Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Petroleum Engineering, University of Houston, 2. Metarock Laboratories, 3. Department of Earth and Atmospheric Sciences, University of Houston) 16:00-16:30 Break and Walk to Bizzell Museum 16:30-17:30 Tour: History of Science Collections, Bizzell Memorial Library, The University of Oklahoma 17:30-19:00 Networking Reception: Thurman J. White Forum Building
- Research Report > New Finding (0.93)
- Overview (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.72)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (47 more...)
- North America > United States > Texas (1.00)
- Europe (0.93)
- Research Report > New Finding (0.93)
- Overview (0.88)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (49 more...)
Abstract The Early Triassic Montney Formation in western Canada hosts a world-class unconventional petroleum accumulation with a complex history of hydrocarbon charging from both external and internal source rocks. This study focuses on self-sourced hydrocarbons and their intraformational migration within the siltstone-dominated Montney Formation. A review of recent geochemical studies highlights evidence of three main widespread episodes of intraformational hydrocarbon migration. The first episode was characterized by the migration of early-generated oil from internal Montney organic-rich source rocks during rapid burial. The second episode consisted of gas-condensate migration during deep burial and over-pressuring. The final episode involved methane-rich gas migration, mainly during basin uplift and depressurization. Spatial and temporal relationships of these three migration episodes fit a dynamic model of hydrocarbon generation, hydrocarbon migration and pressure evolution tied to basin subsidence and uplift history. Intraformational migration of gas and condensate has direct economic impacts on Montney well performance, such as higher gas-oil ratios and lower hydrocarbon liquid contents than expected from routine thermal maturity proxies. The Montney Formation has abundant publicly available subsurface data and thus provides a well-documented analogue for evaluating intraformational hydrocarbon migration in other unconventional petroleum accumulations. Introduction Intraformational migration of hydrocarbons driven by the changing pressure, volume and temperature (PVT) conditions that accompany basin subsidence and uplift is gaining increased recognition as a common phenomenon in unconventional low-permeability petroleum accumulations (Han et al., 2015, 2019; Wood and Sanei, 2016; Zumberge et al., 2016; Ducros et al., 2017; Euzen et al., 2018, 2019, 2020, 2021; Wood et al., 2021a, 2022). Recognizing significant hydrocarbon migration episodes is important for assessing unconventional oil and gas plays because it provides a basis for understanding intricate geographic distributions of gas-oil ratio (GOR) or condensate-gas ratio (CGR) in terms of first-order thermal maturity trends and second-order migration trends (Wood and Sanei, 2016; Wood and Sanei, 2017; Wood et al., 2021a). Sound delineation of intraformational migration and consequent mixing of hydrocarbon fluids directly impacts play economics by enhancing the ability to target liquid-rich versus drier gas zones, depending on changing commodity prices or corporate resource-development strategy.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.51)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (39 more...)
Abstract As the petroleum industry builds long-term production histories in major liquid-rich unconventional resource (UCR) plays, development geologists and engineers have realized that the production gas oil ratio, petroleum type, and ultimate recoveries do not always match the predictive petroleum system models. Early studies suggested that the UCR petroleum systems require neither traditional petroleum traps nor major migration systems but an organic-rich source within optimal maturity window. Possible explanations for these production discrepancies that were not fully characterized in the initial models include uncertainties in source rock characteristics, primary migration fractionation, fractionation related to storage, and production fractionation. Long-term empirical observations suggest that off-structure migration contribution, trapping mechanisms, and reservoir phase (single versus two) play an important role in the liquid-rich UCR production. If the liquid-rich UCR petroleum system is a well-behaved predominantly local charge system, then the generation product can be estimated with an understanding of the local organic matter type and in situ level of maturity. However, if the UCR play is hybrid with significant migrated down-dip charge contribution, then a more complicated work program will be required to estimate well rates and volumes. The liquid-rich UCR play evaluation should reflect these additional factors, which can greatly impact surface production rate and liquid recovery.
- North America > United States > North Dakota (1.00)
- North America > United States > Texas (0.94)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- (2 more...)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (68 more...)
Abstract Quantifying hydrocarbon phase behavior in shale & tight formations is important for properly engineering and developing liquid rich shale (LRS) reservoir, forecasting liquid production, and improving EUR and production, and reliable experimental data are needed for calibrating/validating the theoretical models. In this paper, we will discuss our efforts in quantifying the confinement effects on phase behavior in S&T formations from both experimental study and numerical modeling. For the first time, one experiment design is provided to measure the fluid properties inside nanopore, including density, pressure, and composition. A Shale-PVT model has been developed for quantifying the fluid phase behavior in shale system. Experiment data are used in the calibration of molecular dynamic (MD) simulations. Then the lab data and MD results are utilized in the development of EOS, which is include in the Shale-PVT model to provide a robust understanding of the fluid inside shale reservoir. The Shale-PVT model is capable of modeling initial composition of hydrocarbon in place and producing fluid compositions during depletion at different reservoir conditions. The combination of lab study and modeling capability can also enable us to improve depletion and gas EOR designs. Introduction It has been well recognized that production from liquid-rich shale (LRS) reservoirs behaves very differently from conventional reservoirs due to very small pore size of shale rocks. However, the underlying physics behind multiphase fluid flow in unconventional tight reservoirs has not yet been fully understood. Based on pore sizes and fluid rock interactions, the hydrocarbon streams in shale formations can be divided into two categories (Sing 1985, Rouquerol, et al. 1994). First is the fluid in micro and macro fractures and large pores inside shale matrix. The interconnected micro and macro fracture network coupled with natural fracture provides pathways for fluid migration from the stimulated tight shale matrix into wells. Inside those fractures as well as large pores of shale matrix, the fluid phase behavior is determined by molecular interactions of the fluid, and impact of solid surface on fluid behaviors can be ignored due to the large pore size. As a results, the fluid phase behaviors can be described by bulk phase PVT. On the other hand, inside the nano pores in shale matrix, the fluid is confined by the nanopores, and the fluid phase behaviors will be dependent on both fluid molecule-fluid molecule and fluid molecule-pore surface interactions. The interactions between fluid molecules and pore surface may lead to heterogeneity in composition and/or density and dependency of phase behaviors on pore size and geometry. Therefore, a Shale-PVT model is required to properly describe fluid phase behaviors in nano pores, which is critical to estimate original hydrocarbon in place and compositions, understand depletion mechanism and efficiency, and evaluate EOR potential. For example, a better understanding of the phase behavior of multicomponent hydrocarbon fluids in nanopores will help to determine condensate blocking and its potential impact on well productivity, and to predict the GOR and CGR behaviors during production from shale reservoirs.
- North America > United States > Texas (0.46)
- North America > United States > Colorado (0.28)
- Research Report > Experimental Study (0.87)
- Research Report > New Finding (0.67)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
Abstract Organic-rich carbonates from the Upper Cretaceous period in southeastern Turkey are recognized as major unconventional hydrocarbon source rocks. A workflow for derisking the productivity of an unconventional play involves examining the S1 X 100/TOC ratios, which represent potentially producible fluid oil and gas volumes or the oil saturation index (OSI). Based on their organic matter content, fluid oil and biogenic gas saturations, maturity, and sorption coefficient, the Upper Cretaceous Karababa and Karabogaz formations in southeastern Turkey have the potential to produce fluid oil and biogenic gas. Introduction Organic-rich carbonates from the Upper Cretaceous period in the Middle East and North Africa, including southeastern Turkey, were deposited under dysoxic to anoxic conditions along the southern margins of the Tethys Ocean, resulting in the accumulation of abundant marine sapropelic organic matter (Beydoun, 1986; Tannenbaum and Lewan, 2002). These source rocks have been assessed as unconventional plays (Şen, 2014, 2016; Al-Bahar et al., 2019; Şen, 2022). The Upper Cretaceous Karababa and Karabogaz formations in southeastern Turkey extend from Osmaniye in the west to Diyarbakir in the east, covering an area nearly 300 km long and 150 km wide (Fig. 1). The organic-rich carbonates are similar to the unconventional fluid oil and biogenic gas-producing Niobrara Formation in North America. A workflow for de-risking productivity of an unconventional play is in part based on our examination of the S1 · 100/total organic carbon (TOC) ratios, which represent potentially producible oil, where S1 is obtained from Rock-Eval-II pyrolysis analysis and TOC from LECO measurement on samples. The S1 is referred to as the available "free" (Espitalie et al., 1977) or, more correctly, "volatile" hydrocarbons (Pepper, 1991; Pepper et al., 2019) retained within the rock. Although Jarvie (2012) suggested 100 mg HC/g TOC to sorption coefficient, recent studies have shown that the sorption coefficient ranges from 100 to 40 mg oil/g TOC for fluid oil and less than 40 mg HC/g TOC for biogenic gas based on maturity (Pepper et al., 2019; Şen and Kozlu, 2020; Şen, 2021).The aim of this study is to examine the potential producible fluid oil and biogenic gas saturations of the Upper Cretaceous carbonates in the northern Arabian plate of southern Turkey, based on their organic matter content, fluid oil and biogenic gas saturations, maturity, and sorption coefficient.
- North America > United States (1.00)
- Asia > Middle East > Turkey > Osmaniye Province > Osmaniye (0.24)
- Asia > Middle East > Turkey > Diyarbakir Province > Diyarbakir (0.24)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.61)
- (2 more...)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- (10 more...)
High-Resolution Core Study Relating Chemofacies to Reservoir Quality: Examples from the Permian Wolfcamp XY Formation, Delaware Basin, Texas
Putri, Shaskia Herida (Colorado School of Mines) | Jobe, Zane (Colorado School of Mines) | Wood, Lesli J. (Colorado School of Mines) | Melick, Jesse (Colorado School of Mines) | French, Marsha (Colorado School of Mines) | Pfaff, Katharina (Colorado School of Mines)
Abstract The Wolfcamp and Bone Spring Formations are comprised of siliciclastic and carbonate sediment gravity flow deposits, including turbidites and debrites that were sourced from multiple uplifted areas and deposited in the Delaware Basin, Texas during the early-middle Permian (Early Leonardian, ∼285 Ma). Deep-water lobe deposits in these formations are primary unconventional reservoir targets in the North-central Delaware Basin of Texas. Despite numerous recent reservoir characterization studies in this area, integrated multi-scale core-based studies relating to reservoir quality are sparsely published. This research aims to provide a workflow to better predict source rock and reservoir distribution by integrating geochemistry and petrophysical data from this deep-water depositional system. Using high-resolution (1 cm), continuous X-ray fluorescence (XRF) data from 218 feet of core from the Wolfcamp XY interval, this study focuses on the controls that depositional processes and diagenesis impart on chemofacies. Unsupervised k-means clustering and principal component analysis on 17 XRF-derived elemental concentrations derive four chemofacies that characterize geochemical heterogeneity: (1) calcareous, (2) oxic-suboxic argillaceous, (3) anoxic argillaceous, and (4) detrital mudrock. Results indicate that vertical, event-bed-scale variations in XRF-based chemofacies accurately represent depositional facies changes, often matching cm-by-cm the human-described lithofacies. This research demonstrates the relationship of chemofacies to petrophysical properties (e.g., total organic carbon, porosity, and water saturation), which can be used for log-based reservoir prediction of the Wolfcamp and Bone Spring Formations in the Permian Basin, as well as for other mixed clastic-carbonate deep-water reservoirs around the world. Introduction Mixed siliciclastic-carbonate mudstone unconventional reservoirs contain complex sub-well-log-scale heterogeneity in mineralogical composition due to depositional process variability (Lazar et al., 2015; Comerio et al., 2020, Kvale et al., 2020; Ochoa et al., 2022). Moreover, these lithofacies are organized as repetitive meter-scale sedimentation units that are linked to depositional-element architectural and sequence stratigraphic evolution (Thompson et al., 2018; Zhang et al., 2021). High-resolution core studies can help to capture fine-scale depositional units and diagenetic process (Baumgardner et al., 2014; Ochoa et al., 2022). Because it is difficult to visually observe the heterogeneity in mixed siliciclastic-carbonate mudstone cores, it is crucial to integrate quantitative petrophysical analyses with mineralogical and geochemical data to improve the accuracy of predictive models (Lazar et al., 2015; Ochoa et al., 2022).
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geophysics > Seismic Surveying (0.93)
- Geophysics > Borehole Geophysics (0.88)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- (55 more...)
Oil and Gas Generation, Migration, Production Prediction, and Reservoir Characterization of Northern Denver Basin: Implication from the Total Petroleum Systems
Rahman, Mohammad 'Wahid' (Impac Exploration Services, Inc. / Ossidiana Energy) | Fox, Mathew (Ossidiana Energy) | Kramer, Darrell (Ossidiana Energy) | Mullen, Chris (Ossidiana Energy)
Abstract The Denver-Julesburg (Dj) basin has multiple oils and gas producing unconventional reservoirs but the oil-source-reservoir correlation of hydrocarbon from these reservoirs are not well fingerprinted through detailed geochemistry dataset. It is important to determine the origin of hydrocarbons to estimate the hydrocarbon phase, GOR and production prediction. Many of these reservoir parameters vary based on the type of source rock and nature of its expulsion in varying PVT conditions. This study focuses on the detailed geochemistry from source rock, extracted oil, mud gas, and production gas and oil to determine the origin of the hydrocarbon stored in different Cretaceous intervals from Denver basin and their production equivalent phases. Geochemistry data were generated from cored rocks, cuttings, mud gas, extracted oils and compared with the produced gas and oils from the Denver basin. This article includes source rock analysis through Rock-Eval pyrolysis on cored and cuttings rocks, Leco-TOC, gas composition and compound specific isotopes via GC-IRMS, thermal extract gas chromatography (TEGC), high resolution gas chromatography, Gas Chromatography-Mass Spectrometry (GCMS) biomarker analysis on MPLC (medium pressure liquid chromatography) separated saturates and aromatics, bulk carbon isotope analysis on extracted oil and produced oil (Peters et al., 2005; Rahman et al., 2016; Rahman et al., 2017). Clayton and Swetland (1980) concluded that all the Cretaceous oils are compositionally similar throughout the basin. But the extracted oils from cored rock and cuttings and associated gas and oil data from several intervals from this study clearly depict there are significant differences in oils found in these Cretaceous reservoirs. Geochemistry data from source rock suggests that most of the organic matter in different Cretaceous source rocks are of Type II kerogen. However, the source rock differs in chemistry because of depositional environment associated with marine shale vs carbonate. It is evident from the pyrolysis, mud gas, and extracted oil chemistry data from the Denver basin that there are distinct differences in origin of oil and gas in these reservoirs. The major highpoints of this study are as follows: 1) the novel organic geochemistry data should be used to better characterize any basin for conventional and unconventional exploration and development; 2) this approach helps to model better petroleum systems, basin evaluation, and overall understanding of the quality of petroleum, expulsion histories, migration pathways and type of petroleum stored in rocks.
- North America > United States > Wyoming (1.00)
- North America > United States > Nebraska (1.00)
- North America > United States > Kansas (1.00)
- North America > United States > Colorado (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.36)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (47 more...)
Recent Advances and New Insights of Fiber Optic Techniques in Fracture Diagnostics Used for Unconventional Reservoirs
Nath, Fatick (School of Engineering, Texas A&M International University, Laredo) | Hoque, S. M. Shamsul (School of Geosciences, University of Louisiana at Lafayette) | Mahmood, Md. Nahin (Petroleum Engineering, University of Louisiana at Lafayette)
Abstract Technological advancements in well completion and stimulation have resulted in record production and considerable growth in global unconventional markets. However, the connection of the wellbore to hydrocarbon resource volumes by effective fracture stimulation is a critical factor in unconventional reservoir completions. Fiber optic (FO) techniques are gaining confidence among researchers for a better understanding of fracture diagnostics, visualization of the created hydraulic fractures, and identifying the proppant placement in the deep formation. Several notable outcomes have been observed recently in this emerging field. This paper investigates the recent advances and future opportunities in FO measurements for evaluating the stimulation performance in unconventional reservoirs. FO technique - Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) cover the way to overcome the lack of knowledge in fracture diagnosis. Advances in this technique address challenges of fracture diagnostic between new cracks and reactivation of existing cracks, understanding fracture geometry, strain field, accurate inflow profile, and the far-field response of hydraulic fracturing treatment. A comprehensive discussion is made with their application in different shale formations (Eagle Ford, Bakken, Permian Basin, and Marcellus) of the United States. The advantages and limitations of each technique were highlighted. Finally, the paper evaluates what are the completion evaluation strategies to employ in unconventional moving forward. The result illustrates the observations obtained from the deployment of FO techniques in the Bakken, Eagle Ford, Marcellus, and Permian shale formations. The comparative outcomes of those methods have been analyzed to develop a pragmatic guideline for factors impacting fracture diagnostics. The review finds that modeling and interpreting DAS strain rate responses can help quantitatively to map fracture propagation and stimulated reservoir volume. The relationship between injection rate and strain rate responses is investigated to show the potential of using DAS measurements to diagnose multistage fracturing. FO diagnostics indicate that interactions between the well, the fracture, and the rock are complex, hence the need to integrate the results with other diagnostics and reservoir information. Rapidly growing FO implementation in fracture diagnostics needs direction based on recent developments made in this field. This work discusses and summarizes important outcomes that will benefit future researchers to integrate ideas and generate breakthroughs in FO implementation for fracture evaluation and monitoring. Extensive insight is a need for the industry given that there are growing developments and opportunities in unconventional plays, as operators are finding more economic ways to enhance production through stimulation. However, a critical review of FO implementation by analyzing the public domain has not been done before with the breadth and depth that this paper provides.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
- Geology > Petroleum Play Type > Unconventional Play (0.89)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (41 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Vaca Muerta: Integrated Characterization of Natural Fractures and Oil Wettability Using Cores, Micro-Resistivity Images and Outcrops for Optimizing Landing Zones of Horizontal Wells
Abd Karim, Rahimah (University of Calgary and PETRONAS) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary) | Vittore, Franco Juan (YPF S.A.) | Rincon, Maria Florencia (YPF S.A.)
Abstract Understanding natural fracture width distribution, and pore sizes relation to thermal maturity, permeability and wettability is important in assessing shale reservoir quality and determining the productive landing zones for horizontal wells. Natural fractures and pore systems in Vaca Muerta are complex with significant lateral and vertical variations. This study provides an integrated characterization using cores, micro-resistivity images and outcrops that reveal the vertical variability of natural fractures and oil-wet characteristics of Vaca Muerta shale. The proposed method describes first the distribution of fracture widths from cores, micro-resistivity images and outcrops using a Variable Shape Distribution (VSD) model. The VSD provides a good fit of the data, which improves fracture width and intensity prediction. Subsequently, porosity, Total Organic Carbon (TOC) and water saturation (Sw) are modeled and calibrated with core data. Values of the porosity exponent m and the water saturation exponent n reflect the complexity of the pore system and wettability characteristics of Vaca Muerta. The method also incorporates for the first time, thin bed heterogeneity that comprises calcite beef, ash beds and nodules. Results indicate that fracture widths at Vaca Muerta range between 0.0003 and 2 mm for cores, 0.01 and 2 mm for micro-resistivity images, and 0.0003 and 7 mm for outcrops. The VSD captures the entire distribution of cores, images and outcrops, which allow pragmatic fracture width extrapolation. The physical widths can also be used to generate synthetic production logs (PLT) that indicate relative productivity from fractured intervals. The study reveals that better reservoir quality lies in the deeper organic-rich units of the Lower Vaca Muerta (LVM) shale. The LVM has lower Sw, larger pores, higher TOC, and greater natural fracture intensity. Pickett plots indicate decreasing m and increasing n values with depth. This suggests increasing natural fractures intensity and oil wettability towards the LVM, which is corroborated by cuttings descriptions, micro-resistivity images and a published Scanning Electron Microscopy (SEM) study. All these findings support the relation between pore sizes and thermal maturity, permeability and wettability. Finally, the study highlights the importance of incorporating thin bed heterogeneity in the analysis, due to its high occurrence in the organic-rich unit. The integrated analysis using cores, micro-resistivity images and outcrops reveals the variability of natural fracture intensity and oil-wet characteristics in each stratigraphic unit of the Vaca Muerta shale. The analysis considers, for the first time, the internal anatomy of thin bed heterogeneity. This methodology proves powerful for understanding the complex Vaca Muerta shale and for optimizing the landing zones of horizontal wells.
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Colorado > Spindle Field (0.99)
- (10 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)