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.

Offshore MMV Planning for Sustainability of CO2 Storage in a Depleted Carbonate Reservoir, Malaysia

2021 ◽  
Author(s):  
Pankaj Kumar Tiwari ◽  
Debasis Priyadarshan Das ◽  
Parimal Arjun Patil ◽  
Prasanna Chidambaram ◽  
Zoann Low ◽  
...  
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
Carbonate Reservoir ◽  
Co2 Injection ◽  
Storage Site ◽  
Gas Field ◽  
Plume Migration ◽  
Co2 Plume ◽  
The Impact

Abstract CO2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, Measurement and Verification (MMV) planning of CO2 sequestration is crucial along with geological site selection, transportation and injection process. Several geological formations have been evaluated in the past for potential storage site which divulges the containment capacity of identified large, depleted gas reservoirs as well as long term conformance. Offshore environment makes MMV plan challenging and demands rigorous integration of monitoring technologies to optimize project economic and involved logistics. The role of MMV is critical for sustainability of the CO2 storage project as it ensures that injected CO2 in the reservoir is intact and safely stored for hundreds of years post-injection. Field specific MMV technologies for CO2 plume migration with proactive approach were identified after exercising pre-defined screening criteria. Marine CO2 dispersion study is carried out to confirm the impact of any potential leakage along existing wells and faults, and to understand the CO2 behavior in marine environment in the event of leakage. Study incorporates integration of G&G subsurface and Meta-Ocean & Environment data along with other leakage character information. Multi-Fiber Optic Sensors System (M-FOSS) to be installed in injector wells for monitoring well & reservoir integrity, overburden integrity and monitoring of early CO2 plume migration by acquiring & analyzing the distributed sensing data (DTS/DPS/DAS/DSS). Based on 3D couple modeling, a maximum injection rate of approximately 200 MMscfd of permeate stream produced from a high CO2 contaminated gas field can be achieved. Injectivity studies indicate that over 100 MMSCFD of CO2 injection rates into depleted gas reservoir is possible from a single injector. Injectivity results are integrated with dynamic simulation to determine number and location of injector wells. 3D DAS-VSP simulation results show that a subsurface coverage of approximately 3 km2 per well is achievable, which along with simulated CO2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. As planned injector wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume. To overcome this challenge, requirement of surface seismic acquisition survey is recommended for full field monitoring. An integrated MMV plan is designed for cost-effective long-term offshore monitoring of CO2 plume migration. The present study discusses the impacting parameters which make the whole process environmentally sustainable, economically viable and adhering to national and international regulations.

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.

Overcoming CO2 Injector Well Design and Completion Challenges in a Carbonate Reservoir for World's First Offshore Carbon Capture Storage CCS SE Asia Project

2021 ◽  
Author(s):  
Mahesh S. Picha ◽  
M. Azuan B. Abu Bakar ◽  
Parimal A. Patil ◽  
Faiz A. Abu Bakar ◽  
Debasis P. Das ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Injection Pressure ◽  
Co2 Concentration ◽  
Carbonate Reservoir ◽  
Seismic Survey ◽  
Co2 Injection ◽  
Injection Wells ◽  
Gas Field ◽  
Accelerated Corrosion ◽  
Well Design

Abstract Oil & Gas Operators are focusing on zero carbon emission to comply with government's changing rules and regulations, which play an important role in the encouragement of carbon capture initiatives. This paper aims to give insights on the world's first offshore CCS project in carbonate reservoir, where wells will be drilled to inject CO2, and store produced CO2 from contaminated fields. To safeguard the storage containment, the integrity of all wells needs to be scrutinized. Development wells in the identified depleted gas field are more than 40 years old and were not designed with consideration of high CO2 concentration in the reservoir. In consequence, the possibility of well leakage due to accelerated corrosion channeling and cracks, along the wellbore cannot be ignored and require careful evaluation. Rigorous process has been adopted in assessing the feasibility for converting existing gas producers into CO2 injectors. The required defined basis of designs for gas producer and CO2 injection wells differs in a great extent and this governs the re-usability of wells for CO2 injection or necessity to be abandoned. Three (3) new CO2 injectors with fat to slim design approach, corrosion resistant alloy (CRA) material and CO2 resistant cement are designed in view to achieve lifecycle integrity. Optimum angle of 53 deg and maintaining the injection pressure of 50 bar at 90 MSCFD rate is required for the injection of supercritical CO2 for 20 years. During well execution, challenges such as anti-collision risk, total loss scenarios while drilling in Carbonate reservoir need to be addressed before execution. The completion design is also focusing on having minimal number of completion jewelries to reduce pressure differential and potential leak paths from tubing hangar down to the end of lower completion. The selection of downhole safety valve (TRSV) type is of high importance to accommodate CO2 phase attributes at different pressure/temperature. Fiber Optic is included for monitoring the migration of CO2 plume by acquiring seismic survey and for well integrity by analyzing DAS/DTS data.

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.

Long-term Strategy Optimization of Scale Squeeze Treatment in a Carbonate Reservoir Under CO2-WAG Water-Alternating-Gas Injection

2021 ◽  
Author(s):  
Vahid Azari ◽  
Hydra Rodrigues ◽  
Alina Suieshova ◽  
Oscar Vazquez ◽  
Eric Mackay
Keyword(s):  
Net Present Value ◽  
Co2 Storage ◽  
Gas Injection ◽  
Carbonate Reservoir ◽  
Co2 Injection ◽  
Base Case ◽  
Production Well ◽  
Water Alternating Gas ◽  
Gradient Descent Algorithm

Abstract The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition. Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle. The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window. The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.

An Experimental Study of the Effects of CO2 Injection on Gas/Condensate Recovery and CO2 Storage in Gas-Condensate Reservoirs

2021 ◽  
Author(s):  
Ifeanyi Seteyeobot ◽  
Mahmoud Jamiolahmady ◽  
Philip Jaeger ◽  
Abdulelah Nasieef
Keyword(s):  
Co2 Storage ◽  
Injection Pressure ◽  
Gas Condensate ◽  
Phase Behaviour ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Experimental Phase ◽  
Co2 Gas ◽  
Gas Condensate Reservoirs ◽  
Core Flood

Abstract The application of non-hydrocarbon gas injection for enhanced gas and condensate recovery (EGCR) is still in a developmental stage as the mixing/interaction between the injected gas and resident reservoir fluid is yet to be extensively understood and the inability to optimize the recovery process has led to limited pilot trials. Carbon dioxide (CO2) injection into gas-condensate reservoirs for improved recovery and CO2 storage provides additional and favorable changes in phase and fluid flow behaviour making it economically more attractive compared to other injection gases. However, to make an informed decision, adequate phase and flow behaviour analysis are required to better forecast the reservoir performance under CO2 injection. In this research, appropriate experimental phase behaviour, EOS modeling, and unsteady-state flow tests have been conducted to determine the level of CO2/gas-condensate interaction including condensing/vaporizing mechanisms during CO2 Huff-n-Puff (HnP) injection. A CO2 HnP injection technique was followed to identify the best CO2 flooding conditions. A total of four HnP injection cycles with incremental CO2 volumes of 20, 40, 60, and 80 % of the initial resident fluid volume prior to depletion was considered. CO2 injection pressure and volume are optimized below the saturation pressure. The analysis is based on evaluating the level of interaction between CO2 and resident fluid at the maximum condensate saturation of the corresponding CO2-gas-condensate fluid mixture as determined in a phase equilibria cell. Appropriate experimental phase behaviour and core flood data were generated and analyzed to identify and quantify the level of condensing/vaporizing mechanisms which are vital for adequate optimization of the injection pressure and amount of injected CO2 for both enhanced gas and condensate recovery and CO2 storage purposes. The amount of gas, condensate, and CO2 produced at each core flood stage was recorded. These data allow bridging the gap between conflicting reports on the trend and level of CO2/gas-condensate fluid interactions at pressures below the dew point pressure (Pdew). They also provide a better knowledge of the governing mechanisms during CO2 flooding, which are required for designing appropriate CO2 HnP injection for reservoir engineering applications.

An Experimental and Simulation Study of CO2 Sequestration in an Underground Formations; Impact on Geomechanical and Petrophysical Properties

2021 ◽  
Author(s):  
Sobia Fatima ◽  
Hafiz Muhammad Mutahhar Khan ◽  
Zeeshan Tariq ◽  
Mohammad Abdalla ◽  
Mohamed Mahmoud
Keyword(s):  
Simulation Model ◽  
Reaction Kinetics ◽  
Co2 Sequestration ◽  
Laboratory Experiments ◽  
Co2 Storage ◽  
Storage Period ◽  
Simulation Software ◽  
Carbonate Reservoir ◽  
Petrophysical Properties ◽  
Porosity And Permeability

Abstract Carbon dioxide (CO2) sequestration is a technique to store CO2 into an underground formation. CO2 can cause a severe reaction with the underground formation and injection tubing inside the well. Successful CO2 storage into underground formations depends on many factors such as efficient sealing, no escaping from the storage, and minimum corrosion to injection tubing/casing. Therefore, proper planning involving thorough study and reaction kinetics of CO2 with the underground formation is indeed necessary for proper planning. The main aim and objective of this study are to investigate the effect of CO2 storage with different cap rocks such as tight carbonate and shale under simulated reservoir conditions. The samples were stored for different times such as 10, 20, and 120 days. The objectives of the study were achieved by carrying out extensive laboratory experiments before and after sequestration. The laboratory experiments included were rock compressive and tensile strength tests, petrophysical tests, and rock mechanical tests. The laboratory results were later used to investigate the reaction kinetics study of CO2 with the underground formation using CMG simulation software. The effect of injection rate, the point of injection, purity of the injection fluid, reservoir heterogeneity, reservoir depth, and minimum miscibility pressure was analyzed. In this simulation model, CO2 is injected for 25 years using CMG-GEM simulation software and then the fate of CO2 post injection is modeled for the next 225 years. The simulation results showed a notable effect on the mechanical strength and petrophysical parameters of the rock after sequestration, also the solubility of CO2 decreases with the increase in salinity and injection pressure. The results also showed that the storage of CO2 increases the petrophysical properties of porosity and permeability of the formation rock when the storage period is more than 20 days because of calcite precipitation and CO2 dissolution. A storage period of fewer than 20 days does not show any significant effect on the porosity and permeability of carbonate reservoir rock. A sensitivity analysis was carried out which showed that the rate of CO2 sequestration is sensitive to the mineral-water reaction kinetic constants. The sensitivity of CO2 sequestration to the rate constants decreases in magnitude respectively for different clay minerals. The new simulation model considers the effect of reaction kinetics and geomechanical parameters. The new model is capable of predicting the compatibility of CO2 sequestration for a particular field for a particular time.

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.

Feasibility Investigation and Modeling Analysis of CO2 Sequestration in Arbuckle Formation Utilizing Salt Water Disposal Wells

2009 ◽  
Vol 131 (2) ◽  
Author(s):  
Jamal Daneshfar ◽  
Richard G. Hughes ◽  
Faruk Civan
Keyword(s):  
Co2 Sequestration ◽  
Power Plants ◽  
Oil And Gas ◽  
Chemical Interaction ◽  
Salt Water ◽  
Injection Pressure ◽  
Simulation Models ◽  
Co2 Production ◽  
Co2 Injection ◽  
Reservoir Properties

The rate of CO2 production in many states, primarily from coal-fired power plants, is such that it only takes a few years to fill up any depleted oil and gas reservoirs. In order to reduce the level of CO2 in the atmosphere and to minimize the cost of sequestration, the injection of CO2 into aquifers utilizing disposal wells has been targeted. In this paper, an analysis of one particular case, namely, the Arbuckle formation in Oklahoma, was carried out to demonstrate its feasibility for CO2 sequestration. First, a general review for CO2 sequestration into aquifers utilizing existing disposal wells is presented. The limiting criteria for CO2 sequestration in terms of the geology of the aquifer, lithology of the host rock, cost of operation, impact on reservoir properties, depth of the completed interval to maintain supercritical conditions for CO2, injection pressure and rate to minimize gravity segregation, mobility ratio to prevent viscous fingering, and chemical interaction of aqueous and solid phases are discussed. Then, the existence of residual oil in the aquifer and its effect on reaction chemistry concerning the potential CO2 sequestration applications in the Arbuckle formation are evaluated. This investigation was conducted by means of simulation of the prevailing processes. The cutoff points from dissolution to precipitation for each constituent in terms of different CO2 injection rates were obtained by utilizing the simulation models GEM-GHG and PHREEQC and were supported by a database of 150 disposal wells from which 25 wells were completed in the Arbuckle formation. We critically evaluate the current state of knowledge, identify areas needing research, and offer practical approaches for the evaluation of potential CO2 sequestration sites using commercial disposal wells.

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