Subsurface gas storage in porous media is a viable option
to mitigate shortages in energy supply in systems largely based on renewable
sources. Fault systems adjacent to or intersecting with gas storage could
potentially result in a leakage of stored gas. Variations in formation
pressure during a storage operation can affect the gas leakage rates,
requiring a site and scenario specific assessment. In this study, a
geological model of an existing structure in the North German Basin (NGB) is
developed, parameterised and a methane gas storage operation is simulated.
Based on the observed storage pressure, a sensitivity study aimed at
determining gas leakage rates for different parametrisations of the fault
damage zone is performed using a simplified 2-D model. The leakage scenario
simulations show a strong parameter dependence with the fault acting as
either a barrier or a conduit for gas flow. Furthermore, the storage
operation greatly affects the gas leakage rates for a given parametrisation
with significant leakage only during the injection periods and thus during
increased overpressures in the storage formation. During injection, the peak
leakage rates can be as high as 2308 Sm3d-1 for damage zone
permeabilities of 10 mD and a capillary entry pressure of 4 bar. Increasing
capillary entry pressure results in a sealing effect. If the capillary entry
pressure is scaled according to the damage zone permeability, peak leakage
rates can be higher, i.e. 3240 Sm3d-1 for 10 mD and 0.13 bar. During
withdrawal periods, the pressure gradient between a storage formation and a
fault zone is reduced or even reversed, resulting in greatly reduced leakage
rates or even a temporary stop of the leakage. Total leakage volume from
storage formation was assessed based on the 2-D study by considering the
exposure of the gas-filled part of the storage formation to the fault zone
and subsequently compared with gas in place volume.
Introduction
Worldwide, countries are promoting a transition from conventional to
renewable energy sources to mitigate global climate change (IPCC, 2015). In
Germany, the so-called “Energiewende” resulted in 31.6 % of the total
power generation in the year 2016 being based on renewable sources, with the
overall aim being 80 % by the year 2050 (BMWi, 2018). However, power
generation from renewable sources is stochastic, so that the fluctuating
availability of wind and solar radiation can cause challenges for an optimal
management of energy system and energy storage on various scales might be
required in systems largely based on renewable power generation (Schiebahn
et al., 2015). The geological subsurface and specifically porous formations
can provide large storage capacities for gases (Bauer et al., 2013; Kabuth
et al., 2017), either for a mechanical energy storage concept utilising
compressed air (Wang and Bauer, 2017; Mouli-Castillo et al., 2019; Sopher et
al., 2019) or for storing a chemical energy carrier, such as hydrogen or
methane (Sainz-Garcia et al., 2017; Pfeiffer et al., 2017; Matos et al.,
2019).
The North German Basin has previously been investigated for CO2 storage
(e.g. Schäfer et al., 2010; Kempka et al., 2015). This led to the
identification of several potential storage sites (Hese, 2012), which used
for storing other gases such as methane or compressed air. However, fault
systems exist throughout the NGB, including the identified storage sites,
which introduces uncertainty regarding the possibility of gas leakage
(Oldenburg et al., 2002; Folga et al., 2016). Such a leakage of gas would
not only result in a reduced gas in place (GIP), but also in a potential
drop in formation pressure, both resulting in a reduced storage capacity and
storage self-discharging over time. Furthermore, gas leaking from a
subsurface storage site into shallow formations can trigger chemical
reactions and can have an adverse effect on e.g. drinking water supplies
(Kempka et al., 2015). Consequently, an assessment of potential gas leakage
rates is useful to be able to assess potential impacts prior to any storage
development or operation.
The leakage of gas from a gas storage site is driven by the buoyancy of the
lighter gas compared to the surrounding formation water as well as the
pressure gradient between the storage formation and the fault zone (Chen et
al., 2013). During a gas storage operation, the storage pressure fluctuates
several bars, depending on the current operational mode and storage setup,
e.g. up to ±35 bar for a hydrogen storage site designed for weekly
withdrawal periods (Pfeiffer et al., 2017) and ±41.5 bar for a
compressed air energy storage used in a daily storage scheme (Wang and
Bauer, 2017). Studies on gas leakage during natural gas storage show that
frequent pressure fluctuations in the storage formation can affect leakage
rates through fault zones intersecting the gas storage site (Chen et al.,
2013). In addition to the changes in formation pressure due to the storage
operation, also the properties of the fault system and its internal
structure affect leakage of fluids. However, such fault zone properties are
often unknown and are subject to uncertainties (Gibson, 1998; Fisher and
Knipe, 2001; Faulkner et al., 2003). The effect of existing fault systems on
the operation at a potential storage site, i.e. occurring leakage rates and
resulting reduction in formation pressure, must be investigated prior to any
deployment. This study is aimed at investigating leakage characteristics
during a storage operation at a potential gas storage site in the NGB for
different fault zone parametrisations. For this, first a geological model of
a potential gas storage site in the NGB, which includes six individual
faults, was constructed. A hypothetical methane storage operation is
designed and the storage operation is simulated using a 3-D reservoir model
to obtain realistic storage pressures. Subsequently, a sensitivity analysis
aimed at determining leakage rates for different fault zone parametrisations
is carried out on a 2-D slice of the model area.
Geological storage model
A potential gas storage site must satisfy the following criteria: a
sufficiently high reservoir volume to store the desired amount of gas, a
high intrinsic permeability to provide the required flow rates and a
satisfactory containment of the stored gas (e.g. Bennion et al., 2000; Matos
et al., 2019). In the NGB the Quickborn-Volpriehausen, the Rhaetian and the
Dogger sandstones are potential storage formations, as they typically
provide sufficiently high permeabilities and occur in combination with
potential cap rocks (Hese, 2012). Due to salt tectonics within the NGB, all
sedimentary depositions were affected by changes in regional stresses
(Baldschuhn et al., 2001; Hese, 2012). This resulted in formation of
potentially suitable geological traps as well as major fault systems
(Baldschuhn et al., 2001; Lehné and Sirocko, 2005). These major fault
systems typically strike N–S to NNE–SSW (Fig. 1a). Local faults striking in
different directions often accompany the major fault systems on the top and
sides of salt structures (Baldschuhn et al., 2001; Reinhold et al., 2008).
The combination of the number of fault systems and the different strike
directions results in a complex sedimentary architecture in the NGB.
Structural model used for the investigation of gas leakage from a storage
site must represent this complexity and should therefore include all
existing structures.
(a) Salt structures, associated faults and the study area within
the NGB in Schleswig-Holstein (SH). The dashed outline is the area of
Geotectonic Atlas of Northwestern Germany and the German North Sea (GTA)
within SH (after Baldschuhn et al., 2001; Hese, 2012); (b) 3-D geological
structure model created for the study with six fault systems (average dip
angle 61 to 82∘).
In this study, a structural model of a potential storage structure was
previously investigated for CO2 (Hese, 2012) and later for hydrogen
storage (Pfeiffer et al., 2017) and is created and used for the scenario
simulations. At the storage site, an anticline trap was formed by
halokinesis, with normal and reverse faults intersecting with the structure
and providing potential leakage pathways for fluid migration (Fig. 1b). In
the previous study by Pfeiffer et al. (2017), the faults at the study site
are assumed to be sealing and boundary conditions were chosen accordingly
for the flow simulation model. Of the three potential storage formations in
the NGB, only the Quickborn-Volpriehausen and the Rhaetian sandstones exist
at the storage site. While the Quickborn-Volpriehausen sandstones are at
depths of 1860 unitm, the Rhaetian sandstones are located at a more suitable,
shallower depth of around 400 m. In total, 14 deep (Permian till Paleogene)
and 9 shallow (Miocene till Pleistocene) base horizons were used to create
the 3-D geological model, which has a spatial extend 23.5 km by 27.7 km by 6 km. The modelling was done using the Petrel E&P platform, based on
horizon and fault data provided and calibrated based on six well drilling
data and seven seismic profiles by Hese (2012). For each fault system, the
geometrical fault-fault and fault-horizon interrelationships are considered.
The fault systems are featured in a discrete corner point grid, which
enables the representation of the fault zone complexity and allows local
grid refinements, according to the requirements of the study (Fig. 1b). The
structural analysis of fault systems at the study site shows a dip-slip
movement tendency. The average dip angle of Faults 1, 3 and 4 is
70∘. Fault 2 has a lower average dip angle of 61∘,
while Faults 5 and 6 show a higher average dip angle of 82∘. The
primary strike direction is NE–SW, similar to the major salt structures in
the NGB (Reinhold et al., 2008). The fault systems crosscut the Triassic
storage formations and reach up to the Oligocene horizon (Baldschuhn et al.,
2001). The average fault throw is 30 m with a total displacement of 35 m.
However, locally the fault throw can reach 200 m and total displacement can
be up to 240 m, which can serve as a rough probability indicator for faults
acting as a possible leakage pathway (Knipe et al., 1997; Manzocchi et al.,
1999; Shipton and Cowie, 2001).
During the formation of such faults, the grains of the host rock are crushed
and re-arranged along the deformation band, resulting in the formation of
breccias, catalaclasites, ultracataclasites and veins (Aydin, 1978; Caine et
al., 1996). The adjacent rock matrix to each side of the deformation band is
typically densely fractured (Caine et al., 1996; Fossen et al., 2007). The
petrophysical properties of these two zones differ significantly, which is
commonly represented by distinguishing between a fault core and a damage
zone (Aydin, 1978; Caine et al., 1996; Faulkner et al., 2003). Understanding
the fluid flow processes occurring in a fault zone requires the
investigation of the main characteristics of the system, i.e. the fault
core, the damage zones and the adjacent host rock. The properties of these
units affecting fluid flow are hydraulic permeability and capillary entry
pressure as well as spatial extent (Knipe et al., 1997).
Due to the aforementioned processes, the fault core typically acts as a
barrier towards fluid flow, i.e. the permeability is lower than that of the
undisturbed host rock (Aydin, 1978; Caine et al., 1996; Gibson, 1998). The
petrophysical properties within a fault zone formed through a deformation
band mechanism are controlled by the host rock properties and permeability
reductions of approximately 4 to 6 orders of magnitude compared to the
original host rock can be observed (Knipe et al., 1997; Gibson, 1998;
Faulkner et al., 2003). Studies show that the fault core permeability is
within the range from 10-2 to 10-6mD for siliciclastic rocks
similar to those found in the NGB (Caine et al., 1996; Gibson, 1998; Shipton
and Cowie, 2001; Faulkner et al., 2003; Flodin et al., 2005). The damage
zones are the area or volume of host rock affected by the fault genesis to
both sides of the fault core (Aydin, 1978; Caine et al., 1996; Faulkner et
al., 2003). Contrary to the fault core, damage zones typically have
hydraulic conductivities that are higher than the respective host rock due
to high density of fractures, faults and cleavage (Caine et al., 1996). For
siliciclastic rocks, damage zone permeabilities typically range from 10
to 10-2mD (Gibson, 1998; Torabi et al., 2013; Rinaldi et al., 2014b).
Capillary processes can be significant due to the reservoir rock being
juxtaposed across the fault zone against the upper formations. Capillary
entry pressure is one of the important parameters controlling the fluid flow
in such conditions, with values given in literature typically ranging from 4
to 100 bar (Knipe et al., 1997; Gibson, 1998; Flodin et al., 2005;
Torabi et al., 2013). Experimental and literature studies have shown that
damage zones can reach up to 100 m on both sides from fault centre, whereas
fault cores have significantly smaller thicknesses of less than 0.5 m (Knipe
et al., 1997; Shipton and Cowie, 2001; Faulkner et al., 2003).
Gas storage simulation
The pressure fluctuations induced by a storage operation depend on the
thickness and extent of the storage formation, the petrophysical properties
of the storage formation as well as the injection/withdrawal history and the
underlying storage scenario, which dictates the boundary conditions for the
storage operation. For this study, a storage scenario is constructed, based
on the assumption periods with no power generation from renewable sources
for one week. In 2016 the average weekly electricity demand of the state of
Schleswig-Holstein was about 1.04 million GJ (MELUR, 2018). Taking this as a
reference and assuming the efficiency of re-electrification of methane to be
60 % (Schiebahn et al., 2015), a storage site must provide 48.4 million Sm3 (at surface conditions) of synthetic natural gas during the period
of 7 d to cover the complete storage demand of such scenario.
The storage operation consists of an initial filling of the storage with
gas, a cycling storage operation and a subsequent shut-in period. The
initial gas injection lasts for 1460 d, during which 263 million Sm3
of gas are injected. The cyclic operation consists of six storage cycles,
with the withdrawal rate in each cycle being set to 1.4 million Sm3d-1
per well. Each withdrawal period is followed by refilling of the storage
formation with gas at a rate of 350 000 Sm3d-1 per well for 30 d.
Subsequent to the cyclic operation, a shut-in period of 222 d is
simulated, resembling a temporary abandonment of the operation.
Gas phase distribution in the 3-D model after the storage
initialisation. Five vertical storage wells located near the top of the
anticline, 900 m from well 1 is the “virtual” well for pressure
controlling in 2-D study.
The storage operation is simulated using five vertical wells located near
the top of the anticline at the depths of 429, 458, 484, 514 and 554 m (Fig. 2). The corresponding initial well pressures are 43.0, 46.0, 48.6, 51.6 and 55.4 bar. The gradient of the minimum
horizontal stress of the suprasalinar sediments in the NGB is estimated to
be around 0.15 barm-1 (Röckel and Lempp, 2003). Assuming this to be the
fracture pressure gradient and thus the maximum allowable pressure increase,
the upper bottom hole pressure (BHP) values in wells 1 to 5 are calculated
as 64.3, 68.7, 72.6, 77.1 and 83.1 bar, respectively.
The lower pressure limit of the wells during withdrawal were set to an
arbitrary 30 bar. Geomechanical processes such as fault reactivation are
not explicitly considered in this study. However, with the defined BHP
limits geomechanical reactions due to the storage operation are assumed
unlikely. To minimise the computational load, the Rhaetian storage formation
and the cap rocks are included in this simulation, with the spatial
discretisation 50 m by 50 m in lateral directions. At the storage site, the
mudstones of the Lias and the Lower Cretaceous form the cap rocks above the
storage formation. However, the Lias is eroded towards the fault axis, so
that only the Lower Cretaceous forms a complete seal over the storage
formation.
The model is discretised in vertical direction by dividing the individual
units, i.e. the cap rocks and the storage formation, into a constant number
of layers. The resulting vertical discretisation of the grid varies
therefore with the local thickness of the individual unit. The storage
formation is divided into five layers, with the resulting vertical
discretisation ranging from 0.01 to 26 m. The Lias and the Lower
Cretaceous cap rocks are discretised using twenty layers, with resulting
vertical discretisation ranging from 0.001 to 13 m and 1 to 5 m,
respectively. No flow is allowed across the model boundaries, providing a
conservative estimation of the pressure changes occurring during the storage
operation, as overpressures cannot dissipate. All petrophysical properties
are assumed as homogeneous and isotropic within the individual geological
units (Table 1). The Brooks and Corey formulation (Brooks and Corey, 1946)
is used to calculate phase permeabilities and capillary pressure, based on
phase saturations. The ECLIPSE E100 black-oil simulator is used
(Schlumberger Ltd., 2017), assuming immiscible two-phase flow of water and gas.
It was successfully tested in a benchmark paper by Class et al. (2009) for a
comparable setting and represents therefore a valid choice as modelling
tool.
Model parameters used for 3-D gas storage simulation.
ParametersStorageCapFaultDamageformationrockcorezonePermeability, k [mD]50010-410-210-2Porosity, ϕ [–]0.300.150.150.15Residual water saturation, Sw,r [–]0.200.600.400.40Gas relative permeability, Krg [–]0.790.480.560.56Capillary entry pressure, Pc [bar]0.206044
During initial storage filling, the injected gas accumulates at the top of
the anticline (Fig. 2). The initial filling of the storage is accompanied
with a significant pressure increase, so that the BHP in well 1 reaches the
upper limit after 300 d, resulting in an automatic reduction of applied
injection rates and ultimately in the well being shut after 1410 d (Fig. 3). For the deeper wells 2, 3, 4 and 5 the upper limit is not exceeded
during the initial filling, with well pressures peaking at 65.9, 67.0, 67.6 and 68.3 bar, respectively.
Bottom hole pressure for five vertical wells during the storage
cyclic operation starting at day 1461 and the following shut-in period of
222 d; the dashed red line depicts the pressure change at the position of
the 2-D-slice used for the leakage scenario simulations.
The target withdrawal rates of 1.4 million Sm3d-1 are sustained for all
wells in all storage cycles, so that 49 million Sm3 of gas is produced
from the storage formation in each cycle. During the first storage cycle the
well pressures decrease to 38.5, 37.1, 34.2, 33.3 and
34.1 bar in wells 1 to 5, respectively. In the subsequent refilling period,
the target injection rates are achieved in wells 2 to 5, while the upper BHP
limit is reached in well 1. Thus, less gas can be injected than planned,
with the total injected gas volume being 50.9 million Sm3. Regardless,
the target withdrawal rates are achieved in every storage cycle, so that the
storage site can cover 100 % of the storage demand, as defined in this
study. The storage pressure follows the trend of well pressure with the
magnitude of the pressure change during different storage phases being
considerably dampened (Fig. 3). After the initial filling, the storage
pressure 900 m south of the storage wells, which is the position of the 2-D
slice used for the leakage scenario simulations, is around 62 bar. During
the storage operation, pressure fluctuates between about 60 and 55 bar. Thus, the observed pressure changes during the storage operation is 7 bar at the position of the 2-D model. In the shut-in period of the storage
operation after 1683 d, the storage pressure rebounds to 62.0 bar and
then slowly declines to around 59.9 bar at the end of simulation at the day 1827.
Gas leakage simulationsSetup
For the leakage simulations, only a 2-D slice extracted from the full 3-D
model is used (Fig. 2), with the initial and boundary conditions being set
based on the simulation results of the full 3-D model of the storage
operation. The 2-D slice is oriented W–E, intersecting with the gas storage
at about 900 m south of the storage well 1. The slice position was selected
to represent realistic storage pressures, a high local gas volume, as well
as a good approximation of the fault-storage interface (Fig. 2). At the
given slice position, the pressure in the storage formation fluctuates
during the cyclic storage operation by 7 bars, as can be seen from the 3-D
simulation (Fig. 3). For a realistic representation of storage pressure, an
additional well is placed 350 m east from the fault zone in the 2-D model
that does not exist in the 3-D model. The operation of this “virtual” well
is the pressure control, i.e. the temporal evolution of storage pressure in
the 3-D model is represented by cycling the pressure at the virtual well
between the minimum pressure of 55 bar and the maximum pressure of 62 bar
observed in the 3-D model (Fig. 3). The petrophysical properties of the fault
damage zone are directly assigned to the grid elements. Using local grid
refinement, the first 50 m from the fault zone and the storage formation
were refined to grid blocks of 50 m by 1 m in lateral direction. The fault
core properties are assigned using transmissibility multipliers at the
connecting grid blocks (Manzocchi et al., 1999). For the leakage scenario
simulations, only the cyclic storage phase and the subsequent shut-in period
are considered. Thus, the initial formation pressure is assumed to be 62.7 bar (compare Fig. 3).
Model parameters used for leakage scenario simulations.
Three different scenario parametrisations are tested in this study (Table 2). In the scenario I only the permeability of the damage zone is changed,
while in the scenario II the capillary entry pressures are being varied. In
the scenario III, both the damage zone permeability and the capillary entry
pressure are varied simultaneously based on the Leverett J-function scaling
(Leverett, 1941). For this, 0.01 mD and 4 bar are set as the respective
reference permeability and capillary entry pressure. Thus, increasing damage
zone permeabilities are accompanied by decreasing capillary entry pressures
in the simulation runs of the scenario III.
Pressure fluctuation during cycling operation in 2-D model, solid
lines represent pressure in the fault zones: (a) scenario I – for the damage
zone permeability cases; (b) scenario II – for capillary entry pressure
cases; (c) scenario III – for normalised capillary entry pressure cases.
Simulation results and discussion
The leakage simulations start with a withdrawal cycle, during which the
pressure in the storage formation decreases to values close to 55 bar and
the fault zone pressures being 55.0, 55.0, 54.9 and 54.8 bar
for simulation runs #1 to #4 (Fig. 4a). Even though the pressure
differential between the storage formation and the fault zone is small, the
gas leaks into the fault zone and rises upwards (Fig. 5). The peak gas
leakage rates are 325 and 2308 Sm3d-1 in simulation runs #3 and #4, while runs #1 and #2 show leakage rates below 25 Sm3d-1.
Exemplary gas phase saturation in the fault zone at day 1827 in
run #11, scaled-up by 3 units in z axis. Gas flows from the storage
formation to the damage zone is directed upwards within the damage zone.
Gas leakage rates during six injection periods for: (a) scenario I – damage zone permeability cases;
(b) scenario II – capillary entry pressure cases; (c) scenario III – normalised capillary entry pressure cases.
During the subsequent injection period from day 1468 to day 1498, the
pressure in the storage formation rapidly increases, with the fault zone
pressure following behind (Fig. 4a). Correspondingly, gas leakage occurs
with peak rates being 5, 24, 325 and 2308 Sm3d-1 during the first injection for the simulation runs #1 to #4
of the scenario I (Fig. 6a). However, the rates quickly decline within the
first hours of injection for the simulation case, assuming a damage zone
permeability of 10 mD (run #4) with the average leakage rate being 2020 Sm3d-1. Contrary to that, the peak and average leakage rates are
relatively constant in the remaining simulation runs. During the following
withdrawal of gas, the pressure in the storage formation is again dropping
to around 55 bar, which greatly reduces the gas leakage for the higher
permeability simulation runs (#3, #4) and stops it for in the lower
permeability runs (#1, #2) altogether (Fig. 4a). The characteristics
of the gas leakage rates are similar in the subsequent storage cycles,
however, the differences between the peak and average leakage rates during
injection increase slightly. In the dormant phase of the storage operation
after 222 d of operation, gas leakage rates gradually decrease to around
2, 35, 348 and 866 Sm3d-1 for damage
zone permeabilities of 0.01, 0.1, 1 and 10 mD, respectively. This
happens while the pressure differential between the storage formation and
the fault zone remains relatively constant (Fig. 4a).
Comparison of the influence of fault zone parameters on the
average leakage rate during six injection periods; Parameters: (a) damage
zone permeability; (b) capillary entry pressure; (c) scaled capillary pressure
and damage zone permeability.
For the different capillary entry pressure cases at a constant fault zone
permeability of 0.01 mD (scenario II), the gas leakage rate never exceeds 15 Sm3d-1 during injection (Fig. 6b). For the simulation cases with higher
capillary entry pressures, i.e. 6, 8 and 10 bar, the differential
between the gas phase pressure in the storage and the fluid pressure in
fault system is not sufficient to result in significant leakage. For the
simulation case with the lower capillary entry pressure (run #8), the
highest leakage rates of the scenario II are observed. However, the low
damage zone permeability retards the advance of the gas phase sufficiently
to minimise gas leakage. The low pressure differential between the storage
formation and the fault zone inhibits any leakage during the first
withdrawal period in simulation runs #1, #5 to #8. The pressure in
the fault zone is not lower than the storage formation pressure in the
following withdrawal cycles, so that no gas leakage occurs (Fig. 4b). In the
shut-in period of the storage operation, the gas leakage rates are constant,
never exceeding 3.5 Sm3d-1.
The overall characteristics of the gas leakage in the scenario III, i.e. when capillary entry pressure is scaled according to the permeability of the
damage zone (runs #9 to #11), are similar to the results of the
scenario I (Fig. 4a, c). However, the gas leakage rates are generally higher
than in the scenario I, with peak leakage rates being 30, 473 and 3240 Sm3d-1, in simulation runs #9, #10 and #11,
respectively (Fig. 6c). For the simulation runs with higher fault zone
permeabilities, a decrease in the leakage rates is observed, so that in
simulation run #11 (10 mD, 0.13 bar) the average gas leakage rate is 2770 Sm3d-1. For the low permeability case, the peak and average leakage
rates only show a small decrease over the injection periods. In the shut-in
phase of the storage operation, leakage rates gradually decrease to around
47, 497 and 1143 Sm3d-1, for damage zone
permeabilities of 0.1, 1 and 10 mD, in combination with scaled entry
pressures of 1.26, 0.4 and 0.13 bar, correspondingly.
For all tested scenarios, an increase in the peak gas leakage rate is
observed with the number of storage cycles (Fig. 6). This can be explained
by changes in the phase mobility over time. After the first couple of
storage cycles, gas intrudes into the fault zone (Fig. 5), resulting in a
reduced water saturation. Correspondingly, the relative permeability of gas
in the affected area increases, while the relative permeability of water
decreases. This increased gas mobility results in a further advance of the
gas intrusion as the buoyancy of the gas drives it upwards. During the
withdrawal cycles with no or only very little gas entering the fault zone,
so this can result in decreasing gas saturations and thus a reduced
mobility. After all storage cycles are completed, i.e. in the dormant phase
of the storage, leakage rates decrease for all scenarios asymptotically, as
the overpressures in the storage formation are redistributed and local
pressure gradients decrease.
Comparing the average leakage rates during the injection phases of the
storage operation shows a strong dependence of the observed leakage rates on
the damage zone permeability and the capillary pressure (Fig. 7).
Unsurprisingly, leakage rates decrease with increasing capillary entry
pressure and decreasing damage zone permeability. Considerable gas leakage
occurs when the damage zone permeability is greater than 1 mD. The capillary
entry pressure acts as the main sealing mechanism with no significant gas
leakage in any of the tested cases (Fig. 7b). However, the capillary entry
pressure strongly depends on geometry of the pores within the rock
formation, as does the permeability. Considering this, by scaling the
capillary entry pressure according to the damage zone permeability shows a
significant increase in the gas leakage rates for higher permeabilities and
thus lower capillary entry pressures (Fig. 7c).
Based on the leakage rate observed in the 2-D model, the total leakage rate
and the leakage volume can be calculated by considering the exposure of the
gas-filled part of the storage formation to the fault zone. For the given
site, the total exposure length is about 3900 m (Fig. 3). Thus, the total
leakage rate is in the range from 1.3×102 to 2.2×105Sm3d-1 during the injection periods of the storage
operation and 0.2×102 to 1.5×105Sm3d-1 during withdrawal. During a complete storage cycle the total gas
leakage volume is in the range from 4.3×103 to 7.5×106Sm3, corresponding to 0.002 % to 2.8 % of the
total GIP.
Summary and conclusion
In this study, the leakage of gas along a fault system during a subsurface
gas storage operation at an existing geological structure was investigated
and the dependence of the gas leakage rates on the fault damage zone
permeability and capillary entry pressure was analysed. A 3-D
structural-geological model of the hypothetical storage site was constructed
and used to simulate a storage operation to obtain realistic boundary
conditions for the sensitivity analysis. The storage operation was designed
to provide enough electricity for one week to offset a complete lack of
renewable power generation in the state of Schleswig-Holstein, home to
around 2.8 million people. With the baseline characterisation, the gas
storage can deliver 100 % of the target power demand over a period of 7 d using five vertical wells. At the storage-fault interface this storage
operation results in pressure changes between injection and withdrawal of
around 7 bar. The leakage scenario simulations show that the fault zone
intersecting the storage formation can act as either a conduit or a barrier
for fluid flow, depending on petrophysical parameters, the fluid flow
properties and the current storage operation. During gas injection the
storage pressure increases, thus the peak leakage rates are observed during
these phases with values as high as 3000 Sm3d-1 for damage zone
permeabilities of 10 mD and capillary entry pressures of 0.13 bar. For lower
damage zone permeabilities and higher capillary entry pressures, the gas
leakage during injection is greatly reduced. However, the reduced or even
reversed pressure differential between the storage formation and the fault
zone during withdrawal periods can stop the leakage of gas altogether
regardless of the parametrisation of the fault zone. Thus, for storage
demand cases with long injection and short withdrawal periods gas leakage
might be more prominent than in cases with equal length withdrawal and
injection periods. The simulations show that the total leakage volume within
one cycle is less than 1.0 % of the GIP in the storage formation in most
cases. For a highly permeable damage zones, the simulated leakage volume can
reach up to 2.8 % of the total GIP.
The presented study considers isotropic and homogeneous petrophysical
properties in each individual (geological) unit. In reality, however, all
formations and fault zones show spatial heterogeneity in their petrophysical
parameters. A heterogeneous permeability distribution in the storage
formation could result in a local increase or decrease of the formation
pressure, compared to the homogenous case (Pfeiffer et al., 2017). As shown
in this and the previous studies such pressure changes affect the leakage
rates occurring in the fault zone. Furthermore, heterogeneity in the fault
zone can cause an appearance of impermeable lenses (Fredman et al., 2007;
Torabi et al., 2013), resulting in a decrease in gas leakage rate and thus
total leakage volume. It can also be expected that heterogeneity in the
fault zone can prevent significant flow upwards within the damage zone,
while the increase in pore pressure and the resulting reduction in effective
normal stress on the fault core can lead to its reactivation, potentially
increasing the fault core permeability (Rinaldi et al., 2014a). To consider
these processes in fully coupled hydro-mechanical process simulations a
detailed analysis and characterisation of the (site-specific) mechanical
properties of a fault zone is required.
Data availability
The data that support the findings of this study are available from the corresponding author upon reasonable request. The input data and the simulation results are not publicly available due to large dataset size (over 25 GB).
Author contributions
Initial conceptualisation of this topic have been done by SB and WTP and further developed by FG. Extensive literature research and numerical simulations have been carried out by FG. WTP and FG have analysed the simulation results with contributions of SB. The original draft has been written by FG under the supervision of WTP. Final draft editions have been carried out by SB.
Competing interests
The authors declare that they have no conflict of interest.
Special issue statement
This article is part of the special issue “European Geosciences Union General Assembly 2019, EGU Division Energy, Resources & Environment (ERE)”. It is a result of the EGU General Assembly 2019, Vienna, Austria, 7–12 April 2019.
Acknowledgements
The presented work is part of the ANGUS II research project (http://www.angus2.de/en, last access: 14 October 2019). We gratefully acknowledge the funding of the ANGUS II joint project by the German Federal Ministry of Economic Affairs and Energy (BMWi), as well as the support of the Project Management Jülich (PtJ). Furthermore, we would like to acknowledge the thoughtful reviews of the reviewers and the editor, and their constructive comments supporting the manuscript revision.
Financial support
This research has been supported by the German Federal Ministry of Economic Affairs and Energy (BMWi) (grant no. 03ET6122A).
Review statement
This paper was edited by Antonio Pio Rinaldi and reviewed by Lei Qinghua and one anonymous referee.
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