Clay-bound Water Research Articles

Pore Size Classification and Prediction Based on Distribution of Reservoir Fluid Volumes Utilizing Well Logs and Deep Learning Algorithm in a Complex Lithology

Pore size analysis plays a pivotal role in unraveling reservoir behavior and its intricate relationship with confined fluids. Traditional methods for predicting pore size distribution (PSD), relying on drilling cores or thin sections, face limitations associated with depth specificity. In this study, we introduce an innovative framework that leverages nuclear magnetic resonance (NMR) log data, encompassing clay-bound water (CBW), bound volume irreducible (BVI), and free fluid volume (FFV), to determine three PSDs (micropores, mesopores, and macropores). Moreover, we establish a robust pore size classification (PSC) system utilizing ternary plots, derived from the PSDs.Within the three studied wells, NMR log data is exclusive to one well (well-A), while conventional well logs are accessible for all three wells (well-A, well-B, and well-C). This distinction enables PSD predictions for the remaining two wells (B and C). To prognosticate NMR outputs (CBW, BVI, FFV) for these wells, a two-step deep learning (DL) algorithm is implemented. Initially, three feature selection algorithms (f-classif, f-regression, and mutual-info-regression) identify the conventional well logs most correlated to NMR outputs in well-A. The three feature selection algorithms utilize statistical computations. These algorithms are utilized to systematically identify and optimize pertinent input features, thereby augmenting model interpretability and predictive efficacy within intricate data-driven endeavors. So, all three feature selection algorithms introduced the number of 4 logs as the most optimal number of inputs to the DL algorithm with different combinations of logs for each of the three desired outputs. Subsequently, the CUDA Deep Neural Network Long Short-Term Memory algorithm(CUDNNLSTM), belonging to the category of DL algorithms and harnessing the computational power of GPUs, is employed for the prediction of CBW, BVI, and FFV logs. This prediction leverages the optimal logs identified in the preceding step. Estimation of NMR outputs was done first in well-A (80% of data as training and 20% as testing). The correlation coefficient (CC) between the actual and estimated data for the three outputs CBW, BVI and FFV are 95%, 94%, and 97%, respectively, as well as root mean square error (RMSE) was obtained 0.0081, 0.098, and 0.0089, respectively. To assess the effectiveness of the proposed algorithm, we compared it with two traditional methods for log estimation: multiple regression and multi-resolution graph-based clustering methods. The results demonstrate the superior accuracy of our algorithm in comparison to these conventional approaches. This DL-driven approach facilitates PSD prediction grounded in fluid saturation for wells B and C.Ternary plots are then employed for PSCs. Seven distinct PSCs within well-A employing actual NMR logs (CBW, BVI, FFV), in conjunction with an equivalent count within wells B and C utilizing three predicted logs, are harmoniously categorized leading to the identification of seven distinct pore size classification facies (PSCF). this research introduces an advanced approach to pore size classification and prediction, fusing NMR logs with deep learning techniques and extending their application to nearby wells without NMR log. The resulting PSCFs offer valuable insights into generating precise and detailed reservoir 3D models.

Comparative Laboratory Wettability Study of Sandstone, Tuff, and Shale Using 12-MHz NMR T1-T2 Fluid Typing: Insight of Shale

Summary Wettability is a fundamental parameter significantly influencing fluid distributions, saturations, and relative permeability in porous media. Despite the availability of several wettability measurement techniques, obtaining consistent wettability index results, particularly in tight reservoirs, remains a challenge. Nevertheless, obtaining accurate wettability indices is crucial for gaining a more profound understanding of rock properties and precisely identifying and evaluating oil recovery processes. This study adapts T1-T2 nuclear magnetic resonance (NMR) in twin plugs (cores cut in half from the middle) style wettability measurement for different reservoirs. The fluid typing in different lithologies by T1-T2 NMR is proved to be effective by introducing D2O with a modified pressurization saturation process. Therefore, demarcating the regions requires multiple experiments, including sole brine, sole oil phase, and D2O imbibition processes, to define oil and water distribution regions. Such fluid typing ability enables better accuracy in wettability characterization. The weighing method shows good agreement with the T2 spectrum but lacks the ability to differentiate fluids. It is observed that the same fluid in various porous media displays different divisions of T1/T2 ratios. The wettability index of sandstone, tuff, and shale measured by weighing and T1-T2 NMR method are compared and studied to demonstrate the applicability of different methods. The weighing method and the NMR method, as modified-Amott methods, share the same fundamental principle but differ in their measurement techniques. This study’s T1-T2 NMR wettability indices are −0.52, 0.06, and 0.14, whereas the weighing wettability indices are −0.63, 0.07, and 0.34 of sandstone, tuff, and shale, respectively. In addition to the difference in shale wettability index, there are also differences in shale porosity measured by methods with/without the ability to differentiate the fluid types. The T1-T2 NMR method is more accurate in measuring the wettability of shale because it can distinguish among free water in pores, structural water, and clay-bound water in smectitic clay minerals. If the clay-related water is not treated properly, the hydrophilicity of the shale will be overestimated. Ultimately, four types of pores (water-wet, oil-wet, mixed-wet, and unconnected pores) are classified and quantified by the proposed NMR method.

Effect of marine clay minerals on the thermodynamics of CH4 hydrate: Evidence for the inhibition effect with implications

Clay minerals are widely distributed in hydrate-bearing sediments worldwide, especially in the clayey-silty sediments in the South China Sea. The debate on the influence of clay on the thermodynamics of natural gas hydrate (NGH) remains and impedes the fundamental understanding of hydrate-clay interactions and the design of effective production strategies for energy recovery. Specifically, the phase equilibria of MH in the presence of clay and how different types of water associated with clay particles affect NGH thermodynamics and stability are not fully elucidated and warrant investigation. In this study, the phase equilibria of methane hydrate (MH) were measured in the presence of typical clays from the South China Sea, i.e., montmorillonite, kaolinite, and illite. The shift of MH phase equilibria curve to a more stringent pressure was identified with Na-montmorillonite showing the most significant inhibition. The leftward shift (inhibition) of phase equilibrium temperature (Teq) is up to 3.9 K at a pressure of 10.40 MPa for Na-montmorillonite compared with pure water. Furthermore, we develop a thermodynamic model based on the classical Chen-Guo model first accounting for the change in water activity (aw) due to cation exchange of Na-montmorillonite. The developed model exhibits good predictability with the measured phase equilibira data. The inhibition on the phase equilibria of MH is linked to the reduction of aw due to the clay-bound water for clays with a swelling nature. The findings of this study offer direct evidence and explanations on how clay minerals thermodynamically inhibit CH4 hydrate. It provides valuable insights into the resource estimation of clayey-silty NGH in nature and facilities the design of suitable production strategies targeting clay-rich hydrate-bearing sediments.

Quantifying the influence of clay-bound water on wave dispersion and attenuation signatures of shale: An experimental study

Understanding the elastic and attenuation signatures of shales is of considerable interest for unconventional reservoir characterization and sealing capacity evaluation for CO2 sequestration and nuclear waste disposal. We have conducted laboratory measurements on seven shale samples at seismic frequencies (2–100 Hz) to study the effects of clay-bound water (CBW) on their wave dispersion and attenuation signatures. With nuclear magnetic resonance and a helium porosimeter, the volume of CBW in the shale samples is quantified. The forced-oscillation measurement reveals that Young’s modulus exhibits a continuous dispersion trend from 2 to 100 Hz. The extensional attenuation ([Formula: see text]) shows a weak frequency and pressure dependence on effective pressure ranging from 5 to 35 MPa. The magnitude of extensional attenuation shows a positive correlation with CBW, with an [Formula: see text] value of 0.89. It is found that 4% of CBW in the rock frame causes approximately a 5% modulus increase from 2 to 100 Hz. We adopt a constant [Formula: see text] model for assigning frequency-dependent bulk and shear moduli to the CBW in the rock-physics modeling, which can fit the experimental data of modulus dispersion and attenuation well, indicating that the bulk and shear moduli of CBW in shales might behave viscoelastically.

Matrix decomposition methods for accurate water saturation prediction in Canadian oil-sands by LF-NMR T2 measurements

This article presents a novel method for quantifying water saturation in oil-sand reservoirs by employing 1D low-field nuclear magnetic resonance (LF-NMR) spin-spin relaxation and bulk density measurements as indicators of pore volume variations. One of the challenges in accurately determining the volumes of bitumen and water in oil-sands is the effective separation of their overlapping T2 signals, attributed to similar spin-spin relaxation decay times and diffusive coupling. Conventional methods require deconvolution of T2 peaks and or experimentation to determine T2 cutoff values, differentiating between bitumen and water signals, notably capillary and clay-bound water. In contrast, our approach predicts the proportion of water by utilizing matrix decomposition methods to compress the T2 relaxation distribution and extract significant components. These components subsequently train the regression model, facilitating the accurate estimation of relative water saturation percentages.The NMR dataset was obtained by benchtop LF-NMR T2 measurements from 82 oil-sand samples, with preserved bitumen and water saturations at both reservoir and ambient temperatures (6 °C and 25 °C), yielding 164 observations. We examined four matrix decomposition methods, including principal component analysis, its variation integrating a kernel function, canonical correlation analysis, and partial least squares regression. X-ray CT measurements and Dean-Stark extraction ascertained the respective sample bulk densities and fluid-solid volume proportions.The PCA model prediction statistics (RMSE = 0.86%, R2 = 0.84), indicate its application can be extended for saturation prediction from NMR and bulk density well logs. Moreover, we underscore the importance of incorporating bulk density measurements and establish the statistical and physical correlations between these measurements and NMR T2 relaxation, providing insights into the approach's efficacy and causality.

Exploration of the comparison method between nuclear magnetic logging porosity and core detection porosity

Porosity is the basis of reservoir parameter interpretation, permeability and saturation parameters are closely related to porosity, and the interpretation model of porosity has been established with the correlation between core porosity and electrical properties, and core porosity is the effective porosity measured by applying liquid saturation method. With the application of nuclear magnetic logging technology, the interpretation of porosity is more refined and can be subdivided into total porosity, effective porosity, capillary-bound water porosity, and clay-bound water porosity. In order to apply the nuclear magnetic logging technology more accurately, it is necessary to find a method to compare the two porosity detection methods. In this paper, we discuss the meaning of core porosity through the operation procedure of core detection porosity, combined with core piezometric curve and core density calculation method, get the conclusion that core detection porosity approximates total porosity, explore the comparison method between total porosity and core porosity of nuclear magnetic logging, and lay the geological foundation for the next step of applying nuclear magnetic logging data to improve porosity interpretation.

Effect of Bentonite Admixture Content on Effective Porosity and Hydraulic Conductivity of Clay-based Barrier Backfill Materials

Clay-based barrier wall has been diffusely employed as vertical barriers. Nevertheless, there were few project practices of these walls in China. And few research have been performed to study the impact on the permeability of the addition of domestic bentonites. To solve this problem, the influences of bentonite level on hydraulic conductivity, porosity and clay-bound water of soil-bentonite admixtures have been assessed employing a flexible-wall test and water centrifugal dewatering experiment with various bentonites. The outcomes revealed that as barrier walls are constructed by blending bentonite and Fujian standard sandy soil, there is a critical bentonite level of the smallest porosity. If the bentonite level is less than the critical bentonite content, hydraulic conductivity is reduced quickly, while if the bentonite level is greater than the critical bentonite content, hydraulic conductivity is reduced gently. Additionally, as the bentonite level grew, the clay-bound water centage of the admixtures continually improved. Supposing that the clay-bound water enclosed the clay grains, a near computation approach of the effective porosity is put forward and showed that the effective porosity decreased with bentonite content. Additionally, an exponential relationship was found between the effective porosity and the permeability.

Logging evaluation of pore structure and reservoir quality in shale oil reservoir: The Fengcheng Formation in Mahu Sag, Junggar Basin, China

The Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin is characterized by frequent changes of mineral compositions and lamina structure. The alkali lacustrine shale reservoir shows strong heterogeneity and anisotropy, it is particularly important to clarify the relationship between pore structure and reservoir quality. The pore characteristics were investigated by using thin sections, Scanning Electron Microscope (SEM), and Nuclear Magnetic Resonance (NMR) analyses. The pore types are mainly composed of inorganic pores, organic pores, and microfractures. The storage space is dominated by inorganic pores and microfractures. The pore structure was divided into four types by NMR parameters including T2 spectral morphology, T2gm, total porosity, and movable fluid porosity. Combined with core NMR experiments and two-dimensional (2D) NMR logs, 21 ms was adopted as the T2cutoff value to represent the demarcation between movable and bound fluids. From Type I to Type IV, the energy clusters reflect the movable fluids including movable oil and movable water gradually decreasing in the upper right corner. The energy clusters reflect the bound fluids including clay-bound water and bitumen gradually increasing in the lower left corner in the T1-T2 map. The results show that the heterogeneity of mineral compositions and lamina structures are the key factors directly leading to the complexity and distribution of pore structure. Quartz with strong compaction resistance helps keep a large number of primary interparticle pores, and feldspar dissolution pores caused by organic acids are present. Dolomite intercrystalline pores and dissolution pores provide a large amount of storage space for the shale, while the cementation of calcite reduces pore spaces. The increase of felsic mineral content is conducive to improving the pore structure and oil-bearing potential of oil shale reservoir, while clay minerals and calcite are contrary. There are abundant primary interparticle pores and dissolution pores in the layered siliceous (felsic) shales, and they consist of the upper sweet spot in the Fengcheng Formation. The longitudinal time (T1) and transverse time (T2) spectra are bimodal with high total porosity and movable oil content, reflecting high reservoir quality and oil-bearing property. Laminated dolomite shales contain dolomite intercrystalline pores and dissolution pores, and they consist of the lower sweet spot in the Fengcheng Formation. The results above provide a new perspective on the evaluation of pore structure and reservoir quality of shales in the context of an alkaline lake.

NMR-Based Analysis of Fluid Occurrence Space and Imbibition Oil Recovery in Gulong Shale

The Gulong shale oil reservoir is situated in freshwater to slightly saline lacustrine basins mainly consisting of a pure shale geological structure, which is quite different from other shale reservoirs around the world. Currently, the development of Gulong shale oil mainly relies on hydraulic fracturing, while the subsequent shut-in period for imbibition has been proven to be an effective method for enhancing shale oil recovery. To clarify the characteristics of the fluid occurrence space and the variation in the fluid occurrence during saltwater imbibition in Gulong shale, this paper carried out porosity and permeability tests on Gulong shale cores and analyzed the fluid occurrence space characteristics and imbibition oil recovery based on nuclear magnetic resonance (NMR). In the porosity and permeability tests, T2 distributions were used to correct the porosity measured by the saturation method to obtain the NMR porosity. Combined with the identification of fractures in shale cores using micro-CT and the analysis of porosity and permeability parameters, it was found that the permeability of the shale cores was related to the development of fractures in the shale cores. Through the testing and analysis of T1-T2 maps of the shale cores before and after saturation with oil, it was found that the shale mainly contained heavy oil, light oil, and clay-bound water, and they were distributed in different regions in the T1-T2 maps. Finally, the T1-T2 maps of the shale cores at different imbibition stages were analyzed, and it was found that saltwater mainly entered the minuscule inorganic pores of clay minerals during the imbibition process and squeezed the larger-sized inorganic pores containing light oil through the hydration expansion effect, thus expelling the light oil from the shale core and achieving the purpose of enhanced oil recovery.

Pore-Scale Investigation of CH4 Hydrate Kinetics in Clayey-Silty Sediments by Low-Field NMR

Clayey-silty sandy media have been widely discovered in naturally occurring hydrate-bearing sediments in the South China Sea. However, the phase change behavior of CH4 hydrate (MH) and the resulting pore structure change and the migration of fluid in clayey-silty sediments remain less known and warrant investigation. In this study, we examine the pore-scale behavior of MH formation and dissociation in clayey-silty sediments and the associated fluid migration by low-field nuclear magnetic resonance (NMR). Based on T2 spectra measurement, MH starts to grow in small pores (pore size <1 μm) first and in large pores (pore size >10 μm) subsequently. The presence of clay, i.e., Na-MMT, practically retards the overall growth kinetics of MH evidenced by the low H2O conversion (<10%) to MH in clay-associated small pores. During depressurization, MH starts to dissociate in sand-associated large pores first. Free water migrates to clay-associated small pores and partially converts to clay-bound water. MRI visualization depicts the heterogeneous spatial distribution of both MH and the residual water in the process. The experimental results provide possible explanations on the spatial heterogeneity of MH in clay-silty sediments in nature and on the multiphase fluid migration during energy recovery from MH reservoirs.

Separation of solid and liquid components in organic-rich chalks using NMR relaxation

Currently there is great interest in interpreting the 1H NMR T2 relaxation (i.e., transverse relaxation) of porous geological media containing both liquid-like and solid-like signals. This has an impact on the interpretation of commercial NMR core and log analysis of organic-rich shales, such as shale oil and shale gas, where T1-T2 relaxation maps are routinely used to identify sweet spots and producibility of the hydrocarbon reservoir. We report a novel method to separate liquid-like components with an exponential decay (T2e) in transverse magnetization from solid-like components with a Gaussian decay (T2G). The method uses novel pulse sequences together with a 20 MHz 1H NMR relaxometer optimized for reservoir core plugs. The method is applied to obtain 2D T1-T2 maps in organic-rich chalks saturated with water or heptane, as well as bitumen-extracted samples. The T1-T2 maps clearly distinguish liquid-like signals (including micro/meso-macro pore fluids, heptane dissolved in bitumen, and clay-bound water) from solid-like signals (including kerogen, bitumen, and clay hydroxyls) in the organic-rich chalks. The liquid-like (T2e) components in the T1-T2 maps show a clear contrast between water and heptane in the micro/meso-macro pores, which shows potential for improved fluid typing and saturation in organic-rich chalks and gives insights into diffusive coupling and bitumen blockage of the pore network. The solid-like (T2G) components in the T1-T2 maps are used for clay mineral identification, determination of kerogen content, and quantification of solvent-extracted bitumen versus bitumen expelled from kerogen due to swelling from dissolved heptane.

Accurate Rock Mineral Characterization With Nuclear Magnetic Resonance

Nuclear magnetic resonance (NMR) logging is a powerful formation evaluation technology that provides mineralogy-independent porosity and helps distinguish clay-bound water, capillary-bound water, and free fluids. NMR logging tool generally operates at 1H NMR frequency of 2 MHz (magnetic field, B0 ~ 470 Gauss) or lower. At this magnetic field, it is only feasible to detect 1H signal from fluids in pores and rely on the relaxation time variation to characterize fluid and pore types. As magnetic field strength increases, NMR sensitivity increases very dramatically, and NMR signals from solid matrix become easier to be detected in high field. For example, NMR at 600 MHz is about 5,000 times more sensitive than the NMR at 2 MHz. Meanwhile, the spectral resolution of high-field NMR is also greatly increased, and high-field NMR spectrum can resolve the detailed differences between molecule types. Therefore, the high sensitivity and spectral resolution of high-field NMR open a totally new horizon for the characterization of geological samples, especially in organic shale reservoirs, in which organic matter and complex mineralogy remain challenging to be accurately characterized. In this work, we report high-field NMR applications for mineral characterization using a 600-MHz NMR spectrometer equipped with a multichannel and Magic-Angle Spinning (MAS) probe. Compared to X-ray diffraction (XRD), which is the primary tool for identifying and quantifying the mineralogy of crystalline compounds in geological samples based on Bragg’s diffraction, NMR can provide more compositional and structural information for noncrystalline compounds due to its sensitivity to local electronic binding structures. Here we demonstrate such an application of high-resolution 27Al NMR to determine the composition and bonding chemistry of 27Al as a fingerprint for a wide range of minerals. The ratio of 27Al at tetrahedral and octahedral binding sites is quantitative and essential to differentiate the dioctahedral and trioctahedral phases. 27Al NMR can also distinguish plagioclase series members ranging from albite to anorthite end members, where Na and Ca atoms can substitute for each other. 27Al NMR can be further combined with 1H, 13C, 29Si, 25Mg, 23Na, and 31P for more detailed mineral determination and clay typing. Our results show that, combined with XRD, this group of high-field NMR spectroscopic methods can greatly improve the accuracy of rock mineral and formation clay characterization in tight-rock and unconventional reservoirs.

Storing characteristics and main controlling factors of connate water in lower Paleozoic shales in southeast Chongqing, China

Recent studies show that the shale gas content and storage space are influenced by connate water, while it is unclear how connate water occurs in different nanoscale pores in high and overmature shales, and research concerning the occurrence characteristics and factors controlling connate water in overmature shale gas formations is scarce. In this research, overmature lower Paleozoic shale samples from southeastern Chongqing were selected for connate water distribution and factor analysis. The results show that connate water in the lower Paleozoic shale occurs in organic matter and clay minerals, mainly occurs in clay minerals and tends to form clay-bound water in clay minerals. The effect of the connate water content (CIW) on the inorganic nonmicropore (mesopore + macropore) surface area (SA) is greater than that on the organic nonmicropore SA. The CIW mainly affects the micropore structure parameters of clay minerals, and the total organic carbon (TOC) content is the main factor controlling the shale micropore structure. Connate water occurs in shale micropores and nonmicropores, and adsorption and filling states simultaneously exist and are distributed in <10 nm mesopores and 0.4–0.6 nm micropores; this distribution reduces the pore structure parameters of inorganic matter in shale, especially the nonmicropore SA. The effect of the CIW on nonmicropore SA and micropore pore volume (PV) in inorganic minerals is significantly greater than that of organic matter. Connate water mainly occurs in inorganic mineral pores and mainly occupies the mineral nonmicropore SA. Connate water significantly reduces the inorganic pore structure parameters, while its effect on organic pores is limited.

Synthesizing Nuclear Magnetic Resonance (NMR) Outputs for Clastic Rocks Using Machine Learning Methods, Examples from North West Shelf and Perth Basin, Western Australia

A nuclear magnetic resonance (NMR) logging tool can provide important rock and fluid properties that are necessary for a reliable reservoir evaluation. Pore size distribution based on T2 relaxation time and resulting permeability are among those parameters that cannot be provided by conventional logging tools. For wells drilled before the 1990s and for many recent wells there is no NMR data available due to the tool availability and the logging cost, respectively. This study used a large database of combinable magnetic resonance (CMR) to assess the performance of several well-known machine learning (ML) methods to generate some of the NMR tool’s outputs for clastic rocks using typical well-logs as inputs. NMR tool’s outputs, such as clay bound water (CBW), irreducible pore fluid (known as bulk volume irreducible, BVI), producible fluid (known as the free fluid index, FFI), logarithmic mean of T2 relaxation time (T2LM), irreducible water saturation (Swirr), and permeability from Coates and SDR models were generated in this study. The well logs were collected from 14 wells of Western Australia (WA) within 3 offshore basins. About 80% of the data points were used for training and validation purposes and 20% of the whole data was kept as a blind set with no involvement in the training process to check the validity of the ML methods. The comparison of results shows that the Adaptive Boosting, known as AdaBoost model, has given the most impressive performance to predict CBW, FFI, permeability, T2LM, and SWirr for the blind set with R2 more than 0.9. The accuracy of the ML model for the blind dataset suggests that the approach can be used to generate NMR tool outputs with high accuracy.

Improved Description of Organic Matter in Shales by Enhanced Solid Fraction Detection with Low-Field 1H NMR Relaxometry

Nuclear magnetic resonance (NMR) relaxometry is routinely used to characterize the oil fraction in unconventional shale formations with low-field benchtop NMR hardware. However, organic phases with restricted mobility like kerogen and bitumen are typically not detectable with the standard Carr–Purcell–Meiboom–Gill (CPMG) method on such equipment, with the rapid spin–spin (T2) signal decay of these solid/viscous components not visible to the measurement. The solid-echo (SE) and mixed-echo (ME) pulse sequences offer an alternative to the CPMG, extending the lifetime of the time-domain signal and allowing the capture of solid hydrogen-containing species. Accordingly, we combine NMR relaxation data generated from the application of the CPMG, SE, and ME experiments to a set of powdered oil- and brine-saturated Eagle Ford shale samples, with the aim of identifying and quantifing both the immobile (kerogen/bitumen) and mobile (oil/brine) components. Two-dimensional relaxometry correlating spin–lattice relation times T1 to the effective decay times T2 obtained using CPMG and SE techniques provides more complete information on the immobile phases in the shales, such as solid organic matter and clay-bound water. The three spin–echo techniques have similar efficiencies when detecting signal from mobile and low-viscosity fluids, while significant differences are seen in shale samples containing immobile organics. Overall, the combination of the three spin echo techniques provides an improved description of the solid, viscous, and liquid components in the investigated shales at low magnetic field.

NMR relaxometry interpretation of source rock liquid saturation — A holistic approach

Fluid types and saturation are essential factors in assessing oil recovery resources and potential in organic-rich mudstones. One of the methods for analyzing tight rocks' saturation is low-field nuclear magnetic relaxometry (NMR). Interpretation of NMR results, particularly the data of T1-T2 maps, delivers different fluid saturation and estimates hydrogen populations. Although previous research proposed a qualitative interpretation of T1-T2 distributions, there is still no obvious scheme that can be directly applied in routine petrophysical studies. However, current NMR-based workflows and manual interpretation routines are subjective and laborious. We attempt to fill this gap by identifying the best interpretation scheme for three distinct types of organic-rich source rock of the Bazhenov formation and modifying a well-known T1-T2 map interpretation scheme. Experimental results include NMR 2-MHz T1-T2 datasets (original and differential maps for samples in as-received, dried, and saturated states) with the corresponding Rock-Eval pyrolysis parameters and mineral composition from X-ray diffraction. The analytical part compares the existing schemes and modifies the interpretation scheme based on the rock petrophysical background. The paper reviews the features of the manual interpretation and previously established schemes and proposes a modified scheme best fitted to the petrophysical and geochemical data. In addition, we study the impact of mineral composition and geochemical properties on T1-T2 signal interpretation and analyze cross-correlations. The study confirms the presence of a significant amount of clay-bound water from a detailed analysis of the corresponding regions in T1-T2 regular and differential maps. In the paradigm, we propose a semi-automated processing of NMR T1-T2 data using a custom interpretation scheme composed of regions from multiple interpretation schemes and consider their modification for high-quality results.

Molecular Dynamics Simulation in the Interlayer of Mixed-Layer Clays Due to Hydration and Swelling Mechanism

The swelling behavior of clay minerals is widely known for its importance in soil and environmental sciences and its detrimental effects in engineering fields. Although more than 70 percent of all clays are of mixed-layer types, the vast majority of the previous experiments and simulations are focused on pure clays, which cause the swelling mechanism of the widespread mixed-layer clay (MLC) and its role in soils are little understood, especially the most common illite-montmorillonite (I-M) mixed-layer clay (MLC). This paper reports on a molecular dynamics (MD) study of the differences in swelling behavior between I-M MLCs containing K+ and Na+ and Na-montmorillonite (MMT). It captures the evolution of quantitative properties such as basal spacing d, interaction energy, and many hydrogen bonds in the clay interlayer, increasing hydration for the first time through the scripts. It is found that MLCs have smaller swellings than Na-MMT due to the asymmetric interlayer charges and mixed counterions in the I-M interlayer. However, in terms of the interaction energy for the in-depth reason of swelling, it is found that the clay-clay interaction energy and the clay-ion interaction energy drop, while the clay-water interaction energy increases with increasing hydration. In addition, the attractive interaction of clay-bound water seriously promotes swelling, and it is mainly composed of Coulomb interaction and Van der Waals interaction. The higher the K+ concentration, the more noticeable these phenomena are. Besides, it is also reported that the number and distribution mechanism of hydrogen bonds in MLCs are very different from that of pure clay. This work provides insight into the molecular mechanism for initial swelling and clay-bound water interaction in widespread MLCs. This will help to decipher its specific role in soils and minimize clay swelling.

An Integrated Experimental Workflow for Formation Water Characterization in Shale Reservoirs: A Case Study of the Bazhenov Formation

Summary In this study, we aim to develop a new integrated solution for determining the formation water content and salinity for petrophysical characterization. The workflow includes three core components: the evaporation method (EM) with isotopic analysis, analysis of aqueous extracts, and cation exchange capacity (CEC) study. The EM serves to quickly and accurately measure the contents of both free and loosely clay-bound water. The isotopic composition confirms the origin and genesis of the formation water. Chemical analysis of aqueous extracts gives the lower limit of sodium chloride (NaCl) salinity. The CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks. A representative collection of rock samples is formed based on the petrophysical interpretation of well logs from a complex source rock of the Bazhenov Formation (BF; Western Siberia, Russia). The EM employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, and X-ray diffraction (XRD) analysis. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δ18O and δ2H. A modified alcoholic ammonium chloride [(NH4Cl)Alc] method provides the CEC and exchangeable cation concentration of the rock samples with low carbonate content. The studied rock samples had residual formation water up to 4.3 wt%, including free up to 3.9 wt% and loosely clay-bound water up to 0.96 wt%. The latter correlates well to the clay content. The estimated formation water salinity reached tens of grams per liter. At the same time, the isotopic composition confirmed the formation genesis at high depth and generally matched with that of the region's deep stratal waters. The content of chemically bound water reached 6.40 wt% and exceeded both free and loosely bound water contents. The analysis of isotopic composition proved the formation water origin. The CEC fell in the range of 1.5 to 4.73 cmol/kg and depended on the clay content. In this study, we take a qualitative step toward quantifying formation water in shale reservoirs. The research effort delivered an integrated workflow for reliable determination of formation water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs and general reservoir characterization and reserve estimation. The research novelty uses a unique suite of laboratory methods adapted for tight shale rocks holding less than 1 wt% of water.

Swelling Phenomena of the Nonswelling Clay Induced by CO2 and Water Cooperative Adsorption in Janus-Surface Micropores.

With the development of microscopy and sensor techniques, it becomes evident that nonswelling clays show swelling behavior under CO2-water mixture environments at high pressures and temperatures. The examples include Illite, muscovite, and kaolinite-rich rock samples. Here, we investigated the underlying mechanisms of kaolinite swelling induced by CO2 and water using molecular simulations and low-pressure gas adsorption experiments. The results suggest the cooperative adsorption behavior of CO2 and water on contact with kaolinite micropores, which have distinct wettabilities on the two adjoining interlayer surfaces. Even if clay-bound water exists, CO2 can enter the micropores to induce swelling. The measured micropore volume, simulated equilibrium stable interlayer distance with pure water, and that with CO2-water mixture were used in the swelling estimation, which shows good agreement with our experiments. The CO2 and water molecule distributions inside the interlayer micropores verify the importance of the wettabilities of the kaolinite surfaces in this cooperative adsorption behavior. The result extends the traditional understanding of the swelling mechanism, i.e., cation hydration and subsequent osmotic processes. In addition to earlier observations of kaolinite swelling behavior with potassium acetate, our study indicates the significance of the subtle balance of the noncovalent interactions between CO2, water, and the kaolinite Janus surfaces.

Geochemical, petrographic and petrophysical characterization of the Lower Bakken Shale, Divide County, North Dakota

The Lower Bakken Shale is a key member of the Bakken Petroleum System, which is a prolific unconventional accumulation in North America. Unconventional accumulations have unpredictable lateral variations in hydrocarbon production due to a variety of factors including porosity, permeability, and other rock properties. Therefore, understanding the geochemical (source rock potential), petrological, and petrophysical properties of these units is essential in evaluating the hydrocarbon potential for the Lower Bakken Shale. This study utilized cores from four wells within three fields in Divide County, North Dakota, with samples collected for Rock- Eval pyrolysis, organic petrology, petrographic thin section studies, XRD, SEM, porosity, pore size, and pore fluid distribution. Helium porosimetry and NMR T2 porosity techniques were used to estimate porosity and also to check the quality of the results and avoid discrepancies. Results showed that maturity in the study area varies from immature to early mature using Tmax and solid bitumen reflectance. Organic petrology showed the dominance of solid bitumen and marine alginites, which confirms the Type II kerogen identified from pyrolysis and marine depositional environment in the study area. Major organic matter types identified from SEM studies involve stringy OM, OM-mineral admixture, particulate OM and pure OM which host the majority of the organic matter pores. Furthermore, pore types identified from SEM include mineral matrix pores, organic matter pores, and microfracture pores. Porosity values based on both helium and NMR varies but the difference was nominal and attributed to the presence of abundant clay minerals. Pore sizes are distributed within micropores, mesopores, and macropores with thermal maturity, TOC, and clay mineral proportion having a major influence on pore distribution. Clay-bound water was identified to be the dominant fluid within the shale samples using the T2 cutoff values and supporting evidence from the abundance of clay matrix porosity.