Toward A Mechanistic Understanding of Re-Infiltration in Naturally Fractured Reservoirs with Surfactant-Aided Gravity Drainage Process

Surfactant-aided gravity drainage is an improved oil recovery technique for water-invaded zone in fractured carbonate reservoirs, which are mostly oil-wet or mixed-wet rocks. The re-infiltration mechanism in water-invaded zone has a considerable effect on oil vertical movement in gravity drainage processes. In this work, a mechanistic understanding of re-infiltration in surfactant-aided gravity drainage, in comparison to oil–water gravity drainage is presented using an experimentally and numerically validated model. A column model is constructed from three matrix blocks. These blocks are separated from each other by horizontal fractures. A storage tank is considered on top of the model to store depleted oil from matrix blocks. The stacked-blocks model for re-infiltration is validated and verified to simulate water and chemical flooding using a mesh independency study and experimental flooding data in a composite core experiment. Using this model, several analyses are performed to investigate effects of rock and fluid properties, rock saturation functions, wettability alteration, surfactant adsorption, and capillary continuity on re-infiltration.     

Enhanced Wettability Alteration by Surfactants with Multiple Hydrophilic Moieties

The main production mechanism during water flooding of naturally fractured oil reservoirs is the spontaneous imbibition of water into matrix blocks and resultant displacement of oil into the fracture system. This is an efficient recovery process when the matrix is strongly water-wet. However, in mixed- to oil-wet reservoirs, secondary recovery from water flooding is often poor. Oil production can be improved by dissolving low concentrations of surfactants in the injected water. The surfactant alters the wettability of the reservoir rock, enhancing the spontaneous imbibition process. Our previous study revealed that the two main mechanisms responsible for the wettability alteration are ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface. Based on the superior performance of surfactin, an anionic biosurfactant with two charged groups on the hydrophilic head, it was hypothesized that the wettability alteration process might be further improved through the use of dimeric or gemini surfactants, which have two hydrophilic head groups and two hydrophobic tails. We believe that when ion-pair formation is the dominant wettability alteration mechanism, wettability alteration in oil-wet cores can be improved by increasing the charge density on the head group(s) of the surfactant molecule since the ion-pair formation is driven by electrostatic interactions. At a concentration of 1.0 mmol L⁻¹ a representative anionic gemini surfactant showed oil recoveries of up to 49% original oil-in-place (OOIP) from oil-wet sandstone cores, compared to 6 and 27% for sodium laureth sulfate and surfactin, respectively. These observations are consistent with our hypothesis.     

Surfactant Enhanced Oil Recovery in a High Temperature and High Salinity Carbonate Reservoir

The goal of this work was to find an effective surfactant system for enhanced oil recovery after water injection substituting for oil at a vuggy fractured reservoir with a high temperature and high salinity (220,000 mg/L). Four types of surfactants with concentrations (less than 0.2 %) were screened. Washing oil experiments were conducted in Amott cells. A surfactant system was established by mixing a surfactant with best ultimate recovery and one with best recovery rate. The optimized surfactant system could recover 50 % of remaining oil. To study the mechanism of enhanced oil recovery after water injection substituting oil, interfacial tension (IFT) and contact angle were measured. Experimental results showed that surfactants with good washing ability had low IFT, but surfactants with low IFT may not have a good washing ability. IFT had no obvious relationship with the increased oil recovery or washing ability. The optimized system could not alter carbonate to decrease the oil‐wetting capability. Though octadecyl trimethyl ammonium chloride had a good ability wet the carbonate with water, it could not recover much oil. Therefore, except for interfacial tension and wettability alteration, there must be other parameters dominating oil recovery after water injection substituting for oil.     

Surfactant-Induced Wettability Alteration of Oil-Wet Sandstone Surface: Mechanisms and Its Effect on Oil Recovery

Different analytical methods were utilized to investigate the mechanisms for wettability alteration of oil-wet sandstone surfaces induced by different surfactants and the effect of reservoir wettability on oil recovery. The cationic surfactant cetyltrimethylammonium bromide (CTAB) is more effective than the nonionic surfactant octylphenol ethoxylate (TX-100) and the anionic surfactant sodium laureth sulfate (POE(1)) in altering the wettability of oil-wet sandstone surfaces. The cationic surfactant CTAB was able to desorb negatively charged carboxylates of crude oil from the solid surface in an irreversible way by the formation of ion pairs. For the nonionic surfactant TX-100 and the anionic surfactant POE(1), the wettability of oil-wet sandstone surfaces is changed by the adsorption of surfactants on the solid surface. The different surfactants were added into water to vary the core surface wettability, while maintaining a constant interfacial tension. The more water-wet core showed a higher oil recovery by spontaneous imbibition. The neutral wetting micromodel showed the highest oil recovery by waterflooding and the oil-wet model showed the maximum residual oil saturation among all the models.     

Laboratory Studies to Determine Suitable Chemicals to Improve Oil Recovery from Garzan Oil Field

Garzan oil field is located at the south east of Turkey. It is a mature oil field and the reservoir is fractured carbonate reservoir. After producing about 1% original oil in place (OOIP) reservoir pressure started to decline. Waterflooding was started in order to support reservoir pressure and also to enhance oil production in 1960. Waterflooding improved the oil recovery but after years of flooding water breakthrough at the production wells was observed. This increased the water/oil ratio at the production wells. In order to enhance oil recovery again different techniques were investigated. Chemical enhanced oil recovery (EOR) methods are gaining attention all over the world for oil recovery. Surfactant injection is an effective way for interfacial tension (IFT) reduction and wettability reversal. In this study, 31 different types of chemicals were studied to specify the effects on oil production. This paper presents solubility of surfactants in brine, IFT and contact angle measurements, imbibition tests, and lastly core flooding experiments. Most of the chemicals were incompatible with Garzan formation water, which has high divalent ion concentration. In this case, the usage of 2-propanol as co-surfactant yielded successful results for stability of the selected chemical solutions. The results of the wettability test indicated that both tested cationic and anionic surfactants altered the wettability of the carbonate rock from oil-wet to intermediate-wet. The maximum oil recovery by imbibition test was reached when core was exposed 1-ethly ionic liquid after imbibition in formation water. Also, after core flooding test, it is concluded that considerable amount of oil can be recovered from Garzan reservoir by waterflooding alone if adverse effects of natural fractures could be eliminated.     

Evaluation of the polymer hydrogels as a potential relative permeability modifier

Excessive water production poses a significant challenge in the oil industry, especially in Pre-salt carbonate reservoirs, leading to reduced oil recovery, corrosion, and well abandonment. We explore the potential of polymeric preformed particle gels (PPGs) as innovative relative permeability modifiers (RPMs) for carbonate reservoirs. RPMs involve applying polymeric hydrogels to alter reservoir wettability, reducing water flow while enhancing oil productivity. PPGs offer a promising surface-based production alternative with improved control and minimized formation damage compared to traditional in-situ gels. We conducted crosslinking experiments using poly(acrylamide-acrylic acid-2-methyl propane sulfonate) terpolymer (AM-AA-AMPS) and aluminum (III) ions, assessing their impact on hydrogel properties. We also investigated the swelling behavior of these hydrogels and their interactions with rock samples. Results showed that crosslinking significantly affects PPG viscoelastic properties and swelling behavior. Adsorption tests revealed the formation of a polymeric film on rock surfaces, potentially altering wettability. Contact angle measurements demonstrated PPGs' ability to shift rock wettability, particularly in carbonate samples, from strongly oil-wet to water-wet conditions. This study underscores PPGs' potential as RPMs, offering valuable insights into improving oil extraction efficiency and addressing water production challenges in the industry.     

Wettability reversal of reservoir rock surface through surfactant stabilized microemulsion

In the process of the tertiary recovery of oil and gas resources, it is necessary to use external fluids to displace the crude oil in the reservoir. Whether the crude oil on the surface of the rock can be effectively displaced and the wettability of the rock can be changed to avoid re-adsorption by the crude oil is directly related to the level of oil recovery. Therefore, it is critical to study the cleaning and wettability reversal of reservoir rock surface. Because microemulsions have outstanding performance in changing the wettability of rocks and solubilizing crude oil, this paper uses cetyl trimethyl ammonium bromide (CTAB) as a surfactant and n-butanol as a co-surfactant to prepare microemulsions. The performance of microemulsions with different microstructures on the cleaning and wettability changes of crude oil on the rock surface were studied. The results show that the water-in-oil (W/O) microemulsion has good cleaning efficiency, and the oil removal rate on the sandstone core surface can reach 79.65%. In terms of changing the wettability of the rock surface, W/O, bi-continuous phase (B.C.) and oil-in-water (O/W) microemulsions can change the core surface from lipophilic to hydrophilic. And the effects of the B.C. and O/W microemulsions are more obvious. The microemulsion system that was prepared based on cationic surfactants has a good application prospect in changing the wettability of the reservoir and cleaning the adsorbed crude oil.     

Separation of oil contaminants by surfactant-aided foam fractionation

The separation of oily contaminants out of aqueous/non-aqueous phases using foam fractionation with a surfactant was investigated. In the separation of the light oil (hexadecane), the eluted amount of oil and the o/w (oil/water) ratio increased with the weight percentage of SDS (sodium dodecyl sulfate); and the ratio actually remained the same above the CMC (critical micelle concentration) point (0.23 wt% of SDS). Most of the oil was eluted even at 49:1 initial o/w ratio with the surfactant. For the heavy oil (carbon tetrachloride), the eluted o/w ratio and the oil recovery had maxima at 0.05 and 0.1 wt% of SDS solution, respectively, even though the overall recovery of 20–30 % was much lower than that of 80–100 % in the light oil. It was speculated that emulsion formation might affect oil entrapment in the foams. Higher gas flow rates, in general, increased the oil recovery, but did not increase the o/w ratio in the effluents.     

Stabilization of natural gas foams using different surfactants at high pressure and high temperature conditions

Natural gas foam can be used for mobility control and channel blocking during natural gas injection for enhanced oil recovery, in which stable foams need to be used at high reservoir temperature, high pressure and high water salinity conditions in field applications. In this study, the performance of methane (CH₄) foams stabilized by different types of surfactants was tested using a high pressure and high temperature foam meter for surfactant screening and selection, including anionic surfactant (sodium dodecyl sulfate), non-anionic surfactant (alkyl polyglycoside), zwitterionic surfactant (dodecyl dimethyl betaine) and cationic surfactant (dodecyl trimethyl ammonium chloride), and the results show that CH₄-SDS foam has much better performance than that of the other three surfactants. The influences of gas types (CH₄, N₂, and CO₂), surfactant concentration, temperature (up to 110°C), pressure (up to 12.0 MPa), and the presence of polymers as foam stabilizer on foam performance was also evaluated using SDS surfactant. The experimental results show that the stability of CH₄ foam is better than that of CO₂ foam, while N₂ foam is the most stable, and CO₂ foam has the largest foam volume, which can be attributed to the strong interactions between CO₂ molecules with H₂O. The foaming ability and foam stability increase with the increase of the SDS concentration up to 1.0 wt% (0.035 mol/L), but a further increase of the surfactant concentration has a negative effect. The high temperature can greatly reduce the stability of CH₄-SDS foam, while the foaming ability and foam stability can be significantly enhanced at high pressure. The addition of a small amount of polyacrylamide as a foam stabilizer can significantly increase the viscosity of the bulk solution and improve the foam stability, and the higher the molecular weight of the polymer, the higher viscosity of the foam liquid film, the better foam performance.     

非离子氟碳表面活性剂与重烷基苯磺酸钠复配驱油剂的研究

研究了氟碳intechem-01表面活性剂(FC-01)/重烷基苯磺酸钠(HABS)复配驱油体系的性能,以金属筛网洗油率和静态驱油率、界面张力、与注入水和模拟地层水的配伍性为考察指标。结果表明,复配体系的最佳配比为氟碳intechem-01表面活性剂浓度为0.08%,重烷基苯磺酸钠质量浓度为0.10%,碳酸钠质量浓度为0.20%,碳酸氢钠质量浓度为0.20%。复配体系与定边油田的原油形成较低界面张力,驱油率显著提高,且与定边油田采油注入水和模拟地层水有良好的配伍性。     

A new surfactant wettability alteration model for reservoir simulators

Surfactants enhance oil recovery in naturally-fractured oil-wet rocks by wettability alteration and interfacial tension reduction. The oil-wet state is ascribed to the adsorption of soap on the rock surface. Soaps are the dissociated forms of carboxylic acids in the crude oil, that is, carboxylate surfactants. This paper describes a new mechanistic surfactant wettability alteration model that was developed for and implemented in a reservoir simulator. The model captures the geochemical reactions of acid/soap, the formation of mixed micelles, Henry's law adsorption, and the formation of cationic surfactant-anionic soap ion-pairs. A new wettability scaling factor is used to interpolate between the oil-wet and water-wet relative permeability and capillary pressure curves. The new model also accounts for the effect of salinity and pH, so it should also be useful for modeling low-salinity flooding without surfactant. Previous surfactant wettability alteration models ignored the underlying mechanisms and were not predictive. Simulations of both static and dynamic imbibition were performed to better understand the key surfactant parameters and the dynamics of wettability alteration, microemulsion phase behavior, and interfacial tension reduction on oil recovery. Optimizing surfactant formulations for wettability alteration is discussed.     

Study on Streptomycin Sulfate Recovery by Batch Foam Separation

The feasibility of foam separation as a technique was assessed for the recovery of streptomycin sulfate from the waste solution by using an anionic surfactant sodium dodecyl sulfate (SDS). The experimental parameters examined were SDS concentration, superficial gas velocity, initial pH, and liquid loading volume. The results showed that sodium dodecyl sulfate as the surfactant for foam separation had good foaming quality and could effectively concentrate streptomycin sulfate of the aqueous solution by technology of foam separation. The enrichment ratio and the recovery rate of streptomycin sulfate were 4.0 and 85%, respectively under the best operating conditions of sodium dodecyl sulfate concentration 0.4 g/L, superficial gas velocity 300 mL/min, liquid loading volume 300 mL and initial pH 6.0 when streptomycin sulfate concentration was 0.5 g/L.     

十二烷基苯磺酸钠与非离子氟碳表面活性剂复合驱油剂的研究

研究了十二烷基苯磺酸钠(SDBS)/氟碳Intechem-01表面活性剂(FC-01)复合驱油剂的性能,以驱油率、界面张力、与注入水和模拟地层水的配伍性为考察指标,正交实验结果表明,氟碳Intechem-01表面活性剂的质量分数为0.05%,十二烷基苯磺酸钠的质量分数为0.15%,碳酸钠、碳酸氢钠的质量分数都为0.25%时,复配体系的效果较好,且复配体系与定边油田采油注入水和模拟地层水有良好的配伍性。     

耐油抗醇泡排剂的研究

针对气井含油、含醇情况,以十二烷基硫酸钠(SDS)、芥酸酰胺丙基甜菜碱(EAB)为主成分,特种表面活性剂氟碳型FC-117为稳定剂,添加剂PVG,获得SDS、EAB、FC-118、PVG的最佳配比为2:1:0.04:0.04,从而研制出独特的抗油、抗盐、抗乙二醇复配泡排剂,与现场常用泡排剂UT-6、UT-11C、UT-10B进行对比。实验表明:复配泡排剂不仅具有优异的抗凝析油、抗甲醇能力,且具有良好的抗温、抗盐等常规泡排剂所具备的优势。     

Mechanical and processing requirements for a shock mitigating phenolic foam

A high load-bearing shock-mitigating phenolic foam was developed to meet specific compression-deflection and gas permeability requirements. It was required that the foam display an almost constant compressive stress within the limits of 50–68 psi at strains ranging from 10% to 60%. Furthermore, the foam had to possess a highly open-celled structure so that its resistance to gas flow would be minimal. These properties were obtained from a chemical formulation utilizing a combination of two phenolic resins, a phosphoric-sulfuric acid catalyst system, a surfactant combination that included both a hydrophilic and a lipophilic surfactant, and a fluorocarbon blowing agent.     

Determination of dynamic contact angles in solid–liquid–liquid systems using the Wilhelmy plate apparatus

The purpose of this work was to carry out a systematic study of the effects of brine composition and rock mineralogy on rock-oil-brine interactions taking place in petroleum reservoirs. These terms are generally lumped into a single term called wettability in petroleum engineering. The extent of wetting of the rock surface by water or oil depends on the dynamic contact angles measured in such a mode as to enable movements of the three-phase contact line. The Wilhelmy plate technique has been used in this study to measure adhesion tension (which is the product of interfacial tension and cosine of the contact angle) at the solid-liquid interface. The water-advancing and water-receding contact angles have been calculated from the adhesion tensions by making independent measurements of the liquid-liquid interfacial tensions using a du Noüy ring tensiometer. The water-advancing and receding angles have been measured in this study for pure hydrocarbons against synthetic brines of different concentrations. Polished surfaces of glass slides and dolomite have been used to simulate the reservoir rock surfaces. A nonionic surfactant (ethoxy alcohol), which is being used in Yates reservoir in West Texas for enhancing oil recovery, was used to quantify its wettability effects. The results of the systematic experimental investigation of the effects of practical variables on wettability are presented. It is found that interactions between surface-active agents at the interface of two liquids have an effect on wettability alteration. The composition and concentrations of different organic and inorganic chemical species have a major effect in making a reservoir oil-wet or water-wet.     

Wettability alteration of oil-wet carbonate rocks by chitosan derivatives for application in enhanced oil recovery

The increasing demand for oil and the fast decline of crude oil production from mature fields encourages the development of new enhanced oil recovery (EOR) technologies. In this work, trimethyl chitosan (TMC) and trimethyl chitosan hydrophobized with myristoyl chloride (TMC-C14) are synthesized, and their wettability modification capacity of oil-wet carbonate rocks is evaluated through contact angle measurements, atomic force microscopy, and Raman spectroscopy. Their interaction with asphaltene molecules was evaluated through UV–Vis spectroscopy. Transport behavior and oil displacement capacity were investigated in an unconsolidated porous medium. Results show that they can modify the wettability of oil-wet carbonate rocks, turning them water-wet, promoting oil displacement increases by 25% for TMC, and 16% for TMC-C14.TMC shows a better performance for wettability alteration than TMC-C14, confirming the hypothesis that the higher the positive charge density on the polymeric surfactant structure, the more efficient will be the system as a wettability modifier and as an EOR agent.     

表面活性剂驱室内评价实验研究

三次采油是油藏水驱开发之后提高原油采收率的重要途径,表面活性剂驱是三次采油技术中的重要组成部分,对提高高温高盐油藏采收率起到了较好的效果;表面活性剂通过降低油水界面张力或改变储层岩石润湿性来提高洗油效率,表面活性剂溶液的浓度、注入倍数、注入时机直接影响原油最终采收率,结合实际区块岩石,通过室内表面活性剂驱替实验优选出表面活性剂以及相应的注入参数,应用于该油田区块,原油递减趋势明显变缓,增油效果很好。     

Emerging applications of nanomaterials in chemical enhanced oil recovery:Progress and perspective

In enhanced oil recovery, different chemical methods utilization improves hydrocarbon recovery due to their fascinating abilities to alter some critical parameters in porous media, such as mobility control, the interaction between fluid to fluid, and fluid to rock surface. For decades the use of surfactant and polymer flooding has been used as tertiary recovery methods. In the current research, the inclusion of nanomaterials in enhanced oil recovery injection fluids solely or in the presence of other chemicals has got colossal interest. The emphasis of this review is on the applicability of nanofluids in the chemical enhanced oil recovery. The responsible mechanisms are an increment in the viscosity of injection fluid, decrement in oil viscosity, reduction in interfacial and surface tension, and alteration of wettability in the rock formation. In this review, important parameters are presented,which may affect the desired behavior of nanoparticles, and the drawbacks of nanofluid and polymer flooding and the need for a combination of nanoparticles with the polymer are discussed. Due to the lack of literature in defining the mechanism of nanofluid in a reservoir, this paper covers majorly all the previous work done on the application of nanoparticles in chemical enhanced oil recovery at home conditions. Finally, the problems associated with the nano-enhanced oil recovery are outlined, and the research gap is identified, which must be addressed to implement polymeric nanofluids in chemical enhanced oil recovery.     

Complexation of Surfactant/β‐Cyclodextrin to Inhibit Surfactant Adsorption onto Sand,Kaolin, and Shale for Applications in Enhanced Oil Recovery Processes. Part I: Static Adsorption Analysis

Surfactant adsorption onto solid surfaces is a major issue during surfactant flooding in enhanced oil recovery applications; it decreases the effectiveness of the chemical injection making the process uneconomical. Therefore, it was hypothesized that the adsorption of surfactant onto solid surfaces could be inhibited using a surfactant delivery system based on the complexation between the hydrophobic tail of anionic surfactants and β‐cyclodextrin (β‐CD). Proton nuclear magnetic resonance spectroscopy was used to confirm the complexation of sodium dodecyl sulfate (SDS)/β‐CD. Surface tension analysis was used to establish the stoichiometry of the complexation and the binding constant (K_a). Static adsorption testing was applied to determine the adsorption of surfactant onto different solids (sandstone, shale, and kaolinite). The release of the surfactant from the β‐CD cavity was qualitatively evaluated through bottle testing. The formation of the inclusion complex SDS/β‐CD with a 1:1 stoichiometry was confirmed. The K_a of the complexations increases as salinity and hardness concentration increases. The encapsulation of the surfactant into the β‐CD cavity decreases the adsorption of surfactant onto solid surfaces up to 79 %. Qualitative observations indicate that in the presence of solid adsorbents partially saturated with crude oil, the β‐CD cavity releases surfactant molecules, which migrate towards the oil–water interface.