Join SEPM in the Exhibition Hall for all-day poster sessions. Channels are conduits through which fluids, sediment (suspended and bed-load) and dissolved loads are transported across the Earth surface. Their general geomorphologic expression is comparable similar in terrestrial, submarine and extraterrestrial environments; however, formative sedimentary processes can be fundamentally different. For example, sinuosity and aspect ratio tend to be similar; however, submarine channels tend to be larger than fluvial channels and the stratigraphic records of fluvial and submarine channel deposits can be different. A key research challenge is the link between the geomorphic expression and stratigraphic record of channels. Rivers are more accessible to direct monitoring compared to submarine channels and the link between fluvial geomorphology and stratigraphy is better understood. In the case of submarine channels, we commonly rely on the stratigraphic record to inform insights about formative processes and evolution.

Join SEPM in the Exhibition Hall for all-day poster sessions. Channels are conduits through which fluids, sediment (suspended and bed-load) and dissolved loads are transported across the Earth surface. Their general geomorphologic expression is comparable similar in terrestrial, submarine and extraterrestrial environments; however, formative sedimentary processes can be fundamentally different. For example, sinuosity and aspect ratio tend to be similar; however, submarine channels tend to be larger than fluvial channels and the stratigraphic records of fluvial and submarine channel deposits can be different. A key research challenge is the link between the geomorphic expression and stratigraphic record of channels. Rivers are more accessible to direct monitoring compared to submarine channels and the link between fluvial geomorphology and stratigraphy is better understood. In the case of submarine channels, we commonly rely on the stratigraphic record to inform insights about formative processes and evolution.

Panel_14419 Panel_14419 8:30 AM 5:00 PM
Panel_14429 Panel_14429 8:30 AM 5:00 PM
8:30 a.m.
Regional Stratigraphy and a High-Resolution Geochemical Model of the Upper Pennsylvanian Cline Shale, Midland Basin, Texas
Exhibition Hall
The Cline Shale is an organic-rich mudrock deposited in the Midland Basin during the Late Pennsylvanian. Exploration and production activity in this unconventional resource play has increased in recent years. A depositional model of the Cline Shale is interpreted using regional wireline log stratigraphy coupled with a core-based, high-resolution geochemical model. The study area was a restricted deep-water, epicratonic basin near the southern extent of Laurussia during the late Pennsylvanian. It is widely thought that slow sedimentation rates and oceanic oxygen depletion controlled the accumulation and preservation of organic matter. Large amplitude relative sea-level changes contributed to significant depositional heterogeneity both laterally and vertically throughout the Cline. The eastern boundary of the Cline Shale is the Eastern Shelf, where it grades into Canyon and Cisco age carbonates, shales, and sandstones. The Central Basin Platform and the Horseshoe Atoll are the western and northern boundaries of the Cline system respectively. Distinct changes in wireline log character from the Eastern Shelf into the Midland basin are apparent, and these changes can be attributed to basin-scale heterogeneities within the Cline Shale. High-resolution (2-inch sampling interval) x-ray fluorescence (XRF) geochemical data were collected from four Cline Shale cores. Three of the cores are discontinuous and represent deposition at or near the basin center. One core preserves a continuous Cline section and represents strata deposited on the slope of the Eastern Shelf. The XRF data delineate both mineralogical composition and depositional conditions, i.e., periods of oceanic oxygen depletion, throughout the interval at sub-facies resolution. Chemical facies can be interpreted on a 2-inch scale using agglomerative hierarchical cluster analysis; a statistical method that identifies similar groups of data in large datasets. This high-resolution facies scheme is coupled with strategic TOC and XRD measurements in order to create a robust geochemical model for the Cline Shale. The basin-centered cores and the core on the slope of the Eastern Shelf exhibit two distinct depositional and redox environments. These differences can be related to paleogeography and the transgressive nature of the formation. The Cline Shale is an organic-rich mudrock deposited in the Midland Basin during the Late Pennsylvanian. Exploration and production activity in this unconventional resource play has increased in recent years. A depositional model of the Cline Shale is interpreted using regional wireline log stratigraphy coupled with a core-based, high-resolution geochemical model. The study area was a restricted deep-water, epicratonic basin near the southern extent of Laurussia during the late Pennsylvanian. It is widely thought that slow sedimentation rates and oceanic oxygen depletion controlled the accumulation and preservation of organic matter. Large amplitude relative sea-level changes contributed to significant depositional heterogeneity both laterally and vertically throughout the Cline. The eastern boundary of the Cline Shale is the Eastern Shelf, where it grades into Canyon and Cisco age carbonates, shales, and sandstones. The Central Basin Platform and the Horseshoe Atoll are the western and northern boundaries of the Cline system respectively. Distinct changes in wireline log character from the Eastern Shelf into the Midland basin are apparent, and these changes can be attributed to basin-scale heterogeneities within the Cline Shale. High-resolution (2-inch sampling interval) x-ray fluorescence (XRF) geochemical data were collected from four Cline Shale cores. Three of the cores are discontinuous and represent deposition at or near the basin center. One core preserves a continuous Cline section and represents strata deposited on the slope of the Eastern Shelf. The XRF data delineate both mineralogical composition and depositional conditions, i.e., periods of oceanic oxygen depletion, throughout the interval at sub-facies resolution. Chemical facies can be interpreted on a 2-inch scale using agglomerative hierarchical cluster analysis; a statistical method that identifies similar groups of data in large datasets. This high-resolution facies scheme is coupled with strategic TOC and XRD measurements in order to create a robust geochemical model for the Cline Shale. The basin-centered cores and the core on the slope of the Eastern Shelf exhibit two distinct depositional and redox environments. These differences can be related to paleogeography and the transgressive nature of the formation. Panel_14943 Panel_14943 8:30 AM 5:00 PM
8:30 a.m.
Innovative Workflows for Mitigating the Horizontal Well Placement Challenges Associated With Deep Unconventional Reservoirs
Exhibition Hall
Kuwait Oil company is currently engaged in an early phase of appraisal of the deep tight fractured carbonate reservoirs and resource plays of Oxfordian – Callovian age (over 14000ft depth, HPHT) in the northern part of Kuwait. The primary driver for successful appraisal of such unconventional reservoirs is optimal wellbore design (horizontal well) maximizing reservoir contact which intersects open fractures or facilitates effective hydraulic fracturing. The key factors that determine the success in achieving the objectives of these horizontal wells are well selection, well placement and well testing and completion. The well design and placement of these horizontal wells is severely constrained by the very highly overpressured (upto 21 ppg mud weight equivalent) evaporite section (Salt+Anhydrite) overlying the target unconventional reservoirs. Although, the individual thickness of the reservoir units range from 40’-50’ , for well placement / geo-steering purposes the sweet spot within these units is of the order of 5’-10’. Due to resolution limitation of the available 3D seismic data, predicting local dip changes of the order 1°-2° and very minor subseismic faults at the depth range of 14000’-15000’ is fraught with higher uncertainty. To mitigate the well placement challenges and maximize success, utilising innovative workflows many iterations / updating of the initial fine scale static model (which is constrained by the offset well data and 3D seismic data) are carried out and different potential scenarios (for changes in dip and observed apparent thickness changes as a result of the combination of bed dip and inclination of the well) are prepared dynamically in conjunction with the well placement team to assist in real time geosteering of the well. Taking into consideration the lessons learnt from the two horizontal wells drilled recently, the above novel approach has resulted in 100% placement of 2000’ drain hole in the third well (final TD: approx.. 19000’ MD) targeting the deep unconventional reservoir in northern part of Kuwait. Kuwait Oil company is currently engaged in an early phase of appraisal of the deep tight fractured carbonate reservoirs and resource plays of Oxfordian – Callovian age (over 14000ft depth, HPHT) in the northern part of Kuwait. The primary driver for successful appraisal of such unconventional reservoirs is optimal wellbore design (horizontal well) maximizing reservoir contact which intersects open fractures or facilitates effective hydraulic fracturing. The key factors that determine the success in achieving the objectives of these horizontal wells are well selection, well placement and well testing and completion. The well design and placement of these horizontal wells is severely constrained by the very highly overpressured (upto 21 ppg mud weight equivalent) evaporite section (Salt+Anhydrite) overlying the target unconventional reservoirs. Although, the individual thickness of the reservoir units range from 40’-50’ , for well placement / geo-steering purposes the sweet spot within these units is of the order of 5’-10’. Due to resolution limitation of the available 3D seismic data, predicting local dip changes of the order 1°-2° and very minor subseismic faults at the depth range of 14000’-15000’ is fraught with higher uncertainty. To mitigate the well placement challenges and maximize success, utilising innovative workflows many iterations / updating of the initial fine scale static model (which is constrained by the offset well data and 3D seismic data) are carried out and different potential scenarios (for changes in dip and observed apparent thickness changes as a result of the combination of bed dip and inclination of the well) are prepared dynamically in conjunction with the well placement team to assist in real time geosteering of the well. Taking into consideration the lessons learnt from the two horizontal wells drilled recently, the above novel approach has resulted in 100% placement of 2000’ drain hole in the third well (final TD: approx.. 19000’ MD) targeting the deep unconventional reservoir in northern part of Kuwait. Panel_14948 Panel_14948 8:30 AM 5:00 PM
8:30 a.m.
Eagle Ford Lateral Wellbore Analysis Using Drill Cuttings
Exhibition Hall
Thanks to advances in technology and expertise, shale well drilling times continue to drop and the total drilling cost per well continues to decline. Enhancing this trend of improved drilling efficiency, operators are also developing methods and procedures for improving well stimulation based on local rock characteristics. These “engineered completions” require rock quality data along the lateral in order to be effective. Since open-hole well logs (MWD/LWD) and conventional coring is seldom practical along laterals and there can be a great deal of variability, it is becoming more critical to obtain high quality geologic data from drill cuttings. We will show results of drill cuttings analysis from several hundred samples along both the vertical and horizontal tracts from an Eagle Ford well (EF1). Data collected from drill cuttings samples includes elemental composition and scanning electron microscopy to allow detailed visualization and quantification of pore types and organic material abundance throughout the section. Utilizing cuttings can assist in adjusting the landing (target) zone, adjusting geologic spacing of fracturing zones for well completions, predicting Estimated Ultimate Recovery (EUR), and comparing results between multiple wells. Well EF1 has data from both a vertical pilot-hole (10 foot intervals) and from the lateral wellbore (30 foot intervals). In all more than 350 sample intervals were analyzed. Specialized sample collection and handling procedures were developed for this project. These procedures helped ensure that adequate and useable samples were collected and that the depth registration was reliable. Analytical results show that lithology variation along the lateral wellbore can be determined from shale cuttings samples. The drill cuttings data has been compared to other data from well logs and whole core and the results are consistent. The data shows that some zones along the lateral were in the targeted strata and others were not. Thanks to advances in technology and expertise, shale well drilling times continue to drop and the total drilling cost per well continues to decline. Enhancing this trend of improved drilling efficiency, operators are also developing methods and procedures for improving well stimulation based on local rock characteristics. These “engineered completions” require rock quality data along the lateral in order to be effective. Since open-hole well logs (MWD/LWD) and conventional coring is seldom practical along laterals and there can be a great deal of variability, it is becoming more critical to obtain high quality geologic data from drill cuttings. We will show results of drill cuttings analysis from several hundred samples along both the vertical and horizontal tracts from an Eagle Ford well (EF1). Data collected from drill cuttings samples includes elemental composition and scanning electron microscopy to allow detailed visualization and quantification of pore types and organic material abundance throughout the section. Utilizing cuttings can assist in adjusting the landing (target) zone, adjusting geologic spacing of fracturing zones for well completions, predicting Estimated Ultimate Recovery (EUR), and comparing results between multiple wells. Well EF1 has data from both a vertical pilot-hole (10 foot intervals) and from the lateral wellbore (30 foot intervals). In all more than 350 sample intervals were analyzed. Specialized sample collection and handling procedures were developed for this project. These procedures helped ensure that adequate and useable samples were collected and that the depth registration was reliable. Analytical results show that lithology variation along the lateral wellbore can be determined from shale cuttings samples. The drill cuttings data has been compared to other data from well logs and whole core and the results are consistent. The data shows that some zones along the lateral were in the targeted strata and others were not. Panel_14941 Panel_14941 8:30 AM 5:00 PM
8:30 a.m.
Bedding-Parallel Fractures in Shales: Characterization, Prediction and Importance
Exhibition Hall
Bedding-parallel fractures are common although not ubiquitous in shale. Several lines of evidence (mine-back experiments, microseismic data and tiltmeter data) suggest that hydraulic fractures used to stimulate wells in hydrocarbon reservoirs sometimes have a horizontal (bedding-parallel) component, even at significant depth. Natural, sealed horizontal fractures may facilitate horizontal growth of hydraulic fractures by acting as planes of weakness that enhance the already marked strength anisotropy due to bedding-parallel laminae and planar fabric. Impacts on hydraulic fracture growth might include height growth inhibition and horizontal propagation. Intensity and morphology of bedding-parallel fractures vary; planar, lens-shaped fractures, and complex, branching geometries are all found. Cement fills are typically calcite or sulphates, sometimes with hydrocarbon inclusions, and may be fibrous or show crack-seal texture. Quartz also occurs, and pyrite is a common accessory mineral. Scaling of faults and subvertical opening-mode fractures has been well documented, with populations following power-law distributions. We investigate whether similar scaling laws apply to bedding-parallel fracture sets. One of the challenges of collecting systematic data for bedding-parallel fractures is the difficulty of distinguishing between fibrous beef-filled fractures and fossils with a fibrous structure, e.g. the Inoceramidae bivalves present in many Mesozoic shales. We show criteria to distinguish these during core-description work, and demonstrate stable isotope and petrographic differences. Different mechanisms may be responsible for fracture generation and more than one mechanism may have operated in the history of a given shale. We will attempt to use stable isotope geochemistry and fluid inclusion analysis to constrain conditions of formation, and thereby narrow down the possible mechanisms for each case. This approach, along with tying the occurrence to lithotype, will allow us to predict bedding-parallel fracture occurrences. Bedding-parallel fractures are common although not ubiquitous in shale. Several lines of evidence (mine-back experiments, microseismic data and tiltmeter data) suggest that hydraulic fractures used to stimulate wells in hydrocarbon reservoirs sometimes have a horizontal (bedding-parallel) component, even at significant depth. Natural, sealed horizontal fractures may facilitate horizontal growth of hydraulic fractures by acting as planes of weakness that enhance the already marked strength anisotropy due to bedding-parallel laminae and planar fabric. Impacts on hydraulic fracture growth might include height growth inhibition and horizontal propagation. Intensity and morphology of bedding-parallel fractures vary; planar, lens-shaped fractures, and complex, branching geometries are all found. Cement fills are typically calcite or sulphates, sometimes with hydrocarbon inclusions, and may be fibrous or show crack-seal texture. Quartz also occurs, and pyrite is a common accessory mineral. Scaling of faults and subvertical opening-mode fractures has been well documented, with populations following power-law distributions. We investigate whether similar scaling laws apply to bedding-parallel fracture sets. One of the challenges of collecting systematic data for bedding-parallel fractures is the difficulty of distinguishing between fibrous beef-filled fractures and fossils with a fibrous structure, e.g. the Inoceramidae bivalves present in many Mesozoic shales. We show criteria to distinguish these during core-description work, and demonstrate stable isotope and petrographic differences. Different mechanisms may be responsible for fracture generation and more than one mechanism may have operated in the history of a given shale. We will attempt to use stable isotope geochemistry and fluid inclusion analysis to constrain conditions of formation, and thereby narrow down the possible mechanisms for each case. This approach, along with tying the occurrence to lithotype, will allow us to predict bedding-parallel fracture occurrences. Panel_14951 Panel_14951 8:30 AM 5:00 PM
8:30 a.m.
Shale Rheology and Retained Fracture Conductivity
Exhibition Hall
The effective exploitation of most shale petroleum reservoirs is generally considered to be reliant on the creation of economically productive fractures within the low permeability shale matrix. Hydraulic fracture stimulation is the most commonly attempted method of achieving this, and the creation of effectively propped fracture surface area is a key component of doing this successfully. Although field evidence is limited it is generally acknowledged that many such hydraulic fracture treatments result in significant fracture area that is minimally propped (monolayer of proppant), partially propped or not propped at all and yet is in hydraulic communication with the wellbore. Many factors may contribute to the reduction of this initial fracture conductivity and we will present some work related to retained fracture conductivity from the perspective of rock rheology. Rock mechanical testing was performed on core samples from the Duvernay Shale from the Western Canadian Sedimentary Basin and the Wolfcamp Shale from the Midland Permian Basin. The stress and time-dependent mechanical properties of these shales were determined and are described in relation to the petrophysical composition and fabric of the reservoir interval. Of note, the time-dependent deformation of some producing shales is on the same order as the elastic deformation. Appropriate creep deformation models were built to describe this behavior and to improve the overall constitutive model of shale response to stress changes through time. Proppant embedment and fracture conductivity measurements were made in these same shales over a range of stress and time paths. The constitutive models are shown to be able to predict the reduction in conductivity due to embedment. Numerical models are used to demonstrate the impact of reservoir stress path on damage mechanisms that act to reduce initial fracture conductivity. The implications for proppant selection and managed pressure drawdown are discussed. The effective exploitation of most shale petroleum reservoirs is generally considered to be reliant on the creation of economically productive fractures within the low permeability shale matrix. Hydraulic fracture stimulation is the most commonly attempted method of achieving this, and the creation of effectively propped fracture surface area is a key component of doing this successfully. Although field evidence is limited it is generally acknowledged that many such hydraulic fracture treatments result in significant fracture area that is minimally propped (monolayer of proppant), partially propped or not propped at all and yet is in hydraulic communication with the wellbore. Many factors may contribute to the reduction of this initial fracture conductivity and we will present some work related to retained fracture conductivity from the perspective of rock rheology. Rock mechanical testing was performed on core samples from the Duvernay Shale from the Western Canadian Sedimentary Basin and the Wolfcamp Shale from the Midland Permian Basin. The stress and time-dependent mechanical properties of these shales were determined and are described in relation to the petrophysical composition and fabric of the reservoir interval. Of note, the time-dependent deformation of some producing shales is on the same order as the elastic deformation. Appropriate creep deformation models were built to describe this behavior and to improve the overall constitutive model of shale response to stress changes through time. Proppant embedment and fracture conductivity measurements were made in these same shales over a range of stress and time paths. The constitutive models are shown to be able to predict the reduction in conductivity due to embedment. Numerical models are used to demonstrate the impact of reservoir stress path on damage mechanisms that act to reduce initial fracture conductivity. The implications for proppant selection and managed pressure drawdown are discussed. Panel_14940 Panel_14940 8:30 AM 5:00 PM
8:30 a.m.
Micro Fracture Propagation During Post-Frac Shut in and Enhanced Gas Production From Shale
Exhibition Hall
Recently, the shale gas has become an important source of energy around the globe, thus attracting many operators to engage in research on shale gas. To support the industry efforts, it is our objective to create a simple yet robust method of image analysis which would lead to better evaluation of gas bearing intervals and higher gas production from shale gas wells. We propose an efficient method for imaging the absorbed water vapor on shale. We used the SEM to generate images of the shale samples after being exposed to water vapor. We found a remarkable contrast between the sample regions where the water vapor was absorbed randomly and the unabsorbed regions. Interestingly, various types of micro fractures initiated in and propagated from the regions of highly absorbed water vapor. To quantify the micro fractures and the contrasting regions, we processed the SEM images. We used segmentation algorithm to distinguish the above mentioned regions in the shale. Furthermore, dynamic threshholding and morphological concepts were applied to separate the absorbed water vapor regions from the rest. Finally, we filtered the SEM image spectrum for edge detection which was necessary for seamlessly transitioning the absorbed water vapor regions to micro fractures. We conclude that: (1) The amount of absorbed water vapor is directly related to the initiation of micro fractures and activation of gas bearing capillaries in the shale, (2) Dynamic thresholding and segmentation parameters illustrate the robustness of image processing technique for images with dissimilar illuminations and colors, and (3) the proposed technique can analyze the shale samples automatically, quickly, and reliably. Based on the SEM image analysis, which detect many useful attributes, the proposed method can help the operators in making the best decision for shale gas prospecting. This computerized method offers the industry with the following: (1) Increases the speed and accuracy of the analysis of intervals with high micro fracture density and identifies the micro fracture types and sizes per unit mass and (2) Accurately quantifies and separates the regions of shale where the absorbed water and the activated, gas bearing capillaries are the most. These contributions could lead to the enhanced shale gas production. Recently, the shale gas has become an important source of energy around the globe, thus attracting many operators to engage in research on shale gas. To support the industry efforts, it is our objective to create a simple yet robust method of image analysis which would lead to better evaluation of gas bearing intervals and higher gas production from shale gas wells. We propose an efficient method for imaging the absorbed water vapor on shale. We used the SEM to generate images of the shale samples after being exposed to water vapor. We found a remarkable contrast between the sample regions where the water vapor was absorbed randomly and the unabsorbed regions. Interestingly, various types of micro fractures initiated in and propagated from the regions of highly absorbed water vapor. To quantify the micro fractures and the contrasting regions, we processed the SEM images. We used segmentation algorithm to distinguish the above mentioned regions in the shale. Furthermore, dynamic threshholding and morphological concepts were applied to separate the absorbed water vapor regions from the rest. Finally, we filtered the SEM image spectrum for edge detection which was necessary for seamlessly transitioning the absorbed water vapor regions to micro fractures. We conclude that: (1) The amount of absorbed water vapor is directly related to the initiation of micro fractures and activation of gas bearing capillaries in the shale, (2) Dynamic thresholding and segmentation parameters illustrate the robustness of image processing technique for images with dissimilar illuminations and colors, and (3) the proposed technique can analyze the shale samples automatically, quickly, and reliably. Based on the SEM image analysis, which detect many useful attributes, the proposed method can help the operators in making the best decision for shale gas prospecting. This computerized method offers the industry with the following: (1) Increases the speed and accuracy of the analysis of intervals with high micro fracture density and identifies the micro fracture types and sizes per unit mass and (2) Accurately quantifies and separates the regions of shale where the absorbed water and the activated, gas bearing capillaries are the most. These contributions could lead to the enhanced shale gas production. Panel_14947 Panel_14947 8:30 AM 5:00 PM
8:30 a.m.
Integration of Elemental and Stable Isotope Chemostratigraphy to Characterize Paleoenvironmental Diachroneity in the Duvernay Formation (Mid-Frasnian), a Mixed Carbonate-Siliciclastic Unconventional Play in the Western Canada Basin
Exhibition Hall
Elemental geochemistry is widely used to characterize the depositional history of unconventional plays. Although this method can inform chronostratigraphic interpretations, there are risks involved in using the same dataset for paleoenvironmental reconstruction as well. Diachronous facies cannot be fully recognized with elemental geochemistry alone; it must integrated with other methodologies, such as stable carbon isotope chemostratigraphy. Diagnostic signals recorded by d13C curves in marine sedimentary rocks are well documented to be isochronous, facies independent, and highly resistant to late diagenetic alteration, making this a powerful tool for chronostratigraphic correlation. Elemental and stable isotope chemostratigraphy are integrated herein to investigate paleoenvironmental diachroneity in the Duvernay Formation, a mid-Frasnian carbonate-rich shale play in the Western Canada Basin. Twelve wells are included in the study: eight from the Kaybob area and four from Willesden Green. During the mid-Frasnian, these were partially isolated sub-basins, further compartmentalized by local reef build-ups. Changes in paleoredox have been modelled between sub-basins using a multi-trace element approach, providing a framework for predicting the spatial and temporal distribution of preserved organic matter across the play. The timing of anoxia can be calibrated by a series of diagnostic d13Corg excursions, which are correlated with a high degree of confidence between wells. These fluctuations, which are interpreted as the mid-Frasnian “punctata Excursion” constrain the Duvernay Formation in the study wells to the transitans, punctata, and hassi conodont Biozones. Furthermore, they demonstrate that development of anoxia is not synchronous between the Kaybob and Willesden Green, or even between closely spaced wells. This fine-scale diachroneity occurs below the resolution of traditional biostratigraphic methods, underscoring to the applicability of stable carbon isotopes for chronostratigraphic correlation in unconventional plays. Elemental geochemistry is widely used to characterize the depositional history of unconventional plays. Although this method can inform chronostratigraphic interpretations, there are risks involved in using the same dataset for paleoenvironmental reconstruction as well. Diachronous facies cannot be fully recognized with elemental geochemistry alone; it must integrated with other methodologies, such as stable carbon isotope chemostratigraphy. Diagnostic signals recorded by d13C curves in marine sedimentary rocks are well documented to be isochronous, facies independent, and highly resistant to late diagenetic alteration, making this a powerful tool for chronostratigraphic correlation. Elemental and stable isotope chemostratigraphy are integrated herein to investigate paleoenvironmental diachroneity in the Duvernay Formation, a mid-Frasnian carbonate-rich shale play in the Western Canada Basin. Twelve wells are included in the study: eight from the Kaybob area and four from Willesden Green. During the mid-Frasnian, these were partially isolated sub-basins, further compartmentalized by local reef build-ups. Changes in paleoredox have been modelled between sub-basins using a multi-trace element approach, providing a framework for predicting the spatial and temporal distribution of preserved organic matter across the play. The timing of anoxia can be calibrated by a series of diagnostic d13Corg excursions, which are correlated with a high degree of confidence between wells. These fluctuations, which are interpreted as the mid-Frasnian “punctata Excursion” constrain the Duvernay Formation in the study wells to the transitans, punctata, and hassi conodont Biozones. Furthermore, they demonstrate that development of anoxia is not synchronous between the Kaybob and Willesden Green, or even between closely spaced wells. This fine-scale diachroneity occurs below the resolution of traditional biostratigraphic methods, underscoring to the applicability of stable carbon isotopes for chronostratigraphic correlation in unconventional plays. Panel_14949 Panel_14949 8:30 AM 5:00 PM
8:30 a.m.
Modified Method and Interpretation of Source Rock Pyrolysis for an Unconventional World
Exhibition Hall
Our understanding of unconventional reservoirs is evolving daily and never at a greater rate than the past 15 years. However, programmed pyrolysis methods developed in the 1970s are still used today to assess the present day organic matter quality and quantity of potential source rocks. More importantly the interpretive guidelines for unconventional reservoirs developed for the Barnett Shale int eh 80s and 90s are still being used to characterize organic matter quality and maturity of nearly all prospective unconventional plays new and old. Recent advancements in pyrolysis technology, manufacturing, training and communications have paved the way for organic screening via pyrolysis on larger numbers of samples with faster turnaround times. The results are now available for critical time sensitive decisions such as where to land a lateral and how to apply customized completions, but also feed development of more models and trend mapping. Investigation of pyrograms which now span a much larger range of organic matter types and maturities has exposed multiple caveats in the traditional pyrolysis method and the interpretive guidelines being applied to liquids rich source rocks. The most problematic of which are attributed to heavy hydrocarbon carryover from S1 to S2 which can complicate kerogen quality assessment, maturity determination and production quantity/quality estimate resulting in potential inconsistencies between maps/models and production. Pyrograms and comparative results from parallel samples run through different pyrolysis methods will be presented for discussion. Modified initial isotherm temperatures designed to volatize a larger range of hydrocarbon without cracking kerogen provide a possible solution to the heavy hydrocarbon carryover issues. Pyrograms generated from both a traditional temperature ramp and a more rapid pyrolysis temperature ramp are presented to fully investigate the effects on the S2 peak geometry/quantification as well as Tmax assessment. Furthermore we attempt to properly address maturity as a function of kerogen quality with several new concepts better using the raw data generated from our modified source rock pyrolysis method. Our understanding of unconventional reservoirs is evolving daily and never at a greater rate than the past 15 years. However, programmed pyrolysis methods developed in the 1970s are still used today to assess the present day organic matter quality and quantity of potential source rocks. More importantly the interpretive guidelines for unconventional reservoirs developed for the Barnett Shale int eh 80s and 90s are still being used to characterize organic matter quality and maturity of nearly all prospective unconventional plays new and old. Recent advancements in pyrolysis technology, manufacturing, training and communications have paved the way for organic screening via pyrolysis on larger numbers of samples with faster turnaround times. The results are now available for critical time sensitive decisions such as where to land a lateral and how to apply customized completions, but also feed development of more models and trend mapping. Investigation of pyrograms which now span a much larger range of organic matter types and maturities has exposed multiple caveats in the traditional pyrolysis method and the interpretive guidelines being applied to liquids rich source rocks. The most problematic of which are attributed to heavy hydrocarbon carryover from S1 to S2 which can complicate kerogen quality assessment, maturity determination and production quantity/quality estimate resulting in potential inconsistencies between maps/models and production. Pyrograms and comparative results from parallel samples run through different pyrolysis methods will be presented for discussion. Modified initial isotherm temperatures designed to volatize a larger range of hydrocarbon without cracking kerogen provide a possible solution to the heavy hydrocarbon carryover issues. Pyrograms generated from both a traditional temperature ramp and a more rapid pyrolysis temperature ramp are presented to fully investigate the effects on the S2 peak geometry/quantification as well as Tmax assessment. Furthermore we attempt to properly address maturity as a function of kerogen quality with several new concepts better using the raw data generated from our modified source rock pyrolysis method. Panel_14942 Panel_14942 8:30 AM 5:00 PM
8:30 a.m.
Detailed Sequence Stratigraphic Framework of the Middle Devonian Geneseo Formation of New York, USA: Implications for Unconventional Reservoir Quality and Distribution
Exhibition Hall
The Middle Devonian Geneseo Formation and lateral equivalents in the Northern Appalachian Basin constitute shale-gas plays with promising economic potential. Mudstone properties within the Geneseo are highly variable, and reflect an overall shallowing trend that corresponds to the westward progradation of the Catskill delta. High-resolution stratigraphy has allowed differentiation of genetically related packages, comprised of distinct lithofacies, with characteristic physical, biological, and chemical attributes. Correlation of this succession was conducted at the parasequence scale, and includes detailed descriptions of multiple drill cores and surface exposures, as well as subsurface mapping. Isopach maps were constructed to identify thickness trends and lateral variations of mudstone properties, and the Geneseo Formation has been differentiated into two discrete depositional sequences with three lithostratigraphic units (the Lower Geneseo, Fir Tree, and Upper Geneseo members). The Lower Geneseo Member overlies the Tully Formation, and where the latter is absent, its basal contact is marked by a pyritic-phosphatic lag (the Leicester Pyrite Bed; MFDLS). The Lower Geneseo is an organic-rich dark gray to grayish black mudstone succession with aggradational to progradational parasequence stacking patterns (HST). The Fir Tree Member unconformably overlies the Lower Geneseo, displays progradational-aggradational-retrogradational parasequence stacking patterns (LST and TST), and consists of silt-rich calcareous mudstones rich in auloporid tabulate corals, ostracodes, and small brachiopods. The Upper Geneseo displays aggradational to progradational parasequence stacking patterns (HST), and consists of dark gray silty mudstones and muddy siltstones with abundant wave/current ripples, graded beds, and evidence for extensive reworking and erosion. Reactivation of basement structures and syndepositional faulting appears to have strongly influenced accommodation during deposition of the Geneseo Formation. In particular, the N-S trending Clarendon-Linden Fault System seems to have acted as a western sediment barrier during Geneseo Time. Through the development of a fully integrated sequence stratigraphic framework that incorporates surface and subsurface data, reservoir quality and distribution in the Geneseo Formation can be evaluated away from sample control, and thus enhance the potential for future economic success of unconventional resource plays in this interval. The Middle Devonian Geneseo Formation and lateral equivalents in the Northern Appalachian Basin constitute shale-gas plays with promising economic potential. Mudstone properties within the Geneseo are highly variable, and reflect an overall shallowing trend that corresponds to the westward progradation of the Catskill delta. High-resolution stratigraphy has allowed differentiation of genetically related packages, comprised of distinct lithofacies, with characteristic physical, biological, and chemical attributes. Correlation of this succession was conducted at the parasequence scale, and includes detailed descriptions of multiple drill cores and surface exposures, as well as subsurface mapping. Isopach maps were constructed to identify thickness trends and lateral variations of mudstone properties, and the Geneseo Formation has been differentiated into two discrete depositional sequences with three lithostratigraphic units (the Lower Geneseo, Fir Tree, and Upper Geneseo members). The Lower Geneseo Member overlies the Tully Formation, and where the latter is absent, its basal contact is marked by a pyritic-phosphatic lag (the Leicester Pyrite Bed; MFDLS). The Lower Geneseo is an organic-rich dark gray to grayish black mudstone succession with aggradational to progradational parasequence stacking patterns (HST). The Fir Tree Member unconformably overlies the Lower Geneseo, displays progradational-aggradational-retrogradational parasequence stacking patterns (LST and TST), and consists of silt-rich calcareous mudstones rich in auloporid tabulate corals, ostracodes, and small brachiopods. The Upper Geneseo displays aggradational to progradational parasequence stacking patterns (HST), and consists of dark gray silty mudstones and muddy siltstones with abundant wave/current ripples, graded beds, and evidence for extensive reworking and erosion. Reactivation of basement structures and syndepositional faulting appears to have strongly influenced accommodation during deposition of the Geneseo Formation. In particular, the N-S trending Clarendon-Linden Fault System seems to have acted as a western sediment barrier during Geneseo Time. Through the development of a fully integrated sequence stratigraphic framework that incorporates surface and subsurface data, reservoir quality and distribution in the Geneseo Formation can be evaluated away from sample control, and thus enhance the potential for future economic success of unconventional resource plays in this interval. Panel_14950 Panel_14950 8:30 AM 5:00 PM
8:30 a.m.
A Traditional Approach to Using New Technology: Maximizing the Efficacy of Handheld X-Ray Florescence Data – An Example From the Rietavas Licence of Lithuania
Exhibition Hall
Handheld X-ray fluorescence (HHXRF) instruments are increasingly used to acquire elemental data in unconventional plays. Because the instruments provide a means to quickly acquire inorganic geochemical data by direct, high resolution, non-destructive analysis of cores, they are powerful tools in helping to understand unconventional resource plays. However, with the proliferation of HHXRF data acquisition, the basic concepts of geologically understanding elemental data have become somewhat forgotten; the need to understand the controls on elemental changes and combine elemental data with other datasets are often omitted from HHXRF studies, which greatly diminishes the usefulness of the datasets. A 14 well chemostratigraphic correlation of Ordovician and Silurian sediments from the Rietavas Licence of Lithuania constructed from data acquired by HHXRF and handheld magnetic susceptibility (HHMS) instruments will be presented. The correlation incorporates over 1000 HHXRF and HHMS determinations made by direct measurement of conventional cores at storage facilities in Lithuania and the UK. Although the correlation defined is chemostratigraphically robust, its geological significance would have remained enigmatic if the additional data outlined below had not been acquired. A lack of understanding of the controls on elemental and magnetic susceptibility data in any study, unconventional or conventional, greatly diminishes the amount information that can be gleaned from the data and can render chemostratigraphic correlations meaningless. Here, X-ray diffraction, petrographic, and TOC data were acquired from a subset of core samples and sedimentological logs were compiled for select cores. By integrating these traditional data with the hand held datasets, it is shown that key variables used to define the chemostratigraphic correlation are responding to paleosol development (Fe2O3, MS, MgO), marine productivity (P2O5), provenance (Zr, TiO2), paleoredox (U, Mo, V) and facies (Al2O3, SiO2, CaO, MgO). Not only does this provide context to the chemostratigraphic correlation, it adds to understanding the depositional evolution of study intervals. This “return-to-basics” approach to using HHXRF data provides a clear demonstration that when carefully interpreted, elemental data acquired by direct analysis of core, using handheld instruments, is able to provide enhanced stratigraphic and geological understanding in subsurface studies. Handheld X-ray fluorescence (HHXRF) instruments are increasingly used to acquire elemental data in unconventional plays. Because the instruments provide a means to quickly acquire inorganic geochemical data by direct, high resolution, non-destructive analysis of cores, they are powerful tools in helping to understand unconventional resource plays. However, with the proliferation of HHXRF data acquisition, the basic concepts of geologically understanding elemental data have become somewhat forgotten; the need to understand the controls on elemental changes and combine elemental data with other datasets are often omitted from HHXRF studies, which greatly diminishes the usefulness of the datasets. A 14 well chemostratigraphic correlation of Ordovician and Silurian sediments from the Rietavas Licence of Lithuania constructed from data acquired by HHXRF and handheld magnetic susceptibility (HHMS) instruments will be presented. The correlation incorporates over 1000 HHXRF and HHMS determinations made by direct measurement of conventional cores at storage facilities in Lithuania and the UK. Although the correlation defined is chemostratigraphically robust, its geological significance would have remained enigmatic if the additional data outlined below had not been acquired. A lack of understanding of the controls on elemental and magnetic susceptibility data in any study, unconventional or conventional, greatly diminishes the amount information that can be gleaned from the data and can render chemostratigraphic correlations meaningless. Here, X-ray diffraction, petrographic, and TOC data were acquired from a subset of core samples and sedimentological logs were compiled for select cores. By integrating these traditional data with the hand held datasets, it is shown that key variables used to define the chemostratigraphic correlation are responding to paleosol development (Fe2O3, MS, MgO), marine productivity (P2O5), provenance (Zr, TiO2), paleoredox (U, Mo, V) and facies (Al2O3, SiO2, CaO, MgO). Not only does this provide context to the chemostratigraphic correlation, it adds to understanding the depositional evolution of study intervals. This “return-to-basics” approach to using HHXRF data provides a clear demonstration that when carefully interpreted, elemental data acquired by direct analysis of core, using handheld instruments, is able to provide enhanced stratigraphic and geological understanding in subsurface studies. Panel_14954 Panel_14954 8:30 AM 5:00 PM
8:30 a.m.
A Petrophysical Method to Estimate Fractures From Standard Open-Hole Logs
Exhibition Hall
For a realistic approach of the potential of unconventional reservoirs, it is important to assess the degree of fracturing – both open and healed (cemented) fractures. The standard and most accurate approach is from interpretation of image logs. However, there are many areas where image logs have not been run, although there will probably be an abundance of standard open-hole logs. The procedure described here involves the interpretation of standard open-hole logs and consists of examining rates of change of curve magnitudes with depth. If the change to apparent high porosity cannot be reasonably explained as a consequence of depositional variations, an open fracture is assumed. Conversely, if the change is to low porosity, a healed (cemented) fracture is assumed. All log traces, as well as the caliper and density correction curves are examined. For each log, the interpreter defines a minimum change in curve magnitude from one depth increment to the next. Additionally, a minimum change over a defined depth window is defined. Results of fracture identification from individual logs are stacked to identify potential fracture clusters. By comparing this analysis with image logs over the same intervals, we have found that there is good correlation, especially if clusters occur. It is understood that log resolution does not allow identification of individual fractures. However fracture swarms can be recognized. Examples of the technique from a variety of reservoirs are included. For a realistic approach of the potential of unconventional reservoirs, it is important to assess the degree of fracturing – both open and healed (cemented) fractures. The standard and most accurate approach is from interpretation of image logs. However, there are many areas where image logs have not been run, although there will probably be an abundance of standard open-hole logs. The procedure described here involves the interpretation of standard open-hole logs and consists of examining rates of change of curve magnitudes with depth. If the change to apparent high porosity cannot be reasonably explained as a consequence of depositional variations, an open fracture is assumed. Conversely, if the change is to low porosity, a healed (cemented) fracture is assumed. All log traces, as well as the caliper and density correction curves are examined. For each log, the interpreter defines a minimum change in curve magnitude from one depth increment to the next. Additionally, a minimum change over a defined depth window is defined. Results of fracture identification from individual logs are stacked to identify potential fracture clusters. By comparing this analysis with image logs over the same intervals, we have found that there is good correlation, especially if clusters occur. It is understood that log resolution does not allow identification of individual fractures. However fracture swarms can be recognized. Examples of the technique from a variety of reservoirs are included. Panel_14953 Panel_14953 8:30 AM 5:00 PM
8:30 a.m.
A Comparison of Handheld Energy-Dispersive X-Ray Fluorescence (HH-ED-XRF) Techniques for the Evaluation of Core and Cuttings Chemostratigraphy: Examples From Late Cretaceous Strata, South Texas
Exhibition Hall
Energy dispersive x-ray fluorescence (ED-XRF) has become a mainstay geochemical technique in the petroleum industry, especially in the analysis of mudstone-dominated successions. In the last few years ED-XRF has been utilized to generate supporting data sets, with applications ranging from directional drilling to reservoir characterization and optimization in unconventional plays. It is also used to generate data sets for correlation, elementally-defined mineralogical variability, and facies discrimination. With all of the emphasis on generating geochemical/chemostratigraphic data sets, it is important to define the limitations, errors, and best-practice strategies for generating the most useful results. In order to optimize the quality and usability of ED-XRF data sets, a rigorous approach to sample preparation and measurement techniques should be taken. If done properly, an ED-XRF analysis of a slabbed drill core face has the potential to yield quantitative geochemical results that help quantify individual facies and the degree of facies variability—at a range of scales, from fractions of an inch to feet, depending upon the requirements of the study. The spatial resolution of a well cuttings geochemical data set may be on the order of ten to thirty feet, and the retrieved samples are much more susceptible to contamination with respect to samples taken from drill core. The positive attribute of well cuttings is that they are far more accessible. Scanning of unconsolidated cuttings in sample cups is the easiest and fastest method for undertaking XRF analysis; however, pulverizing and pelletizing the cuttings before scanning ensures a more homogeneous matrix and increases the sensitivity to (and accuracy of) lighter major element concentrations (e.g., Na through Ca). In essence, the pelletized powder from a well cuttings sample mimics the slabbed face of a core, providing the optimal form of sample. Geochemical results from a Cretaceous Eagle Ford shale drill core and the accompanying set of well cuttings are evaluated in order to demonstrate the limits, pitfalls, and benefits of the various methods of generating XRF data sets. Energy dispersive x-ray fluorescence (ED-XRF) has become a mainstay geochemical technique in the petroleum industry, especially in the analysis of mudstone-dominated successions. In the last few years ED-XRF has been utilized to generate supporting data sets, with applications ranging from directional drilling to reservoir characterization and optimization in unconventional plays. It is also used to generate data sets for correlation, elementally-defined mineralogical variability, and facies discrimination. With all of the emphasis on generating geochemical/chemostratigraphic data sets, it is important to define the limitations, errors, and best-practice strategies for generating the most useful results. In order to optimize the quality and usability of ED-XRF data sets, a rigorous approach to sample preparation and measurement techniques should be taken. If done properly, an ED-XRF analysis of a slabbed drill core face has the potential to yield quantitative geochemical results that help quantify individual facies and the degree of facies variability—at a range of scales, from fractions of an inch to feet, depending upon the requirements of the study. The spatial resolution of a well cuttings geochemical data set may be on the order of ten to thirty feet, and the retrieved samples are much more susceptible to contamination with respect to samples taken from drill core. The positive attribute of well cuttings is that they are far more accessible. Scanning of unconsolidated cuttings in sample cups is the easiest and fastest method for undertaking XRF analysis; however, pulverizing and pelletizing the cuttings before scanning ensures a more homogeneous matrix and increases the sensitivity to (and accuracy of) lighter major element concentrations (e.g., Na through Ca). In essence, the pelletized powder from a well cuttings sample mimics the slabbed face of a core, providing the optimal form of sample. Geochemical results from a Cretaceous Eagle Ford shale drill core and the accompanying set of well cuttings are evaluated in order to demonstrate the limits, pitfalls, and benefits of the various methods of generating XRF data sets. Panel_14946 Panel_14946 8:30 AM 5:00 PM
8:30 a.m.
Using XRF, SEM and Pyrolysis for an Economic Appraisal of the Marcellus Formation of Western Pennsylvania for Fracking Purposes
Exhibition Hall
An analysis of a core from the Marcellus Formation of Western Pennsylvania was undertaken using 3 laboratory tools; an XRF, SEM with EDX capability and a HAWK pyrolysis instrument. A 4th parameter was porosity measurements from a PHIE and PHIT neutron emitting tool,. Unexpected relationships emerged from a comparison between the various downhole curves. Hydrocarbons that were generated from kerogen pyrolysis (S2) varied directly with the neutron probe's total porosity. Macroporosity (SEM >5 microns) varied more closely with the TOC. Macroporosity also varied with the siliceous microfossil content, particularly radiolaria within the Marcellus and unknown shell hash in the overlying Burkett and paralleled the free silica. The “free oil” S1 showed a similar distribution to the S2 and indicated 3 prospective sweetspots; Lower Marcellus, Upper Marcellus and Burkett. Carbonate horizons showed low porosity, due to the presence of clay. The SEM also showed the limestones were extensively bioturbated, shelly and phosphatic. Pyrolysis showed they had low TOC. The carbonate rich relatively oxidizing paleoenvironment allowed for the presence of burrowing organisms. The rest of the Marcellus seemed to have been deposited under very anoxic conditions and was largely composed of silty clay, siltiest near the base of the formation. The zones of lowest clay content (Middle of the Lower Marcellus "transgressive systems tract") also had highest macroporosity, highest oil content (S1, S2), and probably correspond to the best sweet spot. Organic richness is very good within the Marcellus, ranging between 2 and 12 % TOC and so is the source potential (S2 often greater than 5 mg hydrocarbons/g rock). The Burkett - Tully Limestone often had greater than 2% TOC. Tmax maturity data showed the Marcellus to lie in the condensate/wet gas window (Tmax of 455 – 475 °C). The Lower Marcellus sweet spot had a relatively low clay and high silt content that makes it the best, candidate for fracking. This zone had good brittleness and high hydrocarbons content (S1 and S2). At the base of the Marcellus and immediately above the Onondaga Limestone, a very thin zone of extreme ductility occurs, that probably corresponds to a bentonitic ash layer. The combination of detailed lithological analyses with an appraisal of the hydrocarbons within the Marcellus and adjacent Formations, allows their zonation in terms of potential economic productivity and engineering suitability for fracking purposes. An analysis of a core from the Marcellus Formation of Western Pennsylvania was undertaken using 3 laboratory tools; an XRF, SEM with EDX capability and a HAWK pyrolysis instrument. A 4th parameter was porosity measurements from a PHIE and PHIT neutron emitting tool,. Unexpected relationships emerged from a comparison between the various downhole curves. Hydrocarbons that were generated from kerogen pyrolysis (S2) varied directly with the neutron probe's total porosity. Macroporosity (SEM >5 microns) varied more closely with the TOC. Macroporosity also varied with the siliceous microfossil content, particularly radiolaria within the Marcellus and unknown shell hash in the overlying Burkett and paralleled the free silica. The “free oil” S1 showed a similar distribution to the S2 and indicated 3 prospective sweetspots; Lower Marcellus, Upper Marcellus and Burkett. Carbonate horizons showed low porosity, due to the presence of clay. The SEM also showed the limestones were extensively bioturbated, shelly and phosphatic. Pyrolysis showed they had low TOC. The carbonate rich relatively oxidizing paleoenvironment allowed for the presence of burrowing organisms. The rest of the Marcellus seemed to have been deposited under very anoxic conditions and was largely composed of silty clay, siltiest near the base of the formation. The zones of lowest clay content (Middle of the Lower Marcellus "transgressive systems tract") also had highest macroporosity, highest oil content (S1, S2), and probably correspond to the best sweet spot. Organic richness is very good within the Marcellus, ranging between 2 and 12 % TOC and so is the source potential (S2 often greater than 5 mg hydrocarbons/g rock). The Burkett - Tully Limestone often had greater than 2% TOC. Tmax maturity data showed the Marcellus to lie in the condensate/wet gas window (Tmax of 455 – 475 °C). The Lower Marcellus sweet spot had a relatively low clay and high silt content that makes it the best, candidate for fracking. This zone had good brittleness and high hydrocarbons content (S1 and S2). At the base of the Marcellus and immediately above the Onondaga Limestone, a very thin zone of extreme ductility occurs, that probably corresponds to a bentonitic ash layer. The combination of detailed lithological analyses with an appraisal of the hydrocarbons within the Marcellus and adjacent Formations, allows their zonation in terms of potential economic productivity and engineering suitability for fracking purposes. Panel_14952 Panel_14952 8:30 AM 5:00 PM
8:30 a.m.
Introduction of MicroScope HD in the Permian Basin: Revealing the Hidden Fracture Complexity in the Wolfcamp
Exhibition Hall
The Wolfcamp shale is an oil-rich source rock in the Delaware Basin being targeted for horizontal drilling. The play exhibits a fairly high degree of heterogeneity in rock characteristics, lithology and natural fractures. Particularly, presence of these natural fractures can indicate potentially better reservoir quality (RQ) as well as provide information for better completion quality (CQ). After drilling several horizontal wells in the Delaware Basin that were not producing uniformly, Endeavor Energy recognized that LWD technology would be required to overcome the geological challenges that were impeding production. Schlumberger implemented MicroScope (Imaging-While-Drilling tool) in some of the exploration wells which provided full borehole coverage electrical images and laterolog resistivity measurements. The recorded mode borehole images were then used to accurately identify different fracture types and orientations for an effective completion strategy. Instead of setting equally spaced fracture stages along the lateral, a better completion design with fewer and more strategically placed stages was achieved. This helped in delivering a successful well by increasing the reservoir contact through stimulating the existing natural fracture network. Since Endeavor started using the MicroScope LWD imaging tool for geosteering and then for fracture detection, they were able to achieve successful drilling operations and completion, while improving recovery. Schlumberger then provided MicroScope HD high-definition imaging-while-drilling service in one of the wells which has identified far more number of fractures, leading to better RQ and CQ analysis. MicroScope HD high-definition imaging-while-drilling service provides borehole images for reservoir description, from structural modeling to sedimentology analysis. This service enables detailed fracture characterization and completion optimization in conductive drilling fluids. The interpretation included full structural feature identification and detailed fracture characterization to identify types of fractures as well as morphology and geometry of each fracture, the fracture density, fracture aperture and fracture distribution along the logged interval. The geological interpretation of the MicroScope HD images revealed the presence of few major open fractures that were likely enhanced during drilling, and a large number of partial discontinuous conductive and resistive fractures. The Wolfcamp shale is an oil-rich source rock in the Delaware Basin being targeted for horizontal drilling. The play exhibits a fairly high degree of heterogeneity in rock characteristics, lithology and natural fractures. Particularly, presence of these natural fractures can indicate potentially better reservoir quality (RQ) as well as provide information for better completion quality (CQ). After drilling several horizontal wells in the Delaware Basin that were not producing uniformly, Endeavor Energy recognized that LWD technology would be required to overcome the geological challenges that were impeding production. Schlumberger implemented MicroScope (Imaging-While-Drilling tool) in some of the exploration wells which provided full borehole coverage electrical images and laterolog resistivity measurements. The recorded mode borehole images were then used to accurately identify different fracture types and orientations for an effective completion strategy. Instead of setting equally spaced fracture stages along the lateral, a better completion design with fewer and more strategically placed stages was achieved. This helped in delivering a successful well by increasing the reservoir contact through stimulating the existing natural fracture network. Since Endeavor started using the MicroScope LWD imaging tool for geosteering and then for fracture detection, they were able to achieve successful drilling operations and completion, while improving recovery. Schlumberger then provided MicroScope HD high-definition imaging-while-drilling service in one of the wells which has identified far more number of fractures, leading to better RQ and CQ analysis. MicroScope HD high-definition imaging-while-drilling service provides borehole images for reservoir description, from structural modeling to sedimentology analysis. This service enables detailed fracture characterization and completion optimization in conductive drilling fluids. The interpretation included full structural feature identification and detailed fracture characterization to identify types of fractures as well as morphology and geometry of each fracture, the fracture density, fracture aperture and fracture distribution along the logged interval. The geological interpretation of the MicroScope HD images revealed the presence of few major open fractures that were likely enhanced during drilling, and a large number of partial discontinuous conductive and resistive fractures. Panel_14945 Panel_14945 8:30 AM 5:00 PM
8:30 a.m.
Optimized Hydraulic Fracture Design: Using High-Resolution Borehole Images for 3-D Structural Delineation in Horizontal Shale Wells
Exhibition Hall
Designing and executing an optimized well completion design is of top priority for operators in unconventional plays. High-resolution wellbore image data is critical in identifying structural features that can significantly impact hydraulic fracturing effectiveness. Quanta-Geo, a new imaging technology, paired with eXpandBG, a well-centric structural modeling workflow, provides a new level of detail in reservoir analysis. Interpretation of Quanta-Geo images can identify, characterize, and map faults, fractures, and rock texture, allowing for smart completion design and, ultimately, increased production. This study focuses on lateral wells drilled into the upper Eagle Ford Shale play in South Texas, USA, where 3D seismic data has been acquired and interpreted. Faults, both regional and sub-seismic scale, are common across the acreage. There is also multiple water bearing zones overlying and underlying the target interval. The key to successful field development in this area is to distinguish which faults may present a hazard while drilling or during the stimulation process. If a wellbore is connected to a water hazard (via fault or hydraulic fracture), it has a high potential for failure. The first two wells in this area were stimulated without detailed analysis of the image logs. The end result was two wells drilled parallel off of the same pad that cost over $6MM each and a) produced with over a 95% water cut and b) failed to meet economics by a significant margin. Subsequent wells used the interpretation of the Quanta-Geo data to optimize the frac design. A significant fault was identified and appeared to be a potential hazard for water influx into the wellbore. This time, the operator attempted to mitigate the risk of water production by implementing a 350 foot safe zone on both sides of the subject fault during the completion and stimulation planning phase. The result for these wells was more positive as both produced at a normal water cut and showed no indication of a connection to water zone. This study provides a clear demonstration of how sub-seismic scale structural features can significantly affect well performance. High resolution image data upscaled to a well-centric structural model is critical to success in these wells. Completion designs that incorporate these models are essential to maximize production. Designing and executing an optimized well completion design is of top priority for operators in unconventional plays. High-resolution wellbore image data is critical in identifying structural features that can significantly impact hydraulic fracturing effectiveness. Quanta-Geo, a new imaging technology, paired with eXpandBG, a well-centric structural modeling workflow, provides a new level of detail in reservoir analysis. Interpretation of Quanta-Geo images can identify, characterize, and map faults, fractures, and rock texture, allowing for smart completion design and, ultimately, increased production. This study focuses on lateral wells drilled into the upper Eagle Ford Shale play in South Texas, USA, where 3D seismic data has been acquired and interpreted. Faults, both regional and sub-seismic scale, are common across the acreage. There is also multiple water bearing zones overlying and underlying the target interval. The key to successful field development in this area is to distinguish which faults may present a hazard while drilling or during the stimulation process. If a wellbore is connected to a water hazard (via fault or hydraulic fracture), it has a high potential for failure. The first two wells in this area were stimulated without detailed analysis of the image logs. The end result was two wells drilled parallel off of the same pad that cost over $6MM each and a) produced with over a 95% water cut and b) failed to meet economics by a significant margin. Subsequent wells used the interpretation of the Quanta-Geo data to optimize the frac design. A significant fault was identified and appeared to be a potential hazard for water influx into the wellbore. This time, the operator attempted to mitigate the risk of water production by implementing a 350 foot safe zone on both sides of the subject fault during the completion and stimulation planning phase. The result for these wells was more positive as both produced at a normal water cut and showed no indication of a connection to water zone. This study provides a clear demonstration of how sub-seismic scale structural features can significantly affect well performance. High resolution image data upscaled to a well-centric structural model is critical to success in these wells. Completion designs that incorporate these models are essential to maximize production. Panel_14944 Panel_14944 8:30 AM 5:00 PM
The rise of unconventional resources has fostered and necessitated a "back-to-the-rocks" approach to reservoir analysis. This group of presentations will showcase insights and innovations involving contemporary core analysis, and participants will have the opportunity to see the "raw data." Not only will presenters discuss core-based studies, but you will also view core samples used in those studies. Presentations will cover a range of topics including natural fractures, geochemistry and chemostratigraphy, ichnology and sedimentology, tight oil plays, analysis pores and pore systems.

The rise of unconventional resources has fostered and necessitated a "back-to-the-rocks" approach to reservoir analysis. This group of presentations will showcase insights and innovations involving contemporary core analysis, and participants will have the opportunity to see the "raw data." Not only will presenters discuss core-based studies, but you will also view core samples used in those studies. Presentations will cover a range of topics including natural fractures, geochemistry and chemostratigraphy, ichnology and sedimentology, tight oil plays, analysis pores and pore systems.

Panel_14416 Panel_14416 8:30 AM 5:00 PM
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Alicia Collins Events Coordinator +1 918 560 2616
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