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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 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]

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]

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.

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]

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]

Waters that return to the surface after injection of a hydraulic fracturing fluid for gas and oil production contain elements, including regulated metals and metalloids, which are mobilized through interactions between the fracturing fluid and the shale formation. The rate and extent of mobilization depends on the geochemistry of the formation and the chemical characteristics of the fracturing fluid. In this work, laboratory scale experiments investigated the influence of water chemistry on element mobilization from core samples taken from the Bakken formation, one of the most productive shale oil plays in the US. Fluid properties were systematically varied and evaluated with regard to pH, oxidant level, solid:water ratio, temperature, and chemical additives. Element mobilization strongly depended on solution pH and redox conditions and to a lesser extent on the temperature and solid:water ratio. The presence of oxygen and addition of hydrogen peroxide or ammonium persulfate led to pyrite oxidation, resulting in elevated sulfate concentrations. Further, depending on the mineral carbonates available to buffer the system pH, pyrite oxidation could lower the system pH and enhance the mobility of several metals and metalloids. [ABSTRACT FROM AUTHOR]

The Bakken formation contains billions of barrels of oil and gas trapped in rock and shale. Horizontal drilling and hydraulic fracturing methods have allowed for extraction of these resources, leading to exponential growth of oil production in the region over the past decade. Along with this development has come an increase in associated emissions to the atmosphere. Concern about potential impacts of these emissions on federal lands in the region prompted the National Park Service to sponsor the Bakken Air Quality Study over two winters in 2013-2014. Here we provide an overview of the study and present some initial results aimed at better understanding the impact of local oil and gas emissions on regional air quality. Data from the study, along with longterm monitoring data, suggest that while power plants are still an important emissions source in the region, emissions from oil and gas activities are impacting ambient concentrations of nitrogen oxides and black carbon and may dominate recent observed trends in pollutant concentrations at some of the study sites. Measurements of volatile organic compounds also definitively show that oil and gas emissions were present in almost every air mass sampled over a period of more than 4 months. [ABSTRACT FROM AUTHOR]

Using the model information and in situ data on hydrofracturing in an oil and gas reservoir of the Bakken Formation (USA), potential of locating hypocenters of microseismic events concurrently with determining parameters of velocity anisotropy of seismic waves in rock mass is analyzed. It is shown that inclusion of anisotropy in the analysis improves accuracy of spatial location of microseismic event hypocenters and increases validity of estimation of the fracturing direction. [ABSTRACT FROM AUTHOR]

Characterization of reservoir deliverability is fundamental for the economic development of any field. In the Bakken, there is a need for reliable pressure-transient tests to provide the effective formation permeability of the fracture/matrix system in this formation for deliverability calculations. This effective permeability can then be compared with laboratory-measured core permeability of the matrix rock samples. This comparison is the basis for planning early-production options and subsequent enhanced-oil-recovery (EOR) decisions. This comparison is particularly important because of the influence of massive hydraulic-fracture stimulation on reservoir performance. Determining well-deliverability potential by conventional drill-stem tests (DSTs) or traditional wireline formation tests (WFTs) in the past has resulted in mixed success in the Bakken. On the other hand, the mini-DST has increased the reliability of pressure-transient tests because the formation interval of interest is produced at a precise constant rate into a chamber between two inflated packers with negligible wellbore-storage effects. Also, the operation of a mini-DST tool requires much less time than the classical DST, and multiple zones can be tested sequentially to assess the individual-zone deliverability. The mini-DST tool uses the conventional WFT configured with a dual-packer module and downhole pump. Tests are conducted by inflating the dual-packer module to isolate a 3-ft interval of the wellbore. The formation fluid is pumped out from the packer-isolated wellbore interval to conduct pressure-drawdown and -buildup tests in the interval. An overlay of all the pressure-drawdown and -buildup results from various intervals is compared on a single plot to identify the most productive interval. Finally, conventional pressure-transient analyses are performed to interpret all pressure-drawdown and -buildup tests. In this paper, we present several field tests that were analyzed both by the preceding procedure and by numerical simulation. The analyses of several mini-DST results have provided insight into a better understanding of the flow mechanism in the Bakken both during primary production and in forecasting various improved-recovery and EOR proposals. The results can also serve as a basis for test design in similar low-permeability reservoirs elsewhere. [ABSTRACT FROM AUTHOR]

North Dakota Bakken oil recovery has increased nearly 100-fold over the last 5 years, driven by technological advancements in hydraulic fracturing and completion design. For one North Dakota operator with 150 Bakken producing wells, 22 of the wells have experienced at least one event of severe calcium carbonate scaling in the pump and production tubing, leading to well failure. Bakken wells are completed to a vertical depth of approximately 10,000 ft, with horizontal laterals up to 10,000 ft, and are produced by means of multizone hydraulic fracturing. The operator initially conducted a typical scale-prediction study to reduce well failures and maintain oil production. However, the scale-prediction study was challenging to perform for these Bakken wells because of the variability of the composition of the produced water. Attention then turned to the tracking and analysis of historical field conditions. A "post-mortem" of data collected from all failed wells because of scale was conducted, considering the failure type, date, type of hydraulic-fracturing procedure, pump-intake pressure, scale-inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure. Results showed that 82% of the wells failed during early production (defined as less than 20,000 bbls of water produced and 2 years' production since first oil), after which failures became increasingly rare. This correlated with transient alkalinity spikes in the water analyses attributed to fracturing-fluid flowback during this critical period. Simulated blending of fracturing and formation waters demonstrated that this was the most important period to maintain high scale-inhibitor residuals because of high deposition potentials. This paper discusses the various field and laboratory studies conducted in an effort to understand the problem, the results obtained, and the implications. Also discussed is the evaluation of two scale inhibitors before and after laboratory aging in simulated fracturing fluids. [ABSTRACT FROM AUTHOR]

The article presents a reprint of the article "Fear of Fracking," by Richard A. Epstein, which appeared in the 2011 issue of "Defining Ideas." It says that the advances in fracking technology has the potential to unlock even more petroleum and natural gas reserves in various areas of the U.S. like the Permian Basin in Texas and the Bakken formation in the Dakotas. However, the public and most environmentalist are against the use of nuclear power and fracking in petroleum product extraction.

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. [ABSTRACT FROM AUTHOR]