SESolid EarthSESolid Earth1869-9529Copernicus PublicationsGöttingen, Germany10.5194/se-7-917-2016X-ray CT analyses, models and numerical simulations: a comparison with
petrophysical analyses in an experimental CO2 studyHenkelStevenhenkel.steven@uni-jena.dePudloDieterEnzmannFriederhttps://orcid.org/0000-0003-0506-3636ReitenbachViktorAlbrechtDanielGanzerLeonhardGauppReinhardInstitute of Geosciences, Friedrich Schiller University Jena, 07749
Jena, GermanyInstitute for Geosciences, Johannes Gutenberg University Mainz, 55122
Mainz, GermanyInstitute of Petroleum Engineering, Clausthal University of
Technology, 38678 Clausthal-Zellerfeld, GermanySteven Henkel (henkel.steven@uni-jena.de)7June20167391792725February20168March201611May201621May2016This work is licensed under a Creative Commons Attribution 3.0 Unported License. To view a copy of this license, visit http://creativecommons.org/licenses/by/3.0/This article is available from https://se.copernicus.org/articles/7/917/2016/se-7-917-2016.htmlThe full text article is available as a PDF file from https://se.copernicus.org/articles/7/917/2016/se-7-917-2016.pdf
An essential part of the collaborative research project
H2STORE (hydrogen to store), which is funded by the German government,
was a comparison of various analytical methods for characterizing reservoir
sandstones from different stratigraphic units. In this context Permian,
Triassic and Tertiary reservoir sandstones were analysed. Rock core
materials, provided by RWE Gasspeicher GmbH (Dortmund, Germany), GDF Suez
E&P Deutschland GmbH (Lingen, Germany), E.ON Gas Storage GmbH (Essen,
Germany) and RAG Rohöl-Aufsuchungs Aktiengesellschaft (Vienna, Austria),
were processed by different laboratory techniques; thin sections were
prepared, rock fragments were crushed and cubes of 1 cm edge length and plugs 3
to 5 cm in length with a diameter of about 2.5 cm were sawn from macroscopic
homogeneous cores. With this prepared sample material, polarized light
microscopy and scanning electron microscopy, coupled with image analyses,
specific surface area measurements (after Brunauer, Emmet and Teller, 1938; BET), He-porosity and
N2-permeability measurements and high-resolution
microcomputer tomography (μ-CT), which were used for numerical
simulations, were applied. All these methods were practised on most of the
same sample material, before and on selected Permian sandstones also after
static CO2 experiments under reservoir conditions. A major concern in
comparing the results of these methods is an appraisal of the reliability of
the given porosity, permeability and mineral-specific reactive (inner)
surface area data. The CO2 experiments modified the petrophysical as
well as the mineralogical/geochemical rock properties. These changes are
detectable by all applied analytical methods. Nevertheless, a major outcome
of the high-resolution μ-CT analyses and following numerical data
simulations was that quite similar data sets and data interpretations were
maintained by the different petrophysical standard methods. Moreover, the
μ-CT analyses are not only time saving, but also non-destructive.
This is an important point if only minor sample material is available and a
detailed comparison before and after the experimental tests on micrometre
pore scale of specific rock features is envisaged.
Introduction
The globally rising carbon dioxide emissions associated with increasing
climate extremes are intensively discussed by government authorities,
scientists, industrial representatives and the public. The target of the
intended so-called German Energiewende is a shift in energy production
based on fossil fuels and nuclear power to renewable energy sources (e.g.
wind, solar).
As part of these debates and transformation processes the German Federal Ministry of Education and Research (BMBF) funded the
hydrogen to store project (H2STORE). One main objective of the research
was to characterize mineral, synthetic formation fluid, microbiological and
petrophysical interactions in reservoir sandstones, induced by hydrogen and
carbon dioxide autoclave batch experiments (Pudlo et al., 2013, 2015; Henkel,
2016). Such reactions were investigated by autoclave experiments at reservoir
temperatures and pressures, using non-corrosive autoclaves and fluids similar
to reservoir-specific formation fluids. To satisfy the need to reduce
greenhouse gas emissions as per the Kyoto Protocol (1997) and most recently
the UN climate conference in Paris in 2015, intentions to capture, inject and
store CO2 (CCS) in the geological underground are even more relevant. In
particular, the geochemical and fluid chemical reactions of stored CO2
and the geological underground, which occur under different reservoir
conditions (p, T, x fluid), are not fully understood and need further
research, primarily on the maximum pressure, temperature and formation water
salinity conditions for potential CO2 storage sites. Also, the
utilization of CO2 combined with H2 injection into the geological
underground for the “green methane” generation (Šmigiáň et al.,
1990), enforced by microorganism activity (Panfilov, 2010), demands further
research regarding the potential
CO2–biotic-mineral-formation-fluid reactions.
Additionally, the integrity of wells, including the behaviour of e.g. bore
hole casings in a highly corrosive environment of H2/ CO2-gas
mixtures is an essential consideration in the potential usage of the
geological underground for storage options. This study contributes to these
topics by analysing rock samples provided by the industrial partners RWE
Gasspeicher GmbH (Dortmund, Germany), GDF Suez E&P Deutschland GmbH
(Lingen, Germany), E.ON Gas Storage GmbH (Essen, Germany) and RAG
Rohöl-Aufsuchungs-Aktiengesellschaft (Vienna, Austria). The samples are
representative for different sandstone reservoirs and therefore different
reservoir conditions.
High-resolution computed tomography (μ-CT) data associated with
numerical fluid flow simulations using the
GeoDict – Math2Market® modules and standard
petrophysical analyses, which were conducted at the Technical University
Clausthal before and after static autoclave experiments, were applied. Thus
we verified potential reactions induced by the CO2 autoclave
experiments on the Permian sandstones and compared these data with the results,
achieved by the other conventional petrophysical analytic methods (e.g. Pudlo
et al., 2014).
Material
The used sandstones derive from areas and stratigraphic formations which
comprise the main reservoir units in Germany and Austria. The sample material
originates from three different stratigraphic units, (a) the Permian from the
Altmark in north-eastern Germany, (b) the Triassic from the Emsland in
north-western Germany and (c) the Tertiary from the Molasse of south Germany and
north-western Austria (cf. Fig. 1 and Henkel et al., 2013). Therefore, the
source areas, the detrital content, the depositional environment and the
diagenetic evolution of these sediments are diverse, implying that the
samples experienced different burial pressures, temperatures and interactions
with their site-specific formation fluids. The current reservoir conditions
of the sample sites of interest are summarized in Table 1, showing the marked
differences, especially in regard to the Permian and Tertiary sample sites. The
current burial depth of the Permian samples is about 3500 m with a reservoir
temperature of 120 to 125 ∘C. This is in contrast to the recent
Tertiary reservoir conditions with a burial depth of 1600 m and reservoir
temperatures of about 40 ∘C (Table 1). Also, the formation fluid
salinities range from 35.22 % salinity in the Permian reservoirs to only
1.81 % salinity in the Tertiary formation fluids. Table 2 presents the
data on the handled sandstone samples along with the methods applied and the
Permian material used for the CO2 experiments.
Location map of the study areas with information on reservoir depth
and the company which provided sample material. The coloured outlined areas
represent the distribution of strata in the underground of the potential
reservoir units. In red the Permian, in blue the Triassic and in green the
Tertiary strata are shown (adapted from Henkel et al., 2013).
Overview of the recent reservoir conditions of the sampled
locations.
Sample overview and methods used for the presented data (A represents single analyses, B represents repeated method after CO2 autoclave experiments
with the same sample; X is outlining the samples used for these
experiments).
Material Thin sectionsPlugs CubeRockfragmentssamplestratigraphypetrographicHe-N2-autoclaveμ-CTBETanalysesporositypermeabilityexperimentC-1TertiaryAAAAC-2AAAC-3AAAC-4AAAC-5AAAC-6AAAC-7AAAAB-1TriassicAAAAAB-2AAAAAB-3AAAB-4AAAB-5AAAAB-6AAAAB-7AAAB-8AAAAA-1PermianAA/BA/BXA/BA/BA-2AAAAA-3AA/BA/BXA/BA/BA-4AAAAA-5AAAXA/BA-6AAAA-7AAAA-8AAAXA/BA/BA-9AAAXA/BA-10AAAXA/BA/B
Comparison of the detrital rock composition by petrographic thin-section
analyses shows that a wide range of sandstone types is present because of the
quartz, feldspar and lithoclast content of the different locations (Fig. 2,
after McBride, 1963). The Permian samples are classified mainly as arkoses,
subarkoses and quartz arenites; the Triassic sandstones vary from subarkoses,
lithic subarkoses, sublitharenites to litharenites and the Tertiary samples
comprise lithic subarkoses, sublitharenites, litharenites, lithic arkoses and
feldspar litharenites.
Petrographic sandstone classification after McBride (1963) for
samples of this study. This petrographic classification was conducted by
identifying and analysing 300 minerals in thin sections of the selected
samples and plotting the determined quartz (Q), feldspar (F) and lithoclast
(L) content in a ternary diagram. The different colours correspond to the
different stratigraphic units and therefore locations (cf. Fig. 1, Table 2).
Moreover, the rocks contain varying amounts of pore-filling, framework-stabilizing
cements like anhydrite, carbonate and exhibit different amounts
of open pore space (Fig. 3), which all influence the fluid flow fields
because of the different tortuosities of the pore network.
Thin-section images with 50× magnification given different
diagenetic features (pore-filling cements) of the sandstone samples. In (a) a
transmitted light image of a sample with free pore space is shown (blue
represents open pore). In (b) an image of a thin section with crossed nicols
is shown, highlighting pore-filling anhydrite cement (rainbow colours). In (c)
a transmitted light image of a thin section with pore-filling carbonate
cement is shown (arrows).
For the autoclave experiments and the petrophysical, mineralogical and
chemical analyses, the core material from all locations was prepared as in
Henkel et al. (2014). Thus the sandstone material for thin sections, plugs
(3.0 to 5.0 cm in length, 2.5 cm in diameter), μ-CT cubes (1.0 cm edge
length) and rock fragment (0.3 to 0.5 cm in diameter) preparation was
sampled side by side in the homogeneous zones of the drill core material to
guarantee the best possible comparability of the data generated by the
different methods. This is the standard for reservoir material
characterization. Examples of macroscopic homogeneous parts of the sampled
drill cores are given in Fig. 4, in which different lithotypes of the
reservoir material are also indicated. This will again influence the fluid
flow or fluid migration characteristics of the reservoir sandstones and
therefore the petrophysical properties, owing to the considerable tortuosities
of the pore network. Thus a wide range of different rock compositions and
qualities were available for this study. Also, the grain sizes of the
different sandstone samples varied from silt/fine sand to coarse sand
(Fig. 5) fraction (Wentworth, 1922).
Different examples of lithotypes of the analysed Permian sandstones.
In (a) a brownish, plane-horizontal stratified medium-grained sandstone type
is shown. In (b) a red, massive, medium coarse-grained sandstone type is
visualized and in (c) a greyish, obliquely bedded fine-medium-grained
sandstone type is presented.
In (a) the porosity results of the same eleven μ-CT and
He-porosity analysed samples are shown for the three different stratigraphic
units. The ellipse marks the sandstone samples with coarse sand
(2.00–0.63 mm) and medium sand (0.63–0.20 mm) grain sizes. In (b) the
permeability data of the same sample set as shown in (a) are presented. In (c)
the mean grain fraction sizes (after Wentworth, 1922) analysed on thin
section with the corresponding standard deviation of the 25 samples in this
study are shown (cf. Table 2). In (d) the mean values of the specific surface
area data from the BET and μ-CT methods are outlined for Permian and
Triassic samples.
Thus the property differences of the various reservoirs influence their
characteristics. In the CO2 autoclave experiments under reservoir
conditions, only the Permian samples were used, for capacity reasons. For all
samples the following methods were applied and the outcomes of the different
petrophysical methods were compared with the μ-CT-generated data.
Methods
Analytical methods were applied to macroscopically homogeneous sandstones
from the three stratigraphic formations on identical drill core material to
compare the outcomes achieved by the different analytical methods.
Additionally, the Permian samples were used for CO2 experiments in
sample-specific reservoir conditions and were analysed before and after
these experiments at the same samples and marked sample positions
respectively. Therefore, a pinpoint comparison of different mineral
reactions owing to the CO2 experiments was possible.
CO2 autoclave batch experiments lasting between four and seven weeks
were conducted at the Clausthal University of Technology (TU Clausthal) on
rock-formation brine systems, at high pressure and high temperature (HPHT)
with corrosion-resistant autoclaves and using selected thin sections, rock
fragments, cubes and plugs (Pudlo et al., 2015; Henkel et al., 2015). Helium
porosity and nitrogen permeability measurements before and after the tests
were performed on sandstone plugs at TU Clausthal. For porosity analysis the
set-up by Torsaeter and Abtahi (2003) was used and permeability
determinations were conducted with a Hassler cell in an up- and downstream
regime and calculated with Darcy's law equations.
In (a) the helium porosity and nitrogen permeability measurement
results of 16 Permian samples before and after CO2 experiments are
presented (data from Pudlo et al., 2012). In (b) the μ-CT porosity and
μ-CT permeability data for two Permian cube samples before and after
the CO2 experiments are shown. In (c) the mean values of the measured BET
surface areas (six samples) and the calculated μ-CT surface areas
(four samples) before and after the CO2 experiments are shown.
The fluid samples of the formation fluids used in the two autoclave
experiments (5 to 10 mL) were taken before, during and after the tests at TU
Clausthal and were chemically analysed in terms of their major, minor and trace
element contents at the Friedrich Schiller University Jena (FSU Jena).For the
analyses with an error of about 1 %, an inductively coupled plasma mass
spectroscope combined with an optical emission spectroscope (ICP-MS/OES) of
Thermo Fischer (Scientific X Series II) were used. Also, the
physicochemical characterization of the formation fluid was conducted in the
laboratories of the Institute of Geoscience in Jena. PHREEQC 3.3 software
(Parkhurst and Appelo, 2013) and a database for highly saline fluids (Pitzer
et al., 1984) were used to calculate the saturation indices of the fluids for
the pore-filling minerals (carbonate and anhydrite). Polarized light
microscopy and field-emission scanning electron microscopy (FE-SEM) were used
at FSU Jena for the mineralogical investigations. Thereby a Zeiss Axioplan II
petrological microscope, equipped with 10× magnification and
objectives of 2.5×, 5×, 10×, 20×, 40×
magnifications, was used. The microscope was combined with a mounted Hitachi
HV-C20 digital camera for high-resolution thin-section documentation. An SMT
ULTRA plus field-emission scanning electron microscope from Carl Zeiss
Enterprises, coupled with an energy-dispersive X-ray (EDX) detector and the analytical software of
Bruker AXS Microanalysis GmbH, was used for mineral documentation and
identification.
A Procon CT Alpha 160 device at Johannes Gutenberg University Mainz was used
for high-resolution computer tomography. The detector resolution was about
2048 × 2048 pixels. The parameters were 100 kV of voltage and a
current of 80 µA. Scans were performed at 0.45∘ steps over
a total rotation range of 360∘. The achieved resolution for the
different sample material was between 7.6 and 8.6 µm per voxel.
Sandstone cubes with an edge length of 1.0 cm were scanned. The
reconstruction of the scans was performed with the Octopus
7.0® software. The μ-CT image adaptation
with anisotropic diffusion filtering and pore space segmentation was
performed with Avizo® fire 7.1 software.
Intense distinct beam hardening was corrected with the software
MATLAB® and the approaches based on Jovanovic et
al. (2013). For the calculations of porosity, surface area, fluid flow and
deduced permeability, the corresponding modules PoroDict and FlowDict of the
software package GeoDict (Math2Market®) were
used (Wiegmann, 2007; Wiegmann et al., 2013). Therefore the calculated
surface areas from the μ-CT data correlated with the volume and weight of
the corresponding sandstone cube. The Navier–Stokes–Brinkman flow solver in
FlowDict and density properties of water at 20 ∘C were used for the
fluid flow simulation and permeability calculations.
The specific surface area (BET) measurements for gently crushed rock
fragments were determined following Brunauer et al. (1938) at the Technical
University of Munich before and after the experimental runs with exactly the
same sample material. Therefore the representable sandstone material adjacent
to the plugs, thin sections and cubes was used and broken by a press into
fragments with a diameter of about 0.3 to 0.5 cm. This material was
separated by a ripple divider to produce 5 to 7 g of sample
material for the analyses. This material was shipped for BET analyses, and
selected Permian samples after the measurements were used for the CO2
experiments before the BET analyses were repeated to detect any surface area
variation caused by the autoclave experiments. FE-SEM analyses of the crushed
sample surfaces were partly conducted after sample preparation to identify
any crack generation. No such artificial cracks were detected at the sample
surfaces up to nanometre scale.
Results
The initial state of the statistical porosity, permeability and specific
surface area data, determined by the different methods of this study, is shown
in Fig. 5. The measured helium porosity and nitrogen permeability values for
the Permian plug samples ranged from 5.64 to 14.73 % and from 2.61 to
161.32 mD respectively. For the measured Triassic samples, the helium
porosity data ranged between 11.02 and 29.95 % and nitrogen permeability
data between 251.93 and 1609.43 mD. The measured Tertiary plug samples
represent porosity values of 19.14 to 26.62 % and permeability values
from 25.80 to 388.00 mD. The corresponding parameters calculated from the
μ-CT data with PoroDict and FlowDict in the GeoDict software produced
porosity values of 2.55 to 15.36 % and permeability values of 8.56 to
570.28 mD for the Permian samples. For the Triassic samples porosities of
9.79 to 22.57 % and permeability values ranging from 18.41 to 449.09 mD
were computed. The Tertiary samples had calculated porosities of 0.52 to
10.41 %. Lack of flow connectivity (no connected pore networks in the
Tertiary samples were detected) meant that modelling of permeability from CT
data was not possible for these samples.
The specific surface area measured by the BET method after Brunauer et
al. (1938) of crushed rock fragments of the Permian samples revealed values
of 0.64 to 2.34 m2 g-1 and for the Triassic samples values
ranging from 0.45 to 1.72 m2 g-1. The calculated surface area
from the CT data sets ranged from 0.0018 to 0.0033 m2 g-1 for the
Permian sandstones and from 0.0006 to 0.0038 m2 g-1 for the
Triassic samples. The four Permian and two Triassic samples, which were
cross-checked by the BET and μ-CT calculation methods, are outlined in
Fig. 5d.
PHREEQC numerical simulations confirmed that because of the very high
concentrations of Na+, Ca2+ and Cl- (Table 2) the used
formation fluids are very close to saturation with respect to NaCl and
CaCO3 (Table 3). In contrast, this modelling suggests that anhydrite
(CaSO4) can be dissolved in these fluids, because of its slight
undersaturation of sulfur (S). Because of the high ion concentrations in the
synthetic brine, a very high electrical conductivity was measured (cf.
Tables 2 and 3).
Results of formation fluid analyses (ICP-MS/OES) of selected ions
and the corresponding physicochemical data of two Permian autoclave runs,
before and after CO2 experiments under static reservoir conditions.
Because of the common stratigraphic origin the initial formation brine
composition is similar for both samples.
Before CO2 experiments After CO2 experiments Na+Ca2+Cl-StotalpHelec. cond.Na+Ca2+Cl-StotalpHelec. cond.(g L-1)(g L-1)(g L-1)(mg L-1)(µS cm-1)(g L-1)(g L-1)(g L-1)(mg L-1)(µS cm-1)S 165.5354.27203.807.509.4545 7007.056.1522.24247.006.716790S 25.534.7717.5454.006.775370
For the CO2 experiments only sample material from Permian sandstones was
used. The measured petrophysical data after the CO2 experiments under
sample-specific reservoir conditions from the selected 16 sandstone plugs ranged
from 3.25 to 19.24 % for porosity and from > 0.01–419.60 mD
for permeability (Fig. 6a). These data were compiled from identical sample
material in a study by Pudlo et al. (2012). The calculated petrophysical data
of two sandstone cube samples from μ-CT scans resulted in porosity of
10.43 and 17.93 % and permeability of 247.58 and 1909.05 mD (Fig. 6b).
To determine the specific surface area in six Permian samples (cf. Table 2),
the BET method was used and values of 0.51 to
2.75 m2 g-1 were revealed. In contrast, PoroDict-calculated real surface areas
(after Ohser and Mücklich, 2000) from the μ-CT data sets of four
Permian sample cubes with a volume of 1 cm3 were lower. Here the
estimated real surface areas ranged between 0.0017 and
0.0024 m2 g-1 (Fig. 6c).
By comparing the calculated fluid flow fields before and after the CO2
experiments (cf. Figs. 7a–b and 8a–b), we found an increase of fluid
pathways related to enhanced porosity and permeability after the CO2
tests. Regarding the FE-SEM and EDX results on thin sections (cf. Fig. 9), a
dissolution of pore-filling anhydrite and carbonate cements was evident when
we compared identical sample position before and after the CO2
experiments (Fig. 9). The fluid chemical analyses after the CO2
experiments indicated an increase of sulfur and a depletion of Na+,
Ca2+ and Cl- (Table 3) in the formation fluid. Also, the pH and the
electrical conductivity values decreased in the formation fluid after the
CO2 experiments (cf. Tables 3 and 4).
PHREEQC modelling, showing saturation results of the interaction of
the synthetic formation fluid used before, during and after the CO2
experiments exposed to the Permian sandstones (n.a. is not analysed,
SI is the saturation index, pE is the negative logarithm of electron concentration
directly proportional to the redox potential).
P (MPa)T (∘C)pHpESI CaCO3SI CaSO4SI NaClLaboratory standard conditions0.1209.546.70.48-3.27-1.35before CO2 experimentsReservoir conditions during25.01203.236.7-3.19-4.09-1.70CO2 experimentsLaboratory standard conditions0.1206.71n.a.-3.39-4.93-3.10after CO2 experiments
In (a) and (b) the details of the same Permian sandstone sample before
(a) and after (b) the seven-week CO2 experiments under reservoir
conditions are shown. Note the reduction of the blocky cements (light grey)
and therefore the fluid flow field with increased fluid migration pathways
and rather higher migration velocities (blue to red colours) after the
experiments (b). This is verified by arrows I to III in a direct comparison
of the same sample position before and after the CO2 experiments.
In (a) and (b) the identical Permian sandstone sample is presented
before (a) and after (b) CO2 experiments under reservoir conditions.
The images are enhanced sections from Fig. 7 and verify the dissolution of
the blocky pore-filling cements (arrows) and the enhanced fluid flow field
and fluid flow velocities after the experiments resulting from the
dissolution events (blue to red colours).
Secondary electron FE-SEM images of the same section of a Permian
sandstone sample before (a, c) and after (b, d) CO2 experiments
under reservoir conditions for seven weeks. The dissolution of pore-filling
calcite cement (star in b) and the exposure of grain rimming clay minerals
(arrow in b) led to increasing porosity outcomes after the CO2
experiments and the increase of the specific surface area (modified after
Henkel et al., 2014). In (c) and (d) the dissolution of pore-filling anhydrite
cement (star in d) is shown at exactly the same thin-section position before
(c) and after (d) the CO2 experiments, also leading to increasing
porosity values after the experiments.
The PHREEQC calculations (Table 4) regarding the data sets from the
ICP-MS/OES analyses after the CO2 experiments suggested supersaturation
with respect to CaCO3 in the formation fluids. The slight
undersaturation of CaSO4 (anhydrite) in the fluids was even further
depressed during the CO2 experiments.
Discussion
The given comparison of the porosity data deduced by high-resolution computer
tomography scans and measurements by helium porosity confirms that the two
methods achieve very similar results (cf. Fig. 5). Nevertheless, the grain
sizes of sandstones (cf. Fig. 5a, c) and the restricted resolution rate of
the μ-CT scans of this sample influence the quality of the calculated
porosity data. Results from the fine-grained and very fine-grained sandstone
samples from the Tertiary and Triassic imply that the data of helium porosity
measurements are more precisely due to helium intrusion even into micropores
(< 7.6 µm resolution of μ-CT) and thus the
capability of helium to migrate even through very narrow pore throats. In
contrast, because of the limited resolution of μ-CT scans (7.6 to
8.6 µm voxel-1), such micropores are therefore not
detectable and calculated porosities are marginally lower than those revealed
by helium porosity measurements. These differences regarding micropores
probably led to distinct porosity data in fine-grained to very fine-grained
rocks, whereas porosity determinations on coarse- and medium-grained
sandstone samples are similar in both methods. By comparing the results from
identical samples after the CO2 experiments, we found that both methods
confirm the same increase in porosity. The mean helium porosity measurements
revealed an increase in total porosity of 16.0 % and the calculated
μ-CT data one of 12.6 % because of the CO2 experiments. Thus,
the effects on porosity characteristics after four to seven week-long
CO2 experiments under reservoir conditions are verified by both methods.
Also, the calculation of the surface areas using μ-CT data is limited by the
restricted resolution of the μ-CT scans. However, the calculations by the
GeoDict software can offer reference values. Nevertheless, the results of the
specific surface area measurements after Brunauer et al. (1938) are more
realistic if compared with sandstone data from the literature (see e.g.
Pudlo et al., 2015) and for a direct comparison of the data from the same
sample before and after the CO2 experiments, the BET method is of great
benefit (cf. Kieffer et al., 1999). Also, compared with the GeoDict approach,
more reliable data were achieved with the BET method. The μ-CT
calculations and GeoDict modules could profit by including additional
parameters in the calculations such as rock/mineral densities, volume and the
compositional as well as the morphological features of the pore space exposed
mineral phases. Nevertheless an important outcome of comparing the data sets
compiled before and after the CO2 experiments is that both methods
confirm an increase in surface area. The μ-CT investigations and
calculations indicated an enhancement in the surface area of about
14.3 %, which is very similar to the 10.4 % maintained by the BET
method. This is supported by the FE-SEM findings (Fig. 9) with an enhanced
exposure of small grain rimming clay minerals (chlorite) to the pore space
after the CO2 experiments because of the dissolution of the former pore
filling and the clay minerals blocking carbonate and anhydrite cements.
The measured nitrogen permeability data and the results from the μ-CT
calculations by GeoDict are of the same order (cf. Fig. 5b). Nevertheless,
the quality of calculated permeabilities from the μ-CT data sets is
restricted to the resolution of the CT scan and therefore of the segmented
pore space (pixel resolution: 7.6 to 8.6 µm). Here again the grain
size of the scanned samples is a limiting factor combined with the scan
resolution. While for coarse- and medium-grained sandstones, the results are
most similar to the nitrogen permeability measurements, these resemblances
are minimized with decreasing grain size. Nevertheless, by comparing the
permeability data after the CO2 experiments with the results before the
experiments, we found that both methods confirmed a marked increase in
permeability induced by the tests (cf. Fig. 6a, b). This increase is about
1.75 times higher in the calculations than in the nitrogen permeability
measurements.
The fluid chemical analyses confirmed the petrophysical outcomes e.g. an
increase of Stotal in the formation fluids after the experiments
which originated from the dissolution of the pore-filling anhydrite cements
in the samples. This led to increased petrophysical properties (porosity,
permeability, surface area) in the reservoir sandstone samples. The fluid
flow simulations also indicated that, even when sampled in homogeneous drill
core zones, the lithotypes and poikiloblastic texture of the cements (cf.
Fig. 8) influenced the fluid migration pathways and their dissolution as the
CO2 experiments enhanced the reservoir quality.
Nevertheless, the heterogeneity of a sandstone sample within a few millimetres or
centimetres can reveal different petrophysical characteristics or influence different
geochemical or fluid chemical analyses compared with a sample alongside to the previous.
This is of concern, especially in the analysis of different lithotypes in
one reservoir unit, sandstone samples with poikiloblastic textures of pore-filling cements or sandstones with clay lenses.
Conclusions
This study confirms that high-resolution computer tomography is a suitable
method for verifying data from petrophysical standard methods as well as for
identifying alteration of various mineral phases of sandstone samples
induced during CO2 batch experiments. The benefit of analysing the same
sample before and after environmental impacts or mechanical stress is
already well known in the literature (Saadatfar et al., 2012; Rozenbaum,
2011; Van den Bulcke et al., 2009; Zabler et al., 2008).
The dissolution of carbonates and anhydrite, present as pore-filling cements
before the tests, increased rock porosity and surface area. The gain in
surface area was caused by an enhanced exposure of small grain-rimming clay
minerals to the pore space, which were covered by the pore-filling cements
before the experiments and detectable with all methods.
The results from μ-CT analyses and numerical simulations are in
accordance with helium porosity and nitrogen permeability measurements. The
determination of specific surfaces by BET after Brunauer et al. (1938) and
findings by scanning electron microscopy as well as hydro-, mineral- and geochemical
analyses of similar sandstones (e.g. Pudlo et al., 2012, 2013, 2015; Henkel, 2016)
confirm marked modifications in rock composition induced by CO2 autoclave
experiments. This is most relevant in evaluating the suitability and quality
of potential underground reservoirs. Nevertheless the compromise between the representative sample size and the
pixel resolution of the μ-CT scans, especially regarding heterogeneities
of the sampled material, will still be challenging (Cnudde and Boone, 2013).
In the future, the discussed deviations of data reliability related to grain
sizes can be precluded by applying higher scan resolutions and/or smaller
sample sizes, following e.g. the approach of Nordahl and Ringrose (2008) to
determine an appropriate representative elementary volume (REV) for each
sample. This complexity is one of the major topics of the ongoing work by the
authors in the HyINTEGER collaborative research project.
Acknowledgements
The authors thank G. Pronk and K. Heister of the Technical University
Munich for BET measurements and support. We appreciate funding of the
collaborative project H2STORE (grant no. 03SF0434) by the German Federal
Ministry of Education and Research (BMBF) within the Energiespeicher
R&D programme. We also thank the German Federal Ministry for Economic
Affairs and Energy for funding the subsequent HyINTEGER project (grant no. 03ET6073). Special thanks go to the industrial partners RWE Gasspeicher GmbH
(Dortmund, Germany), GDF Suez E&P Deutschland GmbH (Lingen, Germany),
E.ON Gas Storage GmbH (Essen, Germany) and RAG Rohöl-Aufsuchungs
Aktiengesellschaft (Vienna, Austria) for sample and data allocation.
Edited by: H. Steeb
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