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Second EAGE CO2 Geological Storage Workshop 2010
- Conference date: 11 Mar 2010 - 12 Mar 2010
- Location: Berlin, Germany
- Published: 11 March 2010
21 - 40 of 79 results
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Analytical Analysis of Layer Spreading in the CO2 Plume at Sleipner
Authors F. C. Boait, M.J. Bickle, R.A. Chadwick and N.J. WhiteAt the Sleipner field, CO2 is removed from natural gas extracted at the Sleipner East field and pumped into the Utsira sandstone. The time-lapse seismic reflection profiles across the injection site show the CO2 plume as a series of bright reflective layers. Combining analytical solutions of flow with observations from the extensive seismic reflection data has provided understanding of the CO2 migration. For a buoyant flow in porous medium, show that if the net input flux remains constant, radius will increase with the square root of time and the height of the flow will increase from the nose of the current to the centre. Accumulations of CO2 in layers at Sleipner exhibit this behaviour over the first six years of injection. The CO2 plume has been mapped on subsequent seismic surveys. After 2004 the growth of the accumulations of CO2 varies throughout the plume. Layers higher in the plume continue to exhibit a linear relationship between radius squared and time indicating no change in net input flux. The area of the lower layers decreases at a similar rate to the initial growth and to a first approximation this may indicate a net output flux, however the reflectivity of the lower horizons is also reduced significantly. The reflectivity of the plume varies both spatially and temporally. Quantifying the reduction of CO2 from layers which exhibit a decrease in area and amplitude will only be possible if the decrease due to imaging processes is known and understood. Reduction in reflectivity or seismic amplitude can be caused by: 1) Lateral velocity variations. 2) Transmission loss at reflective interfaces, which increasingly becomes a problem as the reflectivity of the layers increases with greater amounts of CO2. 3) Increased amounts of intra-layer CO2 at low saturations results in intrinsic attenuation and lower reflection coefficients. The total area of the layers of CO2 is no longer increasing at the same rate as injection of CO2. The CO2 that does not appear present in the high saturation layers is either, a)dissolved in the brine, b)present as low saturations, ”diffuse CO2”, or c)present in the high saturation layers and the decreased reflectivity is an artefact of the imaging. It is most likely to be a combination of all three and this ongoing research endeavors to investigate this.
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Basic Physics of Geological Carbon Storage
By K. U. WeyerIn 1937 and 1940 two basic treatises on fluid flow in the subsurface were published. Muskat, 1937, shaped the development of reservoir engineering while Hubbert , 1940, introduced the physically consistent Theory of Force Potentials to petroleum exploration and hydrogeology. Two decades later, the development of the advanced hydrogeological methods of gravitational Groundwater Flow Systems (Tóth, 1962) were based on Hubbert’s Force Potential. Muskat’s, 1937, methods lead to very successful and prosperous hydrocarbon productions. They are based on continuum mechanics [energy related to volume] and are physically inconsistent. In petroleum production, the actual flow paths are not of great importance as long as the hydrocarbons and other fluids enter the production wells. The same is applicable for EOR. The large scale injection of CO2, however, will remove the sink conditions of hydrocarbon production and EOR application and replace it with source conditions causing long term rise of the pressure potential. From the source injection wells the CO2 will flow along pathways which cannot be determined by using methods based on Muskat [1937]. Methods based on Hubbert’s Force Potential [energy related to mass] and gravitational Groundwater flow systems are , however, particularly suitable for the determination of the flow paths for hydrous fluids, hydrocarbons and CO2 on their migration away from the CO2 injection sites. In this context the presentation will show why off-shore injection encounters hydrostatic conditions while on-shore injection will encounter hydrodynamic conditions. The presentation will address the interplay between gravitational, pressure potential and capillary forces. It will also shed light on the role, within Carbon Sequestration, of so-called ‘Buoyancy Forces’, of pressure potential forces, of the physics of the occurrence of ‘Buoyancy Reversal’ (Weyer, 1978) and how all these conditions can be beneficially applied in carbon sequestration. References Hubbert, M. King, 1940. The theory of groundwater motion. J.Geol., vol.48, No.8, p.785-944. Hubbert, M. King, 1953. Entrapment of petroleum under hydrodynamic conditions. The Bulletin of the AAPG, vol. 37, no. 8, p. 1954-2026. Muskat, Morris, 1937. The flow of homogeneous fluids through porous media. McGraw-Hill. Tóth, J. 1962. A theory of groundwater motion in small drainage basins in Central Alberta, Canada. J. Geophys. Res., vol.67, no.1, p.4375-4387. Weyer, K.U., 1978. Hydraulic forces in permeable media. Mémoires du B.R.G.M., vol. 91, p.285-297, Orléans, France
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Remediation of CO2 Leakage from Deep Saline Aquifer Storage Based on Reservoir and Pollution Engineering Techniques
Authors J.R. Rohmer, T.L.G. Le Guenan, A.R. Reveillere and C.Q.V. VongThe need to know “what can be done” in case of abnormal behaviour of the CO2 storage reservoir has been outlined by various regulation frameworks on CCS operations. Therefore, a proper risk management scheme should include a remediation plan to demonstrate that any undesired consequences can be corrected. The available remediation measures mainly stem from the field of pollution engineering and of oil and gas industry. But due to the uniqueness of CO2 geological storage activities (time and spatial scale), the extent to which such measures can be used, if not adapted, for CO2 storage in deep saline aquifers should be investigated. We adopt the global framework of the “source – transfer – target” approach in case of an accidental CO2 leakage from the reservoir (either through faults or through abandoned wells). At each stage of the approach, the feasibility of the remediation measures is assessed based on large scale multiphase fluid flow transport simulations using TOUGH2 (LBNL). At the “source” level, the proposed intervention strategy relies on the pore pressure control of the reservoir. The injection of CO2 at an industrial scale is simulated using a large scale model of the Dogger layer in the Paris basin. Once an irregularity has been detected, the first corrective action is to stop injection leading to the aquifer pressure recovery. We show that the overpressure in the injection zone rapidly decreases and it can be strongly accelerated by fluid production directly at the CO2 injection well. Nevertheless, lowering pressure at a larger distance from the injection zone requires the creation of an additional production well. Considering the “transfer” component, we propose an intervention strategy based on the creation of a hydraulic barrier, which consists in injecting brine in the overlying aquifer to prevent the CO2 leak from vertically migrating through the leakage pathway. Results of the parametric simulations (injection rates, local conditions) show that this technique can be efficient, but might be at the cost of large over-pressure. At the “target” level, we define a synthetic shallow freshwater aquifer based on the Paris basin case. We investigate the feasibility to rely on natural processes without human intervention to both reduce the mass of mobile accumulated CO2 and the concentrations of potentially releaseable trace elements. We show that the natural attenuation is characterized by very large time scales, hence requiring the combination with more active intervention procedures (e.g. pump and treats techniques).
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Conservative Assessment of Geological CO2 Storage Capacity for Germany
Authors S. Hoeller and P. ViebahnWhen it comes to geological CO2 storage, it is rather difficult to deliver a specific number of CO2 storage capacity because estimates suffer from huge uncertainty. Nevertheless it is crucial for political decision makers and industrial investors to know at least the minimum amount of CO2 that can be stored in the underground. For reasons of land-use regulation and planning of a relevant CO2 – pipeline network, such a conservative estimate is needed by authorities to provide sufficient information for the overall political implementation of the CCS technology in Germany. Therefore, this study selects conservative assumptions and provides a conservative CO2 storage capacity calculation for Germany. It is based on existing concepts and methods to estimate the capacity for CO2 sequestration in deep saline aquifers onshore and offshore Germany as well as in gas fields. The capacity in aquifers is calculated using a top-down volumetric approach and general parameter values. Gas fields are derived by the bottom-up method based on cumulative recovery. Several existing studies based on these methods were reviewed to compare the different parameters applied for calculations. The results are discussed to clarify the differences and the difficulties of storage capacity estimates. The most varying parameter is the efficiency factor, applied in a range from 0.1% to 40%. For saline aquifers a reasonable efficiency of 1% is selected in the authors' estimate, taking into account a maximum pressure increase and compressibility of subsurface rock and water. Another relevant factor, the replacement of natural gas in depleted fields (sweep efficiency), is supposed to be possible to an amount of 75%, as it can be considered unrealistic that the entire amount of only produced hydrocarbons can be replaced. Furthermore, the effects of impurities within the CO2 stream towards density are considered and conservative average CO2 density values of 600 kg/m3 are selected. These values undercut or stay in the lower range of most of the existing national estimates for Germany. Therefore, the conservative authors' estimate of the total CO2 storage capacity for Germany, which results in 2 Gt, lies considerably under the available published estimations (18 - 44 Gt CO2). It shows that many authors assessed theoretical capacities with an unrealistic high capacity of CO2 sequestration due to optimistic selection of parameters. These findings form the scope on which the mentioned stakeholders can base their regional selection of suitable emitters and the consideration of an appropriate infrastructure.
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Romanian Oil fields, Possible Natural Reservoirs for CO2 Storage
By O. ColtoiIn 2002 total net GHG emissions for Romania have decrease about 50 % compared with 1989, reference years. This decrease was due Romania’s economic restructuring, primarily, due to reduction industrial production and comes into operation the first nuclear reactor at Cernavoda (1996). CO2 emission into the atmosphere as a result to the burning process of fossil coal into power plant is one of the major negative aspects with serious implications in climate change recorded on the our world. ROMANIAN OIL FIELDS – A SHORT OVERVIEW Petroleum systems are found into 9 petroliferous basins: Moesian Platform (Romanian sector), Moldavian Platform, Transylvanian Basin, Paleogene Flysch, Carpathian Foredeep (Neogene Molasse, Diapir Fold Zone, Getic Depression), Scythian Platform, Pannonian Basin (Romanian sector), Dobrogea North Promontory and Romanian Black Sea Continental Platform The area of Moesian Platform is more than 43,000 km2. In the reservoir rocks of the Moesian Platform have been discovered more than 160 oil and gas fields. The Transylvanian Basin is a basin of elliptical form elongated on N-S direction (the length is of ca. 300 km and its width is of ca. 200 km). In the reservoir rocks of the Transylvanian Basin have been discovered more than 110 gas fields. The Moldavian Platform represents the western part of the East European Platform with a monoclinal character of the deposits and they dip westward beneath the Carpathian Foredeep (Molasse) and Eastern Carpathian Flysch. In the reservoir rocks of the Scythian Platform have been discovered about 10 oil and gas fields. Pannonian Basin is presents in Romania by the his easternmost part. Neogene formations are represented by Miocene and Pliocene deposits (marls, shales, sand and sandstone are predominant lithologies). In the reservoir rocks of the Pannonian Basin have been discovered more than 80 oil and gas fields. Romanian Black Sea Continental Platform is located on the extension of two main onshore structural units separated by the important fault (Peceneaga-Camena). In this area have been discovered about 7 oil and gas fields. Paleogene Flysch is represented by the Tarcau Nappe, Marginal Folds Nappe and Subcarphatian Nappe. In the reservoir rocks of the Paleogene Flysch have been discovered more than 35 oil and gas fields In the reservoir rocks of the Carphatian Foredeep have been discovered more than 70 oil and gas fields. Oil and gas fields must be recounted, reevaluation to be used for CO2 storage.
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Microseismics– Adding Value to Monitoring for CO2 Injection Compliance
Authors T.I. Urbancic, A. Higgs, J. Daugherty and W. CoulterFrom a compliance, environmental, and human impact standpoint, critical goals of any CO2 injection monitoring program are to identify the position of the CO2 plume, to verify containment of the injectant and cap rock integrity. These goals are common from pilot scale demonstrations through to commercial scale CO2 injection projects. Activities within a reservoir, such as injection and production, lead to a change in the local stress-strain fields. When a critical change is achieved, microseismic activity in or around the reservoir can occur. This release of seismic energy may be related to the reactivation of pre-existing fault or fracture networks, or to the initiation of new fractures. Installation of downhole geophone arrays to “listen” for any significant changes within the reservoir is an application that has been adopted by the petroleum industry during steaming and hydraulic fracture operations. It is, therefore, a natural fit in the scenario of CO2 injection monitoring, where it is crucial to identify and locate any mechanism that may contribute to the creation of a potential CO2 leakage pathway. Conversely, a lack of observed microseismic activity in such a system is of equal importance in that it provides a level of confidence that containment has not been compromised through rock fracturing during the injection process. To look at the potential value of microseismic monitoring for assessing its potential role in CO2 injection compliance, an integrated CO2 injection monitoring field test was carried out in Ostego County in February 2008 by the Midwest Regional Carbon Sequestration Partnership’s (MRCSP). Based on these studies, we were able to identify that microseismic monitoring can play a significant role in assessing the stability of a CO2 injection program, particularly when it comes to cap rock integrity. This has the potential to impact public perception and acceptance of carbon sequestration and storage projects. To provide effective monitoring programs, current microseismic instrumentation will need to be adapted and developed to improve efficiencies in deployment and monitoring economics, and allow for more integrated monitoring solutions (e.g., inclusion of additional non-seismic sensors or acquisition parameters)
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Passive Seismic Monitoring and Geomechanical Modelling of CO2 Injection at Weyburn
Authors J. Verdon, J.M. Kendall, D.J. White, D.A. Angus, Q.J. Fisher and T. UrbancicThe IEA GHG Weyburn-Midale CO2 is currently the largest operational geologic carbon storage project, injecting 3 million tonnes of CO2 every year into a mature oilfield in central Canada since 2000. In 2003 a passive seismic monitoring component was added to the project with the installation of a downhole array near to a new injection well. In this paper we present the results from 5 years of passive seismic monitoring at Weyburn, focusing in particular on how microseismic observations can be linked with geomechanical models of the reservoir. Few events have been recorded during injection - about 100 over 5 years. This suggests that the CO2 is moving through the reservoir aseismically, and geomechanical deformation is low. The few events recorded have been located using a 1-D model developed from well logs. We find that they are generally located near to the horizontal production wells that lie either side of the injector. Depths are poorly constrained, but many appear to be located in the overburden. Shear wave splitting measurements made on the event waveforms find a dominant fracture strike to the NW, matching one of the fractures identified in core samples. Microseismic events are an observable manifestation of geomechanical deformation, so to interpret them create a simple geomechanical model to represent the model. When the reservoir is modelled as softer than the surrounding rocks, stress is transferred into the overburden and deviatoric stresses develop over the producing wells, placing these areas at greatest risk of shear-induced failure. Furthermore, the shear-wave splitting predicted by the model matches the measurements made on microseismic data. This demonstrates how passive seismic observations can be used to groundtruth geomechanical models, improving our understanding of deformation processes occurring during injection.
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The Pressure Impact of CO2 Storage Operations on Neighboring Sites
Authors F. Schaefer, L. Walter, H. Class and C. MüllerNumerical simulations of CO2 storage are usually either generic, using simple brick or pie slice grids, or site specific, predicting CO2 flow and pressure increase for a given storage site. The pressure impact of CO2 storage operations on neighboring sites, where competing operational interests might exist, is still largely unknown. Here we present a saline aquifer showcase model from the Northeast German Basin (NEGB), predicting the regional pressure impact of an industrial scale CO2 storage operation on its surroundings. We emphasize that we do not intend to predict safe operation pressures at or near the well as this would require a very different model setup (grid resolution, injection schedule). The static model is based on real geology while the injection program is fictitious. The geological model mimics the Buntsandstein Group of the NEGB in a slightly simplified fashion. We simulated a rate controlled injection of 2.5 Million tons CO2 per year through a single vertical well into the structural top of a dome shaped anticline, over a period of 10 years. The target is a 20 m thick sandstone layer intercalated in low permeability claystone sequences. We used ECLIPSE300 with its CO2STORE module and MUFTE-UG to predict pressure at the top of the sandstone layer in 1, 5, 10, and roughly 30 km distance to the injection point. The farthest point represents the structural top of a neighboring anticlinal dome, another favourable potential storage site. We varied the model’s boundary conditions, permeability, permeability anisotropy, rock compressibility, and injection temperature. Comparison of the reference scenarios showed that the results of both simulators match well. The parameters that had the largest impact on regional pressure increase are the model’s boundary conditions, rock compressibility and permeability. In a model scenario with Dirichlet boundary conditions, pressure increase is lowest and dissipates back to the pre-injection state within 30 years after injection shutdown. In fully closed model scenarios with Neumann boundaries, pressure peaks are high, equilibrating to a remnant, model-wide overpressure several decades after the end of injection. In model scenarios which are laterally closed on one side, but open on the other, pressure relief is seriously retarded in comparison to the fully open model. In all cases, the pressure maximum arrives at the neighboring structure much later than the actual injection shutdown – at least 5 to 10 years in the open model and several decades in the no flow boundary models (depeding on permeability).
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A Global Sensitivity Methodology to Guide Risk Assessment for CO2 Geological Storage in Deep Saline Aquifers
By J.R. RohmerVarious sources of uncertainties are associated with the risk assessment models. In this context, the recent European Commission directive on CO2 storage operations (Annex I Step 3.2 Sensitivity characterization) has outlined the need for measuring the influence of these sources of uncertainties for an appropriate decision for risk management. Nevertheless, numerical models can be complex and associated with high non-linearities and high computer time cost. Therefore, appropriate tools to carry out sensitivity analysis should be developed to measure parameter importance. In this view, the present paper describes a stepwise selection approach based on non parametric regression techniques is proposed to provide the measures of the parameter importance at a moderate computational cost taking into account all model non linearities. Unlike the commonly used “one factor at a time” approach, the analysis is global so that the potential co-operative effect between input parameters are investigated. A multiphase fluid flow transport model of the Dogger deep saline aquifer in the French Paris basin context is used as an application case. Four key factors for co2 risk assessment are then considered, namely the maximal overpressure, the maximal lateral distance of respectably the CO2 plume, the elevated pressure zone and the drying out zone. The influence of each of them to eight sources of uncertainties is studied, namely the intrinsic permeability, the porosity, the pore compressibility, the capillary model parameters, the residual fluid and gas saturation and the salinity. The analysis shows in particular that the residual gas saturation has an important effect when considering risk associated with pressure perturbation. The effect of salinity appears to be negligible, whereas the pore compressibility presents a moderate influence only for the maximal lateral distance of the elevated pressure zone. Both porosity and intrinsic permeability represent 80 % of the effect on all considered risk outputs.
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A Study of the Feasibility of Imaging CO2 Injection at the CO2SINK Project Using Seismic Techniques
Authors J. Verdon and X. CampmanKetzin is a pilot project sequestering CO2 in a natural aquifer near the town of Ketzin, Germany. Numerous techniques have been deployed to monitor the CO2 flood - this paper provides modelling relevant to the 4D seismic monitoring taking place late 2009. The purpose of the paper is to assess whether the CO2 plume will show up on the repeat survey, and what seismic attribute(s) will be the most effective in imaging it. Ketzin is a geologically heterogenous reservoir, where thin sand channels are believed to control the flow of CO2. These channels are below the tuning thickness, so the seismic changes will not necessarily be linear, as reflections from the top and bottom of the channel will interfere. Furthermore, fluid flow modelling suggests that CO2 will not fill up these channels completely, so we must model a thin channel containing an even thinner layer of CO2. We model the seismic response using simple reflectivity modelling and full waveform finite difference modelling, finding good agreement between the two methods. We find that the presence of CO2 creates detectable amplitude changes, but that there is not enough thickness for a detectable time-shift to accumulate. Amplitude changes increase with increasing CO2 layer thickness, so there will be a minimum detectable thickness determined by the survey repeatability. AVO behaviour is not found to differ significantly after CO2 injection. We also attempt to invert the seismic response computed using finite difference modelling for the velocity change induced by a CO2 layer, and the thickness of the layer. However, we find that there is a trade-off between layer thickness and the velocity change within that layer. This means that quantitative estimates of CO2 volume in the reservoir - beyond the plume extent - may well be problematic. Flow simulations often indicate that CO2 will form thin layers at the top of a reservoir. This being the case, more work must be focused on imaging CO2 plumes that are similar to or thinner than the tuning thickness.
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An Assessment of CO2 Storage Potential Within Carboniferous Aquifers of the Onshore Clare Basin, West Ireland - A Case Study for Pre-feasibility Appraisal of Storage Sites
Authors B. Loske, M. Holdstock, I. Farrelly and F. NeeleThe Irish Environmental Protection Agency (EPA) commissioned an international group led by Aurum Exploration Services, DMT GmbH & Co. KG and TNO Built Environment and Geosciences to conduct a pre-feasibility study to assess the CO2 storage potential in the vicinity of Ireland’s largest single point emitter at Moneypoint Power Station (currently 3.95 Mt CO2 per annum). The Ross Sandstone Formation and Dinantian Limestones were identified as potential reservoirs for CO2 storage within the Clare Basin with the Clare Shale and Gull Island Formations as seals. Structurally, the area is dominated by open folds of Variscan age with subordinate thrusting and faulting. Extensive data compilation of surface data from heterogeneous sources was undertaken in addition to limited subsurface information from deep boreholes and historical 2D seismic surveys. Two new borehole locations were selected for wireline logging and core sampling to provide key information on the potential reservoir and seal horizons. The resultant data was assimilated into a final 3D subsurface model which provides a description of the structural setting and the spatial reservoir/seal property distribution; allowing an early assessment of the potential storage volume and suitability. The study reveals that the Clare Basin in unsuitable for CO2 storage in saline aquifers for the following reasons: - The Dinantian limestones are developed over large areas at depths in excess of 800m with the overlying Clare Shale Formation providing a suitable seal. However, core data suggest the development of an unfavourable basin facies over large portions of the project area. A relatively small theoretical trap volume of some 11 Mt is estimated. - Limited portions of the Ross Sandstone Formation are developed within the required depth window (<800m). The validity of the Gull Island Formation as a potential seal to the Ross Sandstone Formation remains subject to further examination (internal mudstone continuity is unknown). Analysis of surface tectonic features suggests that the majority of anticlines are plunging and therefore prone to potential leakage. Very limited trap potential remains within domal anticlines which may be further compartmentalised by brittle deformation. - Permeability and porosity tests carried out as part of this study clearly demonstrate that the Ross Sandstone Formation and Dinantian Limestones have a tight character. The results for both horizons range from 0.003-0.009 mD. To ensure adequate injection rates and storage, permeabilities in the order of 200 mD (milli-Darcy) are considered necessary to ensure injection at sufficient rates.
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Electromagnetic Monitoring of CO2 Storage in Deep Saline Aquifers– Numerical Simulations and Laboratory Experiments
Authors J.H. Börner, V. Herdegen, R.U. Börner and K. SpitzerTo guarantee the safety of civilization and environment the storage of CO2 has to be monitored efficiently and reliable. The knowledge of petrophysical parameters and their contrasts is crucial to a resilient monitoring. Stipulated by the pressure and temperature regime in deep sequestration formations the stored CO2 occurs in supercritical state (scCO2). The influence of scCO2 on the electrical conductivity of the formation is not sufficiently known. To predict the contrast in electrical conductivity, estimates based on empirical equations and numerical simulations were implemented, and laboratory experiments were carried out. Several submodels were linked resulting in a concept for application, allowing calibration by measured data. Two-phase flow governing the physical storage of CO2 was simulated using the software packages COMSOL Multiphysics and Mod2PhaseThermo. The resulting non-stationary spatial distributions of saturation were transformed into distributions of electrical conductivity using Archie's law (1942) and the law of Waxman & Smits (1968). An increase of electrical conductivity by a factor of 2 to 10 has been predicted. An experimental set-up was developed and constructed which allows the experimental simulation of the sequestration process on a laboratory scale. Central element of the set-up is a measuring cell inserted into an autoclave allowing to monitor the average electrical conductivity of a sand sample. As a first step it could be proved that pure CO2 as well as the CO2 rich binary mixture of CO2 and water do not show any relevant electrical conductivity when a pressure of up to 130 bar has been employed. Experiments with CO2 flowing through a water saturated sample replacing the pore water were carried out with pressures up to 130 bar and temperatures up to 40°C. An increase of electrical conductivity by a factor of 27 to 33 occured when a pressure range up to 50 bar has been considered, which is dominated by a residual water content of 14 to 18%. The increase in electrical conductivity induced by the sequestration has also been demonstrated under supercritical conditions. All experimental data could be interpreted using Archie's law with sufficient reliability.
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Combined Seismic and Geoelectric Modeling of CO2 Plumes in Deep Saline Reservoirs
Authors S.A. al Hagrey, M. Strahser and W. RabbelOur geophysical task within the multidisciplinary project “CO2 MoPa” (modelling and parameterisation of CO2 storage in deep saline formations for dimensions and risk analysis) is to estimate the sensitivity and the resolution of reflection seismic and borehole geoelectrical time-lapses in order to determine the propagation and development of the CO2 reservoir in the subsurface formations. Compared with seismic, electric resistivity tomography (in boreholes, BRT) has lower mapping resolution, but its permanent installation and continuous monitoring can make it an economical alternative or complement. Applications of both methods to quantify changes of intrinsic aquifer properties with time are justified by the lower seismic velocity, and high electric resistivity of CO2 in comparison to pore brine. We present here synthetic modeling results on almost realistic scenarios similar to that of deep saline formations of the German Basin (candidate for CCS). For this basin the study focuses on effects of parameters related to depths (1-3km, temperature gradient of 30°C/l/km, petrophysics (TDS of 100g/km, porosity of ≥0.15), plume dimensions (≥ some meters)/saturations (30-80%) and data acquisition, processing and inversions. Both methods show stronger effects with increasing brine salinity, CO2 reservoir thickness, porosity and CO2 saturation in the pore fluid. They have a pronounced depth dependence due to the pressure and temperature dependence of the velocities, densities and resistivities of the sequestration targets (host rock, brine and CO2). Increasing depth means also decreasing frequencies of the seismic signal and hence weaker resolution. Because of the limited thickness of the CO2 reservoir expected in this basin, the reflections from its top and bottom will most likely interfere with each other, making it difficult to determine the exact dimensions of the reservoir. In BRT, the resulting resistivity resolution and anomaly magnitudes are inversely proportional to the salinity and temperatures and directly proportional to CO2 saturation and dimensions. The sensitivity of the seismic method to CO2 saturation changes is most pronounced for low CO2 concentrations while the geoelectric method has a higher sensitivity at high concentrations and/or lower salinity. Acknowledgments: This study is funded by the German Federal Ministry of Education and Research (BMBF), EnBW Energie Baden-Württemberg AG, E.ON Energie AG, E.ON Ruhrgas AG, RWE Dea AG, Vattenfall Europe Technology Research GmbH, Wintershall Holding AG and Stadtwerke Kiel AG as part of the CO2-MoPa joint project in the framework of the Special Programmne GEOTECHNOLOGIEN.
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Development of Storage Coefficients for Carbon Dioxide Storage in Deep Saline Formations
Authors L. Basava-Reddi, C. Gorecki and N. WildgustThe aim of this study was to define a series of storage coefficients, which can be applied to regional calculations to provide more realistic estimates. Coefficients were considered and derived principally for Deep Saline Formations (DSF), reflecting the large storage potential but associated inherent complexity and uncertainty.
The study has successfully built upon earlier work by both the CSLF and US DOE, confirming the similarities of the two methodologies and more importantly, establishing an ease of comparison of storage coefficients employed and resources calculated for deep saline formations.
Due to the limited amount of data available from real-world CO2 injection projects, focus was kept to the use of modelling simulations to derive storage coefficients. The alternative numerical modelling approach was employed with input parameters derived from global hydrocarbon reservoir data. The modelling work showed the relative influence of various parameters on the efficiency of storage, and allowed the derivation of probabilistic ranges of storage coefficients for calculation of effective storage resource at both site-specific and formation levels.
‘Open’ systems form the majority cases for DSF storage and have relatively consistent geological properties and may be largely un-faulted and fluid and pressure communication across the formation will be strong.
However, ‘closed’ or ‘semi-closed’ systems may also exist, where lateral flow boundaries such as faults can restrict fluid movement. CO2 injection would result in pressure increase, limiting effective storage capacity to the volume created by both the compressibility of the formation and existing pore fluids, and the limit of pressure increase before physical damage to the system. A series of equations derived from US DOE methodology; enable the storage coefficient to be defined as the fraction of total pore volume that will be accessible to CO2, based on volumetric changes caused by compressibility.
Heterogeneous models were developed using statistical distributions from the Average Global Database for the various lithologies, depositional environments and structures, to derive ranges of storage capacity coefficients. The resulting values for storage coefficient ranged from 4% to 17% with an 80% confidence interval. Structural setting was found the exert the largest influence of any parameter on the results, with storage coefficients for effective resource exceeding 25% in some cases.
The study provides a series of storage coefficients that can be used for assessment of CO2 storage resources in deep saline formations.
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What have we Learnt From CCS Demonstrations?
Authors L. Basava-Reddi, B. Beck, M. Haines, T. Dixon and N. WildgustIEAGHG has undertaken an assessment of the learning that is being provided by operational, large-scale, pilot, demonstration and commercial CCS projects around the world. This was undertaken by questionnaire and analysis of the responses.
The criteria to define operational large-scale CCS projects, was that they were operational by the end of 2008, and satisfied one of the following criteria:
• Capturing over 10,000 tCO2 per year from a flue gas;
• Injecting over 10,000 tCO2 per year with the purpose of geological storage with monitoring;
• Capturing over 100,000 tCO2 per year from any source;
• Coal-bed storage of over 10,000 tCO2 per year;
• Commercial CO2-EOR is excluded unless there is an associated monitoring programme.
There were found to be 28 eligible projects from which 20 questionnaires were returned and information was provided verbally from 3 other projects.
As the CCS industry looks to move from demonstration phase to full scale deployment, it is useful to assess which technologies have been demonstrated and which are yet to be demonstrated. The European Union Zero Emissions Technology Platform matrix was used to identify the key technology steps on which testing are still required.
From analysis of responses, key themes, learning points and areas for beneficial collaboration are identified. Coverage of projects is summarised in terms of geological properties and monitoring techniques.
From this initial analysis, key learning areas identified as warranting further investigation include:
• Effectiveness of various monitoring techniques
• Injectivity – prediction, restoration and enhancement
• Design to avoid hydrate formation
• Performance of materials in CO2 environments
• Scaling up capture train size
• Wells – designing, placing, and monitoring cementation
Whilst complete large scale CCS systems on power plants are still to be demonstrated, there is already significant operation of closely integrated parts of CCS systems. The survey returns are also encouraging in that they show some specific areas where more information sharing is likely to be of benefit to future projects. In particular this can help in defining those areas which need further development and testing.
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Sayindere Cap Rock Integrity during Possible CO2 Sequestration in Turkey
Authors C. Dalkhaa and E. OkandanThe important public concern about carbon capture and storage is whether stored CO2 will leak to groundwater sources and eventually back into the atmosphere or not, since CO2 at high concentration is hazardous. Besides, if it leaks back, then it means the process would not be working as a climate change mitigation method. During underground CO2 storage, the containment of CO2 will be crucially dependent on the cap rock integrity above the CO2. Thus, it is important to assess how the CO2 might impact cap rocks, since this could control the ultimate longevity of CO2 storage. The objective of this research is to identify the geochemical reactions of the dissolved CO2 in the synthetic formation water with the rock minerals of the Sayindere formation in laboratory. It is also aimed to assess the potential impacts of geochemical processes on the integrity of the Sayindere cap rock in the long term by using mathematical models and simulation techniques. Sayindere formation, a clayey carbonate, is the cap rock of the Caylarbasi field, which is near to a CO2 source-cement factory. In previous studies, the Caylarbasi field has been studied as an optimum site for the possible CO2 storage in Turkey. The experimental work consists of static and dynamic experiments. In the static experiment, original core is put into the core holder filled with CO2 saturated synthetic formation water. The system is under a pressure of 100 bars and a temperature of 90° C, representing the field conditions. In the dynamic experiment, the core is ground and packed and CO2 saturated synthetic formation water is injected through the unconsolidated core. In the dynamic experiment, X-Ray Diffraction analysis of the grinded core sample will be made prior to and after the experiment. So far, the static experiment has been carried out. Thin Section and Scanning Electron Microscope analyses for mineral identification and composition prior to and after the experiment have been carried out. Cations available in water are analyzed by Inductively Coupled Plasma-Optical Emission Spectroscopy and anions are analyzed by Ion Chromatography. Bicarbonate ion concentrations are determined by titration. The mineralogical investigation and fluid chemistry analysis of the static experiment show that calcite was dissolved from the cap rock as a result of CO2- water- rock interaction. Presently, the dynamic experiment is being carried out and the geochemical modeling of Sayindere cap rock geochemical evolution is being investigated using ToughReact software.
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Storage Site Candidate for Belchatow Demo Plant
Authors A. Wojcicki, S. Nagy, B. Papiernik, W. Szott, J. Checko, R. Tarkowski and T. BakThe Budziszewice-Zaosie (B-Z) structure is located 60 km NE of Belchatow, in central Poland. This is the best explored structure out of three potential storage sites for Belchatow demo plant till now because within the structure contour 6 wells penetrating reservoirs in question appear and there are 9 seismic lines of sufficient quality (6 old, 3 relatively new). Two remining structures will be explored soon by reconnaissance seismic survey and single research wells. The Belchatow demo plant is expected to provide 1.8 million ton of CO2 yearly for geological sequestration after 2015, for a period of at least 25 years, which makes at least 45 million tonnes of CO2. The principal reservoir is of Lower Jurassic, precisely Synemurian and Upper Pliensbachian sandstones, and the main seal is of Lower Toarcian shales which are relatively homogeneous and undisturbed. The reservoir properties are good according to new and archive analyses of drill core samples and well logging interpretation – porosity is of about 20% and permeability of hundreds mD. The secondary reservoir is of Lower Triassic (Buntersandstone). The static model was constructed archive structural maps and results of reinterpretation of seismic sections, including horizons from the terrain surface to the top of Zechstein. In case of seismic interpretation velocity model was based on data from 6 wells. Facies interpretation was carried out where possible. The storage capacity of the structure calculated for static and models is within the range of 100-500 million tonnes, depending on which reservoirs are considered. In case of dynamic modelling a number of approaches (software packages, assumptions) was used and test injection within one well together with full scale injection in 1-4 wells were simulated. The geological risks evaluation involved the fact of low salinity of brine (but according to geochemical analyses and paleontology the possible infiltration of potable water into the reservoir is definitely not of recent origin) and inhomegeneity of the seal between two Lower Jurassic reservoirs (this secondary seal practically ceases to exist at the topmost part of the structure) and partly of the Upper Pliensbachian reservoir. As the next step of the site investigation a baseline monitoring is proposed. In a network of profiles at the injection site of 100 sq. km area high resolution seismic, electromagnetic and gravity survey are planned. Apart from measurements within the wells, around the wells geochemical and geophysical subsurface monitoring and biomonioring is proposed.
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