Tight sandstone reservoirs represent a pivotal unconventional oil and gas production target.The upper section of the deeply buried Huagang Formation in the Xihu Depression is abundant in hydrocarbons and forms a tight...Tight sandstone reservoirs represent a pivotal unconventional oil and gas production target.The upper section of the deeply buried Huagang Formation in the Xihu Depression is abundant in hydrocarbons and forms a tight reservoir.It exhibits substantial diagenetic variability and strong heterogeneity in sand bodies,which is reflected in variations in physical properties and grain size.Through integrated geological analysis,including rock thin sections,scanning electron microscopy,X-ray diffraction,well logging and production test data,we investigated the diagenesis,reservoir formation mechanisms,and controlling factors of high-quality reservoirs within the superposed sandstone bodies exceeding 100 m thick in the deeper Huagang Formation.We also studied the formation characteristics of these ultrathick sandstones,clarifying that diagenesis and post-depositional modification are crucial for developing high-quality reservoirs in this formation.Our findings indicate that the sandstone underwent compaction,cementation(by chlorite,calcite and quartz),dissolution(of K-feldspar and carbonate cement),and authigenic clay mineral cementation(such as illite,chlorite,kaolinite).Multiple dissolution zones are present within the thick sandstone units.The distribution of these dissolution zones is mainly controlled by temperature and sandstone composition.With increasing temperature,acidic fluids derived from coal-bearing strata and early hydrocarbon source rocks promoted feldspar dissolution.The thick sandstone units in different intervals of varying depths are at various diagenetic stages.The petrophysical zoning of the reservoir is collectively controlled by diagenetic facies dominated by sedimentation,compaction,and dissolution processes.These findings provide valuable guidance and reference for oil and gas exploration and development in this area,particularly within the ultra-thick sandstone layers.展开更多
Ghana has four sedimentary basins,but attention has mostly been concentrated on the Tano Basin.This preference among potential investors is largely due to the fact that it has been extensively studied and also its est...Ghana has four sedimentary basins,but attention has mostly been concentrated on the Tano Basin.This preference among potential investors is largely due to the fact that it has been extensively studied and also its established oil and gas reserves,which have facilitated the discovery and development of major fields such as the Jubilee Field.In contrast,the Saltpond,Keta,and Voltaian basins have not undergone the same level of exploration and research,thereby making them less attractive to investors.A comparative analysis of the research conducted on the Tano Basin and the other basins is necessary to identify research opportunities that could enhance understanding of these less-explored basins and increase investor interests.The findings indicate that the Tano Basin requires minimal further exploration,while studies on the Saltpond,Keta,and Voltaian basins have primarily focused on sedimentological and geochemical analyses,offering valuable but limited insights into their petroleum systems and hydrocarbon potential.Unlocking Ghana's hydrocarbon potential demands tailored studies for each basin.In the Tano Basin,the key to sustaining and optimizing production lies in advanced seismic reprocessing,pre-stack depth migration,4D reservoir monitoring,and machine-learning-assisted reservoir characterization to address deepwater complexity and compartmentalization.Revitalizing the Saltpond Basin demands updated petroleum system evaluation through modern geochemical techniques,reprocessed 2D/3D seismic data,and comprehensive 1D–3D basin modeling to clarify trap integrity and overlooked plays.In the underexplored Accra–Keta Basin,high-resolution seismic imaging,sequence stratigraphic mapping,and full petroleum system modeling are essential to define reservoir intervals and assess charge potential.For the Voltaian Basin,a deep seismic profiling,integrated geological mapping,source-rock evaluation,and analog-based reservoir/seal studies are required to evaluate its hydrocarbon potential.These targeted efforts are key to de-risking and advancing exploration.An integrated approach is vital for gaining a deeper understanding of the petroleum system elements in these basins.This will not only expand scientific knowledge and inform decision-making at the highest levels but also provide a strong foundation for future exploration,development,and efficient exploitation of hydrocarbon resources.展开更多
The effective channeling of fluid flow by fractures is a liability for enhanced oil recovery(EOR)methods like CO_(2) flooding or CO_(2) storage.Developing a distributed fracture model to understand the heterogeneity o...The effective channeling of fluid flow by fractures is a liability for enhanced oil recovery(EOR)methods like CO_(2) flooding or CO_(2) storage.Developing a distributed fracture model to understand the heterogeneity of the fracture network is essential in characterizing tight and low-permeability reservoirs.In the Ordos Basin,the Chang 8-1-2 layer of the Yanchang Formation is a typical tight and low permeability reservoir in the JH17 wellblock.The strong heterogeneity of distributed fractures,differing fracture scales and fracture types make it difficult to effectively characterize the fracture distribution within the Chang 8-1-2 layer.In this paper,multi-source and multi-attribute methods are used to integrate data into a neural network at different scales,and fuzzy logic control is used to judge the correlation of various attributes.The results suggest that attribute correlation between coherence and fracture indication is the best,followed by correlations with fault distance,north–south slope,and north–south curvature.Advantageous attributes from the target area are used to train the neural network,and the fracture density model and discrete fracture network(DFN)model are built at different scales.This method can be used to effectively predict the distribution characteristics of fractures in the study area.And any learning done by the neural network from this case study can be applied to fracture network modeling for reservoirs of the same type.展开更多
During drilling process,the water phase in drilling fluids infiltrates rock fractures through capillary action.The surface wettability of dolomite is governed by multiple factors,resulting in an unstable wetting state...During drilling process,the water phase in drilling fluids infiltrates rock fractures through capillary action.The surface wettability of dolomite is governed by multiple factors,resulting in an unstable wetting state.Studies have shown that altering the surface wettability of reservoir rocks to an intermediate wetting state can effectively reduce the damage of drilling fluids to oil and gas reservoirs and improve oil and gas recovery.Therefore,it is necessary to develop a reservoir protectant to prevent the water phase in the drilling fluid from intruding into the oil and gas reservoirs.Given this,a modified polysiloxane was synthesized to alter the surface wettability of dolomite.Tetramethylcyclotetrasiloxane(D^(H)_(4))and octamethylcyclotetrasiloxane(D_(4))were ring-opened copolymerized to obtain the hydrogencontaining polysiloxane,which in turn reacted with unsaturated hydrocarbons to obtain the modified polysiloxane.The ability of reservoir protectants to regulate the surface wettability of dolomite under high-temperature and high-salinity conditions was tested.The experimental results show that the reservoir protectant is able to alter the wettability of the dolomite surface to an intermediate wetting state by adsorption on the rock surface even after 16 h of aging at 240℃ and 15% salt concentration.展开更多
This study investigates four Late Permian Gondwana coals from the Raniganj sub-basin,Damodar Valley and three Early Permian Gondwana coals from the Talcher sub-basin,Mahanadi Valley.The study aims to characterize the ...This study investigates four Late Permian Gondwana coals from the Raniganj sub-basin,Damodar Valley and three Early Permian Gondwana coals from the Talcher sub-basin,Mahanadi Valley.The study aims to characterize the kerogen type,hydrocarbon generation potential,thermal maturity,and organic matter composition,as well as to explore the impact of organic matter characteristics on kerogen kinetic parameters,utilizing multi proxy approach.The study further investigates the influence of the mineral matrix on kerogen decomposition kinetics.Based on the Rock-Eval parameters,Fourier transform infrared spectroscopy(FTIR)parameters,and vitrinite reflectance(R_(o)),the kerogen is primarily classified as immature/early mature TypeⅢkerogen derived from terrestrial land plants,with minor contribution from TypeⅡkerogen having mainly gas generating potential.The source of the organic matter,as determined by stable carbon isotopic composition(δ^(13)C_(org))values and C/N ratios indicates a primary input from C_(3) terrestrial plants.The presence of enriched collotelinites and liptinites,such as sporinite and resinite,provides evidence for the input of terrestrial higher plants,including both herbaceous and arborescent species.Various indices derived from maceral abundances,including the gelification index(GI),tissue preservation index(TPI),and vegetation index(VI),collectively indicate diverse depositional conditions which range from wet forest swamps to shallow water-covered wet forest swamps and even dry forest swamps.The variation in vitrinite macerals influenced the kerogen type and consequently impacted the kinetic parameters,viz.the distribution of activation energies(E_(a)),kerogen transformation ratio(KTR),and hydrocarbon generation rate(HGR).Among the Talcher coals,shaly coals exhibit different kerogen type and kerogen transformation.This dissimilarity can be attributed to variable maceral compositions.Unlike the Talcher samples,all Raniganj samples show consistent kinetic behaviour despite their sample type(coal/shaly coal)or kerogen type(TypeⅢ/mixed TypeⅡ/Ⅲ)owing to comparable liptinite/vitrinite maceral composition.This study reveals that whilst the presence of mineral matrix shifts the apparent E_(a) of kerogen through interactions like adsorption and catalysis,it does not significantly affect the kerogen type,HGR,or KTR of the studied coals.展开更多
Delineating sweet spots is critical for the exploration and production of oil and gas in deep and tight sand reservoirs.The lack of advanced and reliable methods makes this a challenge for geologists and geophysicists...Delineating sweet spots is critical for the exploration and production of oil and gas in deep and tight sand reservoirs.The lack of advanced and reliable methods makes this a challenge for geologists and geophysicists.This study introduces,for the first time,an integrated workflow that combines pre-stack seismic inversion with rock physics modeling to predict reservoir porosity and shale volume(V-shale)for sweet spot identification in tight sand reservoirs.A new elastic parameter,the density calculation index(DCI),is introduced which links acoustic and shear impedance for seismic density inversion,thereby addressing the long-standing problem of poor density inversion accuracy.A novel combined Sun–Walsh rock physics model,developed as part of this study,significantly improves V-shale evaluation from seismic data.The proposed three-step seismic inversion approach includes:(1)deriving acoustic and shear impedance from angle-stack seismic data using model-based inversion;(2)calculating density using shear impedance constrained by DCI,followed by porosity estimation from the density–porosity relation;and(3)evaluating V-shale using theα-parameter derived from the Sun–Walsh model and pre-stack inversion results.This integrated workflow provides an effective tool for building accurate 3D reservoir models,and is especially applicable to deep,low-porosity,tight sand reservoirs worldwide.展开更多
Fault sealing capacity is controlled by present-day geometry and clay content,with current research focusing on enhancing the accuracy of capacity estimates.The mechanisms for evaluating both presentday and paleo-seal...Fault sealing capacity is controlled by present-day geometry and clay content,with current research focusing on enhancing the accuracy of capacity estimates.The mechanisms for evaluating both presentday and paleo-sealing are consistent,where the current sealing capacity representing the final stage in the evolutionary process of fault sealing.To address the limitations of the conventional shale gouge ratio(SGR)in evaluating the dynamic nature of fault sealing,this study proposes a visual model for fault sealing evolution.Fault sealing evolution is jointly controlled by the burial history and clay smear history and exerts a critical influence on hydrocarbon migration and accumulation.Hydrocarbon exploration data confirm that fault sealing during and after hydrocarbon migration critically impacts reservoir preservation.If faults remain unsealed during hydrocarbon migration and accumulation,they serve solely as conduits,with their present-day sealing capacity having limited impact.Effective fault sealing thus depends on the alignment between the evolutionary sealing stages and hydrocarbon activity.Building on this framework,we propose a method to visually and quantitatively characterize the fault sealing evolution alongside hydrocarbon activity.A case study of the Xishanyao Formation in the Houxia Basin highlights that the F4 fault transitioned from being over-open to sealed at the onset of hydrocarbon migration,thereby preserving the trap,while the F8-2 fault underwent a complete sealed–reopen cycle,with the late-stage reopening leading to an absence of hydrocarbon accumulation.This temporal contrast forms the basis for a new time-sensitive methodology for assessing fault-seal integrity in complex structural settings.展开更多
By investigating the evolution of shale gas generation,storage,adjustment and accumulation under different structural settings in superimposed basins,this study elucidates the differential accumulation mechanisms of s...By investigating the evolution of shale gas generation,storage,adjustment and accumulation under different structural settings in superimposed basins,this study elucidates the differential accumulation mechanisms of shale gas.An improved evaluation method of shale gas content evolution in superimposed basins is proposed.This method incorporates the coupling effect of key geological factors such as temperature,pressure,organic matter abundance,maturity,and pore characteristics on the content and occurrence state of shale gas,as well as the configuration relationship between shale gas generation and storage throughout geological history.Using this approach,the gas evolution histories of the Longmaxi Formation shales in wells N201 and PY1 are reconstructed under varying geological conditions.The Longmaxi Formation shales in these wells are dominated by typeⅠkerogen,with original total organic carbon(TOC_(o))contents of 6.20 wt% and 4.92 wt%,respectively,indicating differences in the initial material basis for gas generation.At the maximum burial depth of approximately 5000 m,the Longmaxi Formation shale in well N201 exhibits a formation pressure coefficient of 2.05,an organic matter maturity of 2.2%,and organic pores accounting for 68%of the total porosity.The gas generation quantity(Q_(g))reaches 19.24 m^(3)/t,while the gas storage capacity(Q_(s))is 4.30 m^(3)/t.The actual total gas content(Q_(a)),constrained by Q_(s),is 4.30 m^(3)/t,with free gas comprising 94%.Following relatively moderate tectonic uplift,the Q_(a) in well N201 decreases to 4.03 m^(3)/t,with free gas accounting for 63%.In contrast,the Longmaxi Formation shale in well PY1 reached a maximum burial depth of 6300 m,associated with a formation pressure coefficient of 1.62,organic matter maturity of 2.5%,and organic pore proportion of 67%.Here,Q_(g) is 16.87 m^(3)/t,and both Q_(s) and Q_(a) are 3.65 m^(3)/t,with free gas accounting for 98%.After intense tectonic uplift,Q_(a) declines to 2.72 m^(3)/t,and the proportion of free gas drops to51%.Finally,a four-stage differential accumulation model of shale gas is established:Slow gas generation and only adsorbed gas occur in stageⅠ,which is primarily controlled by TOC content;both adsorbed gas and free gas present in stageⅡ,with free gas becoming dominant;rapid gas generation and free gas predominance are controlled by temperature and porosity in stageⅢ;and gas adjustment and accumulation are primarily controlled by temperature and pressure in stageⅣ.展开更多
The Wufeng–Longmaxi Formation derives its name from the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation,found in sequence in the Sichuan Basin.This formation hosts rich shale gas reservoir...The Wufeng–Longmaxi Formation derives its name from the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation,found in sequence in the Sichuan Basin.This formation hosts rich shale gas reservoirs,and its shale gas enrichment patterns are examined in this study using data from 1197 shale samples collected from 14 wells.Five basic and three key parameters,eight in all,are assessed for each sample.The five basic parameters include burial depth and the contents of four mineral types—quartz,clay,carbonate,and other minerals;the three key parameters,representing shale gas enrichment,are total organic carbon(TOC)content,porosity,and gas content.The SHapley Additive exPlanations(SHAP)analysis originated in game theory is used here in an interpretable machine learning framework,to address issues of heterogeneous data structure,noisy relationships,and multi-objective optimization.An evaluation of the ranking,contribution values,and conditions of changes for these parameters offers new quantitative insights into shale gas enrichment patterns.A quantitative analysis of the relationship between data-sets identifies the primary factors controlling TOC,porosity,and gas content of shale gas reservoirs.The results show that TOC and porosity jointly influence gas content;mineral content has a significant impact on both,TOC and porosity;and the burial depth governs porosity which,in turn,affects the conditions under which shale gas is preserved.Input parameter thresholds are also determined and provide a basis for the establishment of quantitative criteria to evaluate shale gas enrichment.The predictive accuracy of the model used in this study is significantly improved by the step-wise addition of two input parameters,namely TOC and porosity,separately and together.Thus,the game theory method in big data-driven analysis uses a combination of TOC and porosity to evaluate the gas content with encouraging results—suggesting that these are the key parameters that indicate source rock and reservoir properties.展开更多
Organic-rich sediments represent vital components of Earth's geochemical cycles, acting both as potential hydrocarbon and coal reservoirs and as unconventional archives for critical metals such as rare earth eleme...Organic-rich sediments represent vital components of Earth's geochemical cycles, acting both as potential hydrocarbon and coal reservoirs and as unconventional archives for critical metals such as rare earth elements(REEs). With the growing emphasis on clean energy technologies, the Cenozoic organic deposits of India have gained renewed significance;however, those from the southern state of Kerala remain understudied. This study investigates lignite and associated carbonaceous sediments from the Cheruvathur and Warkalli Formations using a multi-proxy approach integrating organic petrography,infrared spectroscopy, stable carbon isotopes, and REE geochemistry. The lignite exhibits huminite dominance with Type Ⅲ kerogen, deposited in a wet, mesotropic bog forest swamp under anoxic conditions. The mineral assemblage, dominated by kaolinite, quartz, illite, montmorillonite, feldspar,and pyrite/marcasite, reflects strong chemical alteration in a reducing environment. The δ^(13)C values(-25.1 to-27.3) indicate a C_(3) angiosperm source and deposition in tropical to subtropical swamp settings. REE patterns reveal LREE enrichment in carbonaceous shales and HREE enrichment in lignite,with distinct Ce, Eu, and Gd anomalies associated with provenance and redox conditions. The findings provide new insights into the paleoenvironmental evolution of Kerala's Cenozoic basins and highlight their potential as unconventional REE-bearing resources in the context of the global energy transition.展开更多
Unsecured legacy wells pose significant risks to carbon capture and storage(CCS)as they present potential leakage pathways for stored CO_(2) to return to the atmosphere.In the UK,legacy wells must be assessed for a ca...Unsecured legacy wells pose significant risks to carbon capture and storage(CCS)as they present potential leakage pathways for stored CO_(2) to return to the atmosphere.In the UK,legacy wells must be assessed for a carbon storage permit to be granted and high-risk wells require costly remediation.We use a well risk assessment scheme to evaluate the risk of wells in the Southern North Sea.We then combine our well risk assessment with investigation using the analytical tool CO2BLOCK,which relies on a gravity current model to estimate pressure and plume migration distances.We evaluate the Viking,Camelot and Poseidon projects,which plan to inject CO_(2) into the depleted reservoirs of Southern North Sea gas fields.Carbon dioxide plumes are typically several kilometers wide,and it should be possible to avoid plume migration to high-risk legacy wells.In contrast,pressure fields produced by CO_(2) injection are tens of kilometers wide and low magnitude pressure increases frequently extend beyond the bounds of storage licence areas.The pressure fields encounter hundreds of wells and in the cases of the Camelot and Poseidon projects,interact with each other.展开更多
Geological CO_(2) storage is a promising strategy for reducing greenhouse gas emissions and has become a growing focus of research and deployment.This paper presents numerical simulations of CO_(2) injection and stora...Geological CO_(2) storage is a promising strategy for reducing greenhouse gas emissions and has become a growing focus of research and deployment.This paper presents numerical simulations of CO_(2) injection and storage in a depleted gas reservoir within the B Depression and evaluates associated CO_(2) trapping mechanisms.In the base case,a constant injection rate of 3500 m^(3)/d over fifteen years resulted in a cumulative injection of 19.2×10^(6) m^(3).The CO_(2) plume expanded radially during injection and subsequently migrated up-dip under buoyancy forces.The final stored mass of CO_(2) in the reservoir was 10.6 million tonnes(Mt),representing less than 10% of its theoretical capacity.The plume was projected to reach the entrapment crest and the top of the reservoir within a century,indicating secure long-term containment.Structural,stratigraphic,and residual trapping dominate in Reservoir A(approximately 90%).Anticlinal closures with thick overlying mudstones in the Zhujiang Formation provide effective seals,further enhancing storage security.Reservoir properties and heterogeneity play a crucial role in controlling CO_(2) storage.However,reservoir heterogeneity exerts only a limited influence when intrinsic properties are favorable.Overall,the study and implementation of CO_(2) capture,utilization,and storage(CCUS)in China's offshore basins show promising prospects.展开更多
Carbon Capture,Utilization,and Storage(CCUS)technology has gained widespread attention in recent years as a critical strategy to combat global climate change,particularly in achieving carbon neutrality goals.The Guang...Carbon Capture,Utilization,and Storage(CCUS)technology has gained widespread attention in recent years as a critical strategy to combat global climate change,particularly in achieving carbon neutrality goals.The Guangdong-Hong Kong-Macao Greater Bay Area(GBA),as one of China's most economically active regions,serves as a key engine for economic growth while also facing considerable carbon emission challenges.This study analyzes the industrial emission volume and geographical distribution of key emitting enterprises in the GBA,summarizes their technological processes and main carbonemitting equipment,and provides scientific support for precise mitigation policies and low-carbon development.Based on data from 176 key emitting enterprises,the study reveals that Guangzhou and Dongguan host the largest number of such enterprises.Carbon emissions are primarily concentrated in the power sector,dominated by coal-and gas-fired power units,characterized by significant spatial dispersion and uneven distribution.Beyond the power sector,the paper industry has a high number of enterprises but lower emissions.Key facilities such as boilers,cogeneration systems,and production lines are predominantly located near tributaries rivers in Dongguan and Jiangmen.The building materials sector,primarily cement production,ranks as the second-largest emitter,with hightemperature kilns and grinding equipment,particularly rotary kilns and glass furnaces,as the main sources.The petrochemical and chemical sectors have fewer enterprises and lower emissions in the GBA,mainly located in suburban industrial clusters.Carbon emissions in the GBA exhibit distinct industry concentration and geographical distribution disparities.This study provides crucial data and theoretical insights for the development of targeted emission reduction strategies,optimization of source-sink matching,and the advancement of CCUS technologies in the region,particularly from the GBA to the northern South China Sea.展开更多
The Liushagang Formation in the Weixinan Depression,Beibu Gulf Basin,southern China,is one of the key stratigraphic units for offshore shale oil exploration in the country.The shale oil reservoirs in the formation are...The Liushagang Formation in the Weixinan Depression,Beibu Gulf Basin,southern China,is one of the key stratigraphic units for offshore shale oil exploration in the country.The shale oil reservoirs in the formation are characterized by low porosity,low permeability and strong heterogeneity,which constrain the precise evaluation of reservoir properties,the accurate prediction of sweet spots,and efficient development.This study integrates core observation,mineralogical analysis,and multi-scale pore characterization to systematically clarify the variations in reservoir properties and their controlling mechanisms.The results show that the physical properties of matrix-type,lamina-type,and interlayer-type reservoirs exhibit distinct stepwise variations:Among these,interlayer-type reservoirs show the greatest development potential(quartz content 65%,average porosity 15%,permeability>10 mD,and mobile fluid saturation 60%),whereas matrix-type reservoirs are the least favorable(dominated by 40 nm nanoscale pores,and clay content 45%).Mineral composition,sedimentary-diagenetic processes,and fault systems collectively control reservoir property heterogeneity.Quartz-rich rigid frameworks resist compaction,resulting in a porosity increase by approximately 2% for every 10%rise in q uartz content.The transformation of clay minerals induces stratified porosity zoning within the layered reservoirs,while fault systems enhance heterogeneity through the development of fracture networks and acid-induced dissolution.This study provides theoretical support for the evaluation and development of shale oil sweet spots in the Weixinan Depression and holds practical significance for the commercial development of shale oil in China's offshore areas.展开更多
Significant hydrocarbon accumulations in the offshore Gulf of Gabes, Tunisia, remain largely undeveloped due to elevated concentrations of carbon dioxide(CO_(2)), nitrogen(N_(2)), and hydrogen sulfide(H_(2)S),which co...Significant hydrocarbon accumulations in the offshore Gulf of Gabes, Tunisia, remain largely undeveloped due to elevated concentrations of carbon dioxide(CO_(2)), nitrogen(N_(2)), and hydrogen sulfide(H_(2)S),which compromise commercial viability and have delayed field development. Addressing these constraints requires the deployment of technically robust and environmentally sustainable CO_(2) management strategies. Carbon capture, utilization, and storage(CCUS) offers a comprehensive solution by enabling the redirection of captured CO_(2) for enhanced oil recovery(EOR), industrial reuse, or permanent geological sequestration, supporting both resource recovery and long-term emissions mitigation.Building upon earlier pre-screening assessments, this study re-evaluates the CO_(2) storage potential of selected sites in the Gulf of Gabes, with a focus on informing integrated utilization and storage frameworks. Based on geological, logistical, and socioeconomic criteria, the Fd1 Field within the Hasdrubal development area was selected as a prime candidate. A multi-scale assessment approach was applied to characterize the geological context, reservoir properties, containment integrity, and injection feasibility. The Eocene El Garia Formation within Fd1 Field, composed of thick-bedded nummulitic limestones, was identified as the most suitable reservoir for sequestration. It offers favorable characteristics in terms of porosity(10 %–26 %), permeability(40–100 mD), adequate structural thickness, and effective sealing by the overlying caprock. A key contribution of this study lies in the integration of regional geological screening with advanced 3D coupled flow-geomechanical simulations, the first of its kind in Tunisia's offshore domain. The simulation workflow evaluated pressure evolution, CO_(2) plume migration, mechanical stability, and long-term seal integrity over a 30-year injection period. Results indicate that up to 16.5 million metric tonnes of CO_(2) can be safely injected at a daily rate of 1.174 Mm^(3),with pressure buildup remaining within acceptable thresholds and no caprock failure observed. Overall,the findings demonstrate the technical feasibility and containment reliability of CO_(2) storage in the El Garia Formation. The study establishes Fd1 Field as a strategic CCUS site and provides a transferable methodology for evaluating CO_(2) storage potential in fractured carbonate reservoirs across North Africa and comparable offshore settings.展开更多
The physical properties of hydrocarbon reservoirs are important factors affecting the percolation ability of the reservoirs.Tight-sand reservoirs exhibit complex pore throat connectivity due to the extensive developme...The physical properties of hydrocarbon reservoirs are important factors affecting the percolation ability of the reservoirs.Tight-sand reservoirs exhibit complex pore throat connectivity due to the extensive development of micro-and nano-scale pore and throat systems.Characterizing the microscopic properties of these reservoirs using nondestructive,quantitative methods serves as an important means to determine the characteristics of microscopic pores and throats in tight-sand reservoirs and the mechanism behind the influence of these characteristics on reservoir porosity and permeability.In this study,a low-permeability sandstone sample and two tight sandstone samples collected from the Ordos Basin were nondestructively tested using high-resolution nano-CT technology to quantitively characterize their microscopic pore throat structures and model them three-dimensionally(in 3D)based on CT threshold differences and gray models.A thorough analysis and comparison reveal that the three samples exhibit a certain positive correlation between their porosity and permeability but the most important factor affecting both porosity and permeability is the microscopic pore throat structure.Although the number of pores in tight sandstones shows a minor impact on their porosity,large pores(more than 20μm)contribute predominantly to porosity,suggesting that the permeability of tight sandstones is controlled primarily by large pore throats.For these samples,higher permeability corresponds to larger average throat sizes.Therefore,throats with average radii greater than 2μm can significantly improve the permeability of tight sandstones.展开更多
Accurate estimation of mineralogy from geophysical well logs is crucial for characterizing geological formations,particularly in hydrocarbon exploration,CO_(2) sequestration,and geothermal energy development.Current t...Accurate estimation of mineralogy from geophysical well logs is crucial for characterizing geological formations,particularly in hydrocarbon exploration,CO_(2) sequestration,and geothermal energy development.Current techniques,such as multimineral petrophysical analysis,offer details into mineralogical distribution.However,it is inherently time-intensive and demands substantial geological expertise for accurate model evaluation.Furthermore,traditional machine learning techniques often struggle to predict mineralogy accurately and sometimes produce estimations that violate fundamental physical principles.To address this,we present a new approach using Physics-Integrated Neural Networks(PINNs),that combines data-driven learning with domain-specific physical constraints,embedding petrophysical relationships directly into the neural network architecture.This approach enforces that predictions adhere to physical laws.The methodology is applied to the Broom Creek Deep Saline aquifer,a CO_(2) sequestration site in the Williston Basin,to predict the volumes of key mineral constituents—quartz,dolomite,feldspar,anhydrite,illite—along with porosity.Compared to traditional artificial neural networks (ANN),the PINN approach demonstrates higher accuracy and better generalizability,significantly enhancing predictive performance on unseen well datasets.The average mean error across the three blind wells is 0.123 for ANN and 0.042 for PINN,highlighting the superior accuracy of the PINN approach.This method reduces uncertainties in reservoir characterization by improving the reliability of mineralogy and porosity predictions,providing a more robust tool for decision-making in various subsurface geoscience applications.展开更多
Key technologies that make productivity increase are revealed through analyzing the best practices and production data in major shale basins of North America.Trends of the key technologies and optimization designs for...Key technologies that make productivity increase are revealed through analyzing the best practices and production data in major shale basins of North America.Trends of the key technologies and optimization designs for shale oil and gas development are summarized and analyzed based on drilling and completion operations and well data.These technologies mainly include:(1)Optimizing well design and hydraulic fracturing design,including reducing cluster spacing,increasing proppant and fracturing fluid volumes,optimizing horizontal well lateral length and fracture stage length.The most effective method is to reduce cluster spacing to an optimized length.The second most effective method is to optimally increase proppant volumes.(2)Placing horizontal wells in the sweet spots and drilling the wells parallel or close to the minimum horizontal stress direction.(3)Using cube development with optimized well spacing to maximize resource recovery and reduce well interferences.Plus,in-situ stress impacts on hydraulic fracture propagation and hydrocarbon production are addressed.Determination of formation breakdown pressure is studied by considering the impacts of in-situ stresses,drilling and perforation directions.Whether or not the hydraulic fracturing can generate orthogonal fracture networks is also discussed.The key technologies and optimization design parameters proposed in this paper can be applied to guide new well placement,drilling and completion designs,and hydraulic fracture operations to increase productivity.展开更多
Tectonic activities significantly impact deep reservoir properties via sedimentary and diagenetic processes,and this is particularly true for lacustrine rift basins.The tectonic-sedimentary-diageneticreservoir system ...Tectonic activities significantly impact deep reservoir properties via sedimentary and diagenetic processes,and this is particularly true for lacustrine rift basins.The tectonic-sedimentary-diageneticreservoir system is crucial in deep reservoir exploration.This study examined the first member and upper submember of the second member of the Dongying Formation in the Bodong Low Uplift in the Bohai Bay Basin(East China),documenting the petrologic features and physical properties of reservoirs in different tectonic sub-units through integrated analysis of log and rock data,along with core observation.A mechanism for deep reservoir formation in lacustrine rift basins was developed to elucidate the sedimentary and diagenetic processes in complex tectonic settings.The results show that tectonic activities result in the occurrence of provenances in multiple directions and the existence of reservoirs at varying burial depths,as well as the significant diversity in sedimentary and diagenetic processes.The grain sizes of the sandstones,influenced by transport pathways rather than the topography of the sedimentary area,exhibit spatial complexity due to tectonic frameworks,which determine the initial pore content of reservoirs.However,the burial depth,influenced by subsequent tectonic subsidence,significantly impacts pore evolution during diagenesis.Based on the significant differences of reservoirs in slope zone,low uplift and depression zone,we establish different tectonic-diagenetic models in deep complex tectonic units of lacustrine rift basins.展开更多
Gas-bearing shales have become a major source of future natural gas production worldwide.It has become increasingly urgent to develop a reliable prediction model and corresponding workflow for identifying shale gas sw...Gas-bearing shales have become a major source of future natural gas production worldwide.It has become increasingly urgent to develop a reliable prediction model and corresponding workflow for identifying shale gas sweet spots.The formation of gas-bearing shales is closely linked to relative sealevel changes,providing an important approach to predicting sweet spots in the Wufeng-Longmaxi shale in the southern Sichuan Basin,China.Three types of marine shale gas sweet spots are identified in the shale based on their formation stages combined with relative sea-level changes:early,middle,and late transgression types.This study develops a prediction model and workflow for identifying shale gas sweet spots by analyzing relative sea-level changes and facies sequences.Predicting shale gas sweet spots in an explored block using this model and workflow can provide a valuable guide for well design and hydraulic fracturing,significantly enhancing the efficiency of shale gas exploration and development.Notably,the new prediction model and workflow can be utilized for the rapid evaluation of the potential for shale gas development in new shale gas blocks or those with low exploratory maturity.展开更多
基金funded by the National Science and Technology Major Project(No.2016ZX05027-004)General Department Project of Shanghai Branch of CNOOC(China)Limited(No.KJ2022-JYZJ-SH01)。
文摘Tight sandstone reservoirs represent a pivotal unconventional oil and gas production target.The upper section of the deeply buried Huagang Formation in the Xihu Depression is abundant in hydrocarbons and forms a tight reservoir.It exhibits substantial diagenetic variability and strong heterogeneity in sand bodies,which is reflected in variations in physical properties and grain size.Through integrated geological analysis,including rock thin sections,scanning electron microscopy,X-ray diffraction,well logging and production test data,we investigated the diagenesis,reservoir formation mechanisms,and controlling factors of high-quality reservoirs within the superposed sandstone bodies exceeding 100 m thick in the deeper Huagang Formation.We also studied the formation characteristics of these ultrathick sandstones,clarifying that diagenesis and post-depositional modification are crucial for developing high-quality reservoirs in this formation.Our findings indicate that the sandstone underwent compaction,cementation(by chlorite,calcite and quartz),dissolution(of K-feldspar and carbonate cement),and authigenic clay mineral cementation(such as illite,chlorite,kaolinite).Multiple dissolution zones are present within the thick sandstone units.The distribution of these dissolution zones is mainly controlled by temperature and sandstone composition.With increasing temperature,acidic fluids derived from coal-bearing strata and early hydrocarbon source rocks promoted feldspar dissolution.The thick sandstone units in different intervals of varying depths are at various diagenetic stages.The petrophysical zoning of the reservoir is collectively controlled by diagenetic facies dominated by sedimentation,compaction,and dissolution processes.These findings provide valuable guidance and reference for oil and gas exploration and development in this area,particularly within the ultra-thick sandstone layers.
文摘Ghana has four sedimentary basins,but attention has mostly been concentrated on the Tano Basin.This preference among potential investors is largely due to the fact that it has been extensively studied and also its established oil and gas reserves,which have facilitated the discovery and development of major fields such as the Jubilee Field.In contrast,the Saltpond,Keta,and Voltaian basins have not undergone the same level of exploration and research,thereby making them less attractive to investors.A comparative analysis of the research conducted on the Tano Basin and the other basins is necessary to identify research opportunities that could enhance understanding of these less-explored basins and increase investor interests.The findings indicate that the Tano Basin requires minimal further exploration,while studies on the Saltpond,Keta,and Voltaian basins have primarily focused on sedimentological and geochemical analyses,offering valuable but limited insights into their petroleum systems and hydrocarbon potential.Unlocking Ghana's hydrocarbon potential demands tailored studies for each basin.In the Tano Basin,the key to sustaining and optimizing production lies in advanced seismic reprocessing,pre-stack depth migration,4D reservoir monitoring,and machine-learning-assisted reservoir characterization to address deepwater complexity and compartmentalization.Revitalizing the Saltpond Basin demands updated petroleum system evaluation through modern geochemical techniques,reprocessed 2D/3D seismic data,and comprehensive 1D–3D basin modeling to clarify trap integrity and overlooked plays.In the underexplored Accra–Keta Basin,high-resolution seismic imaging,sequence stratigraphic mapping,and full petroleum system modeling are essential to define reservoir intervals and assess charge potential.For the Voltaian Basin,a deep seismic profiling,integrated geological mapping,source-rock evaluation,and analog-based reservoir/seal studies are required to evaluate its hydrocarbon potential.These targeted efforts are key to de-risking and advancing exploration.An integrated approach is vital for gaining a deeper understanding of the petroleum system elements in these basins.This will not only expand scientific knowledge and inform decision-making at the highest levels but also provide a strong foundation for future exploration,development,and efficient exploitation of hydrocarbon resources.
基金supported by the National Science and Technology Project of China(No.2024ZD1004300)。
文摘The effective channeling of fluid flow by fractures is a liability for enhanced oil recovery(EOR)methods like CO_(2) flooding or CO_(2) storage.Developing a distributed fracture model to understand the heterogeneity of the fracture network is essential in characterizing tight and low-permeability reservoirs.In the Ordos Basin,the Chang 8-1-2 layer of the Yanchang Formation is a typical tight and low permeability reservoir in the JH17 wellblock.The strong heterogeneity of distributed fractures,differing fracture scales and fracture types make it difficult to effectively characterize the fracture distribution within the Chang 8-1-2 layer.In this paper,multi-source and multi-attribute methods are used to integrate data into a neural network at different scales,and fuzzy logic control is used to judge the correlation of various attributes.The results suggest that attribute correlation between coherence and fracture indication is the best,followed by correlations with fault distance,north–south slope,and north–south curvature.Advantageous attributes from the target area are used to train the neural network,and the fracture density model and discrete fracture network(DFN)model are built at different scales.This method can be used to effectively predict the distribution characteristics of fractures in the study area.And any learning done by the neural network from this case study can be applied to fracture network modeling for reservoirs of the same type.
基金funded by the Opening Project of Oil&Gas Field Applied Chemistry Key Laboratory of Sichuan Province(YQKF202214)。
文摘During drilling process,the water phase in drilling fluids infiltrates rock fractures through capillary action.The surface wettability of dolomite is governed by multiple factors,resulting in an unstable wetting state.Studies have shown that altering the surface wettability of reservoir rocks to an intermediate wetting state can effectively reduce the damage of drilling fluids to oil and gas reservoirs and improve oil and gas recovery.Therefore,it is necessary to develop a reservoir protectant to prevent the water phase in the drilling fluid from intruding into the oil and gas reservoirs.Given this,a modified polysiloxane was synthesized to alter the surface wettability of dolomite.Tetramethylcyclotetrasiloxane(D^(H)_(4))and octamethylcyclotetrasiloxane(D_(4))were ring-opened copolymerized to obtain the hydrogencontaining polysiloxane,which in turn reacted with unsaturated hydrocarbons to obtain the modified polysiloxane.The ability of reservoir protectants to regulate the surface wettability of dolomite under high-temperature and high-salinity conditions was tested.The experimental results show that the reservoir protectant is able to alter the wettability of the dolomite surface to an intermediate wetting state by adsorption on the rock surface even after 16 h of aging at 240℃ and 15% salt concentration.
基金supported by the project grant,MLP-7016-28(EVB)of CSIR-NGRI,India。
文摘This study investigates four Late Permian Gondwana coals from the Raniganj sub-basin,Damodar Valley and three Early Permian Gondwana coals from the Talcher sub-basin,Mahanadi Valley.The study aims to characterize the kerogen type,hydrocarbon generation potential,thermal maturity,and organic matter composition,as well as to explore the impact of organic matter characteristics on kerogen kinetic parameters,utilizing multi proxy approach.The study further investigates the influence of the mineral matrix on kerogen decomposition kinetics.Based on the Rock-Eval parameters,Fourier transform infrared spectroscopy(FTIR)parameters,and vitrinite reflectance(R_(o)),the kerogen is primarily classified as immature/early mature TypeⅢkerogen derived from terrestrial land plants,with minor contribution from TypeⅡkerogen having mainly gas generating potential.The source of the organic matter,as determined by stable carbon isotopic composition(δ^(13)C_(org))values and C/N ratios indicates a primary input from C_(3) terrestrial plants.The presence of enriched collotelinites and liptinites,such as sporinite and resinite,provides evidence for the input of terrestrial higher plants,including both herbaceous and arborescent species.Various indices derived from maceral abundances,including the gelification index(GI),tissue preservation index(TPI),and vegetation index(VI),collectively indicate diverse depositional conditions which range from wet forest swamps to shallow water-covered wet forest swamps and even dry forest swamps.The variation in vitrinite macerals influenced the kerogen type and consequently impacted the kinetic parameters,viz.the distribution of activation energies(E_(a)),kerogen transformation ratio(KTR),and hydrocarbon generation rate(HGR).Among the Talcher coals,shaly coals exhibit different kerogen type and kerogen transformation.This dissimilarity can be attributed to variable maceral compositions.Unlike the Talcher samples,all Raniganj samples show consistent kinetic behaviour despite their sample type(coal/shaly coal)or kerogen type(TypeⅢ/mixed TypeⅡ/Ⅲ)owing to comparable liptinite/vitrinite maceral composition.This study reveals that whilst the presence of mineral matrix shifts the apparent E_(a) of kerogen through interactions like adsorption and catalysis,it does not significantly affect the kerogen type,HGR,or KTR of the studied coals.
文摘Delineating sweet spots is critical for the exploration and production of oil and gas in deep and tight sand reservoirs.The lack of advanced and reliable methods makes this a challenge for geologists and geophysicists.This study introduces,for the first time,an integrated workflow that combines pre-stack seismic inversion with rock physics modeling to predict reservoir porosity and shale volume(V-shale)for sweet spot identification in tight sand reservoirs.A new elastic parameter,the density calculation index(DCI),is introduced which links acoustic and shear impedance for seismic density inversion,thereby addressing the long-standing problem of poor density inversion accuracy.A novel combined Sun–Walsh rock physics model,developed as part of this study,significantly improves V-shale evaluation from seismic data.The proposed three-step seismic inversion approach includes:(1)deriving acoustic and shear impedance from angle-stack seismic data using model-based inversion;(2)calculating density using shear impedance constrained by DCI,followed by porosity estimation from the density–porosity relation;and(3)evaluating V-shale using theα-parameter derived from the Sun–Walsh model and pre-stack inversion results.This integrated workflow provides an effective tool for building accurate 3D reservoir models,and is especially applicable to deep,low-porosity,tight sand reservoirs worldwide.
基金funded by the Project of Xinjiang University of Technology(No.2025XQYM044)PetroChina Coalbed Methane Company Project(No.WK23020DG04)。
文摘Fault sealing capacity is controlled by present-day geometry and clay content,with current research focusing on enhancing the accuracy of capacity estimates.The mechanisms for evaluating both presentday and paleo-sealing are consistent,where the current sealing capacity representing the final stage in the evolutionary process of fault sealing.To address the limitations of the conventional shale gouge ratio(SGR)in evaluating the dynamic nature of fault sealing,this study proposes a visual model for fault sealing evolution.Fault sealing evolution is jointly controlled by the burial history and clay smear history and exerts a critical influence on hydrocarbon migration and accumulation.Hydrocarbon exploration data confirm that fault sealing during and after hydrocarbon migration critically impacts reservoir preservation.If faults remain unsealed during hydrocarbon migration and accumulation,they serve solely as conduits,with their present-day sealing capacity having limited impact.Effective fault sealing thus depends on the alignment between the evolutionary sealing stages and hydrocarbon activity.Building on this framework,we propose a method to visually and quantitatively characterize the fault sealing evolution alongside hydrocarbon activity.A case study of the Xishanyao Formation in the Houxia Basin highlights that the F4 fault transitioned from being over-open to sealed at the onset of hydrocarbon migration,thereby preserving the trap,while the F8-2 fault underwent a complete sealed–reopen cycle,with the late-stage reopening leading to an absence of hydrocarbon accumulation.This temporal contrast forms the basis for a new time-sensitive methodology for assessing fault-seal integrity in complex structural settings.
基金funded by the Sinopec Science and Technology Project(No.P23132)the AAPG Foundation Grants-inAid Program(No.18644937)。
文摘By investigating the evolution of shale gas generation,storage,adjustment and accumulation under different structural settings in superimposed basins,this study elucidates the differential accumulation mechanisms of shale gas.An improved evaluation method of shale gas content evolution in superimposed basins is proposed.This method incorporates the coupling effect of key geological factors such as temperature,pressure,organic matter abundance,maturity,and pore characteristics on the content and occurrence state of shale gas,as well as the configuration relationship between shale gas generation and storage throughout geological history.Using this approach,the gas evolution histories of the Longmaxi Formation shales in wells N201 and PY1 are reconstructed under varying geological conditions.The Longmaxi Formation shales in these wells are dominated by typeⅠkerogen,with original total organic carbon(TOC_(o))contents of 6.20 wt% and 4.92 wt%,respectively,indicating differences in the initial material basis for gas generation.At the maximum burial depth of approximately 5000 m,the Longmaxi Formation shale in well N201 exhibits a formation pressure coefficient of 2.05,an organic matter maturity of 2.2%,and organic pores accounting for 68%of the total porosity.The gas generation quantity(Q_(g))reaches 19.24 m^(3)/t,while the gas storage capacity(Q_(s))is 4.30 m^(3)/t.The actual total gas content(Q_(a)),constrained by Q_(s),is 4.30 m^(3)/t,with free gas comprising 94%.Following relatively moderate tectonic uplift,the Q_(a) in well N201 decreases to 4.03 m^(3)/t,with free gas accounting for 63%.In contrast,the Longmaxi Formation shale in well PY1 reached a maximum burial depth of 6300 m,associated with a formation pressure coefficient of 1.62,organic matter maturity of 2.5%,and organic pore proportion of 67%.Here,Q_(g) is 16.87 m^(3)/t,and both Q_(s) and Q_(a) are 3.65 m^(3)/t,with free gas accounting for 98%.After intense tectonic uplift,Q_(a) declines to 2.72 m^(3)/t,and the proportion of free gas drops to51%.Finally,a four-stage differential accumulation model of shale gas is established:Slow gas generation and only adsorbed gas occur in stageⅠ,which is primarily controlled by TOC content;both adsorbed gas and free gas present in stageⅡ,with free gas becoming dominant;rapid gas generation and free gas predominance are controlled by temperature and porosity in stageⅢ;and gas adjustment and accumulation are primarily controlled by temperature and pressure in stageⅣ.
基金funded by the Technical Development(Entrusted)Project of Science and Department of SINOPEC(Grant No.P23240-4)the National Natural Science Foundation of China(Grant Nos.42172165,42272143 and 2025ZD1403901-05)。
文摘The Wufeng–Longmaxi Formation derives its name from the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation,found in sequence in the Sichuan Basin.This formation hosts rich shale gas reservoirs,and its shale gas enrichment patterns are examined in this study using data from 1197 shale samples collected from 14 wells.Five basic and three key parameters,eight in all,are assessed for each sample.The five basic parameters include burial depth and the contents of four mineral types—quartz,clay,carbonate,and other minerals;the three key parameters,representing shale gas enrichment,are total organic carbon(TOC)content,porosity,and gas content.The SHapley Additive exPlanations(SHAP)analysis originated in game theory is used here in an interpretable machine learning framework,to address issues of heterogeneous data structure,noisy relationships,and multi-objective optimization.An evaluation of the ranking,contribution values,and conditions of changes for these parameters offers new quantitative insights into shale gas enrichment patterns.A quantitative analysis of the relationship between data-sets identifies the primary factors controlling TOC,porosity,and gas content of shale gas reservoirs.The results show that TOC and porosity jointly influence gas content;mineral content has a significant impact on both,TOC and porosity;and the burial depth governs porosity which,in turn,affects the conditions under which shale gas is preserved.Input parameter thresholds are also determined and provide a basis for the establishment of quantitative criteria to evaluate shale gas enrichment.The predictive accuracy of the model used in this study is significantly improved by the step-wise addition of two input parameters,namely TOC and porosity,separately and together.Thus,the game theory method in big data-driven analysis uses a combination of TOC and porosity to evaluate the gas content with encouraging results—suggesting that these are the key parameters that indicate source rock and reservoir properties.
文摘Organic-rich sediments represent vital components of Earth's geochemical cycles, acting both as potential hydrocarbon and coal reservoirs and as unconventional archives for critical metals such as rare earth elements(REEs). With the growing emphasis on clean energy technologies, the Cenozoic organic deposits of India have gained renewed significance;however, those from the southern state of Kerala remain understudied. This study investigates lignite and associated carbonaceous sediments from the Cheruvathur and Warkalli Formations using a multi-proxy approach integrating organic petrography,infrared spectroscopy, stable carbon isotopes, and REE geochemistry. The lignite exhibits huminite dominance with Type Ⅲ kerogen, deposited in a wet, mesotropic bog forest swamp under anoxic conditions. The mineral assemblage, dominated by kaolinite, quartz, illite, montmorillonite, feldspar,and pyrite/marcasite, reflects strong chemical alteration in a reducing environment. The δ^(13)C values(-25.1 to-27.3) indicate a C_(3) angiosperm source and deposition in tropical to subtropical swamp settings. REE patterns reveal LREE enrichment in carbonaceous shales and HREE enrichment in lignite,with distinct Ce, Eu, and Gd anomalies associated with provenance and redox conditions. The findings provide new insights into the paleoenvironmental evolution of Kerala's Cenozoic basins and highlight their potential as unconventional REE-bearing resources in the context of the global energy transition.
基金supported by the Natural Environment Research Council[grant number NE/S007415/1]Shell as iCASE sponsors。
文摘Unsecured legacy wells pose significant risks to carbon capture and storage(CCS)as they present potential leakage pathways for stored CO_(2) to return to the atmosphere.In the UK,legacy wells must be assessed for a carbon storage permit to be granted and high-risk wells require costly remediation.We use a well risk assessment scheme to evaluate the risk of wells in the Southern North Sea.We then combine our well risk assessment with investigation using the analytical tool CO2BLOCK,which relies on a gravity current model to estimate pressure and plume migration distances.We evaluate the Viking,Camelot and Poseidon projects,which plan to inject CO_(2) into the depleted reservoirs of Southern North Sea gas fields.Carbon dioxide plumes are typically several kilometers wide,and it should be possible to avoid plume migration to high-risk legacy wells.In contrast,pressure fields produced by CO_(2) injection are tens of kilometers wide and low magnitude pressure increases frequently extend beyond the bounds of storage licence areas.The pressure fields encounter hundreds of wells and in the cases of the Camelot and Poseidon projects,interact with each other.
基金funded by the National Natural Science Foundation of China(Grant No.42102169)the Shaanxi Province key Research and Development Project(Grant No.2023-ZDLSF-64)+1 种基金the Scientific Research and Technological Development Project of China National Logging Corporation(Grant No.25ZYCJSG013-2504)the Youth Science and Technology Special Fund of PetroChina(Grant No.2024DQ03172)。
文摘Geological CO_(2) storage is a promising strategy for reducing greenhouse gas emissions and has become a growing focus of research and deployment.This paper presents numerical simulations of CO_(2) injection and storage in a depleted gas reservoir within the B Depression and evaluates associated CO_(2) trapping mechanisms.In the base case,a constant injection rate of 3500 m^(3)/d over fifteen years resulted in a cumulative injection of 19.2×10^(6) m^(3).The CO_(2) plume expanded radially during injection and subsequently migrated up-dip under buoyancy forces.The final stored mass of CO_(2) in the reservoir was 10.6 million tonnes(Mt),representing less than 10% of its theoretical capacity.The plume was projected to reach the entrapment crest and the top of the reservoir within a century,indicating secure long-term containment.Structural,stratigraphic,and residual trapping dominate in Reservoir A(approximately 90%).Anticlinal closures with thick overlying mudstones in the Zhujiang Formation provide effective seals,further enhancing storage security.Reservoir properties and heterogeneity play a crucial role in controlling CO_(2) storage.However,reservoir heterogeneity exerts only a limited influence when intrinsic properties are favorable.Overall,the study and implementation of CO_(2) capture,utilization,and storage(CCUS)in China's offshore basins show promising prospects.
基金supported by the National Natural Science Foundation of China(52304098,52106092,42376215,52474105)Shenzhen Science and Technology Program(JCYJ20220818095605012,JCYJ20220530113011027)+5 种基金Guangdong Basic and Applied Basic Research Foundation(2022A1515110338,2023A1515012316,2023A1515012761,2025A1515010748)Research Team Cultivation Program of Shenzhen University(2023QNT004)Shenzhen Key Laboratory of Natural Gas Hydrates(ZDSYS20200421111201738)the General Research Fund(No.12616222)Early Career Scheme(No.22611624)of Hong Kong Research Grants CouncilMajor Science and Technology Infrastructure Project of Material Genome Big–science Facilities Platform supported by the Municipal Development and Reform Commission of Shenzhen。
文摘Carbon Capture,Utilization,and Storage(CCUS)technology has gained widespread attention in recent years as a critical strategy to combat global climate change,particularly in achieving carbon neutrality goals.The Guangdong-Hong Kong-Macao Greater Bay Area(GBA),as one of China's most economically active regions,serves as a key engine for economic growth while also facing considerable carbon emission challenges.This study analyzes the industrial emission volume and geographical distribution of key emitting enterprises in the GBA,summarizes their technological processes and main carbonemitting equipment,and provides scientific support for precise mitigation policies and low-carbon development.Based on data from 176 key emitting enterprises,the study reveals that Guangzhou and Dongguan host the largest number of such enterprises.Carbon emissions are primarily concentrated in the power sector,dominated by coal-and gas-fired power units,characterized by significant spatial dispersion and uneven distribution.Beyond the power sector,the paper industry has a high number of enterprises but lower emissions.Key facilities such as boilers,cogeneration systems,and production lines are predominantly located near tributaries rivers in Dongguan and Jiangmen.The building materials sector,primarily cement production,ranks as the second-largest emitter,with hightemperature kilns and grinding equipment,particularly rotary kilns and glass furnaces,as the main sources.The petrochemical and chemical sectors have fewer enterprises and lower emissions in the GBA,mainly located in suburban industrial clusters.Carbon emissions in the GBA exhibit distinct industry concentration and geographical distribution disparities.This study provides crucial data and theoretical insights for the development of targeted emission reduction strategies,optimization of source-sink matching,and the advancement of CCUS technologies in the region,particularly from the GBA to the northern South China Sea.
基金jointly supported by the National Natural Science Foundation of China(42474156)the Technical Service Project of China Oilfield Services Limited(YJB23YF001)。
文摘The Liushagang Formation in the Weixinan Depression,Beibu Gulf Basin,southern China,is one of the key stratigraphic units for offshore shale oil exploration in the country.The shale oil reservoirs in the formation are characterized by low porosity,low permeability and strong heterogeneity,which constrain the precise evaluation of reservoir properties,the accurate prediction of sweet spots,and efficient development.This study integrates core observation,mineralogical analysis,and multi-scale pore characterization to systematically clarify the variations in reservoir properties and their controlling mechanisms.The results show that the physical properties of matrix-type,lamina-type,and interlayer-type reservoirs exhibit distinct stepwise variations:Among these,interlayer-type reservoirs show the greatest development potential(quartz content 65%,average porosity 15%,permeability>10 mD,and mobile fluid saturation 60%),whereas matrix-type reservoirs are the least favorable(dominated by 40 nm nanoscale pores,and clay content 45%).Mineral composition,sedimentary-diagenetic processes,and fault systems collectively control reservoir property heterogeneity.Quartz-rich rigid frameworks resist compaction,resulting in a porosity increase by approximately 2% for every 10%rise in q uartz content.The transformation of clay minerals induces stratified porosity zoning within the layered reservoirs,while fault systems enhance heterogeneity through the development of fracture networks and acid-induced dissolution.This study provides theoretical support for the evaluation and development of shale oil sweet spots in the Weixinan Depression and holds practical significance for the commercial development of shale oil in China's offshore areas.
文摘Significant hydrocarbon accumulations in the offshore Gulf of Gabes, Tunisia, remain largely undeveloped due to elevated concentrations of carbon dioxide(CO_(2)), nitrogen(N_(2)), and hydrogen sulfide(H_(2)S),which compromise commercial viability and have delayed field development. Addressing these constraints requires the deployment of technically robust and environmentally sustainable CO_(2) management strategies. Carbon capture, utilization, and storage(CCUS) offers a comprehensive solution by enabling the redirection of captured CO_(2) for enhanced oil recovery(EOR), industrial reuse, or permanent geological sequestration, supporting both resource recovery and long-term emissions mitigation.Building upon earlier pre-screening assessments, this study re-evaluates the CO_(2) storage potential of selected sites in the Gulf of Gabes, with a focus on informing integrated utilization and storage frameworks. Based on geological, logistical, and socioeconomic criteria, the Fd1 Field within the Hasdrubal development area was selected as a prime candidate. A multi-scale assessment approach was applied to characterize the geological context, reservoir properties, containment integrity, and injection feasibility. The Eocene El Garia Formation within Fd1 Field, composed of thick-bedded nummulitic limestones, was identified as the most suitable reservoir for sequestration. It offers favorable characteristics in terms of porosity(10 %–26 %), permeability(40–100 mD), adequate structural thickness, and effective sealing by the overlying caprock. A key contribution of this study lies in the integration of regional geological screening with advanced 3D coupled flow-geomechanical simulations, the first of its kind in Tunisia's offshore domain. The simulation workflow evaluated pressure evolution, CO_(2) plume migration, mechanical stability, and long-term seal integrity over a 30-year injection period. Results indicate that up to 16.5 million metric tonnes of CO_(2) can be safely injected at a daily rate of 1.174 Mm^(3),with pressure buildup remaining within acceptable thresholds and no caprock failure observed. Overall,the findings demonstrate the technical feasibility and containment reliability of CO_(2) storage in the El Garia Formation. The study establishes Fd1 Field as a strategic CCUS site and provides a transferable methodology for evaluating CO_(2) storage potential in fractured carbonate reservoirs across North Africa and comparable offshore settings.
文摘The physical properties of hydrocarbon reservoirs are important factors affecting the percolation ability of the reservoirs.Tight-sand reservoirs exhibit complex pore throat connectivity due to the extensive development of micro-and nano-scale pore and throat systems.Characterizing the microscopic properties of these reservoirs using nondestructive,quantitative methods serves as an important means to determine the characteristics of microscopic pores and throats in tight-sand reservoirs and the mechanism behind the influence of these characteristics on reservoir porosity and permeability.In this study,a low-permeability sandstone sample and two tight sandstone samples collected from the Ordos Basin were nondestructively tested using high-resolution nano-CT technology to quantitively characterize their microscopic pore throat structures and model them three-dimensionally(in 3D)based on CT threshold differences and gray models.A thorough analysis and comparison reveal that the three samples exhibit a certain positive correlation between their porosity and permeability but the most important factor affecting both porosity and permeability is the microscopic pore throat structure.Although the number of pores in tight sandstones shows a minor impact on their porosity,large pores(more than 20μm)contribute predominantly to porosity,suggesting that the permeability of tight sandstones is controlled primarily by large pore throats.For these samples,higher permeability corresponds to larger average throat sizes.Therefore,throats with average radii greater than 2μm can significantly improve the permeability of tight sandstones.
基金the North Dakota Industrial Commission (NDIC) for their financial supportprovided by the University of North Dakota Computational Research Center。
文摘Accurate estimation of mineralogy from geophysical well logs is crucial for characterizing geological formations,particularly in hydrocarbon exploration,CO_(2) sequestration,and geothermal energy development.Current techniques,such as multimineral petrophysical analysis,offer details into mineralogical distribution.However,it is inherently time-intensive and demands substantial geological expertise for accurate model evaluation.Furthermore,traditional machine learning techniques often struggle to predict mineralogy accurately and sometimes produce estimations that violate fundamental physical principles.To address this,we present a new approach using Physics-Integrated Neural Networks(PINNs),that combines data-driven learning with domain-specific physical constraints,embedding petrophysical relationships directly into the neural network architecture.This approach enforces that predictions adhere to physical laws.The methodology is applied to the Broom Creek Deep Saline aquifer,a CO_(2) sequestration site in the Williston Basin,to predict the volumes of key mineral constituents—quartz,dolomite,feldspar,anhydrite,illite—along with porosity.Compared to traditional artificial neural networks (ANN),the PINN approach demonstrates higher accuracy and better generalizability,significantly enhancing predictive performance on unseen well datasets.The average mean error across the three blind wells is 0.123 for ANN and 0.042 for PINN,highlighting the superior accuracy of the PINN approach.This method reduces uncertainties in reservoir characterization by improving the reliability of mineralogy and porosity predictions,providing a more robust tool for decision-making in various subsurface geoscience applications.
文摘Key technologies that make productivity increase are revealed through analyzing the best practices and production data in major shale basins of North America.Trends of the key technologies and optimization designs for shale oil and gas development are summarized and analyzed based on drilling and completion operations and well data.These technologies mainly include:(1)Optimizing well design and hydraulic fracturing design,including reducing cluster spacing,increasing proppant and fracturing fluid volumes,optimizing horizontal well lateral length and fracture stage length.The most effective method is to reduce cluster spacing to an optimized length.The second most effective method is to optimally increase proppant volumes.(2)Placing horizontal wells in the sweet spots and drilling the wells parallel or close to the minimum horizontal stress direction.(3)Using cube development with optimized well spacing to maximize resource recovery and reduce well interferences.Plus,in-situ stress impacts on hydraulic fracture propagation and hydrocarbon production are addressed.Determination of formation breakdown pressure is studied by considering the impacts of in-situ stresses,drilling and perforation directions.Whether or not the hydraulic fracturing can generate orthogonal fracture networks is also discussed.The key technologies and optimization design parameters proposed in this paper can be applied to guide new well placement,drilling and completion designs,and hydraulic fracture operations to increase productivity.
基金funded by the Open Fund of Key Laboratory of Marine Geology and Environment,Chinese Academy of Sciences(Grant No.MGE2020KG10)the Open Fund of Key Laboratory of Submarine Geosciences,Ministry of Natural Resources(Grant No.KLSG 2208)+2 种基金the Natural Science Basic Research Program of Shaanxi(Grant No.2024JC-YBMS-227,2023-JC-QN-0287)the Postgraduate Innovation and Practice Ability Development Fund of Xi'an Shiyou University(No.YCS23113046)the National Natural Science Foundation of China(Grant No.41802128,42076219)。
文摘Tectonic activities significantly impact deep reservoir properties via sedimentary and diagenetic processes,and this is particularly true for lacustrine rift basins.The tectonic-sedimentary-diageneticreservoir system is crucial in deep reservoir exploration.This study examined the first member and upper submember of the second member of the Dongying Formation in the Bodong Low Uplift in the Bohai Bay Basin(East China),documenting the petrologic features and physical properties of reservoirs in different tectonic sub-units through integrated analysis of log and rock data,along with core observation.A mechanism for deep reservoir formation in lacustrine rift basins was developed to elucidate the sedimentary and diagenetic processes in complex tectonic settings.The results show that tectonic activities result in the occurrence of provenances in multiple directions and the existence of reservoirs at varying burial depths,as well as the significant diversity in sedimentary and diagenetic processes.The grain sizes of the sandstones,influenced by transport pathways rather than the topography of the sedimentary area,exhibit spatial complexity due to tectonic frameworks,which determine the initial pore content of reservoirs.However,the burial depth,influenced by subsequent tectonic subsidence,significantly impacts pore evolution during diagenesis.Based on the significant differences of reservoirs in slope zone,low uplift and depression zone,we establish different tectonic-diagenetic models in deep complex tectonic units of lacustrine rift basins.
文摘Gas-bearing shales have become a major source of future natural gas production worldwide.It has become increasingly urgent to develop a reliable prediction model and corresponding workflow for identifying shale gas sweet spots.The formation of gas-bearing shales is closely linked to relative sealevel changes,providing an important approach to predicting sweet spots in the Wufeng-Longmaxi shale in the southern Sichuan Basin,China.Three types of marine shale gas sweet spots are identified in the shale based on their formation stages combined with relative sea-level changes:early,middle,and late transgression types.This study develops a prediction model and workflow for identifying shale gas sweet spots by analyzing relative sea-level changes and facies sequences.Predicting shale gas sweet spots in an explored block using this model and workflow can provide a valuable guide for well design and hydraulic fracturing,significantly enhancing the efficiency of shale gas exploration and development.Notably,the new prediction model and workflow can be utilized for the rapid evaluation of the potential for shale gas development in new shale gas blocks or those with low exploratory maturity.
