Reservoir Distribution Research Articles

Prediction of grain shoal reservoirs via seismic forward modeling and waveform classification: Application to the northern slope of the central Sichuan Uplift, Sichuan Basin, SW China

Grain shoals are one of the principal reservoir facies of carbonate rocks in oil and gas exploration domains. With the discovery of oil and gas in the grain shoal reservoirs of the Longwangmiao Formation in the central Sichuan paleo-uplift, the characteristics and distribution of grain shoal reservoirs are still unclear in the northern slope of the central Sichuan paleo-uplift. Through integrated analysis of wireline logs and high-quality 3D seismic data, combined with seismic forward modeling and waveform classification, reservoir seismic facies, reservoir classification, and the reservoir distribution of different grades are investigated. The results show that (1) under the thin thickness (i.e., the thickness is around 80 m) of the Longwangmiao Formation (i) when reservoirs are not developed, the seismic waveform is manifested as a single peak, and the top interface of the Longwangmiao Formation corresponds to 1/8 [Formula: see text] above the single peak. (ii) When a single set of reservoirs is merely developed in the second member of the Longwangmiao Formation (SMLF), the waveform displays a single peak, and the top peak moves downward. In addition, when multiple sets of reservoirs are developed in the SMLF, the seismic reflections of multiple reservoirs are consistent with those of a single reservoir with the same cumulative thickness. (iii) When the reservoirs are developed in the first member of the Longwangmiao Formation (FMLF) and SMLF, the single peak moves downward, and either the reservoir thickness of the SMLF is greater than that of the FMLF or the reservoir velocity of the SMLF is lower than that of the FMLF. (2) Under the thick thickness (i.e., the thickness is approximately 110 m) of the Longwangmiao Formation, (i) when reservoirs are not developed, the waveform of the Longwangmiao Formation exhibits a double peak, and the top interface of the Longwangmiao Formation corresponds to the extreme value of the upper peak. (ii) When only a single set of reservoirs or multiple sets of reservoirs are developed in the SMLF, the Longwangmiao Formation exhibits a single peak, and the top interface of the Longwangmiao Formation corresponds to the trough. (iii) With the reservoir development in the first and second members of the Longwangmiao Formation, the waveform of the Longwangmiao Formation shows an asymmetric low-frequency peak, and either the reservoir thickness of the SMLF is greater than that of the FMLF or the reservoir velocity of the SMLF is lower than that of the FMLF. (3) Using the waveform classification method, seismic waveforms corresponding to the Longwangmiao Formation could be summarized into four types (i.e., two types of waveforms associated with reservoir development and two types of waveforms associated with reservoir un-development). Two reservoir waveforms are distributed as two strips oriented approximately east–west and spread in the central study area, according to the planar study results that combine seismic attributes and waveform classification. The reservoir stripes near well PS1 represent the better-developed reservoir zones in the study area.

Implications of suspended sediment in the migration of nutrients at the water-sediment interface in retention reservoirs

The significance of suspended sediment in the context of nutrient cycling and distribution in reservoirs is rarely reported in the scientific literature. What’s more, suspended sediment (SS) have so far not been taken into account as a potential factor amplifying the degrading effects of nutrients on the functioning of reservoirs. In the experiment described here, the variability of SS concentrations and the content of total nitrogen (TN), total phosphorus (TP), total organic carbon (TOC) and organic matter (OM) were investigated to determine the potential and determinants of SS in the process of migration of these substances at the water-sediment interface in retention reservoirs. The results showed that SS significantly manipulate the distribution of values of total phosphorus and total organic carbon contained in bottom sediment. It was confirmed that the circulation and distribution of selected nutrients in reservoirs is closely related to suspended sediment. Thus, it was proven that SS significantly affect the quality of deposited sediment. Finally, it was concluded that suspended sediment in the water of reservoirs forms a kind of micro-ecosystem, in which it plays a hitherto undiscovered role of a catenary (hub) consolidating a number of phenomena and processes occurring between individual components in the water-bottom sediment system.

The influence of major faults and fractures on the development of non-matrix porosity system in a pre-salt carbonate reservoir, Santos Basin – Brazil

Faults and fractures are central for characterizing the permeability distribution in carbonate reservoirs since they act as pathways for diagenetic fluids that often favor intense rock dissolution and permeability. Usually, high permeability zones and fractures are not easily recognized in seismic data due to limited resolution and they are often associated with higher concentrations of hydrocarbons or even significant fluid losses during drilling, thus creating a challenge for hydrocarbon exploration. In the Santos Basin, southeast Brazil, the pre-salt carbonate reservoirs from the Barra Velha Formation (BVE) are the main hydrocarbon producers in Brazilian Atlantic margin and well-known for being extremely heterogeneous, exhibiting complex dual-porosity systems. In this study, we built a conceptual model of these fracture zones and non-matrix porosity formation that helped narrowing the understanding of these complex systems. The characterization of faults and fractures was carried out using seismic, well-logs, and borehole image data to understand the influence of these structures in the porosity formation along the Barra Velha Formation. In the study area, three fault sets were defined (F1, F2, and F3) from seismic data. F1 represents to the larger faults, while the F3 fault set represents the smaller faults related to the reactivation of F1; both sets being oriented NE-SW. The F2 fault set is associated with the rift formation and is oriented to NNE-SSW. These three fault sets compartmentalized the studied area into different domains, each exhibiting distinct fracture sets. The natural open fractures were formed during the reactivation of rift faults and are oriented mainly NW, NNE-NNW, NE, and ENE and were identified across the entire study area, but with different intensity values. The fracture intensity closely relates to the distance from major faults where the wells with the highest fracture intensity occurs located 150–590 m from the larger F1 fault set. Scan-lines were conducted throughout the area to determine the fault width, and an average value of 1.2 km was established. Seven non-matrix porosity classes were characterized and classified into stratigraphically concordant and discordant non-matrix pore types at well scale through borehole image interpretation. The Barra Velha Formation exhibit higher occurrence of stratigraphically discordant non-matrix porosity related to fractured zones while stratigraphically concordant non-matrix porosity is mainly controlled by the paleotopography of the study area. Overall, non-matrix porosity formation tends to follow an orientation that suggests a preferential dissolution flow towards NE and ENE directions. Intervals with higher silica content shows a positive correlation with both fracture intensity and stratigraphically discordant non-matrix porosities. This work provides a conceptual model about the fractures and non-matrix porosity distribution in pre-salt carbonate rocks that can help address some of associated structural and stratigraphic uncertainties during field appraisal and development.

Characteristics of middle-deep reservoirs and the genesis of pore development in the southern slope of the Nanpu sag in the Bohai Bay Basin, China

To clarify the distribution of favorable reservoirs in the middle and deep layers of the southern slope of the Nanpu sag and identify relatively high-quality reservoir sections, the characteristics of the reservoirs in the middle and deep layers of the southern slope of the Nanpu sag were studied by means of core analysis, thin section casting, scanning electron microscopy, and analytical tests. Research shows that the middle and deep reservoirs on the southern slope of the Nanpu sag are mainly lithic feldspathic sandstone and that the debris is mainly magmatic rock. The diagenesis processes are mainly compaction, cementation, and dissolution. The deformation of plastic particles, brittle microcracks on the surface of rigid clastic particles, calcareous cementation, quartz overgrowth, and feldspar dissolution are common. The pores are co-developed by primary pores and secondary pores, in which the primary pores are more common in the third member of the Dongying Formation and the first member of the Shahejie Formation, whereas the secondary pores are more common in the first member of the Shahejie Formation. The genesis of pore development is discussed. It is considered that the anticompaction components, chlorite film, and hydrocarbon filling play major roles in the formation of primary pores, whereas atmospheric water leaching, diagenetic evolution, thermal evolution of organic matter, and clay mineral transformation play major roles in the formation of secondary pores.

Structure and Evolution of Multi-Trend Faults in BZ19-6 Buried Hill of the Bohai Bay Basin, Eastern China

Defining the structure and evolution of multi-trend faults is critical for analyzing the accumulation of hydrocarbons in buried hills. Based on high-resolution seismic and drilling data, the structural characteristics and evolutionary mechanism of multi-trend faults were investigated in detail through the structural analysis theory and quantitative calculations of fault activity, allowing us to determine the implication that fault evolution exerts on hydrocarbon accumulation in the BZ19-6 buried hill. There are four kinds of strike faults developed on the buried hill: SN-, NNE-, NE–ENE-, and nearly EW-trending, which experienced the Mesozoic Indosinian, Yanshan, and Cenozoic Himalayan tectonic movements. During the Indosinian, the BZ19-6 was in a SN-oriented compressional setting, with active faults composed of SN-trending strike-slip faults (west branch of the Tanlu fault zone) and near EW-trending thrust faults (Zhang-peng fault zone). During the Yanshanian, the NNE-trending normal faults were formed under the WNW–ESE tensile stress field. Since the Himalayan period, the BZ19-6 buried hill has evolved into the rifting stage. In rifting stage Ⅰ, all of the multi-trend pre-existing faults were reactivated, and the EW-trending thrust faults became normal faults due to negative inversion. In rifting stage II, a large number of NE–ENE-trending normal faults were newly formed in the NW–SE-oriented extensional setting, which made the structure pattern more complicated. In rifting stage III, the buried hill entered the post-rift stage, with only part of the NNE- and NE–ENE-trending faults continuously active. Multi-trend faults are the result of the combination of various multi-phase stress fields and pre-existing structures, which have great influence on the formation of tectonic fractures and then control the distribution of high-quality reservoirs in buried hills. The fractures controlled by the NNE- and EW-trending faults have higher density and scale, and fractures controlled by NE–ENE trending faults have stronger connectivity and effectiveness. The superposition of multi-trend faults is the favorable distribution of high-quality reservoirs and the favorable accumulation area of hydrocarbon.

Studying the impact of pore sizes on gas flow and distribution in volatile carbonate reservoirs using a new triple-porosity model

Studying the impact of pore sizes on gas flow and distribution in volatile carbonate reservoirs using a new triple-porosity model

Oolitic Sedimentary Characteristics of the Upper Paleozoic Bauxite Series in the Eastern Ordos Basin and Its Significance for Oil and Gas Reservoirs

In recent years, great breakthroughs have been made in gas explorations of the Upper Paleozoic bauxite series in the Longdong area of the Ordos Basin, challenging the understanding that bauxite is not an effective reservoir. Moreover, studying the reservoir characteristics of bauxite is crucial for oil and gas exploration. Taking the bauxite series in the Longdong area as an example, this study systematically collects data from previous publications and analyzes the petrology, mineralogy, oolitic micro-morphology, chemical composition, and other sedimentary characteristics of the bauxite series in the study area using field outcrops, core observations, rock slices, cast slices, X-ray diffraction analysis, scanning electron microscopy and energy spectra, and so on. In this study, the oolitic microscopic characteristics of the bauxite reservoir and the significance of oil and gas reservoirs are described. The results show that the main minerals in the bauxite reservoir are boehmite and clay minerals composed of 73.5–96.5% boehmite, with an average of 90.82%. The rocks are mainly bauxitic mudstone and bauxite. A large number of oolites are observable in the bauxite series, and corrosion pores and intercrystalline pores about 8–20 μm in size have generally developed. These pores are important storage spaces in the reservoir. The brittleness index of the bauxite series was found to be as high as 99.3%, which is conducive to subsequent mining and fracturing. The main gas source rocks of oolitic bauxite rock and the Paleozoic gas series are the coal measure source rocks of the Upper Paleozoic. The oolitic bauxite reservoirs in the study area generally have obvious gas content, but the continuity of the planar distribution of the bauxite reservoirs is poor, providing a scientific basis for studying bauxite reservoirs and improving the exploratory effects of bauxite gas reservoirs.

Sedimentary Reservoir Characteristics of Fuyu Oil Formation in the Middle of Fuxin Uplift, Southern Songliao Basin

Currently, the Fuyu reservoir in the middle of the Fuxin uplift, located in the southern Songliao Basin, is in a high water cut development stage. The understanding of this reservoir is limited, and the distribution of favorable reservoirs remains unclear, necessitating detailed reservoir characterization. This study employs a combination of well and seismic technologies to accurately depict the sedimentary and reservoir characteristics of the Fuyu oil reservoir. By conducting detailed correlations of oil zones, a regional high-resolution isochronous stratigraphic framework is established. The division of sedimentary microfacies enables fine characterization of single sand bodies, identifying channel boundaries, clarifying lateral connectivity, and detailing the vertical contact relationships of sand bodies across different deposition periods. The results demonstrate that root-mean-square amplitude and total energy metrics effectively correspond to sand bodies in the study area and can be used to analyze sand body distribution. Provenance is primarily from the southwest to the northeast, with shallow deltas predominantly developed. Delta plain subfacies are found in zones 4-12, while delta front subfacies are in zones 1-3. Microfacies types mainly include the main distributary channel, distributary channel sides, crevasse splay, overbank sand, and underwater distributary channels. The main distributary channel reservoirs exhibit the best physical properties, with porosity ranging from 20-25%, while sand bodies at the sides of distributary channels reach 15-20%. Predicted favorable areas are mainly located at the intersections of distributary channels and structural highs, where drilling is likely to yield high oil flow.

High resolution 3-D seismic and sequence stratigraphy for reservoir prediction in ‘Stephi’ field, offshore Niger Delta, Nigeria

The Offshore Niger Delta, Nigeria, stands as a dynamic geological marvel, known for its intricate processes and extensive hydrocarbon reservoirs. This study employed an integrated approach, utilizing 3D seismic data and well logs, to conduct a thorough analysis of sequence stratigraphy and reservoir characterization in the pursuit of optimizing hydrocarbon exploration in the region. The study focused on the NW–SE trending Miocene depocenters, which predominantly comprises alternating sandstone and thick shale layers within the Agbada Formation. These reservoir units showcased stacked shallow marine fluvial–deltaic sediments, separated by significant marine shale units. Within the study area, two hydrocarbon-bearing reservoirs were identified and named: R1 and R2. Petrophysical analysis identified R2 as the most promising reservoir, with a permeability of 1184 × 10− 3 µm2, 85% hydrocarbon saturation, porosity of 0.30, and effective porosity of 0.27. Fault structural analysis uncovered that hydrocarbons are trapped within a network of growth faults within the wave-dominated Niger Delta depositional system. From the sequence stratigraphic interpretation, four depositional sequences were delineated between the depths of 2030–3417 m, and are bounded by five sequence boundaries. Integrated seismic facies analysis revealed high-energy feeder systems likely supplying sediments from river sources to offshore locations. These integrated findings provide essential insights to inform resource management, exploration strategies, understanding of reservoir distribution, and structural intricacies within the complex offshore Niger Delta, Nigeria, providing valuable information. The depositional environment helped in the understanding of the stratigraphic traps which are prospects in the study area. This together with the associated reservoir quality allowed accurate prediction for potential reservoir facies and will further improve the field development plans.

Unsupervised Machine Learning-Based Singularity Models: A Case Study of the Taiwan Strait Basin

The identification of geochemical anomalies in oil and gas indicators is a fundamental task in oil and gas exploration, as the process of oil and gas accumulation is a low probability event. Machine learning algorithms for anomaly detection are applicable to the identification of oil and gas geochemical anomalies related to oil and gas accumulation. However, when using oil and gas indicators for anomaly detection, the diversity of these indicators often leads to the influence of the indicator redundancy on the identification of such features. Therefore, it is particularly important to select appropriate oil and gas indicators for anomaly detection. In this study, a hybrid model combining unsupervised machine learning methods and singularity analysis methods was used to evaluate oil and gas indicator anomalies using geochemical data from the Taiwan Strait Basin. The models used in this study include the singularity index model (LSP), the principal component model combined with the singularity index model (PCA and LSP), and the cluster analysis combined with the principal component model and the singularity index model (CLA-PCA-LSP). PCA models can reduce the dimensions of the data and retain as much information as possible. CLA divides data samples into different groups, so that samples within the same group are more similar and samples between different groups are less similar. LSP is mainly used for measuring the setting and singular degree of local anomalies in multi-scale geochemistry, geophysics, and other types of local anomalies, and it has a unique advantage in extracting low and weak anomalies and nonlinear characteristics. The results of the study show that the results obtained using the CLA-PCA-LSP hybrid model are very similar to those obtained by performing PCA on the entire index and then calculating the singularity index. This also verifies that, for the study areas of the Jiulongjiang Depression and Jinjiang Depression, we can select oil and gas indicators that are favorable for exploration analysis, without including all indicators in the analysis scope, thereby improving the computational efficiency. The application of a singularity analysis method and generalized self-similarity principle in extracting the geochemical information of oil and gas indicators in the Taiwan Strait Basin highlights key technologies such as the identification of weak anomalies, decomposition of composite anomalies, and integration of spatial information. The combination anomalies delineated by the singularity analysis method and S-A method not only reflect the spatial relationship with known oil and gas reservoir distribution, but also show the multiple combination anomalies in unknown areas, providing favorable guidance for the next exploration direction in the Taiwan Strait Basin.

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.

Differences in reservoir quality within distributary channel belts at the braided river delta front in the Xinchang area of Western Sichuan’s 2nd member of the Xujiahe Formation: genesis and implications

AbstractThe tight sandstone reservoris are important exploration and production target in the Xujiahe Formation in Xinchang area of Western Sichuan. Due to the various lithofacies and diagenetic alteration in distributary channel belt sandstones, the reservoirs exhibit strong heterogeneity. The strong heterogeneity makes the identification of petrologically superior sandbodies a great challenge. In order to better understand reservoir quality, this study constructs a model between diagenetic alterations and reservoir quality within distributary channel belts. 73 plug samples were taken from 17 wells located in the channel belt. An integration of thin sections, X-ray diffraction, carbon and oxygen isotope ratios, cathodoluminescence, and micro-CT were analysed for the genesis and distribution of reservoir quality. The results show that subaqueous distributary channels are formed under various hydrodynamics, resulting in different lithofacies. The thicknesses of channels can be divided into less than 2 m, 2–6 m, and more than 6 m. The diagenetic alteration in lithofacies were identified. Coarse-grained sandstones with low content of rock fragments are relatively weakly compacted with less calcite and chlorite cementation. Fine-grained sandstones with high content of rock fragments are strongly compacted with calcite cementation during early diagenesis. The dissolution pores are related to the soluble mineral content and the distribution of mudstones. The subaqueous distributary channels formed in high-energy, moderate-energy, and low-energy hydrodynamic settings have experienced different diagenetic intensities. Additionally, fractures can effectively improve the reservoir properties. The distribution of good quality reservoirs is controlled by the combined influence of diagenetic heterogeneity and fractures. This would help to promote better understanding of reservoir quality within the subaqueous distributary channel belts in braided-river delta front.

Chemostratigraphic characterization of the Lower Paleozoic Amdeh Formation outcrops and correlation to the subsurface Haima Supergroup and Nimr Group, Sultanate of Oman

A chemostratigraphic correlation between the siliciclastic Lower Paleozoic Amdeh Formation outcrops of the Saih Hatat area, just south of Muscat, and the hydrocarbon-bearing Haima Supergroup and Nimr Group of subsurface Oman is presented. The Amdeh Formation is a 3.4 km-thick succession of Cambrian to Ordovician-aged sandstones and shales, divided into five lithological members (Am1–Am5). The Amdeh Formation type section was sampled throughout for inorganic elemental geochemistry, quantitative mineralogy and U–Pb zircon geochronology. A robust chemostratigraphic framework for the equivalent Haima Supergroup and Nimr Group intervals, defined in the subsurface, is utilized to correlate with the Amdeh Formation. The Amdeh is interpreted to be a basinward, fully marine, time equivalent of the subsurface Haradh (and likely also the Karim), Amin, Miqrat, Al Bashair, Barik, Mabrouk, Barakat, Ghudun and Saih Nihayda formations. This correlation is based on the identification of key mineralogical, depositional, provenance and sequence stratigraphic events within the inorganic geochemical data, guided by outcrop observations of depositional facies and key surfaces, and existing biostratigraphy. Positioned beyond the northern edge of the Ghaba Salt Basin, the Amdeh Formation outcrops provide important constraints on subsurface reservoir distribution, palaeogeography and basin evolution, factors that are relevant to deep gas prospectivity.

Integrated Sequence Stratigraphic and Seismic Facies Analysis for Hydrocarbon Prospectivity of the Taranaki Basin, New Zealand

This study analyses the hydrocarbon potential and basin characteristics of the Taranaki Basin in New Zealand, the country's primary petroleum-producing region. The research, which uses a robust methodology involving 2D seismic data, well logs, and other geological information, examines the basin's stratigraphy, structural features, and petroleum systems. Key findings include the identification of two genetic sequences with associated system tracts, multiple reservoir and source rock units, and both structural and stratigraphic trapping mechanisms. Seismic facies analysis revealed eight distinct facies types which characterize the depositional environments. Play fairway mapping identified sweet spots where all petroleum system elements overlap. Risk assessment highlighted factors like gas chimneys and fault-compromised seals. The study concludes by presenting the geologic chance of success for three identified plays and one prospect in different stratigraphic intervals. This comprehensive analysis provides new insights into the under-explored portions of the Taranaki Basin and its hydrocarbon potential. By enhancing the understanding of the basin's stratigraphic architecture and depositional history, this study aims to improve reservoir distribution and quality predictability. Moreover, integrating seismic facies analysis with sequence stratigraphy offers a robust tool for delineating potential hydrocarbon-bearing zones, thereby reducing exploration risk and aiding the efficient reassessment of existing prospective zones and future exploration efforts.

Depositional, stratigraphic and structural controls on the geometry of Montney Formation reservoirs: Lower Triassic, northeast British Columbia, northwest Alberta

Abstract The Lower Triassic Montney Formation is a world-class unconventional hydrocarbon reservoir that spans the border of northeast British Columbia and northwest Alberta. Integrated sedimentological and ichnological analyses suggest that the Montney Formation was deposited in a predominantly prodeltaic setting that was commonly influenced by both river flood and storm processes. Riverine processes include the local occurrence of normally- and inversely-graded siltstone and sandstone interbeds, interpreted as the record of sediment-laden hyperpycnal flows. Episodic storms are recorded by the local occurrence of hummocky cross-stratified interbeds, as well as normally graded, parallel and wave-ripple laminated beds, which are commonly draped by structureless carbonaceous mudstones. These mudstone drapes represent river-flood-derived fluid muds that collapsed from hypopycnal plumes following the passage of the storms and suggest the intimate linkage between storms and heightened fluvial discharge. The basin in which the Montney Formation was deposited began as three sub-basins, northern, central and southern, each of which experienced different patterns of subsidence and uplift that varied both spatially and temporally during sedimentation. Subsidence of the northern sub-basin was compartmentalized by deep seated faults that provided accommodation for the basal sequence of the Montney Formation, Sequence 1. Subsequent fault movement resulted in reduced accommodation in the northern sub-basin and accelerated subsidence in the central sub-basin, providing accommodation for deposition of Sequence 2, the basal sequence in the central sub-basin. The northern sub-basin remained paleotopographically elevated throughout deposition of Sequence 2 and early Sequence 3 successions, and these younger units did not extend beyond the northern limit of the central sub-basin. During subsequent deposition of the late Sequences 3 and Sequence 4 successions, compartmentalization between the north and central sub-basin was greatly reduced and these intervals were deposited relatively more uniformly along-strike. The unconventional and conventional reservoirs in both the northern and central sub-basins occur at the scale of systems tracts within the four depositional sequences of the Montney Formation. Reconstructing the depositional history of the component systems tracts of Sequence 1 through early Sequence 3 reveals the dynamic interplay between syndepositional tectonism, fluctuating relative sea-level and deltaic depositional processes in controlling the character, geometry and distribution of prolific Montney Formation reservoirs. The recognition of these key geological controls enhances predictability in this valuable resource and may be applicable to other fine-grained reservoirs elsewhere.

Study on the Control of Steam Front Mobility in High-Temperature and High-Salinity Conditions Using Polymer-Enhanced Foam.

This study investigated the enhancing effects of the temperature-resistant polymer Poly(ethylene-co-N-methylbutenoyl carboxylate-co-styrenesulfonate-co-pyrrolidone) (hereinafter referred to as Z364) on the performance of cocamidopropyl hydroxy sulfobetaine (CHSB) foam under high-temperature and high-salinity conditions. The potential of this enhanced foam system for mobility control during heavy oil thermal recovery processes was also evaluated. Through a series of experiments, including foam stability tests, surface tension measurements, rheological assessments, and parallel core flooding experiments, we systematically analyzed the interaction between the Z364 polymer and CHSB surfactant on foam performance. The results indicated that the addition of Z364 significantly improved the strength, thermal resistance, and salt tolerance of CHSB foam. Furthermore, the adsorption of CHSB on the polymer chains enhanced the salt resistance of the polymer itself, particularly demonstrating stronger blocking effects in high-permeability cores. The experimental findings showed that Z364 increased the viscosity of the liquid film, slowed down liquid drainage, and reduced gas diffusion, effectively extending the half-life of CHSB foam and improving its stability under high-temperature conditions. Additionally, in parallel core flooding experiments, the polymer-enhanced foam exhibited significant flow diversion effects in both high-permeability and low-permeability cores, effectively directing more fluid into low-permeability channels and improving fluid distribution in heterogeneous reservoirs. Overall, Z364 polymer-enhanced CHSB foam demonstrated superior mobility control during heavy oil thermal recovery, offering new technical insights for improving the development efficiency of high-temperature, high-salinity reservoirs.

Prediction of deep low permeability sandstone seismic reservoir based on CBAM-CNN

The prediction of sand body is a key focus in evaluating reservoir distribution, playing a crucial role in oil and gas exploration and development. To clarify the development characteristics of the sand body in the Huangyan structural belt of the Xihu Sag and effectively identify the hidden channel, a new approach is proposed. This approach incorporates a Convolutional Block Attention Module (CBAM) into a Convolutional Neural Network (CNN). Well logging and seismic data were used to predict the distribution of sand body in the lower section of the Huagang Formation (H12). Firstly, based on known sand-stratum ratio data and well-side seismic data, the seismic attributes that are sensitive to the reservoir response are preferred through correlation analysis, which are used to construct a Polynomial Linear Regression (PLR) model to obtain the preliminary sand distribution prediction results. Secondly, the grid is divided according to this result. Then, three sample selection methods, namely proportional, fixed-range, and random, are used to construct three sample sets in conjunction with the geologic model guide. Finally, CBAM-CNN, CNN, Random Forest (RF), Support Vector Machines (SVM), and Backpropagation Neural Network (BPNN) are utilized for sand body prediction. The results indicate that when using the same model, the sample set selected by the fixed-range selection method yielded the best prediction outcome. When using the same sample set, the CBAM-CNN model outperformed the others. Among various strategies, training the CBAM-CNN model with the sample set derived from the fixed-range selection method led to the highest test set R2 of 0.913. The results of the sand body distribution indicate that fine river channels are more continuous, and reservoir boundaries are clearer, significantly outperforming other schemes. This outcome can serve as a guide for further reservoir delineation.

Origin of porosity in evaporite platform dolostone in the middle Cambrian Shaelek Formation, NW Tarim Basin, China: constraints from petrology, mineralogy and geochemistry

The extensive middle Cambrian evaporite platform dolostone represents a significant area for hydrocarbon exploration in the Tarim Basin with recent advances indicating promising exploration prospects. However, owing to its considerable depth and the limited exploration, the genesis and distribution of evaporite-related dolostone reservoirs from the middle Cambrian remain poorly understood. This study includes detailed field investigations along with petrological, mineralogical and geochemical analyses to characterise the secondary porosity of the middle Cambrian Shaelek Formation evaporite platform dolostone and to explore the origin of the diagenetic fluids responsible for these features. The results show that gypsum dissolution vugs are the main secondary porosity in the evaporite platform dolostone reservoirs, with their development and distribution strongly controlled by sedimentary facies. Meteoric dissolution during the penecontemporaneous period is responsible for this secondary porosity. The frequent fluctuation in sea-levels and the transient exposure of the dolostone reservoirs provide favourable conditions for the dissolution of unstable gypsum. The multiple stages of calcite filling in the vugs result from supersaturated precipitation from fluids during the late stage of meteoric diagenesis. Variations in δ13C, δ18O and rare earth element compositions between the two types of calcite reflect different stages of fluid evolution and varying degrees of water–rock reaction. The vug-filling fluorite is of non-hydrothermal genesis but results from the highly evaporative concentrated seawater and terrigenous input. The highly concentrated F– in evaporative seawater, combined with F– from fluvial input (if any) during subaerial exposure, most likely provides the F– necessary for fluorite precipitation. A model of reservoir formation and evolution has been established that will be beneficial for hydrocarbon exploration and prediction of the deeply buried Cambrian evaporite platform dolostone reservoir.

Genesis and reservoir preservation mechanism of 10 000‐m ultradeep dolomite in Chinese craton basin

AbstractThe 10 000‐m ultradeep dolomite reservoir holds significant potential as a successor field for future oil and gas exploration in China's marine craton basin. However, major challenges such as the genesis of dolomite, the formation time of high‐quality reservoirs, and the preservation mechanism of reservoirs have always limited exploration decision‐making. This research systematically elaborates on the genesis and reservoir‐forming mechanisms of Sinian–Cambrian dolomite, discussing the ancient marine environment where microorganisms and dolomite develop, which controls the formation of large‐scale Precambrian–Cambrian dolomite. The periodic changes in Mg isotopes and sedimentary cycles show that the thick‐layered dolomite is the result of different dolomitization processes superimposed on a spatiotemporal scale. Lattice defects and dolomite embryos can promote dolomitization. By simulating the dissolution of typical calcite and dolomite crystal faces in different solution systems and calculating their molecular weights, the essence of heterogeneous dissolution and pore formation on typical calcite and dolomite crystal faces was revealed, and the mechanism of dolomitization was also demonstrated. The properties of calcite and dolomite (104)/(110) grain boundaries and their dissolution mechanism in carbonate solution were revealed, showing the limiting factors of the dolomitization process and the preservation mechanism of deep buried dolomite reservoirs. The in situ laser U‐Pb isotope dating technique has demonstrated the timing of dolomitization and pore formation in ancient carbonate rocks. This research also proposed that dolomitization occurred during the quasi‐contemporaneous or shallow‐burial periods within 50 Ma after deposition and pores formed during the quasi‐contemporaneous to the early diagenetic periods. And it was clear that the quasi‐contemporaneous dolomitization was the key period for reservoir formation. The systematic characterization of the spatial distribution of the deepest dolomite reservoirs in multiple sets of the Sinian and the Cambrian in the Chinese craton basins provides an important basis for the distribution prediction of large‐scale dolomite reservoirs. It clarifies the targets for oil and gas exploration at depths over 10 000 m. The research on dolomite in this study will greatly promote China's ultradeep oil and gas exploration and lead the Chinese petroleum industry into a new era of 10 000‐m deep oil exploration.

Global diversity and ecological functions of viruses inhabiting oil reservoirs

Oil reservoirs, being one of the significant subsurface repositories of energy and carbon, host diverse microbial communities affecting energy production and carbon emissions. Viruses play crucial roles in the ecology of microbiomes, however, their distribution and ecological significance in oil reservoirs remain undetermined. Here, we assemble a catalogue encompassing viral and prokaryotic genomes sourced from oil reservoirs. The catalogue comprises 7229 prokaryotic genomes and 3,886 viral Operational Taxonomic Units (vOTUs) from 182 oil reservoir metagenomes. The results show that viruses are widely distributed in oil reservoirs, and 85% vOTUs in oil reservoir are detected in less than 10% of the samples, highlighting the heterogeneous nature of viral communities within oil reservoirs. Through combined microcosm enrichment experiments and bioinformatics analysis, we validate the ecological roles of viruses in regulating the community structure of sulfate reducing microorganisms, primarily through a virulent lifestyle. Taken together, this study uncovers a rich diversity of viruses and their ecological functions within oil reservoirs, offering a comprehensive understanding of the role of viral communities in the biogeochemical cycles of the deep biosphere.