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Fifth CO2 Geological Storage Workshop
- Conference date: November 21-23, 2018
- Location: Utrecht, Netherlands
- Published: 21 November 2018
21 - 40 of 58 results
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Control Of Pressure Propagation In A Heterogeneous CO2 Storage Reservoir Using Water Production
More LessSummaryInjection of CO2 into a reservoir increases the pressure above initial values, resulting in overpressure of a hydrostatically charged formation. Without careful monitoring and management, excessive pressure can lead to a number of serious complications for a CO2 storage operations. Using numerical simulations with four distinct porosity/permeability distributions to represent reservoirs with random and structured heterogeneity. We initially consider the impact heterogeneity has on pressure propagation from a CO2 injection well; in particular the effect of channels on the lateral extent of the region of increased pressure. Subsequently, we investigate how heterogeneity influences the efficacy of water production as a pressure management tool and the optimisation of well positioning. For a channelized reservoir the most effective production well, which reduces the area of high pressure by up to 88%. Even in a randomised reservoir with no structured distribution of porosity and permeability, water production can still reduce the high pressure footprint by 60–88%. The location of the production well relative to the heterogeneity has been shown have a significant effect. The most effective production well location may not always be close to the target, but should be connected to the target by relatively high permeability pathways.
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Opportunities For A CO2-Enhanced Oil Recovery Project In The North Sea: Analysis Of Profitability And Environmental Impact
Authors K. Welkenhuysen, T. Compernolle, B. Meyvis, M. Moretti, K. Piessens, P. Roefs and R. SwennenSummaryThe economic and environmental impact of an integrated CO2-EOR project in the Buzzard field in the North Sea is investigated through a life cycle analysis, a standard economic analysis and a more advanced geo-economic simulation. Results show the benefits of combining EOR with CO2 storage. However, the current economic environment provides insufficient long-term outlooks to justify the investment.
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Assessing Potential Influence Of Nearby Hydrocarbon Production On CO2 Storage At Smeaheia
Authors H. Lauritsen, S. Kassold, R. Meneguolo and A. FurreSummaryIn 2016, a study identified the Smeaheia area located 30km off the western coast of Norway, as a suitable storage site for CO2. A concept selection study requested by the Gassnova public enterprise was subsequently performed by the Northern Lights subsurface team, a group comprised of personnel from Equinor and partners. The study revealed challenges with the various geological structures planned for CO2 storage, as well as the importance of understanding the pressure connectivity with the neighbouring hydrocarbon producing Troll field. Due to these challenges Smeaheia was not found mature enough for concept selection at this stage
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Field-Scale Implications Of Density-Driven Convection In CO2-EOR Reservoirs
Authors S.E. Gasda, M.T. Elenius and R. KaufmannSummaryIn this paper, we present gravity-driven mixing for different CO2-hydrocarbon mixtures using a highly accurate computational model. The simulation results are used to characterize the fine-scale behavior for gravity-stable systems. Preliminary simulations for flowing systems are presented. We discuss the implications for behavior of convective systems at the field scale.
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Analysis Of The Use Of Superposition For Analytic Models Of CO2 Injection Into Reservoirs With Multiple Injection Sites
Authors S. De Simone, S.J. Jackson, R.W. Zimmerman and S. KrevorSummaryLarge scale CCS is crucial to reduce the cost associated with minimizing climate change. Energy system models should thus include CCS at regional or global scale with a proper evaluation of pressure limitations and injectivity, which are currently ignored. To this aim, the use of simplified analytical solutions is highly useful because they provide fast evaluation of pressure and plume evolution without the computational costs of the numerical models. Application of these solutions to assess storage capacity has been extended to cases of multiple well injection. In these cases, the pressure build-up is evaluated as the superposition of the analytical solutions for pressure associated with each individual well. In this study we investigate the validity of the superposition procedure, given the non-linearity of the multiphase flow. We quantify the error associated with the application of superposition to estimate reservoir pressurisation in different scenarios of.multi-site CO2 injection in a large regional aquifer. We find that the error associated with the adoption of this procedure increases with time and with the number of wells in proportion to the area invaded by CO2 in the reservoir.
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Svelvik CO2 Field Lab: Upgrade And Experimental Campaign
Authors P. Eliasson, C. Ringstad, A. Grimstad, M. Jordan and A. RomdhaneSummaryA small-scale CO2 field laboratory was established at Svelvik, Norway during 2009–2013. The original intent was to use the field lab for CO2 migration monitoring studies. Findings during the construction of the lab and during the initial experimental campaign indicated that the field lab is better suited for research on monitoring of CO2 storage. The suitability of the field lab for such research was further confirmed in 2013 by feasibility studies based on CO2 injection simulations and sensitivity studies for various geophysical methods. Since 2017, SINTEF is working, within the ECCSEL consortium, on upgrading the field lab with additional monitoring wells, instrumentation for cross-well seismic and ERT, and trenched DAS cables. The upgrade of the lab will be completed in spring 2019, and several new research projects have plans for experiments. The first new experimental campaign will be conducted during 2019 within the Pre-ACT project with the objective to produce field data and develop methods for quantification and discrimination of pressure and saturation changes in the subsurface, caused by CO2 injection.
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Predictive Modelling Of CO2 Storage In Aquifers: Integrating The Effects Of Boundary Conditions And Saturation Functions
Authors M. Onoja and S. ShariatipourSummaryIn reservoir engineering, the predictive analyses of CO2 sequestration in subsurface formations commonly employ numerical models of subsurface formations. A significant number of work have utilised numerical modelling techniques to predict the impact of the reservoir’s boundary conditions and interlayer communication on CO2 storage capacity in aquifers. To the best of our knowledge, no study on the impact of boundary conditions on CO2 storage efficiency has focused on the combined effect of this factor in the reservoir and saturation functions in the caprock. To this end, this study examined the effect of integrating both processes on pressure evolution in the caprock during the numerical simulation of CO2 injection into a deep saline aquifer. Utilising the Sleipner benchmark model, we also showed how varying saturation functions in the caprock can affect the storage efficiency in the reservoir formation.
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Low Salinity Surfactant Nanofluids For Enhanced CO2 Storage Application At High Pressure And Temperature
Authors N.K. Jha, M. Ali, M. Sarmadivaleh, S. Iglauer, A. Barifcani, M. Lebedev and J. SangwaiSummaryCO2 storage and its containment security are key concern of a large-scale CCS project. One of the most important parameters affecting the CO2 storage potential is CO2/brine interfacial tension. In this work, we use low salinity surfactant nanofluids to demonstrate its potential application for CO2 storage at high pressure and temperature conditions by significantly lowering CO2/brine interfacial tension. The present work gives novel insight on the use of nanoparticles in CO2 storage application. We use Sodium dodecylbenzenesulfonate (SDBS) surfactant and ZrO2 nanoparticles for our formulation. Determination of interfacial tension were carried out using pendent drop method at 20 MPa and 70 °C and drop shape analysis were carried out using pendant drop plugin of Image J software.
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CO2 Injection In Low Pressure Depleted Reservoirs
Authors A. Twerda, S. Belfroid and F. NeeleSummaryRe-using depleted fields (and platforms and wells) offers advantages over developing storage projects in saline formations. However, with reservoir pressures after production sometimes below 20 bar, there can be a large pressure difference between the reservoir and the transport pipeline at the surface, which will be typically at pressures in the range of 80 – 120 bar. This pressure difference must be carefully managed to ensure that the temperature of the CO2, the surface installations and the well, remain within materials specifications and within proper operating boundaries. Pressure drops of the CO2 result in potentially large decrease in temperature, due to its high Joule-Thomson coefficient; in addition, the temperatures and pressures that occur in a typical CO2 transport and storage system are such that two-phase flow is likely to occur. Pipeline pressure and temperature management can easily be done in a single source- single sink scenario as the pipeline pressure is a free parameter. However, if the pipeline must act as a backbone for multiple wells at different reservoir pressure, pressure and flow management must be balanced carefully. In this paper, the differences between a pipeline as transport and a pipeline as backbone will be discussed in detail.
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Huff-n-Puff Test For Minimum Miscibility Pressure Determination For Heavy Oil
Authors E. Shilov and A. CheremisinSummaryThis paper presents problems correlated to unsuccessful MMP determination by STT, then procedure of samples preparation for Huff-n-Puff test, intermediate results of Huff-n-Puff test and MMP calculation via MMP correlations for the provided oil samples.
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Chimneys And Channels: History Matching The Growing CO2 Plume At The Sleipner Storage Site
Authors G. Williams and A. ChadwickSummaryA revised analysis of seismic data at Sleipner has revealed large-scale, roughly north-trending, channels at a range of levels in the Utsira Sand. The seismic data also reveal localised chimneys within the reservoir and overburden, some of which show evidence of having provided vertical conduits for earlier natural gas flow. Reservoir flow models were set up with flow properties constrained by the observed levels of CO2 accumulation in the reservoir and the arrival time of CO2 at the reservoir top just prior to the first repeat survey in 1999. The initial model with laterally homogeneous sand units separated by thin semi-permeable mudstones achieved a moderate match to the observed time-lapse seismics. Subsequent flow models, progressively incorporating higher permeability vertical chimneys through the mudstones and large-scale channelling within the reservoir sands, yielded a progressive and marked improvement in the history-match of key CO2 layers within the plume. The preferred plume simulation flow model was converted into a seismic property model using Gassmann fluid substitution with an empirical Brie mixing law. Synthetic seismograms generated from this show a striking resemblance to the observed time-lapse data, both in terms of plume layer reflectivity and also of time-shifts within and beneath the CO2 plume.
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Forensic Mapping Of Spatial Velocity Heterogeneity In A CO2 Layer At Sleipner Using Time-Lapse 3D Seismic Monitoring
Authors A. Chadwick and G. WilliamsSummaryThe Sleipner injection operation has stored over 17 Mt of CO2. Time-lapse seismic monitoring has provided high resolution images of CO2 plume development, constraining and verifying numerical flow simulations. Seismic velocity is a key diagnostic parameter for CO2 layer properties and we adopt a forensic interpretative approach to determine velocity variation in the topmost layer of the plume. The 2010 seismic dataset enables, for the first time, temporal thicknesses of the layer to be determined, taking into account interference-induced time-shifts. Combining these with CO2 layer thicknesses determined from structural analysis of the topseal topography allows layer velocity to be mapped. A marked spatial variation in velocity is evident across the layer with higher velocities (1630±103 ms-1) in the central part of the layer contrasting with lower values (∼1370± 122 ms-1) to the north. Recent published work has identified a north-trending channel in the topmost Utsira sand unit, which greatly improves history-matching of the topmost CO2 layer with numerical flow simulations. This channel correlates almost exactly with the low velocity area mapped from the seismic, the higher velocity area corresponding to less permeable overbank deposits. The seismic therefore provides key corroborative evidence of permeability heterogeneity within the reservoir sand.
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Reservoir Simulation And Feasibility Study For Seismic Monitoring At CaMI.FRS, Newell County, Alberta
Authors M. Macquet and D. LawtonSummaryWe present the results of reservoir simulations and feasibility study of surface seismic monitoring applied to the CO2 sequestration at the CaMI Field Research Station (FRS). We first test the influence of injection parameters, as reservoir temperature, maximum bottom-hole pressure and of the ratio vertical permeability over horizontal permeability on the amount of CO2 you can inject and on the gas plume shape. We demonstrate that if the reservoir temperature has a very small influence on the injectivity, the maximum bottom-hole pressure and the ratio of permeabilities play a key role on the gas injection. The next step is fluid substitution, necessitated to estimate the variation in elastic parameters induced by the gas injection. We test different methods to compute the bulk modulus of the fluid (Reuss, Voigt, HRV and Brie) and compare their results. We finally use a 3D finite difference modeling to simulate the seismic response in the elastic models generated for the baseline, for 1 year of injection and for 5 years of injection.
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Results From The Second Monitor DAS VSP At Quest CCS
Authors A. Halladay, V. Orpeza Bacci, S. O’Brien and K. HindriksSummaryThe Quest CCS project uses time-lapse seismic methods to demonstrate conformance of the CO2 in the reservoir to modelled predictions. This paper outlines the results of the second monitor DAS VSP.
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Foam Stability Enhanced Technology For Mobility Control Of CO2 EOR
Authors H. Yonebayashi, K. Takabayashi, Y. Miyagawa and T. WatanabeSummaryThe latest CO2 foam technology reviews were conducted to understand recent research trends in CO2 enhanced oil recovery (EOR). In general, it is expected to improve CO2 sweep efficiency resulting in better oil recovery and prevention of early breakthrough. From CCUS point of views, the delay of gas breakthrough has a significant advantage in underground storage of industry-originated CO2. The reviews highlighted that various types of nano-additives have been investigated to develop further advanced foam technology. Key points to be focused on are how achieving more robust foam stability. Even a conventional CO2 foam generated with surfactant agents might be deteriorated in short period, those additives can extend foam half-life time. As additives, the recent researches have paid attention to nano-particles, polymer, viscoelastic surfactant, etc. The investigation measured half-life, viscosity, and differential pressure in core flood as key performance indicators. In addition, “high temperature (HT)” and “high salinity (HS)” are keywords in their researches. Namely, screening criteria of experimental conditions are aiming to more harsh conditions. However, the reviewed reports have not covered up to our target conditions in typical Middle East region. Thus, we have been concentrating to develop nano-additive enhancing CO2 foam technology in HTHS.
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Ensuring Integrity Of CO2 Storage: An Overview Of Ongoing Experimental Activity
By N. OpedalSummaryThe Ketzin pilot site is the longest operating onshore CO2 storage site in Europe. CO2 injection began in June 2008 and ended in August 2013. In total five wells were drilled at the Ketzin pilot site. During the abandonment, well construction material samples were retrieved. The samples were retrieved from the cementitious plug as well as from the steel casing and the production string at different depths. The samples were analyzed by a set of complementary experimental techniques.
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Effects Of Gravity On Flow Behaviour Of Supercritical CO2 During Enhanced Gas Recovery (EGR) By CO2 Injection And Sequestration
Authors M. Abba, A. Abbas, B. Saidu, G. Nasr and A. Al-OtaibiSummaryA core flooding experiment was carried out to simulate an Enhanced Gas Recovery (EGR) process to inject supercritical Carbon Dioxide (SCO2) into a core sample saturated with methane (CH4). This was done to investigate the flow behaviour of the injected SCO2 at the flow conditions when the injection orientation was switched from horizontal to vertical during the CH4 displacement. From the results, it was found that gravity has significant effects on the flow behaviour of SCO2 at lower flowrates; more pronounced is the seemingly lower permeability in the horizontal orientation compared with the vertical orientation. So the choice of the injection pattern or direction during EGR by SCO2 injection for the purpose of additional recovery of CH4 and subsequent sequestration of the injected CO2 should be made in conjunction with the determination of optimum injection rate for efficient injectivity.
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Numerical Analysis Of Immiscible/Near-Miscible CO2-WAG Displacement, Incorporating Compositional And Interfacial Tension Effects
More LessSummaryThe central objective of this paper is to study the balance and interactions of the different mechanistic contributions to the physics occurring during oil displacement by CO2 (both continuous and WAG). Mechanism 1 (M1) is the conventional oil stripping/compositional effect and Mechanism 2 (M2) is the near-miscible IFT effect on oil relative permeability through enhanced layer flow. Using sufficiently fine-scale models, we explain how these mechanisms interact with each other and affect the sweep and local displacement efficiency in a heterogeneous permeability field. We believe that studying the key processes separately leads to a greater insight into the physics of CO2 displacement, and this will help us to simulate the transition from immiscible to miscible displacement consistently at larger scales.
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Influencing The CO2-Oil Interaction For Improved Miscibility And Enhanced Recovery In CCUS Projects
More LessSummaryIn this work the physics of a fluid CO2 – crude oil mixture are explained and correlated to the evaluation of the best performance of a CO2 EOR project. The impact of different factors on the miscibility of the two fluids is described. Based on this knowledge some methods for the determination of the minimum miscibility pressure (MMP) are introduced and their pros and cons are discussed. Additionally, the concept of using miscibility enhancing additives to improve the oil recovery for successful CCUS projects is introduced. At the end a good understanding of the complex CO2 – oil mixture and its influencing parameters is developed. The reasons for good or poor miscibility are understood. An approach to make reservoirs applicable for CO2 EOR which were naturally not is shown by the application of the miscibility enhancing additives in order to improve the economics and to provide a proper justification for CCUS.
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CO2 Storage Potential Of The Neogene Stratigraphy In The North Viking Graben
More LessSummaryThe main Neogene reservoirs for CO2 storage in the North Viking Graben are the Utsira and Skade Formations, collectively known as the Utsira- Skade Aquifer. This is one of ten aquifers in the North Sea that is deemed suitable for CO2 storage ( Halland et al., 2011 ). Most studies have been either a large scale assessment of the entire aquifer or finer detailed studies in the southern area, as this is currently where injection of CO2 is currently taking place at the Sleipner storage facility. This study assesses the suitability of the aquifer and its surrounding stratigraphy in the North Viking Graben. Analysis showed that a lack of a thick depocentre at a suitable depth results in poorer potential in this region compared to its southern counterpart. Injection into the Utsira Formation would need to occur in the north-east section to be at a suitable depth, utilising mostly 20–100m thick sands with a maximum migration distance of 90 km. The Skade Formation benefits from 85m thick closed traps but a max migrati
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