Abstract:To avoid lumps and accelerate the dissolution of xanthan gum in water, surfaces of xanthan gum particles were modified in dimethylbenzene with organometallic complex COMe. The preparation condition of dispersible xanthan gum (Disperse XC) was optimized by orthogonal experiment, and its molecular structure was characterized by IR. The dispersibility, rheological property and solubility of Disperse XC were studied. The results showed that the optimum reaction condition of Disperse XC was obtained as follows: 10 g xanthan gum, 0.09 g COMe and 4.5 g distilled water, and the pH value was about 4.5 adjusted by citric acid. Testing result of IR showed that the molecular structure of xanthan gum didn’t change after modification, while the hydrogen bonding between xanthan gum molecuars weakened. Disperse XC powders completely dissolved in simulated seawater in 35 min without lumps, and the apparent viscosity of Disperse XC solution was 19.5 mPa?s. The rheological property of Disperse XC was similar with that of XC, dispersibility and solubility of Disperse XC were better than that of XCD.

Abstract:In order to obtain oil-based drilling fluid with high performance, the emulsion stability of oil-based drilling fluid was improved by using hydrophobically-modified silicon dioxide nanoparticle DSW-S. The microscopic morphology and hydrophobic of DSW-S were examined, the effect of DSW-S dosage on rheological property and electric stability of oil-based drilling fluid was studied, and the stability mechanism of drilling fluid by nanomaterial was analyzed. The results showed that hydrophobic nanoparticle helped to stabilize the W/O emulsion. At the same time, nanomaterial helped to increase the viscosity and shearing force of oil-based drilling fluid. The addition of 3% DSW-S could make the demulsification voltage of oil-based drilling fluid increase from 318 V to 535 V. The emulsion stability of oil-based drilling fluid improved substantially, which contributed to fast and safe drilling in shale formation.

Abstract:In order to solve the problem of the higher solid phase sedimentation of the high-density oil-based drilling fluid used API barite as weighting materials, three kinds of ultrafine powders (particle size≤4 μm),API barite and the complex system of ultrafine powder and API barite in mass ratio of 1:1 was respectively added in the high-density emulsion inversion oil-based drilling fluid and the relative performance was evaluated. The results showed that, compared to the API barite, ultrafine powders could improve greatly the rheology and electric stability of high-density oil-based drilling fluid, micromax did the best effort, and then was microdense, the last was microbarite. When adding the complex sytem of ultrafine powders and API barite in mass ratio of 1:1, only the drilling fluid with density of 2.3 g/cm³ containing micromax and microdense could have a good rheology, while the drilling fluid containing microbarite had worse theology, however, which could be improved by decreasing the dosage of the emulsifier. The apparent viscosity of the drilling fluid, using the complex system of ultrafine barite and API barite in mass ratio of 1:1 as high-density weighting materials, was of only 68 mPa?s, the plastic viscosity was of 59 mPa?s, initial gel strength/10 minute gel strength was of 6 Pa/8 Pa, at the same time, demulsification voltage was greater than 1732 V, and stability index TSI was 0.5. Ultrafine powders technology significantly improved the theology and the static high temperature stability of the drilling fluid and reduced the cost, which could easily meet the needs of ultra-deep well complex geological conditions.

Abstract:In order to improve the durability of the cement sheath, The silane coupling agent KH-560 was used to coating on the surface of oil well cement particles, and a self-repairing well cementation cement slurry system was formulated by adding 10% oil well cement particles coated with the silane coupling agent to the cement slurry. Through the analysis of wettability and hydrate exothermal tests，the surface properties of oil well cement particles coated with the silane coupling agent KH-560 were studied; through the analysis of scanning electron microscope (SEM) and the model experiments of the cement sheath self-healing with micro-clearances and micro-cracks，the microstructure and self- repairing properties of the cement sheath formed by the new self- repairing well cementation cement slurry system were studied. The results showed that, the surface of oil well cement particles coated with the silane coupling agent KH-560 formed a hydrophobic protective membrane , which could decrease the activity of hydration reaction. The quantity of unhydrated particles and the ability of multiple hydration reaction of the cement sheath formed by the new self- repairing well cementation cement slurry system were increased significantly compared to that of the common cement slurry，which improved the self-repairing performance of cement slurry. For the injured cement slurry samples（for modeling the micro-clearances and micro-cracks of the cement sheath），it is found that the anti-channeling strength recovery value was higher than 50% in the cement sheath samples formed by the new self- repairing well cementation cement slurry system，and the self-healing performance for micro-clearance and micro-crack was superior to the ordinary cementing slurry，as a result, the durability and intergrity of the cement sheath was enhanced and the cementing quality of oil and gas well and gas storage under complex conditions was improved.

Abstract:Oil-based drilling fluid adhesion makes the casing surface change into lipophilic，which will influence bonding strength between casing and cement sheath. By measuring the bonding strength between casing with different wettability and cement sheath，the effect of the casing surface wettability on the interface bonding strength was explored，and the influence mechanism was analyzed using atomic force microscopy，in addition，effect of the surfactant type and concentration，temperature on the surface wettability of casing was probed. Results showed that with the increase of the surface concentration，the casing surface became more hydrophilic，and the effect of anionic surfactant LAS was the best. Through emulsification solubilization of surfactants，most of the oil adhered on the casing surface was carried away，so that the hydrophilic casing surface was exposed. The bonding strength increased with the increase of the hydrophilicity of the cashing（decrease of the surface contact angle），and changed in mutation at contact angle of 62°—63° . The contact angle decreased with the increase of the LAS concentration，the contact angle decreased rapidly when the surfactant concentration was less than 5 g/L；the contact angle changed little when the surfactant concentration was more than 20 g/L，as a result，the LAS amount should be within 20 g/L. in addition，temperature had a promoting effect on the LAS reverse wetting ability

Abstract:For the development of a new clean fracturing fluid, a thickener MC-1 was obtained by compounding sodium fatty acid methyl ester sulfonate (MES) and erucyl amidopropyl carboxyl betaine (CAB). The effect of the content of MC-1 and inorganic salt on the viscosity of MES fracturing fluid was studied. The temperature and shearing resistance, sand-carrying capacity and gel breaking performances of the clean fracturing fluid (3% MC-1+4% KCl) were evaluated. The results showed that MC-1 thickener had a good compatibility with ionic salt, such as KCl, NH4Cl and NaCl, among which KCl was the best. The viscosity of fracturing fluid increased with increasing content of MC-1 and KCl. The fracturing fluid possessed good temperature tolerance and shearing resistance. The settling velocity was 1.18 mm/s on the condition of 80℃ and 40% sand ratio, which indicated that the fracturing fluid had a good sand-carrying capacity. The fracturing fluid completely broke down in 2 hrs at 80℃ with the addition of kerosene. The viscosity of the gel breaking liquid was 4.5 mPa?s, and the surface tension and interfacial tension of that was 24 mN/m and 0.8764 mN/m, respectively. The fracturing fluid was adapt to the formation whose temperature was smaller than 90℃.

Abstract:To reveal the performance characteristics of homemade degradable fracturing polymer ball, the degradation behavior of fracturing ball at various degradable time and temperature was investigated by using water, fracturing fluid and flow-back fluid acting as a degradable media of fracturing ball. Furthermore, the degradation mechanism of fracturing ball was discussed via infrared spectroscopy and XRD technology. The results showed that the mass and diameter of fracturing ball, immersing in water at 100℃, decreased gradually when degradable time increased. The mass of fracturing ball, immersing in flow-back fluid, decreased gradually when degradable time increased, and the degradation rate of fracturing ball increased when environment temperature increased. When they were immersed in fracturing fluid, the mass and diameter of fracturing ball kept instant with increasing degradable time. The degradation mechanism of fracturing ball was analyzed from molecular structure and aggregation of polymers. Fracturing polymer ball with stable compressive property was carried out in a conventional pitching manner in fracturing process. After fracturing, polymer ball was self-degraded without recycling. Degradable polymer ball had a wider application compared with degradable alloy ball.

Abstract:In view of the sand production in fracturing process of production well with strong base/surfactant/polymer (ASP) flooding, taking the sand production rate as evaluation index, the sand production degree and influence factor of ASP flooding in artificial core were studied. The results showed that with increasing closure stress of fracture and concentration of sand filling, as well as decreasing injection rate, the sand production rate decreased. The sand production rate of ASP flooding was higher than that of water flooding. When the injection rate was 200 and 800 mL/min, the sand production rate of ASP was 3.29 times and 1.84 times of sewage’s, respectively. The sand production rate of vertically fracture was higher than that of horizontal fracture. The type of displacement fluid and fracture pattern had no influence on the sand production rate of alkali resistant resin sand, which was zero when injection rate was 200—800 mL/min. Mixing quartz sand with walnut shell or carbon fiber could reduce the sand production rate, and “quartz sand+walnut shell” had better effect than “quartz sand+carbon fiber”. During the process of ASP flooding, alkali resistant resin sand and “quartz sand+walnut shell” should be used to support agent.

Abstract:In order to obtain a crosslinker with good resistance of high temperature and shearing, and good effect of retarding crosslinking, an organic boron-zirconium crosslinker with certain viscosity and color of reddish brown was synthesized at 80℃, with citric acid, glycerol, formaldehyde, triethanolamine as the ligands, zirconium oxychloride and borax as the main components. The preparation condition of the crosslinker was optimized, the effect of the dosage of crosslinker and regulator on crosslinking time was investigated, and the performance of gel breaking and shearing resistance at high temperature about the gel was evaluated. The results showed that, in preparation of the crosslinker, the optimum mass ratio between zirconium oxychloride and borax was 0.9—1.5. The optimum volume ratio of regulator, crosslinker and fracturing base fluid was 0.4:0.5:100. On this condition, the crosslinking time with picking and hanging was 64 s. After adding 0.001%—0.003% ammonium persulfate in guar gum fracturing base fluid, the gel breaking time was 6—12 h, the viscosity after gel breaking and the surface tension conformed to the requirement of industry standard. The viscosity of gel remained 100 mPa?s after continuous shearing for 90 minutes at 140℃ and 170 s^-1. The crosslinker had good performance on high temperature and shearing resistance and effect of retarding crosslinking, which could meet the need of the most oil and gas wells fracturing construction.

Abstract:Based on diffusion action and Fick's law and the kinetic data of the Cr³⁺ release rate at different time), a kinetic model for predicting Cr³⁺ release rate of W/O/W multiple emulsion was estabilished. The change of Cr³⁺ release rate of three different internal water phase of W/O/W multiple emulsion with time was monitored for 10 days at the temperatures of 20℃ and 60℃, respectively. Cr³⁺ release occurred without film rupturing (coalescence), mainly due to entropically driven diffusion/permeation phenomena. At the temperature of 60℃, compared with non-chelating agents, when there was a chelating agent(potassium sodium tartrate)，the Cr³⁺ release rate was significantly decreased from 98% to 70%，effectively delaying the release of Cr³⁺.The kinetic data were consistent with the kinetic model based on diffusion action and chromium chelation.

Abstract:In order to study the mechanism and effect of multi-slug agent profile control in fractured reservoirs，the multi-slug agent flow control process of single and multiple fractures system was researched by indoor visual fracture model，and the mechanism of multi-slug agent profile control in fractured reservoirs was analyzed. The field tests of multi-slug agent profile control were conducted in Yanchang eastern oilfield. Experiments and field tests showed that the multi-slug agent profile control process in single fracture has two stages：gel filling stage and gel compaction stage，the water flooding pressure gradient after multi-cycle with small slug agent injection increases more than 2 times than that of large slug agent continuous injection；the multi-slug agent profile control processed in multiple fractures system had three stages：agent selective entrance stage，gel filling stage and gel compaction stage，eventually the profile control of fractures was improved. After multi-slug agent profile control，the injection wells of Yanchang eastern oilfield returned to normal，water injection pressure rose from 0.25 MPa to 8.5 MPa，water injection rate rose from 2.0 m3/d up to 8 m3/d，the daily oil increment was 2.52 t，the average water cut decreased from more than 90% to 71.7%. The multi-slug gel profile control technology obtained good effect in oilfield，which could be used as one of the increasing oil and decreasing water technology for fractured low permeability reservoirs.

Abstract:In order to prevent the polymer solutions from channeling during polymer flooding, a profile control agent HN-3 used in polymer flooding technology in Henan oilfield, consisted of 400-800 mg/L multifunctional ionic Polymer ZN930 and 40-80 mg/L organic chromium cross-linking agent DT862, was prepared. The compatibility between the ZN930 and polymers used in Henan oilfield was studied, the effect of ZN932 concentration, DT862 concentration and shear action on the gelling performance was investigated，and the injecting and plugging ability of the HN-3 in porous media was evaluated. The experimental results showed that the compatibility between the ZN930 and polymers used in polymer flooding units was good. No seperation or precipitation occurred to after being placed for 90 days at reservoir temperature of 50℃, moreover, the viscosity of the aged system was slightly higher than the initial viscosity. Gelling properties of multifunctional ionic polymer was superior to partially hydrolyzed polyacrylamide with the same or slightly higher molecular weight in the case of the same polymer consumption. At the reservoir condition, good gel could be obtained after mixing ZN930 of 400—800 mg/L with DT862 of 40-80 mg/L, and the gel did not break within 180 d，which indicated that the system after gelling had excellent stability. With the increase of the injection speed, the initial viscosity and the gelling viscosity decreased and the gelling time prolonged, especially at the speed of 1200 mL/h, the system after sheared hardly form the gel, hence, the shear of ground equipment on the system should be controlled. Under the same injection rate，compared to the polymer 3630、SMO-4000、1285 solutions at the same concentration of 1000 mg/L, the HN-3 has a favorable injection，high plugging ratio（>90%） and controllable strength(40-1500 mPa?s).

Abstract:In order to obtain the Profile Control System suitable for Heavy Oil Reservoir Steam Drive，firstly, the traditional high temperature resistant main agent, NH-1 main agent(aromatic hydroxy carboxylate), was modified though introducing the substituent nitro-group in the benzene ring of NH-1 main agent to improve the heat-resistant ability; secondly, quaternary copolymer gel solution was developed by mixing the modified NH-1 main agent with the coagulant aids and two different cross-linking agents; hirdly, graphite particle-gel complex profile control (GPGCPC) system was obtained by combining the gel solution with graphite particles. The adaptability, plugging ability, anti-scour ability and heat stability of the GPGCPC system were evaluated. Experimental results showed that the modified NH-main agent was. The formula of the GPGCPC system was as follows, 0.025% Coagulant BK-A05+ 2.2% cross-linking agent I +1.8% cross-linking agent II+8% modified NH-1 main agent(developed at 1:6 mass ratio of NH-1 to nitric acid with fraction of 65%)+0.7% graphite particles （10000 mush）+0.3% suspending agent CMC. The gel-forming viscosity of the gel solution was up to 2×10⁶ mPa?s, and the gel-forming temperature ranged from 160℃ to 280℃; the gel solution was heat-resistant to 300℃, applicable to the formation of pH = 6 ~ 8 and the alkaline water salinity limit was 8000 mg/L. The Injectivity of the GPGCPC system was good; the plugging rate of the GPGCPC system on the cores with water permeability of 900×10^-3 μm² was more than 99%. In addition, the anti-scour ability and heat stability of the GPGCPC system was excellent, the plugging rate of the cores only decreased by 0.35% and 1.63%, respectively, after 30 PV high-speed steam (300℃) scouring，and the thermostability test at the temperature of 300℃for 50 days, respectively, which was obvious stronger than that of the single gel system.

Abstract:In order to obtain the gel performance on the condition of reservoir with heterogeneity, modified starch graft copolymer plugging agent was studied using conventional single sand pipe, parallel sand pipes and independently developed two-dimensional vertical heterogeneous long-core model. The experiment results showed that the plugging agent consisted of 5% modified starch, 5% acryl amide, 0.05% cross-linking agent and 0.1% initiator had good injectivity. The plugging rate of plugging agent to high permeability, media permeability and low permeability sand pipes was 99.2%, 97.1% and 91.0% respectively, showing good plugging ability. The plugging agent had good injection selectivity which preferred to plug high permeability layer. With the increase of permeability contrast, the injection selectivity improved. The plugging agent effectively plugged large channel of heterogeneous long-core model caused by water flooding. The medium and low permeability reservoirs had been fully utilized. The water flooding recovery efficiency of high permeability, medium permeability and low permeability reservoir increased by 2.2%, 3.3% and 5.6%, respectively, and the ultimate recovery rate increased by 11.1%. Finally, it had strong washing resistance ability. The plugging agent had good gel performance, which could be applied to heterogeneous heavy oil reservoir.

Abstract:In order to improve mechanical properties of fiber complex sand control system, fiber complex was modified by introducing nanoparticles SiO₂ into resin-coated sand. Nano-SiO₂ modified resin-coated sand was made by dispersing nano-SiO₂ (3% of resin mass fraction) into water soluble phenolic resin using ultrasonic dispersion solution blending method, and the fiber was added into nano-SiO₂ modified resin-coated sand to obtain fiber complex. Properites of the different sand control systems were characterized. Experiment results showed that nano-SiO₂ had good reinforcing effect on the mechanical properties of the resin coated sand control system and had little effect on the permeability of the fiber complex sand control system, the compressive strength of the fiber complex modified by nano-SiO₂ was improved by 26.12%; on the other hand, fiber could improve the permeability of the resin coated sand control system by 11.13%.

Abstract:RTS-polymer HNY-1 is prepared for high saline Bamianhe oilfield, especially aiming to high bivalent cation oil reservoir condition. Viscosity increasing ability, anti-bivalent cation ability and long-term stability of this RTS-polymer have been evaluated by laboratory performance evaluation, and oil displacement efficiency has been evaluated by physical modeling. The study results indicate that the polymer has strong salt tolerant. With increasing bivalent cations, viscosity of the polymer decreases, but is　22.6 mPa?s higher than 16mPa?s in 30000mg/l salinity and 2000mg/l lime magnesia ions, and anti-bivalent cation performance is superior than that of KYPAM series. Viscosity of the polymer trends to be steady after 100 days under conditions of Mian 1 Block, and viscosity is 20.1 mPa?s higher than 16mPa?s，The viscosity retention rate of static adsorption is 81.2% higher than 80%，the injectivity is accord with reservoir conditions in Mian 1 Block. The polymer is well adaptable for oil reservoirs. Oil displacement experiments show that recovery ratio was 14.48% more after HNY-1 polymer injection in dual natural core by Mian 1 block waterflooding experiment, 1.06% higher than that of KYPAM series, and can improve development performance of heterogeneous oil reservoirs in Mian 1 Block.

Abstract:In order to study the aggregation behavior of hydrophobic modification dendrimer in solution，fluorescence probe was used to research the mutual effect between pyrene and hydrophobic associating polymer AP-P4 or dendrimer. The microsturcture of two kinds of polymers in solution was compared through ESEM. The results showed that the amount of hydrophobic micro-domain formed in solution increased with increasing concentration of polymer. When the average capacity of hydrophobic micro-domain solubilizing pyrene molecule reached maximum，the mass concentratioin of AP-P4 and dendrimer was 1300 mg/L and 600 mg/L respectively. The capacity of dendrimer solution sloubilizing pyrene molecule was stronger than that of AP-P4 solution，and the number of hydrophobic micro-domain formed was larger too. While polymer concentraion was more than 870 mg/L，the average capacity of dendrimer solubilizing pyrene molecule was less than that of AP-P4. Comparing the microstructure of dendrimer and AP-P4 through ESEM，there were small network structure stacking，spreading and connecting with each other in three-dimensional network structure formed by dendrimer in solution，which increased the whole microstructure tightness but reduced the hydrophobica micro-domain volume of dendrimer and the average capacity of hydrophobic micro-domain solubilizing pyrene molecule.

Abstract:Salt-resistangt polymer, in particular the hydrophobic associated polymer get good effect during the practice of EOR in oilfield, however, technical staff just concentrated on viscosity of polymer solution and neglected the adaptability between polymer molecular aggregates and rock pore and heterogeneity of reservoir in the past. Experiment that the degree association of hydrophobic associated polymer AP-P4 and the adjustment method was carried out based on reservoir and liquid in Bohai SZ36-1 oilfield, and the evaluation of adaptation between heterogeneity of core and the degree of hydrophobic associated polymer molecule association was conducted. The results showed that, When β- CD was added into the AP-P4 solution with concentration of 1750 mg/L, the amount of β-CD increased from 0 to 0.08%, the viscosity of β-CD/AP-P4 system reduced from 172.1 mPa?s to 7.7 mPa?s and the molecular clew dimension Dh of β-CD/AP-P4 system decreased from 1078.2 nm to 500.1 nm, while the suitable core permeability varied from 1500?10^-3 μm² to 150?10^-3 μm², respectively. β-CD could adjust the size and size distribution of polymer aggregates and improve the adaptability of the polymer with rock pore of reservoir. The hydrophobic associated polymer with different association degree was suitable for special heterogeneity of reservoir. When the adaptability between flooding agent and pore throat of core was well, the oil recovery could reach to the maximum.

Abstract:Due to the apparent phenomena of hydrolysis and degradation reaction of HPAM in the condition of high temperature, the property of temperature resistance and salt resistance of HPAM is worse. Depending on the macromolecule net structure formed through the association among molecules, the property of salt-resistance of hydrophobic associated polymer is improved, which compensated the defect of the poor salt-resistance of HPAM. However, there exists a problem that the compatibility between the molecular thread size of hydrophobic associated polymer and pore size of porous medium of the reservoir is poor, which result in the difficulty of injection of hydrophobic associated polymer. Aiming at the problem of worse compatibility between hydrophobic associated polymer and reservoir, β-cyclodextrin（β-CD）was used as association-degree adjustment agent of hydrophobic associated polymer, by means of indoor core displacement experiment, the influence of a β-CD on the transmission migration of hydrophobic associated polymer AP-P4 was probed. Results showed that, β-CD could change the association action of AP-P4 and the behaviors of AP-P4 in the porous media. After adding β-CD into the AP-P4 solution with the concentration of 1 g/L, the viscosity of AP-P4 solution reduced with the increase of β-CD content, and when the β-CD content was 0.07%, the viscosity of the AP-P4 solution reduced to the lowest（26.2 mPa·s, which was of bulk viscosity），at this time, the aggregation hardly happened. As the aggregation among molecular chains of hydrophobic associated polymer became weaker, the molecule thread size also reduced. With the increase of the concentration of β-CD, on the condition of the same core permeability, the resistance coefficient and residual resistance coefficient of hydrophobic associated polymer solution decreased, and its transmission migration capacity in the core pores was enhanced.

Abstract:In order to obtain the surfactant with good performance, the synergism between sulfonate and sulfonate surfactant for lowering interfacial tension at oil/water interface was studied. The dodecyl alkylbenzene sulfonate（C12ΦS）, 4-(7'- tetradecyl) benzene sulfonate (7C14ΦS) and 4-(8'-octadecyl) benzene sulfonate (8C18ΦS) and two branched alkylbenzene sulfonates were selected, the alkane scanning curves of the sulfonates and their mixtures were obtained, the effects of hydrophilic-lipophilic abilities of sulfonates and mixing ratio on synergism were investigated, and the tensions of sulfonates and their mixtures against crude oil were measured. Experiment results showed that the synergism between sulfonates derived from the amelioration of the hydrophilic-lipophilic ability, when the hydrophilic sulfonate was mixed with the lipophilic sulfonate, a surfactant mixture with a moderate hydrophilic-lipophilic ability could be produced, and synergism action decreasing interfacial tension could be achieved. After adding proper complex sulfonate surfactants, the interfacial tension between the crude oil of Changqing oilfield and the 1% NaCl solutions could decrease to be a ultra-low value.

Abstract:In order to reveal the performance of petroleum carboxylate and alkyl benzene sulfonate compound system, the effect of mixed micelle (supramolecular structure) formed from petroleum carboxylate and alkyl benzene sulfonate on the interfacial activity of compound system was investigated. The research results showed that the difference of hydrophilic lipophilic balance (HLB) value made petroleum carboxylate and alkyl benzene sulfonate having different insertion depth of molecules at oil-water interface. The distance of polar groups became far and polar group’s repulsion reduced. As a result, their mixed micelles arranged more closely, the interfacial adsorption increased and the interfacial activity was better than that of a single surfactant. The structural characteristics of compound system made it having the advantages of interfacial activity. Compound system had ultra-low interfacial tension in a wide range of surfactant concentration and salinity. It had an excellent interfacial activity in weak base case (0.6%—1.2% Na₂CO₃), which avoided formation damage from strong base (NaOH). It took less surfactant to achieve ultra-low interfacial tension and could reduce the cost of surfactants for chemical flooding. After contacting with oil droplet, it could quickly achieve ultra-low interfacial tension, which was beneficial to the oil displacement process. The interfacial activity of compound system was good in strong base, weak base and none-alkali system. The molecular structure of alkyl benzene sulfonate which had a good synergistic effect with petroleum carboxylate should be linear so that they could form closed mixed micelle with a better interfacial activity.

Abstract:In order to get an effective flooding system used in low permeability and high salinity reservoir in Changqing oilfield, a kind of mixed surfactants YFFP-2 was obtained through the mixture of petroleum sulfonate anionic surfactant CQPS and fatty alcohol series of nonionic surfactant ZFC-2 with the help of additive ZJ-5. The interface characteristic, emulsifying property, adsorption and EOR performance of the mixed surfactants were evaluated. The results showed that the best formula for the system was obtained as follows: 0.15% CQPS, 0.05% ZFC-2 and 0.005% ZJ-5. The interfacial tension between YFFP-2 and oil was 3.35×10^-3 mN/m at the condition of 80℃ and salinity of 50 g/L. The drainage rate of YFFP-2 emulsion after placing 15 h was 15%. The dynamic adsorption in natural low permeability core (20×10^-3 μm²) was 0.63 mg/g, which was much smaller than the static adsorption in the surface of oil sand and clean sand (13.9, 12.8 mg/g). The final oil recovery of YFFP-2 system was 68.4%, and the mixed surfactants flooding could improve the oil recovery by 26.4% on the basis of water flooding. The EOR effect of the mixed surfactants was better than that of CQPS.

Abstract:anionic-nonionic sulfonate surfactant has advantages both of anionic surfactants and nonionic surfactants, containing one hydrophobic chain and two hydrophilic-chains consisted of ethylene oxide chain (EO) and sulfo group,which endow the surfactants with unique surface-active properties, especially in temperature resistance and salt tolerance. The surface activie properties of two surfactants, named as sodium palm diethanolamine polyoxyethylene ethers sulfonate (abbreviated as PDES), sodium oleic acid diethanolamine polyoxyethylene ethers sulfonate (abbreviated as ODES) were investigated. The results showed that, the critical micelle concentrations ccmc of the PEES and ODES were 1.14×10^-3 and 6.67×10^-4 mol/L, respectively, the relative surface tensions γcmc were 38.40 and 35.68 mN/m, respectively. With the salinity and temperature increasing, the values of ccmc and γcmc decreased a little. The Kraftt points of PEDS and ODES was lower than that of the conventional anionic surfactants, being of 17℃and 14℃, respectively, and their cloud point were both higher than 110℃, exhibiting good water-solubility and temperature resistance. In addition , when the PEDS or ODES solutions with mass fraction of 0.5% in 100 g/L Na⁺ salt solution or 4 g/L Ca²⁺ salt solution, there was no precipitation, which indicated that PEDS and ODES had excellent salt-tolerant ability.

Abstract:A type of betaine trimeric surfactant，penta sodium N，N'，N'' - dodecyl diethylene triamine pentaacetic acid，was synthesized by alkali neutralization reaction and nucleophilic substitution reaction with diethylene triamine pentaacetic acid，sodium hydroxide and dodecyl bromide as main raw materials. The structure of the product was characterized by 1H-NMR and FT-IR，and the surface tension curve and related parameters were acquired by surface tension measurements. The experimental results showed that the structure of the synthesized compounds was in conformity with the expected structure of surfactant，the critical micelle concentration（ccmc）was of 1.1 mmol/L，and the surface tension at ccmc（γcmc）was of 34 mN/m，pC20（negative logarithm of the surfactant's molar concentration C20，required to reduce the surface tension by 20 mN/m）was 3.22，the surface excess（Γmax）at air/solution interface was 5.15×10^-3 mol/cm² and the minimum area per surfactant molecule at the air/solution interface（Amin）was 3.1 nm² at 25℃，which meaned that target product had good surface activity.

Abstract:In order to analyze the appearance of water-in-oil type emulsion with high viscosity (3000 mPa?s) during some binary flooding production wells in Xinjiang oilfield, the emulsification process of surfactant/polymer compound system and crude oil in chemical flooding was simulated in laboratory. The effect of salinity, oil-water ratio, surfactant concentration and the dilution of underwater on the type of emulsion was studied. The model of emulsion conversion was also built during core flooding. The results showed that when the salinity was lower (100 mg/L NaCl), the main emulsion type was oil-in-water. When the salinity was 10 g/L, the water-in-oil emulsion formed. The emulsion type was oil-in-water when the ratio of oil to water was 1:9 and 3:7. Once oil-water ratio reached 5:5 and the concentration of surfactant was 500 mg/L, water-in-oil emulsion formed. With the increase of groundwater, the oil-in-water emulsion changed to water-in-oil emulsion. The flooding experiment results showed that during the propulsion process of binary system, the salinity and water-oil ratio increased, the concentration of surfactant reduced, which made emulsion change from oil-in-water type to water-in-oil type.

Abstract:In order to dip remaining oil further in reservoir after polymer flooding，the comparative experiments were carried out by alternately injecting the slug of the gel and polymer/surfactant compound system or the slug of gel and polymer solution into artificial heterogeneity large flat core. The experimental results showed that，by alternately injecting 0.26 PV gel and 0.39 PV polymer/surfactant slug after polymer flooding，the oil recovery could be enhanced more than 11.29% on the basis of polymer flooding，while the oil recovery could be enhanced more than 7.10% by alternately injecting 0.26 PV gel and 0.39 PV polymer slug，which indicated that compared with the alternate injection of gel and polymer，alternately injecting the slug of the gel and polymer/surfactant had more potential on further developing the residual oil and enhancing the recovery after polymer flooding，but the cost of the former was higher. Therefore，apart from the recovery，the other factors must be considered，such as cost and market price of crude oil，in actual technique optimization.

Abstract:In order to understand the synergistic effect among components of organic alkaline/surfactant/polymer (OASP) flooding system, the interfacial tension (IFT) between OASP flooding system and n-alkanes were studied using the spinning drop method. The results showed that the nonionic surfactant alkanolamide 6501 could effectively reduce the oil-water IFT. At an optimum concentration of 2.0 g/L, the IFT between n-decance and 6501 surfactant solution could be decreased to 10^-1 mN/m. The addition of organic alkalines (monoethanolamine or diethanolamine) would further reduce the IFT to 10^-2 mN/m by increasing the solubility and molecular arrangement of 6501 at the oil/water interface. Monoethanolamine has a stronger ability of reducing IFT than diethanolamine. Moreover, the different types of polymers have significant influence on the IFT of OASP system. Water-soluble polymer would reduce the IFT to 10^-3 mN/m, while hydrophobic association polymer would increase the dynamic IFT value and the steady IFT remained to be 10^-1 mN/m order of magnitude.

Abstract:In order to confirm the polymer injectivity of the chemical displacing agents, the influence factors of hydrodynamic size of polymer was analyzed for polymer(P), alkali-polymer(AP), surfactant-polymer(SP) and alkali-surfactant-polymer(ASP) flooding, respectively, and the polymer solution injection experiments for the different reservoir with 6 kinds of permeability was carried out to obtain the optimal matching polymer injection. The results showed that, for P system, the hydrodynamic diameter Dh of polymer increased with the increase of polymer molecular weight (Mr) and polymer concentration(C), respectively. For AP system, Dh decreased with the increase of concentration of alkali and the effect of strong base was better than that of weak base. For SP system, surfactant concentration needed for maximum Dh was decided by the relative content of surfactant and polymer. For ASP system, when surfactant content is relatively less than polymer content, alkali and surfactant had mutual restriction effect for Dh; when surfactant content was relatively more than polymer content, alkali and surfactant have mutual synergy effect for Dh. When polymer solution was injected into the cores, the C and Mr of polymer should match with the K of the cores, when 53≤K＜91×10^-3μm²，C＜1g?L^-1 and Mr＜1×10⁷；when 91≤K＜146×10^-3μm²，C＜2 g?L^-1 and Mr≤1×10⁷；when 146≤K＜199×10^-3μm²，C≤2 g?L^-1and Mr≤1.5×10⁷；when 199≤K＜252×10^-3μm²，C≤2.5 g?L^-1and Mr≤2.7×10⁷.

Abstract:In order to discover the reason of stable emulsion with high viscosity from ASP production well, on the basis of analyzing oil phase viscosity difference from core and production well, the affecting factors of emulsion stability and viscosity were investigated by changing stirring rate and chemical type and concentration and water cut and petroleum composition. In addition, the related mechanism was discussed. The results showed that high viscosity emulsion was formed by mixing produced water with ultra-low concentration chemical agents and crude oil using strong acting force(stirring rate of homogenizer >6000 r/min) at certain water cut(≤50%), and asphaltene in crude oil was the key factor to the formation of stable emulsion with high viscosity. When chemical agents（heavy alkyl benzene sulfonate, alkali or HPAM）with low concentration were added in the simulated formation water, the viscosity of crude oil-water emulsion, prepared at water cut of 50% and at the stirring rate of 11000 r/min, was over 100 mPa?s and phase separation didnont appear after 90 days; however, the addition of chemical agents with high concentration in the simulated formation water was unfavourable for the formation of high viscosity emulsion , and viscosity of emulsion was less than 100 mPa?s and water separating proportion was over 85% after 7 days, which is mainly because that the added heavy alkyl benzene sulfonate and HPAM mainly played the role of de-emulsifier.

Abstract:With maleic anhydride，lauryl alcohol and salicylic acid as raw material，p-toluenesulfonic acid as catalyst，a new foaming agent of salicylate type was synthesized. The optimum synthesis condition was obtained as follows: solvent-free condition， 1.2∶1∶1 the monomer mole ratio of maleic anhydride，lauryl alcohol and salicylic acid，3% catalyst，80℃ reaction temperature. The foaming agent solution had a low surface tension. When the mass concentration of foaming agent was 3000 mg/L，the surface tension reached 20.9 mN/m. At room temperature，the KCl resisting concentration of the foaming agent could reach 40 g/L and CaCl₂ resisting concentration was 30 g/L. It had good resistance of oil（25%）and high temperature（140℃）.

Abstract:In order to reveal the adaptability of air foam flooding to the reservoir, the influence of foam injection on oil displacement and water cut in the conditions of different permeability variation coefficient was studied. The results showed that when the injection rate changed between 0 to 0.3 PV, enhanced oil recovery rate and declined water cut increased with the increase of injection volume for any heterogeneity reservoir, and it had great influence on the change of reservoirs with medium and strong heterogeneity. When the injection rate changed between 0.35 to 0.5 PV, increasing the amount of injection almost had no effect on the enhanced oil recovery rate and declined water cut of reservoirs with weak and strong heterogeneity, while had great effect on that of strong heterogeneity reservoir. The enhanced oil recovery rate and declined water cut of reservoirs with any heterogeneity was poor with the increase of injection rate when the injection rate was between 0.5 to 0.6 PV. At the same time, the best foam injection of reservoir with weak, medium and strong heterogeneity was 0.3, 0.4 and 0.35 PV respectively, the maximum of enhanced oil recovery rate was 13%OOIP, 23%OOIP and 25%OOIP, the maximum of declined water cut was 16.7%, 29.7% and 33.1%. Foam flooding was suitable for the reservoirs with medium and strong heterogeneity.

Abstract:For CO₂ flooding at high temperature in low permeability and heterogeneous oil reservoir, there was a problem of gas channeling. In this study, a research was carried out using a CO₂ gas flooding channeling sealing agent which had excellent property of temperature and salt resistance. The dosage of acrylamide, modifier, initiator, formaldehyde, N,N'-methylenebisacrylamide and retarding agent was 4.5%, 0.2%, 0.2%, 0.25%, 0.005% and 0.8% in channeling sealing agent at 135℃. The application scope of positive ion Na⁺, Mg²⁺, Ca²⁺ was obtained as follows: Na⁺<25 g/L, Mg²⁺<15 g/L and Ca²⁺<12 g/L, indicating good salt resistance. The plugging experiment result showed that the longer of gelling time, the better of plugging ratio was. The plugging ratio could basically stabilize at 98% when the gelling time beyond 40 h. With increasing injection volume of channeling sealing agent, the plugging ratio of sand pack model improved. The plugging ratio could arrive 91.5% when the injection volume was 0.6 PV. The system had good performance of selectivity plugging which could reduce the permeability of high sand pack model by 92.5%. It also had strong ability for CO₂ flooding and in the CO₂ flooding oil displacement experiment, the oil recovery rate could be further improved by 11.2% after plugging.

Abstract:In order to solve the problem of serious gas channeling of flue gas that reducesdevelopment effectin the process of fireflood, the screening and performance evaluation on gas mobility control system in gas injection well was carried out, which provided the guarantee to improvement of gas entry profile and development effect. Using foam volume and foam half-life time as parameters, the most optimized formula at 350℃ was as follows,5 g/L Sodium alpha-olefin Sulfonate(AOS)+2 g/L sodium?dodecyl?benzene?sulfonate(SDBS)+0.5 g/L ?hydroxyethyl cellulose(HEC). The results showedtha the foam volume and the foam half-life timeof 100mL foaming solution prepared by Simulated formation water withsalinity of10902.1mg/L, was 700mL and 170 minutes, respectively. The salt-resistance resulted shows that when salinity varied from 0mg/L to 10902.1mg/L, the foam volume and the half-life time change a little,which indicated the formula system had good salt-resistance. The oil-resistance results showed that when oil saturation was greater than 10%, the parameters began to reduce sharply, which indicatedoil had sensitive impact on the formulasystem and diplayed the selectivity of foam on formation fluid.

Abstract:In order to reveal the performance characteristics of produced fluid in steam assisted gravity drainage (SAGD) production of heavy oil reservoir, the liquid samples produced during three stages of SAGD production were taken as the research objects: early stage of circulating preheating, intermediate stage of circulating preheating and the stage of full production, from Well-Block Zhong-1 in Fengcheng Field, Xinjiang Oilfield. The component, emulsion type and stability of that were studied, and the stability mechanism was discussed. The results showed that the three samples all contained high concentration of asphaltene and resin, and three liquid samples were mixed emulsions composed primarily of O/W emulsion and some W/O/W double emulsion. Besides, the water content, clay concentration and Zeta-potential of the samples decreased along with the SAGD production process. The three stages of SAGD emulsion were stable without phase separation at room temperature, appearing in the form with an oil rich and an aqueous rich phase. With an increase of stewing time, the backscattering value (15—25 mm) of early stage of circulating preheating, intermediate stage of circulating preheating and the stage of full production was increased from 9%, 21% , 9.5% to 11%, 26.5%, 10%, the internal particle size of three stages of SAGD emulsion was decreased from 18.9, 62.2, 169.1 μm to 16.5, 49.9, 165.3 μm, respectively. The average drift rate of the dispersed particles in three stages emulsion was 1.59, 1.56 and 1.55 mm/h. The stability index of full production emulsion was minimum, which indicated that it was the most stable crude. The early stage of circulating preheating emulsion was less stable. The sample during the early circulating preheating stage was stable crucially because of the diffusion double layer, while the sample during full production stage was stabilized predominantly by “asphaltenes-film”.

Abstract:The intermediate was prepared through reaction between ethanolamine and epichlorohydin in ethanol solvent; the molecular deposition film，named as TEEMD, was obtained through quaterisation reaction between the intermediate and triethylamine. The cationic degree of TEEMD, the relative viscosity and conductivity of the TEEMD solution, oil-water partition coefficient of the TEEMD and the contact angle of the TEEMD solution on different surfaces were determined. The results showed that cationic degree of the TEEMD calculated by titration was 82.1%. The relative viscosity measured at different concentrations was of 0.98, which didn't change with the addition of TEEMD. The measurements of conductivity of the TEEMD solutions at different concentrations indicated that TEEMD completely dissociate into ions in aqueous solution, the conductivity increased with the increase of TEEMD. With the increase of TEEMD concentration, the aqueous solution did not form “micelles” state. In the two phases of crude oil and water, the oil-water partition coefficient increased with the time prolonged and concentrations increased gradually, finally reached distribution equilibrium. When the TEEMD concentrations were 0.335, 0.446, 0.558, 0.669 mmol/L, respectively, the oil-water partition coefficient were 0.050, 0.099, 0.552, 0.698, respectively. Measurements of contact angle on different solid surfaces showed that the surface wettability enhanced with the increase of the TEEMD concentration.

Abstract:In order to study the influence mechanism of clay stabilizer and heavy oil viscosity reducer on the demulsification in the process of tertiary oil recovery, the influence of cationic clay stabilizer NT-1A and anionic and non-ionic compounded viscosity reducer JN-1A on the interfacial film strength of Binnan crude oil and four components demulsification was studied by means of interface expansion rheometer. The effects of NT-1A and JN-1A on the structure and morphology of asphaltene aggregation were observed by AFM. The results showed that asphaltene in crude oil had a higher modulus expansion. NT-1A promoted the formation of cross-linked aggregates of asphaltene molecules by electrostatic attraction and the size of aggregates grew from 489 nm to 665 nm. As a result, the interfacial film strength enhanced, which made the dilational modulus of crude oil increase from 3.23 mN/m to 5.93 mN/m and the dehydration rate reduce from 77.27% to 7.80%. JN-1A had stronger ability on the oil-water interface adsorption and replaced the active ingredient in crude oil. It inhibited the aggregation of asphaltene molecules on oil-water interface and the size of aggregates dropped from 489 nm to 215 nm. As a result, the interfacial film strength decreased, which made the dilational modulus reduce from 3.23 mN/m to 1.68 mN/m and the dehydration rate increase from 77.27% to 87.50%. NT-1A and JN-1A had a significant impact on the demulsification of heavy oil crude by changing the dilational modulus of asphaltene.

Abstract:Oil water two-phase flow is one of the main flow phenomena in heavy oil development process，and the accurate measurement of its viscosity matters the scientific design and reasonable administration of the whole pipeline. However，the technology nowadays cannot solve the problem conveniently and accurately. Dimethyl silicone oil，J7 crude oil and CZ27 crude oil were separatelyused as oil phase，tap water as water phase to produce oil-water immiscible systems. The rheological properties of high viscosity oil-water immiscible system was measured by adopting Anton-PaarRheolabQC coaxialrotational viscometer with its DIN 53019 cylinder. The effects of water content，type of oil phase，temperature and shear rate on rheological properties were studied through statistically analysis，and the equations were established to predict the rheological properties of oil-water immiscible system. The results showed that the high viscosity oil-water immiscible system exhibited the same rheological properties as the pure oil. The apparent viscosity developing trend could be divided into four sections according to its water cut：0～40% water cut non-affected region，40%～55%water cut linear variation region，55%～75% water cut fluctuation region and 75%～93% water cut linear variation region. Dimethyl silicone oil and it′s oil-water immiscible system showed Newtonian fluid properties， while the emulsified heavy oil and it′s oil -water immiscible system presented shear thinning behavior.

Abstract:In order to overcome the disadvantages, such as complicated testing steps, poor timeliness, high cost and so on, of the conventional starch-cadmium iodide polymer concentration detection method, a “microfiltration-nitrogen detection” method was established. Firstly, microfiltration membrane with a pore size of 0.45 μm was introduced to pre-treat produced liquid for removing interfering factors. Then, the relationship of double wavelength corrected absorbance A and polymer concentration C was detected via the potassium persulfate UV spectrophotometry method for determining the polymer concentration finally. The accuracy and repeatability were studied and a portable polymer concentration detector was produced accordingly. The experiment results showed that when the method was used for the simulative HPAM solution, the relative error was less than 1.0%. When used for the produced fluids in oilfield, the relative standard deviation was less than 2%, and the data reproducibility was better than that of starch-cadmium iodide method. The portable polymer concentration detector, which possessed the advantages of small size, light weight (about 4 kg), simple and rapid test procedure, could meet the in situ sampling and testing needs on the platform.

Abstract:The phenomena of internal phase oil droplet retraction occurred when TX550A spinning drop tensiometer was used to measure interfacial tension. The mechanism of this phenomenon that interfacial tension dropped rapidly at the early stage, then increased was analyzed, the effect of oil droplet volume on interfacial tension was investigated, and right steps were suggested. The results showed that the oil droplet retraction was associated with the solubilization effect of surfactant and Marangoni convection which existed between oil-water interface. To prevent the abnormal deformation of oil droplet which caused by horizontal movement, the rotating speed of tensiometer should be increased gradually and the tensiometer should be gently adjusted to the balance at the initial measurement stage. In the measurement process, the value of interfacial tension was more accurate when the volume of oil droplet was relatively small. The volume of internal phase oil droplet should be limited to 1—3 μL when big test tube (2500 μL) was used, while for small test tube (300 μL), the volume of that should be limited to 0.3—1 μL. The reasonable measurement method of diameter and length for four special shape oil droplets was proposed.

Abstract:The common plugging techniques at present were introduced，including confined plugging technology，plugging technology while drilling，plastic plugging technology，plugging technology with bellow pipe and gas drilling plugging technology. All kinds of plugging technology were compared and evaluated. And future research for plugging technology was proposed.