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Review Article

Modeling, Simulation, and Optimization of Geological Sequestration of CO2

[+] Author and Article Information
Ramesh K. Agarwal

Department of Mechanical Engineering and
Materials Science,
Washington University in St. Louis,
St. Louis, MO 63130

Contributed by the Fluids Engineering Division of ASME for publication in the JOURNAL OF FLUIDS ENGINEERING. Manuscript received August 23, 2018; final manuscript received March 6, 2019; published online April 25, 2019. Editor: Francine Battaglia.

J. Fluids Eng 141(10), 100801 (Apr 25, 2019) (26 pages) Paper No: FE-18-1550; doi: 10.1115/1.4043164 History: Received August 23, 2018; Revised March 06, 2019

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.

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Figures

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Fig. 1

Schematic of carbon capture and sequestration [7]

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Fig. 2

Four major trapping mechanisms of GCS [7]

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Fig. 3

Trapping mechanisms and their dominant timeframes, storage contribution, storage security, and governing principles [1]

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Fig. 4

Spatial scale of different processes and features for GCS [11,12]

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Fig. 5

Time scale of different processes and features for GCS [11,12]

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Fig. 6

Assessment of CO2 leakage rate with time: (a) present results and (b) results obtained using various codes [14]

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Fig. 7

Variation of CO2 and CH4 mass-flux with time: (a) present results and (b) results obtained using various codes [14]

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Fig. 8

Variation of CO2 accumulation with time: (a) present results and (b) results obtained using various codes [14]

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Fig. 9

Schematic of integrated simulation and optimization code GA-TOUGH2 [14]

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Fig. 10

Core injection area and elevation of Mt. Simon Sandstone [19]

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Fig. 11

(a) Permeability, (b) porosity, and computational mesh of the 24 sublayers of the Mt. Simon formation model at WH #1 well [14]

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Fig. 12

Saturation of gaseous CO2 at (a) 5th, (b) 25th, and (c) 50th year of injection [20]

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Fig. 13

Seismic image of Utsira formation after 9-years of injection, S–N cross section [22]

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Fig. 14

Computational mesh and layered structure of the generalized nine-layered model of Utsira formation [14]

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Fig. 15

In situ CO2 distribution for 15 years of injection in Utsira formation model [14]

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Fig. 16

Gaseous CO2 accumulation in the topmost sandstone layer [14]

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Fig. 17

Amplitude maps of layer #9 from 1999 to 2008 from Singh et al. [23]

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Fig. 18

Three-dimensional overview and plan-view of the 3D layer #9 model of Utsira indicating feeder locations (black dot: main feeder; cyan square: secondary feeder) [24]

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Fig. 19

Simulated CO2 migration in layer #9 of Utsira formation, 2000–2008 [14]

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Fig. 20

Schematic of a typical WAG cycle

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Fig. 21

Generic domain for optimization of WAG operation with a vertical injection well

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Fig. 22

Schematic of the optimized WAG operation with vertical well injection

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Fig. 23

Radial gas saturation comparisons of optimized WAG operation and the nonoptimized CGI operation for vertical injection well

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Fig. 24

Quarter computational domain for WAG operation with horizontal injection well

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Fig. 25

Schematic of the optimal WAG operation with horizontal injection well

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Fig. 26

Radial gas saturation comparisons of optimized WAG operation and nonoptimized CGI operation using a horizontal injection well

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Fig. 27

SG underneath the caprock; optimized WAG and nonoptimized injection operations in an anisotropic saline aquifer

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Fig. 28

SG contours for optimized WAG and three nonoptimized injection operations

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Fig. 29

Reservoir pressure response of optimized WAG and three nonoptimized injection schemes

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Fig. 30

Schematic of optimized WAG operation for Utsira layer #9 model

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Fig. 31

SG underneath the caprock showing plume reduction with optimized WAG injection for Utsira layer #9 model

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Fig. 32

Schematic of injection pressure response with time under various CO2 injection rates

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Fig. 33

Schematic of a cubic (third-order) Bézier curve

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Fig. 34

Injection pressure and injection rate of the optimized CPI operation, and its comparison with low-rate CGI and high-rate CGI

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Fig. 35

Computational domain of four-well injection systems with various interwell distances

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Fig. 36

Pressure profile at the cross section: wells (a) 600 m apart, (b) 800 m apart, (c) 1200 m apart, and (d) 1600 m apart

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Fig. 37

Gas saturation underneath the caprock at the cross section: wells (a) 600 m apart, (b) 800 m apart, (c) 1200 m apart, and (d) 1600 m apart

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