Rohaldin Miri

Examination of CO2-SO2 solubility in water by SAFT1. Implications for CO2 transport and storage.

Removal of toxic gases like SO2 by cosequestration with CO2 in deep saline aquifers is a very attractive suggestion from environmental, human health and economic point of view. Examination of feasibility of this technique and forecasting the underlying fluid-rock interactions requires precise knowledge about the phase equilibria of the ternary mixture of SO2-CO2-H2O at conditions relevant to carbon capture and storage (CCS). In this study, a molecular-based statistical association fluid theory (SAFT1) model is applied to estimate the phase equilibria and aqueous phase density of mixtures. The molecules are modeled as associating segments while self-association is not allowed. The model is tested for different SO2 concentrations and for temperatures and pressures varying between 30-100 °C and ∼6-30 MPa, respectively. Comparison of the results of this model against the available experimental data of binary systems demonstrates the capability of this equation of state, although, in contrast to the previous works, no temperature dependent binary interaction coefficient is applied. The results show that the total solubility of SO2 + CO2 in water varies exponentially with respect to SO2 concentrations, i.e., at low concentrations of SO2, total changes in solubility of the CO2 in water is negligible.

On Layer Specific CO2 Plume Distributions and Variability in Mineralization Potential

Candidate sandstone reservoirs for CO2 storage in the North Sea typically display layered geometries and varying degree of geological heterogeneity. The spatial distribution of depositional environments and the diagenetic imprint controls the reservoir properties. From correlation of well data (geophysical logs and rock samples) property grids may be constructed. Deterministic scenario modeling, taking the geological interpretation of facies into account, shows layer specific estimated dissolved volumes and lateral reaches of the plume. In comparison, standard averaging techniques such as harmonic mean for estimating the vertical permeability will yield a smaller plume front area and a mean vertical distribution. Using Eclipse 300 to illustrate the effects of averaging and PHREEQ-C to model the geochemical system, we demonstrate the range of mineralization potentials within the Johansen Formation (Northern North Sea) according to observed variations in mineralogy.

Fracture Capillary Pressure Based on the Liquid Bridge Dynamic Stability Study

Performance study of gas oil gravity drainage in stacks of overwhelmed blocks in a gas-invaded zone of naturally fractured reservoirs presents difficult challenges to petroleum engineers. It is believed that there exists some degree of block-to-block interaction that may lead to capillary continuity in fractured reservoirs. Effect of such continuity in gravity drainage is much more pronounced as it increases the height of the continuous fluid column in a reservoir and thereby the recovery of oil as height is a key parameter in gravity drainage mechanisms. It has been experimentally proven that liquid or solid bridges in horizontal fracture can contribute to wetting phase transfer across the horizontal fracture, but there is no mathematical model that predicts the probability of such continuity. In this article, a mathematical model developed by using 1-D Navier-Stock for the free surface flow equation and Young-Laplace of capillary for breakage of the stable liquid bridge held between two pairs of support while stretching. The model gives critical length of fracture aperture, which surely provides capillary continuity. Moreover, the developed model shows flow dependency of fracture capillary pressure and predicts a nonzero value for this parameter, while in the past many researchers used zero fracture capillary pressure for history matching of fractured reservoirs.

Effect of CO2 Phase States and Flow Rate on Salt Precipitation in Shale Caprocks—A Microfluidic Study

Fracture networks inside the caprock for CO2 storage reservoirs may serve as leakage pathways. Fluid flow through fractured caprocks and bypass conduits, however, can be restrained or diminished by mineral precipitations. This study investigates precipitation of salt crystals in an artificial fracture network as a function of pressure-temperature conditions and CO2 phase states. The impact of CO2 flow rate on salt precipitation was also studied. The primary research objective was to examine whether salt precipitation can block potential CO2 leakage pathways. In this study, we developed a novel microfluidic high-pressure high-temperature vessel to house geomaterial micromodels. A fracture network was laser-scribed on the organic-rich shales of the Draupne Formation, the primary caprock for the Smeaheia CO2 storage in Norway. Experimental observations demonstrated that CO2 phase states influence the magnitude, distribution, and precipitation patterns of salt accumulations. The CO2 phase states also affect the relationship between injection rate and extent of precipitated salts due to differences in solubility of water in CO2 and density of different CO2 phases. Injection of gaseous CO2 resulted in higher salt precipitation compared to liquid and supercritical CO2. It is shown that micrometer-sized halite crystals have the potential to partially or entirely clog fracture apertures.

Static Stability of Liquid Bridges Between Matrix Blocks of a Gas Invaded Zone of Naturally Fractured Reservoirs

A large portion of oil and gas reservoirs in the world are located in naturally fractured reservoirs. Despite such importunity, the production mechanisms of these reservoirs are not completely well defined. Gas–oil gravity drainage that takes place in the gas-invaded zone of this type of reservoirs is one instance of such a weakness. The density difference between gas-filled fractures in contact with oil-saturated matrix blocks brings the oil out of the matrix blocks into the fracture. The drained oil can reach the production well through two different paths: continues fracture network and block-to-block path. These two different paths require different approaches to modeling of gravity drainage. Single-block approaches are used when drained oil only travels through the fracture network, which totally formulated before. But when oil prefers to travel through the matrix blocks, continuum approaches such as Darcys law may not work in their basic forms any more. Liquid bridges and film that form in the horizontal fracture between matrix blocks usually transfer the wetting phase across the fracture. Stability condition and duration of stability can help better understanding of gravity drainage in stacks of blocks. In this article, the stability of liquid bridges between the matrix blocks studied and a minimum length of stability is predicated. The results show that this stable length of liquid bridges formed between adjacent matrix blocks is 2r0π, which is a function of the pore throat. This critical length can be used in modeling of capillary continuity and wetting phase transfer across matrix blocks.

Proper Implementation of Gas-oil Gravity Drainage Transfer Functions in Dual Porosity Simulators

Free fall and forced gravity drainage are established production mechanisms, which contribute to significant oil production in naturally fractured reservoirs, commonly 30–60% original oil in place. Accurate and proper implementation of gravity drainage performance, as an exchange term, in dual porosity simulators is a critical issue. A numerical model of gas-oil gravity drainage was developed and solved analytically for some simple cases and also numerically for more complicated forms of capillary pressure and relative permeabilities. In this article, three famous transfer functions in the literature in a comparative study were checked by a developed numerical model. The result revealed that transfer functions studied here predict less accurate results in comparison with the numerical model and using constant matching parameters cannot resolve this issue because problems arise from simple treatment of time dependent parameters, such as capillary pressure and relative permeability.

Developments in SAFT EOS for Carbon Capture and Storage (CSS)

The fluid mixtures involving in the different stages of a Carbon Capture and Storage (CSS) project can be categorized as associate electrolyte solutions. Due to highly non-ideal intermolecular interactions, investigation of phase equilibria of such fluids is one of the challenging engineering tasks of the last decade. The SAFT type equations of state is one promising approach that can account for different intermolecular non-ideality such as association, polarity and chain forming. In this study a modified version of SAFT Equation of State (EoS), SAFT1-RPM, is utilized to calculate the vapor - liquid equilibrium (VLE) of CH4-CO2-H2O-NaCl mixtures. SAFT1-RPM is chosen because of its accuracy and predictive capabilities in modeling of associating electrolyte fluids. Molecular parameters for binary sub-systems were regressed from experimental data. The model predictions at 25°C show that, adding CH4, even in a small percentage, will reduce the solubility of CO2 in the water in a same way as NaCl reduce the solubility.