Abstract Acid treatment has been proven to effectively reduce reservoir fracture pressure, but the variation pattern of sandstone brittleness after acid treatment remains unclear. To effectively evaluate the characteristics of brittleness changes, uniaxial compression tests were conducted on tight sandstone subjected to acid treatment for different durations, and a brittleness index evaluation method based on radial strain response was established. The results show that sandstone uniaxial compressive strength decreases stepwise with prolonged acid treatment. Elastic modulus decreases slowly initially, drops sharply after 24 h of acid treatment, and stabilizes between 120 and 168 h. Poisson’s ratio decreases linearly after 6 h of acid treatment. The brittleness index first increases and then decreases, peaking at 12–24 h of acid treatment—consistent with AE results showing more high-intensity signals during the elastic compression stage of axial stress-strain curves. After acid treatment, sandstone crack initiation stress first increases slowly, then gradually decreases, and finally drops rapidly. This is attributed to acid-rock reaction-induced dissolution of minerals and cementing materials, which detaches fine-grained matrix particles, increases porosity, and reduces crack initiation stress. The findings provide a reference for engineering design and construction of high fracture pressure tight sandstone reservoirs.

The Chang 9 oil-bearing interval in the Beiliang area of Wuqi is an important oil-bearing interval in the lower assemblage of the Yanchang Formation in the Ordos Basin. To clarify its reservoir characteristics and the main controls on hydrocarbon accumulation, this study integrates stratigraphic correlation of 163 wells, sedimentary-facies analysis of 10 representative wells, log-derived porosity and permeability data, thin-section and scanning-electron-microscope observations, and pressure–temperature and fluid data. The results show that the K₀ marker bed at the top of the Chang 9 interval is 1.1–7.9 m thick (2.5 m on average) and that the interval can be subdivided into three sub-members: Chang 9₁, Chang 9₂, and Chang 9₃. The predominant sedimentary facies are delta-front subfacies, and the subaqueous distributary-channel sand bodies constitute the principal reservoir rocks. The reservoir lithologies are dominated by fine-grained feldspathic sandstone and lithic feldspathic sandstone, and the storage spaces are mainly residual intergranular pores and dissolution pores. The average porosities of the Chang 9₃, Chang 9₂, and Chang 9₁ sub-members are 9.66%, 8.23%, and 8.32%, respectively, and the corresponding average permeabilities are 5.64 × 10⁻³, 4.63 × 10⁻³, and 4.28 × 10⁻³ μm². The permeability variation coefficient ranges from 0.71 to 2.07, indicating low-porosity, low-permeability, and strongly heterogeneous reservoirs. The Chang 9 reservoirs are predominantly lithologic, with local modification by low-amplitude structures. The average initial formation pressure is 17.26 MPa, the pressure coefficient is 0.78, and the average formation temperature is 70.25 °C, defining a normal-temperature, low-pressure system. The formation-water salinity ranges from 5.19 to 10.59 g/L (7.53 g/L on average), and the water is mainly of the CaCl₂ type. Regional oil–source correlation indicates that the Chang 7 hydrocarbon source rocks are the principal hydrocarbon-supply interval, whereas the dark shales at the top of the Chang 9 interval may provide a supplementary contribution whose magnitude has not yet been quantified. Hydrocarbon enrichment is mainly controlled by the hydrocarbon-supply conditions, the distribution of subaqueous distributary-channel sand bodies, and reservoir effectiveness and connectivity; low-amplitude nose-shaped uplifts locally modify the oil–water distribution. Regional excess-pressure differences may have provided a driving background for downward migration, but this interpretation still requires verification through paleopressure reconstruction.

The LDX area in the Yinggehai Basin hosts canyon channel reservoirs in the Huangliu Formation's Second Member, characterised by high temperatures, pressures and multi-phase fluid influx, complicating pore structure evaluation. An integrated approach combining petrophysical measurements, thin section analysis, mineralogy, electron microscopy, granulometry and well-log data was used to study compositional and structural impacts on pore networks. Key findings include: (1) Two high-permeability pore types, linked to large pores and good sorting or strong dissolution; (2) Improved rock volume modelling using RT, DEN and CNL logging enhances calcite correlation and mineral content accuracy; (3) The median particle size (M) inversion model based on the classification of particle size sample has high precision, and the sorting coefficient (So) is segmentally correlated with M; (4) The pore structure type recognition model, based on the feature fusion of skeleton knowledge-driven and diagenetic sensitivity curves by multi-modal learning, has good continuous recognition ability in well profiles and (5) High-quality pores dominate thick sandstone at the base, while the middle section is poorer, with some quality pores in the east branch and canyon intersection during the top stage. This study enables continuous pore structure evaluation and summarises development patterns under multi-source canyon systems, advancing understanding of pore evolution and reservoir impacts in the LDX area.

Coal and gas outburst remains a critical and persistent challenge in coal extraction, posing a profound threat for mine safety. The underlying mechanisms of such disaster, particularly the gas-driven coal fragmentation, continue to elude comprehensive understanding. To explore this problem, in this paper, gas seepage regularity in different structural bituminous coal and its influence on outburst-coal breaking were investigated through strength tests, isothermal adsorption tests, and gas seepage tests of stressed coal under various conditions. The results indicated that coal permeability decreased as axial stress, confining pressure, and gas kinetic diameter increased. That meant outburst-induced abrupt stress unloading and coal matrix destabilization changed gas seepage characteristics. As a result, a self-reinforcing cycle effect where outburst-coal breaking and gas seepage are mutually stimulated was formed in a short time period when outbursts initiated, which further promoted outburst-coal breaking and outburst initiation. The findings of this study enhance our understanding of the mechanism of gas participating in coal fragmentation during outbursts, which are significantly conducive to gas disaster prevention, sustainable coal production, and efficient CBM development, further ensuring global energy security.

Fractures are important storage spaces and migration pathways in tight oil and gas reservoirs. Due to the complex origins and multi-stage development of fractures, predicting them presents significant challenges, especially in areas where fault activity is relatively weak and seismic responses are not obvious, making it difficult to identify small to medium-scale fractures using conventional seismic fracture prediction methods. This paper takes the tight reservoir of M oilfield as an example, and use the phase reconstruction technique to accurately characterize the fractures. Through an in-depth analysis of the fracture formation period and combination, and comparing the spectral sensitivity, based on the characteristics of phase spectrum being less affected by energy and changing rapidly, the minimum phase value corresponding to the frequency change point is determined and the phase spectra is reconstructed to improve the seismic resolution of fracture zones through multiple phase calculations, multi-cycle function breakdown, and multiple iterations of single-cycle signal comparison. Through similarity coefficient statistics, achieve accurate tracing and spatial distribution characterization of fractures. This technique is used to effectively predict the fracture distribution in the area with weaker faults activity in the basin of M oilfield. Comparison with the amplitude domain seismic profile, the fractures in the phase domain seismic profile based on phase reconstruction technology are clearer and the continuity of the formation is easier to distinguish. Based on reconstructed phase spectrum data, fractures are detected using Eigen-coherence technology, and the fracture information is very apparent. The prediction results show good consistency with the logging results. This technology has improved fracture prediction accuracy and holds high applicability and promotion value for identifying fractures in tight oil and gas reservoirs with relatively weak fault activity and seismic responses.

The Jiamuhe Formation in the northwest margin of the Shawan Sag comprises tight sandstone reservoirs, and its distribution has obvious regional differences, but the reasons for this difference are not clear. This study aims to clarify the diagenetic facies and pore evolution patterns by integrating petrographic thin sections, fluorescence thin sections, X-ray diffraction, porosity-permeability data. The objective is to identify the causes of these differences, establish a theoretical evolutionary model, and quantitatively characterize pore evolution. The study area is dominated by lithic sandstone, feldspar lithic sandstone, and lithic feldspar sandstone. These rocks are characterized by relatively low textural and compositional maturity. The primary storage space is predominantly composed of secondary pores formed through dissolution, with minor microfractures present. The findings indicate that dissolution is the principal factor contributing to the physical properties of reservoirs observed between the delta plain and delta front. The texture of the cement and secondary pores govern the variations in physical properties within the same facies zone. The diagenetic sequence includes compaction→early chlorite coating→early meteoric water dissolution→early calcite/kaolinite cementation→middle-stage analcime/philipsite/zeolite cementation →middle-stage organic acid dissolution→microfractures. Quantitative analysis indicates that the original porosity decreased 23.89% by compaction and 7.94% by cementation. Conversely, dissolution and tectonic fracturing enhance porosity by 5.87% and 5.10%, respectively. The theoretical calculations align well with the experimental results. Based on the cementation-sedimentation-pore type, the Jiamuhe Formation in the study area is classified into four distinct diagenetic facies, type I is strong cementation - outer delta front - dissolution pores. Type II is strong cementation - inner delta front - intra granular dissolution pores with moderate dissolution. Type III is poor cementation - delta plain - intergranular pores with strong dissolution. Type IV is strong compaction - delta plain - intergranular dissolution pores with moderate cementation. The evolutionary history of each facies was reconstructed by using porosity evolution curves. Type I and Type III were demonstrated significant reservoir potential, offering a reference for predicting favorable reservoir distribution in future studies.

The gravity gradient anomaly zone is produced due to density differences on both sides of a fault. Tracking of extreme points enables the characterization and description of fault locations. However, for some deep-seated faults with large burial depths and secondary faults with moderate burial depths, the gravity horizontal total gradient anomaly must be enhanced using the concept of dip angle to strengthen the weak anomaly extraction for the identification of more fault information. This method was used to predict five regional deep-seated faults and six secondary faults in the Miquan region. The fracture plane extends in a near north-northeast direction; that is, it mostly expands out of the study area, spreads out in a trumpet shape to the southwest, and converges to the northeast. Fracture activity is an important factor in controlling structural units or local structures. The Miquan block is located in a complex structural zone in front of the Bogeda Mountains, which have very complex surface and subsurface geological conditions, and seismic data are unideal. Therefore, fracture prediction results using gravity data are important in-depth understanding of the structure in this area.

The residual oil in the fluvial reservoir of Gudong Oilfield is still widely developed even after decades of development. In order to explore the remaining oil in the subsurface fluvial reservoir, we need to have a better understanding on fluvial sandbody characteristics. This paper aims to demonstrate how to quantify anatomy on meandering fluvial architecture. Sedimentologic data from core descriptions of Guantao Formation in Gudong Oilfield were used to identify architectural elements. The upper Guantao Formation consists of ten lithofacies composing five different types of architectural elements. By integrating the available core, well logs, and seismic data, the fluvial sandbody distribution was analyzed. To characterize the fluvial channel geomorphology, we used seismic inversion to explore the stratigraphic correlation and stacking patterns of different channels, and the sandbody isopach map was obtained by the sandbody thickness in each layer. The architectural elements distribution in the plane was mapped by the sandbody isopach map and its profile characteristics. According to the investigation of meandering fluvial outcrops, subsurface meandering fluvial seismic geomorphology, and modern river morphology, the upstream-bar portions are always eroded because of the downstream channel migration. Statistics on the morphometric parameters (bar width/looplength, upstream deflection angle, downstream deflection angle, etc.) of modern meandering river (Ob River) were obtained from the Google Earth. It is found that the bar width/looplength and upstream deflection angle, upstream deflection angle and downstream deflection angle in modern meandering river have a good relationship, and we can have a quantitative architectural characterization on the point bar. This study quantified lithofacies thickness and proportion in different architectural elements of Guantao Formation, which ensures a high resolution anatomy on the small scale architecture. By using this method, the lithofacies proportion in each architectural element was computed, and through the statistics of architectural elements proportion in the Gudong Oilfield, the different lithofacies proportions in the block 6 can be computed.

The upper Carboniferous tight sandstone strata are considered the most promising targets for gas exploration in the northeastern Ordos Basin. Reservoir quality is critical for the successful commercial exploration and development of tight sandstone gas. Reservoir quality of deeply buried tight sandstones is controlled by diagenesis, yet there is sparse systematic documentation on upper Carboniferous tight sandstone reservoir quality and its diagenetic link. In this study, we utilized core analysis and wireline log data, and core samples were studied using X-ray diffraction, optical light microscopy, scanning electron microscopy, porosity–permeability, mercury intrusion capillary pressure and nuclear magnetic resonance measurements. Dolomite, siderite, quartz, kaolinite, and illite are the main diagenetic cements. The upper Carboniferous sandstones pore system consists of residual intergranular pores, intragranular dissolution pores associated with feldspar grains and micropores mainly related to diagenetic minerals. Due to differences in diagenetic alterations, sandstones have significant differences in pore types and pore-filling components, ultimately leading to differences in reservoir quality. The residual intergranular porosity is closely related to the reservoir quality. Quartz cement and authigenic clay minerals lead to reduced residual intergranular porosity, but their impact on reservoir quality is relatively limited due to their relatively low content. The most significant factors contributing to reservoir quality deterioration are ductile (clay-rich) grain-influenced compaction and pervasive pore-filling carbonate cement. When sandstone contains large numbers of ductile grains, it loses a large amount of intergranular porosity due to compaction, and the pore space contains only a small number of dissolution pores and micropores, resulting in reservoir quality deterioration. Similarly, when a large amount of carbonate cement is developed in sandstone, it leads to intergranular porosity loss. The best reservoir quality sandstones preserve a percentage of intergranular porosity because they (i) have few ductile grains, resulting in low compaction, and (ii) do not have significant amounts of carbonate cements. Finally, the diagenetic variations were successfully correlated with wireline logs to evaluate the reservoir quality of subsurface upper Carboniferous sandstones. The data sets provided in this research offer insights to better evaluate and predict reservoir quality in the northeastern Ordos Basin.

In this study, X-ray diffraction, N 2 adsorption（N 2 A）, and mercury intrusion（MI） experiments were used to investigate the influence of acid treatment on pore structure and fractal characterization of tight sandstones. The results showed that acid treatment generated a certain number of ink-bottle pores in fine sandstone, aggravated the ink-bottle effect in the sandy mudstone, and transformed some smaller pores into larger ones. After the acid treatment, both the pore volume in the range of 2–11 nm and 0.271–8 μm for the fine sandstone and the entire pore size range for the sandy mudstone significantly increased. The dissolution of sandstone cement causes the fine sandstone particles to fall off and fill the pores; the porosity increased at first but then decreased with acid treatment time. The fractal dimension obtained using the Frenkel-Halsey-Hill model was positively correlated with acid treatment time. However, the total fractal dimensions obtained by MI tests showed different changes with acid treatment time in fine sandstone and sandy mudstone. These results provide good guiding significance for reservoir acidification stimulation.

Organic geochemical compositions of shale are the key parameters for evaluating the potential of lacustrine shale oil. Systematic organic geochemical analyses (e.g., total organic carbon (TOC), Rock–Eval pyrolysis, chloroform bitumen “A,” group component, kerogen maceral, and saturated hydrocarbon chromatography) have been carried out on the shale in the lower sub-member of the third member of Eocene Shahejie Formation (Es3L) in the Well L69 from the Zhanhua Sag of Bohai Bay Basin, in order to constrain its sedimentary environment and evaluate the potential of lacustrine shale oil. The shale in the Es3L has TOC content in the range from 0.52% to 9.32%, free hydrocarbon (S1) from 0.03 mg/g to 13.12 mg/g, thermally-cracked hydrocarbon (S2) from 1.19 mg/g to 78.59 mg/g, hydrocarbon generation potential (S1 + S2) from 1.77 mg/g to 82.65 mg/g, chloroform bitumen “A” from 0.2515% to 2.1422%, and total hydrocarbon (HC) from 1630 μg/g to 10,500 μg/g, respectively. The kerogen is mainly composed of type I and type II1 sapropel, whereas the parent material is dominated by lower aquatic organisms. The original total organic carbon (TOCo), oil saturation index (OSI), and total oil (S’) vary from 1.23% to 11.33%, 3 mg oil/g TOC to 258 mg oil/g TOC, and 21.98 bbl oil/ac-ft to 980.38 bbl oil/ac-ft, respectively. The aforementioned organic geochemical compositions indicate that shale in the Es3L is characterized by high organic matter abundance, high paleoproductivity, and good organic matter type, with early maturation to peak maturation. The characteristics of saturated hydrocarbon chromatography indicate that the lake evolved from strong reducing brackish-saline water to weak reducing-weak oxidizing fresh water in the sedimentary period of Es3L in the Zhanhua Sag, providing favorable conditions for high accumulation and preservation of original organic matter. Comprehensive evaluation from these organic geochemical compositions suggests that the 3061–2983 m interval in the Well L69 has high oil content and good potential to further explore the shale oil. This provides good implications for the optimization of favorable intervals for shale oil exploration in the Bohai Bay Basin.

为了研究沾化凹陷沙三段湖相页岩夹层与页岩油产能之间的关系,在分析岩心描述、薄片鉴定、X射线衍射、扫描电镜、压汞等资料的基础上,利用反褶积方法处理测井资料识别夹层类型.结果表明:①砂质夹层和灰质夹层的脆性矿物含量高,易形成裂缝.其中砂质夹层长英矿物和灰质夹层碳酸盐岩矿物的质量分数高达46.7％,57.95％;②夹层中发育异常压力缝、矿物收缩缝、层间缝,在砂质夹层中还发育构造缝.出现裂缝的夹层平均渗透率高达7.59 mD;③夹层主要发育微—纳米级孔隙,有粒间孔、溶蚀孔和晶间孔,孔隙连通性较好.粒间孔常见于砂质夹层.溶蚀孔常见于灰质夹层,大孔隙较多;④夹层测井曲线响应特征:砂质夹层和灰质夹层都表现为低自然伽马和高电阻率特征,砂质夹层具有自然伽马在高背景下低回返、三孔隙度曲线和深侧向电阻率向右偏移,灰质夹层的三孔隙度曲线呈明显向右"靠拢".利用反褶积方法处理后的自然伽马、深侧向电阻率曲线进行重叠可快速识别夹层且分辨率更高、更直观,能够有效地识别湖相泥页岩夹层,为页岩油评价提供依据.

东营凹陷南坡F154区块沙河街组沙三段(Es3)砂岩储层渗透率低,孔隙结构复杂,产能预测难度大.根据岩心覆压物性测试、铸体薄片、恒速压汞、高压压汞及X射线衍射等资料,分析孔隙结构特征及控制因素;基于生产数据求得表征产能的参数采油强度;分析孔隙结构参数与采油强度的关系,对孔隙结构进行分类,通过孔隙结构类型测井识别,将采油强度刻度到测井曲线,建立了基于测井敏感变量的多参数采油强度预测模型,并利用实际井的生产数据进行验证,结果表明:大喉道数量决定了渗透率的高低;采油强度值越大,孔隙结构越好;采油强度较大的孔隙结构类型层段,通常自然伽马低,声波时差、深电阻率、深浅电阻率差值高.实际采油强度与预测采油强度相关系数大于0.9,计算结果符合生产预测的要求.该研究成果为复杂孔隙结构的低渗透砂岩储层产能预测提供了依据.

Pore structure and oil saturation are important parameters in petroleum exploration and development, and the relationship between them is closer in near-oil source reservoirs (with a short-distance migration of oil and gas) than in other reservoirs. Using epoxy-impregnated thin sections, scanning electron microscopy (SEM), conventional core analyses of porosity and permeability, mercury intrusion porosimetry, and well logging, the characteristics of the petrology, physical properties, and pore structure we studied, as well as the relationship between pore structure and fluid saturation (maximum mercury intrusion saturation Smax and oil saturation So) of the near-oil source low-permeability turbidite sandstone reservoirs in the Es3 member of the Dongying Sag, Bohai Bay Basin, eastern China. The results indicate that the turbidite sandstone reservoirs are mainly composed of fine sandstone and siltstone, with porosities and permeabilities ranging from 5 to 25% and 0.1 to 40 mD, respectively, and can be classified as medium to low porosity and extra-low to ultra-low permeability reservoirs. The pore types of high-quality reservoirs are mainly dominated by intergranular pores, both primary and dissolved, probably due to the influence of the acidic fluids generated from the cracking of organic matter. The pore structure is complex with respect to the pore-throat size distribution, and the overall pore-throat radius is small. Several pore structure parameters together affect the fluid saturation distribution, among which the medium pore-throat radius (R50) and medium saturation pressure (P50) are especially correlated with oil saturation. Different pore structure types have different characteristics of fluid saturation distribution, and the oil-bearing grade and oil saturation of the reservoirs above the oil-water contact are typically positively correlated with pore structure. This study will help to classify the pore structure in the wellbore profile and improve the accuracy of the oil saturation calculation by well logging.

利用传统分区岩相建模方法模拟多个物源方向的储层空间分布时,模拟的砂体在分区边界处多呈突变接触,不符合地质认识.为此,提出了一种多物源储层分区耦合建模方法.首先根据不同物源影响范围将研究区划分为若干区块,然后按一定顺序依次模拟.提取先模拟分区边界上的模拟结果作为相邻后续模拟区块的条件数据,并结合后续模拟区块中的井点数据进行模拟计算,保证了分区边界上模拟砂体的连续性.最终得到整个研究区的砂体模型,模拟的砂体在各个分区边界处均连续分布.以东营凹陷盐家油田盐935-936区块沙四段上亚段为例进行了应用研究,并与传统的分区岩相建模和基于局部变化变差函数建模方法进行对比,结果表明,该分区耦合建模方法可以更真实地构建研究区的三维地质模型,解决了传统分区岩相建模方法存在的各区块边界处砂体突变的问题,提高了建模质量.

Tight sands have pore systems with complex structures and widely distributed pore sizes. We have studied the characteristics of these pore systems to better understand their important role in the accumulation and migration mechanisms of oil and gas reservoirs, which may enhance our ability to evaluate reservoir quality and predict reservoir production. To this end, we carried out thin-section analysis, scanning electron microscopy, pressure-controlled porosimetry (PCP), and rate-controlled porosimetry (RCP) to describe the pore systems of a typical tight-sand reservoir in East Asia. We improved a differential-distribution-based splicing method to reveal the full-scale pore systems using PCP and RCP. We found that the typical pore radius distribution in our target reservoir exhibits two peaks: at radius [Formula: see text] and at radius [Formula: see text]. Based on pore shapes and connections, intergranular pores are network structures and clay-host pores are tree-like structures. Intragranular pores, in contrast, can be different structures under different conditions. If wide throats are present, intragranular pores function as typical tree-like pores; if throats are narrow, they serve as the pore parts of a network-pore system. Network pores are the primary contributors to porosity and permeability, whereas tree-like pores mainly contribute to porosity. In some high-clay sands, however, the tree-like pores may also contribute to permeability. Based on their fractal characteristics, we divided the pore systems of tight sands into three types: (1) a network-structure-controlled intergranular pore system, (2) a tree-like-structure-controlled clay-host pore system, and (3) a network-structure-controlled intergranular-intragranular pore system.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2020Enhancing spatial continuity of seismic facies via fuzzy c-means with cross-entropy constraintsAuthors: Hanpeng CaiYifeng FeiJiandong LiangJun WangZhipeng LiHanpeng CaiUniversity of Electronic Science and Technology of China (UESTC)Search for more papers by this author, Yifeng FeiUniversity of Electronic Science and Technology of China (UESTC)Search for more papers by this author, Jiandong LiangUniversity of Electronic Science and Technology of China (UESTC)Search for more papers by this author, Jun WangResearch Institute of Exploration & Production Shengli Oilfield Branch Co., SINOPECSearch for more papers by this author, and Zhipeng LiResearch Institute of Exploration & Production Shengli Oilfield Branch Co., SINOPECSearch for more papers by this authorhttps://doi.org/10.1190/segam2020-3427108.1 SectionsSupplemental MaterialAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail AbstractSeismic facies analysis mainly uses the differences between seismic signals to classify/cluster the stratigraphic reflection characteristics. Traditional methods view the data points as isolated samples regardless of adjacent seismic traces. This results in poor lateral continuity in the generated facies map. In fact, there is a correlation between the reflection elements of adjacent seismic traces, which can be used as a priori information to provide more information for waveform classification. Therefore, we propose a novel seismic facies analysis method called fuzzy c-means with cross-entropy constraints (FCM-CEC). The correlation of adjacent seismic traces is added as a constraint to the seismic facies analysis. We apply the proposed method to synthetic seismic data and actual seismic data, respectively. The proposed method can obtain a clearer seismic facies boundary.Presentation Date: Tuesday, October 13, 2020Session Start Time: 9:20 AMPresentation Time: 9:20 AMLocation: Poster Station 9Presentation Type: PosterKeywords: facies, reservoir characterization, interpretationPermalink: https://doi.org/10.1190/segam2020-3427108.1FiguresReferencesRelatedDetails SEG Technical Program Expanded Abstracts 2020ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2020 Pages: 3887 publication data© 2020 Published in electronic format with permission by the Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished Online: 30 Sep 2020 CITATION INFORMATION Hanpeng Cai, Yifeng Fei, Jiandong Liang, Jun Wang, and Zhipeng Li, (2020), "Enhancing spatial continuity of seismic facies via fuzzy c-means with cross-entropy constraints," SEG Technical Program Expanded Abstracts : 2295-2299. https://doi.org/10.1190/segam2020-3427108.1 Plain-Language Summary Keywordsfaciesreservoir characterizationinterpretationPDF DownloadLoading ...

The evaluation of the pore structure of tight sandstone reservoirs has a significant influence on the effective exploration and development of tight sandstone oil. Laboratory measurements including scanning electron microscopy (SEM), mercury-injection capillary pressure (MICP), gas adsorption, nuclear magnetic resonance (NMR), and Nano-CT can provide detailed pore structure data. However, only NMR results can be used to evaluate the pore structure in a logging profile due to NMR logging. In this study, the relationships between NMR T2 distribution, pore structure, and pore size of tight sandstone in Chang 7 of the Yanchang Formation, in the Heshui area of the Ordos Basin, are analyzed based on NMR principles. The characteristics of the NMR T2 distribution of different rock samples are analyzed; the sensitive parameters of the NMR T2 spectrum are proposed. These parameters are then used to classify pore structure types in tight sandstone reservoirs and divide the active layers in the logging profile of the study area. The results indicate that different pore size structures have different distributions, and that the NMR T2 spectrum can highlight the difference in the pore structure type and pore size distribution using sensitive parameters such as T2P2 (the value of T2 corresponding to the last peak of the bimodal NMR T2 spectrum) and TDM (the mean value of T2 relaxation time obtained by weighted average method). As the pore structure of the rock samples in the study area worsened, their porosity and permeability worsened, T2P2 and TDM decreased, and the displacement pressure and NMR irreducible water saturation increased. The results of classifying the pore structure types obtained in the logging profile are helpful in evaluating the effectiveness of the reservoir and in the broad application of NMR logging in terms of understanding pore structure.