Exploration Of Reservoirs Research Articles

Genesis of an Inorganic CO2 Gas Reservoir in the Dehui–Wangfu Fault Depression, Songliao Basin, China

This study systematically examines the origins and formation mechanisms of inorganic CO2 gas reservoirs located within the Dehui–Wangfu Fault in the southeastern uplift region of the Songliao Basin. The research aims to clarify the primary sources of inorganic CO2, along with its migration and accumulation processes. The identification of the Wanjinta gas reservoir within the Dehui–Wangfu Fault Zone, abundant in inorganic CO2, has sparked significant interest in the pivotal roles of volcanism and tectonic activity in gas generation and concentration. To analyze the release characteristics of CO2, this study conducted degassing experiments on volcanic and volcaniclastic rock samples from various boreholes within the fault trap. It evaluated CO2 release behaviors and controlling factors across varying temperatures (150 °C to 600 °C) and particle sizes (20, 40, and 100 µm). The findings indicated a negative correlation between CO2 release and particle size, with a notable transition at 300 °C—marking this temperature as critical for the release of adsorbed and lattice gases. Moreover, volcaniclastic rocks exhibited higher CO2 release compared to volcanic rocks, attributable to their larger specific surface area and higher porosity. At 600 °C, the decomposition of the rock crystal structure results in substantial gas escape. These observations suggest that the inorganic CO2 in this area derives not only from mantle sources but is also influenced by crustal components. Elevated temperatures prompted by tectonic activity and magmatic intrusion facilitated the degassing of the surrounding rocks, allowing released CO2 to migrate upwards through the fracture system and accumulate in the shallow crust, ultimately forming a gas reservoir. This study enhances the understanding of volcanic rock’s roles in inorganic CO2 gas generation and migration, highlighting the fracture system’s critical controlling influence on gas transport and aggregation. The findings indicate that inorganic CO2 gas reservoirs in the Dehui–Wangfu Fault Zone primarily originate from mantle sources with a mixture of crustal gases. This discovery offers new theoretical insights and practical guidance for the exploration and development of gas reservoirs in the Songliao Basin and similar regions.

Deeply buried clastic rock diagenesis evolution mechanism of Dongdaohaizi sag in the center of Junggar fault basin, Northwest China

Abstract To reveal the diagenetic sequence of reservoir rocks in the central part of the deep depression basin, the Wuerhe Formation in Junggar Basin was taken as an example to conduct the detailed studies on its sedimentary facies, diagenetic sequence, and the micropore structure evolution rules based on the comprehensive data from a super deep exploration well C-6 (approximately 7,000 m in depth). First, an arid environment fan delta sedimentary model of the Wuerhe Formation was established, and its sedimentary evolution law was clarified as a gradual transition from a fan delta front to a fan delta plain during the water-regression process until the lake dried up. Then, the diagenesis types and evolution sequence of the Wuerhe Formation, and the influence degrees of the compaction, cementation, and dissolution on the rock formation process were clarified. Finally, the diagenesis and pore evolution model was established, and the greatest impact factors of the late reservoir densification were clarified. Based on this research, the diagenesis and pore evolution processes of the deep rocks in the studied deep central sag were ultimately revealed to provide useful guidance for the deeply buried oil and gas reservoir exploration.

Prediction of Thin Shoal Reservoirs Under Reef Controlled by Isochronous Stratigraphic Framework

Despite the great success in the global exploration and development of reef reservoirs, research on bioclastic shoals under reefs is still in its infancy. Bioclastic shoal reservoirs are very thin, with multiple vertical levels and fast lateral changes, which makes accurate prediction of the reservoir’s location much tougher. To further implement the reservoir distribution, under the guidance of sequence stratigraphy, the prediction of thin shoals under the control of an isochronous stratigraphic framework was established. Using the combination of spectrum shaping and F-X domain noise suppression techniques and utilizing the signal-to-noise ratio spectrum set as the reference, logging curve as supervision, and well seismic calibration and isochronal amplitude slicing as quality control, the seismic frequency band was extended, and the seismic data resolution and signal-to-noise ratio were improved. After frequency extension, the global optimal seismic automatic interpretation technique was used to construct an isochronal stratigraphic framework model. Through waveform facies-controlled inversion and waveform facies-controlled simulation techniques, the elastic properties of the shoal reservoir were obtained, from which the planar distribution of the reservoir was accurately predicted. The above methods were applied to the prediction of the bioclastic shoal reservoir in the lower submember of the Changxing formation in the Yuanba gas field (China). The plane distribution of bioclastic shoal in the first and second levels was identified, which provides a guideline for the prediction of thin shoal reservoirs.

Effects of supercritical CO2, water, and supercritical CO2-based water on the mechanical properties and fracturability of shale

The study of the effects of supercritical CO2 (ScCO2) under high temperature and high pressure on the mechanical properties and fracturing potential of shale holds significant implications for advancing our understanding of enhanced shale gas extraction and reservoir exploration and development. This study examines the influence of three fluids, i.e. ScCO2, deionized water (DW), and ScCO2+DW, on the mechanical properties and fracturability of shale at immersion pressures of 15 MPa and 45 MPa, with a constant temperature of 100 °C. The key findings are as follows: (1) Uniaxial compressive strength (UCS) of shale decreased by 10.72%, 11.95%, and 23.67% at 15 MPa, and by 42.40%, 46.84%, and 51.65% at 45 MPa after immersion in ScCO2, DW, and ScCO2+DW, respectively, with the most pronounced effect observed in ScCO2+DW; (2) Microstructural analysis revealed that while ScCO2 and DW do not significantly alter the microstructure, immersion in ScCO2+DW results in a more complex surface morphology; (3) Acoustic emission (AE) analysis indicates a reduction in stress for crack damage, with a decreased fractal dimension of AE signals in different fluids. AE energy is primarily generated during the unstable crack propagation stage; (4) A quantitative method employing a multi-factor approach combined with the brittleness index (BI) effectively characterizes shale fracturability. Evaluation results show that ScCO2+DW has a more significant effect on shale fracturability, with fracturability indices of 0.833% and 1.180% following soaking at 15 MPa and 45 MPa, respectively. Higher immersion pressure correlates positively with increased shale fracturability.

Untapped potentials exploration for deep-marine gas-bearing reservoirs: a case study from the Taranaki Basin

Untapped potentials exploration for deep-marine gas-bearing reservoirs: a case study from the Taranaki Basin

Improved Fracture Permeability Evaluation Model for Granite Reservoirs in Marine Environments: A Case Study from the South China Sea

Permeability is a crucial parameter in the exploration and development of oil and gas reservoirs, particularly in unconventional ones, where fractures significantly influence storage capacity and fluid flow. This study investigates the fracture permeability of granite reservoirs in the South China Sea, introducing an enhanced evaluation model for planar fracture permeability based on Darcy’s law and Poiseuille’s law. The model incorporates factors such as fracture heterogeneity, tortuosity, angle, and aperture to improve permeability assessments. Building on a single-fracture model, this research integrates mass transfer equations and trigonometric functions to assess intersecting fractures’ permeability. Numerical simulations explore how tortuosity, angle, and aperture affect individual fracture permeability and the influence of relative positioning in intersecting fractures. The model makes key assumptions, including minimal consideration of horizontal stress and the assumption of unidirectional laminar flow in cross-fractures. Granite outcrop samples were systematically collected, followed by full-diameter core drilling. A range of planar models with varying fracture apertures were designed, and permeability measurements were conducted using the AU-TOSCAN-II multifunctional core scanner with a steady-state gas injection method. The results showed consistency between the improved model and experimental findings regarding the effects of fracture aperture and angle on permeability, confirming the model’s accuracy in reflecting the fractures’ influence on reservoir flow capacity. For intersecting fractures, a comparative analysis of core X-ray computed tomography (X-CT) scanning results and experimental outcomes highlighted discrepancies between actual permeability measurements and theoretical simulations based on tortuosity and aperture variations. Limitations exist, particularly for cross-fractures, where quantifying complexity is challenging, leading to potential discrepancies between simulation and experimental results. Further comparisons between core experiments and logging responses are necessary for model refinement. In response to the challenges associated with evaluating absolute permeability in fractured reservoirs, this study presents a novel theoretical assessment model that considers both single and intersecting fractures. The model’s validity is demonstrated through actual core experiments, confirming the effectiveness of the single-fracture model while highlighting the need for further refinement of the dual-fracture model. The findings provide scientific support for the exploration and development of granite reservoirs in the South China Sea and establish a foundation for permeability predictions in other complex fractured reservoir systems, thereby advancing the field of fracture permeability assessment.

Faulted karst reservoir spaces in Middle-Lower Triassic carbonates, Qingjiang Region, Yangtze block, China

The complexity and heterogeneity of ultra-deep faulted karst reservoirs pose significant challenges for hydrocarbon exploration. In this study, we integrated remote sensing image analysis, field measurements, and core sample testing to evaluate the characteristics and controlling factors of carbonate reservoir spaces within the Middle and Lower Triassic formations along a regional strike-slip fault in the Qingjiang region of China. The strike-slip fault zone is composed of multiple fault cores and damage zones. Based on differences in damage zone width and linear fault density, the fault zone was subdivided into transtensional and transpressional segmentations. The carbonate reservoirs, primarily developed within the damage zones, consist of fractures, fracture clusters, and cavities. Detailed measurements of the carbonate outcrops were conducted to obtain geometric parameters of the reservoir spaces. Quantitative results indicate that in the transtensional segmentation, the reservoir is dominated by tensile fracture-cavity systems, characterized by larger fracture apertures (0.13–1.25 m), higher linear fracture density (0.38–8.37 m⁻1), and well-developed cavities (0.03–4.84 m2), which contribute to better fluid connectivity and storage capacity. In contrast, the transpressional segmentation is dominated by compressional fracture-fracture cluster systems, with longer fractures (0.11–12.52 m), smaller fracture apertures (0.01–0.94 m), and extensive fracture clusters development (0.18–17.87 m2), but with lower fluid connectivity and limited storage capacity. Mechanical testing results show that the average compressive strength in the transtensional segmentation (133.95 MPa) is significantly higher than that in the transpressional segmentation (70.28 MPa). In terms of mineral composition, the transtensional segmentation has a higher calcite content, whereas the transpressional segmentation is richer in dolomite and quartz. Based on the observed differences in reservoir space characteristics across the strike-slip fault zone, we discussed the combined effects of structural segmentation, formation thickness, rock mechanics, and brittle mineral content on reservoir space development. The study emphasizes that stress conditions (primary factor) and material properties (secondary factor) jointly control fluid migration and storage efficiency in the reservoirs. Additionally, we suggest that the outcrop studies in the Qingjiang region provide valuable geological analogs for faulted karst reservoirs, offering critical insights for improving the precision of carbonate reservoir exploration and optimizing production efficiency.

A hybrid denoising method for low-field nuclear magnetic resonance data

Low-field nuclear magnetic resonance (NMR) has broad application prospects in the exploration and development of unconventional oil and gas reservoirs. However, NMR instruments tend to acquire echo signals with relatively low signal-to-noise ratio (SNR), resulting in poor accuracy of T2 spectrum inversion. It is crucial to preprocess the low SNR data with denoising methods before inversion. In this paper, a hybrid NMR data denoising method combining empirical mode decomposition-singular value decomposition (EMD-SVD) was proposed. Firstly, the echo data were decomposed with the EMD method to low- and high-frequency intrinsic mode function (IMF) components as well as a residual. Next, the SVD method was employed for the high-frequency IMF components denoising. Finally, the low-frequency IMF components, the denoised high-frequency IMF components, and the residual are summed to form the denoised signal. To validate the effectiveness and feasibility of the EMD-SVD method, numerical simulations, experimental data, and NMR log data processing were conducted. The results indicate that the inverted NMR spectra with the EMD-SVD denoising method exhibit higher quality compared to the EMD method and the SVD method.

Geochemical Characteristics and Significance of Molecular Markers in the Paleogene-Neogene Crude Oils of the Northwest Qaidam Basin.

The western Qaidam Basin is rich in oil and gas resources, constituting over 90% of the total oil and gas resources in the whole basin. However, the regional distribution characteristics of molecular markers of crude oil and the petroleum system elements relevant to the distribution of oil and gas in the northwest Qaidam Basin are still unclear, which restricts further exploration of oil and gas reservoirs. A total of 38 crude oils were collected from the Xiaoliangshan Sag and Mangya Sag in the northwest Qaidam Basin and analyzed by gas chromatography-mass spectrometry (GC-MS). The indicators of sedimentary environment, organic matter source, and thermal maturity show regular changes from the west to the east in the Xiaoliangshan Sag and Mangya Sag. The nC21 -/nC22 +, n(C21 + C22)/n(C28 + C29), and C27-C28-C29 regular sterane distribution characteristics indicate that the input proportion of lower aquatic organisms in source rocks (E3-N1) gradually increases, while the input proportion of terrigenous organic matter gradually decreases. The triaromatic dinosterane index (TDSI) and methyltriaromatic steroid index (MTDSI) indicate that the input proportion of dinoflagellates gradually increases. The gradual increase in the Pr/Ph ratio indicates a decrease in the reducibility of the sedimentary environment of source rocks. The gammacerane index (Ga/C30H) and methylated-2-methyltrimethyltride-cylchromans (MTTCs) indicate that the degree of stratification and salinity of water body gradually decrease. A total of 23 thermal maturity parameters indicate that crude oil is in a mature evolution stage, and the thermal maturity of crude oil increases with depth, indicating that there are the characteristics of hydrocarbon accumulation close to source rocks. The variation features of sedimentary environment, organic matter origin, and thermal maturity indicators from the west to the east in the Xiaoliangshan Sag and Mangya Sag are controlled by the sedimentary structure characteristics of the study area.

Coupled Effects of Paleofluid Evolution on Ultra-deep Microbialite Reservoir Modification: A case study of the upper Ediacaran Deng-2 Member within the Penglai area of central Sichuan Basin, SW China

Paleofluid-rock interaction results in the modification of the ultra-deep reservoir quality, but the coupling effects of the paleofluid evolution on reservoir quality modification are still underestimated. Here, the multi-stage dolomite cements have been studied by means of core observations, thin section identification, fluid inclusions, and in situ elements and isotopic analyses in order to reaveal the paleofluid evolution processes and their effects on the reservoir quality. The fibrous dolomite cement (FDC) and bladed dolomite cement (BDC) both have similar geochemical properties and homogenization temperature (Th) to the matrix dolostone. Subsequent early silicification occurs (QZ1). However, silt- to fine-sized crystalline dolomite cement (CD2) has higher concentration of Fe and medium rare earth element, more negative δ18O than for FDC and BDC, and 103.4 to 150.2 °C in Th. The first petroleum charge episode solid bitumen 1 (SB1) followed the CD2. The medium to coarse sized crystalline dolomite cement (CD3) is characterized by the higher Mn and lower Sr concentration than CD2, positive δEu anomaly, negative δ13C and δ18O, high 87Sr/86Sr ratio and 138.9 °C to 184.3 °C in Th. The solid bitumen 2 (SB2) occurs after CD3. Subsequently, the saddle dolomite (SD) has higher Fe and Mn concentration and lower Na and Sr than others cement, δEu positive anomaly, negative δ13C and δ18O, high 87Sr/86Sr ratio and 177.5 °C to 243.6 °C in Th. Eventually massive silicification (QZ2) took place. The FDC, BDC, QZ1 and SB1 formed in the early diagenetic stage and have little negative effect on the reservoir quality. But the CD2 and CD3 dramatically decreased the reservoir quality related to a quantity of hydrothermal fluids entrance in the mesodiagenetic stage along the strike-slip faults and the unconformity surface at top of the Deng-2 Member during the late stage of the Caledonian orogeny. The reservoir spaces were retained and enlarged during the late diagenetic stage when the peak petroleum charge occurred, massive silicification and thermochemical sulphate reduction took place with SB2, SD and QZ2 being formed. The research outcome may update our understanding on the retention mechanism and the insights for further hydrocarbon exploration of Precambrian ultra-deep microbial reservoirs.

Integrated Seismic Attributes as a Tool to Delineate the Oligocene Channels Architecture, Baltim Field, Offshore Central Nile Delta, Egypt

The hydrocarbons in the Nile Delta area are produced from both clastic and non-clastic reservoirs, with ages ranging from the Early Cretaceous to the Plio-Pleistocene. The study area is situated in Baltim field offshore, Central Nile Delta, approximately 10 kilometers off the Egyptian coast (Fig. 1). The main producing reservoir in Baltim field is Abu Madi Formation (Miocene age) as there were many discoveries in the last decades resulting in most of the area had been considered as a brown field. Nowadays, the Oligocene section is considered as the hope for new hydrocarbon potentiality in the deep section (below Miocene). Among the drilled sedimentary sequence in the Nile Delta, Tineh Formation (Oligocene age) contains multiple levels of reservoir rocks with high-quality reservoirs including: Satis-1, Satis-3, Notus-1, Tineh-1, Atoll-1 & Salamat-1 (Fig. 2). This work's objective is to delineate the different channels of the Oligocene section in trial to add more reserves to the field. One of the main challenges for the exploration of these deep reservoirs is to delineate the reservoir geometry itself. A strong tool for improving bed thickness imaging and mapping, geologic discontinuities and channel delineation is the spectral decomposition technique providing more details than the conventional amplitude extractions. So, in this work, we applied the spectral decomposition tool to track the geometric dimensions of the Oligocene channels. RGB color blending performed from 10, 16, and 20 Hz represents the most significant geological features to get a better picture of the channel’s geometry. After determining the channel’s boundary by using the RGB blending, the channel geo-body was extracted. This technique helps in reducing the uncertainties of hydrocarbon exploration. Consequently to the integration between RMS amplitude maps and the channel geo-body that was extracted from the spectral decomposition, Oligocene channels became clearer and the boundaries well defined.

Research on the Biogas Production Mechanism of Mudstone in the Qaidam Basin under Different CO2 Pressures.

Mudstone, a class of sedimentary rocks rich in organic matter, possesses considerable potential for biogas production. Mudstones possess a rich biological origin, which is conducive to refining the mechanisms and enrichment patterns of biogenic gas reservoirs. This has significant theoretical and practical implications for guiding the exploration and development of Quaternary mudstone gas reservoirs. Furthermore, the Qaidam Basin is an excellent place for the geological storage of CO2 due to its rich petroleum reservoir conditions. Experimental research on biogas production under diverse CO2 pressure-mudstone-microorganism-water interactions is conducted to determine the biogas production mechanism of mudstone under different CO2 pressures during sequestration circumstances. According to the results: (1) under supercritical carbon dioxide conditions, there is a slight initial increase in biogas production, followed by a gradual decrease. The periods and peaks of gas production vary among the different reaction groups. As carbon dioxide pressure increases, the gas production cycle lengthens significantly, while the gas yield declines. (2) Siderite and secondary carbonate minerals have increased in the mudstone's mineral fraction both before and after biogas production, while clay mineral groups have decreased. Specifically, there was a notable drop in chlorite and kaolinite. (3) Microorganism species in the system were analyzed, and the results showed that there was a gap in each microorganism's ability to adapt to its surroundings, and the diversity and quantity of bacteria declined with increasing pressure. After carbon dioxide was fluxed, there was a considerable shift in the pattern of biogas generation, which consequently had a major impact on the alterations in mineral fractions.

Segmentation characteristics of strike-slip fault zone and its reservoir control mechanisms in the southwestern Tarim Basin

Understanding how fault-related structures influence oil and gas accumulation is crucial for geological investigations and exploration planning. This study, based on 3D seismic data, analyzes the northeast-trending strike-slip fault zone in the eastern part of the Bachu Uplift. Automatic fault extraction techniques were employed to delineate the strike-slip fault zone, and the parallel bedding indicator was used to identify reservoirs and investigate the fault’s segmented features and reservoir-controlling characteristics. The results show that the northeast-trending strike-slip fault is primarily governed by simple shear stress and conforms to the Riedel shear model. Three distinct structural styles were developed: vertical, pull-apart, and push-up segments, each exhibiting varying profile characteristics and planar patterns. The segmentation of the strike-slip fault controls the distribution of Ordovician fault-karst reservoirs. An oil and gas enrichment model for the strike-slip fault zone has been established, characterized by external hydrocarbon supply, fault-mediated migration, segmented reservoir control, and high-elevation accumulation. This study offers valuable insights for the exploration of fault-karst reservoirs controlled by strike-slip faults.

Effective application of geological process modeling for unravelling carbonate build-up complexity: A case study from the EX-Carbonate build-up in central Luconia Province, Malaysia

In the dynamic field of carbonate reservoir Exploration, the need for specialized models is vital, assisting as a key tool to facilitate interdisciplinary collaboration and enhance strategies for predicting reservoir behavior. This study examines the use of geological process (GPM), a standard tool to simulate forward stratigraphic modelling, particularly focusing on the Central Luconia Province in the South China Sea. Central Luconia Province stands out for its extensive carbonate build-ups and is recognized as a prolific hydrocarbon reservoir. Forward Stratigraphic Modelling (FSM) leads to a paradigmatic change in geological modeling. Unlike geostatistical models controlled by geometrical parameters, FSM relies on mathematical representations of the physical rules determining erosion, transport, and sedimentation in carbonate growth. This tool, supported by various researchers, has proven its ability in quantitative sedimentary system analysis across diverse temporal and spatial scales. This study located in EX Field showcases the ability of stratigraphic forward modeling in replicating sedimentary complexities and resulting stratigraphic architecture of the EX isolated carbonate platform. The methodology links parameters from existing literature with multiscale data. Additionally, carbonate production laws, contingent on water depth, play a pivotal role in the meticulous modeling process. This work illustrates the efficacy of geological process modelling as a transformative approach for unraveling the complexities of carbonate systems, particularly in regions with prolific hydrocarbon reservoirs like Central Luconia. The incorporation of literature-derived parameters and multiscale data serves as evidence of the model's ability to offer nuanced understandings of the dynamic evolution of carbonate platforms, thereby advancing our understanding of reservoir prediction and future management strategies.

Seismic Facies-Controlled Porosity Prediction in a Tight Sandstone Reservoir Based on the XGBoost Algorithm

Porosity is one of the most important properties for evaluating hydrocarbon reservoirs. There is a strong nonlinearity between seismic data and rock physical properties. Machine learning methods possess the powerful ability to capture complex nonlinear relationships between these two parameters, holding significant potential for porosity prediction in tight sandstone reservoirs. In this study, we propose a seismic facies-controlled porosity prediction method based on the extreme gradient boosting algorithm. Through seismic meme inversion method,we obtain high-resolution P-impedance data. In the inversion process, lateral variations of seismic waveforms were utilized instead of the variogram function. We create labels for model training using porosity curves and borehole side P-impedance data, applying them to the extreme gradient boosting regressor. To demonstrate its feasibility, we apply the model to a real 3D case from an oil field in the Songliao Basin. Our application results demonstrate that this method can provide porosity predictions for tight sandstone reservoirs, maintaining consistency with seismic waveforms and adhering to seismic facies control patterns. The method uses only acoustic travel time, density, gamma rays, and spontaneous potential well-log data and post-stack 3D seismic data as inputs, allowing for quick porosity predictions in the field. Compared to the seismic facies-controlled inversion combined with support vector machine and multi-Layer perceptron methods, the method proposed in this study provides more reliable porosity predictions, offering insights and references for the exploration and development of tight sandstone reservoirs.

Reservoir oriented migrated seismic image improvement and poststack seismic inversion using well-seismic mistie

In seismic exploration of subsurface hydrocarbon reservoirs, migrated seismic image is the foundation for structural interpretation and subsequent seismic inversion for reservoir properties. Seismic events in migrated images can be mispositioned due to several factors including seismic velocity inaccuracy. The mispositioned events lead to poor well-seismic tie and degrades the accuracy of subsequent inversion and reservoir prediction. Particularly, the mistie can be quite obvious for the mid- and mature- phases of the reservoir development after many wells drilled. We propose to utilize the information from mistie between seismic images and synthetic traces to improve the accuracy of migrated seismic images and thus inversion results. Our method includes three major steps: firstly, calculate time shifts between the synthetic traces and the co-located seismic trace using the path-limited dynamic time warping (PDTW) algorithm; then compute the time shift volume for the entire migrated image using the seismic-driven modeling approach based on the time shift traces at the well locations; apply the time shift volume to update the migrated image. The improved seismic volume can be used for further processing such as seismic inversion, which makes the inversion results more consistent with seismic and well data. We apply our method to synthetic and field datasets. The results demonstrate that the updated seismic image has an improved seismic well tie and an improved inversion result. Our method indicates a venue for a better honor of seismic and well data in reservoir characterization.

Pore structure of the mixed sedimentary reservoir of Permian Fengcheng Formation in the Hashan area, Junggar Basin

The Permian Fengcheng Formation (P1f.) in the Hashan area, situated on the southwestern margin of the Junggar Basin, has witnessed a remarkable breakthrough in shale oil exploration in recent years with nearly 789 million tons of shale oil resources. As a unique set of mixed sedimentary shales, the Fengcheng Formation in the Hashan area is characterized by mixed sedimentation of terrigenous siliciclastic sediments, authigenic minerals, and tuffaceous materials. However, the understanding of pore characteristics in the mixed sedimentary reservoir still remains limited, prohibiting accurate estimation of the oil content and insights into oil mobility. Scanning electron microscopy (SEM), X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), X-Ray Computer Tomography (X-CT), and geochemical analysis were performed to investigate the pore size distribution and main controlling factors of the mixed sedimentary reservoir. Results showed that the main pore types in the mixed sedimentary reservoir are intergranular pores and dissolution pores. The pores of the P1f. mixed shales in the Hashan area were classified into II-micropores (< 25 nm), I-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (> 1000 nm). In general, the mixed sedimentary rocks of P1f. formation feature few macropores but a large number of micropores and mesopores. The CS exhibits the most favourable physical properties among all lithofacies. It is concluded that the abundance and maturity of organic matter, mineral composition, sedimentary structure, and diagenesis of reservoir together impact the pore structure in the mixed sedimentary reservoirs. The maturity of organic matter and the content of tuffaceous minerals are the most significant in influencing the pore structure of P1f. shales. Overall, the pore structure of complex lithologic reservoir formed by mixed deposition and its influence on physical properties are studied, and the characteristics of the microscopic pore-throat system of the dominant lithofacies in the Hashan area are clarified, which is of great significance as a guide for the exploration and development of mixed sedimentary reservoirs in continental shale oil in China.

Dipole acoustic remote detection (ARD) logging and its application in fracture-cave reservoir

Abstract Oil and gas from deep reservoirs are mostly enriched in the fracture-cave reservoirs. For this reason, fine evaluation of large-scale fracture-cave and effective detection of small scale fracture-cave are the key issues to be solved in the exploration of fracture-cave type carbonate reservoirs. The acoustic remote detection logging technology is based on acoustic reflection method to continuously image the formation around the well. The cross dipole array sonic data can be processed to image geological anomalies within a range of about 20 meters outside the well. Dipole S wave remote detection has the remarkable advantages of low emission frequency and larger investigation depth, but it has 180 degrees’ azimuthal ambiguity. This study is based on previously developed far field dipole S wave remote detection tool, finite difference is performed on formation models with and without are obtained for representative fracture-cave formations and remote detection processing and interpretation software is updated. These are applied on a well in the northwestern area. Through the comprehensive analysis of remote logging, conventional logging, electrical imaging logging and seismic data of the fracture-cave geological anomalies, a fine picture of the morphology and development of the geological anomalies from the near wellbore to the far end is formed

Intelligent seismic AVO inversion method for brittleness index of shale oil reservoirs

The brittleness index (BI) is crucial for predicting engineering sweet spots and designing fracturing operations in shale oil reservoir exploration and development. Seismic amplitude variation with offset (AVO) inversion is commonly used to obtain the BI. Traditionally, velocity, density, and other parameters are firstly inverted, and the BI is then calculated, which often leads to accumulated errors. Moreover, due to the limited of well-log data in field work areas, AVO inversion typically faces the challenge of limited information, resulting in not high accuracy of BI derived by existing AVO inversion methods. To address these issues, we first derive an AVO forward approximation equation that directly characterizes the BI in P-wave reflection coefficients. Based on this, an intelligent AVO inversion method, which combines the advantages of traditional and intelligent approaches, for directly obtaining the BI is proposed. A TransU-net model is constructed to establish the strong nonlinear mapping relationship between seismic data and the BI. By incorporating a combined objective function that is constrained by both low-frequency parameters and training samples, the challenge of limited samples is effectively addressed, and the direct inversion of the BI is stably achieved. Tests on model data and applications on field data demonstrate the feasibility, advancement, and practicality of the proposed method.

Characterization of fault-karst reservoirs based on deep learning and attribute fusion

AbstractThe identification of fault-karst reservoir is crucial for the exploration and development of fault-controlled oil and gas reservoirs. Traditional methods primarily rely on well logging and seismic attribute analysis for karst cave identification. However, these methods often lack the resolution needed to meet practical demands. Deep learning methods offer promising solutions by effectively overcoming the complex response characteristics of seismic wave fields, owing to their high learning capabilities. Therefore, this research proposes a method for fault-karst reservoir identification. Initially, a comparative analysis between the improved U-Net++ network and traditional deep convolutional networks is conducted to select appropriate training parameters for separate training of karst caves and faults. Subsequently, the trained models are applied to actual seismic data to predict karst caves and faults within the research area, followed by attribute fusion to acquire data on fault-karst reservoirs. The results indicate that: (1) The proposed method effectively identifies karst caves and faults, outperforming traditional seismic attribute and coherence methods in terms of identification accuracy, and slightly surpassing U-Net and FCN; (2) The fusion of predicted karst caves and faults yields clear delineation of the relationship between top karst caves and bottom fractures within the research area. In summary, the proposed method for fault-karst reservoirs identification and characterization provides valuable insights for the exploration and development of fault-controlled oil and gas reservoirs in the region.