Abstract:The rheological data of micro-foam drilling fluids was analyzed by linear regression method and the optimum rheological model was power-law model τ=Kγⁿ. The effects of air content, pressure and temperature on the rheological properties of micro-foam drilling fluids were investigated and discussed. The results showed that the stress at high shear rate increased dramatically with increasing volume fraction of foam when the volume fraction of foam was larger than 24%. However, the stress at low shear rate did not change significantly. The effect of pressure was smaller than that of temperature. The micro-foam drilling fluids had good stability at high temperature（100—150℃）, and no thickening and thinning phenomena were observed. The constitutive equations of tested liquids at different temperature were obtained by linear regression and the linear correlation coefficients were all more than 0.99. Based on the equations, the variations of liquidity index n and consistency coefficient K with temperature were established: n=5.2584×10^-9 T⁴-2.0122×10^-6 T³+2.8151×10^-4 T²-1.6739×10^-2 T+0.8298，(R²=0.9982)；K=-1.0769×10^-8 T⁴+4.7940×10^-6 T³-8.2658×10^-4 T²+5.8472×10^-2 T-0.1180，(R²=0.9998)

Abstract:With fatty acid and amines as raw material, carboxy-amine small molecule inhibitor was prepared. The effect of type of amine, length of fatty acid chain, mole ratio of acid and amine, and dosage of inhibitor on liner expansion of bentonite was studied. Orthogonal and single factor experiment results showed that lauric acid-diethylenetriamine compound, with acid and amine functional group mole ratio of 1:2, displayed the highest inhibitory followed by oleic acid-tetraethylenepentamine compound with the dosage of 0.5%. The linear swelling ratio of bentonite at 90 min was 24.3% in 0.5% lauric acid-diethylenetriamine solution, which was only 43.5% of that in 4.0% potassium chloride solution and 32.8% of that in distilled water under the same condition. The linear swelling ratio of bentonite at 90 min was 39.2% in 0.5% oleic acid-tetraethylenepentamine solution, which was only 59.4% of that in 4.0% potassium chloride solution and 44.9% of that in distilled water under the same condition. Mud ball experiment results showed that the lauric acid-diethylenetriamine solution could inhibit clay ball from hydration and swelling obviously. And it had better effect than oleic acid-tetraethylenepentamine. The fatty acid-amine complexes could improve the viscosity of water-based drilling fluid at room temperature. After 0.3% lauric acid-diethylenetriamine was added, the apparent viscosity (AV) of drilling fluid increased 1.9 times. However, the AV only increased 1.0 times, when 0.5% oleic acid-tetraethylenepentamine was added. Moreover, lauric acid-diethylenetriamine and oleic acid-tetraethylenepentamine were compatible with KD-03 polysaccharide pretreated drilling fluid. The AV of drilling fluid was increased by 2.4 and 3.5 times, respectively.

Abstract:Home-made surfactant REB with hydroxyl, RDB contained a single B-O spiro and ROB contained double B-O spiro. The critical micelle concentration (ccmc) of REB, RDB and ROB was 2.7×10-4, 1×10-3 and 0.8×10-4 mol/L, and γcmc of that was 29.6, 20.8 and 28.3 mN/m, respectively, which indicated good surface activity. When 1% REB, RDB or ROB was added to the mud, the viscosity coefficient of filter cake (Kf) decreased from 0.1944 to 0.1139, 0.1051 or 0.1139 respectively. Medium slurry adding ROB foamed severely whose density was less than 0.7 g/cm3. ROB was not suitable as a lubricant for drilling fluid. The Kf value of slurry containing 0.5% REB was 0.1495 and 0.2123 at room temperature and after 16 h rolling at 80℃, which showed poor heat resistance performance. The Kf value of slurry containing 1% RDB before and after hot rolling was 0.1228 and 0.1495, which showed good heat resistance performance. The Kf value of slurry containing 1% RDB was 0.1228 and 0.1317 before and after adding 4% NaCl, which showed good salt tolerance. RDB could be used as drilling fluid lubricant.

Abstract:One of the effective means to improve the drilling speed was adding anti-sticking agent to drilling fluid which prevented bit balling or partial of bit adhering by drilling cuttings. A drilling fluid anti-sticking agent was synthesized by a series of reaction including humic acid sulfonation, chlorination, and amidation. The optimum reaction condition was obtained as follows: humic acid reacted with concentrated sulfuric acid to generate sulfonated humic acid at 160℃ for 8 h in a ratio of mass to volume 3:5; then reacted with excess thionyl chloride to produce humic acid chloride at 70℃ for 6 h; at last the humic acid chloride reacted with fatty amine at 0—10℃ for 4 h in mass ratio 25:4. The performance evaluation results showed that the anti-sticking agent could change drill bit and cuttings surface from strong hydrophilic into weakly hydrophilic, and reduce the surface tension of drilling fluid significantly. The wetting contract angle reached the maximum 68.3° from 33°and the surface tension decreased from 74.4 to 42.0 mN/m when the mass fraction of anti-sticking agent increased from 0 to 1.5%. The friction coefficient reduced from 0.43 to 0.27 when 2% anti-sticking agent was added to 4% bentonite slurry. The expansion rate of bentonite core was 1.6% and 3.5% in 1.5% anti-sticking agent solution when the test time was 2 h and 16 h respectively.

Abstract:In order?to improve the pressure-bearing plugging strength under the complicated geological conditions，the effect of the temperature-change thickener (TCT)on the thixotropic and plugging properties of the cement slurry systems, the conventional pressure-bearing plugging systems and reticular fiber plugging systems. The results showed that, under normal temperature conditions, the TCT has little effect on the rheological properties of the pressure-bearing plugging system, which is favorable to pump the plugging slurry. When the slurry temperature rose to above 70℃, the TET played a thickening role by cross-linking reaction, and the viscosity of the system was above 150 mPa·s, at the same time, the gel strength and thixotropy of the pressure-bearing plugging agent was improved, making the sealing slurry from liquid into a semi-solid plastic paste structure. Thus, the plugging slurry could reside effectively and form plugging layer rapidly in the lost circulation formations. By simulating the large pore path (6 mm) and fracture(6 mm) of thief zones, it was found that the pressure-bearing strength of the plugging slurry exceed 5 MPa. In the plugging system, the optimum dosage of the TCT was 3%.

Abstract:The anti-temperature and anti-shear properties of two surface cross-linked acids under different crosslink ratios, 120℃ and 170 s^-1, the slurring sand capacities at room temperature and 90℃, and the gel-breaking features at 90℃ were studied in laboratory. There were two formula of acids, one (formula Ⅰ) was: 20% HCl+0.8%~1.2% DMJ-130A (thickener)+2.5% DJ-04 (corrosion inhibitor)+0.5% DJ-02 (cleanup additive)+1.2% DJ-07 (ferric ion stabilizer)+0.5% DJ-10 (demulsifier), with DMJ-130B crosslinking agent made from organometallic compounds, the other (formula Ⅱ) was: 20% HCl+0.6%~1.0% FA-214 (polymer)+2.5% DJ-04+0.5% DJ-02+ 1.2% DJ-07+0.5% DJ-10, with AC-14 crosslinking agent made from organometallic compounds. The viscosity of formula Ⅰ was within 100~250 mPa×s, and kept 200 mPa×s above after shearing 50 min when the crosslink ratio was 100:0.8. And that was within 80~170 mPa×s, and kept about 100 mPa×s after shearing 37 min when the crosslink ratio was 100:1.0. The viscosity of formula Ⅱ was within 40~57 mPa×s after shearing 20 min when the crosslink ratio was 100:1.0. And that changed in the period of beginning, and decreased sharply from 600 mPa×s to 60 mPa×s after shearing 15 min when the crosslink ratio was 100:1.3. The sedimentation rate of proppant haycite in two surface cross-linked acids and a regular guar cross-linked fluid was similar, the value was in the range of 2.4×10^-3—3.8×10^-3 mm/s. Gel-breaking for the two surface cross-linked acids fulfilled completely under 90℃ after reaction 4 hrs with carbonate rock core, and formula Ⅱ was earlier than formulaⅠ. Formula Ⅰ had better slurring sand capacity, retarding H+ transport capacity, improving distance of active acid flow, and enlarging swept area of fracture than formula Ⅱ.

Abstract:The acid-rock reaction rates between four different acids, such as conventional acid, gelled acid, steering acid, crosslinked acid, and carbonate rock were tested using self-developed device which could measure reaction kinetics parameters of different viscosity acids with carbonate. At the same time, common ion effect on acid-rock reaction rate in different acid systems was considered. The results showed that the average acid-rock reaction rate of conventional acid, gelled acid, steering acid and crosslinked acid was 6.0909×10^-6, 5.4583×10^-6, 10.6005×10^-6 and 4.8191×10^-6 mol/(cm²·s)，but that changed to 3.3935×10^-6, 5.1353×10^-6, 9.0923×10^-6 and 4.7386×10^-6 mol/(cm²·s) after adding CaCl₂ and MgCl₂ into the acids respectively. The reaction rate of conventional acid after adding common ion was slower than that without it, and the spent acid concentration of convention acid with common ion was higher than that of fresh acid. The impact of common ion effect on the reaction rate of gelled acid, steering acid and crosslinked acid increased in 8, 4 and 12 min after reaction respectively when common ion existed. Four acid systems were arranged according to the viscosity in following order: crosslinked acid (250 mPa·s)＞gelled acid (31 mPa·s)＞steering acid (18 mPa·s)＞conventional acid (3 mPa·s), and according to the decrease order of reaction rate under the influence of common ion in following order: conventional acid (44.29%)＞steering acid (14.23%)＞gelled acid (5.92%)＞crosslinked acid (1.68%). The effect of common ion was inversely proportional to the viscosity of acid. The higher viscosity, the smaller influence of common ion effect was.

Abstract:A high temperature fracturing fluid with low formation damage was developed by mixing supramolecular anionic surfactant (VES-HT01) and 6% KCl. Fracturing fluid evaluating experiment results showed that the viscosity of fracturing fluid increased first and then decreased with increasing temperature when the shearing rate was 100 s^-1. The maximum viscosity was 180 mPa·s at 100oC and the viscosity was 55 mPa·s at 150oC. The fluid viscosity was unchanged after shearing 60 min at 140oC and 170 s^-1, which showed good viscoelasticity. The settlement rate of ceramic proppant in fracturing fluid was 5 and 33 mm/min at 25oC and 100oC, respectively. The VES gel could be broken with no residue by contacting with 2%, 1% diesel after 120 min at 50oC and 100oC. The viscosity of broken-gel fluid was 3 mPa·s and surface tension was 23.5 mN/m. The fracturing fluid had good anti-microbial properties. The cost of fluid was comparable to that of conventional guar fracturing fluid.

Abstract:According to the geological characteristics and temperature (80℃) conditions of low permeability oil field in northern Shaanxi, homemade 20 carbon atoms sulfonate anionic surfactant (D3F-AS05) was used in performing hydraulic fracturing. Anion fracturing fluid was composed of 3% D3F-AS05, 6% KCl, 0.6% KOH and 0.2% EDTA. The performance of anion fracturing fluid was studied, such as rheological property, viscoelastic, shear resistance, suspended sand performance, and gas gel breaking performance. The results showed that the anion fracturing fluid had good rheological properties at 80℃. The viscosity of fluid remained at 90~100 mPa·s at a shearing rate of 170 s^-1. The viscosity of fluid was essentially constant with the increase of shearing time. The ratio of storage modulus to loss modulus was 39.2, but that of guar gum fracturing fluid was only 2. The viscosity of anion fracturing fluid was low and elasticity was good. After a series of shearing rate changes (170, 0, 200, 500, 170 s^-1), the viscosity of anion fracturing fluid changed and returned to the original state (90~100 mPa·s) finally. The injection pressure of carbon dioxide gas increased from 0 to 4 MPa, the viscosity of fracturing fluid rapidly dropped from 65 to 2 mPa·s. The injection pressure of natural gas increased from 0 to 12 MPa, the viscosity of fracturing fluid reduced by half. Nitrogen did not change the viscosity of fracturing fluid. As the temperature increased from 40 ℃ to 100 ℃（40，60，80，100 ℃）, the viscosity of anionic surfactant fracturing fluid increased first and then decreased. At 80℃, the viscosity of fracturing fluid reached a maximum (about 94 mPa·s in average). The average settlement rate of single particle proppant in this fracturing fluid gradually increased with increasing temperature. At the same temperature (less than 100℃), the average settlement rate of single particle size ceramic in guar gum fracturing fluid was significantly greater than that in anion fracturing fluid. The average settlement rate of ceramic with 10% sand ratio was minimum in anion fracturing fluid.

Abstract:The viscoelasticity of fracturing fluid was closely related to the proppant suspending capacity, which was the important parameter of fracturing fluid performance and one of the key factors of successful fracturing. The viscoelasticity and single-particle settling rate of proppant about base fluid or gel of hydroxypropyl guar gum (HPG), synthetic polymer FA92 and xanthan gum solution were tested. The results showed that viscosity was the major performance for HPG and FA92 base fluid. When the mass fraction of thickening agent increased from 0.2% to 0.5%, the storage modulus (G′) of HPG and FA92 increased from 0.16 and 0.12 Pa to 0.88 and 0.45 Pa, the loss modulus (G″) increased from 0.16 and 0.18 Pa to 1.86 and 0.86 Pa, respectively, proppant settling rate decreased from 15.190 and 15.380 cm/min to 0.729 and 0.952 cm/min at 20℃. The dosage of thickening agent increased, the viscosity and proppant suspending capacity enhanced. The higher temperature, the smaller viscoelasticity of liquid was. Xanthan gum solution had greater flexibility, and the flexibility was far greater than the viscosity. At 20℃, G′ and G″ of 0.5% xanthan gum solution were 7.17 and 2.81 Pa, and that changed to 5.774 and 2.514 Pa at 60℃. It’s support settling rate was 0, 0.075 cm/min at 20℃, 60℃, which showed good suspending ability and could be used as fracturing fluid at non-crosslinked state. Elasticity was the key performance of HPG and FA92 gel. At room temperature, when the mass fraction of crosslinking agent changed from 0.1% to 0.5%, G′ of HPG/borax gel, HPG/ BCL-81 gel and FA92/FAS-301 gel increased from 0.29, 0.13, 0.56 Pa to 0.90, 6.02, 8.31 Pa, G″ of that increased from 0.50, 0.75, 0.87 Pa to 0.77, 1.05, 0.98 Pa, and proppant settling rate of that decreased from 0.891, 0.094, 0.015 cm/min to 0.009, 0.006, 0 cm/min, respectively. The higher crosslinker concentration, the greater gel elasticity and the stronger proppant suspension was. The gel elasticity of FA92 was higher than that of HPG, and it’s proppant suspension was strongest.

Abstract:Based on the sandy conglomerate gravel core of extra-low permeability from Toutun River formation of Fudong slope area, the effects of static and dynamic filtration of guanidine gum fracturing fluids and broken fluid on permeability of the natural core and of the sand pack prepared with natural core powder were evaluated through flow test system. Core static filtration results showed that guanidine gum fracturing fluid filtration had little harm to the cores from Toutun River formation of Fudong slope area. In the core dynamic filtration process, guanidine gum fracturing fluid formed the filter cake on the end of the core with the permeability of 9.61×1^-3μm², thus leading to the core damage rate obtained to 25%. However, the filter cake hardly formed on the end of the cores with the permeability of 0.32×10^-3μm² and 46.20×10^-3μm², respectively, leading to the core damage rate was less than 10%. The results indicated that the state of the filter cake in the dynamic filtration process also depended on the porous medium besides fracturing fluid. In addition, it was found that the permeability reduces by 80% by injecting the broken fluid containing 320 mg/L residue into sand pack with a water permeability of 1300×10-3μm2.The results will provide guidance on fracturing design in Toutun River formation of Fudong slope area.

Abstract:in long-term water drive reservoir, small dose and short radius profile control can not meet the needs, so deep profile control and flooding are needed. During the placement and processing of conventional deep profile control and flooding agent, the zoning classification formed by the changes of pressure field and fluid field are not taken into account. In the paper, the iso-pressure drop gradient progressive deep profile control and flooding method were studied. According to drawdown curve, the formation was divided into near wellbore zone, well-far zone and deep zone. As each zone of the pressure gradient is different and therefore different intensity of slugs are required. According to iso-pressure drop gradient rule, namely the breakthrough pressure gradient of agent is equal to the formation pressure gradient, each slug blocking agent was screened. Then the slugs of agent were combined, and optimized at the lowest cost. Hence, the flooding agents with different intensity were placed in different locations, and the fluid diversion of whole course achieved by combining the different intensity of blocking agent. The method was tested successfully for 2 wells in Zhuangxi block of Shengli Oilfield, the construction slugs were divided into three slugs after our optimization. The average injection pressure was increased by 3.25 MPa, approximate 400 tons of incremental oil was obtained with 3.04% water-cut decrease.

Abstract:The Block Gao89 of Shengli oilfield belongs to high temperature, low permeability and heterogeneous oil reservoir. Aimed at the reservoir, a recipe of CO₂ gas flooding channeling sealing agent (CGFCSA) was optimized as followed: the dosage of AM was 4.5% (mass fraction, the same below), the dosage of N,N-Methylenebisacrylamide was 0.05%, the dosage of modifier was 0.3%, the dosage of initiator was 0.25%, the dosage of formaldehyde was 0.25% and the dosage of inhibitor ES was 0.5%. The performance of the CGFCSA was probed; the sealing and oil displacement experiments were carried out. When the gel solution of pH was 3-7, the gelling time could be controlled within about 6 h and pH value had little effect on it. When the gel was put into the environment for 3 month at 126℃ and at pH=3, the viscosity changed little. the viscosity of the channeling sealing agent was more than 150×10⁴ mPa·s when the pressure of CO₂ was between 0 and 10 MPa at 126℃. The shear performance of the gel was perfect, , the viscosity was 62×10⁴ mPa.s after sheared at the speed of 183 s^-1 for about 20 min. The physical model test showed that the system could reduce the permeability remarkablely, , the plugging rate was more than 90% after water flooding of 40 PV. The sand pack of oil displacement experiment showed that the system had good performance of sealing channeling for CO₂ and the EOR could be further improved by 9.32%.

Abstract:On the basis of new type of foaming agent DLF for reservoirs with high temperature and high salinity, , its comprehensive performances were tested and evaluated, such as the surficial/interfacial tension, foamability, stability, oil resistance, oil displacement efficiency, et al. The results showed that, at the optimal mass fraction of 0.5%, the DLF system had the lowest surficial/interfacial tension, and highest high foamability, stability and oil resistance. The displacement efficiency of DLF surfactant system could reach 23.06% higher than that of water under stimulated formation condition. Under the comprehensive action of powerful washing and foam plugging and diversion, synchronal diversion of DLF low tension foam flooding could be maintained for a longer period, and the remaining oil in high/low permeability core, especially low one, could be displaced to the max degree. Hence, by the end of subsequent water flooding, the integrated oil recovery was increased by 28.9%, thereinto, low permeability core was increased by 48.8%, and the high permeability one was increased by about 21.6%.

Abstract:In this paper, a new indepth water shutoff and profile control agent composed of 2% modified water soluble phenic resin and 1% thermo-sensitive latent acid was presented, which is used to reduce indepth steam channeling in heavy oil reservoir. The performance of delaying polycondensation, high temperature tolerance and long-term stability was investigated. The results tests showed the homogeneous transparent and low viscous solution was formed at brine with high salinity, such as 200 g/L NaCl, 3.5g/L CaCl₂, or 7g/L MgCl₂·6H₂O solution. The said solution kept stable after aging one week under temperature lower than 80℃, which met the need of selective injection of diverting agent into the deep formation with high permeability channel. Thermosetting phenolic resin was catalyzed to solidify by the latent acid under the temperature higher than 100℃，whose plugging rate reached 100%, plugging strength and resistance to stream reached five thousands pascal. The gel properties kept stable after storing more than three months at 200℃.

Abstract:The effect of formation water hardness, salinity and oil on foam performance of homemade foam agent (DHF-1) was investigated aiming at heavy oil reservoir in Shengli oilfield. The compatibility of DHF-1 with displacement agent alkylbenzene sulfonate surfactant (WT) was determined. The displacement effects of different displacement mode were compared. Experiment results showed that foaming volume and half-time of DHF-1 decreased with increasing hardness and salinity of formation water. When the hardness of formation water was 120 mg/L (CaCl₂), the foaming volume and half -time of DHF-1 was 155 mL and 65 s respectively, and turbidity was seen in the interface of foam system. When the salinity of formation water was 20000 mg/L, the foaming volume and half-time of DHF-1 was 168 mL and 43 s respectively, and insoluble materials generated in foam system. The half-time of DHF-1 decreased quickly with increasing oil dosage. When the mass ratio of oil to DHF-1 was less than 0.3, the foaming volume of DHF-1 changed little, and later decreased quickly. Foaming property of DHF-1 wasn’t affected by WT. The oil-water interfacial tension of oil displacement system decreased with increasing DHF-1 dosage. When the mass ratio of DHF-1 to WT was 20, the interfacial tension was 0.05013 mN/m. The ultimate recovery of steam-foam-displacement agent combination flooding was 72.1%, which increased by 14.6% comparing with that of steam flooding. The synergy effect was significant.

Abstract:Alkali lignin was one better kind of plugging agent which could be used for steam flooding. But phenolic resin served as alkali lignin cross-linking agent was synthesized by phenol and formaldehyde which resulted in relatively high cost. The chemical activity of alkali lignin was improved after hydroxymethylation reaction. And the product, HKLF, partially substituted for resol to synthesize alkali lignin formaldehyde resin. The optimum reaction condition was obtained as follows: 0.75% NaOH dosage, 3.5 hrs reaction time, 85℃ reaction temperature, 3:1 alkali and formaldehyde mass ratio, 20% replacing proportion of HKLF and resol. Alkali lignin gel solution with 10.00 pH value was prepare by mixing 10% alkali lignin and 4% alkali lignin resin crosslinking agent. The initial viscosity was 3.8 mPa·s at 25℃ before gel, and the performance in pumping was good. The gel strength loss was 5.44% after rabbling 5 hrs with 3000 r/min at room temperature which demonstrated a perfect anti-shear stability. The gel strength of cross-linked alkali lignin was 0.092 MPa and gelling time was 1.5 hrs at 200℃. Gelling temperature range was 120—250℃. The gel strength loss was 4.12% after placing at 200℃ one and a half months which showed a good thermal stability. The core plugging experiment results showed that the breakthrough pressure increased and the plugging rate reduced with decreasing pro-permeability of sand filling tube. The lowest steam breakthrough pressure was 3.52 MPa and the minimum plugging rate was 96.6%. The greater permeability contrast, the more alkali lignin gel got into high permeable zone. The highest profile-improve rate was 3.638. Compared with resol, alkali lignin formaldehyde resin had a better performance and lower price.

Abstract:In high-temperature and high-pressure (HTHP) reaction kettle, with formic acid as hydrogen donor and nickel salt as catalytic system, the influence factors on aquathermolysis reaction of Niujuanhu oil were studied by considering the effects of different catalyst systems, crude oil properties and reaction temperature on oil viscosity reduction ratio and SARA changes. The results showed that viscosity reduction rate of nickel oleate, nickel naphthenate and nickel sulfate catalytic systems to stock tank oil was 65.3%, 52.6% and 55.7%. Nickel oleate was selected as optimum catalytic system. After aquathermolysis catalytic reaction, the content of colloid and asphaltene decreased, and that of saturated hydrocarbons and aromatic hydrocarbons increased. The more content of heavy hydrocarbon in oil, the stronger aquathermolysis reaction, and the more favorable viscosity reduction of oil was. After aquathermolysis catalytic reaction, the viscosity reduction rate of residuum, stock tank oil and simulated formation oil was 90.41%, 64.78% and 55.78% at 45℃. The content of colloid and asphaltene in crude oil was the basic root of aquathermolysis reaction. The conversion ratio of colloid and asphaltene converting into saturated hydrocarbon and aromatic hydrocarbon in residuum, stock tank oil and simulated formation oil was 36.50%, 26.51% and 16.73%. The viscosity reduction rate of simulated formation oil was 56.43%, 55.78%, 48.23% and 14.14% at 280℃, 220℃, 180℃ and 100℃ reaction temperature. The optimum reaction temperature was 220℃. The macromolecule bond rupture of colloid and asphaltene into small molecule saturated hydrocarbons was the main reason of permanence viscosity reduction of crude oil during aquathermolysis reaction.

Abstract:Gravity draining assisted steam flooding conducted by Liaohe oilfield had made significant development effect. The draining law of condensed water was unclear during the development. It was simulated by using homogeneous and heterogeneous visual cores with glass etching. In the middle of two piece of glass, a horizontal reservoir which was composed of pore and throat formed. The images before and after gravity draining which were transformed into computer numerical signal by image acquisition system were contrasted. The effect of core homogeneity and differential pressure on draining law was analyzed through experiment data. The results showed that the condensed water did not drain evenly, but discharged along a certain draining channel. The instantaneous quantity of draining water with the changes of differential pressure was not obvious in the early of forming draining channel. It increased with increasing differential pressure during the medium-term, and that was stable at the late stage. The formation of drainage channel in homogeneous cores was earlier than that in heterogeneous cores. The effect of differential pressure on instantaneous quantity of draining water in heterogeneous cores was bigger than that in homogeneous cores after the draining channel formed.

Abstract:In view of the actual conditions of high temperature, high salinity in Orienteoil field, the viscosity- concentration relationship, viscosity-temperature relationship and stabilization of three kinds of polymer oil-displacing agents was investigated. It could be concluded that, with the increase of the concentration of the three kinds of polymer oil-displacing agents, the viscosity increased as well. Obviously, the tackification range of APP5 oil-displacing agent was greater than that of the other two kinds of polymer oil-displacing agents, and when the concentration of the APP5 was 2500 mg/L, the requirements of the theory viscosity value of the reservoir could be met. However, due to the specific conditions of the reservoir with high temperature (95℃), the single polymer APP5 could not continue to maintain theory viscosity value. Secondly, chromium acetate (the mass fraction is 2.7%) and 200 mg/L retarder (the main ingredient is hydroxy carboxylic acid salt—sodium tartrate) were added in the single polymer solution at polymer to “Cr³⁺” mass ratio of 60:1, the crosslinking reaction took place. The results showed that the viscosity of the three gels tended to stabilize after 60 days, and Cr³⁺/APP5 gel with polymer to “Cr³⁺” mass ratio of 60:1 could meet the requirements of the theory viscosity value of the reservoir. Finally, indoor physical simulation experiments indicated that when the average water content of oil field reaches 90%, Cr³⁺/APP5 gel was injected for 0.6 PV, the oilfield economic benefits achieve the best condition.

Abstract:A new functional monomer B with hydrophilic long-chain structure was formed by 10-hydroxy decanoate acid and allyl chloride. By reversed-phase emulsion polymerization method, taking azobisisobutyronitrile hydrochloride as initiator, decane, emulsifiers, acrylic acid, acrylamide and monomer B were mixed to develop a macromolecular polymer emulsion (comb). The effect of experiment factors such as pH value, the dosage of AM, AA, monomer B and initiator, the total mass fraction of monomer, polymerization temperature and reaction time on the intrinsic viscosity of polymer was studied. The optimum synthesis condition of comb macromolecular emulsion with high characteristic viscosity through orthogonal experiment was obtained as follows: 40℃ initiation temperature, 7 pH value, 40% total mass fraction of monomer, AA, monomer B and initiator accounted for 20%, 5% and 0.15% of monomer total mass respectively, 6 h reaction time. Under optimum polymerization condition, the effective content of comb was 30% and the intrinsic viscosity was 22.9 dL/g.

Abstract:A near wellbore shear simulation device was designed on the basis of previous work. And two typical polyacrylamide polymer, partially hydrolyzed polyacrylamide (HPAM) and hydrophobically associating polyacrylamide (HAPAM) were selected in the laboratory. The viscosity and viscosity retention rate, the mobility control capability and the oil displacement efficiency of two polymer solutions after shearing were investigated. The experimental results showed that, with the increase of intake capacity, the viscosity and viscosity retention rate of two polymer solutions at the concentration of 1750 mg/L decreased rapidly. Morever, the viscosity and viscosity retention rate of HAPAM solution after sheared, was higher than that of HPAM solution because of its hydrophobic interaction. When two polymer solutions were sheared at the intake capacity of 10 m³/(m·d) and 20 m³/(m·d), respectively, the resistance factor and residual resistance factor of HAPAM solution were much larger than that of HPAM solution; the resistance factor loss of the HAPAM solution was less than that of HPAM solution and the residual resistance factor loss was higher than that of HPAM solution. HAPAM solution after sheared had higher oil displacement efficiency than that of HPAM solution. While, the loss of oil recovery rate of HAPAM solution is slightly higher than that of HPAM solution.

Abstract:The effect of ethylene oxide chain length (EO number), temperature, inorganic salts and pH value on sodium alkyl phenol polyoxyethylene ether carboxylate (APEC(Na)) reducing interfacial tension (IFT) was researched under Chengbei reservoir conditions. The results showed that when the EO number was 6, the IFT between crude oil and surfactant solution of sea water could achieve the lowest value 6.5×10^-3 mN/m. When the temperature rose from 30℃ to 80℃, the IFT between sea water contained 0.3% APEC(Na) (EO=6) and crude oil reduced from 5.6×10^-2 mN/m to 6.4×10^-3 mN/m. While after the surfactant completely dissolved between 50℃ to 80℃, the temperature had no influence to IFT. When there was one kind of inorganic salt in solution, the IFT decreased first and then increased with increasing concentration of inorganic salt. The effect of cation on IFT was stronger than that of anion. When the mass concentration of Na₂SO₄, MgCl₂ and CaCl₂ was 25×10⁴,10×10⁴ and 25×10⁴ mg/L, the minimum IFT of oil-water was 1.2×10-3, 2.2×10-3 and 5.8×10-3 mN/m, respectively. In inorganic ions, Mg²⁺ had more obvious influence to APEC(Na) than others. Adding 1% NaOH to APEC(Na) solution of sea water, the APEC(Na) with 7 EO number could reduce the IFT to the lowest value 2.9×10^-3 mN/m. The IFT between APEC(Na) (EO=7) solution and crude oil decreased first and then increased with increasing pH value of sea water. When the pH value was 13.4 (1% NaOH), the IFT reached the minimum value.

Abstract:The adsorption loss of surfactant on the sandstone has an influence on oil displacement efficiency of viscosity-reducing agent. In the paper, the method was established to determinate the concentration of nonionic /anionic viscosity-reducing agent system and was used to measure the adsorption loss. The results indicated that the complex viscosity-reducing system composed of anionic surfactant XJ-1+ nonionic surfactant OP-10 was suitable for the Zhong-2 section of the Gudao oilfield. In the complex system, the concentration of XJ-1 was determined by two-phase titration method, and the concentration of OP-10 was determined by cobalt thiocyanate colorimetry. The adsorption of the complex viscosity-reducing system on the surface of the oily sand reached saturation value of 16.28 mg/g. Interfacial tension between viscosity-reducing agent system, 0.15%XJ-1+0.15%OP-10~ 0.3%XJ-1+0.3%OP-10, with the crude oil before and after adsorption change little, and the oil recovery efficiency of viscosity-reducing agent system was more 15.6% than that of water flooding.

Abstract:Taking Zhengwang heavy oil as the study object, kerosene-water simulated emulsion was prepared. The effects of gathering and transportation viscosity reducer (SH) compounded by non-ionic and anionic surfactants on interfacial tension, zeta potential, dilational rheology, emulsion stability and the association between interfacial properties and emulsion stability were investigated. The results showed that when the mass fraction of SH viscosity reducer was below 0.05%, the interfacial tension and zeta potential were influenced little while the dilational modulus decreased from 16.18 to 4.60 mN/m rapidly. The elasticity modulus reduced from 13.76 to 3.54 mN/m, and the viscous modulus reduced from 85.12 to 29.46 mN/m. The dehydration rate increased from 4.4% to 83.1%. Thus the decrease of interfacial film strength was the main factor affecting the emulsion stability. The larger dilational modulus, the more stable emulsion was. When the mass fraction of SH viscosity reducer was between 0.05% and 0.3%, the interfacial tension decreased from 48.93 to 35.50 mN/m and the absolute value of zeta potential decreased from7.83 to 3.95 mV. The dilational modulus, elasticity modulus and viscous modulus increased to 7.38, 6.42 and 36.52 mN/m, respectively. The dehydration rate decreased to 60.0%. When the mass fraction of SH viscosity reducer was below 0.3%, the dilational modulus had a good correlation with dehydration rate of simulated emulsion. The dilational modulus could be used to represent emulsion stability.

Abstract:A five-membered or six-membered ring chelate formed by polydentate ligands and metal ions was very stable. Based on the orbital energy theory, the thioureido imidazoline molecule was designed by connecting several groups or structures which had inhibition function to a molecule. Imidazoline derivatives whose colour was orange was synthesized by polyethylene polyamine, oleic acid and thiourea. The structure was characterized by infrared spectroscopy. Anti-H₂S corrosion inhibitor XL-1 was obtained by mixing synthetic thioureido?imidazoline with surfactants, pyridines, aldehydes and acetylenic alcohols. The corrosion inhibition effect of XL-1 was good. On the condition of 2500 mg/L H2S and 0.25% XL-1, the inhibition efficiency of XL-1 was 95.3% and corrosion rate of carbon steel was 0.013 mm/a at 25℃. XL-1 had good resistance of high temperature (90℃). When the temperature rose from 25℃ to 90℃, the corrosion rate of carbon steel increased from 0.007 mm/a to 0.023 mm/a, and the inhibition efficiency decreased from 95.3% to 89.0%. The corrosion rate of carbon steel increased, and the inhibition efficiency decreased with increasing dosage of NaCl. Under the condition of 0.5% XL-1, 10% mass fraction of NaCl, 2500 mg/L H2S and 55℃ corrosion temperature, the corrosion rate of H2S to carbon steel was 0.027 mm/a and the inhibition efficiency was 87.3%. When XL-1 mixed with common drilling fluids, chemical agents, and formation water in regions of Sichuan and Chongqing, there was no separation and the inhibition efficiency was above 92%, which showed a good compatibility. This corrosion inhibitor could be widely applied in all sorts of chemical anti-corrosion operations in sour gas fields.

Abstract:Using the self-made epoxysuccinic acid as raw material, polyepoxysuccinic acid (PESA) was synthesized in virtue of anionic polymerization. In addition, the expected product was characterized by means of IR. and the six factors influencing relative molecular weight and yield of PESA were investigatd, as a result, the optimized reaction conditions was obtained. Under the optimized conditions, a series of scale inhibitors whose molecular weights were between 350 and 1300 were prepared in the yield of more than 65%. Then, conductivity analysis was used to analyze and evaluate the scale inhibition performance of the synthesized PESAs in oilfield wastewater containing calcium carbonate, strontium sulfate, and barium sulfate. It was indicated that the performance of PESA was relative to its relative molecular weight and concentration. When the relative weight of PESAs were between 1100 and 1300, the scale inhibition performance was better, and there existed a good “threshold effect ”. The optimum dosage and the relative molecular weight of PESA should be selected according to the different type and concentration of scale in practical application.

Abstract:It was difficult to rapidly and accurately evaluate the scaling tendency of produced water containing polymer for the chelation ability of residual polymer. In this paper, electrochemical quartz crystal microbalance (EQCM) technique was used to evaluate the accelerated calcium carbonate scaling behavior in produced water containing polymer. The results showed that polarized potential, temperature and the concentration of calcium ion had remarkable influence on scaling. More negative polarization of the potential, higher temperature and more concentrated calcium solution were beneficial to scaling tendency and scaling rate. The presence of linear polyacrylamide (HPAM) lowered the scaling rate on the surface of gold electrode. The inhibition effect of 50 mg/L HPAM addition was more apparent than that of 500 mg/L HPAM. The higher polarized potential, the more number of calcium carbonate crystal was with greater size and more obvious aggregation. The presence of HPAM had pronounced effect on the morphology of calcium carbonate crystals. In the absence of HPAM, the shape of scale was mainly hexahedron. In lower polarized potential (-0.6 V), the CaCO3 crystals looked like balls compiled with pieces and regular hexahedron. In higher potential (-1.4 V), it took the shapes of irregular round piles (50 mg/L HPAM) or flower alike structures (500 mg/L HPAM). The main reason for these special morphologies lay in the potential field effect and the adsorption of polymer molecules on the scale crystal.

Abstract:According to the composition of wastewater produced in SZ36-1 polymer flooding of oil field, the effect of molecular weight, concentration and hydrolytic degree of hydrophobic associating polymer on the apparent viscosity, particle sizes of oil droplets, Zeta potential, dynamic interfacial tension, equalize interfacial tension and interfacial dilational properties were measured. The results indicated that the produced polymer with low molecular weight could improve the apparent viscosity of wastewater, the zeta potential of O/W emulsion and the oil-water interfacial film strength were increased after adsorption of polymer in oil-water interface. Consequently, the wastewater emulsion stability was increased, and the coalescence efficiency of oil droplets in wastewater decreased greatly.

Abstract:The loose and hard soil was named No. 1 which formed by ground crude oil from Liaohe oilfield gathering station, with 7.4% oil and 17.8% water content, 2.64 g/cm³ density and 7.8 pH value. Heavy oil contaminated soft and bonding soil was named No. 2, with 21.5% oil and 35.6% water content, 2.23 g/cm³ density and 7.8 pH value. Heavy oil contaminated No. 1 soil contained 29.11% saturated hydrocarbon, 22.54% aromatic hydrocarbon, 30.26% colloid and 18.08% asphaltene. Heavy oil contaminated No. 2 soil contained 25.19% saturated hydrocarbon, 26.23% aromatic hydrocarbon, 32.49% colloid and 16.09% asphaltene. 1—5 strains was selected by enrichment and separation from heavy oil contaminated soil. Taking heavy oil as sole carbon source, the degradation rate of 1—5 strains to crude oil was 20.0%, 6.1%, 22.5%, 12.7% and 34.7%, respectively. No. 5 strain with higher degradation rate and No. 1 strain with good adaptability to environment were isolated as predominant bacteria. The optimum N and P source of No. 1 bacteria was (NH₄)₂SO₄ and K₂HPO₄, the corresponding degradation rate was 28.13% and 15.16%. And that of No. 5 bacteria was KNO₃ and KH₂PO₄, the corresponding degradation rate was 49.12% and 50.04%. 0.15% H2O2 had a good effect of oxidative degradation and promoted a role, however, the degradation rate used H₂O₂ alone was 25% (60 d). Within 60 days after adding surfactants, oily soil degradation rate greatly increased. The highest degradation rate of TW-80, TW-40 and rhamnolipid was 73%, 70% and 84% respectively. So 0.1% TW-80 and 0.1% rhamolipid composite surfactant was selected as penetrating agent for oil soil microbial degradation. Through the small scale test, the degradation rate of No. 1 and No. 2 heavy oil contaminated soil achieved 66.7% and 73.5% respectively 80 days later which indicated the degradation effect was good.

Abstract:Cation exchange capacity (CEC) had important influence on the hydration characteristics of formation core, which was thought as a vital data in well logging. In the experiment, the tuff sandstone cores came from Daqing oilfield. The CEC value of core was measured by pH meter method. The effect of formation water salinity, formation water type, ion exchange temperature and core grain diameter on CEC determination of cores was analyzed. The experiment results showed that the measured value of core CEC decreased with increasing salt content when the core was soaked in NaHCO3 solution. CEC value was basically stable when the salinity was greater than 1.00×10⁴ mg/L. The influence laws of two type of formation water on core CEC measurements were basically identical, that was, CEC value decreased with increasing salinity. CEC value of core processed by Na₂SO₄ solution was slightly greater than that by NaHCO₃ formation water, when the degree of mineralization was the same. With the temperature of ion exchange rising, ion exchange was more fully and core CEC increased. The smaller core particle size, the greater CEC value was. The CEC value of 200—250 mesh (diameter 75—58 μm) core was 3.11 mmol/100 g and when the particle size was greater than 200 mesh, CEC was basically stable. The calculated value and measured value of membrane potential for 100—120 mesh and 200—250 mesh cores were compared. It showed that the measured CEC value of 200—250 mesh core was more accurate.

Abstract:Reacidizing is an important method in Plugging Removal of oil well as well as in reducing pressure and increasing injection of water well. In the paper, the domestic acid system in common use was introduced and the reacidizing effects were analyzed, the advantages and disadvantages of the domestic acid system in common use are summarized, which would provide a reference for the subsequent reacidizing work.

Abstract:Applications progress of emulsion system used in floodding,profile control and water plugging were reviewed, including emulsion flooding, spontaneous emulsification flooding, microemulsion flooding, emulsion profile control,emulsified heavy oil water plugging. In addition, the developmental tendency of emusion system in enhanced oil recovery was analyzed.

Abstract:In present work, the constructions of wormlike micelles were mainly based on viscoelastic cationic surfactants, while there were little studies and application on anionic surfactant wormlike micelles. Therefore, in this paper, the molecular geometry parameters theory of surfactants utilized to construct wormlike micelles was firstly introduced. Based on this theory, relevant mechanisms and methods to construct anionic surfactant wormlike micelles by using various kinds of inorganic and organic counterions were described in detail. Additionally, applications of viscoelastic anionic wormlike micelles in oilfield development were briefly introduced and the development direction of constructing anionic wormlike micelles was pointed out.

Abstract:The performance testing of liquid foam referred to the evaluation of formation or decay process of liquid foam made by specific methods. This paper focused on evaluation indicators of foam performance, foaming modes and evaluation methods. The characterization methods for foaming power and foam stability were described. Several foaming modes and their evaluation indicators were presented. The conventional and modern observation technologies as well as their applications were showed. The applicability of the evaluation methods and their advantages and disadvantages were discussed in details, which would provide reference for adopting matching methods for a given liquid foam system.