Abstract
The effective permeability of the storage formation affects the amount and rate of CO2 injection
and has been identified as a major cost driver for selecting geological storage sites [1]. The
injection and storage of CO2 in geological formations with siliciclastic rocks can potentially
involve dissolution of the cement binding sand grains. Depending on the volumetric percentage of
the cement and pore (and throat) size distribution of the rock, fine migration and cement dissolution
can enhance or impair CO2 injection [2, 3]. The key factors governing the rate of cement
dissolution are mineralogy of the binding cement in the rock, ionic content of the formation brine
and pH of CO2-rich brine as well as pore surface area [4].These factors determine the dissolution
rates of cement in contact with the acidic CO2-aqueous phase.
Two sets of experiments were designed and performed to represent the dissolution of these
minerals at different conditions. The results from coreflood experiments would help investigate
whether resulting fine migration can affect permeability at the core scale. The batch test would
provide results representative of parts of the storage formation far away from the injection well
where mineral dissolution is diffusion dominant. The coreflood tests would be representative of
dissolution process in areas closer to the wellbore where advection is the dominant dissolution
mechanism. The selected core samples for both type of experiments was Berea sandstone. A brine
with a typical salinity of North Sea brine was selected (31,300ppm), including Na+, K+, Mg2+ and
Ca2+. The set of batch experiments was performed at typical reservoir conditions for storage (50°C
and 260 bars), using 38 mm diameter core samples with CO2-saturated brine over a 6 weeks period.
To investigate how CO2-saturated brine interacts with binding cement at conditions, the ionic
content of the brine before and after the experiments were analyzed by Inductively Coupled Plasma
- Optical Emission Spectrometer (ICP-OES).
In addition, to study potential cementing agent dissolution and its effect on permeability, a set of
coreflood experiments at similar pressure and temperature to the batch tests are performed. The
coreflood involves injection of CO2-saturated brine in the sandstone core samples of the same
Berea formation. During the tests, the produced effluent brine is sampled, and pH and ionic content
are analyzed. The pressure drop is recorded during the experiments to observe any potential
blockage or increase in permeability.
This paper will present a comprehensive characterization of the core samples, including porosity,
permeability measured before and after the hydrothermal experiments. The core samples are
further analyzed by XRD, SEM and micro CT.
and has been identified as a major cost driver for selecting geological storage sites [1]. The
injection and storage of CO2 in geological formations with siliciclastic rocks can potentially
involve dissolution of the cement binding sand grains. Depending on the volumetric percentage of
the cement and pore (and throat) size distribution of the rock, fine migration and cement dissolution
can enhance or impair CO2 injection [2, 3]. The key factors governing the rate of cement
dissolution are mineralogy of the binding cement in the rock, ionic content of the formation brine
and pH of CO2-rich brine as well as pore surface area [4].These factors determine the dissolution
rates of cement in contact with the acidic CO2-aqueous phase.
Two sets of experiments were designed and performed to represent the dissolution of these
minerals at different conditions. The results from coreflood experiments would help investigate
whether resulting fine migration can affect permeability at the core scale. The batch test would
provide results representative of parts of the storage formation far away from the injection well
where mineral dissolution is diffusion dominant. The coreflood tests would be representative of
dissolution process in areas closer to the wellbore where advection is the dominant dissolution
mechanism. The selected core samples for both type of experiments was Berea sandstone. A brine
with a typical salinity of North Sea brine was selected (31,300ppm), including Na+, K+, Mg2+ and
Ca2+. The set of batch experiments was performed at typical reservoir conditions for storage (50°C
and 260 bars), using 38 mm diameter core samples with CO2-saturated brine over a 6 weeks period.
To investigate how CO2-saturated brine interacts with binding cement at conditions, the ionic
content of the brine before and after the experiments were analyzed by Inductively Coupled Plasma
- Optical Emission Spectrometer (ICP-OES).
In addition, to study potential cementing agent dissolution and its effect on permeability, a set of
coreflood experiments at similar pressure and temperature to the batch tests are performed. The
coreflood involves injection of CO2-saturated brine in the sandstone core samples of the same
Berea formation. During the tests, the produced effluent brine is sampled, and pH and ionic content
are analyzed. The pressure drop is recorded during the experiments to observe any potential
blockage or increase in permeability.
This paper will present a comprehensive characterization of the core samples, including porosity,
permeability measured before and after the hydrothermal experiments. The core samples are
further analyzed by XRD, SEM and micro CT.
| Original language | English |
|---|---|
| Title of host publication | 10th Trondheim Conference on CO2 Capture, Transport and Storage |
| Publication status | Published - 19 Jun 2019 |
| Event | 10th Trondheim Conference on CO2 Capture, Transport and Storage 2019 - Trondheim, Norway Duration: 17 Jun 2019 → 19 Jun 2019 |
Conference
| Conference | 10th Trondheim Conference on CO2 Capture, Transport and Storage 2019 |
|---|---|
| Abbreviated title | TCCS 2019 |
| Country/Territory | Norway |
| City | Trondheim |
| Period | 17/06/19 → 19/06/19 |
Keywords
- Well drilling and completion, Site screening and site monitoring