Abstract:To solve problems of the O/W emulsion drilling fluid applied in deep formation， an O/W emulsion drilling fluid with high-temperature tolerance was developed by using self-made zwitterionic emulsifier SKT-1 with high-temperature tolerance， auxiliary emulsifier Span-80， tackifier Dristemp， filtrate loss reducer sulfomethal phenolaldehy resin（SMP-I）and amphoteric ion coating agent FA-367， and so on. The stability， temperature-resistant property， rheological property at high temperature and high pressure and contamination-resistant property of this drilling fluid were studied. The results showed that the optimum formula of the drilling fluid was obtained as follows：2% sodium bentonite+2.5% SMP-I+0.2% Dristemp+0.2% FA-367+0.2% NaOH+ 2% emulsifiers（SKT-1∶Span-80=3∶1）+0.5% aluminium stearate， with 5∶5 volume ratio of diesel oil and water. The drilling fluid system had good rheological property， which density was adjusted between 0.90 to 0.98 g/cm³ and was stable at 210℃. Meanwhile， this drilling fluid had the ability to resist 20% water， 20% oil， 2% NaCl and 15% cuttings showing little damage to reservoir， which met the drilling requirements of deep formation.

Abstract:In order to obtain oil-based drilling fluid with excellent performance at low oil-water ratio suitable for shale gas horizontal wells，the effect of oil-water ratio on the particle size and stability of water-in-oil emulsions was studied by using Turbiscan Lab type dispersion stability analyzer，and the effect of oil-water ratio on the performance of oil-based drilling fluid was researched. The research results showed that particle size of the water-in-oil emulsions increased from 5.65 μm to 8.21 μm when the oil-water ratio decreased from 90∶10 to 60∶40，and the variation range of the reflected light intensity indicated the poor stability with decreasing oil-water ratio，which meant that the stability of the water-in-oil decreased with the decrease of the oil-water ratio. At the same dosage of additives，the plastic viscosity and yield point of the aged oil based drilling fluid increased respectively from 16 mPa·s to 55 mPa·s and from 7 Pa to 30 Pa，the emulsion breaking voltage decreased from 1211 V to 303 V，when the oil-water ratio decreased from 90∶10 to 60∶40. Through increasing the amount of emulsifier and reducing the amount of organic clay，an oil-based drilling fluid with excellent performance at low water-oil ratio was formed，which had been successfully used in well Jiaoye 54-3HF，well Jiaoye 25-2HF，well Jiaoye 54-1HF，and so on.

Abstract:Using waste cooking oil preparing biodiesel as basic oil and sorbitan monooleate（SP-80），alkylphenols polyoxyethylene （OP-10），PEG-30 dipolyhydroxystearate（ARLACEL-P135）as stabilizers，A environment-friendly lubricant，SWR-2，composed of biodiesel +2.25% SP-80+0.25% OP-10+0.18% ARLACEL-P135，at oil-water ratio of 6∶4，was prepared through probing the effect of HLB value and the ARLACEL-P135 dosage on the stability of the emulsion，and the lubricating property of SWR-2 was evaluated in the bentonite muds and drilling fluid. The result showed that the SWR-2 had outstanding lubricating property. The lubricating factor could be decreased above 80% after adding 0.5% SWR-2 into bentonite slurry，and it could maintain good lubricating property at high temperature（180℃） . SWR-2 also was resistant to NaCl to some degree and could be used in various water-based drilling fluids.

Abstract:In order to analyze the effect of water invasion on the reservoir permeability，the water-in-oil water emulsified drilling fluid systems after water invasion was simulated through preparing the drilling fluid with different oil-water ratio of 80： 20，70： 30，60： 40，50： 50，40： 60，30： 70，and the evaluation experiments of the reservoir damage on the drilling fluid，the rheological and wettability of drilling fluids with different oil-water ratios，were conducted. The results indicated that，on one hand，with the decrease of oil-water ratio，the stability of drilling fluid became worse，which would intensify the erosion degree of the borehole wall，destroy the mud cake and increase the filtration loss，making a large number of solid particles enter the formation and cause the reservoir damage. On the other hand，the binding ability of the fractured surface to the fluid was reduced，which was beneficial to the reverse flow of the drilling fluid in the near wellbore and reduce of reservoir damage. The suitable oil-water ratio of water-in-oil water emulsified drilling fluid systems was 40∶60—60∶ 40。

Abstract:Tight sandstone gas reservoirs are prone to aqueous phase trapping damage（APTD），due to narrow pore throat，high capillary pressure，locally ultra-low water saturation，which will reduce the productivity of the gas wells. The extent of the APTD was evaluated with the methods of phase trapping factors in the upper Shihezi formation in M gas field of Ordos basin. Imbibitions tests and liquid retention evaluations were conducted to analyze what cause the APTD，and the prevention and removal of the APTD was explored through using FW-134，a surface-modifying agents for wettability modification. Results showed that there was potentially strong damage of water phase trapping in the upper Shihezi formation. The better the physical properties of the reservoir was，such as He2+3，the easier the water imbibitions and flow back. The average liquid flowback rate in the upper Shihezi formation was 10%—47%，and the average flowback rate of filtrate was 22.4%—32.3%. The use of quaternary ammonium fluoride to change the surface to gas wetting effectively inhibited the liquid imbibition in tight stone. The flow back rate of liquid increased from 56.3% to 83.4%. Gas permeability recovery of the cores was increased from 66.1% to 88.2% after treated by FW-134. Wettability alteration from water wetting to gas wetting is an important way to prevent and alleviate the APTD in tight sandstone gas reservoirs，which is significant to recovery of the gas well productivity.

Abstract:The reservoir collapse， screen blocked and gravel packing difficult to pack densely were the main problems in open hole of horizontal well. To solve these problems， a polyurethane-expandable material that had shape memory function was developed. The shape memory， permeability， compression resistance and acid and alkali resistance of polyurethane demo were studied， and the throughput capacity and sand control accuracy of polyurethane sieve tube sample were investigated. The results showed that the shape memory function of polyurethane material was good. The shape recovery and expansion were affected by temperature. The higher temperature， the higher shape recovery rate and the faster shape recovery were. The shape recovery rate was above 99% and polyurethane material returned to the initial state when the temperature reached 90℃. The expansion rate of polyurethane material increased with increasing temperature， which maximum value was up to 400% . The permeability of polyurethane compression material after returned to the initial state was 180 × 10^-3—200 × 10^-3 μm²， and the compressive strength was 1—3 MPa. The polyurethane material had good acid and alkali resistance. Compared with the resin screen， the polyurethane sieve tube sample had poor throughput capacity and high sand control accuracy.

Abstract:To resolve the serious problem of the washing liquid leakage of dilute oil wells of Hainan the third block in Yuehai oilfield，the ZD-1 temporary plugging agent was developed，composed of 0.5% hydroxypropyl Gua，0.3% organic titanium，0.3% dodecyl dimethyl betaine，5% petroleum resin and 0.10% sodium sulfite，and the sealing performance and breaking performance of gel as well as the damage to the reservoir of the temporary plugging agent were evaluated. The results showed that the plugging rate of the temporary plugging agent to the cores with permeability of 100×10^-3—1000×10^-3 μm² was above 92%；and the gel formed by temporary plugging agent was completely broken after adding 0.02%—0.04% ammonium persulfate，and the damage rate of gel breaking liquid to permeability was only 5.23%，which was less damage to the reservoir. The agent has been applied to 8 wells and the hot washing water of the average single well was reduced by 37 m³. The average heat cleaning drainage period shortended about 3.8 days based on achieving the heat cleaning result.

Abstract:In order to improve the strengthen of inorganic gel and avoid precipitation and separation after adding polymer into inorganic gel，a thermo-responsive composite gel diverting agent was synthesized using low-cost polymerized aluminum ferric sulfate，urea，acryl amide，initiator ammonium peroxydisulfate and cross-linking agent N，N-methylene-bis-acrylamide. The microstructure and distribution state of diverting agent were characterized by using infrared spectrometer and scanning electron microscope. The temperature resistance and washing resistance of composite gel diverting agent were studied. The results showed that the suitable synthesis condition of thermo-responsive composite gel diverting agent was obtained as follows：2.0%—3.0% acryl amide， 1.5%—2.5% polymerized aluminum ferric sulfate， 0.4%—0.8% urea， 0.03%—0.05% ammonium peroxydisulfate， 0.02%—0.04% N， N-methylene-bis-acrylamide， 50—90℃ gelling temperature. The gelation time of this diverting agent ranged from 5 to 36 hrs and the gel strength was higher than 3×10⁴mPa·s. It overcame the deficiency of gelling quickly of common inorganic gel. Because of the low initial viscosity（<10 mPa·s），the diverting agent had favorable injectivity and migration property which achieved objectives of large dose injection and in-depth plugging. The composite gel had good thermal stability with 87.4% viscosity retention rate after aging 120 days at 90℃. The plugging ratio of composite gel was above 98%， and its sealing property and washing resistance were obviously stronger than that of common inorganic gel and organic gel. The thermo-responsive composite gel diverting agent could meet the requirement of profile controlling and flooding in oilfield.

Abstract:In order to investigate the gel breaking and degradation behavior of cationic polyacrylamide thickener in acid solutions at higher temperature，poly（methacryloyloxyethyl trimethyl ammonium chloride）PDMC， poly（acrylamide）PAM and P（DMC-AM） with ionic degree of 100.0%， 0.0%， 49.1%，45.9% and 12.7% ，respectively，were synthesized under the condition of pH 7.5 and the temperature of 40~60℃ with the DMC/AM monomer mass ratio of 12/0，0/12，9/3，6/6，3/9，respectively. The change of solution viscosity of P（DMC-AM）with different cationic degree before and after degradation was explored，and the structural change of P（DMC-AM）before and after degradation were analyzed by IR and 1H-NMR. The results showed that when the five samples were dissolved in acidic liquid（2% or 10% hydrochloric acid）with the mass fraction of 1%，and then was leaved at the temperature of 120℃ for 24 h or 48 h，with the increase of ionic degree，the viscosity of P（DMC-AM）solution increased slightly after degradation in general. The steric hindrance effect of cationic side chain could inhibit the degradation，and the higher ionic degree could inhibit gel-breaking. During the degradation process，P（DMC-AM）chiefly occurred backbone scission accompanied by ester bond and amide bond cleavage. Moreover，the degradation of copolymer increased with the increase of the concentration of hydrochloric acid.

Abstract:Multiple-time hydraulic fracturing is generally required in low permeability reservoirs with the implementation of CO₂ flooding，and the formation presents weakly acidic condition，which leads to the poor guar gum crosslinking effect. In order to solve this problem，hydroxypropyl guar gum （HPG） was selected as the main crosslinking agent，preprocessed partially hydrolyzed polyacrylamide（HPAM）by methanol as the assisted agent，and then different types of crosslinker were screened under the simulated acidic condition. Furtherly，the influence of the dosage ratio of crosslinker and thickener，reaction time and reaction temperature on the crosslinking effect was studied. In this way，the novel method was developed to prepare guar gum crosslinking system under the acidic condition，and the gel-forming property and sand-carrying capability of the system was investigated. The optimizing formula under acidic condition（pH=3—5）was as follows：1.6% HPG+0.2%HPAM+0.3%methanol+0.5g/L resorcinol， and the methanol-preprocessed time was 3—5 h. Gelling property of the systerm was excellent，the viscosity of the system before and after crosslinking for 5 h at the temperature of 65℃ was 100 mPa·s and 2000 mPa·s，respectively，and the sedimentation rate of proppant in the former was 31 times as long as that in the latter，which indicated that the system possessed good proppant transportation performance.

Abstract:After water or polymer flooding in heterogeneous reservoir， middle and low permeability lays in the vicinity of oil well were difficult to reach and the saturation of remaining oil was high. In order to further understand the effect of fracturing fluid filtration on fracturing and oiling， the filtration performance of five fracturing fluids was compared. By changing the filtration time of fracturing fluid and crack length， the effect and the mechanism of fracturing fluid filtration on oil increment were studied. The results showed that the filtration performance of polymer fracturing fluid was better than that of modified guar gum. Filtrate loss fluid could displace the remaining oil near the entrance of horizontal fracture to the deep area of core. The residual oil returned to production points along cracks under the action of subsequent water flooding， which improved oil recovery. By selecting the type of fracturing fluid and increasing fracturing construction time and crack length， the loss of fracturing fluid increased， the swept volume of filtrate fluctuated and the volume of surplus oil increased， as a result， the ultimate enhanced oil recovery rate increased. Under the consideration of economic benefits， the construction with a combination slug of polymer fluid and polymer gel was recommended. Rational fracture length ranged from 1/5 to 1/3 of injection-production well spacing.

Abstract:At present，CO₂fracturing technology faces many challenges of low viscosity and poor sand carrying capacity. The thickened liquid CO₂ fracturing fluid（TLCFF）was prepared by add a new thickener FAL-16（fluorine ether carboxylate surfactant） and auxiliary additive FAL-31（complexing metal ion（aluminum）organic salt）at the dosage of 1% into the liquid CO₂，and the rheological properties of the TLCFF were evaluated by a high pressure pipeline rheological experimental device. The results showed that，the viscosity of the liquid CO₂ fracturing fluid could be improved significantly by adding 1% FAL-16 and 1% FAL-31，and the viscosity of the TLCFF was up to 20 mPa·s（20 MPa，0℃，393 s^-1），which was 86—498 times higher than that of pure CO₂. The TLCFF showed the characteristic of shear thinning，the viscosity decreased exponentially with the increase of temperature. With the increase of temperature，the flow index n of the TLCFF increased，while the consistency coefficient k of the TLCFF decreased.

Abstract:In order to obtain a polymer fracturing fluid with good performance on temperature and shearing resistance，a acrylamide copolymer PAAD which contained cationic groups and organic titanium cross-linking agent TC were designed and synthesized. The cationic polymer fracturing fluid was prepared by thickening agent PAAD，crosslinking agent TC and crosslinking accelerator polyol MH. The effects of the concentration of PAAD，TC，MH and pH value on the properties of fracturing fluid were investigated. The results showed that PAAD might be used as thickening agent and it had excellent viscosifying ability. TC could crosslink PAAD effectively to form polymer gel at acidic condition. MH reacted with PAAD under high temperature that could promote the formation of polymer crosslinking network and improve the viscosity and high temperature resistance of fracturing fluid. The properties of fracturing fluid were obviously affected by the composition of fracturing fluid. The viscosity of fracturing fluid increased with increasing concentration of PAAD. But the increase rate of viscosity decreased when the dosage of PAAD was above 0.6%. When the PAAD was in a certain concentration，TC and MH had an optimum concentration for the high viscosity gel. pH value had a considerable effect on the properties of fracturing fluid. The optimum pH value to prepare fracturing fluid was 3—4. The viscosity of fracturing fluid that contained 0.6% PAAD，1.0% TC and 0.2% MH remained 90 mPa·s after continuous shearing for 90 minutes at 150℃ and 170 s^-1，which could meet the requirement of fracturing construction in oil and gas wells at high temperature（150℃）.

Abstract:In order to weaken the effect of shearing， adsorption and dilution on the bulk gel， a new profile control agent（zirconium gel dispersion agent）was prepared by the mechanical shear method with zirconium gel. The main influence factors such as bulk gel strength， shear time and shear distance on the viscosity and particle size of dispersion agent were evaluated， and the plugging and profile control performance of dispersion agent was studied in laboratory. The results showed that the gelation time and gel strength of zirconium bulk gel could be controlled by adjusting the dosage of polymer and zirconium crosslinker. With increasing dosage of both polymer and crosslinker， the crosslinking rate accelerated and gel strength became stronger. The size of zirconium gel dispersion could be controlled from 5.66 to 224.87 μm by adjusting bulk gel strength， shear time and shear distance， whereas， the viscosity ranged from 1.8 to 41.0 mPa·s. With increasing bulk gel strength and shear distance， the viscosity and particle size of dispersion agent increased， while that decreased with increasing shear time. The core flooding test results showed that the plugging rate of zirconium gel dispersion decreased with increasing core permeability. The dispersion agent had an ability to control injection profile， and enhanced oil recovery rate was up to 46%.

Abstract:In order to improve the simulation of physical model for low permeability fractured reservoir， a physical model was designed， which could adjust the width of fracture and measure the flow rate of matrix and fracture. The plugging strength performance of weak gel， pre-gel particle and their composite profile control system was evaluated， respectively， by using the fracture physical model. What’ s more， low permeability fractured cores flooding experiment was developed by using composite profile control system. The results showed that the plugging strength performance of the three systems decreased with increasing fracture width. When the fracture width was greater than 0.69 mm， the weak gel and pre-gel particle could not effectively block.With decreasing concentration of pre-gel particle， the injection volume and injection time increased when the injection pressure increased significantly， and the optimum injection concentration of pre-gel particle was 1000 mg/L. However， the maximum sealing pressure of composite profile control system was higher than that of weak gel and pre-gel particle in the same fracture width， and the content of pre-gel particle was relatively small.When the composite profile control system completely blocked the fracture， the recovery rate of low permeability fractured core increased from 5.33% to 45.58%， showing significant effect for oil recovery.

Abstract:In order to reveal the effect of nonionic surfactant on the interfacial tension between oil and CO₂ and minimum miscibility pressure（MMP）， the influencing rule of temperature and molecular structure of nonionic surfactant on the interfacial tension between oil and supercritical CO₂ and MMP was studied by pendant-drop method on autoclave. The results showed that the miscibility pressure of supercritical CO₂ and oil and MMP increased gradually with increasing temperature. The decline of CO₂ flooding miscibility pressure by lauryl alcohol polyoxypropylene allyl ether（C₁₂PO₆）increased first and then decreased， which showed the largest drop（25.6%）at 60℃. The MMP of supercritical CO₂ and oil increased gradually when the carbon number of straight chain fatty alcohol increased from 12 to 18. C₁₂PO₆ reduced CO₂ flooding miscibility pressure best. The interfacial tension and miscibility pressure of CO₂ flooding were reduced sharper with polyoxypropylene ether group than polyoxyethlene ether group. The MMP decreased first and then increased with increasing polymerization degree of polyoxypropylene ether， which minimum was 13.22 MPa with 6 polymerization degree. C₁₂PO₆surfactant had best effect on decreasing miscibility pressure of CO₂ flooding.

Abstract:In order to reveal the influence of anti-clay swelling agent of quaternary ammonium salt cationic polymer on the stability of heavy oil emulsion，basing on the factor of on-site produced liquid of cycle steam stimulation in NB35-2 oilfield，W/O emulsion was prepared by high-temperature high-pressure autoclave. The effects of anti-clay swelling agent on oil-water interfacial tension and interfacial shearing viscosity，apparent viscosity and emulsion dehydration rate were studied. The results indicated that oil-water interfacial tension decreased and interfacial shearing viscosity increased with increasing anti-clay swelling agent concentration. With the increase of shear rate，oil-water interfacial shearing viscosity increased and finally reached stability when anti-clay swelling agent concentration was constant. The temperature had great effect on the property of emulsion. The anti-clay swelling agent could not form a stable emulsion with crude oil at 55℃. The emulsion was stable and its apparent viscosity increased with increasing anti-clay swelling agent concentration when emulsification temperature was 100℃ and 150℃. Apparent viscosity of emulsion increased and emulsion dehydration rate decreased with increasing emulsifying temperature. When anti-clay swelling concentration was 0.5% —10% ，the emulsion was stable and dehydration rate was 0 at 150℃ . Anti-clay swelling agent of quaternary ammonium salt cationic polymer could reduce oil-water interfacial tension and increase interfacial film strength and the stability of W/O emulsion.

Abstract:To improve polymer flooding results in Bohai heterogeneous heavy oil field，the dual parallel core flooding test was conducted to study effects of permeability differential，polymer concentration，water cut at polymer injection on the profile reversion，and effect of the injected polymer type and concentration，polymer alternative injection cycles on enhanced oil recovery was investigated. The results showed that polymer injection was suitable at early stage（water cut less than 80%）， small permeability differental（less than 6），and appropriate polymer concentration for effective mobility control and good injectivity had vital importance on polymer flooding efficiency. The alternating injection of weak polymer gel and polymer solution would reduce the total recovery at the same dosage of polymer injection；alternate injection of high concentration polymer system（2250 mg/L×0.15 PV）and low concentration polymer system（1750 mg/L×0.15 PV）for 2 cycles had more than 4.3% recovery efficiency than that of the direct polymer injection at the same dosage of 1200 mg/L·PV. The alternative injection of polymer slug could improve polymer flooding performance in Bohai heterogeneous heavy oil reservoir.

Abstract:In order to understand the laws of HPAM adsorption and desorption，the dual polarization interferometry （DPI） technology was introduced to study the microcosmic adsorption and desorption behavior of polymer in the oil-water interface，the thermodynamic and kinetic model for polymer adsorption was established，and then the mechanism of the polymer adsorption in oil-water interface could be revealed from molecular level，providing new ideas and theoretical basis in the treatment of polymer-contained water. It was demonstrated that polymer displayed fast adsorption-slow desorption process in the oil-water interface. The maximum adsorption showed a linear relationship with the polymer concentration. The polymer adsorption capacity was significantly affected by the polymer molecular weight，hydrolysis degree and hydrophobic monomer content. Absorption kinetic parameters conformed to the pseudo-first order kinetic rule. Under different concentration，the corresponding reaction rate constant K was 0.029 s^-1. After long time desorption，there were still residual polymer in the oil-water interface. The residual quantity increased with the increase of polymer concentration.

Abstract:Dual polarization interferometry was used to investigate the interaction between typical Daqing crude oil and three acrylamide-based polymers，and the effects of polymer concentrations and structures on the mass，thickness and density of oil films were examined. A five-stage model，including physical absorption，high coverage，deposition of polymer micelles，solubilization of crude oil and encapsulation of oil drops was proposed for the interaction between amphiphilic polymer and oil . It was found that NaCl solution has a negligible effect on mass of oil film. The mass and thickness of oil film increased and the density of oil film decreased after eluted with the amphiphilic polymeric surfactant PAM1 solution，because the formed polymer micelles could dissolve oil and carry it away from oil film. The higher the concentration of PAM1 was，the stronger the interaction was. PAM2， bearing a side unit of 2-Acryloylamino-2-methyl-1-propanesulfonic acid，could only adsorb onto the surface of oil film；while PAM3，a common HPAM，showed no interaction with crude oil owing to its strong hydrosolubility.

Abstract:Aiming at the problem that common surfactants didn’t resist high concentration salt and it was not easy to be used as flooding chemicals and fracture liquids in high salinity reservoirs，a new type of betaine surfactant containing hydroxyl and sulfo， named N-（6-tetradecyloxy-5-hydroxyl）-propoxyethyl-N-dimethyl-N-（2-hydroxyl）propanesulfonic acid sodium ammonium chloride， was successfully synthesized by two step etherification and one quaternization with tetradecyl alcohol，epoxy chloropropane，N，N-dimethylethanolamine and 3-chloro-2-hydroxy propanesulfonic acid sodium as main raw materials. The structure of the product was characterized by infrared spectrometer，and their surface activities of surfactant solution were studied. The results showed that the synthesized surfactant had good surface activity，whose critical micelle concentration（c_CMC）was 6.4 × 10^-4 mol/L，surface tension（γ_CMC）was 32.2 mN/m，surface tension reduction efficiency（pC₂₀）was 3.38，the saturated extent of adsorption（Γ_max）was 2.80×10^-6 mol/m² and the minimum adsorption area（A_min）was 0.17 nm² per molecule at 25℃. The high salinity had less impact on the hydrophilic group of surfactant. When the mass concentration of NaCl，CaCl₂ and MgCl₂ arrived 2.8×10⁵，2.0×10⁴ and 2.0×10⁴ mg/L，respectively，the synthesized Gemini surfactant didn’t generate precipitation，indicating good salt resistance.

Abstract:In order to study the change law of various performances of the functional poly-surfactant during the long distance migration process in porous media，a physical sand-packed model with 30 meters long was set up to conduct the oil displacement experiment with poly-surfactant BI system in laboratory，the dynamic law of the mobility control ability and the pressure， viscosity，concentration and emulsification of the poly-surfactant during the long distance migration was studied. The experimental results showed that the injection of poly-surfactant BI system could greatly improve mobility ratio and percolating resistance. The oil recovery percentage could be increased by 20.85% on the basis of waterflooding（43.12%），and the total recovery degree was as high as 63.97%. The effective distance of poly-surfactant solution was 2/3 of the injector-producer spacing. The viscosity and concentration of the poly-surfactant BI system reduced to a quite lower level after migrating 20 m，and so as the pressure reflected. The poly-surfactant BI had a strong emulsifying ability，which made emulsion band form in the model. The emulsion band migrated to the in-depth area of the model with the injection of poly-surfactant system，the emulsion was broken when migrating 20 m，and the emulsion could not be formed in the latter 1/3 of the injector-producer spacing.

Abstract:In order to reveal the effect of temperature on the physical and chemical properties and the stability of micellar structure of anionic surfactant at critical micelle concentration，the surface tension，foam half-life and viscosity of sodium dodecyl sulfate （C₁₂H₂₅SO₄Na） and sodium dodecyl benzene sulfonate （C₁₈H₂₉NaO₃S） solution were measured. The physical and chemical properties such as viscosity activation energy，micelle standard enthalpy change and standard entropy change were studied. The results showed that the critical micelle concentration of C₁₂H₂₅SO₄Na and C₁₈H₂₉NaO₃S was 0.008 and 0.002 mol/L at room temperature respectively. The surface tension and foam half-life of two surfactants decreased exponentially and the viscosity decreased linearly with the increase of temperature. The viscosity activation energy of C₁₈H₂₉NaO₃S was 1.96 times of that of C₁₂H₂₅SO₄Na，but the efficiency of reducing surface tension and adsorption trend of C₁₂H₂₅SO₄Na were more than that of C₁₈H₂₉NaO₃S. The standard micellization free energy and standard enthalpy change of C₁₂H₂₅SO₄Na were larger than that of C₁₈H₂₉NaO₃S，and the micellar structure was more stable.

Abstract:In order to probe the real migration role of the polymer and polymer/ surfactant binary compound flooding system，two 15 meter core models with oil sand of J oilfield were established，and the binary compound flooding system，composed of 1200 mg/L polymer 3640，a acrylamide/acroleic acid copolyler with relative molecular weight of 2000×10⁴ and hydration degree of 20%，and 1200 mg/L surfactant HDS，a complex of sodium alpha-olefin sulfonate and surfactant APG，and polymer flooding（1200 mg/L polymer 3640） displacing experiments were carried out under the condition of 57℃ and monitored by measurement of the concentration and viscosity of the samples obtained during displacing process at different pressure monitoring nodes. The results showed that polymer concentration and viscosity of two systems reduced with migration distance increasing and the viscosity lost more. Compared with polymer flooding，the binary compound flooding system had lower injection pressure and the enhanced oil recovery was 4.94% higher. Lower interfacial tension between the binary compound flooding system and the simulated oil maintained half of the distance，and finally it was close to that of polymer flooding. The binary compound system could form the stable emulsion with the simulated oil，when injected into the core. With the increase of migration distance，the adsorption loss of surfactant would lead to demulsification and coalescence of the emulsion. The migration rule based on the super-long core would provide effective parameters to guide the following scheme optimization and adjustment.

Abstract:In order to understand the change of the microbial community during process of MEOR displacing in Baolige oil field， the type and abundance of the microbial community in the key oil wells was analyzed by high-throughput sequencing technology. The results showed that the microbial diversity of the analyzed reservoir was rich，while the species distribution was very uneven.The abundant genera were Pseudomonas，Acinetobacter，Alishewanella，Thauera，Halomonas and Wolinella during the process of microbial enhanced oil recovery，which indicated that the main microbial role in this stage was to produce biosurfactant and degrade the hydrocarbon. The biosurfactant concentration increased by 44.23% on average，and the surface tension of the produced liquid decreased by 12.75% on average. When the injection of the nutrients to the reservoir was over，the concentration of hydrocarbon degrading bacteria decreased，and the abundance of anaerobacteria and methanogens increased. The methanogens abundance increased from 0.116% to 40.77% in oil well B18-41. In this stage，the main microbial role was to produce gas by anaerobic fermentation. After the completion of microbial displacement of 60 days，the methane gas content increased 10.65%.

Abstract:In order to reveal the relationship between the changes of biochemical indexes in produced fluid and the effect of increasing production in oil well，indigenous microbial flooding field test was carried out in four injection wells and 11 production wells of Keshang conglomerate reservoir in mid-7 district of Karamay oilfield. Biochemical index of the test wells，including total viable count in produced fluid，hydrocarbon-oxidizing bacteria（HOB）number，sulfate-reducing bacteria（SRB）number，nutrients （total sugar and total nitrogen），acetate ion concentration，water quality and aqueous phase surface tension，etc，were tracked and monitored. The results of test showed that indigenous microbes could increase the total number of bacteria with 1—2 orders of magnitude and the number of HOB with 2 orders of magnitude. The SRB was inhibited. The higher the number of live bacteria and HOB，the more obvious effect was. The average concentration of acetate ion per well increased to 8.0 mg/L after microbial flooding measures. The total sugar and total nitrogen content were less than 10% of that with injected nutrient，and the change of monitoring period was not obvious. It would be a higher utilization rate on the condition of activator nutrients injected into the reservoir. While the change of aqueous phase surface tension，water salinity and pH value was little，which had little impact on the effect of increasing production.

Abstract:In order to dissolve the corrosion and scaling problems of injection-production string for the Dagang gas storage，through the optimization of a variety of functional additives，such as density regulator，corrosion inhibitors，deoxidizer，scale inhibitors and fungicides，a kind of self-healing annulus protection fluid（SHAPF），whose density can be adjusted within 1.0—1.6 g/cm³，was developed as follows：base solution +5% imidazoline corrosion inhibitor GL-3（imidazoline dithio phosphate as main component）+ 2% oxime deoxidizer dimethyl ketoxime（DMKO）+1% bactericide 1227（dodecyl dimethyl benzyl ammonium chloride）+1.3% organic phosphate scale inhibitor ZC-21 （ATMP as main component）+ 0.01% pH regulator （sodium carbonate）. Corrosion inhibition property，oxygen removal performance，sterilizing performance，scale inhibition performance of SHAPF and effect of SHAPF on the performance of the packer rubber tube of was examined. The experimental results showed that，the corrosion rate of steel sheet in the SHAPF could be as low as 0.045 mm/a，oxygen in the solution could be reduced to 40 mg/L，the sterilization rate could reach up to 100%，the anti-scaling rate of the SHAPE to CaCO₃ and CaSO₄，BaSO₄ scale could reach as high as 99%，93% and 81% respectively，and the SHAPF almost had no effect on the packer rubber tube. The SHAPF could buffer effectively hydrogen ions dissolved by acid gases and remain the related properties. Hence，the SHAPF can achieve the goal of effective protection of tubing and casing and is suitable for application in the acidic gas reservoir.

Abstract:In order to probe the inversion mechanism of water-in-oil emulsion of heavy oil and to provide the theoretical guidance for oilfield exploitation and transportation，five heavy oil in shengli oil field were used as the research object to study the inversion characteristic of crude water-in-oil emulsion. The viscosity of the heavy oil emulsion with the different cut content and the HLB value of heavy oil emulsion was measured，in addition，combining the grey correlation entropy method，the relationship between the viscosity of heavy oil emulsion and the four components（resin，asphaltene，aromatic and saturate）was investigated，and the reason for the differences of the reserve phase point of heavy oil with different properties was analyzed with the HLB value of heavy oil. The results showed that the order of correlation degree between the polar fractions and the viscosity of heavy oil by grey correlation entropy method was as follows：heavy component（resin + asphaltene）>aromatic>saturate，the influence of heavy component on viscosity of the heavy oil was the greatest. For the same kind of heavy oil，with the increase of water cut，the apparent viscosity of emulsion increased first and then decreased；as the temperature increased，the reverse phase point of heavy oilemulsion raised. The viscosity of five kinds of dehydrated heavy oil in the experiment （50℃ ） was arranged as follows： Cao20-ping124（14400 mPa·s）>Wang152-1（22400 mPa·s）＞Cao20-ping149（24000 mPa·s）＞Cao20-ping131（76800 mPa·s）＞ Caonanping40（89400 mPa·s）. The viscosity of five kinds of heavy oil emulsion with water cut of 30% had the same order in accordance with that of dehydrated heavy oil. The reverse phase point of five heavy oil was arranged as follows：Cao20-ping124 （59.1%）＞Wang152-1（55.5%）＞Cao20-ping149（53.5%）＞Cao20-ping131（47.9%）＞Caonanping40（45.7%）. It was found that the reverse phase of emulsion dropped with the increase of the viscosity of dehydrated heavy oil.

Abstract:In order to reveal the effect of polymer sheared by stratum on oilfield output liquid，the electrostatic separation effect of nonionic polyacrylamide（NPAM）after degrading and demulsifier YFPC-792 on W/O emulsion of Brazilian Peregrino oilfield through indoor electrostatic coalescence fast evaluation system was studied. The results showed that YFPC-792 could improve the electrostatic separation effect of W/O emulsion. Under the electric field of 150 Hz and 294.44 kV/m，the best electric field residence time of W/O emulsion was 100 min. With increasing NPAM concentration，the electrostatic separation efficiency and average droplet size of W/O emulsion decreased，and the viscosity of NPAM solution increased. Because of the bridging flocculation effect between NPAM molecules，the electrostatic coalescence effect of emulsion with 200 mg/L NPAM before degrading was the best whose dehydration rate was 81%. While the electrostatic coalescence efficiency of emulsion containing degrading NPAM decreased with increasing NPAM concentration. The electrostatic coalescence efficiency of 20% moisture content emulsion was the worst （49%），while that of 30% moisture content emulsion was the best（81%）. Within 5—15 min after the dehydration of W/O emulsion containing YFPC-792 and degrading NPAM，the W/O emulsion separating effect of gravity sedimentation was better than that of electrostatic separation effect，and then the opposite.

Abstract:In order to improve the demulsification effect of the high-solid dirty oil with strong stability，the process of ultrasound combined with demulsifier agents（UCD）was employed，and using water content of demulsified oil as the evaluation index，at the condition of 0.15 g/L water-soluble demulsifier SP3 and 0.15 g/L oil-soluble demulsifier AR304，the effect of ultrasound on dirty oil demulsification was investigated systematically. Without ultrasonic assistance，the demulsifier agents alone had no obvious demulsification effect，and the dirty oil was basically in a state of emulsion. By contrast，as the dirty oil was processed by UCD，the water content in oil layer could be decreased from 54.8%（without ultrasonic）to 10.2%，realizing three-phase separation of water，oil and solid. Meanwhile，UCD could decrease solid particle size，ensuring the solid particle separated from oil phase easily；and the contact angle of water on the surface of solid particle was lower than 90°，indicating that UCD could enhance the surface wettability of solid particle. Furthermore，UCD still could decrease the content of resin and asphaltene in dirty oil， promoting the transfer of chemical agents and ultrasonic energy，and reducing the stability of dirty oil，thus achieving demulsification，dehydration and solid removal effectively. The optimal ultrasonic condition was achieved as follows，the ultrasonic power was 500W，the frequency was 22 kHz and the treating time was 10 min.

Abstract:In order to resolve the CaCO₃、CaSO₄ scaling problem of Huaziping Block of Changqing oilfield，The scale inhibitors of 1.0G PAMAM-COONa and 2.0G PAMAM-COONa were obtained by the reaction between polyamidoamine （PAMAM） and chloroacetic acid，and then the molecular structures was established by FT-IR and elemental analysis. The scale inhibition performance of 1.0G PAMAM-COONa and 2.0G PAMAM-COONa tor CaCO₃、CaSO₄ was studied，and the scale inhibition performance of the complex scale inhibitor PNF-2.0G ，composed of the scale inhibitor PNF and 2.0G PAMAM-COONa at mass ratio of 1∶1，to the blend water of produced water Block Huaziping and the injection water at mass ratio of 1∶1 was studied. In addition，the field test was conducted. The results showed that the scale inhibition of PAMAM-COONa to CaCO₃ and CaSO₄ was better than that of PAMAM，and the scale inhibition of 2.0G PAMAM-COONa to CaCO3 and CaSO4 was better than that of 1.0G PAMAM-COONa at the temperature of 60℃ . At the dosage of 20 mg/L，the scale inhibition rate of 2.0G PAMAM-COONa to CaCO₃、CaSO₄ was about 95.64%，92.35% ，respectively，while the scale inhibition rate of 1.0G PAMAM-COONa to CaCO₃、 CaSO₄ was about 82.25%，89.36%，respectively. As for the blend water of the produced water of 97-42 well and the injection water， when the addition of was 20 mg/L，and the scale inhibition scale of the 2.0G PAMAM-COONa and PNF was 75.53% and 60.5%， respectively，while that of the PNF-2.0G was 95.56%. As for the blend water of the produced water of 100-45 well and the injection water，the scale inhibition rate of 2.0G PAMAM-COONa and PNF was 38.5% and49.5%，respectively，while that of the PNF-2.0G was 98.91%. The field test results showed that the compound scale inhibitor PNF-2.0G played an excellent scale inhibition effect.

Abstract:The offshore oil field injection well polymer concentration can be measured fast，accurately and safely by nitrogen detection technology，however，when detecting the produced fluid，it was found that the impurities including emulsified crude oil and mud sand，etc，are difficult to be separated，which lead to larger absorbance and interfere the determination results. Based on the above situation，the particle size distribution of emulsified crude oil，hydrodynamic diameter，relative molecular mass distribution，etc，was analyzed，combining the screening theory of microporous filtering film，a“microporous filtering film filternitrogen content determination”method was established to determine the polymer concentration in produced fluid. The results showed that the produced fluid oil droplet size was mainly distributed in range of 5—20 μm with median diameter of 9—17 μm， more than 80% emulsified oil droplet size was larger than 5 μm，while the residual polymer hydrodynamic diameter was mainly distributed between 0.4—1.2 μm. Based on the size difference between the oil droplet and polymer，the microporous filtering film with aperture size of 1.2—5 μm was chosen to pretreat the produced fluid，and the determination error could be reduced from 16% to 5%. The method has been tested several times in offshore polymer injection oilfield，and an excellent application effects has been obtained.

Abstract:Inaccessible pore volume（IPV）of polymer had a deep impact on the swept volume in polymer flooding. In order to reduce the effect of IPV as much as possible in consideration of formula optimization，a new method for the measurement of IPV was built. Starch-cadmium iodide method was used to measure the concentration of polymer through the cores，then the IPV could be calculated directly with the equation of mass conservation. Besides，with the distribution of pore radius by mercury intrusion method，the limit radius of IPV could be calculated. With this method，the IPV and the limit radius of IPV of HPAM and crosslinking HPAM solution were calculated，and on this basis，the effect of permeability and crosslinking agent dosage on the two parameters was studied. The results showed that the IPV increased with decreasing permeability，and the ratio of IPV increased with increasing concentration of crosslinking agent when the permeability was similar. The limit radius of IPV enlarged with increasing dosage of crosslinking agent in the core with high permeability. However，the dosage of crosslinking agent barely affectd the limit radius of IPV when the permeability was lowered to a certain extend. The method was simple and reliable. The IPV and the limit radius of IPV of any oil layer could be measured as long as the outcrop cores were obtained. The result of the study could provide data support on the formula optimization of polymer or crosslinking polymer flooding.

Abstract:At present，the traditional scale weighting analysis method which also was called weighting compatibility test could only evaluate the weight of scale but lacking of approaches and standards for quantitative scaling degree evaluation. In order to improve the traditional scale weighting analysis method，the scaling type and scaling degree were evaluated from the two aspects of qualitative and quantitative study. The basic concepts like suspended scale，settling scale and total scale were proposed，and the parameters and standards for scaling degree evaluation of injection water and formation water were established. Taking injection water of Guantao group and formation water of Minghuazhen group in BZ28-2 south oilfield as the research object，the types and content of scale were studied by several approaches such as X-ray diffraction analysis（XRD），scanning electron microscopy （SEM）and optical microscopy analysis（OP）. The results showed that the injection water and formation water in BZ28-2 south oilfield were seriously incompatible and the comprehensive evaluation index of fluid compatibility degree was 3.33. The comprehensive evaluation index of the scaling degree was 3.87 and the scaling degree was medium to strong，which was easy to generate CaCO₃ scale. The measured total scale was from 27.5 to 94.0 mg/L，and among which the settling scale was predominated. In addition，the scale was the most serious when the volume ratio of injection water to formation water was 1∶1. The scaling degree evaluation method was both scientific and objective，which could be applied to evaluate the scaling degree among various fluid types in oilfield.

Abstract:Carbon dioxide fracturing technology had the advantages of low damage and easy flowback. It was especially suitable for low pressure，low permeability，dense and strong water sensitivity complex reservoir. This technology had a good effect on formations with low water cut and serious oil pollution. In this paper，carbon dioxide fracturing and carbon dioxide foam fracturing technology were introduced from the aspects of technical principle，fracturing fluid preparation，characteristics and applications. In addition，two kinds of special fracturing technique including super critical carbon dioxide fracturing and liquid carbon dioxide foam fracturing were also introduced.