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20 pages, 17296 KiB

Open AccessArticle

Pre-Stack Fracture Prediction in an Unconventional Carbonate Reservoir: A Case Study of the M Oilfield in Tarim Basin, NW China

by Bo Liu, Fengying Yang, Guangzhi Zhang and Longfei Zhao

Energies 2024, 17(9), 2061; https://doi.org/10.3390/en17092061 - 26 Apr 2024

Viewed by 818

Abstract

The reservoir of the M oilfield in Tarim Basin is an unconventional fracture-cave carbonate rock, encompassing various reservoir types like fractured, fracture-cave, and cave, exhibiting significant spatial heterogeneity. Despite the limited pore space in fractures, they can serve as seepage pathways, complicating the [...] Read more.

The reservoir of the M oilfield in Tarim Basin is an unconventional fracture-cave carbonate rock, encompassing various reservoir types like fractured, fracture-cave, and cave, exhibiting significant spatial heterogeneity. Despite the limited pore space in fractures, they can serve as seepage pathways, complicating the connectivity between reservoirs. High-precision fracture prediction is critical for the effective development of these reservoirs. The conventional post-stack seismic attribute-based approach, however, is limited in its ability to detect small-scale fractures. To address this limitation, a novel pre-stack fracture prediction method based on azimuthal Young’s modulus ellipse fitting is introduced. Offset Vector Tile (OVT) gather is utilized, providing comprehensive information on azimuth and offset. Through analyzing azimuthal anisotropies, such as travel time, amplitude, and elastic parameters, smaller-scale fractures can be detected. First, the original OVT gather data are preprocessed to enhance the signal-to-noise ratio. Subsequently, these data are partially stacked based on different azimuths and offsets. On this basis, pre-stack inversion is carried out for each azimuth to obtain the Young’s modulus in each direction, and, finally, the ellipse fitting algorithm is used to obtain the orientation of the long axis of the ellipse and the ellipticity, indicating the fracture orientation and density, respectively. The fracture prediction results are consistent with the geological structural features and fault development patterns of the block, demonstrating good agreement with the imaging logging interpretations. Furthermore, the results align with the production dynamics observed in the production wells within the block. This alignment confirms the high accuracy of the method and underscores its significance in providing a robust foundation for reservoir connectivity studies and well deployment decisions in this region. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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16 pages, 7635 KiB

Open AccessArticle

Current Status of Helium Resource Research and Prediction of Favorable Areas for Helium Reservoir in China

by Ye Xiong, Shan Jiang, Jingjing Yi and Yi Ding

Energies 2024, 17(7), 1530; https://doi.org/10.3390/en17071530 - 22 Mar 2024

Viewed by 1109

Abstract

As an unconventional oil and gas reservoir, helium gas reservoirs have gradually become a focus of attention. In recent years, with the continuous increase in demand for helium gas, the uneven distribution of global helium resources has attracted China’s attention to helium resources. [...] Read more.

As an unconventional oil and gas reservoir, helium gas reservoirs have gradually become a focus of attention. In recent years, with the continuous increase in demand for helium gas, the uneven distribution of global helium resources has attracted China’s attention to helium resources. In this study, a method for predicting favorable areas of helium gas was proposed based on the natural gas exploration theory and the idea of “finding gas in enrichment areas”. We conducted an in-depth study and analysis of the types of helium gas formations in China by comprehensively using geochemical and isotope-testing data, identifying the distribution of helium source rocks in China. Based on this, we conducted directed analyses of the transport channels and caprock conditions for helium gas, and summarized the enrichment modes of helium gas. Using this method, we predicted five favorable areas for the enrichment of helium gas in China, providing an important basis for the future exploration and development of helium resources in China. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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19 pages, 9228 KiB

Open AccessArticle

Heterogeneity of a Sandy Conglomerate Reservoir in Qie12 Block, Qaidam Basin, Northwest China and Its Influence on Remaining Oil Distribution

by Qingshun Gong, Zhanguo Liu, Chao Zhu, Bo Wang, Yijie Jin, Zhenghao Shi, Lin Xie and Jin Wu

Energies 2023, 16(7), 2972; https://doi.org/10.3390/en16072972 - 24 Mar 2023

Cited by 2 | Viewed by 1618

Abstract

In view of the key geological factors restricting reservoir development, the reservoir heterogeneity of an alluvial fan sandy conglomerate reservoir in the Qie12 block of Qaidam Basin, Northwest China, and its influence on remaining oil distribution, were studied according to geology, wireline logging [...] Read more.

In view of the key geological factors restricting reservoir development, the reservoir heterogeneity of an alluvial fan sandy conglomerate reservoir in the Qie12 block of Qaidam Basin, Northwest China, and its influence on remaining oil distribution, were studied according to geology, wireline logging data, and dynamic production data. This study illustrates that the difference in pore structures, which are controlled by different sedimentary fabrics, is the main cause of reservoir microscopic heterogeneity. Besides, the temporal and spatial distribution of architectural units in the alluvial fan controls reservoir macroheterogeneity. Our results show that the thick sandy conglomerate develops two types of pores, two types of permeability rhythms, two types of interlayers, two types of interlayer distribution, two types of effective sand body architecture, and four types of sand body connecting schemes. The strongest plane heterogeneity is found in the composite channel unit formed by overlapping and separated stable channels of the middle fan, and the unit’s permeability variation coefficient is >0.7. However, the variation coefficient in the range of 0.3–0.5 is found in the extensively connected body unit sandwiched with intermittent channels of the inner fan. The distributions of the remaining oil vary significantly in different architectural units because of the influence of reservoir heterogeneity, including distribution patterns of flow barriers, permeability rhythm, and reservoir pore structures. The composite channel unit formed by overlapping and separated stable channels, or the lateral alternated unit with braided channel and sheet flow sediment of the middle fan, is influenced by the inhomogeneous breakthrough of injection water flowing along the dominant channel in a high-permeability layer. The microscopic surrounding flow and island-shaped remaining oils form and concentrate mainly in the upper part of a compound rhythmic layer. Meanwhile, in the extensively connected body unit sandwiched with intermittent channels of the inner fan, poor injector–producer connectivity and low reservoir permeability lead to a flake-like enrichment of the remaining oil. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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19 pages, 4220 KiB

Open AccessArticle

Effects of Inorganic Minerals and Kerogen on the Adsorption of Crude Oil in Shale

by Yanyan Zhang, Shuifu Li, Shouzhi Hu and Changran Zhou

Energies 2023, 16(5), 2386; https://doi.org/10.3390/en16052386 - 2 Mar 2023

Cited by 1 | Viewed by 1955

Abstract

Shale oil stored in the shale system occurs mainly in adsorbed and free states, and ascertaining the amount of adsorbed crude oil in shale is a method of ascertaining its free oil content, which determines the accuracy of shale oil resource evaluation. Both [...] Read more.

Shale oil stored in the shale system occurs mainly in adsorbed and free states, and ascertaining the amount of adsorbed crude oil in shale is a method of ascertaining its free oil content, which determines the accuracy of shale oil resource evaluation. Both inorganic minerals and kerogen have the ability to adsorb crude oil, but there is controversy surrounding which plays the greatest part in doing so; clarifying this would be of great significance to shale oil resource evaluation. Therefore, in this study, the evolution states of inorganic minerals and kerogen in shale were changed using pyrolysis, and the adsorbents were prepared for crude oil adsorption experiments, to explore the effects of inorganic minerals and kerogen on the crude oil adsorption of shale. The results showed that the differences in kerogen’s structural units and content in organic-rich shale (TOC = 1.60–4.52%) had no obvious effects on its crude oil adsorption properties. On the contrary, inorganic minerals, as the main body of shale, played a dominant role in the adsorption of crude oil. The composition and evolution of the inorganic minerals controlled the surface properties of shale adsorbents, which is the main reason for the different crude oil adsorption properties of the different types of adsorbents. The results of this study are helpful in improving our understanding of the performance and mechanisms of shale in adsorbing crude oil and promoting the development of shale oil resource evaluation. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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12 pages, 3977 KiB

Open AccessArticle

Thin Reservoir Identification Based on Logging Interpretation by Using the Support Vector Machine Method

by Xinmao Zhou, Yawen Li, Xiaodong Song, Lingxuan Jin and Xixin Wang

Energies 2023, 16(4), 1638; https://doi.org/10.3390/en16041638 - 7 Feb 2023

Cited by 4 | Viewed by 1714

Abstract

A reservoir with a thickness less than 0.5 m is generally considered to be a thin reservoir, in which it is difficult to directly identify oil-water layers with conventional logging data, and the identify result coincidence rate is low. Therefore, a support vector [...] Read more.

A reservoir with a thickness less than 0.5 m is generally considered to be a thin reservoir, in which it is difficult to directly identify oil-water layers with conventional logging data, and the identify result coincidence rate is low. Therefore, a support vector machine method (SVM) is introduced in the field of oil-water-dry layer identification. The basic approach is to map the nonlinear problem (input space) to a new high-dimensional feature space through the introduction of a kernel function, and then construct the optimal decision surface in the high-dimensional feature space and conduct sample classification. There are plenty of thin reservoirs in Wangguantun oilfield. Therefore, 63 samples are established by integrating general logging data and oil testing data from the study area, including 42 learning samples and 21 prediction samples, which are normalized. Then, the kernel function is selected, based on previous experience, and the fluid identification model of the thin reservoir is built. The model is used to identify 21 prediction samples; 18 are correct, and the prediction accuracy reaches 85.7%. The results show that the SVM method is feasible for fluid identification in thin reservoirs. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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20 pages, 40470 KiB

Open AccessArticle

Along-Strike Reservoir Development of Steep-Slope Depositional Systems: Case Study from Liushagang Formation in the Weixinan Sag, Beibuwan Basin, South China Sea

by Sheng Liu, Hongtao Zhu, Qianghu Liu, Ziqiang Zhou and Jiahao Chen

Energies 2023, 16(2), 804; https://doi.org/10.3390/en16020804 - 10 Jan 2023

Viewed by 1817

Abstract

Seismic, core, drilling, logging, and thin-section data are considered to analyze the reservoir diversity in the east, middle, and west fan of the Liushagang Formation in the steep-slope zone of the Weixinan Sag, Beibuwan Basin. Three factors primarily affect the reservoir differences for [...] Read more.

Seismic, core, drilling, logging, and thin-section data are considered to analyze the reservoir diversity in the east, middle, and west fan of the Liushagang Formation in the steep-slope zone of the Weixinan Sag, Beibuwan Basin. Three factors primarily affect the reservoir differences for steep-slope systems: (1) Sedimentary factors mostly control reservoir scales and characteristics and the drainage system and microfacies. Massive high-quality reservoirs have shallow burial depths. Channel development and sediment supply favor the formation of these reservoirs. The sedimentary microfacies suggest fan delta plain distributary channels. (2) Lithofacies factors primarily control reservoir types and evolution. The diagenesis of high-quality reservoirs is weak, and a weak compaction–cementation diagenetic facies and medium compaction–dissolution diagenetic facies were developed. (3) Sandstone thickness factors primarily control the oil-bearing properties of reservoirs. The average porosity and permeability of high-quality reservoirs are large, the critical sandstone thickness is small, the average sandstone thickness is large, and the oil-bearing capacity is high. Furthermore, the reservoir prediction models are summarized as fan delta and nearshore subaqueous fan models. The high-quality reservoir of the fan delta model is in the fan delta plain, and the lithology is medium–coarse sandstone. The organic acid + meteoric freshwater two-stage dissolution is developed, various dissolved pores are formed, and a Type I reservoir is developed. The high-quality reservoir of the nearshore subaqueous fan model is in the middle fan, and the lithology is primarily medium–fine sandstone. Only organic acid dissolution, dissolution pores, and Type I–II reservoirs are developed. Regarding reservoir differences and models, the high-quality reservoir of the steep-slope system is shallow and large-scale, and the reservoir is a fan delta plain distributary channel microfacies. Weak diagenetic evolution, good physical properties, thick sandstone, and good oil-bearing properties developed a Type I reservoir. The study of reservoir control factors of the northern steep-slope zone was undertaken in order to guide high-quality reservoir predictions. Further, it provides a reference for high-quality reservoir distribution and a prediction model for the steep-slope system. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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16 pages, 8938 KiB

Open AccessArticle

High-Resolution Seismic Characterization of Gas Hydrate Reservoir Using Wave-Equation-Based Inversion

by Jie Shao, Yibo Wang, Yanfei Wang and Hongyong Yan

Energies 2022, 15(20), 7652; https://doi.org/10.3390/en15207652 - 17 Oct 2022

Cited by 1 | Viewed by 1478

Abstract

The high-resolution seismic characterization of gas hydrate reservoirs plays an important role in the detection and exploration of gas hydrate. The conventional AVO (amplitude variation with offset) method is based on a linearized Zoeppritz equation and utilizes only the reflected wave for inversion. [...] Read more.

The high-resolution seismic characterization of gas hydrate reservoirs plays an important role in the detection and exploration of gas hydrate. The conventional AVO (amplitude variation with offset) method is based on a linearized Zoeppritz equation and utilizes only the reflected wave for inversion. This reduces the accuracy and resolution of the inversion properties and results in incorrect reservoir interpretation. We have studied a high-resolution wave-equation-based inversion method for gas hydrate reservoirs. The inversion depends on the scattering integral wave equation that describes a nonlinear relationship between the seismic wavefield and the elastic properties of the subsurface medium. In addition to the reflected wave, it considers more wavefields including the multiple scattering and transmission during inversion to improve the subsurface illumination, so as to enhance the accuracy and resolution of the inversion properties. The results of synthetic data from Pearl River Mouth Basin, South China Sea, demonstrate the validity and advantages of the wave-equation-based inversion method. It can effectively improve the resolution of inversion results compared to the conventional AVO method. In addition, it has good performance in the presence of noise, which makes it a promising method for field data. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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15 pages, 4015 KiB

Open AccessArticle

Quantitative Evaluation of Water-Flooded Zone in a Sandstone Reservoir with Complex Porosity–Permeability Relationship Based on J-Function Classification: A Case Study of Kalamkas Oilfield

by Xuanran Li, Jingcai Wang, Dingding Zhao, Jun Ni, Yaping Lin, Angang Zhang, Lun Zhao and Yuming Liu

Energies 2022, 15(19), 7037; https://doi.org/10.3390/en15197037 - 25 Sep 2022

Cited by 1 | Viewed by 1458

Abstract

The water-flooded zone in a sandstone reservoir with a complex porosity–permeability relationship is difficult to interpret quantitatively. Taking the P Formation of Kalamkas Oilfield in Kazakhstan as an example, this paper proposed a reservoir classification method that introduces the J-function into the crossplot [...] Read more.

The water-flooded zone in a sandstone reservoir with a complex porosity–permeability relationship is difficult to interpret quantitatively. Taking the P Formation of Kalamkas Oilfield in Kazakhstan as an example, this paper proposed a reservoir classification method that introduces the J-function into the crossplot of resistivity and oil column height to realize the classification of sandstone reservoirs with a complex porosity–permeability relationship. Based on the classification results, the initial resistivity calculation models of classified reservoirs were established. The oil–water seepage experiment was performed for classified reservoirs to measure the lithoelectric parameters and establish the relationship between water production rate and resistivity for these reservoirs, and then water production was quantitatively calculated according to the difference between the inverted initial resistivity and the measured resistivity. The results show that the reservoirs with an unclear porosity–permeability relationship can be classified by applying the J-function corresponding to grouped capillary pressure curves to the crossplot of oil column height and resistivity, according to the group average principle of capillary pressure curves. This method can solve the problem that difficult reservoir classification caused by a weak porosity–permeability correlation. Moreover, based on the results of reservoir classification, the water production rate and resistivity model of classified reservoirs is established. In this way, the accuracy of quantitative interpretation of the water-flooded zone in the reservoir can be greatly improved. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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24 pages, 12799 KiB

Open AccessFeature PaperArticle

Insights into Heterogeneity and Representative Elementary Volume of Vuggy Dolostones

by Yufang Xue, Zhongxian Cai, Heng Zhang, Qingbing Liu, Lanpu Chen, Jiyuan Gao and Fangjie Hu

Energies 2022, 15(16), 5817; https://doi.org/10.3390/en15165817 - 10 Aug 2022

Cited by 3 | Viewed by 1757

Abstract

Carbonate reservoirs commonly have significant heterogeneity and complex pore systems due to the multi-scale characteristic. Therefore, it is quite challenging to predict the petrophysical properties of such reservoirs based on restricted experimental data. In order to study the heterogeneity and size of the [...] Read more.

Carbonate reservoirs commonly have significant heterogeneity and complex pore systems due to the multi-scale characteristic. Therefore, it is quite challenging to predict the petrophysical properties of such reservoirs based on restricted experimental data. In order to study the heterogeneity and size of the representative elementary volume (REV) of vuggy dolostones, a total of 26 samples with pore sizes ranging from micrometers to centimeters were collected from the Cambrian Xiaoerbulake Formation at the Kalping uplift in the Tarim Basin of northwestern China. In terms of the distribution of pore size and contribution of pores to porosity obtained by medical computed tomography testing, four types of pore systems (Types I–IV) were identified. The heterogeneity of carbonate reservoirs was further quantitatively evaluated by calculating the parameters of pore structure, heterogeneity, and porosity cyclicity. The results indicate that different pore systems yield variable porosities, pore structures, and heterogeneity. The porosity is relatively higher in Type-II and Type-IV samples compared to those of Type-I and Type-III. It is caused by well-developed large vugs in the former two types of samples, which increase porosity and reduce heterogeneity. Furthermore, the REV was calculated by deriving the coefficient of variation. Nine of the twenty-six samples reach the REV within the volume of traditional core plugs, which indicates that the REV sizes of vuggy dolostones are commonly much larger than the volume of traditional core plugs. Finally, this study indicates that REV sizes are affected by diverse factors. It can be effectively predicted by a new model established based on the relationship between REV sizes and quantitative parameters. The correlated coefficient of this model reaches 0.9320. The results of this study give more insights into accurately evaluating the petrophysical properties of vuggy carbonate reservoirs. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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11 pages, 714 KiB

Open AccessArticle

Spatial Fractional Darcy’s Law on the Diffusion Equation with a Fractional Time Derivative in Single-Porosity Naturally Fractured Reservoirs

by Fernando Alcántara-López, Carlos Fuentes, Rodolfo G. Camacho-Velázquez, Fernando Brambila-Paz and Carlos Chávez

Energies 2022, 15(13), 4837; https://doi.org/10.3390/en15134837 - 1 Jul 2022

Cited by 4 | Viewed by 1592

Abstract

Due to the complexity imposed by all the attributes of the fracture network of many naturally fractured reservoirs, it has been observed that fluid flow does not necessarily represent a normal diffusion, i.e., Darcy’s law. Thus, to capture the sub-diffusion process, various tools [...] Read more.

Due to the complexity imposed by all the attributes of the fracture network of many naturally fractured reservoirs, it has been observed that fluid flow does not necessarily represent a normal diffusion, i.e., Darcy’s law. Thus, to capture the sub-diffusion process, various tools have been implemented, from fractal geometry to characterize the structure of the porous medium to fractional calculus to include the memory effect in the fluid flow. Considering infinite naturally fractured reservoirs (Type I system of Nelson), a spatial fractional Darcy’s law is proposed, where the spatial derivative is replaced by the Weyl fractional derivative, and the resulting flow model also considers Caputo’s fractional derivative in time. The proposed model maintains its dimensional balance and is solved numerically. The results of analyzing the effect of the spatial fractional Darcy’s law on the pressure drop and its Bourdet derivative are shown, proving that two definitions of fractional derivatives are compatible. Finally, the results of the proposed model are compared with models that consider fractal geometry showing a good agreement. It is shown that modified Darcy’s law, which considers the dependency of the fluid flow path, includes the intrinsic geometry of the porous medium, thus recovering the heterogeneity at the phenomenological level. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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15 pages, 8734 KiB

Open AccessArticle

Application of Machine Learning for Lithofacies Prediction and Cluster Analysis Approach to Identify Rock Type

by Mazahir Hussain, Shuang Liu, Umar Ashraf, Muhammad Ali, Wakeel Hussain, Nafees Ali and Aqsa Anees

Energies 2022, 15(12), 4501; https://doi.org/10.3390/en15124501 - 20 Jun 2022

Cited by 36 | Viewed by 3726

Abstract

Nowadays, there are significant issues in the classification of lithofacies and the identification of rock types in particular. Zamzama gas field demonstrates the complex nature of lithofacies due to the heterogeneous nature of the reservoir formation, while it is quite challenging to identify [...] Read more.

Nowadays, there are significant issues in the classification of lithofacies and the identification of rock types in particular. Zamzama gas field demonstrates the complex nature of lithofacies due to the heterogeneous nature of the reservoir formation, while it is quite challenging to identify the lithofacies. Using our machine learning approach and cluster analysis, we can not only resolve these difficulties, but also minimize their time-consuming aspects and provide an accurate result even when the user is inexperienced. To constrain accurate reservoir models, rock type identification is a critical step in reservoir characterization. Many empirical and statistical methodologies have been established based on the effect of rock type on reservoir performance. Only well-logged data are provided, and no cores are sampled. Given these circumstances, and the fact that traditional methods such as regression are intractable, we have chosen to apply three strategies: (1) using a self-organizing map (SOM) to arrange depth intervals with similar facies into clusters; (2) clustering to split various facies into specific zones; and (3) the cluster analysis technique is used to identify rock type. In the Zamzama gas field, SOM and cluster analysis techniques discovered four group of facies, each of which was internally comparable in petrophysical properties but distinct from the others. Gamma Ray (GR), Effective Porosity(eff), Permeability (Perm) and Water Saturation (Sw) are used to generate these results. The findings and behavior of four facies shows that facies-01 and facies-02 have good characteristics for acting as gas-bearing sediments, whereas facies-03 and facies-04 are non-reservoir sediments. The outcomes of this study stated that facies-01 is an excellent rock-type zone in the reservoir of the Zamzama gas field. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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20 pages, 16343 KiB

Open AccessArticle

Non-Matrix Quick Pass: A Rapid Evaluation Method for Natural Fractures and Karst Features in Core

by Paul J. Moore and Fermin Fernández-Ibáñez

Energies 2022, 15(12), 4347; https://doi.org/10.3390/en15124347 - 14 Jun 2022

Cited by 5 | Viewed by 1764

Abstract

Mechanical and chemical processes experienced by carbonate rocks result in a complex network of natural fractures and dissolution features that have direct implications on porosity, permeability, and connectivity in reservoirs. Characterization of natural fractures is best done in core; however, it can be [...] Read more.

Mechanical and chemical processes experienced by carbonate rocks result in a complex network of natural fractures and dissolution features that have direct implications on porosity, permeability, and connectivity in reservoirs. Characterization of natural fractures is best done in core; however, it can be time-consuming due to the large amounts of individual features present and the long list of attributes typically collected for each feature. Additionally, karst features in core, such as vugs and small cavities, are seldom characterized in a quantitative way or are overlooked. We introduce a new methodology, called the non-matrix quick pass (NMQP), which allows for the collection of non-matrix features in a rapid yet quantitative fashion at a rate of 12 to 20 m of core per hour. The NMQP methodology offers enough vertical resolution so that observations can be integrated with other wellbore data types (e.g., wireline logs, well tests, and production logs). This method also yields estimates of density and porosity that are rigorous enough to provide the technical basis to build first-generation dual-porosity models describing the non-matrix component of a carbonate reservoir and its potential impact on field performance. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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18 pages, 48228 KiB

Open AccessArticle

High-Frequency Sea-Level Cycle Reconstruction and Vertical Distribution of Carbonate Ramp Shoal Facies Dolomite Reservoir in Gucheng Area, East Tarim Basin

by Tong Lin, Kedan Zhu, You Zhang, Zihui Feng, Xingping Zheng, Bin Li and Qifan Yi

Energies 2022, 15(12), 4287; https://doi.org/10.3390/en15124287 - 11 Jun 2022

Viewed by 1468

Abstract

During the sedimentary period of the Ordovician Yingshan Formation, the carbonate platform of the Gucheng area in the Tarim basin was characterized by a distally steepened ramp. Relative sea-level changes exerted a strong influence on the shoal facie dolomite reservoirs of the 3rd [...] Read more.

During the sedimentary period of the Ordovician Yingshan Formation, the carbonate platform of the Gucheng area in the Tarim basin was characterized by a distally steepened ramp. Relative sea-level changes exerted a strong influence on the shoal facie dolomite reservoirs of the 3rd Member of the Ordovician Yingshan Formation (the Ying 3 member), sedimented in the context of a shallow water environment on the carbonate ramp. However, previous studies that lacked high-frequency sea-level changes in the Gucheng area prevent further dolomite reservoir characterization. The current work carries out systematic sampling based on the continuous core from the upper and middle parts of the Ying 3 member in two newly drilled exploration wells (GC17 and GC601) and a series of geochemistry analyses, such as C-O isotope, Sr isotope, and rare earth elements (REE), which helps to investigate the features of the shoal facies dolomite reservoir development against high-frequency sea-level changes. With the help of Fischer plots of these two wells, high-density δ13C data (sample interval is about 0.272 m) were merged to construct a comprehensive curve, contributing to characterizing the high-frequency sea-level changes of the upper and middle parts of the Ying 3 member in the Gucheng area and validating the relationship between the pore-vug vertical distribution and high-frequency sea-level changes. Results revealed that the porosity of dolomite reservoirs increased when the high-frequency sea-level fell and decreased when it rose. Furthermore, the karst surface can be found at the top of the upward-shallowing cycle during the high-frequency sea-level falling; the pore-vug reservoirs are concentrated below the karst exposure surface, and porous spaces are more developed closer to the top of the cycle. The high frequency sea-level curve built in this study can be used as a standard for further research of regional sea-levels in the Gucheng area, and this understanding is highly practical in the prediction of shoal facies carbonate reservoir in carbonate ramp. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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19 pages, 4456 KiB

Open AccessArticle

Geological Characteristics and Development Techniques for Carbonate Gas Reservoir with Weathering Crust Formation in Ordos Basin, China

by Haijun Yan, Ailin Jia, Jianlin Guo, Fankun Meng, Bo Ning and Qinyu Xia

Energies 2022, 15(9), 3461; https://doi.org/10.3390/en15093461 - 9 May 2022

Cited by 2 | Viewed by 1763

Abstract

The carbonate gas reservoir is one of the most important gas formation types; it comprises a large proportion of the global gas reserves and the annual gas production rate. However, a carbonate reservoir with weathering crust formation is rare, and it is of [...] Read more.

The carbonate gas reservoir is one of the most important gas formation types; it comprises a large proportion of the global gas reserves and the annual gas production rate. However, a carbonate reservoir with weathering crust formation is rare, and it is of significant interest to illustrate the geological characteristics of this kind of formation and present the emerging problems and solution measures that have arisen during its exploitation. Therefore, in this research, a typical carbonate gas reservoir with weathering crust formation that is located in Ordos Basin, China, was comprehensively studied. In terms of formation geology, for this reservoir, the distribution area is broad and there are multiple gas-bearing layers with low abundance and strong heterogeneity, which have led to large differences in gas well production performance. Some areas in this reservoir are rich in water, which seriously affects gas well production. Regarding production dynamics, the main production areas in this gas reservoir have been stable on a scale of 5.5 billion cubic meters for more than a decade, and the peripheral area has been continually evaluated to improve production capacity. Nevertheless, after decades of exploration and development, the main areas of this reservoir are faced with several problems, including an unclear groove distribution, an unbalanced exploitation degree, low formation pressure, and increases in intermittent gas wells. To deal with these problems and maintain the stability of gas reservoir production, a series of technologies have been presented. In addition, several strategies have been proposed to solve issues that have emerged during the exploration and exploitation of peripheral reservoir areas, such as low-quality formation, unclear ancient land and complex formation-water distribution. These development measures employed in the carbonate gas reservoir with weathering crust formation in the Ordos Basin will surely provide some guidance for the efficient exploitation of similar reservoirs in other basins all over the world. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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15 pages, 11168 KiB

Open AccessArticle

Application of Far-Gather Seismic Attributes in Suppressing the Interference of Coal Beds in Reservoir Prediction

by Yunxin Mao, Chunjing Yan, Ruoyu Zhang, Yangsen Li, Min Lou, Luxing Dou, Xinrui Zhou and Xixin Wang

Energies 2022, 15(6), 2206; https://doi.org/10.3390/en15062206 - 17 Mar 2022

Cited by 1 | Viewed by 1917

Abstract

The sandstone reservoir of the Pinghu Formation in the Xihu Depression, East China Sea is characterized by great depth, small thickness, radical facies change and a widespread coal bed. It is difficult to describe the reservoir accurately using conventional reservoir prediction methods. In [...] Read more.

The sandstone reservoir of the Pinghu Formation in the Xihu Depression, East China Sea is characterized by great depth, small thickness, radical facies change and a widespread coal bed. It is difficult to describe the reservoir accurately using conventional reservoir prediction methods. In order to analyze the influence of coal-bearing strata on the prediction of the mid-low thickness sandstone reservoir, the seismic response of different sandstone–coal stratigraphic assemblages was simulated by seismic forward modeling. The modeling result indicates that the post-stack seismic response is dominated by coal bed, whereas the response of sandstone can hardly be recognized. In contrast, the difference between the pre-stack AVO (amplitude versus offset) response characteristics of coal seams and gas-bearing sandstones has been clarified based on the statistics pertaining to AVO characteristics of drilled wells. Therefore, we propose a method to reduce the interference of coal beds in sandstone reservoir prediction using far-gather seismic information. This method has significantly improved the accuracy of reservoir prediction and sand description in sand–coal coupled environments and has been applied successfully in the exploration of coal-rich strata in the Pingbei slope belt, Xihu Depression. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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27 pages, 94089 KiB

Open AccessArticle

Characteristics and Formation Mechanism of the Lower Paleozoic Dolomite Reservoirs in the Dongying Depression, Bohai Bay Basin

by Xuemei Zhang, Qing Li, Xuelian You, Lichi Ma, Anyu Jing, Wen Tian and Lang Wen

Energies 2022, 15(6), 2155; https://doi.org/10.3390/en15062155 - 16 Mar 2022

Cited by 2 | Viewed by 2482

Abstract

The Lower Paleozoic carbonate strata experience multi-stage tectonic activity and post-depositional volcanic activity in the Dongying Depression, Bohai Bay basin. These tectonic and magmatic activities have caused the reservoir to undergo severe diagenesis, resulting in strong reservoir heterogeneity. This study aims to identify [...] Read more.

The Lower Paleozoic carbonate strata experience multi-stage tectonic activity and post-depositional volcanic activity in the Dongying Depression, Bohai Bay basin. These tectonic and magmatic activities have caused the reservoir to undergo severe diagenesis, resulting in strong reservoir heterogeneity. This study aims to identify the characteristics of dolomite, various reservoir spaces’ characteristics, the origin of different types of dolomite, and the porosity evolution. According to crystal size and morphology, dolomites can be divided into three kinds of matrix dolomites and four kinds of dolomite cements. The petrology and geochemistry of the dolomite suggests that matrix dolomite is formed from seawater. The medium-to-coarse-crystalline dolomite cement (D3) has a higher ⁸⁷Sr/⁸⁶Sr ratio (0.7119 to 0.7129) and a higher homogenization temperature (>125 °C), suggesting that the fluid for the precipitation of D3 is a mixed fluid formed by hydrothermal fluid eroding the ⁸⁷Sr-rich feldspar sandstone. The strikingly negative δ¹⁸O values (−23.7 to −25.7‰ VPDB) of saddle dolomite (D4) indicate that D4 precipitated from hydrothermal fluids and the Mg²⁺ source may be due to dissolution of the host dolomite that formed in the evaporation environment. The reservoir spaces of the target strata in the study area mainly include fractures, dissolution vugs, intercrystalline pores, and moldic pores. Dissolution is the basis for forming high-quality dolomite reservoirs. The faults and fractures provided favorable conditions for dissolution. Hydrothermal fluid and organic acid were the main dissolution fluids for the dolomite reservoir, which were beneficial to the development of secondary pores. In the study area, organic acid dissolution was shown to contribute more than hydrothermal dissolution in the study area. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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25 pages, 13733 KiB

Open AccessArticle

A Technique of Hydrocarbon Potential Evaluation in Low Resistivity Gas-Saturated Mudstone Horizons in Miocene Deposits, South Poland

by Anita Lis-Śledziona and Weronika Kaczmarczyk-Kuszpit

Energies 2022, 15(5), 1890; https://doi.org/10.3390/en15051890 - 4 Mar 2022

Cited by 2 | Viewed by 2504

Abstract

The petrophysical properties of Miocene mudstones and gas bearing-heteroliths were the main scope of the work performed in one of the multihorizon gas fields in the Polish Carpathian Foredeep. Ten boreholes were the subject of petrophysical interpretation. The analyzed interval covered seven gas-bearing [...] Read more.

The petrophysical properties of Miocene mudstones and gas bearing-heteroliths were the main scope of the work performed in one of the multihorizon gas fields in the Polish Carpathian Foredeep. Ten boreholes were the subject of petrophysical interpretation. The analyzed interval covered seven gas-bearing Miocene horizons belonging to Sarmatian and Badenian deposits. The water saturation in shaly sand and mudstone intervals was calculated using the Montaron connectivity theory approach and was compared with Simandoux water saturation. Additionally, the Kohonen neural network was used for qualitative interpretation of four PSUs (petrophysically similar units), which represent the deposits of comparable petrophysical parameters. This approach allowed us to identify the sediment group with the highest probability of hydrocarbon saturation. Then, the spatial distribution of PSUs and reservoir parameters was carried out in Petrel. The resolution of the model was selected to reflect the variability of log-derived parameters. The reconstruction of the spatial distribution of shale volume, porosity, and permeability was performed with standard parametric modeling procedures using the Gaussian random function simulation stochastic algorithm, while PSU distribution and hydrocarbon saturation (SH) required a separate approach. The distribution into PSU groups was carried out by facies classification. Predefined ranges of clay volume, effective porosity, and permeability were used as discriminators to achieve spatial distribution of the PSU groups. The spatial distribution of hydrocarbon saturation was performed by creating the meta-attribute of this parameter and then reducing the derived pseudo-saturation model to physical values. Results included the creation of maps of hydrocarbon saturation that show the preferable areas with the highest hydrocarbon saturation for each gas horizon. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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20 pages, 9321 KiB

Open AccessArticle

A Multi-Point Geostatistical Seismic Inversion Method Based on Local Probability Updating of Lithofacies

by Zhihong Wang, Tiansheng Chen, Xun Hu, Lixin Wang and Yanshu Yin

Energies 2022, 15(1), 299; https://doi.org/10.3390/en15010299 - 2 Jan 2022

Cited by 8 | Viewed by 1928

Abstract

In order to solve the problem that elastic parameter constraints are not taken into account in local lithofacies updating in multi-point geostatistical inversion, a new multi-point geostatistical inversion method with local facies updating under seismic elastic constraints is proposed. The main improvement of [...] Read more.

In order to solve the problem that elastic parameter constraints are not taken into account in local lithofacies updating in multi-point geostatistical inversion, a new multi-point geostatistical inversion method with local facies updating under seismic elastic constraints is proposed. The main improvement of the method is that the probability of multi-point facies modeling is combined with the facies probability reflected by the optimal elastic parameters retained from the previous inversion to predict and update the current lithofacies model. Constrained by the current lithofacies model, the elastic parameters were obtained via direct sampling based on the statistical relationship between the lithofacies and the elastic parameters. Forward simulation records were generated via convolution and were compared with the actual seismic records to obtain the optimal lithofacies and elastic parameters. The inversion method adopts the internal and external double cycle iteration mechanism, and the internal cycle updates and inverts the local lithofacies. The outer cycle determines whether the correlation between the entire seismic record and the actual seismic record meets the given conditions, and the cycle iterates until the given conditions are met in order to achieve seismic inversion prediction. The theoretical model of the Stanford Center for Reservoir Forecasting and the practical model of the Xinchang gas field in western China were used to test the new method. The results show that the correlation between the synthetic seismic records and the actual seismic records is the best, and the lithofacies matching degree of the inversion is the highest. The results of the conventional multi-point geostatistical inversion are the next best, and the results of the two-point geostatistical inversion are the worst. The results show that the reservoir parameters obtained using the local probability updating of lithofacies method are closer to the actual reservoir parameters. This method is worth popularizing in practical exploration and development. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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18 pages, 5015 KiB

Open AccessArticle

Linearized Frequency-Dependent Reflection Coefficient and Attenuated Anisotropic Characteristics of Q-VTI Model

by Yahua Yang, Xingyao Yin, Bo Zhang, Danping Cao and Gang Gao

Energies 2021, 14(24), 8506; https://doi.org/10.3390/en14248506 - 16 Dec 2021

Cited by 3 | Viewed by 2316

Abstract

Seismic wave exhibits the characteristics of anisotropy and attenuation while propagating through the fluid-bearing fractured or layered reservoirs, such as fractured carbonate and shale bearing oil or gas. We derive a linearized reflection coefficient that simultaneously considers the effects of anisotropy and attenuation [...] Read more.

Seismic wave exhibits the characteristics of anisotropy and attenuation while propagating through the fluid-bearing fractured or layered reservoirs, such as fractured carbonate and shale bearing oil or gas. We derive a linearized reflection coefficient that simultaneously considers the effects of anisotropy and attenuation caused by fractures and fluids. Focusing on the low attenuated transversely isotropic medium with a vertical symmetry axis (Q-VTI) medium, we first express the complex stiffness tensors based on the perturbation theory and the linear constant Q model at an arbitrary reference frequency, and then we derive the linearized approximate reflection coefficient of P to P wave. It decouples the P- and S-wave inverse quality factors, and Thomsen-style attenuation-anisotropic parameters from complex P- and S-wave velocity and complex Thomsen anisotropic parameters. By evaluating the reflection coefficients around the solution point of the interface of two models, we analyze the characteristics of reflection coefficient vary with the incident angle and frequency and the effects of different Thomsen anisotropic parameters and attenuation factors. Moreover, we realize the simultaneous inversion of all parameters in the equation using an actual well log as a model. We conclude that the derived reflection coefficient may provide a theoretical tool for the seismic wave forward modeling, and again it can be implemented to predict the reservoir properties of fractures and fluids based on diverse inversion methods of seismic data. Full article

(This article belongs to the Special Issue Characterization of Conventional and Unconventional Hydrocarbon Reservoirs)

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