Abstract:Serious mud losses happened at Huaqing oilfield due to the induced fractures. The current bridging plug agent is poor adaptable to the fracture and pore size. the bridging material, polymeric adsorbent materials and filler material and particle size distribution were optimized, as a result, the bridging materials were compounded of the rubber particles with different particle size, which the percentage of particle diameter of 0.6—1.0 mm, 1.1—1.5 mm and 1.6—2.0 mm was 30%, 30% and 40%, respectively. The polymer adsorption materials was CDL-1. the filling material consisted of 30% vermiculite with particle diameter of 0.4—0.5 mm, 5%—10% of mica, 5%—10% of sawdust, 20%—25% of the bridge plug agent QD-1, 20%—30% of QD-2 and 10%—20% of the one-way pressure sealer DF-A. By orthogonal experiments, the plugging drilling fluid adaptable to leakproof was determined by adding 2% rubber particles, 0.2% CDL-1 and 3% fill material in the base slurry (water+0.3% PAM +4% bentonite). The viscosity of the drilling fluid was of 10 mPa ? s, the yield point was of 3 Pa, the pressure capacity was of 4 MPa and the minimum closure time was of 10 min. The field test proved the drilling fluid could seal the lost layer in a relatively short time effectively.

Abstract:In order to study the relationship between the structure and properties of the copolymer thinners, SSMA and AMA thinners were synthesized using sodium p-styrene sulfonate, maleic anhydride and acrylic acid as raw materials, ammonium persulfate (APS) as initiator. The viscosity reduction performance, temperature resistance and salt tolerance of them were investigated. The results showed that SSMA and AMA, with sulfonic acid group and carboxyl group respectively, could efficiently break the links between clay particles in the drilling mud, leading to the decline of the viscosity and the shearing force. While the behaviors of SSMA and AMA became complicated at high temperature or with adding certain amount of NaCl and CaCl2 into the drilling mud. Compared with SSMA, AMA showed the better thinning performances in both fresh-water and saline-based drilling fluid and played more effectively role in the calcium-based mud with lower dosage range(≤0.3%) , but when the dosage was higher than 0.3%, the property of viscosity reduction of AMA became worse even increased the viscosity. The drilling fluid treated with SSMA showed the poorer resistance to NaCl pollution and stronger resistance to CaCl2. The performance of high temperature resistance of AMA was better than that of SSMA.

Abstract:In the operations acidification, the Fe3+ easily forms Fe(OH)3 precipitation which cause secondary damage of strata. Self-made synthetic ferric ion stabilizer SWLY-1 with ferric ion can form a stable soluble chelate. In this paper, the relative property of SWLY-1 was investigated. The results showed that the ability of stability stable ferric ion of SWLY-1 of 1435 mg/g. The maximum resistance of SWLY-1 to high temperature was of 150℃ and the solubility was good in water, 20% hydrochloric acid, mud acid（12%HCl+6%HF）.The damage of SWLY-1 on the core permeability was low, and it had good compatibility with other acid additives. With the stability constants at different pH values as evaluation index, several ferric ion stabilizers including SWLY-1, EDTA-2Na, citric acid, oxalic acid and acetic acid, was arranged as follows: SWLY-1>EDTA-2Na>citric acid>oxalic acid > acetic acid.

Abstract:The rheological properties of self-diverting acid system with erucylamide betaine viscoelastic surfactant as main reagent were studied. By the experiments of steady shear flow, the constitutive equations of fresh and residual acid systems were obtained as follows: σ =0.0893γ0.803 （R2=0.967）and σ =6.30γ0.383（R2=0.983）, which were in line with the power-laws equations for non-newtonian fluids. The viscosity of two acid systems reduced rapidly with increasing shear rate. Under shear rate of 100 s-1, the viscosity platform value of fresh acid was about 40 mPa·s, and that of residual acid was about 150 mPa·s at 400 s-1. The thixotropic experiment results of two acid systems showed that at low shear rate, the viscosity on downline of fresh acid system was higher than that on upline, which indicated the composite thixotropy. For residual system, the area of thixotropic loop was small which indicated good recovery of structure after shear. The small oscillation experiment results showed that in fresh acid system, storage modulus (G') was bigger than loss modulus (G''), and the curve of G'—G'' basically exhibited in beeline. However, in residual acid system, G'' was bigger than G', and the curve of G'—G'' was in line with Cole-Cole diagram of Maxwell model at low frequency, which suggested a linear viscoelastic behaviour with a single relaxation time. Whereas, under high frequency, the curve of G'—G'' showed linear trends, indicating a complex viscoelastic behaviour.

Abstract:The gravel fill sand control technology of viscosity steady acidizing fluid was researched in view of the problem that the conventional acid treating had easily caused reservoir sand production and immediate vicinity of wellbore blocking. The formula of the NWS-Ⅰacidizing fluid system was obtained as follows: 6% HCl, 3% ZNW, 0.1% HPAM, 0.05% aluminium citrate (YL-1), 1% ammonium chloride, 1% ion stabilizers, 1% XP inhibiter, 0.5% CF-5B cleanup additive. After the core was treated by viscosity steady acidizing fluid, the dissolution rate of core decreased from 1.58% to 0.55%. The exit pH value was about 4.7, and the effective distance was more than 2.0 m. The subsidence time of gravel in viscosity steady acidizing fluid was longer than 10 min. The sand mixed uniformly, subsidence velocity was homogeneous. The retention rate of viscosity was up to 83.3%, 68.7% and 59.7% respectively, when the acidizing fluid was sheared at 30, 60 and 80℃ with 120 min, which had a good rheological behavior. When the concentration of acidizing fluid increased from 200 to 1000 mg/L, the damage rate of core increased from 0.6 to 1.27, which had little damage to formation. Compared with mud acid, viscosity steady acidizing system could restrain second sediment better. Field test in Shengli oilfield indicated that the productivity of five test wells increased 1.54times, construction success rate was 100% and valid period was long.

Abstract:In order to meet the requirements of integrated technology of water plugging and acidification, the cationic polymer thickener with 800—12 million molecular weight was synthesized in laboratory by the method of polymerization in solution using acrylamide, dimethyl diallyl ammonium chloride and methyl propenyl acyloxy ethyl three alkyl ammonium chloride. Indoor evaluation experiment results showed that the optimum dosage of thickener was of 1.0% and the soluble time of thickener was of 30 min in 5% and 10% HCl solution. When 5% and 10% HCl solutions were taken as a contrast to analysis the thickener performance, the initial viscosity of acid system was of 31.0 mPa·s and 26.8 mPa·s, respectively. After refluxing 1 h at 72℃, the viscosity loss rate was of 21.94% and 32.46%, and that was of 39.67% and 36.12% after soaking 48 min in acid. But after cross-linking reaction, gel viscosity was more than 100 Pa·s, and gelation time was less than 8 hrs. Salt resistance experiment results showed that the soluble time extended with increasing salinity, but the initial viscosity of acid system, the viscosity of gel and gelation time were not affected. The thickener could meet the requirements of integrated technology of water plugging and acidification.

Abstract:With the fracturing treatment of deep wells and high-pressure wells at home and abroad, weighting of fracturing fluid had become the necessary measures of reducing pressure in fracturing operation. And the commonly aggravating materials were inorganic salt, such as NaCl and NaBr. The effect of NaCl and NaBr on the properties of fracturing fluid was studied. The results showed that the viscosity of fracturing fluid increased exponentially after inorganic salt added. The fluid capability of temperature-resisting and shear resistance raised. The viscosity of fracturing fluid contained 14% NaCl and 14% NaBr was 200 mPa·s and 300 mPa·s respectively with 130℃ temperature, 170 s-1 shear rate and 120 min shear time. However, that of non-aggravating fracturing fluid dropped to 100 mPa·s after 70 min. Inorganic salt could reduce the fracturing fluid loss at high temperature, but would lower its viscoelastic. After aggravating, gel breaking became relatively difficult and the gel breaking dose increased. The effect of 30% NaBr fracturing fluid mixing 0.3% APS above could equal to that of the non-aggravating fracturing fluid mixing 0.05% APS at 125℃. In low shear rate, the friction of aggravating fracturing fluid was on the high side relatively. But with increasing shear rate, the friction of aggravating fracturing fluid would lower than that of non-aggravating fracturing fluid.

Abstract:The foam discharging agent composed of oxidation amine (A) and synthetic amphoteric surfactants (B) as the main agent and special surface-active agent (C) as stabilizer was studied. With the Ross-Miles method, using the sparkling height and the fluid volume as evaluation index, the optimal ratio of A, B and C were determined, and the relative properties of foam discharging agent with 8:2:1 of A: B: C, named as FHG-1, were tested. The results indicated that, at the temperature of 30℃, 5 min foam height and fluid amount of FHG-1, was 110 mm and 116 mL in the water containing 20% oil, and was 170 mm and 176 mL in the water containing 20% ethanol, respectively, which indicated that FHG-1 had excellent oil resistance and methanol tolerance ability. In addition, the compatibility of FHG-1 with formation water As a result, the foaming agent FHG-1could be used in the gas well containing oil and ethanol。

Abstract:According to the reservoir petrophysics, heterogeneity and fluid property in Gaoqianbei area of Jidong oilfield, the gelation ability of phenolic resin cross-linked polymer solution was evaluated. A series formula that controlled the gelation time and strength was formed by adjusting the amount of polymer and crosslinking agent. The viscoelasticity of gels with different concentration were measured. The movement-detention law in the porous media of the gel was explained and its effect of oil displacement was evaluated. The results showed that the phenolic resin cross-linked polymer had a good viscoelasticity feature, and the gel viscoelasticity was obviously affected by the concentration of polymer and crosslinking agent. The gel system could displace the oil finitely by migrating-plugging-remigrating-replugging in the formation and contribute to the deep profile control and flooding. When the gel with 0.3 times of high permeability pore space volume was injected, the oil recovery increment of per unit plugging agent was the highest (80%). When the water-cut was between 35% and 80%, the final recovery after the profile control was up to 32.8%—35.9%.

Abstract:Considering the evaluation indexes of foaming capability, foam half-life time and interfacial tension, CEA/FSA1 and CEA/DHF-1 in mass ratio 7:3 were firstly chosen as two kinds of mixed foam systems in the simulated water-oil condition of Gaoqianbei reservoir of Jidong oilfield. The comprehensive properties of CEA/FSA1 and CEA/DHF-1 was good with 152 mL and 140 mL foaming volume, 72 min and 63 min half-life time, 21.144 and 19.881 dimensionless filter coefficient, and 10-3 magnitude interfacial tension, respectively. The foam performance evaluation experiments showed that the foaming volume decreased to 110 mL, the half-life time decreased to 40 min, and the dimensionless filter coefficient decreased to 1.180 when CEA/FSA1 reacted with Jidong oil. Compared to CEA/DHF-1, CEA/FSA1 had better oil tolerance, temperature tolerance and aging resistance ability. It was recommended as foam agent for natural gas foam flooding in Gaoqianbei reservoir of Jidong oilfield and the dosage was of 0.5%. The single tube blocking experiment showed that the resistance factor of CEA/FSA1 was of 127, which meant CEA/FSA1 had good plugging performance. When CEA/FSA1 was mixed with Aisen polymer, the resistance factor of enhanced foam system was of 438, which meant the compatibility of CEA/FSA1 and Aisen polymer was good. In double tube displacement experiment, the recovery ratio of enhanced foam flooding increased by 22.9% and that of high and low permeability tubes increased by 18.8% and 27.0% respectively after water flooding.

Abstract:Performance characteristics of partially hydrolyzed polyacrylamide（HPAM）and the pecial viscoelastic Cr3+ cross–linked polymer（CLP, Cr3+ as the cross linker）solution were investigated by the measurement of the viscosity, viscoelasticity, polymer coil dimensions, molecular configuration, flow characteristics, and profile modification using the Bush viscometer, rheometer, dynamic light scattering system and core flow device. The results showed that, under the same polymer solution, intra-molecular cross–linking reaction and inter-molecular cross-linking reaction could take place when the cross-linking agent concentration was proper. The intra-molecular cross-linked would make the viscoelasticity of the system increase obviously. Compared to the polymer solution with the same concentration, the viscosity of intra-molecular cross-linking polymer gel was similar, while the viscoelasticity were a little bigger, and the d rag coefficient increased by 50 times, and the residual resistance coefficient increased more than 100 times, and the oil recovery of the intra-molecular cross–linking polymer gel increased by 6.2%.

Abstract:Using dissipative particle dynamics simulation, the viscosity of hydrophobically associating polymer (HAP) solution was studied with different concentrations, temperatures and shear strengths respectively, and the assembly behavior was also simulated in water-oil system. It was found that the assembly behavior of HAP was similar to surfactant. The change of viscosity was attributed to different assembly structure. Lower viscosity was due to intramolecular associating of HAP, and higher value derived from lower diffusivity of water beads was for the spatial network forming by intermolecular associating with the increase of polymer concentration. Also, the structures of system changed from columned assemblies to spherical ones when the temperature increased, which exhibited lower viscosity and higher diffusivity of water particles. With increasing shearing rate, the macromolecules were realigned along the shear stress and the associated degree of polymer fell sharply, and the viscosity thus decreased. Meanwhile, HAP could easily absorb at water-oil interface, and influence their emulsification and phase transition.

Abstract:Hydrophobically associating polyacrylamide (PAMBA) modified with long fatly chain prepared by free radical polymerization of octadecyl acrylate (ODA), acrylamide (AM), 2-acrylamido-2-methyl propane sulfonic acid (AMPS) and acrylic acid (AA). The effect factors in the process of polymerization were discussed, and the optimum copolymerization conditions were determined, and the performances of PAMBA were characterized by infrared spectrum (FT-IR), X-ray diffraction (XRD) and transmission electron microscope (TEM). The results showed that the optimal reaction condition was obtained with the viscosity value as evaluation index, the monomer content of ODA, AMPS and AA was 0.6%, 20% and 10%, respectively, and the initiator dosage was 0.3%. At room temperature and shear rate of 170 l/s, the viscosity of the 0.2% PAMBA solution was 56.2 mPa·s. There were strongly intermolecular hydrophobically associating interactions in the PAMBA aqueous solution.

Abstract:Interfacial dilatational rheology of the interface between ORS-41 surfactant solution and Zhuangxi crude oil was investigated by small periodic oscillation method at 55°C using DSA100 interfacial dilatational rheometer. The influence of experiment conditions and surfactant on interface properties was studied by measuring the parameters of interfacial dilatational modulus, interfacial elastic modulus and interfacial viscous modulus. The results showed that the droplet size and amplitude had slight influence on the experiment results. The main relaxation process which occurred on the interface was diffusion relaxation. Dilatational modulus, elastic modulus and viscous modulus increased with increasing oscillation frequency. The appropriate experiment condition was obtained as follows: 0.01% mass fraction of ORS-41, 1 μL amplitude of oil drop, 10 s oscillation period and 300 s equilibrium time of surfactant. The interfacial film could be seen as elastic film without ORS-41, and elastic modulus and dilatational modulus was 2.8409 mN/m and 2.8490 mN/m respectively, while viscous modulus was approximately zero. Dilatational modulus and elastic modulus of the interface film decreased sharply to 0.1503 mN/m and 0.1786 mN/m after adding ORS-41, but viscous modulus increased at first then decreased.

Abstract:N, N-bis(dodecylamidoethyl)-carboxybetaine was prepared using sodium chloroacetate and N, N-bis(dodecylamidoethyl)-N-methylamine, which was synthesized by amidation and methylation reaction from dodecanoic acid and diethylenetriamine. And its chemical structure was confirmed by FT-IR and ESI-MS spectrometry. The results showed that N, N-bis(dodecylamidoethyl)-carboxybetaine had superior surface and interfacial activity, with 1.2×10-5 mol/L critical micelle concentration (Ccmc), and 25.38 mN/m the lowest surface tension (γcmc) at 25℃. The minimum area per surfactant molecule at air/solution interface was of 0.28 nm2 at saturated adsorption, which was less than N, N-didodecyl-N-methyl-carboxybetaine. The product had a good tolerance to electrolytes, while 0.01 mol/L NaCl had little effect on Ccmc and γcmc. When N, N-bis(dodecylamidoethyl)-carboxybetaine was mixed with other surfactants, the interfacial tension between Daqing crude oil and connate water reduced to 7.16×10-4 mN/m at 45℃ over a wide surfactant dosage range from 0.05% to 0.3% without adding any alkaline agent.

Abstract:The emulsifying and rheological properties of polymer surfactant Ⅲ and BⅢ were investigated and compared with that of hydrolyzed polyacrylamide （HPAM）at Daqing reservoir condition. Meanwhile, the mechanism how the functional monomers enhanceed the solution properties of polymer surfactant were discussed. The experiment results showed that polymer surfactant had better emulsifying performance, viscosifying capacity and elasticity than HPAM had. At the concentration of 1000 mg/L, the emulsion formed with polymer surfactant Ⅲ（is 5% after 4 hours）was more stable than that with HPAM, the separated water was 5% and 100% after 4 hours, respectively. At the concentration of 1600 mg/L, the viscosity of polymer surfactant Ⅲ solution（63.5 mPa·s） was higher than HPAM solution（44 mPa?s）at the temperature of 45℃and the shear rate of 7.34 s-1, with the same viscosity of 20 mPa?s, it was found that the storage modlus and the hystersis area of polymer surfactant Ⅲ>polymer surfactant BⅢ>HPAM. The interaction between polymer surfactant withβ-CD and SDBS were investigated, as a result, it was found that there was strong hydrophobic associating effect in the polymer surfactant solution. The critical associating concentration（CAC）of polymer surfactantⅢ and polymer surfactant BⅢ was 811 mg/L and 852 mg/L, respectively. By introducing functional monomers, polymer surfactants had better viscosifying capacity, elasticity and emulsification performance.

Abstract:According to single factor experiments, the surfactant system CQBH-1 was obtained by compounding heavy alkyl benzene sulfonic acid sodium (A1) with isopropanol (CH-2), Isomeric alcohol ethoxylates (F-2) and Gemini surfactant (GL-2) in mass ratio of 3:6:2:2, the price of which is lower than commonly used surfactants in oil field by more than 20%. The compatibility, adsorption and displacement experiments were conducted. The results showed that the interfacial tension between CQBH-1 solution with mass fraction 0.3%~0.5% and the simulated crude oil of Changqing oilfield was 5×10-3—8×10-3 mN/m. CQBH-1 had good compatibility with Changqing oilfield injected water, formation water and simulation crude oil in normal pressure and at the temperature of 60℃, and had good resistance to adsorption. After static adsorption, the interfacial tension between CQBH-1 solution with mass fraction of 0.3%—0.5% and the simulated oil could reach super-low interfacial tension. Core displacement experiments showed that on the basis of water flooding of average oil recovery of 56.70%, the oil recovery of the artificial cores with permeability of 1.1×10-3—100×10-3 μm2 could be enhanced by 10.48% through injecting 0.3 PV of CQBH-1 surfactant solutions.

Abstract:Aimed at the 80℃ high temperature reservoir after polymer flooding, Petroleum sulfonate 1# was chosen and used for the surfactant/polymer (SP) system. The effects of surfactant concentration, polymer concentration, salinity and fresh water on interfacial tension were studied, and then the long period heat resistance of the SP system, adsorption of surfactant on the Shuanghe oil sand, injectivity was studied and oil displacement experiments were carried out. The results showed that the surfactant 1# had a very good interfacial activity. The interfacial tension between the SP system and the crude oil could be reduced to ultra-low (10-3mN/m) when the concentrations was of 0.1%—0.5%. The polymer had little effect on it. The SP system had good salt tolerance and thermal stability, the interfacial tension could keep 10-2 mN/m after kept in 80℃ drying oven for 90 days. The surfactant adsorption of the SP system was lower than that of single surfactant on Shuanghe oil sand. The SP system had a good injectivity. The core flooding test showed that low interfacial tension system could enhance the higher oil recovery efficiency. The system composed of polymer concentration 1800 mg/L and surfactant concentration 3000mg/L could enhance the oil recovery of 10.26% after polymer flooding.

Abstract:The profile control characteristics of modified starch gel system were studied by monolayer homogeneous core model and parallel sand filling tube model. The gel composed of 4% modified starch, 4% acrylamide monomer and gelatinizing control agent in appropriate proportion. The results showed that the injection performance before gelling was good and the residual resistance factor was 834—2548 after gelling, breakthrough pressure gradient was greater than 50 MPa/m as well as the sealing rate was greater than 99%. So water channeling problem could be solved effectively. The influence of three flooding methods on enhanced oil recovery was evaluated based on double-layer inhomogeneous core model. The oil recovery ratio of ternary flooding including 0.3% polyacrylamide, 0.3% sodium alkyl benzene sulfonate and 0.1 g/L NaOH, 0.3% polyacrylamide flooding and water flooding was 20%, 17% and 10%, respectively. Residual oil in high permeability layer would be further produced by modified starch gel system. After gelling, oil in low permeability layer would be produced effectively by ternary flooding system. The recovery ratio increased 37% by combining modified starch gel system and ternary flooding.

Abstract:Emulsifying types and emulsifying degree of ASP system seepage flow in porous media impacted the injection ability and flooding efficiency of the system. The passage adopted a 90 cm homogeneous core model with two sampling windows in the middle. The emulsion forming rule of ASP system consisting of hydrolyzed polyacrylamide(relative molecular mass 2500×104 ), petroleum sulfonate surfactant and Na2CO3 and Daqing oil seepage flow in the core was studied, which was under the condition of medium and high water ratio. The permeability of low, medium and high-level was approximately 300×10-3、1500×10-3、2500×10-3 μm2. The results showed that in middle moisture (60%—80%), ASP system injection of starting to emulsify was 0.3, 0.4 and 0.84 PV, and that of having good emulsifying effect was 0.48, 0.6 and 0.94 PV respectively, where was 30, 60 cm from low permeability cores entrance and exit. In high moisture (85%—95%), compound system injection of starting to emulsify was 0.41, 0.49 and 0.86 PV, and that of gaining good emulsifying effect was 0.49, 0.63 and 0.97 PV respectively in same pressure points. The emulsion laws of medium and high permeability cores were similar. When water ratio was the same, ASP system in low permeability rock appeared emulsion first. When the injection was about 0.8 PV, emulsify appeared in rock export with deeper color emulsion and good emulsion effect. In high permeability rock, the time of appearing emulsion was late. When the injection was about 1.0 PV, emulsify appeared in rock export with lighter color emulsion and bad emulsion effect. When the core permeability was the same, the emulsification of ASP system would appear earlier and the emulsifying effect was better under medium water ratio.

Abstract:In this paper, the adhesive bacteria isolated from the production water in Daqing oilfield was used to investigate the movement of bacteria and the hydrocarbon adhesion by the method of microscopic observation and micro- bial adhesion to hydrocarbons (MATH) method. The results showed that the oil adhesive effection of adhesive bacteria could be formed within 10 min, at the same time, the chemotaxis phenomena could be observed notably. on logarithm growth phase of bacteria, the average surface hydrophobicity value of the strains PR-1、1507、12-J to xylene, hexadecane, dodecane and cyclohexane, were 83%、56% and 21%,respectively. A certain concentration of organism A (biological surfactant) and B(chemical surfactant) played an significant role on the microbial chemotaxis and adhesive effection. After adding 0.01 mol/L of A or B, The surface hydrophobicity value of strain 12-J was increased from 18% to 70% and 85%, respectively, which obviously stimulated the chemotaxis movement of the adhesive bacteria. The further microscopic observation showed that the addition of a certain amount of organism A and B could improve significantly the chemotaxis movement of the adhesive baterica to the crude oil.

Abstract:The microbial growth was obviously effected by different geologic condition in MEOR. The effect of produced water, porous medium (quartz sand) and porous medium with crude oil on microbial growth was studied in simulated Zhongyi area reservoir condition. Meanwhile two activators were used, formula a was: 1 g/L glucose, 0.15 g/L peptone, 0.05 g/L yeast powder, 0.1 g/L ammonium nitrate, 0.05 g/L diammonium phosphate, and formula b was: 5 g/L starch hydrolysate, 0.1 g/L ammonium nitrate, 0.1 g/L diammonium phosphate, 1 g/L urea. The results showed that the microbial density was more in produced water than that in porous medium, which related to the adsorption of microbe in porous medium. The effect of starch hydrolysates was better than that of glucose. The solution pH value reduced from 8 to 5 obviously after microbe activated by starch hydrolysates. At the same time the small molecule acid was produced much more, which would increase the durative of MEOR. The microscopic examination results showed that the microbe was absorbed above 104 cells/mL in porous medium, which was benefited for the growth in-situ of microbe in the cores.

Abstract:A 75 ℃ high temperature resistant bacteria (HB) was isolated and cultured from the active sludge sewage treatment plant under the Xia'ermen oilfield high viscosity heavy oil for domesticating of half a year. The HB was identified as a heat of the genus bacillus (Thermophilic Bacillus ) by 16 S rDNA. The culture condition of HB and the performance of the oil recovery of the HB were investigated. The results showed that the HB got good adaptability under the culture condition of salt content of 0—3%, pH value of 6.0—9.0，and the optimum salt concentration and the optimum pH value was found to be 1% and 7.0, respectively. When the cells were grown at the dosage of 5% on optimal conditions oil degradation medium containing 5 g/L (1#) Crude oil at 75℃ and 120 r/min for 10 days, the HB could make oil degradation rate reach to 33%, the emulsified index was up to 55% and the surface tension of the fermented liquid reduced from 74.5 mN/m to 41.2 mN/m. After treated by HB for 7 days, the content of pectin and asphalt of 2# and 3# crude oil reduced from 28.0% and 22.6% to 26.4% and 19.9%, respectively, the freezing point of 2# and 3# crude oil reduced from 29.4℃ and 28.1℃ to 28.5℃and 27.3℃, respectively. The viscosity of 1# ,2# and 3# crude oil reduced from 735, 682 and 274 mPa·s to 509, 467and 103 mPa·s, respectively after treated by HB for 20 d. In a word, microbial activity made the Components of crude oil change and the oil property improve.

Abstract:Three strains chosen by enrichment, taming and separation from Jinglou oilfield water were gas production bacteria, hydrocarbon oxidation bacteria and biological surfactant bacterium. After three strains mixed according to inoculation amount in 1:1:1, the biological surfactant in metabolites increased from 1.7% to 2.2%, gas production increased from 95 mL to 120 mL, and pH value decreased from 6.1 to 5.9. The microbial indoor test results for the crude oil of Jinglou oilfield showed that the symbiont digesting strains had a good adaptability, and emulsification of heavy oil viscosity reduction effect was obvious. The drop sticky rate of crude oil could be as high as 63.9%, the viscosity of emulsion oil-in-water varied from 100 to 300 mPa·s, the content of resin and asphalt decreased, and the surface tension of fermented liquid decreased by 9.4%-11.6%. This cold nitrogen microbial production technology was applied in 7 wells of Jinglou oilfield on site with 10-15 m single well radius, 2000-10000 Nm3 nitrogen replacing slug, 2.5-6.0 t microbial fluid. The results showed that the produced liquid per well increased by 1.8-9.8 times, oil production per day increased from 0-0.1 t to a maximum value 2.7 t, oil increment was of 470 t after 115 days, and the effective rate was of 85.7%.

Abstract:In order to improve the development efficiency of heavy oil reservoir, the application of chem-thermogenic and catalytic pyrolysis to reduce the viscosity of heavy oil was particularly important. NaNO2 and NH4Cl solution were chosen as chemical heat-generating agent, and orthogonal experiment was designed. The optimum reaction condition was obtained as follows: 4 mol/L NaNO2, 4 mol/L NH4Cl and 2 system pH value. On this condition, the temperature and pressure of reaction rose rapidly in a short time with peak value 204℃ and 13.6 MPa after 6 min, respectively. The temperature of reaction solution increased 149℃. The best formula of oil-soluble nickel-based catalysts system was established: the mass of reactive crude oil as benchmark, 0.3% oleic acid nickel catalyst, 7% formic acid hydrogen donors, 7% auxiliary of carbamide and 0.13% sodium dodecyl benzene sulfonate. The optimum reaction temperature of the catalytic system was of 280℃. When the crude oil was catalyzed by oleic acid nickel, the viscosity decreased from 213.8 mPa·s to 74.2 mPa·s and the viscosity reduction rate was of 65.3%. When the chemical heat-generating agent and the catalytic cracking catalyst worked together, the viscosity reduction rate was up to 66.5%. The content of saturated hydrocarbon and aromatic hydrocarbon increased, whereas that of colloid and asphaltine decreased. So the catalytic degradation effect was quite well.

Abstract:A oilfield acidification corrosion inhibitor was synthesized by Mannich reaction of secondary amine, acetophenone and formaldehyde. The effect of the synthetic technology，including molar ratio of reactant, reaction temperature and reaction time, on the inhibition performance of the inhibitor was evaluated by coupon corrosion tests. In addition, the inhibition mechanism of the inhibitor was investigated by electrochemical test and scanning electronic microscope observation. The results showed that the inhibitor exhibited the best inhibition efficiency when the molar ratio of primary amine, acetophenone and formaldehyde was 1:2:5 and the reaction were maintained at 80℃ for 10 h. After compounded with polyether and propargyl alcohol, the inhibitor could reach the first-class level at the dosage of 0.5%. The corrosion inhibitor was assigned as a mixed inhibitor mainly which inhibited the anode process through electrochemistry method. The scanning electronic microscope observation indicated that the corrosion forms of steels were improved significantly after adding 0.5% corrosion inhibitor.

Abstract:The source water salinity of Suizhong 36-1 oilfield was as high as 9548 mg/L, and the ion concentration of magnesium and calcium was of 819.94 mg/L. As a result, the problem of water injection line scaling was serious. The well scaling products were analyzed by ESEM, EDS and XRD. The results showed that the calcium carbonate scales which in the surface pipeline and the underground string were significantly different in crystal feature, granularity and shape. The scale produced from underground string was calcite, which had complete crystal shape and coarse grains. The main elements of scale products included O, Si, Ca, C and a small amount of Mg, Fe, S, etc. It represented the scale characteristics under the downhole conditions of pressure and temperature without the influence of scale inhibitor. The scale crystals produced from surface pipeline were calcite in form of crystal rhombohedron and aragonite in form of acicular and columnar shapes, both of which distributed alternately. The main elements of scale products included O, Ca, C and a small amount of Mg, Fe. This phenomenon showed that the scale inhibitor prevented aragonite from changing into calcite. The characteristics comparison of calcium carbonate scale in the surface pipeline and the underground string offered a typical case for the mechanism studies on influences of crystal growth characteristics by scale inhibitor.

Abstract:Black paste of oily sludge in the process of sewage treatment in Henan oilfield was analyzed, which consisted of 35.08% water, 29.06% oil, 35.86% argillaceous and 4.12% sieve rate of 150 mesh. The solid phase of oily sludge was composed of argillaceous particles such as sand and clay with different particle size, accounting for 97.45%, particle size smaller than 63μm accounted for 84.02%. The argillaceous particle size was fine and distribution was concentrated. The deep fluid diversion agent with the main material of oilfield oily sludge was developed, which included 0.20% —0.25% JHW-1 suspension, 0.3% —0.4% FSJ-1 dispersant, 2.5% —4.0%NT-1 curing agent. The experiment results showed that the slurry had a good stability, poured nature, higher strength （the breakthrough pressure gradient> 0.28MPa/cm）, 88.2%—95.6% core plugging rate, and low cost which was suitable for large scale of deep injection. Double parallel sand pipes experiment results showed that the water flooding recovery of hypotonic and hypertonic core increased by 25.73% and 17.11% respectively after fluid diversion agent profile control. The agent was used in 56 wells in Henan oilfield with oily sludge consumption of 105118 m3, cumulative oil increment of 17369 t and water cut decrease of 90000 m3. The application showed that the starting pressure of measure wells increased, water absorption index lowered, water injection pressure rose, and water injection profile improved. The pilot effects of increasing oil production and decreasing water cut were obvious.

Abstract:In this paper, the quick hot breaking-emulsion and floatation separation process of oil material recovery from oily sludge obtained from an oil field was probed to obtain the essential parameters in the relevant engineering design or practices. The optimal process was as follows. Firstly, the mixture containing 25% oily sludge and 75% water was adjusted to a pH of 6, following by adding about 0.4% emulsion breaking agent, and then heating to 80℃ under stirring slowly, The crude oil separation was finished after stirring softly for 15~20 minutes at 80℃. Secondly, at the room temperature, the major-oil-removed mixture was further treated by means of flotation for about 10 minutes in order to separate the residual oil. The oil content of the mud cake formed by the centrifugal separation of the last mixture was less than 1%. And the result that centrifugal separation mixture liquid for the next oily sludge treatment was great. Furthermore, the test result of planting clover on the soil sample composed of the dry mud cake and some seedbed soil showed that the seed germination and growth were normal.

Abstract:A smooth black gel as pre-polymer was prepared at room temperature by mixing Waste tire rubber (WTR), butyl acrylate (nBA), and an appropriate amount of BPO. And WTR/PBA oil-absorbing materials could be formed under further reaction of the pre-polymer with cross-linker DVB. The structure and property of the pre-polymer were studied by FT-IR, and the saturated oil absorption of the oil-absorbing materials in gasoline was measured and the compatibility of WTR/PBA oil absorbing materials was investigated by dynamic mechanical analysis (DMA) and scanning electronic microscope (SEM). The results showed that the BPO could cause the reaction of nBA at room temperature in the existence of WTR, resulting in the formation of the gel. The oligomer of butyl acrylate was detected, as well as parts of butyl acrylate grafted onto WTR. The conversion of the monomer was between 10% and 20%. The test results of rheological properties of the pre-polymer showed that the gel belonged to a Bingham fluid. The saturated oil absorption of the WTR/PBA oil-absorbing materials increased first and then decreased with increasing the amount of crosslinking agent, the maximum amount of the absorped gasoline was 6.2 g/g at the dosage of 1% crosslinking agent, and the adsorption reaction reached balance after 60 min. The DMA and SEM measurements showed that the compatibility of the WTR/PBA oil-absorbing materials was excellent.

Abstract:The composition of the flowback fluid was complex and it is difficult to characterize the organic matter content. The hydroxypropyl guar gum, which is the main components of fracturing fluid was chosen as the research project, the effect of the content of organic matter and cholrine ion, oxidation treatment on the identification of the organic matter content of fracturing liquid were investigated by measurement of chemical oxygen demand(COD) and total organic carbon (TOC), respectively. The results showed that there was larger limitation when using COD method to characterize liquid organic matter content of fracturing fluid, while TOC was more suitable to charaterize the content of the organic matter of hydroxypropyl guar gum solution.

Abstract:The unit of mass concentration, molecular concentration and molality is kg/L (or kg/m3), m-3 and mol/kg, respectively. As an abbreviation, “concentration” should only refer to amount-of-substance concentration, whose legal unit is mol/L or mol/m3. Mass fraction and volume fraction, whose unit is %, can not be referred to as “concentration” for short.

Abstract:In this paper, the applications of nanomaterial in the fields of drilling fluids, completion fluids as well as reservoir protection in recent years were reviewed. The nanomaterials used as nanocomposite filtration-reducing agent, nanocomposite viscosifier, nanosized lubricant, nano-cement slurry, nano-spacer, nanomaterials for reservoir protection, and so on, were introduced, which had played an essential role in maintaining borehole stability, improving cementing quality and protecting reservoir. Finally, the further application of nanomaterial in drilling/completion fluids and reservoir protection is also prospected.

Abstract:Steam flooding and steam huff-puff were the mean method to recovery heavy oil. However, steam overlay and channeling during the exploitation process had serious influence on development effect. On account of these problems, recent developments of heat-resistant profile agent in heavy oil were presented, including particle blocking agent, heat-resistant gel blocking agent, heat-resistant foam blocking agent and other heat-resistant blocking agent. Their relative merits and disadvantages were summarized.

Abstract:The international research progress of the diffusion coefficient of CO2 in reservoir fluids was reviewed. The measurement principle and experimental methods for diffusion coefficient of gas in liquid were summarized. The advantages and disadvantages of common methods were compared, and the applicability of these methods in the diffusion process of CO2 in reservoir fluid was studied. The diffusion coefficients of CO2 in various reservoir fluids were listed, the main affecting parameters and variation of diffusion coefficients were discussed, and some typical correlations of diffusion coefficients were proposed. Finally, in view of the domestic reservoir condition and the lack of diffusion research, the optimization of experimental methods under high pressure high temperature was discussed, which provided a reference for future research.

Abstract:The application of foam fluid in the immediate vicinity of wellbore was introduced, including foam acidizing, fracturing, plug removing, gravel packing and water-coning controlling. The application status of foam fluid in the formation was summarized, including foam for water and gas plugging and profile control and flooding. The prospect and development direction of foam fluid stimulation techniques from the aspects of theoretical study and construction technology were proposed.