Laboratory experiments
for CO2 geological
characterisation
Aim to characterise the input
parameters for input into the CO2
injection and storage reservoir model
Katriona Edlmann
Presentation Outline
• Elements of the CO2 storage system
–
–
–
–
Caprock
Storage reservoir rock
Fluids: formation and injected CO2
Fractures
• Laboratory experiments for geological
characterisation
–
–
–
–
Rock properties
Rock mechanical properties
Fluid properties
Rock / fluid interactions
• Summary of the experimentally derived
parameters controlling the CO2 storage system
Geological storage of CO2
CO2 storage mechanisms
•
•
•
•
•
Structural trapping
Residual trapping
Solubility trapping
Mineral trapping
Adsorptive trapping
Primary geological elements of the
CO2 storage system
• Overburden
• Caprock
• Storage reservoir
rock
• Fluids: formation
and injected CO2
• Fractures
Caprock properties
•
•
•
•
•
•
•
•
•
Structural storage reservoir seal
Mudstones, claystones, shale and evaporites
Limited clay and other mineral reactivity.
Low permeability /barrier to flow.
Small pores and pore throats – capillary sealing.
Ductile so less prone to faulting and fracturing
Lack of fractures
Lateral seal continuity
Thick multi layered deposits
Storage reservoir rock properties
• Under impermeable layer (caprock) with a
trapping structure.
• Porous and permeable rock
• Sandstones and limestones
• Silicate and carbonate minerals and cements
• Deeper than potable water / usable aquifers
• Thick and extensive deposits
Fluids
• Multiphase system
– Formation brines
– Hydrocarbons: gas and oil
– CO2 (generally
supercritical
Miscibility of in
oil and
CO – an overview state)
2
68 bar – 1000 psi
Immiscible CO2
102 bar – 1500 psi
Miscibility begins to develope
Final stage: Higher HC forms
continuous phase- CO2 immiscible
170 bar – 2500 psi
CO2 has developed miscibility
Higher hydrocarbons (dark spots)
begins to condense
7
Fracture networks
•
•
•
•
Reactivation of existing faults
Sealing or non sealing faults
Pre-existing micro-fractures within the caprock
Hydraulic fracturing
Geological characterisation
• Provide data for the
storage site
reservoir model
• Each grid block can
be over 100m3
• Differences in scale
– Micron to cm in lab
– m’s in wireline logs
– 100’s km in field
Upscaling
• Upscaling statistics
• Fine-scale geological model must be upscaled
to a coarser grid suitable for fluid flow
simulations
microns
mm
m
km
100km
Laboratory Experiments
Laboratory
experiments to
determine the
parameters
needed for
geological
characterisation
Rock / fluid
interactions
Rock
(matrix)
properties
Fluid
properties
Mechanical
properties
Geological data available
Rock (matrix) properties
•
•
•
•
•
•
•
•
Porosity
Pore diameters
Grain shape, sorting and distribution
Permeability
Bulk density
Rock mineralogy
Rock heterogeneity
Fracture profiling
Porosity
• A measurement of the pore volume available
within the rock. Defined as the percentage of
the bulk rock volume (Vb) not occupied by
solid material.
• Easier to measure grain volume (Vg) of a
sandstone:
Porosity = ((Vb – Vg)*100)/Vb
• Gives no indication of pore size, distribution
or connectivity as rocks with identical
porosity can have very different physical
properties.
Porosity
Triple weighing method
Dry sample (in vaccum)
  100

Immersed sample
M saturated  M dry
M saturated  M immersed
M dry
M saturated  M immersed
With three weighing, we can
calculate the water available
porosity and the sample density.
Measuring porosity
• Helium gas expansion porosimeter is used for
direct grain volume and pore volume
measurement. It is based on the Boyle's law
of expansion of helium gas where:
• Under conditions of fixed gas quantity and
constant temperature, the product of the
pressure and volume stay constant.
• Boyle's law is expressed as follows:
P1V1 = P2V2:
Pore (and pore throat) diameters
• Pore throat diameter
influences:
– Capillary entry
pressures
– Flow through of the
sample (permeability)
especially in
multiphase systems
Measuring pore diameters
Intrusion pressure (psia)
Mercury intrusion porosimetry
70000
Method:
-Mercury is injected into the sample
-Mercury intrusion pressure is increased
to access to smaller pore diameters
60000
50000
40000
30000
Série1
20000
10000
0
Incremental volume (mL/g)
0
0.1
0.2
0.3
0.4
0.5
Pore diameter (µm)
25
The total injected mercury volume
represents the connected porosity
(down to pore diameter of ~1nm)
20
15
Série1
10
5
0
0
0.02
0.04
0.06
Pore diameter (µm)
0.08
0.1
Measuring porosity, pore size
distribution and pore diameters
From thin sections / optical microscope using 2D images
Determination of total porosity on
2D images using blue epoxy on thin
section by microscopy technique.
Segmentation of the 2D image
to determine the total porosity,
which represents the ratio
between the number of black
pixel and the total pixel of the
image.
Here: 55.4% of porosity
Advantages:
-Easy and rapid method
-Total porosity determined and
not only the connected porosity
Drawbacks:
-2D porosity ( from 3D porosity )
-Depends on the pixel size resolution
Measuring porosity, pore size
distribution and pore diameters
Using X-ray microtomography to generate 3D images
Advantages:
-3D images with high resolution pixel
size
-A lot of physical and structural
parameters can be measured or
calculated from the processed images :
porosity (total and connected), specific
surface, tortuosity, permeability, …)
Drawbacks:
-Expensive and time consuming technique
Grain sorting and distribution
• Grain size, shape, sorting will influence
porosity
– Grain sorting: porosity is generally found to
increase with increased sorting
– Grain packing: porosity will vary depending on how
the grains are packed.
– Grain shape; sediments composed of spherical
grains will have a lower porosity and very elongate
particles can align in a manner to pack tightly
– Grain cement: the amount and distribution of
cement has a huge impact on porosity.
Measuring grain sorting and
distribution
Using samples whole or in thin section with the aid
of a microscope or magnifying lens.
Permeability
• Permeability is a measurement of rocks ability for
gases or fluids to flow through the rock.
• High permeability values mean that fluids and
gases can move rapidly through the rock.
• In a storage system you want the reservoir rocks to
have a reasonable permeability and the caprock
must have very low permeability (impermeable).
Permeability
The Darcy flow equation defines permeability, and after
some rearrangement, is used to calculate permeability
from laboratory measurements.
Q = K * A * (P1 - P2) / (u * L)
Where:
Q = flow rate
K = permeability
A = area
P1 - P2 = pressure drop
L = path length
u = mobility
Permeability measurement
• Absolute (intrinsic) permeability (Ka)
measured with a nitrogen permeameter
using Darcy's equation.
• When water is used as the single fluid,
the result is called "liquid permeability"
(Kliq).
• Air permeability is usually a little higher
than liquid perm.
• The Klinkenberg correction is used to
reduce air perm to an equivalent liquid
permeability.
Permeability measurement
• Effective permeability is the permeability of a
rock to one fluid in a two phase system.
– For example, the effective permeability of oil in an oil-water
system (Ko) will be less than absolute permeability.
• Relative permeability is the ratio of the effective
permeability of a fluid at a given saturation to
some base permeability.
– Base permeability is typically defined as
• absolute permeability (Ka),
• air permeability (Kair), or
• effective permeability to non-wetting phase at irreducible wetting phase
saturation.
Relative permeability
Measured using a steady state approach
Porosity (main 18.2%)
2.6 cm3.min-1
Porosity (main 20.3%)
1.2 cm3.min-1
Résults (Perrin et al., Energy Procedia, 2009)
Bulk Density
• Density varies with rock type due to differences in
mineralogy and porosity.
• Density is taken to be the weight in air of a unit
volume of a rock at a specific temperature.
• Density is calculated from the weight of grains and
cement (solids) (Wg) and the total volume of the
grains and cements plus the void space (Vb).
bulk density (b)= Wg / Vb
Vb = plug diameter2*p/4*plug length / 1000
Bulk density (b) = plug weight / Vb
Mineralogy
• The minerals that make up the reservoir rock and
caprock are of paramount importance as they
provide information about potential rock / fluid
reactivity – precipitation / dissolution
• They also influence fluid dynamics through
wettability, interfacial tension and contact angle.
• In general thermodynamics favours the
dissolution of carbonate phases in limestone and
dissolution of silicates and precipitation of
carbonates in sandstones.
Mineralogy measurements
• Scanning Electron Microscope (SEM) imaging
– Electron beam interacts with mineral. The mineral
electrons lose energy by scattering and absorption
within an interaction volume – this provides
information on atomic number and density.
• EDS (energy dispersive) X-ray analysis
– The number and energy of x-rays emitted from a
mineral allows elemental compositions
• X-Ray Diffraction (XRD) analysis
– Analysis of the scattered intensity of a x-ray beam
hitting a mineral allows identification.
Fracture profiling
• Laser scanner used for capturing fracture surface
topography
22/10/2013
PANACEA
32
Rock heterogeneity
• Geological characterisation requires average
parameter input values
• Averaged over grid block areas of in excess of
100m3
• Rocks are NOT homogeneous (at any scale)
• Statistical up scaling – representative elemental
volume.
Mechanical properties
Rock / fluid
interactions
Rock
(matrix)
properties
Fluid
properties
Mechanical
properties
Mechanical properties
• As rocks are buried the weight of the overlying
material generates stress.
• This stress works on the rock matrix, pores and
pore fluids.
• Injection of CO2 creates fluid and thermal
stresses that also acts on the rock matrix / pore
/ fluid system.
• The mechanical properties of the rock
categorise how the rocks respond to any
changes in stress.
Mechanical properties
• Burial and fluid forces act on the rock mass to
create a stress (force per unit area).
• Three principle stresses in a reservoir
s1 (maximum) > s2 (intermediate) >s3 (minimum)
• When stress is applied to a rock (matrix), the
rock experiences a change in dimension,
volume or shape termed strain (e)
• The fluids exert multi directional loads on the
walls of the pore spaces called pore pressure
Mechanical properties - Failure
• Elastic region
– If stress is removed sample will return to original
state
• Yield point
– Point at which permanent changes occur
• Ductile region
– Sample undergoes deformation but can support load
• Brittle region
– Ability to withstand stress decreases as deformation
is increased
Mechanical properties
Elastic Moduli
• Measurement of distortion under linear stress
• Modulus of Elasticity (Young's Modulus) (E)
– Samples ability to resist compression
• Poisson’s Ratio (u)
– Measure of the lateral expansion relative to
longitudinal contraction
Static elastic moduli testing
• Loading frame (delivers load s1)
• Hoek cell (delivers a confining
stress (s2 and s3)
• Strain gauged samples
(measure rock deformation)
Elastic moduli testing
• Sample loaded into Hoek cell
• Confining pressure applied
• Hoek cell sample loaded hydrostatically (axial
sa and radial (or confining stress) sr pressure
(stress) set to same values) from 7MPa to
70MPa in incremental steps.
• At each hydrostatic stress level the axial stress
is increased and decreased by approx 3kN to
induce vertical and horizontal strain.
• The stress strain curves are measured from the
strain gauges.
Elastic moduli measurements
• Modulus of elasticity (E)
– Calculated as the ratio of change in axial stress (sa) to
change in axial strain (ea) E = Dsa/Dea
• Poisson’s ratio (u)
– Calculated as the ratio of the change in radial strain
(er) to change in axial strain (ea) u = Der/Dea
Dynamic / static elastic properties
• The static moduli are those directly measured in a
deformational experiment
• The dynamic moduli of rock are those calculated
from the elastic wave velocity and density (from
wireline data).
• The static and dynamic moduli of the same rock
may significantly differ from each other.
• The main reason is likely to be the difference in the
deformation (strain) amplitude between the
dynamic and static experiments. In dynamic strain
is around 10-7 while static strain may reach 10-2.
Dynamic mechanical properties
material : a transducer arrangement (propagate waves), a ultrasonic pulse generator and an
oscilloscope, measurements on saturated and dried samples
measure
arrival time of the wave t
calculate
acoustic velocities Vp and Vs
L
V
t
bulk modulus K and shear modulus G
4
K   G
3
Vp 

Vs 
G

other elastic moduli (poisson coeff n, Young’s modulus E)
E  2G1 n   3K 1  2n 
1
 1   


Vp V f
Vma
(Wyllie, 1956)
relationship to porosity
Mechanical properties
Strength parameters
• Uniaxial Compressive strength (Co)
– Maximum stress the rock can withstand (yield point)
• Cohesion (So)
– Inherent shear strength
• Angle of internal friction ()
– the angle on the Mohr's Circle of the shear stress and
normal effective stresses at which shear failure occurs
• Triaxial stress factor (k)
– Related to the angle of internal friction by:
(1+sin ) / (1-sin)
Strength testing
• Basic compressive test involves loading a Hoek
cell sample at a constant rate to failure at a
constant value of confining pressure
• This results in a single pair of minimum and
maximum principle stresses and the
determination of stress at failure (UCS) can be
calculated:
UCS = load / cross sectional area of sample
Mechanical properties
Strength parameters
• Generally failure occurs as a shear failure, when the
shear stress along some plane in the sample is too large
• Mohr / Coulomb assumed failure as a result of the
normal stress across a plane and the shear stress along
the plane
Shear
stress
Effective
normal stress
Strength testing
• To generate a failure envelope multi failure tests
must be done
• Axial stress at a constant confining stress is
increases until incipient failure is observed on the
load versus axial displacement curve and a
reduction in slope occurs – then stopped.
• The confining pressure is increased to next target
(postponing failure) and the increase in axial
stress is continued.
• Termination at the maximum confining pressure
and the sample is allowed to fail.
Strength testing
• A Mohr coulomb failure criterion is obtained from
a plot of axial stress (load / cross sectional area)
versus confining stress.
• A linear function can be applied to the data
expressed as s1 = s0 + s3k
– s1 is maximum principle stress, s3 the confining
pressure, so the UCS and k the triaxial stress factor.
• Cohesion (So) is calculated from So = s0 / 2√k
• Angle of internal friction (k) is calculated from
K = (1+sin ) / (1-sin)
Caprock Ductility
• Ductility is a solid material's ability to deform
under tensile stress. Desire high ductility in
caprock so less likely to fracture.
• Measured in a tensile test.
• Lithology dependant:
Salt
Anhydrite
Organic-rich shales
Silty shales
Calcareous mudstones
Cherts
most ductile
least ductile
Fluid properties
Rock / fluid
interactions
Rock
(matrix)
properties
Fluid
properties
Mechanical
properties
Fluid properties
• Fluid composition
– Formation brine (in equilibrium with host rock)
– CO2 (water + CO2 = weak carbonic acid)
– Hydrocarbon (oil and gas)
Measuring fluid composition
Fluid analyses:
- Element concentrations
- major, ICP-AES (Inductively Coupled Plasma-Atomic Emission Spectroscopic)
- minor, ICP-MS (Inductively Coupled Plasma-Mass Spectrometry)
In batch reactor experiment
- Gas composition
- in-situ raman or infra-red analyses
- gas chromatography
Fluid properties
• Transport of fluids depends on how each
property responds to changes in pressure and
temperature:
–Density
– Viscosity
– Soluability
–Residual saturation
Supercritical CO2
• Supercritical carbon
dioxide at or above its
critical temperature
(31.1 °C) and critical
pressure (7.39 MPa),
• Adopts properties
midway between a gas
and a liquid.
• Expands to fill its
container like a gas but
with the density of a
liquid.
Phase diagram for CO2
Density of CO2 with depth
• Cubes represent relative
volume occupied by the
CO2
• CO2 density increases
rapidly up to 800m,
where CO2 reaches
supercritical state.
• At depths below 1.5km
density and specific
volume become nearly
constant:
• Inc temp at depth
causes low density
• Inc pressure results
in higher density
IPCC/Angus (assume hydrostatic pressure and
25oC/km geothermal gradient
Density of CO2 in relation to
temperature and pressure
• Under normal conditions the
density of water is constant
compared to the density of
CO2
• Water containing salt or CO2 is
heavier than pure water
• At depth CO2 has a density
lower than water and migrates
upwards
• This effect becomes stronger
as it moves upwards as the dec
in pressure results in an even
lower density.
• However lowering the temp at
same pressure leads to higher
density
IPCC/bachu
Viscosity of CO2
• At higher temperatures there
is a lower viscosity.
• A lower viscosity means lower
resistance to flow, better CO2
injection
• scCO2 is much less viscous
than water and oil
• Notable contrast in mobility of
CO2 and formation fluids
• High mobility of CO2
• Viscous fingering occurs at
front of injected CO2 where
part of the CO2 displaces the
formation fluids.
• This can cause CO2 to bypass
some of the pore space
IPCC/bachu
Solubility of CO2
• At 100bar and 50oC, 50kg
of CO2 can be dissolved in
1 m3 water
• In brines, CO2 solubility
decreases when salinity
increases
• It can take a period of tens
of years up to 100 year
before an equilibrium has
been reached
IPCC/Kohl and Nielsen
Residual saturation
• Water saturation is the ratio of water volume to
pore volume, in an aquifer is 100%.
• Generally the rock mineral surfaces are covered
with water.
• When CO2 is injected it will be located in the
centre of the pores
• Due to the water covering the mineral surfaces
which are very difficult to remove, you will never
get 100% CO2 saturation.
Rock / fluid interactions
Rock / fluid
interactions
Rock
(matrix)
properties
Fluid
properties
Mechanical
properties
Rock fluid interactions
• Wettability
–
the relative preference of a rock to be covered by a certain
fluid phase. Rock is described as water-wet if the rock has
(much) more affinity for water than for oil or CO2.
• Contact angle
–
–
The angle, (conventionally measured through the liquid),
where a liquid interface meets a solid surface.
It quantifies the wettability of a solid surface by a liquid via
the Young equation. Wetting refers to how a fluid in contact
with a solid spreads out:
–
so a small contact angle = strong wetting.
Rock fluid interactions
• Interfacial tension
–
–
–
The interface between two immiscible fluid phases.
Measured as the Gibbs free energy per unit area of interface at
fixed temperature and pressure.
Interfacial tension occurs because a molecule near an
interface has different molecular interactions than an
equivalent molecule within the other fluid.
• Capillary pressure
–
Capillary pressure pc is defined as the
pressure difference between the
non-wetting phase and the wetting phase
as a function of the (wetting phase) saturation
Rock fluid interactions
• Dissolving CO2 in water produces weak carbonic acid,
which can react with carbonate or silicate minerals to
form bicarbonate ions.
• Continued reaction combines bicarbonate ions with
calcium, magnesium and iron dissolved from silicate
minerals such as feldspars, olivine, pyroxenes or clays to
form solid carbonates
CO2(aq) + H2O = H2CO3 = HCO3– + H+ = CO32– + 2H+
(Ca,Mg,Fe)2+ + HCO3– = (Ca,Mg,Fe)CO3 + H+
(Ca,Mg,Fe)2+ + CO32– = (Ca,Mg,Fe)CO3
Mineral dissolution: permeability enhancement
Mineral precipitation: permeability reduction
Processes influencing the storage
system
Determine the parameters required for numerical
reservoir scale models
Thermal processes
Heat transport
Chemical processes
Reactivity of the fluids,
gasses and solids
CO2
storage
system
Mechanical processes
Stress strain and deformation
Hydraulic processes
Fluid transport
Rock / fluid interactions
Experiments
• Thermodynamic experiments(chemical
equilibrium)
• Effective kinetic experiments (pure phases)
• Flow through / percolation experiments
Thermodynamic data (chemical equilibrium)
In the reaction:
Law of mass action
aA  bB  cC  dD
[C ]c [ D]d
K eq 
[ A]a [ B]b
is the equilibrium constant
The reaction Gibbs energy:
DG  DG0  RT ln(Q)
At equilibrium DG = 0, and Q is written as Keq to
symbolise equilibrium and is referred to as the
equilibrium constant
DG 0   RT ln( K eq )
The equilibrium is attained when the
reaction Gibbs energy of the system is zero
(Q = Keq)
Titration experiment
Effective Kinetics (pure phases)
Mineral dissolution rate r (mol.s-1):
r
dn
 kr S r  km S r (1  W m ) m'
dt
kr is the kinetic constant of the global reaction (mol.m-2.s-1)
Sr is the reactive surface area (m2)
km is the intrinsec kinetic constant of the mineral (mol.m-2.s-1)
W is the saturation index
Calcite example (dissolution by CO2)
k1
CaCO3  H  
Ca2  HCO3

k2
CaCO3  H 2CO3 
Ca2  2 HCO3
k3
CaCO3 
Ca2  CO3

2
kr  k1aHn   k2 aH 2CO3  k3aH 2O  k3aCa2 aCO2
3
Measurement of km and Sr
Percolation through
unconsolidated samples
Flow-through percolation system
Method:
-Injection of different fluid composition
and different flow rate
-Measurement of permeability changes
-Fluid sampling at the outlet
Singurindy and Berkowitz [2003]; Singurindy etal [2004]
High p and T flow through
38mm diameter samples
sandstone and fractured caprock
38mm
Percolation on reservoir rock samples
T  200 °C ; P  200 bar
- In situ conditions
- Permeability measurement
- Outlet fluid sampling (at T and P)
- Raman in situ measurement
Sample size : 9 x 18 mm
6.35 x 13 mm
Luquot and Gouze (2009), Gouze and Luquot (2011)
Percolation on fractured rock samples
Measurement of
specific surface area
during dissolution
reaction (depending
on mineral
composition)
Gouze et al (2003,2004), Noiriel et al (2004, 2007, 2009)