Pub Date : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.266
Youwei Jiang, Qiu Li
Abstract Heavy oil, as an important oil supply in China, has been exploited with steam injection for almost forty years. The production of major heavy oil reservoirs now is challenged by low oil steam ratio, low productivity and high energy consumption. The geological character and formation fluid properties of two of China’s heavy oil fields, Liaohe Oil Field and Xinjiang Oil Field, are compared. Two major thermal recovery technologies, steam assisted gravity drainage and in-situ combustion, are found to be complementary and the outcomes are promising. With the assistance of experimental physical simulation and numerical simulation, the major mechanisms of, and differences between, these two techniques are highlighted. Pilot performance is also described.
{"title":"Heavy oil and bitumen resources and development of Liaohe and Xinjiang oil fields of China","authors":"Youwei Jiang, Qiu Li","doi":"10.2113/GSCPGBULL.64.2.266","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.266","url":null,"abstract":"Abstract Heavy oil, as an important oil supply in China, has been exploited with steam injection for almost forty years. The production of major heavy oil reservoirs now is challenged by low oil steam ratio, low productivity and high energy consumption. The geological character and formation fluid properties of two of China’s heavy oil fields, Liaohe Oil Field and Xinjiang Oil Field, are compared. Two major thermal recovery technologies, steam assisted gravity drainage and in-situ combustion, are found to be complementary and the outcomes are promising. With the assistance of experimental physical simulation and numerical simulation, the major mechanisms of, and differences between, these two techniques are highlighted. Pilot performance is also described.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.266","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208740","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 : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.324
P. Putnam, J. Russel-Houston, S. Christensen
Abstract Using the data from over 8000 wells augmented by seismic and thermal response information, a comparison of McMurray Formation (Cretaceous) and Grosmont C member (Devonian) thermal recovery reservoirs of northeastern Alberta is provided along with a discussion of reservoir performance to date. Fluvial-estuarine McMurray Formation reservoirs perform best where bitumen-charged homogeneous lenticular sandstones at least 20 metres thick are found. These deposits are relatively rare as the formation is characterized by endemic heterogeneity mainly in the form of inclined heterolithic stratification (IHS). Most of the best McMurray steam-assisted gravity drainage (SAGD) reservoirs appear to be currently on-line and produce approximately 113 000 m3/day of bitumen from fourteen projects. Platform carbonate Grosmont C successions are blanket deposits 32–35 metres thick, with bitumen columns typically 15–24 metres thick, and are characterized by consistent reservoir properties facilitated by pervasive multi-scale fracturing. Although no reserves have yet to be assigned to Alberta’s bitumen-bearing carbonates by the province, recent pilot results derived from cyclic steam stimulation (CSS) operations suggest that Grosmont C reservoir performance could ultimately prove to be competitive with superior McMurray SAGD reservoirs. Under current technological and economic conditions, McMurray SAGD reservoirs appear incapable of providing the 15.9 billion m3 of in-situ bitumen reserves (59% of Canada’s total oil reserves) ascribed to this formation by the province of Alberta as only circa 6 billion m3 of oil-in place appears to reside within optimal reservoirs (i.e. those reservoirs at least 20 metres thick with average porosity and oil saturation values of 33% and 80%, respectively). Barring future technological breakthroughs and, or, economic improvements, future commercial development of both the Grosmont C and other carbonate reservoirs might be needed to make up for some of the potential reserve shortfall associated with McMurray Formation SAGD reservoirs.
{"title":"Comparison of McMurray Formation (Lower Cretaceous) and Grosmont Formation (Upper Devonian) bitumen reservoirs with some speculations, from a geological perspective, on the future of Canadian thermal recovery","authors":"P. Putnam, J. Russel-Houston, S. Christensen","doi":"10.2113/GSCPGBULL.64.2.324","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.324","url":null,"abstract":"Abstract Using the data from over 8000 wells augmented by seismic and thermal response information, a comparison of McMurray Formation (Cretaceous) and Grosmont C member (Devonian) thermal recovery reservoirs of northeastern Alberta is provided along with a discussion of reservoir performance to date. Fluvial-estuarine McMurray Formation reservoirs perform best where bitumen-charged homogeneous lenticular sandstones at least 20 metres thick are found. These deposits are relatively rare as the formation is characterized by endemic heterogeneity mainly in the form of inclined heterolithic stratification (IHS). Most of the best McMurray steam-assisted gravity drainage (SAGD) reservoirs appear to be currently on-line and produce approximately 113 000 m3/day of bitumen from fourteen projects. Platform carbonate Grosmont C successions are blanket deposits 32–35 metres thick, with bitumen columns typically 15–24 metres thick, and are characterized by consistent reservoir properties facilitated by pervasive multi-scale fracturing. Although no reserves have yet to be assigned to Alberta’s bitumen-bearing carbonates by the province, recent pilot results derived from cyclic steam stimulation (CSS) operations suggest that Grosmont C reservoir performance could ultimately prove to be competitive with superior McMurray SAGD reservoirs. Under current technological and economic conditions, McMurray SAGD reservoirs appear incapable of providing the 15.9 billion m3 of in-situ bitumen reserves (59% of Canada’s total oil reserves) ascribed to this formation by the province of Alberta as only circa 6 billion m3 of oil-in place appears to reside within optimal reservoirs (i.e. those reservoirs at least 20 metres thick with average porosity and oil saturation values of 33% and 80%, respectively). Barring future technological breakthroughs and, or, economic improvements, future commercial development of both the Grosmont C and other carbonate reservoirs might be needed to make up for some of the potential reserve shortfall associated with McMurray Formation SAGD reservoirs.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.324","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208774","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 : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.278
D. Hills, Christopher Hooks, M. McIntyre-Redden, Levi A. Crooke, B. Tew, K. Parks
Abstract With the increased desire for North American energy independence, there has been a recent increase in interest in assessment of unconventional resources in the United States, including oil sands. To that end, the Alabama Oil Sands Program (AOSP) has been established at the Geological Survey of Alabama (GSA) and the Alabama State Oil and Gas Board (OGB). With this program, the GSA and OGB will provide a focus for oil sands activities and initiatives in the state, in order to assist in the realization of potential economic and societal benefits that accrue from prudent, orderly, and environmentally sound development. The AOSP will evaluate and develop appropriate legal and regulatory frameworks. Alberta, Canada, has a long history of assessment and development of oil sands area; therefore, when developing a research and development program, it is prudent to examine similarities and differences between Alberta and Alabama, both in the resource itself and in development and regulatory pathways.
{"title":"Oil sands in Alabama, USA: A fresh look at an emerging potential resource","authors":"D. Hills, Christopher Hooks, M. McIntyre-Redden, Levi A. Crooke, B. Tew, K. Parks","doi":"10.2113/GSCPGBULL.64.2.278","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.278","url":null,"abstract":"Abstract With the increased desire for North American energy independence, there has been a recent increase in interest in assessment of unconventional resources in the United States, including oil sands. To that end, the Alabama Oil Sands Program (AOSP) has been established at the Geological Survey of Alabama (GSA) and the Alabama State Oil and Gas Board (OGB). With this program, the GSA and OGB will provide a focus for oil sands activities and initiatives in the state, in order to assist in the realization of potential economic and societal benefits that accrue from prudent, orderly, and environmentally sound development. The AOSP will evaluate and develop appropriate legal and regulatory frameworks. Alberta, Canada, has a long history of assessment and development of oil sands area; therefore, when developing a research and development program, it is prudent to examine similarities and differences between Alberta and Alabama, both in the resource itself and in development and regulatory pathways.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.278","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68209051","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 : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.119
H. Pouderoux, Adam B. Coderre, P. Pedersen, D. Cronkwright
Abstract Hydrocarbons have been produced from the Grand Rapids oil sands for decades; however, large volumes still remain in place, mostly due to the extreme complexity of the reservoirs. Detailed examination of wireline logs and cores from 1127 wells within the 400 km2 Manatokan Field (Twp 62–63; Rge 4–5 W4M) are used to characterize the deposits, define the stratigraphic framework, establish the depositional architecture, and infer the mechanisms and parameters controlling the deposition of the formation. Twenty-one facies are identified based on detailed core analysis (sedimentology, ichnology, geochemistry), and are organized into five recurring facies associations: 1) wave-dominated shoreface deposits; 2) delta-influenced shoreface deposits; 3) interdistributary bay deposits; 4) marine-influenced fluvial deposits; and 5) coastal plain deposits. Shoreface deposits, which form correlatable 3–30 m-thick coarsening-up cycles, are classified as wave-dominated fluvial-influenced to fluvial-dominated wave-influenced, potentially tide-affected (Wft to Fwt). Marine-influenced fluvial deposits are mostly emplaced as point bars within 100–2000 m wide and 3–30 m deep fluvial bodies distributed within the strata. The established stratigraphic framework subdivides the formation into 11 parasequences, 7 parasequence sets, 7 stratigraphic levels containing fluvial bodies and 2 depositional sequences capped by sequence boundaries. Those observations contrast with previous interpretations that recognized seven sequences boundaries capping each of the parasequence sets. However, stratigraphy of the Grand Rapids Formation is primarily controlled by eustacy: sequences and parasequence sets are primarily influenced by long-period moderate-amplitude (1.2–2.4 m.y.; 15–30 m) and short-period low-amplitude (0.4 m.y.; <10 m) glacio-eustatic sea-level cyclicity, respectively. Individual parasequences are likely controlled by short-period allocyclic (100 to 20 kyr climatic variations) and/or autocyclic parameters (delta lobe switching every 5 to 2 kyr) that affect regional and local sediment flux. These parameters and different timescales explain the peculiar distribution of reservoirs in the field with small and isolated geobodies.
{"title":"Characterization, architecture and controls of Cold Lake marginal-marine oil sands: the Grand Rapids Formation (Upper Mannville) of east-central Alberta, Canada","authors":"H. Pouderoux, Adam B. Coderre, P. Pedersen, D. Cronkwright","doi":"10.2113/GSCPGBULL.64.2.119","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.119","url":null,"abstract":"Abstract Hydrocarbons have been produced from the Grand Rapids oil sands for decades; however, large volumes still remain in place, mostly due to the extreme complexity of the reservoirs. Detailed examination of wireline logs and cores from 1127 wells within the 400 km2 Manatokan Field (Twp 62–63; Rge 4–5 W4M) are used to characterize the deposits, define the stratigraphic framework, establish the depositional architecture, and infer the mechanisms and parameters controlling the deposition of the formation. Twenty-one facies are identified based on detailed core analysis (sedimentology, ichnology, geochemistry), and are organized into five recurring facies associations: 1) wave-dominated shoreface deposits; 2) delta-influenced shoreface deposits; 3) interdistributary bay deposits; 4) marine-influenced fluvial deposits; and 5) coastal plain deposits. Shoreface deposits, which form correlatable 3–30 m-thick coarsening-up cycles, are classified as wave-dominated fluvial-influenced to fluvial-dominated wave-influenced, potentially tide-affected (Wft to Fwt). Marine-influenced fluvial deposits are mostly emplaced as point bars within 100–2000 m wide and 3–30 m deep fluvial bodies distributed within the strata. The established stratigraphic framework subdivides the formation into 11 parasequences, 7 parasequence sets, 7 stratigraphic levels containing fluvial bodies and 2 depositional sequences capped by sequence boundaries. Those observations contrast with previous interpretations that recognized seven sequences boundaries capping each of the parasequence sets. However, stratigraphy of the Grand Rapids Formation is primarily controlled by eustacy: sequences and parasequence sets are primarily influenced by long-period moderate-amplitude (1.2–2.4 m.y.; 15–30 m) and short-period low-amplitude (0.4 m.y.; <10 m) glacio-eustatic sea-level cyclicity, respectively. Individual parasequences are likely controlled by short-period allocyclic (100 to 20 kyr climatic variations) and/or autocyclic parameters (delta lobe switching every 5 to 2 kyr) that affect regional and local sediment flux. These parameters and different timescales explain the peculiar distribution of reservoirs in the field with small and isolated geobodies.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.119","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208711","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 : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.147
K. Barrett
Abstract The Grosmont Formation, with an estimated resource of 64.5 billion m3 (406 billion bbl), is one of the largest bitumen deposits in the world. The Grosmont Formation contains four stacked carbonate units. The uppermost two, the Grosmont C and D, contain the bulk of the Grosmont bitumen resource. The Grosmont C reservoir interval is 20 m thick and consists mainly of vuggy dolomite with an average porosity of 18.6%. The overlying 32 m thick Grosmont D has an average porosity of 24.3% and its main reservoir facies is dolomite breccia. Bitumen and water saturations are variable throughout the reservoir and require either core analysis or exotic logging tools such as nuclear magnetic resonance logging for accurate determination. One outcome of the improved understanding of bitumen saturations within the Grosmont reservoirs was the identification of a lean bitumen zone within the Grosmont D. Through the use of radioactive tracer logs, it was determined that this zone is a major drilling fluids thief zone. Laricina Energy Ltd. and Osum Corp. are conducting a cyclic steam assisted gravity drainage (SAGD) pilot at Section 26 Twp 85 Rge 19W4M using horizontal wells in both the Grosmont C and D. The pilot has produced 79 500 m3 (500 000 bbl) of bitumen up to February, 2015.
{"title":"Reservoir geology of the Grosmont Formation Bitumen Steam Pilot, Saleski, Alberta","authors":"K. Barrett","doi":"10.2113/GSCPGBULL.64.2.147","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.147","url":null,"abstract":"Abstract The Grosmont Formation, with an estimated resource of 64.5 billion m3 (406 billion bbl), is one of the largest bitumen deposits in the world. The Grosmont Formation contains four stacked carbonate units. The uppermost two, the Grosmont C and D, contain the bulk of the Grosmont bitumen resource. The Grosmont C reservoir interval is 20 m thick and consists mainly of vuggy dolomite with an average porosity of 18.6%. The overlying 32 m thick Grosmont D has an average porosity of 24.3% and its main reservoir facies is dolomite breccia. Bitumen and water saturations are variable throughout the reservoir and require either core analysis or exotic logging tools such as nuclear magnetic resonance logging for accurate determination. One outcome of the improved understanding of bitumen saturations within the Grosmont reservoirs was the identification of a lean bitumen zone within the Grosmont D. Through the use of radioactive tracer logs, it was determined that this zone is a major drilling fluids thief zone. Laricina Energy Ltd. and Osum Corp. are conducting a cyclic steam assisted gravity drainage (SAGD) pilot at Section 26 Twp 85 Rge 19W4M using horizontal wells in both the Grosmont C and D. The pilot has produced 79 500 m3 (500 000 bbl) of bitumen up to February, 2015.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.147","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208252","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 : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.233
M. Gingras, J. Maceachern, S. Dashtgard, M. Ranger, S. Pemberton
Abstract This paper considers the paleoecological and paleodepositional significance of bioturbated channel-associated sands of the McMurray Formation, Alberta, Canada. The facies associations described in this paper include: 1) thalweg-associated cross-stratified sand; 2) bar-related Inclined Heterolithic Stratification; and 3) bar-top / tidal-flat deposits. Thalweg-associated cross-stratified sands contain mud-lined Skolithos and Cylindrichnus, with rare Planolites, Palaeophycus, Siphonichnus, Conichnus, and bivalve-generated equilibrichnia and fugichnia. Bar-related inclined heterolithic stratification contains Planolites-Teichichnus-Cylindrichnus associations, Cylindrichnus-Skolithos-Planolites assemblages, and monospecific Gyrolithes-dominated facies, any of which may contain subordinate Siphonichnus, Palaeophycus, Psilonichnus, and Arenicolites. Bar-top/tidal-flat deposits are characterized by gently dipping to horizontal, bioturbated, heterolithic media containing Planolites and Cylindrichnus, with rare Skolithos, Thalassinoides and Arenicolites. The trace-fossil assemblages in the three facies associations show numerous features characteristic of brackish-water environments: 1) suites are of low diversities; 2) suites contain marine-derived ichnogenera; 3) ichnogenera are characterized by size diminution; 4) ethological associations correspond to the activities of trophic generalists; 5) intervals locally indicate high infaunal biomasses; and 6) intervals display evidence of r-selected (opportunistic) colonization strategies. Such trace-fossil assemblages are only consistent with examples of brackish-water ichnocoenoses in modern settings and in high-certainty brackish-water deposits documented from around the world. These ichnological observations are supported by the abundance of tidally generated sedimentary structures (sigmoidal bedding, draped foresets, reactivation surfaces and bidirectionally oriented cross-stratification) as well as marine dinocysts recovered from these facies. The paleontological and physical sedimentological characteristics require the presence of tidal currents and brackish-water to explain middle McMurray Formation deposition. Bioturbation ascribable to fresh-water conditions is present, albeit rarely, in the McMurray Formation. This includes occurrences of irregularly shaped shafts and tunnels displaying variable diameters, as well as Taenidium and Naktodemasis observed in bar-top units. These trace fossils are normally found in association with root traces and pedogenically altered sediments situated near the top of the lower McMurray. These assemblages confirm that during McMurray time, freshwater and brackish-water ichnocoenoses were present and yielded discrete and readily discernible trace fossil suites. Brackish-water thalweg, bar, and bartop units, which are consistently devoid of pedogenic alteration and root traces, are explained by: 1) the presence of brackish-water in the depositional setting; and
{"title":"The significance of trace fossils in the McMurray Formation, Alberta, Canada","authors":"M. Gingras, J. Maceachern, S. Dashtgard, M. Ranger, S. Pemberton","doi":"10.2113/GSCPGBULL.64.2.233","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.233","url":null,"abstract":"Abstract This paper considers the paleoecological and paleodepositional significance of bioturbated channel-associated sands of the McMurray Formation, Alberta, Canada. The facies associations described in this paper include: 1) thalweg-associated cross-stratified sand; 2) bar-related Inclined Heterolithic Stratification; and 3) bar-top / tidal-flat deposits. Thalweg-associated cross-stratified sands contain mud-lined Skolithos and Cylindrichnus, with rare Planolites, Palaeophycus, Siphonichnus, Conichnus, and bivalve-generated equilibrichnia and fugichnia. Bar-related inclined heterolithic stratification contains Planolites-Teichichnus-Cylindrichnus associations, Cylindrichnus-Skolithos-Planolites assemblages, and monospecific Gyrolithes-dominated facies, any of which may contain subordinate Siphonichnus, Palaeophycus, Psilonichnus, and Arenicolites. Bar-top/tidal-flat deposits are characterized by gently dipping to horizontal, bioturbated, heterolithic media containing Planolites and Cylindrichnus, with rare Skolithos, Thalassinoides and Arenicolites. The trace-fossil assemblages in the three facies associations show numerous features characteristic of brackish-water environments: 1) suites are of low diversities; 2) suites contain marine-derived ichnogenera; 3) ichnogenera are characterized by size diminution; 4) ethological associations correspond to the activities of trophic generalists; 5) intervals locally indicate high infaunal biomasses; and 6) intervals display evidence of r-selected (opportunistic) colonization strategies. Such trace-fossil assemblages are only consistent with examples of brackish-water ichnocoenoses in modern settings and in high-certainty brackish-water deposits documented from around the world. These ichnological observations are supported by the abundance of tidally generated sedimentary structures (sigmoidal bedding, draped foresets, reactivation surfaces and bidirectionally oriented cross-stratification) as well as marine dinocysts recovered from these facies. The paleontological and physical sedimentological characteristics require the presence of tidal currents and brackish-water to explain middle McMurray Formation deposition. Bioturbation ascribable to fresh-water conditions is present, albeit rarely, in the McMurray Formation. This includes occurrences of irregularly shaped shafts and tunnels displaying variable diameters, as well as Taenidium and Naktodemasis observed in bar-top units. These trace fossils are normally found in association with root traces and pedogenically altered sediments situated near the top of the lower McMurray. These assemblages confirm that during McMurray time, freshwater and brackish-water ichnocoenoses were present and yielded discrete and readily discernible trace fossil suites. Brackish-water thalweg, bar, and bartop units, which are consistently devoid of pedogenic alteration and root traces, are explained by: 1) the presence of brackish-water in the depositional setting; and ","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.233","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208684","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 : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.354
D. Cullimore
Abstract Oil sand samples from the Suncor mining operations in Northern Alberta were investigated for active microbiological content. Using the technologies associated with bacterial community activities, it was found that the bulk of the activity was related to anaerobic bacteria functioning under fermentative reductive conditions. In 2013, oil sand samples were evaluated to develop protocols and in 2014 these protocols were applied to high grade, low grade, and oxidized ore samples. Five protocols were developed applicable to the oil sands. These included metabolic activity (using ATP), bacterial activity (using Bart testers), community identification (using RASI-MIDI), application of the penetrant CBD (to disperse colloidal biomass), and the generation of bioelectricity by the intrinsic biomass. For ATP activity it was found that all of the oil sand samples tested had some activity. However the low grade ores were found to be as active as in wastewater treatment lagoons. Oxidized ores were found on average to be active at one third the low-grade ores while the high-grade ores were lower on average by 38 times than the low grade ore. This would indicate that the high-grade ore had very little bacterial activity and possibly these ores were now matured. While activity did vary with the type of ore sample, the bacterial population remained relatively constant and was dominated by slime forming, heterotrophic and denitrifying bacteria. Some differences were noted in the relationships between the three groups due to sample sizes being too small to ensure continuity. Community identification found that the protocol yielded a constant type expressed as ENG 610 with very good similarity indexes. Bitumen within the oil sand became mobilized using the dispersant CBD relatively in all grades of oil sand. Bioelectrical potentials were also investigated and it was found that voltages remained fairly constant (e.g. 1.6 volts DC) but did vary in milli-amperages depending on the sample type. In summary, all of the oil sand samples appeared to have detectable activities mostly associated with bacteria. Using the E-tATP activity measurement, it was found that the low grade ores were the most active. However, bacterial communities of SLYM (sliming forming), HAB (heterotrophic aerobic bacteria), and DN (denitrifying bacteria) dominated with the fatty acid fingerprint relating to SCE 610. All oil sand samples were found to be ATP active and contained large populations of the three bacterial communities which shifted from a dormant to an active state depending upon conditions within the ore.
{"title":"Initial investigations of the potential bacteriological and associated biochemical activity in oil sands mined in Northern Alberta","authors":"D. Cullimore","doi":"10.2113/GSCPGBULL.64.2.354","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.354","url":null,"abstract":"Abstract Oil sand samples from the Suncor mining operations in Northern Alberta were investigated for active microbiological content. Using the technologies associated with bacterial community activities, it was found that the bulk of the activity was related to anaerobic bacteria functioning under fermentative reductive conditions. In 2013, oil sand samples were evaluated to develop protocols and in 2014 these protocols were applied to high grade, low grade, and oxidized ore samples. Five protocols were developed applicable to the oil sands. These included metabolic activity (using ATP), bacterial activity (using Bart testers), community identification (using RASI-MIDI), application of the penetrant CBD (to disperse colloidal biomass), and the generation of bioelectricity by the intrinsic biomass. For ATP activity it was found that all of the oil sand samples tested had some activity. However the low grade ores were found to be as active as in wastewater treatment lagoons. Oxidized ores were found on average to be active at one third the low-grade ores while the high-grade ores were lower on average by 38 times than the low grade ore. This would indicate that the high-grade ore had very little bacterial activity and possibly these ores were now matured. While activity did vary with the type of ore sample, the bacterial population remained relatively constant and was dominated by slime forming, heterotrophic and denitrifying bacteria. Some differences were noted in the relationships between the three groups due to sample sizes being too small to ensure continuity. Community identification found that the protocol yielded a constant type expressed as ENG 610 with very good similarity indexes. Bitumen within the oil sand became mobilized using the dispersant CBD relatively in all grades of oil sand. Bioelectrical potentials were also investigated and it was found that voltages remained fairly constant (e.g. 1.6 volts DC) but did vary in milli-amperages depending on the sample type. In summary, all of the oil sand samples appeared to have detectable activities mostly associated with bacteria. Using the E-tATP activity measurement, it was found that the low grade ores were the most active. However, bacterial communities of SLYM (sliming forming), HAB (heterotrophic aerobic bacteria), and DN (denitrifying bacteria) dominated with the fatty acid fingerprint relating to SCE 610. All oil sand samples were found to be ATP active and contained large populations of the three bacterial communities which shifted from a dormant to an active state depending upon conditions within the ore.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.354","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208872","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 : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.291
G. Joussineau, K. Barrett, M. Alessandroni, T. L. Maux
Abstract The Grosmont Formation in Alberta contains one of the largest hydrocarbon accumulations of a carbonate reservoir in the world. It is also a highly fractured reservoir, where natural fracture networks have a key bearing on production and final recovery. The present fracture study focused on the Grosmont C and D units of the Saleski leases, where a steam injection pilot for the Grosmont was initiated in 2010 by Laricina Energy Ltd. and its partner, Osum Oil Sands Corp. This study aimed at characterizing the types, scales and organization of fractures in the reservoir units in order to build a representative fracture model and derive corresponding fracture properties to be used in dual porosity dynamic simulations. Detailed core and borehole image analyses revealed that fracturing in the Grosmont C and D units is organized into four sets of metre-scale joints and isotropic, centimetre-scale dissolution-related cracks. The joint density is controlled by facies. Dynamic data analysis revealed a link between mud losses, rock dissolution and facies types, especially in the Middle D unit. It also emphasized the fracture contribution to overall reservoir permeability. All of these findings were integrated to build a multiscale fracture model which, once dynamically calibrated, allowed computing fracture porosity, permeability tensor and matrix block sizes. These outputs are critical for thermal dual porosity dynamic simulations.
阿尔伯塔省的格罗斯蒙特组是世界上最大的碳酸盐岩储层之一。这也是一个高度裂缝性的油藏，天然裂缝网络对产量和最终采收率有着关键的影响。目前的裂缝研究主要集中在Saleski租地的Grosmont C和D单元，Laricina Energy Ltd.及其合作伙伴Osum Oil Sands Corp.于2010年启动了Grosmont的蒸汽注入试验。该研究旨在表征储层单元中裂缝的类型、规模和组织，以建立具有代表性的裂缝模型，并得出相应的裂缝特性，用于双孔隙度动态模拟。详细的岩心和井眼图像分析显示，Grosmont C和D单元的压裂被组织成四组米尺度的节理和各向同性的厘米尺度溶蚀相关裂缝。节理密度受相控制。动态数据分析揭示了泥浆损失、岩石溶蚀和相类型之间的联系，特别是在中D单元。它还强调了裂缝对储层整体渗透率的贡献。所有这些发现都被整合到一个多尺度裂缝模型中，一旦进行动态校准，就可以计算裂缝孔隙度、渗透率张量和基质块尺寸。这些输出对于热双重孔隙度动态模拟至关重要。
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Pub Date : 2016-06-01DOI: 10.2113/GSCPGBULL.64.2.362
F. Hein, K. Parks
Abstract Commercial development of Alberta’s oil sands deposits has been underway since the 1960s. Their growth has always been guided by a strong provincial energy regulator. The interplay of regulation and development has been well served by the generation of public geoscience at the regulator. The role of public geoscience in regulatory stewardship of the oil sands in the Alberta context from the 1960 to 2010 is examined. This examination focuses on the historical delivery of resource appraisal of the oil sands deposits and geoscience in adjudicative support during gas-over-bitumen regulatory disputes.
{"title":"Public geoscience in regulating Alberta’s oil sands development: A Historical Retrospective 1960-2010","authors":"F. Hein, K. Parks","doi":"10.2113/GSCPGBULL.64.2.362","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.2.362","url":null,"abstract":"Abstract Commercial development of Alberta’s oil sands deposits has been underway since the 1960s. Their growth has always been guided by a strong provincial energy regulator. The interplay of regulation and development has been well served by the generation of public geoscience at the regulator. The role of public geoscience in regulatory stewardship of the oil sands in the Alberta context from the 1960 to 2010 is examined. This examination focuses on the historical delivery of resource appraisal of the oil sands deposits and geoscience in adjudicative support during gas-over-bitumen regulatory disputes.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.2.362","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68209314","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 : 2016-03-01DOI: 10.2113/GSCPGBULL.64.1.1
L. Dafoe, J. Shaw, C. Jauer, P. Giles, J. Waldron, D. Potter
St. George’s Bay lies south of Port au Port Peninsula on the west coast of Newfoundland, Canada. The Carboniferous Bay St. George subbasin extends beneath the bay and onshore to the southeast. The subbasin is an extension of the Magdalen Basin, a Carboniferous basin with probable resource potential, part of the broader Maritimes Basin. The onshore geology of the subbasin is relatively well understood. Marine datasets from the less well known offshore portion include high-resolution bathymetry, aeromagnetic data, shallow and industry wells, and both shallow and deeper (conventional) two-dimensional seismic data. Quaternary features were previously documented in inner St. George’s Bay where the surficial cover is thick. In the outer part of the bay, bedrock ridges are draped by iceberg-turbated glaciomarine mud and moraines. Beneath this cover, reinterpreted palynological analyses in the A-36 well reflect only Visean Codroy Group. The uppermost Codroy Group of this well may correlate with nearby red sandstones from shallow marine bedrock drill cores; however, younger Carboniferous rocks may also be present. Reflectors mapped using conventional seismic data mark the base Codroy Group and the top of a salt unit in the Codroy Group. Salt-cored anticlines and synclines are associated with halokinesis, and with a fault system with both dip-slip and dextral-slip components. Multibeam bathymetry and the second vertical derivative of the magnetic field delineate the folds as curvilinear, en echelon, and, in some cases, doubly plunging. Beneath the subbasin, seismic and aeromagnetic data indicate Proterozoic basement blocks and an offshore extension of the early Paleozoic Romaines Brook Fault. The Carboniferous structures suggest an environment of dextral transtension that reactivated early Paleozoic structures aligned with pre-existing weaknesses in basement.
{"title":"New insights into the Bedrock and Quaternary Geology of St. George’s Bay from a vertical integration of marine datasets, offshore western Newfoundland","authors":"L. Dafoe, J. Shaw, C. Jauer, P. Giles, J. Waldron, D. Potter","doi":"10.2113/GSCPGBULL.64.1.1","DOIUrl":"https://doi.org/10.2113/GSCPGBULL.64.1.1","url":null,"abstract":"St. George’s Bay lies south of Port au Port Peninsula on the west coast of Newfoundland, Canada. The Carboniferous Bay St. George subbasin extends beneath the bay and onshore to the southeast. The subbasin is an extension of the Magdalen Basin, a Carboniferous basin with probable resource potential, part of the broader Maritimes Basin. The onshore geology of the subbasin is relatively well understood. Marine datasets from the less well known offshore portion include high-resolution bathymetry, aeromagnetic data, shallow and industry wells, and both shallow and deeper (conventional) two-dimensional seismic data. Quaternary features were previously documented in inner St. George’s Bay where the surficial cover is thick. In the outer part of the bay, bedrock ridges are draped by iceberg-turbated glaciomarine mud and moraines. Beneath this cover, reinterpreted palynological analyses in the A-36 well reflect only Visean Codroy Group. The uppermost Codroy Group of this well may correlate with nearby red sandstones from shallow marine bedrock drill cores; however, younger Carboniferous rocks may also be present. Reflectors mapped using conventional seismic data mark the base Codroy Group and the top of a salt unit in the Codroy Group. Salt-cored anticlines and synclines are associated with halokinesis, and with a fault system with both dip-slip and dextral-slip components. Multibeam bathymetry and the second vertical derivative of the magnetic field delineate the folds as curvilinear, en echelon, and, in some cases, doubly plunging. Beneath the subbasin, seismic and aeromagnetic data indicate Proterozoic basement blocks and an offshore extension of the early Paleozoic Romaines Brook Fault. The Carboniferous structures suggest an environment of dextral transtension that reactivated early Paleozoic structures aligned with pre-existing weaknesses in basement.","PeriodicalId":56325,"journal":{"name":"Bullentin of Canadian Petroleum Geology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2113/GSCPGBULL.64.1.1","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"68208026","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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