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Salt Precipitation During CO2 Injection and Changes in Reservoir Porosity and
Permeability
Presentation · June 2016
DOI: 10.13140/RG.2.1.1984.4083
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Marinus van Dijke
Tsinghua University
Heriot-Watt University
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Heriot-Watt University
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Porosity-Permeability Relationships in Modeling
Salt Precipitation During CO2 Sequestration
Shuo Zhanga , Hui-Hai Liua , Marinus I.J. van Dijkeb , Sebastian
Geigerb , Susan Agara
a
Aramco Research Center - Houston
b
Heriot-Watt University
Overview
Introduction
Porosity-Permeability Relationships
Theory Development
Numerical Implementation, Case Study
Discussions
Overview
Introduction
Porosity-Permeability Relationships
Theory Development
Numerical Implementation, Case Study
Discussions
Salt Precipitation in CO2 Sequestration
I
I
I
I
I
I
Water evaporates into dry gas
Salt precipitation affects CO2 injectivity
Observed in natural gas producing and
storage wells
Kleinitz et al. (2003),Place Jr et al. (1984)
Extra pressure build-up in CO2 projects
Baumann et al. (2014), Grude et al. (2014)
Numerical studies
Pruess and Müller (2009)
Experimental studies
Ott et al. (2012)
Ott et al. (2015)
Source: Eric Mackay
Will The Reservoir Be Clogged?
Numerical Studies
Giorgis et al. (2007)
I
I
Two-phase Darcy flow
K0 , Kw (Sw ), Kg (Sw )
Capillary pressure
Pc(Sw )
I
Salt precipitation
„
I
Permeability change
K („)
Experiments
Peysson et al. (2014)
Andre et al. (2014)
Wang et al. (2010)
Overview
Introduction
Porosity-Permeability Relationships
Theory Development
Numerical Implementation, Case Study
Discussions
Porosity-Permeability Relationships in Literature
Publication
Pruess and Müller (2009)
Andre et al. (2014)
Giorgis et al. (2007)
Zeidouni et al. (2009)
Wang et al. (2010)
Porosity-permeability relation
k
„/„0 ≠ „r 2
=(
) , „r = 0.9
k0
1 ≠ „r
k
„/„0 ≠ „r 2
=(
) , „r = 0.91
k0
1 ≠ „r
k
„/„0 ≠ „r ·
=(
) , „r = 0.3, · = 4.1
k0
1 ≠ „r
k
„
1 ≠ „0 2
= ( )3 (
) , „0 = 0.12
k0
„0
1≠„
k
„
1 ≠ „0 2
= ( )c (
) , c = 2.4
k0
„0
1≠„
Relation type
Verma and Pruess
Verma and Pruess
Verma and Pruess
Carman-Kozeny
Carman-Kozeny
Carman-Kozeny Relation - Assumes Uniform Pore Size
I
Define porosity
I
Define permeability
Ô
„ = nt fir 2 ·
k=
I
fint r 4
Ô
8 ·
Porosity-permeability relationship
„r 2
8·
I After some algebra manipulation
k=
k=C
„3
(1 ≠ „)2
I
New permeability for new porosity
k
(1 ≠ „i )2 „ 3
=
( )
ki
(1 ≠ „)2 „i
Overview
Introduction
Porosity-Permeability Relationships
Theory Development
Numerical Implementation, Case Study
Discussions
van Genuchten/Mualem’s Relative Permeability Model
Capillary Pressure (Pa)
106
van Genuchten
PNM
105
S=[1+(– h)n ]-m
∆
104
103
0.2
0.3
0.4
0.5 0.6 0.7
Saturation
r = 1/h, Dv (r ) =
0.8
dS
dr
0.9
1
sr
rdr 2
)
0 rdr
krw (S) = S 1/2 [1 ≠ (1 ≠ S 1/m )m ]2
krw
=S
1/2
0
(s Œ
Change of Pore Size Distribution
I
I
I
I
I
The ratio of pore volume after salt precipitation to that before precipitation
Sw ≠ Ss
—=
Sw
The ratio of hydraulic radius
” = — ‰ , ‰ = 4.5
The ratio ofs permeability s
rp
Œ
”—rf (r )dr + rp rf (r )dr
K
0
sŒ
= · 1/2 [
]2
K0
rf
(r
)dr
0
Van Genuchten
relation
sr
rf (r )dr
0
f (S) = s Œ
= 1 ≠ (1 ≠ S 1/m )m
rf
(r
)dr
0
The ratio of permeability
K
= · 1/2 [(”— ≠ 1)(1 ≠ (1 ≠ S 1/m )m ) + 1]2
K0
New Constitutive Relations Between Mineral Reactions and
Multi-Phase Flow Properties
I
h(S) =
I
kw
kw 0
I
kg
kg0
I
I
I
h0 (S)
”
h0 (S)
S Æ Sp
S > Sp
Y 3 2
S Æ Sp
]” —
S ≠ Sp + ” 2 Sp 1/2 f (S) + (”— ≠ 1)f (Sp ) 2
=
) [
] S > Sp
[(
S
f (S)
Y
] (Sp ≠ S)” 2 + (1 ≠ Sp ) 1/2 1 ≠ ”—f (S) + (”— ≠ 1)f (Sp ) 2
] [
]
= [
1≠S
1 ≠ f (S)
[
1
Continuum scale, closed-form relations
No new measurements needed
S Æ Sp
S > Sp
Pore Network Modeling, Numerical Estimation of Pc, Kr
Source: Sebastian Geiger, HWU
Pore Network Model and Initial Capillary Pressure Curve
Capillary Pressure (Pa)
106
9.77 mm3 of Berea Sandstone
Blue: Water, Red: CO2
van Genuchten
PNM
105
S=[1+(– h)n ]-m
104
103
0.2
0.3
0.4
0.5 0.6 0.7
Saturation
0.8
0.9
1
Compare with Pore Network Modeling
Capillary Pressure (Pa)
106
Our Model
PNM post precipitation
PNM initial
I
105
I
104
I
103
0.2
0.3
0.4
0.5 0.6 0.7
Saturation
0.8
0.9
1
Capillary pressure increases due to
precipitation
Only water occupied pores are
modified (S=0.2-0.5)
Discontinuity at S=0.5 well
captured by close-form equation
Change in Relative Permeability
Relative permeability of water
10≠1
I
10
≠3
I
10≠5
10≠7
I
10≠9
Our Model
PNM post precipitation
PNM initial
10≠11
0.2
0.3
0.4
0.5 0.6 0.7
Saturation
0.8
0.9
I
1
Decrease porosity from 0.24 to 0.22
New model predicts relative
permeability satisfactorily
No tunable parameters
Changes in relative permeability - 2
orders of magnitude
Change in Permeability
100
Permeability ratio
I
10≠1
I
10
≠2
10≠3
0.19
Our model
PNM data
Traditional approach
0.2
0.21
0.22
Porosity
0.23
I
0.24
Zhang, Liu, Geiger, van Dijke, Agar, submitted to TIPM
Traditional approach predicts
exponential decrease of
permeability
Only water occupied pores should
be modified for multi-phase flow
Permeability does not decrease to
zero
Overview
Introduction
Porosity-Permeability Relationships
Theory Development
Numerical Implementation, Case Study
Discussions
Salt Precipitation by CO2 Dry-Out
Porosity-permeability relationship
k
„ ≠ „c n
=(
) , „c = 0.9, n = 2
ki
„i ≠ „c
Pruess and Müller (2009)
Injection pressure exceeds limit due
to reduced permeability
New Code Predicts Less Reduction in Permeability
1
Verma Pruess
New Model
Permeability Ratio
0.8
0.6
0.4
0.2
0
10≠1
100
101
102
103
Radial distance (m)
104
105
New Code Predicts Less Increase in Injection Pressure
·107
Verma Pruess
New Model
Pressure (Pa)
5
I
4
I
3
I
2
I
1
10≠1
100
101
102
103
Radial distance (m)
Zhang and Liu, submitted to IJGGC
104
105
Permeability does not decrease to
zero
No big increase in injection pressure
Do not require pre-flushing with
fresh water
Supported by field evidence in CO2
pilot projects
Overview
Introduction
Porosity-Permeability Relationships
Theory Development
Numerical Implementation, Case Study
Discussions
Does Salt Precipitate in Aqueous Phase?
I
I
I
Ott et al. (2015)
Initial CO2 and salt occupy
complementary space
Overlap less than 5%
Does Salt Precipitate in Aqueous Phase?
I
I
I
I
I
Miri et al. (2015)
Experiment on a chip
Strong film flow
Salt precipitates in gas
phase
Not common in porous
media
What is the Experimentally Measured Porosity-Permeability
Relationship
I
I
I
Bacci et al. (2013)
I
Follow the Verma and
Pruess (1988) model
Average porosity and
permeability change of the
entire core
Representative element
volume: one slice of the
core
Valid only for homogeneous
precipitation
What is the Experimentally Measured Porosity-Permeability
Relationship
I
I
I
I
Ott et al. (2015)
Low flow rate: capillary
back flow
Precipitation close to
injection surface
High flow rate: uniform
precipitation
What is the Experimentally Measured Porosity-Permeability
Relationship
I
Wang et al. (2010) measurement,
I
Our model,
I
Verma and Pruess (1988) model,
k
= 0.50 v 0.57
k0
k
= 0.55
k0
k
= 0.0017
k0
Will Salt Clog the Reservoir?
Andre et al. (2014)
Conclusions
I
Salt precipitates in aqueous phase
I
CO2 pathways stay open
I
Capillary back flow may cause clogging
I
New porosity-permeability relations for numerical simulations
I
Interpret experimental data for the right REVs
Acknowledgments
Hui-Hai Liu
Sebastian Geiger
Rink van Dijke
Susan Agar
Thank you/Questions?
References I
Andre, L., Peysson, Y., Azaroual, M., 2014. Well injectivity during co 2 storage operations in deep saline
aquifers–part 2: Numerical simulations of drying, salt deposit mechanisms and role of capillary forces.
international journal of Greenhouse Gas Control 22, 301–312.
Bacci, G., Durucan, S., Korre, A., 2013. Experimental and numerical study of the effects of halite scaling on
injectivity and seal performance during co 2 injection in saline aquifers. Energy Procedia 37, 3275–3282.
Baumann, G., Henninges, J., De Lucia, M., 2014. Monitoring of saturation changes and salt precipitation during
co 2 injection using pulsed neutron-gamma logging at the ketzin pilot site. International Journal of
Greenhouse Gas Control 28, 134–146.
Giorgis, T., Carpita, M., Battistelli, A., 2007. 2d modeling of salt precipitation during the injection of dry co 2
in a depleted gas reservoir. Energy Conversion and Management 48 (6), 1816–1826.
Grude, S., Landrø, M., Dvorkin, J., 2014. Pressure effects caused by co 2 injection in the tubåen fm., the
snøhvit field. International Journal of Greenhouse Gas Control 27, 178–187.
Kleinitz, W., Dietzsch, G., Köhler, M., 2003. Halite scale formation in gas-producing wells. Chemical
Engineering Research and Design 81 (3), 352–358.
Miri, R., van Noort, R., Aagaard, P., Hellevang, H., 2015. New insights on the physics of salt precipitation
during injection of co 2 into saline aquifers. International Journal of Greenhouse Gas Control 43, 10–21.
Ott, H., de Kloe, K., van Bakel, M., Vos, F., van Pelt, A., Legerstee, P., Bauer, A., Eide, K., van der Linden,
A., Berg, S., Makurat, A., 2012. Core-flood experiment for transport of reactive fluids in rocks. Review of
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URL http://scitation.aip.org/content/aip/journal/rsi/83/8/10.1063/1.4746997
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in unimodal sandstone. International Journal of Greenhouse Gas Control 43, 247–255.
References II
Peysson, Y., Andre, L., Azaroual, M., 2014. Well injectivity during co 2 storage operations in deep saline
aquifers—part 1: Experimental investigation of drying effects, salt precipitation and capillary forces.
international journal of Greenhouse Gas Control 22, 291–300.
Place Jr, M., Smith, J., et al., 1984. An unusual case of salt plugging in a high-pressure sour gas well. In: SPE
Annual Technical Conference and Exhibition. Society of Petroleum Engineers.
Pruess, K., Müller, N., 2009. Formation dry-out from co2 injection into saline aquifers: 1. effects of solids
precipitation and their mitigation. Water Resources Research 45 (3).
Verma, A., Pruess, K., 1988. Thermohydrological conditions and silica redistribution near high-level nuclear
wastes emplaced in saturated geological formations. Journal of Geophysical Research: Solid Earth
(1978–2012) 93 (B2), 1159–1173.
Wang, Y., Luce, T., Ishizawa, C., Shuck, M., Smith, K., Ott, H., Appel, M., 2010. Halite precipitation and
permeability assessment during supercritical co2 core flood. In: International symposium of the society of
core analysis, Halifax. pp. 4–7.
Zeidouni, M., Pooladi-Darvish, M., Keith, D., 2009. Analytical solution to evaluate salt precipitation during co 2
injection in saline aquifers. International Journal of Greenhouse Gas Control 3 (5), 600–611.
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