Unconventional Shale Gas Research Articles

Deep Learning Phase Pickers: How Well Can Existing Models Detect Hydraulic-Fracturing Induced Microseismicity from a Borehole Array?

Summary Deep learning (DL) phase picking models have proven effective in processing large volumes of seismic data, including successfully detecting earthquakes missed by other standard detection methods. Despite their success, the applicability of existing extensively-trained DL models to high-frequency borehole datasets is currently unclear. In this study, we compare four established models (GPD, U-GPD, PhaseNet and EQTransformer) trained on regional earthquakes recorded at surface stations (100 Hz) in terms of their picking performance on high-frequency borehole data (2000 Hz) from the Preston New Road (PNR) unconventional shale gas site, in the United Kingdom (UK). The PNR-1z dataset, which we use as a benchmark, consists of continuously recorded waveforms containing over 38,000 seismic events previously catalogued, ranging in magnitudes from -2.8 to 1.1. Remarkably, all four DL models can detect induced seismicity in high frequency borehole data and two might satisfy the monitoring requirements of some users without any modifications. In particular, PhaseNet and U-GPD demonstrate exceptional recall rates of 95% and 76.6%, respectively, and detect a substantial number of new events (over 15,800 and 8,300 events, respectively). PhaseNet’s success might be attributed to its exposure to more extensive and diverse instrument dataset during training, as well as its relatively small model size, which might mitigate overfitting to its training set. U-GPD outperforms PhaseNet during periods of high seismic rates due to its smaller window size (400-samples compared to PhaseNet’s 3000-sample window). These models start missing events below Mw -0.5, suggesting that the models could benefit from additional training with microseismic datasets. Nonetheless, PhaseNet may satisfy some users’ monitoring requirements without further modification, detecting over 52,000 events at PNR. This suggests that DL models can provide efficient solutions to the big data challenge of downhole monitoring of hydraulic-fracturing induced seismicity as well as improved risk mitigation strategies at unconventional exploration sites.

A nonlinear inversion method for Young’s modulus and shear modulus based on the exact Zoeppritz equations

IntroductionYoung’s modulus and shear modulus are essential mechanical parameters for evaluating subsurface rocks, playing a pivotal role in the exploration and development of unconventional resources. Young’s modulus indicates the brittleness of the reservoir, while shear modulus determines the ease of fracturing rock layers.MethodsTraditional methods estimate these moduli through indirect calculations and approximate expressions, which are prone to cumulative errors and rely on multiple assumptions, reducing inversion accuracy. This paper presents a direct inversion method for acquiring of Young’s modulus and shear modulus using the exact Zoeppritz equations, integrated within a Bayesian framework for pre-stack inversion. The quantum particle swarm optimization (QPSO) algorithm is introduced to achieve a nonlinear solution to the objective function.ResultsTests on synthetic and actual field data demonstrate the feasibility and effectiveness of the proposed method, yielding more accurate inversion results compared to traditional methods.DiscussionThese findings provide valuable insights for predicting reservoir brittleness and characterizing reservoirs in unconventional shale gas exploration and development.

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources.

Data-driven multiscale geomechanical modeling of unconventional shale gas reservoirs: a case study of Duvernay Formation, Alberta, West Canadian Basin

The Duvernay Formation in Canada is one of the major oil and gas source formations in the Western Canadian Sedimentary Basin, located at its deepest point. While it demonstrates promising development potential, challenges arise in the urgent need for integration of geology and engineering models, as well as in optimizing sweet spots, particularly as infill wells and pads become central operational objectives for the shale gas field. A lack of the geomechanical understanding of shale gas reservoirs presents a significant obstacle in addressing these challenges. To overcome this, we implemented data acquisition and prepared historical models and profiles, resulting in an extended high-resolution geological and reservoir property model with a fine grid system. Subsequently, a 3D full-field multi-scale geomechanical model was constructed for the main district by integrating seismic data (100 m), geological structures (km), routine logs (m), core data (cm), and borehole imaging (0.25 m), following a well-designed workflow. The predicted fracturability index (brittleness) ranges from 0.6 to 0.78, and a lower horizontal stress difference (STDIFF) is anticipated in the target formation, Upper Duvernay_D, making it a favorable candidate for hydraulic fracturing treatment. Post-analysis of the multi-disciplinary models and various data types provides guidelines for establishing a specific big database, which serves as the foundation for production performance analysis and aggregate sweet spot analysis. Fourteen geological and geomechanical candidate parameters are selected for the subsequent sweet spot analysis. This study highlights the effectiveness of multi-scale geomechanical modeling as a tool for the integration of multi-disciplinary data sources, providing a bridge between geological understanding and future field development decisions. The workflows also offer a data-driven framework for selecting parameters for sweet spot analysis and production dynamic analysis.

Generation of abnormal distributions of inter- and intramolecular δ13C compositions in hydrocarbons from gold tube pyrolysis of an Australian torbanite

Abnormal stable carbon isotopic (δ13C) compositions, deviating from the conventional order of δ13C1 < δ13C2 < δ13C3, are frequently observed in natural gas reservoirs. For thermogenic gas, these anomalies, such as δ13C1 < δ13C3 < δ13C2 or δ13C1 > δ13C2 > δ13C3, have multiple formation mechanisms including gas mixing in conventional systems and desorption processes of gaseous hydrocarbons in unconventional shale gas systems due to their inconsistency with Rayleigh fractionation processes. Considering distinct reaction pathways (e.g., C1 polymerized to C2), these aberrant δ13C signatures are often construed as intrinsic hallmarks of extensively evolved natural gas. However, on the basis of gas generation simulation, not all findings exhibit abnormal δ13C values, hinting at multifaceted and intricate mechanisms governing the isotopic fractionation of alkane gas components. This study conducted gold tube pyrolysis of an Australian torbanite, revealing four distinct types of δ13C anomalies in hydrocarbon classes. Polycyclic aromatic hydrocarbons (PAHs) exhibited δ13C values more negative than co-occurring n-alkanes. δ13C3 displayed a negative trend shift from EasyRo = 3.5 %, resulting in a partially δ13C-reversed gas (δ13C1 < δ13C3 < δ13C2) formed at EasyRo ≈ 4.1 %. Moreover, intramolecular δ13C3 (both terminal and central carbons, termed δ13Ca and δ13Cb, respectively) reversed alongside the overall δ13C3 trend. Additionally, the evolution of site preference in δ13C3 (termed ‰SP = δ13Ca – δ13Cb) transitioned from progressively negative to positive. The results of this study demonstrate that the potential conversion between saturated hydrocarbons, aromatic hydrocarbons, and alkane gases is at least partially responsible for δ13C anomalies, but also that gaseous hydrocarbons formed from other fractions at high maturity cannot be ruled out, such as kerogen and pyrobitumen.

Novel methodology to couple decline curve analysis with CFD reservoir simulations for complex shale gas reservoirs

AbstractShale reservoirs are highly complex and are difficult to study using conventional reservoir simulation tools. This study introduces a novel methodology for estimating production from complex shale gas reservoirs by coupling decline curve analysis (DCA) with computational fluid dynamics (CFD) simulations. The proposed method uses exponential DCA to analyze production data from a dual porosity–permeability shale gas transport model. These complexities include fracture characteristics, geomechanical properties, nanopore confinement effects, and multiple flow mechanisms contributing to the total production performance. The shale gas transport model is validated through historical production data from Marcellus shale. The new methodology also tests fracture characteristics. It shows that increased porosity and permeability will increase the recoverable reserves but will have varying effects on the decline rate. The paper demonstrates the advantages of the proposed methodology over conventional reservoir simulation tools. It provides insights into the factors affecting shale gas production performance through the inclusion of the complexities of an unconventional shale gas reservoir. The paper provides a proof of concept on the particular reservoir of which the field data is provided—Barnett and Marcellus Shale.

Beetaloo or bust: the route to commercial success for an Australian shale play

There is a huge unconventional shale gas resource in the remote heart of the Northern Territory with the potential to trigger big new gas developments in Darwin, including export liquefied natural gas (LNG), and underpin the chronically undersupplied East Coast market. And yet despite this promise, the Beetaloo is not universally viewed as a viable commercial project. Nonetheless, the Beetaloo is one of the hottest topics in Australia’s upstream sector, and two of its key operators, Tamboran and Empire, are closing in on final investment decision (FID) for initial gas production. So why are many in the market still sceptical the play will work? To create a definitive answer, we investigate the key factors required to make the Beetaloo commercially viable. We will evaluate what a Beetaloo gas project could look like across a range of resource sizes, estimated ultimate recovery (EUR) from analogue production profiles, and well costs. The work aims to understand the key cost barriers and price hurdles that need to be broached for economic success. From here we can determine the full range of economic pitfalls and potential rewards that lie in wait for ambitious Beetaloo operators.

Identification of Milankovitch sedimentary cycle in Fengcheng Formation, Mahu depression: a case study of well Maye 1

The sedimentary cycle of Fengcheng Formation in Junggar Basin changes rapidly and is difficult to identify. The low classification accuracy of high-frequency fine-grained sedimentary cycles restricts the exploration of unconventional shale oil and gas. Full-interval coring of well Maye 1 provides a solid foundation for small-layer research. In this paper, the high-frequency sedimentary cycle of Milan kovitch in Fengcheng Formation is studied by means of spectral analysis and wavelet transform, and the shale sweet spot is identified. The long period of eccentricity of 405ka, short period of eccentricity of 100ka and long period of axis slope of 42736a can be used as semi-quantitative basis for the classification of the fourth, fifth and sixth sequences. The Fengcheng Formation can be divided into 2 quaternary sequence cycles, 9 quaternary sequence cycles and 16 quaternary sequence cycles. A long period of eccentricity of 405ka can identify large-scale lake recessional and recessional, and there is a maximum lake flooding surface in the middle of the second Fengcheng Formation, which corresponds to high abundance of organic matter and high hydrocarbon generation potential. The 100ka short period eccentricity can identify the sweet spot layer, and there are 8 sweet spots in the well Maye 1, which is consistent with the results of nuclear magnetic interpretation. The research results provide a semi-quantitative basis for the classification of high-frequency sedimentary cycles and the identification of sweet spots of Fengcheng Formation in Mahu Sag, Junggar Basin.

Machine learning prediction of methane, ethane, and propane solubility in pure water and electrolyte solutions: Implications for stray gas migration modeling

Hydraulic fracturing is an effective technology for hydrocarbon extraction from unconventional shale and tight gas reservoirs. A potential risk of hydraulic fracturing is the upward migration of stray gas from the deep subsurface to shallow aquifers. The stray gas can dissolve in groundwater leading to chemical and biological reactions, which could negatively affect groundwater quality and contribute to atmospheric emissions. The knowledge of light hydrocarbon solubility in the aqueous environment is essential for the numerical modelling of flow and transport in the subsurface. Herein, we compiled a database containing 2129 experimental data of methane, ethane, and propane solubility in pure water and various electrolyte solutions over wide ranges of operating temperature and pressure. Two machine learning algorithms, namely regression tree (RT) and boosted regression tree (BRT) tuned with a Bayesian optimization algorithm (BO) were employed to determine the solubility of gases. The predictions were compared with the experimental data as well as four well-established thermodynamic models. Our analysis shows that the BRT-BO is sufficiently accurate, and the predicted values agree well with those obtained from the thermodynamic models. The coefficient of determination (R2) between experimental and predicted values is 0.99 and the mean squared error (MSE) is 9.97 × 10−8. The leverage statistical approach further confirmed the validity of the model developed.

Acid-assisted subcritical blunt-tip crack propagation in carbonate rocks

AbstractSubcritical crack propagation in stressed carbonate rocks in a chemically reactive environment is a fundamental mechanism underlying many geomechanical processes frequently encountered in the engineering of geo-energy, including unconventional shale gas, geothermal energy, carbon sequestration and utilization. How a macroscopic Mode I crack propagates driven by a reactive fluid pressurizing on the crack surfaces with acidic agents diffusing into the rock matrix remains an open question. Here, the carbonate rock is modeled as an elasto-viscoplastic material with the mineral mass removal process affecting the rock properties in both elastic and plastic domains. A blunt-tip crack is considered to avoid any geometrically induced singularity problem and to allow a numerical analysis on the evolution of the chemical field being linked to the micro-cracking activities in front of the crack tip, affecting the delivery of acid. The model is capable of reproducing an archetypal three-region behavior of subcritical crack growth in a reactive environment. The crack propagation exhibits a prominent acceleration in Region III due to a two-way mutually enhancing feedback between mineral dissolution and the degradation process, which is most pronounced in front of the crack tip. With the consideration of initial imperfections in the rock, the macroscopic crack propagation is further accelerated with a secondary acceleration arising due to self-organization of micro-bands inside the chemically enabled plasticity zone.

Geochemical and mineralogical characterizations of Silurian “Hot” shales: Implications for shale gas/oil reservoir potential in Jeffara basin-southeastern Tunisia, North Africa

The Silurian organic-rich hot shale deposits represent the origin of 80–90% Paleozoic sourced hydrocarbons on the entire Saharan Platform. As such, it is an area of significant interest for exploring its potential as an unconventional reservoir and gaining new insights into its properties. In this study, the geochemical and mineralogical analysis of eighty-two borehole samples from three studied wells (T, B, and M) located in Jeffara Basin, in southeastern Tunisa, distributed over a depth between 1200 m and 2200 m, show that the hot shale layer has significant potentials of an unconventional shale gas reservoir. According to the rock-eval and GCMS results, the total organic carbon (TOC) of the hot shale deposits is good to great, ranging between 0.54 wt% and 23.86 wt%, and the average hydrogen index (HI) is around ∼200 mg HC/g of TOC, which indicates that the hot shales were originally rich in type II/III organic matter (OM). The thermal maturity of the preserved OM is determined by the kerogen type with values varying from 0.4% to 1%, and Tmax values reaching 460 °C in T, B, and M wells which indicate that the hot shales preserved early mature to mature OM placed within oil/gas generation window. The calculated geochemical parameters reveal an average hydrocarbon generation potential (HGP) for the three studied wells of 20.37 kg HC/ton rock. In addition, the transformation ratios (TR) in T, B, and M wells are, respectively, 21.12%, 30% and 35.25%. However, only B and M wells show a cross-over layer, with oil saturation index (OSI) exceeding 100%, with significant potential as a hydrocarbon saturated source rock, making it a considerable target for unconventional oil exploration. Relevant results of Rock-Eval, biomarkers and XRD exhibit coherent features that reflect reducing marine conditions during the lower Silurian period. Moreover, the mineralogical composition was investigated to estimate the importance of frackable mineral fractions such as quartz (∼15%) and carbonates (calcite-dolomite). Mineral brittleness index (MBI) was calculated and compared to a well-known unconventional reservoir in the Neal shale member of the Floyd shale group in the Black Warrior Basin (US), which displays moderate to low MBI. The hot shales in the study area have a considerable MBI, which could be easily enhanced by hydraulic fracturing to liberate oil/gas from the potentially saturated unconventional shale reservoir.

Origin of organic matter pore heterogeneity in oil mature Triassic Chang-7 mudstones, Ordos Basin, China

Organic matter (OM)-hosted pores play a crucial role in hydrocarbon storage and migration in unconventional shale oil and gas systems. An accurate identification of different OM compositions is critical to understanding the origin of heterogeneity in OM-hosted pore development, which remains challenging due to the lack of apparent intrinsic connection between them. This study correlates light-electron-Raman spectroscopy to investigate various OM maceral types and their molecular structures with respect to the pore characteristics in an oil mature Triassic Chang-7 lacustrine mudstone from the Ordos Basin, China. Moreover, the occurrence and distribution of soluble bitumen and its effect on OM-hosted pore development were directly characterized by comparison of a stitched large SEM image mosaic (∼1 mm2) before and after organic solvent extraction. Results show that terrestrial OM including inertinite and vitrinite fragments display well-preserved biological structure and high reflectance intensity in light microscopy. They often are nonporous under SEM, and have no change before and after solvent extraction. Solid bitumen is the predominant maceral of the examined mudstone, and shows two general populations: 1) nonporous or weakly porous solid bitumen (SB1) that often occurs in large-sized and structured accumulation; 2) porous solid bitumen (SB2) that is filled or dispersed in mineral matrix. After extraction, SB2 was completely removed and have a noticeable recovery of pores, while SB1 changed slightly. The heterogenous pore characteristics can be related to the varying OM molecular structure which shows a decreasing trend of aromaticity in the order of terrestrial macerals, SB1, and SB2 as indicated by Raman parameters. A relatively higher pore abundance in SB2 may be attributed to chromatographic fractionation which led to more mobile and compliant components of SB2.

On the resilience of bio-cemented silica sands in chemically reactive environment

Exposure of geomaterials to an acidic environment is frequently encountered in modern-day geo-energy and geo-environmental engineering activities, in e.g. incorporation of chemical stimulation for unconventional shale gas exploitation, enhanced geothermal systems, geological carbon sequestration, and the long-term regional stability in carbonate-rich coastal areas. The Multiphysics-involved process for each application is complex and an optimised control calls for a better understanding on the coupling mechanism of the chemical, hydraulic and mechanical fields. This laboratory-based study aims to provide a quantitative calibration and derivation of the key coupling parameters accommodating our recently proposed framework of reactive chemo-mechanics, using a bio-cemented rock-like material as a representative for dissolvable rocks. The advantage of bio-cemented specimens (here by microbially induced carbonate precipitation) over natural rocks lies in their more uniform grain-bond structure and laboratory tunable calcite content. An experimental setup is introduced for investigating the role of calcite content on the mechanical and hydraulic properties of bio-cemented silica sands, followed by uniaxial tests on the bio-cemented specimens immersed in acidic environment to allow a reactive chemo-mechanical setting. Our results show that bio-cemented samples appear to be more “resilient” to an acidified aqueous environment in terms of less strength degradation compared to natural carbonate-rich rocks. Ductile failure mode is observed in the bio-cemented specimens within a certain range of the calcium carbonate content and a brittle-to-ductile transition in the failure mode occurs when the calcite content in the specimen decreases. With the calibrated model and the derived coupling parameters, we further illustrate an example of numerical prediction on the mechanical response of bio-cemented specimens under varying acidic environments and loading rates.

Upscaling the creep behavior of clay-rich and quartz-rich shales from nanoindentation measurements: Application to the Wufeng-Longmaxi shale, China

Creep of shale controls the stability of fault gouge in sedimentary rocks, aseismic deformation in the upper crust, and several engineering operations, such as proppant embedment, reservoir subsidence, and wellbore stability during unconventional shale gas exploitation. However, measuring the creep properties of shale is challenging due to the multi-scale structure of this rock. Here, our goal is to assess how creep parameters measured at the core sample scale depend on those measured at the nanoscale in shales. We selected three clay-rich and quartz-rich shale samples and conducted a series of experiments on shale samples at two scales: nanoindentation creep measurements on thin sections, and uniaxial creep tests on core samples. The creep parameters, including creep displacement (Δh), indentation creep (CIT), creep strain rate sensitivity (m), contact creep modulus (C), and viscoelastic parameters (E1, E2, η1, and η2) of the Burgers' model, were calculated by fitting the nanoindentation creep data of each single-phase component of shale matrix. From these data, we upscale the creep parameters (E1, E2, and C) of shale matrix to those of the bulk shale. Upscaled E2 and C values based on the Mori-Tanaka scheme are found to be relatively close to those measured in previous microindentation study on Longmaxi shale and are consistent with our measurements in uniaxial creep tests on core samples of clay-rich shale and quartz-rich shale. The upscaling value of the elastic parameters, E1, is almost twice larger than the results from uniaxial creep test. We interpret this difference as due to low elastic stiffness along grain contacts of the shale that nanoindentation measurements underestimate. Our results show a consistency of some creep parameters upscaled from nanoindentation data and those measured at a macroscopic scale on core samples.

Chemical and Carbon Isotope Composition Proves Effective as Gas Diagnostic Tool

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209992, “Gas Chemical and Carbon Isotope Composition as a Diagnostic Tool for Energy,” by Zainab Almubarak, SPE, Mohammad Alrowaie, and Feng Lu, Saudi Aramco, et al. The paper has not been peer reviewed. _ Chemical and carbon isotopic compositions of produced gases are useful tools to monitor gas production and to assess their origin, thermal maturity, and migration. In the complete paper, the authors present different geochemical approaches to assess the origin of gases and thermal maturity and to evaluate the effect of adsorption on shale gas during production. Introduction Carbon isotope type curves constructed for compounds from methane through n-pentane can be used to group gases into distinct families and correlate them to their source rocks. Large variations in carbon isotope ratios exist among the natural gas compounds, which are caused by isotopic fractionation between the sedimentary organic matter (kerogen) and each individual hydrocarbon compound. During the generation of hydrocarbons from kerogen, cracking of 12C-12C bonds requires slightly less energy than 13C-12C bonds. Thus, hydrocarbons will be enriched in 12C relative to the kerogen. Methane, which contains only one carbon atom, shows the greatest fractionation and will have the most negative δ13C value (most enriched in 12C). Ethane through pentane show progressively less fractionation (less negative δ13C values), with the latter usually having a δ13C value close to that of kerogen (and associated oil). The magnitude of the fractionation effect will vary depending on the type of kerogen (i.e., Type I, II, IIS, or III), the temperature during hydrocarbon generation, and the adsorption/desorption effect. Thus, gases generated from different source rocks often have distinctive carbon isotope type curves. In shale gas (unconventional reservoirs), two different types of gases coexist—free gas and adsorbed gas. Free gas occurs in natural fractures and matrix pores, whereas adsorbed gas is noted on the surface of pores. During the early stages of production, free gas accounts for most produced gas. The adsorbed gas starts in mid-late stages but maintains high and stable production. In this study, the authors use carbon isotopic compositions of light hydrocarbons (C1–C5) to assess origin and thermal maturity and to compare different gases derived from unconventional reservoirs. Moreover, carbon isotopes are used to assess migration paths and to monitor gas production in unconventional shale gas reservoirs. The gas samples were collected periodically from the same interval to monitor any isotope variation and evaluate the effect of gas adsorption. Methods Pressurized samples of natural gas were collected from conventional and unconventional reservoirs through production tests, drillstem tests, or downhole samplers and analyzed for chemical composition. For the conventional study, a total of 13 gas samples were collected from different reservoirs (A, B, C, D, and J): four gas samples from Reservoir A, two gas samples from Reservoir B, three gas samples from Reservoir C, three gas samples from Reservoir D, and one gas sample from Reservoir J. Gases derived from Reservoirs A, B, and J are younger and shallower than gases derived from Reservoirs C and D (older and deeper). For the unconventional study, seven gas samples were collected periodically from the same shale interval (Reservoir W) from the same well (Well Y) on different dates to monitor any isotope variation.

Geomechanical risk and mechanism analysis of CO2 sequestration in unconventional coal seams and shale gas reservoirs

With global greenhouse gas emissions hitting record highs in 2021, CO2 geological sequestration (CGS) is the most realistic and feasible technology to ensure large-scale carbon reduction to achieve global carbon capping and carbon neutrality goals. Both coalbed methane and shale gas have the characteristics of self-generation and self-storage, which is considered to be a valuable target reservoir for geological sequestration of CO2. After a high volume of CO2 is injected into unconventional coal seams and shale gas reservoirs, many geomechanical issues may be induced, resulting in leakage. Therefore, it is crucial to evaluate the geomechanical risks of CO2 geological sequestration. In this article, global CO2 emissions and geological resources available for sequestration are teased out. The effects of coupled CO2-water-rock-driven geomechanical, geophysical, and geochemical interactions on the evolution of rock physical properties and pore characteristics, as well as caprock sealing, are discussed. The caprock failure and its inducing mechanism are analyzed, and the criteria for predicting the occurrence of risk are summarized, which is necessary for pressure management and risk prevention. To serve as a benchmark for CO2 sequestration in unconventional coal seams and shale gas reservoirs.

Unconventional shale gas potential of lower visean organic-rich formations in Glynsko-Solohivskyi petroleum region

Exploration of unconventional gas resources in Ukraine is highly relevant and important for achievement energy independence of Ukraine and Europe. Production of current oil &amp; gas fields and alternative energy resources are not able to cover our needs nowadays. Now we can not fully fill these gaps by energy resources. In this article geological environments, age, mineralogy composition and maturity of unconventional shale and carbonate gas reservoirs of Lower Visean in one of the biggest field of Dnipro-Donets Basin (DDB) were studied. The hydrocarbon potential of two main target horizons V-23 and V-24-25 by using integrated approach of analyzing available core analysis data were performed. The results of the geochemical analysis show that the maturity level of shale of the Rudov beds (V-23) appear in oil window (Ro~0.8%) which can generate oil in the early mature phase. Visean carbonates (V-24-25) have the similar level of maturity - (Ro~0.77%). Target rocks are characterized by high total organic content (TOC): average values vary from 2% for organic-rich carbonates to 5.6% for shales which indicates relatively good to excellent source rock generative potential. According to X-ray diffraction analyses (XRD) of black shale formation domination of silica minerals (54.6%), calcite and clays (25.6%) with minor amounts of albite, feldspar and pyrite were observed. Carbonate platform V-24-25 logically is characterized by much higher calcite content of 52.2 % with low amount of dolomite – 5.5%. Quite high quartz content is also observed – average value is of about 30.7%. Clay minerals are not identified in every sample, but average values are of about 18.9%, pyrite content – 6.8%. It shows that Visean target formation of Glynsko-Solohivsky Petroleum region is characterized by anoxic environment. This data verified that V-23 and V-24-25 horizons are the brittle formations and favorable for multistage fracking. Thin section analysis confirms our results from mineralogical point of view. The presence of fractures in core samples is additional indicator for hydraulic fracturing and producing gas from such unconventional reservoirs. As a conclusion, the Lower Visean organic-rich formations V-23 and V-24-25 from Glynsko-Solohivsky Petroleum region are mature, are characterized by a high content of organic carbon, have enough thickness (30-120 m) and large areal extent. They should be regarded as a potential shale gas target.

Simplified scaling relations for the depth-dependence and IFT reduction of fluid imbibition in gas-saturated reservoir rocks

Imbibition of water into fractured unconventional reservoirs is a significant factor contributing to the large volumes of permanently lost water by hydraulic fracturing. The lost water partitions at the fracture-matrix interface thereby restricting gas flow into the fractures. Thus, minimizing the large water footprint during the fracturing process is very attractive for water conservation and gas production. A key step towards achieving this goal is quantifying uncertainties needed to reliably predict water imbibition and to evaluate the success of efforts aimed at minimizing it. In this contribution, we present new scaling relations for water imbibition in gas-saturated rocks that account for the depth-dependence of fluid properties and chemical alteration of IFT through the use of a surfactant. We then propose a new method for quantifying uncertainties relating to rock properties, two-phase fluid properties, and the driving force for imbibition. We applied the proposed approach to analyze glass-bead pack and shale experiments involving water imbibition into air-filled pores, and validated our model predictions against published values from X-ray CT images and transient permeability measurements. Our work provides a methodology for quantifying the uncertainties pertaining to water imbibition, thereby enabling optimization of post-fracturing interventions aimed at minimizing water loss in deep unconventional shale gas reservoirs.

Oxidation treatment of shale gas produced water: Molecular changes in dissolved organic matter composition and toxicity evaluation

Produced water (PW) is the largest waste stream generated by hydraulic fracturing in an unconventional shale gas reservoir. Oxidation processes (OPs) are frequently used as advanced treatment method in highly complicated water matrix treatments. However, the degradation efficiency is the main focus of research, organic compounds and their toxicity have not been properly explored. Here, we obtained the characterization and transformation of dissolved organic matters of PW samples from the first shale gas field of China by two selected OPs using FT-ICR MS. CHO, CHON, CHOS, and CHONS heterocyclic compounds associated with lignins/CRAM-like, aliphatic/proteins, and carbohydrates compounds were the major organic compounds identified. Electrochemical Fe2+/HClO oxidation preferentially removed aromatic structures, unsaturated hydrocarbons, and tannin compounds with a double-bond equivalence (DBE) value below 7 to more saturated compounds. Nevertheless, Fe (VI) degradation manifested in CHOS compounds with low DBE values, especially single bond compounds. Oxygen- and Sulfur-containing substances, primarily O4–11, S1O3-S1O12, N1S1O4, and N2S1O10 classes, were the main recalcitrant components in OPs. The toxicity assessment showed that the free-radical-formed Fe2+/HClO oxidation could cause significant DNA damage. Therefore, the toxicity response byproducts need spcial attention when conducting OPs. Our results led to discussions on designing appropriate treatment strategies and the development of PW discharge or reuse standards.

Parallel fully implicit chemical potential-based modeling of unconventional shale gas reservoirs

The design of novel mathematical models and state-of-the-art simulators for unconventional shale gas reservoirs plays an increasingly important role in the current energy mix of the world’s growing energy demand. In this paper, we present a robust and scalable framework, which is based on the chemical potential-based modeling and the fully implicit method (FIM), to model and simulate this highly nonlinear flow transport problem on a large scale. In the proposed approach, a thermodynamically consistent mathematical model of gas flow in shale formations, which employs the gas density and the chemical potential gradient, is developed to satisfy the second law of thermodynamics and meanwhile guarantee the energy dissipation property. And then the family of fully implicit finite element algorithms is utilized to accurately capture the complicated flow physics behind the transport process in shale media on high resolution grids. In particular, our approach further enhances the numerical formulation by proposing the family of Newton–Krylov methods for efficiently computing, and the parallel implementation of the simulator is achieved by using the domain decomposition technique. Numerical experiments are presented to demonstrate the robustness and parallel scalability of the solution strategies for several interesting shale gas flow problems in two or three dimensions. With the proposed parallel method, large-scale reservoir simulation can be obtained on the Shaheen-II supercomputer with up to 40960 processors, which enables to achieve a good strong scalability by saving more than 90 percent of computing time, when the problem size is enlarged to hundreds of millions of degrees of freedom.