Rock physics analysis and time-lapse rock imaging of geochemical effects due to the injection of CO2 into reservoir rocks

Geophysics ◽  
2011 ◽  
Vol 76 (5) ◽  
pp. O23-O33 ◽  
Author(s):  
Tiziana Vanorio ◽  
Amos Nur ◽  
Yael Ebert
Keyword(s):  
Seismic Velocity ◽  
Fluid Pressure ◽  
Rock Physics ◽  
Time Lapse ◽  
Seismic Monitoring ◽  
Physical Parameters ◽  
Salt Precipitation ◽  
S Wave ◽  
Seismic Properties ◽  
Small Pore

The fundamental concept of time-lapse seismic monitoring is that changes in physical parameters—such as saturation, pore fluid pressure, temperature, and stress—affect rock and fluid properties, which in turn alter the seismic velocity and density. Increasingly, however, time-lapse seismic monitoring is called upon to quantify subsurface changes due in part to chemical reactions between injected fluids and the host rocks. This study springs from a series of laboratory experiments and high-resolution images assessing the changes in microstructure, transport, and seismic properties of fluid-saturated sandstones and carbonates injected with [Formula: see text]. Results show that injecting [Formula: see text] into a brine-rock system induces chemo-mechanical mechanisms that permanently change the rock frame. Injecting [Formula: see text] into brine-saturated-sandstones induces salt precipitation primarily at grain contacts and within small pore throats. In rocks with porosity lower than 10%, salt precipitation reduces permeability and increases P- and S-wave velocities of the dry rock frame. On the other hand, injecting [Formula: see text]-rich water into micritic carbonates induces dissolution of the microcrystalline matrix, leading to porosity enhancement and chemo-mechanical compaction under pressure. In this situation, the elastic moduli of the dry rock frame decrease. The results in these two scenarios illustrate that the time-lapse seismic response of chemically stimulated systems cannot be modeled as a pure fluid-substitution problem. A first set of empirical relationships links the time-variant effects of injection to the elastic properties of the rock frame using laboratory velocity measurements and advanced imaging.

Reciprocal velocity-porosity general linear form provides consistent and systematic industry-wide applications

2019 ◽  
Vol 7 (4) ◽  
pp. T751-T759
Author(s):  
Killian Ikwuakor
Keyword(s):  
Linear Form ◽  
Oil And Gas ◽  
Rock Physics ◽  
Time Lapse ◽  
General Linear ◽  
S Wave ◽  
Rock Property ◽  
Formation Evaluation ◽  
Clastic Rocks ◽  
Universal Applicability

Velocity is an important rock property that is required and used in different applications in petrophysics, rock physics, and seismic. The published literature shows a plethora of equations and models that relate velocity and porosity, a critical reservoir property. Attempts to account for the presence of shale in the formation invariably lead to more complicated relations. The inability of the industry to streamline these relations handicaps advancements in rock physics and formation evaluation, complicates the application of best practices in time-lapse seismic and fluid substitutions, and jeopardizes the integration of petrophysical, geologic, and seismic characteristics of oil and gas reservoirs. I have considered the following criteria to grade some of the different velocity-porosity relations in use today: (1) the significance of effective stress, (2) usefulness for interpreting geology, (3) predictive capability, and (4) universal applicability. Judging by these criteria, the general linear form, first prescribed by the late George R. Pickett, is the clear winner. The general linear form is a linear relationship between the reciprocal velocity and porosity. It passes theoretical and empirical justification. It is also valid for P- and S-wave velocities, yields easily to mathematical manipulation, and satisfies carbonate as well as clastic rocks for porosities encountered in everyday subsurface investigations. I evaluate practical examples in which the general linear form is the basis for multiple rock-typing criteria, comparative formation evaluation, and interpretive use of the [Formula: see text] ratio. Appropriate integration of the general linear form with other rock property relations provides avenues to redefine the [Formula: see text] ratio and acoustic impedance, and it expands the understanding and applications of reservoir elastic properties, as well as it constrains and streamlines rock physics models and applications.

ROCK PHYSICS—APPLICATION TO GEOLOGICAL STORAGE OF CO2

2003 ◽  
Vol 43 (1) ◽  
pp. 567 ◽  
Author(s):  
J.J. McKenna ◽  
B. Gurevich ◽  
M. Urosevic ◽  
B.J. Evans
Keyword(s):  
Elastic Moduli ◽  
Co2 Storage ◽  
Rock Physics ◽  
Sedimentary Basins ◽  
Time Lapse ◽  
Seismic Monitoring ◽  
Potential Contribution ◽  
Underground Brine ◽  
Shear Moduli ◽  
Borehole Seismic

Sequestration of anthropogenic CO2 into underground brine-saturated reservoirs is an immediate option for Australia to reduce CO2 emissions into the atmosphere. Many sites for CO2 storage have been defined within many Australian sedimentary basins. It is anticipated that seismic technology will form the foundation for monitoring CO2 storage within the subsurface, although it is recognised that several other technologies will also be used in support of seismic or in situations where seismic recording is not suitable. The success of seismic monitoring will be determined by the magnitude of the change in the elastic properties of the reservoir during the lifecycle of CO2 storage. In the short-term, there will be a strong contrast in density and compressibility between free CO2 and brine. The contrast between these fluids is greater at shallower depth and higher temperature where CO2 resembles a vapour. The significant change in the elastic moduli of the reservoir will enable time-lapse seismic methods to readily monitor structural or hydrodynamic trapping of CO2 below an impermeable seal. Because the acoustic contrast between brine saturated with CO2 and brine containing no dissolved CO2 is very slight, however, dissolved CO2 is unlikely to be detected by any seismic technology, including high-resolution borehole seismic. The detection of increases in porosity, associated with dissolution of susceptible minerals within the reservoir may provide a means for qualitative monitoring of CO2 dissolution. Conversion of aqueous CO2 into carbonate minerals should cause a detectable rise in the elastic moduli of the rock frame, especially the shear moduli. The magnitude of this rise increases with depth and demonstrates the potential contribution that can be made from repeated shear-wave and multi-component seismic measurements. Forward modelling suggests that the optimal reservoir depth for seismic monitoring of CO2 storage within an unconsolidated reservoir is between 1,000 and 2,500 m. Higher reservoir temperature is also preferred so that free CO2 will resemble a vapour.

scholarly journals 4D Travel-Time Tomography as a Tool for Tracking Fluid-Driven Medium Changes in Offshore Oil–Gas Exploitation Areas

Energies ◽  
2020 ◽  
Vol 13 (22) ◽  
pp. 5878
Author(s):  
Grazia De Landro ◽  
Ortensia Amoroso ◽  
Guido Russo ◽  
Aldo Zollo
Keyword(s):  
Seismic Velocity ◽  
Fluid Pressure ◽  
Time Lapse ◽  
Velocity Model ◽  
Target Volume ◽  
Fluid Injection ◽  
Pressure Perturbation ◽  
Operational Conditions ◽  
Starting Point ◽  
Velocity Changes

The monitoring of rock volume where offshore exploitation activities take place is crucial to assess the corresponding seismic hazard. Fluid injection/extraction operations generate a pore fluid pressure perturbation into the volume hosting the reservoir which, in turn, may trigger new failures and induce changes in the elastic properties of rocks. Our purpose is to evaluate the feasibility of reconstructing pore pressure perturbation diffusion in the host medium by imaging the 4D velocity changes using active seismic. We simulated repeated active offshore surveys and imaged the target volume. We constructed the velocity model perturbed by the fluid injection using physical modeling and evaluated under which conditions the repeated surveys could image the velocity changes. We found that the induced pressure perturbation causes seismic velocity variations ranging between 2–5% and 15–20%, depending on the different injection conditions and medium properties. So, in most cases, time-lapse tomography is very efficient in tracking the perturbation. The noise level characterizing the recording station sites is a crucial parameter. Since we evaluated the feasibility of the proposed 4D imaging strategy under different realistic environmental and operational conditions, our results can be directly applied to set up and configure the acquisition layout of surveys aimed at retrieving fluid-induced medium changes in the hosting medium. Moreover, our results can be considered as a useful starting point to design the guidelines to monitor exploitation areas.

Recent advances in rock physics

Geophysics ◽  
1985 ◽  
Vol 50 (12) ◽  
pp. 2480-2491 ◽  
Author(s):  
David P. Yale
Keyword(s):  
Electrical Properties ◽  
Seismic Waves ◽  
Seismic Velocity ◽  
Pore Space ◽  
Rock Physics ◽  
Rock Properties ◽  
Bright Spot ◽  
Geometrical Parameters ◽  
S Wave ◽  
Velocity Models

The need to extract more information about the subsurface from geophysical and petrophysical measurements has led to a great interest in the study of the effect of rock and fluid properties on geophysical and petrophysical measurements. Rock physics research in the last few years has been concerned with studying the effect of lithology, fluids, pore geometry, and fractures on velocity; the mechanisms of attenuation of seismic waves; the effect of anisotropy; and the electrical and dielectric properties of rocks. Understanding the interrelationships between rock properties and their expression in geophysical and petrophysical data is necessary to integrate geophysical, petrophysical, and engineering data for the enhanced exploration and characterization of petroleum reservoirs. The use of amplitude offsets, S‐wave seismic data, and full‐waveform sonic data will help in the discrimination of lithology. The effect of in situ temperatures and pressures must be taken into account, especially in fractured and unconsolidated reservoirs. Fluids have a strong effect on seismic velocities, through their compressibility, density, and chemical effects on grain and clay surfaces. S‐wave measurements should help in bright spot analysis for gas reservoirs, but theoretical considerations still show that a deep, consolidated reservoir will not have any appreciable impedance contrast due to gas. The attenuation of seismic waves has received a great deal of attention recently. The idea that Q is independent of frequency has been challenged by experimental and theoretical findings of large peaks in attenuation in the low kHz and hundreds of kHz regions. The attenuation is thought to be due to fluid‐flow mechanisms and theories suggest that there may be large attenuation due to small amounts of gas in the pore space even at seismic frequencies. Models of the effect of pores, cracks, and fractures on seismic velocity have also been studied. The thin‐crack velocity models appear to be better suited for representing fractures than pores. The anisotropy of seismic waves, especially the splitting of polarized S‐waves, may be diagnostic of sets of oriented fractures in the crust. The electrical properties of rocks are strongly dependent upon the frequency of the energy and logging is presently being done at various frequencies. The effects of frequency, fluid salinity, clays, and pore‐grain geometry on electrical properties have been studied. Models of porous media have been used extensively to study the electrical and elastic properties of rocks. There has been great interest in extracting geometrical parameters about the rock and pore space directly from microscopic observation. Other models have focused on modeling several different properties to find relationships between rock properties.

scholarly journals Effect of grain-scale gas patches on the seismic properties of double porosity rocks

2016 ◽  
Vol 208 (1) ◽  
pp. 432-436 ◽  
Author(s):  
Stanislav Glubokovskikh ◽  
Boris Gurevich
Keyword(s):  
High Frequency ◽  
Low Frequency ◽  
Rock Physics ◽  
Time Lapse ◽  
Double Porosity ◽  
Ultrasonic Velocities ◽  
Seismic Properties ◽  
Partially Saturated ◽  
Frequency Regime ◽  
Wave Induced

Time-lapse ultrasonic measurements constitute a tool to establish and calibrate rock physics models for surface seismic monitoring of partially saturated rocks. This workflow requires one to take into account seismic dispersion caused by frequency-dependent wave-induced fluid flow. We develop a theory of squirt flow in rocks saturated with a viscoelastic material containing isolated gas patches between compliant intergranular contacts. This model is valid for the entire frequency range, from seismic to ultrasonic. In the limit of full saturation the derived equations reduce to the Gassmann equations in the low-frequency regime and traditional squirt theory in the high-frequency regime. The model prediction of ultrasonic velocities versus saturation matches with experimental observations.

Acoustic velocity and permeability of acidized and propped fractures in shale

Geophysics ◽  
2021 ◽  
pp. 1-55
Author(s):  
Jihui Ding ◽  
Anthony C. Clark ◽  
Tiziana Vanorio ◽  
Adam D. Jew ◽  
John R. Bargar
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracturing ◽  
Seismic Velocity ◽  
Rock Physics ◽  
Elastic Stiffness ◽  
Acoustic Velocity ◽  
S Wave ◽  
Fracture Permeability ◽  
Mechanical Fracture ◽  
Flow Pathways

From geochemical reactions to proppant emplacement, hydraulic fracturing induces various chemo-mechanical fracture alterations in shale reservoirs. Hydraulic fracturing through the injection of a vast amount and variety of fluids and proppants has substantial impacts on fluid flow and hydrocarbon production. There is a strong need to improve our understanding on how fracture alterations affect flow pathways within the stimulated rock volume and develop monitoring tools. We conducted time-lapse rock physics experiments on clay-rich (carbonate-poor) Marcellus shales to characterize the acoustic velocity and permeability responses to fracture acidizing and propping. Acoustic P- and S-wave velocities and fracture permeability were measured before and after laboratory-induced fracture alterations along with microstructural imaging through X-ray computed tomography and scanning electron microscopy. Our experiments show that S-wave velocity is an important geophysical observable, particularly the S-wave polarized perpendicular to fractures since it is sensitive to fracture stiffness. The acidizing and propping of a fracture both decrease its elastic stiffness. This effect is stronger for acidizing, and so it is possible that proppant monitoring will be masked by chemical alteration except when propping is highly efficient (i.e., most fractures are propped). However, fracture permeability is undermined by the softening of fracture surfaces due to acidizing, while greatly enhanced by propping. These contrasting effects on fluid flow in combination with similar seismic attributes indicate the importance of experiments to improve existing rock physics models, which must include changes to the rock frame. Such improvements are necessary for a correct interpretation of seismic velocity monitoring of flow pathways in stimulated shales.

Fluid-pressure discrimination in anisotropic reservoir rocks — A sensitivity study

Geophysics ◽  
2005 ◽  
Vol 70 (3) ◽  
pp. O1-O11 ◽  
Author(s):  
Alexey Stovas ◽  
Martin Landrø
Keyword(s):  
Pore Pressure ◽  
Seismic Data ◽  
Seismic Anisotropy ◽  
Fluid Pressure ◽  
Rock Physics ◽  
Time Lapse ◽  
Reservoir Rock ◽  
Sand Layer ◽  
Weak Anisotropy ◽  
Fluid Saturation

We investigate how seismic anisotropy influences our ability to distinguish between various production-related effects from time-lapse seismic data. Based on rock physics models and ultrasonic core measurements, we estimate variations in PP and PS reflectivity at the top reservoir interface for fluid saturation and pore pressure changes. The tested scenarios include isotropic shale, weak anisotropic shale, and highly anisotropic shale layers overlaying either an isotropic reservoir sand layer or a weak anisotropic sand layer. We find that, for transverse isotropic media with a vertical symmetry axis (TIV), the effect of weak anisotropy in the cap rock does not lead to significant errors in, for instance, the simultaneous determination of pore-pressure and fluid-saturation changes. On the other hand, changes in seismic anisotropy within the reservoir rock (caused by, for instance, increased fracturing) might be detectable from time-lapse seismic data. A new method using exact expressions for PP and PS reflectivity, including TIV anisotropy, is used to determine pressure and saturation changes over production time. This method is assumed to be more accurate than previous methods.

AVO attribute inversion for finely layered reservoirs

Geophysics ◽  
2006 ◽  
Vol 71 (3) ◽  
pp. C25-C36 ◽  
Author(s):  
Alexey Stovas ◽  
Martin Landrø ◽  
Per Avseth
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Time Lapse ◽  
Oil Saturation ◽  
Seismic Properties ◽  
Seismic Input ◽  
Fluid Properties ◽  
Random Variability ◽  
Net To Gross ◽  
Avo Attributes

Assuming that a turbidite reservoir can be approximated by a stack of thin shale-sand layers, we use standard amplitude variaiton with offset (AVO) attributes to estimate net-to-gross (N/G) and oil saturation. Necessary input is Gassmann rock-physics properties for sand and shale, as well as the fluid properties for hydrocarbons. Required seismic input is AVO intercept and gradient. The method is based upon thin-layer reflectivity modeling. It is shown that random variability in thickness and seismic properties of the thin sand and shale layers does not change significantly the AVO attributes at the top and base of the turbidite-reservoir sequence. The method is tested on seismic data from offshore Brazil. The results show reasonable agreement between estimated and observed N/G and oil saturation. The methodology can be developed further for estimating changes in pay thickness from time-lapse seismic data.

scholarly journals TIME-LAPSE POROSITY AND VELOCITY ANALYSIS USING ROCK PHYSICS MODELS IN NIGER DELTA, NIGERIA

2021 ◽  
Vol 5 (2) ◽  
pp. 47-52
Author(s):  
Emmanuel Aniwetalu ◽  
Akudo Ernest ◽  
Juliet Ilechukwu ◽  
Okechukwu Ikegwuonu ◽  
Uzochukwu Omoja
Keyword(s):  
Oil And Gas ◽  
Seismic Velocity ◽  
Water Saturation ◽  
Rock Physics ◽  
Time Lapse ◽  
Fluid Substitution ◽  
Average Value ◽  
Velocity Models ◽  
Fluid Properties ◽  
Average Water

The analysis of 3-D and time-lapse seismic data in Isomu Field has offered the dynamic characterization of the reservoir changes. The changes were analyzed using fluid substitution and seismic velocity models. The results of the initial porosity of the reservoirs was 29.50% with water saturation value of12%.The oil and gas maintained saturation values of 40% and 48% with average compressional and shear wave velocities of 2905m/s and 1634m/s respectfully. However, in fluid substitution modelling, the results reflect a change in fluid properties where average gas and oil saturation assume a new status of 34% and 24% which indicates a decrease by 14% and 16% respectively. The average water saturation increases by 30% with an average value of 42%. The decrease in hydrocarbon saturation and increase in formation water influence the porosity. Thus, porosity decreased by 4.16% which probably arose from the closure of the aspect ratio crack due to pressure increase.

scholarly journals Using onset times from frequent seismic surveys to understand fluid flow at the Peace River Field, Canada

2020 ◽  
Vol 223 (3) ◽  
pp. 1610-1629
Author(s):  
Gil Hetz ◽  
Akhil Datta-Gupta ◽  
Justyna K Przybysz-Jarnut ◽  
Jorge L Lopez ◽  
D W Vasco
Keyword(s):  
Initial Conditions ◽  
Saturation Pressure ◽  
Substantial Reduction ◽  
Fluid Pressure ◽  
Saturation Temperature ◽  
Rock Physics ◽  
Time Lapse ◽  
Peace River ◽  
Physics Model ◽  
Rock Physics Model

SUMMARY Our limited knowledge of the relationship between changes in the state of an aquifer or reservoir and the corresponding changes in the elastic moduli, that is the rock physics model, hampers the effective use of time-lapse seismic observations for estimating flow properties within the Earth. A central problem is the complicated dependence of the magnitude of time-lapse changes on the saturation, pressure, and temperature changes within an aquifer or reservoir. We describe an inversion methodology for reservoir characterization that uses onset times, the calendar time of the change in seismic attributes, rather than the magnitude of the changes. We find that onset times are much less sensitive than magnitudes to the rock physics model used to relate time-lapse observations to changes in saturation, temperature and fluid pressure. We apply the inversion scheme to observations from daily monitoring of enhanced oil recovery at the Peace River field in Canada. An array of 1492 buried hydrophones record seismic signals from 49 buried sources. Time-shifts for elastic waves traversing the reservoir are extracted from the daily time-lapse cubes. In our analysis 175 images of time-shifts are transformed into a single map of onset times, leading to a substantial reduction in the volume of data. These observations are used in conjunction with bottom hole pressure data to infer the initial conditions prior to the injection, and to update the reservoir permeability model. The combination of a global and local inversion scheme produces a collection of reservoir models that are best described by three clusters. The updated model leads to a nearly 70 percent reduction in seismic data misfit. The final set of solutions successfully predict the observed normalized pressure history during the soak and flow-back into the wells between 82 and 175 days into the cyclic steaming operation.

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