Insights into Enhanced Oil Recovery by Polymer-Viscosity Reducing Surfactant Combination Flooding in Conventional Heavy Oil Reservoir

Polymer flooding has a significant potential to enhance oil recovery in a light oil reservoir. However, for polymer flooding in a conventional heavy oil reservoir, due to unfavorable mobility ratio between water and oil, the improvement of sweep efficiency is limited, resulting in a low incremental oil recovery and failure to achieve high-efficiency development for polymer flooding in a conventional heavy oil reservoir. Inspired by the EOR mechanisms of the surfactant-polymer (SP) flooding process, the polymer-viscosity reducing surfactant flooding (P-VRSF) system was proposed to enhance conventional heavy oil recovery. Thus, to gain an insight into enhancing oil recovery by P-VRSF in a conventional heavy oil reservoir, the viscosity property, oil-water interfacial tension property, and oil viscosity reduction property were investigated. A series of parallel sand pack experiments were conducted to investigate enhanced oil recovery ability of polymer flooding and P-VRSF in a heterogeneous reservoir. Then, the 2D micromodel flooding experiments were conducted to investigate the EOR mechanism from porous media to pore level. Results demonstrated that polymer could increase the viscosity of injection water and improve the sweep efficiency. The emulsifying stability of surfactant with ultralow IFT (10-3 mN/m) was worse than that of the surfactant with higher IFT (10-2 mN/m). The viscosity reduction rate of the surfactant with higher IFT was higher than 80% at different oil-water volume ratios. The incremental oi recovery of P-VRSF was higher than that of polymer flooding. Moreover, the polymer-viscosity reducing surfactant with higher IFT could have higher incremental oil recovery. The 2D micromodel flooding results showed that the swept area of polymer flooding and P-VRSF was larger than that of water flooding. Moreover, the swept area of the surfactant with good emulsifying stability was larger than that of the surfactant with ultralow IFT. These findings could provide insights into enhancing oil recovery by P-VRSF in the conventional heavy oil reservoir.

Pore-scale simulation of water/oil displacement in a water-wet channel

Water/oil flow characteristics in a water-wet capillary were simulated at the pore scale to increase our understanding on immiscible flow and enhanced oil recovery. Volume of fluid method was used to capture the interface between oil and water and a pore-throat connecting structure was established to investigate the effects of viscosity, interfacial tension (IFT) and capillary number (Ca). The results show that during a water displacement process, an initial continuous oil phase can be snapped off in the water-wet pore due to the capillary effect. By altering the viscosity of the displacing fluid and the IFT between the wetting and non-wetting phases, the snapped-off phenomenon can be eliminated or reduced during the displacement. A stable displacement can be obtained under high Ca number conditions. Different displacement effects can be obtained at the same Ca number due to its significant influence on the flow state, i.e., snapped-off flow, transient flow and stable flow, and ultralow IFT alone would not ensure a very high recovery rate due to the fingering flow occurrence. A flow chart relating flow states and the corresponding oil recovery factor is established.

Ultralow-Interfacial-Tension Foam-Injection Strategy in High-Temperature Ultrahigh-Salinity Fractured Oil-Wet Carbonate Reservoirs

Summary Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oil–wet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injection–strategy investigation of ultralow–interfacial–tension (IFT) foam in a high–temperature (greater than 80°C), ultrahigh–formation–salinity [greater than 23% total dissolved solids (TDS)] fractured oil–wet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontal–dilution map was created to simulate frontal–displacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulk–foam tests were also conducted to study the salinity–gradient effect on the performance of ultralow–IFT foam. Ultralow–IFT foam–injection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oil–wet core systems with initial oil/brine two–phase saturation. The representative fractured system included a well–defined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10−2 to 10−3 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralow–IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow–IFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oil–wet systems because of the selective diversion of ultralow–IFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high–salinity brine flowing back to the fracture ahead of the front. The crossflow of oil/high–salinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralow–IFT foam process to ensure good foam propagation and high oil–recovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralow–IFT foam in high–temperature, ultrahigh–salinity fractured oil–wet carbonate reservoirs and investigated the injection strategy to enhance the low–IFT foam performance. The ultralow–IFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobility–control agent in a fractured system for better sweep efficiency.

Modifikasi SLS dengan epoksida dari asam oleat dan hidrogen peroksida untuk meningkatkan kualitas surfaktan pada EOR

SLS modification using epoxyde from oleat acid and hydrogen peroxyde to improve the quality of surfactant in EORSurfactant is one of the compounds used in Enhanced Oil Recovery (EOR) which function is to enhance the oil production. One of the surfactants widely used is Sodium Ligno Sulfonat (SLS) due to its high degradability. However the modification with another compound is still needed in orderto decrease its Inter Facial Tension (IFT) until reach the ultralow IFT(±10-3 mN/m). One of the chemical compounds used to modify the surfactant is epoxidebecause it has reactive oxirane ring. The addition of oleic epoxide will increase solubility of surfactant in oil so it brings more stable microemulsion. Epoxidation of oleic acid was carried out with peroxyacetic acid that was generated insitu from aqueous hydrogen peroxide and glacial acetic acid. The modification of SLS was then done by adding the epoxide in various conversion resulted from epoxidation. The experiment was investigated at temperature, ratio of epoxide to SLS and reaction time of 70oC, 1:2 and 1 hour, respectively. The modified product were then measured their IFTat temperature of 30-60oC and tested the stability of microemulsion based on time of formation of microemulsion up back in its original state. The present study revealed that epoxides has capability to decrease IFT. The results of experiment shows that the lowest IFT is modification of epoxide with the conversion of 10% as 3,7 x10-3 mN/m and has most excellent stability with time 113 minutes.Keywords: epoxide, Sodium Ligno Sulfonat (SLS), microemulsion, surfactant, EOR AbstrakSurfaktan adalah salah satu bahan kimia yang digunakan dalam Enhanced Oil Recovery (EOR) untuk meningkatkan produksi minyak. Salah satu jenis surfaktan yang banyak digunakan adalah Sodium Ligno Sulfonat (SLS) karena mudah didegradasi limbahnya. Namun modifikasi dengan senyawa lain masih perlu dilakukan untuk menurunkan tegangan antarmuka atau Inter Facial Tension (IFT) hingga mencapai ultralow IFT (±10-3 mN/m). Salah satu bahan kimia yang dapat digunakan untuk modifikasi surfaktan adalah epoksida karena memiliki cincin oksiren yang reaktif. Penambahan epoksi oleat ini akan meningkatkan kelarutan surfaktan dalam minyak sehingga didapatkan mikroemulsi yang lebih stabil. Modifikasi SLS dibuat dengan menambahkan epoksida dengan variasi konversi yang dihasilkan dari proses epoksidasi. Percobaan dilakukan pada temperatur 70oC, rasio perbandingan epoksida:SLS adalah 1:2 dengan waktu reaksi 1 jam. IFT produk modifikasi diukur pada temperatur 30-60oC dan diuji kestabilan mikroemulsinya berdasarkan waktu pembentukan mikroemulsi sampai kembali pada keadaan semula. Dari penelitian didapatkan bahwa epoksida dapat menurunkan IFT. IFT paling rendah dihasilkan dari modifikasi epoksida dengan konversi 10%, yaitu 3,7 x10-3 mN/m dan memiliki kestabilan paling baik dengan waktu emulsi 113 menit.Kata kunci: epoksida, Sodium Ligno Sulfonat (SLS), mikroemulsi, surfaktan, EOR

THE EFFECT OF ANIONIC AND NONIONIC CO-SURFACTANT FOR IMPROVING SOLUBILITY OF POLYOXY-BASED SURFACTANT FOR CHEMICAL FLOODING

Surfactant is one of the crucial components for chemical flooding to recover oil production in the tertiary stage of the low primary and secondary recovery oil field. The mechanism is performed by decreasing the interfacial tension of oil and water which enhancing microscopic displacement efficiency. The present study showed the effect of commercial nonionic and anionic co-surfactant Tergitol, Teepol, Merpol, and SDS on the solubility of polyoxy based-surfactant (POS) through compatibility analysis, fi ltration ratio analysis, and IFT measurement. Whereas the presence of Teepol and Merpol did not change the original compatibility of POS in all concentrations, the addition of co-surfactant Tergitol and SDS were able to alter the solubility of POS from milky solution into a clear transparent solution. However, the most important characteristic of surfactant for reducing the IFT of oil-water was affected by the addition of co-surfactant which does not have sufficient IFT to release the trapped oil in the reservoir. Thus, exposing the mixture of surfactant and co-surfactant for a few days at the reservoir temperature has changed the visual appearance of solution from a clear transparent solution into a milky suspension, indicating the occurrence of thermal degradation. These results suggest that the addition of anionic and nonionic co-surfactant improved the solubility of POS, but increased the IFT. It can be concluded that the compatibility of POS in the brine can then be achieved by mixing it with suitable co-surfactant. Screening the other co-surfactant is required to obtain the one that enhances the compatibility as well as maintaining the ultralow IFT of POS.

Scaling of Low-Interfacial-Tension Imbibition in Oil-Wet Carbonates

Summary Primary and secondary oil recovery from naturally fractured oil-wet carbonate reservoirs is very low. Enhanced oil recovery (EOR) from these reservoirs by use of surfactants to alter the wettability and reduce the interfacial tension (IFT) has been extensively studied for many years, but there are still many questions regarding the process mechanisms, surfactant selection and testing, experimental design, and, most importantly, how to scale up the laboratory results to the field. Therefore, the primary objective of this study was to determine the effect of scale on the oil recovery from cores with different dimensions under low-IFT conditions. There was a particular need to perform experiments by use of cores with larger horizontal dimensions because nearly all previous experiments have been performed in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static-imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the produced emulsion. We used microemulsion-phase-behavior tests to develop surfactant formulations used in this study. These surfactants gave ultralow IFT at optimum salinity and good aqueous stability. Although we used ultralow-IFT (approximately 0.002 dynes/cm) formulations for most of the experiments, we also performed tests at low IFT (approximately 0.3 dynes/cm) for comparison. A second major objective of this study was to develop a simple analytical model to predict the oil recovery as a function of vertical- and horizontal-fracture spacing, rock properties, and fluid properties. The model and experimental data were found to be in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different from the traditional scaling groups in the literature. The model is useful for both interpreting the experiments and for scaling the results from the laboratory to the field.

In-Situ Visualization of Multidimensional Imbibition in Dual-Porosity Carbonates

Summary Oil recovery by waterflood is usually small in fractured carbonates because of selective channeling of injected water through fractures toward producers, leaving much of the oil trapped in the matrix. One option to mitigate the low recovery is to reduce fracture uptake by increasing the viscosity of the injected fluids by use of polymers or foams. Another option, that is the objective of this work, is to inject surfactant solutions to reduce capillary effects responsible for trapping oil and allow gravity to segregate oil by buoyancy. Analysis of gravity and capillary forces suggests that such segregation is achievable in the laboratory, provided that cores are moderately long and oriented vertically. Besides investigating the role of gravity on oil recovery, the effect of surfactant-flood mode (secondary-flood mode and tertiary-flood mode) on the ultimate recovery (UR) was also investigated. To investigate the predictions of this analysis, coreflood experiments were conducted by use of carbonate cores and monitored by an X-ray computed-tomography (CT) scanner featuring true vertical positioning to quantify fluid saturation history in situ. Novel aspects of this work include cores that are oriented both horizontally and vertically to maximize gravitational effects as well as a special core holder that mimics aspects of fractured systems by use of the whole core. This paper discusses the contrast in experimental results in vertical and horizontal orientation with and without surfactant. To study gravity effects, surfactant reduced interfacial tension (IFT) from 40 to 3 mN/m. For this mode of recovery, ultralow IFT is not preferred because some capillary action is needed to aid injectant transport into the matrix. The vertical experiment showed that gravity has the potential of improving oil recovery at low IFT. Another surfactant was used to study the flood-mode effect; this surfactant reduced IFT from 40 to 0.001 mN/m (ultralow IFT). In this study, two experiments were conducted: a tertiary-surfactant-flood experiment and a secondary-surfactant-flood experiment. The secondary-flood experiment showed an improvement in recovery with the early implementation of the surfactant flood relative to the tertiary-flood experiment. This work highlights the importance of gravity at low IFT in terms of mobilizing trapped oil and also the effect of flood mode on UR. Moreover, this work emphasizes the use of surfactant solutions as a method of enhancing oil recovery in fractured resources not necessarily because of wettability alteration but mainly because of gravity effects. Experimental results are presented primarily as 1D and 3D reconstructions of in-situ oil- and water-phase saturation obtained by use of X-ray CT.