Abstract:The properties of cationic viscoelastic surfactant CTAB solution, including rheology, temperature resistance, fluid loss and gel breaking performance of matched breaker through experiments, were studied. Experimental results showed that viscosity of the system, prepared by mixing 2% CTAB with 3% additives sodium salicylate(NaSal), increased to 160 mPa·s at the shear rate of 170 s^-1, at the temperature of 25℃ and at pH value of 7. The filter loss droped greatly at the existence of a few fluid loss agent LA, composed of hydrolyzed polyacrylonitrile ammonium (NH4-HPAN) and sulfonated phenolic resin (SMP-Ⅱ). The viscosity of the gel breaking fluid was significantly reduced to 1—3 mPa·s when a gel breaker Br was added, which showed a good performance on the gel breaking. A new drilling fluid system with cationic viscoelastic surfactant CTAB as the main agent——surfactant micellar drilling fluid DIF-a (1.5%CTAB+2.0%NaSal+1.2% compound additive agent LA+0.5% xanthan gum XC) was studied. The results showed that small flow friction, good fluid loss performance as well as easier flowback after completion was generated using drilling system DIF-a when drilling in carbonate formation. Ultimately, the retention rate of the reservoir permeability could reach up to 91.41% and reservoir damage of the external fluid was greatly reduced.

Abstract:In this paper, Fe₃O₄ nanoparticles were prepared through thermal decomposition method, and the obtained Fe₃O₄ nanoparticles were characterized by FT-IR, XRD, and TEM. The dispersion stabilities of Fe₃O₄ nanoparticles in NaCl solution under ultrasonic were investigated, and their plugging properties were tested on artificial mud cake. The experimental results indicated that the optimized reactive temperature and reactive time were 200℃ and 2 h, respectively. FT-IR analysis showed that the Fe₃O₄ nanoparticles are coated by PEG. XRD analysis revealed that the Fe₃O₄ nanoparticles were in cubic phase. TEM analysis indicateed the diameter of the nanoparticle was about 9.5 nm. The dispersion stability of the Fe₃O₄ nanoparticles was good after ultrasonic treatment for 0.5 h. The artificial mud cake demonstrated that Fe₃O₄ nanoparticles possessed prominent property for inhibiting water.The filtration of 100 mL aqueous solution containing 3% nanoparticles after 7200 s was 11.3 mL under the pressure of 3.5 MPa.

Abstract:The S22/NaSal thickening diesel gelled hydrochloride acid system was prepared with cationic surfactant docosanylamidopropyl trimethyl ammonium chloride (S22) containing 22 carbon chain length as main surfactant, sodium salicylate (NaSal) as co-additive, diesel, hydrochloride acid, n-butanol and 1-octanol as main materials. The effect of dosages of S22 and NaSal on the formation of thickening and gelled diesel hydrochloride acid was investigated. When the dosage of S22 added from 0.7008 to 1.2013 g, and the dosage of 1-octanol added from 0.4887 to 0.8708 g, the acid system changed from viscous fluid to gel gradually at 50℃. When the dosage of NaSal increased from 0.0216 to 0.1515 g, the dosage of 1-octanol needed to form transparent gelling acid decreased from 0.4600 to 0.3766 g. If there was no dosage of NaSal added, the transparent gelling acid system could not formed. The results of rheological study showed that S22/NaSal thickening diesel gelled hydrochloride acid possessed shear thinning property, and exhibited hysteresis loop of viscoelastic-thixotropic fluid. Its viscosity curves could be described by non-linear co-rotational Jeffreys constitutive equation. The consumption mass of marble reacted with S22/NaSal thickening diesel gelled hydrochloride acid system was much less than that reacted with same concentration of hydrochloride acid, and the retard reaction rate of the system ranged from 83% to 98%, which showed good retard reaction performance.

Abstract:Clay anti-swelling agent, as an essential core additive for fracturing fluid system, possessed many excellent and distinctive characteristics, such as inhibition of clay swelling, preventing particle migrant and improving formation permeability. In this study, trimethylamine hydrochloride was synthesized by using raw material concentrated hydrochloric acid and trimethylamine, then under weakly alkaline condition, the product was modified by epichlorohydrin to get organic cationic polymer, furthermore, compound with inorganic salt ammonium chloride at 60℃ to get yellowish clay anti-swelling agent. The clay anti-swelling agent was characterized by infrared spectrum, thermal weight/differential thermal analysis and X-ray diffraction. And the influence of dosage of raw material and anti-swelling agent on the anti-swelling effect was studied. The results showed that anti-swelling ratio increased with increasing amount of organic cationic polymer. The optimum dosage of organic cationic polymer was 0.9%. When the amount of organic cationic polymer was same, the anti-swelling ratio increased with increasing mass ratio between epichlorohydrin and trimethylamine hydrochloride. When the mass ratio between them was 2:1, the anti-swelling ratio of polymer with dosage of 0.35%, 0.6% and 0.9% was 85.87%, 87.07% and 89.58%, respectively. When the working concentration was 0.4% and 0.8%, the anti-swelling ratio of clay anti-swelling agent reached 90% and 94.1%, respectively, which showed good anti-swelling effect.

Abstract:After gel-breaking, the residue is the main causes of damaging the conductivity of proppant bed deposition and the permeability of matrix. In order to research the damage characteristics and reduce the formation damage, in the study, the performance of the gel-breaking fluids of two kinds of guar-gum fracturing fluids at different dosages of gel breaker was investigated and the molecular weight of guar-gum after gel-breaking was analyzed by combining with the measurement of the viscosity of the gel-breaking fluids. The molecular size during the gel-breaking process was measured using a laser particle size analyzer and the residue content measured by centrifugating the gel-breaking fluids. Finally, the reservoir damage of different types of fracturing fluid was evaluated by the core flow experiment. The results showed that when the gel-breaking time was too long, the liquid molecular size would be bigger, and the flocculation phenomena would appear, which would cause more damage; meanwhile, the view that the smaller the viscosity of the gel-breaking fluids, the smaller molecular size, the smaller the damage to the reservoir was not comprehensive, and existed some limitations.

Abstract:A novel betaine surfactant fracturing fluid (BVES-80) was developed. The optimum formula of BVES-80 clean fracturing fluid was obtained as follows: 2.5% betaine surfactant DBA2-12, 4.0% KCl, 0.5% sodium salicylate, 1.0% isopropanol and water. The results of performance evaluation showed that when the dosage of NaCl, CaCl₂ and MgCl₂ was 3%，the viscosity of fracturing fluid was 337, 370 and 394 mPa·s, respectively, indicating good resistance to salt. The viscosity of fracturing fluid (321 mPa·s) did not change significantly after standing for 7 d, indicating good stability. Under the condition of 170 s^-1 shear rate and 60℃ or 80℃ temperature, the viscosity of fracturing fluid was 50 mPa·s or 30 mPa·s respectively after continuous shearing for 1 h, showing good temperature and shearing resistance at medium and low temperature. Under the condition of 30℃ and 0.01—10 Hz oscillator frequence, the storage modulus G′ of fracturing fluid was always larger than the loss modulus G″ with G′ more than 10 Pa and G″ more than 0.3 Pa, suggesting good viscoelasticity. The falling rate of ceramsite in BVES-80 clear fracturing fluid at 60℃ was 0.14 mm/s, which was much less than that of 0.5% guanidine?gum?fracturing?fluid with 1.50 mm/s, showing good sand-carrying capacity. Within 12 h and at 30℃, the clear fracturing fluid could completely break when mixed with paraffin. The viscosity of gel breaking fluid was less than 5 mPa·s, the residue was 23.46—54.37 mg/L, the surface tension of gel breaking fluid was 26.3—27.5 mN/m and the interfacial tension between gel breaking fluid and paraffin was 0.55—0.62 mN/m. The filtration coefficient was 4.75×10-4 m/min^0.5 at 80℃ and the damage rate was only 7.4% for core permeability. BVES-80 clear fracturing fluid was suitable for the reservoir reform of medium and low temperature and low permeability formation below 80℃.

Abstract:In view of existed problem of plant gum fracturing fluid, a new kind of low concentration synthetic polymer fracturing fluid system for middle-high reservoir was developed. The fracturing fluid system included 0.35%—0.6% anionic synthetic polymer SKY-C100A, which was free of water?insoluble?substance, 0.5%—0.7% crosslinked fluid composed of cross linking agent SKY-J100B and cross linking regulator SKY-Y100C, 0.3% clay stabilizer LYC-1, 0.6% cleanup additive ZL-1 and 0.5% demulsifier KCB-1. The cross linking time of fracturing system was adjustable from 20 to 180 s. The results showed that the fracturing gel had good shear resistance and heat-resistant. Under the condition of 80—100℃, SKY-C100A dosage of 0.35%, shearing 120 min at 170 s^-1 (including 2 min high shearing at 1000 s^-1), the viscosity of fracturing gel was still kept from 77 to 220 mPa·s; that kept about 220 mPa·s with 0.45% SKY-C100A and 120℃; that maintained about 83 mPa·s with 0.5% SKY-C100A and 140℃. Under the static gel breaking condition of 80℃, the residue content in gel-broken fluid was 30 mg/L within 2 h. At 80—120℃, the filtration coefficient was 1.13×10-4—3.62×10-4 m/min^0.5, and the damage rate to artificial core matrix was only 8.3%. Comparing with plant gum fracturing fluid, the new fracturing system did not require other pH regulator and bactericides.

Abstract:The pale yellow gelling agent dialkyl phosphate ester was synthesized with triethyl phosphate, phosphorus pentoxide, and three alcohols as basic materials. The basic properties (proppant carrying capacity, temperature and shear resistance) and rheological properties (viscoelasticity, thixotropy, shear thinning) of the gel systems based on four kinds of hydrocarbons (n-hexane, octane, kerosene and diesel) instead of water were investigated for the first time. The results showed that the viscosity of diesel based gel was 177.26 mPa·s under proper conditions, such as 100:1.0 optimum crosslinking ratio, 1% gelling agent with iron complex as crosslinking agent. Four hours later, the descending distance of ceramsite was 8.0, 5.0, 4.5 and 8.0 mm in n-hexane, octane, kerosene and diesel based gel, respectively. At 100℃, the four fracturing fluids were sheared at 170 s^-1 for 1.5 h, the reserved viscosity was 16.9, 229.5, 293.6 and 324.3 mPa·s for n-hexane, octane, kerosene and diesel based gel, respectively. The shear resistance and heat resistance of fracturing fluids intensified, and the elasticity modulus and the area of thixotropic loop decreased gradually with the growth of carbon chain of base fluid. Four gel systems possessed shear thinning property after shearing. At the same shear rate, the viscosity of each gel system decreased relatively with increasing carbon chain of base fluid. Non-linear co-rotational Jeffreys model could be applied to describe the flow curve of gel systems based on different hydrocarbons correctly and the calculated value was in good agreement with the experiment date.

Abstract:In order to explore the chemical plugging agent (CPA) which was suitable for snubbing service of water injection wells, environment factors and their own requirements of CPA were analyzed theoretically. Then, the design of CPA was put forward and the evaluation of the designed CPA was carried out through laboratory experiment. The results indicated that the applicable time of CPA, containing epoxy resin E-44, reactive diluent 660A and Density regulator at the mass ratio of 100:5:210, fell fast as the amount of curing agent or the temperature increased, especially in the condition of the higher temperature. The CPA was more suitable for the snubbing service of water injection well with larger temperature gradient when the temperature in bottom of well was between 50℃and 70℃. When the adding amount of curing agent was of 10% and the length of CPA was 3.0 m, the applicable time of CPA could reach 4.7 h (25℃) and the maximum of bearing strength almost reached 26.5 MPa.

Abstract:The combination process of the “Oxidation-Flocculation- Filtration” was used for the treatment of fracturing fluid flowback (FFF) from the continental shale gas well. The effects of chemical agents on the treatment were discussed in detail, and the optimum experimental condition was determined. The experimental results showed that when the FFF was oxidized by 1 g/L Oxidation agent OD-H for 5 min, flocculated by 60 mg/L Flocculation agent IF-L and 2 mg/L coagulant aid OF-Y for 20 min, and filtrated subsequently, the effluent water quality met the requirement of confecting fracturing fluid water. the suspended solids of the effluent water was lower than 4.0 mg/L, bacterial content was lower than n×10个/mL, dynamic viscosity was lower than 1.2 mPa·s and ΣFe content was lower than 0.2 mg/L.

Abstract:Water-soluble crosslinked polymer microspheres were prepared by dispersion polymerization in ammonium sulfate solution (AS), polymerized by acrylamide (AM), 2-acrylamide-2-methyl propane sulfonic acid (AMPS) and sodium acrylate (SAA). The optimum synthesis condition was obtained as follows: dispersion stabilizer of polyvinylpyrrolidone K60 with 350000 molecular weight, 0.5%~0.75% mole ratio of crosslinking agent to main monomers, 15:2:3 monomer mole ratio of AM/SAA/AMPS, and 14.5% AS. The results showed that the crosslinked polymer microsphere had a morphology of regular and homogeneous spheric and particle size of 1—3 μm in powder but 8—10 μm in slaking dispersed system. The crosslinked polymer microsphere dispersed system had the characteristics of shear resistance, heat resistance and salt tolerance. At 30℃, with increasing shear rate, the viscosity of crosslinked polymer microsphere dispersed system (400 mg/kg) decreased, which was 9.3 Pa·s at 100 r/min. The viscosity retention rate of dispersed system decreased from 100% to 53.58% when temperature increased from 30℃ to 90℃. And that decreased from 98.13% to 53.74% when the salinity increased from 0 to 10 g/L. Plugging experiment results indicated that the crosslinked polymer microspheres had a favorable property of plugging, deformability and effect of deep profile control step by step. At 25℃, the plugging time of microporous membrane increased with the growth of swelling number of days which was 8.2 h after 4 days. At 75℃, the blocking time of microporous membrane reduced with the growth of swelling number of days which was 3 h after 3 days. With increasing concentration of polymer microspheres, the initial injection pressure of core reduced. The optimum injection concentration was 400 mg/L in artificial core with permeability of 0.5 μm².

Abstract:In view of the problem that plugging agent leaks easily along the crack formation during water plugging construction at the low permeable fractured reservoir, the compound plugging agent technology was put forward. The polyamidoamine dendrimers /organic phenolic aldehyde crosslinking system were selected, and the performance of the pre-crosslinked particlesc was studied. The results showed that, the strength of gel system, consisted of 2000 mg/L polymer, 1500 mg/L hexamine, 250 mg/L resorcinol, 1600 mg/L oxalic acid, 180 mg/L thiourea and 200 mg/L cobalt dichloride, was up to 21600 mPa?s and the settling time was of 103 days. The expansion rate of the pre-crosslinked particles reached 15.7 times in the formation water, performing good salt tolerance. 0.3 PV composite plugging agent, composed of 0.05 PV pre-crosslinked particles with the concentration of 2000 mg/L, 0.2 PV polymer gel system with the concentration of 2000 mg/L and 0.05 PV polymer gel system with the concentration of 4000 mg/L, was injected into artificial cracked core, the plugging rate being of above 97.25%, breakthrough pressure gradient being up to 13.68MPa/m, indicating that the composite plugging agent had a good ability to adjust production profile. After the site construction, the total water content of construction well decreased by 10.5%, and good water plugging effect was obtained.

Abstract:The water injection development mode which blended clean water and sewage during reinjection process was widely used in early exploitation stage of offshore oilfield. The clean water and the sewage were produced from Guantao formation and Minghua Town formation in BZ28-2 south oilfield. The salinity of that was 8514.7 and 6605.7 mg/L, and the water type of that was CaCl₂ and NaHCO₃, respectively. Taking BZ28-2 south oilfield as an example, we utilized parameters including formation mineral sensitivity analysis, sensitivity experiments, compatibility experiments of sewage and clean water, indoor core flooding and platforms water quality study to comprehensively analyze formation damage mechanism of the oilfield during water injection; and aiming at the characteristics pertaining to offshore oilfield water injection, we established a set of evaluation method with reference to formation damage mechanism associated with water flooding. Studies showed that the water injection effect of BZ28-2 south oilfield was primarily affected by higher intensity of water injection that caused velocity sensitivity damage. The results from static compatibility evaluation showed that the total amount of scale in regard to clean water was 27.0—70.5 mg/L at 80℃. The total amount of scale in average decreased from 70.5 mg/L to 18.3 mg/L when the temperature decreased from 80℃ to 60℃, which indicated that the clean water had a better scaling ability. When clean water blended with formation water with different volume fraction, the content of suspension scale and settlement scale as well as total amount of scale increased first and then decreased with increasing volume faction of formation water, and the peaks occured where volume fraction was 1:1. The dominant component of suspension scale and settlement scale was CaCO₃. It could be discovered from the results referred to dynamic compatibility evaluation that the damage rate of permeability caused by clean water to the core was 41.11%—89.36%. The clean water injected into formation was incompatible with formation fluid, which made the flow channels be blocked by calcium scaling and consequently the reservoir had difficulty in water injection. Meanwhile, the key factor that the current water injection hadn’t reached requirements was attributed to the platform shorter sewage treatment time as well as larger processing capacity, which had the oil content failed to reach the standard. Specific measures proposed to prevent formation damage, as a result, the absorbing capacity of water injection wells improved and the balance of injection and production in oilfield was ensured.

Abstract:Jilin oil field reservoir has the characteristics of poor physical property, great permeability contrast and fracture development, so gas channeling take place easily, which can seriously affect the gas flooding efficiency. To solve the problem, a CO₂ foam system was developed to expand the gas flooding swept volume, as well as to improve gas flooding efficiency. A performance method for foam system evaluations was established in the lab, the optimum CYL foam system was chosen, composed of anionic surfactant and nonionic surfactant，and the CYL optimum dosage of 0.3% and the gas-liquid ratio of 1:1 was determined. The physical simulated tests showed that in cores with fracture development and low permeability, the oil recovery ratio (ORR)could be achieved the best of 53.67% by CO₂ foam flooding, and the ORR of the CO₂ gas flooding toke second place(35.74%), while the ORR of the water flooding was the lowest(23.42%). It was sure that the effect of CO₂ foam flooding was obviously better than that of water flooding and CO₂ gas flooding. In the field application, CO₂ foam flooding test made the gas injection pressure increase from 6.0 MPa to 8.1 MPa , as well as the daily oil production of a well group increase from 7.7 m³ to 10.8 m³. The result of the CO₂ foam flooding was obvious, and the gas flooding development was improved effectively.

Abstract:The anionic foaming agent ZY with 30% effective content was provided by production engineering and technology institute in Zhongyuan oilfield. When the best dosage of ZY was 0.5%, the foam volume was 400 mL, foam half-life was 540 s, foam composite index was 216 L·s, and the viscosity of foam was 1210 mPa·s. The core flooding experiment result showed that the seepage rate had an important influence on the characteristics of ZY in porous media. The smallest line speed to make ZY foam in porous media was 0.3 m/d. When the line speed increased from 0.3 to 1 m/d, the resistance coefficient in average (the whole sand filling tube) of foam system increased from 14 to 64. The average resistance coefficient was about 70 when the line speed was above 1 m/d which indicated that the seepage rate had less effect to foam plugging capacity. The plugging capacity of foam in front-end of filling sand tube was bigger than that in back-end. Foam continuously generated and decay when it transported in porous media, and the blistering speed was always less than defoaming speed until the foam completely disappeared.

Abstract:The viscous jelly ,which exist in the filter and pipe wall of polymer injection allocation system, is the product of microbial populations of the Injection water in the system. It will not only clog up the near wellbore area reservoir pore ,but also change polymer solution properties after contacting with the polymer solution,even will affect the development effect of polymer flooding. The Xingshugang oil field polymer injection allocation system spawned jelly was collected, sheared and combined with polymer solution. The research on jelly’s impact on properties of the polymer solution and polymer flooding development effect was carried out by physical simulation method. The results showed that, after being added to the polymer solution ,the jelly resulted in the defect of the reticular polymer molecule aggregation and the part of the molecular chain breaking, thereby caused the decrease of polymer solution viscosity and poor viscoelasticity. Compared with the high molecular weight polymer solution, the flow resistance of the polymer solution with jelly was large and transmission and migration ability was poor in the porous medium. With the injection volume of the jelly increasing, the polymer flooding recovery first inceased then decreased. Therefore, the jelly had an influence on polymer flooding development effect, and a small amount of jelly would help to improve polymer flooding effect. With heterogeneity of the reservoir and the average penetration rate increaseing, the influence of jelly on polymer flooding development effect dereased.

Abstract:Compared with onshore oilfield, the platform space of offshore oilfiled is limited，which require higher demands for polymer injection device process and dissolution time. According to the actual demands of offshore oilfields, the performance evaluation of "soluble instant" polymer solution and Cr³⁺ polymer gel was carried out under the LD10-1 oilfield geological and fluid conditions from aspects of production solubility, viscosity, rheology, viscoelasticity, molecular clew dimension, and flow characteristics. The results showed that "soluble instant" polymer was better in solubility than "high molar mass" polymer, and possessed excellent viscosity, rheology and viscoelasticity properties under the Bohai main oilfield conditions. Compared with the "linear branched" structure of polymer configuration, polymer molecules in Cr³⁺ polymer gel mainly aggregate with a "local reticular" structure which was less flexible and more rigid, making the flow resistance be enlarged. In the succeeding water-flooding, the dilution effect of injection water leaded to the molecular clew dimension of Cr³⁺ polymer gel detained in core pore increase and the increment of flow resistance was larger than the decrement caused by the outflow of polymer retained in pore core, which made the higher injection pressure of Cr³⁺ polymer gel and the residual resistance coefficient larger than the resistance coefficient, showing peculiar permeability characteristics from common polymer solution.

Abstract:N-(3-18 alkoxy 2-hydroxypropyl)-N, N-dimethyl betaine, named as JHD-18, was synthesized by using octadecanol，epichlorohydrin and dimethylamine as raw materials. Surface activity of JHD-18 and complex of JHD-18 with OP-10 were studied. The results showed that the critical micelle concentration ccmc of JHD-18 was 500 mg/L and the critical surface tension gcmc was 28.94 mN/m at the temperature of 25℃； while the ccmc and gcmc of the complex of JHD-18 with OP-10 in molar ratio of 3:7 was 450 mg/L and 20.47 mN/m, respectively, and could make the oil-water interfacial tension decrease to be ultra-low order of magnitude(10^-3 mN/m). In addition, the complex system have good compatibility with formation water and strong salt resistance, when the concentrations of Ca²⁺ was up to 16000 mg/L, the interface tension between the system and the crude oil could still be ultra-low (10^-3 mN/m). The results of the displacement experiments using the cores with different permeabilty (0.32×10-3~3.14×10-3 μm²)showed that based on the water flooding(42.78%),the oil displacement efficiency can be increased by 15.72% after injecting 0.3 PV of the complex system of JHD-18 with OP-10 in molar ratio of 3:7 with the contentration of 1500 mg/L.

Abstract:We evaluated dilute Gemini surfactant (0.2%) formulation for oil recovery in sandstone cores under high salinity, the effect of Gemini surfactant structure and its formula on enhanced oil recovery efficiency was studied. Sandstone core was saturated with imbibition by formation water and crude oil in turn, and then was measured in surfactant solution. The results showed that cationic Gemini surfactant 12-3-12 had no effect, the oil recovery of anionic Gemini surfactant AAAS, compounded system of anionic Gemini surfactant 12-2-12 and amphoteric surfactant C14AB, compounded system of AAAS and sodium laurite sulfate AES, compounded system of TW-60 and AES was 37.27%, 38.80%, 53.95% and 60.20%, respectively. Due to the instability of ester bond in TW-60 surfactant, the compounded system of AAAS and AES was used as basic formula. The imbibition recovery of the formula added alkaline (sodium metaborate) was 59.85%, which was higher than that of formula without alkaline by 20.17%. Indoor one-dimensional homogeneous core flood experiment result showed that anionic Gemini surfactant formulation had improved 29.8% oil recovery more than water flooding.

Abstract:On account of the characteristics of high-temperature, high-salinity and high hardness of homogeneous section of Tazhong 402CIII reservoir, betaine surfactant BS-12 and its applicable concentration were optimized. The performance of emulsification, adsorption and oil displacement was also evaluated. The results showed that under the reservoir condition (110℃, 11.52×10⁴ mg/L salinity, 7654 mg/L Ca²⁺ and Mg²⁺), BS-12 solution had a good compatibility with formation water. The oil-water interfacial tension (IFT) was as low as 1.5×10^-2—5.2×10^-2 mN/m with BS-12 concentration ranging from 0.03% to 0.05%. The IFT maintained by 2 orders of magnitude after aging for 30 days at 110℃，which indicated good thermostability. The emulsion formed by 0.03% and 0.05% BS-12 solution and crude oil was stable after 12 h, and the water separation rate of surfactant systems was 69% and 50%, respectively. The droplets of emulsion showed a sparse distribution and its diameter ranged from 0.3 to 1.0 μm. The adsorption capacity on the surface of oil sands was tested with 20:1 mass ratio of liquid to solid. The static adsorption was 6.592 mg/g. The dynamic adsorption was 4.938 mg/g and its retention was 1.411 mg/g. Finally, core displacement experiment results showed that the oil recovery increment was 4.14% after injecting 0.3 PV 0.2% BS-12 surfactant.

Abstract:Based on the chemical-displacing technology in low-permeability oilfield，the surface/interfacial activity ，emulsifing ability and displacing efficiency of a gemini surfactant oil-displacing agent YC- 2 were investigated. The results showed that when the concentration of YC-2 was of 3000mg/L，the surface tension of YC- 2 solution was around 30mN/m，and the interface tension between YC-2 solution and the crude oil could reached the ultra-low order magnitude（~10^-3 mN/m）. The YC-2 solution had strong salt resistance to NaCl and CaCl₂. Moreover ，the YC-2 solution/crude oil emulsion exudated water quickly ，which was favorable for the disemulsion of the produced fluid. The oil displacement experiment showed that oil-displacing agent YC- 2 solution with the concentration of 3000mg/L could enhance the oil displacement efficiency of the core of Kg 0.3541× 10-3μm² over 15% based on the water flooding（50%）. With the increase of the permeabililty of the core ，the displacing efficiency of the YC- 2 solution reduced ， indicating that the YC- 2 was suitable for the low permeability reservoir. The surfactant YC- 2 had been applied in Qinghuabian ，Wayaobao，Qingpinchuan oilfield factory of Yanchang Oilfield，and remarkable displacement efficiency had been obtained.

Abstract:The possibility of the application of active polymer APA-1 after binary compound flooding was probed by measurement of the interfacial tension, emulsifying ability, anti-shear ability, viscoelasticity and oil-displacement capacity of the active polymer APA-1. The results showed that the active polymer possessed more outstanding oil solubility and emulsifying ability, had better thickening behavior and stronger resistance to calcium and magnesium ions than that of the ordinary polymer BH with high molecular weight (25 million). After placed for 30 days, the viscosity of active polymer solution with the concentration of 1000 mg/L was up to 220 mPa·s. When calcium and magnesium ion content was of 190 mg/L, the viscosity of active polymer solution with the concentration of 1500 mg/L was of 80 mPa·s. After placed for 6 hours, the emulsion system obtained by mixing active polymer solution of the concentration of 1000~1200 mg/L and the crude oil was stable and without delamination. Hence, the active polymer emulsion system might be superior to the simple polymer system and binary system. The core displacement experiment showed that, compared with the binary flooding oil displacement system, active polymer flooding system had more significant late course emulsification characteristics. After binary compound flooding, the oil recovery could be further enhanced by 5%—10% by the active polymer solution.

Abstract:The efficiency of enhanced heavy oil recovery by applying sodium fatty alcohol polyoxyethylene ether sulfate（AES ）and hydrophobically associating polyacrylamide（APP 5）composite system was investigated using physical model displacement test.The results were compared with that of AES/partially hydrolyzed polyacrylamide（SNF ）system. It was found that ，under the condition of 1.2 g/L SNF，1.2 g/L APP5，2.0 g/L AES and50℃，the final recovery efficiency of simulated formation water ，SNF ，APP 5，SNF/AES and APP 5/AES was 50.1% ，60.0% ，61.2% ，64.9% and70.7% ，respectively. The heavy oil recovery efficiency of APP 5/AES was the highest. The ultra-low interfacial tension could not be obtained when AES system mixed with heavy oil. The lowest interfacial tension of APP5/AES and SNF/AES was not improved after adding 0.1 g/L APP5 and SNF with 1.40and 1.43mN/m，respectively. The viscosity of composite system was higher than that of single polymer system with AES dosage of 2.0 g/L，and the viscosity of APP5/AES was the highest. At 50℃and 7.34s^-1，the viscosity of 1.6 g/L APP5 and 2.0 g/L AES composite system was 32.42mPa? s. The mechanism of enhanced heavy oil recovery was analyzed in terms of interfacial tension and viscosity. Compared with the Van der Waals interaction ，the hydrophobic effect played a more important role in enhancing the viscosity of APP 5/AES system. APP 5/AES enhanced oil recovery mainly by increasing the viscosity of composite system and reducing oil-water mobility ratio，rather than reducing the interfacial tension.

Abstract:The performance of displacing agent would get worse when it flew deep into the reservoir during ASP flooding，as thephysical and chemical reaction between alkaline （A），surfactant （S），polymer（P），reservoir rock and crude oil led to the loss ofagent. The test on the content of alkali ，surfactant and polymer in aqueous phase ，after the reaction between ASP and crude oil from the 1th ，4th and 6th factory of Daqing oilfield ，was carried out. The results indicated that only alkaline and surfactant could react with crude oil，and the distribution coefficient of surfactant was 0.2—0.3. Furthermore the dissolution of surfactant in oil phase was reversible. 20% —30% surfactant in oil phase would transfer into aqueous phase after water washing. The distribution coefficient of surfactant and alkali in oil phase was larger in the 6th factory than that in the 1th and 4th factory. Compared with the 1th and 4th factory ，the main carbon in the 6th factory was C23with higher content of heavy component and wider distribution of carbon chain，which resulted in more likely dissolution of surfactant in oil phase. The distribution coefficient of surfactant in oil phase increased with increasing oil-water ratio and stirring time. Under the condition of same stirring time ，the system was arranged according tothe distribution coefficient of surfactant in crude oil in following order: A/S system，surfactant solution ，A/S/P system and S/P system.

Abstract:The influential factors and economic effect of the oil recovery after alkali/surfactant/polymer (ASP) flooding with high polymer concentration were analyzed in this paper. The results showed that under the same displacement agent cost, the recovery efficiency increment of 0.12% high molecular mass polymer flooding, 0.3% nonionic surfactant/0.25% ultra high molecular mass polymer flooding and 1.2% alkali/0.3% sulfonate/0.25% ultra high molecular mass polymer flooding was 19.6%, 15.9% and 13.7% respectively. Under the same viscosity of ASP flooding system, the interfacial tension of the solution decreased from 8.10×10^-1 to 5.73×10^-3 mN/m, and the recovery efficiency increment increased from 23.4% to 27.7%. When the viscosity of ASP system increased from 36.8 to 134.4 mPa·s, the recovery efficiency increment increased from 18.5% to 32.9%. The recovery efficiency increment increased from 15.6% to 30.7% when the plug size increased from 0.095 to 0.475 PV, whose increment difference gradually decreased. In the situation of same chemicals cost, the recovery efficiency increment (33.8%) was higher with the slug combination: polymer solution pre-slug + principal ASP slug + vice ASP slug + polymer solution protect slug. The recommended polymer concentration in ASP system was range from 0.2% to 0.25%, and the recommended slug size was range from 0.380 to 0.475 PV when technical and economic benefits were considered in Daqing Lamadian oilfield. For highly heterogeneous reservoir, the influence of swept volume on oil recovery was more obvious than that of displacement efficiency.

Abstract:Reservoir mineral component of Sazhong Block in Daqing Oilfield include kaolinite，illite ，chlorite，feldspar and quartz，the static alkali consumption experiment of five minerals in the ASP ternary complex system and single sodium hydroxide solution were studied. The alkali consumption rule of the five minerals in the ASP ternary complex system and in single sodium hydroxide solution were put forward and analyzed ，respectively. The research showed that polymer and surfactant had inhibitory effect on the reservoir mineral alkali consumption. The reservoir mineral alkali consumption in the ASP ternary complex system reduced obviously compared to that in the single sodium hydroxide solution. In single sodium hydroxide solution ，the alkali consumption of skeletal mineral and clay mineral were mainly in chemical reaction alkali way；however，the alkali consumption of clay in the ASP ternary complex system was mainly in physical adsorption alkali way ，and skeletal mineral alkali consumption was mainly in chemical reaction alkali way.

Abstract:The two crude oil components, resins and asphaltenes, were separated from shengli Bo61 crude oil, and the interfacial tension and dilational rheological properties between two crude oil components and ethanolamine solutions were investigated at the kerosene-water interface by means of oscillating drop method. The experimental results showed that the mixed adsorption film of the fatty acid and its soap was?formed by reaction?between the fatty acid in resins and ethanolamine, which?was?beneficial to reduce the interfacial tension and ?had little effect on the interfacial dilational modulus. The reaction between asphaltenes and ethanolamine promoted the adsorption of aromatic acid, which resulted in decreasing interfacial tension and increasing film strength. However, the viscosity of interfacial film increased and film strength decreased with the further increase of ethanolamine concentration due to the enhancement of the diffusion-exchange process of aromatic soap between the interfacial film and the bulk.

Abstract:Through the observation of static experiment and dynamic core flow experiment, we inspected the dispersion of coal powder in different surfactant solvents, and the critical flow velocity and velocity sensitive index after the coal contacted with different surfactant. The cationic surfactant was octadecyl trimethyl ammonium chloride (1831), the anionic surfactants were ten alkyl diphenyl ether disulfonic acid sodium (Dowfax 3 B2), sodium dodecyl sulfate and sulfonated fatty acid methyl ester sodium salt (MES). The static experiment results showed that coal powder dispersed weak in formation water, but dispersed easier in surfactant solution. The dispersion of anionic surfactant was better than that of cationic surfactant. Using experiment facility of core fluxion, indoor experiment of compacted coal powder was carried out. The experiment results showed that the critical flow rate was 0.25 mL/min without surfactant and the velocity sensitive index was 0.45. After adding 0.5% Dowfax 3B2, MES and 1831, the critical flow velocity was 0.25, 0.25, and 0.5 mL/min, the velocity sensitive index was 0.58, 0.60 and 0.48, respectively. After adding 1% Dowfax 3B2 and 1831, the critical flow velocity was 0.1 and 0.5 mL/min, the velocity sensitive index was 0.57 and 0.48, respectively. The damage of anionic surfactant on the core was greater than that of cationic surfactant.

Abstract:The simulated produced fluid (10%—50% water ratio) for polymer-surfactant flooding of north third region in Changqing oilfield was prepared, containing 1000 mg/L polyacrylamide and 1667 mg/L betaine surfactant. The demulsification experiment of simulated produced fluid (30% water ratio) was carried out under the condition of 55℃ dehydration temperature, 100 mg/L demulsifier and 40 min dehydration time. The water-soluble sulfonate demulsifier KL-9, KL-10 and KL-14 were screened from 28 kinds of demulsifier, showing better demulsification effect. When the dosage of demulsifier was 50 mg/L, the dewatering rate of KL-14 was 92.6%, 97.8% and 99.9% under dehydration temperature 40℃, 45℃ and 50℃, respectively, greater than that of KL-9, KL-10. The demulsification effect of KL-14 was the best. The similar results were obtained from simulated produced fluid with 10% and 50% water ratio. Therefore, it was concluded that KL-14 was the best demulsifier for the simulated produced fluid with 10%—50% water ratio. The dehydration rate increased under same demulsifier dosage, with increasing demulsification temperature. The dehydration rate of KL-14 increased under same dehydration temperature, with increasing demulsifier dosage. With extending dehydration time, the dehydration rate increased and turned to be stable gradually. The optimum demulsification condition was obtained as follows: 50—55℃ dehydration temperature, 100 mg/L demulsifier, 30 min dehydration time.

Abstract:According to the problems of high viscosity, poor liquidity and difficulties in exploitation and transportation of Henan extra-heavy oil, the research on reducing viscosity of extra-heavy oil in Henan oilfield by emulsifying was carried out. The optimized composite reducing viscosity agent F2 comprised main agent RA-1, stabilizer ?polyacrylamide and additive alkali at the mass ratio of 1:0.25:0.36. When the dosage of the F2 was 0.483% in the emulsion and the oil to water mass ratio was 7:3, the stable O/W emulsion was obtained at the temperature of 70℃. At the temperature of 50℃, after emulsified, the viscosity of the extra-heavy oil (240 Pa·s) could reduce to 42.8 mPa·s(50℃), and the viscosity reducing rate was up to 99.98%. In addition, the mechanism of viscosity reduction by emulsifying was studied.

Abstract:Jinzhou9-3 oilfield lacked a simple and accurate quantitative detection method for the produced surfactant in binary system flooding. The chromogenic agent of NH₄Co(SCN)₃ could react with anion/non-ion surfactant HDS to form a blue compound，whose color depth was linear with the concentration of HDS. Therefore，the concentration of HDS in produced water could be determined by spectrophotometry method. The detection method was optimized by laboratory experiments and the optimum testing condition was obtained as follows: testing wavelength of 322 nm，the chromogenic agent solution containing 620g NH₄SCN and 280 g Co （NO₃）₂· 6H₂O，benzene dosage of 15mL in extractant，reaction time of 25min，holding time of 60min，running speed centrifuge of 2000r/min and centrifugal separation time of 20min. The results showed that the fitted equation of standard curve could be described as y=0.0011 x，and the correlation coefficient（R² ）of standard curve was 0.9973，indicating good dependency ，and the relative deviation of absolute value was less than 5%. The optimum test method had an expectation to use for the quick determination of surfactant in compound flooding of offshore oilfield.

Abstract:To determine the concentration of calcium and magnesium ions in polymer solution, the acid chrome blue K(ACBK) -naphthol green B(NGB) mixed indicator K-B was used as chromogenic reagent. In partially hydrolyzed polyacrylamide (HPAM) solution, the influencing factors on the concentration of calcium and magnesium ions were investigated by using 722 UV-Vis spectrophotometer. The results showed that the optimal measurement condition was as follows, the wavelength was 472 nm, the mass ratio of the ACBK to NGB was 1:2, the volume ratio among the mixed solution containing both Ca²⁺ and Mg²⁺, indicator K-B solution and NH₃-NH₄Cl buffer solution with pH value of 10 was 1:3:8, the total concentration of Ca²⁺ and Mg²⁺ was in the range of 0 to 32 mg/L. The obtained standard curve obeyed the Lambert-Beer law, and the linear regression equation between concentration and absorbance, A=0.30124+0.01001c_m, was obtained, whose average error was less than ±0.9%.

Abstract:The flow behaviors of polymer aqueous solutions containing the insoluble gel were analyzed during going through the porous membranes. The flow curve analytical method was founded and the parameter of the insoluble gel content in polymer aqueous solution was used as an effective evaluation method to the solubility and the homogeneity of the polymer solution. Contrast to the existing method, the method was more efficient and more suitable, furthermore, the result via this method only depend on the homogeneity of the solution and the pore size of the porous membrane, the other factors in the test was unrelated. As for the polyacrylamide which was widely used in enhanced oil recovery, the method could provide the value of the polymer insoluble gel content efficiently. The relation curve of filter factor and insoluble gel content were also found by the calculation, and it was found that while the filter factor of PAM was 1.5, the insoluble gel content of PAM was approximately 0.4%.

Abstract:Polymer molecular weight associated with the permeability was the key factor affecting polymer flooding in EOR of low permeability reservoirs. The determination method of polymer molecular weight for low permeability reservoirs at home and abroad was reviewed in this article. When polymer molecular weight associated with permeability was chosen，factors should be considered such as polymer injectivity，inaccessible pore volume and reservoir geological conditions ，etc. The enhancement of polymer only in oil recovery was low ，and combination with other chemicals was recommended.