geosciences
Article
Geological Model of a Storage Complex for a CO
2
Storage Operation in a Naturally-Fractured
Carbonate Formation
Yann Le Gallo
1,
* and José Carlos de Dios
2
1
Geogreen, 2 rue des Martinets, 92569 Rueil Malmaison, France
2
Fundación Ciudad de la Energía, Avenida del Presidente Rodríguez Zapatero, 24492 Cubillos del Sil, Spain;
jc.dedios@ciuden.es
* Correspondence: ylg@geogreen.fr; Tel.: +33-1-4708-7351
Received: 23 May 2018; Accepted: 12 September 2018; Published: 19 September 2018
Abstract:
Investigation into geological storage of CO
2
is underway at Hontomín (Spain). The storage
reservoir is a deep saline aquifer formed by naturally fractured carbonates with low matrix
permeability. Understanding the processes that are involved in CO
2
migration within these formations
is key to ensure safe operation and reliable plume prediction. A geological model encompassing
the whole storage complex was established based upon newly-drilled and legacy wells. The matrix
characteristics were mainly obtained from the newly drilled wells with a complete suite of log
acquisitions, laboratory works and hydraulic tests. The model major improvement is the integration
of the natural fractures. Following a methodology that was developed for naturally fractured
hydrocarbon reservoirs, the advanced characterization workflow identified the main sets of fractures
and their main characteristics, such as apertures, orientations, and dips. Two main sets of fracture
are identified based upon their mean orientation: North-South and East-West with different fracture
density for each the facies. The flow capacity of the fracture sets are calibrated on interpreted injection
tests by matching their permeability and aperture at the Discrete Fracture Network scale and are
subsequently upscaled to the geological model scale. A key new feature of the model is estimated
permeability anisotropy induced by the fracture sets.
Keywords:
CO
2
geological storage; naturally-fractured fractured carbonates; CO
2
migration plume;
updated geological model; Discrete Fracture Network
1. Introduction
CO
2
geological storage has reached industrial scale in sites, such as Sleipner (Norway), In-Salah
(Algeria), and Decatur (IL, USA). These sites represent examples approaching the ideal conditions for
establishing a commercial site according to criteria established in the SACS project [
1
]. Other CO
2
injection pilots also achieved notable scientific results for example, including Otway (Vic, Australia),
Ketzin (Germany), Nagaoka (Japan), and Rousse (France) [2].
The Hontomín pilot is the only current onshore injection site in Europe for CO
2
geological storage,
recognized by the European Parliament [
3
] as key test facility for Carbon Capture and Storage (CCS)
technology development. It is located close to Burgos in the north of Spain, and is operated by
Fundación Ciudad de la Energía (CIUDEN, Cubillos del Sil, Spain).
The Hontomín storage reservoir comprises naturally fractured limestones and dolomites.
The injection of CO
2
into fractured carbonate rocks for dedicated storage is unique in a European
context, although considerable experience of injection into carbonates was gained in association with
enhanced oil recovery (EOR) operations, as, for example, in the Weyburn-Midale CO
2
project (SK,
Canada) [4] and the Uthmaniyah CO
2
-EOR demonstration project (Saudi Arabia) [5].
Geosciences 2018, 8, 354; doi:10.3390/geosciences8090354 www.mdpi.com/journal/geosciences
Geosciences 2018, 8, 354 2 of 13
Prior to dynamically modeling the CO
2
migration, a detailed modeling of the characteristics of
the storage complex is required as a key first step workflow for CO
2
storage site characterization [
6
].
The storage complex boundaries, defined in the European Storage Directive [
7
] as “the storage site
and surrounding geological domain which can have an effect on overall storage integrity and security;
that is, secondary containment formations”.
This paper presents the main features of the geological model of the storage complex with
its stratigraphic and petrophysical properties. The characterization workflow applied to fractured
sandstone formations at In-Salah [
8
] is transposed to naturally fractured carbonate. These reservoirs
are particularly challenging to handle because of their high level of heterogeneity that conditions the
reservoir behaviour during the injection. In particular, natural fractures have a significant impact on
well performance. Furthermore, the understanding of the processes that are involved in CO
2
migration
within relatively low-permeability storage influenced by fractures and faults is essential for enabling
safe storage operation [
9
]. This work integrates the characterization (size, conductivities) of the natural
fracture networks by its modeling in the drainage volume of the wells [10].
As part of the European project “Enabling Onshore CO
2
Storage in Europe” (ENOS) [
11
],
the site geological model is updated by integration of the recently acquired data, such as the image
log interpretations from injection and observation newly-drilled wells. The geological model is
generated through the analysis and integration of data, including borehole images and well test data.
Following a methodology developed for naturally fractured hydrocarbon reservoirs [
12
], the image
log analysis identified two sets of diffuse fractures. Discrete Fracture Network (DFN) [
13
] were
built within the drainage volume of the newly-drilled wells that encompass the caprock, storage and
underburden formations.
The fracture characteristics of the two sets of diffuse fractures, such as orientations, densities,
and conductivities, are calibrated upon the interpretation of the injection tests. For each facies, the DFN
characteristics were then upscaled and propagated to the full-field reservoir simulation model as
three-dimensional (3-D) fracture properties (fracture porosity, fracture permeability, and equivalent
block size).
2. Geological Modeling
2.1. Geological Context
The storage site represents a structural dome where the cap rock and reservoir belong to the
Jurassic formations Marly Lias and Sopeña, respectively. Keuper is the underlying seal and Dogger,
Purbeck and Weald form the overburden [
14
]. Pair seal-reservoir is located at the depth of 900 in the
top of the dome and 1832 m in flanks. During the site construction two wells were specifically drilled
and monitored reaching the depth of 1600 m (Keuper Formation), one for injection (HI) and other for
observation (HA) [15]. Four legacy wells are also located in the study area (H1, H2, H3, and H4).
Marly Lias and Pozazal formations are mainly comprised of highly carbonated marls (close to
50%) with uniaxial strength values equal or higher than 130
×
10
6
Pa and Young modulus values in the
range 15–30 × 10
9
Pa. The Sopeña formation is comprised of limestone in the upper part of reservoir
and dolomite at the bottom. Their geomechanical properties correspond to rocks with high values of
uniaxial strength, as the cap rock case, being the values for limestones and dolomites equal or higher
than 180
×
10
6
Pa and 190
×
10
6
Pa, respectively. As regards the Young Modulus values, they are in
the ranges of 30–60
×
10
9
Pa and 50–85
×
10
9
Pa [
16
]. The overlaying formation Dogger has similar
properties. Consequently, post fracture behaviors for the seal, overlaying formations, and the reservoir
should be different, while taking into account the tectonic effects induced in the rock layers during the
formation of the dome. Uniaxial strength values are really high for a carbonated marl, but the Young
Modulus range reveals that despite being a hard rock its behavior should be of type “strain softening”,
with significant deformations pre and post fracture. On other hand, carbonates in Sopeña and Dogger
Geosciences 2018, 8, 354 3 of 13
formations show also high values of uniaxial strength, but Young Modulus values support an “elastic
brittle” behavior that means no significant strains take place after rock fracture.
These assumptions were confirmed by the acoustic Televiewer logging [
17
] that was conducted
during the well drilling at Hontomín pilot, which revealed the existence of faults and associated
fractures that mainly affect the overburden without continuity through the cap rock and reservoir
what ensures its integrity except in two cases described below. High degree of fracture within the
reservoir was also proven [18].
The petrophysical properties, such as effective porosity and gas permeability, were determined
by laboratory tests conducted with reservoir core samples acquired during well drilling. These tests
were conducted under reservoir conditions (pressure and temperature) injecting CO
2
and brine to
assess the hydrodynamic and geochemical effects [
19
]. The results revealed that fluid transmissivity is
dominated by carbonate fractures. Subsequent tests conducted at field scale on site during the hydraulic
characterization were performed injecting brine to determine the permeability in several intervals of
the open hole of each well and the hydraulic connectivity between wells. The interpretation of the
results using Saphir
TM
supported the assumption that fluid migration is dominated by fractures [18].
In the development of the static model, which will be described later, all of the peculiarities
analyzed above were considered. Two main faults cross the storage complex from the reservoir to
the overburden, which limit the south-eastward extension of the storage. Ubierna fault, located at
the southern part of Hontomín area, and East fault are shown in Figure 1. The storage formation is
dipping towards the north and north-west, with its apex around H2 well. Future works will be carried
out to determine whether both faults are sealing or transmissible to flow.
Geosciences 2018, 8, x FOR PEER REVIEW 3 of 13
and Dogger formations show also high values of uniaxial strength, but Young Modulus values
support an “elastic brittle” behavior that means no significant strains take place after rock fracture.
These assumptions were confirmed by the acoustic Televiewer logging [17] that was conducted
during the well drilling at Hontomín pilot, which revealed the existence of faults and associated
fractures that mainly affect the overburden without continuity through the cap rock and reservoir
what ensures its integrity except in two cases described below. High degree of fracture within the
reservoir was also proven [18].
The petrophysical properties, such as effective porosity and gas permeability, were determined
by laboratory tests conducted with reservoir core samples acquired during well drilling. These tests
were conducted under reservoir conditions (pressure and temperature) injecting CO
2
and brine to
assess the hydrodynamic and geochemical effects [19]. The results revealed that fluid transmissivity
is dominated by carbonate fractures. Subsequent tests conducted at field scale on site during the
hydraulic characterization were performed injecting brine to determine the permeability in several
intervals of the open hole of each well and the hydraulic connectivity between wells. The
interpretation of the results using Saphir
TM
supported the assumption that fluid migration is
dominated by fractures [18].
In the development of the static model, which will be described later, all of the peculiarities
analyzed above were considered. Two main faults cross the storage complex from the reservoir to
the overburden, which limit the south-eastward extension of the storage. Ubierna fault, located at the
southern part of Hontomín area, and East fault are shown in Figure 1. The storage formation is
dipping towards the north and north-west, with its apex around H2 well. Future works will be carried
out to determine whether both faults are sealing or transmissible to flow.
Figure 1. Hontomín geological model extension. The South fault, i.e., Ubierna fault (in dark blue), and
East fault (in light green) control the structural south-eastward extension of the storage formation.
Figure 1.
Hontomín geological model extension. The South fault, i.e., Ubierna fault (in dark blue),
and East fault (in light green) control the structural south-eastward extension of the storage formation.
Geosciences 2018, 8, 354 4 of 13
2.2. Geological Model
The geological model covers the whole storage complex from the overburden (Dogger formation)
down to the storage (Sopeña formation) and the underburden (Keuper formation), as shown in Figure 2.
Geosciences 2018, 8, x FOR PEER REVIEW 4 of 13
2.2. Geological Model
The geological model covers the whole storage complex from the overburden (Dogger
formation) down to the storage (Sopeña formation) and the underburden (Keuper formation), as
shown in Figure 2.
Figure 2. Vertical cross-section of the geological model of the Hontomìn storage complex; The HA
and HI newly-drilled wells are the observation and CO
2
injection wells, respectively, while H2 to H4
wells are legacy wells.
2.3. Structural Model
A 3-D seismic reflection survey was acquired in 2010, which parameters included 22 source lines
(cross-lines), deployed East-West (E-W), perpendicular to 22 receiver lines (in-lines) deployed North-
South (N-S), with intervals of 25 m between sources and between receivers; the inline and crossline
spacing was 250 m and 275 m, respectively, covering a total extent of 36 km
2
. Due to the complex
geological setting of the Hontomìn site and the existence of an unexpected sharp velocity inversion
near the surface, which was associated to the Upper-Lower Cretaceous contact [20], the 3-D seismic
only identified the main horizons below the Dogger. These horizons were matched to the
corresponding makers for legacy and newly-drilled wells.
The faults are only interpreted at the top of the storage formation from the 3-D seismic
interpretations and are assumed to be vertical within the reservoir.
The grid of the geological model was designed to follow the facies vertical heterogeneities
(Figure 3). The storage formation is modeled with 39 layers, which thicknesses range between 1 and
10 m. The lateral facies heterogeneities representations are coarser due to the lack of well correlations
and because they represent a significant uncertainty in the modeling approach.
Figure 2.
Vertical cross-section of the geological model of the Hontomìn storage complex; The HA and
HI newly-drilled wells are the observation and CO
2
injection wells, respectively, while H2 to H4 wells
are legacy wells.
2.3. Structural Model
A 3-D seismic reflection survey was acquired in 2010, which parameters included 22 source
lines (cross-lines), deployed East-West (E-W), perpendicular to 22 receiver lines (in-lines) deployed
North-South (N-S), with intervals of 25 m between sources and between receivers; the inline and
crossline spacing was 250 m and 275 m, respectively, covering a total extent of 36 km
2
. Due to the
complex geological setting of the Hontomìn site and the existence of an unexpected sharp velocity
inversion near the surface, which was associated to the Upper-Lower Cretaceous contact [
20
], the 3-D
seismic only identified the main horizons below the Dogger. These horizons were matched to the
corresponding makers for legacy and newly-drilled wells.
The faults are only interpreted at the top of the storage formation from the 3-D seismic
interpretations and are assumed to be vertical within the reservoir.
The grid of the geological model was designed to follow the facies vertical heterogeneities
(Figure 3). The storage formation is modeled with 39 layers, which thicknesses range between 1 and
10 m. The lateral facies heterogeneities representations are coarser due to the lack of well correlations
and because they represent a significant uncertainty in the modeling approach.
Geosciences 2018, 8, 354 5 of 13
Geosciences 2018, 8, x FOR PEER REVIEW 5 of 13
Figure 3. Facies, fracture dip–Televiewer log (Courtesy of Instituto de Ciencias de la Tierra Jaume
Almera) and porosity logs for HI and HA wells.
2.4. Petrophysical Model
The petrophysical model is established from the facies and neutron porosity log available from
HA and HI wells and laboratory results. Since only the two newly-drilled wells have facies and
porosity information, a simple modeling approach is selected for property modeling, as detailed next.
2.4.1. Facies
The facies are based upon horizontally-isotropic spherical variograms with an assumed
correlation length that is equal to 100 m, while still being constrained at the wells. Due to the lack of
correlation, the vertical correlation length of the facies is assumed to be limited to the formation
thicknesses as shown in Table 1. This is particularly important in the Pozazal and Marly Lias
formations (main cap rock) which show successions of shales, limestones, and marls. The vertical
correlation length may alter the vertical connectivity between the formations. Consequently, the grid
thickness is quite small in the Pozazal formation, which shows alternations of marl and shale layers,
as illustrated in Figure 3.
Figure 3.
Facies, fracture dip–Televiewer log (Courtesy of Instituto de Ciencias de la Tierra Jaume
Almera) and porosity logs for HI and HA wells.
2.4. Petrophysical Model
The petrophysical model is established from the facies and neutron porosity log available from
HA and HI wells and laboratory results. Since only the two newly-drilled wells have facies and
porosity information, a simple modeling approach is selected for property modeling, as detailed next.
2.4.1. Facies
The facies are based upon horizontally-isotropic spherical variograms with an assumed correlation
length that is equal to 100 m, while still being constrained at the wells. Due to the lack of correlation,
the vertical correlation length of the facies is assumed to be limited to the formation thicknesses as
shown in Table 1. This is particularly important in the Pozazal and Marly Lias formations (main cap
rock) which show successions of shales, limestones, and marls. The vertical correlation length may
alter the vertical connectivity between the formations. Consequently, the grid thickness is quite small
in the Pozazal formation, which shows alternations of marl and shale layers, as illustrated in Figure 3.
