Two effective methods for calculating water saturations in shale-gas reservoirs

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. D187-D197 ◽  
Author(s):  
Jingling Xu ◽  
Lei Xu ◽  
Yuxing Qin
Keyword(s):  
Shale Gas ◽  
Water Saturation ◽  
Critical Issue ◽  
Petroleum Exploration ◽  
Gas Content ◽  
Gas Reservoirs ◽  
Gas Saturation ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Southeastern Sichuan Basin

Water saturation is one of the most important parameters in petroleum exploration and development. However, its calculation has been limited by the insufficient logging data required by a new technique that further influences the calculation of the free gas content. The accuracy of water saturation estimates is also a critical issue because it controls whether or not we can obtain an accurate gas saturation estimate. Organic matter plays an important role in shale-gas reservoirs, and the total organic carbon (TOC) indirectly controls the gas content and gas saturation. Hence, water saturation is influenced by inorganic and organic components. After analyzing the relationship among TOC, core water saturation, and conventional gas saturation, considering the influence of TOC on gas saturation in organic-rich shale reservoirs, we developed two new methods to improve the accuracy of water saturation estimates: the revised water saturation-TOC method and the water saturation separation method, in which Archie water saturation, modified total shale water saturation, and TOC are integrated. According to case studies of Longmaxi-Wufeng shale, southeastern Sichuan Basin, China, the water saturation results from these two methods in shale reservoirs with different lithologies are consistent with those from core analysis. We concluded that these two methods can be evaluated quickly and they effectively evaluate the water saturation of shale reservoirs.

scholarly journals Prediction of Shale Gas Reservoirs Using Fluid Mobility Attribute Driven by Post-Stack Seismic Data: A Case Study from Southern China

2020 ◽  
Vol 11 (1) ◽  
pp. 219
Author(s):  
Jing Zeng ◽  
Alexey Stovas ◽  
Handong Huang ◽  
Lixia Ren ◽  
Tianlei Tang
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Spectral Decomposition ◽  
Southern China ◽  
Gas Reservoirs ◽  
Seismic Attribute ◽  
Longmaxi Formation ◽  
Shale Gas Reservoirs ◽  
The Sichuan Basin ◽  
Shale Reservoirs

Paleozoic marine shale gas resources in Southern China present broad prospects for exploration and development. However, previous research has mostly focused on the shale in the Sichuan Basin. The research target of this study is expanded to the Lower Silurian Longmaxi shale outside the Sichuan Basin. A prediction scheme of shale gas reservoirs through the frequency-dependent seismic attribute technology is developed to reduce drilling risks of shale gas related to complex geological structure and low exploration level. Extracting frequency-dependent seismic attribute is inseparable from spectral decomposition technology, whereby the matching pursuit algorithm is commonly used. However, frequency interference in MP results in an erroneous time-frequency (TF) spectrum and affects the accuracy of seismic attribute. Firstly, a novel spectral decomposition technology is proposed to minimize the effect of frequency interference by integrating the MP and the ensemble empirical mode decomposition (EEMD). Synthetic and real data tests indicate that the proposed spectral decomposition technology provides a TF spectrum with higher accuracy and resolution than traditional MP. Then, a seismic fluid mobility attribute, extracted from the post-stack seismic data through the proposed spectral decomposition technology, is applied to characterize the shale reservoirs. The application result indicates that the seismic fluid mobility attribute can describe the spatial distribution of shale gas reservoirs well without well control. Based on the seismic fluid mobility attribute section, we have learned that the shale gas enrich areas are located near the bottom of the Longmaxi Formation. The inverted velocity data are also introduced to further verify the reliability of seismic fluid mobility. Finally, the thickness map of gas-bearing shale reservoirs in the Longmaxi Formation is obtained by combining the seismic fluid mobility attribute with the inverted velocity data, and two favorable exploration areas are suggested by analyzing the thickness, structure, and burial depth. The present work can not only be used to evaluate shale gas resources in the early stage of exploration, but also help to design the landing point and trajectory of directional drilling in the development stage.

scholarly journals APPLICATION OF FRACTAL GEOMETRY IN EVALUATION OF EFFECTIVE STIMULATED RESERVOIR VOLUME IN SHALE GAS RESERVOIRS

Fractals ◽  
2017 ◽  
Vol 25 (04) ◽  
pp. 1740007 ◽  
Author(s):  
GUANGLONG SHENG ◽  
YULIANG SU ◽  
WENDONG WANG ◽  
FARZAM JAVADPOUR ◽  
MEIRONG TANG
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Fractal Geometry ◽  
Fracture Network ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Adsorbed Gas ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs

According to hydraulic-fracturing practices conducted in shale reservoirs, effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for confirming the success of hydraulic fracturing and predicting the production of hydraulic fracturing wells in shale reservoirs. However, ESRV calculation remains a longstanding challenge in hydraulic-fracturing operation. In considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), this paper introduces a fractal random-fracture-network algorithm for converting the microseismic data into fractal geometry. Five key parameters, including bifurcation direction, generating length ([Formula: see text]), deviation angle ([Formula: see text]), iteration times ([Formula: see text]) and generating rules, are proposed to quantitatively characterize fracture geometry. Furthermore, we introduce an orthogonal-fractures coupled dual-porosity-media representation elementary volume (REV) flow model to predict the volumetric flux of gas in shale reservoirs. On the basis of the migration of adsorbed gas in porous kerogen of REV with different fracture spaces, an ESRV criterion for shale reservoirs with SRV is proposed. Eventually, combining the ESRV criterion and fractal characteristic of a fracture network, we propose a new approach for evaluating ESRV in shale reservoirs. The approach has been used in the Eagle Ford shale gas reservoir, and results show that the fracture space has a measurable influence on migration of adsorbed gas. The fracture network can contribute to enhancement of the absorbed gas recovery ratio when the fracture space is less than 0.2 m. ESRV is evaluated in this paper, and results indicate that the ESRV accounts for 27.87% of the total SRV in shale gas reservoirs. This work is important and timely for evaluating fracturing effect and predicting production of hydraulic fracturing wells in shale reservoirs.

Numerical Simulation of Shale Gas Production

2011 ◽  
Vol 402 ◽  
pp. 804-807 ◽  
Author(s):  
Song Ru Mu ◽  
Shi Cheng Zhang
Keyword(s):  
Shale Gas ◽  
Simulation Models ◽  
Fracture Network ◽  
Gas Production ◽  
Wire Mesh ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Fracture Mapping

Shale gas reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. The application of microseismic fracture mapping measurements requires estimation of the structure of the complex hydraulic fracture or the volume of the reservoir that has been stimulated by the fracture treatment. There are three primary approaches used to incorporate microseismic measurements into reservoir simulation models: discrete modeling of the complex fracture network, wire-mesh model, and dual porosity model. This paper discuss the different simulation model, the results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.

scholarly journals A new method for calculation of water saturation in shale gas reservoirs usingVP-to-VSratio and porosity

2018 ◽  
Vol 15 (1) ◽  
pp. 224-233 ◽  
Author(s):  
Kun Liu ◽  
Jianmeng Sun ◽  
Hongpan Zhang ◽  
Haitao Liu ◽  
Xiangyang Chen
Keyword(s):  
Shale Gas ◽  
Water Saturation ◽  
New Method ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs

Identification and Applications of Micro to Macroscale Shale Lithofacies

2021 ◽  
Vol 21 (1) ◽  
pp. 659-669
Author(s):  
Shengxiang Long ◽  
Yongmin Peng ◽  
Jing Lu ◽  
Tong Zhu ◽  
Chuanxiang Sun ◽  
...  
Keyword(s):  
Shale Gas ◽  
Gas Content ◽  
Systematic Research ◽  
Upper Ordovician ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Well Drilling ◽  
Reservoir Evaluation ◽  
Rock Types ◽  
Shale Gas Reservoirs

Systematic research and evaluations of shale gas reservoirs are critical in shale gas exploration and development. Previous studies in this field mainly depend on experimental analysis that is often overly simplified. Here, we report an integrated geological and engineering method that combines the lithofacies division system with an identification and evaluation technology from the micro to macroscale. This method has been successfully applied in field sites. The key achievements of this method include the following: 1 Lithofacies refers to the rock or rock assemblage formed in a specific depositional environment that has experienced a certain degree of diagenesis, which is a comprehensive term that contains information about the lithology, physical properties, gas content and fracturability. With the main rock type or several rock types combined as the basic name, the shale lithofacies are classified and named by highlighting particular characteristics such as total organic carbon (TOC) and content of brittle minerals. 2 Based on the lithofacies classification and constrained by the equivalent sequence interfaces or thin layer interfaces, the organic matter-rich shales in the Upper Ordovician Wufeng Formation to the Lower Silurian Longmaxi Formation in the Fuling gas field are longitudinally divided into 7 shale lithofacies. Furthermore, the organic carbonrich, high-silicon lithofacies is identified as the most favorable type for shale gas reservoirs. 3 A set of marine shale lithofacies identification technologies was created using cross-referenced scales of conventional logging and image logging, as well as logging summarization. Lastly, 4 the lithofacies technologies reported here have been successfully applied in multiple areas, including in the south and southeast of the Sichuan Basin and the Pengshui area. Applications in these areas include shale formation comparison and analysis, monitoring and analysis of horizontal well drilling, and assessment of fracturing stages in horizontal sections. The lithofacies technology is proven to be efficient and applicable for comprehensive shale gas reservoir evaluation.

scholarly journals A new method for calculating gas saturation of low-resistivity shale gas reservoirs

2017 ◽  
Vol 4 (5) ◽  
pp. 346-353
Author(s):  
Jinyan Zhang ◽  
Shurong Li ◽  
Libin Wang ◽  
Fang Chen ◽  
Bin Geng
Keyword(s):  
Shale Gas ◽  
New Method ◽  
Gas Reservoirs ◽  
Low Resistivity ◽  
Gas Saturation ◽  
Shale Gas Reservoirs

scholarly journals Application of Dipole Array Acoustic Logging in the Evaluation of Shale Gas Reservoirs

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3882
Author(s):  
Wenrui Shi ◽  
Xingzhi Wang ◽  
Yuanhui Shi ◽  
Aiguo Feng ◽  
Yu Zou ◽  
...  
Keyword(s):  
Shale Gas ◽  
Total Porosity ◽  
P Wave ◽  
S Wave ◽  
Gas Reservoirs ◽  
Acoustic Logging ◽  
Gas Saturation ◽  
Shale Gas Reservoirs ◽  
Gas Potential ◽  
The Relationship

In order to effectively evaluate shale gas reservoirs with low porosity, extra-low permeability, and no natural productivity, dipole array acoustic logging, which can provide various types of information including P-wave slowness (DTC) and S-wave slowness (DTS), is widely used. As the dipole array acoustic logging tool has a larger investigation depth and is suitable for complex borehole environments, such as those with a high wellbore temperature, high drilling fluid column pressure, or irregular borehole wall, it has been mainly applied to the evaluation of lithology, gas potential, fractures, and stimulation potential in shale gas reservoirs. The findings from a case study of the Sichuan Basin in China reveal that the acoustic slowness, S-P wave slowness ratio (RMSC), and S-wave anisotropy of the dipole array acoustic logging can be used to qualitatively identify reservoir lithology, gas potential, and fractures. Using the relationship between DTC and the total porosity of shale gas reservoirs, and combined with the compensated neutron (CNL) and shale content (Vsh) of the reservoir, a mathematical model for accurately calculating the total porosity of the shale gas reservoir can be established. By using the relationship between the RMSC and gas saturation in shale gas reservoirs and tied with density log (DEN), a mathematical model of gas saturation can be established, and the determination of gas saturation by the non-resistivity method can be achieved, delivering a solution to the issue that the electric model is not applicable under low resistivity conditions. The DTS, DTC, and DEN of shale can be used to calculate rock mechanic parameters such as the Poisson’s ratio (POIS) and Young’s modulus (YMOD), which can be used to evaluate the shale stimulation potential.

Novel Analytical Core-Sample Analysis Indicates Higher Gas Content in Shale-Gas Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1397-1408 ◽  
Author(s):  
Seyyed A. Hosseini ◽  
Farzam Javadpour ◽  
G. Eric Michael
Keyword(s):  
Shale Gas ◽  
Coalbed Methane ◽  
Current Data ◽  
Gas Content ◽  
Accurate Estimation ◽  
Gas Evolution ◽  
Gas Reservoirs ◽  
Reservoir Condition ◽  
Core Samples ◽  
Shale Gas Reservoirs

Summary Accurate estimation of gas content in shale-gas reservoirs is challenging. Gas-evolution data from retrieved core samples are used to estimate gas content in shale-gas reservoirs. Current data analysis was developed for coalbed methane (CBM) which only accounts for sorbed gas. The CBM method underestimates gas content for the shale core samples because it neglects free gas in nanopores. In this study, we present a rigorous mathematical model to model temporal gas-volume release from the surrounding and top/bottom surfaces of a nanoporous core. Our model accounts for both gas expansion and desorption. With the model, we first match gas-evolution data to determine average core pressure. Then, we calculate the amount of the free and sorbed gas in the core at reservoir condition. With our novel model, we estimated gas content at reservoir condition in many tested core samples to be much higher than values reported on the basis of traditional analysis.

scholarly journals Experimental Study on the Characteristics of Adsorbed Gas and Gas Production in Shale Formations

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Zhiming Hu ◽  
Xianggang Duan ◽  
Nan Shao ◽  
Yingying Xu ◽  
Jin Chang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Physical Simulation ◽  
Gas Production ◽  
Production Optimization ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
Free Gas ◽  
Adsorbed Gas ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs

Adsorbed gas and free gas both exist in shale reservoirs simultaneously due to the unique nanoscale pore structure, resulting in the complex flow mechanism of gas in the reservoir during the development process. The dynamic performance analysis of shale reservoirs has mostly been conducted by the numerical simulation and theoretical model, while the physical simulation method for relevant research is seen rarely in the literature. Thus, in this paper, an experiment system was designed to simulate the degraded development experiments of shale, coal, and tight sandstone to reveal the output law of gas in different occurrence states of shale reservoirs and clarify the pressure propagation rules of different reservoirs, and then, adsorption gas and free gas production laws were studied by theoretical models. Research indicated the following: (1) The gas occurrence state is the main factor that causes the difference of the pressure drop rate and gas production law of shale, coal, and tight sandstone. During the early stage of the development of shale gas, the free gas is mainly produced; the final contribution of free gas production can reach more than 90%. (2) The static desorption and dynamic experiments confirm that the critical desorption pressure of adsorbed gas is generally between 12 and 15 MPa. When the gas reservoir pressure is lower than the critical desorption pressure in shale and coal formation, desorption occurs. Due to the slow propagation of shale matrix pressure, desorption of adsorbed gas occurs mainly in the low-pressure region close to the fracture surface. (3) The material balance theory of closed gas reservoirs and the one-dimensional flow model of shale gas have subsequently validated the production performance law of adsorbed gas and free gas by the physical simulation. Therefore, in the practical development of shale gas reservoirs, it is recommended to shorten the matrix supply distance, reduce the pressure in the fracture, increase the effective pressure gradient, and enhance the potential utilization of adsorbed gas as soon as possible to increase the ultimate recovery. The findings of this study can help for a better understanding of the shale reservoir utilization law so as to provide a reference for production optimization and development plan formulation of the shale gas reservoirs.

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