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Hypothesis The change of wettability toward more water-wet by the injection of low salinity water can improve oil recovery from porous rocks, which is known as low salinity water flooding. To simulate this process at the pore-scale, we propose that the alteration in surface wettability mediated by thin water films which are below the resolution of simulation grid blocks has to be considered, as observed in experiments. This is modeled by a wettability alteration model based on rate-limited adsorption of ions onto the rock surface. Simulations The wettability alteration model is developed and incorporated into a lattice Boltzmann simulator which solves both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport. The model is validated against two experiments in the literature, then applied to 3D micro-CT images of a rock. Findings Our model correctly simulated the experimental observations caused by the slow wettability alteration driven by the development of water films. In the simulations on the 3D rock pore structure, a distinct difference in the mixing of high and low salinity water is observed between secondary and tertiary low salinity flooding, resulting in different oil recoveries.

Hypothesis: The wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium. Experiments: We investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using zeta-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock. Findings: The results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%. (C) 2019 The Authors. Published by Elsevier Inc.

The performance of latent thermal energy storage (LTES) heat exchangers is related to the stored energy (i.e. state of charge) during the (dis)charging of the energy storage system. Therefore, measuring the stored energy is crucial to understand the behavior of LTES systems. However, technical considerations often oppose the measurability of the stored energy. The present article presents a case where only measurements at the in- and outlet of the heat transfer fluid and on the outer surface of the heat exchanger were possible. Based on this sparse set of measurements, estimators for the stored energy are developed. To test these estimators, a finite volume model of the LTES heat exchanger is made. The finite volume model is fitted by comparing the predicted heat transfer fluid outlet temperature for 36 experiments. The energy estimators are compared to simulation results. The estimators for the stored energy in the heat transfer fluid, metal and phase change material obtain an average deviation of respectively 0.5 %, 3.9 % and 0.6 % with the stored energy predicted by the finite volume model. The estimator for the stored energy in the heat transfer fluid should be applicable to all LTES heat exchangers while the applicability of the estimators for stored energy in the metal and phase change material depend on small temperature differences between surface and interior of the metal and negligible heat losses.

We study the impact of brine acidity and initial pore structure on the dynamics of fluid/solid reaction at high Peclet numbers and low Damkohler numbers. A laboratory μ -CT scanner was used to image the dissolution of Ketton, Estaillades, and Portland limestones in the presence of CO 2 -acidified brine at reservoir conditions (10 MPa and 50 °C) at two injected acid strengths for a period of 4 h. Each sample was scanned between 6 and 10 times at ∼4 μm resolution and multiple effluent samples were extracted. The images were used as inputs into flow simulations, and analysed for dynamic changes in porosity, permeability, and reaction rate. Additionally, the effluent samples were used to verify the image-measured porosity changes. We find that initial brine acidity and pore structure determine the type of dissolution. Dissolution is either uniform where the porosity increases evenly both spatially and temporally, or occurs as channelling where the porosity increase is concentrated in preferential flow paths. Ketton, which has a relatively homogeneous pore structure, dissolved uniformly at pH = 3.6 but showed more channelized flow at pH = 3.1. In Estaillades and Portland, increasingly complex carbonates, channelized flow was observed at both acidities with the channel forming faster at lower pH. It was found that the effluent pH, which is higher than that injected, is a reasonably good indicator of effective reaction rate during uniform dissolution, but a poor indicator during channelling. The overall effective reaction rate was up to 18 times lower than the batch reaction rate measured on a flat surface at the effluent pH, with the lowest reaction rates in the samples with the most channelized flow, confirming that transport limitations are the dominant mechanism in determining reaction dynamics at the fluid/solid boundary.

We investigate the impact of initial pore structure and velocity field heterogeneity on the dynamics of fluid/solid reaction at high Peclet numbers (fast flow) and low Damkohler number (relatively slow reaction rates). The Diamond Lightsource Pink Beam was used to image dissolution of Estaillades and Portland limestones in the presence of CO 2 -saturated brine at reservoir conditions (10 MPa and 50 °C representing ~ 1 km aquifer depth) at two flow rates for a period of 2 h. Each sample was scanned between 51 and 94 times at 4.76-μm resolution and the dynamic changes in porosity, permeability, and reaction rate were examined using image analysis and flow modelling. We find that the porosity can either increase uniformly through time along the length of the samples, or may exhibit a spatially and temporally varying increase that is attributed to channel formation, a process that is distinct from wormholing, depending on initial pore structure and flow conditions. The dissolution regime was structure-dependent: Estaillades with a higher porosity showed more uniform dissolution, while the lower porosity Portland experienced channel formation. The effective reaction rates were up to two orders of magnitude lower than those measured on a flat substrate with no transport limitations, indicating that the transport of reactant and product is severely hampered away from fast flow channels.

During CO2 storage in depleted oil fields, under immiscible conditions, CO2 can be trapped in the pore space by capillary forces, providing safe storage over geological times - a phenomenon named capillary trapping. Synchrotron X-ray imaging was used to obtain dynamic three-dimensional images of the flow of the three phases involved in this process - brine, oil and gas (nitrogen) - at high pressure and temperature, inside the pore space of Ketton limestone. First, using continuous imaging of the porous medium during gas injection, performed after waterflooding, we observed chains of multiple displacements between the three phases, caused by the connectivity of the pore space. Then, brine was re-injected and double capillary trapping - gas trapping by oil and oil trapping by brine - was the dominant double displacement event. We computed pore occupancy, saturations, interfacial area, mean curvature and Euler characteristic to elucidate these double capillary trapping phenomena, which lead to a high residual gas saturation. Pore occupancy and saturation results show an enhancement of gas trapping in the presence of both oil and brine, which potentially makes CO2 storage in depleted oil reservoirs attractive, combining safe storage with enhanced oil recovery through immiscible gas injection. Mean curvature measurements were used to assess the capillary pressures between fluid pairs during double displacements and these confirmed the stability of the spreading oil layers observed, which facilitated double capillary trapping. Interfacial area and Euler characteristic increased, indicating lower oil and gas connectivity, due to the capillary trapping events.

Geological carbon dioxide storage must be designed such that the CO 2 cannot escape from the rock formation into which it is injected, and often simple stratigraphic trapping is insufficient. CO 2 can be trapped in the pore space as droplets surrounded by water through capillary trapping. X-ray microtomography was used to image, at a resolution of 6.6 μm, the pore-scale arrangement of these droplets in three carbonates and two sandstones. The pressures and temperatures in the pore space were representative of typical storage formations, while chemical equilibrium was maintained between the CO 2 , brine and rock phases to replicate conditions far away from the injection site. In each sample substantial amounts of CO 2 were trapped, with the efficiency of trapping being insensitive to pore-morphology and chemistry. Apart from in one extremely well connected sample, the size distribution of residual ganglia larger than 10 5 voxel 3 obey power law distributions with exponents broadly consistent with percolation theory over two orders of magnitude. This work shows that residual trapping can be used to locally immobilise CO 2 in a wide range of rock types.

Two carbonate rocks were studied experimentally at reservoir conditions at two flow rates using dynamic X-ray tomography. Cores of both homogeneous (Ketton) and heterogeneous (Portland) carbonates, were injected with CO 2 -saturated at 10 MPa and 50oC. Images were taken at between 30-second and 40- minute time-resolutions during injection. Reaction-induced changes in porosity, permeability, and structure were obtained by segmenting the images and extracting a pore/throat network. Differences in dissolution type and magnitude were found for each rock and flow rate. At the highest flow rates, Ketton displayed uniform dissolution. Conversely, Portland formed wormholes at high and compact dissolution at low flow rates.

Pore-scale imaging and modelling – digital core analysis – is becoming a routine service in the oil and gas industry, and has potential applications in contaminant transport and carbon dioxide storage. This paper briefly describes the underlying technology, namely imaging of the pore space of rocks from the nanometre scale upwards, coupled with a suite of different numerical techniques for simulating single and multiphase flow and transport through these images. Three example applications are then described, illustrating the range of scientific problems that can be tackled: dispersion in different rock samples that predicts the anomalous transport behaviour characteristic of highly heterogeneous carbonates; imaging of super-critical carbon dioxide in sandstone to demonstrate the possibility of capillary trapping in geological carbon storage; and the computation of relative permeability for mixed-wet carbonates and implications for oilfield waterflood recovery. The paper concludes by discussing limitations and challenges, including finding representative samples, imaging and simulating flow and transport in pore spaces over many orders of magnitude in size, the determination of wettability, and upscaling to the field scale. We conclude that pore-scale modelling is likely to become more widely applied in the oil industry including assessment of unconventional oil and gas resources. It has the potential to transform our understanding of multiphase flow processes, facilitating more efficient oil and gas recovery, effective contaminant removal and safe carbon dioxide storage.

Co-injection of water with CO2 is an effective scheme to control the initial gas saturation in porous media. The fractional flow rate of water about 5 to 10% is enough to reduce the initial gas saturations, and after water injection, most of gas injected in porous media is trapped by capillarity with low fractional volume of migrating gas. In this paper, first we derive an analytical model to predict the gas saturations for the co-injection with water. Next, the effect of the initial gas saturation, which is controlled by the fractional flow ratio in co-injection process, on the residual gas saturation at capillary trapping is investigated experimentally for the water and nitrogen system at room condition. Depending on the relative permeabilities, the initial gas saturation is reduced by the co-injection of water. In case of the Berea sandstone core, if the initial saturation is controlled to be in the range between 20% and 40%, most of the gas is trapped by capillarity and less than 20% of gas with respect to the injected gas volume is migrate by water injection. In case of the packed bed of Toyoura standard sand, the initial gas saturation is about 20% for a wide range of gas fractional flow rate from 0.50 to 0.95. The residual gas saturation for these conditions is about 15%. Approximately less than 25% of gas migrates by water injection. Based on the analytical model and the experimental results, advantages and disadvantages of co-injection systems are discussed.