Proposing a rigorous empirical model for estimating the bubble point pressure in heterogeneous carbonate reservoirs

 Bubble point pressure is of great significance in reservoir engineering calculations affecting the success of reservoir simulation. For determining this valuable parameter, experimental tests are the most reliable techniques; however, these measurements are costly and time-consuming. So, it is crucial to propose an empirical model for estimating bubble point pressure. The existing correlations mainly have large errors and develop based on restricted database from a specific geographical location. As a result, development of an all-inclusive correlation is essential. In current article, gene expression programming (GEP) was used to create a generalized model for bubble point pressure estimation. To do this, an all-inclusive source of data was utilized for training and testing the model from the petroleum industry. Several statistical approaches including both illustration tools and diverse error functions were utilized to show the supremacy of the developed GEP model. Consequently, the recommended model is the most accurate as compared to the similar correlations in literature with the average absolute relative error (AARE = 11.41%) and determination coefficient (R2 = 0.96). Furthermore, the solution gas-oil ratio shows to be the most influencing variable on determining bubble point pressure according to sensitivity analysis. The results of contour map analysis demonstrate that most portions of the experimental region are predicted via the GEP equation with fewer errors as compared to two well-known literature correlations. Finally, the proposed GEP model can be of high prominence for accurate bubble point pressure estimation.Cited as: Rostami, A., Daneshi, A., Miri, R. Proposing a rigorous empirical model for estimating the bubble point pressure in heterogeneous carbonate reservoirs. Advances in Geo-Energy Research, 2020, 4(2): 126-134, doi: 10.26804/ager.2020.02.0

Effects of CO2-Brine-Rock Interactions on CO2 Injectivity – Implications for CCS

Carbon capture and storage (CCS) in geological reservoirs – especially saline aquifers – is a key midterm solution to mitigate climate changes caused by increasing anthropogenic CO2. In order to ensure that a CCS project reach the required level of success, three essential elements need to be guaranteed; storage capacity, injectivity and containment. Among these elements, relatively less research has been conducted relevant to the injectivity, thus there are several technical uncertainties in this regard that should be understood and quantified in order to ensure long-term storage of CO2. This thesis is therefore centered at improving such knowledge and understanding by addressing some of the vague research areas in regard to CO2 injectivity including: CO2/H2O mutual solubilities, salt precipitation and depositional heterogeneities. First part of this study is devoted to thermodynamic modeling of fluid mixtures relevant for CO2 storage with particular focus on effect of methane (CH4) and sulphur dioxide (SO2) impurities. To do this, a molecular based framework, Statistical Association Fluid Theory (SAFT) is chosen and the molecular parameters required by the model were adjusted against the available experimental data. The developed model is effectively used to predict phase partitioning, the aqueous phase density and water drop-out in contact with solid surface, which we believe to be especially well-suited to the assessment of injectivity of a proposed CO2 storage reservoir. In the next part of this thesis, the processes of drying-out and salting-out were explored in more detail. This work encompasses the fabrication of the two sets of glass microchips, as well as series of experimental characterisation that has given us a valuable insight into the mechanism of salt precipitation. In particular, we have identified two mechanisms which together dramatically intensify the precipitation rate and amount of salt precipitated. From this insight, the reported discrepancies in the literature regarding the salt precipitation could be successfully explained and a new prototype for modeling of the process could be provided. We have also studied, but to a lesser extend, the effect of prepositional heterogeneities on the plume migration and pressure response at the injection well. We came to the conclusion that extreme well and aquifer pressures are unlikely for the setting studied in this thesis

Fluid‐Rock Interactions in Clay‐Rich Seals: Impact on Transport and Mechanical Properties

Fluid‐rock interaction in low‐permeable clay‐rich seal units is an important topic for the evaluation of the long‐term seal integrity during geological storage of CO2. In low‐permeable sealing units, the diffusion of CO2 into the matrix is a slow process, and studies of CO2‐initiated fluid‐rock interaction in seals are challenging. In this paper, we present an overview of CO2 transport mechanism and fluid‐rock interaction processes that might alter mechanical and transport properties of seals. The review includes theoretical considerations and simulations, experimentally demonstrated processes, and field examples of flow and fluid‐rock interaction in intact clay‐rich seals as well as for fractures. For clay‐rich seals dominated by minerals like quartz, illite, and smectite, the reactivity due to drop in pH is found to be low, and most reaction observed is found to involve calcite. Only minor porosity changes are observed, and implications for flow and CO2 transport are uncertain due to limited data available. Swelling and shrinking property of smectites due to CO2 sorption and CO2 alterations within fractures in clay‐rich seal is hardly addressed in the literature.Fluid‐Rock Interactions in Clay‐Rich Seals: Impact on Transport and Mechanical PropertiesacceptedVersio

Phase relations in the Longyearbyen CO2 Lab reservoir – forecasts for CO2 injection and migration

Understanding of fluid-mixture properties relevant to the Longyearbyen CO2 Lab pilot project (LYBCO2) is of great importance for the assessment of the injection performance. Phase equilibria and density of the binary, ternary and quaternary systems containing CO2, CH4, H2O and NaCl were investigated using a Statistical Associating Fluid Theory (SAFT)-based equation of state (EoS) at ambient temperature and pressure, and salt concentrations up to 5 mol kgw-1, all relevant to LYBCO2. Binary interaction parameters of the subsystems (CO2–CH4, CH4–H2O, and CH4–NaCl) were tuned against available experimental data, using previously adjusted parameters for pure components and CO2–H2O subsystems. Solubility of CH4 and CO2 and subsequent mixture densities were predicted at 298 K and pressure up to 100 bar. It is found that by increasing the hydrocarbon in the injection stream (even in small amounts) and also the salt concentration and solubility of the CO2 in the aqueous phase, then consequently the density of the mixture will reduce. Moreover, hydrocarbon impurities like CH4 would result in a favourable density difference and faster plume migration; however, the probability of a three-phase state (two liquid and one vapour phase) near the bubble line is very high too. The results of this work are applicable to estimation of storage capacity as well as simulation of plume migration and fate in all projects involving a CO2, CH4, H2O and NaCl-bearing fluid system. http://www.geologi.no/njg

Effects of geological heterogeneity on CO2 distribution and migration – A case study from the Johansen Formation, Norway

In characterizing subsurface reservoirs for CO2 storage, the geological heterogeneity distribution is of importance with respect to the injectivity and migration paths. The object of this study is a saline aquifer of Jurassic age; the Johansen Formation of the Northern North Sea. Through scenario modeling the effect of site-typical geological heterogeneities of depositional origin have been tested. The existence of laterally continuous calcite cemented layers and draping mud layers of low permeability in association with flooding events, could compartmentalize the reservoir. This is not necessarily a disadvantage; however, as the sweep efficiency becomes higher when the plume is spread out, potentially increasing the effect of trapping mechanisms

Pore scale modeling and evaluation of clogging behavior of salt crystal aggregates in CO₂-rich phase during carbon storage

The optimal CO2 storage operation requires high permeability in the near-well region in order to keep it safe and cost-efficient. Nucleation and growth of salt crystals driven by the evaporation of formation water into under-saturated (dry) super-critical CO2 streams result in the changes in porosity and permeability of the near well-bore area. Permeability reduction is one of the main reasons for injectivity losses in the context of CO2 storage in saline aquifers. According to recent studies, during CO2 storage, salt crystals grow in two different forms: 1) single, large crystals in the aqueous phase, and 2) aggregates of micro-meter size salt crystals in the CO2-rich vapor phase. All previous numerical studies at pore-scale have addressed the formation of single, large crystals in the aqueous phase. In this work we have developed a 3D pore-scale reactive transport solver based on a D3Q19 advection-diffusion Lattice-Boltzmann model. The model takes for the first time salt nucleation into consideration via a new probabilistic approach to simulate the formation of micro-meter size salt crystal aggregates in the CO2-rich phase and their effect on changes in pore morphology and permeability. Comparing the results of porosity-permeability relations with some of the well-known clogging models, confirms the need for a new clogging model to capture the permeability reduction caused by salt aggregates

Modified PC-SAFT characterization technique for modeling asphaltenic crude oil phase behavior

The perturbed-chain version of Statistical Association Fluid Theory (PC-SAFT) emerged as a powerful tool to study the phase behavior of complex fluids such as polymers and asphaltene. In spite of this, it has not gained widespread acceptance in the industry because of its sophisticated oil characterization procedure. In fact, the predictive performance of the current characterization methods is limited and not all-inclusive as they use a large number of fitting parameters and/or a non-integrated procedure. In this study, a convenient and easy-to-use procedure for crude oil characterization is proposed, assuming asphaltene as a combination of poly-nuclear aromatics, benzene derivatives, and saturates. To achieve the best match between measured and model predictions, a simple and robust Trust-Region based optimization method is used. A set of weighting factors is also used based on uncertainties in experimental data. Additionally, it is showed that the poor agreement between the measured amounts of precipitated asphaltene (from filtration test) and thermodynamic model predictions —tuned toward experimental asphaltene onset pressure data— is because of the inherent difference between the accuracy of the experimental methods. The performance of the proposed method is evaluated against reliable literature data of three frequently used crude oils which have been previously characterized over wide range of temperature, pressure, and compositions, and a reservoir fluid sample taken from a southwestern Iranian reservoir. The results are encouraging if compared to the available characterization procedures in the literature

Extension of PC-SAFT equation of state to include mineral surface effect in fluid properties using molecular dynamic simulation

In the vicinity of fluid-mineral interfaces a transition zone exist in which the order and packing of the molecules differ from that of the bulk phase where the distribution of intermolecular forces exhibit a more homogenous form. To develop an understanding of the thermodynamic properties in the fluid-mineral interface molecular dynamic (MD) simulation was conducted for the water-calcite system. To predict the water properties near the calcite wall, we have defined a contribution for Helmholtz energy extended from PC-SAFT equation of state (EOS). The new energy contribution depends on the confinement parameters i.e. potential of fluid-wall interaction, confinement degree, bulk density, and fraction of confined molecules estimated by MD simulation. The outcomes of MD simulation exhibit the layering transition of water on the water-calcite interface. In addition, MD simulation confirm the energy deviation within the layering transition zone, where the calcite adsorbs the water molecules. In this approach, the modified PC-SAFT showed a good agreement with MD observations. The results of this study can contribute to a better understanding of fluid behavior at the fluid-mineral interface. In addition, this technique is a valuable tool that can be used to estimate solubility limits in multicomponent fluid processing and pipeline transport

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

Continuum scale modelling of salt precipitation in the context of CO2 storage in saline aquifers with MRST compositional

Carbon capture and storage (CCS) would contribute considerably towards climate change mitigation, if it would be implemented on a very large scale; at many storage sites with substantial injection rates. Achieving high injection rates in deep saline aquifers requires a detailed assessment of injectivity performance and evaluation of the processes that alter the permeability of the near-well region. One of the most common forms of the injectivity loss in the context of CO2 storage in saline aquifers is salt precipitation driven by the evaporation of brine into the relatively dry injected CO2 stream. We present a novel compositional transport formulation based on overall-composition variables which models salt as a separate solid phase which could potentially form through two essentially different ways, i.e., kinetic or equilibrium. To model formation drying-out and subsequent halite-precipitation, an accurate and reliable fluid model ePC-SAFT, which can effectively account for ionic effects, is applied. In addition, a volume balance approach (i.e., depending on how far the salt saturation is from the solubility limit) is implemented to estimate solid saturation in a simulation cell. The resulting simulator is benchmarked against several well-known examples, with analytical solutions demonstrating the ability of the code to cover a variety of physical mechanisms. Finally, injection of dry CO2 into a brine-saturated core-scale domain is simulated and sensitivity analyses over various parameters are performed. We show that the new model is capable to quantitatively represent the physics of salt precipitation (for example salt self-enhancing) under different reservoir conditions