Faults can act as barriers to fluid flow in sedimentary
basins, hindering the migration of buoyant fluids in the subsurface,
trapping them in reservoirs, and facilitating the build-up of vertical fluid
columns. The maximum height of these columns is reliant on the retention
potential of the sealing fault with regards to the trapped fluid. Several
different approaches for the calculation of maximum supported column height
exist for hydrocarbon systems. Here, we translate these approaches to the
trapping of carbon dioxide by faults and assess the impact of uncertainties
in (i) the wettability properties of the fault rock, (ii) fault rock
composition, and (iii) reservoir depth on retention potential. As with
hydrocarbon systems, uncertainties associated with the wettability of a
CO2–brine–fault rock system for a given reservoir have less of an
impact on column heights than uncertainties of fault rock composition. In
contrast to hydrocarbon systems, higher phyllosilicate entrainment into the
fault rock may reduce the amount of carbon dioxide that can be securely
retained due a preferred CO2 wettability of clay minerals. The
wettability of the carbon dioxide system is highly sensitive to depth, with
a large variation in possible column height predicted at 1000 and 2000 m
of depth, which is the likely depth range for carbon storage sites. Our results show
that if approaches developed for fault seals in hydrocarbon systems are
translated, without modification, to carbon dioxide systems the capacity of
carbon storage sites will be inaccurate and the predicted security of
storage sites erroneous.
Introduction
Carbon capture and storage (CCS) is one of the key technologies to mitigate the
emission of anthropogenic carbon dioxide (CO2) to the atmosphere
(IPCC, 2005; Benson
and Cole, 2008; Haszeldine, 2009; Aminu et al., 2017). Fault seal behaviour
will impact geological CO2 storage security and storage capacity
calculations. For the successful widespread implementation of CCS, the
long-term security of storage sites is vital and the fate of injected
CO2 needs to be understood. Faults are of major importance as potential
fluid pathways for both the vertical and lateral migration of fluids in the
subsurface (Bjørlykke,
1993; Sibson, 1994; Bense et al., 2013). Assessing whether a fault forms a
lateral flow barrier or baffle for CO2 is crucial to assessing the
efficiency and safety of subsurface carbon storage, as faults are
ubiquitous in sedimentary basins, which are the most likely CO2 storage
reservoirs, and will naturally occur close to or within storage complexes.
The scale and distribution of faults depend on the type of sedimentary
basin and its geological history. In particular, faults that are below the
resolution of seismic surveys cannot be avoided (Maerten
et al., 2006; Le Gallo, 2016). Indeed, faults occur at many of the first
industrial and pilot-scale CO2 storage sites located in sedimentary
basins (e.g. In Salah, Algeria, Mathieson et
al., 2010; Snøvhit, Norway, Chiaramonte et al., 2011; Ketzin, Germany, Martens et al., 2012; Otway, Australia, Hortle et al.,
2013).
Faults influence the flow and migration of fluids in three basic ways: (i) they can modify flow paths by juxtaposing stratigraphically distinct
permeable and impermeable units against each other (Fig. 1a; Allan,
1989). (ii) The petrophysical properties of fault rocks can impede
cross-fault flow between permeable units (Fig. 1b; Yielding et al., 1997; Aydin and Eyal, 2002; van der Zee and Urai, 2005),
and (iii) faults can provide fault-parallel flow through fracture networks
in otherwise impermeable rocks linking separate permeable units (Fig. 1c;
Eichhubl et al., 2009;
Dockrill and Shipton, 2010). Mechanism (i) assumes no (or minimal) permeability change
in the fault zone, whereas mechanisms (ii) and (iii) require permeability reduction and
increase respectively. For CO2 storage sites the latter two mechanisms
are of particular interest and are considered here. It is worth noting that
these permeability changes are temporal and dynamic, and fault reactivation
(Barton et al., 1995; Wiprut and
Zoback, 2000) should be an important consideration in CO2 storage
projects.
Impact of faults on plume migration in a CO2 storage site. (a) Juxtaposition of the permeable storage formation and impermeable cap rocks
generating a juxtaposition seal. (b) Impermeable fault rocks impede fluid
flow within the storage formation (fault rock seal). (c) Fault-parallel,
vertical migration through fracture networks bypasses the cap rock.
Whether a fault is sealing or non-sealing is dependent on the structure and
composition of the rock volume affected by faulting and the mechanics of faulting (Caine
et al., 1996; Aydin, 2000; Annunziatellis et al., 2008; Faulkner et al.,
2010). Caine et al. (1996) describe fault zones in siliciclastic rocks
defined by a fault slip surface and core and an associated damage zone, and
they considered the changes in the permeability of a fault in this context. Fault
damage zones and the fault cores are interpreted as having contrasting
mechanical and hydraulic properties, with the fault core often being rich in
phyllosilicates, which typically have low permeability, while open fractures
in the damage zone can have a substantially higher permeability than the
host rock (Caine
et al., 1996; Faulkner and Rutter, 2001; Guglielmi et al., 2008; Cappa,
2009). Models for fault zone characterization have evolved and describe
fault zones with single high-strain cores (Chester and Logan,
1986) and containing several cores (Faulkner
et al., 2003), with cores and slip surfaces at the edge of the fault zone
and in the middle. Perhaps to think of it simply, one model does not fit all
and the heterogeneities in natural fault systems and rocks result in unique
fault geometries and evolutions, albeit with similarities and
semi-predictable processes.
When a fluid lighter than the pore-filling brine, such as hydrocarbons or
CO2, is introduced into a reservoir, it will naturally migrate upwards
due to the buoyancy effect until it encounters a flow barrier such as a
cap rock or a fault. The fluid will accumulate underneath the flow barrier
until capillary breakthrough or, less frequently, induced fracturing occurs
due to the increase in pressure within the reservoir. The maximum vertical
extent of the fluid underneath the seal before seal failure, often referred
to as column height, is controlled by the fluid flow properties of the seal
with regards to the fluid (Wiprut and
Zoback, 2002). In the hydrocarbon industry, column heights are routinely
calculated as they estimate the maximum amount of oil or gas that could be
accumulated within a prospect (Downey, 1984). As the fluid flow
properties of the seal may vary spatially, some uncertainty is associated
with column heights, in particular when faults with their associated
heterogeneities form reservoir-bounding seals. In the context of CO2
storage, column heights represent the maximum amount of CO2 that could
be stored within a reservoir before migration out of the reservoir.
Evidence from outcrop studies indicates that faults play an important role
for the migration of CO2 in the subsurface. Both fault-parallel
migration of CO2 in fault damage zones (Annunziatellis
et al., 2008; Gilfillan et al., 2011; Kampman et al., 2012; Burnside et al.,
2013; Keating et al., 2013, 2014; Frery et al., 2015; Jung et al., 2015;
Skurtveit et al., 2017; Bond et al., 2017; Miocic et al., 2019) and
across-fault migration have been reported (Shipton et
al., 2004; Dockrill and Shipton, 2010). Studies of natural analogues for
CO2 storage sites have shown that if naturally occurring CO2
reservoirs fail to retain column heights of CO2 in the subsurface, this
is almost exclusively due to fault leakage (Miocic et
al., 2016; Roberts et al., 2017).
Injection of CO2 into a faulted geological formation where
the fault is sealing. The buoyancy of CO2 creates a pressure difference
at the seal and fault displayed on a pressure–depth plot for the point of
the diagram labelled A–A'.
In this contribution we review the main methods used to predict hydrocarbon
column heights for fault-bound reservoirs as applied to hydrocarbons.
Placing these into a CO2 context, we consider the implications of the
assumptions used and their applicability for CO2 storage. Stochastic
simulations are used to test the impact of CO2-specific uncertainties
on different fault seal algorithms and how these affect the predicted
CO2 column height. The results highlight the fact that fault seal parameters are
poorly constrained for CO2 and can significantly change the predicted
CO2 storage volume in fault-bounded reservoirs. Importantly, our
results suggest that increasing amounts of phyllosilicates within the fault
core, normally associated with increasing fault impermeability, may not
necessarily increase the CO2 column height within a reservoir.
Predicting fault seals for hydrocarbons and implications for CO2
storage
As they are less dense than the pore-filling brine, hydrocarbons (HCs)
migrate to the top of a reservoir where they accumulate underneath a seal.
The buoyancy of HCs creates a pressure difference of ΔP at the
seal–reservoir interface that is proportional to the hydrocarbon
plume or column height (h) and the difference in mass density between brine
(ρw) and HC (ρhc):
ΔP=ρw-ρhcgh,
where g is the gravitational constant, and the density of HCs is dependent on
the phase (gas or oil) and the in situ pressure and temperature conditions.
The trapping of HCs within rocks is controlled by capillary forces: the
interfacial tension (IFT) between HCs and the brine, the wettability of the
rock–mineral surface (wetting or contact angle, θ) with respect to
HCs, and the structure (size) of the pore system. Capillary pressure
(Pc), the pressure difference that occurs at the interface of HCs and
brine, is commonly expressed as
Pc=Phc-Pbrine=2IFT×cosθr,
where Phc is the pressure of the HC, Pbrine is the pressure of the
brine, and r is the pore-throat radius. Pc is inversely proportional to
the pore-throat radius, and thus fine-grained rocks with small pores exhibit
larger Pc and act as flow barriers to migrating HCs, leading to the
accumulation of fluids underneath fine-grained seal rocks.
For HCs the wettability parameters IFT and θ vary with depth, and
particularly large changes occur between surface conditions and conditions found at
depths of 1000 m. IFT of oil increases from around 25 mN m-1 at very shallow
conditions to around 40 mN m-1 for conditions commonly found in reservoirs at
2.5 km of depth (Yielding et al.,
2010). For methane IFT is around 70 mN m-1 at surface conditions and decreases
to 40 mN m-1 at subsurface conditions (Firoozabadi
and Ramey, 1988; Watts, 1987). The contact angle for HCs is commonly
reported as 0∘ (Vavra et al., 1992), simplifying
Eq. (2) as the cosine of 0∘ is 1. However, for other fluids
such as CO2, the wettability parameters IFT and θ are even more
pressure and temperature dependent.
Due to the heterogeneous nature of rocks the size of pores within the
sealing rock (fault rock or cap rock) varies to a certain degree, and thus
two capillary pressures can be defined. The first is the capillary entry
pressure (Pe), which controls the initial intrusion of the non-wetting
fluid into the low-permeability rock and is controlled by the radius of the
largest pore throat that is in contact with the reservoir rock. The second,
which is of greater interest for column height calculations, is the capillary
threshold pressure (Pth), sometimes called the capillary breakthrough
pressure, at which the wetting phase in the low-permeability rock is
displaced to such an extent that the percolation threshold is exceeded and a
continuous flow path of the non-wetting phase forms across the pore network.
The capillary threshold pressure is controlled by the smallest pore throat
along the flow path, and thus Pe < Pth applies. Seal
failure occurs when buoyancy pressure is larger than capillary breakthrough
pressure and the maximum supported column height follows from Eqs. (1)
and (2):
h=2IFT×cosθr×1ρw-ρhc×g.
The ability of fault-bound reservoirs to retain significant column heights
thus depends on the fault rock composition, which controls the pore-throat
size (r), and the wettability parameters (IFT, θ). The
composition and type of fault rocks in siliciclastic rocks are mainly
influenced by (i) the composition of the wall rocks that are slipping past
each other at the fault, in particular their content of fine-grained
phyllosilicate clay minerals, (ii) the stress conditions at the time of
faulting, and (iii) the maximum temperature that occurred in the fault zone
after faulting (Yielding et
al., 2010).
In clay-poor sequences (i.e. clean sandstones with less than 15 % clay),
the dominant fault rock types are disaggregation zones and cataclasites (Fisher
and Knipe, 1998; Sperrevik et al., 2002). Disaggregation zones form during
fault slip at low confining stress during early burial and constitute grain
reorganization without grain fracturing. Thus, they tend to have similar
hydraulic properties as their host sandstones and do not form flow barriers
(Fisher and Knipe, 2001). At
deeper burial (typically > 1 km) and higher confining stresses,
cataclastic processes are more significant and the resulting fractured grain
fragments block the pore space, resulting in higher Pth and in
permeabilities on average 1 to 2 orders of magnitude lower than the host rock
(Fisher and Knipe, 2001).
Additionally, quartz cementation can further lower permeabilities in both
disaggregation zones and cataclasites if they are subjected to
post-deformation temperatures of > 90 ∘C, which equates
to > 3 km burial depths at typical geothermal gradients
(Fisher et al., 2000).
In sequences with intermediate clay content (15 %–40 % phyllosilicate),
fault rocks are formed by a deformation-induced mixing of generally
unfractured quartz grains and clay matrix. The resulting texture creates a
fault rock with a texture termed clay-matrix gouge or phyllosilicate
framework fault rock (Fisher and
Knipe, 1998). Due to the clay content these fault rocks generally have high
Pth and low permeabilities (Gibson,
1998).
In sequences dominated by clay or shale beds (> 40 %
phyllosilicate), clay- and shale-rich smears can be formed on the fault plane
(Weber et al., 1978). Such smears occur during ductile
deformation at depths at which the beds are not strongly consolidated and are
often wedge-shaped, with the thickest smear adjacent to the source bed
(Aydin and Eyal, 2002; Vrolijk
et al., 2016). If faulting occurs at deeper burial depths at which the beds are
lithified, shale smears can be generated by abrasional rather than ductile
processes. In such cases thin shale coatings of more or less constant
thickness are formed along the fault plane (Lindsay et
al., 1993). Gaps within the clay and shale smears can occur at any point
(Childs et al., 2007),
lowering the hydrocarbon sealing capacity of the fault rock significantly.
As direct information on fault rock composition is very rare for subsurface
cases, several algorithms have been developed in the past decades to
estimate the probable fault rock composition at each point of the fault
surface (Weber et
al., 1978; Fulljames et al., 1997; Lindsay et al., 1993). The widely used
shale gouge ratio (SGR) algorithm takes the average clay content of beds
that slipped past any point (based on fault throw) (Yielding et al., 1997):
SGR=∑Clay content×bed thicknessthrow×100%.
SGR can be used as an estimate of fault rock composition; with high SGRs
(> 40 %–50 %) the fault rock is assumed to be dominated by clay
smears, while low SGRs (< 15 %–20 %) indicate that the fault rock is
likely to be disaggregation zones or cataclasites (Yielding et al., 2010). The
SGR algorithm, similar to other algorithms like the shale smear factor
(Lindsay et al., 1993), the clay smear potential
(Fulljames et al., 1997), and the
probabilistic shale smear factor (Childs et al., 2007),
which all use a combination of throw and clay bed distribution or thickness
to predict the effects of clay smears, does not consider the detailed fault
rock distribution and fault zone complexity observed on outcrops or at the
centimetre and sub-centimetre scale (Faulkner
et al., 2010; Schmatz et al., 2010). It has, however, been successfully used
during the last 2 decades to predict hydrocarbon fault seals in the
subsurface (Manzocchi et
al., 2010; Yielding, 2012).
Two different approaches to link SGR and fault rock composition estimation
with fault seal prediction parameters such as capillary threshold pressure
have been developed over the years: (1) using known sealing faults to
constrain relationships between SGR and HC column height and/or across fault
pressure differences (Bretan
et al., 2003; Yielding et al., 2010) and (2) measuring the capillary threshold
pressures and clay content of micro-faults and correlating these with SGR,
assuming that SGR is equivalent to the clay content of the fault rock
(Sperrevik et al., 2002). The
first approach has been fine-tuned with datasets from sedimentary basins
around the world, while equations linking capillary pressure and clay
content in the second approach are derived from best-fit relationships of
samples mainly from the North Sea.
PthB=10SGR27-CBretan et al. (2003),
with C=0.5 for burial depths of less than 3 km, C=0.25 for burial
depths of 3.0–3.5 km, and C=0 for burial depths greater than 3.5 km.
PthY=0.3×SGR-6Yielding (2012)
(for burial depths of less than 3 km)
PthY=0.15×SGR+1.9Yielding (2012)
for burial depths of more than 3.5 km
PthS=31.838×kf-0.3848Sperrevik et al. (2002)PthS is the Hg–air fault rock threshold pressure and kf the
fault rock permeability:
kf=80000exp{-19.4×SGR+0.00403zmax+(0.0055zf-12.5)(1-SGR)7,
where zmax is the maximum burial depth and zf is the depth at
the time of faulting.
These three algorithms (Eqs. 5–9) are widely applied to predict fault seals.
In combination with Eq. (3) they can be used to calculate maximum
fluid-column heights. While the Bretan et al. (2003) algorithm (Eq. 5)
assumes an exponential correlation between the fault rock clay content
(FRCC) and the capillary threshold pressure, Yielding's (2012) algorithm
(Eqs. 6 and 7) is based on the assumption of a linear correlation between
these variables. The Sperrevik et al. (2002) (Eqs. 8 and 9) algorithm also
assumes an exponential relationship but tends to predict lower capillary
threshold pressures than the Bretan et al. (2003) algorithm (Fig. 3). Note
that reported capillary pressures are typically measured in Hg–air–rock
systems, which are often used to experimentally derive capillary pressures.
In order to convert them to fluid–brine–rock systems, the following equation
is used:
Phc-brine=PHg-air×IFThc-brine×cosθhc-brineIFTHg-air×cosθHg-air,
where P is capillary pressure, IFT interfacial tension, and θ contact
angle; indices indicate the fluid system. This equation highlights the fact that
uncertainties of the wettability parameters can strongly influence capillary
breakthrough pressures derived from mercury injection experiments (Heath
et al., 2012; Lahann et al., 2014; Busch and Amann-Hildenbrand, 2013). Thus,
the results of the three algorithms are not necessarily directly comparable.
Here we apply these equations (Eqs. 5–10) to a CO2 storage framework to
test their veracity and analyse the revealed associated uncertainties.
Plot of SGR content of fault rocks and the resulting column
heights for the algorithms of Bretan et al. (2003), Sperrevik et al. (2002),
and Yielding (2012) for different fluid types for a reservoir at a depth of
1000 m. Assumes contact angles of 50∘ for CO2 and
0∘ for methane and oil, with interfacial tensions of 38 mN m-1 for
the CO2–brine–rock system, 60 mN m-1 for the methane–brine–rock system,
and 30 mN m-1 for the oil–brine–rock system. Fluid densities are 515 kg m-3 for CO2, 75 kg m-3 for methane,
800 kg m-3 for oil, and 1035 kg m-3 for
brine.
Fault seal algorithms for CO2
In contrast to the HC–brine–rock system, the wettability of the
CO2–brine–rock system is strongly controlled by temperature, pressure,
and mineralogy (Iglauer et al.,
2015b; Zhou et al., 2017). As a result, a fault seal that supports a certain
hydrocarbon column height may not necessarily support a similar amount of
CO2 (Naylor et al., 2011). This highlights the need to have a good
understanding of the CO2 wettability in the subsurface in order to
establish the security of carbon storage sites.
The IFT of the CO2–brine system is temperature, pressure, and salinity
dependent. It decreases from ∼72 to 25 mN m-1 as pressure
increases from atmospheric to 6.4 MPa and plateaus at around 25±5 mN m-1 for supercritical CO2 conditions and deionized water (Kvamme
et al., 2007; Chiquet et al., 2007; Espinoza and Santamarina, 2010). High
salinity levels, as often found in the brine filling deep saline
formations, can increase the interfacial tension by up to 10 mN m-1
(Espinoza
and Santamarina, 2010; Saraji et al., 2014). Additionally, CO2
dissolved in the brine may decrease IFT
(Nomeli and Riaz, 2017), as may
impurities such as CH4 or SO2 (Ren et al.,
2000; Saraji et al., 2014). Thus, for the conditions most likely for storage
reservoirs – supercritical CO2 at depths greater than 1200 m with
saline brine (Miocic et al., 2016) –
CO2–brine IFT will be of the order of 35±5 mN m-1 (Fig. 4),
similar to the range recently illustrated by Iglauer (2018).
Figure showing the influence of contact angle (θ) and
interfacial tension (IFT) on supported CO2 column height. Black lines
are contours at 50 m intervals. The full range of IFT and θ shown
here has been reported for CO2–brine–rock systems; the dashed rectangle
indicates conditions likely for geological storage. Column height calculated
using Eqs. (1) and (2) with a pore-throat diameter of 100 nm, a typical
value for organic-poor shales (Dong et
al., 2017), and a CO2 density of 630 kg m-3,
correlating to a depth of about 1500 m.
The contact angle formed by the CO2–brine interface on mineral surfaces
varies strongly and is dependent on pressure and temperature conditions,
mineral type, the presence of organic matter, and the wetting phase
(Sarmadivaleh et
al., 2015; Espinoza and Santamarina, 2017). On water-wet minerals, the
contact angle (θ) is about 40∘ on amorphous silica and
calcite surfaces, θ∼40 to 85∘
on mica, θ∼50 to 120∘ on coal,
and θ∼8 to 30∘ on organic shale
surfaces, while on oil-wet amorphous silica θ∼85 to 95∘ (Chi
et al., 1988; Chiquet et al., 2007; Chalbaud et al., 2009; Espinoza and
Santamarina, 2010, 2017; Iglauer et al., 2015b; Arif et al., 2016; Guiltinan et al., 2017). With pressure rising from 10 to
15 MPa, θ increases up to 10∘ on quartz surfaces, while an
increase in temperature from 50 to 70 ∘C at 10 MPa
leads to an increase in θ of 15∘
(Sarmadivaleh et al., 2015). The CO2
state also seems to influence the contact angle in oil-wet pores with
θgas < θsc
(Li and Fan, 2015). Additionally, the
wettability of rocks may shift towards more hydrophobic the longer it is
exposed to a CO2–brine mixture (Wang and Tokunaga, 2015). From
the experimental data available for the conditions most likely for storage
reservoirs, θ in water-wet conditions will range from
∼40∘ for quartz-dominated rocks to ∼70∘ for an organic-mica-rich rock (Fig. 4), with higher values
likely for deeper reservoirs (Iglauer, 2018).
A general issue with the wettability data available is that most experiments
are done on single, very pure, and cleaned mineral surfaces and that data on
the wettability of “real” subsurface rock–brine–CO2 systems are very
limited. Indeed, for potential cap rock and reservoir rock lithologies such
as dolomite, anhydrite, halite, mudrock, clays, or fault rocks no data for
subsurface conditions exist (Iglauer et al.,
2015b). Recent developments for characterizing microscale variations of
wettability in low-permeability rocks may improve knowledge in the
future (Deglint et al., 2017). The wettability
of fault rocks has to our knowledge not been studied experimentally yet but,
as illustrated by the influence of mineralogy on contact angles, will depend
on fault rock composition.
As a wide range of IFT and CA values seem possible at the CO2–seal
interface at the subsurface conditions likely for carbon storage sites, the
sealing potential of faults for CO2 and the conditions under which
faults will form seals to CO2 flow are unclear.
Markov chain Monte Carlo modelling of fault seals for CO2
In order to better understand the impact of the uncertainties of interfacial
tension, contact angle (wettability), and fault rock composition (FRC)
described on commonly used fault seal algorithms when applied to CO2,
we run stochastic models in which the input parameters follow probability
distributions (i.e. have uncertainties associated). We use a Markov chain
Monte Carlo (MCMO) approach, which samples the probability distributions of
input parameters (Gilks et al., 1996), to statistically
analyse the effect of uncertainties in wettability and fault rock clay
content (based on SGR) on the amount of CO2 that can be securely stored
in a fault-bound reservoir. The input parameters, which are all treated as
independent, are derived from the published data described: empirical values
from Iglauer (2018) and experimental from Botto
et al. (2017), Iglauer et al. (2015b), and Saraji et al. (2014). These parameters
follow a normal distribution described by the mean and the standard
deviation (σ) as seen in Table 1 and are randomly sampled 20 000
times for each model run. Capillary threshold pressures for fault seals are
calculated by using Eqs. (5) to (9) (the algorithms by Bretan et al., 2003, Yielding, 2010, and Sperrevik et al., 2002); these are then
converted to the CO2–brine system using Eq. (10), and subsequently
column heights are calculated assuming a pore-throat size of 100 nm (Eq. 3).
Note that Eqs. (5) to (7) result in maximum column heights (or minimal
wettability), while Eqs. (8)–(9) give an average column height. The
resulting column heights also follow a probability distribution (Table 2).
Table listing the input parameters for the MCMO modelling.
Reservoir A and B refer to the two theoretical reservoirs described in the
text, the approach refers to the algorithm used (see text), and the model indicates
whether uncertainties in wettability parameters (Wet), fault rock
composition (FRC), and/or combined uncertainties (Comb) are modelled. IFT is the
interfacial tension (mN m-1), CA the contact angle, SGR the shale gouge ratio
as a parameter for fault rock composition, and PTS the pore-throat size in nanometres;
σ is the standard deviation and describes the shape of the input
normal distribution.
Model no.ReservoirApproachModelIFTσCAσSGRσ1Reservoir ASperrevik et al. (2002)Wet1381502.5602Reservoir ASperrevik et al. (2002)Wet2382.5505603Reservoir ASperrevik et al. (2002)Wet33855010604Reservoir ASperrevik et al. (2002)FRC138506055Reservoir ASperrevik et al. (2002)FRC2385060106Reservoir ASperrevik et al. (2002)FRC3385060207Reservoir ASperrevik et al. (2002)Comb1381502.56058Reservoir ASperrevik et al. (2002)Comb2382.550560109Reservoir ASperrevik et al. (2002)Comb33855010602010Reservoir ABretan et al. (2003)Wet1381502.56011Reservoir ABretan et al. (2003)Wet2382.55056012Reservoir ABretan et al. (2003)Wet338550106013Reservoir ABretan et al. (2003)FRC1385060514Reservoir ABretan et al. (2003)FRC23850601015Reservoir ABretan et al. (2003)FRC33850602016Reservoir ABretan et al. (2003)Comb1381502.560517Reservoir ABretan et al. (2003)Comb2382.5505601018Reservoir ABretan et al. (2003)Comb33855010602019Reservoir AYielding (2012)Wet1381502.56020Reservoir AYielding (2012)Wet2382.55056021Reservoir AYielding (2012)Wet338550106022Reservoir AYielding (2012)FRC1385060523Reservoir AYielding (2012)FRC23850601024Reservoir AYielding (2012)FRC33850602025Reservoir AYielding (2012)Comb1381502.560526Reservoir AYielding (2012)Comb2382.5505601027Reservoir AYielding (2012)Comb33855010602028Reservoir BSperrevik et al. (2002)Wet1341702.56029Reservoir BSperrevik et al. (2002)Wet2342.57056030Reservoir BSperrevik et al. (2002)Wet334570106031Reservoir BSperrevik et al. (2002)FRC1347060532Reservoir BSperrevik et al. (2002)FRC23470601033Reservoir BSperrevik et al. (2002)FRC33470602034Reservoir BSperrevik et al. (2002)Comb1341702.560535Reservoir BSperrevik et al. (2002)Comb2342.5705601036Reservoir BSperrevik et al. (2002)Comb33457010602037Reservoir BBretan et al. (2003)Wet1341702.56038Reservoir BBretan et al. (2003)Wet2342.57056039Reservoir BBretan et al. (2003)Wet334570106040Reservoir BBretan et al. (2003)FRC1347060541Reservoir BBretan et al. (2003)FRC23470601042Reservoir BBretan et al. (2003)FRC33470602043Reservoir BBretan et al. (2003)Comb1341702.560544Reservoir BBretan et al. (2003)Comb2342.5705601045Reservoir BBretan et al. (2003)Comb33457010602046Reservoir BYielding (2012)Wet1341702.56047Reservoir BYielding (2012)Wet2342.57056048Reservoir BYielding (2012)Wet334570106049Reservoir BYielding (2012)FRC1347060550Reservoir BYielding (2012)FRC23470601051Reservoir BYielding (2012)FRC33470602052Reservoir BYielding (2012)Comb1341702.5605
Two theoretical cases are modelled: reservoir A is located at 1000 m of depth
with a temperature of 45 ∘C, a pressure of 10.2 MPa, and a
resultant CO2 density of 515 Kg m-3. Reservoir B is
located at a depth of 1800 m, has a temperature of 69 ∘C, a
pressure of 18.36 MPa, and a resultant CO2 density of 617 Kg m-3. Both reservoirs have a brine density of 1035 Kg m-3, a maximum burial depth of 2000 m, and a faulting
depth of 1500 m. The normal distributions of the input parameters (FRC (SGR)
and wettability of the fault rock (CA, IFT)) for the MCMO modelling are
listed in Table 1. IFTs of 38 and 34 mN m-1 and CAs of 50 and
70∘ are used as mean wettability for the MCMO models of reservoir
A and reservoir B, respectively, based on the IFT–depth and CA–depth
relationships of Iglauer (2018). For models
in which the approaches by Bretan et al. (2003) and Yielding (2010) are used,
these correspond to the mean least wettability. For each of the reservoirs
27 models were run with 20 000 iterations each, 9 models for each of
the approaches that link SGR to fault rock threshold pressure (Eqs. 5 to 9). Of
these nine models three simulate varying uncertainties in CA and IFT of the
fault rock (models Wet1 to Wet3), three have varying uncertainties in FRC
(models FRC1 to FRC3), and three models calculate column heights based on
uncertainties of FRC and fault rock wettability (models Comb1 to
Comb3).
Density distribution of column heights of models for reservoir A
(models 1 to 27). (a, d, g) The impact of
uncertainties in fault rock wettability, (b, e, h) the
impact of uncertainties in fault rock clay content (SGR), and
(c, f, i) the impact of combined uncertainties on column heights. Each
row uses a different approach to link fault rock composition to threshold
pressure. Uncertainty increases from dark- to light-coloured models (Table 1).
For all models N=20000.
Density distribution of column heights of models for reservoir B
(models 28 to 54). (a, d, g) The impact of
uncertainties in fault rock wettability, (b, e, h) the
impact of uncertainties in fault rock clay content (SGR), and
(c, f, i) the impact of combined uncertainties on column heights. Each
row uses a different approach to link fault rock composition to threshold
pressure. Uncertainty increases from dark- to light-coloured models (Table 1).
For all models N=20000.
Five additional models investigate the impact FRC (and associated
uncertainties) and the size of the pore throat have on supported column
heights for reservoir A using Eq. (3). Model nos. 55 to 57 simulate a
quartz-rich fault rock (95 % of IFT within 38±2 mN m-1, 95 % of CA
within 40±5∘), a quartz–phyllosilicate mixture (95 % of
IFT within 38±2 mN m-1, 95 % of CA within 60±5∘),
and a phyllosilicate-rich fault rock (95 % of IFT within 35±2 mN m-1,
95 % of CA within 75±5∘) with pore-throat sizes of
100±10 nm (95 % interval). Model nos. 58 and 59 adopt pore-throat
sizes reported by Gibson (1998) for outcrop and core samples of fault zones:
the pore-throat diameters of the quartz–phyllosilicate mixture of model no.
58 are intermediate (95 % within 50±5 nm), and for the
phyllosilicate-rich fault rock of model no. 57 they are low (95 % within 10±1 nm).
The results of the MCMO models highlight the differences between the three
approaches that link FRC to fault rock threshold pressure with the approach
of Sperrevik et al. (2002), generally resulting in lower column heights than the
approaches of Bretan et al. (2003) and Yielding (2012) for both reservoir A
and B (Table 2, Figs. 5 and 6). Uncertainties in the wettability of fault
rocks (CA, IFT) have less of an impact on the supported column height
distributions than uncertainties in FRC.
Table showing the results of the MCMO models defined in Table 1.
For reservoir A, the models which are used to investigate the impact of
uncertainties in wettability (Wet1–Wet3) have column heights ranging from
14.8±0.9 to 14.6±3.6 m (after Sperrevik et al., 2002),
from 73±4 to 72±18 m (after Bretan et al., 2003), and from
111±6 to 110±27 m (after Yielding, 2012). Models which
simulate uncertainties in FRC in the same reservoir have column heights
ranging from 16±7 m, from 74±14 to 95±80 m, and
from 111±14 to 111±55 m for the three different approaches,
respectively. Models which combine the uncertainties of fault rock
wettability and FRC (Comb1–Comb3) have an even wider spread in column height
distributions (Fig. 5c, f, i). For reservoir B, all models show a similar
pattern to those of reservoir A (Fig. 6); however, the mean supported column
heights are only about 60 % of those for reservoir A due to the
differences in fault rock wettability parameters (Tables 1, 2). This
illustrates the fact that conditions in deeper reservoirs may lead to lower column
heights.
The results of models 55 to 59 (Fig. 7) illustrate the impact of both
pore-throat size and FRC on the supported column height. For conditions
similar to reservoir A, a quartz-rich fault rock with a pore-throat size of
100 nm (model 55) can support a column height of 118±13 m, while a
mixture of quartz and phyllosilicates with the same pore-throat size (model
56) is likely to support 77±10 m, and a phyllosilicate-rich fault
rock (model 57) can support a column height of 40±8 m. For a smaller
pore-throat size of 50 nm a mixture of quartz and phyllosilicates (model 58)
can support a column height of 153±20 m, and a phyllosilicate-rich
fault rock with a pore-throat size of 10 nm can on average support a column
height of 398±78 m. Note that the tails of the model distributions
increase from model 55 to model 59. Based on the change in pore-throat
sizes alone, the column heights of model 59 should be 1 order of magnitude
larger than those of model 55.
The density distribution of column heights of models 55 to 59
illustrates the role of fault rock composition and pore-throat size on
supported column heights. If the pore-throat size is the same,
phyllosilicate-rich fault rocks can only support low column heights compared
to quartz-rich fault rocks. If the pore size decreases with increasing
phyllosilicate content, the column height increases with increasing
phyllosilicate content. However, the increase in column heights is
significantly less than the 1 order of magnitude expected due to the
change in pore-throat size. This is due to CO2 wettability depending on fault rock composition, which results in phyllosilicate-rich fault
rocks supporting a lower column than quartz-rich fault rocks with a similar
pore throat. Column height is calculated using Eq. (3) and a CO2 density
of 515 kg m-3 (as reservoir A). For all five models
N=20000.
Supported column heights of a fault with a phyllosilicate-rich
fault rock (SGR = 40) depending on the depth of the fault and the trapped
fluid. For CO2 the column height decreases with depth (after an optimum
at ∼1000 m of depth), while methane column heights increase with
depth. Based on depth–wettability relationships for CO2 by Iglauer (2018).
Discussion
The results of the stochastic modelling illustrate that even small
uncertainties in fault seal parameters can introduce significant variations
and spread in the amount of CO2 predicted to be securely stored within
a fault-bound siliciclastic reservoir. In particular, uncertainties in fault
rock composition result in a wider range of possible column heights when
compared to uncertainties of CO2–brine–rock wettability. The outcomes
also illustrate large differences between the algorithms used to calculate
column heights. Additionally, phyllosilicate-rich fault rocks can support
lower CO2 column heights than quartz-rich fault rocks if a constant
pore-throat radius is assumed.
The use of SGR as a proxy for fault rock composition, as in our study, is
widely accepted and commonly applied for hydrocarbon reservoirs
(Fristad et al.,
1997; Lyon et al., 2005). The algorithm linking SGR to fault zone threshold
pressure and column height is a critical step in fault seal studies, and our
results show that different algorithms (Eqs. 5–9) predict different CO2
column heights. This is in line with other works comparing the three
algorithms (Bretan, 2016) and is due to the
sensitivity of the Sperrevik algorithm to geological history (faulting
depth and maximum burial). The algorithm has been developed from samples of
North Sea cores from depths ranging from 2000 to 4500 m. The approaches by
Bretan et al. (2003) and Yielding (2012) are both used to calculate the
maximum threshold pressure, and the approach by Sperrevik et al. (2002) gives an
average threshold pressure. Thus, when used for a carbon storage capacity
assessment, the column heights calculated with the algorithms of Bretan et al. (2003) and Yielding (2012) would illustrate the maximum potential
storage capacity, while the column heights resulting from the Sperrevik et al. (2002) algorithm would likely represent average capacities.
The high impact of SGR on column heights is predictable as SGR is a proxy
for the amount of phyllosilicates incorporated into the fault rock,
and our results are in line with other work which highlights the fact that good
prediction of fault rock composition is crucial for hydrocarbon column
height prediction (Fisher
and Knipe, 2001; Yielding et al., 2010). When SGR is used for predicting
fault seals in a hydrocarbon context, higher SGR values coincide with higher
contained column heights, as high-SGR-value fault rocks have a higher
phyllosilicate content (and hence smaller pore-throat radii). Our results
show that for a CO2 fluid the decrease in pore-throat size due to a
higher phyllosilicate content results in lower column heights than
anticipated. The fact that for constant pore-throat sizes phyllosilicate-rich fault rocks can only support lower column heights than quartz-rich
fault rocks (Fig. 7) highlights the difference between the wettability of
the CO2–brine–rock system and the wettability of the HC–brine–rock
system at subsurface conditions. Phyllosilicate minerals have contact angles
of up to 85∘, while quartz has a contact angle around 40∘
(Espinoza and Santamarina, 2017;
Iglauer et al., 2015a). Increasing the content of phyllosilicates in the
fault rock (increasing FRCC and SGR) effectively increases the contact angle,
which directly reduces the capillary threshold pressure as the cosine of the
contact angles approaches zero (Eq. 2). This indicates that an increase in
phyllosilicates in the fault rock may not increase the amount CO2 that
can be retained by the fault to the same degree as for hydrocarbons. This
calls into question whether algorithms such as SGR, which assume that higher
phyllosilicate content in fault gouges equal higher sealing properties, can
be used to effectively predict CO2 fault seals. We suggest that
introducing pore-throat sizes into fault seal algorithms may result in more
reasonable column height predictions for CO2 systems.
The results of our stochastic models also illustrate the impact of depth on
the wettability of the CO2–brine–rock system, with the deeper faulted
reservoir scenario (at a depth of 1800 m) holding significantly lower column
heights than the shallower reservoir (depth of 1000 m). This is in contrast
to fault seals for hydrocarbons for which faults can retain higher fluid columns
for similar SGR values in deeper reservoirs
(Yielding, 2012). The influence of pressure on
the sealing capacity of fault rocks for CO2 has direct implications for
the selection of carbon storage sites, with shallow reservoirs being able to
retain a higher column of CO2 than deeper reservoirs (Fig. 8). Note
that minimum CO2 storage site depths are around 1000 m and are governed
by the CO2 state and density (Miocic et al., 2016).
Non-sealing faults are often undesired in a hydrocarbon exploration context,
but this is not necessarily true in the case of carbon storage sites. Here,
sealing faults may actually reduce the amount of CO2 that can be safely
stored within a reservoir as the lateral migration of the CO2 plume is
hindered and pressure build-up may occur (Chiaramonte et al., 2015;
Vilarrasa et al., 2017). If fault rocks that are sealing for hydrocarbons
are not necessarily sealing for CO2, as the results of our study
suggest, faulted abandoned hydrocarbon reservoirs could form good carbon
storage sites as long as no vertical migration of CO2 along the fault
occurs.
Conclusions
Fault seal modelling is associated with significant uncertainties arising
from the limited subsurface data, resolution of seismic data, faulting
mechanics and fault zone structure, spatial and temporal variations, and
overall limitations of the scalability of observations. Nonetheless, several
models to estimate the sealing properties of faults have been developed and
successfully used to predict hydrocarbon column heights. However, for the fault
seal modelling of CO2 reservoirs the wettability of the
CO2–brine–rock system introduces additional uncertainties and reduces
the amount of CO2 that can be securely stored within a reservoir
compared to hydrocarbons.
In this study uncertainties in fault rock composition, as well as
uncertainties of how CO2 fluid–rock wettability properties of the
reservoir change with depth, have a stronger impact on CO2 column
heights than uncertainties in wettability. Importantly, a higher
phyllosilicate content within the fault rock at a given pore-throat size,
which is commonly assumed to increase the threshold pressure, may reduce the
threshold pressure due to increased CO2-wetting behaviour with such
minerals. In particular, deep reservoirs and high pressures seem to lead to lower
column heights when compared to the equivalent predicted hydrocarbon column
height.
To ensure CO2 storage security, appropriate site characterization for
storage sites is critical. Faults of all scales must be identified and their
seal potential modelled with a range of uncertainties, including the fault
rock composition and wettability. During storage operations fault seal
potential predictions could be refined by high-resolution monitoring and
the development of databases similar to those used (Bretan
et al., 2003; Yielding et al., 2010) to predicted hydrocarbon column
heights. While fault seals may impact storage capacities, it should be
kept in mind that lateral migration through non-sealing faults can increase
storage capacity.
Code and data availability
Model code is available from the corresponding author upon request.
Author contributions
JMM and GJ designed the project with input from CEB. JMM developed the model
code and performed the MCMO simulations. The paper was written by JMM
with contributions from both GJ and CEB.
Competing interests
The authors declare that they have no conflict of interest.
Special issue statement
This article is part of the special issue “Understanding the unknowns: the impact of uncertainty in the geosciences”. It is not associated with a conference.
Financial support
This research has been partly supported by the European Commission PANACEA project (grant no. 282900).
Review statement
This paper was edited by Lucia Perez-Diaz and reviewed by Katriona Edlmann and Graham Yielding.
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