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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
79 results
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Europe GeoCapacity
Authors V. Hladik, T. Vangkilde-Pedersen and the GeoCapacity project teamSummary not available
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General requirements for hand-over: a risk-based perspective
Authors J. Rohmer, O. Bouc, H. Fabriol, D. Seyedi and S. SySummary not available
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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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Advances in Reservoir Monitoring Using Satellite Radar Sensors
Authors A. Tamburini, G. Falorni, F. Novali, A. Fumagalli and A. FerrettiSurface deformation monitoring can provide valuable constraints on the dynamic behaviour of a reservoir, by allowing the evaluation of volume/pressure changes with time, as well as an estimation of reservoir permeability. Levelling campaigns, tiltmeters, GPS and InSAR are all geodetic techniques used to detect and monitor surface deformation phenomena. Among them, InSAR data from satellite radar sensors are gaining increasing attention for their unique technical features and cost-effectiveness. In particular, Permanent Scatterer InSAR (PSInSAR™) is an advanced InSAR technique, developed in the late nineties, capable of providing very precise 1D displacement measurements along the satellite line-of-sight (LOS) and high spatial density (typically exceeding 100 measurement points/sqkm) over large areas, by exploiting point-wise radar targets already available on ground. PSInSAR™ data have been already used successfully for environmental assessments, reservoir monitoring in CO2 sequestration experiments (Vasco et al. 2008, Mathieson et al. 2009), as well as for the analysis of gas storage areas. Recently, some significant advances have been reported in InSAR data processing that can further increased the quality and the effectiveness of this data source for reservoir monitoring: (a) the development of new InSAR algorithms and in particular the so-called SqueeSAR™ approach. This new approach allows a significant increased in the spatial density of measurement points, as well as an improved quality of the time series of deformation; (b) the availability of an increased number of satellite radar sensors characterized by higher sensitivity to surface deformation (compared to previous available sensors), higher spatial resolution (down to 1 m), as well as better temporal frequency of acquisition (down to a few days, rather than a monthly update); (c) the possibility to combine 2 or more data-stacks acquired along different satellite orbits to estimate the 3D displacement vector, rather than a set of 1D deformation measurements along the satellite LOS. In this paper all three topics mentioned above will be addressed giving some insights on the potential impacts for reservoir monitoring and CO2 sequestration.
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Stratigraphic Inversions for CO2 Storage– A Case Study of the Sleipner Field
Authors N. Delépine, V. Clochard, K. Labat and P. RicarteIn the Sleipner field (Norwegian North sea), Statoil has injected for 15 years more than 11 Mt of CO2 into a saline aquifer. To monitor the CO2 migration inside the aquifer, time-lapse seismic acquisitions have regularly been applied and seven pre-stack PP seismic vintages are now available. The time pre-stack stratigraphic inversion currently used by the oil industry has been applied to the Sleipner-CO2 storage to better characterize the aquifer. The methodology developed by IFP is based on Bayesian formalism, the workflow consists of 3 steps: (1) a seismic to well-log calibration, (2) the building of an a priori model and (3) the inversion process. The last step consists in simultaneously inverting a few limited incidence angle stacks in order to estimate an optimal multi-parameter earth model, parameterized in P- and S-wave impedances, by an iterative process. Such values are crucial attributes for both reservoir characterization and CO2 monitoring. With several vintages available, like the Sleipner-CO2 case, a complementary study has been done with a time lapse (4D) inversion which consists in simultaneously inverting several vintages. The results of this study are focused on the 1994 (before injection) and 2006 (after an injection of 8.4 Mt of CO2) vintages. The IFP stratigraphic inversion methodology was applied: from offset gathers of 1994 and 2006 vintages, we have built 3 limited angle substacks, then the well-to-seismic calibration step was achieved for each of them. Finally pre-stack inversion (one inversion is performed for each vintage) and 4D joint inversion has also been performed. Considering the elastic impedances results inside the CO2 plume, P-wave impedances decrease drastically due to the presence of CO2. S-wave impedances are much less affected since there are no major changes in the rock matrix: the variations are essentially due to density variations. Outside the plume (around and in the shale overburden), the variations are quasi-nonexistent, especially for the 4D inversion results, providing at least a good delineation of the CO2 plume. In agreement with seismic amplitude analyses, the stratigraphic inversion results tend to show the efficiency of the shale overburden at the resolution level attained after inversion, which is a key issue for the long-term storage of CO2. These results are helpful inputs for both reservoir simulations and petro-elastic considerations to try to target quantifying the CO2 mass.
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Effects of Fractures on CO2 Storage
By M. IdingStorage safety is mainly controlled by a number of physical trapping mechanisms including the cap rock's ability to retain the trapped CO2 over long periods of time. It is therefore Important to consider geological heterogeneities, and in particular the effects of faults and fractures when evaluating the long term behaviour of a storage system. Collecting fracture data, integrating this information in geo- and reservoir models, and performing CO2 plume flow simulations are challenging tasks and an important area of research. There are a number of CO2 EOR (enhanced oil recovery) projects as well as active and potential CO2 storage sites where there are data on fracture properties. Among these locations are Weyburn (Canada), Sprayberry (USA), Snøhvit (Norway), In Salah (Algeria), Teapot Dome (USA). This data is of variable quality and needs to be reviewed and put into context for the purpose of CO2 storage. In this poster we compile this fracture data, compare the quality and usability for CO2 storage predictions, and evaluate the potential influence on the long term storage behaviour. Furthermore, we compare this data with our recent work on fracture characterization at the In Salah CO2 storage project. This work includes building of discrete fracture models and compositional fluid flow simulations. We will show that we needed to include fracture properties in our reservoir models to be able to explain the short term development of the CO2 plume 1-2 years after injection. This is a strong indication for the even stronger importance of appropriate fracture treatment for long-term simulations.
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TOGEOS – Towards Geological Storage of Carbon Dioxide in the Czech Republic
Authors R. Lojka, V. Hladik, D.G. Hatzignatiou, V. Kolejka, J. Francu, E. Francu, F. Riis and F. BratteliTOGEOS is a collaborative research project carried out by the Czech Geological Survey (CGS) and the International Research Institute of Stavanger (IRIS) aiming to continue the work on CO2 geological storage potential of the Czech Republic carried out by CGS since 2003, and especially within the EU-funded projects CASTOR and EU GeoCapacity. The main objectives of the TOGEOS project are to (a) increase significantly the level of knowledge of the most promising structures potentially suitable for geological storage of CO2 in Czechia – i.e. the deep saline aquifers of the Central Bohemian Permian-Carboniferous basins and (semi )depleted hydrocarbon fields of eastern Moravia, and (b) re-assess more accurately their potential CO2 storage capacity. The first project step was the selection of the most promising structures for further investigation. Based on an extensive literature review, a set of site selection criteria was prepared. The criteria were divided into 4 groups, namely, reservoir parameters, location, data availability and uncertainties. These criteria were applied in basin scale on three partial basins of the Central Bohemian Permian-Carboniferous area that were studied within the earlier EU GeoCapacity project. After a thorough analysis, the Central Bohemian (Roudnice) Basin was selected for a further research including characterization and evaluation. For the selected basin, a simplified reservoir model is being constructed using Petrel, a commercial geological modelling software, and a sequence-stratigraphic and basin evolution models are being created in conjunction with the PetroMod basin modelling software. To be able to build these models, extensive efforts were made to gather sufficient amount of data on both reservoir and sealing rock properties, basin structure, stratigraphy, etc. Due to the fact that the costs of drilling of a new well to the selected structure highly exceed the available project budget, other data resources had to be used such as for example, archive core samples stored in the core depository, new, freshly drilled samples from a shallow analogue for the purposes of laboratory analyses (especially in determining formation effective porosity and permeability), petrophysical data from the Czech national geophysical database, archive reports and hydrogeological tests, etc. Archive geophysical data – reflection seismic sections and gravity maps – were also used to specify the basin geometry, layering, faults, etc. in more details. The project is co-funded by the EEA Grants and Norway Grants, and by the Czech Ministry of Education, Youth and Sports.
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Geological Factors Influencing Time-lapse Seismic Monitoring of Subsurface CO2 Storage
Authors G. Cairns, H. Jakubowicz, L. Lonergan and A. MuggeridgeCarbon dioxide sequestration offers an immediate way to reduce CO2 emissions and mitigate global warming. Due to expense and potential danger, storage sites must be monitored to assess their long-term integrity and detect leakage. Ideally, monitoring must be able to locate the CO2, quantify its saturation distribution, and detect the CO2 trapping phase. Time-lapse seismic surveys are expected to form the foundation of this monitoring and their ability to fulfil these requirements must be established. The seismic response of injected CO2 is dictated by the rock and fluid properties of the reservoir and overburden. In this work we study the combined effect of the fluid distribution and corresponding rock physics model on seismic data. Since seismic waves induce changes in pore pressure, the speed of propagation depends on whether the fluids equilibrate within the seismic period, and is in turn affected by the fluid distribution. If the fluids are well mixed and the distribution is homogeneous, the pressures equilibrate, and the rock properties can be described using a harmonic average. However, if the fluids are not mixed (i.e. are “patchy”), then the pressures may persist and “stiffen” the rock; the rock physics is then modelled using an arithmetic average. These two end-member models predict very different relationships between saturation and Vp. In this study we simulate the seismic response from a generic sandstone, similar to that of the Sherwood formation, located beneath a uniform layer of shale. Our results show that, for homogeneous fluid distributions, injection of small quantities of CO2 (1-5%) significantly reduces the P-wave velocity, and can be detected at all the depths examined (1000 m to 2000 m). However, further CO2 injection has very little additional effect on the response, making any direct measurement of saturation difficult. On the other hand, for patchy saturations, the response is much more sensitive to changes in the amount of CO2, potentially allowing saturation to be measured directly. Indeed, the differences in the responses of homogeneous and patchy saturations are sufficiently large that it may be possible to quantify the amount of heterogeneity and mixing in the reservoir. It is therefore possible that seismic measurements could distinguish between different reservoir models of the CO2 distribution.
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Field Experiences with Isotopic Tracing of Injected CO2 at Enhanced Oil Recovery Sites in Canada
Authors B. Mayer, G. Johnson, M. Shevalier, M. Nightingale and I. HutcheonMonitoring and verification of CO2 storage is an essential component of geological storage projects. We present evidence from several enhanced oil recovery projects in Canada that geochemical and isotopic techniques can be successfully used to trace the fate of injected CO2. Geochemical and isotopic data for fluids and gases obtained from multiple wells at the Penn West Pembina Cardium CO2-Enhanced Oil Recovery Monitoring Pilot (Alberta, Canada) and from other pilot project sites were collected before and throughout the CO2 injection phase. Carbon isotope ratios of injected CO2 were markedly different from those of background CO2. After commencement of CO2 injection, the concentrations and carbon isotope values of CO2 and HCO3- in fluids and gases repeatedly obtained from monitoring wells were determined. Increasing CO2 and often also HCO3- concentrations in concert with carbon isotope values trending towards those of the injected CO2 revealed effective solubility and ionic trapping of injected CO2 at several monitoring wells at the study sites. In addition, changes in the oxygen isotope values of reservoir fluids provided independent evidence for dissolution of injected CO2 in the produced waters. We conclude that geochemical and isotopic monitoring techniques can play an important role in verification of CO2 storage in mature oilfields and saline aquifers, provided that the isotopic composition of the injected CO2 is distinct.
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Sleipner CO2 Storage– 13 Years of Injection and Monitoring
Authors S. Østmo, J. Lippard and O. EikenCO2 has been stored in the Utsira Formation of the North Sea at the Sleipner field since 1996, and at the end of 2009, more than 11 million tonnes had permanently been placed underground. Injection has been going on with high regularity during these 13 years. CO2 enters the formation at supercritical (dense phase) conditions. The geophysical monitor data consists of a base seismic survey from 1994 and six high-quality repeat surveys, giving a unique “movie” of the development of the subsurface CO2 plume. The seismic images are unusually bright, caused by the large contrast in compressibility between fully water-saturated rocks to CO2-saturated rocks. Rock velocity reduces from 2050 m/s to about 1400 m/s and formation fluid density is reduced from about 1030 kg/m3 to around 730-770 kg/m3 on average for the subsurface CO2. The CO2 plume consists of nine different identifiable layers of CO2, interpreted as thin CO2 accumulations trapped below the sealing cap rock and below thin intra-Utsira shale layers. The 4D seismic defines the geometry and growth of the plume well, and show with high confidence that all of the injected CO2 stays in the primary storage formation, without any leakage. Seafloor gravity monitoring has successfully been applied in 2002, 2005 and 2009, showing separable time-lapse signals from both the CO2 plume and the hydrocarbon gas reservoir beneath. These data give the best estimate of plume average density (and temperature). The data interpretation shows that the CO2 plume is growing in all directions. The flow seems to be mainly topographically controlled. The storage capacity and efficiency of the primary anticline benefits from a large rock volume receiving CO2. Even if the CO2 is not permanently trapped, a significant part will stay as residual saturation. Focus in recent years has been on demonstration of seal integrity and lack of any leakage. This is important for this high profile project, which is the first, longest-running and largest CCS (Carbon Capture and Storage) project world-wide.
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Microbial Monitoring During CO2 Storage in Deep Subsurface Saline Aquifers in Ketzin, Germany
Authors D. Morozova, M. Zettlitzer, A. Vieth and H. WürdemannThorough studies of samples from deep boreholes, using a variety of molecular techniques, have shown an active biosphere composed of diverse groups of microorganisms. Since microorganisms represent very effective geochemical catalysts, the investigation of their distribution and physiology could be of great importance for the process of CO2 storage. In the frame of the EU Project CO2SINK a field laboratory to study CO2 storage into saline aquifer is operated. Our studies aim at the monitoring of biological and biogeochemical processes and their impact on the technical effectiveness of CO2 storage technique. Interactions between microorganisms and the minerals of both the reservoir and the cap rock may cause major changes to the structure and chemical composition of the rock formations, which may influence the permeability within the reservoir. In addition, precipitation and corrosion may occur around the well affecting casing and cement. Moreover, the growth of microorganisms on the material surface (biofilms) can have a profound effect on material performance. Therefore, analyses of the composition of microbial communities and its changes should contribute to an evaluation of the effectiveness and reliability of the long-term CO2 storage, e.g. speed up of mineralisation. In order to investigate processes in the deep biosphere that will occur between injected supercritical CO2, the rock substrate and the microorganisms, the PCR SSCP method (Single-Strand-Conformation Polymorphism) and FISH method (Fluorescence in situ Hybridisation) were used. The identification and quantification of microorganisms enables the correlation to metabolic classes and provides information about the biochemical processes in the deep biosphere. Although saline aquifers could be characterised as an extreme habitat for microorganisms due to reduced conditions, high pressure and salinity, high numbers of diverse groups of microorganisms were found. The deep biosphere community was dominated by the haloalkalifilic fermentative bacteria (Halomonas, Halolactibacillus, Halobacteroides), extremophilic organisms like Deinococcus, and sulphate reducing bacteria (Desulfosporosinus, Desulfotomaculum, Desulfohalobium). Of great importance was the identification of sulphate reducing bacteria, which are known to be involved in corrosion processes. Microbial monitoring during CO2 injection has shown that microbial communities were strongly influenced by the CO2 injection. In addition, microbial communities revealed high adaptability to the changed environments after CO2 injection. Further analyses of the microbial community using PCR-DGGE (Denaturing Gradient Gel Electrophoresis) as well as 16S rRNA molecular cloning of the complete gene are in progress.
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Microbial Aspects of Mineral Dissolution and Precipitation During CO2 Storage– First Results of Long-term CO2 Exposure
Authors L. Pellizzari, M. Wandrey, S. Fischer, A.K. Scherf, M. Zettlitzer and H. WürdemannMicroorganisms play a major role in mineral distribution and redistribution of elements within the earth’s crust. The storage of CO2 may affect the local composition of organic and inorganic components of reservoir systems, consequently influencing microbial activities. Biologically mediated reactions like mineral dissolution and precipitation are examples of how a reservoir could be affected. Within the frame of CO2SINK (Schilling et al., 2009) long-term experiments under in situ P-T-conditions are performed in order to investigate the impact of chemically and microbially induced dissolution and precipitation reactions during CO2 storage. Freshly drilled sandstone sections from the target reservoir at Ketzin from a depth of about 630 m were acquired and have been incubated together with synthetic brine in high pressure vessels at 5.5 MPa and 40 °C since September 2007. Compared to the initial composition, Ca2+, Mg2+ and K+ concentrations are increased and exceed those of the reservoir fluid. Observed effects may be caused by mineral dissolution in response to CO2 exposure. Since the total dissolved solids concentration (TDS) of the synthetic brine is about 20 % lower than that of the Ketzin reservoir fluid, additional information is still needed to only detect changes exclusively caused by CO2. In consistence with the inorganic declines, XRD, SEM and EMP analysis suggests feldspar dissolution. Organic acids are marker for the presence of active microorganisms. They are intermediate products of the bacterial metabolism, and are metabolised to gain energy. If excreted, organic acids can locally decrease the pH at the bacterial attachment site and may support mineral dissolution. Untreated sandstone samples showed an organic acid concentration of about 50 mg/kg, yielded by fresh water extraction. The concentration of organic acids in the vessel fluid was lower (19-87 µg / ml compared to about 250 µg / ml) than the expected concentration, indicating microbial degradation. The composition of the microbial community mainly consists of chemoheterotrophic bacteria (Methylophilales bacterium, Rhizobium radiobacter, Arthrobacter, Sphingomonas) and hydrogen oxidizing bacteria (Ralstonia, Hydrogenophaga), gaining their energy from the oxidation of organic molecules and hydrogen, respectively. During the long-term exposure experiment only minor changes of the microbial community composition were observed, reflecting the adaptation of the microorganisms to the modified conditions. The analysis of microbial metabolic activities and SEM/EDX studies will help to identify and quantify bacterial processes and to assess their long-term influence on storage efficiency.
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Capillary Trapping Capacity of Sands and Sandstones
Authors C.H. Pentland, S. Iglauer, Y. Tanino, R. El-Magrahby, O. Gharbi, B. Bijeljic, H. Okabe and M.J. BluntWe quantify the influence of the initial non-wetting phase saturation and porosity on the residual non-wetting phase saturation based on data in the literature and our own experimental results from sandpacks and consolidated rocks. The principal application of this work is for carbon capture and storage (CCS) where capillary trapping is a rapid and effective way to render the injected CO2 immobile, guaranteeing safe storage. We introduce the concept of capillary trapping capacity (Ctrap) which is the product of residual saturation and porosity that represents the fraction of the rock volume that can be occupied by a trapped non-wetting phase. We propose empirical fits to the data to correlate trapping capacity and residual saturation to porosity and initial saturation. We show that trapping capacity reaches a maximum of approximately 7% for rock porosities of 20%, which suggests an optimal porosity for CO2 storage. We present initial results from a super critical CO2-brine core flood experiment. Computer tomography imaging is used to quantify phase saturations within the sandstone core. We show that super critical CO2 is trapped within the core and that the mixing of super critical CO2 and brine is a key experimental procedure.
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Physical Phenomena During CO2 Injection– From Lab to Field
Authors R. Berenblyum, A. Shchipanov and L. SurguchevCO2 Capture and Storage is a relatively new and a rapidly developing area which may benefit from knowledge acquired in both natural gas storage and Enhanced Oil Recovery projects. Some of the EOR methods like foam and polymer application to gas injection may be used to improve CO2 sweep in the underground storage cites and therefore, maximize storage capacity. Good understanding and correct representation of physical phenomena in simulation are essential to predict storage capacity of a site and CO2 migration over geological timescale. A number of laboratory investigations and simulation studies performed in IRIS over a course of last years provided a deeper understanding of physical phenomena and highlighted potential problems in scaling up those phenomena to reservoir level. While those investigations were performed for CO2 EOR projects the effects of the above mentioned physical phenomena would be much more pronounced during millennia of storage compared to years of typical EOR applications. Several phenomena are addressed here: CO2 dissolution in aqueous phase; The carbon dioxide would migrate inside the storage site both as a free and dissolved phase; diffusive transfer in the formation; carbon dioxide interaction with reservoir rock may result in changes in rock properties; fractures and faults may be affected by the pressure changes during the CO2 injection / migration and may become conducting altering CO2 migration path and inducing leak-offs from the storage site. A mechanistic investigation was performed to evaluate sensitivity of the CO2 storage and migration to uncertainty of the reservoir parameters for a typical formation in the North Sea. It was shown that correct understanding and representation of physical phenomena is essential for designing the CSS project. The paper concluded with suggestions on how to apply modern reservoir simulators to the CSS problems and aid engineers in optimizing the storage projects.
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Regional Tectonicand Petrophysical Investigation of the Williston Basin Sediments in and Around the Weyburn CO2 Sequestration Reservoir
More LessAs a component of Phase I and II of the International Weyburn CO2 Sequestration Project, regional seismic investigations are conducted around a 100 km radius of the Midale (Mississippian) reservoir in Southern Saskatchewan. The operator EnCana intends to sequester 20 million tones of CO2 to recover an estimated 130 million bbl of oil in the next 40 years. The objective of the regional study is to document the tectonic, petrophysical and rheological properties of the sedimentary fill which guarantee the permanent storage of CO2 in the region. To achieve the above goals, 2000 kms of industry donated seismic reflection data and over 1000 boreholes and related wireline information, as well as a 15 km2 3D seismic coverage of the reservoir are analyzed. In Phase II, started from 2008, 800 boreholes with 4000 well log data have been added in the central one third area of the Phase-I territory. Eleven geologically recognizable seismic horizons are mapped, from the top of the Cretaceous to the Precambrian basement unconformity. By the integrated analysis of the seismic sections, the regional structural setting of the sedimentary fill and top of the Precambrian are mapped. The relationship between the basement structures and the disturbances, influences of deep epeirogenic movements on the development of the basin are established. The fault/fracture pattern, similarly like in any other intracratonic basin on the world, is extremely intricate. The different 1-5 kilometer blocks reactivated four times. These reactivations can be identified on the seismic sections. The starting point of establishing the three dimensional mapping of the tectonically disturbed zones has been the analysis of the 2D/3D seismic sections. To delineate and connect the different trends in areas that were covered by 2D seismic sections only, other geophysical methods, mapped geological sequences and thickness maps were applied. Included in the investigation is a detailed petrophysical analysis of the rock volume from the surface to basement level. Special attention and a detailed neural network enhanced seismic inversion have been applied to the 40 meter thick top seal of the reservoir. In the investigated area, no large scale regional tectonic elements intersect in the Weyburn field. Small scale structural disturbances (fault with small offsets/local flexures) have been identified in and above the reservoir. However, through the comprehensive analysis of the petrophysical and structural properties of the 40 meter thick cap-rock seal, the long term storage of the CO2 can be estimated with higher probability.
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Carbon Capture and Storage– Challenges for CO2 Measurement Technology
Authors K. Petrat, B. Hoff, S. Lipps and K. SchlottmannAt each stage of the Carbon, Capture and Storage (CCS) chain the captured CO2 must be accurately measured. This is necessary for detecting CO2 leakages, but also essential for verification of the CO2 quantity accounted under offsetting within emissions trading scheme (ETS). Only for the amount of CO2 which is safely stored in geological formations emission certificates will be refunded. According to the European Directive on the geological storage of carbon dioxide also the purity of the CO2 must be monitored. For ETS and the requirements of the Monitoring Guidelines uncertainties of less than 1.5 % must be achieved. Therefore the German Environmental Agency initiated a research project on the uncertainties and capability of existing continuous emission monitoring systems (CEMS) for CCS. The study was executed by TUEV SUED Industrie Service GmbH. This conference contribution summarizes the major outcomes of the study: Relevant manufacturers of analysing technology were asked to answer a questionnaire regarding measurement of CO2 to contents up to 100 %. The experiences from operators of pilot plants, literature research and own experiences were compiled and evaluated. It yielded that common CO2 analysing technology like non-dispersive infrared spectrometer (NDIR) is theoretically suitable for determine CO2 contents up to 100 %. But all this analysis devices are mechanically not able to cope with the pressures in CO2 pipelines or at the injection sites. Therefore CO2-flow has to be expanded to atmospheric conditions to be analysed. For determine the mass of CO2 the volume respectively the mass flow must be known. Thus, at the next step the existing flow metering technology regarding CO2 in the dense or supercritical stage was evaluated. Orifice plate meters, ultrasonic meters or coriolis meters could measure a CO2 flow but all of them have restrictions and the demanded uncertainties could not be guaranteed under conditions like pressure drops, two-phase conditions or at the supercritical stage. This contribution evaluates existing analysis and flow metering technology and summarizes its challenges and restrictions. It identifies main areas of future research and development work on existing technology in order to cope with the identified restrictions. Thus will giving a guideline for the next future regarding this very important aspect of CCS.
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Uncertainties in Hydrogeochemical Modelling of Water-mineral Interaction in the Field of CO2-storage
Authors C. Haase, M. Ebert, F. Dethlefsen and A. DahmkeModelling of water-mineral interactions in deep saline aquifers following an injection of CO2 shows significant dependence on the applied software and thermodynamic dataset. Five scenarios were used to calculate the precipitation or dissolution of a mineral and each scenario was modelled with the programmes and their provided thermodynamic datasets. Four different hydrogeochemical modelling programmes, PHREEQC, EQ3/6, The Geochemist’s Workbench and FactSage/ChemApp, were used. While the first three programmes compute the equilibrium state based on the equilibrium constant approach, FactSage minimizes the Gibbs energy to reach the equilibrium state. Comparisons of the programmes using the same thermodynamic dataset show that the modelling results are similar. In four out of five modelled scenarios hypothetical groundwater compositions consisting of major cations and anions in ionic strengths of 0.04 and 0.6 mol/l, respectively, were used. Selected temperatures were 25 and 60°C, respectively, and the CO2 fugacity was fixed at 10 bars. For the fifth scenario a brine of Lower Cretaceous sediments at reservoir conditions was used. In this case CO2 fugacity was fixed according to a depth of approximately 1000 m. In all of the scenarios the dissolved or precipitated amount of various minerals was calculated, which typically occur in the sediments of northern Germany and which are in addition important for the mineral trapping of CO2. The results of the first four scenario calculations show exemplarily for calcite that at the low ionic strength of 0.04 mol/l and both given temperatures the amount of dissolved calcite varies from 8.4 × 10-3 to 1.7 × 10-2 mol at 60°C between the dataset “llnl.dat” of PhreeqC and “FT_Helg” of Factsage. At the higher ionic strength of 0.6 mol/l a dissolution of calcite with a variation from 5.5 × 10-2 to 6.3 × 10-2 was calculated by using three of the 22 thermodynamic datasets. By using the other 19 datasets calcite precipitates by 3.5 × 10-3 to 7.8 × 10-3 mol instead of being dissolved. In the fifth scenario the variation of the amount of dissolved calcite ranges from 3.8 × 10-3 to 2.2 × 10-2 mol. This discrepancy is caused by different aqueous complexes and their equilibrium constants, which are differing in the used datasets. 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 Programme GEOTECHNOLOGIEN.
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CO2 Storage– Monitoring of Related Surface Movements from Space - Potential for Central European Land Cover Conditions?
Authors L. Petrat, M. Riedmann and J. AnderssohnThe EU Directive on Carbon Capture and Storage passed EU Parliament in April, 2009. It requests a complex plan for monitoring CO2 storage sites - during operation and many years after operation. Monitoring methods should represent the best available technique for detecting the existence of the CO2 in the underground. The technology should also provide a wide areal spread in order to capture information of the complete storage complex and beyond. Under this aspect, the strong potential of satellite based radarinterferometric monitoring of surface movements related to underground CO2 storage has been demonstrated at the onshore CO2 storage project at In Salah in Algeria. This arid storage site with sparse vegetation offers perfect conditions for the technique. Nevertheless, future CO2 storage sites in Europe are very likely located in areas with stronger vegetated or agricultural land cover. These areas are subject to some challenges regarding the technique due to short term changes in surface conditions - e.g. vegetation growth. The suitability of the method needs thus also to be demonstrated for Central Europe surface conditions to further establish this very promising technology. As a consequence, a project was initiated by the European Space Agency in order to evaluate the impact of different surface conditions by using most sophisticated radar satellite data available. This contribution summarizes the main results: Latest radar satellite data from TerraSAR-X satellite with maximum spatial and temporal resolution have been used for two different field tests. As a first field case, the CO2 storage site operated by BP/Statoil at In Salah in Algeria has been monitored since 2008. Interferometric processing yielded more complex spatial and temporal surface movement information of the area compared to results from conventional radar satellite data. On the other hand, due to lack of operational CO2 storage sites in Central Europe the technique was evaluated for a gas storage site in Germany - mainly covered by forest and agricultural fields: Number of points with surface movement information from space increased with the use of high resolution data from TerraSAR-X satellite. With this higher number of points and also improved sensitivity to smaller surface movements, the suitability of the method under these surface conditions has been demonstrated. As such, it can be stated that the method of spaceborne radarinterferometry should further be considered for a contribution to the monitoring plan requested by the EU Directive.
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Identification of Dissolved CO2 Brine by Time-lapse Logging
Authors T. Matsuoka, Z. Xue and J. KimAs is well known, CCS is considering one of effective approaches to global warming problem and many pilot projects are executing around the world. At Japan, RITE (Research Institute of Innovation Technology of the Earth) had executed a pilot CO2 injection project at Nagaoka site in Niigata Prefecture. At Nagaoka pilot site, total 10,400 ton of CO2 was injected at 1110m deep saline aquifer. In order to developing geophysical monitoring technology, time-lapse seismic tomography and time-lapse sonic and induction logging were conducted at observation wells. CO2 breakthrough was observed after 8 months of the CO2 injection at 40 m apart observation well. The evidences of breakthrough are (1) a moderate increase in resistivity by induction data (2) a drastic decrease in P-wave velocity by sonic data (3) a decrease in neutron porosity. The time-lapse logging had continued after the end of injection to investigate post-injection CO2 behavior. Total 37 time-lapse were conducted during 2 years injection period and 3 years post-injection period. Injected CO2 is trapped physically under the cap rock and also CO2 is dissolved into the brine and CO2 is chemically trapped at reservoir water. These two trapping mechanize might be identified by using resistivity data since the supercritical CO2 is almost insulating body, but CO2 dissolved brine becomes low resistivity values. The density of CO2 dissolved brine becomes larger than undissolved brine, therefore dissolved brine will move down ward at the reservoir zone. The time-lapsed induction logging shows the resistivity value increase at deeper part of reservoir after the CO2 breakthrough after 3 years. This shows the CO2 dissolved brine migration process at post injection phase.
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Preliminary Studies on Potential Rock Samples for CCS in the Pannonian Basin, Hungary
More LessOne of the largest storage potential for CCS is in the deep saline aquifers because their pore water cannot be used for drinking and for agricultural activities. In the Pannonian Basin (Hungary) there are a few sedimentary subbasins filled up by sedimentary rock sequences containing such aquifers, which have the main potential for CCS. Our chosen study area in the Pannonian Basin is the Jászság subbasin, where numerous seismic data and documents of hydrocarbon exploration wells are available. As Hungary is situated in the middle of the Pannonian Basin, its emissions could be significantly reduced by CCS. That is the main reason to find a suitable place for CCS. The potential reservoir rock series now form a hidrogeologically coherent regional system, indicating a large potential for storage capacity. Furthermore, the saline aquifer system is large enough to ensure its long-term industrial usage for CCS, because the injection does not cause critical increase in the pressure. The siltstone in the selected formations does not have porosity high enough to be the storage rock, whereas the permeability is not low enough to be a good cap rock. That is why we avoided sampling siltstone-rich rocks. Our detailed studies deal with the sandy Szolnok Formation, and the clayey Algyő Formation. The Szolnok Formation is consists basically of sandstone, its bottom is nearly 1000 to 3500 m deep under the surface, thus it would be used as a storage rock. Its cap rock is called as Algyő Formation with more than 1000 m thickness, and a clayey composition. These potential rock associations are studied in detail in our ongoing research. We will do ex situ tests observing the behavior of the rocks when injecting supercritical CO2 in the saline pore water on pressure and temperature representing the depth of planned injection conditions. These results will be presented in our poster. Tests are made on both of the storage, and reservoir rocks. Moreover, we will present some tests with samples from the boundary of cap and reservoir formations to determine what kind of geochemical reactions and petrophysical changes take place on the very critical part of the storage complex, in order to ensure long term safe storage.
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Effects of Impurities on Carbon Dioxide Storage Processes
By C.E. BesuaSuccessful engineered impure carbon dioxide storage in geological reservoirs integrates both the ability to identify an appropriate reservoir and forecast their long-term integrity. As many pilot-scale CCS projects are ongoing successfully, very little attention has been focus on what quality of carbon dioxide is required for a specific geological reservoir of interest to maximize storage mechanisms and security. In this research, I report my findings on (1) reservoir fluid characterization using an equation of state based programme, and (3) a fully compositional, three dimensional reservoir simulation model using ECLIPSE compositional simulator to investigate the feasibility of injecting carbon dioxide rich gases captured using Post, Pre or Oxy fuel combustion capture technologies on two important aspects of large scale geological storage of carbon dioxide: well injectivity and enhanced gas recovery in a depleted gas reservoir. The simulation results shows that, the effectiveness of enhanced gas recovery process using impure carbon dioxide depends on the degree of mixing stability and mobility ratio. Until 10 % carbon dioxide produced, Pure CO2 and Post CO2 produced 62.2 MSm3 of methane gas compared to 61.5 MSm3 for Pre CO2 and 60.9 MSm3 Oxy CO2 . The well injectivity until original pressure of reservoir was attained (346 bar) using Pure CO2 and Post CO2 were 36.5 BSm3 compared to 36.0 BSm3 for Pre CO2 and 35.7 BSm3 for Oxy CO2. The model predicts that Post CO2 appeared to be the most desirable, as separation cost would probably be cheaper than Pure CO2 since both have the same compositional changes at typical reservoir conditions. Nevertheless, Oxy CO2 is least desirable to Pre CO2 but they will be very suitable candidates for shallow reservoirs with very low pressure and temperature gradients. The procedure and findings developed in this research can be used as guidelines for designing and implementing any future large scale CCS project in a gas reservoir.
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Impact of Fault Rock Properties on CO2 Storage in Sandstone Reservoirs
Authors A. Torabi, R. Gabrielsen, E. Skurtveit, H. Fossen, F. Cuisiat and J. TverangerOver the years of research and development in CO2 sequestration technology, saline aquifer and depleted petroleum reservoirs have been considered as potential reservoirs for geological storage of CO2 (Baines & Worden, 2004; Bergmo et al., 2009; Hermanrud et al., 2009). The storage capacity of a reservoir is determined by five factors: the formation thickness, the area of the storage site, rock porosity, CO2 density and the storage efficiency (Cooper, 2009). Main challenges for capacity estimation is geological heterogeneities within the reservoir, specially the presence of sub-seismic fractures, faults and deformation structures. An optimal CO2 storage reservoir needs to have high porosity and good permeability and right communicational properties. Within sandstone reservoirs, deformation bands and faults may act as barriers, introduce compartmentalization and hence reduce the injection rate and the total capacity of the reservoir or compartments. In addition, CO2 injection in aquifers/reservoirs creates a fluid pressure increase, which leads to changes in the stress state of the aquifer/reservoir and the sealing rocks above and below. This might affect and reactivate faults both within and around the reservoir (Li et al., 2007), which might have undesirable consequences. With these in mind, the main challenge is to enhance our understanding of the processes and products of brittle deformation in porous sandstone in order to forecast the distribution and impact of faults on reservoir/aquifer performance and seal properties. This will contribute to improve risk assessment and optimized planning for the choice of reservoir/aquifer for CO2 storage. In the light of this, our main focus within our ongoing research have been to rise to the above challenge by an integrated, cross-disciplinary, comprehensive study which combines analysis of empirical outcrop and possibly subsurface data, experiments using physical analogues, micro-structural analysis and numerical modeling. Our research based on natural and analogue examples reveal that faults and their associated deformation structure in sandstone reservoirs can reduce the petrophysical properties of porous sandstone considerably (Tveranger et al., 2008;Braathen et al., 2009). Permeability is decreased up to 4 orders of magnitude within deformation bands (Torabi & Fossen, 2009). On the other hand, the thickness, microstructure and hence the petrophysical properties of faults and deformation bands can change along them at short distances, changing and in most cases reducing the ability of the faults and bands to act as barriers to fluid flow (Torabi et al., 2008; Torabi and Fossen, 2009).
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Subseismic Deformation Analysis- A Prediction Tool for a Safe CO2- Reservoir Management
Authors C.M. Krawczyk and D.C. TannerThe evolution of a reservoir is mostly affected by deformation. Large-scale, subsurface structure and deformation is typically identified by seismic data, small-scale fractures by well data. However, faulting at the medium sub-seismic scale plays an important role, e.g. in gas or geothermal reservoirs: large individual reservoirs can be disrupted by faults enhancing fluid flow, or producing compartmentalized deposits due to cementation of fractures. Thus, between both scales, seismic and well data, we lack a deeper understanding of how deformation scales in the sub-seismic region. Bridging this gap will allow to make predictions about the future development of a reservoir, the generation of possible pathways due to changes in the stress regime, and thus to judge storage safety. To start tackling this problem, a 3-D reflection seismic data set in the North German Basin was analysed with respect to structure and faults in great detail, calibrated by well data. This led to the determination of magnitude and distribution of deformation and its accumulation in space and time on the seismic scale. The structural interpretation unravels the kinematics in the North German Basin with extensional events during basin initiation and later inversion. For further quantitative deformation and fracture prediction on the sub-seismic scale, two different approaches are introduced. Increased resolution of subtle tectonic lineaments is achieved by coherency processing yielding together with geostatistic tools the distribution of low- and high-strain zones in the region. Independently, the distribution and quantification of the strain magnitude is predicted from 3-D retro-deformation of the identified structures. For the fault structure analysed, it shows major-strain magnitudes between 5-15% up to 1.5 km away from a fault trace, and variable deviations orientation of associated extensional fractures. The small scale is represented by FMI data from borehole measurements, showing main fault directions and densities. These well data allow the validation of our sub-seismic deformation analyses. In summary, the good correlation of results across the different scales makes the prediction of small-scale faults/fractures possible. The suggested geomechanical workflow requires principally the 3-D coverage of a region. It yields in great detail both the tectonic history of a region as well as predictions for the genesis of structures below the resolution of reflection seismics.
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Ground Deformation Monitoring for all Project Phases of CO2 Storage Using Radar Satellites
Authors A. Arnaud, M. de Faragó, B. Payás, J. Duro, G. Cooksley and M. BanwellInSAR (Interferometry for Synthetic Aperture Radar) technology is a spaceborne measurement method that uses radar satellite images to detect and measure ground deformation with millimetric precision. Measurements are taken remotely from space, making this an appropriate tool for measuring ground motion in difficult to reach remote areas and in almost all weather conditions, during day or night. The Stable Point Network (SPN) is an advanced differential interferometric chain which was developed in order to process several raw radar images to achieve millimetric ground motion measurements. Results are provided in GIS format and can be received and analysed by CO2 reservoir engineers remotely without the need for site visits. InSAR may be applied at different stages during a CO2 storage project: 1)To select the most suitable site, prior to any ground work; the technique allows for the creation of historical ground motion studies of areas of interest to assess the stability of potential sites of CO2 storage by using images from the last 15 years. Moreover, SAR images are used to provide information for the detection of faults, lineaments and geological structures for surface characterization of potential reservoirs. 2)Once the site is selected and before the injection phase, a high resolution two year study enables the assessment of seasonal motion of the area of interest and the accurate identification of existing weak points (infrastructure, houses, etc.) to categorise them before the injection and pay special attention to them during the injection. 3)During the injection, surface deformation monitoring contributes to a better understanding of the CO2 distribution inside the reservoir. Given the wide area covered by radar satellite images, InSAR is a cost effective monitoring tool for the entire area surrounding the CO2 storage site. 4)For long term CO2 storage, InSAR provides a reliable and non-intrusive remote monitoring system. InSAR is adaptable to any site conditions; measurements can be taken in remote desert areas as well as in rural vegetated areas. In the later case, aluminium reflectors are installed to guarantee satellite measurement points. The frequency of measurement updates depends on the concrete project needs and can be increased during critical stages of the project. The technique’s capability to combine different satellites guarantees continuity of the measurements for at least the next 20 years.
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The In Salah CO2 Storage Demonstration Project: Short-term Monitoring to Constrain Long-term Verification
Authors P.S. Ringrose, A. Mathieson, J. Midgley, N. Saoula and I. WrightThe In Salah project in Algeria is an industrial-scale CO2 storage project that has been in operation since 2004. CO2 from several gas fields, which have a CO2 content of 5-10%, is removed from the production stream to meet the sales gas export specification of 0.3% CO2. The project has several key features which make it unique among the early-mover CCS demonstration projects. The site is onshore in a remote desert location, with storage in low-permeability rock formations in the saline aquifer adjacent to a producing gas reservoir. This demonstration project is thus relevant to many candidate CCS sites in saline aquifers and depleted oil and gas reservoirs in continental locations close to major point-sources of CO2. The key question the project had to address was which monitoring methods would be fit-for-purpose at this site. The criteria for determining this include: (a) ability of the method to detect CO2 migration as a fluid or gaseous phase, (b) the practical constraints for surface and down-hole tool deployment, and (c) cost. After a thorough and progressive review of the potential methods, the following monitoring portfolio has emerged: • Downhole gas analysis (as a baseline for subsurface gas distributions) • Surface gas analysis (as a baseline for surface gas distributions) • Production and injection wellhead monitoring (including pressures, temperatures, gas composition, and detection of injected tracers) • Micro-seismic event detection (deployed in a dedicated monitoring well) • Time-lapse 3D seismic (over a limited area of interest) • Satellite (InSAR) data to detect surface deformation • Tiltmeters and GPS stations to calibrate surface deformations • Groundwater wells (to measure base-line groundwater chemistry and flow and to deploy longer-term CO2 monitoring devices) • Core and well log data to characterise the reservoir and calibrate subsurface models. The ongoing R&D programme, involving several partners supported by the US DoE and the European Commission, focuses on improved understanding of the coupled mechanical and multi-phase flow processes, and the corresponding input data and assumptions. Preliminary models show a CO2 migration pattern consistent with observations to date. Longer-term predictions are inherently uncertain, but the 5-year monitoring history does give us improved constraints to these uncertainties.
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Aquifer Appraisal and Pressure Management
Authors D.S. Hughes and A. BecklySummary not available
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What Have We Learnt from Demonstration Projects?
Authors M. Basava-Reddi, B. Beck, M. Haines, T. Dixon and N. WildgustSummary not available
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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. BakSummary not available
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