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Panel_14424 Panel_14424 8:00 AM 11:50 AM

Panel_15776 Panel_15776 8:00 AM 12:00 AM

A fundamental conundrum common to Unconventional assets is how to understand the relative contribution of the sub-surface versus the drilling and completion practice to our EUR estimates, given the inter-connectedness of many parameters. It is common sense to expect the completion design to change where there is a significant change in the sub-surface. In reality however, this is difficult to implement because intuitive solutions to optimize the interaction of the wellbore to the sub-surface are often hindered by a requirement for quantitative and statistically valid proof, typically measured in the increase in a production performance metric. To address these technical and cross-discipline integration challenges, a new workflow was derived for the Marcellus in Tioga Co. (PA), but the steps are mostly applicable to all unconventionals. The steps in the workflow, applied somewhat iteratively rather than linearly, are as follows: (1) Normalize flow for the well-bore: use inverse productivity index for pressure and also account for lateral length. (2) Normalize for the sub-surface: gross thickness was used as a proxy for HCIIP. (3) Brainstorm hypotheses that might affect EUR: Use sub-surface, drilling & completions and flowback categories and then consolidate. (4) Scrutinize the very best and very worst wells (from the inverse productivity index) in each thickness area to high-grade the hypotheses (called Outlier Analysis). (5) Create a Framework Map: map out those hypotheses that are supported by Outlier Analysis, and distinguish between changes relating to HCIIP and Access-to-HCIIP. (6) Use dynamic modeling as a sensitivity analysis to quantify potential production changes related to individual sub-surface variables. (7) Use multi-variant analysis as an independent cross-check of those hypotheses that are supported and assess the relative impact in the HCIIP and Access-to-HCIIP parameters with tornado charts. (8) Create a strategy map(s) to enable development and economic decision-making. Attempts at correlating a single parameter with EUR were not fruitful, be it a sub-surface or an engineering parameter. However, the framework map derived from this production-constrained workflow has a fit with >80% wells. Despite multiple completion optimization trials, the primary control on production was concluded to be the sub-surface variability and to address this, six drilling and completion design changes were recommended to maximize value of highly heterogeneous acreage. A fundamental conundrum common to Unconventional assets is how to understand the relative contribution of the sub-surface versus the drilling and completion practice to our EUR estimates, given the inter-connectedness of many parameters. It is common sense to expect the completion design to change where there is a significant change in the sub-surface. In reality however, this is difficult to implement because intuitive solutions to optimize the interaction of the wellbore to the sub-surface are often hindered by a requirement for quantitative and statistically valid proof, typically measured in the increase in a production performance metric. To address these technical and cross-discipline integration challenges, a new workflow was derived for the Marcellus in Tioga Co. (PA), but the steps are mostly applicable to all unconventionals. The steps in the workflow, applied somewhat iteratively rather than linearly, are as follows: (1) Normalize flow for the well-bore: use inverse productivity index for pressure and also account for lateral length. (2) Normalize for the sub-surface: gross thickness was used as a proxy for HCIIP. (3) Brainstorm hypotheses that might affect EUR: Use sub-surface, drilling & completions and flowback categories and then consolidate. (4) Scrutinize the very best and very worst wells (from the inverse productivity index) in each thickness area to high-grade the hypotheses (called Outlier Analysis). (5) Create a Framework Map: map out those hypotheses that are supported by Outlier Analysis, and distinguish between changes relating to HCIIP and Access-to-HCIIP. (6) Use dynamic modeling as a sensitivity analysis to quantify potential production changes related to individual sub-surface variables. (7) Use multi-variant analysis as an independent cross-check of those hypotheses that are supported and assess the relative impact in the HCIIP and Access-to-HCIIP parameters with tornado charts. (8) Create a strategy map(s) to enable development and economic decision-making. Attempts at correlating a single parameter with EUR were not fruitful, be it a sub-surface or an engineering parameter. However, the framework map derived from this production-constrained workflow has a fit with >80% wells. Despite multiple completion optimization trials, the primary control on production was concluded to be the sub-surface variability and to address this, six drilling and completion design changes were recommended to maximize value of highly heterogeneous acreage. Panel_14902 Panel_14902 8:05 AM 8:25 AM

Projections published in 2014 by the U. S. Energy Information indicate that annual U.S. gas demand could increase from 25.6 Tcf (trillion cubic feet) in 2012 (latest available data) to 31.6 Tcf by the year 2040. This demand total includes initiation and growth of LNG exports, projected to result in the U.S. becoming a net natural gas exporter by 2018. Shale gas production, which dates from 1821 in the United States, accounted for 9.7 Tcf in 2012. Growing shale gas consumption and enhanced understanding of our shale gas endowment are due to improvements in exploration, completion and production technologies, aided by relative stability of wellhead pricing. The current 9.7 Tcf of shale gas production is projected to more than double to 19.8 Tcf by 2040. Given these U.S. Government assumptions, what do we believe about the amount of technically recoverable shale gas? The latest Potential Gas Committee (PGC) biennial assessment, for year-end 2012 (released April 2013), showed an overall increase of 28% (486 Tcf) for total U.S. gas resources compared to year-end 2010. More significantly, shale gas now accounts for 57% of the U.S. gas resource, excluding coalbed methane. The next PGC assessment will be released in April, 2015. This paper analyses shale gas future potential – incorporating both geological and economic realities as viewed by multiple organizations – in light of past production, current proved reserves, and trends in assessment of technically recoverable resources. Current and past PGC methodological approaches are discussed. Projections published in 2014 by the U. S. Energy Information indicate that annual U.S. gas demand could increase from 25.6 Tcf (trillion cubic feet) in 2012 (latest available data) to 31.6 Tcf by the year 2040. This demand total includes initiation and growth of LNG exports, projected to result in the U.S. becoming a net natural gas exporter by 2018. Shale gas production, which dates from 1821 in the United States, accounted for 9.7 Tcf in 2012. Growing shale gas consumption and enhanced understanding of our shale gas endowment are due to improvements in exploration, completion and production technologies, aided by relative stability of wellhead pricing. The current 9.7 Tcf of shale gas production is projected to more than double to 19.8 Tcf by 2040. Given these U.S. Government assumptions, what do we believe about the amount of technically recoverable shale gas? The latest Potential Gas Committee (PGC) biennial assessment, for year-end 2012 (released April 2013), showed an overall increase of 28% (486 Tcf) for total U.S. gas resources compared to year-end 2010. More significantly, shale gas now accounts for 57% of the U.S. gas resource, excluding coalbed methane. The next PGC assessment will be released in April, 2015. This paper analyses shale gas future potential – incorporating both geological and economic realities as viewed by multiple organizations – in light of past production, current proved reserves, and trends in assessment of technically recoverable resources. Current and past PGC methodological approaches are discussed. Panel_14899 Panel_14899 8:25 AM 8:45 AM

Approaching its first thousand horizontal wells, the Utica/Point Pleasant play in Ohio, West Virginia and Pennsylvania is a newcomer to the "unconventional club". While the Ohio oil and gas industry has a long history, the Utica and deeper Point Pleasant formations have only recently emerged as economically viable transitional gas-to-liquids targets. While these Ordivician-aged rocks do not have an exact analogue in any other North American unconventional play, many of the learnings from transitional phase plays like the Eagle Ford have provided general blueprints for effective field development. Depth, thickness and geochemistry maps provide valuable insights into the west-east transition of the basin from liquids-rich to dry gas, near and beyond the Pennsylvania border. Rock cuttings and log data provide insights into the porosity and permeability characteristics of the Utica, Point Pleasant and Marcellus, the latter largely shallowing to uneconomic depths in the area of this study. Sufficient well coverage is in place to correlate geologic measurements with fluid phase maps of gas-oil ratio and breakdown pressures measured during hydraulic fracturing. In combination, analytic characterization of geologic and fluid maps provide valuable insights into relative sweetspots and emerging opportunities in southern Ohio and in West Virginia. As in other unconventional plays, extensive experimentation is underway to "right-size" drilling and completions for variable rock and fluid characteristics. Starting 50% higher than the Eagle Ford historic average, Utica and Point Pleasant completions are placing an average of 6.5 million pounds of sand, with individual wells ranging beyond 17 million pounds. Fluid volumes are comparable to the Eagle Ford, at an average of 100,000 barrels. Horizontal well lengths generally fall between 4000 and 7000 feet, but do extend up to 9000 feet. Analytic studies of gas and liquids production in the Utica and Point Pleasant play indicate that the geology and fluid mix are amenable to "high-intensity" fracing. Normalized to horizontal lengths, Eagle-Ford like frac jobs of 1000-2000 pounds per foot of sand and 20-40 barrels per foot correlate to the best producing wells to date. Recent drilling results are also bearing out geologic prospectivity further south than the initial "core area" of east-central Ohio. Approaching its first thousand horizontal wells, the Utica/Point Pleasant play in Ohio, West Virginia and Pennsylvania is a newcomer to the "unconventional club". While the Ohio oil and gas industry has a long history, the Utica and deeper Point Pleasant formations have only recently emerged as economically viable transitional gas-to-liquids targets. While these Ordivician-aged rocks do not have an exact analogue in any other North American unconventional play, many of the learnings from transitional phase plays like the Eagle Ford have provided general blueprints for effective field development. Depth, thickness and geochemistry maps provide valuable insights into the west-east transition of the basin from liquids-rich to dry gas, near and beyond the Pennsylvania border. Rock cuttings and log data provide insights into the porosity and permeability characteristics of the Utica, Point Pleasant and Marcellus, the latter largely shallowing to uneconomic depths in the area of this study. Sufficient well coverage is in place to correlate geologic measurements with fluid phase maps of gas-oil ratio and breakdown pressures measured during hydraulic fracturing. In combination, analytic characterization of geologic and fluid maps provide valuable insights into relative sweetspots and emerging opportunities in southern Ohio and in West Virginia. As in other unconventional plays, extensive experimentation is underway to "right-size" drilling and completions for variable rock and fluid characteristics. Starting 50% higher than the Eagle Ford historic average, Utica and Point Pleasant completions are placing an average of 6.5 million pounds of sand, with individual wells ranging beyond 17 million pounds. Fluid volumes are comparable to the Eagle Ford, at an average of 100,000 barrels. Horizontal well lengths generally fall between 4000 and 7000 feet, but do extend up to 9000 feet. Analytic studies of gas and liquids production in the Utica and Point Pleasant play indicate that the geology and fluid mix are amenable to "high-intensity" fracing. Normalized to horizontal lengths, Eagle-Ford like frac jobs of 1000-2000 pounds per foot of sand and 20-40 barrels per foot correlate to the best producing wells to date. Recent drilling results are also bearing out geologic prospectivity further south than the initial "core area" of east-central Ohio. Panel_14895 Panel_14895 8:45 AM 9:05 AM

Is the stage set for U.S. operators to drill themselves into lower domestic oil prices, similar to what they did with gas? Investment in shale plays across North America has undoubtedly shifted from the early gas targets in the Barnett, Fayetteville, and Woodford to liquids-rich zones and oil producing formations like the Bakken, Eagle Ford, and Wolfcamp. At the peak of the gas boom, a little more than 75% of activity was targeting gas plays. Now, over 75% of industry activity targets oil plays. The shift has been driven by strong liquids prices and, most importantly, technology improvements that allow tight oil plays to provide sector-leading returns. US onshore operators realize rates of return as high as 30% in tight oil assets, or roughly double what they experienced in shale gas plays. Liquids-rich shales also provide as much upside as many new deepwater and ultra-deepwater projects. Exploration dollars that were once being invested abroad are coming onshore now as operators push the limits of downspacing and look to prove the viability of secondary targets or stacked pay zones. Both downspacing and stacked pay have the potential to multiply the resource prize and extend the life of the biggest unconventional fields. Total investment in tight oil plays in the US is approaching US$100 billion per year, a similar amount to what the entire upstream industry invested in the US just a few short years ago. Operators in the top tier assets are focused on enhancing completions and streamlining operations. Using our proprietary well analysis tool and coverage of over 100 companies in 300 Lower 48 plays and sub-plays, we have benchmarked the best acreage across all resource types; gas, rich gas, and oil. Looking forward, we have also evaluated the variability in performance across plays, the emergence of secondary or stacked pay in the major producing areas, and changing drilling and completion strategies. We characterise how much those factors could further shift the industry over the next five years. Will drilling inventories dry up or will there still be room to run in 2020? Is the stage set for U.S. operators to drill themselves into lower domestic oil prices, similar to what they did with gas? Investment in shale plays across North America has undoubtedly shifted from the early gas targets in the Barnett, Fayetteville, and Woodford to liquids-rich zones and oil producing formations like the Bakken, Eagle Ford, and Wolfcamp. At the peak of the gas boom, a little more than 75% of activity was targeting gas plays. Now, over 75% of industry activity targets oil plays. The shift has been driven by strong liquids prices and, most importantly, technology improvements that allow tight oil plays to provide sector-leading returns. US onshore operators realize rates of return as high as 30% in tight oil assets, or roughly double what they experienced in shale gas plays. Liquids-rich shales also provide as much upside as many new deepwater and ultra-deepwater projects. Exploration dollars that were once being invested abroad are coming onshore now as operators push the limits of downspacing and look to prove the viability of secondary targets or stacked pay zones. Both downspacing and stacked pay have the potential to multiply the resource prize and extend the life of the biggest unconventional fields. Total investment in tight oil plays in the US is approaching US$100 billion per year, a similar amount to what the entire upstream industry invested in the US just a few short years ago. Operators in the top tier assets are focused on enhancing completions and streamlining operations. Using our proprietary well analysis tool and coverage of over 100 companies in 300 Lower 48 plays and sub-plays, we have benchmarked the best acreage across all resource types; gas, rich gas, and oil. Looking forward, we have also evaluated the variability in performance across plays, the emergence of secondary or stacked pay in the major producing areas, and changing drilling and completion strategies. We characterise how much those factors could further shift the industry over the next five years. Will drilling inventories dry up or will there still be room to run in 2020? Panel_14901 Panel_14901 9:05 AM 9:25 AM

Panel_15777 Panel_15777 9:25 AM 12:00 AM

Evaluation of the total resource storage and productivity in shale gas and tight oil reservoirs provides critical information for shale oil/gas exploration and production. Among different evaluation parameters, porosity and permeability have often been assessed to infer the reservoir potential and the producing capacity. However, direct measurement of porosity and permeability in unconventional reservoirs is usually time-consuming and/or bears significantly uncertainty, which makes it difficult to apply to field operations demanding prompt and consistent measurements. Here, we present a novel stage-wise degassing approach to assess quantity of released hydrocarbon gases and the permeability of the shale samples. We quantify released gases from rock samples at each degassing stage via the PVT equation. We measure the gas carbon isotope ratios by gas chromatography-InfraRed Isotope ratio Analyzer (GC-IR2). For method calibration, we measured the nanoporosity, permeability and rock TOC via independent and well-established methods. We demonstrate that 1) stage-wise degassing amount implies the available gas distribution among different pore sizes, 2) d13C1 increases during the degassing process, 3) wetness of recovered gas helps to estimate gas composition for a range of pore sizes, and 4) the largest d13C1 change through degassing is related to the largest permeability among examined samples. Our approach provides rapid and consistent analysis on carbon isotope variations and degassing quantity. This method is applied to the Eagle Ford, the Woodford and the Sichuan Basin, and proves to be efficient and insightful in aiding the prompt decision on “sweet spot” during field operation. Evaluation of the total resource storage and productivity in shale gas and tight oil reservoirs provides critical information for shale oil/gas exploration and production. Among different evaluation parameters, porosity and permeability have often been assessed to infer the reservoir potential and the producing capacity. However, direct measurement of porosity and permeability in unconventional reservoirs is usually time-consuming and/or bears significantly uncertainty, which makes it difficult to apply to field operations demanding prompt and consistent measurements. Here, we present a novel stage-wise degassing approach to assess quantity of released hydrocarbon gases and the permeability of the shale samples. We quantify released gases from rock samples at each degassing stage via the PVT equation. We measure the gas carbon isotope ratios by gas chromatography-InfraRed Isotope ratio Analyzer (GC-IR2). For method calibration, we measured the nanoporosity, permeability and rock TOC via independent and well-established methods. We demonstrate that 1) stage-wise degassing amount implies the available gas distribution among different pore sizes, 2) d13C1 increases during the degassing process, 3) wetness of recovered gas helps to estimate gas composition for a range of pore sizes, and 4) the largest d13C1 change through degassing is related to the largest permeability among examined samples. Our approach provides rapid and consistent analysis on carbon isotope variations and degassing quantity. This method is applied to the Eagle Ford, the Woodford and the Sichuan Basin, and proves to be efficient and insightful in aiding the prompt decision on “sweet spot” during field operation. Panel_14896 Panel_14896 10:10 AM 10:30 AM

The Woodford Shale is an Upper Devonian organic-rich black shale and potential gas and liquid reservoir in the Permian Basin, west Texas. It is widespread and thick (up to 200 meters) and represents the longest continuous record of black shale deposition in North America. Detailed sedimentological and geochemical studies have been carried out on two Woodford cores, from 8300 feet and 12900 feet, equivalent to 0.71% and 1.48% Ro, based on Rockeval Tmax values. The geochemical data, combined extended modern log suites, provides an opportunity to examine the impact of varying total organic carbon (TOC) content and thermal maturity on acoustic velocities and density. By correlating the gamma log to core TOC, a complete record of organic carbon content through the well is obtained; the log-estimated TOC is then compared to Vp, Vs and density logs. Vp and Vs decrease systematically with increasing TOC, by 20 to 25% as TOC increases from 0% to 10%. Because density also decreases with increasing TOC, the effect on acoustic impedance is substantial, as much as 30% in the range of 0 to 10% TOC. Velocity is affected because organic matter is relatively soft material, while density is affected because organic matter is composed primarily of the light elements carbon and hydrogen. Although organic matter is relatively ductile, particularly in lower maturity rocks, and would be expected to transmit shear waves relatively poorly, a decrease in Vp/Vs ratios is evident with increasing TOC; this may be because high TOC is accompanied by high volumes of quartz cement, which would provide a stiff framework to the shale. The effect of thermal maturity is significant. The velocity of both P waves and S waves is approximately 20% higher in the higher maturity well than in the lower maturity well. Acoustic impedance is also substantially higher. This may result from loss of organic carbon during oil and gas generation and expulsion, or it may result from changes in the physical properties of kerogen related to thermal maturation. These results suggest that it may be possible to map isomaturity lines in a source rock formation based on acoustic velocities, and where seismic resolution is sufficient, it may be possible to identify intervals of high TOC based on impedance maps. However prediction of shale TOC may have to be accompanied by an independent interpretation of thermal maturity such as basin modeling. The Woodford Shale is an Upper Devonian organic-rich black shale and potential gas and liquid reservoir in the Permian Basin, west Texas. It is widespread and thick (up to 200 meters) and represents the longest continuous record of black shale deposition in North America. Detailed sedimentological and geochemical studies have been carried out on two Woodford cores, from 8300 feet and 12900 feet, equivalent to 0.71% and 1.48% Ro, based on Rockeval Tmax values. The geochemical data, combined extended modern log suites, provides an opportunity to examine the impact of varying total organic carbon (TOC) content and thermal maturity on acoustic velocities and density. By correlating the gamma log to core TOC, a complete record of organic carbon content through the well is obtained; the log-estimated TOC is then compared to Vp, Vs and density logs. Vp and Vs decrease systematically with increasing TOC, by 20 to 25% as TOC increases from 0% to 10%. Because density also decreases with increasing TOC, the effect on acoustic impedance is substantial, as much as 30% in the range of 0 to 10% TOC. Velocity is affected because organic matter is relatively soft material, while density is affected because organic matter is composed primarily of the light elements carbon and hydrogen. Although organic matter is relatively ductile, particularly in lower maturity rocks, and would be expected to transmit shear waves relatively poorly, a decrease in Vp/Vs ratios is evident with increasing TOC; this may be because high TOC is accompanied by high volumes of quartz cement, which would provide a stiff framework to the shale. The effect of thermal maturity is significant. The velocity of both P waves and S waves is approximately 20% higher in the higher maturity well than in the lower maturity well. Acoustic impedance is also substantially higher. This may result from loss of organic carbon during oil and gas generation and expulsion, or it may result from changes in the physical properties of kerogen related to thermal maturation. These results suggest that it may be possible to map isomaturity lines in a source rock formation based on acoustic velocities, and where seismic resolution is sufficient, it may be possible to identify intervals of high TOC based on impedance maps. However prediction of shale TOC may have to be accompanied by an independent interpretation of thermal maturity such as basin modeling. Panel_14897 Panel_14897 10:30 AM 10:50 AM

The Woodford Shale (Oklahoma, U.S.A.), like many prolific unconventional resource shales, sits atop a major unconformity on the surface of underlying carbonates and shales.. There is variable topographic relief on this unconformity surface due to incised valley and/or karst formation during lowstand periods of subaerial exposure. This variable topography may result in a variety of depositional environments/subenvironments, including open marine, restricted marine, restricted-to-open marine, hypersaline lakes and swamps, and perhaps even perennial lakes. As a result, stratigraphy can vary locally as well as regionally within, and between basins and adjacent shelf areas. Anomalously thick intervals of the shale can form within these topographic depressions, giving rise to potential ‘sweet spots’ as drilling targets; they can be recognized on subsurface well logs by their anomalous thickness. Inversion of 3D seismic data to TOC distribution revealed TOC-enriched, compartmentalized intervals. Also, gamma ray logs often exhibit a high-API interval at or near the basal unconformity due to early marine transgression into topographic depressions, which hinders water circulation and gives rise to localized anoxic depositional environments conducive to preservation of organic matter. With continued rise in sea level, marine circulation might improve, giving rise to less preserved TOC, and lower gamma-ray log response. The Woodford Shale (Oklahoma, U.S.A.), like many prolific unconventional resource shales, sits atop a major unconformity on the surface of underlying carbonates and shales.. There is variable topographic relief on this unconformity surface due to incised valley and/or karst formation during lowstand periods of subaerial exposure. This variable topography may result in a variety of depositional environments/subenvironments, including open marine, restricted marine, restricted-to-open marine, hypersaline lakes and swamps, and perhaps even perennial lakes. As a result, stratigraphy can vary locally as well as regionally within, and between basins and adjacent shelf areas. Anomalously thick intervals of the shale can form within these topographic depressions, giving rise to potential ‘sweet spots’ as drilling targets; they can be recognized on subsurface well logs by their anomalous thickness. Inversion of 3D seismic data to TOC distribution revealed TOC-enriched, compartmentalized intervals. Also, gamma ray logs often exhibit a high-API interval at or near the basal unconformity due to early marine transgression into topographic depressions, which hinders water circulation and gives rise to localized anoxic depositional environments conducive to preservation of organic matter. With continued rise in sea level, marine circulation might improve, giving rise to less preserved TOC, and lower gamma-ray log response. Panel_14898 Panel_14898 10:50 AM 11:10 AM

Approaching 10,000 total horizontal wells, the Eagle Ford play in South Texas is one of the most mature unconventional fields in the US. However, recent developments have the Eagle Ford geologic targets growing both spatially and vertically, with identification of the viable "Easter Eagle Ford" (or Eaglebine), multi-lateral development of the Upper and Lower Eagle Ford and vertical-well exploitation of the underlying Buda limestone. Each of these expansions of the traditional Eagle Ford play illustrate an expanding understanding of the geology and fluid characteristics of the rocks underlying the Austin Chalk. Mapping of fluid characteristics in the form of oil API gravity or gas-oil-ratio (GOR) have consistently delineated the Eagle Ford "sweetspots" for optimal production of oil, condensate, natural gas liquids and dry gas. Extension of this technique beyond the San Marcos Arch to Burleson and Brazos Counties exhibits similar characteristics to Karnes, Gonzales and other liquids-rich parts of the play. Early well results are promising and provide economic opportunities that increase the overall Eagle Ford extents. Heavy well coverage is providing well log data that are also enhancing understanding of the distinct character and thickness of the Upper and Lower Eagle Ford. Regional mapping of geologic tops, coupled with detailed directional survey data and validated reported reservoir data provides insights into targeted zones and corresponding production. Sufficient thickness in both the Upper and Lower Eagle Ford is also providing opportunities for staggered multi-lateral development of both formations, in certain areas. Improved understanding of the Upper and Lower Eagle Ford, coupled with older and recent deeper vertical wells, is identifying targeted development opportunities for the Buda limestone. Impressive initial liquids production is being reported with vertical wells with relatively high-intensity completions. Against this backdrop of improved geologic understanding of the Austin/Eagle Ford/Buda/Eaglebine is a method increasing of the size of hydraulic fractures. With a historic average of 4 million pounds of sand per well, recent completions are ranging two to more than four times this value, with impressive geologic and fluid flow responses. Time will tell with respect to decline rates and sustainability, but indications are that the geology and fluid characteristics of the "old" and "new" Eagle Ford are amenable to high-intensity completions. Approaching 10,000 total horizontal wells, the Eagle Ford play in South Texas is one of the most mature unconventional fields in the US. However, recent developments have the Eagle Ford geologic targets growing both spatially and vertically, with identification of the viable "Easter Eagle Ford" (or Eaglebine), multi-lateral development of the Upper and Lower Eagle Ford and vertical-well exploitation of the underlying Buda limestone. Each of these expansions of the traditional Eagle Ford play illustrate an expanding understanding of the geology and fluid characteristics of the rocks underlying the Austin Chalk. Mapping of fluid characteristics in the form of oil API gravity or gas-oil-ratio (GOR) have consistently delineated the Eagle Ford "sweetspots" for optimal production of oil, condensate, natural gas liquids and dry gas. Extension of this technique beyond the San Marcos Arch to Burleson and Brazos Counties exhibits similar characteristics to Karnes, Gonzales and other liquids-rich parts of the play. Early well results are promising and provide economic opportunities that increase the overall Eagle Ford extents. Heavy well coverage is providing well log data that are also enhancing understanding of the distinct character and thickness of the Upper and Lower Eagle Ford. Regional mapping of geologic tops, coupled with detailed directional survey data and validated reported reservoir data provides insights into targeted zones and corresponding production. Sufficient thickness in both the Upper and Lower Eagle Ford is also providing opportunities for staggered multi-lateral development of both formations, in certain areas. Improved understanding of the Upper and Lower Eagle Ford, coupled with older and recent deeper vertical wells, is identifying targeted development opportunities for the Buda limestone. Impressive initial liquids production is being reported with vertical wells with relatively high-intensity completions. Against this backdrop of improved geologic understanding of the Austin/Eagle Ford/Buda/Eaglebine is a method increasing of the size of hydraulic fractures. With a historic average of 4 million pounds of sand per well, recent completions are ranging two to more than four times this value, with impressive geologic and fluid flow responses. Time will tell with respect to decline rates and sustainability, but indications are that the geology and fluid characteristics of the "old" and "new" Eagle Ford are amenable to high-intensity completions. Panel_14894 Panel_14894 11:10 AM 11:30 AM

The U.S. Energy Information Administration is updating maps of major tight oil and shale gas plays of the lower 48 states including the Marcellus shale of the Appalachian basin. The revised Marcellus play map summarizes geologic play elements, the growth of production, and distribution of sweet spots within the play based on publicly available data and a commercial well information database. The Middle Devonian Marcellus shale was deposited during the early stages of mountain building events in a foreland basin. The Marcellus Shale disconformably overlies the Onondaga Limestone and is composed of a basal black shale, a widespread limestone unit, and an upper black shale. Key geologic drivers defining the most prospective areas within the Marcellus shale footprint are comparable to other shale-gas plays and consist of an optimal combination of structural, geochemical, petrophysical, and thermodynamic characteristics. From 2004 through July 2014 more than 7000 wells targeting Marcellus shale were drilled in the Appalachian basin (Drilling Info, Inc). Reported natural gas production from the Marcellus play is more than 15 billion cubic feet per day (Bcf/d), accounting for almost 40% of U.S. shale gas production as of July 2014 (EIA, 2014). For the Marcellus play, the geologic elements presented include contoured elevation of the top and base of formation, isopach, major structures and tectonic features, play boundaries, well locations, and gas-to-oil ratios of producing wells. Additional map layers will be added as additional geologic data becomes available. The U.S. Energy Information Administration is updating maps of major tight oil and shale gas plays of the lower 48 states including the Marcellus shale of the Appalachian basin. The revised Marcellus play map summarizes geologic play elements, the growth of production, and distribution of sweet spots within the play based on publicly available data and a commercial well information database. The Middle Devonian Marcellus shale was deposited during the early stages of mountain building events in a foreland basin. The Marcellus Shale disconformably overlies the Onondaga Limestone and is composed of a basal black shale, a widespread limestone unit, and an upper black shale. Key geologic drivers defining the most prospective areas within the Marcellus shale footprint are comparable to other shale-gas plays and consist of an optimal combination of structural, geochemical, petrophysical, and thermodynamic characteristics. From 2004 through July 2014 more than 7000 wells targeting Marcellus shale were drilled in the Appalachian basin (Drilling Info, Inc). Reported natural gas production from the Marcellus play is more than 15 billion cubic feet per day (Bcf/d), accounting for almost 40% of U.S. shale gas production as of July 2014 (EIA, 2014). For the Marcellus play, the geologic elements presented include contoured elevation of the top and base of formation, isopach, major structures and tectonic features, play boundaries, well locations, and gas-to-oil ratios of producing wells. Additional map layers will be added as additional geologic data becomes available. Panel_14900 Panel_14900 11:30 AM 11:50 AM

Panel_14486 Panel_14486 8:00 AM 11:50 AM

Panel_15800 Panel_15800 8:00 AM 12:00 AM

Earthquakes attributable to human activities, “induced seismic events”, have received heightened public attention in the United States over the past several years. Upon request from the U.S. Congress and the Department of Energy, the National Research Council was asked to assemble a committee of experts to examine the scale, scope, and consequences of seismicity induced during fluid injection and withdrawal associated with geothermal energy development, oil and gas development, and carbon capture and storage (CCS). The committee’s report, publicly released in June 2012, indicates that induced seismicity associated with fluid injection or withdrawal is caused in most cases by change in pore fluid pressure and/or change in stress in the subsurface in the presence of faults with specific properties and orientations and a critical state of stress in the rocks. The factor that appears to have the most direct consequence in regard to induced seismicity is the net fluid balance (total balance of fluid introduced into or removed from the subsurface). Energy technology projects that are designed to maintain a balance between the amount of fluid being injected and withdrawn, such as most oil and gas development projects, appear to produce fewer seismic events than projects that do not maintain fluid balance. Major findings from the study include: (1) as presently implemented, the process of hydraulic fracturing for shale gas recovery does not pose a high risk for inducing felt seismic events; (2) injection for disposal of waste water derived from energy technologies does pose some risk for induced seismicity, but very few events have been documented over the past several decades relative to the large number of disposal wells in operation; and (3) CCS, due to the large net volumes of injected fluids suggested for future large-scale carbon storage projects, may have potential for inducing larger seismic events. Earthquakes attributable to human activities, “induced seismic events”, have received heightened public attention in the United States over the past several years. Upon request from the U.S. Congress and the Department of Energy, the National Research Council was asked to assemble a committee of experts to examine the scale, scope, and consequences of seismicity induced during fluid injection and withdrawal associated with geothermal energy development, oil and gas development, and carbon capture and storage (CCS). The committee’s report, publicly released in June 2012, indicates that induced seismicity associated with fluid injection or withdrawal is caused in most cases by change in pore fluid pressure and/or change in stress in the subsurface in the presence of faults with specific properties and orientations and a critical state of stress in the rocks. The factor that appears to have the most direct consequence in regard to induced seismicity is the net fluid balance (total balance of fluid introduced into or removed from the subsurface). Energy technology projects that are designed to maintain a balance between the amount of fluid being injected and withdrawn, such as most oil and gas development projects, appear to produce fewer seismic events than projects that do not maintain fluid balance. Major findings from the study include: (1) as presently implemented, the process of hydraulic fracturing for shale gas recovery does not pose a high risk for inducing felt seismic events; (2) injection for disposal of waste water derived from energy technologies does pose some risk for induced seismicity, but very few events have been documented over the past several decades relative to the large number of disposal wells in operation; and (3) CCS, due to the large net volumes of injected fluids suggested for future large-scale carbon storage projects, may have potential for inducing larger seismic events. Panel_15501 Panel_15501 8:05 AM 8:25 AM

In the past several years, injection induced seismicity has become an important issue. Though the phenomenon has been observed and documented for at least half a century, recent media attention and increased seismic activity in many regions have fueled public awareness and trepidation. As the public outcry builds, it is inevitable that stricter regulations governing the monitoring and protocols associated with induced seismicity will be introduced. Indeed more stringent regulations have already been established in Ohio within the past year. However what exact form these regulations will take remains unclear. It goes without saying that magnitude will play a central role in these policies, but where, if at all, will properties such as location, depth, b-value, and seismicity rate feature. All of these properties have some measure of subjectivity associated with data quality, processing methodology, and a priori knowledge that will inexorably be passed on to the regulations themselves. We address the challenges associated with implementing and meeting regulations that are effective and fair to both the public and the industry. How can we ensure that a seismic monitoring network meets the criteria set out by the regulations? How do we ensure that our attenuation model is giving an unbiased magnitude estimate? How do we incorporate the effect of complex local geology into event location algorithms? We discuss methods and monitoring strategies for industry to overcome these obstacles and to meet new regulations with minimal cost and effort. Finally, we investigate strategies to reduce the subjectivity of the regulations associated with the inherent uncertainty in earthquake properties. In the past several years, injection induced seismicity has become an important issue. Though the phenomenon has been observed and documented for at least half a century, recent media attention and increased seismic activity in many regions have fueled public awareness and trepidation. As the public outcry builds, it is inevitable that stricter regulations governing the monitoring and protocols associated with induced seismicity will be introduced. Indeed more stringent regulations have already been established in Ohio within the past year. However what exact form these regulations will take remains unclear. It goes without saying that magnitude will play a central role in these policies, but where, if at all, will properties such as location, depth, b-value, and seismicity rate feature. All of these properties have some measure of subjectivity associated with data quality, processing methodology, and a priori knowledge that will inexorably be passed on to the regulations themselves. We address the challenges associated with implementing and meeting regulations that are effective and fair to both the public and the industry. How can we ensure that a seismic monitoring network meets the criteria set out by the regulations? How do we ensure that our attenuation model is giving an unbiased magnitude estimate? How do we incorporate the effect of complex local geology into event location algorithms? We discuss methods and monitoring strategies for industry to overcome these obstacles and to meet new regulations with minimal cost and effort. Finally, we investigate strategies to reduce the subjectivity of the regulations associated with the inherent uncertainty in earthquake properties. Panel_15504 Panel_15504 8:25 AM 8:45 AM

In 2012 the National Research Council published a study “Induced Seismicity Potential in Energy Technologies”1 which reviewed the occurrence of earthquakes with various energy operations, including oil and gas waste water disposal and hydraulic fracturing. The report found only two documented examples of felt earthquakes related to hydraulic fracturing. Since the report was published, the rate of suspected induced earthquakes related to oil and gas operations has continued to rise. Hydraulic fracturing earthquakes in multiple areas of British Columbia, reported after the release of the NRC report, suggest in special cases that hydraulic fracturing is capable of producing earthquakes that can be felt on the surface. Additional reports and analysis of suspected induced earthquakes from both waste water injection wells and hydraulic fracturing operations have been reported in many states in the USA, including Kansas, Colorado, Texas, Ohio and in particular, Oklahoma, which has experienced a continued and dramatic rise in suspected induced earthquakes. This presentation will discuss recent occurrences of induced seismicity related to oil and gas operations and the seismic monitoring techniques used to understand the issue, along with new and proposed regulations suggested by authorities in the affected areas to ensure continued safe operations. In 2012 the National Research Council published a study “Induced Seismicity Potential in Energy Technologies”1 which reviewed the occurrence of earthquakes with various energy operations, including oil and gas waste water disposal and hydraulic fracturing. The report found only two documented examples of felt earthquakes related to hydraulic fracturing. Since the report was published, the rate of suspected induced earthquakes related to oil and gas operations has continued to rise. Hydraulic fracturing earthquakes in multiple areas of British Columbia, reported after the release of the NRC report, suggest in special cases that hydraulic fracturing is capable of producing earthquakes that can be felt on the surface. Additional reports and analysis of suspected induced earthquakes from both waste water injection wells and hydraulic fracturing operations have been reported in many states in the USA, including Kansas, Colorado, Texas, Ohio and in particular, Oklahoma, which has experienced a continued and dramatic rise in suspected induced earthquakes. This presentation will discuss recent occurrences of induced seismicity related to oil and gas operations and the seismic monitoring techniques used to understand the issue, along with new and proposed regulations suggested by authorities in the affected areas to ensure continued safe operations. Panel_15498 Panel_15498 8:45 AM 9:05 AM

Recent seismicity in the northern Appalachian Basin has been attributed to active wastewater injection operations. Current models of induced seismicity suggest that movement along pre-existing faults/fractures with orientations optimal to the regional maximum horizontal stress field is the likely source of recorded earthquakes. As part of this investigation, we evaluated the relationships between injection wells, waveform template matching-derived locations of induced earthquakes, and subsurface structures mapped using data from over 600 wells in Ohio and West Virginia. We also evaluated subsurface in-situ stress conditions determined from regional studies and local hydraulic fracturing operations to evaluate the principle stress orientations/magnitudes for comparison with the trends of identified earthquake epicenters. Study results indicate that the locations of seismic events likely induced by wastewater injection operations in Washington County, Ohio correspond to the trend of small-amplitude folds in Upper Devonian rocks close to injection well locations. Similar amplitude folds imaged in nearby seismic reflection lines are associated with basement-involved fault systems that cut the injection interval, providing a possible permeability pathway for fluid pressure increases that could initiate slip. While subsurface mapping in other parts of the basin have not yielded similar structural/epicentral relationships, the orientation of induced events throughout eastern Ohio correspond to the predicted optimal orientation of reactivated fault/fracture zones given the regional principle stress directions. Recent seismicity in the northern Appalachian Basin has been attributed to active wastewater injection operations. Current models of induced seismicity suggest that movement along pre-existing faults/fractures with orientations optimal to the regional maximum horizontal stress field is the likely source of recorded earthquakes. As part of this investigation, we evaluated the relationships between injection wells, waveform template matching-derived locations of induced earthquakes, and subsurface structures mapped using data from over 600 wells in Ohio and West Virginia. We also evaluated subsurface in-situ stress conditions determined from regional studies and local hydraulic fracturing operations to evaluate the principle stress orientations/magnitudes for comparison with the trends of identified earthquake epicenters. Study results indicate that the locations of seismic events likely induced by wastewater injection operations in Washington County, Ohio correspond to the trend of small-amplitude folds in Upper Devonian rocks close to injection well locations. Similar amplitude folds imaged in nearby seismic reflection lines are associated with basement-involved fault systems that cut the injection interval, providing a possible permeability pathway for fluid pressure increases that could initiate slip. While subsurface mapping in other parts of the basin have not yielded similar structural/epicentral relationships, the orientation of induced events throughout eastern Ohio correspond to the predicted optimal orientation of reactivated fault/fracture zones given the regional principle stress directions. Panel_15502 Panel_15502 9:05 AM 9:25 AM

Panel_15803 Panel_15803 9:25 AM 12:00 AM

The midcontinent has experienced a dramatic increase in seismic activity in the past several years. Seismic activity in Colorado, Arkansas, and Oklahoma has been linked to linked to saline water disposal from oil and gas production, and led to conversations about anthropogenic versus natural seismicity, regulation of saltwater disposal, and agency, industry, and governmental response. In early 2014, Kansas Governor Sam Brownback appointed a state task force to study and determine an appropriate response to increased seismic activity in south-central Kansas. That task force, which included representatives of the Kansas Geological Survey, Kansas Corporation Commission, and Kansas Department of Health and Environment, developed a response plan that included recommendations for enhanced monitoring and a seismic scoring formula that helps guide agency response to these events. The regional nature of this activity has led to coordination with the Oklahoma Geological Survey and the U.S. Geological Survey. In addition, the KGS has developed public information materials about induced seismicity. Also, Kansas is represented in national efforts to study and address the issue, including work by the Interstate Oil and Gas Compact Commission and Groundwater Protection Council, and development of a statement on induced seismicity from the Association of American State Geologists. The midcontinent has experienced a dramatic increase in seismic activity in the past several years. Seismic activity in Colorado, Arkansas, and Oklahoma has been linked to linked to saline water disposal from oil and gas production, and led to conversations about anthropogenic versus natural seismicity, regulation of saltwater disposal, and agency, industry, and governmental response. In early 2014, Kansas Governor Sam Brownback appointed a state task force to study and determine an appropriate response to increased seismic activity in south-central Kansas. That task force, which included representatives of the Kansas Geological Survey, Kansas Corporation Commission, and Kansas Department of Health and Environment, developed a response plan that included recommendations for enhanced monitoring and a seismic scoring formula that helps guide agency response to these events. The regional nature of this activity has led to coordination with the Oklahoma Geological Survey and the U.S. Geological Survey. In addition, the KGS has developed public information materials about induced seismicity. Also, Kansas is represented in national efforts to study and address the issue, including work by the Interstate Oil and Gas Compact Commission and Groundwater Protection Council, and development of a statement on induced seismicity from the Association of American State Geologists. Panel_15500 Panel_15500 10:10 AM 10:30 AM

Spatial, temporal and magnitude-frequency relationships for earthquakes occurring between 1976 and 1984 near Heron and El Vado reservoirs in northern New Mexico are examined for evidence of reservoir-induced seismicity (RIS). Most of the 264 located shocks, including those with the highest magnitude (mb = 3.8), occurred in 1982 when Heron reservoir reached its maximum capacity of approximately 0.5 km3 and an impoundment depth of 66 m. More recent data obtained with EarthScope’s transportable array suggests seismicity is continuing below the reservoirs. Between 1976 and 1984 earthquake swarms followed, or were enhanced by, reservoir filling where filling resulted in new maximum water volumes for Heron reservoir. Shocks generally cluster between the reservoirs in a region of north-south block faulting. A cumulative earthquake frequency versus magnitude plot for Heron-El Vado produced a “b-value” of 0.92 +/- 0.03 (1 SD) which is slightly higher than other b-values for northern New Mexico, and is consistent with b-values for reservoir-induced shocks in other areas. The spatial and temporal distribution of these events, along with their b-value, suggests most of them have been triggered by reservoir loading and elevated pore pressure. Practical implications are that RIS can occur in reservoirs with impounded water depths of less than 100 m – thus these formations may be acutely sensitive to waste fluid injection in the San Juan basin. Also, hydraulic diffusivity is are quite high, suggesting seismicity may onset almost immediately after an injection event. Spatial, temporal and magnitude-frequency relationships for earthquakes occurring between 1976 and 1984 near Heron and El Vado reservoirs in northern New Mexico are examined for evidence of reservoir-induced seismicity (RIS). Most of the 264 located shocks, including those with the highest magnitude (mb = 3.8), occurred in 1982 when Heron reservoir reached its maximum capacity of approximately 0.5 km3 and an impoundment depth of 66 m. More recent data obtained with EarthScope’s transportable array suggests seismicity is continuing below the reservoirs. Between 1976 and 1984 earthquake swarms followed, or were enhanced by, reservoir filling where filling resulted in new maximum water volumes for Heron reservoir. Shocks generally cluster between the reservoirs in a region of north-south block faulting. A cumulative earthquake frequency versus magnitude plot for Heron-El Vado produced a “b-value” of 0.92 +/- 0.03 (1 SD) which is slightly higher than other b-values for northern New Mexico, and is consistent with b-values for reservoir-induced shocks in other areas. The spatial and temporal distribution of these events, along with their b-value, suggests most of them have been triggered by reservoir loading and elevated pore pressure. Practical implications are that RIS can occur in reservoirs with impounded water depths of less than 100 m – thus these formations may be acutely sensitive to waste fluid injection in the San Juan basin. Also, hydraulic diffusivity is are quite high, suggesting seismicity may onset almost immediately after an injection event. Panel_15499 Panel_15499 10:30 AM 10:50 AM

Generation of earthquakes by injection of fluids at depth in sedimentary basins is a growing issue worldwide. The largest felt earthquakes generated in this manner originate in basement rock beneath sedimentary injection horizons. We examine geologic controls on transmission of fluid pressure across basal nonconformities into basement faults in an attempt to improve risk assessment for proposed injection sites. Although a considerable amount of previous work has investigated the controls on fluid flow in fault zones in sedimentary and crystalline basement rocks, few, if any, have investigated the hydrologic coupling of the two (faulted sedimentary/basement) systems. We have developed conceptual models of fault-zone permeability architecture of faulted nonconformities and refined the models using data from outcrop analogues in New Mexico and Colorado. Outcrop characterization included description of fault-zone architecture and basement and sedimentary section lithologic variation, and permeability distribution using a portable permeameter. The diagenetic history of the sites has also been investigated with an emphasis on determining the history of past fluid flow across the basement/sedimentary interface. Key variables that influence the permeability architecture of such coupled systems include: the degree of weathering of the nonconformity, timing of deformation relative to lithification, likelihood of fault mineralization, basal lithology, and the nature of mechanical infiltration of sediment into basement fracture networks. Our conceptual models will constrain numerical models to assess the risk of induced seismicity for a given site using commonly available geologic data. Generation of earthquakes by injection of fluids at depth in sedimentary basins is a growing issue worldwide. The largest felt earthquakes generated in this manner originate in basement rock beneath sedimentary injection horizons. We examine geologic controls on transmission of fluid pressure across basal nonconformities into basement faults in an attempt to improve risk assessment for proposed injection sites. Although a considerable amount of previous work has investigated the controls on fluid flow in fault zones in sedimentary and crystalline basement rocks, few, if any, have investigated the hydrologic coupling of the two (faulted sedimentary/basement) systems. We have developed conceptual models of fault-zone permeability architecture of faulted nonconformities and refined the models using data from outcrop analogues in New Mexico and Colorado. Outcrop characterization included description of fault-zone architecture and basement and sedimentary section lithologic variation, and permeability distribution using a portable permeameter. The diagenetic history of the sites has also been investigated with an emphasis on determining the history of past fluid flow across the basement/sedimentary interface. Key variables that influence the permeability architecture of such coupled systems include: the degree of weathering of the nonconformity, timing of deformation relative to lithification, likelihood of fault mineralization, basal lithology, and the nature of mechanical infiltration of sediment into basement fracture networks. Our conceptual models will constrain numerical models to assess the risk of induced seismicity for a given site using commonly available geologic data. Panel_15506 Panel_15506 10:50 AM 11:10 AM

The Cambro-Ordovician Arbuckle Group consists of laterally extensive shelf carbonates that unconformably overly Proterozoic basement or Cambrian strata. The thickness (~200 to 1400 ft), relatively high permeability (10 to 1500 mD), depth (>3500 ft), and naturally low pressure (below hydrostatic) of the Arbuckle have made it an ideal target for UIC Class I and II injection in Kansas, and more recently for proposed injection of CO2 for long-term storage (Class VI). However, a recent increase in the frequency and size of earthquakes in Harper and Sumner counties, southern Kansas, where coproduction and disposal of brines associated with development of the Mississippian play has been most active, has elevated concerns about the relationship between fluid injection and seismicity. To evaluate the impacts of fluid disposal within this area of recent seismicity and possible mitigating strategies, we are constructing a geologic model of the Arbuckle in Petrel™. The model will incorporate detailed stratigraphic and reservoir property analysis (e.g., ?, Sw, Vsh, k) of ~24 wells, covering a 600 km2area. The porosity of the Arbuckle will be estimated using multi-mineral quantitative formation evaluation, whereas the permeability of the formation will be estimated using a neural network, fuzzy logic, or alternative method pending availability of core data. The model will also incorporate faults identified from analysis of regional structure contour and isopach maps and potential field data. The geologic model will be upscaled into a dual-permeability compositional model for simulation in CMG™, which will be used to estimate changes in pore fluid pressure, the vertical and lateral extent of disposed fluids, and geomechanical stability of the formation. The geologic and simulation model could provide stakeholders tools and information to guide mitigation should seismicity in the area exceed thresholds established by the Kansas Seismic Action Plan. The Cambro-Ordovician Arbuckle Group consists of laterally extensive shelf carbonates that unconformably overly Proterozoic basement or Cambrian strata. The thickness (~200 to 1400 ft), relatively high permeability (10 to 1500 mD), depth (>3500 ft), and naturally low pressure (below hydrostatic) of the Arbuckle have made it an ideal target for UIC Class I and II injection in Kansas, and more recently for proposed injection of CO₂ for long-term storage (Class VI). However, a recent increase in the frequency and size of earthquakes in Harper and Sumner counties, southern Kansas, where coproduction and disposal of brines associated with development of the Mississippian play has been most active, has elevated concerns about the relationship between fluid injection and seismicity. To evaluate the impacts of fluid disposal within this area of recent seismicity and possible mitigating strategies, we are constructing a geologic model of the Arbuckle in Petrel™. The model will incorporate detailed stratigraphic and reservoir property analysis (e.g., ?, Sw, Vsh, k) of ~24 wells, covering a 600 km²area. The porosity of the Arbuckle will be estimated using multi-mineral quantitative formation evaluation, whereas the permeability of the formation will be estimated using a neural network, fuzzy logic, or alternative method pending availability of core data. The model will also incorporate faults identified from analysis of regional structure contour and isopach maps and potential field data. The geologic model will be upscaled into a dual-permeability compositional model for simulation in CMG™, which will be used to estimate changes in pore fluid pressure, the vertical and lateral extent of disposed fluids, and geomechanical stability of the formation. The geologic and simulation model could provide stakeholders tools and information to guide mitigation should seismicity in the area exceed thresholds established by the Kansas Seismic Action Plan. Panel_15505 Panel_15505 11:10 AM 11:30 AM

Starting in the mid-2000s, there has been an increase in seismic activity around areas where fluid injection was expanding because of shale development. As the injection rate increased, so did occurrences of earthquakes in the surrounding the area. Extensive studies have been done regarding the correlation between injection wells and induced seismicity (Frohlich 2012, Davis 1995). However, many injectors don’t cause earthquakes, and the boundaries between safe and high risk practice have yet to be defined. Also, there is often a time lag between the onset of injection and the occurrence of seismic activities – what controls that timescale? In order to encompass areas of injection with and without seismic activity, a reservoir simulation model was built for most of the Fort Worth Basin (FWB), including 374 wells with available relevant data located in the following counties: Denton, Ellis, Erath, Hill, Hood, Jack, Johnson, Palo Pinto, Parker, Somervell, Tarrant and Wise. The data needed for the simulation include minimum and maximum injection depths, monthly injection pressures and monthly volumes. The locations of major faults in the basin are being worked into the model to include the effects of transsmissive versus sealing faults on flow patterns. Preliminary simulation results show that where earthquakes occur, there is some spatial correlation with injection well locations. Furthermore, the modeling shows the quake areas have substantial increases in pore pressure due to injection. However, not all areas of increased pore pressure have induced earthquakes. Preliminary analysis suggests absence of induced seismicity in areas of elevated pore pressure might be attributed to shallow depth and lack of large pre-existing faults. Similar correlation difficulties are seen between the timing of injection and earthquake occurrence. The distance between the injector and the fault as well as the permeability-thickness (kh) of the injection formation are being investigated as controls on this time lag effect. Starting in the mid-2000s, there has been an increase in seismic activity around areas where fluid injection was expanding because of shale development. As the injection rate increased, so did occurrences of earthquakes in the surrounding the area. Extensive studies have been done regarding the correlation between injection wells and induced seismicity (Frohlich 2012, Davis 1995). However, many injectors don’t cause earthquakes, and the boundaries between safe and high risk practice have yet to be defined. Also, there is often a time lag between the onset of injection and the occurrence of seismic activities – what controls that timescale? In order to encompass areas of injection with and without seismic activity, a reservoir simulation model was built for most of the Fort Worth Basin (FWB), including 374 wells with available relevant data located in the following counties: Denton, Ellis, Erath, Hill, Hood, Jack, Johnson, Palo Pinto, Parker, Somervell, Tarrant and Wise. The data needed for the simulation include minimum and maximum injection depths, monthly injection pressures and monthly volumes. The locations of major faults in the basin are being worked into the model to include the effects of transsmissive versus sealing faults on flow patterns. Preliminary simulation results show that where earthquakes occur, there is some spatial correlation with injection well locations. Furthermore, the modeling shows the quake areas have substantial increases in pore pressure due to injection. However, not all areas of increased pore pressure have induced earthquakes. Preliminary analysis suggests absence of induced seismicity in areas of elevated pore pressure might be attributed to shallow depth and lack of large pre-existing faults. Similar correlation difficulties are seen between the timing of injection and earthquake occurrence. The distance between the injector and the fault as well as the permeability-thickness (kh) of the injection formation are being investigated as controls on this time lag effect. Panel_15503 Panel_15503 11:30 AM 11:50 AM

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Panel_14492 Panel_14492 8:00 AM 11:50 AM

Mudstone lithofacies are now known to be highly variable, impacting on all aspects of their source, seal and reservoir potential in different locations within the basin. Previously, much of this variability has been interpreted by examining chemical proxies and their subtle variability in redox sensitivities (particularly the presence of anoxia). However, some of the interpretations from geochemistry appear to be at odds with conclusions reached from the petrographic and detailed logging studies. The aim of this paper is investigate these discrepancies and refine stratigraphic models to provide a clear insight into how a source rock varies laterally within a basin. This is achieved by integrating detailed (sub-mm to 10s m scale) petrographic analyses of lithofacies (grain size, mineralogy, fabric), total organic carbon and inorganic geochemical data acquired from a well-constrained proximal to distal succession of Bashkirian-aged mudstones (beds enclosing the Bilinguites gracilis horizon) in the UK Pennsylvanian basin. Seven lithofacies have been identified in this study (using the combined approach of petrographic and geochemical analysis), which are either bioturbated or organized into thin graded beds. In proximal locations, facies are mainly silt-bearing, clay-rich mudstones with up to 2% TOC and contain <4.5 ppm U and <1.8 ppm Mo. In more distal locations the facies are broadly similar, but contain more clay and TOC (up to 8.9%), with higher concentrations of the redox sensitive elements, up to 25.1 ppm U and up to 205 ppm Mo. When integrated, as in this example, the datasets appear to provide a relatively consistent story, indicating that there are systematic differences in the grain size down the sediment transport path (reflected in compositional variability in the chemical data, and grain size in the petrology) and that typically more organic matter was preserved downdip in conditions that may have been prone to developing anoxia (high trace element concentrations). Somewhat counterintuitively, slower sediment accumulation rates updip (perhaps accommodation limited) may be the primary cause of the lateral differences. Sediment accumulation rates downdip were more continuous and faster, enabling a higher proportion of organic matter to be preserved by relatively continuous burial. This study demonstrates the need to integrate geochemical and petrographic methods when seeking to understand controls on source rock facies variability in basins. Mudstone lithofacies are now known to be highly variable, impacting on all aspects of their source, seal and reservoir potential in different locations within the basin. Previously, much of this variability has been interpreted by examining chemical proxies and their subtle variability in redox sensitivities (particularly the presence of anoxia). However, some of the interpretations from geochemistry appear to be at odds with conclusions reached from the petrographic and detailed logging studies. The aim of this paper is investigate these discrepancies and refine stratigraphic models to provide a clear insight into how a source rock varies laterally within a basin. This is achieved by integrating detailed (sub-mm to 10s m scale) petrographic analyses of lithofacies (grain size, mineralogy, fabric), total organic carbon and inorganic geochemical data acquired from a well-constrained proximal to distal succession of Bashkirian-aged mudstones (beds enclosing the Bilinguites gracilis horizon) in the UK Pennsylvanian basin. Seven lithofacies have been identified in this study (using the combined approach of petrographic and geochemical analysis), which are either bioturbated or organized into thin graded beds. In proximal locations, facies are mainly silt-bearing, clay-rich mudstones with up to 2% TOC and contain <4.5 ppm U and <1.8 ppm Mo. In more distal locations the facies are broadly similar, but contain more clay and TOC (up to 8.9%), with higher concentrations of the redox sensitive elements, up to 25.1 ppm U and up to 205 ppm Mo. When integrated, as in this example, the datasets appear to provide a relatively consistent story, indicating that there are systematic differences in the grain size down the sediment transport path (reflected in compositional variability in the chemical data, and grain size in the petrology) and that typically more organic matter was preserved downdip in conditions that may have been prone to developing anoxia (high trace element concentrations). Somewhat counterintuitively, slower sediment accumulation rates updip (perhaps accommodation limited) may be the primary cause of the lateral differences. Sediment accumulation rates downdip were more continuous and faster, enabling a higher proportion of organic matter to be preserved by relatively continuous burial. This study demonstrates the need to integrate geochemical and petrographic methods when seeking to understand controls on source rock facies variability in basins. Panel_15556 Panel_15556 8:05 AM 8:25 AM

The heterogeneity of source rocks is an aspect that is often ignored in basin modelling studies, but essential in the correct estimation of hydrocarbon generation, migration and trapping. Using a unique process-based modelling tool (OF-Mod) a detailed model was made on the organic facies of the Late Jurassic Hekkingen Formation. The Hekkingen Fm. is approximately time equivalent to other Late Jurassic source rocks: Spekk Fm. (central Norway), Draupne Fm. and Kimmeridge Fm. (North Sea). The Hammerfest Basin during the Late Jurassic has a complicated and poorly constrained tectonic and marine history [1], requiring several scenarios to be tested. The goal of this study was to provide models of the distribution of the inorganic (sand, shale) and organic (TOC, HI) fractions, which will be used as input in a separate basin modelling study [2]. The process-based modelling tool OF-Mod [3] was used to calculate the organic and inorganic properties at time of deposition. Multiple scenarios with varying key input parameters were tested, such as paleo-water depth, sedimentary systems, and the creation and preservation of organic matter. High resolution models were created: 100 layers vertically and 400 x 400 m horizontally. This is essential to reproduce the significant lateral and vertical changes in sand fraction and the organic components. A critical input is paleo-water depth: the basin configuration at time of deposition. This dictates the distribution of the various sedimentary facies. In this study two different paleo-water depth scenarios were tested, based on different tectonic scenarios. The modelled sand fraction in the basin was compared to well data from 11 sites, allowing the informed selection of the optimal paleo-water depth scenario. A second crucial aspect is the extent of anoxia, as this has a large influence on the fraction of organic matter which will be preserved. We compared modelled results (oxic and anoxic) with high resolution measurements of TOC and HI in 25 wells. This allowed the subdivision of the area in an oxygen rich and an anoxic area. Understanding the distribution of anoxia allows us to extrapolate this to areas where no wells are available for testing. This helps predict the possible carbon distribution and provides more realistic input for subsequent basin modelling. The heterogeneity of source rocks is an aspect that is often ignored in basin modelling studies, but essential in the correct estimation of hydrocarbon generation, migration and trapping. Using a unique process-based modelling tool (OF-Mod) a detailed model was made on the organic facies of the Late Jurassic Hekkingen Formation. The Hekkingen Fm. is approximately time equivalent to other Late Jurassic source rocks: Spekk Fm. (central Norway), Draupne Fm. and Kimmeridge Fm. (North Sea). The Hammerfest Basin during the Late Jurassic has a complicated and poorly constrained tectonic and marine history [1], requiring several scenarios to be tested. The goal of this study was to provide models of the distribution of the inorganic (sand, shale) and organic (TOC, HI) fractions, which will be used as input in a separate basin modelling study [2]. The process-based modelling tool OF-Mod [3] was used to calculate the organic and inorganic properties at time of deposition. Multiple scenarios with varying key input parameters were tested, such as paleo-water depth, sedimentary systems, and the creation and preservation of organic matter. High resolution models were created: 100 layers vertically and 400 x 400 m horizontally. This is essential to reproduce the significant lateral and vertical changes in sand fraction and the organic components. A critical input is paleo-water depth: the basin configuration at time of deposition. This dictates the distribution of the various sedimentary facies. In this study two different paleo-water depth scenarios were tested, based on different tectonic scenarios. The modelled sand fraction in the basin was compared to well data from 11 sites, allowing the informed selection of the optimal paleo-water depth scenario. A second crucial aspect is the extent of anoxia, as this has a large influence on the fraction of organic matter which will be preserved. We compared modelled results (oxic and anoxic) with high resolution measurements of TOC and HI in 25 wells. This allowed the subdivision of the area in an oxygen rich and an anoxic area. Understanding the distribution of anoxia allows us to extrapolate this to areas where no wells are available for testing. This helps predict the possible carbon distribution and provides more realistic input for subsequent basin modelling. Panel_15559 Panel_15559 8:25 AM 8:45 AM

This paper presents the findings of a integrated and comprehensive assessment of the oil generative potential for the Lower and Upper Bakken within the northern portion of the Williston Basin, using high resolution sampling of core from over 40 boreholes, analyses show the total organic carbon (wt% TOC) content for the Bakken Formation is not constant throughout any cored depth interval, but exhibits an extreme degree of variability both with depth and across northern portion of the Williston Basin. This is replicated by a variation in S1, S2, Tmax and HI across the study area and mirrored by the variation in yield of extractable organic matter (EOM), saturate, aromatic and NSO compounds as well as total sulphur, g.c.-fingerprint analysis, Pr/Ph ratios, short-chain/long-chain ratios, and the abundance and distribution in biomarkers. The dominant type of organic matter is a Type II fluorescing Bituminite, but relatively high amounts of total sulphur and organic sulphur within the kerogen indicate the localized presence of Type IIs, with implications for the early generation of hydrocarbon at low levels of thermal maturity. The presence of sulphur is supported by the relatively high abundance of aryl isoprenoids. A depth-wise and basin-wide variation in transition metal concentration, noteably Molybdium, Chromium, Nickel and Vanadium, key molecular ‘fingerprints’ and biomarkers within the Upper and Lower Bakken shales, indicate existence of stratified water column characterized by photic-zone anoxia during deposition. The presence of cyanobacteria, green sulfur bacteria (e.g., Chlorobiaceae) and the presence of anaerobic Bacterivorous Ciliates during the deposition of the Upper and Lower Bakken, suggest that the amorphous organic matter within the Bakken (identified as Bituminite) represents the bacterial reworking of primary organic matter by Bacterivorous Ciliates. Some of the broader implication from this study includes support for a paleo-water depth during the Upper and Lower Bakken that is at least 100m a mechanism and process that explains the origin and composition of the amorphous kerogen, an explanation for the presence of high amounts of sulphur and pyrite within the shale, the variation in organic matter content, variation in biomarker distribution and presents a challenge to the established notion that precursor organic matter is extensively reworked, and hence transformed into amorphous kerogen, exclusively within the sediment. This paper presents the findings of a integrated and comprehensive assessment of the oil generative potential for the Lower and Upper Bakken within the northern portion of the Williston Basin, using high resolution sampling of core from over 40 boreholes, analyses show the total organic carbon (wt% TOC) content for the Bakken Formation is not constant throughout any cored depth interval, but exhibits an extreme degree of variability both with depth and across northern portion of the Williston Basin. This is replicated by a variation in S1, S2, Tmax and HI across the study area and mirrored by the variation in yield of extractable organic matter (EOM), saturate, aromatic and NSO compounds as well as total sulphur, g.c.-fingerprint analysis, Pr/Ph ratios, short-chain/long-chain ratios, and the abundance and distribution in biomarkers. The dominant type of organic matter is a Type II fluorescing Bituminite, but relatively high amounts of total sulphur and organic sulphur within the kerogen indicate the localized presence of Type IIs, with implications for the early generation of hydrocarbon at low levels of thermal maturity. The presence of sulphur is supported by the relatively high abundance of aryl isoprenoids. A depth-wise and basin-wide variation in transition metal concentration, noteably Molybdium, Chromium, Nickel and Vanadium, key molecular ‘fingerprints’ and biomarkers within the Upper and Lower Bakken shales, indicate existence of stratified water column characterized by photic-zone anoxia during deposition. The presence of cyanobacteria, green sulfur bacteria (e.g., Chlorobiaceae) and the presence of anaerobic Bacterivorous Ciliates during the deposition of the Upper and Lower Bakken, suggest that the amorphous organic matter within the Bakken (identified as Bituminite) represents the bacterial reworking of primary organic matter by Bacterivorous Ciliates. Some of the broader implication from this study includes support for a paleo-water depth during the Upper and Lower Bakken that is at least 100m a mechanism and process that explains the origin and composition of the amorphous kerogen, an explanation for the presence of high amounts of sulphur and pyrite within the shale, the variation in organic matter content, variation in biomarker distribution and presents a challenge to the established notion that precursor organic matter is extensively reworked, and hence transformed into amorphous kerogen, exclusively within the sediment. Panel_15552 Panel_15552 8:45 AM 9:05 AM

The Fire Creek Siltstone, Shublik Formation, and Karen Creek Sandstone in northern Alaska record four third-fourth order depositional sequences. The Shublik, a proven Prudhoe Bay source rock, records geochemical, ichnologic, and facies evidence of significant variation in bottom water redox conditions, detrital input, and biological productivity. Low oxygen conditions facilitated both the accumulation of organic matter and development of abundant phosphatic facies that include both granular and nodular phosphorites. The Shublik is extremely heterogeneous containing claystone, organic-rich shale, bioclastic wackestone and packstone, sandstone, nodular and pebbly phosphorite, and phosphatic and glauconitic silt/sandstone. Facies are commonly stacked in shoaling upward cycles that evolve from organic-rich shales through phosphatic silt/sandstones to more carbonate rich facies. Total Organic Carbon (TOC) data in conjunction with redox sensitive trace metal concentrations, geochemical indicators of detrital input and bioproductivity, and ichnofabric analysis provide insight into the paleoceanographic changes concomitant with the development of different systems tracts during relative sea level change. The most organic rich facies (up to 4%) are usually contained within the Transgressive Systems Tract (TST) that commonly display the lowest ichnofabric indices. Redox sensitive geochemical indicators of low oxygen environments (Mo, V, U, Ni) are also concentrated over background levels within transgressive facies. Some HST facies, however, record relatively high TOC contents (1-2%) even when fairly coarse grained. Also, while these facies usually display much lower concentrations of redox sensitive trace metals they are commonly still elevated over background levels. This points to at least intermittent development of low oxygen conditions even during sea level highstand. The Shublik is commonly interpreted to represent deposition under upwelling conditions. We, however, also observe that some TOC-rich intervals display concentration of geochemical indicators of detrital input (Al, Si, Ti) and bioproductivity (Cu, Ni, Zn) above background levels. These relationships could point toward productivity driven by detrital input rather than upwelling of nutrients from deeper water. The Fire Creek Siltstone, Shublik Formation, and Karen Creek Sandstone in northern Alaska record four third-fourth order depositional sequences. The Shublik, a proven Prudhoe Bay source rock, records geochemical, ichnologic, and facies evidence of significant variation in bottom water redox conditions, detrital input, and biological productivity. Low oxygen conditions facilitated both the accumulation of organic matter and development of abundant phosphatic facies that include both granular and nodular phosphorites. The Shublik is extremely heterogeneous containing claystone, organic-rich shale, bioclastic wackestone and packstone, sandstone, nodular and pebbly phosphorite, and phosphatic and glauconitic silt/sandstone. Facies are commonly stacked in shoaling upward cycles that evolve from organic-rich shales through phosphatic silt/sandstones to more carbonate rich facies. Total Organic Carbon (TOC) data in conjunction with redox sensitive trace metal concentrations, geochemical indicators of detrital input and bioproductivity, and ichnofabric analysis provide insight into the paleoceanographic changes concomitant with the development of different systems tracts during relative sea level change. The most organic rich facies (up to 4%) are usually contained within the Transgressive Systems Tract (TST) that commonly display the lowest ichnofabric indices. Redox sensitive geochemical indicators of low oxygen environments (Mo, V, U, Ni) are also concentrated over background levels within transgressive facies. Some HST facies, however, record relatively high TOC contents (1-2%) even when fairly coarse grained. Also, while these facies usually display much lower concentrations of redox sensitive trace metals they are commonly still elevated over background levels. This points to at least intermittent development of low oxygen conditions even during sea level highstand. The Shublik is commonly interpreted to represent deposition under upwelling conditions. We, however, also observe that some TOC-rich intervals display concentration of geochemical indicators of detrital input (Al, Si, Ti) and bioproductivity (Cu, Ni, Zn) above background levels. These relationships could point toward productivity driven by detrital input rather than upwelling of nutrients from deeper water. Panel_15551 Panel_15551 9:05 AM 9:25 AM

Panel_15735 Panel_15735 9:25 AM 12:00 AM

The Niobrara Formation in the Denver Basin is an unconventional oil and gas play composed of alternating chalk and marl units. Key characterization parameters that provide an understanding of the distribution of source potential within the Niobrara include: total organic carbon (TOC), maturity level, mineralogy, thickness and organic matter type. Sample based results combined with full log suites including high resolution density, resistivity, sonic, porosity and spectral gamma ray logs will help in fully characterizing the Niobrara. Two widely used empirical approaches developed to quantitatively estimate TOC from log data are the Schmoker density log technique and the combination sonic or density and resistivity log technique known as ? log R. Other common methods for TOC estimation include using uranium or gamma ray logs as indicators of organic matter, although they often require a local calibration. This study compares the different methods of quantifying TOC from logs and how they apply to the Niobrara formation. Each method was analyzed and tested on the Niobrara Formation. The methods were then modified by recalibrating to core TOC data and applying new empirical relationships. Qualitative log indicators of elevated TOC include elevated neutron porosity, low bulk density, high sonic transit time, and high gamma ray or uranium. However, these measurements respond to more than just organic matter and therefore, interpretation of these logs in terms of organic matter requires accounting for the effect of mineralogy and fluids on log signatures in the Niobrara as well. The modified equations were used to quantify TOC in the Niobrara and a method was developed to classify organic-rich (high TOC) and organic-lean (low TOC) facies in an ordered manner. Statistical tools such as neural networks and decision tree analysis were then utilized to identify the best open hole log combinations that would be most predictive of those facies in wells that lack core TOC data. The Niobrara Formation in the Denver Basin is an unconventional oil and gas play composed of alternating chalk and marl units. Key characterization parameters that provide an understanding of the distribution of source potential within the Niobrara include: total organic carbon (TOC), maturity level, mineralogy, thickness and organic matter type. Sample based results combined with full log suites including high resolution density, resistivity, sonic, porosity and spectral gamma ray logs will help in fully characterizing the Niobrara. Two widely used empirical approaches developed to quantitatively estimate TOC from log data are the Schmoker density log technique and the combination sonic or density and resistivity log technique known as ? log R. Other common methods for TOC estimation include using uranium or gamma ray logs as indicators of organic matter, although they often require a local calibration. This study compares the different methods of quantifying TOC from logs and how they apply to the Niobrara formation. Each method was analyzed and tested on the Niobrara Formation. The methods were then modified by recalibrating to core TOC data and applying new empirical relationships. Qualitative log indicators of elevated TOC include elevated neutron porosity, low bulk density, high sonic transit time, and high gamma ray or uranium. However, these measurements respond to more than just organic matter and therefore, interpretation of these logs in terms of organic matter requires accounting for the effect of mineralogy and fluids on log signatures in the Niobrara as well. The modified equations were used to quantify TOC in the Niobrara and a method was developed to classify organic-rich (high TOC) and organic-lean (low TOC) facies in an ordered manner. Statistical tools such as neural networks and decision tree analysis were then utilized to identify the best open hole log combinations that would be most predictive of those facies in wells that lack core TOC data. Panel_15545 Panel_15545 10:10 AM 10:30 AM

The Upper Devonian Duvernay Formation is a significant unconventional exploration target in Alberta, particularly for liquids. We focus on the origin of heterogeneities in the Duvernay that are significant to the producibility of hydrocarbons. Sea level exerts a first order control on the sedimentology and stratigraphy of the Duvernay, which in turn are linked to mudstone composition and development of organic porosity. Establishing relationships between sea level cycles and shale porosity and permeability is an important part of our research. We report here on results and interpretations from long cores in five wells across the maturity gradient, including high resolution geochemical and petrophysical datasets. Interpretations are compared to a parallel sedimentological and stratigraphic analysis, providing an unusual opportunity for independent corroboration of models. Basinal facies are generally carbonate-poor mudstones, massive to finely laminated and typically enriched in pyrite. Shallower water facies are more carbonate-rich, often bioturbated, and contain a higher abundance of silt-sized shell debris. TOC decreases in carbonate-rich intervals but is unrelated to the clay content. Geochemical redox proxies indicate that deposition of TOC-rich intervals was associated with more reducing conditions. SiO2 varies inversely with carbonate content. We interpret a biogenic source for the silica. Shale composition exerts control over porosity and pore size distribution and the potential of the pore system to store and deliver gas. Data will be presented describing the relationships between geochemistry and pore system characteristics. Ion milled SEM photographs were analyzed for a range of TOC values. Types and abundance of porosity varied with TOC content. The lowest TOC sample had low porosity and was dominated by porosity hosted between mineral grains. The highest TOC sample had high porosity and was dominated by organic matter hosted porosity. A sample with intermediate TOC had a mix of porosity types. Organic matter content is highest in TST and HST deposits and increased biogenic silica creates brittle, non-fissile strata. By integrating geochemical properties and petrophysical parameters within the context of sea level, our goal is to improve the ability to identify and predict favourable locations where all factors affecting production are optimized. The Upper Devonian Duvernay Formation is a significant unconventional exploration target in Alberta, particularly for liquids. We focus on the origin of heterogeneities in the Duvernay that are significant to the producibility of hydrocarbons. Sea level exerts a first order control on the sedimentology and stratigraphy of the Duvernay, which in turn are linked to mudstone composition and development of organic porosity. Establishing relationships between sea level cycles and shale porosity and permeability is an important part of our research. We report here on results and interpretations from long cores in five wells across the maturity gradient, including high resolution geochemical and petrophysical datasets. Interpretations are compared to a parallel sedimentological and stratigraphic analysis, providing an unusual opportunity for independent corroboration of models. Basinal facies are generally carbonate-poor mudstones, massive to finely laminated and typically enriched in pyrite. Shallower water facies are more carbonate-rich, often bioturbated, and contain a higher abundance of silt-sized shell debris. TOC decreases in carbonate-rich intervals but is unrelated to the clay content. Geochemical redox proxies indicate that deposition of TOC-rich intervals was associated with more reducing conditions. SiO2 varies inversely with carbonate content. We interpret a biogenic source for the silica. Shale composition exerts control over porosity and pore size distribution and the potential of the pore system to store and deliver gas. Data will be presented describing the relationships between geochemistry and pore system characteristics. Ion milled SEM photographs were analyzed for a range of TOC values. Types and abundance of porosity varied with TOC content. The lowest TOC sample had low porosity and was dominated by porosity hosted between mineral grains. The highest TOC sample had high porosity and was dominated by organic matter hosted porosity. A sample with intermediate TOC had a mix of porosity types. Organic matter content is highest in TST and HST deposits and increased biogenic silica creates brittle, non-fissile strata. By integrating geochemical properties and petrophysical parameters within the context of sea level, our goal is to improve the ability to identify and predict favourable locations where all factors affecting production are optimized. Panel_15554 Panel_15554 10:30 AM 10:50 AM

The application of the Arrhenius equation to the problem of petroleum generation promises to predict hydrocarbon generation rates given experimentally defined kinetic parameters and temperature. There are several ways to determine kinetic parameters. In most, if not all of these methods, small variations in experimental conditions result in a linear covariance between activation energy (Ea) and the natural log of the frequency factor (A). This covariance is usually referred to as the compensation effect, the underlying cause of which is debated. However, experimental compensation effects frequently include frequency factors that are thermodynamically impossible. Based on thermodynamic arguments, the frequency factor should be largely unaffected by temperature and as a consequence be nearly constant. The covariance in A and Ea is explained from a statistical standpoint by noting that random experimental errors, particularly in temperature, result in “best fit” solutions to some experimental variable, usually temperature. Solutions for Ea and A that incorporate these errors lie within an extremely elongated ellipse that coincides with the compensation effect. An analytical solution exists that relates the harmonic mean of experimental temperatures containing random errors to the slope of the resulting compensation effect. “Compensation effects” from numerical simulations of programmed pyrolysis experiments containing random temperature errors are consistent with the analytical solution. Furthermore, calculated compensation effects using experimental temperatures are very close to the compensation effect obtained from non-isothermal kinetic analyses of samples from the Bakken (Miss-Dev) and Red River (Ord.) formations. The compensation effect is largely due to temperature errors that may be corrected to a constant value of A using the harmonic mean of the peak reaction temperatures. Assuming a constant frequency factor allows “correct” activation energies to be obtained. When done, corrected values of Ea from the Bakken (Type II) change more rapidly with depth than do samples from the Red River (Type I). A map of “corrected” activation energies from the Bakken Formation is consistent with current notions of the formation’s thermal maturity within the Williston Basin of North Dakota. The application of the Arrhenius equation to the problem of petroleum generation promises to predict hydrocarbon generation rates given experimentally defined kinetic parameters and temperature. There are several ways to determine kinetic parameters. In most, if not all of these methods, small variations in experimental conditions result in a linear covariance between activation energy (Ea) and the natural log of the frequency factor (A). This covariance is usually referred to as the compensation effect, the underlying cause of which is debated. However, experimental compensation effects frequently include frequency factors that are thermodynamically impossible. Based on thermodynamic arguments, the frequency factor should be largely unaffected by temperature and as a consequence be nearly constant. The covariance in A and Ea is explained from a statistical standpoint by noting that random experimental errors, particularly in temperature, result in “best fit” solutions to some experimental variable, usually temperature. Solutions for Ea and A that incorporate these errors lie within an extremely elongated ellipse that coincides with the compensation effect. An analytical solution exists that relates the harmonic mean of experimental temperatures containing random errors to the slope of the resulting compensation effect. “Compensation effects” from numerical simulations of programmed pyrolysis experiments containing random temperature errors are consistent with the analytical solution. Furthermore, calculated compensation effects using experimental temperatures are very close to the compensation effect obtained from non-isothermal kinetic analyses of samples from the Bakken (Miss-Dev) and Red River (Ord.) formations. The compensation effect is largely due to temperature errors that may be corrected to a constant value of A using the harmonic mean of the peak reaction temperatures. Assuming a constant frequency factor allows “correct” activation energies to be obtained. When done, corrected values of Ea from the Bakken (Type II) change more rapidly with depth than do samples from the Red River (Type I). A map of “corrected” activation energies from the Bakken Formation is consistent with current notions of the formation’s thermal maturity within the Williston Basin of North Dakota. Panel_15557 Panel_15557 10:50 AM 11:10 AM

Source rock kerogen hydrogen indices and transformation ratios are frequently used as thermal maturation surrogates, and as proxies for calculating the amount of hydrocarbons generated from a thermally mature source rock, assuming an original hydrogen index can be assigned to the source rock. Transformation ratio (TR) and hydrogen index (HI) are commonly assumed to be linearly related via TR = (HIo – HI)/HIo, where HIo is a constant – the immature source rock’s average original hydrogen index – and HI is the present day hydrogen index. In reality, however, the TR-HI relationship is shown to be non-linear. That non-linearity manifests itself most markedly in highly oil-prone, high original HI source rocks, which has important petroleum exploration implications. For example, an area where the present day HI is ~550 for an oil-prone source with HIo = 700 would traditionally calculate at a TR = ~20%. However, its true TR is ~40%. Therefore, areas where the source transformation ratio has traditionally been calculated as too low to have generated / expelled commercial amounts of hydrocarbons may in fact have transformation ratios which do imply significant hydrocarbon generation and expulsion. Examples and application are presented. Source rock kerogen hydrogen indices and transformation ratios are frequently used as thermal maturation surrogates, and as proxies for calculating the amount of hydrocarbons generated from a thermally mature source rock, assuming an original hydrogen index can be assigned to the source rock. Transformation ratio (TR) and hydrogen index (HI) are commonly assumed to be linearly related via TR = (HIo – HI)/HIo, where HIo is a constant – the immature source rock’s average original hydrogen index – and HI is the present day hydrogen index. In reality, however, the TR-HI relationship is shown to be non-linear. That non-linearity manifests itself most markedly in highly oil-prone, high original HI source rocks, which has important petroleum exploration implications. For example, an area where the present day HI is ~550 for an oil-prone source with HIo = 700 would traditionally calculate at a TR = ~20%. However, its true TR is ~40%. Therefore, areas where the source transformation ratio has traditionally been calculated as too low to have generated / expelled commercial amounts of hydrocarbons may in fact have transformation ratios which do imply significant hydrocarbon generation and expulsion. Examples and application are presented. Panel_15555 Panel_15555 11:10 AM 11:30 AM

Mapping thermal maturity across a basin of interest is one of the most basic tasks a geoscientist undertakes when exploring for hydrocarbons, particularly in unconventional shale plays. Some difficulties can arise with traditional thermal maturation assessment tools, however. For example, optical evaluation of cuttings with little to no vitrinite, or cuttings which have been dried at excessively high heat, can be misleading. In addition, the correlation of Rock-Eval Tmax to %Ro varies, depending on the kerogen type and/or the source rock’s bitumen content. Data from produced fluids are often not available in areas of frontier exploration. The source organic facies frequently varies greatly through the sediment column, making maturity assessments based on Hydrogen Index (HI) or Transformation Ratio (TR) difficult, since each organic facies will have a different original HI. A very effective way around this difficulty is to use the activation-energy (Ea) distribution for kerogens, because while the original HI of the various organic facies may vary due to changes in preservation, their Ea distributions will not, if the organic matter input remains relatively uniform during deposition. One-run kinetic analyses using a fixed A is a technology well suited to this approach. An alternative approach is to model the transformation of the various organic facies using a kinetic profile reasonable for the particular kerogen type, based on knowledge of the depositional environment. This approach allows one to fit the modeled kinetic transforms to Hydrogen Index data and more confidently assess the Transformation Ratio of the organic matter within a sediment column at a single well. It also permits the Tmax-%Ro relationship to be adjusted to fit the pyrolysis data and the modeled kinetic transform. Thus, maturity over a basin can be mapped quickly and often with excellent accuracy if one has enough pyrolysis data over the basin. If produced fluid data are available, the model can be calibrated to those data. This workflow will be demonstrated in an example from a North American basin. Mapping thermal maturity across a basin of interest is one of the most basic tasks a geoscientist undertakes when exploring for hydrocarbons, particularly in unconventional shale plays. Some difficulties can arise with traditional thermal maturation assessment tools, however. For example, optical evaluation of cuttings with little to no vitrinite, or cuttings which have been dried at excessively high heat, can be misleading. In addition, the correlation of Rock-Eval Tmax to %Ro varies, depending on the kerogen type and/or the source rock’s bitumen content. Data from produced fluids are often not available in areas of frontier exploration. The source organic facies frequently varies greatly through the sediment column, making maturity assessments based on Hydrogen Index (HI) or Transformation Ratio (TR) difficult, since each organic facies will have a different original HI. A very effective way around this difficulty is to use the activation-energy (Ea) distribution for kerogens, because while the original HI of the various organic facies may vary due to changes in preservation, their Ea distributions will not, if the organic matter input remains relatively uniform during deposition. One-run kinetic analyses using a fixed A is a technology well suited to this approach. An alternative approach is to model the transformation of the various organic facies using a kinetic profile reasonable for the particular kerogen type, based on knowledge of the depositional environment. This approach allows one to fit the modeled kinetic transforms to Hydrogen Index data and more confidently assess the Transformation Ratio of the organic matter within a sediment column at a single well. It also permits the Tmax-%Ro relationship to be adjusted to fit the pyrolysis data and the modeled kinetic transform. Thus, maturity over a basin can be mapped quickly and often with excellent accuracy if one has enough pyrolysis data over the basin. If produced fluid data are available, the model can be calibrated to those data. This workflow will be demonstrated in an example from a North American basin. Panel_15558 Panel_15558 11:30 AM 11:50 AM

Panel_14458 Panel_14458 8:00 AM 11:50 AM

Panel_15736 Panel_15736 8:00 AM 12:00 AM

Facies based reservoir modeling has long been influenced by studies of outcrop analogs and modern systems. Outcrops typically provide cross sectional data on element geometries while modern systems provide data on the plan view dimensions of elements and their lateral relationships with surrounding facies. The advent of free remote sensing data (Google Earth etc) has improved the availability of modern analogs but selection is commonly undertaken on an adhoc basis and it can be difficult to identify suitable parts of the World to use. The goal of this study has been to develop a methodology for the systematic identification of modern analogs based upon parameters such as, depositional environment and processes; tectonic setting and basin type; climate and latitude. The second stage is to automatically extract geometric data from architectural elements as inputs for reservoir modeling. Given that sedimentary systems in basins are significantly different to their counterparts in areas of net erosion, the first stage of the work was to distinguish modern day basins from areas of net degradation at a global scale. This was done using a series of GiS layers which mapped combinations of gradient and bedrock geology. The result suggests that only 16% of the Earth’s land surface lies within basins. The remainder will not be represented in any future rock record and should not be used for analog studies. The second stage of the work flow was to superimpose layers for climate and tectonic setting. The results of this work suggest that arid systems are over represented in basins (27% of earths land but 60% of basins). To address depositional process in the shallow marine realm, a model was built which incorporates data on tidal range, mean wave height and proximity to, and size of, fluvial input points. This allows a relatively coarse (5km segments) classification of the global coastline on a WTF plot. Classification of continental environments was based on subdivision into fluvial, eolian and lacustrine. This was achieved at the global scale by the automated identification of water bodies (lacustrine systems) and the mapping of eolian deposits. As with the shallow marine systems these can then be subdivided by climate, basin type and latitude. Final a series of tools have been developed to automatically extract geometric data on architectural elements for input to object-based, variogram-based and multi-point statistical reservoir modelling packages. Facies based reservoir modeling has long been influenced by studies of outcrop analogs and modern systems. Outcrops typically provide cross sectional data on element geometries while modern systems provide data on the plan view dimensions of elements and their lateral relationships with surrounding facies. The advent of free remote sensing data (Google Earth etc) has improved the availability of modern analogs but selection is commonly undertaken on an adhoc basis and it can be difficult to identify suitable parts of the World to use. The goal of this study has been to develop a methodology for the systematic identification of modern analogs based upon parameters such as, depositional environment and processes; tectonic setting and basin type; climate and latitude. The second stage is to automatically extract geometric data from architectural elements as inputs for reservoir modeling. Given that sedimentary systems in basins are significantly different to their counterparts in areas of net erosion, the first stage of the work was to distinguish modern day basins from areas of net degradation at a global scale. This was done using a series of GiS layers which mapped combinations of gradient and bedrock geology. The result suggests that only 16% of the Earth’s land surface lies within basins. The remainder will not be represented in any future rock record and should not be used for analog studies. The second stage of the work flow was to superimpose layers for climate and tectonic setting. The results of this work suggest that arid systems are over represented in basins (27% of earths land but 60% of basins). To address depositional process in the shallow marine realm, a model was built which incorporates data on tidal range, mean wave height and proximity to, and size of, fluvial input points. This allows a relatively coarse (5km segments) classification of the global coastline on a WTF plot. Classification of continental environments was based on subdivision into fluvial, eolian and lacustrine. This was achieved at the global scale by the automated identification of water bodies (lacustrine systems) and the mapping of eolian deposits. As with the shallow marine systems these can then be subdivided by climate, basin type and latitude. Final a series of tools have been developed to automatically extract geometric data on architectural elements for input to object-based, variogram-based and multi-point statistical reservoir modelling packages. Panel_15219 Panel_15219 8:05 AM 8:25 AM

The appraisal and development phases of deepwater Wilcox and Miocene Gulf of Mexico hydrocarbon reservoirs bring a requirement for higher resolution mapping and modelling to each project. Accurate geologic modelling of the reservoir is necessary to optimise well placement and the overall development scenario as well as ensuring safe drilling practices through shallow hazard detection and assessment. We demonstrate the utility of taking a quantitative seismic stratigraphic approach to characterising deepwater channel facies and architecture in a high resolution, shallow seismic dataset. The method and application of the characterization is twofold: 1. Direct application in the shallow section as identification of reservoir facies distributions or potential shallow drilling hazards. 2. Use high resolution facies mapping and architecture as a quantitative analogue for reservoir intervals in regions of poor seismic quality. A single channel complex located in the Choctaw Basin, Gulf of Mexico was chosen to provide proof-of-concept for the methodology. Using high definition frequency decomposition and colour blending techniques the internal variability and geometries of the individual channel elements were mapped, and gave the necessary vertical resolution to image the smaller components within the system, increasing accuracy of positioning and extents of the imaged structures. With the seismic facies classification these channel complexes were extracted directly from the colour blend, as geobodies, giving the foundation for a geological model without the need for manual horizon picking. This technique enabled the extraction of sub-element scale features within channels which can neither be accurately imaged in other, single-volume attributes, nor manually interpreted as horizons in a feasible manner. Seismic attributes, facies, and geobodies were imported into geomodeling software where final lithologic mapping and modelling were completed to glean all applicable quantitative information and trends. Overall, the technique resulted in mapped facies distributions resembling known deepwater channel facies distributions from recently published outcrop and subsurface datasets providing a validation appropriate for the quality of input data. The appraisal and development phases of deepwater Wilcox and Miocene Gulf of Mexico hydrocarbon reservoirs bring a requirement for higher resolution mapping and modelling to each project. Accurate geologic modelling of the reservoir is necessary to optimise well placement and the overall development scenario as well as ensuring safe drilling practices through shallow hazard detection and assessment. We demonstrate the utility of taking a quantitative seismic stratigraphic approach to characterising deepwater channel facies and architecture in a high resolution, shallow seismic dataset. The method and application of the characterization is twofold: 1. Direct application in the shallow section as identification of reservoir facies distributions or potential shallow drilling hazards. 2. Use high resolution facies mapping and architecture as a quantitative analogue for reservoir intervals in regions of poor seismic quality. A single channel complex located in the Choctaw Basin, Gulf of Mexico was chosen to provide proof-of-concept for the methodology. Using high definition frequency decomposition and colour blending techniques the internal variability and geometries of the individual channel elements were mapped, and gave the necessary vertical resolution to image the smaller components within the system, increasing accuracy of positioning and extents of the imaged structures. With the seismic facies classification these channel complexes were extracted directly from the colour blend, as geobodies, giving the foundation for a geological model without the need for manual horizon picking. This technique enabled the extraction of sub-element scale features within channels which can neither be accurately imaged in other, single-volume attributes, nor manually interpreted as horizons in a feasible manner. Seismic attributes, facies, and geobodies were imported into geomodeling software where final lithologic mapping and modelling were completed to glean all applicable quantitative information and trends. Overall, the technique resulted in mapped facies distributions resembling known deepwater channel facies distributions from recently published outcrop and subsurface datasets providing a validation appropriate for the quality of input data. Panel_15223 Panel_15223 8:25 AM 8:45 AM

As petroleum exploration ventures further offshore, the ability to more accurately predict and characterize the architecture of deep-water slope deposits is increasingly important. With well costs of 100’s of millions of dollars, limited seismic resolution, and sparse well control, insight beyond well and seismic data is of increased importance. Leveraging outcrop analogs can aid in understanding the impact of inter- and intra-channel architecture on pay connectivity. Such architecture is generally below the resolution of subsurface seismic-reflection imaging and is difficult to deduce from well data. A high-resolution digital model of stacked, deep-water channels from the Laguna Figueroa section of the Late Cretaceous Tres Pasos Formation in Chile was created. This model is based on > 1,600 meters of cm-scale measured section, > 100 paleoflow measurements, and 1,000’s of dGPS points (10 cm accuracy) from a well-exposed outcrop belt 2.5 km long and 130 m thick. The model elucidates the effects of facies relationships and intra-channel architecture on channel connectivity. The model captures observed facies geometries at a resolution of 2 m horizontally and 1/4 m vertically (~600M cells). Emphasis was placed on accurate and detailed intra-channel architecture. Three channel width (200, 250, and 300 m) models and two channel base drape (CBD) scenarios were created, for a total of six models. Static connectivity analyses were performed on the models by (1) calculating an overall model value; (2) by channel pair to assess connectivity through stratigraphy; and (3) down depositional-dip to capture planview connectivity variability. As such a fine-scale model would likely not be used in flow simulations, an upscaling analysis was performed to explore architecture degradation and its effects on connectivity. Results of the connectivity analysis show that the CBD scenarios strongly impact sandstone connectivity and that smaller channel widths are more susceptible to poor connectivity and disconnected sandstone. Net-to-gross was calculated to explore its relationship with connectivity metrics. Upscaling the models consistently increases connectivity, and small changes in cell geometry impact architecture, which can artificially induce connectivity. Ultimately, this work aims to constrain uncertainty related to sub-seismic scale architecture and its impact on reservoir connectivity by providing concrete connectivity data and contributing to better predictive models. As petroleum exploration ventures further offshore, the ability to more accurately predict and characterize the architecture of deep-water slope deposits is increasingly important. With well costs of 100’s of millions of dollars, limited seismic resolution, and sparse well control, insight beyond well and seismic data is of increased importance. Leveraging outcrop analogs can aid in understanding the impact of inter- and intra-channel architecture on pay connectivity. Such architecture is generally below the resolution of subsurface seismic-reflection imaging and is difficult to deduce from well data. A high-resolution digital model of stacked, deep-water channels from the Laguna Figueroa section of the Late Cretaceous Tres Pasos Formation in Chile was created. This model is based on > 1,600 meters of cm-scale measured section, > 100 paleoflow measurements, and 1,000’s of dGPS points (10 cm accuracy) from a well-exposed outcrop belt 2.5 km long and 130 m thick. The model elucidates the effects of facies relationships and intra-channel architecture on channel connectivity. The model captures observed facies geometries at a resolution of 2 m horizontally and 1/4 m vertically (~600M cells). Emphasis was placed on accurate and detailed intra-channel architecture. Three channel width (200, 250, and 300 m) models and two channel base drape (CBD) scenarios were created, for a total of six models. Static connectivity analyses were performed on the models by (1) calculating an overall model value; (2) by channel pair to assess connectivity through stratigraphy; and (3) down depositional-dip to capture planview connectivity variability. As such a fine-scale model would likely not be used in flow simulations, an upscaling analysis was performed to explore architecture degradation and its effects on connectivity. Results of the connectivity analysis show that the CBD scenarios strongly impact sandstone connectivity and that smaller channel widths are more susceptible to poor connectivity and disconnected sandstone. Net-to-gross was calculated to explore its relationship with connectivity metrics. Upscaling the models consistently increases connectivity, and small changes in cell geometry impact architecture, which can artificially induce connectivity. Ultimately, this work aims to constrain uncertainty related to sub-seismic scale architecture and its impact on reservoir connectivity by providing concrete connectivity data and contributing to better predictive models. Panel_15218 Panel_15218 8:45 AM 9:05 AM

Current models for deepwater sediment sources call upon conduit-fed slope canyons bringing sediments in to steep-sloped settings, generating turbidite-driven basinward sediment transport. However, new findings in shelf environments suggest that shelfal processes can play a large role in line-sourcing sediment plumes directly from the shelf, absent of slope conduits. In addition, distal shelf settings, once thought to be devoid of reservoir quality sediments are increasingly the target of low-net:gross exploration efforts, whose risk can be reduced through careful understanding of outer shelf sediment distributions. A series of experimental studies have been performed in a large, non-recirculating flume to test plunging hyperpycnal plumes (PHP) as a viable means for cross-shelf sand transport to middle and outer shelf locations, and potentially to deeper-water locations. PHP result from storm-flood events bringing in huge amounts of sediments into the shelf. However, these plumes are believed to die off quickly as they cannot maintain their turbulence due to the gentle nature of shelf slopes. Modern studies at Eel River, California suggest that high wave energy present during storms has a significant role in maintaining the turbulence within the wave boundary layer allowing the undercurrent to sustain its flow and keep suspended sediment from settling. In our studies, we physically model the interaction of storm-produced gravity waves and the hyperpycnal plumes generated due to storm-associated flood events, and how change in the current and wave characteristics affect the sediment transport. The results of physical models have been combined with field study, which examine the nature of hummocky cross-stratified sands in shelfal settings around the world. Current paradigms assume these sediments to be deposited above storm wave base. However, the results of preliminary experiments suggest that wave energy can get embedded into and carried forward with the current, suggesting a need to reconsider the origin of wave-formed sedimentary structures in all shelf settings. Such reconsideration has implications for interpretation of environmental settings, paleo-climate models, paleo-water depth assessments and understanding of reservoir nature and distribution in distal shelf and deepwater settings. Current models for deepwater sediment sources call upon conduit-fed slope canyons bringing sediments in to steep-sloped settings, generating turbidite-driven basinward sediment transport. However, new findings in shelf environments suggest that shelfal processes can play a large role in line-sourcing sediment plumes directly from the shelf, absent of slope conduits. In addition, distal shelf settings, once thought to be devoid of reservoir quality sediments are increasingly the target of low-net:gross exploration efforts, whose risk can be reduced through careful understanding of outer shelf sediment distributions. A series of experimental studies have been performed in a large, non-recirculating flume to test plunging hyperpycnal plumes (PHP) as a viable means for cross-shelf sand transport to middle and outer shelf locations, and potentially to deeper-water locations. PHP result from storm-flood events bringing in huge amounts of sediments into the shelf. However, these plumes are believed to die off quickly as they cannot maintain their turbulence due to the gentle nature of shelf slopes. Modern studies at Eel River, California suggest that high wave energy present during storms has a significant role in maintaining the turbulence within the wave boundary layer allowing the undercurrent to sustain its flow and keep suspended sediment from settling. In our studies, we physically model the interaction of storm-produced gravity waves and the hyperpycnal plumes generated due to storm-associated flood events, and how change in the current and wave characteristics affect the sediment transport. The results of physical models have been combined with field study, which examine the nature of hummocky cross-stratified sands in shelfal settings around the world. Current paradigms assume these sediments to be deposited above storm wave base. However, the results of preliminary experiments suggest that wave energy can get embedded into and carried forward with the current, suggesting a need to reconsider the origin of wave-formed sedimentary structures in all shelf settings. Such reconsideration has implications for interpretation of environmental settings, paleo-climate models, paleo-water depth assessments and understanding of reservoir nature and distribution in distal shelf and deepwater settings. Panel_15220 Panel_15220 9:05 AM 9:25 AM

Panel_15737 Panel_15737 9:25 AM 12:00 AM

The Upper Cretaceous Blackhawk Formation, Castlegate Sandstone, and related strata exposed in the Book Cliffs of east-central Utah are widely used as an archetype for the sequence stratigraphy of marginal-marine and shallow-marine strata. Stratigraphic architectures in these strata are classically interpreted to reflect forcing by relative sea level. However, key aspects can instead be attributed to variations in sediment flux, which are characterised using a mass-balance framework that captures the rate of upsystem-to-downsystem loss of sediment (mass) and the spatial distribution of accommodation. Facies partitioning and sediment budgets are estimated for eight stratigraphic intervals, in order to compare temporal dynamics of the sediment routing system from erosional source to depositional sink. Mapping of each stratigraphic interval and its constituent segments, from upsystem to downsystem, was achieved along a representative, dip-oriented 2D cross section over a distance of c. 350 km. The cross section provides time-averaged estimates of the spatial distribution of deposition in each interval. Sediment supply characteristics for each of the eight stratigraphic intervals are constrained by total facies proportions in each interval. Comparison of the downsystem mass-balance characteristics of the eight stratigraphic intervals suggests that there were depositional gains and losses of shallow-marine shale in the five youngest intervals, which can be attributed to along-strike sediment transport. This result is consistent with increased interaction through time with vigorous wave- and tide-driven circulation in the seaway, as the sediment-routing system advanced out of a sheltered embayment in response to decreasing tectonic subsidence rate. In the youngest stratigraphic interval, the upstream-unconformable base of the Castlegate Sandstone is marked by a pronounced increase in the sand- to gravel-grade mass fraction of the fluvially supplied depositional volume. This marked increase can be attributed to hinterland unroofing and/or cannibalization of wedge-top basins, leading to export of coarse-grained sediment into the Castlegate fluvial system. Our results demonstrate the value of analyzing downsystem sediment loss within a mass-balance framework as a simple and practical tool to quantify the relationship between accommodation and sediment supply, and thus to decode past external forcing mechanisms from stratigraphic architecture. The Upper Cretaceous Blackhawk Formation, Castlegate Sandstone, and related strata exposed in the Book Cliffs of east-central Utah are widely used as an archetype for the sequence stratigraphy of marginal-marine and shallow-marine strata. Stratigraphic architectures in these strata are classically interpreted to reflect forcing by relative sea level. However, key aspects can instead be attributed to variations in sediment flux, which are characterised using a mass-balance framework that captures the rate of upsystem-to-downsystem loss of sediment (mass) and the spatial distribution of accommodation. Facies partitioning and sediment budgets are estimated for eight stratigraphic intervals, in order to compare temporal dynamics of the sediment routing system from erosional source to depositional sink. Mapping of each stratigraphic interval and its constituent segments, from upsystem to downsystem, was achieved along a representative, dip-oriented 2D cross section over a distance of c. 350 km. The cross section provides time-averaged estimates of the spatial distribution of deposition in each interval. Sediment supply characteristics for each of the eight stratigraphic intervals are constrained by total facies proportions in each interval. Comparison of the downsystem mass-balance characteristics of the eight stratigraphic intervals suggests that there were depositional gains and losses of shallow-marine shale in the five youngest intervals, which can be attributed to along-strike sediment transport. This result is consistent with increased interaction through time with vigorous wave- and tide-driven circulation in the seaway, as the sediment-routing system advanced out of a sheltered embayment in response to decreasing tectonic subsidence rate. In the youngest stratigraphic interval, the upstream-unconformable base of the Castlegate Sandstone is marked by a pronounced increase in the sand- to gravel-grade mass fraction of the fluvially supplied depositional volume. This marked increase can be attributed to hinterland unroofing and/or cannibalization of wedge-top basins, leading to export of coarse-grained sediment into the Castlegate fluvial system. Our results demonstrate the value of analyzing downsystem sediment loss within a mass-balance framework as a simple and practical tool to quantify the relationship between accommodation and sediment supply, and thus to decode past external forcing mechanisms from stratigraphic architecture. Panel_15224 Panel_15224 10:10 AM 10:30 AM

Accurately capturing flow path connectivity in reservoir models is critical to predicting fluid flow performance. In deep-water slope channel reservoirs, flow path connectivity is controlled by multi-scale stratigraphy including a combination of sub-seismic internal channel architecture and the stacking patterns of channels into channel complexes. Fine-scale architecture (e.g., channel base drapes) has a first order control on connectivity. Upscaling consistently increases connectivity and even small changes in cell geometry impacts architecture and artificially induces connectivity. In order to optimize the upscaling process, a high-resolution geocellular model of stacked, deep-water channels from the Laguna Figueroa section of the Late Cretaceous Tres Pasos Formation in Chile was used. The three-dimensional outcrop model of deep-water slope channels from the Cretaceous Tres Pasos Formation in the Magallanes Basin of Chile captures observed facies geometries at a resolution of 2 m horizontally and 1/4 m vertically (~600M cells). The goal was to find the optimal upscaling workflow while honoring static connectivity metrics. Results show that methods which preferentially preserve facies relationships across channel element boundaries consistently most closely matched static connectivity metrics from the fine-scale grid. These methods were considered most successful as the fine-scale grid is assumed to be the most accurate, and therefore most useful to preserve. Furthermore, flow simulation results showed more consistent pressure communication and sweep efficiency in upscaled models that preserved fine-scale connectivity metrics. Accurately capturing flow path connectivity in reservoir models is critical to predicting fluid flow performance. In deep-water slope channel reservoirs, flow path connectivity is controlled by multi-scale stratigraphy including a combination of sub-seismic internal channel architecture and the stacking patterns of channels into channel complexes. Fine-scale architecture (e.g., channel base drapes) has a first order control on connectivity. Upscaling consistently increases connectivity and even small changes in cell geometry impacts architecture and artificially induces connectivity. In order to optimize the upscaling process, a high-resolution geocellular model of stacked, deep-water channels from the Laguna Figueroa section of the Late Cretaceous Tres Pasos Formation in Chile was used. The three-dimensional outcrop model of deep-water slope channels from the Cretaceous Tres Pasos Formation in the Magallanes Basin of Chile captures observed facies geometries at a resolution of 2 m horizontally and 1/4 m vertically (~600M cells). The goal was to find the optimal upscaling workflow while honoring static connectivity metrics. Results show that methods which preferentially preserve facies relationships across channel element boundaries consistently most closely matched static connectivity metrics from the fine-scale grid. These methods were considered most successful as the fine-scale grid is assumed to be the most accurate, and therefore most useful to preserve. Furthermore, flow simulation results showed more consistent pressure communication and sweep efficiency in upscaled models that preserved fine-scale connectivity metrics. Panel_15217 Panel_15217 10:30 AM 10:50 AM

Stacking patterns describe how channelized deposits are spatially located relative to one another. Three methods are used to describe stacking patterns in fluvial systems: (1) clustering, (2) compensation, and (3) connectivity. Clustering is defined as a close grouping of a set of channels. Compensational stacking is defined as the tendency of a sediment transport system to fill in topographic lows resulting in a semi-organized stacking pattern. Connectivity is defined as the degree of sand-on-sand contacts between stratigraphically adjacent channel belts. This study uses outcrop measurements to document how clustering, compensational stacking, and connectivity of fluvial channel belts relate to lateral confinement. To address this goal we quantitatively compare outcrop architectural styles of the valley-confined Dakota Sandstone to the unconfined-dispersive fluvial system in the lower Wasatch Formation, both exposed in Utah. At each locality we documented the following: (1) cluster size, (2) cluster shape in 3 dimensions, (3) paleocurrents, (4) channel-belt types and styles (eg-single or multistory and accretion style), and (5) connectivity between channel belts. Results are the following. First, both confined and unconfined systems have documented clustering using K-functions; however, the sizes of clusters are smaller in the confined system. Second, clusters in the confined system are more longitudinally persistent than those in the unconfined system. Third, the unconfined system has a low compensation index (0.5), compared to the unconfined system, which is > 0.8. Fourth, channels in the confined system have higher connectivity values than those in the unconfined system. Results of this study provide a conceptual framework from which to relate degree of confinement of a depositional system to its internal stacking patterns and have implications for reservoir modeling. Stacking patterns describe how channelized deposits are spatially located relative to one another. Three methods are used to describe stacking patterns in fluvial systems: (1) clustering, (2) compensation, and (3) connectivity. Clustering is defined as a close grouping of a set of channels. Compensational stacking is defined as the tendency of a sediment transport system to fill in topographic lows resulting in a semi-organized stacking pattern. Connectivity is defined as the degree of sand-on-sand contacts between stratigraphically adjacent channel belts. This study uses outcrop measurements to document how clustering, compensational stacking, and connectivity of fluvial channel belts relate to lateral confinement. To address this goal we quantitatively compare outcrop architectural styles of the valley-confined Dakota Sandstone to the unconfined-dispersive fluvial system in the lower Wasatch Formation, both exposed in Utah. At each locality we documented the following: (1) cluster size, (2) cluster shape in 3 dimensions, (3) paleocurrents, (4) channel-belt types and styles (eg-single or multistory and accretion style), and (5) connectivity between channel belts. Results are the following. First, both confined and unconfined systems have documented clustering using K-functions; however, the sizes of clusters are smaller in the confined system. Second, clusters in the confined system are more longitudinally persistent than those in the unconfined system. Third, the unconfined system has a low compensation index (0.5), compared to the unconfined system, which is > 0.8. Fourth, channels in the confined system have higher connectivity values than those in the unconfined system. Results of this study provide a conceptual framework from which to relate degree of confinement of a depositional system to its internal stacking patterns and have implications for reservoir modeling. Panel_15222 Panel_15222 10:50 AM 11:10 AM

Capturing multiscale heterogeneities within deep-water stratigraphy can help to improve reservoir models and therefore recovery factors. The use of outcrop analogues is a key tool within this process for gaining knowledge on detailed sedimentary architectures and facies relationships. The sand-rich submarine fan systems of the Tanqua depocentre allow a detailed study of individual submarine lobes. An advanced geological reservoir model of a terminal lobe complex of Fan 3 (Skoorsteenberg Formation) was constructed using ReservoirStudioTM, which permits realistic architectures and facies distributions of both lobe and channel bodies to be captured. Available data from the Glitne gas field, a similar sand-rich submarine fan system in the northern North Sea, was used to construct petrophysical property models. Artificial injectors and producers were implemented at various locations in the system. By the use of streamline analysis (RMS2012 TM) the effects on fluid flow were tested between i) traditional lobe deposit models with vertically stacked facies belts that mimic coarsening-upwards in all locations, and ii) deterministic models that include lateral facies changes with dimensions and distributions constrained from previous field data from the Karoo. The findings show that the lobe architecture model employed has a significant influence on the predictability of the breakthrough time within reservoirs. Channelized lobe areas show the best connectivity, but the presence of channels at the well location becomes less important within the more deterministic lobe models due to lobe axis amalgamation. Within channelized lobe areas, the proportion of sand the submarine lobe deposits and the level of facies detail within the channel infill have a major influence on fluid-flow behaviour. Breakthrough time becomes up to 75% shorter with added flow barriers such as mud-clast conglomerate lags and mud-bearing banded sandstones. The implementation of sedimentary detail and the use of realistic sedimentary concepts on the architectural scale are shown to be vital in accurately capturing multiscale reservoir heterogeneities, which will help to improve predictions of reservoir recovery. Capturing multiscale heterogeneities within deep-water stratigraphy can help to improve reservoir models and therefore recovery factors. The use of outcrop analogues is a key tool within this process for gaining knowledge on detailed sedimentary architectures and facies relationships. The sand-rich submarine fan systems of the Tanqua depocentre allow a detailed study of individual submarine lobes. An advanced geological reservoir model of a terminal lobe complex of Fan 3 (Skoorsteenberg Formation) was constructed using ReservoirStudioTM, which permits realistic architectures and facies distributions of both lobe and channel bodies to be captured. Available data from the Glitne gas field, a similar sand-rich submarine fan system in the northern North Sea, was used to construct petrophysical property models. Artificial injectors and producers were implemented at various locations in the system. By the use of streamline analysis (RMS2012 TM) the effects on fluid flow were tested between i) traditional lobe deposit models with vertically stacked facies belts that mimic coarsening-upwards in all locations, and ii) deterministic models that include lateral facies changes with dimensions and distributions constrained from previous field data from the Karoo. The findings show that the lobe architecture model employed has a significant influence on the predictability of the breakthrough time within reservoirs. Channelized lobe areas show the best connectivity, but the presence of channels at the well location becomes less important within the more deterministic lobe models due to lobe axis amalgamation. Within channelized lobe areas, the proportion of sand the submarine lobe deposits and the level of facies detail within the channel infill have a major influence on fluid-flow behaviour. Breakthrough time becomes up to 75% shorter with added flow barriers such as mud-clast conglomerate lags and mud-bearing banded sandstones. The implementation of sedimentary detail and the use of realistic sedimentary concepts on the architectural scale are shown to be vital in accurately capturing multiscale reservoir heterogeneities, which will help to improve predictions of reservoir recovery. Panel_15221 Panel_15221 11:10 AM 11:30 AM

The Sarah Formation is a glaciogenic sedimentary unit of the latest Ordovician (Ashgillian) ice age deposited along the Gondwana Margin. It forms part of an extensive, but discontinuous belt of outcrop deposits that extends from the Arabian Peninsula to westernmost North Africa. The short-lived ice age resulted in initial incision and large-scale palaeovalley (PV) generation. Subsequent filling of the PVs juxtaposed the Sarah reservoirs against different older Ordovician marine source rocks and sealed them with a major Silurian source rock. This unique setting makes these Sarah glacial deposits one of the main reservoir targets in the subsurface of Arabia. Our study currently focusses on PV fills exposed in the Tayma area, northwestern Saudi Arabia. The exposures provide excellent reservoir analogs for the glaciogenic PV fills in the subsurface and for other time-equivalent units on the Arabian Peninsula and in North Africa. Outcrop-based reservoir characterization provides a unique insight to the 3D architecture and heterogeneity of PV reservoirs and allows the pre-drill prediction of reservoir quality distribution. Based on our work in the Rahal Daba’a PV, which includes sedimentological sections, general depositional environment mapping and architectural analysis (photomosaics), we present a preliminary 3D static reservoir analogue model. We deduce the evolution of the complex network of the Sarah PVs to the shoreline as well as depositional controls on facies change and reservoir architecture. This initial model captures the spatial and temporal lithofacies’ heterogeneity within the Rahl Daba’a and the 3D connectivity of reservoir geobodies. Reservoir quality data and mechanical properties derived from samples tied to measured sections are assigned to sandstone geo-bodies and lithofacies. They provide the crucial link between the Sarah outcrops in northwestern Saudi Arabia and equivalent subsurface reservoirs. The static 3D model incorporates porosity/permeability and density/velocity cubes for forwards seismic modeling, which is an important approach to reservoir architectural prediction in the subsurface. The approaches taken so far are part of a larger workflow, which will incorporate terrestrial LiDAR, near-surface seismics, calibration wells behind the outcrop and dynamic modeling approaches. The Sarah Formation is a glaciogenic sedimentary unit of the latest Ordovician (Ashgillian) ice age deposited along the Gondwana Margin. It forms part of an extensive, but discontinuous belt of outcrop deposits that extends from the Arabian Peninsula to westernmost North Africa. The short-lived ice age resulted in initial incision and large-scale palaeovalley (PV) generation. Subsequent filling of the PVs juxtaposed the Sarah reservoirs against different older Ordovician marine source rocks and sealed them with a major Silurian source rock. This unique setting makes these Sarah glacial deposits one of the main reservoir targets in the subsurface of Arabia. Our study currently focusses on PV fills exposed in the Tayma area, northwestern Saudi Arabia. The exposures provide excellent reservoir analogs for the glaciogenic PV fills in the subsurface and for other time-equivalent units on the Arabian Peninsula and in North Africa. Outcrop-based reservoir characterization provides a unique insight to the 3D architecture and heterogeneity of PV reservoirs and allows the pre-drill prediction of reservoir quality distribution. Based on our work in the Rahal Daba’a PV, which includes sedimentological sections, general depositional environment mapping and architectural analysis (photomosaics), we present a preliminary 3D static reservoir analogue model. We deduce the evolution of the complex network of the Sarah PVs to the shoreline as well as depositional controls on facies change and reservoir architecture. This initial model captures the spatial and temporal lithofacies’ heterogeneity within the Rahl Daba’a and the 3D connectivity of reservoir geobodies. Reservoir quality data and mechanical properties derived from samples tied to measured sections are assigned to sandstone geo-bodies and lithofacies. They provide the crucial link between the Sarah outcrops in northwestern Saudi Arabia and equivalent subsurface reservoirs. The static 3D model incorporates porosity/permeability and density/velocity cubes for forwards seismic modeling, which is an important approach to reservoir architectural prediction in the subsurface. The approaches taken so far are part of a larger workflow, which will incorporate terrestrial LiDAR, near-surface seismics, calibration wells behind the outcrop and dynamic modeling approaches. Panel_15225 Panel_15225 11:30 AM 11:50 AM

Panel_14449 Panel_14449 8:00 AM 11:50 AM

Panel_15738 Panel_15738 8:00 AM 12:00 AM

A significant proportion of the world’s remaining hydrocarbon reserves occur within deltaic deposits, thus understanding the key controls on reservoir development in deltaic systems has important economic implications. We are undertaking a study of modern day deltas to help understand reservoir development and compiled a global database of all (n=97) the large (>30 km in length from apex to toe) modern deltas using remotely sensed imagery. Deltas were classified according to dominant process – wave, fluvial, tidal or mixed, and modifiers applied depending on the influence of subordinate processes e.g. wave (tidal). Although there is overlap between different delta types, some general observations can be made. Wave dominated deltas account for 60% of the dataset, mixed process deltas are uncommon (10%) and tidal influenced and fluvial influenced deltas both account for 15% each. Most large deltas occur on passive margins and delta type is strongly influenced by latitude, climate and shoreline physiography. All deltas comprise a radial, distributive fluvial system (DFS) centred on the delta apex. Large, non-fluvial deltas (>75 km) show a disconnect between the DFS and shoreline although this distance varies depending on scale of fluvial system. Smaller non-fluvial deltas (30-75 km) generally show a good connection between the DFS and shoreline, again dependent on fluvial system scale. The significance of this observation is that small non-fluvial deltas supply sand directly to the shoreface whereas larger non-fluvial deltas do not. Fluvial-dominated deltas supply sand directly to the marine realm. Locating the apex of a delta – the point at which channels either bifurcate from or avulse from – is important as the majority of the transported sand is dropped immediately downstream of the apex. The backwater effect (the distance upstream of the delta mouth to where the base of the channel intersects sea-level) has been highlighted as a key controls apex location in modern deltas. Analysis of our dataset suggests that the backwater effect has no control on the apex location of large rivers, instead, the primary control on apex location of virtually all of the large deltas studied is relict topography. The dataset is definitive in terms of including all the large marine deltas on Earth, it is therefore the most comprehensive dataset available for comparison with ancient deltaic successions and should at least in part be representative of the rock record. A significant proportion of the world’s remaining hydrocarbon reserves occur within deltaic deposits, thus understanding the key controls on reservoir development in deltaic systems has important economic implications. We are undertaking a study of modern day deltas to help understand reservoir development and compiled a global database of all (n=97) the large (>30 km in length from apex to toe) modern deltas using remotely sensed imagery. Deltas were classified according to dominant process – wave, fluvial, tidal or mixed, and modifiers applied depending on the influence of subordinate processes e.g. wave (tidal). Although there is overlap between different delta types, some general observations can be made. Wave dominated deltas account for 60% of the dataset, mixed process deltas are uncommon (10%) and tidal influenced and fluvial influenced deltas both account for 15% each. Most large deltas occur on passive margins and delta type is strongly influenced by latitude, climate and shoreline physiography. All deltas comprise a radial, distributive fluvial system (DFS) centred on the delta apex. Large, non-fluvial deltas (>75 km) show a disconnect between the DFS and shoreline although this distance varies depending on scale of fluvial system. Smaller non-fluvial deltas (30-75 km) generally show a good connection between the DFS and shoreline, again dependent on fluvial system scale. The significance of this observation is that small non-fluvial deltas supply sand directly to the shoreface whereas larger non-fluvial deltas do not. Fluvial-dominated deltas supply sand directly to the marine realm. Locating the apex of a delta – the point at which channels either bifurcate from or avulse from – is important as the majority of the transported sand is dropped immediately downstream of the apex. The backwater effect (the distance upstream of the delta mouth to where the base of the channel intersects sea-level) has been highlighted as a key controls apex location in modern deltas. Analysis of our dataset suggests that the backwater effect has no control on the apex location of large rivers, instead, the primary control on apex location of virtually all of the large deltas studied is relict topography. The dataset is definitive in terms of including all the large marine deltas on Earth, it is therefore the most comprehensive dataset available for comparison with ancient deltaic successions and should at least in part be representative of the rock record. Panel_15133 Panel_15133 8:05 AM 8:25 AM

Lateral (10-100 km) variations in process dominance in mixed-energy coastal-deltaic systems need not reflect significant allogenic changes in regional or local basin physiography. However, in tectonically active mixed-energy settings, deciphering between the multitude of both autogenic and allogenic-forced process variations is very challenging. We integrate paleogeographic interpretation, paleotidal modeling and stratigraphic facies analysis in order to deconvolve allogenic vs. autogenic controls on two contrasting late-mid Miocene outcrop successions in the Baram Delta Province (BDP): (1) the Lambir Formation (western BDP), and (2) the Belait Formation (eastern BDP). The Lambir Formation records deposition during rapid early coastal-deltaic progradation and comprises fluvio-tidal sandstones that are sharp-to-erosionally juxtaposed on wave-dominated (storm-reworked) prodelta to delta front successions. In tidal channel bodies (4-15 m thick), abrupt vertical changes from sandier facies, through heterolithic facies, to bioturbated mudstones reflect rapid autogenic changes in local sediment supply, with varying degrees of fluvial and marine energy during abandonment. Proximal parasequence sets also contain 4-17 m scale, erosive-based fluvial channel bodies and wave-tide influenced, muddy sandbar deposits. Regional paleotidal modeling indicates that local autogenic deltaic processes controlled wave vs. tidal effectiveness. The Belait Formation was deposited under significant tectonic influence within a narrow (5-20 km), fault-bounded embayment (Berakas Syncline). This sub-basin configuration and its high rate of accommodation creation formed an effective sediment trap, with high aggradation and a steeply rising shelf trajectory. Abundant upward coarsening successions are interpreted as prograding storm- and river flood-influenced delta front deposits. Storm-reworking of tidal bars and intercalated tidal sand bodies further indicate mixed-energy processes. However, larger-scale (10-100 m) partitioning of stratigraphic architecture into relatively tide- and wave-dominated successions suggests temporal changes in process dominance. Paleotidal modeling confirms allogenic-forced changes to an embayed coastline resulted in tidal amplification. We illustrate how numerical modeling of paleo-oceanic processes places important constraints on understanding autogenic vs. allogenic control on sedimentological and stratigraphic architecture in coastal-deltaic successions. Lateral (10-100 km) variations in process dominance in mixed-energy coastal-deltaic systems need not reflect significant allogenic changes in regional or local basin physiography. However, in tectonically active mixed-energy settings, deciphering between the multitude of both autogenic and allogenic-forced process variations is very challenging. We integrate paleogeographic interpretation, paleotidal modeling and stratigraphic facies analysis in order to deconvolve allogenic vs. autogenic controls on two contrasting late-mid Miocene outcrop successions in the Baram Delta Province (BDP): (1) the Lambir Formation (western BDP), and (2) the Belait Formation (eastern BDP). The Lambir Formation records deposition during rapid early coastal-deltaic progradation and comprises fluvio-tidal sandstones that are sharp-to-erosionally juxtaposed on wave-dominated (storm-reworked) prodelta to delta front successions. In tidal channel bodies (4-15 m thick), abrupt vertical changes from sandier facies, through heterolithic facies, to bioturbated mudstones reflect rapid autogenic changes in local sediment supply, with varying degrees of fluvial and marine energy during abandonment. Proximal parasequence sets also contain 4-17 m scale, erosive-based fluvial channel bodies and wave-tide influenced, muddy sandbar deposits. Regional paleotidal modeling indicates that local autogenic deltaic processes controlled wave vs. tidal effectiveness. The Belait Formation was deposited under significant tectonic influence within a narrow (5-20 km), fault-bounded embayment (Berakas Syncline). This sub-basin configuration and its high rate of accommodation creation formed an effective sediment trap, with high aggradation and a steeply rising shelf trajectory. Abundant upward coarsening successions are interpreted as prograding storm- and river flood-influenced delta front deposits. Storm-reworking of tidal bars and intercalated tidal sand bodies further indicate mixed-energy processes. However, larger-scale (10-100 m) partitioning of stratigraphic architecture into relatively tide- and wave-dominated successions suggests temporal changes in process dominance. Paleotidal modeling confirms allogenic-forced changes to an embayed coastline resulted in tidal amplification. We illustrate how numerical modeling of paleo-oceanic processes places important constraints on understanding autogenic vs. allogenic control on sedimentological and stratigraphic architecture in coastal-deltaic successions. Panel_15134 Panel_15134 8:25 AM 8:45 AM

Modern sequence-stratigraphic models increasingly need to expand consideration of allogenic forcing to various factors interfering with the well-established role of base level at basin scale. Climate remains a particularly difficult variable to isolate in very ancient successions, for which accurate chronological correlation and proxy-based quantification of paleoenvironmental conditions are seriously limited. However, sedimentary facies analysis still represents a fundamental conceptual tool to recognize process-patterns typical of specific climatic contexts. Recent developments show that fluvial systems in monsoonal settings are subject to prolonged hydrological inactivity alternating with brief (inter)annual phases of possibly extreme discharges, recognizable by sedimentological attributes such as great volumes of supercritical-flow deposits, vegetation-induced structures within channel fills and coarse overbank facies. Distally linked, flood-prone deltas, with higher preservation potential, should also present distinctive traits. Late Carboniferous (Bashkirian) sandstones of the Lower Kinderscout Grit (Millstone Grit Group, UK) were deposited at subequatorial latitudes in fluvio-deltaic and shallow-marine settings of the Pennine Basin, north of the Variscan Orogen, during early assemblage of the Pangean megacontinent. Outcrops frequently feature large, wavy geometries and unusual architectures traditionally difficult to interpret. The unique stratal configuration of deltaic deposits at Derby Delph Quarry (West Yorkshire) comprises thick sets of giant, rhythmically undulating sedimentary structures in massive, poorly sorted sandstones, with fully aggradational architecture. Recent insights on sediment beds under supercritical currents allow to interpret these deposits as geologically instantaneous progradation of a proximal delta front from a long-lived hyperpycnal current which accreted cyclic steps, bedforms identified only recently under high-energy flow conditions. The paleogeographic, paleoclimatic and sequence-stratigraphic context indicate that the region was subject to a tropical seasonal climate that enhanced megamonsoonal circulation on the eastern margin of the early Pangean landmass. Exceptional fluvial floods were able to transfer large volumes of sediment basinward, especially during interglacial phases of marked seasonality and base-level rise, forcing a high progradational efficiency for clastic systems locally also during transgressions. Modern sequence-stratigraphic models increasingly need to expand consideration of allogenic forcing to various factors interfering with the well-established role of base level at basin scale. Climate remains a particularly difficult variable to isolate in very ancient successions, for which accurate chronological correlation and proxy-based quantification of paleoenvironmental conditions are seriously limited. However, sedimentary facies analysis still represents a fundamental conceptual tool to recognize process-patterns typical of specific climatic contexts. Recent developments show that fluvial systems in monsoonal settings are subject to prolonged hydrological inactivity alternating with brief (inter)annual phases of possibly extreme discharges, recognizable by sedimentological attributes such as great volumes of supercritical-flow deposits, vegetation-induced structures within channel fills and coarse overbank facies. Distally linked, flood-prone deltas, with higher preservation potential, should also present distinctive traits. Late Carboniferous (Bashkirian) sandstones of the Lower Kinderscout Grit (Millstone Grit Group, UK) were deposited at subequatorial latitudes in fluvio-deltaic and shallow-marine settings of the Pennine Basin, north of the Variscan Orogen, during early assemblage of the Pangean megacontinent. Outcrops frequently feature large, wavy geometries and unusual architectures traditionally difficult to interpret. The unique stratal configuration of deltaic deposits at Derby Delph Quarry (West Yorkshire) comprises thick sets of giant, rhythmically undulating sedimentary structures in massive, poorly sorted sandstones, with fully aggradational architecture. Recent insights on sediment beds under supercritical currents allow to interpret these deposits as geologically instantaneous progradation of a proximal delta front from a long-lived hyperpycnal current which accreted cyclic steps, bedforms identified only recently under high-energy flow conditions. The paleogeographic, paleoclimatic and sequence-stratigraphic context indicate that the region was subject to a tropical seasonal climate that enhanced megamonsoonal circulation on the eastern margin of the early Pangean landmass. Exceptional fluvial floods were able to transfer large volumes of sediment basinward, especially during interglacial phases of marked seasonality and base-level rise, forcing a high progradational efficiency for clastic systems locally also during transgressions. Panel_15129 Panel_15129 8:45 AM 9:05 AM

Our current understanding of the sedimentary evolution in marine rift basins is biased towards examples developed under humid climatic conditions in which sediment is mainly sourced by perennial fluvial/alluvial systems. Such circumstances are seldom the case in arid to semi-arid basins, where the sources tend to be dominated by strongly seasonally controlled ephemeral processes. It is fundamental to take these factors into consideration in order to correctly asses the autogenic and allogenic controls affecting the depositional environments in arid to semi-arid settings. The spatial and temporal evolution of a prograding fan delta system and its interaction with coral-algal associations and evaporites is studied from Miocene exposures of the El Qaa half-graben, Suez Rift, Sinai Peninsula, Egypt. The results obtained constitute a valid depositional model comparable to other arid rift basins characterized by hyper-saline and marginal marine successions (e.g. pre-salt hydrocarbon plays in the South Atlantic). The eastern margin of the El Qaa half-graben is characterized by a coarse-grained deltaic succession with coral-algal deposits concentrated at the topset of the lobes. This succession progrades progressively on top of mudstone and evaporite dominated prodelta units towards the west, across the half-graben. The deltaic lobes evolve from east to west from 30 to 50 m thick conglomerate dominated units to up to 120 m sandstone dominated ones. Progradational-aggradational cycles, interpreted from the alternation of siliciclastic and carbonate bodies, appear punctuated by relative sea-level lowstands defined by the presence of the evaporites. Hangingwall subsidence and deformation is the primary control on the stacking pattern of the deltaic lobes. However, the internal architecture of the lobes reveals an interplay between the ephemeral alluvial input of sediment and its reworking in the coastal setting that proves to be a crucial factor determining the evolution of the individual lobes. The delivery of sediment from the continental source to the marine environment is determined by the magnitude of the ephemeral events. As the radius of a fan delta increases the magnitude of these events has to increase accordingly in order to be able to cross the subaerial portion of the fan delta and reach the coast. Consequently, the duration, paucity and magnitude of the alluvial events impose critical restrictions on the size of the resulting fan deltas in a depocentre. Our current understanding of the sedimentary evolution in marine rift basins is biased towards examples developed under humid climatic conditions in which sediment is mainly sourced by perennial fluvial/alluvial systems. Such circumstances are seldom the case in arid to semi-arid basins, where the sources tend to be dominated by strongly seasonally controlled ephemeral processes. It is fundamental to take these factors into consideration in order to correctly asses the autogenic and allogenic controls affecting the depositional environments in arid to semi-arid settings. The spatial and temporal evolution of a prograding fan delta system and its interaction with coral-algal associations and evaporites is studied from Miocene exposures of the El Qaa half-graben, Suez Rift, Sinai Peninsula, Egypt. The results obtained constitute a valid depositional model comparable to other arid rift basins characterized by hyper-saline and marginal marine successions (e.g. pre-salt hydrocarbon plays in the South Atlantic). The eastern margin of the El Qaa half-graben is characterized by a coarse-grained deltaic succession with coral-algal deposits concentrated at the topset of the lobes. This succession progrades progressively on top of mudstone and evaporite dominated prodelta units towards the west, across the half-graben. The deltaic lobes evolve from east to west from 30 to 50 m thick conglomerate dominated units to up to 120 m sandstone dominated ones. Progradational-aggradational cycles, interpreted from the alternation of siliciclastic and carbonate bodies, appear punctuated by relative sea-level lowstands defined by the presence of the evaporites. Hangingwall subsidence and deformation is the primary control on the stacking pattern of the deltaic lobes. However, the internal architecture of the lobes reveals an interplay between the ephemeral alluvial input of sediment and its reworking in the coastal setting that proves to be a crucial factor determining the evolution of the individual lobes. The delivery of sediment from the continental source to the marine environment is determined by the magnitude of the ephemeral events. As the radius of a fan delta increases the magnitude of these events has to increase accordingly in order to be able to cross the subaerial portion of the fan delta and reach the coast. Consequently, the duration, paucity and magnitude of the alluvial events impose critical restrictions on the size of the resulting fan deltas in a depocentre. Panel_15130 Panel_15130 9:05 AM 9:25 AM

Panel_15739 Panel_15739 9:25 AM 12:00 AM

The Brazos River empties into the Gulf of Mexico (Gulf of Mexico) forming a wave-influenced delta dominated by a muddy subaqueous portion. Recent work in the lower river and subaqueous delta (SAD) however, have discovered evidence for sedimentary processes more often associated with higher sediment discharge rivers and/or high-gradient rivers. These studies utilized high-resolution geophysics on the SAD and water-column profiling in the lower river to investigate the transfer to and fate of fluvial sediment on the shelf. From the SAD results showed the eastern portion was dominated by high side scan sonar backscatter features, an erosional scarp along the upper shoreface, and a thinning of the Holocene sediment package immediately downslope of the scarp. The thickness of the Holocene sediment package increased in deeper water. These features suggest sediment mass wasting events on the delta front. After rapidly prograding during the early and mid 20th century, reductions in sediment load, and a shift in the primary depocenter lead to erosion on these abandoned portions of the delta. The result is the erosional scarp upslope of the high backscatter features representing exposed relict consolidated sediments. In the lower river we observed a separate extreme event. During an elevated fluvial discharge event, data from the lower river showed an anomalously high suspended sediment layer. This fluid mud layer was >1 m thick in areas, and located along a 6 Km span of the river ~ 2 Km upstream from the mouth. The location corresponded to a reach of the river impacted by salt-water intrusions from the GOM. This salt-water intrusion was shown to inhibit sediment export from the river to the GOM, and facilitate deposition of fine-grained sediment in the lower river. Based on our observations we believe that this is a mechanism for the development of hyperpycnal flow in the river. The mud layer in the lower river builds during moderate and low discharge periods and remobilized during increased discharge. We observed suspended sediment concentrations up to 100 g/l in the fluid mud layer during this event. While our observations did not capture the transition from fluid mud to hyperpycnal flow, we believe that with persistent increased discharge the fluid mud layer could transition to hyperpycnal flow. These results highlight the potential for sedimentary processes not typically associated with a river in this environmental setting. The Brazos River empties into the Gulf of Mexico (Gulf of Mexico) forming a wave-influenced delta dominated by a muddy subaqueous portion. Recent work in the lower river and subaqueous delta (SAD) however, have discovered evidence for sedimentary processes more often associated with higher sediment discharge rivers and/or high-gradient rivers. These studies utilized high-resolution geophysics on the SAD and water-column profiling in the lower river to investigate the transfer to and fate of fluvial sediment on the shelf. From the SAD results showed the eastern portion was dominated by high side scan sonar backscatter features, an erosional scarp along the upper shoreface, and a thinning of the Holocene sediment package immediately downslope of the scarp. The thickness of the Holocene sediment package increased in deeper water. These features suggest sediment mass wasting events on the delta front. After rapidly prograding during the early and mid 20th century, reductions in sediment load, and a shift in the primary depocenter lead to erosion on these abandoned portions of the delta. The result is the erosional scarp upslope of the high backscatter features representing exposed relict consolidated sediments. In the lower river we observed a separate extreme event. During an elevated fluvial discharge event, data from the lower river showed an anomalously high suspended sediment layer. This fluid mud layer was >1 m thick in areas, and located along a 6 Km span of the river ~ 2 Km upstream from the mouth. The location corresponded to a reach of the river impacted by salt-water intrusions from the GOM. This salt-water intrusion was shown to inhibit sediment export from the river to the GOM, and facilitate deposition of fine-grained sediment in the lower river. Based on our observations we believe that this is a mechanism for the development of hyperpycnal flow in the river. The mud layer in the lower river builds during moderate and low discharge periods and remobilized during increased discharge. We observed suspended sediment concentrations up to 100 g/l in the fluid mud layer during this event. While our observations did not capture the transition from fluid mud to hyperpycnal flow, we believe that with persistent increased discharge the fluid mud layer could transition to hyperpycnal flow. These results highlight the potential for sedimentary processes not typically associated with a river in this environmental setting. Panel_15135 Panel_15135 10:10 AM 10:30 AM

Shelf-edge deltas [SEDs] are the primary driver of shelf-margin accretion and a principle mechanism of deepwater sediment delivery. Fluvial-dominated SEDs are thought to be the most efficient at deepwater sediment delivery and for prograding the shelf margin. Yet, this notion prescribes that all fluvial-dominated SEDs accrete the shelf margin and deliver sediment to deepwater in the same manner. These interpretations spring from recognition criteria of fluvial-dominated SEDs derived from 2-D outcrops and subsurface data. Here we compare five fluvial-dominated SED–slope outcrops in the Permian Karoo-, Cretaceous Washakie-, and Eocene Ainsa- and Spitsbergen Central Basins. Our data highlights similar distribution of architectural elements from shelf edge to slope in each system and a repeated pattern of progradation, sediment bypass, and renewed progradation. We observe greater variability in the mechanisms of these patterns than previous studies, evidenced in the distinct facies within the architectural elements. This has implications for the timing and style of progradation, deepwater sediment delivery, and reservoir connectivity. In particular, we recognize three main types of fluvial-dominated SED dynamics: failure-dominated [FD], hyperpycnal flow-dominated [HD]; and episodic bypass-dominated [BD]. In FD systems mouth bar progradation at the shelf edge is a function of repeated buildup, collapse and evacuation, and reestablishment. Collapsed sediment is transported basinward but trapped at the upper slope, and accretes the margin. Coarse-grained sediment is only rarely delivered to lower slope or basin floor. In HD systems, hyperpycnal flows frequently erode mouth bars and transport the sediment to the slope, causing shelf-margin accretion by building thick turbidite aprons at the upper slope, attached to the SED. In BD systems, distributary channel avulsion halted progradation and forced the rapid and punctuated redistribution of sediment from the shelf edge to the basin floor. In FD systems, the juxtaposition of non-deformed and collapsed mouth bars limits the connectivity at the shelf edge, and preferential trapping on the upper slope results in low volumes of deepwater sands even under high sediment supply. In HD systems the constant sediment redistribution from shelf to slope results in well connected, extensive reservoirs on the slope. In BD systems, the episodic nature of sediment bypass results in spatially and temporally localized reservoirs. Shelf-edge deltas [SEDs] are the primary driver of shelf-margin accretion and a principle mechanism of deepwater sediment delivery. Fluvial-dominated SEDs are thought to be the most efficient at deepwater sediment delivery and for prograding the shelf margin. Yet, this notion prescribes that all fluvial-dominated SEDs accrete the shelf margin and deliver sediment to deepwater in the same manner. These interpretations spring from recognition criteria of fluvial-dominated SEDs derived from 2-D outcrops and subsurface data. Here we compare five fluvial-dominated SED–slope outcrops in the Permian Karoo-, Cretaceous Washakie-, and Eocene Ainsa- and Spitsbergen Central Basins. Our data highlights similar distribution of architectural elements from shelf edge to slope in each system and a repeated pattern of progradation, sediment bypass, and renewed progradation. We observe greater variability in the mechanisms of these patterns than previous studies, evidenced in the distinct facies within the architectural elements. This has implications for the timing and style of progradation, deepwater sediment delivery, and reservoir connectivity. In particular, we recognize three main types of fluvial-dominated SED dynamics: failure-dominated [FD], hyperpycnal flow-dominated [HD]; and episodic bypass-dominated [BD]. In FD systems mouth bar progradation at the shelf edge is a function of repeated buildup, collapse and evacuation, and reestablishment. Collapsed sediment is transported basinward but trapped at the upper slope, and accretes the margin. Coarse-grained sediment is only rarely delivered to lower slope or basin floor. In HD systems, hyperpycnal flows frequently erode mouth bars and transport the sediment to the slope, causing shelf-margin accretion by building thick turbidite aprons at the upper slope, attached to the SED. In BD systems, distributary channel avulsion halted progradation and forced the rapid and punctuated redistribution of sediment from the shelf edge to the basin floor. In FD systems, the juxtaposition of non-deformed and collapsed mouth bars limits the connectivity at the shelf edge, and preferential trapping on the upper slope results in low volumes of deepwater sands even under high sediment supply. In HD systems the constant sediment redistribution from shelf to slope results in well connected, extensive reservoirs on the slope. In BD systems, the episodic nature of sediment bypass results in spatially and temporally localized reservoirs. Panel_15127 Panel_15127 10:30 AM 10:50 AM

Shallow-water, coastal plain deltas are commonly associated with broad, low-gradient coastal-plain settings and are an under appreciated architectural style in marginal marine systems. These deltas are located in wetlands and are detached from the coeval shoreline. The goal of this study is to document the evolution and 3D architecture of a coastal plain delta in the Neslen Formation, Floy Canyon, Utah. The delta was deposited in a ~ 6 m deep wetland located about 70 miles from the coeval shoreline. The outcrop is highly rugose and exposes a large portion of the delta: from the feeder channel to the delta front. Upward and longitudinal facies variations of the delta lobe are evident. The feeder channel contains fine to medium grained, cross stratified sandstone. These strata longitudinally transfer to foreset stratigraphy that is composed of generally fine grained, upward coarsening and thickening beds containing predominantly ripple laminations. These beds de-amalgamate and become thinner and finer grained in the down-current direction towards the margin of the delta. The beds are contorted and amalgamated along the axis of the system. The upward and lateral facies associations are distinctively different from deltas deposited in deep-water, open marine settings. For example, there is little to no bottomset aggradation, the clinoform angles are shallow, and the foresets are dominantly composed of ripples. The delta foresets were deposited primarily by tractional processes as opposed to the sediment gravity flows commonly associated with deltas in open marine settings. The delta also has a high proportion of amalgamated beds and a low proportion of contorted bedding. Shallow-water, coastal plain deltas are commonly associated with broad, low-gradient coastal-plain settings and are an under appreciated architectural style in marginal marine systems. These deltas are located in wetlands and are detached from the coeval shoreline. The goal of this study is to document the evolution and 3D architecture of a coastal plain delta in the Neslen Formation, Floy Canyon, Utah. The delta was deposited in a ~ 6 m deep wetland located about 70 miles from the coeval shoreline. The outcrop is highly rugose and exposes a large portion of the delta: from the feeder channel to the delta front. Upward and longitudinal facies variations of the delta lobe are evident. The feeder channel contains fine to medium grained, cross stratified sandstone. These strata longitudinally transfer to foreset stratigraphy that is composed of generally fine grained, upward coarsening and thickening beds containing predominantly ripple laminations. These beds de-amalgamate and become thinner and finer grained in the down-current direction towards the margin of the delta. The beds are contorted and amalgamated along the axis of the system. The upward and lateral facies associations are distinctively different from deltas deposited in deep-water, open marine settings. For example, there is little to no bottomset aggradation, the clinoform angles are shallow, and the foresets are dominantly composed of ripples. The delta foresets were deposited primarily by tractional processes as opposed to the sediment gravity flows commonly associated with deltas in open marine settings. The delta also has a high proportion of amalgamated beds and a low proportion of contorted bedding. Panel_15131 Panel_15131 10:50 AM 11:10 AM

The Berea interval (Upper Famennian) is a widespread siliciclastic unit in the Appalachian basin, which in the subsurface of Athens County in southeastern Ohio, varies in thickness from less than 3 to more than 30 m and may contain one or two sandstones. These sandstones, which are informally referred to as the Berea (upper) and Second Berea (lower), were examined with limited core data augmented with cross sections, isopach maps, and log motif maps constructed using 294 gamma-ray logs. The data show that the Berea sandstones prograded from the southeast as two high frequency sequences. The lower sequence averages 15 m in thickness and is composed of the Cleveland Shale and the overlying Second Berea Sandstone. The gross sandstone isopach map shows that the interval thickens to the northwest, pinches out to the southeast, and contains two NE-SW oriented sandstone belts separated by an area of zero sandstone thickness. The log motif patterns are primarily coarsening upward. The upper sequence is averages 11 m thick and consists of the Berea Sandstone capped by the Bedford Shale. The gross sandstone isopach of the upper sequence also thickens to the northwest but is laterally continuous. The log motifs in this sequence are primarily blocky. The log patterns and isopach maps of both sandstones are consistent with deposition by wave-dominated deltas broadly similar in scale to the modern Grijalva Delta during forced regressions. Both sequences contain fining upward log motifs that can be oriented perpendicular to the main sandstone trends and which are interpreted as products of distributary channels that flowed from a source to the southeast. The lower sequence formed detached shoreface sandstones, whereas the shoreface sandstones of the upper sequence are attached. The difference in offlap patterns suggests that the rate of formation of accommodation during the transgression that capped the upper sequence was greater and preserved more of those sandstones than that capping the lower sequence. The Berea interval (Upper Famennian) is a widespread siliciclastic unit in the Appalachian basin, which in the subsurface of Athens County in southeastern Ohio, varies in thickness from less than 3 to more than 30 m and may contain one or two sandstones. These sandstones, which are informally referred to as the Berea (upper) and Second Berea (lower), were examined with limited core data augmented with cross sections, isopach maps, and log motif maps constructed using 294 gamma-ray logs. The data show that the Berea sandstones prograded from the southeast as two high frequency sequences. The lower sequence averages 15 m in thickness and is composed of the Cleveland Shale and the overlying Second Berea Sandstone. The gross sandstone isopach map shows that the interval thickens to the northwest, pinches out to the southeast, and contains two NE-SW oriented sandstone belts separated by an area of zero sandstone thickness. The log motif patterns are primarily coarsening upward. The upper sequence is averages 11 m thick and consists of the Berea Sandstone capped by the Bedford Shale. The gross sandstone isopach of the upper sequence also thickens to the northwest but is laterally continuous. The log motifs in this sequence are primarily blocky. The log patterns and isopach maps of both sandstones are consistent with deposition by wave-dominated deltas broadly similar in scale to the modern Grijalva Delta during forced regressions. Both sequences contain fining upward log motifs that can be oriented perpendicular to the main sandstone trends and which are interpreted as products of distributary channels that flowed from a source to the southeast. The lower sequence formed detached shoreface sandstones, whereas the shoreface sandstones of the upper sequence are attached. The difference in offlap patterns suggests that the rate of formation of accommodation during the transgression that capped the upper sequence was greater and preserved more of those sandstones than that capping the lower sequence. Panel_15128 Panel_15128 11:10 AM 11:30 AM

On the Mediterranean continental shelves the post-glacial transgressive succession is a complex picture composed by backstepping units, associated to phases of enhanced rates of sea level rise, and seaward progradations, related to sea level stillstands and/or increased sediment transport toward the coast. Among Late Pleistocene examples, mid-shelf progradational deposits has been related to the short-term climatic variability of the Younger Dryas event, a period during which the combination of increased sediment supply from rivers and reduced rates of sea level rise promoted the formation of tens-meters thick muddy subaqueous progradations. We present the documentation of a deltaic system where both delta front sands and related fine-grained subaqueous progradations (prodeltaic to shallow marine) has been completely preserved. This compound delta systems formed offshore the modern Gargano Promontory (southern Adriatic Sea) during the Younger Dryas cold event and probably may be considered the first documentation of a compound delta preserved within transgressive deposits; this provides the opportunity to investigate the processes controlling the formation and preservation of a complex deltaic system during an overall sea level rise and to compare ancient and modern compound systems. The finding of the PGCD, in agreement with further documentation worldwide (especially for the Amazon delta), suggests that subaqueous deltas are always genetically linked delta front deposits, characterized by a shallower rollover point. The formation of this compound system within the short time window of the Younger Dryas event implies that the time required for the development of this kind of deltaic deposits may take place in few centuries; this notion may be useful in interpreting ancient stratigraphic record where a much lower geochronological resolution may lead to assume or imply much slower rates of sediment accumulation. On the Mediterranean continental shelves the post-glacial transgressive succession is a complex picture composed by backstepping units, associated to phases of enhanced rates of sea level rise, and seaward progradations, related to sea level stillstands and/or increased sediment transport toward the coast. Among Late Pleistocene examples, mid-shelf progradational deposits has been related to the short-term climatic variability of the Younger Dryas event, a period during which the combination of increased sediment supply from rivers and reduced rates of sea level rise promoted the formation of tens-meters thick muddy subaqueous progradations. We present the documentation of a deltaic system where both delta front sands and related fine-grained subaqueous progradations (prodeltaic to shallow marine) has been completely preserved. This compound delta systems formed offshore the modern Gargano Promontory (southern Adriatic Sea) during the Younger Dryas cold event and probably may be considered the first documentation of a compound delta preserved within transgressive deposits; this provides the opportunity to investigate the processes controlling the formation and preservation of a complex deltaic system during an overall sea level rise and to compare ancient and modern compound systems. The finding of the PGCD, in agreement with further documentation worldwide (especially for the Amazon delta), suggests that subaqueous deltas are always genetically linked delta front deposits, characterized by a shallower rollover point. The formation of this compound system within the short time window of the Younger Dryas event implies that the time required for the development of this kind of deltaic deposits may take place in few centuries; this notion may be useful in interpreting ancient stratigraphic record where a much lower geochronological resolution may lead to assume or imply much slower rates of sediment accumulation. Panel_15132 Panel_15132 11:30 AM 11:50 AM

Panel_14481 Panel_14481 8:00 AM 11:50 AM

Panel_15801 Panel_15801 8:00 AM 12:00 AM

An understanding of crustal thickness, ocean-continent-transition structure, continent-ocean-boundary location and crustal type (continental, oceanic or exhumed mantle) is a critical component of petroleum systems evaluation in the Gulf of Mexico (GoM) and elsewhere. Using public-domain data and OCTek 3D gravity inversion, we have produced regional grids and maps of Moho depth, crustal-basement thickness, continental-lithosphere thinning-factor and residual continental-crustal-thickness for the GoM. Crustal-basement thickness and lithosphere thinning from the 3D gravity inversion show the distribution of oceanic crust within the GoM and constrain continent-ocean-boundary location. Crustal cross-sections using Moho depths from the 3D gravity inversion show the form of the ocean-continent transition. Superposition of shaded-relief satellite free-air gravity onto maps of crustal-basement thickness and lithosphere thinning from gravity inversion show clearly the pattern and location of ocean-ridge and transform segments within the western and central GoM. These in turn reveal sea-floor spreading trajectory along with pre-breakup rifted-margin conjugacy. Maps of crustal thickness with superimposed shaded-relief free-air gravity may be used to test and refine plate-reconstruction models for the development of the GoM and its relationship to the formation of the early Central Atlantic. 2D and 3D flexural-backstripping and subsidence modelling, driven by lithosphere thinning/beta-factors from gravity inversion, have been used to predict the evolution of palaeobathymetry through the post-breakup history of the GoM. We also use lithosphere thinning determined from gravity inversion, together with crustal type, to predict the residual continental radiogenic heat-flow contribution and the post-rift transient heat-flow component, which together permit predictions of heat-flow history. Outputs from 3D gravity inversion for the GoM include grids of lithosphere thinning, ?-factor and heat-flow history for input to petroleum systems modelling. An understanding of crustal thickness, ocean-continent-transition structure, continent-ocean-boundary location and crustal type (continental, oceanic or exhumed mantle) is a critical component of petroleum systems evaluation in the Gulf of Mexico (GoM) and elsewhere. Using public-domain data and OCTek 3D gravity inversion, we have produced regional grids and maps of Moho depth, crustal-basement thickness, continental-lithosphere thinning-factor and residual continental-crustal-thickness for the GoM. Crustal-basement thickness and lithosphere thinning from the 3D gravity inversion show the distribution of oceanic crust within the GoM and constrain continent-ocean-boundary location. Crustal cross-sections using Moho depths from the 3D gravity inversion show the form of the ocean-continent transition. Superposition of shaded-relief satellite free-air gravity onto maps of crustal-basement thickness and lithosphere thinning from gravity inversion show clearly the pattern and location of ocean-ridge and transform segments within the western and central GoM. These in turn reveal sea-floor spreading trajectory along with pre-breakup rifted-margin conjugacy. Maps of crustal thickness with superimposed shaded-relief free-air gravity may be used to test and refine plate-reconstruction models for the development of the GoM and its relationship to the formation of the early Central Atlantic. 2D and 3D flexural-backstripping and subsidence modelling, driven by lithosphere thinning/beta-factors from gravity inversion, have been used to predict the evolution of palaeobathymetry through the post-breakup history of the GoM. We also use lithosphere thinning determined from gravity inversion, together with crustal type, to predict the residual continental radiogenic heat-flow contribution and the post-rift transient heat-flow component, which together permit predictions of heat-flow history. Outputs from 3D gravity inversion for the GoM include grids of lithosphere thinning, ?-factor and heat-flow history for input to petroleum systems modelling. Panel_15466 Panel_15466 8:05 AM 8:25 AM

Recently acquired seismic refraction data in the northern Gulf of Mexico (GOM) provide new insights into the basin’s crustal structure. We use the four refraction profiles to build regional-scale crustal sections across the GOM, and then employ these profiles as the basis for basin modeling of crustal subsidence through time. Basin modeling includes flexural backstripping of the sediment load and correction for thermal subsidence, with the aim of calculating the shape of the basin at the time (Callovian) of salt deposition. The age of salt deposition relative to rifting events is poorly constrained, with opinions ranging from salt being synrift to entirely postrift. We suggest that salt was deposited near the end of rifting, close to the time of initiation of sea floor spreading. This interpretation is based partly on reconstructing possible water depths at the start of salt deposition, using the backstripping method, and on interpretation of overlying age-dated seismic horizons that downlap onto oceanic crust. Backstripping shows that if water depths were too deep during salt deposition, i.e. sea floor spreading already established, salt thickness based on isostatic balance would be far too large. If water depths were too shallow in the model, i.e. little crustal thinning, salt thickness would be too thin. We can compare the outcome of this analysis with the distribution of evaporites in the Gulf of Mexico basin, which may have formed a 4 km thick layer in some areas, though these salt deposits have subsequently been remobilized. Crustal structure from the refraction data shows crustal thicknesses of 8-15 km under the salt basin. The seismic velocity structure of the thinned crust suggests that at least some of the basement was formed by magmatic intrusions. If we correct for the inferred stretching of the continental margin and thermal subsidence, we obtain a plausible depth for the margin at Callovian time. Velocity structure from the refraction data plus observations of seaward dipping reflections (SDRs) in the eastern GOM are consistent with the margins of the GOM having a significant synrift volcanic component. We suggest that this volcanic component is a prerequisite for formation of marginal salt basins like the GOM, Aptian South Atlantic and present-day Red Sea. Recently acquired seismic refraction data in the northern Gulf of Mexico (GOM) provide new insights into the basin’s crustal structure. We use the four refraction profiles to build regional-scale crustal sections across the GOM, and then employ these profiles as the basis for basin modeling of crustal subsidence through time. Basin modeling includes flexural backstripping of the sediment load and correction for thermal subsidence, with the aim of calculating the shape of the basin at the time (Callovian) of salt deposition. The age of salt deposition relative to rifting events is poorly constrained, with opinions ranging from salt being synrift to entirely postrift. We suggest that salt was deposited near the end of rifting, close to the time of initiation of sea floor spreading. This interpretation is based partly on reconstructing possible water depths at the start of salt deposition, using the backstripping method, and on interpretation of overlying age-dated seismic horizons that downlap onto oceanic crust. Backstripping shows that if water depths were too deep during salt deposition, i.e. sea floor spreading already established, salt thickness based on isostatic balance would be far too large. If water depths were too shallow in the model, i.e. little crustal thinning, salt thickness would be too thin. We can compare the outcome of this analysis with the distribution of evaporites in the Gulf of Mexico basin, which may have formed a 4 km thick layer in some areas, though these salt deposits have subsequently been remobilized. Crustal structure from the refraction data shows crustal thicknesses of 8-15 km under the salt basin. The seismic velocity structure of the thinned crust suggests that at least some of the basement was formed by magmatic intrusions. If we correct for the inferred stretching of the continental margin and thermal subsidence, we obtain a plausible depth for the margin at Callovian time. Velocity structure from the refraction data plus observations of seaward dipping reflections (SDRs) in the eastern GOM are consistent with the margins of the GOM having a significant synrift volcanic component. We suggest that this volcanic component is a prerequisite for formation of marginal salt basins like the GOM, Aptian South Atlantic and present-day Red Sea. Panel_15460 Panel_15460 8:25 AM 8:45 AM

The creation of mega-evaporite basins such as those along the margins of the Gulf of Mexico (GOM) and South Atlantic (SAT) suggests evaporite deposition at rates of several km in less than a few million years. These rapid rates were once assumed to require tectonic control, but deeply penetrating seismic data now show that these deposits rest above largely unfaulted “top-rift” or “base-salt” unconformities and hence are post-rift or extremely late syn-rift units. Thermal subsidence could be expected to control them, but the observed subsidence rates far exceed thermal rates. We use seismic, well, and regional stratigraphic data from the Gulf of Mexico, South Atlantic, Mediterranean and Red Sea to assess the relative merits and shortcomings of possible mechanisms for the deposition of thick “mega-salt” basins. These include; (1) out-of-sequence late rift-related faulting/subsidence, (2) progressive infilling of pre-existing sub-sea air-filled depressions, and (3) post-rift outer marginal collapse. Option 1 is not supported by regional structural mapping in the GoM or SAT. Option 2 is fails to address the lack of interbedded/interfingered basin rim clastics and salt in both basins. Option 3 avoids these pitfalls and explains the unfaulted depositional continuity of thin salt in the eastern GOM, reaching from the onlap limit as allowed by global sea level in the Appalachiacola Basin to the structural level of the oceanic crust at the continent-ocean transition, which was emplaced at 2.5-3 km sub-sea. While current arguments for option 3 in the South Atlantic are weaker than for the GoM, we highlight circumstantial evidence from seismic and other data that favours evaporite deposition at global sea level on this margin. We highlight additional observations such as strong, early basinward tilting of the base salt surface, and the onlap by earliest sediments atop oceanic crust onto deformed salt cored folds above the rifted margin that are best explained by an outer marginal collapse model. Finally, we summarise how the concept of outer marginal collapse, which occurs between the rift and drift stages of margin formation, impacts petroleum systems in general. The creation of mega-evaporite basins such as those along the margins of the Gulf of Mexico (GOM) and South Atlantic (SAT) suggests evaporite deposition at rates of several km in less than a few million years. These rapid rates were once assumed to require tectonic control, but deeply penetrating seismic data now show that these deposits rest above largely unfaulted “top-rift” or “base-salt” unconformities and hence are post-rift or extremely late syn-rift units. Thermal subsidence could be expected to control them, but the observed subsidence rates far exceed thermal rates. We use seismic, well, and regional stratigraphic data from the Gulf of Mexico, South Atlantic, Mediterranean and Red Sea to assess the relative merits and shortcomings of possible mechanisms for the deposition of thick “mega-salt” basins. These include; (1) out-of-sequence late rift-related faulting/subsidence, (2) progressive infilling of pre-existing sub-sea air-filled depressions, and (3) post-rift outer marginal collapse. Option 1 is not supported by regional structural mapping in the GoM or SAT. Option 2 is fails to address the lack of interbedded/interfingered basin rim clastics and salt in both basins. Option 3 avoids these pitfalls and explains the unfaulted depositional continuity of thin salt in the eastern GOM, reaching from the onlap limit as allowed by global sea level in the Appalachiacola Basin to the structural level of the oceanic crust at the continent-ocean transition, which was emplaced at 2.5-3 km sub-sea. While current arguments for option 3 in the South Atlantic are weaker than for the GoM, we highlight circumstantial evidence from seismic and other data that favours evaporite deposition at global sea level on this margin. We highlight additional observations such as strong, early basinward tilting of the base salt surface, and the onlap by earliest sediments atop oceanic crust onto deformed salt cored folds above the rifted margin that are best explained by an outer marginal collapse model. Finally, we summarise how the concept of outer marginal collapse, which occurs between the rift and drift stages of margin formation, impacts petroleum systems in general. Panel_15459 Panel_15459 8:45 AM 9:05 AM

Here we use dynamical models of rifting to show how lower crustal rheology affects conjugate margin architecture and the nature of the continent-ocean transition (COT). We explore the behavior of South Atlantic conjugate margins, specifically the Campos/Angola, which developed along the Late Proterozoic Ribeira/Kaoko fold belt, to the Camamu/South Gabon basins, formed on the São Francisco/Congo Craton. Along these conjugate margins the degree of asymmetry increases southwards. Additionally, in Campos the crust tapers smoothly towards break-up, faults show small offsets and the area of hyper-extended crust (< 10 km thickness) is very wide (~ 200 km). To the North, in the Camamu, faults have much larger offsets, crustal thinning is abrupt and the margin much narrower. Our models show that a strong lower crustal rheology, which would be expected for a craton-like setting of the Camamu, effectively couples deformation in upper crust and mantle, leading to rapid crustal break-up and subsidence through crust-cutting faults. These crust-cutting faults allow serpentinisation to start before break-up, and produce narrow margins with only slight degrees of asymmetry. Coupling of lithospheric layers leads to quick upwelling of the asthenosphere and melting. For slow extension velocities, such as those prevalent in this area, < 5 mm/yr, melting starts after the onset of serpentinisation. The resulting COT consists of exhumed and serpentinised mantle, underlain by a thin layer of frozen magma. For the same extension velocities, when the lower crust is weak as anticipated for a fold belt setting such as in Campos/Angola, rifting starts with a prolonged phase characterized by minor faulting distributed over a wide area and moderate crustal thinning. Continuing extension leads to strain localization, coupling of lithospheric layers, more pronounced crustal thinning and the emergence of an array of sequential, oceanward younging faults, and produces wide, hyper-extended and asymmetric margins (Brune et al., 2014). In this case, serpentinisation is insignificant because active faults do not reach the mantle. Asthenospheric upwelling is less pronounced, and the onset and amount of melting is delayed with respect to the previous case. When crustal break-up occurs, magma rises to form oceanic crust and a narrow continent-ocean transition. Thus during rifting, melting and oceanization is not only controlled by extension velocity but also by the rheology of the lower crust. Here we use dynamical models of rifting to show how lower crustal rheology affects conjugate margin architecture and the nature of the continent-ocean transition (COT). We explore the behavior of South Atlantic conjugate margins, specifically the Campos/Angola, which developed along the Late Proterozoic Ribeira/Kaoko fold belt, to the Camamu/South Gabon basins, formed on the São Francisco/Congo Craton. Along these conjugate margins the degree of asymmetry increases southwards. Additionally, in Campos the crust tapers smoothly towards break-up, faults show small offsets and the area of hyper-extended crust (< 10 km thickness) is very wide (~ 200 km). To the North, in the Camamu, faults have much larger offsets, crustal thinning is abrupt and the margin much narrower. Our models show that a strong lower crustal rheology, which would be expected for a craton-like setting of the Camamu, effectively couples deformation in upper crust and mantle, leading to rapid crustal break-up and subsidence through crust-cutting faults. These crust-cutting faults allow serpentinisation to start before break-up, and produce narrow margins with only slight degrees of asymmetry. Coupling of lithospheric layers leads to quick upwelling of the asthenosphere and melting. For slow extension velocities, such as those prevalent in this area, < 5 mm/yr, melting starts after the onset of serpentinisation. The resulting COT consists of exhumed and serpentinised mantle, underlain by a thin layer of frozen magma. For the same extension velocities, when the lower crust is weak as anticipated for a fold belt setting such as in Campos/Angola, rifting starts with a prolonged phase characterized by minor faulting distributed over a wide area and moderate crustal thinning. Continuing extension leads to strain localization, coupling of lithospheric layers, more pronounced crustal thinning and the emergence of an array of sequential, oceanward younging faults, and produces wide, hyper-extended and asymmetric margins (Brune et al., 2014). In this case, serpentinisation is insignificant because active faults do not reach the mantle. Asthenospheric upwelling is less pronounced, and the onset and amount of melting is delayed with respect to the previous case. When crustal break-up occurs, magma rises to form oceanic crust and a narrow continent-ocean transition. Thus during rifting, melting and oceanization is not only controlled by extension velocity but also by the rheology of the lower crust. Panel_15461 Panel_15461 9:05 AM 9:25 AM

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The Argentinian Passive Margin provides an exceptional example of a volcanic passive margin that has been a focus, along with much of the South Atlantic, for hydrocarbon exploration and understanding the crustal architecture will be essential for exploration success. Recently acquired, well imaged, seismic reflection data is used to constrain the margin architecture. These new data provide significant improvements in imaging throughout the oceanic and continental lithosphere that enables us to interpret lower and mid crustal reflectivity, the continental and oceanic moho, seaward dipping reflections and oceanic crust domains. Despite this high quality imaging uncertainty still remains in both the interpretation of the data as well as the geophysical properties of the margin, including the extent of lower crustal magmatic bodies, the geometry of break-up volcanics and Seaward Dipping Reflection emplacement. Constraining these interpretations have a fundamental control in our understanding of the processes involved in continental rifting and break up. Interpretation of previous data, as well as existing models of the margin, do not account for such uncertainty in the interpretations. In this study we present multiple seismic-structural interpretations for data that are geometrically valid. We then use a number of techniques, including kinematic restorations, gravity modelling, backstripping and subsidence analysis to test the validity of each of the models. By addressing the uncertainty inherent in any sub-surface data we can better constrain the suite of likely scenarios. This enables us not only to understand the evolution of, hence process involved in, lithospheric stretching, it also allows us to discuss how these uncertainty will influence the risking of future exploration in such frontier areas. The Argentinian Passive Margin provides an exceptional example of a volcanic passive margin that has been a focus, along with much of the South Atlantic, for hydrocarbon exploration and understanding the crustal architecture will be essential for exploration success. Recently acquired, well imaged, seismic reflection data is used to constrain the margin architecture. These new data provide significant improvements in imaging throughout the oceanic and continental lithosphere that enables us to interpret lower and mid crustal reflectivity, the continental and oceanic moho, seaward dipping reflections and oceanic crust domains. Despite this high quality imaging uncertainty still remains in both the interpretation of the data as well as the geophysical properties of the margin, including the extent of lower crustal magmatic bodies, the geometry of break-up volcanics and Seaward Dipping Reflection emplacement. Constraining these interpretations have a fundamental control in our understanding of the processes involved in continental rifting and break up. Interpretation of previous data, as well as existing models of the margin, do not account for such uncertainty in the interpretations. In this study we present multiple seismic-structural interpretations for data that are geometrically valid. We then use a number of techniques, including kinematic restorations, gravity modelling, backstripping and subsidence analysis to test the validity of each of the models. By addressing the uncertainty inherent in any sub-surface data we can better constrain the suite of likely scenarios. This enables us not only to understand the evolution of, hence process involved in, lithospheric stretching, it also allows us to discuss how these uncertainty will influence the risking of future exploration in such frontier areas. Panel_15458 Panel_15458 10:30 AM 10:50 AM

The composition and thickness of crustal basement are critical to frontier hydrocarbon exploration in deep-water rifted continental margin settings. For the Black Sea, we need to know the distribution of continental and oceanic crust, ocean-continent transition structure, continent-ocean boundary location and magmatic type (whether magma poor, normal or magma rich). We apply a set a quantitative analytical techniques based on ION’s deep long-offset seismic reflection data. These quantitative analytical techniques consist of: (1) Gravity inversion, incorporating a lithosphere thermal gravity anomaly, to give Moho depth, crustal basement thickness & continental lithosphere thinning (2) RDA (residual depth anomaly) analysis to give departures from oceanic bathymetry (3) Subsidence analysis using 3D flexural backstripping to give lithosphere thinning (4) Joint inversion of deep seismic reflection and gravity data to give lateral variations in basement density and seismic velocity. The combined interpretation of these independent quantitative measurements are used together to determine OCT structure, COB location and crustal type. Superposition of the 3D Moho surface determined from gravity inversion onto PSDM and PSTM seismic sections provides assistance to, and validation of, deep seismic reflection interpretation. Integrated quantitative analysis maximises the use of the ION deep seismic data. Radiogenic heat-productivity within continental basement contributes significantly to hydrocarbon maturation; in contrast oceanic crust or exhumed mantle contributes very little. We use lithosphere thinning determined from gravity inversion together with crustal type determined from combined integrated quantitative analysis to predict the residual continental radioagenic heat flow contribution. Outputs from our 3D quantitative analysis of the Black Sea include grids of lithosphere thinning , ? factor and heat flow history for input to petroleum systems modelling. The composition and thickness of crustal basement are critical to frontier hydrocarbon exploration in deep-water rifted continental margin settings. For the Black Sea, we need to know the distribution of continental and oceanic crust, ocean-continent transition structure, continent-ocean boundary location and magmatic type (whether magma poor, normal or magma rich). We apply a set a quantitative analytical techniques based on ION’s deep long-offset seismic reflection data. These quantitative analytical techniques consist of: (1) Gravity inversion, incorporating a lithosphere thermal gravity anomaly, to give Moho depth, crustal basement thickness & continental lithosphere thinning (2) RDA (residual depth anomaly) analysis to give departures from oceanic bathymetry (3) Subsidence analysis using 3D flexural backstripping to give lithosphere thinning (4) Joint inversion of deep seismic reflection and gravity data to give lateral variations in basement density and seismic velocity. The combined interpretation of these independent quantitative measurements are used together to determine OCT structure, COB location and crustal type. Superposition of the 3D Moho surface determined from gravity inversion onto PSDM and PSTM seismic sections provides assistance to, and validation of, deep seismic reflection interpretation. Integrated quantitative analysis maximises the use of the ION deep seismic data. Radiogenic heat-productivity within continental basement contributes significantly to hydrocarbon maturation; in contrast oceanic crust or exhumed mantle contributes very little. We use lithosphere thinning determined from gravity inversion together with crustal type determined from combined integrated quantitative analysis to predict the residual continental radioagenic heat flow contribution. Outputs from our 3D quantitative analysis of the Black Sea include grids of lithosphere thinning , ? factor and heat flow history for input to petroleum systems modelling. Panel_15465 Panel_15465 10:50 AM 11:10 AM

Integration of seismic, well, shallow core, 40Ar/39Ar (Ar), apatite fission track (AFT), detrital zircon U/Pb (DZ), and biostratigraphic data from the Alaska Chukchi shelf provides a record of Cretaceous tectonics and sedimentation from the front of the Wrangel-Herald arch, across its foreland, and into the North Chukchi, Canada, and Colville basins. Geochronology of tephra (Ar) and analysis of minimum DZ crystallization and AFT cooling ages, effective tools as the result of coeval volcanism on the Russian Chukotka peninsula, and biostratigraphy confirm a complete Aptian through Campanian (and perhaps younger) stratigraphy preserved in parts of the Chukchi shelf. AFT analysis suggests prolonged Cretaceous exhumation of the Chukotka thrust belt, rapid cooling at the front of the thrust belt (Wrangel-Herald arch) between 120 and 80 Ma, and slow cooling in the proximal foreland beginning between 90 and 80 Ma. Lower Cretaceous stratal geometry displays proximal, topset seismic facies that grade northward and eastward into clinothems comprising bottomset, foreset, and topset seismic facies. Upper Cretaceous stratal geometry in the west includes a series of north-dipping, shingled unconformities and in the east includes a series of low relief sequence-bounding disconformities. The up-section change in strata geometry likely reflects a temporal gradation in tectonic influences. Early Cretaceous influences included relict accommodation domains (positive and negative) inherited from Late Paleozoic extension (Hanna trough and flanking platforms), approaching north-vergent contraction in the Chukotka thrust belt, and presence of high accommodation domains to the north (North Chukchi and Canada extensional basins) and east (Colville foreland basin). Late Cretaceous influences included waning of north-vergent contraction in the Chukotka thrust belt, rejuvenation of extensional accommodation in the North Chukchi basin, and filling of the Colville basin. In essence, the Chukchi shelf during the Cretaceous was an area of moderate to low accommodation, decreasing sediment supply, and increasing sediment by-pass between provenance areas to the south (Chukotka thrust belt) and high accommodation (>8–12 km) to the north (North Chukchi and Canada basins) and east (Colville basin, Early Cretaceous only). A significant consequence of this setting is a huge area (>80,000 km2) across which key source rocks and prospective reservoirs are in the oil window. Integration of seismic, well, shallow core, 40Ar/39Ar (Ar), apatite fission track (AFT), detrital zircon U/Pb (DZ), and biostratigraphic data from the Alaska Chukchi shelf provides a record of Cretaceous tectonics and sedimentation from the front of the Wrangel-Herald arch, across its foreland, and into the North Chukchi, Canada, and Colville basins. Geochronology of tephra (Ar) and analysis of minimum DZ crystallization and AFT cooling ages, effective tools as the result of coeval volcanism on the Russian Chukotka peninsula, and biostratigraphy confirm a complete Aptian through Campanian (and perhaps younger) stratigraphy preserved in parts of the Chukchi shelf. AFT analysis suggests prolonged Cretaceous exhumation of the Chukotka thrust belt, rapid cooling at the front of the thrust belt (Wrangel-Herald arch) between 120 and 80 Ma, and slow cooling in the proximal foreland beginning between 90 and 80 Ma. Lower Cretaceous stratal geometry displays proximal, topset seismic facies that grade northward and eastward into clinothems comprising bottomset, foreset, and topset seismic facies. Upper Cretaceous stratal geometry in the west includes a series of north-dipping, shingled unconformities and in the east includes a series of low relief sequence-bounding disconformities. The up-section change in strata geometry likely reflects a temporal gradation in tectonic influences. Early Cretaceous influences included relict accommodation domains (positive and negative) inherited from Late Paleozoic extension (Hanna trough and flanking platforms), approaching north-vergent contraction in the Chukotka thrust belt, and presence of high accommodation domains to the north (North Chukchi and Canada extensional basins) and east (Colville foreland basin). Late Cretaceous influences included waning of north-vergent contraction in the Chukotka thrust belt, rejuvenation of extensional accommodation in the North Chukchi basin, and filling of the Colville basin. In essence, the Chukchi shelf during the Cretaceous was an area of moderate to low accommodation, decreasing sediment supply, and increasing sediment by-pass between provenance areas to the south (Chukotka thrust belt) and high accommodation (>8–12 km) to the north (North Chukchi and Canada basins) and east (Colville basin, Early Cretaceous only). A significant consequence of this setting is a huge area (>80,000 km²) across which key source rocks and prospective reservoirs are in the oil window. Panel_15462 Panel_15462 11:10 AM 11:30 AM

The Siberian Arctic Shelf is one of the broadest continental shelves on Earth containing the Laptev, East Siberian and Chukchi Seas across an area of 3x106 km2. More than 13,000 line km of reflection data in the Laptev, East Siberian, and Chukchi Seas forms the basis for the interpretation east of the New Siberian Islands covering the North Chukchi-Vilkitski and New Siberian Sea Rift basins. The basement offshore (acoustic basement) is interpreted as an extension of onshore geology, which is dominated by Phanerozoic fold belts and their associated volcanic and plutonic complexes, and suture assemblages. These surveys and potential field data image a number of late Mesozoic and Cenozoic basins with at least 7.5 to 10 km of sedimentary fill. In the North Chukchi Basin as much as 20 km of sedimentary fill lies above acoustic basement. The entire shelf is overlain by a post-rift prograding succession. These basins have contrasting structural styles, even though they are connected and collectively relate to the opening of the Arctic Ocean. In the west, the East Siberian Sea Rift is comprised of arrays of tilted fault blocks rooting in a mid-crustal detachment system, underlain by a master fault at or near Moho level. It covers an area equivalent in size to the entire North Sea. In contrast, the North Chukchi Basin is a deep, gently-structured basin detached at Moho level and floored by oceanic crust, or possibly by serpentinized mantle. These basins exhibit contrasting styles of stratigraphic fill, related to the tectonics underlying their creation. For example, late-stage (post-rift) architecture in the North Chukchi Basin shows Tertiary shelf margin progradation traversing over 400 km northward over vertically accreting, Late Cretaceous high-accommodation aggradational sedimentation. In contrast, the East Siberian Sea Rift exhibits more conventional rift basin architecture, with tilted fault blocks bounded by deep troughs and potential large hydrocarbon fetch areas, similar to the North Sea. These basins contain the potential for reservoir development in shelf margin, lowstand systems, sub-unconformity regional stratigraphic traps, and within horst-graben systems typical of Neogene rifts. A mega-regional total sediment (above acoustic basement) isopach map over the large area illustrates that several other large gravity lows are present and suggests substantial potential for additional prospective basins. The Siberian Arctic Shelf is one of the broadest continental shelves on Earth containing the Laptev, East Siberian and Chukchi Seas across an area of 3x106 km². More than 13,000 line km of reflection data in the Laptev, East Siberian, and Chukchi Seas forms the basis for the interpretation east of the New Siberian Islands covering the North Chukchi-Vilkitski and New Siberian Sea Rift basins. The basement offshore (acoustic basement) is interpreted as an extension of onshore geology, which is dominated by Phanerozoic fold belts and their associated volcanic and plutonic complexes, and suture assemblages. These surveys and potential field data image a number of late Mesozoic and Cenozoic basins with at least 7.5 to 10 km of sedimentary fill. In the North Chukchi Basin as much as 20 km of sedimentary fill lies above acoustic basement. The entire shelf is overlain by a post-rift prograding succession. These basins have contrasting structural styles, even though they are connected and collectively relate to the opening of the Arctic Ocean. In the west, the East Siberian Sea Rift is comprised of arrays of tilted fault blocks rooting in a mid-crustal detachment system, underlain by a master fault at or near Moho level. It covers an area equivalent in size to the entire North Sea. In contrast, the North Chukchi Basin is a deep, gently-structured basin detached at Moho level and floored by oceanic crust, or possibly by serpentinized mantle. These basins exhibit contrasting styles of stratigraphic fill, related to the tectonics underlying their creation. For example, late-stage (post-rift) architecture in the North Chukchi Basin shows Tertiary shelf margin progradation traversing over 400 km northward over vertically accreting, Late Cretaceous high-accommodation aggradational sedimentation. In contrast, the East Siberian Sea Rift exhibits more conventional rift basin architecture, with tilted fault blocks bounded by deep troughs and potential large hydrocarbon fetch areas, similar to the North Sea. These basins contain the potential for reservoir development in shelf margin, lowstand systems, sub-unconformity regional stratigraphic traps, and within horst-graben systems typical of Neogene rifts. A mega-regional total sediment (above acoustic basement) isopach map over the large area illustrates that several other large gravity lows are present and suggests substantial potential for additional prospective basins. Panel_15463 Panel_15463 11:30 AM 11:50 AM

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Panel_15805 Panel_15805 8:00 AM 12:00 AM

An advanced system of mud flow measurement while drilling enabled to detect fractures and intervals of high permeability within a tight, fractured reservoir via the identification and interpretation of mud micro-losses. The system is based on an electromagnetic flow meter installed on the flow line. The high accuracy of the flow data obtained was achieved thanks to the specifications of the meter, much more accurate than standard field systems, and with fit-for-purpose installation design of the system. Standard mud flow detection while drilling only enables a qualitative indication of the flow and it is not sensitive enough to identify subtle flow changes linked to the initial stages of an influx or to the minor fluid loss occurring when a formation fracture is encountered. However, the more direct, instantaneous indication of the presence of an open fracture in a well comes from the mud flow variations. The authors have utilized such data in conjunction with offset data from previous wells and existing literature, which indicated the presence of two different set of fractures with different aperture and density. An interpretation model was then generated and applied to the well being drilled. The fracture detection capability was enhanced by the analysis of drilling and hydraulic parameters variations also recorded in Real-Time; their change was related to change of the mechanical properties or the rock. Another decisive parameter monitored was the mud gas, since gas readings variations were often associated with the presence of open fractures in which hydrocarbons were circulating. The two families of fractures were clearly identified using this technique. The system and procedure have been recognised as a valid solution for fractured reservoir characterization and have been used in a composite log along with other data from e-logs, collected after the well was drilled. Furthermore the system enabled to detect the mechanical fractures induced by the drilling action, which masked the natural open fractures pattern in the e-logs of the offset wells drilled previously in the same basin. An advanced system of mud flow measurement while drilling enabled to detect fractures and intervals of high permeability within a tight, fractured reservoir via the identification and interpretation of mud micro-losses. The system is based on an electromagnetic flow meter installed on the flow line. The high accuracy of the flow data obtained was achieved thanks to the specifications of the meter, much more accurate than standard field systems, and with fit-for-purpose installation design of the system. Standard mud flow detection while drilling only enables a qualitative indication of the flow and it is not sensitive enough to identify subtle flow changes linked to the initial stages of an influx or to the minor fluid loss occurring when a formation fracture is encountered. However, the more direct, instantaneous indication of the presence of an open fracture in a well comes from the mud flow variations. The authors have utilized such data in conjunction with offset data from previous wells and existing literature, which indicated the presence of two different set of fractures with different aperture and density. An interpretation model was then generated and applied to the well being drilled. The fracture detection capability was enhanced by the analysis of drilling and hydraulic parameters variations also recorded in Real-Time; their change was related to change of the mechanical properties or the rock. Another decisive parameter monitored was the mud gas, since gas readings variations were often associated with the presence of open fractures in which hydrocarbons were circulating. The two families of fractures were clearly identified using this technique. The system and procedure have been recognised as a valid solution for fractured reservoir characterization and have been used in a composite log along with other data from e-logs, collected after the well was drilled. Furthermore the system enabled to detect the mechanical fractures induced by the drilling action, which masked the natural open fractures pattern in the e-logs of the offset wells drilled previously in the same basin. Panel_15052 Panel_15052 8:05 AM 8:25 AM

Amplitude and phase shift of complex resistivity are analyzed on 150+ brine-saturated carbonate core plug samples in a log sweep of 15 frequency steps from 0.1 – 100,000 Hz at varying reservoir pressures. In the measured dolomites the dispersive behavior of resistivity is between 100 – 100,000 Hz and is directly related to the porosity of the sample. Spectral analysis of complex resistivity is the study of the dispersive behavior of resistivity that is the change of resistance of a medium at different frequencies. Complex resistivity consists of the amplitude and the phase shift, which is the delay between the induced voltage signal and the resulting current signal. The delay can be attributed to polarization effects of a medium that is exposed to an alternating current. The magnitude of polarization is dependent on surface chemical and pore geometrical properties. The samples of this study are all carbonates, and, thus, surface chemistry effects can be omitted, leaving the pore geometry as sole influencing factor. Consequently, the dispersion of complex resistivity can be used to estimate pore geometric and hence rock petrophysical properties. For example, in the high-porosity samples, amplitudes are low across the frequency spectrum. In the low-porosity samples, amplitudes are high but drop significantly at frequencies above 1,000 Hz. Phase shifts display more variance in all of the samples. Focusing on the 100 – 2,000 Hz range we see a characteristic slope in the phase shift dispersion, which correlates with the permeability of the sample. Using the slope, porosity, and cementation factor, calculated from the amplitude at 720 Hz, we are able to predict permeability with high correlation coefficient of R2 = 0.82. Additionally, pore geometries of the samples are quantified and parameterized with digital image analysis (DIA) on thin-sections. We observe trends of larger and less complex pores resulting in higher cementation factors. The extracted pores are also used to analyze the pore size distribution, which shows a power-law behavior in all samples when plotted on log-log scale using non-linear binning, indicating fractal scaling of the pore space. Amplitude and phase shift of complex resistivity are analyzed on 150+ brine-saturated carbonate core plug samples in a log sweep of 15 frequency steps from 0.1 – 100,000 Hz at varying reservoir pressures. In the measured dolomites the dispersive behavior of resistivity is between 100 – 100,000 Hz and is directly related to the porosity of the sample. Spectral analysis of complex resistivity is the study of the dispersive behavior of resistivity that is the change of resistance of a medium at different frequencies. Complex resistivity consists of the amplitude and the phase shift, which is the delay between the induced voltage signal and the resulting current signal. The delay can be attributed to polarization effects of a medium that is exposed to an alternating current. The magnitude of polarization is dependent on surface chemical and pore geometrical properties. The samples of this study are all carbonates, and, thus, surface chemistry effects can be omitted, leaving the pore geometry as sole influencing factor. Consequently, the dispersion of complex resistivity can be used to estimate pore geometric and hence rock petrophysical properties. For example, in the high-porosity samples, amplitudes are low across the frequency spectrum. In the low-porosity samples, amplitudes are high but drop significantly at frequencies above 1,000 Hz. Phase shifts display more variance in all of the samples. Focusing on the 100 – 2,000 Hz range we see a characteristic slope in the phase shift dispersion, which correlates with the permeability of the sample. Using the slope, porosity, and cementation factor, calculated from the amplitude at 720 Hz, we are able to predict permeability with high correlation coefficient of R2 = 0.82. Additionally, pore geometries of the samples are quantified and parameterized with digital image analysis (DIA) on thin-sections. We observe trends of larger and less complex pores resulting in higher cementation factors. The extracted pores are also used to analyze the pore size distribution, which shows a power-law behavior in all samples when plotted on log-log scale using non-linear binning, indicating fractal scaling of the pore space. Panel_15055 Panel_15055 8:25 AM 8:45 AM

Models for carbonate platform slope deposition are generally thought to be line-sourced sediments with the grain size distribution that is controlled by down-dip orientation of sediment transport. Increased sedimentation is expected on the leeward side of the platform, such as the western slope of GBB, that receives the fines from the producing platform. High-resolution multibeam, subbottom profiles, and a new map based on morphological classification of the area from attributes of bathymetry data, reveal the duality of the slope processes in an unprecedented way. The slope facies distribution is a result of: 1) platform-derived gravity-driven sediment transport and 2) the sediment distribution parallel and down-slope by benthic and cascading density currents, respectively. The classic interpretation of the platform margin acting as line-source for slope sediment facies distribution should be refined. Karst features produced during platform emergence influences cascading density currents by confining and channelizing the flow. The regular nature of these karst features (grooves) is responsible for the regular spacing of the plunge pools and gullies. As such, the gullies dissecting the upper slope along southwestern GBB have a hydrodynamic origin. Grain size distribution is not solely controlled by down-dip, but rather reflects the complex interplay of bathymetry and sediment transporting currents. Changes in inclination provide hydraulic jumps to transform current regime of downslope currents, which ultimately results in the deposition of characteristic bedforms. Slope parallel currents erode and redistribute the sediment along platform strike (winnowing), leaving the coarse-grained sediment fraction behind. Models for carbonate platform slope deposition are generally thought to be line-sourced sediments with the grain size distribution that is controlled by down-dip orientation of sediment transport. Increased sedimentation is expected on the leeward side of the platform, such as the western slope of GBB, that receives the fines from the producing platform. High-resolution multibeam, subbottom profiles, and a new map based on morphological classification of the area from attributes of bathymetry data, reveal the duality of the slope processes in an unprecedented way. The slope facies distribution is a result of: 1) platform-derived gravity-driven sediment transport and 2) the sediment distribution parallel and down-slope by benthic and cascading density currents, respectively. The classic interpretation of the platform margin acting as line-source for slope sediment facies distribution should be refined. Karst features produced during platform emergence influences cascading density currents by confining and channelizing the flow. The regular nature of these karst features (grooves) is responsible for the regular spacing of the plunge pools and gullies. As such, the gullies dissecting the upper slope along southwestern GBB have a hydrodynamic origin. Grain size distribution is not solely controlled by down-dip, but rather reflects the complex interplay of bathymetry and sediment transporting currents. Changes in inclination provide hydraulic jumps to transform current regime of downslope currents, which ultimately results in the deposition of characteristic bedforms. Slope parallel currents erode and redistribute the sediment along platform strike (winnowing), leaving the coarse-grained sediment fraction behind. Panel_15054 Panel_15054 8:45 AM 9:05 AM

Heterozoan carbonate systems are increasingly being recognized as important petroleum reservoirs in the rock record, yet models for such systems are lacking, especially those that developed in low latitude settings. A Middle-Late Miocene carbonate ramp system in Puerto Rico provides ideal outcrops of heterozoan-dominated carbonates that were deposited in a tropical setting. Three sequences (DS1, DS2, and DS3) developed in response to relative sea-level fluctuations. Each sequence is characterized by basal heterozoan-dominated facies (e.g. benthic foraminifera, molluscs, red algae) that grade upward to a mix of heterozoan and photozoan (e.g. cool- and turbid-water corals) facies at the top. DS1 transgressive deposits consist of in-place Kuphus incrassatus bivalves within a soritid foraminifera facies, and Amphistegina sp. foraminifera packstone interbedded with Kuphus and oyster facies. Upper DS1 consists of Montastrea sp. coral debris flows followed by in-place Goniopora sp. and Porites sp. coral reef that can be traced down paleoslope indicating deposition during highstand and relative sea-level fall. DS2 transgressive deposits consist of soritid and bivalve packstone facies that grade upward to facies containing corals (Montastrea sp., Porites sp.) deposited during highstand and relative sea-level fall. DS3 transgressive deposits consist of soritid and bivalve packstone facies, which grade upward to red algae boundstones and coral-rich facies (Montastrea sp., Porites sp., and Agariicid sp.) deposited during highstand and relative sea-level fall. Upwelling has been documented as a regional process in the Caribbean during the Middle and Late Miocene. The dominance of heterozoans and local photozoan corals tolerant of cool and turbid conditions in our study is consistent with upwelling of nutrient-rich and cooler water. Although upwelling appears to have been persistent throughout deposition, the presence of photozoans only in the highstand and regressive portions of sequences suggests a relationship of upwelling to relative sea level, with highest intensities during transgressions. Shallow water heterozoan systems that form in tropical settings require special conditions; in our study upwelling and sea level were the major controls and their interaction resulted in predictable facies partitioning. These results have application to heterozoan reservoir systems, such as those in offshore Vietnam and Venezuela. Heterozoan carbonate systems are increasingly being recognized as important petroleum reservoirs in the rock record, yet models for such systems are lacking, especially those that developed in low latitude settings. A Middle-Late Miocene carbonate ramp system in Puerto Rico provides ideal outcrops of heterozoan-dominated carbonates that were deposited in a tropical setting. Three sequences (DS1, DS2, and DS3) developed in response to relative sea-level fluctuations. Each sequence is characterized by basal heterozoan-dominated facies (e.g. benthic foraminifera, molluscs, red algae) that grade upward to a mix of heterozoan and photozoan (e.g. cool- and turbid-water corals) facies at the top. DS1 transgressive deposits consist of in-place Kuphus incrassatus bivalves within a soritid foraminifera facies, and Amphistegina sp. foraminifera packstone interbedded with Kuphus and oyster facies. Upper DS1 consists of Montastrea sp. coral debris flows followed by in-place Goniopora sp. and Porites sp. coral reef that can be traced down paleoslope indicating deposition during highstand and relative sea-level fall. DS2 transgressive deposits consist of soritid and bivalve packstone facies that grade upward to facies containing corals (Montastrea sp., Porites sp.) deposited during highstand and relative sea-level fall. DS3 transgressive deposits consist of soritid and bivalve packstone facies, which grade upward to red algae boundstones and coral-rich facies (Montastrea sp., Porites sp., and Agariicid sp.) deposited during highstand and relative sea-level fall. Upwelling has been documented as a regional process in the Caribbean during the Middle and Late Miocene. The dominance of heterozoans and local photozoan corals tolerant of cool and turbid conditions in our study is consistent with upwelling of nutrient-rich and cooler water. Although upwelling appears to have been persistent throughout deposition, the presence of photozoans only in the highstand and regressive portions of sequences suggests a relationship of upwelling to relative sea level, with highest intensities during transgressions. Shallow water heterozoan systems that form in tropical settings require special conditions; in our study upwelling and sea level were the major controls and their interaction resulted in predictable facies partitioning. These results have application to heterozoan reservoir systems, such as those in offshore Vietnam and Venezuela. Panel_15053 Panel_15053 9:05 AM 9:25 AM

Panel_15806 Panel_15806 9:25 AM 12:00 AM

Changes in the factory of Cenozoic tropical marine carbonates have been for long attributed to major variations on climatic and environmental conditions. Although important changes on the factories of Cenozoic Caribbean carbonates seem to have followed global climatic and environmental changes, the influence of tectonics on the occurrence, distribution and stratigraphy of shallow marine carbonate factories along this area is far from being well understood. Here we use sedimentologic characterization and multiple geochemical proxies to assess the influence of changing environmental conditions, tectonics and sea level change on the development of the shallow marine carbonate factories. During the Paleocene-early Oligocene interval, a period of predominant high atmospheric pCO2, coralline algae were the principal carbonate builders of shallow marine carbonate successions. The predominance of coralline red algae over corals on the shallow marine carbonate factories was likely related to high sea surface temperatures and high turbidity. Deposition of these factories was also controlled by diachronic opening of different sedimentary basins along the SE Circum Caribbean resulting from transpressional tectonics. Calcareous algae persisted until the middle Oligocene; a period when the drop of atmospheric pCO2 allowed the appearance of corals as the main constituents of the shallow marine carbonate factories by late Oligocene times. The late Oligocene interval is characterized by the occurrence of low diversity patchy coralline reefs, often mixed with siliciclastics. The occurrence of these patchy coralline successions occurred along rimmed mixed silicilastic/carbonate platforms and seems to have been related to low sea level. The lower Miocene interval is characterized by the development of rimmed carbonate platforms along which high diversity fringing coral reefs developed. The occurrence of these high diversity coralline carbonate factories was favored by a decrease in the siliciclastic input from the continents and further decrease in sea surface temperatures. Coral reef dominated the shallow marine carbonate factories until the middle Miocene, when a new period of calcareous algae reefs occurred along the Caribbean. This new change was the result of major changes in the Caribbean environmental conditions, which were driven by increased continental sediment runoff resulting from the exhumation of the northern Andes. Changes in the factory of Cenozoic tropical marine carbonates have been for long attributed to major variations on climatic and environmental conditions. Although important changes on the factories of Cenozoic Caribbean carbonates seem to have followed global climatic and environmental changes, the influence of tectonics on the occurrence, distribution and stratigraphy of shallow marine carbonate factories along this area is far from being well understood. Here we use sedimentologic characterization and multiple geochemical proxies to assess the influence of changing environmental conditions, tectonics and sea level change on the development of the shallow marine carbonate factories. During the Paleocene-early Oligocene interval, a period of predominant high atmospheric pCO₂, coralline algae were the principal carbonate builders of shallow marine carbonate successions. The predominance of coralline red algae over corals on the shallow marine carbonate factories was likely related to high sea surface temperatures and high turbidity. Deposition of these factories was also controlled by diachronic opening of different sedimentary basins along the SE Circum Caribbean resulting from transpressional tectonics. Calcareous algae persisted until the middle Oligocene; a period when the drop of atmospheric pCO₂ allowed the appearance of corals as the main constituents of the shallow marine carbonate factories by late Oligocene times. The late Oligocene interval is characterized by the occurrence of low diversity patchy coralline reefs, often mixed with siliciclastics. The occurrence of these patchy coralline successions occurred along rimmed mixed silicilastic/carbonate platforms and seems to have been related to low sea level. The lower Miocene interval is characterized by the development of rimmed carbonate platforms along which high diversity fringing coral reefs developed. The occurrence of these high diversity coralline carbonate factories was favored by a decrease in the siliciclastic input from the continents and further decrease in sea surface temperatures. Coral reef dominated the shallow marine carbonate factories until the middle Miocene, when a new period of calcareous algae reefs occurred along the Caribbean. This new change was the result of major changes in the Caribbean environmental conditions, which were driven by increased continental sediment runoff resulting from the exhumation of the northern Andes. Panel_15051 Panel_15051 10:10 AM 10:30 AM

A stratiform dolomite layer is developed in the Barremian shallow-water carbonates from offshore Abu Dhabi, United Arab Emirates. The average thickness is only 1.1 m, but the porosity-permeability values are significantly variable within the layer. We discuss the origin and development of the stratiform dolomite based on an integrated geochemical, petrographic and petrophysical evaluation using 81 cores recovered from the entire field. Carbon isotope values (d13C values) of the dolomite are relatively high (>5‰) and the strontium isotope ratios (87Sr/86Sr) mostly fall in the range of Barremian seawater. These geochemical signatures and the thin stratiform geometry suggest an early dolomitization phase below the seafloor driven by the diffusion of Mg2+ from the overlying mature seawater on the shallow platform top. Lateral changes in the dolomite content and permeability at the inter-well scale seem to be controlled by the permeability of the precursor facies. Dolomitization progressed further in grainier precursor (packstone) with higher permeability than muddier precursor (wackestone to mudstone), which led to higher dolomite content and greater permeability improvement in the grainier precursor. Oxygen isotope values (d18O values), trace element (Sr, Na, Fe and Mn) concentrations and existence of oil inclusions in the dolomites indicate a later burial dolomitization phase during and after oil emplacement. Late burial dolomitization yielded significant pore-filling dolomite cementation that seems to have preferentially impacted the higher permeability early dolomite, to the point of significantly deteriorating reservoir quality in some instances. The degree of cementation and the Na, Fe and Mn contents of dolomite generally increase toward the flank of the field in response to the delay in oil charge and the higher water saturation compared to the crest. Subsequently, dolomite-to-dolomite recrystallization is a dominant phase under current burial temperatures (>100 degrees Celsius), which have reset the d18O values and prevented the isotopically lighter Sr of formation water being incorporated into the dolomite. This recrystallization does not have significant impact on the petrophysical properties in the oil leg. Variance in reservoir quality of the stratiform dolomite is mainly dependent on the intensity and duration of dolomitization which is controlled by the interplay of depositional facies, structural position and oil charge. A stratiform dolomite layer is developed in the Barremian shallow-water carbonates from offshore Abu Dhabi, United Arab Emirates. The average thickness is only 1.1 m, but the porosity-permeability values are significantly variable within the layer. We discuss the origin and development of the stratiform dolomite based on an integrated geochemical, petrographic and petrophysical evaluation using 81 cores recovered from the entire field. Carbon isotope values (d13C values) of the dolomite are relatively high (>5‰) and the strontium isotope ratios (87Sr/86Sr) mostly fall in the range of Barremian seawater. These geochemical signatures and the thin stratiform geometry suggest an early dolomitization phase below the seafloor driven by the diffusion of Mg2+ from the overlying mature seawater on the shallow platform top. Lateral changes in the dolomite content and permeability at the inter-well scale seem to be controlled by the permeability of the precursor facies. Dolomitization progressed further in grainier precursor (packstone) with higher permeability than muddier precursor (wackestone to mudstone), which led to higher dolomite content and greater permeability improvement in the grainier precursor. Oxygen isotope values (d18O values), trace element (Sr, Na, Fe and Mn) concentrations and existence of oil inclusions in the dolomites indicate a later burial dolomitization phase during and after oil emplacement. Late burial dolomitization yielded significant pore-filling dolomite cementation that seems to have preferentially impacted the higher permeability early dolomite, to the point of significantly deteriorating reservoir quality in some instances. The degree of cementation and the Na, Fe and Mn contents of dolomite generally increase toward the flank of the field in response to the delay in oil charge and the higher water saturation compared to the crest. Subsequently, dolomite-to-dolomite recrystallization is a dominant phase under current burial temperatures (>100 degrees Celsius), which have reset the d18O values and prevented the isotopically lighter Sr of formation water being incorporated into the dolomite. This recrystallization does not have significant impact on the petrophysical properties in the oil leg. Variance in reservoir quality of the stratiform dolomite is mainly dependent on the intensity and duration of dolomitization which is controlled by the interplay of depositional facies, structural position and oil charge. Panel_15056 Panel_15056 10:30 AM 10:50 AM

The Late Jurassic Arab-D reservoir, composed of the Arab-D Member of the Arab Formation and upper part of the underlying Jubaila Formation, is highly prolific in several supergiant oil and gas fields in the Middle East. An outcrop analogue of equivalent age in central Saudi Arabia shows depositional facies and stratigraphic architecture that are similar to those inferred in the subsurface. This analogue has been studied using a high-resolution digital outcrop model integrated with measured sections, in order to understand and quantify facies relationships in storm-dominated, shallow-marine carbonates. Outcrops of the lower to middle Arab-D reservoir reveal a succession of interbedded muddy and grainy rocks that occur as a series of thin (0.5-1 m) fining-upward cycles. Cycles typically comprise a coarse-grained grainstone-to-rudstone lower part that contains muddy intraclasts and, locally, stromatoporoid and coral fragments, which fines upward into a wackestone cap. The finer portions of these cycles are bioturbated, and swaley cross-stratification occurs locally in both mud- and grain-dominated beds. Cycles are separated by sharp-to-erosional bases of varying relief, which cause cycle thickness to vary laterally. Locally, 1-3 m thick chaotically bedded conglomeratic intervals containing overturned stromatoporoid and coral clasts up to 1 m in diameter infill scours with steep-to-vertical walls that incise several meters into underlying deposits. The fining-upward cycles are interpreted to result from storm events that locally scoured and reworked sediments. The occurrence of swaley cross-stratification suggests deposition below fair weather wave base but above storm wave base. Larger storm events produced steep-sided scours that were filled by conglomeratic debris transported offshore from shallower water settings. Storm-event deposits vary laterally and vertically in their geometry, spacing and connectivity. Few coarse-grained beds extend across outcrop (<1 km) but instead pinch out laterally. Their lateral extent and degree of vertical amalgamation is controlled by erosional relief and paleotopography at bed boundaries. Conglomeratic scour fills show symmetrical and asymmetrical cross-sectional profiles, implying 3D variation in scour geometry and orientation. The heterogeneity observed in these outcrops has implications for the identification and correlation of reservoir flow units between wells, and for the effective properties of the flow units. The Late Jurassic Arab-D reservoir, composed of the Arab-D Member of the Arab Formation and upper part of the underlying Jubaila Formation, is highly prolific in several supergiant oil and gas fields in the Middle East. An outcrop analogue of equivalent age in central Saudi Arabia shows depositional facies and stratigraphic architecture that are similar to those inferred in the subsurface. This analogue has been studied using a high-resolution digital outcrop model integrated with measured sections, in order to understand and quantify facies relationships in storm-dominated, shallow-marine carbonates. Outcrops of the lower to middle Arab-D reservoir reveal a succession of interbedded muddy and grainy rocks that occur as a series of thin (0.5-1 m) fining-upward cycles. Cycles typically comprise a coarse-grained grainstone-to-rudstone lower part that contains muddy intraclasts and, locally, stromatoporoid and coral fragments, which fines upward into a wackestone cap. The finer portions of these cycles are bioturbated, and swaley cross-stratification occurs locally in both mud- and grain-dominated beds. Cycles are separated by sharp-to-erosional bases of varying relief, which cause cycle thickness to vary laterally. Locally, 1-3 m thick chaotically bedded conglomeratic intervals containing overturned stromatoporoid and coral clasts up to 1 m in diameter infill scours with steep-to-vertical walls that incise several meters into underlying deposits. The fining-upward cycles are interpreted to result from storm events that locally scoured and reworked sediments. The occurrence of swaley cross-stratification suggests deposition below fair weather wave base but above storm wave base. Larger storm events produced steep-sided scours that were filled by conglomeratic debris transported offshore from shallower water settings. Storm-event deposits vary laterally and vertically in their geometry, spacing and connectivity. Few coarse-grained beds extend across outcrop (<1 km) but instead pinch out laterally. Their lateral extent and degree of vertical amalgamation is controlled by erosional relief and paleotopography at bed boundaries. Conglomeratic scour fills show symmetrical and asymmetrical cross-sectional profiles, implying 3D variation in scour geometry and orientation. The heterogeneity observed in these outcrops has implications for the identification and correlation of reservoir flow units between wells, and for the effective properties of the flow units. Panel_15057 Panel_15057 10:50 AM 11:10 AM

Geologists working in offshore Brazil still vigorously debate the genetic origin of Cretaceous pre-salt lacustrine carbonates in the Santos Basin. Some carbonate petrologists have inferred that many of the macro-scale depositional features are of biological origin. Others contend that Brazilian pre-salt carbonate deposits are abiotic chemical precipitates formed in highly alkaline lakes. Each of these end-member paradigms has significant implications for how geologic models are constructed. To evaluate these genetic paradigms, detailed thin-section petrography (TSP), scanning electron microscopy (SEM) and energy dispersive spectroscopy (EDS) were performed on thin sections and bulk core samples from well BM-S-22 Guarani-1ST (3-ESSO-004-SPS). The cored interval is characterized by a diverse boundstone assemblage including shrubs, spherulites, laminated sediments with abundant stevensite clay, domal and columnar stromatolites, oncoids, thrombolites, and travertine. In some boundstones, macro-scale structures and morphologies, such as crinkly-laminated stromatolites with centimeter-scale columnar relief, are highly suggestive of microbially-influenced sedimentation. SEM analyses of freshly broken core samples indicate that the columnar stromatolite/oncolite facies contains abundant evidence of fossilized microbes including microtubules, filaments, rods and molds that measure 1-2 µm in diameter and tens of µm in length. These features are similar in size and shape to modern and fossilized microbes. SEM observations coupled with geochemical evidence from within the various boundstone assemblages indicate that the influence of microbes on sedimentation within the Santos Basin is unequivocal. Although microscopic evidence does not illuminate the precise role microbes play within the basin (e.g., binding, trapping, baffling, or biostabilizing sediments) fossilized microbial features within the pre-salt suggest that depositional and reservoir models should account for their potential impact. Geologists working in offshore Brazil still vigorously debate the genetic origin of Cretaceous pre-salt lacustrine carbonates in the Santos Basin. Some carbonate petrologists have inferred that many of the macro-scale depositional features are of biological origin. Others contend that Brazilian pre-salt carbonate deposits are abiotic chemical precipitates formed in highly alkaline lakes. Each of these end-member paradigms has significant implications for how geologic models are constructed. To evaluate these genetic paradigms, detailed thin-section petrography (TSP), scanning electron microscopy (SEM) and energy dispersive spectroscopy (EDS) were performed on thin sections and bulk core samples from well BM-S-22 Guarani-1ST (3-ESSO-004-SPS). The cored interval is characterized by a diverse boundstone assemblage including shrubs, spherulites, laminated sediments with abundant stevensite clay, domal and columnar stromatolites, oncoids, thrombolites, and travertine. In some boundstones, macro-scale structures and morphologies, such as crinkly-laminated stromatolites with centimeter-scale columnar relief, are highly suggestive of microbially-influenced sedimentation. SEM analyses of freshly broken core samples indicate that the columnar stromatolite/oncolite facies contains abundant evidence of fossilized microbes including microtubules, filaments, rods and molds that measure 1-2 µm in diameter and tens of µm in length. These features are similar in size and shape to modern and fossilized microbes. SEM observations coupled with geochemical evidence from within the various boundstone assemblages indicate that the influence of microbes on sedimentation within the Santos Basin is unequivocal. Although microscopic evidence does not illuminate the precise role microbes play within the basin (e.g., binding, trapping, baffling, or biostabilizing sediments) fossilized microbial features within the pre-salt suggest that depositional and reservoir models should account for their potential impact. Panel_15099 Panel_15099 11:10 AM 11:30 AM

Previous studies have addressed the role of siliciclastic basin infill on accommodation space and consequent influence on progradation geometry of carbonate platforms. Few studies have addressed the role of siliciclastic basin fill on carbonate platform margin evolution from a basin-wide perspective. In order to analyze the impact of siliciclastic turbidite basin infill on platform architecture, this study integrates a regional analysis of turbidite provenance and compares evolution of Triassic margin architecture of the Great Bank of Guizhou (an isolated platform) in the Nanpanjiang Basin of South China and its adjacent extensive attached Yangtze Platform. In the Yangtze Platform, earlier arrival of Anisian siliciclastic turbidites sourced from the Jiangnan uplift in the eastern area filled the basin margin at Guiyang, producing a substratum above which the platform could prograde basinward. In the western area at Guanling, synchronous infilling of the basin margin allowed intertonguing and promoted stability of the margin and vertical aggradation. Later arrival of the turbidite basin fill distant from the Jiangnan uplift coupled with high subsidence rates caused margin instability and development of a backstepped and gravitational collapse architecture in the Zhenfeng and Anlong areas. Likewise in the Great Bank of Guizhou, earlier arrival (Anisian) and infilling of the basin by turbidites resulted in progradation of the platform margin in the Xiliang area proximal to the Jiangnan uplift, whereas in western areas distal from the siliciclastic sources the platform aggraded to develop extreme relief and gravitationally collapsed margins. High rates of subsidence coupled with the lack of basin infilling locked the platform into aggradational growth and resulted in the development of a high-relief escarpment architecture and large-scale gravitational collapse. The timing and pattern of basin infill impacts carbonate platform evolution in a regionally predictable pattern: early infill enables margin progradation in areas proximal to siliciclastic sources, whereas late infill in platform areas distant from sources results in aggradation and development of extreme platform margin relief with large-scale gravitational sector collapse. Previous studies have addressed the role of siliciclastic basin infill on accommodation space and consequent influence on progradation geometry of carbonate platforms. Few studies have addressed the role of siliciclastic basin fill on carbonate platform margin evolution from a basin-wide perspective. In order to analyze the impact of siliciclastic turbidite basin infill on platform architecture, this study integrates a regional analysis of turbidite provenance and compares evolution of Triassic margin architecture of the Great Bank of Guizhou (an isolated platform) in the Nanpanjiang Basin of South China and its adjacent extensive attached Yangtze Platform. In the Yangtze Platform, earlier arrival of Anisian siliciclastic turbidites sourced from the Jiangnan uplift in the eastern area filled the basin margin at Guiyang, producing a substratum above which the platform could prograde basinward. In the western area at Guanling, synchronous infilling of the basin margin allowed intertonguing and promoted stability of the margin and vertical aggradation. Later arrival of the turbidite basin fill distant from the Jiangnan uplift coupled with high subsidence rates caused margin instability and development of a backstepped and gravitational collapse architecture in the Zhenfeng and Anlong areas. Likewise in the Great Bank of Guizhou, earlier arrival (Anisian) and infilling of the basin by turbidites resulted in progradation of the platform margin in the Xiliang area proximal to the Jiangnan uplift, whereas in western areas distal from the siliciclastic sources the platform aggraded to develop extreme relief and gravitationally collapsed margins. High rates of subsidence coupled with the lack of basin infilling locked the platform into aggradational growth and resulted in the development of a high-relief escarpment architecture and large-scale gravitational collapse. The timing and pattern of basin infill impacts carbonate platform evolution in a regionally predictable pattern: early infill enables margin progradation in areas proximal to siliciclastic sources, whereas late infill in platform areas distant from sources results in aggradation and development of extreme platform margin relief with large-scale gravitational sector collapse. Panel_15045 Panel_15045 11:30 AM 11:50 AM

Panel_14498 Panel_14498 1:15 PM 5:05 PM

Panel_15729 Panel_15729 1:15 PM 12:00 AM

Postle Field in Panhandle Oklahoma is undergoing CO2 flooding and it is important to understand the characteristics of the Morrow A sandstone reservoir for successful flood management. Prestack P- and S-wave amplitude versus angle (AVA) inversion and joint P- and S-wave inversion provide density estimates along with the P- and S-impedance for better characterization of the Morrow A sandstone. We will discuss the poststack, prestack and joint inversion methods applied to the Postle field data. Fluid substitution modeling is done to prepare the logs for seismic data inversion by replacing the original fluid properties when the well was logged with those present during seismic data acquisition. The single link existing between well data and seismic data is the wavelet, therefore, it should be carefully estimated. The well to seismic calibration is divided into two main stages: the first one uses seismic data only and evaluates a preliminary zero-phase wavelet whose amplitude spectrum is representative of the signal in the seismic data. The second main stage tries to globally conciliate the seismic data and the well data to derive a unique wavelet for the whole field. This two stage analysis is performed for all P, SV and SH stacks. After performing poststack and prestack P- and S-wave inversion, the joint P- and S-wave inversion is performed in a way that the density, P- and S-impedance can be interpreted in the same PP time. The SS to PP time correspondence is achieved using a warping method which minimizes the difference between the S-impedance obtained from prestack P inversion in PP time and the S-impedance obtained from prestack S inversion transformed in PP time using initial Vs/Vp model. One way of analyzing the results is by visually comparing the bandpass filtered well logs and bandpass filtered inversion results. Another way of finding the quality of inversion results is to high-cut filter the logs to inversion bandwidth and cross correlate it with the inversion results. Cross correlation of seismic inversion results with well log data and visual comparison of inverted volumes show that the P-impedance is well estimated from prestack inversion of P data and the S-impedance and density are well estimated from prestack inversion of SV data. Postle Field in Panhandle Oklahoma is undergoing CO₂ flooding and it is important to understand the characteristics of the Morrow A sandstone reservoir for successful flood management. Prestack P- and S-wave amplitude versus angle (AVA) inversion and joint P- and S-wave inversion provide density estimates along with the P- and S-impedance for better characterization of the Morrow A sandstone. We will discuss the poststack, prestack and joint inversion methods applied to the Postle field data. Fluid substitution modeling is done to prepare the logs for seismic data inversion by replacing the original fluid properties when the well was logged with those present during seismic data acquisition. The single link existing between well data and seismic data is the wavelet, therefore, it should be carefully estimated. The well to seismic calibration is divided into two main stages: the first one uses seismic data only and evaluates a preliminary zero-phase wavelet whose amplitude spectrum is representative of the signal in the seismic data. The second main stage tries to globally conciliate the seismic data and the well data to derive a unique wavelet for the whole field. This two stage analysis is performed for all P, SV and SH stacks. After performing poststack and prestack P- and S-wave inversion, the joint P- and S-wave inversion is performed in a way that the density, P- and S-impedance can be interpreted in the same PP time. The SS to PP time correspondence is achieved using a warping method which minimizes the difference between the S-impedance obtained from prestack P inversion in PP time and the S-impedance obtained from prestack S inversion transformed in PP time using initial Vs/Vp model. One way of analyzing the results is by visually comparing the bandpass filtered well logs and bandpass filtered inversion results. Another way of finding the quality of inversion results is to high-cut filter the logs to inversion bandwidth and cross correlate it with the inversion results. Cross correlation of seismic inversion results with well log data and visual comparison of inverted volumes show that the P-impedance is well estimated from prestack inversion of P data and the S-impedance and density are well estimated from prestack inversion of SV data. Panel_15625 Panel_15625 1:20 PM 1:40 PM

Microseismic event locations are often used as input into geomechanical models to describe the effect of hydraulic stimulations, if only just to calibrate modelled fractures to the spatial microseismic response. While such methods are used to model production decline curves, and can be tuned through time with history matching observations, using only the distribution of microseismicity offers a relatively weak constraint on reservoir dynamics and ignores the potential benefits of utilizing the source characteristics associated with microseismic events. Specifically, each microseismic event location not only represents a point measure of failure in the reservoir but more correctly identifies the initiation point of a rupture on a fracture with dimensions and orientation that can be inferred through higher-order analyses such as Seismic Moment Tensor Inversion (SMTI) and source parameter analyses (eg., seismic moment, seismic energy, and stress release), where data quality are sufficiently sampled from a large azimuthal range (achieved through multi-array downhole deployments). Not every microseismic event detected by a array qualifies for SMTI and can to used to delineate fracture orientations. Some events rupture smaller fractures that result in less energy released and lower signal quality on the arrays, other events may be geometrically ill-favored for SMTI though their position relative to the monitoring arrays. In order to incorporate these features, we project these events onto features drawn from the distribution of SMTI derived fracture plane orientations. Construction of the discrete fracture network in this fashion offers a bridge between microseismic data collection and geomechanical modelling. This DFN describes the fractures that were favoured to slip through pressure and/or stress perturbations, and can be considered as the activated fracture set within the total fractures in the reservoir. By using SMTI-derived failure mechanisms (generally mixed-mode shear-tensile failures), constraints can also be applied to the DFN model development and be used to image the fractures that can accept proppant, and those fractures that are clamped. The question of how to extend this information on the style of fracturing to the sub-SMTI events is currently being investigated, and again drawing from the sampling of available fracture behaviours in a spatio-temporal sense will be key to further extending these constraints on DFN model development. Microseismic event locations are often used as input into geomechanical models to describe the effect of hydraulic stimulations, if only just to calibrate modelled fractures to the spatial microseismic response. While such methods are used to model production decline curves, and can be tuned through time with history matching observations, using only the distribution of microseismicity offers a relatively weak constraint on reservoir dynamics and ignores the potential benefits of utilizing the source characteristics associated with microseismic events. Specifically, each microseismic event location not only represents a point measure of failure in the reservoir but more correctly identifies the initiation point of a rupture on a fracture with dimensions and orientation that can be inferred through higher-order analyses such as Seismic Moment Tensor Inversion (SMTI) and source parameter analyses (eg., seismic moment, seismic energy, and stress release), where data quality are sufficiently sampled from a large azimuthal range (achieved through multi-array downhole deployments). Not every microseismic event detected by a array qualifies for SMTI and can to used to delineate fracture orientations. Some events rupture smaller fractures that result in less energy released and lower signal quality on the arrays, other events may be geometrically ill-favored for SMTI though their position relative to the monitoring arrays. In order to incorporate these features, we project these events onto features drawn from the distribution of SMTI derived fracture plane orientations. Construction of the discrete fracture network in this fashion offers a bridge between microseismic data collection and geomechanical modelling. This DFN describes the fractures that were favoured to slip through pressure and/or stress perturbations, and can be considered as the activated fracture set within the total fractures in the reservoir. By using SMTI-derived failure mechanisms (generally mixed-mode shear-tensile failures), constraints can also be applied to the DFN model development and be used to image the fractures that can accept proppant, and those fractures that are clamped. The question of how to extend this information on the style of fracturing to the sub-SMTI events is currently being investigated, and again drawing from the sampling of available fracture behaviours in a spatio-temporal sense will be key to further extending these constraints on DFN model development. Panel_15622 Panel_15622 1:40 PM 2:00 PM

A feasibility study (FS) is often done before planning and acquiring 4D seismic to determine if it will positively impact the economic viability of the field. A 4D FS was done on an AVO Class 2p turbidite deep water field in Nigeria (F1) based on core measurements. The results of the 4D modeling illustrated that changes of the fluid fronts are readily seen but the 4D changes from pressure are hard to see with the current expected change in pressure. More 4D modeling was undertaken with core measurements from analog fields to analyze the potential variance of the 4D signal. This was done by substituting the dry rock frame and acoustic impedance (AI) contrast of analog fields into F1 with saturations and pressures being held constant. The analog fields were chosen based on the closest depth below mud line, depositional environment and AI contrast to F1. Additionally, the analogs were selected based on a nonlinear method of defining the dry rock frame that relates differential pressure (Pd), porosity, dry and bulk modulus. Based on a plot of Pd and velocity (Vp), a low Vp (F2) and high Vp (F3) analog field were chosen. F2 and F3 were selected because they were both deep water fields deposited as turbidites that are AVO Class 3. The 4D modeling with F2 and F3 rock parameters, like F1, confirm that fluid fronts are seen. The main difference between F2 and F3 from F1 is the increased strength of the amplitude differences highlighting the fronts caused by the larger AI contrast of AVO Class 3 rock. Again, the expected change in pressure is not easily interpreted on the modeled 4D seismic. Another suite of 4D modeling was commenced by changing the pore pressure (Pp) to investigate 4D pressure effect. F1’s 4D response still saw fluid fronts with some pressure influence. The pressure change dominated F2’s 4D response, making it much more difficult to interpret fluid fronts. The fluid fronts on F3’s 4D response were still easily interpreted. The change in pressure caused noticeable 4D seismic differences between the three fields. It was found that the AI contrast between the reservoir matrix and surrounding rock is influential to detectable 4D signal. Secondarily, the location within the pressure regime of the rock physics models is important because the relationship between Vp and Pd is not linear. This is why the increase of the Pp influenced the results. Because of this, the choice of analog field and its dry rock frame is an important component of a 4D FS. A feasibility study (FS) is often done before planning and acquiring 4D seismic to determine if it will positively impact the economic viability of the field. A 4D FS was done on an AVO Class 2p turbidite deep water field in Nigeria (F1) based on core measurements. The results of the 4D modeling illustrated that changes of the fluid fronts are readily seen but the 4D changes from pressure are hard to see with the current expected change in pressure. More 4D modeling was undertaken with core measurements from analog fields to analyze the potential variance of the 4D signal. This was done by substituting the dry rock frame and acoustic impedance (AI) contrast of analog fields into F1 with saturations and pressures being held constant. The analog fields were chosen based on the closest depth below mud line, depositional environment and AI contrast to F1. Additionally, the analogs were selected based on a nonlinear method of defining the dry rock frame that relates differential pressure (Pd), porosity, dry and bulk modulus. Based on a plot of Pd and velocity (Vp), a low Vp (F2) and high Vp (F3) analog field were chosen. F2 and F3 were selected because they were both deep water fields deposited as turbidites that are AVO Class 3. The 4D modeling with F2 and F3 rock parameters, like F1, confirm that fluid fronts are seen. The main difference between F2 and F3 from F1 is the increased strength of the amplitude differences highlighting the fronts caused by the larger AI contrast of AVO Class 3 rock. Again, the expected change in pressure is not easily interpreted on the modeled 4D seismic. Another suite of 4D modeling was commenced by changing the pore pressure (Pp) to investigate 4D pressure effect. F1’s 4D response still saw fluid fronts with some pressure influence. The pressure change dominated F2’s 4D response, making it much more difficult to interpret fluid fronts. The fluid fronts on F3’s 4D response were still easily interpreted. The change in pressure caused noticeable 4D seismic differences between the three fields. It was found that the AI contrast between the reservoir matrix and surrounding rock is influential to detectable 4D signal. Secondarily, the location within the pressure regime of the rock physics models is important because the relationship between Vp and Pd is not linear. This is why the increase of the Pp influenced the results. Because of this, the choice of analog field and its dry rock frame is an important component of a 4D FS. Panel_15628 Panel_15628 2:00 PM 2:20 PM

Microseismicity can be used as a diagnostic tool to identify the nature of the hydraulic fracture stimulation associated with different completion styles and determine which style most effectively stimulates the targeted zone of interest. We coupled a proppant-filled Discrete Facture Network (DFN) model with treatment information (slurry volume and proppant concentration) to compare fracture growth and proppant distribution between two wells targeting the Niobrara Formation. One well was completed with twenty-seven sliding-sleeve stages while the other well was treated with thirty-two plug and perf stages. Differences in slurry volumes (93%) and treating pressures (88%) between wells were small and unlike the other wells in the eleven-well pad treatment they were not zipper-fraced. We extend our proppant-filled DFN model (McKenna and Toohey, 2013) by calibrating the model on the entire pad and employ a data-driven proppant-filling algorithm to account for stress anisotropy. By assuming all fractures are fluid filled at the end of the pad treatment, we avoid differentiating rock-stress from fluid-induced microseisms and set the total fracture volume equal to the product of injected slurry volume and fluid efficiency (to account for leakoff). Distal fractures (stage center reference) located near untreated stages likely accommodate injected fluid from those stages. The calibrated fracture model is filled with proppant volumes stage-by-stage outwards from the stage center. The major stress azimuth (?) is calculated using a spatial-temporal correlation using chronologically-occurring hypocenters (assuming microseismicity occurring close in times reflects displacement along the same failure plane) which is verified by focal mechanism strike. Proppant fills the DFN elliptically to mimic the shape of the microseismic cloud. The major and semi-minor axes of the microseismic cloud is calculated by stacking fractures from all stages and measuring the distance parallel to ?, perpendicular to ?, and vertically. Plug and perf stages show tight, long trends that continue to increase length while pumping, vertical distribution is skewed toward shallower depths, and energy release rate is more constant during the entire treatment. Sliding sleeve stages show broad, short trends resulting in more near-wellbore complexity, vertical distribution is symmetric about the wellbore, and energy release rate reduces as treatment progresses. Microseismicity can be used as a diagnostic tool to identify the nature of the hydraulic fracture stimulation associated with different completion styles and determine which style most effectively stimulates the targeted zone of interest. We coupled a proppant-filled Discrete Facture Network (DFN) model with treatment information (slurry volume and proppant concentration) to compare fracture growth and proppant distribution between two wells targeting the Niobrara Formation. One well was completed with twenty-seven sliding-sleeve stages while the other well was treated with thirty-two plug and perf stages. Differences in slurry volumes (93%) and treating pressures (88%) between wells were small and unlike the other wells in the eleven-well pad treatment they were not zipper-fraced. We extend our proppant-filled DFN model (McKenna and Toohey, 2013) by calibrating the model on the entire pad and employ a data-driven proppant-filling algorithm to account for stress anisotropy. By assuming all fractures are fluid filled at the end of the pad treatment, we avoid differentiating rock-stress from fluid-induced microseisms and set the total fracture volume equal to the product of injected slurry volume and fluid efficiency (to account for leakoff). Distal fractures (stage center reference) located near untreated stages likely accommodate injected fluid from those stages. The calibrated fracture model is filled with proppant volumes stage-by-stage outwards from the stage center. The major stress azimuth (?) is calculated using a spatial-temporal correlation using chronologically-occurring hypocenters (assuming microseismicity occurring close in times reflects displacement along the same failure plane) which is verified by focal mechanism strike. Proppant fills the DFN elliptically to mimic the shape of the microseismic cloud. The major and semi-minor axes of the microseismic cloud is calculated by stacking fractures from all stages and measuring the distance parallel to ?, perpendicular to ?, and vertically. Plug and perf stages show tight, long trends that continue to increase length while pumping, vertical distribution is skewed toward shallower depths, and energy release rate is more constant during the entire treatment. Sliding sleeve stages show broad, short trends resulting in more near-wellbore complexity, vertical distribution is symmetric about the wellbore, and energy release rate reduces as treatment progresses. Panel_15624 Panel_15624 2:20 PM 2:40 PM

The hydrocarbon bearing strata, due to attenuation of seismic waves, appear as zones of low frequency shadows and its application as a direct hydrocarbon indicator for several years. Traditionally the limited low frequency seismic impedance component can be estimated by interpolation of filtered well logs when performing acoustic inversion and modeling for reservoir characterization. However, sparse wells or low accurate log data can’t satisfy with the accuracy of seismic inversion. Breakthrough of low frequency passive seismic survey with low frequency emissions, large offset and high density came from the Pilot experiments between BGP and Shell in western China in 2009 and the innovation of BGP self-developed KZ28LFV3 low frequency vibroseis and its seismic acquisition design was successful to narrow this gap by designing to acquire 1.5 - 3Hz low frequency content. Specific low frequency seismic data processing focused on low-frequency compensation by retaining broad signal band and source wavelet constraint which can effectively preserve the relative amplitude of the broadband seismic data with high S/N ratio. Between February and June, 2013, BGP successfully conducted the first production application of low frequency, high density, broadband, wide-azimuth vibroseis survey on pre-salt carbonate reservoir in the H block of PreCaspian basin in Kazakhstan. Subsequently, standard amplitude-preserved data processing was applied. The resulted seismic data demonstrated high quality imaging of the boundaries of salt domes and subtle geologic geometries within the carbonate reservoir. Obvious low frequency shadows presented beneath oil zones, which were absent in conventional seismic dataset. This technology was successful applied to Taibei depression of Tuha basin in the western China in 2013. In the basin, technical challenges to seismic acquisition were that the less seismic wave propagates can penetrate through the reservoir zones due to thick high attenuation coal beds above the reservoirs. The revolutionary solution was achieved by designing to add 1-3Hz low frequency contents during vibroseis survey so that the seismic energy underneath thick coal-beds can be effectively compensated. The high quality of seismic imaging on geological geometries within the reservoir was finalized by specific amplitude-preserved processing and inversion. The hydrocarbon bearing strata, due to attenuation of seismic waves, appear as zones of low frequency shadows and its application as a direct hydrocarbon indicator for several years. Traditionally the limited low frequency seismic impedance component can be estimated by interpolation of filtered well logs when performing acoustic inversion and modeling for reservoir characterization. However, sparse wells or low accurate log data can’t satisfy with the accuracy of seismic inversion. Breakthrough of low frequency passive seismic survey with low frequency emissions, large offset and high density came from the Pilot experiments between BGP and Shell in western China in 2009 and the innovation of BGP self-developed KZ28LFV3 low frequency vibroseis and its seismic acquisition design was successful to narrow this gap by designing to acquire 1.5 - 3Hz low frequency content. Specific low frequency seismic data processing focused on low-frequency compensation by retaining broad signal band and source wavelet constraint which can effectively preserve the relative amplitude of the broadband seismic data with high S/N ratio. Between February and June, 2013, BGP successfully conducted the first production application of low frequency, high density, broadband, wide-azimuth vibroseis survey on pre-salt carbonate reservoir in the H block of PreCaspian basin in Kazakhstan. Subsequently, standard amplitude-preserved data processing was applied. The resulted seismic data demonstrated high quality imaging of the boundaries of salt domes and subtle geologic geometries within the carbonate reservoir. Obvious low frequency shadows presented beneath oil zones, which were absent in conventional seismic dataset. This technology was successful applied to Taibei depression of Tuha basin in the western China in 2013. In the basin, technical challenges to seismic acquisition were that the less seismic wave propagates can penetrate through the reservoir zones due to thick high attenuation coal beds above the reservoirs. The revolutionary solution was achieved by designing to add 1-3Hz low frequency contents during vibroseis survey so that the seismic energy underneath thick coal-beds can be effectively compensated. The high quality of seismic imaging on geological geometries within the reservoir was finalized by specific amplitude-preserved processing and inversion. Panel_15629 Panel_15629 2:40 PM 3:00 PM

Panel_15740 Panel_15740 3:00 PM 12:00 AM

Mongolia contains several under-explored sedimentary basins. These basins are geologically similar to highly productive basins in China. No basins had been previously identified on the Sukhbaatar block which covers approximately 22,600 square kilometers in Eastern Mongolia. An interdisciplinary approach was used to evaluate the block. Land based gravity and magnetic surveys were conducted, processed and used to define the location of the Cretaceous lacustrine rift basins. A remote sensing study included structural, lithologic and alteration mineral interpretation utilizing enhanced multispectral satellite imagery and digital elevation model data. Approximately 450 line kilometers of 2D seismic was conducted, processed and interpreted, further defining the basin location. A hydrocarbon geochemical survey was conducted using the seismic shot hole sediments, results indicate that volatile and liquid hydrocarbon microseeps are evident at the basin margins and surface expression of faults. Integrating these studies along with geologic field mapping has resulted in several prospects/leads to be drilled. Mongolia contains several under-explored sedimentary basins. These basins are geologically similar to highly productive basins in China. No basins had been previously identified on the Sukhbaatar block which covers approximately 22,600 square kilometers in Eastern Mongolia. An interdisciplinary approach was used to evaluate the block. Land based gravity and magnetic surveys were conducted, processed and used to define the location of the Cretaceous lacustrine rift basins. A remote sensing study included structural, lithologic and alteration mineral interpretation utilizing enhanced multispectral satellite imagery and digital elevation model data. Approximately 450 line kilometers of 2D seismic was conducted, processed and interpreted, further defining the basin location. A hydrocarbon geochemical survey was conducted using the seismic shot hole sediments, results indicate that volatile and liquid hydrocarbon microseeps are evident at the basin margins and surface expression of faults. Integrating these studies along with geologic field mapping has resulted in several prospects/leads to be drilled. Panel_15623 Panel_15623 3:25 PM 3:45 PM

The Eastern Margin of Brazil (EMB) extends from the Pernambuco-Paraíba Basin (PEPB) in the northeasternmost part of Brazil to the southernmost Pelotas Basin (PB) bordering with Uruguay. From North to South, the EMB is constituted by the PEPB, Sergipe-Alagoas (SEAL), Jacuípe (JAC), Camamu-Almada (CAMAL), Jequitinhonha (JEQ), Cumuruxatiba (CUM), Espírito Santo (ES), Campos (CAM), Santos (SAN) and Pelotas Basins (PEL). They are all typical passive margin basins formed during the breakup of Western Gondwana and opening of the South Atlantic. Extensional stresses dominated their formation and development. The EMB is well known to the international petroleum industry due to the prolific Campos Basin that produces around 1,700,000 boepd from post-salt turbidites and carbonates. In the last 8 years, another EMB basin (SAN) has dazzled the world with the huge discoveries of oil reserves (such as Lula and Buzios fields) in an uncommon carbonate reservoir in the pre-salt section (microbialites, also present in CAM). However, the large petroleum potential of the EMB is not restricted to these two basins. Recently, large discoveries of light oil, condensate and gas (sourced from Cretaceous marine shales) in late cretaceous turbidites were reported in the SEAL. The basin that is a traditional producer in shallow waters has now become one of the most promising frontiers in ultra-deep waters. In the ES, another traditional producer from cretaceous and cenozoic turbidites in shallow and deep waters, presents the potential for sub-salt discoveries associated to allochthonous salts (similar to those in GOM) in its ultra-deep waters. In the PEL attention is now focused to stratigraphic plays associated to late cretaceous/paleogene turbidites and cretaceous marine source rocks within a very thick drift section resting upon huge piles of seaward-dipping reflectors (SDRs). Several exploratory blocks in the adjacent margin of Uruguay had been acquired by companies in the last bid round. Recent studies carried out by ANP, including regional and detailed interpretation and mapping of extensive seismic grids, pointed out several exploratory opportunities in diverse areas of the EMB. Bright/flat spots and stratigraphic pinch-outs/incised channels associated to turbidite sandstones are the most common leads. Turtleback structures in albian carbonates also comprise a common play. This renewed view indicated that there is a significant petroleum potential remaining in the EMB. The Eastern Margin of Brazil (EMB) extends from the Pernambuco-Paraíba Basin (PEPB) in the northeasternmost part of Brazil to the southernmost Pelotas Basin (PB) bordering with Uruguay. From North to South, the EMB is constituted by the PEPB, Sergipe-Alagoas (SEAL), Jacuípe (JAC), Camamu-Almada (CAMAL), Jequitinhonha (JEQ), Cumuruxatiba (CUM), Espírito Santo (ES), Campos (CAM), Santos (SAN) and Pelotas Basins (PEL). They are all typical passive margin basins formed during the breakup of Western Gondwana and opening of the South Atlantic. Extensional stresses dominated their formation and development. The EMB is well known to the international petroleum industry due to the prolific Campos Basin that produces around 1,700,000 boepd from post-salt turbidites and carbonates. In the last 8 years, another EMB basin (SAN) has dazzled the world with the huge discoveries of oil reserves (such as Lula and Buzios fields) in an uncommon carbonate reservoir in the pre-salt section (microbialites, also present in CAM). However, the large petroleum potential of the EMB is not restricted to these two basins. Recently, large discoveries of light oil, condensate and gas (sourced from Cretaceous marine shales) in late cretaceous turbidites were reported in the SEAL. The basin that is a traditional producer in shallow waters has now become one of the most promising frontiers in ultra-deep waters. In the ES, another traditional producer from cretaceous and cenozoic turbidites in shallow and deep waters, presents the potential for sub-salt discoveries associated to allochthonous salts (similar to those in GOM) in its ultra-deep waters. In the PEL attention is now focused to stratigraphic plays associated to late cretaceous/paleogene turbidites and cretaceous marine source rocks within a very thick drift section resting upon huge piles of seaward-dipping reflectors (SDRs). Several exploratory blocks in the adjacent margin of Uruguay had been acquired by companies in the last bid round. Recent studies carried out by ANP, including regional and detailed interpretation and mapping of extensive seismic grids, pointed out several exploratory opportunities in diverse areas of the EMB. Bright/flat spots and stratigraphic pinch-outs/incised channels associated to turbidite sandstones are the most common leads. Turtleback structures in albian carbonates also comprise a common play. This renewed view indicated that there is a significant petroleum potential remaining in the EMB. Panel_16762 Panel_16762 3:45 PM 4:05 PM

Geoscientists routinely use common geophysical and geological mapping methods to study structural geological settings of sedimentary basins. However, traditional field methods are inadequate for mapping regional geomorphic features in remote areas that are characterised by flat topography and lack of adequate bedrock exposures. The applications of geological remote sensing and GIS to study the regional geospatial characteristics of surface geological features are therefore increasingly recognised. Available 2D seismic, ground gravity, satellite gravity, magnetic and well log datasets integrated with optical and radar remote sensing datasets are used in this research to study structural lineament features. The objective is to determine the synergistic relationship between the surface and subsurface structural styles identified from the multi-source datasets. The semi-arid intracontinental Bornu Basin in north eastern Nigeria is selected since previous field geological studies in the Bornu Basin remain constrained by flat topography and inadequate continuous bedrock outcrops. The methodology involves mapping of the palaeotectonic subsurface structural lineaments from the seismic, gravity and magnetic datasets as well as mapping surface lineaments from optical Landsat imageries. Surface lithological variations in the study area were delineated from the RGB colour composite optical images. The geomorphic characteristics detected from Synthetic Aperture Radar (SAR) and Advanced Synthetic Aperture Radar (ASAR) interferometry analysis indicated neotectonic (Quaternary) deformation in the basin. The subsurface structural analysis indicated patterns and alignments of the subsurface faults with the basement configuration. The local stratigraphic units in the study area were identified from correlated pattern analysis of the well logs and confirmed from the seismic sections. GIS analysis was carried out to establish the geospatial characteristics of the surface deformational features as geomorphic expressions of the basement lineaments mapped from seismic, gravity and magnetic data. The significance of the structural lineaments to the potential hydrocarbon systems and prospectivity of the basin are evaluated. Geoscientists routinely use common geophysical and geological mapping methods to study structural geological settings of sedimentary basins. However, traditional field methods are inadequate for mapping regional geomorphic features in remote areas that are characterised by flat topography and lack of adequate bedrock exposures. The applications of geological remote sensing and GIS to study the regional geospatial characteristics of surface geological features are therefore increasingly recognised. Available 2D seismic, ground gravity, satellite gravity, magnetic and well log datasets integrated with optical and radar remote sensing datasets are used in this research to study structural lineament features. The objective is to determine the synergistic relationship between the surface and subsurface structural styles identified from the multi-source datasets. The semi-arid intracontinental Bornu Basin in north eastern Nigeria is selected since previous field geological studies in the Bornu Basin remain constrained by flat topography and inadequate continuous bedrock outcrops. The methodology involves mapping of the palaeotectonic subsurface structural lineaments from the seismic, gravity and magnetic datasets as well as mapping surface lineaments from optical Landsat imageries. Surface lithological variations in the study area were delineated from the RGB colour composite optical images. The geomorphic characteristics detected from Synthetic Aperture Radar (SAR) and Advanced Synthetic Aperture Radar (ASAR) interferometry analysis indicated neotectonic (Quaternary) deformation in the basin. The subsurface structural analysis indicated patterns and alignments of the subsurface faults with the basement configuration. The local stratigraphic units in the study area were identified from correlated pattern analysis of the well logs and confirmed from the seismic sections. GIS analysis was carried out to establish the geospatial characteristics of the surface deformational features as geomorphic expressions of the basement lineaments mapped from seismic, gravity and magnetic data. The significance of the structural lineaments to the potential hydrocarbon systems and prospectivity of the basin are evaluated. Panel_15630 Panel_15630 4:25 PM 4:45 PM

Tarim basin, especially the deep area, is becoming one of the most attractive areas for hydrocarbon exploration in China. The extensional tectonic environment during the Sinian period and the movements of the multistage faults in the Tarim basin make a contribution to the development of the Sinian rift, the poor research on which bring great difficulties to the further exploration within the deep area in Tarim basin. Based on drilling data, new 3D seismic data and aeromagnetic data, the tectonic development characteristics of the Sinian in the whole Tarim basin have been firstly depicted meticulously. And analysis shows that the Sinian rift in Tarim basin is mainly controlled by the rifting of ancient Tianshan ocean and ancient Kunlun ocean and which results in the occurrence of three aulacogens such as Maigaiti aulacogen, Manjiaer aulacogen, and Awati aulacogen and three ancient uplifts such as Tabei uplift, Bachu-tazhong uplift and Hetian uplift. Moreover, the Sinian sedimentary system in Tarim basin can be subdivided into the former rift sedimentary system and the latter depression sedimentary system. The rift sedimentary system is dominated by clastic rock, tillite and volcanic rock and assumes the wedge reflections on the seismic section. In addition, the depression sedimentary system mainly develops carbonate deposits, especially dolomite, which is characterized by the parallel and continuous sheet reflection of weak amplitude on the seismic section. The further analysis discloses that the Sinian tectonic movement has great guiding significance in oil and gas exploration, which can be interpreted as the following four aspects. Firstly, the Sinian rift and its successive subsidence directly control the sedimentary distribution of the source rock within the Sinian and Yuertusi Formation in the Lower Cambrian. Secondly, the margins of the Sinian successive rift control the distribution of the platform margin facies belt and successive ancient uplifts control the distribution of platform facies within the Lower Cambrian which can act as favorable reservoirs. Thirdly, platform margin facies belt developed within both the Lower Cambrian and the Sinian ancient uplifts control the distribution of gypsum rock in the Middle Cambrian which can act as important cap-rock. Fourthly, the big structural traps successively develop under the gypsum rock in the Middle Cambrian, which can be the favorable hydrocarbon accumulation zones, especially in the Bachu and Madong. Tarim basin, especially the deep area, is becoming one of the most attractive areas for hydrocarbon exploration in China. The extensional tectonic environment during the Sinian period and the movements of the multistage faults in the Tarim basin make a contribution to the development of the Sinian rift, the poor research on which bring great difficulties to the further exploration within the deep area in Tarim basin. Based on drilling data, new 3D seismic data and aeromagnetic data, the tectonic development characteristics of the Sinian in the whole Tarim basin have been firstly depicted meticulously. And analysis shows that the Sinian rift in Tarim basin is mainly controlled by the rifting of ancient Tianshan ocean and ancient Kunlun ocean and which results in the occurrence of three aulacogens such as Maigaiti aulacogen, Manjiaer aulacogen, and Awati aulacogen and three ancient uplifts such as Tabei uplift, Bachu-tazhong uplift and Hetian uplift. Moreover, the Sinian sedimentary system in Tarim basin can be subdivided into the former rift sedimentary system and the latter depression sedimentary system. The rift sedimentary system is dominated by clastic rock, tillite and volcanic rock and assumes the wedge reflections on the seismic section. In addition, the depression sedimentary system mainly develops carbonate deposits, especially dolomite, which is characterized by the parallel and continuous sheet reflection of weak amplitude on the seismic section. The further analysis discloses that the Sinian tectonic movement has great guiding significance in oil and gas exploration, which can be interpreted as the following four aspects. Firstly, the Sinian rift and its successive subsidence directly control the sedimentary distribution of the source rock within the Sinian and Yuertusi Formation in the Lower Cambrian. Secondly, the margins of the Sinian successive rift control the distribution of the platform margin facies belt and successive ancient uplifts control the distribution of platform facies within the Lower Cambrian which can act as favorable reservoirs. Thirdly, platform margin facies belt developed within both the Lower Cambrian and the Sinian ancient uplifts control the distribution of gypsum rock in the Middle Cambrian which can act as important cap-rock. Fourthly, the big structural traps successively develop under the gypsum rock in the Middle Cambrian, which can be the favorable hydrocarbon accumulation zones, especially in the Bachu and Madong. Panel_15627 Panel_15627 4:45 PM 5:05 PM

Panel_14487 Panel_14487 1:15 PM 5:05 PM

Llanos Basin petroleum systems combine complex geology with complex petroleum geochemistry consisting of multiple source rocks and charges at different maturities. In addition, many of these charges were biodegraded to varying degrees. We have shown that all of these factors can converge in a single oil accumulation. Using advanced geochemical technologies (AGTs) we have determined that certain oilfields consist of multiply co-sourced accumulations with as many as four sources, thermally cracked light oil mixed together with normally-maturated black oil, and multiply-charged reservoirs culminating in a wide range of biodegradation severities in the same oil. AGTs were applied to see through biodegradation and maturity issues to determine source affinities and unravel mixtures. The most critical AGTs are diamondoid-based, including compound specific isotope analysis (CSIA) and quantitative extended diamondoid analysis (QEDA), which are unaffected by biodegradation and high maturity. Through these diamondoid methods five oil sources and their mixtures were differentiated. By the addition of taxon-specific biomarker analysis and CSIA of biomarkers (CSIA-B), source rock age and depositional environment were constrained. The oils are of five source-types: (1) Cretaceous terrestrial-marine shale mix (2) Cretaceous marine-terrestrial carbonate mix, (3) Tertiary terrestrial shale, and (4) and (5) both Cretaceous marine shale, but from distinct facies. Hydrous pyrolysis of asphaltenes introduced another dimension to this study. Asphaltenes are both highly resistant to biodegradation and preferentially represent low-maturity oil charges. QEDA, CSIA and biomarker parameters applied to the pyrolysates revealed similarities and differences between sources for the maltenes and the asphaltenes, exposing and unraveling the co-sources with a high level of confidence. Biomarker Acids Analysis (BAA) was used to characterize oil biodegradation history and the relative importance of each charge pulse to the reservoirs. It was determined that most oil reservoirs have multiple charge-pulses with different levels of biodegradation. Losses of liquid oil due to biodegradation were estimated using High Temperature Simulated Distillation (HT-SimDis). Results were found to directly correlate to oil gravity. Since very little oil is necessary to run HT-SimDis it could be a useful tool for field development to estimate oil gravity from cores and oil shows. Llanos Basin petroleum systems combine complex geology with complex petroleum geochemistry consisting of multiple source rocks and charges at different maturities. In addition, many of these charges were biodegraded to varying degrees. We have shown that all of these factors can converge in a single oil accumulation. Using advanced geochemical technologies (AGTs) we have determined that certain oilfields consist of multiply co-sourced accumulations with as many as four sources, thermally cracked light oil mixed together with normally-maturated black oil, and multiply-charged reservoirs culminating in a wide range of biodegradation severities in the same oil. AGTs were applied to see through biodegradation and maturity issues to determine source affinities and unravel mixtures. The most critical AGTs are diamondoid-based, including compound specific isotope analysis (CSIA) and quantitative extended diamondoid analysis (QEDA), which are unaffected by biodegradation and high maturity. Through these diamondoid methods five oil sources and their mixtures were differentiated. By the addition of taxon-specific biomarker analysis and CSIA of biomarkers (CSIA-B), source rock age and depositional environment were constrained. The oils are of five source-types: (1) Cretaceous terrestrial-marine shale mix (2) Cretaceous marine-terrestrial carbonate mix, (3) Tertiary terrestrial shale, and (4) and (5) both Cretaceous marine shale, but from distinct facies. Hydrous pyrolysis of asphaltenes introduced another dimension to this study. Asphaltenes are both highly resistant to biodegradation and preferentially represent low-maturity oil charges. QEDA, CSIA and biomarker parameters applied to the pyrolysates revealed similarities and differences between sources for the maltenes and the asphaltenes, exposing and unraveling the co-sources with a high level of confidence. Biomarker Acids Analysis (BAA) was used to characterize oil biodegradation history and the relative importance of each charge pulse to the reservoirs. It was determined that most oil reservoirs have multiple charge-pulses with different levels of biodegradation. Losses of liquid oil due to biodegradation were estimated using High Temperature Simulated Distillation (HT-SimDis). Results were found to directly correlate to oil gravity. Since very little oil is necessary to run HT-SimDis it could be a useful tool for field development to estimate oil gravity from cores and oil shows. Panel_15516 Panel_15516 1:20 PM 1:40 PM

Higher diamondoids are composed of four or more face-fused diamond cages. Unlike the lower diamondoids, adamantane, diamantane and triamantane, higher diamondoids have a variety of structural isomers. There are four different tetramantane isomers found in petroleum, two of which are enantiomeric. There are nine pentamantane isomers of molecular weight 344, six of which are enantiomeric pairs. There are 39 hexamantanes, but only one of which has a molecular weight of 342, the highly condensed cyclohexamantane. Here we show it is possible to use the relative concentrations and distributions of higher diamondoids to determine source in much the way biomarker sterane and terpane-concentrations and distributions are used. Unlike biomarkers which are among the most thermally labile compounds in petroleum, diamondoids are for their molecular weight, the most thermally stable. As a result, unlike biomarker distributions, higher diamondoid distributions can be used to correlate hydrocarbon liquids of any thermal maturity. We will show 1) oil to oil, 2) oil to condensate and 3) oil and condensate to source-rock correlations for a variety of samples, including condensates from liquids collected from highly-mature dry gas wells. Several examples representing various sources in both the US and Mexican GOM will be used to illustrate the application. Higher diamondoids are composed of four or more face-fused diamond cages. Unlike the lower diamondoids, adamantane, diamantane and triamantane, higher diamondoids have a variety of structural isomers. There are four different tetramantane isomers found in petroleum, two of which are enantiomeric. There are nine pentamantane isomers of molecular weight 344, six of which are enantiomeric pairs. There are 39 hexamantanes, but only one of which has a molecular weight of 342, the highly condensed cyclohexamantane. Here we show it is possible to use the relative concentrations and distributions of higher diamondoids to determine source in much the way biomarker sterane and terpane-concentrations and distributions are used. Unlike biomarkers which are among the most thermally labile compounds in petroleum, diamondoids are for their molecular weight, the most thermally stable. As a result, unlike biomarker distributions, higher diamondoid distributions can be used to correlate hydrocarbon liquids of any thermal maturity. We will show 1) oil to oil, 2) oil to condensate and 3) oil and condensate to source-rock correlations for a variety of samples, including condensates from liquids collected from highly-mature dry gas wells. Several examples representing various sources in both the US and Mexican GOM will be used to illustrate the application. Panel_15511 Panel_15511 1:40 PM 2:00 PM

Determining the extent of thermochemical sulfate reduction (TSR) in petroleum reservoirs is critical for assessing the risk of hydrocarbon loss through oxidation and reservoir souring via hydrogen sulfide formation. However, distinguishing between the effects of TSR and thermal maturation or other alteration processes (e.g., biodegradation or water washing) can be difficult, particularly during the early stages of TSR. Compound-specific sulfur-isotopic analysis (CSSIA) is a new tool that has the potential to provide additional information related to petroleum formation and alteration. This study applied CSSIA to a suite of 16 Phosphoria Formation-sourced oils from the Bighorn Basin of Wyoming, USA that had undergone TSR to a variable extent. The target analytes included benzothiophene (BT) and dibenzothiophene (DBT), and their methyl-, dimethyl-, and trimethyl-alkylated forms. A general trend of 34S enrichment in all of the studied compounds with increasing source thermal maturity was observed. The ?34S composition of BTs and DBTs in low-maturity oils tends to be lighter than that of the bulk oil, but at higher maturities, they are nearly equivalent. This may suggest that sulfur isotopic homogenization among different sulfur-containing petroleum fractions (e.g., asphaltenes, NSOs, pyrobitumen) occurs during thermal maturation. However, oils that had experienced slight to moderate TSR exhibited a pronounced 34S enrichment in the BT compounds relative to the DBTs, with the BTs being 34S enriched and the DBTs 34S depleted relative to the bulk oil composition. For most of the oils that experienced little or no TSR, the sulfur-isotopic composition of the majority of compounds examined correlated with the bulk ?34S of the oil. In contrast, oils that had experienced the greatest amount of TSR generally do not conform to the compound-specific versus bulk ?34S trends defined by the other oils. All of the oils exposed to the highest degree of TSR (four samples) showed a consistent pattern of ?34S compositions in the alkylated BTs and DBTs that was not observed in the other oils. The possibility that this is an inherited signal from a distinct facies in the Phosphoria source rocks (e.g., Meade Peak versus Retort Member) can largely be discounted based on biomarker and other geologic data. It is most likely to be a reflection of the TSR mechanism, whereby specific BT and DBT isomers are preferentially involved in the reaction. Determining the extent of thermochemical sulfate reduction (TSR) in petroleum reservoirs is critical for assessing the risk of hydrocarbon loss through oxidation and reservoir souring via hydrogen sulfide formation. However, distinguishing between the effects of TSR and thermal maturation or other alteration processes (e.g., biodegradation or water washing) can be difficult, particularly during the early stages of TSR. Compound-specific sulfur-isotopic analysis (CSSIA) is a new tool that has the potential to provide additional information related to petroleum formation and alteration. This study applied CSSIA to a suite of 16 Phosphoria Formation-sourced oils from the Bighorn Basin of Wyoming, USA that had undergone TSR to a variable extent. The target analytes included benzothiophene (BT) and dibenzothiophene (DBT), and their methyl-, dimethyl-, and trimethyl-alkylated forms. A general trend of 34S enrichment in all of the studied compounds with increasing source thermal maturity was observed. The ?34S composition of BTs and DBTs in low-maturity oils tends to be lighter than that of the bulk oil, but at higher maturities, they are nearly equivalent. This may suggest that sulfur isotopic homogenization among different sulfur-containing petroleum fractions (e.g., asphaltenes, NSOs, pyrobitumen) occurs during thermal maturation. However, oils that had experienced slight to moderate TSR exhibited a pronounced 34S enrichment in the BT compounds relative to the DBTs, with the BTs being 34S enriched and the DBTs 34S depleted relative to the bulk oil composition. For most of the oils that experienced little or no TSR, the sulfur-isotopic composition of the majority of compounds examined correlated with the bulk ?34S of the oil. In contrast, oils that had experienced the greatest amount of TSR generally do not conform to the compound-specific versus bulk ?34S trends defined by the other oils. All of the oils exposed to the highest degree of TSR (four samples) showed a consistent pattern of ?34S compositions in the alkylated BTs and DBTs that was not observed in the other oils. The possibility that this is an inherited signal from a distinct facies in the Phosphoria source rocks (e.g., Meade Peak versus Retort Member) can largely be discounted based on biomarker and other geologic data. It is most likely to be a reflection of the TSR mechanism, whereby specific BT and DBT isomers are preferentially involved in the reaction. Panel_15507 Panel_15507 2:00 PM 2:20 PM

The transformation of kerogen to hydrocarbons in the early stages of oil generation is critical for understanding the resource potential of liquid-rich shale plays. Organic petrology commonly is used to evaluate type, quality, and thermal maturity of organic matter, but the relationship of the visual changes to chemical transformations is not well characterized. To improve our understanding of these processes we have analyzed microfossils of the unicellular green alga Tasmanites in Upper Devonian Ohio Shale (Huron Member, Appalachian Basin) via micro-spectrometry (µ-FTIR, XPS, EMPA, fluorescence) in core and outcrop samples with solid bitumen Ro values from 0.45-0.80%. Hydrous pyrolysis of a low-maturity sample was used to simulate the natural maturation sequence. µ-FTIR spectrometry revealed a decrease in CH2/CH3 ratios with increasing maturity, indicating aliphatic chains become shorter and more branched. Oxygenated functional groups also decreased relative to aliphatic stretching bands. In samples pyrolyzed for 72 hrs at temperatures of 300-320°C (solid bitumen Ro range of 0.39-0.68%) Tasmanites showed similar trends, whereas at pyrolysis temperatures of 340°C and higher (bitumen Ro >0.71%), Tasmanites was pseudomorphed by accumulations of solid bitumen, carbonate and sulfide. Preliminary EMPA of Tasmanites in the natural sequence showed consistent decrease in S, Co, Mo, and U concentrations with increasing thermal maturity, possibly due to destruction of metallo-porphyrin complexes. XPS indicated the molar proportion of aliphatic C increases with increasing thermal maturity, accompanied by decreases in oxygenated functional groups and olefinic C. Fluorescence microscopy and spectrometry showed a red shift in spectral maximum and decreasing emission intensity with increasing maturity. The compositional data showed evidence of the loss of fluorophores such as conjugated polyenes (decrease in olefinic C observed by XPS) or metallo-porphyrins (decreasing trace metal concentrations) that is consistent with the changes observed via fluorescence. Replacement of Tasmanites by bitumen, carbonate, and sulfide in hydrous pyrolysis experiments at higher temperatures implies that a large fraction of this component of TOC is converted to hydrocarbons. Additional work is in progress to develop non-destructive methods to chemically differentiate kerogen, bitumen, and residual hydrocarbons to improve our understanding of both generation and expulsion. The transformation of kerogen to hydrocarbons in the early stages of oil generation is critical for understanding the resource potential of liquid-rich shale plays. Organic petrology commonly is used to evaluate type, quality, and thermal maturity of organic matter, but the relationship of the visual changes to chemical transformations is not well characterized. To improve our understanding of these processes we have analyzed microfossils of the unicellular green alga Tasmanites in Upper Devonian Ohio Shale (Huron Member, Appalachian Basin) via micro-spectrometry (µ-FTIR, XPS, EMPA, fluorescence) in core and outcrop samples with solid bitumen Ro values from 0.45-0.80%. Hydrous pyrolysis of a low-maturity sample was used to simulate the natural maturation sequence. µ-FTIR spectrometry revealed a decrease in CH2/CH3 ratios with increasing maturity, indicating aliphatic chains become shorter and more branched. Oxygenated functional groups also decreased relative to aliphatic stretching bands. In samples pyrolyzed for 72 hrs at temperatures of 300-320°C (solid bitumen Ro range of 0.39-0.68%) Tasmanites showed similar trends, whereas at pyrolysis temperatures of 340°C and higher (bitumen Ro >0.71%), Tasmanites was pseudomorphed by accumulations of solid bitumen, carbonate and sulfide. Preliminary EMPA of Tasmanites in the natural sequence showed consistent decrease in S, Co, Mo, and U concentrations with increasing thermal maturity, possibly due to destruction of metallo-porphyrin complexes. XPS indicated the molar proportion of aliphatic C increases with increasing thermal maturity, accompanied by decreases in oxygenated functional groups and olefinic C. Fluorescence microscopy and spectrometry showed a red shift in spectral maximum and decreasing emission intensity with increasing maturity. The compositional data showed evidence of the loss of fluorophores such as conjugated polyenes (decrease in olefinic C observed by XPS) or metallo-porphyrins (decreasing trace metal concentrations) that is consistent with the changes observed via fluorescence. Replacement of Tasmanites by bitumen, carbonate, and sulfide in hydrous pyrolysis experiments at higher temperatures implies that a large fraction of this component of TOC is converted to hydrocarbons. Additional work is in progress to develop non-destructive methods to chemically differentiate kerogen, bitumen, and residual hydrocarbons to improve our understanding of both generation and expulsion. Panel_15510 Panel_15510 2:20 PM 2:40 PM

The Anadarko Basin is one of the most petroliferous basins in the world, and has a poly-basin history that can be subdivided into Ordovician, Devonian-Mississippian, and Pennsylvanian petroleum systems. Several previous studies within the Anadarko Basin highlight the potential of Pennsylvanian mudstones/shales as viable hydrocarbon sources. However, unlike source rocks in the Ordovician and Devonian-Mississippian petroleum systems, where clear geochemically validated examples of sourcing contributions in the basin exist, those of the Pennsylvanian system lack any clear geochemical ties. This study highlights the hydrocarbon-source relationship within Mills Ranch field (Hogshooter Formation: Missourian Series) along the Texas and Oklahoma border by clearly demonstrating the genetic relationship between produced oils/condensates and Missourian shales. Bitumen extracts from two mudstone-shale cores in the Hogshooter portion of the field were used to link the produced fluids to Missourian source beds. To validate key geochemical correlation characteristics, low maturity extracts from other representative source facies within the Anadarko basin were also used for comparison. Additionally, data from Woodford shale produced oils were used as a Devonian source control. Based on gas chromatography, coupled gas chromatography/mass spectrometry, and stable carbon isotope-ratio-mass-spectrometry analyses, light oils and condensates produced from Mills Ranch field are genetically related to local Missourian mudstones/shales. Key geochemical attributes that set the Pennsylvanian oils apart from the Ordovician and Devonian-Mississippian systems are Mango K1 and K2 ratios, C27/C29 14? and 14?-sterane ratios > 1, abundant diahopane relative to 17?-hopane and high saturate/aromatic fraction d13C canonical variables. At least three organic-facies are identified within the Missourian section from integration of sedimentology, petrography and geochemistry. However, there is just one primary type-II organic-facies that is geochemically tied to the petroleum liquids. Models for the distribution of the primary type-II liquids-generating organic-facies have led to an improved assessment of the Mills Ranch field Missourian section, and a better understanding of the economic potential of Pennsylvanian shales in the Anadarko Basin. The Anadarko Basin is one of the most petroliferous basins in the world, and has a poly-basin history that can be subdivided into Ordovician, Devonian-Mississippian, and Pennsylvanian petroleum systems. Several previous studies within the Anadarko Basin highlight the potential of Pennsylvanian mudstones/shales as viable hydrocarbon sources. However, unlike source rocks in the Ordovician and Devonian-Mississippian petroleum systems, where clear geochemically validated examples of sourcing contributions in the basin exist, those of the Pennsylvanian system lack any clear geochemical ties. This study highlights the hydrocarbon-source relationship within Mills Ranch field (Hogshooter Formation: Missourian Series) along the Texas and Oklahoma border by clearly demonstrating the genetic relationship between produced oils/condensates and Missourian shales. Bitumen extracts from two mudstone-shale cores in the Hogshooter portion of the field were used to link the produced fluids to Missourian source beds. To validate key geochemical correlation characteristics, low maturity extracts from other representative source facies within the Anadarko basin were also used for comparison. Additionally, data from Woodford shale produced oils were used as a Devonian source control. Based on gas chromatography, coupled gas chromatography/mass spectrometry, and stable carbon isotope-ratio-mass-spectrometry analyses, light oils and condensates produced from Mills Ranch field are genetically related to local Missourian mudstones/shales. Key geochemical attributes that set the Pennsylvanian oils apart from the Ordovician and Devonian-Mississippian systems are Mango K1 and K2 ratios, C27/C29 14? and 14?-sterane ratios > 1, abundant diahopane relative to 17?-hopane and high saturate/aromatic fraction d13C canonical variables. At least three organic-facies are identified within the Missourian section from integration of sedimentology, petrography and geochemistry. However, there is just one primary type-II organic-facies that is geochemically tied to the petroleum liquids. Models for the distribution of the primary type-II liquids-generating organic-facies have led to an improved assessment of the Mills Ranch field Missourian section, and a better understanding of the economic potential of Pennsylvanian shales in the Anadarko Basin. Panel_15508 Panel_15508 2:40 PM 3:00 PM

Panel_15741 Panel_15741 3:00 PM 12:00 AM

The organic nitrogen content of most oils ranges from 0.1 to 2.0%. Migration distance, thermal maturity and depositional environments can potentially affect the distribution of carbazole and benzocarbazole isomers in the oils. However, the extent of variation within these compounds during migration is still poorly understood. In this study, the relationship between the distribution of organic nitrogen compounds in Woodford oils and source rocks in the Anadarko Basin has been investigated. 22 Oil samples and 4 rock samples from the Woodford have been investigated. 12 Woodford oils and 1 rock sample are from the Pauls Valley-Hunton Uplift area and 10 Woodford oils and 3 rock samples are from the Cherokee Platform region. The maturity of oil samples from Pauls Valley-Hunton Uplift is in the range of 0.58 to 0.69 (Rc) estimated from the methylphenanthrene index (MPI). Such small range maturity variations minimize the maturity impact on the distribution of nitrogen compounds. The content of nitrogen shielded carbazoles is low near the Anadarko Basin but high in the Pauls Valley-Hunton Uplift. The benzo-[a]/[(a)+(c)] -carbazole ratio (BC) is increasing from the Pauls Valley-Hunton Uplift to the Anadarko Basin. This trend suggests the migration pathway is from the center of the Anadarko Basin to the Pauls Valley-Hunton Uplift. Oil samples from Cherokee Platform are produced horizontally from the Woodford Shale. The maturity of the source rock and oils is higher than that of Pauls Valley-Hunton Uplift samples. The oils have a low abundance of both the carbazole and benzocarbazole isomers. Biomarker distributions indicate the organic matter input in Cherokee Platform is different from that in the Pauls Valley-Hunton Uplift. The organic facies might potentially affect the distribution of nitrogen compounds. Another possibility is that the Cherokee Platform oils have already migrated long distances, leading to a depletion of the carbazole and benzocarbazole isomers. Future work will focus on elucidating organic facies, depositional environments and maturity of these samples by studying aliphatic and aromatic compounds. Such research will potentially aid in the interpretation of migration pathways by using the distributions of carbazole and benzocarbazole isomers in the Anadarko Basin petroleum system. The organic nitrogen content of most oils ranges from 0.1 to 2.0%. Migration distance, thermal maturity and depositional environments can potentially affect the distribution of carbazole and benzocarbazole isomers in the oils. However, the extent of variation within these compounds during migration is still poorly understood. In this study, the relationship between the distribution of organic nitrogen compounds in Woodford oils and source rocks in the Anadarko Basin has been investigated. 22 Oil samples and 4 rock samples from the Woodford have been investigated. 12 Woodford oils and 1 rock sample are from the Pauls Valley-Hunton Uplift area and 10 Woodford oils and 3 rock samples are from the Cherokee Platform region. The maturity of oil samples from Pauls Valley-Hunton Uplift is in the range of 0.58 to 0.69 (Rc) estimated from the methylphenanthrene index (MPI). Such small range maturity variations minimize the maturity impact on the distribution of nitrogen compounds. The content of nitrogen shielded carbazoles is low near the Anadarko Basin but high in the Pauls Valley-Hunton Uplift. The benzo-[a]/[(a)+(c)] -carbazole ratio (BC) is increasing from the Pauls Valley-Hunton Uplift to the Anadarko Basin. This trend suggests the migration pathway is from the center of the Anadarko Basin to the Pauls Valley-Hunton Uplift. Oil samples from Cherokee Platform are produced horizontally from the Woodford Shale. The maturity of the source rock and oils is higher than that of Pauls Valley-Hunton Uplift samples. The oils have a low abundance of both the carbazole and benzocarbazole isomers. Biomarker distributions indicate the organic matter input in Cherokee Platform is different from that in the Pauls Valley-Hunton Uplift. The organic facies might potentially affect the distribution of nitrogen compounds. Another possibility is that the Cherokee Platform oils have already migrated long distances, leading to a depletion of the carbazole and benzocarbazole isomers. Future work will focus on elucidating organic facies, depositional environments and maturity of these samples by studying aliphatic and aromatic compounds. Such research will potentially aid in the interpretation of migration pathways by using the distributions of carbazole and benzocarbazole isomers in the Anadarko Basin petroleum system. Panel_15514 Panel_15514 3:25 PM 3:45 PM

A comprehensive geochemical study of oils from Railroad Valley and two candidate source rock intervals from the nearby Egan Range, was conducted in order to establish oil-oil and oil-source rock correlations. Total organic carbon analyses showed high organic content in the Mississippian Chainman Shale. However, outcrop samples of the Paleogene Sheep Pass Formation Member B are organically lean. Strata in both of these units are mature, and tend to be oil-gas prone. Biomarker analysis of oil samples revealed that two different oil families exist. Group 1 oils (Trap Spring and Grant Canyon oils) appear to originate from marine shale source rocks that were deposited under normal marine salinity and dysoxic conditions, as shown by high Pr/Ph ratios, low homohopane index, and high diasterane/steranes ratios. Group 1 oil correlates with Chainman Shale source rock extracts. Group 2 oils (Eagle Spring, Kate Spring, and Ghost Ranch oils) are lacustrine-derived and have low Pr/Ph, high gammacerane, good preservation of homohopane, and low diasterane/sterane ratios. The abundance of oleonane and dinosterane provides good evidence that oils belonging to this group are derived from source rocks younger than the Cretaceous, which points to the Sheep Pass Formation Member B. Our comprehensive geochemical study of oil also suggests that the oils from Kate Spring and Ghost Ranch are slightly different from oils from Eagle Spring but they are still closely related. Detail geochemical analysis were able to show that a difference in source rock facies and source rock depositional conditions in the lacustrine system serves as a key control that resulted in those differences. Stable carbon isotope data clearly showed two different groups. Group 1 oils have low d13CSAT and high d13CAROM, which is indicative of a marine source rock. On the other hand, Group 2 oils appear to have high d13CSAT and high d13CAROM, which suggests a lacustrine-derived oil. Additionally, diamondoid analyses showed most of my oil have low abundances of diamondoids, which suggest that intense oil cracking has not yet occurred. The result of this research shows that two different intervals (the Chainman Shale and the Sheep Pass Formation Member B) serve as effective source rocks in this basin.This new understanding of effective source rock(s) in this basin will significantly improve the hydrocarbon play concept as well as open the new perspective of hydrocarbon exploration within the Basin and Range area. A comprehensive geochemical study of oils from Railroad Valley and two candidate source rock intervals from the nearby Egan Range, was conducted in order to establish oil-oil and oil-source rock correlations. Total organic carbon analyses showed high organic content in the Mississippian Chainman Shale. However, outcrop samples of the Paleogene Sheep Pass Formation Member B are organically lean. Strata in both of these units are mature, and tend to be oil-gas prone. Biomarker analysis of oil samples revealed that two different oil families exist. Group 1 oils (Trap Spring and Grant Canyon oils) appear to originate from marine shale source rocks that were deposited under normal marine salinity and dysoxic conditions, as shown by high Pr/Ph ratios, low homohopane index, and high diasterane/steranes ratios. Group 1 oil correlates with Chainman Shale source rock extracts. Group 2 oils (Eagle Spring, Kate Spring, and Ghost Ranch oils) are lacustrine-derived and have low Pr/Ph, high gammacerane, good preservation of homohopane, and low diasterane/sterane ratios. The abundance of oleonane and dinosterane provides good evidence that oils belonging to this group are derived from source rocks younger than the Cretaceous, which points to the Sheep Pass Formation Member B. Our comprehensive geochemical study of oil also suggests that the oils from Kate Spring and Ghost Ranch are slightly different from oils from Eagle Spring but they are still closely related. Detail geochemical analysis were able to show that a difference in source rock facies and source rock depositional conditions in the lacustrine system serves as a key control that resulted in those differences. Stable carbon isotope data clearly showed two different groups. Group 1 oils have low d13CSAT and high d13CAROM, which is indicative of a marine source rock. On the other hand, Group 2 oils appear to have high d13CSAT and high d13CAROM, which suggests a lacustrine-derived oil. Additionally, diamondoid analyses showed most of my oil have low abundances of diamondoids, which suggest that intense oil cracking has not yet occurred. The result of this research shows that two different intervals (the Chainman Shale and the Sheep Pass Formation Member B) serve as effective source rocks in this basin.This new understanding of effective source rock(s) in this basin will significantly improve the hydrocarbon play concept as well as open the new perspective of hydrocarbon exploration within the Basin and Range area. Panel_15515 Panel_15515 4:05 PM 4:25 PM

Geochemical assessment of the composition of oil extracted from rocks is substantially different from that of produced oils. There is an obvious fractionation of petroleum during production in gas and oil composition and distribution. Understanding the petroleum in the unconventional source/reservoir rock is fundamental to understanding production results from volumes to phase and oil quality. There are a variety of processes alter petroleum compositions. These include primary migration, expulsion, and secondary migration to conventional reservoirs. In addition there are potential in situ alteration effects such as evaporative fractionation, gas washing, and biodegradation often identified in light hydrocarbon distributions. Thermal processes leads to an exponential series of alkanes that can be utilized to characterize oil type (black or volatile oil, condensate, wet or dry gas) from slope factors to oil quality such as API gravity. The formation of non-linear hydrocarbons including branched and cycloalkanes as well as aromatics is a function of petroleum structures in organic matter that includes both kerogen and secondarily formed products and lithofacies or inorganic chemical composition of source rocks. This interaction results in isomerization reactions that redistribute the hydrocarbons found in oil. As a result of these processes, intrinsic gas-to-oil ratio (GOR) can be predicted for petroleum stored in organoporosity. This technique is now extended source and reservoir rock extracts for pre-drill or organofacies variations in oil quality and GOR. The result of these processes, interpretation, and intrinsic calculations is a better understanding of in situ reservoir hydrocarbon fluids enabling enhanced production engineering decisions. Geochemical assessment of the composition of oil extracted from rocks is substantially different from that of produced oils. There is an obvious fractionation of petroleum during production in gas and oil composition and distribution. Understanding the petroleum in the unconventional source/reservoir rock is fundamental to understanding production results from volumes to phase and oil quality. There are a variety of processes alter petroleum compositions. These include primary migration, expulsion, and secondary migration to conventional reservoirs. In addition there are potential in situ alteration effects such as evaporative fractionation, gas washing, and biodegradation often identified in light hydrocarbon distributions. Thermal processes leads to an exponential series of alkanes that can be utilized to characterize oil type (black or volatile oil, condensate, wet or dry gas) from slope factors to oil quality such as API gravity. The formation of non-linear hydrocarbons including branched and cycloalkanes as well as aromatics is a function of petroleum structures in organic matter that includes both kerogen and secondarily formed products and lithofacies or inorganic chemical composition of source rocks. This interaction results in isomerization reactions that redistribute the hydrocarbons found in oil. As a result of these processes, intrinsic gas-to-oil ratio (GOR) can be predicted for petroleum stored in organoporosity. This technique is now extended source and reservoir rock extracts for pre-drill or organofacies variations in oil quality and GOR. The result of these processes, interpretation, and intrinsic calculations is a better understanding of in situ reservoir hydrocarbon fluids enabling enhanced production engineering decisions. Panel_15513 Panel_15513 4:25 PM 4:45 PM

Hydrocarbons are retained in shales either in an adsorbed state on particle surfaces or in a free form within pores and fractures. The relative importance of the two mechanisms and the total retention capacity vary considerably at both reservoir and regional scales. Identifying the controls of hydrocarbon retention, and predicting sweet spots in heterogeneous media are key goals in exploration. Here we contrast two shale plays – the Barnett Shale, known for its heterogeneity with locally high productivity, and the Posidonia Shale (Germany), a lithologically homogeneous calcareous mudstone/marl with untested potential. Using a multiparameter approach involving geochemistry, mineralogy and petrophysics, well profiles have been characterized in detail. Organic matter properties i.e. richness, thermal maturity and kerogen composition control retention in both cases. A generally positive correlation is observed between organic richness and the amount of retained bitumen. As maturity increases the TOC normalized bitumen concentration (S1/TOC) first increases in the oil window, and subsequently decreases once the shale enters the wet-gas window. Interestingly, it is the “live” carbon, especially where aromatic, rather than “dead” carbon which preferentially retains hydrocarbons. Shale intervals enriched in free oil or bitumen are not necessarily associated with the organic richest layers. Indeed, oil crossovers (S1/TOC >100 mg/g TOC) generally occur within layers where biogenic matrices are also abundant. In the Barnett Shale for instance, the presence of sponge spicules directly controls the accumulation of intraformationally migrated oil, as demonstrated by compositional mass balance calculations. In the Posidonia Shale, oil crossovers occur in zones where biogenic calcite in the form of coccolithophores provides enhanced pore space. The overall porosity first decreases with increasing maturity, which can be ascribed to progressing compaction on the one hand and to pore plugging by bitumen on the other hand. Then, nano-pores formed by kerogen decomposition subsequently contribute to the later increase of porosity in the gas window. In summary, the combination of organic matter enrichment and abundance of porous fossils delineate the most productive intervals in both of the examples shown. The siliceous sponge spicule and calcareous coccolithophore enrichment layers in the Barnett and Posidonia Shale, respectively, represent the main reservoir facies. Hydrocarbons are retained in shales either in an adsorbed state on particle surfaces or in a free form within pores and fractures. The relative importance of the two mechanisms and the total retention capacity vary considerably at both reservoir and regional scales. Identifying the controls of hydrocarbon retention, and predicting sweet spots in heterogeneous media are key goals in exploration. Here we contrast two shale plays – the Barnett Shale, known for its heterogeneity with locally high productivity, and the Posidonia Shale (Germany), a lithologically homogeneous calcareous mudstone/marl with untested potential. Using a multiparameter approach involving geochemistry, mineralogy and petrophysics, well profiles have been characterized in detail. Organic matter properties i.e. richness, thermal maturity and kerogen composition control retention in both cases. A generally positive correlation is observed between organic richness and the amount of retained bitumen. As maturity increases the TOC normalized bitumen concentration (S1/TOC) first increases in the oil window, and subsequently decreases once the shale enters the wet-gas window. Interestingly, it is the “live” carbon, especially where aromatic, rather than “dead” carbon which preferentially retains hydrocarbons. Shale intervals enriched in free oil or bitumen are not necessarily associated with the organic richest layers. Indeed, oil crossovers (S1/TOC >100 mg/g TOC) generally occur within layers where biogenic matrices are also abundant. In the Barnett Shale for instance, the presence of sponge spicules directly controls the accumulation of intraformationally migrated oil, as demonstrated by compositional mass balance calculations. In the Posidonia Shale, oil crossovers occur in zones where biogenic calcite in the form of coccolithophores provides enhanced pore space. The overall porosity first decreases with increasing maturity, which can be ascribed to progressing compaction on the one hand and to pore plugging by bitumen on the other hand. Then, nano-pores formed by kerogen decomposition subsequently contribute to the later increase of porosity in the gas window. In summary, the combination of organic matter enrichment and abundance of porous fossils delineate the most productive intervals in both of the examples shown. The siliceous sponge spicule and calcareous coccolithophore enrichment layers in the Barnett and Posidonia Shale, respectively, represent the main reservoir facies. Panel_15509 Panel_15509 4:45 PM 5:05 PM

Panel_14430 Panel_14430 1:15 PM 5:05 PM

Panel_15742 Panel_15742 1:15 PM 12:00 AM

Total organic carbon (TOC) content and the quartz/clay ratio are critical elements of shale reservoir characterization. TOC influences the volumes of hydrocarbon generated, the fraction of porosity and the mechanism of hydrocarbon storage (free gas versus adsorbed gas). The quartz/clay ratio influences the mechanical properties of formations and therefore whether they are prone to develop natural or hydraulically induced fractures. Quantitative measurements of these properties are now based on either direct chemical analyses of rock samples or interpretations of well logs. Chemical measurements on core samples are a subsample of the entire formation, and the continuous distribution has to be extrapolated from discrete points. Well logs provide a continuous record but average properties at scales up to one meter. Where chemical properties vary significantly at smaller scales, likely the case in shale formations, these techniques provide an incomplete or blurry record of the rock properties. We have tested a new technique for characterizing shale formations – hyperspectral scanning. This technique relies on the distinctive spectral properties of quartz, clay and organic carbon-bearing substances, specifically key absorption bands in the shortwave and longwave IR spectra. We report on two data sets. Core samples from two wells in the Woodford Shale, Permian Basin, west Texas, were analyzed for major/minor/trace elements, TOC and Rockeval parameters. The strength of absorptions in reflectance spectra correlates effectively with both TOC and SiO2 content (R2=0.87 and 0.93, respectively). The Woodford has very different thermal maturities in two wells, a difference also effectively identified by spectral results. We are now applying and evaluating this approach to an extensively sampled 150 meter core from the Horn River shale in British Columbia, where TOC ranges from 0.12 to 9.38% and Al2O3/SiO2 ranges from 0.04 to 0.37. Total organic carbon (TOC) content and the quartz/clay ratio are critical elements of shale reservoir characterization. TOC influences the volumes of hydrocarbon generated, the fraction of porosity and the mechanism of hydrocarbon storage (free gas versus adsorbed gas). The quartz/clay ratio influences the mechanical properties of formations and therefore whether they are prone to develop natural or hydraulically induced fractures. Quantitative measurements of these properties are now based on either direct chemical analyses of rock samples or interpretations of well logs. Chemical measurements on core samples are a subsample of the entire formation, and the continuous distribution has to be extrapolated from discrete points. Well logs provide a continuous record but average properties at scales up to one meter. Where chemical properties vary significantly at smaller scales, likely the case in shale formations, these techniques provide an incomplete or blurry record of the rock properties. We have tested a new technique for characterizing shale formations – hyperspectral scanning. This technique relies on the distinctive spectral properties of quartz, clay and organic carbon-bearing substances, specifically key absorption bands in the shortwave and longwave IR spectra. We report on two data sets. Core samples from two wells in the Woodford Shale, Permian Basin, west Texas, were analyzed for major/minor/trace elements, TOC and Rockeval parameters. The strength of absorptions in reflectance spectra correlates effectively with both TOC and SiO2 content (R2=0.87 and 0.93, respectively). The Woodford has very different thermal maturities in two wells, a difference also effectively identified by spectral results. We are now applying and evaluating this approach to an extensively sampled 150 meter core from the Horn River shale in British Columbia, where TOC ranges from 0.12 to 9.38% and Al2O3/SiO2 ranges from 0.04 to 0.37. Panel_14958 Panel_14958 1:20 PM 1:40 PM

Over the last 10 years the use of inorganic elemental data to characterize and correlate sedimentary sequences both in academia and within the oil and gas industry has increased dramatically. The increase in demand for elemental data has come hand-in-hand with an increase in the number of different analytical options available to generate this type of dataset; from lab-based ICP (inductively-coupled plasma) OES and MS (Optical Emission spectroscopy and Mass Spectroscopy) to portable and hand-held XRF (X-ray fluorescence) instruments. In this study we investigate the type and quality of data derived from different analytical methodologies (ICP, XRF) and instrument types (hand-held, bench-top or laboratory). Additionally, we demonstrate the efficacy of different instrumentation in the acquisition of elemental data from core, cuttings and powdered/pelleted samples. Through a series of case studies from several North American shale plays, we discuss the best strategies for interpreting and assessing data quality from full lab-based XRF and ICP-OES/MS datasets through to those generated from hand-held XRF instruments, where lighter major elements like sodium are not acquired. Furthermore, the level of confidence that can be placed on key elements when providing an interpretation from these datasets will also be addressed, specifically where elemental data is used to generate mineral models or where trace elements such as Mo, V, Ni and U are used to assess anoxic conditions at the time of deposition. In many cases, these parameters are used to refine target zones within a shale play and are best put to use when integrated with other mineralogical or petrophysical datasets. As users of these data, it is important to understand the confidence that can be placed on different bulk elemental datasets especially when using different sample selection, preparation and analytical methodologies. Over the last 10 years the use of inorganic elemental data to characterize and correlate sedimentary sequences both in academia and within the oil and gas industry has increased dramatically. The increase in demand for elemental data has come hand-in-hand with an increase in the number of different analytical options available to generate this type of dataset; from lab-based ICP (inductively-coupled plasma) OES and MS (Optical Emission spectroscopy and Mass Spectroscopy) to portable and hand-held XRF (X-ray fluorescence) instruments. In this study we investigate the type and quality of data derived from different analytical methodologies (ICP, XRF) and instrument types (hand-held, bench-top or laboratory). Additionally, we demonstrate the efficacy of different instrumentation in the acquisition of elemental data from core, cuttings and powdered/pelleted samples. Through a series of case studies from several North American shale plays, we discuss the best strategies for interpreting and assessing data quality from full lab-based XRF and ICP-OES/MS datasets through to those generated from hand-held XRF instruments, where lighter major elements like sodium are not acquired. Furthermore, the level of confidence that can be placed on key elements when providing an interpretation from these datasets will also be addressed, specifically where elemental data is used to generate mineral models or where trace elements such as Mo, V, Ni and U are used to assess anoxic conditions at the time of deposition. In many cases, these parameters are used to refine target zones within a shale play and are best put to use when integrated with other mineralogical or petrophysical datasets. As users of these data, it is important to understand the confidence that can be placed on different bulk elemental datasets especially when using different sample selection, preparation and analytical methodologies. Panel_14960 Panel_14960 1:40 PM 2:00 PM

Since the initial Bakken discovery well in 1957, over 8000 Bakken and 1600 Three Forks wells have been drilled across North Dakota, Montana and Saskatchewan. Over the past decade we have seen a rapid uptick in the geologic understanding of the Bakken and Three Forks, coupled with increasingly effective, and efficient, customization of drilling and completions. We illustrate how the emergence of geologic data coverage has driven industry understanding of play nuances. Regional structural, thickness and geochemistry maps highlight early play characterization and identification of the eastern "line of death" and unique characteristics of the Sanish and Parshall fields. Lithofacies classification of vertical well log suites illustrate the insights gained from delineation wells that framed interpretation of the complex play stratigraphy. More recently, sufficient well coverage has emerged to consistently map oil saturation/water cut across the basin; supported by more detailed depth and character mapping using the extensive gamma-ray coverage. Keeping pace with burgeoning geologic understanding, well completion techniques have been tested and tuned - from single to 40 and 50 stages - with sand volumes ranging well above 10 million pounds and accompanying fluids beyond 150,000 barrels. Currently, multi-lateral co-development of Bakken and two-to-four Three Forks formations are becoming standard operating procedure. "Frac hits" have emerged as the key development optimization focus as well spacings approach 500 feet in common formations and 250 feet in staggered multi-level patterns. While overlapping zones of stimulation can have beneficial effects, delayed infills are proving to be very problematic with unclear economic tradeoffs of increased, though contested well production, often offset with dramatic production decline in adjacent, active wells. Oilfield analytics provide a unique perspective of the ongoing efforts to "right size" drilling and completions engineering for rock and fluid characteristics in the Bakken and Three Forks reservoirs. Dynamic well spacing, vertical and lateral geometry, drilling and completions parameters and geologic character can all be quantified; providing a common basis for using analytic techniques to predict well performance. The results of these analyses are improved understanding of geologic prospectivity, independent of engineering, as well as indications of optimized engineering techniques for different geologic scenarios. Since the initial Bakken discovery well in 1957, over 8000 Bakken and 1600 Three Forks wells have been drilled across North Dakota, Montana and Saskatchewan. Over the past decade we have seen a rapid uptick in the geologic understanding of the Bakken and Three Forks, coupled with increasingly effective, and efficient, customization of drilling and completions. We illustrate how the emergence of geologic data coverage has driven industry understanding of play nuances. Regional structural, thickness and geochemistry maps highlight early play characterization and identification of the eastern "line of death" and unique characteristics of the Sanish and Parshall fields. Lithofacies classification of vertical well log suites illustrate the insights gained from delineation wells that framed interpretation of the complex play stratigraphy. More recently, sufficient well coverage has emerged to consistently map oil saturation/water cut across the basin; supported by more detailed depth and character mapping using the extensive gamma-ray coverage. Keeping pace with burgeoning geologic understanding, well completion techniques have been tested and tuned - from single to 40 and 50 stages - with sand volumes ranging well above 10 million pounds and accompanying fluids beyond 150,000 barrels. Currently, multi-lateral co-development of Bakken and two-to-four Three Forks formations are becoming standard operating procedure. "Frac hits" have emerged as the key development optimization focus as well spacings approach 500 feet in common formations and 250 feet in staggered multi-level patterns. While overlapping zones of stimulation can have beneficial effects, delayed infills are proving to be very problematic with unclear economic tradeoffs of increased, though contested well production, often offset with dramatic production decline in adjacent, active wells. Oilfield analytics provide a unique perspective of the ongoing efforts to "right size" drilling and completions engineering for rock and fluid characteristics in the Bakken and Three Forks reservoirs. Dynamic well spacing, vertical and lateral geometry, drilling and completions parameters and geologic character can all be quantified; providing a common basis for using analytic techniques to predict well performance. The results of these analyses are improved understanding of geologic prospectivity, independent of engineering, as well as indications of optimized engineering techniques for different geologic scenarios. Panel_14956 Panel_14956 2:00 PM 2:20 PM

Methods and results from high resolution x-ray fluorescence studies on mudstone units from the Western Canadian Basin and eastern Canada show how a simple tool can be of great value for constructing a stratigraphic framework, complementing and refining sedimentological descriptions, as well as for optimizing and improving hydraulic fracturing of shales. Acquisition of continuous XRF was performed at a centimeter scale on cores and every five meters in cuttings and covered four different shale/mudstone facies associations; two from siliciclastic origin and two from carbonates. The various studies collected more than 110,000 samples from cores. The relationships between different XRF derived elemental compositions have helped define sedimentary successions that elegantly complement sedimentological core descriptions and shed light on some sedimentary processes of deposition. Among numerous findings of various kinds, our study showed that the relationship calcium manganese in the Montney Formation can clearly define more than twenty chemo-stratigraphic units and distinguish between specific carbonate lithofacies and calcite cemented horizons and can be used as a proxy for sedimentation rate. Obvious shifts in Ca/Mn trends are used to distinguish between sedimentary packages; the polarity of the shift reflecting sedimentary processes and sequence stratigraphy / system tracts. Extensive statistical analysis of elemental composition against geomechanics has demonstrated that each newly defined chemostratigraphic unit has the better relationship/regression than any combination of adjacent packages; i.e. Rsquare is always higher for a single package that for any possible combination including the underlying and/or overlying units. Both XRF and XRD data clearly demonstrate that single formulae are not adequate to predict brittleness; e.g. in some units such as the Duvernay using XRD, a tectosilicate (quartz + feldspars + plagioclase ) cut-off of 40% has to be applied prior to establishing a relationship between mineralogy and Young’s Modulus. Similarly at a larger scale and based on stratigraphy, the Upper Montney needs to be analyzed separately from the Middle/Lower Montney if any meaningfull results are to be expected. Basin and field wide XRF-based correlations have been established to satisfaction and can be used for steering, unit selection for stimulation and frac placement analysis. Methods and results from high resolution x-ray fluorescence studies on mudstone units from the Western Canadian Basin and eastern Canada show how a simple tool can be of great value for constructing a stratigraphic framework, complementing and refining sedimentological descriptions, as well as for optimizing and improving hydraulic fracturing of shales. Acquisition of continuous XRF was performed at a centimeter scale on cores and every five meters in cuttings and covered four different shale/mudstone facies associations; two from siliciclastic origin and two from carbonates. The various studies collected more than 110,000 samples from cores. The relationships between different XRF derived elemental compositions have helped define sedimentary successions that elegantly complement sedimentological core descriptions and shed light on some sedimentary processes of deposition. Among numerous findings of various kinds, our study showed that the relationship calcium manganese in the Montney Formation can clearly define more than twenty chemo-stratigraphic units and distinguish between specific carbonate lithofacies and calcite cemented horizons and can be used as a proxy for sedimentation rate. Obvious shifts in Ca/Mn trends are used to distinguish between sedimentary packages; the polarity of the shift reflecting sedimentary processes and sequence stratigraphy / system tracts. Extensive statistical analysis of elemental composition against geomechanics has demonstrated that each newly defined chemostratigraphic unit has the better relationship/regression than any combination of adjacent packages; i.e. Rsquare is always higher for a single package that for any possible combination including the underlying and/or overlying units. Both XRF and XRD data clearly demonstrate that single formulae are not adequate to predict brittleness; e.g. in some units such as the Duvernay using XRD, a tectosilicate (quartz + feldspars + plagioclase ) cut-off of 40% has to be applied prior to establishing a relationship between mineralogy and Young’s Modulus. Similarly at a larger scale and based on stratigraphy, the Upper Montney needs to be analyzed separately from the Middle/Lower Montney if any meaningfull results are to be expected. Basin and field wide XRF-based correlations have been established to satisfaction and can be used for steering, unit selection for stimulation and frac placement analysis. Panel_14962 Panel_14962 2:20 PM 2:40 PM

The Upper Cretaceous Eagle Ford Shale and equivalent Boquillas Formation contain abundant bentonitic, volcanic ash beds of varying thickness. The abundance of melt-derived, non-detrital zircon crystals in these deposits provides an opportunity to develop a high-resolution geochronology of a mudrock system with U-Pb dating that can be used as a basis for testing the accuracy and validity of other methods of stratal and temporal correlation. Here we present the first extensive collection of U-Pb dates yet obtained for this system and discuss their implications. We collected, processed, and analyzed 14 ash beds from outcrops and cores from three areas in a 350 mi transect along the South Texas shelf from around Austin, Texas on the east to outcrops near Comstock, Texas on the west. Zircon abundance ranged from 27 to 164 crystals per sample (average: 60). Zircons were analyzed using laser ablation ICP-MS procedures at the University of Texas at Austin. Ash bed ages range from about 87 to 97 Ma. Comparisons of our new age dates with biostratigraphic determinations of Cenomanian/Turonian boundary show that our data are largely consistent with those reported elsewhere at about 93-94 Ma. However, U-Pb dates suggest that the Eagle Ford/Boquillas section varies greatly in temporal duration locally, ranging from as much as 10 Ma in some areas to possibly as little as 5-6 Ma in others. Although ash bed LA-ICP-MS U-Pb dates do not provide sufficient temporal resolution needed to develop bed-to-bed correlations, they do place important constraints on regional correlation frameworks based on biostratigraphy, chemostratigraphy facies, and wireline logs. Not surprisingly, these data illustrate that the upper and lower contacts of the Eagle Ford are time transgressive - findings previously discounted by many - casting doubt on wireline log-based correlations. But U-Pb data are also locally in disagreement with more robust methods of correlation, including carbon isotope and redox trace element profiles. Collective comparison of different data sets suggests that although more extensive biostratigraphic data are needed, additional U-Pb zircon geochronology using LA-ICP-MS and higher resolution thermal ionization mass spectrometry (TIMS) combined with redox sensitive trace element chemostratigraphy may form the best basis for defining temporal correlations and mudrock facies architecture in this complex depositional system. The Upper Cretaceous Eagle Ford Shale and equivalent Boquillas Formation contain abundant bentonitic, volcanic ash beds of varying thickness. The abundance of melt-derived, non-detrital zircon crystals in these deposits provides an opportunity to develop a high-resolution geochronology of a mudrock system with U-Pb dating that can be used as a basis for testing the accuracy and validity of other methods of stratal and temporal correlation. Here we present the first extensive collection of U-Pb dates yet obtained for this system and discuss their implications. We collected, processed, and analyzed 14 ash beds from outcrops and cores from three areas in a 350 mi transect along the South Texas shelf from around Austin, Texas on the east to outcrops near Comstock, Texas on the west. Zircon abundance ranged from 27 to 164 crystals per sample (average: 60). Zircons were analyzed using laser ablation ICP-MS procedures at the University of Texas at Austin. Ash bed ages range from about 87 to 97 Ma. Comparisons of our new age dates with biostratigraphic determinations of Cenomanian/Turonian boundary show that our data are largely consistent with those reported elsewhere at about 93-94 Ma. However, U-Pb dates suggest that the Eagle Ford/Boquillas section varies greatly in temporal duration locally, ranging from as much as 10 Ma in some areas to possibly as little as 5-6 Ma in others. Although ash bed LA-ICP-MS U-Pb dates do not provide sufficient temporal resolution needed to develop bed-to-bed correlations, they do place important constraints on regional correlation frameworks based on biostratigraphy, chemostratigraphy facies, and wireline logs. Not surprisingly, these data illustrate that the upper and lower contacts of the Eagle Ford are time transgressive - findings previously discounted by many - casting doubt on wireline log-based correlations. But U-Pb data are also locally in disagreement with more robust methods of correlation, including carbon isotope and redox trace element profiles. Collective comparison of different data sets suggests that although more extensive biostratigraphic data are needed, additional U-Pb zircon geochronology using LA-ICP-MS and higher resolution thermal ionization mass spectrometry (TIMS) combined with redox sensitive trace element chemostratigraphy may form the best basis for defining temporal correlations and mudrock facies architecture in this complex depositional system. Panel_14957 Panel_14957 2:40 PM 3:00 PM

Panel_15743 Panel_15743 3:00 PM 12:00 AM

As the pursuit of oil and gas in unconventional reservoirs grows, it is increasingly evident that horizontal wellbore placement, or targeting, plays a first-order role in the production capability of a well. Indeed, the percentage of a wellbore “in target” is a common metric used when evaluating the causes for good or poor production from any particular well. The most common process used for geosteering a horizontal wellbore into a chosen target is the correlation of logging-while-drilling (LWD) total gamma ray (GR) to a vertical pilot-hole GR log. However limitations inherent to this procedure can reduce the ability to effectively use LWD GR data. These limitations can include short GR counting intervals vs rate of penetration (ROP), GR detector sizes, and data transmission. Geologic factors such as low GR contrast from bed to bed, and repetitive GR trends, especially in areas where faulting with significant throw (defined as ? to thickness of the target) can further complicate the correlation of LWD GR data back to the pilot hole. In effort to more accurately geosteer wells we have employed the use of elemental data derived from energy-dispersive X-ray fluorescence (ED-XRF). Elemental data is acquired on vertical pilot holes at the heal and, where possible, near the toe of proposed laterals, at one foot intervals on core and five foot intervals on cuttings. This data is used to build a chemostratigraphic profile and zonation of the section. Chemostratigraphic zones are defined as having multiple elements (where possible) which illustrate distinct changes in chemical profiles from one zone to another. These zones must be correlative over reasonable distances (at a minimum the length of the horizontal wellbore) and must be readily identifiable in cuttings. Using these criteria chemostratigraphic zonations have been constructed in the Marcellus Shale, Lower Huron Shale, and Newman (Big Lime) Limestone. Well site ED-XRF data was used in conjunction with LWD GR to geosteer a ~25’ thick porosity zone which resides at the base of a ~400’ thick non-porous/non reservoir carbonate section of the Newman Limestone and immediately underlain by the siltstones and shales of the Borden Shale. Well site XRF data was successfully used to identify cave-ins that were mistakenly identified as the Borden Shale, determine the position of the wellbore in zones of non-descript GR signature, and determine the lateral extent of the reservoir interval. As the pursuit of oil and gas in unconventional reservoirs grows, it is increasingly evident that horizontal wellbore placement, or targeting, plays a first-order role in the production capability of a well. Indeed, the percentage of a wellbore “in target” is a common metric used when evaluating the causes for good or poor production from any particular well. The most common process used for geosteering a horizontal wellbore into a chosen target is the correlation of logging-while-drilling (LWD) total gamma ray (GR) to a vertical pilot-hole GR log. However limitations inherent to this procedure can reduce the ability to effectively use LWD GR data. These limitations can include short GR counting intervals vs rate of penetration (ROP), GR detector sizes, and data transmission. Geologic factors such as low GR contrast from bed to bed, and repetitive GR trends, especially in areas where faulting with significant throw (defined as ? to thickness of the target) can further complicate the correlation of LWD GR data back to the pilot hole. In effort to more accurately geosteer wells we have employed the use of elemental data derived from energy-dispersive X-ray fluorescence (ED-XRF). Elemental data is acquired on vertical pilot holes at the heal and, where possible, near the toe of proposed laterals, at one foot intervals on core and five foot intervals on cuttings. This data is used to build a chemostratigraphic profile and zonation of the section. Chemostratigraphic zones are defined as having multiple elements (where possible) which illustrate distinct changes in chemical profiles from one zone to another. These zones must be correlative over reasonable distances (at a minimum the length of the horizontal wellbore) and must be readily identifiable in cuttings. Using these criteria chemostratigraphic zonations have been constructed in the Marcellus Shale, Lower Huron Shale, and Newman (Big Lime) Limestone. Well site ED-XRF data was used in conjunction with LWD GR to geosteer a ~25’ thick porosity zone which resides at the base of a ~400’ thick non-porous/non reservoir carbonate section of the Newman Limestone and immediately underlain by the siltstones and shales of the Borden Shale. Well site XRF data was successfully used to identify cave-ins that were mistakenly identified as the Borden Shale, determine the position of the wellbore in zones of non-descript GR signature, and determine the lateral extent of the reservoir interval. Panel_14961 Panel_14961 3:25 PM 3:45 PM

The Wolfcamp Formation has emerged as a major unconventional resource play in Texas. There is a wide range of oil vs. water production observed in the hundreds of horizontal wells that have targeted this formation. This variability has become a serious challenge for many operators and there is a strong need to understand how to select lateral landing zones to increase oil production and minimize water production. Using slabbed core from the Texas Bureau of Economic Geology (BEG) in Austin, TX, we have used a combination of X-ray CT imaging and 3D FIB-SEM analysis to look for some clues. The well will be referred to as Wolfcamp-1 and is located in the southern Midland Basin. The 168 foot cored interval from Wolfcamp-1 was X-ray CT imaged using a dual-energy method. Dual energy CT imaging allows for the computation of both bulk density and PEF (photoelectric factor) and this information was used to determine rock facies and reservoir quality at high resolution. In combination with spectral gamma scanning, the dual-energy CT data allows for application of petrophysical principles to compute lithology, brittleness, and TOC over the entire cored depth interval. This data was also used to select the exact locations where plug samples were needed to begin to understand the rock characteristics. Additional detailed analysis was conducted on plug samples to define and quantify the key shale reservoir properties including total porosity, connected porosity, organic porosity, pore size distribution, permeability, and the apparent transformation ratio, which is controlled by thermal maturity and kerogen type. The collection and integration of the data from this Digital Rock Physics (DRP) study of samples from the Wolfcamp formation shows that rock types, porosity, and permeability are highly variable and that data from the Wolfcamp-1 well are typical of other Wolfcamp wells we have tested. The DRP analysis further shows that some samples have mostly intergranular pores and while other samples have mostly porosity inside the organic material. Both types of samples may have relatively high porosity and permeability. If we assume that water resides mostly in the intergranular pores and that hydrocarbons are more common in the organic pores, then it suggests that oil production may be increased by targeting the lateral landing zone in the intervals with greatest organic porosity, not just the greatest total porosity. The Wolfcamp Formation has emerged as a major unconventional resource play in Texas. There is a wide range of oil vs. water production observed in the hundreds of horizontal wells that have targeted this formation. This variability has become a serious challenge for many operators and there is a strong need to understand how to select lateral landing zones to increase oil production and minimize water production. Using slabbed core from the Texas Bureau of Economic Geology (BEG) in Austin, TX, we have used a combination of X-ray CT imaging and 3D FIB-SEM analysis to look for some clues. The well will be referred to as Wolfcamp-1 and is located in the southern Midland Basin. The 168 foot cored interval from Wolfcamp-1 was X-ray CT imaged using a dual-energy method. Dual energy CT imaging allows for the computation of both bulk density and PEF (photoelectric factor) and this information was used to determine rock facies and reservoir quality at high resolution. In combination with spectral gamma scanning, the dual-energy CT data allows for application of petrophysical principles to compute lithology, brittleness, and TOC over the entire cored depth interval. This data was also used to select the exact locations where plug samples were needed to begin to understand the rock characteristics. Additional detailed analysis was conducted on plug samples to define and quantify the key shale reservoir properties including total porosity, connected porosity, organic porosity, pore size distribution, permeability, and the apparent transformation ratio, which is controlled by thermal maturity and kerogen type. The collection and integration of the data from this Digital Rock Physics (DRP) study of samples from the Wolfcamp formation shows that rock types, porosity, and permeability are highly variable and that data from the Wolfcamp-1 well are typical of other Wolfcamp wells we have tested. The DRP analysis further shows that some samples have mostly intergranular pores and while other samples have mostly porosity inside the organic material. Both types of samples may have relatively high porosity and permeability. If we assume that water resides mostly in the intergranular pores and that hydrocarbons are more common in the organic pores, then it suggests that oil production may be increased by targeting the lateral landing zone in the intervals with greatest organic porosity, not just the greatest total porosity. Panel_14959 Panel_14959 3:45 PM 4:05 PM

The Rock-Eval is a versatile, high-tech instrument for geochemical assessment of fossil organic matter. It imposed itself as a standard technic which has evolved over the last decades in terms of hardware, software and interpretation capabilities. Primarily, in a conventional petroleum system perspective, it has been designed as a screening tool assessing basic organic attributes of source rocks, such as occurrence of organic matter, TOC, petroleum potential and thermal maturity (Espitalié and Bordenave 1993). Further improvements were developed in order to determine kinetics parameters (e.g. Ungerer 1986, 1987) and more recently carbonate content and type (Pillot et al 2013). Moreover, several of these attributes are instrumental inputs for any numerical basin modeling. Due to operational constraints, sampling is often poor and relies mainly on cuttings which are mixing lithologies and are often stored in non-adequate conditions, implying an uncertain assessment of free hydrocarbons content (S1). The Rock-Eval program developed was then not specifically directed to measure this parameter with accuracy. For instance, the initial heating temperature of the standard Rock-Eval program (set à 300°C) leads to a loss of the lighter end of free hydrocarbons. Consequently with this standard methodology the S1 parameter is generally not seriously considered. With the rise of shale plays interest, a specific focus is needed in order to quantify the occurring free hydrocarbons and assess their nature and properties. In this respect, a new Rock-Eval method is proposed to provide this kind of information. This method, presented using examples, implies a low initial thermovaporization temperature which allows to minimize the loss of the lightest hydrocarbons. Consequently, it provides a more realistic value for the free hydrocarbons occurring in shale play samples. This method is also designed to generate a double peak for the free hydrocarbons, with the aim to tentatively provide an insight in the quality of the hydrocarbon fluids. This double peak is artificially induced by introducing a selected temperature plateau during the step of hydrocarbons thermovaporization. Information on the nature of hydrocarbon fluids and operational proxies, i.e. API of the fluid in the rock, are derived from a processing of the relative importance of these two peaks. In addition, this new methodology intents to prevent the potential interference of heavy hydrocarbons with the peak resulting from the pyrolysis of the kerogen (S2). This interference is more likely to occur in oil-rich shale plays and are likely to bias parameters such as residual HI and Tmax. The Rock-Eval is a versatile, high-tech instrument for geochemical assessment of fossil organic matter. It imposed itself as a standard technic which has evolved over the last decades in terms of hardware, software and interpretation capabilities. Primarily, in a conventional petroleum system perspective, it has been designed as a screening tool assessing basic organic attributes of source rocks, such as occurrence of organic matter, TOC, petroleum potential and thermal maturity (Espitalié and Bordenave 1993). Further improvements were developed in order to determine kinetics parameters (e.g. Ungerer 1986, 1987) and more recently carbonate content and type (Pillot et al 2013). Moreover, several of these attributes are instrumental inputs for any numerical basin modeling. Due to operational constraints, sampling is often poor and relies mainly on cuttings which are mixing lithologies and are often stored in non-adequate conditions, implying an uncertain assessment of free hydrocarbons content (S1). The Rock-Eval program developed was then not specifically directed to measure this parameter with accuracy. For instance, the initial heating temperature of the standard Rock-Eval program (set à 300°C) leads to a loss of the lighter end of free hydrocarbons. Consequently with this standard methodology the S1 parameter is generally not seriously considered. With the rise of shale plays interest, a specific focus is needed in order to quantify the occurring free hydrocarbons and assess their nature and properties. In this respect, a new Rock-Eval method is proposed to provide this kind of information. This method, presented using examples, implies a low initial thermovaporization temperature which allows to minimize the loss of the lightest hydrocarbons. Consequently, it provides a more realistic value for the free hydrocarbons occurring in shale play samples. This method is also designed to generate a double peak for the free hydrocarbons, with the aim to tentatively provide an insight in the quality of the hydrocarbon fluids. This double peak is artificially induced by introducing a selected temperature plateau during the step of hydrocarbons thermovaporization. Information on the nature of hydrocarbon fluids and operational proxies, i.e. API of the fluid in the rock, are derived from a processing of the relative importance of these two peaks. In addition, this new methodology intents to prevent the potential interference of heavy hydrocarbons with the peak resulting from the pyrolysis of the kerogen (S2). This interference is more likely to occur in oil-rich shale plays and are likely to bias parameters such as residual HI and Tmax. Panel_14955 Panel_14955 4:05 PM 4:25 PM

Detailed investigation of the chemical nature and the hardness of the Devonian-Mississippian Bakken Formation as well as the underlying Devonian Three Forks Formation, Williston Basin of North Dakota, were undertaken to both evaluate the relationships of these rock properties within a stratigraphic and paleontological framework and to assess their utility in correlating intervals within these formations across a broad areal extent. Hand-held X-ray fluorescence (XRF) data and rock hardness analyses were acquired on the same intervals at a high density (generally every 3”) throughout the entire Bakken and into the Three Forks in two widely spaced wells (~30 miles apart) and these data were augmented with XRF data from a third well (~40 mi away). Chemofacies established from the XRF data were primarily defined using calcium, silicon and aluminum and secondarily by other major elements as well as the trace metals iron and molybdenum. A strong, negative relationship exists between rock hardness results and intervals enriched in aluminum and potassium (associated with clay minerals), resulting in particular hardness zones and chemofacies co-occurring at the same stratigraphic intervals. These intervals also appear to co-occur with distinct lithofacies and biofacies that facilitate the subdivision of the Bakken Formation and the upper Three Forks into at least 9 zones that can be correlated across this transect in the Williston Basin. Of the 9 zones, a total of 7 are apparent in the Bakken, with 2 each in the upper and lower shale members, and 3 in the middle member. The remaining 2 zones were identified in the upper part of the Three Forks. Some facies show minor or significant lateral variations in chemical, faunal, hardness, or sedimentological character whereas others appear continuous across the studied transect. The 9 stratigraphic intervals can be confidently distinguished in the Bakken and the Three Forks by combining different facies/chemofacies characteristics. Because many of these facies also have identifiable well log signatures, the integration of facies evaluations from Bakken/Three Forks cores with XRF and rock hardness data may improve interpretations of log data from locations where core is not readily available, especially as it pertains to predicting rock properties. Detailed investigation of the chemical nature and the hardness of the Devonian-Mississippian Bakken Formation as well as the underlying Devonian Three Forks Formation, Williston Basin of North Dakota, were undertaken to both evaluate the relationships of these rock properties within a stratigraphic and paleontological framework and to assess their utility in correlating intervals within these formations across a broad areal extent. Hand-held X-ray fluorescence (XRF) data and rock hardness analyses were acquired on the same intervals at a high density (generally every 3”) throughout the entire Bakken and into the Three Forks in two widely spaced wells (~30 miles apart) and these data were augmented with XRF data from a third well (~40 mi away). Chemofacies established from the XRF data were primarily defined using calcium, silicon and aluminum and secondarily by other major elements as well as the trace metals iron and molybdenum. A strong, negative relationship exists between rock hardness results and intervals enriched in aluminum and potassium (associated with clay minerals), resulting in particular hardness zones and chemofacies co-occurring at the same stratigraphic intervals. These intervals also appear to co-occur with distinct lithofacies and biofacies that facilitate the subdivision of the Bakken Formation and the upper Three Forks into at least 9 zones that can be correlated across this transect in the Williston Basin. Of the 9 zones, a total of 7 are apparent in the Bakken, with 2 each in the upper and lower shale members, and 3 in the middle member. The remaining 2 zones were identified in the upper part of the Three Forks. Some facies show minor or significant lateral variations in chemical, faunal, hardness, or sedimentological character whereas others appear continuous across the studied transect. The 9 stratigraphic intervals can be confidently distinguished in the Bakken and the Three Forks by combining different facies/chemofacies characteristics. Because many of these facies also have identifiable well log signatures, the integration of facies evaluations from Bakken/Three Forks cores with XRF and rock hardness data may improve interpretations of log data from locations where core is not readily available, especially as it pertains to predicting rock properties. Panel_14964 Panel_14964 4:25 PM 4:45 PM

Unconventional resource production from non-reservoir formations, with very low permeability-to-viscosity ratio that require permeability-creating mechanisms (Cander, 2012), such as fracking need special attention to not only understand and predict the fluid composition of the hydrocarbons to extract but also track phase behavior at changing formation pressures. Bubble point and dew point computation become critical to predicting phase evolution with pressure drop inherent to hydrocarbon production. In this study, we calculate thermal maturity and pressure to predict gas-to-oil-ratio (GOR) distribution over the Tuscaloosa Marine Shale in Louisiana, Mississippi and East Texas, first as a function of thermal maturity, then as a function of organofacies variations. Saturation pressure is calculated using a basin-scale compositional fluid flow model and head room is deduced. Unconventional resource production from non-reservoir formations, with very low permeability-to-viscosity ratio that require permeability-creating mechanisms (Cander, 2012), such as fracking need special attention to not only understand and predict the fluid composition of the hydrocarbons to extract but also track phase behavior at changing formation pressures. Bubble point and dew point computation become critical to predicting phase evolution with pressure drop inherent to hydrocarbon production. In this study, we calculate thermal maturity and pressure to predict gas-to-oil-ratio (GOR) distribution over the Tuscaloosa Marine Shale in Louisiana, Mississippi and East Texas, first as a function of thermal maturity, then as a function of organofacies variations. Saturation pressure is calculated using a basin-scale compositional fluid flow model and head room is deduced. Panel_14963 Panel_14963 4:45 PM 5:05 PM

Panel_14436 Panel_14436 1:15 PM 5:05 PM

Panel_15744 Panel_15744 1:15 PM 12:00 AM

A preliminary evaluation of un-decompacted, time-averaged rates of accumulation can be facilitated by the application of a biostratigraphically calibrated, 3rd-order sequence stratigraphic model to Palaeozoic successions. This comparison was made globally, across a wide range of sedimentary environments and tectonic settings, and resulted in the creation of a unique database that provides the ability to compare sediment accommodation and characterise both the typical rates of accumulation and the generalised lithological composition. The initial results illuminate major temporal changes in the global creation of accommodation and sediment composition throughout the Palaeozoic. For example, a globally pronounced thinning of systems tracts occurs over the Late Cambrian to Early Ordovician that is coupled with a decline in the proportion of carbonate deposition. The application of this, and similar knowledge, can be used in frontier basins to provide insight into the modelling of basin architecture. At the outset, it must be recognised that the absolute generation of accommodation in any one location is affected by the amount of eustatic change. However, at a global scale it is suggested that these systematic trends in the averaged amount of accommodation must be influenced by additional longer term processes at the scale of several millions of years. Due to the biostratigraphically calibrated nature of the sequence stratigraphic model, the database provides an interpretation of a minimum estimate for the range in magnitudes of sedimentation rates throughout the Palaeozoic. These interpretations are preliminary and are based on an interpretation of un-decompacted data. However, it is suggested that the interpreted range in magnitudes is well within that predicted for rock units deposited within a timeframe of 105-106 Ma. However, what is also evident from these data, is that the shorter-duration systems tracts (<2Ma) are deposited at higher, and more variable, sedimentation rates when compared to their longer duration counter parts (>2Ma). These observations are tentatively interpreted to support the notion that globally averaged systems-tract thicknesses are not sediment-limited and that system tracts can accumulate rapidly until they reach the state of balance. This also supports the commonly held view that the stratigraphic record is dominated more by gaps that by rock. A preliminary evaluation of un-decompacted, time-averaged rates of accumulation can be facilitated by the application of a biostratigraphically calibrated, 3rd-order sequence stratigraphic model to Palaeozoic successions. This comparison was made globally, across a wide range of sedimentary environments and tectonic settings, and resulted in the creation of a unique database that provides the ability to compare sediment accommodation and characterise both the typical rates of accumulation and the generalised lithological composition. The initial results illuminate major temporal changes in the global creation of accommodation and sediment composition throughout the Palaeozoic. For example, a globally pronounced thinning of systems tracts occurs over the Late Cambrian to Early Ordovician that is coupled with a decline in the proportion of carbonate deposition. The application of this, and similar knowledge, can be used in frontier basins to provide insight into the modelling of basin architecture. At the outset, it must be recognised that the absolute generation of accommodation in any one location is affected by the amount of eustatic change. However, at a global scale it is suggested that these systematic trends in the averaged amount of accommodation must be influenced by additional longer term processes at the scale of several millions of years. Due to the biostratigraphically calibrated nature of the sequence stratigraphic model, the database provides an interpretation of a minimum estimate for the range in magnitudes of sedimentation rates throughout the Palaeozoic. These interpretations are preliminary and are based on an interpretation of un-decompacted data. However, it is suggested that the interpreted range in magnitudes is well within that predicted for rock units deposited within a timeframe of 105-106 Ma. However, what is also evident from these data, is that the shorter-duration systems tracts (<2Ma) are deposited at higher, and more variable, sedimentation rates when compared to their longer duration counter parts (>2Ma). These observations are tentatively interpreted to support the notion that globally averaged systems-tract thicknesses are not sediment-limited and that system tracts can accumulate rapidly until they reach the state of balance. This also supports the commonly held view that the stratigraphic record is dominated more by gaps that by rock. Panel_15018 Panel_15018 1:20 PM 1:40 PM

Tazhong 4 oilfield is located on the eastside of central fault horst belt, Tazhong low uplift in Tarim basin, with a petroliferous area of 50 km2. The multistage tectonic movements, multi-type sedimentary system and diverse diagenesis in Tazhong area results in multistage accumulation, several reservoir-caprock assemblages, multiple traps and reservoirs in Carboniferous. There are heavy oil reservoirs in CIII Donghe sandstone, conventional crude with condensate gas cap in CIII pebbled sandstone, condensate gas in CII bioclast limestone and conventional crude in CI clasolite. This article explains the complex genesis of Tazhong 4 Carboniferous reservoirs with meshwork-carpet hydrocarbon accumulation theory. A complete meshwork-carpet hydrocarbon accumulation system consists of four parts. (1) Source channel meshwork, which is fault, unconformity or volcanic rock intrusion connecting source rock and storage layer, severs as vertical migration channel; (2) Middle storage layer, which is unconformity complex or continuous sand body beyond charging threshold, contains hydrocarbon to migrate horizontally and aggregate in suitable traps; (3) hydrocarbon adjustment meshwork, which is fault or unconformity connecting two storage layers, can adjust reservoir vertically to upper traps; (4) upper storage layer is merely different from middle storage layer in relative position. The combination of meshwork-carpet system can be classified into “Y-shape”, “T-shape” and “S-shape”. Processing the seismic data with methods of stratum reposition, coherent body, attribute pickup and plane-profile interaction, we clarified the tectonic history of Tazhong 4 area and concluded the accumulation history as: early charge of CIII happened in the late Hercynian though the thrust fault and the unconformity between Donghe sandstone and peddled sandstone; in early Himalayan oil in CIII adjusted to CI by faults, due to inferior reservoir properties, CII was not charged by then ; in the late Himalayan cracking gas filled CIII and episodically broke through fault closure pressure and migrated form CIII to CII, forming the current reservoirs distribution pattern of“deep gas and shallow oil” in Carboniferous. According to the analysis, the integrity of meshwork-carpet system is the key influence of allothigenous source reservoir accumulation. Tazhong 4 oilfield is located on the eastside of central fault horst belt, Tazhong low uplift in Tarim basin, with a petroliferous area of 50 km². The multistage tectonic movements, multi-type sedimentary system and diverse diagenesis in Tazhong area results in multistage accumulation, several reservoir-caprock assemblages, multiple traps and reservoirs in Carboniferous. There are heavy oil reservoirs in CIII Donghe sandstone, conventional crude with condensate gas cap in CIII pebbled sandstone, condensate gas in CII bioclast limestone and conventional crude in CI clasolite. This article explains the complex genesis of Tazhong 4 Carboniferous reservoirs with meshwork-carpet hydrocarbon accumulation theory. A complete meshwork-carpet hydrocarbon accumulation system consists of four parts. (1) Source channel meshwork, which is fault, unconformity or volcanic rock intrusion connecting source rock and storage layer, severs as vertical migration channel; (2) Middle storage layer, which is unconformity complex or continuous sand body beyond charging threshold, contains hydrocarbon to migrate horizontally and aggregate in suitable traps; (3) hydrocarbon adjustment meshwork, which is fault or unconformity connecting two storage layers, can adjust reservoir vertically to upper traps; (4) upper storage layer is merely different from middle storage layer in relative position. The combination of meshwork-carpet system can be classified into “Y-shape”, “T-shape” and “S-shape”. Processing the seismic data with methods of stratum reposition, coherent body, attribute pickup and plane-profile interaction, we clarified the tectonic history of Tazhong 4 area and concluded the accumulation history as: early charge of CIII happened in the late Hercynian though the thrust fault and the unconformity between Donghe sandstone and peddled sandstone; in early Himalayan oil in CIII adjusted to CI by faults, due to inferior reservoir properties, CII was not charged by then ; in the late Himalayan cracking gas filled CIII and episodically broke through fault closure pressure and migrated form CIII to CII, forming the current reservoirs distribution pattern of“deep gas and shallow oil” in Carboniferous. According to the analysis, the integrity of meshwork-carpet system is the key influence of allothigenous source reservoir accumulation. Panel_15031 Panel_15031 1:40 PM 2:00 PM

Analogue models are a critical tool for screening unconventional exploration plays. Being able to identify the Lower 48 Eagle Ford as a strong analogy for the Vaca Muerta shale in Argentina was one of the reasons the Argentine tight oil play has realised significant exploration investment to date. In general terms though, a lack of physical drilling outside of the US has limited the quantity of primary data collected for onshore shale assets. As a result, explorers, investors, and researchers have had to rely on other methods of play evaluation. Fortunately though, many exploratory shale plays have been logged, measured, and cored historically as operators targeted adjacent conventional zones. This data can be mined relatively well, so it is usually possible to get a good starting point. In order to advance improve the analysis of prospective assets, Wood Mackenzie has constructed an analogue model with desktop data. The model pairs non-producing targets with the world’s most productive, well-understood shale plays. Similar work to this has clearly been performed already, but much of it relies on subjective comparisons of less than 10 variables. Our model is quantitative, thorough, and unbiased. We use a proprietary database of over 1,700 data points and 74 variables to compute an analogue index (AI) for each play and then present multiple “ match” plays for each unknown “target” play we have studied. Examples of variables included in Wood Mackenzie’s model that are not always used in other screening tools include basin configuration, facies classification, and the quality of natural fracture barriers. Outcomes from the model challenge some of the generally accepted analogues to date, giving a fresh perspective on some exploration plays. For example, the La Luna Shale in Colombia has been likened to the Eagle Ford and Bakken, but we believe La Luna wells could actually perform more like completions in the oil window of the Utica. This has large implications for explorers in many plays; the Middle Magdalena Valley Basin is just one example. Analogue models are a critical tool for screening unconventional exploration plays. Being able to identify the Lower 48 Eagle Ford as a strong analogy for the Vaca Muerta shale in Argentina was one of the reasons the Argentine tight oil play has realised significant exploration investment to date. In general terms though, a lack of physical drilling outside of the US has limited the quantity of primary data collected for onshore shale assets. As a result, explorers, investors, and researchers have had to rely on other methods of play evaluation. Fortunately though, many exploratory shale plays have been logged, measured, and cored historically as operators targeted adjacent conventional zones. This data can be mined relatively well, so it is usually possible to get a good starting point. In order to advance improve the analysis of prospective assets, Wood Mackenzie has constructed an analogue model with desktop data. The model pairs non-producing targets with the world’s most productive, well-understood shale plays. Similar work to this has clearly been performed already, but much of it relies on subjective comparisons of less than 10 variables. Our model is quantitative, thorough, and unbiased. We use a proprietary database of over 1,700 data points and 74 variables to compute an analogue index (AI) for each play and then present multiple “ match” plays for each unknown “target” play we have studied. Examples of variables included in Wood Mackenzie’s model that are not always used in other screening tools include basin configuration, facies classification, and the quality of natural fracture barriers. Outcomes from the model challenge some of the generally accepted analogues to date, giving a fresh perspective on some exploration plays. For example, the La Luna Shale in Colombia has been likened to the Eagle Ford and Bakken, but we believe La Luna wells could actually perform more like completions in the oil window of the Utica. This has large implications for explorers in many plays; the Middle Magdalena Valley Basin is just one example. Panel_15019 Panel_15019 2:00 PM 2:20 PM

We have updated our compilation of giant oil and gas fields of the world for the period of 2000 to 2014 using over 1400 articles and reports. During this decade and half of observation, 185 new giants bring the total number of the world’s giants discovered from 1868 to 2014 to 1063. Of these 187 newly discovered giants, 90 are oil giants and 85 are gas giants and 12 combination oil and gas giants. 137 were discovered offshore while 48 were discovered onshore. Of the 137 offshore giants, 67 are gas, 60 are oil and 10 are a combination of both oil and gas. Of the 48 onland giants, 22 are gas, 24 are oil and 2 are combinations. The tectonic settings of the newly discovered giants closely follow a pattern we described in 2003 for pre-2000 giant discoveries. The majority of the 2000-2014 discoveries are found along continental passive margins fronting major ocean basins (18 in West Africa, 13 in the Gulf of Mexico, 13 in East Africa, 8 in the Persian Gulf, 7 in the Mediterranean Sea, 20 in Brazil, and 9 in Sunda). Far fewer giants were found on continental and arc collision margins (14 in the Persian Gulf, 6 in the Caspian Sea and 4 in China), and rift and inverted rift settings (11 in the Caspian Sea, 9 in Siberia, 8 in the Barents Sea and 6 in North Africa). We predict that the decade 2010-2019 is on track to be the fourth highest giant discovery decade since 1868 with 117 new giants added. Emerging giant clusters - defined as areas with new giant discoveries in areas that previously lacked giants - include the passive margins of East Africa and the eastern Mediterranean Sea. We have updated our compilation of giant oil and gas fields of the world for the period of 2000 to 2014 using over 1400 articles and reports. During this decade and half of observation, 185 new giants bring the total number of the world’s giants discovered from 1868 to 2014 to 1063. Of these 187 newly discovered giants, 90 are oil giants and 85 are gas giants and 12 combination oil and gas giants. 137 were discovered offshore while 48 were discovered onshore. Of the 137 offshore giants, 67 are gas, 60 are oil and 10 are a combination of both oil and gas. Of the 48 onland giants, 22 are gas, 24 are oil and 2 are combinations. The tectonic settings of the newly discovered giants closely follow a pattern we described in 2003 for pre-2000 giant discoveries. The majority of the 2000-2014 discoveries are found along continental passive margins fronting major ocean basins (18 in West Africa, 13 in the Gulf of Mexico, 13 in East Africa, 8 in the Persian Gulf, 7 in the Mediterranean Sea, 20 in Brazil, and 9 in Sunda). Far fewer giants were found on continental and arc collision margins (14 in the Persian Gulf, 6 in the Caspian Sea and 4 in China), and rift and inverted rift settings (11 in the Caspian Sea, 9 in Siberia, 8 in the Barents Sea and 6 in North Africa). We predict that the decade 2010-2019 is on track to be the fourth highest giant discovery decade since 1868 with 117 new giants added. Emerging giant clusters - defined as areas with new giant discoveries in areas that previously lacked giants - include the passive margins of East Africa and the eastern Mediterranean Sea. Panel_15014 Panel_15014 2:20 PM 2:40 PM

Panel_15745 Panel_15745 3:00 PM 12:00 AM

The offshore areas of Tanzania and Mozambique have proven a rich exploration province over the last 5 year with over 130 tcf of gas discovered to date, as well as an emerging liquids potential. However, fundamental questions remain regarding the structural history and the impact that has on reservoir distribution and source maturation. Integrated interpretation of regional, deep seismic data from Kenya in the north to Madagascar in the south, including the most recent data in the Comoros Islands area, has allowed for the development of a regional play based framework to address these questions. Basement architecture and tectonic history began with the development of the Karoo basin system and was followed by continental extension and break-up in the Jurassic. Multiple re-configurations of the Indian Ocean plates continued throughout the Cretaceous including the development of the Davies Fracture Zone. Development of the Ruvuma and Rufiji Delta systems in the Cenozoic was driven and enhanced by uplift of the African Craton. These delta systems distributed sediment thicknesses of over 4km far out into the deepwater Somali Basin; clear evidence shows robust modern channels carrying terrestrial plant material as far as 500km offshore. The interplay of sediment supply and structural development of the delta systems including gravity driven deformation and the development of the Kerimbas Graben system will be discussed. More recent emplacement of the Comoros Volcanic province in the Late Tertiary has redistributed recent sediments and deformed existing sediments with the potential for formation of trapping mechanisms and enhanced heat-flows. The new seismic data in this area demonstrates the potential extensions of the proven deep water plays in Tanzania and Mozambique further out in the basin. The offshore areas of Tanzania and Mozambique have proven a rich exploration province over the last 5 year with over 130 tcf of gas discovered to date, as well as an emerging liquids potential. However, fundamental questions remain regarding the structural history and the impact that has on reservoir distribution and source maturation. Integrated interpretation of regional, deep seismic data from Kenya in the north to Madagascar in the south, including the most recent data in the Comoros Islands area, has allowed for the development of a regional play based framework to address these questions. Basement architecture and tectonic history began with the development of the Karoo basin system and was followed by continental extension and break-up in the Jurassic. Multiple re-configurations of the Indian Ocean plates continued throughout the Cretaceous including the development of the Davies Fracture Zone. Development of the Ruvuma and Rufiji Delta systems in the Cenozoic was driven and enhanced by uplift of the African Craton. These delta systems distributed sediment thicknesses of over 4km far out into the deepwater Somali Basin; clear evidence shows robust modern channels carrying terrestrial plant material as far as 500km offshore. The interplay of sediment supply and structural development of the delta systems including gravity driven deformation and the development of the Kerimbas Graben system will be discussed. More recent emplacement of the Comoros Volcanic province in the Late Tertiary has redistributed recent sediments and deformed existing sediments with the potential for formation of trapping mechanisms and enhanced heat-flows. The new seismic data in this area demonstrates the potential extensions of the proven deep water plays in Tanzania and Mozambique further out in the basin. Panel_15020 Panel_15020 3:25 PM 3:45 PM

East African margin evolved from the assembly and fragmentation of Gondwana and thus shares a multi-phase rift-drift history with Madagascar, Seychelles and West Indian margin. Through the construction of 19 paleofacies maps spanning Carboniferous-Pliocene periods and 24 integrated stratigraphic charts for both onshore and offshore East African basins, this study suggests six tectonostratigraphic megasequences with implications for a stack of source rocks and reservoirs in the region: (1) Late Carboniferous-Early Triassic, (2) Late Triassic-Early Jurassic, (3) Middle Jurassic-Cenomonian, (4) Turonian-Maastrichtian, (5) Paleocene-Eocene, and (6) Late Oligocene-Miocene megasequences. In this interpretation, the so-called “Karoo Group” is divided into two distinct groups: Karoo-1 corresponds to purely continental gas-prone plays of Late Carboniferous-Early Triassic age well preserved in the interior basins such as Anza and Rufiji, while Karoo-2 represents fluvial-lacustrine sediments related to initial continental rifts between East Gondwana and West Gondwana and thus associated with Karoo volcanics (185-175 Ma). The Jurassic-Recent tectonostratigraphy is marked by a succession of rift events: (1) opening of the Somali oceanic basin and Mozambique Channel (165-100 Ma) resulting in the separation of Madagascar from East African margin; (2) opening of the Mascarene oceanic basin (90-60 Ma) beginning with separation of Seychelles-India from Madagascar; (3) opening of the SW Indian ocean (70 Ma to present) associated with separation of Seychelles from West India; and (4) the Afar triangle at the junction of Red Sea, Gulf of Aden, Kenya-Mozambique rift systems (Oligocene-Recent). Although recent discoveries of East African deepwater basins have been major gas fields, regional geological analysis is suggestive of oil plays as well. East African margin evolved from the assembly and fragmentation of Gondwana and thus shares a multi-phase rift-drift history with Madagascar, Seychelles and West Indian margin. Through the construction of 19 paleofacies maps spanning Carboniferous-Pliocene periods and 24 integrated stratigraphic charts for both onshore and offshore East African basins, this study suggests six tectonostratigraphic megasequences with implications for a stack of source rocks and reservoirs in the region: (1) Late Carboniferous-Early Triassic, (2) Late Triassic-Early Jurassic, (3) Middle Jurassic-Cenomonian, (4) Turonian-Maastrichtian, (5) Paleocene-Eocene, and (6) Late Oligocene-Miocene megasequences. In this interpretation, the so-called “Karoo Group” is divided into two distinct groups: Karoo-1 corresponds to purely continental gas-prone plays of Late Carboniferous-Early Triassic age well preserved in the interior basins such as Anza and Rufiji, while Karoo-2 represents fluvial-lacustrine sediments related to initial continental rifts between East Gondwana and West Gondwana and thus associated with Karoo volcanics (185-175 Ma). The Jurassic-Recent tectonostratigraphy is marked by a succession of rift events: (1) opening of the Somali oceanic basin and Mozambique Channel (165-100 Ma) resulting in the separation of Madagascar from East African margin; (2) opening of the Mascarene oceanic basin (90-60 Ma) beginning with separation of Seychelles-India from Madagascar; (3) opening of the SW Indian ocean (70 Ma to present) associated with separation of Seychelles from West India; and (4) the Afar triangle at the junction of Red Sea, Gulf of Aden, Kenya-Mozambique rift systems (Oligocene-Recent). Although recent discoveries of East African deepwater basins have been major gas fields, regional geological analysis is suggestive of oil plays as well. Panel_15013 Panel_15013 3:45 PM 4:05 PM

With the rapid changing environments associated with leasing new viable oil and gas plays in a mature region, attention has turned to the statistical analysis of all of the available data (i.e. big data). This has occurred on a basin-wide scale down to the individual play. For the most-part, the tools used are statistical, geostatistical and multivariate based. Oftentimes, the user is either given a toolset in a larger program or works with one of the many fine programs available on the market. Even with a deep understanding of the myriad of assumptions associated with of these approaches, it is difficult to extract all but the most observable results from the various types of geologic data and even more thorny to quantify the economic confidence of any result. A common workflow is to gather in the best data available (geologic, geophysical, geochemical, log-based and so forth), create multiple layers/surfaces of geo-located information and then perform some appropriate multivariate analysis. A great many of the assumptions associated with the common multivariate techniques are based on the necessity of the data being derived from either one or a fixed number of known populations. With big data, verifying these assumptions are often overlooked with statistically ambiguous or difficult to validate results being common. An extra step in the workflow needs to be added in these cases - partitioning the data in an appropriate way and then analyzing each partition separately. Recognizing when this partitioning is needed via visual, statistical, geostatistical and deterministic techniques was a large part of the study described below. The 'big data' consisting of well-based and geophysical data (gravity and magnetic) in several counties in Northwest Kansas. In this area, the early Paleozoic rocks appear to be dominated by basement tectonics at the time of deposition whereas the later Paleozoic formations appear to simply overlie these rocks. After recognizing the visual hints that data partition was appropriate, computer programs designed for data partitioning (Polytopic Vector Analysis-based programs, Fuzzy Clustering including Fuzzy N-Varieties) were applied. The results showed that partitioning the data focused the results such that a more refined probability of success could be defined by the multivariate analysis. This same workflow can be applied to the analysis of basins as well. With the rapid changing environments associated with leasing new viable oil and gas plays in a mature region, attention has turned to the statistical analysis of all of the available data (i.e. big data). This has occurred on a basin-wide scale down to the individual play. For the most-part, the tools used are statistical, geostatistical and multivariate based. Oftentimes, the user is either given a toolset in a larger program or works with one of the many fine programs available on the market. Even with a deep understanding of the myriad of assumptions associated with of these approaches, it is difficult to extract all but the most observable results from the various types of geologic data and even more thorny to quantify the economic confidence of any result. A common workflow is to gather in the best data available (geologic, geophysical, geochemical, log-based and so forth), create multiple layers/surfaces of geo-located information and then perform some appropriate multivariate analysis. A great many of the assumptions associated with the common multivariate techniques are based on the necessity of the data being derived from either one or a fixed number of known populations. With big data, verifying these assumptions are often overlooked with statistically ambiguous or difficult to validate results being common. An extra step in the workflow needs to be added in these cases - partitioning the data in an appropriate way and then analyzing each partition separately. Recognizing when this partitioning is needed via visual, statistical, geostatistical and deterministic techniques was a large part of the study described below. The 'big data' consisting of well-based and geophysical data (gravity and magnetic) in several counties in Northwest Kansas. In this area, the early Paleozoic rocks appear to be dominated by basement tectonics at the time of deposition whereas the later Paleozoic formations appear to simply overlie these rocks. After recognizing the visual hints that data partition was appropriate, computer programs designed for data partitioning (Polytopic Vector Analysis-based programs, Fuzzy Clustering including Fuzzy N-Varieties) were applied. The results showed that partitioning the data focused the results such that a more refined probability of success could be defined by the multivariate analysis. This same workflow can be applied to the analysis of basins as well. Panel_15016 Panel_15016 4:05 PM 4:25 PM

Since its inception data has been the basis of the petroleum industry. Oil and gas exploration and development has always been about knowing where to look and where exactly to drill. Oil and gas geosciences have been pursing big data before “big data” was big. In the first decade of the 21st century, “big data” burst upon the scene, while horizontal drilling and fracture stimulation have been around for decades. What has created successful exploration and development of unconventional resources is smart exploration, drilling and completion. Integrated geologic and geophysical analysis provides the map that lets one know where to drill, while down-hole real-time sensors tell one where to steer the well within the correct zone. The latest technologies of micro-seismic and fiber-optics tell one where and how to complete. The bottom line is that a drilling rig has become a mass of sensors and computers with a drill bit attached to one end. Increased usage in subsurface geology of data from sensors and operational data gathering devices has significantly increased the amount of unstructured data. Oil and gas has long handled massive volumes of structured data such as 3D seismic, what is the new challenge is development of tools to handle new types of unstructured data or to integrate diverse structured and unstructured data sets from diverse geologic disciplines. Exploration and development of unconventional resources requires integration of “big data” within traditional models and approaches to geologic analysis. We provide several examples from the Marcellus and Utica mudrock plays of the northern Appalachian basin to illustrate low-cost technologies to store, query, and analyze large and diverse data sources and new data types much of which is found outside of the company’s firewall. Integration involving more diverse unstructured, semi-structured and structured data can lead to a better understanding of unconventional resource plays and provide predictive exploration and development models for unconventional resources that often span multiple countries, states and hundreds of kilometers. Since its inception data has been the basis of the petroleum industry. Oil and gas exploration and development has always been about knowing where to look and where exactly to drill. Oil and gas geosciences have been pursing big data before “big data” was big. In the first decade of the 21st century, “big data” burst upon the scene, while horizontal drilling and fracture stimulation have been around for decades. What has created successful exploration and development of unconventional resources is smart exploration, drilling and completion. Integrated geologic and geophysical analysis provides the map that lets one know where to drill, while down-hole real-time sensors tell one where to steer the well within the correct zone. The latest technologies of micro-seismic and fiber-optics tell one where and how to complete. The bottom line is that a drilling rig has become a mass of sensors and computers with a drill bit attached to one end. Increased usage in subsurface geology of data from sensors and operational data gathering devices has significantly increased the amount of unstructured data. Oil and gas has long handled massive volumes of structured data such as 3D seismic, what is the new challenge is development of tools to handle new types of unstructured data or to integrate diverse structured and unstructured data sets from diverse geologic disciplines. Exploration and development of unconventional resources requires integration of “big data” within traditional models and approaches to geologic analysis. We provide several examples from the Marcellus and Utica mudrock plays of the northern Appalachian basin to illustrate low-cost technologies to store, query, and analyze large and diverse data sources and new data types much of which is found outside of the company’s firewall. Integration involving more diverse unstructured, semi-structured and structured data can lead to a better understanding of unconventional resource plays and provide predictive exploration and development models for unconventional resources that often span multiple countries, states and hundreds of kilometers. Panel_15015 Panel_15015 4:25 PM 4:45 PM

The Tarim Basin is a significant petroliferous basin in the west of China. The Lower Cretaceous Bashijiqike Formation, whose buried depth exceeds 6000m and has a low matrix porosity(<10%) and permeability(<0.1mD), is the main gas producing interval in Kuqa depression of Tarim Basin. Structural fractures can improve reservoir permeability effectively. CT scanning results and pressure experiments indicate that although the fractures in tight sandstone can only cause low porosity (<0.5%), however they can improve permeability largely (to 10~100 times). Meantime microfractures can improve pore throat configuration. Microscope and SEM evidences indicate that connectivity of uncharged microfractures is proportional to fracture aperture. And microfractures can connect pore throats which are located 20~100 times around fracture aperture. In the study area, there are 3 stages of fractures which are controlled by palaeostress field and rock fabric. And the third stage fractures play an important role in improving tight sandstone permeability. Isotopic dating of fracture fillers and burial history analysis indicate that some fractures developed before gas emplacement, but most of fractures probably developed in the same time with peak gas generation and charge, which suggests that gas probably migrated along fractures and accumulated in the sandstone reservoirs. Build-up of pressure data during producing test indicates that high fracture permeability areas are located in anticline crest, fault transition zone and around secondary faults. The Tarim Basin is a significant petroliferous basin in the west of China. The Lower Cretaceous Bashijiqike Formation, whose buried depth exceeds 6000m and has a low matrix porosity(<10%) and permeability(<0.1mD), is the main gas producing interval in Kuqa depression of Tarim Basin. Structural fractures can improve reservoir permeability effectively. CT scanning results and pressure experiments indicate that although the fractures in tight sandstone can only cause low porosity (<0.5%), however they can improve permeability largely (to 10~100 times). Meantime microfractures can improve pore throat configuration. Microscope and SEM evidences indicate that connectivity of uncharged microfractures is proportional to fracture aperture. And microfractures can connect pore throats which are located 20~100 times around fracture aperture. In the study area, there are 3 stages of fractures which are controlled by palaeostress field and rock fabric. And the third stage fractures play an important role in improving tight sandstone permeability. Isotopic dating of fracture fillers and burial history analysis indicate that some fractures developed before gas emplacement, but most of fractures probably developed in the same time with peak gas generation and charge, which suggests that gas probably migrated along fractures and accumulated in the sandstone reservoirs. Build-up of pressure data during producing test indicates that high fracture permeability areas are located in anticline crest, fault transition zone and around secondary faults. Panel_15021 Panel_15021 4:45 PM 5:05 PM

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At the mouths of rivers, and for a considerable distance inland in low-gradient settings, fluvial and tidal processes interact to create a unique suite of deposits. Most rivers display variations in discharge, and their hydrographs can be divided simplistically into two parts: the river flood when most of the sediment discharge occurs, and the longer-duration interflood period when sediment discharge is small. Tidal currents, by contrast, act throughout the year, although their strength varies on various time scales (e.g., neap-spring cycles). Most importantly, the increase in the strength of fluvial currents during river floods decreases the tidal influence by pushing the limit of tidal intrusion (and also salt-water intrusion) seaward. In the more proximal parts of the fluvial-marine transition, depositional conditions alternate between being river-dominated during river floods and tide-dominated during interflood/low-flow periods. This is commonly reflected in an alternation between coarser sandy deposits with a unidirectional seaward paleocurrent and minimal bioturbation (river-flood deposits), and finer-grained, commonly muddy, deposits in which tidal lamination and higher levels of bioturbation are present (interflood deposits). These deposits are indicative of a fluvially dominated, tidally influenced environment. In more distal areas where tidal currents are stronger, tidal lamination and/or reversed paleocurrents begin to occur in the waning-flow portion of the flood deposits, until eventually the tidal currents become strong enough to overprint the entire river-flood bed. In such settings, river-flood deposits can be cryptic, but can be marked by the coarsest sand and thickest fluid-mud beds. Bioturbation is typically more intense, but restricted, in the interflood deposits. This pattern indicates a tidally dominated, fluvially influenced environment. Considerable local variability is expected, but general trends in the character of river-flood and interflood beds are a powerful tool for determining location in the fluvial-marine transition and the nature of coastal environments at a larger scale. At the mouths of rivers, and for a considerable distance inland in low-gradient settings, fluvial and tidal processes interact to create a unique suite of deposits. Most rivers display variations in discharge, and their hydrographs can be divided simplistically into two parts: the river flood when most of the sediment discharge occurs, and the longer-duration interflood period when sediment discharge is small. Tidal currents, by contrast, act throughout the year, although their strength varies on various time scales (e.g., neap-spring cycles). Most importantly, the increase in the strength of fluvial currents during river floods decreases the tidal influence by pushing the limit of tidal intrusion (and also salt-water intrusion) seaward. In the more proximal parts of the fluvial-marine transition, depositional conditions alternate between being river-dominated during river floods and tide-dominated during interflood/low-flow periods. This is commonly reflected in an alternation between coarser sandy deposits with a unidirectional seaward paleocurrent and minimal bioturbation (river-flood deposits), and finer-grained, commonly muddy, deposits in which tidal lamination and higher levels of bioturbation are present (interflood deposits). These deposits are indicative of a fluvially dominated, tidally influenced environment. In more distal areas where tidal currents are stronger, tidal lamination and/or reversed paleocurrents begin to occur in the waning-flow portion of the flood deposits, until eventually the tidal currents become strong enough to overprint the entire river-flood bed. In such settings, river-flood deposits can be cryptic, but can be marked by the coarsest sand and thickest fluid-mud beds. Bioturbation is typically more intense, but restricted, in the interflood deposits. This pattern indicates a tidally dominated, fluvially influenced environment. Considerable local variability is expected, but general trends in the character of river-flood and interflood beds are a powerful tool for determining location in the fluvial-marine transition and the nature of coastal environments at a larger scale. Panel_15180 Panel_15180 1:20 PM 1:40 PM

The Upper Permian Rangal Coal Measures and equivalents formed during a phase of declining continental arc volcanism and active thrust loading in the complex retroarc foreland Bowen Basin of eastern Queensland, Australia. The unit, around 100 m thick in total, comprises sandstone bodies, thick heterolithic sandstone-siltstone intervals with Inclined Heterolithic Stratification (IHS), mudrocks with thin-bedded sandstones, and coal bodies up to 8 m thick. A number of large, opencut mines have provided extensive though temporary exposures of the Rangal Coal Measures, allowing an evaluation of their sedimentology and stratigraphy. In an earlier study, Fielding (1993, Sedimentary Geology, 85, 475-497) carried out a facies analysis and concluded that the depositional environment was an extensive, low-lying alluvial plain crossed by rivers that alternated between two distinct fluvial styles; 1. Moderately sinuous (< 1.5) streams that formed highly complex, heterolithic channel fills, and 2. More mobile, perhaps braided rivers that formed sheet-like sandstone bodies. In this study, a re-evaluation of the dataset is presented, and the conclusion is drawn that significant portions of the Rangal Coal Measures were likely formed in tidally-influenced rivers (estuaries) that drained the north-south Bowen Basin axially during the latest Permian. The principal lines of evidence in support of this reinterpretation are 1. abundance and diversity of IHS-filled channel forms, and abrupt lateral facies variations that indicate significant areal partitioning of sand in the formative rivers, 2. presence of abundant small-scale sedimentary structures commonly associated with tidal activity (flaser bedding, mud drapes, etc.), 3. presence of a low-diversity, sporadically distributed trace fossil suite, 4. presence of fish fossils of types that have been previously regarded as marine, and 5. bimodal to bipolar palaeocurrent distributions. Given this reinterpretation, the Rangal Coal Measures can serve as a well-exposed analogue for the internal stratal architecture and reservoir heterogeneity that is known to characterize the Cretaceous McMurray formation in the Athabasca oil sands province. The Upper Permian Rangal Coal Measures and equivalents formed during a phase of declining continental arc volcanism and active thrust loading in the complex retroarc foreland Bowen Basin of eastern Queensland, Australia. The unit, around 100 m thick in total, comprises sandstone bodies, thick heterolithic sandstone-siltstone intervals with Inclined Heterolithic Stratification (IHS), mudrocks with thin-bedded sandstones, and coal bodies up to 8 m thick. A number of large, opencut mines have provided extensive though temporary exposures of the Rangal Coal Measures, allowing an evaluation of their sedimentology and stratigraphy. In an earlier study, Fielding (1993, Sedimentary Geology, 85, 475-497) carried out a facies analysis and concluded that the depositional environment was an extensive, low-lying alluvial plain crossed by rivers that alternated between two distinct fluvial styles; 1. Moderately sinuous (< 1.5) streams that formed highly complex, heterolithic channel fills, and 2. More mobile, perhaps braided rivers that formed sheet-like sandstone bodies. In this study, a re-evaluation of the dataset is presented, and the conclusion is drawn that significant portions of the Rangal Coal Measures were likely formed in tidally-influenced rivers (estuaries) that drained the north-south Bowen Basin axially during the latest Permian. The principal lines of evidence in support of this reinterpretation are 1. abundance and diversity of IHS-filled channel forms, and abrupt lateral facies variations that indicate significant areal partitioning of sand in the formative rivers, 2. presence of abundant small-scale sedimentary structures commonly associated with tidal activity (flaser bedding, mud drapes, etc.), 3. presence of a low-diversity, sporadically distributed trace fossil suite, 4. presence of fish fossils of types that have been previously regarded as marine, and 5. bimodal to bipolar palaeocurrent distributions. Given this reinterpretation, the Rangal Coal Measures can serve as a well-exposed analogue for the internal stratal architecture and reservoir heterogeneity that is known to characterize the Cretaceous McMurray formation in the Athabasca oil sands province. Panel_15185 Panel_15185 1:40 PM 2:00 PM

Tidal successions are comprised of a complex mixture of fluvial, tidal, and marine lithofacies. Subtle changes in the transition from tidal to fluvial deposits make lithofacies differentiation from subsurface wireline log and seismic reflection data problematic. Because tide-dominated and tidally-influenced reservoirs account for a significant portion of petroleum reserves, forward seismic reflection modeling coupled with a predictive facies model framework derived from rock physics measurements on cores and outcrops can lead to invaluable insights for interpreting subsurface data. The Cretaceous John Henry Member (Straight Cliffs Formation), located in the Kaiparowits Plateau of southern Utah, reveals excellent outcrops of fluvial and tidally-influenced deposits, and offers an opportunity to improve our understanding of wireline log interpretation and seismic imaging in similar subsurface petroleum reservoirs. The focus of this study is a 240 m core that captures a progradational succession from shoreface through tidally-influenced lagoon to fluvial deposits. The full spectrum of lithofacies stacking patterns present in the core is captured with a Markov Chain analysis. Benchtop measurements were performed on 1 inch core plugs (57 total; 25 from the coastal plain succession and 32 from the tidal succession) to obtain physical rock properties (Vp, Vs, density, permeability and porosity) for each lithofacies. The rock properties show a wide range of values as a direct result of the highly heterolithic nature of these deposits. Although measurements from different lithofacies are overlapping, we observe a slight offset between fluvial and tidal rock properties. To test our ability to observe the tidal to fluvial transition with seismic imaging, average rock properties for each lithofacies were used to generate synthetic seismic reflection models for different expressions of upward-fining packages documented in the core. This investigation elucidates variations in amplitude versus offset responses as a function of variable tidal influence. The number of overlapping values highlights the complications associated with interpreting these deposits in subsurface data. However, the modeling shows promise in differentiating the end member packages, along with a gradational trend for intermediate packages consistent with the sedimentology of transitioning from more marine influence to more terrestrial influence. Tidal successions are comprised of a complex mixture of fluvial, tidal, and marine lithofacies. Subtle changes in the transition from tidal to fluvial deposits make lithofacies differentiation from subsurface wireline log and seismic reflection data problematic. Because tide-dominated and tidally-influenced reservoirs account for a significant portion of petroleum reserves, forward seismic reflection modeling coupled with a predictive facies model framework derived from rock physics measurements on cores and outcrops can lead to invaluable insights for interpreting subsurface data. The Cretaceous John Henry Member (Straight Cliffs Formation), located in the Kaiparowits Plateau of southern Utah, reveals excellent outcrops of fluvial and tidally-influenced deposits, and offers an opportunity to improve our understanding of wireline log interpretation and seismic imaging in similar subsurface petroleum reservoirs. The focus of this study is a 240 m core that captures a progradational succession from shoreface through tidally-influenced lagoon to fluvial deposits. The full spectrum of lithofacies stacking patterns present in the core is captured with a Markov Chain analysis. Benchtop measurements were performed on 1 inch core plugs (57 total; 25 from the coastal plain succession and 32 from the tidal succession) to obtain physical rock properties (Vp, Vs, density, permeability and porosity) for each lithofacies. The rock properties show a wide range of values as a direct result of the highly heterolithic nature of these deposits. Although measurements from different lithofacies are overlapping, we observe a slight offset between fluvial and tidal rock properties. To test our ability to observe the tidal to fluvial transition with seismic imaging, average rock properties for each lithofacies were used to generate synthetic seismic reflection models for different expressions of upward-fining packages documented in the core. This investigation elucidates variations in amplitude versus offset responses as a function of variable tidal influence. The number of overlapping values highlights the complications associated with interpreting these deposits in subsurface data. However, the modeling shows promise in differentiating the end member packages, along with a gradational trend for intermediate packages consistent with the sedimentology of transitioning from more marine influence to more terrestrial influence. Panel_15179 Panel_15179 2:00 PM 2:20 PM

Incised valley fills (IVF) are complex features which complicate the interpretation of stratal successions. The Upper Cretaceous Mt. Garfield Formation, exposed near Grand Junction, Colorado, consists of shallow marine sandstones truncated by numerous sequence boundaries and contains multiple incised valleys. These valley fills are often nested and show significant lateral variability. When nested, facies successions alone are not distinct enough to distinguish individual valleys. Some IVF are dominantly nonmarine/fluvial with numerous coal beds and paleosols. Other IVF have a strong tidal signature: evidence for tidal influence include multiple reactivation surfaces, double mud drapes, flaser/wavy/lenticular bedding, heterolithic bedding and tidal bundles. Field study of IVF at the facies level yields a detailed sequence stratigraphic analysis at the parasequence scale. Parasequences are traced from canyon to canyon to determine lateral and down dip extent of facies. Valley fills which show tidal dominance contain numerous estuarine facies associations: tidally influenced channel-fill sandstones, estuarine deltas, coals/mires, paleosols and migrating tidal bars/burrowed sandstones interpreted as estuarine floor deposits. Individual facies average 5 to 7 meters in thickness. This is interpreted to reflect accommodation steps during sea level rise of 5 to 7 meters. Some facies have limited lateral extent (coals, tidally influenced channel-fill sandstones) and are aerially restricted within individual valley fill, while other facies are correlated over a distance of kilometers (estuarine floor deposits, estuarine deltas) and seen in multiple canyons. The IVF facies can be partitioned into high energy and low energy/protected depositional settings. Estuarine floor deposits contain meter-scale tidal bars which indicate the velocity of the tidal currents within the estuary were significant. Other estuarine facies, such as the estuarine deltas, were deposited in a more protected part of the estuary. Estuarine deltas are upward coarsening successions and rarely show large scale cross stratification. These heterolithic deposits are thinly bedded, contain flaser/wavy/lenticular bedding and have double mud drapes within finer grained interbeds. These deltas are abundant in the IVF but are not a dominant sub-environment in modern estuaries. Other estuarine floor deposits are mud dominated and highly burrowed, and were deposited in a protected setting. Incised valley fills (IVF) are complex features which complicate the interpretation of stratal successions. The Upper Cretaceous Mt. Garfield Formation, exposed near Grand Junction, Colorado, consists of shallow marine sandstones truncated by numerous sequence boundaries and contains multiple incised valleys. These valley fills are often nested and show significant lateral variability. When nested, facies successions alone are not distinct enough to distinguish individual valleys. Some IVF are dominantly nonmarine/fluvial with numerous coal beds and paleosols. Other IVF have a strong tidal signature: evidence for tidal influence include multiple reactivation surfaces, double mud drapes, flaser/wavy/lenticular bedding, heterolithic bedding and tidal bundles. Field study of IVF at the facies level yields a detailed sequence stratigraphic analysis at the parasequence scale. Parasequences are traced from canyon to canyon to determine lateral and down dip extent of facies. Valley fills which show tidal dominance contain numerous estuarine facies associations: tidally influenced channel-fill sandstones, estuarine deltas, coals/mires, paleosols and migrating tidal bars/burrowed sandstones interpreted as estuarine floor deposits. Individual facies average 5 to 7 meters in thickness. This is interpreted to reflect accommodation steps during sea level rise of 5 to 7 meters. Some facies have limited lateral extent (coals, tidally influenced channel-fill sandstones) and are aerially restricted within individual valley fill, while other facies are correlated over a distance of kilometers (estuarine floor deposits, estuarine deltas) and seen in multiple canyons. The IVF facies can be partitioned into high energy and low energy/protected depositional settings. Estuarine floor deposits contain meter-scale tidal bars which indicate the velocity of the tidal currents within the estuary were significant. Other estuarine facies, such as the estuarine deltas, were deposited in a more protected part of the estuary. Estuarine deltas are upward coarsening successions and rarely show large scale cross stratification. These heterolithic deposits are thinly bedded, contain flaser/wavy/lenticular bedding and have double mud drapes within finer grained interbeds. These deltas are abundant in the IVF but are not a dominant sub-environment in modern estuaries. Other estuarine floor deposits are mud dominated and highly burrowed, and were deposited in a protected setting. Panel_15178 Panel_15178 2:20 PM 2:40 PM

Process-based facies models for estuaries and deltas are largely derived from modern analogs, and generally depict end-member energy settings. It is unclear how applicable these models are to interpretations of the rock record, particularly in more complex mixed-energy estuarine, deltaic, and tidal environments. Such ambiguity reflects the difficulty in understanding preservation potential, the close temporal and stratigraphic interplay between end-member systems, and a general knowledge gap for both modern and ancient high-energy, sand-rich tidal settings. Differences in the temporal and physical scales of observation between modern and ancient examples pose a challenge to analog studies and their application to subsurface reservoirs. This research presents a detailed assessment and model for outcrops of a mixed-energy (wave- and tide-dominated) estuary from the Cretaceous Straight Cliffs Formation, southern Utah, with specific modern analog comparisons. Along a 1,200 m-wide, 60 to 120 m-thick section, cm-scale measured sections, petrography, and photos are used to document vertical and lateral facies changes. The estuary consists of three depositional units (DU): (1) a lowermost interval, 20–30 m thick, of tidal bars and marsh deposits composed of carbonaceous shales and coals; (2) a middle interval, 50–80 m thick, with channelized tidally-influenced bayhead delta / tidally-dominated delta deposits; and (3) an uppermost interval, 30–50 m thick, of landward-stepping barrier island strata. A combination of modern analogs show the evolution of the estuary. The system began similar to the North Carolina coast at Cape Hatteras (DU1). As the estuary filled it looked more like Winyah Bay, South Carolina (DU2). The capping barrier island strata could be similar to Big Sarasota Pass, Florida or the East Friesian Islands, Germany (DU3). This study highlights areas for improvement in the modern to ancient to reservoir analog workflow, particularly in mixed-energy systems. For example, we illustrate the difficulties in distinguishing between bayhead and tidal deltas in outcrop, despite the importance of such distinctions for both sequence-stratigraphic and reservoir interpretations. Overall, detailed facies characterization and predictive 3-D geobody analysis does elucidate key recognition criteria for the mixed-energy system, including the preservation of both tide and wave energy indicators, tidal packages, and barrier island facies. Process-based facies models for estuaries and deltas are largely derived from modern analogs, and generally depict end-member energy settings. It is unclear how applicable these models are to interpretations of the rock record, particularly in more complex mixed-energy estuarine, deltaic, and tidal environments. Such ambiguity reflects the difficulty in understanding preservation potential, the close temporal and stratigraphic interplay between end-member systems, and a general knowledge gap for both modern and ancient high-energy, sand-rich tidal settings. Differences in the temporal and physical scales of observation between modern and ancient examples pose a challenge to analog studies and their application to subsurface reservoirs. This research presents a detailed assessment and model for outcrops of a mixed-energy (wave- and tide-dominated) estuary from the Cretaceous Straight Cliffs Formation, southern Utah, with specific modern analog comparisons. Along a 1,200 m-wide, 60 to 120 m-thick section, cm-scale measured sections, petrography, and photos are used to document vertical and lateral facies changes. The estuary consists of three depositional units (DU): (1) a lowermost interval, 20–30 m thick, of tidal bars and marsh deposits composed of carbonaceous shales and coals; (2) a middle interval, 50–80 m thick, with channelized tidally-influenced bayhead delta / tidally-dominated delta deposits; and (3) an uppermost interval, 30–50 m thick, of landward-stepping barrier island strata. A combination of modern analogs show the evolution of the estuary. The system began similar to the North Carolina coast at Cape Hatteras (DU1). As the estuary filled it looked more like Winyah Bay, South Carolina (DU2). The capping barrier island strata could be similar to Big Sarasota Pass, Florida or the East Friesian Islands, Germany (DU3). This study highlights areas for improvement in the modern to ancient to reservoir analog workflow, particularly in mixed-energy systems. For example, we illustrate the difficulties in distinguishing between bayhead and tidal deltas in outcrop, despite the importance of such distinctions for both sequence-stratigraphic and reservoir interpretations. Overall, detailed facies characterization and predictive 3-D geobody analysis does elucidate key recognition criteria for the mixed-energy system, including the preservation of both tide and wave energy indicators, tidal packages, and barrier island facies. Panel_15184 Panel_15184 2:40 PM 3:00 PM

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The exploration of coal-bearing reservoirs for both conventional and unconventional hydrocarbon resources, has increased the interest in similar fluvial/estuarine successions worldwide. In this context, Eastern Kentucky offers excellent outcrop analogues for Carboniferous fluvial-dominated deltaic where facies associations, depositional environments and sequence-stratigraphic patterns can be observed in detail. Extensive roadcuts and a vast database of well/core data (coal and gas exploration), available at the KGS (Kentucky Geological Survey) make the Eastern Kentucky an great field laboratory for studying sedimentology and stratigraphy in coal-bearing successions. The middle Pennsylvanian Pikeville and Hyden Formations are very well exposed along the US highways 23 and 119 in Pike County (SE Kentucky). The local stratigraphy is well known thanks to numerous studies focused on very extensive Pennsylvanian coal beds, used as stratigraphic markers for outcrop correlation. Both formations were deposited in a foredeep basin during the building of the Appalachian orogeny located ot the East. Fluvio-deltaic systems prograded toward west and northwest across the basin, subject to periodic transgressions driven by high-amplitude glacio-eustatic base-level changes during the Late Palaeozoic Gondwanan glaciation. In this paper we present the observations from several outcrops in the Pikeville Formation. They were logged at 1:20 scale and densely sampled for rock-typing analysis including automated petrography with QEMSCAN. In the Pikeville Formation, successions are generally formed by vertically stacked, erosively based transgressive depositional sequences with thickness varying from a few meters to a few tens of meters. The studied sedimentary interval consists mostly of three main architectural elements: (1) river-dominated valley fills with frequent tidally-influenced deposition; (2) transitional sediments of coastal to marginal-marine environments, including coalbeds; (3) extensive marine shales, locally intercalated with prograding mouth-bar deposits. The vertical stacking of this facies form fourth-order sequences, which are grouped into third-order sequences bounded by the extensive marine shales. A series of closely spaced logs, integrated with the available subsurface datasets, will be used to derive detailed geo-cellular 3D facies and architectural models of coal-bearing succession, with the aim to link rock properties to sequence-stratigraphic system tracts. The exploration of coal-bearing reservoirs for both conventional and unconventional hydrocarbon resources, has increased the interest in similar fluvial/estuarine successions worldwide. In this context, Eastern Kentucky offers excellent outcrop analogues for Carboniferous fluvial-dominated deltaic where facies associations, depositional environments and sequence-stratigraphic patterns can be observed in detail. Extensive roadcuts and a vast database of well/core data (coal and gas exploration), available at the KGS (Kentucky Geological Survey) make the Eastern Kentucky an great field laboratory for studying sedimentology and stratigraphy in coal-bearing successions. The middle Pennsylvanian Pikeville and Hyden Formations are very well exposed along the US highways 23 and 119 in Pike County (SE Kentucky). The local stratigraphy is well known thanks to numerous studies focused on very extensive Pennsylvanian coal beds, used as stratigraphic markers for outcrop correlation. Both formations were deposited in a foredeep basin during the building of the Appalachian orogeny located ot the East. Fluvio-deltaic systems prograded toward west and northwest across the basin, subject to periodic transgressions driven by high-amplitude glacio-eustatic base-level changes during the Late Palaeozoic Gondwanan glaciation. In this paper we present the observations from several outcrops in the Pikeville Formation. They were logged at 1:20 scale and densely sampled for rock-typing analysis including automated petrography with QEMSCAN. In the Pikeville Formation, successions are generally formed by vertically stacked, erosively based transgressive depositional sequences with thickness varying from a few meters to a few tens of meters. The studied sedimentary interval consists mostly of three main architectural elements: (1) river-dominated valley fills with frequent tidally-influenced deposition; (2) transitional sediments of coastal to marginal-marine environments, including coalbeds; (3) extensive marine shales, locally intercalated with prograding mouth-bar deposits. The vertical stacking of this facies form fourth-order sequences, which are grouped into third-order sequences bounded by the extensive marine shales. A series of closely spaced logs, integrated with the available subsurface datasets, will be used to derive detailed geo-cellular 3D facies and architectural models of coal-bearing succession, with the aim to link rock properties to sequence-stratigraphic system tracts. Panel_15151 Panel_15151 3:25 PM 3:45 PM

The Eocene of the Central Basin of Spitsbergen shows a series of eastward building clinothems deposited in a foreland basin. This basin was formed by a westerly active fold and thrust-belt which also acted as provenance area for these shallow-marine sand-wedges. Some of these shallow-marine wedges prograded onto the shelf, whereas some of them reached the shelf-edge and have associated deep-marine sand-lobes. Three of these clinothems have been studied with focus on depositional environment, lateral facies variations, internal stacking pattern and shoreline trajectory pattern. All of them show a regressive deltaic to transgressive estuary/tidal couplet. Internally, there are clear differences between the three clinothems in terms of the style of the regressive deltaic part and the transgressive estuary part. The deltaic parts range from a) fluvial and punctuated mass-flow style; b) wave reworked and delta front collapse style; and c) mixed tide and fluvial influenced delta. The transgressive parts of the clinothems show a variation of the thickness of estuary sandstones and coastal plain fines developments conditioned on the degree of aggradation. Previous studies of these Eocene clinothems have interpreted the associated deep-marine sand-lobes as due to: a) sea-level fall with shelf-incision and basinward movement of the deltaic system beyond the shelf-break; b) high sediment-supply mechanism as hyperpycnal flow within shelf-edge deltas feeding the basin-fans during sustained flow; and c) having a narrow shelf that easily gets prograded across with high sediment supply. On individual basis each of these clinothems can be interpreted with these mechanisms above. However, it is interesting to see how the shape and size of each clinothem has a direct effect on the next clinothem that occurs above. As a clinothem consist of a dominant muddy part, the mud-volume can be stored: at the shelf-edge and expand the width of the shelf, on the shelf and building up the shelf height or even be stored more landward within the lagoonal and coastal areas, starving the shelf. This study show how a volumetrically-limited clinothem enables the next clinothem above, to easily cross the shelf and feed sediments down the shelf slope from a fluvial delta. The two following clinothem faced a wider shelf that first gave a wave-dominated delta and finally a mixed tidal and fluvial delta capped by an estuary. The Eocene of the Central Basin of Spitsbergen shows a series of eastward building clinothems deposited in a foreland basin. This basin was formed by a westerly active fold and thrust-belt which also acted as provenance area for these shallow-marine sand-wedges. Some of these shallow-marine wedges prograded onto the shelf, whereas some of them reached the shelf-edge and have associated deep-marine sand-lobes. Three of these clinothems have been studied with focus on depositional environment, lateral facies variations, internal stacking pattern and shoreline trajectory pattern. All of them show a regressive deltaic to transgressive estuary/tidal couplet. Internally, there are clear differences between the three clinothems in terms of the style of the regressive deltaic part and the transgressive estuary part. The deltaic parts range from a) fluvial and punctuated mass-flow style; b) wave reworked and delta front collapse style; and c) mixed tide and fluvial influenced delta. The transgressive parts of the clinothems show a variation of the thickness of estuary sandstones and coastal plain fines developments conditioned on the degree of aggradation. Previous studies of these Eocene clinothems have interpreted the associated deep-marine sand-lobes as due to: a) sea-level fall with shelf-incision and basinward movement of the deltaic system beyond the shelf-break; b) high sediment-supply mechanism as hyperpycnal flow within shelf-edge deltas feeding the basin-fans during sustained flow; and c) having a narrow shelf that easily gets prograded across with high sediment supply. On individual basis each of these clinothems can be interpreted with these mechanisms above. However, it is interesting to see how the shape and size of each clinothem has a direct effect on the next clinothem that occurs above. As a clinothem consist of a dominant muddy part, the mud-volume can be stored: at the shelf-edge and expand the width of the shelf, on the shelf and building up the shelf height or even be stored more landward within the lagoonal and coastal areas, starving the shelf. This study show how a volumetrically-limited clinothem enables the next clinothem above, to easily cross the shelf and feed sediments down the shelf slope from a fluvial delta. The two following clinothem faced a wider shelf that first gave a wave-dominated delta and finally a mixed tidal and fluvial delta capped by an estuary. Panel_15186 Panel_15186 3:45 PM 4:05 PM

Simple and compound dunes are developed on the intertidal tributary channel and channel bank of Yeochari macrotidal flat in Gyeonggi Bay, west coast of Korea. Dunes are asymmetrical with the majority of their steeper lee faces and master bedding surfaces dipping toward ebb current direction. Dunes consist of cross-bedded medium to coarse sands with a coarsening-up textural trend, which overlie channel bank comprised of sand flat and mud flat facies and channel point bars composed of various channel facies including fluid muds and channel lags. Four-year long morphodynamic observations revealed that simple dunes on the tributary channel migrate seaward as fast as 1.5-2 m per day. In contrast compound dunes on the southern channel bank migrate either landward or seaward at much slower rates of 2-3 m per month. Despite greater current speeds on the channel bank, smaller tidal asymmetry leads compound dunes to migrate relatively slowly. In the case of intense wave activity, however, compound dunes seem to migrate at a noticeable rate. Compound dunes continued to shift their location over point bars toward northern channel bank as tributary channel migrates back and forth. Concurrent migration of compound dunes and channels produced a complicated stratigraphic architecture consisting of fining-upward point-bar succession overlain by coarsening-up compound-dune succession with master bedding surfaces dipping nearly opposite to those of point-bar succession. Tidal asymmetry, wave intensity and migration of tributary channel are seen to exert an important control on the stratigraphic architecture of compound dunes and point bars in the intertidal environment. Simple and compound dunes are developed on the intertidal tributary channel and channel bank of Yeochari macrotidal flat in Gyeonggi Bay, west coast of Korea. Dunes are asymmetrical with the majority of their steeper lee faces and master bedding surfaces dipping toward ebb current direction. Dunes consist of cross-bedded medium to coarse sands with a coarsening-up textural trend, which overlie channel bank comprised of sand flat and mud flat facies and channel point bars composed of various channel facies including fluid muds and channel lags. Four-year long morphodynamic observations revealed that simple dunes on the tributary channel migrate seaward as fast as 1.5-2 m per day. In contrast compound dunes on the southern channel bank migrate either landward or seaward at much slower rates of 2-3 m per month. Despite greater current speeds on the channel bank, smaller tidal asymmetry leads compound dunes to migrate relatively slowly. In the case of intense wave activity, however, compound dunes seem to migrate at a noticeable rate. Compound dunes continued to shift their location over point bars toward northern channel bank as tributary channel migrates back and forth. Concurrent migration of compound dunes and channels produced a complicated stratigraphic architecture consisting of fining-upward point-bar succession overlain by coarsening-up compound-dune succession with master bedding surfaces dipping nearly opposite to those of point-bar succession. Tidal asymmetry, wave intensity and migration of tributary channel are seen to exert an important control on the stratigraphic architecture of compound dunes and point bars in the intertidal environment. Panel_15183 Panel_15183 4:05 PM 4:25 PM

The Prince Creek Fm (Maastrichtian) of Alaska, deposited at 80-85° north paleolatitude, preserves an Arctic paleopolar Greenhouse ecosystem. We suggest that distinctive, recurring facies and sedimentary-pedogenic structures coupled with isotopic trends are evidence of a high-latitude signature on this low-gradient, muddy coastal plain. Strata record deposition in meandering trunk channels, meandering-fixed distributaries, and associated floodplains. Crevassing was common and splay complexes make up the bulk of sandy deposits. Inclined heterolithic stratification (IHS) and carbonaceous root traces are found in all channels. Although IHS is interpreted to record tidal-influence, ubiquitous roots on all IHS may also evidence a flashy system with regular discharge fluctuations. Entisols-Inceptisols are drab-colored and contain carbonaceous material and Fe-oxide depletion coatings indicating waterlogging and anoxia, consistent with a high water table. Fe-oxide mottles, ferruginous segregations, bioturbation, and illuvial clay coatings indicate recurring oxidation and periodic drying-out of soils. These compound-cumulative soils experienced repeated wetting and drying, with soil formation repeatedly interrupted by alluviation. Common pedogenic illite/smectite in ash-rich Prince Creek soils also suggest weathering and alternating wetting-drying. Bonebeds on floodplains exhibit a recurring facies pairing consistent with deposition by viscous hyperconcentrated flows. We suggest that exceptional discharge events, generated by seasonal snowmelt in the nearby Brooks Range increased suspended sediment concentrations and generated recurring, erosive hyperconcentrated flows. Hyperpycnites have also been identified in prodelta deposits of the genetically-linked shallow-marine sediments of the Schrader Bluff Fm. Stable oxygen isotope analysis of dinosaur tooth enamel and pedogenic siderite suggest that d18O depleted water ingested by dinosaurs, and meteoric water from siderite, result from increased rainout linked to increased latent heat transfer to the poles, an intensified hydrological cycle, and snowmelt. d18O and d13C values from authigenic aragonite in brackish-water invertebrates likely record seasonal fluctuations attributed to drainage from high altitude freshwater sources. We interpret these characteristics to record a seasonally flashy system, which is the high-latitude signature in the Prince Creek Fm likely driven by the paleopolar light and temperature regime. The Prince Creek Fm (Maastrichtian) of Alaska, deposited at 80-85° north paleolatitude, preserves an Arctic paleopolar Greenhouse ecosystem. We suggest that distinctive, recurring facies and sedimentary-pedogenic structures coupled with isotopic trends are evidence of a high-latitude signature on this low-gradient, muddy coastal plain. Strata record deposition in meandering trunk channels, meandering-fixed distributaries, and associated floodplains. Crevassing was common and splay complexes make up the bulk of sandy deposits. Inclined heterolithic stratification (IHS) and carbonaceous root traces are found in all channels. Although IHS is interpreted to record tidal-influence, ubiquitous roots on all IHS may also evidence a flashy system with regular discharge fluctuations. Entisols-Inceptisols are drab-colored and contain carbonaceous material and Fe-oxide depletion coatings indicating waterlogging and anoxia, consistent with a high water table. Fe-oxide mottles, ferruginous segregations, bioturbation, and illuvial clay coatings indicate recurring oxidation and periodic drying-out of soils. These compound-cumulative soils experienced repeated wetting and drying, with soil formation repeatedly interrupted by alluviation. Common pedogenic illite/smectite in ash-rich Prince Creek soils also suggest weathering and alternating wetting-drying. Bonebeds on floodplains exhibit a recurring facies pairing consistent with deposition by viscous hyperconcentrated flows. We suggest that exceptional discharge events, generated by seasonal snowmelt in the nearby Brooks Range increased suspended sediment concentrations and generated recurring, erosive hyperconcentrated flows. Hyperpycnites have also been identified in prodelta deposits of the genetically-linked shallow-marine sediments of the Schrader Bluff Fm. Stable oxygen isotope analysis of dinosaur tooth enamel and pedogenic siderite suggest that d18O depleted water ingested by dinosaurs, and meteoric water from siderite, result from increased rainout linked to increased latent heat transfer to the poles, an intensified hydrological cycle, and snowmelt. d18O and d13C values from authigenic aragonite in brackish-water invertebrates likely record seasonal fluctuations attributed to drainage from high altitude freshwater sources. We interpret these characteristics to record a seasonally flashy system, which is the high-latitude signature in the Prince Creek Fm likely driven by the paleopolar light and temperature regime. Panel_15139 Panel_15139 4:25 PM 4:45 PM

Oligocene strata In the Llanos basin, comprise 4 units: lower, and upper Early Oligocene, and lower and upper late Oligocene. Each unit contains a couplet of thick basal sand-rich subunit and an upper shaly one. The objective here is to characterize the temporal-spatial variation of the productive Oligocene sands, specially the upper Early Oligocene one (C7), in context of foreland development and sea level oscillations. This unit hosts heavy oil reservoirs in the Rubiales and other fields. Analysis of 118 wells, 16 seismically calibrated regional transects, and 45 maps, helped to document regional facies variation in the Oligocene strata. Thickening of the Oligocene from proximal east to distal west coincided with a progressively finer granulometry westward. Significantly thick blocky proximal reservoir sands, including some incised valley fill deposits, in the east, pass laterally into finer facies toward west. The sand unit of Early Oligocene (C7) shows thickness variation across the area; the thickest basal sands (upto 400’ thick) with minor shaly intercalations occur as a belt closer to the eastern border near Guyana shield, whereas a thinner belt (upto 200’ thick) occurs westward. Further west, the 200’ sandy belt laterally passes into a silty shale facies containing only a few thin sand beds. Our upper Early Oligocene gross depositional environment (GDE) map shows 3 facies belts, broadly paralleling the lithofacies variation mentioned above. The two C7 sand belts are mainly of fluvial origin, whereas its coeval westerly shalier unit varies from proximal brackish to restricted marine outward. The Oligocene units show a marked easterly back-stepping character in all basin-transverse sections. Oligocene 0’ line distribution map reveals that following initial lower Early Oligocene regression, 3 succeeding Oligocene intervals experienced progressive eastward marine incursions coinciding with stacked retrogradational sandy units. MFS-related shales of sand/shale couplets, provide seals for the C7 sand reservoirs westward. However, hydrodynamic factors were responsible for entrapment of oil in easternmost C7 reservoirs lacking effective seals. Punctuated Oligocene uplift of the Eastern Cordilleras likely triggered the cyclic marine transgressions in the foreland basin. The significance of this study is that it provides an understanding of the temporal spatial distribution of the productive Oligocene sands in relation to seal, source rock and entrapment. Oligocene strata In the Llanos basin, comprise 4 units: lower, and upper Early Oligocene, and lower and upper late Oligocene. Each unit contains a couplet of thick basal sand-rich subunit and an upper shaly one. The objective here is to characterize the temporal-spatial variation of the productive Oligocene sands, specially the upper Early Oligocene one (C7), in context of foreland development and sea level oscillations. This unit hosts heavy oil reservoirs in the Rubiales and other fields. Analysis of 118 wells, 16 seismically calibrated regional transects, and 45 maps, helped to document regional facies variation in the Oligocene strata. Thickening of the Oligocene from proximal east to distal west coincided with a progressively finer granulometry westward. Significantly thick blocky proximal reservoir sands, including some incised valley fill deposits, in the east, pass laterally into finer facies toward west. The sand unit of Early Oligocene (C7) shows thickness variation across the area; the thickest basal sands (upto 400’ thick) with minor shaly intercalations occur as a belt closer to the eastern border near Guyana shield, whereas a thinner belt (upto 200’ thick) occurs westward. Further west, the 200’ sandy belt laterally passes into a silty shale facies containing only a few thin sand beds. Our upper Early Oligocene gross depositional environment (GDE) map shows 3 facies belts, broadly paralleling the lithofacies variation mentioned above. The two C7 sand belts are mainly of fluvial origin, whereas its coeval westerly shalier unit varies from proximal brackish to restricted marine outward. The Oligocene units show a marked easterly back-stepping character in all basin-transverse sections. Oligocene 0’ line distribution map reveals that following initial lower Early Oligocene regression, 3 succeeding Oligocene intervals experienced progressive eastward marine incursions coinciding with stacked retrogradational sandy units. MFS-related shales of sand/shale couplets, provide seals for the C7 sand reservoirs westward. However, hydrodynamic factors were responsible for entrapment of oil in easternmost C7 reservoirs lacking effective seals. Punctuated Oligocene uplift of the Eastern Cordilleras likely triggered the cyclic marine transgressions in the foreland basin. The significance of this study is that it provides an understanding of the temporal spatial distribution of the productive Oligocene sands in relation to seal, source rock and entrapment. Panel_15149 Panel_15149 4:45 PM 5:05 PM

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Paleozoic organic rich lacustrine mudstones are important source rocks within the Maritimes Basin, but also form shale gas reservoirs and oil shale deposits. The 100-400m thick Lower Carboniferous Frederick Brook Member of the Albert Formation within the Moncton Basin of the Maritimes Basin of southeastern New Brunswick is comprised of a thick succession of mainly lacustrine clastics and carbonates. Organic rich mudstones occur at several stratigraphic levels, both intercalated with relative deep water lake deposits and also with relative shallow shoreline proximal deposits. Thus organic content of the deposits was likely main related to organic productivity and not to water depth, i.e. anoxia and detrital dilution. Organic matter content and composition changes quite significantly vertically, with RockEval analysis showing that surprisingly the shallower water compared with the deeper water organic rich mudstones generally have higher organic content (8-12% with a maximum of 29% versus 6-8%), slightly higher Hydrogen Index (850-950 versus 700-850) (Lynch, 1999). These difference in organic content and composition is reflected in drastic difference in oil shale yield productivity tests with the shallow water deposits in the uppermost part of the Frederick Brook Member having 2 to 3 times higher yields, average yield of 90-100 liters/ton of 30 API oil (Lynch 1999; Macauley 1984). Relative high lateral variability between wells in organic content, composition and thereby oil shale yields of the organic rich mudstones reflect the relative shallow water depositional setting and observed lateral changes in sedimentary facies. Similar high yield shallow water organic rich lacustrine mudstones are also present in oil shale deposits of the Pennsylvanian Pictou Group by Stellarton in Nova Scotia, where they are intercalated with grey coastal plain mudstones, coarse grained fluvial deposits and thick coal seams, in cases directed overlain by thick coals. The hydrogen rich oil shale deposits are rich in type 1 kerogen, dominated by Botryococcus-type telalginite algae remains (Macauley 1984). The findings that the shallow water organic rich mudstones have the highest hydrogen content not only have a large impact for evaluation of oil shale potential of the succession, but also for selection of units for the ongoing shale gas exploration of these deposits in the deeper part of the Moncton Basin, i.e. pore development during maturation and fluid content. Paleozoic organic rich lacustrine mudstones are important source rocks within the Maritimes Basin, but also form shale gas reservoirs and oil shale deposits. The 100-400m thick Lower Carboniferous Frederick Brook Member of the Albert Formation within the Moncton Basin of the Maritimes Basin of southeastern New Brunswick is comprised of a thick succession of mainly lacustrine clastics and carbonates. Organic rich mudstones occur at several stratigraphic levels, both intercalated with relative deep water lake deposits and also with relative shallow shoreline proximal deposits. Thus organic content of the deposits was likely main related to organic productivity and not to water depth, i.e. anoxia and detrital dilution. Organic matter content and composition changes quite significantly vertically, with RockEval analysis showing that surprisingly the shallower water compared with the deeper water organic rich mudstones generally have higher organic content (8-12% with a maximum of 29% versus 6-8%), slightly higher Hydrogen Index (850-950 versus 700-850) (Lynch, 1999). These difference in organic content and composition is reflected in drastic difference in oil shale yield productivity tests with the shallow water deposits in the uppermost part of the Frederick Brook Member having 2 to 3 times higher yields, average yield of 90-100 liters/ton of 30 API oil (Lynch 1999; Macauley 1984). Relative high lateral variability between wells in organic content, composition and thereby oil shale yields of the organic rich mudstones reflect the relative shallow water depositional setting and observed lateral changes in sedimentary facies. Similar high yield shallow water organic rich lacustrine mudstones are also present in oil shale deposits of the Pennsylvanian Pictou Group by Stellarton in Nova Scotia, where they are intercalated with grey coastal plain mudstones, coarse grained fluvial deposits and thick coal seams, in cases directed overlain by thick coals. The hydrogen rich oil shale deposits are rich in type 1 kerogen, dominated by Botryococcus-type telalginite algae remains (Macauley 1984). The findings that the shallow water organic rich mudstones have the highest hydrogen content not only have a large impact for evaluation of oil shale potential of the succession, but also for selection of units for the ongoing shale gas exploration of these deposits in the deeper part of the Moncton Basin, i.e. pore development during maturation and fluid content. Panel_15653 Panel_15653 1:20 PM 1:40 PM

The Cretaceous McMurray Formation, located in northeastern Alberta, Canada, is the primary host of the Athabasca Oil Sands. The McMurray Formation is generally interpreted to represent the fluvial to estuarine deposits of the boreal sea transgression over a karsted Devonian landscape during the Aptian to the Albian. Commonly observed in the McMurray Formation is Inclined Heterolithic Stratification (IHS), which comprises dipping, regularly interbedded sandstone and mudstone. IHS units are most commonly taken to represent the deposits of laterally accreting point bars. Sandy IHS (defined herein as >70% sandstone) is potentially a reservoir-quality facies, whereas muddy IHS (i.e. <70% sandstone) is typically a non-reservoir facies. The mud-sand content of IHS is directly related to the tidal and fluvial forces that modulate deposition. An in depth understanding of the degree of the paleo-fluvial or -tidal energy acting on IHS deposition is one of the vital parameters needed to understand IHS mud-sand distributions. One way to consider the relative influence of tides, which result from lunar cyclicity, and fluvial flux, which reflects seasonal, annual or decadal variations in streamflow, is to document and interpret rhythmic bedding in IHS successions. Moreover there are basic observations that can be made, that constrain the temporal character of the observed sand-mud pairs. Herein, we focus on two basic and informative observations: (1) the nature and distribution of bioturbation, which reflects that sedimentation rates were low enough to permit infaunal colonization of the sediment; and (2) bed thickness observations that are consistent with tidal versus fluvial sedimentation. Using these observations, we identify IHS units, wherein bioturbation and sediment thickness are consistent with tidal sedimentation: for these the quantitative study of IHS cyclicity, using wavelet transforms, represents a method for determining the degree of tidal influence affecting IHS deposition. Incorporating quantitative and qualitative information, the degree of tidal or fluvial influence modulating IHS deposition is determined and used to better constrain the paleogeographic distribution of IHS. The Cretaceous McMurray Formation, located in northeastern Alberta, Canada, is the primary host of the Athabasca Oil Sands. The McMurray Formation is generally interpreted to represent the fluvial to estuarine deposits of the boreal sea transgression over a karsted Devonian landscape during the Aptian to the Albian. Commonly observed in the McMurray Formation is Inclined Heterolithic Stratification (IHS), which comprises dipping, regularly interbedded sandstone and mudstone. IHS units are most commonly taken to represent the deposits of laterally accreting point bars. Sandy IHS (defined herein as >70% sandstone) is potentially a reservoir-quality facies, whereas muddy IHS (i.e. <70% sandstone) is typically a non-reservoir facies. The mud-sand content of IHS is directly related to the tidal and fluvial forces that modulate deposition. An in depth understanding of the degree of the paleo-fluvial or -tidal energy acting on IHS deposition is one of the vital parameters needed to understand IHS mud-sand distributions. One way to consider the relative influence of tides, which result from lunar cyclicity, and fluvial flux, which reflects seasonal, annual or decadal variations in streamflow, is to document and interpret rhythmic bedding in IHS successions. Moreover there are basic observations that can be made, that constrain the temporal character of the observed sand-mud pairs. Herein, we focus on two basic and informative observations: (1) the nature and distribution of bioturbation, which reflects that sedimentation rates were low enough to permit infaunal colonization of the sediment; and (2) bed thickness observations that are consistent with tidal versus fluvial sedimentation. Using these observations, we identify IHS units, wherein bioturbation and sediment thickness are consistent with tidal sedimentation: for these the quantitative study of IHS cyclicity, using wavelet transforms, represents a method for determining the degree of tidal influence affecting IHS deposition. Incorporating quantitative and qualitative information, the degree of tidal or fluvial influence modulating IHS deposition is determined and used to better constrain the paleogeographic distribution of IHS. Panel_15655 Panel_15655 1:40 PM 2:00 PM

Dipmeter data has traditionally been used to assist interpretation of geologic structure, to infer depositional environments, and determine paleocurrent direction. However, dipmeter data is seldom used as direct conditioning for population of geocellular model properties. We discuss the preparation and use of dipmeter data for interpolation of Facies and Gamma Ray properties in a fluvial point bar deposit. Our example is from the McMurray Formation in Alberta, Canada. Dipmeter data in fluvial point bar deposits are noisy, containing signals from trough cross bedding, subaqueous dune foresets, slumping, mud clast conglomerates, and inclined heterolithic sediments (IHS). Trough cross bedding and dune foresets indicate paleocurrent direction, while the orientations of IHS beds contain information about the architecture of bar-scale lateral accretion packages. When populating geocellular model properties, it is these roughly co-planar, dipping IHS orientations that tell us how to correlate the beds between wells. We have developed a processing method that measures the variation of dipmeter orientations within a moving window, which allows isolation of the coherent bed orientation signal of the co-planar IHS beds. Once the dipmeter data has been high-graded, it can be upscaled into a model framework, interpolated throughout the model volume, and then used as a Locally Varying Azimuth to orient variograms/training images in the property modeling algorithms. The workflow is as follows: (1) Create bed co-planarity “coherency” scores using moving depth windows in dipmeter data (2) Apply coherency score filtering and other criteria (i.e. exclude certain facies) to high-grade dipmeter readings for use in model conditioning (3) Supplemental bed dip data from geophysical survey interpretations can be added to the dataset (4) Decompose the bed dip azimuths and dip angles into unit circle vectors dX, dY, and dZ (strategy to avoid azimuth aliasing) (5) Upscale the dX, dY, and dZ coherent bed orientation data into a model framework (6) Interpolate dX, dY, and dZ through the geomodel framework using inverse distance squared weighting (7) Recombine unit circle vector properties into Dip Azimuth and Dip Angle (8) Replicate upscaled core and wireline log data around the wells according to interpolated Dip Azimuths and Dip Angles to enhance local honoring of coherent bed orientation data (9) Perform property modeling using the bed orientation properties as Locally Varying Azimuth for steering variograms Dipmeter data has traditionally been used to assist interpretation of geologic structure, to infer depositional environments, and determine paleocurrent direction. However, dipmeter data is seldom used as direct conditioning for population of geocellular model properties. We discuss the preparation and use of dipmeter data for interpolation of Facies and Gamma Ray properties in a fluvial point bar deposit. Our example is from the McMurray Formation in Alberta, Canada. Dipmeter data in fluvial point bar deposits are noisy, containing signals from trough cross bedding, subaqueous dune foresets, slumping, mud clast conglomerates, and inclined heterolithic sediments (IHS). Trough cross bedding and dune foresets indicate paleocurrent direction, while the orientations of IHS beds contain information about the architecture of bar-scale lateral accretion packages. When populating geocellular model properties, it is these roughly co-planar, dipping IHS orientations that tell us how to correlate the beds between wells. We have developed a processing method that measures the variation of dipmeter orientations within a moving window, which allows isolation of the coherent bed orientation signal of the co-planar IHS beds. Once the dipmeter data has been high-graded, it can be upscaled into a model framework, interpolated throughout the model volume, and then used as a Locally Varying Azimuth to orient variograms/training images in the property modeling algorithms. The workflow is as follows: (1) Create bed co-planarity “coherency” scores using moving depth windows in dipmeter data (2) Apply coherency score filtering and other criteria (i.e. exclude certain facies) to high-grade dipmeter readings for use in model conditioning (3) Supplemental bed dip data from geophysical survey interpretations can be added to the dataset (4) Decompose the bed dip azimuths and dip angles into unit circle vectors dX, dY, and dZ (strategy to avoid azimuth aliasing) (5) Upscale the dX, dY, and dZ coherent bed orientation data into a model framework (6) Interpolate dX, dY, and dZ through the geomodel framework using inverse distance squared weighting (7) Recombine unit circle vector properties into Dip Azimuth and Dip Angle (8) Replicate upscaled core and wireline log data around the wells according to interpolated Dip Azimuths and Dip Angles to enhance local honoring of coherent bed orientation data (9) Perform property modeling using the bed orientation properties as Locally Varying Azimuth for steering variograms Panel_15654 Panel_15654 2:00 PM 2:20 PM

With Cdn$314 billion of post-tax present value in the ground, we view Canada’s oil sands as one of the last material resource capture opportunities. The scale is impressive with four million barrels per day of bitumen production forecasted in 2020. For perspective, this is double the amount of tight oil projected from the prolific Eagle Ford. This level of output has undeniably resulted in growing pains. By 2017 we see production exceeding current takeaway capacity. Luckily help is on the way in the form of proposed pipelines, and rail can provide fit-gap solutions. The most interesting scenario involves Northern Gateway (we project on-stream in 2023) and TransMoutain Express (we project on-stream in 2018) which both terminate on Canada’s West Coast. Asia now becomes accessible to a heavy Canadian oil sands barrel. China also happens to be the single largest heavy crude demand centre other than the US. Our analysis on the refining value of WCS (Western Canadian Select) indicates that China places the highest price on this heavy crude, over a five percent premium to the US Gulf Coast. However, regardless of this new market, we expect a WCS barrel to trade US$20 to US$27 below WTI onward into the next decade. This impacts economics of projects and causes operator to rigorously vet and re-evaluate prior to a final investment decision (FID). In the past year we have seen an upgrader indefinably suspended as diluting bitumen is providing more favourable economics. We have also recently seen a SAGD project phase delayed by years while the expansion and new technologies are reconsidered. This presentation will discuss the challenges and opportunities for extracting bitumen. We will then chronicle the journey of a heavy oil barrel as it searches for the best price in the market to maximize the producers value capture. With Cdn$314 billion of post-tax present value in the ground, we view Canada’s oil sands as one of the last material resource capture opportunities. The scale is impressive with four million barrels per day of bitumen production forecasted in 2020. For perspective, this is double the amount of tight oil projected from the prolific Eagle Ford. This level of output has undeniably resulted in growing pains. By 2017 we see production exceeding current takeaway capacity. Luckily help is on the way in the form of proposed pipelines, and rail can provide fit-gap solutions. The most interesting scenario involves Northern Gateway (we project on-stream in 2023) and TransMoutain Express (we project on-stream in 2018) which both terminate on Canada’s West Coast. Asia now becomes accessible to a heavy Canadian oil sands barrel. China also happens to be the single largest heavy crude demand centre other than the US. Our analysis on the refining value of WCS (Western Canadian Select) indicates that China places the highest price on this heavy crude, over a five percent premium to the US Gulf Coast. However, regardless of this new market, we expect a WCS barrel to trade US$20 to US$27 below WTI onward into the next decade. This impacts economics of projects and causes operator to rigorously vet and re-evaluate prior to a final investment decision (FID). In the past year we have seen an upgrader indefinably suspended as diluting bitumen is providing more favourable economics. We have also recently seen a SAGD project phase delayed by years while the expansion and new technologies are reconsidered. This presentation will discuss the challenges and opportunities for extracting bitumen. We will then chronicle the journey of a heavy oil barrel as it searches for the best price in the market to maximize the producers value capture. Panel_15651 Panel_15651 2:20 PM 2:40 PM

With an estimated 16 billion barrels of bitumen and heavy oil, Utah holds the largest oil sand resource in the United States. At least fifty deposits are known flanking and within the petroliferous Uinta and Paradox Basins in eastern Utah, but fewer than ten are of potential commercial consequence. During the three decades preceding the collapse in oil price in the mid-1980s, Utah “tar sands” were the object of continuous exploration activity by the petroleum industry and development research by U.S. Department of Energy laboratories and DOE-funded university teams. Since then, this significant domestic energy resource largely has been neglected. To date, there has been no commercially-viable extraction of the oils for fuel. A majority of the deposits are in heterogeneous fluvial sandstones, giving rise to large spatial variability in oil resource-in-place. The very extensive lower Eocene fluvial deposits on the south flank of the Uinta Basin have average oil concentrations less than 50 thousand barrels/acre (MBO/ac), but one small portion of the Sunnyside deposit holds more than 300 MBO/ac. On the north flank of the basin at Asphalt Ridge, Cretaceous-age stacked channel sands contain 120-190 MBO/ac. A small north flank deposit hosted in Triassic-Jurassic eolian sandstone, Whiterock, is even richer, 450-485 MBO/ac. The 4.3 to 5.2 BBO Tar Sands Triangle bitumen deposit covering an area of nearly 200 square miles in south-central Utah is in a Permian-age eolian sandstone reservoir. This deposit is quite lean having an average OOIP of just 37 to 42 MBO/ac. Unfortunately, Utah’s oil sand deposits present numerous technical challenges to commercial exploitation. The reservoirs are sandstone, not unconsolidated sands, and they tend to be “oil-wet”. The bitumen and heavy oils are highly viscous. Many deposits are in regions with exceptional scenic quality and high environmental/conservation values presenting added regulatory and legal obstacles. New solvent-based extraction technologies may prove successful unlocking this very large, but elusive, oil sand resource. With an estimated 16 billion barrels of bitumen and heavy oil, Utah holds the largest oil sand resource in the United States. At least fifty deposits are known flanking and within the petroliferous Uinta and Paradox Basins in eastern Utah, but fewer than ten are of potential commercial consequence. During the three decades preceding the collapse in oil price in the mid-1980s, Utah “tar sands” were the object of continuous exploration activity by the petroleum industry and development research by U.S. Department of Energy laboratories and DOE-funded university teams. Since then, this significant domestic energy resource largely has been neglected. To date, there has been no commercially-viable extraction of the oils for fuel. A majority of the deposits are in heterogeneous fluvial sandstones, giving rise to large spatial variability in oil resource-in-place. The very extensive lower Eocene fluvial deposits on the south flank of the Uinta Basin have average oil concentrations less than 50 thousand barrels/acre (MBO/ac), but one small portion of the Sunnyside deposit holds more than 300 MBO/ac. On the north flank of the basin at Asphalt Ridge, Cretaceous-age stacked channel sands contain 120-190 MBO/ac. A small north flank deposit hosted in Triassic-Jurassic eolian sandstone, Whiterock, is even richer, 450-485 MBO/ac. The 4.3 to 5.2 BBO Tar Sands Triangle bitumen deposit covering an area of nearly 200 square miles in south-central Utah is in a Permian-age eolian sandstone reservoir. This deposit is quite lean having an average OOIP of just 37 to 42 MBO/ac. Unfortunately, Utah’s oil sand deposits present numerous technical challenges to commercial exploitation. The reservoirs are sandstone, not unconsolidated sands, and they tend to be “oil-wet”. The bitumen and heavy oils are highly viscous. Many deposits are in regions with exceptional scenic quality and high environmental/conservation values presenting added regulatory and legal obstacles. New solvent-based extraction technologies may prove successful unlocking this very large, but elusive, oil sand resource. Panel_15652 Panel_15652 2:40 PM 3:00 PM

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The grain component of the oil sands fabric was explored from three Canadian oil sands depositional settings from the McMurray Formation to determine grain morphology and weatherability, along with ‘sourcing grains’ to confirm depositional environments. In reservoir management studies, it is well known that accurate predictions of reservoir quality have a major influence on the success of a recovery program. Inherit characteristics of grains can be directly observed including textural properties (such as grain size, grain shape and sorting) and pore scale properties all which control reservoir properties. 18,000 grains from cores, 6000 from each environment, a transition depositional setting, estuary reservoir proper and the main estuarine reservoir were observed by SEM and results analyzed with an image analysis package. Preliminary results from SEM analysis revealed that grains from the three depositional settings displayed markedly different characteristics. Grains from the transitional depositional setting ranged from coarse to very fine sand (according to the Udden-Wentworth grain scale), although grains were predominately medium and fine sand sized. Whilst grains from the estuary reservoir proper changed to be predominately medium and fine sand sized, as were those from the main estuarine reservoir. These shifts in grain sizes between depositional environments are indicative of sorting differences which greatly influence reservoir characteristics and quality. Weatherability and fracturing of grains that also control reservoir conditions were observed to vary between the three depositional settings. Grains from the transitional depositional setting displayed the least amount of weathering; whereas weathering significantly increased in the estuary reservoir proper and significantly increased again in the main estuarine reservoir. Few grains of the transitional depositional setting were observed to be fractured either along the edges or across grain surfaces. Whilst grain fracturing significantly increased in the estuary reservoir proper, although slightly decreased in the main estuarine reservoir. Fractured and weathered grains can introduce a secondary porosity to the reservoir and impact reservoir productivity. Mechanical grain features observed from the three depositional settings confirmed that sources of the grains are derived from the logged distinct environments. The grain component of the oil sands fabric was explored from three Canadian oil sands depositional settings from the McMurray Formation to determine grain morphology and weatherability, along with ‘sourcing grains’ to confirm depositional environments. In reservoir management studies, it is well known that accurate predictions of reservoir quality have a major influence on the success of a recovery program. Inherit characteristics of grains can be directly observed including textural properties (such as grain size, grain shape and sorting) and pore scale properties all which control reservoir properties. 18,000 grains from cores, 6000 from each environment, a transition depositional setting, estuary reservoir proper and the main estuarine reservoir were observed by SEM and results analyzed with an image analysis package. Preliminary results from SEM analysis revealed that grains from the three depositional settings displayed markedly different characteristics. Grains from the transitional depositional setting ranged from coarse to very fine sand (according to the Udden-Wentworth grain scale), although grains were predominately medium and fine sand sized. Whilst grains from the estuary reservoir proper changed to be predominately medium and fine sand sized, as were those from the main estuarine reservoir. These shifts in grain sizes between depositional environments are indicative of sorting differences which greatly influence reservoir characteristics and quality. Weatherability and fracturing of grains that also control reservoir conditions were observed to vary between the three depositional settings. Grains from the transitional depositional setting displayed the least amount of weathering; whereas weathering significantly increased in the estuary reservoir proper and significantly increased again in the main estuarine reservoir. Few grains of the transitional depositional setting were observed to be fractured either along the edges or across grain surfaces. Whilst grain fracturing significantly increased in the estuary reservoir proper, although slightly decreased in the main estuarine reservoir. Fractured and weathered grains can introduce a secondary porosity to the reservoir and impact reservoir productivity. Mechanical grain features observed from the three depositional settings confirmed that sources of the grains are derived from the logged distinct environments. Panel_15647 Panel_15647 3:25 PM 3:45 PM

The hydrocarbon potential of the Mississippian-age Hartselle Sandstone in northwestern Alabama and northeastern Mississippi has long been known. The most recent publically available systematic study on the resource, Gary Wilson’s Geological Survey of Alabama (GSA) Bulletin 111 (B111), was completed almost three decades ago. Wilson estimated that Alabama’s surface and subsurface oil sands deposits contain up to 7.5 billion barrels of hydrocarbon, with up to 350 million barrels within 50 feet of the surface. No commercial exploitation of these resources for the purpose of extracting oil has occurred to date, owing to various economic and limiting technological factors; however, interest has recently increased, particularly in light of growing desire for North American energy independence. Alabama Governor Dr. Robert Bentley established the Alabama Oil Sands Program (AOSP) at the GSA and the State Oil and Gas Board (OGB) of Alabama in early 2014. The purpose of the AOSP is to provide a road map for an initiative that facilitates commercial development of Alabama’s oil sands resources; assist in the realization of potential economic and societal benefits that accrue from prudent, orderly, and environmentally sound development of Alabama’s oil sands; provide focus for oil sands activities and initiatives in the state conducting complete geological, geochemical, geophysical, and engineering analyses; and evaluate and develop appropriate legal and regulatory frameworks. Work within the AOSP has included a comprehensive review of existing data at the GSA and OGB, including data from wells, cores, and field notes. Fieldwork has commenced, building on B111. Specific plans include additional cores and analyses of the rock and bitumen, with particular attention to data that would inform decisions about feasible economic development. Reservoir models and reserve estimates will then be recalculated using up-to-date methodologies. Information is being sought about newer surface and in situ extraction technologies that could be economically employed on small- to medium-sized deposits such as this. These facts will allow for a comprehensive assessment of the potential development of Alabama’s Mississippian-age Hartselle oil sands. The hydrocarbon potential of the Mississippian-age Hartselle Sandstone in northwestern Alabama and northeastern Mississippi has long been known. The most recent publically available systematic study on the resource, Gary Wilson’s Geological Survey of Alabama (GSA) Bulletin 111 (B111), was completed almost three decades ago. Wilson estimated that Alabama’s surface and subsurface oil sands deposits contain up to 7.5 billion barrels of hydrocarbon, with up to 350 million barrels within 50 feet of the surface. No commercial exploitation of these resources for the purpose of extracting oil has occurred to date, owing to various economic and limiting technological factors; however, interest has recently increased, particularly in light of growing desire for North American energy independence. Alabama Governor Dr. Robert Bentley established the Alabama Oil Sands Program (AOSP) at the GSA and the State Oil and Gas Board (OGB) of Alabama in early 2014. The purpose of the AOSP is to provide a road map for an initiative that facilitates commercial development of Alabama’s oil sands resources; assist in the realization of potential economic and societal benefits that accrue from prudent, orderly, and environmentally sound development of Alabama’s oil sands; provide focus for oil sands activities and initiatives in the state conducting complete geological, geochemical, geophysical, and engineering analyses; and evaluate and develop appropriate legal and regulatory frameworks. Work within the AOSP has included a comprehensive review of existing data at the GSA and OGB, including data from wells, cores, and field notes. Fieldwork has commenced, building on B111. Specific plans include additional cores and analyses of the rock and bitumen, with particular attention to data that would inform decisions about feasible economic development. Reservoir models and reserve estimates will then be recalculated using up-to-date methodologies. Information is being sought about newer surface and in situ extraction technologies that could be economically employed on small- to medium-sized deposits such as this. These facts will allow for a comprehensive assessment of the potential development of Alabama’s Mississippian-age Hartselle oil sands. Panel_15646 Panel_15646 3:45 PM 4:05 PM

The geocellular models most faithful to the formation architecture are those in which the cell layers are parallel to bedding. Achieving this in fluvial point bar deposits is difficult because bedding in the heterolithic upper point bar is neither parallel to the point bar’s scour base nor to the overlying seal beds. In general, the upper point bar bed geometry is sigmoidal in cross section and arcuate in map view. This shape can be described with the following algorithm: (1) Ps = (SQRT( (Xc - Xs)^2 + (Yc - Ys)^2 ) - R) / W (2) IF Ps < 0 THEN Zs = UpperZ (3) ELSE IF Ps > 1 THEN Zs = LowerZ (4) ELSE Zs = UpperZ+ (0.5 x cos( 3.14159 x Ps ) - 0.5) * (UpperZ-LowerZ ) where: Ps = normalized position of the sample point on the sigmoidal slope Xs = sample location X coordinate Ys = sample location Y coordinate * Xc = circular planform shape centroid X coordinate * Yc = circular planform shape centroid Y coordinate * R = circular planform shape radius to top of sigmoid slope * W = width of sigmoid from top of slope to base of slope Zs = calculated elevation of sample * UpperZ = elevation of top of sigmoid slope * LowerZ = elevation of base of sigmoid slope * = term in sigmoid shape equation The dip angle of the sigmoidal surface at any location can be determined as the first derivative of the above function. Also, the down-dip azimuth can be calculated as the angle between any sample point and the shape centroid relative to due North. The algorithm of Equations 1 through 4 is optimized to the surface elevation picks in wells and/or geophysical data using a spreadsheet that iteratively modifies the six equation parameters of the mathematically defined surface (denoted with asterisks) until an objective function of fit to the real data is minimized. The objective function is a weighted summation of elevation estimation error, dip angle estimation error, and dip azimuth estimation error. After the best-fit equation terms are determined, the same algorithm is used to assign elevation values to the nodes of a surface elevation grid. These surfaces can then be flexed to match well data and/or geophysical interpretations and then used as zone boundaries, as layer orientation guides for the geocellular framework, or to help correlate between widely spaced wells. This method has been successfully applied to a Brazos River (Texas) modern point bar with dense borehole coverage, and to two heavy oil reservoirs in Alberta, one with 3D seismic and the other with ground penetrating radar. The geocellular models most faithful to the formation architecture are those in which the cell layers are parallel to bedding. Achieving this in fluvial point bar deposits is difficult because bedding in the heterolithic upper point bar is neither parallel to the point bar’s scour base nor to the overlying seal beds. In general, the upper point bar bed geometry is sigmoidal in cross section and arcuate in map view. This shape can be described with the following algorithm: (1) Ps = (SQRT( (Xc - Xs)^2 + (Yc - Ys)^2 ) - R) / W (2) IF Ps < 0 THEN Zs = UpperZ (3) ELSE IF Ps > 1 THEN Zs = LowerZ (4) ELSE Zs = UpperZ+ (0.5 x cos( 3.14159 x Ps ) - 0.5) * (UpperZ-LowerZ ) where: Ps = normalized position of the sample point on the sigmoidal slope Xs = sample location X coordinate Ys = sample location Y coordinate * Xc = circular planform shape centroid X coordinate * Yc = circular planform shape centroid Y coordinate * R = circular planform shape radius to top of sigmoid slope * W = width of sigmoid from top of slope to base of slope Zs = calculated elevation of sample * UpperZ = elevation of top of sigmoid slope * LowerZ = elevation of base of sigmoid slope * = term in sigmoid shape equation The dip angle of the sigmoidal surface at any location can be determined as the first derivative of the above function. Also, the down-dip azimuth can be calculated as the angle between any sample point and the shape centroid relative to due North. The algorithm of Equations 1 through 4 is optimized to the surface elevation picks in wells and/or geophysical data using a spreadsheet that iteratively modifies the six equation parameters of the mathematically defined surface (denoted with asterisks) until an objective function of fit to the real data is minimized. The objective function is a weighted summation of elevation estimation error, dip angle estimation error, and dip azimuth estimation error. After the best-fit equation terms are determined, the same algorithm is used to assign elevation values to the nodes of a surface elevation grid. These surfaces can then be flexed to match well data and/or geophysical interpretations and then used as zone boundaries, as layer orientation guides for the geocellular framework, or to help correlate between widely spaced wells. This method has been successfully applied to a Brazos River (Texas) modern point bar with dense borehole coverage, and to two heavy oil reservoirs in Alberta, one with 3D seismic and the other with ground penetrating radar. Panel_15650 Panel_15650 4:05 PM 4:25 PM

The Cretaceous Fengcheng oil sand in the northwestern margin of the Jungar Basin, NW China is a major heavy oil producing reservoir in China. It comprises three reservoir units, namely, No. 1, No. 2, No. 3 oil sands. The reservoir can be divided into three sections stratigraphically: Sections K1q3, K1q2, and K1q1, developed on paleo monoclinal structural highs striking NE-SW. The base of the Cretaceous (K1q3) is composed of sandy conglomerate and pebbly sandstone. The K1q2 oil sand in the middle comprises sandstone. The top K1q1 oil sand consists primarily of fine sandstone. The No. 1 oil sand is of braided river delta front deposition, whereas the No. 2 and No. 3 oil sands are of braided river delta plain deposition. The oil sands contain primary intergranular pore, residual intergranular pore and minor intragranular dissolved pores. The average porosity and permeability of the K1q2 oil-bearing sandstone is 34.2%, and 1090 mD, respectively. The oil density is 0.9789 g/cm3, while the surface viscosity at 50 degree C is 266,000 mPa.s. The No. 1 oil sand is typical of a lithological-structural reservoir, while the No. 2 and No. 3 oil sands are of structural-lithological reservoirs. The burial depths of the oil sands have been always shallow, < 200 m. The reservoir temperature is 18-20 degree C, and the pressure is 1-2.3 MPa. The major oil sand pay zones are of channel bars and underwater inter-distributary channels. The oil sand reservoir has the following characteristics: (1) Reservoirs in proximity to faults and unconformity surfaces have higher oil saturation; (2) Higher oil saturation corresponds to reservoir units with better porosity and permeability; (3) The Deeply buried oil sands have better oil saturation. The Cretaceous Fengcheng oil sand in the northwestern margin of the Jungar Basin, NW China is a major heavy oil producing reservoir in China. It comprises three reservoir units, namely, No. 1, No. 2, No. 3 oil sands. The reservoir can be divided into three sections stratigraphically: Sections K1q3, K1q2, and K1q1, developed on paleo monoclinal structural highs striking NE-SW. The base of the Cretaceous (K1q3) is composed of sandy conglomerate and pebbly sandstone. The K1q2 oil sand in the middle comprises sandstone. The top K1q1 oil sand consists primarily of fine sandstone. The No. 1 oil sand is of braided river delta front deposition, whereas the No. 2 and No. 3 oil sands are of braided river delta plain deposition. The oil sands contain primary intergranular pore, residual intergranular pore and minor intragranular dissolved pores. The average porosity and permeability of the K1q2 oil-bearing sandstone is 34.2%, and 1090 mD, respectively. The oil density is 0.9789 g/cm3, while the surface viscosity at 50 degree C is 266,000 mPa.s. The No. 1 oil sand is typical of a lithological-structural reservoir, while the No. 2 and No. 3 oil sands are of structural-lithological reservoirs. The burial depths of the oil sands have been always shallow, < 200 m. The reservoir temperature is 18-20 degree C, and the pressure is 1-2.3 MPa. The major oil sand pay zones are of channel bars and underwater inter-distributary channels. The oil sand reservoir has the following characteristics: (1) Reservoirs in proximity to faults and unconformity surfaces have higher oil saturation; (2) Higher oil saturation corresponds to reservoir units with better porosity and permeability; (3) The Deeply buried oil sands have better oil saturation. Panel_15648 Panel_15648 4:25 PM 4:45 PM

In 2013 gas hydrate samples (average saturation of 45%~55% of pore volume) were obtained in Dongsha Sea Area (GMGS2). The high resolution 3D seismic data here shows there are small various landslide bodies in huge mass transport deposits. Referring to the landslides in outcrops of other areas, these bodies are divided into 7 types by analyzing the shape, architecture, and genesis, namely the slide, collapse, and deformation above BSRs, as well as the slump wedge, lens, block, and sheet below BSRs. The features are listed to identify them in seismic profiles and multi beam bathymetric submarine geomorphology maps. Based on this classification detailed studies are completed, including the measurements for landslide body scales, and slope gradients, the depiction for three-dimensional characteristics, and the research on landslide distribution. The results display that slump sheet and wedge have obvious long axes while slide, slump lens, and block have similar length and width. The slope gradients imply the collapse and slump sheet develop when the slope gradient is below 5° while the slide, slump block and lens occur when the slope gradient higher than 10°. In space the slump wedge is a lobe-like shape while the slump sheet seems like a spade. Above BSRs, the deformation constitute the main part of slump fan while below BSRs, the slump lens, and blocks make up the slump fan and slump sheet appears in fault belts. In order to determine the genetic differences for these 7 types, this paper discussed the possibility of vertical flow-pattern-transformation and specific mechanism for submarine landslides. In the study area the trigger mechanisms for these landslide bodies include gas hydrate decomposition, sediments overload, steep slope, sand-beds interbeds, and tectonic activities. The conclusions are that the dominant factor is free gas caused by gas hydrate decomposition and transformation between flow patterns exists probably, which can be verified by the complex configuration in slump lens. Finally there are 2 kinds of response between landslides and BSRs since the free gas either influences the landslide bodies below BSRs or those above BSRs, leading to A and B, 2 kinds of landslide body associations. A type is characterized by slide above BSRs and slump lens below BSRs while B type has collapse or deformation above BSRs and slump block below BSRs. A type is preferred because it indicates less decomposition and better capping of gas hydrate layers. In 2013 gas hydrate samples (average saturation of 45%~55% of pore volume) were obtained in Dongsha Sea Area (GMGS2). The high resolution 3D seismic data here shows there are small various landslide bodies in huge mass transport deposits. Referring to the landslides in outcrops of other areas, these bodies are divided into 7 types by analyzing the shape, architecture, and genesis, namely the slide, collapse, and deformation above BSRs, as well as the slump wedge, lens, block, and sheet below BSRs. The features are listed to identify them in seismic profiles and multi beam bathymetric submarine geomorphology maps. Based on this classification detailed studies are completed, including the measurements for landslide body scales, and slope gradients, the depiction for three-dimensional characteristics, and the research on landslide distribution. The results display that slump sheet and wedge have obvious long axes while slide, slump lens, and block have similar length and width. The slope gradients imply the collapse and slump sheet develop when the slope gradient is below 5° while the slide, slump block and lens occur when the slope gradient higher than 10°. In space the slump wedge is a lobe-like shape while the slump sheet seems like a spade. Above BSRs, the deformation constitute the main part of slump fan while below BSRs, the slump lens, and blocks make up the slump fan and slump sheet appears in fault belts. In order to determine the genetic differences for these 7 types, this paper discussed the possibility of vertical flow-pattern-transformation and specific mechanism for submarine landslides. In the study area the trigger mechanisms for these landslide bodies include gas hydrate decomposition, sediments overload, steep slope, sand-beds interbeds, and tectonic activities. The conclusions are that the dominant factor is free gas caused by gas hydrate decomposition and transformation between flow patterns exists probably, which can be verified by the complex configuration in slump lens. Finally there are 2 kinds of response between landslides and BSRs since the free gas either influences the landslide bodies below BSRs or those above BSRs, leading to A and B, 2 kinds of landslide body associations. A type is characterized by slide above BSRs and slump lens below BSRs while B type has collapse or deformation above BSRs and slump block below BSRs. A type is preferred because it indicates less decomposition and better capping of gas hydrate layers. Panel_15649 Panel_15649 4:45 PM 5:05 PM

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The Upper Cretaceous Niobrara Formation of the western U.S. has been the target of oil and gas drilling for decades, but recent technological improvements have spurred an exponential growth in exploration and production. The Niobrara extends from NM to MT, and NE to CO (with equivalent strata further west, e.g., Mancos Shale), and is quite variable in terms of chalk-marlstone development and total organic content. The Niobrara was deposited during a time of generally enhanced organic matter production and preservation associated with Oceanic Anoxic Event 3 (OAE3). Reconstructing local variations in oceanographic conditions can help explain and predict variations in organic content across the Western Interior Sea (WIS). Understanding the conditions that lead to the development of anoxic conditions in the WIS also has broad implications for processes that drive the formation of anoxia in restricted seaways around the world. We present data on foraminiferal paleoecology and biostratigraphy from a transect of sites across the central part of the seaway in CO, KS, and NM to quantify paleoenvironmental variability across the Niobrara Formation and understand how circulation or runoff/precipitation changes that may have lead increased organic matter preservation in the WIS. We also compare the development of OAE3 in the Western Interior to the development of the Cenomanian-Turonian OAE2 (which is related to, for example, the Eagle Ford Shale) to use the differences and similarities between the two to understand the underlying mechanisms that drive organic carbon preservation in the Western Interior. The lithology of the Niobrara Formation varies strongly both east-west and north-south, with the purest chalks deposited in a belt from west TX to central KS. Foraminiferal paleoecology varies greatly across the Niobrara as well. Chalk units in the Fort Hays Limestone Member have a higher percentage and diversity of benthic foraminifera than do the thin interbedded dark gray shales; the chalks also have a higher percentage of biserial planktic foraminifera, a generalist group that typically dominates low-diversity assemblages, suggesting high productivity conditions. The OAE3 interval of the Smoky Hill Chalk Member is generally dominated by a low diversity planktic assemblage with very few to no benthic foraminifera. This is coincident with increased organic matter content, and suggests dysoxic to anoxic conditions on the seafloor created by increased stratification. The Upper Cretaceous Niobrara Formation of the western U.S. has been the target of oil and gas drilling for decades, but recent technological improvements have spurred an exponential growth in exploration and production. The Niobrara extends from NM to MT, and NE to CO (with equivalent strata further west, e.g., Mancos Shale), and is quite variable in terms of chalk-marlstone development and total organic content. The Niobrara was deposited during a time of generally enhanced organic matter production and preservation associated with Oceanic Anoxic Event 3 (OAE3). Reconstructing local variations in oceanographic conditions can help explain and predict variations in organic content across the Western Interior Sea (WIS). Understanding the conditions that lead to the development of anoxic conditions in the WIS also has broad implications for processes that drive the formation of anoxia in restricted seaways around the world. We present data on foraminiferal paleoecology and biostratigraphy from a transect of sites across the central part of the seaway in CO, KS, and NM to quantify paleoenvironmental variability across the Niobrara Formation and understand how circulation or runoff/precipitation changes that may have lead increased organic matter preservation in the WIS. We also compare the development of OAE3 in the Western Interior to the development of the Cenomanian-Turonian OAE2 (which is related to, for example, the Eagle Ford Shale) to use the differences and similarities between the two to understand the underlying mechanisms that drive organic carbon preservation in the Western Interior. The lithology of the Niobrara Formation varies strongly both east-west and north-south, with the purest chalks deposited in a belt from west TX to central KS. Foraminiferal paleoecology varies greatly across the Niobrara as well. Chalk units in the Fort Hays Limestone Member have a higher percentage and diversity of benthic foraminifera than do the thin interbedded dark gray shales; the chalks also have a higher percentage of biserial planktic foraminifera, a generalist group that typically dominates low-diversity assemblages, suggesting high productivity conditions. The OAE3 interval of the Smoky Hill Chalk Member is generally dominated by a low diversity planktic assemblage with very few to no benthic foraminifera. This is coincident with increased organic matter content, and suggests dysoxic to anoxic conditions on the seafloor created by increased stratification. Panel_15263 Panel_15263 1:20 PM 1:40 PM

Mudstone aggregates form the main detrital component of mudstone-dominated strata of the Upper Cretaceous Second White Specks and Carlile Formations. The formations were deposited in very different settings within the Interior Cretaceous Seaway and are separated by an unconformity. The Second White Specks (2WS) Formation is comprised of organic rich mudstones with a large content of calcareous macro- and microfossils, and at several levels calcareous fine-grained sandstone beds. It varies from 5-7% TOC and is dominated by type II and III kerogens. The 2WS is an established target for biogenic oil and gas production but a thorough understanding of the complex stratal architecture remains challenging and ongoing. In contrast, the Carlile Formation is comprised of intensely bioturbated non-calcareous mudstones with a variable content of silt- and sand-sized silica grains, with the strata forming 20-30m tall mudstone clinoforms in contrast to the tabular stratal architecture of the 2WS strata. The mudstone aggregates are well preserved in the studied strata due to the relative shallow maximum burial of approximately 1500-2000m. The aggregates occur as silt- to sand-sized particles with different composition, with the oval shape indicating they are only slightly compacted and that they were semi-indurated at the time of deposition. Potential origin of the mudstone aggregates includes extrabasinal grains, and/or intrabasinal rip-up clasts, or crustacean micro-coprolite fragments. However, the presence of coccolith fragments within the aggregates clearly demonstrates that the majority of the mudstone aggregates are intraformational, however their variable composition from the surrounding matrix mud suggests transport a significant distance from their site of origin. Furthermore, significant abrupt vertical changes in the grain size of the mudstone aggregates and their chemical composition shows that the area of origin changes between dominantly intra-formation rip-up clasts to micro-coprolites, relating to relative sea level changes. However, as individual sequence stratigraphic units often have relative uniform composition of the mudstone aggregates, composition of the mudstone aggregates do not seem to be strongly related to water depth but rather changes in circulation within the Interior Seaway. Mudstone aggregates form the main detrital component of mudstone-dominated strata of the Upper Cretaceous Second White Specks and Carlile Formations. The formations were deposited in very different settings within the Interior Cretaceous Seaway and are separated by an unconformity. The Second White Specks (2WS) Formation is comprised of organic rich mudstones with a large content of calcareous macro- and microfossils, and at several levels calcareous fine-grained sandstone beds. It varies from 5-7% TOC and is dominated by type II and III kerogens. The 2WS is an established target for biogenic oil and gas production but a thorough understanding of the complex stratal architecture remains challenging and ongoing. In contrast, the Carlile Formation is comprised of intensely bioturbated non-calcareous mudstones with a variable content of silt- and sand-sized silica grains, with the strata forming 20-30m tall mudstone clinoforms in contrast to the tabular stratal architecture of the 2WS strata. The mudstone aggregates are well preserved in the studied strata due to the relative shallow maximum burial of approximately 1500-2000m. The aggregates occur as silt- to sand-sized particles with different composition, with the oval shape indicating they are only slightly compacted and that they were semi-indurated at the time of deposition. Potential origin of the mudstone aggregates includes extrabasinal grains, and/or intrabasinal rip-up clasts, or crustacean micro-coprolite fragments. However, the presence of coccolith fragments within the aggregates clearly demonstrates that the majority of the mudstone aggregates are intraformational, however their variable composition from the surrounding matrix mud suggests transport a significant distance from their site of origin. Furthermore, significant abrupt vertical changes in the grain size of the mudstone aggregates and their chemical composition shows that the area of origin changes between dominantly intra-formation rip-up clasts to micro-coprolites, relating to relative sea level changes. However, as individual sequence stratigraphic units often have relative uniform composition of the mudstone aggregates, composition of the mudstone aggregates do not seem to be strongly related to water depth but rather changes in circulation within the Interior Seaway. Panel_15261 Panel_15261 1:40 PM 2:00 PM

Intervals of chert in the Mississippian carbonates of the Mid-Continent are primary reservoir targets, yet little is known about the origin of the chert or the controls on porosity development within them. The primary source of silica is generally thought to be from the dissolution of siliceous sponges, interpreted due to the presence of abundant spicules and spiculitic molds in many of the cherts. Further influx of silica into the system (volcanic ash or detrital quartz) may accelerate sponge productivity and thus help account for the abundance of chert found in these units. Chertification of carbonate was initiated by dissolution of biogenic amorphous silica and the subsequent precipitation of opal-CT and quartz. Carbonate replacement was achieved by a force of crystallization controlled replacement, where dissolution of carbonate material was driven by the precipitation of various silica phases. Dissolution of carbonate and silica, as well as the volumetric change from amorphous silica to quartz, created pore space in many of the cherts. Porosity abundance in the cherts is controlled by the relative rate of burial during deposition, as it controls the initial ratio of carbonate to spicules. Extremely slow burial resulted in minimal carbonate input, resulting in the dissolution and re-precipitation of spicules as nearly pure, non-porous cherts. Slow burial rates resulted in a higher percentage of spicules in the carbonate, allowing for nearly complete replacement of limestone by silica and forming abundant porosity in the rock. Faster burial increased the overall ratio of carbonate to spicules, effectively decreasing the volume of carbonate that could be replaced, resulting in a decrease in the total porosity. In outcrop, the variety of chert exhibits a strong correlation to the sequence stratigraphic framework. Overall, gradational changes from pure, to highly porous, to less porous cherts are observed vertically at multiple frequencies due to varying orders of sea level cyclicity. The link between chert variety, relative sea level fluctuation, and the observed sequence stratigraphic framework aids in explaining the controls on porosity distribution at both the 3rd and 4th order scales. Intervals of chert in the Mississippian carbonates of the Mid-Continent are primary reservoir targets, yet little is known about the origin of the chert or the controls on porosity development within them. The primary source of silica is generally thought to be from the dissolution of siliceous sponges, interpreted due to the presence of abundant spicules and spiculitic molds in many of the cherts. Further influx of silica into the system (volcanic ash or detrital quartz) may accelerate sponge productivity and thus help account for the abundance of chert found in these units. Chertification of carbonate was initiated by dissolution of biogenic amorphous silica and the subsequent precipitation of opal-CT and quartz. Carbonate replacement was achieved by a force of crystallization controlled replacement, where dissolution of carbonate material was driven by the precipitation of various silica phases. Dissolution of carbonate and silica, as well as the volumetric change from amorphous silica to quartz, created pore space in many of the cherts. Porosity abundance in the cherts is controlled by the relative rate of burial during deposition, as it controls the initial ratio of carbonate to spicules. Extremely slow burial resulted in minimal carbonate input, resulting in the dissolution and re-precipitation of spicules as nearly pure, non-porous cherts. Slow burial rates resulted in a higher percentage of spicules in the carbonate, allowing for nearly complete replacement of limestone by silica and forming abundant porosity in the rock. Faster burial increased the overall ratio of carbonate to spicules, effectively decreasing the volume of carbonate that could be replaced, resulting in a decrease in the total porosity. In outcrop, the variety of chert exhibits a strong correlation to the sequence stratigraphic framework. Overall, gradational changes from pure, to highly porous, to less porous cherts are observed vertically at multiple frequencies due to varying orders of sea level cyclicity. The link between chert variety, relative sea level fluctuation, and the observed sequence stratigraphic framework aids in explaining the controls on porosity distribution at both the 3rd and 4th order scales. Panel_15265 Panel_15265 2:00 PM 2:20 PM

The Arbuckle Mountains are a complex geologic province, characterized by thick sequences of intensely folded and faulted carbonates, sandstones, and shales of the Late Cambrian through Pennsylvanian. Cave, karst and paleokarst features occur in relatively high densities within several limestone and dolostone formations and play a significant role in the storage and transport of fluids in the subsurface. Knowing the origins, morphology and distribution of these karst features is necessary for understanding the karst porosity in production horizons in oil and gas fields. Traditionally, the origins and morphology of these karst features has been viewed as being epigenic, developing from the surface downward; however, recent studies have provided compelling evidence for a more complex evolutionary history for the carbonates. Analyses of more than 1,530 caves, karst and paleokarst features indicate that multiple physical and chemical processes may have taken place, with at least 70 of the features displaying classic signatures for having occurred as a result of hypogenic origins, developing from upwelling corrosive fluids. Hypogenic karst signatures can be found in caves throughout the Arbuckle Mountains, but occur most commonly in the regimes where deformation is most severe, such as the north flank of the Arbuckle anticline. However, there is evidence that hypogenic speleogenesis may have occurred on the south flank of the Arbuckle anticline where the semi-confining Simpson Group overlaid the upper Arbuckle Group, producing maze-like caves which are indicative of such processes. Hypogenic karst development appears to be continuing today where the soluble carbonates are overlain by confining units along the edges of the anticline where fresh and saline waters mix and microbial interactions with hydrocarbons provide the fluid geochemistry allowing carbonate dissolution. Hypogenic karst processes may also be responsible for the origin and development of cavities and conduits in these same formations, encountered during drilling in the deeper subsurface, that have otherwise been attributed to eogenetic processes during Paleozoic sea level fluctuations. The Arbuckle Mountains are a complex geologic province, characterized by thick sequences of intensely folded and faulted carbonates, sandstones, and shales of the Late Cambrian through Pennsylvanian. Cave, karst and paleokarst features occur in relatively high densities within several limestone and dolostone formations and play a significant role in the storage and transport of fluids in the subsurface. Knowing the origins, morphology and distribution of these karst features is necessary for understanding the karst porosity in production horizons in oil and gas fields. Traditionally, the origins and morphology of these karst features has been viewed as being epigenic, developing from the surface downward; however, recent studies have provided compelling evidence for a more complex evolutionary history for the carbonates. Analyses of more than 1,530 caves, karst and paleokarst features indicate that multiple physical and chemical processes may have taken place, with at least 70 of the features displaying classic signatures for having occurred as a result of hypogenic origins, developing from upwelling corrosive fluids. Hypogenic karst signatures can be found in caves throughout the Arbuckle Mountains, but occur most commonly in the regimes where deformation is most severe, such as the north flank of the Arbuckle anticline. However, there is evidence that hypogenic speleogenesis may have occurred on the south flank of the Arbuckle anticline where the semi-confining Simpson Group overlaid the upper Arbuckle Group, producing maze-like caves which are indicative of such processes. Hypogenic karst development appears to be continuing today where the soluble carbonates are overlain by confining units along the edges of the anticline where fresh and saline waters mix and microbial interactions with hydrocarbons provide the fluid geochemistry allowing carbonate dissolution. Hypogenic karst processes may also be responsible for the origin and development of cavities and conduits in these same formations, encountered during drilling in the deeper subsurface, that have otherwise been attributed to eogenetic processes during Paleozoic sea level fluctuations. Panel_15260 Panel_15260 2:20 PM 2:40 PM

An evaluation of the Three Forks Formation, to determine hydrocarbon potential, was performed in the Williston Basin of South Dakota using well logs from the South Dakota Geological Survey. Basin analysis included identification of upper and lower boundaries, extent, lithologic description, stratigraphic correlation, and hydrocarbon potential. Thickness of Three Forks rocks ranges from 0 to 170 feet, and was thickest in northern Perkins and Corson counties and thinned toward the basin margins. Lithologically, the rocks consisted primarily of interbedded shale and dolomitic limestone. Stratigraphically, Three Forks rocks occurred between the underlying Birdbear Formation and overlying Englewood Formation. In areas where the Englewood was absent, it was overlain by the Lodgepole Formation. In North Dakota, eastern Montana, and Canada, the Three Forks underlies the Bakken Formation, serving as a reservoir for Bakken shale oil. No Bakken rocks were identified in well logs from South Dakota and the Three Forks and other Late Devonian formations have been underexplored. Well log analysis revealed three previously unidentified potential subsurface structures in the Williston Basin of South Dakota. In addition, data have supported proposed southeastern extensions of the Cedar Creek Anticline and Sheep Mountain Syncline. Black shale, indicating areas of restricted water circulation, have been identified in the Three Forks, in limited areas of estimated maturity, that suggest ideal conditions for the preservation of organic matter. These areas were correlated using gamma-ray spikes and estimated TOC values from 1.4 to 5.6 wt. %, at depths Three Forks rocks would be expected to contain mature hydrocarbons. Based on estimated TOC values and associated thicknesses of TOC-bearing intervals, limited potential exists for Three Forks source and reservoir rock in northwestern South Dakota, particularly in northern Perkins and eastern Harding counties. An evaluation of the Three Forks Formation, to determine hydrocarbon potential, was performed in the Williston Basin of South Dakota using well logs from the South Dakota Geological Survey. Basin analysis included identification of upper and lower boundaries, extent, lithologic description, stratigraphic correlation, and hydrocarbon potential. Thickness of Three Forks rocks ranges from 0 to 170 feet, and was thickest in northern Perkins and Corson counties and thinned toward the basin margins. Lithologically, the rocks consisted primarily of interbedded shale and dolomitic limestone. Stratigraphically, Three Forks rocks occurred between the underlying Birdbear Formation and overlying Englewood Formation. In areas where the Englewood was absent, it was overlain by the Lodgepole Formation. In North Dakota, eastern Montana, and Canada, the Three Forks underlies the Bakken Formation, serving as a reservoir for Bakken shale oil. No Bakken rocks were identified in well logs from South Dakota and the Three Forks and other Late Devonian formations have been underexplored. Well log analysis revealed three previously unidentified potential subsurface structures in the Williston Basin of South Dakota. In addition, data have supported proposed southeastern extensions of the Cedar Creek Anticline and Sheep Mountain Syncline. Black shale, indicating areas of restricted water circulation, have been identified in the Three Forks, in limited areas of estimated maturity, that suggest ideal conditions for the preservation of organic matter. These areas were correlated using gamma-ray spikes and estimated TOC values from 1.4 to 5.6 wt. %, at depths Three Forks rocks would be expected to contain mature hydrocarbons. Based on estimated TOC values and associated thicknesses of TOC-bearing intervals, limited potential exists for Three Forks source and reservoir rock in northwestern South Dakota, particularly in northern Perkins and eastern Harding counties. Panel_15267 Panel_15267 2:40 PM 3:00 PM

Panel_15808 Panel_15808 3:00 PM 12:00 AM

The Skull Creek Formation is a fine-grained siliciclastic unit in the Cretaceous Dakota Group along the Front Range in the western US. Well-known for its storm-generated structures, the unit is sandwiched between two sandstone packages, the Plainview and underlying Lytle Formations below, and the overlying J sandstone. Current models interpret the Skull Creek Formation as late transgressive to early highstand sediments deposited in an offshore environment with a maximum flooding surface in its lower part. A detailed sedimentology of this unit, however, is still lacking despite its importance as a potential hydrocarbon source rock for the overlying well-explored J sandstones. In this study, the Skull Creek Formation is subdivided into three facies associations: a sandy portion characterized by sandy gutter casts lined with shale at their bases, combined flow ripples and HCS sandstones, a siltstone-dominated part with low-angle combined flow ripples, and a silt-rich and in places laminated mudstone with lenticular siltstone laminae. The level of bioturbation varies throughout the section and is generally better developed the coarser the grain size. The Skull Creek Formation is interpreted as an offshore environment subdivided into three depositional facies belts that are equivalent to the three facies associations: a proximal, sand-rich part that received abundant sediment input from nearshore settings during storms; an intermediate portion consisting of siltstones deposited above storm wave base but beyond the reach of sand-rich currents from the proximal shelf; and a distal environment showing relatively high-energy deposition during storms, with intermittent mudstone sedimentation during fair-weather. Filling of the gutter casts in the proximal facies, however, was most likely the result of two consecutive storms, the shale linings reflect waning energy after the scouring and prior to their infill with sand. Based on its stacking patterns the Skull Creek Formation reflects an initial transgression expressed in the fining-upward in the lower part of the unit. A weakly developed regression is reflected in an overall coarsening-upward and the presence of sand-rich gutter casts and HCS sandstones. Following a slight transgression the succession shallows until the overlying J sandstones reflected in a gradual increase in sand content. The Skull Creek Formation is a fine-grained siliciclastic unit in the Cretaceous Dakota Group along the Front Range in the western US. Well-known for its storm-generated structures, the unit is sandwiched between two sandstone packages, the Plainview and underlying Lytle Formations below, and the overlying J sandstone. Current models interpret the Skull Creek Formation as late transgressive to early highstand sediments deposited in an offshore environment with a maximum flooding surface in its lower part. A detailed sedimentology of this unit, however, is still lacking despite its importance as a potential hydrocarbon source rock for the overlying well-explored J sandstones. In this study, the Skull Creek Formation is subdivided into three facies associations: a sandy portion characterized by sandy gutter casts lined with shale at their bases, combined flow ripples and HCS sandstones, a siltstone-dominated part with low-angle combined flow ripples, and a silt-rich and in places laminated mudstone with lenticular siltstone laminae. The level of bioturbation varies throughout the section and is generally better developed the coarser the grain size. The Skull Creek Formation is interpreted as an offshore environment subdivided into three depositional facies belts that are equivalent to the three facies associations: a proximal, sand-rich part that received abundant sediment input from nearshore settings during storms; an intermediate portion consisting of siltstones deposited above storm wave base but beyond the reach of sand-rich currents from the proximal shelf; and a distal environment showing relatively high-energy deposition during storms, with intermittent mudstone sedimentation during fair-weather. Filling of the gutter casts in the proximal facies, however, was most likely the result of two consecutive storms, the shale linings reflect waning energy after the scouring and prior to their infill with sand. Based on its stacking patterns the Skull Creek Formation reflects an initial transgression expressed in the fining-upward in the lower part of the unit. A weakly developed regression is reflected in an overall coarsening-upward and the presence of sand-rich gutter casts and HCS sandstones. Following a slight transgression the succession shallows until the overlying J sandstones reflected in a gradual increase in sand content. Panel_15266 Panel_15266 3:25 PM 3:45 PM

Detailed, regional sequence-stratigraphic correlation and growth-strata analysis support a complex spatio-temporal overlap in structural style during the Sevier-Laramide transition, and a general NE-younging trend in Laramide uplifts that mirror Shatsky Rise subduction. In the western margin of the Uinta basin, Cenomanian- Turonian syntectonic unconformities in the Sanpete Fm., and locally-shoaling shoreface lithofacies in the lower Funk Valley Fm. indicate incipient, thrust-propagation folding in Thistle, UT at ~95-92 Ma. These structures later formed part of the Santaquin Culmination at ~85-80 Ma, pinning the margin of the Sevier Fold-thrust belt in Central Utah. In the south-central Uinta Basin, Campanian intrabasinal stratal thinning and syntectonic unconformity development in the Mesaverde Grp indicates Laramide-style uplift of the San Rafael Swell at ~77-80 Ma. In the northeastern and northwestern parts of Uinta Basin, Campanian thinning trends outline two sites of incipient topography associated with Uinta Uplift at ~75 Ma. The 2 Campanian structures linked laterally forming the Uinta Uplift in the late Campanian to early Maastrichtian; this is consistent with a well-formed, East-West trending, stratal thick that parallels the southern boundary of the Uinta Uplift at ~73 Ma. At the Uinta-Piceance Basin boundary a thinning trend in the lower Williams Fork Fm. (~73 Ma) followed by stratal truncation and growth-strata development in the upper Williams Fork Fm. (~72 Ma) across the Douglas Creek Arch, indicates Campanian-Maastrichtian aged Laramide-style uplift in the Piceance Basin. In the Denver Basin, syntectonic unconformities in the Denver-Dawson formations indicate early Paleocene (~67 Ma) uplift of the south-central Colorado Front Range. Detailed, regional sequence-stratigraphic correlation and growth-strata analysis support a complex spatio-temporal overlap in structural style during the Sevier-Laramide transition, and a general NE-younging trend in Laramide uplifts that mirror Shatsky Rise subduction. In the western margin of the Uinta basin, Cenomanian- Turonian syntectonic unconformities in the Sanpete Fm., and locally-shoaling shoreface lithofacies in the lower Funk Valley Fm. indicate incipient, thrust-propagation folding in Thistle, UT at ~95-92 Ma. These structures later formed part of the Santaquin Culmination at ~85-80 Ma, pinning the margin of the Sevier Fold-thrust belt in Central Utah. In the south-central Uinta Basin, Campanian intrabasinal stratal thinning and syntectonic unconformity development in the Mesaverde Grp indicates Laramide-style uplift of the San Rafael Swell at ~77-80 Ma. In the northeastern and northwestern parts of Uinta Basin, Campanian thinning trends outline two sites of incipient topography associated with Uinta Uplift at ~75 Ma. The 2 Campanian structures linked laterally forming the Uinta Uplift in the late Campanian to early Maastrichtian; this is consistent with a well-formed, East-West trending, stratal thick that parallels the southern boundary of the Uinta Uplift at ~73 Ma. At the Uinta-Piceance Basin boundary a thinning trend in the lower Williams Fork Fm. (~73 Ma) followed by stratal truncation and growth-strata development in the upper Williams Fork Fm. (~72 Ma) across the Douglas Creek Arch, indicates Campanian-Maastrichtian aged Laramide-style uplift in the Piceance Basin. In the Denver Basin, syntectonic unconformities in the Denver-Dawson formations indicate early Paleocene (~67 Ma) uplift of the south-central Colorado Front Range. Panel_15258 Panel_15258 3:45 PM 4:05 PM

The Codell Sandstone Member of the Carlile Shale is a complex stratigraphic succession preserved within and south of the Denver Basin. Evidence for large-scale basinward migration of the shoreline in the Turonian is interpreted from facies and isotope study of this unit. The Codell Sandstone Member is the terminal unit in the well-studied Greenhorn regressive hemicyclothem of Kauffman, and records an overall upward-shallowing depositional facies trend. This unit was revisited to determine the magnitude of sea level fall during this regressive event, and the extent of strandline migration associated with the fall. This was done through facies interpretation of key stratigraphic sections (outcrop and subsurface) and strontium analysis of the strata bracketing this interval. Outcrops and core studied were deposited near the axis of the Cretaceous Western Interior Seaway. Two distinct facies are interpreted within the Codell Sandstone Member: an upward–coarsening unit interpreted as distal lower shoreface facies at the base of the member and an estuarine facies association at the top of the member. The estuarine facies association is composed of complex relationships of bioturbated, heterolithic, channelized, and deltaic facies. The surface separating the lower shoreface facies and estuarine facies association is interpreted as a sequence boundary and the base of a 10 meter thick incised valley fill exposed near Pueblo, Colorado. 87 Sr/86Sr ratio analyses from unaltered shell material show an isotopic excursion within the estuarine facies, which is attributed to freshwater input. Facies interpretation and isotopic analysis places the lowstand shoreline for the Codell Sandstone Member west of Pueblo, Colorado. The time equivalent shoreline for the highstand (lower shoreface) strata of the Codell Sandstone Member is placed between central Kansas and central Missouri, 700 to 1100 km east of the study area. Brackish-water strata of the incised valley fill would require a minimum of 700 km of lateral translation of the eastern margin of the Cretaceous Western Interior Seaway during deposition of the Codell Sandstone Member. This westward shift in the eastern shoreline resulted from a sea level fall that could have been as little as 30-60 meters. Such a significant seaward translation in shoreline position associated with a sea level fall of this magnitude suggests that the sea floor along the eastern margin of the Seaway was of low gradient over large distances. The Codell Sandstone Member of the Carlile Shale is a complex stratigraphic succession preserved within and south of the Denver Basin. Evidence for large-scale basinward migration of the shoreline in the Turonian is interpreted from facies and isotope study of this unit. The Codell Sandstone Member is the terminal unit in the well-studied Greenhorn regressive hemicyclothem of Kauffman, and records an overall upward-shallowing depositional facies trend. This unit was revisited to determine the magnitude of sea level fall during this regressive event, and the extent of strandline migration associated with the fall. This was done through facies interpretation of key stratigraphic sections (outcrop and subsurface) and strontium analysis of the strata bracketing this interval. Outcrops and core studied were deposited near the axis of the Cretaceous Western Interior Seaway. Two distinct facies are interpreted within the Codell Sandstone Member: an upward–coarsening unit interpreted as distal lower shoreface facies at the base of the member and an estuarine facies association at the top of the member. The estuarine facies association is composed of complex relationships of bioturbated, heterolithic, channelized, and deltaic facies. The surface separating the lower shoreface facies and estuarine facies association is interpreted as a sequence boundary and the base of a 10 meter thick incised valley fill exposed near Pueblo, Colorado. 87 Sr/86Sr ratio analyses from unaltered shell material show an isotopic excursion within the estuarine facies, which is attributed to freshwater input. Facies interpretation and isotopic analysis places the lowstand shoreline for the Codell Sandstone Member west of Pueblo, Colorado. The time equivalent shoreline for the highstand (lower shoreface) strata of the Codell Sandstone Member is placed between central Kansas and central Missouri, 700 to 1100 km east of the study area. Brackish-water strata of the incised valley fill would require a minimum of 700 km of lateral translation of the eastern margin of the Cretaceous Western Interior Seaway during deposition of the Codell Sandstone Member. This westward shift in the eastern shoreline resulted from a sea level fall that could have been as little as 30-60 meters. Such a significant seaward translation in shoreline position associated with a sea level fall of this magnitude suggests that the sea floor along the eastern margin of the Seaway was of low gradient over large distances. Panel_15262 Panel_15262 4:05 PM 4:25 PM

Nearly continuous sections of Upper Cretaceous Sevier foreland basin strata are exposed in outcrop throughout parts of southern New Mexico. Here, Cenomanian–lower Campanian stratigraphy are defined from base-to-top by (1) fluvial and shoreline deposits of the Dakota Sandstone, (2) lower- and upper-offshore deposits of the Mancos Shale (Tokay Tongue) and Bridge Creek Limestone and Sandstone Members, (3) shoreline deposits of the Atarque Sandstone Member and fluvial strata of the Tres Hermanos Formation, (4) lower- and upper-offshore strata of the D-Cross Tongue of the Mancos Shale and lower shoreface and shoreline strata of the Gallup Sandstone, and (5) fluvial strata of the Crevasse Canyon Formation. Presented here are new sedimentologic data from the Coniacian–lower Campanian Crevasse Canyon Formation and new provenance data (sandstone modal composition and U-Pb detrital zircon geochronology) from nonmarine parts of the Dakota Sandstone, Tres Hermanos Formation, and Crevasse Canyon Formation. New sedimentary facies and architectural element analysis from the Crevasse Canyon Formation reveal an upsection transition from more meandering to braided stratigraphic architectures. The lower member of the Crevasse Canyon Formation is thought to be Coniacian–Santonian in age and is characterized by lenticular (channel) sandstone units that exhibit well-developed lateral accretion surfaces. Lenticular units are bound by tabular sandstone and pedogenically-altered mudstone deposits that are interpreted to represent floodplain crevasse splay sedimentation and paleosol development, respectively. The upper part of the Crevasse Canyon Formation (Ash Canyon Member) is thought to be lower Campanian in age and consists primarily of amalgamated lenticular sandstone units that are interpreted to represent a braided channel complex. Trends in detrital modes from the Dakota Sandstone,Tres Hermanos, and Crevasse Canyon Formations show an upsection transition from more quartz-dominated to more lithic-dominated compositions. The basal Dakota Sandstone has a higher relative abundance of quartz compared to the Tres Hermanos and Crevasse Canyon Formations, each of which have higher relative abundances of lithic volcanic fragments and feldspar. New sedimentologic and provenance data from Upper Cretaceous strata in southern New Mexico provide a means for testing trends in exhumation and sediment dispersal along the southern margin of the Sevier foreland basin. Nearly continuous sections of Upper Cretaceous Sevier foreland basin strata are exposed in outcrop throughout parts of southern New Mexico. Here, Cenomanian–lower Campanian stratigraphy are defined from base-to-top by (1) fluvial and shoreline deposits of the Dakota Sandstone, (2) lower- and upper-offshore deposits of the Mancos Shale (Tokay Tongue) and Bridge Creek Limestone and Sandstone Members, (3) shoreline deposits of the Atarque Sandstone Member and fluvial strata of the Tres Hermanos Formation, (4) lower- and upper-offshore strata of the D-Cross Tongue of the Mancos Shale and lower shoreface and shoreline strata of the Gallup Sandstone, and (5) fluvial strata of the Crevasse Canyon Formation. Presented here are new sedimentologic data from the Coniacian–lower Campanian Crevasse Canyon Formation and new provenance data (sandstone modal composition and U-Pb detrital zircon geochronology) from nonmarine parts of the Dakota Sandstone, Tres Hermanos Formation, and Crevasse Canyon Formation. New sedimentary facies and architectural element analysis from the Crevasse Canyon Formation reveal an upsection transition from more meandering to braided stratigraphic architectures. The lower member of the Crevasse Canyon Formation is thought to be Coniacian–Santonian in age and is characterized by lenticular (channel) sandstone units that exhibit well-developed lateral accretion surfaces. Lenticular units are bound by tabular sandstone and pedogenically-altered mudstone deposits that are interpreted to represent floodplain crevasse splay sedimentation and paleosol development, respectively. The upper part of the Crevasse Canyon Formation (Ash Canyon Member) is thought to be lower Campanian in age and consists primarily of amalgamated lenticular sandstone units that are interpreted to represent a braided channel complex. Trends in detrital modes from the Dakota Sandstone,Tres Hermanos, and Crevasse Canyon Formations show an upsection transition from more quartz-dominated to more lithic-dominated compositions. The basal Dakota Sandstone has a higher relative abundance of quartz compared to the Tres Hermanos and Crevasse Canyon Formations, each of which have higher relative abundances of lithic volcanic fragments and feldspar. New sedimentologic and provenance data from Upper Cretaceous strata in southern New Mexico provide a means for testing trends in exhumation and sediment dispersal along the southern margin of the Sevier foreland basin. Panel_15259 Panel_15259 4:25 PM 4:45 PM

The Paleocene Fort Union Formation in the eastern Greater Green River Basin is a thick succession of shale, sandstone, coal, and siltstone, deposited as syn-orogenic Laramide basin fill. Recent production from the Washakie Basin has demonstrated the viability of the Fort Union Formation as a productive gas reservoir, especially with improved horizontal drilling technology. This begs the question: are there other potentially analogous Fort Union reservoirs that have been overlooked elsewhere in the eastern Greater Green River Basin? In the case of the Washakie Basin, wet gas is produced from the China Butte Member of the Fort Union Formation. This basal member has numerous coal seams interbedded with lenticular sandstones. Gas is believed to be derived in situ, as well as from the deeper Cretaceous-age formations. Production is from approximately 3,048 m (10,000 ft) TVD. Burial history curve analyses and vitrinite reflectance extrapolation suggests 975 m (3,200 ft) of Neogene erosion, reflecting condensate generation at less than 4,023 m (13,200 ft) burial depth (geothermal gradients in this region are not elevated). Regional correlations of the China Butte Member show the succession of coals thickens into the Great Divide Basin, where no Fort Union production is occurring and no drill stem tests are publicly available. Mud logs from wells drilled into the deeper Cretaceous formations show methane gas spikes associated with the China Butte Member, but this coal-rich interval is at maximum depths of approximately 914 to 1,829 m (3,000 to 6,000 ft) TVD. Extrapolation of vitrinite reflectance results suggests 1,676 to 2,103 m (5,500 to 6,900 ft) of Neogene erosion in the Great Divide Basin, placing the China Butte Member at maximum burial depths just shy of those required for in-situ condensate generation in the Washakie Basin. Furthermore, vitrinite reflectance measured from a handful of Fort Union Formation samples in the Great Divide Basin record values approximately 0.4 to 0.7% Ro, significantly less than the >1.2% values from the Washakie Basin. Preliminary data suggest that although Fort Union Formation coals may not have reached maximum burial depths sufficient for condensate generation in the Great Divide Basin, this coal-rich interval may be methane saturated, at least in places, and could be worth a second look. The Paleocene Fort Union Formation in the eastern Greater Green River Basin is a thick succession of shale, sandstone, coal, and siltstone, deposited as syn-orogenic Laramide basin fill. Recent production from the Washakie Basin has demonstrated the viability of the Fort Union Formation as a productive gas reservoir, especially with improved horizontal drilling technology. This begs the question: are there other potentially analogous Fort Union reservoirs that have been overlooked elsewhere in the eastern Greater Green River Basin? In the case of the Washakie Basin, wet gas is produced from the China Butte Member of the Fort Union Formation. This basal member has numerous coal seams interbedded with lenticular sandstones. Gas is believed to be derived in situ, as well as from the deeper Cretaceous-age formations. Production is from approximately 3,048 m (10,000 ft) TVD. Burial history curve analyses and vitrinite reflectance extrapolation suggests 975 m (3,200 ft) of Neogene erosion, reflecting condensate generation at less than 4,023 m (13,200 ft) burial depth (geothermal gradients in this region are not elevated). Regional correlations of the China Butte Member show the succession of coals thickens into the Great Divide Basin, where no Fort Union production is occurring and no drill stem tests are publicly available. Mud logs from wells drilled into the deeper Cretaceous formations show methane gas spikes associated with the China Butte Member, but this coal-rich interval is at maximum depths of approximately 914 to 1,829 m (3,000 to 6,000 ft) TVD. Extrapolation of vitrinite reflectance results suggests 1,676 to 2,103 m (5,500 to 6,900 ft) of Neogene erosion in the Great Divide Basin, placing the China Butte Member at maximum burial depths just shy of those required for in-situ condensate generation in the Washakie Basin. Furthermore, vitrinite reflectance measured from a handful of Fort Union Formation samples in the Great Divide Basin record values approximately 0.4 to 0.7% Ro, significantly less than the >1.2% values from the Washakie Basin. Preliminary data suggest that although Fort Union Formation coals may not have reached maximum burial depths sufficient for condensate generation in the Great Divide Basin, this coal-rich interval may be methane saturated, at least in places, and could be worth a second look. Panel_15264 Panel_15264 4:45 PM 5:05 PM