Abstract:

As oil and gas exploration advances to deep and ultra-deep layers，deep and ultra-deep clastic rocks face challenges such as complex wellbores and low signal-to-noise ratio of logging data under complex mud systems，which puts forward higher requirements for logging evaluation technology. To this end，we have extensively investigated the literature，systematically summarized the concept，classification standard，and geological characteristics of deep and ultra-deep clastic rocks，and sorted out the logging evaluation technologies of deep and ultra-deep clastic rocks in recent years. We have clarified that the research on rock physical properties，high-precision processing of logging data，and reservoir effectiveness evaluation are three core links.Combined with the current status of China’s deep and ultra-deep clastic rock logging technology and oilfield production needs，a forward-looking outlook on its development direction and countermeasures were made：① Deepening rock physics experimental research，focusing on the response mechanism of different fluids in acoustic-electrical-nuclear logging and high-fidelity fast testing experimental technology at the well site，expanding the experimental scope，and optimizing measurement accuracy and speed. ②Strengthening the fine processing of new logging technologies，overcoming the sensitive information compensation and correction technology of nuclear magnetic resonance and acoustic and electrical imaging logging，and developing advanced signal processing algorithms to establish error compensation models in combination with rock physics experimental results. ③ Developing interpretation and evaluation methods and technologies suitable for deep，high-temperature，and high-pressure environments，overcoming key technical issues in fluid identification and reservoir effectiveness logging evaluation under low signal-to-noise ratio conditions，and developing new methods to improve the accuracy of reservoir effectiveness evaluation.

Abstract:

At present，reservoir architecture characterization is the most commonly used and effective method to describe a single sand body in fine reservoir description. At the same time，different reservoir architecture interfaces have a significant impact on the remaining oil distribution within the reservoir. Based on detailed literature research and analysis，the similarities and differences in reservoir architecture characterization between China and other countries were identified from the aspects of research contents，research objects，and research methods related to reservoir architecture. It was proposed that the problems existing in the research on reservoir architecture in China were mainly reflected in the following aspects：The classification scheme of reservoir architecture is not uniform；the classification level is too fine；the research focuses on conceptual innovation rather than the application of results；the research of reservoir architecture interface has not attracted enough attention，and the characterization method of reservoir architectures is relatively single. The future development direction of reservoir architecture research in fine reservoir description were pointed out：the application of quantitative characterization methods of reservoir architecture such as well-seismic combination，the study of architectures of special lithologic reservoirs such as carbonate rocks，the establishment of classification scheme of characteristic reservoir architecture，the characterization and application of reservoir architecture interface，and the field application of reservoir architecture characterization results.

Abstract:

As an essential layer system for shale gas exploration in southern China，the shale of the Longmaxi Formation in northeastern Chongqing has undergone multi-stage tectonic movement superposition and transformation，and its nano-pore structure and fractal characteristics have not been systematically explained. Through the observation of nano-pore morphology by field emission scanning electron microscopy （FESEM） and the quantitative characterization of pore structures based on Image J software，combined with the specific surface area，pore volume，and pore size distribution parameters obtained by low-temperature N₂ adsorption experiments，the FHH fractal model was used to calculate the pore fractal dimension. The fractal characteristics and influencing factors of nano-pores in the tectonically deformed shale of the Longmaxi Formation in the Dabashan foreland thrust belt in northeastern Chongqing were systematically revealed. The results show that the tectonically deformed shale of the Longmaxi Formation in the study area primarily develops organic matter pores，intergranular pores，and intragranular pores，with the reservoir space dominated by mesopores，accounting for an average of 59.30%. The calculation results of the FHH fractal model indicate that the low-temperature N₂ adsorption-desorption curve of the tectonically deformed shale of the Longmaxi Formation begins to show a hysteresis loop when the relative pressure P/P₀ = 0.45. Based on this，the fractal dimension D is divided into D₁ in the low pressure region（P/P₀ < 0.45）and D₂ in the high pressure region（P/P₀ ≥ 0.45）. The average D₁ is 2.609 0，and the average D₂ is 2.657 1，indicating that the nano-pores of the tectonically deformed shale have obvious fractal characteristics. With the increase in specific surface area and pore volume，the fractal dimension also increases；the pore structure becomes more complex，and heterogeneity is stronger. There is a significant positive correlation between the total organic carbon content and the fractal dimension，which confirms that the hydrocarbon generation and pressurization during the thermal evolution of organic matter promote the development of nano-pores. The quartz content is positively correlated with the fractal dimension，reflecting the protective effect of rigid minerals on pore structure. Clay minerals are negatively correlated with fractal dimension，indicating that plastic minerals reduce the complexity of pore structure through particle recombination under tectonic stress.

Abstract:

Tight sandstone reservoirs have poor physical properties and complex pore structures，so hydraulic fracturing technology is usually used to improve the beneficial development of tight sandstone reservoirs. However，the permeability of tight sandstone shows significant nonlinear characteristics with the change in effective stress，and the TERZAGHI linear effective stress theory is no longer suitable for evaluating the relationship between permeability and effective stress in tight sandstone due to the combined action of the complex fracture network formed after hydraulic fracturing and proppant. In order to determine the effective stress and stress sensitivity of tight sandstone，this paper studies the tight sandstone samples from Xujiahe Formation in the southern part of Sichuan Basin and carries out the stress sensitivity experiments for rock samples with matrix，natural fractures，and artificial fractures under three different confining pressures. The results show that during the aging test of tight sandstone，the permeability damage rates of rock samples with matrix，natural fractures，and artificial fractures without proppant increase successively，and the recovery rates of permeability decrease successively. For rock samples with artificial fractures，the proppant filling effectively increases the permeability，with the maximum permeability achieved at 25% proppant filling，which reduces the permeability damage rate of the rock samples. Compared with those of the rock samples with matrix and natural fractures，the non-linear characteristics of permeability contours of the rock samples with artificial fractures are more obvious. The non-linear effective stress coefficients of the rock samples are calculated by the response-surface model，and the variation range of non-linear effective stress coefficients is the widest in the proppant-filled rock samples with artificial fractures，followed by the rock samples with natural fractures，and the rock samples with the matrix come last. Finally，the effective stress calculated by the non-linear effective stress coefficient produces a good correlation with the permeability.

Abstract:

Massive fan-delta sediments are developed in the first member of the Neogene Shawan Formation（N₁s₁）in the Chepaizi area of the Junggar Basin. However，the sedimentary evolution models and sand body distribution remain poorly understood，which has limited oil and gas exploration and development in the Chepaizi area. According to the core，well logging，and seismic data，this study investigated the characteristics and sand body distribution patterns of the retrogradational fan-delta sediments of N₁s₁ during the lake basin expansion period. The results show that the sedimentary environment of N₁s₁ is dominated by the fan-delta front subfacies，which develop the main channel，distributary channel，interchannel bay，channel edge，and other microfacies.From landward to lakeward，the thickness of the sand body gradually decreases，and the grain size of the sediments becomes finer，leading to the formation of estuary bar and sheet sand microfacies in the fan-delta outer-front subfacies. The fan-delta inner-front sand body is mainly composed of conglomerate and sandstone and generally shows the retrogradational sedimentary sequence with rising lake water levels. With the rise in lake water level，the boundaries of the fan-delta sediments shift towards the direction of provenance，and the sedimentary sand bodies shift landward. Horizontally，the scale of sand body development gradually decreases.Longitudinally，it is formed by the superimposed three-phase sand body retrogradation and is characterized by the positive rhythmic characteristic. In the first phase，the main channel develops sand bodies with large amounts of widely distributed gravel and poor physical properties and oiliness. In the second phase，the distributary channel develops sand bodies with large thickness，good connectivity，small gravel diameter，and good oiliness. In the third phase，sediments in the interchannel bay and channel edge increase；the thickness of the sand body becomes thinner，and the connectivity worsens. The grain size is fine，and the physical properties are poor. The gray matter is strongly cemented and has poor oiliness. A retrogradational fan-delta sediment model of N₁s₁ in the Chepaizi area is established，which reveals the evolution characteristics of fan-delta sediments formed on the basin margin，characterized by a steep topographic slope and abundant near-source clastic material supply under the background of lake transgression.

Abstract:

Studying DFS river parameters has become crucial for predicting oil and gas reservoirs and guaranteeing geological work since the concept of distributive fluvial systems （DFS） was introduced. However，manual measurement methods are time-consuming and labor-intensive. To automatically extract，study，and characterize DFS river parameters，this paper proposed a distributive fluvial system river identification and parameter extraction method based on deep learning and morphology. First，a network model，Seg_ASPP，integrating Segformer and ASPP，was proposed for generating river network masks. Subsequently，the cumulative cost and polynomial fitting algorithms were used to extract the river mask centerline，and a scheme was designed to extract the DFS river length，width，and curvature based on the mask centerline. Finally，the DFS area in the Golmud region of the Qaidam Basin was selected as the experimental area，and multiple deep learning models were used to predict DFS rivers. The accuracy of the masks extracted by the Seg_ASPP network model was compared and evaluated. The automatically extracted parameter values obtained using this method were compared with manually measured actual values，showing average relative errors of 10.22%，13.57%，and 5.41% for length，width，and curvature，respectively. The DFS river fan in the Golmud experimental area was quantitatively characterized by the grid method. According to the different changes in the distance of the parameters from the vertex，the DFS was divided into braided river sections，braided and meandering sections，and low-bend river sections.

Abstract:

Complex reservoirs usually have characteristics such as strong heterogeneity，large lithological changes，and complex pore structures. Traditional single frequency or narrow spectrum inversion methods are difficult to accurately describe reservoir characteristics. However，the low-frequency part retains richer information reflectingthe underground interface in actual seismic data，which plays an important role in the fidelity of inversion results. Especially with the improvement of seismic acquisition accuracy，the low-frequency information contained in earthquakes is becoming increasingly rich. In inversion，it is necessary to fully explore and utilize low-frequency information to improve the accuracy of reservoir prediction. Therefore，based on the understanding of sedimentary laws and geological structures as geological information，research on broadband spectrum inversion techniques with geological constraints was carried out. A geological model was designed based on the lithological combination of a single well，and a broadband wavelet that conformed to seismic data was constructed for forward modeling. The impact of low-frequency information on inversion and the seismic reflection characteristics of complex lithologies were analyzed by comparing it with actual seismic data. A broadband wavelet for mining low-frequency information in seismic data was constructed，and a quantitative template for time thickness and bandwidth was established. Low-frequency constraint factors were added to the inversion objective function，and a broadband spectrum inversion technique based on geological low-frequency constraints was formed. Simulated annealing and improved least squares joint optimization algorithm were employed to achieve precise reservoir description of lithological oil and gas reservoirs. Theoretical model testing has verified the accuracy and effectiveness of the broadband spectrum simulation algorithm for complex reservoirs based on geological constraints. Practical application in the turbidite sand bodies of the Chaoyang-Yong’an area in the Fushan Sag has shown that the inversion results are in good agreement with actual logging data. The broadband spectrum simulation inversion for complex reservoirs based on geological constraints can well predict the longitudinal and transverse sand body distribution characteristics of each sand group in the upper submember of the second member of Liushagang Formation in the Chaoyang-Yong’an area，providing a basis and guarantee for well site deployment in this area.

Abstract:

A key challenge in acid fracturing in fracture-cavity carbonate reservoirs is to create effective fractures in an economically efficient manner，avoiding both excessive displacement rates that inflate costs and insufficient displacement rates that fail to connect the natural vugs. Therefore，it is imperative to determine an optimal critical displacement rate that balances fracture volume against treatment expenditure. Using gelling acid，solid acid，and self-generating acid employed in the Tahe Oilfield，combined with acid fracturing experiments on artificial rock samples under true triaxial conditions，this study innovatively adopted an equal-stepwise displacement method. Based on whether wellbore pressure buildup occurred or the duration of pressure buildup at the bottom hole，the ranges of critical displacement rates for different acid fluid systems and concentrations were determined.Additionally，fracture propagation research was conducted using 10%，15%，and 20% concentrations of gelling acid，solid acid， and self-generating acid. Fracture propagation is influenced by both horizontal stress and cavity attraction. While higher acid fluid concentrations promote rougher fracture surfaces，they reduce the likelihood of activating cavities. The findings are as follows：For 10%，15%，and 20% gelling acid，the laboratory critical displacement rates are 10-11 mL/min，16-18 mL/min，and 18-20 mL/min，corresponding to field displacement rates of 6.3-6.9 m³/min，10.0-11.3 m³/min，and 11.3-12.6 m³/min，respectively. For 10%，15%，and 20% solid acid，the laboratory critical displacement rates are 8-9 mL/min，9-10 mL/min，and 10-12 mL/min，corresponding to field displacement rates of 5.0-5.6 m³/min，5.6-6.3 m³/min，and 6.3-7.5 m³/min，respectively. For 8%，10%，and 12% self-generating acid，the laboratory critical displacement rates are 10-11 mL/min，11-12 mL/min，and 12-13 mL/min，corresponding to field displacement rates of 6.3-6.9 m³/min，6.9-7.5 m³/min，and 7.5-8.2 m³/min，respectively. Concurrently，fracture propagation research is conducted using 10%，15%，and 20% gelling acid at a displacement rate of 45 mL/min，as well as 20% gelling acid at displacement rates of 30，45，and 60 mL/min in the laboratory acid fracturing experiment. The results indicate that within the same acid system，at a constant displacement rate，fractures become more prone to perforation as acid fluid concentration increases，while an increase in displacement rate significantly accelerates fracture propagation.

Abstract:

The development of ultra-deep fault-controlled fracture-cavity reservoirs is confronted with such issues as insufficient formation pressure，unclear reserve status，subpar water injection effects，and ambiguous direction for significant enhanced oil recovery（EOR）. This paper systematically summarizes the understanding of reservoir energy，reserve production，and water injection effects，while exploring technologies for substantially improving the recovery of such reservoirs. The research reveals that the static pressure measured by a single well in ultra-deep fault-controlled fracture-cavity reservoirs fails to represent the formation pressure in areas beyond the wellbore or at distant locations or reflect the overall energy level of the entire reservoir. When inter-well connectivity weakens，the energy-variation coefficient and inter-well dynamic connectivity-variation coefficient of the connected well-group both increase. Reserves must be activated before they can be produced. Some reserves become“quasi unproduced reserves”in the development，and dynamic reserves are consistent with activated reserves. It is one-sided to judge the effectiveness of water injection merely by comparing evaluation indices before and after water injection. Water-injection supplementation requires reasonable control of the injection-production ratio， along with dynamic adjustment and optimization. Three-dimensional development is an important technical direction for significantly improving the recovery of ultra-deep fault-controlled fracture-cavity reservoirs in the future.

Abstract:

Dissolution trapping is a critical mechanism for CO₂ storage in saline aquifers. However， existing research predominantly relies on static equilibrium assumptions， lacking a systematic understanding of dynamic CO₂ dissolution characteristics under reservoir conditions. This study combined dynamic CO₂ dissolution experiments with response surface methodology，employing the Double Boltzmann function to characterize the non-equilibrium dissolution mechanism. Using central composite design，we constructed a quadratic polynomial regression model examining the effects of injection rate，flow unit index，and salinity on CO₂ dissolution，aiming to reveal the dynamic CO₂ dissolution characteristics and main controlling factors. Results demonstrate that the dynamic CO₂ dissolution process can be categorized into four stages：rapid gas displacement，unstable dissolution lag，dissolution mass-transfer dominance，and diffusive dissolution equilibrium. Non-equilibrium dissolution index curves indicate that dynamic CO₂ dissolution reaches 91% of equilibrium solubility. Quantitative analysis reveals a dual-stage dissolution mechanism transitioning from convection-dominated（decay factor of 3.335，contributing 67.7% of dissolution）to diffusion-dominated（decay factor of 0.967，contributing 32.3% of dissolution）processes. Response surface analysis results show that the influence of factors on solubility in descending order is as follows：salinity，flow unit index，and injection rate，with the optimal dissolution conditions being salinity of 3 750 mg/L，flow unit index of 7.5，and injection rate of 0.5 mL/min. For implementing storage engineering projects，priority should be given to reservoirs with low salinity（<5 000 mg/L），moderate permeability（50×10^-3-150×10^-3 μm²），and moderate porosity（15%-20%）. Based on the stage characteristics of the dissolution process，a phased injection strategy should be adopted. Initially，low injection rates of 0.2-0.5 mL/min should be employed to prevent rapid breakthrough of CO₂ as a continuous phase and increase gas-liquid contact time. In the intermediate stage，a pulsed injection mode can be adopted，periodically adjusting injection rates to promote contact between CO₂ and fresh brine，avoiding decreased dissolution efficiency caused by localized increases in salt concentration

Abstract:

CO₂主导宏观驱油，非混相条件下纳米聚硅强化微观洗油，可共同实现采收率提升。 In view of the low recovery of tight low-permeability oil reservoirs by water flooding in a certain block of Changqing Oilfield，a supercritical CO₂-nano-polysilicon composite displacement fluid was developed to explore its oil displacement mechanism and the effect of enhanced oil recovery. Poly（2-acrylamido-2-methylpropane sulfonic acid）（PAMPS）was used for insitu surface modification of SiO₂ to prepare nano-polysilicon particles with strong adsorption capacity and interfacial activity.Through core displacement experiments，the oil displacement performance of composite systems of nano-polysilicon with different mass fractions（1%-5%）and supercritical CO₂ was compared under miscible and immiscible conditions. The recovery change was monitored in the experiments，and the effects of nano-polysilicon on rock wettability，interfacial tension，and flow characteristics were analyzed. Under miscible conditions，supercritical CO₂ dominated the oil displacement process. The recovery of water flooding was only 32.7%，while the composite system increased it to over 70.0%. Among them，low-dose nano-polysilicon （1%-3%）significantly expanded the swept area of the oil phase and improved micro-scale oil displacement efficiency by enhancing the viscoelasticity and interfacial activity of the displacement fluid. However，high-dose nano-polysilicon（4%-5%）was prone to blocking flow channels due to particle accumulation，leading to a sharp increase in displacement pressure and a slowdown in recovery growth. Under immiscible conditions，nano-polysilicon played a more critical role. It reduced the interfacial tension between supercritical CO₂ and crude oil，increased fluid viscosity，and synergistically prolonged the shut-in time，promoting more nano-polysilicon to adsorb on the oil-bearing rock surface，transforming the oil-wet surface into a water-wet or neutral-wet state，and stripping residual oil phases. Under these conditions，the recovery increased from 31.6% of water flooding to 50%-60%. The surface modification of nano-polysilicon gave it amphiphilicity，enabling it to form a stable adsorption layer at the rock，oil，and water interface and weaken the adhesion between crude oil and rock. Supercritical CO₂ formed miscible displacement by mixing with crude oil. The synergistic effect of the two significantly improved oil washing efficiency. Supercritical CO₂ and nano-polysilicon complemented each other in displacement. CO₂ dominated macro-scale oil displacement under miscible conditions，while nano-polysilicon strengthens micro-scale oil washing under immiscible conditions，jointly achieving recovery improvement.

Abstract:

In order to solve the problem of channeling in the process of CO₂ displacement，a technique of the in-situ generating foam system carried by CO₂ for formation flow and foam plugging was studied. The law of channeling plugging with in-situ generating foam was discussed under supercritical conditions. Firstly，the dispersibility of the foam system in CO₂，the salt resistance performance of the system，and the temperature and pressure resistance ability of the enhanced foam were evaluated to ensure that the system had good foam performance under reservoir conditions. Then，through microfluidic simulation and core displacement experiment，the distribution of residual oil under microscopic conditions and the mobilization of residual oil under different displacement methods were observed，and the ability of in-situ generating foam to block channeling flow and enhance oil recovery was tested. The experimental results show that the in-situ generating foam system has good foaming and foam stability. The system can achieve in-situ foam generation，effectively reduce the residual oil content in column，film，and cluster patterns，and significantly improve the effect of CO₂ displacement after CO₂ injection. The swept volume is 41.16% higher than that achieved by water flooding and 28.25% higher than that achieved by CO₂ displacement. The recovery is 36.56% higher than that achieved by water flooding and 24.78% higher than that achieved by CO₂ displacement. The displacement pressure difference in the late stage of in-situ generating foam flooding can reach 1.4 MPa，which is 140 times that of water flooding in the core displacement experiment.After subsequent water flooding，the final recovery reaches 59.20%，which is 40.00% higher than water flooding and 34.90% higher than CO₂ displacement.

Abstract:

The pore-throat of the fractured sandstone reservoir matrix with ultra-low permeability is fine，and micro fractures are developed，which provides favorable conditions for the role of imbibition and oil displacement；surfactant solution can change the interface reaction between rock and fluid，enhance imbibition effect，and have an important impact on enhanced oil recovery.Through interface tension experiments，wettability determinations，and spontaneous imbibition experiments，the interface tension，wettability，and spontaneous imbibition and oil displacement efficiency of the anionic non-ionic surfactant YCSX-1 solution with different mass fractions were studied，as well as the influence of the injection mass fraction and injection rate of the surfactant on the oil displacement efficiency. A matrix-fracture dual-medium core was innovatively designed based on the Warren-Root model，and a dual-medium mathematical model considering the effects of surfactants and imbibition was constructed. Physical and numerical simulation methods were comprehensively employed to investigate the oil displacement laws under different injection mass fractions and injection volumes of surfactants. The experimental results demonstrate that the interfacial tension and wetting contact angle decrease first and then increase with the increase in surfactant mass fraction，which are the key factors affecting the imbibition’s oil displacement efficiency. The surfactant system with a mass fraction of 0.4% has the strongest imbibition effect and the highest oil displacement efficiency，and the enhanced imbibition effect improves the mobilization of crude oil in the matrix. The oil displacement efficiency shows a trend of increasing first and then decreasing with the increase in injection rate. The optimal injection rate is 1.2 mL/min. Based on the experimental results，the constructed dual-medium mathematical model was used for simulation calculation，and the injection parameters were optimized. The optimal injection mass fraction is 0.4%，and the optimal single-well injection volume is 12 m³/d. The simulation result was applied to the water injection development in the X Block，yielding an obvious effect，and the maximum increase in daily oil production is up to 54%. The technology of controlling injection rate and increasing imbibition effect to enhanced oil recovery changes the interfacial tension and wettability of matrix pores through the mass fraction optimization of surfactant solution；it simultaneously controls the water injection rate to ensure that the meniscus of the two-phase fluid remains in an ideal dynamic state during the oil displacement process，exerting the dual dynamic effects of capillary force and displacement pressure，further enhancing the relative contribution of flow and absorption in the oil displacement process，and increasing the flow capacity of crude oil in the small-pores of matrix. More crude oil in the pores of the matrix is recovered，improving the oil displacement efficiency.

Abstract:

The continental shale reservoir has a complex hydrocarbon composition and multi-scale pore structures，which further leads to the complexity of the phase behavior of continental shale gas. This intensifies the difficulty of reserve evaluation and dynamic analysis of continental shale gas exploitation. This study focused on the continental shale gas of the Jurassic Ziliujing Formation in the Sichuan Basin and developed a multi-scale phase equilibrium calculation method based on multi-scale phase equilibrium criterion，particle swarm optimization，and interior point method by using the PR equation and taking into account the influence of the confinement effect，so as to achieve the global equilibrium simulation. The constant composition expansion was used to simulate the depletion development process and study the phase characteristics and phase behavior of hydrocarbons in the multi-scale pores under different pressure conditions. The study finds that due to the confinement effects，the lighter components tend to exist in small pores，while the heavier components tend to exist in large pores under the initial conditions. As a result，the P-T phase diagram corresponding to the hydrocarbon mixture in pores with pore diameter ≤ 10 nm shifts to the upper left；the critical temperature decreases，and the degree of deviation decreases with the increase in the pore diameter. In the depletion development process，with the reduction of reservoir pressure，the lighter components in the pores can easily enter the large pore for enrichment，while the heavier components in the small pore remain in the small pore.

Abstract:

In-situ combustion （ISC），as a low-energy-consumption and low-emission method for heavy oil recovery，faces limitations in application due to the low combustion efficiency and high reaction activation energy. The catalytic methods of different types of metal catalysts，including conventional metal catalysts，nanometal oxide catalysts，and multi-metal composite catalysts，for crude oil combustion and steamflooding cracking were summarized through a systematic literature review. Combined with multidimensional data such as thermogravimetric analysis and combustion tube experiments，the catalytic mechanisms of metal catalysts in heavy oil oxidation reactions were thoroughly analyzed. Key findings reveal that metal salt catalysts significantly reduce reaction activation energy，among which iron nitrate can increase the combustion efficiency of heavy oil by 20%，and cobalt naphthenate can reduce the starting temperature of low-temperature oxidation by 18 °C. Nanometal oxide catalyst exhibits superior activity：Iron oxide nanoparticles reduce the asphaltene oxidation temperature by up to 160 °C and decrease activation energy by 32.4%；nickel oxide nanoparticles not only reduce high-temperature oxidation （HTO） activation energy but also accelerate combustion front velocity. Multi-metal composite catalysts further enhance performance：The TiO₂-ZrO₂ bimetallic catalyst increases light fraction yield by >12% compared to single components，and the Mo-Ni-W trimetallic catalyst achieves 50% oil recovery within just 5 hours，while significantly reducing sulfur content. In summary，metal catalysts markedly improve fuel deposition and combustion efficiency by drastically reducing activation energy and oxidation temperatures. Iron oxide nanoparticles and multi-metal composite catalysts demonstrate exceptional potential，yet overcoming critical challenges，such as hightemperature deactivation，nanoparticle retention，and H₂S generation，remains imperative for industrial-scale implementation.

Abstract:

Rhamnolipid，an anionic biosurfactant produced by microbial metabolism，can effectively enhance the development effect of heavy oil reservoirs during the ultra-high water-cut stage. Compared to conventional chemical surfactants，it not only exhibits comparable interfacial regulation capabilities but also demonstrates significant eco-friendly advantages. The rhamnolipid fermentation broth system holds substantial research value and application potential in petroleum production. However，current studies on its action mechanism and reservoir adaptability remain insufficient，limiting its large-scale application. Three ordinary heavy oil reservoirs were used as the research object in Shengli Oilfield，and microfluidic models were employed to simulate reservoir conditions and conduct micro-displacement experiments on the rhamnolipid fermentation broth system. High-speed microphotography and digital image processing techniques were employed to monitor and quantitatively analyze the oil displacement behavior dynamically. The oil displacement effects in different types of heavy oil reservoirs were comparatively evaluated，and their mechanism of action was deeply analyzed. The results demonstrate that the rhamnolipid fermentation broth system effectively enhances oil recovery in all three ordinary heavy oil reservoirs. Its action mechanisms mainly include interfacial tension（IFT）reduction，emulsification，and wettability alteration，which are quantitatively characterized by the values of oil-water IFT，the average droplet size of emulsified oil，and the magnitude of change in average contact angles，respectively. Emulsification is the key factor determining the displacement efficiency of the fermentation broth system，while IFT reduction ensures the effective mobilization of emulsified oil droplets. The synergistic effect of these two mechanisms significantly enhances oil recovery.

Abstract:

Spontaneous imbibition-induced reservoir water lock damage is one of the significant factors affecting the production capacity of tight sandstone gas reservoirs. The addition of polymeric surfactants in drilling fluids can alter the wettability of rock surfaces，reduce liquid surface tension，and mitigate reservoir water lock damage. This study synthesized a fluorocarbon-type polymeric surfactant. Through static characterization methods，including infrared spectroscopy，thermogravimetric analysis，and particle size analysis，the study clarified their molecular structures，thermal stability，and particle size distribution characteristics.On this basis，surface tension experiments，gas-liquid-solid three-phase contact angle experiments，spontaneous imbibition experiments，core displacement experiments，and nuclear magnetic resonance（NMR）were employed to investigate its effect and principle in mitigating water lock damage. The results show that the synthesized polymeric surfactant molecules exhibit no weight loss below 200 °C with slow thermal decomposition rates up to 330 °C，demonstrating good thermal stability characterized by a primary decomposition peak at 390 °C. The particles show excellent uniformity with an average size of 53.69 nm，belonging to the nanoscale emulsion category that meets the dimensional requirements for accessing most pore throats in tight sandstone. This polymeric surfactant maintains effective surface tension reduction under high-temperature conditions，with its 1.0% wt aqueous solution exhibiting a surface tension of 41 mN/m at ambient temperature and decreasing to 28 mN/m at elevated temperatures. The contact angle of deionized water on core surfaces increases from 45° to 94°. The capillary force significantly weakens as the contact angle increases，significantly inhibiting the spontaneous imbibition rate of the core. This modification leads to a 61.4% average reduction in spontaneous imbibition rate within the 0-10 minute，with ultimate water saturation decreasing to less than one-third of the original value. When incorporated into simulated drilling fluids at 1.0% concentration，the surfactant substantially reduces liquid phase retention in pores and mitigates water block effects caused by fluid invasion，resulting in improved average core permeability recovery rate from 60% to 86%. The synthesized polymeric surfactant demonstrates dual advantages of excellent thermal stability and nanoscale characteristics，enabling efficient plugging of tight sandstone pore throats. It significantly reduces liquid surface tension while enhancing core contact angles through hydrophobic modification，thereby suppressing spontaneous imbibition rates and improving permeability recovery rates effectively. By regulating wettability，reducing capillary forces，and enhancing fluid flowback capacity，the polymeric surfactant mitigates water block damage，providing key technical support for optimizing hightemperature reservoir drilling fluids.