CO2 flooding technology is an effective technical means for tertiary oil recovery in high water cut reservoirs. Using an existing well pattern to inject CO2 is an economical and feasible development method under low contemporary oil prices. Although the particle migration caused during the displacement process will block the pore throat of the rock, the injection of CO2 can effectively reduce the CO2 injection pressure, and the dissolution that occurs during the injection process improves the seepage capacity of the fluid as a whole. In this study, assessments of particle migration and plugging after CO2 flooding and evaluations of rock dissolution by CO2-aqueous solution were carried out, and the variation characteristics of the relative permeability curve before and after displacement were evaluated, further explaining the influence of CO2 flooding on reservoir seepage capacity. The results show that, in the process of CO2 injection, the injection pressure decreases under different injection rates. After CO2 flooding under oil conditions, the core permeability loss was 43.8%, and after cleaning with toluene and anhydrous ethanol, the core permeability recovery was 24.3%, indicating that the particles were bound by crude oil during the migration process and accumulated into clusters, resulting in blockages. Although there was a certain degree of blockage, the CO2-aqueous solution mainly reacted with chlorite and released Ca2+, Mg2+, and Fe2+ ions. The concentration of Ca2+ increased by 157.43%, the concentration of Mg2+ decreased by 43.33%, and the concentration of Fe2+ decreased by 50.47%, indicating that, although the generated MgCO3 and Fe2O3 blocked the pore throat of the rock, the overall dissolution effect of CO2 on CaCO3 was stronger, and the overall seepage capacity of the fluid was improved. To a certain extent, this technique can improve the water injection capacity and the effect of subsequent water flooding.
Gas condensate exists generally in the upper Paleozoic Sulige gas reservoir.During production,it was found that the produced liquid of condensate in some gas gathering stations was seriously emulsified,which had a great impact on the normal production.Taking the produced liquid emulsion of condensate in Sulige gas field as the research object,the emulsification characteristics and influencing factors of produced liquid in typical blocks were analyzed.The composition of the five produced condensate emulsions was quite different,and the stability of the emulsions was in good correspondence with zeta potential and salinity.The greater the absolute value of Zeta potential,the more stable the emulsion.The higher the salinity of the aqueous phase,the lower the stability of the emulsion.The mass fraction of alcohols and esters in five produced condensate emulsions was 1.48%—4.80%and 2.08%—6.34%,respectively.the polar organic substances of alcohols and esters would form a composite interface facial film with hydrophilic surfactant at the interface,which was conducive to the formation of condensate emulsion.In the condensate emulsion in Sulige gas field,the water phase was continuous phase and oil was dispersed phase.For some single oil droplet,oil was a continuous phase and water was a dispersed phase,which finally formed a complex water-in-oil-in-water(W/O/W)type emulsion.With the increase of foaming agent and suspended matter content,the volume fraction of the simulated condensate emulsion increased first and then decreased.When the mass fraction of foaming agent was 0.6%and the mass fraction of suspended solids was 0.4%,the volume fraction of the simulated condensate emulsion was the largest,while the concentration of corrosion inhibitor had no obvious effect on the volume fraction of condensate emulsion.
Biosurfactant is a specific natural surfactant produced by the microorganism.Its adsorption on rock surface has a great impact on the change of reservoir wettability.The mechanism of wettability alteration is crucial to the oil recovery.In this paper,the interaction between rhamnolipid biosurfactant and hydrophobic glass surface was studied by contact angle experiment,oil displacement experiment,free energy of liquid-solid interface measurement and molecular dynamics simulation,explaining the adsorption effect of rhamnolipid biosurfactant on the hydrophobic glass surface's wettability.The results showed that the wettability of hydrophobic slide could be rapidly altered by rhamnolipid biosurfactant.Once the rhamnolipid biosurfactant adsorbed on the hydrophobic glass surface lasting for 12 h,the contact angle could be dramatically decreased from 111.6°to 32.7°.The optimum dosage of rhamnolipid biosurfactant to extract oil from oilsands was 30%,resulting in the better oil displacement efficiency(i.e.,84.83%)and the lower adhesion force(0.2 mN/m).Furthermore,the free energy between deionized water and hydrophobic glass slide treated by rhamnolipid solution using the liquid-solid interface free energy formula was-140.2 mJ/m2,which was much lower than that between deionized water and original hydrophobic glass slide(-52.1 mJ/m2).On the other hand,based on the molecular simulation,the rhamnolipid molecules could quickly adsorb on the hydrophilic surface via hydrogen bonds(strong interaction force),while both the electrostatic force and van der Waals force(weak interaction force)were the main interaction forces between rhamnolipid molecules and hydrophobic surface.Therefore,the adsorption binding energy between rhamnolipid molecules and hydrophilic surface(29.7 eV)was much higher than that between molecule and hydrophobic surface(12.2 eV),leading to the stronger interfacial competitive adsorption capacity of rhamnolipid molecules compared to asphaltenes.In other words,according to the free energy calculation and molecular simulation results,rhamnolipid molecules would easily anchor to the hydrophilic surface and"sweep off"the oil molecule,resulting in higher oil displacement efficiency.This paper provided an insight to construct an effective wetting control flooding system based on rhamnolipid biosurfactants.
In order to improve the wellbore instability caused by poor plugging performance of drilling fluid during the drilling of shale oil and gas horizontal wells,firstly,the composition and the wellbore instability of Longmaxi shale in South Sichuan were analyzed.Then n-cetyl-triethoxy-silane,aminopropyl-triethoxy-silane and activated carbon nanotube were used as raw materials to synthesize the nano-micron plugging agent(NP-1)for oil-based drilling fluid.Its structural and physicochemical properties were analyzed by Fourier transform infrared,thermogravimetric,transmission electron microscope and surface wettability,and then its compatibility with oil-based drilling fluid was investigated.Finally,the plugging performance was evaluated by breakthrough pressure,pressure transmission and triaxial compressive strength.The mechanism was analyzed and then the field application was carried out.The results showed that there were lots of developed pore throats in size of nanometer and micron-meter and serious capillary spontaneous imbibition of shale in South Sichuan.As a result,the liquid would permeate into the wellbore continuously,which would lead to wellbore instability.The diameter of NP-1 was in the range of 30-50 nm,the length was in the micron-meter,the surface wettability was hydrophobic and lipophilic,and then the thermal stability was good below 385.2℃.NP-1 had good compatibility and stability with oil-based drilling fluid.The high temperature and high pressure filtration loss after aging 16 h at 180℃was reduced from 2.8 mL to 1.8 mL after adding 3%NP-1 to ordinary oil-based drilling fluid.The oil-based drilling fluid with NP-1 could effectively plug the end face of shale,which could improve the breaking pressure,prevent the pressure transmission,stabilize the core internal structure and compressive strength,and then maintain the wellbore stability.Field application results showed that NP-1 could effectively alleviate the lost circulation and wellbore instability of adjoining well caused by the weak plugging ability of drilling fluid.The enlargement rate of well diameter in average was only 5.61%after treating.NP-1 had excellent plugging performance for shale in oil-based drilling fluid.It provided a reference for efficient drilling of similar complex shale gas wells in South Sichuan.
Taking into account of the current challenges of poor injectability and a short gelation period of conventional gel plugging materials,a high-temperature delayed cross-linked polymer plugging agent(PM-1)was developed through a synergistic approach combining free radical polymerization and cross-linking reaction using acrylamide(AA)and 2-acrylamide-2-methylpropane sulfonic acid(AMPS)as reaction monomers,azobisisobutyronitrile hydrochloride as initiator,and polyethyleneimine and N,N'-methylenebisacrylamide(MBA)as cross-linking agents.Optimal synthetic conditions for PM-1 were determined via orthogonal and single-factor experiments.The injectability,gelation performance,and plugging efficiency of PM-1 was evaluated,and the delayed cross-linking mechanism of PM-1 at high-temperature was probed.The optimal synthetic conditions for PM-1 was as follows,mass fraction of monomers was 10%and mole ratio of AM to AMPS was 4∶1,polyethyleneimine and N,N'-methylenebisacrylamide(MBA)dosage was 0.4%and 0.2%,azobisisobutyronitrile hydrochloride dosage was 0.1%and polymer BRZ dosage was 1.2%.the injectability of the PM-1 was good.After aging for 96 h at the temperature of 130℃,PM-1 could still effectively plug sand layers with meth size of 1.7-4 mm and exhibit a pressure-bearing capacity of 6 MPa for 5 mm fractured layers when combined with inert materials to form a composite gel.Intriguingly,the addition of 0.4%polyethyleneimine extended the cross-linking plugging time of PM-1 to about 3-5 h,which was essential to ensure the smooth construction of underground crosslinking gel plugging.
In order to satisfy the increasingly stringent requirements for environmental protection,the biological toxicity and degradability of several emulsifiers,internal phase salts and base fluids were tested,and then an environment-friendly non-water-based drilling fluid system was constructed on the basis of plant oleic acid and its ester derivative BIO-EMUL and BIO-COAT,combining with base fluid BIO-OIL and sodium acetate solution by measuring the electrical stability,emulsifying efficiency of water-in oil emulsion and oil/water interfacial tension,interfacial rheology between BIO-EMUL+BIO-COAT solutions and BIO-OIL.The fundamental performance and anti-contamination ability of the drilling fluid was evaluation.The results showed that BIO-EMUL and BIO-COAT could effectively reduce the interfacial tension of oil/water and form water-in-oil emulsions with demulsification voltage up to 350 V and emulsifying efficiency up to 95%.The LC50 of the water-in-oil emulsion system was about 28200 mg/L,and the BOD5/CODCr was greater than 0.25,indicating that it was an environment-friendly system with low biological toxicity and good degradability.The prepared drilling fluid system had a wide range of applicable density and strong anti-contamiation ability,which provided a foundation for the future study of environmental protection non-water-based drilling fluid system and materials.
The resource potential of in-situ conversion of shale oil is enormous,and it is a strategic replacement resource for China's oil and gas industry.However,extreme high temperatures under low maturity shale oil in-situ conversion conditions can lead to a decline in the strength of hardened cement.The influence of modified material sodium hexametaphosphate on the hydration behavior of aluminate cement and the application performance of cement slurry at the high temperature environment of 650℃was systematically studied,and its macro performance and microstructure were deeply explored.low field nuclear magnetic resonance analysis and testing technology showed that the sodium hexametaphosphate had a significant retarding effect on the initial hydration behavior of aluminate cement and could effectively improve its rheological properties.In addition,at the temperature of 50℃,addition of sodium hexametaphosphate could significantly reduce the permeability of hardened aluminate cement,at the same time,which had no significant impact on the strength.After treatment at the temperature of 650℃,the maximum compressive strength of was 47.19 MPa by adding 5%sodium hexametaphosphate to modify hardened aluminate cement.Simultaneously,before and after treatment at 650℃,the hydration products of aluminate cement slurry underwent significant transformation,the C3AH6 and AH3 converted into C12A7 and CA mainly.C3AH6 and AH3 underwent thermal decomposition mainly during the period of 180-400℃.the pore size distribution of mercury intrusion showed that the pore size range of clean hardened aluminate cement and 5%sodium hexametaphosphate modified hardened aluminate cement was mainly between 100 and 1000 nm,and the pore size of both types of cement stones increased due to the transformation of crystal form after high-temperature treatment at the temperature of 650℃.
The settlement stability of cementing slurry is one of the important indicators of cement slurry construction performance.With the more complex well conditions such as deep wells and ultra-deep wells,especially in recent years,the well depth is extended to 10000 meters,therefor the temperature of the bottom of the well will reach more than 240℃.Consequently,it poses a challenge to the stability of cementing slurry.Previously the suspending agents can improve the suspension stability,but reduce the rheological property of cementing slurry,which is detrimental to well cementing under complex well conditions.By summarizing the research status of oil well cement suspension,the main types and mechanisms of suspending agents were systematically discussed.Additionally,the optimization of current suspension agents was analyzed,including the optimal compounding of inorganic and organic polymer materials,the optimization of comonomers,as well as the graft copolymerization,which would provide reference for research of oil well cement suspension.
To solve the problems that cement slurry can not stay,is easy to be diluted by water,and is poor in cementing strength and plugging effect for blocking the malignant leakage in large cracks,vug and aquifer,a quadripolymer gel was prepared by copolymerization of acrylamide(AM),2-acrylamide-2-methylpropanesulfonic acid(AMPS),N-vinylpyrrolidone(NVP)and hydrophobic monomer(MJ-16),and the gel was further added to cement slurry to form a gel-cement slurry composite leakage plugging system.The water dilution resistance,rheology,retention capacity and compressive strength of the composite system were studied.The results showed that the gel had good rheological property and temperature resistance.The system formed by gel,cement,retarder and defoamer had a fluidity of 21 cm and adjustable thickening time,and can be pumped safely.The system was still integrated under water and had good resistance to water invasion,resulting in it was not diluted by water at the stirring speed of 150 r/min.Moreover,the system had good retention capacity,as a result,the time of the system to pass the 1 mm crack was more than 10 times that of the ordinary cement slurry,and the system could stay and stack at the entrance of the leak layer,as wells as the compressive strength reached more than 7 MPa.The gel-cement system was especially suitable for the leakage plugging of large channels,large fracture holes,underground rivers and aquifers.
In order to control excessive water production in oil wells in offshore oilfield,the properties including injectivity,plugging capability,selectivity and water flushing resistance of an in-situ gelation water shutoff system in offshore oilfield,composed of 1%functional microsphere +3%functional monomer +0.8%gel promoter,were evaluated,and a field pilot test was carried out.The property evaluation results showed that the gelation time of the in-situ gelation water shutoff system from strength A to strength I was as long as 134 h,which could meet the requirements of on-site implementation for gelation time.The injection pressure was only 0.28 MPa in the sandpack with a permeability of 1020×10-3 μm2,and decreased with the increase of permeability,indicating the good injectivity of the system.The system had good properties of selectivity,plugging and water erosion resistance.It could preferentially enter the high permeability channeling area.After gelation,the plugging rate of the high permeability channeling area was more than 90%,and the plugging rate was only reduced by about 5.0%after 100 PV continuously water injection.After 60 days of immersing in water at the temperature of 65℃,the strength loss rate was only 4.1%,indicating that the system had good property of water immersion resistance after gelation.The field pilot test results showed that the water plugging effect of the in-situ gelation water shutoff system was obvious,the complex water channeling of the target well could be effectively controlled,and achieved the purpose of decreasing water production and increasing oil production of the target well.
Preformed particle gels(PPG)are widely used to control the dominant channeling channel of reservoir to stabilize oil production and control water production.In order to solve the problems of inadequate strength,poor shear recovery performance and salt intolerance of conventional PPG with covalent structure,a host-guest inclusion supramolecular particle gels(S-PPG)profile control agent containing covalent and non-covalent crosslinked structure was developed,which had shear recovery performance.S-PPG was prepared using allyl-β-cyclodextrin(allyl-β-CD,host functional monomer),cetyldimethylallyl ammonium chloride(C16DMAAC,guest functional monomer)and N,N-methylene diacrylamide(MBA,crosslinking agent)and acrylamide(AM)as main raw materials.The rheological properties,swelling properties and salt tolerance of S-PPG was systematically investigated by measurements of rheometer,laser particle size analyzer and optical microscope.The results showed that the elastic modulus of S-PPG(2.5+2.5)system with mass fraction of 0.6%prepared with the formation water was 73 Pa after swelling for 24 h,which was 3.04 times of conventional PPG.The yield stress was 120 Pa,the shear viscosity loss rate was only 39%,the shear resistance and yield stress were about 4 times of the conventional PPG,and the swelling ratio in formation water was 23.In addition,the swelling property of S-PPG was gradually increased with the increase of salt content,and the swelling ratio could reach 27.9 at 1×105 mg/L NaCl concentration,showing excellent salt tolerance.It provides a potential new shear resistant S-PPG material for reservoir in-depth conformance control.
In order to compare the scale penetrability and penetration mechanism of different bactericides,a simulated penetration experiment was conducted under the scale layer from the field,employing polyhexamethylene monoguanidine hydrochloride(PHMH)and glutaraldehyde as prototypes.The pore size distribution of scale samples was characterized by nitrogen adsorption-desorption method.Meanwhile,the charging property of scale layers in 3.5%NaCl solution was determined by dynamic light scattering technique.Standard curves for PHMH and glutaraldehyde in 3.5%NaCl solution were established at 506.7 nm and 232.2 nm,respectively.With the aid of self-made device and standard curves,the penetrations of PHMH and glutaraldehyde with time were monitored by ultraviolet spectrophotometer.The results showed that two scale samples on site were mainly composed of calcium carbonate and barium sulfate with an average pore size of 0.43 and 0.27 μm,respectively.The Zeta potentials showed a trend from positive to negative as the pH value of the solution increased.The corresponding isoelectric points were 4.14 and 4.56,respectively.After immersing two scale samples in NaCl solution,the interface showed negative charge with Zeta potential of-6.56 mV and-5.14 mV,respectively.After 15 days of penetration monitoring,PHMH showed a slow penetration behavior first and then fast with 17.70%the highest permeability,while glutaraldehyde showed a fast penetration behavior first and then slow with 38.75%the highest permeability.The pore size of scale sample directly affected the total diffused amount of bactericide,but did not change its diffusion pattern.Electrostatic interaction with the scale layer resulted in the early slow penetration of PHMH,while physical screening effect determined the final penetration amount of glutaraldehyde.This work provided guidance for the screening of on-site bactericide and the synergistic compatibility with other agents.
In order to enhance the strength of polyacrylamide(PAM)gel,nanocrystalline cellulose(NCC)was used to prepare AM/NCC composite hydrogel.The effects of NCC on the tensile property,compressive property,adhesion property and viscoelastic property of composite hydrogel were investigated by using texture analyzer and rheometer,and then the microstructure of composite hydrogel was observed by scanning electron microscope(SEM).The results showed that the tensile strength,compressive stress,adhesive force,elasticity modulus and viscosity modulus of composite hydrogel were significantly higher than those without NCC.When the mass ratio of AM to NCC was 5∶3,the tensile strength,compressive stress and elasticity modulus of composite hydrogel reached the maximum.The toughness of composite hydrogel was significantly enhanced.Meanwhile,the tensile stress and adhesion force were nearly 3 times higher than those of PAM gel.Compared with PAM gel,the network structure of PAM/NCC composite hydrogel became denser.Furthermore,the mechanical strength and adhesion to wellbore wall became better.PAM/NCC composite hydrogel could be used for underbalanced drilling in oil and gas fields.
Self-healing material is a kind of material which can heal itself after being damaged by external action.It is of great significance to prolong the service life of materials,eliminate safety hazards and reduce maintenance costs.In recent years,it has been widely researched and applied in the field of oil and gas drilling and production.Self-healing materials were classified into external and intrinsic types based on different healing methods.The healing mechanisms and characteristics of external(microcapsules,oil and gas activated materials,differential pressure activated sealants)and intrinsic(physical self-healing,chemical self-healing)self-healing materials were systematically summarized in this paper.Physical self-healing mainly included hydrogen bonding,hydrophobic association,ionic bond actions,host-guest recognition.Chemical self-healing mainly included the combination and fracture of imine bond,acylhydrazone bond,disulfide bond,etc.The research status of different types of self-healing materials in the fields of well cementing,downhole pipe fittings repair,leak-proof plugging,wellbore strengthening,fluid loss reduction,and profile control and water shutoff was summarized,and the prospects for their development were prospected.
the factors affecting the asphaltene stability in crude oil are complex,and the mechanism of the change of crude oil composition on the stability of asphaltene is still unclear.On the basis of measuring the density,viscosity,element composition and four components(saturated hydrocarbon,aromatic hydrocarbon,resin and asphaltene)content of 10 different crude oil samples,the composition of 10 crude oil samples and their interaction characteristics with asphaltene were studied by means of field emission scanning electron microscopy,Fourier transform infrared spectroscopy,X-ray fluorescence spectroscopy and Zeta potential evaluation.The influence of wax,water and inorganic salt on the stability of asphaltene.The results showed that the density and viscosity of crude oil were in direct proportion to the content ratio of heavy and light hydrocarbons.When the asphaltene content increased,the H content and molar ratio of H to C in crude oil decreased,while the non hydrocarbon content increased,and the stability of asphaltene decreased.Wax and water would change the composition of crude oil and affect the stability of asphaltene.The contents of inorganic and organic metals in crude oil were 0.0021%—0.0814%and 0.0007%—0.0655%,respectively.Organic metals such as vanadium and nickel would destroy the stability of asphaltene,while inorganic metals in the reservoir would enhance the stability of asphaltene.There were a large number of negatively charged inorganic particles on the surface of asphaltene sediment,resulting in negative Zeta potential of its aqueous solution.When the absolute value of Zeta potential was greater,the stability of asphaltene was better,indicating that the charge generated by inorganic particles could stabilize asphaltene in crude oil and reduce the aggregation tendency of asphaltene.The research results provided a reference for effective prevention of asphaltene deposition and mitigation of deposition damage.
The harmless treatment of oily sludge in oilfield production is difficult and costly.Reinjection of oily sludge is a low-cost harmless treatment technology.The conventional reinjection profile control method can only reinject the oily sludge particles with smaller particle size,which can not fully recycle the oily sludge.Therefore,the oily sludge particles were ball milled to the micro-nano scale,and then petroleum sulfonate surfactant was added to form a stable oil displacement system by stirring,ultrasonication and centrifugation.The particle size distribution,emulsification ability and oil displacement performance of oily sludge flooding system with micro-nano particle were studied.The results showed that the median particle size of oily sludge micro-nano particle in oil displacement system was 158 nm.The system could maintain good suspension after standing at room temperature(25℃)for 4 days.The time of complete separation of oil and water was equal or greater than 5 min.The interfacial tension between the system with kerosene at 60℃was 7.4×10-3 mN/m,indicating strong emulsification ability.Due to the dual effects of emulsification and plugging,the oily sludge micro-nano particle flooding system had better injection capacity and oil displacement effect than surfactant flooding,which was suitable for medium and low permeability reservoirs.Under the condition of 60℃,injection volume of 0.5 PV and injection rate of 1 mL/min,the oil displacement efficiency was about 20 percentage points higher than that of water flooding and about 8 percentage points higher than that of surfactant flooding.The preparation method of oily sludge micro-nano particle flooding system could completely treat oily sludge,and then realize the efficient reuse of oily sludge.
In order to remove strontium barium sulfate scale generated during the development of oil and gas fields,which is characteristic of dense scaling,low solubility,and insoluble in acids and alkalis,the chemical scaling technology was adopted.Firstly,a chelating agent was selected,and then different additives were added to utilize their synergistic and modifying effects.The optimal formulation of barium sulfate/strontium scale remover was determined through single factor experiments as follows,10%DTPA+6%salicylic acid+0.03%potassium polyacrylate concentration+0.2%Tween-80.The effects of pH,temperature,and reaction time on the scale removal effect were also investigated.The results showed that the best scale removal effect was achieved when the pH value was 12,the temperature was 80℃,and the scale removal time was 8 hours.Under these conditions,the descaling rates of barium sulfate,strontium sulfate,and actual scale samples were 79.41%,80.56%and 59.7%,respectively.The scale remover had the advantages of high scale removal efficiency,short scale removal time and low cost,and had broad application prospects in oil and gas field scale removal.
In view of the problem that the performance of conventional slip-water drag reducer is seriously decreased at high temperature and high salinity,a no-miscible salt-resistant polymer emulsion was developed as a drag reducer.It is necessary to carry out research on the optimization of polymer emulsion formula.Rheology,viscoelasticity,resistance reduction,gel breaking properties,core damage of fracturing fluid prepared with clean water and Ma 18 water were tested in laboratory and field application was carried out.The results showed that,when the concentration of salt-resistant polymer emulsion was 0.05%—1.2%,the viscosity retention rate was between 32.5%—62.5%at high salinity of 21159.88 mg/L,and the performance of the fracture liquid system at the concentration of 0.2%—0.5%could be similar to that at the concentration of 0.1%—0.2%at low salinity,and the elastic modulus of the system was dominant.The resistance reduction rate of the system was more than 4%higher than that of conventional polymer emulsion.The surface tension of the gel-breaking fluid was less than 28 mN/m,and the interfacial tension with kerosene was less than 2 mN/m,and the residue content was less than 50 mg/L.The damage of gel-breaking fluid to core was less.In field application,the idea of stepping polymer concentration increase was adopted,and it was obtained that when the sand concentration was 30-270 kg/m3,the mass fraction of polymer fracturing fluid should be 0.15%—0.2%;when the sand concentration was 300-360 kg/m3,the mass fraction of polymer fracturing fluid should be 0.2%—0.35%.The mass fraction of polymer fracturing fluid was further optimized to be 0.15%—0.35%,and the resistance reduction rate could reach up to about 85%during construction.After the test well was put into operation,the effect was good,which provided a reasonable technical scheme for the effective use of polymer fracturing liquid system in horizontal wells of Mahu oilfield.
四川大学高分子学科由我国高分子材料科学与工程的奠基人之一、"中国塑料之父"、中国科学院院士徐僖先生于1953年创立,已走过70年辉煌历程.经过国家重点学科、国家重点实验室、"211工程"、"985工程"、双一流重点学科建设,已成为国内一流、国际知名的以高分子材料高性能化、加工为特色的高分子材料科学与工程领域规模最大的科研和教学基地之一.
In order to meet the strength,gelling time and gel breaking performance requirements of the gel plugging system for high pressure water injection wells under pressure operation,a temperature-resistant and salt-resistant gel plugging system was developed.This system utilized acrylamide(AM)/2-acrylamido-2-methylpropanesulfonic acid(AMPS)as a binary polymer system and trimethylol compound(Smel30)as crosslinking agent.The effects of temperature,inorganic salt,simulated oil content,and shear time on gelling time and gel strength of the system were investigated.Additionally,the influence of sodium persulfate on gel breaking effect of the system was studied.The results showed that when the temperature increased from 40℃to 100℃,the gelling time of the system decreased from 23.5 hours to 2.0 hours,while the gel strength increased from 39.4 Pa to 88.6 Pa.Inorganic salts could reduce the distance between polymer chains,which led to shorter gelation time and a slight increase in gel strength.Three inorganic salts were arranged according to the effects on gelling time and gel strength of the system in following order:NaCl
