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- Volume 64, Issue 4, 2016
Geophysical Prospecting - 4 - Advances in Rock Physics, 2016
4 - Advances in Rock Physics, 2016
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A new laboratory apparatus for the measurement of seismic dispersion under deviatoric stress conditions
Authors Dawid Szewczyk, Andreas Bauer and Rune M. HoltABSTRACTA better understanding of seismic dispersion and attenuation of acoustic waves in rocks is important for quantitative interpretation of seismic data, as well as for relating seismic data, sonic‐log data, and ultrasonic laboratory data. In the present work, a new laboratory setup is described, allowing for combined measurements of quasistatic deformations of rocks under triaxial stress, ultrasonic velocities, and dynamic elastic stiffness (Young's modulus and Poisson's ratio) at seismic frequencies. The setup has been used mainly for the study of shales. For such rocks, it is crucial that the saturation of the samples is preserved, which requires fast sample mounting. The design of our setup, together with a technique that was developed for rapid mounting of strain gauges onto the sample and subsequent sealing of the sample, allows for sample preservation, which is of particular importance for shales. The performance of the new experimental setup and sample mounting procedure is demonstrated with test materials (aluminium and polyetheretherketone) and two different shale types (Mancos shale and Pierre shale). Furthermore, experimental results are presented that demonstrate the capability of measuring the impact of saturation, stress, and stress path on seismic dispersion. For the tests with Mancos shale and Pierre shale, large dispersion (up to 50% in Young's modulus normal to bedding) was observed. Increased water saturation of Mancos shale results in strong softening of the rock at seismic frequencies, whereas hardening is observed at ultrasonic frequencies due to an increase in dispersion, counteracting the rock softening. The Poisson's ratio of Mancos shale strongly increases with the level of saturation but appears to be nearly frequency independent. We have found that the different types of shale exhibit different stress sensitivities during hydrostatic loading and that the stress sensitivity is different at seismic and ultrasonic frequencies.
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Laboratory measurements of the effect of fluid saturation on elastic properties of carbonates at seismic frequencies
Authors Vassily Mikhaltsevitch, Maxim Lebedev and Boris GurevichABSTRACTA significant portion of the world's hydrocarbon reserves are found in carbonate reservoirs, yet analysis of the petrophysical properties of these reservoirs is associated with a number of challenges. Some of these challenges stem from physical and chemical interactions between the carbonate rock matrix and pore fluids, which can affect elastic properties of the rock. Hence, the study of the pore fluid effects on the elastic properties of carbonates is important for understanding a change of the field performance properties of а carbonate reservoir caused by fluid movements during hydrocarbon extraction in producing fields. In this laboratory study, we investigate the applicability of Gassmann's model for predictions of the elastic moduli of water‐ and hydrocarbon‐saturated Savonnières limestone and the influence of partial water saturation on elastic and anelastic properties of the rock. We present the results of two sets of laboratory experiments on the Savonnières oolitic limestone where we: (i) evaluate the effect of full water and n‐decane saturation on elastic moduli and attenuation at seismic (0.1 Hz–120 Hz) and ultrasonic (0.5 MHz) frequencies; and (ii) quantify the dependence of elastic moduli and extensional attenuation on water saturation at two seismic frequencies of 1 Hz and 10 Hz. We demonstrate that the change in the bulk modulus of limestone fully saturated either with n‐decane or water is in agreement with Gassmann's fluid substitution theory, whereas the shear modulus is noticeably reduced. The measurements with partial saturation show that the bulk modulus decreases with increasing water saturation to a lesser extent than the Young's and shear moduli. Our results show that extensional attenuation in the samples with closed boundaries is insignificant under dry and fully saturated conditions but is influenced greatly by the liquid content when saturation is between 0 and 20% or 95% and 100%.
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Impact of chemical alteration on the poromechanical properties of carbonate rocks
Authors E. Bemer, M.T. Nguyen, J. Dautriat, M. Adelinet, M. Fleury and S. YoussefABSTRACTThe technical and economic success of a CO2 geological storage project requires the preservation of the site injectivity and integrity properties over its lifetime. Unlike conventional hydrocarbon gas injection, CO2 injection may imply geochemical reactions between acidified pore fluids and target reservoir formations, leading to modifications of their poromechanical properties. To date, the chemical effects on the host rock mechanical behaviour are not satisfactorily taken into account in site‐scale numerical models of CO2 injection, mainly due to a lack of quantitative data. The present experimental work aims at characterizing the evolution of carbonate poromechanical properties induced by acid alteration. Unlike standard experimental approaches, the implemented alteration method induces a homogeneous dissolution pattern, which ensures reliable poromechanical measurements on altered samples. These well‐controlled alteration conditions allow a proper interpretation of the test results through the macroscopic continuous approach of poromechanics. Petrophysical, geomechanical, and petroacoustic properties of outcrop carbonate samples have been measured for different levels of alteration to mimic long‐term exposure to reactive brine. The obtained experimental data show clear trends of chemically induced mechanical weakening. Nuclear magnetic resonance measurements and microscanner imaging performed before and after alteration have provided complementary insights into the alteration effects at the microscopic scale.
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Integrated geophysical and hydromechanical assessment for CO2 storage: shallow low permeable reservoir sandstones
Authors Ismael Falcon‐Suarez, Laurence North, Kelvin Amalokwu and Angus BestABSTRACTGeological reservoirs can be structurally complex and can respond to CO2 injection both geochemically and geomechanically. Hence, predicting reservoir formation behaviour in response to CO2 injection and assessing the resulting hazards are important prerequisites for safe geological CO2 storage. This requires a detailed study of thermal‐hydro‐mechanical‐chemical coupled phenomena that can be triggered in the reservoir formation, most readily achieved through laboratory simulations of CO2 injection into typical reservoir formations. Here, we present the first results from a new experimental apparatus of a steady‐state drainage flooding test conducted through a synthetic sandstone sample, simulating real CO2 storage reservoir conditions in a shallow (∼1 km), low permeability ∼1mD, 26% porosity sandstone formation. The injected pore fluid comprised brine with CO2 saturation increasing in steps of 20% brine/CO2 partial flow rates up to 100% CO2 flow. At each pore fluid stage, an unload/loading cycle of effective pressure was imposed to study the response of the rock under different geomechanical scenarios. The monitoring included axial strains and relative permeability in a continuous mode (hydromechanical assessment), and related geophysical signatures (ultrasonic P‐wave and S‐wave velocities Vp and Vs, and attenuations Qp−1 and Qs−1, respectively, and electrical resistivity). On average, the results showed Vp and Vs dropped ∼7% and ∼4% respectively during the test, whereas Qp−1 increased ∼55% and Qs−1 decreased by ∼25%. From the electrical resistivity data, we estimated a maximum CO2 saturation of ∼0.5, whereas relative permeability curves were adjusted for both fluids. Comparing the experimental results to theoretical predictions, we found that Gassmann's equations explain Vp at high and very low CO2 saturations, whereas bulk modulus yields results consistent with White and Dutta–Odé model predictions. This is interpreted as a heterogeneous distribution of the two pore fluid phases, corroborated by electrical resistivity tomography images. The integration of laboratory geophysical and hydromechanical observations on representative shallow low‐permeable sandstone reservoir allowed us to distinguish between pure geomechanical responses and those associated with the pore fluid distribution. This is a key aspect in understanding CO2 injection effects in deep geological reservoirs associated with carbon capture and storage practices.
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Analysis of high‐resolution X‐ray computed tomography images of Bentheim sandstone under elevated confining pressures
ABSTRACTA sample of Bentheim sandstone was characterized using high‐resolution three‐dimensional X‐ray microscopy at two different confining pressures of 1 MPa and 20 MPa. The two recordings can be directly compared with each other because the same sample volume was imaged in either case. After image processing, a porosity reduction from 21.92% to 21.76% can be deduced from the segmented data. With voxel‐based numerical simulation techniques, we determined apparent hydraulic transport properties and effective elastic properties. These results were compared with laboratory measurements using reference samples. Laboratory and computed volumes, as well as hydraulic transport properties, agree fairly well. To achieve a reasonable agreement for the effective elastic properties, we define pressure‐dependent grain contact zones in addition to mineral phases in the digital rock images. From that, we derive a specific digital rock physics template resulting in a very good agreement between laboratory data and simulations. The digital rock physics template aims to contribute to a more standardized approach of X‐ray computed tomography data analysis as a tool to determine and predict elastic rock properties.
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Impact of fines and rock wettability on reservoir formation damage
Authors Ahmed Al‐Yaseri, Hani Al Mukainah, Maxim Lebedev, Ahmed Barifcani and Stefan IglauerABSTRACTPore throat plugging of porous rock by fine particles causes formation damage, and thus has attracted attention in various areas such as petroleum engineering, hydrology and geothermal energy production. Despite significant efforts, the detailed pore‐scale mechanisms leading to formation damage and the associated permeability reduction are not well understood. We thus investigated plugging mechanisms and characteristics with a combination of ex situ (i.e., coreflooding measurements and scanning electron microscopy imaging) and in situ (i.e., nuclear magnetic resonance and μCT) methods, with a particular focus on the effect of wettability.
The corefloods indicated that permeability drops rapidly when fines are injected; mechanistically thin pore throats are plugged first, followed by filling of adjacent pore bodies with the fine material (as evidenced by the nuclear magnetic resonance and μCT experiments, which can measure the pore size distribution evolution with fines injection). Furthermore, it is clear that wettability plays a major role: if fines and rock wettability are identical, plugging is significantly accelerated; wettability also controls the 3D distribution of the fines in the pore space. Furthermore we note that the deposited fines were tightly packed, apparently due to strong adhesion forces.
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Static and dynamic pressure sensitivity anisotropy of a calcareous shale
Authors Oliver N. Ong, Douglas R. Schmitt, Randolph S. Kofman and Kristine HaugABSTRACTOptimizing the productivity of nonconventional, low‐permeability “shale” reservoirs requires detailed knowledge of the mechanical properties of such materials. These rocks' elastic anisotropy is acknowledged but usually ignored due to difficulties in obtaining such information. Here we study in detail the dynamic and static elastic properties of a suite of calcareous mudstones from the nonconventional Duvernay reservoir of Alberta, Canada. The complete set of transversely isotropic elastic constants is obtained from strategically oriented ultrasonic transducers to confining pressures of 90 MPa. Wave speed anisotropies of up to 35% are observed at even the highest confining pressures. Furthermore, the stress sensitivity of the wave speeds, and hence moduli, is itself highly dependent on direction with speeds taken perpendicular to the bedding plane being highly nonlinearly dependent on pressure, whereas those along the bedding plane show, unexpectedly, nearly no pressure dependence. These observations are in qualitative agreement with the preferentially oriented porosity and minerals seen in scanning electron microscope images. These results may be significant to the interpretation of sonic logs and azimuthal amplitude versus offset for principal stress directions, for the concentration of stress within such formations, and for estimation of static engineering moduli from sonic log wave speeds.
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Creation of synthetic samples for physical modelling of natural shale
Authors Xinyuan Luan, Bangrang Di, Jianxin Wei, Jianguo Zhao and Xiangyang LiABSTRACTNatural shale samples, particularly well‐preserved, drilled core samples, are extremely difficult to obtain for laboratory research. Multiple tests must be carried out on one sample, and some samples are disposed after destructive tests. Therefore, rarity and non‐reusability of samples strongly restrict shale studies. In this study, based on statistical data from the world's major shale block, a new type of synthetic shale was physically constructed via a process of interfusion, stuffing, and compaction using quartz, clay, carbonate, and kerogen as the primary materials, according to statistical data from the world's major shale blocks. Further evaluation of the synthetic shale involved the use of scanning electron microscopy imagery and analysis of its anisotropic characteristics in comparison with natural shale. The synthetic shale had a laminated microstructure similar to natural shale, and its velocity anisotropy corresponded to Thomsen's anisotropy of a transversely isotropic medium. The results of tests for homogeneity and repeatability indicated that the construction process was stable and that several identical synthetic samples, which were satisfactorily similar to natural shale, could be produced for both iterative and destructive tests. The composition of each mineral, as well as the density, porosity, permeability, and anisotropy of the samples, were all variable. Therefore, a series of synthetic samples could be obtained with properties set to meet the requirements of petrophysical experimentation. Moreover, gas or oil saturation was also considered in the construction of the synthetic shale, meaning that the characteristics of gas or oil saturation (or the complete range of data from dry to saturated samples) could be tested using the synthetic shale.
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Experimental mechanical compaction of sands and sand–clay mixtures: a study to investigate evolution of rock properties with full control on mineralogy and rock texture
Authors Mohammad Koochak Zadeh, Nazmul Haque Mondol and Jens JahrenABSTRACTDevelopment of rock physical properties in well‐sorted and poorly‐sorted unconsolidated mono‐quartz sands and sand–clay mixtures as a function of effective stress in both dry and brine‐saturated conditions is assessed in this study. The tested samples were prepared with full control on their mineralogy, grain size, grain shape, sorting, and fabric. The experiments were performed in a high‐stress uniaxial oedometer up to a maximum of 30 MPa vertical effective stress. Sand–clay samples were a mixture of sand grains and clay particles (kaolinite or smectite) in different proportions. The maximum clay volume fraction used in the experiments was at most 30%. The initial bulk density of the tested sand‐dominated samples was adjusted to be close to the maximum index density expected for natural sediments (sand–clay mixtures) during deposition.
In pure sand samples, finer grained sand show higher initial porosity than relatively coarser grained sands. Moreover, sand–clay mixtures have lower initial porosity than pure sands. Porosity decreases as a function of increasing clay content. The poorly‐sorted sand samples are less compaction prone than the well‐sorted sand samples. Among well‐sorted sand samples, coarser grained sands are more compressible than finer grained sands. At a given effective stress level, sand–clay mixtures are more compaction prone compared with their sand component alone. Pure sands and clay‐poor sand–clay mixtures (either sand–kaolinite or sand–smectite) show almost the same degree of compaction when tested in both dry and brine‐saturated conditions. In contrast, clay‐rich sand–kaolinite and sand–smectite mixtures (clay volume >20%) are significantly more compact in brine‐saturated condition. The Vp values of brine‐saturated sand–kaolinite mixtures shows a positive correlation with the kaolinite content, whereas Vp starts to decrease substantially when the volume fraction of smectite exceeds 10% of the whole sand–smectite samples.
Saturated bulk moduli estimated by Gassmann's fluid substitution agree with measurements for brine‐saturated clay‐poor sand samples. However, the model does not yield proper predictions for sand–clay samples containing 20% clay volume and above, particularly when the clay is mainly smectite. The acoustic and physical properties derived from experimental compaction of pure sands and sand–clay mixtures show a good agreement with rock properties derived from well logs of mechanically compacted pure sands and shaly sands in progressively subsided basins such as Viking Graben in the North Sea. Thus, the outcome of this study can provide reliable constraints for rock physical properties of sands and shaly sands within the mechanical compaction domain and contribute to improved basin modelling and identification of hydrocarbon presence, overconsolidation, and/or undercompaction.
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Effects of aligned fractures on the response of velocity and attenuation ratios to water saturation variation: a laboratory study using synthetic sandstones
Authors Kelvin Amalokwu, Angus I. Best and Mark ChapmanABSTRACTP‐wave‐to‐S‐wave ratios are important seismic characterization attributes. Velocity ratios are sensitive to the petrophysical properties of rocks and to the presence of gas. Attenuation ratios have also been shown to be sensitive to the presence of partial liquid/gas saturation. The relationship between liquid/gas saturation and P‐wave and S‐wave ratios has been used to distinguish gas‐saturated rocks from liquid‐saturated rocks. Aligned fractures are common in the Earth's crust and cause seismic anisotropy and shear wave splitting. However, most existing relationships between partial gas/liquid saturation and P‐wave and S‐wave ratios are for non‐fractured rocks. We present experimental results comparing the effects of changing water saturation on Qs/Qp versus Vp/Vs ratios between a non‐fractured rock and one containing fractures aligned parallel to wave propagation direction. We also study the effects of aligned fractures on the response of Vp/Vs to changing water saturation using synthetic fractured sandstones with fractures aligned at 45o and parallel to the wave propagation direction. The results suggest that aligned fractures could have significant effects on the observed trends, some of which may not be obvious. Fractures aligned parallel to wave propagation could change the response of Qs/Qp versus Vp/Vs ratios to water saturation from previously reported trends. Shear wave splitting due to the presence of aligned fractures results in two velocity ratios (Vp/Vs1 and Vp/Vs2). The fluid independence of shear wave splitting for fractures aligned parallel to wave propagation direction means the difference between Vp/Vs1 and Vp/Vs2 is independent of water saturation. For fractures aligned at oblique angles, shear wave splitting can be sensitive to water saturation and consequently be frequency dependent, which can lead to fluid and frequency‐dependent differences between Vp/Vs1 and Vp/Vs2. The effect of aligned fractures on Vp/Vs ratios not only depends on the fracture effects on both P‐wave and S‐wave velocities but also on the effects of water saturation distribution on the rock and fracture stiffness, and hence on the P‐wave and S‐wave velocities. As such, these effects can be frequency dependent due to wave‐induced fluid flow. A simple modelling study combining a frequency‐dependent fractured rock model, and a frequency‐dependent partial saturation model was used to gain valuable interpretations of our experimental observations and possible implications, which would be useful for field seismic data interpretation.
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Assessing rock brittleness and fracability from radial variation of elastic wave velocities from borehole acoustic logging
Authors Xiao‐Ming Tang, Song Xu, Chun‐Xi Zhuang, Yuan‐Da Su and Xue‐Lian ChenABSTRACTRock brittleness and fracability of subsurface formations are two important parameters for hydraulic fracturing in hydrocarbon reservoir production. This paper presents an effective technique to assess these parameters using the radial variation of compressional and shear velocities from borehole acoustic logging. Our technique is based on a rock mechanic phenomenon that a brittle rock with high fracability tends to leave a significant amount of drilling‐induced cracks at the borehole wall, resulting in radial elastic wave velocity variation away from borehole. By determining the velocity variation, the combined effects of brittleness and fracability of formation rocks can be assessed. The compressional‐wave travel‐time tomography and flexural shear‐wave inversion methods are respectively used to obtain compressional‐ and shear‐velocity variations. Well‐log data analysis examples demonstrate the practicability and effectiveness of this technique.
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Are changes in time‐lapse seismic data due to fluid substitution or rock dissolution? A CO2 sequestration feasibility study at the Pohokura Field, New Zealand
Authors Cheng Yii Sim and Ludmila AdamABSTRACTSeismic methods are commonly used to monitor the subsurface when carbon dioxide (CO2) is injected into a reservoir. Besides fluid saturation and pressure changes, CO2–water mixtures may cause rock alteration. In this petrophysical study, we compare the elastic property changes due to fluid replacement and those due to mineral dissolution for carbonate‐cemented sandstones at the Pohokura Field, New Zealand. We quantify the effects of fluid substitution from fully brine to fully supercritical CO2 saturation and carbonate cement dissolution on the seismic signatures of the reservoir rocks by combining laboratory results, petrographic analyses, and geophysical well log data. We conclude that elastic property changes due to mineral dissolution are significantly greater than those due to fluid substitution alone. The northern part of the Pohokura Field has coarser‐grained sandstones, which experience the largest changes in wave speeds. Our hypothesis is that these changes result from carbonate cement dissolution in the presence of CO2–water–sandstone reactions. If time‐lapse seismic data were to be acquired in this field, the northern area could show P‐wave velocity reductions of up to 20% and a 131.7% increase in seismic amplitude from a brine‐saturated rock to an altered, fully CO2‐saturated rock. In comparison, the southern part of the field, where sandstones are mostly fine‐grained, we expect a P‐wave velocity decrease of 6% if such dissolution process took place. Finally, we show that the elastic properties of the reservoir rocks can be described with the constant‐cement model. The model is used to predict that the dissolution process reduces the volume of grain contact cement, on average, from 2.5% to 1.75% of the total rock mineral volume. Our analysis suggests that changes to the rock frame, which includes carbonate minerals, cannot be ignored for a CO2 injection scenario.
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Case History: Using time‐lapse vertical seismic profiling data to constrain velocity–saturation relations: the Frio brine pilot CO2 injection
Authors Mohammed Al Hosni, Eva Caspari, Roman Pevzner, Thomas M. Daley and Boris GurevichABSTRACTCO2 sequestration projects benefit from quantitative assessment of saturation distribution and plume extent for field development and leakage prevention. In this work, we carry out quantitative analysis of time‐lapse seismic by using rock physics and seismic modelling tools. We investigate the suitability of Gassmann's equation for a CO2 sequestration project with 1600 tons of CO2 injected into high‐porosity, brine‐saturated sandstone. We analyze the observed time delays and amplitude changes in a time‐lapse vertical seismic profile dataset. Both reflected and transmitted waves are analyzed qualitatively and quantitatively. To interpret the changes obtained from the vertical seismic profile, we perform a 2.5D elastic, finite‐difference modelling study. The results show a P‐wave velocity reduction of 750 m/s in the proximity of the injection well evident by the first arrivals (travel‐time delays and amplitude change) and reflected wave amplitude changes. These results do not match with our rock physics model using Gassmann's equation predictions even when taking uncertainty in CO2 saturation and grain properties into account. We find that time‐lapse vertical seismic profile data integrated with other information (e.g., core and well log) can be used to constrain the velocity–saturation relation and verify the applicability of theoretical models such as Gassmann's equation with considerable certainty. The study shows that possible nonelastic factors are in play after CO2 injection (e.g., CO2–brine–rock interaction and pressure effect) as Gassmann's equation underestimated the velocity reduction in comparison with field data for all three sets of time‐lapse vertical seismic profile attributes. Our work shows the importance of data integration to validate the applicability of theoretical models such as Gassmann's equation for quantitative analysis of time‐lapse seismic data.
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Saturation scale effect on time‐lapse seismic signatures
Authors Qiaomu Qi, Tobias M. Müller and Boris GurevichABSTRACTQuantitative interpretation of time‐lapse seismic signatures aims at assisting reservoir engineering and management operations. Time‐lapse signatures are thought to be primarily induced by saturation and pressure changes. Core‐flooding and reservoir flow simulations indicate that a change of the driving forces during dynamic fluid injection gives rise to a varying saturation scale. This saturation scale is yet another variable controlling the time‐lapse seismic signal. In this work, we investigate the saturation scale effect on time‐lapse seismic signatures by analysing simple modelling scenarios. We consider three characteristic saturation scales, ranging from few millimetres to metres, which may form during gas injection in an unconsolidated water‐saturated reservoir. Using the random patchy saturation model, we compare the corresponding acoustic signatures, i.e., attenuation, reflectivity, and seismic gather associated with each saturation scale. The results show that the millimetre saturation scale produces minimum attenuation and the same seismic signatures with those obtained from the elastic modelling. The centimetre saturation scale produces maximum attenuation, whereas the metre saturation scale causes highest velocity dispersion. The analyses of the time shift and amplitude change indicate that ignoring a time‐dependent saturation scale can result in biased estimation/discrimination of the saturation and the fluid pressure. In particular, the 4D signal can be strongly affected by the saturation‐scale change when the reservoir gas saturation is low and the effective pressure is high. In the presence of an increasing (decreasing) saturation scale during injection, interpreting an observed time shift and amplitude change using the Gassmann model will lead to underestimation (overestimation) of the change in gas saturation and fluid pressure. We show that including the effects of capillarity and residual saturation into the rock physics modelling can potentially reduce the interpretation uncertainty due to the saturation‐scale change.
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Analysis of velocity dispersion using full‐waveform multichannel sonic logging data: A case study
Authors Langqiu F. Sun, Bernd Milkereit and Nicola TisatoABSTRACTSeismic attenuation and velocity dispersion are potentially able to reveal the rock physical properties of the subsurface. Conventionally, a frequency‐independent quality factor (Q) is measured. This Q is equivalent to the total velocity dispersion in a seismic record and is inadequate for analysing the attenuation mechanism or rock physical properties. Here a new method is proposed to extract the velocity dispersion curves so that more attributes can be obtained from full‐waveform multichannel sonic logging data, especially the critical frequency (fc) if it is within the bandwidth of the data. This method first decomposes the seismic data into a series of frequency components, computes the semblance of each frequency component for different velocity values, cross‐correlates the semblance matrices of adjacent frequency components to get the velocity gradients, and finally integrates to obtain a velocity dispersion curve. Results of this method are of satisfactory accuracy and robustness. This method is applied to the data acquired in Mallik 5L‐38 gas hydrate research well in Mackenzie Delta, Northwest Territories, Canada. The observed P‐wave velocity dispersion compares well with the geological setting. In the gas hydrate zone (about 900 m–1100 m), high concentration of gas hydrate causes very strong velocity dispersion and a distinct fc at about 15 kHz, likely due to strong scattering of centimetre‐scale inclusions of gas hydrate; concurrently, water flow in connected cracks in some ranges of this zone adds a large part of velocity dispersion and a dimmer fc at about 9.5 kHz. Immediate underneath the gas hydrate zone, abundant free water in weakly laminated sediments causes quite strong velocity dispersion and an fc at about 6.5 kHz. Velocity dispersion is mild and without an obvious fc in sediments above the gas hydrate zone.
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Attenuation modes from Vertical Seismic Profiling and sonic waveform in a carbonate reservoir, Abu Dhabi, United Arab Emirates
Authors F. Bouchaala, M.Y. Ali and J. MatsushimaABSTRACTIn this study, we derived accurate and high‐resolution attenuation profiles using spectral ratio, centroid frequency shift, and seismic interferometry methods. We utilized high‐quality vertical seismic profiling and sonic waveform data acquired in a carbonate reservoir located in Abu Dhabi, United Arab Emirates. The scattering profile of vertical‐seismic‐profiling data contributes significantly to wave attenuation that can be explained by high heterogeneity of the carbonate rocks. The scattering profile also correlates well with the reservoir lithology and fractured zones imaged by the Formation MicroImager. A tar mat zone occurs within the lower part of Arab D reservoir. This zone corresponds with a decrease in scattering attenuation. The tar mat may have filled the pores and made this zone less heterogeneous. Therefore, a decrease in scattering attenuation can be considered a potential parameter for tar mat detection. After removing the scattering effect, nonphysical negative intrinsic attenuation values still exist at certain depths. The most probable explanation for this is the three‐dimensional scattering effect, which is not taken into account in this paper, and short‐period upgoing waves. Seismic interferometry is less sensitive to the remaining scattered upgoing wave, which is why seismic interferometry method shows fewer negative values than the spectral ratio and centroid frequency shift methods. Compared with vertical‐seismic‐profiling attenuation, scattering attenuation estimated from sonic waveforms recorded in the reservoir zones is insignificant, and the intrinsic attenuation is almost equivalent to the total attenuation. We attribute this underestimation of the scattering attenuation to the sparse spatial sampling of the sonic logging data at 0.1524 m, which is not sufficient to appropriately estimate the scattering effect in heterogeneous media. The cross‐plots between sonic attenuation and various petrophysical properties show slight dependence between the sonic attenuation and neutron porosity and resistivity in the reservoir zones. However, we can highlight from these plots two zones belonging to the Arab reservoirs. The lower zone corresponds to Arab D reservoir and displays higher sonic intrinsic attenuation than the upper zone (Arab A–C reservoirs) due to higher oil saturation. This highlights the sensitivity of the intrinsic attenuation to the oil saturation.
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Theoretical derivation of a Brie‐like fluid mixing law
Authors Giorgos Papageorgiou, Kelvin Amalokwu and Mark ChapmanABSTRACTPrediction of the velocity of acoustic waves in partially saturated rocks is very important in geophysical applications. The need to accurately predict acoustic velocities has resulted in a widespread popularity of Brie's effective fluid mixing law. This empirical model together with Gassmann's formula are used routinely in fluid substitution problems in petroleum geophysics and seismic monitoring of carbon capture and storage. Most attempts to justify Brie's model have been focused on interpretation in terms of patchy saturation models and attaching meaning to the Brie parameter in terms of the patch size. In this paper, using a microstructural description of the rock and a parameter relating to capillary pressure, we calculate an effective fluid modulus that is very similar to Brie's law. The fluid mixing law we propose is independent of frequency and has a solid theoretical foundation. This proposed law produces analytically harmonic and arithmetic averaging at the endpoints. Our results indicate that Brie‐like behaviour may not necessarily be related to frequency‐ and patch‐size‐ dependent phenomena.
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