The Characteristics of CO2 Flow and Thermal Field in a Porous Media

2010 ◽  
Author(s):  
Hang Seok Choi ◽  
Yeon Seok Choi ◽  
Hoon Chae Park ◽  
Cheol Huh ◽  
Seong-Gil Kang ◽  
...  
Keyword(s):  
Porous Structure ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Physical Conditions ◽  
Thermal Fields ◽  
Level Model ◽  
Temperature And Pressure ◽  
Set Up ◽  
Co2 Flow ◽  
And Storage

International attention has been considerably paid for the technology of CO2 capture and storage (CCS) these days because of global warming. Among the technologies of CCS, the prediction of CO2 behavior in underground is very crucial for CO2 storage design. In the present study, a pore-scale level model is developed to mimic real porous structure and by using CFD (computational fluid dynamics) the characteristics of the CO2 flow and thermal fields are investigated in the pore-level micro porous structure. Varying the CO2 injection conditions such as flow rate, pressure and temperature, the behavior of CO2 is calculated. Especially, the physical conditions such as temperature and pressure are set up equivalent to the underground condition at which CO2 is injected. From the results, the injection condition of CO2 is very critical to the characteristics of the flow and thermal fields in the micro-scale porous structure.

scholarly journals Managing Uncertainty in Geological CO2 Storage Using Bayesian Evidential Learning

Energies ◽  
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.

THE ECONOMICS OF GEOLOGICAL STORAGE OF CO2 IN AUSTRALIA

2003 ◽  
Vol 43 (1) ◽  
pp. 623 ◽  
Author(s):  
W.G. Allinson ◽  
D.N. Nguyen ◽  
J. Bradshaw
Keyword(s):  
Co2 Storage ◽  
Storage Site ◽  
Carbon Credit ◽  
Cooperative Research ◽  
Cost Estimates ◽  
Market Prices ◽  
Economic Analyses ◽  
Co2 Flow ◽  
The Cost ◽  
And Storage

The economics of the storage of CO2 in underground reservoirs in Australia have been analysed as part of the Australian Petroleum Cooperative Research Centre’s GEODISC program. The economic analyses in the paper are based on cost estimates generated by a CO2 storage technical/economic model developed at the beginning of the GEODISC project. The estimates rely on data concerning the characteristics of geological reservoirs in Australia. The uncertainties involved in estimating the costs of such projects are discussed and the economics of storing CO2 for a range of CO2 sources and potential storage sites across Australia are presented.The key elements of the CO2 storage process and the methods involved in estimating the costs of CO2 storage are described and the CO2 storage costs for a hypothetical, but representative storage project in Australia are derived. The effects of uncertainties inherent in estimating the costs of storing CO2 are shown.The analyses show that the costs are particularly sensitive to parameters such as the CO2 flow rate, the distance between the source and the storage site, the physical properties of the reservoir and the market prices of equipment and services. Therefore, variations in any one of these inputs can lead to significant variation in the costs of CO2 storage. Allowing for reasonable variations in all the inputs together in a Monte Carlo simulation of any particular site, then a large range of total CO2 storage costs is possible. The effect of uncertainty for the hypothetical representative storage site is illustrated.The impact of storing other gases together with CO2 is analysed. These gases include methane, hydrogen sulphide, nitrogen, nitrous oxides and oxides of sulphur, all of which potentially could be captured together with CO2. The effect on storage costs when varying quantities of other gases are injected with the CO2 is shown.Based on the CO2 storage cost estimates and the published costs capturing CO2 from industrial processes, the economics are shown of combined capture and storage (that is, the sequestration process as a whole) for the major CO2 generation sites across Australia combined with potential compatible storage sites. Examples are shown of the volumes of CO2 that could be sequestered economically depending on the level of the carbon credit in a hypothetical carbon credit trading regime. Purely as an illustration, assuming hypothetically that a real carbon credit of US$50 per tonne applied and that the cost of capture was US$40 per tonne across the board, then preliminary indications are that, ignoring tax considerations, it would be economic to store about 180 million tonnes per year of CO2. This is equivalent to about 70% of the annual CO2 emissions from stationary sources in Australia in 2000.

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

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2130 ◽  
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.

scholarly journals Why CCS? Milestone on Research and Regulation Coverages

KnE Energy ◽  
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

<p>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.</p><p>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. </p><p><em><strong>Keywords</strong></em>: CCS, reduction of carbon emission, regulation umbrella </p>

scholarly journals Simulasi difusi dan adsorpsi matriks pada proses enhanced coalbed methane

2018 ◽  
Vol 12 (1) ◽  
pp. 173
Author(s):  
Ade Nurisman ◽  
Retno Gumilang Dewi ◽  
Ucok W.R. Siagian
Keyword(s):  
Mathematical Model ◽  
Co2 Emissions ◽  
Coalbed Methane ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
The Matrix ◽  
Enhanced Coalbed Methane ◽  
And Storage

Diffusion and matrix adsorption simulations in enhanced coalbed methane process. Carbon capture and storage (CCS) can be considered as one of climate change mitigation efforts, through capturing and injecting of CO2 in underground formations for reducing CO2 emissions. CO2 injection in coalbed methane (CBM) reservoir has potentially attracted for reducing CO2 emissions and enhancing coalbed methane (ECBM) recovery. Diffusion and sorption are phenomenon of gas in the matrix on CO2 injection in CBM reservoir. The objectives of the research are focused on understanding of diffusion and sorption of gas in the coal matrix with mathematical model and estimating of CO2 storage in coalbed and CH4 recovery. In this research, mathematical model is developed to describe the mechanism in the matrix on ECBM process. Mathematical model, which have been valid, is simulated in various variables, i.e. macroprosity (0.001, 0.005, and 0,01), pressure (1, 3, and 6 MPa), temperature (305, 423, and 573 K), and initial fraction of CO2 (0.05, 0.1, 0.3, and 0.5). The results of this research show that preferential sequestration of CO2 and preferential recovery of CH4 in the surface of micropore on macroporosity 0.001, pressure 1 MPa, temperature 305 K, and inital fraction CO2 0,5 conditions are 0.9936 and 0.0064.Keywords: carbon capture and storage (CCS), coalbed methane (CBM), ECBM, diffusion, adsorption Abstrak Carbon capture and storage (CCS) dapat dipertimbangkan sebagai salah satu upaya mitigasi perubahan iklim, yaitu dengan menangkap CO2 dan menginjeksikannya ke dalam formasi bawah permukaan. Injeksi CO2 pada lapangan coalbed methane (CBM) berpotensi mengurangi emisi CO2 dan meningkatkan produksi CBM (ECBM). Pada proses injeksi CO2 di lapangan CBM, fenomena yang terjadi di dalam matriks lapisan batubara (coalbed) adalah difusi dan adsorpsi. Penelitian ini bertujuan memahami fenomena difusi dan adsorpsi pada proses injeksi CO2 untuk ECBM melalui model matematika, dan memperkirakan potensi penyimpanan CO2 di dalam lapangan CBM dan potensi recovery CH4. Pada penelitian dilakukan pengembangan model matematika untuk menjelaskan fenomena di dalam matriks pada proses ECBM. Model matematika, yang telah valid, disimulasikan dengan memvariasikan beberapa variabel, yaitu makroporositas (0,001, 0,005, dan 0,01), tekanan (1, 3, dan 6 MPa), suhu (305, 423, dan 573 K), dan fraksi CO2 awal (0,05, 0,1, 0,3, dan 0,5). Hasil penelitian menunjukkan pada makroporositas 0,001, tekanan 1 Pa, suhu 305 K, dan fraksi CO2 awal 0,5, fraksi CO2 yang teradsorpsi pada permukaan mikropori bernilai 0,9936 dan sisa fraksi CH4 yang teradsorpsi pada permukaan mikropori bernilai 0,0064. Kata kunci: carbon capture and storage (CCS), coalbed methane (CBM), ECBM, difusi, adsorpsi

Analysis of Vertical Permeability and Its Influence on CO2 EOR and Storage in a Carbonate Reservoir

2021 ◽  
Author(s):  
Bo Ren ◽  
Jerry Jensen ◽  
Larry Lake ◽  
Ian Duncan ◽  
Frank Male
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Distribution Functions ◽  
Carbonate Reservoir ◽  
Cumulative Distribution ◽  
Co2 Injection ◽  
Buoyant Flow ◽  
Co2 Eor ◽  
Co2 Flow ◽  
And Storage

Abstract The objective of this study is to improve understanding of the geostatistics of vertical (bed-normal) permeability (kz) and its influence on reservoir performance during CO2 enhanced oil recovery (EOR) and storage. kz is scrutinized far less often than horizontal permeability (kx, ky) in most geological and reservoir modeling. However, our work indicates that it is equally important to understand kz characteristics to better evaluate their influence on CO2 EOR and storage performance prediction. We conducted this study on about 9,000 whole-core triaxial permeability (kx, ky, kz) measurements from 42 wells in a San Andres carbonate reservoir. We analyzed kz data, including heterogeneity, correlation, and sample sufficiency measures. We analyzed wells with the largest and smallest fractions of points with kz &gt; kmax = max(kx, ky), to explore geological factors that coincided with large kz. We quantified these geological effects through conditional probabilities on potential permeability barriers (e.g., stylolites). Every well had at least some whole-cores where kz &gt; kmax. This is a statistically justifiable result; only where Prob(kz &gt; kmax) is statistically different from 1/3 are core samples non-isotropic. In conventional core data interpretation, however, modelers usually assume kz is less than kmax. For the well with the smallest fraction (11%) of cores where kz &gt; kmax, the cumulative distribution functions differ and coincides with the presence of stylolites. We found that kz is about twice as variable as kx in many wells. This makes kz more difficult to interpret because it was (and usually is) heavily undersampled. To understand the influence of kz heterogeneity on CO2 flow, we built a series of flow simulation models that captured these geostatistical characteristics of permeability, while considering kz realizations, flow regimes (e.g., buoyant flow), CO2 injection strategies, and reservoir heterogeneity. CO2 flow simulations showed that, for viscous flow, assuming variable kx similar to the reservoir along with a constant kz/kx = 0.1 yields a close (within 0.5%) cumulative oil production to the simulation case with both kx and kz as uncorrelated variables. However, for buoyant flow, oil production differs by 10% (at 2.0 hydrocarbon pore volume HCPV of CO2 injected) between the two cases. Such flows could occur for small CO2 injection rates and long injection times, in interwell regions, and/or with vertically permeable conduits. Our geostatistical characterization demonstrates the controls on kz in a carbonate reservoir and how to improve conventional interpretation practices. This study can help CO2 EOR and storage operators refine injection development programs, particularly for reservoirs where buoyant flow exists. More broadly, the findings potentially apply to other similar subsurface buoyancy-driven flow displacements, including hydrogen storage, geothermal production, and aquifer CO2 sequestration.

New Insights Into CO2 Injection and Storage in Saline Aquifers

2012 ◽  
Author(s):  
Mehran Sohrabi ◽  
Masoud Riazi ◽  
Christian Bernstone ◽  
Mahmoud Jamiolahmady ◽  
Nils-Peter Christensen
Keyword(s):  
Saline Aquifers ◽  
Co2 Injection ◽  
And Storage

scholarly journals The Low-redshift Intergalactic Medium

1999 ◽  
Vol 16 (1) ◽  
pp. 95-99 ◽  
Author(s):  
J. Michael Shull ◽  
Steven V. Penton ◽  
John T. Stocke
Keyword(s):  
Galaxy Formation ◽  
Large Scale ◽  
Intergalactic Medium ◽  
Hubble Space Telescope ◽  
Characteristic Size ◽  
Baryon Density ◽  
Frequency Space ◽  
Physical Conditions ◽  
Low Metallicity ◽  
Set Up

AbstractThe low-redshift Lyα forest of absorption lines provides a probe of large-scale baryonic structures in the intergalactic medium, some of which may be remnants of physical conditions set up during the epoch of galaxy formation. We discuss our recent Hubble Space Telescope (HST) observations and interpretation of low-z Lyα clouds toward nearby Seyferts and QSOs, including their frequency, space density, estimated mass, association with galaxies, and contribution to Ωb. Our HST/GHRS detections of ∼ 70 Lyα absorbers with Nhi ≥ 1012·6 cm−2 along 11 sightlines covering pathlength Δ(cz) = 114,000 km s−1 show f (>Nhi) α Nhi−0·63±0·04 and a line frequency dN/dz = 200 ± 40 for Nhi > 1012·6 cm−2 (one every 1500 km s−1 of redshift). A group of strong absorbers toward PKS 2155–304 may be associated with gas (400–800) kpc from four large galaxies, with low metallicity (≤0·003 solar) and D/H ≤ 2 × 10−4. At low-z, we derive a metagalactic ionising radiation field from AGN of J0 = × 10−23 erg cm−2 s−1 Hz−1 sr−1 and a Lyα-forest baryon density Ωb =(0·008 ± 0·004)[J−23N14b100]½ for clouds of characteristic size b = (100 kpc)b100.

Cement-Sheath Wellbore Integrity for CO2 Injection and Storage Wells

2010 ◽  
Author(s):  
Koji Takase ◽  
Yogesh Ramesh Barhate ◽  
Hiroyuki Hashimoto ◽  
Siddhartha Francois Lunkad
Keyword(s):  
Co2 Injection ◽  
Wellbore Integrity ◽  
Cement Sheath ◽  
And Storage

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.

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