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.

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.

Improving CO2 storage and oil recovery by injecting alcohol-treated CO2

2020 ◽  
Vol 60 (2) ◽  
pp. 662
Author(s):  
Saira ◽  
Furqan Le-Hussain
Keyword(s):  
Oil Recovery ◽  
Co2 Sequestration ◽  
Computer Modelling ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Numerical Studies ◽  
Reservoir Simulator ◽  
Enhance Oil Recovery

Oil recovery and CO2 storage related to CO2 enhance oil recovery are dependent on CO2 miscibility. In case of a depleted oil reservoir, reservoir pressure is not sufficient to achieve miscible or near-miscible condition. This extended abstract presents numerical studies to delineate the effect of alcohol-treated CO2 injection on enhancing miscibility, CO2 storage and oil recovery at immiscible and near-miscible conditions. A compositional reservoir simulator from Computer Modelling Group Ltd. was used to examine the effect of alcohol-treated CO2 on the recovery mechanism. A SPE-5 3D model was used to simulate oil recovery and CO2 storage at field scale for two sets of fluid pairs: (1) pure CO2 and decane and (2) alcohol-treated CO2 and decane. Alcohol-treated CO2 consisted of a mixture of 4 wt% of ethanol and 96 wt% of CO2. All simulations were run at constant temperature (70°C), whereas pressures were determined using a pressure-volume-temperature simulator for immiscible (1400 psi) and near-miscible (1780 psi) conditions. Simulation results reveal that alcohol-treated CO2 injection is found superior to pure CO2 injection in oil recovery (5–9%) and CO2 storage efficiency (4–6%). It shows that alcohol-treated CO2 improves CO2 sweep efficiency. However, improvement in sweep efficiency with alcohol-treated CO2 is more pronounced at higher pressures, whereas improvement in displacement efficiency is more pronounced at lower pressures. The proposed methodology has potential to enhance the feasibility of CO2 sequestration in depleted oil reservoirs and improve both displacement and sweep efficiency of CO2.

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.

Modeling, Simulation, and Optimization of Geological Sequestration of CO2

2019 ◽  
Vol 141 (10) ◽  
Author(s):  
Ramesh K. Agarwal
Keyword(s):  
Fluid Dynamics ◽  
Co2 Sequestration ◽  
Spatial Scales ◽  
The United States ◽  
Co2 Injection ◽  
Temporal Scales ◽  
Simulation And Optimization ◽  
Modeling Simulation ◽  
Plume Migration ◽  
Basic Fluid

With heightened concerns on carbon dioxide (CO2) emissions from coal power plants, there has been a major emphasis in recent years on development of safe and economical geological carbon sequestration (GCS) technology. However, the detailed multiphase fluid dynamics and processes of GCS are not fully understood because various CO2 trapping mechanisms in geological formations have large variations in both spatial and temporal scales. As a result, there remain many uncertainties in determining the sequestration capacity of the reservoir and the safety of sequestered CO2 due to leakage. Furthermore, the sequestration efficiency is highly dependent on the CO2 injection strategy, which includes injection rate, injection pressure, and type of injection well, and its orientation, etc. The goal of GCS is to maximize the sequestration capacity and minimize the plume migration by optimizing the GCS operation. In this paper, first the basic fluid dynamics and trapping mechanisms for CO2 sequestration are briefly discussed. They are followed by a brief summary of current GCS projects worldwide with special emphasis on those in the United States. Majority of the paper is devoted to the numerical modeling, simulation, and optimization of CO2 sequestration in saline aquifers at macro spatial scales of a few to hundreds of kilometers and macro temporal scales of a few to hundreds of years. Examples of numerical simulations of a few large industrial scale projects are presented. The optimization studies include the investigation of various injection and well placement strategies to determine the optimal approach for maximizing the storage and minimizing the plume migration.

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.

Geochemical monitoring of fluid-rock interaction and CO2 storage at the Weyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada

Energy ◽  
2004 ◽  
Vol 29 (9-10) ◽  
pp. 1393-1401 ◽  
Author(s):  
S. Emberley ◽  
I. Hutcheon ◽  
M. Shevalier ◽  
K. Durocher ◽  
W.D. Gunter ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Geochemical Monitoring ◽  
Rock Interaction

scholarly journals CO2 Storage in Low Permeable Carbonate Reservoirs: Permeability and Interfacial Tension (IFT) Changes During CO2 Injection in an Iranian Carbonate Reservoir

2019 ◽  
Vol 64 (4) ◽  
pp. 491-504
Author(s):  
Mohammad Afkhami Karaei ◽  
Bizhan Honarvar ◽  
Amin Azdarpour ◽  
Erfan Mohammadian
Keyword(s):  
Interfacial Tension ◽  
Co2 Sequestration ◽  
Co2 Storage ◽  
Experimental Studies ◽  
Injection Pressure ◽  
Confining Pressure ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Co2 Injection ◽  
Permeability Alteration

The lack of fundamental experimental studies on low permeable carbonate reservoirs for CO2 sequestration purposes is essential for further application of CO2 sequestration as a highly-anticipated CO2 mitigation method in deep saline aquifers, specifically those with low permeabilities. The core samples were taken from a carbonate reservoir in Iran and the brine composition was based on that of the same formation. The objective of this study is to investigate permeability alteration during CO2 sequestration in the aquifers of a low permeable Iranian carbonate reservoir. Various parameters have been investigated. The effects of different parameters such as injection pressure, confining pressure, and temperature on permeability alteration of the cores was investigated. Moreover, the interfacial tension (IFT) of CO2/brine was also determined at pressures and temperatures up to 7 MPa and 100 °C, respectively. The experimental results showed CO2 solubility and rock dissolution to be the governing mechanism when CO2 was injected into carbonate cores. The permeability measurements showed that permeability increases by increasing injection pressure and decreases by increasing confining pressure and temperature. The IFT measurement results showed that the IFT decreases significantly when there is an increase in pressure and temperature.

Integrated CO2 Modeling Studies to Assess CO2 Sequestration Prospect in a Depleted Carbonate Gas Reservoir, Malaysia

2021 ◽  
Author(s):  
Mohd Azran A. Jalil ◽  
Sharidah M. Amin ◽  
Siti Syareena M. Ali
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
Injection Pressure ◽  
Injection Rate ◽  
Co2 Injection ◽  
Coupled Modelling ◽  
Compositional Model ◽  
Development Concept ◽  
Modelling Study

Abstract This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution. Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field. Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process. This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance for a safe and long-term CO2 sequestration.

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