Advances in multiscale rock physics for unconventional reservoirs

The multiscale rock physics of unconventional reservoirs have drawn increasing attention in recent years, which involves several essential issues, including measuring method, transport property, physics model, characteristic scale, and their application. These issues vastly affect science and engineering regarding the exploration and development of unconventional reservoirs. To encourage communication on the advances of research on the rock physics of unconventional reservoirs, a conference on Multiscale Rock Physics for Unconventional Reservoirs was jointly organized by the journals Energies and Advances in Geo-Energy Research. Due to the limitations of movement caused by COVID-19, 21 experts introduced their work online, and the conference featured the latest multiscale theories, experimental methods and numerical simulations on unconventional reservoirs.Cited as: Cai, J., Zhao, L., Zhang, F., Wei, W. Advances in multiscale rock physics for unconventional reservoirs. Advances in Geo-Energy Research, 2022, 6(4): 271-275. https://doi.org/10.46690/ager.2022.04.0

Modeling the elastic characteristics of overpressure due to thermal maturation in organic shales

Modeling the overpressure of organic shales caused by thermal maturation and its elastic responses is crucial for geophysical characterization of source rocks and unconventional shale reservoirs. Thermal maturation involves the generation of excess fluid contents (oil and gas) and can cause the overpressure if an organic shale preserves the produced fluids partly or wholly. The solid organic matter (e.g., kerogen or solid bitumen) with the potential of generating hydrocarbon presents two types of morphology in organic shales: scattered patches as pore-fillings and continuous network as load-bearings. According to the kerogen morphology, two bulk volume models are devised to simulate the elasticity of organic shales using respective rock-physics modeling schemes. The rock physics modeling combined with the density and compressibility of pore-fillings are demonstrated to effectively capture the excess pore pressure characteristics due to thermal maturation in organic shales. The basic principle of solving the overpressure is that the pore space volume equals the total volume of all components within the pores before and after the maturation. According to the modeling results, the elastic characteristics of overpressure due to thermal maturation reveal a decrease in velocity and a slight decrease in density. Besides, for an organic shale with a relatively rigid framework, it tends to yield higher overpressure than a shale with a relatively compliant framework. With proper calibration, the modeling strategy shows its potential in quantitatively interpreting the well-log data of organic shale formation within the thermal maturation window.Document Type: Original articleCited as: Qin, X., Zhao, L., Zhu, J., Han, D. Modeling the elastic characteristics of overpressure due to thermal maturation in organic shales. Advances in Geo-Energy Research, 2023, 10(3): 174-188. https://doi.org/10.46690/ager.2023.12.0

Rock physics characteristics of marine sediments in the South China sea: The link between the geological factors and elastic properties

Understanding the geological factors behind the physical and elastic properties of marine sediments and unconsolidated rock is essential for the interpretation of geophysical measurements, hazard assessment, and ocean engineering applications. Core and well logging data from the six drilling sites of the Ocean Drilling Program/International Ocean Discovery Program (ODP/IODP) were used to analyze the rock physical characteristics in the South China sea. The depositional environment plays a significant role in affecting the physical properties of marine sediments. The sediments deposited under shallow water conditions show a higher velocity than the basin, slope, and deeper shelf carbonate deposits. Moreover, the non-depositional hiatus along the Oligocene-Miocene boundary displays a notable control on the variation of rock physical properties. It is found that the lithofacies and physical compaction remarkably influence the elastic characteristics of P-impedance and Vp/Vs ratio. The calcareous-rich sediment and ooze have very low P-impedance and high Vp/Vs ratio, whereas the siltstone and coarse sand present high P-impedance and low Vp/Vs ratio characteristics. With the enhancement of the consolidation degree, the Vp/Vs ratio significantly decreases from 6 to less than 2, suggesting that the shear wave velocity is highly sensitive to physical compactions. The basalt at site U1431 is considerably lower in its P-wave velocity than that at the site of U1433, which is probably caused by the intense fracturing occurring at the site of U1431 associated with different tectonic environments. We establish the link between geological factors and elastic characteristics of marine sediments of SCS, laying the foundation for characterizing depositional environments, lithofacies, and compaction degrees using geophysical measurements

Rock physics based probabilistic lithology and fluid prediction in a heterogeneous carbonate reservoir

Summary The deep-buried Paleozoic marine carbonate reservoirs of Sichuan Basin, SW China, exhibit strong heterogeneities due to complicated diagenetic processes. The goal of our work is to map posterior probabilities of lithology and fluid based on seismic and well observations in this reservoir, thus helping characterize reservoir complexity. Rock physics study gives physical insight on how the elastic properties of different litho-fluid classes can be distinguished. Bayesian linearized AVO inversion results indicate that the posterior distribution of P-wave and Swave velocity are confidently extracted, while the inverted density tends to show high uncertainty due to a lack of wide angle of seismic data. Finally, a full Bayesian approach was implemented to propagate uncertainty from prestack seismic data to assess posterior probabilities of litho-fluid classes in an integrated framework

POROELASTIC AND SEISMIC CHARACTERIZATION OF HETEROGENEOUS RESERVOIR ROCKS

The primary focus of this dissertation is to link the poroelastic model that couples rock’s elastic and hydraulic properties to seismic characterization of the heterogeneous reservoirs. I have presented how to incorporate the dynamic poroelastic responses of microscopic and mesoscopic flow into the classical Biot theory. The resulting effective Biot media can capture the characteristics of velocity dispersion and wave attenuation in heterogeneous media. On the basis of this effective Biot media, I developed an approach to quantify the impact of both global flow and local flow simultaneously on the signatures of seismic reflectivity. The computed poroelastic reflections not only depend on the elastic properties contrast and incident angle, but also rely on the fluid mobility and observational frequency. For a typical shale-sand reflector, we find that the effect of local flow causes reflection amplitude variations in frequency to be as high as 40%, and a maximum phase shift as high as 12 degrees at the seismic exploration frequency band. However, the global flow effect on reflectivity is almost trivial (<1.5%) and occurs mainly at ultrasonic frequency band. Poroelastic seismic analysis shows that ignoring the dispersion behavior of seismic reflection can lead to inaccurate seismic imaging and misleading interpretation of reservoir properties. I further demonstrate that the AVO response at the interface is strongly impacted by the reflection dispersion behavior: the bright spot (Class III AVO) gets brighter at lower frequency, the dim spot (Class I AVO) gets dimmer at lower frequency, and the Class II AVO reservoir exhibits significant phase distortion in the frequency domain. It is found that, for certain permeability ranges (about 2 orders of magnitude), seismic amplitude can exhibit an almost linear relationship with permeability variation. For Class III AVO reservoir scenario, high fluid mobility zones usually enhance the seismic amplitude; while for Class I AVO reservoir scenario, high fluid mobility zones weaken the seismic amplitude. Finally, a field case study on the Offshore Brazil data set shows that poroelastic reflection from the interface of underlain carbonate with overburden marlstone exhibits considerably different frequency behavior at two nearby wells. Based on the poroelastic modeling, this discrepancy is likely to be caused by the fact that the fluid mobility in the underlain grainstone at well A is remarkably greater than that in the underlain packstone at well B.Earth and Atmospheric Sciences, Department o

Current states of well-logging evaluation of deep-sea gas hydrate-bearing sediments by the international scientific ocean drilling (DSDP/ODP/IODP) programs

Since deep-sea gas hydrate-bearing sediments were drilled for the first time in the Blake Ridge in 1970, gas hydrates have been discovered at 53 drill sites in the continental margins of global oceans with international scientific ocean drilling (DSDP/ODP/IODP Programs). As a result, massive amounts of geophysical well-logging data have been accumulated, which provide critical information for understanding the in-situ properties of gas hydrates and their host sediments. Gas hydrates have such physical and chemical properties as non-conductivity, low density, high acoustic velocity, and high hydrogen content, which form the basis of identifying gas hydrate reservoirs and predicting their distribution by well-logging data. A series of well-logging evaluation methods have been proposed to estimate gas hydrate saturation of sediments, including Archie equation, combined methods of density and nuclear magnetic resonance well logging, various forms of three-phase acoustic wave equations, and elastic wave velocity simulations based on different rock physical models. The distribution of gas hydrates is highly heterogeneous, which is mainly manifested in the selectivity of hydrate occurrence to the lithology of host sediments and to the nucleation sites within a host sediment of the same lithology. The scientific-ocean-drilling well logging data have also been preliminarily used for evaluating the heterogeneity of gas hydrate distribution and inferring the growth habit of gas hydrates in host sediments. Nevertheless, there still exist some problems. The formation models used in logging evaluation are in general oversimplified, in which only two or three stratal components are involved. The application of high-resolution logging while-drilling (LWD) data remains limited. Log interpretation is not closely integrated with core geology. Therefore, joint inversion of lithologic components, porosity and gas hydrate saturation based on more complex formation models, together with the applications of high-resolution LWD logging data and core calibration, may represent an important direction in future well-logging evaluation of gas hydrate reservoirs

Geophysical Prospecting

A B S T R A C T This paper discusses and addresses two questions in carbonate reservoir characterization: how to characterize pore-type distribution quantitatively from well observations and seismic data based on geologic understanding of the reservoir and what geological implications stand behind the pore-type distribution in carbonate reservoirs. To answer these questions, three geophysical pore types (reference pores, stiff pores and cracks) are defined to represent the average elastic effective properties of complex pore structures. The variability of elastic properties in carbonates can be quantified using a rock physics scheme associated with different volume fractions of geophysical pore types. We also explore the likely geological processes in carbonates based on the proposed rock physics template. The pore-type inversion result from well log data fits well with the pore geometry revealed by a FMI log and core information. Furthermore, the S-wave prediction based on the pore-type inversion result also shows better agreement than the Greensberg-Castagna relationship, suggesting the potential of this rock physics scheme to characterize the porosity heterogeneity in carbonate reservoirs. We also apply an inversion technique to quantitatively map the geophysical pore-type distribution from a 2D seismic data set in a carbonate reservoir offshore Brazil. The spatial distributions of the geophysical pore type contain clues about the geological history that overprinted these rocks. Therefore, we analyse how the likely geological processes redistribute pore space of the reservoir rock from the initial depositional porosity and in turn how they impact the reservoir quality. Key words: Carbonates, Pore type, Dolomitization. I N T R O D U C T I O N Carbonate rocks are considered a major host rock for hydrocarbon reservoirs, making up almost 60% of the world&apos;s proven reserves. They significantly differ from siliciclastic reservoirs because of their different depositional environments and complicated diagenetic processes One of the main challenges of quantitative reservoir characterization in carbonates lies in identifying producible, economic reserves and distinguishing them from low recoverable reserves. Insights into producibility can be gained from permeability prediction, which is strongly related to the complex pore structures mentioned earlie

Geophysical pore type inversion in carbonate reservoir: Integration ofcores, well logs, and seismic data (Yadana field, offshore Myanmar)

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