Bakken Formation Research Articles

Segregating Laterals for Efficient Gas Re-Injection in Shale Plays Using Smart Completion

There is a strong global demand for oil and gas resources, and forecasts indicate robust growth in oil demand in the coming years. Meeting this demand necessitates the exploitation of unconventional resources and enhancing the recovery of existing oil and gas fields. Field trials indicate that traditional gas injection in shale wells has low sweeping efficiency. Emerging technologies play an exceedingly significant role in solving the challenges of gas EOR in shale and tight formations. Among these advancements, smart or intelligent well technology has emerged as a promising solution to enhance field development outcomes. This study focuses on improving gas flooding efficiency in the Bakken formation by utilizing smart completions to reduce the gas–oil ratio (GOR) and increase oil recovery. An economic assessment of gas re-injection is conducted, considering both gas storage and enhanced oil recovery, with analysis incorporating capital expenditures, operating costs, and revenue from increased production. Reservoir simulations were employed to determine the most effective gas injection scenarios for maximizing recovery and storage efficiency. Simulation results demonstrate that 20% of perforated laterals account for 80% of the injected gas. To address this challenge, this work proposes using smart completions to segregate lateral sections, thereby optimizing gas injection efficiency, and unlocking additional oil in tight formations. Segregating horizontal laterals for gas re-injection using smart completion technology can achieve gas injection efficiencies of up to 0.25 barrels per Mcf of gas injected, with lower incremental gas production. The optimal injection rate is between 1 MMcfd and 3 MMcfd, with an injection period ranging from one to three years. It was also found that injecting gas into the toe section results in high bottom hole pressure but lower oil recovery due to reduced gas injection efficiency. From an economic perspective, the project yielded favorable outcomes, with a positive net present value (NPV) at a 7% discount rate. Even at lower oil prices (USD 50 per barrel), the Internal Rate of Return (IRR) was calculated to be 170%, indicating strong potential profitability.

Assessing the potential of large-scale geological hydrogen storage in North Dakota's Bakken Formation: A case study integrating wind-powered hydrogen production

The research seeks to assess the feasibility of utilizing depleted oil and gas reservoirs for large-scale hydrogen storage through wind energy in the Middle Bakken, North Dakota, USA. Despite the region's vast oil and gas reserves and development activities, wind energy for hydrogen production and storage remains largely untapped. The study discovered significant hydrogen storage capacities in Well A, Well B, and Well C, using a real gas behavior mathematical model. This presents a large-scale, co-located renewable energy storage solution serving as a model for the sustainable energy transition. The results show hydrogen storage potentials of 250.27, 401.48, and 163.296 ktons, respectively, with 50 % cushion gas. The cumulative hydrogen production and energy content from hydrogen over the study period were for Well B is 367,278 kg and 12,430 MWh, enabling hydrogen storage for up to 1088 days. A sensitivity analysis reveals that a lower cushion gas percentage is preferable for hydrogen storage efficiency. This approach is valuable for stakeholders, including government bodies, geological services, renewable energy facilities, and the chemical/petrochemical industry, as it provides opportunities in developing a co-located wind and hydrogen system to tackle the intermittent nature of wind energy and offers a sustainable repurposing of depleted oil and gas infrastructure, enhancing energy security and reducing greenhouse gas emissions while supporting sustainable energy transitions.

Evaluating the Impact of CO2 Submersion Time on the Permeability and Porosity of Carbonate-Rich Geological Samples: A Comprehensive Laboratory Study of Middle Bakken Formation

Evaluating the Impact of CO₂ Submersion Time on the Permeability and Porosity of Carbonate-Rich Geological Samples: A Comprehensive Laboratory Study of Middle Bakken Formation

An improved convolutional architecture for quantitative characterization of pore networks in fine-grained rocks using FIB-SEM

Focused ion beam scanning electron microscope (FIB-SEM) is one of the most advanced imaging techniques for analyzing and understanding complex pore networks in shale and other fine-grained formations. However, FIB-SEM imaging tends to be time-consuming and labor-intensive and can result in biased interpretations associated with pore analysis. Recently, U-Net or its variants for image segmentation have been applied to capture microscopic pores at higher resolutions. The ‘traditional’ encoder-decoder-based approaches tend to detect very fine-scale microscopic pores poorly. This study presents an improved convolutional architecture for automatically analyzing pore structures in shale reservoirs using FIB-SEM. It does so by applying an overcomplete convolutional architecture, KiU-Net, to capture very fine-scale microscopic pores by accurately defining their edges in the input FIB-SEM images. The KiU-Net learns low and high-level features by making the model more sensitive to fine-scale microscopic pores in the input images. The purpose of this study is to demonstrate KiU-Net's capabilities by analyzing different shale formations with varying characteristics. The results indicate that KiU-Net is more accurate and efficient than other methods in predicting nanopores in the Longmaxi, Niutitang, Qingshankou, Qianjiang, and Yanchang Formations (China), Bakken shale (Canada), and coal reservoirs (China). Furthermore, KiU-Net demonstrated the advantage of requiring fewer parameters and achieving super convergence compared to the Attention U-Net technique. KiU-Net addresses the challenges of the Edge-Threshold Automatic Processing (ETAP) methods by capturing very fine-scale microscopic pores with accurate edges. This study further enhances the accuracy and efficiency of pore analysis in shales, thereby offering an improved method for understanding shale reservoir quality with the potential to improve petroleum recovery from such formations.

Integration of Wind Energy and Geological Hydrogen Storage in the Bakken Formation, North Dakota: Assessing the Potential of Depleted Reservoirs for Hydrogen Storage

Integration of Wind Energy and Geological Hydrogen Storage in the Bakken Formation, North Dakota: Assessing the Potential of Depleted Reservoirs for Hydrogen Storage

Assessment of bi-metal paleo-redox proxies in the Bakken Formation black shales, Williston Basin, North Dakota, USA

The influence of paleoredox conditions and water-mass restriction on trace metal (TM) accumulation in the lower (LBS) and upper black shales (UBS) of the Devonian–Mississippian (D–M) Bakken Formation was assessed utilizing V/Cr, V/(V + Ni), Ni/Co, U/Th, and enrichment factors (EF) for Mo vs. U. These assessments were compared to previously published estimates based on degree of pyritization (DOPT), sulfur‑iron and C–S–Fe relationships, and sedimentological data. Bi–metal ratios suggest >80 % of samples were deposited under suboxic to anoxic/euxinic conditions, whereas DOPT results suggest >60 % of samples were deposited under dysoxic (0.42–0.75 DOPT) bottom–water conditions. DOPT results are in good agreement with C–S–Fe and total S vs. Fe assessments of paleoredox conditions and sedimentological evidence. Good agreement is also seen between Mo/TOC and Mo EF/U EF that both suggest the Bakken shales were deposited under a relatively unrestricted water mass conditions resulting in consistent renewal of TMs into the basin. With TM resupply outpacing drawdown, the basin could support enhanced primary productivity as well as high concentrations of TMs. Trace metal concentrations for the Bakken Fm. show considerable range for Co (0–10,324 ppm), Mo (0–2018 ppm), Ni (0–1574 ppm), U (0–1604 ppm), and V (0–3194 ppm), and bi–metal ratios for the Bakken Fm. are up to 5× greater than those reported for other D–M black shale formations. Bivariate and principal component analysis indicate Mo, Ni, U, and V accumulation was more closely associated with the organic fraction than with reducing conditions, thus accumulation of organic matter during deposition and generation, migration, and biodegradation of hydrocarbons during diagenesis may have influenced the accumulation and distribution of these TMs. Furthermore, changes in biogeochemical processes during the D–M transition may have fundamentally altered marine chemistry, with the evolution of vascular land plants and enhanced terrestrial weathering leading to an increased influx of nutrients into marine waters resulting in the Annulata, Dasberg, and Hangenberg black shale events. Factors controlling TM accumulation during time of deposition (e.g., TM availability, bottom-water redox conditions, adsorption onto organic matter) and during diagenesis and catagenesis (e.g., alteration and break down of organic matter, movement of fluid hydrocarbons or other basinal fluids) likely contribute to the lack of agreement between redox proxies, and subsequently, the lack of applicability of bi–metal ratios in assessing bottom–water conditions for the Bakken shales. Therefore, it is suggested that these bi-metal redox proxies are not an effective means to describe bottom-water conditions during the deposition of the Bakken shales.

‘Supercharged’ Shale EOR: A Liquid-Hydrocarbon-Based Approach Enters the Fray

Around a decade of research and testing has passed by, and the unconventional sector has yet to show that natural gas huff-and-puff can scale effectively across tight-oil fields. This doesn’t mean enhanced oil recovery (EOR) in shale is a lost cause. Though it does suggest that the industry needs alternatives to the first and most well-known method. Proof of this can be found in North Dakota’s Bakken Shale where researchers, operators, and a firm called EOR ETC have tried to show that the water-alternating-gas method is a cheaper, less gas-intensive way of adding incremental barrels. EOR ETC has indicated on its website that ExxonMobil subsidiary XTO Energy is currently testing the technology. Chevron has also recently shared how it has rethought shale EOR methods by designing a program for production-boosting surfactant injections and gas injections that can be done with artificial lift instead of giant compressors. Another emerging shale EOR concept goes a step further, arguing that the unconventional sector should abandon natural gas injections altogether. Denver-based Shale Ingenuity proposes that liquid-hydrocarbon solvents should be used instead. Shale Ingenuity has patented a process called SuperEOR, which it claims delivered a strong showing during its initial field test in the Eagle Ford Shale of south Texas. After nearly a year of cyclic solvent injections, which began in early 2023, a horizontal well with a 4,400-ft lateral and 16 fracture stages produced 44% more oil than its previous total output. This resulted in a 30-fold boost in flow rate, from 13 to 391 B/D. Building on its initial success, Shale Ingenuity informed JPT that two private producers in the Permian Basin and the Eagle Ford have selected its EOR technology for upcoming projects. Both will involve single four-well pads, with EOR operations expected to begin in 2026. The solvents used in the pilot consisted mostly of natural gas liquids (NGL)—ethane, propane, butane, and pentane. Shale Ingenuity said formulations may include other hydrocarbon and nonhydrocarbon liquids. While the bulk of these products flow straight out of thousands of wellheads in the US shale sector, Shale Ingenuity emphasizes that the key to unlocking their potential for EOR lies in its proprietary method of blending, or “tuning,” the solvents based on formation and crude oil properties. This allows the injected solvents to quickly mix with and help mobilize the residual oil droplets that are trapped in tight-rock formations, according to the company. Robert Downey, founder and CEO of Shale Ingenuity, explained the process. “The tuned solvents we are using have a minimum miscibility pressure (MMP) of 700 to 900 psi, which means it doesn’t take much pressure to drive them into solution. When pumped into the well, they instantly become miscible with oil, and as the formation heats up and the well is reopened, the solvents expand back into gas at 100 to 200 times their liquid volume.” The effect of all this is what he describes as a “supercharging” of the solution gas drive mechanism that promotes the strong early well flow shale wells are known for. This is the energy released by dissolved gas in the oil as it expands during the pressure drop brought on by producing the well.

Case Study: Understanding H2S Occurrence: Bakken Production Using Sulfur Isotopes

_ Souring—or H2S generation—in the Bakken petroleum system (BPS) production is becoming problematic for oil producers and pipeline operators because of the sporadic occurrence and associated economic and HSE impacts. Paradoxically, crude oil produced from the tight Middle Bakken (MB) and underlying Three Forks (TF) reservoirs of the BPS has historically been light (40 °API to 50 °API) with low sulfur content (<0.2 wt.%), typically exhibiting nonexistent to low (<10 parts per million) H2S concentrations. Additionally, neither the MB nor the TF reservoirs have public records indicating the presence of H2S during drillstem tests (DST). However, based on previous work performed by the University of North Dakota Energy & Environmental Research Center (EERC), the frequency of H2S occurrence in BPS wells has increased from 2010 to 2023. Even though the observed H2S increases correlate with larger, multistage well stimulation and completion practices in the BPS, the unclear geographical and temporal trends make the exact mechanisms responsible for souring an open research question. At least five known mechanisms can potentially lead to H2S occurrence in the oil production stream of BPS wells, including: 1. Thermochemical sulfate reduction (TSR) 2. Bacterial sulfate reduction (BSR) 3. Source rock generation 4. Migration from deeper or shallower H2S reservoirs 5. Geochemical mechanisms related to reservoir stimulation work (Table 1). Understanding the mechanisms of H2S generation might reduce the risk of souring in new wells and enable more effective mitigation and management strategies in the wells already producing H2S. Samples Used in the Study This study is focused on oil and gas operations in the North Dakota portion of the Williston Basin and the H2S occurrences in the BPS, which includes two main oil-producing reservoirs: the MB and the TF. In the simplified stratigraphic sequence, the BPS comprises three distinctive lithofacies. From deepest to shallowest, those lithofacies are the Lower Bakken Shale (LBS), the MB reservoir, and the Upper Bakken Shale (UBS). Underlying the BPS is the TF, the upper part of which is the oil-rich TF reservoir, considered part of the BPS. The UBS and LBS are the source rocks for the oil in MB and TF reservoirs and consist of black, organic-rich, siliciclastic mudstones (i.e., shale). Directly overlying the BPS is the Madison Group, a carbonate-dominated Mississippian section that is subdivided into three formations—the Lodgepole (LP), Mission Canyon (MC), and Charles. The Birdbear Formation lies beneath the TF and on top of the Duperow Formation. Both the Duperow and Birdbear Formations produce oil and are dominated by carbonate deposits of shallow marine limestone and dolostones. A sampling program was developed to investigate areas of the BPS with varying levels of souring in the production stream and multiple organic-rich formations representing potential source rocks, including the UBS, LBS, LP, and MC. The samples were collected from locations and formations with different lithologies and maturity levels. Over 70 sour wells were identified for H2S sampling in western North Dakota.

Geologic characteristics, exploration and production progress of shale oil and gas in the United States: An overview

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle–Late Devonian, Early Carboniferous (Middle–Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian–Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and “shale reservoirs” are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×1012 t and 290×1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the “shale revolution”, the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007–2023, shale oil and gas production in the United States increased from approximately 11.2×104 tons of oil equivalent per day (toe/d) to over 300.0×104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Insights on Using Solid Bitumen Reflectance as a Thermal Maturity Proxy in the Bakken Formation, Williston Basin, USA.

To further refine the use of solid bitumen reflectance (BRo in %) as a measurement of thermal maturity in source-rock reservoirs, we examined its relationship to other thermal proxies in the Bakken Formation. Comparisons included criteria from programmed temperature pyrolysis, gas chromatography (GC), and Fourier transform infrared (FTIR) spectroscopy. Thirty-two organic-rich samples from the lower and upper shale members of the Devonian-Lower Carboniferous Bakken Formation were collected from eight cores across the Williston Basin, USA, at depths (∼7575-11,330 ft) representing immature through post peak oil/early condensate thermal maturity conditions based on proximity to current hydrocarbon production. Unmodified BRo values were correlated to programmed temperature pyrolysis parameters (hydrogen index, production index, and T max), normal hydrocarbon and isoprenoid analysis of extractable organic matter (pristane/n-C17 and phytane/n-C18) from GC analysis, and peak ratios from FTIR spectroscopy (branching ratio and A-factor). Strong correlations between unmodified BRo values (not corrected to a vitrinite reflectance equivalent, VRe) and other thermal proxies suggest that BRo can be used as a direct thermal proxy in marine Paleozoic source-rock reservoirs where vitrinite is rare or absent. Moreover, an apparent overestimation of VRe at the lowest thermal maturity investigated herein may argue against the application of BRo conversion to VRe in the Bakken Formation. Solvent extraction caused a consistent decrease in BRo when average post-extraction values from a given well were compared to BRo prior to extraction, although the decrease in mean value was not statistically significant. These results are discussed in the context of advocating for the use of unmodified BRo values as a best practice for thermal maturity determination in Paleozoic marine source-rock reservoirs.

Sustainable hydrogen production from flare gas and produced water: A United States case study

Gas flaring and produced water (PW) emissions are common environmental challenges with significant impacts on the oil production industry. This study proposes a novel approach to address these concerns by developing energy self-sufficient networks for simultaneous utilization of flare gas (FG) and PW for sustainable hydrogen production. Three distinct scenarios are analyzed: hydrogen production without CO2 capture (Hydra), fossil fuel-based (FF) hydrogen production with CO2 capture and utilization in enhanced oil recovery (HydraCap-FF), and a solar-thermal-assisted HydraCap-FF system (HydraCap-RE). Techno-economic and environmental models are constructed for each scenario's optimal configuration, enabling a comparative analysis of their economic viability and environmental impact. Additionally, the designed systems are examined through a flexibility analysis to evaluate input materials and their influence on the system's viability. Results highlight the promising potential of HydraCap-RE, achieving significant reductions in CO2 emissions and water footprint compared to traditional methods. The HydraCap-RE generates hydrogen with the cost of 2.86 $/kg H2, hydrogen yield of 31.25 kg H2/100 kg FG, specific emission of 0.86 kg CO2/kg H2 and water footprint of 0.185 kg H2O/kg H2. Moreover, the flexibility analysis indicates that an optimal FG/PW ratio of 0.53 yields the highest economic value. The results demonstrate that deploying HydraCap-FF in the Permian, Bakken, and Eagle Ford shale regions can produce 0.807, 0.454, and 0.121 million tons of hydrogen annually, respectively, and reduce CO2 emissions by 6.37, 3.58, and 0.956 million tons, respectively. Furthermore, the HydraCap-RE deployment in these shale fields outperformed, with 17 % higher hydrogen production and 28.42 % lower CO2 emissions. These findings provide valuable insights for decision-makers seeking to reduce CO2 emissions the oil and gas industries and providing clean and sustainable products for these areas.

Experimental investigation of zwitterionic surfactant for enhanced oil recovery in unconventional reservoir: A study in the middle bakken formation

Some surfactants may not be effective in harsh reservoir environments because of their tendency to precipitate in high salinity and high temperature conditions. However, Zwitterionic surfactants are considered more tolerant to salinity and temperature. This study investigates the ability of zwitterionic surfactants to improve oil recovery in tight core samples obtained from the Middle Bakken (MB) Formation in North Dakota. The Laboratory tests to determine the efficacy of three betaine zwitterionic surfactants were carried out at a temperature of 90 °C and a high salinity formation brine of 29 wt% to simulate oil recovery under Bakken reservoir conditions. Before the imbibition experiment, the samples underwent petrophysical investigation, and the mineral compositions were determined using the XRD method. The three surfactant samples ME1, CD 2, and CG 3 applied in the study consistently changed the wetting condition of Bakken cores from contact angle of 143.2° to a range of 32°-42°, indicating changing from oil-wet to water-wet. The result obtained shows that the interfacial tension (IFT) between brine and crude oil was reduced from 34.5 mN/m to 8.9 × 10−1 mN/m, 1.19 mN/m, and 2.49 mN/m, respectively, at a critical micelle concentration (CMC) of 0.05 %. The surfactants demonstrated a significantly higher ability to recover oil from the core samples compared to the use of brine only. The imbibition experiments revealed an extra oil recovery of 16.4 % at CMC. Thus, the imbibition of surfactant formulations offers significant potential for enhancing oil recovery in the Bakken Formation.

Analyzing thermal maturity effect on shale organic matter via PeakForce quantitative nanomechanical mapping

Organic-rich shales have gained significant attention in recent years due to their pivotal role in unconventional hydrocarbon production. These shale rocks undergo thermal maturation processes that alter their mechanical properties, making their study essential for subsurface operations. However, characterizing the mechanical properties of organic-rich shale is often challenging due to its multiscale nature and complex composition. This work aims to bridge that knowledge gap to fully understand the nanomechanical properties of Shale organic matter at various thermal maturation stages. This study employs PeakForce Quantitative Nanomechanical Mapping (PF-QNM) using Atomic Force Microscopy (AFM) to investigate how changes at the immature, early mature, and peak mature stages impact the mechanical properties of the Bakken Shale organic matter. PF-QNM provides reliable mechanical measurements, allowing for the quantification and qualification of shale constituents' elastic modulus (E). We also accounted for the effect of probe type and further analyzed the impact of probe wear on the nanomechanical properties of shale organic matter. In immature shale, the average elastic modulus of organic matter is approximately 6 ​GPa, whereas in early mature and peak mature shale, it decreases to 5.5 ​GPa and 3.8 ​GPa, respectively. Results reveal a mechanical degradation with increasing thermal maturation, as evidenced by a reduction in Young's modulus (E). Specifically, the immature shale exhibits an 8% reduction in E, while the early mature and peak mature shales experience more substantial reductions of 31% and 37%, respectively. This phenomenon could be attributed to the surface probing of low-modulus materials like bitumen generated during heating. The findings underscore the potential of AFM PF-QNM for assessing the nanomechanical characteristics of complex and heterogeneous rocks like shales. However, it also highlights the need for standardized measurement practices, considering the diverse components in these rocks and their different elastic moduli.

How Quickly Do Oil and Gas Wells “Water Out”? Quantifying and Contrasting Water Production Trends

Water production from petroleum (oil and natural gas) wells is a topic of increasing environmental and economic importance, yet quantification efforts have been limited to date, and patterns between and within petroleum plays are largely unscrutinized. Additionally, classification of reservoirs as “unconventional” (also known as “continuous”) carries scientific and regulatory importance, but in some cases the distinction from "conventional" wells is unclear. Using water, oil, and gas production data, we calculated a set of quantitative metrics that elucidate trends in the water-to-petroleum ratio over the life of each producing well. The percent growth of the water-to-petroleum ratio quantifies the degree to which a well “waters out” over time; values calculated for 153,900 wells in 18 oil and gas plays show generally much higher values for conventional wells than for continuous/unconventional wells. Analysis of the percent growth along with the slope and median metrics reveals greater variation between conventional plays and between continuous (unconventional) plays than previously recognized. Further, an example from the Bakken Formation in the Williston Basin, USA, illustrates that, within a single play, the metrics provide insight into spatial variation of water production trends, as influenced by geology and reservoir characteristics. By quantifying the variability of water production trends within individual plays and between plays, including differences between conventional and continuous (unconventional) plays, these results provide a more nuanced view of water production from oil and gas wells than has previously been possible and they illustrate the degree to which water management considerations vary spatially and temporally.

Refining vanadium hyper‐enrichment in black shales of the Late Devonian–Early Mississippian Bakken Formation (USA)

AbstractVanadium hyper‐enrichment (V ≥ 500 μg g−1) is widespread in ancient marine organic‐rich sedimentary rocks and is controlled by its source and accumulation. To understand how V source and accumulation control V hyper‐enrichment, the V hyper‐enriched organic‐rich black shales of the Late Devonian–Early Mississippian Bakken Formation (USA) were investigated here. The results imply that V in the Bakken Formation black shales is mainly derived from detritus and open ocean. Its hyper‐enrichment was always related to the complexation of V(IV) species by organic matter and/or fine clay mineral adsorption, though extremely reducing (i.e. euxinic) depositional conditions sometimes assisted in accumulating V through forming V(IV)–sulphur structure and/or V(III). Vanadium is a frequently used seawater redox indicator, but its hyper‐enrichment in marine sediments/sedimentary rocks does not always need to be redox driven. This study, thus, reminds us to be more careful when reconstructing palaeoceanographic redox states using V‐involved proxies.

ОГЛЯД ВІЗЕЙСЬКИХ КОЛЕКТОРІВ НЕТРАДИЦІЙНОГО ТИПУ ДНІПРОВСЬКО-ДОНЕЦЬКОЇ ЗАПАДИНИ ТА ПОРІВНЯННЯ З ПІВНІЧНОАМЕРИКАНСЬКИМИ НЕТРАДИЦІЙНИМИ ФОРМАЦІЯМИ

Background. Modern advances in the extraction of hydrocarbons from shale and tight formations, namely improved horizontal drilling technologies and multi-stage hydraulic fracturing at economically viable costs, are opening up new horizons for oil and gas exploration and development around the world. The importance of shale oil and gas has sparked interest around the world following the great success of production in North America. This article is a continuation of a series of publications on the study of Visean unconventional reservoirs within Dnipro-Donets Depression. In this paper, the Visean sediments, namely the Lower Visean carbonate plate of the XIII MFH (horizons V-24-25), and the "Rudov Beds", siliceous calcified organic-rich shales (V-23) within the identified prospective zones of the Dnipro-Donets Basin (DDB), are considered for their unconventional reservoir development potential using the method of analogy with successful North American formations. Methods. Key geological and geochemical parameters were compared with the selected analogues, namely, geological age, sedimentation conditions, lithology and sediment thickness, geochemical data (total organic carbon (TOC), vitrinite reflectance (Ro), rock generation properties according to pyrolytic studies and rock maturity), mineralogical composition and porosity. Results. According to this study, the Visean unconventional deposits within DDB clearly correlate with the most productive gas fields from unconventional reservoirs (shales, organic-rich carbonates) in North America. The depth and geological position of the Visean unconventional targets are generally comparable to or slightly higher than their North American counterparts based on available data; sediment thicknesses are in similar ranges. In terms of mineralogical composition, namely X-ray diffraction (XRD) analysis, the ore beds are similar to the Barnett and Woodford shales, and the V-24-25 carbonate horizons correspond to the Eagle Ford Formation. The high average TOC content of the V-23 horizon (up to 10% by weight) is comparable to the Bakken and Woodford shales. Сonclusions. The geological and geochemical parameters of the Visean horizons considered in this paper are promising in terms of the prospects for the development of unconventional reservoirs to increase Ukraine's energy resource base. However, in order to draw conclusions about the economic profitability of the development of the studied objects, a more detailed study is required, taking into account the results of drilling and testing after multistage hydraulic fracturing.

A Comparative Assessment of the Potential of the Bakken Formation Oil and Gas Field Produced Water for Critical Mineral Extraction, with a Focus on the Inyan Kara Formation: An Analysis of Salinity and Infrastructure

A Comparative Assessment of the Potential of the Bakken Formation Oil and Gas Field Produced Water for Critical Mineral Extraction, with a Focus on the Inyan Kara Formation: An Analysis of Salinity and Infrastructure

Trace-metal enrichment mechanisms in Bakken Formation black shales, Williston Basin, North Dakota, USA

The Bakken black shales represent a unique sedimentary system characterized by high total organic carbon contents (TOC; Lower Bakken shale = 10.8 and Upper Bakken shale = 11.8 avg. wt%) and enrichment factors (EF) of various trace metals (TMs) such as Cu (6.2–7.7), Mo (219.7–237.8), Ni (9.4–10.2), U (20.6–29.3), V (9.9–14.2), and Zn (10.4–12.2) that are considerably higher than many other Devonian-Mississippian (D–M) black shales. In this study, raw distributions of elemental concentrations combined with bivariate and principal component analysis (PCA) were used to clarify processes that contributed to high TM EF values in the Bakken shales. Total organic carbon shares heavier PCA component loadings (>0.445) and stronger Pearson correlation coefficients (r) with Cu, Mo, Ni, U, V, and Zn than with pyrite-associated (As, Co, Fe, and S) elements, suggesting that organic matter (OM) played a primary role in the scavenging and accumulation of TMs in the sediments. Reducing conditions within bottom waters or sediment pore waters may have accelerated the accumulation of redox-sensitive Cu, Mo, Ni, V, and Zn introduced into the sediments via an OM detritus host and most likely played a secondary role in their enrichment. Deep-water renewal times for the Bakken have been estimated to be ∼10–30 yrs. based on Mo/TOC results. The high TM EF values observed in the Bakken shales may reflect frequent resupply of TMs into basin waters, enhanced primary productivity that is necessary in scavenging TMs from the water column, the presence of H2S within sediment pore or bottom waters, or possibly secondary processes associated with basin-wide fluid and hydrocarbon migration. High TOC concentrations may be the result of a possible shallow water column (∼150 m), which would limit exposure time of OM to oxidation and degradation, coupled with intermittent fluctuations between dysoxic and anoxic/euxinic bottom-water redox conditions, the latter of which would reduce rates of OM degradation by benthic organisms.

Enhanced oil recovery through alternating gas Re-injection to reduce gas flaring in the Bakken

Environmental performance is a significant driver of energy production today, and providing attractive methods to reduce flaring remains a high priority for oil producers. The Energy & Environmental Research Center (EERC), with support from the Bakken Production Optimization Program (BPOP), is investigating the reinjection of the associated gas into producing wells to reduce flaring.The project's main objectives are to evaluate technically and economically the feasibility of deploying alternating gas re-injection in the Bakken formation as a means to increase oil recovery, reduce flaring and maintain compliance. The approach addresses the compression capacity constraints, mineral ownership types, and gas availability. Gas reinjection has the added benefit of producing incremental oil that can offset installation and operational costs associated with gas compression and nonproducing time for a well during injection. A flow simulation model is created to investigate alternating gas injection of a four-well pad and to assess the possibility of incremental oil production. Extensive numerical simulation is conducted. Capital expenditure, operating costs and the revenue from oil recovery were considered. Results indicate that gas injection within rates of 100–200 Mcfd can produce incremental oil. The gas volume needed is greater than what is typically flared from a facility, however, less than the total produced gas volume, and, therefore, possible. Communication of gas is likely to occur between wells within 1500 feet and wells positioned heel to heel that are common to the well-pad facility. The most promising injection period appeared to be within a 2-week to 1-month cycle. Thus, the proposed approach can be employed as an efficient Enhanced Oil Recovery (EOR) technique, alternating gas injection of 3 MMcfd may potentially increase the produced oil rate by 70 %. The findings support continued work to further investigate well configurations that can best benefit from the technique and to mature economic case studies.

Organic petrology and geochemistry of the Devonian-Mississippian bakken formation, Williston Basin, North Dakota

The Devonian–Mississippian (D–M) black shales of the Bakken Formation are of interest as a hydrocarbon source due to their high total organic carbon (TOC; 2.2–17.4%) content. The Upper and Lower Members of the Bakken Fm. are shallow marine (100–150 m) sequences. Thirty samples were selected for maceral identification, kerogen typing, and solid bitumen reflectance (SBRo) based on TOC content and down-core spacing. The shales contain alginite, bituminite, abundant solid bitumen (SB), and minor amounts of inertinite. Solid bitumen increases in quantity with increasing thermal maturity. Pyrolysis (85 samples) provided S1 (avg. 8.0 mg HC/g rock), S2 (avg. 24.3 mg HC/g rock), hydrogen index (HI; avg. 201 mg HC/g TOC), oxygen index (OI; avg. 7 mg CO2/g TOC), and Ro (0.60–1.03%) calculated from Tmax. Plots of HI vs. OI and HI vs. Tmax (°C) were used to assess kerogen type but are not consistently in agreement with the petrographic assessment. Some samples from more thermally mature cores plot as Type III (vitrinite) kerogen instead of Type II (alginite and bituminite) kerogen, the latter confirmed through petrographic observations of lower maturation samples. This is largely due to increased SB in more thermally mature samples (Ro = 0.83–1.03%), as SB is known to have a lower HI content than Type II kerogen. Petrographic data show more alginite and bituminite (19–55%) in the thermally less mature samples (Ro = 0.60–0.83%) compared to more dispersed SB (67–86%) and less alginite and bituminite (<1%) in the more thermally mature samples (Ro = 0.89–1.01%).Early research on the Bakken Fm. reported lower than expected vitrinite reflectance values and attributed them to vitrinite “suppression”. The scarcity of vitrinite and abundance of SB suggest that early work likely reported reflectance on SB. Recent attempts to assess the thermal maturity of the Bakken black shales have converted SBRo to vitrinite reflectance equivalence (VRE). However, there are multiple SB populations present in these shales and it is not always clear which SB populations were included, possibly contributing to error. In the current study, only smooth, homogenous SB was measured (0.68–1.14% SBRo) and VRE values calculated (0.54–1.49%) to assess thermal maturity from the basin margin to the depocenter; inclusion of measurements on granular, heterogeneous SB (14–21 vol%), which are ~53% lower than those for smooth, homogenous SB (3–12 vol%), results in lower mean reflectances, especially in more mature samples. Vitrinite reflectance equivalent data calculated using the D–M New Albany Shale equation of Liu et al. (2019) agrees with liptinite fluorescence and Rock-Eval Ro, whereas VRE based on the D–M Woodford Shale equation of Cardott and Comer (2021) does not. This suggests the importance of applying VRE equations from similar formations both in terms of thermal history, as well as kerogen type and age. Results from SBRo, Rock-Eval Ro, VRE, and observations of alginite fluorescence indicate that samples from the current study range from the early oil window into the condensate, wet gas zone.