Abstract:In order to overcome the shortcomings of polyacrylamide power chemicals, two kinds of emulsion polymers P(AM/KAA/C4A) and P(AM/KAA/C6A) were synthesized by emulsion polymerization with acrylamide, acrylic acid, dimethylaminoethyl methacrylate, 1-bromobutane or 1-bromine hexane as raw materials. Laboratory experiment results showed that the performance of two polymers was quite similar. The dissolution time of homemade emulsion polymer was less than 5 min. It was more suitable to use P(AM/KAA/C4A) as additional agent due to the less cost than P(AM/KAA/C6A). After adding 0.6% P(AM/KAA/C4A) to the fresh water mud, the value of apparent viscosity (AV), plastic viscosity (PV), yield point (YP) and filtration quantity (FL) was 30.5 mPa·s, 18.5 mPa·s,12.0 Pa and 12.2 mL. After ageing 16 h on the condition of 150℃, the value of AV, PV, YP and FL was 25.5 mPa·s, 17.0 mPa·s, 8.5 Pa and 14.2 mL, respectively. The mud could resist saturated salt solution after adding 0.6% P(AM/KAA/C4A). The contrast experiment result showed that the performance in temperature and salt tolerance of homemade emulsion polymer was better than that of Daqing and Hebei emulsion polymers. When 0.6% homemade emulsion polymer was added to the compound salt mud, the value of AV, PV and FL was 14.0 mPa·s, 8.0 mPa·s and 43 mL after aging 16 h at 150℃, which showed that the homemade emulsion polymers could be used as a drilling fluid additive.

Abstract:Spherical polystyrene hollow microsphere was prepared by emulsion polymerization method. The surface of microsphere was compact and smooth and shell thickness was uniform. The density of the particle was 0.2—0.6 g/cm3 and the diameter was 10—120 μm. In laboratory research, microsphere which density of the particle in average was about 0.50 g/cm3 and the diameter was in range of 20—60 μm was chosen as light weight additive. Low-density (0.92 g/cm3) drilling fluid was prepared by adding 10% hollow polystyrene sphere to 0.2% xanthan gum solution. The density of drilling fluid changed to 0.96 or 0.93 g/cm3 when it was rolled 16 hrs at 90℃ and under constant pressure or 0.3 MPa. Drilling fluid’s density changed little when temperature rose to 90℃ and pressure rose to 50 MPa. Low-density drilling fluid’s density was 0.92 g/cm3 when it was stirred 8 hrs at a speed of 12000 r/min, and that was 0.93 g/cm3 when it was grinded 8 hrs, which indicated that the influence of stirring and grinding on hollow polystyrene sphere was smaller than that on hollow glass sphere. Hollow polystyrene sphere was applied in oilfield for the first time at Zhangwu area in northeast. The results showed that polystyrene sphere had little effect to drilling fluid and had a good ability to reduce drilling fluid’s density. But the sphere was easy to reunite together and adsorb to drillings, as a result, it was easy to be screened by solids control equipment.

Abstract:A microemulsion viscosifier AM/AA/AMPS/DMAM was synthesized by inverse microemulsion polymerization with acrylamide (AM), acrylic acid (AA), 2-acrylamido-2-methylpropane sulfonic acid (AMPS) and N, N-dimethylacrylamide (DMAM) as monomers. The microemulsion could be added into the drilling fluids directly. The apparent viscosity(AV), plastic viscosity(PV), yield point(YP) and fluid loss(FL) of drilling fluids were 26.5 mPa·s, 16.0 mPa·s, 10.5 Pa and 14.2 mL accordingly when the addition amount of microemulsion was 0.6% at room temperature. The AV, PV and YP of drilling fluids showed downtrend and FL increased with increasing rolling temperature when the addition amount of microemulsion was 1.0%. But the variation was minor with the temperature less than 150℃, which showed good temperature tolerance. The NaCl resisting concentration of the drilling fluids could reach saturation and CaCl2 resisting concentration was 0.6% when 2.0% microemulsion added. Compared with the conventional viscosifier 80A-51, the temperature and salt tolerance of the synthesized polymer had been improved obviously.

Abstract:Through the development of X-diffraction, coefficient of rolling recovery and expansion laboratory experiments, the physical and chemical performance distribution rule of the formation clay mineral in Baka area was summarized. According to characteristics of formation lithological and technical difficulties of the drilling fluid used in Baka area, combined with the existing several different drilling fluid systems, including sulphonated polymer mud, polyether glycol drilling fluid, and amino poly alcohol drilling fluid, the conventional performance, inhibition performance and plugging and anti -sloughing ability were investigated and the best drilling fluid was carried out in t Ke21-ping 1 well. The experimental results showed that the content of coal and clay minerals were higher, thereinto, the clay minerals were mainly illite and smectite mixed layer, which meant that the drilling fluid in coal seam drilling hole should have strong inhibitory, in the lower should have anti-sloughing ability. The recipe of the optimal drilling fluid system with the strongest inhibitory and plugging and anti-sloughing ability, an amino poly alcohol drilling fluid, was as follows: (4%-5%) bentonite+0.5% amino poly alcohol AP-1+0.5% aluminum polymer anti-sloughing agent DLP-1+ (0.8%-1%) Hydrolyzed polyacrylonitrile sodium NaHPAN+0.5% NaOH+ (0.3%-0.5%) carboxymethyl cellulose CMC+ (3%-4%) cationic emulsified asphalt +3% sulfomethylation phenolic resin SMP-1+ (3%-5%) sulfomethylation phenolic resin SMP-2+3% lignite resin SPNH +2% non-invaded protection agents BST-2+3% sulfonated tannins SMT+ (2%-4%) sulfonated humic acid chromium PSC. The API filtration of the optimal drilling fluid was 4.2 mL, and the high temperature and high pressure filtration was 12 mL, which could inhibit shale hydration swelling effectively, exhibiting the excellent plugging and anti - sloughing ability. Field test results of Ke21 - ping 1 well showed that in the coal seam section drilling process the underground complicated accidents had not occurred to, and the penetration of many sets of coal seam and coal-bearing stratum was achieved successfully. At the same time, it also ensured the stability of directional drilling of borehole wall, and made the drilling cycle significantly shorten and the performance of drilling fluid maintenance more easily. The operation was simple and could fulfill the safety drilling requirements of coal seam hole.

Abstract:Because there are many surfactants in the domestic styrene-butadiene latex, the foams could be produced and existed stably in the cement slurry though the mixing process, which would seriously influence the density and compressive strength of the cement pastes. In this paper, the surface tension and stability of the latex was tested and the flowability and density at different temperature was measured and the compressive strength and microstructure of the cement pastes with or without defoamers were studied as well. The results showed that the influence of the concentration of styrene-butadiene latex was lower than that of the type of the defoamers. Moreover, the foaming reaction of cement slurry with latex at high temperature was intenser than in room temperature. The surface tensile and defoamers of isooctanol as well as dimethicone was much lower than that of the others, and the both defoamers which had a good defoaming ability at 90℃would not effect the stability and flowability of the latex cement slurry, however, the defoaming effect was the best at the dosage of 0.3%. After adding the compound defoamers (the mass ratio of dimethicone to isooctanol was 1:1.5) in the latex cement slurry, the compressive strength of the obtained cement paste was much higher and the number of pore and bubble in the cement paste was fewer than that without defoamers, meaning that the microstructure of the cement paste with compound defoamers was denser.

Abstract:The condensate gas reservoir output could be enhanced significantly with a fluorocarbon gas-wetting reversal FC-1 developed in laboratory. However, the changes in the wettability will affect the dispersing properties of clay minerals in condensate gas reservoir. The properties of montmorillonite were studied before and after FC-1 treatment. The results showed that when the mass fraction of FC-1 was 100%, zeta potential of montmorillonite of 100 to 200 meshes increased from -31.70 mV to -17.27 mV, approaching to non-dispersion condition gradually. With the increase of the FC-1 concentration, cation exchange capacity dropped sharply and Methylene blue capacity droped from 2.14 to 0.2 when the mass fraction of FC-1 was 100%. The max swelling height of montmorillonite treated with 100% FC-1 was 0.83 mm after 16 h. The montmorillonite crystal aggregation form and micro-shape are analyzed by TEM and SEM. Conclusions were drawn that fluoridated alkyl groups of FC-1 had been attached on the surface of montmorillonite particles and formed a gas-wetting reversal film which maintains their stability.

Abstract:Several factors influencing the viscosity of the hydroxypropyl sulfo-betaine VESBET-4 solution relation, including the VESBET-4 concentration, pH value and the addition of inorganic salt (NH4Cl and KCl), were investigated, and the properies of the fracturing fluid composed of 2.5% surfactant, 3% inorganic salt and 0.5% clay stabilizer, such as the temperature tolerance and shearing resistance, prop-carrying capacity and gel breaking, were evaluated. The result demonstrated that the viscosity of VESBET-4 solution with mass fraction of 2% reached 600 mPa·s at a speed of 250 r/min. The surfactant VESBET-4 was suitable for use in neutral and alkaline conditions and had a good compatibility with clay stabilizers (NH4Cl and KCl), which almost had no influence on its viscosity. The fracturing fluid possessed good temperature tolerance and shearing resistance, the viscosity of the system was still higher than 50 mPa·s at the temperature of 70℃and the shearing rate of 170 s-1; and the viscosity of the system was still higher than 85 mPa·s after shearing for 2 h at the temperature of 60℃ and the shearing rate of 170 s-1. Meanwhile, the system had a good prop-carrying capacity, the settling velocity of single sand was 0.95 cm/h and when the sand ratio was 30% in volume settling velocity was 1.11 cm/h. The simulated formation water had been used to gel breaking, and the viscosity of the gel breaking liquid was lower than 4.5 mPa·s within 1 h.

Abstract:Weighted fracturing fluid is one of the effective means to solve the too high pressure problem during the process of fracturing operation. However, the common weighted gel fracturing fluid has some disadvantages, such as high residue content, huge tube frictional resistance, low shear resistance, etc. At the same time, most of clean fracturing fluid can not be used at high temperature. To solve the above problems, a novel weighted fracturing fluid (WFF) that the density reached to 1.3 g/cm3 and more and the temperature-resistant was 140℃ was investigated. The formula of the WFF was established as follows: 0.6% thicker GRF-1H, 0.3% thickening additive GRF-2 and 37.05% weighting agent JZ12. The dynamic sand-carrying properties, temperature and shear resistance proerty, filtration performance and fracture conductivity of the WFF were evaluated. The experiment results showed that as long as the viscosity reached up to 22 mPa·s, the WFF could possess a good sand-carrying performance. High-temperature rheologic tests showed that the WFF system has good temperature and shear resistance property. With the increase of density, there was a significant thickening effect of salt. The static filtraition performance of the system was evaluated using real cores. The WFF system did not contain water insoluble but it had low filtration coefficient. The damage of the WFF on the fracture conductivity was only 8.94%, which was far less than that of boron crosslinked HPG fracturing fluid.

Abstract:Aiming at the problems such as high water injection pressure and severe shorting-injection resulting from the low porosity and low permeability in low permeability sandstone reservoir, the cationic surfactant with amide groups (BNFS) whose name was molecular injection agent was developed. The adsorption property, wettability, surface and interfacial activity, and drag reduction performance of BNFS was evaluated. The results showed that a layer of molecular film formed after BNFS absorbed on the sandstone surface. The contact angle of sandstone surface was increased from 27.6° to 88.6°, and the wettability of that changed from strong water wetting to slight water wetting. When the concentration of BNFS was 200 mg/L, the surface tension of solution was 26.61mN/m and the interfacial tension with kerosene was 0.06 mN/m. The core flooding experiment results showed that water phase permeability of sandstone core increased 80%—120% and water injection pressure decreased 12%—18% by BNFS. The analysis result of molecular injection mechanism showed that the magnitude order of adsorption energy was 10-18 J between molecular injection agent and hole wall, and that was 10-20 J between water molecule and hole wall. The adsorption energy of former was far greater than that of latter. Therefore, molecular injection agent had absolute advantage in the competitive adsorption to make effective seepage channel increase. The adhesion work between core and water molecule reduced from 136.5 mN/m to 75.7 mN/m after BNFS applied to core, which showed obvious drag reduction.

Abstract:Oligomeric quaternary ammonium salts MD-I and MD-II were synthesized from epichlorohydrin, dimethylamine and bromo hydrocarbons. Adsorption behaviors of the cationic oligomeric quaternary ammonium salt on natural sandstone surface were studied through attenuated total reflectance-Fourier transform infrared spectroscopy (ATR-FTIR), X ray diffraction (XRD), scanning electron microscopy (SEM) analysis and the determination of contact angle. ATR-IR analysis showed that MD-I and MD-II were adsorbed on the surface of the sandstone to form thin film, moreover, MD-I and MD-II molecules in the membrane had a specific alignment; X ray diffraction analysis indicated that the crystal plane spacing and the crystalline structure of two treated cores was not significantly changed; Environmental scanning electron microscopy results showed that surface structure of the sandsone treated by MD-I had not significantly altered, however, the surface of the sandstone treated by MD-II gave some slender materials. And oil wet surface of natural sandstone slice (water contact angle of 96.7°) adsorbed by two aqueous oligomeric quaternary ammonium salt(MD-I and MD-II), respectively, turned to be water-wet (water contact angle of 34.1° and 44.5°, respectively), thereinto, after adsorption equilibrium, MD-I could change the wettability of surface of the sandstone more obviously.

Abstract:According to the plugging difficulty in fractured reservoir of Wangyao infilled block, the urea-formaldehyde resin plugging agent with high strength was synthesized by formaldehyde and carbamide at 55℃, and its performance was studied. The results showed that the dissolution rate in injected water, paraffin and mixed acid (10% HCl＋3% HF) was 1.54%, 2.40% and 14.30%, respectively. Its hydrotrope, oil and acid soluble were all lower which indicated good stability. With increasing temperature, the curing time of urea-formaldehyde resin shortened, and its compressive resistance increased fast. The curing time was 10 h, and the compressive resistance was 12.2 MPa at 55℃. With increasing degree of mineralization, the compressive resistance decreased and the curing time extended. The curing time was 12 h, and the compressive resistance was 4 MPa when the degree of mineralization was 50 g/L. The plugging efficiency in fractured reservoir was higher than 95%, and the breakthrough pressure was more than 24 MPa which showed high plugging off intensity. The "weak gel and urea-formaldehyde resin" system was applied for field construction in converted injector well Wang19-06. Cumulative quantity of oil was 545.56 t, water cut decrease was 475.92 m3, and valid period was more than 10 months. The pilot effects of increasing oil production and decreasing water cut were good.

Abstract:An environment-friendly self-crosslinkable polymer gel was prepared utilizing acrylamide (AM) and double acetone acrylamide (DAAM) oxazine sulfate. The optimum syntheses condition was obtained as follows: 5% AM, 0.8% DAAM oxazine sulfate, 0.8% initiator, 8 pH value and 50℃ reaction temperature. The viscosity of solution before gelling was about 15 mPa·s which indicated good injection. The gelation time could be controlled by 1—3 days. Meanwhile, the high gel strength (I grade) of binary crosslinkable copolymer kept 1 days at 60℃. Core plugging experiment results showed that the blocking rate of water was between 93.50% and 99.71%, and breakthrough pressure gradient was in a range of 31.25—58.61 MPa/m.

Abstract:According to the high temperature condition in Zhaowa block of Henan oilfield, the optimum formula of polymer cross-linking system was obtained as follows: 1.5 g/L comb polymer KY-6, 15 g/L aldehyde cross-linking agent. The optimum gelation temperature was about 90℃. This profile control agent had resistance of temperature 110℃ and salinity 20 g/L. The viscosity retention rate of gel was more than 80% after 90 days at 90℃ gelling temperature. The storage modulus of the gel was above 10 Pa which showed it was strong gel. The physical model results showed that the blocking ratio of the profile control agent in core was more than 96%, and the retention rate of blocking ratio was beyond 99% after water scouring. Sand packed tube model experiment results showed that the increase of oil recovery was up to 15.91%, with 0.3 PV injection and slug combination of lead slug, subject slug and rear slug. Parallel core profile control experiment results showed that the improving rate of injection profile was up to 88% after profile control. Recovery efficiency of high and low permeability layers was improved by 14.13% and 19.28%, respectively. Water driving degree of different permeability core was improved.

Abstract:Enhanced oil recovery by waterflooding is low and injected pressure is high in the ultra-low permeability reservoir, but nitrogen is easy to be injected. In this paper, core displacement experiments were conducted by the means of conventional nitrogen injection, WAG and pulse gas injection in ultra-low permeability reservoir after waterflooding. The experiment results showed that since the microanisotropy characteristic of ultra-low permeability reservoir, Nitrogen can crossflow easily in the big pore channel, therefore, injecting nitrogen normally after water flooding make an ineffective effort to enhance oil recovery. However, with using the WAG the dispersive degree of different fluid phase could be enhanced, and then, the capillary force could be formed in the advantage flow channel firstly, which make the later injected nitrogen come into partial dense area, oil recovery being enhanced effectively by 16.37%; The pulse gas injection could form pressure disturbance and interactive seepage between high-permeability zone and low-permeability zone which made the fluid redistributed in the reservoir, and finally the oil trapped in the low-permeability area was launched, thereby the oil recovery could be enhanced by 15.94%. Besides, the pulse gas injection pressure was low, and the gas injectivity was better than WAG.

Abstract:CO2 foam has been used as an effective conformance and mobility control agent to prevent early gas breakthrough during CO2 flooding in heterogeneous reservoirs. In this study, the performance of CO2 foams generated using various surfactants was investigated. The effects of surfactant concentration, temperature, salinity and pressure on performance of CO2 foam were studied under high temperature and high salinity conditions prevailed in Zhongyuan oilfield. The performance of the CO2 foam on mobility control was measured via flooding and displacement experiments using sandpacks. The results showed that the complex of amphoteric surfactants LX-8 and nonionic surfactants FL-6 with HLB values between 14 and 16 had good foam stability at high temperature and salinity conditions. The resistance factor of foams generated in sandpacks could reach up to 130 under 100℃ and 15 MPa, indicating that the CO2 foams had good mobility control and sealing capabilities at reservoir conditions. The experimental results also showed that the resistance was more sensitive to half life time of the CO2 foam, which could be the main factor to evaluate CO2 foam’s stability and blocking performance.

Abstract:Aqueous foam is widely used in oil drilling, oil displacement, mineral flotation and so on; however, the foam belongs to an essentially thermodynamically unstable system. Based on the synergy of different surfactants, the foaming ability and stability of their mixtures were investigated through Waring Blender method, and an aqueous foam system with high stability, named as AFS-2, was screened out. And then, its microstructure was observed, and its oil-sensitivity and salt-sensitivity were evaluated. The experimental results showed that the best system AFS-2 was composed of 1 g/L SDS, 1 g/L 3#, 3 g/L PAM, 3 g/L SF-1 and 3 g/L dodecanol. The volume of AFS-2 foam generated by its 100 milliliters solution was 380 milliliters at 20℃, and the bubbles are round, and their diameters are distributed within the range of 10～100 μm. The half-life period of the system was 6050 minutes which meant that the AFS-2 system had high stability. Three kinds of oils, including 0# diesel, Tahe heavy oil and Fengcheng super-heavy oil, could strongly destroy the foam. At the same time, the higher the oil viscosity, the weaker the damage capability to the foam. When the concentration of Fengcheng super-heavy oil wais less than 10.6 g/L, half-life period of the system was more than 3720 min. When the concentrations of CaCl2 and NaCl were less than 1 g/L and 10 g/L, respectively, AFS-2 foam system could maintain adequate stability.

Abstract:A series of foam systems, which was mainly composed of the mixture of amino sulfonate amphoteric surfactants with 12 carbon atoms (AS12) and 14 carbon atoms (AS14) in the mass ratio of 3:1, were developed. FJ-1, FJ-2, FJ-4, FJ-6 and FJ-8 were obtained in the increasing mass content of AS12 and AS14 in the mixtures. Thereinto, FJ-4, FJ-6 and FJ-8, compatible with the aqueous solution with mineralization degree of 120.67 g/L, were screened out from a series of foam systems. The critical micelle concentrations (abbr. ccmc) of them in aqueous solution were determined by the method of surface tension, and the properties of salt-tolerance and temperature resistance of them in aqueous solution under the concentrations of ccmc were evaluated by determining the half-life of bubble, on behalf of foaming stability. The results showed that at the temperature of 25℃, the foaming stability of FJ-6 or FJ-8 reduced in aqueous NaCl solution as the dosage of NaCl increased (less than 120 g/L) and linearly increased in queous CaCl2 solution with the increase of the content of CaCl2 (<14 g/L), and did not strikingly weakened in aqueous solution of mixed salt of 120.67 g/L due to the effect of the divalent counterion Ca2+ or Mg2+. With the increase of temperature (lower than 80℃), the gentle drop of the foaming stability in aqueous solution containing the mixed salt of 120.67g/L, contrasting to the rapid drop in aqueous solution without salt, showed the excellent temperature resistance of FJ-6 or FJ-8.

Abstract:The high oil viscosity and heterogeneity of multi-layer reservoir are the key factors influencing the development effects of polymer flooding in offshore heavy oilfield. In this paper, parallel twin-tube physical simulation was used to study the volume ratio entering different permeability tubes on the condition of different polymer injection timing and different polymer injection speed in the multilayer heterogeneous reservoir. Then the effect of permeability differential on the recovery factor of the high and low permeability layers and the total recovery factor was analyzed. Experimental results showed that the reasonable permeability ratio of polymer flooding in multi-layer reservoir was in the range of 5-6. On this condition, polymer flooding could improve reservoir vertical heterogeneity and obtain a higher oil recovery. The conclusion of the study will provide experimental and applied basis for determining reasonable strata combination limit in multi-layer heterogeneity reservoir.

Abstract:For efficient cold production of unconventional heavy oil, a new surfactant containing sulfonic hydrophobically associating polymer SAP was synthesized, the viscosity properties and the temperature resistance and salt tolerance were investigated and the simulated displacement experiments were carried out. The results showed that the critical aggregation concentration (CAC) of SAP was 2200 mg/L. The viscosity of SAP soultion increased with the increase of salinity above CAC. The viscosity retention rate of SAP solution was only 5% after aged at 80℃ for 90 days. The displacement experiments showed that the oil recovery curve of SAP flooding belonged to S type; the higher the residual oil saturation, or the higher the SAP concentration or the larger the polymer slug size, the bigger the oil recovery of SAP flooding. The heavy oil emulsion was produce discontinuously by SAP flooding and the cationic surfactant DTAB was efficient in demulsifying the produce crude oil emulsion.

Abstract:In the light of poor salt tolerance and difficulty to improve washing oil efficiency of the polymers used in oil fields, a kind of salt tolerance copolymer with surface activity，called GL, was synthesized and the characteristics of GL were evaluated under specific reservoir condition of Daqing oil field. The results demonstrated that, when the solution concentrations were between 250 mg/L and 1500 mg/L and the salinity was 2400 mg/L and the temperature were 45℃, the viscosity of GL solutions were higher than that of HPAM solutions. Although the viscosity of the two kinds of polymer solutions at the concentration of 1000 mg/L decreased with the increase of the salinity, the viscosity of GL solution was almost 20 mPa·s higher than that of HPAM solution. The water separation ratio of the emulsion obtained with GL solution at the concentration of 1000 mg/L and the crude oil was lower, being of about 50%, while that of HPAM solution at the same concentration reached 95% quickly. The oil displacement experiment results indicated that based on the water flood, the oil recovery of the GL solution was 4.0% higher than that of HPAM solution at the same concentration (1000 mg/L); the oil recovery of the GL solution with 2.6% higher than that of HPAM solution at the same viscosity (62 mPa·s )with same viscosity.

Abstract:The surface and interfacial tensions without alkali between Daqing crude oil and homemade carboxyl betaine (BC) containing double bond were studied. The critical micelle concentration (Ccmc) of BC was 1.02×10-5 mol/L, and γcmc was 29.603 mN/m at 45°C. When oil and produced water source was the first oil production factory in Daqing, the interfacial tension between BC surfactant solution or BC/0.09% HPAM binary solution with BC concentration of 0.05%—0.20% and crude oil or simulated crude oil reached ultralow level (10-3 mN/m magnitude). The decrease of interfacial tension between BC and simulated crude oil was bigger than that of crude oil. The time to reach ultralow interfacial tension of binary solution was longer than that of single surfactant solution. When oil and produced water source was the third oil production factory in Daqing, the interfacial tension between 0.05%—0.20% BC surfactant solution and crude oil reached ultralow level. Furthermore, 10-3 mN/m magnitude interfacial tension could maintain after 160 days aging at 45℃ which showed good stability of BC.

Abstract:Using polyoxyethylene lauryl ether and maleic anhydride as the main raw materials, a high surface activity gemini surfactant CAPM was synthesized, and the structure of CAPM was characterized by IR. The surface tension and oil/water interface tension were investigateded and the core displacement experiments were conducted with authentic sandstone microscopic model. The results showed that the surfactant CAPM could make surface tension of water reduce to 27.08 mN/m and the critical micelle concentration was about 0.163 g/L. The interface tension between the crude oil and CAPM solution could be reduced to 10-3 mN/m, which is suitable for enhancement of oil recovery. The core displacement experiments showed that the CAPM solution could displace the oil in the sandstone effectively.

Abstract:In consideration of high temperature and high salinity of the thin oil reservoirs in Jianghan Oilfield and poor performance of common surfactants under such conditions, a series of SH anionic-nonionic surfactants，C12H25O(CH2CH2O)nCH2CH(OH)CH2SO3Na (the SH01~SH05 was corresponding to n value of 5~9），were synthesized. Their properties such as surface activity, temperature resistance, and salt tolerance were measured in laboratory, and oil displacement efficiencies were evaluated with physical models. The experimental results showed that the synthesized surfactants have fine temperature resistance and salt tolerance, and the oil-water interfacial tension became even lower as temperature and salinity increased. The interfacial tension between the oil from Zhongshi Oilfield and the aqueous solution having high salinity of 300g/L and surfactants of 0.3% could descend to an ultra-low order of 10-3 mN/m. The physical simulation experiments showed that when injecting 0.3 PV the 0.3% SH-3 solution alone, oil displacement efficiency could be enhanced by 6%; while the combination flooding system(0.3% SH03+0.3% SMG) could enhance the oil displacement efficiency by 12.1%. The Zhong10-5 Wellblock in Zhongshi Oilfield was chosen to carry out the pilot test and yielded a good result of increasing oil.

Abstract:The alkali ASP system was composed of petroleum sulfonate surfactant, Na2CO3 and polymer P620, P700 and P1400 with relative molecular mass 620×104, 700×104 (salt resistant) and 1400×104. When the ASP flooding weak alkali system flowed in the core of class Ⅲ reservoir of Saertu oilfield, the apparent viscosity, interfacial tension, coefficient of resistance and other parameters at different injecting stage were tested, and the change law of ASP flooding weak alkali system flooding properties in the core was obtained. The results showed that the apparent viscosity increased continuously with increasing composite system injection. When subsequent water was injected, the apparent viscosity increased first and then decreased with increasing water injection. The highest viscosity retention rate of P620, P700 and P1400 alkali ASP system was 81.53%, 17.22% and 12.05%, respectively. The interface tension of produced liquid decreased first and then increased during the conduct of displacement. The lowest interface tension of P700, P620 was 6.59×10-2 and 2.38×10-3 mN/m. With increasing injection rate of P700, P620 and P1400 ASP system, the injection pressure increased to the highest at 2.88, 0.60 and 0.87 MPa. When the follow-up water was injected, the injection pressure decreased. The resistance coefficient of P620, P700 and P1400 alkali ASP system was 75.00, 360.00 and 109.25, and the residual resistance factor of that was 22.25, 155.00 and 28.25, respectively. The injection rate of P620 alkali ASP system was the lowest when the flowing of ASP system in the core achieved stability.

Abstract:The static corrosion of alkali, alkali/surfactant(AS) and alkali/surfactant/polymer(ASP) system on minerals of reservoir were carried out by detecting the content of aluminium and silicon elements on the rock surface and the concentration of Ca2+, Mg2+, Si4+, Al3+, OH-, CO32-, HCO3-and Cl- in liquid phase. The results indicated that alkali mainly corroded clay minerals instead of feldspar. The concentration of Si4+ and Al3+ increased and that of Ca2+ and Mg2+ decreased in liquid phase, while content of Si and Al of the rock surface decreased after rock specimen was soaked in the ASP solution. With the increase of alkali concentration or the ratio of liquid to solid increases or soaking time, the corrosion became serious. Surfactant and polymer could reduce the corrosion of alkali on rock minerals to some degree. At first, alkali corroded rock strongly; after 60 days, the molecules of silicic acid in liquid phase polymerized each other and dehydrated into silica scale with the help of alkali. Polymer promoted silicone body to aggregate and scale furtherly.

Abstract:the best synthetic method of the copolymer of maleic anhydride, styrene and octadecyl acrylate(MSA), an oil-soluble heavy oil viscosity depressant, was investigated and the effects of the dosage of MSA, sodium dodecane sulphonate as adjuvant and water on the viscosity reduction of the Shengli heavy simulated oil was probed. The results showed that the best synthetic conditions of MSA were as follows, the mass ratio of solvent toluene and total monomers were 1:1, the mol ratio of octadecyl acrylate, styrene and maleic anhydride were 6:1:2, the synthetic temperature were 90℃ and the synthetic time were 4 h. When the dosage of MSA was 1.0% and the temperature was 90℃, the effect of viscosity reduction of Shengli heavy simulated oil was the best. Besides, the adjuvant of sodium dodecane sulphonate could improve the effect of viscosity reduction of Shengli heavy simulated oil evidently, and the best dosage of sodium dodecane sulphonate was 0.8%. As the content of water in raw oil increased, the effect of viscosity reduction of Shengli heavy simulated oil increased, and when the content of water in raw oil was up to 40%, the ratio of viscosity reduction of Shengli heavy simulated oil exceeded 90%.

Abstract:XJ Mannich bases were synthesized with formaldehyde, acetophenone, aromatic hydrazine as raw material. Through orthogonal experiments the optimum synthesis conditions was obtained as follows: the reaction temperature was 70℃, the molar ratio of formaldehyde to aromatic hydrazine was 2.9:1, the malor ratio of acetophenone to aromatic hydrazine was 3.2:1, the pH value was 4 and the reaction time was 6 hours. The Mannich base prepared by the optimal recipes was named as XJ-3. The inhibition action of XJ-3 Mannich base on N80 steel was investigated by means of mass loss and electrochemical techniques. It was showed that the corrosion rate of N80 steel was 0.256 g·(㎡·h)-1 in 15% hydrochloric acid containing 1.0% of XJ-3,which was lower than the first Grade Standard of SY/T 5405-1996. Electrochemical test results showed that, the XJ-3 Mannich base belonged to a mainly anodic-controlling composite corrosion inhibitor. XJ series corrosion inhibitor effect was further confirmed by AC impedance technique. The adsorption behavior of the XJ corrosion inhibitor on the surface of N80 steel was subject to Langmiur adsorption isotherm.

Abstract:A sorbitan phosphate corrosion scale inhibitors (SPA) was prepared from the reaction monomers of sorbitol and phosphoric acid. The influence of relevant factors on the corrosion performance of SPA was studied using the corrosion rate as the evaluating index. The scale and corrosion inhibition performance of SPA was evaluated by using the static scale evaluation and the atmospheric static method, and the mechanism of corrosion inhibition was discussed though electrochemical polarization curves. The experiment results showed the SPA had best property when synthesized at atmospheric pressure, the mole ratio of sorbitol (SOR) and phosphoric acid (PA) was 3:1, the esterification reaction time was 3 h and the optimum temperature was 120℃~140℃. The inhibition rate of the SPA on CaCO3 scale was more than 90% when the mass concentration was greater than 25 mg/L. The corrosion rate of A3 steel in the simulated water was 0.0234 mm/a and the corrosion rate was 85.26% when the dosage of the SPA was 100 mg/L. The potentiodynamic polarization curves showed that SPA was a mainly cathode-controlling mixed corrosion inhibitor.

Abstract:Experiments of mixing barium/strontium sulfates scale formation, as well as effects of reaction time, temperature, stirring rate, concentration of Ba2+/Sr2+ and SO42- on the formation of barium/strontium sulfates scale at L95 and T9 production sites in Linpan oil production factory of Shengli oilfield, were investigated in the paper. The results showed that the scaling rate of barium/strontium scale was basically stable in ten minutes. The scaling rate of BaSO4 was above 98%, while that of SrSO4 was about 22%. Reaction time and stirring rate had no effect on the scaling rate of barium/strontium sulfates scale, while the temperature (30—80℃) and the concentration of Ba2+ had a little influence on the scaling rate of BaSO4. The scaling rate of BaSO4 increased with increasing SO42- concentration, and that increased from 94.68% to 99.97% when the concentration of SO42- increased from 1.53 mmol/L to 3.06 mmol/L. The scaling rate of SrSO4 had greatly increased with increasing temperature as well as the concentration of SO42- and Sr2+. When the concentration of SO42- and Sr2+ increased to 24 mmol/L and 3 mmol/L respectively, the scaling rate of SrSO4 scale was nearly to 80% at the temperature higher than 80℃. Besides, When the concentration ratio of [Ba2+], [Sr2+] and [SO42-] was 2:1:6, the total scaling rate of mixed barium/strontium sulfates scale was as high as 93.75%. Because of the addition of 6 times concentration of SO42-, the total scaling rate of barium/strontium sulfates scale was about 91% with 20 min scaling time by using the continuous point scaling technology. In general, it was an effective way to improve the scaling rate of barium/strontium sulfates scale by increasing SO42- as scale accelerator.

Abstract:Taking some analog sewages containing polymer as study subjects, the effects on chemical oxidation and flocculating of the sewages under different reaction conditions was studied. The turbidity of the supernatant was tested and analyzed by turbidity meter, the microstructure of flocs was observed by image analyzers and the fractal dimension was calculated by perimeter-size method; the PAM concentration was tested by starch-cadmium iodide method, then PAM removal rate was calculated. The results showed that there was a negative correlation between the fractal dimension of flocs and the turbidity of supernatant, so the fractal dimension of flocs could represent the effects of flocculation and sedimentation in electric-Fenton treatment. The PAM removal rate and the fractal dimension of flocs showed different rules in various reaction conditions; hence, it was more reasonable to adjust the test conditions on the basis of these rules. Under optimal reaction condition of pH value of 2.6, FeSO4 dosage of 130 mg/L, H2O2 dosage of 1 ml/L, electric current density of 25 mA/cm2, and the PAM removal rate was 95.34%, the fractal dimension of flocs was 1.8438 and the subsiding time was 26 min.

Abstract:A strain of sulfate reducing bacteria (SRB) was isolated from waste water in Changqing gas filed. The cell of strain was found to be Gram-negative, non-spore-forming, rough, and motile by a flagellum. The cell was rod or arc with 0.6—0.8 μm wide and 1.0—5.0 μm long. The strain showed positive reaction in the SRB test bottle. According to the modality and physiology, it was concluded that the strain belonged to Desulfovibrio sp. The quantity of SRB was 9.5×108 per milliliter after the strain was cultured in liquid for two days without Fe2+. The strain reached logarithmic phase after inoculation for 6 hrs, and reached a peak after 48 hrs, then stabilized about 4 hrs, finally entered a period of decline. The corrosion behaviors of 20R steel in SRB solution were studied by electrochemical impedance spectrometry and polarization curve. The results showed that the corrosion rate increased with increasing initial concentration of SRB, but the relationship was not linear. The corrosion rate of 20R steel soaked in SRB solution, 10 times diluent, 100 times diluent and contrast medium for three days was 0.0922, 0.0343, 0.0284 and 0.0281 mm/a, respectively. The corrosion rate of 20R steel soaked in 100 times diluted SRB solution for seven days was 0.0578 mm/a. The corrosion rate increased with increasing immersion time. The promoting role of SRB on cathode was greater than that on anode.

Abstract:The silicon molybdbenum yellow method for spectrophotometry determination was applied to quantitative analyze silicon ion in ASP-flooding produced water. The effects of NaOH, polymer (HPAM) and sodium dodecylbenzene sulfonate (LAS) on quantitative analysis of silicon ions were discussed. The results showed that NaOH (0—7200 mg/L) and LAS (0—2400 mg/L) had almost no effect on the absorbance. Hydrochloric acid could be used to eliminate the influence of NaOH with high concentration (>7200 mg/L). When the pH value was 1.2 and the dosage of HPAM (M=35 million) was between 0 and 80 mg/L, solution absorbance increased with increasing concentration of HPAM. The interference of polymer on the measuring of silicon ion could not be eliminated by adding 1 mL acetone, but it could be eliminated by diluting with distilled water. The interference of polymer with low molecular weight (M=3 millon) and low concentration (0—40 mg/L) was weak. The method suggested was simple, rapid and of satisfactory precision and accuracy. The standard curve of linear regression equation was: A=0.0145c, and the correlation coefficient R2 was 0.9996. The linearity of absorbance concentration relationship maintained in the range of silicon ion concentration 0—20 mg/L. The accuracy of the method was less than 2%. The measured value of the relative standard deviation was only 1.39%, which indicated the repeatability of this method was good.

Abstract:The relationships between the stability of W/O emulsion in five typical blocks of Shengli oilfield and the compositions of heavy oil, including the content of polar fractions, heteroatom and transition metals, as well as the properties of heavy oil, such as the mean dipole moment of polar fractions, were studied by gray correlation entropy method. At the same time, the microcosmic image of W/O emulsion and the Zeta of polar fractions were also studied in order to analyze the stability mechanism of W/O emulsion. SV value was used to represent the stability of the emulsion, the larger of SV value, the more stable of the emulsion. The results showed that four polar fractions, three heteroatoms and three transition metals were arranged according to the degree of association with SV value in following order: resin (0.9945)>saturate (0.9928)>aromatic (0.9901)>asphaltene (0.9597), N(0.9993)>O (0.9918)>S (0.9667), Ni (0.9891)>Fe (0.9852)>V (0.9845). The degree of association between the content of resin, N and Ni and SV value were the biggest which indicated that they were the main factors influencing the stability of W/O emulsion. The polar fractions were arranged according to the degree of association between mean dipole moment and SV value in following order: resin (0.9929)>asphaltene (0.9916)>aromatic (0.9796). The mean dipole moment of resin was the key factor that affecting the stability of emulsion. The mean dipole moment of resin was the key factor influencing the stability of W/O emulsion. The W/O emulsion of heavy oil in 3-12-182 block was the most stable with the biggest Zeta of polar fraction absolute value, the smallest of droplet size, the most concentrated size distribution (0.5—1.5) of droplets and the largest SV value (1026.70)

Abstract:Flooding containing alkali was commonly used in EOR. The interface-active components interacting with alkali in crude oil were introduced. The main active components were organic acids, non-acids and heavier substances which played a supporting role. Some crude oil also contained special trace components including siloxanes、amino acids and anilines which affected its alkaline emulsifying properties. The mechanisms of alkaline flooding were reviewed, such as reducing the interfacial tension, reversing wettability, emulsifying, increasing the viscosity of water phase, changing the rheology of crude oil, solubilizing the rigid film and thermodynamic analysis, as well as the influencing factors of alkali, salt, etc.

Abstract:By surveying relevant literatures in nearly twenty years, research progress on steel electrochemical corrosion in oil and gas fields water system was summarized. The influences of CO2, H2S, Cl—, sulfate-reducing bacteria, temperature, pH value and other factors on steel corrosion rate were analyzed according to the characteristics of water quality. Meanwhile, the steel corrosion mechanisms were reviewed. Besides, in view of the various factors which affecting steel corrosion, some protective measures were proposed to reduce corrosion. It was pointed out that steel corrosion in dissolved oxygen, saprophytic bacteria, iron bacteria and other corrosion factors as well as steel corrosion mechanisms in concomitant medium would become a hot research area in the future.