A key factor for the petroleum potential of source rock is the degree of chemical and physical structure evolution of its kerogen fraction through a range of maturation processes. In this study, various high-field, solid-state NMR methods have been applied to a series of kerogen isolates (type I) over a defined maturity range (vitrinite reflectance R-0 from 0.98 to 1.86%). Results obtained from C-13 MAS NMR show that the sp(2)/sp(3)-hybridized carbon ratio of kerogen, here defined as the aromatic/aliphatic ratio, increases with increasing maturity. H-1 MAS NMR spectra contain partly overlapping aliphatic and aromatic resonances with distinct transverse relaxation behavior. In Hahn-echo experiments, the aromatic signal decays more slowly than the aliphatic signal, indicating that for these systems, transverse 'H relaxation is rather controlled by local distances between hydrogen atoms than by molecular mobility. Similar relaxation differences are also found in static (nonspinning) H-1 Hahn-echo NMR experiments, here used to discriminate between phases with different proton mobilities and/or densities in the kerogen samples and, ultimately, between aromatic and aliphatic fractions. The distributions of the static transverse relaxation time (T-2), extracted from the Hahn-echo decays, are characterized by a short-T-2 peak (similar to 10 /is) and a long-T-2 peak (similar to 100 mu s). The ratio between these two peaks correlates well with the aliphatic-to-aromatic signal intensity ratios in MAS NMR spectra of the corresponding kerogen samples, suggesting that a net decrease in kerogen proton density-occurring during maturation-is also reflected by H-1 NMR relaxation. For the investigated kerogen isolates, the long-T-2 peak in the T-2 distribution can be considered an indicator of aromatic content, which can be directly detected by measuring H-1 T-2 relaxation.

Nuclear magnetic resonance (NMR) is a powerful technique for determining the petrophysical properties (porosity, permeability, and fluid mobility) of subsurface reservoirs through well logs, laboratory core analysis, or surface measurements of drill cuttings at the rig site. In well logging, NMR is considered a lithology-independent tool, but in surface measurements, it is possible to determine the apparent magnetic susceptibility contrast between the rock and a saturating liquid from a measure of the free induction decay. The magnetic susceptibility of the rock is influenced by paramagnetic minerals (iron and manganese oxides) and provides a simple method for detecting variations in lithology, particularly shale bands. Here, NMR measurements of apparent magnetic susceptibility contrast are obtained on a selection of core plugs, powdered rock, and drilled cuttings using a commercial bench top instrument, and shown to correlate to the iron content of the samples. This rapid and robust analysis complements the standard NMR petrophysical measurements and could be used to detect formation tops in near-real-time at the rig site.

We present a nonlinear inversion method for generating sparse solutions to the Fredholm Integral equation describing two-dimensional distributions of nuclear magnetic resonance (NMR) relaxation times or diffusion coefficients. Our greedy variational method approximates the distribution of exponential rate constants using a sum of Dirac delta functions, which constitute our dictionary elements. The greedy nature of the method promotes sparsity in the representation by iteratively increasing the number of terms. The variational component estimates the parameters of the Dirac delta functions from a continuum at each iteration by reducing the least squares misfit to the data. Unlike sparsity promoting linearized inversion methods, where the dictionary is fixed and can exponentially grow in the case of multiple variables or when searching for higher resolution, the greedy component of our method aims to keep the dictionary small while the variational component keeps the dictionary dynamic. We demonstrate our method with synthetic data and experimental measurements of T1-T2 correlations of liquid-saturated porous rocks. The sparsity of the approximate solutions is ideal for real-time processing and transmission in remote or mobile NMR applications such as well logging.

We explore, by direct numerical simulations of the Bloch-Torrey equation in a single model pore, NMR decay by "diffusion in a gradient". Illustrative results from the finite-element package COMSOL are shown for a single "pore" taken from a numerical model (unrelated) of a human vertebra reduced 3 orders of magnitude in size, with the internal field modelled by numerical solution of the local magnetostatic problem. Results are shown for a single Hahn echo in the known limits of "Short Time" (ST), "Motionally Averaged" (MAV) and "Localization" (LOC) behaviour. Computing time on a laptop is less than 1 min; the approach is entirely practical for obvious immediate extensions. The LOC regime is shown explicitly to be qualitatively different from both the ST and MAV limits, where the dominant diffusion eigenmode is uniform. In LOC, the intra-pore magnetization is rapidly distorted, and "Localized" to small pockets, either where restricted by the pore walls, or around internal field extrema. Surviving magnetization may comprise only a small and possibly unrepresentative fraction of the fluid-filled pore volume. These features are in agreement with the limited analytical results. (C) 2017 Published by Elsevier Inc.

Oil-based drilling fluids are complex emulsio-dispersions used in the construction of subsurface wellbores. Design and control of the rheological properties are crucial for successful drilling operations because the fluid performs several critical functions, such as hole cleaning (particle transport) and ensuring wellbore stability. One of the physical characteristics of the fluid that relates to rheology is the size of the water-in-oil emulsion droplets. Here we demonstrate the use of nuclear magnetic resonance (NMR) pulsed field gradient (PFG) diffusion measurements to determine droplet size distributions in oil-based drilling fluid analogues and a commercial formulation. NMR PFG allows these optically opaque samples to be measured without dilution, and the measurement is sensitive only to the liquid components. Although the NMR technique is established, the application to drilling fluids is novel. Through simulation and experiment, the suitability of a low-field benchtop NMR instrument (commonly used for rock core analysis in the petroleum industry) for measuring droplet size distributions in these fluids is explored. Despite limitations on the available gradient strength and the bulk diffusion coefficient of the brine, droplet radii in the range a = 1 mu m to 50 mu m are measured. The low-field NMR instrument is shown to be suitable for characterizing drilling fluids and similar complex emulsions.

Single-phase flows of viscoelastic polymer solutions in both microfluidic devices and rock cores exhibit apparent flow thickening. We demonstrate that this thickening occurs above a critical Deborah number corresponding to the onset of spatio-temporal fluctuations. These fluctuations are observed to occur over a broad range of spatial and temporal scales consistent with elastic turbulence. The fluctuations provide a previously unreported mechanism for enhancing the displacement of a second, capillary trapped, immiscible phase.

Viscoelastic polymer solutions flowing through reservoir rocks have been found to improve oil displacement efficiency when the aqueous-phase shear-rate exceeds a critical value. A possible mechanism for this enhanced recovery is elastic turbulence that causes breakup and mobilization of trapped oil ganglia. Here, we apply nuclear magnetic resonance (NMR) pulsed field gradient (PFG) diffusion measurements in a novel way to detect increased motion of disconnected oil ganglia. The data are acquired directly from a three-dimensional (3D) opaque porous structure (sandstone) when viscoelastic fluctuations are expected to be present in the continuous phase. The measured increase in motion of trapped ganglia provides unequivocal evidence of fluctuations in the flowing phase in a fully complex 3D system. This work provides direct evidence of elastic turbulence in a realistic reservoir rock - a measurement that cannot be readily achieved by conventional laboratory methods. We support the NMR data with optical microscopy studies of fluctuating ganglia in simple two-dimensional (2D) microfluidic networks, with consistent apparent rheological behaviour of the aqueous phase, to provide conclusive evidence of elastic turbulence in the 3D structure and hence validate the proposed flow-fluctuation mechanism for enhanced oil recovery.

A laboratory study on core plugs from a carbonate field confirmed the efficacy of an alkaline surfactant (AS) formulation at reservoir conditions. Continuous monitoring of remaining oil saturation (ROS) in short core plugs using spatially resolved nuclear magnetic resonance (NMR) can provide insights into the processes by which surfactants release post-water-flood remaining oil. In single short plugs, volumetric averages do not correctly quantify remaining oil due to capillary end effects (high remaining oil saturation post water flood observed at the outlet face of the plug), oil banks, and other flow heterogeneities. These effects are all quantifiable by NMR, allowing accurate monitoring of ROS. Here, consistent ROS values are obtained in the laboratory, in single-well pilots, and in single-well chemical-tracer (SWCT) tests. Laboratory core floods with nuclear magnetic resonance (NMR) monitoring at low magnetic fields therefore provide a valuable calibration of the NMR logs, in addition to the direct assessment of ROS. Corroboration across multiple length scales, spatial resolution, and correspondence with preferred logging measurements, all contribute to the value of NMR-monitored core-floods as a complement to field pilot studies. Introduction Monitoring the efficacy of enhanced oil recovery (EOR) processes is an important step in the screening of new chemical agents. This screening process begins at the laboratory scale (Stoll et al. 2011). It is important to understand both the liquidliquid and liquid-rock interactions. A possible EOR agent is identified and then adjusted to provide the required fluid-phase behavior for a given set of reservoir conditions (temperature, salinity, crude composition, restore reservoir wettability). The role of surfactants is to reduce the interfacial tension (IFT) between oil and water; this is a critical requirement of the chosen formulation. The alkaline convert some of the oil into surfactant, further reducing the oil/water interfacial tension. Laboratoryscale core floods constitute the next stage of screening to explore liquid-rock interactions before reservoir pilots. Here, the alkaline alters the charge of the rock surface to reduce surfactant adsorption. Nuclear magnetic resonance (NMR) is a powerful tool for assessing remaining oil saturation (ROS) during EOR both in the reservoir—via NMR logging—and in the laboratory with a low-field bench-top instrument. Quantitative EOR evaluation has been demonstrated on short plugs at the laboratory scale using spatially resolved low-field NMR. The spatial dimension is important at all EOR piloting length scales, but is critical when studying short plugs where bulk volumetrics may be dominated by capillary or geometry end effects and yield inaccurate ROS values. At the laboratory scale, it is usual to construct long composite cores (length > 30 cm [12 in.]) from plugs to reduce the significance of end effects and other flow heterogeneities on bulk assays of remaining oil (e.g., effluent gravimetrics). Commercial NMR systems are not suited to bulk measurements of such long samples, thereby requiring some form of mechanical scanning to explore the entire core. Such methodology prevents continuous monitoring of ROS during a core flood. In the laboratory, NMR offers the capability to spatially resolve the distribution of ROS within a short core plug (length = 5 cm [2 in.]). Previously, we demonstrated the quantitative measurements of ROS, consistent with well logs, in such short plugs by monitoring a central portion of the plug expected to be free from capillary or geometry end effects. Magnetic resonance imaging (MRI) of core plugs has been unsuccessful as a probe of ROS; implemented at high field, the solid/fluid magnetic susceptibility contrast prevents quantitative assay of in-situ liquid volumes, and limits the practical spatial resolution, preventing pore-scale imaging. The history of MRI in special core analysis (SCAL) is given by Mitchell et al. (2013b). Here, we use a low-field permanent magnet (B0 = 50 mT [500 G]) to obtain a spatial distribution of oil saturation in a profile (single image axis). The signal-to-noise ratio

Sandstone rocks can contain microscopic variations in composition that complicate interpretation of nuclear magnetic resonance (NMR) relaxation time measurements. In this work, methods for assessing the degree of sample heterogeneity are demonstrated in three sandstones. A two-dimensional T1-Δχapp correlation (where Δχapp is the apparent solid/liquid magnetic susceptibility contrast) reveals the microscopic heterogeneity in composition, whilst a spatially resolved T1 profile reveals the macroscopic structural heterogeneity. To perform these measurements efficiently, a rapid measure of longitudinal T1 relaxation time has been implemented on a low-field NMR spectrometer with a magnetic field strength B0=0.3 T. The "double-shot" T1 pulse sequence is appropriate for analysis of porous materials in general. Example relaxation time distributions are presented for doped water phantoms to validate the method. The acquisition time of the double-shot T1 sequence is equivalent to the single-shot Carr-Purcell Meiboom-Gill (CPMG) sequence used routinely in petrophysics to measure transverse T2 relaxation. Rapid T1 measurements enable practical studies of core plugs at magnetic field strengths previously considered inappropriate, as T1 is independent of molecular diffusion through pore-scale (internal) magnetic field gradients.

Abstract A laboratory study on core plugs from a carbonate field confirmed the efficacy of an alkaline surfactant (AS) formulation at reservoir conditions. Continuous monitoring of remaining oil saturation (ROS) in short core plugs using spatially resolved nuclear magnetic resonance (NMR) can provide insights into the processes by which surfactants release post-water-flood remaining oil. In single short plugs, volumetric averages do not correctly quantify remaining oil due to capillary end effects (high remaining oil saturation post water flood observed at the outlet face of the plug), oil banks, and other flow heterogeneities. These effects are all quantifiable by NMR, allowing accurate monitoring of ROS. Here, consistent ROS values are obtained in the laboratory, in single-well pilots, and in single-well chemical-tracer (SWCT) tests. Laboratory core floods with nuclear magnetic resonance (NMR) monitoring at low magnetic fields therefore provide a valuable calibration of the NMR logs, in addition to the direct assessment of ROS. Corroboration across multiple length scales, spatial resolution, and correspondence with preferred logging measurements, all contribute to the value of NMR-monitored core-floods as a complement to field pilot studies.

Surfactant formulations that give rise to ultra-low interfacial tensions are used to enhance the recovery of crude oil by eliminating the trapping effects of capillary forces. The formulations, when mixed with oil, often give microemulsion-type phase behaviour. Depending on the surfactant affinity for oil and water, the microemulsion may exist as water-in-oil (L2), oil-in-water (L1), or bi-continuous (L3). Here, an aqueous formulation of anionic surfactants and butan-2-ol that would give rise to Ll and L3 phase behaviours at different NaC1 concentrations is injected into decane-filled porous media. The displacement processes in rock cores are followed by spatially resolved NMR and in microfluidic models by optical microscopy. Both surfactant formulation types enhance the oil displacement from the core but the L3-forming system shows more complex behaviour, consistent with first the formation and then the displacement of microemulsion phases, which leads to significant enhancements in oil recovery. (C) 2014 Elsevier B.V. All rights reserved.