Residual Saturation Research Articles

The potential for CO2 storage in residual oil zones in onshore Australian basins

Geoscience Australia and CSIRO have collaborated to investigate whether residual oil zones (ROZs), sometimes associated with conventional Australian hydrocarbon plays, could provide a carbon dioxide (CO2) storage resource and enhance the storage capacity of depleted fields. Our petrophysical study demonstrates that ROZs occur in Australia’s hydrocarbon-rich regions, particularly in the Cooper-Eromanga Basin. ROZs with more than 10% residual oil saturation are uncommon, likely due to small original oil columns and lower residual saturations retained in sandstone reservoirs than in classic, carbonate-hosted North American ROZs. Extensive, reservoir-quality rock is found below the deepest occurring conventional oil in many of the fields in the Eromanga Basin, potentially offering significant CO2 storage capacity. Multiphase compositional flow modelling was used to estimate the CO2 storage efficiency of typical Australian ROZs. We developed a novel modelling methodology that first captures oil migration events leading to the formation of ROZs. Modelling CO2 storage over a 20-year injection period demonstrates that CO2-oil interactions increase the density and viscosity of CO2, enhancing CO2 sweep efficiency and lateral flow, improving storage efficiency. The extent of these effects depends on the quantity and spatial distribution of residual oil in place and the miscibility of CO2 at reservoir conditions.

Modelling CO2 storage in oil and gas reservoirs in the Gippsland Basin

The Gippsland Basin has world class geology for carbon capture and storage (CCS) and a long history of oil and gas production. Depleted oil and gas fields within the Gippsland Basin that are candidates for carbon dioxide (CO2) storage are in close proximity to existing infrastructure that could be repurposed as part of a CCS project. Modelling of CO2 storage in the depleted Bream oil and gas reservoir is being progressed. Bream reservoir properties are very well understood due to extensive geological and geophysical data sets available from wells and seismic data. Additionally, the field has been through three key phases of development during its production history; oil production and gas re-injection in 1988, gas cap blowdown started in 2002, and seasonal gas storage and withdrawal started in 2012 through to field shut-in in 2020. This provides a wealth of dynamic data that is used to calibrate the reservoir models to improve our confidence in the CO2 plume prediction. However, there are also challenges in modelling CO2 storage in depleted fields. Unlike saline aquifers, CO2 can be injected into a three-phase depleted reservoir that contains residual oil and gas saturation. The key aspects of our workflow to evaluate the plume behaviour are presented in this paper.

Spatiotemporal X-Ray Imaging of Neat and Viscosified CO2 in Displacement of Brine-Saturated Porous Media

Summary CO2 storage in saline aquifers may contribute to a 90% share in preventing emissions to the atmosphere. Due to low CO2 viscosity at the subsurface often found in supercritical (sc) conditions, the injected CO2 may spread quickly at the formation top and increase the probability of leakage. This work relates to improved CO2 storage in saline aquifers by effective viscosification of the sc-CO2 at very low concentrations of engineered oligomers and the effectiveness of slug injection of viscosified CO2 (vis-CO2). We present the results from X-ray computed tomography (CT) imaging to advance the understanding of two-phase CO2-brine flow in porous media and firmly establish the transport mechanisms. X-ray CT imaging of displacement experiments is conducted to quantify the in-situ sc-CO2 saturation spatiotemporally. In neat CO2 injection, gravity override and adverse mobility ratio may result in early breakthrough and low sweep efficiency. We find cumulative brine production from the fraction collector to be lower than X-ray CT imaging at 2 pore volume (PV) injection. The difference between the two is attributed to the solubility of the produced water in the produced CO2 at atmospheric pressure. We show that when the solubility is accounted for, there is a good agreement between direct measurements and in-situ saturation results. There are three reports (two by the same group) that oligomers of 1-decene (O1D) with six repeat units may have marginal CO2 viscosification. The majority of published work by other groups shows that O1D with six repeat units and higher are effective CO2 viscosifiers. In the past, we have demonstrated the effectiveness of an O1D in the displacement of brine by CO2 at a concentration of 1.5 wt%. The effectiveness is examined and identified by three different methods. In this work, we show that the same oligomer is effective at a low concentration of 0.6 wt%. The oligomer slows the breakthrough by 1.6 times and improves the brine production by 34% in the horizontal orientation. X-ray CT imaging results reveal that such a large effect may be from the increase in the interfacial elasticity. We also show that there is no need for continuous injection of the oligomer. A slug of 0.3 PV injection (PVI) of vis-CO2 followed by neat CO2 injection has the same effectiveness as the continuous injection of the vis-CO2. In this work, we also demonstrate the effectiveness of a new engineered molecule at 0.3 wt% that may increase residual trapping by about 35%. The combination of mobility control and residual brine saturation reduction is expected to improve CO2 storage by effective viscosification with low concentrations of oligomers.

Maximizing the capacity and benefit of CO2 storage in depleted oil reservoirs

Sequestering CO2 in depleted oil reservoirs provides one of the most appealing measures to reduce greenhouse gases (GHG) concentration in the atmosphere. The remaining liquids after enhanced oil recovery (EOR) processes, including residual oil and remaining water, lead to the main challenges to this approach. How to effectively evacuate a depleted oil reservoir by recovering not only residual oil but also remaining water is a critical consideration for this type of CO2 sequestration. This paper presents conceptual investigations concerning the methods which effectively evacuate depleted oil reservoirs from both the displacement efficiency and the sweep efficiency points of view. To improve the displacement efficiency, surfactant slug and solvent slug injection was examined using a core scale numerical model. Investigations regarding improving sweep efficiency, such as horizontal well pattern infilling and foam injection, were carried out based on a typical row well pattern. Simulation results showed that surfactant slug which modified the relative permeability and capillary pressure remarkably reduced both residual oil saturation and remaining water saturation. A CO2 slug injected before surfactant slug can help improve the oil recovery. Solvent enriched CO2 slug also remarkably reduced the residual oil saturation to as low as 2%. Horizontal well pattern infilling had great advantage for thick or inclined reservoirs, and foam slug injection greatly improved CO2 storage capacity in thin reservoirs by improving the sweep efficiency. Maximum mobility reduction (MRF) is the most important parameter to maximize the storage capacity and the benefit. The variation of CO2 storage capacity along with CO2 slug size. Larger foam slug size will play a better storage performance. The conceptual simulation investigations confirmed that depleted oil reservoirs can be effectively evacuated for CO2 storage. Depleted oil reservoirs with maximum evacuation are the best candidates for CO2 sequestrations.

Mechanistic analysis of acid gas storage and oil recovery in naturally fractured reservoirs using single matrix block approach

AbstractThe objective of this study is to assess the storage of acid gas, containing CO2 and H2S, in a depleted naturally fractured reservoir (NFR) using single matrix block (SMB) approach. The acid gas dissolution in oil is considered by Peng‐Robinson equation of state and compositional simulation. The PHREEQC package is used to determine acid gas solubility in formation brine. Three types of acid gases with different compositions are used for this study and their swelling behavior and miscibility in relation to the reservoir oil are analyzed. An SMB model, with a matrix block surrounded by fractures, is constructed, and validated for simulation of a real experiment. The simulation is conducted for synthetic and real reservoir fluids when the oil is in its residual saturation. A sensitivity analysis is performed to study the effects of key parameters, such as acid gas composition, reservoir pressure, permeability, porosity and matrix height on the storage capacity and oil recovery factor. The matrix has a volume of 27 m3 and about half of acid gas storage is achieved in the first 5 years while the simulations are run for 30 years. The results show that up to 90% of remained oil is recoverable, and more than 0.67 kmol of acid gas per cubic meter of matrix is stored whether matrix contains a real oil or a synthetic one. Higher storage is achieved for higher matrix porosities and heights and large H2S proportion in acid gas. In all cases about 10% of acid gas is trapped in water and the remaining 90% is dissolved in oil. The mineral trapping was more active in CO2‐rich acid gases. While about 10 kg of the matrix rock was dissolved in the acidic brine when the acid gas contained H2S, the amount of the dissolved minerals in acidic brine resulted from the injection of CO2‐rich acid gas was more than 16 kg. Finally, this study gives a comparative analysis of the storage performance of acid gas mixture and pure CO2. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

DISPLACEMENT OF OIL BY MICELLAR SOLUTION WITH NANOPARTICLES FROM POROUS MODEL WITH CORE MATERIAL

Enhanced oil recovery (EOR) techniques play an important role in maintaining oil production worldwide. These methods are given special attention due to the constant decline in the availability of oil resources. One type of EOR is the tertiary method - a chemical method that involves the use of synthetic substances for mining. Liquid flooding in the presence of a surfactant is a common chemical EOR, and microemulsions belong to these systems. The injection of the microemulsion rim reduces the interfacial tension between the crude oil and the formation fluid, which results in the mobilization of a significant portion of the residual oil. Recently, the possibility of simultaneous use of nanoparticles and chemicals to increase the efficiency of the processes of increasing oil recovery has been considered. In this work, nanoparticles participate in the role of microemulsion stabilization, and their joint effect on the displacement capacity of oil from the bulk model of a porous medium is also analyzed. The work is aimed at studying the effect of adding silicon oxide nanoparticles to a microemulsion solution, which is an agent for displacing viscous oil from a bulk porous medium. In the experiment, laboratory studies of oil displacement by various compositions, including surfactants, salt, alcohol and nanoparticles, were carried out on two types of bulk models assembled from glass beads and quartz sand, phase saturations were determined at different points in time, and displacement capacity graphs were built. The oil displacement study was carried out for six liquids: water, mineralized water, nanofluid, aqueous solution with surfactant, also a solution for microemulsion without and with the addition of nanoparticles. It has been found that the effect of adding nanoparticles to the microemulsion composition in the case of bulk models consisting of glass beads leads to a slight increase in the volume of displaced oil. In the case of bulk models consisting of core material, an increase in residual oil saturation is observed, which is associated with adsorption of particles on the surface of core material.

Optimization of Discontinuous Polymer Flooding Processes for Offshore Oilfields Using a Novel PSO–ICA Algorithm

Recently, discontinuous polymer flooding has been proposed and successfully applied in some offshore oilfields. The performance of discontinuous polymer flooding depends on various operational parameters, such as injection timing, polymer concentrations, and crosslinker concentrations of four types of chemical slugs. Because the number of the operational parameters are large and they are nonlinearly related, the traditional reservoir numerical simulation might not simultaneously obtain the optimal results of these operational parameters. In this study, to simulate the discontinuous polymer flooding processes, a simulation model was built using a commercial reservoir simulator (CMG STARS), in which the mechanisms of the four types of chemical slugs were considered, such as polymer viscosification, adsorption, and degradation. Then, a PSO–ICA algorithm was developed by using the PSO algorithm to improve the exploration ability of the ICA algorithm. The codes were written with MATLAB and linked to CMG STARS to perform optimization processes. Finally, the PSO–ICA algorithm was compared with the ICA and PSO algorithms on benchmark functions to verify its reliability and applied to optimize a discontinuous polymer flooding process in a typical offshore oilfield in Bohai Bay, China. The results showed that the developed PSO–ICA algorithm had lower iteration numbers, higher optimization accuracy, and faster convergence rate than these of PSO and ICA, indicating that it was an effective method for optimizing the operational parameters of discontinuous polymer flooding processes. Compared to the continuous polymer flooding, the discontinuous polymer flooding had a higher oil production rate, a lower water cut, and a lower residual oil saturation. The net present value of the optimal scheme of discontinuous polymer flooding reached 7.49 × 108 $, which is an increase of 6% over that of the scheme of continuous polymer flooding. More research including selecting more reasonable parameters of the PSO–ICA algorithm to increase its optimization accuracy and convergence rate, comparing with other available optimization algorithms, and verifying the performance of the optimal scheme of discontinuous polymer flooding in the practical offshore oilfield will be required in the future.

Residual oil saturation in Pre-salt Brazilian carbonates: A multi-approach core-to-log case study

Accurate residual oil saturation (Sor) measurement is paramount for successful reservoir management and has significant economic implications. Considerable uncertainty surrounds its estimation due to inaccurate direct measurements and non-representative lab results. This case study combines well logging, petrography, RCAL, and SCAL to estimate and understand Sor in Pre-salt reservoirs in Santos Basin, Brazil. The results indicate that the distribution of Sor is strongly influenced by lithology. In-situ facies have higher Sor values than reworked facies due to their greater textural and porous complexity. It has been observed that laboratory experiments and well logging results show a correlation between irreducible water saturation, porosity, and permeability with Sor, thus validating the upscaling of laboratory data. The dielectric tool provides the most accurate results in Sor logging evaluation. This is due to its shallow depth of investigation, high sampling rate, and the elimination of uncertainty associated with electrical parameters and salinity used in the Archie equation. Nuclear magnetic resonance (NMR) logging can qualitatively identify regions with higher remaining oil, which can be correlated with areas of high Sor. Still, it cannot quantitatively directly assess residual saturation by the conventional cutoff approach. Conversely, machine learning results indicate that NMR T2 times can be used to predict Sor values obtained by dielectric logging.

Pore-to-field scale modeling of residual gas trapping in tight carbonate underground gas reservoirs

The deep saline aquifer and depleted gas reservoirs are suitable candidates for CO2 storage. The estimation of residual gas and corresponding flowing behavior are major parameters for successful CO2 trapping in geological formations. In this article the residual gas trapping phenomenon in pore scale has been studied using Micro-CT images. In macro scale, the results of imbibition experiments on core plug samples have been considered to determine residual gas saturation (RGS) and the corresponding water relative permeability. In the field scale, pressure transient data in water leg has been used to determine the water relative permeability at RGS in a tight carbonate reservoir in Middle East. In the proposed workflow, an artificial intelligence approach is applied to determine absolute permeability profile. Then, a numerical dynamic single well model is built to calculate the water relative permeability. The comparison of core and pressure transient data shows that the absolute permeability and water relative permeability from core imbibition test are significantly overestimated while the results of gas-water simulation in pore scale confirmed the real field transient data. The proposed method can be used by industrial reservoir simulator to define rock/fluid interaction parameters in simulation of CO2 storage in depleted underground gas reservoirs.

Time-dependent model for two-phase flow in ultra-high water-cut reservoirs: Time-varying permeability and relative permeability

For the ultra-high water-cut reservoirs, after long-term water injection exploitation, the physical properties of the reservoir change and the heterogeneity of the reservoir becomes increasingly severe, which further aggravates the spatial difference of the flow field. In this study, the displacement experiments were employed to investigate the variations in core permeability, porosity, and relative permeability after a large amount of water injection. A relative permeability endpoint model was proposed by utilizing the alternating conditional expectation (ACE) transformation to describe the variation in relative permeability based on the experimental data. Based on the time dependent models for permeability and relative permeability, the traditional oil-water two-phase model was improved and discretized using the mimetic finite difference method (MFD). The two cases were launched to confirm the validation of the proposed model. The impact of time-varying physical features on reservoir production performance was studied in a real water flooding reservoir. The experimental results indicate that the overall relative permeability curve shifts to the right as water injection increases. This shift corresponds to a transition towards a more hydrophilic wettability and a decrease in residual oil saturation. The endpoint model demonstrates excellent accuracy and can be applied to time-varying simulations of reservoir physics. The impact of variations in permeability and relative permeability on the reservoir production performance yields two distinct outcomes. The time-varying permeability of the reservoir results in intensified water channeling and poor development effects. On the other hand, the time-varying relative permeability enhances the oil phase seepage capacity, facilitating oil displacement. The comprehensive time-varying behavior is the result of the combined influence of these two parameters, which closely resemble the actual conditions observed in oil field exploitation. The time-varying simulation technique of reservoir physical properties proposed in this paper can continuously and stably characterize the dynamic changes of reservoir physical properties during water drive development. This approach ensures the reliability of the simulation results regarding residual oil distribution.

Numerical Simulation of Time-Varying Characteristics in a High-Permeability Sandstone Reservoir: A Case of Gaoqian Southern Area

In the process of long-term water flooding in the Gaoqian Southern Area with an average porosity of 30% and an average permeability of 1333.5×10−3 μm2, the fluid-solid interaction among oil, water, and rock has a great influence on the pore structure. It has resulted in changes in reservoir parameters with the extension of time. This paper used electron microscopy scanning, mercury injection, X-ray diffraction, physical properties, and oil-water relative permeability curves to study the variation of clay mineral content, pore throat structure, porosity, permeability, and relative permeability curves of high-permeability sandstone after high-pressure water flooding. The results showed that clay minerals such as montmorillonite and kaolinite were dissolved, hydrated, and migrated after long-term water flooding, which resulted in the decrease of clay mineral content in fine sandstone and medium sandstone, the increase of pore throat radius, and the decrease of displacement pressure, median pressure, and separation coefficient. The saturation of the isotonic point of the oil-water relative permeability curve was obviously shifted to the right, the hydrophilicity was significantly enhanced, and the porosity and permeability were effectively improved, but there was a blockage of the throat less than 2 μm in the fine sandstone. In addition, this paper established the equations of water injection, permeability, irreducible water saturation, residual oil saturation, and oil-water relative permeability curve coefficient and establishes the initial permeability model with the well data before water flooding. The logging interpretation results of development wells in the process of water flooding as verification data were used, and the relative error of permeability far lower than the general requirement of permeability error within an order of magnitude was less than 30%, which verified the rationality of the method.

Influence of Reservoir Microstructure on the State of Residual Oil According to Nuclear Magnetic Resonance (NMR) Spectroscopy

The influence of core properties on the state of residual oil in the process of oil displacement by water at the micro level is investigated. The pore size distribution, core permeability, dynamics and morphology of residual oil were studied. The analysis of the available experimental approaches to the study of the properties of the core and residual oil in the core samples showed that the existing methods do not provide complete information about the studied parameters. To solve these problems, it is proposed to use a combination of innovative relaxation-diffusion spectroscopy technology of nuclear magnetic resonance with traditional technology. A combination of mercury injection and nuclear magnetic resonance is used to measure the pore size distribution. The core permeability was determined using the nuclear magnetic resonance method. Two-dimensional nuclear magnetic resonance spectroscopy makes it possible to study the microscopic state of residual oil in an undisturbed core during the displacement process. With the help of the proposed methodology, a core study of the Shengli deposit in China was carried out. Pore size distributions were obtained, permeability and residual oil saturation at different stages of displacement were studied. Four types of residual oil are distinguished: strip-shaped (island), film, mesh, continuous. The influence of permeability on the fraction content of different types of residual oil in the process of displacement is shown. The research results demonstrate the influence of the pore space structure and wettability on the state of residual oil.

An enhanced oil recovery technology applicable to kazakhstan reserves with highly viscous oils

The subject of discussion of the article below is polymer flooding as an EOR (enhanced oil recovery) technique considered here within the context of Kazakhstan’s depleted oil-fields exploitation. The underlying factor for considerable residual hydrocarbon saturation observed in the productive reservoirs of the majority of Kazakhstan’s oil fields connected with their stratified heterogeneous structures. Such kind of Oil Reservoirs require additional developments comprising new technologies promoting enhanced oil-recovery. Keywords: viscosity; inhomogeneity; polymer flooding; polyacrylamide; degree of inhomogeneity; permeability; catholyte; trim.

Study on determination of residual oil saturation in waterflooded zones

Study on determination of residual oil saturation in waterflooded zones

Experimental Study on the Mechanism and Law of Low-Salinity Water Flooding for Enhanced Oil Recovery in Tight Sandstone Reservoirs.

Currently, research surrounding low-salinity water flooding predominantly focuses on medium- to high-permeability sandstone reservoirs. Nevertheless, further investigation is necessary to implement this technique with regard to tight sandstone reservoirs. The present study comprises a series of experiments conducted on the crude oil and core of the Ordos Chang 6 reservoir to investigate the influence of ionic composition on low-salinity water flooding in tight oil reservoirs. The change in wettability on the rock surface was analyzed by using the contact angle experiment. The change in recovery rate was analyzed using a core displacement experiment. The reaction between rock fluids was analyzed using an ion chromatography experiment. Additionally, a nuclear magnetic resonance (NMR) experiment was used to analyze the mobilization law of crude oil and the change in wettability on the scale of the rock core. This led to a comprehensive discussion of the law and mechanism of enhancing the recovery rate via low-salinity water flooding from various perspectives. Experiments show that low-salinity water flooding is an effective technique for enhancing recovery in tight sandstone reservoirs. Altering the ionic composition of injected water can improve the water wettability of the rock surface and enhance recovery. Decreasing the mass concentration of Ca2+ or increasing the mass concentration of SO42- can prompt the ion-exchange reaction on the rock surface and detachment of polar components from the surface. Consequently, the wettability of the rock surface strengthens, augmenting the recovery process. Nuclear magnetic resonance experiments evidence that low-salinity water injection, with ion adjustment, significantly alters the interactions between the rock and fluid in tight sandstone reservoirs. As a result, the T2 signal amplitude decreases significantly, residual oil saturation reduces considerably, and the hydrophilic nature of the rock surface increases.

Surfactant-polymer flood with seawater for a high temperature carbonate reservoir

Developing ultralow tension surfactant formulations for carbonate reservoirs at high temperatures (> 100 °C) in the presence of hard brine is challenging. The target carbonate reservoir had been flooded with seawater and changing of the injection brine (softening or low salinity) for enhanced oil recovery was considered expensive. Seawater was presumed to be the injection brine for this study. The goal of this research work was to develop an ultralow tension surfactant-polymer (SP) formulation with seawater for this carbonate reservoir at 115 °C and to evaluate core floods with and without salinity gradient. Phase behavior was studied for many surfactants and ultralow IFT formulations were identified with the optimal salinity near the seawater salinity. SP core floods were conducted in reservoir sand packs at 115 °C; a novel 2-oven technique was used to collect the effluent with no wax formation and minimal hydrocarbon vaporization. The residual oil saturation was reduced to less than 1% in floods with salinity gradient and about 5% in constant salinity floods (at seawater salinity). The novelty of the work lies in developing SP formulations with seawater at a high temperature and studying the effect of salinity gradient. This process can be considered for many off-shore fields which have been waterflooded with seawater.

Research and Application of Carbon Capture, Utilization, and Storage–Enhanced Oil Recovery Reservoir Screening Criteria and Method for Continental Reservoirs in China

CCUS-EOR is a crucial technology for reducing carbon emissions and enhancing reservoir recovery. It enables the achievement of dual objectives: improving economic efficiency and protecting the environment. To explore a set of CCUS-EOR reservoir screening criteria suitable for continental reservoirs in China, this study investigated and compared the CCUS-EOR reservoir screening criteria outside and in China, sorted out the main reservoir parameters that affect CO2 flooding, and optimized the indices and scope of CCUS-EOR reservoir screening criteria in China. The weights of parameters with respect to their influences on CCUS-EOR were determined through principal component analysis. The results show that there are 14 key parameters affecting CO2 flooding, which can be categorized into four levels. For the first level, the crude oil-CO2 miscibility index holds the greatest weight of 0.479. It encompasses seven parameters: initial formation pressure, current formation pressure, temperature, depth, C2–C15 molar content, residual oil saturation, and minimum miscibility pressure. The second level consists of the crude oil mobility index, which has a weight of 0.249. This index includes four parameters: porosity, permeability, density, and viscosity. The third level pertains to the index of reservoir tectonic characteristics, with a weight of 0.141. It comprises two parameters: permeability variation coefficient and average effective thickness. Lastly, the fourth level focuses on the index of reservoir property change, with a weight of 0.131, which solely considers the pressure maintenance level. Based on the CCUS-EOR reservoir screening criteria and index weights established in this study, comprehensive scores for CCUS-EOR were calculated for six blocks in China. Among these, five blocks are deemed suitable for CCUS-EOR. Based on the comprehensive scoring results, a planning for field application of CCUS-EOR is proposed. The study provides a rational method to evaluate the CCUS-EOR reservoir screening and field application in continental reservoirs in China.

Factors Influencing the Rheology of Methane Foam for Gas Mobility Control in High-Temperature, Proppant-Fractured Reservoirs

Gas-enhanced oil recovery (EOR) through huff-n-puff (HnP) is an important method of recovering oil from fracture-stimulated reservoirs. HnP productivity is hampered by fracture channeling, leading to early gas breakthroughs and gas losses. To mitigate these issues, foam-generating surfactants have been developed as a method of reducing injected gas phase mobility and increasing oil recovery. This work investigates foam generation and propagation by a proprietary surfactant blend in high-temperature, high-pressure, high-permeability, and high-shear conditions that simulate the environment of a proppant-packed fracture. Bulk foam tests confirmed the aqueous stability and foaming viability of the surfactant at the proposed conditions. Through several series of floods co-injecting methane gas and the surfactant solution through a proppant pack at residual oil saturation, the effects of several injection parameters on apparent foam viscosity were investigated. The foam exhibited an exceptionally high transition foam quality (>95%) and strong shear-thinning behavior. The foam viscosity also linearly decreased with increasing pressure. Another flood series conducted in an oil-free proppant pack showed that swelling of residual oil had no effect on the apparent foam viscosity and was not the reason for the inversely linear pressure dependency. An additional flood series with nitrogen as the injection gas was completed to see if the hydrophobic attraction between the methane and surfactant tail was responsible for the observed pressure trend, but the trend persisted even with nitrogen. In a previous study, the dependence of foam viscosity on pressure was found to be much weaker with a different foaming surfactant under similar conditions. Thus, a better understanding of this important phenomenon requires additional tests with a focus on the effect of pressure on interfacial surfactant adsorption.

Modelling of CO2 Sequestration in Deep Saline Aquifer Reservoir using Surface Evolver Software

A strategy to mitigate CO2 concentration in the atmosphere is injection of supercritical CO2 in porous sedimentary medium filled with saline water where CO2 gets trapped in the pores. Sequestration is resultant of two processes, drainage and imbibition in accordance with capillary law. Simulation of the pore-scale trapping has been performed on reservoir scale. A simple model reservoir consisting of 1000 tetrahedral subunits was constructed. Using Surface Evolver software, pore volueach subunit. The CO2 pressure and liquid saturation curves of the reservoir displayed hysteretic character, indicating that the evolution of the system is pathway-dependent. The simulated curves illustrate the pathway dependency of the residual gas saturation, an important parameter controlling the amount of CO2 stored in the reservoir, hence the efficiency of the CO2 storage. Our study also shows the existence of critical thresholds in terms of in/out gassing during the drainage or imbibition processes

Design of Multi-Luminescent Silica-Based Nanoparticles for the Detection of Liquid Organic Compounds.

Tracer testing in reservoir formations is utilised to determine residual oil saturation as part of optimum hydrocarbon production. Here, we present a novel detection method of liquid organic compounds by monodisperse SiO2 nanoparticles (NPs) containing two luminophores, a EuIII:EDTA complex and a newly synthesised fluorophore based on the organic boron-dipyrromethene (BODIPY)-moiety. The particles exhibited stable EuIII PL emission intensity with a long lifetime in aqueous dispersion. The fluorescence of the BODIPY was also preserved in the aqueous environment. The ratiometric PL detection technique was demonstrated by using toluene and 1-octanol as model compounds of crude oil. The optimal synthesis conditions were found to give NPs with a diameter of ~100 nm, which is suitable for transport through porous oil reservoir structures. The cytotoxicity of the NPs was confirmed to be very low for human lung cell and fish cell lines. These findings demonstrate the potential of the NPs to replace the hazardous chemicals used to estimate the residual oil saturation. Moreover, the ratiometric PL detection technique is anticipated to be of benefit in other fields, such as biotechnology, medical diagnostics, and environmental monitoring, where a reliable and safe detection of a liquid organic phase is needed.