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Estimating Recovery by Quantifying Mobile Oil and Geochemically Allocating Production in Source Rock Reservoirs
Adams, Jennifer (Stratum Reservoir, Houston) | Flannery, Matt (Stratum Reservoir, Houston) | Ruble, Tim (Stratum Reservoir, Houston) | McCaffrey, Mark A. (Stratum Reservoir, Houston) | Krukowski, Elizabeth (Stratum Reservoir, Houston) | Kolodziejczyk, Daniel (GeoLab Sur S.A., Buenos Aires, Argentina) | Villar, Hรฉctor (GeoLab Sur S.A., Buenos Aires, Argentina)
Abstract Due to highly variable well performance, unconventional reservoir (UR) field development relies heavily on production monitoring to predict total recovery, assess well interference, delineate drained rock volume, and diagnose mechanical issues. Completion design and well spacing decisions depend on accurate recovery estimates from reservoir models, and these can be limited by non-uniqueness in the history matching. Geochemical production allocation can greatly improve operatorsโ understanding of well performance when integrated with reservoir characterization and in-reservoir P/T monitoring. There are several long-standing challenges in the characterization of UR fluid flow: (i) collecting reservoir samples representative of mobile oil, (ii) accounting for production fractionation over the life of a well, and (iii) determining recoverable original oil in place (OOIP) from contributing zones. Although many metrics and correlations are commonly used, ultimate recovery requires accurate quantification of the provenance of produced fluids and proportion of total OOIP. We have developed a rapid method for quantifying mobile and total oil saturations from water-based mud (WBM) collected, tight cuttings and sidewall core samples using low temperature hydrous pyrolysis (EZ-LTHP). These mobile oils commonly include even the gasoline range compounds, which are the dominant compounds of produced liquids in most mid-continent UR fields, making EZ-LTHP-derived oils representative end-members for geochemical production allocation studies. EUR estimates and production forecasts by zone, are more accurate when calibrated to the mobile oil fraction, rather than to total oil saturation. EZ-LTHP provides this step-change by quantifying the mobile oil fraction in WBM cuttings and, when paired with reservoir volumetrics, allows for better reservoir model calibration and field management. Other industry techniques, such as solvent extraction and vaporization, suffer from the same limitations as log-derived values which are known to overestimate mobile oil in kerogen-rich intervals by incorrectly including kerogen-bound immobile oil. In this paper, we present quantified mobile oil recovery estimates based on integrated geochemical allocation studies from the Vaca Muerta, Neuquรฉn basin, and the Niobrara, Denver basin. In the Vaca Muerta play (Argentina), the organic-rich Cocina and Organico intervals in the Vaca Muerta expelled liquid into intervening good quality reservoir lithologies. However, liquids dominantly are produced from the most organic-rich zones, with evidence of a larger drained rock volume (DRV) during early production. Gas and oil allocations show different DRVs explained by fluid mobility. The Montney play (Canada) shows contribution of liquid from non-target zones. Interbedded zones of indigenous Montney oil mixed with migrated more mature fluid - and major discontinuities in mud gas isotopes - document minimal vertical mixing. Horizontal wells produce gas and oil dominantly from better-quality reservoirs regardless of landing zone, with natural gas bypassing low permeability zones. Accurate estimations of out-of-zone contributions therefore require cuttings/core-based geochemical allocation. A subset of these wells requires additional consideration of production fractionation.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (1.00)
- North America > Canada > British Columbia (1.00)
- (3 more...)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- (59 more...)
On the Path to Least Principal Stress Prediction: Quantifying the Impact of Borehole Logs on the Prediction Model
Dvory, N. Z. (Civil & Environmental Engineering & Energy and Geoscience Institute) | Smith, P. J. (Chemical Engineering) | McCormack, K. L. (Energy and Geoscience Institute) | Esser, R. (Energy and Geoscience Institute) | McPherson, B. J. (Civil & Environmental Engineering & Energy and Geoscience Institute)
ABSTRACT Knowledge of the minimum horizontal principal stress (Shmin) is essential for geo-energy utilization. Shmin direct measurements are costly, involve high-risk operations, and provide only discrete values of the required quantity. Other methods were developed to interpret a continuous stress sequence from sonic logs. These methods usually require some โhorizontal tectonic stressโ correction for calibration and rarely match sections characterized by stress profiling due to viscoelastic stress relaxation. Recently, several studies have tried to predict the stress profile by an empirical correlation corresponding to an average strain rate through geologic time or by using machine learning technologies. Here, we used the Bayesian Physics-Based Machine Learning framework to identify the relationships among the viscoelastic parameter distributions and to quantify statistical uncertainty. More specifically, we used well logs data and ISIP measurements to quantify the uncertainty of the viscoelastic-dependent stress profile model. Our results show that the linear regression approach suffers from higher uncertainty, and the Gaussian process regression Shmin prediction shows a relatively smaller uncertainty distribution. Extracting the lithology logs from the prediction model improves each method's uncertainty distribution. We show that the density and the porosity logs have a superior correlation to the viscoplastic stress relaxation behavior. INTRODUCTION Comprehensive recognition of the least principal stress is essential for economic multistage hydraulic fracturing stimulation design. It is well established that hydraulic fractures propagate perpendicular to the least principal stress and that the stress profile prominent the hydraulic fractures generation in both the lateral and horizontal direction (Fisher et al., 2012; Hubbert and Willis, 1957; Kohli et al., 2022; Valkรณ and Economides, 1995; Zoback et al., 2022)c. In other words, the stress layering could act as a โfrac barrierโ that limits fracture development in discrete directions and promotes progress in different directions (Singh et al., 2019). Detailed knowledge of the least principal stress profile is significant for hydraulic fracture growth assessment, proppants technology optimization, and efficient landing zone detection (Pudugramam et al., 2022). Traditionally, these considerations were aligned with the oil and gas industry. Still, today, they have substantial implications for enhanced geothermal system development, carbon storage integrity, and in a broader sense, a safe path for a carbon neutrality economy.
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- (13 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Traditional assessment of "free" oil-in-place via programmed pyrolysis can be challenged due to false positives (OBM invasion/interference), non-unique signatures (i.e. low temperature shoulders) or biased from sample handling procedures (unpreserved or โvintageโ core/cuttings). Additionally, estimated oil saturations and volumetrics of producible hydrocarbons from core material may be underrepresented if certain extraction practices are used. Here, we utilize an advanced thermal extraction technique that is tailored to optimize mobile bulk volumes of oil within a target horizon. Further geochemical assessment of the collected thermal extract aids in additional understanding of the hydrocarbons in place (source/maturity/migration). Retort oil evaluation via fine-tuned thermal extraction techniques can significantly increase estimated oil saturations and oil in place calculations. Itโs important to note that the selected retort temperature regime for Formation X in Basin A may very well be different than Formation Y in Basin B due to variations in source rock (kerogen) type, thermal maturity and/or a number of other factors. Therefore, a tailored experimental set up for a specific formation of interest would provide the dataset with the highest confidence for saturation and producibility evaluations. Introduction When evaluating the geochemical makeup of hydrocarbons within a rock (core/SWC/cuttings/etc.), it is important to understand the effects that the chosen extraction technique has on the fluid that is being extracted. For instance, when using excess solvent in a Soxhlet or Dean Stark apparatus, the solvent must be evaporated off to concentrate the extract before analysis. During that evaporation phase, light- to mid-chain hydrocarbons (typically up to โผnC15), which were potentially present in the parent rock sample, would also be lost before analysis even begins. If extraction of the heavier hydrocarbons was the goal, a solvent-based approach is appropriate but if light- to mid-chain hydrocarbons are dominant or if accurate original oil in place (OOIP) estimations are needed, then the loss of such hydrocarbons should be avoided.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (0.94)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.75)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Utah > Uinta Basin (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, โผ285 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 > Neuquรฉn > 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...)
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)
Summary In this study, we developed a data mining-based multivariate analysis (MVA) workflow to identify correlations in complex high-dimensional data sets of small size. The research was motivated by the integration analysis of geologic, geophysical, completion, and production data from a 4-square-mile study field located in the Northern Denver-Julesburg (DJ) Basin, Colorado, USA. The goal is to establish a workflow that can extract learnings from a small data set to guide the future development of surrounding acreages. In this research, we propose an MVA workflow, which is modified significantly based on the random forest algorithm and assessed using the R score from K-fold cross-validation (CV). The MVA workflow performs significantly better in small data sets compared to traditional feature selection methods. This is because the MVA workflow includes (1) the selection of top-performing feature combinations at each step, (2) iterations embedded, (3) avoidance of random correlation, and (4) the summarization of each featureโs occurrence at the end. When the MVA workflow was initially applied on a complex synthetic small data set that included numerical and categorical variables, linear and nonlinear relationships, relationships within independent variables, and high dimensionality, it correctly identified all correlating variables and outperformed traditional feature selection methods. Following that, a field data set consisting of the information from 23 wells was investigated using the MVA workflow aiming at identifying the key factors that affect the production performance in the study area. The MVA workflow reveals the weak correlation between production and legacy well effect. The results show that the key factors affecting production in this study area are total organic carbon (TOC) percentage, open fracture densities, clay content, and legacy well effect, which should receive significant attention when developing neighboring acreage of the DJ Basin. More importantly, this MVA method can be implemented in other basins. Considering the heterogeneity of unconventional resources, it is worthwhile to identify the key production drivers on a small scale. The outperformance of this MVA method on small data sets makes it possible to provide valuable insights for each specific acreage.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
Summary In this study, we developed a data mining-based multivariate analysis (MVA) workflow to identify correlations in complex high-dimensional data sets of small size. The research was motivated by the integration analysis of geologic, geophysical, completion, and production data from a 4-square-mile study field located in the Northern Denver-Julesburg (DJ) Basin, Colorado, USA. The goal is to establish a workflow that can extract learnings from a small data set to guide the future development of surrounding acreages. In this research, we propose an MVA workflow, which is modified significantly based on the random forest algorithm and assessed using the R score from K-fold cross-validation (CV). The MVA workflow performs significantly better in small data sets compared to traditional feature selection methods. This is because the MVA workflow includes (1) the selection of top-performing feature combinations at each step, (2) iterations embedded, (3) avoidance of random correlation, and (4) the summarization of each featureโs occurrence at the end. When the MVA workflow was initially applied on a complex synthetic small data set that included numerical and categorical variables, linear and nonlinear relationships, relationships within independent variables, and high dimensionality, it correctly identified all correlating variables and outperformed traditional feature selection methods. Following that, a field data set consisting of the information from 23 wells was investigated using the MVA workflow aiming at identifying the key factors that affect the production performance in the study area. The MVA workflow reveals the weak correlation between production and legacy well effect. The results show that the key factors affecting production in this study area are total organic carbon (TOC) percentage, open fracture densities, clay content, and legacy well effect, which should receive significant attention when developing neighboring acreage of the DJ Basin. More importantly, this MVA method can be implemented in other basins. Considering the heterogeneity of unconventional resources, it is worthwhile to identify the key production drivers on a small scale. The outperformance of this MVA method on small data sets makes it possible to provide valuable insights for each specific acreage.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
Lithologically-Controlled Variations of the Least Principal Stress with Depth and Resultant Frac Fingerprints During Multi-Stage Hydraulic Fracturing
Zoback, Mark (Stanford University) | Ruths, Troy (Petro.ai) | McClure, Mark (ResFrac) | Singh, Ankush (ResFrac) | Kohli, Arjun (Stanford University) | Hall, Brendon (Petro.ai) | Irvin, Rohan (ResFrac) | Kintzing, Malcolm (Henry Resources)
Abstract We present observational data and modeling results which support the hypothesis that the degree of vertical to horizontal hydraulic fracture propagation during multi-stage hydraulic fracturing is largely controlled by variations of the least principal stress with depth. It is obvious that monotonic variations of the least principal stress with depth imply either upward or downward hydraulic fracture growth. More interestingly, we present several case studies in which direct measurements show layer-to-layer stress variations of the least principal stress as large as ~10 MPa (~1500 psi) which are lithologically controlled. Using two different types of analysis approaches, we investigate complex patterns of vertical and horizontal hydraulic fracture growth from the Midland Basin. In each case, we show that pattern of hydraulic fracture propagation (and resultant drainage volumes) are largely governed by the detailed variation of the magnitude of the least horizontal stress with depth and exact position of a given stage. In gun barrel view, this complex pattern we refer to as a frac fingerprint for convenience. The frac fingerprint depends on the exact vertical position of a frac stage with respect to the variations of the least principal stress in the layers both above and below the stage depth. We show how frac fingerprints can vary along the length of a well because of the way its trajectory encounters lithofacies along its length. We briefly discuss the implication of these concepts for choosing optimal well spacings and landing depths and the relationships between hydraulic fracture geometry and drainage volumes. Introduction It was established 65 years ago that hydraulic fractures should propagate perpendicular to the minimum horizontal principal stress, Shmin (Hubbert and Willis, 1957). While there have been abundant observations consistent with this concept, recent experiments in the Eagleford Formation (Raterman et al., 2017) and the Permian Basin at HFTS-1 and HFTS-2 (Gale et al., 2018: 2021) have added appreciable new data confirming this concept. Hubbert and Willis (1957) also argued that the magnitude of the least principal stress governs the pressure required for propagation of hydraulic fractures. In most areas, of interest to development of unconventional oil and gas reservoirs, the least principal stress is the least principal horizontal stress, Shmin (see recent review by Lund Snee and Zoback (2022) of stress orientations and magnitudes in unconventional sedimentary basins in North America). Thus, knowledge of Shmin and its variations with depth is especially important in unconventional oil and gas reservoirs exploited with multi-stage hydraulic fracturing in horizontal wells. Of specific interest in this paper is the variation of Shmin with depth. The least principal stress governs the degree to which hydraulic fractures propagate vertically, either upward or downward, depending on Shmin magnitudes above, within and below the horizontal section of well commonly referred to as the lateral. Significant vertical propagation can limit successful exploitation of the targeted formation and defines the number of laterals required to exploit productive zones at multiple depth intervals or stacked pay. Hence, optimizing the depths and number of laterals needed to exploit stacked pay as well as the optimal well spacing at different depths will be closely related to how the magnitude of Shmin varies with depth.
- North America > United States > Texas (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.25)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (45 more...)
Abstract Pore radius and pore surface wettability affect capillary pressure and relative permeability functions which, in turn, affect fluid distribution in the flow channels and the outcome of improved and enhanced oil recovery in the reservoir. The contact angle between each pair of fluids and the pore surface is the main wettability determinant which is the focus of this paper; thus, we present measured contact angles for 16 samples from five unconventional reservoirs in the US and we correlate mineralogy of the facies and the crude oil composition to the reservoir rock wettability. Beyond enhanced oil recovery (EOR), the results may be significant in managing CO2 flooding and in determining the fraction of the sequestered CO2 in carbon capture utilization and storage (CCUS). Primary production, IOR, and EOR are affected by wettability and wettability alterations during the reservoir's life as a result of reservoir production methods used. Contact angles were measured using a drop shape analyzer (DSA) at the reservoir temperature and pressure for reservoir samples from Wolfcamp, Eagle Ford, Niobrara, Codell, and Bakken: 1) unaged core slices surrounded with formation brine, 2) aged core slices surrounded with formation brine, and 3) aged core samples surrounded with formation brine and CO2. Core slices of 1-in width were prepared and polished using different grades of sandpaper and cleaned using toluene, chloroform, and methanol in a Soxhlet extractor, and dried in the oven. Sample saturation was accomplished in an ultrafast centrifuge. Results show that the carbonate-dominated facies from Wolfcamp-A formation and Niobrara A-Chalk show a relatively higher contact angle even when the core sample is cleaned and is not aged. However, Eagle Ford, Niobrara B-chalk and C-chalk, Codell, Bakken, Three Forks indicate strong water-wet behavior when unaged as expected in ambient conditions. The same characteristics were observed for aged samples from the Eagle Ford. The results indicate the need for studying the wide variations for the formation facies and the need for evaluating the wettability of the reservoir facies prior to any EOR application in unconventional reservoirs, especially in Wolfcamp formation, where the facies mineralogy and wettability are significantly different in almost every foot.
- North America > United States > Texas (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > New Mexico (1.00)
- North America > United States > Colorado (1.00)
- Phanerozoic > Paleozoic (0.95)
- Phanerozoic > Mesozoic > Cretaceous (0.47)
- Geology > Mineral > Silicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.98)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.70)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract The US shale revolution in the past decade has doubled the country's crude production, and tight clay-rich formations account for 60% of the US crude production. Nevertheless, our knowledge of petroleum system controls on the reservoir performance of these tight shale systems remains poor. We report on a methodology to utilize production data to compare and rank the US shale oil plays in conjunction with geologic descriptions of the plays. For this study, we have used 36,642 horizontal oil wells from 12 tight shale formations in the Rockies and Midwest basins with vertical depths ranging from 5,000-15,000 feet and with at least 24 months of production to rank these plays based on their performance. These formations include: Wolfcamp (Delaware and Midland/Permian), Bone Spring (Delaware/Permian), Eagle Ford (Gulf Coast West and Central/ Cretaceous), Niobrara (Denver and Powder River/Cretaceous), Bakken (Williston/Devonian), Austin Chalk (Gulf Coast West/Cretaceous), Woodford (Anadarko/Devonian), Spraberry (Midland/Permian), and Barnett (Fort Worth/Mississippian). Their production data were normalized for cumulative oil (STB/ft/month), and the results were then analyzed in light of geologic and geochemical data from the formations. Integrated production and geologic-geochemical data on the tight formations offer valuable insights into the control of petroleum system elements on production patterns. These comparative patterns were used for ranking the shale plays for various parameters. In terms of cumulative oil production (STB/ft/month), Wolfcamp (Delaware) ranks top (0.93 STB/ft/month) while Barnett (Fort Worth) has the lowest crude production (0.07 STB/ft/month). In terms of GOR changes during production, Wolfcamp (Delaware) shows the lowest change (1.38 times), while Barnet (Fort Worth) has the highest change (13.37 times). These may be related to the oil-prone nature of Wolfcamp and the gas-prone characteristics of Barnet. Overall, deeper shale plays yield more oil (per foot per month) than the shallower plays. Some plays exhibit intra-formational migration of hydrocarbons. The results and the methodology of this study provide a multi-disciplinary geo-engineering to characterize shale oil plays in various basins. Variability in the performance of shale oil plays given by production data can be reverse engineered to petroleum systems.
- Phanerozoic > Paleozoic > Permian > Cisuralian (0.70)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.48)
- Phanerozoic > Paleozoic > Carboniferous > Mississippian (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (62 more...)