scholarly journals Preliminary geochemical modeling of water–rock–gas interactions controlling CO2 storage in the Badenian Aquifer within Czech Part of Vienna Basin

2016 ◽  
Vol 75 (14) ◽  
Author(s):  
K. Labus ◽  
P. Bujok ◽  
M. Klempa ◽  
M. Porzer ◽  
D. Matýsek
Keyword(s):  
Geochemical Modeling ◽  
Co2 Storage ◽  
Experimental Tests ◽  
Oil Field ◽  
Hydrochemical Modeling ◽  
Long Term Effects ◽  
Vienna Basin ◽  
Carbon Dioxide Gas ◽  
Gas Interactions ◽  
Water Gas

Abstract Prediction of hydrogeochemical effects of geological CO2 sequestration is crucial for planning an industrial or even experimental scale injection of carbon dioxide gas into geological formations. This paper presents a preliminary study of the suitability of saline aquifer associated with a depleted oil field in Czech Part of Vienna Basin, as potential greenhouse gas repository. Two steps of modeling enabled prediction of immediate changes in the aquifer and caprocks impacted by the first stage of CO2 injection and the assessment of long-term effects of sequestration. Hydrochemical modeling and experimental tests of rock–water–gas interactions allowed for evaluation of trapping mechanisms and assessment of CO2 storage capacity of the formations. In the analyzed aquifer, CO2 gas may be locked in mineral form in dolomite and dawsonite, and the calculated trapping capacity reaches 13.22 kgCO2/m3. For the caprock, the only mineral able to trap CO2 is dolomite, and trapping capacity equals to 5.07 kgCO2/m3.

scholarly journals Simulations of the Impact of Co-injected Gases on CO2 Storage, the SIGARRR Project: First Results on Water-gas Interactions Modeling

2014 ◽  
Vol 63 ◽  
pp. 3160-3171 ◽  
Author(s):  
J. Corvisier ◽  
E. El Ahmar ◽  
C. Coquelet ◽  
J. Sterpenich ◽  
R. Privat ◽  
...  
Keyword(s):  
Co2 Storage ◽  
First Results ◽  
Gas Interactions ◽  
The Impact ◽  
Water Gas

scholarly journals Carbon dioxide-water-silicate mineral reactions enhance CO2 storage; evidence from produced fluid measurements and geochemical modeling at the IEA Weyburn-Midale Project

2009 ◽  
Vol 1 (1) ◽  
pp. 3149-3155 ◽  
Author(s):  
Mark Raistrick ◽  
Ian Hutcheon ◽  
Maurice Shevalier ◽  
Michael Nightingale ◽  
Gareth Johnson ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Geochemical Modeling ◽  
Co2 Storage ◽  
Silicate Mineral

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.

scholarly journals InSAR Monitoring to Evaluate Surface Changes with CO2 Storage in a Depleted Oil Field in Northern Michigan

2020 ◽  
Author(s):  
Matthew Place ◽  
◽  
Marie-Josée Banwell ◽  
Giacomo Falorni ◽  
Neeraj Gupta
Keyword(s):  
Co2 Storage ◽  
Oil Field ◽  
Northern Michigan ◽  
Surface Changes

scholarly journals A novel experimental approach for studying spontaneous imbibition processes with alkaline solutions

2019 ◽  
Vol 89 ◽  
pp. 04004
Author(s):  
T. Chevalier ◽  
J. Labaume ◽  
A. Delbos ◽  
T. Clemens ◽  
V. M. Waeger ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Alkaline Solution ◽  
Recovery Process ◽  
Oil Field ◽  
Spontaneous Imbibition ◽  
Alkaline Solutions ◽  
Vienna Basin ◽  
Natural Surfactants ◽  
Current Flows ◽  
Kinetics Of

Spontaneous imbibition processes can play an important role in oil production. It can be enhanced or influenced by wettability changes generated by properly designed chemicals or by the natural surfactants resulting from reactive crude oils in the presence of alkaline solutions. The reaction of basic salts with some components of oil can, indeed, lead to the formation of natural soaps that reduces the interfacial tension between oil and brine. The latter scenario is studied herein on samples and oil from the St Ulrich oil field in the Vienna basin. To that end, spontaneous imbibition experiments were performed with two brines differing by the absence or presence of alkali. We first present a general novel technique to monitor saturation changes on small rock samples for the purpose of assessing the efficiency of a given recovery process. Samples of only 15 mm in diameter and 20 mm in length and set at irreducible saturation were fully immersed in the solution of interest, and the evolution of the samples’ saturation with time was monitored thanks to a dedicated NMR technique involving the quantification of the sole oil phase present within the sample. A fully-3D imbibition configuration was adopted, involving counter-current flows through all faces of the sample. The experimental method is fast for two reasons: (i) the kinetics of capillary imbibition process is proportional to the square of sample size, i.e. very rapid if accurate measurements can be acquired on tiny samples, (ii) the present 3D situation also involves faster kinetics than the 1D configuration often used. The NMR technique was crucial to achieve such conditions that cannot be satisfied with conventional volumetric methods. The kinetics of oil desaturation during spontaneous imbibition is interpreted with the help of an analytical 3D diffusion model. For the alkaline solution, the diffusion coefficient is reduced by a factor of only two compared to the non-alkaline brine, although the interfacial tension between the oil and the imbibing solution is reduced by a factor of 10. Hence, a wettability change to a more water wet state has to be assumed when the alkaline solution replaces the non-alkaline solution in the imbibition process. However, no significant impact on the final saturation was observed.

scholarly journals Application of a physics-based lumped parameter model to evaluate reservoir parameters during CO2 storage

2020 ◽  
Vol 10 (8) ◽  
pp. 3925-3935
Author(s):  
Samin Raziperchikolaee ◽  
Srikanta Mishra
Keyword(s):  
Oil Recovery ◽  
Co2 Storage ◽  
Field Application ◽  
Oil Field ◽  
Lumped Parameter Model ◽  
Linear Regression Method ◽  
Oil Reservoir ◽  
Michigan Basin ◽  
Reservoir Properties ◽  
Lumped Parameter

Abstract Evaluating reservoir performance could be challenging, especially when available data are only limited to pressures and rates from oil field production and/or injection wells. Numerical simulation is a typical approach to estimate reservoir properties using the history match process by reconciling field observations and model predictions. Performing numerical simulations can be computationally expensive by considering a large number of grids required to capture the spatial variation in geological properties, detailed structural complexity of the reservoir, and numerical time steps to cover different periods of oil recovery. In this work, a simplified physics-based model is used to estimate specific reservoir parameters during CO2 storage into a depleted oil reservoir. The governing equation is based on the integrated capacitance resistance model algorithm. A multivariate linear regression method is used for estimating reservoir parameters (injectivity index and compressibility). Synthetic scenarios were generated using a multiphase flow numerical simulator. Then, the results of the simplified physics-based model in terms of the estimated fluid compressibility were compared against the simulation results. CO2 injection data including bottom hole pressure and injection rate were also gathered from a depleted oil reef in Michigan Basin. A field application of the simplified physics-based model was presented to estimate above-mentioned parameters for the case of CO2 storage in a depleted oil reservoir in Michigan Basin. The results of this work show that this simple lumped parameter model can be used for a quick estimation of the specific reservoir parameters and its changes over the CO2 injection period.

NMR studies of water-gas interactions

BIOPHYSICS ◽  
2013 ◽  
Vol 58 (4) ◽  
pp. 446-452 ◽  
Author(s):  
V. P. Kutyshenko ◽  
S. I. Vorob’ev
Keyword(s):  
Nmr Studies ◽  
Gas Interactions ◽  
Water Gas
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