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 CO2 mineralization by olivine at hydrothermal conditions

2014 ◽  
Vol 78 (6) ◽  
pp. 1473-1477
Author(s):  
Jan Přikryl ◽  
Andri Stefánsson
Keyword(s):  
Ph Value ◽  
Hydrothermal Conditions ◽  
Solution Ph ◽  
Rock Interaction ◽  
Carbonate Formation ◽  
Effects Of Temperature ◽  
Co2 Mineralization ◽  
Geochemical Reaction ◽  
Insight Into ◽  
Water Rock Interaction

The interaction of CO2-rich water with olivine was studied using geochemical reaction modelling in order to gain insight into the effects of temperature, acid supply (CO2) and extent of reaction on the secondary mineralogy, water chemistry and mass transfer. Olivine (Fo93) was dissolved at 150 and 250ºC and pCO2 of 2 and 20 bar in a closed system and an open system with secondary minerals allowed to precipitate. The progressive water–rock interaction resulted in increased solution pH, with gradual carbonate formation starting at pH 5 and various Mg-OH and Mg-Si minerals becoming dominant at pH>8. The major factor determining olivine alteration is the pH of the water. In turn, the pH value is determined by acid supply, reaction progress and temperature.

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.

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.

Interfacial tension measurements and wettability evaluation for geological CO2 storage

2009 ◽  
Vol 32 (1) ◽  
pp. 98-109 ◽  
Author(s):  
C. Chalbaud ◽  
M. Robin ◽  
J-M Lombard ◽  
F. Martin ◽  
P. Egermann ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Co2 Storage ◽  
Geological Co2 Storage

scholarly journals Technical Work Processes for Qualifying Geological CO2 Storage

2013 ◽  
Vol 37 ◽  
pp. 4794-4803
Author(s):  
Gøril Tjetland ◽  
Hallvard Høydalsvik ◽  
Espen Erichsen
Keyword(s):  
Co2 Storage ◽  
Work Processes ◽  
Geological Co2 Storage ◽  
Technical Work

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 Numerical Simulation and Optimization of CO2 Sequestration in Saline Aquifers

2012 ◽  
Author(s):  
Zheming Zhang ◽  
Ramesh Agarwal
Keyword(s):  
Numerical Simulation ◽  
Co2 Sequestration ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Injection Well ◽  
Co2 Injection ◽  
Great Promise ◽  
Saline Aquifer ◽  
Simulation And Optimization ◽  
Co2 Plume

With recent concerns on CO2 emissions from coal fired electricity generation plants; there has been major emphasis on the development of safe and economical Carbon Dioxide Capture and Sequestration (CCS) technology worldwide. Saline reservoirs are attractive geological sites for CO2 sequestration because of their huge capacity for sequestration. Over the last decade, numerical simulation codes have been developed in U.S, Europe and Japan to determine a priori the CO2 storage capacity of a saline aquifer and provide risk assessment with reasonable confidence before the actual deployment of CO2 sequestration can proceed with enormous investment. In U.S, TOUGH2 numerical simulator has been widely used for this purpose. However at present it does not have the capability to determine optimal parameters such as injection rate, injection pressure, injection depth for vertical and horizontal wells etc. for optimization of the CO2 storage capacity and for minimizing the leakage potential by confining the plume migration. This paper describes the development of a “Genetic Algorithm (GA)” based optimizer for TOUGH2 that can be used by the industry with good confidence to optimize the CO2 storage capacity in a saline aquifer of interest. This new code including the TOUGH2 and the GA optimizer is designated as “GATOUGH2”. It has been validated by conducting simulations of three widely used benchmark problems by the CCS researchers worldwide: (a) Study of CO2 plume evolution and leakage through an abandoned well, (b) Study of enhanced CH4 recovery in combination with CO2 storage in depleted gas reservoirs, and (c) Study of CO2 injection into a heterogeneous geological formation. Our results of these simulations are in excellent agreement with those of other researchers obtained with different codes. The validated code has been employed to optimize the proposed water-alternating-gas (WAG) injection scheme for (a) a vertical CO2 injection well and (b) a horizontal CO2 injection well, for optimizing the CO2 sequestration capacity of an aquifer. These optimized calculations are compared with the brute force nearly optimized results obtained by performing a large number of calculations. These comparisons demonstrate the significant efficiency and accuracy of GATOUGH2 as an optimizer for TOUGH2. This capability holds a great promise in studying a host of other problems in CO2 sequestration such as how to optimally accelerate the capillary trapping, accelerate the dissolution of CO2 in water or brine, and immobilize the CO2 plume.

scholarly journals Managing Uncertainty in Geological CO2 Storage Using Bayesian Evidential Learning

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1557
Author(s):  
Amine Tadjer ◽  
Reidar B. Bratvold
Keyword(s):  
Uncertainty Quantification ◽  
History Matching ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Monitoring Program ◽  
Co2 Injection ◽  
Drinking Water Contamination ◽  
Model Inversion ◽  
Geological Co2 Storage ◽  
And Storage

Carbon capture and storage (CCS) has been increasingly looking like a promising strategy to reduce CO2 emissions and meet the Paris agreement’s climate target. To ensure that CCS is safe and successful, an efficient monitoring program that will prevent storage reservoir leakage and drinking water contamination in groundwater aquifers must be implemented. However, geologic CO2 sequestration (GCS) sites are not completely certain about the geological properties, which makes it difficult to predict the behavior of the injected gases, CO2 brine leakage rates through wellbores, and CO2 plume migration. Significant effort is required to observe how CO2 behaves in reservoirs. A key question is: Will the CO2 injection and storage behave as expected, and can we anticipate leakages? History matching of reservoir models can mitigate uncertainty towards a predictive strategy. It could prove challenging to develop a set of history matching models that preserve geological realism. A new Bayesian evidential learning (BEL) protocol for uncertainty quantification was released through literature, as an alternative to the model-space inversion in the history-matching approach. Consequently, an ensemble of previous geological models was developed using a prior distribution’s Monte Carlo simulation, followed by direct forecasting (DF) for joint uncertainty quantification. The goal of this work is to use prior models to identify a statistical relationship between data prediction, ensemble models, and data variables, without any explicit model inversion. The paper also introduces a new DF implementation using an ensemble smoother and shows that the new implementation can make the computation more robust than the standard method. The Utsira saline aquifer west of Norway is used to exemplify BEL’s ability to predict the CO2 mass and leakages and improve decision support regarding CO2 storage projects.

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