Pore–Scale Numerical Investigations of the Impact of Mineral Dissolution and Transport in Naturally Fractured Systems During CO2–Enriched Brine Injection

2021 ◽  
Author(s):  
Jiahui You ◽  
Kyung Jae Lee
Keyword(s):  
Dissolution Rate ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Initial Time ◽  
Co2 Injection ◽  
Pore Scale ◽  
Acid Rock ◽  
Rock Interaction ◽  
Connected Area ◽  
The Impact

Abstract CO2 storage and sequestration are regarded as an effective approach to mitigate greenhouse gas emissions. While injecting an enormous amount of CO2 into carbonate–rich aquifers, CO2 dissolves in the formation brine under the large pressure, and the subsequently formed CO2–enriched brine reacts with the calcite. Reaction–induced changes in pore structure and fracture geometry alter the porosity and permeability, giving rise to concerns of CO2storage capacity and security. Especially in the reservoir or aquifer with natural fractures, the fractures provide a highly permeable pathways for fluid flow. This study aims to analyze the acid–rock interaction and subsequent permeability evolution in the systems with complex fracture configurations during CO2 injection by implementing a pore–scale DBS reactive transport model. The model has been developed by expanding the functionality of OpenFOAM, which is an open–source code for computational fluid dynamics. A series of partial differential equations are discretized by applying the Finite Volume Method (FVM) and sequentially solved. Different fracture configurations in terms of fracture length, density, connection, and mineral components have been considered to investigate their impacts on the dynamic porosity–permeability relationship, dissolution rate, and reactant transport characteristics during CO2 storage. The investigation revealed several interesting findings. We found that calcium (Ca) concentration was low in the poorly connected area at the initial time. As CO2–enriched brine saturated the system and reacted with calcite, Ca started being accumulated in the system. However, Ca barely flowed out of the poor–connected area, and the concentration became high. Lengths of branches mainly influenced the dissolution rates, while they had slight impacts on the porosity–permeability relationship. While fracture connectivity had an apparent influence on the porosity–permeability relationship, it showed a weak relevance on the dissolution rate. These microscopic insights can help enhance the CO2 sealing capacity and guarantee environmental security.

Pore-scale hydrodynamic evolution within carbonate rock during CO2 injection and sequestration

2021 ◽  
Author(s):  
Chi Zhang ◽  
Siyan Liu ◽  
Reza Barati
Keyword(s):  
High Resolution ◽  
Reactive Transport ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Pore Scale ◽  
Modeling Framework ◽  
Calcite Dissolution ◽  
Potential Factors ◽  
The Impact

<p><span>The continuously rising threat of global warming caused by human activities related to CO</span><span><sub>2</sub> emission is facilitating the development of greenhouse gas control technologies. Subsurface CO</span><span><sub>2</sub> injection and sequestration is one of the promising techniques to store CO</span><span><sub>2</sub> in the subsurface. </span><span> </span><span>However, during CO<sub>2</sub> injection, the mechanisms of processes like injectant immobilizations and trapping and pore-scale geochemical reactions such as mineral dissolution/precipitation are not well understood. Consequently, the multi-physics modeling approach is essential to elucidate the impact of all potential factors during CO<sub>2</sub> injection, thus to facilitate the optimization of this engineered application.</span> </p><p><span>Here, we propose a coupled framework to fully utilize the capabilities of the geochemical reaction solver PHREEQC while preserving the Lattice-Boltzmann Method (LBM) high-resolution pore-scale fluid flow integrated with diffusion processes. The model can simulate the dynamic fluid-solid interactions with equilibrium, kinetics, and surface reactions under the reactive-transport scheme.  In a simplified 2D spherical pack, we focused on examining the impact of pore sizes, grain size distributions, porosity, and permeability on the calcite dissolution/precipitation rate. Our simulation results show that the higher permeability, injection rate, and more local pore connectivity would significantly increase the reaction rate, then accelerate the pore-scale geometrical evolutions. Meanwhile, model accuracy is not sacrificed by reducing the number of reactants/species within the system.</span></p><p><span>Our modeling framework provides high-resolution details of the pore-scale fluid-solid interaction dynamics. To gain more insights into the mineral-fluid interfacial properties during CO</span><span><sub>2</sub> sequestration, our next step is to combine the electrodynamic forces into the model. Potentially, the proposed framework can be used for model upscaling and adaptive subsurface management in the future. </span><span> </span></p>

Analyzing the Dynamics of Mineral Dissolution during Acid Fracturing by Pore-Scale Modeling of Acid-Rock Interaction

SPE Journal ◽  
2021 ◽  
pp. 1-14
Author(s):  
Jiahui You ◽  
Kyung Jae Lee
Keyword(s):  
Numerical Model ◽  
Multiphase Flow ◽  
Scale Model ◽  
Pore Scale ◽  
Acid Rock ◽  
Rock Interaction ◽  
Acid Fracturing ◽  
Geometry Model ◽  
The Impact ◽  
Pore Scale Model

Summary Hydrochloric acid (HCl) is commonly used in acid fracturing. Given that the interaction between acid and rock affects multiphase flow behaviors, it is important to thoroughly understand the relevant phenomena. The Darcy-Brinkman-Stokes (DBS) method is most effective in describing the matrix-fracture system among the proposed models. This study aims to analyze the impact of acid-rock interaction on multiphase flow behavior by developing a pore-scale numerical model applying the DBS method. The new pore-scale model is developed based on OpenFOAM, an open-source platform for the prototyping of diverse flow mechanisms. The developed simulation model describes the fully coupled mass balance equation and the chemical reaction of carbonate acidizing in an advection-diffusion regime. The volume of fluid (VOF) method is used to track the liquid- and gas-phase interface on fixed Eulerian grids. Here, the penalization method is applied to describe the wettability condition on immersed boundaries. The equations of saturation, concentration, and diffusion are solved successively, and the momentum equation is solved by pressure implicit with splitting of operators method. The simulation results of the developed numerical model have been validated with experimental results. Various injection velocities and the second Damkohler numbers have been examined to investigate their impacts on the CO2 bubble generation, evolving porosity, and rock surface area. We categorized the evolving carbon dioxide (CO2) distribution into three patterns in terms of the Damkohler number and the Péclet number. We also simulated a geometry model with multiple grains and a Darcy-scale model using the input parameters found from the pore-scale simulations. The newly developed pore-scale model provides the fundamental knowledge of physical and chemical phenomena of acid-rock interaction and their impact on acid transport. The modeling results describing mineral acidization will help us implement a practical fracturing project.

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1058-1068 ◽  
Author(s):  
P.. Bolourinejad ◽  
R.. Herber
Keyword(s):  
The Netherlands ◽  
Carbonic Acid ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Geological Time ◽  
Core Samples ◽  
Carbon Dioxide Co2 ◽  
Gas Fields

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

scholarly journals Experimental Investigation on the Effects of CO2 Displacement Methods on Petrophysical Property Changes of Ultra-Low Permeability Sandstone Reservoirs Near Injection Wells

Energies ◽  
2019 ◽  
Vol 12 (2) ◽  
pp. 327 ◽  
Author(s):  
Qian Wang ◽  
Shenglai Yang ◽  
Haishui Han ◽  
Lu Wang ◽  
Kun Qian ◽  
...  
Keyword(s):  
Physical Properties ◽  
Pore Size ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Low Permeability ◽  
Co2 Flooding ◽  
Formation Water ◽  
Injection Wells ◽  
Rock Interaction ◽  
Sandstone Reservoirs

The petrophysical properties of ultra-low permeability sandstone reservoirs near the injection wells change significantly after CO2 injection for enhanced oil recovery (EOR) and CO2 storage, and different CO2 displacement methods have different effects on these changes. In order to provide the basis for selecting a reasonable displacement method to reduce the damage to these high water cut reservoirs near the injection wells during CO2 injection, CO2-formation water alternate (CO2-WAG) flooding and CO2 flooding experiments were carried out on the fully saturated formation water cores of reservoirs with similar physical properties at in-situ reservoir conditions (78 °, 18 MPa), the similarities and differences of the changes in physical properties of the cores before and after flooding were compared and analyzed. The measurement results of the permeability, porosity, nuclear magnetic resonance (NMR) transversal relaxation time (T2) spectrum and scanning electron microscopy (SEM) of the cores show that the decrease of core permeability after CO2 flooding is smaller than that after CO2-WAG flooding, with almost unchanged porosity in both cores. The proportion of large pores decreases while the proportion of medium pores increases, the proportion of small pores remains almost unchanged, the distribution of pore size of the cores concentrates in the middle. The changes in range and amplitude of the pore size distribution in the core after CO2 flooding are less than those after CO2-WAG flooding. After flooding experiments, clay mineral, clastic fines and salt crystals adhere to some large pores or accumulate at throats, blocking the pores. The changes in core physical properties are the results of mineral dissolution and fines migration, and the differences in these changes under the two displacement methods are caused by the differences in three aspects: the degree of CO2-brine-rock interaction, the radius range of pores where fine migration occurs, the power of fine migration.

scholarly journals Experimental Investigation and Numerical Simulation of CO2–Brine–Rock Interactions during CO2 Sequestration in a Deep Saline Aquifer

2019 ◽  
Vol 11 (2) ◽  
pp. 317 ◽  
Author(s):  
Bo Liu ◽  
Fangyuan Zhao ◽  
Jinpeng Xu ◽  
Yueming Qi
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
Early Period ◽  
Mineral Dissolution ◽  
Solution Ph ◽  
Sem Images ◽  
Deep Saline Aquifer ◽  
Rock Interaction ◽  
Geological Co2 Storage ◽  
Co2 Mineralization

CO2 mineralization is a long-term and secure solution for geological CO2 storage that primarily depends on the CO2–brine–rock interaction during CO2 sequestration in subsurface formations. In this study, lab experiments were conducted to investigate the CO2–brine–rock interaction over short timescales, and numerical simulations were performed to reveal dynamic interactions and equilibrium interactions by applying TOUGHREACT and PHREEQC, respectively. In the experiments, the main ions of HCO3− and Ca2+ were detected in the solution, and calcite dissolution and dawsonite precipitation were observed from SEM images. The simulation results showed that the CO2 dissolution and the solution pH were affected by the temperatures, pressures, types of solutions, and solution concentrations and were further influenced by mineral dissolution and precipitation. The results of the equilibrium simulation showed that the dissolved minerals were albite, anhydrite, calcite, Ca-montmorillonite, illite, K-feldspar, and chlorite, and the precipitated minerals were dolomite, kaolinite, and quartz, which led to HCO3−, K+, and Na+ being the main ions in solutions. The results of the dynamic simulation showed that calcite and dolomite dissolved in the early period, while other minerals began to dissolve or precipitate after 100 years. The dissolved minerals were mainly albite, kaolinite, K-feldspar, and chlorite, and precipitated minerals were Ca-montmorillonite, illite, and quartz. Anhydrite and pyrite did not change during the simulation period, and the main ions were HCO3−, Na+, Ca2+, and Mg2+ in the simulation period. This study provides an effective approach for analyzing the CO2–brine–rock interaction at different stages during CO2 storage, and the results are helpful for understanding the CO2 mineralization processes in deep saline aquifers.

scholarly journals Experimental Investigation of the Mechanisms of Salt Precipitation during CO2 Injection in Sandstone

2019 ◽  
Vol 5 (1) ◽  
pp. 4 ◽  
Author(s):  
Yen Adams Sokama-Neuyam ◽  
Jann Rune Ursin ◽  
Patrick Boakye
Keyword(s):  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Physical Mechanisms ◽  
Low Salinity ◽  
Core Flood ◽  
Dry Out ◽  
The Impact ◽  
Brine Salinity

Deep saline reservoirs have the highest volumetric CO2 storage potential, but drying and salt precipitation during CO2 injection could severely impair CO2 injectivity. The physical mechanisms and impact of salt precipitation, especially in the injection area, is still not fully understood. Core-flood experiments were conducted to investigate the mechanisms of external and internal salt precipitation in sandstone rocks. CO2 Low Salinity Alternating Gas (CO2-LSWAG) injection as a potential mitigation technique to reduce injectivity impairment induced by salt precipitation was also studied. We found that poor sweep and high brine salinity could increase salt deposition on the surface of the injection area. The results also indicate that the amount of salt precipitated in the dry-out zone does not change significantly during the drying process, as large portion of the precipitated salt accumulate in the injection vicinity. However, the distribution of salt in the dry-out zone was found to change markedly when more CO2 was injected after salt precipitation. This suggests that CO2 injectivity impairment induced by salt precipitation is probably dynamic rather than a static process. It was also found that CO2-LSWAG could improve CO2 injectivity after salt precipitation. However, below a critical diluent brine salinity, CO2-LSWAG did not improve injectivity. These findings provide vital understanding of core-scale physical mechanisms of the impact of salt precipitation on CO2 injectivity in saline reservoirs. The insight gained could be implemented in simulation models to improve the quantification of injectivity losses during CO2 injection into saline sandstone reservoirs.

An Experimental Investigation of the Use of Combined Resistivity and Temperature Logs for Scale Monitoring In Carbonate Formations During CO2 Sequestration

2014 ◽  
Vol 137 (3) ◽  
Author(s):  
Abdulrauf Rasheed Adebayo ◽  
Hasan Y. Al-Yousef ◽  
Mohammed Mahmoud
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
The United States ◽  
Co2 Injection ◽  
Petrographic Analysis ◽  
Base Line ◽  
Geochemical Analysis ◽  
Overburden Pressure ◽  
Rock Interaction ◽  
Dissolution And Precipitation

This study investigates the prospect of using permanent downhole resistivity and temperature sensors for scale monitoring during CO2 sequestration in saline carbonate aquifer. Current industry practice involves continuous geochemical analysis of produced formation water and petrographic analysis of cuttings at the surface. A major limitation of such methods is that formation scale dynamics is not captured in situ and in real time. Moreover, high cost and compositional change of produced fluid caused by evolution of dissolved gases are other setbacks. In this study, resistivity and temperature measurements were logged continuously for several months at 30 min interval during CO2 storage in brine saturated core samples. Carbonate samples were acquired from Indiana outcrops in the United States and cut into cylindrical cores. Samples were saturated with synthetic formation brine and CO2 was injected and stored at a temperature of 45 °C, pore pressure of 2000 psig, and an overburden pressure of 2500 psig. The pressure, temperature and resistivity of samples were collected and transmitted to a PC computer at an interval of 30 min for the period of storage. A base line log recorded after CO2 injection but prior to CO2/brine/rock interaction (CBRI) allowed us to track onset of dissolution and precipitation. Deflection away from the baseline either inward or outward during the period of storage marks two distinct reaction phenomenon-dissolution and precipitation. Our hypothesis was justified by results of geochemical analysis of prestorage brine and poststorage brine, and also by petrographic study of the cores. Several other tests were also run to ensure consistency. This study is new compared to previous works in the following ways: Many previous works focused on the applicability of electrical resistivity measurements to track CO2 migration by way of resistivity change as a function of CO2 saturation changes during CO2 sequestration. Many others also studied the effect of CO2 injection on the petrophysical and electrical properties of rocks. Previous works of these types used continuous flow of fluid in and out of the sample and such flow experiments lasted only few hours. The fate of formation resistivity under static condition and at longer storage period was not considered.

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