Pub Date : 2015-12-01DOI: 10.2113/GSCPGBULL.63.4.304
P. Abrahamsen, P. Dahle, V. Hauge, Ariel Almendral-Vazquez, Maria Vigsnes
Abstract We demonstrate accurate prediction of geological surfaces by imposing consistent physical and stochastic relationships between surfaces. The accuracy is improved by using all relevant information collected in wells: well points, zonation in horizontal sections, and gas/fluid content along wells. The conditioned surfaces are used to provide estimates of gross rock volumes of oil and gas reservoirs. In particular, it is shown how knowledge of spill point and zonation along well paths affect trapped volumes. A plain rejection sampling technique is used to deal with the highly non-linear relationships between a surface and its spill point. For well path conditioning, an extension of kriging to treat inequality constraints is proposed. It is based on efficient rejection sampling from a high dimensional truncated multivariate Gaussian distribution. The impact on gross rock volume distributions from different assumptions and data types is demonstrated by examples and the uncertainties in all the involved data types are consistently handled and quantified.
{"title":"Surface Prediction using Rejection Sampling to Handle Non-linear Constraints","authors":"P. Abrahamsen, P. Dahle, V. Hauge, Ariel Almendral-Vazquez, Maria Vigsnes","doi":"10.2113/GSCPGBULL.63.4.304","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.4.304","url":null,"abstract":"Abstract We demonstrate accurate prediction of geological surfaces by imposing consistent physical and stochastic relationships between surfaces. The accuracy is improved by using all relevant information collected in wells: well points, zonation in horizontal sections, and gas/fluid content along wells. The conditioned surfaces are used to provide estimates of gross rock volumes of oil and gas reservoirs. In particular, it is shown how knowledge of spill point and zonation along well paths affect trapped volumes. A plain rejection sampling technique is used to deal with the highly non-linear relationships between a surface and its spill point. For well path conditioning, an extension of kriging to treat inequality constraints is proposed. It is based on efficient rejection sampling from a high dimensional truncated multivariate Gaussian distribution. The impact on gross rock volume distributions from different assumptions and data types is demonstrated by examples and the uncertainties in all the involved data types are consistently handled and quantified.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.4.304","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207913","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-12-01DOI: 10.2113/GSCPGBULL.63.4.318
O. Babak
Abstract Predicting bitumen recovery from the McMurray Formation oil sands is required to optimize resource management and development planning. While there are many parameters that affect the recovery predictions, bitumen grade and fines in the oil sands mining, and permeability in the in situ projects, are the most important geological parameters. In this paper, we discuss how particle size distribution data can aid in the estimation of these and some other parameters and what value it brings in improving our understanding of oil sands quality and recovery. We conclude with a short review of the methods currently available for particle size distribution modeling, while paying special attention to a practical particle size distribution modeling approach based on look-up tables. The proposal is illustrated using Telephone Lake data.
{"title":"A Discussion of the Importance of Particle Size Distribution Data for Characterizing Athabasca Oil Sands","authors":"O. Babak","doi":"10.2113/GSCPGBULL.63.4.318","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.4.318","url":null,"abstract":"Abstract Predicting bitumen recovery from the McMurray Formation oil sands is required to optimize resource management and development planning. While there are many parameters that affect the recovery predictions, bitumen grade and fines in the oil sands mining, and permeability in the in situ projects, are the most important geological parameters. In this paper, we discuss how particle size distribution data can aid in the estimation of these and some other parameters and what value it brings in improving our understanding of oil sands quality and recovery. We conclude with a short review of the methods currently available for particle size distribution modeling, while paying special attention to a practical particle size distribution modeling approach based on look-up tables. The proposal is illustrated using Telephone Lake data.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.4.318","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207977","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-12-01DOI: 10.2113/GSCPGBULL.63.4.345
Samane Sadeghi, J. Boisvert
Abstract Stochastic simulation of facies is a continuing and important area of research. To increase model performance and reproduce realistic relationships between categories (facies), an understanding of the geometries and internal architecture of the domain is required. Modelling of spatial categorical data with truncated bi-Gaussian simulation and generating the required mask that reproduces the desired category’s spatial relationships is an important, initial step in categorical variable modelling. Truncated bi-Gaussian simulation is typically used when there are known, complex spatial relationships between the categories. Truncation rules based on thresholds applied to the Gaussian realizations (i.e. the mask) control the proportions and ordering of categories in the simulation. The choice of these thresholds has a large effect on the final models. This work describes a program that is developed for truncated Gaussian simulation where the truncation rules are linear, but are locally varying to account for locally varying proportions. The appropriate truncation rules are calculated based on the user supplied locally varying proportion maps. Moreover, an optimization framework to determine the input variograms used to generate the initial Gaussian realizations is presented. Initially, the optimization is brute force with the best set of variograms carried forward; the second local refinement step is important in obtaining reasonable bi-Gaussian models. A case study simulating rock types at a mineral deposit is presented to illustrate the implementation of the proposed methodology.
{"title":"Optimization of Variograms used for Truncated Plurigaussian Simulation","authors":"Samane Sadeghi, J. Boisvert","doi":"10.2113/GSCPGBULL.63.4.345","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.4.345","url":null,"abstract":"Abstract Stochastic simulation of facies is a continuing and important area of research. To increase model performance and reproduce realistic relationships between categories (facies), an understanding of the geometries and internal architecture of the domain is required. Modelling of spatial categorical data with truncated bi-Gaussian simulation and generating the required mask that reproduces the desired category’s spatial relationships is an important, initial step in categorical variable modelling. Truncated bi-Gaussian simulation is typically used when there are known, complex spatial relationships between the categories. Truncation rules based on thresholds applied to the Gaussian realizations (i.e. the mask) control the proportions and ordering of categories in the simulation. The choice of these thresholds has a large effect on the final models. This work describes a program that is developed for truncated Gaussian simulation where the truncation rules are linear, but are locally varying to account for locally varying proportions. The appropriate truncation rules are calculated based on the user supplied locally varying proportion maps. Moreover, an optimization framework to determine the input variograms used to generate the initial Gaussian realizations is presented. Initially, the optimization is brute force with the best set of variograms carried forward; the second local refinement step is important in obtaining reasonable bi-Gaussian models. A case study simulating rock types at a mineral deposit is presented to illustrate the implementation of the proposed methodology.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.4.345","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208118","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-09-01DOI: 10.2113/GSCPGBULL.63.3.243
M. McMechan
Abstract The Neoproterozoic succession exposed in the central Canadian Rocky Mountains comprises a thick (2 to 5 km) sequence of marine clastic rocks deposited after major subsidence associated with continental scale rifting. A major transverse south to north change in lithofacies separates the succession into southern more distal and northern more proximal sequences. The southern sequence (Miette Group) comprises the sandstone-conglomerate dominated McKale Formation (new) overlain by the argillite and siltstone dominated East Twin Formation (new). Locally, black pyritic slate and limestone of the Cushing Creek Formation (new) occurs at the base. The Cushing Creek Formation was deposited in a deep euxinic basin with only minor sandstone turbidite deposition. The lower part of the McKale Formation was deposited in basin-floor turbidite complexes, whereas the upper part, with its thick interlayered argillite intervals and uncommon slump structures, was deposited in lower slope environments. A thick varicoloured argillite unit separates the lower and upper McKale Formation in northeastern exposures. This unit, mappable into the lower part of the Framstead Formation and correlative with the Old Fort Point Formation, records an abrupt reduction in the supply of clastic material associated with the termination of glaciation. The East Twin Formation represents a transition from slope sedimentation at the base to shallow-marine sedimentation at the top. It records the reduction of the supply of coarse clastic material into the basin and the filling of the Neoproterozoic basin. The northern sequence (Misinchinka Group) comprises in succession: diamictite of the Vreeland Formation (new); argillite with local carbonate olistoliths, medial sandstone to conglomerate and, in the east, basal interbedded sandstone and argillite of the Framstead Formation (new); carbonate of the Chowika Formation; and argillite and siltstone of the Cut Thumb Formation (new). Locally interbedded siltstone, argillite and sandstone of the Paksumo Formation (new) occur at the base of the exposed succession. The Paksumo, Vreeland Formation and basal part of the Framstead Formation record glacially influenced slope sedimentation. The Paksumo Formation and basal part of the Framstead Formation are primarily turbidite deposits, whereas diamictites of the Vreeland Formation are primarily resedimented mass flow and glaciogenic ‘rain-out’ deposits. The lower part of the Framstead Formation records an abrupt reduction in the supply of clastic material associated with a post-glacial eustatic sea level rise. Large olistoliths of shallow-water carbonate in both the lower and upper parts of the Framstead Formation indicate deposition in a slope environment and instability of the adjacent carbonate platform. Sandstone to conglomerate turbidite-filled channels in the middle part of the Framstead Formation record a relative sea level drop and a temporary breakdown of the adjacent carbonate platform
{"title":"The Neoproterozoic succession of the central Rocky Mountains, Canada","authors":"M. McMechan","doi":"10.2113/GSCPGBULL.63.3.243","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.3.243","url":null,"abstract":"Abstract The Neoproterozoic succession exposed in the central Canadian Rocky Mountains comprises a thick (2 to 5 km) sequence of marine clastic rocks deposited after major subsidence associated with continental scale rifting. A major transverse south to north change in lithofacies separates the succession into southern more distal and northern more proximal sequences. The southern sequence (Miette Group) comprises the sandstone-conglomerate dominated McKale Formation (new) overlain by the argillite and siltstone dominated East Twin Formation (new). Locally, black pyritic slate and limestone of the Cushing Creek Formation (new) occurs at the base. The Cushing Creek Formation was deposited in a deep euxinic basin with only minor sandstone turbidite deposition. The lower part of the McKale Formation was deposited in basin-floor turbidite complexes, whereas the upper part, with its thick interlayered argillite intervals and uncommon slump structures, was deposited in lower slope environments. A thick varicoloured argillite unit separates the lower and upper McKale Formation in northeastern exposures. This unit, mappable into the lower part of the Framstead Formation and correlative with the Old Fort Point Formation, records an abrupt reduction in the supply of clastic material associated with the termination of glaciation. The East Twin Formation represents a transition from slope sedimentation at the base to shallow-marine sedimentation at the top. It records the reduction of the supply of coarse clastic material into the basin and the filling of the Neoproterozoic basin. The northern sequence (Misinchinka Group) comprises in succession: diamictite of the Vreeland Formation (new); argillite with local carbonate olistoliths, medial sandstone to conglomerate and, in the east, basal interbedded sandstone and argillite of the Framstead Formation (new); carbonate of the Chowika Formation; and argillite and siltstone of the Cut Thumb Formation (new). Locally interbedded siltstone, argillite and sandstone of the Paksumo Formation (new) occur at the base of the exposed succession. The Paksumo, Vreeland Formation and basal part of the Framstead Formation record glacially influenced slope sedimentation. The Paksumo Formation and basal part of the Framstead Formation are primarily turbidite deposits, whereas diamictites of the Vreeland Formation are primarily resedimented mass flow and glaciogenic ‘rain-out’ deposits. The lower part of the Framstead Formation records an abrupt reduction in the supply of clastic material associated with a post-glacial eustatic sea level rise. Large olistoliths of shallow-water carbonate in both the lower and upper parts of the Framstead Formation indicate deposition in a slope environment and instability of the adjacent carbonate platform. Sandstone to conglomerate turbidite-filled channels in the middle part of the Framstead Formation record a relative sea level drop and a temporary breakdown of the adjacent carbonate platform","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.3.243","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207730","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-09-01DOI: 10.2113/GSCPGBULL.63.3.225
H. Brekke
Abstract For the first time, a subaereal scroll bar setting is described for the McMurray Formation. It is made up of ridge and swale features capping point bar deposits. Occurring in the same narrow stratigraphic zone, scroll bars appear as either a vertical section of low-angle dips corresponding to ridges, or flat-lying bedding deposited in swales. These features were deposited from suspension during flooding events; the orientation of one set of ridges parallels point bar development, while the ridges overlying a second point bar are oriented obliquely. The orientation of the oblique ridges was locally controlled by superelevation of the river. Newly interpreted vertical loading structures up to 60 cm deep and 50 cm across are interpreted to be dinosaur footprints. These footprints are limited to a narrow stratigraphic zone above the point bars in the associated ridge and swale setting of the scroll bar. These are the first dinosaur footprints discovered in the McMurray Formation and the first to be interpreted from image logs. Although these footprints were identified in image logs, the image log features now permit the identification of footprints in core. The scroll bars and dinosaur footprints each provide direct evidence for a floodplain environment in the McMurray Formation, but combined provide compelling documentation of a subaereal setting and the complete point bar –scroll bar cycle. This new interpretation expands the depositional framework for future mapping in the McMurray Formation.
{"title":"Cretaceous forensic podiatry: big game tracking with a microresistivity image log on a McMurray Formation scroll bar","authors":"H. Brekke","doi":"10.2113/GSCPGBULL.63.3.225","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.3.225","url":null,"abstract":"Abstract For the first time, a subaereal scroll bar setting is described for the McMurray Formation. It is made up of ridge and swale features capping point bar deposits. Occurring in the same narrow stratigraphic zone, scroll bars appear as either a vertical section of low-angle dips corresponding to ridges, or flat-lying bedding deposited in swales. These features were deposited from suspension during flooding events; the orientation of one set of ridges parallels point bar development, while the ridges overlying a second point bar are oriented obliquely. The orientation of the oblique ridges was locally controlled by superelevation of the river. Newly interpreted vertical loading structures up to 60 cm deep and 50 cm across are interpreted to be dinosaur footprints. These footprints are limited to a narrow stratigraphic zone above the point bars in the associated ridge and swale setting of the scroll bar. These are the first dinosaur footprints discovered in the McMurray Formation and the first to be interpreted from image logs. Although these footprints were identified in image logs, the image log features now permit the identification of footprints in core. The scroll bars and dinosaur footprints each provide direct evidence for a floodplain environment in the McMurray Formation, but combined provide compelling documentation of a subaereal setting and the complete point bar –scroll bar cycle. This new interpretation expands the depositional framework for future mapping in the McMurray Formation.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.3.225","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207621","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-06-01DOI: 10.2113/GSCPGBULL.63.2.171
L. Hou, Chun Yang, Fan Yang, Xiaojun Lou, Yan Wei
Abstract Previous studies on volcanic rock reservoirs were focused on lithology, lithofacies and fractures. Primary processes may lead to high porosity and permeability, and secondary processes tend to decrease primary porosity. However, this is not the case in northern Xinjiang, where Carboniferous volcanic rocks covered an area of 378×103 km2 dominated by intermediate-basic rocks of low porosity. At the end of the Carboniferous, these rocks were uplifted, underwent denudation and weathering, and then formed a weathered crust. All types of volcanic rocks might form favorable reservoirs after long-term weathering. The reservoir properties of the crust were controlled by weathering degree and fault development. Four types of reservoir porosity developed: dissolutional pore, pore-fracture, fracture and fracture-cave. Dissolutional pores and fractures are the main reservoir spaces. Under the influence of fractures and an enhanced fracture dissolution environment, the volcanic reservoirs have improved physical properties in deeper burial settings. The depth range of effective reservoirs under the unconformity, either close to, or far from fracture zones, is between 1100 m and 550 m, with maximum porosities of 32% and 24%, respectively. Hydrocarbons have accumulated close to the effective source rock zone due to strong heterogeneities of the volcanic reservoir. The overlying Carboniferous mudstone formed effective caprock. The current structural highs and slope zone coincided well with the paleogeomorphology and form traps for hydrocarbons. Faults and fractures control hydrocarbon enrichment. This is contrary to the view that the Carboniferous is simply impermeable basement in this region, and not capable of hydrocarbon generation.
{"title":"Petroleum geology of Carboniferous volcanic weathered crust in northern Xinjiang, China","authors":"L. Hou, Chun Yang, Fan Yang, Xiaojun Lou, Yan Wei","doi":"10.2113/GSCPGBULL.63.2.171","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.2.171","url":null,"abstract":"Abstract Previous studies on volcanic rock reservoirs were focused on lithology, lithofacies and fractures. Primary processes may lead to high porosity and permeability, and secondary processes tend to decrease primary porosity. However, this is not the case in northern Xinjiang, where Carboniferous volcanic rocks covered an area of 378×103 km2 dominated by intermediate-basic rocks of low porosity. At the end of the Carboniferous, these rocks were uplifted, underwent denudation and weathering, and then formed a weathered crust. All types of volcanic rocks might form favorable reservoirs after long-term weathering. The reservoir properties of the crust were controlled by weathering degree and fault development. Four types of reservoir porosity developed: dissolutional pore, pore-fracture, fracture and fracture-cave. Dissolutional pores and fractures are the main reservoir spaces. Under the influence of fractures and an enhanced fracture dissolution environment, the volcanic reservoirs have improved physical properties in deeper burial settings. The depth range of effective reservoirs under the unconformity, either close to, or far from fracture zones, is between 1100 m and 550 m, with maximum porosities of 32% and 24%, respectively. Hydrocarbons have accumulated close to the effective source rock zone due to strong heterogeneities of the volcanic reservoir. The overlying Carboniferous mudstone formed effective caprock. The current structural highs and slope zone coincided well with the paleogeomorphology and form traps for hydrocarbons. Faults and fractures control hydrocarbon enrichment. This is contrary to the view that the Carboniferous is simply impermeable basement in this region, and not capable of hydrocarbon generation.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.2.171","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207375","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-06-01DOI: 10.2113/GSCPGBULL.63.2.143
M. Golding, M. Orchard, J. Zonneveld, N. Wilson
Abstract Conodont biostratigraphy of the upper Montney and Doig formations in the subsurface of northeastern British Columbia provides the first age constraints on the boundary between these two formations. Previously presumed to be broadly but uniformly equivalent to the Spathian-Anisian boundary, it is shown herein to be highly diachronous, ranging from Spathian to Middle Anisian in age. It is oldest in the Altares area (at 56.201389 N; 121.906667 W) and youngest in the Dawson area (at 55.846389 N; 120.203333 W). The fact that the Montney-Doig boundary is oldest in the centre of the study area and younger in all directions suggests that the basal Doig Formation does not represent simple west-east transgression as previously thought. Rather, the Doig Formation was apparently deposited in the Altares region first and transgression must have proceeded away from this point. The lowest part of the Doig Formation, the Doig Phosphate Zone, has long been recognised as a condensed horizon. However, it is not condensed equally throughout northeastern British Columbia. It is most condensed in the Swan and eastern Groundbirch areas, and most expanded in the Altares and western Groundbirch areas. Together, these observations support the presence of palaeo-highs within and to the west of the Western Canada Sedimentary Basin during the Middle Triassic, a hypothesis that has been proposed previously on the basis of sedimentary thickness variation and provenance studies.
{"title":"Determining the age and depositional model of the Doig Phosphate Zone in northeastern British Columbia using conodont biostratigraphy","authors":"M. Golding, M. Orchard, J. Zonneveld, N. Wilson","doi":"10.2113/GSCPGBULL.63.2.143","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.2.143","url":null,"abstract":"Abstract Conodont biostratigraphy of the upper Montney and Doig formations in the subsurface of northeastern British Columbia provides the first age constraints on the boundary between these two formations. Previously presumed to be broadly but uniformly equivalent to the Spathian-Anisian boundary, it is shown herein to be highly diachronous, ranging from Spathian to Middle Anisian in age. It is oldest in the Altares area (at 56.201389 N; 121.906667 W) and youngest in the Dawson area (at 55.846389 N; 120.203333 W). The fact that the Montney-Doig boundary is oldest in the centre of the study area and younger in all directions suggests that the basal Doig Formation does not represent simple west-east transgression as previously thought. Rather, the Doig Formation was apparently deposited in the Altares region first and transgression must have proceeded away from this point. The lowest part of the Doig Formation, the Doig Phosphate Zone, has long been recognised as a condensed horizon. However, it is not condensed equally throughout northeastern British Columbia. It is most condensed in the Swan and eastern Groundbirch areas, and most expanded in the Altares and western Groundbirch areas. Together, these observations support the presence of palaeo-highs within and to the west of the Western Canada Sedimentary Basin during the Middle Triassic, a hypothesis that has been proposed previously on the basis of sedimentary thickness variation and provenance studies.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.2.143","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207305","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-06-01DOI: 10.2113/GSCPGBULL.63.2.192
Jacqueline Colborne, G. Reinson, R. Bustin
Abstract Within the past decade, the Big Valley and Exshaw formations in southern Alberta have received significant interest as a potential unconventional oil play because of the overwhelming exploration/exploitation success in the stratigraphically-equivalent Three Forks and Bakken formations in Saskatchewan, Manitoba and North Dakota. Because of continuous industry hype, this upper Devonian-lower Mississippian succession came to be known as the “Alberta Bakken”. Such a term suggests potentially prolific oil production from a reservoir similar to the Bakken in Saskatchewan. In fact the term “Alberta Bakken” is misleading since to date there has been only moderate oil production from localized carbonate reservoirs in the Big Valley Formation, and from very fine-grained sandstones and siltstones of the Mississippian Lower Banff Formation. Reservoir development in the Big Valley Formation is stratigraphically and areally restricted by both depositional facies controls and post-depositional early diagenetic, subaerial and structural-collapse processes. Detailed lithofacies analysis indicates that the Big Valley Formation is divisible into two units: an upper shallow marine limestone and a lower hydrocarbon-bearing, partially dolomitized, peritidal carbonate. The peritidal unit, in turn, is divisible into four lithofacies: peloidal packstone-grainstone (the primary oil-bearing lithofacies), microbial laminite, laminated dolomudstone and intraclastic breccia-laminite. Regionally, each lithofacies is discontinuous and in the order of 0.5 to 2.0 m thick. Locally, however, the peloidal packstone-grainstone attains thicknesses of up to 8 m, forming isolated oil-producing reservoirs. These over-thickened zones correspond to specific areas of Big Valley Formation ‘thicks’, which tend to align with a NNW-SSE trending ‘basement’ lineament that underlies the study area. It is equivocal whether this structural trend is basement-controlled, or reflects dissolution of salt beds along the margin of an underlying evaporite basin. Successful exploration in the Big Valley Formation appears to depend on whether the over-thickened areas can be located.
{"title":"Stratigraphic Framework and Depositional Controls on Reservoir Occurrence, Big Valley Formation, Southern Alberta","authors":"Jacqueline Colborne, G. Reinson, R. Bustin","doi":"10.2113/GSCPGBULL.63.2.192","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.2.192","url":null,"abstract":"Abstract Within the past decade, the Big Valley and Exshaw formations in southern Alberta have received significant interest as a potential unconventional oil play because of the overwhelming exploration/exploitation success in the stratigraphically-equivalent Three Forks and Bakken formations in Saskatchewan, Manitoba and North Dakota. Because of continuous industry hype, this upper Devonian-lower Mississippian succession came to be known as the “Alberta Bakken”. Such a term suggests potentially prolific oil production from a reservoir similar to the Bakken in Saskatchewan. In fact the term “Alberta Bakken” is misleading since to date there has been only moderate oil production from localized carbonate reservoirs in the Big Valley Formation, and from very fine-grained sandstones and siltstones of the Mississippian Lower Banff Formation. Reservoir development in the Big Valley Formation is stratigraphically and areally restricted by both depositional facies controls and post-depositional early diagenetic, subaerial and structural-collapse processes. Detailed lithofacies analysis indicates that the Big Valley Formation is divisible into two units: an upper shallow marine limestone and a lower hydrocarbon-bearing, partially dolomitized, peritidal carbonate. The peritidal unit, in turn, is divisible into four lithofacies: peloidal packstone-grainstone (the primary oil-bearing lithofacies), microbial laminite, laminated dolomudstone and intraclastic breccia-laminite. Regionally, each lithofacies is discontinuous and in the order of 0.5 to 2.0 m thick. Locally, however, the peloidal packstone-grainstone attains thicknesses of up to 8 m, forming isolated oil-producing reservoirs. These over-thickened zones correspond to specific areas of Big Valley Formation ‘thicks’, which tend to align with a NNW-SSE trending ‘basement’ lineament that underlies the study area. It is equivocal whether this structural trend is basement-controlled, or reflects dissolution of salt beds along the margin of an underlying evaporite basin. Successful exploration in the Big Valley Formation appears to depend on whether the over-thickened areas can be located.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.2.192","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207532","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2015-03-01DOI: 10.2113/GSCPGBULL.63.1.5
Zhuoheng Chen, Y. Shuai, Norman Wang
Abstract Tens of thousands of production wells drilled during the past 100 years reveal that biogenic gas accumulations in the Upper Cretaceous succession in southeast Alberta and southwest Saskatchewan are a regionally pervasive gas field with mixed reservoirs and varying resource density across the region. Historical pool boundaries have disappeared gradually as a result of in-fill drilling. This suggests that previous resource assessments that used methods based on feature counting, such as the number of pools and individual pools sizes, may have significantly underestimated the resource potential of this field because the resource potential occurring between the pool boundaries were largely ignored and the areal extent of the field is still growing geographically. This study used available historical production data and employed a well performance-based method to re-assess the natural gas potential of this giant gas field. Three major production intervals, Medicine Hat, Milk River and Second White Speckled formations in Upper Cretaceous successions, were assessed. The geographical locations of 86 561 production wells with production from one of these three intervals were used to define the play boundaries. More than ten thousand production wells with historical records were collected and analyzed. All wells with comingled production from more than one zone were excluded to eliminate the impact from mixed contributions from multiple intervals. The remaining 2783 production wells with production from a single formation were used in the Estimated Ultimate Reserve (EUR) calculation for each of the three intervals. The estimated total technically recoverable natural gas resource in the three stratigraphic intervals vary from 30.2 to 73.3 TCF (P90 to P10) with a median of 43.6 and a mean of 50.1 TCF. The total inferred resources obtained for this study are much larger than those obtained previously for this field.
{"title":"A reassessment of gas resources in selected Upper Cretaceous biogenic gas accumulations in southeastern Alberta and southwestern Saskatchewan, Canada","authors":"Zhuoheng Chen, Y. Shuai, Norman Wang","doi":"10.2113/GSCPGBULL.63.1.5","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.1.5","url":null,"abstract":"Abstract Tens of thousands of production wells drilled during the past 100 years reveal that biogenic gas accumulations in the Upper Cretaceous succession in southeast Alberta and southwest Saskatchewan are a regionally pervasive gas field with mixed reservoirs and varying resource density across the region. Historical pool boundaries have disappeared gradually as a result of in-fill drilling. This suggests that previous resource assessments that used methods based on feature counting, such as the number of pools and individual pools sizes, may have significantly underestimated the resource potential of this field because the resource potential occurring between the pool boundaries were largely ignored and the areal extent of the field is still growing geographically. This study used available historical production data and employed a well performance-based method to re-assess the natural gas potential of this giant gas field. Three major production intervals, Medicine Hat, Milk River and Second White Speckled formations in Upper Cretaceous successions, were assessed. The geographical locations of 86 561 production wells with production from one of these three intervals were used to define the play boundaries. More than ten thousand production wells with historical records were collected and analyzed. All wells with comingled production from more than one zone were excluded to eliminate the impact from mixed contributions from multiple intervals. The remaining 2783 production wells with production from a single formation were used in the Estimated Ultimate Reserve (EUR) calculation for each of the three intervals. The estimated total technically recoverable natural gas resource in the three stratigraphic intervals vary from 30.2 to 73.3 TCF (P90 to P10) with a median of 43.6 and a mean of 50.1 TCF. The total inferred resources obtained for this study are much larger than those obtained previously for this field.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.1.5","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68206985","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Abstract Quantitative seismic interpretation can be used to identify lithology and detect petroleum accumulations by integrating rock properties and attributes derived from advanced seismic inversion methods with existing petrophysical data and geological knowledge. We use quantitative seismic interpretations for detection of shallow biogenic gas accumulations in the Qaidam Basin, China, employing an integrated workflow that incorporates petrophysical data, seismic attribute analysis, Constrained Simultaneous Inversion (C-SI) and Bayesian-based Support Vector Machine (B-SVM) inference. Previous petrophysical studies have shown that it is challenging to effectively identify gas-bearing intervals using parameters such as impedance, Poisson’s ratio and porosity, because the reservoir sediments are unconsolidated and at shallow depths. The resistivity well-log response remains as an effective tool for estimating gas saturation and identifying gas-bearing intervals. In this study, we propose the use of the petroleum pore-volume, which is defined as the product of reservoir porosity and gas saturation, to detect biogenic gas accumulations seismically. Rock properties inferred from seismic inversion, such as compressional velocity (Vp), shear velocity (Vs) and density, cannot be used directly for petroleum pore-volume estimation. Therefore, we employ a Bayesian-based support vector machine approach to cross-link well-log properties, seismic AVO attributes and seismic rock properties to quantitatively predict petroleum pore-volume in 2D and 3D seismic dataset. Because seismic information is crucial to statistical inference, we propose C-SI to infer the Vp, Vs and density from seismic elastic impedance gathers, which can be generated from seismic gathers using a traditional recursive seismic inversion method. The C-SI procedures use the Interior-Point algorithm to optimize and solve elastic impedance equations. The Interior-Point method is a popular method for handling constrained non-convex, non-linear optimization problems that involve simultaneously inverting the seismic properties with thousands of seismic samples. This case study indicates that the integrated study workflow is useful for quantitatively predicting petroleum pore-volume, especially in the depth-domain, and that it is an excellent potential indicator for biogenic gas accumulations in complicated geological settings.
{"title":"Quantitative seismic interpretations to detect biogenic gas accumulations: a case study from Qaidam Basin, China","authors":"Yexin Liu, Zhuoheng Chen, Liqun Wang, Yong-shu Zhang, Zhiqiang Liu, Y. Shuai","doi":"10.2113/GSCPGBULL.63.1.108","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.63.1.108","url":null,"abstract":"Abstract Quantitative seismic interpretation can be used to identify lithology and detect petroleum accumulations by integrating rock properties and attributes derived from advanced seismic inversion methods with existing petrophysical data and geological knowledge. We use quantitative seismic interpretations for detection of shallow biogenic gas accumulations in the Qaidam Basin, China, employing an integrated workflow that incorporates petrophysical data, seismic attribute analysis, Constrained Simultaneous Inversion (C-SI) and Bayesian-based Support Vector Machine (B-SVM) inference. Previous petrophysical studies have shown that it is challenging to effectively identify gas-bearing intervals using parameters such as impedance, Poisson’s ratio and porosity, because the reservoir sediments are unconsolidated and at shallow depths. The resistivity well-log response remains as an effective tool for estimating gas saturation and identifying gas-bearing intervals. In this study, we propose the use of the petroleum pore-volume, which is defined as the product of reservoir porosity and gas saturation, to detect biogenic gas accumulations seismically. Rock properties inferred from seismic inversion, such as compressional velocity (Vp), shear velocity (Vs) and density, cannot be used directly for petroleum pore-volume estimation. Therefore, we employ a Bayesian-based support vector machine approach to cross-link well-log properties, seismic AVO attributes and seismic rock properties to quantitatively predict petroleum pore-volume in 2D and 3D seismic dataset. Because seismic information is crucial to statistical inference, we propose C-SI to infer the Vp, Vs and density from seismic elastic impedance gathers, which can be generated from seismic gathers using a traditional recursive seismic inversion method. The C-SI procedures use the Interior-Point algorithm to optimize and solve elastic impedance equations. The Interior-Point method is a popular method for handling constrained non-convex, non-linear optimization problems that involve simultaneously inverting the seismic properties with thousands of seismic samples. This case study indicates that the integrated study workflow is useful for quantitatively predicting petroleum pore-volume, especially in the depth-domain, and that it is an excellent potential indicator for biogenic gas accumulations in complicated geological settings.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.63.1.108","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68207042","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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