Estimate Permeability from Nuclear Magnetic Resonance Measurements Using Improved Artificial Neural Network Based on Genetic Algorithm

Nuclear magnetic resonance (NMR) and magnetic susceptibility (MS) borehole logging measurements were collected at the Rifle Integrated Field Research Challenge (IFRC) site. The Rifle IFRC site is located at a former uranium ore‐processing facility in Rifle, Colorado. Although removed from the site by 1996, leachate from spent mill tailings has resulted in residual uranium contamination of both groundwater and sediments within the local aquifer. Since 2002, research at the site has primarily focused on quantifying uranium mobility associated with stimulated biogeochemical processes. Ongoing studies at the site include an acetate amendment strategy, in which stimulation of native microbial populations by introduction of a carbon source serves to alter local redox conditions, and immobilization of uranium in insoluble forms. NMR and MS logging measurements were taken before, during, and after acetate amendment. Changes in these signals are expected to correlate with changes in redox conditions and iron speciation thus potentially allowing their use as a non‐invasive tool for monitoring bioremediation. Experimental data was collected from two wells upstream of the acetate amendment, used as controls, and from three downstream wells. The MS measurements revealed vertically stratified magnetic mineralization, likely the result of a detrital magnetic fraction within the bulk alluvium. Data were highly replicable over the monitoring interval, with little to no change observed in the MS measurements, suggesting negligible production of magnetic phases (e.g. magnetite, pyrrhotite) as a result of enhanced microbial activity. NMR measurements had high levels of noise contamination requiring significant signal processing, and ongoing analysis suggests that any changes due to enhanced microbial activity may be difficult to differentiate from simultaneous changes in water content.

Formation evaluation studies suggest that high in the hydrocarbon column, the resistivity logs can precisely quantify fluid saturation due to the large contrast in the resistivities of hydrocarbon-bearing and water-bearing formations. However, in the transition zone where water and oil reside in more or less equal volumes, the determination of hydrocarbon saturation by resistivity value becomes challenging. Some of these intervals exhibit low resistivity pay (LRP) characteristics where resistivity-based log analysis predicts high water saturation, yet they can produce little or no water-cut. Conventional log-based saturation and rock quality evaluation in a low permeability carbonate reservoir is difficult due to the lack of the input measurement's sensitivity to pore size and the amount of pore-filling fluids. Pore size information provided by Nuclear Magnetic Resonance (NMR) logs from this LRP provides good sensitivity, but it needs to be calibrated for quantitative use. The objective of this study is to determine a height-based NMR Bulk Volume Irreducible (HBVI) cutoff to distinguish and quantify the amounts of reservoir fluids across a wellbore using NMR logs. The procedure consists of two-part workflow. The first part describes the acquisition of a data base that includes high-quality laboratory NMR and capillary pressure measurements to determine the pore aspect ratio and the effect of temperature on the formation's NMR properties using core samples from the target reservoir. These measurements are then used to underpin the mathematical description of the HBVI cutoff as a function of displacement pressure that is translated to height above the free water level (HAFWL). The second part of the workflow is a well-log processing scheme where the new formula is implemented to calculate a continuous fluid saturation profile across the well using NMR logs. The laboratory measurements suggest a good agreement between the capillary pressure and NMR T2 measurements. Both data sets indicate a well sorted pore size distribution. The T2 relaxation time increases with temperature, which is then considered in the downhole implementation of the HBVI model. The NMR-based saturation log is consistent with wireline formation testing (WFT) observations and mercury injection capillary pressure (MICP)-based saturation height modeling results in a low resistivity pay reservoir. The results of this study suggest that the laboratory calibration and NMR log processing workflows described herein provide a viable alternative for the calculation of fluid saturations in complex reservoirs where the conventional log-based saturation evaluation faces uncertainties.

This paper presents results of laboratory studies of nuclear magnetic resonance (NMR) relaxometry for NMR log calibration aimed at enhancing petrophysical measurements in oil wells. Relationships between NMR longitudinal relaxation parameters and the Hydraulic Units (HU) concept for predicting petrophysical properties from wireline logs have been established previously. However, modern NMR logging tools measure the transverse relaxation parameters. Hence in this paper, we show that measurements of the transverse component of the NMR signal can provide the same information as the longitudinal. Laboratory NMR transverse relaxation characteristics of water in rock samples were measured with CoreSpec-1000. The NMR data were used to validate models for predicting permeability and producible fluid in clastic rocks. The predictive model for permeability includes the rock surface area to grain volume (Sgv) the tortuosity of the flow paths (), the shape factor (Fs), the transverse relaxation time (T2), relaxivity (), and porosity (). The models were used to develop the required NMR log calibration. The transverse relaxation parameters were used with core analysis data of permeability, porosity, and mercury injection capillary pressures to sort the rock samples into hydraulic (flow) units. Protocol for the use of laboratory NMR core spectrometry and core analysis data for NMR log calibration is presented. Relationships between T1 and T2, and between flow zone indicators (FZI) and relaxivity () were established. It was observed that T2 cut-off (T2c) is related to T1 cut-off (T1c) in the same way that T2 is related to T1. Relaxation time cutoffs are used for determining producible fluid (free fluid porosity or free fluid index, FFI). The results show that reliable prediction of permeability and producible fluid from NMR logging tools requires calibration of the tools with laboratory NMR measurements on representative rock samples. We demonstrate the use of T2c for determining FFI from T2 distributions. The methodology for identification and characterization of HU within geological facies based on NMR T2 was validated. Introduction The (HU) concept has successfully been integrated with laboratory core NMR measurements for evaluating petrophysical properties from wireline logs (Ohen et al.). The HU and NMR techniques were linked through the FZI and NMR relaxation parameters, because both the FZI and the relaxation parameters are related to the rock surface phenomenon which controls the microscopic attributes of the rock. Ohen et al. measured the longitudinal (spin-lattice) relaxation time (T1) on a number of reservoir rock samples at a Larmor frequency of 1 MHz with the CoreSpec-1000. P. 329

Coal pore systems can be commonly classified as diffusion pores, permeation pores and cleats. The classification accuracy influences the coalbed methane (CBM) migration processes from diffusion to permeation and then to outflow, and finally affects the predicted CBM recoverability. To classify coal pore systems precisely, measurements of nuclear magnetic resonance (NMR), mercury intrusion porosimetry (MIP), and nitrogen adsorption isotherm (NAI) are conducted in this paper, and then a comprehensive classification method is proposed. The following cognitions are achieved. NMR spectra can be divided into three categories of three-peak, single narrow peak, and non-three/non-single-narrow peak spectra. The former two categories can be directly used to identify coal pore systems as one peak representing one pore system, and pore systems of the last category can be distinguished by using cumulative amplitudes at the fully water-saturated and centrifuged conditions. Fractal theory suggests that the dividing radii of diffusion–permeation pores obtained by MIP and NAI are quite close, which indicates that the two methods are both effective and accurate. Comparisons between mercury intrusive and cumulative amplitudes indicate that the classification results obtained by measurements of MIP and NMR are similar, which can be a base for transforming transverse relaxation time to pore radius. As a result, the dividing radius of diffusion–permeation pores is about 65 nm, and that of permeation–cleat pores is approximately 600–700 nm.

Assessing quantitatively the microscopic pore structures of porous rocks, including irregularities of pore shapes and pore size distributions, is becoming one of the most challenging efforts. Nuclear magnetic resonance (NMR) measurements were used to provide insights into the pore geometry (pore size and shape) and pore connectivity of the Chang 7 tight shaly sandstones (in situ permeability <0.1 md) in Ordos basin. The incremental transverse relaxation time (T2) distributions for the 100% brine-saturated samples display unimodal and bimodal behaviors, presenting a geometrical arrangement composed of small to large pore size domains. The NMR parameters such as bulk volume irreducible (BVI) (capillary and clay-bound water), free fluid index (FFI) (movable water), the value of T2 separating the BVI from FFI, the amplitude weighted mean on a logarithmic scale (T2gm), and the value of T2 that shows the highest frequency on the T2 spectrum (T2peak) for each sample were determined. Then the fractal theory was adopted to quantitatively express the complexity and heterogeneity of the sandstones. The results show that only minor primary intergranular porosity remains, and variable amounts of micropores and secondary intragranular porosity with poor connectivity occur in the Chang 7 tight shaly sandstones. Assuming spherical pores, a new model to calculate the fractal dimension of pore structure from the NMR T2 distributions is proposed. The fractal dimensions of all the samples are calculated, and the accuracy of the proposed model is verified by the regression coefficients. The microscopic pore structures are heterogeneous in these tight sandstones according to the high value of fractal dimensions. Micropores are the primary causes of heterogeneity in tight sandstones, and samples with unimodal T2 distribution behaviors and high content of short components have the highest fractal dimension and heterogeneity. The calculated fractal dimension is strongly correlated with T2peak and T2gm; therefore, the fractal model proposed in this study can be used to calculate the fractal dimensions and evaluate the heterogeneities of the porous rocks satisfactorily. The fractal model proposed in this study helps to quantitatively assess the pore structures of tight sandstones using NMR measurements.

NMR (Nuclear magnetic Resonance) measurements have been extensively used for characterizing porosity and pore size distribution with assumption of constant magnetic field gradient within porous media. However, internal gradients of magnetic field generated due to the presence of paramagnetic or diamagnetic centers such as clay particles can significantly affect NMR response and the resulting interpretation for pore-size distribution and porosity. In this paper, we quantify the impact of internal magnetic gradients and spatial distribution of matrix components such as clay minerals on NMR response using pore-scale NMR numerical simulations. We also quantify the influence of the aforementioned parameters on the NMR-based evaluation of porous media. We used finite volume method to numerically solve Bloch equations (Bloch 1946) and simulated magnetization decay in porous media. We cross-validated the reliability of numerical simulations using analytical solutions given for spherical pores in different diffusion regimes. The model is then used for simulation of NMR response in the pore-scale images of sandstone and carbonate rocks. We developed synthetic cases based on actual rock images covering a wide range of spatial distribution of clay minerals (i.e., paramagnetic or diamagnetic centers) to quantify the sensitivity of NMR decay to internal magnetic gradients. We quantified the sensitivity of NMR response for distribution of clays as random dispersion in the rock grains, as thin laminae in the rock and as thin layers on the surface of grains. The results showed that at low concentration (e.g., 0.3%-0.7%) of dispersed clay, there is negligible impact of internal magnetic gradients on magnetization decay. At higher concentration of dispersed clay (e.g., 5.1%-7.3%), we observed significant impact of internal magnetic gradients on magnetization decay. The presence of clay minerals can cause 53% variation in the location of transverse relaxation time constant (T2) and up to 67% relative error in assessment of dominant pore sizes. We also observed that structural clays even at high volumetric concentrations of 40% produce negligible effect on NMR measurements. Shale laminations containing clay were found to produce an effect of up to 17.5% on T2 relaxation time constant that could cause a relative error of 23.1% in estimates of dominant pore size in the rock. The outcomes of this paper can potentially improve conventional techniques of pore network characterization (pore-size distribution and pore volume) in the presence of clay minerals where internal magnetic gradients are not negligible.

α-Synuclein (αS) is a presynaptic protein that binds to cell membranes and is linked to Parkinson’s disease (PD). Binding of αS to membranes is a likely first step in the molecular pathophysiology of PD. The αS molecule can adopt multiple conformations, being largely disordered in water, adopting a β-sheet conformation when present in amyloid fibrils, and forming a dynamic multiplicity of α-helical conformations when bound to lipid bilayers and related membrane-mimetic surfaces. Multiscale molecular dynamics simulations in conjunction with nuclear magnetic resonance (NMR) and cross-linking mass spectrometry (XLMS) measurements are used to explore the interactions of αS with an anionic lipid bilayer. The simulations and NMR measurements together reveal a break in the helical structure of the central non-amyloid-β component (NAC) region of αS in the vicinity of residues 65–70, which may facilitate subsequent oligomer formation. Coarse-grained simulations of αS starting from the structure of αS when bound to a detergent micelle reveal the overall pattern of protein contacts to anionic lipid bilayers, while subsequent all-atom simulations provide details of conformational changes upon membrane binding. In particular, simulations and NMR data for liposome-bound αS indicate incipient β-strand formation in the NAC region, which is supported by intramolecular contacts seen via XLMS and simulations. Markov state models based on the all-atom simulations suggest a mechanism of conformational change of membrane-bound αS via a dynamic helix break in the region of residue 65 in the NAC region. The emergent dynamic model of membrane-interacting αS advances our understanding of the mechanism of PD, potentially aiding the design of novel therapeutic approaches.

Polymer gel treatment is a successful technology for conformance improvement. Achieving effective deep conformance control in high-temperature reservoirs requires improving the performance of gel in these environments and a deep understanding of gel-conformance control mechanisms inside reservoir rocks. In this work, a laboratory study was conducted to evaluate a polyacrylamide/chromium gel system for a carbonate reservoir at high-temperature and high-salinity (HTHS) conditions. Displacement experiments combined with nuclear magnetic resonance (NMR) measurements were performed to investigate the mechanisms of conformance treatment as well as demonstrate the potential of oil production improvement by a gelling system. Coreflooding tests were performed on carbonate core samples with different configurations of high-permeability channels. Both gel treatment and polymer flooding experiments were conducted to quantify and differentiate between fluid-diversion and viscous effects on oil production improvement due to the treatment. Detailed spatial fluid variations inside the core samples before and after gel treatment were closely monitored using low-field NMR techniques. Both coreflooding experiments and NMR measurements clearly showed that significant oil production improvement was achieved by gel treatment. The bypassed oil during waterflooding was effectively mobilized. Gel treatment is more efficient in oil production improvement for more heterogeneous core samples. The comparison study of gel treatment and polymer flooding helps gain insight into the mechanisms of oil displacement. Results show that the blockage or fluid-diversion effect plays a more significant role in oil production improvement after gel treatment. The viscous effect of gelant flow helps mobilize oil in the matrix region. The oil production improvement by gel treatment is mainly attributed to the fluid-diversion effect, especially for the treatment in high-permeable configuration. Moreover, results of the study demonstrate the potential of the studied gel system for carbonate reservoirs at high temperature. NMR techniques add additional valuable information to conventional displacement tests to identify the dominant mechanisms of oil mobilization.

Small and medium sized HDL particles are protectively associated with coronary calcification in a cross-sectional population-based sample

Pore size distributions in rocks may be represented by fractal scaling, and fractal descriptions of pore systems may be used for prediction of petrophysical properties such as permeability, tortuosity, diffusivity, and electrical conductivity. Transverse relaxation time (T2) distributions determined by nuclear magnetic resonance (NMR) measurements may be used to determine the fractal scaling of the pore system, but the analysis is complicated when internal magnetic field gradients at the pore scale are sufficiently large. Through computations in ideal porous media and laboratory measurements of glass beads and sediment samples, we found that the effect of internal magnetic field gradients was most pronounced in rocks with larger pores and a high magnetic susceptibility contrast between the pore fluid and mineral grains. We quantified this behavior in terms of pore size and Carr-Purcell-Meiboom-Gill (CPMG) half-echo spacing through scaling arguments. We additionally found that the effects of internal field gradients may be mitigated in the laboratory by performing T2 measurements with different CPMG half-echo spacings and fitting the apparent fractal dimensions determined by the NMR measurements with a model to determine the true pore system fractal dimension.

This paper reports the formation and structure of fast setting geopolymers activated by using three sodium silicate solutions with different modules (1.6, 2.0 and 2.4) and a berlinite-type aluminum orthophosphate. By varying the concentration of the aluminum orthophosphate, different Si/Al-ratios were established (6, 3 and 2). Reaction kinetics of binders were determined by isothermal calorimetric measurements at 20 °C. X-ray diffraction analysis as well as nuclear magnetic resonance (NMR) measurements were performed on binders to determine differences in structure by varying the alkalinity of the sodium silicate solutions and the Si/Al-ratio. The calorimetric results indicated that the higher the alkalinity of the sodium silicate solution, the higher the solubility and degree of conversion of the aluminum orthophosphate. The results of X-ray diffraction and Rietveldt analysis, as well as the NMR measurements, confirmed the assumption of the calorimetric experiments that first the aluminum orthophosphate was dissolved and then a polycondensation to an amorphous aluminosilicate network occurred. The different amounts of amorphous phases formed as a function of the alkalinity of the sodium silicate solution, indicate that tetrahydroxoaluminate species were formed during the dissolution of the aluminum orthophosphate, which reduce the pH value. This led to no further dissolution of the aluminum orthophosphate, which remained unreacted.

Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection- an Eagle Ford study

ABSTRACTThe measurements of nuclear magnetic resonance (NMR) parameters to investigate petrophysical properties related to fluid (e.g., water) storage and transport processes provide unique insights compared to other geophysical methods and have become a very useful tool for geophysicists during the last decades at the laboratory scale and as a borehole tool.We investigated, at a groundwater test site in the desert of Abu Dhabi, the reliability and limitation of surface NMR, a new but establishing technique that measures the NMR parameter from the surface by comparing its results to borehole NMR logs. Surface NMR or magnetic resonance sounding measurements (MRS) were conducted along a profile, close to several boreholes. The available borehole NMR logs were used to i) evaluate the potential of surface NMR derived results comparing them with borehole NMR measurements and to ii) extend the hydrogeological knowledge of the groundwater site.Firstly, we show how to carefully handle short relaxation signals of surface NMR data. The most significant steps during this process are: i) broad‐band filtering to preserve the short decaying NMR signals, ii) correction for relaxation during pulse effects and iii) QT‐inversion to extract reliable subsurface parameter distribution.By comparing surface NMR results with borehole NMR logs we found the following limitations: i) surface NMR is not able to detect borehole NMR measured water content related to decay times lower than decay time. This reduced detectable water content of surface NMR is due to an instrumental dead time of 40 ms, measured relaxation times and a lower Larmor frequency of 2 kHz and ii) borehole NMR has significantly higher vertical resolution. Taking this into account, surface NMR is in good agreement with borehole NMR.Secondly, on a profile of 1.3 km length 11 MRS measurements were carried out to map the lateral aquifer structure. The obtained results show that surface NMR provides unique lateral information of demanded aquifer properties complementary to e.g., transient electromagnetic.

Analysis of heterogeneous gas sand reservoirs is one of the most difficult problems. These reservoirs usually produced from multiple layers with different permeability and complex formation, which is often enhanced by natural fracturing. Therefore, using new well logging techniques like NMR or a combination of NMR and conventional open hole logs, as well as developing new interpretation methodologies are essential for improved reservoir characterization. Nuclear magnetic resonance (NMR) logs differ from conventional neutron, density, sonic and resistivity logs because the NMR measurements provide mainly lithology independent detailed porosity and offer a good evaluation of the hydrocarbon potential. NMR logs can also be used to determine formation permeability and capillary pressure. This paper concentrates on permeability estimation from NMR logging parameters. Three models used to derive permeability from NMR are Kenyon model, Coates-Timer model and Bulk Gas Magnetic Resonance model. These models have their advantages and limitations depending on the nature of reservoir properties. This paper discusses permeability derived from Bulk Gas Magnetic Resonance Model and introduces neural network model to derive formation permeability using data from NMR and other open hole log data. The permeability results of neural network model and other models were validated by core permeability for the studied wells.

The viscosity of crude oil plays a pivotal role in the exploration and development of oil fields. The predominant reliance on laboratory measurements, which are constrained by manual expertise, represents a significant limitation in terms of efficiency. Two-dimensional nuclear magnetic resonance (NMR) logging offers a number of advantages over traditional methods. It is capable of providing faster measurement rates, as well as insights into fluid properties, which can facilitate timely adjustments in oil and gas development strategies. This study focuses on the loose sandstone reservoirs with high porosity and permeability containing heavy oil in the Huabei oilfield. Two-dimensional nuclear magnetic resonance (NMR) measurements and analyses were conducted on saturated rocks with different-viscosity crude oils and varying oil saturation levels, in both natural and artificial rock samples. This study elucidates the distribution patterns of different-viscosity crude oils within the two-dimensional NMR spectra. Furthermore, the T1 and T2 peak values of the extracted oil signals were employed to establish a model correlating oil viscosity with NMR parameters. Consequently, a criterion for determining oil viscosity based on two-dimensional NMR was formulated, providing a novel approach for estimating oil viscosity. The application of this technique in the BQ well group of the Huabei oilfield region yielded an average relative error of 15% between the actual oil viscosity and the computed results. Furthermore, the consistency between the oil types and the oil discrimination chart confirms the reliability of the method. The final outcomes meet the precision requirements for practical log interpretation and demonstrate the excellent performance of two-dimensional nuclear magnetic resonance (NMR) logging in calculating oil viscosity. The findings of this study have significant implications for subsequent exploration and development endeavors in the research area’s oilfields.