Abstract:The phase-transition?temperature of walnut green husk powder was 166.0℃. It was used as water-based drilling fluid additive, and the filtration reduction effect of walnut green husk with powder mesh greater than 120-mesh was slightly better than that of others. The performance evaluation results showed that when the mass fraction of walnut green husk increased from 0 to 1.0%, the apparent viscosity (AV) and plastic viscosity (PV) of drilling fluids waved unremarkably, and the fluid loss (FL) reduced from 12.9 to 7.7 mL, the filtration reduction rate reached to 40.3%. As the treatment temperature increased, AV and PV increased first and then decreased, the effect of reducing fluid loss gradually weakened and lost at more than 160℃. The walnut green husk water extract could obviously inhibit hydration and swelling of clay, and the swelling ratio of calcium bentonite in 0.3%, 0.5% and 1.0% walnut green husk water extract was 50.18%, 46.10% and 39.88%, respectively, which were lower than that of 4.0% KCl solution (56.51%). When the dosage of walnut green husk was 0.3%, the compatibility effect between it and modified starch was better than that between it and polyacrylamide. The former’s viscosity and FL reduced, and the latter’s viscosity increased and FL reduced. The compatibility between walnut green husk and heteropoly glucoside KD-03 drilling fluids was favorable whose FL decreased by 0.6—0.7 mL and the ability of suspension to cuttings, filtration properties and lubricity was improved.

Abstract:Aimed at the problem of poor anti-temperature capability of solid-free drilling fluid，which cannot meet the needs of high temperature deep buried hill reservoir protection technology, the ultra-high temperature polymer viscosifier SDKP was developed．The molecular structure of SDKP was analyzed by the measurements of FT-IR and 1H-NMR. The relative molecular weight was measured with GPC. Thermal stability of the SDKP was analyzed with TGA. The property of thickening, temperature resistance and salt tolerance in solid-free drilling fluid was evaluated. The thickening mechanism was analyzed by using environmental scanning electron microscopy (ESEM) and rheometer. Results showed that SDKP had excellent thickening ability and thermal stability and could effectively improve the viscosity of solid-free drilling fluid. Temperature resistance of SDKP in freshwater solid-free drilling fluid and in brine solid-free drilling fluid was up to 180℃, which was much better than that of the similar foreign representative treatment agent HE300. The close spatial network structure formed by micron fiber bundles was made up of SDKP in water and continuous network structures were still formed in the brine solution, and SDKP had the thermo-thickening properties, and also had some thermo-thickening properties in saline. It was applied in horizontal well Magu-H117 of Liaohe Xinggu buried hill. The field application results showed that the brine solid-free drilling fluid with SDKP as the main treatment agent, had good rheological and thermal stability, ensuring the safe and smooth construction of horizontal section.

Abstract:A tan drilling fluid lubricant BZ-BL was synthesized using waste animal/plant oil, ethanolamine, p-toluene sulfonic acid, hydrogen peroxide and white oil as raw material. The density, freezing point and fluorescence grade of lubricant was 0.9 g/cm³, -15℃ and 3, respectively. The optimum synthesis condition of lubricant was obtained as follows: 7% ethanol amine, 5% p-toluene sulfonic acid, 135—140℃ reaction temperature and 4 h reaction time. The performance test results showed that the reduced rate of lubricating coefficient of 4% brine and saturation brine mud was 76.9% and 67.4% respectively, which indicated good salt resistance, and the temperature resistance was up to 180℃. The effects of BZ-BL on rheological property and filtration property of polymer, silicate-based and potassium-based mud were small. The application of BZ-BL in more than 10 wells on site showed that the lubricant?had good lubricating property and good compatibility with drilling fluid additives. It was friendly to?the environment, which could be used at deep, highly-deviated, horizontal wells, and exploration and development of environmental sensitive region.

Abstract:In the early, cellulose fracturing fluid had problems in fluid mixing, temperature resistance, gelout and severe formation damage. In this paper, an instant dissolving cellulose fracturing fluid with no residue was composed with 0.4% hydroxyethyl carboxymethyl cellulose FAG-500, 0.2% viscosity increaser FAZ-1 and 0.5% regulator FAJ-305. The viscosity characteristics of fracturing fluid solution, such as the resistance to salt, high temperature and shearing, proppant carrying ability, breaking property, dynamic filtration and halmful performance were analyzed. The results showed that the viscosity of base fluid was about 67.5 mPa·s under the condition of medium salinity (242—2444 mg/L). The gel was formed by adding crosslinking agent FAC-201 under 4.5—5.0 pH value. The viscosity of gel was about 150 mPa·s after shearing 70 min under 120℃, 170 s^-1, which satisfied the requirements of formation fracturing under 130℃. The viscosity of gel was about 200 mPa·s after shearing 90 min under 100℃, 170 s^-1 when 0.002% gel breaker ammonium persulfate was added. The gel breaker did not affect the rheological properties of construction system. There was no residue after breaking process, and the surface tension of gel breaking liquid was 24.44 mN/m, the interfacial tension was 3.20 mN/m. The energy storage modulus G′ and the energy consumption modulus G" of 0.3% fracturing fluid gel was 7.2 Pa and 1.6 Pa at 90℃ respectively. The carrier performance of cross-linked gel carrier fluid in sand ratio 40% was well with no grit after 6 h bath heating. The damage rate of core permeability was 24.75%. The cellulose fracturing fluid had some characteristics, including instant dissolving, acid cross-linked, without expansion agent, and so on. The cellulose fracturing fluid was applied in two tight oil wells and two tight gas wells of Changqing oilfiled. The rate of well-construction was more than 95% and the rate of effective construction was 100%.

Abstract:A reversal wetting multi-effect additive（PA-VERT）was proposed in the paper, and the interfacial activity, wetting reversal performance, cleanup ability, waterproof damage capability and oil-washing ability of PA-VERT were evaluated through the measurements of the oil-water interfacial tension，wetting angle and the physical model experiments. Experimental results showed that the PA-VERT had excellent interfacial activity and could reduce the oil-water interfacial tension to 10^-2mN/m order of magnitude. The carbonate rock surface could be changed from oil-wet to water-wet with the treatment of the 1%PA-VERT solution. It could also significantly reduce the water influx rate at the constant pressure, as well as the pressure of oil driving water，which could effectively relieve water blocking damage，so it had high cleanup rate and strong ability of preventing water-damage; Besides， the additive has strong oil-washing power，and the increase of the temperature was beneficial to improve its capability of washing oil.

Abstract:Experiments were conducted to study the viscosity, molecular configuration dimension, molecular aggregation, effect of flooding and fluid diversion of four kinds of flooding agents, and the mechanism was analyzed briefly. The results showed that the flooding agents were arranged according to the viscosity at same concentration in following order: polymeric surfactant＞Cr³⁺ polymer gel＞HPAM solution＞polymer nanosphere（about 2 mPa·s）. When the water content of water flooding was 40% and then 0.38 PV flooding agent was injected, the flooding agents were arranged according to the increase recovery rate in following order: Cr³⁺ polymer gel（14.5%）＞HPAM solution（10.2%）＞polymeric surfactant（6.8%）＞polymer nanosphere(-5.1%). The results of fluid diversion experiment showed that, at the end of chemical flooding, the increase recovery rate of Cr³⁺ polymer gel, HPAM solution, polymeric surfactant and polymer nanosphere in low permeability layer was 24.7%, 16.5%, 10.3% and 3.1%, and the diversion rate of that in low permeability layer was 20.8%, 12.4%, 9.7% and 3.2% respectively. The molecular aggregation of flooding agent played a major role in its apparent viscosity and the effect of fluid diversion. The hydrodynamic radius (Rh) of polymer nanosphere, HPAM solution, Cr³⁺ polymer gel and polymeric surfactant was 0.267, 0.066, 0.079 and 0.771 μm, which were all less than 0.46R (radius of pore throat). It's difficult to form stable block in pore throat theoretically. Among of them, which had granular, wire network, local network and regional network of molecular aggregation respectively, the retention and flow resistance of Cr³⁺ polymer gel was the largest in rock pore throat. Polymeric surfactant had a high apparent viscosity. However, it had a poor compatibility with the pore throat of rock, and it was more likely to block the injection side.

Abstract:Using white oil as the continuous phase, a blend of surfactants (Span80 and OP10) as emulsifying system and 40.0% aqueous solution of acrylamide as the dispersed phase, the inverse microemulsion was prepared, including 43% white oil, 24.7% Span80/OP10 (26:74) emulsifiers and 36.4% aqueous solution of acrylamide. The inorganic vermiculite was added in the polymerization system during the preparation of polyacrylamide inverse emulsion and the composite polyacrylamide microspheres (PAMCMS) with core-shell structure were obtained. Using the size, swelling property and emulsion stability as indicators, the effect of stirring speed, reaction time, and concentration of initiators and crosslinking agent on the polymerization were investigated. When the concentration of initiator and crosslinking agent was 0.09% and 0.025%, respectively, the latex particles with particle diameter of 680.4 nm could be obtained under stirring rate 300 r/min at the temperature of 40℃. The measurement of scanning electronic microscope and Laser particle diameter analyzer showed that the particle diameter of PAMCMS reached up to 2792 nm after swelling in deionized water for 10h, increased by nearly 4 times.

Abstract:To solve water control problem in low permeability and low temperature reservoirs with water flow predominant channels, a multi-component crosslinked polymer (MCCP) gel was studied in the lab. The matching relationship between the gel’s performance and predominant channels in heterogeneous formations was studied from the aspects of static performance, rheology, diversion adjustment ability, plugging property and migration depth. The experimental results showed that, at the temperature of 40℃, the initial gelation time was of about 3 h, the completely gelling time was of 24 h, and the gel strength was more than 50000 mPa?s. The shear thinned phenomenon occurred before gelation. The selective plugging property of the MCCP gel was good in heterogeneous formation whose permeability differential was less than 10. After injecting 0.3 PV MCCP solution, for the predominant channels with permeability of 600×10^-3、1000×10^-3、10000×10^-3μm², the gel had good plugging property. Its final migration depth in sand filling tube with permeability of 10000×10^-3μm² could reach 3/5 of the total length; for sand filling tubes with permeability of 1000×10^-3 and 600×10^-3μm², the depths both could reach 2/5 of the total length.

Abstract:In order to effectively solve the high permeable layer or plane channel influence on oil displacement effect under a variety of displacement methods during oilfield development process, the effect of microfiber blocking agent CZZL-10 on sand filling tube and artificial core plugging was investigated. Sand filling tube experiment result of water flooding showed that the permeability ratio of tube after CZZL-10 flooding reduced by more than 90% than that after water flooding, and driving pressure increased 10.6 times. Plugging experiment result of polymer flooding showed that after adding CZZL-10, the permeability ratio of polymer flooding reduced by more than 80%, and driving pressure increased 7.4 times. Experiment result of artificial homogeneous core showed that when core permeability was high, the effect of blocking using CZZL-10 was significant. When the water permeability of core was 435×10^-3, 666×10^-3 and 953×10^-3 μm², the core plugging rate of CZZL-10 was 40.0%, 66.7% and 57.6%, and the residual resistance factor of core was 1.6, 3.0 and 2.1, respectively. The lowest measured water permeability was 222×10^-3 μm² after plugging, achieving the purpose of blocking while not totally blocked. Microfiber polymer solution was used to plug three layer heterogeneity cores. The larger heterogeneity variation coefficient and permeability differential of the core, the better blocking effect of high permeability layer was. The shunt rate of high permeability layer decreased significantly, while that of low-mid level permeability layer increased substantially, which achieved the purpose of expanding swept volume and enhancing oil recovery .

Abstract:Jin-91 block entered the later period of steam huff-puff and was flooded seriously, which lacked the theory of steam flooding in heavy oil reservoir with edge and bottom water. Three layers of inhomogeneous artificial core with 500×10^-3、1000×10^-3、1500×10^-3 μm² permeability were used in experiment. There were 5 producing wells, four assist production wells which were designed for saturating core with oil, four water inlets which were used for modeling sufficient edge water on the right. High permeability (16000×10^-3 μm²) transition with 2 cm width was close to the edge water. The effect of pressure, temperature and distance of water and bottom water on the encroachment sensitivity of edge-bottom water was analyzed. The results showed that When the differential pressure (ΔP) was 0.04, 0.06, 0.08 MPa and the temperature was 45℃, the relationship between instant water influx Q and ΔP was Q=0.0021×e^72.8ΔP×t (t=0~75 h) and Q=0.007×e^51.708ΔP×(t-75)+0.157e^72.64ΔP (t=75~125 h) in early and later stage of the experiment, respectively. When ΔP was small, the relationship between Q and time was approximately linear. With increasing ΔP, the curve of Q appeared inflection point. And the instant water-output tended to be stable at later stage of water invasion. When the temperature increased from 45℃ to 75℃, the water breakthrough time delayed. The effect of temperature on water breakthrough time of producing wells far from edge water was the most obvious. The nearer to edge water, the more serious water logging was. The effect of ΔP to the law of water invasion was the most obvious among water invasion sensitive factors. The result provided evidence for the development of heavy water flooded zone turning to steam drive.

Abstract:In the titled reservoir of average stratum temperature 65℃ and oil in place viscosity 90.34 mPa·s, a series of profiling and/or flooding operations were performed and led to a water cut of 97%. To seek for ways of further oil recovery, a laboratory experimental study on air foam flooding was made. The microscopic simulating experiment demonstrated that plugging/blocking and emulsifying mechanisms were involved in oil displacement. In static oxidation experiment, it was found that the oil could be oxidized slowly under simulated reservoir conditions with an oxidation rate of (2.261×10^-5—2.448×10^-5 molO₂·h^-1·[mL(oil)]^-1 determined, which increased with raising pressure and temperature. In the physical modeling experiment on sandpacks, air, air foam, water, and air again were injected successively after an initial water injection, which stopped at 12.35% oil recovery obtained, and an enhancement in oil recovery of 36.47%, 14.12%, 11.18%, and 0%, respectively, was observed; the changes in CO₂ and O₂ contents in the produced gas mixture indicated oxidation of experimental viscous oil and the variation in injecting pressure indicated plugging/blocking effect of the air foam. For the titled reservoir, air foam flood seems to be a practical method of EOR.

Abstract:Air foam complex flooding used to improving oil recovery was feasible and effective method in low permeability and high salinity reservoir of Changqing oilfield. The effect of strata medium, such as high salinity formation water and oil etc, on the foaming and steady performance of eight foaming agents, and the effect of foaming agent on the surface tension and viscosity of crude oil and high salinity formation water were evaluated. The eight different foaming agents were sodium alcohol ether sulphate, cocoamidopropyl betaine, sodium dodecyl benzene sulphonate, octaphenyl polyoxyethyiene (TX-10), alkylphenol ethoxylates (OP-10), coconutt diethanol amide 6501, alcohol ether carboxylate, FLH nonionic osmotic agent, which were numbered consecutively from 1 to 8. The injected water type of Changqing oilfield was Na₂SO₄, with 1.1 g/L salinity and 6.5 pH value. The formation water type was CaCl₂ with 82.2 g/L salinity and 5.95 pH value. The density of crude oil was 0.85 g/cm³, and the viscosity was 6 mPa·s. Experiment results indicated that No. 6—8 foaming agents were not compatibility with formation water. No. 1—5 foaming agents reduced the surface tension of injected water and formation water by half. And there was no influence on surface tension and viscosity of crude oil. When injected water was changed to a combination of injected water and formation water in volume ratio 1:1, the foam volume of No. 1—5 foaming agents changed a little, and there was no change of foam half-life of No. 3—5 foaming agents. The foam half-life of No. 1 foaming agent increased from 70 to 260 min, and that of No. 2 decreased from 60 to 25 min. After 1% crude oil was mixed with 5% No. 1 foaming agent solution, the foam volume reduced from 398 to 388 mL, and the foam half-life decreased from 70 to 7 min, showing good washing oil ability. No. 1 foaming agent sodium alcohol ether sulphate satisfied the requirement of air foam flooding in Changqing oilfield.

Abstract:The effect of two methods of oil displacement, air foam flooding and surfactant flooding by using XHY-4 foaming agent (anionic surfactant) was studied. Single tube core displacement experiment results showed that the enhanced oil recovery rate increased with increasing concentration of foaming agent and gradually stabilized in two kinds of oil displacement mode. The enhanced oil recovery rate of air foam flooding was higher than that of surfactant flooding under the same foaming agent concentration. When the concentration of foaming agent was 0.1%, the enhanced oil recovery rate of foam flooding was 8.5%, and that of surfactant flooding was 3.4%. Two parallel tubes core displacement experiment results showed that comprehensive recovery rate of surfactant flooding was 5.47%, the enhanced oil recovery rate of high and low permeability tube was 7.6% and 3.3%, and the water cut decreased from 99.55% to 94.95%. The comprehensive recovery rate of foam flooding was 16.5%, the enhanced oil recovery rate of high and low permeability tube was 13.82% and 19.53%, and the water cut decreased from 98.08% to 70.97%. The surfactant flooding improved oil recovery by increasing efficiency of wash oil, while air foam flooding improved recovery factor by improving swept volume. In the process of foam flooding, the cumulative fluid of low permeability tube increased by 0.14 PV.

Abstract:Five kinds of surfactants were synthesized as foaming agent including alkanolamide, modified sulfonic betaine, ethylene oxide sulfonate, fluorocarbon (FC) and sodium dodecyl sulfate (SDS). The FC surfactants were selected priority because its film number was less than 1, and SDS was also selected because of its good foamability. The properties of foaming agents were measured by Waring Blender method. The testing results showed that FC surfactants (JSC-6) had good performance on oil tolerance, whose foaming volume was 320 mL, draining half time was 2.5 h and foam composite index (FCI) was 2285.7 in the presence of crude oil (10%). When inorganic salt ZC-1 was added into SDS solution, the foaming agent showed poor oil tolerance and short foam stability with 10% oil, and the foaming volume was 330 mL while the draining half time was 15 min and FCI was 235.7. When partially hydrolyzed polyacrylamide was added to the foaming agent system, the stability of both JSC-6 and SDS foaming agent was improved, and the half time increased from 36 and 10 min to 126 and 68 min, respectively. When the oil saturation was low (less than 25%), the SDS foaming agent had a high foam composite complex index, but FC system had better foamability and stability when the oil saturation was higher than 25%.

Abstract:In order to study on feasibility of dilute polymer systems prepared with polymer-containing oilfield wastewater in the process of polymer flooding in Daqing oilfield，polymer solutions systems the same concentrati on with were prepared，and the viscosity，shear-resistance，viscoelasticity，stability，molecular siz，the injection ability and recovery efficiency of the polymer solutions were measured. The results showed that system prepared with the clean water and diluted with deep treated sewage was superior to the symtem prepared and diluted with wastewater at the polymer concentration of 0，and superior to the system prepared and diluted with biochemical wastewater in the experiment of polymer property test，injection ability and recovery efficiency. Residual polymer in the wastewater could increase the viscosity of the system. The higher the concentration of residual polymer，the higher the property of the polymer system，when the polymer system was at the same preparation of concentration. Dilute polymer systems prepared with polymer-containing wastewater would be widely applied in Daqing oilfield. on comprehensive consideration of polymer injectivity and recovery efficiency，it was advised to prepare and dilute the polymer system with the wasterwater containing 200—400 mg/L residual polymer in Daqing oilfield.

Abstract:Aiming at profile reversal during polymer flooding, in this paper, based on the geological conditions of a reservoir in the Bohai oilfield, the law of profile reversal during polymer injection with polymer viscosity was researched by investigating the diversion rate in low permeability layers with homogeneous polymer solution with different viscosity, furthermore, the oil-displacement experiments of slug combination were conducted with two heterogeneous polymers HPAM and HAPAM solutions with the concentration of 1500 mg/L and the viscosity of 30.5 mPa·s and130.8 mPa·s, respectively. The results showed that, with the increase of the polymer viscosity, the opportunity of profile reversal during polymer flooding became ahead of time, the diversion rate rose first and then fell, the peak value of the diversion rate in low permeability layers enhanced. Too high or too low viscosity was detrimental to enhancement of oil recovery. As for the Bohai oilfield, it was suitable to control the viscosity of the polymer solutions after across the embrasure within the range of 15—30 mPa·s. The profile improvement effect of the HAPAM solution with higher viscosity to multilayer heterogeneity reservoir was better than that of the HPAM solution with lower viscosity polymer; however, the injection pressure of the HAPAM solution was much higher than that of the HPAM solution. The alternating injection of high-low viscosity heterogeneous polymers had a more pronounced profile improvement effect for the multilayer heterogeneity reservoir offshore which was being implemented polymer flooding.

Abstract:The impact of core permeability, water washout and crude oil viscosity on relative permeability and the displacement efficiency of polymer flooding were studied through core displacement experiment, core CT scanning and theoretical analysis, aiming at reservoir geological characteristics, fluid properties and field construction technology of the offshore heavy oil reservoir. The results showed that, with the increase of core permeability, the oil phase relative permeability reduced, the seepage resistance of displacing phase decreased, and the water phase relative permeability increased, the swept volume become bigger, two-phase flow span got wider, resulting in the ultimate oil recovery was enhanced. The function of ‘cleaning’ and ‘erosion’ that water washout exerted on core pore structure would enlarge the pore throat radius, increase core permeability, and its influence on relative permeability curve and displacement efficiency was similar to the influence of the increase of the core permeability. With viscosity of the crude oil increasing, oil/water phase relative permeability reduces, displacing phase viscous fingering phenomenon aggravated, seepage resistance increased, and the swept volume became smaller, two-phase flow span got narrower, resulting in the ultimate oil recovery decreased.

Abstract:Aimed at the certain reservoir with formation temperature of 82℃, a comb copolymer flooding was probed, the physical and chemical properties of the comb copolymer was evaluated, such as high temperature resistance, shearing rheological property, shear stability, long term stability and salt resistance; then, dynamic flooding experiments were carried out, and the slug size, the slug concentration and the way of injection method were screened. The resulted showed that the viscosity retention rate of comb polymer solutions with the concentration of 1500—2000 mg/L was still more than 40% after aged at the temperature of 82℃for 30 days. The viscosity of comb polymer solution decreased by only 8.95 mPa ? s after sheared at the speed of 1500 r/min for 120 minutes. The comb polymer had more excellent temperature resistance and salt resistance than that the common polymer and the comb polymer solution belonged to a typical non-Newtonian fluid. The oil displacement experiments showed that the larger the slug size the more the recovery efficiency under the condition of the same slug concentration, and the higher the slug concentration the more recovery efficiency under the condition of the same slug size. The optimal slug concentration was 2000 mg/L, the optimal slug size was 0.3 PV, and the way of injection was complete injection.

Abstract:In actual oil reservoir conditions, by measuring interfacial tension between new hydroxyl sulfobetaine surfactant designed for target oil reservoir and crude oil of target oil reservoir, the new hydroxyl sulfobetaine surfactant’s adaptability for injected water, produced water and formation water of target oil reservoir, compatibility with the polymer used in target oil reservoir, resistance to?adsorption to natural oil sands of target oil reservoir and the stability for long-term placement were investigated systematically. Experimental results indicated that the new hydroxyl sulfobetaine surfactant HSB01 had a good adaptability to water quality of actual reservoir and had a good compatibility with the polymer. When the surfactant mass fraction ranged from 0.25 g/L to 2 g/L, the interfacial tension between the HSB01 solution and the crude oil could achieve an ultra-low order of magnitude. After adsorbed by natural oil sands for 9 times or placed for 90 days at reservoir temperature of 50℃, the interfacial tension between the HSB01(1.5 g/L) /polymer(1.5 g/L) binary system and the crude oil could reach ultra-low order of magnitude. In addition, the HSB01 also had a good interfacial activity with the other two crude oil different from target oil reservoir.

Abstract:Due to the EOR need of injecting weak alkaline water in Linnan oilfield, developing surfactant system under the condition of weak alkaline water was of great significance. The production water in Linnan oilfield was neutral water with pH value of 6.89 and salinity of 44118 mg/L, while the treated water belonged to weak alkaline water with pH value of 7.88 and salinity of 39116 mg/L. By testing the interfacial tension between different types of surfactants and crude oil, the compound system CDS6 composed of fatty alcohol ether sulfonate (CEOS6) and amide-type nonionic surfactant (CDA01) was selected. The effect of solution medium on interfacial tension and the optimized slug injection and concentration of surfactant were also investigated. The experiment results showed that the constituent of optimum compound system CDS6 was obtained as follows: 0.1% CEOS6+0.2% CDA01. The interfacial tension of composite surfactant system in neutral water and weak alkaline water with crude oil was 5.84×10^-3 and 1.70×10^-3 mN/m, respectively. Weak alkaline water had synergistic effect with CDS6 in decreasing interfacial tension. The simulation flooding test results showed that the oil displacement efficiency of 0.3% CDS6 in weak alkaline water was higher than that in neutral water. The oil displacement efficiency of 0.3% CDS6 weak alkaline solution at the slug injection of 0.4 PV was 57.33% which was improved by 10.66% compared with that of water flooding.

Abstract:A preferably kind of chemical decompression and augmented injection system was studied under the temperature of 50 centigrade in this paper. The basic recipe was obtained as follows: 0.05% dimeric surfactant HA-1, 0.1% ethanol amine MEA and 0.1% methanol, which could decline instantaneous minimum interfacial tension (IFT_min) between oil and water to 3.78×10^-5 mN/m. The system’s performance on changing wettability, resistance to inorganic salts and temperature was investigated. The results showed that the system could convert the oil-wet surface to wet surface observably, and the contact angle between simulated formation water and core decreased from 130° to 60° after 33 hrs. When the dosage of NaCl was 5000—20000 mg/L, IFT_min could reach 10^-2—10^-5mN/m. While when 50—200 mg/L CaCl₂ was added, IFT_min and equilibrium interfacial tension would reach 10^-3 and 10^-2 mN/m orders of magnitude, respectively. The system was suitable for the reservoir with the conditions of 5000—20000 mg/L NaCl, less than 200 mg/L CaCl₂, and 40~70℃. The core displacement experiment results showed that the depressurization rate of the system could reach to 20%, and the system had a good decompression and augmented injection effect for low permeability reservoir.

Abstract:Under the influence of bottom water coning, bottom water reservoir is characterized by short water free oil production period, the rapid increase of water cut after water breakthrough and even sudden water flooding, which have bad influence on exploitation of oilfield. Based on reservoir geological characteristics and fluid properties of Tuha Hong-lian oil field as the experimental platform and physical simulation technology as experimental method, experimental researches on enhanced oil recovery was conducted, in which influential factors also was investigated. The results showed that, as for bottom water reservoir, water flooding recovery was only 17.7% after improving injection speed; after blocking bottom water with the zwitterionic polymer gel profile control agent, the flooding recovery was increased to 28.4%; the effect of the binary compound flooding is better than that of the polymer flooding after blocking bottom water layer; at the same amount of profile control agent, the oil recovery of the binary compound flooding with blocking bottom water layer at both oil well and water well was 25.9%, 3.6% more than binary compound flooding recovery with blocking bottom water layer at water well only, therefore, comparing with blocking bottom water layer at water well，blocking bottom water layer at both oil well and water well could get a better effect of water flooding and chemical flooding.

Abstract:The effect of pipe oil flowing improver on raising water content ratio, increasing discharged water chemical oxygen demand and etching installation of petroleum refinery was analyzed. Based on the requirement of pipe oil flowing improver in refinery, it was necessary to add electric dehydration, chemical oxygen demand and organochlorine content in evaluation method. This paper introduced the detailed experiment procedures. 3 pipe oil flowing improvers including ethylene-vinyl acetate copolymer, alkylphenol ethoxylates and polyoxyethylene polyoxypropylene copolymer were evaluated by this method. Their electric dehydration rate was 89%,75% and 96%, the ratio of biochemical oxygen demand after five days and chemical oxygen demand in discharged water was 0.33, 0.45 and 0.89, and organochlorine content was 0.95%、0.23% and 0.02%. Polyoxyethylene polyoxypropylene copolymer had little affection on oil electric dehydration, chemical oxygen demand and organochlorine content, which met the quality requirement of petroleum refinery.

Abstract:In order to evaluate asphaltene dispersant effectively and accurately, the diluting viscosity alteration measurement method was carried out for the first time, and the defect of old precipitation method was analyzed combining with the evaluation results of commercially available dispersants. The effect of different groups, chain length and structure on the dispersion performance of dispersant was studied by the new method. The results showed that when precipitation method was used to measure the dispersant, alkyl benzene sulfonic acid and long chain ionic liquid with strong polarity caused serious concentration. According to a well?of?blending?diluting?oil in Tahe oilfield, the most suitable asphaltene dispersant was amine nonionic surfactant with C18 alkyl chain length and 2—4 polar groups. Based on this conclusion, a new type of long-chain alkyl amide asphaltene dispersant was synthesized by using oleic acid and diethylenetriamine. By diluting viscosity alteration measurement method, the average viscosity of dispersant and asphalt mixture was 890 and 277 mPa·s at 30℃ and 60℃ respectively, which increased 27% and 46% than that of commercial dispersant Span80.

Abstract:The main component polyethylene-vinyl acetate in pour point depressant was determined by using infrared spectroscopy. No.0 diesel oil from Heilongjiang, Dalian and Jilin (ordinal numbers for 1—3) was studied by depressant susceptibility tests. The results showed that polyethylene-vinyl acetate depressant could reduce the condensation point of No.1—3 diesel by 31, 9 and 26℃, and the cold filter plugging point of that by 18, 12 and 21℃, respectively, indicating good sensitivity. The total n-alkane content (17.74%) of No.2 diesel was higher than that of No.1 diesel (14.29%) and No.3 diesel (13.03%), with 87.2% of its total content of C10—C19. The effect of pour point depressant of No.2 diesel was worse than that of No.1 and No.3 diesel because higher content of n-alkane in No. 2 diesel. The effect of depressant on wax crystal morphology and thermodynamics was studied by using polarizing microscope, differential scanning calorimetry (DSC) and X-ray diffraction (XRD). After adding depressant, the shape of wax crystal particles became from irregular elongated rod to small class ball. DSC analysis results showed that the wax precipitation peak temperature of No.1 and No. 2 diesel increased from -1.46 and -2.38 to 0.46 and 2.41℃ after adding depressant, the crystallization peak slope decreased, the absolute value of solid-liquid phase change energy (ΔH) in the phase change process decreased from 3278 and 5.283 to 3.459 and 1.737 J/g. The low temperature fluidity of diesel was changed by depressant through changing ΔH. XRD analysis results showed that the eutectic role occurred between depressant and diesel, the way of wax crystal aggregation changed, and single crystalline growth rate decreased. Polarizing microscope, DSC and XRD results indicated that the mechanism of pour point depressant was a combination of crystal nucleation theory and common theory of joint action.

Abstract:In the paper, the viscoelasticity of hydrophobic associating polymer BCG-1 solution was investigated, the frictional resistance of the BCG-1 solutions with different concentration was examined using homemade flow loop testing system and the filed test was conducted. Experimental results showed that the first normal stress difference N1 of the BCG-1 aqueous solutions with different concentrations increased with shear stress increasing, moreover, Under high shear stress, a more elastic effects was shown, the higher concentration, the greater the values of the first normal stress difference N1 at the same shear stress. When the concentration of the BCG-1 aqueous solutions was less than the critical associating concentrations, G′was less than G〞, the association was weaker between the molecular chains, and an effective spatial structure did not form, after the concentration of BCG-1 was above of critical associating concentrations, G' was greater than G", the association between molecular chains was increased. As the concentration increased, the curve of G' and G" of BCG-1 solution was gradually closer to parallel, the viscoelastic contribution percentage of the hydrophobic association decreased, while the viscoelastic contribution percentage of molecular interaction between main chain entanglements increased. The drag reduction rate first increased and then decreased as the concentration increased, under strong shear force, the disentanglement between the hydrophobic associating polymer main chain required longer time, and the aqueous liquidity weakened, resistance-reducing capacity reduced. It is not the only way to increase the relative molecular weight to improve resistance-reducing capability of polymer. Hydrophobic associating polymer thick water solution system also had good resistance reduction capability. The field construction showed that the maximum Drag reduction rate was of over 70%.

Abstract:A series of emulsion with different water-oil ratio were prepared， and the viscosity and viscoelasticity of the emulsion were measured. The results showed that the emulsions with more water cut had larger droplet and had a relatively larger viscosity than that with lower water cut. The emulsions showed the characteristics of Newtonian fluid when water content was less than 30%, the viscosity change little with temperature and share rate. When water content was more than 30%, the emulsion showed the characteristics of non-Newtonian fluid, the viscosity change obviously with temperature and share rate. The viscoelasticity of emulsion had a relationship with water cut. Emulsion with higher water cut had a smaller linear viscoelastic region and a more unstable structure. According to the rheological experiment, the addition of demulsifiers could reduce the viscosity of crude oil emulsion, moreover, the emulsion with higher water cut had better demulsification efficiency.

Abstract:Carboxymethyl cellulose (CMC) doped polyaniline was synthesizedby chemical oxidation method. The product was characterized by FTIR absorption spectra. The corrosion inhibition performance, the film formation and destruction, and the corrosion protection mechanism of PANI as a steel corrosion inhibitor in oilfield water injection were measured by polarization technique and electrochemical impedance spectroscopy. Experiment results indicated that the inhibition efficiency in oilfield water injection increased with increasing concentration of PANI. The inhibition efficiency reached 90.8% when the concentration of PANI was 0.4 g/L. PANI was one kind of cathodic corrosion inhibitor. The corrosion mechanism of PANI on Q235 steel in oilfield water injection was “effects of surface cover geometry”. CMC doping was an important reason to improve the corrosion performance.

Abstract:Based on the complex of silicon molybdic acid, barium chloride and polyether polyol, an ultraviolet spectrophotometry was established to determine the absorbance (A) of residual polyether polyol in drilling fluid. The polyether polyol mass fraction (W) was then calculated by the linear relationship between A and W. The optimum determining method was obtained as follows. Hydrochloric acid was added in 3.5 mL diluted sample and the pH value was adjusted to 2. Then 1 mL 300 g/L barium chloride was added, standing for 5 min and centrifuged for 5 min at 9000 r/min. At last, 100.00 μL silicon molybdic acid was added, standing for 30 min and centrifuged for 5 min at 9000 r/min. The supernatant was measured at 210 nm. The linear relationship between A and W was A=?0.1196W+0.6732 and the linear correlation coefficient was 0.996. The drilling fluid of Liang X15 well in Jiangsu oilfield at 1450 m was determined by this method. The mass fraction of polyether polyol was 1.01% and the relative standard deviation was 2.0%.

Abstract:The residual concentration of gemini quaternary ammonium salt was determined with the color reaction method using thymol blue as color developing reagent. The optimal developing conditions was obtained as follows, the concentration of color developing reagent was 0.4%, the best dosage of buffer solution was 10 mL, and the developing time was 60 min. The standard curve of absorbance and concentration of the?gemini quaternary ammonium salt solution was obtained to determine the concentration of the ?corrosion inhibitor. In addition, the influence of interference ions, polyacrylamide, and oil on test results has been studied. Tagged recovery rate of the method could reach up to about 98.6%, which could be generalized in the oilfield. The results showed that when the concentration of Ca²⁺ was below 4000 mg/L, the concentration of Mg²⁺ was below 1800 mg/L, or the concentration of Fe³⁺ was below 1.5 mg/L, the error of the testing method was less than 5%. When the concentration of PAM was below 200 mg/L, the relationship of absorbance and inhibitor’s concentration was linear. The crude oil in the sewage had a great effect on the testing results.

Abstract:As an unconventional oil resource，oil sands and its properties ，separation methods had attracted more and more attention both in china and abroad. In this paper ，the effect of wettability of oil sands on the bitumen separation processes was discussed. The methods for the determination of wettability of oil sands and the influence factors during the determination processes were introduced. The effect of weathering on the wettability of oil sands was analyzed. The effect of wettability on the processability of oil sands was also discussed briefly.

Abstract:Serious scaling problems of stratum and the surface of oil production equipments and their harms in ASP flooding was reviewed. Based on the causes of scaling, composition and structure analysis of dirt and the influence factors of scaling process in ASP flooding, the research prospects of scaling mechanism and the solutions of scaling formation on the surface of oil production equipments were discussed. The development direction of anti-scaling researches of oil production equipments’ surface was proposed.