Effect of Temperature on Surfactant Adsorption in Porous Media

1981 ◽  
Vol 21 (02) ◽  
pp. 218-228 ◽  
Author(s):  
Victor M. Ziegler ◽  
Lyman L. Handy
Keyword(s):  
Crude Oil ◽  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Elevated Temperatures ◽  
Steam Injection ◽  
Mineral Dissolution ◽  
Hot Water ◽  
Effect Of Temperature ◽  
Surfactant Adsorption ◽  
Thermal Stabilities

Abstract The effect of temperature on the adsorption of asulfonate surfactant and a nonionic surfactant ontocrushed Berea sandstone was studied by both staticand dynamic techniques. Static experiments were conducted over atemperature range from 25 to 95 degrees C to definetemperature-sensitive rock/surfactant systems and toestablish the shape of the equilibrium isotherm.Dynamic experiments served to reinforce the findingsof the static tests and extended the temperature rangefor sorption to 80 degrees C. This is a typicalsteamflood temperature. A mathematical model thatincorporates the mass transport, thermal degradation, and rate-dependent adsorption of the surfactantrepresented these dynamic results. The model wasused to determine the effect of temperature on the sorption rate constants. Mineral dissolution at elevated temperatures hasbeen found to cause precipitation of the sulfonate.Adsorption of the nonionic surfactant decreased withan increase in temperature at low concentrations, whereas the opposite was true at high concentrations.This has favorable implications for a low-concentration injection scheme. When performingstatic adsorption experiments, care had to be takenbecause of the poor thermal stability of the nonionic surfactant. Introduction Injection of surfactants concurrently with steam intooil-bearing reservoirs has been proposed recentlyto improve the recovery efficiency of the steam-driveprocess. From the behavior of chemical additivespreviously used in steamfloods, it is anticipated thatthe injected surfactant will travel through thatportion of the reservoir being flooded by hot water. Oil recovery can be increased if the surfactanteffectively reduces the residual oil saturation withinthis hot-water zone. For concurrent surfactant/steam injection to be technically attractive, a synergisticeffect between the surfactant and temperature isdesired. In our concept of the process, the surfactant mustmove in the heated portion of the reservoir and beable to function as an effective recovery agent atelevated temperatures for prolonged periods of time.Surfactant screening, therefore, requires thisinformation:surfactant stability under steamfloodconditions,temperature effects on the interfacial tension (IFT) between the reservoir oil and aqueoussurfactant,an evaluation of the effect oftemperature on surfactant flood performance, andthe effect of temperature on surfactant adsorption atthe water/solid interface. Handy et al. reported the thermal stabilities ofseveral classes of surfactants. Hill et al. showed thattemperature can have a dramatic effect in reducingthe IFT between crude oil and an aqueous sulfonatesystem. Handy et al. saw a similar temperatureeffect for a nonionic-surfactant/crude-oil system. Itappears, therefore, that the required synergismbetween temperature and surface activity necessaryfor concurrent surfactant/steam injection exists.Surfactant core floods are required to evaluate theeffect of temperature on oil recovery. Finally, toensure that the surfactant moves in the heatedportion of the reservoir, it is necessary to determinethe effect of temperature on adsorption. SPEJ P. 218^

Thermal Stability of Surfactants for Reservoir Application (includes associated papers 11323 and 11597 )

1982 ◽  
Vol 22 (05) ◽  
pp. 722-730 ◽  
Author(s):  
L.L. Handy ◽  
J.O. Amaefule ◽  
V.M. Ziegler ◽  
I. Ershaghi
Keyword(s):  
Nonionic Surfactant ◽  
Oil Recovery ◽  
Half Life ◽  
Elevated Temperatures ◽  
Effect Of Temperature ◽  
Residual Oil ◽  
Chemical Additives ◽  
Thermal Stabilities ◽  
Oil Saturation ◽  
Residual Oil Saturation

Abstract The thermal stabilities of several sulfonate surfactantsand one nonionic surfactant have been evaluated. Thedecomposition reactions have been observed to followfirst-order kinetics. Consequently, a quantitativemeasure of a surfactant's stability at a given temperatureis its half-life. Furthermore, the activation energy can beestimated from rate data obtained at two or moretemperatures. This permits limited extrapolation of theobserved decomposition rates to lower temperatures forwhich the rates are too low for convenient measurement.The surfactants we investigated are being considered forsteamflood additives and need to be relatively stable atsteam temperatures.None of the surfactants evaluated to date has therequisite stability for use in steamfloods. The most stablepetroleum sulfonate we have investigated has a half-lifeof 11 days at 180 degrees C (356 degrees F). With this half-life, substantial overdosing would be required tomaintain the minimum effective surfactant concentration forthe life of the flood. On the other hand, the estimatedhalflife for this surfactant at 93 degrees C (200 degrees F), calculated by extrapolation, would be 33 years.Tests with the nonionic surfactant, nonylphenoxy-polyethanol, have shown this material to have a very short half-life at steam temperatures, but it doesappear to be more stable at concentrations greater than thecritical micelle concentration(CMC). In limited tests, the sulfonates showed increased stability in the presenceof a 2-M salt solution. Introduction Several chemical additives are being considered for usewith steamfloods to reduce the producing steam/oilratios and to increase oil recovery from steam projects.The emphasis to date has been on inorganic chemicaladditives. Sodium hydroxide has been used in the fieldwithout success. We have been investigating thepotential benefits of using organic surfactants. This hasbeen discusssed recently by Brown et al. and byGopalakrishnan et al. The surfactant would be introducedinto the reservoir along, with the steam at the beginning ofthe steamflood and, possibly, intermittently during the floodprocess. The surfactant would be injected in diluteconcentrations and would be expected to travel in thatportion of the reservoir being flooded by hot water.Although the residual oil saturation in the steam zone has been observed to be very low, residual saturation in thehot water portion of the steamflood is expected to be thenormal waterflood residual. A surfactant in the hot watermay reduce this residual oil saturation. A synergistic effect could be observed between the surfactant and thetemperature to give better performance than would beobserved for a surfactant flood at normal reservoirtemperatures.For the process to work as anticipated, the surfactantmust move in the heated portion of the reservoir, and it must be sufficiently stable at elevated temperatures tofunction as an effective recovery agent for the life of theflood. Therefore, two aspects of the process are beingstudied simultaneously. One of these is the effect oftemperature on adsorption of the surfactants, and theother is the effect of heat on the stability of thesurfactants. The effect of temperature on adsorption will bediscussed in a later paper. The objective of this paper isto discuss the experimental evaluation of the thermalstability of some surfactant types that could haveapplication in reservoir floods. The effect of temperatureon adsorption and stability of these surfactants also willbe important in micellar floods at higher reservoirtemperatures. Experimental Procedures Several anionic and noninoic surfactants were selectedfor evaluation. SPEJ P. 722^

Steam Distillation of Crude Oils

1983 ◽  
Vol 23 (02) ◽  
pp. 265-271 ◽  
Author(s):  
J.H. Duerksen ◽  
L. Hsueh
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Steam Distillation ◽  
Steam Injection ◽  
Hot Water ◽  
Saturated Steam ◽  
Crude Oils ◽  
Simulated Distillation ◽  
Distillation Temperature ◽  
Hydrocarbon Vapor

Abstract The objectives of this investigation were to generate crude oil steam distillation data for the prediction of phase behavior in steamflood simulation and to correlate the steam distillation yields for a variety of crude oils. Thirteen steam distillation tests were run on 10 crude oils ranging in gravity from 9.4 to 37 deg. API (1.004 to 0.840 g/cm3). In each test the crude was steam distilled sequentially at about 220, 300, 400, and 500 deg. F (104, 149, 204, and 260 deg. C). The cumulative steam distillation yields at 400 deg. F (204 deg. C) ranged from about 20 to 55 vol%. Experimental results showed that crude oil steam distillation yields at steamflood conditions are significant, even for heavy oils. The effects of differences in steam volume throughput and steam temperature were taken into account when comparing yields for different crudes or repeat runs on the same crude. Steam distillation yields show a high correlation with crude oil API gravity and wax content. Introduction Steam distillation is an important steamflood oil recovery mechanism, especially in reservoirs containing light oils. Injected steam heats the formation and eventually forms a steam zone, which grows with continued steam injection. A fraction of the crude oil in the steam zone vaporizes into the steam phase according to the vapor pressures of the hydrocarbon constituents contained in the crude oil. The hydrocarbon vapor is transported through the steam zone by the flowing steam. Both the steam and hydrocarbon vapor condense at the steam front to form a hot-water zone and a hydrocarbon distillate bank. The vaporization, transport, and condensation of the hydrocarbon fractions is a dynamic process that displaces the lighter hydrocarbon fractions and generates a distillate bank that miscibly drives reservoir oil to producing wells. The effect of steam distillation on oil recovery has been investigated in several laboratory studies, steamf lood field tests, and in simulation studies. In a critical review of steam flood mechanisms, Wu discussed the steam distillation mechanism in detail. Wu and Brown reported steam distillation yields for six crude oils ranging from 9 to 36 deg. API (1.007 to 0.845 g/cm3). When plotted against their steam distillation correlation parameter, Vw/Voi (the ratio of collected steam condensate, Vw, and initial oil volume, Voi), the yields were independent of the porous medium used, steam-injection rate, and initial oil volume. For the crude oils tested, they concluded that changing the saturated steam pressure and temperature had an insignificant effect on yield, but superheating the steam from 471 to 600 deg. F (244 to 316 deg. C) significantly increased the yield. Wu and Elder reported steam distillation yields for 16 crude oils ranging from 12 to 40 deg. API (0.986 to 0.825 g/cm3). Yields ranged from 12 to 56% of initial oil volume at a distillation temperature and pressure of 380 deg. F and 200 psig (193 deg. C and 1.379 MPa). Yields at Vw/Voi = 15 were correlated with three parameters:simulated distillation temperature of the oil at 20% yield,oil viscosity, andoil API gravity. The simulated distillation obtained by gas chromatography closely approximates the true boiling-point distillation as determined by ASTM distillation. The simulated distillation temperature at 20% yield gave the closest correlation with steam distillation yield. SPEJ P. 265^

scholarly journals Screening of waterflooding, hot waterflooding and steam injection for extra heavy crude oil production from Tatarstan oilfield

2021 ◽  
Vol 931 (1) ◽  
pp. 012002
Author(s):  
A Pituganova ◽  
I Minkhanov ◽  
A Bolotov ◽  
M Varfolomeev
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Water Injection ◽  
Oil Production ◽  
Steam Injection ◽  
Hot Water ◽  
Heavy Crude Oil ◽  
Oil Viscosity ◽  
Heavy Crude ◽  
Bulk Model

Abstract Thermal enhanced oil recovery techniques, especially steam injection, are the most successful techniques for extra heavy crude oil reservoirs. Steam injection and its variations are based on the decrease in oil viscosity with increasing temperature. The main objective of this study is the development of advanced methods for the production of extra heavy crude oil in the oilfield of the Republic of Tatarstan. The filtration experiment was carried out on a bulk model of non-extracted core under reservoir conditions. The experiment involves the injection of slugs of fresh water, hot water and steam. At the stage of water injection, no oil production was observed while during steam injection recovery factor (RF) achieved 13.4 % indicating that fraction of immobile oil and non-vaporizing residual components is high and needed to be recovered by steam assisted EORs.

scholarly journals Role of divalent ions, temperature, and crude oil during water injection into dolomitic carbonate oil reservoirs

2019 ◽  
Vol 74 ◽  
pp. 36 ◽  
Author(s):  
Mohammad Fattahi Mehraban ◽  
Shahab Ayatollahi ◽  
Mohammad Sharifi
Keyword(s):  
Contact Angle ◽  
Crude Oil ◽  
Oil Recovery ◽  
Elevated Temperatures ◽  
Angle Measurement ◽  
Wettability Alteration ◽  
Effect Of Temperature ◽  
Surface Charges ◽  
Potential Measurement ◽  
Asphaltene Content

Although wettability alteration has been shown to be the main control mechanism of Low Salinity and Smart Water (LS-SmW) injection, our understanding of the phenomena resulting in wettability changes still remains incomplete. In this study, more attention is given to direct measurement of wettability through contact angle measurement at ambient and elevated temperatures (28 °C and 90 °C) during LS-SmW injection to identify trends in wettability alteration. Zeta potential measurement is utilized as an indirect technique for wettability assessment in rock/brine and oil/brine interfaces in order to validate the contact angle measurements. The results presented here bring a new understanding to the effect of temperature and different ions on the wettability state of dolomite particles during an enhanced oil recovery process. Our observations show that increasing temperature from 28 °C to 90 °C reduces the contact angle of oil droplets from 140 to 41 degrees when Seawater (SW) is injected. Besides, changing crude oil from crude-A (low asphaltene content) to crude-B (high asphaltene content) contributes to more negative surface charges at the oil/brine interface. The results suggest that the sulphate ion (SO42-) is the most effective ion for altering dolomite surface properties, leading to less oil wetness. Our study also shows that wettability alteration at ambient and elevated temperatures during LS-SmW injection can be explained by Electrical Double Layer (EDL) theory.

Tertiary Recovery Improvement of Steam Injection Using Chemical Additives: Pore Scale Understanding of Challenges and Solutions Through Visual Experiments

2021 ◽  
Author(s):  
Randy Agra Pratama ◽  
Tayfun Babadagli
Keyword(s):  
Porous Media ◽  
Phase Change ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Phase Distribution ◽  
Steam Injection ◽  
Hot Water ◽  
Heavy Oil Recovery ◽  
Residual Oil ◽  
Tertiary Recovery

Abstract Our previous research, honoring interfacial properties, revealed that the wettability state is predominantly caused by phase change—transforming liquid phase to steam phase—with the potential to affect the recovery performance of heavy-oil. Mainly, the system was able to maintain its water-wetness in the liquid (hot-water) phase but attained a completely and irrevocably oil-wet state after the steam injection process. Although a more favorable water-wetness was presented at the hot-water condition, the heavy-oil recovery process was challenging due to the mobility contrast between heavy-oil and water. Correspondingly, we substantiated that the use of thermally stable chemicals, including alkalis, ionic liquids, solvents, and nanofluids, could propitiously restore the irreversible wettability. Phase distribution/residual oil behavior in porous media through micromodel study is essential to validate the effect of wettability on heavy-oil recovery. Two types of heavy-oils (450 cP and 111,600 cP at 25oC) were used in glass bead micromodels at steam temperatures up to 200oC. Initially, the glass bead micromodels were saturated with synthesized formation water and then displaced by heavy-oils. This process was done to exemplify the original fluid saturation in the reservoirs. In investigating the phase change effect on residual oil saturation in porous media, hot-water was injected continuously into the micromodel (3 pore volumes injected or PVI). The process was then followed by steam injection generated by escalating the temperature to steam temperature and maintaining a pressure lower than saturation pressure. Subsequently, the previously selected chemical additives were injected into the micromodel as a tertiary recovery application to further evaluate their performance in improving the wettability, residual oil, and heavy-oil recovery at both hot-water and steam conditions. We observed that phase change—in addition to the capillary forces—was substantial in affecting both the phase distribution/residual oil in the porous media and wettability state. A more oil-wet state was evidenced in the steam case rather than in the liquid (hot-water) case. Despite the conditions, auspicious wettability alteration was achievable with thermally stable surfactants, nanofluids, water-soluble solvent (DME), and switchable-hydrophilicity tertiary amines (SHTA)—improving the capillary number. The residual oil in the porous media yielded after injections could be favorably improved post-chemicals injection; for example, in the case of DME. This favorable improvement was also confirmed by the contact angle and surface tension measurements in the heavy-oil/quartz/steam system. Additionally, more than 80% of the remaining oil was recovered after adding this chemical to steam. Analyses of wettability alteration and phase distribution/residual oil in the porous media through micromodel visualization on thermal applications present valuable perspectives in the phase entrapment mechanism and the performance of heavy-oil recovery. This research also provides evidence and validations for tertiary recovery beneficial to mature fields under steam applications.

A Temperature Operating Window Concept for Application of Nonionic Surfactants for EOR in Unconventional Shale Reservoirs

2021 ◽  
Author(s):  
I Wayan Rakananda Saputra ◽  
David S. Schechter
Keyword(s):  
Crude Oil ◽  
Nonionic Surfactant ◽  
Cloud Point ◽  
Oil Recovery ◽  
Nonionic Surfactants ◽  
Spontaneous Imbibition ◽  
Reservoir Temperature ◽  
Rock System ◽  
Temperature Operating ◽  
Operating Window

Abstract Surfactant performance is a function of its hydrophobic tail, and hydrophilic head in combination with crude oil composition, brine salinity, rock composition, and reservoir temperature. Specifically, for nonionic surfactants, temperature is a dominant variable due to the nature of the ethylene oxide (EO) groups in the hydrophilic head known as the cloud point temperature. This study aims to highlight the existence of temperature operating window for nonionic surfactants to optimize oil recovery during EOR applications in unconventional reservoirs. Two nonylphenol (NP) ethoxylated nonionic surfactants with different EO head groups were investigated in this study. A medium and light grade crude oil were utilized for this study. Core plugs from a carbonate-rich outcrop and a quartz-rich outcrop were used for imbibition experiments. Interfacial tension and contact angle measurements were performed to investigate the effect of temperature on the surfactant interaction in an oil/brine and oil/brine/rock system respectively. Finally, a series of spontaneous imbibition experiments was performed on three temperatures selected based on the cloud point of each surfactant in order to construct a temperature operating window for each surfactant. Both nonionic surfactants were observed to improve oil recovery from the two oil-wet oil/rock system tested in this study. The improvement was observed on both final recovery and rate of spontaneous imbibition. However, it was observed that each nonionic surfactant has its optimum temperature operating window relative to the cloud point of that surfactant. For both nonionic surfactants tested in this study, this window begins from the cloud point of the surfactant up to 25°F above the cloud point. Below this operating window, the surfactant showed subpar performance in increasing oil recovery. This behavior is caused by the thermodynamic equilibrium of the surfactant at this temperature which drives the molecule to be more soluble in the aqueous-phase as opposed to partitioning at the interface. Above the operating window, surfactant performance was also inferior. Although for this condition, the behavior is caused by the preference of the surfactant molecule to be in the oleic-phase rather than the aqueous-phase. One important conclusion is the surfactant achieved its optimum performance when it positions itself on the oil/water interface, and this configuration is achieved when the temperature of the system is in the operating window mentioned above. Additionally, it was also observed that the 25°F operating window varies based on the characteristic of the crude oil. A surfactant study is generally performed on a single basin, with a single crude oil on a single reservoir temperature or even on a proxy model at room temperature. This study aims to highlight the importance of applying the correct reservoir temperature when investigating nonionic surfactant behavior. Furthermore, this study aims to introduce a temperature operating window concept for nonionic surfactants. This work demonstrates that there is not a "one size fits all" surfactant design.

Software Tool for the Study, Analysis and Evaluation of Enhanced Oil Recovery Processes

2014 ◽  
Author(s):  
C. L. Delgadillo-Aya ◽  
M.L.. L. Trujillo-Portillo ◽  
J.M.. M. Palma-Bustamante ◽  
E.. Niz-Velasquez ◽  
C. L. Rodríguez ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Injection ◽  
Software Tool ◽  
Steam Injection ◽  
Hot Water ◽  
Assessment Process ◽  
Analytical Models ◽  
Financial Assessment ◽  
Recovery Processes

Abstract Software tools are becoming an important ally in making decisions on the development or implementation of an enhanced oil recovery processes from the technical, financial or risk point of view. This work, can be manually developed in some cases, but becomes more efficient and precise with the help of these tools. In Ecopetrol was developed a tool to make technical and economic evaluation of enhanced oil recovery processes such as air injection, both cyclic and continuous steam injection, and steam assisted gravity drainage (SAGD) and hot water injection. This evaluation is performed using different types of analysis as binary screening, analogies, benchmarking, and prediction using analytical models and financial and risk analysis. All these evaluations are supported by a comprehensive review that has allowed initially find favorable conditions for different recovery methods evaluated, and get a probability of success based on this review. Subsequently, according to the method can be used different prediction methods, given an idea of the process behavior for a given period. Based on the prediction results, it is possible to feed the software to generate a financial assessment process, in line with cash flow previously developed that incorporates all the elements to be considered during the implementation of a project. This allows for greater support to the choice or not the application of a method. Finally the tool to evaluate the levels of risks that outlines the development of the project based on the existing internal methodology in the company, identifying the main and level of criticality and define actions for prevention, mitigation and risk elimination.

Correlation of Crude Oil Steam Distillation Yields With Basic Crude Oil Properties

1983 ◽  
Vol 23 (06) ◽  
pp. 937-945 ◽  
Author(s):  
Ching H. Wu ◽  
Robert B. Elder
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Boiling Point ◽  
Steam Distillation ◽  
Recovery Process ◽  
Steam Injection ◽  
Steam Pressure ◽  
Oil Viscosity ◽  
Simulated Distillation ◽  
Distillation Yield

Abstract Steam distillation can occur in reservoirs during steam injection and in-situ combustion processes. To estimate the amount of vaporized oil caused by steam distillation, we established correlations of steam distillation yields with the basic crude oil properties. These correlations were based on steam distillation tests performed on 16 crude oils from various pans of the U.S. The gravity of oils varied from 12 to 40 deg. API [0.99 to 0.83 g/cm3]. The viscosity of oil ranged from 5 to 4,085 cSt [5 to 4085 mm /s] at 100 deg. F [38 deg. C]. The steam distillations were performed at a saturated steam pressure of 220 psia [1.5 MPa]. One oil sample was used in experiments to investigate the effect of steam pressure (220 to 500 psia [1.5 to 3.4 MPa]) on the steam distillation yield. The experiments were carried out to a steam distillation factor (Vw/Voi) of 20, with the factor defined as the cumulative volume of condensed steam used in distillation, Vw, divided by the initial volume of oil, Voi. At a steam distillation factor of 20, the distillation yields ranged from 13 to 57% of the initial oil volume. Several basic crude oil properties can be used to predict steam distillation yields reasonably well. A correlation using oil viscosity in centistokes at 100 deg. F [38 deg. C] can be used to predict the steam distillation yield within a standard error of 4.3 %. The API gravity can be used to estimate wields within 5.6%. A gas chromatographic analysis was made for each crude oil to obtain the component boiling points (simulated distillation temperatures). A correlation parameter was selected from the simulated distillation results that can be used to estimate the steam distillation yields within 4.5%. Introduction Steamflooding has been used commercially to recover heavy oils for several decades. Although it is considered a heavy-oil recovery process, it has been demonstrated to be an effective and commercially feasible process for recovering light oils. To enhance the effectiveness of the oil recovery process, it is important to fully understand and utilize the basic steamflooding mechanisms. Willman et al. investigated the mechanisms of steamflooding. They concluded that oil viscosity reduction, oil volume expansion, and steam distillation are the major mechanisms for oil recovery. Since then, more research has been done on all phases of steam injection. However, steam distillation and its ramifications on recovery have not been quantified fully because of lack of experimental data. Steam distillation can lower the boiling point of a water/oil mixture below the boiling point of the individual components. SPEJ P. 937^

scholarly journals Characterization and assessment of biosurfactant producing indigenous hydrocarbonoclastic bacteria: potential application in bioremediation

2018 ◽  
Vol 17 (2) ◽  
pp. 103-114 ◽  
Author(s):  
Pranjal Bharali ◽  
Salam Pradeep Singh ◽  
Yasir Bashir ◽  
Nipu Dutta ◽  
Bolin Kumar Konwar ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Potential Application ◽  
Elevated Temperatures ◽  
Extreme Temperature ◽  
Chemical Characterization ◽  
Bacterial Strains ◽  
Hydrocarbonoclastic Bacteria ◽  
Rdna Sequencing ◽  
Thermo Stability

Abstract Petroleum and hydrocarbons contamination can be remediated by physical, chemical or biological methods. Among these, in situ bioremediation is considered to be environmentally friendly because it restores the soil structure, requires less energy input and involves the notable removal after degradation of biosurfactant. The present study involves the characterization and assessment of biosurfactant producing indigenous hydrocarbonoclastic bacteria and their potential application in bioremediation processes. Three bacterial strains were isolated from various crude oil contaminated environments and characterized using standard identification techniques. The results clearly demonstrate the capability of utilizing hydrocarbon and biosurfactant produced by the bacterial strains. 16S rDNA sequencing followed by BLAST analysis revealed their similarity to Pseudomonas aeruginosa. The physico-chemical characterization of the biosurfactants revealed significant surface properties with stability at extreme temperature conditions (up to 121˚C), pH (5 - 8) and salinity (up to 4 %). Further, the mass spectrometry confirmed predominance of di-rhamnolipids in biosurfactant mixtures. The biosurfactants were found to be efficient in the removal of crude oil from the contaminated sand suggesting its applicability in bioremediation technology. Further, improved discharge of crude oil at elevated temperatures also confirms their thermo-stability which, could be exploited in microbial enhanced oil recovery processes. Thus, the applications of biosurfactants produced by the indigenous hydrocarbonoclastic strains appeared to be advantageous for bioremediation of petroleum-contaminated environments.

Experimental Research on Hot Water Flooding of Different Rhythm Heavy Oil Reservoir after the Steam Injection

2012 ◽  
Vol 550-553 ◽  
pp. 2878-2882 ◽  
Author(s):  
Ping Yuan Gai ◽  
Fang Hao Yin ◽  
Ting Ting Hao ◽  
Zhong Ping Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Physical Simulation ◽  
Steam Injection ◽  
Hot Water ◽  
Water Flooding ◽  
Oil Reservoir ◽  
Steam Flooding ◽  
Heavy Oil Reservoir ◽  
Swept Volume

Based on the issue of enhancing oil recovery of heavy oil reservoir after steam injection, this paper studied the development characteristics of hot water flooding in different rhythm (positive rhythm, anti-rhythm, complex rhythm) reservoir after steam drive by means of physical simulation. The research shows that the positive rhythm reservoir has a large swept volume with steam flooding under the influence of steam overlay and steam channeling. Anti-rhythm reservoir has a large swept volume with hot water flooding, because hot water firstly flows along the high permeability region in upper part of the reservoir, in the process of displacement, hot water migrates to the bottom of reservoir successively for its higher density.

Sign in / Sign up

Export Citation Format

Share Document