Monitoring and volumetric estimation of injected CO2 using 4D seismic,petrophysical data,core measurements and well logging: a case study at Ketzin,Germany

More than 50 000 tons of CO₂ have been injected at Ketzin into the Stuttgart Formation, a saline aquifer, at approximately 620 m depth, as of summer 2011. We present here results from the 1^st repeat 3D seismic survey that was performed at the site in autumn 2009, after about 22 000 tons of CO₂ had been injected. We show here that rather complex time‐lapse signatures of this CO₂ can be clearly observed within a radius of about 300 m from the injection well. The highly irregular amplitude response within this radius is attributed to the heterogeneity of the injection reservoir. Time delays to a reflection below the injection level are also observed. Petrophysical measurements on core samples and geophysical logging of CO₂ saturation levels allow an estimate of the total amount of CO₂ visible in the seismic data to be made. These estimates are somewhat lower than the actual amount of CO₂ injected at the time of the survey and they are dependent upon the choice of a number of parameters. In spite of some uncertainty, the close agreement between the amount injected and the amount observed is encouraging for quantitative monitoring of a CO₂ storage site using seismic methods.     

Influence of subsurface injection on time‐lapse seismic: laboratory studies at seismic and ultrasonic frequencies

Seismic monitoring of reservoir and overburden performance during subsurface CO₂ storage plays a key role in ensuring efficiency and safety. Proper interpretation of monitoring data requires knowledge about the rock physical phenomena occurring in the subsurface formations. This work focuses on rock stiffness and elastic velocity changes of a shale overburden formation caused by both reservoir inflation induced stress changes and leakage of CO₂ into the overburden. In laboratory experiments, Pierre shale I core plugs were loaded along the stress path representative for the in situ stress changes experienced by caprock during reservoir inflation. Tests were carried out in a triaxial compaction cell combining three measurement techniques and permitting for determination of (i) ultrasonic velocities, (ii) quasistatic rock deformations, and (iii) dynamic elastic stiffness at seismic frequencies within a single test, which allowed to quantify effects of seismic dispersion. In addition, fluid substitution effects connected with possible CO₂ leakage into the caprock formation were modelled by the modified anisotropic Gassmann model. Results of this work indicate that (i) stress sensitivity of Pierre shale I is frequency dependent; (ii) reservoir inflation leads to the increase of the overburden Young's modulus and Poisson's ratio; (iii) in situ stress changes mostly affect the P‐wave velocities; (iv) small leakage of the CO₂ into the overburden may lead to the velocity changes, which are comparable with one associated with geomechanical influence; (v) non‐elastic effects increase stress sensitivity of an acoustic waves; (iv) and both geomechanical and fluid substitution effects would create significant time shifts, which should be detectable by time‐lapse seismic.     

Iterated extended Kalman filter method for time-lapse seismic full-waveform inversion

Time-lapse seismic data is useful for identifying fluid movement and pressure and saturation changes in a petroleum reservoir and for monitoring of CO₂ injection. The focus of this paper is estimation of time-lapse changes with uncertainty quantification using full-waveform inversion. The purpose of also estimating the uncertainty in the inverted parameters is to be able to use the inverted seismic data quantitatively for updating reservoir models with ensemble-based methods. We perform Bayesian inversion of seismic waveform data in the frequency domain by combining an iterated extended Kalman filter with an explicit representation of the sensitivity matrix in terms of Green functions (acoustic approximation). Using this method, we test different strategies for inversion of the time-lapse seismic data with uncertainty. We compare the results from a sequential strategy (making a prior from the monitor survey using the inverted baseline survey) with a double difference strategy (inverting the difference between the monitor and baseline data). We apply the methods to a subset of the Marmousi2 P-velocity model. Both strategies performed well and relatively good estimates of the monitor velocities and the time-lapse differences were obtained. For the estimated time-lapse differences, the double difference strategy gave the lowest errors.     

Seismic time‐lapse effects of solution salt mining – a feasibility study

This article addresses the question whether time‐lapse seismic reflection techniques can be used to follow and quantify the effects of solution salt mining. Specifically, the production of magnesium salts as mined in the north of the Netherlands is considered. The use of seismic time‐lapse techniques to follow such a production has not previously been investigated. For hydrocarbon production and CO₂ storage, time‐lapse seismics are used to look at reservoir changes mainly caused by pressure and saturation changes in large reservoirs, while for solution mining salt is produced from caverns with a limited lateral extent, with much smaller production volumes and a fluid (brine) replacing a solid (magnesium salt). In our approach we start from the present situation of the mine and then study three different production scenarios, representing salt production both in vertical and lateral directions of the mine. The present situation and future scenarios have been transformed into subsurface models that were input to an elastic finite‐difference scheme to create synthetic seismic data. These data have been analysed and processed up to migrated seismic images, such that time‐lapse analyses of intermediate and final results could be done. From the analyses, it is found that both vertical and lateral production is visible well above the detection threshold in difference data, both at pre‐imaging and post‐imaging stages. In quantitative terms, an additional production of the mine of 6 m causes time‐shifts in the order of 2 ms (pre‐imaging) and 4 ms (post‐imaging) and amplitude changes of above 20% in the imaged sections. A laterally oriented production causes even larger amplitude changes at the edge of the cavern due to replacement of solid magnesium salt with brine introducing a large seismic contrast. Overall, our pre‐imaging and post‐imaging time‐lapse analysis indicates that the effects of solution salt mining can be observed and quantified on seismic data. The effects seem large enough to be observable in real seismic data containing noise.     

Rapid inversion of data from 2D resistivity surveys with electrode displacements

Resistivity monitoring surveys are used to detect temporal changes in the subsurface using repeated measurements over the same site. The positions of the electrodes are typically measured at the start of the survey program and possibly at occasional later times. In areas with unstable ground, such as landslide‐prone slopes, the positions of the electrodes can be displaced by ground movements. If this occurs at times when the positions of the electrodes are not directly measured, they have to be estimated. This can be done by interpolation or, as in recent developments, from the resistivity data using new inverse methods. The smoothness‐constrained least squares optimisation method can be modified to include the electrode positions as additional unknown parameters. The Jacobian matrices with the sensitivity of the apparent resistivity measurements to changes in the electrode positions are then required by the optimisation method. In this paper, a fast adjoint‐equation method is used to calculate the Jacobian matrices required by the least squares method to reduce the calculation time. In areas with large near‐surface resistivity contrasts, the inversion routine sometimes cannot accurately distinguish between electrode displacements and subsurface resistivity variations. To overcome this problem, the model for the initial time‐lapse dataset (with accurately known electrode positions) is used as the starting model for the inversion of the later‐time dataset. This greatly improves the accuracy of the estimated electrode positions compared to the use of a homogeneous half‐space starting model. In areas where the movement of the electrodes is expected to occur in a fixed direction, the method of transformations can be used to include this information as an additional constraint in the optimisation routine.     

Constructing a discrete fracture network constrained by seismic inversion data

Rock fractures are of great practical importance to petroleum reservoir engineering because they provide pathways for fluid flow, especially in reservoirs with low matrix permeability, where they constitute the primary flow conduits. Understanding the spatial distribution of natural fracture networks is thus key to optimising production. The impact of fracture systems on fluid flow patterns can be predicted using discrete fracture network models, which allow not only the 6 independent components of the second‐rank permeability tensor to be estimated, but also the 21 independent components of the fully anisotropic fourth‐rank elastic stiffness tensor, from which the elastic and seismic properties of the fractured rock medium can be predicted. As they are stochastically generated, discrete fracture network realisations are inherently non‐unique. It is thus important to constrain their construction, so as to reduce their range of variability and, hence, the uncertainty of fractured rock properties derived from them. This paper presents the underlying theory and implementation of a method for constructing a geologically realistic discrete fracture network, constrained by seismic amplitude variation with offset and azimuth data. Several different formulations are described, depending on the type of seismic data and prior geologic information available, and the relative strengths and weaknesses of each approach are compared. Potential applications of the method are numerous, including the prediction of fluid flow, elastic and seismic properties of fractured reservoirs, model‐based inversion of seismic amplitude variation with offset and azimuth data, and the optimal placement and orientation of infill wells to maximise production.     

Rock physics modelling and inversion for saturation-pressure changes in time-lapse seismic studies

Time-lapse seismic data are generally used to monitor the changes in dynamic reservoir properties such as fluid saturation and pore or effective pressure. Changes in saturation and pressure due to hydrocarbon production usually cause changes in the seismic velocities and as a consequence changes in seismic amplitudes and travel times. This work proposes a new rock physics model to describe the relation between saturation-pressure changes and seismic changes and a probabilistic workflow to quantify the changes in saturation and pressure from time-lapse seismic changes. In the first part of this work, we propose a new quadratic approximation of the rock physics model. The novelty of the proposed formulation is that the coefficients of the model parameters (i.e. the saturation-pressure changes) are functions of the porosity, initial saturation and initial pressure. The improvements in the results of the forward model are shown through some illustrative examples. In the second part of the work, we present a Bayesian inversion approach for saturation-pressure 4D inversion in which we adopt the new formulation of the rock physics approximation. The inversion results are validated using synthetic pseudo-logs and a 3D reservoir model for CO₂ sequestration.     

Static and dynamic stiffness measurements with Opalinus Clay

In this work, an experimental study was carried out with the aim of reconciling static and dynamic stiffness of Opalinus Clay. The static and dynamic stiffness of core plugs from a shaly and a sandy facies of Opalinus Clay were characterized at two different stress states. The measurements included undrained quasi-static loading–unloading cycles from which the static stiffness was derived, dynamic stiffness measurement at seismic frequencies (0.5–150 Hz) and ultrasonic velocity measurements (500 kHz) probing the dynamic stiffness at ultrasonic frequencies. The experiments were carried out in a special triaxial low-frequency cell. The obtained results demonstrate that the difference between static and dynamic stiffness is due to both dispersion and non-elastic effects: Both sandy and shaly facies of Opalinus Clay exhibit large dispersion, that is, a large frequency dependence of dynamic stiffness and acoustic velocities. Especially dynamic Young's moduli exhibit very high dispersion; between seismic and ultrasonic frequencies they may change by more than a factor 2. P-wave velocities perpendicular to bedding are by more than 200 m/s higher at ultrasonic frequencies than at seismic frequencies. The static undrained stiffness of both sandy and shaly facies is strongly influenced by non-elastic effects, resulting in significant softening during both loading and unloading with increasing stress amplitude. The zero-stress extrapolated static undrained stiffness, however, reflects the purely elastic response and agrees well with the dynamic stiffness at seismic frequency.     

Anisotropic 4D seismic response inferred from ultrasonic laboratory measurements: A direct comparison with the isotropic response

Pore-pressure depletion causes changes in the triaxial stress state. Pore-pressure depletion in a flat reservoir, for example, can be reasonably approximated as uniaxial compaction, in which the horizontal effective stress change is smaller than the vertical effective stress. Furthermore, the stress sensitivity of velocities can be angle-dependent. Therefore, time-lapse changes in reservoir elastic anisotropy are expected as a consequence of production, which can complicate the interpretation of the 4D seismic response. The anisotropic 4D seismic response caused by pore-pressure depletion was investigated using existing core velocity measurements. To make a direct comparison between the anisotropic 4D seismic response and the isotropic response based only on vertical velocities, pseudoisotropic elastic properties were utilized, and the two responses were compared in terms of a dynamic rock physics template. A comparison of the dynamic rock physics templates indicates that time-lapse changes in reservoir elastic anisotropy have a noticeable impact on the interpretation of 4D seismic data. Changes in anisotropy as a result of pore-pressure depletion cause a time-lapse amplitude variation with offset response as if there is a reduction in V_P/V_S (i.e., pseudoisotropic V_P/V_S decreases), although the vertical V_P/V_S increases. The impact of time-lapse changes in anisotropy on the amplitude variation with offset gradient was also investigated, and the time-lapse anisotropy was found to enhance changes in the amplitude variation with offset gradient for a given case.     

Relating 4D seismics to reservoir geomechanical changes using a discrete element approach

A modified discrete element method is briefly introduced and used for modelling reservoir geomechanical response during fluid injection and depletion. The modified approach works as a continuum method until some local failure is initiated, after which it behaves like a discrete element method on a polygonal lattice. The method is advantageous for modelling fracture developments in rocks. It is applied here to synthetic models of two reservoirs taken from the North Sea (Gullfaks and Elgin‐Franklin). For Gullfaks, two cases of water injection were modelled, one with low horizontal effective stress and the other with low vertical effective stress. Vertical fractures are developed in the first case, whereas horizontal fractures are developed in the second case. This would not have been seen using traditional methods. Based on 4D seismics data for the Gullfaks field, one may envision that horizontal fractures could have been formed. The Elgin‐Franklin synthetic model is used to study various scenarios of changing stress field around the depleting reservoir. Based on 4D seismics data from this field, one may see changes that could be interpreted in terms of possible fault reactivation.     

Quantitative estimation of water storage and residence time in the epikarst with time‐lapse refraction seismic

The hydrodynamic characterization of the epikarst, the shallow part of the unsaturated zone in karstic systems, has always been challenging for geophysical methods. This work investigates the feasibility of coupling time‐lapse refraction seismic data with petrophysical and hydrologic models for the quantitative determination of water storage and residence time at shallow depth in carbonate rocks. The Biot–Gassmann fluid substitution model describing the seismic velocity variations with water saturation at low frequencies needs to be modified for this lithology. I propose to include a saturation‐dependent rock‐frame weakening to take into account water–rock interactions. A Bayesian inversion workflow is presented to estimate the water content from seismic velocities measured at variable saturations. The procedure is tested first with already published laboratory measurements on core samples, and the results show that it is possible to estimate the water content and its uncertainty. The validated procedure is then applied to a time‐lapse seismic study to locate and quantify seasonal water storage at shallow depth along a seismic profile. The residence time of the water in the shallow layers is estimated by coupling the time‐lapse seismic measurements with rainfall chronicles, simple flow equations, and the petrophysical model. The daily water input computed from the chronicles is used to constraint the inversion of seismic velocities for the daily saturation state and the hydrodynamic parameters of the flow model. The workflow is applied to a real monitoring case, and the results show that the average residence time of the water in the epikarst is generally around three months, but it is only 18 days near an infiltration pathway. During the winter season, the residence times are three times shorter in response to the increase in the effective rainfall.     

Fidelity and repeatability of wave fields reconstructed from multicomponent streamer data

Wave field reconstruction – the estimation of a three‐dimensional (3D) wave field representing upgoing, downgoing or the combined total pressure at an arbitrary point within a marine streamer array – is enabled by simultaneous measurements of the crossline and vertical components of particle acceleration in addition to pressure in a multicomponent marine streamer. We examine a repeated sail line of North Sea data acquired by a prototype multicomponent towed‐streamer array for both wave field reconstruction fidelity (or accuracy) and reconstruction repeatability. Data from six cables, finely sampled in‐line but spaced at 75 m crossline, are reconstructed and placed on a rectangular data grid uniformly spaced at 6.25 m in‐line and crossline. Benchmarks are generated using recorded pressure data and compared with wave fields reconstructed from pressure alone, and from combinations of pressure, crossline acceleration and vertical acceleration. We find that reconstruction using pressure and both crossline and vertical acceleration has excellent fidelity, recapturing highly aliased diffractions that are lost by interpolation of pressure‐only data. We model wave field reconstruction error as a linear function of distance from the nearest physical sensor and find, for this data set with some mismatched shot positions, that the reconstructed wave field error sensitivity to sensor mispositioning is one‐third that of the recorded wave field sensitivity. Multicomponent reconstruction is also more repeatable, outperforming single‐component reconstruction in which wave field mismatch correlates with geometry mismatch. We find that adequate repeatability may mask poor reconstruction fidelity and that aliased reconstructions will repeat if the survey geometry repeats. Although the multicomponent 3D data have only 500 m in‐line aperture, limiting the attenuation of non‐repeating multiples, the level of repeatability achieved is extremely encouraging compared to full‐aperture, pressure‐only, time‐lapse data sets at an equivalent stage of processing.     

Relations between static and dynamic moduli of sedimentary rocks

Static moduli of rocks are usually different from the corresponding dynamic moduli. The ratio between them is generally complex and depends on several conditions, including stress state and stress history. Different drainage conditions, dispersion (often associated with pore fluid effects), heterogeneities and strain amplitude, are all potential reasons for this discrepancy. Moreover, comparison of static and dynamic moduli is often hampered and maybe mistaken due to insufficient characterization of anisotropy. This paper gives a review of the various mechanisms causing differences between static and dynamic moduli. By careful arrangements of test conditions, it is possible to isolate the mechanisms so that they can be studied separately. Non-elastic deformation induced by the large static strain amplitudes is particularly challenging, however a linear relationship between non-elastic compliance and stress makes it possible to eliminate also this effect by extrapolation to zero strain amplitude. To a large extent, each mechanism can be expressed mathematically with reasonable precision, thus quantitative relations between the moduli can be established. This provides useful tools for analyses and prediction of rock behaviour. For instance, such relations may be used to predict static stiffness and even strength based on dynamic measurements. This is particularly useful in field situations where only dynamic data are available. Further, by utilizing the possibility for extrapolation of static measurements to zero strain amplitude, dispersion in the range from seismic to ultrasonic frequencies may be studied by a combination of static and dynamic measurements.     

Forced imbibition into a limestone: measuring P‐wave velocity and water saturation dependence on injection rate

Quantitative interpretation of time‐lapse seismic data requires knowledge of the relationship between elastic wave velocities and fluid saturation. This relationship is not unique but depends on the spatial distribution of the fluid in the pore‐space of the rock. In turn, the fluid distribution depends on the injection rate. To study this dependency, forced imbibition experiments with variable injection rates have been performed on an air‐dry limestone sample. Water was injected into a cylindrical sample and was monitored by X‐Ray Computed Tomography and ultrasonic time‐of‐flight measurements across the sample. The measurements show that the P‐wave velocity decreases well before the saturation front approaches the ultrasonic raypath. This decrease is followed by an increase as the saturation front crosses the raypath. The observed patterns of the acoustic response and water saturation as functions of the injection rate are consistent with previous observations on sandstone. The results confirm that the injection rate has significant influence on fluid distribution and the corresponding acoustic response. The complexity of the acoustic response —‐ that is not monotonic with changes in saturation, and which at the same saturation varies between hydrostatic conditions and states of dynamic fluid flow – may have implications for the interpretation of time‐lapse seismic responses.     

Understanding acquisition and processing error in microseismic data: An example from Pouce Coupe Field,Canada

A challenge in microseismic monitoring is quantification of survey acquisition and processing errors, and how these errors jointly affect estimated locations. Quantifying acquisition and processing errors and uncertainty has multiple benefits, such as more accurate and precise estimation of locations, anisotropy, moment tensor inversion and, potentially, allowing for detection of 4D reservoir changes. Here, we quantify uncertainty due to acquisition, receiver orientation error, and hodogram analysis. Additionally, we illustrate the effects of signal to noise ratio variances upon event detection. We apply processing steps to a downhole microseismic dataset from Pouce Coupe, Alberta, Canada. We use a probabilistic location approach to identify the optimal bottom well location based upon known source locations. Probability density functions are utilized to quantify uncertainty and propagate it through processing, including in source location inversion to describe the three-dimensional event location likelihood. Event locations are calculated and an amplitude stacking approach is used to reduce the error associated with first break picking and the minimization with modelled travel times. Changes in the early processing steps have allowed for understanding of location uncertainty of the mapped microseismic events.     

Mechanical compaction and ultrasonic velocity of sands with different texture and mineralogical composition

This study presents the results of experimental compaction while measuring ultrasonic velocities of sands with different grain size, shape, sorting and mineralogy. Uniaxial mechanical compaction tests up to a maximum of 50 MPa effective stress were performed on 29 dry sand aggregates derived from eight different sands to measure the rock properties. A good agreement was found between the Gassmann saturated bulk moduli of dry and brine saturated tests of selected sands. Sand samples with poor sorting showed low initial porosity while sands with high grain angularity had high initial porosity. The sand compaction tests showed that at a given stress well‐sorted, coarse‐grained sands were more compressible and had higher velocities (Vp and Vs) than fine‐grained sands when the mineralogy was similar. This can be attributed to grain crushing, where coarser grains lead to high compressibility and large grain‐to‐grain contact areas result in high velocities. At medium to high stresses the angular coarse to medium grained sands (both sorted sands and un‐sorted whole sands) showed high compaction and velocities (Vp and Vs). The small grain‐to‐grain contact areas promote higher deformation at grain contacts, more crushing and increased porosity loss resulting in high velocities. Compaction and velocities (Vp and Vs) increased with decreasing sorting in sands. However, at the same porosity, the velocities in whole sands were slightly lower than in the well‐sorted sands indicating the presence of loose smaller grains in‐between the framework grains. Quartz‐poor sands (containing less than 55% quartz) showed higher velocities (Vp and Vs) compared to that of quartz‐rich sands. This could be the result of sintering and enlargement of grain contacts of ductile mineral grains in the quartz‐poor sands increasing the effective bulk and shear stiffness. Tests both from wet measurements and Gassmann brine substitution showed a decreasing Vp/Vs ratio with increasing effective stress. The quartz‐rich sands separated out towards the higher side of the Vp/Vs range. The Gassmann brine substituted Vp and Vs plotted against effective stress provide a measure of the expected velocity range to be found in these and similar sands during mechanical compaction. Deviations of actual well log data from experimental data may indicate uplift, the presence of hydrocarbon, overpressure and/or cementation. Data from this study may help to model velocity‐depth trends and to improve the characterization of reservoir sands from well log data in a low temperature (<80–100^o C) zone where compaction of sands is mostly mechanical.     

An estimation method for effective stress changes in a reservoir from 4D seismics data

Advances in seismics acquisition and processing and the widespread use of 4D seismics have made available reliable production‐induced subsurface deformation data in the form of overburden time‐shifts. Inversion of these data is now beginning to be used as an aid to the monitoring of a reservoir's effective stress. Past solutions to this inversion problem have relied upon analytic calculations for an unrealistically simplified subsurface, which can lead to uncertainties. To enhance the accuracy of this approach, a method based on transfer functions is proposed in which the function itself is calibrated using numerically generated overburden strain deformation calculated for a small select group of reference sources. This technique proves to be a good compromise between the faster but more accurate history match of the overburden strain using a geomechanical simulator and the slower, less accurate analytic method. Synthetic tests using a coupled geomechanical and fluid flow simulator for the South Arne field confirm the efficacy of the method. Application to measured time‐shifts from observed 4D seismics indicates compartmentalization in the Tor reservoir, more heterogeneity than is currently considered in the simulation model and moderate connectivity with the overlying Ekofisk formation.     

Quantitative integration of 3D and 4D seismic impedance into reservoir simulation model updating in the Norne Field

The ultimate goal of reservoir simulation in reservoir surveillance technology is to estimate long-term production forecasting and to plan development and management of petroleum fields. However, maintaining reliable reservoir models which honour available static and dynamic data, involve inherent risks due to the uncertainties in space and time of the distribution of hydrocarbons inside reservoirs. Recent applications have shown that these uncertainties can be reduced by quantitative integration of seismic data into the reservoir modelling workflows to identify which areas and reservoir attributes of the model should be updated. This work aims using seismic data to reduce ambiguity in calibrating reservoir flow simulation model with an uncertain petro-elastic model, proposing a circular workflow of inverted seismic impedance (3D and 4D) and engineering studies, with emphasis on the interface between static and dynamic models. The main contribution is to develop an updating procedure for adjusting reservoir simulation response before using it in the production forecasting and enhance the interpretive capability of reservoir properties. Accordingly, the workflow evaluates consistency of reservoir simulation model and inverted seismic impedance, assisted by production history data, to close the loop between reservoir engineering and seismic domains. The methodology is evaluated in a complex, faulted, sandstone reservoir, the Norne benchmark field, where a significant reservoir behaviour understanding (about the static and dynamic reservoir properties) is obtained towards the quantitative integration of seismic impedance data. This leads to diagnosis of the reservoir flow simulation reliability and generation of an updated simulation model consistent with observed seismic and well production history data, as well as a calibrated petro-elastic model. Furthermore, as Norne Field is a benchmark case, this study can be considered to enrich the discussions over deterministic or probabilistic history matching studies.     

Dual sensor streamer technology used in Sleipner CO2 injection monitoring

CO₂ has been injected into the saline aquifer Utsira Fm at the Sleipner field since 1996. In order to monitor the movement of the CO₂ in the sub‐surface, the seventh seismic monitor survey was acquired in 2010, with dual sensor streamers which enabled optimal towing depths compared to previous surveys. We here report both on the time‐lapse observations and on the improved resolution compared to the conventional streamer surveys. This study shows that the CO₂ is still contained in the subsurface, with no indications of leakage. The time‐lapse repeatability of the dual sensor streamer data versus conventional data is sufficient for interpreting the time‐lapse effects of the CO₂ at Sleipner, and the higher resolution of the 2010 survey has enabled a refinement of the interpretation of nine CO₂ saturated layers with improved thickness estimates of the layers. In particular we have estimated the thickness of the uppermost CO₂ layer based on an analysis of amplitude strength together with time‐separation of top and base of this layer and found the maximum thickness to be 11 m. This refined interpretation gives a good base line for future time‐lapse surveys at the Sleipner CO₂ injection site.     

Effect of oil composition on fluid substitution in heavy oil reservoirs

Unlike light oils, heavy oils do not have a well‐established scheme for modelling elastic moduli from dynamic reservoir properties. One of the main challenges in the fluid substitution of heavy oils is their viscoelastic nature, which is controlled by temperature, pressure, and fluid composition. Here, we develop a framework for fluid substitution modelling that is reliable yet practical for a wide range of cold and thermal recovery scenarios in producing heavy oils and that takes into account the reservoir fluid composition, grounded on the effective‐medium theories for estimating elastic moduli of an oil–rock system. We investigate the effect of fluid composition variations on oil–rock elastic moduli with temperature changes. The fluid compositional behaviour is determined by flash calculations. Elastic moduli are then determined using the double‐porosity coherent potential approximation method and the calculated viscosity based on the fluid composition. An increase in temperature imposes two opposing mechanisms on the viscosity behaviour of a heavy‐oil sample: gas liberation, which tends to increase the viscosity, and melting, which decreases the viscosity. We demonstrate that melting dominates gas liberation, and as a result, the viscosity and, consequently, the shear modulus of the heavy oils always decrease with increasing temperature. Furthermore, it turns out that one can disregard the effects of gas in the solution when modelling the elastic moduli of heavy oils. Here, we compare oil–rock elastic moduli when the rock is saturated with fluids that have different viscosity levels. The objective is to characterize a unique relation between the temperature, the frequency, and the elastic moduli of an oil–rock system. We have proposed an approach that takes advantage of this relation to find the temperature and, consequently, the viscosity in different regions of the reservoir.