Cement-Sheath Wellbore Integrity for CO2 Injection and Storage Wells

Carbon capture and storage (CCS) has been increasingly looking like a promising strategy to reduce CO2 emissions and meet the Paris agreement’s climate target. To ensure that CCS is safe and successful, an efficient monitoring program that will prevent storage reservoir leakage and drinking water contamination in groundwater aquifers must be implemented. However, geologic CO2 sequestration (GCS) sites are not completely certain about the geological properties, which makes it difficult to predict the behavior of the injected gases, CO2 brine leakage rates through wellbores, and CO2 plume migration. Significant effort is required to observe how CO2 behaves in reservoirs. A key question is: Will the CO2 injection and storage behave as expected, and can we anticipate leakages? History matching of reservoir models can mitigate uncertainty towards a predictive strategy. It could prove challenging to develop a set of history matching models that preserve geological realism. A new Bayesian evidential learning (BEL) protocol for uncertainty quantification was released through literature, as an alternative to the model-space inversion in the history-matching approach. Consequently, an ensemble of previous geological models was developed using a prior distribution’s Monte Carlo simulation, followed by direct forecasting (DF) for joint uncertainty quantification. The goal of this work is to use prior models to identify a statistical relationship between data prediction, ensemble models, and data variables, without any explicit model inversion. The paper also introduces a new DF implementation using an ensemble smoother and shows that the new implementation can make the computation more robust than the standard method. The Utsira saline aquifer west of Norway is used to exemplify BEL’s ability to predict the CO2 mass and leakages and improve decision support regarding CO2 storage projects.

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Romania CCS Demo Project-Monitoring Technologies for CO2 Injection and Storage

10.3997/2214-4609.202020165 ◽

2020 ◽

Author(s):

S. Anghel ◽

C.S. Sava ◽

A. Dudu

Keyword(s):

Co2 Injection ◽

Project Monitoring ◽

Monitoring Technologies ◽

And Storage

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A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽

10.2118/205503-pa ◽

2021 ◽

pp. 1-17

Author(s):

Saira ◽

Emmanuel Ajoma ◽

Furqan Le-Hussain

Keyword(s):

Carbon Dioxide ◽

Oil Recovery ◽

Carbon Capture ◽

Molar Fraction ◽

Co2 Injection ◽

Carbon Dioxide Injection ◽

Treated Carbon ◽

Carbon Dioxide Co2 ◽

And Storage ◽

Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

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Cyclic CO2 – H2O injection and residual trapping: implications for CO2 injection efficiency and storage security

10.31223/osf.io/653cv ◽

2018 ◽

Author(s):

Katriona Edlmann ◽

Sofi Hinchliffe ◽

Niklas Heinemann ◽

Gareth Johnson ◽

Jonathan Ennis-King ◽

...

Keyword(s):

Co2 Injection ◽

Injection Efficiency ◽

Storage Security ◽

Residual Trapping ◽

And Storage

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The Impact of Geomechanics on Predicted Seismic Attributes for CO2 Injection and Storage

1st Sustainable Earth Sciences Conference and Exhibition (SES2011) ◽

10.3997/2214-4609.20144125 ◽

2011 ◽

Author(s):

T. Lynch ◽

Q.J. Fisher and P. Lorinczi

Keyword(s):

Seismic Attributes ◽

Co2 Injection ◽

The Impact ◽

And Storage

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An Experimental and Numerical Study of CO2–Brine-Synthetic Sandstone Interactions under High-Pressure (P)–Temperature (T) Reservoir Conditions

Applied Sciences ◽

10.3390/app9163354 ◽

2019 ◽

Vol 9 (16) ◽

pp. 3354

Author(s):

Zhichao Yu ◽

Siyu Yang ◽

Keyu Liu ◽

Qingong Zhuo ◽

Leilei Yang

Keyword(s):

High Pressure ◽

Numerical Modelling ◽

Numerical Study ◽

Mineral Dissolution ◽

Co2 Injection ◽

High Pressure And Temperature ◽

Reservoir Conditions ◽

Stainless Steel Reactor ◽

Geochemical Reactions ◽

And Storage

The interaction between CO2 and rock during the process of CO2 capture and storage was investigated via reactions of CO2, formation water, and synthetic sandstone cores in a stainless-steel reactor under high pressure and temperature. Numerical modelling was also undertaken, with results consistent with experimental outcomes. Both methods indicate that carbonates such as calcite and dolomite readily dissolve, whereas silicates such as quartz, K-feldspar, and albite do not. Core porosity did not change significantly after CO2 injection. No new minerals associated with CO2 injection were observed experimentally, although some quartz and kaolinite precipitated in the numerical modelling. Mineral dissolution is the dominant reaction at the beginning of CO2 injection. Results of experiments have verified the numerical outcomes, with experimentally derived kinetic parameters making the numerical modelling more reliable. The combination of experimental simulations and numerical modelling provides new insights into CO2 dissolution mechanisms in high-pressure/temperature reservoirs and improves understanding of geochemical reactions in CO2-brine-rock systems, with particular relevance to CO2 entry of the reservoir.

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Groundwater Anomaly Related to CCS-CO2 Injection and the 2018 Hokkaido Eastern Iburi Earthquake in Japan

Frontiers in Earth Science ◽

10.3389/feart.2020.611010 ◽

2020 ◽

Vol 8 ◽

Author(s):

Yuji Sano ◽

Takanori Kagoshima ◽

Naoto Takahata ◽

Kotaro Shirai ◽

Jin-Oh Park ◽

...

Keyword(s):

Carbon Capture ◽

Dissolved Inorganic Carbon ◽

Isotope Composition ◽

Source Region ◽

Carbon Capture And Storage ◽

Co2 Injection ◽

Focal Region ◽

Injection Point ◽

Anthropogenic Carbon ◽

And Storage

Carbon capture and storage (CCS) is considered a key technology for reducing CO2 emissions into the atmosphere. Nonetheless, there are concerns that if injected CO2 migrates in the crust, it may trigger slip of pre-existing faults. In order to test if this is the case, covariations of carbon, hydrogen, and oxygen isotopes of groundwater measured from Uenae well, southern Hokkaido, Japan are reported. This well is located 13 km away from the injection point of the Tomakomai CCS project and 21 km from the epicenter of September 6th, 2018 Hokkaido Eastern Iburi earthquake (M 6.7). Carbon isotope composition was constant from June 2015 to February 2018, and decreased significantly from April 2018 to November 2019, while total dissolved inorganic carbon (TDIC) content showed a corresponding increase. A decrease in radiocarbon and δ13C values suggests aquifer contamination by anthropogenic carbon, which could possibly be attributable to CCS-injected CO2. If such is the case, the CO2 enriched fluid may have initially migrated through permeable channels, blocking the fluid flow from the source region, increasing pore pressure in the focal region and triggering the natural earthquake where the brittle crust is already critically stressed.

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