Economically recovering oil from tight/shale reservoirs requires extensively developed propped fracture networks and rock matrices with sufficient oil mobility, which imposes higher demands on the fracturing fluid. This study develops a DME-aided viscous slickwater (MEVS) that addresses these dual challenges. During hydraulic fracturing, DME reinforces viscoelasticity through hydrophobic association, significantly improving proppant-carrying capacity without substantially increasing viscosity, thereby enabling the creation of extensive propped fractures. After hydraulic fracturing, DME minimizes surfactant adsorption and deepens wettability alteration, thereby enlarging the water-wet zone of rock matrix to enhance oil recovery via imbibition and increased oil relative permeability. Laboratory evaluations using a visualized rough fracture model reveal that the fluid elasticity can be quantified using the Weissenberg number, and then used to predict the proppant transport performance at a specific flow condition during hydraulic fracturing. In-situ NMR and pressure transmission tests confirm that DME can mobilize oil in different-sized pores from the tight rock and significantly enhance oil recovery through water imbibition, meanwhile accelerating the pressure propagation by two orders of magnitude and enlarging the surfactant-modified zone. Field applications demonstrate that MEVS can successfully carry 400 kg/m3 proppants at 10 m3/min without plugging issues, and triple oil production comparing to wells using the conventional slickwater. This work establishes an integrated fracturing-EOR approach and provides a laboratory-based method to optimize the pumping schedule in field operations.

Severe steam channeling in heterogeneous heavy oil reservoirs severely restricts thermal recovery efficiency, as conventional conformance control materials cannot simultaneously achieve long-term high-temperature resistance and deep reservoir penetration. This work develops a high-temperature-resistant epoxy-based liquid microsphere system for deep profile control in heavy oil steam flooding. A triple thermal-stabilization strategy is constructed: imide chain extension to enhance backbone rigidity, benzoxazine-phthalonitrile grafting to form dense triazine crosslinked networks, and KH-550-functionalized nano-silica for synergistic reinforcement. FT-IR and 1H NMR verify the successful incorporation of rigid imide and triazine structures. TGA confirms the optimal formulation exhibits less than 5% mass loss at 350 °C. Multi-segment sand-packed tube tests demonstrate favorable deep migration capacity with inter-stage pressure ratios below 4 across 5000–15,000 × 10−3 μm2 permeability, and the cured network retains over 95% plugging efficiency after 350 °C steam scouring. Dual-tube heterogeneous flooding delivers 12.05% incremental oil recovery, outperforming rigid inorganic particles. This system provides a high-performance candidate for deep steam channeling mitigation in heavy oil thermal recovery.

Widely developed in marine and continental strata worldwide, mixed sedimentation is an important type of high-quality reservoir with significant implications for oil and gas exploration and development. Various types of lacustrine mixed sedimentation were developed in The Sha 1-2 members of the Paleogene in the Bohai Sea area, constituting unique form of mixed sedimentation in the eastern basins of China. Exploration results have revealed that the anomalously high-porosity zones in deep lacustrine carbonate reservoirs within the Shahejie formation of the Bohai Sea are in positive correlation with the development intervals of micritic envelopes. However, current understanding of the distribution patterns of micritic envelopes and their mechanisms on reservoirs remains limited. Systematically investigating the influence and genetic models of micritic envelopes on high-quality mixed sedimentary reservoirs in continental lacustrine basins holds significant importance for reservoir geological research and hydrocarbon exploration in the Bohai Sea and analogous basins worldwide.Utilizing various techniques such as core observation, thin-section identification, FIB-SEM, fluid simulation experiments, rare earth element analysis, and laser micro-area carbon-oxygen isotope analysis, systematic research was obtained on the microstructure of micritic envelopes, their stability under different acidic conditions, and their selective dissolution mechanism of different types of grains. Based on the type of attached grains, micritic envelopes are classified into three categories: sandy-gravelly micritic envelopes, bioclast micritic envelopes, and ooid micritic envelopes. Statistic results show that micritic envelopes selectivity develop on grains such as volcanic gravels, rock feldspars or matrix, bioclasts, and ooids. Moreover, micritic envelopes exhibit numerous microbial borings, and their unique structure facilitates fluid exchange with the external environment. It is common to observe complete dissolution of feldspar or rock matrix grains and bioclasts within the micritic envelopes, suggesting that the envelopes present function similarly to a "molecular sieve." Further research indicated that reservoirs with developed micritic envelopes show a notably higher degree of dolomitization. Microbial activity produces abundant spherical microbial dolomite, with early diagenetic dolomite providing nucleation for late diagenetic dolomite, thereby promoting continuous dolomitization. Simulation experiments demonstrate that under similarly weak acidic conditions, calcite and dolomite dissolve prior to the micritic envelopes. This differential dissolution plays a crucial role in supporting and preserving pores in the reservoirs.Macroscopically, the distribution of different types of micritic envelopes is evidently constrained by lacustrine facies belts. Nearshore steep slopes mainly develop gravelly beach bars interbedded with bioclast beach bar assemblages, where micritic envelopes on volcanic grains and bioclasts are common. Nearshore gentle slopes, influenced by intermittent sediment supply from braided river deltas, often form grain aggregate shoals, ooid shoals, and sandy shoal lithological associations, where bioclast and ooid micritic envelopes develop. In subaqueous paleo-uplift areas far from the lake shore, bioclast beach bars develop, which is corresponded to bioclast micritic envelopes. The research findings on the controlling effects of micritic e

Shallow deltaic thin-bedded (mostly 2-5 m) sandstones of the Upper Miocene Minghuazhen Formation in the Bohai Offshore Basin are among the most significant offshore hydrocarbon reservoirs in China. The prediction of sandstone is essential for breakthroughs in oil and gas exploration. We introduce an enhanced seismic lithology workflow, along with refined seismic methods to unravel the sedimentology. Specifically, within parasequence sets, we establish a quantitative relationship between sand content and seismic amplitude through lithofacies, sedimentary microfacies analysis, and forward modeling. Furthermore, we use common seismic attributes to interpret the thin-bedded lithology and to map the sedimentology. Taking the BZ29 block as an example, we subdivided the lower member of the Minghuazhen Formation into 10 parasequence sets and 6 lithofacies. Based on the selection of 50 samples from representative parasequence sets, we established, through the calculation of sand content, one-dimensional forward modeling and normalization of the amplitude, a strong exponential relationship (coefficient of determination = 0.85) between sand content and amplitude. The interpretations of thin-bedded lithology indicate that shallow deltas are dominated by distributary channel sands, which are potentially good reservoirs, and that the consistency of the sandstone predictions is high. The objectives of our seismic lithology workflow are to establish an intrinsic relationship between sand content and amplitude if the

The carbonate reservoirs of the Guadalupian series in the Middle Permian are an important target for natural gas exploration in the Sichuan Basin. Episodic Emeishan mantle-plume activity reconfigured the Upper Yangtze depositional architecture: pre-eruptive doming controlled the Roadian-Wordian carbonate-ramp system, whereas volcanic eruption drove a Capitanian transition to a rimmed carbonate platform, generating a SE-NW-trending platform-margin belt along the northern Upper Yangtze Block. Research indicates significant differences in rock types and diagenetic processes on both sides of the platform margin belt, which may be influenced by the potential effects of the Emeishan mantle-plume activity. This study integrates representative wells along the northern Upper Yangtze platform margin, combining detailed petrography with C-O stable-isotope analyses, in situ microscale rare-earth-element determinations, and U-Pb carbonate geochronology to define margin-flanking lithofacies, elucidate the origin and evolution of their contrasting diagenetic signatures, and evaluate their potential linkage to Emeishan mantle-plume activity. The results indicate the following: (1) On both sides of the platform-margin belt along the Capitanian Stage of the Guadalupian Series of the northern edge of the Upper Yangtze region, lithology and diagenetic processes exhibit distinct variations: The inner restricted environment primarily underwent dolomitization, forming MD1 and MD2, while the outer open environment mainly experienced silicification, developing BS and DS. (2) Episodic Emeishan mantle-plume activity induced tectono-sedimentary differentiation within the Guadalupian succession, changing depositional architecture and diagenetic environments; contemporaneous magmatic heating intensified convective dolomitization and upwelling, potentially influencing the differential conditions on both sides of the margin zone. These findings provide a direct exploration template for Guadalupian reservoirs across the Upper Yangtze: forthcoming drilling should prioritize dolostone prospects within the inner platform-margin belt.

Summary Low Salinity Water Flooding (LSWF) is a proved method for enhancing oil recovery by laboratory and field tests in secondary oil recovery. However, its numerical simulation that can capture the physics behind has not been established. The DLVO theory, which describes colloidal interactions governing the wetting fluid stability and the rock wettability, provides a critical framework to explain the problem from the perspective of microscale interfacial forces. In this study, a numerical model based on the DLVO theory is established to calculate the disjoining pressure among multiphases and thus their flow in the porous media. The two main long-range interaction forces, the van der Waals force and the electrostatic force, are calculated under different salinity and composition conditions. This is achieved by determining two important parameters, the Hamaker constant and the zeta potential. Then experimental measurements are conducted using the atomic force microscopy (AFM) under a liquid phase environment to verify the calculation results. Results indicate that there exists an optimal salinity in the oil-water-quartz three-phase system during low salinity water flooding. The mechanism is that the van der Waals force exhibits a monotonic variation trend with the decrease of liquid film thickness when the electrostatic force shows a nonmonotonic trend with the rising salinity. Next, a numerical model on predicting the contact angle on the oil-water-rock interface is proposed based on the calculated disjoining pressure in different salinity and composition conditions. Moreover, a single-channel two-phase imbibition model considering disjoining pressure is also established and verified by the published experimental results, revealing that disjoining pressure effectively influences the imbibition rate in different tube diameters. Finally, a further validation is conducted using a nuclear-magnetic-resonance-monitored (NMR-monitored) imbibition in tight rocks, which shows that the spontaneous imbibition of NaCl solution at optimal salinity has the highest recovery rate of 40.47% among all comparing cases.

Abstract Subsea pipelines are predominantly constructed with a double-layer insulated pipe structure. If the outer pipe of such a double-layer pipeline leaks, water ingress into the insulation layer can lead to pipeline condensation, blockage, and eventual failure, compromising flow assurance. Furthermore, direct exposure of the inner pipe wall to seawater can cause corrosion-induced perforation, potentially triggering oil and gas leaks that severely endanger offshore production. This paper proposes an internal inspection method for detecting water ingress into the insulation layer caused by outer pipe leakage, based on active excitation. The echo signals generated by an internal detector that actively knocks on the pipe wall to inject excitation signals are analyzed. The research includes: first, the design of a pipeline leak detection experiment; second, the development of a noise reduction method based on variational modal decomposition (VMD); and third, the combined use of time-frequency domain analysis and Mel spectrograms to accurately characterize the time-frequency and energy differences between acoustic signals. Finally, a random forest (RF) algorithm is used to extract and filter signal features, which are then input into a long short-term memory (LSTM) neural network. Compared with other machine learning models such as extreme gradient boosting (XGBoost), support vector machine (SVM), and convolutional neural network (CNN), the proposed method achieves the highest accuracy of 94.67%. Through theoretical analysis, model construction, and experimental verification, the feasibility and effectiveness of the proposed technical principle are preliminarily confirmed, providing a new research avenue for subsea pipeline outer pipe leakage detection.

The Baikouquan Oilfield edge expansion wells suffer from poor reservoir properties and limited connectivity, leading to low waterflooding sweep efficiency and insufficient reservoir energy. While oil displacement agents (ODAs) are currently employed in huff-and-puff flooding to enhance recovery, there is a lack of a solid basis for selecting these ODAs, and the dominant mechanisms of enhanced oil recovery (EOR) remain unclear. To address this issue, this study combines experimental work and reservoir numerical simulation to investigate the mechanisms of EOR by ODAs, optimize the selection of ODAs, and fine-tune the huff-and-puff flooding parameters. The results show that the selected nanoemulsion ODA (Nano ODA) significantly reduces the oil–water interfacial tension (IFT) by 97%, thereby increasing capillary number. Additionally, the ODA induces a shift from water–wet to neutral–wet conditions on rock surfaces, reducing capillary forces and weakening spontaneous imbibition. The Nano ODA demonstrates strong emulsification and oil-carrying ability, with an emulsification efficiency of 75%. Overall, the ODA increases the relative permeability of the oil phase, reduces residual oil saturation, and achieves a recovery improvement of more than 10% compared with conventional waterflooding. The injection volume and shut-in time were optimized for the target well, and the recovery enhancement from multiple cycles of huff-and-puff flooding was predicted. The research in this paper is expected to provide guidance for the design of huff-and-puff flooding schemes in low-permeability reservoirs.

Lacustrine depositional systems are more sensitive to climatic fluctuations than marine systems, producing significant stratigraphic and sedimentological heterogeneity that affects shale oil distribution. However, the mechanisms linking paleoclimatic variability to shale oil enrichment remain insufficiently constrained. This study investigates the coupling between hydrological variations, organic matter enrichment, and pore structure development under different climatic conditions in the Second Member of the Funing Formation from Well A1 in the Qintong Depression. Using a combination of total organic carbon (TOC) analysis, total sulfur (TS) analysis, X-ray diffraction (XRD), high-resolution geochemical profiling, field-emission scanning electron microscopy (FE-SEM), and helium porosimetry, we reveal how paleoclimate influences shale oil accumulation. The Second Member of the Funing Formation is subdivided into four stratigraphic units based on TOC variations, with units 1 and 3 corresponding to extremely arid conditions, unit 2 to arid conditions, and unit 4 to a humid climate. Both arid and humid conditions promoted elevated lacustrine primary productivity and moderate sedimentation rates, thereby favoring efficient organic matter accumulation. Increased water depth and optimal salinity also facilitated bottom-water anoxia, enhancing organic matter preservation. The study demonstrates that climatic variations in terrigenous clastic input and lake salinity affect the mineral composition of the lacustrine shale, influencing pore development. Under arid conditions, favorable mineralogical proportions enhances the formation of intercrystalline pores within the clay matrix, improving hydrocarbon storage potential. This research establishes that paleoclimate plays a critical role in shale oil enrichment by influencing both organic matter accumulation and pore structure. Among the analyzed units, unit 2, deposited under arid conditions, shows the most favorable source-reservoir characteristics and is identified as the most promising interval for future shale oil exploration.

[Objective]The early Cenozoic collision between the Indian and Eurasian plates triggered multi-stage uplift of the Tibetan Plateau,resulting in its remarkable landscapes and abundant mineral resources,while profoundly influencing climate,environment,and hazard evolution across Asia and beyond.The Tibetan Plateau and its surroundings have undergone intense tectonic activity and recurrent natural disasters,particularly earthquakes,which have significantly shaped its tectonic and geomorphic evolution.Seismic records indicate that more than half of the major earthquakes on the Chinese mainland and the surrounding regions occur within the plateau and its margins,controlled by the diverse types,scales,and distributions of active faults.[Methods]This study synthesizes decades of research on active faults and earthquake hazards across the Tibetan Plateau.It builds on the results of the Active Faults and Earthquake Hazards theme of the Second Tibetan Plateau Scientific Expedition and Research Program(STEP),which provided detailed documentation of major active fault zones.This study integrated current deformation fields,seismicity,and stress regimes to examine the seismotectonic settings associated with strong earthquakes across different regions of the plateau.Based on this analysis,the future seismic hazard potential of the plateau was further evaluated.[Conclusion]The image of active faults on the Tibetan Plateau indicates that different regions comprise fault systems with diverse scales,kinematics,and activity patterns.The tectonic settings associated with strong earthquakes have evolved through prolonged,multi-stage deformation,progressively establishing the present seismotectonic framework governing the nucleation and occurrence of large earthquakes.Current patterns of crustal deformation reveal northeastward deceleration with limited eastward extrusion of crustal blocks.Stress regimes,in contrast,are characterized by shear-extension in the interior and compression along the margins.Seismic hazard trends inferred from active tectonics and crustal deformation suggest a distinct segmented zonal pattern of strong earthquake activity,with plateau margins and fault-dense interiors representing the primary loci of future large earthquakes.Additionally,tectonic and geomorphic boundary zones demonstrate an increased likelihood for strong seismic events.

Identifying the source of solid bitumen is a crucial step in oil and gas source correlation. The origin of solid bitumen in the Maokou Formation of the Huayingshan area has always been a subject of debate. This research explores the origin of solid bitumen in the Maokou Formation of Huayingshan through biomarker and carbon isotope analysis of 5 solid bitumen samples and 1 source rock sample. The results show that the solid bitumen originates from a strongly reducing, low-salinity marine environment, with predominant input from bacteria and algae, showing high-overmature stage of maturation. The tricyclic terpane distribution shows C23 tricyclic terpane exceeds C21, and hopanes are dominated by C30H. Regular steranes exhibit an inverted “L” distribution with C28 < C27 < C29. An inversion of carbon isotope type-curves, characterized by δ13Caro < δ13Csat < δ13Cnos < δ13Casp in marl and dolomite limestones, whereas in dolomites, it is δ13Casp < δ13Cnos < δ13Csat < δ13Caro. The hydrocarbon source correlation suggests a strong genetic affinity between solid bitumen in the Maokou Formation reservoirs and source rocks from Maokou Formation I and Longmaxi Formation. Carbon isotope of group compositions type-curves suggest that solid bitumen in the dolomite limestones received more input from the Maokou Formation I, while solid bitumen in dolomite was more influenced by contributions from the Longmaxi Formation. A comprehensive analysis concludes that the inversion is a result of the segmented supply of hydrocarbons from source rocks under pervasive TSR and biodegradation.

In the context of developing unconventional liquid- rich reservoirs, the application of supercritical carbon dioxide (sc-CO2) has shown many advantages, including enhanced oil recovery (EOR), reducing formation damage, reducing water usage, and promoting the formation of complex fracture networks. However, sc-CO2 faces certain limitations in shale oil reservoirs that hinder its widespread application, such as ultralow viscosity, asphaltene deposition, and high miscible pressure. The addition of chemical agents is expected to overcome some limitations of sc-CO2 and further improve the CO2- EOR performance. Diluted microemulsion (DME) shows great potential as a chemical additive in water- based fracturing fluids to improve oil recovery by wettability alteration during the shut- in period after hydraulic fracturing. It is essential to explore the synergistic mechanism of DME and sc-CO2 through laboratory experiments to understand the microscopic mechanism of oil mobilization in shale reservoirs and to guide field applications. In this study, three soaking sequences were designed and compared to explore the EOR mechanisms combining sc-CO(2 )with DME using crude oil and core samples from the Lucaogou shale formation. To distinguish the DME at different stages, the DME injection in the subsequent stage is referred to as postDME (pDME). The soaking sequences consist of only sc-CO2 soaking, water-sc-CO2-pDME (W- C- D) soaking, and DME-sc-CO2- pDME (D- C- D) soaking. They correspond, respectively, to the CO2 fracturing process and the process of CO2- EOR technology after hydraulic fracturing with different water- based fracturing fluids. Low- field nuclear magnetic resonance (NMR) technology was used to quantify the oil distribution among different pores and to monitor changes in the fluid state during each soaking stage. Additionally, the component changes of the produced oil were characterized using gas chromatography (GC). The T 2 spectra results indicate that sc-CO(2 )soaking yields the highest oil recovery in the first soaking stage compared with water soaking and DME soaking. DME soaking effectively mobilizes more oil in small pores than water soaking. Subsequent sc-CO2 soaking and pDME soaking exhibit better EOR performance in the W- C- D soaking sequence than in the D- C- D soaking sequence, primarily mobilizing the remaining oil in larger pores. The sequence of total oil recovery is D- C- D soaking > only sc-CO2 soaking > W- C- D soaking. While the total oil recovery from large pores is similar across different soaking sequences, the D- C- D sequence achieves the highest oil recovery in small pores. The GC results suggest that DME can enhance the recovery of heavy components (C17+) by reducing interfacial tension (IFT) and altering wettability, thereby providing a conducive environment for heavy component mobilization in the subsequent soaking period. DME enables balanced mobilization of both heavy and light components, while sc-CO2 enhances oil mobilization from the unswept area by the aqueous phase. Therefore, combining sc-CO2 and DME can result in a higher ultimate oil recovery factor in shale oil reservoirs. The findings of this study provide an in- depth understanding of the oil mobilization mechanism during the soaking period and inform the design of soaking sequences for field applications in shale oil reservoirs.

With advancements in 3D laser scanning technology, point cloud resolution has achieved submillimeter precision. The high precision and volume of point cloud data pose significant challenges for storage, processing, and visualization. Therefore, this article presents a novel method for point cloud simplification that integrates intensity variations with multiple features. This method preserves geometric features and introduces the reflection intensity from laser scanning as a texture feature, thereby enhancing the retention of texture features. It integrates normal vector deviation, intensity difference, and curvature to identify feature and non-feature points. Specifically, points with large normal vector deviations, distinct intensity differences, or significant curvature are identified as feature points, while points lacking these characteristics are classified as non-feature points. Additionally, an adaptive voxel sampling method is proposed, which estimates the input grid size based on the spatial boundaries and density of the point cloud, ensuring that the sampled points approximate the desired quantity. Non-feature points are sampled using this adaptive method and combined with feature points to obtain the final simplified point cloud. Testing on open-source datasets shows that the proposed method produces distinct features, a uniform point cloud distribution, and small errors. Engineering tests using rock surface data confirm clear features and regular distributions, with a simplification error of only 0.23%. These results demonstrate the effectiveness and accuracy of the proposed method and highlight its superiority.

During the shut-in treatment after hydraulic fracturing, the interaction between the water-based fracturing fluid and the reservoir rock can cause the swell of clay minerals. This can alter the stress condition of the rock, thus activating and expanding the natural fractures in the shale reservoir. However, it is currently controversial whether the effect of water-rock interaction on shale permeability is positive or negative under different closure stresses.To investigate this effect on natural fractures and rock permeabilities under closure stress, imbibition experiments are conducted, and the nuclear magnetic resonance (NMR) T2 spectrum is continually scanned to identify the fracture formation.Results show that the water-rock interaction can activate and expand the natural fractures, resulting in increases of 20.0%—61.6% in rock permeability during the spontaneous imbibition without closure stress; as the percentage of clay minerals increases in shale samples, the degree of rock permeability enhancement also increases. Meanwhile, during the forced imbibition without closure stress (i.e., centrifuge), increases of 1.14—46,912 times in rock permeability are observed, indicating that higher imbibition pressure (or pore pressure) results in a greater degree of rock permeability enhancement. However, when the closure stress exists, the increase of shale permeability during the forced imbibition is only 8.3%—11.5%, even though the activation and expansion of natural fractures are observed; this indicates that the closure stress can hinder the activation and expansion of natural fractures, thus hinders the enhancement of shale permeability by the water-rock interaction.Experimental results of this study indicate the stress condition can significantly affect the impact of water-rock interaction on natural fractures and shale permeability; therefore, operators should consider this effect when designing the shut-in time after hydraulic fracturing to maximize the oil recovery rate.

HSG (high-sulfur gas) reservoirs are prevalent globally, yet their exploitation is hindered by elevated levels of hydrogen sulfide. A decrease in temperature and pressure may result in the formation of sulfur deposits, thereby exerting a notable influence on gas production. Test instruments are susceptible to significant corrosion due to the presence of hydrogen sulfide, resulting in challenges in obtaining bottom hole temperature and pressure test data. Consequently, a WTD (wellbore temperature distribution) model incorporating sulfur precipitation was developed based on PPP (physical property parameter), heat transfer, and GSTP (gas–solid two-phase) flow models. The comparison of a 2.53% temperature error and a 4.80% pressure error with actual field test data indicates that the established model exhibits high accuracy. An analysis is conducted on the impact of various factors, such as production, sulfur layer thickness, reservoir temperature, and reservoir pressure, on the distribution of the wellbore temperature field and pressure field. Increased gas production leads to higher wellhead temperatures. The presence of sulfur deposits reduces the flow area and wellhead pressure. A 40% concentration of hydrogen sulfide results in a 2 MPa pressure drop compared to a 20% concentration. Decreased reservoir pressure and temperature facilitate the formation of sulfur deposits at the wellhead.

A deep understanding of hydrate formation path is currently one of the most important thresholds for the energy, environmental and safety applications of hydrate. Methane hydrate, a kind of clean energy and the most widespread hydrate clathrates, is selected as the research focus in this study. The trajectories of the hydrate growth are generated by Molecular Dynamics (MD) simulations. Then, these trajectories are analyzed by applying the Markov State Model for the first time, from which the evolution path and structure conversion are extracted. The results show that nine independent meta-stable states can be identified. The findings reveal the existence of nine distinct metastable states during the hydrate formation process. Transitions between these states occur at nanosecond timescales, considerably slower than conventional MD simulations. Moreover, based on the state transitions, a single-track path traversing the metastable states leads to the final state, while two bidirectional paths arise due to the infiltration or escape of methane molecules. These results facilitate the sampling and observation of the hydrate formation process in laboratory conditions and inspire strategies for controlling hydrate evolution.

Summary The development of unconventional liquid-rich reservoirs, supercritical carbon dioxide (scCO2) considers a promising fluid to further improve oil recovery of shale oil reservoirs in and after hydraulic fracturing. However, the scCO2 has some disadvantages to limit its application in hydraulic fracturing, such as ultra-low viscosity, asphaltene deposition and high miscible pressure. Diluted microemulsion (DME) shows great potential as the additive of fracturing fluid to improve the well productivity through strengthening the spontaneous imbibition during the shut-in period after hydraulic fracturing. Therefore, it is essential to further understand the synergic effects between scCO2 and DME at the pore scale. In this study, three soaking sequences are designed and compared, which include only scCO2 soaking, water-scCO2-DME soaking sequence, and DME-scCO2-DME soaking sequence using shale cores from the Lucaogou Formation. Low-field nuclear-magnetic-resonance (NMR) technique are utilized to quantify the oil distribution among different pores in each soaking stage. Furthermore, component change of the produced oil is characterized by the gas chromatography (GC). Notably, T1-T2 spectra are introduced to verify the results of T2 spectra and GC. Results show that DME can replace the oil from small pores into large pores and thus improve the extraction effects of scCO2. The solid-liquid and oil-water/scCO2 interactions determine the adhesion work of heavy components. DME can enhance the heavy component (C17+) mobilization through interfacial tension (IFT) reduction and wettability alteration. Combing scCO2 and DME can effectively improve the mobilization of both light and heavy components of crude oil, and thus achieve a better ultimate oil recovery rate.

Multi-component thermal fluid stimulation has been conducted in Bohai Oilfield for about ten years and at the early stage of the pilot, the corrosion of the thermal fluid injection tubing is severe with the existence of the oxygen and the carbon dioxide under high temperature conditions, which result in damage of the insulation tubing, increase of the production cost and even unwanted workover. For solving the corrosion problem and extending the working life of the tubing, the corrosion mechanisms is researched and analyzed at the first place. XRD and SEM is applied for analyzing the corrosion product. The results show that the corrosion is mainly caused by the high temperature carbon dioxide and vestigial oxygen. The high fluid flowing velocity and variable inner diameter of the insulation tubing also accelerate the corrosion process. Then, further study of corrosion behavior and corrosion prevention technology are proceeded. Corrosion behavior study is carried out through indoor experiment. The results indicate that steel corrosion rate would reach the maximum value at the temperature of about 80 centigrade. At low temperature range, the corrosion is mainly dominated by CO2, and at high temperature range, the corrosion is mainly dominated by O2. For O2 corrosion at the conditions of about 370 centigrade and 15MPa, if the O2 concentration is below 1000 ppm, the corrosion rate would be lower than 0.076mm/a and when the concentration reaches about 1%, the corrosion rate would rapidly increase to be about 2.38mm/a. Based on the analysis above, high temperature corrosion inhibitor is researched and selected. The inhibition efficiency of the optimized inhibitor could be higher than 90% which could meet the technical requirement for corrosion prevention. For further increasing the efficiency of the corrosion prevention, tubing with higher corrosion resistance is used. For the existence of the CO2 and O2 in the inner tubing during the injection process, the selected corrosion inhibitor is injected before the thermal fluid for forming the protective film at the inner side. And for the annular space, high purity Nitrogen which is higher than 99.9% is injected for lowering its O2 concentration. Till now, the comprehensive corrosion prevention technology has been applied for field test for nearly 30 well times. The corrosion problem has been greatly solved, the corrosion rate is lower than 0.1mm/a and no severe corrosion occurs during the thermal fluid injection process. Its successful application would provide a guidance and technical support for the subsequent offshore thermal exploitation.

Due to the fact that reservoirs containing carbon dioxide gas (CO2) and natural gas (CH4) exhibit the same seismic response characteristics as ”bright spots”, conventional AVO inversion methods or fluid factor inversion techniques cannot distinguish between them. To address this challenge, we explored the use of FAVO inversion technology to achieve semi quantitative prediction of reservoir natural gas saturation. Through the application of seismic data from an actual drilled area, the results show that the inversion results can effectively distinguish the saturation of natural gas at the location where drilling has already occurred. Compared with conventional fluid factor inversion results, the prediction results are well matched with actual drilling, which provides a strong guarantee for promoting the natural gas exploration process.