Abstract:PMA-MMA emulsion with high mass ratio of methacrylic acid (MA) and methyl methacrylate (MMA) was prepared using MA and MMA as monomers and ammonium persulfate as initiator by soap-free emulsion polymerization. The effect of different reaction conditions on polymerization was studied. The optimum reaction condition of PMA-MMA emulsion was obtained as follows: 70℃ reaction temperature, 6:1 mass ratio of MA and MMA, 13% total monomer mass fraction, 2‰ mass ratio of initiator and total monomer, 25 min?reaction time of MA and initiator and then MMA adding, 5 h continuous reaction time. The viscosity of the obtained white emulsion was 280 mPa·s, the conversion rate was 99.1% and gel rate was 0.5%, without separation after storage for one month at normal temperature. PMA-MMA emulsion was used to treat the oilfield oily wastewater in the east of South China Sea, the results showed that the oil removal efficiency could reach 95% when emulsion dosage was 15 mg/L, which was superior to that of on-site foreign reagent (92%). The oil content of discharged production waste water decreased from15 mg/L to 8 mg/L when the emulsion dosage on site was 10 mg/L.

Abstract:In view of the problems which were found in field application of alkyl glucoside drilling fluid, the cationic alkyl glucoside (CAPG) was firstly introduced into drilling fluid system by drilling fluid technology company of Zhongyuan oilfield. The optimum formula of CAPG drilling fluid was obtained as follows: 375 mL water, 6% CAPG, 0.6% filtrate reducer LV-CMC, 0.6% flow regulator xanthan gum, 0.4% thickening agent HV-CMC, 3% plugging agent WLP, 0.4% NaOH, 0.2% Na₂CO₃, 24% NaCl and 0.4% antioxidant NaHSO₃. The performance test results showed that CAPG drilling fluid had excellent performances including inhibition, temperature resistance, lubricity, filtrate surfactivity, pollution resistance and reservoir protection, such as 99.15% cuttings first recovery, 99.45% cuttings relative recovery, 91.4% relative inhibition rate, 160℃ resistance temperature, 0.097 extreme pressure lubrication coefficient, 19.52 mN/m surface tension of filtration solution, 4.0 mL filtrate volume. Excellent pollution resistance was revealed, according to the mass fraction, the antipollution results were showed as follows: 36% NaCl, 5% CaCl₂, 10% bentonite, 10% drilling cuttings, 20% water, 10% crude oil. The static core permeability recovery value was greater than 93%, and the dynamic permeability recovery value was greater than 92%. All the performance of CAPG drilling fluid was superior to that of alkyl glucoside drilling fluid. The application prospect of cationic alkyl glucoside was well in exploration and development of oil and gas.

Abstract:In order to meet the requirements of fast drilling and reservoir protection in salt layer at high temperature, the anti-high temperature and saturated salt water based clay-free drilling fluid was developed by selecting and compounding the viscosifiers, cross linkers, filtrate reducers, lubricants and anti-collapse inhibitors. The formula of drilling fluid was: saturated salt water, 0.2% Na₂CO₂, 1.2% SSDP, 0.4% DDL, 0.4% PAM, 0.3% Na₂B₄O₇, 3% SL-Ⅱ, 3% ultrafine CaCO₃, 1% HL-8 and 2% AP-1. The laboratory evaluation results showed that the temperature resistance of the clay-free drilling fluid reached to 170℃, and the density was 1.22 g/cm3. It had good resistance to unconsolidated rock and the capacity was 10%. The lubrication coefficient was 0.0388, which was close to that of oil-based drilling fluid. The shale recovery was as high as 96.84% in the drilling fluid. The expansion rate of clay in clay-free drilling fluid was lower than that in fresh water, which indicated good anti-collapse performance. The permeability recovery rate of core was more than 90%，which indicated good reservoir protection effect.

Abstract:Due to the problems of traditional W/O emulsion drilling fluid, such as high viscosity, low gel and worse cuttings carrying capacity under high temperature, a new 200℃-resistance W/O emulsifier was designed and synthesized. A new W/O emulsion drilling fluid system with low viscosity and high gel was obtained after optimizing various agents, and the formula was: 90:10 oil-water ratio, 6.5% primary emulsifier DQGC-II, 2.2% secondary emulsifier DQNS-II, 4% No.4 organic clay, 1.5% CaO and 6% fluid loss control DQHA. This system showed good characteristics in lab including high electricity stability（ES1644V）, heat stability, good rheology, especially appropriate viscosity and gel under a low speed with 19mPa·s PV, 8 Pa YP, 0.42 YP/PV, 8.6mL HTHP filter loss. The new drilling fluid system was applied in GS-3 well of Daqing oilfield, there was no downhole complex. The ratio of overcut in average was 5.83%, and the following construction went smoothly. This new W/O drilling fluid system could replace the VersaClean system of M-I SWACO.

Abstract:A water-based drilling fluid, GreenLube, was produced through O/W emulsion with 33% vegetable oil, 50%~80% polyols aqueous solution and compounded surfactant (sorbitan trioleate and polyoxyethylenesorbitan monooleate, HLB=6~7). GreenLube was a readily biodegradable and low toxicity material with 0.95 BOD5/COD and 35981 mg/L 96 h LC50. Compared with based slurry, GreenLube (30 kg/m₃) could reduce the torque value for fresh water and sea water based bentonite by 69% and 47%, respectively. The properties of GreenLube were further evaluated by JFC, PEM and PEC drilling fluid systems currently used in offshore oilfield. The results showed that the lubrication factor for test systems were reduced from 0.24—0.26 to 0.14—0.16 without influence of the mud rheologies. GreenLube had been successfully used in several wells of Bohai oilfield. The friction coefficient of mud cake and torque of drilling tool were notably reduced.

Abstract:The adsorption capacity of potassium chloride on the surface of clay and quartz sand, and that of potassium formate and ammonium formate on the surface of montmorillonite was studied. The inhibition effect of organic salt solution OS500A (containing 75% potassium formate) and OS500B (containing 75% ammonium formate), potassium chloride solution and clean water on the hydration and dispersion of clay was compared. The results showed that for potassium chloride solution, potassium formate solution and ammonium formate solution, the adsorption capacity of salt increased gradually with increasing concentration of salt solution. When the mass concentration of potassium chloride solution was 160 g/L, the maximum adsorption capacity of potassium chloride on the surface of montmorillonite, kaolinite and quartz sand was 5.6, 2.06 and 1.57 mg, respectively. When the mass concentration of formic acid brines approached 100 g/L, the maximum adsorption capacity of potassium formate and ammonium formate on the surface of montmorillonite was 5.51 and 5.42 mg. The adsorption of organic salt on montmorillonite was easily saturated, and its maximum adsorption capacity was equal to that of inorganic salt. The result of grain size analysis showed that four solution were arranged according to their inhibition ability on the hydration and dispersion of clay in following order: ammonium formate (OS500B)>potassium formate (OS500A)>potassium chloride 5%>clean water. If the wettability of rock surface was changed by kerosene, it would improve the inhibition effect of clay dilating by organic salt. The compounded system of potassium chloride and formic acid brines was applied in 10 wells of Fudong region，the protection effect was obvious.

Abstract:According to the reservoir characteristics, the optimized formula of well completion fluid of organic acid salt with resistance of high temperature 170℃ was established: HCOONa (density of 1.30 g/cm₃) or HCOONa, HCOOK compound salt (density of 1.50 g/cm3 ) base fluid, 0.5% modified xanthan gum adhesion promoter DHV, 2% polyanionic cellulose fluid loss agent PAC-142 with low adhesion, 1% acid corrosion inhibitor SD-2, 0.8% amphoteric ionic cleanup additive SAT, 0.2% NaOH, 0.5% Na₂SO₃. After standing at 160℃, the stabilization time of this organic acid salt completion fluid was 64 hrs, the viscosity reduction rate was less than 50％, API fluid loss was less than 16 mL, and HTHP fluid loss was less than 30 mL at 160℃. The average corrosion rate of P110 steel was less than 0.05 mm/a and the core permeability recovery rate was about 86.5%—88.0%. The damages to hydrocarbon reservoir by fluid in well during the test could be effectively reduced by the well completion fluid. Additionally, the underground accidents happened in the process of gas test, which caused by solid settlement and the inhibition capacity reduction of working fluid on well condition of high temperature and high pressure, could also be avoided.

Abstract:The effects of mixing rate, mixing time, concentrations of foam stabilizer xanthan gum (XC) and homemade surfactant DBA2-12 on the size of microbubbles were investigated using microscopic-imaging technique combined with Nano Measurer1.2 size analysis software. The results showed that high mixing rate and increasing XC concentration were beneficial to generate homogeneous distribution, fine and stable bubbles. However, the bubble size did not change significantly as the mixing time and surfactant concentration different. The optimum reaction condition of microbubble system was obtained as follows: 0.4% sodium carboxymethylcellulose (HV-CMC), 0.4% XC, 0.2% DBA2-14, 10000 r/min mixing rate and 2 min mixing time. The corresponding size of microbubble was between 23.58 μm and 109.65 μm with a mean size of 71.87 μm。The microbubbles would slowly grow bigger with the lapse of standing time, but its size did not exceed 200 μm after 12 hrs .

Abstract:aiming at problems of low permeability, alkali-sensitive, deep zone, high temperature and so on, a fracturing fluid system of high temperature resistance copolymer was developed by using copolymer as thickener and introducing a compound cross-linking agent capable of retarded release, which contained metal ions as well as organic compound that can form co-ordination complex with the former. Thereby cross linking reaction between the fracturing fluid and the compound cross-linking agent under acidic condition. The mass ratio of base fluid to cross linking agent and the optimal applicable range of zirconium salt content in the compound cross linking agent were determined. The rheological property, filtration property and gel breaking property of the fracturing fluid were examined at 140℃ and the field test was performed. The formula of the fracturing fluid with temperature resistance of 140℃ was as follows: 0.6% FTS-17 thickener +0.3% FTZP-6 cleanup additive +0.3% FTFM foaming agent +0.2% FTFP-6 anti-swelling agent +0.6% FTJL-3 cross linking agent +0.02% FTPJ-8 gel breaker. Under conditions of constant temperature of 140℃ and shear rate of 170 s_-1, the viscosity of the fracturing fluid was over 120 mPa?s after continuous shearing for 120 min, showing good properties of temperature resistance and shearing resistance. After gel breaking, the residue of fracturing fluid was only 50?mg/L. The viscosity of gel breaking fluid was only 1.6 mPa?s, the surface tension of gel breaking fluid is 23.56 mN/m, and the interfacial tension between the gel breaking fluid and kerosene was 2.46?mN/m, which showed that the fracturing fluid had good property of reducing filtration, fewer residues, and was less harmful to formation. This copolymer fracturing fluid system had been tested in Qinghai and Changqing oilfields; the highest field operation pressure was 80?MPa; the flowback rate was up to 75%.

Abstract:Xingouzui formation was typical low pressure, low porosity, low permeability and shallow buried reservoir in Wancheng oilfield. To re-treatment successfully and improve postfracture response in the formation, it was critical to select the fracturing fluid system for refracturing, which could be provided with proppant carrying capacity enough, broken and flowbacked easily and low reservoir damage. According to the research in laboratory, a special kind of low damage refracturing fluid system including 0.50% gelling agent HPG, 0.50% cleanup additive BA1-5, 0.50% clay inhibitor BA1-13, 0.20% bactericidal agent BA2-3 and 0.45% crosslinker BA1-21A and BA1-21B (10%—30% NaOH solution) in mass ratio 10:1 was developed successfully. Fracturing fluid evaluating experiment results showed that this system was characterized by excellent anti-shearing performance, as the viscosity of fracturing fluid gel still kept about 120 mPa·s after shearing 2 hrs at 70℃ and 170 s-1, good gel breaking property, as the viscosity of broken-gel fluid was 3 mPa·s with (NH₄)₂S₂O₈ dosage of 500 mg/L, and little damage to the formation, as the formation fracture conductivity was about 116.68 D·cm with the fracture conductivity damage rate about 28% after system breaking. The fracturing fluid system was used to retreatment in W5X well successfully, with 29.3% proppant concentration in average and 4.5~5.0 m³/min construction displacement. The postfracture response was desired whose stable daily fluid production rate was 6.5 t and daily oil production was 5.1 t.

Abstract:Aimed at the low temperature and high salinity condition of low permeability fractured reservoir in GY oilfield, the crosslinker JL-1 was synthesized by three chromium chloride, sodium hydroxide, acetic acid and daucic acid. Then with gelling time and gel strength as evaluation indexes, a weak gel profile control system KY-1 in low temperature and high salinity reservoirs was prepared by regulating the relative molecular mass of polymer (HPAM) and the concentration of HPAM and JL-1. The performance of salt tolerance and shear resistance of KY-1 was investigated, and the plugging capacity and oil displacement efficiency of KY-1 was estimated. The results showed that the best formula?of KY-1?weak gel flooding?system which was applied to GY oilfield was: T114 oil?formation water, 3000 mg/L HPAM（M=1400×10⁴） and 500 mg/L J L-1. When the salinity of formation water?was 40 g/L, the weak gel system could gelatinize rapidly in 60 hrs with 30 Pa·s gel strength and good salt tolerance. The system also had good sheering tolerance. The gel strength of system was 25600 mPa·s and the gel viscosity loss rate was 18.99% after 120 min sheering at 200 s^-1, 27℃. The stemming ratio of fractured cores in average was 88.7%, and average enhanced oil recovery rate was 12.1%.

Abstract:The shear-stretch action of reservoir pores on weak gel was one of the key factors which influenced the gelling and plugging properties of weak gel when it flowed through the reservoir. The influences of this shear-stretch action on one kind of weak gel (HPAM solution + crosslinking agent) gelling properties were studied in this paper. The affected and unaffected weak gel solution were injected to sand-packed models and the influences of this shear-stretch action on weak gel profile-control properties were evaluated by the index of residual resistance coefficient. The results showed that the original viscosity of weak gel before and after shear-stretch of reservoir pores was 170 and 43 mPa·s, and the viscosity loss rate of gel was 74.7%. Meanwhile the viscous modulus and elastic modulus of the weak gel whose solution was sheared and stretched by pores and gelled in the static condition was reduced maximumly by 18% and 55% respectively, and the strength of gel decreased sharply. Compared with the unaffected sample, the maximum residual resistance coefficient of the sheared and starched weak gel which gelled in sand pack was reduced by 26.9 times in the gel injection part. And the reduction speed of this residual resistance coefficient was accelerated significantly with increasing water injection. The maximum residual resistance coefficient of sheared and starched weak gel in none gel injection part was reduced by 22.7 times. Thus the profile-control properties of sheared and stretched weak gel were significantly weakened by the pores’ shear-stretch action.

Abstract:By screening of the inhibitor, the initiator and the modifier of the channeling sealing agent, a CO₂ gas flooding channeling sealing agent which had excellent properties and was suitable for high temperature and low permeability oil reservoirs was developed. The composition of the channeling sealing agent is as followed: the dosage of AM was 4.5 % (mass fraction), of initiator was 0.25%, of modifier was 0.3% and of inhibitor was 0.5%. At room temperature, the viscosity of the channeling sealing agent solution is 1.1 mPa·s, hence, it was easy to be pumped and injected. At 100℃, the gelling time was controlled within 2.5-12 hours through changing the dosage of inhibitor, and the viscosity was above 120×10⁴ mPa·s accordingly. For the channeling sealing agent in salinity of 57728.92 mg/L, its viscosity was more than 170×10⁴ mPa·s when the pressure of CO₂ reached 8.0 MPa at 126℃. In a sand pack with a length of 120 cm, a diameter of 25cm and the permeability of 1.631 μm², the pressure of injection water is about 0.08 MPa, and the pressure of CO₂ flooding was around 2.2 MPa after gelation. In a word, the system was easy for injection, and had a strong plugging ability for CO₂ gas flooding. The parallel core experiment showed that the system had good performance of sealing channeling for CO₂ and the EOR could be further improved by 5.1%.

Abstract:the Ⅱ reservoir of heavy oil which is a deep buried heavy oil field with active edge and bottom water and high viscosity and so on, almost is in the middle and later stage, however, there are not any effective replacement processes currently. To solve these problems, the mechanism of steam flooding adding urea and foaming agent was studied with the physical simulation. In the experiment, the concentration of urea solution was 25%, the concentration of foam solution GFPA-4B and viscosity reducer DVB-107 was 0.5%, respectively, the permeability measured by water flooding of the sand-pack was 1.83~2.16 μm², the flooding rate was 3.6 mL/min. The results showed that urea solution could significantly improve the displacement efficiency , the cumulative displacement efficiency of the hot water+urea displacement, hot water+urea+foam solution displacement, hot water+urea+foam solution+viscosity reducer displacement was increased by 8.13%, 16.67% and 21.27%, respectively, compared to that of hot water displacement. The displacement efficiency of steam displacement section was also improved by 3.49%—9.41%, the cumulative displacement efficiency of the steam+urea displacement, steam+urea+foam solution displacement, steam+urea+foam solution+viscosity reducer displacement is increased by 3.49%、5.31% and 9.41%, respectively, compared to that of steam displacement. Besides, that the mechanism of steam displacement adding urea and foam solution was studied.

Abstract:Air foam flooding was one of the effective EOR methods. In order to research the mechanism of low temperature oxidation by air injection process, this study was carried into execution. Its main contents included air and formation oil phase behaviors, reaction kinetics of low-temperature oxidation, influencing factors of low temperature oxidation and the reaction path and reaction domain of low temperature oxidation. The results showed that the single degassing volume shrinkage of Huzhuang oil was 10.1126%, and the saturation pressure was 6.36 MPa at 90℃. The volume of oil increased 5.49% when the temperature increased from 90℃ to 150℃ and the pressure was 23.5 MPa. 9.07% air of its own volume could solve in oil and swelling factor was 3.68% at the formation condition (90℃、23 MPa). The reaction of low temperature oxidation between formation oil and air was first order reaction with 5.1×10^-3 h^-1 reaction rate constant, 81.9 kJ/mol activation energy, and 2.85×10⁹ h^-1 pre-exponential factor. The value of activation energy was high, but the activity was lower. Huzhuang oil was provided with the higher consume ability of oxygen. In 96 days, the oil consumed 2.4 times its own volume of oxygen in the air, and the oxygen volume fraction separated from oil was less than 3%. Increasing temperature or pressure, adding clay or formation water could enhance the reaction rate. Temperature was the main factor. Oil oxidation characters depended on its group composition. After the low-temperature oxidation reaction, the relative amounts of saturated and aromatic hydrocarbons reduced, and that of resin, asphaltene and oxygen increased. Formation oil oxidation reaction at low temperature could be divided into two steps, adding oxygen reaction and chain breaking reaction.

Abstract:Based on fatty alcohol polyoxyethylene ether（AEO-3, AEO-5, AEO-7）with different ethylene oxide (EO) structural unit, 1, 2-ethylene glycol, 1, 3-propanediol, 1, 4-butanediol and maleic anhydride, anionic-nonionic Gemini surfactants were synthesized. The structural formula was abbreviated as follows: ANG_n-m-n, n=3、5、7, indicating AEO-3, AEO-5 and AEO-7 respectively, m=Ⅱ、Ⅲ、Ⅳ, indicating the spacer length of ethylene glycol, propanediol and butanediol respectively. The foaming property was determined for the 9 kinds of anionic-nonionic Gemini surfactants of polyalkoxylated ether sulfonate. The results showed that the foaming height increased with increasing spacer length of the Gemini surfactant, when the dosage of surfactant was 0.2% and EO unit was same. The foaming height increased with increasing EO structural unit, when the spacer length was same. In generally, the shorter spacer length, the better stability of foam was. The influence of salt concentration on the foaming properties of ANG 7-Ⅳ-7 was investigated. The foaming height and half-life (t_1/2) increased first and then decreased with increasing salt concentration. When the concentration of NaCl reached 20 g/L, the foaming height was 167.2 cm and t_1/2 was 1163 s. When the concentration of CaCl₂ reached 1 g/L, the foaming height was 161.4 cm and t_1/2 was 1131 s. When the temperature increased, the foaming height increased first and then decreased with 151.5 cm maximum value at 50℃, and t_1/2 decreased gradually. When the volume fraction of alcohol increased, the foaming height and t_1/2 increased first and then decreased. The optimum dosage of ethanol, isopropanol and n-butanol was 4%, 3% and 2%, respectively.

Abstract:According to the foam drainage difficulty for condensate oil-gas well, a kind of long chain alkyl amine oxide OA was synthesized using a long chain alkyl dimethyl tertiary amines as the main raw material and hydrogen peroxide as oxidant. Anticoagulant condensate oil frother main agent ZJ was obtained which introduced a small amount sulfonic acid salts surfactant with synergistic effect. It was compounded with stable foam agent to form a high anticoagulant compound foaming agent. The formula was obtained as follows: 2% ZJ, 0.04% NaOH, 0.03% guar gum. Under the condition of high condensate oil (50%—70%), the foam drainage performance of ZJ was superior to that of common foaming agent UT-11c. When the content of condensate oil was 70% at 70℃, the foaming capacity (initial foam height) of ZJ was 13.7 cm, foam stability (foam height after 3 min) was 9.8 cm, and liquid carrying capacity was 12 mL/15 min. The three data changed to 15.4 cm, 17.8 cm and 60 mL/15 min respectively after compounding. The resistance temperature was 90℃, and salt resisting mass fraction was 8%. This compound foaming agent was successfully applied in two effusion wells with high content of condensate oil (above 50%) of gas condensate in Wubaochang possession. Two intermittent production wells returned to continuous production, and the gas production increased about 40%.

Abstract:At present, the preparation injection technology used in Daqing Oilfield is that polymer solution is prepared with fresh water and then diluted by oil produced water. Oil produced water dilution has a bad influence on the viscosity of polymer solution and flooding effect because of the higher salinity and unqualified water. Use triethanolamine, HEDP, citric acid, sodium pyrophosphate as metal ions screening agent, the performance of increasing viscosity of HPAM solution was studied, as a result, the optimal water-quality-modification treatment agent SY which could increase the initial viscosity and stabilize the higher initial viscosity was developed by mixing triethanolamine, HEDP, citric acid, sodium pyrophosphate and the other additive in mass ratio of 100:60:60:300:150. The results showed that SY has a good viscosity-increasing ability. The viscosity of the HPAM solution prepared with water treated by screening agent SY increased by 28.4 mPa·s, and the viscosity increasing rate reached 43.5%, compared with HPAM solution prepared with water of Daqing Oilfield untreated. After 40 days, the viscosity of the HPAM solution increased by 27 mPa·s, and the viscosity mataining rate increased by 19.53%, compared with HPAM solution prepared with water of Daqing Oilfield untreated. In addition, the mechanisms were analyzed.

Abstract:The apparent viscosity change of polyacrylamide (HPAM) solution with shearing time was studied by control stress rheometer at 30℃ and different shear rate, which reflected the influence law of shear flow conditions on the viscosity of HPAM solution. According to the site conditions, shear rate and shear time of different concentration of HPAM oil displacement agent in pipeline flow were obtained by calculating. The results showed that when the shear rate was 3.11—7.76 s^-1 and shear time was 55—22 min, the viscosity of high concentration (5000 mg/L) HPAM oil displacement agent increased slightly with the extension of shear time. The adhesion loss rate per unit time was -0.43%/h—-0.91%/h. In the process of conveying, pipe flow shear had no effect on the viscosity loss of high concentration HPAM oil displacement agent. When the shear rate was 36.84—92.10 s^-1 and shear time was 2.26—0.90 h, the viscosity of low concentration (1000, 2000 mg/L) HPAM oil displacement agent gradually reduced with the extension of shear time. The adhesion loss rate per unit time was 0.08%/h—0.86%/h and 0.07%/h—0.30%/h, respectively. In the range of low concentration, the influence of shear history on the viscosity and adhesion loss rate of HPAM oil displacement agent increased with decreasing concentration of HPAM flooding agent. Increasing concentration was helpful to reduce the adhesion loss rate of oil displacement agent.

Abstract:The effect of five different kinds of pipes on viscocisy loss of polyacrylamide displacing agent with the concentration was studied in this paper. The results showed that the seamless steel pipe of 20# and the pipe with corrosion protective coating had greater influence on the viscosity loss of polyacrylamide displacing agent, and the viscosity loss rate could reach 60% and 10%, respectively. While GFRP pipe, flexible composite pipe for high pressure and 0Cr18Ni9 stainless steel pipe had smaller influence on the viscosity loss, and the viscosity loss rate was less than 3%. With the higher concentration of polyacrylamide, the viscosity increased and the effect of pipe material on viscosity and the viscosity loss rate tended to be smaller

Abstract:The properties salt tolerance and temperature resistance of the newly-synthesized hydroxyl sulfobetaine surfactant (HSS) were investigated by measuring interfacial tension between HSS solutions and the crude oil from the high-temperature and high-salinity reservoirs of Tuha and Saudi oilfield. The experiment indicated that the HSS solution had the advantage of interfacial property at a certain range of low concentration of 0.3—0.5 g/L without help of alkali and other additives，the interfacial tension was reduced to ultralow value (≤10-3 mN/m). The SHH could make the dynamic interfacial tension decrease to be ultralow at a wide temperature range of 40—100℃. The highest salinity resistance of Tuha/Saudi crude oil and water system was up to 270 g/L and 200 g/L, respectively, thereinto, the highest Ca2+ and Mg2+ resistance was up to 19 g/L and 23 g/L. In addition, the SHH possessed good heat resistance within 90 d.

Abstract:For the characteristics of water injection pressure rising fast and difficultly injecting in the water injecting process in Chao Yanggou low permeability oilfield, the lowering pressure and increasing injecting surfactant system was screened and the recipe of surfactant system was determined as follows:0.2% Petroleum sulfonate salts surfactant T702-40# surfactant+ 0.5% Na₂CO₃. The experimental results indicated that the equilibrium interfacial tension between the surfactant system and the Chao Yanggou crude oil could reach 2×10^-2 mN/m, the of the surfactant system had good temperature resistance and salinity resistance, and had good compatibility with injecting water and formation water, and could make the rocky wettability reverse, which make the oil recovery be improved by about 5%. The movable permeability value calculated from the surfactant system flooding was 15% bigger than that of water flooding, which could reduce start-up pressure obviously. And the mechanism of surfactant system reducing start-up pressure was researched. Field test results of 82-152 well area in Chao Yanggou oilfield indicated that the surfactant system could reduce start-up pressure, improve reservoir water absorbing capacity, increase producing proportion of low permeability reservoir, and cumulative oil increment of 7 wells was 1768 t.

Abstract:The optimal formula and thermal stability, repetitious adsorption capacity, core displacement experiment of surfactant/polymer (SP) and alkali/surfactant/polymer (ASP) combinational flooding system were studied for ultra-high water cut reservoirs in IV5-11 layers Shuanghe oil filed. The experimental results showed that the optimized SP system and ASP system, composed of 2000 mg/L surfactant SH6+1500 mg/L polymer ZL-II, 8000 mg/L Na₂CO₃ +2000 mg/L surfactant SH6+1500 mg/L polymer ZL-II，respectively, had high viscosity(74.6 mPa·s and 46.5 mPa·s, respectively) and ultra low interfacial tension properties(3.64×10^-3 and 3.89×10^-4 mN/m, respectively). Compared with SP system, the interfacial tension of ASP system had a magnitude of decline, and the viscosity of ASP system decreased by 37%. With the condition of 81℃ aging for 120 days, ASP system had higher viscosity retention rate and lower interfacial tension compared with that of SP system, indicating that ASP system possessed more superior thermal stability. After repeatable adsorption at natural oil sand for five times, the interfacial tension between ASP system and the crude oil increased from 3.63×10^-4 mN/m to 4.67×10^-3 mN/m, still being ultra low order of magnitude. The heterogeneous core displacement experiments showed that ASP compound flooding after water flooding finished, the enhanced oil recovery were 3%—5% higher than that of SP compound flooding. Therefore, ASP compound flooding was applied in IV5-11 layers Shuanghe oil filed as a replacing technology at ultra-high water cut stage. Through about two year’s field test, good effect of increasing oil and decreasing water appears.

Abstract:Alkali/surfactant/polymer (ASP) flooding can enhance oil recovery greatly, but the scaling problem restricts its large-scale application. The experiments were performed on reservoir rocks in Daqing Lamadian Oilfield and ASP system, visual research on rock structure after alkali flooding and research on alkaline driving agent flowing property were carried out in this paper. The microscopic experiments results showed that, alkali mainly dissolved clay minerals and had little impact on feldspar framework. The flow experiments results showed that in produced fluid, the concentrations of calcium ion and magnesium ion were low and had little impact on the core penetration, the concentration of silicon ion was high and deposition easily during migration would form a large of silicone scale in layer and production systems. Further analysis of the results showed that the damage of ASP flooding to the reservoir rock became severer as alkali concentration increasing, both surfactant and polymer could reduce dissolution, however, the effect of the former was weaker.

Abstract:Maleic acid polyether ester(Ester-61) was synthesized from polyether glycol(L61) and maleic anhydride(MA) with p-toluenesulfonic acid as the catalyst. The reaction conditions were studied by orthogonal experiment. The results showed that the optimum reaction conditions were as follows, the mass ratio of L61 to MA was1.5:1, the content of p-toluenesulfonic acid was 1.8%, the reaction temperature was 150℃ and the reaction time was 8 h. A novel comb-like bicomper(DEMU-L61)with hydrophilic side chains was synthesized from Ester-61 and allyl polyethylene glycol(XPEG-1000) using benzoyl peroxide(BPO) as the initiator by free radical solution copolymerization when the mass ratio of Ester-L61 to XPEG-1000 was 1:0.9, the content of BPO was 1.0%, reaction temperature was 120℃ and reaction time was5 h. IR and NMR analysis showed the synthesized product was a target product. The DEMU-L61, obtained under the optimum conditions, had a good performance in the demulsification of crude oil from Yanchang oilfield Eastern district, the demulsification rate being about 99%, the purification oil content being less than 0.5% water.

Abstract:AVS Diesel Fuel pour point depressant, n-alkyl acrylate-vinyl acetate-styrene terpolymers with different alkyl chain length，named as AVS-12, AVS-14, AVS-16 and AVS-18 according to alkyl chain length, were synthesized by radical polymerization, and the effect of the systems on the solidifying point (SP) and cold filter plugging point (CFPP) of diesel fuel was determined. The content and the carbon number distribution of n-alkanes in diesel fuel were analyzed by gas chromatograph; the rheological behavior and crystallization behavior of diesel fuel treated with and without additives were studied using an advanced rheometer and an optical microscope. The results demonstrated that the terpolymer whose alkyl chain length was close to the average carbon number of n-alkanes in diesel fuel had the best effect on reducing the SP and could reduce the SP by 12℃. The terpolymer which made the wax crystals more dispersed and evenly had the best effect on reducing the CFPP could reduce the CFPP by 4℃. The size, shape and aggregation of wax crystals directly affected the CFPP of diesel fuel, while the formation of three-dimensional network played a decisive role on the SP, thus a good diesel pour point depressant should be adverse to the formation of three-dimensional network and detrimental to the formation of too large wax crystals or wax crystals tending to form large clusters.

Abstract:In view of the oilfield water scaling problems, the scaling tendency, scaling component and core damage rate experiments were studied through indoor static analysis and the core flow experiment. The results showed that the main component of the scale was iron hydroxide, barium carbonate, calcium carbonate and a little magnesium carbonate. Static damage rate of scaling was 9.6%, and dynamic damage rate was 34.3%, and the damage rate of iron deposition was 56.7%. Hence, it is important to research on the compatibility of raw water and formation before injection raw water, which could reduce reservoir damage to the lowest limit and improve the development effect of oil field.

Abstract:Dealing with the polymer flooding sewage and injection to the stratum in LD10-1 oilfield is the important guarantee for developing of the oilfield, using a nonionic purifying agent BHQ-402, the treatment effect of the dosage, stirring speed, stirring time and other factors, were investigated. The results showed that, when the BHQ-402 was diluted to mass fraction of 1% with fresh water, the degreasing and cleansing effect was good at the BHQ-402 amount of 500 mg/L, pharmacy reaction of 200—400 r/min, and stirring time of 2—3 min. Oil removal rate was up to 83.69%, and turbidity removal rate was as high as 92.74%.When the BHQ-402 was first dissolved with ethyl alcohol and then diluted to mass fraction of 1% with fresh water, when the BHQ-402 amount was 200 mg/L, stirring speed was 400 r/min and stirring time was 3 min, the degreasing rate was greater than or equal to 87%, and the turbid rate was greater than or equal to 92%. The BHQ-402 addition amount was less, while the treated water quality indicators were increased greatly.

Abstract:The oily sludge originated from Suizhong36-1 oilfield, was composed mostly of 77.21% formation water, 9.12% crude oil and 13.67% other solid matter with peak size about 250 μm, d₁₀=30.33 μm, d₅₀=176.94 μm, d₉₀=530.51 μm. The size of solid particles was reduced to meet the requirements of reinjection (d90<50 μm) by flexible grinding device. An effective reinjection system was formed by oily sludge and hydrophobic associating polymer AP-P4 solution (1750 mg/L), which eventually achieved the harmless disposal and resource utilization of oily sludge in the polymer flooding process. In this paper, the influence of oily sludge on the properties of oily sludge reinjection system was studied. Experiment results showed that the apparent viscosity of reinjection system increased with increasing dosage of grinded oily sludge (<1500 mg/L), and the viscosity increase was more than 90% in the range of 30—250 mg/L with a stationary phase over 120 h. With an overdose grinded oily sludge (3000 mg/L), the apparent viscosity of reinjection system reduced sharply by 37.28%, and appeared lower viscosity and poor stability with the extension of standing time. Adding a small amount of oily sludge (<250 mg/L) could improve the shear resistance of reinjection system, and its shear stress was higher than or near to the value of AP-P4 solution without oily sludge. While excessive oily sludge (3000 mg/L) significantly decreased the shear viscosity of reinjection system, and its shear stress increased with increasing shear rate, but was lower than that of AP-P4 solution without oily sludge. Moreover, when the shear rate was higher, the difference was more obvious. With a little dose of grinded oily sludge (<750 mg/L), the gel strength of reinjection system were enhanced, and G′/G″ was much larger than that of AP-P4 solution without oily sludge. While excessive oily sludge (3000 mg/L) drastically enhanced flocculation sedimentation and led to stratification in reinjection system, which ultimately resulted in a rapid increase of G′/G″ at high frequency, and even was higher than that of reinjection systems with other concentration.

Abstract:The determining reliability of partially hydrolyzed polyacrylamide (HPAM) concentration which existed in injection fluid and produced fluid was analyzed by liquid chromatography (HPLC) in the process of oilfield production. The influence factors of concentration determination by HPLC, including relative molecular mass, degree of hydrolysis, and production batch of HPAM, shearing time, solvent and surfactant KPS, was studied. The experiment results showed that hydrolyzing degree and production batch of HPAM, and water preparing HPAM solution had a significant impact on the test results. The greater degree of hydrolysis, the smaller slope of standard working curve was. The standard working curve slope of the production in 2011 was less than that of the production in 2009. The standard working curve slope of HPAM sewage solution was bigger than that of HPAM clean water solution. To make sure the accuracy of results, corresponding standard curve according to different sample should be built. Diluting the sample could reduce the influence of clean water and waste water on test result. The factors such as relative molecular mass of HPAM, shearing time and 0—0.3% KPS had a little effect on test results.

Abstract:Chemical agent loss degree had direct effect on the utilization efficiency of Chemical slug. Previous studies mainly focused on static chemical agent adsorption degree on rock surface. Factors of influencing chemical agent loss degree could not be fully considered by this way. To solve this problem, the changes of surfactant and NaOH mass fraction, composition of surfactant and interfacial tension were systematically investigated after the adsorption of alkali/surfactant/polymer (ASP) system in multiple oil sand and crude oil. The composition of ASP was obtained as follows: 1.5 g/L hydrolyzed polyacrylamide (HPAM), 0.3% ceiling mass fraction of surfactant, and 1.2% ceiling mass fraction of NaOH. The results showed that both rock surface adsorption and oil phase adsorption not only reduced the mass fraction of surfactant and NaOH, but also change the composition of surfactant, and eventually led to the changes of interfacial tension between ASP system and crude oil. The mass fraction of surfactant decreased from 0.28% to 0.02%, and that of NaOH decreased from 1.10% to 0.71% for ASP system after 7 times oil sand adsorption. In addition, the interfacial tension between ASP system after 5 times oil sand adsorption and crude oil could not be reduced to 10^-3 mN/m order of magnitude. For ASP system after mixing with the crude oil, the mass fraction of surfactant decreased substantially and the largest decline reached 50%, while the molecular weight of surfactant obviously increased. Compared with surfactant, the mass fraction variation of NaOH was smaller with largest fall of only 15.22%. The interfacial tension between ASP system after 3 times oil sand adsorption and crude oil greatly increased which could not be reduced to 10^-3 mN/m order of magnitude after mixing with the crude oil. In order to comprehensively evaluate the changes of above properties, a new evaluation method was proposed which combined multiple sand adsorption with crude oil adsorption.

Abstract:CO₂ flood had been used successfully to recover crude oil from reservoirs over 60 years. Theoretically microscope displacement efficiency was approaching 100%. However, low viscosity and density of CO₂ compared with crude oil and reservoir heterogeneity resulted in viscous fingering and gravity segregation, which caused poor sweep efficiency. Different methods of mobility control in foreign countries were reviewed including water-alternating-gas, direct thickening CO₂ by polymer, CO₂-foam flooding, combined gas with chemicals and gas assisted gravity drainage. Other methods about improving sweep volume had also been introduced briefly. Mechanisms of these methods and their advantages and disadvantages were analyzed. The goal was to gain advanced approaches and experience for further improving sweep volume for CO₂ flood in China.

Abstract:Categories and research progress of profile control and displacement with foam were summarized. The mechanism of profile control and displacement with all kinds of foam was analyzed, the synergetic mechanism of profile control and displacement with foam and other chemical agent was also analyzed. The disadvantages of profile control and displacement with foam were pointed out in mechanism research and field application at present, and its development directions was proposed.

Abstract:As a kind of compressible non-Newtonian fluid, foams have been widely used in drilling, stimulation of wells, well workover, EOR and so on. Nanoparticles, as an emerging material to stabilize foam, can significantly improve the stability of foam. In this paper, the mechanisms of the nanoparticles in the foam stability was mainly discussed from three aspects, including the interaction between nanoparticles and interface, influencing factors of single hydrophobic particles in stabilizing foams, synergistic stabilization of foams by a mixture of hydrophilic nanoparticles and surfactant. In addition, the prospects and direction of nanoparticles for stabilizing foams were also discussed.

Abstract:As far as the disposal of heterogeneous reservoir is concerned, self-diverting acidizing technique is burgeoning one for reservoir reconstruction problem. In the paper, the species and types of viscoelastic surfactants (VES) used in self-diverting acid were summarized by investigating the research status and the latest development of self-diverting acid system. The performance differences of cationic viscoelastic surfactant, amphoteric viscoelastic surfactant, nonionic viscoelastic surfactant and Gemini viscoelastic surfactant based self-diverting acid systems were analyzed systematically. The applied scope of different types of self-diverting acid system was determined and present problems were pointed out. In addition, research direction and development prospect of self-diverting acid system were forecasted.