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1.
One of the main concerns of geological carbon storage (GCS) systems is the risk of leakage through “weak” permeable areas of the sealing formation or caprock. Since the fluid pressure pulse travels faster than the carbon dioxide (CO2) plume across the storage reservoir, the fluid overpressure transmitted into overlying permeable formations through caprock discontinuities is potentially detectable sooner than actual CO2 leakage occurs. In this work, an inverse modeling method based on fluid pressure measurements collected in strata above the target CO2 storage formation is proposed, which aims at identifying the presence, the location, and the extent of possible leakage pathways through the caprock. We combine a three-dimensional subsurface multiphase flow model with ensemble-based data assimilation algorithms to recognize potential caprock discontinuities that could undermine the long-term safety of GCS. The goal of this work is to examine and compare the capabilities of data assimilation algorithms such as the ensemble smoother (ES) and the restart ensemble Kalman filter (REnKF) to detect the presence of brine and/or CO2 leakage pathways, potentially in real-time during GCS operations. For the purpose of this study, changes in fluid pressure in the brine aquifer overlying to CO2 storage formation aquifer are hypothetically observed in monitoring boreholes, or provided by time-lapse seismic surveys. Caprock discontinuities are typically characterized locally by higher values of permeability, so that the permeability distribution tends to fit to a non-Gaussian bimodal process, which hardly complies with the requirements of the ES and REnKF algorithms. Here, issues related to the non-Gaussianity of the caprock permeability field are investigated by developing and applying a normal score transform procedure. Results suggest that the REnKF is more effective than the ES in characterizing caprock discontinuities. 相似文献
2.
Seismic monitoring of sequestered carbon dioxide (CO2) in underground deposits is a matter of growing importance. The subsurface monitoring of this greenhouse gas is possible due to the marked contrast between the physical properties of natural reservoir fluids and those of carbon dioxide after the injection. This technique makes necessary the investigation of appropriate seismic indicators to link seismic attributes to petrophysical properties, composition and state of the rock as well as pore-fluid type and in-situ physical conditions. With this motivation in mind, we use a Biot–Gassmann formulation to model the theoretical P-wave amplitude reflection coefficients vs. angle of incidence in the seismic range when a planar P-wave strikes the interface between a caprock and a porous sandstone which has its pore space saturated by a mixture of CO2 with brine or oil at different states (supercritical, liquid and gas). The effects of dissolution of CO2 in oil and the existence of a saturation threshold, above which a free CO2 phase develops, are included in the computations. Attention is particularly focused on the sensitivity of the classic best-fit amplitude variations with angle coefficients, to different degrees of CO2 saturation. We conclude from this analysis that the changes in seismic AVA attributes between 30 and 40 degrees can be useful to infer bounds on the CO2 saturation degree, to detect the presence of immiscible CO2 phase and, in some cases, to infer the physical state of the accumulations. 相似文献
3.
We reformulate the original model of Hatchell and Bourne and Røste, Stovas and Landrø that couples fractional velocity change to subsurface strain via a fundamental constant R. The new model combines elastic compressibility of a dual‐porosity system for a sand–shale mixture with horizontal planes of inter‐granular weakness. The majority of observed R‐factor magnitudes from post‐stack 4D seismic data in both the reservoir and overburden can thus be explained. R is predicted to depend strongly on lithology and also initial strain state. The model is also extended to predict the observed angle‐dependence of time‐lapse time‐shifts from pre‐stack data. An expression for the gradient of time‐shift with incidence angle is obtained in terms of the background VP/VS, and also the ratio of tangential to normal compliances BT/BN representing loss or creation of inter‐granular coupling. If accurately estimated from data, this compliance ratio can be used as an additional parameter to assess the post‐production state of the overburden. It is concluded that whilst R remains the over‐arching parameter controlling the magnitude of time‐shifts measured from 4D seismic data, BT/BN is a subtler parameter that may also prove of future value. 相似文献
4.
Michinori Asaka 《Geophysical Prospecting》2023,71(1):17-28
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 VP/VS (i.e., pseudoisotropic VP/VS decreases), although the vertical VP/VS 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. 相似文献
5.
CO2 saturations are estimated at Sleipner using a two-step imaging workflow. The workflow combines seismic tomography (full-waveform inversion) and rock physics inversion and is applied to a two-dimensional seismic line located near the injection point at Sleipner. We use baseline data (1994 vintage, before CO2 injection) and monitor data that was acquired after 12 years of CO2 injection (2008 vintage). P-wave velocity models are generated using the Full waveform inversion technology and then, we invert selected rock physics parameters using an rock physics inversion methodology. Full waveform inversion provides high-resolution P-wave velocity models both for baseline and monitor data. The physical relations between rock physics properties and acoustic wave velocities in the Utsira unconsolidated sandstone (reservoir formation) are defined using a dynamic rock physics model based on well-known Biot–Gassmann theories. For data prior to injection, rock frame properties (porosity, bulk and shear dry moduli) are estimated using rock physics inversion that allows deriving physically consistent properties with related uncertainty. We show that the uncertainty related to limited input data (only P-wave velocity) is not an issue because the mean values of parameters are correct. These rock frame properties are then used as a priori constraint in the monitor case. For monitor data, the Full waveform inversion results show nicely resolved thin layers of CO2–brine saturated sandstones under intra-reservoir shale layers. The CO2 saturation estimation is carried out by plugging an effective fluid phase in the rock physics model. Calculating the effective fluid bulk modulus of the brine–CO2 mixture (using Brie equation in our study) is shown to be the key factor to link P-wave velocity to CO2 saturation. The inversion tests are done with several values of Brie/patchiness exponent and show that the CO2 saturation estimates are varying between 0.30 and 0.90 depending on the rock physics model and the location in the reservoir. The uncertainty in CO2 saturation estimation is usually lower than 0.20. When the patchiness exponent is considered as unknown, the inversion is less constrained and we end up with values of exponent varying between 5 and 20 and up to 33 in specific reservoir areas. These estimations tend to show that the CO2–brine mixing is between uniform and patchy mixing and variable throughout the reservoir. 相似文献
6.
Although previous seismic monitoring studies have revealed several relationships between seismic responses and changes in reservoir rock properties, the quantitative evaluation of time‐lapse seismic data remains a challenge. In most cases of time‐lapse seismic analysis, fluid and/or pressure changes are detected qualitatively by changes in amplitude strength, traveltime and/or Poisson's ratio. We present the steps for time‐lapse seismic analysis, considering the pressure effect and the saturation scale of fluids. We then demonstrate a deterministic workflow for computing the fluid saturation in a reservoir in order to evaluate time‐lapse seismic data. In this approach, we derive the physical properties of the water‐saturated sandstone reservoir, based on the following inputs: VP, VS, ρ and the shale volume from seismic analysis, the average properties of sand grains, and formation‐water properties. Next, by comparing the in‐situ fluid‐saturated properties with the 100% formation‐water‐saturated reservoir properties, we determine the bulk modulus and density of the in‐situ fluid. Solving three simultaneous equations (relating the saturations of water, oil and gas in terms of the bulk modulus, density and the total saturation), we compute the saturation of each fluid. We use a real time‐lapse seismic data set from an oilfield in the North Sea for a case study. 相似文献
7.
8.
Faisal Alonaizi Roman Pevzner Andrej Bóna Mohammad Alshamry Eva Caspari Boris Gurevich 《Geophysical Prospecting》2014,62(2):197-209
Time‐lapse seismic analysis is utilized in CO2 geosequestration to verify the CO2 containment within a reservoir. A major risk associated with geosequestration is a possible leakage of CO2 from the storage formation into overlaying formations. To mitigate this risk, the deployment of carbon capture and storage projects requires fast and reliable detection of relatively small volumes of CO2 outside the storage formation. To do this, it is necessary to predict typical seepage scenarios and improve subsurface seepage detection methods. In this work we present a technique for CO2 monitoring based on the detection of diffracted waves in time‐lapse seismic data. In the case of CO2 seepage, the migrating plume might form small secondary accumulations that would produce diffracted, rather than reflected waves. From time‐lapse data analysis, we are able to separate the diffracted waves from the predominant reflections in order to image the small CO2 plumes. To explore possibilities to detect relatively small amounts of CO2, we performed synthetic time‐lapse seismic modelling based on the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) Otway project data. The detection method is based on defining the CO2 location by measuring the coherency of the signal along diffraction offset‐traveltime curves. The technique is applied to a time‐lapse stacked section using a stacking velocity to construct offset‐traveltime curves. Given the amount of noise found in the surface seismic data, the predicted minimum detectable amount of CO2 is 1000–2000 tonnes. This method was also applied to real data obtained from a time‐lapse seismic physical model. The use of diffractions rather than reflections for monitoring small amounts of CO2 can enhance the capability of subsurface monitoring in CO2 geosequestration projects. 相似文献
9.
CO2 storage in the high Arctic: efficient modelling of pre‐stack depth‐migrated seismic sections for survey planning 
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下载免费PDF全文 P. Lubrano Lavadera D. Kühn B.D.E. Dando I. Lecomte K. Senger Å. Drottning 《Geophysical Prospecting》2018,66(6):1180-1200
The sequestration of CO2 in subsurface reservoirs constitutes an immediate counter‐measure to reduce anthropogenic emissions of CO2, now recognized by international scientific panels to be the single most critical factor driving the observed global climatic warming. To ensure and verify the safe geological containment of CO2 underground, monitoring of the CO2 site is critical. In the high Arctic, environmental considerations are paramount and human impact through, for instance, active seismic surveys, has to be minimized. Efficient seismic modelling is a powerful tool to test the detectability and imaging capability prior to acquisition and thus improve the characterization of CO2 storage sites, taking both geological setting and seismic acquisition set‐up into account. The unique method presented here avoids the costly generation of large synthetic data sets by employing point spread functions to directly generate pre‐stack depth‐migrated seismic images. We test both a local‐target approach using an analytical filter assuming an average velocity and a full‐field approach accounting for the spatial variability of point spread functions. We assume a hypothetical CO2 plume emplaced in a sloping aquifer inspired by the conditions found at the University of Svalbard CO2 lab close to Longyearbyen, Svalbard, Norway, constituting an unconventional reservoir–cap rock system. Using the local‐target approach, we find that even the low‐to‐moderate values of porosity (5%–18%) measured in the reservoir should be sufficient to induce significant change in seismic response when CO2 is injected. The sensitivity of the seismic response to changes in CO2 saturation, however, is limited once a relatively low saturation threshold of 5% is exceeded. Depending on the illumination angle provided by the seismic survey, the quality of the images of five hypothetical CO2 plumes of varying volume differs depending on the steepness of their flanks. When comparing the resolution of two orthogonal 2D surveys to a 3D survey, we discover that the images of the 2D surveys contain significant artefacts, the CO2‐brine contact is misplaced and an additional reflector is introduced due to the projection of the point spread function of the unresolvable plane onto the imaging plane. All of these could easily lead to a misinterpretation of the behaviour of the injected CO2. Our workflow allows for testing the influence of geological heterogeneities in the target aquifer (igneous intrusions, faults, pervasive fracture networks) by utilizing increasingly complex and more realistic geological models as input as more information on the subsurface becomes available. 相似文献
10.
Elastic rock properties can be estimated from prestack seismic data using amplitude variation with offset analysis. P‐wave, S‐wave and density ‘reflectivities’, or contrasts, can be inverted from angle‐band stacks. The ‘reflectivities’ are then inverted to absolute acoustic impedance, shear impedance and density. These rock properties can be used to map reservoir parameters through all stages of field development and production. When P‐wave contrast is small, or gas clouds obscure reservoir zones, multicomponent ocean‐bottom recording of converted‐waves (P to S or Ps) data provides reliable mapping of reservoir boundaries. Angle‐band stacks of multicomponent P‐wave (Pz) and Ps data can also be inverted jointly. In this paper Aki‐Richards equations are used without simplifications to invert angle‐band stacks to ‘reflectivities’. This enables the use of reflection seismic data beyond 30° of incident angles compared to the conventional amplitude variation with offset analysis. It, in turn, provides better shear impedance and density estimates. An important input to amplitude variation with offset analysis is the Vs/Vp ratio. Conventional methods use a constant or a time‐varying Vs/Vp model. Here, a time‐ and space‐varying model is used during the computation of the ‘reflectivities’. The Vs/Vp model is generated using well log data and picked horizons. For multicomponent data applications, the latter model can also be generated from processing Vs/Vp models and available well data. Reservoir rock properties such as λρ, μρ, Poisson's ratio and bulk modulus can be computed from acoustic impedance, shear impedance and density for pore fill and lithology identification. λ and μ are the Lamé constants and ρ is density. These estimations can also be used for a more efficient log property mapping. Vp/Vs ratio or Poisson's ratio, λρ and weighted stacks, such as the one computed from λρ and λ/μ, are good gas/oil and oil/water contact indicators, i.e., pore fill indicators, while μρ mainly indicates lithology. μρ is also affected by pressure changes. Results from a multicomponent data set are used to illustrate mapping of gas, oil and water saturation and lithology in a Tertiary sand/shale setting. Whilst initial log crossplot analysis suggested that pore fill discrimination may be possible, the inversion was not successful in revealing fluid effects. However, rock properties computed from acoustic impedance, shear impedance and density estimates provided good lithology indicators; pore fill identification was less successful. Neural network analysis using computed rock properties provided good indication of sand/shale distribution away from the existing wells and complemented the results depicted from individual rock property inversions. 相似文献
11.
José M. Carcione Martin Landrø Anthony F. Gangi Fabio Cavallini 《Geophysical Prospecting》2007,55(6):793-804
Hydrocarbon depletion and fluid injection cause compaction and stretching of the reservoir and overburden layers. 4D prestack seismic data can be used to detect these changes because compaction/stretching causes changes in traveltimes and seismic velocities. We show that, by using two different petro‐elastic models at varying effective pressures, a good approximation is to assume that the fractional changes in layer thickness, ΔL/L, and seismic velocity, Δv/v, are related by a linear function of ΔL/L. The slope of this function (the dilation factor, α= (Δv/v)/(ΔL/L) ) is negative and its absolute value generally decreases (shale, low porosity) or increases (sandstone, high porosity) with increasing layer thickness and decreasing effective pressure. The analysis is mainly performed for isotropic deformations. The dilation factor for uniaxial deformations is smaller in absolute value. The dilation factor, which can be calculated from time‐lapse data, can be used to predict reservoir compaction/stretching as a function of depth and surface subsidence. 相似文献
12.
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. 相似文献
13.
J. -R. Grasso 《Pure and Applied Geophysics》1992,139(3-4):507-534
We review earthquake distributions associated with hydrocarbon fields in the context of pore pressure diffusion models, poroelastic stress transfer and isostasy theory. These three mechanisms trigger or induce seismic instabilities at both local scale (D5 km) and at regional scale (D20 km). The modeled changes in stress are small (1 MPa), whatever the tectonic setting. Each mechanism corresponds to different production processes. (1) Local hydraulic fracturing due to fluid injection induces seismic-slip on cracks (M
L3) within the injected reservoir through decreasing the effective stress. (2) Pure fluid withdrawal causes pore pressure to decrease within the reservoir. It triggers adjustments of the geological structure to perturbations related to the reservoir response to depletion. Poroelastic mechanisms transfer this stress change from the reservoir to the surrounding levels whereM
L5 seismic instabilities occur either above or below the reservoir. (3) Massive hydrocarbon recovery induces crustal readjustments due to the removal of load from the upper crust. It can induce larger earthquakes (M
L6) at greater distance from the hydrocarbon fields than the two other mechanisms.Due to the mechanical properties of the shallow rock matrices involved, seismic slip triggered either by mechanism (1) or (2), is a second-order process of the main elastoplastic deformation. for a minimum of 80% of commercially productive basins, most of the local deformation is reported as aseismic, i.e., there is no evidence forM
L3 earthquakes. Nevertheless, the induced stresses vary as a function of time in a manner that depends on the hydraulic diffusivity (i.e., permeability) of the reservoir and surrounding rocks. Because small earthquakes (M
L3) indicate changes in stress and pore pressure, monitoring of seismicity is a means of assessingin situ reservoir behavior.The less constrained seismic response to hydrocarbon recovery is the possible connection between local fluid manipulations, triggered earthquakes and major regional earthquakes. Positive feedback mechanisms suggest that the region of seismic hazard changes is much larger than the area where hydrocarbons are extracted. These observations and models testify that fluid movement and pore pressure changes (increase or decrease) play important roles in the mechanics of earthquakes and in the triggering of natural earthquakes. 相似文献
14.
Carbon capture and storage is a viable greenhouse gas mitigation technology and the Sleipner CO2 sequestration site in the North Sea is an excellent example. Storage of CO2 at the Sleipner site requires monitoring over large areas, which can successfully be accomplished with time lapse seismic imaging. One of the main goals of CO2 storage monitoring is to be able to estimate the volume of the stored CO2 in the reservoir. This requires a parametrization of the subsurface as exact as possible. Here we use elastic 2D time‐domain full waveform inversion in a time lapse manner to obtain a P‐wave velocity constrain directly in the depth domain for a base line survey in 1994 and two post‐injection surveys in 1999 and 2006. By relating velocity change to free CO2 saturation, using a rock physics model, we find that at the considered location the aquifer may have been fully saturated in some places in 1999 and 2006. 相似文献
15.
Colin MacBeth 《Geophysical Prospecting》2014,62(1):75-96
An approximation is developed that allows mapped 4D seismic amplitudes and time‐shifts to be related directly to the weighted linear sum of pore pressure and saturation changes. The weights in this relation are identified as key groups of parameters from a petroelastic model and include the reservoir porosity. This dependence on groups of parameters explains the inherent non‐uniqueness of this problem experienced by previous researchers. The proposed relation is of use in 4D seismic data feasibility studies and inversion and interpretation of the 4D seismic response in terms of pore pressure and water saturation changes. A further result is drawn from analysis of data from the North Sea and West Africa, which reveals that the relative interplay between the effects of pore pressure and saturation changes on the seismic data can be simplified to the control of a single, spatially variant parameter CS/CP. Combining these results with those from published literature, we find that CS/CP = 8 appears to be a generality across a range of clastic reservoirs with a similar mean porosity. Using this CS/CP value, an in situ seismic‐scale constraint for the rock stress sensitivity component of the petroelastic model is constructed considering this component carries the largest uncertainty. 相似文献
16.
This study attempts to determine the relation between source parameters and mechanical properties of the rock matrix in which the microseismic events occur. For this purpose, accurate geological, mechanical and seismological data were acquired on a gas field experiencing induced seismicity due to its reservoir pressure drop. More than 30 deep boreholes (depth greater than 4 km) are concentrated in a 10×10×5 km volume, providing core samples for both geological and mechanical assessment. In this study, we focus on induced seismic events recorded by the local seismic network, over a three-year-long period. Characteristics of the seismic sources were obtained using spectral analysis and a dynamic model of failure. Results point out correlation between physical parameters of the seismic sources and the geomechanical properties of the rocks involved. Maximal static stress drops are found to be associated with the mechanical strength of the geological strata where the rupture occurs. The fracture size, using a circular model of failure, is also found to be dependent on the geomechanical setting. It is found that the size of the seismic fractures is dependent on the layer thickness and the prefracturation of the medium, both factors influencing the extension of preexisting discontinuities. The parameters of the seismic sources also show important changes when the gas reservoir is reached. The reservoir unit experienced a 45 MPa pore fluid pressure drop over a period of 20 years. 相似文献
17.
Alexey Yurikov Maxim Lebedev Marina Pervukhina Boris Gurevich 《Geophysical Prospecting》2019,67(4):984-996
Shales play an important role in many engineering applications such as nuclear waste, CO2 storage and oil or gas production. Shales are often utilized as an impermeable seal or an unconventional reservoir. For both situations, shales are often studied using seismic waves. Elastic properties of shales strongly depend on their hydration, which can lead to substantial structural changes. Thus, in order to explore shaly formations with seismic methods, it is necessary to understand the dependency of shale elastic properties on variations in hydration. In this work, we investigate structural changes in Opalinus shale at different hydration states using laboratory measurements and X-ray micro-computed tomography. We show that the shale swells with hydration and shrinks with drying with no visible damage. The pore space of the shale deforms, exhibiting a reduction in the total porosity with drying and an increase in the total porosity with hydration. We study the elastic properties of the shale at different hydration states using ultrasonic velocities measurements. The elastic moduli of the shale show substantial changes with variations in hydration, which cannot be explained with a single driving mechanism. We suggest that changes of the elastic moduli with variations in hydration are driven by multiple competing factors: (1) variations in total porosity, (2) substitution of pore-filling fluid, (3) change in stiffness of contacts between clay particles and (4) chemical hardening/softening of clay particles. We qualitatively and quantitatively analyse and discuss the influence of each of these factors on the elastic moduli. We conclude that depending on the microstructure and composition of a particular shale, some of the factors dominate over the others, resulting in different dependencies of the elastic moduli on hydration. 相似文献
18.
A 3D relocation technique permits precise locations of induced earthquakes. Geostatistical processing using the data of 87 boreholes provides the basis of a precise 3D structure, with a dome geometry. Conventional laboratory mechanical tests performed on deep rock samples (1000 m to 5000 m) define the rock properties at depths similar to those of the seismic events (1<M
L<4.2) that range from 1 to 7 km.In the studied period, most (85%), of the events were located above the gas reservoir, with very few located in the reservoir itself. Because the production parameters (50 MPa depletion of the gas pressure reservoir) are homogeneous throughout the gas field, the lateral inhomogeneity of the seismic rupture locations are a consequence of variations in the rheological response of the dome to the deformation induced by gas production.Here a ratio of two is found between the elastic modulus of the seismic rock matrix and the elastic modulus of the aseismic rock matrix. The contrast in strength is at least as great, if not greater. Repeated measured surface deformations involve the whole structure. Spatial and temporal deformations indicate that aseismic deformation is quantitatively the main process of this structural deformation. The heterogeneous stress pattern inferred fromP-axes of induced earthquakes disagrees with the tectonic regional stress field. The radial distribution ofP-axes towards the gas reservoir probably reflects the production induced deformation. The inferred deformation of the dome occurs in response to weak induced stresses. 相似文献
19.
Anozie Ebigbo Rainer Helmig Alfred B. Cunningham Holger Class Robin Gerlach 《Advances in water resources》2010
The concentration of greenhouse gases – particularly carbon dioxide (CO2) – in the atmosphere has been on the rise in the past decades. One of the methods which have been proposed to help reduce anthropogenic CO2 emissions is the capture of CO2from large, stationary point sources and storage in deep geological formations. The caprock is an impermeable geological layer which prevents the leakage of stored CO2, and its integrity is of utmost importance for storage security. Due to the high pressure build-up during injection, the caprock in the vicinity of the well is particularly at risk of fracturing. Biofilms could be used as biobarriers which help prevent the leakage of CO2 through the caprock in injection well vicinity by blocking leakage pathways. The biofilm could also protect well cement from corrosion by CO2-rich brine. 相似文献
20.
Kenneth Bredesen Per Avseth Tor Arne Johansen Richard Olstad 《Geophysical Prospecting》2019,67(4):825-842
Understanding how physical properties and seismic signatures of present day rocks are related to ancient geological processes is important for enhanced reservoir characterization. In this paper, we have studied this relationship for the Kobbe Formation sandstone in the Barents Sea. These rocks show anomalous low shear velocities and high VP/VS ratios, which does not agree well with conventional rock physics models for moderately to well consolidated sandstones. These sandstones have been buried relatively deeply and subsequently uplifted 1–2 km. We compared well log data of the Kobbe sandstone with velocity–depth trends modelled by integrating basin modelling principles and rock physics. We found that more accurate velocity predictions were obtained when first honouring mechanical and chemical compaction during burial, followed by generation of micro-cracks during uplift. We suspect that these micro-cracks are formed as overburden is eroded, leading to changes in the subsurface stress-field. Moreover, the Kobbe Formation is typically heterogeneous and characterized by structural clays and mica that can reduce the rigidity of grain contacts. By accounting for depositional and burial history, our velocity predictions become more consistent with geophysical observables. Our approach yields more robust velocity predictions, which are important in prospect risking and net erosion estimates. 相似文献