Abstract:The polyetheramine inhibitors of the existing water-based drilling fluid systems are difficult to effectively inhibit the hydration of shale in shale gas formation in the eastern Sichuan area，thus unfavorable well conditions were created. In order to improve the inhibitory effect of polyetheramine inhibitor，the hyperbranched polyetheramine agent（HBEA）with higher ratio of amine groups as a shale inhibitor was synthesized by the reaction of aziridine and TAEEA made from triethanolamine（TEA）and 2-chloroethylamine hydrochloride（CEAH）. Meanwhile，the metal organic framework（MOF）material was employed as catalyst for ring-opening reaction. The adsorption morphology of HBEA on clay surface was simulated by molecular dynamics，the inhibition of HBEA and the compatibility with drilling fluid system were evaluated. The results showed that attributing to its high ratio of amine groups，HBEA exhibited larger amine density than the straight chain polyetheramine D230 and D400. The adsorption model of HBEA on clay surface was consistent with that of D230 and D400，but the density and adsorption energy of a single molecule were significantly higher than that of the latter two，indicating the excellent adsorption capacity of HBEA. The yield point of slurry system containing 1% HBEA was only 7.0 Pa when the dosage of bentonite reached 25%. The swelling height of bentonite in 2% HBEA solution reduced about 60% compared with fresh water system and the rolling recovery rate of shale was 78.87%. Compared with the original polyetheramine inhibitor in three drilling fluids，HBEA with same dosage ensured the system stability of rheological property and filtration before and after aging. Meanwhile，HTHP filtration decreased gently and the rolling recovery rate of shale increased slightly. HBEA had excellent inhibition and compatibility with different drilling fluids.

Abstract:In the drilling of mud shale formation，the shale is very easy to absorb water and expand，resulting in block falling and collapse of well wall. Therefore，the well wall needs to be reinforced during drilling process. Simulating the biomineralization deposition process，nanoparticle and cationic polymer were alternately deposited on the surface of silicon wafer to form nano mineralized deposition layer. Nanoparticle and cationic polymer were optimized. The surface and cross-section morphology of deposited layer were analyzed by atomic force microscope and scanning electron microscope. The composition of deposited layer was analyzed by infrared spectrometer，and the mechanical properties of deposited layer were studied. The results showed that the deposition effect of nano calcium carbonate was better than that of nano silica，and the deposition effect of nano calcium carbonate with low concentration was excellent. A uniformly dispersed，dense and firm“mud brick stacking”structure was formed after silicon wafer deposited alternately in 1% cationic polymer（branched polyethyleneimine）and 0.4% nano calcium carbonate. When the number of deposition cycles reached 25，the thickness of deposition layer was 23.88 μm and the transverse tensile Young’s modulus was 1.4086 MPa，showing good viscoelasticity. Modified nano calcium carbonate and cationic polymer could form a dense and stable sedimentary layer on the simulated well wall，which provided a new idea for strengthening and improving the stability of well wall.

Abstract:In order to study the high temperature degradation mechanism of acrylamide polymers in aqueous solution，two template polymers P （AA/AMPS） and P （AM/AA/AMPS） were prepared by using acrylamide （AM）， acrylic acid （AA） and 2-acrylamide-2-methylpropanesulfonic acid （AMPS） as monomers. The two polymers in aqueous solution were degraded at 200 ℃，220 ℃ and 240 ℃，respectively. The polymers and their degradation products were analyzed by FTIR，¹H NMR，XPS， GPC and TG-IR. The results showed that the high temperature degradation behavior of acrylamide polymers in aqueous solution mainly occurred in the side groups，which showed that the proportion of methylene in the main chain decreased. After the methylene bond was broken，the main chain was broken，resulting in the reduction of polymer molecular weight，and small molecules，such as carbon dioxide and ammonia，were generated in the degradation process. There is a contradiction between the temperature resistance of the two polymers in thermogravimetric test and that in aqueous solution. TG-DTG cannot be used as a standard to evaluate the temperature resistance of acrylamide drilling fluid treatment agent.

Abstract:Solid content of drilling fluid has significant influence on system performance，downhole safety and construction cost. The accuracy of the measured values will directly affect the reasonable formulation of on-site maintenance programs and the cost of solid content control. In practice，it is found that there are certain problems in the measurement and data processing of drilling fluid solid phase，leading to large errors in the measurement values and processing results. The errors caused by different data processing methods was different greatly. The total solid content，water content and oil content of a series of on-site potassium-based polysulfonic drilling fluid systems were tested. The water-phase density，solid content after salt correction，low-density solid content and high-density solid content of drilling fluid were calculated according to GB/T 16783.1—2014“Petroleum and Natural Gas Industry Drilling fluid Field Test part 1：Water-based Drilling Fluid”and Drilling Manual（Party A），respectively. The accuracy of calculation results of solid content was analyzed，several attentive problems in operation and calculation were pointed out，and the reasonable range of solid content was discussed. In addition，the examples were given to analyze the phenomenon that the calculated value deviated greatly from the actual operation in process of the determination and calculation of solid phase content. The error caused by the calculation method listed in the standard GB/T 16783.1—2014 was much higher than that caused by the calculation method recommended in "Drilling Manual·（Party A）". When using the calculation method with less error，it was also necessary to correctly understand and use the variables in the formula，otherwise，the incorrect processing results would be obtained. Due to the errors in the calculation methods listed in the standard "GB/T 16783.1—2014”，it was suggested to revise the corresponding part of the standard.

Abstract:Fractures in the Chepaizi block of Junggar Basin are complex. The relatively developed fractures in Carboniferous strata cause the formation to collapse and leak easily，and the success rate of one-time plugging is low. On the basis of full consideration of the engineering geological characteristics of Chepaizi volcanic rock formation，the study of leakage prevention and plugging system was carried out. A wide-coverage high-efficiency leak-proof plugging agent （Heseal），granular fiber （FiBall） and composite nano-material（Namaterial）were added to the on-site drilling fluid and a plugging slurry was prepared. The plugging effect of plugging slurry on sand bed and fractures was studied. The turning plugging ability and vomiting trend of plugging slurry in irregular formation fracture were evaluated by the method of simulating turning and vomiting. The results showed that the best combination ratio of Heseal，FiBall and Namaterial was 6∶3∶1. The three plugging materials had little effect on the rheology and fluid loss of drilling fluid. The plugging slurry had good steering performance，sealing effect on sand bed and fracture，and leak protection effects，which could meet the requirements of leakage prevention and plugging under complex fracture patterns in Chepaizi block.

Abstract:Under the existing cementing slurry technology，ensuring the long-term stability of wellbore integrity is facing challenges，especially the conventional slurry with low density. After perforation，the integrity of cement stone is seriously damaged，resulting in sealing failure，poor cementing quality between cement stone and casing or well wall，and channeling is easy to occur. In view of the above problems，the elastic agent（RES-1）was prepared by using epoxy resin and anhydride curing agent as raw materials，the liquid fiber was used to increase the strength and toughness of cement paste，and the nano liquid lightening agent was used to improve the settlement stability of cement slurry. The comprehensive performance evaluation of elastic sealing cement slurry with low density was carried out. The results showed that RES-1 could reduce the elastic modulus and improve the deformation capacity of cement paste. The optimum dosage was 10%. The elastic sealing cement slurry system with low density （1.5 g/cm³）had good rheology. The water loss was less than 50 mL and the linear expansion rate reached 0.45%，which could effectively inhibit the generation of micro annulus and micro gap. The elastic sealing cement slurry with low density had good compactness，flexibility and elastic deformation ability. Compared with ordinary cement slurry with low density，its permeability and elastic modulus were reduced by 69.5% and 78.4%，and its compressive strength and flexural strength were increased by 61% and 87.9% respectively. The elastic sealing cement slurry with low density could effectively increase the long-term sealing capacity of cement sheath and improve cementing quality.

Abstract:In the cementing of deep and ultra-deep oil and gas wells，due to the influence of formation high temperature，some additives in cement slurry fail，which causes sedimentation of solid particle. As a result，the slurry loses stability and the risk of channeling increases in cementing process. Polyelectrolyte hydrophobically associating composite suspension stabilizer（P-AB）was prepared by strong electrostatic interaction between positive and negative ions using 2-acrylamide-methylpropanesulfonic acid， acrylamide，N-vinylpyrrolidone and N，N-dimethyloctadecylallyl ammonium chloride as raw materials. The structure of P-AB was characterized. Its influence on the performance of cement slurry was studied，and the suspension stability mechanism was analyzed. The results showed that P-AB could form a unique grid structure through electrostatic interaction and hydrophobic association， which helped to suspend cement particles and prevented cement slurry settlement and free water separation. At 40—150 ℃，1% P-AB aqueous solution could maintain high viscosity. After adding 0.5%—1% P-AB into cement slurry and curing at 200 ℃ for 1 d，the density difference between the upper and lower segments of cement stone was less than 0.02 g/cm³，and there was no free liquid of cement paste. P-AB mainly increased the settlement resistance of cement particle material through hydration，and formed a dense cross-linked network structure through electrostatic adsorption and hydrophobic association，which ensured the stability of cement at high temperature. This technology was conducive to improving the cementing quality of deep and ultra-deep wells and reducing the cementing risk.

Abstract:Slick water hydrofracking is an important method for the efficient development of shale gas，but there are a series of challenges such as low viscosity，large freshwater consumption and slick water-to-gel transition，which limit its application on the hydrofracking of deeper（>3500 m）shale gas reservoirs. In order to solve these problems，an integrated thickener（HVFR）with high viscosity and drag reduction was synthesized by free radical polymerization of acrylamide and 2-acrylamido-2- methylpropanesulphonic acid. The solubility，thickening ability，drag reduction，proppant carrying capability and temperature and shear resistance of HVFR were studied. The results showed that the relative molecular mass of HVFR was 22.7 × 10⁶. HVFR thickener exhibited a rapid dissolution rate with thickening rate of 93% within 1 min，which was conducive to the online continuous mixing of fracturing fluid. HVFR thickener exhibited significant drag reduction performance. At a flow rate of 150 L/min，the drag reduction of slick water was higher than 70% for both low and high viscosity，and that was up to 68% for gel. HVFR thickener exhibited multifunctional properties and could be freely transited between slick water with low and high viscosity and gel by altering the concentration of HVFR. The cross-linked fracturing fluid based on HVFR displayed not only remarkable temperature and shear resistance，but also good proppant carrying capacity. The viscosity of cross-linked fracturing fluid could be maintained about 120 mPa·s after shearing 120 min at 120 ℃ and 170 s^-1，which met the requirement of fracturing operation.

Abstract:In order to solve the problems of displacement fluctuation and pumping difficulty during continuous preparation process， three typical field thickeners such as guar gum，low molecular polymer LP-1 and LP-2 were selected as the research objects，and power-law relationship，viscoelasticity and Weissenberg effect of the polymer solution were measured to reveal their internal mechanism. The clean fracturing system with high temperature resistance of 120 ℃ was constructed and applied in the field. The experimental results showed that，according to the power-law relationship and solution viscoelasticity，its elasticity and consistency coefficients of LP-1 with a linear molecular structure and relatively high molecular weight，were relatively large. The Weissenberg effect of LP-1 solution was obvious，which leaded to the difficulty of pumping on site，uneven mixture and fluctuation of displacement. Based on the micro-branched associating polymer LP-2 with low climbing rod effect and the principles of “hydrophobic association and chemical crosslinking”，a clean fracturing system for engineering application，composed of 0.3% LP-2+0.3% FA+0.25% GAF-5+0.3% FP-15+0.4% AP-5，was constructed. The viscosity of the base solution of the system was 35.5 mPa·s，and the viscosity of the system was 110.3 mPa·s after shearing for 1 h at the temperature of 120 ℃ and at the shear rate of 170 s^-1 . It had the characteristics of low dosage，high temperature resistance（120 ℃），low damage（the residue content was 35.2 mg/L，the damage rate to rock core was 8.46%）and easy flowback（the surface tension of gel breaking fluid was 26.89 mN/m，the interfacial tension with kerosene was 1.15 mN/m）. The fracturing fluid system had accumulated more than 20 well times of field operation，addition of proppant had been completed according to the design，the maximum sand concentration was 400 kg/m³ . The construction displacement was stable，the construction success rate was 100% ，which provided technical support for the development of unconventional tight reservoir.

Abstract:In order to further improve the recovery of imbibition fracturing fluid after well shut-in，the effects of different residue content and molecular weight of the thickener in fracturing fluid gel breaker on imbibition recovery were studied. Through the optimization of imbibition agent and its effects on the viscosity increasing，temperature resistance，shear resistance and imbibition recovery performance of non-crosslinked associative thickener（CFZ），a set of imbibition recovery non-crosslinked associative clean fracturing fluid system with low residue and low molecular weight was constructed and optimized. The results showed that the lower the residue content and molecular weight in gel breaker，the smaller the effect on imbibition recovery. When the system， composed of 0.3% thickener CFZ + 0.2% imbibition agent SZX-1 + 0.06% gel breaker APS，was sheared at the temperature of 90 ℃ and at the shear rate of 170 s^-1 for 90 min，the viscosity was 77.43 mPa·s. The contact angle of the gel breaker on oil wet surface was 31.6°，the oil-water interfacial tension was 0.66 mN/m，the residue content was 17.2 mg/L and the molecular weight of the thicker in the gel breaker was 1.15 × 10⁴ ，the imbibition recovery was 14.8%. The system provided the theoretical basis and technical support for further improving the imbibition recovery after fracturing.

Abstract:In order to save water resources，reduce pollution and realize the recycling of fracturing fluid，the influence of residual crosslinking agent and thickener in the flowback fluid of vegetable gum fracturing fluid on the recycling was studied. Based on the standard that the system is homogeneous，raman spectroscopy was used to determine the binding forms of different polyhydroxy compounds with boron. The minimum non action amount of residual crosslinking agent boron in the system was studied. The molecular weight，total sugar content and pH value of thickener were determined. The results showed that the residual crosslinking agent and thickener are sensitive factors restricting the recycle of flowback liquid. The performance of borax mannitol complex was stable，indicating that mannitol could be used as a high-efficiency masking agent，and the minimum amount of boron without action was less than 5 mg/L. Persulfate gel breaking could partially degrade the large molecules of guar gum. With the extension of gel breaking time，the proportion of small molecules increased，and the total sugar content in the system decreased. it was found that when the total sugar content in the system was less than 1800 mg/L，the fracturing fluid could meet the requirements of cyclic utilization，but the risk of residue damage increased.

Abstract:With the development and application of volumetric hydraulic fracturing in horizontal wells，more and more fracturing fluid is being used and a lot of flowback fluid is produced. The composition of flowback fluid is complex，and It's hard to use efficiently. Direct discharge will cause environmental pollution. In order to relieve the shortage of water and reduce the fracturing cost in Xinjiang oilfield，the reutilization technology of flowback fluid from Jimusaer Shale oil fracturing was studied. After chemical treatment，such as pH adjustment，boron ion shielding and sterilization，the fracturing flowback fluid of Jimsar shale oil block was used to prepare guar gum fracturing fluid. Through investigating the swelling performance，the temperature and shear-resistance and the gel breaking performance，the best formula of guar gum fracturing fluid was determined. Then the field test was carried out at well J1. According to the characteristics of high alkali content，high boron content and high bacteria content of Jimsaer shale oil flowback fluid，the injection of 0.06% pH regulator A，0.08% shielding agent C and 0.10% efficient fungicide BLX-1 was carried out，the pH of the flowback fluid was adjusted to 7.0；then 0.3% cross-linking agent XJ-3 and 0.045% pH regulator B were added. the cross-linking time of the fracturing fluid prepared with the treated flowback fluid could be controlled within 90—110 s，and the viscosity of the fracturing fluid after gelation was still greater than 200 mPa·s after shearing for 120 min， indicating that the fracturing fluid had good performance of temperature tolerance，shearing resistance and proppant carrying capacity. Furthermore，it also possessed perfect gel breaking performance and could meet the industry standard. By using continuous mixing and reuse technology of shale oil fracturing fluid，4.5 ×10⁴ m³ fracturing flowback fluid was reused，moreover，the prepared fracturing fluid had successfully applied to shale oil well J1 of Xinjiang oilfield，which layed the groundwork for efficient and environmentally friendly development of shale oil in future.

Abstract:In order to solve the biodegradation，dehydration problem of ordinary polyacrylamide gel under the condition of high temperature and high salt，the composite gel was prepared with the konjac glucomannan（KGM） and poly（acrylamide/ 2-Acrylamido-2-methylpropane sulfonic acid），P（AM/AMPS）for short，as the main agent，xanthan gum as strengthening agent， methenamine and hydroquinone as crosslinking agent，the optimum amount was determined through investigation of the base fluid viscosity and gelling time. The structure of the composite gel was characterized by Fourier transform infrared spectroscopy（FT-IR） and thermogravimetry（TGA），and the gelling strength，temperature resistance and plugging effect of the composite gel were investigated.The results showed that the composite gel had strong temperature and salt resistance，and the gelling time could be adjusted within 120—180 min. It could meet the harsh reservoir environment with the temperature of 130 ℃ and the salinity of 210 g/L，and could maintain long-term stability.When the P（AM/AMPS）dosage was 0.5%，KGM dosage was 0.5%，xanthan gum dosage was 0.3%，ullotropine dosage was 0.5%，hydroquinone dosage was 0.6%，the gelling strength of the composite gel was the largest，the elastic modulus after gelling was 35.233 Pa. After aging for 7 days，the elastic modulus gradually increased to 71.377 Pa. The composite gel had strong plugging performance. When the injection rate was 1 PV，the plugging rate of core with permeability of 800×10^-3 μm² could reach up to 99.11%.

Abstract:During development of NH-A oilfield by gas injection，the gas-oil ratio measured in oil wells increases sharply， indicating the obvious gas channeling. To address this issue，a seawater-based and high temperature gel system was developed. Non-ionic polyacrylamide（NPAM）and phenolic system were selected as the main agent and crosslinking agent，three methods were explored to enhance the high-temperature stability of the gel by increasing polymer concentration，adding deaerators to inhibit polymer degradation and adding high temperature stabilizer. The crosslinking agent，high temperature stabilizer and polymer concentration optimization were carried out to form a seawater-based high temperature gel system. Finally，the natural gas tolerance and plugging ability of the system were evaluated. The results showed that，although the high-concentration polymer could enhance the thermal stability of gels，the dehydration rate of single-high-concentration（0.8%）non-ionic polyacrylamide gel was more than 90% after ageing for only 48 h. The presence of deoxidizer was also difficult to significantly enhance the thermal stability of gel. Fortunately，the high-temperature stabilizer could inhibit the interaction between the calcium，magnesium ions and the polymer， thus，obviously enhanced its temperature resistance，which was the key to the construction of seawater based high temperature gel system. The final gel formula formed by component-concentration optimization was：0.4% NPAM + 0.3% urotropine + 0.3% resorcinol + 0.8% stabilizer. It could maintain excellent colloidal state under high calcium，magnesium ion concentration，high temperature of 125 ℃ and natural gas condition，with a elastic modulus greater than 1500 mPa and a dehydration rate less than 10%. The gel could coexist with natural gas under high temperature and high pressure environment without breaking. It could form a good plugging on the core with a residual resistance coefficient of 210，a plugging rate of 99.5%，and a high scouring resistance.

Abstract:Conventional polymer gel used for conformance control suffers from unfavorable temperature resistance and salt tolerance. The gel strength and gel stability decrease significantly under high temperature and high salinity conditions. A polymer gel system with temperature-resistance and salt tolerance prepared by formation produced water was developed based on polymer TSRP and phenolic resin crosslinker. The mechanism of thermal stability of the gel system was studied through Fourier transform infrared spectroscopy，scanning electron microscope and dynamic light scattering. The results showed that the gelation kinetics of the gel system was significantly affected by polymer concentration，the mass ratio of polymer to crosslinker，and the dosage of thermal stabilizer. The optimum formula of weak gel was obtained as follows：2 g/L polymer，1∶1 the ratio of polymer and crosslinker and 400 mg/L thioureas. When the weak gel was prepared by formation produced water with a salinity of about 38 g/L，the gel forming time was 63 h，and the viscosity of gel was 1760 mPa·s at 90 ℃ and 7.34 s^-1 . The gel system remained stable after aging 90 d at 90 ℃ . The good stability of the gel system at high temperature was related to two aspects. The ring structure of N-vinyl pyrrolidone in the polymer chain of TSRP improved the rigidity of the polymer chain，which effectively inhibited the thermal degradation of polymer chains. Besides，the rigid network structure formed by crosslinked TSRP could partly inhibit the curling of polymer chains at high salinity，which prevented the polymer gel from syneresis.

Abstract:Nanospheres have been widely used in low permeability reservoir development. In order to study the adsorption mechanism of nano-spheres on rock and mineral surfaces，it is necessary to quantitatively characterize the influence of mineral types on the adsorption capacity of nano-spheres on rock and mineral surfaces. Firstly，starch-cadmium iodide method was used to calibrate the concentration of emulsion，and then the adsorption capacity of microspheres on the surface of single component mineral and multi-component mineral was determined. Then，based on the measured microsphere adsorption capacity on the surface of single component mineral，the predicted value of microsphere adsorption capacity on the surface of multi-component mineral was obtained by weighted superposition according to the relative content of rock minerals. The results showed that the static adsorption capacity of nanospheres on different mineral surfaces varied greatly. The adsorption capacity of clay mineral to microspheres was generally stronger than that of non-clay mineral. Kaolinite had the strongest adsorption capacity for microspheres， which was 14.75 times stronger than quartz. The adsorption capacity of microspheres on the surface of potash feldspar was 1.96 times and 8.42 times stronger than that on the surface of albite and quartz，respectively. For the adsorption capacity of microspheres on the surface of multi-component mineral，the relative error between predicted value and measured value by weighted superposition method was within 3% . Based on the adsorption phenomenon at solid-liquid interface during the migration of nano-spheres in pore channels，the analysis showed that the clay mineral on the pore wall could strengthen the adsorption of nano-spheres，which was beneficial to change the pore radius and realized partial liquid flow direction under the condition of incomplete plugging.

Abstract:According to the strong heterogeneity characteristics of Y reservoir in Xinjiang oilfield and the characteristics of low production degree and high water cut in the development profile，the formula of nitrogen foam system suitable for water injection preparation was selected. The reservoir adaptability of the foam system，the performance of the reservoir under temperature and pressure and the influence of bacteria on the foam performance were evaluated，the rheology of the foam was studied，and the oil displacement effect under different permeability ratio was analyzed by physical simulation. The results showed that the foam volume of the selected nitrogen foam system was 530 mL，the foam half-life was 167 min，and the composite index was 66 382 mL·min， which indicated that the nitrogen foam system had good reservoir adaptability. The nitrogen foam system exhibited typical shear thinning，and the addition of foam stabilizer could significantly increase the viscosity of the foam system，but it would not affect its flow in the formation. The viscosity modulus of nitrogen foam was higher than the elastic modulus（G''/G'＞1）in the frequency range of 0.1—10 Hz，exhibiting good viscous behavior and a certain elastic behavior. It could be seen from the core flow experiment that the diversion rate of high-permeability cores increased with the increase of the permeability max-min ratio in the water flooding stage，and the low-permeability cores could not be started effectively when the permeability max-min ratio was 11.53. In the foam flooding and subsequent water flooding stages，the efficiency of the low-permeability cores first increased and then decreased with the increase of the permeability max-min ratio. When the permeability max-min ratio was 8.67，the oil displacement efficiency of the low-permeability cores was increased to the maximum value of 44.97%.

Abstract:Gas channeling is easy to occur during air injection in Bohai 34-2 high temperature and low permeability reservoir. There are many limitations in conventional control methods，so it is urgent to study new profile control technology. Based on the dual characteristics of polymer viscosity increasing and foam profile control，a new polymer foam profile control system was developed， and the foam stability and shear resistance of the system were tested. The plugging performance and action range of the new profile control system were evaluated through indoor displacement experiment and CT scanning. On this basis，the two-dimensional model was used to carry out the anti channeling experiment of water gas alternation（WAG）after air injection and the anti channeling experiment of profile control agent after air injection. The results showed that the plugging rate of core with permeability of 35×10^-3 μm² was up to 98% at 130 ℃ and the gas channelling could be well suppressed by the polymer foam profile control system. After gas breakthrough，WAG method could improve oil displacement efficiency by 10.14%. However，the oil displacement efficiency was improved by 15.81% using the injection compound foam profile control system and then gas flooding，which was more than 5% higher than that of conventional WAG. Polymer foam profile control system had good plugging ability and could enhance oil recovery under high temperature，which provided a new idea for gas injection and channeling prevention in similar high temperature and low permeability reservoirs.

Abstract:Based on the respective characteristics of gel conformance control systems of HPAM/Cr³⁺ and HPAM/phenolic resin prepolymer，the chromic acetate and phenolic resin prepolymer（PRP）composite can not only improve the thermal stability of HPAM/Cr³⁺ gel，but also promote the better application of HPAM/PRP gel in low-medium temperature oil reservoirs. Besides，it can improve the mechanical properties of the HPAM gel. However，the mechanism of the composite cross-linking reaction between Cr³⁺ -PRP and HPAM is still unclear. Therefore，by characterizing the performance differences between Cr³⁺ -PRP solution and PRP solution，the chemical reaction process between Cr³⁺ and PRP was studied. Thus，by comparing the reaction differences between Cr³⁺ -PRP/HPAM and Cr³⁺ /HPAM，PRP/HPAM，the mechanism of the composite crosslinking reaction of Cr³⁺ -PRP/HPAM was revealed. In a Cr³⁺ -PRP solution，because the hydroxymethyl and phenolic hydroxyl groups on the benzene ring of PRP are more active than acetate，a new polynuclear hydroxyl bridge complex ion（Cr³⁺ -PRP complex）was formed. The cross-linking reaction between the Cr³⁺ -PRP complex and HPAM was a multiple complex reaction. At first，part of Cr³⁺ from the Cr³⁺ -PRP complex reacted with HPAM，and then the remaining Cr³⁺ and all PRP in the complex reacted with the polymer at the same time. The cross-linking reaction of Cr³⁺ and carboxy group could affect the cross-linking reaction of PRP and amide group. The reaction process of Cr³⁺ -PRP complex with HPAM was different from the superposition of the reaction of Cr³⁺ /HPAM and PRP/HPAM. The experimental results promoted the understanding of the crosslinking mechanism of Cr³⁺ -PRP/HPAM system，which could lay a certain theoretical foundation for its efficient application.

Abstract:The interaction mechanism between CO₂ miscible fracturing fluid and reservoir core was clarified through the experiment of the change law of core pore structure，core mineral composition and permeability before and after the interaction of non flowback acid，CO₂ + solubilizer（or swelling agent or viscosity reducer）in CO₂ miscible fracturing fluid system with the core of Liuzan fault block under formation pressure and formation temperature by using the experimental methods such as core displacement，SEM，XRD and CT. The results showed that non flowback acid and the carbonic acid solution formed by the mixing of CO₂ and different water-soluble additives could dissolve feldspar and clay minerals and preferentially dissolve feldspar to produce minerals such as kaolinite and quartz. The dissolution effect of non flowback acid was the strongest，followed by the mixture of CO₂ and solubilizer and the mixture of CO₂ and viscosity reducer. The liquid permeability and gas permeability showed the same increasing trend，and the increasing range of liquid permeability showed a strong power relationship with the change of gas permeability before and after CO₂ miscible fracturing fluid injection. The research results provided some technical support for CO₂ miscible fracturing EOR technology.

Abstract:A flaky two-dimensional（2-D）black nanosheet has been proven to be effective in enhancing oil recovery in low permeability and tight reservoirs， showing excellent water/oil （W/O） interface characteristics. However， the microscopic mechanism of 2-D black nanosheet interaction with W/O interface is still unclear. A molecular dynamics study was presented to reveal the characteristics of 2-D black nanosheet at W/O interface which was performed using the Lammps package at room temperature and atmospheric pressure（i.e.，298 K and 1 atm）. The influence of the number of 2-D black nanosheet on the density distribution of different molecules at the W/O interface，the thickness of the W/O interface，the rate of interface coverage（RIC）， the intermolecular interaction energy，and the rate of interfacial tension，was analyzed. The results showed that when the 2-D black nanosheets number was four，that is，RIC was approximately one，the W/O interface density distribution was stable in the MoS2 nanosheets W/O interface model. The peak density of the 2-D black nanosheets’interface almost did not increase，but the peak density became wider. Moreover，the interface thickness was 24.4 ?；the interaction energy was ? 4164 kcal/mol，and the interfacial tension ratio was 0.767 at the W/O interface，which was relatively stable. The study of 2-D black nanosheet can provide theoretical basis and guidance for their laboratory experiment and concentration optimization of field application，and lay a theoretical foundation for the study of nanosheet oil displacement mechanism.

Abstract:In order to analyze the effect of zeolitic imidazolate framework（ZIF）nanoparticles as nano-oil flooding agent on enhanced oil recovery，ZIF-8 nanoparticles were prepared at ambient temperature and aqueous phase using zinc nitrate hexahydrate and 2-methylimidazole as original materials. The microstructure of ZIF-8 nanoparticles was characterized. ZIF-8 nanoparticles were dispersed in water to obtain nanofluid. The stability of the nanofluid was studied，and the mechanism of enhanced oil recovery was analyzed by measuring oil-water interfacial tension and contact angle. Finally，the oil displacement efficiency of ZIF-8 oil displacement system was evaluated through core displacement experiment. The results showed that the average diameter of ZIF-8 nanoparticle was 65.8 nm，and the phase state was single without impurity. When the mass fraction was not higher than 0.03%，the dispersion of ZIF-8 nanoparticle in water was excellent，and the absolute value of Zeta potential was about 30 mV，indicating a high stability. After adding 0.03% ZIF-8 nanoparticle to simulated formation water and low salinity water，the oil-water interfacial tension decreased to 4.66 and 3.97 mN/m，respectively，which decreased by 75.77% and 73.25% compared with that without adding. The contact angle between nanofluid and core slice decreased from 114° and 109° to 78° and 73°，respectively，and the rock surface turned to water-wet，which was more conducive to the peeling of oil film. In the core displacement experiment，after flooding with formation water until oil-free production，0.03% ZIF-8 nanofluid was injected. The recovery factor in formation water and low salinity water was increased by 8.25 percentage points and 10.7 percentage points，respectively，which showed a good effect of enhanced oil recovery.

Abstract:The poor dissolution of hydrophobically associating polymers caused by the interactions of hydrophobes restricts their popularization and application on oilfields. Irreversible viscosity loss of polymer solution will inevitably occur through the current physical accelerated dissolution modes. Based on the inclusion of cyclodextrins and hydrophobes，cyclodextrin was added in the dissolution process of associating polymer，and the effects of cyclodextrin on the solubility and rheology of hydrophobic associating polymer were studied. The results showed that the inclusion of hydrophobe by cyclodextrin accelerated the dissolution of associating polymer without the loss of polymer solution viscosity. The inclusion of cyclodextrin on hydrophobe improved the interaction between associating polymer and solvent. As the molar ratio of cyclodextrin to hydrophobic group increased，the dissolution time of hydrophobically associating polymer decreased exponentially. Utilizing the competitive inclusion properties of cyclodextrin inclusion complex，the rheological properties of associating polymer solution could be completely restored by adding an appropriate amount of nonionic surfactant with stronger affinity to cyclodextrin.

Abstract:In the foam drainage and gas recovery process，it is difficult to achieve controllable defoaming after the foam reaches earth surface. In order to obtain a foam discharge system with both stability and responsiveness，and clarify the applicability in inorganic salt and oil phase environments，sodium dodecyl sulfate（SLS），sodium dodecyl sulfate（SDS）and sodium dodecyl benzene sulfonate（SDBS）were compounded with N-dodecyl-N，N-dimethyl tertiary amine（C₁₂A），respectively. The foam property of the compound solution and the effect of inorganic salt and oil on the compound system were studied. For the SLS/C₁₂A and SDS/ C₁₂A compound systems with better foam property，CO₂ response defoaming and N₂ heating re-foaming experiments were carried out，and the response mechanism of the compound foam was analyzed. The results showed that the foam property of SLS/C₁₂A compound system was the best，and the foam stability of SDBS/C₁₂A was the worst. SLS/C₁₂A compound system had strong salt tolerance，and SDS/C₁₂A compound system had significant oil resistance. Both compound systems showed good responsiveness and reversibility. The response mechanism was analyzed by the change of solution morphology and surface tension after defoaming. The protonated C₁₂A electrostatically attracted surfactant to form a complex，which precipitated from the solution. The surface activity of the solution was reduced and the breakage of the foam was accelerated. It had certain guiding significance for the selection of surfactant system in oil and gas fields with different environments.

Abstract:Spontaneous imbibition is the main way to improve oil recovery in tight reservoir. But the surfactant used in conventional oil flooding is easy to be adsorbed by rock and the adsorption loss is large. It cannot meet the requirement of enhanced oil recovery in harsh reservoir，and the effect of improving spontaneous imbibition recovery is not obvious. Using cyclooctane，fatty alcohol polyoxyethylene ether emulsifier，ethylene glycol and triethanolamine as raw materials，the nano-microemulsion with organic phase as inner phase and surfactant as shell film was prepared. The oil displacement mechanism was revealed by interfacial tension and wettability inversion experiments，and the effect of enhanced oil recovery was verified by spontaneous imbibition experiment. The results showed that the particle size of 0.3% nano-microemulsion system was about 10 nm，and the oil-water interfacial tension was 3.56 mN/m. The nano-microemulsion could reverse the wettability of quartz surface from oil-wet（130.6°）to water-wet （11.7°），showing good wettability reversal. The ultimate spontaneous imbibition recovery of core in the emulsion was 43.2%，that was about 2.4 times bigger than that of water. The spontaneous imbibition improved the recovery significantly.

Abstract:Aiming at the phenomenon that asphaltene deposition is easy to occur in the process of CO₂ injection to enhance oil recovery，the damage characteristics of asphaltene deposition on tight sandstone reservoir during CO₂ huff and puff were studied by using CO₂ huff and puff and nuclear magnetic resonance. The experimental results showed that，the higher the asphaltene content in the oil sample，the greater the asphaltene deposition rate in the process of CO₂ huff and puff. With the increase of experimental pressure，the asphaltene deposition first increased and then decreased，and the asphaltene deposition rate reached the maximum when the pressure was 25 MPa. The damage degree of asphaltene deposition to reservoir permeability was greater，while the damage degree to porosity was relatively small during CO₂ huff and puff. The asphaltene mainly deposit in the bigger pores， moreover，the higher the asphaltene content of the crude oil，the greater the damage degree of the bigger pores. The asphaltene deposition could make the wettability of the inlet core edge change from hydrophilic to the lipophilic. The asphaltene deposition would affect the oil recovery during CO₂ huff and puff，the greater the asphaltene content，the lower the oil recovery. In the process of CO₂ huff and puff in tight sandstone reservoir，the corresponding measures should be taken to restrain asphaltene deposition，so as to improve the effect of CO₂ huff and puff.

Abstract:In order to solve the blockage problem during the oilfield development，the representative X-5 crude oil in one Xinjiang oilfield was studied. The components of the crude oil and the blockage in both wellhead and wellbore were also studied to analyze the origin of blockage. The average structure of asphaltenes derived from crude oil，wellhead blockage and wellbore blockage were all measured，and the evolution of wax deposits for X-5 crude oil was further analyzed. It was shown that the stability of X-5 crude oil was poor and the asphaltene was easy to get aggregated and deposited. The aromatic carbon ratio（fA）of the asphaltenes derived from crude oil，wellhead blockage or wellbore blockage increased successively，which was 0.46，0.52 and 0.65，respectively. It was supposed that the asphaltenes with higher fA in crude oil were easier to aggregate and deposit. Consequently，the wellbore blockages mainly consisted of asphaltenes with higher fA. The asphaltene with lower fA was hard to form precipitates，however，it could form blockages with the participation of sand. The sand and the deposited asphaltene in oil wells were the key factors leading to blockage in the wellhead and wellbore. In addition，the wax deposits also led to the blockage of oil well.

Abstract:The factors affecting the effect of polyethylenepolyamine water clarifier produced by crosslinking linear ethylene oxide and propylene oxide with tetraethylene pentamine were studied experimentally. The results showed that the clear water process of this type of water clarifier was a demulsification process. When the temperature was higher than a certain value，the clear water effect of the water clarifier with relative molecular weight of about 10000 was mainly relative to the cloud point of the agent. When the temperature was higher than the cloud point temperature，the clear water effect became significantly worse. The cloud point temperature of the agent was mainly affected by the ratio of ethylene oxide to propylene oxide. The cloud point temperature of the agent increased with the increase of the ratio of ethylene oxide to propylene oxide. Therefore，the applicable temperature range of the water clarifier could be expanded by increasing the ratio of ethylene oxide to propylene oxide. By reducing the effective content of the water clarifier，the cloud point temperature could also be increased，so as to expand the applicable temperature range of the reagent. The injection test of water clarifier Q-03 and Q-03（diluted by 11%）with the ratio of ethylene oxide to propylene oxide of 5∶2 was carried out in the oil field. When the injection concentration was 200 mg/L，the effect of Q-03（11%）was significantly better than Q-03，which greatly improved the sewage treatment effect in the oil field.

Abstract:In order to realize the environmental protection and recyclability of the demulsifier，functionalized carbon nanotubes （CNTs）and Fe₃O₄ were composited and the CNTs/Fe₃O₄ magnetic demulsifier was prepared by solvothermal method，and the demulsifier was characterized by XRD，FT-IR and SEM. The demulsification performance of the CNTs/Fe₃O₄ magnetic demulsifier was studied，and the conditions for achieving the best demulsification performance and the recovery performance were explored. The results showed that the dispersibility of the prepared magnetic demulsifier CNTs/Fe₃O₄ was significantly enhanced by successfully compounding Fe₃O₄ and CNTs together through the solvothermal method. The best demulsification effect was achieved when the demulsification temperature was 65 ℃，the concentration of demulsifier was 600 mg/L，the demulsification time was 90 min and the pH value was 6. The light transmittance of the treated oily wastewater was up to 96.03% and the oil content of the wastewater was 0.017 g/L. CNTs/Fe₃O₄ still had a significant demulsification effect recycling four times and the light transmittance was still up to 91.43%.

Abstract:For the traditional water-based fracturing fluid，it is easy to cause water-sensitive damage to reservoir. Carbon dioxide fracturing fluid has become a new direction of unconventional oil and gas development research due to its non-aqueous components. However，due to the low viscosity of pure carbon dioxide fracturing fluid，which seriously affects the fracturing effect，it is imperative to find a suitable thickener to improve the viscosity of carbon dioxide fracturing fluid. Based on the literature research， the structure and performance characteristics of four kinds of carbon dioxide thickeners including surfactant，hydrocarbon polymer， fluoropolymer and siloxane polymer were reviewed，and the current research status of carbon dioxide fracturing fluid thickening from two aspects of thickening mechanism and thickening performance was summarized. Finally，the characteristics of various thickeners were summarized and suggestions for future research directions were put forward.

Abstract:A large amount of emulsion is easily formed in the process of crude oil production due to the active components， including asphaltene，resin，petroleum acid and wax. Based on the composition and existing state of active components in crude oil，the influence mechanism of each active component on the stability of emulsion was described. The interaction between active components and asphaltene with their influence on emulsion stability was summarized. Among the active components of crude oil， asphaltene was the main component of interfacial film，and suitable resin with asphaltene could strengthen the emulsifying effect. The effects between carboxylic organic acids with different relative molecular mass and asphaltene were various，and the wax could enhance the strength of interfacial film when they crystallized or interacted with asphaltene. Meanwhile，current problems and future development directions were prospected.