scholarly journals Assessing roles of geochemical reactions on CO2 plume, injectivity and residual trapping

2021 ◽  
Author(s):  
Abdiaziz Abdullahi Maalim ◽  
Hisham Ben Mahmud ◽  
Mojtaba Seyyedi
Keyword(s):  
Residual Trapping ◽  
Geochemical Reactions ◽  
Co2 Plume

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.

A Numerical Investigation of Low Salinity Polymer Flooding Effects from a Geochemical Perspective

2021 ◽  
Author(s):  
Omar Chaabi ◽  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Aqueous Phase ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Solution Chemistry ◽  
Related Effect ◽  
Exchange Reactions ◽  
Two Phase ◽  
Low Salinity ◽  
Geochemical Reactions

Abstract Low salinity polymer (LSP) flooding is getting more attention due to its potential of enhancing both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MRST was coupled with the geochemical software IPhreeqc. The effects of polymer were captured by considering Todd-Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to PHREEQC database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST-IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against PHREEQC for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

Robust CO2 Plume Imaging Using Joint Tomographic Inversion Of Distributed Pressure And Temperature Measurements

2021 ◽  
Author(s):  
Changqing Yao ◽  
Hongquan Chen ◽  
Akhil Datta-Gupta ◽  
Sanjay Mawalkar ◽  
Srikanta Mishra ◽  
...  
Keyword(s):  
Carbon Sequestration ◽  
History Matching ◽  
Temperature Measurements ◽  
Injection Well ◽  
Co2 Injection ◽  
Pressure Data ◽  
Distributed Temperature Sensing ◽  
Data Set ◽  
Monitoring Well ◽  
Co2 Plume

Abstract Geologic CO2 sequestration and CO2 enhanced oil recovery (EOR) have received significant attention from the scientific community as a response to climate change from greenhouse gases. Safe and efficient management of a CO2 injection site requires spatio-temporal tracking of the CO2 plume in the reservoir during geologic sequestration. The goal of this paper is to develop robust modeling and monitoring technologies for imaging and visualization of the CO2 plume using routine pressure/temperature measurements. The streamline-based technology has proven to be effective and efficient for reconciling geologic models to various types of reservoir dynamic response. In this paper, we first extend the streamline-based data integration approach to incorporate distributed temperature sensor (DTS) data using the concept of thermal tracer travel time. Then, a hierarchical workflow composed of evolutionary and streamline methods is employed to jointly history match the DTS and pressure data. Finally, CO2 saturation and streamline maps are used to visualize the CO2 plume movement during the sequestration process. The power and utility of our approach are demonstrated using both synthetic and field applications. We first validate the streamline-based DTS data inversion using a synthetic example. Next, the hierarchical workflow is applied to a carbon sequestration project in a carbonate reef reservoir within the Northern Niagaran Pinnacle Reef Trend in Michigan, USA. The monitoring data set consists of distributed temperature sensing (DTS) data acquired at the injection well and a monitoring well, flowing bottom-hole pressure data at the injection well, and time-lapse pressure measurements at several locations along the monitoring well. The history matching results indicate that the CO2 movement is mostly restricted to the intended zones of injection which is consistent with an independent warmback analysis of the temperature data. The novelty of this work is the streamline-based history matching method for the DTS data and its field application to the Department of Engergy regional carbon sequestration project in Michigan.

Effect of brine salinity on CO2 plume migration and trapping capacity in deep saline aquifers

2017 ◽  
Vol 57 (1) ◽  
pp. 100 ◽  
Author(s):  
Emad A. Al-Khdheeawi ◽  
Stephanie Vialle ◽  
Ahmed Barifcani ◽  
Mohammad Sarmadivaleh ◽  
Stefan Iglauer
Keyword(s):  
Co2 Storage ◽  
Three Dimensional ◽  
Rock Properties ◽  
Saline Aquifers ◽  
Migration Distance ◽  
Deep Saline Aquifer ◽  
Plume Migration ◽  
Co2 Plume ◽  
Wet Rocks ◽  
Brine Salinity

CO2 migration and storage capacity are highly affected by various parameters (e.g. reservoir temperature, vertical to horizontal permeability ratio, cap rock properties, aquifer depth and the reservoir heterogeneity). One of these parameters, which has received little attention, is brine salinity. Although brine salinity has been well demonstrated previously as a factor affecting rock wettability (i.e. higher brine salinity leads to more CO2-wet rocks), its effect on the CO2 storage process has not been addressed effectively. Thus, we developed a three-dimensional homogeneous reservoir model to simulate the behaviour of a CO2 plume in a deep saline aquifer using five different salinities (ranging from 2000 to 200 000 ppm) and have predicted associated CO2 migration patterns and trapping capacities. CO2 was injected at a depth of 1408 m for a period of 1 year at a rate of 1 Mt year–1 and then stored for the next 100 years. The results clearly indicate that 100 years after the injection of CO2 has stopped, the salinity has a significant effect on the CO2 migration distance and the amount of mobile, residual and dissolved CO2. First, the results show that higher brine salinity leads to an increase in CO2 mobility and CO2 migration distance, but reduces the amount of residually trapped CO2. Furthermore, high brine salinity leads to reduced dissolution trapping. Thus, we conclude that less-saline aquifers are preferable CO2 sinks.

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