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.
