Quantitative Estimate of Site Injectivity in Saline Formations for CO2 SequestrationQi Fang, Yilian Li, Wei Zhang, Peng Cheng, Sanxi Peng, Yibing Ke, Ronghua Wu
School of Environmental studies, China University of Geosciences, Wuhan, Hubei 430074,P.R. China.
Optimization of the methodology to assess the suitability of
potential geological sequestration sites is one of the most
challenging research areas to deploy CCS effectively and safely
on a global scale. Site selection is a fundamental step that
conditions the success of a CO2 storage operation. Assessing a
potential site whether or not suitable for CO2 geological
sequestration, three most important factors which are injectivity,
capacity and containment are considered . Injectivity can be
defined as the rate at which CO2 will be injected before pressure
buildup goes beyond given threshold values (Sandrine Grataloup
et al , 2009) . I t depends on reservoir permeabil i ty,
thermodynamics conditions, which determine CO2 density and
viscosity, reservoir thickness available for injection, and
mechanical properties of both reservoir and caprock. The main
goal of the present work is to put forward a quantitative method
to assess the site injectivity in terms of maximum pressure
buildup determined by different geological parameters which can
be used to quickly judge whether a saline formation can be a
candidate for CO2 sequestration. The approach used in this work
consists of the following two steps: first to select the key
parameters influencing the pressure buildup, and then to carry
out the batch simulations to get enough results which could be
used to develop multiple regression relationships.
In this model, the radial, two-dimensional model was established
to study the reservoir injectivity and seal capacity, including
three geological layers which represent saline aquifer as target
formation, sealing layers and extra top aquifer as to test the CO2
leakage, respectively. The ECO2N module of the TOUGH2 code
(Pruess, 2005) was used to simulate the CO2-water flow in a
deep aquifer during CO2 injection over 50 years.
The data on maximum reservoir pressure buildup after 7days, 15
days, 30 days, 180 days, 1 year, 5years, 10years and 50years
after CO2 injection were extracted and partial correlation
analysis was made to study the dependence between the
maximum pressure buildup and different parameters as listed
above. The most four significant parameters influencing
affecting the pressure buildup are permeability of reservoir, the
initial temperature and pressure and thickness of reservoir which
all pass the test of significance with the confidence coefficient
0.05. The maximum fluid buildup pressure has a remarkable
negative relationship with permeability of reservoir,
thickness of reservoir and initial temperature.
Injectivity can be defined as the rate at which CO2 will be
injected before pressure buildup goes beyond given threshold
values. When the buildup pressure is smaller than 150% of the
initial hydrostatic pressure, the rock will be safe(Zhou quanlin,
2008). In the following simulations, four parameters were
divided into three pairs which are initial pressure and
permeability, initial pressure and reservoir thickness as well as
the initial pressure and temperature, respectively coupled with
five injection rates.
Fig. 1: Pressure change with permeability and initial pressure at different rates
Ten easy-available parameters influencing CO2 sequestration
in saline formations were chosen to study their significances
to pressure buildup. Each parameter was given five different
values and the experimental design approach was used to
reduce the number of simulations into 50 since the experimental
design approach allows large reduction in the number of the
simulations while retaining statistical significance. The
combinations of different parameters with different levels
are shown in table 1 in detail.
Introduction
Parameters selection
Table 1 : parameters chosen and values given
No. Parameters Value 1 Value 2 Value 3 Value 4 Value 5
1 Porosity of aquifer 0.1 0.15 0.2 0.25 0.3
2 Permeability of aquifer (mD) 50 100 200 300 500
3 Thickness of aquifer (m) 50 60 70 80 100
4 Porosity of caprock 0.01 0.03 0.05 0.08 0.10
5 Permeability of caprock (mD) 10-1 10-2 10-3 10-4 10-5
6 Thickness of caprock (m) 10 20 30 40 50
7Ratio of vertical to horizontal
permeability (Kv/Kh)1.0 0.5 0.3 0.2 0.1
8 Water salinity 0.05 0.1 0.15 0.2 0.25
9 Initial temperature (℃) 45 51 60 75 90
10 Initial pressure (bar) 100 120 150 200 250
Batch simulation and results
Initial pressure, permeability, rate & buildup pressure
Table 2: Initial condition and model setup
Thickness 100m
Temperature 60℃
Initial pressure 70bar, 100bar, 130bar, 160 bar, 190bar, 220bar, 250bar
Permeability 50mD, 100mD, 200mD, 300mD, 400mD,500mD
Injection rate 15.85kg/s(0.5Mt/yr), 31.7kg/s(1Mt/yr), 63.4kg/s(2Mt/yr),
95.1kg/s(4Mt/yr), 126.8kg/s(4Mt/yr), 148.5kg/s(5Mt/yr)
Fig. 2: Maximum pressure contour with permeability and initial pressure at different rates
Initial pressure, thickness, rate & buildup pressure
Table 3: Initial condition and model setup
Permeability 200mD
Temperature 60℃
Initial pressure 70bar, 100bar, 130bar, 160 bar, 190bar, 220bar, 250bar
Thickness 20m, 40m, 60m, 80m, 100m, 120m
Injection rate 15.85kg/s(0.5Mt/yr), 31.7kg/s(1Mt/yr), 63.4kg/s(2Mt/yr),
95.1kg/s(4Mt/yr), 126.8kg/s(4Mt/yr), 148.5kg/s(5Mt/yr)
Fig. 3: pressure change with thickness and initial pressure at different rates
Fig. 4: Maximum pressure contour with thickness and initial pressure at different rates
Initial pressure, temperature, rate & buildup pressure
Table 4: Initial condition and model setup
Permeability 200mD
Thickness 100m
Initial pressure 70bar, 100bar, 130bar, 160 bar, 190bar, 220bar, 250bar
Temperature 30℃, 45℃, 60℃, 75 ℃, 90 ℃
Injection rate 15.85kg/s(0.5Mt/yr), 31.7kg/s(1Mt/yr), 63.4kg/s(2Mt/yr),
95.1kg/s(4Mt/yr), 126.8kg/s(4Mt/yr), 148.5kg/s(5Mt/yr)
Fig. 6: Maximum pressure contour with temperature and initial pressure at different rates
Fig. 5: Pressure change with temperature and initial pressure at different rates
Multiple Regression relationships
Initial pressure, permeability, rate & buildup pressure
Pmax= 92.308 + 0.956P0 - 0.212K + 0.461Rt With R= 0.949
Initial pressure, thickness, rate & buildup pressure
Pmax= 91.31 + 0.944P0 - 0.568Th + 0.530Rt With R= 0.896
Initial pressure, temperature, rate & buildup pressure
Pmax= 49.090 + 0.956P0 - 0.381T + 0.555Rt With R= 0.995
All parameters included
Pmax= 148.764+0.952P0 – 0.190K – 0.484Th -0.381T + 0.495Rt With R= 0.936
Parameters description
Pmax maximum buildup pressure (bar)
Po initial hydrostatics pressure (bar)
K reservoir permeability (mD)
Th reservoir thickness (m)
T reservoir temperature (℃)
Rt injection rate (kg/s)
Case1: Injection rate = 0.5Mt/yr
0
10
20
30
40
50
60
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge (
bar) 20m
40m
60m
80m
100m
120m
Case2: Injection rate = 1 Mt/yr
10
20
30
40
50
60
70
80
90
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge (
bar) 20m
40m
60m
80m
100m
120m
Case4: Injection rate = 3 Mt/yr
40
60
80
100
120
140
160
180
200
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge (
bar)
20m
40m
60m
80m
100m
120m
Case3: Injection rate = 2 Mt/yr
30
50
70
90
110
130
150
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
hang
e (
bar)
20m
40m
60m
80m
100m
120m
Case6: Injection rate = 5 Mt/yr
60
80
100
120
140
160
180
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge (
bar)
40m
60m
80m
100m
120m
Case5: Injection rate = 4 Mt/yr
50
70
90
110
130
150
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge (
bar)
40m
60m
80m
100m
120m
Case1: Injection rate = 0.5Mt/yr
0
10
20
30
40
50
60
70
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
)
50mD
100mD
200mD
300mD
400mD
500mD
Case2: Injection rate = 1 Mt/yr
0
20
40
60
80
100
120
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
)
50mD
100mD
200mD
300mD
400mD
500mD
Case3: Injection rate = 2 Mt/yr
0
20
40
60
80
100
120
140
160
180
50 100 150 200 250
Initial pressure (bar)
Pre
ssure
chan
ge
(bar
)
50mD
100mD
200mD
300mD
400mD
500mD
Case4: Injection rate = 3 Mt/yr
0
20
40
60
80
100
120
140
50 100 150 200 250
Initial pressure (bar)
Pre
ssure
chan
ge
(bar
)
100mD
200mD
300mD
400mD
500mD
Case5: Injection rate = 4 Mt/yr
0
20
40
60
80
100
120
140
160
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
)
100mD
200mD
300mD
400mD
500mD
Case6: Injection rate = 5 Mt/yr
0
20
40
60
80
100
120
140
160
180
200
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re b
uil
du
p (
bar
)
100mD
200mD
300mD
400mD
500mD
Case1: Injection rate = 0.5Mt/yr
10
12
14
16
18
20
22
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
) 30℃
45℃
60℃
75℃
90℃
Case3: Injection rate = 2 Mt/yr
30
40
50
60
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
)
30℃
45℃
60℃
75℃
90℃
Case2: Injection rate = 1 Mt/yr
10
15
20
25
30
35
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
)
30℃
45℃
60℃
75℃
90℃
Case4: Injection rate = 3 Mt/yr
30
40
50
60
70
80
90
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
)
30℃
45℃
60℃
75℃
90℃
Case5: Injection rate = 4 Mt/yr
40
50
60
70
80
90
100
110
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re c
han
ge
(bar
)
30℃
45℃
60℃
75℃
90℃
Case6: Injection rate = 5 Mt/yr
405060708090
100110120130
50 100 150 200 250
Initial pressure (bar)
Pre
ssu
re b
uid
up
(b
ar) 30℃
45℃
60℃
75℃
90℃