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Abstract Multi-stage, multi-well completions cause pore-pressures to increase around each stage treated, compound from earlier offset treatment stages, then dissipate as the injected fluid leaks off into the rock formation. Rock stresses change in a dynamic fashion from virgin reservoir stress to an altered stress influencing subsequently treated stages which can restrict slurry propagation from these injections into regions experiencing excess stress. Stress shadows are time-dependent and dissipate over time and return to the virgin stress state. Microseismic focal mechanisms detected from a high-fold wide azimuth surface array can be used to observe and calculate stress changes in the reservoir and constrain the time it takes for stresses to return to the virgin reservoir state. Operators can take advantage of stress changes and contain fractures close to the stages by building stress wedges around subsequently treated stages. After stress dissipates fluid propagates into previously opened fractures leading to poor fracture containment. In this paper, we review the effects of time-dependent stress shadows on multi-well completions in the Wolfcamp Formation in Southeast New Mexico. Then radioactive tracer data from the Niobrara Formation in the Denver-Julsburg basin is analyzed to provide further verification of the time-dependent process. Increased stresses from previous treatments remain elevated for ∼7 days which push fluid injected on neighboring wells away from the stress shadow. Production of well-specific tracer corroborates the hypothesis that local stress-shadows are elevated for ∼7 days which can push fluid from subsequent neighboring wells. After stresses dissipate through the fractures created during the initial stimulation, new tracer on offset wells was produced as much as 3,000 ft away on a neighboring well. Introduction Microseismic monitoring is a proven technology for observing and mapping reservoir response to hydraulic fracture stimulations. The event radiation pattern of the P-wave first arrival reveals advanced characteristics of the fracture describing deformation at the source location when detected using a high-fold wide azimuth surface array. The full-moment tensor can be generally decomposed into the relative percentages of isotropic, double couple and compensated linear vector dipole components (e.g. Aki and Richards, 1980) which fully describes the failure process in terms of volume change, amount of shearing, and other complexities related to deformation. The local stress field can be calculated using a set of focal mechanisms by minimizing the misfit angle between the modeled stress field and the observed focal mechanism slip vectors (Angelier, 1989) where the local stress field extent is defined by the spatial extent of the observed focal mechanisms. The local stress field orientation and relative magnitude can be resolved for a group of microseismic focal mechanisms by minimizing the misfit angle between the modeled stress field and the observed focal mechanism slip vectors for the subsets using a method described by Vavrycuk, 2014.
- North America > United States > New Mexico (0.55)
- North America > United States > Texas (0.35)
- North America > United States > Wyoming (0.34)
- (3 more...)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (7 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)
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, Héctor (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 operators’ 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, Neuquén 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 > Neuquén > 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 ‘horizontal tectonic stress’ 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; Valkó and Economides, 1995; Zoback et al., 2022)c. In other words, the stress layering could act as a ‘frac barrier’ 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 ‘vintage’ 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. It’s 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 ∼nC15), 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, ∼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)
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 feature’s 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)
Abstract According to Novi Labs, a well data analytics company, as of April, 2022, 94,000 horizontal shale oil wells had been placed into production in the 5 major US shale oil basins. Oil production from these wells is characterized by high initial rates and steep declines, with well lives of 9 to 16 years. Oil recovery factors, as a percentage of oil in place, range from 2.5 to 8 percent, leaving the vast majority of oil resources unrecovered. Shale oil EOR is in its infancy, with only 49 permitted projects involving a few hundred wells. 36 of these EOR projects are in the Eagle Ford shale. Prior publications have provided information on this activity, almost all of which involve cyclic injection of natural gas, or Huff-n-Puff EOR. Incremental recoveries have been projected to range from 10% to 80% of primary EUR. Our objective is to describe two novel shale oil EOR methods that may provide superior incremental shale oil recovery of 100 to 200% of primary EUR in the DJ Basin Niobrara shale. We have developed two superior shale oil EOR methods that utilize a triplex pump to inject a liquid solvent mixture into the Niobrara shale reservoir, and methods to fully recover the injectant at the surface, for storage and reinjection. The processes are fully integrated with compositional reservoir simulation to optimize the recovery of residual oil during each injection and production cycle. Compositional reservoir simulation modeling of the processes in a production and pressure history-matched horizontal DJ Basin Niobrara well indicates recoveries of 180% to 360% of primary EUR may be achieved. These processes have numerous advantages over cyclic gas injection - shorter injection time, faster and greater oil recovery, lower risk of interwell communication, lower cost of production, elimination of the need for artificial lift, and lower GHG emissions and water costs. These processes should work in all US shale oil plays, and have been successfully field tested in some. If implemented early in the well life, their application may enable recovery of more oil, faster, and preclude the need for artificial lift, resulting in shallower decline rates and much greater reserves. The processes also emit less GHG emissions and have lower water costs per barrel than primary recovery.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.69)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > South Dakota > Williston Basin (0.99)
- (36 more...)
Discrete Measurements of the Least Horizontal Principal Stress from Core Data: An Application of Viscoelastic Stress Relaxation
McCormack, Kevin L. (Energy and Geoscience Institute, University of Utah) | McLennan, John D. (Energy and Geoscience Institute, University of Utah) | Jagniecki, Elliot A. (Utah Geological Survey) | McPherson, Brian J. (Energy and Geoscience Institute, University of Utah (Corresponding author))
Summary The emerging Paradox Oil Play in southeastern Utah is among the most significant unconventional plays in the western USA. The mean total undiscovered oil resources within just the Pennsylvanian Cane Creek interval of the Paradox Basin are believed to exceed 215 million barrels. However, to date, less than 5% (~9 million barrels) of the total Cane Creek resource has been produced from fewer than 40 wells, and only approximately one-half of those are horizontal wells. More than 95% of production is from the central Cane Creek Unit (CCU). Natural fractures are a key feature of many production wells, but stimulation by induced hydraulic fractures is not consistently successful. We hypothesize that more effective production in this play will rely on better fundamental characterization, especially on better quantification of the state of stress. Approximately 110 ft of core, well logs, and a diagnostic fracture injection test (DFIT) were acquired from the State 16-2 well within the CCU. With these data, we applied two methods to constrain and clarify the state of stress. The first technique, the Simpson’s coefficient method, provides lower bounds on the two horizontal principal stresses and relies on only limited data. Alternatively, the viscoelastic stress relaxation (VSR) method is used to estimate the least horizontal principal stress, building on observations that principal stresses become more isotropic as the viscous behavior of a rock is more pronounced. Results of these two methods support the hypothesis that the state of stress in the CCU of the Paradox Basin is nearly lithostatic and isotropic. Other factors consistent with this hypothesis include high formation pore pressure, which tends to reduce the possible stress states by changing the frictional failure equilibrium; lack of induced fractures in the core, which should be present in the case of stress anisotropy; and interbedded halite layers, which given their high degree of ductility, probably lead to greater VSR for the entire sedimentary package.
- North America > United States > Utah (1.00)
- North America > United States > Colorado (1.00)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian (1.00)
- Phanerozoic > Mesozoic (0.93)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.93)
- (3 more...)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.66)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- 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)
- (23 more...)