scholarly journals Theoretical Modeling of the Impact of Salt Precipitation on CO2 Storage Potential in Fractured Saline Reservoirs

ACS Omega ◽  
2020 ◽  
Vol 5 (24) ◽  
pp. 14776-14785
Author(s):  
Yen A. Sokama-Neuyam ◽  
Patrick Boakye ◽  
Wilberforce N. Aggrey ◽  
Nicholas O. Obeng ◽  
Francis Adu-Boahene ◽  
...  
Keyword(s):  
Co2 Storage ◽  
Theoretical Modeling ◽  
Salt Precipitation ◽  
Storage Potential ◽  
The Impact

scholarly journals Experimental Investigation of the Mechanisms of Salt Precipitation during CO2 Injection in Sandstone

2019 ◽  
Vol 5 (1) ◽  
pp. 4 ◽  
Author(s):  
Yen Adams Sokama-Neuyam ◽  
Jann Rune Ursin ◽  
Patrick Boakye
Keyword(s):  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Physical Mechanisms ◽  
Low Salinity ◽  
Core Flood ◽  
Dry Out ◽  
The Impact ◽  
Brine Salinity

Deep saline reservoirs have the highest volumetric CO2 storage potential, but drying and salt precipitation during CO2 injection could severely impair CO2 injectivity. The physical mechanisms and impact of salt precipitation, especially in the injection area, is still not fully understood. Core-flood experiments were conducted to investigate the mechanisms of external and internal salt precipitation in sandstone rocks. CO2 Low Salinity Alternating Gas (CO2-LSWAG) injection as a potential mitigation technique to reduce injectivity impairment induced by salt precipitation was also studied. We found that poor sweep and high brine salinity could increase salt deposition on the surface of the injection area. The results also indicate that the amount of salt precipitated in the dry-out zone does not change significantly during the drying process, as large portion of the precipitated salt accumulate in the injection vicinity. However, the distribution of salt in the dry-out zone was found to change markedly when more CO2 was injected after salt precipitation. This suggests that CO2 injectivity impairment induced by salt precipitation is probably dynamic rather than a static process. It was also found that CO2-LSWAG could improve CO2 injectivity after salt precipitation. However, below a critical diluent brine salinity, CO2-LSWAG did not improve injectivity. These findings provide vital understanding of core-scale physical mechanisms of the impact of salt precipitation on CO2 injectivity in saline reservoirs. The insight gained could be implemented in simulation models to improve the quantification of injectivity losses during CO2 injection into saline sandstone reservoirs.

Regional Variability of Michigan Niagaran Reefs and the Impact on CO2 Storage Resources

2019 ◽  
Author(s):  
Autumn Haagsma ◽  
Andrew Burchwell ◽  
Amber Conner ◽  
Jackie Gerst ◽  
Wayne Goodman ◽  
...  
Keyword(s):  
Co2 Storage ◽  
Regional Variability ◽  
The Impact

A shortcut pressure swing adsorption analogue model to estimate Gas-in-Place and CO2 storage potential of gas shales

Fuel ◽  
2021 ◽  
Vol 301 ◽  
pp. 121014
Author(s):  
Humera Ansari ◽  
Elena Rietmann ◽  
Lisa Joss ◽  
JP Martin Trusler ◽  
Geoffrey Maitland ◽  
...  
Keyword(s):  
Pressure Swing Adsorption ◽  
Co2 Storage ◽  
Analogue Model ◽  
Gas Shales ◽  
Storage Potential ◽  
Pressure Swing

scholarly journals The impact of boundary conditions on CO2 storage capacity estimation in aquifers

2011 ◽  
Vol 4 ◽  
pp. 4828-4834 ◽  
Author(s):  
D.J. Smith ◽  
D.J. Noy ◽  
S. Holloway ◽  
R.A. Chadwick
Keyword(s):  
Boundary Conditions ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Capacity Estimation ◽  
The Impact

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1058-1068 ◽  
Author(s):  
P.. Bolourinejad ◽  
R.. Herber
Keyword(s):  
The Netherlands ◽  
Carbonic Acid ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Geological Time ◽  
Core Samples ◽  
Carbon Dioxide Co2 ◽  
Gas Fields

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

scholarly journals The investigation of CO2 storage potential in the Algoa basin in South Africa

2014 ◽  
Vol 63 ◽  
pp. 2800-2810 ◽  
Author(s):  
Nontobeko Chabangu ◽  
Brendan Beck ◽  
Nigel Hicks ◽  
Jurie Viljoen ◽  
Sean Davids ◽  
...  
Keyword(s):  
South Africa ◽  
Co2 Storage ◽  
Storage Potential

Online Modeling of CO2 Storage Systems

2021 ◽  
Author(s):  
Dale Douglas Erickson ◽  
Greg Metcalf
Keyword(s):  
Co2 Storage ◽  
Free Water ◽  
Oil Field ◽  
Management Tool ◽  
Carbon Dioxide Injection ◽  
Injection Wells ◽  
Internal Corrosion ◽  
Injection Process ◽  
Corrosion Risk ◽  
The Impact

Abstract This paper discusses the development and deployment of a specialized online and offline integrated model to simulate the CO2 (Carbon Dioxide) Injection process. There is a very high level of CO2 in an LNG development and the CO2 must be removed in order to prepare the gas to be processed into LNG. To mitigate the global warming effects of this CO2, a large portion of the CO2 Rich Stream (98% purity) is injected back into a depleted oil field. To reduce costs, carbon steel flowlines are used but this introduces a risk of internal corrosion. The presence of free water increases the internal corrosion risk, and for this reason, a predictive model discussed in this paper is designed to help operations prevent free water dropout in the network in real time. A flow management tool (FMT) is used to monitor the current state of the system and helps look at the impact of future events (startup, shutdowns etc.). The tool models the flow of the CO2 rich stream from the outlet of the compressor trains, through the network pipeline and manifolds and then into the injection wells. System behavior during steady state and transient operation is captured and analyzed to check water content and the balance of trace chemicals along with temperature and pressure throughout the network helping operators estimate corrosion rates and monitor the overall integrity of the system. The system has been running online for 24/7 for 2 years. The model has been able to match events like startup/shutdown, cooldowns and blowdowns. During these events the prediction of temperature/pressure at several locations in the field matches measured data. The model is then able to forecasts events into the future to help operations plan how they will operate the field. The tool uses a specialized thermodynamic model to predict the dropout of water in the near critical region of CO2 mixtures which includes various impurities. The model is designed to model startup and shutdown as the CO2 mixture moves across the phase boundary from liquid to gas or gas to liquid during these operations.

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