We suggest two new thermodynamic models for the adsorption of ions to the brine/carbonate and brine/crude oil interface. We calibrate the model parameters to the ionic adsorption and zeta potential data. We then investigate the effect of the rock and oil surface charges on the dissolution, wettability alteration, and mechanical properties of the carbonates in the context of modified-salinity water flooding in the North Sea chalk reservoirs.
We modify a charge-distribution multi-site complexation (CD-MUSIC) model and optimize its parameters by fitting the model to a large data set of calcite surface zeta potential in presence of different brine compositions. We also modify and optimize a diffuse layer model for the oil/brine interface. We then use the optimized surface complexation models with a finite-volume solver to model the two phase reactive transport of oil and brine in a chalk reservoir, including the impact of dissolution, polar-group adsorption, and compaction on the relative permeability of chalk to water and oil. We compare the simulation results with the published experimental data.
Taheri, Mirhossein (Danish Hydrocarbon Research and Technology Center) | Bonto, Maria (Danish Hydrocarbon Research and Technology Center) | Eftekhari, Ali Akbar (Danish Hydrocarbon Research and Technology Center) | M. Nick, Hamidreza (Danish Hydrocarbon Research and Technology Center)
Our objective is to find an alternative approach to the history matching of the modified salinity water flooding tests in secondary and tertiary mode. Instead of matching only the recovery factor and pressure drop history, we give a higher priority to matching the different ion concentrations and oil breakthrough times. Based on these analyses, we suggest the predominant mechanisms for the modified-salinity water flooding in carbonates.
The work is done in three steps: 1) Studying a large data-set of modified-salinity water flooding experiments in carbonates. 2) Quantifying the adsorption of potential determining ions (PDIs) on the carbonate surface using an optimized in-house surface-complexation model 3) Adjusting the relative permeability parameters to history-match the experimental data using different analytical solution of water-flooding (with and without ionic adsorption) combined with modern search-based optimization algorithms. The optimization algorithm gives a high weight factor to the breakthrough time of oil and PDIs.
Having too many parameters in the relative permeability (6 parameters for Brooks-Corey type) make it possible to match any type of recovery curves. However, we found out that matching the breakthrough times, especially in the tertiary modified salinity waterflooding, can only be achieved by considering the wettability change due to the adsorption of PDIs on the carbonate surface. This observation, combined with our ability to accurately model the adsorption of PDIs on the carbonate surface, helped us to identify the important PDIs that cause the wettability change in carbonates. For instance, we observe that a model that considers the wettability change due to the adsorption of calcium ions on the chalks surface matches perfectly to the tertiary flooding of the Stevns Klint outcrop chalk with seawater. The second important observation is that the lag between the start of the injection of the modified-salinity brine and the oil breakthrough time is not always due to the adsorption of ions and sometimes can be explained by the wettability change due to the lower salinity of the injected brine. It must be noted that this new approach is still semi-empirical, and needs to be combined with more fundamental studies to identify the actual mechanisms.
It is generally assumed that while the presence of foam reduces the mobility of the gas phase, it does not alter the mobility of the liquid phase. Here, the effect of surfactant type and concentration on the behavior of nitrogen foam flow in porous media is investigated by simultaneous injection of gas and surfactant into Bentheimer sandstone cores. Different surfactant types, viz., anionic alpha-olefin-sulfonate (AOS) and zwitterionic Betaine with different surfactant concentrations from critical-micelle-concentration (CMC) to higher concentration are used in this study. The foam strength is quantified by measuring the pressure drop in different sections of the core. The liquid saturation is measured by analyzing the X-ray images obtained in a medical CT-scanner.
It is shown that the connate water saturation is reduced by increasing the surfactant concentration, and therefore the relative permeability relation for the aqueous phase should be modified when fitting the data to the foam models. It is observed that it is not possible to fit one monotonic liquid relative permeability curve to all the data points, obtained with different surfactant type and concentration in one rock type. Moreover, increasing AOS concentration above a certain value does not have a significant effect on the mobility reduction of the gas phase; however it modifies the liquid relative permeability. These results indicate that the water relative permeability measured in absence of surfactant should not be used to model the flow of foam in porous media, as it can lead to erroneous calculations of the liquid saturation.
Foam has been employed as an Improved/Enhanced oil recovery (IOR/EOR) method to overcome gravity override and the channeling and fingering of the injected gas, which arises due to the low density and viscosity of the injected fluid combined with the rock heterogeneity. A major challenge; however, is the stability of the generated foam when it contacts the oil. Foam boosters, which are generally costly surfactants, have been co-injected together with the main foaming surfactant to create stable foams in the presence oil. Similar to surfactants, particles can also accumulate at the gas-liquid and liquid-liquid interfaces. The difference is that the energy of adsorption and desorption of particles to the interface is so large that their adsorption is considered irreversible. Nanoparticles are orders of magnitude smaller than pore throats and therefore can easily flow through porous media.
In this study we investigate the possibility of replacing the expensive foam boosters with inexpensive nanoparticles made of coal fly-ash, which is abundantly available as a by-product of coal power plants. We investigate the viability of reducing the size of fly-ash particles using high frequency ultrasonic grinding. We also study the foaminess (foamability) and stability of the foams made with minor concentrations of fly-ash nanoparticles and surfactant both in bulk and porous media. The effect of monovalent and divalent ion concentration on the foaminess of the nano-ash suspension combined with very low concentrations of a commercial alpha olefin sulfonate (AOS) surfactant, in presence and absence of oil, is studied.
We observe that bulk foam that contains very small amounts of nano-ash particles shows a higher stability in presence of model oils. Furthermore, experiments in porous media exhibit remarkably stronger foam with mixtures of nano-ash and surfactant, such that the amount of produced liquids from the cores significantly increases. In presence of oil, the nano-ash-AOS foam shows a higher stability, although crude oil tends to form stable emulsions in water in presence of nano-ash.
Huge oil deposits (> 8 billion barrels) were recently discovered off the coast of Brazil below 2000 m of seawater and 1000-2000 m of reservoir, below 2000 m of salt layers. The high pressures (~ 700 bars) make these reservoirs excellent candidates for high pressure miscible gas injection, e.g., CO2 injection. For the geothermal gradients encountered in this area the temperatures are around 473 K. At high pressures it is possible that the mass density of carbon dioxide is higher than of oil, which will allow gravity stabilized injection. We consider the CO2-brine system, firstly for its storage as a greenhouse gas. Secondly, it is an initial step to describe displacement in the CO2-oil-brine system.
In this paper we study the phase behavior of carbon dioxide in a brine bearing layer at a temperature of 473 K and pressures between 600 and 800 bars. The quantification of the displacement process requires the thermodynamic equilibrium relations in the oil-water-salt-CO2 system at the prevailing pressures. Here we limit our interest to the thermodynamic behavior of the carbon dioxide-brine system. We show that it is possible to use the PRSV equation of state to estimate the composition of the vapor and aqueous phases. The PRSV is a modification of the Peng-Robinson equation of state. We use an activity-coefficient based mixing rule for the thermodynamic calculations. A volume shift procedure is applied to improve liquid density.
Wahanik, Helmut (Inst. Matematica Pura/Aplicada) | Eftekhari, Ali Akbar (Delft U. of Technology) | Bruining, Johannes (Inst. Matematica Pura/Aplicada) | Marchesin, Dan (Delft U. of Technology) | Wolf, Karl-Heinz A.A.
Concern about global warming is generating interest in reducing the emissions of greenhouse gases such as CO2. One way of reducing CO2 emissions is to replace conventional (hydrocarbon fuels) energy sources for heating buildings by geothermal energy. Recently it was suggested to co-inject carbon dioxide with cold water for simultaneous geothermal energy production and subsurface carbon dioxide storage. Our data correspond to a geothermal energy project proposed for heating the buildings of the Technical University of Delft. After injection of the water/CO2 mixture a complex interaction between physical transport and the phase redistribution of the components, i.e., water and CO2, occurs. This redistribution is usually described in terms of local thermodynamic equilibrium. There are no published complete analytical solutions for 1-D problems involving complex thermodynamics that include CO2 and heat effects in the flow. We take into account the heat effects related to the cold fluid injection and related to the dissolution of CO2.
We give an analytical solution for the model equations for the temperature and for the flow of CO2, vapor and water after combined injection of a cold carbon dioxide-water mixture in a geothermal reservoir. Due to high pressures and temperatures, CO2 is in a supercritical state and it is necessary to determine the phase equilibrium for non-ideal gases. We used a modification of the Peng-Robinson equation of state and an activity coefficient based mixing rule for the thermodynamic calculations. A volume shift procedure is applied to obtain an accurate liquid density. The structure of the solution depends strongly on the injection and initial reservoir conditions. The application of the work is in the effective recovery of heat from geothermal reservoirs with simultaneous CO2 storage. Moreover, the theory provides fundamental understanding of non-isothermal flow of mixtures undergoing mass transfer between phases. The advantage of the analytical model is that it provides a simple methodology to screen injection conditions for optimal geothermal recovery or maximal storage of carbon dioxide.