Phase Behavior Tests Research Articles

Effect of Baggase NaLS Surfactant Concentration to Increase Recovery Factor

Surfactant flooding may increase oil recovery by lowering interfacial tension between oil and water. Bagasse is one of the organic materials which contain fairly high lignin, where lignin is the basic substance of making Natrium Lignosulfonate (NaLS) Surfactant. In this research, bagasse based surfactant was applied for surfactant flooding. The research was divided into two sections, namely: phase behavior test and NaLS Surfactant flooding where the water contained 70,000 ppm NaCl. Two surfactant concentrations which were used were 0.75% and 1.5% NaLS surfactant. Phase behavior tests were carried out to find the middle phase emulsion formation. Based on phase behavior test results, the percentage of emulsion volume for 0.75% and 1.5% NaLS is 13.75% and 8.75%, respectively. NaLS surfactant flooding was performed for to obtain the best recovery factor. FTIR equipment used determine recovery factor. The optimum condition was obtained at 0.75% NaLS surfactant concentration where the recovery factor was 4.4%.

Assessment of a surfactant- polymer formulation for conditions in a Colombian field

The surfactant-polymer (SP) process is one of the Chemical Enhanced Oil Recovery (CEOR) methods used in the industry. It has been continuously studied; however, it is still a challenge for the petroleum industry due to the difficulty to design the solution to be injected and forecast process performance. This paper is intended to contribute to the design of fluids used in an SP process based on some previously known properties and conditions. Hence, reservoir and fluid properties of a Colombian Field were used as reference parameters to select the polymer and surfactant. Then, the effects of salts, temperature, and surfactant on tailor-made polymer solutions were determined through a rheological study. Ostwald-de Waele and Carreau-Yasuda models adjusted the measured viscosity data against shear rate, while Arrhenius equation fitted viscosity values at 7,8 s-1 against temperature. The surfactant performance was analyzed using phase behavior tests, and the Chun Huh equations determined the interfacial tension (IFT) values. The Bancroft’s rule was used as a qualitative verification tool of the kind of micro- emulsion formed. From rheology, we concluded that the viscous modulus is predominant for all polymer solutions, and the fluid thickness is reduced due to the presence of divalent cations and raise on temperature, salts or surfactant concentration. On the other hand, the observed phase behavior corresponded to a transition Winsor II to I without finding any Winsor III micro-emulsion. Therefore, some criteria were proposed to select the optimal conditions. For the desired conditions, the reduction of IFT reached values ranging in magnitudes of 10-3 to 10-4 [mN/m]. These values are usually associated with an improved oil recovery factor.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SummaryThe high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments.Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone.Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

Exploring the Potential Application of Palm Methyl Ester Sulfonate as an Interfacial Tension Reducing Surfactant for Chemical Enhanced Oil Recovery

As the petroleum industry is facing challenges to add more oil reserves in their book, greater emphasis has been placed on improving the ultimate recovery factor for oilfields. When the recovery from primary and secondary methods could not be improved further, enhanced oil recovery (EOR) generally will be sought as the last option. One of the techniques applied in EOR is known as surfactant flooding. Though surfactants are very effective for the incremental oil recovery, there are implications during the post-flooding process. EOR surfactants that derived from petrochemicals generally display negative effects towards the marine ecosystem. This initial study aims to evaluate the potential application of palm oil based methyl ester sulfonate (MES) as a possible candidate for EOR application. Three qualitative and quantitative tests were performed on MES to evaluate its properties and capabilities for application in a specific offshore field. The results obtained from the qualitative compatibility and stability tests show that this anionic surfactant has great stability and compatibility with the brine solution as there are no visible signs of precipitation formation. However, the qualitative phase behavior test results indicated that the surfactant solution although has the ability to react with the crude oil but not at the required micro-emulsion state. In addition, the quantitative interfacial tension (IFT) test results also verified and supported the phase behavior test results where the strength of the MES was not adequate as a single surfactant system to achieve the ultra-low IFT state.

Potential of a Novel Surfactant Slug in Recovering Additional Oil from Highly Saline Calcite Cores during the EOR Process: Synergistic Blend of Surface Active Ionic Liquid and Nonionic Surfactant

In the present study, a chemical formulation containing a surface-active ionic liquid (SAIL; tributylhexadecylphosphonium bromide) and a nonionic surfactant (TERGITOL 15-S-9) has been prepared. The composition of the mixed micelle and the interaction parameter between the SAIL and nonionic surfactant at varying concentrations were evaluated by Rubingh theory. The most optimal formulation was then screened through phase behavior tests to determine optimal salinity for the crude/brine/chemical formulation system. The optimal salinity for the oil/water/surfactant system was found to be as high as 9.28 wt %. Dynamic light scattering (DLS) studies and small-angle neutron scattering (SANS) experiments have been performed to provide further insight into the size and structure of the micelles formed by the SAIL and nonionic surfactant, respectively. Traditional laboratory-scale oil displacement experiments were performed to study the effectiveness of the optimized chemical formulation in recovering oil during the surfactant-assisted EOR process. Prolate ellipsoidal-shaped mixed micelles, formation of a WINSOR III phase at high salinities, low equilibration time, and prolonged stability of the ternary phase system facilitate high oil solubilization. It was observed that, after the secondary waterflooding process, during the tertiary oil recovery process, individual nonionic surfactant at the same salinity recovered only 7.28% additional oil, whereas the optimized chemical formulation containing both SAIL and nonionic surfactant in an equimolar ratio recovered 16.68% additional oil.

Experimental analysis to design optimum phase type and salinity gradient of Alkaline Surfactant Polymer flooding at low saline reservoir

This paper presents the experimental analysis to find the optimum alkaline-surfactant-polymer (ASP) formula and the effects of salinity gradient suitable for oil reservoirs with low salinity formation water. It has been challenging to obtain high oil recovery when the reservoir salinity is lower than the injection salinity of ASP formulation. This paper carried out phase behavior tests for 28 experiments with 22 kinds of surfactant and subsequent coreflooding for the optimum formula with pre-designed salinity gradient profiling for pre-flush, ASP slug, and polymer drive. The optimum ASP formula from the phase behavior study, i.e., 0.5 wt% Linear alkylbenzene sulfonate (LAS), 2 wt% Diethylene glycol butyl ether (DGBE), and 1 wt% Na2CO3, results in the optimum salinity of 2.8 wt% NaCl with 10 cc/cc solubilization ratio, and the middle phase type III microemulsion occurs in the range of 2.5–3.4 wt% NaCl. The oil recovery implementing this formula and negative salinity gradient, i.e. Winsor type II-III-I for coreflooding experiments are about 75.8% which is better than the other salinity gradients such as Winsor type I-II-I and I-III-I. Excluding high saline pre-flush, the salinity gradient consisted of Winsor type I-II-I and Winsor type I-III-I are able to recover the desirable amount of oil. The results could be applicable on designing the optimal ASP flooding at low salinity formation considering the formulation of surfactants and co-solvents, and the effects of salinity gradients.

An experimental study on the mechanisms of enhancing oil recovery by nanoparticles-assisted surfactant flood

ABSTRACT The central concern of this study is to examine the synergic effects of an anionic surfactant and hydrophilic silica nanoparticles on the improvement of surfactant properties. The assessment of the effect of silica nanoparticles on the emulsification ability of the surfactant solution was performed by the use of both electrical conductivity measurements and phase behavior tests. Accordingly, an optimal chemical formulation for the utilized crude oil was suggested. Optical absorption technique was also employed to evaluate the stability of the optimal solution. The oil recovery experiments were carried out in a transparent glass micromodel saturated with crude oil to monitor some pore-scale displacement events during the simultaneous flow of the optimal solution and the crude oil through porous media. Phase behavior tests indicated that the silica nanoparticles are effective in terms of Interfacial tension (IFT) reduction since they can achieve ultra-low IFT level. The results of conductivity experiments proved the ability of silica nanoparticles to reduce the Critical Micelle Concentration (CMC) of the surfactant. The stability tests proved that the optimal solution is stable for a reasonable time. The multiphase flow experiments revealed that oil recovery increased by about 5% during nanoparticles-assisted surfactant flooding compared with surfactant flood.

Low-IFT Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Oil-Wet Carbonate Reservoirs

Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10−2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.

Microfluidics experimental study in porous media applied for nanosilica/alkaline flooding

This study examines for the first time the impact of silica nanoparticle on alkaline flooding with the aim of enhancing heavy oil recovery. The results show that the presence of silica nanoparticle and its increased concentration in alkaline-nanoparticle solution may cause an interfacial tension whose rates in equal concentrations of nanoparticle and two types of alkali is greater in the case of sodium carbonate than sodium hydroxide. Also, alkaline-nanoparticle solution - as against pure alkaline solution - has a higher capacity for wettability alteration of the medium from oil-wet to water-wet. In fact, the contact angle can vary from 140° to about 60-40° in the alkaline solution and in the presence of the nanoparticle; this value can reach even about 10°. The phase behavior test also indicated that the presence of nanoparticle in an alkaline solution has no effect on the type of emulsion formed (water-in-oil), and only the number of droplets of water and their size will change in oil. The viscosity test also proved that increase of the nanoparticle's concentration could improve fluid viscosity by 0.6 cp in sodium carbonate solution and 3 cp in sodium hydroxide solution. Moreover, the results of the design of experiments and flooding analysis revealed that in alkaline-nanoparticle flooding, alkali concentration plays a more important role in increasing oil recovery than the concentration of the nanoparticle. Also, the presence of nanoparticle in alkaline flooding up to the optimal concentration of nanoparticle leads to an increase in oil extraction. This rise of oil recovery is about 3% in sodium carbonate flooding and about 11% in sodium hydroxide flooding; also, an increase beyond the optimal concentration will reduce the amount of oil recovery. In addition, the presence of silica nanoparticle in alkaline flooding can reduce formation damage if low concentration of nanoparticle is utilized.

Mechanistic Modeling of Nanoparticles-Assisted Surfactant Flood

High interfacial tension (IFT) between oil and water brings about high capillarity leading to high residual oil saturation. Surfactants are employed to reduce IFT or modify wettability and mobilize the trapped oil. This paper aims to investigate the interaction of sodium dodecyl sulfate as a surfactant and two types of silica nanoparticles in different particle sizes for the purpose of enhancing oil recovery. Accordingly, the effect of employed nanoparticles on the critical micelle concentration (CMC) of the surfactant was investigated by the use of electrical conductivity measurements. Phase behavior studies were also carried out to examine the solubilizing ability of the surfactant and nanoparticles assembly. Based on the analysis of solubilization curves, an ultra-low IFT chemical formulation for the target reservoir crude oil was identified and the stability of the optimum solutions was examined through visual observation, optical absorption, and zeta potential measurements. The oil recovery experiments were performed in a quarter five-spot transparent pore network model saturated with crude oil to observe the displacement behavior of the injectant and its influence on oil recovery. Phase behavior tests indicated that the silica nanoparticles smaller in size are more effective in terms of IFT reduction since they can achieve ultra-low IFT level, and the conductivity measurements showed they relatively reduce the CMC of the surfactant. The results of stability tests demonstrated the optimum solutions are stable for more than 1 week. The micromodel experiments displayed that oil recovery increased by 4% during nanoparticles-assisted surfactant flood in comparison with surfactant flood.

Adoption of phase behavior tests and negative salinity gradient concept to optimize Daqing oilfield alkaline-surfactant-polymer flooding

A high performance surfactant formulation was developed using more universally accepted Winsor type phase behavior tests rather than relying primarily on interfacial tension (IFT) measurement for the first time for Daqing oilfield. A surfactant mixture of alkylbenzene sulfonate and fatty alcohol propoxylated ether sulfate was identified which was able to form middle-phase microemulsion with Daqing less reactive crude oil (acid number below 0.1 mg KOH/g crude), lower oil water IFT to ultralow level, and hold desired aqueous stability. Winsor type phase behavior tests at various water oil ratios (WORs) showed the optimum salinity changed slightly from 1.95% to 2% when WOR was increased from 5:5 to 9:1 due to the low reactivity of the Daqing crude oil. To investigate the significance of salinity on Daqing alkaline-surfactant-polymer (ASP) flooding, 4 salinity profiles were designed during coreflooding that corresponded to different types of microemulsions including III–III–I, I–III–I, II–III–I, and III–III–III. For each coreflooding, 0.3 pore volume (PV) of ASP slug with 0.3% total surfactant concentration and 0.2 PV polymer drive was injected. The results demonstrated when negative salinity gradient (3.0%–2.0%–0.5% Na2CO3 in waterflood, ASP, and polymer slugs) was applied, the highest incremental oil recovery of 45.9% original oil in place (OOIP) was achieved. If no Na2CO3 was added in water preflush prior to the injection of ASP slug, the lowest incremental recovery of 32.8% OOIP was observed. For a constant salinity profile at optimum salinity, an intermediate oil recovery (37.4%) was encountered. The measurement of surfactant and Na2CO3 concentrations in the effluents indicated that when negative salinity gradient (II–III–I) was applied, the surfactant loss in the porous media and the oil phase was moderate compared to the two corefloods with III–III–III (highest surfactant loss) emulsion and I–III–I emulsion (lowest surfactant loss). This implied that at optimized salinity profile, the surfactants were more close to hydrophobic-hydrophilic balance during the propagation in the reservoir, which showed the highest potential of increasing oil recovery for the Daqing Oilfield without significantly increasing chemical consumption.

Synthesis and Application of Green Surfactant from Oil Palm Empty Fruit Bunches’s Lignin for Enhanced Oil Recovery Studies

Surfactants are used to reduce the interfacial tension between fluid and oil. In the implementation, the price of surfactant is expensive and limited, so it is necessary to develop surfactants which are cheap and easily obtained. Isolation of lignin from oil palm empty fruit bunches and synthesis of sodium lignosulphonate have been done by using batch method. The optimization of isolation and synthesis method was achieved through this study. The study was conducted on the optimization of lignin isolation, surfactant synthesis and EOR application processes. The optimization of lignin isolation included about size of empty fruit bunch’s, types of solvent, and reaction time. Synthesis of surfactant was done by using proven methods. In EOR test, there are consist of IFT, phase behavior, thermal stability, compatibility tests. Optimum condition for lignin isolation which include optimum empty fruit bunch’s size, reaction temperature, types of solvent and reaction time respectively are 10 mesh, reflux temperature, aquadest, and the reaction was carried out for 3 h. This reaction gave 14.56 % of yield. For sulphonation process, excellent yields and selective products were obtained (90 – 92 %). Finally, for surfactant test conducted up to the feasibility test as an EOR agent. This test was very important for a preliminary test like core flooding and another advanced test. The results demonstrated that 1 % surfactant solution have 0.2 IFT value and also great in compatibility, phase behavior, and thermal stability test.

Ionic liquids for low-tension oil recovery processes: Phase behavior tests

Chemical flooding with surfactants for reducing oil-brine interfacial tensions (IFTs) to mobilize residual oil trapped by capillary forces has a great potential for Enhanced Oil Recovery (EOR). Surface-active ionic liquids (SAILs) constitute a class of surfactants that has recently been proposed for this application. For the first time, SAILs or their blends with an anionic surfactant are studied by determining equilibrium phase behavior for systems of about unit water-oil ratio at various temperatures. The test fluids were model alkane and aromatic oils, NaCl brine, and synthetic hard seawater (SW). Patterns of microemulsions observed are those of classical phase behavior (Winsor I-III-II transition) known to correlate with low IFTs. The two anionic room-temperature SAILs tested were made from common anionic surfactants by substituting imidazolium or phosphonium cations for sodium. These two anionic and two cationic SAILs were found to have little potential for EOR when tested individually. Thus, also tested were blends of an anionic internal olefin sulfonate (IOS) surfactant with one of the anionic SAILs and both cationic SAILs. Most promising for EOR was the anionic/cationic surfactant blend of IOS with [C12mim]Br in SW. A low equilibrium IFT of ∼2·10−3mN/m was measured between n-octane and an aqueous solution having the optimal blend ratio for this system at 25°C.

Statement of Removal

ABSTRACTChemical flooding is an attractive approach to improve both microscopic and macroscopic sweep efficiencies due to the synergistic effects of interfacial tension reduction and mobility control improvement. In this study, the effect of two hydrophilic silica nanoparticles with different particle sizes of 7 and 25 nm on the phase behavior of surfactant solution and rheological behavior of polymer solution was investigated. Oil recovery experiments for the formulations with high viscosity and low interfacial tension were also conducted in a quarter five-spot glass micromodel. Phase behavior tests indicated that interfacial tension decreased dramatically (0.002 mN/m) due to the presence of smaller dispersed silica nanoparticles in surfactant solution. Rheological experiments showed that larger silica nanoparticles improve the viscosity of low molecular-weight polymer solution more than 20 cP in a wide range of shear rates. Oil recovery experiments revealed that dispersed silica nanoparticles in both surfactant and polymer solutions can improve heavy oil recovery significantly.

Predicting microemulsion phase behavior using physics based HLD-NAC equation of state for surfactant flooding

Screening optimum formulation for surfactant flooding is usually time consuming, and correctly modeling microemulsion phase behavior is critical for chemical flooding simulation. This paper extends the physics based Hydrophilic Lipophilic Difference (HLD) Net Average Curvature (NAC) model, and comprehensively demonstrated its capabilities in predicting the optimum formulation and microemulsion phase behavior. This paper uses quantitatively characterized HLD parameters, accurately predicted four optimum surfactant formulations for a target reservoir. This paper measured surfactant head area of extended surfactants and further predicted the equilibrium interfacial tension of four phase behavior test. Comparing to the empirical Hand's rule phase behavior model, the HLD-NAC equation of state shows great advantages in helping formulation design and modeling microemulsion phase behavior. Surfactant flooding sandpack laboratory tests are also interpreted by UTCHEM chemical flooding simulator coupled with the HLD-NAC phase behavior model. The results indicate the significance of HLD-NAC equation of state in not only shorten the surfactant screening processes for formulators, but also predicting microemulsion phase behavior based on surfactant structure. A compositional reservoir simulator with such an equation of state will increase its predictability and hence help with the design of surfactant formulation.

Synergism and Performance for Systems Containing Binary Mixtures of Anionic/Cationic Surfactants for Enhanced Oil Recovery

AbstractThe surfactant structure–performance relationship and application properties in enhanced oil recovery (EOR) for binary mixtures of anionic and cationic surfactants are presented and discussed. A polyoxyethylene ether carboxylate anionic surfactant was blended with a quaternary ammonium chloride cationic surfactant and tested for a high‐temperature, low‐salinity, and high‐hardness condition as found in an oil reservoir. These mixtures were tailored by phase behavior tests to form optimal microemulsions with normal octane (n‐C8) and crude oil having an API gravity of 48.05°. The ethoxy number of the polyoxyethylene carboxylate anionic surfactant and the chain length of the cationic surfactant were tuned to find an optimal surfactant blend. Interfacial tensions with n‐C8 and with crude oil were measured. Synergism between anionic and cationic surfactants was indicated by surface tension measurement, CMC determination, calculation of surface excess concentrations and area per molecule of individual surfactants and their mixtures. Molecular interactions of anionic and cationic surfactants in mixed monolayers and aggregates were calculated by using regular solution theory to find molecular interaction parameters βσ and βM. Morphologies of surfactant solutions were studied by cryogenic TEM. The use of binary mixtures of anionic/cationic surfactants significantly broadens the scope of application for conventional chemical EOR methods.

Investigation of synergy between nanoparticle and surfactant in stabilizing oil-in-water emulsions for improved heavy oil recovery

This study presents an experimental study, including phase behavior tests, rheology studies, core flooding and microscopic visualization tests for investigating the synergistic effect of nanoparticles and surfactants in stabilizing oil-in-water (O/W) emulsions for improved heavy oil recovery. The emulsion stability and rheology studies show that the addition of nanoparticles can not only improve the stability of the emulsion, but also greatly increase the bulk viscosity of emulsion. The core flooding conducted with the nanoparticle-surfactant stabilized emulsion show a marked improvement in oil recovery over the surfactant-stabilized emulsions. The tertiary oil recovery can reach over 40% of the initial oil in place (IOIP) for crude oil with the viscosity of 350 mPa s at 50 °C. The micromodel tests indicate that the nanoparticles can thicken the emulsion to the desirable mobility, which can damp the viscous fingering phenomena to dramatically improve sweep efficiency. In addition, the heavy oil can be emulsified into the water phase to form oil-in-water emulsions with the aid of the surfactant. These results demonstrate that the nanoparticle-surfactant stabilized emulsion has a great potential for enhanced oil recovery in waterflooded heavy oil reservoirs.

Pembuatan Surfaktan Berbahan Dasar Jerami Padi

Indonesia's oil production has declined due to the low level of production of oil wells that have been old. Extraction of oil from the wells can be enhanced by the injection of surfactant. Potential raw material for the manufacture of surfactants, especially the waste material so that lower-priced. This material include lignocellulosic materials and plantation agricultural waste. Rice straw is one of them. This study aims to make surfactants from rice straw. The axpetriment was conducted through the steps of: (1) preparation of raw materials, (2) delignification and isolation of lignin, (3) sulfonation of lignin using NaHSO 3 . Delignification of rice straw held at a temperature of 166 o C and a pressure of 1.2 atm. Sulfonated of lignin conducted at a temperature of 90-95°C and pH 7. Lignin and sodium lignosulfonate tested using FTIR and gravimetric. The results show at 2.5 g lignin, weight percent of NaHSO 3 60% of the weight of lignin, pH 7, temperature 90-95 ° C for 4 hour reaction obtained 2,5509 g of sodium lignosulfonate (SLS). Sodium lignosulfonate is soluble in water. Sodium lignosulfonate phase behavior test using crude oil from Oil Drilling Tanjung, South Kalimantan, at the surfactant concentration 3000 and 5000 ppm result that the type of emulsion is water in oil. So that this surfactant not suggested for EOR.

Surfactant–polymer flooding characteristics for heavy oil recovery with varying injection volumes of surfactant and polymer

A laboratory surfactant–polymer flooding experiment was performed to improve the recovery of heavy oil. The surfactant phase behavior tests and a series of flooding experiments were conducted to find the best and optimal additional oil recovery condition after water flooding using a surfactant–polymer slug. Through the phase behavior tests, it was found that a combination of a 2.5 wt% surfactant solution with 1.5 wt% of salinity was the optimal for injection experiments. In the surfactant–polymer flooding, the combination of injected volume which was 0.6 pore volume (PV) of combined slugs of surfactant and polymer was varied in each test. The additional oil recovery obtained by the surfactant–polymer flooding after water flooding ranged from 13.6% to 28.6%. With the same total volume of the surfactant and polymer, the oil recovery decreased as the volume of polymer increased when the volume of polymer was lesser than the volume of surfactant; however, the oil recovery increased with increase in the volume of the polymer when the volume of the polymer was greater than or equal to the volume of the surfactant. The highest oil recovery of 28.6% was obtained by injecting 0.1 PV of surfactant and 0.5 PV of polymer.

Surfactant flooding characteristics of dodecyl alkyl sulfate for enhanced oil recovery

Surfactant-enhanced oil recovery is a type of enhanced oil recovery (EOR), a method to produce residual oil by injecting surfactant solution into the reservoir. The application of surfactant EOR requires knowledge of the phase behavior for more efficient production of residual oil.In this study, the relationship between dodecyl alkyl sulfate and some specific crude oils was examined through phase behavior test. It was found that the branched surfactant was more effective than the linear surfactant. The system was stable at salinities <3wt%. On adding a small amount of co-surfactant, the emulsion activity was increased.The gravity drainage flooding test (GDFT) was performed to determine the potential of dodecyl alkyl sulfate to produce residual oil in porous media. It was found that the solution could be flooded at temperatures of 60°C or higher. In the core flooding test, injecting one pore volume of 2wt% surfactant solution with 3wt% salinity produced 26.6% more oil after water flood. With the addition of only 0.01wt% co-surfactant, oil production increased by 1.6%. Contrary to the phase behavior test, the linear surfactant produced 1.3% more oil than the branched surfactant in the core flooding test.