quantitative estimate of site injectivity in saline …4 porosity of caprock 0.01 0.03 0.05 0.08...

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

Permeability 200mD

Temperature 60℃

Thickness 20m, 40m, 60m, 80m, 100m, 120m

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

Permeability 200mD

Thickness 100m

Temperature 30℃, 45℃, 60℃, 75 ℃, 90 ℃

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

50 100 150 200 250

Initial pressure (bar)

bar) 20m

Case2: Injection rate = 1 Mt/yr

50 100 150 200 250

bar) 20m

50 100 150 200 250

) 30℃

50 100 150 200 250

405060708090

100110120130

50 100 150 200 250

ar) 30℃

quantitative estimate of site injectivity in saline …4 porosity of caprock 0.01 0.03 0.05 0.08...

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