Abstract:A viscosifier for oil-based drilling fluid was synthesized by condensation method, using senior fatty acid and divinyl triammonium as main raw materials, and concentrated sulfuric acid as catalyst. The rheological property of different fluid systems which contained the same dose of viscosifier was characterized. These fluid systems included No. 5 white oil, No.5 white oil plus organoclay and oil-based drilling fluid system. The effect of dosage of viscosifier and density of drilling fluid on the rheological property of oil-based drilling fluid was also discussed. The formula of oil-based drilling fluid was obtained as follows: No.5 white oil, 3.0% organoclay, 2.0% fluid loss (FL) agent A, 2.0% FL agent B, 0.5% CaO, 3% superfine CaCO3, 0—180% barite, 0.2% wetting agent and 0—2.0% homemade viscosifier. The results showed that different fluid systems would become gel before and after hot rolling and there were no delamination and sedimentation if 1.0% VIS-3 viscosifier was added. Furthermore, the viscosifier had relatively excellent thicking properties in three fluid systems. When the dosage of viscosifier increased from 0 to 2.0%, the dates of rheological properties of oil-based drilling fluid before aging were obtained as follows: f3 value increased from 2 to 27, gel strength (Gel, Pa) increased from 2/2 to 26/27, plastic viscosity(PV) decreased from 58 to 28 mPa·s, yield point (YP) increased from 3.5 to 20 Pa and API filtration decreased from 5 to 3 mL. The dates after aging at 150℃ for 16 hrs were obtained as follows: f3 value increased from 2 to 21 Pa, Gel increased from 4/5 to 22/25, PV decreased from 59 to 24 mPa·s, YP increased from 3.5 to 21 Pa and API filtration decreased from 4 to 2 mL. When the density of oil-based drilling fluid which contained 1.0% VIS-3 viscosifier increased from 0.9×10³ to 2.0×10³ kg/m3, the f3 value increased from 2 to 10 and Gel increased from 2/3 to 10/11 before aging, and the f3 value increased from 2 to 7 and Gel increased from 2/3 to 9/11 after aging. The density of drilling fluid could improve the viscosifying ability. However, the f3 value and Gel were slightly lower after aging, when the density of drilling fluid was similar. Moreover, the effect of density of drilling fluid on PV and YP was no obvious rule.

Abstract:The oil-based drilling fluid with same water activity（0.9），density（ρ=1.8 g/cm³）and oil-water volume ratio（80∶20）composed by different internal salt such as CaCl₂，HCOOK，HCOONa and ₄Ca(NO₃)₃ was formulated indoors. The rheological property，dynamic/static settling stability，viscoelastic property and thixotropic ability of four different systems were compared and the anti-pollution ability of ₄Ca(NO₃)₃ internal oil-based drilling fluid was studied. The results showed that after the systems were aged under the temperature of 150℃ for 16 h，₄Ca(NO₃)₃ drilling fluid had the lowest shear force under the same shear rate compared with other drilling fluids with the lowest viscosity. The density decrease of ₄Ca(NO₃)₃ drilling fluid was only 0.255 g/cm³，while the ⊿ρ of other internal salt drilling fluids were 0.513—0.545 g/cm³ under the shear rate of 170.3 s^-1 at 50℃. The ratio of elastic modulus and viscosity modulus（G' /G' ）of ₄Ca(NO₃)₃drilling fluid was the highest among four systems，which showed that it had the best dynamic settling stability. When four drilling fluids were aged at 50℃ for 16 h after they were sheared under the shear rate of 10000 r/min for 30 min at 50℃，the surface tension of ₄Ca(NO₃)₃ drilling fluid was 27.744 mN/m²，the free oil volume was the smallest with only 1.37 mL and the density difference of upper and lower for the residual solution was only 0.038 g/cm³. It could formed the strongest gel structure with the peak of gel was 3.47 Pa. ₄Ca(NO₃)₃drilling fluid had the best static settling stability and thixotropic ability. 10% drilling solids and 15% salt water were added to the system to test the effect of drill solids and brine on the property. The result showed that₄Ca(NO₃)₃ drilling fluid had good anti-pollution performance.

Abstract:When the wells were drilled in and under the formation of the west hill YAO groups in South Bao block，many complicated troubles occurred due to too low density of the drilling fluid used, such as sticking and well leakage. In this paper, the screening and evaluation research of drilling fluid suitable for this block was studied, through performance tests, filtrate reducer, plugging agent and wetting agent were determined, and the optimal recipe of the drilling fluid system was determined as follows: 3%caly+2% fluid loss agent SPNH +1% fluid loss agent SMP-1 +0.3% polyacrylicacid potassium+0.3% fluid loss agent PAC-LV +0.1% richmond agent XCD +2% low fluorescence collapse prevention agent SFT +2% blocking agent NFA-25 +2% film-forming blocking agent CMJ-2 +2% comprehensive blocking agent ZHFD-1 +0.3% polyamine inhibitor AP-2+5% white oil +0.2% surfactant ABSN emulsifier+ barite. The density of the drilling fluid was 1.10～1.21g/cm³, the apparent viscosity was 33 mPa·s, the plastic viscosity was 24 mPa·s, the yield value(YP)was 9 Pa, the dynamic plastic ratio was 0.375,the filter loss in high temperature and high pressure was 10.0-11.0 mL, API filter loss was 2.5-2.8 mL, pH value was 8-9,and the density was controlled among 1.10-1.21 g/cm3. application of the drilling fluid system in Well Bao 16-1 showed that, the drilling fluid system had low filter loss, good rheology and strong plugging and preventing collapse capability. The complicated agents of sticking was zero, the circle of drilling shortened,and the expanding rate of caliper reduced remarkably. Well Bao 16-1 was constructed smoother than the others drilled in the same structure, indicating that strong restraining and plugging polyamine class agents could solve the problem of stability of the well wall in this block effectively.

Abstract:The AA/AMPS polymer with low relative molecular weight was synthesized using 2-acrylamino-2-methypropylsufonic acid (AMPS) and acrylic acid as raw materials. And then water-based drilling fluid thinner MHRT was obtained by mixing AA/AMPS polymer with epichlorohydrin-dimethylamine cationic polymer. The reducing viscosity performance of MHRT to the water-based drilling fluid, the particle size of the drilling fluid and the clay swelling before and after adding MHRT, were evaluated. The experimental results showed that HMRT had a good performance below 250℃, the reducing viscosity rate was above89.6% at the temperature of 250℃; the clay swelling inhibition rate of the core was 74% after being soaked in 3% MHRT water solution for 8 h. It was a key factor to improve the heat resistance of thinners that the thinner can inhibit the clay swelling and depression.

Abstract:based on molecular structure design to prepare amphoteric polymer fluid loss additive PADMS with properties of high temperature resistance and salt tolerance, AM, AMPS, DMDAAC and NVP were chosen as reactive monomers for quaternary copolymerization. The feasibility of molecular structure design of PADMS was proved by FITR and its adsorption capacity on clay particles was superior to sulfonated phenolic resin of SMP-II and SMP-III. After adding 2.0% PADMS, the apparent viscosity and plastic viscosity of the freshwater mud increased from 10.5 mPa·s to 35.0 mPa·s and from 5.0 mPa·s to 28.0 mPa·s, respectively, API filter loss decreased from 28.0 mL to 6.0 mL. The apparent viscosity and plastic viscosity is 17.5 mPa·s and 15.0 mPa·s, respectively, after aged for 16 h at the temperature of 200℃, and API filter loss decreased from 48.6 mL to 15.6mL. After adding 2.0% PADMS, the apparent viscosity and plastic viscosity of the compounded brine mud increased from 3.0 mPa·s to 19.5 mPa·s and from 1.5 mPa·s to 15.0 mPa·s, respectively. The viscosity of the compounded brine mud also increased with the increas of PADMS content after aged for 16 h at the temperature of 200℃. After adding 2.0% PADMS, API filter loss of pre and post aging decreased respectively from 88.0 mL to 8.2 mL and from 168.0 mL to 54.6 mL. HTHP filter loss decreased from severe loss to 86.4 mL.

Abstract:In order to obtain high temperature microemulsified acid and provide novel acids for deep acidization of oil and gas fields, a novel high temperature microemulsified hydrochloric acid system with cationic Gemini surfactant propylene-1, 3-bis (octadecyl dimethyl ammonium chloride) (18-3-18) as main emulsifier, n-butanol and n-octanol as assistant emulsifier, diesel as oil phase and hydrocholoric acid as acid phase was prepared in this paper. The thermal stability, phase behavior, retarded reactivity and CaCl2 tolerance of the microemulsified hydrochloric acid were investigated. The results showed that, at proper conditions, cationic Gemini 18-3-18 diesel microemulsified hydrochloric acid may keep stable at 100℃，and CaCl2 tolerance reached 120 g/L. It was proved that the microemulsified hydrochloric acid emulsified by Gemini18-3-18 and AEO9 also possessed good thermal stability at 95℃. It is benefit to enrich the novel high temperature microemulsified acid systems.

Abstract:the thickening agent PAMSDV was synthesized by homogeneous polymerization in aqueous solution，using AM, AMPS, DAC and NVP as raw materials. Through investigating the effect of the dosage of PAMSDV and cross-linking agent on the viscosity of temperature controlling viscosity acid (TCA), the optimal recipe of TCA was obtained, which was composed of 5% PAMSDV and 1.25% cross-linking agent (cross-linking agent comprised methane and Al₂(SO₄)₃ at mass ratio of 1:1), and dissolved in 20% hydrochloric acid. The viscosity of the TCA system changed with temperature. The viscosity reached the maximum value of 2400 mPa·s at the temperature of 70℃. Although the viscosity decreased a little at the temperature of 90℃, the viscosity was 1100 mPa?s, which displayed a certain performance of high-temperature resistance. In addition, the TCA system had other excellent performances such as compatibility, salt resistance and acid-rock reaction retardation. After the gel of the TCA was completely broken, the viscosity of the gel breaking fluid was 8 mPa?s.

Abstract:With the deepening of exploration and development, deep and ultra-deep carbonate reservoirs were discovered and have been put into development, therefore, a series of unconventional acid systems were formed gradually, facing some difficulties such as fast acid-rock reaction and short acid etched distance. A self-generating hydrochloric acid (SGHA) system was prepared by mixing self-generating hydrochloric acid A agent, High degree of polymerization of carbonyl compounds and self-generating hydrochloric acid B agent, ammonium salts preparation at the mass ratio of 1:1, which could slowly react and generate hydrochloric acid under high temperature conditions in the formation, and its performance was evaluated. The SGHA system could produce hydrochloric acid content of 12.94% at the temperature of 90℃and about 20% at the temperature of above 120℃ after reacting for 2 h, having a good ability to produce acid. The low-temperature stability of the SGHA system is in general, however, A agent and B agent have good low-temperature stability, respectively, hence, preparing the A agent and B agent separately before the construction site was suggested and the system should be used in that day. The heat resistance experiments showed that the SGHA system was applicable to the reservoir of 90~150℃.The SGHA system had good etching conductivity, and slower acid-rock reaction than that of the gelled acid system, the acid-rock reaction time was more than 2 h, which could ensure that the SGHA system played the role of deep acidification. In addition, the uneven core surface after the reaction could further increase the fracture conductivity.

Abstract:Because of the thickeners in fracturing fluids were mainly macromolecular compound, the damage of macromolecular residues to the reservoir seriously impacted well productivity. The most effective way to reduce insoluble residue damage was to decrease the molecular weight of thickener. This paper described a method to get guar gum with low molecular weight (LMG) by enzyme degradation through simple technological process and without solvent. The reaction condition was obtained as follows: 40—50oC reaction temperature, 3.5 u/mL enzyme dosage, 2 hrs reaction time. The weight-average molecular weight of obtained LMG was 4.25×10⁵ g/mol and the viscosity?of fracturing fluid with LMG was 27 mPa·s. The IR spectrum?of guar gum before and after degradation showed that the enzyme had broken the molecular chain which became short chain with low molecular weight. The viscosity of gel which formed by organic boron crosslinker and fracturing fluid including 3.5 g/L LMG was more than 80 mPa·s after shearing 2 hrs at 100oC and 170 s^-1. The residue content of LMG fracturing fluid was 96 mg/L, which was a quarter of common guar gum fracturing fluid residue.

Abstract:The formula of high temperature resistant acidic clean fracturing fluid was obtained as follows: 0.1%—5% acetic acid, 0.1% salicylic acid, 0.5%—1% anionic polyacrylamide, 0.1%—0.2% quaternary ammonium salt cationic gemini surfactant, 0.5%—3% clay stabilizers (potassium chloride, ammonium chloride) and water. The rheological properties, thickening time, sand-carrying properties and gel-breaking performance as a function of thickener concentration of acidic fracturing fluid were studied. The pH value of acidic clean fracturing fluid was 4—5. The viscosity of fracturing fluid was 30—50 mPa·s at 120℃ and 20 mPa·s at 140℃, which indicated a good shear and temperature resistance. The thickening time of fracturing fluid was within 60 s. The gel viscosity reached 140 mPa·s when the dosage of thickening agent was 1.0%. The acidic clean fracturing fluid possessed excellent proppant-carrying performance. The settling velocity of single sand in acidic fracturing fluid was only 0.023 mm/s with 0.8% thickener, while that in guar-based fracturing fluid with same thickener concentration was 0.169 mm/s. The acidic fracturing fluid would break automatically when it encountered a certain amount of oil, gas and formation water. And there was a accelerating in gel-breaking when ammonium persulfate was added. The gel-breaking time of acidic clean fracturing fluid was less than 1 min at 60—80℃. The acidic clean fracturing fluid was suitable for low permeability reservoir with high-calcium under 120℃.

Abstract:In order to promote the hydration process of traditional hydroxypropyl guar gum (HPG), a liquid guar gum thickening agent (LGC) was fabricated, which mainly consists of white oil, surfactant and emulgator, with simpler preparation, better dispersion ability and faster swelling. The viscosity of tap water and sea water with 1.0% LGC and 0.15% methanal was 110.11 and 112.40 mPa·s separately under low-speed mixing for half an hour at room temperature, which was the same as standard base solution with the same effective amount of HPG. Base fluid prepared with LGC was not sensitive to pH value and salinity of any water source. Both of sea water and fresh water could be used, which could dramatically reduce the construction cost in off shore oil production. Base fluid of LGC or HPG (0.4% effective content HPG) with organic borate-zirconate cross-linker CYS-1 could be completely broken with final viscosity 3.542 and 2.243 mPa·s and glue residue 476 and 432 mg/L by using 0.08% ammonium persulfate (APS) at 95 oC for 4 hrs. The base fluid with 1.0% LGC (40% effective content) and CYS-1 had initial filtration Vsp of 1.907′10-4 m³/m², filtration coefficient Cw of 0.997′10^-4 m/min^? and average filtration Vcm of 0.366′10-4 m³/(m²·min) at 120oC. For powder HPG, the swelling time of base fluid with 0.6% HPG, CYS-1 and other additives was up to 24 hrs, and the viscosity was 180 mPa·s under the shear rate of 170 s^-1 at 160oC. However, for the LGC sample, under the same experiment condition as above, the swelling time was only less than 30 min, and the viscosity of base fluid could be 190 mPa·s which kept above 122 mPa·s even under high shear rate of 1000 s^-1 for 3 min at 170oC. LGC met the high requirement of rapid preparation, fast swelling and high temperature resistance under high shear rate.

Abstract:There was swelling problem of thickening agent when the fracturing fluids prepared with seawater was continuously mixed during the offshore hydraulic fracturing operation. So the research on the swelling performance of guar gum was conducted. The effect of the type of modified group, the degree of molar substitutions, stirring speed, guar gum concentration, pH value and temperature on swelling performance of guar gum was studied. The results showed that the seawater sample was rich in⁺、Mg²⁺、Ca²⁺ and Cl^-、SO₄^2- with 34440 mg/L salinity. Under conventional conditions such as 20℃, 300 r/min and 7.5 pH value, the swelling time of carboxymethyl guar gum, hydroxypropyl guar gum (DS=0.3), hydroxypropyl guar gum (DS=0.15) and unmodified guar gum was 25, 50, 55 and 60 min, and the corresponding apparent viscosity of that was 63, 59, 45 and 23 mPa·s. The effect of other factors on swelling performance of carboxymethyl guar gum was studied and the optimum preparation condition was obtained as follows: 400—500 r/min stirring speed, 30—40℃ temperature, 6—7 pH value and dosage of guar gum within 0.5%. The swelling time could be optimized within 10 min to meet the requirement of continuously preparing seawater-based fracturing fluids.

Abstract:As the limitations of high content of water insoluble substance and high residual content to the gum fracturing fluids and poor rheological property to the active water fracturing fluids, the article studies a new fracturing fluid was studied using a nonionic polyacrylamide (A-1) as the thickening agent and organic zirconium (G-1) as the cross-linking agent. By investigating the gelation time, the formulation of the fracturing fluid adapted to site operation was optimized as follows: 0.5%A-1+2.5%G-1, and the effects of different factors, such as pH value, temperature, volume ratio of crosslinker to based liquid and salinity, on performance of the zirconium gel was analyzed. The evaluation tests showed that the aqueous zirconium gel was suitable to low permeable oil reservoir. The fracturing fluid had characteristic of low filtrate loss, little residue of the gel-breaking and good capability of transporting sand. The initial filtration rate was only about 16.41×10^-3 m³/m² and the filtration coefficient was 6.66×10^-4m/min^1/2at the temperature of 90℃. The zirconium gel possessed shearing resistance, the viscosity remained above 50mPa·s after sheared at shear rate of 170 s^-1 for two hours. The damage of gel-breaking liquid to the formation was 14.88% and the gel breaking liquid was easy to flow back.

Abstract:Taking starch, acrylic acid and acrylamide as raw material, ammonium persulfate and sodium bisulfite as initiator, DJ-1 with unsaturated double bond organic compound as crosslinking agent, a water-soluble fracturing temporary blocking agent was synthesized and its properties were characterized. The results showed that with increasing temperature and prolonging dissolved time, the solubility of temporary blocking agent in formation water increased. When the solid-liquid (formation water) ratio was 1:300, the water soluble rate of temporary blocking agent in 16 hrs was 96%—98% at 20—80℃, which indicated good water solubility. After complete dissolution, the viscosity of 5—20 g/L solution was 12.6—53.7 mPa·s, which had good flow back. The tensile strength of 20 g/L solution of temporary blocking agent was 9.1 N, which had good adhesion ability. The results of core experiment showed that the blocking strength of temporary blocking agent decreased with increasing core permeability. The maximum pressure gradient of temporary blocking agent was 47.1 MPa/m, which had the ability of sealing original cracks, making the maximum principal stress deviating, and then generating new cracks. The plugging rate of temporary blocking agent on the core was greater than 90%, and the recovery rate of core permeability after formation water flushing was up to 97.6%. The selectively plugging rate of temporary blocking agent on high permeability layers was greater than 83.2% and that increased with increasing core permeability contrast.

Abstract:The super-absorbent compound resin was synthesized by aqueous solution polymerization using acrylic acid（AA），2-acrylamide-2-methyl propane sulfonate（AMPS），initiator potassium persulphate，cross-linking agent N，N-methylenebisacrylamide and kaolin clay mineral as raw materials. The optimum reaction condition was obtained as follows: 4∶1 mass ratio of AA to AMPS，0.2%，0.06% and 10% initiating agent，cross-linker and kaolin dosage for total monomer in quality respectively，72℃ reaction temperature，75% neutralization degree of acrylic acid. The absorption ratio of super-absorbent resin synthesized under optimum condition for pure water and salt water was 1200 and 92.3 g/g，respectively. The water loss and retention property of resin was studied，and the results showed that the water loss rate increased with extending time and increasing temperature. The retention water rate of resin increased first and then decreased with increasing dosage of kaolin. When the dosage of kaolin was 10%，the water retention rate reached to maximum value 82%.

Abstract:Reservoir heterogeneity and invalid water cycle is more serious after polymer flooding. Viscoelastic behavior of traditional gel profile control agent is decreased sharply after being sheared in reservoir, which reduced the effect of profile control obviously. In the paper, the effect of anionic polyacrylamide CH601 concentration, crosslinker SQ-1 concentration, stabilizer TRB-5 concentration and the value pH on the gelling performance of the self-repairing gel system (SRGS) were investigated, as a result, the optimum formula was obtained. Moreover, the temperature tolerance, shearing, sealing characteristics of self-repairing gel system were investigated. The results showed that the optimum formula of the SRGS was as follows, 3000-5000 mg/L anionic polyacrylamide CH601+ 3000-4500 mg/L crosslinker SQ-1+200-400 mg/L stabilizer TRB-5, at the value pH 5-6. Heat stability of self-repairing gel system was good. At the temperature of 45℃,viscosity and elasticity modulus retention rate was 76.9% and 76.5%, respectively. At the temperature of 45℃, after the system went through the gelling-shearing-gelling- shearing process for three times, the gel viscosity was above 4000 mPa?s, and the viscosity recovery rate was above 45%. Core test demonstrated that the plugging rate of the SRGS was above 99% for silica sand artificial core with water permeability of 1.2-4.5 μm², and residual resistance factor was 68-147.

Abstract:Aiming at the problem of numerous microcracks, serious heterogeneity and water channeling in low permeability reservoir, and that conventional flooding technology?was difficult to play an effective role in the reservoir, experiment study on polymer microsphere(polyacrylamide microsphere)/surfactant (alkanolamide surfactant)compound flooding system was carried out, compatibility of the compounding flooding system was evaluated firstly, then the injection parameter and oil displacement performance were optimized and evaluated. The results showed that polymer microsphere and surfactant were?compatible, and the optimal composite injection system was as follows: 0.4 PV polymer microspheres solution (2000 mg/L) +0.3 PV surfactant solution (2000 mg/L), and the composite system could improve the recovery efficiency by above 15% based on the water flooding. Polymer microspheres/surfactant compound flooding control technology was well suitable for low permeability fractured reservoirs.

Abstract:A research was carried out on the prediction model of the viscosity of viscous oil mixture based on neural network .The research proved that the model of viscosity of the viscous oil mixtures established by the use of the BP-neural network method is reliable. A series of prediction models of the viscosity of viscous oil mixtures of an oil field in Sinkiang was established by BP- neural network as an example. The maximum error of the model was 4.1%. The correlation between viscosity, temperature and the rate of viscous oil and thin oil matched preferable, and proved a better fit compared with linear regression and Cragoe method.

Abstract:In the paper, an aqueous emulsifying viscosity reducer was developed, which could improve low-temperature fluidity of Xinjiang crude oil. The effect of temperature, single and composite viscosity reducers on the viscosity of Xinjiang crude oil were investigated. The results showed that: the three single viscosity reducer, AEO、OP-10、AES, which had better viscosity reducing effect, were screened. At the same condition, the three viscosity reducer was arranged according to the viscosity reducing effect: AEO＞OP-10＞AES. Through orthogonal experiment, the optimum composition of composite viscosity reducer XJ-1 was obtained as follows: 0.3% AEO, 0.2% OP-10, 0.1%AES and 0.2% additive dosage NaOH. the viscosity of Xinjiang crude oil could be decreased to 40.56 mPa·s and the rate of viscosity reduction was above 98% through adding XJ-1 at 50℃ with the oil-water ratio?of 7: 3. At the same time, the emulsion had good stability and demulsifying and dewatering were much easier.

Abstract:Four surfactants were chosen as foaming agent in this study ，including nonionic surfactants N-NP- 15c and N-NP-21c，newly synthesized anionic-nonionic surfactants N-NP-15c-H and N-NP-21c-H ，whose nonionic group was ethylene oxide（EO）and anionic group was sulfonic group. The performance of surfactants as CO ₂ foaming agent was investigated at high temperature and pressure conditions using a HTHP visualization foam meter with agitator. The effect of various influence factors on foam stability，including surfactant concentration ，water salinity，Ca²⁺ concentration，temperature and pressure，was studied. Experiment results showed that the foam performance of N-NP- 15c-H was the best ，whose foam volume was81.6 mL and half-life was 10.8 min at 125℃ with 0.7% foaming agent dosage，10MPa pressure and50g/L NaCl concentration. The foam volume and half-life of CO₂ foam first increased and then decreased with increasing mass fraction of surfactant ，and the optimum mass fraction was 0.7%. High temperature and high salinity（or Ca²⁺ concentration）were not conducive to the stability of CO₂ foam，while the increase of pressure could improve the performance of CO₂ foam significantly. When the pressure increased from 5 MPa to 12MPa，the foam volume increased from87.9 mL to165.8 mL and foam’s half-life increased from34.5 min to 295.2 min.

Abstract:Ordinary foaming agent had the characteristics of short dissolving and foaming time，so the effect of foam drainage gas recovery was poor. In order to solve this problem ，slow-released foaming agent was studied. The effect of temperature ，salinity ， methanol and condensate oil on the foaming agent was investigated. The results showed that the foaming height decreased from 120 mm to 105 mm，and the liquid carrying rate changed from 77% to56% when temperature increased from60℃ to 100℃ . The foaming height decreased from 130 mm to 90mm，and the liquid carrying rate changed from 71% to48% when the salinity increased from 0 to 250 g/L. The foaming height reduced from 140 mm to 70mm，and the liquid carrying rate decreased from 85% to 78% when the volume fraction of methanol increased from 0 to 40%. The foaming height reduced from 140 mm to 120 mm，and the liquid carrying rate decreased from 85% to76.3% when the volume fraction of condensate oil increased from 0 to 40% . In general ，the foaming agent could be used under the condition of 90℃ temperature ，150 g/L salinity resistance ，30% methanol and 30% condensate oil ，which fully met the needs of drainage gas recovery for low pressure and low production gas wells in Sulige gas field. The slow-released foaming agent was applied in 5 gas wells on site during 2012—2013. The average pressure difference for oil and casing reduced 1.3 MPa，and gas production in average increased by 0.07×10⁴m³/d.

Abstract:In order to resolve the problem that the heterogeneous is serious and the effect of water flooding is poor of ultra heavy oil reservoir in Lu-keqin oil filed，through the laboratory experiment and field experimentation, the foam ability, stability, salt-resistance and displacement effect of foam system was researched，and the foaming process was also tested. The results showed that，in the condition of high temperature(80℃) and high salinity(160000 mg/L)，the foaming rate of XHY-4 foam system was greater than 600%，and the half-life period was greater than 600 seconds，and the core flooding experiment indicated that the XHY-4 foam system could improved oil recovery by 15% with the injection of air-liquid alternation. Field test of nitrogen foam showed that the injection of gas-liquid alternation could form bubbles in the formation，the dominant channel of water flooding could be effectively plugged，which would reduce producing water and increase oil. The success of injection test has provided strong technical support for foam flooding pilot test of ultra deep heavy oil reservoir in Lu-keqin oil filed.

Abstract:In allusion to the low efficiency of utilizing diluents, taking heavy oils in J7, TK675X and FZ010 wells of Xinjiang oilfield and two kinds of diluents (gas condensate and diesel) as research objects, the influences of temperature and diluents on dissolution rate and reduction of viscosity were studied. The viscosities of J7, TK675X and FZ010 at 50℃ was 524.5, 4337.3 and 139836.6 mPa·s, respectively. Research results showed that when the mass concentration of heavy oil in diluent was range from 0 to 1200 mg/L, it was in good linear relationship with absorbance of oil mixture, and the fitting relevancy of standard curve was greater than 0.99. The dissolution rates of three heavy oils in diluents increased with increasing temperature. When diluent was diesel, the dissolution rate of J7, TK675X and FZ010 increased from 44.3, 5.4 and 28.3 mg/(m²·s) to 413.9, 171.2 and 201.8 mg/(m²·s) respectively with temperature raising from 30℃ to 80℃. And when diluent was gas condensate, the dissolution rate of J7, TK675X and FZ010 increased from 224.7, 110.8 and 168.3 mg/(m²·s) to 994.1, 450.1 and 371.8 mg/(m²·s) respectively with temperature raising from 30℃ to 80℃. At the same temperature, the dissolution rate of J7 oil was greater than that of TK675X and FZ010 oil. Dissolution rates of heavy oils in gas condensate were higher than those in diesel. The viscosities of oil mixture were dramatically decreased with increasing mass ratio of oil to diluents. When the diluent was diesel, the viscosity-reducing rate of J7, TK675X and FZ010 was 90.54%, 92.59% and 96.04% with 0.4, 0.3 and 0.2 mass ratio of oil to diluent, respectively. The higher viscosity of heavy oil, the more significant viscosity-reduction effect was. When the diluent was gas condensate, the rule of viscosity reduction was similar to that in diesel. Viscosity-reducing rates of heavy oils mixed with gas condensate were higher than that with diesel at same mass ratio of oil to diluent. So it was more appropriate for gas condensate as the diluent in terms of dissolution rate and viscosity-reducing rate.

Abstract:The viscosity of heavy oil in Suizhong36-1 (SZ36-1) oilfield was 1251.5 mPa·s and 417518.1 mPa·s at 50℃ and 3℃ respectively. The heavy oil presented Newtonian fluid during 3—60℃, and the density was 0.953 g/cm³at 20℃ which belonged to ordinary heavy oil. The SZ36-1 heavy oil-in-water emulsions with different volume ratios of oil and water (8:2—6:4) and dosages of emulsifier (0.3%—0.7%) were prepared using non-ionic surfactant BJN-01 as emulsifier. The effect of oil and water ratio and emulsifier concentration on the stability of oil-in-water emulsion was studied through thermostatic standing, rheological experiment and microscopic observation at low temperature (3℃). The results showed that the stability of O/W emulsion improved significantly with increasing emulsifier concentration. Water separation rate of the emulsion with 6:4 and 7:3 oil and water ratio increased when the time extended. When oil and water ratio was 8:2, the emulsion was unstable, oil and water phase was separated immediately after preparation. Flocculation and coalescence took place in O/W emulsions at different degrees after dynamic shearing for 2 hrs. When the oil and water ratio was higher or emulsifier concentration was lower, the flocculation and coalescence was more significant. When the dosage of emulsifier was 0.5% and oil and water ratio was 6:4, the O/W emulsion showed Newtonian fluid, the viscosity of emulsion was less than 50 mPa·s, and when the dosage of emulsifier was 0.7% and oil and water ratio was 7:3, the viscosity of emulsion was less than 100 mPa·s after dynamic shearing for 2 hrs at 3℃. Therefore, the static and dynamic stabilities of these emulsions were perfect. The oil-in-water emulsion was suitable for transportation and restart-up of pipeline at low temperature.

Abstract:Aiming at the heavy oil of a certain block of one oilfield, the emulsifying viscosity reducer system was determined through formulation screening, the system was composed of 0.4% surfactant CD-1、0.2% NaOH and 0.07% polymer HPAM. At the oil-water volume ratio of 7:3, the viscosity of the obtained emulsion was 189.3 mPa·s, the viscosity reduction rate reached by 96.1%, at the same time, the stabilization time was up to 48 h. A good heavy oil recovery effects could be achieved and heavy oil recovery could be improved by combining chemical huff and puff with emulsification viscosity reduction. The process of chemical huff and puff technique of heavy oil emulsified viscosity-reducing was simulated using laboratory physical model, and the chemical huff and puff technology parameters of indoor simulation was obtained as follows through orthogonal experiment, injection volume was 16 mL, injection rate was 0.34 mL/min, shut-in time was 48 h, and injection temperature was 50℃. Finally, the effects of indoor stimulation showed that based on water flood (oil recovery ratio was 8.25%), and the oil recovery efficiency increased by 10.78% after the double chemical huff and puff process.

Abstract:Five petroleum degrading strains, named as PD1301—PD1305, were isolated from petroleum pollution soil in Liaohe oilfield. Biodegrading percentage of the best degrading strain PD1301 was 57.7% with 4 d cultivatable time, 30℃ cultivatable temperature, 7.0 initial pH value of culture medium and 5.0 g/L petroleum mass concentration, and that of PD1302—PD1305 was 39.0%, 44.4%, 33.5% and 21.8%. PD1301 was identified as Pseudomonas aeruginosa by thallus morphology analysis, colonies characterization, physiological reaction, biochemical reaction and 16S rDNA analysis. The single colony of PD1301 was round, yellow-white and slightly raised, and the surface of colony was smooth without wrinkles. PD1301 was a gram negative bacillus, which had no spore and capsule. PD1301 also could produce pyocyanin. The 16S rDNA sequence homology of PD1301 was similar with that of Pseudomonas aeruginosa by 99%. The effect of cultivatable time, cultivatable temperature, initial pH value of medium and petroleum concentration on degrading ability of strain PD1301 was studied. The results showed that the degrading rate was significantly increased at exponential phase (1—4 d), and there had small changes after cultured 5 d. With increasing petroleum concentration, the degrading capacity of strain showed a bell-shaped curve. The maximum value was 58.6% when petroleum mass concentration was 5.0 g/L. With increasing temperature, the degrading rate increased first and then decreased. The maximum value was 57.7% at 30℃ cultivatable temperature. With increasing initial pH value of culture medium, the degrading rate increased first and then decreased. The peak value was 59.4% when initial pH value was 7.0.

Abstract:Aimed at the actual needs, the adaptability between polymer solution and reservoir strata of Sazhong area was studied through testing molecular coil size (D_h) and Core seepage characteristics of the polymer solution. The results showed that with the increase of the molecular weight of the polymer and the reduction of the salinity and shear intensity, the polymer molecule coil size (D_h) increased and the pore size matched with the polymer molecules increased accordingly. During the injection of polymer solution to the rock, the stable injection pressure indicates that polymer molecule coil size match well with the pore size of rock. When the rock is nonhomogeneous, the molecular weight matched with the first type, the second type and the third reservoir were over 2500×10⁴ , 1900×10⁴—500×10⁴，400×10⁴— 800×10⁴ , respectively. The adaptability between polymer solution and reservoir strata was affected by permeability distribution, heterogeneity, molecular weight, salinity and shear intensity,and so on, the ratio of median value of throat radius to molecule coil size was between 7 and 16.

Abstract:According to the actual demands of Henan oilfield, laboratory research was conducted to find out the lower limit concentration and the best pore volume of high concentration polymer (ZL-I partially hydrolyzed polyacrylamide) flooding. The results showed that the viscosity increased gradually from 11.8 to 227.2 mPa·s when the polymer concentration increased from 500 to 3000 mg/L. The viscosity increased greatly when the polymer concentration was higher than 1670 mg/L. At the frequency of 0.1 Hz, the viscous modulus increased obviously when the polymer concentration was higher than 1643 mg/L and the elastic modulus increased obviously when the polymer concentration was higher than 1680 mg/L. Therefore, the lower limit concentration of high concentration polymer flooding was 1700 mg/L. The enhanced oil recovery increased rapidly to 19.77% when the injection volume of 2000 mg/L polymer increased to 0.7 PV. But when the injection volume was more than 0.85 PV, the oil recovery increase improved slowly. It was suggested that the best polymer concentration suitable for Xia Er-men oilfield was 1800—2000 mg/L, and the most appropriate pore volume was 0.85 PV. After field application on 10 polymer injection wells, daily fluid production was 891.3 t and daily oil production was 77.9 t, the cumulative oil production was 143498 t, the oil recovery increase of second polymer flooding was 8.66%, which indicated that high concentration and large pore volume polymer flooding could enhance oil recovery dramatically and improve economic benefit greatly.

Abstract:In Shengtuo oilfield, the formation temperature was more than 80℃, the salinity of formation water was above 20000 mg/L, the concentration of calcium and magnesium ions was more than 500 mg/L, and the heterogeneity of reservoir was strong. According to the reservoir characteristics of Shengtuo oilfield, reinforced polymer flooding oil system was developed by adding polymer enhancer to ultra-high molecular weight hydrophobic associating polyacrylamide. The results showed that when the dosage of enhancer increased from 0 to 2500 mg/L, the apparent viscosity of oil displacement system increased from 7.8 to 42.9 mPa·s, the viscous modulus increased from 120 to 315 mPa, and the modulus of elasticity increased from 0 to 106 mPa. In the simulation of Shengtuo oilfield conditions, when the mass ratio of ultra-high molecular weight associative polymer and enhancer was equal to four, the viscosity retention rate of reinforced polymer flooding system was 85.5% after 60 days, which was better than that of modified polyacrylamide (GXPAM) (66.2%). The reinforced polymer displacement system had well thermal stability. When the reinforced polymer flooding oil system (2500 mg/L) was injected in heterogeneous core, the liquid production percentage of hypertonic model decreased from 98.5% gradually with 32.7% minimum value, and that of low permeable model increased from 1.5% step by step with 67.3% maximum value. When the sequent water (1 PV) was injected, the liquid production percentage of hypertonic model was 58.5%, and that of low permeable model was 41.5%. The core heterogeneity was improved obviously. When the core permeability ratio was 1:5 and 1:3, the enhanced recovery rate of reinforced polymer flooding oil system increased by 26.0% and 10.9%, however that of GXPAM increased by 14.8% and 7.1%, respectively. Oil recovery efficiency of reinforced polymer flooding oil system was better than that of GXPAM, and the flooding effect was better in high permeability ratio.

Abstract:The simulated produced fluid for polymer-surfactant flooding was prepared with oil from north third district in Changqing oilfield, oilfield produced water, polyacrylamide and betaine surfactant. The water ratio of produced fluid was range from 10% to 90%. High-concentration produced fluid contained 1000 mg/L polymer and 1667 mg/L surfactant, while low-concentration produced fluid contained 400 mg/L polymer and 600 mg/L surfactant. The effect of water ratio, concentration of polymer or surfactant, shear rate and temperature on the rheological property of simulated produced fluid was studied. The results showed that the emulsion type of high-concentration produced fluid was W/O when its water ratio was 10%—20%, and it turned to O/W when its water ratio was more than 25%. The phase transition point was between 20% and 25%. While the phase transition point of low-concentration produced fluid was between 25% and 30%. The viscosity of simulated produced fluid decreased with increasing temperature. When the water ratio was low, the viscosity of simulated produced fluid (W/O) remained constant with decreasing concentration of polymer-surfactant. When the water ratio was high, the viscosity of simulated produced fluid (O/W) decreased with increasing water ratio and decreasing concentration of polymer-surfactant at same temperature. Besides, whether the simulated produced fluid was W/O or O/W emulsion, the viscosity of simulated produced fluid decreased with increasing shear rate when temperature was below the abnormal point, which showed the property of shear-thinning.

Abstract:Using double-layer heterogeneous core model, fully playing advantages of profile control and oil displacement, the improving oil recovery effect of eight projects in different permeability contrast conditions was evaluated. The results showed that the water ratio decreased about 15% and oil recovery increased 6.7% and 8.3% in ASP flooding and polymer flooding respectively, when the permeability of core was 30×10^-3/1000×10^-3μm². After modified-starch gel was formed, the water cut of ASP flooding declined to 44%, which was significantly less than the lowest value of polymer flooding (60%) and water flooding (70%), and the oil recovery increase was 23.5%, 19.2% and 10.1% in ASP flooding, polymer flooding and water flooding respectively. ASP flooding could effectively start the lower permeability layer and produce better exploitation results than polymer flooding. The oil recovery increase of “modified-starch gel+ASP flooding” was 40.4%, which was better than the oil recovery sum of separately using modified- starch gel and ASP flooding (35.6%), and 4.3 percent higher than that of “chromium gel+ASP flooding”. When the permeability was 30×10^-3/2000×10^-3 μm² and 30×10^-3/500×10^-3μm², the oil recovery increase of “modified-starch gel+ASP flooding” was 45.3% and 34.4%, and the oil recovery of ASP flooding increased 25.1% and 22.2%, respectively, which indicated that the more severe reservoir heterogeneity, the better exploitation results of combination flooding was.

Abstract:The performance of ASP （alkali/surfactant/polymer）was studied in the aspects of viscosity，interfacial tension ，molecular clew dimension（D_h）， molecular configuration ，flooding effect and their influencing factors. The mechanism of enhancing oil recovery was analyzed. The results showed that the viscosity of ASP system decreased from 246.9 mPa·s to 138.8 mPa·s，the interfacial tension decreased and D_h fell from 324.7 nm to 263.5 nm when the mass fraction of NaOH increased from 0 to 1.2%. As the dosage of surfactant increased from 0 to 0.3% ，the viscosity of ASP system decreased from 127.0 mPa·s to 122.1 mPa·s and then increased to 138.8 mPa·s，the interfacial tension decreased and D_h increased from 139.7 nm to 263.5 nm. As the mass ratio of solid to liquid and adsorption times increased，the interfacial tension of ASP system increased. In alkali/polymer system ，structural morphology of polymer molecules gave priority to“sheet”，the“nets ”came with complementary. In heavy alkyl benzene sulfonate/polymer system ，there appeared a big area of“bead ”for structural morphology of polymer molecules ，however，structure of “nets ”wasn’t obvious. In ASP system ，structure of “nets-sheet ”presented for structural morphology of polymer molecules. The results of oil displacement experiment showed that the recovery efficiency increment of ASP system，polymer solution and alkali/surfactant system was 14.8% ，12.2% and 4.8% respectively in comparison to water flooding. With increasing viscosity of oil-displacement agent，the chemical recovery efficiency increased ，but its increment decreased gradually. When the mass fraction of polymer was 0.12% ，0.18% and0.25% ，the recovery efficiency increment of polymer flooding was 12.2% ，15.8% and 18.7% ，and that of ASP flooding was14.8% ，18.3% and 21.0% ，respectively. In the condition of same polymer dosage，the recovery efficiency increment of ASP flooding was higher than that of polymer flooding by 2.3% —2.6% . The contribution of the effect of oil-displacement agent on enlarging swept volume to recovery efficiency was greater than that on improving oil-displacement efficiency to recovery efficiency.

Abstract:It is well known that there are four forms for oil in produced wastewater from polymer flooding, including oil slick, dispersed oil, emulsified oil and soluble oil. Not only the content of emulsified oil but also the water stability would increase because of the soluble polymer used as flooding agent. In the article, the water produced from polymer flooding was studied, and the oily ratio of different forms with different polymer concentrations was determined. It was found that the content of the emulsified oil was 90 percent of in the simulated wastewater containing polymer, which was the key object for water treatment of polymer flooding. In the addition, the emulsified oil of the simulated wastewater, exhibited obviously increased when the concentration of polymer in water was above 50 mg/L, compared to that of simulated wastewater without polymer. Meanwhile, the emulsified oil of the produced wastewater containing polymer of about 50 mg/L was higher than that of the simulated wastewater; hence, the former was more stable and more difficult to be treated with than the latter.

Abstract:The mixed water properties of river water and Chang-6 layer produced-water(C-6W) in Shanbei Oil production plant was studied, including ion content, scale and scale type, calcium loss rate, respectively, in order to reduce the scale harm to Chang-6 layer from river water and C-6W. It was shown that the salinity of C-6W was above of 80000 mg/L, the river water salinity was about 1200 mg/L; when the volume ratio of C-6W to River water was 6:4, the highest calcium loss rate and amount of scale (9.5% and 36 mg/L, respectively) were achieved at the temperature of 30℃; when the mixed water was remixed with river water at volume ratio of 7:3, the lowest reservoir calcium loss rate and amount of scale (0.59% and 21.5 mg/L, respectively) were obtained. The amount of suspension content and oil content of the processed mixed water was decreased from 68 mg/L and 115 mg/L to 2.6 mg/L and 3.7 mg/L, respectively, which met the re-injection water quality standard, and a low core damage rate of 14.29%(<20%) could be found when the re-injection volume was 1-15 PV.

Abstract:a new method was developed for the composition quantitative determination of heavy alkylbenzene sulfonate(HABS) in surfactant complex systems. The absorption spectra of HABS showed the presence of β-cyclodextrin (β-CD) could result in the enhancement of absorption intensities of HABS. The results indicated that the determination precision of HABS can be significantly improved by β-CD, and the effect of several common interfering substances (SDS,OP-10,HPAM,Cl^-,Na⁺,Ca²⁺,etc.) on determination of HABS in β-CD aqueous solution can be greatly reduced. Based on this, the maximum errors of the determined HABS are less than 2.2% under multifactor interferences, and the precision of the method is as high as 10^-2~10^-3 mg/L. In general, synergistic effect of these interference factors could not formed by the excited UV absorption spectrometry.

Abstract:Suspending agent of cement slurry is a kind of cementing additive which develops slowly and has less type. In this paper, the domestic and overseas suspending agents for cement slurry and related material were summarized according to the kinds, at the same time, the advantages and disadvantages of different kinds of material are compared and analyzed. What’s more, based on the present problems and research situation of the suspending agents for cement slurry, some comments were made on its development trends.

Abstract:Cross-linked polymer gel was the most widely used profile control and water shutoff agent. The gelling condition was conclusively influenced by a series of factors. In this paper, a plenty of research achievements were integrated. Influencing factors on dynamic gelling process such as mechanical shear, porous media shear action, absorption, pH value, lithology character were discussed. And further research direction of dynamic gelling of cross-linked polymer in porous media was proposed.