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Porosity is a fundamental petrophysical parameter in shale gas reservoirs that governs the space for hydrocarbon storage, and directly determines the free gas amount and absorbed gas capability. Technically, in kerogen-bearing shales, well-log derived porosity may yield inaccurate results as the porosity tools in response to both the kerogen and the liquid-filled pore spaces that are often undifferentiated. In this paper, we propose a new method for porosity estimation in kerogen-bearing shales, where porosity is assumed to be composed of both matrix porosity and kerogen porosity. The kerogen responses of density, sonic and neutron logs are first calculated from experimental data to calibrate porosity logs with the kerogen volume. The matrix porosity is then computed using the improved Wyllie equation based on the calibrated logging data with the kerogen influence removed. The kerogen porosity is estimated by a mass-balance relation based on the original total organic carbon (TOCo) and kerogen maturity characterized by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Application of the new method to a shale gas reservoir in the Ordos Basin, China shows that the estimated porosity matches the core derived porosity satisfactorily well. Furthermore, the results also indicate that the shale kerogen porosity is relatively higher than the shale matrix porosity when the kerogen amount and maturity are high. The results of the study lead to a better understanding of the shale formation and thus contribute towards the better evaluation of shale gas reservoirs.

The authors regret that the Fig. 3 was uploaded wrong by mistake. Refers to: Hongyan Yu, Zhenliang Wang, Reza Rezaee, Yihuai Zhang, Tongcheng Han, Muhammad Arif, Lukman Johnson. Porosity estimation in kerogen-bearing shale gas reservoirs. Journal of Natural Gas Science and Engineering, Volume 52, April 2018, Pages 575-581.

Carbon capture and sequestration technology is a major approach developed to mitigate the amount of greenhouse gases released into the atmosphere. Technically, depleted oil and gas reservoirs are one of the feasible subsurface geologic media for large-scale carbon dioxide (CO2) storages. Trapping mechanisms during and after CO2 injection in geologic formations ensure the long-term safety and security of a storage task. However, depending on characteristics of geologic sites and subsurface conditions, different trapping mechanisms may come to play during sequestration, among which residual trapping is by far the most efficient one in a short-term scale. Although there have been many experimental and numerical studies carried out in the past years to evaluate this trapping potential prior to injection, there is not any field-scale approaches developed to assess CO2 residual trapping at the depletion stage of oil and gas reservoirs. The aim of this paper is to present a method for residual trapping assessment of CO2 storage sites by considering related and effective constraints such as residual hydrocarbon saturation, interfacial tension, pore geometry, and wettability. An analytical method based on a adjustment factor was proposed which could be used to determine the residual CO2 saturation/residual trapping for different rock types having different wetting characteristics. Two wells out of a total number of 20 wells (mostly depleted) from the largest gas field in Malaysia were considered as part of this study to show how the proposed method can be executed in the field scale for determination of the residual trapping ability of the reservoir. The results obtained indicated that the average residual CO2 saturation by the proposed method is around 26% and 27% for Well A and Well B, respectively. Thus, the maximum volume of CO2 residual trapped could be approximately 0.96 Tscf or 0.97 Tscf of the effective pore volume (excluding 30% Sgr), based on the average saturation

A systematic and careful analysis of changes in the magnitude of geomechanical parameters is essential to mitigate the risk of leakage from CO2 storage sites. However, depending on rocks and storage sites, these changes might be different due to chemical reactions taking place, especially when it comes to saline aquifers. There have only been few studies carried out in the past to evaluate the maximum sustained pressure of rocks being exposed to these chemical interactions. However, more studies are still required to evaluate the strength of the storage medium or seals when different kinds of rocks and fluids (fresh water or brine) are included in the hostile environment of a storage site. In this paper, attempts were made to evaluate changes in the variation of geomechanical parameters of the Berea sandstone during and after the injection of supercritical CO2 in a short period of time. The results obtained indicated that the presence of brine in the pore space during injection enhances the severity of geochemical reactions, causing reductions in the magnitudes of elastic parameters including shear modulus. Having a good look into the SEM images of the sample before and after exposure to scCO2 indicated that these changes can be attributed to the dissolution/fracturing of calcite and clays in the matrix of the sample. Although findings were provided based on the pulse measurements tests, more studies are required to have a deeper understanding as to how geochemical reactions may cause difficulties during and after injection into a storage site.

The formation damages, such as water blocking and clay swelling, in tight gas reservoir have been recognized as severe problems impairing gas production. To remedy these damages, formation heat treatment (FHT) was taken as one of the effective measures by some researchers. In this paper, the effects of microwave heating on the petrophysical properties of sandstone samples has been investigated. A modified commercial microwave oven was used to heat the core plugs and aluminum tubes were used to accommodate tight sandstone samples in order to confine them and reduce their contact with air. After microwave heating, any alterations in the porosity, permeability, texture, structure, mineralogy, and pore size distribution of tight sandstones were investigated by a series of lab experiments. By subjecting tight sandstone samples to microwave, the surface temperature of sandstone can be elevated to approximately 400 °C or more. The intense heat is effective in changing the structure, texture and mineralogy of the sandstone. The shrinkage or decomposition of minerals, which are shown by XRD analysis, and generation of micro-fractures created more spaces in the samples.By employing Automated Permeameter, porosity and permeability are found increased after heating. Nuclear Magnetic Resonance (NMR) and CT numbers of all samples after microwave heating indicate the increase of porosity as well. Moreover, the NMR T2 distribution reveals the smaller pores diminished, so the incremental porosity of short NMR T2 decreased. Micro-fractures generated between grains or in grains due to decomposition of some cement minerals and clay shrinkage, so the amplitude of long NMR T2 increased. The fractures are visible both in X-ray CT images and in Scanning Electronic Microscopy (SEM) images. By comparing with NMR T2 distribution data, it is found that the presence of micro-fractures accounts for the increased population of pores with T2 larger than 10 ms. The numerical simulation of microwave