Abstract:Oil and gas exploration and development in deep and ultra-deep well have put forward higher requirements on the temperature resistance of fluid loss reducer for drilling fluid. Taking advantage of β-cyclodextrin’s special rigid stabilizing structure in the shape of a conical ring table and special adsorption ability of inner hydrophobicity and outer hydrophilicity，β-cyclodextrin （β-CD） was grafted by maleic anhydride （MAH）. Meanwhile，3-（trimethoxymethylsilyl） propyl methacrylate （KH₅₇₀） with excellent high-temperature stability was introduced，and then copolymerized in an aqueous solution with p-styrenesulfonic acid sodium salt（SSS）and dimethyldiallylammonium chloride（DMDAAC）. As a result，a high-temperature resistance fluid loss reducer（LY-1）was synthesized. The optimum preparation conditions of LY-1 were determined by measuring the high-temperature and high-pressure filtration loss of sodium bentonite based slurry containing 3% LY-1. The structure of LY-1 was characterized by gel chromatography，infrared spectrometry and thermogravimetric analysis. The effects of LY-1 on the filtration loss and rheological properties of base slurry were evaluated. The performance of LY-1 was compared with that of three commonly used high temperature resistance fluid loss reducers. The results showed that the optimum synthesis conditions of LY-1 were obtained as follows：25% total mass fraction of the monomer，1% initiator mass fraction of the monomer mass，15∶3∶2∶15 mass ratio of the monomers（SSS，KH570，DMDAAC and MAH-β-CD），10 pH value，75 ℃ reaction temperature，and 4 h reaction time. The average relative molecular mass of LY-1 was 14 589. The total heat loss mass was about 35.98% at 284—453 ℃，which meant it had good temperature resistance at 300 ℃. LY-1 had a good performance of lowering the filtration loss at high temperatures. When 3% LY-1 was added to the base slurry，the filtration loss of base fluid was reduced from 143 mL to 12 mL after hot rolling at 200 ℃for 16 h，with a reduction rate of 91.6%. The effect of LY-1 on the rheological properties of base slurry was small. It’s filtration reduction performance and temperature resistance were better than those of three commonly used high temperature resistance fluid loss reducers.

Abstract:In oil and gas exploration and development operations，the geological conditions are complex，and the salinity of formation water in salt-gypsum layers is extremely high. A large number of metal cations have a serious negative impact on the viscosity and filtration reduction of water-based drilling fluids. In order to solve this problem，an anti-multivalent cation zwitterionic hyperbranched polymer filtrate reducer XZ-DJ2 was prepared by introducing a branching agent on the basis of zwitterionic polymer. The optimum reaction conditions were explored through experiments，and a series of characterization tests on its physical and chemical properties were carried out. The rheology，filtration loss reduction，salt resistance，particle size and Zeta potential of the drilling fluid base slurry after adding XZ-DJ2 were tested. The results showed that after adding 2% XZ-DJ2 into the base slurry，the Zeta potential changed from ?31.9 mV to ?42.4 mV，and the absolute value of Zeta potential increased，indicating that XZ-DJ2 could improve the stability of the system. The filtration loss before and after aging at the temperature of 150 ℃ for 16 h was 5.6 mL and 6 mL，respectively，which was significantly lower than that of the base slurry without XZ-DJ2，being of 26.6 mL and 31.8 mL，respectively，indicating that XZ-DJ2 had good filtration loss reduction performance. With the increase of XZ-DJ2 dosage，the viscosity of drilling fluid increased and the filtration loss decreased slightly. After contaminated by 30% NaCl、30% KCl、5% CaCl₂、5% MgCl₂ and 1% Al₂（SO₄）₃·18H₂O，the viscosity of the drilling fluid was significantly reduced，but the filtration loss change little，being of 6.3，6.2，5.2，6.8，7.0 mL，respectively，indicating that XZ-DJ2 had excellent temperature resistance and multivalent cation pollution resistance，and XZ-DJ2 achieved the fluid loss reduction effect by improving the compactness of the filter cake rather than improving the viscosity of the drilling fluid，which is conducive to drilling speed and further save drilling fluid operating costs.

Abstract:In order to solve effectively the leakage phenomenon during drilling in high-temperature deep fractured formations，a new type of high-temperature resistant rigid sealing agent HTD-2 was developed，and it was compounded with modified inorganic mineral fiber GXW-1 and elastic sealing material TDS-2 to form a composite sealing material. The performance of the plugging material was evaluated through temperature resistance performance experiments，crack sealing experiments，high-temperature and high-pressure sand bed sealing experiments and compatibility experiments with drilling fluid. The results showed that the temperature resistance performance of HTD-2，GXW-1，and TDS-2 was significantly better than that of walnut shell. Under high temperature and pressure conditions，a single sealing material could not achieve good sealing effects on cracks with different size， while composite sealing materials had better sealing effects. The composite sealing materials，composes of 8% HTD-2 + 1.5%GXW-1+6% TDS-2，could make the 30 min leakage of 0.5—2 mm cracks be reduced to below 100 mL，and the pressure bearing capacity of the sealing layer was greater than 10 MPa. The addition of composite plugging materials could make the drilling fluid have good sealing effect in different sizes of rock debris sand beds，with a 60 min invasion depth of only 9.3 cm for 0.85—2 mm sand beds. In addition，the composite sealing materials had good compatibility with drilling fluids. The in-site application results showed that when using drilling fluid with composite plugging materials for in-site construction，there was no significant leakage phenomenon during the drilling process of GX-1 well，and the drilling process was smooth，effectively improving drilling efficiency and quality. This composite sealing material is suitable for promotion and application in sealing construction operations in high-temperature and deep fractured formations.

Abstract:To meet the requirements on well integrity of oil wells under large temperature difference environment，it is needed to clarify the evolution of mechanical properties of oil well setting cement under a wider range of temperature and pressure. Pure cement system and silica-cement system was selected as research targets，the influence of temperature，pressure and silica fume content on the evolution of cement strength under the temperature range of 30—200 ℃ was systematically studied and the driving mechanism of cement strength development and high temperature strength retrogression mechanism under each factor was investigated. The results showed that within 30—110 ℃，the compressive strength of pure cement system increased with the increase of temperature. As The temperature increased from 100 ℃ to 150 ℃，the strength retrogression of the pure cement system happened under high temperature. Within the temperature of 110—200 ℃，the ultrasonic intensity of silica-cement system changed not monotonically with the temperature；however，the ultrasonic intensity development could be accelerated by the increase of pressure. At the temperature of 200 ℃，the phenomena of strength retrogression and volume expansion of silica-cement system happened. By increasing the amount of silica sand，the early strength decline rate could alleviated to a certain extent. Phase composition analysis showed that the development of the early strength of cement was mainly related to the formation of C-S-H gel and Ca（OH）₂；at the temperature of 130 ℃，the main reason causing the high temperature strength retrogression of pure cement system was the formation of α-C₂SH；at the temperature of 200 ℃，the main reason causing the strength retrogression of silica-cement system was that the C-S-H gel was gradual transited from amorphous to other crystalline.

Abstract:Addition of quartz sand to Portland cement can prevent its mechanical properties from declining due to crystal transformation at high temperatures. However，the composition and morphology changes of hydration products of sand-coated cement under the combined action of 180 ℃ and supercritical CO₂ are more complex，so the effect of high temperature CO₂ on the mechanical properties of cement is still unclear. Therefore，the corrosion depth，pore size distribution，mechanical properties， phase composition，functional groups and microstructure of cement stone in supercritical CO₂ environment at 180 ℃ were analyzed by means of scanning electron microscopy，mercury injection，thermogravimetric analysis，X-ray diffraction test and infrared spectrum characterization. The results showed that with the increase of corrosion time，the corrosion depth of cement stone increased，the compressive strength decreased，and the porosity decreased first and then increased. The hydration products were composed of acicular xonotlite（C₆S₆H），columnar hillebrandite（C₂SH），sheet and rod-shaped calcium carbonate（CaCO₃）and loose porous amorphous SiO₂. Under the condition of supercritical CO₂ at 180 ℃，the influence mechanism of hydration product evolution of cement on its performance was obtained as follows. In the early stage of corrosion，a large amount of C₂SH and a small part of C₆S₆H were corroded to generate CaCO₃ and amorphous SiO₂. CaCO₃（mainly aragonite and vaterite）would fill part of the pores，while the polymerization degree of C-S-H gel increased，slowing down the carbonization corrosion rate. In the later stage of corrosion，the increase of calcite content could promote the development of strength to a certain extent. But with the progress of corrosion，the vaterite and aragonite dissolved，a large number of C₆S₆H were corroded and then the morphology changed toward flake and block，resulting in the increase of porosity of cement stone，the decrease of polymerization degree of C-S-H gel and compressive strength，and the acceleration of carbonization. Under supercritical CO₂ at 180 ℃，the evolution of C-S-H gel（C₆S₂H and C₆SH）and calcium carbonate（calcite，aragonite and vaterite）determined the change of mechanical properties of Portland cement.

Abstract:Due to its low viscosity and weak sand carrying capacity，the slickwater fracturing fluid is often unable to meet the efficient filling of proppant in complex fracture networks post-fracture. Based on the theory of bubble suspended sand，a CO₂ suspension proppant technology was proposed and the CO₂ suspension sand effect in slickwater fracturing fluid was evaluated under normal temperature and pressure，high temperature and high pressure，respectively. The results showed that the surface modified coating of suspended proppant could play a stable gas-solid bridging effect. For the surface modified suspended proppant，the adsorption of CO₂ and the bridging effect of proppant could effectively reduce the specific gravity of proppant，significantly slow down the settling speed of the proppant in slickwater with a reduction of 99%，being of 0.15 cm/min，thus achieving the effect of “low formation damage and high sand carrying capacity”. The performance of CO₂ suspended sand under the condition of normal temperature and pressure was mainly affected by the viscosity of slickwater. The degree of suspension and stable suspension duration increased with the increase of viscosity of slippery water fracturing fluid，but it is basically not affected by sand concentration. Under the condition of high temperature and pressure，carbon dioxide was in a supercritical state（SC-CO₂），but it could still adsorb on the surface of suspended quartz sand and play a certain suspension role，causing a large amount of suspended quartz sand to be suspended during the stirring process. CO₂ suspension proppant technology can significantly improve the sand carrying capacity of slickwater，and has important practical significance to reduce the risk of sand plugging in complex fracture networks and improve the efficiency of oil and gas well reconstruction by efficient proppant filling.

Abstract:In order to achieve imbibition stimulation of low permeability tight oil reservoirs，a microemulsion additive（ME）for increasing production by imbibition stimulation was developed， based on the integrated construction method of “compression-injection-recapture”and with the goal of improving the performance of fracturing fluids. The major raw ingredients were fatty alcohol alkoxylation sulfate anionic surfactant（SY-1）and methyl 9-octanoate（MS-9）. The phase behavior was explored by fitting a ternary phase diagram，and then the formula was optimized using orthogonal tests. Its performance was evaluated by laboratory experiment，and then the stimulation effect during fracturing was tested. The results showed that the optimum formula for preparing ME was obtained as follows：25% SY-1，12.5% triethylene glycol butyl ether，37.5% KCl aqueous solution（2%mass fraction） and 25% MS-9. The average particle size of the microemulsion was 70.5 nm. It could keep stable under the conditions of long standing（180 days）and high-speed centrifugation（8000 r/min）. It could also reduce the interfacial tension to the order of 10^-4～10^-3 mN/m. Compared with water，it could reduce the contact angle by approximately 35°. It could maintain high interfacial activity after 8 adsorptions with core powders，indicating strong anti-sorption ability. It had good compatibility with fracturing fluid. When the fracturing fluid without ME was used as blank control，ME could enhance the oil washing efficiency by 54.94 percentage points—61.82 percentage points during the simulated fracturing entry stage. During the simulated fracturing well stage，the imbibition displacement impact might be raised by 15.68 percentage points. Meanwhile，during the flowback stage，it could accelerate the speed and degree of crude oil recovery，and then the crude oil recovery rate could be increased by 32.56 percentage points. The microemulsion had the advantages of small particle size，strong stability，low interfacial tension between oil and water，good wetting improvement effect and strong adsorption resistance. It could increase oil recovery during the whole process of fracturing construction. The effect of increasing permeability and oil displacement was remarkable.

Abstract:Acidizing and acid fracturing reservoir reconstruction technology is an important means to increase production. Traditional dry powder acid thickener has a dissolution time of more than 2 h when used to prepare acid solution，which makes it impossible to continuously mix on site. As for the emulsion thickener with better solubility，acid resistance，salt resistance and shear resistance in special environment need to be improved. In this paper，using APS/TEMPO composite catalyst，acrylamide （AM），fluorine-containing，sulfonate-containing and ammonium chloride-containing monomers as raw materials，a self-healing， quick-dissolving and hydrochloric acid-resistant thickener PASD based on strong amphiphobic interaction was prepared by inverse emulsion polymerization. The chemical structure of PASD was characterized by infrared spectroscopy，and its relative molecular mass，stability，acid resistance，acid dissolution time，temperature resistance，salt resistance，shear resistance，amphiphobic inversion and displacement performance were tested. The thickener PASD had excellent chemical stability. When the concentration of inorganic salt ions was less than 50 mg/L，the viscosity could be maintained above 24 mPa·s. PASD could be dissolved in 20 % hydrochloric acid within 3 min，and the viscosity of tackifying acid could reach up to 38 mPa·s. When destroyed by strong shear，the viscosity self-healing rate of the tackifying acid was 65% within 30 min. The gel breaking liquid of PASD tackifying acid could result in wettability reversal of rock with strong-amphiphobic（super-hydrophobic and strong oleophobic），reduce capillary action and driving pressure，and communicate with the pore cracks of the formation to a greater extent. This study provides a material basis for the realization of on-line mixing of acid liquid and the integration of thickened acid fracturing and replacement.

Abstract:During the acidification of 160 ℃ high temperature sandstone reservoirs in offshore WC oilfield，the clay minerals such as illite are hydrated and decomposed in hydrochloric acid，causing particle migration and reservoir damage，resulting in reduced productivity of oil and gas wells. To solve the problems of fast reaction at high temperatures，sensitivity of illite clay，and short penetration distance of conventional mud acid，experiments such as high-temperature acid dissolution，core flooding，and produced liquid ions analysis were carried out，and a high-temperature resistant chelating acid，composed of 5% GLDA+8% acetic acid+1%HF+1.5% clay stabilizer NW-1+1% corrosion inhibitor CT-1，was proposed. The chelating acid achieved a dissolution rate of 15.2% at the temperature of 160 ℃ for 16 hours，a corrosion rate of 3.7451 g/（m²·h），and an anti-swelling rate of 90.9% . After the chelating acid interacted with the rock core，Si⁴⁺，Ca²⁺，Mg²⁺，and Fe³⁺ content gradually increased，indicating that the chelating acid had a multivalent metal ion chelating effect，which could avoid secondary and tertiary damage to the rock core by the acid solution，achieving the effect of the acid dissolution on deep penetration of the formation. In response to the lack of mature professional software for chelating acid acidification design，a simplified acid rock reaction plane radial flow model was used， considering the material balance of hydrofluoric acid，a chelating acid acidification simulation design software was developed using MATLAB language. The optimal acid injection rate for Well A was calculated to be 2 m³/min，and the volume of acid used in each section did not exceed 70 m³. The chelating acid system was successfully used to remove blockages in 5 offshore water injection wells. After the measures，the average daily injection volume increased by more than 110 m³，and the injection pressure decreased significantly，with a maximum pressure drop of 12 MPa. The chelating acid system had a good effect on removing blockages and increasing injection in the 160 ℃high illite sandstone gas reservoir.

Abstract:In order to solve the problems of inefficient，ineffective circulation of injected water and imbalanced injection and production in the later stage of oilfield development due to intensified contradictions in reservoir profile and development of dominant channel of water flow，a temperature and salt resistant gel profile control system was developed using hydrophobic associating ploymer as the main agent，organic aluminum zirconium crosslinking agent made from inorganic salt aluminum and zirconium oxychloride as the main crosslinking agent，and sodium lignosulfonate heat stabilizer as the auxiliary. Its gelling performance，anti-dilution performance，shear resistance，plugging performance and erosion resistance were studied. The optimal formula for the profile control system was as follows：0.4% hydrophobic associating polymer，0.3%—0.35% organic aluminum zirconium crosslinking agent and 0.2% heat stabilizer. The research results indicated that the viscosity of the base liquid was 88.3—95.8 mPa·s，and the low viscosity base fluid endowed with better pumping performance，which could ensure the construction safety. Under the condition of 200 ℃ and salinity of 27 123.5 mg/L，the gelation viscosity of the system within 90 d could be maintained above 6000 mPa·s，and the viscosity retention rate could reach above 80%. When diluted with 60% of the formation water，the gelation viscosity of the system could still reach over 4000 mPa·s，and the dilution after gelation had a smaller impact on the gelation strength of the system. The system has good migration ability in cores with permeability of 500×10^-3，1000×10^-3 and 2000×10^-3 μm²，respectively，and the pressure gradually stabilized at a distance greater than 50 cm from the injection end of the rock core，and plugging rate was over 80%. With the displacement of a large amount of injected water，the permeability of the injected profile control system remained basically unchanged，exhibiting good erosion resistance.

Abstract:The dominant seepage channel in the middle and later stages of oilfield development leads to the increase of water cut and the decrease of oil production in oil wells. In order to improve the stability of gel profile control agent in high temperature and high salt harsh reservoirs，based on the phenomenon that the basic crosslinking system composed of low concentration polymer and phenolic crosslinking agent is easy to degrade and dehydrate under the condition of high temperature and high salt，the gel strength and dehydration rate were taken as the main indexes，and the additives that could improve the stability was optimized through semi-quantitative analysis method. The gel strength，temperature resistance and salt tolerance of the obtained gel system were evaluated. The experimental results showed that the addition of antioxidant 1#（compounds containing nitrogen）and complexing agent 2#（organic phosphonate）to the polymer gel system could significantly enhance the stability of the system. Under the condition of salinity of 45 550 mg/L（calcium ion content of 3120 mg/L），the gel system，composed of 0.4% polymer + 0.4%crosslinking agent +1.8% complexing agent 2# + 0.5% antioxidant 1#，had a gel strength of H grade at the temperature of 125 ℃， which was stronger than that of the basic crosslinking system. The gel strength could still reach grade E at the temperature of 140 ℃and the gel dehydration rate was only 5.2% after aging for 180 days，exhibiting excellent temperature and salt resistance. The gel system had good injectivity and plugging performance，the plugging rate being greater than 98%，which was suitable for reservoirs with the temperature of 90—140 ℃，and provided technical support for oil stability and water control in complex and harsh reservoirs.

Abstract:The existing gel has the problems of short gel time，poor dilution resistance and poor long-term stability under high temperature formation conditions. Based on a two-level cross-linked structure design，a temperature and salt-resistant double cross-linked gel profile control and plugging agent was synthesized using glycidyl methacrylate（GMA）and diethylene glycol dimethacrylate（EDMA）as copolymer monomers，tert-butyl hydroperoxide（TBHP）as the initiation system，polyethylene glycol （PEG）as organic solvent，and fumed silica（AEROSIL）as the reinforcing agent. The effects of each component dosage on the gelling time and storage modulus of the gel were studied. The performance of viscoelasticity，aging stability，dilution resistance to formation water and plugging property of the gel were investigated. The results showed that the optimal formula of gel system was 10% GMA+ 0.7% EDMA+ 0.066% TBHP+3% AEROSIL，and the rest was PEG solvent. The initial viscosity of the system was 315 mPa·s，the gelling time was 2—10 hours，the storage modulus was 5230 Pa，and the compressive strength was 0.221 MPa. After aging for 30 days at the temperature of 140 ℃ in the simulated formation water with a salinity of 2.2×10⁵ mg/L，there was no volume shrinkage，and the storage modulus could reach more than 4000 Pa. The gel had good dilution resistance to formation water. When adding formation water with volume fraction of 40%，the shear strength of the gel was reduced by about 18%，but the storage modulus could still reach more than 4000 Pa. The gel base fluid showed good injection stability，and the reverse breakthrough pressure gradient in the displacement experiment reached 5.5 MPa/m，the mechanical strength of the formed gel could meet the needs of plugging fracture channels. A potential plugging and regulating material for high-temperature and high-salinity reservoirs was provided.

Abstract:Long-term water injection in oilfields leads to high water cut in oil wells，necessitating the development of environmentally friendly，low-cost，high-quality，and efficient chemical agents for profile adjustment and water shutoff. Using polyvinyl alcohol （PVA），rubber powder，glutaraldehyde，and a self-prepared hydrophobic modifier as raw materials，a thermoplastic flexible particle profile adjustment and water shutoff agent that could be formed in one step in aqueous phase was prepared. The particle size and microstructure of the profile modification and water shut-off agent were analyzed，and then its mechanical properties were evaluated using texture analysis method. The stability of the agent was examined under the conditions of high-salinity water and temperatures ranging from 120 ℃ to 200 ℃. A full-penetration fracture model was used to investigate the injection，transport and blockage effects of the agent in fractures. The results showed that when the mass ratio of rubber powder and PVA was between 0 and 1.75，flexible particles with an advantageous particle size of 10—20 mesh（2.00—0.85 mm）could be prepared，significantly reducing synthesis costs. Compared to particles without rubber powder，the rubber powder-doped flexible particles exhibited a loose and porous structure，higher thermal stability，and better mechanical properties. The weight loss temperature increased from 200 ℃ to 300 ℃，the hardness increased from 18.73 N to 37.31 N，the elasticity increased from 0.86 to 0.99，the resilience increased from 0.48 to 0.60，and then the chewiness increased from 15.39 N to 35.88 N. The flexible particles remained stable in high-temperature and high-salinity water，without impact on mechanical properties after aging 60 days at 120 ℃. The particles exhibited good thermoplasticity，beginning to adhere together after aging 3 days. Physical model experiments demonstrated that rubber powder-doped flexible particles could form stable pressure fluctuations，quickly adapt to fracture deformation and pressure changes，and effectively block fractures，with a blockage efficiency of 85.7%. The rubber powder-doped flexible particles possessed excellent deformability，thermal stability and injectivity，which were suitable for improving deep liquid flow redirection in high water cut oilfields and enhancing oil recovery.

Abstract:As the development of deep fractured reservoirs，water channeling has become increasingly prominent，leading to the wastage of formation energy and a decrease in oil recovery efficiency. The primary cause of water channeling in these complex fracture networks is extreme heterogeneity. Urgent measures are required to plug these water breakthrough channels，with plugging agents playing a central role in addressing this challenge. Deep fractured reservoirs are characterized by high temperatures（≥ 110 ℃）and high salinity（≥20×10⁴ mg/L）. Under these conditions，conventional gels struggle to maintain stability. To overcome these challenges，modified nano-silica was synthesized by introducing hydroxyl and phenolic hydroxyl groups into nano-silica through diazotization and oxidation reactions using 3-amino-4-hydroxybenzenesulfonic acid. This modified nano-silica was then reacted with nonionic polymer，hexamethylenetetramine（HMTA），and hydroquinone to produce a nano-hybrid gel. The formula of nano-hybrid gel was optimized based on gelation performance and dehydration rate. The stability，viscoelasticity and blocking capability of nano-hybrid gel were evaluated. A temperature and pressure-resistant visualized fracture network model was established according to the geological model of typical deep fractured reservoirs in Northwest oilfield. The residual oil distribution patterns were analyzed，and then the multi-round blocking effectiveness was determined. The results showed that the nano-hybrid gel with formula of 0.8% nonionic polymer，0.2% modified nano-silica，0.4% HMTA and 0.4% hydroquinone could remain stable for up to 60 days at temperatures ≤140 ℃ with a dehydration rate <10% . Modified nano-silica significantly enhanced the viscoelastic properties of nano-hybrid gel. The nano-hybrid gel exhibited excellent blocking effects on single fractures with various scales （1—10 mm）. Under the condition of 140 ℃，2 MPa backpressure and 22 × 10⁴ mg/L salinity，multi-round blocking experiments with nano-hybrid gel increased the recovery efficiency of fracture network model by 15.9 percentage points. The nano-hybrid gel demonstrated superior thermal and salt resistance，viscoelasticity and long-term stability，which made it well-suited for effective plugging and enhanced oil recovery in deep fractured reservoirs.

Abstract:The tight-low permeability reservoirs in Yanchang oilfield of Ordos Basin are characterized by low matrix permeability，strong heterogeneity and widespread presence of naturally developed micro-scale fractures. These lead to the problem of fluid easily flowing along fracture channels and high-permeability pore throats during water flooding and CO₂ flooding. Traditional profile control and water shutoff technologies are only effective in the near-wellbore area，which can improve the water absorption profile of injection wells but fail to fundamentally solve the water channeling problem in the deep formation. To address these issues，a green and low-carbon microbial dispersion profile control and plugging agent was developed based on endogenous microorganisms and their metabolic products as growth nuclei，which were dispersed as small spheres in the water phase （i.e.，microbial dispersions）. The results showed that the optimum activation and growth conditions for the microbial dispersion-producing functional strain（Novosphingobium sp.，similarity 98%—99%）were obtained as follows：45 ℃ temperature，60 g/L salinity，7 pH value. The most suitable activation nutrient formula was obtained as follows：carbon source（1.5% molasses），mixed nitrogen source（0.50% sodium nitrate，0.30% ammonium sulfate），trace elements（0.06% industrial yeast powder，0.002% ferrous sulfate， 0.002% manganese sulfate）. Meanwhile，the mechanism of microbial dispersion profile control and plugging was preliminarily clarified. The microbial dispersion-producing functional bacteria formed a matching plugging with the reservoir fracture channels by utilizing their individual adaptive growth and deformation properties，and then continuously migrated and controlled the profile in the deep part of fractures and high-permeability porous media，thereby changing the flow direction of injected water/CO₂ gas and ultimately achieving full profile control. The microbial dispersion had good profile control and plugging capabilities in water flooding/CO₂ flooding environments，with plugging rates all above 80% . The research results provided a reference for the application of microbial dispersion profile control and plugging technology in controlling the fracture channeling zones and high-permeability porous media channeling zones in low-permeability tight oil reservoirs and enhancing oil recovery.

Abstract:To solve the problem of the uneven injection of sand consolidating agents in strong heterogeneous reservoir，a water-soluble low-viscosity surfactant sand consolidation system was prepared，and the injection performance and the influencing factors of the sand consolidation performance of the system were investigated. A fine layered chemical sand control technology was carried out based on the intralayer low viscosity active agent sand consolidation and interlayer selective separate-layer sand control. Indoor tests showed that the low viscosity active sand consolidation system was characterized by the good injectability，low damage and high consolidation strength. The viscosity of the sand consolidation system with 10% modified epoxy resin and 1%ethylenediamine content was 4.5 mPa s，exhibiting good flowability. The sand consolidation system was suitable for the reservoir temperature of 50—90 ℃. The permeability of the cemented core formed by the sand consolidation system and quartz sand was higher than 1 μm²，and the compressive strength was higher than 5 MPa，and it had good dynamic erosion resistance. The selective seperate-layer chemical sand control string was complemented based on the injection parameter optimization，which could implement the selective injection of sand consolidation agents. The fine layered chemical sand control performed well in field tests. After a cumulative production of 2700 days，the liquid production of the test well was 52.4 m³/d，and the oil production was 5.3 t/d. The effective period had been significantly improved. It is of great significance to prolong the lifespan and increase the efficiency of sand control wells in complex fault-block reservoir.

Abstract:Heavy oil oxygen-enriched fire flooding is an enhanced in-situ combustion technology，which can effectively improve the combustion efficiency of heavy oil by injecting high concentration oxygen. However，there are few studies on the mechanism of heavy oil oxygen-enriched combustion and the kinetic parameters under different oxygen contents. In order to clarify the effect of oxygen enrichment on the oxidation characteristics of heavy oil in-situ combustion，Liaohe heavy oil was taken as an example. The simultaneous thermal analyzer was used to study the thermal weight loss and exothermic characteristics of heavy oil oxidation under different oxygen concentrations and heating rates. Based on the iso-conversional method，the activation energy under different conversion rates and different oxygen concentrations was calculated，and then the improvement effect of oxygen enrichment on in-situ combustion was studied by numerical simulation. The results showed that the oxidation of heavy oil under oxygen-rich environment could still be divided into four stages：pre-low temperature oxidation，low temperature oxidation，coke deposition and high temperature oxidation. With the increase of oxygen dosage from 20% to 100%，the oxidation reaction was more intense，the reaction rate was larger，the heat release increased，and then the corresponding coke deposition stage was advanced by 20 ℃. The change trend of activation energy under different oxygen concentrations was the same. In the low temperature oxidation stage，the oxygen concentration had little effect on the activation energy. While in the high temperature oxidation stage，the response was intense，and then the activation energy was reduced by 15—25 kJ/mol. At the same oxygen concentration，the increase of heating rate would lead to thermal hysteresis. The numerical simulation study verified that the oxygen-enriched condition could effectively improve the combustion effect of fire flooding. When the oxygen dosage increased from 30% to 50%，the cumulative oil production increased by 11 234 m³. When the oxygen dosage increased from 70% to 100%，the cumulative oil production increased by 3753 m³. It was recommended to use 50%—70% oxygen as the injection gas of oxygen-enriched fire flooding. With the increase of oxygen concentration，the leading edge temperature（350—450 ℃）increased，which improved the stability of combustion and the combustion effect of conventional fire flooding.

Abstract:During CO₂-EOR，supercritical CO₂ will extract the light components in the crude oil，resulting in the heavy components residue，which not only makes it difficult to greatly enhance the oil recovery，but also causes blockage of the pore throat and irreversible damage to the reservoir. To solve this problem，a new idea of surfactant micelle solubilizing heavy components after CO₂ flooding was proposed in this work. Sodium dodecylbenzene sulfonate and aliphatic alcohol polyoxypropylene ether sulfate were selected to investigate their micellar solubilization behavior for heavy components. The changes of micelle size and morphology during solubilization were investigated by dynamic light scattering and transmission electron microscopy. The results showed that the surfactant micelles could solubilize effectively the heavy components after CO₂ flooding. The maximum solubilization capacity of 0.2% surfactant solution to heavy alkanes and heavy aromatics was 2.5 g/L and 3.2 g/L，respectively. Heavy alkanes were more soluble in micelle core while heavy aromatics in palisade layer.

Abstract:In view of the high carbon number of paraffin wax in Yingmai crude oil of Tarim Oilfield，the poor effect of conventional oil-soluble paraffin inhibitor and the difficulty of filling due to the high viscosity at low temperature，an ultra-long carbon chain ternary polymer DMS was prepared by free radical solution polymerization using docosyl acrylate，maleic anhydride and styrene as raw materials，which was suitable for preventing wax deposition in high carbon wax crude oil. The preparation conditions and anti-wax properties of emulsion anti-wax agent HDMS with DMS as dispersed phase and deionized water as continuous phase were emphatically discussed. The results showed that when the mass ratio of T-80 to S-80 was 7∶3 and the composite emulsifier dosage was 10%，the prepared HDMS had good fluidity at 10 ℃ and the viscosity was 24.65 mPa·s. HDMS had good dispersion stability after standing at room temperature for 28 d. The particle size of HDMS was about 2200 nm and the amount of dehydration was only 0.6 mL（the bulk volume was 80 mL）within 1—28 d. When the action temperature was 60 ℃，the action time was 80 min，and the HDMS dosage was 2000 mg/L，the wax prevention rate of HDMS for high-carbon waxy crude oil was up to 84% and had certain wax prevention universality.

Abstract:Oilfield produced water has a high concentration of pollutants and lacks elements such as N and P needed for biological growth. Domestic sewage is rich in N and P，but the discharge fluctuates greatly，and the cost of separate treatment is high. In order to improve the biological treatment efficiency and reduce the treatment cost of oilfield sewage，the simulated oilfield produced water was mixed with the simulated domestic sewage for microalgae-bacteria symbiosis culture，and then the effects of different volume mixing ratios of produced water and domestic sewage（1∶3，1∶5，1∶15，1∶35）on the growth of organisms and the removal of nutrients were investigated. The microalgae was Chlorella vulgaris，while the strains were composed of Saccharomyces cerevisiae，Lactobacillus，Nitrobacter and Bacillus subtilis. The results showed that the biomass，algal density，bacterial density and chlorophyll of different ratios of produced water/domestic sewage mixtures basically presented an increasing trend with the increase of incubation time. Microalgae-bacteria grew best in the produced water/domestic sewage mixture with a mixing ratio of 1∶3. The total biomass was 0.55 g/L after 7 d of incubation，of which the algal density was 0.23 g/L and the bacterial density was 0.32 g/L. The high ratio of produced water/domestic sewage mixture was favorable for the growth of algae. The highest content of algal chlorophyll a was 649.27 μg/mg after 7 d of incubation in the produced water/domestic sewage mixing ratio of 1∶3，while the highest content of algal chlorophyll b was 821.23 μg/mg in the mixing ratio of 1∶5. In the aspect of nutrient removal，the sewage with a high mixing ratio was more favorable for the nutrient absorption by microalgae-bacteria. The highest removal rates of organic matter and ammonia-nitrogen were obtained when the mixing ratio of produced water and domestic sewage was 1∶3. Meanwhile， the removal rate of chemical oxygen demand（COD）was 65%，and that of ammonia-nitrogen was 37%. The water sample with a mixing ratio of produced water and domestic sewage of 1∶5 had the best removal of total phosphorus，with a removal rate of 70%. Mixing oilfield produced water and domestic sewage in appropriate volume ratio could promote the growth of algae-bacteria and improve the efficiency of biological treatment.

Abstract:As for the problem that the detection method of residual monomer of water-soluble polymer was too targeted，a method for simultaneous determination of maleic acid，fumaric acid and itaconic acid in water-soluble polymer used in drilling fluid by HPLC was established. The experimental conditions were obtained as follows：the water-soluble polymer was extracted with acetonitrile for 30 min，and the mobile phase contained 0.1% phosphoric acid and acetonitrile at volume ratio 85∶15. Agilent Zorbax Eclipse XDB C18 column（250 × 4.6 mm，5 μm）was used，and the flow rate of column was 0.8 mL/min，the column temperature was 45 ℃，and the detection wavelength was 210 nm. Under the above experimental conditions，the detection results had good separation characteristics（the separation degree was greater than 3），good linear relationship（the R² value was greater than 0.999）and good stability（the RSD was less than 1%）. The minimum detection limit of maleic acid，fumaric acid and itaconic acid were 0.32，0.34 and 0.63 mg/kg. the quantitation of maleic acid，fumaric acid and itaconic acid were 1.21，1.26 and 2.02 mg/kg. The recoveries of the three residual monomers were 98%—101%. The mass fractions of the three residual monomers in a sample of the viscosifier were 2.261%，0.284% and 2.775%. The time of chromatographic detection was less than 10 min，and it could meet the quality control of the water-soluble polymer. The method could accurately control the synthesis process of water-soluble polymers and achieve accurate quality control.

Abstract:With the acceleration of domestic oil and gas field development，it is difficult for traditional oilfield chemical materials to adapt to the increasingly complicated underground working environment. However，pH-responsive materials can respond under the stimulation of underground acid-base environment，so as to change their own structure and surface properties，and then better adapt to underground environment to meet the needs of oil and gas drilling and production operations. This paper briefly analyzes the action mechanism of pH responsive materials，and reviews the response mechanism and research status of pH responsive materials based on surfactants and polymers in drilling fluids，chemical flooding and fracturing fluids.

Abstract:Fine tapping of old oil fields is a key means of stabilizing the crude oil production. The main old oil fields are generally in the middle and late stages of "double high" development，with great difficulty in stabilizing production，especially in high temperature and high salinity formations. The existing plugging agent technology is difficult to solve problems such as high water content and formation heterogeneity. Based on the harsh conditions of high temperature and high salinity formation and the limitations of existing technologies，this paper introduces the research and application of modified polyacrylamide gel，silica polymer gel，slow cross-linking polymer gel and biological based profile control and plugging gel system at home and abroad，and focuses on the slow cross-linking polymer gel system，slow cross-linking technology and influencing factors. Among the above gels，PEI polymer gel has strong reliability and wider application range，however，with tightening of environmental protection policies，bio-based polymer gel plugging agent is the main development trend in the future.

Abstract:To address the issue of poor stability in conventional foam systems during oil flooding，nanoparticles are utilized to stabilize foams. For foam systems stabilized by nanoparticles used in oil flooding，based on the main components of the system formulas，they could be categorized into three types：nanoparticle foaming system，nanoparticle-surfactant foaming system，and nanoparticle-surfactant-polymer foaming system. The characteristics of different types of nanoparticles in stabilizing foams were analyzed. Based on this，it was pointed out that the development of nanoparticle-stabilized foam systems for oil flooding should move towards diversity，functionality，high performance，low cost，environmental friendliness and recyclability. Currently，the development of nanoparticle-stabilized oil flooding foam systems mainly relied on extensive experiments. Further research was needed on the microscopic mechanism of nanoparticle-stabilized foam. It should establish parameters that could quantitatively describe the factors affecting foam stability，and then realize the functional customization of new foam systems. Thus，the nanoparticle-stabilized foam systems could be applied to different reservoirs or various extraction fields.

Abstract:Asphaltene precipitation is a common challenge in the petroleum industry，occurring across nearly every stage of oil production，processing and transportation，often leading to serious operational problem. Nanoparticles（NPs），as a novel class of materials，possess exceptionally high surface energy due to their unique properties，including small size，surface effect，and quantum size effect，making them highly effective in adsorption and catalysis applications. This paper explored the mechanisms by which NPs inhibit asphaltene precipitation，including adsorption stabilization and steric hindrance. The potential action modes of each mechanism were also elaborated. Furthermore，the factors influencing the effectiveness of NPs in inhibiting asphaltene precipitation were reviewed，including nanoparticle factors，asphaltene properties and medium characteristics. The underlying mechanisms of these factors were analyzed，along with the synergistic or antagonistic interactions among them.