Fines migration is a phenomenon of practical importance in the petroleum-production and drilling industry. The movement of clay particles, induced by incompatible aqueous-phase chemistry or high flow rate, obstructs pore throats downstream of the fluid flow, leading to permeability reductions that can be as large as two orders of magnitude. Magnetic-resonance-imaging (MRI) methods derived from the Carr-Purcell-Meiboom-Gill (CPMG) method (Meiboom and Gill 1958) can map T₂ distributions in porous rocks, hence showing the spatial variation of the pseudo-pore-size distribution. In this work, the traditional water-shock experiment was used to mobilize clay particles in the aqueous phase flowing in Berea core plugs. Spin-echo single-point imaging (SE-SPI), a phase-encoding MRI method derived from the CPMG method, was used to determine spatially resolved T₂ spectra of the samples, and therefore the pseudo-pore-size distributions. The shift in the T₂ spectra of the core inlet and outlet showed opposite trends. The pore-size distribution of the inlet and outlet, inferred from T₂ distributions, were shifted to larger and smaller values, respectively. Therefore, the average pore size was increased at the inlet of the core and reduced at the outlet of the core. This MRI method provides a new analytical approach to screen reservoirs for potential fines-migration problems.

Magnetic-resonance imaging (MRI) provides a wealth of information on petroleum-flooding-displacement mechanisms and in-situ pore-level behavior. This study demonstrates MRI methods that have potential for studying the mechanisms of carbon dioxide (CO₂) displacement processes in Berea core plugs during the recovery of decane and heavy oil. The correlation between fluid saturation and transverse relaxation time (T₂) revealed the contrast in decane/pore-surface interaction between miscible and immiscible drainage of decane by CO₂. T₂ profiles demonstrated changes in the composition and viscosity of the heavy oil caused by the extraction of light components by CO₂.

We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried out in core plugs with reduced pore volumes, i.e., short core samples and aged with a dynamic ageing method. The method was evaluated by three different oil compositions. A series of synthetic multicomponent brines and designed fluid injection scenarios are investigated; injection flow rates are optimized to ensure that a capillary-dominant regime is maintained. Changes in brine compositions and fluid distribution in the core plugs are characterized using ion chromatography and X-ray computed tomography, respectively. First, we show that polar components in the oil phase play a major role in wettability alteration during ageing; this controls the oil production behavior. We also show that, compared to seawater, both formation water and ten-times-diluted seawater are better candidates for enhanced oil recovery in the Dan field. Finally, we show that the modified flow zone indicator, a measure of rock quality, is likely the main variable responsible for the higher oil recoveries observed in Tor core samples.

Nonground eigenvalues are widely disregarded in magnetic resonance relaxation measurements of porous media due to difficulties involved in their measurement, detection, and the derivation of physically meaningful parameters from them. Such nonground eigenvalues may be experimentally observed in relaxation measurements, such as the relaxation correlation of $T_1-T_2$, and yield information on the pore size and surface relaxivity of porous media without calibration through other independent measurements. Nonground eigenvalue analysis of $T_1-T_2$ measurements on Berea sandstone undertaken at three static magnetic fields produces pore sizes consistent with those obtained through x-ray microtomography and SEM measurements. Similar agreement is found for a Bentheimer sandstone with a more complex pore geometry. A phase-encoding imaging variant of this method measures the imbibition confinement-size profile in Berea sandstone. It is suggested that the existence of nonground eigenmodes may be much more prevalent in simple magnetic resonance relaxation measurements than previously considered. Therefore, it is possible to measure pore size by matching numerical Brownstein-Tarr solutions with those of experiments in a wide variety of samples and magnetic resonance methods.

Multi‐exponential decay is prevalent in magnetic resonance spectroscopy, relaxation, and imaging. This paper describes simple MATLAB and Python functions and scripts for regularized multi‐exponential analysis methods for 1D and 2D data and example test problems and experiments. Regularized least‐squares solutions provide production‐quality outputs with robust stopping rules in ~5 and ~20 lines of code for 1D and 2D inversions, respectively. The software provides an open‐architecture simple solution for transforming exponential decay data to the distribution of their decay lifetimes. Examples from magnetic resonance relaxation of a complex fluid, a Danish North Sea crude oil, and fluid mixtures in porous materials—brine/crude oil mixture in North Sea reservoir chalk—are presented. Developed codes may be incorporated in other software or directly used by other researchers, in magnetic resonance relaxation, diffusion, and imaging or other physical phenomena that require multi‐exponential analysis.