“Nanofluids”, a colloidal mixture consisting of nano-sized particles dispersed in a fluid medium with amended thermo-physical properties play a critical role in the heat transfer performance of a thermal system. Surface tension is the surface energy per unit area or the force per unit length dominates the transportation of the liquid and shows a significant role in heat transfer. However, a few numbers of studies demonstrated about the effect of surface tension of nanofluids. Thus, the present experimental study investigates the effect of nanoparticles concentration as well as the influence of variation of nanoparticles along with their sizes. The nanofluids are prepared by dispersing Al2O3(13nm and 50nm),TiO2 (21nm) and SiO2 (5∼15nm and 10∼20nm) nanoparticles in Distilled Water (DW).The traditional Du-Noüy ring method was used to measure the value of the surface tension of nanofluids by an automatic surface tensiometer (DCAT 11EC). The results show that the surface tension of the nanofluids increases with increase in concentration and nanoparticle sizes. Besides,TiO2-DW nanofluids exhibit higher surface tension than Al2O3-DW and SiO2-DW nanofluids respectively. All in all, the results indicate surface tension of the nanofluids enhances from 2.62% to 4.82% in comparison with the base fluids for concentration variation of 0.05 Vol % to 0.25 Vol % at 25°C

In carbon storage activities, and in shale oil and gas extraction (SOGE) with carbon dioxide (CO₂) as stimulation fluid, CO₂ comes into contact with shale rock and its pore fluid. As a reactive fluid, the injected CO₂ displays a large potential to modify the shale’s chemical, physical, and mechanical properties, which need to be well studied and documented. The state of the art on shale–CO₂ interactions published in several review articles does not exhaust all aspects of these interactions, such as changes in the mechanical, petrophysical, or petrochemical properties of shales. This review paper presents a characterization of shale rocks and reviews their possible interaction mechanisms with different phases of CO₂. The effects of these interactions on petrophysical, chemical and mechanical properties are highlighted. In addition, a novel experimental approach is presented, developed and used by our team to investigate mechanical properties by exposing shale to different saturation fluids under controlled temperatures and pressures, without modifying the test exposure conditions prior to mechanical and acoustic measurements. This paper also underlines the major knowledge gaps that need to be filled in order to improve the safety and efficiency of SOGE and CO₂ storage.

Gassmann's fluid substitution theory is commonly used to predict seismic velocity change upon change in saturation, and is hence essential for 4-D seismic and AVO studies. This paper addresses the basics assumptions of the Gassmann theory, in order to see how well they are fulfilled in controlled laboratory experiments. Our focus is to investigate the sensitivity of shear modulus to fluid saturation, and the predictability of Gassmann's fluid substitution theory for P-wave modulus. Ultrasonic P- and S-wave velocities in dry and saturated (3.5 wt per cent NaCl) unconsolidated clean sands (Ottawa and Columbia) were measured in an oedometer test system (uniaxial strain conditions) over a range of 0.5–10 MPa external vertical stress. This study shows shear modulus hardening upon brine saturation, which is consistent with previous data found in the literature. Analysis of the data shows that most of the hardening of the ultrasonic shear modulus may be explained by Biot dispersion. Isotropic Gassmann's fluid substitution is found to underestimate the P-wave modulus upon fluid saturation. However, adding the Biot dispersion effect improves the prediction. More work is required to obtain good measurements of parameters influencing dispersion, such as tortuosity, which is very ambiguous and challenging to measure accurately.

Carbon capture and storage (CCS) by geological sequestration comprises a permeable formation (reservoir) for CO₂ storage topped by an impermeable formation (caprock). Time-lapse (4D) seismic is used to map CO₂ movement in the subsurface: CO₂ migration into the caprock might change its properties and thus impact its integrity. Simultaneous forced-oscillation and pulse-transmission measurements are combined to quantify Young’s modulus and Poisson’s ratio as well as P- and S-wave velocity changes in the absence and in the presence of CO₂ at constant seismic and ultrasonic frequencies. This combination is the laboratory proxy to 4D seismic because rock properties are monitored over time. It also improves the understanding of frequency-dependent (dispersive) properties needed for comparing in-situ and laboratory measurements. To verify our method, Draupne Shale is monitored during three consecutive fluid exposure phases. This shale appears to be resilient to CO₂ exposure as its integrity is neither compromised by notable Young’s modulus and Poisson’s ratio nor P- and S-wave velocity changes. No significant changes in Young’s modulus and Poisson’s ratio seismic dispersion are observed. This absence of notable changes in rock properties is attributed to Draupne being a calcite-poor shale resilient to acidic CO₂-bearing brine that may be a suitable candidate for CCS.

Reservoir formation waters typically contain scaling ions which can precipitate and form mineral deposits. Such mineral deposition can be accelerated electrochemically, whereby the application of potential between two electrodes results in oxygen reduction and water electrolysis. Both processes change the local pH near the electrodes and affect the surface deposition of pH-sensitive minerals. In the context of the plugging and abandonment of wells, electrochemically enhanced deposition could offer a cost-effective alternative to the established methods that rely on setting cement plugs. In this paper, we tested the scale electro-deposition ability of six different formation waters from selected reservoirs along the Norwegian continental shelf using two experimental setups, one containing CO₂ and one without CO₂. As the electrochemical deposition of scaling minerals relies on local pH changes near the cathode, geochemical modelling was performed to predict oversaturation with respect to the different mineral phases at different pH values. In a CO₂-free environment, the formation waters are mainly oversaturated with portlandite at pH > 12. When CO₂ was introduced to the system, the formation waters were oversaturated with calcite. The presence of mineral phases was confirmed by powder X-ray diffraction (XRD) analyses of the mineral deposits obtained in the laboratory experiments. The geochemical-modelling results indicate several oversaturated Mg-bearing minerals (e.g., brucite, dolomite, aragonite) in the formation waters but these, according to XRD results, were absent in the deposits, which is likely due to the significant domination of calcium-scaling ions in the solution. The amount of deposit was found to be proportional to the concentration of calcium present in the formation waters. Formation waters with a high concentration of Ca ions and a high conductivity yielded more precipitate.

Utilization of natural shale formations for the creation of annular barriers in oil and gas wells is currently discussed as a mean of simplifying cumbersome plugging and abandonment procedures. Shales that are likely to form annular barriers are shales with high content of swelling clays and relatively low content of cementation material (e.g., quartz, carbonates). Shales with large content of quartz and low content of swelling clays will be rather brittle and not easily deformable. In this paper we ask the question whether and to what extent it is possible to modify the mechanical properties of relatively brittle shales by chemically removing some cementation material. To answer this question, we have leached out carbonates from Pierre I shale matrix using hydrochloric acid and we have compared mechanical properties of shale before and after leaching. We have also followed leaching dynamics using X-ray tomography. The results show that removal of around 4–5 wt% of cementation material results in 43% reduction in Pierre I shale shear strength compared to the non-etched shale exposed to sodium chloride solution for the same time. The etching rate was shown to be strongly affected by the volume of fluid staying in direct contact with the shale sample.