integrated sedimentological and stratigraphic analysis of the upper McMurray member located in the Pike and Jackfish project areas (Townships 73–76 and Ranges 4–7 W4M) of the southern Athabasca oil sands. Using core data, geophysical well logs, and seismic data, two main facies associations (embayment and fluvial) are evident. The embayment deposits were likely sourced by up-dip distributary channels and are commonly expressed in the subsurface as a series of coarsening-upward parasequences. The facies expressions in core range from bioturbated mudstones to wave-rippled sandstones. Noticeable, however, is the fact that there are areas where strata within the parasequences are instead substituted with sand, inclined heterolithic stratification, and mud. These deposits, in the form of fluvial channels with brackish-water overprint, occur at three different parasequence horizons within the study area. The removal of these embayment deposits is believed to be initiated, in part, by halite dissolution of the Middle Devonian Prairie Evaporite Formation deposits during upper McMurray deposition. Notably, the halite dissolution edge on the eastern half of the study area is believed to have created a subregional shelf–slope break during upper McMurray deposition. As such, the distributary channels likely re-equilibrated themselves to the slope created by the salt dissolution edge and thus proceeded to incise into previously deposited upper McMurray parasequence and underlying middle McMurray deposits.

Experimental Study on Geomechanical Dilation of Oil Sands During Cold–Water Injection

Summary Steam-assisted-gravity-drainage (SAGD) processes become effective only after thermal and hydraulic communication between an injection and production well has been established during the startup operation of the well pair. Conventional steam-circulation startup operations typically take 2 to 3 months to achieve interwell communication, but reductions in the startup time can have a favorable impact on project economics. Enhancement of interwell permeability using fluid-injection (water, or steam, or solvent) strategies to promote geomechanical dilation of the oil sands has been proposed as a startup technique. These fluid-injection processes will produce complex interactions of thermal, geomechanical, and multiple-phase flow behavior in the interwell formation region. Understanding better the role that these interactions play in establishing well-pair communication will provide opportunities to improve SAGD recovery performance. A triaxial experimental program has been designed and executed to explore whether cold-water injection would be sufficient to induce enhancements in effective permeability to water from geomechanical dilation mechanisms. Sample preparation techniques were modified to allow the preparation of reconstituted, very dense water-wet/bitumen sand specimens with different fluid saturations and almost identical porosities. Reclaimed/cleaned tailings sand from oil-sands mining operations was used to prepare artificial specimens, which are representative of McMurray Formation oil sands. A water-wet or bitumen sand core plug was then tested in an environmental chamber to simulate reservoir boundary conditions in terms of stress state, temperature, and pore pressure. A set of experiments was carried out in a triaxial cell under either initial isotropic or initial anisotropic stress state. Experimental results highlight the promising potential to dramatically enhance effective permeability to water and porosity in the dilated zone using cold-water injection at modest levels of stress anisotropy. The experimental results also provide support for the development of numerical models used in predicting SAGD startup performance and proactive utilization of the dilation as startup process for in-situ oil-sands development.

Reconstruction of brackish-water systems using an ichnological framework

This paper provides an overview of the history of ichnology from both Russian and international perspectives. However, the main purpose of the paper is to review how trace fossils can be used to discern the brackish-water sedimentary environments from their open-marine counterparts. A number of modern studies are presented, including: (1) Kouchibouguac Bay, New Brunswick, Canada; (2) Willapa Bay, Washington, USA; (3) Ogeechee River Estuary, Georgia, USA; and (4) Petitcodiac River estuary, New Brunswick, Canada. Cretaceous examples from the Western Canada Sedimentary Basin (i.e., McMurray Formation, AB, Canada and Gething Formation, British Columbia, Canada) are provided to test the models derived from the modern estuaries.

Mudstone Clast Breccia in the Cretaceous Athabasca Oil Sands, Western Canada: Fluvial Debris-Flow Transitions into Traction Carpets

AbstractThe origin and distribution of mudstone clast breccia bed deposits of the middle McMurray Formation responded to a range of current flow conditions associated with downchannel migrations by kilometers-long point bars, which accumulated as reservoirs of the Cretaceous Athabasca oil sands in northern Alberta. Fabrics consisting of dispersed clast entrainments within centimeters- to decimeters-thick stratified sand beds accumulated as grain flows and small-scale debris flows that filled shallow, flat-bottomed troughs during bed erosion on the point bar. Most low-density clast dispersals were sourced by eroded mudstone beds exposed along the bar bed surfaces. Clast-laden debris flows, 1–2 m thick, filled deeper troughs on the point bar, often as overlying flow-surge deposits, resulting in internal erosional surfaces within the breccia bed. Elsewhere, voluminous debris flows were sourced by undercut older channel walls that eroded mud-dominated counter point bar beds or exhumed lower McMurray floodplai...

Orogeny and the collapse of the Devonian Prairie Evaporite karst in Western Canada: impact on the overlying Cretaceous Athabasca Oil Sands

Abstract The Middle Devonian Prairie Evaporite Formation accumulated up to 200 m of halite-dominated beds across Western Canada in a salt basin extending from northern Alberta southeastwards into southern Saskatchewan and western North Dakota. A 1000 km long salt dissolution trend along the eastern basin margin resulted in the removal of 100–150 m of halite–anhydrite beds. A second salt dissolution trend removed up to 200 m of section across southern Saskatchewan. The removal of the halite-dominated beds and the collapse of the overlying strata responded to regional aquifer and vertical water flows driven by compaction up-structure to the NE towards the eastern margins of the foreland Alberta and intracratonic Williston constituent basins of the Western Canadian Sedimentary Basin. Flows resulting in dissolution trends in the deepening Alberta foreland basin were responses to Middle Jurassic–Early Cretaceous Columbian orogenic tectonism, in contrast with the multiple Paleozoic and Mesozoic dissolution stages across the southern Saskatchewan area of the northern Williston basin. Water flows along the Devonian Keg River strata migrated into the overlying Prairie Evaporite salt beds. The dissolution fronts advanced along multi-kilometre long NW- and NE-oriented sets of fault–fracture lineaments resulting from orogenic Precambrian block movements propagated into the overlying Devonian strata. The Athabasca Oil Sands accumulated above a 300 km long segment of the dissolution trend along the eastern margin of the evaporite basin. An unusually low 1:2 thickness ratio of removed salt beds to overlying strata resulted in significant structural controls on the deposition of the overlying Cretaceous McMurray Formation point bar complexes. Fluvial point bars up to 6 km long and tens of metres thick collinearly aligned along fairways tens of kilometres long, following the halite dissolution trends 200 m below. These sand reservoirs trapped Laramide oil migration into the area. Biodegradation followed, resulting in a trillion barrel resource. A final stage of salt removal occurred with the influx of subglacial meltwaters, rejuvenating 10 km 2 Cretaceous collapses across southern Saskatchewan.

Three-Dimensional Reconstruction of Meander-Belt Evolution, Cretaceous Mcmurray Formation, Alberta Foreland Basin, Canada

Three-Dimensional Reconstruction of Meander-Belt Evolution, Cretaceous Mcmurray Formation, Alberta Foreland Basin, Canada