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Chunqing Jiang - One of the best experts on this subject based on the ideXlab platform.
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An Integrated Mass Balance Approach for Assessing Hydrocarbon Resources in a Liquid-Rich Shale Resource Play: An Example from Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin
Journal of Earth Science, 2020Co-Authors: Zhuoheng Chen, Chunqing JiangAbstract:Petroleum resource assessment using reservoir volumetric approach relies on porosity and oil/gas saturation characterization by laboratory tests. In liquid-rich resource plays, the pore fluids are subject to phase changes and mass loss when a drilled core is brought to the surface due to volume expansion and evaporation. Further, these two closely related volumetric parameters are usually estimated separately with gas saturation inferred by compositional complementary law, resulting in a distorted gas to oil ratio under the circumstances of liquid hydrocarbon loss from sample. When applied to liquid-rich shale resource play, this can lead to overall under-estimation of resource volume, distorted gas and oil ratio (GOR), and understated resource heterogeneity in the shale reservoir. This article proposes an integrated mass balance approach for resource calculation in liquid-rich shale plays. The proposed method integrates bulk rock geochemical data with production and reservoir parameters to overcome the problems associated with laboratory characterization of the volumetric parameters by restoring the gaseous and light hydrocarbon loss due to volume expansion and evaporation in the sample. The method is applied to a Duvernay production well (14-16-62-21W5) in the Western Canada Sedimentary Basin (WCSB) to demonstrate its use in resource evaluation for a liquid-rich play. The results show that (a) by considering the phase behavior of reservoir fluids, the proposed method can be used to infer the quantity of the lost gaseous and light hydrocarbons; (b) by taking into account the lost gaseous and light hydrocarbons, the method generates an unbiased and representative resource potential; and (c) using the corrected oil and gas mass for the analyzed samples, the method produces a GOR estimate close to compositional characteristics of the produced hydrocarbons from initial production in 14-16-62-21W5 well.
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artificial thermal maturation of source rocks at different thermal maturity levels application to the triassic montney and doig formations in the western canada Sedimentary Basin
Organic Geochemistry, 2016Co-Authors: Mariafernanda Romerosarmiento, Tristan Euzen, Chunqing Jiang, Sebastien Rohais, Ralf LittkeAbstract:Abstract Artificial thermal maturation of petroleum source rocks is widely performed by either open- or closed-system pyrolysis. These experiments are performed usually on immature source rock or isolated kerogen samples to quantify petroleum generation potential and to calculate kinetic parameters. Here, we characterize a maturation series from the Triassic Montney and Doig formations in the Western Canada Sedimentary Basin (WCSB), in order to investigate the evolution of the source rock properties and their corresponding kerogen kinetic parameters as a function of the thermal maturity. Organic petrography determined the thermal maturity and the spatial distribution of organic matter particles. Rock-Eval Shale Play analyses were then applied to assess the presence of both free and sorbed hydrocarbons still contained in the sample as well as the hydrocarbon generation potential. Based on vitrinite reflectance values, three kerogen samples from the Doig Formation and one kerogen sample from the Montney Formation at different thermal maturity levels were selected for analysis of bulk kinetic parameters (e.g., activation energy distribution, frequency factor) using programmed open-system pyrolysis. Additionally, we evaluated the type of hydrocarbons and determined the molecular composition of organic compounds that comprise the first two Rock-Eval peaks (Sh0 and Sh1) obtained during the improved thermovaporization. TD–GC–MS–FID analyses were carried out on rock samples sequentially from 100 °C to 200 °C and then from 200 °C to 350 °C in order to characterize the composition of hydrocarbons represented by each Rock-Eval Shale Play peak. Free and sorbed low-to-medium molecular weight aliphatic and aromatic hydrocarbons ( 20 ) are the main hydrocarbon components released in the temperature range corresponding to the Rock-Eval Shale Play Sh0 parameter. Medium and high-molecular weight hydrocarbons (C 10 –C 30 aromatics and saturates) are predominant components thermally released in the temperature range corresponding to the Rock-Eval Shale Play Sh1 parameter. Results show both an increasing activation energy and loss of petroleum generation potential as thermal degradation proceeds. The Shale Play method has been developed to better discriminate the generated fluids (Sh0 + Sh1) from the residual kerogen (Sh2) providing a more accurate Rock-Eval T max . Sh0 and Sh1 parameters also offer a practical way for an early estimate of oil in place.
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a revised method for organic porosity estimation in shale reservoirs using rock eval data example from duvernay formation in the western canada Sedimentary Basin
AAPG Bulletin, 2016Co-Authors: Zhuoheng Chen, Chunqing JiangAbstract:Studies suggest that nanometer-scale pores exist in organic matter as a result of thermal decomposition of kerogen. Depending on the host rock lithology, organic pores could be the primary storage for hydrocarbon accumulation in unconventional petroleum plays. Although various methods are publicly available, estimation of organic porosity remains a challenge because the procedures involve certain simplification or some implicit assumptions on the calculation of initial total organic carbon (TOC). In this study, we propose a revised method to address some of these issues. A model of estimating hydrocarbon expulsion efficiency is developed and incorporated into the calculation of initial TOC, thus producing an estimate of organic porosity with an improved mass balance. The method has been tested and compared with estimates using other methods based on a Rock-Eval data set in the literature. An application of the method to a large data set from the Upper Devonian Duvernay Formation petroleum system in the Western Canada Sedimentary Basin reveals that the modification has a significant effect on the estimated organic porosity. This study also indicates that organic porosity in the Duvernay Formation ranges greatly from none in immature intervals to >6% in highly mature and organic-rich shale intervals. Scanning electron microscope images of immature and mature organic-rich shale samples of the Duvernay Formation show a progressive increase in organic porosity with increasing thermal maturity, supporting the proposed model calculation. The presence of a large volume of organic porosity in mature shale intervals suggests a significant amount of hydrocarbon may be stored in the organic nanopores in the Duvernay Formation.
Nicholas B Harris - One of the best experts on this subject based on the ideXlab platform.
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organic matter accumulation in the upper devonian duvernay formation western canada Sedimentary Basin from sequence stratigraphic analysis and geochemical proxies
Sedimentary Geology, 2018Co-Authors: Nicholas B Harris, Levi J Knapp, Julia M Mcmillan, Maria MastalerzAbstract:Abstract We present a model for organic carbon accumulation in the Upper Devonian Duvernay Formation of the Western Canada Sedimentary Basin, relating total organic carbon (TOC) concentrations to a high resolution geochemical and organic petrologic database and comparing these to a core-based sequence stratigraphic interpretation. Many previous source rock studies have suggested that organic matter is enriched in transgressive systems tracts or at maximum flooding surfaces, an observation that is commonly attributed to an assumed relationship between water depth and oxygen levels. Our data set enables us to associate total organic matter content and organic assemblages with particular systems tracts and to examine how the organic assemblages change across the Basin, tested against proxies for redox conditions and bioproductivity to relate relative sea level to specific mechanisms for organic accumulation. The Duvernay Formation comprises three third-order depositional sequences, superimposed on a second-order late transgressive systems tract and early highstand systems tract. Sequences are composed almost entirely of transgressive systems tracts and highstand systems tracts, with a lowstand systems tract only at the base of the upper cycle that marks the second-order sea level turnaround. Depositional facies generally vary from bioturbated carbonate-rich siltstones to siliceous mudstones from the platform margins to Basin center. Organic petrologic analysis records predominantly amorphous organic matter and solid bitumen, with much less abundant vitrinite and inertinite. Organic matter type indicated by Rock-Eval analysis shows that in most cases, high total organic carbon (TOC) content is associated with better quality organic matter (high hydrogen index) and vice versa, indicating more reducing conditions or higher bioproductivity were responsibility for organic enrichment. However, near carbonate reefs, hydrogen index is uncorrelated with TOC, indicating that here, dilution by carbonate minerals was the primary control on organic enrichment. Across most of the Basin, highest TOCs are recorded just above the second-order maximum flooding surface. Secondary peaks in TOC are recorded above the maximum flooding surface in the upper third-order cycle and in the transgressive systems tract of lower third-order cycle. Low TOC values are recorded in the lowstand systems tract and in the middle and upper third-order transgressive systems tracts almost up to the maximum flooding surfaces. Throughout much of the Basin, proxies for relative sea level, restriction of water masses (Mo/TOC), redox conditions (Mo/Al and S/Fe) and bioproductivity (biogenic silica) coincide. These relationships demonstrate that organic carbon accumulation resulted from influxes of nutrient-rich upwelled water during high sea level; thus, TOC values are highest in the upper part of transgressive systems tracts and lower highstand systems tracts. Anoxia typically developed as a result of bioproductivity and enhanced organic matter accumulation but was not itself a trigger for organic sedimentation. Near carbonate reefs, however, varying sea level regulated carbonate sedimentation rate and organic matter dilution, and bioproductivity had less impact on organic matter concentrations; thus, TOC was high when carbonate deposition was low during transgressions, which forced carbonate reefs to backstep, limiting carbonate sedimentation in deeper water area.
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the effect of thermal maturity on geomechanical properties in shale reservoirs an example from the upper devonian duvernay formation western canada Sedimentary Basin
Marine and Petroleum Geology, 2018Co-Authors: Tian Dong, Nicholas B Harris, Levi J Knapp, Julia M Mcmillan, David L BishAbstract:Abstract Shale reservoirs are characterized by low matrix permeability and therefore require effective models of geomechanical properties to optimize drilling and hydraulic fracturing strategies. Both initial rock composition and thermal maturity are potentially critical controls on geomechanical properties. We investigate the Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin, a major shale gas target that spans a wide range in rock compositions and thermal maturity to identify relationships between these parameters and geomechanical properties. Core hardness measurements and dipole sonic and density log data were used to characterize the geomechanical properties. Major element chemical analysis, X-ray diffraction analysis and LECO combustion were used to determine mineralogy, bulk rock chemistry and total organic carbon (TOC) content and to distinguish biogenic from detrital silica. Scanning electron microscopy (SEM) images with complementary energy-dispersive spectroscopy (EDS) maps were obtained for representative samples to document the rock fabric and distribution of organic matter and minerals. Hardness and Al2O3 concentrations are strongly negatively correlated in all cores, regardless of thermal maturity, suggesting that clay minerals are the most significant factor controlling geomechanical properties. Biogenic silica is positively correlated to hardness. Detrital silica is negatively correlated to hardness, an artifact of the positive correlation between detrital clay minerals and detrital quartz. The positive correlations between CaO content and hardness in all cores suggest the brittle behavior of carbonate minerals. Increased thermal maturity from immature to oil window results in greater hardness for rocks of similar geochemical compositions. We propose that this results from: (1) enhanced mechanical compaction; (2) carbonate cementation; (3) increased stiffness of kerogen; and (4) partial conversion of kerogen into expelled hydrocarbons that reduces the load-bearing function of the organic matter. At maturities greater than oil window, thermal maturity does not exert a major control on the rock strength; thus, there are no significant changes in hardness between samples from oil window and dry gas window. Geomechanical properties can be related to mineralogy, which exerts a major impact on the geomechanical properties. Quartz cements sourced from biogenic silica rather than smectite-to-illite transition are the primary contributor to the rock strength in the Duvernay Formation. However, it is noteworthy that thermal maturity should also be considered as an important factor when predicting geomechanical properties from mineralogy.
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geothermal potential of foreland Basins a case study from the western canadian Sedimentary Basin
Geothermics, 2018Co-Authors: Jonathan Banks, Nicholas B HarrisAbstract:Abstract Geotechnical and hydrogeological data from well bore logs and rock cores were used to identify, map, and model the power production potential of geothermal reservoirs in Sedimentary formations in the Western Canadian Sedimentary Basin across several municipal districts in western Alberta. We show a general workflow for using oil and gas data to assess geothermal resources in Sedimentary Basins, present a series of contour maps and stratigraphic grids of salient geothermal reservoir properties and assess the power production potential of these resources using a volumetric (heat-in place) method. In total, throughout the study area, we identified a potential thermal power capacity of ∼6100 MWt per for a 30-year production period. Reservoir depths ranged from about 2500 m to over 5000 m. Formation temperatures ranged from ∼60 °C to over 150 °C. The calculated thermal power capacity equates to ∼1150 MWe of potential electrical power capacity over the 30 year production period, of which ∼ 800 MWe are considered high grade (>120 °C) resources that may reliably produce electricity with existing technology.
Zhuoheng Chen - One of the best experts on this subject based on the ideXlab platform.
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An Integrated Mass Balance Approach for Assessing Hydrocarbon Resources in a Liquid-Rich Shale Resource Play: An Example from Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin
Journal of Earth Science, 2020Co-Authors: Zhuoheng Chen, Chunqing JiangAbstract:Petroleum resource assessment using reservoir volumetric approach relies on porosity and oil/gas saturation characterization by laboratory tests. In liquid-rich resource plays, the pore fluids are subject to phase changes and mass loss when a drilled core is brought to the surface due to volume expansion and evaporation. Further, these two closely related volumetric parameters are usually estimated separately with gas saturation inferred by compositional complementary law, resulting in a distorted gas to oil ratio under the circumstances of liquid hydrocarbon loss from sample. When applied to liquid-rich shale resource play, this can lead to overall under-estimation of resource volume, distorted gas and oil ratio (GOR), and understated resource heterogeneity in the shale reservoir. This article proposes an integrated mass balance approach for resource calculation in liquid-rich shale plays. The proposed method integrates bulk rock geochemical data with production and reservoir parameters to overcome the problems associated with laboratory characterization of the volumetric parameters by restoring the gaseous and light hydrocarbon loss due to volume expansion and evaporation in the sample. The method is applied to a Duvernay production well (14-16-62-21W5) in the Western Canada Sedimentary Basin (WCSB) to demonstrate its use in resource evaluation for a liquid-rich play. The results show that (a) by considering the phase behavior of reservoir fluids, the proposed method can be used to infer the quantity of the lost gaseous and light hydrocarbons; (b) by taking into account the lost gaseous and light hydrocarbons, the method generates an unbiased and representative resource potential; and (c) using the corrected oil and gas mass for the analyzed samples, the method produces a GOR estimate close to compositional characteristics of the produced hydrocarbons from initial production in 14-16-62-21W5 well.
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a revised method for organic porosity estimation in shale reservoirs using rock eval data example from duvernay formation in the western canada Sedimentary Basin
AAPG Bulletin, 2016Co-Authors: Zhuoheng Chen, Chunqing JiangAbstract:Studies suggest that nanometer-scale pores exist in organic matter as a result of thermal decomposition of kerogen. Depending on the host rock lithology, organic pores could be the primary storage for hydrocarbon accumulation in unconventional petroleum plays. Although various methods are publicly available, estimation of organic porosity remains a challenge because the procedures involve certain simplification or some implicit assumptions on the calculation of initial total organic carbon (TOC). In this study, we propose a revised method to address some of these issues. A model of estimating hydrocarbon expulsion efficiency is developed and incorporated into the calculation of initial TOC, thus producing an estimate of organic porosity with an improved mass balance. The method has been tested and compared with estimates using other methods based on a Rock-Eval data set in the literature. An application of the method to a large data set from the Upper Devonian Duvernay Formation petroleum system in the Western Canada Sedimentary Basin reveals that the modification has a significant effect on the estimated organic porosity. This study also indicates that organic porosity in the Duvernay Formation ranges greatly from none in immature intervals to >6% in highly mature and organic-rich shale intervals. Scanning electron microscope images of immature and mature organic-rich shale samples of the Duvernay Formation show a progressive increase in organic porosity with increasing thermal maturity, supporting the proposed model calculation. The presence of a large volume of organic porosity in mature shale intervals suggests a significant amount of hydrocarbon may be stored in the organic nanopores in the Duvernay Formation.
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revised models for determining toc in shale play example from devonian duvernay shale western canada Sedimentary Basin
Marine and Petroleum Geology, 2016Co-Authors: Zhuoheng Chen, Pengwei Wang, Xiongqi Pang, Kezhen Hu, Xiao ChenAbstract:Abstract Determination of total organic carbon (TOC) is essential in unconventional shale resource play evaluation. Indirect method, such as petrophysical approach, can provide a fast, convenient and cost efffective means for TOC estimation from well logs. Among the publically available approaches, the ΔlogR method is a popular one in conventional source rock evaluation and has been applied to unconventional resource play evaluation by many practitioners. Careful examination of the method finds that improvements can be made for a better TOC estimation with relaxed limitations. This study proposes the following revisions on the original ΔlogR method: 1) allowing estimation of petrophysical parameters from the targeted source rock rather an assumed linear approximation, 2) using additional logs to improve TOC prediction, and 3) replacing LOM (level of organic metamorphism unit) with a more commonly used thermal indicator Tmax for convenience. Depending on data or preference, the choice of using different porosity logs (density versus sonic) and parameter estimation methods (cross-plot method versus data-driven approaches) makes the revised method flexible for application. We present the revisions along with application examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin to demonstrate the application of the improved ΔlogR method in shale gas evaluation. Comparison of the results from the revised method and the original one reveals that the revised models provide better and unbiased estimates of TOC with a higher correlation coefficient and bell-shaped residues centered at zero.
Marc R Bustin - One of the best experts on this subject based on the ideXlab platform.
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variation of gas flow properties in coal with probe gas composition and fabric examples from western canadian Sedimentary Basin
International Journal of Coal Geology, 2013Co-Authors: Oyeleye O Adeboye, Marc R BustinAbstract:Abstract Flow properties (permeability and diffusivity) of subbituminous to high volatile bituminous coals from the Horseshoe Canyon and Mannville formations of the Western Canada Sedimentary Basin have been investigated using both solid coal plugs and samples crushed to between 0.8 mm and 0.6 mm (20–30 mesh). The coals examined have contents of vitrinite between 65%–98%, inertinite up to 31% and rare liptinite macerals. Permeability of crushed coal ranges from 1.46 ∙ 10 −5 md to 7.60 ∙ 10 −3 md whereas coal plug permeability is between 0.38 md to 0.01 md. Average diffusivity of crushed coal is estimated to be on the order of 10 −11 m 2 /s. This difference of up to four orders of magnitude between crushed and coal plug permeability is attributed to different stress conditions during sample testing and the influence of coal cleat and coal fractures on coal plug permeability. The permeability of crushed coal is influenced by coal matrix properties including maceral content and micro fabric. The coals with greatest amount of inertinite have the greatest matrix permeability and diffusivity due to the greater macro- and meso- porosity of inertinite. Increasing effective stress, with all other factors kept constant, leads to a decrease in coal plug permeability. Coal plug permeability declines exponentially with increasing effective stress which is attributed to the closure of permeability pathways due to compaction of coal at high effective stress levels. Probe gas type influences plug permeability. Helium permeability measurements are higher than permeability measured with methane or nitrogen. Permeability difference with probe gas is attributed to a combination of different probe gas molecule size, relative swelling effects of probe gas on coal and associated changes at in-situ stress during tests.
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investigating the use of Sedimentary geochemical proxies for paleoenvironment interpretation of thermally mature organic rich strata examples from the devonian mississippian shales western canadian Sedimentary Basin
Chemical Geology, 2009Co-Authors: Daniel J K Ross, Marc R BustinAbstract:Abstract Shales and mudrocks are enriched with diverse suites of major elements and trace metals that reflect their depositional environment, provenance and diagenesis. Here we present geochemical data for Devonian–Mississippian shaly strata (Western Canadian Sedimentary Basin) to assess the use of geochemical proxies for thermally mature deposits (> 1.5% vitrinite reflectance; VRo), and the ability to apply such proxies to elucidate the paleoceanographic conditions responsible for element distributions. Specifically, excess silica contents, C–S–Fe relationships, Ni/Co, V/Cr, Mo/Al and Re/Mo are utilized. Although regional in scope, the data presented here has broader implications for utilizing trace element geochemistry from geologic periods (Devonian–Mississippian) in which significant organic-rich sediment accumulation occurred, and subsequently underwent high levels of thermal diagenesis. Comparison of thermally mature lower Besa River, Golata, Muskwa and Fort Simpson shales (> 2% VRo for lower Besa River, and between 1.5% and 2% VRo for Golata, Muskwa and Fort Simpson), show that: 1) thermal maturation has had no effect upon the distribution of redox-sensitive elements (e.g., Ni, V, Mo, Tl, Cd and U); and 2) these elements are delivered to the sediment in association with the organic matter under anoxic (possibly euxinic) water-column conditions. Major element geochemistry (and optical microscopy) indicates organic-rich lower Besa River and Muskwa sediments are enriched in biogenic silica (proxied by excess SiO 2 concentrations), hence the use of Si as a proxy of detrital quartz input must be used with caution. Excess Si concentrations could be used as paleoproductivity proxies in reducing sediments where elements such as P and Ba are mobilized and not retained in the sediments. Golata sediments also have high excess Si contents, but the enrichment of Ti, Nb, Th, Ce, Hf and La (detrital-proxying elements) relative to average shale implies a detrital source of the quartz. Organic-rich, sulfur-rich upper Besa River shales were deposited in anoxic conditions (based upon C–S–Fe and Re/Mo relationships), akin to lower Besa River and Muskwa shales. However, upper Besa River shales show no enrichment of redox-proxying elements Mo, U and V, indicating benthic anoxia was not a ubiquitous requirement for element sequestration. Thermal maturation levels are similar to that of lower Besa River shales; hence element loss through diagenesis is not implied. A possible explanation is differing sedimentation rates which can affect the diffusion and concentration of elements into the sediment, and subsequent authigenic enrichment. This behavior makes Mo, U and V of limited use as paleoredox proxies under these Sedimentary conditions.
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characterizing the shale gas resource potential of devonian mississippian strata in the western canada Sedimentary Basin application of an integrated formation evaluation
AAPG Bulletin, 2008Co-Authors: Daniel J K Ross, Marc R BustinAbstract:Devonian–Mississippian strata in the northwestern region of the Western Canada Sedimentary Basin (WCSB) were investigated for shale gas potential. In the subsurface, thermally mature strata of the Besa River, Horn River, Muskwa, and Fort Simpson formations attain thicknesses of more than 1 km (0.6 mi), encompassing an area of approximately 125,000 km2 (48,300 mi2) and represent an enormous potential gas resource. Total gas capacity estimates range between 60 and 600 bcf/section. Of particular exploration interest are shales and mudrocks of the Horn River Formation (including the laterally equivalent lower Besa River mudrocks), Muskwa Formation, and upper Besa River Formation, which yield total organic carbon (TOC) contents of up to 5.7 wt.%. Fort Simpson shales seldom have TOC contents above 1 wt.%. Horn River and Muskwa formations have excellent shale gas potential in a region between longitudes 122W and 123W and latitudes 59N and 60N (National Topographic System [NTS] 94O08 to 94O15). In this area, which covers an areal extent of 6250 km2 (2404 mi2), average TOC contents are higher (3 wt.% as determined by wire-line-log calibrations), and have a stratal thickness of more than 200 m (656 ft). Gas capacities are estimated to be between 100 and 240 bcf/section and possibly greater than 400 tcf gas in place. A substantial percentage of the gas capacity is free gas caused by high reservoir temperatures and pressures. Muskwa shales have adsorbed gas capacities ranging between 0.3 and 0.5 cm3/g (9.6–16 scf/t) at reservoir temperatures of 60–80C (140–176F), whereas Besa River mudrocks and shales have low adsorbed gas capacities of less than 0.01 cm3/g (0.32 scf/t; Liard Basin region) because reservoir temperatures exceed 130C (266F). Potential free gas capacities range from 1.2 to 9.5 cm3/g (38.4 to 304 scf/t) when total pore volumes (0.4–6.9%) are saturated with gas. The mineralogy has a major influence on total gas capacity. Carbonate-rich samples, indicative of adjacent carbonate platform and embayment successions, commonly have lower organic carbon content and porosity and corresponding lower gas capacity (1% TOC and 1% porosity). Seaward of the carbonate Slave Point edge, Muskwa and lower Besa River mudrocks can be both silica and TOC rich (up to 92% quartz and 5 wt.% TOC) and most favorable for shale gas reservoir exploration because of possible fracture enhancement of the brittle organic- and siliceous-rich facies. However, an inverse relation between silica and porosity in some regions implies that zones with the best propensity for fracture completion may not provide optimal gas capacity, and a balance between favorable reservoir characteristics needs to be sought.
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late devonian and early mississippian bakken and exshaw black shale source rocks western canada Sedimentary Basin a sequence stratigraphic interpretation
AAPG Bulletin, 2000Co-Authors: Mark G Smith, Marc R BustinAbstract:The Late Devonian and Early Mississippian Bakken and Exshaw formations are a continuum of regionally correlated, organic-rich (up to 35% total organic carbon), black shale source rocks covering much of the Western Canada Sedimentary Basin. The Bakken Formation is composed of (1) a black mudstone lower member, (2) a gray mudstone/sandstone middle member, and (3) a black mudstone upper member. The Exshaw Formation, beneath the Alberta Plains and in exposures in the Foothills and Front Ranges of the Rocky Mountains, is composed of (1) a lower black shale member and (2) an upper siltstone member. The basal black shale unit of the Lower Mississippian Banff Formation, overlying the Exshaw Formation, is a second organic-rich interval. These black shales are regionally significant hydrocarbon source rocks and local reservoirs. The middle Bakken member is a locally important reservoir rock with substantial economic potential. The Bakken and Exshaw formations and the basal Banff black shale are divisible into three systems tracts: (1) a transgressive systems tract, (2) a lowstand systems tract, and (3) a second transgressive systems tract. Lodgepole and Banff formation carbonates, overlying the Bakken and Exshaw formations, are part of a highstand systems tract. A sequence boundary occurs between the lower and middle Bakken members. The conformable equivalent of this sequence boundary is within the Exshaw black shale member. Variations in the internal composition of these systems tracts imply that two depocenters, (1) the Williston Basin and (2) the Prophet trough and the western margin of the North American craton, were affected differently by relative sea level rise and fall during Bakken and Exshaw deposition because of differences in water depth and sediment accommodation. Spatial and temporal changes in black shale and gray mudstone/sandstone, as highlighted by this sequence stratigraphic interpretation, may have significant impacts on source rock potential and hydrocarbon reservoir size, location, and quality.
Tian Dong - One of the best experts on this subject based on the ideXlab platform.
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the effect of thermal maturity on geomechanical properties in shale reservoirs an example from the upper devonian duvernay formation western canada Sedimentary Basin
Marine and Petroleum Geology, 2018Co-Authors: Tian Dong, Nicholas B Harris, Levi J Knapp, Julia M Mcmillan, David L BishAbstract:Abstract Shale reservoirs are characterized by low matrix permeability and therefore require effective models of geomechanical properties to optimize drilling and hydraulic fracturing strategies. Both initial rock composition and thermal maturity are potentially critical controls on geomechanical properties. We investigate the Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin, a major shale gas target that spans a wide range in rock compositions and thermal maturity to identify relationships between these parameters and geomechanical properties. Core hardness measurements and dipole sonic and density log data were used to characterize the geomechanical properties. Major element chemical analysis, X-ray diffraction analysis and LECO combustion were used to determine mineralogy, bulk rock chemistry and total organic carbon (TOC) content and to distinguish biogenic from detrital silica. Scanning electron microscopy (SEM) images with complementary energy-dispersive spectroscopy (EDS) maps were obtained for representative samples to document the rock fabric and distribution of organic matter and minerals. Hardness and Al2O3 concentrations are strongly negatively correlated in all cores, regardless of thermal maturity, suggesting that clay minerals are the most significant factor controlling geomechanical properties. Biogenic silica is positively correlated to hardness. Detrital silica is negatively correlated to hardness, an artifact of the positive correlation between detrital clay minerals and detrital quartz. The positive correlations between CaO content and hardness in all cores suggest the brittle behavior of carbonate minerals. Increased thermal maturity from immature to oil window results in greater hardness for rocks of similar geochemical compositions. We propose that this results from: (1) enhanced mechanical compaction; (2) carbonate cementation; (3) increased stiffness of kerogen; and (4) partial conversion of kerogen into expelled hydrocarbons that reduces the load-bearing function of the organic matter. At maturities greater than oil window, thermal maturity does not exert a major control on the rock strength; thus, there are no significant changes in hardness between samples from oil window and dry gas window. Geomechanical properties can be related to mineralogy, which exerts a major impact on the geomechanical properties. Quartz cements sourced from biogenic silica rather than smectite-to-illite transition are the primary contributor to the rock strength in the Duvernay Formation. However, it is noteworthy that thermal maturity should also be considered as an important factor when predicting geomechanical properties from mineralogy.
