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The net-effective stress is a fundamental physical property that undergoes dynamic changes in response to variations in pore pressure during production and injection activities. Petrophysical properties, including porosity, permeability, and wave velocities, play a critical role and exhibit strong dependence on the mechanical stress state of the formation. The Williston basin's Bakken Formation represents a significant reservoir of hydrocarbons within the United States. To investigate this formation, we extracted core plugs from three distinct Bakken members, namely Upper Bakken, Middle Bakken, and Lower Bakken. Subsequently, we conducted a series of measurements of ultrasonic compressional and shear wave velocities, as well as pulse decay permeabilities using nitrogen, under various confining pressures employing the Autolab-1500 apparatus. Our experimental observations revealed that the ultrasonic wave velocities and permeability display a significant sensitivity to stress changes. We investigated existing empirical relationships on velocity-effective stress, compressional-shear wave velocities, and permeability-effective stress, and proposed the best models and associated fitting parameters applicable to the current datasets. In conjunction with the acquired datasets, these models have considerable potential for use in time-lapse seismic monitoring and the study of production decline behavior. The best fitting models can be used to forecast the petrophysical and geomechanical property changes as the reservoir pore pressure is depleted due to the production, which is critical to the production forecast for unconventional reservoirs. [ABSTRACT FROM AUTHOR]

Tight reservoirs around the world contain a significant volume of hydrocarbons; however, the heterogeneity of these reservoirs limits the recovery of the original oil in place to less than 20%. Accurate characterization is therefore needed to understand variations in reservoir properties and their effects on production. Water saturation (Sw) has always been challenging to estimate in ultra-tight reservoirs such as the Bakken Formation due to the inaccuracy of resistivity-based methods. While machine learning (ML) has proven to be a powerful tool for predicting rock properties in many tight formations, few studies have been conducted in reservoirs of similar complexity to the Bakken Formation, which is an ultra-tight, multimineral, low-resistivity reservoir. This study presents a workflow for Sw prediction using well logs, core data, and ML algorithms. Logs and core data were gathered from 29 wells drilled in the Bakken Formation. Due to the inaccuracy and lack of robustness of the tried and tested regression models (e.g., linear regression, random forest regression) in predicting Sw as a continuous variable, the problem was reformulated as a classification task. Instead of exact values, the Sw predictions were made in intervals of 10% increments representing 10 classes from 0% to 100%. Gradient boosting and random forest classifiers scored the best classification accuracy, and these two models were used to construct a voting classifier that achieved the best accuracy of 85.53%. The ML model achieved much better accuracy than conventional resistivity-based methods. By conducting this study, we aim to develop a new workflow to improve the prediction of Sw in reservoirs where conventional methods have poor performance.

Tight reservoirs around the world contain a significant volume of hydrocarbons; however, the heterogeneity of these reservoirs limits the recovery of the original oil in place to less than 20%. Accurate characterization is therefore needed to understand variations in reservoir properties and their effects on production. Water saturation (Sw) has always been challenging to estimate in ultra-tight reservoirs such as the Bakken Formation due to the inaccuracy of resistivity-based methods. While machine learning (ML) has proven to be a powerful tool for predicting rock properties in many tight formations, few studies have been conducted in reservoirs of similar complexity to the Bakken Formation, which is an ultra-tight, multimineral, low-resistivity reservoir. This study presents a workflow for Sw prediction using well logs, core data, and ML algorithms. Logs and core data were gathered from 29 wells drilled in the Bakken Formation. Due to the inaccuracy and lack of robustness of the tried and tested regression models (e.g., linear regression, random forest regression) in predicting Sw as a continuous variable, the problem was reformulated as a classification task. Instead of exact values, the Sw predictions were made in intervals of 10% increments representing 10 classes from 0% to 100%. Gradient boosting and random forest classifiers scored the best classification accuracy, and these two models were used to construct a voting classifier that achieved the best accuracy of 85.53%. The ML model achieved much better accuracy than conventional resistivity-based methods. By conducting this study, we aim to develop a new workflow to improve the prediction of Sw in reservoirs where conventional methods have poor performance. [ABSTRACT FROM AUTHOR]

The Williston Basin of central North America contains prodigious quantities of coal and oil. Could the antediluvian biosphere have provided this carbon mass, or did it require many millions of years to accumulate? In this concluding part, we focus on fossil fuels. As we have seen many times in many places, what appear to be strong arguments against the Biblical view of Earth history turn out to be strong arguments against uniformitarianism. [ABSTRACT FROM AUTHOR]

The author discusses the impact of the Bakken Formation petroleum industry in North Dakota on cultural production. He discusses the impact of oil production in North Dakota as one aspect of anthropocene action, cultural production such as documentary films and art inspired by the petroleum industry, and the role of aesthetics in the creation of this art.

• Non-redox factors strongly influence authigenic trace-metal concentrations in sediments. • Diffusion-reaction modelling quantifies watermass chemistry & sedimentation rate effects. • Watermass chemistry controls authigenic Mo and U enrichment in modern Black Sea muds. • Sedimentation rate controlled authigenic Mo and U enrichment in Devonian black shales. Although redox conditions are the dominant control on authigenic enrichment of trace metals in marine sediments, other factors may be important within environments having relatively uniform redox characteristics, such as some anoxic silled basins. Notably, watermass chemistry (specifically, aqueous trace-metal concentrations) and sedimentation rate can also influence the authigenic accumulation of redox-sensitive trace metals such as molybdenum (Mo) and uranium (U) in the sediment, although these effects have received less attention than redox controls to date. Here, we (1) utilize a diffusion-reaction model to evaluate the effects of variations in watermass chemistry and sedimentation rate on authigenic trace-metal enrichment, and (2) present case studies of Mo and U enrichment in modern Black Sea sediments and North American Devonian-Carboniferous boundary (DCB) black shales that illustrate these influences. In both case studies, redox conditions were assessed using non-trace-metal-based proxies (i.e., C-S-Fe, Fe T /Al, and C org :P). Stations 6 and 7 of the modern Black Sea, at water depths of 380 and 1176 m, respectively, exhibit marked differences in authigenic Mo and U enrichment: median Mo/TOC is 13.2 at Station 6 (range 11.5–14.8) versus 5.7 at Station 7 (range 3.7–7.6), and median U/TOC is 2.6 at Station 6 (range 1.5–3.0) versus 1.3 at Station 7 (range 0.7–1.9) (note: units are ppm/% or 10−4, and ranges are 16th-84th percentiles). Given the nearly identical redox conditions and sedimentation rates at these two sites, the most likely cause of the >2× enrichment of Mo and U at Station 6 relative to Station 7 is differences in aqueous Mo and U concentrations, which decline steeply through the upper part of the Black Sea water column, demonstrating the influence of watermass chemistry on patterns of authigenic trace-metal enrichment in the sediment. For the DCB black shales, the median Mo/TOC is 22.2 in the Lower and Upper Bakken (range 15.8–27.0), 28.8 in the Sunbury (range 19.2–37.2), and 14.3 in the Cleveland (range 9.3–22.5), and the median U/TOC is 6.2 in the Lower and Upper Bakken (range 3.5–9.6), 2.6 in the Sunbury (range 1.7–3.4), and 1.2 in the Cleveland (range 0.7–1.7). Differences in Mo and U concentrations between these formations show no relationship to inferred aqueous trace-metal concentrations, Mn–Fe particulate shuttles, or paleoenvironmental redox conditions, but they broadly correlate with variation in sedimentation rates, providing evidence that sedimentation rates can measurably influence the degree of authigenic trace-metal enrichment of marine sediments. [ABSTRACT FROM AUTHOR]

Late Devonian (Famennian) marine successions globally are typified by organic‐rich black shales deposited in anoxic and euxinic waters and the cessation of shelf carbonate sedimentation. This global 'carbonate crisis', known as the Hangenberg Event, coincides with a major extinction of reef‐building metazoans and perturbations to the global carbon cycle, evidenced by positive carbon‐isotope excursions of up to 4‰. It has been suggested that authigenic carbonate, formed as cements in sedimentary pore spaces during early burial diagenesis, is a significant mass fraction of the total global carbon burial flux, particularly during periods of low oxygen concentration. Because some authigenic carbonate could have originated from remineralization of organic carbon in sediments, it is possible for this reservoir to be isotopically depleted and thereby drive changes in the carbon isotopic composition of seawater. This study presents bulk isotopic and elemental analyses from fine‐grained siliciclastics of the Late Devonian–Early Mississippian Bakken Formation (Williston Basin, USA) to assess the volume and isotopic composition of carbonates in these sediments. Carbonate in the Bakken black shales occurs primarily as microscopic disseminated dolomite rhombs and calcite cements that, together, comprise a significant mass‐fraction (ca 9%). The elemental composition of the shales is indicative of a dynamic anoxic to sulphidic palaeoenvironment, likely supported by a fluctuating chemocline. Despite forming in an environment favourable to remineralization of organic matter and the precipitation of isotopically depleted authigenic carbonates, the majority of carbon isotope measurements of disseminated carbonate fall between −3‰ and +3‰, with systematically more depleted carbonates in the deeper‐water portions of the basin. Thus, although there is evidence for a significant total mass‐fraction of carbonate with contribution from remineralized organic matter, Bakken authigenic carbonates suggest that Famennian black shales are unlikely to be sufficiently 13C‐depleted relative to water column dissolved inorganic carbon to serve as a major lever on seawater isotopic composition. [ABSTRACT FROM AUTHOR]

Early development of the Bakken Petroleum System recognized the significance of source rock maturation and the onset of oil generation in determining the geographic limits of production. The process of oil generation kinetics within source rocks involves intricate chemical reactions, where the nature of organic matter and thermal history influence the production of petroleum products. While simple models work well for some kerogen types (Type I), they fail for others (Type II and III), revealing the limitations of assuming invariant kinetic properties. This study explores the complexity of oil generation kinetics and its significance, particularly in the context of the Bakken Formation. Various methods have been used to identify the boundaries of oil sources, yet many are inductive. This research introduces a novel method to distinguish between catagenesis and diagenesis in Bakken's organic matter. A common linear relationship between activation energy (Ea) and frequency factor (ln(A)) appears in kinetic studies of source rocks, often attributed to statistical errors. This study investigates these relationships, revealing non-statistical compensation effects. Furthermore, extended kinetic models uncover a range of behaviors, highlighting the complexity of oil generation pathways. Notably, a kinetic compensation effect (KCE) is observed in the Bakken Formation, closely resembling findings for Type II kerogen. These compensation effects are not statistically forced, emphasizing their physiochemical origins. This research sheds light on the diverse KCEs within the Bakken Formation through a combination of experimental maturation, core analyses, and kinetic modeling. The study suggests that provenance, particularly for Type II kerogen, plays a crucial role in these effects. The data reveal multiple KCE patterns, including linear, inclined arch, and random clusters, with some transitioning between patterns during the oil generation process. These findings underscore the complexity of oil generation kinetics and its dependency on organic provenance. They also provide valuable insights for understanding oil reservoirs in the Bakken Formation and beyond. • This study explores oil generation kinetics in the Bakken Formation. • The study details the presence of a non-statistical kinetic compensation effect. • Extended kinetics methods are applied. • The data reveal multiple KCE patterns of experimental and naturally matured samples. [ABSTRACT FROM AUTHOR]

The effective development of unconventional tight oil formations, such as Bakken, could include CO2 enhanced oil recovery (EOR) technologies with associated benefits of capturing and storing large quantities of CO2. It is important to conduct the gas injection at miscible condition so as to reach maximum recovery efficiency. Therefore, determination of the minimum miscibility pressure (MMP) of reservoir live oil–injection gas system is critical in a miscible gas flooding project design. In this work, five candidate injection gases, namely CO2, CO2-enriched flue gas, natural gas, nitrogen, and CO2-enriched natural gas, were selected and their MMPs with a Bakken live oil were determined experimentally and numerically. At first, phase behaviour tests were conducted for the reconstituted Bakken live oil and the gases. CO2 outperformed other gases in terms of viscosity reduction and oil swelling. Rising bubble apparatus (RBA) determined live oil–CO2 MMP as 11.9 MPa and all other gases higher than 30 MPa. The measured phase behaviour data were used to build and tune an equation-of-state (EOS) model, which calculated the MMPs for different live oil-gas systems. The EOS-based calculations indicated that CO2 had the lowest MMP with live oil among the five gases in the study. At last, the commonly-accepted Alston et al. equation was used to calculate live oil–pure CO2 MMP and effect of impurities in the gas phase on MMP change. The Bakken oil–CO2 had a calculated MMP of 10.3 MPa from the Alston equation, and sensitivity analysis showed that slight addition of volatile impurities, particularly N2, can increase MMP significantly.

The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations. In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k -fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines. • Deep neural network (DNN) models are first developed to forecast well productions in unconventional shale reservoirs. • Optimum DNN models are achieved by tuning the hyperparameters of DNN models. • Importance of hydraulic fracturing parameters is identified through global sensitivity analysis. • Data-driven models are useful for reservoir engineers when designing the fracture treatments in unconventional reservoirs. [ABSTRACT FROM AUTHOR]

The Bakken Formation (uppermost Devonian-Lower Carboniferous) in North Dakota consists of black shales with a middle member composed of mixed siliciclastics and carbonates. Millimeter to decimeter-scale soft-sediment deformation structures (SSDS) are common in the upper third to quarter of the middle member, having been observed in sixty-three out of ninety cores studied. The nine categories identified herein reflect brittle and ductile deformation and loss of sediment shear in compressional and extensional settings. They are interpreted to form due to seismically-induced folding, liquefaction and fluidization of unconsolidated sediment, as well as microfaulting and brecciation of consolidated sediment, and reflect synsedimentary tectonic movements, e.g. along faults that were active during deposition. The distribution of SSDS follows the orientation of the major structural elements rooted in the basement of the Williston Basin. The stratigraphic and spatial distribution of SSDS suggests variable tectonic activity: cores near the most active fault systems have the highest net thickness of units with SSDS, whereas those farther from the most active faults exhibit only a few deformed units. The predominance of SSDS in the upper portion of the middle member suggests there was a change from relative tectonic quiescence to a more active regime which in turn led to modifications of basin geometry and new accommodation patterns. Synsedimentary deformation might have had a positive effect on reservoir quality in deformed units by increasing porosity and permeability as a result of cohesion loss and rearrangement of grains. Additionally, multiple injection structures and complexes of small-scale normal and reverse faults could contribute to better connectivity of reservoir units. • Abundant soft-sediment deformation structures in the middle Bakken member. • Soft-sediment deformation structures record syndepositional movement of basement structures. • Seismites can serve a tool to recognize paleotectonic activity in intracratonic basins. [ABSTRACT FROM AUTHOR]

Abstract Integrated petrophysical analysis is used in conventional and unconventional reservoirs to visualize the distribution pattern of different lithofacies and interpret depositional environments. In this study, core data from 17 wells and well logs from 517 wells are used to construct 3D data-driven lithofacies models for the upper and lower shale members in the Bakken Formation of the Williston basin in North Dakota, United States. The principal objective of this multi-scale (core, well log, and regional) study is to use the petrophysical response of lithofacies defined in core from a very limited number of wells to identify different shale lithofacies in the Bakken Formation in the numerous and geographically extensive wells with wireline log suites. Shale lithofacies are defined in the core using quantitative mineralogy, Total Organic Carbon content, and petrophysical properties. These lithofacies are calibrated to advanced geochemical spectroscopy logs and conventional well logs at well scales. A machine learning algorithm, Support Vector Machine, is used to recognize the pattern of different shale lithofacies, associated with basic petrophysical parameters from ubiquitous conventional well log suites. Sequential Indicator Simulation is used to populate all lithofacies in a 3D grid, covering a large portion of the Williston basin in North Dakota. The results show that the Bakken shale members are vertically and laterally heterogeneous, but are successfully classified into five different lithofacies. Organic-rich shale lithofacies outweigh the proportion of organic-lean shale lithofacies. It appears several factors influenced the pattern of shale lithofacies distribution of the Bakken Formation. Highlights • Application of machine learning for quantitative shale facies classification. • Implementation of Support Vector Machine algorithm to predict the presence of complex shale facies. • Vertical and lateral heterogeneity of the upper and lower Bakken shale members. [ABSTRACT FROM AUTHOR]

The Bakken and Three Forks Formations of the Williston Basin have been targeted by over 10,000 unconventional style wells (horizontal drilling coupled with hydraulic fracturing). Exploration and developmental drilling initially focused on the Middle Bakken but later expanded into the underlying upper Three Forks (located directly below the Bakken) and eventually the middle and lower Three Forks, which are positioned 10s to 100 + feet below the Bakken. Hydrocarbons (oil and associated gas) within both formations are believed to be sourced from the upper and lower Bakken shale members, which are both highly organic-rich (>10% TOC), thermally mature petroleum source beds. However, minimal literature exists examining the relationship between hydrocarbons generated by the lower Bakken shale and expelled downward into the various reservoirs of the Three Forks. Core-plug oil and water saturation data from 65 partial to complete Three Forks cores were utilized to map out fluid saturation trends within the upper, middle, and lower Three Forks. Over 500 core chip analyses from 52 cores were used to spatially delineate the present day average hydrogen index (thermal maturity) of the lower Bakken shale while a lower shale isopach map was created from wireline logs of 240 wells. Lastly, the geochemical and standard core-plug data from four complete Bakken-Three Forks cores were used to calculate and compare the volumetric amount of oil generated and expelled from the lower Bakken shale with the original oil in place (OOIP) of the entire Three Forks section. The results show a strong spatial relationship between increased thickness-thermally maturity of the lower Bakken shale and increased core-plug oil saturations across the upper to middle Three Forks members, and a similar, but less pronounced relationship with the lower Three Forks. The calculated lower Bakken shale expelled oil volumes ranged from 13 to 51 million barrels of oil (MMBO) per section (640 acres) which overall equaled to exceeded the OOIP of the entire Three Forks section (9–25 MMBO/section). These spatial and volumetric relationships indicate that local hydrocarbon generation and expulsion from the lower Bakken shale is the primary control for hydrocarbon charge within the underlying Three Forks Formation, where in some locations hydrocarbons have been pushed downwards 200 + ft. Understanding downward hydrocarbon charge has implications in exploring for and developing hydrocarbon resources within the Bakken-Three Forks as well as numerous other unconventional petroleum systems. • The lower Bakken shale (source bed) overlies the Three Forks Formation (reservoir). • Thickness and thermal maturity control source bed hydrocarbon expulsion volumes. • Three Forks oil saturations are a function of overlying source bed properties. • Downward hydrocarbon charge in low permeability rock can extend over 200 ft. [ABSTRACT FROM AUTHOR]

In order to analyze and compare the differences in pore structures between shale gas and shale oil formations, a few samples from the Longmaxi and Bakken Formations were collected and studied using X-ray diffraction, LECO TOC measurement, gas adsorption and field-emission scanning electron microscope. The results show that samples from the Bakken Formation have a higher TOC than those from the Longmaxi Formation. The Longmaxi Formation has higher micropore volume and larger micropore surface area and exhibited a smaller average distribution of microsize pores compared to the Bakken Formation. Both formations have similar meso-macropore volume. The Longmaxi Formation has a much larger meso-macropore surface area, which is corresponding to a smaller average meso-macropore size. CO2 adsorption data processing shows that the pore size of the majority of the micropores in the samples from the Longmaxi Formation is less than 1 nm, while the pore size of the most of the micropores in the samples from the Bakken Formation is larger than 1 nm. Both formations have the same number of pore clusters in the 2-20 nm range, but the Bakken Formation has two additional pore size groups with mean pore size diameters larger than 20 nm. Multifractal analysis of pore size distribution curves that was derived from gas adsorption indicates that the samples from the Longmaxi Formation have more significant micropore heterogeneity and less meso-macropore heterogeneity. Abundant micropores as well as meso-macropores exist in the organic matter in the Longmaxi Formation, while the organic matter of the Bakken Formation hosts mainly micropores. [ABSTRACT FROM AUTHOR]

Abstract Understanding organic matter properties in terms of maturity and production potential are crucial for the initial assessment of unconventional plays. This is important since the amount of hydrocarbon that can be generated is a function of organic matter type and content in the formation and its thermal maturity. The complexity of shale plays in terms of constituent components has demonstrated that new analytical methods should be acquired to better understand hydrocarbon generation processes. In this study, a few samples from the upper and lower members of the Bakken Formation in the USA were selected from different depths and maturity levels. The samples were analyzed by a high frequency (22 MHz) nuclear magnetic resonance (NMR relaxometry) equipment, followed by Rock-Eval pyrolysis (using the Basic/Bulk-Rock method for all samples and a multi-heating rate method, MHR, for the two least mature samples) and bitumen reflectance evaluations. Results showed NMR can detect different hydrogen populations within the samples and distinguish among phases, such as solid organic matter, hydrocarbons (mobile oil), and water by T 1 -T 2 mapping. We were also able to relate different identified areas on NMR T 1 -T 2 maps to geochemical parameters of the organic matter obtained from Rock-Eval pyrolysis (such as S1, S2, and HI) and with thermal maturity (vitrinite reflectance-equivalent). [ABSTRACT FROM AUTHOR]

Highlights • Statistical compensation effect is predictable from experimental temperatures. • Analytical solution for statistical compensation effect using the Kissinger Equation. • Gradient equals harmonic mean of reaction temperatures X gas constant. • Solution tested with simulated and laboratory pyrolysis experiments. • Statistical compensation found in the 2 cores of the Bakken Fm. Abstract The "compensation effect" refers to the general presence of a linear relationship between experimental activation energies (E a) and the logarithm of the corresponding frequency factor (A). This study examined the compensation effect with regard to petroleum generation and source rocks found in the Bakken Formation in the Williston Basin. The specific purpose was to test whether or not these compensation effects are caused by experimental conditions or actual differences in source rock kinetics. An analytical solution for the compensation effect developed for isothermal kinetics experiments is adapted for use with the Kissinger method for obtaining activation energies (E a) and frequency factors (A) from nonisothermal experiments (programed pyrolysis). This results in an expression that shows that the linear relationship between E a and ln(A) or compensation effect, present in most if not all, kinetic analyses of source rocks, is an artifact of experimental design and error and is not caused by an underlying physiochemical property. The compensation effect described by this expression, caused by experimental errors, forms an extremely elongated error ellipse in the E a -ln(A) plane that is closely approximated by a line that corresponds its principal or major axis. The gradient of the principal axis is equal to the product of the harmonic mean of the peak reaction temperatures and the gas constant. Simulated programmed pyrolysis experiments demonstrate that the reformulated analytical solution, when applied to the Kissinger Equation, predicts the slope of the linear dependence between different apparent values of E a and ln(A) caused by experimental imprecision. This result is present in rearranged and multiple split experimental data. Even though the apparent kinetic parameters may vary between analyses within a single set of sample splits, all share the same statistical compensation effect and demonstrate equivalent kinetics, whereas sample splits with different kinetic parameters lie along different statistical compensation effects. The results show that it is not possible to differentiate source rocks on the basis of apparent values of E a and A without also demonstrating that these kinetic parameters lie along statistically different compensation effects. Failure to recognize this behavior leads to serious errors when extrapolated to geologic time and temperature scales. [ABSTRACT FROM AUTHOR]

Organic-rich shale, which is a heterogeneous material, has been studied extensively from various perspectives. Among all the components that constitute shale, organic matter is less known in regards to its mechanical properties. Since organic matter is relatively the softer part compared to inorganic minerals, high concentrations of it can have a significant impact on bulk mechanical properties of the rock, which can affect field operations such as hydraulic fracturing. In this study, four shale samples from the Bakken Formation in Williston Basin, North Dakota, were examined by a combination of experimental methods including X-ray diffraction (XRD), Rock-Eval pyrolysis, optical and scanning electron microscopy (SEM) along with atomic force microscope (AFM). PeakForce Quantitative Nano-mechanical Mapping mode in AFM was used particularly, to map the modulus of organic matter in nano-scale. XRD analysis showed that quartz and clays are the main constituent minerals in the shale samples. Geochemical results showed that all samples are extremely organic-rich, and the organic matter is mostly type II, varying from thermally immature to oil generation window. Elastic properties test results demonstrated that surface topographic features including pores, microfractures and grain boundaries would have a negative impact on AFM data, and a data filtering procedure was conducted on AFM data to get rid of wrong values. The elastic modulus of identified organic matter (bitumen and micrinite) was measured in the range of 7–23 GPa with a significant heterogeneity in a single studied organic particle and dependent upon the type of organic particle. [ABSTRACT FROM AUTHOR]

Resulting from a booming shale-energy sector, from 2007 to 2014, income per capita in North Dakota increased 40%. Does this reflect the experience of a few oil-rich counties, or were the gains more evenly distributed across the region? We find the shale boom generated significant economic gains for counties above and near the Bakken Shale Formation, but not for those farther away. We also document significant state-border effects, which are not easily explained. Conditional on distance to the Bakken region, the shale boom generated limited outward migration from South Dakota, and as a result, the economic gains that accrued there were muted. (Q32, Q33) [ABSTRACT FROM AUTHOR]

As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low. As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock. Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30–45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived. [ABSTRACT FROM AUTHOR]

Organic-rich shales are highly heterogeneous due to the presence of a variety of constituent components. Among them, organic matter is poorly known in terms of mechanical properties due to the lack of high-resolution analytical equipment to isolate organic matter in-situ for mechanical testing. In this study, we proposed a new method to link morphology and geochemical properties of organic matter to its mechanical characteristics at the nanoscale. Kerogen type and thermal maturity, along with mineralogy were evaluated by Rock- Eval 6 pyrolysis/Total Organic Carbon (TOC) analysis and X-ray Diffraction (XRD) analysis. Then, the atomic force microscopy PeakForce Quantitative Nano-mechanical Mapping (AFM PeakForce QNM) mode was employed and coupled with optical and electron microscopy, to first visualize and then quantify the elastic properties of organic components in three different samples from the Bakken Formation. Hebamorphinite matrix bituminite and solid bitumen were identified as the main organic constituent, along with oil-prone marine kerogen type II (alginite and acritarch) and also a bacterial-derived granular micrinite-like maceral. Based on Tmax and vitrinite Ro values (or VRo-Eq from Bitumen Ro), thermal maturity of the samples ranged from immature to mature (past peak oil window). The average value of Young's modulus for organic matter was measured in the range of 2.91–11.77 GPa. It was also found that organic matter becomes stiffer with increased thermal maturity. This study exhibits a great potential, as a novel method, for in-situ analysis of mechanical properties of organic matter in shale reservoirs at a fine scale. [ABSTRACT FROM AUTHOR]

New paleontologic data from the Bakken Formation in theWilliston Basin of North Dakota are described, with an updated synthesis of previous biostratigraphic studies done in the basin. By combining the new data with the previously published data, a revised biostratigraphic framework is established for the Bakken Formation. Conodont data suggests that the Lower Bakken Member is late Famennian in age, ranging from the Pseudopolygnathus granulosus Zone to the Bispathodus ultimus Zone, and possibly to the early Tournaisian Protognathodus kockeli Zone. Upper Bakken conodont data shows that the unit is entirely Tournaisian in age and may range from the Siphonodella duplicata Zone to the Siphonodella quadruplicata Zone. Although no conodont data was analyzed from the Middle Bakken, the age constraints provided by the Upper and Lower Bakken suggest that the earliest Tournaisian conodont Zones, and potentially the historical Devonian-Carboniferous Boundary interval are in this unit. Palynologic data from the MiddleBakken indicates that the historical Devonian-Carboniferous Boundary should be placed at the unconformable contact between the lower Middle Bakken (Middle Bakken 1) and the upperMiddle Bakken (Middle Bakken 2) based on the highest stratigraphic occurrence of Retispora lepidophyta. Combining the biostratigraphic datawith detailed core description and x-ray fluorescence (XRF) chemostratigraphy, several stratigraphic units can be identifiedwithin each member of theBakken. These units can be mapped regionally throughout theWillistonBasin, thus improving our understanding of the spatial distribution of the different source and reservoir rock intervals within the Williston Basin oil play. [ABSTRACT FROM AUTHOR]

Pores that exist within the organic matter can affect the total pore system of bulk shale samples and, as a result, need to be studied and analyzed carefully. In this study, samples from the Bakken Formation, in conjunction with the kerogen that was isolated from them, were studied and compared through a set of analytical techniques: X-ray diffraction (XRD), Rock-Eval pyrolysis, Fourier Transform infrared spectroscopy (FTIR), and gas adsorption (CO 2 and N 2 ). The results can be summarized as follows: 1) quartz and clays are two major minerals in the Bakken samples; 2) the samples have rich organic matter content with TOC greater than 10 wt%; 3) kerogen is marine type II; 4) gas adsorption showed that isolated kerogen compared to the bulk sample has larger micropore volume and surface area, meso- and macropore volume, and Brunauer–Emmett–Teller (BET) surface area; 5) deconvolution of pore size distribution (PSD) curves demonstrated that pores in the isolated kerogen could be separated into five distinct clusters, whereas bulk shale samples exhibited one additional pore cluster with an average pore size of 4 nm hosted in the minerals. The comparison of PSD curves obtained from isolated kerogen and bulk shale samples proved that most of the micropores in the shale are hosted within the organic matter while the mesopores with a size ranging between 2 and 10 nm are mainly hosted by minerals. The overall results demonstrated that organic matter-hosted pores make a significant contribution to the total porosity of the Bakken shale samples. [ABSTRACT FROM AUTHOR]

This study evaluates and compares the performance of microbial fuel cells (MFCs) and microbial capacitive deionization cells (MCDCs) fed with wastewater produced from the Bakken shale. The produced water was characterized by high levels of dissolved solids and chemical oxygen demand (COD). Two-compartment MFCs and three-compartment MCDCs were evaluated under batch-fed mode using mixed microbial consortia in the anode, ferricyanide in the cathode, and produced water as the electrolyte in the anode and capacitive deionization units. COD removal in the MFCs was 88%, while that in the MCDCs was limited to 76%. The lower performance of the MCDCs was due to the large impedance (6600 Ω cm 2 ) compared with the MFCs (870 Ω cm 2 ). However, the MCDCs achieved two-fold higher removal of dissolved solids. Both the MFCs and MCDCs suffered from a higher impedance induced by fouling in the latter stages of the operation. [ABSTRACT FROM AUTHOR]

In this study, the geomechanical behavior of the shale layers is investigated in various capacities under isotropic and anisotropic scenarios. Primarily, an accurate estimation of geomechanical properties is carried out. Different geomechanical parameters including Young's modulus, Poisson's ratio, and rock strength for both isotropic and anisotropic modes are estimated based on field investigations for all three members. Dynamic elastic moduli are estimated from advanced acoustic log tests, and static moduli are measured in the laboratory. Then, a comparison is made, and a correlation is developed to convert dynamic to static elastic properties. Consequently, stress alteration and deformation changes around the boreholes are modeled in response to drilling. Measured parameters are utilized in a finite difference numerical model to predict rock deformation and stress variation. Based on the geomechanical models, stress regimes and medium deformations around the borehole are compared in both anisotropic and isotropic circumstances. Moreover, the effects of wellbore inclination on stress distribution, wellbore deformation, and yielding zones are discussed. The effects of wellbore inclination on stress distribution are monitored by studying horizontal principal stresses. According to the results, the relative plasticity radius of the medium is determined by dividing maximum radius of the yielded zone by the primary radius of the wellbore. Consequently, the failure zones and relative plasticity radiuses are compared for different well inclinations from vertical to horizontal wellbores. The relative plasticity radiuses are shown constant from vertical borehole to the borehole with 45 degrees of inclination with a gradual increase in values towards a horizontal borehole. [ABSTRACT FROM AUTHOR]

Biomarkers have been used extensively to correlate oil families, oil–source rock relationships and source inputs, and to help identify the palaeodepositional environment for a given geological sedimentary unit. Despite their application in characterising the Bakken Formation shales, a number of biomarkers still appear unable to provide us a consistent understanding regarding heterogeneity in source organic matter and palaeoenvironment. Here, we infer the palaeodepositional environment within the Bakken Formation shales using a biomarker suite and biomarker depth profiles. We also use the occurrence and abundance of biomarkers to define organic facies and to make inferences regarding biotic interactions drawn from modern analogues. The variations and co-occurrence of biomarkers is explained by the existence of a proposed complex algal–bacterium–bacteriovore palaeoecosystem. This approach not only helps explain the depth variation in occurrence and concentration of biomarkers and the molecular composition of associated organic matter, but also advances the use of biomarker analysis and biomarker associations to determine a complex environment-sensitive palaeoecosystem. [ABSTRACT FROM AUTHOR]

Artificially intelligent and predictive modelling of geomechanical properties is performed by creating supervised machine learning data models utilizing artificial neural networks (ANN) and will predict geomechanical properties from basic and commonly used conventional well logs such as gamma ray, and bulk density. The predictive models were created by following the approach on a large volume of data acquired from 112 wells containing the Bakken Formation in North Dakota. The studied wells cover a large surface area of the formation containing the five main producing counties in North Dakota: Burke, Mountrail, McKenzie, Dunn, and Williams. Thus, with a large surface area being analyzed in this research, there is confidence with a high degree of certainty that an extensive representation of the Bakken Formation is modelled, by training neural networks to work on varying properties from the different counties containing the Bakken Formation in North Dakota. Shear wave velocity of 112 wells is also analyzed by regression methods and neural networks, and a new correlation is proposed for the Bakken Formation. The final goal of the research is to achieve supervised artificial neural network models that predict geomechanical properties of future wells with an accuracy of at least 90% for the Upper and Middle Bakken Formation. Thus, obtaining these logs by generating it from statistical and artificially intelligent methods shows a potential for significant improvements in performance, efficiency, and profitability for oil and gas operators. [ABSTRACT FROM AUTHOR]

Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organicrich shale could permanently store CO2 without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO2-enhanced oil shale recovery and shale formation CO2 sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO2 injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO2 flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO2 injectivity. [ABSTRACT FROM AUTHOR]

Over the last decade, production from unconventional resources in North America, particularly shale gas and tight oil, has seen continuous growth and became an increasingly important consideration for the industry. In such reservoirs, sharp declines and limited drainage area has resulted in rapid abandonment conditions with significant amounts of oil in place left untouched. In order to maximize the recovery from unconventional resources, several different solutions including infill drilling, refracturing, and enhanced oil recovery (EOR) techniques have been researched. In this study, we have optimized the application of CO 2 -EOR methods for the Middle Bakken Formation. Numerical simulations have been paired with the experimental design method in order to identify the parameters that could control oil recovery, CO 2 utilization, and CO 2 retention factors of the cyclic CO 2 -EOR process. Unlike previous studies, a growing injection-production cycle size scheme was designed and optimized in this study. It was ultimately shown that for the same set of geological parameters, the variable cycle design resulted in an additional 1.4 per cent and 5.9 per cent in oil recovery and CO 2 retention factors, respectively, with 10.6 MSCF/STB less CO 2 utilized than typically seen in the constant cycle operation. Furthermore, this study analyzed the combined effect of operational and geological parameters on the three responses of oil recovery, CO 2 utilization, and CO 2 retention factors. In particular, fracture spacing, fracture half-length, start time of operation, oil gravity, as well as injection pressure were identified as the most influential variables. Interaction effects of the mentioned variables with geological parameters of porosity, pay-zone thickness, and permeability were also studied. The range of operational values which yields the optimum responses for specific geological parameters were identified. The statistical approach also helped provide screening strategies for an optimized operation of a CO 2 -EOR process in an unconventional reservoir. [ABSTRACT FROM AUTHOR]

Understanding the pore structures of unconventional reservoirs such as shale can assist in estimating their elastic transport and storage properties, thus enhancing the hydrocarbon recovery from such massive resources. Bakken Shale Formation is one of the largest shale oil reserves worldwide located in the Williston Basin, North America. In this paper, we collected a few samples from the Bakken and characterized their properties by using complementary methods including X-ray diffraction (XRD), N 2 and CO 2 adsorption, and Rock-Eval pyrolysis. The results showed that all range of pore sizes: micro (<2 nm), meso (2–50 nm) and macro-pores (>50 nm) exist in the Bakken shale samples. Meso-pores and macro-pores are the main contributors to the porosity for these samples. Compared with the Middle Bakken, samples from Upper and Lower Bakken own more micro pore volumes. Fractal dimension analysis was performed on the pore size distribution data, and the results indicated more complex pore structures for samples taken from the Upper and Lower Bakken shales than the Middle Bakken. Furthermore, the deconvolution of the pore distribution function from the combination of N 2 and CO 2 adsorption results proved that five typical pore size families exist in the Bakken shale samples: one micro-pore, one macro-pore and three meso-pore size families. The studies on the correlations between the compositions and the pore structures showed that mostly feldspar and pyrite affect the total pore volume of samples from Middle Bakken Formation whereas clay dominates the total pore volume of samples from Upper/Lower Bakken Formation. TOC and clay content are the major contributors to the micro-pore size family in the Upper/Lower Bakken. Also, it was observed that the increase of hard minerals could increase the percentage of macro-pore family in the Middle Bakken Formation. [ABSTRACT FROM AUTHOR]

Rock brittleness is pivotal in the development of the unconventional reservoirs. However, the existence of various methods of calculating the brittleness index (BI) such as the mineral-based brittleness index (MBI), the log-based brittleness index (LBI), and the elastic-based brittleness index (EBI) lead to inconclusive estimations of the brittleness index. Hence, in this work, the existing correlations are applied on prolific unconventional plays in the U.S. such as the Marcellus, Bakken, Niobrara, and Chattanooga Formation to examine the various BI methods. A detailed comparison between the MBI, LBI, and EBI has also been conducted. The results show that a universal correlation cannot be derived in order to define brittleness since it is a function of lithology. Correlation parameters vary significantly from one shale play to another. Nevertheless, an overall trend shows that abundant quartz and carbonates content yield high brittleness values, while the high clay content and porosity lower the rock brittleness.

The Bakken Formation is a typical tight oil reservoir and oil production formation in the world. Pore structure is one of the key factors that determine the accumulation and production of the hydrocarbon. In order to study the pore structures and main controlling factors of the Bakken Formation, 12 samples were selected from the Bakken Formation and conducted on a set of experiments including X-ray diffraction mineral analysis (XRD), total organic carbon (TOC), vitrinite reflectance (Ro), and low-temperature nitrogen adsorption experiments. Results showed that the average TOC and Ro of Upper and Lower Bakken shale is 10.72 wt% and 0.86%, respectively. The Bakken Formation develops micropores, mesopores, and macropores. However, the Upper and Lower Bakken shale are dominated by micropores, while the Middle Bakken tight reservoir is dominated by mesopores. The total pore volume and specific surface area of the Middle Bakken are significantly higher than those of the Upper and Lower Bakken, indicating that Middle Bakken is more conducive to the storage of oil and gas. Through analysis, the main controlling factors for the pore structure of the Upper and Lower Bakken shale are TOC and maturity, while those for Middle Bakken are clay and quartz contents.

Drilling and fracture stimulating horizontal wells in low permeability fields, such as tight oil reservoirs, is a common practice. Estimating the connectivity between these wells (interwell connectivity or IWC) is important for the design and management of a field, especially when waterflood recovery is applied. For example, IWC affects the determination of fracture conductivity and length and can help identify favorable locations for infill drilling and optimize injection rates. In this paper, we show how an alternative method, developed for and successfully applied in conventional reservoirs to determine IWC, can be modified to estimate tight formation IWC using solely production- and injection-rate fluctuations. The model is based on the Capacitance Model, or CM, and is modified to include a pseudo well (CM-PW). The CM-PW is tested with various heterogeneous simulation cases and field data. The CM-PW can identify inter-well heterogeneities. The model accuracy is based on the match to production data and, for all simulation cases, the model accuracy is good with R 2 ≥0.83. The field application, from a tight oil waterflood in the Bakken Formation, shows that the CM-PW results are consistent with tracer test results and field reports showing fracture hits between wells. The CM-PW evaluations also correlate well with the seismically-derived acoustic impedance. Integrating the connectivity analysis with tracer tests, seismic, and the geology enabled us to identify reasons for the connectivity observed, assessing whether injected fluid flows through the reservoir matrix or fractures between injector-producer pairs. To our knowledge, this is the first time the CM has been applied to horizontal wells. [ABSTRACT FROM AUTHOR]

Black shales of the Late Devonian to Early Mississippian Bakken Formation are characterized by high concentrations of organic carbon and the hyper-enrichment (> 500 to 1000s of mg/kg) of V and Zn. Deposition of black shales resulted from shallow seafloor depths that promoted rapid development of euxinic conditions. Vanadium hyper-enrichments, which are unknown in modern environments, are likely the result of very high levels of dissolved H 2 S (~ 10 mM) in bottom waters or sediments. Because modern hyper-enrichments of Zn are documented only in Framvaren Fjord (Norway), it is likely that the biogeochemical trigger responsible for Zn hyper-enrichment in Framvaren Fjord was also present in the Bakken basin. With Framvaren Fjord as an analogue, we propose a causal link between the activity of phototrophic sulfide oxidizing bacteria, related to the development of photic-zone euxinia, and the hyper-enrichment of Zn in black shales of the Bakken Formation. [ABSTRACT FROM AUTHOR]

The Late Devonian to Early Mississippian Bakken Formation in the Williston basin of North Dakota, USA, shows a tri-partite subdivision: a middle mixed carbonate-siliciclastic member is sandwiched in-between two black siliciclastic mudstones, the lower and upper Bakken member shales. However, the transition from the lower shale member to the middle member does not represent a gradual coarsening but contains in places several millimeter - to centimeter-thick siliciclastic mudstones and carbonates that consist of three facies: (1) a glauconitic carbonate-rich siliciclastic mudstone, (2) a carbonate mud-to wackestone, and (3) an echinoderm wacke-to packstone with shell fragments. These three facies are present in many (all?) of the cores close and directly in the basin center in Mountrail County, North Dakota. At least one of these three facies is present in all 23 cores included in this study. This thin carbonate unit at the transition between the lower and the middle Bakken members is interpreted as representing the remnants of the transgressive systems tract. It is assumed that relative sea-level fell before deposition of the middle Bakken member establishing a proximal coarse-grained to distal fine-grained depositional transect that successively migrated into the basin. During the subsequent transgression, the siliciclastic input was low to absent, and the entire sedimentary system switched to depositing carbonates. The proximal to distal transect during this time showed coarse-grained packstones (and grainstones?) close to the shoreline, and a fining outwards towards the distal parts of the basin. This transgression also eroded what remained of the regressive and most of the subsequent transgressive sediments, leaving only the thin carbonate layer behind. Evidence for the regression, even though no sediment is directly preserved along the lower to middle Bakken member contact, comes from the fill of clastic dykes that cut through the lower Bakken member shale. The fill of the clastic dykes is partly siliciclastic and partly carbonate and not similar to any of the surrounding sediment. This indicates that these dykes must have originated before the middle Bakken member was deposited, yet the overlying sediment must have been carbonate at some point and siliciclastic another time. As it is not present anymore, this sediment must have been entirely removed by erosion. The here presented model suggests that the Bakken Formation reflects two entire sea-level oscillations. The first encompasses the lower Bakken member shale and the siliciclastic regressive portion of the lowstand only preserved as infill of the clastic dykes. The subsequent transgression deposited the carbonates now blanketing the lower to middle Bakken member transition, and the highstand and subsequent regression plus lowstand are represented by the middle Bakken member. The transgressive surface and therewith the onset of the topmost Bakken transgression is marked by the transition from the middle to the upper Bakken shale member. [ABSTRACT FROM AUTHOR]

Pore structures are one of the most important factors affecting the hydro-mechanical properties of the reservoirs. Unlike the homogeneous pore structures in sandstones, the pores in the shale formations are heterogeneous and more complex to characterize due to the diagenesis and geological processes that they experienced. The heterogeneous rock pore structures can influence not only the flow properties of the oil and gas but also the fracture initiation and propagation characteristics which can impact the hydraulic fracturing performance, a common technique to increase the total production in tight shale formations. Therefore, quantifying the heterogeneities of the pore structures in unconventional shale formations carries a great importance. In this paper, we collected the samples from Bakken formation, which is a typical unconventional oil shale reservoir in North America. We applied image analysis method to study the pore structures. After segmentation of these images, we determined the representative elementary area (REA) of the samples based on the relationships between porosity and magnification ratios. Multifractal theory and lacunarity methods were applied to analyze the pore structures. Multifractal parameters were used to describe the pore probability distributions and the lacunarity value was applied to quantify the heterogeneity of the pores. The impact of the mineral compositions on heterogeneity values is also discussed. Finally, a new REA indicator, which contains the porosity and heterogeneity information, was proposed. [ABSTRACT FROM AUTHOR]

Experimental and numerical techniques have been developed to evaluate performance of CO 2 huff-n-puff processes for unlocking resources from the Bakken tight oil formations. Experimentally, a series of coreflooding tests have been conducted by using core samples collected from the Bakken tight formation with a permeability range of 0.27–0.83 mD. The performance of four recovery schemes (i.e., waterflooding, immiscible CO 2 huff-n-puff, near-miscible CO 2 huff-n-puff, and miscible CO 2 huff-n-puff processes) has been comparatively evaluated. Theoretically, numerical simulation is performed to match the experimental measurements and then extended for evaluating field-scale CO 2 huff-n-puff performance in the Bakken formation. Once the history matching on either the experimental measurements or the field geological model is completed, the tuned numerical model is then employed to optimize the injection pressure, soaking time, and production pressure, respectively. It is experimentally found that the waterflooding process leads to a higher oil recovery factor of 51.5% in comparison with the immiscible CO 2 huff-n-puff process, while both the near-miscible and miscible CO 2 huff-n-puff processes result in a higher recovery efficiency with the final recovery factors of 63.0% and 61.0% of OOIP, respectively. As for the history matched reservoir geological model, either a higher injection pressure or a lower production pressure usually results in better recovery performance but lower than the corresponding experimental measurements, while recovery factor can be optimized if soaking time of 15 days is applied in this study. [ABSTRACT FROM AUTHOR]

Wastewaters from oil and gas development pose largely unknown risks to environmental resources. In January 2015, 11.4 M L (million liters) of wastewater (300 g/L TDS) from oil production in the Williston Basin was reported to have leaked from a pipeline, spilling into Blacktail Creek, North Dakota. Geochemical and biological samples were collected in February and June 2015 to identify geochemical signatures of spilled wastewaters as well as biological responses along a 44-km river reach. February water samples had elevated chloride (1030 mg/L) and bromide (7.8 mg/L) downstream from the spill, compared to upstream levels (11 mg/L and < 0.4 mg/L, respectively). Lithium (0.25 mg/L), boron (1.75 mg/L) and strontium (7.1 mg/L) were present downstream at 5–10 times upstream concentrations. Light hydrocarbon measurements indicated a persistent thermogenic source of methane in the stream. Semi-volatile hydrocarbons indicative of oil were not detected in filtered samples but low levels, including tetramethylbenzenes and di-methylnaphthalenes, were detected in unfiltered water samples downstream from the spill. Labile sediment-bound barium and strontium concentrations (June 2015) were higher downstream from the Spill Site. Radium activities in sediment downstream from the Spill Site were up to 15 times the upstream activities and, combined with Sr isotope ratios, suggest contributions from the pipeline fluid and support the conclusion that elevated concentrations in Blacktail Creek water are from the leaking pipeline. Results from June 2015 demonstrate the persistence of wastewater effects in Blacktail Creek several months after remediation efforts started. Aquatic health effects were observed in June 2015; fish bioassays showed only 2.5% survival at 7.1 km downstream from the spill compared to 89% at the upstream reference site. Additional potential biological impacts were indicated by estrogenic inhibition in downstream waters. Our findings demonstrate that environmental signatures from wastewater spills are persistent and create the potential for long-term environmental health effects. [ABSTRACT FROM AUTHOR]

In recent years, hydraulic fracturing and horizontal drilling have been applied to extract crude oil from tight reservoirs, including the Bakken formation. There is growing interest in understanding the greenhouse gas (GHG) emissions associated with the development of tight oil. We conducted a life cycle assessment of Bakken crude using data from operations throughout the supply chain, including drilling and completion, refining, and use of refined products. If associated gas is gathered throughout the Bakken well life cycle, then the well to wheel GHG emissions are estimated to be 89 g CO2eq/MJ (80% CI, 87-94) of Bakken-derived gasoline and 90 g CO2eq/MJ (80% CI, 88-94) of diesel. If associated gas is flared for the first 12mo of production, then life cycleGHGemissions increase by 5% on average. Regardless of the level of flaring, the Bakken life cycle GHG emissions are comparable to those of other crudes refined in the United States because flaring GHG emissions are largely offset at the refinery due to the physical properties of this tight oil. We also assessed the life cycle freshwater consumptions of Bakken-derived gasoline and diesel to be 1.14 (80% CI, 0.67-2.15) and 1.22 barrel/barrel (80% CI, 0.71-2.29), respectively, 13% of which is associated with hydraulic fracturing. [ABSTRACT FROM AUTHOR]

The Bakken is one of the shale reservoirs that has been discovered to hold a vast amount of resource and is contributing to the production boom in the US. This unconventional reservoir, like most others, displays favorable initial production rates due to stimulation by hydraulic fracturing, but production rates quickly decline after few months. Due to the extremely low permeability and low recoveries, miscible gas injection is considered for improving the recovery of oil in the Bakken formation. Feasibility of miscible gas injection in the Bakken would depend on the analysis of minimum miscibility pressure (MMP) experiments. The Rising Bubble Apparatus (RBA) has been chosen for the purpose of these experiments. The RBA provides results in a short amount of time using small amounts of fluid samples. The RBA consists of a cell gage containing a flat glass tube where oil samples are placed and an injection needle where gas is injected into the flat glass tube. To simulate reservoir conditions, the glass tube is pressurized using de-ionized water, and heating plates surrounding the cell are used to regulate temperature. Visual observation of the injected gas bubble behavior is captured by a camera as it rises and moves upward along the oil column. By observing the shape and dissolution behavior of the bubble, the MMP can be determined. MMP results from a Bakken crude sample are shown to range from 2100 to 3500 psi at temperatures from 160 to 240 °F using CO 2 as the injection fluid. Other injection fluids such as nitrogen and hydrocarbon gases have been tested and also provided reasonable MMP values. MMP results from Bakken crude oil samples were compared to existing correlations, and the correlations were found to produce mostly unreliable MMP results for the Bakken oils evaluated in the study. On the other hand, an equation of state phase behavior program showed similarities with the RBA MMP results. The impact of different injection fluids, inclusive of CO 2 and enriched hydrocarbon gases is the subject of this study. MMP results are influenced by the choice of injection fluids, providing valuable information for economic production and increased recovery in the Bakken formation. The results from this study provide a range of MMP data that can be used in planning pilot tests for miscible gas injection in the Bakken. [ABSTRACT FROM AUTHOR]