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Enhanced oil recovery methods are of high importance in extracting bypassed oil from reservoirs and increasing total production. In this abstract, we investigate the effect of CO2 injection into the fracture to recover matrix's bypassed oil. specifically, thermal Marangoni phenomenon is studied and distinguished due to the effects on recovery of bypassed oil when miscibility is difficult or cannot be established. Results show that not only the Marangoni flux does exist and has significant impact on the recovery of bypassed oil but also, its magnitude is proportional to the absolute value of temperature gradient in phases interface. furthermore, This effect is significant because this would affect in opposite direction and result in increasing or decreasing the recovery factor.

Summary High cost of CO2 purification from the flue gas is an essential barrier to CO2 sequestration projects, especially for conventional power plants. However, N2 is the most dominant impurity in the flue gas of power plants, but there is no experimental work to examine the effect of N2 impurity on the dissolution behavior of CO2 in brine. Since N2 impurity reduces the solubility of CO2 in brine, therefore the available theoretical works concluded the later onset of convection for CO2- N2 mixture in comparison of pure CO2. For the first time, a high pressure Hele- Shaw cell is designed and constructed in this study to examine the dissolution of CO2- N2 mixture through the qualitative (image) and quantitative (pressure decay) measurements which helps to obtain the whole understanding from process progressing. With analyzing the experimental data, effective diffusion coefficient of CO2 is introduced as a missing concept in previous theoretical studies. In the examined condition, it has been shown that 90%CO2-10%N2 mixture represents earlier onset of convection with higher critical wave number than pure CO2 experiments. It is an interesting finding which can help to tackle the possible barriers about impure CO2 sequestration and reduce the cost of projects.

This study experimentally investigated the effects of dispersion coefficient and frequency of dead-end pores on bypassed oil recovery during CO2 injection in fractures at different miscibility regimes (first-contact miscibility, near-miscibility, and immiscibility); a special setup was designed and a series of CO2 injection experiments were performed using two different types of rocks. In the light of dimensionless analysis and tracer experiments the rule of different forces (viscous, gravity, and capillary), mechanisms (vaporization and swelling) and matrix properties (the effect of dispersion coefficient and frequency of dead-end pores) were studied. In all miscibility regimes, the oil recovery factor decreased as rock complexity (dispersion coefficient) and the frequency of dead-end pores increased or permeability decreased; thus, types of heterogeneity and pore space structure play significant roles in oil recovery and cause some oil to be left untouched by gas injection in remote dead-end pores. In rock types with a high frequency of dead-end pores, like carbonates, conventional oil-producing mechanisms are no longer effective; the role of the near-critical-point-wetting mechanism is thus more significant. As a result, the recovery factor values of the near-critical and the super-critical tests diverge from each other.

Summary In the context of the CO2 sequestration in saline aquifers, purification is costly, then it is required to study the co-injection of impurities to examine its possibility to reduce the project costs. Besides this, some impurities such as SO2 has a hazardous effect on environment. In this process, the dissolution rate of the injected gas into brine is an important factor. After the last two decades, there is an extensive body of published research on the pure CO2. Resulted solution of brine+ dissolved gas for some of these impurities is lighter than brine+ CO2 (like N2), while others produce denser solution (like SO2). To study the dissolution process in the presence of impurities, two samples of these impurities should be considered. Saline aquifers have their own flow (background flow) which can affect the dissolution process. In this study, effect of background flow on the pure CO2 and impure gas stream (97.5% CO2 + 2.5%SO2 and 90% CO2 +10%N2) have been examined. For simplicity in the most studies, effect of heterogeneity wasn’t considered. To verify the results in the more realistic cases than homogeneous systems, simulations were repeated for heterogeneous cases.

Tertiary miscible gas injection is widely used after waterflooding in order to recover the remaining oil in the reservoir. In water-wet media, the thin water film present on the surface of the reservoir rock coalesces into a water layer in some narrower throats, impeding direct contact between the oil behind and the injected gas on the other side. However, the injected gas manages to reach the oil ganglion through dissolving in water and diffusing into oil, causing it to swell gradually and break the water barrier if given enough time. This phenomenon is generally referred to as “water shielding”. Several models have been previously proposed to estimate the required time for water-shielded oil to break the water barrier, all of which suffer from either requiring measurement of experimental parameters such as partition coefficient or neglecting the gas volume change due to non-ideal mixing. In this study, a new model has been developed which takes into account the partial molar volumes of oil and gas components, and also depends solely on temperature, pressure and fluid compositions as input parameters. The model has been used to investigate the effect of volume change caused by non-ideal mixing on the recovery time of water-shielded oil.

According to the Intergovernmental Panel on Climate Change (IPCC), global CO2 emissions must be reduced by 50 to 80 percent by 2050 to avoid dramatic consequences of global warming. Geological storage of CO2 in saline aquifers is a promising method for reducing atmospheric CO2 concentration. For this aim, accurate modeling of CO2 sequestration into underground formations (saline aquifers) is required. In petroleum industry, normally this is achieved by using compositional reservoir simulators which is computationally expensive and time consuming. To overcome this, an accurate fluid model was coupled to a flow simulator to model CO2 sequestration in saline aquifers. Next, sensitivity analyses of thermodynamic properties (pressure, temperature and salinity) were done on some saline aquifers of Alberta basin, in Canada to investigate the effects of thermodynamics properties on CO2 dissolution in these aquifers. Results show that salinity has the strongest effect on CO2 dissolution in our studied aquifers compared to temperature and pressure effects. Results of this study enable us to assess the potential of each saline aquifer for CO2 storage and therefore help us in selecting suitable injection sites for CO2 sequestration.

Experimental design and Response Surface Methodology (RSM), together with Monte Carlo simulation provide an efficient statistical framework to investigate the influence of multiple parameters and their interactions on a response of interest with limited number of simulations, and estimate the range of the response accurately. In the present study, the simulation model for a laboratory experiment of miscible CO2 injection into a matrix-fracture system is used to investigate the effect of different parameters on oil recovery. First, parameters with the most influence on oil recovery are determined by sensitivity analysis. Then in order to quantify the significance of each parameter, the model is employed to produce a response surface via Box-Behnken design, and the recovery factor is approximated as a second-order function of five reservoir and fluid parameters. Finally, the probable range of recovery factor is estimated by Monte Carlo simulation. The results show that the most effective parameters are matrix permeability, core diameter and diffusion coefficients with positive, and fracture permeability with negative contribution to oil recovery. In addition, the most-likely value (P50) calculated for oil recovery from matrix block is 71.6%. Recovery factor drops from 86.3% for the optimistic value (P10) to 55% for the pessimistic one (P90).