Abstract:In order to speed up the development of tight oil and improve the horizontal well drilling technology of tight reservoir in Yanchang oilfield，meanwhile，aiming at the polyacrylamide potassium salt（K-PAM）polymer drilling fluid system used in the current stage of Yanchang oilfield had shortcomings such as poor rheology，insufficient plugging and inhibition，the indoor optimization of the commonly used fluid loss reducer，inhibitor，lubricant，plugging agent and other treatment agent was preferred to obtain a formula of strong plugging type nano-polymeric alcohol water-based drilling fluid suitable for tight reservoir. Finally，the drilling fluid was applied in the field. The results showed that the polymer fluid loss additive COP-FL could significantly improve the water loss and wall-forming property of the system. The non-fluorescent anti-collapse lubricant FT342 had strong inhibition. The liquid extreme pressure lubricant JM-1 had good overall lubrication effect. And blocking agent anhydrous polymeric alcohol WJH-1 and nano-emulsion RL-2 could increase the drilling fluid blocking rate by 51.7%，which could enhance the wellbore stability. The horizontal section strong plugging type drilling fluid system，whose formula was 4% sodium bentonite，0.2% soda ash，0.4% K-PAM，2% COP-FL，1.5% FT342，1.0% JM-1，5% WJH-1 and 3% RL-2，was applied to two horizontal wells in tight reservoir of Yanchang oilfield. During the construction process，the system had good leakage prevention and sealing effect. The mechanical drilling speed increased by 30% compared with the adjacent one，the construction period shortened by 35% ，the downhole accident rate reduced by 85.7%，and the drilling cost reduced by 34.7%，which provided effective technical support for the excellent drilling of horizontal wells in tight reservoir of Yanchang oilfield.

Abstract:A new fluorescent-free biomass lubricant ZYRH was developed to overcome the disadvantages of high fluorescence level and poor thermal stability of commonly used lubricants. The fluorescence grade，emulsifying stability，lubricity，temperature resistance and salt resistance of ZYRH were studied. The effects of ZYRH on the rheology and wall building properties of drilling fluid were investigated. The results showed that the ZYRH level was less than 3，the stability of emulsification was good，the tolerance to temperature was up to 200℃，and the salt resistance was saturated. After adding 1% ZYRH lubricant to the base pulp， the decrease rate of the extreme pressure lubrication coefficient was 91.5%—93%，the biological toxicity EC50>1×10⁶ mg/L. ZYRH was compatible with polymer drilling fluid，polysulfonate drilling fluid and microbubble drilling fluid. ZYRH was applied in 25 wells，such as Wei 455 well and Wen 23 gas storage，and achieved good results，and the product had no pollution to the environment.

Abstract:The volume expansion and separating water of submicron cement after solidification can not be explained by existing theories. In order to explore its mechanism，G-grade，ultra-fine and submicron cement slurry were cured at high temperature of 95℃ under sealed condition. Their deformation during hydration process had many similarities and obvious differences. It was concluded that in different hydration stages，the particles of hydration products in the slurry experienced the mutual exclusion， mutual pulling and mutual extrusion，which was the fundamental reason for the micro expansion，shrinkage，cracking，expansion， separating water and many other phenomena of the slurry in turn. On this basis，referring to the research results of other scholars，acement slurry hydration deformation model was constructed，which could provide a reasonable explanation for some phenomena.

Abstract:To improve the thickening ability and crosslinkingperformance of cellulose，widen its application in fracturing fluid field，a new kind of hydrophobic etherifying agent（3-chloro -2-hydroxypropylerucylamideammonium acetate was prepared to modify carboxymethyl hydroxyethyl cellulose （CMHEC）. Hydrophobic erucamidopropyl dimethylamine carboxymethyl hydroxyethyl cellulose （ED-CMHEC） was first prepared. The rheological and crosslinking experiments of CMHEC and ED-CMHEC were carried out. The results showed that ED-CMHEC solutions exhibited higher viscosities，more apparent thixotropy and viscoelasticity，compared to CMHEC solution. At the mass fraction of 0.3% ，the viscosity of CMHEC and ED-CMHEC solutions at the temperature of 30℃ and at the shearing rate of 170 s^-1were 18.0 mPa·s and 71 mPa·s，respectively. The shear thinning behaviors of CMHEC and ED-CMHEC solutions at different concentrations could be well described by Cross model. Under the same crosslinking conditions that the dosage of zirconium organic crosslinker was 0.2%，the viscosity of gel formed by 0.3% ED-CMHEC solution was 2.4 times than that by 0.3% CMHEC solution，which indicated that ED-CMHEC had a stronger crosslinking performance.

Abstract:Based on the analysis of the water quality characteristics of the guar gum fracturing flow-back fluid（GGFFBF）from acertain oil well in Yanchang oilfield，the process of water quality regulation-flocculation-O₃ oxidation was carried out to treat the GGFFBF and the treated GGFFBF was reused to prepare the slick water fracturing fluid. The effects of various process parameters on the treatment effect were explored. The results showed that when adjusting the pH value of the 500 mL GGFFBF to 9.0 and adding 800 mg/L flocculant IF-A and 1.0 mg/L coagulant FA-B，and then pumping O3 for 40 min at a speed of 30 mL/min，the treated GGFFBF was colorless，clear and transparent，and the water quality was good. The SS content was less than 3.0 mg/L，the Feion content was below 0.5 mg/L，the viscosity was reduced to 1.28 mPa·s，and the bacterial content was low. The slick water fracturing fluid was prepared with the treated GGFFBF，and the performance of the slick water fracturing fluid was similar to that of the slick water fracturing fluid prepared with tap water，according with DB.61/T 575—2013 standard. The treated GGFFBF met the requirements for water preparation for slick water fracturing fluid.

Abstract:In order to significantly reduce the preparation and transportation costs of existing fracturing fluid，and realize online preparation of sand-carrying fluid，a new type of self-thickening proppant was prepared by attaching guanidine gum powder onto the surface of proppant particles. Performance evaluation and reservoir damage experiments of the self-thickening proppant were carried out under experimental conditions of high-temperature and high-salinity reservoir environment. The results showed that under conditions of 80℃，compared with injection water of SZ36-1 oilfield，injection water of Changqing oilfield，sewage of Daqing oilfield and fresh water of Daqing oilfield，guanidine gum solution prepared by injection water of Dagang oilfield with the highest salinity had the best gel forming effect，the highest apparent viscosity，the largest energy storage modulus and the strongest sand carrying capacity. When the sand ratio was greater than 30%，the suspension time of the self-thickening proppant was less than 20 s and the settling time was greater than 4 h. When the dosage of the self-thickening proppant was 0.03%—5.0%，the gel breaking time was 14—2.5 h. In the constant velocity experiment，with the increase of core permeability，the filtration loss increased gradually and the damage rate decreased gradually. In the constant pressure experiment，with the increase of the filtration pressure difference，the filtration amount and the injury rate gradually increased. The self-thickening proppant could meet the need of fracturing construction in high-temperature and high-salinity reservoir，and had a a broad application prospect.

Abstract:In order to reduce the damage to the reservoir caused by the leakage of fracturing fluid and the solid phase residue after breaking the gel，based on the shielding temporary plugging oil and gas layer protection theory and the characteristics of microcapsule breaker，the helper-breaking capsule type shielding temporary plugging protection agent in fracturing named TD-1was prepared by liquid drying method，which used organic acid as the core material，ethyl cellulose as the capsule material，polyethylene pyrrolidone as the porogen，and polyvinyl alcohol as the protective agent. The preparation condition was optimized and the performance of TD-1 was evaluated. The results showed that the main particle size of TD-1 was about 300 μm，the content of organic acid in coated core material was 34.1%，and the release rate was 69.0%，when TD-1 was synthesized under the condition of 2.0% polyvinyl alcohol，4.0% ethyl cellulose and polyvinyl pyrrolidone，and 500 r/min stirring rate. TD-1 was helpful for gel breaking of fracturing fluid，which could reduce the viscosity of fracturing fluid by 35.6% and the solid residue content by 44.9%. Meanwhile TD-1 had little effect on the viscosity of fracturing fluid and gel breaking time. TD-1 could form a temporary plugging zone on the surface of reservoir，which could reduce the invasion damage caused by the fracturing fluid filtrate and solid phase material. TD-1 improved the permeability recovery rate by 11.32% and made the core permeability recovery rate reached 82.47%，showing good effect on temporary shield plugging reservoir.

Abstract:In order to deal with the issue that high strength chromium gel always had high crosslinking speed，the formula of plugging agent was optimized by selecting cationic polymer and using of alumina sol. The chromium gel plugging agent suitable for deep profile control was developed and its performance was evaluated. The results showed that for acrylamide （AM）/ acryloyloxyethyltrimethylammonium chloride（DAC）binary copolymer organic chromium gel，the lower the cationic degree，the longer the gelation time was. Alumina sol could effectively delay the gelation time of cationic polymer chromium gel and improve its strength and long-term stability. The optimum formula of chromium gel system was 0.8% polymer Y5 with 5% cationic degree， 0.3% chromium acetate and 0.2% aluminum sol. The gelation time was 55 h at 90℃ and the elastic modulus was 16.6 Pa，which belonged to high-strength gel. The plugging agent had good injection ability and strong shear resistance. Meanwhile，it had strong temperature and salt resistance，and its blocking rate could reach more than 96%. This plugging agent had long gelation time and strong plugging performance，which could satisfy the requirements of deep profile control.

Abstract:In order to improve the oil displacement efficiency of offshore oilfields and meet the operational requirements of offshore platforms，an emulsion polymer gel system suitable for deep flooding of offshore oilfields was obtained by measuring the viscosity of emulsion polymer solution and gel system with time. The sealing performance and oil displacement effect of the emulsion polymer gel were studied by a sand-filling model plugging experiment with a length of 1 m and a homogeneous core flooding experiment. The results showed that the stability of the emulsion polymer was good，and the viscosity retention was 71.15% after the solution was placed for 31 days. The polymer gel consisting of two phenolic cross-linking agents and an emulsion polymer had a gelation time of 8 days and a gelling viscosity of 911 mPa·s indicating good stability. When the injection rate of water flooding and polymer flooding was 5 m/d，the plugging effect of the sand filling model was relatively good，and the plugging rate along the sandpack was more than 90%. In the core flooding experiment，the recovery degree increment of the core with a permeability of 5000×10^-3μm² was 12.46% and 3.83% higher than that of 1000×10^-3μm²and 3000×10^-3μm². Therefore，the polymer gel system couldenter the deep part of the reservoir to achieve deep adjustment and drive under high permeability conditions，and improve the effectof water flooding.

Abstract:With the end of the block of polymer flooding area or the late effect，the dominant percolation channel is more prominent， and the difficulty of effective mining is increased. In view of the demand for fixed plugging in the deep fixed point after polymer flooding，in order to further tap the remaining oil and reduce the ineffective circulation of the injecting fluid in the process of production and development after polymer flooding，a low initial viscosity controllable gel plugging agent，composed of hydrolyzed anionic polymer with molecular weight of 25 million，metalion crosslinker，regulator，retarder，strengthening agent，was developed，and the performance of gel plugging agent system was evaluated. The results showed that the formulation of the system prepared with reclaimed wastewater was as follows，500—1000 mg/L polymer LH2500+1000—2500 mg/L cross-linking agent CYJL+200—500 mg/L regulator（citric acid）+ 100—150 mg/L retarder（sodiumsulfite）+ 100—200 mg/L enhancing agent（polyphosphate sodium），the initial viscosity of the system was low，being of within 10 mPa·s，and the gelation time was controllable within 10—30 days，and the gelling viscosity was above 2000 mPa·s. the tolerance to salinity was up to 20000 mg/L，and the suitable pH range was 8—9. The system has better core plugging performance，the blocking rate of the system to the core with the permeability of 0.48—3.9 μm² was more than 99%，and the residual resistance factors was in range of 95.6—396.1.The results of the three-layer parallel core experiments indicated that the system had less pollution to the mid-low permeability core，meeting the in-sit plugging demand.

Abstract:The effective period of film-forming sand control agent depended on the molecular adsorption performance onto the surface of reservoir rock. In order to prolong the effective period of film-forming sand control agent，the adsorption performance of some cationic compounds onto the rock surface was simulated by combining molecular simulation with Monte Carlo method.According to the results of molecular simulation，the amphiphilc cationic polymer was designed and synthesized as a new film-forming sand control agent. The erosion resistance performance of film-forming sand control agent was studied，and it was implemented in Shengli oilfield. The results of simulation computation showed that hexane diacid monomer （HDA） and cyclohexane diamine monomer could not be well dissolved in water，but could be well dissolved in oil. HDA-DM1 polyamide chain had relatively good adsorption performance with -56.34 kcal/mol adsorption energy on the surface of quartz，indicating good thermal and mechanical performance. The core flooding experiment results showed that HDA-DM1 had good wash-resistant ability which was 3 times higher than that of standard requirement. The film-forming sand control agent was applied on 10 wells successfully，the sand control effect was obvious and the sand control life extended.

Abstract:The interfacial dilational rheological properties of the four components of Daqing crude oil at the kerosene-water system were investigated by means of oscillating drop method. The effects of the oscillating frequency and the bulk mass fraction were detected. The experimental results showed that all of the four crude oil components had interfacial active and the order of reducing interfacial tension was as follows，resins＞asphaltenes＞aromatics＞saturates. The dilational modulus of all crude oil fractions increased with increasing frequency while phase angle decreased. With the increase of mass fraction，the dilational modulus of asphaltenes increased linearly，and the maximum dilational modulus could reach about 50 mN/m，which was not only higher than that of the others but also higher than the crude oil fractions in other regions. The phase angle of all crude oil fractions increased with increasing mass fraction and the values were lower，appearing strongly elastic nature.

Abstract:In order to improve the efficiency of depressurization and injection increase of water injection wells in low permeability reservoirs，the influence of rock surface wettability，interfacial tension and other factors on water injection resistance was studied，on this basis，a multifunctional drag reduction and injection augmenter CNG was developed，the abilities of CNG solution to change oil-water interfacial tension，rock surface electrical property and wettability，and core pressure-lowering and injection-increasing effect were evaluated. The results showed that，CNG could reduce the oil-water interfacial tension to n×10^-3 mN·m^-1（n<10），eliminate core capillary resistance. CNG could also adsorb on rock surface to eliminate negative charge on rock surface and improve the wettability of rock surface to weak water-wet. Therefore，CNG was not only suitable for core depressurization and injection enhancement with residual oil，but also for drag reduction and injection enhancement in strong water-wet reservoirs，and also suitable for pressure reduction，drag reduction and injection enhancement in reservoirs with both residual oil and strong water-wet.For the natural core of a certain block in Shengli oilfield，when CNG was used in the original core without washing oil，the permeability was increased by 48.49% and the displacement pressure difference was reduced by 31.25%；while when CNG was used in the core without residual oil and with water wetting state，the permeability was increased by 36.32% and the displacement pressure difference was reduced by 27.66%.

Abstract:Aiming at the problems of poor physical properties，high water injection pressure，increasing number of under-injected wells year by year and difficult treatment in Jiyuan oilfield，combining with the flow characteristics of small water volume and branched form in Changqing oilfield，a long-term on-line injection enhancement technology based on boosting water injection and medicament pressure control was proposed after analyzing characteristics of main blocks. Different types of booster devices with water injection capacity of 100—300 m³/d were installed in the well site，and comprehensive depressurization and injection agents were added to meet the demand of water injection. The pressure prediction chart of main blocks was established and applied in Jiyuan oilfield. The results showed that the booster met the local on-line boosting and injection requirements. The comprehensive agent COA-2 for water injection wells with stripping dispersant，chelating agent，wetting agent，cleaning agent，acidizing corrosion inhibitor and methanol as the main agents，had the advantages of anti-swelling，scale inhibition and reducing oil-water interfacial tension，and good effect of pressure control and injection boosting. The pressure prediction chart of the main block provided a basis for effectively controlling the rise of pressure. A total of 48 well groups were implemented in the oil production plant，which improved the under-injection problem of 105 wells with ineffective multi-round injection stimulation. The average validity period was 266 days，the average single well daily injection increased by 11 m³，and the cumulative injection amount increased by 54.95×10⁴ m³. In the corresponding 826 oil wells，234 oil wells were effective with 2.25 t daily oil increase for average single well group，and 1.95 × 10⁴ t cumulative oil increase，which reached the purpose of long-term stable water injection for multi-rounds ineffective injection wells.

Abstract:In order to overcome the shortcomings of common methods for evaluating the performance of injected fluids and realize the effective evaluation of the process of injected fluids flooding in tight reservoirs，three self made microfluidic models，including two dimensions porous media model，two and half dimensions throat model and semi-circle multichannel model，were used to online characterize the oil displacement property of nano fluidity modifier for tight reservoir. The results showed that the nano fluidity modifier could greatly decrease the water flooding start-up pressure and enter the smaller pore easier. The nano fluidity modifier divided the crude oil into smaller oil drop，thus significantly increased the fluidity and migration ability of crude oil with above 90% oil displacement efficiency，which could be expected to help the development of tight oil.

Abstract:Aiming at the problems of rapid rising of water injection pressure and under-injection during the process of water injection in Gaoshangpu oilfield，a cationic-nonionic surfactant and pressure-lowering and injection-increasing agent JDZC was designed through the physical characteristics of low permeability reservoir in Jidong oilfield. The effects of JDZC dosage on surface tension，oil-water interfacial tension and emulsifying ability，and the temperature resistance，pressure-lowering and injection increasing ability of JDZC were studied. Finally，JDZC was applied in the field. The results showed that the temperature resistance of JDZC made from polyoxyethylene ether nonionic surfactant and rosin-based triquaternary ammonium salt could reach 130℃. With the increase of JDZC dosage，the surface tension of JDZC solution decreased and stabilized gradually. The surface tension of 500 mg/L JDZC solution was 28 mN/m. The critical micelle concentration of JDZC solution prepared with injected water in Jidong oilfield was 1000 mg/L. The minimum interfacial tension between 500—5000 mg/L JDZC solution and Jidong crude oil was maintained in the order of 10^-2 mN/m. The emulsifying ability of JDZC to crude oil was good，and the larger the dosage，the stronger the emulsifying ability was. JDZC had obvious effect of reducing pressure and increasing injection for the core of Gaoshangpu main formation. The permeability of core after washing increased by 40% and the pressure decreased by 26%. The field application results of 38 wells showed that the field implementation efficiency was 94%，the initial injection pressure of water injection wells decreased by 8.5 MPa on average，the validity period was more than half a year，and the average enhanced injection of single well was more than 2×10³ m³，which improved the water injection problem of Gaoshangpu low permeability reservoir.

Abstract:In view of the high concentration of hydrogen sulfide in water injection system of an oilfield in Bohai Sea，the modified triazine liquid desulfurizer and polyphosphate scale inhibitor were selected by measuring the desulfurization efficiency of desulfurizer on injected water and the effect of scale inhibitor on calcium ion concentration in injected water. Furthermore，the field pilot test was carried out on platform C where was the location of water injection well. The results showed that the desulfurization efficiency of modified triazine liquid desulfurizer for injected water was 98.1%，and the desulfurization effect was the best，but the concentration of calcium ion in water would reduce and scaling would occur. While used with polyphosphate scale inhibitor，the deposition of calcium ion could be significantly reduced. During the pilot test of the platform，the dosage of desulfurizer and scale inhibitor was 500 mg/L and 20 mg/L respectively. The concentration of hydrogen sulfide in the water source well system reduced from 800 mg/m³ to about 20 mg/m³，and the amount of hydrogen sulfide in the production fluid reduced from 150 mg/m³ to about 4mg/m³，which met the desulfurization requirement of the platform and avoided depositing scale.

Abstract:Nanoparticle flooding technology has a good oil displacement effect in low permeability reservoirs，but the problem of nanoparticles agglomeration in aqueous solution and blocking small pores in the formation has not been well solved. Low-cost oleic acid is used herein to surface modification of nano-TiO2 for reducing the agglomeration of nanoparticles，and the oil displacement system was optimized through low-permeability core simulation flooding experiment. The results showed that when the molar ratio of oleic acid to nano-TiO2 was 1∶1 and reacted at 60℃ for 4 h，the obtained modified nano-TiO2 had the longest stabilized dispersion time in aqueous solution. Infrared spectroscopy confirmed that the oleic acid group was successfully grafted onto the surface of nano-TiO2 . SEM and Zeta potential indicated that the dispersibility and stability of the modified nano-TiO2 particles was greatly improved. The particle size test results showed that the average particle size of nano-TiO2 in aqueous solution was 246.7 nm. the contact angle of unmodified nano-TiO2 and modified nano-TiO2 system with mass fracion of 0.05% on the surface of hydrophilic slide was 29.95o and 81.44 o，respectively，and the interfacial tension value was 0.475 and 0.74 mN/m，respectively，which explained the mechanism of enhancing oil recovery of the modified nano-TiO2 was still mainly relying on changing rock wettability and reducing oil-water interfacial tension. As for the low peameability reservoir with peameability of 9×10-3～12×10-3μm2，the reasonable injection parameters of the displacement system was 0.1% modified nano-TiO2+0.05% OP-10，and the reasonable injection volume was 0.3 PV，at this time，the enhanced oil recovery reached up to 15%. The nano-TiO2 solution could not only reduce the pressure of the injected water，but also improve the recovery rate of low-permeability core.

Abstract:Diffusion of CO2 in oil phase plays an important in enhanced oil recovery，since its impact on the recovery improvement percentage and oil viscosity reduction percentage. The research progress on the CO2 diffusion coefficient measurement methods including direct method and indirect method，were summarized. The difference of mathematic models and research progress of indirect method were pointed out in this paper. Based on the summary，it is pointed out that the improving the analysis of impact factors，enriching the research dimension，and improving the study of diffusion law in different scale pores will become the focus and hotspot of the future.