Furqan Hussain

Permeability Upscaling for Carbonates from the Pore-Scale Using Multi-Scale Xray-CT Images

bility due to large permeability contrasts. The most accurate upscaling technique is employing Darcy’s law. A key part of the study is the establishment of porosity transforms between highresolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.

Computation of Relative Permeability from Imaged Fluid Distributions at the Pore Scale

Image-based computations of relative permeability for capillary-dominated quasi-static displacements require a realistic description of the distribution of the fluids in the pore space. The fluid distributions are usually computed directly on the imaged pore space or on simplified representations of the pore space extracted from the images using a wide variety of models which capture the physics of pore-scale displacements. Currently this is only possible for uniform strongly wetting conditions where fluid–fluid and rock–fluid interactions at the pore-scale can be modelled with a degree of certainty. Recent advances in imaging technologies which make it possible to visualize the actual fluid distributions in the pore space have the potential to overcome this limitation by allowing relative permeabilities to be computed directly from the imaged fluid distributions. The present study explores the feasibility of doing this by comparing laboratory measured capillary-dominated drainage relative permeabilities with relative permeabilities computed from micro-CT images of the actual fluid distributions in the same rock. The agreement between the measurements and the fluid image-based computations is encouraging. The paper highlights a number of experimental difficulties encountered in the study which should serve as a useful guide for the design of future studies.

Adsorption/desorption characteristics for methane, nitrogen and carbon dioxide of coal samples from Southeast Qinshui Basin, China

This paper presents an experimental and modelling study of the adsorption/desorption of pure gases CH4, CO2 and N2 and their binary and ternary mixtures on coal samples obtained from southeast Qinshui Basin, China. Results show that the adsorbed amounts of N2, CH4 and CO2 have approximate ratios of 1.0:1.3:2.4, respectively. No significant hysteresis from adsorption to desorption is observed for pure N2 and CH4 whereas significant hysteresis is measured for CO2 in CO2-CH4 and CO2-CH4-N2 mixtures and CH4 in the N2- CH4 mixture. The experimental observations are modelled using three different models, namely the extended Langmuir (EL), the Langmuir-based ideal adsorbed solution (L-IAS) and the Dubinlin-Radushkevich-based ideal adsorbed solution (D-R-IAS). The models predict well the experimental observations for desorption tests. But the measurements for the low adsorbate capacity in binary and ternary mixtures are overestimated by the prediction models. It is found that the EL model predicts the CO2-CH4 desorption test better while the D-R-IAS model is the best model for the CO2-CH4-N2 adsorption.

A Semi-Analytical Model for Two Phase Immiscible Flow in Porous Media Honouring Capillary Pressure

This article describes a semi-analytical model for two-phase immiscible flow in porous media. The model incorporates the effect of capillary pressure gradient on fluid displacement. It also includes a correction to the capillarity-free Buckley–Leverett saturation profile for the stabilized-zone around the displacement front and the end-effects near the core outlet. The model is valid for both drainage and imbibition oil–water displacements in porous media with different wettability conditions. A stepwise procedure is presented to derive relative permeabilities from coreflood displacements using the proposed semi-analytical model. The procedure can be utilized for both before and after breakthrough data and hence is capable to generate a continuous relative permeability curve unlike other analytical/semi-analytical approaches. The model predictions are compared with numerical simulations and laboratory experiments. The comparison shows that the model predictions for drainage process agree well with the numerical simulations for different capillary numbers, whereas there is mismatch between the relative permeability derived using the Johnson–Bossler–Naumann (JBN) method and the simulations. The coreflood experiments carried out on a Berea sandstone core suggest that the proposed model works better than the JBN method for a drainage process in strongly wet rocks. Both methods give similar results for imbibition processes.

Experimental study for reducing gas inflow by use of thin spray-on liners in underground coal mines

Abstract This paper presents an investigation of the potential use of thin spray-on liners (TSLs) in underground coal mines as a gas management tool. The coal samples used were taken from a coal mine in Australia. Three different TSLs were examined. The experiments include single phase gas flow tests through intact and treated dry coal samples. Experimental observations indicate that TSLs can reduce gas permeability of coal by up to three orders of magnitude. However, the degree of the impact depends strongly on the type of TSLs. Further, the initial permeability of coal and TSL thickness also affect the efficiency of the process. There is a linear relation between the efficiency of the TSLs in controlling gas flow and their adhesion strength to the coal sample.

Effect of Fractional Gas Injected on Gas Relative Permeability in Near-miscible SWAG Flood

Simultaneous water and gas (SWAG) injection is known as an efficient enhanced oil recovery method. Numerical simulations generally use the two-phase gas relative permeability (krg) to model three-phase SWAG processes where the same krg is used for different fractional gas injected (FGI) values. This approach does not account for the reduction in krg in presence of water. In this paper, we investigate the impact of FGI on krg for predicting SWAG flood performance through an experimental and simulation methodology. Core flooding experiments are performed at different FGI values on a sandstone sample. A mixture of hexane and decane is used as the oil phase and CO2 and water as injectants. Experiments are run at 70oC and 1700 psi which represents the near-miscible displacements for the given fluids. Oil recovery, differential pressure and compositions are recorded during experiments. Then history matching is conducted to estimate the FGI-dependent relative permeability function. Numerical simulations show that accurate modelling of SWAG displacement requires FGI dependent relative permeability. Considerable reduction in krg in SWAG, compared to conventional two-phase functions, improves the vertical sweep efficiency of CO2. The highest reduction is obtained in displacement with FGI=0.75.

How to Co-optimize Oil Recovery and CO2 Storage during CO2 EOR - A Laboratory Study

This paper presents experimental observations that delineate co-optimisation of CO2 EOR and CO2 storage. Supercritical CO2 was injected into a homogeneous Bentheimer sandstone sample under various miscibility conditions. A two-component hydrocarbon system (65% hexane and 35% decane) was used to represent the oil phase. Three experiments were run at the same temperature (70oC) but different pressures (1,300, 1,700 and 2,100 psi). These pressures were determined using a PCT simulator before the experiments in order to obtain immiscible, near miscible and miscible conditions. Oil recovery and CO2 saturation were recorded during experiments. A co-optimisation function is defined and was calculated using the measured data for each experiment. Experimental observations demonstrate that oil recovery during miscible and near miscible displacement is almost the same while it is 20% less in the immiscible displacement. We note that heavier hydrocarbons produced from miscible and near miscible displacements are much higher than the immiscible displacement. On the other hand, CO2 is stored in the rock sample more efficiently during the near miscible displacement. The co-optimisation function also suggests that the near miscible displacement offers the best performance for coupling CO2 EOR and storage.