Transcript Poster - DETERMINATION OF CO2 AND H2S INFLUENCE11

2014-78
DETERMINATION OF CO2 AND H2S INFLUENCE
ON MINERALOGICAL COMPOSITION AND PETROPHYSICAL
PARAMETERS OF AQUIFER AND CAP ROCKS
Krzysztof
1)
1)
Labus ,
Renata
2)
Cicha-Szot ,
Silesian University of Technology;
2)
Grzegorz
2)
Leśniak
Oil and Gas Institute-NRI
Introduction
Acid gas (mainly CO2 and, H2S) interactions with rocks became of interest during the last decades
due to greenhouse effect abatement (e.g. Holloway, 2005), and in the case of carbon dioxide enhanced oil and gas recovery and energized fluid fracturing (Sinal, Lancaster, 1987). Although a
considerable research and published work on this subject, there are still uncertainties about the
behaviour of rocks under the influence of gases, in such artificial geochemical systems. In order to
investigate these phenomena in selected aquifers and low permeability rock formations of Central
Europe, we designed and performed a comprehensive study, enabling the hydrochemical models,
calibrated on the basis of experiments, considering the impact of acid gases: CO2 and H2S.
Experimental
results
Verified process of skeletal
grains dissolution (the most
intense in carbonates).
Cavities parallel to cleavage
planes in microcline, formed
due to selective etching of
the K-lamellae relative to Na
-lamellae
Amongst
the
secondary minerals also the
pyrite wasare found. Pits
developed on quartz grains,
initiate
the
crystals
destruction
Dawsonite observed only after
experiments is formed in the
pore
space
between
framework grains and within
clay mineral blades.
Elemental sulfur, surrounded by
FeS2 crystals cover mudstones
reacted in brine with H2S-CO2
mixture, no other secondary
minerals observed.
Materials and methods
Core samples represent Upper Carboniferous sandstones and mudstones of the Upper Silesian
Coal Basin, Jurassic marls the Mikulov Formation of the Vienna Basin, gas shales of Lower
Paleozoic of the East European Craton.
Composition of mineral assemblages determined by means of petrographic and planimetric
analysis of thin sections, and XRD analysis
Porosimetric properties determined by the Mercury Intrusion Porosimetry.
Samples were placed in the autoclave filled with artificial brine (composition equivalent to the
formation fluid), and acid gas injected to the desired pressure. The experiment was carried on for
100 days in order to simulate the initial period of storage, and reproduced water-rock-gas
interactions at the PVT regime of possible storage site.
Scanning electron microscope with EDX analyzer was used in examination of mineral phases in the
bare samples before and after autoclave experiments.
Modeling of water-rock-gas interactions was performed in two stages. The first one was aimed at
simulating the immediate changes in the aquifer and insulating rocks impacted by the beginning of
CO2 and/or H2S injection, the second – enabled assessment of long-term effects of sequestration.
The reactions quality and progress were monitored and their effects on formation porosity and
mineral sequestration capacity were calculated.
Pressure of 150 bar, exerted at T
80°C on clay mineral sheets,
forced water to be expelled. This,
further enabled oxidation of pyrite.
Desorbed cations form secondary
minerals – e.g. gypsum, celestite
Modeling acid gas impact on geochemical systems
PETROLOGICAL EVALUATION
Water chemistry
PT data
MICROSCOPY
SEM, XRD
HYDROGEOCHEMICAL MODELING
Sample
Short-term
Geochemical
Model
Mineralogy
Long-term
Geochemical
Model
Sequestration capacity assessment
Fresh core
POROSIMETRY
Porosity
Porosity
0
.245
Primary:
- minerals
- porosity
+10
+20
+30
+40
+50
+60
+70
+80
+90
Time (day)
.24
Secondary:
- minerals
- water composition
- porosity
.235
.23
.22
4+1
+10
+100
Time (yr)
3.5
+1000
Example 1
Calcite
Dawsonite
Sequestration
capacity
2.5
2
1.5
1
Dolomite
Siderite
.5
+10
+100
Time (yr)
For most of the sandstone aquifers
calculated mineral-trapping capacity
varies between 1.2 and nearly 1.9
kgCO2/m3, and for cap rocks is
between 0.89 and 1.42 kgCO2/m3,
which is 2-3 times lower than for
instance the Gulf Coast arenaceous
sediments considered as perspective
CO2 repositories. Solubility trapping
capacity is the highest for the aquifers
of high final porosities, and reaches
over 4.0 kgCO2/m3.
+1e4
3
0
+1
Geochemical
modeling
Primary
formation
water
composition
+100
.225
Some minerals (delta mol)
First stage - 100 days injection of CO2,
- increases gas fugacity, CO2(aq)
concentrations; pH drops at the same
time. Porosity increase is controlled by
dissolution of carbonates and kaolinite.
During 20 000 years of storage the total
porosity decreases in sandstones due
to precipitation of calcite, dolomite and
dawsonite - NaAlCO3(OH)2, in CO2
experiment.
Minerals
precipitating
in
CO2
experiment
are
chalcedony
and
dawsonite while iron sulfides and
elemental
sulfur
are
secondary
minerals in
H2S-CO2 sequestration
experiment.
Formation
water
Natural Analogue
Model
Experiment comparison
.245
.244
.243
.242
.241
.24
.239
.238
Formation PT
data
+1000
+1e4
Example 2
Caprock Aquifer Caprock Aquifer
B6
np -primary – 0 ka
nf - final - 20 ka
0.029
Porosity
0.025
Dawsonite
Precipitating
Minerals
Dolomite
0.064
mol/UVR*
Siderite
0.127
Siderite
Dissolution
mol/UVR*
Kalcite
mol/UVR
0.255
CO2
Mineral trapping
kg/m3 rock matrix
1.090
as HCO3- g/l
0.2
CO2
Solubility trapping kg CO2/m3 rock matrix 0.004
SUM [kg CO2/m3]
1,094
*)UVR-10dm3 (rock matrix + pore space)
B4
B9
B7
0.050
0.041
3.133
0.025
1.638
1.595
6.669
42.7
1.263
7.932
0.029
0.037
0.212
0.004
0.208
0.889
31.9
0.851
1.740
0,113
0,116
0,635
0,229
0,406
1,585
48,6
4.067
5.562
The research leading to these results has received funding from the Polish-Norwegian Research Programme, operated by the National Centre for Research and Development
under the Norwegian Financial Mechanism 2009-2014, in the frame of Project Contract No Pol-Nor/196923/49/2013.