Low back pain (LBP) is the most common pain syndrome, and is an enormous burden and cost generator for society. Lumbar facet joints (FJ) constitute a common source of pain, accounting for 15–45% of LBP. Facet joint degenerative osteoarthritis is the most frequent form of facet joint pain. History and physical examination may suggest but not confirm facet joint syndrome. Although imaging (radiographs, MRI, CT, SPECT) for back pain syndrome is very commonly performed, there are no effective correlations between clinical symptoms and degenerative spinal changes. Diagnostic positive facet joint block can indicate facet joints as the source of chronic spinal pain. These patients may benefit from specific interventions to eliminate facet joint pain such as neurolysis, by radiofrequency or cryoablation. The purpose of this review is to describe the anatomy, epidemiology, clinical presentation, and radiologic findings of facet joint syndrome. Specific interventional facet joint management will also be described in detail.Teaching points • Lumbar facet joints constitute a common source of pain accounting of 15–45%. • Facet arthrosis is the most frequent form of facet pathology. • There are no effective correlations between clinical symptoms, physical examination and degenerative spinal changes. • Diagnostic positive facet joint block can indicate facet joints as the source of pain. • After selection processing, patients may benefit from facet joint neurolysis, notably by radiofrequency or cryoablation.

It is critical to probe in situ the dynamics and wettability of oil, water, and gas trapped in the complex microstructure of oil-shale rocks. However, usual techniques cannot separate these fluids in shale rocks. Here, we use multifrequency and multidimensional nuclear magnetic relaxation (NMR) techniques for probing these dynamics. The frequency dispersion behaviors of the longitudinal relaxation rates 1/T 1 for oil and water confined in shales are interpreted through a relaxation model showing one-dimensional (oil) and two-dimensional (2D) (water) diffusing phases confined within the organic kerogen and mineral layers, respectively. We probe the average hopping and residence times of these fluids at pore surfaces and assign signals to water and oil at both organic and mineral pore surfaces for characterizing their local wettability. This allows interpreting our 2D T 1 −T 2 correlation spectra that could be made down-hole, thus giving an invaluable tool for investigating oil and gas recovery on these important porous rocks.

We present a theory and experiments that relate the NMR longitudinal T 1 and transverse T 2 relaxation times to the viscosity η for heavy crude oils with different asphaltene concentrations. The nuclear magnetic relaxation equations are based on a one-dimensional (1D) hydrocarbon translational diffusion in a transient porous network of slowly rotating asphaltene macroaggregates containing paramagnetic species VO 2+ . For heavy crude oils with viscosity η above a certain threshold η c , the effective 1D confinement causes a transition from the usual Stokes−Einstein relation for the translational diffusion coefficient D ∝ 1/η below η c to a wetting behavior D ∼ C te close to the asphaltene aggregates above η c . The theory is compared successfully with the universal viscosity dependencies of relaxation times T 1 and T 2 observed over a large range of viscosities. The theory reproduces the relaxation features of the 2D correlation spectra T 1 −T 2 and D−T 2 for heavy crude oils when varying the asphaltene concentration. This foundation is important because these measurements can be performed down-hole, thus giving a valuable tool for investigating in situ the molecular dynamics of petroleum fluids.

We introduce a method for estimating the wettability of rock/oil/brine systems using noninvasive in situ nuclear magnetic relaxation dispersion. This technique scans over a large range of applied magnetic fields and yields unique information about the extent to which a fluid is dynamically correlated with a solid rock surface. Unlike conventional transverse relaxation studies, this approach is a direct probe of the dynamical surface affinity of fluids. To quantify these features we introduce a microscopic dynamical surface affinity index which measures the dynamical correlation (i.e., the microscopic wettability) between the diffusive fluid and the fixed paramagnetic relaxation sources at the pore surfaces. We apply this method to carbonate reservoir rocks which are known to hold about two thirds of the world's oil reserves. Although this nondestructive method concerns here an application to rocks, it could be generalized as an in situ liquid/surface affinity indicator for any multimodal porous medium including porous biological media.

Asphaltenes cause many problems in crude oil transportation, refinery and production. A clear understanding of asphaltene behavior in crude oils is thus crucial for improving crude oil production. Here, we used noninvasive multiscale NMR techniques such as low field NMR 2D D-T 2 , T 1 -T 2 , nuclear magnetic relaxation dispersion (NMRD) techniques as well as high field 2D NMR DOSY for probing the dynamics and interaction of maltenes with asphaltene aggregates in crude oil. We prepared different asphaltene concentrations ranging between 0% wt (pure maltenes) and 9% wt (native crude oil) by using a dilution procedure that maintains the asphaltene aggregates structure initially present in native crude oil. We showed by multiscale NMR techniques that changing asphaltene concentration induces a drastic modification of hydrocarbon dynamics. In native crude oil, we observe anomalous relation between the diffusion coefficient (D) and the transverse relaxation time (T 2 ) that we can reproduce theoretically by a quasi 1D diffusion of hydrocarbons in between slowly rotating asphaltene macroaggregates. The relation D α T 2 usually observed in crude oils without asphaltenes was progressively appearing when asphaltene concentration decreased. Our 2D D-T 2 results at 2.5 and 23 MHz show that the diffusion coefficient varies by a factor 4 while the T 2 changes by more than an order of magnitude when the asphaltene concentrations vary. These observations prove that the hydrocarbon dynamics changes drastically at nanoscale and vary much less at large length scales (µm). Moreover, the 2D D-T 2 also shows two different dynamics for short and long chain hydrocarbons in crude oil. This is confirmed by high field 2D NMR DOSY. We found also that the ratio T 1 /T 2 in 2D T 1 -T 2 distribution was progressively reduced when asphaltene concentration decrease with an upward bent away in native crude oil at short T 2 that we succeeded to interpret with the quasi 1D hydrocarbon dynamics. We observed that the NMRD profiles are completely different for crude oil with and without asphaltenes. In native crude oil, NMRD techniques clearly evidence a 2D translational diffusion of short hydrocarbon chains at proximity of the asphaltene nanoaggregates. In crude oil without asphaltene, the NMRD profile is explained in term of a rotational reorientation of hydrocarbon chains. Most of our proposed multiscale NMR techniques could be made down-hole and then can give an invaluable tool for a clear understanding of asphaltene behavior in crude oil.