Monday, 1 June - Oral Sessions

  Technical Program   >   Technical Program   >   Monday, 1 June - Oral Sessions

8:00 a.m.–11:50 a.m.
Theme 1: Pore Systems in Unconventional Reservoirs (AAPG/EMD)
Four Seasons Ballroom 1, Monday Oral Sessions, 01 June, 2015

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Panel_14428 Panel_14428 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Four Seasons Ballroom 1
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Panel_15778 Panel_15778 8:00 AM 9:00 AM
8:05 a.m.
Compositional Classification for Fine-Grained Sediments and Sedimentary Rocks: Foundation for Bulk Rock Property Prediction
Four Seasons Ballroom 1
In fine-grained sediments and rocks (>50 percent weight or volume of particles less than 62.5 µm) the primary grain assemblage reflects grain generation processes at deposition and is also an important control on the evolution of bulk rock properties in diagenesis. As in classifications for sandstones and limestones, the primary grain assemblage is a practical basis for classification of fine-grained materials. Tarl (terrigenous-argillaceous) refers to a grain assemblage with >75 percent of particles of extrabasinal derivation, including grains derived from continental weathering and also volcanogenic debris. Carl (calcareous-argillaceous) contains <75 percent of extrabasinal particles and among intrabasinal grains has a preponderance of biogenic carbonate particles including carbonate aggregates. Sarl (siliceous-argillaceous) contains <75 percent of extrabasinal particles and has a preponderance of biogenic siliceous particles over carbonate grains. These classes separate sediments of distinct depositional settings and contrasting organic matter content and minor grain types. Tarls dominate in thick mudrock successions characterized by high rates of sediment accumulation and typically contain little organic matter, much of it terrestrial. Carls and sarls are generally associated with thinner successions. The slower rates of accumulation for carls and sarls tend to favor generation of intrabasinal particles such as sediment aggregates (intraclasts, pellets, agglutinated allochems, etc.) and phosphatic debris. If organic-rich, carls and sarls tend to contain organic matter that originated in the water column. In the subsurface, tarls are relatively unreactive and only manifest significant reaction of the grain assemblage at elevated temperatures (>80° C). Under ordinary geothermal gradients tarls tend to remain unconsolidated until approximately 2 km of burial or more. In contrast carls and sarls contain chemically unstable grain assemblages (including labile organic matter) prone to react with pore fluids early in burial. Reactive grain assemblages in carls and sarls cause cementation and the generation of brittle rock properties relatively early in the burial history. Classification based on the grain assemblage is only the beginning of a complete rock description, but constitutes a valuable foundation for placing samples into the larger stratigraphic context and for making predictions about the post-depositional evolution of bulk rock properties. In fine-grained sediments and rocks (>50 percent weight or volume of particles less than 62.5 µm) the primary grain assemblage reflects grain generation processes at deposition and is also an important control on the evolution of bulk rock properties in diagenesis. As in classifications for sandstones and limestones, the primary grain assemblage is a practical basis for classification of fine-grained materials. Tarl (terrigenous-argillaceous) refers to a grain assemblage with >75 percent of particles of extrabasinal derivation, including grains derived from continental weathering and also volcanogenic debris. Carl (calcareous-argillaceous) contains <75 percent of extrabasinal particles and among intrabasinal grains has a preponderance of biogenic carbonate particles including carbonate aggregates. Sarl (siliceous-argillaceous) contains <75 percent of extrabasinal particles and has a preponderance of biogenic siliceous particles over carbonate grains. These classes separate sediments of distinct depositional settings and contrasting organic matter content and minor grain types. Tarls dominate in thick mudrock successions characterized by high rates of sediment accumulation and typically contain little organic matter, much of it terrestrial. Carls and sarls are generally associated with thinner successions. The slower rates of accumulation for carls and sarls tend to favor generation of intrabasinal particles such as sediment aggregates (intraclasts, pellets, agglutinated allochems, etc.) and phosphatic debris. If organic-rich, carls and sarls tend to contain organic matter that originated in the water column. In the subsurface, tarls are relatively unreactive and only manifest significant reaction of the grain assemblage at elevated temperatures (>80° C). Under ordinary geothermal gradients tarls tend to remain unconsolidated until approximately 2 km of burial or more. In contrast carls and sarls contain chemically unstable grain assemblages (including labile organic matter) prone to react with pore fluids early in burial. Reactive grain assemblages in carls and sarls cause cementation and the generation of brittle rock properties relatively early in the burial history. Classification based on the grain assemblage is only the beginning of a complete rock description, but constitutes a valuable foundation for placing samples into the larger stratigraphic context and for making predictions about the post-depositional evolution of bulk rock properties. Panel_14939 Panel_14939 8:05 AM 8:25 AM
8:25 a.m.
Stratigraphic Controls on Diagenetic Processes in Mudstones From the Upper Cretaceous of the North American Western Interior Seaway: Implications for Source Rocks and Unconventional Reservoir Quality
Four Seasons Ballroom 1
Diagenesis exerts a major control on the ultimate organic carbon contents and mechanical properties of mudstones by controlling organic carbon degradation pathways and cementation histories. Diagenetic processes therefore strongly impact hydrocarbon source and unconventional reservoir attributes. Recent studies suggest that in mudstones much diagenesis occurs prior to compaction and is intimately associated with processes occurring close to sediment water interface. Here we investigate how pre-compaction diagenetic processes are controlled by stratigraphic setting and how varying sediment starting compositions effect subsequent chemical transformations. Using our existing high-resolution stratigraphic framework erected for Cenomanian-Turonian aged sediments preserved in the Mid-Cretaceous Seaway as a natural laboratory the diagenesis within coeval sediment packages preserved in both proximal clastic detritus sediment rich locations and more distal production detritus rich settings were investigated. The data to inform this study were obtained using a combination of petrographic (optical and electron optical techniques) and geochemical techniques (XRD, total organic carbon (TOC)) methods. Mudstones collected from clastic detritus-rich environments are thin bedded siliciclastic medium to coarse mudstones with framework materials composed of quartz, and a matrix dominated by clay minerals. These mudstones are relatively depleted in biogenic debris, contain up to 2% (TOC) and contain framboidal pyrite and carbonate cements. The latter either infill the bulk of the intergranular volume close to stratal surfaces or former patchy cements infilling intragranular pore space. In contrast, those in production detritus-rich successions comprise thin-bedded calcareous medium to coarse mudstones, enriched in planktonic foraminifer (framework component), with up to 5% TOC, and some framboidal pyrite. These mudstones also contain significant volumes of calcite, kaolinite and silica cements that infill available pore space. The varying composition of these assemblages indicates that microbial degradation processes acting in pre-compaction pore waters strongly control diagenetic reactions that follow with key regional differences being generated by varying starting composition of the sediment (particular the varying availability of metastable biogenic detritus). Diagenesis is significantly influenced by stratigraphic setting and cannot be treated as a fixed variable. Diagenesis exerts a major control on the ultimate organic carbon contents and mechanical properties of mudstones by controlling organic carbon degradation pathways and cementation histories. Diagenetic processes therefore strongly impact hydrocarbon source and unconventional reservoir attributes. Recent studies suggest that in mudstones much diagenesis occurs prior to compaction and is intimately associated with processes occurring close to sediment water interface. Here we investigate how pre-compaction diagenetic processes are controlled by stratigraphic setting and how varying sediment starting compositions effect subsequent chemical transformations. Using our existing high-resolution stratigraphic framework erected for Cenomanian-Turonian aged sediments preserved in the Mid-Cretaceous Seaway as a natural laboratory the diagenesis within coeval sediment packages preserved in both proximal clastic detritus sediment rich locations and more distal production detritus rich settings were investigated. The data to inform this study were obtained using a combination of petrographic (optical and electron optical techniques) and geochemical techniques (XRD, total organic carbon (TOC)) methods. Mudstones collected from clastic detritus-rich environments are thin bedded siliciclastic medium to coarse mudstones with framework materials composed of quartz, and a matrix dominated by clay minerals. These mudstones are relatively depleted in biogenic debris, contain up to 2% (TOC) and contain framboidal pyrite and carbonate cements. The latter either infill the bulk of the intergranular volume close to stratal surfaces or former patchy cements infilling intragranular pore space. In contrast, those in production detritus-rich successions comprise thin-bedded calcareous medium to coarse mudstones, enriched in planktonic foraminifer (framework component), with up to 5% TOC, and some framboidal pyrite. These mudstones also contain significant volumes of calcite, kaolinite and silica cements that infill available pore space. The varying composition of these assemblages indicates that microbial degradation processes acting in pre-compaction pore waters strongly control diagenetic reactions that follow with key regional differences being generated by varying starting composition of the sediment (particular the varying availability of metastable biogenic detritus). Diagenesis is significantly influenced by stratigraphic setting and cannot be treated as a fixed variable. Panel_14935 Panel_14935 8:25 AM 8:45 AM
8:45 a.m.
Quantification of Organic Nano-Pores Using a Helium Ion Microscope
Four Seasons Ballroom 1
Scanning electron microscopy of ion polished samples has become a common way to estimate porosity and organic matter content within shale resource rocks. Since quantitative SEM analysis has emerged as a means for assessing the porosity of shale rock, a common goal has been to image polished samples at extremely high resolutions. Since nano-pores are visible at pixel resolutions ranging from 5-10 nm, it is natural to consider the possibility of a pore regime below 5 nm which could contribute a significant amount to the total porosity of the system. When considering that a molecule of methane gas is on the order of 0.4 nm diameter, these 5 nm pores could be significant transport pathways in a reservoir. These nano-pores are a significant source of porosity within certain organic matter bodies, where total detectable pores using SEM (i.e., ~10 nm pore body diameter and up) can comprise up to 50 percent or more of the original volume of organic matter present. With the potential to examine the population of pores below ~10nm in diameter using the helium ion microscope, it is possible to construct a rock model that is more representative of the varied pore size regimes present. In this study, 12 organic shale samples were selected for systematic imaging using the Carl Zeiss Orion helium ion microscope. These samples were chosen based on examination of previously completed imaging using Carl Zeiss Auriga FESEM, and were selected due to the presence of porous and non-porous organic matter. Prior to SEM imaging, the samples had been ion-polished using a Gatan argon ion polishing system. The previously completed set of SEM images were acquired with a pixel resolution of 10 nm. Samples were imaged in the helium ion system using varying parameters in order to optimize image quality. Field of view and resolution were selected and increased as appropriate, with each acquired image matching a subset of an extant SEM image to allow for a direct comparison of grayscale, resolution, and volume percentage of various materials. The smallest pixel size of these images was 0.5nm. After careful and consistent segmentation, it was concluded that most samples had no significant pore fraction below the detection threshold of conventional FESEM imaging. The advanced resolution capabilities of the helium ion beam provide much sharper definition of pore boundaries but the total volume of these <10nm diameter pores in most samples was negligible. Scanning electron microscopy of ion polished samples has become a common way to estimate porosity and organic matter content within shale resource rocks. Since quantitative SEM analysis has emerged as a means for assessing the porosity of shale rock, a common goal has been to image polished samples at extremely high resolutions. Since nano-pores are visible at pixel resolutions ranging from 5-10 nm, it is natural to consider the possibility of a pore regime below 5 nm which could contribute a significant amount to the total porosity of the system. When considering that a molecule of methane gas is on the order of 0.4 nm diameter, these 5 nm pores could be significant transport pathways in a reservoir. These nano-pores are a significant source of porosity within certain organic matter bodies, where total detectable pores using SEM (i.e., ~10 nm pore body diameter and up) can comprise up to 50 percent or more of the original volume of organic matter present. With the potential to examine the population of pores below ~10nm in diameter using the helium ion microscope, it is possible to construct a rock model that is more representative of the varied pore size regimes present. In this study, 12 organic shale samples were selected for systematic imaging using the Carl Zeiss Orion helium ion microscope. These samples were chosen based on examination of previously completed imaging using Carl Zeiss Auriga FESEM, and were selected due to the presence of porous and non-porous organic matter. Prior to SEM imaging, the samples had been ion-polished using a Gatan argon ion polishing system. The previously completed set of SEM images were acquired with a pixel resolution of 10 nm. Samples were imaged in the helium ion system using varying parameters in order to optimize image quality. Field of view and resolution were selected and increased as appropriate, with each acquired image matching a subset of an extant SEM image to allow for a direct comparison of grayscale, resolution, and volume percentage of various materials. The smallest pixel size of these images was 0.5nm. After careful and consistent segmentation, it was concluded that most samples had no significant pore fraction below the detection threshold of conventional FESEM imaging. The advanced resolution capabilities of the helium ion beam provide much sharper definition of pore boundaries but the total volume of these <10nm diameter pores in most samples was negligible. Panel_14933 Panel_14933 8:45 AM 9:05 AM
9:05 a.m.
Thermal Conductivity of Organic Shales and Coals – How Their Presence and Persistence Effect Thermal Maturity
Four Seasons Ballroom 1
Mature source-rock intervals commonly act as thermal insulators to heat flow and can be identified by the first derivative of a wireline temperature log. When displayed in a cross section, the first derivative curve readily identifies intervals where the temperature curve flattens (insulators) and steepens (conductors). The lithologic control of thermal conductivity is so strong that stratigraphy can be easily correlated using only the first derivative curve. The first derivate correlates strongly to the sonic curve in mature source rock intervals; the sonic curve shows slow velocities and the first derivative indicates flattening of the temperature curve. Because thermal gradient increases at capillary seals, they can be readily identified on first derivative curves. While it is important to identify the insulating lithologies, it is equally important to identify their persistence through time as this can profoundly affect the thermal maturity of underlying source rocks. The burial and exhumation history of the Front Range from southeastern Wyoming to the Monument Hill area of Colorado provides an example of how the pre-Oligocene erosion of nearly 2500 to 3000 feet of Paleocene section including the Arapahoe, Denver, and Dawson formations can affect the thermal maturity of source rocks such as the Niobrara or other lower Cretaceous organic shales. While it appears that the Wattenberg geothermal anomaly controls where the Niobrara is highly thermally mature, the areas where the Niobrara is anomalously immature may be a function of the erosion of the Paleocene thermal insulator prior to the Oligocene. Mature source-rock intervals commonly act as thermal insulators to heat flow and can be identified by the first derivative of a wireline temperature log. When displayed in a cross section, the first derivative curve readily identifies intervals where the temperature curve flattens (insulators) and steepens (conductors). The lithologic control of thermal conductivity is so strong that stratigraphy can be easily correlated using only the first derivative curve. The first derivate correlates strongly to the sonic curve in mature source rock intervals; the sonic curve shows slow velocities and the first derivative indicates flattening of the temperature curve. Because thermal gradient increases at capillary seals, they can be readily identified on first derivative curves. While it is important to identify the insulating lithologies, it is equally important to identify their persistence through time as this can profoundly affect the thermal maturity of underlying source rocks. The burial and exhumation history of the Front Range from southeastern Wyoming to the Monument Hill area of Colorado provides an example of how the pre-Oligocene erosion of nearly 2500 to 3000 feet of Paleocene section including the Arapahoe, Denver, and Dawson formations can affect the thermal maturity of source rocks such as the Niobrara or other lower Cretaceous organic shales. While it appears that the Wattenberg geothermal anomaly controls where the Niobrara is highly thermally mature, the areas where the Niobrara is anomalously immature may be a function of the erosion of the Paleocene thermal insulator prior to the Oligocene. Panel_14934 Panel_14934 9:05 AM 9:25 AM
9:25 a.m.
Break
Four Seasons Ballroom 1
Panel_15779 Panel_15779 9:25 AM 12:00 AM
10:10 a.m.
Diagenetic Evolution of Organic Matter Cements in Unconventional Shale Reservoirs
Four Seasons Ballroom 1
Organic matter cements in the form of bitumen and pyrobitumen are commonly observed in scanning electron microscopic images in many U.S. unconventional shale reservoirs that range in age from Cretaceous to Ordovician. Organic matter cements are distinguished from kerogen based on petrographic identification of cement as a void-filling material within matrix pores, microfossil internal voids, and microfractures. The character of organic matter cements and the impact on reservoir quality changes with increasing thermal maturity as illustrated by the organic-rich interval of the lower Eagle Ford Formation in south Texas. In thermally immature (<0.50%Ro) outcrops of the Boquillas (Eagle Ford) Formation, meniscus-type organic matter cements partially fill interparticle pores within coccolith-rich lamina. The origin of this organic matter cement is interpreted as pre-oil generation bitumen created at the initial stage during the conversion of kerogen to oil. In the subsurface, migrated residual oil (migra-bitumen) fills matrix pores and foraminifera chambers forming solid organic matter plugs that may serve to form updip lateral seals along the updip edge of the oil window. This soluble bitumen may be partially removed by hot solvent (toluene) during Dean Stark extraction on crushed rock samples (GRI method), that could result in overly optimistic porosity measurements. Down dip at higher thermal maturity (>1.0%Ro), organic matter cements in the form of pyrobitumen develop a well-connected secondary porosity network, often mistakenly described as “kerogen” porosity. The organic matter pores are interpreted to form as a result of gas generation during the thermal cracking of oil retained within primary matrix pores preserved prior to oil generation and migration. Mineral cements observed within foraminifera chambers (e.g. calcite, quartz, kaolinite) predate the surrounding organic matter cement. This relationship suggests that mineral cementation may be terminated during primary oil migration as oil replaces water expelled from primary pores within the source rock. Organic matter cements in the form of bitumen and pyrobitumen are commonly observed in scanning electron microscopic images in many U.S. unconventional shale reservoirs that range in age from Cretaceous to Ordovician. Organic matter cements are distinguished from kerogen based on petrographic identification of cement as a void-filling material within matrix pores, microfossil internal voids, and microfractures. The character of organic matter cements and the impact on reservoir quality changes with increasing thermal maturity as illustrated by the organic-rich interval of the lower Eagle Ford Formation in south Texas. In thermally immature (<0.50%Ro) outcrops of the Boquillas (Eagle Ford) Formation, meniscus-type organic matter cements partially fill interparticle pores within coccolith-rich lamina. The origin of this organic matter cement is interpreted as pre-oil generation bitumen created at the initial stage during the conversion of kerogen to oil. In the subsurface, migrated residual oil (migra-bitumen) fills matrix pores and foraminifera chambers forming solid organic matter plugs that may serve to form updip lateral seals along the updip edge of the oil window. This soluble bitumen may be partially removed by hot solvent (toluene) during Dean Stark extraction on crushed rock samples (GRI method), that could result in overly optimistic porosity measurements. Down dip at higher thermal maturity (>1.0%Ro), organic matter cements in the form of pyrobitumen develop a well-connected secondary porosity network, often mistakenly described as “kerogen” porosity. The organic matter pores are interpreted to form as a result of gas generation during the thermal cracking of oil retained within primary matrix pores preserved prior to oil generation and migration. Mineral cements observed within foraminifera chambers (e.g. calcite, quartz, kaolinite) predate the surrounding organic matter cement. This relationship suggests that mineral cementation may be terminated during primary oil migration as oil replaces water expelled from primary pores within the source rock. Panel_14937 Panel_14937 10:10 AM 10:30 AM
10:30 a.m.
Wettability Imaging of Unconventional Mudrock Reservoirs
Four Seasons Ballroom 1
Understanding wettability is key to optimizing oil recovery. Conventional methods of wettability characterization via core analysis are not feasible in mudrock (shale) reservoirs, owing to the severe difficulties in establishing well-defined initial states and performing fluid displacements in such matrix pore systems. An alternative method has been developed that utilizes high-resolution SEM imaging of fresh surfaces of preserved samples that have been mildly solvent cleaned to remove bulk fluids. In conventional reservoirs, asphaltene residues cling to oil-wet pore walls and can be distinguished (in secondary electron images at low voltage) by their distinctive nodular, nano-particulate film texture, while water-wet surfaces appear clean with no residues. In shale samples, the same characteristic textures are often seen, as well as thicker organic coatings interpreted to be bitumen. Examples from multiple shale reservoir formations will be shown, from a range of maturities and mineralogic compositions. Wettability is commonly seen to vary at the pore scale in shale formations, and assumptions that mineral pores remain water-wet can be misleading. The SEM technique also allows the same subarea of a shale sample to be imaged and re-imaged during a cleaning sequence to directly visualize the local removal of organics by harsher solvents. SEM surface imaging of some shale samples after cleaning will be compared to micro-CT imaging of their preserved state prior to cleaning, in which X-ray contrast enhancement techniques are employed to highlight the spatial distribution of in-place fluids at micron-millimeter scales and relations to wettability at these and finer scales. Understanding wettability is key to optimizing oil recovery. Conventional methods of wettability characterization via core analysis are not feasible in mudrock (shale) reservoirs, owing to the severe difficulties in establishing well-defined initial states and performing fluid displacements in such matrix pore systems. An alternative method has been developed that utilizes high-resolution SEM imaging of fresh surfaces of preserved samples that have been mildly solvent cleaned to remove bulk fluids. In conventional reservoirs, asphaltene residues cling to oil-wet pore walls and can be distinguished (in secondary electron images at low voltage) by their distinctive nodular, nano-particulate film texture, while water-wet surfaces appear clean with no residues. In shale samples, the same characteristic textures are often seen, as well as thicker organic coatings interpreted to be bitumen. Examples from multiple shale reservoir formations will be shown, from a range of maturities and mineralogic compositions. Wettability is commonly seen to vary at the pore scale in shale formations, and assumptions that mineral pores remain water-wet can be misleading. The SEM technique also allows the same subarea of a shale sample to be imaged and re-imaged during a cleaning sequence to directly visualize the local removal of organics by harsher solvents. SEM surface imaging of some shale samples after cleaning will be compared to micro-CT imaging of their preserved state prior to cleaning, in which X-ray contrast enhancement techniques are employed to highlight the spatial distribution of in-place fluids at micron-millimeter scales and relations to wettability at these and finer scales. Panel_14737 Panel_14737 10:30 AM 10:50 AM
11:10 a.m.
Characterization of Fine Grained Lithofacies in Coeval Strata From a Superregional Nearshore to Offshore Transect in the Upper Cretaceous of the North American Western Interior Seaway
Four Seasons Ballroom 1
As the exploration of unconventional plays continues to expand into increasingly challenging geologic environments the ability to predict the distribution of high reservoir quality has become an area of active research. Strata deposited around the Cenomanian – Turonian (C-T) boundary have received particular attention globally. Widely regarded as one of the premier times of source rock accumulation this time period has been extensively studied regarding enhanced preservation of organic carbon. Given recent developments of C-T strata becoming world class unconventional reservoirs (i.e.: Eagle Ford) gaining a full understanding of regional variations in how these rocks both generate and store hydrocarbons requires knowledge of the detailed lithofacies variations both vertically and laterally. In this study we have logged and sampled strata spanning the C-T boundary super-regionally from the North American Cretaceous Western Interior Seaway (KWIS). Samples from both cores and exposures from central Utah to Kansas have been analyzed to 1. determine their biostratigraphic context; 2. facies attributes and 3. environments of deposition. Lithofacies were observed from strata of the late transgressive to early highstand associated with the early Turonian maximum flooding. Strata from fluvial influenced environments are highly bioturbated argillaceous mudstones with abundant plant material. At the top of the interval coarsening upwards parasequences are more apparent with the tops of the parasequences becoming increasingly silt-rich with wave rippled laminae. Away from clastic input the coeval lithofacies are mixed calcareous - siliciclastic systems. The primary carbonate components are pelagic coccoliths and foraminifera. The early transgressive deposits consist of intervals of highly bioturbated bases that evolve upward to wave rippled thin (<1 cm) graded beds. Within the late transgressive to highstand a similar stacking is observed with the tops being 10 – 20 cm thick highly cemented carbonates. From these observations we believe that strata deposited in the transgressive interval of the mixed system environments make the optimal tight oil reservoirs in this part of the KWIS. The strata studied from the more terrestrially influenced environments were too influenced by fluvial processes. It is possible that other strata along strike where riverine input was less dominant could have high reservoir potential. As the exploration of unconventional plays continues to expand into increasingly challenging geologic environments the ability to predict the distribution of high reservoir quality has become an area of active research. Strata deposited around the Cenomanian – Turonian (C-T) boundary have received particular attention globally. Widely regarded as one of the premier times of source rock accumulation this time period has been extensively studied regarding enhanced preservation of organic carbon. Given recent developments of C-T strata becoming world class unconventional reservoirs (i.e.: Eagle Ford) gaining a full understanding of regional variations in how these rocks both generate and store hydrocarbons requires knowledge of the detailed lithofacies variations both vertically and laterally. In this study we have logged and sampled strata spanning the C-T boundary super-regionally from the North American Cretaceous Western Interior Seaway (KWIS). Samples from both cores and exposures from central Utah to Kansas have been analyzed to 1. determine their biostratigraphic context; 2. facies attributes and 3. environments of deposition. Lithofacies were observed from strata of the late transgressive to early highstand associated with the early Turonian maximum flooding. Strata from fluvial influenced environments are highly bioturbated argillaceous mudstones with abundant plant material. At the top of the interval coarsening upwards parasequences are more apparent with the tops of the parasequences becoming increasingly silt-rich with wave rippled laminae. Away from clastic input the coeval lithofacies are mixed calcareous - siliciclastic systems. The primary carbonate components are pelagic coccoliths and foraminifera. The early transgressive deposits consist of intervals of highly bioturbated bases that evolve upward to wave rippled thin (<1 cm) graded beds. Within the late transgressive to highstand a similar stacking is observed with the tops being 10 – 20 cm thick highly cemented carbonates. From these observations we believe that strata deposited in the transgressive interval of the mixed system environments make the optimal tight oil reservoirs in this part of the KWIS. The strata studied from the more terrestrially influenced environments were too influenced by fluvial processes. It is possible that other strata along strike where riverine input was less dominant could have high reservoir potential. Panel_14936 Panel_14936 11:10 AM 11:30 AM
11:30 a.m.
Reconsidering the Distinction Between Matrix and Porosity in Light of Molecular Structural Models of Coal and Petroleum Source Rocks
Four Seasons Ballroom 1
Studies of the organic structural chemistry of coal and petroleum source rocks over the past few decades can provide useful insights into the characteristics of carbonaceous low permeability (CLP) reservoirs. Rather than using these models to provide a valid foundation to describe the reservoir at molecular dimensions, then up-scaling, however, the petroleum industry has doggedly applied the same conceptual model developed for conventional reservoirs at orders of magnitude larger scale, then down-sizing to nanometer scale, while largely neglecting sub-nanometer molecular features. The conventional reservoir model is based on the binary distinction between matrix and porosity, where matrix broadly represents the solid fraction, and porosity represents the fluid fraction (liquid and gas). These simple terms are difficult to apply in practice, however, which can lead to oversimplified or erroneous description and analysis results. Even classification of constituents as solid, liquid, and gas is problematic, as the dispersion of low molecular weight species through a high molecular weight medium is better described in terms of colloids or clathrates than the classic states of matter. In reality, organic materials span a continuum of molecular sizes and weights, ranging from methane at one extreme, to complex, cross-linked macromolecules at the other. Setting a boundary between matrix and porosity is somewhat arbitrary, misleading, and dependent on specific analysis method(s), P-V-T conditions, and changes to the physical structure and chemical composition occurring during sampling and analysis. During the 1970s, coal chemists introduced the term “mobile phase” to describe the fraction of organic matter exhibiting vibrational mobility in 1H NMR, representing non-bonded molecular species occluded within a macromolecular matrix, where the density of cross linkages is dependent on organic matter rank and type. Mobile phase is largely immobile, however, in the context of expulsion and migration, and is only partially accessible to common organic solvents at low temperature. Petroleum geochemists have made an analogous distinction between bitumen (soluble) and kerogen (insoluble), based upon solubility. The relevancy of these binary classes to the distinction between porosity and matrix in reservoir engineering context is dubious. It would be better to start with new conceptual models and analysis methods, rather than try to force a square peg into a round hole. Studies of the organic structural chemistry of coal and petroleum source rocks over the past few decades can provide useful insights into the characteristics of carbonaceous low permeability (CLP) reservoirs. Rather than using these models to provide a valid foundation to describe the reservoir at molecular dimensions, then up-scaling, however, the petroleum industry has doggedly applied the same conceptual model developed for conventional reservoirs at orders of magnitude larger scale, then down-sizing to nanometer scale, while largely neglecting sub-nanometer molecular features. The conventional reservoir model is based on the binary distinction between matrix and porosity, where matrix broadly represents the solid fraction, and porosity represents the fluid fraction (liquid and gas). These simple terms are difficult to apply in practice, however, which can lead to oversimplified or erroneous description and analysis results. Even classification of constituents as solid, liquid, and gas is problematic, as the dispersion of low molecular weight species through a high molecular weight medium is better described in terms of colloids or clathrates than the classic states of matter. In reality, organic materials span a continuum of molecular sizes and weights, ranging from methane at one extreme, to complex, cross-linked macromolecules at the other. Setting a boundary between matrix and porosity is somewhat arbitrary, misleading, and dependent on specific analysis method(s), P-V-T conditions, and changes to the physical structure and chemical composition occurring during sampling and analysis. During the 1970s, coal chemists introduced the term “mobile phase” to describe the fraction of organic matter exhibiting vibrational mobility in 1H NMR, representing non-bonded molecular species occluded within a macromolecular matrix, where the density of cross linkages is dependent on organic matter rank and type. Mobile phase is largely immobile, however, in the context of expulsion and migration, and is only partially accessible to common organic solvents at low temperature. Petroleum geochemists have made an analogous distinction between bitumen (soluble) and kerogen (insoluble), based upon solubility. The relevancy of these binary classes to the distinction between porosity and matrix in reservoir engineering context is dubious. It would be better to start with new conceptual models and analysis methods, rather than try to force a square peg into a round hole. Panel_14932 Panel_14932 11:30 AM 11:50 AM

8:00 a.m.–11:50 a.m.
Discovery Thinking I: Global Discoveries (AAPG/DPA)
Four Seasons Ballroom 2 & 3, Monday Oral Sessions, 01 June, 2015

This "Discovery Thinking" Forum will be the 12th presentation of the AAPG 100th Anniversary Committee's program recognizing "100 Who Made a Difference." The forum will feature four invited speakers who will describe major discoveries in global exploration settings. This forum, combined with its counterpart into a day of Discovery Thinking, will celebrate how Creative Thinking Using Integrated Technology Leads to Giant and Super Giant Discoveries. Each speaker and their associates overcame significant business, technical and professional challenges. Topics to be discussed will include philosophy of exploration, stories from remarkable careers, professional insights, colorful anecdotes and lessons learned on the path to success. As technology advances and young geoscientists enter our profession, the organizers see continued interest in forums such as these. These forums provide a venue for explorers to discuss the personal side of success and what has been called the "art of exploration." As always, the audience is fortunate to hear the speakers share abundant technical data and insights derived from costly and hard won experience. AAPG offers many technical sessions. "Discovery Thinking" forums fill an important gap in how technical and professional skills combine to turn prospects into discoveries. Speakers are encouraged to share personal stories about discoveries they know well, bring forward appropriate technical data and address questions from the audience and fellow explorers. Morning talks will emphasize exciting discoveries in global settings. Denver, an important center for both global and North American exploration, is a great venue to celebrate discoveries in both of these settings.

This "Discovery Thinking" Forum will be the 12th presentation of the AAPG 100th Anniversary Committee's program recognizing "100 Who Made a Difference." The forum will feature four invited speakers who will describe major discoveries in global exploration settings. This forum, combined with its counterpart into a day of Discovery Thinking, will celebrate how Creative Thinking Using Integrated Technology Leads to Giant and Super Giant Discoveries.

Each speaker and their associates overcame significant business, technical and professional challenges. Topics to be discussed will include philosophy of exploration, stories from remarkable careers, professional insights, colorful anecdotes and lessons learned on the path to success. As technology advances and young geoscientists enter our profession, the organizers see continued interest in forums such as these. These forums provide a venue for explorers to discuss the personal side of success and what has been called the "art of exploration." As always, the audience is fortunate to hear the speakers share abundant technical data and insights derived from costly and hard won experience.

AAPG offers many technical sessions. "Discovery Thinking" forums fill an important gap in how technical and professional skills combine to turn prospects into discoveries. Speakers are encouraged to share personal stories about discoveries they know well, bring forward appropriate technical data and address questions from the audience and fellow explorers. Morning talks will emphasize exciting discoveries in global settings. Denver, an important center for both global and North American exploration, is a great venue to celebrate discoveries in both of these settings.

 Panel_14242 Panel_14242 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Four Seasons Ballroom 2 & 3
Panel_15780 Panel_15780 8:00 AM 12:00 AM
8:05 a.m.
Successful Lithology and Fluid Prediction Based Exploration in East Africa-Tanzania Block 2
Four Seasons Ballroom 2 & 3
In 2007 Statoil ASA was awarded the rights to explore for hydrocarbons in Block 2, offshore Tanzania. At that time no deep water wells were drilled in the area. From being unexplored, deep water offshore Tanzania has over recent years turned into a prolific gas province, with great exploration success both in Block 2 and in neighboring licenses. Since 2012 Statoil ASA and license partner ExxonMobil Exploration and Production Tanzania Limited have had two drilling campaigns with a total of 12 exploration and appraisal wells which have resulted in 7 announced discoveries. The total in-place volume discovered in Block 2 now exceeds 20 tcf of gas. This talk will provide some of the exploration highlights, explaining successes and failures. We will present how the geological understanding of the area has evolved over time, and demonstrate the impact that state of the art geophysical workflows have in fluid and lithology prediction. Extensive use of AVO attributes like colored inversion and extended elastic impedance rotations enabled de-risking of prospects and thereby maturation of prospects into drilling candidates very efficiently. Interpretation of angle stacks and pre-stack gather analysis has become essential to understand prospectivity. The widespread application of advanced seismic interpretation techniques has provided involved explorationists a true challenge and has given an incredible learning curve. The outcome will provide memories for a life time, as LFP based exploration in Block 2 has been a great success delivering a string of world class discoveries. In 2007 Statoil ASA was awarded the rights to explore for hydrocarbons in Block 2, offshore Tanzania. At that time no deep water wells were drilled in the area. From being unexplored, deep water offshore Tanzania has over recent years turned into a prolific gas province, with great exploration success both in Block 2 and in neighboring licenses. Since 2012 Statoil ASA and license partner ExxonMobil Exploration and Production Tanzania Limited have had two drilling campaigns with a total of 12 exploration and appraisal wells which have resulted in 7 announced discoveries. The total in-place volume discovered in Block 2 now exceeds 20 tcf of gas. This talk will provide some of the exploration highlights, explaining successes and failures. We will present how the geological understanding of the area has evolved over time, and demonstrate the impact that state of the art geophysical workflows have in fluid and lithology prediction. Extensive use of AVO attributes like colored inversion and extended elastic impedance rotations enabled de-risking of prospects and thereby maturation of prospects into drilling candidates very efficiently. Interpretation of angle stacks and pre-stack gather analysis has become essential to understand prospectivity. The widespread application of advanced seismic interpretation techniques has provided involved explorationists a true challenge and has given an incredible learning curve. The outcome will provide memories for a life time, as LFP based exploration in Block 2 has been a great success delivering a string of world class discoveries. Panel_15931 Panel_15931 8:05 AM 8:45 AM
8:45 a.m.
Unlocking of the Pre-Salt Play in the Deepwater Kwanza Basin of Offshore Angola
Four Seasons Ballroom 2 & 3
Panel_15933 Panel_15933 8:45 AM 9:25 AM
9:25 a.m.
Break
Four Seasons Ballroom 2 & 3
Panel_15781 Panel_15781 9:25 AM 12:00 AM
10:10 a.m.
40 TCF and Counting: Understanding the Petroleum System of the Deep Water Levant Basin
Four Seasons Ballroom 2 & 3
Panel_15934 Panel_15934 10:10 AM 10:50 AM
10:50 a.m.
Stratigraphic Traps in Sergipe — Alagoas Basin, NE Brazil
Four Seasons Ballroom 2 & 3
Panel_15935 Panel_15935 10:50 AM 11:30 AM
11:30 a.m.
Question and Answer
Four Seasons Ballroom 2 & 3
Panel_15936 Panel_15936 11:30 AM 12:30 PM

8:00 a.m.–11:50 a.m.
Theme 7: Exploration and Production Applications of Basin Modeling (AAPG)
Four Seasons Ballroom 4, Monday Oral Sessions, 01 June, 2015

Panel_14489 Panel_14489 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Four Seasons Ballroom 4
Panel_15782 Panel_15782 8:00 AM 12:00 AM
8:05 a.m.
Impact of Fluid Retention on Bulk Petroleum Properties in Shale
Four Seasons Ballroom 4
Predicting GOR and petroleum properties within an unconventional resource play has become a paramount concern. Subtle changes in bulk fluid composition are manifested by large differences in phase envelope geometry, meaning that pressure drawdown during production may or may not suit predicted fluid types. In addition, the heterogeneity of sedimentary packages as well as the variability of organic matter composition strongly impact producibility of fluids and thus production allocation. Here we present new insights into the evolution of petroleum properties, relating structures within kerogen to retained and expelled fluid chemistries as a function of maturity. Pyrolysis-gc and Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) were used to investigate source rock extracts, oils and pyrolysates. While pyrolysis-gc lends itself well to analyzing structural units in kerogens and extracts using small compounds of low polarity (e.g. hydrocarbons), FT-ICR-MS is a perfect tool for rapidly characterizing polar NSO compounds in complex mixtures from pyrolysates, extracts and crude oil. NSO compounds are of high interest because they feature functional groups and thus strongly influence sorption, solubility and partitioning of petroleum compounds within unconventional shale system. Differences in the evolution of the petroleum composition of unconventionally and conventionally reservoired oils are revealed by comparing the polar compound composition of (1) extracts of six Posidonia source rock samples with maturity levels between 0.43 and 1.45% Ro, (2) open-system pyrolysates of those six source rocks, and (3) four Posidonia sourced medium gravity conventional crude oils. The aromaticity and degree of condensation was found to increase much more pronouncedly with increasing maturity for retained NSOs than for oil NSOs. Pyrolysate NSOs hold “intermediate” compositions, pointing to a preferential expulsion of smaller compounds in the crudes and enhanced cyclisation and aromatization processes within retained fluids. The latter process was shown to occur at the cost of aliphatic precursors. A genetic link of the fluids as well as the likely timing of petroleum expulsion was revealed by comparing carbon number distributions in connection with alkyl-chain length distributions. The chemical differences documented here are manifested in the sorptive properties of fluids, and need to be taken into account in formulating production strategies. Predicting GOR and petroleum properties within an unconventional resource play has become a paramount concern. Subtle changes in bulk fluid composition are manifested by large differences in phase envelope geometry, meaning that pressure drawdown during production may or may not suit predicted fluid types. In addition, the heterogeneity of sedimentary packages as well as the variability of organic matter composition strongly impact producibility of fluids and thus production allocation. Here we present new insights into the evolution of petroleum properties, relating structures within kerogen to retained and expelled fluid chemistries as a function of maturity. Pyrolysis-gc and Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) were used to investigate source rock extracts, oils and pyrolysates. While pyrolysis-gc lends itself well to analyzing structural units in kerogens and extracts using small compounds of low polarity (e.g. hydrocarbons), FT-ICR-MS is a perfect tool for rapidly characterizing polar NSO compounds in complex mixtures from pyrolysates, extracts and crude oil. NSO compounds are of high interest because they feature functional groups and thus strongly influence sorption, solubility and partitioning of petroleum compounds within unconventional shale system. Differences in the evolution of the petroleum composition of unconventionally and conventionally reservoired oils are revealed by comparing the polar compound composition of (1) extracts of six Posidonia source rock samples with maturity levels between 0.43 and 1.45% Ro, (2) open-system pyrolysates of those six source rocks, and (3) four Posidonia sourced medium gravity conventional crude oils. The aromaticity and degree of condensation was found to increase much more pronouncedly with increasing maturity for retained NSOs than for oil NSOs. Pyrolysate NSOs hold “intermediate” compositions, pointing to a preferential expulsion of smaller compounds in the crudes and enhanced cyclisation and aromatization processes within retained fluids. The latter process was shown to occur at the cost of aliphatic precursors. A genetic link of the fluids as well as the likely timing of petroleum expulsion was revealed by comparing carbon number distributions in connection with alkyl-chain length distributions. The chemical differences documented here are manifested in the sorptive properties of fluids, and need to be taken into account in formulating production strategies. Panel_15534 Panel_15534 8:05 AM 8:25 AM
8:25 a.m.
Geochemical and Basin Modeling Evaluation of the Utica/Point Pleasant Unconventional Play, Eastern Ohio
Four Seasons Ballroom 4
The geochemical analysis of rocks and fluids was a key component in the construction and evaluation of a basin thermal model used to appraise the Utica/Point Pleasant unconventional play in eastern Ohio. The business impact of this work was made in three primary areas: 1) the construction and calibration of a predictive and interactive basin thermal model used to evaluate source rock maturity, 2) the stratigraphic evaluation of oil yield (bbls/acre) to evaluate the oil window portion of the unconventional play, and 3) the measurement and prediction of fluid properties (BTU, CGR, and GOR) to determine the origin of the gas/condensate and to delineate the liquid “sweetspot” of the unconventional play. Modeled source rock thermal maturity, which is a function of burial and temperature history, was compared to vitrinite reflectance equivalent (%Roeq) values derived from aromatic biomarkers in oils, production gas isotopes, graptolite %Roeq measurements, and surface coal vitrinite reflectance. These measured thermal maturity data were used to refine the amount of burial and erosion at the surface unconformity needed to calibrate the modeled thermal maturity of the Point Pleasant Formation. Detailed stratigraphic analysis of the Point Pleasant oil yield (bbls/acre) was evaluated using TOC and Rock-Eval results combined with well log ?LogR analysis. These results were used to calculate oil yield (bbls/acre) in over fifty wells. The highest oil yields occur in an area defined by the late stage oil to wet gas window ranging from 0.95 to 1.3 %Ro. However, when compared to other unconventional plays such as the Eagle Ford, the cumulative oil yields are much lower making the oil window part of this unconventional play more technically challenged. An expulsion-retention model which considers sorption, pore saturation, inorganic (matrix) and organic (kerogen) porosity was used to predict fluid properties such as the gas-oil ratio (GOR ) and the condensate gas ratio (CGR). Calibration of these modeled fluid properties was performed using isotube mud gas analyses, separator gas, and production gas data. Prediction of BTU was also derived from gas wetness derived from both isotube mud gas and production gas data. These data provide insights as to the origin of the gas and condensate (primary versus secondary cracking) and allow for the mapping of the liquid “sweetspot” of this unconventional play. The geochemical analysis of rocks and fluids was a key component in the construction and evaluation of a basin thermal model used to appraise the Utica/Point Pleasant unconventional play in eastern Ohio. The business impact of this work was made in three primary areas: 1) the construction and calibration of a predictive and interactive basin thermal model used to evaluate source rock maturity, 2) the stratigraphic evaluation of oil yield (bbls/acre) to evaluate the oil window portion of the unconventional play, and 3) the measurement and prediction of fluid properties (BTU, CGR, and GOR) to determine the origin of the gas/condensate and to delineate the liquid “sweetspot” of the unconventional play. Modeled source rock thermal maturity, which is a function of burial and temperature history, was compared to vitrinite reflectance equivalent (%Roeq) values derived from aromatic biomarkers in oils, production gas isotopes, graptolite %Roeq measurements, and surface coal vitrinite reflectance. These measured thermal maturity data were used to refine the amount of burial and erosion at the surface unconformity needed to calibrate the modeled thermal maturity of the Point Pleasant Formation. Detailed stratigraphic analysis of the Point Pleasant oil yield (bbls/acre) was evaluated using TOC and Rock-Eval results combined with well log ?LogR analysis. These results were used to calculate oil yield (bbls/acre) in over fifty wells. The highest oil yields occur in an area defined by the late stage oil to wet gas window ranging from 0.95 to 1.3 %Ro. However, when compared to other unconventional plays such as the Eagle Ford, the cumulative oil yields are much lower making the oil window part of this unconventional play more technically challenged. An expulsion-retention model which considers sorption, pore saturation, inorganic (matrix) and organic (kerogen) porosity was used to predict fluid properties such as the gas-oil ratio (GOR ) and the condensate gas ratio (CGR). Calibration of these modeled fluid properties was performed using isotube mud gas analyses, separator gas, and production gas data. Prediction of BTU was also derived from gas wetness derived from both isotube mud gas and production gas data. These data provide insights as to the origin of the gas and condensate (primary versus secondary cracking) and allow for the mapping of the liquid “sweetspot” of this unconventional play. Panel_15532 Panel_15532 8:25 AM 8:45 AM
8:45 a.m.
Assessing Hydrocarbon Migration in the Hekkingen Formation Source-Rock — A New 3-D Look at the Hammerfest Basin, Barents Sea
Four Seasons Ballroom 4
The Late Jurassic Hekkingen Formation, an approximate time equivalent to the North Sea Kimmeridge Clay, is as a prolific, oil-prone source-rock in the Norwegian Barents Sea. Despite its limited regional oil window maturity, it is regarded as the main source of many hydrocarbon finds in deeper-seated Early to Middle Jurassic reservoir rocks, particularly within the Hammerfest Basin. This source-rock is a dark gray shale, deposited under restricted marine / deep marine conditions and considered homogenous. Still, thin sand bodies are reported in several wells but their origin and lateral extend are poorly examined. We presume that HC migration pattern within the Hekkingen Formation may play a crucial yet underestimated role in explaining HC observations in associated older reservoirs. We aim to investigate if lithological variations in this source-rock direct HC flow and thus pre-define zones that are particularly prone for HC liberation. Furthermore, we investigate how such intra-source-rock flow relates to the unit’s source-rock potential variation and their impact on the secondary migration pattern in the older carrier units in the basin. In order to test our assumptions, we built a detailed Hammerfest Basin model at a lateral resolution of 400m x 400m, with a particular focus on the Hekkingen Formation. This unit was discretized into 100 isochronous sub layers, representing less than a few meters thickness each. Results of a 3-D source-rock modelling study (de Jager et al., 2015, this conference) performed to model the distributions of the inorganic (sand, shale) and the organic (TOC, HI) components of the source, are used to populate the Hekkingen unit in our basin model. Detailed representations of HC migration within fine-grained siliciclastic source-rocks are often very limited in basin models. We employ a novel model approach that accounts for a high-resolution vertical description of the entry pressure field at basin scale. This enables the simulator to model migration into thin porous stringers (e.g. thief zones that transfer oil and gas laterally into faults) embedded in shales and thus exploits 3-D source-model results at high resolution. Important modelling results include the visualization of the detailed HC migration pattern histories within the 3-D Hekkingen Formation source-rock basin model. In-depth analysis can reveal how these results relate to the HC migration pattern and well site observations in the Early/Middle Jurassic Stø Formation. The Late Jurassic Hekkingen Formation, an approximate time equivalent to the North Sea Kimmeridge Clay, is as a prolific, oil-prone source-rock in the Norwegian Barents Sea. Despite its limited regional oil window maturity, it is regarded as the main source of many hydrocarbon finds in deeper-seated Early to Middle Jurassic reservoir rocks, particularly within the Hammerfest Basin. This source-rock is a dark gray shale, deposited under restricted marine / deep marine conditions and considered homogenous. Still, thin sand bodies are reported in several wells but their origin and lateral extend are poorly examined. We presume that HC migration pattern within the Hekkingen Formation may play a crucial yet underestimated role in explaining HC observations in associated older reservoirs. We aim to investigate if lithological variations in this source-rock direct HC flow and thus pre-define zones that are particularly prone for HC liberation. Furthermore, we investigate how such intra-source-rock flow relates to the unit’s source-rock potential variation and their impact on the secondary migration pattern in the older carrier units in the basin. In order to test our assumptions, we built a detailed Hammerfest Basin model at a lateral resolution of 400m x 400m, with a particular focus on the Hekkingen Formation. This unit was discretized into 100 isochronous sub layers, representing less than a few meters thickness each. Results of a 3-D source-rock modelling study (de Jager et al., 2015, this conference) performed to model the distributions of the inorganic (sand, shale) and the organic (TOC, HI) components of the source, are used to populate the Hekkingen unit in our basin model. Detailed representations of HC migration within fine-grained siliciclastic source-rocks are often very limited in basin models. We employ a novel model approach that accounts for a high-resolution vertical description of the entry pressure field at basin scale. This enables the simulator to model migration into thin porous stringers (e.g. thief zones that transfer oil and gas laterally into faults) embedded in shales and thus exploits 3-D source-model results at high resolution. Important modelling results include the visualization of the detailed HC migration pattern histories within the 3-D Hekkingen Formation source-rock basin model. In-depth analysis can reveal how these results relate to the HC migration pattern and well site observations in the Early/Middle Jurassic Stø Formation. Panel_15531 Panel_15531 8:45 AM 9:05 AM
9:05 a.m.
Evolution of the Southwestern Midcontinent Basin During the Middle Pennsylvanian: Evidence From Sequence Stratigraphy, Core and XRF in Southeastern Colorado
Four Seasons Ballroom 4
Understanding the interplay of regional tectonic setting, basin geometry, and facies relationships is critical to characterizing the petroleum systems of a basin. This is a challenge for the southwestern Midcontinent Basin due to the lack of outcrops of equivalent lithostratigraphy and facies encountered in the subsurface and the dearth of subsurface studies for this broad region. In order characterize the stratigraphic relationships and basin architecture of this petroleum-rich area, our study focuses on the Atokan and Desmoinesian stages (Atoka, Cherokee, and Marmaton formations) of the Middle Pennsylvanian. We utilize and integrate subsurface data including well logs, core data, X-ray fluorescence data, and formation image logs to support our sequence stratigraphic interpretation and a spatially and temporally complex facies model that encompasses southeastern Colorado to central Kansas. Our results reveal a dynamic character to the southwestern Midcontinent Basin. During the Atokan Stage, the basin edge was characterized by interbedded carbonaceous shale, coal, and limestone with facies suggesting a lagoonal margin periodically dominated by cyclothemic marine flooding events. Trace elements suggest a strongly restricted basin within an overall marine transgression trend. The basin morphology is interpreted as a sedimentary wedge, rapidly thinning to the east towards the basin center. During the subsequent Desmoinesian Stage, this region was characterized by interbedded carbonaceous shale and limestone, dominantly controlled by large-scale glacio-eustastic cyclothems in an open marine setting. Depositional environments range from intertidal platform, tidal flats, and shoals to deep, subtidal platform. In contrast to the Atokan Stage, trace elements suggest a weakly restrictive basin. Carbonate buildups, shoals, and paleosols are possibly coincident with an activated flexural forebulge and sediment baffle within the basin but peripheral the basin center and its condensed stratigraphic section. Our data and analysis support a model of dramatic glacio-eustatic transgression-regression cycles within an overall marine transgression from Atokan through Desmoinesian time. Our observations have implications for purported superestuarine circulation, the degree of Midcontinent basin restriction, and patterns of condensed vs thickened stratigraphic sections, all of which are important to historic and emerging petroleum systems of the region. Understanding the interplay of regional tectonic setting, basin geometry, and facies relationships is critical to characterizing the petroleum systems of a basin. This is a challenge for the southwestern Midcontinent Basin due to the lack of outcrops of equivalent lithostratigraphy and facies encountered in the subsurface and the dearth of subsurface studies for this broad region. In order characterize the stratigraphic relationships and basin architecture of this petroleum-rich area, our study focuses on the Atokan and Desmoinesian stages (Atoka, Cherokee, and Marmaton formations) of the Middle Pennsylvanian. We utilize and integrate subsurface data including well logs, core data, X-ray fluorescence data, and formation image logs to support our sequence stratigraphic interpretation and a spatially and temporally complex facies model that encompasses southeastern Colorado to central Kansas. Our results reveal a dynamic character to the southwestern Midcontinent Basin. During the Atokan Stage, the basin edge was characterized by interbedded carbonaceous shale, coal, and limestone with facies suggesting a lagoonal margin periodically dominated by cyclothemic marine flooding events. Trace elements suggest a strongly restricted basin within an overall marine transgression trend. The basin morphology is interpreted as a sedimentary wedge, rapidly thinning to the east towards the basin center. During the subsequent Desmoinesian Stage, this region was characterized by interbedded carbonaceous shale and limestone, dominantly controlled by large-scale glacio-eustastic cyclothems in an open marine setting. Depositional environments range from intertidal platform, tidal flats, and shoals to deep, subtidal platform. In contrast to the Atokan Stage, trace elements suggest a weakly restrictive basin. Carbonate buildups, shoals, and paleosols are possibly coincident with an activated flexural forebulge and sediment baffle within the basin but peripheral the basin center and its condensed stratigraphic section. Our data and analysis support a model of dramatic glacio-eustatic transgression-regression cycles within an overall marine transgression from Atokan through Desmoinesian time. Our observations have implications for purported superestuarine circulation, the degree of Midcontinent basin restriction, and patterns of condensed vs thickened stratigraphic sections, all of which are important to historic and emerging petroleum systems of the region. Panel_15527 Panel_15527 9:05 AM 9:25 AM
9:25 a.m.
Break
Four Seasons Ballroom 4
Panel_15783 Panel_15783 9:25 AM 12:00 AM
10:10 a.m.
A Vintage Well Perspective on Basin Model Production Prediction Within the Niobrara Formation, Southern Powder River Basin, Wyoming
Four Seasons Ballroom 4
The Late Cretaceous Niobrara formation is a steadily emerging unconventional resource play within the greater Rocky Mountain foreland province. A substantial amount of research and operational effort has been directed towards understanding the complexity of the Niobrara in the Denver-Julesberg (DJ) basin. While sharing the same shallow seaway depositional environment as the DJ basin, but with an alternative Laramide-style deformation sequence of events and diagenetic alteration, the Powder River basin stands valiantly as a viable resource play for the Niobrara. This is especially true for the deeper, geochemically mature southern portion (Converse and Niobrara Counties) of the Powder River basin. As a completely self-sourced reservoir, the Niobrara formation makes up a cohesive petroleum system, free from the effects of any external geology. The alternating brittle, chalk-rich reservoir intervals and associated ductile, marl-rich source rock intervals lead to a predictable hydrocarbon migration system. Such migration information plays a critical role in optimized well placement and hydraulic stimulation planning, ultimately leading to enhanced production. It was therefore of paramount importance that a complete visualization of the brittleness behavior, trends, and patterns be actualized. A basin model was created in order to statistically interpolate such patterns and trends inherent within the subsurface environment. The approach to such an endeavor had one objective in mind - use free, publicly available well data. The gamma ray (GR) log curve provided the much needed information pertaining to the "purity" of the chalk-rich reservoir intervals. Within the confines of the Niobrara, lower GR units indicated increasingly "pure", and hence, more brittle reservoir rocks conducive to natural hydrocarbon migration and fracturing. In order to test such results, this information pertaining to the optimal "sweet spot" well placement was compared to present-day and historical petroleum production. The results prove that if the basin modeler continually ties the model back to a clearly defined objective central to the history of the rocks, the limitation of data availability may be ultimately ignored. The Late Cretaceous Niobrara formation is a steadily emerging unconventional resource play within the greater Rocky Mountain foreland province. A substantial amount of research and operational effort has been directed towards understanding the complexity of the Niobrara in the Denver-Julesberg (DJ) basin. While sharing the same shallow seaway depositional environment as the DJ basin, but with an alternative Laramide-style deformation sequence of events and diagenetic alteration, the Powder River basin stands valiantly as a viable resource play for the Niobrara. This is especially true for the deeper, geochemically mature southern portion (Converse and Niobrara Counties) of the Powder River basin. As a completely self-sourced reservoir, the Niobrara formation makes up a cohesive petroleum system, free from the effects of any external geology. The alternating brittle, chalk-rich reservoir intervals and associated ductile, marl-rich source rock intervals lead to a predictable hydrocarbon migration system. Such migration information plays a critical role in optimized well placement and hydraulic stimulation planning, ultimately leading to enhanced production. It was therefore of paramount importance that a complete visualization of the brittleness behavior, trends, and patterns be actualized. A basin model was created in order to statistically interpolate such patterns and trends inherent within the subsurface environment. The approach to such an endeavor had one objective in mind - use free, publicly available well data. The gamma ray (GR) log curve provided the much needed information pertaining to the "purity" of the chalk-rich reservoir intervals. Within the confines of the Niobrara, lower GR units indicated increasingly "pure", and hence, more brittle reservoir rocks conducive to natural hydrocarbon migration and fracturing. In order to test such results, this information pertaining to the optimal "sweet spot" well placement was compared to present-day and historical petroleum production. The results prove that if the basin modeler continually ties the model back to a clearly defined objective central to the history of the rocks, the limitation of data availability may be ultimately ignored. Panel_15585 Panel_15585 10:10 AM 10:30 AM
10:30 a.m.
High TOC Source Rocks, Multiple Oils and Low Permeability Reservoir Rocks: Mississippian Heath Formation Hybrid Oil Petroleum System, Central Montana, USA
Four Seasons Ballroom 4
The late Mississippian Heath Formation of central Montana contains interstratified organic-rich carbonate mudstone source rocks and low permeability oil-saturated (“tight oil”) carbonate reservoir rocks. A study of source rocks, extracted oils and bitumens, and produced oils indicates the presence of at least three hydrocarbon sources within the Heath, including in descending order the Heath Limestone, Cox Ranch Oil Shale, and Van Dusen Zone. Oil API gravity and maturity increase with increasing source rock thermal maturity indicating little or no lateral migration within Heath reservoirs. Aryl isoprenoids in the oils indicate photic zone euxinia (PZE) existed during source rock deposition. The presence of gammacerane in the oils is indicative of a stratified water column and evaporitic or hypersaline environments. The Heath Limestone includes tan dolomite, gray marine limestone, calcareous mudstone, and anhydrite and has been the primary target of most of the horizontal wells drilled in the Heath to date. Source beds contain TOC up to 11 wt% and HI up to 793 mgHC/gTOC; reservoirs are best developed in intertidal to supratidal dolomites with porosity up to 18.7% and permeability up to 1.1md. The Cox Ranch Oil Shale contains interbedded dark brown to black calcareous mudstone, gray marine limestone, and minor dark gray fissile shales. Source beds contain TOC up to 26 wt% and HI up to 757 mgHC/gTOC; limestone reservoirs have 2-6% porosity and mudstones have up to 21% porosity. The Van Dusen zone contains dolomitized limestones, gray marine limestones, dark brown to black calcareous mudstones, coals, and greenish-gray claystones. Source beds, including coals, contain TOC up to 73 wt% and HI up to 646 mgHC/gTOC; oils generated by these sources contain abundant terrestrial biomarkers. Van Dusen reservoirs include fractured limestones with 1-5% porosity and mudstones with up to 26% porosity. Interpretation of biomarkers suggests that each of the Heath Limestone, Cox Ranch Oil Shale, and Van Dusen Zone generate distinct oils. Produced oils examined from horizontal wells with laterals drilled in the Heath Limestone contain only Heath Limestone biomarkers, suggesting that drilling and completion techniques applied to date have not contacted the entire pay thickness in the Heath. The late Mississippian Heath Formation of central Montana contains interstratified organic-rich carbonate mudstone source rocks and low permeability oil-saturated (“tight oil”) carbonate reservoir rocks. A study of source rocks, extracted oils and bitumens, and produced oils indicates the presence of at least three hydrocarbon sources within the Heath, including in descending order the Heath Limestone, Cox Ranch Oil Shale, and Van Dusen Zone. Oil API gravity and maturity increase with increasing source rock thermal maturity indicating little or no lateral migration within Heath reservoirs. Aryl isoprenoids in the oils indicate photic zone euxinia (PZE) existed during source rock deposition. The presence of gammacerane in the oils is indicative of a stratified water column and evaporitic or hypersaline environments. The Heath Limestone includes tan dolomite, gray marine limestone, calcareous mudstone, and anhydrite and has been the primary target of most of the horizontal wells drilled in the Heath to date. Source beds contain TOC up to 11 wt% and HI up to 793 mgHC/gTOC; reservoirs are best developed in intertidal to supratidal dolomites with porosity up to 18.7% and permeability up to 1.1md. The Cox Ranch Oil Shale contains interbedded dark brown to black calcareous mudstone, gray marine limestone, and minor dark gray fissile shales. Source beds contain TOC up to 26 wt% and HI up to 757 mgHC/gTOC; limestone reservoirs have 2-6% porosity and mudstones have up to 21% porosity. The Van Dusen zone contains dolomitized limestones, gray marine limestones, dark brown to black calcareous mudstones, coals, and greenish-gray claystones. Source beds, including coals, contain TOC up to 73 wt% and HI up to 646 mgHC/gTOC; oils generated by these sources contain abundant terrestrial biomarkers. Van Dusen reservoirs include fractured limestones with 1-5% porosity and mudstones with up to 26% porosity. Interpretation of biomarkers suggests that each of the Heath Limestone, Cox Ranch Oil Shale, and Van Dusen Zone generate distinct oils. Produced oils examined from horizontal wells with laterals drilled in the Heath Limestone contain only Heath Limestone biomarkers, suggesting that drilling and completion techniques applied to date have not contacted the entire pay thickness in the Heath. Panel_15529 Panel_15529 10:30 AM 10:50 AM
10:50 a.m.
Subsurface and Outcrop Organic Geochemistry of the Eagle Ford Shale in West, Southwest, Central and East Texas
Four Seasons Ballroom 4
A comprehensive regional organic geochemical study was performed on outcrop and core samples from the Eagle Ford Shale with the aim of determining variations in organic matter source, thermal maturity and depositional environments. A total of 178 samples were subjected to total organic carbon (TOC) and Rock Eval analysis. These data were used to select for vitrinite reflectance and for biomarker and isotope analyses using gas chromatography, gas chromatography-mass spectrometry, and gas chromatography-isotope ratio mass spectrometry. TOC and Rock Eval parameters show that the Eagle Ford Shale has excellent source rock potential and is dominated by Type II kerogen. Distributions of regular steranes, hopanes and monoaromatic steroid hydrocarbons point towards a marine carbonate depositional environment. Aryl isoprenoids suggest the occurrence of intermittent photic zone anoxia. In addition, n-alkanes, steranes distributions, and the tentative identification of gammacerane, suggest deposition of source material under hypersaline conditions in West and East Texas. Biomarker parameters show that in East Texas the Eagle Ford Shale was partly sourced by terrigenous organic matter, reflecting the influence of the Harris Delta. Thermal maturity parameters indicate that the Eagle Ford is immature to marginally mature in West and Central Texas, and show a progressive increase in maturity towards the southeast. In East Texas, the Eagle Ford Shale is in the main oil-window. Geochemical logs show minimal vertical variation within the Eagle Ford Shale. The Lower Eagle Ford has the highest TOC and hydrogen index (HI) values and in particular, the Lozier Canyon Member is the most organic-rich. Pristane and phytane (Pr/Ph) and biomarker ratios suggest the establishment of stronger anoxic conditions during deposition of the Lower Eagle Ford Shale. In East Texas, Pr/Ph ratios indicate source rock deposition under oxic-suboxic conditions. Isotope data indicates a marine organic matter source for the Eagle Ford Shale, but d13C values do not show significant organic facies, depositional environment or thermal maturity changes. A comprehensive regional organic geochemical study was performed on outcrop and core samples from the Eagle Ford Shale with the aim of determining variations in organic matter source, thermal maturity and depositional environments. A total of 178 samples were subjected to total organic carbon (TOC) and Rock Eval analysis. These data were used to select for vitrinite reflectance and for biomarker and isotope analyses using gas chromatography, gas chromatography-mass spectrometry, and gas chromatography-isotope ratio mass spectrometry. TOC and Rock Eval parameters show that the Eagle Ford Shale has excellent source rock potential and is dominated by Type II kerogen. Distributions of regular steranes, hopanes and monoaromatic steroid hydrocarbons point towards a marine carbonate depositional environment. Aryl isoprenoids suggest the occurrence of intermittent photic zone anoxia. In addition, n-alkanes, steranes distributions, and the tentative identification of gammacerane, suggest deposition of source material under hypersaline conditions in West and East Texas. Biomarker parameters show that in East Texas the Eagle Ford Shale was partly sourced by terrigenous organic matter, reflecting the influence of the Harris Delta. Thermal maturity parameters indicate that the Eagle Ford is immature to marginally mature in West and Central Texas, and show a progressive increase in maturity towards the southeast. In East Texas, the Eagle Ford Shale is in the main oil-window. Geochemical logs show minimal vertical variation within the Eagle Ford Shale. The Lower Eagle Ford has the highest TOC and hydrogen index (HI) values and in particular, the Lozier Canyon Member is the most organic-rich. Pristane and phytane (Pr/Ph) and biomarker ratios suggest the establishment of stronger anoxic conditions during deposition of the Lower Eagle Ford Shale. In East Texas, Pr/Ph ratios indicate source rock deposition under oxic-suboxic conditions. Isotope data indicates a marine organic matter source for the Eagle Ford Shale, but d13C values do not show significant organic facies, depositional environment or thermal maturity changes. Panel_15533 Panel_15533 10:50 AM 11:10 AM
11:10 a.m.
Hydrocarbon Potential of the Northeastern Caribbean Based on Integration of Depth to Basement and Source Rock Maturity Data
Four Seasons Ballroom 4
The northeastern Caribbean on the islands of Hispaniola and Puerto Rico and their offshore areas has over one century of hydrocarbon exploration with over 72 wildcat wells drilled, but insignificant commercial production to date. A key question is whether these large Caribbean oceanic islands, removed from the input of large terrigenous river systems found in other areas like the Gulf of Mexico and northern South America, have experienced sufficient subsidence and depth of burial for any source rocks that may be present to reach maturity and produce commercial hydrocarbons. We compiled well data and seismic interpretations from previous workers into a depth to Cretaceous-Eocene igneous-metamorphic basement map for Hispaniola, Puerto Rico, and their offshore areas. These maps show the areas of greatest depth to igneous-metamorphic basement and overlying fill to include the Enriquillo basin of the Dominican Republic (5 km), San Juan basin of the Dominican Republic (5.3 km) and Central Plateau basin of Haiti (5.3 km), Cibao basin of the Dominican Republic (5 km), north coast basin of Puerto Rico (1.7 km), south coast basin of Puerto Rico (1.3 km), and Virgin Islands basin (8 km). Of these seven basins, 2D basin modeling using available vitrinite data show that only the collinear San Juan and Azua basins of the Dominican Republic have achieved sufficient burial to place known and inferred source rocks into the oil window in both areas. This result is supported in the case of the Azua basin by the presence of natural, surficial oil seeps and limited production from shallow wells (about 50,000 barrels of 20° API, biodegraded oil was produced in the 1940s and 50s). Low Ro% values of sediments in the Enriquillo basin of comparable thickness and identical source rocks to the San Juan and Azua indicate lower heat flow in the Enriquillo basin. Some of the lack of commercial success in the San Juan basin and adjacent Central Plateau basin of Haiti may reflect that only a total of four wildcat wells have been drilled, two of which had oil and gas shows. Biogenic gas is likely more prevalent in these same basins and within the larger deltas of Hispaniola. The northeastern Caribbean on the islands of Hispaniola and Puerto Rico and their offshore areas has over one century of hydrocarbon exploration with over 72 wildcat wells drilled, but insignificant commercial production to date. A key question is whether these large Caribbean oceanic islands, removed from the input of large terrigenous river systems found in other areas like the Gulf of Mexico and northern South America, have experienced sufficient subsidence and depth of burial for any source rocks that may be present to reach maturity and produce commercial hydrocarbons. We compiled well data and seismic interpretations from previous workers into a depth to Cretaceous-Eocene igneous-metamorphic basement map for Hispaniola, Puerto Rico, and their offshore areas. These maps show the areas of greatest depth to igneous-metamorphic basement and overlying fill to include the Enriquillo basin of the Dominican Republic (5 km), San Juan basin of the Dominican Republic (5.3 km) and Central Plateau basin of Haiti (5.3 km), Cibao basin of the Dominican Republic (5 km), north coast basin of Puerto Rico (1.7 km), south coast basin of Puerto Rico (1.3 km), and Virgin Islands basin (8 km). Of these seven basins, 2D basin modeling using available vitrinite data show that only the collinear San Juan and Azua basins of the Dominican Republic have achieved sufficient burial to place known and inferred source rocks into the oil window in both areas. This result is supported in the case of the Azua basin by the presence of natural, surficial oil seeps and limited production from shallow wells (about 50,000 barrels of 20° API, biodegraded oil was produced in the 1940s and 50s). Low Ro% values of sediments in the Enriquillo basin of comparable thickness and identical source rocks to the San Juan and Azua indicate lower heat flow in the Enriquillo basin. Some of the lack of commercial success in the San Juan basin and adjacent Central Plateau basin of Haiti may reflect that only a total of four wildcat wells have been drilled, two of which had oil and gas shows. Biogenic gas is likely more prevalent in these same basins and within the larger deltas of Hispaniola. Panel_15528 Panel_15528 11:10 AM 11:30 AM
11:30 a.m.
Lithology and TOC at the Base of the Vaca Muerta Formation, Neuquén Basin, Argentina
Four Seasons Ballroom 4
Detailed outcrop and geochemical analyses provides a new understanding to fluctuations in lithology and organic matter at the base of the Vaca Muerta Formation in the Neuquén Basin. Total organic carbon content (TOC) varies (<0.1% - ~16%) throughout the entire Vaca Muerta with the highest values in the initial 70 m and a general decrease upsection. Spectral Gamma Ray (SGR) data collected shows a positive correlation between uranium concentrations and TOC that could be beneficial in unconventional exploration. In the Sierra de la Vaca Muerta (SdlVM) area, five sections were measured to observe the lithologic and TOC changes from a proximal to a distal setting. The strata rich in total organic carbon are confined to the fore and bottom sets of a prograding mixed carbonate siliciclastic shelf on top of the mostly eolian strata of the Tordillo Formation. The onset of marine sedimentation in the Vaca Muerta Formation consists of 20 m thick succession of intercalated sands and siltstones after the initial marine mudstone, and another, thinner (10-15 m) package occurs 40 m above the contact, separated by marine mudstones high in organic content. The TOC varies in concert with sequence stratigraphy; the highest observed TOC value is found just below the maximum flooding surface that is associated with the initial flooding of the basin. In the first sequence, average TOC values are slightly higher in the distal section than in the proximal section (4.6% and 3.7% respectively). Up-section the TOC decreases significantly. The distribution, however, follows a sequence stratigraphic control as packages of richer concentrations coincide with the maximum flooding intervals of subsequent sequences. Correlating SGR and source quality has been used with varying success in other systems. This study’s findings in the Sierra de la Vaca Muerta show that uranium concentrations show peaks at stratigraphic intervals that coincide with higher TOC values. Based on these observations, trends in organic material follow predictable patterns (controlled by lithology and sequences) with the highest concentrations associated with the initial flooding of the basin. Detailed outcrop and geochemical analyses provides a new understanding to fluctuations in lithology and organic matter at the base of the Vaca Muerta Formation in the Neuquén Basin. Total organic carbon content (TOC) varies (<0.1% - ~16%) throughout the entire Vaca Muerta with the highest values in the initial 70 m and a general decrease upsection. Spectral Gamma Ray (SGR) data collected shows a positive correlation between uranium concentrations and TOC that could be beneficial in unconventional exploration. In the Sierra de la Vaca Muerta (SdlVM) area, five sections were measured to observe the lithologic and TOC changes from a proximal to a distal setting. The strata rich in total organic carbon are confined to the fore and bottom sets of a prograding mixed carbonate siliciclastic shelf on top of the mostly eolian strata of the Tordillo Formation. The onset of marine sedimentation in the Vaca Muerta Formation consists of 20 m thick succession of intercalated sands and siltstones after the initial marine mudstone, and another, thinner (10-15 m) package occurs 40 m above the contact, separated by marine mudstones high in organic content. The TOC varies in concert with sequence stratigraphy; the highest observed TOC value is found just below the maximum flooding surface that is associated with the initial flooding of the basin. In the first sequence, average TOC values are slightly higher in the distal section than in the proximal section (4.6% and 3.7% respectively). Up-section the TOC decreases significantly. The distribution, however, follows a sequence stratigraphic control as packages of richer concentrations coincide with the maximum flooding intervals of subsequent sequences. Correlating SGR and source quality has been used with varying success in other systems. This study’s findings in the Sierra de la Vaca Muerta show that uranium concentrations show peaks at stratigraphic intervals that coincide with higher TOC values. Based on these observations, trends in organic material follow predictable patterns (controlled by lithology and sequences) with the highest concentrations associated with the initial flooding of the basin. Panel_15530 Panel_15530 11:30 AM 11:50 AM

8:00 a.m.–11:50 a.m.
Theme 5: New Insights From the Classics—Contraction, Extension and Strike-Slip I (AAPG/PSGD)
Room 501/502/503, Monday Oral Sessions, 01 June, 2015

Panel_14473 Panel_14473 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Room 501/502/503
Panel_15784 Panel_15784 8:00 AM 12:00 AM
8:05 a.m.
Sequence of Deformation in Thrust-Fold Belts: Implications for Cross-Section Balancing
Room 501/502/503
The complex deformational history of thrust-belt structures has implications for the validity of cross-section balancing. 1) The first structures to form are regional fracture sets generated by prevailing plate tectonic stresses. 2) As the thrust wedge grows, the tectonic load flexes the foreland crust leading to extensional fractures sub-parallel to the thrust belt. 3) With continuing thrust advance, the foreland basin rocks experience a third phase of fracturing induced by near-field thrust-tectonic stresses. 4) Perhaps overlapping with stage 3, dominant units, such as carbonate and coarse clastic rocks, undergo layer-parallel shortening (LPS) by pressure-solution cleavage, wedging, and tectonic compaction. Bedding plane detachments accommodate contraction within the LPS zones to produce fold-, cleavage-, and fault-duplexes. 5) The various detachments may link to form through-going thrusts, generating ramp anticlines (fault-bend folds), detachment (lift-off) folds, and fault-cored anticlines (fault-propagation folds). 6) As thrust-related folds evolve, fractures and subsidiary faults initiate in response to constantly changing stress fields in the dominant members. This complex and protracted sequence of deformation raises conflicts with the underlying assumptions of cross-section balancing. Zones of LPS, joined by bedding parallel detachments, produce cryptic global shear strain throughout individual thrust sheets and the thrust wedge as a whole. Cross-section balancing relies on measuring line-lengths and/or areas between established pin-lines, lines perpendicular to bedding in regions presumed to have experienced only plane strain. If rocks have experienced extensive global shear, this assumption is invalid. The validity of balancing is further compromised by an inability to predict the magnitude and distribution of sub-resolution strain produced by LPS in stage 4. Finally, geometric and kinematic relations between thrusts and folds may not be as simple as portrayed in common balancing approaches. Thrust-belt cross sections usually show continuous, through-going master faults (step 5 above), which originate at great depth within the hinterland and step up section toward the foreland to terminate in triangle zones or emerge at the earth’s surface. However, at various stages in their evolution, discontinuous thrust segments may be linked by single folds and fold duplexes, leading to alternative interpretations for many “balanced” sections. The complex deformational history of thrust-belt structures has implications for the validity of cross-section balancing. 1) The first structures to form are regional fracture sets generated by prevailing plate tectonic stresses. 2) As the thrust wedge grows, the tectonic load flexes the foreland crust leading to extensional fractures sub-parallel to the thrust belt. 3) With continuing thrust advance, the foreland basin rocks experience a third phase of fracturing induced by near-field thrust-tectonic stresses. 4) Perhaps overlapping with stage 3, dominant units, such as carbonate and coarse clastic rocks, undergo layer-parallel shortening (LPS) by pressure-solution cleavage, wedging, and tectonic compaction. Bedding plane detachments accommodate contraction within the LPS zones to produce fold-, cleavage-, and fault-duplexes. 5) The various detachments may link to form through-going thrusts, generating ramp anticlines (fault-bend folds), detachment (lift-off) folds, and fault-cored anticlines (fault-propagation folds). 6) As thrust-related folds evolve, fractures and subsidiary faults initiate in response to constantly changing stress fields in the dominant members. This complex and protracted sequence of deformation raises conflicts with the underlying assumptions of cross-section balancing. Zones of LPS, joined by bedding parallel detachments, produce cryptic global shear strain throughout individual thrust sheets and the thrust wedge as a whole. Cross-section balancing relies on measuring line-lengths and/or areas between established pin-lines, lines perpendicular to bedding in regions presumed to have experienced only plane strain. If rocks have experienced extensive global shear, this assumption is invalid. The validity of balancing is further compromised by an inability to predict the magnitude and distribution of sub-resolution strain produced by LPS in stage 4. Finally, geometric and kinematic relations between thrusts and folds may not be as simple as portrayed in common balancing approaches. Thrust-belt cross sections usually show continuous, through-going master faults (step 5 above), which originate at great depth within the hinterland and step up section toward the foreland to terminate in triangle zones or emerge at the earth’s surface. However, at various stages in their evolution, discontinuous thrust segments may be linked by single folds and fold duplexes, leading to alternative interpretations for many “balanced” sections. Panel_15373 Panel_15373 8:05 AM 8:25 AM
8:25 a.m.
Structural Analysis and Section Balancing to Reduce Uncertainty in Field Development in the Upper Magdalena Basin, Colombia
Room 501/502/503
The Neiva sub-basin of the Upper Magdalena basin in Colombia is a mature oil producing area, with prolific production from many fields. It is an intramontane basin limited on the west by the Central Cordillera and on the east by the Eastern Cordillera. The traps are primarily structural in this folded and thrusted area of extensive deformation. Production is typically from sandstones in the Cretaceous Montserrate, Caballos, and Tertiary Honda Formations. Increased coverage of 3D seismic, combined with the extensive well database, has allowed improved and more detailed mapping of the area, and has led to identification of additional opportunities in the area. The 3D seismic is of generally good quality in the deeper Cretaceous units, but in areas of structural complexity the imaging suffers and thus there is significant uncertainty in many parts of the basin. Structural modeling aids in defining opportunities and reducing uncertainty in the areas of greatest opportunity and interest. In addition, this basin has excellent unconventional potential from La Luna, Tetuan and possibly other formations, which will depend on detailed, tested structural mapping and definition as this aspect is explored in the future. The Neiva sub-basin was formed principally by compressive tectonics. In general, the Central Cordillera was thrust eastward (ESE) in the mid-Tertiary, and the thrusts extended into and through the stratigraphic section (Jurassic-Cretaceous-Paleogene) that floors the current basin. These thrusts generally verge east. The basin was a part of the uplifted, eroding fold and thrust belt on the east side of the Central Cordillera in the Eocene, and eventually was overlapped by a foreland/piggyback basin section before and during later episodes of ongoing compressional deformation, again showing eastward vergence in the sub-basin area. In mid-late Miocene, the Eastern Cordillera began significant uplift on generally west-verging thrusts, feeding sediments into the basin from the east side in this latest phase, as well as isolating the basin between the Cordilleras. The Arrayan field is an area that was identified with the expanded 3D coverage. It is a faulted anticline, deep in the basin, and it produces from Caballos Formation. Detailed structural analysis of wells, with structural balancing, illustrates the structural development in the context of the regional tectonics and reduces uncertainty on probable shape and extent of the field. The Neiva sub-basin of the Upper Magdalena basin in Colombia is a mature oil producing area, with prolific production from many fields. It is an intramontane basin limited on the west by the Central Cordillera and on the east by the Eastern Cordillera. The traps are primarily structural in this folded and thrusted area of extensive deformation. Production is typically from sandstones in the Cretaceous Montserrate, Caballos, and Tertiary Honda Formations. Increased coverage of 3D seismic, combined with the extensive well database, has allowed improved and more detailed mapping of the area, and has led to identification of additional opportunities in the area. The 3D seismic is of generally good quality in the deeper Cretaceous units, but in areas of structural complexity the imaging suffers and thus there is significant uncertainty in many parts of the basin. Structural modeling aids in defining opportunities and reducing uncertainty in the areas of greatest opportunity and interest. In addition, this basin has excellent unconventional potential from La Luna, Tetuan and possibly other formations, which will depend on detailed, tested structural mapping and definition as this aspect is explored in the future. The Neiva sub-basin was formed principally by compressive tectonics. In general, the Central Cordillera was thrust eastward (ESE) in the mid-Tertiary, and the thrusts extended into and through the stratigraphic section (Jurassic-Cretaceous-Paleogene) that floors the current basin. These thrusts generally verge east. The basin was a part of the uplifted, eroding fold and thrust belt on the east side of the Central Cordillera in the Eocene, and eventually was overlapped by a foreland/piggyback basin section before and during later episodes of ongoing compressional deformation, again showing eastward vergence in the sub-basin area. In mid-late Miocene, the Eastern Cordillera began significant uplift on generally west-verging thrusts, feeding sediments into the basin from the east side in this latest phase, as well as isolating the basin between the Cordilleras. The Arrayan field is an area that was identified with the expanded 3D coverage. It is a faulted anticline, deep in the basin, and it produces from Caballos Formation. Detailed structural analysis of wells, with structural balancing, illustrates the structural development in the context of the regional tectonics and reduces uncertainty on probable shape and extent of the field. Panel_15369 Panel_15369 8:25 AM 8:45 AM
8:45 a.m.
Kinematic and Thermal Modelling of Contractional Belts: An Example From the Colombian Eastern Foothill Belt
Room 501/502/503
The evolution of the shape and geometry of geological structures through time has rarely been considered in detail in areas where growth strata are absent. This is a long-standing problem because in such cases kinematic restorations have been mostly schematic in nature, and changes in shape and geometry were not realistically considered. As a result, vectors of movement for individual particles during deformation have been only carefully analyzed during analogue modeling. No real examples of the movement of most of the points in a cross section have been documented. In this context actual rock properties cannot be tracked with confidence through geological time and petroleum systems modeling is therefore very speculative in many aspects. In this work we show examples in the Colombian eastern foothill belt, of the application of a new tool (Fetkin-prep) which allows tracking of the position of individual points in the different steps of a kinematic restoration. In our examples this procedure allows subsequent thermal modeling with Fetkin, where the kinematic restoration is calibrated with respect to thermochronometric data. There are many unexpected findings in this pilot study. The first is the fact that it is highly unlikely that the generation of structural relief and topography in the Colombian Eastern Cordillera is only related with brittle faulting. Instead for most of the duration of the deformation in the Cenozoic we find evidence of homogeneous flattening. This means potentially that this mechanism must be considered during deformation in many other orogenic belts, wherever deformation happens at low rates. The second is that oil generation and migration could be as fast as trap formation, if deformation rates are fast. In such a context prospectivity is reduced in those traps where homogeneous flattening was significant and in contrast risk is reduced in those areas where structures appear to be very young. The evolution of the shape and geometry of geological structures through time has rarely been considered in detail in areas where growth strata are absent. This is a long-standing problem because in such cases kinematic restorations have been mostly schematic in nature, and changes in shape and geometry were not realistically considered. As a result, vectors of movement for individual particles during deformation have been only carefully analyzed during analogue modeling. No real examples of the movement of most of the points in a cross section have been documented. In this context actual rock properties cannot be tracked with confidence through geological time and petroleum systems modeling is therefore very speculative in many aspects. In this work we show examples in the Colombian eastern foothill belt, of the application of a new tool (Fetkin-prep) which allows tracking of the position of individual points in the different steps of a kinematic restoration. In our examples this procedure allows subsequent thermal modeling with Fetkin, where the kinematic restoration is calibrated with respect to thermochronometric data. There are many unexpected findings in this pilot study. The first is the fact that it is highly unlikely that the generation of structural relief and topography in the Colombian Eastern Cordillera is only related with brittle faulting. Instead for most of the duration of the deformation in the Cenozoic we find evidence of homogeneous flattening. This means potentially that this mechanism must be considered during deformation in many other orogenic belts, wherever deformation happens at low rates. The second is that oil generation and migration could be as fast as trap formation, if deformation rates are fast. In such a context prospectivity is reduced in those traps where homogeneous flattening was significant and in contrast risk is reduced in those areas where structures appear to be very young. Panel_15367 Panel_15367 8:45 AM 9:05 AM
9:05 a.m.
Development of a Structurally Complex Field Without “Seeing”, Eastern Cordillera Fold and Thrust Belt, Colombia
Room 501/502/503
The initial wells in the Piedemonte area were drilled in an attempt to extend on prolific discoveries to the south. These exploration wells were drilled based on models similar to the observed geometry in the fields to the south. These wells showed significant productive potential and thus 3D seismic was acquired. The 3D seismic, even through several iterations of reprocessing, still does not yield much of an image of the thrust sheets at depth. This has made development of these resources difficult and with high uncertainty on position, extent and size. Structural modeling techniques, especially 2D and 3D restoration and balancing, based in large part on well data have allowed effective development of the area. An initial structural model was developed, based in large part on two sets of two wells, each set oriented in the dip direction. This model was extended to other sections, first including other single wells that encountered only the shallowest producing thrust sheet. Further expanding the network of sections allowed definition of a fault network, with extensive testing of the model via 2D restoration and balancing. The sections were then used as a template to build a full 3D model. Additional 3D restoration and balancing improved the sections and model. Drilling based on this model has proved successful, and has greatly extended the vision of the thrust sheets. As wells are completed, new data are incorporated in the sections and model, thus continuing to reduce uncertainty as drilling progresses. This area of Piedemonte, north of the earlier Cupiagua-Recetor discoveries, with the data from the new wells, has confirmed the initial, foreland verging, stacked thrust model and refined it. The structural style of an antiformal stack in this area is different than the observed backthrusted geometry to the south, and this impacts shape, extent and size of the thrust sheets. Uncertainty in these un-imaged thrust sheets remains high, but the structural model allowed developing the resources effectively. With ten new wells, the thrust sheets are now much better defined, with additional resources discovered and continuing to be developed. The ten wells are all producers or potential producers. With high drilling costs, ensuring that the structural uncertainty is minimized has been to key to effective development. The initial wells in the Piedemonte area were drilled in an attempt to extend on prolific discoveries to the south. These exploration wells were drilled based on models similar to the observed geometry in the fields to the south. These wells showed significant productive potential and thus 3D seismic was acquired. The 3D seismic, even through several iterations of reprocessing, still does not yield much of an image of the thrust sheets at depth. This has made development of these resources difficult and with high uncertainty on position, extent and size. Structural modeling techniques, especially 2D and 3D restoration and balancing, based in large part on well data have allowed effective development of the area. An initial structural model was developed, based in large part on two sets of two wells, each set oriented in the dip direction. This model was extended to other sections, first including other single wells that encountered only the shallowest producing thrust sheet. Further expanding the network of sections allowed definition of a fault network, with extensive testing of the model via 2D restoration and balancing. The sections were then used as a template to build a full 3D model. Additional 3D restoration and balancing improved the sections and model. Drilling based on this model has proved successful, and has greatly extended the vision of the thrust sheets. As wells are completed, new data are incorporated in the sections and model, thus continuing to reduce uncertainty as drilling progresses. This area of Piedemonte, north of the earlier Cupiagua-Recetor discoveries, with the data from the new wells, has confirmed the initial, foreland verging, stacked thrust model and refined it. The structural style of an antiformal stack in this area is different than the observed backthrusted geometry to the south, and this impacts shape, extent and size of the thrust sheets. Uncertainty in these un-imaged thrust sheets remains high, but the structural model allowed developing the resources effectively. With ten new wells, the thrust sheets are now much better defined, with additional resources discovered and continuing to be developed. The ten wells are all producers or potential producers. With high drilling costs, ensuring that the structural uncertainty is minimized has been to key to effective development. Panel_15368 Panel_15368 9:05 AM 9:25 AM
9:25 a.m.
Break
Room 501/502/503
Panel_15785 Panel_15785 9:25 AM 12:00 AM
10:30 a.m.
Detachment Fold Kinematic Modeling: A Breakthrough in Quantitative Descriptions of Detachment Folds
Room 501/502/503
Detachment folds are an important type of fault-related folding structures in fold-thrust belts. Although many geometric and kinematic models for detachment folds have been developed, there is no such a model that presents a quantitative relationship between fold shapes and fault kinematics as fault-propagation fold and fault-bend fold models do. Therefore, the kinematic evolution of detachment folds cannot be mathematically deciphered from the geometries of deformed folds. In this study, a series of fully quantitative models for detachment folds, named DF kinematic models, are developed on the basis of the mathematical expression of conservation of mass. Similar to trishear models for fault-propagation folds, the DF kinematic models are quantitatively described using velocity fields such that they are appropriate for forward and inverse kinematic modeling. The DF kinematic models are able to produce a variety of fold geometries and along-strike variable fold vergence that are commonly observed in nature. As compared to other detachment fold models, the DF kinematic models do not need to specify hinge migration or limb rotation, both of which are inherent in the DF kinematic models, and do not require sinking of synclines on the fold limbs to keep the area balanced. Detachment folds are an important type of fault-related folding structures in fold-thrust belts. Although many geometric and kinematic models for detachment folds have been developed, there is no such a model that presents a quantitative relationship between fold shapes and fault kinematics as fault-propagation fold and fault-bend fold models do. Therefore, the kinematic evolution of detachment folds cannot be mathematically deciphered from the geometries of deformed folds. In this study, a series of fully quantitative models for detachment folds, named DF kinematic models, are developed on the basis of the mathematical expression of conservation of mass. Similar to trishear models for fault-propagation folds, the DF kinematic models are quantitatively described using velocity fields such that they are appropriate for forward and inverse kinematic modeling. The DF kinematic models are able to produce a variety of fold geometries and along-strike variable fold vergence that are commonly observed in nature. As compared to other detachment fold models, the DF kinematic models do not need to specify hinge migration or limb rotation, both of which are inherent in the DF kinematic models, and do not require sinking of synclines on the fold limbs to keep the area balanced. Panel_15370 Panel_15370 10:30 AM 10:50 AM
10:50 a.m.
New Evidence for the Reactivation of Basement Faults in the Development of Alleghany Plateau Folds in the Central Appalachians
Room 501/502/503
Reactivation of Cambrian and older faults throughout the central Appalachians has been long recognized. However what has only recently been recognized and documented is the extent to which these faults have episodically moved throughout the Paleozoic. This recognition has evolved through the benefit of 3-D and better 2-D seismic coverage integrated with well logs studies. These reactivations resulted in thin- or thick-skinned tectonics, depending upon numerous factors including the presence/thickness of salt. Extensive examples of structures with inferred dip-slip and strike-slip motion are presented for faults that trend parallel to both the Iapetan and cross-strike discontinuity (CSD) fabrics. Structural inversion of the Rome Trough faults is very common, and is best observed where there is a minimal Salina salt cover, and where there is significant throw on the faults. Some notable examples are Paint Creek Uplift in eastern Kentucky, Warfield Anticline in southern West Virginia, and Arches fork, Wolf Summit and Chestnut Ridge anticlines in northern West Virginia. Timing on these inversion structures generally had been thought to be primarily Alleghanian; however, reversals in motion (both dip slip and strike slip) compared to original Rome Trough fault motions began as early as Taconic time. Although the throw on the Rome Trough faults diminishes to the north into Pennsylvania, many of the anticlines (e.g., Chestnut ridge, Fayette, Belle Vernon) associated with these faults also reactivated. In addition to reversal of dip slip movement, strike slip movement occurred on many of these faults, as evidenced by series of Riedal shear structures in the Paleozoic section overlying Iapetan faults in West Virginia and Pennsylvania. Right lateral motion is inferred for most of the orogen-parallel, reactivated Rome trough faults. In addition, generally left lateral reactivation of (CSDs) occurred throughout Pennsylvania in Taconic through Alleghanian times. Lastly, the reactivation of many of the Iapetan faults throughout western Pennsylvania beneath the cover of Salina salt during Acadian time caused the initiation of a gravity sliding episode which was later greatly amplified by Alleghanian tectonics. Reactivation of Cambrian and older faults throughout the central Appalachians has been long recognized. However what has only recently been recognized and documented is the extent to which these faults have episodically moved throughout the Paleozoic. This recognition has evolved through the benefit of 3-D and better 2-D seismic coverage integrated with well logs studies. These reactivations resulted in thin- or thick-skinned tectonics, depending upon numerous factors including the presence/thickness of salt. Extensive examples of structures with inferred dip-slip and strike-slip motion are presented for faults that trend parallel to both the Iapetan and cross-strike discontinuity (CSD) fabrics. Structural inversion of the Rome Trough faults is very common, and is best observed where there is a minimal Salina salt cover, and where there is significant throw on the faults. Some notable examples are Paint Creek Uplift in eastern Kentucky, Warfield Anticline in southern West Virginia, and Arches fork, Wolf Summit and Chestnut Ridge anticlines in northern West Virginia. Timing on these inversion structures generally had been thought to be primarily Alleghanian; however, reversals in motion (both dip slip and strike slip) compared to original Rome Trough fault motions began as early as Taconic time. Although the throw on the Rome Trough faults diminishes to the north into Pennsylvania, many of the anticlines (e.g., Chestnut ridge, Fayette, Belle Vernon) associated with these faults also reactivated. In addition to reversal of dip slip movement, strike slip movement occurred on many of these faults, as evidenced by series of Riedal shear structures in the Paleozoic section overlying Iapetan faults in West Virginia and Pennsylvania. Right lateral motion is inferred for most of the orogen-parallel, reactivated Rome trough faults. In addition, generally left lateral reactivation of (CSDs) occurred throughout Pennsylvania in Taconic through Alleghanian times. Lastly, the reactivation of many of the Iapetan faults throughout western Pennsylvania beneath the cover of Salina salt during Acadian time caused the initiation of a gravity sliding episode which was later greatly amplified by Alleghanian tectonics. Panel_15375 Panel_15375 10:50 AM 11:10 AM
11:10 a.m.
Using a New 3-D Structural Model of the Wyoming Laramide Rockies Basement for Static Characterization and Kinematic Reconstruction
Room 501/502/503
To assist with basin screening and modeling, resource assessment, and as input for geomechanical analysis we have constructed a 3D model of the crystalline basement for the region of Wyoming where Laramide structures occurred. Using the model we are able to assess the static characteristics of this system and examine its temporal and spatial evolution. The model was built using published geologic maps and cross sections; 1200 2D seismic lines and 53000 well penetrations. Mapped structures include the principal arches and related back-thrusts and back-limb tightening anticlines. Geometric viability of the model is facilitated using 3D structural framework interpretation and kinematic validation methods. Static Characteristics. The structural relief of principal arches ranges to a maximum of 9.5km. The deepest depressions are at intersections of NW and E-striking principal arches. The controlling faults dip between 20-80° with a mean of 45° and don’t appear to vary as a function of regional strike. The fault length to displacement ratios average 0.08 and fall within published thrust and strike-slip fault populations. High gradients in fault displacement occur where the tips of adjacent faults interact. Arches to the SW, (Wind River arch), are structurally mature with one master fault compared to the more embryonic Bighorn arch in the NE with its many flanking faults. Comparing cross sections between embryonic and mature cases it appears that arch folding predates significant fault slip. 75% of the structural relief for the Bighorn arch is from arch folding with minor fault slip. The Wind River arch has an equal degree of folding but 80% of its total offset is attributable to fault slip. Kinematic Analysis. The principal arches and their attached basins are divided for independent and fault-pinned restoration using flexural flattening and restored opposite to their structural vergence and according to fault fitting constraints. Assuming a fixed NA craton and NE-ward tectonic progression we infer a 4 stage history. The Green River basin moved NNE under-thrusting the Gros Ventre, Wind River, and Sierra Madre domains. These 4 domains then moved NE. Movement changed to ENE as the Beartooth and Owl Creek domains joined the allocthonous group. Final movement was eastward and included the Bighorn, Casper, and Laramie domains. Left-oblique movement occurred on E-W domain boundaries as an accommodation and a slight clockwise rotation of the SW domains is also inferred. To assist with basin screening and modeling, resource assessment, and as input for geomechanical analysis we have constructed a 3D model of the crystalline basement for the region of Wyoming where Laramide structures occurred. Using the model we are able to assess the static characteristics of this system and examine its temporal and spatial evolution. The model was built using published geologic maps and cross sections; 1200 2D seismic lines and 53000 well penetrations. Mapped structures include the principal arches and related back-thrusts and back-limb tightening anticlines. Geometric viability of the model is facilitated using 3D structural framework interpretation and kinematic validation methods. Static Characteristics. The structural relief of principal arches ranges to a maximum of 9.5km. The deepest depressions are at intersections of NW and E-striking principal arches. The controlling faults dip between 20-80° with a mean of 45° and don’t appear to vary as a function of regional strike. The fault length to displacement ratios average 0.08 and fall within published thrust and strike-slip fault populations. High gradients in fault displacement occur where the tips of adjacent faults interact. Arches to the SW, (Wind River arch), are structurally mature with one master fault compared to the more embryonic Bighorn arch in the NE with its many flanking faults. Comparing cross sections between embryonic and mature cases it appears that arch folding predates significant fault slip. 75% of the structural relief for the Bighorn arch is from arch folding with minor fault slip. The Wind River arch has an equal degree of folding but 80% of its total offset is attributable to fault slip. Kinematic Analysis. The principal arches and their attached basins are divided for independent and fault-pinned restoration using flexural flattening and restored opposite to their structural vergence and according to fault fitting constraints. Assuming a fixed NA craton and NE-ward tectonic progression we infer a 4 stage history. The Green River basin moved NNE under-thrusting the Gros Ventre, Wind River, and Sierra Madre domains. These 4 domains then moved NE. Movement changed to ENE as the Beartooth and Owl Creek domains joined the allocthonous group. Final movement was eastward and included the Bighorn, Casper, and Laramie domains. Left-oblique movement occurred on E-W domain boundaries as an accommodation and a slight clockwise rotation of the SW domains is also inferred. Panel_15374 Panel_15374 11:10 AM 11:30 AM
11:30 a.m.
Emplacement of Sand Injections During Contractional Tectonics
Room 501/502/503
Intrusive geological bodies such as magma or salt have been widely recognized in contractional tectonic settings where they fill anticlinal cores or are intruded along thrust planes. However, much less is known about clastic intrusions that potentially intrude along and fill contractional structures. There has recently been a growing interest regarding the study of sand injection complexes and their relevance to hydrocarbon reservoir characterization. Giant exposures of sand injection complexes, including sandstone dykes and sills which cut through hundreds of metres of hydrofractured mudstones, have been described in detail in the Upper Cretaceous-Eocene succession cropping-out in the Panoche and Tumey Hills area (Central California). Here, the occurrence of a large volume of sandstones, organized as interconnected dikes and sills, importantly increases the connectivity and permeability within the host mudstone, thereby providing valuable pathways for fluid migration. In contractional settings, sand intrusion is in theory attributed to high pore-pressure conditions that develop because of the increase in compressive stress. The contribution provided by horizontal compressive stresses (tectonics), although hypothesized, is still to be substantiated by robust field observations. A detailed field survey, carried out in the Panoche and Tumey hills area, allows contractional tectonics-related sandstone intrusions to be recognized for the first time. These sandstones cut through the Upper Cretaceous to Eocene succession (Moreno and Kreyenahgen formations) and are observed to intrude along thrust planes, reverse fault planes and dilational jogs. These relationships allow us to ascertain the role played by contractional tectonics on emplacement of sandstone intrusions during the contractional stages which involved the Great Valley Sequence basin-fill succession. The recognition of such sandstone intrusions systems in contractional settings will allow refinement of reservoir connectivity models. Intrusive geological bodies such as magma or salt have been widely recognized in contractional tectonic settings where they fill anticlinal cores or are intruded along thrust planes. However, much less is known about clastic intrusions that potentially intrude along and fill contractional structures. There has recently been a growing interest regarding the study of sand injection complexes and their relevance to hydrocarbon reservoir characterization. Giant exposures of sand injection complexes, including sandstone dykes and sills which cut through hundreds of metres of hydrofractured mudstones, have been described in detail in the Upper Cretaceous-Eocene succession cropping-out in the Panoche and Tumey Hills area (Central California). Here, the occurrence of a large volume of sandstones, organized as interconnected dikes and sills, importantly increases the connectivity and permeability within the host mudstone, thereby providing valuable pathways for fluid migration. In contractional settings, sand intrusion is in theory attributed to high pore-pressure conditions that develop because of the increase in compressive stress. The contribution provided by horizontal compressive stresses (tectonics), although hypothesized, is still to be substantiated by robust field observations. A detailed field survey, carried out in the Panoche and Tumey hills area, allows contractional tectonics-related sandstone intrusions to be recognized for the first time. These sandstones cut through the Upper Cretaceous to Eocene succession (Moreno and Kreyenahgen formations) and are observed to intrude along thrust planes, reverse fault planes and dilational jogs. These relationships allow us to ascertain the role played by contractional tectonics on emplacement of sandstone intrusions during the contractional stages which involved the Great Valley Sequence basin-fill succession. The recognition of such sandstone intrusions systems in contractional settings will allow refinement of reservoir connectivity models. Panel_15372 Panel_15372 11:30 AM 11:50 AM

8:00 a.m.–11:50 a.m.
Salman Bloch Memorial Session (AAPG/SEPM)
Room 505/506/507, Monday Oral Sessions, 01 June, 2015

Salman Bloch was a truly unique individual who was as passionate about geology as he was devoted to the sport of bodybuilding. He grew up in Poland under Communist rule, a fact that profoundly shaped his personality and outlook on life. He immigrated to the United States to continue his education and start a new life in the West. He was a gifted speaker and writer and fluent in Russian, German, English and his native Polish. Sal received his M.S. degree from University of Wrocław in Poland and a Ph.D. from George Washington University and published numerous papers. After joining the petroleum industry in 1982, where he held research positions at Atlantic-Richfield (ARCO), Norsk Hydro and Texaco, Sal combined his geochemical skills with a newfound interest in sedimentary petrology. Sal was well respected for his dedication and commitment to the geological sciences. He will be remembered for his keen intellect, strong work ethic, dry wit and intense personality; he will definitely be missed.

Salman Bloch was a truly unique individual who was as passionate about geology as he was devoted to the sport of bodybuilding. He grew up in Poland under Communist rule, a fact that profoundly shaped his personality and outlook on life. He immigrated to the United States to continue his education and start a new life in the West. He was a gifted speaker and writer and fluent in Russian, German, English and his native Polish. Sal received his M.S. degree from University of Wrocław in Poland and a Ph.D. from George Washington University and published numerous papers. After joining the petroleum industry in 1982, where he held research positions at Atlantic-Richfield (ARCO), Norsk Hydro and Texaco, Sal combined his geochemical skills with a newfound interest in sedimentary petrology. Sal was well respected for his dedication and commitment to the geological sciences. He will be remembered for his keen intellect, strong work ethic, dry wit and intense personality; he will definitely be missed.

 Panel_14418 Panel_14418 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Room 505/506/507
Panel_15786 Panel_15786 8:00 AM 12:00 AM
8:05 a.m.
Comparing Chlorite-Coat Coverage and Reservoir Quality in Deep Tuscaloosa Sandstones, Louisiana Gulf Coast, USA
Room 505/506/507
Continuous chlorite coats on detrital grains in deep Upper Cretaceous Tuscaloosa sandstones preserve porosity by inhibiting quartz cementation. Where chlorite-coats are discontinuous and incomplete, Tuscaloosa sandstones are extensively cemented by quartz. However, it is not known what percentage of the exposed grain surfaces must be coated by chlorite in order to reduce quartz cementation and preserve porosity in hot (>135°C), deeply buried (> 5 km) Tuscaloosa sandstones. Previous work has quantified the whole-rock volume of chlorite cement in Tuscaloosa sandstones by thin-section point counts but has not measured the 2D proportion of chlorite-coated grain surfaces. In this study, we quantified the percentage of exposed quartz-grain surfaces covered by chlorite cement in deep Tuscaloosa sandstones and compared it to reservoir quality. Petrography and routine core analysis of 141 samples from central Louisiana documented composition, diagenesis, and reservoir quality in fluvial and deltaic Tuscaloosa sandstones. Porosity, permeability, and chlorite-cement volume all have bimodal distributions. Twelve samples representing a wide range of porosity and permeability were selected for quantifying chlorite grain-coat coverage on 50 detrital quartz grains per sample. Average chlorite-coat coverage in these samples ranges from 29% to 95% and has a bimodal distribution. Statistically significant correlations exist between chlorite-coat coverage and volume of chlorite cement, quartz cement, porosity, and permeability. Samples having average chlorite-coat coverage of >60% have preserved high porosity (15–28%) and permeability (4–1249 md) at temperatures of 160°C to 195°C by inhibiting quartz cementation. On the basis of point-count data of chlorite volume from the larger petrographic database, we estimate that less than half the Tuscaloosa sandstones in central Louisiana contain an average of >60% chlorite-coat coverage. The occurrence of continuous chlorite coats has an important influence on reservoir quality in Tuscaloosa sandstones, but local variations in coat coverage are difficult to predict. Although one cannot predict chlorite-coat coverage and reservoir quality foot by foot, a risk estimate can be assigned for encountering higher reservoir quality. Continuous chlorite coats on detrital grains in deep Upper Cretaceous Tuscaloosa sandstones preserve porosity by inhibiting quartz cementation. Where chlorite-coats are discontinuous and incomplete, Tuscaloosa sandstones are extensively cemented by quartz. However, it is not known what percentage of the exposed grain surfaces must be coated by chlorite in order to reduce quartz cementation and preserve porosity in hot (>135°C), deeply buried (> 5 km) Tuscaloosa sandstones. Previous work has quantified the whole-rock volume of chlorite cement in Tuscaloosa sandstones by thin-section point counts but has not measured the 2D proportion of chlorite-coated grain surfaces. In this study, we quantified the percentage of exposed quartz-grain surfaces covered by chlorite cement in deep Tuscaloosa sandstones and compared it to reservoir quality. Petrography and routine core analysis of 141 samples from central Louisiana documented composition, diagenesis, and reservoir quality in fluvial and deltaic Tuscaloosa sandstones. Porosity, permeability, and chlorite-cement volume all have bimodal distributions. Twelve samples representing a wide range of porosity and permeability were selected for quantifying chlorite grain-coat coverage on 50 detrital quartz grains per sample. Average chlorite-coat coverage in these samples ranges from 29% to 95% and has a bimodal distribution. Statistically significant correlations exist between chlorite-coat coverage and volume of chlorite cement, quartz cement, porosity, and permeability. Samples having average chlorite-coat coverage of >60% have preserved high porosity (15–28%) and permeability (4–1249 md) at temperatures of 160°C to 195°C by inhibiting quartz cementation. On the basis of point-count data of chlorite volume from the larger petrographic database, we estimate that less than half the Tuscaloosa sandstones in central Louisiana contain an average of >60% chlorite-coat coverage. The occurrence of continuous chlorite coats has an important influence on reservoir quality in Tuscaloosa sandstones, but local variations in coat coverage are difficult to predict. Although one cannot predict chlorite-coat coverage and reservoir quality foot by foot, a risk estimate can be assigned for encountering higher reservoir quality. Panel_14833 Panel_14833 8:05 AM 8:25 AM
8:25 a.m.
Distinguishing Organic Matter Pores Associated With Depositional Organic Matter versus Migrated Organic Matter in Mudrocks
Room 505/506/507
Organic-matter (OM) pores are an important constituent of mudrocks and comprise the dominant or subsidiary pore network of many shale-gas and shale-oil systems. New research suggests that OM pores form not only in kerogen, as originally proposed, but also in solid bitumen and pyrobitumen. Identifying the type of nanometer- to micrometer-sized organic matter that is present in mudrocks is extremely difficult, if not impossible, using a scanning electron microscope (SEM). However, distinguishing whether the OM-pore hosted organic material exists in place or has migrated would allow the determination to be made whether the original organic material was kerogen or migrated bitumen. There are several SEM-based petrographic criteria that can be used to separate depositional versus migrated organic matter. These criteria include: (1) organic matter occurring after cementation in mineral pores, (2) fossil body-cavity voids filled with organic matter, (3) dense, spongy pore texture of the organic matter, (4) abundant contiguous pores filled with organic matter having a spongy pore network, (5) no alignment of pores in organic matter (aligned OM pores are present in kerogen), (6) cracks in organic matter related to devolatilization, and (7) anomalously larger bubbles associated with development of two hydrocarbon phases. It is important to recognize the difference between deposition organic matter versus migrated organic matter associated nanopores because their distribution is different and this has a profound effect on reservoir quality. Original depositional organic material is composed of kerogen, which can be transformed to bitumen and then oil, gas, solid bitumen, and pyrobitumen (char) during thermal maturation. When bitumen is produced from the kerogen, it can migrate into the mineral pore network and later transform to solid bitumen or pyrobitumen. The final pore network and associated reservoir quality within the mudrock is dependent on the proportions of the distribution of these two organic matter states. OM pores in isolated depositional organic matter may not be well connected and not form a continuous permeability pathway for the hydrocarbons. Migrated organic-matter-hosted pores mimic the three-dimensional distribution of the original mudrock mineral pore network and provide more extensive contiguous permeability pathways than isolated organic matter, thus providing a higher reservoir-quality mudstone system. Organic-matter (OM) pores are an important constituent of mudrocks and comprise the dominant or subsidiary pore network of many shale-gas and shale-oil systems. New research suggests that OM pores form not only in kerogen, as originally proposed, but also in solid bitumen and pyrobitumen. Identifying the type of nanometer- to micrometer-sized organic matter that is present in mudrocks is extremely difficult, if not impossible, using a scanning electron microscope (SEM). However, distinguishing whether the OM-pore hosted organic material exists in place or has migrated would allow the determination to be made whether the original organic material was kerogen or migrated bitumen. There are several SEM-based petrographic criteria that can be used to separate depositional versus migrated organic matter. These criteria include: (1) organic matter occurring after cementation in mineral pores, (2) fossil body-cavity voids filled with organic matter, (3) dense, spongy pore texture of the organic matter, (4) abundant contiguous pores filled with organic matter having a spongy pore network, (5) no alignment of pores in organic matter (aligned OM pores are present in kerogen), (6) cracks in organic matter related to devolatilization, and (7) anomalously larger bubbles associated with development of two hydrocarbon phases. It is important to recognize the difference between deposition organic matter versus migrated organic matter associated nanopores because their distribution is different and this has a profound effect on reservoir quality. Original depositional organic material is composed of kerogen, which can be transformed to bitumen and then oil, gas, solid bitumen, and pyrobitumen (char) during thermal maturation. When bitumen is produced from the kerogen, it can migrate into the mineral pore network and later transform to solid bitumen or pyrobitumen. The final pore network and associated reservoir quality within the mudrock is dependent on the proportions of the distribution of these two organic matter states. OM pores in isolated depositional organic matter may not be well connected and not form a continuous permeability pathway for the hydrocarbons. Migrated organic-matter-hosted pores mimic the three-dimensional distribution of the original mudrock mineral pore network and provide more extensive contiguous permeability pathways than isolated organic matter, thus providing a higher reservoir-quality mudstone system. Panel_14832 Panel_14832 8:25 AM 8:45 AM
8:45 a.m.
Impact of Microbes on Reservoir Quality
Room 505/506/507
It has long been recognized that temperature is a major factor in controlling mineral dissolution and creating secondary porosity in reservoirs. But, what about alteration that occurs soon after deposition? Studies of modern and low temperature ancient sandstones suggests that microbial processes play a very important early role in diagenesis which impacts both conventional and unconventional reservoir quality. Initial mineral dissolution, the development of early carbonate cements, and the formation of early clay grain coats, all appear to be influenced by microbial activity at near surface conditions. Recognizing and understanding these processes is key to improved diagenetic modeling. Examples showing the influence of microbes on early diagenesis will be shown from a variety of modern depositional settings. For example, SEM/EDS studies of modern fluvial sandstones show the presence of thin, transparent "saran-like" biofilms which appear to act as a glue attaching clay to grains to form early clay coats and also promoting the precipitation of early carbonate cement. Other examples include the partial dissolution of feldspar and mafic minerals to form early intragranular "secondary porosity" in a tropical delta, the binding of sand grains in a modern shrimp burrow, and the alteration of basalt in a contaminated aquifer. It has long been recognized that temperature is a major factor in controlling mineral dissolution and creating secondary porosity in reservoirs. But, what about alteration that occurs soon after deposition? Studies of modern and low temperature ancient sandstones suggests that microbial processes play a very important early role in diagenesis which impacts both conventional and unconventional reservoir quality. Initial mineral dissolution, the development of early carbonate cements, and the formation of early clay grain coats, all appear to be influenced by microbial activity at near surface conditions. Recognizing and understanding these processes is key to improved diagenetic modeling. Examples showing the influence of microbes on early diagenesis will be shown from a variety of modern depositional settings. For example, SEM/EDS studies of modern fluvial sandstones show the presence of thin, transparent "saran-like" biofilms which appear to act as a glue attaching clay to grains to form early clay coats and also promoting the precipitation of early carbonate cement. Other examples include the partial dissolution of feldspar and mafic minerals to form early intragranular "secondary porosity" in a tropical delta, the binding of sand grains in a modern shrimp burrow, and the alteration of basalt in a contaminated aquifer. Panel_14831 Panel_14831 8:45 AM 9:05 AM
9:05 a.m.
Diagenesis and Reservoir Quality of the Oligocene Vedder Sandstone, of the Rio Bravo Oil Field, California
Room 505/506/507
The Rio Bravo oil field is located about 15 miles north-west of Bakersfield, CA. The zone of importance is the Vedder Sandstone, which is about 1,250 feet (380m) in thickness. The thin (<100ft, 30m) Miocene Rio Bravo sandstone, which unconformably overlies the Vedder, is included in the main Vedder reservoir. Burial depths range from approximately 10,750 feet (3,415m) to 12,450 feet (3,800m), with reservoir temperature at 120°C. The mineralogy and lithology of Oligocene sandstones of the Rio Bravo oil field were examined using a petrographic microscope and a scanning electron microscope equipped with and energy dispersive x-ray spectrometer (SEM-EDS) and a cathode luminescence imaging system (SEM-CL). The Vedder Sandstones are medium to fine-grain, subangular to subround, very poorly to well sorted, arkosic arenites and wackes. Accessory minerals of the Vedder Formation include biotite, muscovite, chlorite, glauconite, pyrite, zircon, zeolite, hornblende, rutile, phosphate, and apatite. The diagenetic features affecting reservoir quality of the Vedder Sandstones are similar among wells. Albitization occurs extensively along fractures in plagioclase and K-feldspar grains. Plagioclase shows varying degrees of alteration to clay or sericite. Biotite has been altered to chlorite and pyrite. Precipitation of cements include clays (kaolinite, chlorite, and illite and/ or mixed-layer illite/smectite or illite/chlorite), and carbonates. Kaolinite occurs as pore-filling cement, commonly associated with feldspar dissolution. Carbonates include calcite and dolomite. Calcite cement occurs within some through going fractures. Both calcite and dolomite have partially to completely replaced framework-grains. Porosity within the Vedder sands is controlled mainly by compaction and dissolution of framework-grains. Compaction decreased porosity through ductile grain deformation of shale clasts and micas, which commonly were squeezed into adjacent pores to form pseudomatrix. Rotation and slippage of grains and fracturing of brittle grains is also widespread. Dissolution of framework-grains created oversized and elongate pores, with the result that secondary intergranular porosity contributes significantly to overall reservoir quality. The Rio Bravo oil field is located about 15 miles north-west of Bakersfield, CA. The zone of importance is the Vedder Sandstone, which is about 1,250 feet (380m) in thickness. The thin (<100ft, 30m) Miocene Rio Bravo sandstone, which unconformably overlies the Vedder, is included in the main Vedder reservoir. Burial depths range from approximately 10,750 feet (3,415m) to 12,450 feet (3,800m), with reservoir temperature at 120°C. The mineralogy and lithology of Oligocene sandstones of the Rio Bravo oil field were examined using a petrographic microscope and a scanning electron microscope equipped with and energy dispersive x-ray spectrometer (SEM-EDS) and a cathode luminescence imaging system (SEM-CL). The Vedder Sandstones are medium to fine-grain, subangular to subround, very poorly to well sorted, arkosic arenites and wackes. Accessory minerals of the Vedder Formation include biotite, muscovite, chlorite, glauconite, pyrite, zircon, zeolite, hornblende, rutile, phosphate, and apatite. The diagenetic features affecting reservoir quality of the Vedder Sandstones are similar among wells. Albitization occurs extensively along fractures in plagioclase and K-feldspar grains. Plagioclase shows varying degrees of alteration to clay or sericite. Biotite has been altered to chlorite and pyrite. Precipitation of cements include clays (kaolinite, chlorite, and illite and/ or mixed-layer illite/smectite or illite/chlorite), and carbonates. Kaolinite occurs as pore-filling cement, commonly associated with feldspar dissolution. Carbonates include calcite and dolomite. Calcite cement occurs within some through going fractures. Both calcite and dolomite have partially to completely replaced framework-grains. Porosity within the Vedder sands is controlled mainly by compaction and dissolution of framework-grains. Compaction decreased porosity through ductile grain deformation of shale clasts and micas, which commonly were squeezed into adjacent pores to form pseudomatrix. Rotation and slippage of grains and fracturing of brittle grains is also widespread. Dissolution of framework-grains created oversized and elongate pores, with the result that secondary intergranular porosity contributes significantly to overall reservoir quality. Panel_14830 Panel_14830 9:05 AM 9:25 AM
9:25 a.m.
Break
Room 505/506/507
Panel_15787 Panel_15787 9:25 AM 12:00 AM
10:10 a.m.
Formation Water Composition as a Guide to Fluid Flow and Diagenetic Processes in Three Southern California Basins
Room 505/506/507
Fluid composition can provide important evidence of active basin processes. In the offshore Santa Barbara basin, changes in fluid composition in wells close to the fault demonstrate the influx of sea water into the South Ellwood field along the Ellwood fault. The reservoir is about one km below the sea bed in siliceous, Monterey shale and is currently underpressured (about 50% of hydrostatic). The opal to quartz transition has resulted in the shift of d18O from near zero to about +4 in the present day reservoir fluid. Wells close to the South Ellwood fault have d18O values approaching zero due to the influx of sea water, in addition to having elevated SO4= and Mg++ content consistent with sea water influx. Formation waters in the San Joaquin basin (SJB) and Los Angeles basin (LAB) are classic examples of arkosic sediment-sea water interaction in young, largely late Tertiary, first-cycle sedimentary basins. Maximum depth of sample control is about 4.1 km in the SJB to about 3.5 km in the LAB, where temperatures are 130-160°C to 150°C, respectively. Both basin waters are generally more dilute than sea water (60 to 80%), which mostly reflects dilution by the I-S clay reaction and the lack of salt or other evaporite underpinnings to these basins. Abundant SO4= and Mg++ in sea water is sequestered by early pyrite, siderite and dolomite cements. One similarity in the deep waters from the two basin, and offshore waters is abundant organic acids in the waters (up to 90 % of the total alkalinity) from Monterey type kerogen. Water from both basins show trends of positive oxygen and negative hydrogen relative to sea water and the meteoric water line. There are some significant differences in the water composition in the deep part of both basins. In the SJB, the albitization of plagioclase results in high Ca/Na ratios and low Sr isotopic ratios relative to initial Tertiary marine values. In contrast, the LAB has a relatively radiogenic Sr isotopic values and the d18O is not as positive as in the SJB. High 87/86Sr values are attributed to clay diagenesis in the LAB but this conclusion is not well documented. Overall the formation waters are consistent with petrographic observations that the basin systems as a whole have not been subjected to large scale vertical fluid flow. Formation waters from the deep basins can be distinguished from those at shallow levels, allowing detection of upward fluid movement along pathways. Fluid composition can provide important evidence of active basin processes. In the offshore Santa Barbara basin, changes in fluid composition in wells close to the fault demonstrate the influx of sea water into the South Ellwood field along the Ellwood fault. The reservoir is about one km below the sea bed in siliceous, Monterey shale and is currently underpressured (about 50% of hydrostatic). The opal to quartz transition has resulted in the shift of d18O from near zero to about +4 in the present day reservoir fluid. Wells close to the South Ellwood fault have d18O values approaching zero due to the influx of sea water, in addition to having elevated SO4= and Mg++ content consistent with sea water influx. Formation waters in the San Joaquin basin (SJB) and Los Angeles basin (LAB) are classic examples of arkosic sediment-sea water interaction in young, largely late Tertiary, first-cycle sedimentary basins. Maximum depth of sample control is about 4.1 km in the SJB to about 3.5 km in the LAB, where temperatures are 130-160°C to 150°C, respectively. Both basin waters are generally more dilute than sea water (60 to 80%), which mostly reflects dilution by the I-S clay reaction and the lack of salt or other evaporite underpinnings to these basins. Abundant SO4= and Mg++ in sea water is sequestered by early pyrite, siderite and dolomite cements. One similarity in the deep waters from the two basin, and offshore waters is abundant organic acids in the waters (up to 90 % of the total alkalinity) from Monterey type kerogen. Water from both basins show trends of positive oxygen and negative hydrogen relative to sea water and the meteoric water line. There are some significant differences in the water composition in the deep part of both basins. In the SJB, the albitization of plagioclase results in high Ca/Na ratios and low Sr isotopic ratios relative to initial Tertiary marine values. In contrast, the LAB has a relatively radiogenic Sr isotopic values and the d18O is not as positive as in the SJB. High 87/86Sr values are attributed to clay diagenesis in the LAB but this conclusion is not well documented. Overall the formation waters are consistent with petrographic observations that the basin systems as a whole have not been subjected to large scale vertical fluid flow. Formation waters from the deep basins can be distinguished from those at shallow levels, allowing detection of upward fluid movement along pathways. Panel_14829 Panel_14829 10:10 AM 10:30 AM
10:30 a.m.
3-D Grain-Scale Simulation of Diagenesis and Rock Properties
Room 505/506/507
Fundamental geomechanical, petrophysical, and fluid-flow properties of clastic rocks reflect grain-scale compositions and textures. There is a revolution underway in the ability to predict these properties via “digital physics” simulations at the grain scale using high-resolution three-dimensional images of sample material as input constraints. Comparatively little work has been done, however, to develop “digital sedimentary petrology” models capable of predicting 3D grain-scale compositions and textures as a function of sediment depositional properties and diagenetic histories. Yet such models are intriguing because, when combined with digital physics simulations, they could provide a uniquely powerful basis for predicting rock properties away from well control, reconstructing the evolution in rock properties through geologic time, and forecasting rock response to engineering activities. Consequently, we are developing a 3D petrologic modeling system (“Cyberstone”) that incorporates the following components: (1) simulation of the physics of grain deposition where shapes, size distributions, compositions, and physical properties of grains reflect the characteristics of sediments in nature, (2) simulation of the processes responsible for compaction including grain rearrangement; elastic, plastic, and brittle deformation; and contact dissolution (“pressure solution”), and (3) simulation of the effects of geochemical reactions such as quartz overgrowth cementation. An important input for the simulator is the stress and thermal history of the simulated rock. In parallel with the development of the modeling system we are conducting a suite of laboratory experiments that yield fundamental insights into the controls on depositional and diagenetic processes while providing benchmarks for evaluating the model performance. We also rely on detailed analysis of geologic data for process understanding, constraining material properties and geochemical kinetics, and testing the efficacy of model assumptions. Fundamental geomechanical, petrophysical, and fluid-flow properties of clastic rocks reflect grain-scale compositions and textures. There is a revolution underway in the ability to predict these properties via “digital physics” simulations at the grain scale using high-resolution three-dimensional images of sample material as input constraints. Comparatively little work has been done, however, to develop “digital sedimentary petrology” models capable of predicting 3D grain-scale compositions and textures as a function of sediment depositional properties and diagenetic histories. Yet such models are intriguing because, when combined with digital physics simulations, they could provide a uniquely powerful basis for predicting rock properties away from well control, reconstructing the evolution in rock properties through geologic time, and forecasting rock response to engineering activities. Consequently, we are developing a 3D petrologic modeling system (“Cyberstone”) that incorporates the following components: (1) simulation of the physics of grain deposition where shapes, size distributions, compositions, and physical properties of grains reflect the characteristics of sediments in nature, (2) simulation of the processes responsible for compaction including grain rearrangement; elastic, plastic, and brittle deformation; and contact dissolution (“pressure solution”), and (3) simulation of the effects of geochemical reactions such as quartz overgrowth cementation. An important input for the simulator is the stress and thermal history of the simulated rock. In parallel with the development of the modeling system we are conducting a suite of laboratory experiments that yield fundamental insights into the controls on depositional and diagenetic processes while providing benchmarks for evaluating the model performance. We also rely on detailed analysis of geologic data for process understanding, constraining material properties and geochemical kinetics, and testing the efficacy of model assumptions. Panel_14828 Panel_14828 10:30 AM 10:50 AM
10:50 a.m.
A Regional Diagenetic and Petrophysical Model for the Montney Formation, Western Canada Sedimentary Basin
Room 505/506/507
The Lower Triassic Montney Formation of the Western Canadian Sedimentary Basin is a world-class unconventional resource of gas, gas condensate and oil. Although commonly described as a shale, it is a siltstone over most of its subcrop, which presents complications for understanding and predicting petrophysical properties and hydrocarbon distribution. Petrophysical properties are functions of rock fabric, mineralogy and diagenetic processes, which in turn depend on sediment provenance, depositional environment, the pressure and temperature history, and fluid flow. In this study we are building a basin-wide petrophysical assessment of the Montney Formation, related to mineralogy and diagenesis and correlated with a sequence stratigraphic model. Datasets include mineralogical analyses from QEMSCAN and XRD, whole rock geochemical analyses by ICP-MS/ ICP-EAS, petrographic analysis from thin section investigation with optical and cathodoluminescence microscope and SEM imaging and pore system characterization. The Montney paragenetic sequence includes both pore-occluding and porosity-enhancing events. Pore-occluding events include precipitation of cements (quartz, feldspar, calcite and several generations of dolomite), mineral replacement (dolomite was found to replace silicate grains and gypsum replaces carbonates) and precipitation of authigenic phases in open pore space (pyrite and different types of clay). Pore-enhancing events include dissolution of different phases (feldspar, quartz and carbonate bioclaststic grains). Mapping mineralogy and diagenesis throughout the basin and incorporating this information together with well-logs into GAMLS software (Geologic Analysis via Maximum Likelihood System) enabled us to generate a lithological model of the Montney that was fine-tuned against core logs. From the calibrated model, we calculated porosity and water saturation profiles for selected wells and compared these results with porosity data obtained in the lab. This study is the first attempt at understanding pore systems of the Montney formation on a regional scale and within the sequence stratigraphic boundaries. Our results provide a platform for modeling basin scale fluid flow and predicting hydrocarbon distribution in the Montney. The Lower Triassic Montney Formation of the Western Canadian Sedimentary Basin is a world-class unconventional resource of gas, gas condensate and oil. Although commonly described as a shale, it is a siltstone over most of its subcrop, which presents complications for understanding and predicting petrophysical properties and hydrocarbon distribution. Petrophysical properties are functions of rock fabric, mineralogy and diagenetic processes, which in turn depend on sediment provenance, depositional environment, the pressure and temperature history, and fluid flow. In this study we are building a basin-wide petrophysical assessment of the Montney Formation, related to mineralogy and diagenesis and correlated with a sequence stratigraphic model. Datasets include mineralogical analyses from QEMSCAN and XRD, whole rock geochemical analyses by ICP-MS/ ICP-EAS, petrographic analysis from thin section investigation with optical and cathodoluminescence microscope and SEM imaging and pore system characterization. The Montney paragenetic sequence includes both pore-occluding and porosity-enhancing events. Pore-occluding events include precipitation of cements (quartz, feldspar, calcite and several generations of dolomite), mineral replacement (dolomite was found to replace silicate grains and gypsum replaces carbonates) and precipitation of authigenic phases in open pore space (pyrite and different types of clay). Pore-enhancing events include dissolution of different phases (feldspar, quartz and carbonate bioclaststic grains). Mapping mineralogy and diagenesis throughout the basin and incorporating this information together with well-logs into GAMLS software (Geologic Analysis via Maximum Likelihood System) enabled us to generate a lithological model of the Montney that was fine-tuned against core logs. From the calibrated model, we calculated porosity and water saturation profiles for selected wells and compared these results with porosity data obtained in the lab. This study is the first attempt at understanding pore systems of the Montney formation on a regional scale and within the sequence stratigraphic boundaries. Our results provide a platform for modeling basin scale fluid flow and predicting hydrocarbon distribution in the Montney. Panel_14827 Panel_14827 10:50 AM 11:10 AM
11:10 a.m.
Surface Energy Effects on Formation and Preservation of Microrhombic Calcite Fabrics and Porosity
Room 505/506/507
Surface energy affects both nucleation and growth of small crystals. This study evaluates the theory behind several proposed mechanisms for porosity preservation by surface-energy control related to crystal and pore-size variations. These theories are tested with microrhombic calcite fabrics in the Pawnee Field (Cretaceous limestone reservoir, Bee Co, TX). Ostwald ripening, crystal growth, and size-selective nucleation will be evaluated. Examined microrhombic calcite fabrics do not have the size distribution expected by Ostwald ripening. Therefore, alteration of crystal and pore-size distribution by Ostwald ripening after calcite precipitation is not a major influence on microrhombic calcite and associated micropore fabrics. Emmanuel et al. (2010) proposed that surface energy selectively preserves small pores by reducing Surface-area normalized growth rate into small pores. The smallest possible stable pore has a critical radius that is controlled by degree of supersaturation and the surface energy. Smaller pores enlarge to the critical radius by dissolution. Larger pores cement until they also approach the critical radius. Observed mean crystal size and size distributions could be explained by this model, but dissolution-enlarged micropores are absent and pore-size variation is too large to be consistent with this theory. This mechanism may help form microrhombic calcite, but it is not responsible for its preservation. Nucleation controls burial cementation by controlling where and how many crystals grow in pores. Burial calcite nucleation is also controlled by surface energy and supersaturation. Because surface area per pore is small for small pores, calcite crystals are less likely to nucleate in a small pore, and if they do, they occlude only the small volume of the pore. Microrhombic calcite fabrics at Pawnee field are most consistent with selective porosity preservation during burial by nucleation. These concepts can be used to predict settings where porosity between microrhombs is expected and how this porosity is preserved during early and late burial. Supersaturation controls both nucleation and growth, so supersaturation history controls formation and preservation of porosity associated with microrhombic calcite. Surface energy affects both nucleation and growth of small crystals. This study evaluates the theory behind several proposed mechanisms for porosity preservation by surface-energy control related to crystal and pore-size variations. These theories are tested with microrhombic calcite fabrics in the Pawnee Field (Cretaceous limestone reservoir, Bee Co, TX). Ostwald ripening, crystal growth, and size-selective nucleation will be evaluated. Examined microrhombic calcite fabrics do not have the size distribution expected by Ostwald ripening. Therefore, alteration of crystal and pore-size distribution by Ostwald ripening after calcite precipitation is not a major influence on microrhombic calcite and associated micropore fabrics. Emmanuel et al. (2010) proposed that surface energy selectively preserves small pores by reducing Surface-area normalized growth rate into small pores. The smallest possible stable pore has a critical radius that is controlled by degree of supersaturation and the surface energy. Smaller pores enlarge to the critical radius by dissolution. Larger pores cement until they also approach the critical radius. Observed mean crystal size and size distributions could be explained by this model, but dissolution-enlarged micropores are absent and pore-size variation is too large to be consistent with this theory. This mechanism may help form microrhombic calcite, but it is not responsible for its preservation. Nucleation controls burial cementation by controlling where and how many crystals grow in pores. Burial calcite nucleation is also controlled by surface energy and supersaturation. Because surface area per pore is small for small pores, calcite crystals are less likely to nucleate in a small pore, and if they do, they occlude only the small volume of the pore. Microrhombic calcite fabrics at Pawnee field are most consistent with selective porosity preservation during burial by nucleation. These concepts can be used to predict settings where porosity between microrhombs is expected and how this porosity is preserved during early and late burial. Supersaturation controls both nucleation and growth, so supersaturation history controls formation and preservation of porosity associated with microrhombic calcite. Panel_14826 Panel_14826 11:10 AM 11:30 AM
11:30 a.m.
Reservoir Quality and Rock Properties Modeling Results – Triassic and Jurassic Sandstones, Greater Shearwater Area, UK Central North Sea
Room 505/506/507
The complex burial and diagenetic histories of the Jurassic Fulmar and Triassic Skagerrak sandstones in the UK Central North Sea present significant challenges with regards to reservoir quality and rock property prediction. Commercial reservoir quality is retained despite deep burial and associated high temperatures and pressures. Shallow marine Fulmar sands are normally compacted (mean IGV = 26±3%) yet have porosities of 21 – 33%. Porosity was preserved through inhibition of quartz cementation by clay and microquartz coatings, and enhanced by dissolution of framework grains (~ 5%). Skagerrak fluvial sands are more compacted (mean IGV = 23±2%), exhibit minor feldspar dissolution (<1%), and have porosities of 16 – 27%. Quartz cement averages only 2±1.5% due to robust chlorite coats that cover 80% (±13%) of quartz surfaces. We modeled reservoir quality evolution using the forward diagenetic model Touchstone, which simulates porosity loss due to compaction and quartz cementation. Quantitative petrographic analyses and burial history data were used to calibrate Touchstone model parameters. The results were applied to deeper prospects for pre-drill prediction of porosity and permeability. In parallel, petrophysical data were used to characterize the elastic properties of the sandstones to provide a basis for quantitative seismic forward modeling. Experimental data and core-calibrated petrophysical results, reflecting variable in situ fluids and saturations, were used to build an elastic properties model. The model is robust and was used to generate fluid-filled sandstone properties, incorporating Touchstone results, for prospect-specific seismic attribute modeling. Well results from exploration wells are in good agreement with pre-drill Touchstone and elastic properties model predictions. The complex burial and diagenetic histories of the Jurassic Fulmar and Triassic Skagerrak sandstones in the UK Central North Sea present significant challenges with regards to reservoir quality and rock property prediction. Commercial reservoir quality is retained despite deep burial and associated high temperatures and pressures. Shallow marine Fulmar sands are normally compacted (mean IGV = 26±3%) yet have porosities of 21 – 33%. Porosity was preserved through inhibition of quartz cementation by clay and microquartz coatings, and enhanced by dissolution of framework grains (~ 5%). Skagerrak fluvial sands are more compacted (mean IGV = 23±2%), exhibit minor feldspar dissolution (<1%), and have porosities of 16 – 27%. Quartz cement averages only 2±1.5% due to robust chlorite coats that cover 80% (±13%) of quartz surfaces. We modeled reservoir quality evolution using the forward diagenetic model Touchstone, which simulates porosity loss due to compaction and quartz cementation. Quantitative petrographic analyses and burial history data were used to calibrate Touchstone model parameters. The results were applied to deeper prospects for pre-drill prediction of porosity and permeability. In parallel, petrophysical data were used to characterize the elastic properties of the sandstones to provide a basis for quantitative seismic forward modeling. Experimental data and core-calibrated petrophysical results, reflecting variable in situ fluids and saturations, were used to build an elastic properties model. The model is robust and was used to generate fluid-filled sandstone properties, incorporating Touchstone results, for prospect-specific seismic attribute modeling. Well results from exploration wells are in good agreement with pre-drill Touchstone and elastic properties model predictions. Panel_14825 Panel_14825 11:30 AM 11:50 AM

8:00 a.m.–11:50 a.m.
Theme 3: Modeling of Carbonate and Evaporite Systems (AAPG/SEPM)
Room 601/603, Monday Oral Sessions, 01 June, 2015

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Panel_14443 Panel_14443 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Room 601/603
Panel_15788 Panel_15788 8:00 AM 12:00 AM
8:05 a.m.
Evaporite Diagenesis Models of a Continental Sabkha System: Insights From the Holocene at Dukhan, Qatar
Room 601/603
Inner ramp carbonate systems are characterized by micro-relief where small changes in sea level may introduce or remove marine waters. The water table is close to the surface, promoting evaporite formation in capillary zones and standing water. This results in precipitation of evaporites, with solutes derived from meteoric and marine waters. Diagenetic reactions in these ‘evaporite factories’ affect pore systems in sediments and in underlying and downdip bedrock. Here we examine the distribution and origin of evaporites in the Holocene Dukhan sabkha in Qatar, and their response to hydrochemical changes in a system driven by isolation from marine influence and input of meteoric waters. Holocene sabkha sediments 4-6 m thick (max 12 m) have accumulated in a structural low covering 107 km2. Sea-level reconstruction suggests early Holocene marine flooding from the north, forming an embayment that became progressively more restricted, marked by evaporitic lakes or salinas. Prismatic gypsum, up to 7 m thick, is interpreted as a saline lake in middle portions of the sabkha. In the northeast a 12 km2 salt flat is the youngest lake facies, fed by marine waters. Most of the sabkha is 1-2 meters below sea level. The water table lies 0.5 to 1.0 m below the surface (-2.5 to -3.0 m masl), fluctuating annually by c.40 cm reflecting dynamic recharge and evaporative drawdown. Gypsum is the dominant evaporite mineral (20-30%), followed by halite (8-11%), anhydrite (5%) and grain coating carbonate. Total dissolved solids in pore-waters in underlying Eocene carbonates increase with depth and exceed those in Holocene sediments, even at the height of the dry season. However, measurements of piezometric head indicate upward flow from the Eocene into overlying confining sabkha sediments, driven by shallow evaporation. This results in gypsum precipitation, depleting calcium and sulfate in shallow brines relative to source waters. Within the Holocene sediments, this depletion increases from the margins to the center of the sabkha. The sabkha is thinner towards the north, enhancing evaporative concentration of solutes and diagenetic gypsum formation. However, within the Eocene there is a gentle but significant decrease in head from north to south (c.8 cm/km), reflecting inflow of marine waters from the north. Topographic control on sedimentation and fluid flow patterns combine to control precipitation of evaporites both within restricted water bodies and as diagenetic precipitates. Inner ramp carbonate systems are characterized by micro-relief where small changes in sea level may introduce or remove marine waters. The water table is close to the surface, promoting evaporite formation in capillary zones and standing water. This results in precipitation of evaporites, with solutes derived from meteoric and marine waters. Diagenetic reactions in these ‘evaporite factories’ affect pore systems in sediments and in underlying and downdip bedrock. Here we examine the distribution and origin of evaporites in the Holocene Dukhan sabkha in Qatar, and their response to hydrochemical changes in a system driven by isolation from marine influence and input of meteoric waters. Holocene sabkha sediments 4-6 m thick (max 12 m) have accumulated in a structural low covering 107 km2. Sea-level reconstruction suggests early Holocene marine flooding from the north, forming an embayment that became progressively more restricted, marked by evaporitic lakes or salinas. Prismatic gypsum, up to 7 m thick, is interpreted as a saline lake in middle portions of the sabkha. In the northeast a 12 km2 salt flat is the youngest lake facies, fed by marine waters. Most of the sabkha is 1-2 meters below sea level. The water table lies 0.5 to 1.0 m below the surface (-2.5 to -3.0 m masl), fluctuating annually by c.40 cm reflecting dynamic recharge and evaporative drawdown. Gypsum is the dominant evaporite mineral (20-30%), followed by halite (8-11%), anhydrite (5%) and grain coating carbonate. Total dissolved solids in pore-waters in underlying Eocene carbonates increase with depth and exceed those in Holocene sediments, even at the height of the dry season. However, measurements of piezometric head indicate upward flow from the Eocene into overlying confining sabkha sediments, driven by shallow evaporation. This results in gypsum precipitation, depleting calcium and sulfate in shallow brines relative to source waters. Within the Holocene sediments, this depletion increases from the margins to the center of the sabkha. The sabkha is thinner towards the north, enhancing evaporative concentration of solutes and diagenetic gypsum formation. However, within the Eocene there is a gentle but significant decrease in head from north to south (c.8 cm/km), reflecting inflow of marine waters from the north. Topographic control on sedimentation and fluid flow patterns combine to control precipitation of evaporites both within restricted water bodies and as diagenetic precipitates. Panel_15073 Panel_15073 8:05 AM 8:25 AM
8:25 a.m.
Textural Types of Evaporites in Holocene Sabkhas of Qatar and Their Geological Significance
Room 601/603
The growth habits and distribution of evaporite minerals in sabkhas of Qatar provide insights in their origins and models for the interpretation of ancient evaporites. The Holocene forms a 3-10 km wide coastal plain around the peninsula of Qatar. Rates of evaporation exceed precipitation by a factor of 1000 for six or more months of the year. In such an arid climate, bodies of standing water and evaporation in the capillary fringe promote rapid formation of evaporites. Evaporite minerals are common throughout the 3-10 meters of the Holocene. Gypsum dominantes (8-20%), followed by halite (6-10%), with minor anhydrite, calcite, dolomite and probably attapulgite. The most obvious textural differences occur between subaqueous mineral phases deposited in standing water, those formed in the capillary fringe, and precipitates near the water table. Subaqueous crystals are clear, devoid of much sediment, relatively large (mm-cm sized), laminated and may show compressional ridges(tepees) at the surface. Gypsum forms vertically-oriented, ‘fish-tail’ twins in vertical arrays. Halite occurs as hoppers and vertical prisms. Halite is an indicator of a marine water source. Thick subaqueous deposits only occur where there has been a marine source. Layers of crystals nucleated along chemical contacts in the water column and fish-tail twin habits are diagnostic. Evaporites formed in the capillary fringe are typically displacive, incorporate sediment, finely crystalline or poikilotopic, showing variable degree of crystallographic ordering. Micritic coatings are common. Halite is a common pore-filling, often leaving molds. Capillary fringe evaporites habits and morphology reflect seasonal changes in water chemistry. Evaporites formed at the water table are poikilotopic and may/may not be euhedral. This style of predominantly gypsum cementation has not been documented previously. Desert rose twins are the most well know water table morphology. Layers may extend over kilometers, reducing interparticle pore space by 20-30%. Crystals grow by interparticle cementation with little/no replacement. All styles of evaporite cementation are driven by extreme aridity of the climate. Millimeter sized crystals can grow in a few months, a geological instant. Limiting factors on growth rates of evaporites are seasonal water chemistry fluctuations and in some cases, limited supply of marine waters. Surface evaporites in Holocene export plumes into underlying bedrock. The growth habits and distribution of evaporite minerals in sabkhas of Qatar provide insights in their origins and models for the interpretation of ancient evaporites. The Holocene forms a 3-10 km wide coastal plain around the peninsula of Qatar. Rates of evaporation exceed precipitation by a factor of 1000 for six or more months of the year. In such an arid climate, bodies of standing water and evaporation in the capillary fringe promote rapid formation of evaporites. Evaporite minerals are common throughout the 3-10 meters of the Holocene. Gypsum dominantes (8-20%), followed by halite (6-10%), with minor anhydrite, calcite, dolomite and probably attapulgite. The most obvious textural differences occur between subaqueous mineral phases deposited in standing water, those formed in the capillary fringe, and precipitates near the water table. Subaqueous crystals are clear, devoid of much sediment, relatively large (mm-cm sized), laminated and may show compressional ridges(tepees) at the surface. Gypsum forms vertically-oriented, ‘fish-tail’ twins in vertical arrays. Halite occurs as hoppers and vertical prisms. Halite is an indicator of a marine water source. Thick subaqueous deposits only occur where there has been a marine source. Layers of crystals nucleated along chemical contacts in the water column and fish-tail twin habits are diagnostic. Evaporites formed in the capillary fringe are typically displacive, incorporate sediment, finely crystalline or poikilotopic, showing variable degree of crystallographic ordering. Micritic coatings are common. Halite is a common pore-filling, often leaving molds. Capillary fringe evaporites habits and morphology reflect seasonal changes in water chemistry. Evaporites formed at the water table are poikilotopic and may/may not be euhedral. This style of predominantly gypsum cementation has not been documented previously. Desert rose twins are the most well know water table morphology. Layers may extend over kilometers, reducing interparticle pore space by 20-30%. Crystals grow by interparticle cementation with little/no replacement. All styles of evaporite cementation are driven by extreme aridity of the climate. Millimeter sized crystals can grow in a few months, a geological instant. Limiting factors on growth rates of evaporites are seasonal water chemistry fluctuations and in some cases, limited supply of marine waters. Surface evaporites in Holocene export plumes into underlying bedrock. Panel_15068 Panel_15068 8:25 AM 8:45 AM
8:45 a.m.
3-D Forward Stratigraphic Modeling in Reservoir Quality Prediction – Arab-D Reservoir, Ghawar Field, Saudi Arabia
Room 601/603
Carbonate reservoirs are characterized by significant heterogeneity at the regional to inter-well scale. Reservoir quality predictions (RQPs) based on geostatistical and object-based modeling approaches contain additional uncertainties in carbonates compared to siliciclastic reservoirs. Process-based, forward stratigraphic modeling (FSM) offers high potential for improved RQP with reduced risk in exploration and improved recovery in production. FSM tools and workflows have been used for RQPs in the Arab-D reservoir (Lower Jurassic) in the Ghawar field. Data quality and coverage are exceptional with wells spaced at short distances. While effective porosities and permeabilities are generally high, marked lateral and vertical heterogeneities occur in this homoclinal carbonate ramp setting. They are related both to depositional facies with small-scale paleogeography and diagenetic overprint, e.g., dolomitization. FSM for RQPs in the Arab-D has been performed at a regional scale (270x180 km, cell size 2,000 m, time step 5 ka). Models are calibrated to 11 key wells and detailed depth/thickness grids from several hundred wells. The model has been tested by comparing virtual wells generated from the FSM to real-world wells, which were not included in the input database. Both Navier-Stokes/Lagrangian and diffusion-based approaches have been applied. Over reservoir thicknesses of 1-3 m, FSM correctly predicts (textural) porosities with errors of ±3 pu. Modeled depositional facies, e.g., skeletal-oolitic grainstone/rudstones and stromatoporoid packstone/ grainstone/boundstones with high porosities closely match core and log data. Vertical stacking patterns, e.g., parasequence sets and high-frequency sequences at the scale of 5-10 m resolution are predicted according to the actual subsurface data. In shallow subtidal to peritidal reservoir-prone settings, thickness uncertainties range between ±4 and ±10%. In more open marine settings (outer ramp to basin), uncertainties are higher and may reach up to ±28%. Input data and processes in these settings still require optimization. Current FSM studies focus on the field to inter-well scale based on a rigorous sequence stratigraphic framework. They reach the resolution of individual flow units (parasequences, shallowing/deepening upward cycles). FSM may be coupled with other modeling approaches, e.g., reactive transport modeling for diagenesis and surfaced-based modeling for fluid flow. Carbonate reservoirs are characterized by significant heterogeneity at the regional to inter-well scale. Reservoir quality predictions (RQPs) based on geostatistical and object-based modeling approaches contain additional uncertainties in carbonates compared to siliciclastic reservoirs. Process-based, forward stratigraphic modeling (FSM) offers high potential for improved RQP with reduced risk in exploration and improved recovery in production. FSM tools and workflows have been used for RQPs in the Arab-D reservoir (Lower Jurassic) in the Ghawar field. Data quality and coverage are exceptional with wells spaced at short distances. While effective porosities and permeabilities are generally high, marked lateral and vertical heterogeneities occur in this homoclinal carbonate ramp setting. They are related both to depositional facies with small-scale paleogeography and diagenetic overprint, e.g., dolomitization. FSM for RQPs in the Arab-D has been performed at a regional scale (270x180 km, cell size 2,000 m, time step 5 ka). Models are calibrated to 11 key wells and detailed depth/thickness grids from several hundred wells. The model has been tested by comparing virtual wells generated from the FSM to real-world wells, which were not included in the input database. Both Navier-Stokes/Lagrangian and diffusion-based approaches have been applied. Over reservoir thicknesses of 1-3 m, FSM correctly predicts (textural) porosities with errors of ±3 pu. Modeled depositional facies, e.g., skeletal-oolitic grainstone/rudstones and stromatoporoid packstone/ grainstone/boundstones with high porosities closely match core and log data. Vertical stacking patterns, e.g., parasequence sets and high-frequency sequences at the scale of 5-10 m resolution are predicted according to the actual subsurface data. In shallow subtidal to peritidal reservoir-prone settings, thickness uncertainties range between ±4 and ±10%. In more open marine settings (outer ramp to basin), uncertainties are higher and may reach up to ±28%. Input data and processes in these settings still require optimization. Current FSM studies focus on the field to inter-well scale based on a rigorous sequence stratigraphic framework. They reach the resolution of individual flow units (parasequences, shallowing/deepening upward cycles). FSM may be coupled with other modeling approaches, e.g., reactive transport modeling for diagenesis and surfaced-based modeling for fluid flow. Panel_15074 Panel_15074 8:45 AM 9:05 AM
9:05 a.m.
Evolution of the Raised Rims of Isolated Buildups in the Primorsk Region, Pricaspian Basin, Kazakhstan: A Quantitative Investigation of Compaction
Room 601/603
The Primorsk region in the North Caspian Sea of Kazakhstan contains several large isolated carbonate buildup reservoirs featuring raised rims (narrow, structurally elevated margins that partly or completely surround the buildups). Stratigraphic and facies data from the buildups show that the margin elevations (average 160 m) were generated by differential compaction during burial, that arose because of mechanical contrasts between rigid microbial boundstone and associated facies along the margin and more compressible grainstone and packstone facies in the buildup interior. Due to poor seismic resolution and a lack of deep well control, the distribution and thickness of microbial boundstone facies is poorly constrained in the raised rim areas. A series of 1-D and 2-D compaction and decompaction experiments were run using Basin2 software to determine sensitivities of the compaction process to facies thickness, depositional geometries, and burial history. While the thickness and depositional orientation of microbial boundstone facies along the margin resulted in corresponding measurable changes in rim morphology after compaction, the most important compaction sensitivity was burial history. The Primorsk buildups are overpressured reservoirs that experienced a past pressure release due to top-seal failure at near-lithostatic pressures and depths. The compaction models show that the overpressure was sufficient to delay compaction until the depressurization event, which was then followed by a period of rapid differential compaction. The rapid compaction episode has implications for genesis of vertical faults and fault-associated fractures in the raised rim, a region of Primorsk buildups dependent on non-matrix permeability for reservoir quality. The Primorsk region in the North Caspian Sea of Kazakhstan contains several large isolated carbonate buildup reservoirs featuring raised rims (narrow, structurally elevated margins that partly or completely surround the buildups). Stratigraphic and facies data from the buildups show that the margin elevations (average 160 m) were generated by differential compaction during burial, that arose because of mechanical contrasts between rigid microbial boundstone and associated facies along the margin and more compressible grainstone and packstone facies in the buildup interior. Due to poor seismic resolution and a lack of deep well control, the distribution and thickness of microbial boundstone facies is poorly constrained in the raised rim areas. A series of 1-D and 2-D compaction and decompaction experiments were run using Basin2 software to determine sensitivities of the compaction process to facies thickness, depositional geometries, and burial history. While the thickness and depositional orientation of microbial boundstone facies along the margin resulted in corresponding measurable changes in rim morphology after compaction, the most important compaction sensitivity was burial history. The Primorsk buildups are overpressured reservoirs that experienced a past pressure release due to top-seal failure at near-lithostatic pressures and depths. The compaction models show that the overpressure was sufficient to delay compaction until the depressurization event, which was then followed by a period of rapid differential compaction. The rapid compaction episode has implications for genesis of vertical faults and fault-associated fractures in the raised rim, a region of Primorsk buildups dependent on non-matrix permeability for reservoir quality. Panel_15076 Panel_15076 9:05 AM 9:25 AM
9:25 a.m.
Break
Room 601/603
Panel_15789 Panel_15789 9:25 AM 12:00 AM
10:10 a.m.
Fundamental Reservoir Units of Heterozoan Carbonates: Sedimentologic and Reservoir Properties of Shoaling- and Fining-Upward Cycles
Room 601/603
Hydrocarbon-bearing reservoirs in heterozoan carbonate deposits currently lack necessary predictive reservoir-analog models. Neogene complexes of the Cabo de Gata region of SE Spain provide ideal outcrops of heterozoan carbonates preserved as fining-upward cycles and fining-up-depositional-dip progradational clinothems. This pattern differs significantly from the coarsening-upward shoaling cycles of photozoan carbonates, suggesting the fundamental differences of heterozoan and photozoan carbonate reservoir architecture. Study of multiple outcrops of Miocene and Pliocene carbonates shows there are four fundamental cycle types. The cycles are documented using vertical and time-equivalent, lateral stratigraphic sections to provide a 3-D representation of facies. Each cycle contains coarse rhodolith and bivalve-rich gravel facies at the base, representing in situ production in deeper water. These facies systematically fine upward into sand-sized bioclastic facies that result from wave abrasion in shallower water, indicating a shoaling-upward origin for each cycle. Petrographic and petrophysical analyses allow for the quantification of sedimentologic variables and their control on reservoir character, as well as evaluation of geologic controls on reservoir-analog properties. Analyses include grain size and sorting, origin of sediment supply, grain constituents, abrasion parameters, mineralogy, and diagenesis as they relate to and are controlled by the shoaling- and fining-upward cycle. Preliminary porosity analyses demonstrate that the basal, and cycle-capping facies contain the highest porosity at 26-29%, whereas medially deposited coarse-grained facies contain 13-19% porosity, and with burial, may act as potential baffles to fluid flow. The main controls on porosity distribution appear to be grain sorting and the abundance of coralline algae. Analysis of the extent of diagenetic alteration correlates to grain size, and therefore enhances variation in reservoir quality throughout cycles. We propose that the shoaling- and fining-upward cycle could be used as a fundamental object-based unit for construction of subsurface geomodels in heterozoan reservoirs. Property modeling in Petrel will be used to develop 3-D reservoir-analog models for application. These results provide a vital reservoir unit and data applicable to recent discoveries in offshore Vietnam and Perla Field, Gulf of Venezuela, as well as application to future discoveries of heterozoan reservoirs. Hydrocarbon-bearing reservoirs in heterozoan carbonate deposits currently lack necessary predictive reservoir-analog models. Neogene complexes of the Cabo de Gata region of SE Spain provide ideal outcrops of heterozoan carbonates preserved as fining-upward cycles and fining-up-depositional-dip progradational clinothems. This pattern differs significantly from the coarsening-upward shoaling cycles of photozoan carbonates, suggesting the fundamental differences of heterozoan and photozoan carbonate reservoir architecture. Study of multiple outcrops of Miocene and Pliocene carbonates shows there are four fundamental cycle types. The cycles are documented using vertical and time-equivalent, lateral stratigraphic sections to provide a 3-D representation of facies. Each cycle contains coarse rhodolith and bivalve-rich gravel facies at the base, representing in situ production in deeper water. These facies systematically fine upward into sand-sized bioclastic facies that result from wave abrasion in shallower water, indicating a shoaling-upward origin for each cycle. Petrographic and petrophysical analyses allow for the quantification of sedimentologic variables and their control on reservoir character, as well as evaluation of geologic controls on reservoir-analog properties. Analyses include grain size and sorting, origin of sediment supply, grain constituents, abrasion parameters, mineralogy, and diagenesis as they relate to and are controlled by the shoaling- and fining-upward cycle. Preliminary porosity analyses demonstrate that the basal, and cycle-capping facies contain the highest porosity at 26-29%, whereas medially deposited coarse-grained facies contain 13-19% porosity, and with burial, may act as potential baffles to fluid flow. The main controls on porosity distribution appear to be grain sorting and the abundance of coralline algae. Analysis of the extent of diagenetic alteration correlates to grain size, and therefore enhances variation in reservoir quality throughout cycles. We propose that the shoaling- and fining-upward cycle could be used as a fundamental object-based unit for construction of subsurface geomodels in heterozoan reservoirs. Property modeling in Petrel will be used to develop 3-D reservoir-analog models for application. These results provide a vital reservoir unit and data applicable to recent discoveries in offshore Vietnam and Perla Field, Gulf of Venezuela, as well as application to future discoveries of heterozoan reservoirs. Panel_15072 Panel_15072 10:10 AM 10:30 AM
10:30 a.m.
Sequence Stratigraphy, Chemostratigraphy and Diagenesis of the Miocene Carbonate-Evaporite Successions, Al-Jabal Al-Khdar Uplift and Soluq Trough, Cyrenaica, Northeastern Libya
Room 601/603
The Cyrenaican Miocene carbonate-evaporite platform of NE Libya is the focus of this sequence stratigraphic, chemostratigraphic and diagenetic study. The integrated study involves determining detailed regional facies relationships from field and lab observations. The field work included 25 measured stratigraphic sections, 14 spectral gamma-ray profiles constructed using a hand-held gamma-ray scintillometer at 0.5 m intervals, and annotated panoramic digital photomosaics. The lab work includes petrographic and diagenetic studies of 501 hand samples, thin sections and stable isotope (? 18O and ? 13C) analyses. The sequence stratigraphic framework is based on the sedimentological analysis, correlation of stratigraphic time surfaces and vertical stratigraphic sections, oxygen and carbon stable isotope profiles, and gamma-ray logs. The Ar-Rajmah Group Miocene carbonate rocks record two 2nd order supersequences (97 m maximum thickness); containing six 3rd order sequences, and at least 10 higher frequency 3rd order sequences. The TST of the younger 2nd order sequence is separated by a sharp disconformity surface from the preserved HST of the older 2nd order sequence, and by maximum flooding zone from the HST of the younger 2nd order sequence. The HST of the older 2nd sequence is the Early Miocene Benghazi Formation (46 m maximum thickness), and dominated by red algal reefs, and bioclastic packstones. The TST and HST of the younger 2nd order sequence occur in the Middle and Late Miocene Wadi Al-Qattarah Formation (26 m and 25m maximum thicknesses respectively), and dominated by continuous oolitic grainstones, microbialites that associated with evaporites and siliciclastics. The 3rd order sequences range in thickness from 5 m to more than 15 m. In the study area, the peritidal facies are dominant in the younger sequences, while the ramp crest-subtidal facies dominant in the older sequences. The chemostratigraphic data suggests the entire Miocene preserved. The Early Miocene is enriched in both d18O and d13C, the Middle Miocene is enriched in d13C but depleted in d18O, and the Late Miocene is depleted in both d18O and d13C. The petrographic analysis shows two distinct lithological, textural and paragenetic patterns. The Langhian and older facies are dominated by silicified dedolomitized red algal and bioclastic packstones, the Serravallian and younger facies are dominated by silicified and recrystallized oolitic grainstone, microbial-bioclastic-oolitic grainstone. The Cyrenaican Miocene carbonate-evaporite platform of NE Libya is the focus of this sequence stratigraphic, chemostratigraphic and diagenetic study. The integrated study involves determining detailed regional facies relationships from field and lab observations. The field work included 25 measured stratigraphic sections, 14 spectral gamma-ray profiles constructed using a hand-held gamma-ray scintillometer at 0.5 m intervals, and annotated panoramic digital photomosaics. The lab work includes petrographic and diagenetic studies of 501 hand samples, thin sections and stable isotope (? 18O and ? 13C) analyses. The sequence stratigraphic framework is based on the sedimentological analysis, correlation of stratigraphic time surfaces and vertical stratigraphic sections, oxygen and carbon stable isotope profiles, and gamma-ray logs. The Ar-Rajmah Group Miocene carbonate rocks record two 2nd order supersequences (97 m maximum thickness); containing six 3rd order sequences, and at least 10 higher frequency 3rd order sequences. The TST of the younger 2nd order sequence is separated by a sharp disconformity surface from the preserved HST of the older 2nd order sequence, and by maximum flooding zone from the HST of the younger 2nd order sequence. The HST of the older 2nd sequence is the Early Miocene Benghazi Formation (46 m maximum thickness), and dominated by red algal reefs, and bioclastic packstones. The TST and HST of the younger 2nd order sequence occur in the Middle and Late Miocene Wadi Al-Qattarah Formation (26 m and 25m maximum thicknesses respectively), and dominated by continuous oolitic grainstones, microbialites that associated with evaporites and siliciclastics. The 3rd order sequences range in thickness from 5 m to more than 15 m. In the study area, the peritidal facies are dominant in the younger sequences, while the ramp crest-subtidal facies dominant in the older sequences. The chemostratigraphic data suggests the entire Miocene preserved. The Early Miocene is enriched in both d18O and d13C, the Middle Miocene is enriched in d13C but depleted in d18O, and the Late Miocene is depleted in both d18O and d13C. The petrographic analysis shows two distinct lithological, textural and paragenetic patterns. The Langhian and older facies are dominated by silicified dedolomitized red algal and bioclastic packstones, the Serravallian and younger facies are dominated by silicified and recrystallized oolitic grainstone, microbial-bioclastic-oolitic grainstone. Panel_15064 Panel_15064 10:30 AM 10:50 AM
10:50 a.m.
The Vaca Muerta-Quintuco Mixed Depositional System: New Insights From Carbon Stable Isotopes (d13Ccarb and d13Corg) and Geochemical Data at the Jurassic-Cretaceous Boundary (Neuquén Basin, West Argentina)
Room 601/603
The Late Jurassic-Early Cretaceous Vaca Muerta (VMF) and Quintuco (QF) Formations consist of a mixed system composed of three low frequency sequences identifiable on seismic. Sequences can be traced from basinal organic rich shale and limestone of the VMF, updip to shallow marine mixed carbonates and siliciclastics of the QF. Carbon isotope data (d13Ccarb and d13Corg) measured on continuous and sidewall cores from the VMF and the QF, reveal excursions that may aid in higher-resolution stratigraphic correlation across the Neuquén basin. Distinct isotopic trends are recognised along the studied interval, with more positive values found in maximum flooding zones and more negative ones found at sequence boundaries. The maximum flooding interval of the VMF displays a negative d13Ccarb shift (-5.0‰) influenced by the presence of organic matter, light d13Corg values (-30.1‰), and high SiO2 and Mo content. Negative isotopic values are followed by a positive d13Ccarb excursion (2.0‰), related either to continued sequestration of organic matter further offshore in the basin or to a global Tithonian oceanic anoxic event. The overlying HST, characterised by prograding clinoforms identified on seismic, shows low isotopic values (0.5‰) and low SiO2 and Al2O3 concentrations. In the subsequent TST a second positive d13Ccarb shift (2.4‰) is recorded, coupled with increased concentrations of SiO2 and Al2O3. Main reservoir facies in the QF occur just above this interval where regressive, shallow marine, high-energy grainstones and sandstones display negative isotopic values (?0.2‰) possibly affected by meteoric diagenesis. During the last TST the highest SiO2 and lowest CaO values are observed. No clear d13Ccarb trend is recorded, due to insufficient carbonate content. The following HST sees the deposition of thick aggrading mixed sequences, characterised by constant d13Ccarb values (1.0‰) possibly corresponding to the Berriasian and Early Valanginian stages. Overall trends in d13Ccarb and ? 13Corg curves correlate from well to well, although it is not yet fully understood if they reflect true secular variations in seawater chemistry or result from a combination of global changes and local diagenetic effects. The published isotopic curve is not sufficiently detailed over the Tithonian-Berriasian for direct comparison. This work represents the first continuous isotopic record in the Neuquén Basin at the Jurassic-Cretaceous boundary. The Late Jurassic-Early Cretaceous Vaca Muerta (VMF) and Quintuco (QF) Formations consist of a mixed system composed of three low frequency sequences identifiable on seismic. Sequences can be traced from basinal organic rich shale and limestone of the VMF, updip to shallow marine mixed carbonates and siliciclastics of the QF. Carbon isotope data (d13Ccarb and d13Corg) measured on continuous and sidewall cores from the VMF and the QF, reveal excursions that may aid in higher-resolution stratigraphic correlation across the Neuquén basin. Distinct isotopic trends are recognised along the studied interval, with more positive values found in maximum flooding zones and more negative ones found at sequence boundaries. The maximum flooding interval of the VMF displays a negative d13Ccarb shift (-5.0‰) influenced by the presence of organic matter, light d13Corg values (-30.1‰), and high SiO2 and Mo content. Negative isotopic values are followed by a positive d13Ccarb excursion (2.0‰), related either to continued sequestration of organic matter further offshore in the basin or to a global Tithonian oceanic anoxic event. The overlying HST, characterised by prograding clinoforms identified on seismic, shows low isotopic values (0.5‰) and low SiO2 and Al2O3 concentrations. In the subsequent TST a second positive d13Ccarb shift (2.4‰) is recorded, coupled with increased concentrations of SiO2 and Al2O3. Main reservoir facies in the QF occur just above this interval where regressive, shallow marine, high-energy grainstones and sandstones display negative isotopic values (?0.2‰) possibly affected by meteoric diagenesis. During the last TST the highest SiO2 and lowest CaO values are observed. No clear d13Ccarb trend is recorded, due to insufficient carbonate content. The following HST sees the deposition of thick aggrading mixed sequences, characterised by constant d13Ccarb values (1.0‰) possibly corresponding to the Berriasian and Early Valanginian stages. Overall trends in d13Ccarb and ? 13Corg curves correlate from well to well, although it is not yet fully understood if they reflect true secular variations in seawater chemistry or result from a combination of global changes and local diagenetic effects. The published isotopic curve is not sufficiently detailed over the Tithonian-Berriasian for direct comparison. This work represents the first continuous isotopic record in the Neuquén Basin at the Jurassic-Cretaceous boundary. Panel_15036 Panel_15036 10:50 AM 11:10 AM
11:10 a.m.
Integrated Stratigraphy of the Famennian Three Forks Formation, Williston Basin: A Study Using Physical, Biological, Sr, and S Isotopic Stratigraphic Signatures
Room 601/603
Sequence stratigraphy, biostratigraphy, strontium, and sulfur isotopes are used to constrain the relationship between the siliciclastic enriched Famennian Three Forks Formation deposits of the Williston basin and the chronostratigraphic equivalent deposits of the Wabamun carbonate ramp system. Seven allogeneic third-order transgressive-regressive cycles, correlated throughout the region, are biostratigraphically constrained as equivalents between the Three Forks and Wabamun formations. This biostratigraphic model allows for precise comparison of measured strontium isotope values to the secular curve. Three Forks 87Sr/86Sr values are consistently more radiogenic than the secular curve while following its trend. Authigenic evaporites from the Williston basin are slightly more radiogenic. Siliciclastic components of dolomudstone samples are even more radiogenic than the secular curve. This indicates that compared to the well-mixed ocean signatures, increased riverine run-off into the Williston basin occurred, especially associated with increased influx of detrital siliciclastics. Sulfur isotope values reveal a distinct partitioning between the two formations. Values are consistently enriched by three to five per mil ?34S in the Wabamun deposits compared to the Three Forks deposits. This distinction corroborates the Sr isotopic results, confirming elevated continental run-off in the Williston basin compared to the Western Canadian Sedimentary basin. No evaporite phases except anhydrite have been identified in the Three Forks, while halite and anhydrite have been identified in the Wabamun. The Williston basin salinities were thus buffered by fluvial inputs and rarely exceeded penesaline conditions. Sequence stratigraphy, biostratigraphy, strontium, and sulfur isotopes are used to constrain the relationship between the siliciclastic enriched Famennian Three Forks Formation deposits of the Williston basin and the chronostratigraphic equivalent deposits of the Wabamun carbonate ramp system. Seven allogeneic third-order transgressive-regressive cycles, correlated throughout the region, are biostratigraphically constrained as equivalents between the Three Forks and Wabamun formations. This biostratigraphic model allows for precise comparison of measured strontium isotope values to the secular curve. Three Forks 87Sr/86Sr values are consistently more radiogenic than the secular curve while following its trend. Authigenic evaporites from the Williston basin are slightly more radiogenic. Siliciclastic components of dolomudstone samples are even more radiogenic than the secular curve. This indicates that compared to the well-mixed ocean signatures, increased riverine run-off into the Williston basin occurred, especially associated with increased influx of detrital siliciclastics. Sulfur isotope values reveal a distinct partitioning between the two formations. Values are consistently enriched by three to five per mil ?34S in the Wabamun deposits compared to the Three Forks deposits. This distinction corroborates the Sr isotopic results, confirming elevated continental run-off in the Williston basin compared to the Western Canadian Sedimentary basin. No evaporite phases except anhydrite have been identified in the Three Forks, while halite and anhydrite have been identified in the Wabamun. The Williston basin salinities were thus buffered by fluvial inputs and rarely exceeded penesaline conditions. Panel_15075 Panel_15075 11:10 AM 11:30 AM
11:30 a.m.
The Development of Dolomite Geobodies Formed by Geothermal Convection of Seawater: Insights From New Reactive Transport Models Incorporating Platform Growth and Compaction
Room 601/603
It is estimated that as much as 50% of the world's carbonate rocks are dolomitised (Zenger et al., 1980) and significant volumes of global hydrocarbon resources are contained within dolomite reservoirs. As such, understanding the spatial distribution of dolomitization and how it impacts reservoir quality is key to the characterisation of carbonate reservoirs. Syn-depositional, massive dolomites are generally thought to source Mg from seawater or modified seawater (Land, 1985). Suggested flow systems include circulation within the mixing zone beneath carbonate islands, and reflux of dense brines produced by seawater evaporation in restricted platform top environments. However, both of these scenarios require specific conditions that are only attained intermittently in the lifespan of a carbonate platform. In contrast, geothermal convection of seawater, can occur continuously and is independent of sealevel. Previous reactive transport models (RTMs) of dolomitisation driven by this mechanism have highlighted that it is capable of producing characteristic distributions of dolomite (Whitaker and Xiao, 2012). Dolomite geobodies progressively grow from the platform margin into the platform interior, producing a wedge-shaped dolomite body that thins with distance from the margin. This is calculated to take many millions of years. On this time scale, a carbonate platform can prograde, aggrade or back-step significantly; a factor which is not considered by these simulations. However, the strong spatial association between the platform margin and the final dolomite geobody suggests that an evolving platform geometry could exercise an important control on the final distribution of dolomite within platform successions. We present a series of advanced RTMs that explore this concept. These models consider both platform growth and sediment compaction alongside the geothermal convection mechanism for dolomitisation. The results of these models reveal that the evolution of platform geometry could significatly influence both the amount and distribution of dolomite produced by this mechanism. Specifically, incorporating platform growth within such models does not generate the distinct dolomite geobodies described by Whitaker and Xiao (2012). Instead dolomitisation increases with depth into the carbonate platform as it is within the older, deeper parts of the platform succession that the elevated temperatures required to accelerate rates of dolomitisation exist. It is estimated that as much as 50% of the world's carbonate rocks are dolomitised (Zenger et al., 1980) and significant volumes of global hydrocarbon resources are contained within dolomite reservoirs. As such, understanding the spatial distribution of dolomitization and how it impacts reservoir quality is key to the characterisation of carbonate reservoirs. Syn-depositional, massive dolomites are generally thought to source Mg from seawater or modified seawater (Land, 1985). Suggested flow systems include circulation within the mixing zone beneath carbonate islands, and reflux of dense brines produced by seawater evaporation in restricted platform top environments. However, both of these scenarios require specific conditions that are only attained intermittently in the lifespan of a carbonate platform. In contrast, geothermal convection of seawater, can occur continuously and is independent of sealevel. Previous reactive transport models (RTMs) of dolomitisation driven by this mechanism have highlighted that it is capable of producing characteristic distributions of dolomite (Whitaker and Xiao, 2012). Dolomite geobodies progressively grow from the platform margin into the platform interior, producing a wedge-shaped dolomite body that thins with distance from the margin. This is calculated to take many millions of years. On this time scale, a carbonate platform can prograde, aggrade or back-step significantly; a factor which is not considered by these simulations. However, the strong spatial association between the platform margin and the final dolomite geobody suggests that an evolving platform geometry could exercise an important control on the final distribution of dolomite within platform successions. We present a series of advanced RTMs that explore this concept. These models consider both platform growth and sediment compaction alongside the geothermal convection mechanism for dolomitisation. The results of these models reveal that the evolution of platform geometry could significatly influence both the amount and distribution of dolomite produced by this mechanism. Specifically, incorporating platform growth within such models does not generate the distinct dolomite geobodies described by Whitaker and Xiao (2012). Instead dolomitisation increases with depth into the carbonate platform as it is within the older, deeper parts of the platform succession that the elevated temperatures required to accelerate rates of dolomitisation exist. Panel_15069 Panel_15069 11:30 AM 11:50 AM

8:00 a.m.–11:50 a.m.
Theme 4: Source-to-Sink Analyses of Sediment Dispersal Systems I (AAPG/SEPM)
Room 605/607, Monday Oral Sessions, 01 June, 2015

Panel_14465 Panel_14465 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Room 605/607
Panel_15790 Panel_15790 8:00 AM 12:00 AM
8:05 a.m.
Numerical Stratigraphic Modeling of Climatic Controls on Basin-Scale Sedimentation
Room 605/607
Stratigraphic concepts interpret stratal architecture and sediment distribution as results of the interaction of sea level, sediment supply, and tectonism. Typically, these concepts emphasize changes in accommodation driven by sea level as a principal control on deposition with sediment supply held constant. Yet, sediment supply to a basin can vary over time due to autogenic processes, tectonism, and climate change. Additionally, the supply to a basin may be out of phase with sea-level changes. We use a numerical forward stratigraphic modeling program to generate basin-scale (shelf to abyssal plain) numerical end-member cases that examine the dynamic interaction of sediment supply cycles that are at a 0, 90, 180, or 270 degree phase relationship with sea-level amplitudes typical of icehouse and greenhouse conditions on the 100 kyr timescale (eccentricity). These numerical models quantify the impact of sea level and climate driven sediment supply on sediment distribution and preservation during long-term basin evolution. Our results demonstrate the utility of sediment transport modeling by testing concepts of basin fill typically applied to exploration areas. Stratigraphic concepts interpret stratal architecture and sediment distribution as results of the interaction of sea level, sediment supply, and tectonism. Typically, these concepts emphasize changes in accommodation driven by sea level as a principal control on deposition with sediment supply held constant. Yet, sediment supply to a basin can vary over time due to autogenic processes, tectonism, and climate change. Additionally, the supply to a basin may be out of phase with sea-level changes. We use a numerical forward stratigraphic modeling program to generate basin-scale (shelf to abyssal plain) numerical end-member cases that examine the dynamic interaction of sediment supply cycles that are at a 0, 90, 180, or 270 degree phase relationship with sea-level amplitudes typical of icehouse and greenhouse conditions on the 100 kyr timescale (eccentricity). These numerical models quantify the impact of sea level and climate driven sediment supply on sediment distribution and preservation during long-term basin evolution. Our results demonstrate the utility of sediment transport modeling by testing concepts of basin fill typically applied to exploration areas. Panel_15297 Panel_15297 8:05 AM 8:25 AM
8:25 a.m.
How Much Sediment Has Been Eroded off Southwestern South Africa Since the Cretaceous, and Where is it Now?
Room 605/607
Quantifying the flux and character of sediment generated from continents and transported to oceans remains a challenge, which requires an estimation of the volume and lithology of material removed and the timing of erosion to be constrained. The majority of exhumation onshore Africa occurred during the Late Cretaceous-Early Tertiary and is related to uplift associated with the African superplume. A better understanding of the long-term landscape evolution can be determined by constraining the volume removed from a c. 140,000 km2 area in SW South Africa since the start of the Cretaceous. The study area covers three main drainage basins, the Olifants, the Breede, and the Gouritz. An advantage of investigating this area is that the drainage network is demonstrably antecedent, the onshore geology is well constrained, and that there has been little tectonic activity since the Cretaceous. Several assumptions need to be made in order to construct a grid of structural cross sections across the study area, with the estimated ‘maximum’ and ‘minimum’ thicknesses of lithostratigraphic groups extrapolated above present day topography. The extent of the lithostratigraphic units at the time of exhumation is constrained by provenance analysis of onshore Cretaceous deposits that exposed in the hanging-wall of major extension faults. The cross-sections have been georeferenced in 3DMove, with a surface fit between. The volumes calculated range from 0.72 x 106 km3 to 1.56 x 106 km3. The southern offshore basins are of interest to industry, and with a better understanding of the volume and composition of the eroded sediment; assessment of reservoir quality can be improved. The estimated volume of material is more than several of the largest submarine fans on the planet, and is an order of magnitude greater than the material found in offshore basins. Explanations for this missing sediment include breakdown and transport as fines, unidentified submarine fans, or that the majority of exhumation occurred during the early Cretaceous break-up of Pangaea and has been tectonically transported elsewhere. Quantifying the flux and character of sediment generated from continents and transported to oceans remains a challenge, which requires an estimation of the volume and lithology of material removed and the timing of erosion to be constrained. The majority of exhumation onshore Africa occurred during the Late Cretaceous-Early Tertiary and is related to uplift associated with the African superplume. A better understanding of the long-term landscape evolution can be determined by constraining the volume removed from a c. 140,000 km2 area in SW South Africa since the start of the Cretaceous. The study area covers three main drainage basins, the Olifants, the Breede, and the Gouritz. An advantage of investigating this area is that the drainage network is demonstrably antecedent, the onshore geology is well constrained, and that there has been little tectonic activity since the Cretaceous. Several assumptions need to be made in order to construct a grid of structural cross sections across the study area, with the estimated ‘maximum’ and ‘minimum’ thicknesses of lithostratigraphic groups extrapolated above present day topography. The extent of the lithostratigraphic units at the time of exhumation is constrained by provenance analysis of onshore Cretaceous deposits that exposed in the hanging-wall of major extension faults. The cross-sections have been georeferenced in 3DMove, with a surface fit between. The volumes calculated range from 0.72 x 106 km3 to 1.56 x 106 km3. The southern offshore basins are of interest to industry, and with a better understanding of the volume and composition of the eroded sediment; assessment of reservoir quality can be improved. The estimated volume of material is more than several of the largest submarine fans on the planet, and is an order of magnitude greater than the material found in offshore basins. Explanations for this missing sediment include breakdown and transport as fines, unidentified submarine fans, or that the majority of exhumation occurred during the early Cretaceous break-up of Pangaea and has been tectonically transported elsewhere. Panel_15295 Panel_15295 8:25 AM 8:45 AM
8:45 a.m.
Approaches to Source-To-Sink Reconstruction of Ancient, Outcropping Clastic Basin-Fill Successions: Examples From the Shannon Basin (Western Ireland) and the Western Interior Basin, USA
Room 605/607
Source-to-Sink analyses (S2S) are normally applied to ancient subsurface or Modern-Recent near-surface successions adjacent to onshore catchments. The method is equally applicable to outcropping clastic basin-fill successions, even where the rocks in the basin-fill succession occur in vertical sequence. S2S analysis here requires calculation of key S2S parameters from the data and conversion to uncompacted values. Global S2S statistics then provide direct lead-in to interpretation of quantitative characteristics of systems that formed the ancient basin-fill successions. The 2200 m thick basin-fill succession of the Carboniferous Shannon Basin in Western Ireland is upward-shallowing from basinal mudstones and submarine fan deposits through slope to deltaic and incised valley-fill sediments. The slope succession is 700 m thick (vertical thickness), which transforms to an approximately 900 m uncompacted succession. Conventional trigonometry yields a slope length of approximately 52 km for a slope with 1o inclination. This slope length then provides a direct lead-in to comparison with similar, yet Modern-Recent S2S systems from the global statistics. The Shannon Basin shelf width is assessed to be 20-30 km and the catchment providing the sediment 40-50000 km2. Moreover, the areal extent of the Ross submarine fan system fed from the slope succession, is interpreted to be around 8-10000 km2, in accordance with the mapped extent of the Ross Formation from outcrop and well data. Despite the uncertainty in the calculations, the S2S analysis provides a powerful method of reconstructing unseen parts of the S2S system related to the outcropping succession, which in turn must be checked against available field data or concepts for such systems. The Campanian Mesaverde Group of the Western Interior Basin, United States provides a different challenge in that most of the dip dimension of the coastal plain-shelf-offshore segments of the S2S system is preserved. The Mesaverde antecedent catchment is not preserved, and now included in the Sevier thrust system. Structural reconstruction has provided a valid interpretation of the catchment segment of the S2S system back to what was likely a drainage divide in the antecedent Wasatch culmination. S2S analysis provides a reality check on the structural reconstruction in the context of the entire Mesaverde clastic wedge and provides a complete view the S2S system during deposition. Source-to-Sink analyses (S2S) are normally applied to ancient subsurface or Modern-Recent near-surface successions adjacent to onshore catchments. The method is equally applicable to outcropping clastic basin-fill successions, even where the rocks in the basin-fill succession occur in vertical sequence. S2S analysis here requires calculation of key S2S parameters from the data and conversion to uncompacted values. Global S2S statistics then provide direct lead-in to interpretation of quantitative characteristics of systems that formed the ancient basin-fill successions. The 2200 m thick basin-fill succession of the Carboniferous Shannon Basin in Western Ireland is upward-shallowing from basinal mudstones and submarine fan deposits through slope to deltaic and incised valley-fill sediments. The slope succession is 700 m thick (vertical thickness), which transforms to an approximately 900 m uncompacted succession. Conventional trigonometry yields a slope length of approximately 52 km for a slope with 1o inclination. This slope length then provides a direct lead-in to comparison with similar, yet Modern-Recent S2S systems from the global statistics. The Shannon Basin shelf width is assessed to be 20-30 km and the catchment providing the sediment 40-50000 km2. Moreover, the areal extent of the Ross submarine fan system fed from the slope succession, is interpreted to be around 8-10000 km2, in accordance with the mapped extent of the Ross Formation from outcrop and well data. Despite the uncertainty in the calculations, the S2S analysis provides a powerful method of reconstructing unseen parts of the S2S system related to the outcropping succession, which in turn must be checked against available field data or concepts for such systems. The Campanian Mesaverde Group of the Western Interior Basin, United States provides a different challenge in that most of the dip dimension of the coastal plain-shelf-offshore segments of the S2S system is preserved. The Mesaverde antecedent catchment is not preserved, and now included in the Sevier thrust system. Structural reconstruction has provided a valid interpretation of the catchment segment of the S2S system back to what was likely a drainage divide in the antecedent Wasatch culmination. S2S analysis provides a reality check on the structural reconstruction in the context of the entire Mesaverde clastic wedge and provides a complete view the S2S system during deposition. Panel_15296 Panel_15296 8:45 AM 9:05 AM
9:05 a.m.
Unraveling Controls on Sediment Transport and Deposition From Source-To-Sink Along a Complex Passive Margin: The Agadir-Essaouira Basin, Morocco Atlantic Margin
Room 605/607
Early Cretaceous deepwater clastics offer the most prospective reservoir target along the offshore Moroccan margin, however, to-date, significant thickness of reservoir quality sands have proved elusive in this underexplored basin. Onshore, extensive Early Cretaceous fluvio-marine deposits are exposed, showing laterally and temporal variability. They comprise dominantly fine-grained deposits with intervals of coarse-siliciclastic to mixed carbonate/siliciclastic deposits. Detailed analysis of outcrops, and integration of all previous data along the Moroccan Atlantic margin, suggest strong paleotopographic, tectonic control and co-eval active salt movement, producing discrete feeder systems traversing the Essaouira and Agadir Area. Offshore, equivalent aged turbiditic deposits are predicted, although as yet only supported by amplitude analysis, some channel like morphologies on seismic data and indirectly confirmed by minor sands in current and older wells. This margin was far from “passive” during the Late Jurassic and Cretaceous. Recent studies (Bertotti & Gouiza, 2012) indicate Late Jurassic and Cretaceous exhumation of 2-3 km in the hinterland during this period, associated with enhanced subsidence in the developing deepwater basin. This study is a multi-disciplinary approach to develop sequential gross depositional element maps across the margin by detailed logging, improved lithostratigraphy and new biostratigraphic age control for key stratigraphic sections. Significant strike-parallel and temporal variations in lithofacies are observed along the margin. Within the Agadir Area a gulf can be recognised, and preliminary paleogeographic reconstructions suggest discrete feeder systems. To the north, more marginal marine to fluvial sections are recorded in the Essaouira and Doukkala Basins. Drainage pattern analysis suggests point source inputs for the main feeder systems. Sedimentary petrography points to distinctive provenance areas, likely from the Moroccan Meseta and Massif Ancien. Initial results also highlight the importance of longshore currents possibly redistributing coarser clastics along the margin. All observations indicate that potential reservoir quality and sediment delivery varies spatially and through time. These results will reduce risk for evaluating reservoir type and location in the deep basins offshore Morocco and are a valuable analogue for the conjugate margin of Nova Scotia and the entire Atlantic margin system. Early Cretaceous deepwater clastics offer the most prospective reservoir target along the offshore Moroccan margin, however, to-date, significant thickness of reservoir quality sands have proved elusive in this underexplored basin. Onshore, extensive Early Cretaceous fluvio-marine deposits are exposed, showing laterally and temporal variability. They comprise dominantly fine-grained deposits with intervals of coarse-siliciclastic to mixed carbonate/siliciclastic deposits. Detailed analysis of outcrops, and integration of all previous data along the Moroccan Atlantic margin, suggest strong paleotopographic, tectonic control and co-eval active salt movement, producing discrete feeder systems traversing the Essaouira and Agadir Area. Offshore, equivalent aged turbiditic deposits are predicted, although as yet only supported by amplitude analysis, some channel like morphologies on seismic data and indirectly confirmed by minor sands in current and older wells. This margin was far from “passive” during the Late Jurassic and Cretaceous. Recent studies (Bertotti & Gouiza, 2012) indicate Late Jurassic and Cretaceous exhumation of 2-3 km in the hinterland during this period, associated with enhanced subsidence in the developing deepwater basin. This study is a multi-disciplinary approach to develop sequential gross depositional element maps across the margin by detailed logging, improved lithostratigraphy and new biostratigraphic age control for key stratigraphic sections. Significant strike-parallel and temporal variations in lithofacies are observed along the margin. Within the Agadir Area a gulf can be recognised, and preliminary paleogeographic reconstructions suggest discrete feeder systems. To the north, more marginal marine to fluvial sections are recorded in the Essaouira and Doukkala Basins. Drainage pattern analysis suggests point source inputs for the main feeder systems. Sedimentary petrography points to distinctive provenance areas, likely from the Moroccan Meseta and Massif Ancien. Initial results also highlight the importance of longshore currents possibly redistributing coarser clastics along the margin. All observations indicate that potential reservoir quality and sediment delivery varies spatially and through time. These results will reduce risk for evaluating reservoir type and location in the deep basins offshore Morocco and are a valuable analogue for the conjugate margin of Nova Scotia and the entire Atlantic margin system. Panel_15293 Panel_15293 9:05 AM 9:25 AM
9:25 a.m.
Break
Room 605/607
Panel_15791 Panel_15791 9:25 AM 12:00 AM
10:10 a.m.
Late Cretaceous-Paleogene Foreland Sediment-Dispersal Systems in Northern and Eastern Mexico: Interpretations From Preliminary Detrital-Zircon Analysis
Room 605/607
Upper Cretaceous-Paleogene stratigraphy of the Mexican foreland-basin system broadly resembles that of the Alpine foreland basin in that both contain initial deepwater (flysch) deposits overlain by younger molasse-type deposits. In the Parras and La Popa basins of northern Mexico, Turonian-Santonian deepwater successions are overlain by shallow-marine and continental deposits of the Maastrichtian-Eocene Difunta Group. Similar molasse deposits are absent above deformed turbidites in the Mesa Central of north-central Mexico, where shallow-water strata may have been eroded from the thrust orogen. In the Tampico-Misantla basin of eastern Mexico, deepwater deposition persisted into the early Eocene, but molasse deposition never took place. Sediment delivery among these broadly correlative successions, the extent of their drainage basins, and locations of their depositional termini in and near the Gulf of Mexico basin are critical unresolved questions regarding the Cretaceous paleogeography of Mexico. New detrital-zircon data indicate that sediment sources for Mesa Central flysch deposits lay as far away as the SW United States, but that those sediment-delivery systems never connected as far south as the Tampico-Misantla basin. Detrital zircon populations in a single sample of flysch in Zacatecas and six Difunta samples from the Parras and La Popa basins contain 1.7-1.6 Ga and 1.4 Ga zircon populations characteristic of SW Laurentian basement. These preliminary data suggest that Turonian-Santonian axial rivers debouched SSE into deep water of the Mexican seaway basin prior to late Campanian time, when the advancing orogen deflected axial drainage eastward along the Sierra Madre foredeep toward Monterrey. Flysch deposits of central Mexico, recorded by a sample of the Soyatal Fm, lack Laurentian grains, indicating local derivation from accreted terranes directly to the west. A sample of Paleocene turbidites from the Puskon #1 well in the distal part of the Tampico-Misantla basin similarly lacks Laurentian zircons, and is dominated by grains ranging 1.3-1.1 Ga and 144-66 Ma, likely derived from exposed Grenville basement and the Cretaceous magmatic arc of southern Mexico, respectively. Because axial drainage recorded by the Difunta Group did not deliver Laurentian sediment into the Tampico-Misantla basin, it is likely that this voluminous Wilcox-equivalent dispersal system instead spilled eastward across the Tamaulipas arch into the NW Gulf of Mexico. Upper Cretaceous-Paleogene stratigraphy of the Mexican foreland-basin system broadly resembles that of the Alpine foreland basin in that both contain initial deepwater (flysch) deposits overlain by younger molasse-type deposits. In the Parras and La Popa basins of northern Mexico, Turonian-Santonian deepwater successions are overlain by shallow-marine and continental deposits of the Maastrichtian-Eocene Difunta Group. Similar molasse deposits are absent above deformed turbidites in the Mesa Central of north-central Mexico, where shallow-water strata may have been eroded from the thrust orogen. In the Tampico-Misantla basin of eastern Mexico, deepwater deposition persisted into the early Eocene, but molasse deposition never took place. Sediment delivery among these broadly correlative successions, the extent of their drainage basins, and locations of their depositional termini in and near the Gulf of Mexico basin are critical unresolved questions regarding the Cretaceous paleogeography of Mexico. New detrital-zircon data indicate that sediment sources for Mesa Central flysch deposits lay as far away as the SW United States, but that those sediment-delivery systems never connected as far south as the Tampico-Misantla basin. Detrital zircon populations in a single sample of flysch in Zacatecas and six Difunta samples from the Parras and La Popa basins contain 1.7-1.6 Ga and 1.4 Ga zircon populations characteristic of SW Laurentian basement. These preliminary data suggest that Turonian-Santonian axial rivers debouched SSE into deep water of the Mexican seaway basin prior to late Campanian time, when the advancing orogen deflected axial drainage eastward along the Sierra Madre foredeep toward Monterrey. Flysch deposits of central Mexico, recorded by a sample of the Soyatal Fm, lack Laurentian grains, indicating local derivation from accreted terranes directly to the west. A sample of Paleocene turbidites from the Puskon #1 well in the distal part of the Tampico-Misantla basin similarly lacks Laurentian zircons, and is dominated by grains ranging 1.3-1.1 Ga and 144-66 Ma, likely derived from exposed Grenville basement and the Cretaceous magmatic arc of southern Mexico, respectively. Because axial drainage recorded by the Difunta Group did not deliver Laurentian sediment into the Tampico-Misantla basin, it is likely that this voluminous Wilcox-equivalent dispersal system instead spilled eastward across the Tamaulipas arch into the NW Gulf of Mexico. Panel_15291 Panel_15291 10:10 AM 10:30 AM
10:30 a.m.
Record of Cretaceous Through Paleogene Gulf of Mexico Drainage Integration From Detrital Zircons
Room 605/607
Published analysis of scaling relationships between sediment-dispersal system components imply that reconstruction of the length-scales of drainage basins and fluvial systems can assist prediction of the dimensions of basin-floor fans. This paper is the first of three to address this overall goal, and provides a summary reconstruction of mid-Cretaceous to Paleogene Gulf of Mexico (GoM) drainage integration and drainage-basin scales from detrital zircons (DZs). GoM DZ data include >6000 U-Pb and Pb-Pb ages from ~60 samples of Cenomanian Tuscaloosa-Woodbine, Paleocene Wilcox, and Oligocene Frio-Catahoula, fluvial deposits: samples were collected across each outcrop belt, from Alabama to Texas. Complementary DZ data comes from Aptian to Cenomanian fluvial deposits of the Great Plains, the US Rocky Mountain Front Range, and Aptian-Albian deposits of the Alberta foreland. Collectively, these data show that much of early-mid Cretaceous North America was part of a continental-scale drainage that originated in the Appalachian-Ouachitas, and flowed north and west across the Great Plains to the Alberta foreland and Boreal Sea. GoM drainage was restricted to south of the Appalachian-Ouachitas through at least the Cenomanian: Tuscaloosa-Woodbine fluvial deposits contain no DZ signatures from the Western Cordillera, fluvial systems were of regional scale only (<<10^6 sq. km), and the largest system is interpreted to represent a paleo-Tennessee River that discharged to the eastern Mississippi embayment. By the Paleocene, much of southern North America, from the Appalachians to the Sierra Nevada, was re-routed to the GoM through a series of major fluvial axes that remain extant today. These included the paleo-Tennessee and its Appalachian source terrain, and an ancestral Mississippi-Arkansas system with an estimated drainage area >10^6 sq. km that encompassed the central and northern Rockies. However, large axes were also located farther west in Texas, and included an ancestral Colorado-Brazos system with headwaters in the Sierra Nevada, Sevier orogen, and Laramide Rockies, and an ancestral Rio Grande with headwaters in the Mexican Cordillera: the paleo-Colorado-Brazos axis had an estimated drainage area >>10^6 sq. km, and length scales >2000 km. Beginning in the Oligocene, far western sources were tectonically dismembered, and GoM drainage areas extended no farther west than the eastern Laramide Rockies, heralding development of the Neogene to present continental divide. Published analysis of scaling relationships between sediment-dispersal system components imply that reconstruction of the length-scales of drainage basins and fluvial systems can assist prediction of the dimensions of basin-floor fans. This paper is the first of three to address this overall goal, and provides a summary reconstruction of mid-Cretaceous to Paleogene Gulf of Mexico (GoM) drainage integration and drainage-basin scales from detrital zircons (DZs). GoM DZ data include >6000 U-Pb and Pb-Pb ages from ~60 samples of Cenomanian Tuscaloosa-Woodbine, Paleocene Wilcox, and Oligocene Frio-Catahoula, fluvial deposits: samples were collected across each outcrop belt, from Alabama to Texas. Complementary DZ data comes from Aptian to Cenomanian fluvial deposits of the Great Plains, the US Rocky Mountain Front Range, and Aptian-Albian deposits of the Alberta foreland. Collectively, these data show that much of early-mid Cretaceous North America was part of a continental-scale drainage that originated in the Appalachian-Ouachitas, and flowed north and west across the Great Plains to the Alberta foreland and Boreal Sea. GoM drainage was restricted to south of the Appalachian-Ouachitas through at least the Cenomanian: Tuscaloosa-Woodbine fluvial deposits contain no DZ signatures from the Western Cordillera, fluvial systems were of regional scale only (<<10^6 sq. km), and the largest system is interpreted to represent a paleo-Tennessee River that discharged to the eastern Mississippi embayment. By the Paleocene, much of southern North America, from the Appalachians to the Sierra Nevada, was re-routed to the GoM through a series of major fluvial axes that remain extant today. These included the paleo-Tennessee and its Appalachian source terrain, and an ancestral Mississippi-Arkansas system with an estimated drainage area >10^6 sq. km that encompassed the central and northern Rockies. However, large axes were also located farther west in Texas, and included an ancestral Colorado-Brazos system with headwaters in the Sierra Nevada, Sevier orogen, and Laramide Rockies, and an ancestral Rio Grande with headwaters in the Mexican Cordillera: the paleo-Colorado-Brazos axis had an estimated drainage area >>10^6 sq. km, and length scales >2000 km. Beginning in the Oligocene, far western sources were tectonically dismembered, and GoM drainage areas extended no farther west than the eastern Laramide Rockies, heralding development of the Neogene to present continental divide. Panel_15290 Panel_15290 10:30 AM 10:50 AM
10:50 a.m.
Utilizing Channel-Belt Scaling Parameters to Constrain Discharge and Drainage Basin Character With Application to the Cretaceous to Teritary Evolution of the Gulf of Mexico
Room 605/607
Fluvial systems possess a range of scaling relationships that reflect drainage-basin controls on water and sediment flux. Quaternary channel-belt thickness (as controlled by bank-full water discharge) has been documented as a reliable first-order proxy for drainage basin size if climatic regimes are independently constrained. In hydrocarbon exploration and production, scaling relationships for fluvial deposits can be utilized to constrain drainage basin size with implications for sequence-stratigraphic interpretations. This study documents the scales of channel belts within Cretaceous to Tertiary fluvial successions from the Gulf of Mexico. Data on single-storey channel-belt scales were compiled from well logs and utilized to constrain contributing catchment areas of Cretaceous, Wilcox, and Oligocene fluvial systems. The data indicate that the Wilcox and Oligocene fluvial systems were significantly larger than the Cretaceous fluvial systems which can be related to drainage basin reorganization. Furthermore the Wilcox fluvial systems were relatively larger than the Oligocene fluvial systems. This could reflect either smaller drainage basins or climatic aridification. These scaling relationships can be validated by regional paleogeographic maps and provide additional insight to the sediment routing systems through time. Fluvial systems possess a range of scaling relationships that reflect drainage-basin controls on water and sediment flux. Quaternary channel-belt thickness (as controlled by bank-full water discharge) has been documented as a reliable first-order proxy for drainage basin size if climatic regimes are independently constrained. In hydrocarbon exploration and production, scaling relationships for fluvial deposits can be utilized to constrain drainage basin size with implications for sequence-stratigraphic interpretations. This study documents the scales of channel belts within Cretaceous to Tertiary fluvial successions from the Gulf of Mexico. Data on single-storey channel-belt scales were compiled from well logs and utilized to constrain contributing catchment areas of Cretaceous, Wilcox, and Oligocene fluvial systems. The data indicate that the Wilcox and Oligocene fluvial systems were significantly larger than the Cretaceous fluvial systems which can be related to drainage basin reorganization. Furthermore the Wilcox fluvial systems were relatively larger than the Oligocene fluvial systems. This could reflect either smaller drainage basins or climatic aridification. These scaling relationships can be validated by regional paleogeographic maps and provide additional insight to the sediment routing systems through time. Panel_15294 Panel_15294 10:50 AM 11:10 AM
11:10 a.m.
Validation of Empirical Source-To-Sink Scaling Relationships in a Large Hydrocarbon-Rich Basin: Gulf of Mexico Cenozoic Deepwater Fan Systems
Room 605/607
Empirical relationships between deep-water siliciclastic fan systems and their linked drainage basins have been established for modern and Quaternary depositional systems and in a few ancient, small-scale basins. Twenty years of mapping the Gulf of Mexico (GOM) Basin and the North American drainage network facilitates a much more rigorous test of these scaling relationships in a large continental size system with multiple mountain source terrains, rivers, deltas, slopes, and abyssal plain fan systems formed over 60 my of geologic time. The large number of drill wells and high quality industry seismic data in this prolific hydrocarbon basin provide the necessary, independent validation of deep-water fan occurrence and extent. Analysis of over 40 deep-water fan and apron systems ranging in age from Paleocene to Pleistocene in the GOM reveals that submarine fan systems scale predictably with interpreted drainage basin size. All deep-water fan system lengths, as measured from shelf edge to mapped termination, fall in a range of 10 to 50% of the drainage basin length. Most are comparable to large (Mississippi-scale) systems though some smaller systems are included in the database (e.g. Oligocene Rio Bravo system). Submarine fan lengths mostly fall in the range of 50% to 200% of estimated river backwater lengths though there is more scatter in the data due to difficulties in measuring backwater lengths in ancient, subsurface strata. Other empirical relationships examined reveal important characteristics of source to sink systems like the GOM. Poor correlations between fan length and delta width (along depositional strike) and fan area and delta area suggest that it is the larger drainage basin network that is paramount in determining fan dimensions, not a delta nearest the basin entry point. Shelf edge storage and transport process are variables intervening between the delta and fan scaling relationships. However, point bars in river systems do scale with drainage basin size and thus we would expect such subsurface measurements to provide additional ways of predicting deep-water fan dimensions prior to drilling. Empirical relationships between deep-water siliciclastic fan systems and their linked drainage basins have been established for modern and Quaternary depositional systems and in a few ancient, small-scale basins. Twenty years of mapping the Gulf of Mexico (GOM) Basin and the North American drainage network facilitates a much more rigorous test of these scaling relationships in a large continental size system with multiple mountain source terrains, rivers, deltas, slopes, and abyssal plain fan systems formed over 60 my of geologic time. The large number of drill wells and high quality industry seismic data in this prolific hydrocarbon basin provide the necessary, independent validation of deep-water fan occurrence and extent. Analysis of over 40 deep-water fan and apron systems ranging in age from Paleocene to Pleistocene in the GOM reveals that submarine fan systems scale predictably with interpreted drainage basin size. All deep-water fan system lengths, as measured from shelf edge to mapped termination, fall in a range of 10 to 50% of the drainage basin length. Most are comparable to large (Mississippi-scale) systems though some smaller systems are included in the database (e.g. Oligocene Rio Bravo system). Submarine fan lengths mostly fall in the range of 50% to 200% of estimated river backwater lengths though there is more scatter in the data due to difficulties in measuring backwater lengths in ancient, subsurface strata. Other empirical relationships examined reveal important characteristics of source to sink systems like the GOM. Poor correlations between fan length and delta width (along depositional strike) and fan area and delta area suggest that it is the larger drainage basin network that is paramount in determining fan dimensions, not a delta nearest the basin entry point. Shelf edge storage and transport process are variables intervening between the delta and fan scaling relationships. However, point bars in river systems do scale with drainage basin size and thus we would expect such subsurface measurements to provide additional ways of predicting deep-water fan dimensions prior to drilling. Panel_15292 Panel_15292 11:10 AM 11:30 AM
11:30 a.m.
The Nature of Connections Between Coastal Systems and Submarine Canyons - Implications for Sediment Transit to Deep Water
Room 605/607
The heads of submarine canyons represent a critical link in the transfer of sediment from terrestrial sediment sources to deep basin sinks. Data from modern canyons and submarine fans suggests the strength of this connection determines the proportion and caliber of sediment stored in shelfal environments relative to that which is transferred to deep-water. Data on grain size, bathymetry and geochronology from twenty-four modern submarine canyons demonstrate this link to be very sensitive to the distance between the canyon head and the shoreline, and, to a lesser extent, wave energy. These data show the width of this zone filters the caliber of sediment delivered into deep-water with significant implications for understanding sediment budgets and reservoir and seal distribution. A surprising observation from these data is how sensitive the transport of grains of sand-size and coarser clasts is to the distance between the river mouth or shoreline and the head of the submarine canyon. Data from these modern systems shows the river mouth or longshore drift system must come within ~500 m of the head of the canyon to deliver gravel-size material and within 1-5 km to deliver sand-size material to be transported down the canyon into deep water. Clay- and silt-size particles are transported greater distances across the shelf, up to a few 10’s of kilometers, whereas beyond about 40 kilometers little sediment makes the connection to the heads of canyons and deposits are commonly dominated by carbonate-rich sediments. Many large, passive margins currently fall into this realm. The insights from this study can be translated and applied to conditions typical of other periods in Earth’s history and have powerful implications for predictions of reservoir and seal. During Greenhouse times, with high but relatively stable sea level and/or narrow continental shelves, a longer-lived connection between fluvial to near-shore environments and deep water was more likely to occur. However, in relatively high-gradient systems, long-lived connections may prevent the deposition of laterally extensive mudstones that are effective top seals. In contrast to Greenhouse conditions, during Icehouse periods, high-amplitude sea level fluctuations and inherently wider continental shelves result in repeated landward and seaward transits of river mouths and shorelines, and shorter connection times between source and sink, especially for sand-size sediment. The heads of submarine canyons represent a critical link in the transfer of sediment from terrestrial sediment sources to deep basin sinks. Data from modern canyons and submarine fans suggests the strength of this connection determines the proportion and caliber of sediment stored in shelfal environments relative to that which is transferred to deep-water. Data on grain size, bathymetry and geochronology from twenty-four modern submarine canyons demonstrate this link to be very sensitive to the distance between the canyon head and the shoreline, and, to a lesser extent, wave energy. These data show the width of this zone filters the caliber of sediment delivered into deep-water with significant implications for understanding sediment budgets and reservoir and seal distribution. A surprising observation from these data is how sensitive the transport of grains of sand-size and coarser clasts is to the distance between the river mouth or shoreline and the head of the submarine canyon. Data from these modern systems shows the river mouth or longshore drift system must come within ~500 m of the head of the canyon to deliver gravel-size material and within 1-5 km to deliver sand-size material to be transported down the canyon into deep water. Clay- and silt-size particles are transported greater distances across the shelf, up to a few 10’s of kilometers, whereas beyond about 40 kilometers little sediment makes the connection to the heads of canyons and deposits are commonly dominated by carbonate-rich sediments. Many large, passive margins currently fall into this realm. The insights from this study can be translated and applied to conditions typical of other periods in Earth’s history and have powerful implications for predictions of reservoir and seal. During Greenhouse times, with high but relatively stable sea level and/or narrow continental shelves, a longer-lived connection between fluvial to near-shore environments and deep water was more likely to occur. However, in relatively high-gradient systems, long-lived connections may prevent the deposition of laterally extensive mudstones that are effective top seals. In contrast to Greenhouse conditions, during Icehouse periods, high-amplitude sea level fluctuations and inherently wider continental shelves result in repeated landward and seaward transits of river mouths and shorelines, and shorter connection times between source and sink, especially for sand-size sediment. Panel_15298 Panel_15298 11:30 AM 11:50 AM

8:00 a.m.–11:50 a.m.
Hydrocarbon and Non-Hydrocarbon Gases in Exploration and Production (AAPG)
Room 702/704/706, Monday Oral Sessions, 01 June, 2015

<br />
Panel_14490 Panel_14490 8:00 AM 11:50 AM
8:00 a.m.
Introductory Remarks
Room 702/704/706
Panel_15792 Panel_15792 8:00 AM 12:00 AM
8:05 a.m.
Correlation of Rocky Mountain Produced Natural Gases to Sources by Application of Gas Isotope Kinetic Modeling
Room 702/704/706
Due to variation in maceral types and concentrations, source rocks have different gas formation kinetic characteristics which result in isotopically different gases. Additionally, cracking of crude oils to gases varies with oil composition. The identification of gases from oil cracking is possible as resulting gases have very different carbon isotopic signatures compared to gases from primary cracking of kerogen (and bitumen). Therefore, experimental calibration of oil cracking allows a differentiation of gas from primary cracking of kerogen. Gas to source correlations can not be completely successful by application of theoretical concepts, but are enhanced by gas formation simulation experiments where gas evolution is monitored and quantified during laboratory thermal maturation of source rocks and cracking of oils. Such experiments allow for the correlation of gas samples back to a more specific source unit. Gas isotope kinetic modeling as described in Tang et al., 2000 (Geochimica et Cosmochimica Acta 64, p. 2673-2687), and Tang and Schoell et al., 2005 (Abstract 96191, AAPG Annual Convention and Exhibition, Calgary, AB, Canada) was employed. Experimental data were available for three Greater Green River Basin samples: a Rock Springs coal, a Mancos Shale, and the asphaltene fraction of a Mowry-sourced oil. These three samples account for much of the types of gases generated in the Greater Green River Basin. A sample set of >400 produced gases with molecular and isotopic compositional data allowed differentiation of e.g., multiple gas sources in Pinedale and Jonah fields of Wyoming which were geologically reasonable. Using the initial laboratory Greater Green River Basin results, this approach has been expanded to include additional carbon isotopic data to evaluate produced gases from five additional Rocky Mountain basins: Denver, Piceance, Powder, San Juan and Uinta. The data commonly show carbon isotopic evolution trends that can be interpreted in terms of source type(s) and generation depths, complementing more traditional gas – source correlation techniques. Due to variation in maceral types and concentrations, source rocks have different gas formation kinetic characteristics which result in isotopically different gases. Additionally, cracking of crude oils to gases varies with oil composition. The identification of gases from oil cracking is possible as resulting gases have very different carbon isotopic signatures compared to gases from primary cracking of kerogen (and bitumen). Therefore, experimental calibration of oil cracking allows a differentiation of gas from primary cracking of kerogen. Gas to source correlations can not be completely successful by application of theoretical concepts, but are enhanced by gas formation simulation experiments where gas evolution is monitored and quantified during laboratory thermal maturation of source rocks and cracking of oils. Such experiments allow for the correlation of gas samples back to a more specific source unit. Gas isotope kinetic modeling as described in Tang et al., 2000 (Geochimica et Cosmochimica Acta 64, p. 2673-2687), and Tang and Schoell et al., 2005 (Abstract 96191, AAPG Annual Convention and Exhibition, Calgary, AB, Canada) was employed. Experimental data were available for three Greater Green River Basin samples: a Rock Springs coal, a Mancos Shale, and the asphaltene fraction of a Mowry-sourced oil. These three samples account for much of the types of gases generated in the Greater Green River Basin. A sample set of >400 produced gases with molecular and isotopic compositional data allowed differentiation of e.g., multiple gas sources in Pinedale and Jonah fields of Wyoming which were geologically reasonable. Using the initial laboratory Greater Green River Basin results, this approach has been expanded to include additional carbon isotopic data to evaluate produced gases from five additional Rocky Mountain basins: Denver, Piceance, Powder, San Juan and Uinta. The data commonly show carbon isotopic evolution trends that can be interpreted in terms of source type(s) and generation depths, complementing more traditional gas – source correlation techniques. Panel_15537 Panel_15537 8:05 AM 8:25 AM
8:25 a.m.
Thermochemical Sulfate Reduction in Anhydrite-Sealed Carbonate Gas Reservoirs: A 3-D Reactive Mass Transport Modeling Approach
Room 702/704/706
Acid gas generation by thermochemical sulfate reduction (TSR) evolves within a complex web of petroleum-water-rock-gas interactions in reservoirs under high temperature conditions of more than 100°C. These interactions lead to formation of toxic and corrosive hydrogen sulfide (H2S gas and dissolved H2S). Such interactions are caused by the instability of hydrocarbons in the presence of water and by a reactive reservoir rock matrix containing water-soluble anhydrite. The mass conversions of inorganic water-rock-gas interactions, which are triggered by the kinetically controlled sulfate reduction with aqueous hydrocarbons, establish a certain, thermodynamically defined state of chemical equilibrium. Any approach to geochemically and quantitatively model TSR-induced “H2S-risks” in petroleum systems should be based on a conceptual model that adequately reproduces the interdependent nature of all simultaneous hydrogeochemical processes contributing to TSR (more than 50 reactions). Such approaches should rely (1) on the thermodynamical calculation of chemical equilibrium species distribution, (2) on the coupling of kinetically controlled sulfate reduction with petroleum-derived reductants to the equilibrium calculations, and (3) on the calculation of diffusive mass transport of solutes through the free pore water network and the irreducible water film. TSR modeling is complex, and therefore, its failure often results from conceptual models which focus on only single reactions like the kinetically controlled sulfate reduction dependent on thermal history or other selected reactions of interest which are isolated from the web of interactions. The key to model TSR, the fate and behavior of sulfidic sulfur, and a realistic “H2S-risk” in petroleum reservoirs is a comprehensive reproduction of the hydrogeochemical reactive transport processes within the whole system. Consequently, we perform 3D hydrogeochemical, multi-component and multi-species reactive mass transport modeling for a semi-generic case study by using the PHAST computer code (provided by the U.S. Geological Survey). The aim is (1) to predict the temporal and spatial evolution of complex TSR interactions under reservoir conditions and (2) to test the effects of various parameters on the concentration of H2S in the gas, on the total amount of sulfidic sulfur present in the reservoir (H2S(g), H2S(aq), HS-(aq), S-2(aq) indicating reservoir souring; FeS2), and on the amount of newly formed elemental sulfur. Acid gas generation by thermochemical sulfate reduction (TSR) evolves within a complex web of petroleum-water-rock-gas interactions in reservoirs under high temperature conditions of more than 100°C. These interactions lead to formation of toxic and corrosive hydrogen sulfide (H2S gas and dissolved H2S). Such interactions are caused by the instability of hydrocarbons in the presence of water and by a reactive reservoir rock matrix containing water-soluble anhydrite. The mass conversions of inorganic water-rock-gas interactions, which are triggered by the kinetically controlled sulfate reduction with aqueous hydrocarbons, establish a certain, thermodynamically defined state of chemical equilibrium. Any approach to geochemically and quantitatively model TSR-induced “H2S-risks” in petroleum systems should be based on a conceptual model that adequately reproduces the interdependent nature of all simultaneous hydrogeochemical processes contributing to TSR (more than 50 reactions). Such approaches should rely (1) on the thermodynamical calculation of chemical equilibrium species distribution, (2) on the coupling of kinetically controlled sulfate reduction with petroleum-derived reductants to the equilibrium calculations, and (3) on the calculation of diffusive mass transport of solutes through the free pore water network and the irreducible water film. TSR modeling is complex, and therefore, its failure often results from conceptual models which focus on only single reactions like the kinetically controlled sulfate reduction dependent on thermal history or other selected reactions of interest which are isolated from the web of interactions. The key to model TSR, the fate and behavior of sulfidic sulfur, and a realistic “H2S-risk” in petroleum reservoirs is a comprehensive reproduction of the hydrogeochemical reactive transport processes within the whole system. Consequently, we perform 3D hydrogeochemical, multi-component and multi-species reactive mass transport modeling for a semi-generic case study by using the PHAST computer code (provided by the U.S. Geological Survey). The aim is (1) to predict the temporal and spatial evolution of complex TSR interactions under reservoir conditions and (2) to test the effects of various parameters on the concentration of H2S in the gas, on the total amount of sulfidic sulfur present in the reservoir (H2S(g), H2S(aq), HS-(aq), S-2(aq) indicating reservoir souring; FeS2), and on the amount of newly formed elemental sulfur. Panel_15542 Panel_15542 8:25 AM 8:45 AM
8:45 a.m.
Significance of Organic Carbon and Bulk Nitrogen Fluctuations Across the Cenomanian-Turonian Boundary, Eagle Ford Formation, Maverick Basin, Texas
Room 702/704/706
A stratigraphic record of organic matter deposition spanning late Cenomanian through at least early Turonian time was reconstructed from a drill core recovered from the Maverick Basin, South Texas. The strata (Eagle Ford Fm) record 1) the depositional evolution in an anoxic/euxinic shelf setting following a hiatus, represented by the contact with the underlying Buda Fm, 2) a shift to more oxygenated conditions after the initiation of the OAE-2 (as defined by a positive shift in d13CTOC), and 3) variably oxygenated (poikiloaerobic) conditions throughout much of the post-OAE-2 succession. Approximately 170 ft of TOC-rich (average 3%, maximum 6.5%) lower Eagle Ford (LEF) strata are subdivided into two sub-equal zones: a lower zone with variable d13CTOC values (ranging from -28.9 to -25.9‰), and an upper zone with a largely unidirectional d13CTOC trajectory that upwardly trends to less depleted values (~-28.1 to ~-26.8‰). Interestingly, the abrupt shift between the two zones coincides with the apex in TOC/N ratio, suggesting that a shift in organic matter source or degradation occurred at this time. The bulk organic characteristics of the upper Eagle Ford (UEF) are significantly more variable. Redox-sensitive trace elemental results show that the OAE-2 began at the LEF-UEF boundary, when the concentration of sedimentary molybdenum (a proxy for euxinia) greatly diminished. The OAE-2 interval (lowermost portion of UEF) spans a thickness of ~70 ft, and yields a d13CTOC range of ~4‰. The upper 230 ft of core (UEF and lower Austin Fm) is defined by highly variable TOC (maximum 4%), an upwardly-increasing trend in TOC/N, and variable d13CTOC (range -28 to -26‰). The majority of bulk rock ?15Ntotal values fall between -5 and -2‰, which is a typical range for strata of this age. The most interesting feature of the nitrogen isotopic record is an abrupt decrease in ?15Ntotal of several permil at the apex of the d13CTOC record in the OAE-2 interval. Following the depletion of nitrate inputs from others sources, this decrease may represent a unique set of water mass conditions under which nitrogen fixation by diazotrophic cyanobacteria was the sole process responsible for bringing nitrogen into the system. The significance of the new record will be discussed with respect to the many existing records of Cenomanian-Turonian paleoceanographic change. A stratigraphic record of organic matter deposition spanning late Cenomanian through at least early Turonian time was reconstructed from a drill core recovered from the Maverick Basin, South Texas. The strata (Eagle Ford Fm) record 1) the depositional evolution in an anoxic/euxinic shelf setting following a hiatus, represented by the contact with the underlying Buda Fm, 2) a shift to more oxygenated conditions after the initiation of the OAE-2 (as defined by a positive shift in d13CTOC), and 3) variably oxygenated (poikiloaerobic) conditions throughout much of the post-OAE-2 succession. Approximately 170 ft of TOC-rich (average 3%, maximum 6.5%) lower Eagle Ford (LEF) strata are subdivided into two sub-equal zones: a lower zone with variable d13CTOC values (ranging from -28.9 to -25.9‰), and an upper zone with a largely unidirectional d13CTOC trajectory that upwardly trends to less depleted values (~-28.1 to ~-26.8‰). Interestingly, the abrupt shift between the two zones coincides with the apex in TOC/N ratio, suggesting that a shift in organic matter source or degradation occurred at this time. The bulk organic characteristics of the upper Eagle Ford (UEF) are significantly more variable. Redox-sensitive trace elemental results show that the OAE-2 began at the LEF-UEF boundary, when the concentration of sedimentary molybdenum (a proxy for euxinia) greatly diminished. The OAE-2 interval (lowermost portion of UEF) spans a thickness of ~70 ft, and yields a d13CTOC range of ~4‰. The upper 230 ft of core (UEF and lower Austin Fm) is defined by highly variable TOC (maximum 4%), an upwardly-increasing trend in TOC/N, and variable d13CTOC (range -28 to -26‰). The majority of bulk rock ?15Ntotal values fall between -5 and -2‰, which is a typical range for strata of this age. The most interesting feature of the nitrogen isotopic record is an abrupt decrease in ?15Ntotal of several permil at the apex of the d13CTOC record in the OAE-2 interval. Following the depletion of nitrate inputs from others sources, this decrease may represent a unique set of water mass conditions under which nitrogen fixation by diazotrophic cyanobacteria was the sole process responsible for bringing nitrogen into the system. The significance of the new record will be discussed with respect to the many existing records of Cenomanian-Turonian paleoceanographic change. Panel_15538 Panel_15538 8:45 AM 9:05 AM
9:05 a.m.
Possible Sources of Dissolved Inorganic Carbon in the Formation of Middle and Upper Devonian Carbonate Concretions, Appalachian Basin
Room 702/704/706
Calcium carbonate concretions are common to the Middle and Upper Devonian shale succession of the Appalachian Basin. Geologic and microtextural evidence suggests that the authigenic carbonate formed at shallow burial depth, perhaps no more than a few tens of meters below the sediment-water interface, in a diagenetic environment resulting from the anaerobic oxidation of methane (AOM). Burial histories of the Middle Devonian Marcellus Shale and Upper Ordovician Utica Shale suggest that only the latter had generated a small amount of thermogenic methane by the time the Devonian shale succession started to accumulate. Thus, oxidized biogenic methane appears to have been the principal dissolved inorganic carbon source of the authigenic carbonate. However, modestly depleted d13C values of concretions, from the Marcellus Shale upward through the Upper Devonian Dunkirk Shale, are well in excess of d13C values of authgenic carbonate formed within a diagenetic environment induced by the anaerobic oxidation of biogenic methane. One explanation of this seemingly incongruent relationship entails a combination of the prolonged oxidation of shallow biogenic methane mixed with methanogenic CO2, both of which were sourced at the bottom of the Marcellus Shale. Alternatively, some volume of the methane inventory consumed by AOM within the Devonian shale succession may have originated within the Upper Ordovician Utica Shale. It is plausible that “ancient” biogenic methane was released from the Utica shale, either over an extended period of time or as a geologically rapid event, to the overlying sedimentary column. Residual biogenic methane that finally reached the accumulating Middle and Upper Devonian deposits would have been only modestly depleted in 13C due to a protracted oxidation history. The obvious shortcoming of a scenario involving the expulsion of methane from the Utica Shale into the Middle and Upper Devonian shale succession is the presence of such intervening units as the Silurian Lockport Dolomite and overlying Salina Formation salt deposits. However, transport of methane from the Utica could have been enhanced by Acadian foreland basin dynamics, including salt removal, reactivated basement faults and the formation of Acadian faults and related fractures. Calcium carbonate concretions are common to the Middle and Upper Devonian shale succession of the Appalachian Basin. Geologic and microtextural evidence suggests that the authigenic carbonate formed at shallow burial depth, perhaps no more than a few tens of meters below the sediment-water interface, in a diagenetic environment resulting from the anaerobic oxidation of methane (AOM). Burial histories of the Middle Devonian Marcellus Shale and Upper Ordovician Utica Shale suggest that only the latter had generated a small amount of thermogenic methane by the time the Devonian shale succession started to accumulate. Thus, oxidized biogenic methane appears to have been the principal dissolved inorganic carbon source of the authigenic carbonate. However, modestly depleted d13C values of concretions, from the Marcellus Shale upward through the Upper Devonian Dunkirk Shale, are well in excess of d13C values of authgenic carbonate formed within a diagenetic environment induced by the anaerobic oxidation of biogenic methane. One explanation of this seemingly incongruent relationship entails a combination of the prolonged oxidation of shallow biogenic methane mixed with methanogenic CO2, both of which were sourced at the bottom of the Marcellus Shale. Alternatively, some volume of the methane inventory consumed by AOM within the Devonian shale succession may have originated within the Upper Ordovician Utica Shale. It is plausible that “ancient” biogenic methane was released from the Utica shale, either over an extended period of time or as a geologically rapid event, to the overlying sedimentary column. Residual biogenic methane that finally reached the accumulating Middle and Upper Devonian deposits would have been only modestly depleted in 13C due to a protracted oxidation history. The obvious shortcoming of a scenario involving the expulsion of methane from the Utica Shale into the Middle and Upper Devonian shale succession is the presence of such intervening units as the Silurian Lockport Dolomite and overlying Salina Formation salt deposits. However, transport of methane from the Utica could have been enhanced by Acadian foreland basin dynamics, including salt removal, reactivated basement faults and the formation of Acadian faults and related fractures. Panel_15541 Panel_15541 9:05 AM 9:25 AM
9:25 a.m.
Break
Room 702/704/706
Panel_15793 Panel_15793 9:25 AM 12:00 AM
10:10 a.m.
Carbon and Noble Gas Isotope Banks in Two-Phase Flow: Changes in Gas Composition During Migration
Room 702/704/706
A dramatic expansion of natural gas exploration and extraction in unconventional reserves is underway. However, there is public concern that hydraulic fracturing will also cause natural gas, reservoir brines and associated fracturing fluids to contaminate shallower groundwater reservoirs. Considerable scientific research is currently focused on attributing methane found in shallow groundwater sources to either thermogenic or low temperature bacterial sources. Attribution techniques use concentration ratios of methane, ethane and propane and their stable carbon and hydrogen isotope ratios, as well the abundance of atmospheric and crustal derived noble gases. These distinct properties can be used to differentiate bacterial and thermogenic methane assuming negligible change in composition and stable isotope ratios during transport. We use experimental results, theoretical models, and existing field data to determine whether hydrocarbon gas will show any appreciable change while migrating a distance greater than 1km. Theoretical two-phase gas displacement models predict that methane will become enriched at the front of a migrating gas plume due to mixing with dissolved biogenic methane in shallow groundwater.. Propane will dissolve more readily into the subsurface brines as the plume rises, leaving the final gas plume in the shallow groundwater heavily enriched in methane. We show that a mixture of a thermogenic gas plume with a small, dissolved biogenic methane supply in the groundwater will cause significant isotopic changes in the gas plume. Furthermore, atmospheric derived noble gases will be swept ahead of the methane pulse, leaving the main gas plume depleted of atmospheric gas components. We present results of experiments investigating these processes. All experiments used a 1m long, sand-packed steel column saturated with water containing dissolved noble gases. We then displaced the water by injecting methane, and measured the composition and carbon isotope ratio of the effluent gas. In this series of ongoing experiments, we are able to test both theory and field observations. Preliminary experimental results agree with theory and field observations, and show that dissolved gases and high volatility gases present in the injection gas are enriched in banks at the front of the displacement. These enrichment processes can be used to aid source identification of both fugitive gas plumes and migration of natural gas from source to reservoirs. A dramatic expansion of natural gas exploration and extraction in unconventional reserves is underway. However, there is public concern that hydraulic fracturing will also cause natural gas, reservoir brines and associated fracturing fluids to contaminate shallower groundwater reservoirs. Considerable scientific research is currently focused on attributing methane found in shallow groundwater sources to either thermogenic or low temperature bacterial sources. Attribution techniques use concentration ratios of methane, ethane and propane and their stable carbon and hydrogen isotope ratios, as well the abundance of atmospheric and crustal derived noble gases. These distinct properties can be used to differentiate bacterial and thermogenic methane assuming negligible change in composition and stable isotope ratios during transport. We use experimental results, theoretical models, and existing field data to determine whether hydrocarbon gas will show any appreciable change while migrating a distance greater than 1km. Theoretical two-phase gas displacement models predict that methane will become enriched at the front of a migrating gas plume due to mixing with dissolved biogenic methane in shallow groundwater.. Propane will dissolve more readily into the subsurface brines as the plume rises, leaving the final gas plume in the shallow groundwater heavily enriched in methane. We show that a mixture of a thermogenic gas plume with a small, dissolved biogenic methane supply in the groundwater will cause significant isotopic changes in the gas plume. Furthermore, atmospheric derived noble gases will be swept ahead of the methane pulse, leaving the main gas plume depleted of atmospheric gas components. We present results of experiments investigating these processes. All experiments used a 1m long, sand-packed steel column saturated with water containing dissolved noble gases. We then displaced the water by injecting methane, and measured the composition and carbon isotope ratio of the effluent gas. In this series of ongoing experiments, we are able to test both theory and field observations. Preliminary experimental results agree with theory and field observations, and show that dissolved gases and high volatility gases present in the injection gas are enriched in banks at the front of the displacement. These enrichment processes can be used to aid source identification of both fugitive gas plumes and migration of natural gas from source to reservoirs. Panel_15543 Panel_15543 10:10 AM 10:30 AM
10:30 a.m.
Application of Noble Gas Isotopic Signatures at McElmo Dome-DOE Canyon to Investigate CO2 Source and System Characterization
Room 702/704/706
The McElmo Dome-DOE Canyon field in the Four Corners region is one of the largest sources of CO2 in the Rocky Mountain region. In prior studies, hypotheses in favor of CO2 generation by thermal in situ decomposition of carbonate-sulfate assemblages in the Leadville Limestone or magmatic-gas release were proposed. The fundamental source of the gases, however, remained poorly understood. In this investigation, noble gas isotope signatures were used in an attempt to fingerprint the source of the CO2 gas and test competing hypotheses on its origin, migration, and evolution. Analyses of noble gas isotopes, stable isotopes, and major gas compositions across the McElmo-DOE field reveal variable and mixed mantle-crust signatures which are dominated by the addition of radiogenic crustal signatures (4He, 21Ne, 40Ar). A comparison of CO2/3He against CO2 concentrations are consistent with a magmatic 3He source that mixed with crustal contributions. The crustal contributions are indicated by helium isotope ratios 3He/4He (where the ratio of RAIR=1) from 0.057 to 0.215 (R/Ra), nucleogenic (following U and Th decay) 20Ne/22Ne (<8.5), 21Ne/22Ne (>0.10), and highly elevated radiogenic Ar with 40Ar/36Ar* >15,000. Our preliminary data suggests that CO2 gas was likely sourced from Cenozoic magmatic activity in the region that filled Leadville Formation traps at the time of magmatism. Magmatic events spanned the period from 75-5 Ma and involved melting of Proterozoic lithospheric mantle which was a key source of carbonated mantle melts in the Oligocene. Mafic rocks generated from these melts have elevated K, U, Th and F, and these magmas could have been a major source of the exceptionally high nucleogenic (21Ne, 22Ne) and radiogenic (4He,40Ar) signatures of noble gases in the McElmo Dome and Doe Canyon CO2 fields. The McElmo Dome-DOE Canyon field in the Four Corners region is one of the largest sources of CO2 in the Rocky Mountain region. In prior studies, hypotheses in favor of CO2 generation by thermal in situ decomposition of carbonate-sulfate assemblages in the Leadville Limestone or magmatic-gas release were proposed. The fundamental source of the gases, however, remained poorly understood. In this investigation, noble gas isotope signatures were used in an attempt to fingerprint the source of the CO2 gas and test competing hypotheses on its origin, migration, and evolution. Analyses of noble gas isotopes, stable isotopes, and major gas compositions across the McElmo-DOE field reveal variable and mixed mantle-crust signatures which are dominated by the addition of radiogenic crustal signatures (4He, 21Ne, 40Ar). A comparison of CO2/3He against CO2 concentrations are consistent with a magmatic 3He source that mixed with crustal contributions. The crustal contributions are indicated by helium isotope ratios 3He/4He (where the ratio of RAIR=1) from 0.057 to 0.215 (R/Ra), nucleogenic (following U and Th decay) 20Ne/22Ne (<8.5), 21Ne/22Ne (>0.10), and highly elevated radiogenic Ar with 40Ar/36Ar* >15,000. Our preliminary data suggests that CO2 gas was likely sourced from Cenozoic magmatic activity in the region that filled Leadville Formation traps at the time of magmatism. Magmatic events spanned the period from 75-5 Ma and involved melting of Proterozoic lithospheric mantle which was a key source of carbonated mantle melts in the Oligocene. Mafic rocks generated from these melts have elevated K, U, Th and F, and these magmas could have been a major source of the exceptionally high nucleogenic (21Ne, 22Ne) and radiogenic (4He,40Ar) signatures of noble gases in the McElmo Dome and Doe Canyon CO2 fields. Panel_15540 Panel_15540 10:30 AM 10:50 AM
10:50 a.m.
Noble Gases Help Trace the Behavior of Hydrocarbons in Unconventional Oil and Gas Shales
Room 702/704/706
The occurrence, distribution, and composition of hydrocarbons in the Earth's crust, result from the complex interplay between the tectonic and hydrologic cycles. For example, there is complex association between the tectonics of fold-thrust belts, the deformation of foreland basins, and the generation and migration of hydrocarbons and other geologic fluids in the subsurface. Accurately characterizing the relationship between these factors is critical to predicting the economic success of conventional and unconventional energy plays. One technique that is traditionally used in these studies is the analysis of gas geochemistry, specifically stable isotopic compositions (e.g., d13C, d18O, and ?2H) of hydrocarbon gases or CO2. The inert noble gases provide a complementary geochemical technique that can be used in concert with hydrocarbon molecular and stable isotope composition to evaluate the source and migrational history of hydrocarbons in conventional and unconventional plays. Additionally, in some cases, noble gases can be used as an external variable to evaluate the timing of closure for hydrocarbon reservoirs, open vs. closed system behavior and to determine and monitor the residual fluids in place during exploration and production. Herein, we will present noble gas and hydrocarbon molecular and stable isotope data from hydrocarbon plays in the Appalachian Basin (Utica, Trenton-Black River, and Marcellus) and Dallas-Fort Worth (Barnett) basins. Our presentation will focus on insights gained about hydrocarbon stable isotopic roll overs and reversals based on noble gas isotope data. Our preliminary data suggests that producing natural gas wells that exhibit isotopic reversals display distinct noble gas evidence consistent with relatively closed system behavior. Additionally, samples with isotopic reversals retain more than 3x the concentrations of atmospheric (air-saturated water) noble gases suggesting that significantly higher levels of formational waters remain in black shale source rocks that exhibit isotopic reversals. The occurrence, distribution, and composition of hydrocarbons in the Earth's crust, result from the complex interplay between the tectonic and hydrologic cycles. For example, there is complex association between the tectonics of fold-thrust belts, the deformation of foreland basins, and the generation and migration of hydrocarbons and other geologic fluids in the subsurface. Accurately characterizing the relationship between these factors is critical to predicting the economic success of conventional and unconventional energy plays. One technique that is traditionally used in these studies is the analysis of gas geochemistry, specifically stable isotopic compositions (e.g., d13C, d18O, and ?2H) of hydrocarbon gases or CO2. The inert noble gases provide a complementary geochemical technique that can be used in concert with hydrocarbon molecular and stable isotope composition to evaluate the source and migrational history of hydrocarbons in conventional and unconventional plays. Additionally, in some cases, noble gases can be used as an external variable to evaluate the timing of closure for hydrocarbon reservoirs, open vs. closed system behavior and to determine and monitor the residual fluids in place during exploration and production. Herein, we will present noble gas and hydrocarbon molecular and stable isotope data from hydrocarbon plays in the Appalachian Basin (Utica, Trenton-Black River, and Marcellus) and Dallas-Fort Worth (Barnett) basins. Our presentation will focus on insights gained about hydrocarbon stable isotopic roll overs and reversals based on noble gas isotope data. Our preliminary data suggests that producing natural gas wells that exhibit isotopic reversals display distinct noble gas evidence consistent with relatively closed system behavior. Additionally, samples with isotopic reversals retain more than 3x the concentrations of atmospheric (air-saturated water) noble gases suggesting that significantly higher levels of formational waters remain in black shale source rocks that exhibit isotopic reversals. Panel_15535 Panel_15535 10:50 AM 11:10 AM
11:10 a.m.
Using Noble Gas Geochemistry to Characterize Sources and Migration of Fluids in the Eagle Ford Shale
Room 702/704/706
The Eagle Ford Shale in south Texas has become one of the most prolific shale plays in the United States in recent years. While production data suggests that oil and natural gas can be produced across a vast area of the field, the source of H2S and hydrocarbons, and the extent to which fluids have migrated into and out of the Eagle Ford, have yet to be determined. This study uses noble gas isotopes, gas composition, and stable isotopes to evaluate the source gases, to characterize the fluids-in-place, and to characterize the extent of fluid migration from the Eagle Ford Shale. The inert nature and distinct isotopic compositions make noble gases ideal tracers of crustal fluid processes. In most shales, the noble gas isotopic composition reflects a binary mixture of: 1) air-saturated water (ASW), containing 20Ne, 36Ar, and 84Kr derived from solubility equilibrium with the atmosphere during groundwater recharge and 2) radiogenic noble gases such as 4He*, 21Ne*, and 40Ar* sourced from the decay of U, Th, and K. Once noble gases incorporate into crustal fluids, they fractionate only by well-constrained physical mechanisms (e.g., diffusion, phase-partitioning). For example, although the decay of U and Th, produces a fixed ratio of 4He/21Ne (2.2x107) and the initial 4He/21Ne of minerals in shale are fixed, 4He will be preferentially released with respect to 21Ne at hydrocarbon-producing temperatures. Over time, the isotopic ratios vary as fluids equilibrate with the shale matrix. Variations occur as a function of temperature, porosity, and the volume of fluid flow. Thus, the isotopic values can be used to reconstruct the history of fluid flow in specific formations. Our data from the Eagle Ford show that mantle-derived gases (elevated 3He/4He= 0.15-0.25Ra and 20Ne/22Ne=10.2-11.1) and radiogenic gases (4He, 21Ne, 40Ar) dominate the overall gas composition. We anticipate that volcanism during Cretaceous/Cenozoic rifting activity caused the observed mantle-gas contributions. Interestingly, higher mantle contributions appear to correlate with elevated H2S in the production wells from this study suggesting thermal sulfate reduction induced by magmatic activity. Additionally, ASW and radiogenic noble gases can be used to model the relative volume of residual fluids-in-place for this Eagle Ford play. Initial data suggests that there has been minimal fractionation of noble gases implying minimal loss of the initial hydrocarbon fluids. The Eagle Ford Shale in south Texas has become one of the most prolific shale plays in the United States in recent years. While production data suggests that oil and natural gas can be produced across a vast area of the field, the source of H2S and hydrocarbons, and the extent to which fluids have migrated into and out of the Eagle Ford, have yet to be determined. This study uses noble gas isotopes, gas composition, and stable isotopes to evaluate the source gases, to characterize the fluids-in-place, and to characterize the extent of fluid migration from the Eagle Ford Shale. The inert nature and distinct isotopic compositions make noble gases ideal tracers of crustal fluid processes. In most shales, the noble gas isotopic composition reflects a binary mixture of: 1) air-saturated water (ASW), containing 20Ne, 36Ar, and 84Kr derived from solubility equilibrium with the atmosphere during groundwater recharge and 2) radiogenic noble gases such as 4He*, 21Ne*, and 40Ar* sourced from the decay of U, Th, and K. Once noble gases incorporate into crustal fluids, they fractionate only by well-constrained physical mechanisms (e.g., diffusion, phase-partitioning). For example, although the decay of U and Th, produces a fixed ratio of 4He/21Ne (2.2x107) and the initial 4He/21Ne of minerals in shale are fixed, 4He will be preferentially released with respect to 21Ne at hydrocarbon-producing temperatures. Over time, the isotopic ratios vary as fluids equilibrate with the shale matrix. Variations occur as a function of temperature, porosity, and the volume of fluid flow. Thus, the isotopic values can be used to reconstruct the history of fluid flow in specific formations. Our data from the Eagle Ford show that mantle-derived gases (elevated 3He/4He= 0.15-0.25Ra and 20Ne/22Ne=10.2-11.1) and radiogenic gases (4He, 21Ne, 40Ar) dominate the overall gas composition. We anticipate that volcanism during Cretaceous/Cenozoic rifting activity caused the observed mantle-gas contributions. Interestingly, higher mantle contributions appear to correlate with elevated H2S in the production wells from this study suggesting thermal sulfate reduction induced by magmatic activity. Additionally, ASW and radiogenic noble gases can be used to model the relative volume of residual fluids-in-place for this Eagle Ford play. Initial data suggests that there has been minimal fractionation of noble gases implying minimal loss of the initial hydrocarbon fluids. Panel_15536 Panel_15536 11:10 AM 11:30 AM
11:30 a.m.
Assessing Compositional Variability and Migration of Natural Gas in Antrim Shale in the Michigan Basin Using Noble Gas Geochemistry
Room 702/704/706
Recent studies in the Michigan Basin looked at the atmospheric and terrigenic noble gas signatures of deep brines to place constraints on the past thermal history of the basin and to assess the extent of vertical transport processes within this sedimentary system. In this contribution, we present noble gas data of shale gas samples from the Antrim shale formation in the Michigan Basin. The Antrim shale was one of the first economic shale-gas plays in the U.S. and has been actively developed since the 1980’s. This study pioneers the use of noble gases in subsurface shale gas in the Michigan Basin to clarify the nature of vertical transport processes within the sedimentary sequence and to assess potential variability of noble gas signatures in shales. Antrim Shale gas samples were analyzed for all stable noble gases (He, Ne, Ar, Kr, Xe) from samples collected at depths between 300 and 500m. Preliminary results show R/Ra values (where R and Ra are the measured and atmospheric 3He/4He ratios, respectively) varying from 0.022 to 0.21. Although most samples fall within typical crustal R/Ra range values (~0.02-0.05), a few samples point to the presence of a mantle He component with higher R/Ra ratios. Samples with higher R/Ra values also display higher 20Ne/22Ne ratios, up to 10.4, and further point to the presence of mantle 20Ne. The presence of crustally produced nucleogenic 21Ne and radiogenic 40Ar is also apparent with 21Ne/22Ne ratios up to 0.033 and 40Ar/36Ar ratios up to 312. The presence of crustally produced 4He, 21Ne and 40Ar is not spatially homogeneous within the Antrim shale. Areas of higher crustal 4He production appear distinct to those of crustally produced 21Ne and 40Ar and are possibly related the presence of different production levels within the shale with varying concentrations of parent elements. Recent studies in the Michigan Basin looked at the atmospheric and terrigenic noble gas signatures of deep brines to place constraints on the past thermal history of the basin and to assess the extent of vertical transport processes within this sedimentary system. In this contribution, we present noble gas data of shale gas samples from the Antrim shale formation in the Michigan Basin. The Antrim shale was one of the first economic shale-gas plays in the U.S. and has been actively developed since the 1980’s. This study pioneers the use of noble gases in subsurface shale gas in the Michigan Basin to clarify the nature of vertical transport processes within the sedimentary sequence and to assess potential variability of noble gas signatures in shales. Antrim Shale gas samples were analyzed for all stable noble gases (He, Ne, Ar, Kr, Xe) from samples collected at depths between 300 and 500m. Preliminary results show R/Ra values (where R and Ra are the measured and atmospheric 3He/4He ratios, respectively) varying from 0.022 to 0.21. Although most samples fall within typical crustal R/Ra range values (~0.02-0.05), a few samples point to the presence of a mantle He component with higher R/Ra ratios. Samples with higher R/Ra values also display higher 20Ne/22Ne ratios, up to 10.4, and further point to the presence of mantle 20Ne. The presence of crustally produced nucleogenic 21Ne and radiogenic 40Ar is also apparent with 21Ne/22Ne ratios up to 0.033 and 40Ar/36Ar ratios up to 312. The presence of crustally produced 4He, 21Ne and 40Ar is not spatially homogeneous within the Antrim shale. Areas of higher crustal 4He production appear distinct to those of crustally produced 21Ne and 40Ar and are possibly related the presence of different production levels within the shale with varying concentrations of parent elements. Panel_15539 Panel_15539 11:30 AM 11:50 AM

1:15 p.m.–5:05 p.m.
Theme 4: Depositional and Diagenetic Processes in Shales and Mudstones (AAPG/SEPM)
Four Seasons Ballroom 1, Monday Oral Sessions, 01 June, 2015

Panel_14453 Panel_14453 1:15 PM 5:05 PM
1:15 p.m.
Introductory Remarks
Four Seasons Ballroom 1
Panel_15794 Panel_15794 1:15 PM 12:00 AM
1:20 p.m.
Are Unbioturbated Mudstones Indicative of Anoxia?
Four Seasons Ballroom 1
X-radiographs of sediment box cores acquired from the western Gulf of Mexico reveal limited bioturbation in sediment deposited at water depths greater than 35 m. Between 15 and 35 m, sediments are thoroughly bioturbated, with averaged bioturbation indices (for all beds in a core) between 2.1 and 5.6, and trace diversities between 2 and 9 distinct burrow forms. Below 35 m water depth, box cores exhibit trace diversities of 1–3 and core-averaged bioturbation indices range between 0.3 and 3.6. There is an overall decrease in trace diversity and bioturbation intensity in the offshore direction. Cross-shore ichnological trends are compared to dissolved oxygen (DO) contents of bottom waters. Dissolved oxygen decreases by an average of 0.117 mg/l per one-meter increase in water depth, such that bottom waters in 100 m water depth contain an average of 4.55 mg/l oxygen. Above 35 m, DO content shows pronounced variability ranging from 100% O2 saturation through to hypoxia (DO < 2.0 mg/l), and reflect the periodic introduction of hypoxic waters during June-July ocean hypoxia events. Below bathymetries of 35 m, the DO contents of bottom waters are consistently 60-75% oxygen saturation of Gulf of Mexico seawater, and oxygen concentrations decrease offshore. Although the present dataset is limited, there is a direct correlation between: a) the density of infauna and the diversity and density of burrows, and b) DO concentrations of bottom water. These trends indicate that the degree of bioturbation is significantly reduced in waters that are oxic but below 80% O2 saturation — the low bioturbation intensities and diversities do not reflect hypoxia or anoxia. Instead, reduced oxygen contents, but well above hypoxia, have a dramatic impact on the health of infaunal communities, which is reflected by severe reductions in the ichnological character of the sediments. Based on these results, we propose that unbioturbated and under-bioturbated marine mudstones and shales may simply reflect reduced DO concentrations of bottom water rather than anoxia in the paleoenvironment. X-radiographs of sediment box cores acquired from the western Gulf of Mexico reveal limited bioturbation in sediment deposited at water depths greater than 35 m. Between 15 and 35 m, sediments are thoroughly bioturbated, with averaged bioturbation indices (for all beds in a core) between 2.1 and 5.6, and trace diversities between 2 and 9 distinct burrow forms. Below 35 m water depth, box cores exhibit trace diversities of 1–3 and core-averaged bioturbation indices range between 0.3 and 3.6. There is an overall decrease in trace diversity and bioturbation intensity in the offshore direction. Cross-shore ichnological trends are compared to dissolved oxygen (DO) contents of bottom waters. Dissolved oxygen decreases by an average of 0.117 mg/l per one-meter increase in water depth, such that bottom waters in 100 m water depth contain an average of 4.55 mg/l oxygen. Above 35 m, DO content shows pronounced variability ranging from 100% O2 saturation through to hypoxia (DO < 2.0 mg/l), and reflect the periodic introduction of hypoxic waters during June-July ocean hypoxia events. Below bathymetries of 35 m, the DO contents of bottom waters are consistently 60-75% oxygen saturation of Gulf of Mexico seawater, and oxygen concentrations decrease offshore. Although the present dataset is limited, there is a direct correlation between: a) the density of infauna and the diversity and density of burrows, and b) DO concentrations of bottom water. These trends indicate that the degree of bioturbation is significantly reduced in waters that are oxic but below 80% O2 saturation — the low bioturbation intensities and diversities do not reflect hypoxia or anoxia. Instead, reduced oxygen contents, but well above hypoxia, have a dramatic impact on the health of infaunal communities, which is reflected by severe reductions in the ichnological character of the sediments. Based on these results, we propose that unbioturbated and under-bioturbated marine mudstones and shales may simply reflect reduced DO concentrations of bottom water rather than anoxia in the paleoenvironment. Panel_15172 Panel_15172 1:20 PM 1:40 PM
1:40 p.m.
New Horizons in Shale Sedimentology — How Experimental Advances Allow a New Look at the Rock Record
Four Seasons Ballroom 1
In recent years flume studies have enabled novel ways of interpreting shale successions by demonstrating that mud can be deposited from currents competent to move sand in bedload, that flocculated muds form ripples that migrate over the seabed, and that these processes result in finely laminated deposits. In the rock record, the latter were once associated with deep and stagnant environments, whereas now a more energetic and dynamic depositional history can be inferred. Comparable advances have been possible for the interpretation of carbonate muds and for shales with lenticular fabrics. A careful look at ancient shale fabrics also suggests that aside of evidence of unidirectional currents (bottom currents, tempestites, turbidites), there is a record of closely spaced multi-directional events that may record distal tidal influences as well as storm wave impingement on muddy sea bottoms. Initial experiments with a newly constructed mudflume system show that comparable structures can be produced in a tidal current regime in muddy sediments. Experimental work also suggests that in cold water settings, eroding muddy substrates should produce an abundance of transport prone sand-size mud aggregates. In an open ocean setting, such conditions should be conducive to mud transport at a larger scale, such as in the form of megaripples and mudwaves. Distribution of deep sea mudwaves in modern oceans, as well as rock record examples observed in the Ordovician Mazarn Shale of Arkansas and the Oligocene Bituminous Marl Formation of the eastern Carpathians in Romania, seem to validate that assumption. Ongoing flume studies of mud deposition are expanding to include multiple and variable flow histories, a wide spectrum of sediment compositions and grain size distributions, and the integration of organic matter (marine snow) into the depositional setup. Observations from these experiments will allow a close calibration of rock record textures to likely physical conditions at the time of deposition. In recent years flume studies have enabled novel ways of interpreting shale successions by demonstrating that mud can be deposited from currents competent to move sand in bedload, that flocculated muds form ripples that migrate over the seabed, and that these processes result in finely laminated deposits. In the rock record, the latter were once associated with deep and stagnant environments, whereas now a more energetic and dynamic depositional history can be inferred. Comparable advances have been possible for the interpretation of carbonate muds and for shales with lenticular fabrics. A careful look at ancient shale fabrics also suggests that aside of evidence of unidirectional currents (bottom currents, tempestites, turbidites), there is a record of closely spaced multi-directional events that may record distal tidal influences as well as storm wave impingement on muddy sea bottoms. Initial experiments with a newly constructed mudflume system show that comparable structures can be produced in a tidal current regime in muddy sediments. Experimental work also suggests that in cold water settings, eroding muddy substrates should produce an abundance of transport prone sand-size mud aggregates. In an open ocean setting, such conditions should be conducive to mud transport at a larger scale, such as in the form of megaripples and mudwaves. Distribution of deep sea mudwaves in modern oceans, as well as rock record examples observed in the Ordovician Mazarn Shale of Arkansas and the Oligocene Bituminous Marl Formation of the eastern Carpathians in Romania, seem to validate that assumption. Ongoing flume studies of mud deposition are expanding to include multiple and variable flow histories, a wide spectrum of sediment compositions and grain size distributions, and the integration of organic matter (marine snow) into the depositional setup. Observations from these experiments will allow a close calibration of rock record textures to likely physical conditions at the time of deposition. Panel_15176 Panel_15176 1:40 PM 2:00 PM
2:00 p.m.
Flume Studies With Graded Quartz Powders and a Mixture of Quartz and Kaolinite — Implications for Silt Laminated Shales in the Rock Record
Four Seasons Ballroom 1
Natural muds contain a substantial quantity of detrital quartz in the 62 – 1 micron grain size range. For a better understanding of potential transport and depositional processes, a series of flume experiments were conducted with commercial quartz powders that had maximum grain sizes of 50 microns, 40 microns, 30 microns and 5 microns. The finer fraction of each sediment batch was removed in an initial experiment step, and the coarse fraction was tested for critical velocity of sedimentation. These quartz powders show critical velocities of sedimentation of 45cm/sec (50 and 40 microns); 40 cm/sec (30 microns), and 20 cm/sec (5 microns). Ripple migration stopped at 20 cm/sec (50 and 40 microns), 25 cm/sec (30 microns), and 10 cm/sec (5 microns). Floccule formation was observed in the finer grain sizes (30-5 microns) and at smaller flow velocities (probably aided by the formation of biofilm in the flume). The coarser size grades (50, 40, 30 microns) form migrating barchan ripples and the finest grade (5 microns) forms migrating transverse ripples once the flow velocity drops below critical. In a separate step the finest grade (5 microns) and the coarsest grade (50 microns) silica was mixed with kaolinite to observe the interplay between silica and kaolinite under uniform low velocity (20cm/sec) flow regime. Initial observation revealed that the finer component of silica (5 microns) would co-mix with kaolinite forming kaolinite rich laminae with fine silt distributed through the clay matrix. The coarsest component of silica however produces silica rich laminae with little contribution from the kaolinite. Because kaolinite forms bedload floccules and floccule ripples at the used velocity setting, the observations indicate that fine silt grains are integrated into clay floccules and form mixed silt-clay laminae after compaction. The coarse silt forms separate ripples that travel through the flume channel at the same time as floccule ripples, and over time a deposit of interlaminated coarse silt and clay (with fine silt) accumulates. This relationship is directly matched by silt laminated shales form the rock record and suggests a comparable origin. Although in a number of ancient shales, the dissemination of fine silt within clay beds has been interpreted as an indication of eolian input, the process observed in our experiments is most likely a better explanation for the majority of cases. Natural muds contain a substantial quantity of detrital quartz in the 62 – 1 micron grain size range. For a better understanding of potential transport and depositional processes, a series of flume experiments were conducted with commercial quartz powders that had maximum grain sizes of 50 microns, 40 microns, 30 microns and 5 microns. The finer fraction of each sediment batch was removed in an initial experiment step, and the coarse fraction was tested for critical velocity of sedimentation. These quartz powders show critical velocities of sedimentation of 45cm/sec (50 and 40 microns); 40 cm/sec (30 microns), and 20 cm/sec (5 microns). Ripple migration stopped at 20 cm/sec (50 and 40 microns), 25 cm/sec (30 microns), and 10 cm/sec (5 microns). Floccule formation was observed in the finer grain sizes (30-5 microns) and at smaller flow velocities (probably aided by the formation of biofilm in the flume). The coarser size grades (50, 40, 30 microns) form migrating barchan ripples and the finest grade (5 microns) forms migrating transverse ripples once the flow velocity drops below critical. In a separate step the finest grade (5 microns) and the coarsest grade (50 microns) silica was mixed with kaolinite to observe the interplay between silica and kaolinite under uniform low velocity (20cm/sec) flow regime. Initial observation revealed that the finer component of silica (5 microns) would co-mix with kaolinite forming kaolinite rich laminae with fine silt distributed through the clay matrix. The coarsest component of silica however produces silica rich laminae with little contribution from the kaolinite. Because kaolinite forms bedload floccules and floccule ripples at the used velocity setting, the observations indicate that fine silt grains are integrated into clay floccules and form mixed silt-clay laminae after compaction. The coarse silt forms separate ripples that travel through the flume channel at the same time as floccule ripples, and over time a deposit of interlaminated coarse silt and clay (with fine silt) accumulates. This relationship is directly matched by silt laminated shales form the rock record and suggests a comparable origin. Although in a number of ancient shales, the dissemination of fine silt within clay beds has been interpreted as an indication of eolian input, the process observed in our experiments is most likely a better explanation for the majority of cases. Panel_15169 Panel_15169 2:00 PM 2:20 PM
2:20 p.m.
Laminated Black Shales: Process Sedimentology at Lamina Scale: Examples From the Eagle Ford Formation, TX, USA
Four Seasons Ballroom 1
Organic-rich depositional sequences, which represent prolific source rocks for both conventional and active unconventional plays, are often characterized by rhythmically interbedded limestones and marlstones, e.g., Utica Fm (Ohio, USA), Vaca Muerta Fm (Argentina), Natih Fm (Oman). New astronomical analyses of limestone-marlstone couplets from continuous sections of the Eagle Ford Formation (Texas, USA) document that the limestone-marlstone couplets reflect climatic forcing driven by solar insolation resulting from integrated Milankovitch periodicities; in particular, obliquity (41 ka) and precession (18-21 ka) forcing on summer insulation and therefore affecting seasonality, in turn determining the lithologic alternations. In fact, the rock preserves primary environmental signals, supporting greater water-mass ventilation and current activity during the deposition of limestones. To understand the laminae in the marlstones, we performed numerous analyses at lamina scale on a continuous thin section from an entire precession cycle (35 cm thick) characterized by high organic content. These analyses include sedimentologic descriptions and micropalaeontologic assemblage reconstructions at mm scale, X-ray fluorescence with 200 µm resolution and Total Organic Carbon measurements at cm scale. Organic-rich depositional sequences, which represent prolific source rocks for both conventional and active unconventional plays, are often characterized by rhythmically interbedded limestones and marlstones, e.g., Utica Fm (Ohio, USA), Vaca Muerta Fm (Argentina), Natih Fm (Oman). New astronomical analyses of limestone-marlstone couplets from continuous sections of the Eagle Ford Formation (Texas, USA) document that the limestone-marlstone couplets reflect climatic forcing driven by solar insolation resulting from integrated Milankovitch periodicities; in particular, obliquity (41 ka) and precession (18-21 ka) forcing on summer insulation and therefore affecting seasonality, in turn determining the lithologic alternations. In fact, the rock preserves primary environmental signals, supporting greater water-mass ventilation and current activity during the deposition of limestones. To understand the laminae in the marlstones, we performed numerous analyses at lamina scale on a continuous thin section from an entire precession cycle (35 cm thick) characterized by high organic content. These analyses include sedimentologic descriptions and micropalaeontologic assemblage reconstructions at mm scale, X-ray fluorescence with 200 µm resolution and Total Organic Carbon measurements at cm scale. Panel_15168 Panel_15168 2:20 PM 2:40 PM
2:40 p.m.
Break
Four Seasons Ballroom 1
Panel_15795 Panel_15795 2:40 PM 12:00 AM
3:25 p.m.
Facies Analysis of Thin-Bedded Reservoirs in Mixed-Influenced Deltaic Systems
Four Seasons Ballroom 1
Despite the historical assumptions that most marine “shelf” mud is deposited by gradual fallout from suspension in quiet water, recent studies of modern muddy shelves show that they are dominated by hyperpycnal fluid mud. Flume work shows that bedload transport is critical in the deposition of mud, and storm-wave aided hyperpycnal flows are common on many modern muddy shelves. We have applied these ideas to the interpretation of mud-rich prodelta deposits of the Cretaceous Western Interior Seaway depositional systems of North America. Thin-bedded heterolithic deposits contain significant sandstone and are volumetrically important zones of bypassed unconventional pay surrounding many conventional reservoirs. The Upper Cretaceous Ferron Sandstone in Utah shows deposition by ignitive turbidity currents, hyperpycnal flows, storm surges, as well as complete bioturbation in areas away from river-influence. Ignitive turbidites show fining upward Bouma sequence. Hyperpycnites show either inversely or normal grading. Storm deposits (tempestites) fine upward and contain hummocky cross stratification (HCS) and wave ripples. Ignitive turbidity currents and hyperpycnal flows indicate fluvial-dominated depositional environments, whereas tempestites are linked to storm-wave dominated environments. Detailed measured sections, as centimeter-scale, allow the relative proportion of sedimentary and biogenic structures generated by each depositional process/event to be calculated. These ` were measured from a series of stratigraphic sections within a mixed wave and fluvial dominated parasequence, exposed continuously exposed along depositional strike. The parasequence shows strong along-strike variation with a completely wave-influenced shoreface environment in the north, that contains minimal thin-beds, passing abruptly into a fluvial-dominated area with a thick heterolithic prodelta, then to an environment with varying degrees of fluvial and wave influence southward, and back to a wave-dominated environment further to the southeast. The depositional model of the parasequence is therefore interpreted as a storm-dominated symmetric delta with a large river-dominated bayhead delta system. It is thus practical to quantify the relative importance of depositional processes and determine the along-strike variation within thin-bedded heteroliths in ancient delta system using thin-bedded facies analysis, which has implications of along-strike heterogeneity of thin-bedded reservoirs. Despite the historical assumptions that most marine “shelf” mud is deposited by gradual fallout from suspension in quiet water, recent studies of modern muddy shelves show that they are dominated by hyperpycnal fluid mud. Flume work shows that bedload transport is critical in the deposition of mud, and storm-wave aided hyperpycnal flows are common on many modern muddy shelves. We have applied these ideas to the interpretation of mud-rich prodelta deposits of the Cretaceous Western Interior Seaway depositional systems of North America. Thin-bedded heterolithic deposits contain significant sandstone and are volumetrically important zones of bypassed unconventional pay surrounding many conventional reservoirs. The Upper Cretaceous Ferron Sandstone in Utah shows deposition by ignitive turbidity currents, hyperpycnal flows, storm surges, as well as complete bioturbation in areas away from river-influence. Ignitive turbidites show fining upward Bouma sequence. Hyperpycnites show either inversely or normal grading. Storm deposits (tempestites) fine upward and contain hummocky cross stratification (HCS) and wave ripples. Ignitive turbidity currents and hyperpycnal flows indicate fluvial-dominated depositional environments, whereas tempestites are linked to storm-wave dominated environments. Detailed measured sections, as centimeter-scale, allow the relative proportion of sedimentary and biogenic structures generated by each depositional process/event to be calculated. These ` were measured from a series of stratigraphic sections within a mixed wave and fluvial dominated parasequence, exposed continuously exposed along depositional strike. The parasequence shows strong along-strike variation with a completely wave-influenced shoreface environment in the north, that contains minimal thin-beds, passing abruptly into a fluvial-dominated area with a thick heterolithic prodelta, then to an environment with varying degrees of fluvial and wave influence southward, and back to a wave-dominated environment further to the southeast. The depositional model of the parasequence is therefore interpreted as a storm-dominated symmetric delta with a large river-dominated bayhead delta system. It is thus practical to quantify the relative importance of depositional processes and determine the along-strike variation within thin-bedded heteroliths in ancient delta system using thin-bedded facies analysis, which has implications of along-strike heterogeneity of thin-bedded reservoirs. Panel_15171 Panel_15171 3:25 PM 3:45 PM
3:45 p.m.
The Role of Muddy Hyperpycnites in Shelfal Mudstones and Their Effect on Reservoir Quality: Examples From the Geneseo Formation of New York, USA
Four Seasons Ballroom 1
Unconventional reservoir character varies at the mm- to km-scale vertically and laterally. This variability occurs in systematic ways that can be deciphered utilizing process-based models within a genetic framework. Variations in mudstone properties have a dramatic effect on prodicibility in shale reservoirs, however, the relative controls are not well understood. Detailed facies analysis, geochemistry, and petrography of the lower Genesee Group in the Northern Appalachian Basin (NAB) shows a wealth of sedimentary textures and fabrics that indicate mud deposition by lateral transport across and along the shelf under energetic conditions. Intervals of silt-rich mudstones and muddy siltstones with internal scours, diffuse stratification, soft-sediment deformation, normal and inverse lamina-set grading, and a reduced intensity and diversity of bioturbation occur in multiple facies types and “interrupt” what appears to be the overall background sedimentation. These intervals and their sedimentary features are interpreted as products of high-density fluvial discharge events, which generated turbulent flows that carried fine-grained clastics several tens of kilometers offshore from the paleoshoreline. Recognizing these sediments as products of river-flood- and storm-wave-generated offshore-directed underflows challenges previous depositional models for organic-rich mudstones in the lower Genesee succession, which call for clastic starvation and suspension settling of clay and silt in a deep stratified basin. In the Genesee Group, these observations imply rapid deposition of fine-grained intervals from hyperpycnal plumes in a setting favoring preservation of organic-rich mudstones, and suggest that similar reappraisals of depositional setting are necessary for comparable mudstone successions elsewhere in the Appalachian Basin. The described strata are yet another example for a carbonaceous mudstone succession that was deposited under comparatively energetic conditions, reflects multiple modes of sediment transport and deposition, and records significant carbon burial without a need for anoxic bottom waters. Through understanding the dynamic nature of mudstone depositional environments, process-based modeling can be conducted much more accurately at the reservoir scale, and can account for subtle changes in composition, cementation, porosity/permeability, as well as organic-matter type. Unconventional reservoir character varies at the mm- to km-scale vertically and laterally. This variability occurs in systematic ways that can be deciphered utilizing process-based models within a genetic framework. Variations in mudstone properties have a dramatic effect on prodicibility in shale reservoirs, however, the relative controls are not well understood. Detailed facies analysis, geochemistry, and petrography of the lower Genesee Group in the Northern Appalachian Basin (NAB) shows a wealth of sedimentary textures and fabrics that indicate mud deposition by lateral transport across and along the shelf under energetic conditions. Intervals of silt-rich mudstones and muddy siltstones with internal scours, diffuse stratification, soft-sediment deformation, normal and inverse lamina-set grading, and a reduced intensity and diversity of bioturbation occur in multiple facies types and “interrupt” what appears to be the overall background sedimentation. These intervals and their sedimentary features are interpreted as products of high-density fluvial discharge events, which generated turbulent flows that carried fine-grained clastics several tens of kilometers offshore from the paleoshoreline. Recognizing these sediments as products of river-flood- and storm-wave-generated offshore-directed underflows challenges previous depositional models for organic-rich mudstones in the lower Genesee succession, which call for clastic starvation and suspension settling of clay and silt in a deep stratified basin. In the Genesee Group, these observations imply rapid deposition of fine-grained intervals from hyperpycnal plumes in a setting favoring preservation of organic-rich mudstones, and suggest that similar reappraisals of depositional setting are necessary for comparable mudstone successions elsewhere in the Appalachian Basin. The described strata are yet another example for a carbonaceous mudstone succession that was deposited under comparatively energetic conditions, reflects multiple modes of sediment transport and deposition, and records significant carbon burial without a need for anoxic bottom waters. Through understanding the dynamic nature of mudstone depositional environments, process-based modeling can be conducted much more accurately at the reservoir scale, and can account for subtle changes in composition, cementation, porosity/permeability, as well as organic-matter type. Panel_15175 Panel_15175 3:45 PM 4:05 PM
4:05 p.m.
Haynesville-Bossier Shale: Diagenetic Development and Reservoir Quality Implications
Four Seasons Ballroom 1
Recent research on the Haynesville-Bossier Shale has focused on sedimentological and stratigraphic variability; but diagenetic processes play a major role in the development of shale attributes on a range of scales. Here we document data from petrographic and mineralogical observations for three Haynesville-Bossier Shale core datasets, including organic-, carbonate- and silica-rich sections, and discusses process-controls and implications for reservoir quality. The most common microfacies present are silt-rich, silt-bearing and clay-rich mudstones. Commonly occurring diagenetic features in the mudstone microfacies are quartz and calcite overgrowths, partial to nearly complete albite replacement of large pyrite- and kaolinite-filled bioclasts, and extensive pyrite framboid development. Iron-rich chlorite is also present, sometimes as a kaolinite pseudomorph. Associated with the mudstone microfacies are generally thin (<50cm), cement-dominated mudstones and siltstones comprising variably of apatite-cored pyrite, calcite, dolomite, and silica cements. Within these cementation is pervasive, either completely destroying the primary fine-grained matrix or limiting fines to the interstices of grain overgrowths. Clay mineral inter-particle pores (<1µm) are the most common type of pore, while intra-particle and intra-crystalline pores (<10 µm) are present. Organic matter pores are normally small (<1µm) and rare. Dolomite-dominated and phosphate-cored pyrite cements are early diagenetic features caused by organic matter oxidation close to the sediment surface. This commonly results from low sedimentation rates during a marine transgression. Quartz overgrowths in mudstones commonly develop due to the dissolution of biologically-sourced opaline silica. Calcite overgrowths and cements probably developed from the local dissolution of bioclasts. Uncompacted bioclasts became filled with early diagenetic pyrite and kaolinite, while albite replacement of calcite requires saline waters as a source of sodium. Aluminium for albite formation could be sourced from the chloritisation of kaolinite, a process which itself would require a source of mobile iron. As in conventional reservoirs, understanding processes of dissolution and precipitation of diagenetic minerals is essential to predicting porosity and permeability; however in shales, it also enables the recognition of reservoir intervals with good fracture potential. Recent research on the Haynesville-Bossier Shale has focused on sedimentological and stratigraphic variability; but diagenetic processes play a major role in the development of shale attributes on a range of scales. Here we document data from petrographic and mineralogical observations for three Haynesville-Bossier Shale core datasets, including organic-, carbonate- and silica-rich sections, and discusses process-controls and implications for reservoir quality. The most common microfacies present are silt-rich, silt-bearing and clay-rich mudstones. Commonly occurring diagenetic features in the mudstone microfacies are quartz and calcite overgrowths, partial to nearly complete albite replacement of large pyrite- and kaolinite-filled bioclasts, and extensive pyrite framboid development. Iron-rich chlorite is also present, sometimes as a kaolinite pseudomorph. Associated with the mudstone microfacies are generally thin (<50cm), cement-dominated mudstones and siltstones comprising variably of apatite-cored pyrite, calcite, dolomite, and silica cements. Within these cementation is pervasive, either completely destroying the primary fine-grained matrix or limiting fines to the interstices of grain overgrowths. Clay mineral inter-particle pores (<1µm) are the most common type of pore, while intra-particle and intra-crystalline pores (<10 µm) are present. Organic matter pores are normally small (<1µm) and rare. Dolomite-dominated and phosphate-cored pyrite cements are early diagenetic features caused by organic matter oxidation close to the sediment surface. This commonly results from low sedimentation rates during a marine transgression. Quartz overgrowths in mudstones commonly develop due to the dissolution of biologically-sourced opaline silica. Calcite overgrowths and cements probably developed from the local dissolution of bioclasts. Uncompacted bioclasts became filled with early diagenetic pyrite and kaolinite, while albite replacement of calcite requires saline waters as a source of sodium. Aluminium for albite formation could be sourced from the chloritisation of kaolinite, a process which itself would require a source of mobile iron. As in conventional reservoirs, understanding processes of dissolution and precipitation of diagenetic minerals is essential to predicting porosity and permeability; however in shales, it also enables the recognition of reservoir intervals with good fracture potential. Panel_15174 Panel_15174 4:05 PM 4:25 PM
4:25 p.m.
Paragenesis of Mineralized Fractures in Organic Rich Shales
Four Seasons Ballroom 1
Mineralized fractures are common in organic-rich shales and are of interest because the mineralogy can influence shale brittleness and porosity/permeability. We have noted similarities in the paragenesis of mineralized fractures from several shale units of different ages and from different basins (Devonian Marcellus Shale [PA], Mississippian Barnett Shale [TX], Devonian/Mississippian Woodford Shale [OK], and Late Jurassic Haynesville Shale [TX]). The shales contain localized vertical/subvertical and some horizontal mineralized fractures that vary in width from thin (~ 0.04 mm), usually filled with calcite, to thick (> 0.2 mm), which have a complex mineralogy. Some fractures or veins are precompactional although most are interpreted to form late in the diagenetic sequence. The Barnett, Haynesville, and Marcellus contain complex fractures with calcite, dolomite, baroque dolomite, quartz, chalcedony, barite, celestine, pyrite, sphalerite, anhydrite, and albite. New work on the Woodford in southern Oklahoma indicates a similar mineralogy. Dissolution events also occur in the paragenetic sequences and some fractures are associated with brecciation. Fluid inclusion studies suggest interaction with multiple fluids, including hydrocarbons and hydrothermal fluids. Variation in cathodoluminescence and compositional variations within individual minerals indicate precipitation from evolving fluids. In some cases the minerals in the fracture extend into the surrounding shale, which could influence brittleness and the likelihood of reactivation. It is also clear that the nature of the fracture can be influenced by the composition of the host shale. The similar and anomalous mineral assemblages in the fractures from the different shales indicate alteration by similar fluids, internal and/or external, and suggest similar sources for the minerals. The results from different shales in different tectonic settings raise fundamental questions about whether the shales are open or closed systems. Mineralized fractures are common in organic-rich shales and are of interest because the mineralogy can influence shale brittleness and porosity/permeability. We have noted similarities in the paragenesis of mineralized fractures from several shale units of different ages and from different basins (Devonian Marcellus Shale [PA], Mississippian Barnett Shale [TX], Devonian/Mississippian Woodford Shale [OK], and Late Jurassic Haynesville Shale [TX]). The shales contain localized vertical/subvertical and some horizontal mineralized fractures that vary in width from thin (~ 0.04 mm), usually filled with calcite, to thick (> 0.2 mm), which have a complex mineralogy. Some fractures or veins are precompactional although most are interpreted to form late in the diagenetic sequence. The Barnett, Haynesville, and Marcellus contain complex fractures with calcite, dolomite, baroque dolomite, quartz, chalcedony, barite, celestine, pyrite, sphalerite, anhydrite, and albite. New work on the Woodford in southern Oklahoma indicates a similar mineralogy. Dissolution events also occur in the paragenetic sequences and some fractures are associated with brecciation. Fluid inclusion studies suggest interaction with multiple fluids, including hydrocarbons and hydrothermal fluids. Variation in cathodoluminescence and compositional variations within individual minerals indicate precipitation from evolving fluids. In some cases the minerals in the fracture extend into the surrounding shale, which could influence brittleness and the likelihood of reactivation. It is also clear that the nature of the fracture can be influenced by the composition of the host shale. The similar and anomalous mineral assemblages in the fractures from the different shales indicate alteration by similar fluids, internal and/or external, and suggest similar sources for the minerals. The results from different shales in different tectonic settings raise fundamental questions about whether the shales are open or closed systems. Panel_15173 Panel_15173 4:25 PM 4:45 PM
4:45 p.m.
Chemostratigraphy of the Triassic Yanchang Fluvio-Lacustrine Succession, Ordos Basin, Shaanxi Province, China
Four Seasons Ballroom 1
A core-based study of a fluvio-lacustrine succession from the southeast Ordos Basin of North-Central China constrains the depositional and hydrographic history of the Triassic lake system. Elemental analysis (using handheld XRF) and mineralogical analysis (using portable XRD) constrain stratigraphic changes in mineralogy and provide insights into the conditions under which organic matter accumulated. In addition, measurements of TOC reveal strong mineralogical controls on organic matter accumulation. The 305-meter-long drill core contains four major (>20m thick) and three minor (10-20m thick) mudrock intervals, with intervening sandstone units. Some units possess interbedded mudrocks and sandstones, but are grouped by their dominant composition. A total of 458 TOC samples were analyzed from the core, at an average sample spacing of 0.6m. Values of TOC generally range between 3% and 6% in the lacustrine mudrock intervals, with some samples reaching 8%. TOC values in the sandstone units average just less than 1%, and based on hand sample observations, may largely reflect wood/charcoal contributions. Hand samples from outcropping fine-grained strata suggest lacustrine macrophytic material may represent a significant proportion of the TOC. A total of 207 XRD samples were analyzed, at an average sample spacing of 1.5m. The dominant mineralogy of the shale units is composed of illite, quartz, albite, kaolinite, and pyrite, with highly variable calcite. The arkosic sandstone units are dominated by albite and quartz, with calcite cement. A total of 2283 major and trace element analyses were undertaken on the slabbed face of the drill core, at an average sample spacing of 0.1m. Major element chemostratigraphic changes largely indicate variations in bulk mineralogy. For instance, the chemostratigraphic pattern of %S is largely reflective of measured stratigraphic shifts in pyrite content, which tends to possess higher concentrations in the mudrocks. This pattern is also observed in the arsenic (As) record, given its chalcophyllic affinity. In general, trace element compositions are indicative of the relative importance of the various minerals, and do not largely reflect variations in the evolution of lake bottom waters (e.g., redox changes). However, the increased pyrite in the mudrock-dominated intervals suggests that bottom waters potentially were at least periodically anoxic. A core-based study of a fluvio-lacustrine succession from the southeast Ordos Basin of North-Central China constrains the depositional and hydrographic history of the Triassic lake system. Elemental analysis (using handheld XRF) and mineralogical analysis (using portable XRD) constrain stratigraphic changes in mineralogy and provide insights into the conditions under which organic matter accumulated. In addition, measurements of TOC reveal strong mineralogical controls on organic matter accumulation. The 305-meter-long drill core contains four major (>20m thick) and three minor (10-20m thick) mudrock intervals, with intervening sandstone units. Some units possess interbedded mudrocks and sandstones, but are grouped by their dominant composition. A total of 458 TOC samples were analyzed from the core, at an average sample spacing of 0.6m. Values of TOC generally range between 3% and 6% in the lacustrine mudrock intervals, with some samples reaching 8%. TOC values in the sandstone units average just less than 1%, and based on hand sample observations, may largely reflect wood/charcoal contributions. Hand samples from outcropping fine-grained strata suggest lacustrine macrophytic material may represent a significant proportion of the TOC. A total of 207 XRD samples were analyzed, at an average sample spacing of 1.5m. The dominant mineralogy of the shale units is composed of illite, quartz, albite, kaolinite, and pyrite, with highly variable calcite. The arkosic sandstone units are dominated by albite and quartz, with calcite cement. A total of 2283 major and trace element analyses were undertaken on the slabbed face of the drill core, at an average sample spacing of 0.1m. Major element chemostratigraphic changes largely indicate variations in bulk mineralogy. For instance, the chemostratigraphic pattern of %S is largely reflective of measured stratigraphic shifts in pyrite content, which tends to possess higher concentrations in the mudrocks. This pattern is also observed in the arsenic (As) record, given its chalcophyllic affinity. In general, trace element compositions are indicative of the relative importance of the various minerals, and do not largely reflect variations in the evolution of lake bottom waters (e.g., redox changes). However, the increased pyrite in the mudrock-dominated intervals suggests that bottom waters potentially were at least periodically anoxic. Panel_15170 Panel_15170 4:45 PM 5:05 PM

1:15 p.m.–5:05 p.m.
Discovery Thinking II: North America Discoveries (AAPG/DPA)
Four Seasons Ballroom 2 & 3, Monday Oral Sessions, 01 June, 2015

This "Discovery Thinking" Forum will be the 13th presentation of the AAPG 100th Anniversary Committee's program recognizing "100 Who Made a Difference." The forum will feature four invited speakers who will describe major discoveries in North American exploration settings. This forum, combined with its counterpart into a day of Discovery Thinking, will celebrate how Creative Thinking Using Integrated Technology Leads to Giant and Super Giant Discoveries. Each speaker and their associates overcame significant business, technical and professional challenges. Topics to be discussed will include philosophy of exploration, stories from remarkable careers, professional insights, colorful anecdotes and lessons learned on the path to success. As technology advances and young geoscientists enter our profession, the organizers see continued interest in forums such as these. These forums provide a venue for explorers to discuss the personal side of success and what has been called the "art of exploration." As always, the audience is fortunate to hear the speakers share abundant technical data and insights derived from costly and hard won experience. AAPG offers many technical sessions. "Discovery Thinking" forums fill an important gap in how technical and professional skills combine to turn prospects into discoveries. Speakers are encouraged to share personal stories about discoveries they know well, bring forward appropriate technical data and address questions from the audience and fellow explorers. Afternoon talks will feature major and significant discoveries in North America. Denver, an important center for both global and North American exploration, is a great venue to celebrate discoveries in both of these settings.

This "Discovery Thinking" Forum will be the 13th presentation of the AAPG 100th Anniversary Committee's program recognizing "100 Who Made a Difference." The forum will feature four invited speakers who will describe major discoveries in North American exploration settings. This forum, combined with its counterpart into a day of Discovery Thinking, will celebrate how Creative Thinking Using Integrated Technology Leads to Giant and Super Giant Discoveries.

Each speaker and their associates overcame significant business, technical and professional challenges. Topics to be discussed will include philosophy of exploration, stories from remarkable careers, professional insights, colorful anecdotes and lessons learned on the path to success. As technology advances and young geoscientists enter our profession, the organizers see continued interest in forums such as these. These forums provide a venue for explorers to discuss the personal side of success and what has been called the "art of exploration." As always, the audience is fortunate to hear the speakers share abundant technical data and insights derived from costly and hard won experience.

AAPG offers many technical sessions. "Discovery Thinking" forums fill an important gap in how technical and professional skills combine to turn prospects into discoveries. Speakers are encouraged to share personal stories about discoveries they know well, bring forward appropriate technical data and address questions from the audience and fellow explorers. Afternoon talks will feature major and significant discoveries in North America. Denver, an important center for both global and North American exploration, is a great venue to celebrate discoveries in both of these settings.

 Panel_14417 Panel_14417 1:15 PM 5:05 PM
1:15 p.m.
Introductory Remarks
Four Seasons Ballroom 2 & 3
Panel_15796 Panel_15796 1:15 PM 12:00 AM
1:20 p.m.
The Exploration Dilemma: Gateway to New Paradigms in Discovery Thinking
Four Seasons Ballroom 2 & 3
Panel_15937 Panel_15937 1:20 PM 2:00 PM
2:00 p.m.
A Late Jurassic Play Fairway Beyond the Jeanne d’Arc Basin, New Insights and Recent Exploration Success in the Northern Flemish Pass Basin
Four Seasons Ballroom 2 & 3
Panel_15938 Panel_15938 2:00 PM 2:40 PM
2:40 p.m.
Break
Four Seasons Ballroom 2 & 3
Panel_15809 Panel_15809 2:40 PM 12:00 AM
3:25 p.m.
Unlocking the Deep Utica Play in Northeast Pennsylvania
Four Seasons Ballroom 2 & 3
<br />
Panel_15940 Panel_15940 3:25 PM 4:05 PM
4:05 p.m.
Case History: Big Bend Gulf of Mexico Exploration Success Through Integrated G&G Technology
Four Seasons Ballroom 2 & 3
The Big Bend discovery is the result of integrated studies which include the use of improved proprietarily processed wide azimuth seismic data (WAz), pore pressure prediction and chimney cube technology. These techniques helped decrease the uncertainty on the risk components which ultimately led to the decision of drilling the prospect. The proprietarily processed WAz data set provided meaningful uplift to the imaging adjacent and under salt, the DHI interpretation as well as the migration velocity. This uplift increased the confidence in reservoir presence and quality. In addition, the improved velocity volume was used in the pore pressure analysis to assess the column height and top seal potential, which helped mitigate the containment risk. The chimney cube technology results confirmed migration pathway and thermogenic charge assumptions, as well as the leaky trap prediction from pore pressure analysis. Additional exploration discoveries in this mature basin are possible when an integrated, experienced, multidisciplinary team is working with the recent advances in technology including 3-D WAZ seismic data acquisition and proprietary processing. The Big Bend discovery is the result of integrated studies which include the use of improved proprietarily processed wide azimuth seismic data (WAz), pore pressure prediction and chimney cube technology. These techniques helped decrease the uncertainty on the risk components which ultimately led to the decision of drilling the prospect. The proprietarily processed WAz data set provided meaningful uplift to the imaging adjacent and under salt, the DHI interpretation as well as the migration velocity. This uplift increased the confidence in reservoir presence and quality. In addition, the improved velocity volume was used in the pore pressure analysis to assess the column height and top seal potential, which helped mitigate the containment risk. The chimney cube technology results confirmed migration pathway and thermogenic charge assumptions, as well as the leaky trap prediction from pore pressure analysis. Additional exploration discoveries in this mature basin are possible when an integrated, experienced, multidisciplinary team is working with the recent advances in technology including 3-D WAZ seismic data acquisition and proprietary processing. Panel_14824 Panel_14824 4:05 PM 4:45 PM
4:45 p.m.
Question and Answer
Four Seasons Ballroom 2 & 3
Panel_15941 Panel_15941 4:45 PM 5:45 PM

Michel T. Halbouty Lecture (AAPG)
Date
Monday, 1 June 2015
Time
5:10 p.m.–6:00 p.m.
Location
Colorado Convention CenterFour Seasons Ballroom 2 & 3
Chair
John Anderson
Fee
Included with registration

The Michael T. Halbouty lecture series – funded by the AAPG Foundation – is an ongoing special event at the AAPG Annual Convention & Exhibition. Lecture topics are designed to focus either on wildcat exploration in any part of the world where major discoveries might contribute significantly to petroleum reserves, or space exploration where astrogeological knowledge would further mankind’s ability to develop resources on Earth and in the Solar System.

This year's Michel T. Halbouty Lecture speaker is Dr. Thomas S. Ahlbrandt, President, Thomasson Partners Associates, Inc. and he will discuss his talk: From Petroleum Scarcity to Abundance: Opportunities and Implications for the U.S. and World.

For 150 years the hydrocarbon industry has focused on about one quarter of the recoverable oil resource, and we are just now turning to the vast resource plays that are part of the Total Petroleum System (TPS) assessed by the United States Geological Survey (USGS) in 2000 and here updated through 2012. The TPS concept focused on the source rock and principal reservoir and recognized the conventional as well as unconventional (resource) components of the petroleum system. However, unconventional resources were basically only being developed in the U.S. at the time of the USGS assessment and were not included in the 2000 study. The USGS 2000 study, also summarized in "AAPG Memoir 86", included 149 provinces exclusive of the U.S. and data as of 1/1996.  Much has changed since that time. Dr. Ahlbrandt will present the updated views through 2013 for 175 provinces for the petroleum endowment elements of conventional undiscovered resources, reserve growth, cumulative production and remaining reserves and now amplified considerably by unconventional (or continuous resources).  The changes in the global hydrocarbon endowment through 2013 for these provinces are significant with the global oil endowment up nearly 50%, gas endowment up by nearly 25% and oil and gas reserves increased each by over 50% in spite of 16 additional years of production. The historical and data driven support for this petroleum revolution will be discussed to address the issue of why have the predicted global oil and natural gas shortages and demise of civilization by 2010 related to these vanishing supplies not occurred?

Thomas S. Ahlbrandt formed a consulting group (Ahlbrandt Consulting) specializing in conventional and unconventional resources globally. He also serves as the President of Thomasson Partners Associates, and Senior Vice President of Exploration for Systems Petroleum all located in Denver, Colorado. Previously he was the Vice President of Exploration for Falcon Oil and Gas in Denver, Colorado where he managed unconventional oil and natural gas exploration in Hungary (Mako Trough), Australia (Beetaloo Basin), and South Africa (Karoo Basin). “AAPG Memoir 86: Global Resource Estimates from Total Petroleum Systems” also summarizes this global petroleum analysis and was the senior author. He has written global resource outlooks for OPEC and in 2013 completed a book with the Energy Intelligence Group (London), “The Global Petroleum Revolution: A New Era of Opportunity” which discusses the global petroleum endowment and past and future petroleum forecasts. He recently discovered petroleum in the world’s oldest petroleum system (1.4 billion year old rocks in the Beetaloo Basin, Australia) and is a contributor to the recent AAPG volume on the Tethys contributing to the petroleum system evaluation of the Middle East and North Africa.

14248

The Michael T. Halbouty lecture series – funded by the AAPG Foundation – is an ongoing special event at the AAPG Annual Convention & Exhibition. Lecture topics are designed to focus either on wildcat exploration in any part of the world where major discoveries might contribute significantly to petroleum reserves, or space exploration where astrogeological knowledge would further mankind’s ability to develop resources on Earth and in the Solar System.

This year's Michel T. Halbouty Lecture speaker is Dr. Thomas S. Ahlbrandt, President, Thomasson Partners Associates, Inc. and he will discuss his talk: From Petroleum Scarcity to Abundance: Opportunities and Implications for the U.S. and World.

For 150 years the hydrocarbon industry has focused on about one quarter of the recoverable oil resource, and we are just now turning to the vast resource plays that are part of the Total Petroleum System (TPS) assessed by the United States Geological Survey (USGS) in 2000 and here updated through 2012. The TPS concept focused on the source rock and principal reservoir and recognized the conventional as well as unconventional (resource) components of the petroleum system. However, unconventional resources were basically only being developed in the U.S. at the time of the USGS assessment and were not included in the 2000 study. The USGS 2000 study, also summarized in "AAPG Memoir 86", included 149 provinces exclusive of the U.S. and data as of 1/1996.  Much has changed since that time. Dr. Ahlbrandt will present the updated views through 2013 for 175 provinces for the petroleum endowment elements of conventional undiscovered resources, reserve growth, cumulative production and remaining reserves and now amplified considerably by unconventional (or continuous resources).  The changes in the global hydrocarbon endowment through 2013 for these provinces are significant with the global oil endowment up nearly 50%, gas endowment up by nearly 25% and oil and gas reserves increased each by over 50% in spite of 16 additional years of production. The historical and data driven support for this petroleum revolution will be discussed to address the issue of why have the predicted global oil and natural gas shortages and demise of civilization by 2010 related to these vanishing supplies not occurred?

Thomas S. Ahlbrandt formed a consulting group (Ahlbrandt Consulting) specializing in conventional and unconventional resources globally. He also serves as the President of Thomasson Partners Associates, and Senior Vice President of Exploration for Systems Petroleum all located in Denver, Colorado. Previously he was the Vice President of Exploration for Falcon Oil and Gas in Denver, Colorado where he managed unconventional oil and natural gas exploration in Hungary (Mako Trough), Australia (Beetaloo Basin), and South Africa (Karoo Basin). “AAPG Memoir 86: Global Resource Estimates from Total Petroleum Systems” also summarizes this global petroleum analysis and was the senior author. He has written global resource outlooks for OPEC and in 2013 completed a book with the Energy Intelligence Group (London), “The Global Petroleum Revolution: A New Era of Opportunity” which discusses the global petroleum endowment and past and future petroleum forecasts. He recently discovered petroleum in the world’s oldest petroleum system (1.4 billion year old rocks in the Beetaloo Basin, Australia) and is a contributor to the recent AAPG volume on the Tethys contributing to the petroleum system evaluation of the Middle East and North Africa.

Panel_14248 Panel_14248 Michel T. Halbouty Lecture (AAPG) 01 June, 2015 01 June, 2015 5:10 PM 6:00 PM Colorado Convention Center

1:15 p.m.–5:05 p.m.
Theme 5: Geomechanics of Unconventionals (AAPG/PSGD)
Four Seasons Ballroom 4, Monday Oral Sessions, 01 June, 2015

Panel_14471 Panel_14471 1:15 PM 5:05 PM
1:15 p.m.
Introductory Remarks
Four Seasons Ballroom 4
Panel_15731 Panel_15731 1:15 PM 12:00 AM
1:20 p.m.
Predicting Sub-Seismic Fracture Density and Orientation: A Case Study From the Gorm Field, Danish North Sea
Four Seasons Ballroom 4
The chalk reservoir of the Gorm field, southern North Sea is dome shaped and faulted due to a combination of salt diapirism and regional E-W extension. Fractures developed in the structure considerably enhance permeability. The dataset discussed here records fractures in horizontal wells from more than 10km of image logs and provides a special opportunity to test theoretical models of fracture development with quantitative observations. In an effort to forecast fracture density and fracture orientation we have estimated the strains in the structure using an elastic dislocation model that incorporates mechanical boundaries in the form of the tectono-stratigraphic interface with salt and tectonic faults. More than 50% of the angular differences between poles to the planes of simulated and observed fractures are less than 30 degrees, 75% are less than 45 degrees. Relative strain magnitude appears to be a useful indicator of fracture density. At the field scale, small strain magnitudes correspond with small non-zero fracture densities and relatively large strain magnitudes correspond with high fracture densities. The chalk reservoir of the Gorm field, southern North Sea is dome shaped and faulted due to a combination of salt diapirism and regional E-W extension. Fractures developed in the structure considerably enhance permeability. The dataset discussed here records fractures in horizontal wells from more than 10km of image logs and provides a special opportunity to test theoretical models of fracture development with quantitative observations. In an effort to forecast fracture density and fracture orientation we have estimated the strains in the structure using an elastic dislocation model that incorporates mechanical boundaries in the form of the tectono-stratigraphic interface with salt and tectonic faults. More than 50% of the angular differences between poles to the planes of simulated and observed fractures are less than 30 degrees, 75% are less than 45 degrees. Relative strain magnitude appears to be a useful indicator of fracture density. At the field scale, small strain magnitudes correspond with small non-zero fracture densities and relatively large strain magnitudes correspond with high fracture densities. Panel_15352 Panel_15352 1:20 PM 1:40 PM
1:40 p.m.
Elemental Analysis as a Tool in Determining Wellbore Stability Issues
Four Seasons Ballroom 4
Solutions to deviated and horizontal wellbore stability issues can be complex. Problems such as lost circulation, stuck pipe, pack off, tight hole and enlarged cuttings can occur while drilling. Drilling techniques, mud pump pressure surges, mud type, weights and additives, cleanup cycle design, borehole azimuth, structure, anisotropic stresses and formation characteristics may be contributing factors in any combination. Determining a wellbore’s failure point is a critical first step toward finding a solution to a stability issue. Borehole imaging-while-drilling tools help but can be costly since an operator would need to routinely run the tools in wellbores in order to “catch” a wellbore failure. Analysis of breakdown/breakout mud weight failure envelopes help as predictive tools but may not be definitive in an actual wellbore failure situation. Wellbore “rubble” (enlarged rocks exiting the well that were not caused by cutting action from the drill bit) can be elementally/compositionally analyzed more precisely to determine where in the rock column the failure occurs. X-Ray Diffraction (XRD) works well to determine bulk mineralogy; however this technique can fall short when trying to differentiate various organic shale sequences and para-sequences. Elemental analysis and chemostratigraphy offer a more in-depth analysis to determine sequence stratigraphic units in mud rocks where type sections are available. This paper details a case study where the utilization of elemental analysis and chemostratigraphy to successfully pinpoint a series of wellbore failure events in the Marcellus Shale Play in southwestern Pennsylvania. Solutions to deviated and horizontal wellbore stability issues can be complex. Problems such as lost circulation, stuck pipe, pack off, tight hole and enlarged cuttings can occur while drilling. Drilling techniques, mud pump pressure surges, mud type, weights and additives, cleanup cycle design, borehole azimuth, structure, anisotropic stresses and formation characteristics may be contributing factors in any combination. Determining a wellbore’s failure point is a critical first step toward finding a solution to a stability issue. Borehole imaging-while-drilling tools help but can be costly since an operator would need to routinely run the tools in wellbores in order to “catch” a wellbore failure. Analysis of breakdown/breakout mud weight failure envelopes help as predictive tools but may not be definitive in an actual wellbore failure situation. Wellbore “rubble” (enlarged rocks exiting the well that were not caused by cutting action from the drill bit) can be elementally/compositionally analyzed more precisely to determine where in the rock column the failure occurs. X-Ray Diffraction (XRD) works well to determine bulk mineralogy; however this technique can fall short when trying to differentiate various organic shale sequences and para-sequences. Elemental analysis and chemostratigraphy offer a more in-depth analysis to determine sequence stratigraphic units in mud rocks where type sections are available. This paper details a case study where the utilization of elemental analysis and chemostratigraphy to successfully pinpoint a series of wellbore failure events in the Marcellus Shale Play in southwestern Pennsylvania. Panel_15351 Panel_15351 1:40 PM 2:00 PM
2:00 p.m.
Remote Sensing of Subsurface Fractures: A South Australian Case Study
Four Seasons Ballroom 4
South Australia’s Penola Trough was used as a natural laboratory for the detection of naturally occurring fractures, following an integrated methodology which included identification and interpretation of fractures in wellbore image logs and core, and the remote detection of fractures in a 3D seismic volume. In this study, electrical resistivity image logs from 11 petroleum wells were interpreted for structural features, with 508 fractures and 523 stress indicators identified. Stress indicators demonstrate a mean maximum horizontal stress orientation of 127°N in the Penola Trough. Two fracture types were identified: 1) 268 electrically conductive (potentially open to fluid flow) fractures with mean NW-SE strikes, and; 2) 239 electrically resistive (closed to fluid flow) fractures with mean E-W strikes. Core recovered from Jacaranda Ridge-1 shows open fractures are more rare than image logs indicate, due to the presence of fracture-filling siderite. Siderite is an iron-rich, electrically conductive cement that may cause fractures to appear hydraulically conductive in resistivity-based image logs. Fracture susceptibility plots created using the defined stress orientation, and previously derived magnitudes, illustrate that the majority of fractures detected are favourably oriented for reactivation under in-situ stresses. However, it is demonstrated that fracture fills exert a primary control over which fractures are open to fluid flow in the sub-surface. As natural fractures generally lie below the resolution of seismic amplitude data, seismic attributes were calculated from the 3D Balnaves/Haselgrove survey and mapped to the target Pretty Hill Formation to enhance observations of structural fabrics. Linear discontinuities likely to represent faults and fractures were identified with orientations consistent with natural fracture orientations identified in image logs, striking E-W and NW-SE. However, these are mostly limited in extent to zones around larger faults and so likely represent damage zones. Additionally, it is unlikely that a large proportion of these fractures are open to fluid flow, given observations from core and image logs. This limits possible fracture connectivity and, therefore, the possibility of significant secondary permeability in the Penola Trough. This integrated methodology provides an effective workflow for the remote detection of natural fractures, and for determining whether or not those fractures are hydraulically conductive. South Australia’s Penola Trough was used as a natural laboratory for the detection of naturally occurring fractures, following an integrated methodology which included identification and interpretation of fractures in wellbore image logs and core, and the remote detection of fractures in a 3D seismic volume. In this study, electrical resistivity image logs from 11 petroleum wells were interpreted for structural features, with 508 fractures and 523 stress indicators identified. Stress indicators demonstrate a mean maximum horizontal stress orientation of 127°N in the Penola Trough. Two fracture types were identified: 1) 268 electrically conductive (potentially open to fluid flow) fractures with mean NW-SE strikes, and; 2) 239 electrically resistive (closed to fluid flow) fractures with mean E-W strikes. Core recovered from Jacaranda Ridge-1 shows open fractures are more rare than image logs indicate, due to the presence of fracture-filling siderite. Siderite is an iron-rich, electrically conductive cement that may cause fractures to appear hydraulically conductive in resistivity-based image logs. Fracture susceptibility plots created using the defined stress orientation, and previously derived magnitudes, illustrate that the majority of fractures detected are favourably oriented for reactivation under in-situ stresses. However, it is demonstrated that fracture fills exert a primary control over which fractures are open to fluid flow in the sub-surface. As natural fractures generally lie below the resolution of seismic amplitude data, seismic attributes were calculated from the 3D Balnaves/Haselgrove survey and mapped to the target Pretty Hill Formation to enhance observations of structural fabrics. Linear discontinuities likely to represent faults and fractures were identified with orientations consistent with natural fracture orientations identified in image logs, striking E-W and NW-SE. However, these are mostly limited in extent to zones around larger faults and so likely represent damage zones. Additionally, it is unlikely that a large proportion of these fractures are open to fluid flow, given observations from core and image logs. This limits possible fracture connectivity and, therefore, the possibility of significant secondary permeability in the Penola Trough. This integrated methodology provides an effective workflow for the remote detection of natural fractures, and for determining whether or not those fractures are hydraulically conductive. Panel_15350 Panel_15350 2:00 PM 2:20 PM
2:20 p.m.
A Geomaterials Approach to Fault-Zone Characterisation
Four Seasons Ballroom 4
Observations demonstrate that some faults appear to be single planes where frictional concepts may be appropriate to assess evolution, stability and properties. Other fault examples show finite-thickness zones of either homogenised fault-rock, or spatially-ordered fault-related components – together these zones might be called a fault core. Such fault zones need to be acknowledged in fluid flow simulations, or in stability assessment, so there is a need to understand what phenomena control the spatial arrangement of fault-rock characteristics, and how those property distributions are expressed in seismic images or in fluid flow simulations. Geomaterials research (experiments, numerical simulation, and observations of natural examples) has been developing important new understanding about the processes that operate during the creation and evolution of shear zones/bands. Lab experiments using uniform material, with full-volume pre-, syn- and post-deformation observations, show that shearing processes often operate to create a finite-thickness zone within which states of stress and strain are far from uniform, and bear little or no relationship to the far-field state. Within the zone, the deformation becomes organised into distinct (often lozenge-shaped) regions where volumetric strains are dilative or compactant, with varying amounts of shear. These outcomes are comparable to the results of numerical simulations, which additionally reveal the variability of local stress states. Smaller-scale natural shears seem to be well explained by the processes identified in lab and simulation. Large-scale faults are compatible with these concepts, but outcrops are rarely/never of sufficient size and quality to allow a demonstration of the direct applicability (length-scales of lozenges exceed outcrop limits). Synthetic seismic models, based on strain states from the numerical methods, would be interpreted as showing multi-stranded faults, where no discontinuities exist. The understanding gained at lab-scale allows the calculation of deformation-caused poro-perm changes, which, when used in reservoir flow models, show the role of a fault zone in terms of flow performance. The standard approaches (transmissibility modifier of cell boundaries) lead to flow performance far from that predicted using the property arrangements derived from the geomechanical approach. A next-generation strategy has been developed for including geomechanical-derived properties in reservoir models. Observations demonstrate that some faults appear to be single planes where frictional concepts may be appropriate to assess evolution, stability and properties. Other fault examples show finite-thickness zones of either homogenised fault-rock, or spatially-ordered fault-related components – together these zones might be called a fault core. Such fault zones need to be acknowledged in fluid flow simulations, or in stability assessment, so there is a need to understand what phenomena control the spatial arrangement of fault-rock characteristics, and how those property distributions are expressed in seismic images or in fluid flow simulations. Geomaterials research (experiments, numerical simulation, and observations of natural examples) has been developing important new understanding about the processes that operate during the creation and evolution of shear zones/bands. Lab experiments using uniform material, with full-volume pre-, syn- and post-deformation observations, show that shearing processes often operate to create a finite-thickness zone within which states of stress and strain are far from uniform, and bear little or no relationship to the far-field state. Within the zone, the deformation becomes organised into distinct (often lozenge-shaped) regions where volumetric strains are dilative or compactant, with varying amounts of shear. These outcomes are comparable to the results of numerical simulations, which additionally reveal the variability of local stress states. Smaller-scale natural shears seem to be well explained by the processes identified in lab and simulation. Large-scale faults are compatible with these concepts, but outcrops are rarely/never of sufficient size and quality to allow a demonstration of the direct applicability (length-scales of lozenges exceed outcrop limits). Synthetic seismic models, based on strain states from the numerical methods, would be interpreted as showing multi-stranded faults, where no discontinuities exist. The understanding gained at lab-scale allows the calculation of deformation-caused poro-perm changes, which, when used in reservoir flow models, show the role of a fault zone in terms of flow performance. The standard approaches (transmissibility modifier of cell boundaries) lead to flow performance far from that predicted using the property arrangements derived from the geomechanical approach. A next-generation strategy has been developed for including geomechanical-derived properties in reservoir models. Panel_15349 Panel_15349 2:20 PM 2:40 PM
2:40 p.m.
Break
Four Seasons Ballroom 4
Panel_15749 Panel_15749 2:40 PM 12:00 AM
3:25 p.m.
Reservoir-Scale Controls on Fracture Orientation: Structural Position Versus Mechanical Variation
Four Seasons Ballroom 4
Characterizing fracture networks across a single field has been a consideration within the petroleum industry for decades but has become increasingly more important with the exploitation of unconventional plays such as tight sandstone and carbonate fields. Recent work has considered the importance of the mechanical stratigraphy in fracture network formation, and whether the present-day mechanical stratigraphy is an accurate predictor of the fracture stratigraphy or fracture network. A third question concerns the scale over which mechanical stratigraphy can influence the generation of fractures. This study considers fracture orientations in several positions across a single anticline, together with the mechanical and diagenetic history of the stratigraphic sequence. Measurements were taken on the crest of the anticline and on both the gently-dipping backlimb and the more steeply-dipping forelimb. At each location, bedding and fracture orientations, and lithology were recorded and unit hardness was measured with a rebound hammer. Samples were collected for thin section analysis of the diagenetic history. Results for the anticline limbs indicate that there are two characteristic patterns, one for each limb, which are not influenced by variation in hardness between individual beds. On the crest of the anticline, a third characteristic fracture pattern can be identified, with some variation between the patterns developed in dolomitic mudstone and the overlying tight sandstone. Again, individual beds within each lithology show variations in hardness with no change in fracture pattern. Thin-section analysis indicates late-stage (i.e. post fracturing) diagenetic changes to the units which are expected to influence the present-day hardness. This data suggests that in a highly deformed area such as a fold-thrust belt, the structural position is the strongest control on the developing fracture pattern, followed by large-scale variations in lithology and diagenesis rather than bed-scale variations in hardness. In less deformed areas, smaller-scale mechanical variation may have a greater influence. In addition, those diagenetic processes occurring after major fracture development will also affect which fracture orientations can be used as fluid-flow pathways. Characterizing fracture networks across a single field has been a consideration within the petroleum industry for decades but has become increasingly more important with the exploitation of unconventional plays such as tight sandstone and carbonate fields. Recent work has considered the importance of the mechanical stratigraphy in fracture network formation, and whether the present-day mechanical stratigraphy is an accurate predictor of the fracture stratigraphy or fracture network. A third question concerns the scale over which mechanical stratigraphy can influence the generation of fractures. This study considers fracture orientations in several positions across a single anticline, together with the mechanical and diagenetic history of the stratigraphic sequence. Measurements were taken on the crest of the anticline and on both the gently-dipping backlimb and the more steeply-dipping forelimb. At each location, bedding and fracture orientations, and lithology were recorded and unit hardness was measured with a rebound hammer. Samples were collected for thin section analysis of the diagenetic history. Results for the anticline limbs indicate that there are two characteristic patterns, one for each limb, which are not influenced by variation in hardness between individual beds. On the crest of the anticline, a third characteristic fracture pattern can be identified, with some variation between the patterns developed in dolomitic mudstone and the overlying tight sandstone. Again, individual beds within each lithology show variations in hardness with no change in fracture pattern. Thin-section analysis indicates late-stage (i.e. post fracturing) diagenetic changes to the units which are expected to influence the present-day hardness. This data suggests that in a highly deformed area such as a fold-thrust belt, the structural position is the strongest control on the developing fracture pattern, followed by large-scale variations in lithology and diagenesis rather than bed-scale variations in hardness. In less deformed areas, smaller-scale mechanical variation may have a greater influence. In addition, those diagenetic processes occurring after major fracture development will also affect which fracture orientations can be used as fluid-flow pathways. Panel_15343 Panel_15343 3:25 PM 3:45 PM
3:45 p.m.
Determining Failure Behavior at Hydraulic Fracturing Conditions Through Experimental Rock Deformation
Four Seasons Ballroom 4
Production of shale reservoirs through hydraulic fracturing techniques has fundamentally changed the U.S. energy landscape. The induced fracture systems are the primary source of transmissivity from the reservoir to the wellbore, so it is vital to understand and predict the extent of the induced fracture network. Geologic observations of natural fluid-pressure assisted fracture networks and microseismicity associated with induced fracturing demonstrate that the resulting geometries are complex. Typical explanations invoke reactivation of preexisting fractures; while natural fractures are important, we suggest that complex fracturing at multiple scales is characteristic of failure at the mixed tensile and compressive stress states associated with hydraulic fracturing. Previous experimental work has demonstrated that the conventional Griffith and modified Griffith failure criterions are inaccurate in predicting the failure strength and fracture angle for mixed stresses; fracture in these conditions involves both opening and shear modes with characteristic fracture morphologies and damage accumulation important in understanding hydraulic fracture networks. We report an experimental rock deformation study to develop a failure criterion for fracture in mixed stress states appropriate to hydraulic fracturing. Triaxial extension experiments employing necked (dogbone) samples were performed on four different rock types representing different porosity, grain structure, and composition. The results demonstrate a characteristic failure envelope for the transition from opening-mode fracture at very low mean stresses, to Coulomb shear fracture at high mean, compressive stress states. Fracture mode and orientation vary systematically across the transition similarly for all the rock types. The results support the hypothesis of a universal failure criterion scalable by rock strength. The results show a constant shape to the failure envelope, such that the ratio of unconfined compressive strength to tensile strength decreases with increases in absolute strength. Additionally, fracture orientation (angle between the fracture and maximum compressive stress) increases linearly with mean stress across the transitional regime. We suggest that the empirical failure envelope can be used to predict failure modes and fracture characteristics for a given reservoir by scaling the failure criterion to the tensile strength of the reservoir and considering in situ stress states. Production of shale reservoirs through hydraulic fracturing techniques has fundamentally changed the U.S. energy landscape. The induced fracture systems are the primary source of transmissivity from the reservoir to the wellbore, so it is vital to understand and predict the extent of the induced fracture network. Geologic observations of natural fluid-pressure assisted fracture networks and microseismicity associated with induced fracturing demonstrate that the resulting geometries are complex. Typical explanations invoke reactivation of preexisting fractures; while natural fractures are important, we suggest that complex fracturing at multiple scales is characteristic of failure at the mixed tensile and compressive stress states associated with hydraulic fracturing. Previous experimental work has demonstrated that the conventional Griffith and modified Griffith failure criterions are inaccurate in predicting the failure strength and fracture angle for mixed stresses; fracture in these conditions involves both opening and shear modes with characteristic fracture morphologies and damage accumulation important in understanding hydraulic fracture networks. We report an experimental rock deformation study to develop a failure criterion for fracture in mixed stress states appropriate to hydraulic fracturing. Triaxial extension experiments employing necked (dogbone) samples were performed on four different rock types representing different porosity, grain structure, and composition. The results demonstrate a characteristic failure envelope for the transition from opening-mode fracture at very low mean stresses, to Coulomb shear fracture at high mean, compressive stress states. Fracture mode and orientation vary systematically across the transition similarly for all the rock types. The results support the hypothesis of a universal failure criterion scalable by rock strength. The results show a constant shape to the failure envelope, such that the ratio of unconfined compressive strength to tensile strength decreases with increases in absolute strength. Additionally, fracture orientation (angle between the fracture and maximum compressive stress) increases linearly with mean stress across the transitional regime. We suggest that the empirical failure envelope can be used to predict failure modes and fracture characteristics for a given reservoir by scaling the failure criterion to the tensile strength of the reservoir and considering in situ stress states. Panel_15347 Panel_15347 3:45 PM 4:05 PM
4:05 p.m.
Lithological Controls on Mechanical Anisotropy in Shales to Predict In Situ Stress Magnitudes and Potential for Shearing of Laminations During Fracturing
Four Seasons Ballroom 4
Accurate and repeatable assessments of in situ stress magnitudes and orientation in unconventional reservoirs can be complicated by the heterogeneous, inelastic, and/or anisotropic mechanical properties of these rocks. The associated vertical and lateral variation in pore pressure and stress through the target zones and bounding intervals can further complicate this effort. For these reasons, some additional factors need to be considered beyond the typical workflow of determining stress state from mini-frac type data and using this data to calibrate log derived stress profiles. We present some case study examples from hydrocarbon-producing shales where a more rigorous analysis of the injection test data and of the shale mechanical properties has allowed a more accurate and repeatable assessment of in situ stress and potential for lamination shearing. Horizontal fracture growth through shear activation of bedding-parallel fabric can be a preferred fracture propagation mechanism in these shales and this behavior can be diagnosed by this improved workflow. In one case study example, in the tight gas Montney siltstone of Western Canada, shear strength anisotropy is shown to be very significant, with bedding parallel shear cohesion less than 10% of the bulk rock cohesion. It is shown through theory and through pressure transient analysis of case study minifrac injection data that shearing of laminations can be predicted, diagnosed and minimised during hydraulic fracturing stimulation. This shear fracturing mechanism is also stress dependent and its understanding requires assessment of all in situ stress magnitudes, not just minimum horizontal stress. An improved method of determining these stress magnitudes is described through multi-component acoustic measurements in core samples. In this way, a petrophysical relationship can be established between anisotropy parameters and rock properties. Accurate and repeatable assessments of in situ stress magnitudes and orientation in unconventional reservoirs can be complicated by the heterogeneous, inelastic, and/or anisotropic mechanical properties of these rocks. The associated vertical and lateral variation in pore pressure and stress through the target zones and bounding intervals can further complicate this effort. For these reasons, some additional factors need to be considered beyond the typical workflow of determining stress state from mini-frac type data and using this data to calibrate log derived stress profiles. We present some case study examples from hydrocarbon-producing shales where a more rigorous analysis of the injection test data and of the shale mechanical properties has allowed a more accurate and repeatable assessment of in situ stress and potential for lamination shearing. Horizontal fracture growth through shear activation of bedding-parallel fabric can be a preferred fracture propagation mechanism in these shales and this behavior can be diagnosed by this improved workflow. In one case study example, in the tight gas Montney siltstone of Western Canada, shear strength anisotropy is shown to be very significant, with bedding parallel shear cohesion less than 10% of the bulk rock cohesion. It is shown through theory and through pressure transient analysis of case study minifrac injection data that shearing of laminations can be predicted, diagnosed and minimised during hydraulic fracturing stimulation. This shear fracturing mechanism is also stress dependent and its understanding requires assessment of all in situ stress magnitudes, not just minimum horizontal stress. An improved method of determining these stress magnitudes is described through multi-component acoustic measurements in core samples. In this way, a petrophysical relationship can be established between anisotropy parameters and rock properties. Panel_15346 Panel_15346 4:05 PM 4:25 PM
4:25 p.m.
Numerical Simulations of Hydraulic Fracture Propagation — A Coupled Eulerian-Lagrangian Approach
Four Seasons Ballroom 4
Current numerical simulations of hydraulic fracturing do a poor job of predicting how fracture networks propagate during hydrofrac operations. These simulations can propagate fluid filled cracks in 3D domains using poroelastic governing equations, a realistic, anisotropic, distribution of material properties, initial ambient stress and fluid pressure conditions that include geostatic and tectonic loads, and time dependent fluid pressure loading. They are incapable of modeling branching fluid filled cracks. The relative magnitude of the differential stress controls the direction and morphology of fracture propagation-as the differential stress magnitude diminishes, fracture orientations become random and favor a branching morphology. This study utilizes a Coupled Eulerian-Lagrangian (CEL) approach to simulate hydrofrac propagation using a method that allows branching fractures. A CEL formulation is a Finite Element Method (FEM) technique that has three fundamental components, an Eulerian FEM (EFEM), which models the fluid, a Lagrangian FEM (LFEM), which models the solid, and general contact specifications to couple the two FEMs. In the EFEM, fluid, driven by fluid pressure gradients resulting from an injection source, is allowed to move through a fixed mesh. The LFEM has a deformable mesh and can track relatively small deformation and stress in elastic domains. Distributions of material properties can be propagated throughout domain if available. The general contact specifications govern the coupling between the two FEMs, satisfying quasi-static equilibrium over linear piece-wise surfaces normal to the fluid and bound by Lagrangian elements collocated with Eulerian elements having partial saturation. Both FEMs occupy the same space and contain appropriate material properties and initial, boundary, and loading conditions. The LFEM contains a cavity to simulate the injection point, and fluids within the EFEM are initially restricted to the cavity. The system is loaded to achieve the desired geostatic equilibrium and fluid flux is applied to the saturated zone of the EFEM. Fluid pressure increases until it exceeds the strength of some point of the chamber wall, which ruptures, introducing a fracture. The CEL analysis remeshes the LFEM to account for the crack, fluid flows into the fracture, and new coupling interfaces are created. With continuing pressurization the fracture propagates according to the time dependent stress field and specified rock strength. Current numerical simulations of hydraulic fracturing do a poor job of predicting how fracture networks propagate during hydrofrac operations. These simulations can propagate fluid filled cracks in 3D domains using poroelastic governing equations, a realistic, anisotropic, distribution of material properties, initial ambient stress and fluid pressure conditions that include geostatic and tectonic loads, and time dependent fluid pressure loading. They are incapable of modeling branching fluid filled cracks. The relative magnitude of the differential stress controls the direction and morphology of fracture propagation-as the differential stress magnitude diminishes, fracture orientations become random and favor a branching morphology. This study utilizes a Coupled Eulerian-Lagrangian (CEL) approach to simulate hydrofrac propagation using a method that allows branching fractures. A CEL formulation is a Finite Element Method (FEM) technique that has three fundamental components, an Eulerian FEM (EFEM), which models the fluid, a Lagrangian FEM (LFEM), which models the solid, and general contact specifications to couple the two FEMs. In the EFEM, fluid, driven by fluid pressure gradients resulting from an injection source, is allowed to move through a fixed mesh. The LFEM has a deformable mesh and can track relatively small deformation and stress in elastic domains. Distributions of material properties can be propagated throughout domain if available. The general contact specifications govern the coupling between the two FEMs, satisfying quasi-static equilibrium over linear piece-wise surfaces normal to the fluid and bound by Lagrangian elements collocated with Eulerian elements having partial saturation. Both FEMs occupy the same space and contain appropriate material properties and initial, boundary, and loading conditions. The LFEM contains a cavity to simulate the injection point, and fluids within the EFEM are initially restricted to the cavity. The system is loaded to achieve the desired geostatic equilibrium and fluid flux is applied to the saturated zone of the EFEM. Fluid pressure increases until it exceeds the strength of some point of the chamber wall, which ruptures, introducing a fracture. The CEL analysis remeshes the LFEM to account for the crack, fluid flows into the fracture, and new coupling interfaces are created. With continuing pressurization the fracture propagates according to the time dependent stress field and specified rock strength. Panel_15345 Panel_15345 4:25 PM 4:45 PM

1:15 p.m.–5:05 p.m.
Theme 2: Analogs and Models (AAPG)
Room 501/502/503, Monday Oral Sessions, 01 June, 2015

Panel_14433 Panel_14433 1:15 PM 5:05 PM
1:15 p.m.
Introductory Remarks
Room 501/502/503
Panel_15750 Panel_15750 1:15 PM 12:00 AM
1:20 p.m.
Impact of Integrated Geological and Reservoir Modeling Best Practices on Production Forecast Accuracy
Room 501/502/503
Major capital project subsurface workflows generally include a significant geological (static) modeling phase followed by a reservoir (dynamic) modeling phase from which reservoir forecasts of fluid/gas production over time are used to justify development decisions. A recent survey of industry major capital projects by Nandurdikar and Wallace (2011) showed that actual production is less than 75% of forecast production at project sanction and for projects with significant “reservoir issues” (as opposed to well or facility “issues”), the actual production was only 55% of that forecast. A variety of data from clastic and carbonate conventional reservoirs, unconventional reservoirs, and synthetic reservoirs been used to better understand the significant sources of forecast optimism and its mitigation. Analysis suggests that about 10-30% of the reported forecast optimism is due to sparse data and/or analog bias, about 15-40% is due to static and geological and reservoir modeling workflow decisions including the use of well location optimization, and the remainder due to human and/or management induced bias, perhaps compounded by unnecessary model complexity. Reservoir forecasts based on static geological and dynamic reservoir models can be improved by recognizing and addressing sources of bias through the use of sound, statistically rigorous uncertainty assessment and proper understanding of the limits imposed on model derived forecasts due to model workflow decisions. The use of external peer review teams, look-back studies, and best practice guides integrated across geological and engineering disciplines may also significantly reduce unintentional technical or management-driven bias. Major capital project subsurface workflows generally include a significant geological (static) modeling phase followed by a reservoir (dynamic) modeling phase from which reservoir forecasts of fluid/gas production over time are used to justify development decisions. A recent survey of industry major capital projects by Nandurdikar and Wallace (2011) showed that actual production is less than 75% of forecast production at project sanction and for projects with significant “reservoir issues” (as opposed to well or facility “issues”), the actual production was only 55% of that forecast. A variety of data from clastic and carbonate conventional reservoirs, unconventional reservoirs, and synthetic reservoirs been used to better understand the significant sources of forecast optimism and its mitigation. Analysis suggests that about 10-30% of the reported forecast optimism is due to sparse data and/or analog bias, about 15-40% is due to static and geological and reservoir modeling workflow decisions including the use of well location optimization, and the remainder due to human and/or management induced bias, perhaps compounded by unnecessary model complexity. Reservoir forecasts based on static geological and dynamic reservoir models can be improved by recognizing and addressing sources of bias through the use of sound, statistically rigorous uncertainty assessment and proper understanding of the limits imposed on model derived forecasts due to model workflow decisions. The use of external peer review teams, look-back studies, and best practice guides integrated across geological and engineering disciplines may also significantly reduce unintentional technical or management-driven bias. Panel_14992 Panel_14992 1:20 PM 1:40 PM
1:40 p.m.
From 3-D Photogrammetric Outcrop Model Towards Reservoir Models: An Integrated Modeling Workflow
Room 501/502/503
3D technologies are now widely used in geosciences to reconstruct outcrops in 3D. The technology used for the 3D reconstruction is usually based on Lidar, which provides very precise models. Such datasets offer the possibility to build well-constrained outcrop analogue models for reservoir study purposes. The photogrammetry is an alternate methodology which principles are based in determining the geometric properties of an object from photographic pictures taken from different angles. Outcrop data acquisition is easy, and this methodology allows constructing 3D outcrop models with many advantages such as light and fast acquisition, moderate processing time (depending on the size of the area of interest), and integration of field data and 3D outcrops into the reservoir modelling tools. Whatever the method, the advantages of digital outcrop model are numerous: collection of data from otherwise inaccessible areas, access to different angles of view, increase of the possible measurements, attributes analysis, fast rate of data collection, and of course training and communication. This paper proposes a workflow where 3D geocellular models are built by integrating all sources of information from outcrops (surface picking, sedimentological sections, structural and sedimentary dips…). The 3D geomodels that are reconstructed can be used at the reservoir scale, in order to compare the outcrop information with subsurface models: the detailed facies models of the outcrops are transferred into petrophysical and acoustic models, which are used to test different scenarios of seismic and fluid flow modelling. The detailed 3D models are also used to test new techniques of static reservoir modelling, based either on geostatistical approaches or on deterministic (process-based) simulation techniques. A modelling workflow has been designed to model reservoir geometries and properties from 3D outcrop data, including geostatistical modelling and fluid flow simulations The case study is a turbidite reservoir analog in Northern Spain (Ainsa). In this case study, we can compare reservoir models that have been built with conventional data set (1D pseudowells), and reservoir model built from 3D outcrop data directly used to constrain the reservoir architecture. This approach allows us to assess the benefits of integrating geotagged 3D outcrop data into reservoir models. 3D technologies are now widely used in geosciences to reconstruct outcrops in 3D. The technology used for the 3D reconstruction is usually based on Lidar, which provides very precise models. Such datasets offer the possibility to build well-constrained outcrop analogue models for reservoir study purposes. The photogrammetry is an alternate methodology which principles are based in determining the geometric properties of an object from photographic pictures taken from different angles. Outcrop data acquisition is easy, and this methodology allows constructing 3D outcrop models with many advantages such as light and fast acquisition, moderate processing time (depending on the size of the area of interest), and integration of field data and 3D outcrops into the reservoir modelling tools. Whatever the method, the advantages of digital outcrop model are numerous: collection of data from otherwise inaccessible areas, access to different angles of view, increase of the possible measurements, attributes analysis, fast rate of data collection, and of course training and communication. This paper proposes a workflow where 3D geocellular models are built by integrating all sources of information from outcrops (surface picking, sedimentological sections, structural and sedimentary dips…). The 3D geomodels that are reconstructed can be used at the reservoir scale, in order to compare the outcrop information with subsurface models: the detailed facies models of the outcrops are transferred into petrophysical and acoustic models, which are used to test different scenarios of seismic and fluid flow modelling. The detailed 3D models are also used to test new techniques of static reservoir modelling, based either on geostatistical approaches or on deterministic (process-based) simulation techniques. A modelling workflow has been designed to model reservoir geometries and properties from 3D outcrop data, including geostatistical modelling and fluid flow simulations The case study is a turbidite reservoir analog in Northern Spain (Ainsa). In this case study, we can compare reservoir models that have been built with conventional data set (1D pseudowells), and reservoir model built from 3D outcrop data directly used to constrain the reservoir architecture. This approach allows us to assess the benefits of integrating geotagged 3D outcrop data into reservoir models. Panel_14993 Panel_14993 1:40 PM 2:00 PM
2:00 p.m.
Architecture and Connectivity of Coal-Bearing Reservoirs: New Insights From Outcrop Analogues
Room 501/502/503
Predictive model for coal-bearing fluvio-deltaic successions in the subsurface are required to drive the effective and cost efficient hydrocarbon development of both unconventional coal-bed methane and conventional reservoir projects. The Eastern Kentucky and West Virginia road network provide world-class exposures of Upper Carboniferous coal bearing successions where the interplay between sand and shale intervals and intervening coals can be studied in detail. In this paper we present a summary of ongoing research recently carried out on the Pennsylvanian Hyden and Pikeville Formations where architecture and laterial facies variability can be observed and followed for several km thanks to exceptional outcrop quality and dense borehole data from coal mining operations. Coals, usually genetically associated with transgressive system tract, lies often on top of channel-fill sandstone and under shale dominated intervals the latter recording the transition from a flooded coastal plain to shallow to deep marine environment. However coals are found as well draping irregular topographic surfaces where wide and relatively deep (10-20 m) incisions can be recognised. In this situations coals are typically overlain by channel fill sandstone forming the stratigraphical unit above. In this cases, the coals are interpreted as forming during a low stand phase and thus possibly the true indicators of development of incised valleys. Five to ten meters-high inclined beds made of mixed heterolithic successions of sandstones and shales are associated with both fluvial-dominated mouth bars and point-bars develop in large meandering river systems often developed within estuarine environment. This study highlights the typical 3D features of these deposits allowing the definition of sedimentological and stratigraphical criteria to distinguish these tow systems in the subsurface. The Carboniferous succession of Eastern Kentucky is compared with the coeval succession in the North Sea (The Netherlands) to highlight the importance of outcrop based analogues studies to help understanding the overall distribution of subsurface geology by providing practical criteria for a) carrying out a well-to-well correlation and b) reconstruct the overall 3D reservoir architecture. Predictive model for coal-bearing fluvio-deltaic successions in the subsurface are required to drive the effective and cost efficient hydrocarbon development of both unconventional coal-bed methane and conventional reservoir projects. The Eastern Kentucky and West Virginia road network provide world-class exposures of Upper Carboniferous coal bearing successions where the interplay between sand and shale intervals and intervening coals can be studied in detail. In this paper we present a summary of ongoing research recently carried out on the Pennsylvanian Hyden and Pikeville Formations where architecture and laterial facies variability can be observed and followed for several km thanks to exceptional outcrop quality and dense borehole data from coal mining operations. Coals, usually genetically associated with transgressive system tract, lies often on top of channel-fill sandstone and under shale dominated intervals the latter recording the transition from a flooded coastal plain to shallow to deep marine environment. However coals are found as well draping irregular topographic surfaces where wide and relatively deep (10-20 m) incisions can be recognised. In this situations coals are typically overlain by channel fill sandstone forming the stratigraphical unit above. In this cases, the coals are interpreted as forming during a low stand phase and thus possibly the true indicators of development of incised valleys. Five to ten meters-high inclined beds made of mixed heterolithic successions of sandstones and shales are associated with both fluvial-dominated mouth bars and point-bars develop in large meandering river systems often developed within estuarine environment. This study highlights the typical 3D features of these deposits allowing the definition of sedimentological and stratigraphical criteria to distinguish these tow systems in the subsurface. The Carboniferous succession of Eastern Kentucky is compared with the coeval succession in the North Sea (The Netherlands) to highlight the importance of outcrop based analogues studies to help understanding the overall distribution of subsurface geology by providing practical criteria for a) carrying out a well-to-well correlation and b) reconstruct the overall 3D reservoir architecture. Panel_14989 Panel_14989 2:00 PM 2:20 PM
2:20 p.m.
Using Image Logs to Identify Facies in Heterogeneous Turbidite and Basinal Organic Mudstone Systems From the Wolfcamp Formation, Delaware Basin, West Texas, USA
Room 501/502/503
Integration of core facies, image log facies (ILF) and wireline logs from heterogeneous turbidite and basinal organic mudstone systems, increases the confidence levels for the database for building regional scale depositional models. Image logs provide a key link to characterize facies and processes in comparison to wireline logs, and can also be used to bridge the correlation between core facies and wireline logs for up-scaling. Systematic use of ILF as part of the correlation increases the data set for facies interpretation, as there is greater availability of image logs compared to core. This presentation details a method that uses borehole image logs to extend core-based facies and process analysis to intervals that lack core, in above mentioned sedimentary systems. The method is successfully used in a workflow that distinguishes carbonate, quartz, mud-rich turbidites and debris flows deposited with organic-rich silicic mudstones in an unconventional play of the Delaware basin. When using this method, electrode data from each pad of the micro-resistivity imaging tool (in water-based mud) is mathematically shifted to generate synthetic micro-resistivity logs that follow the trend of the shallow resistivity logs. The high resolution electrical data that best represents the sedimentary facies either derived from a single pad, or the averages from multiple pads of the imaging tool is selected. Next, the high resolution electrical data and detailed sedimentary textures visible from the image logs are used to identify the ILF and in turn calibrated with core facies. Caution is taken while using electrical data for facies identification as those can be severely affected by pore fluid properties. In the current effort triple-combo logs are considered for identifying broad lithological variation and ILF for more detailed characterization. The results show that of the 10 detailed core facies from cored intervals of mud-dominated turbidite sequences from lower and middle part of Wolfcamp Formation, 6 can be identified from the image logs. Within the sand-dominated turbidite sequence from upper most part of Wolfcamp Formation, 3 different ILF are identified out of 4 core facies. 4 different types of sedimentary processes are also identified from the image logs. Finally the ILF are successfully extended to identify the sedimentary facies and processes of Wolfcamp Formation over those imaged intervals that lack core in a specific well and also in the nearby wells. Integration of core facies, image log facies (ILF) and wireline logs from heterogeneous turbidite and basinal organic mudstone systems, increases the confidence levels for the database for building regional scale depositional models. Image logs provide a key link to characterize facies and processes in comparison to wireline logs, and can also be used to bridge the correlation between core facies and wireline logs for up-scaling. Systematic use of ILF as part of the correlation increases the data set for facies interpretation, as there is greater availability of image logs compared to core. This presentation details a method that uses borehole image logs to extend core-based facies and process analysis to intervals that lack core, in above mentioned sedimentary systems. The method is successfully used in a workflow that distinguishes carbonate, quartz, mud-rich turbidites and debris flows deposited with organic-rich silicic mudstones in an unconventional play of the Delaware basin. When using this method, electrode data from each pad of the micro-resistivity imaging tool (in water-based mud) is mathematically shifted to generate synthetic micro-resistivity logs that follow the trend of the shallow resistivity logs. The high resolution electrical data that best represents the sedimentary facies either derived from a single pad, or the averages from multiple pads of the imaging tool is selected. Next, the high resolution electrical data and detailed sedimentary textures visible from the image logs are used to identify the ILF and in turn calibrated with core facies. Caution is taken while using electrical data for facies identification as those can be severely affected by pore fluid properties. In the current effort triple-combo logs are considered for identifying broad lithological variation and ILF for more detailed characterization. The results show that of the 10 detailed core facies from cored intervals of mud-dominated turbidite sequences from lower and middle part of Wolfcamp Formation, 6 can be identified from the image logs. Within the sand-dominated turbidite sequence from upper most part of Wolfcamp Formation, 3 different ILF are identified out of 4 core facies. 4 different types of sedimentary processes are also identified from the image logs. Finally the ILF are successfully extended to identify the sedimentary facies and processes of Wolfcamp Formation over those imaged intervals that lack core in a specific well and also in the nearby wells. Panel_14995 Panel_14995 2:20 PM 2:40 PM
2:40 p.m.
Break
Room 501/502/503
Panel_15751 Panel_15751 2:40 PM 12:00 AM
3:25 p.m.
Integrated Reservoir Characterization and Depositional Model of Zubair Formation in Exploration Phase, in Bahrah Area, Kuwait
Room 501/502/503
Barremian to Early Aptian Zubair Formation in Northern Kuwait constitutes the significant oil reserve in Sabriyah, Raudhatain, Abdali and Ratqa area. In Bharah area which is situated to the south of Sabriyah field, Zubair Formation has not yet been explored in a systematic way. Five deep wells which were drilled to explore Jurassic section, have shown strong hydrocarbon presence during drilling .The open hole log evaluation (16’’ hole size) has also substantiated the hydrocarbon presence from Zubair section. The challenge of this work has been the evaluation of hydrocarbon potential based on robust depositional model to characterize and to define the geometry of Zubair reservoir. Integrated core and petrographic analysis brought out that Zubair Formation was deposited under tidal influenced deltaic setting that episodically displayed an estuarine character. This indicates that the architecture and reservoir quality of Zubair reservoir sand bodies are representing the deltaic, estuarine channel fill, mouth bar and sandsheet facies association. The gross sequence stratigraphy of Zubair Formation in Bahrah can be described in terms of low frequency sequence sets which contain superimposed higher frequency system tracts. The lower Zubair TST is characterized by back stepping or retro-gradational character suggesting limited lateral extension of sand bodies. The middle Zubair HST shows isolated and stacked channel with very good reservoir potential. The upper Zubair LST is bounded by the sequence boundary at the base and flooding surface at the top that mark the distinct change of depositional style. These channel sand bodies show NW-SE orientation with widespread lateral extent with very good to excellent reservoir quality .Horizon based geo-body extraction of RMS amplitude from PSDM seismic data established the geometry of delta, channel fill and sandsheet facies association. A band pass inversion of seismic guided integrated reservoir model shows very good to excellent reservoir quality with wide spatial distribution of upper Zubair LST sand and comparatively fair to good reservoir quality with limited extent in Lower Zubair TST sand. Integration of above information, analog of nearby producing fields and seismic attributes indicates Zubair Formation has a significant untapped oil production potential in Bahrah. This work will be highly beneficial for efficient selection of locations to prove hydrocarbon potential of Zubair Formation in Bahrah area. Barremian to Early Aptian Zubair Formation in Northern Kuwait constitutes the significant oil reserve in Sabriyah, Raudhatain, Abdali and Ratqa area. In Bharah area which is situated to the south of Sabriyah field, Zubair Formation has not yet been explored in a systematic way. Five deep wells which were drilled to explore Jurassic section, have shown strong hydrocarbon presence during drilling .The open hole log evaluation (16’’ hole size) has also substantiated the hydrocarbon presence from Zubair section. The challenge of this work has been the evaluation of hydrocarbon potential based on robust depositional model to characterize and to define the geometry of Zubair reservoir. Integrated core and petrographic analysis brought out that Zubair Formation was deposited under tidal influenced deltaic setting that episodically displayed an estuarine character. This indicates that the architecture and reservoir quality of Zubair reservoir sand bodies are representing the deltaic, estuarine channel fill, mouth bar and sandsheet facies association. The gross sequence stratigraphy of Zubair Formation in Bahrah can be described in terms of low frequency sequence sets which contain superimposed higher frequency system tracts. The lower Zubair TST is characterized by back stepping or retro-gradational character suggesting limited lateral extension of sand bodies. The middle Zubair HST shows isolated and stacked channel with very good reservoir potential. The upper Zubair LST is bounded by the sequence boundary at the base and flooding surface at the top that mark the distinct change of depositional style. These channel sand bodies show NW-SE orientation with widespread lateral extent with very good to excellent reservoir quality .Horizon based geo-body extraction of RMS amplitude from PSDM seismic data established the geometry of delta, channel fill and sandsheet facies association. A band pass inversion of seismic guided integrated reservoir model shows very good to excellent reservoir quality with wide spatial distribution of upper Zubair LST sand and comparatively fair to good reservoir quality with limited extent in Lower Zubair TST sand. Integration of above information, analog of nearby producing fields and seismic attributes indicates Zubair Formation has a significant untapped oil production potential in Bahrah. This work will be highly beneficial for efficient selection of locations to prove hydrocarbon potential of Zubair Formation in Bahrah area. Panel_14997 Panel_14997 3:25 PM 3:45 PM
3:45 p.m.
Building Global Kinematic Plate Reconstructions Through the Phanerozoic: Testing Alternative Models for the Amalgamation of Pangea
Room 501/502/503
Kinematic plate models that reconstruct the positions of tectonic plates and their boundaries through time are useful in elucidating the geological and tectonic history of a region—essential knowledge in determining regional resource potential. We are using the open-source GPlates software to develop global Phanerozoic kinematic plate reconstructions. The models include continuously closing plate boundaries, whose construction is helpful for testing the consistency of any given model with the rules of plate tectonics. As we extend our models back through the Paleozoic, and data constraints become more sparse, the integration of disparate data sets and the strict adherence to the rules of plate tectonics become essential in producing geologically sound global pre-Pangea plate models. The position of Laurussia relative to Gondwana prior to the amalgamation of Pangea is a major on-going controversy, with different scenarios implying distinct histories of passive margin evolution and basin formation. Models based primarily on paleomagnetic data tend to require large dextral strike-slip motions (up to 8400 km) to bring Laurussia into its Pangea configuration during the Devonian–Carboniferous Variscan Orogeny. These models of the orogeny involve multiple terranes, representing portions of present-day Spain, France and Germany, each with distinct motions, and multiple ocean basins separating them. Models more strongly biased towards honouring the juxtaposition of faunal and geological provinces, as well as geochronological data, involve more orthogonal collision during the Variscan Orogeny, and imply most or all of the European terranes remained connected to Gondwana until Pangea dispersal. We investigate these end-member models using alternative plate reconstructions that are consistent with paleomagnetic data. Strike-slip amalgamation requires Laurussian plate velocities up to 18 cm/yr, which is unreasonably high for a plate comprising a large continent, whereas orthogonal convergence implies velocities more consistent with the rules of plate tectonics. Other testable predictions from the kinematic models of each scenario are compared with geological and paleomagnetic data. Iteratively applying this approach allows us to expand the global model both in regional detail, and further back through time. Future work will extend the model back to Rodinia, and will add in complexity, such as deforming regions within a global tectonic framework. Kinematic plate models that reconstruct the positions of tectonic plates and their boundaries through time are useful in elucidating the geological and tectonic history of a region—essential knowledge in determining regional resource potential. We are using the open-source GPlates software to develop global Phanerozoic kinematic plate reconstructions. The models include continuously closing plate boundaries, whose construction is helpful for testing the consistency of any given model with the rules of plate tectonics. As we extend our models back through the Paleozoic, and data constraints become more sparse, the integration of disparate data sets and the strict adherence to the rules of plate tectonics become essential in producing geologically sound global pre-Pangea plate models. The position of Laurussia relative to Gondwana prior to the amalgamation of Pangea is a major on-going controversy, with different scenarios implying distinct histories of passive margin evolution and basin formation. Models based primarily on paleomagnetic data tend to require large dextral strike-slip motions (up to 8400 km) to bring Laurussia into its Pangea configuration during the Devonian–Carboniferous Variscan Orogeny. These models of the orogeny involve multiple terranes, representing portions of present-day Spain, France and Germany, each with distinct motions, and multiple ocean basins separating them. Models more strongly biased towards honouring the juxtaposition of faunal and geological provinces, as well as geochronological data, involve more orthogonal collision during the Variscan Orogeny, and imply most or all of the European terranes remained connected to Gondwana until Pangea dispersal. We investigate these end-member models using alternative plate reconstructions that are consistent with paleomagnetic data. Strike-slip amalgamation requires Laurussian plate velocities up to 18 cm/yr, which is unreasonably high for a plate comprising a large continent, whereas orthogonal convergence implies velocities more consistent with the rules of plate tectonics. Other testable predictions from the kinematic models of each scenario are compared with geological and paleomagnetic data. Iteratively applying this approach allows us to expand the global model both in regional detail, and further back through time. Future work will extend the model back to Rodinia, and will add in complexity, such as deforming regions within a global tectonic framework. Panel_14996 Panel_14996 3:45 PM 4:05 PM
4:05 p.m.
Rapid Reservoir Modelling: Prototyping of Reservoir Models Using an Intuitive, Sketch-Based Interface
Room 501/502/503
Constructing or refining complex reservoir models is challenging and time-consuming. The lack of an intuitive set of modelling and visualization tools that allows rapid prototyping of reservoir models significantly increases the challenge. Conventional workflows, facilitated by commercially available software, have remained essentially unchanged for the past decade. These workflows are slow, requiring months from initial model concepts to flow simulation or other outputs; moreover, many model concepts, such as large scale reservoir structure and stratigraphy, become fixed early in the process and are difficult to retrospectively change, often because the model must be re-gridded if structure and/or stratigraphy change. Uncertainty is often quantified by changing rock properties assigned to grid blocks within a fixed structural and stratigraphic framework, which may significantly under-estimate, or fail to identify the true cause of, uncertainty. Traditional reservoir modelling workflows are poorly suited to rapid prototyping of a range of reservoir model concepts and testing of how these might impact on reservoir behavior. We present a new reservoir modelling approach termed Rapid Reservoir Modelling (RRM) that allows such prototyping and complements existing workflows. In RRM, all reservoir geometries that describe geological heterogeneities (e.g. faults or sedimentologic features) are modelled as discrete volumes bounded by surfaces, without reference to a predefined grid. These surfaces, and also well trajectories, are created and modified using intuitive, interactive techniques from computer visualisation, such as Sketch Based Interface Modelling (SBIM). Input data can be sourced from seismic, geocellular or flow simulation models, outcrop analogues, conceptual model libraries or blank screen. RRM outputs can be exported to conventional workflows at any stage. Meshing of the models within the RRM framework allows rapid calculation of key reservoir properties. We demonstrate the RRM workflow using a number of examples. This work allows, for the first time, application of rapid prototyping methods in reservoir modeling. Such methods are widely used in other fields of engineering design and allow improved scoping of concepts and options prior, or in addition, to detailed modelling. SBIM can be used on a range of hardware architectures, including table tops and surface PCs, fostering collaboration within integrated asset teams. Constructing or refining complex reservoir models is challenging and time-consuming. The lack of an intuitive set of modelling and visualization tools that allows rapid prototyping of reservoir models significantly increases the challenge. Conventional workflows, facilitated by commercially available software, have remained essentially unchanged for the past decade. These workflows are slow, requiring months from initial model concepts to flow simulation or other outputs; moreover, many model concepts, such as large scale reservoir structure and stratigraphy, become fixed early in the process and are difficult to retrospectively change, often because the model must be re-gridded if structure and/or stratigraphy change. Uncertainty is often quantified by changing rock properties assigned to grid blocks within a fixed structural and stratigraphic framework, which may significantly under-estimate, or fail to identify the true cause of, uncertainty. Traditional reservoir modelling workflows are poorly suited to rapid prototyping of a range of reservoir model concepts and testing of how these might impact on reservoir behavior. We present a new reservoir modelling approach termed Rapid Reservoir Modelling (RRM) that allows such prototyping and complements existing workflows. In RRM, all reservoir geometries that describe geological heterogeneities (e.g. faults or sedimentologic features) are modelled as discrete volumes bounded by surfaces, without reference to a predefined grid. These surfaces, and also well trajectories, are created and modified using intuitive, interactive techniques from computer visualisation, such as Sketch Based Interface Modelling (SBIM). Input data can be sourced from seismic, geocellular or flow simulation models, outcrop analogues, conceptual model libraries or blank screen. RRM outputs can be exported to conventional workflows at any stage. Meshing of the models within the RRM framework allows rapid calculation of key reservoir properties. We demonstrate the RRM workflow using a number of examples. This work allows, for the first time, application of rapid prototyping methods in reservoir modeling. Such methods are widely used in other fields of engineering design and allow improved scoping of concepts and options prior, or in addition, to detailed modelling. SBIM can be used on a range of hardware architectures, including table tops and surface PCs, fostering collaboration within integrated asset teams. Panel_14994 Panel_14994 4:05 PM 4:25 PM
4:25 p.m.
Advanced Workflows for Integration of Multiscale Data and Realistic Geological Modeling
Room 501/502/503
Numerical geological modeling classically uses different geostatistical techniques, which face two conflicting objectives: to make the model more geological from a descriptive point of view and to make it consistent with all available data. As it is well known, the more realistic the model, the more difficult the integration of data. Exploratory efforts are ongoing at IFPEN about the development of geostatistical methods to simulate models respecting constraints originating from seismic or from genetic modeling to obtain more realistic geological distributions of heterogeneities and provide more realistic images of the subsurface geological complexity. This paper focuses on three specific methods and workflows developed to generate geological models with an improved geological flavor and that respect the well and geological and seismic data characterizing the studied area. A first powerful approach is based upon the non-stationary plurigaussian simulation method. The non-stationary context through the computation of the 3D probability distributions of facies proportions offers numerous possibilities to use conceptual geological data and seismic derived information and to obtain at the end realistic geological models. A second method investigates the potential of the Bayesian sequential simulation. Recent developments have been proposed to extend this method to media including distinct facies. We suggest an improved variant to better account for the resolution differences between sonic logs and seismic data. This yields a more robust framework to integrate seismic data. A third innovative approach reconciles geostatistical multipoint simulation with texture synthesis principles. Geostatistical multipoint methods provide models, which better reproduce complex geological features. However, they still call for significant computation times. On the other hand, texture synthesis has been developed for computer graphics: it can help reduce computation time, but it does not account for data. We then envision a hybrid multiscale algorithm with improved computation performances and yet able to respect data and promising in terms of geological realism Numerical geological modeling classically uses different geostatistical techniques, which face two conflicting objectives: to make the model more geological from a descriptive point of view and to make it consistent with all available data. As it is well known, the more realistic the model, the more difficult the integration of data. Exploratory efforts are ongoing at IFPEN about the development of geostatistical methods to simulate models respecting constraints originating from seismic or from genetic modeling to obtain more realistic geological distributions of heterogeneities and provide more realistic images of the subsurface geological complexity. This paper focuses on three specific methods and workflows developed to generate geological models with an improved geological flavor and that respect the well and geological and seismic data characterizing the studied area. A first powerful approach is based upon the non-stationary plurigaussian simulation method. The non-stationary context through the computation of the 3D probability distributions of facies proportions offers numerous possibilities to use conceptual geological data and seismic derived information and to obtain at the end realistic geological models. A second method investigates the potential of the Bayesian sequential simulation. Recent developments have been proposed to extend this method to media including distinct facies. We suggest an improved variant to better account for the resolution differences between sonic logs and seismic data. This yields a more robust framework to integrate seismic data. A third innovative approach reconciles geostatistical multipoint simulation with texture synthesis principles. Geostatistical multipoint methods provide models, which better reproduce complex geological features. However, they still call for significant computation times. On the other hand, texture synthesis has been developed for computer graphics: it can help reduce computation time, but it does not account for data. We then envision a hybrid multiscale algorithm with improved computation performances and yet able to respect data and promising in terms of geological realism Panel_14991 Panel_14991 4:25 PM 4:45 PM
4:45 p.m.
Elastic Dislocation Modelling and Coulomb Stress Change Investigations
Room 501/502/503
Elastic Dislocation modelling based on angular dislocation theory is able to predict displacement fields and the distribution of strain in a poroelastic medium for any slip introduced on a discrete fault. Assuming linear elasticity, the magnitude and distribution of fault-induced stresses can then be calculated and following on from this, the Coulomb stress changes in the surrounding rock can be determined from shear and normal stresses acting upon fractures. In addition, a key application of Coulomb stress change is the ability to determine optimal fracture orientations. Outputs from elastic dislocation and Coulomb stress change modelling have numerous applications for hydrocarbon exploration and production, but a key driver for this new development is the ability to model lateral variation of mechanical properties, such as elastic moduli, strength, and friction. Lateral variations in mechanical properties have not been considered in any of the currently available software packages. For the first time, users have the ability to laterally vary mechanical properties, such as Poisson’s ratio, Young’s modulus and friction, allowing natural lithological variations to influence the calculation of various stress attributes. We will present details on how Elastic Dislocation Modelling and Coulomb stress change calculations have been implemented in Midland Valley’s Move™ software. The new module, called Fault Response Modelling, has been specifically designed to offer this higher degree of freedom. Additionally, the user can use two different friction models in the calculation: (1) an apparent frictional model, and (2) a pore pressure responsive model. The application and potential limitations of these two friction models to geological problems relevant to hydrocarbon exploration and production will be discussed using a combination of illustrative examples and case studies. Significantly, the calculations for optimally oriented fracture planes are based on a general tensor description, which allows users to consider any slip direction and an opening or closing component. Various other stress attributes, including slip tendency, fracture stability and retention capacity can then be calculated for these fractures to assess which fractures are likely to fail in the stress field and potentially act as fluid pathways. Elastic Dislocation modelling based on angular dislocation theory is able to predict displacement fields and the distribution of strain in a poroelastic medium for any slip introduced on a discrete fault. Assuming linear elasticity, the magnitude and distribution of fault-induced stresses can then be calculated and following on from this, the Coulomb stress changes in the surrounding rock can be determined from shear and normal stresses acting upon fractures. In addition, a key application of Coulomb stress change is the ability to determine optimal fracture orientations. Outputs from elastic dislocation and Coulomb stress change modelling have numerous applications for hydrocarbon exploration and production, but a key driver for this new development is the ability to model lateral variation of mechanical properties, such as elastic moduli, strength, and friction. Lateral variations in mechanical properties have not been considered in any of the currently available software packages. For the first time, users have the ability to laterally vary mechanical properties, such as Poisson’s ratio, Young’s modulus and friction, allowing natural lithological variations to influence the calculation of various stress attributes. We will present details on how Elastic Dislocation Modelling and Coulomb stress change calculations have been implemented in Midland Valley’s Move™ software. The new module, called Fault Response Modelling, has been specifically designed to offer this higher degree of freedom. Additionally, the user can use two different friction models in the calculation: (1) an apparent frictional model, and (2) a pore pressure responsive model. The application and potential limitations of these two friction models to geological problems relevant to hydrocarbon exploration and production will be discussed using a combination of illustrative examples and case studies. Significantly, the calculations for optimally oriented fracture planes are based on a general tensor description, which allows users to consider any slip direction and an opening or closing component. Various other stress attributes, including slip tendency, fracture stability and retention capacity can then be calculated for these fractures to assess which fractures are likely to fail in the stress field and potentially act as fluid pathways. Panel_14990 Panel_14990 4:45 PM 5:05 PM

1:15 p.m.–5:05 p.m.
Theme 1: Emerging International Unconventional Plays (AAPG/EMD)
Room 505/506/507, Monday Oral Sessions, 01 June, 2015

Panel_14426 Panel_14426 1:15 PM 5:05 PM
1:15 p.m.
Introductory Remarks
Room 505/506/507
Panel_15752 Panel_15752 1:15 PM 12:00 AM
1:20 p.m.
Unravelling Paradigms in Vaca Muerta Formation, Neuquén Basin, Argentina: The Construction of Geochemical Wellbore Images by Geostatistical Integration of Geochemistry and Conventional Log Data With Wellbore Resistivity Images
Room 505/506/507
In this article the problem of paradigm change in the study of unconventional reservoirs is analyzed. A paradigm change involves not only a deconstruction process of category analysis, but also an intellectual and collective effort of scientific community of the whole local oil industry. The ways to do that are rethinking old techniques, incorporating new ones, combining like elements differently, and adding contributions from other disciplines. We describe a methodology based on the geostatistical integration of organic geochemical (TOC content) and inorganic geochemical data (major and trace element concentration), wireline log (density log), used as hard data and resistivity wellbore image used as soft data. The integration method used was the Sequential Gaussian Simulation with Markov model Type II with hard and soft data mentioned above. Well data belongs to drilled well at Cerro Vagón block, southeast of Neuquén basin, Argentina, where Vaca Muerta Fm. has a thickness of 110 m. Chemical analysis was performed on 45 cutting samples for both organic (destructive pyrolysis analysis) and inorganic (nondestructive X Ray fluorescence analysis with rapid handheld equipment). Moreover, 18 m of core was analyzed for TOC by 12 chip samples irregularly spaced and 180 readings with nondestructive X ray fluorescence analysis, separated 10 cm from each other. As a result of the stochastic simulation process several wellbore images were obtained to a 0.2 inch of vertical resolution involving properties such as density, calcium carbonate and molybdenum concentration together with TOC content. Vaca Muerta Fm. has a pattern of molybdenum and vanadium metals that correlate with TOC and pyrite content and hence, the anoxic level of the sedimentary environment. Pyrite is very precisely evaluated by means of high correlation showed by iron and sulfur. Conventional methods for TOC thickness evaluation (Passey model, among others) are based on high transit time, low density and high resistivity properties of organic matter. In this case the pyrite concentration decreases the resistivity values and underestimates the real TOC thickness values. High resistivity values are related to calcium carbonate concentration which overestimates the TOC thickness as observed in wellbore images. As a conclusion, an accurate TOC thickness evaluation must be made with geochemical and wireline logs geostatistically integrated. In this article the problem of paradigm change in the study of unconventional reservoirs is analyzed. A paradigm change involves not only a deconstruction process of category analysis, but also an intellectual and collective effort of scientific community of the whole local oil industry. The ways to do that are rethinking old techniques, incorporating new ones, combining like elements differently, and adding contributions from other disciplines. We describe a methodology based on the geostatistical integration of organic geochemical (TOC content) and inorganic geochemical data (major and trace element concentration), wireline log (density log), used as hard data and resistivity wellbore image used as soft data. The integration method used was the Sequential Gaussian Simulation with Markov model Type II with hard and soft data mentioned above. Well data belongs to drilled well at Cerro Vagón block, southeast of Neuquén basin, Argentina, where Vaca Muerta Fm. has a thickness of 110 m. Chemical analysis was performed on 45 cutting samples for both organic (destructive pyrolysis analysis) and inorganic (nondestructive X Ray fluorescence analysis with rapid handheld equipment). Moreover, 18 m of core was analyzed for TOC by 12 chip samples irregularly spaced and 180 readings with nondestructive X ray fluorescence analysis, separated 10 cm from each other. As a result of the stochastic simulation process several wellbore images were obtained to a 0.2 inch of vertical resolution involving properties such as density, calcium carbonate and molybdenum concentration together with TOC content. Vaca Muerta Fm. has a pattern of molybdenum and vanadium metals that correlate with TOC and pyrite content and hence, the anoxic level of the sedimentary environment. Pyrite is very precisely evaluated by means of high correlation showed by iron and sulfur. Conventional methods for TOC thickness evaluation (Passey model, among others) are based on high transit time, low density and high resistivity properties of organic matter. In this case the pyrite concentration decreases the resistivity values and underestimates the real TOC thickness values. High resistivity values are related to calcium carbonate concentration which overestimates the TOC thickness as observed in wellbore images. As a conclusion, an accurate TOC thickness evaluation must be made with geochemical and wireline logs geostatistically integrated. Panel_14916 Panel_14916 1:20 PM 1:40 PM
1:40 p.m.
Unconventional Reservoir Potential of the Brown Shale, Central Sumatra Basin, Indonesia From Outcrop Characterization
Room 505/506/507
The Brown Shale (Pematang Group) is an Eocene-Oligocene sequence of lacustrine mudstones deposited in the Central Sumatra basin. It is the major and aerially extensive hydrocarbon oil and gas source rock for shallower reservoirs in Central Sumatra. The objective of this research was to characterize the Brown Shale from an unconventional resource perspective; to do this, an outcrop located inside the Karbindo Coal Mine in Central Sumatra Island was studied. The outcrop is a 220m stratigraphic section of the Brown Shale sitting atop 18+m of mineable coal. An outcrop gamma-ray profile was acquired for the complete section in addition to measured sections and rock sample descriptions. Ten facies (A to J) were described in the Karbindo Coal Mine succession. The Brown Shale section is dominated by calcareous mudstone, calcareous shale and claystone, with some very thin beds of siltstone and sandstone. Mudstones are divided into two main groups: massive and lenticular laminated. TOC values range from 2.51% to 8.56% which are indicative of very good to excellent potential source rock for hydrocarbons. Measured Vitrinite Reflectance in the coal underneath the Brown Shale section is 0.63% which places this section in the early oil window. Tmax, Hydrogen Index and Oxygen Index values are characteristic of Type I (lacustrine - oil prone) kerogen with relatively small input of Type III (terrestrial - gas prone) kerogen. Four depositional stratigraphic cycles (or sequences) were interpreted in the Brown Shale section. Cycle #1 corresponds to Balanced-Fill lake type, Cycles #3 and #4 correspond to Overfilled lake type, and Cycle #2 corresponds to the transition between these two lake types. Each sequence is composed of an early transgressive package and an overlying late regressive package. Based on geological and geochemical data, the Brown Shale Formation is a good prospect for unconventional development (horizontal drilling and fracking) in the subsurface. The recommended target zone is a 20m stratigraphic interval within Cycle #2. This section is represented by the brittle-ductile couplet associated with the transition between the balanced-fill and the overfill lake deposits. The brittle zone of this sequence is associated with the high content of quartz and calcite and low content of clay. The underlying and overlying ductile zones are rich in TOC; especially the overlying zone that contain the highest TOC value in the entire section. The Brown Shale (Pematang Group) is an Eocene-Oligocene sequence of lacustrine mudstones deposited in the Central Sumatra basin. It is the major and aerially extensive hydrocarbon oil and gas source rock for shallower reservoirs in Central Sumatra. The objective of this research was to characterize the Brown Shale from an unconventional resource perspective; to do this, an outcrop located inside the Karbindo Coal Mine in Central Sumatra Island was studied. The outcrop is a 220m stratigraphic section of the Brown Shale sitting atop 18+m of mineable coal. An outcrop gamma-ray profile was acquired for the complete section in addition to measured sections and rock sample descriptions. Ten facies (A to J) were described in the Karbindo Coal Mine succession. The Brown Shale section is dominated by calcareous mudstone, calcareous shale and claystone, with some very thin beds of siltstone and sandstone. Mudstones are divided into two main groups: massive and lenticular laminated. TOC values range from 2.51% to 8.56% which are indicative of very good to excellent potential source rock for hydrocarbons. Measured Vitrinite Reflectance in the coal underneath the Brown Shale section is 0.63% which places this section in the early oil window. Tmax, Hydrogen Index and Oxygen Index values are characteristic of Type I (lacustrine - oil prone) kerogen with relatively small input of Type III (terrestrial - gas prone) kerogen. Four depositional stratigraphic cycles (or sequences) were interpreted in the Brown Shale section. Cycle #1 corresponds to Balanced-Fill lake type, Cycles #3 and #4 correspond to Overfilled lake type, and Cycle #2 corresponds to the transition between these two lake types. Each sequence is composed of an early transgressive package and an overlying late regressive package. Based on geological and geochemical data, the Brown Shale Formation is a good prospect for unconventional development (horizontal drilling and fracking) in the subsurface. The recommended target zone is a 20m stratigraphic interval within Cycle #2. This section is represented by the brittle-ductile couplet associated with the transition between the balanced-fill and the overfill lake deposits. The brittle zone of this sequence is associated with the high content of quartz and calcite and low content of clay. The underlying and overlying ductile zones are rich in TOC; especially the overlying zone that contain the highest TOC value in the entire section. Panel_14913 Panel_14913 1:40 PM 2:00 PM
2:00 p.m.
Acoustic Properties of Unconventional Mineral Combinations From the Vaca Muerta Formation, Neuquén Basin, Argentina
Room 505/506/507
Successful exploitation of unconventional reservoirs requires its reservoir zones to be brittle, porous, and rich in kerogen. Modeling results show that an increasing clay and/or kerogen content, or increasing porosity, will decrease the rocks brittleness. We evaluate the usefulness of forward modeling of rock brittleness using unconventional mineral combinations. Initial model validation is based on samples collected from the Vaca Muerta Formation in Neuquen, Argentina. In addition to porosity and permeability, acoustic properties were measured for all plug samples at a nominal frequency of 1MHz. Carbonate content was determined by crushing part of the sample and dissolving the carbonate portion using 10% hydrochloric acid. Total Organic Carbon (TOC) content was measured on the remaining material using an Elemental Analyzer. The measured acoustic data of mudstone samples from the Vaca Muerta Formation is compared to other mixed siliciclastic samples from the Neuquen Basin, shaley Fontainebleau Sandstone, and clean carbonates from different ages and locations. The Vaca Muerta mudstones show substantially lower compressional and shear velocities than all the other data. To properly capture the influence of clay and kerogen on mechanical rock properties, we calculate mechanical rock properties using a rock physics model and then validate the model using sample measurements. Acoustic measurements of Vaca Muerta outcrop samples support the conclusions derived from forward modeling. Outcrop samples also suggest that if sufficient thickness and lateral homogeneity is present, seismic delineation of brittle and/or clay/kerogen-rich zones is feasible. Gassmann fluid substitution is an important tool in many exploration efforts and is assumed to only work properly in microscopically homogeneous rocks. Clay-rich heterogeneous rocks are thought to be non-compliant with Gassmann’s theory. The Vaca Muerta Formation, although considered unconventional, shows generally much less clay content then many other unconventional reservoirs. To evaluate Gassmann applicability, we compare measured brine saturated velocities with velocities calculated using dry measurements and Gassmann fluid substitution. The results suggest that Vaca Muerta outcrop samples are homogenous enough to comply with Gassmann’s Theory. Successful exploitation of unconventional reservoirs requires its reservoir zones to be brittle, porous, and rich in kerogen. Modeling results show that an increasing clay and/or kerogen content, or increasing porosity, will decrease the rocks brittleness. We evaluate the usefulness of forward modeling of rock brittleness using unconventional mineral combinations. Initial model validation is based on samples collected from the Vaca Muerta Formation in Neuquen, Argentina. In addition to porosity and permeability, acoustic properties were measured for all plug samples at a nominal frequency of 1MHz. Carbonate content was determined by crushing part of the sample and dissolving the carbonate portion using 10% hydrochloric acid. Total Organic Carbon (TOC) content was measured on the remaining material using an Elemental Analyzer. The measured acoustic data of mudstone samples from the Vaca Muerta Formation is compared to other mixed siliciclastic samples from the Neuquen Basin, shaley Fontainebleau Sandstone, and clean carbonates from different ages and locations. The Vaca Muerta mudstones show substantially lower compressional and shear velocities than all the other data. To properly capture the influence of clay and kerogen on mechanical rock properties, we calculate mechanical rock properties using a rock physics model and then validate the model using sample measurements. Acoustic measurements of Vaca Muerta outcrop samples support the conclusions derived from forward modeling. Outcrop samples also suggest that if sufficient thickness and lateral homogeneity is present, seismic delineation of brittle and/or clay/kerogen-rich zones is feasible. Gassmann fluid substitution is an important tool in many exploration efforts and is assumed to only work properly in microscopically homogeneous rocks. Clay-rich heterogeneous rocks are thought to be non-compliant with Gassmann’s theory. The Vaca Muerta Formation, although considered unconventional, shows generally much less clay content then many other unconventional reservoirs. To evaluate Gassmann applicability, we compare measured brine saturated velocities with velocities calculated using dry measurements and Gassmann fluid substitution. The results suggest that Vaca Muerta outcrop samples are homogenous enough to comply with Gassmann’s Theory. Panel_14912 Panel_14912 2:00 PM 2:20 PM
2:20 p.m.
Potential Shale Plays in Sub-Andean Basins of Peru
Room 505/506/507
The proven resources of shale plays in Argentina (Tithonian-Berriasian Vaca Muerta Fm.), positive early exploratory assessments in Bolivia, Brazil, Colombia and Venezuela, and evidence of gas shows in shales of Ucayali Basin (Devonian Cabanillas Fm.) increase the exploration chances in the Sub-Andean Basins of Peru. Based on geological and geochemical keys this study discusses Peru’s potential for shale plays exploration. Madre de Dios Basin is characterized by the presence of three organic-rich shales. Devonian Cabanillas shales (TOC: 1.6–3.8 wt%; kerogen types II/III and III; Ro: 0.64–3.8%; thickness: 100–600 m.), Permian Shinai shales (TOC: 2.5–5.6 wt%; kerogen types II and II/III; thickness: 70–100 m.) and Carboniferous Ambo shales (TOC: 2.3–25 wt%; Ro: 0.4 – 0.76%; kerogen type III; thickness: 100–200 m.). Marañon Basin is characterized by the presence of five organic-rich shales. Cabanillas shales in the SE part of the basin (TOC: 0.79–4.70 wt%; kerogen types II and III; Ro: 1.11–1.35%; thickness: 185–430 m.), Carboniferous Tarma shales in the southern basin (TOC: 1.05–1.65 wt%; kerogen type II/III; Ro: 1.1–1.45%; thickness: 18–254 m.) and Triassic-Jurassic Aramachay shales (TOC: 2–14 wt%; kerogen type II; Ro: 0.67–0.89%; thickness: 350–600 m). Cretaceous Chonta shales (TOC: 0.98–6.00 wt%; kerogen types II and II/III; Ro: 0.45–0.95%) have variable thickness and Oligocene Pozo shales (TOC: 0.5–3.5 wt%; kerogen types I and II) have a widespread areal distribution and variable thickness (50–200 m.). Ucayali Basin is characterized by the presence of five organic-rich shales. Ordovician Contaya shales (TOC: 0.46–2.65 wt%; kerogen type II/III?; Ro: 0.78–3.7%), Cabanillas shales (TOC: 0.65–2.34 wt%; kerogen types II and II/III; Ro: 0.84–2.18%; thickness: 200–1000 m.), Shinai shales (TOC: 1.5–4.0 wt%; kerogen types I/II, II and II/III; Ro: 0.56–1.05%; thickness: 70–100 m.), and Aramachay shales (TOC: 0.53–2.96 wt%; original kerogen was type II, Ro: 0.58–1.40%; thickness: 50–150 m.). Finally Ambo shales (TOC: 0.6–9.0 wt%; kerogen types II/III and III; Ro: 0.77–1.96%; thickness: 25–515m.), have widespread and patchy areal distribution in southern and northern basin respectively. These preliminary results suggest very favourable shale gas potential for three shale units within Madre de Dios Basin and also for five shale units within Ucayali Basin; and in the other hand indicate favourable shale oil/gas potential for five shale units within Marañon Basin. The proven resources of shale plays in Argentina (Tithonian-Berriasian Vaca Muerta Fm.), positive early exploratory assessments in Bolivia, Brazil, Colombia and Venezuela, and evidence of gas shows in shales of Ucayali Basin (Devonian Cabanillas Fm.) increase the exploration chances in the Sub-Andean Basins of Peru. Based on geological and geochemical keys this study discusses Peru’s potential for shale plays exploration. Madre de Dios Basin is characterized by the presence of three organic-rich shales. Devonian Cabanillas shales (TOC: 1.6–3.8 wt%; kerogen types II/III and III; Ro: 0.64–3.8%; thickness: 100–600 m.), Permian Shinai shales (TOC: 2.5–5.6 wt%; kerogen types II and II/III; thickness: 70–100 m.) and Carboniferous Ambo shales (TOC: 2.3–25 wt%; Ro: 0.4 – 0.76%; kerogen type III; thickness: 100–200 m.). Marañon Basin is characterized by the presence of five organic-rich shales. Cabanillas shales in the SE part of the basin (TOC: 0.79–4.70 wt%; kerogen types II and III; Ro: 1.11–1.35%; thickness: 185–430 m.), Carboniferous Tarma shales in the southern basin (TOC: 1.05–1.65 wt%; kerogen type II/III; Ro: 1.1–1.45%; thickness: 18–254 m.) and Triassic-Jurassic Aramachay shales (TOC: 2–14 wt%; kerogen type II; Ro: 0.67–0.89%; thickness: 350–600 m). Cretaceous Chonta shales (TOC: 0.98–6.00 wt%; kerogen types II and II/III; Ro: 0.45–0.95%) have variable thickness and Oligocene Pozo shales (TOC: 0.5–3.5 wt%; kerogen types I and II) have a widespread areal distribution and variable thickness (50–200 m.). Ucayali Basin is characterized by the presence of five organic-rich shales. Ordovician Contaya shales (TOC: 0.46–2.65 wt%; kerogen type II/III?; Ro: 0.78–3.7%), Cabanillas shales (TOC: 0.65–2.34 wt%; kerogen types II and II/III; Ro: 0.84–2.18%; thickness: 200–1000 m.), Shinai shales (TOC: 1.5–4.0 wt%; kerogen types I/II, II and II/III; Ro: 0.56–1.05%; thickness: 70–100 m.), and Aramachay shales (TOC: 0.53–2.96 wt%; original kerogen was type II, Ro: 0.58–1.40%; thickness: 50–150 m.). Finally Ambo shales (TOC: 0.6–9.0 wt%; kerogen types II/III and III; Ro: 0.77–1.96%; thickness: 25–515m.), have widespread and patchy areal distribution in southern and northern basin respectively. These preliminary results suggest very favourable shale gas potential for three shale units within Madre de Dios Basin and also for five shale units within Ucayali Basin; and in the other hand indicate favourable shale oil/gas potential for five shale units within Marañon Basin. Panel_14915 Panel_14915 2:20 PM 2:40 PM
2:40 p.m.
Break
Room 505/506/507
Panel_15753 Panel_15753 2:40 PM 12:00 AM
3:25 p.m.
Unconventional Petroleum System of the Lower Paleozoic Baltic Basin — Insight From the Regional High-Effort Seismic Data and Integrated Geological-Geophysical Analysis
Room 505/506/507
The Baltic Basin of northern Poland forms part of the broader Lower Paleozoic basin that developed above the southwestern edge of the East European Craton. The prospective unconventional shale reservoirs identified within the Baltic Basin are connected with the Upper Cambrian (Furongian) Piasnica formation, Upper Ordovician (Caradoc) Sasino formation and Lower Silurian (Llandovery) Paslek formation. All of these targets are located within the wet-to-dry gas and liquid windows. The Baltic Basin also contains a conventional exploration target - Upper Cambrian sandstones that are connected to onshore and offshore oil production. The Baltic Basin unconventional potential was assessed utilizing high resolution regional seismic reflection lines (PolandSPAN project) calibrated by deep legacy research wells and new recently-drilled shale gas wells. The Cambrian - Ordovician succession was deposited above the Baltica passive margin. Some extensional control on the regional depositional pattern might be inferred as minor thickness changes can be observed across some of the basement faults. The Silurian succession was deposited within the foreland flexural basin that developed due to the continental collision and formation of the Caledonian thrust belt. Deposition within the Caledonian foreland basin was dominated by fine-grained organic rich shales deposited in the distal foredeep basin. Seismically-defined depositional architecture was used to for the quantitative reconstruction of particular stages of development of the Silurian foreland basin. Maximum burial depth of the Ordovician and Silurian source rock was estimated as minimum 5 – 6 km in the southwestern part of the basin and 3 – 4 km in the northeastern part of the basin. Regional seismic data has also imaged fault pattern that may have formed due to the flexural extension triggered by continental collision. Some of these faults have been reactivated as reverse faults in the Late Paleozoic, and then again as normal faults in the Late Triassic. High resolution seismic imaging at the reservoir level allowed a very detailed stratigraphic interpretation to be performed. Rock physics and mechanical models were built at the well locations and used to predict lithology, TOC and mechanical property changes away from known wells utilizing calibrated seismic inversion results. The basin model was then updated with the new information and high resolution maps were generated for subsequent prospect ranking. The Baltic Basin of northern Poland forms part of the broader Lower Paleozoic basin that developed above the southwestern edge of the East European Craton. The prospective unconventional shale reservoirs identified within the Baltic Basin are connected with the Upper Cambrian (Furongian) Piasnica formation, Upper Ordovician (Caradoc) Sasino formation and Lower Silurian (Llandovery) Paslek formation. All of these targets are located within the wet-to-dry gas and liquid windows. The Baltic Basin also contains a conventional exploration target - Upper Cambrian sandstones that are connected to onshore and offshore oil production. The Baltic Basin unconventional potential was assessed utilizing high resolution regional seismic reflection lines (PolandSPAN project) calibrated by deep legacy research wells and new recently-drilled shale gas wells. The Cambrian - Ordovician succession was deposited above the Baltica passive margin. Some extensional control on the regional depositional pattern might be inferred as minor thickness changes can be observed across some of the basement faults. The Silurian succession was deposited within the foreland flexural basin that developed due to the continental collision and formation of the Caledonian thrust belt. Deposition within the Caledonian foreland basin was dominated by fine-grained organic rich shales deposited in the distal foredeep basin. Seismically-defined depositional architecture was used to for the quantitative reconstruction of particular stages of development of the Silurian foreland basin. Maximum burial depth of the Ordovician and Silurian source rock was estimated as minimum 5 – 6 km in the southwestern part of the basin and 3 – 4 km in the northeastern part of the basin. Regional seismic data has also imaged fault pattern that may have formed due to the flexural extension triggered by continental collision. Some of these faults have been reactivated as reverse faults in the Late Paleozoic, and then again as normal faults in the Late Triassic. High resolution seismic imaging at the reservoir level allowed a very detailed stratigraphic interpretation to be performed. Rock physics and mechanical models were built at the well locations and used to predict lithology, TOC and mechanical property changes away from known wells utilizing calibrated seismic inversion results. The basin model was then updated with the new information and high resolution maps were generated for subsequent prospect ranking. Panel_14914 Panel_14914 3:25 PM 3:45 PM
3:45 p.m.
Unconventional Resources Assessment of La Luna Formation in the Middle Magdalena Valley Basin, Colombia
Room 505/506/507
La Luna Formation, a Cretaceous sequence in the Middle Magdelana Valley basin (MMVB) of Colombia, is described as calcareous shales and limestones, black in color, with high foraminifera (Globigerina) content, and with calcareous and phosphate concretions. Formation members are named Galembo (calcareous shales with limestone layers and nodules), Pujamana (claystone, mudstone, gray shale and cherts) and Salada (black shales, black mudstones, black calcareous claystone, black limestone layers and concretions with pyrite). The total organic carbon (TOC) values for Galembo range from 1.09% to 11.90% and for Salada from 2.15% to 11.90 with Type IIS kerogen. Liquid hydrocarbons would be present in the northern and central part of MMVB, and condensates and dry/wet gases are related to the southern MMVB areas. Biomarker analyses reveal variations in redox and predominant marine organic matter deposited under anoxic and high water salinity conditions. The average SEM total area porosity for Galembo is 8.5% and 8.11% for Salada members. The depositional environment is shallow marine, restricted middle shelf. Four major third order stratigraphic cycles corresponding to the three La Luna Formation members are proposed during an overall sea level rise towards the La Luna Formation top. This primary assessment indicates a good potential for a shale oil/gas system, where good organic matter content is present, the formation reached maturity levels for hydrocarbon generation and has relatively high porosity for oil and/or gas storage. The thicknesses in outcrop vary from 180-720 ft. for Galembo, 300-400 ft. for Salada and 500 ft. for the transitional Pujamana member. La Luna Formation, a Cretaceous sequence in the Middle Magdelana Valley basin (MMVB) of Colombia, is described as calcareous shales and limestones, black in color, with high foraminifera (Globigerina) content, and with calcareous and phosphate concretions. Formation members are named Galembo (calcareous shales with limestone layers and nodules), Pujamana (claystone, mudstone, gray shale and cherts) and Salada (black shales, black mudstones, black calcareous claystone, black limestone layers and concretions with pyrite). The total organic carbon (TOC) values for Galembo range from 1.09% to 11.90% and for Salada from 2.15% to 11.90 with Type IIS kerogen. Liquid hydrocarbons would be present in the northern and central part of MMVB, and condensates and dry/wet gases are related to the southern MMVB areas. Biomarker analyses reveal variations in redox and predominant marine organic matter deposited under anoxic and high water salinity conditions. The average SEM total area porosity for Galembo is 8.5% and 8.11% for Salada members. The depositional environment is shallow marine, restricted middle shelf. Four major third order stratigraphic cycles corresponding to the three La Luna Formation members are proposed during an overall sea level rise towards the La Luna Formation top. This primary assessment indicates a good potential for a shale oil/gas system, where good organic matter content is present, the formation reached maturity levels for hydrocarbon generation and has relatively high porosity for oil and/or gas storage. The thicknesses in outcrop vary from 180-720 ft. for Galembo, 300-400 ft. for Salada and 500 ft. for the transitional Pujamana member. Panel_14968 Panel_14968 3:45 PM 4:05 PM
4:05 p.m.
Potential Cretaceous Shale Plays in Talara and Sechura Basins, Northwest Peru
Room 505/506/507
The growing importance of U.S. shale gas resources is reflected in the worldwide extension of unconventional shale plays market. This fact has motivated its exploration and exploitation in South America. In Peru, industry reports have suggested that Cretaceous source rocks of Talara and Sechura Basins may be an important future resource of shale plays. For this reason, a unified biostratigraphic review of more than 40 wells was performed using micropaleontological zonations with key data from unpublished reports in order to update the Campanian and Early Maastrichtian stratigraphy from Talara and Sechura Basins, adjusting the assigned age of these units considered as source rocks. The integrated stratigraphic analysis recognized two depositional sequences of widespread distribution in the study area. Cerro La Mesa Sequence (Middle? to Upper Campanian) is comprised of Cerro La Mesa Fm.: lower (LST) and upper member (TST-HST). Redondo Sequence (Upper Campanian-Lower Maastrichtian) is comprised of Sandino Mb. (LST-TST), Tablones Fm. (TST), Redondo Fm. (TST-HST) and Montegrande Fm. (HST). TST units of the proposed sequences are consistent with maximum transgression events recognized in Northern Peru and Ecuador. The next step was an integrated geological-geochemical assessment for Cerro La Mesa (dark brown, dark gray and black shales and limestones) and Redondo formations (dark brown to gray shales) in order to identify their exploratory potential as shale plays. High average TOC: 2.08 wt % (n = 44), kerogen type II/III, OM predominantly marine, Ro values within the oil window (0.6% < Ro < 1.0%), thickness of 110’–1000’, actual drilled depth between 2400 and 10200 feet, and the heavy oil recovered in the well RC1-2XD (46 Bbls, 12.5° API); suggest that Cerro La Mesa Fm. has appropriate conditions for potential shale oil play. On the other hand, regular average TOC: 0.85% (n = 36), kerógeno type III/IV, OM that varies regionally from marine to terrestrial, Ro values within the oil window (0.6% < Ro < 1.0%) and gas window (Ro > 1.0%), thickness of 100’–1100’, actual drilled depth between 2350 and 12350 feet, and records of gas shows in the well CO1-1X; suggest that Redondo Fm. has appropriate conditions for potential shale oil-gas play. This study shows a new possibility for the investment and extraction of potential resources of unconventional hydrocarbon in the near future; and thereby increases the hydrocarbon production in Peru. The growing importance of U.S. shale gas resources is reflected in the worldwide extension of unconventional shale plays market. This fact has motivated its exploration and exploitation in South America. In Peru, industry reports have suggested that Cretaceous source rocks of Talara and Sechura Basins may be an important future resource of shale plays. For this reason, a unified biostratigraphic review of more than 40 wells was performed using micropaleontological zonations with key data from unpublished reports in order to update the Campanian and Early Maastrichtian stratigraphy from Talara and Sechura Basins, adjusting the assigned age of these units considered as source rocks. The integrated stratigraphic analysis recognized two depositional sequences of widespread distribution in the study area. Cerro La Mesa Sequence (Middle? to Upper Campanian) is comprised of Cerro La Mesa Fm.: lower (LST) and upper member (TST-HST). Redondo Sequence (Upper Campanian-Lower Maastrichtian) is comprised of Sandino Mb. (LST-TST), Tablones Fm. (TST), Redondo Fm. (TST-HST) and Montegrande Fm. (HST). TST units of the proposed sequences are consistent with maximum transgression events recognized in Northern Peru and Ecuador. The next step was an integrated geological-geochemical assessment for Cerro La Mesa (dark brown, dark gray and black shales and limestones) and Redondo formations (dark brown to gray shales) in order to identify their exploratory potential as shale plays. High average TOC: 2.08 wt % (n = 44), kerogen type II/III, OM predominantly marine, Ro values within the oil window (0.6% < Ro < 1.0%), thickness of 110’–1000’, actual drilled depth between 2400 and 10200 feet, and the heavy oil recovered in the well RC1-2XD (46 Bbls, 12.5° API); suggest that Cerro La Mesa Fm. has appropriate conditions for potential shale oil play. On the other hand, regular average TOC: 0.85% (n = 36), kerógeno type III/IV, OM that varies regionally from marine to terrestrial, Ro values within the oil window (0.6% < Ro < 1.0%) and gas window (Ro > 1.0%), thickness of 100’–1100’, actual drilled depth between 2350 and 12350 feet, and records of gas shows in the well CO1-1X; suggest that Redondo Fm. has appropriate conditions for potential shale oil-gas play. This study shows a new possibility for the investment and extraction of potential resources of unconventional hydrocarbon in the near future; and thereby increases the hydrocarbon production in Peru. Panel_14908 Panel_14908 4:05 PM 4:25 PM
4:25 p.m.
Tectonic and Environmental Factors Controlling the Distribution of Sedimentary Facies During the Cretaceous Oceanic Anoxic Events in an Epicontinental Sea: The Colombian Case
Room 505/506/507
The evolution of Cretaceous sedimentary basins in Colombia seems to have been related to the re-activation of former tectonic structures and associated to the development of proto-Caribbean and Gulf of Mexico basins. Timing of the opening of this sedimentary basin has remained difficult due to the lack of a high-resolution age controls of the sedimentary record. It has also affected our ability to identify and predict the occurrence of economically important oil and gas generating rocks and reservoirs. Here we use detailed C-, O- and Sr- chemostratigraphy and published bioestratigraphic information and U-Pb detrital zircon ages to precisely date several carbonate and black shale successions in several Colombia Cretaceous basins. Our multiproxy approach allows suggesting the opening of a major north to south epicontinental seaway, similar to the modern Black Sea; and limited by the ancestral Central Cordillera-Santa Marta massif of Colombia (to the west) and the Guyana Shield (to the east). Variations in depositional systems allow suggesting a consistent deepening of the sedimentary environments towards the south and the central part of the Colombia seaway. Our multi-pronged approach also allows identifying the occurrence of several of the Cretaceous Oceanic Anoxic Events (OAEs) in carbonate units from the northern part of this paleo-seaway, i.e. Weissert-OAE-(Palanz and Rosablanca Formations), Faraoni-(Rosablanca Formation), AOE1a-(Paja and Fomeque Formations, Cogollo Group), OAE1c-(Cogollo Group), OAE2-(Cogollo Group), OAE3-(La Luna Formation). These events are preserved in highly euxinic - organic rich “black shales” successions deposited along the deepest part of the seaway at the Middle Magdalena Valley and Cundinamarca Basin; Weiser-OAE-(Lutitas de Macanal Formation), OAE1a-(Paja Formation, Fomeque Formation), OAE1C-(San Gil Formation). Regional changes in depositional settings and sedimentary facies preserving the different Cretaceous OAEs was likely the result of the combined action of regional changes in paleogeography and tectonic regimes and changes in the physicochemical conditions of the Cretaceous seawater along the Colombian epicontinental seaway. Our results highlight the need of using multi-proxies to investigate the occurrence of conventional and unconventional oil and gas prospectus along the Colombian epicontinental seaway and the proto-Caribbean. The evolution of Cretaceous sedimentary basins in Colombia seems to have been related to the re-activation of former tectonic structures and associated to the development of proto-Caribbean and Gulf of Mexico basins. Timing of the opening of this sedimentary basin has remained difficult due to the lack of a high-resolution age controls of the sedimentary record. It has also affected our ability to identify and predict the occurrence of economically important oil and gas generating rocks and reservoirs. Here we use detailed C-, O- and Sr- chemostratigraphy and published bioestratigraphic information and U-Pb detrital zircon ages to precisely date several carbonate and black shale successions in several Colombia Cretaceous basins. Our multiproxy approach allows suggesting the opening of a major north to south epicontinental seaway, similar to the modern Black Sea; and limited by the ancestral Central Cordillera-Santa Marta massif of Colombia (to the west) and the Guyana Shield (to the east). Variations in depositional systems allow suggesting a consistent deepening of the sedimentary environments towards the south and the central part of the Colombia seaway. Our multi-pronged approach also allows identifying the occurrence of several of the Cretaceous Oceanic Anoxic Events (OAEs) in carbonate units from the northern part of this paleo-seaway, i.e. Weissert-OAE-(Palanz and Rosablanca Formations), Faraoni-(Rosablanca Formation), AOE1a-(Paja and Fomeque Formations, Cogollo Group), OAE1c-(Cogollo Group), OAE2-(Cogollo Group), OAE3-(La Luna Formation). These events are preserved in highly euxinic - organic rich “black shales” successions deposited along the deepest part of the seaway at the Middle Magdalena Valley and Cundinamarca Basin; Weiser-OAE-(Lutitas de Macanal Formation), OAE1a-(Paja Formation, Fomeque Formation), OAE1C-(San Gil Formation). Regional changes in depositional settings and sedimentary facies preserving the different Cretaceous OAEs was likely the result of the combined action of regional changes in paleogeography and tectonic regimes and changes in the physicochemical conditions of the Cretaceous seawater along the Colombian epicontinental seaway. Our results highlight the need of using multi-proxies to investigate the occurrence of conventional and unconventional oil and gas prospectus along the Colombian epicontinental seaway and the proto-Caribbean. Panel_15038 Panel_15038 4:25 PM 4:45 PM
4:45 p.m.
Tough Gas Reservoirs in Fluvial Crevasse Splay Sandstones
Room 505/506/507
The Northwest European gas province is a mature area in which the production of gas from conventional reservoirs is declining. Unconventional tough gas reservoirs in low-net-to-gross stratigraphic intervals may constitute a secondary source of fossil energy to prolong the gas supply in the future. A recent re-perforation test in a depleted well successfully produced 30 Mm3 gas from such an interval at an investment cost of only 50 k€. Production of these fine-grained, low-permeable reservoirs has so far been hampered by the economic risks related to the uncertainties in their size, shape, spatial distribution and reservoir properties. This research focusses on fluvial crevasse splay reservoir sandstone in the West Netherlands Basin, the Netherlands. The thin-bedded sandstones are abundant in floodplain mudrock intervals, but may be undetectable on gamma-ray logs and have previously been discarded as part of non-reservoir zones. Cores, when available, only provide a spatially limited view and do not allow for three-dimensional, high-resolution characterisation of such intervals. In this study, modern-day fluvial systems in the Altiplano Basin, Bolivia, and outcrops of the Cenozoic Ebro and Tremp-Graus Basins, Spain, serve to establish the reservoir architecture of crevasse splay complexes. Combined with well-log and core data, these are used to assess the reservoir potential of crevasse splay deposits as secondary reservoirs. Results show that thin-bedded sand sheets locally constitute over 50% of fluvial floodplain intervals. Individual crevasse splays have surface areas of up to several square kilometres and thicknesses ranging from centimetre to decimetre scale. Intervals of vertically-stacked and laterally-amalgamated crevasse splays reach up to several metres in thickness and form large, interconnected volumes. Despite their grain size typically not exceeding very-fine sand, subsurface core plugs show porosity values up to 15% and permeabilities ranging from 0.01 to 10 milliDarcy. Estimates of the potential gas initially in place are in the order of tens of Mm3, which makes them a potential target for tough gas production as secondary reservoirs. The Northwest European gas province is a mature area in which the production of gas from conventional reservoirs is declining. Unconventional tough gas reservoirs in low-net-to-gross stratigraphic intervals may constitute a secondary source of fossil energy to prolong the gas supply in the future. A recent re-perforation test in a depleted well successfully produced 30 Mm3 gas from such an interval at an investment cost of only 50 k€. Production of these fine-grained, low-permeable reservoirs has so far been hampered by the economic risks related to the uncertainties in their size, shape, spatial distribution and reservoir properties. This research focusses on fluvial crevasse splay reservoir sandstone in the West Netherlands Basin, the Netherlands. The thin-bedded sandstones are abundant in floodplain mudrock intervals, but may be undetectable on gamma-ray logs and have previously been discarded as part of non-reservoir zones. Cores, when available, only provide a spatially limited view and do not allow for three-dimensional, high-resolution characterisation of such intervals. In this study, modern-day fluvial systems in the Altiplano Basin, Bolivia, and outcrops of the Cenozoic Ebro and Tremp-Graus Basins, Spain, serve to establish the reservoir architecture of crevasse splay complexes. Combined with well-log and core data, these are used to assess the reservoir potential of crevasse splay deposits as secondary reservoirs. Results show that thin-bedded sand sheets locally constitute over 50% of fluvial floodplain intervals. Individual crevasse splays have surface areas of up to several square kilometres and thicknesses ranging from centimetre to decimetre scale. Intervals of vertically-stacked and laterally-amalgamated crevasse splays reach up to several metres in thickness and form large, interconnected volumes. Despite their grain size typically not exceeding very-fine sand, subsurface core plugs show porosity values up to 15% and permeabilities ranging from 0.01 to 10 milliDarcy. Estimates of the potential gas initially in place are in the order of tens of Mm3, which makes them a potential target for tough gas production as secondary reservoirs. Panel_14911 Panel_14911 4:45 PM 5:05 PM

1:15 p.m.–5:05 p.m.
Theme 7: The Petroleum System Concept in Action: Practical Applications (AAPG)
Room 601/603, Monday Oral Sessions, 01 June, 2015

Panel_14495 Panel_14495 1:15 PM 5:05 PM
1:15 p.m.
Introductory Remarks
Room 601/603
Panel_15754 Panel_15754 1:15 PM 12:00 AM
1:20 p.m.
Basin Modelling in Western Newfoundland Using Oil Seep Samples
Room 601/603
Recent drilling on the Port au Port Peninsula in western Newfoundland and the presence of oil and oil-seeps along the coast, have focused interest on the late Proterozoic Cow Head Group of the Humber Arm Allochthon as viable source rocks for petroleum. The Late Cambrian to Ordovician Green Point Formation and the more distal Northern Head Group in the Humber Arm Allochthon are type I/II source rocks with a TOC content of up to 10.35%. Hence, they are comparable to time-equivalent prolific source rock, e.g. Utica Shale, of the south Appalachians. Biomarkers from oil seeps are consistent with a Lower Paleozoic source rock. Western Newfoundland is situated at the eastern margin of the Gulf of St. Lawrence, preserving the tectonically-rich history of the northeast Canadian Appalachians, mainly represented by the Humber Arm Supergroup. Westward thrusting of the allochthon over a carbonate platform during the Taconian was overprinted by Acadian deformation shown in north northeast to south southwest trending moderately inclined folds. New Lithoprobe seismic profiles show promising inverted basins beneath the allochthon, reflecting the possibility of deeply buried high porosity carbonate successions of the St. George Group as potential oil reservoirs. The Watts Bight Formation of the St. George Group shows porosities up to 12.9%, however dolomite cement can decrease the pore space substantially. We are developing 1D and 2D models for hydrocarbon generation, expulsion and migration that are constrained by measured maturities from well and outcrops and that are consistent with structural models from seismic and field data. Modeling results will be compared to biomarker-based correlations between oils and potential source rocks. Recent drilling on the Port au Port Peninsula in western Newfoundland and the presence of oil and oil-seeps along the coast, have focused interest on the late Proterozoic Cow Head Group of the Humber Arm Allochthon as viable source rocks for petroleum. The Late Cambrian to Ordovician Green Point Formation and the more distal Northern Head Group in the Humber Arm Allochthon are type I/II source rocks with a TOC content of up to 10.35%. Hence, they are comparable to time-equivalent prolific source rock, e.g. Utica Shale, of the south Appalachians. Biomarkers from oil seeps are consistent with a Lower Paleozoic source rock. Western Newfoundland is situated at the eastern margin of the Gulf of St. Lawrence, preserving the tectonically-rich history of the northeast Canadian Appalachians, mainly represented by the Humber Arm Supergroup. Westward thrusting of the allochthon over a carbonate platform during the Taconian was overprinted by Acadian deformation shown in north northeast to south southwest trending moderately inclined folds. New Lithoprobe seismic profiles show promising inverted basins beneath the allochthon, reflecting the possibility of deeply buried high porosity carbonate successions of the St. George Group as potential oil reservoirs. The Watts Bight Formation of the St. George Group shows porosities up to 12.9%, however dolomite cement can decrease the pore space substantially. We are developing 1D and 2D models for hydrocarbon generation, expulsion and migration that are constrained by measured maturities from well and outcrops and that are consistent with structural models from seismic and field data. Modeling results will be compared to biomarker-based correlations between oils and potential source rocks. Panel_15576 Panel_15576 1:20 PM 1:40 PM
1:40 p.m.
Overpressure Development Through Time Using 4-D PVT Modeling in the Deep Anadarko Basin, Colorado, Kansas, Oklahoma and Texas
Room 601/603
A 4-D petroleum system model of the Anadarko Basin of southeast Colorado, western Kansas, northeast Texas, and Oklahoma was built to evaluate pressure development and petroleum generation, migration, and accumulation through time. This pressure-volume-temperature (PVT) model incorporates 3D Darcy flow to replicate fluid flow and pressure evolution. Modeled Mississippian and Pennsylvanian strata are currently overpressured in an area of the deep Anadarko Basin of Oklahoma and Texas. This pressure compartmentalization is mainly present in Morrowan through lower Virgilian strata. Overpressure began 305 million years ago (Ma) within the Mississippian and Pennsylvanian Morrowan layers in the 4D model. This was primarily the result of disequilibrium compaction from (1) rapid burial of strata in the deep basin through the Mississippian and Pennsylvanian, (2) internal seals that include Morrowan and Atokan mudstone lithofacies, (3) underlying and overlying seals of the Devonian-Mississippian Woodford Shale and (4) Missourian-Virgilian shales; these shales also form permeability barriers at the lateral termination of overpressured strata. Strata below the Woodford Shale were not overpressured through time, probably because sedimentation of these strata was gradual enough for pressure to equilibrate. Overpressured strata in the basin form a wedge that pinches out along the east and west boundaries and thins from south to north. Overpressure was probably enhanced as a result of oil and gas generation and expulsion from petroleum source rocks in the deep basin, as indicated by paleopressure and overpressure being enclosed within the Woodford Shale layer oil- and gas-generation boundaries. Overpressure and oil generation from the Woodford Shale was contemporaneous. A 4-D petroleum system model of the Anadarko Basin of southeast Colorado, western Kansas, northeast Texas, and Oklahoma was built to evaluate pressure development and petroleum generation, migration, and accumulation through time. This pressure-volume-temperature (PVT) model incorporates 3D Darcy flow to replicate fluid flow and pressure evolution. Modeled Mississippian and Pennsylvanian strata are currently overpressured in an area of the deep Anadarko Basin of Oklahoma and Texas. This pressure compartmentalization is mainly present in Morrowan through lower Virgilian strata. Overpressure began 305 million years ago (Ma) within the Mississippian and Pennsylvanian Morrowan layers in the 4D model. This was primarily the result of disequilibrium compaction from (1) rapid burial of strata in the deep basin through the Mississippian and Pennsylvanian, (2) internal seals that include Morrowan and Atokan mudstone lithofacies, (3) underlying and overlying seals of the Devonian-Mississippian Woodford Shale and (4) Missourian-Virgilian shales; these shales also form permeability barriers at the lateral termination of overpressured strata. Strata below the Woodford Shale were not overpressured through time, probably because sedimentation of these strata was gradual enough for pressure to equilibrate. Overpressured strata in the basin form a wedge that pinches out along the east and west boundaries and thins from south to north. Overpressure was probably enhanced as a result of oil and gas generation and expulsion from petroleum source rocks in the deep basin, as indicated by paleopressure and overpressure being enclosed within the Woodford Shale layer oil- and gas-generation boundaries. Overpressure and oil generation from the Woodford Shale was contemporaneous. Panel_15582 Panel_15582 1:40 PM 2:00 PM
2:00 p.m.
Evaluation of Geological Characteristics of the New Albany Shale as a Potential Liquids-From-Shale Play in the Illinois Basin
Room 601/603
The New Albany Shale in the Illinois Basin is a Middle and Upper Devonian to Lower Mississippian unit correlative with the Antrim Shale of the Michigan Basin and the Ohio and Marcellus Shales of the Appalachian Basin. These shale units are thought to be part of a succession deposited in response to a sea-level rise over large areas of the North American craton, and they are important targets for recent unconventional gas and oil shale developments. The New Albany Shale has been a producer of natural gas in Indiana and Kentucky for more than 150 years, and numerous studies have attempted to understand factors that control gas distribution and producibility within the unit. Even though it has been long known that most of the conventional oil found in the Illinois Basin was sourced from the New Albany Shale, little is known about the volume and distribution of liquid hydrocarbons that currently exist within this formation. Commercial and academic interest in in-situ liquid hydrocarbons in the New Albany Shale arose only recently owing to the possibility of producing oil via horizontal drilling and hydraulic fracturing. The available data on organic matter maturity of the New Albany Shale indicate that significant areas in Illinois and some in Indiana and Kentucky lie within the oil window at suitable depths and may have sealing units in place to preserve generated hydrocarbon liquids. Abundant organic matter of marine origin provides an excellent source for hydrocarbons. The presence of oil in the New Albany Shale is confirmed by oil shows, and core analyses. Finally, recent production of oil from the unit in Kentucky clearly confirms the presence of in-situ liquids. Yet, the exact amounts of in-situ hydrocarbons are unknown, and former estimates of the near absence of oil in the New Albany Shale were based on a dearth of relevant data that hindered rigorous evaluation. This presentation re-examines geological and reservoir properties of the New Albany Shale as a potential liquids-from-shale play in the Illinois basin. In addition to the previously available data, new data from recent exploratory wells in Indiana and production wells in Kentucky on organic petrology and geochemistry will be discussed to understand the hydrocarbon generative potential and quality of the generated hydrocarbons. The New Albany Shale in the Illinois Basin is a Middle and Upper Devonian to Lower Mississippian unit correlative with the Antrim Shale of the Michigan Basin and the Ohio and Marcellus Shales of the Appalachian Basin. These shale units are thought to be part of a succession deposited in response to a sea-level rise over large areas of the North American craton, and they are important targets for recent unconventional gas and oil shale developments. The New Albany Shale has been a producer of natural gas in Indiana and Kentucky for more than 150 years, and numerous studies have attempted to understand factors that control gas distribution and producibility within the unit. Even though it has been long known that most of the conventional oil found in the Illinois Basin was sourced from the New Albany Shale, little is known about the volume and distribution of liquid hydrocarbons that currently exist within this formation. Commercial and academic interest in in-situ liquid hydrocarbons in the New Albany Shale arose only recently owing to the possibility of producing oil via horizontal drilling and hydraulic fracturing. The available data on organic matter maturity of the New Albany Shale indicate that significant areas in Illinois and some in Indiana and Kentucky lie within the oil window at suitable depths and may have sealing units in place to preserve generated hydrocarbon liquids. Abundant organic matter of marine origin provides an excellent source for hydrocarbons. The presence of oil in the New Albany Shale is confirmed by oil shows, and core analyses. Finally, recent production of oil from the unit in Kentucky clearly confirms the presence of in-situ liquids. Yet, the exact amounts of in-situ hydrocarbons are unknown, and former estimates of the near absence of oil in the New Albany Shale were based on a dearth of relevant data that hindered rigorous evaluation. This presentation re-examines geological and reservoir properties of the New Albany Shale as a potential liquids-from-shale play in the Illinois basin. In addition to the previously available data, new data from recent exploratory wells in Indiana and production wells in Kentucky on organic petrology and geochemistry will be discussed to understand the hydrocarbon generative potential and quality of the generated hydrocarbons. Panel_15581 Panel_15581 2:00 PM 2:20 PM
2:20 p.m.
Beyond the Bakken, an Integrated Evaluation of Williston Basin Lodgepole/Mission Canyon, Bakken and Ordovician Petroleum Systems
Room 601/603
While the Bakken petroleum system (along with the Eagle Ford of Texas) is an established success – with both plays anecdotally displacing in excess of 2.0MM Bbl of imported oil/day, there are other opportunities for resource plays within Williston basin source rock horizons. Hydrocarbon molecular and isotopic data were integrated with source rock data to yield new insight into the Ordovician Red River and Mississippian Lodgepole/Mission Canyon petroleum systems of the Williston Basin as future resource plays and to provide greater details of the Bakken system. Using multivariate statistics, over 350 Williston Basin oils were grouped into seven families which share common sources based on genetic-specific terpane and sterane biomarkers and stable carbon isotope compositions. Ninety (90) Middle Ordovician-sourced oils were identified by their unique n-paraffin distributions due to the microorganism G. prisca, as well as having the most positive (enriched) stable carbon isotope compositions of oils from the Williston Basin. Most of these oils were produced from the Ordovician Red River Formation, and source rock evaluation of Red River cores and cuttings suggests that the Red River is also the principal source rock unit. Furthermore, another smaller set of oils contain G. prisca biomarkers but have very negative (depleted) stable carbon isotopic compositions; these oils may have been generated from shales of the Ordovician Winnipeg Group. Similarly, genetic-specific biomarker ratios and carbon isotopes of Williston Basin produced oils were used to identify three oil families derived from Mississippian carbonate source rocks. Families 2 and 3 were derived from distinct facies; Family 1 is a mixture of 2 & 3 or 2 and a Bakken input. These carbonate families differ due to algal sterane distributions and stable carbon isotopic compositions. A subset of Red River oils have mixed with Lodgepole oils. Multiple Bakken oil subfamilies were distinguished in the study, including distinct subfamilies in Montana’s Elm Coulee Field, Parshall Field and Three Forks-reservoired oils. Relative contributions of Upper and Lower Bakken source units to Middle Bakken and Three Forks production were delineated. Vitrinite reflectance equivalent values (VRE) were calculated for each of the oils in the study. This allowed prediction of in-place and migrated oil occurrences for all three petroleum systems. While the Bakken petroleum system (along with the Eagle Ford of Texas) is an established success – with both plays anecdotally displacing in excess of 2.0MM Bbl of imported oil/day, there are other opportunities for resource plays within Williston basin source rock horizons. Hydrocarbon molecular and isotopic data were integrated with source rock data to yield new insight into the Ordovician Red River and Mississippian Lodgepole/Mission Canyon petroleum systems of the Williston Basin as future resource plays and to provide greater details of the Bakken system. Using multivariate statistics, over 350 Williston Basin oils were grouped into seven families which share common sources based on genetic-specific terpane and sterane biomarkers and stable carbon isotope compositions. Ninety (90) Middle Ordovician-sourced oils were identified by their unique n-paraffin distributions due to the microorganism G. prisca, as well as having the most positive (enriched) stable carbon isotope compositions of oils from the Williston Basin. Most of these oils were produced from the Ordovician Red River Formation, and source rock evaluation of Red River cores and cuttings suggests that the Red River is also the principal source rock unit. Furthermore, another smaller set of oils contain G. prisca biomarkers but have very negative (depleted) stable carbon isotopic compositions; these oils may have been generated from shales of the Ordovician Winnipeg Group. Similarly, genetic-specific biomarker ratios and carbon isotopes of Williston Basin produced oils were used to identify three oil families derived from Mississippian carbonate source rocks. Families 2 and 3 were derived from distinct facies; Family 1 is a mixture of 2 & 3 or 2 and a Bakken input. These carbonate families differ due to algal sterane distributions and stable carbon isotopic compositions. A subset of Red River oils have mixed with Lodgepole oils. Multiple Bakken oil subfamilies were distinguished in the study, including distinct subfamilies in Montana’s Elm Coulee Field, Parshall Field and Three Forks-reservoired oils. Relative contributions of Upper and Lower Bakken source units to Middle Bakken and Three Forks production were delineated. Vitrinite reflectance equivalent values (VRE) were calculated for each of the oils in the study. This allowed prediction of in-place and migrated oil occurrences for all three petroleum systems. Panel_15578 Panel_15578 2:20 PM 2:40 PM
2:40 p.m.
Break
Room 601/603
Panel_15755 Panel_15755 2:40 PM 12:00 AM
3:25 p.m.
Geochemical Analyses of Oils in the Goudron Field, Onshore Trinidad
Room 601/603
The Goudron Field is a mature oilfield onshore southeastern Trinidad. Originally discovered in 1927, most of the wells in the field had very light oil, lighter than many of the oils produced in neighbouring fields. In addition, in wells which produced from two different zones, some found lighter oil at shallower depths, others found shallow oils to be heavier than deeper oils. Most Trinidad oils have been found to be geochemically altered, many by evaporative fractionation, others by biodegradation. Thirteen oils were collected from the field, in different geographic areas and from different depths and different producing horizons. These range from the lower to middle Pliocene Gros Morne sandstone member of the Moruga Formation to the upper Pliocene Goudron Sandstone Member of the Mayaro formation. The latter includes oils from the upper Miocene Cruse formation and the Gros Morne sands. An oil was also collected from the upper Cretaceous fractured Naparima Hill formation in a well outside the field area because of the very heavy API gravity, at 15.0 degrees. In addition five sidewall samples were collected from a newly drilled well, from all of the known producing horizons within the field area. It was suspected from the API gravity characteristics that the Goudron oils had undergone various forms of alteration, as follows: The deeper oils were residual oils, the shallower lighter oils were evaporative and the heavier shallow oils were biodegraded. It was also believed that the Cretaceous oil was either a residual oil or biodegraded or both. The goals were to determine if the oils were indeed altered and if they were, what alterations had occurred, as this could point the way to additional prospects. For example if evaporative oils were found to be the deepest in any area, it would imply that deeper residual oils were present. Or if residual oils were found without encountering shallower evaporative oils, it would mean that the evaporative oils were either lost to the surface or trapped in offset shallow reservoirs. Results of the analyses, interpretations and exploration implications are discussed. The Goudron Field is a mature oilfield onshore southeastern Trinidad. Originally discovered in 1927, most of the wells in the field had very light oil, lighter than many of the oils produced in neighbouring fields. In addition, in wells which produced from two different zones, some found lighter oil at shallower depths, others found shallow oils to be heavier than deeper oils. Most Trinidad oils have been found to be geochemically altered, many by evaporative fractionation, others by biodegradation. Thirteen oils were collected from the field, in different geographic areas and from different depths and different producing horizons. These range from the lower to middle Pliocene Gros Morne sandstone member of the Moruga Formation to the upper Pliocene Goudron Sandstone Member of the Mayaro formation. The latter includes oils from the upper Miocene Cruse formation and the Gros Morne sands. An oil was also collected from the upper Cretaceous fractured Naparima Hill formation in a well outside the field area because of the very heavy API gravity, at 15.0 degrees. In addition five sidewall samples were collected from a newly drilled well, from all of the known producing horizons within the field area. It was suspected from the API gravity characteristics that the Goudron oils had undergone various forms of alteration, as follows: The deeper oils were residual oils, the shallower lighter oils were evaporative and the heavier shallow oils were biodegraded. It was also believed that the Cretaceous oil was either a residual oil or biodegraded or both. The goals were to determine if the oils were indeed altered and if they were, what alterations had occurred, as this could point the way to additional prospects. For example if evaporative oils were found to be the deepest in any area, it would imply that deeper residual oils were present. Or if residual oils were found without encountering shallower evaporative oils, it would mean that the evaporative oils were either lost to the surface or trapped in offset shallow reservoirs. Results of the analyses, interpretations and exploration implications are discussed. Panel_15580 Panel_15580 3:25 PM 3:45 PM
3:45 p.m.
Microfracture Characterization in the Lower Vaca Muerta Formation, Neuquén Basin, Argentina
Room 601/603
The Vaca Muerta Formation in the Neuquén Basin, Argentina, is an emerging resource play containing shale oil and gas in Late Jurassic to Early Cretaceous foreland basin strata. Like many black shales, it is characterized by the presence of abundant bedding-parallel microfractures within the organic-rich matrix. Sub-vertical fractures are also observed across the studied section, adding complexity to characterization of the mudrocks. The lower Vaca Muerta is composed of alternating mudstones-wackestones, bioclastic siltstones, carbonate mudstones, and bentonite facies. The mudstone-wackestone facies is characterized by an impermeable, wavy, clay-rich matrix that encompasses the kerogen grains. The concept of bedding-parallel microfracturing has been related to thermal maturation of kerogen in organic-rich black shales. Within the oil maturation window, overpressure at the lower Vaca Muerta interval is correlated with significant total organic content values (up to 10 wt%). These conditions eventually dominate the mechanical behavior of the formation. Observed microfractures are filled or partially filled with calcite cement. Thus carbon and oxygen stable isotope chemostratigraphy together with thin-section petrography aid in establishing the paragenetic sequence, and ultimately identify the origin of the aqueous and hydrocarbon fluids. In addition, microfractures may have the potential to contribute to overall effective permeability of the matrix depending on their length, aperture orientation, and connectivity to larger fractures. Thus, microfracture characterization and their relation to facies is key for identifying the sweet spots for future production. The Vaca Muerta Formation in the Neuquén Basin, Argentina, is an emerging resource play containing shale oil and gas in Late Jurassic to Early Cretaceous foreland basin strata. Like many black shales, it is characterized by the presence of abundant bedding-parallel microfractures within the organic-rich matrix. Sub-vertical fractures are also observed across the studied section, adding complexity to characterization of the mudrocks. The lower Vaca Muerta is composed of alternating mudstones-wackestones, bioclastic siltstones, carbonate mudstones, and bentonite facies. The mudstone-wackestone facies is characterized by an impermeable, wavy, clay-rich matrix that encompasses the kerogen grains. The concept of bedding-parallel microfracturing has been related to thermal maturation of kerogen in organic-rich black shales. Within the oil maturation window, overpressure at the lower Vaca Muerta interval is correlated with significant total organic content values (up to 10 wt%). These conditions eventually dominate the mechanical behavior of the formation. Observed microfractures are filled or partially filled with calcite cement. Thus carbon and oxygen stable isotope chemostratigraphy together with thin-section petrography aid in establishing the paragenetic sequence, and ultimately identify the origin of the aqueous and hydrocarbon fluids. In addition, microfractures may have the potential to contribute to overall effective permeability of the matrix depending on their length, aperture orientation, and connectivity to larger fractures. Thus, microfracture characterization and their relation to facies is key for identifying the sweet spots for future production. Panel_15579 Panel_15579 3:45 PM 4:05 PM
4:05 p.m.
Advanced Isotope Geochemistry to Increase Production From Horizontal Wells And Reservoirs
Room 601/603
The efficient and wide use of the isotope analysis has been extensively documented in the reservoir assessment and “sweet spot” identification. However, for a long while, isotope analysis could only be performed in stationary laboratory via sophisticated instruments and significant turning-around time. Until very recently the isotope analysis could be done in the field, but only methane isotope ratios could be available. In this work, we present the novel real-time isotope logging technique for methane, ethane and propane (C1, C2 and C3), and demonstrate how to enhance the “sweet spot” prediction and hydrocarbon production. Our instrument, the Gas Chromatography-InfraRed Isotope Ratio Analyzer (GC-IR2), represents the first of its kind field-deployable isotope ratio analyzer with high accuracy and precision. It is rigorously calibrated with the GC-IRMS (the isotope-ratio mass spectrometry) using standard gas. By field deployment during drilling, we analyze hydrocarbon gas carbon isotope ratios with only minimal turning-around time. We analyze gases derived from both mud gas and cuttings by using our proprietary design of isothermal grinding. All this new information can be given to producers in a standard log format along with other logging parameters. Our results from field application case studies show that the analytical capacity of our instrument makes it possible for various applications in vertical and horizontal drilling. We demonstrate examples from vertical drilling with pairs of mud-gas and cutting-gas under well-controlled experimental conditions to assess nanoporosity and permeability. We also present the usefulness of our technique to identify hydrocarbon sources for horizontal drilling using isotopes as fingerprinting. We conclude that isotope logging via GC-IR2 provides valuable and quantitative evaluation of the reservoir, and in a timely manner add critical information to the mudlogging and geosteering. Pioneering in well-site geochemistry, it makes gas isotope ratios readily and timely accessible to producers and leads to even greater returns from a project. The efficient and wide use of the isotope analysis has been extensively documented in the reservoir assessment and “sweet spot” identification. However, for a long while, isotope analysis could only be performed in stationary laboratory via sophisticated instruments and significant turning-around time. Until very recently the isotope analysis could be done in the field, but only methane isotope ratios could be available. In this work, we present the novel real-time isotope logging technique for methane, ethane and propane (C1, C2 and C3), and demonstrate how to enhance the “sweet spot” prediction and hydrocarbon production. Our instrument, the Gas Chromatography-InfraRed Isotope Ratio Analyzer (GC-IR2), represents the first of its kind field-deployable isotope ratio analyzer with high accuracy and precision. It is rigorously calibrated with the GC-IRMS (the isotope-ratio mass spectrometry) using standard gas. By field deployment during drilling, we analyze hydrocarbon gas carbon isotope ratios with only minimal turning-around time. We analyze gases derived from both mud gas and cuttings by using our proprietary design of isothermal grinding. All this new information can be given to producers in a standard log format along with other logging parameters. Our results from field application case studies show that the analytical capacity of our instrument makes it possible for various applications in vertical and horizontal drilling. We demonstrate examples from vertical drilling with pairs of mud-gas and cutting-gas under well-controlled experimental conditions to assess nanoporosity and permeability. We also present the usefulness of our technique to identify hydrocarbon sources for horizontal drilling using isotopes as fingerprinting. We conclude that isotope logging via GC-IR2 provides valuable and quantitative evaluation of the reservoir, and in a timely manner add critical information to the mudlogging and geosteering. Pioneering in well-site geochemistry, it makes gas isotope ratios readily and timely accessible to producers and leads to even greater returns from a project. Panel_15575 Panel_15575 4:05 PM 4:25 PM
4:25 p.m.
Impact of Source Maturation and Migration Dynamics on the Accumulation and Leakage of Hydrocarbons in the Bredasdorp Basin (Offshore South Africa)
Room 601/603
This study investigates the contribution of Upper Jurassic-Cretaceous source rocks to the reservoired hydrocarbons and natural gas leakage using a 3D basin modelling technique. The established 3D model is based on an integration of subsurface datasets (2D seismics, well data and cores) and links the present-day configuration and related tectonic/geodynamic evolution of the basin at a crustal scale (Sonibare et al., 2014) with the local- to regional-scale thermal histories of the Southern African continental margin. The temporal and spatial distribution of critical moment for hyrocarbon generation, migration and accumulation reveals that three periods, coinciding with the main phases of hydrocarbon generation and expulsion, characterise the reservoir filling history of the basin. The first period corresponds to the Early Cretaceous syn-rift rapid subsidence and sedimentation rates. While the second period indicates the significance of post-rift thermal subsidence and the heating effect of the Late Cretaceous-Early Tertiary hotspot-related heat flow pulse, the third period corresponds to the Miocene margin uplift and thermal perturbation. According to our results, the largest amounts of hydrocarbon accumulations and possible seafloor gas leakages are respectively contributed by the syn-rift Late Hauterivian and Mid Hauterivian source rocks. By performing a series of sensitivity tests, we further gain better insights into the timing of migration pathways and dynamics. The coupling of faulting activity, seal bridging mechanisms and facies heterogeneity predicts the best location of discovered accumulations and observed leakage indicators and thus implies our best approximation of the probable controlling factors of migration, accumulation and leakage in the basin. This study investigates the contribution of Upper Jurassic-Cretaceous source rocks to the reservoired hydrocarbons and natural gas leakage using a 3D basin modelling technique. The established 3D model is based on an integration of subsurface datasets (2D seismics, well data and cores) and links the present-day configuration and related tectonic/geodynamic evolution of the basin at a crustal scale (Sonibare et al., 2014) with the local- to regional-scale thermal histories of the Southern African continental margin. The temporal and spatial distribution of critical moment for hyrocarbon generation, migration and accumulation reveals that three periods, coinciding with the main phases of hydrocarbon generation and expulsion, characterise the reservoir filling history of the basin. The first period corresponds to the Early Cretaceous syn-rift rapid subsidence and sedimentation rates. While the second period indicates the significance of post-rift thermal subsidence and the heating effect of the Late Cretaceous-Early Tertiary hotspot-related heat flow pulse, the third period corresponds to the Miocene margin uplift and thermal perturbation. According to our results, the largest amounts of hydrocarbon accumulations and possible seafloor gas leakages are respectively contributed by the syn-rift Late Hauterivian and Mid Hauterivian source rocks. By performing a series of sensitivity tests, we further gain better insights into the timing of migration pathways and dynamics. The coupling of faulting activity, seal bridging mechanisms and facies heterogeneity predicts the best location of discovered accumulations and observed leakage indicators and thus implies our best approximation of the probable controlling factors of migration, accumulation and leakage in the basin. Panel_15577 Panel_15577 4:25 PM 4:45 PM
4:45 p.m.
Geological Controls and Computational Schemes of Shale Gas Sorption Capacity in Lower Silurian Longmaxi Formation From the Southeastern Chongqing, China
Room 601/603
High-pressure methane sorption experiments on eight Lower Silurian Longmaxi shale moisture- equilibrated samples from the Southeastern Chongqing, China, were conducted at pressure up to 20 MPa, at 20°C, 40°C, 60°C, 80°C and 100°C to investigate the effect of organic matter content, mineralogical compositions, pore structure and reservoir conditions (temperature and pressure) on the methane sorption capacity. The pore characterization of the shale samples was investigated using low pressure gas (N2 and CO2) adsorption and field emission scanning electron microscopy (FE-SEM) observation. The total organic carbon contents (TOC) range from 0.45 wt % to 4.13 wt %. The minerals of the shale samples are dominated by clays (21 - 58 wt %) and quartz (29 - 57 wt %). For the entire shale samples the dominant clay minerals are mixed layer illite/smectite and illite. Both mineral matrix and organic matter pores are well developed with pore size from several to several hundred nanometers. The pore size distributions obtained from the combination of N2 and CO2 adsorption data are bi- or multimodal. The methane sorption capacities of moisture-equilibrated shale samples show a significant positive correlation with TOC contents and BET surface areas. Not a simple linear but quadratic polynomial-law relationship was observed between the clay contents and methane sorption capacities. A threshold of clay content (42.3 – 44.4%) exists in this trend. The methane sorption capacities decline with increasing clay content under the threshold, and later increase with increasing clay content. The Langmuir pressure increases exponentially with temperature and the Langmuir volume decreases linearly with temperature. A computational scheme has been developed to calculate the methane sorption capacity of shales as a function of TOC content, temperature and pressure based on Langmuir sorption isotherm function. Using this algorithm methane sorption capacity of organic shales as function of depth was obtained. Due to the predominating effect of pressure the methane sorption capacity increase with depth initially, through a maximum and then decrease due to the influence of increasing temperature at a greater depth. The maximum gas sorption capacity typically occurs at a depth range between 800 and 1350 m. With TOC content increasing, the maximum methane sorption capacities of organic shales and the corresponding depths increase. High-pressure methane sorption experiments on eight Lower Silurian Longmaxi shale moisture- equilibrated samples from the Southeastern Chongqing, China, were conducted at pressure up to 20 MPa, at 20°C, 40°C, 60°C, 80°C and 100°C to investigate the effect of organic matter content, mineralogical compositions, pore structure and reservoir conditions (temperature and pressure) on the methane sorption capacity. The pore characterization of the shale samples was investigated using low pressure gas (N2 and CO2) adsorption and field emission scanning electron microscopy (FE-SEM) observation. The total organic carbon contents (TOC) range from 0.45 wt % to 4.13 wt %. The minerals of the shale samples are dominated by clays (21 - 58 wt %) and quartz (29 - 57 wt %). For the entire shale samples the dominant clay minerals are mixed layer illite/smectite and illite. Both mineral matrix and organic matter pores are well developed with pore size from several to several hundred nanometers. The pore size distributions obtained from the combination of N2 and CO2 adsorption data are bi- or multimodal. The methane sorption capacities of moisture-equilibrated shale samples show a significant positive correlation with TOC contents and BET surface areas. Not a simple linear but quadratic polynomial-law relationship was observed between the clay contents and methane sorption capacities. A threshold of clay content (42.3 – 44.4%) exists in this trend. The methane sorption capacities decline with increasing clay content under the threshold, and later increase with increasing clay content. The Langmuir pressure increases exponentially with temperature and the Langmuir volume decreases linearly with temperature. A computational scheme has been developed to calculate the methane sorption capacity of shales as a function of TOC content, temperature and pressure based on Langmuir sorption isotherm function. Using this algorithm methane sorption capacity of organic shales as function of depth was obtained. Due to the predominating effect of pressure the methane sorption capacity increase with depth initially, through a maximum and then decrease due to the influence of increasing temperature at a greater depth. The maximum gas sorption capacity typically occurs at a depth range between 800 and 1350 m. With TOC content increasing, the maximum methane sorption capacities of organic shales and the corresponding depths increase. Panel_15583 Panel_15583 4:45 PM 5:05 PM

1:15 p.m.–5:05 p.m.
Theme 5: New Insights From the Classics—Contraction, Extension and Strike-Slip II (AAPG/PSGD)
Room 605/607, Monday Oral Sessions, 01 June, 2015

Panel_14475 Panel_14475 1:15 PM 5:05 PM
1:15 p.m.
Introductory Remarks
Room 605/607
Panel_15756 Panel_15756 1:15 PM 12:00 AM
1:20 p.m.
3-D Fault Geometries and Interactions Associated With Multiphase Extension
Room 605/607
Many rift basins have undergone multiple episodes of extension, commonly with differing extension directions. The resultant fault patterns are complex, potentially affecting both hydrocarbon migration and entrapment. We used experimental (analog) modeling to examine the 3D fault geometries and interactions that developed during multiphase extension. In the models, a homogeneous layer of wet clay underwent two phases of extension whose directions differed by 45°. Additional clay was added after each phase of extension. To examine the deformation within the models, we created closely spaced (1 mm apart) serial sections, interpreted them, and imported our interpretations into Petrel software. The serial sections and Petrel images showed that first-phase faults (striking subperpendicular to the first-phase extension direction) were most common at the base of the models, and second-phase faults (striking subperpendicular to the second-phase extension direction) were most common at shallow levels. The attitude of many faults varied with depth, striking subperpendicuar to the first-phase extension direction near the base of the model and oblique to both extension directions at shallower levels. Displacement profiles on these faults indicated that they formed at depth during the first phase of extension. As they propagated upward during the second phase of extension, their strike rotated, becoming more optimally oriented relative to the second-phase extension direction. Additionally, the dips of these faults varied along strike. Many second-phase faults nucleated at first-phase faults and propagated upward and outward, some terminated into first-phase faults, and others cut and offset first-phase faults. The linkage of the second-phase faults with the first-phase faults created composite faults with zig-zag geometries in both cross-sectional and map views. The 3D fault patterns in the models are similar to those documented in basins that have undergone multiple phases of extension (e.g., the North Malay basin, offshore Thailand; the Taranaki basin, offshore New Zealand; the Jeanne d’Arc basin, offshore Newfoundland, Canada). Many rift basins have undergone multiple episodes of extension, commonly with differing extension directions. The resultant fault patterns are complex, potentially affecting both hydrocarbon migration and entrapment. We used experimental (analog) modeling to examine the 3D fault geometries and interactions that developed during multiphase extension. In the models, a homogeneous layer of wet clay underwent two phases of extension whose directions differed by 45°. Additional clay was added after each phase of extension. To examine the deformation within the models, we created closely spaced (1 mm apart) serial sections, interpreted them, and imported our interpretations into Petrel software. The serial sections and Petrel images showed that first-phase faults (striking subperpendicular to the first-phase extension direction) were most common at the base of the models, and second-phase faults (striking subperpendicular to the second-phase extension direction) were most common at shallow levels. The attitude of many faults varied with depth, striking subperpendicuar to the first-phase extension direction near the base of the model and oblique to both extension directions at shallower levels. Displacement profiles on these faults indicated that they formed at depth during the first phase of extension. As they propagated upward during the second phase of extension, their strike rotated, becoming more optimally oriented relative to the second-phase extension direction. Additionally, the dips of these faults varied along strike. Many second-phase faults nucleated at first-phase faults and propagated upward and outward, some terminated into first-phase faults, and others cut and offset first-phase faults. The linkage of the second-phase faults with the first-phase faults created composite faults with zig-zag geometries in both cross-sectional and map views. The 3D fault patterns in the models are similar to those documented in basins that have undergone multiple phases of extension (e.g., the North Malay basin, offshore Thailand; the Taranaki basin, offshore New Zealand; the Jeanne d’Arc basin, offshore Newfoundland, Canada). Panel_15394 Panel_15394 1:20 PM 1:40 PM
1:40 p.m.
A Tectono-Stratigraphic Development of the Albertine Graben of Uganda, Western Arm of East African Rift System Based on Sedimentary Exposures, Seismic and Well Data
Room 605/607
The Albertine Graben is a Tertiary rift system with a complex evolution history. Though it is essentially an extensional province, there is undeniable evidence of compressional tectonics. The Graben, comprises a number of structural and topographic basins, lying in a general north-easterly (NE) trend in en-echelon pattern. The basins have varying ages, younging both to the north and south. Therefore, correlation of the different Stratigraphic units from one basin to the next has been a complex task. Since Miocene, when rifting was initiated in the Albertine Graben, there has been several tectonic episodes that have shaped the geometry of the basins. The observed structural styles from seismic data, is due to a combination of (1) pre-rift basement fabric and (2) secondary modification as a result of extensional and strike-slip tectonics that has been going on since Miocene. The Albertine Graben, forms the northernmost termination of the western arm of the East African Rift System. Since Miocene, thick sediments up to 6Km in some basins have accumulated. The fault systems that comprise this rift are highly segmented, separated by relay ramps and accommodation zones which sometimes are basement highs. The graben, can be divided into three structural domains based on structural geometry and trend namely; the southern, central and northern domains. The structural elements in the southern domain trend in a NNE–SSW direction, structural elements in the central domain change to a NE–SW direction while the structural elements in the northern domain return to a NNE–SSW trend. Different stratigragraphic schemes have been developed by oil companies and researchers that have operated in Uganda. These schemes have largely been uncoordinated and gives varying ages to same sedimentary packages. The petroleum Exploration and Production Department in the Ministry of Energy and Mineral Development of the Uganda Government is coordinating a study to harmonize the different stratigraphic schemes. This paper will discuss the work that has been done to harmonize the different stratigraphic schemes using sedimentary exposures, seismic and well data that have been acquired in the Albertine Graben. The Albertine Graben is a Tertiary rift system with a complex evolution history. Though it is essentially an extensional province, there is undeniable evidence of compressional tectonics. The Graben, comprises a number of structural and topographic basins, lying in a general north-easterly (NE) trend in en-echelon pattern. The basins have varying ages, younging both to the north and south. Therefore, correlation of the different Stratigraphic units from one basin to the next has been a complex task. Since Miocene, when rifting was initiated in the Albertine Graben, there has been several tectonic episodes that have shaped the geometry of the basins. The observed structural styles from seismic data, is due to a combination of (1) pre-rift basement fabric and (2) secondary modification as a result of extensional and strike-slip tectonics that has been going on since Miocene. The Albertine Graben, forms the northernmost termination of the western arm of the East African Rift System. Since Miocene, thick sediments up to 6Km in some basins have accumulated. The fault systems that comprise this rift are highly segmented, separated by relay ramps and accommodation zones which sometimes are basement highs. The graben, can be divided into three structural domains based on structural geometry and trend namely; the southern, central and northern domains. The structural elements in the southern domain trend in a NNE–SSW direction, structural elements in the central domain change to a NE–SW direction while the structural elements in the northern domain return to a NNE–SSW trend. Different stratigragraphic schemes have been developed by oil companies and researchers that have operated in Uganda. These schemes have largely been uncoordinated and gives varying ages to same sedimentary packages. The petroleum Exploration and Production Department in the Ministry of Energy and Mineral Development of the Uganda Government is coordinating a study to harmonize the different stratigraphic schemes. This paper will discuss the work that has been done to harmonize the different stratigraphic schemes using sedimentary exposures, seismic and well data that have been acquired in the Albertine Graben. Panel_15397 Panel_15397 1:40 PM 2:00 PM
2:00 p.m.
Protracted Fault Growth and Reactivation in Multiphase Rift Basins: Structural Evolution of the East Shetland Basin, Northern North Sea
Room 605/607
Many continental rifts have experienced multiple phases of extension. However, the interaction of faults associated with the different rift phases is not fully understood due to structural overprinting and/or deep burial leading to poor data quality. Multiphase rift basins have previously been studied using physical analogue or numerical modelling, and field and subsurface analyses. These studies typically identify multiple, discrete tectonic stages: pre-, syn-, and post-rift. This simplified approach, however, does not consider the relative evolution of fault systems within a basin as a result of diachronous fault growth, both laterally and between faults. This study focuses on the East Shetland Basin (ESB), a multiphase rift basin located on the western margin of the North Viking Graben, northern North Sea. At least two extensional phases are typically recognised in the basin (Permian-Triassic and Mid-Late Jurassic), with the overall geometry of the latter rift being the result of selective reactivation of faults associated with the former rift. Between and within fault blocks, intra-rift strata gradually thicken eastwards and this geometry has led to two different interpretations: (i) this wedge documents Early-Middle Jurassic, differential thermal subsidence after the first rift event; or (ii) the wedge documents Triassic syn-depositional activity on west-dipping faults. Analysis of 2D and 3D seismic reflection and well data allow us to re-evaluate the structural evolution of the ESB. In the NW of the ESB, Permian-Triassic syn-rift deposits are observed along large (>20 km length) NE-SW striking faults, while elsewhere in the basin, Permian syn-rift deposits are capped by gradually eastward-thickening strata, suggesting a Triassic post-rift sag. Subsequent Early-to-Middle Jurassic deposits thicken across large N-S striking faults eastward, suggesting fault growth during this time and thus the onset of another rift phase. Our results challenge previous interpretations of the structural evolution of the ESB: the timing of initiation, and duration of activity of large fault systems are not consistent throughout the basin, with faults showing polyphase activity, cross-cutting relationships, and protracted growth. The results of this work highlight the complex structural evolution of multiphase rifts and demonstrate that the conventional rift package nomenclature of pre-, syn-, and post-rift does not necessarily apply to multiphase rift basins. Many continental rifts have experienced multiple phases of extension. However, the interaction of faults associated with the different rift phases is not fully understood due to structural overprinting and/or deep burial leading to poor data quality. Multiphase rift basins have previously been studied using physical analogue or numerical modelling, and field and subsurface analyses. These studies typically identify multiple, discrete tectonic stages: pre-, syn-, and post-rift. This simplified approach, however, does not consider the relative evolution of fault systems within a basin as a result of diachronous fault growth, both laterally and between faults. This study focuses on the East Shetland Basin (ESB), a multiphase rift basin located on the western margin of the North Viking Graben, northern North Sea. At least two extensional phases are typically recognised in the basin (Permian-Triassic and Mid-Late Jurassic), with the overall geometry of the latter rift being the result of selective reactivation of faults associated with the former rift. Between and within fault blocks, intra-rift strata gradually thicken eastwards and this geometry has led to two different interpretations: (i) this wedge documents Early-Middle Jurassic, differential thermal subsidence after the first rift event; or (ii) the wedge documents Triassic syn-depositional activity on west-dipping faults. Analysis of 2D and 3D seismic reflection and well data allow us to re-evaluate the structural evolution of the ESB. In the NW of the ESB, Permian-Triassic syn-rift deposits are observed along large (>20 km length) NE-SW striking faults, while elsewhere in the basin, Permian syn-rift deposits are capped by gradually eastward-thickening strata, suggesting a Triassic post-rift sag. Subsequent Early-to-Middle Jurassic deposits thicken across large N-S striking faults eastward, suggesting fault growth during this time and thus the onset of another rift phase. Our results challenge previous interpretations of the structural evolution of the ESB: the timing of initiation, and duration of activity of large fault systems are not consistent throughout the basin, with faults showing polyphase activity, cross-cutting relationships, and protracted growth. The results of this work highlight the complex structural evolution of multiphase rifts and demonstrate that the conventional rift package nomenclature of pre-, syn-, and post-rift does not necessarily apply to multiphase rift basins. Panel_15396 Panel_15396 2:00 PM 2:20 PM
2:20 p.m.
Investigating Fault Interaction and Linkage Within the Hoop Fault Complex, South Western Barents Sea, Norway
Room 605/607
This study presents a structural analysis of the Hoop Fault Complex (HFC) in the SW Barents Sea, Norway covering the area between 73°00’N, 22°00’ E and 74°30’ N, 26°30’ E. Seismic stratigraphy in 3D seismic of HFC is constrained using nearby well data and 2D seismic reflection data. Six seismic reflections were identified, namely the early Carboniferous, the late Permian, the early Triassic, the middle Triassic, the middle Jurassic and the base Cretaceous. From the time-structure map of the base Cretaceous, three seismic sections oriented at high angles to the trend of the faults were selected which represent contrasting structural configurations and are identified as a Northern (NGS), Central(CGS) and Southern (SGS) graben segment. The dominant strike of the structures is N-S (NGS) and NNE-SSW (SGS and CGS). We selected three main faults, all delineating the graben segments described above for detailed analysis and mapped throw distribution both vertically and laterally along main faults to illustrate the temporal and spatial changes in displacement distribution and sedimentation patterns to date coeval fault activity. Main faults in HFC have very distinct growth in Permian. The observations can be explained by either that isolated Carboniferous faults were reactivated and propagated up-section through evaporite layer into the Permian, forming fault scarp. This fault scarp trapped sediments, followed by nucleating younger faults affecting the Permian-Triassic. These segments propagated down-section and up-section and were hard-linked with older Carboniferous faults. The high throw is recorded in the early Permian which might be due to the sum of displacement accumulated by combined upward and downward propagation of younger faults. Alternatively faults nucleated inside the Permian-Triassic sequence and propagated radially, terminated into evaporite layer downwards. Fault linkage between shallower Cretaceous unit and Permian-Triassic is explained by that faults which nucleated in Cretaceous dip-linked to deeper sequences. Main faults in HFC were affected by multiphase rifting, but due to intervening ductile layers like evaporite and shale, strain is decoupled in area. Main events of synsedimentary fault activity were in early Permian, early Triassic, and Jurassic. Timing and evolution of main faults varies within the area and this knowledge is important, as this could impact the fluid flow. This study presents a structural analysis of the Hoop Fault Complex (HFC) in the SW Barents Sea, Norway covering the area between 73°00’N, 22°00’ E and 74°30’ N, 26°30’ E. Seismic stratigraphy in 3D seismic of HFC is constrained using nearby well data and 2D seismic reflection data. Six seismic reflections were identified, namely the early Carboniferous, the late Permian, the early Triassic, the middle Triassic, the middle Jurassic and the base Cretaceous. From the time-structure map of the base Cretaceous, three seismic sections oriented at high angles to the trend of the faults were selected which represent contrasting structural configurations and are identified as a Northern (NGS), Central(CGS) and Southern (SGS) graben segment. The dominant strike of the structures is N-S (NGS) and NNE-SSW (SGS and CGS). We selected three main faults, all delineating the graben segments described above for detailed analysis and mapped throw distribution both vertically and laterally along main faults to illustrate the temporal and spatial changes in displacement distribution and sedimentation patterns to date coeval fault activity. Main faults in HFC have very distinct growth in Permian. The observations can be explained by either that isolated Carboniferous faults were reactivated and propagated up-section through evaporite layer into the Permian, forming fault scarp. This fault scarp trapped sediments, followed by nucleating younger faults affecting the Permian-Triassic. These segments propagated down-section and up-section and were hard-linked with older Carboniferous faults. The high throw is recorded in the early Permian which might be due to the sum of displacement accumulated by combined upward and downward propagation of younger faults. Alternatively faults nucleated inside the Permian-Triassic sequence and propagated radially, terminated into evaporite layer downwards. Fault linkage between shallower Cretaceous unit and Permian-Triassic is explained by that faults which nucleated in Cretaceous dip-linked to deeper sequences. Main faults in HFC were affected by multiphase rifting, but due to intervening ductile layers like evaporite and shale, strain is decoupled in area. Main events of synsedimentary fault activity were in early Permian, early Triassic, and Jurassic. Timing and evolution of main faults varies within the area and this knowledge is important, as this could impact the fluid flow. Panel_15393 Panel_15393 2:20 PM 2:40 PM
2:40 p.m.
Break
Room 605/607
Panel_15757 Panel_15757 2:40 PM 12:00 AM
3:25 p.m.
Reconciling Contemporary Stress Data With Neotectonic Structures: A Case Study From the Otway Basin, Southeastern Australia
Room 605/607
Southeastern Australia is characterised by relatively high levels of neotectonic activity for an intraplate region. This activity comprises compressional deformation and uplift controlled by far-field plate boundary forces. Whilst the orientations of contemporary maximum horizontal stresses determined from petroleum exploration data are generally consistent with palaeostress trends inferred from neotectonic structural features, there is less consistency between stress magnitudes. The neotectonic faulting record points to a reverse fault stress regime, but studies of stress magnitudes using petroleum exploration data have mostly indicated normal or strike slip fault stress conditions. We present a new analysis of contemporary stress orientations and magnitudes in the Otway Basin, one of several basins that formed along Australia’s southern margin during Cretaceous-Paleogene continental separation from Antarctica. Wellbore failure analysis of 11 wells indicates the maximum horizontal stress azimuth is ~135°N, consistent with previous studies. Lithology, underlying structural fabrics and variations in structural style with depth exert important controls on horizontal stress magnitudes. Leak-off pressures are very high (often greater than lithostatic) in post-rift marl and carbonate-dominated formations, where neotectonic deformation is typically manifested by northeast-southwest trending, low amplitude and long wavelength folds. Within the basin there is an overall increase in the minimum horizontal stress gradient of ~1-2 MPa/km from west to east. This increase corresponds with a change in structural style. In the central Otway Basin, rift-related faults are near-parallel to the maximum horizontal stress azimuth and there are comparatively low levels of neotectonic activity, whilst in the eastern Otway Basin where rift-related faults strike near-orthogonal to the maximum horizontal stress azimuth, the level of neotectonic faulting and uplift is much higher. The observation of strike-slip fault stress regimes within syn-rift sections may be due to the underestimation of horizontal stress magnitudes interpreted from leak-off pressures. Alternatively, the partitioning of stress regimes and deformation styles with depth may reflect varying mechanical properties of the basin fill. Our results show how integrating structural and geomechanical datasets can help reconcile contemporary stress data from petroleum exploration with neotectonic geological observations. Southeastern Australia is characterised by relatively high levels of neotectonic activity for an intraplate region. This activity comprises compressional deformation and uplift controlled by far-field plate boundary forces. Whilst the orientations of contemporary maximum horizontal stresses determined from petroleum exploration data are generally consistent with palaeostress trends inferred from neotectonic structural features, there is less consistency between stress magnitudes. The neotectonic faulting record points to a reverse fault stress regime, but studies of stress magnitudes using petroleum exploration data have mostly indicated normal or strike slip fault stress conditions. We present a new analysis of contemporary stress orientations and magnitudes in the Otway Basin, one of several basins that formed along Australia’s southern margin during Cretaceous-Paleogene continental separation from Antarctica. Wellbore failure analysis of 11 wells indicates the maximum horizontal stress azimuth is ~135°N, consistent with previous studies. Lithology, underlying structural fabrics and variations in structural style with depth exert important controls on horizontal stress magnitudes. Leak-off pressures are very high (often greater than lithostatic) in post-rift marl and carbonate-dominated formations, where neotectonic deformation is typically manifested by northeast-southwest trending, low amplitude and long wavelength folds. Within the basin there is an overall increase in the minimum horizontal stress gradient of ~1-2 MPa/km from west to east. This increase corresponds with a change in structural style. In the central Otway Basin, rift-related faults are near-parallel to the maximum horizontal stress azimuth and there are comparatively low levels of neotectonic activity, whilst in the eastern Otway Basin where rift-related faults strike near-orthogonal to the maximum horizontal stress azimuth, the level of neotectonic faulting and uplift is much higher. The observation of strike-slip fault stress regimes within syn-rift sections may be due to the underestimation of horizontal stress magnitudes interpreted from leak-off pressures. Alternatively, the partitioning of stress regimes and deformation styles with depth may reflect varying mechanical properties of the basin fill. Our results show how integrating structural and geomechanical datasets can help reconcile contemporary stress data from petroleum exploration with neotectonic geological observations. Panel_15398 Panel_15398 3:25 PM 3:45 PM
3:45 p.m.
Extensional Structures in Foreland Basin Development: Insights From Northwestern Bonaparte Basin, Australia
Room 605/607
The concept and our understanding of foreland basin systems has largely advanced over the last four decades through studies focused on: 1) foreland-associated fold and thrust belts, 2) stratigraphy-driven basin evolution research, 3) rigidity and flexural profiles of lithosphere, and 4) geodynamics. In comparison, few studies have concentrated on extensional structures in these compression-dominated systems. This is probably because flexural extension is 1) a transient phase during foreland system development, 2) easily superimposed and modified by subsequent compressional structures, 3) usually covered by thick sediments of the foreland sequence, which makes the out-crop exposure limited and/or recognition in seismic challenging, and 4) accompanied by significant involvement of pre-existing fabrics. Extensional structures are crucial in understanding the early stage evolution of foreland basin development. Based on newly released industrial subsurface data, our study centers on characteristics of a Neogene normal fault system in NW Bonaparte Basin, which is the foredeep part of the underfilled Timor foreland basin. 2D regional cross-sections stretching from Timor to Australian shelf clearly document the spatial configuration of the thrust front, crustal down-warping and flexural normal faulting. Neogene normal faults developed on the Australian shelf during the crustal downwarp, with the rapid subsidence of present-day foredeep from -20m to -2500m in late Pliocene to Pleistocene. These Neogene normal faults include newly formed normal faults and reactivation of Jurassic rift-related normal faults, with their fault density gradually decreasing landward. Instant fault throw analysis on regional sections shows the along-dip variation of the normal fault activity during crustal down-warping. In Bonaparte Basin, en echelon normal fault arrays with different stepping patterns are observed in several places with different oriented underlying Jurassic structural grains, which altogether indicate a WSW–ENE Timor foreland flexural wave. In addition, based on our study and synthesis of the current understanding of Timor foreland system, we propose that 1) Neogene flexural extension in NW Bonaparte Basin is decoupled from the sinistral transpressive nature of Timor fold and thrust belt by the thrusting décollement, and 2) flexural extension of Timor foreland is mainly derived from tectonic loading and subduction, instead of lithospheric buckling. The concept and our understanding of foreland basin systems has largely advanced over the last four decades through studies focused on: 1) foreland-associated fold and thrust belts, 2) stratigraphy-driven basin evolution research, 3) rigidity and flexural profiles of lithosphere, and 4) geodynamics. In comparison, few studies have concentrated on extensional structures in these compression-dominated systems. This is probably because flexural extension is 1) a transient phase during foreland system development, 2) easily superimposed and modified by subsequent compressional structures, 3) usually covered by thick sediments of the foreland sequence, which makes the out-crop exposure limited and/or recognition in seismic challenging, and 4) accompanied by significant involvement of pre-existing fabrics. Extensional structures are crucial in understanding the early stage evolution of foreland basin development. Based on newly released industrial subsurface data, our study centers on characteristics of a Neogene normal fault system in NW Bonaparte Basin, which is the foredeep part of the underfilled Timor foreland basin. 2D regional cross-sections stretching from Timor to Australian shelf clearly document the spatial configuration of the thrust front, crustal down-warping and flexural normal faulting. Neogene normal faults developed on the Australian shelf during the crustal downwarp, with the rapid subsidence of present-day foredeep from -20m to -2500m in late Pliocene to Pleistocene. These Neogene normal faults include newly formed normal faults and reactivation of Jurassic rift-related normal faults, with their fault density gradually decreasing landward. Instant fault throw analysis on regional sections shows the along-dip variation of the normal fault activity during crustal down-warping. In Bonaparte Basin, en echelon normal fault arrays with different stepping patterns are observed in several places with different oriented underlying Jurassic structural grains, which altogether indicate a WSW–ENE Timor foreland flexural wave. In addition, based on our study and synthesis of the current understanding of Timor foreland system, we propose that 1) Neogene flexural extension in NW Bonaparte Basin is decoupled from the sinistral transpressive nature of Timor fold and thrust belt by the thrusting décollement, and 2) flexural extension of Timor foreland is mainly derived from tectonic loading and subduction, instead of lithospheric buckling. Panel_15395 Panel_15395 3:45 PM 4:05 PM
4:05 p.m.
Miocene Normal Faulting in the Levant Basin: A Spectacular Example of Compaction/Tectonic Interaction
Room 605/607
The northern part of the Levant basin is located between two major transpressive plate boundaries: the Levant Fault System to the east and the Cyprus arc to the northwest. It is however affected by a dense array of normal faults. The detailed analysis of recent 3D PSTM/PSDM surveys provided by Petroleum Geo-Services (PGS) and the Lebanese Ministry of Energy and Water are used to solve this paradox, shedding light on the interaction between compactions and tectonic stresses. First the dating of these normal faults provide key arguments about their origin. The standard interpretation of the seismic data demonstrates that they are layer bound in an Oligo-Miocene unit. Their impact on stratigraphy unambiguously supports a syn-sedimentary activity during Early Miocene. The geometric relationship between these faults and transpressive structures (faults and folds) also demonstrates that these faults are synchronous with NW-SE compression along the margin. To further study the mechanical origin of these faults, throws were carefully mapped for tens of them. Most of the throw maps show two points a nucleation for faults striking parallel to the maximum horizontal principal stress. They are clearly vertically restricted. Looking at their strikes, they are very constantly oriented around N100 for fault affecting the lower Miocene and more random in the northern most part in the Oligocene units. All these observations, suggest that these normal faults were created as polygonal faults strongly interacting with a compressive tectonic regime. This is the first time that such an observation is made at basin scale. The mechanical implication of this result is further discuss in light of basin models available for this area. The northern part of the Levant basin is located between two major transpressive plate boundaries: the Levant Fault System to the east and the Cyprus arc to the northwest. It is however affected by a dense array of normal faults. The detailed analysis of recent 3D PSTM/PSDM surveys provided by Petroleum Geo-Services (PGS) and the Lebanese Ministry of Energy and Water are used to solve this paradox, shedding light on the interaction between compactions and tectonic stresses. First the dating of these normal faults provide key arguments about their origin. The standard interpretation of the seismic data demonstrates that they are layer bound in an Oligo-Miocene unit. Their impact on stratigraphy unambiguously supports a syn-sedimentary activity during Early Miocene. The geometric relationship between these faults and transpressive structures (faults and folds) also demonstrates that these faults are synchronous with NW-SE compression along the margin. To further study the mechanical origin of these faults, throws were carefully mapped for tens of them. Most of the throw maps show two points a nucleation for faults striking parallel to the maximum horizontal principal stress. They are clearly vertically restricted. Looking at their strikes, they are very constantly oriented around N100 for fault affecting the lower Miocene and more random in the northern most part in the Oligocene units. All these observations, suggest that these normal faults were created as polygonal faults strongly interacting with a compressive tectonic regime. This is the first time that such an observation is made at basin scale. The mechanical implication of this result is further discuss in light of basin models available for this area. Panel_15391 Panel_15391 4:05 PM 4:25 PM
4:25 p.m.
Stratigraphy and Structural Geology of the Eastern Part of the Büyük Menderes Graben, Western Turkey Based on 2-D Seismic Reflection Profiles
Room 605/607
The Alasehir and Büyük Menderes Grabens are two main east-west trending extensional basins located in the central part of Western Anatolia extended terrane, Turkey. These basins are formed during the Cenozoic extension in the region. Although structural development of the Alasehir Graben was studied in detail in recent years, the Büyük Menderes Graben (BMG) has remained relatively unstudied. We have constructed structural cross-sections in the BMG based on our interpretation of the 2D seismic reflection profiles of the Turkish Petroleum Corporation (TPAO) and a wildcat well, Nazilli-1, drilled by the same company. We have delineated stratigraphy of the Miocene to recent sedimentary section and the structural geometry of the extensional features in the eastern BMG. We are also comparing them to published stratigraphic sections and structural cross-sections in the Alasehir graben (AG). Our interpretation of the available seismic and well data together with the depth-conversion conducted by us suggests that the south dipping main boundary fault on the northern side of the BMG has been active during the Miocene sedimentation in the basin. This is evidenced by the wedge-shaped growth strata adjacent to the main boundary fault. Syn-sedimentary extension in the graben has also formed the rollover structure and associate extensional folds and faults. However, these structures are not as well developed as the ones in the AG. This is demonstrated by the very broad nature of the rollover folds and high angle non-rotational nature of the extensional faults within the basinal sediments in the BMG. This suggests that the intensity of the extensional features in the BMG is lesser than the AG. Therefore, although the AG and BMG may have started to form simultaneously, they may have experienced different rates and amounts of extension and they do not contain symmetrical structural features. The Alasehir and Büyük Menderes Grabens are two main east-west trending extensional basins located in the central part of Western Anatolia extended terrane, Turkey. These basins are formed during the Cenozoic extension in the region. Although structural development of the Alasehir Graben was studied in detail in recent years, the Büyük Menderes Graben (BMG) has remained relatively unstudied. We have constructed structural cross-sections in the BMG based on our interpretation of the 2D seismic reflection profiles of the Turkish Petroleum Corporation (TPAO) and a wildcat well, Nazilli-1, drilled by the same company. We have delineated stratigraphy of the Miocene to recent sedimentary section and the structural geometry of the extensional features in the eastern BMG. We are also comparing them to published stratigraphic sections and structural cross-sections in the Alasehir graben (AG). Our interpretation of the available seismic and well data together with the depth-conversion conducted by us suggests that the south dipping main boundary fault on the northern side of the BMG has been active during the Miocene sedimentation in the basin. This is evidenced by the wedge-shaped growth strata adjacent to the main boundary fault. Syn-sedimentary extension in the graben has also formed the rollover structure and associate extensional folds and faults. However, these structures are not as well developed as the ones in the AG. This is demonstrated by the very broad nature of the rollover folds and high angle non-rotational nature of the extensional faults within the basinal sediments in the BMG. This suggests that the intensity of the extensional features in the BMG is lesser than the AG. Therefore, although the AG and BMG may have started to form simultaneously, they may have experienced different rates and amounts of extension and they do not contain symmetrical structural features. Panel_15390 Panel_15390 4:25 PM 4:45 PM
4:45 p.m.
Structural Style of Normal Fault Inversion and Implications for the Hydrocarbon Potential of Rift Basins: Insights From Bornu Basin, Onshore Northeast Nigeria
Room 605/607
Exploration risk in most inverted rift basins is related to a poor understanding of the structural style and distribution of inversion structures, which are controlled by the presence and orientation of pre-existing structures in addition to the magnitude of shortening strain. Consequently, further studies of the dynamics of the normal fault reverse reactivation during inversion, and its impact on petroleum system development are needed. Here, we use 2D and 3D seismic reflection, geochemical, and borehole data from the frontier Bornu Basin, intra-continental rift basin located in NE Nigeria, to constrain the structural style and evolution of inversion structures. We then undertook basin modelling to assess how intra-plate shortening impacted the development of related petroleum systems. Our data indicate that moderately dipping (45° – 60°), NE-SW striking normal faults occur within and form the margins to the major NE trending rift basin. Thickening of the Bima Formation towards these faults indicates Early Aptian to Cenomanian rifting. The major fault bounding the eastern margin of the basin formed in response to the growth and linkage of isolated segments and displays evidence for reverse reactivation during basin shortening. This fault strikes NW-SE and at its northern end it has a low throw (c.690 ms) and dip (40°), and the shortening magnitude is high (c.45 m). In contrast, at the southern end of the fault its dip (55°) and throw (c.900 ms) are high, but the shortening magnitude is low (c.18 m). We interpret that this along-strike change in shortening magnitude is caused by changes in the fault geometry and orientation with respect to the compression direction. Seismic-stratigraphic observations indicate inversion, which was responsible for the formation of the main hydrocarbon traps, occurred in the Turonian and Campanian. Petroleum systems modelling indicates that peak hydrocarbon generation from lacustrine shales of the Bima Formation occurred from the Maastrichtian to Neogene, post-dating the main phase of trap formation. Our study indicates that the magnitude of hanging wall folding, which by implication determines the size of the inversion-related traps, can vary along fault-strike due to changes in fault geometry and strike. Furthermore, petroleum systems modelling shows hydrocarbon maturation and expulsion in the basin occur after formation of inversion-related trap, making these structures attractive exploration targets in the Bornu Basin. Exploration risk in most inverted rift basins is related to a poor understanding of the structural style and distribution of inversion structures, which are controlled by the presence and orientation of pre-existing structures in addition to the magnitude of shortening strain. Consequently, further studies of the dynamics of the normal fault reverse reactivation during inversion, and its impact on petroleum system development are needed. Here, we use 2D and 3D seismic reflection, geochemical, and borehole data from the frontier Bornu Basin, intra-continental rift basin located in NE Nigeria, to constrain the structural style and evolution of inversion structures. We then undertook basin modelling to assess how intra-plate shortening impacted the development of related petroleum systems. Our data indicate that moderately dipping (45° – 60°), NE-SW striking normal faults occur within and form the margins to the major NE trending rift basin. Thickening of the Bima Formation towards these faults indicates Early Aptian to Cenomanian rifting. The major fault bounding the eastern margin of the basin formed in response to the growth and linkage of isolated segments and displays evidence for reverse reactivation during basin shortening. This fault strikes NW-SE and at its northern end it has a low throw (c.690 ms) and dip (40°), and the shortening magnitude is high (c.45 m). In contrast, at the southern end of the fault its dip (55°) and throw (c.900 ms) are high, but the shortening magnitude is low (c.18 m). We interpret that this along-strike change in shortening magnitude is caused by changes in the fault geometry and orientation with respect to the compression direction. Seismic-stratigraphic observations indicate inversion, which was responsible for the formation of the main hydrocarbon traps, occurred in the Turonian and Campanian. Petroleum systems modelling indicates that peak hydrocarbon generation from lacustrine shales of the Bima Formation occurred from the Maastrichtian to Neogene, post-dating the main phase of trap formation. Our study indicates that the magnitude of hanging wall folding, which by implication determines the size of the inversion-related traps, can vary along fault-strike due to changes in fault geometry and strike. Furthermore, petroleum systems modelling shows hydrocarbon maturation and expulsion in the basin occur after formation of inversion-related trap, making these structures attractive exploration targets in the Bornu Basin. Panel_15392 Panel_15392 4:45 PM 5:05 PM

1:15 p.m.–2:40 p.m.
Theme 4: Source-to-Sink Analyses of Sediment Dispersal Systems II (AAPG/SEPM)
Room 702/704/706, Monday Oral Sessions, 01 June, 2015

Panel_14466 Panel_14466 1:15 PM 2:40 PM
1:15 p.m.
Introductory Remarks
Room 702/704/706
Panel_15758 Panel_15758 1:15 PM 12:00 AM
1:20 p.m.
Source to Sink of the Sarah Formation, Latest Ordovician, Northwest Saudi Arabia
Room 702/704/706
A key question that sedimentologists and stratigraphers face is, what controls sedimentary facies and grain-size trends in a depositional basin? Crucial parameters that control grain-size trends are the sediment discharged into the basin, the characteristic grain size mix of the supply, and the spatial distribution of accommodation. In this paper we present an outcrop case study of the latest Ordovician Sarah Formation, in Saudi Arabia, that represents the proximal part of a glacigenic sedimentary system or a pro-glacial outwash fan where these parameters are quantified. In this study, we examine outcrops and glacigenic valley fill deposits of the Sarah Formation in the Northwest of Saudi Arabia. The Sarah Formation is a glacigenic sedimentary unit of latest Ordovician age deposited along the palaeo-Gondwana Margin and as part of the an extensive, but discontinuous belt of outcrop deposits that extend from Saudi Arabia to westernmost North Africa. This is a 600 km sedimentary system and stretches from the northern outcrop belt of Saudi Arabia to at least the borders with Iraq. This source to sink system spans a great range of depositional environments from proximal coarse sand to pebble pro-glacial outwash fan deposits to distal diamictites and offshore fine deep marine deposits. The proximal part is an extraordinary sedimentary unit that is preserved along an elongated and complex network of palaeo-valley fill deposits. It is represented by coarse to medium sand and pebbly deposits of around 250 m thick deposited in a short time span of around 250 ky (mean sedimentation rate of 1 mm/yr). We attribute this large feature to high sediment load and bypass during the interglacial periods. We apply a source to sink approach to calculate the volume of bypassed sediment from specific regions to deposit and preserve the high abundance of coarse grained sediment. We consider controls on the sedimentary architecture with respect to observed grain sizes. We present a model of the evolution of this sedimentary system based on sedimentological and provenance work that includes petrography, heavy mineral analysis and zircon U/Pb geochronology, both in outcrop and core from wells. In addition to provenance, we try to map out sedimentary fairways from seismic regional lines. In this study we teleconnect, reconstruct and calculate sediment budgets for the sedimentary system from the outcrop to the subsurface. A key question that sedimentologists and stratigraphers face is, what controls sedimentary facies and grain-size trends in a depositional basin? Crucial parameters that control grain-size trends are the sediment discharged into the basin, the characteristic grain size mix of the supply, and the spatial distribution of accommodation. In this paper we present an outcrop case study of the latest Ordovician Sarah Formation, in Saudi Arabia, that represents the proximal part of a glacigenic sedimentary system or a pro-glacial outwash fan where these parameters are quantified. In this study, we examine outcrops and glacigenic valley fill deposits of the Sarah Formation in the Northwest of Saudi Arabia. The Sarah Formation is a glacigenic sedimentary unit of latest Ordovician age deposited along the palaeo-Gondwana Margin and as part of the an extensive, but discontinuous belt of outcrop deposits that extend from Saudi Arabia to westernmost North Africa. This is a 600 km sedimentary system and stretches from the northern outcrop belt of Saudi Arabia to at least the borders with Iraq. This source to sink system spans a great range of depositional environments from proximal coarse sand to pebble pro-glacial outwash fan deposits to distal diamictites and offshore fine deep marine deposits. The proximal part is an extraordinary sedimentary unit that is preserved along an elongated and complex network of palaeo-valley fill deposits. It is represented by coarse to medium sand and pebbly deposits of around 250 m thick deposited in a short time span of around 250 ky (mean sedimentation rate of 1 mm/yr). We attribute this large feature to high sediment load and bypass during the interglacial periods. We apply a source to sink approach to calculate the volume of bypassed sediment from specific regions to deposit and preserve the high abundance of coarse grained sediment. We consider controls on the sedimentary architecture with respect to observed grain sizes. We present a model of the evolution of this sedimentary system based on sedimentological and provenance work that includes petrography, heavy mineral analysis and zircon U/Pb geochronology, both in outcrop and core from wells. In addition to provenance, we try to map out sedimentary fairways from seismic regional lines. In this study we teleconnect, reconstruct and calculate sediment budgets for the sedimentary system from the outcrop to the subsurface. Panel_15301 Panel_15301 1:20 PM 1:40 PM
1:40 p.m.
Timing of Upland Erosion for Petroleum System and Geodynamic Implications: An Apatite (U-Th)/He Thermochronologic Approach
Room 702/704/706
The timing of sediment erosion from source regions has a direct implication in petroleum exploration in a number of ways including deciphering the formation timing of major reservoir rocks in the depositional sink areas, and understanding the thermal evolution of petroleum-producing basins. However, the timing of major erosional pulse/s is often associated with uncertainties due to the lacking of proper data in the source region. The Blue Nile River network on the Ethiopian Plateau, East African Rift System has incised a 1.6 km deep canyon, supplying ~96% of the Nile sediment load. The plateau has produced a minimum of 92,200 cubic km of sediments so far that are deposited in alluvial fans in Sudan, and the Nile Delta and Nile Deep Sea Fan in the Mediterranean Sea. We carried out low-temperature apatite (U-Th)/He thermochronology (AHe) dating on single apatite grains isolated from crystalline basement rock and overlying sedimentary rock samples from a vertical transect along the Blue Nile Canyon to constrain the timing of erosion in this source region. Our new thermochronologic cooling age data reveals the timing of tectonically-driven episodic pulses of erosion of the source area, the Ethiopian Plateau. The inverse thermal model simulations of individual samples, guided by reasonable thermal history of the plateau, indicate rapid cooling of the apatites in the helium partial retention zone after 10 Ma as the plateau experienced increased erosions at that time. This timing yields essential information on the likely development of extensive reservoir rocks younger than 10 Ma in the Nile sink area, which is a prolific hydrocarbon-producing region. This increased erosion is associated with the regional tectonics linked to the Afar mantle plume and rift-related activities. Our study of the timing of erosion is critical in understanding the Nile source-to-sink systems that operated during late Miocene. This will allow a better insight of the temporal probability of reservoir rock development and burial-related thermal evolution of the source rocks in the Nile petroleum systems, particularly in the Mediterranean Sea. The timing of sediment erosion from source regions has a direct implication in petroleum exploration in a number of ways including deciphering the formation timing of major reservoir rocks in the depositional sink areas, and understanding the thermal evolution of petroleum-producing basins. However, the timing of major erosional pulse/s is often associated with uncertainties due to the lacking of proper data in the source region. The Blue Nile River network on the Ethiopian Plateau, East African Rift System has incised a 1.6 km deep canyon, supplying ~96% of the Nile sediment load. The plateau has produced a minimum of 92,200 cubic km of sediments so far that are deposited in alluvial fans in Sudan, and the Nile Delta and Nile Deep Sea Fan in the Mediterranean Sea. We carried out low-temperature apatite (U-Th)/He thermochronology (AHe) dating on single apatite grains isolated from crystalline basement rock and overlying sedimentary rock samples from a vertical transect along the Blue Nile Canyon to constrain the timing of erosion in this source region. Our new thermochronologic cooling age data reveals the timing of tectonically-driven episodic pulses of erosion of the source area, the Ethiopian Plateau. The inverse thermal model simulations of individual samples, guided by reasonable thermal history of the plateau, indicate rapid cooling of the apatites in the helium partial retention zone after 10 Ma as the plateau experienced increased erosions at that time. This timing yields essential information on the likely development of extensive reservoir rocks younger than 10 Ma in the Nile sink area, which is a prolific hydrocarbon-producing region. This increased erosion is associated with the regional tectonics linked to the Afar mantle plume and rift-related activities. Our study of the timing of erosion is critical in understanding the Nile source-to-sink systems that operated during late Miocene. This will allow a better insight of the temporal probability of reservoir rock development and burial-related thermal evolution of the source rocks in the Nile petroleum systems, particularly in the Mediterranean Sea. Panel_15299 Panel_15299 1:40 PM 2:00 PM
2:00 p.m.
Driving Sediment Volume and Sand Budgets Into Shelf Margins and Beyond: Sea Level and Sediment Flux?
Room 702/704/706
Examination of sea-level- and supply-drive models for the generation of stratigraphic sequences has yielded the question of ‘what is the main driver of sediment- and sand-volume partitioning into shelf margins and beyond?’ Comparative analysis of a dataset of 25 shelf margins with a spectrum of shelf-edge trajectories and a variety of depositional styles allows us to confirm that both types of margin are common and important, and can be distinguished. We suggest that accommodation-dominated margins have shelf-edge aggradation rates (Ra) of < 200 m/My, shelf-edge progradation rates (Rp) of < 10 km/My, cross-sectional net sediment flux (Fc) of < 10 km2/My, and feeding deltas restricted to the coastal region; supply-dominated margins, on the other hand, have Ra of > 200 m/My, lower Rp of > 10 km/My, lower Fc of > 10 km2/My, and large-scale feeding shelf-margin deltas. Three main styles of shelf-edge growth were recognized in both margin types, including flat to slightly descending (trajectory angles (Tse) of -4° to 0°, aggradation/progradation rates (A/P) of -0.07 to 0), low-angle ascending (Tse of 0° to 2°, A/P of 0 to 0.03) and high-angle ascending shelf-edge trajectories (Tse of 2° to 6°, A/P of 0.03 to 0.10). Descending/flat and low-angle ascending shelf-edge segments of both margin types are commonly fronted by sandy-rich submarine fan systems and mixed sand-mud depositional systems, and sand-prone systems, respectively. Strongly aggradational shelf-edge segments of accommodation- and supply-dominated margins are associated with coeval mud-dominated mass-wasting and sand-prone systems, respectively. Driven by sea-level fall, sand from even small river deltas is delivered into deep-water, accommodation-dominated margins. Driven by high sediment supply, sand of large rivers is delivered into the deep water, supply-dominated margins, and can occur at all sea-level stands. In both margin types, Tse and A/P are proportional to sediment volumes being partitioned into the shelves themselves,, but are inversely proportional to sand-budget partitioning into deep-water areas. These relationships help in relating quantitative characteristics of shelf-edge growth to Source-to Sink sand-budget partitioning, assisting greatly in developing a more dynamic stratigraphy. Examination of sea-level- and supply-drive models for the generation of stratigraphic sequences has yielded the question of ‘what is the main driver of sediment- and sand-volume partitioning into shelf margins and beyond?’ Comparative analysis of a dataset of 25 shelf margins with a spectrum of shelf-edge trajectories and a variety of depositional styles allows us to confirm that both types of margin are common and important, and can be distinguished. We suggest that accommodation-dominated margins have shelf-edge aggradation rates (Ra) of < 200 m/My, shelf-edge progradation rates (Rp) of < 10 km/My, cross-sectional net sediment flux (Fc) of < 10 km2/My, and feeding deltas restricted to the coastal region; supply-dominated margins, on the other hand, have Ra of > 200 m/My, lower Rp of > 10 km/My, lower Fc of > 10 km2/My, and large-scale feeding shelf-margin deltas. Three main styles of shelf-edge growth were recognized in both margin types, including flat to slightly descending (trajectory angles (Tse) of -4° to 0°, aggradation/progradation rates (A/P) of -0.07 to 0), low-angle ascending (Tse of 0° to 2°, A/P of 0 to 0.03) and high-angle ascending shelf-edge trajectories (Tse of 2° to 6°, A/P of 0.03 to 0.10). Descending/flat and low-angle ascending shelf-edge segments of both margin types are commonly fronted by sandy-rich submarine fan systems and mixed sand-mud depositional systems, and sand-prone systems, respectively. Strongly aggradational shelf-edge segments of accommodation- and supply-dominated margins are associated with coeval mud-dominated mass-wasting and sand-prone systems, respectively. Driven by sea-level fall, sand from even small river deltas is delivered into deep-water, accommodation-dominated margins. Driven by high sediment supply, sand of large rivers is delivered into the deep water, supply-dominated margins, and can occur at all sea-level stands. In both margin types, Tse and A/P are proportional to sediment volumes being partitioned into the shelves themselves,, but are inversely proportional to sand-budget partitioning into deep-water areas. These relationships help in relating quantitative characteristics of shelf-edge growth to Source-to Sink sand-budget partitioning, assisting greatly in developing a more dynamic stratigraphy. Panel_15300 Panel_15300 2:00 PM 2:20 PM
2:20 p.m.
Deep-Marine to Shelf-Margin Deltaic Sedimentation, Silurian Succession, Saudi Arabia
Room 702/704/706
A thick Silurian succession, up to 5,000 feet, fills a sag basin in eastern Saudi Arabia. It consists of deep-marine, shelf-margin to inner-shelf deltaic and fluvial deposits. The deep-marine and shelf-margin deposits are called, respectively, the Lower and the Mid-Qusaiba Sand. This study uses subsurface cores and seismic data to investigate the relation between the deep-marine and the shelf-margin deltaic sedimentation. Core logging allowed the recognition of turbidite, hybrid turbidite-debrite, hyperpycnite, mass-transport and mouth bar facies. The turbidite facies were deposited, from high- and low-concentration density flows, in deep-basin and slope fans. The hybrid facies were deposited, from transitional turbulent to laminar flows, on the fringes of the fan lobes. They consist of banded and homogeneous muddy sandstones containing floating mud clasts and sheared sand injections. The hyperpycnites were deposited, from sustained and fluctuating river-born flows, in both the deep-marine fans and shelf-margin deltas. They vary spatially in scale and stratification. Distal hyperpycnites are thin- to medium-bedded, centimeter- to decimeter-scale, and display well-developed inverse to normal grading. Medial hyperpycnites can be very thick-bedded, meter-scale, and exhibit alternating structureless and laminated/rippled divisions. Proximal hyperpycnites have internal erosional surfaces and may lack the lower inverse graded division. They are commonly hosted in slope channels, where they intercalate with trough cross-stratified sandstones, indicating alternating suspension fallout; sediment bypass; traction current reworking and bedload transport. The mass-transport deposits interfinger with slope shales and include distal debrites and proximal slumps. The mouth bar facies comprise current-rippled and laminated sandstones that record buoyancy processes in shelf margin deltas. Seismic data depict low-angle sigmoidal and relatively high-angle dipping reflectors that represent slope clinoforms. The former are associated with an ascending shelf-edge trajectory and are related to slope progradation during rising sea-level conditions. These provided accommodation for the development of the shelf-margin deltas. The latter coincide with a horizontal to descending shelf-edge trajectory that reflects slope degradation during falling sea-level conditions. These induced failure of the shelf-margin deltas, sediment bypass via slope channels and deep-basin sedimentation. A thick Silurian succession, up to 5,000 feet, fills a sag basin in eastern Saudi Arabia. It consists of deep-marine, shelf-margin to inner-shelf deltaic and fluvial deposits. The deep-marine and shelf-margin deposits are called, respectively, the Lower and the Mid-Qusaiba Sand. This study uses subsurface cores and seismic data to investigate the relation between the deep-marine and the shelf-margin deltaic sedimentation. Core logging allowed the recognition of turbidite, hybrid turbidite-debrite, hyperpycnite, mass-transport and mouth bar facies. The turbidite facies were deposited, from high- and low-concentration density flows, in deep-basin and slope fans. The hybrid facies were deposited, from transitional turbulent to laminar flows, on the fringes of the fan lobes. They consist of banded and homogeneous muddy sandstones containing floating mud clasts and sheared sand injections. The hyperpycnites were deposited, from sustained and fluctuating river-born flows, in both the deep-marine fans and shelf-margin deltas. They vary spatially in scale and stratification. Distal hyperpycnites are thin- to medium-bedded, centimeter- to decimeter-scale, and display well-developed inverse to normal grading. Medial hyperpycnites can be very thick-bedded, meter-scale, and exhibit alternating structureless and laminated/rippled divisions. Proximal hyperpycnites have internal erosional surfaces and may lack the lower inverse graded division. They are commonly hosted in slope channels, where they intercalate with trough cross-stratified sandstones, indicating alternating suspension fallout; sediment bypass; traction current reworking and bedload transport. The mass-transport deposits interfinger with slope shales and include distal debrites and proximal slumps. The mouth bar facies comprise current-rippled and laminated sandstones that record buoyancy processes in shelf margin deltas. Seismic data depict low-angle sigmoidal and relatively high-angle dipping reflectors that represent slope clinoforms. The former are associated with an ascending shelf-edge trajectory and are related to slope progradation during rising sea-level conditions. These provided accommodation for the development of the shelf-margin deltas. The latter coincide with a horizontal to descending shelf-edge trajectory that reflects slope degradation during falling sea-level conditions. These induced failure of the shelf-margin deltas, sediment bypass via slope channels and deep-basin sedimentation. Panel_15302 Panel_15302 2:20 PM 2:40 PM

3:20 p.m.–5:05 p.m.
Theme 4: Large Fluvial Fans (AAPG/SEPM)
Room 702/704/706, Monday Oral Sessions, 01 June, 2015

Panel_14457 Panel_14457 3:20 PM 5:05 PM
3:20 p.m.
Introductory Remarks
Room 702/704/706
Panel_15942 Panel_15942 3:20 PM 4:20 PM
3:25 p.m.
Experimental Insights on Distributive Fluvial Systems
Room 702/704/706
Disagreements regarding the importance of large fluvial fans in the sedimentary record tend to focus on whether tributive or distributive drainage patterns comprise the dominant morphotype preserved within fluvial successions. The Distributive Fluvial System (DFS) model seeks to integrate the geomorphic character of fluvial fans into a predictive stratigraphic framework (e.g., Weissmann et al., 2010); however, tributive or axial fluvial systems may be preferentially preserved in continental basins (e.g., Fielding et al., 2012). Differences among these models arise because linkages among topography, dominant surface processes, and preservation of the resulting stratigraphic succession are poorly understood. Understanding process dominance is important for interpreting sedimentary architecture, which is set by interactions between subsidence (pattern and rate) and sediment supply, and how sediment is partitioned among component depositional belts as it is transferred through basins. Physical experimentation can link topography with deposition to provide insights on how discharge and subsidence interact to produce fluvial successions. A unique perspective on how depositional successions form under controlled boundary conditions of subsidence, sediment flux, and water discharge was achieved through experiments in a specially designed flume with four distinct point-sources of sediment into an asymmetrically subsiding tank. Under the imposed conditions, the experimental system self-organized into an axial-drainage system flanked by transverse fans, similar to fluvially dominated intracontinental rift basins. The radial form of these marginal fans was established through nodal avulsions. Axial or tributive drainages formed only where the fans interacted. Distal portions of these fans merged obliquely into the axial-drainage. These distal-fan deflections may complicate differentiation of distributive-fans and axial-river deposits using only paleocurrent data. Imposition of different combinations of lateral sediment fluxes illustrate the impact of sediment partitioning on morphology and sedimentation patterns and highlight the importance of flow-confinement on the formation of axial drainage. Thus, fluvial systems may comprise an amalgamation of axial/tributive and distributive deposits, and the relative abundance of specific deposit-types depends on the spatial distribution of discharge (relative to basin subsidence) and local topographic impediments. Disagreements regarding the importance of large fluvial fans in the sedimentary record tend to focus on whether tributive or distributive drainage patterns comprise the dominant morphotype preserved within fluvial successions. The Distributive Fluvial System (DFS) model seeks to integrate the geomorphic character of fluvial fans into a predictive stratigraphic framework (e.g., Weissmann et al., 2010); however, tributive or axial fluvial systems may be preferentially preserved in continental basins (e.g., Fielding et al., 2012). Differences among these models arise because linkages among topography, dominant surface processes, and preservation of the resulting stratigraphic succession are poorly understood. Understanding process dominance is important for interpreting sedimentary architecture, which is set by interactions between subsidence (pattern and rate) and sediment supply, and how sediment is partitioned among component depositional belts as it is transferred through basins. Physical experimentation can link topography with deposition to provide insights on how discharge and subsidence interact to produce fluvial successions. A unique perspective on how depositional successions form under controlled boundary conditions of subsidence, sediment flux, and water discharge was achieved through experiments in a specially designed flume with four distinct point-sources of sediment into an asymmetrically subsiding tank. Under the imposed conditions, the experimental system self-organized into an axial-drainage system flanked by transverse fans, similar to fluvially dominated intracontinental rift basins. The radial form of these marginal fans was established through nodal avulsions. Axial or tributive drainages formed only where the fans interacted. Distal portions of these fans merged obliquely into the axial-drainage. These distal-fan deflections may complicate differentiation of distributive-fans and axial-river deposits using only paleocurrent data. Imposition of different combinations of lateral sediment fluxes illustrate the impact of sediment partitioning on morphology and sedimentation patterns and highlight the importance of flow-confinement on the formation of axial drainage. Thus, fluvial systems may comprise an amalgamation of axial/tributive and distributive deposits, and the relative abundance of specific deposit-types depends on the spatial distribution of discharge (relative to basin subsidence) and local topographic impediments. Panel_15216 Panel_15216 3:25 PM 3:45 PM
3:45 p.m.
Large Fluvial Fans: Aspects of the Attribute Array
Room 702/704/706
In arguing for a strict definition of the alluvial fan (coarse-grained with radii <10 km, in mountain-front settings), Blair and McPherson (1994) proposed that there is no meaningful difference between the largest fans (large fluvial fans—LFF) and floodplains, as the building blocks of both are the channel-levee-overbank suite of deposits. Sediment bodies at the LFF scale (>100 km long, fan-shaped in planform), of which >160 are now identified globally, are relatively unstudied. The following perspectives suggest that their significance needs to be reconsidered. (1) LFF-formed land surfaces and sediment bodies: Large areas covered by single (up to 200,000 km2) and nested LFF (750,000 km2 contiguous LFF surfaces in S America alone) show that such surfaces are significant at continental scales—though often unrecognized, especially when located far from mountain fronts. Since LFF are a major component of modern Distributive Fluvial Systems (DFS—fanlike forms >30 km), their role in the evolution of buried fluvial strata holds specific interest. (2) Drainage patterns: a—Diverging channel patterns over distances >102 km characterize not only coastal deltas, but also LFF situated hundreds of km from coastlines. b—Rivers in marginal depressions between neighboring LFF tend to be the best developed sectors of lowland, non-axial river systems due to significantly higher episodic drainage discharge. (3) LFF cascade: First-tier LFF (apexed at the upland margin) can give rise in large enough basins to a second tier of downstream derived LFF, the first-tier with distinct conicality, the derived being flatter with alluvial ridges as the most prominent topography. (4) Stratigraphic record: The sheer size of LFF surfaces reduces the rate of surface reworking accomplished by the avulsing river. Combined with relatively higher infiltration capacities LFF are likely to hold more complete sedimentary and pedologic records than those held by the more frequently reworked floodplain surfaces confined between valley walls. (5) Applied aspects: Recognition of a relict LFF in Namibia allowed reinterpretation of the dimensions of two aquifers—as orders of magnitude larger than those implied by the floodplain model. Such reinterpretations can be expected elsewhere. Hydrocarbon exploration can benefit from understanding the architectures and more realistic paleogeographic reconstructions implied in 2 and 1 above. LFF thus warrant classification as a discrete type of fluvial sediment body. In arguing for a strict definition of the alluvial fan (coarse-grained with radii <10 km, in mountain-front settings), Blair and McPherson (1994) proposed that there is no meaningful difference between the largest fans (large fluvial fans—LFF) and floodplains, as the building blocks of both are the channel-levee-overbank suite of deposits. Sediment bodies at the LFF scale (>100 km long, fan-shaped in planform), of which >160 are now identified globally, are relatively unstudied. The following perspectives suggest that their significance needs to be reconsidered. (1) LFF-formed land surfaces and sediment bodies: Large areas covered by single (up to 200,000 km2) and nested LFF (750,000 km2 contiguous LFF surfaces in S America alone) show that such surfaces are significant at continental scales—though often unrecognized, especially when located far from mountain fronts. Since LFF are a major component of modern Distributive Fluvial Systems (DFS—fanlike forms >30 km), their role in the evolution of buried fluvial strata holds specific interest. (2) Drainage patterns: a—Diverging channel patterns over distances >102 km characterize not only coastal deltas, but also LFF situated hundreds of km from coastlines. b—Rivers in marginal depressions between neighboring LFF tend to be the best developed sectors of lowland, non-axial river systems due to significantly higher episodic drainage discharge. (3) LFF cascade: First-tier LFF (apexed at the upland margin) can give rise in large enough basins to a second tier of downstream derived LFF, the first-tier with distinct conicality, the derived being flatter with alluvial ridges as the most prominent topography. (4) Stratigraphic record: The sheer size of LFF surfaces reduces the rate of surface reworking accomplished by the avulsing river. Combined with relatively higher infiltration capacities LFF are likely to hold more complete sedimentary and pedologic records than those held by the more frequently reworked floodplain surfaces confined between valley walls. (5) Applied aspects: Recognition of a relict LFF in Namibia allowed reinterpretation of the dimensions of two aquifers—as orders of magnitude larger than those implied by the floodplain model. Such reinterpretations can be expected elsewhere. Hydrocarbon exploration can benefit from understanding the architectures and more realistic paleogeographic reconstructions implied in 2 and 1 above. LFF thus warrant classification as a discrete type of fluvial sediment body. Panel_15211 Panel_15211 3:45 PM 4:05 PM
4:05 p.m.
An Integrated Actualistic Sedimentary Systems Analysis of the Southern Chaco Foreland Basin
Room 702/704/706
The Chaco foreland basin is a frequently referenced modern analog for studies that use ancient strata to interpret Andean orogenesis. However, the paucity of actualistic geological data from this flexural foreland and its hinterland sediment routing system constrains its viability as an analog. To address this shortcoming, we developed the first modern time-slice sedimentary systems analysis of the southern Chaco foreland in northern Argentina. Sedimentation in the Chaco is dominated by the vast Río Bermejo fluvial megafan (~71,000 km2), which was studied hierarchically using GIS, sand petrography, particle size analysis, clay mineralogy, and U-Pb detrital zircon geochronology. The results provide a new reference catalog of continental depositional environments for an “overfilled”, four-part retroarc foreland basin system that can be used to improve interpretations of syn-orogenic strata. The Río Bermejo megafan is comprised of sediments from three distinct hinterland sub-regions. Despite environmental differences among the sub-regions, megafan provenance is controlled by hinterland parent lithology and outcrop area. Megafan sediments plot within the recycled orogen provenance field (mean QtFL = 77,6,17), which is consistent with weathering and erosion of extensive sedimentary and meta-sedimentary rocks. Compositional maturity increases towards the distal back-bulge depozone. Distinct intra-foreland gradients are captured in sand texture and clay mineral abundance data. Río Bermejo particle sizes become progressively finer towards the forebulge and back-bulge (mean = ~98 µm), whereas mean sand sizes in the proximal wedgetop and foredeep depozones are ~280 and 195 µm, respectively. Remote sensing data reveal changes in channel patterns within the foreland, which can be attributed to particle size variations and the influence of climate and tectonics. The Río Bermejo’s detrital clays consist of illite, smectite, chlorite and kaolinite (in rank order of abundance), with smectite concentrated in foredeep sediments. Trend surface analysis highlights topographic contrasts in architectural elements across the foreland, and indicates the presence of several vintages of fan lobes, as well as remnant accommodation space. Data from the southern Chaco foreland validate conceptual facies models developed for prograding distributive fluvial systems, which are important but poorly understood sedimentary archives in basin analysis and petroleum exploration. The Chaco foreland basin is a frequently referenced modern analog for studies that use ancient strata to interpret Andean orogenesis. However, the paucity of actualistic geological data from this flexural foreland and its hinterland sediment routing system constrains its viability as an analog. To address this shortcoming, we developed the first modern time-slice sedimentary systems analysis of the southern Chaco foreland in northern Argentina. Sedimentation in the Chaco is dominated by the vast Río Bermejo fluvial megafan (~71,000 km2), which was studied hierarchically using GIS, sand petrography, particle size analysis, clay mineralogy, and U-Pb detrital zircon geochronology. The results provide a new reference catalog of continental depositional environments for an “overfilled”, four-part retroarc foreland basin system that can be used to improve interpretations of syn-orogenic strata. The Río Bermejo megafan is comprised of sediments from three distinct hinterland sub-regions. Despite environmental differences among the sub-regions, megafan provenance is controlled by hinterland parent lithology and outcrop area. Megafan sediments plot within the recycled orogen provenance field (mean QtFL = 77,6,17), which is consistent with weathering and erosion of extensive sedimentary and meta-sedimentary rocks. Compositional maturity increases towards the distal back-bulge depozone. Distinct intra-foreland gradients are captured in sand texture and clay mineral abundance data. Río Bermejo particle sizes become progressively finer towards the forebulge and back-bulge (mean = ~98 µm), whereas mean sand sizes in the proximal wedgetop and foredeep depozones are ~280 and 195 µm, respectively. Remote sensing data reveal changes in channel patterns within the foreland, which can be attributed to particle size variations and the influence of climate and tectonics. The Río Bermejo’s detrital clays consist of illite, smectite, chlorite and kaolinite (in rank order of abundance), with smectite concentrated in foredeep sediments. Trend surface analysis highlights topographic contrasts in architectural elements across the foreland, and indicates the presence of several vintages of fan lobes, as well as remnant accommodation space. Data from the southern Chaco foreland validate conceptual facies models developed for prograding distributive fluvial systems, which are important but poorly understood sedimentary archives in basin analysis and petroleum exploration. Panel_15215 Panel_15215 4:05 PM 4:25 PM
4:25 p.m.
Stratigraphic Architecture of Fluvial Distributive Systems in Basins of Internal Drainage
Room 702/704/706
Stratigraphic models of fluvial successions tend to focus on the ‘incised valley’ model, which assumes that a marine base level exerts a strong control on the distribution of sandstones deposited by river channels. However, not all rivers flow to the sea and in basins of internal drainage there is no control exerted on river profiles by fluctuations in marine base level. Internal drainage basins are the sites of approximately half of the actively depositing fluvial systems today, and during periods of continental amalgamation, there would have been significant accumulations of continental successions in these endorheic basins. In relatively humid endorheic basins a deep basin-centre lake may act as a partial downstream control on fluvial successions. However, in temperate through to arid settings, rivers terminate in a shallow, perhaps ephemeral lake, dry out on an alluvial plain or interfinger with aeolian environments. In these settings the level of the downstream termination is related to aggradation in the basin, which is itself determined by sediment supply via the rivers. The fluvial system, its depositional patterns and the stratigraphic architecture are hence controlled by just discharge and sediment supply. A distributive fluvial pattern seems to be dominant in modern and modern and ancient endorheic basins. The fluvial successions formed by these systems in endorheic basins have a fundamentally different architecture to the ‘incised valley fill’ model commonly used in fluvial stratigraphy. Case studies from Miocene strata in northern Spain illustrate the stratigraphic relationships between fluvial channel and overbank successions in an endorheic basin. Stratigraphic models of fluvial successions tend to focus on the ‘incised valley’ model, which assumes that a marine base level exerts a strong control on the distribution of sandstones deposited by river channels. However, not all rivers flow to the sea and in basins of internal drainage there is no control exerted on river profiles by fluctuations in marine base level. Internal drainage basins are the sites of approximately half of the actively depositing fluvial systems today, and during periods of continental amalgamation, there would have been significant accumulations of continental successions in these endorheic basins. In relatively humid endorheic basins a deep basin-centre lake may act as a partial downstream control on fluvial successions. However, in temperate through to arid settings, rivers terminate in a shallow, perhaps ephemeral lake, dry out on an alluvial plain or interfinger with aeolian environments. In these settings the level of the downstream termination is related to aggradation in the basin, which is itself determined by sediment supply via the rivers. The fluvial system, its depositional patterns and the stratigraphic architecture are hence controlled by just discharge and sediment supply. A distributive fluvial pattern seems to be dominant in modern and modern and ancient endorheic basins. The fluvial successions formed by these systems in endorheic basins have a fundamentally different architecture to the ‘incised valley fill’ model commonly used in fluvial stratigraphy. Case studies from Miocene strata in northern Spain illustrate the stratigraphic relationships between fluvial channel and overbank successions in an endorheic basin. Panel_15212 Panel_15212 4:25 PM 4:45 PM
4:45 p.m.
Application of a Quantified System Scale Analyses of DFS to Predicting Basin Scale Facies Distributions
Room 702/704/706
Analysis of modern continental sedimentary basins indicates that distributive fluvial systems (DFS) account for a large proportion of modern continental sedimentary basins and will thus account for a significant proportion of the continental geologic record. A system-wide study on the remarkably well exposed Salt Wash DFS of the Late Jurassic Morrison Formation, SW USA, was conducted in order to test the presence of trends cited in published generic DFS models. A downstream decrease in the sand:mud ratio and presence of channel belt deposits, and a downstream increase in floodplain proportion were quantitatively determined. Analyses of the occurrence and thickness of ribbon fluvial channel fills indicate a relatively uniform presence across the DFS. A consistent change in fluvial architecture was qualitatively identified, with proximal regions dominated by stacked channels belt deposits with a high degree of amalgamation and distal regions dominated by floodplain muds and sheet sandstones and sparse ribbon channels, with little to no amalgamation of channel deposits. This study on the Salt Wash DFS quantitatively and qualitatively demonstrates the robustness and predictability of published DFS models as well as providing additional statistics on trends cited. Results and trends found on the Salt Wash DFS have been utilised to aid mapping efforts at a basin scale of the Paleogene Fort Union and Willwood Formations in the northern portion of the Bighorn Basin, NW USA. Preliminary analyses of multiple successions across an E-W trending cross-section within a NW-SE trending basin reveals the presence of smaller transverse, easterly flowing DFS and the presence of a much larger axial DFS in the basin center flowing northwards. The presence of large scale (up to 30 m thick) amalgamated channel belt deposits separated by equally thick floodplain packages, with no visible connectivity between the channel belt deposits, in the center of the basin indicates that the deposits in this portion of the basin represent the medial to distal portion of a system. These combined studies demonstrate the predictability of the DFS concept at both the system and basin scale, with clear implications in resource exploration efforts. Analysis of modern continental sedimentary basins indicates that distributive fluvial systems (DFS) account for a large proportion of modern continental sedimentary basins and will thus account for a significant proportion of the continental geologic record. A system-wide study on the remarkably well exposed Salt Wash DFS of the Late Jurassic Morrison Formation, SW USA, was conducted in order to test the presence of trends cited in published generic DFS models. A downstream decrease in the sand:mud ratio and presence of channel belt deposits, and a downstream increase in floodplain proportion were quantitatively determined. Analyses of the occurrence and thickness of ribbon fluvial channel fills indicate a relatively uniform presence across the DFS. A consistent change in fluvial architecture was qualitatively identified, with proximal regions dominated by stacked channels belt deposits with a high degree of amalgamation and distal regions dominated by floodplain muds and sheet sandstones and sparse ribbon channels, with little to no amalgamation of channel deposits. This study on the Salt Wash DFS quantitatively and qualitatively demonstrates the robustness and predictability of published DFS models as well as providing additional statistics on trends cited. Results and trends found on the Salt Wash DFS have been utilised to aid mapping efforts at a basin scale of the Paleogene Fort Union and Willwood Formations in the northern portion of the Bighorn Basin, NW USA. Preliminary analyses of multiple successions across an E-W trending cross-section within a NW-SE trending basin reveals the presence of smaller transverse, easterly flowing DFS and the presence of a much larger axial DFS in the basin center flowing northwards. The presence of large scale (up to 30 m thick) amalgamated channel belt deposits separated by equally thick floodplain packages, with no visible connectivity between the channel belt deposits, in the center of the basin indicates that the deposits in this portion of the basin represent the medial to distal portion of a system. These combined studies demonstrate the predictability of the DFS concept at both the system and basin scale, with clear implications in resource exploration efforts. Panel_15214 Panel_15214 4:45 PM 5:05 PM
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