Whidden, Katherine (U.S. Geological Survey) | Birdwell, Justin (U.S. Geological Survey) | Dumoulin, Julie (U.S. Geological Survey) | Fonteneau, Lionel (Corescan Pty Ltd) | Martini, Brigette (Corescan Pty Ltd)
The Middle – Upper Triassic Shublik Formation is an organic-rich heterogeneous carbonate-siliciclastic-phosphatic unit that generated much of the oil in the Prudhoe Bay field and other hydrocarbon accumulations in northern Alaska. A large dataset, including total organic carbon (TOC), X-ray diffraction (XRD), X-ray fluorescence (XRF) and inductively coupled plasma – mass spectrometry (ICP-MS) measurements, has been built from core and outcrop samples of the Shublik, with a focus on the organic-rich intervals. In addition, two core intervals from the Shublik were analyzed using a hyperspectral imaging system in the visible, near-infrared and shortwave-infrared range. Integration of the hyperspectral results with core descriptions, microfacies interpretations, and analytical data is being used to decipher mudstone depositional and diagenetic processes.
Petrographic analysis of Upper Triassic organic-rich intervals within the Shublik suggests that the main microfacies is a laminated bioclastic wackestone/packstone that was episodically disrupted by energetic events of variable intensity. These energetic events produced transitional and sparry calcite bioclastic packstone to grainstone intervals, depending on the depth of sediment column disturbance. By using hyperspectral imaging data from the Ikpikpuk core, individual distribution maps for minerals of interest have been generated and corroborate the microfacies interpretations. These maps also illustrate small-scale vertical changes in mineralogy. The laminated bioclastic wackestone/packstone intervals contain less calcite than the adjacent sparry bioclastic packstone to grainstone intervals. The calcite in these laminated intervals is more iron rich. This interpretation suggests that lower iron concentrations should be expected in the disrupted intervals than in nearby laminated intervals. Textural features are also enhanced in the hyperspectral images relative to visual description of the cores by combining the extraction of the average reflectance in the visible part of the electromagnetic spectrum and the depth of the main carbonate-related feature belonging to calcite. Examples noted in the enhanced imagery include low-angle features, calcite grain-size, and the size, shape and orientation of phosphatic nodules. This enhancement is being used to differentiate laminated from sparry bioclastic packstone to grainstone-rich intervals and provides a more comprehensive assessment of the microfacies than is practical by thin-section analysis.
The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.
Morton, Sarah L. C. (Kansas Geological Survey, formerly U.S. Geological Survey) | Lane, John W. (U.S. Geological Survey) | Thomas, Margaret A. (Connecticut Geological Survey, Department of Energy and Environmental Protection) | Liu, Lanbo (University of Connecticut, Department of Civil and Environmental Engineering)
Five new seismic hazard classifications for Hartford County, Connecticut (CT), were proposed by New England State Geologists (NESG) in an effort to improve the current USGS Seismic Hazard Map. These classes were derived from mapped surficial materials, but in situ information is required to verify this approach. Therefore, active and passive surface wave techniques were performed at thirty field sites to determine VS30 and compare the results to the NESG map. Passive data were processed using the Horizontal-to-Vertical Spectral Ratio (HVSR); active data were processed with the multi-channel analysis of surface waves (MASW) technique. The field investigation demonstrated that the surficial material-based system was not sufficient for 66% of the field sites and in-situ velocity information from at least two methods should be considered for improved classification. The geophysical work discussed here represents the first field de-rived VS30 values for Hartford County, CT.
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 204A (Anaheim Convention Center)
Presentation Type: Oral
Geophysical tomographic methods provide high-resolution information about subsurface geologic structure, hydraulic and geotechnical properties, pore-fluid distribution, and time-varying hydrologic conditions. Electrical, electromagnetic, seismic and ground-penetrating radar measurements collected from surface and (or) cross-hole configurations are inverted to produce two-dimensional, three-dimensional, or four-dimensional (three spatial dimensions plus time) images of the subsurface. Over the last two decades, advances in instrumentation have led to more rapid data acquisition, while advances in modeling, inversion, and computational resources have facilitated time-lapse monitoring, consideration of more rigorous measurement physics, coupled or joint inversion of multiple data types, improved uncertainty quantification, model order reduction, and more routine application of image appraisal techniques. Here, we provide an overview of the current state of the research, remaining challenges, and the path forward for geophysical tomography.
We acquired microtremor array data at 11 sites in the Seattle basin, Washington State, and applied the wavenumber-normalized SPAC method (krSPAC) to obtain
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 213B (Anaheim Convention Center)
Presentation Type: Oral
There is a critical and growing need for information about subsurface geological properties and processes over sufficiently large areas that can inform key scientific and societal studies. Airborne geophysical methods fill a unique role in Earth observation because of their ability to detect deep subsurface properties at regional scales and with high spatial resolution that cannot be achieved with groundbased measurements. Airborne electromagnetics, or AEM, is one technique that is rapidly emerging as a foundational tool for geological mapping, with widespread application to studies of water and mineral resources, geologic hazards, infrastructure, the cryosphere, and the environment. Applications of AEM are growing worldwide, with rapid developments in instrumentation and data analysis software. In this study, we summarize several recent hydrogeophysical applications of AEM, including examples drawn from a recent survey in the Mississippi Alluvial Plain (MAP). In addition, we discuss developments in computational methods for geophysical and geological model structural uncertainty quantification using AEM data, and how these results are used in a sequential hydrogeophysical approach to characterize hydrologic parameters and prediction uncertainty.
Presentation Date: Wednesday, October 17, 2018
Start Time: 8:30:00 AM
Location: 213B (Anaheim Convention Center)
Presentation Type: Oral
ABSTRACT: Enhanced reservoir connectivity generally requires maximizing the intersection between hydraulic fracture (HF) and preexisting underground natural fractures (NF), while having the hydraulic fracture continue to propagate across the natural fractures. Observations of downhole core samples suggest that these natural fractures are in fact veins filled with minerals such as calcite (Mighani et al., 2016). We study this interaction during the approach of a hydraulic fracture to a smooth saw-cut fracture under triaxial stress conditions. The specimen is Solnhofen limestone, a fine-grained (<5 μm grain), low permeability (<10 nD) carbonate. The differential stress (1-20 MPa) and inclination of the fault which determines the approach angle, θ (30, 60°) are the experimental variables. We conduct the experiments on both bare surface and gouge-filled fault surfaces. The gouge is a 1 mm thick crushed powder of Solnhofen limestone with <106 μm grain size. During the hydraulic fracture, acoustic emissions (AE), inferred slip velocity, axial stress and pore pressure are recorded at a 5 MHz sampling rate.
The hydraulic fracture was able to cross the bare surface fault with small induced fault slip. The fault gouge increased the coefficient of friction significantly from 0.12 (bare, polished surface) to > 0.44 (gouged layer). However, the gouge-filled fault arrested the hydraulic fracture and generated a slip event with different characteristics: 1- The stress drop was larger while the generated AE signals had lower magnitude. 2- Slip velocity recorded by the vibrometer was of the same order of magnitude for the bare and gouge- filled faults, but the slip duration increased from 29 μsec for bare surface to ~2.5 msec (~90 times longer rise time) for the gouge- filled fault. The experiments suggest that the gouge-filled fault can accommodate much larger displacement while promoting slow slip on the fault which is harder to detect as AE signals. The observed long duration slip events are similar to the field observations of the long period and long duration (LPLD) events during the stimulation of clay-rich shale formations (Zoback et al., 2012). While the intrinsic low strength, high ductility, and unfavorably oriented natural fractures in shale formations are expected to reduce the occurrence of induced seismicity, our experiments suggest an additional mechanism for the observed LPLD events, i.e. the role of fault gouge. They also suggest that the microseismic detection techniques may under-predict the stimulated volume as the activation of natural gouge-filled fractures may proceed aseismically.
Hydraulic fracture (HF) operations have been extensively used over the years to increase the productivity of low- permeability hydrocarbon reservoirs. The intersection of hydraulic fractures with present underground natural fractures is proven as a major factor in increasing the productivity of the shale gas reservoirs (Mayerhofer et al., 2010). Microseismic observations (Mayerhofer et al., 2010) and mined-back downhole samples from field operations (Warpinski and Teufel, 1987) support the importance of natural fractures and their activation during the operation. Understanding the necessary conditions for the activation of natural fractures, the expected slip magnitude and enhanced fluid transmissivity, and the impact of this slip on the hydraulic fracture path is a key to understanding the role of hydraulic fracture in enhanced recovery operations.
ABSTRACT: Geologically diverse landforms around the world show indications of energetic macroscale fracture. These fractures are sometimes displayed dramatically as so-called “A-tents”, whereby relatively thin rock sheets push upwards and fracture, forming tent-like voids beneath the ruptured sheets. The origin and formation of such features has been a topic of considerable interest and analysis for over a century. Here we show that thermally-induced stresses, coincident with particularly hot days during particularly hot years, were responsible for recent (2014-2016) energetic ruptures of rock sheets forming a granitic exfoliation dome in California, USA. Through a three-year field effort, we found that subcritical fracture occurred due to diurnal and seasonal cumulative thermal stresses. However, our analyses also indicate that subsequent critical fracture could only have been reached if thermal stresses acted in concert with existing tectonic stresses. Thus, we offer a superposition triggering mechanism (background tectonic stresses with cyclic thermal stresses) to explain these rock fracture features.
The process of natural rock fracture on the Earth's surface is rarely observed despite plentiful evidence in rock outcrops around the world. In cliff exposures (e.g., Stock et al., 2012; Collins and Stock, 2016; Ziegler et al., 2014) and in suficially deposited boulders (e.g., McFadden et al., 2005; Eppes et al., 2010, 2016), rocks show ample evidence of recent fracture. Given the tenents of geological time, it is logical to assign most such fractures a subcritical providence - that is, fracture occurring steadily over long time scales (Eppes and Keanini, 2017). Some evidence exists, however, of more rapid rock fracture - for example, those indicated by exfoliation fractures and related A-tents of rock, wherein slabs of rock are perched upon one another, seemingly uplifted away from the Earth's surface (e.g., Ericson and Olvmo, 2004; Twidale and Bourne, 2009). These and similar features (commonly termed exfoliation sheets) have long drawn the attention of geomorphologists (e.g., Gilbert, 1904; Jahns, 1943; Twidale, 1973; Holzhausen, 1989) but considerably less attention from the rock mechanics field (e.g., Martel, 2006, 2017).
Recently, the miscible CO2-EOR tertiary process used in the main pay zone (MP) of suitable reservoirs has broadened to include exploitation of the underlying residual oil zone (ROZ) where a significant amount of oil may remain. The objective of this study is to identify the ROZ and to assess the remaining oil in a brownfield ROZ by using core data and conventional well logs with probabilistic and predictive methods.
Core and log data from three wells located in the East Seminole Field in Gaines County, Texas, were used to identify the MP and ROZ in the San Andres Limestone, and to predict oil saturations. The core measurements were used to calculate probabilistic in-situ oil saturations within the MP and the ROZ as a function of depth. Well logs, in combination with core data and calculated saturations, on the other hand, were used to develop two expert systems using artificial neural networks (ANN); one to identify the ROZ and MP, and the other to predict oil saturation. These systems were also supported by a classification and regression tree (CART) analysis to delineate the rules that lead to classifications of zones.
Results showed that expert systems developed and calibrated by combining core and well log data can identify MP and ROZ with a success score of more than 90%. Saturations within these zones can be predicted with a correlation coefficient of around 0.6 for testing and 0.8 for training data. The analyses showed that neutron porosity and density well log readings are the most influential ones to identify zones in this field and to predict oil saturations in the MP and ROZ. To explain the relationships of input data with the results, a rule-based system was also applied, which revealed the underlying petrophysical differences between MP and ROZ.
This new predictive approach using machine learning techniques, could potentially address the challenges that previous studies have come up against in defining the ROZ within the formation and quantifying remaining oil saturations. The method can potentially be applied to additional fields and help reliably identify the ROZ and estimate saturations for future resource evaluations.
Low-temperature hydrous pyrolysis (LTHP) at 300°C (572°F) for 24 h released retained oils from 12- to 20-mesh-size samples of mature Niobrara marly chalk and marlstone cores. The released oil accumulated on the water surface of the reactor, and is compositionally similar to oil produced from the same well. The quantities of oil released from the marly chalk and marlstone by LTHP are respectively 3.4 and 1.6 times greater than those determined by tight rock analyses (TRA) on aliquots of the same samples. Gas chromatograms indicated this difference is a result of TRA oils losing more volatiles and volatilizing less heavy hydrocarbons during collection than LTHP oils. Characterization of the rocks before and after LTPH by programmable open-system pyrolysis (HAWK) indicate that under LTHP conditions no significant oil is generated and only preexisting retained oil is released. Although LTHP appears to provide better predictions of quantity and quality of retained oil in a mature source rock, it is not expected to replace the more time and sample-size efficacy of TRA. However, LTHP can be applied to composited samples from key intervals or lithologies originally recognized by TRA. Additional studies on duration, temperature, and sample size used in LTHP may further optimize its utility.
The quantity and quality of oil retained in mature source rocks are important attributes in determining the potential of tight-oil accumulations. Retort methods using crushed rock such as “Tight Rock Analysis” (TRA) have been used to determine oil quantities (Handwerger et al. 2011 and 2012). Released TRA oil quantities are determined by volatilization of the retained oil in open-system pyrolysis at 316°C (600°F). Although this retort approach provides a rapid method for evaluating retained oil in numerous core samples in a timely manner, volatilization is not operative in the subsurface extraction of oil from tight-oil accumulations. As a result, TRA may not provide an accurate account of the quantity or quality of retained oil. Low-temperature hydrous pyrolysis (LTHP) provides an alternative to acquiring quantities and quality of retained oil in mature source rocks. LTHP, like TRA uses mature source rocks that are crushed between 12 and 20 mesh size. However, LTHP heats the rock in the presence of liquid water in a closed system at 300°C (572°F) for 24 hours. This condition is below the thermal-stress level typically required to generate oil from the thermal decomposition of bitumen and kerogen, but sufficient to release retained oil in a mature source rock. Under this condition, thermal expansion of pore fluids and reduced capillary forces releases retained oil, which accumulates on the water surface in the reactor during heating. The chalk and marlstone sequence of the Cretaceous Niobrara Formation in the Denver Basin provides an excellent test of this approach with both lithologies being a source and reservoir of retained oil to different degrees.