Unconventional Hydrocarbon Reservoirs Research Articles

Advanced Determination of Heat Flow Density on an Example of a West Russian Oil Field

Reliable geothermal data are required for basin and petroleum system modeling. The essential shortcomings of the methods and results of previous geothermal investigations lead to a necessity to reappraise the data on the thermal properties and heat flow. A new, advanced experimental basis was used to provide reliable data on vertical variations in the thermal properties of formation and heat flow for the area surrounding a prospecting borehole drilled through an unconventional hydrocarbon reservoir of the Domanik Formation in the Orenburg region (Russia). Temperature logging was conducted 12.5 months after well drilling. The thermal properties of the rocks were measured with continuous thermal core profiling on all 1699 recovered core samples. Within non-cored intervals, the thermal conductivity of the rocks was determined from well-logging data. The influence of core aging, multiscale heterogeneity and anisotropy, in situ pressure and temperature on the thermal properties of rock was accounted for. The terrestrial heat flow was determined to be 72.6 ± 2.2 mW·m−2—~114% larger than the published average data for the studied area. The experiment presents the first experience of supporting basin modeling in unconventional plays with advanced experimental geothermal investigations.

Upper Jurassic–Lower Cretaceous calpionellid zones in the Neuquén Basin (Southern Andes, Argentina): Correlation with ammonite zones and biostratigraphic synthesis

This work presents the first regional biostratigraphic study on the calpionellid zones and assemblages of the Tithonian–lower Valanginian interval in the Neuquén Basin, Southern Andes, Western Argentina. The lower Tithonian–lower Valanginian in the Neuquén Basin is mainly represented by the Vaca Muerta Formation, which is a thick sucession (100–1250 m thick) of rhythmic marlstone and limestone alternations corresponding to the distal hemipelagic facies of a carbonate ramp. This formation is one of the most important unconventional hydrocarbon reservoirs in the world and has become a relevant target in Argentina during the last decade. The Vaca Muerta Formation is characterized by an abundant fossil content and a remarkable stratigraphic continuity along several hundred meters, encompassing the Jurassic/Cretaceous boundary. The detailed study of seven outcrop and well sections (three of them studied for the first time herein), allowed the elaboration of a reliable stratigraphic scheme based on the correlation of ammonites, microfossils, magnetostratigraphy and cyclostratigraphy. The Vaca Muerta Formation contains moderate to poorly preserved calpionellids. Despite that, twenty-six calpionellid species and five calpionellid biozones known in the Tethyan regions have been identified: Chitinoidella, Crassicollaria, Calpionella, Calpionellopsis and Calpionellites. Additionally, nine subzones were recognized: Slovenica, Boneti, Remanei, Massutiniana, Alpina, Elliptica, Simplex, Oblonga, and Darderi. These results allow chronostratigraphic correlations between the Tethys and the Southeastern Pacific domains.

Experimental investigation on the application of carbon dioxide adsorption for a shale reservoir

AbstractNew advancements in unconventional oil reservoirs to enhance cumulative oil production are essential for petroleum industries to develop new oilfields. Carbon dioxide injection (CO2) is considered one of the most functional enhanced oil recovery (EOR) methods, especially in shale reservoirs, regarding their low permeability of pores and cracks. This paper aims to experimentally investigate the crucial factors such as shale particle size, pressure, and temperature on the CO2 adsorption that can be used as a useful guideline for developing unconventional hydrocarbon reservoirs. Thereby, pressure increase would be an essential parameter to increase CO2 storage capacity; however, temperature increase has a reverse pattern and has caused to decrease the CO2 storage capacity. The essence of the oil recovery factor from shale reservoirs is another crucial factor that depends on the pressure, temperature, and soaking time factors. CO2 injection would be a proper (EOR) method to increase the oil recovery factor for higher pressures and temperatures. Therefore, the applicability of CO2 injection in shale reservoirs could provide efficient results rather than other EOR techniques.

Earthquake Source Mechanisms and Stress Field Variations Associated With Wastewater‐Induced Seismicity in Southern Kansas, USA

AbstractThe strong increase of seismicity rates in the contiguous USA over the last 10 years is linked to the injection of huge amounts of wastewater from oil and gas production in unconventional hydrocarbon reservoirs. We calculated 549 moment tensors of induced earthquakes (MW ≤ 4.9) in southern Kansas to study their source mechanisms and their relation to injection activity. Seventeen percent of the events analyzed contained significant volumetric (ISO%) components, and these events mostly occurred near the two largest local earthquakes during the 4 months of largest active wastewater disposal. Mapping the local stress field, we determined that most of the region lies within a transtensional stress regime, with a maximum horizontal stress σHmax trending N75°E. In the epicentral area of the MW 4.9 Milan earthquake, the σHmax trend is rotated to about S80°E. Locally, two areas display a change in the stress field orientation with depth, from transtensional above 5.5 km depth to strike slip deeper in the basement. Relating the resolved fault geometries to the obtained local stress field orientation, we find that most of the activated fault planes were optimally oriented to the current stress field and thus small stress perturbations caused by the water injection could lead to failure.

Geomechanical properties of the Permian black shales in the southern main Karoo Basin: lessons from compositional and petrophysical studies

AbstractPermian black shales from the lower Ecca Group of the southern main Karoo Basin (MKB) have a total organic carbon (TOC) of up to ~5 wt% and have been considered primary targets for a potential shale gas exploration in South Africa. This study investigates the influence of shale composition, porosity, pressure (P) and temperatures (T) on their geomechanical properties such as compressive strength and elastic moduli. On average, these lower Ecca Group shales contain a high proportion, ~50 to 70 vol%, of mechanically strong minerals (e.g., quartz, feldspar, pyrite), ~30 to 50 vol% of weak minerals (e.g., clay minerals, organic matter) and ~0 to 50 vol% of intermediate minerals (e.g., carbonates), which have highly variable mechanical strength. Constant strain rate, triaxial deformation tests (at T ≤100°C; P ≤50 MPa) were performed using a Paterson-type high pressure instrument. Results showed that the Prince Albert Formation is the strongest and most brittle unit in the lower Ecca Group in the southern MKB followed by the Collingham and then the Whitehill Formation. Compressive strength and Young’s moduli (E) increase with increasing hard mineral content and decrease with increasing mechanically weak minerals and porosity. On comparison with some international shales, for which compositional and geomechanical data were measured using similar techniques, the lower Ecca Group shales are found to be geomechanically stronger and more brittle. This research provides the foundation for future geomechanical and petrophysical investigations of these Permian Ecca black shales and their assessment as potential unconventional hydrocarbon reservoirs in the MKB.

Effects of Fracturing Parameters on Fracture Unevenness During Large-Stage Multi-Cluster Fracturing in Horizontal Wells

Horizontal wellswith multi-cluster fracturing technology is an effective approach to exploit unconventional hydrocarbon reservoirs. The on-site diagnosis results indicate that multi-cluster fractures always tend to propagate unevenly due to stressinterference, therefore it is very essential to study the effect of fracturing parameters on fracture propagation unevenness. In this paper, the unconventional fracturing model (UFM, Unconventional Fracturing Model) is used to study the effect of multi-cluster fracturing parameters on fracture unevenness in a large stage. This model has been validated with the actual fracturing case on-site in the Longmaxi shale. The investigated parameters include completion parameters (cluster spacing, number of perforations per cluster), pumping parameters (fluid injection intensity and proppant injection intensity). Our simulation results show that firstly reducing fracture spacing will increase stress interference, andhydraulic fractures exhibit a “radial” pattern. Secondly, reducing the perforation number of a single cluster can promote the more uniform propagation of multi-cluster fractures. Thirdly, increasing the fluid injection intensity will increase the fracture length, but will also increase the fracture unevenness. Besides, the injection strength of the proppant has a little effect on the average fracture length and the unevenness of the fracture length. Finally, setting a reasonable cluster spacing and injection fluid strength can obtain a more uniform fracture propagation. Meanwhile reducing the number of perforations per cluster can also reach the goal of propagating evenly. This paper provides a certain reference for the optimization of multi-cluster fracturing parameters in large-stage and multi-cluster wells.

On the application of surfactant and water alternating gas (SAG/WAG) injection to improve oil recovery in tight reservoirs

Tight reservoirs are considered one of the unconventional hydrocarbon reservoirs with low permeability and porosity, directly affecting the oil production rate rather than conventional reservoirs. Thereby, optimum enhanced oil recovery methods would help petroleum industries produce more oil volumes from these reservoirs. In this study, different chemical and thermal enhanced oil recoveries methods such as surfactant alternating gas (SAG), water alternating gas (WAG), surfactant and foam flooding, and carbon dioxide (continuous and cyclic) were experimentally investigated to measure oil recovery factor. According to the results of this study, 3.5% of surfactant concentration, 0.15 PV of surfactant slug size, and 0.75 PV was selected as the total surfactant injection volume was selected as the optimum concentration for the injectivity performances. SAG scenario provided the highest oil recovery factor among all injectivity scenarios. It is about 54% that indicated the best efficiency of enhanced oil recovery methods in tight reservoirs rather than conventional recovery methods. The second highest oil recovery factor is dedicated to the WAG injectivity scenario regarding the feasibility of CO2 phase through porous media. It is about 46%. Moreover, due to the -gas phase in WAG and SAG, water cut had fluctuated as the water and gas had been alternatively injected into the core samples.

Rescaling Method for Improved Machine-Learning Decline Curve Analysis for Unconventional Reservoirs

Summary Decline curve analysis (DCA) has been widely applied in production forecasting of wells in unconventional hydrocarbon reservoirs. However, traditional curve-fit-based methods fall short of forecast accuracy due to three weaknesses: first, they cannot capture the reservoir signals not modeled by the underlying DCA model formulas; second, when predicting the production of a target well, the production history of other wells in the geologic formation (which is valuable information) is not considered; third, the wells’ geographic, geologic, wellbore, well spacing, and completion properties, which are highly relevant to production capability, are not used. More recent approaches have begun replacing traditional DCA with machine-learning methods [e.g., random forest (RF), support vector regression (SVR), etc.] for production forecast. Nevertheless, these methods are still suboptimal in detecting similar production trends in different wells, leading to large forecast error. A new and simple method called dynamic production rescaling (DPR) is developed to improve the accuracy of machine-learning DCA (ML-DCA). By combining DPR with common ML-DCA methods, we observe that the error mean, deviation, and skewness can be significantly reduced by 15 to 35% compared with ML-DCA without DPR. The error reduction is 30 to 60% compared with automatic curve fit of the traditional modified Arps DCA model. DPR has been tested successfully on monthly production data of over 20,000 unconventional horizontal wells in the Permian and Appalachian basins for both long- and short-term forecasts. The significant error reduction is consistent across different basins and formations. DPR is computationally efficient, so a large number of wells can be analyzed automatically and quickly. Moreover, the effectiveness and efficiency of DPR is independent of the underlying machine-learning algorithm, further demonstrating its robustness.

Hierarchical clustering of Pristane and Phytane data to identify the sweet spots in the shale reservoirs

Shale plays have gained prominence as unconventional hydrocarbon reservoirs in the last two decades. The prime aim of most of the petroleum operators is to extract hydrocarbon in a timely and cost-effective manner. For this, operators carry out extensive technical analysis of shale plays to find the sweet spots. Technical studies behind sweet spot mapping often require data like core data, wireline logs and seismic data which involves more capital expenditure. During limited availability of such data, low-cost information like fluid geochemistry can be used to identify sweet spots. Many authors have used Pristane (Pr), Phytane (Ph) and normal alkane (nC17, nC18) to determine the depositional environment, maturity and the kerogen type of the source rock in the conventional hydrocarbon system. This data set combination has rarely been used for sweet spot mapping in shale plays. In this study, an attempt was made to integrate data analytics and fluid geochemical data (mainly Ph/nC18 and Pr/nC17) to map the sweet spots within a producing shale play of North America, i.e. the Eagle Ford Shale.Fluid geochemistry data of 77 wells were used and with the help of hierarchical clustering all the data were segregated into 3 groups and integrated with the present and the paleo-structure maps to identify the sweet spots. Finally, the sweet and non-sweet spots were validated with the help of a few other datasets like Th/U ratio, core and log TOC and the actual production data.This study helped in demarcating the geographical distribution of the sweet and non-sweet spots within the study area of the Eagle Ford Shale. It has also explained the usefulness of fluid geochemical data and hierarchical clustering as a tool for the identification of sweet spots in the absence of an adequate amount of wireline logs, core and seismic data.

EOR applications in unconventional hydrocarbon reservoirs – Numerical trend analysis

This paper presents a detailed numerical trend analysis performed on a mechanistic compositional model using a multiple fractured, single well huff-n-puff technique. A wide range of formation and fluid properties, hydraulic fracture, and operational design considerations with several injectant types using single and multiple huff-n-puff cycles are investigated with different operational alignments. The objective of this study is very well achieved, which is to determine a fluid flow performance trend under different circumstances such that to come up with an optimal EOR and hydraulic fracture design to develop a UHR.

Study of the pattern of fluid flow in the pore space of kerogen-clay-carbonate-siliceous rocks of Bazhenov Suite

The paper is devoted to a numerical study of the features of fluid redistribution in the pore space of an unconventional hydrocarbon reservoir of the Bazhenov Suite (West Siberian oil and gas basin). We analyzed the filtration properties of the microscale layers of the formation with composite structure and multiscale porosity using the triaxial compression test. The simulation results showed that the flow rate of the pore fluid is determined by a set of parameters, including the rate of change of local stresses, the permeability of the skeleton, the viscosity of the pore fluid, reservoir pressure and the size of its differential region. We revealed the dimensionless combination of these parameters that uniquely determines the value of the fluid flow rate. The results of the study can be used in assessing the contributions of the structural elements structure to reservoir production capacity.

Diagenesis of the Vaca Muerta Formation, Neuquén Basin: Evidence from petrography, microthermometry and geochemistry

The Tithonian Vaca Muerta Formation (500 m-thick marine carbonates) in the Pampa de Tril area is a potential unconventional hydrocarbon reservoir but earlier studies rarely focused on its diagenetic history. It constitutes the upper part of the lower Mendoza Group in the Neuquén Basin, western Argentina. Petrographic examinations reveal four generations of calcite (C1, C2, Cb and C3). The microbial lime mudstone (C1, <4 μm), which exhibits dull cathodoluminescence (CL), is the most abundant with mean δ18O value of −7.2 ± 1.3‰ (VPDB) and δ13C of −1 ± 3.3‰ (VPDB) and deemed to have deposited in tropical warm shallow-water settings. The equant calcite cement (C2, 25 μm–140 μm) exhibits red CL and is associated with recrystallization of bioclasts and micritic matrix. The fibrous calcite (Cb, 35 μm–125 μm) fills parallel-to-bedding antitaxial veins (beefs) and shows bright orange CL. Its δ18O and δ13C values are more depleted (−10.7 ± 2.2‰ VPDB and −4.8 ± 3.9‰ VPDB, respectively) relative to those of C1, which is consistent with the occurrence of hydrocarbon fluid inclusions and may imply precipitation during a mid-to late stage of diagenesis within the oil window. The fracture-filling C3 consists of coarse subhedral crystals (40 μm–5 mm) showing bright orange CL, which has been interpreted as precipitated during deep burial conditions at temperatures around 118 ± 26.8 °C based on fluid-inclusion microthermometry. The relative depletion of Fe and Mn from C1 to C3 and the low concentration of U, may imply a relatively closed system of low water/rock interaction and restricted meteoric alteration. The shale normalized (REESN) patterns of C1, Cb and C3 generally exhibit parallel patterns with a distinct positive Eu anomaly and progressive enrichment towards the MREE and HREE. The positive Eu (Eu/Eu*)SN anomalies reflect the impact of dissolution of plagioclase feldspars by circulation of the diagenetic fluids through the surrounding siliciclastics in the basin.The Ce (Ce/Ce*)SN and La (La/La*)SN anomalies of Cb and C3 are consistent with precipitation under reducing conditions of deep burial settings. The Vaca Muerta carbonates are enriched in organic matter (up to 12%) that fills the pores but permeability is insignificant.

Propagation simulation and structural characterization of multiple hydraulic fractures in naturally fractured unconventional hydrocarbon reservoirs

Multiple hydraulic fractures in naturally fractured unconventional hydrocarbon reservoirs often induce complex fracture network growth, as revealed by microseismic monitoring data from Maxwell et al. (2002), Fisher et al. (2005) and Daniels et al. (2007). History matching and production forecasting from an unconventional hydrocarbon reservoir are possible only if a complex fracture network can be clearly described through the engineering parameters. However, the current integrated technology of propagation simulation and structural characterization of a complex fracture network still presents extreme challenges. A new propagation modeling and characterization technique has been developed for complex fracture network expansion that combines the improved displacement discontinuity method (DDM) and pseudo-3D fracture propagation model to simulate the propagation process of complex fracture networks and increase stimulation accuracy. These improvements are very important for modeling and simulation of multifracture propagation in an unconventional hydrocarbon reservoir with natural fractures. The theoretical model includes the calculation model of the combined stress field, the mechanical model of fracture propagation patterns and corresponding propagation criteria, the injection fluid distribution model, and the mathematical model for structural description and morphological characterization as a postprocessing program. The propagation simulation results for a complex fracture network are implicitly and directly entered into the postprocessing program and further characterized by some engineering parameters. Simulation results show that different fracture network propagation patterns are produced, which are governed by the in situ stress anisotropy, hydraulic fracture density, and distribution modes of pre-existing natural fractures as well as the fracture interaction angle. More importantly, the simulation results can be characterized by different engineering parameters. The presented comprehensive workflow could assist reservoir engineers in clearly understanding and evaluating complex fracture networks, including the geometric morphology, spatial distribution and conductivity of complex fracture networks. This technique can help identify stimulation and forecasting strategies that will significantly improve well performance and ultimate recovery from unconventional hydrocarbon reservoirs.

A unified model for the formation and distribution of both conventional and unconventional hydrocarbon reservoirs

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology; that has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, what is the difference of conventional and unconventional resources and why they always related to each other in petroliferous basins is not clear. As the differences and correlations between unconventional and conventional resources are complex challenging issues and very critical for resources assessment and hydrocarbon exploration, this paper focused on studying the relationship of formations and distributions among different oil/gas reservoirs. Drilling results of 12,237 exploratory wells in 6 representative petroliferous basins of China and distribution characteristics for 52,926 oil/gas accumulations over the world were applied to clarify the formation conditions and genetic relations of different oil/gas reservoirs in a petroliferous basin, and then to establish a unified model to address the differences and correlations of conventional and unconventional reservoirs. In this model, conventional reservoirs formed in free hydrocarbon dynamic field with high porosity and permeability located above the boundary of hydrocarbon buoyancy-driven accumulation depth limit. Unconventional tight reservoirs formed in confined hydrocarbon dynamic field with low porosity and permeability located between hydrocarbon buoyancy-driven accumulation depth limit and hydrocarbon accumulation depth limit. Shale oil/gas reservoirs formed in the bound hydrocarbon dynamic field with low porosity and ultra-low permeability within the source rock layers. More than 75% of proved reserves around the world are discovered in the free hydrocarbon dynamic field, which is estimated to contain only 10% of originally generated hydrocarbons. Most of undiscovered resources distributed in the confined hydrocarbon dynamic field and the bound hydrocarbon dynamic field, which contains 90% of original generated hydrocarbons, implying a reasonable and promising area for future hydrocarbon explorations. The buried depths of hydrocarbon dynamic fields become shallow with the increase of heat flow, and the remaining oil/gas resources mainly exist in the deep area of “cold basin” with low geothermal gradient. Lithology changing in the hydrocarbon dynamic field causes local anomalies in the oil/gas dynamic mechanism, leading to the local formation of unconventional hydrocarbon reservoirs in the free hydrocarbon dynamic field or the occurrence of oil/gas enrichment sweet points with high porosity and permeability in the confined hydrocarbon dynamic field. The tectonic movements destroy the medium conditions and oil/gas components, which leads to the transformation of conventional oil/gas reservoirs formed in free hydrocarbon dynamic field to unconventional ones or unconventional ones formed in confined and bound hydrocarbon dynamic fields to conventional ones.

Joint PP and PS pre-stack AVA inversion for VTI medium based on the exact Graebner equation

Unconventional hydrocarbon reservoirs, such as shale rocks, are generally transversely isotropic with a vertical axis of symmetry (VTI). The identification of sweet spots in these reservoirs, which must take into account this anisotropic character, can be performed with amplitude variations with offset/angle (AVO/AVA) inversion. However, most approaches use the Rüger reflection approximate equation as forward modeling, which has low accuracy at moderate to large angles, where the seismic gathers contain most of useful information on anisotropy parameters. In this paper, we propose an exact-equation-based seismic pre-stack AVA inversion for stable estimations of anisotropy parameters in VTI media. A linear inversion scheme is adopted to save computational time and the Fréchet derivatives, the key factors of the scheme, are derived here. To improve the stability and accuracy, the PP data inversion is extended to joint PP and PS inversion, termed joint exact-Graebner-based prestack inversion (JEGI). It is applied to both synthetic and field multi-component seismic data, showing its feasibility and effectiveness.

Proppant transport in dynamically propagating hydraulic fractures using CFD-XFEM approach

Numerically modelling the fluid flow with proppant transport and fracture propagation together are one of the significant technical challenges in hydraulic fracturing of unconventional hydrocarbon reservoirs. The existing models either model the proppant transport physics in static predefined fracture geometry or account for the analytical models for defining the fracture propagation. Furthermore, the fluid leak-off effects are usually neglected in the hydrodynamics of proppant transport in the existing models. In the present paper, a dynamic and integrated numerical model is determined that uses computational fluid dynamics (CFD) technique to model the fluid flow with proppant transport and Extended finite element method (XFEM) to model the fracture propagation. The results of fracture propagation were validated with the real field results and analytical models, and the results of proppant transport are validated with the experimental results. The integrated model is then used to comprehensively investigate the hydrodynamical properties that directly affect the near-wellbore stress and proppant distribution inside the fracture. The model can accurately model the proppant physics and also propose a solution to a frequent challenge faced in the petroleum industry of fracture tip screen out. Thus, using the current model allows the petroleum engineers to design the hydraulic fracturing operation successfully, model simultaneously fracture propagation and fluid flow with proppant transport and gain confidence by tracking the distribution of proppants inside the fracture accurately.

Prospective zones of unconventional hydrocarbon reservoirs in the Cambrian, Ordovician and Silurian shale formations of the East European Craton marginal zone in Poland

The paper presents the latest state of knowledge on the vertical and lateral ranges and characteristics of prospective zones (PZ) within the Lower Paleozoic unconventional hydrocarbon systems in the Baltic-Podlasie-Lublin Basin (Poland). The PZ were identified within the prospective formations based on rigorously determined criteria with the application of stratigraphic, sedimentological, mineralogical, petrographic, geochemical, petrophysical, and geomechanical studies, and interpretations of borehole logs. Archival geological data and information acquired from boreholes drilled recently in concession areas have also been applied in the interpretations. Following these criteria, four prospective zones have been distinguished. The deposits encompass partly or almost completely the Piaśnica, Sasino, and Jantar formations and the lower part of the Pelplin Formation. The characteristic feature of the Lower Paleozoic deposits at the East European Craton (EEC) margin in Poland is the diachronous appearance of the Sasino and Jantar black shale formations from west to east. The Baltic area is most prospective for the occurrence of unconventional hydrocarbon reservoirs in shale formations, specifically the Łeba Elevation, where all 4 prospective zones have been distinguished. The occurrence of liquid and gaseous hydrocarbons is expected in all zones. Due to the very high TOC content and geochemical characteristics, the Piaśnica Formation within PZ1 is the main petroleum source rock in the Polish part of the Baltic Basin. PZ2 (partly corresponding to the Sasino Formation) present in a large part of the Baltic Basin, is the next important prospective unit, despite not being uniform. PZ3 within the Jantar Formation was distinguished only on a limited area of the ˜eba Elevation. Due to the low content of organic matter, the Lublin area is characterized by the lowest hydrocarbon potential. However, low values of that parameter are compensated by a greater thickness and lateral range of PZ4, partly corresponding to the Pelplin Formation. Comparison with other areas within the Lower Paleozoic Baltic Basin reveals the occurrence of shale deposits that may constitute a potential source of hydrocarbons, and that demonstrate diachronism. Towards the east and south-east, ever younger deposits possess the potential for hydrocarbon accumulations. In Poland, in the western part of EEC, these are: the Furongian and the Lower Tremadocian Piaśnica Formation, the Sandbian and Katian Sasino Formation and the Lower/Middle Llandovery (Rhuddanian and Aeronian) Jantar Formation. In the central part of the Baltic Basin (Lithuania), these are the Upper Ordovician and Aeronian shale successions. In the southeastern part of the basin (Ukraine), the Ludlow strata are considered to be the most promising in terms of the potential unconventional hydrocarbons accumulations.

Microscale Chemistry: Raman Analysis of Fluid and Melt Inclusions

Raman spectroscopy is a commonly applied nondestructive analytical technique for characterizing fluid and melt inclusions. The exceptional spatial resolution (~1 µm) and excellent spectral resolution (≤1 cm−1) permits the characterization of micrometer-scale phases and allows quantitative analyses based on Raman spectral features. Data provided by Raman analysis of fluid and melt inclusions has significantly advanced our understanding of complex geologic processes, including preeruptive volatile contents of magmas, the nature of fluids in the deep crust and upper mantle, the generation and evolution of methane-bearing fluids in unconventional hydrocarbon reservoirs. Anticipated future advances include the development of Raman mass spectroscopy and the use of Raman to monitor reaction progress in synthetic and natural fluid inclusion microreactors.

Generalized Multiscale Finite Element Method for the poroelasticity problem in multicontinuum media

In this paper, we consider a poroelasticity problem in heterogeneous multicontinuum media that is widely used in simulations of the unconventional hydrocarbon reservoirs and geothermal fields. Mathematical model contains a coupled system of equations for pressures in each continuum and effective equation for displacement with volume force sources that are proportional to the sum of the pressure gradients for each continuum. To illustrate the idea of our approach, we consider a dual continuum background model with discrete fracture networks that can be generalized to a multicontinuum model for poroelasticity problem in complex heterogeneous media. We present a fine grid approximation based on the finite element method and Discrete Fracture Model (DFM) approach for two and three-dimensional formulations. The coarse grid approximation is constructed using the Generalized Multiscale Finite Element Method (GMsFEM), where we solve local spectral problems for construction of the multiscale basis functions for displacement and pressures in multicontinuum media. We present numerical results for the two and three dimensional model problems in heterogeneous fractured porous media. We investigate relative errors between reference fine grid solution and presented coarse grid approximation using GMsFEM with different numbers of multiscale basis functions. Our results indicate that the proposed method is able to give accurate solutions with few degrees of freedoms.

Methane oxidation and methylotroph population dynamics in groundwater mesocosms.

SummaryExtraction of natural gas from unconventional hydrocarbon reservoirs by hydraulic fracturing raises concerns about methane migration into groundwater. Microbial methane oxidation can be a significant methane sink. Here, we inoculated replicated, sand‐packed, continuous mesocosms with groundwater from a field methane release experiment. The mesocosms experienced thirty‐five weeks of dynamic methane, oxygen and nitrate concentrations. We determined concentrations and stable isotope signatures of methane, carbon dioxide and nitrate and monitored microbial community composition of suspended and attached biomass. Methane oxidation was strictly dependent on oxygen availability and led to enrichment of 13C in residual methane. Nitrate did not enhance methane oxidation under oxygen limitation. Methylotrophs persisted for weeks in the absence of methane, making them a powerful marker for active as well as past methane leaks. Thirty‐nine distinct populations of methylotrophic bacteria were observed. Methylotrophs mainly occurred attached to sediment particles. Abundances of methanotrophs and other methylotrophs were roughly similar across all samples, pointing at transfer of metabolites from the former to the latter. Two populations of Gracilibacteria (Candidate Phyla Radiation) displayed successive blooms, potentially triggered by a period of methane famine. This study will guide interpretation of future field studies and provides increased understanding of methylotroph ecophysiology.