Water cut is a critical parameter in reservoir evaluation because it strongly influences residual oil estimates. Conventional water cut calculation methods often lack effectiveness in complex reservoirs, leading to low prediction accuracy. This study addresses the Triassic Chang 8 Formation in the Hongde region by proposing an empirical water cut prediction method that uses nuclear magnetic resonance (NMR) logging to improve precision. The methodology comprises several steps: first, combining NMR measurements and relative permeability experiments on 20 core samples clarified the impact of pore structure on relative permeability, and an NMR T2-derived parameter was defined to quantify pore structure. Subsequently, the target formation was classified into three formation types, and a relative permeability prediction model was developed for each type using NMR logging. Following this, models were established to estimate water saturation, irreducible water saturation, and irreducible oil saturation so these inputs could be derived from conventional well logging data. Finally, a formula for calculating reservoir water cut based on Darcy’s law was derived and applied to field data in the target reservoirs to predict water cut continuously. Comparison of predicted water cut values with drill stem test data demonstrated the efficacy of the proposed model, achieving an accuracy of 83.3

ABSTRACT Accurate evaluation of fracture effectiveness and activity in buried‐hill reservoirs remains challenging because fracture development is commonly controlled by multi‐stage tectonic overprinting, lithological heterogeneity, weathering‐related mechanical contrasts and complex present‐day stress fields. These difficulties are, particularly, pronounced in buried‐hill intervals composed of crystalline basement rocks, metamorphic or igneous lithologies and weathered fractured zones, where fracture density alone is insufficient to determine reservoir effectiveness. To address this problem, this study develops a geomechanics‐constrained and interval‐specific workflow for evaluating fracture activity and effectiveness within buried‐hill reservoirs. The proposed approach integrates laboratory‐derived rock mechanical parameters, log‐based dynamic–static elastic parameter calibration, seismic structural interpretation, lithology‐constrained three‐dimensional geomechanical modelling and fracture‐scale stress analysis. The workflow explicitly links buried‐hill lithological subdivision, present‐day stress tensor reconstruction, fracture orientation characterisation and three‐dimensional Mohr stress analysis. Different buried‐hill lithologies and weathering zones are assigned distinct mechanical parameters to better represent the vertical and lateral heterogeneity of the reservoir interval. The numerical stress model is iteratively constrained by measured in situ stress data, wellbore information and structural interpretation to improve mechanical consistency. Fracture activity is quantitatively evaluated by resolving the normal and shear stresses acting on mapped fracture sets under the present‐day stress regime, whereas fracture effectiveness is assessed by jointly considering fracture orientation, stress state, lithological layering and mechanical stratification. Model predictions are further validated using borehole image logs, drilling responses and production performance, allowing effective fracture intervals within the buried hill to be identified more reliably. The results show that effective fractures in buried‐hill reservoirs are primarily controlled by stress–structure–lithology coupling rather than by fracture density alone. Fractures that are critically oriented with respect to the present‐day stress field and hosted in mechanically favourable lithological or weathered intervals exhibit higher activation potential and better agreement with observed fracture development and well productivity. This study provides a more geologically constrained, mechanically consistent and interval‐specific framework for fracture effectiveness evaluation in buried‐hill reservoirs. The proposed workflow improves the linkage among geological interpretation, geomechanical simulation, fracture activity assessment and reservoir performance prediction and, therefore, offers practical guidance for sweet‐spot identification and development optimisation in fractured buried‐hill systems.

Shallow gas reservoirs exhibit low formation pressure and gas injection levels, leading to low-resistivity contrast between gas-bearing reservoirs and fully water-saturated layers. Gas-bearing formation identification and water saturation estimation face great challenges. To improve the accuracy of shallow gas reservoir identification and logging evaluation, it is essential to analyze the genesis mechanisms underlying the low-resistivity contrast. This study used the HJ Formation, a typical shallow gas reservoir located in the BY Sag of the eastern South China Sea Basin as an example. Combining the results of nuclear magnetic resonance (NMR), full rock mineral analysis and X-ray diffraction of clay minerals in the laboratory, it was determined that the genesis mechanism for the low-resistivity contrast in the gas-bearing reservoir was due to the high irreducible water saturation (Swi) and the cation-induced supplementary conductivity. Afterwards, we integrated three methods, density–neutron correlation, calculation of the apparent formation water resistivity, and cross-plots of conventional and gas-logging curves, to identify shallow gas reservoirs. In addition, we also established a Waxman–Smits-based model to estimate water saturation. Compared with the typical Archie’s equation, the predicted water saturation curve using the Waxman–Smits-based model was more reasonable. The established methods and models can be used in target shallow gas reservoir evaluations, and it also has reference value for other types of oilfields with similar physical characteristics.

CH4 production rate of coalbed methane (CBM) well decreases rapidly during primary recovery in the deeply buried coal seam, resulting in a lot of CH4 residues. CO2 pour into deep coal seam with high stress sensitivity is available for enhancing CH4 recovery by improving permeability for reservoir fracture and displacing CH4 adsorbed in matrix. A coupled adsorp-hydro-thermo-mechanical (AHTM) model for deep methane development is established by considering the coupling relationships of non-isothermal and non-constant pressure competitive adsorption between CO2 and CH4, multi-phase flow, unsteady diffusion, heat transmission and in-situ stress variety. The model is verified by historical production and then used for CO2 enhanced CBM (CO2-ECBM) of deep coal reservoir in a sedimentary basin in Northwest China. The simulation results show that: (1) For primary recovery, permeability in coal reservoir drops rapidly with the development of CBM, which seriously restricts the production of CH4. The permeability of the reservoir decreases from 7.89 × 10−16 m2 to less than 1.50 × 10−16 m2, CH4 production rate in CBM well reduces to below 2000 m3/d, and the average total CH4 content of coal reservoir is reduced by 5.49 m3/t with the decrease of only 1.12 m3/t of average adsorbed CH4 in a production duration of 2000 d (2) With 10 MPa CO2 continuous injection into coal seam after 700d of primary, the permeability for reservoir and CH4 production rate increase while the total CH4 content and adsorption CH4 content in reservoir decrease compared with the primary recovery. (3) CO2 pouring into coal reservoir increases the CH4 production time and rate, which improves CH4 recovery of coal reservoir. And it increases by 23.36 %, 23.07 % and 22.46 % with shut-in thresholds of CH4 production rate of 1000 m3/d, 800 m3/d and 600 m3/d, respectively. The investigation is of great significance for the development of deep coalbed methane.

The viscosity of crude oil plays a pivotal role in the exploration and development of oil fields. The predominant reliance on laboratory measurements, which are constrained by manual expertise, represents a significant limitation in terms of efficiency. Two-dimensional nuclear magnetic resonance (NMR) logging offers a number of advantages over traditional methods. It is capable of providing faster measurement rates, as well as insights into fluid properties, which can facilitate timely adjustments in oil and gas development strategies. This study focuses on the loose sandstone reservoirs with high porosity and permeability containing heavy oil in the Huabei oilfield. Two-dimensional nuclear magnetic resonance (NMR) measurements and analyses were conducted on saturated rocks with different-viscosity crude oils and varying oil saturation levels, in both natural and artificial rock samples. This study elucidates the distribution patterns of different-viscosity crude oils within the two-dimensional NMR spectra. Furthermore, the T1 and T2 peak values of the extracted oil signals were employed to establish a model correlating oil viscosity with NMR parameters. Consequently, a criterion for determining oil viscosity based on two-dimensional NMR was formulated, providing a novel approach for estimating oil viscosity. The application of this technique in the BQ well group of the Huabei oilfield region yielded an average relative error of 15% between the actual oil viscosity and the computed results. Furthermore, the consistency between the oil types and the oil discrimination chart confirms the reliability of the method. The final outcomes meet the precision requirements for practical log interpretation and demonstrate the excellent performance of two-dimensional nuclear magnetic resonance (NMR) logging in calculating oil viscosity. The findings of this study have significant implications for subsequent exploration and development endeavors in the research area’s oilfields.

The conventional Archie formula struggles with the interpretation of water saturation from resistivity well log data due to the increasing complexity of exploration targets. This challenge has prompted researchers to explore alternative physical parameters, such as acoustic characteristics, for breakthroughs. Clarifying the influencing factors of porous media acoustic characteristics is one of the most important approaches to help understanding the mechanism of acoustic characteristics of carbonate reservoirs. The article uses digital rock technology to characterize the pore structure, quantitatively identify fractures and pore structures in carbonate rocks, and establish digital models. Through conventional acoustic testing, the pressure wave (P-wave) and shear wave (S-wave) velocities of rock samples at different water saturations are obtained, and the dynamic elastic modulus is calculated. A finite element calculation model is established using the digital rock computational model to provide a basis for fluid saturation calculation methods. Based on real digital rock models, different combinations of virtual fractures are constructed, and factors affecting acoustic parameters are analyzed. The study finds that as porosity increases, the velocity difference between porous cores and fractured cores also increases. These findings provide important technical support and a theoretical basis for interpreting acoustic well logging data and evaluating carbonate reservoirs with different pore and fracture types.

The imbibition law of the Jurassic continental shale in Fuxing area is not clear， which brings great challenges to the production test after well shut-in. In addition， studies on the imbibition law and influencing factors of continental shale are insufficient. Therefore， the experiment on the imbibition law of the Jurassic continental shale in Fuxing area was conducted based on the low-field nuclear magnetic resonance （NMR）. First， the differences in physical properties of shale of Lianggaoshan Formation and Dongyuemiao Member in Ziliujing Formation were tested and analyzed. Then， the changes in permeability and porosity before and after the imbibition were set as the evaluation indexes， and the influences of lithology， fluid， fluid pressure， and clay content on the imbibition law of the continental shale were analyzed. Besides， the wettability of the continental shale was evaluated. The experimental results show that compared with that of Dongyuemiao Member， the average porosity of shale of Lianggaoshan Formation is smaller， and the average permeability is larger； the average brittle mineral content is higher， and the average clay mineral content is lower. During the imbibition process of the Jurassic continental shale in Fuxing area， micro-fractures are induced by clay hydration， which provides additional imbibition channels. However， the imbibition ability of limestone is weaker than that of shale， and there are no micro-fractures during the imbibition； in addition， the shell limestone interlayer in the reservoir may inhibit the imbibition and micro-fracture propagation in the shale. The oil phase will enhance the micro-fracture propagation after the shale induces micro-fractures in the aqueous phase， and the complicated oil-water phase imbibition may be beneficial to the permeability improvement in the shale reservoir. Compared with atmospheric imbibition， pressureed imbibition has a limited effect on inducing micro-fractures and improving permeability， and the imbibition rate is larger； the imbibition equilibrium is earlier， but the imbibition amount is smaller. The influence of confining pressure on imbibition should be considered during well shut-in. The micro-fractures induced by hydration in shale with high clay mineral content are more significant， and the effect of improving permeability is more obvious. The imbibition rate and imbibition amount of shale in the oil phase are smaller than those in the aqueous phase， and the wettability of shale is hydrophilic. The experiment reveals the imbibition law and the characteristics of micro-fractures induced by the hydration of the Jurassic continental shale in Fuxing area， which provides a theoretical basis for the well shut-in and production test of continental shale during flowback.

Summary Permeability is a crucial parameter in formation evaluation, which reflects reservoir fluid mobility and directly influences subsequent development and production. In conventional to tight sandstone formations without fractures, numerous methods have been developed to predict permeability. However, permeability prediction accuracy based on the current method is low in fractured tight sandstone reservoirs due to the influence of heterogeneity, and little research is focused on permeability evaluation in such reservoirs. Conventional wireline and nuclear magnetic resonance (NMR) logging lose their role in fracture parameter evaluation, whereas electrical imaging logging is available for reflecting fracture information. Hence, we adopt electrical imaging logging, instead of conventional wireline and NMR logging, to predict permeability in fractured tight sandstone reservoirs. In this study, we propose a morphological method for permeability prediction using electrical imaging logging. Initially, we process the electrical imaging logging data to obtain the porosity spectra and determine the peak of the primary porosity spectrum. We then extract the mean and standard deviation of the primary porosity spectrum based on its distribution morphology. Meanwhile, we also use the normal distribution function to fit the primary porosity spectrum and accumulate the amplitudes of the original and fitted porosity spectra, respectively. When the cumulative amplitude of the fitted spectra stabilizes, the corresponding porosity indicates the boundary between primary and secondary pores. This boundary allows us to calculate the proportion of primary pores to total pores. Permeability in fractured tight sandstone formations is influenced by both primary and secondary pores, showing a strong correlation with the proportion of primary porosity. Finally, we establish a permeability prediction model based on total porosity and the proportion of matrix pores. The reliability of our established permeability evaluation model is confirmed by comparing the predicted permeabilities with core-derived results in the Triassic Chang 63 Member of the Jiyuan area in the Ordos Basin. In unfractured formations, the predicted permeability based on our raised model closely matches the results derived solely from total porosity. In fractured formations, however, the calculated permeability using our proposed model aligns more closely with the core-derived result, while predictions based on current and NMR models tend to underestimate permeability.

A detailed understanding of the distribution and potential of natural gas hydrate (NGHs) resources is crucial to fostering the industrialization of those resources in the South China Sea, where NGHs are abundant. In this study, this study analyzed the applicability of resource evaluation methods, including the volumetric, genesis, and analogy methods, and estimated NGHs resource potential in the South China Sea by using scientific resource evaluation methods based on the factors controlling the geological accumulation and the reservoir characteristics of NGHs. Furthermore, this study compared the evaluation results of NGHs resource evaluations in representative worldwise sea areas via rational analysis. The results of this study are as follows: (1) The gas hydrate accumulation in the South China Sea is characterized by multiple sources of gas supply, multi-channel migration, and extensive accumulation, which are significantly different from those of oil and gas and other unconventional resources. (2) The evaluation of gas hydrate resources in the South China Sea is a highly targeted, stratified, and multidisciplinary evaluation of geological resources under the framework of a multi-type gas hydrate resource evaluation system and focuses on the comprehensive utilization of multi-source heterogeneous data. (3) Global NGHs resources is nx 1015 m3, while the NGHs resources in the South China Sea are estimated to be 1013 m3, which is comparable to the abundance of typical marine NGHs deposits in other parts of the world. In the South China Sea, the NGHs resources have a broad prospect and provide a substantial resource base for production tests and industrialization of NGHs.

Abstract Permeability is of great importance in indicating formation filtration capacity and deliverability. Hence, it plays a key role in exploration and development wells evaluation. However, how to accurately predict reservoir permeability has become a key problem that has puzzled petrophysicists in the past few decades. The common methods, which are established based on multivariate statistics and widely applied, lose their role. The nuclear magnetic resonance (NMR)-based models, e.g., the Schlumberger Doll Research (SDR) center-based model and the Timur-Coates-based model, all cannot be well used due to the effect of saturated hydrocarbon or methane gas (CH4) to NMR response, especially in tight reservoirs due to the poor relationships among permeability and others parameters that caused by complicated pore structure. In addition, fractures play an important role in connecting intergranular pores and increasing permeability, whereas the common and NMR logging responses cannot well reflect this improvement. Since the birth of electrical imaging logging in the late 1980s, quantitatively characterizing fractured tight reservoirs is realized. In this study, to characterize the role of fractures in improving filtration capacity and permeability in fractured tight reservoir, the Palaeogene tight reservoirs in Huizhou Depression, eastern South China Sea Basin is used as an example, two new models of predicting permeability from electrical imaging logging are raised, and the reliability and accuracy are compared. In the first model, we extract two parameters from the porosity frequency spectrum, and they are defined as the logarithmic geometric mean value (φmv) and the golden section point variance (σg). Afterwards, we establish a relationship that connects formation permeability (K) with porosity (φ), φmv and σg. Based on this relationship, fractured tight reservoir permeability can be predicted from porosity frequency spectrum in the intervals with which electrical imaging logging is first acquired. In the second model, we improve the classical hydraulic flow unit (HFU) approach, and establish a new model to predict flow zone indicator (FZI) from electrical imaging logging to classify fractured formation. In these two models, all the involved coefficients are calibrated by using the experimented results of 118 core samples. Finally, these two models are extended into field applications to consecutively predict permeability from electrical imaging logging, and the predicted permeabilities are compared with core-derived results. Good consistency among them illustrates that the raised two models are all usable in our target Palaeogene fractured tight reservoirs in Huizhou Depression, especially the HFU-based model. It can be well used in all three kinds of formations. The average relative error between predicted permeabilities by using HFU-based model and core-derived results is only 14.37%. However, if the classical models are directly used in our target formations, permeability curve is underestimated.

Deep coalbed methane (CBM) demonstrates significant production potential, and a fervent exploration and development boom is currently underway in China. The permeability of coal reservoirs is heavily influenced by pore–fracture structure heterogeneity. Some researches have been conducted on deep coals’ pore–fracture structure; however, these studies mostly consider coal as a homogeneous material, neglecting the heterogeneity of the macrolithotypes within the coal. In this study, 33 deep coals with burial depths of more than 2000 m were obtained from the Daning-Jixian block of the Ordos Basin, covering all macrolithotypes: bright coal (BC), semi-bright coal (SBC), semi-dull coal (SDC), and dull coal (DC). These samples were subjected to three sets of NMR tests in dry, fully saturated, and irreducible water conditions, with the pore–fracture structure characteristics being analyzed. The results demonstrate that the sampled deep coals’ pore–fracture structure is highly heterogeneous, with transitional pores being dominant, followed by mesopores, “macropores and fractures”, and micropores. The NMR T2C ranges from 0.61 to 2.44 ms, with an average of 1.19 ms; a higher T2C value indicates more developed micropores. The ranges for producible water porosity (φpr) and producible water saturation (Spr) are 0.31–7.24% (avg. 2.42%) and 6.97–71.47% (avg. 31.06%), respectively. Both of them exhibit a high positive correlation with the total volumes of “macropores and fractures” and mesopores. Compared to SDC and DC, the BC and SBC, especially the former, overall contain more “macropores and fractures” and mesopores, fewer transitional pores and micropores, and higher φpr and Spr. These findings suggest that regions with abundant BC and SBC should be prioritized during deep CBM exploration and production due to the inherently superior permeability and gas extraction potential of BC and SBC, and these coals are likely to require less intensive stimulation to achieve higher recovery rates and could provide more sustainable gas production over time.

The /3 -skeleton approach can be conveniently utilized to construct the cosmic web based on the spatial geometry distribution of galaxies, particularly in sparse samples. This method plays a key role in establishing the three-dimensional structure of the Universe and serves as a tool for quantitatively characterizing the nature of the cosmic web. This study is the first application of /3 -skeleton information as weights in mark weighted correlation functions (MCFs), presenting a novel statistical measure. We have applied the /3 -skeleton approach to the CMASS NGC galaxy samples from SDSS BOSS DR12 in the redshift interval 0.45 <= z <= 0.55. Additionally, we applied this approach to three COLA cosmological simulations with different settings (SZ m = 0.25, SZ m = 0.31, SZ m = 0.4) for comparison. We measured three MCFs, each weighted by (i) the number of neighboring galaxies around each galaxy, (ii) the average distance of each galaxy from its surrounding neighbors, and (iii) the reciprocal of the average distance of each galaxy from its surrounding neighbors. By comparing measurements and calculating corresponding chi 2 statistics, we observe high sensitivity to the cosmological parameter SZ m through a joint analysis of the two -point correlation and three MCFs.

The evaluation of rock porosity and the mercury injection capillary pressure (MICP) curve is fundamental for oil and gas exploration and production. Digital rock (DR) technology, incorporating 3D micro-CT imaging and numerical methods, has been widely employed to predict these properties. However, analyzing the pore structure of heterogeneous rocks, such as fractured rocks or glutenite, solely through single-scale DR analysis poses challenges. Existing upscaling methods have limitations in fully representing the complete range of pore structures at different scales, with limited comparison to experimental data. To address this, we propose a novel method that upscales porosity and simulates the MICP curve from nano-scale to core scale by merging results from micro-CT (at resolutions of 35 μm and 2 μm) and SEM (at resolutions of 6.5 nm and 65 nm). We validate the developed DR model by applying it to sandstones, glutenite, and igneous rocks, and achieve excellent agreement between the experimental data and the multi-scale DR model across 67 samples. The results demonstrate that the multi-scale model effectively captures the porosity and pore structures across the entire range. In contrast, the single digital rock (DR) model underestimates the porosity measurements for both homogeneous sandstones and heterogeneous cores. While the MICP model based on a single DR proves suitable for homogeneous rock samples, it introduces noticeable discrepancies when applied to heterogeneous rock samples. The developed multi-scale method significantly enhances the confidence in using DR to assess the pore structure of complex rocks.

Pore structure described the macroscopic pore size and microscopic pore connectivity. It heavily determined formation quality and seepage capacity, and thus associated with permeability. Generally, ultra-low permeability to tight sandstone reservoirs were always affected by complicated pore structure and strong heterogeneity. Characterizing pore structure was of great importance in improving tight sandstone reservoir evaluation and validity prediction. Nuclear magnetic resonance (NMR) logging was considered to be valuable in pore structure prediction only in exploration wells because plenty of NMR logging data was acquired in key wells. However, methods that established in exploration wells cannot be directly extended into development wells due to the limitation of quantity of NMR data. In addition, NMR logging was only usable in pore structure characterization in water saturated layers, it cannot be directly used in hydrocarbon-bearing reservoirs. In this study, to establish a widely applicable pore structure characterization method that can be used not only in exploration wells, but also available in development wells to improve formation validity evaluation and high-quality formation identification in Triassic Chang 8 Formation of Shunning Region, Eastern Ordos Basin, we established a technique to synthetize pseudo-Pc curve from geophysical logging data by using deep learning method. This technique was raised based on the morphological feature analysis of mercury injection capillary pressure curves. We found that the applied mercury injection pressures were the same for all core samples during mercury injection experiments, the pore structure difference for all core samples was determined by injected mercury content (SHg) under the same Pc. Hence, once we predicted mercury content under every Pc, pseudo-Pc curve can be synthetized by combining predicted mercury content and known Pc. Constructing pseudo-Pc curve was translated as predicting mercury content. To establish a reasonable model that can be used in development wells, where only conventional logging data was available, we analyzed relationships among mercury contents under every mercury injection pressure and geophysical logging data. This analysis was raised based on heat map of decision tree technique, and the experimental data of 115 core samples that drilled from Triassic Chang 8 Formation in Shunning Region was used. Finally, we found that SHg under 15th capillary pressure was heavily related to porosity and deep and shallow resistivity. Based on this perfect relationship, we established a model to predict 15thSHg from porosity and deep and shallow resistivity by using deep learning method of XGBoost. In this deep learning method, 92 clusters of core analysis data (accounting for 80.0% of the total), were used as training samples, and the rest 20.0% was retained as samples for verification. Meanwhile, relationship between SHgs under two adjacent mercury injection pressures was also closely related. Hence, after SHg under 15th Pc was predicted from conventional logging data, the other SHgs can be calculated by using step iterative method. In addition, considering the used input porosity in XGBoost was also difficult to be estimated based on statistical method, neutron, density, interval transit time (Δt) and delta natural gamma ray (ΔGR) were chosen as input parameters, and XGBoost was used to predict porosity from well logging data. Based on predicted porosity and deep and shallow resistivity, pseudo-Pc curves were consecutively synthetized to characterize pore structure of tight Chang 8 sandstone reservoirs. Meanwhile, pore throat radius distribution, and pore structure evaluation parameters were also calculated, comparison of predicted pore structure evaluation parameters and core derived results illustrated that calculation accuracy reached to 86.4%. In addition, we determined two pore throat radius cutoffs to classify pore throat radius into three parts, which represented small, intermediate and large pore throat sizes, separately. The relative contents of each type of pore throat sizes were calculated, separately. A parameter of formation validity indication was raised to evaluate formation pore structure. Relationship between formation validity indication and daily liquid production per meter was established, and formations were classified into three types. The first and second types of formations were effective formations that contained substantial hydrocarbon production capacity, and the third type of formation was dry. Our raised method and technique were well used to improve tight reservoirs characterization and evaluation in Chang 8 Formation of Shunning Region, and it would also be valuable in indicating the distribution of effective tight sandstones for formations with similar properties.

The Pinghu Formation is a low permeability sandstone reservoir in the KQT Region, East China Sea. Its porosity ranges from 3.6 to 18.0%, and permeability is distributed from 0.5 to 251.19 mD. The relationship between porosity and permeability was poor due to strong heterogeneity. This led to the difficulty of quantitatively evaluating effective reservoirs and identifying pore fluids by using common methods. In this study, to effectively evaluate low permeability sandstones in the Pinghu Formation of KQT Region, pore structure was first characterized from nuclear magnetic resonance (NMR) logging based on piecewise function calibration (PFC) method. Effective formation classification criteria were established to indicate the “sweet spot”. Afterwards, several effective methods were proposed to calculate formation of petrophysical parameters, e.g., porosity, permeability, water saturation (Sw), irreducible water saturation (Swirr). Finally, two techniques, established based on the crossplots of mean value of apparent formation water resistivity (Rwam) versus variance of apparent formation water resistivity (Rwav)—Sw versus Swirr—were adopted to distinguish hydrocarbon-bearing formations from water saturated layers. Field applications in two different regions illustrated that the established methods and techniques were widely applicable. Computed petrophysical parameters matched well with core-derived results, and pore fluids were obviously identified. These methods were valuable in improving low permeability sandstone reservoirs characterization.

Marine deep-water high-temperature and high-pressure (HTHP) reservoirs have excellent potential for future oil and gas exploration. Because reservoir quality is often influenced by pore structure, understanding the characteristics of pore structures is essential for efficient exploitation. Therefore, it is necessary to conduct a comprehensive study of the pore structures in HTHP reservoirs. This study selected samples of the Enping Formation in the South China Sea as the research target and investigated the reservoir pore structures based on scanning electron microscopy, casting thin section, nuclear magnetic resonance, and mercury intrusion (e.g., high-pressure, constant-rate). The results show that the pore geometry and throat radius of different pore types in these reservoirs can lead to pore system heterogeneity. A comprehensive experimental method combining NMR and mercury injection was used to determine pore structure characteristics. In addition, a new pore size classification scheme was developed for marine deep-water HTHP reservoirs, and the controlling effect of pore type on percolation flow capacity was analyzed. This study systematically used a comprehensive pore structure characterization method that combined various experimental techniques to present the pore structure and develop a new pore size classification scheme for deep-water HTHP sandstone reservoirs, providing insight into the reservoir quality of marine deep-water HTHP sandstone reservoirs.

Rock permeability is an essential petrophysical property for evaluating the hydrocarbon exploitation and CO2 geological sequestration. The large-scale rock heterogeneity by single-scale digital rock analysis (DRA) poses a challenge in predicting the permeability of the centimeter-scale core plug for fractured carbonates, vuggy carbonates, and conglomerates. The present study developed two multiscale workflows to upscale the permeability from the millimeter scale to the near centimeter scale. The basic two-step workflow consists of multiscale imaging and multiscale modeling to integrate the Darcy flow in the microporous matrix representative element volume and the Stokes flow in larger-sized pores/vugs/fractures. The basic two-step workflow was then extended to the four-step workflow to speed up the computation and reduce the computer memory. With experimental permeability as the benchmark, this study compared single-scale simulation methods and multiscale workflows to quantify the best permeability analysis method for the three rock types. The basic two-step workflow with binary segmentation is accurate for the fractured carbonate due to fully modeling the preferential flow and the fluid exchange between the fracture and matrix. The extended four-step workflow with ternary segmentation is optimal for the conglomerate to simulate fluid resistances of the gravel and matrix with satisfied computational efficiency. The permeability of some vuggy carbonates can be well evaluated by the single-scale simulation of the matrix flow where the vugs are isolated and cannot facilitate fluid communication. The acceptable agreement between the experimental and simulated permeabilities for 18 core plugs improves the confidence in using the developed DRA to predict the permeability for complex rocks.

Pore-throat size distribution is a key factor controlling the storage capacity and percolation potential of the tight sandstone reservoirs. However, the complexity and strong heterogeneity make it difficult to investigate the pore structure of tight sandstone reservoirs by using conventional methods. In this study, integrated methods of casting thin section, scanning electron microscopy, high-pressure mercury intrusion (HPMI), and constant-pressure mercury intrusion (CPMI) were conducted to study the pore-throat size distribution and its effect on petrophysical properties of the Shanxi Formation tight sandstones in the northern Ordos Basin (China). Results show that pore types of the Shanxi tight sandstone reservoirs include intergranular pores, dissolution pores, intercrystalline micropores, and microfracture, while the throats are dominated by sheet-like and tube-shaped throats. The HPMI-derived pore-throat size ranges from 0.006 to 10 mu m, and the pore-throats with a radius larger than 10 mu m were less frequent. The pore body size obtained from CPMI shows similar characteristics with radii ranging from 100 to 525 mu m, while the throat size varies greatly with radii ranging from 0.5 to 11.5 mu m, resulting in a wide range of pore-throat radius ratio. The full range of pore size distribution curves obtained from the combination of HPMI and CPMI displays multimodal with radii ranging from 0.006 to 525 mu m. Permeability of the tight sandstone reservoirs is primarily controlled by relatively larger pore throats with small proportions, and the permeability decreases as the proportions of smaller pore-throats increase. The pervading nanopores in the tight gas sandstone reservoirs contribute little to the permeability but play an important role in the reservoir storage capacity. A new empirical equation obtained by multiple regression indicates that r15 (pore-throat size corresponding to 15% mercury saturation) is the best permeability estimator for tight gas sandstone reservoirs, which yields the highest correlation coefficient of 0.9629 with permeability and porosity.

To study the shale oil occurrence characteristics of the second member of Kongdian Formation (Ek 2 ) in Cangdong sag, Rock-Eval pyrolysis, pyrolysis–gas chromatography, and gas chromatography of crude oil were conducted to apply multistep programmed pyrolysis and recovery of light hydrocarbon components was evaluated. The factors controlling shale oil occurrence were evaluated by combining petrology and organic geochemistry analyses. The results showed that the shale oil occurrence characteristics differed with different well areas in Cangdong sag. The occurrence patterns and states of shale oil were controlled by occurrence of original sedimentary organic matter and its mineral configuration, thermal evolution of organic matter, and reservoir space. The felsic lamina are the main reservoir space for shale oil in laminated shale, which contains the highest content of oil. However, under similar organic matter content, the free oil content of massive shale is higher than that of laminated shale. The adsorbed oil content is mainly controlled by the abundance and thermal evolution degree of organic matter. The relationship between adsorbed oil content and Rock-Eval S 2-2 was characterized by “three stages.” and the control mechanism of each stage was different. When free oil content (S 1-1 + S 1-2 ) reached 3 mg/g, the main factor controlling free oil content changed from kerogen content to reservoir property.