Low-field Nuclear Magnetic Resonance (NMR) has proved to be a valuable tool for the petrophysical characterization of conventional reservoirs, but its effective application to unconventional reservoirs is still under research. Pore structure characterization of shales is particularly challenging due to the complexity of the pore network and the small size of pores. Using low-field NMR, we performed transverse relaxation (T2) experiments on samples from the Perth Basin, Western Australia. The samples were initially saturated with KCl brine to obtain the total NMR porosity and T2 distribution, then centrifuged and finally oven-dried at increasing temperatures. T2 spectra were also acquired after centrifuging and heating the samples. Our results indicate that most of the transverse relaxation occurs below 3 ms in saturated samples and that a conventional centrifuge cannot remove water from the smaller pores, making the commonly accepted clay bound water cutoff unsuitable for shales. Furthermore, the results from NMR experiments performed on the oven-dried shale samples suggest that the water content remains relatively constant after heating them above 65°C. The calculated T2 cutoff for clay bound water is between 0.22 and 0.26 ms for the samples studied. The methodology presented in this paper can be replicated in other formations to find a suitable T2 value for clay bound water, which can be a good indication of potentially producible porosity and can also be used for permeability estimation.

Low-field Nuclear Magnetic Resonance (NMR) is a non-invasive method widely used in the petroleum industry for the evaluation of reservoirs. Pore structure and fluid properties can be evaluated from transverse relaxation (T 2) distributions, obtained by inverting the raw NMR signal measured at subsurface conditions or in the laboratory. This paper aims to cast some light into the best practices for the T 2 data acquisition and inversion in shales, with a focus on the suitability of different inversion methods. For this purpose, the sensitivity to various signal acquisition parameters was evaluated from T 2 experiments using a real shale core plug. Then, four of the most common inversion methods were tested on synthetic T 2 decays, simulating components often associated with shales, and their performance was evaluated. These inversion algorithms were finally applied to real T 2 data from laboratory NMR measurements in brine-saturated shale samples. Methods using a unique regularization parameter were found to produce solutions with a good balance between the level of misfit and bias, but could not resolve adjacent fast T 2 components. In contrast, methods applying variable regularization-based on the noise level of the data-returned T 2 distributions with better accuracy at short times, in exchange of larger bias in the overall solution. When it comes to reproducing individual T 2 components characteristic of shales, the Butler-Reeds-Dawson (BRD) algorithm was found to have the best performance. In addition, our findings suggest that threshold T 2 cutoffs may be derived analytically, upon visual inspection of the T 2 distributions obtained by two different NMR inversion methods.

CO 2 injection into limestone reservoirs is a typical process in enhanced oil recovery operations, and it is also suggested for carbon geo-storage. However, CO 2 , together with water, is acidic and creates medium strength acid (pH value 3-4) at HP/HT (High Pressure/High Temperature) conditions. At the same time, it is well known that carbonates react and dissolve when exposed to acid. It can, therefore, be expected that the limestone properties change significantly during CO 2 injection.We thus hypothesized that limestone dissolution results in a substantial reduction of mechanical strength of the rock, with potential subsequent (mechanical) collapse of the rock -which would represent a major geohazard and could lead to land subsidence. We therefore conducted HP/HT core flooding tests on Savonnières limestone plugs; the plugs were thoroughly characterised with various experimental techniques (NMR-T2 response, porosity, dynamic permeability, acoustic response, x-ray computed tomography and rock-mechanical tests) before and after acid injection, i.e. exposure to supercritical CO 2 .We indeed measured a significant dissolution of the rock and associated substantial mechanical weakening of the rock. Differently shaped wormholes formed, which strongly influenced the mechanical behaviour. Furthermore, a significant permeability increase was observed (up to 42.3% increase after injection), consistent with wormhole formation. We conclude that CO 2 injection may pose a geohazard if the geo-mechanical strength of the reservoir is compromised.

Over recent decades, the low-field Nuclear Magnetic Resonance (NMR) method has been consistently used in the petroleum industry for the petrophysical characterisation of conventional reservoirs. Through this non-invasive technique, the porosity, pore size distribution and fluid properties can be determined from the signal emitted by fluids present in the porous media. Transverse relaxation (T2) data, in particular, are one of the most valuable sources of information in an NMR measurement, as the resulting signal decay can be inverted to obtain the T2 distribution of the rock, which can in turn be correlated with porosity and pore size distribution. The complex pore network of shales, which can have a large portion of pore sizes in the nanopore and mesopore range, restricts the techniques that can be used to investigate their pore structure and porosity. The ability of the NMR technique to detect signals from a wide range of pores has therefore prompted the quest for more standardised interpretation methods suitable for shales. Using low-field NMR, T2 experiments were performed on shale samples from the Carynginia formation, Perth Basin, at different saturation levels. The shale samples were initially saturated with brine and the T2 spectrum for each sample was obtained. Then, they were placed in a vacuum oven and their weight monitored until a constant value was reached. T2 curves were subsequently obtained for each of the oven-dried samples and a cut-off value for clay-bound water was calculated.

Emulsified acid has attracted considerable attention of the oil and gas industry due to its delayed nature that allows deeper penetration of acid into the formation which essentially facilitate further enhancing the well productivity, and at the same time minimizes the corrosion issues. However, emulsified acid has only been extensively studied and applied on carbonate formations. Considering more than half of the reservoirs worldwide are sandstone reservoirs, studying the effects of emulsified acid on sandstone under high-temperature conditions would unlock the potential of emulsified acid and help generate more value for the oil and gas industry by improving the well productivity from sandstone reservoirs. To ensure the applicability of the emulsified acid on the real sandstone reservoir, which usually has a temperature higher than ambient conditions, the stability of emulsified acids is investigated under 300 °F. Then, the stable emulsified acid samples are developed and their impact on the properties of Berea sandstone core samples, including porosity, pore-size distribution, permeability and wettability, are investigated. The core samples have undergone pre-flush (10% HCl:5% CH 3 COOH) before the main flush (emulsified acid). The emulsified acids are prepared using hydrofluoric acid, hydrochloric acid, phosphoric acid, cationic surfactant and chelating agent. Fourteen core samples are saturated with different emulsified acids under vacuum conditions for 3 days to ensure maximum saturation. The porosity, permeability and wettability of each core sample are measured before and after the reaction with acid. Nuclear magnetic resonance analysis has been applied to evaluate the change in pore size distribution. This study has demonstrated that the emulsified acids are capable of improving the porosity and permeability of Berea sandstone core sample. The pore size distribution has also been affected by the application of emulsified acid, where more large pores have been evolved to the core samples due to the reaction of acids with the sandstone which ultimately helps in improving the productivity of hydrocarbons. This indicates less precipitation of the secondary reaction products resulting better enhancement in sandstone flow properties. These results demonstrate the potential of emulsified acid during sandstone acidizing as emulsified acid significantly improved the sandstone properties which can essentially enhance the well productivity.