Chemistry of Reservoir Fluids in the Aspect of CO2 Injection for Selected Oil Reservoirs in Poland

Worldwide experiences related to geological CO2 storage show that the process of the injection of carbon dioxide into depleted oil reservoirs (CCS-EOR, Carbon Capture and Storage—Enhanced Oil Recovery) is highly profitable. The injection of CO2 will allow an increasing recovery factor (thus increasing CCS process profitability) and revitalize mature reservoirs, which may lead to oil spills due to pressure buildups. In Poland, such a solution has not yet been implemented in the industry. This work provides additional data for analysis of the possibility of the CCS-EOR method’s implementation for three potential clusters of Polish oil reservoirs located at a short distance one from another. The aim of the work was to examine the properties of reservoir fluids for these selected oil reservoirs in order to assure a better understanding of the physicochemical phenomena that accompany the gas injection process. The chemical composition of oils was determined by gas chromatography. All tested oils represent a medium black oil type with the density ranging from 795 to 843 g/L and the viscosity at 313 K, varying from 1.95 to 5.04 mm/s. The content of heavier components C25+ is up to 17 wt. %. CO2–oil MMP (Minimum Miscibility Pressure) was calculated in a CHEMCAD simulator using the Soave–Redlich–Kwong equation of state (SRK EoS). The oil composition was defined as a mixture of n-alkanes. Relatively low MMP values (ca. 8.3 MPa for all tested oils at 313 K) indicate a high potential of the EOR method, and make this geological CO2 storage form more attractive to the industry. For reservoir brines, the content of the main ions was experimentally measured and CO2 solubility under reservoir conditions was calculated. The reservoir brines showed a significant variation in properties with total dissolved solids contents varying from 17.5 to 378 g/L. CO2 solubility in brines depends on reservoir conditions and brine chemistry. The highest calculated CO2 solubility is 1.79 mol/kg, which suggest possible CO2 storage in aquifers.

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Why CCS? Milestone on Research and Regulation Coverages

KnE Energy ◽

10.18502/ken.v1i1.346 ◽

2015 ◽

Vol 1 (1) ◽

pp. 13

Author(s):

Aisyah Kusuma ◽

Eko Widianto ◽

Rachmat Sule ◽

Wawan Gunawan A. Kadir ◽

Mega S. Gemilang

Keyword(s):

Oil Recovery ◽

Carbon Capture ◽

Carbon Emission ◽

Fossil Fuels ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Point Sources ◽

Co2 Injection ◽

Road Map ◽

And Storage

Further to Kyoto Protocol, again in 2009 G-20 Pittsburg Summit, Indonesia delivered the commitment on reducing 26% on its emission level. Moreover, as non-annex 1 country, Indonesia shows strong and bold commitment in supporting reduction on increased concentrations of greenhouse gases produced by human activities such as burning the fossil fuels and deforestation. From the energy sector, Carbon Capture and Storage (CCS) is known as a process of capturing waste carbon dioxide (CO2) from large point sources and depositing it normally at an underground geological formation. CCS becomes now as one of the possible supports to the country commitment. In Indonesia, the potential of CCS applications could be conducted in the gas fields with high content of CO2 and in almost depleted oil fields (by applying CO2-Enchanced Oil Recovery (EOR) The CCS approach could also be conducted in order to increase hydrocarbon production, and at the same time the produced CO2 will be injected and storage it back to the earth. Thus, CCS is a mitigation process in enhancing carbon emission reduction caused by green house effect from production hydrocarbon fields.This paper will show a proposed milestone on CCS Research roadmap, as steps to be taken in reaching the objective. The milestone consists of the study for identifying potential CO2 sources, evaluating CO2 storage sites, detail study related to CO2 storage selection, CO2 injection, and CO2 injection monitoring. Through these five steps, one can expect to be able to comprehend road map of CCS Research. Through this research milestone, applications of CCS should also be conducted based on the regulatory coverage milestone. From this paper, it is hoped that one can understand the upstream activities starting with research milestone to the very end downstream activities regarding to the regulation coverage bound. Keywords: CCS, reduction of carbon emission, regulation umbrella

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Compositional Modeling of Impure CO2 Injection for Enhanced Oil Recovery and CO2 Storage

Applied Sciences ◽

10.3390/app11177907 ◽

2021 ◽

Vol 11 (17) ◽

pp. 7907

Author(s):

Hye-Seung Lee ◽

Jinhyung Cho ◽

Young-Woo Lee ◽

Kun-Sang Lee

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Carbon Capture ◽

Oil And Gas ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Co2 Injection ◽

Displacement Efficiency ◽

Compositional Simulation ◽

Sweep Efficiency

Injecting CO2, a greenhouse gas, into the reservoir could be beneficial economically, by extracting remaining oil, and environmentally, by storing CO2 in the reservoir. CO2 captured from various sources always contains various impurities that affect the gas–oil system in the reservoir, changing oil productivity and CO2 geological storage performance. Therefore, it is necessary to examine the effect of impurities on both enhanced oil recovery (EOR) and carbon capture and storage (CCS) performance. For Canada Weyburn W3 fluid, a 2D compositional simulation of water-alternating-gas (WAG) injection was conducted to analyze the effect of impure CO2 on EOR and CCS performance. Most components in the CO2 stream such as CH4, H2, N2, O2, and Ar can unfavorably increase the MMP between the oil and gas mixture, while H2S decreased the MMP. MMP changed according to the type and concentration of impurity in the CO2 stream. Impurities in the CO2 stream also decreased both sweep efficiency and displacement efficiency, increased the IFT between gas and reservoir fluid, and hindered oil density reduction. The viscous gravity number increased by 59.6%, resulting in a decrease in vertical sweep efficiency. In the case of carbon storage, impurities decreased the performance of residual trapping by 4.1% and solubility trapping by 5.6% compared with pure CO2 WAG. As a result, impurities in CO2 reduced oil recovery by 9.2% and total CCS performance by 4.3%.

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Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

Royal Society Open Science ◽

10.1098/rsos.181902 ◽

2019 ◽

Vol 6 (6) ◽

pp. 181902 ◽

Cited By ~ 1

Author(s):

Junchen Lv ◽

Yuan Chi ◽

Changzhong Zhao ◽

Yi Zhang ◽

Hailin Mu

Keyword(s):

Porous Media ◽

Diffusion Coefficient ◽

Oil Recovery ◽

Carbon Capture ◽

Carbon Capture And Storage ◽

Elevated Pressure ◽

Experimental Results ◽

Saturated Porous Media ◽

Reservoir Conditions ◽

The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

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Managing Uncertainty in Geological CO2 Storage Using Bayesian Evidential Learning

Energies ◽

10.3390/en14061557 ◽

2021 ◽

Vol 14 (6) ◽

pp. 1557

Author(s):

Amine Tadjer ◽

Reidar B. Bratvold

Keyword(s):

Uncertainty Quantification ◽

History Matching ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Monitoring Program ◽

Co2 Injection ◽

Drinking Water Contamination ◽

Model Inversion ◽

Geological Co2 Storage ◽

And Storage

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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The potential for large-scale, subsurface geological CO2 storage in Denmark

Geological Survey of Denmark and Greenland Bulletin ◽

10.34194/geusb.v17.5003 ◽

1969 ◽

Vol 17 ◽

pp. 13-16 ◽

Cited By ~ 1

Author(s):

Peter Frykman ◽

Lars Henrik Nielsen ◽

Thomas Vangkilde-Pedersen

Keyword(s):

Carbon Capture ◽

Large Scale ◽

Best Practice ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

The European Union ◽

Geological Storage ◽

Geological Co2 Storage ◽

Research Programmes ◽

Capture Techniques

Carbon capture and storage (CCS) is increasingly considered to be a tool that can significantly reduce the emission of CO2. It is viewed as a technology that can contribute to a substantial, global reduction of emitted CO2 within the timeframe that seems available for mitigating the effects of present and continued emission. In order to develop the CCS method the European Union (EU) has supported research programmes for more than a decade, which focus on capture techniques, transport and geological storage. The results of the numerous research projects on geological storage are summarised in a comprehensive best practice manual outlining guidelines for storage in saline aquifers (Chadwick et al. 2008). A detailed directive for geological storage is under implementation (European Commission 2009), and the EU has furthermore established a programme for supporting the development of more than ten large-scale demonstration plants throughout Europe. Geological investigations show that suitable storage sites are present in most European countries. In Denmark initial investigations conducted by the Geological Survey of Denmark and Greenland and private companies indicate that there is significant storage potential at several locations in the subsurface.

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Beyond Carbon Steel: Detecting Wellbore Shape and Cavities, and Cement Imperfections in Cased Wells

Energies ◽

10.3390/en12214211 ◽

2019 ◽

Vol 12 (21) ◽

pp. 4211

Author(s):

Timofey Eltsov ◽

Tadeusz W. Patzek

Keyword(s):

Magnetic Field ◽

Carbon Steel ◽

Oil Recovery ◽

Magnetic Permeability ◽

Carbon Capture ◽

Oil And Gas ◽

Carbon Capture And Storage ◽

Vertical Component ◽

Co2 Injection ◽

Gas Field

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.

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Effective Prediction and Management of a CO2 Flooding Process for Enhancing Oil Recovery Using Artificial Neural Networks

Journal of Energy Resources Technology ◽

10.1115/1.4038054 ◽

2017 ◽

Vol 140 (3) ◽

Cited By ~ 31

Author(s):

Si Le Van ◽

Bo Hyun Chon

Keyword(s):

Oil Recovery ◽

Water Saturation ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Environmental Benefits ◽

Co2 Production ◽

Co2 Injection ◽

Co2 Flooding ◽

Injection Process ◽

Artificial Neural

The injection of CO2 has been in global use for enhanced oil recovery (EOR) as it can improve oil production in mature fields. It also has environmental benefits for reducing greenhouse carbon by permanently sequestrating CO2 (carbon capture and storage (CCS)) in reservoirs. As a part of numerical studies, this work proposed a novel application of an artificial neural network (ANN) to forecast the performance of a water-alternating-CO2 process and effectively manage the injected CO2 in a combined CCS–EOR project. Three targets including oil recovery, net CO2 storage, and cumulative gaseous CO2 production were quantitatively simulated by three separate ANN models for a series of injection frames of 5, 15, 25, and 35 cycles. The concurrent estimations of a sequence of outputs have shown a relevant application in scheduling the injection process based on the progressive profile of the targets. For a specific surface design, an increment of 5.8% oil recovery and 4% net CO2 storage was achieved from 25 cycles to 35 cycles, suggesting ending the injection at 25 cycles. Using the models, distinct optimizations were also computed for oil recovery and net CO2 sequestration in various reservoir conditions. The results expressed a maximum oil recovery from 22% to 30% oil in place (OIP) and around 21,000–29,000 tons of CO2 trapped underground after 35 cycles if the injection began at 60% water saturation. The new approach presented in this study of applying an ANN is obviously effective in forecasting and managing the entire CO2 injection process instead of a single output as presented in previous studies.

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Performance of Silica Nanoparticles in CO2 Foam for EOR and CCUS at Tough Reservoir Conditions

SPE Journal ◽

10.2118/191318-pa ◽

2019 ◽

Vol 25 (01) ◽

pp. 406-415 ◽

Cited By ~ 1

Author(s):

Arthur U. Rognmo ◽

Noor Al-Khayyat ◽

Sandra Heldal ◽

Ida Vikingstad ◽

Øyvind Eide ◽

...

Keyword(s):

Silica Nanoparticles ◽

Oil Recovery ◽

Carbon Capture ◽

Elevated Temperatures ◽

Co2 Storage ◽

Sweep Efficiency ◽

Co2 Foam ◽

Reservoir Conditions ◽

Incremental Oil Recovery ◽

Surface Modified

Summary The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.

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CO2 Underground Storage and Wellbore Integrity

Risk Analysis for Prevention of Hazardous Situations in Petroleum and Natural Gas Engineering - Advances in Environmental Engineering and Green Technologies ◽

10.4018/978-1-4666-4777-0.ch015 ◽

2014 ◽

pp. 322-357 ◽

Cited By ~ 1

Author(s):

Nediljka Gaurina-Medjimurec ◽

Borivoje Pasic

Keyword(s):

Carbon Capture ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Injection Wells ◽

Geological Co2 Storage ◽

Wellbore Integrity ◽

Geologic Storage ◽

Injection Zone ◽

Carbon Dioxide Co2 ◽

Confining Unit

Geologic storage is the component of Carbon Capture and Storage (CCS) in which the carbon dioxide (CO2) is disposed in the appropriate underground formation. To successfully inject CO2 into the subsurface to mitigate greenhouse gases in the atmosphere, the CO2 must to be trapped in the subsurface and must not be allowed to leak to the surface or to potable water sources above the injection zone. For the purposes of risk assessment, a priority is to evaluate what would happen if CO2 migrated unexpectedly through the confining unit(s), potentially resulting in undesirable impacts on a variety of potential receptors. One of the main risks identified in geological CO2 storage is the potential for CO2 leakage through or along wells. To avoid leakage from the injection wells, the integrity of the wells must be maintained during the injection period and for as long as free CO2 exists in the injection zone.

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Simulation of Immiscible Water-Alternating-CO2 Flooding in the Liuhua Oilfield Offshore Guangdong, China

Energies ◽

10.3390/en13092130 ◽

2020 ◽

Vol 13 (9) ◽

pp. 2130 ◽

Cited By ~ 1

Author(s):

Gang Hu ◽

Pengchun Li ◽

Linzi Yi ◽

Zhongxian Zhao ◽

Xuanhua Tian ◽

...

Keyword(s):

Oil Recovery ◽

Carbon Capture ◽

Co2 Storage ◽

Simulation Models ◽

Co2 Injection ◽

Co2 Flooding ◽

Full Field ◽

Water Alternating Gas ◽

Production History ◽

And Storage

In this paper, the immiscible water-alternating-CO2 flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO2 injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO2 injection (Con-CO2) and primary depletion production (No-CO2) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO2 WAG over both Con-CO2 and No-CO2 scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO2 injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO2 injection volume, the CO2 storage efficiency is still high, more than 84% of the injected CO2 was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO2 processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO2 enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project.

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