Chemical Enhanced Oil Recovery Methods Research Articles

Surface functionalized Fe3O4‐polyacrylamide dispersion for improved oil recovery at harsh conditions

AbstractWith the growing demand for energy supply and the natural decline of oil reservoirs, the development of new enhanced oil recovery (EOR) techniques become more and more critical. Polymer flooding EOR is one of the most successful chemical EOR methods but suffers many drawbacks at high temperatures and high salinity (HT‐HS) conditions. Superparamagnetic nanoparticles (NPs) have been recently investigated for subsurface applications, including in EOR, due to their unique physicochemical properties. Their applicability under harsh reservoir conditions, however, is yet to be examined. In this work, a novel approach is developed to synthesize superparamagnetic Fe3O4 (NPs) with unique surface functionalization (SMag‐NPs) and to form stable polyacrylamide (PAM) dispersions (SMag‐NPs‐PAM). Both stability and core flooding experiment results demonstrate the promising future of the new dispersion. The SMag‐NPs‐PAM dispersion is not only stable at HT‐HS conditions, but also show excellent EOR capability at HT‐HS by recovering, 61.72% of the initial oil quantity, which is significantly higher than those from conventinal NPs‐PAM disperison and pure PAM fluid. These findings show the promising application potential of SMag‐NPs‐PAM for improving oil recovery in challenging HT‐HS reservoir conditions.

Developing methodology and experimental procedure эfor experimental microfluidic study of chemical enhanced oil recovery

The concern of this research was to review the different methodology on microfluidic experiments conducted to study chemical enhanced oil recovery methods on micromodel chips. In general, there are several ways to study EOR methods such core flooding and microfluidics. The disadvantage of first method is that the flow processes inside the core sample cannot be imagined. Hence, the second method helps us to fully visualize how fluid flow behaviour occurs though the porous medium of the rocks. The various chemical EOR processes such as surfactant flooding, polymer flooding and ASP flooding were studied on microfluidic chips. These chemicals were injected into micromodels to drive out crude oil. It helps to understand the interactions between crude oil and chemicals, the advancement of front developed between displacing and displaced fluids and the viscous fingering effect. Visual studies enabled us to understand the effectiveness of polymer, surfactant and alkaline separately and as combined. The different experimental methodologies to study the EOR methods are reviewed. Mainly experiments divided into two main groups: methods of geological characterisations influence to fluid transport while others study oil displacement at different condition, such high temperature, high pressure, low or high salinity, highly viscous oil. We reviewed methodologies applied to study an oil displacement by polymer, surfactant-polymer (SP) and alkaline surfactant polymer (ASP) solutions, their interactions and transport in porous media. Based on reviewed article the experimental procedure was developed. Analyses of published materials have helped to design and direct the methodology of research.

Characteristics of Malaysian Crude Oils and Measurement of ASP Flooded Water in Oil Emulsion Stability and Viscosity in Primary Separator

With the application of chemical enhanced oil recovery methods, water separation is a major issue in a production facility. Oil/water separation is suppressed with a stable emulsion. The present study evaluated the impact of different emulsifiers in enhanced oil recovery. The effectiveness of each additive such as an alkali, surfactant, or polymer on the stability of the emulsion was anticipated using laser scattering to measure the emulsion’s stability. An artificial neural network was applied to predict the effectiveness of the additives on stabilization/destabilization and to assess how alkali/surfactants, surfactant/polymers, and polymer/surfactants affect the separation profiles. Measurements of the viscosity and zeta potential of residual emulsion clarify that the increase in surfactant makes the emulsion stable and became unstable with the increase in the alkali and polymer. The droplet zeta potential was within −i9~−i5 mV. The absolute value of the zeta potential decreased at a high polymer concentration with a low surfactant concentration resulting in fast flocculence phenomena. With an increase in the surfactant concentration and the presence of high alkali, the droplet’s absolute zeta potential demonstrated an increase in the repulsion force in the emulsions. The study also focuses on the carbon number distribution, wax appearance temperature (WAT) and wax content of four crude oil samples from different field locations (Miri, Angsi, Penara and Dulang). Findings show that crude oil samples with higher mol percent of carbon distribution from C20 to C40 (paraffinic composition) contains higher wax content, wt% and subsequently results in higher wax appearance temperature (WAT). This is obviously shown by the crude oil sample from Penara field. Further similar investigation on other field locations will assist in characterizing the paraffinic composition in Malaysian oil basins.

Strategy for Optimum Chemical Enhanced Oil Recovery Field Operation

The main objective of this review paper is to present practical considerations for field implementation of chemical enhanced oil recovery (CEOR) methods which are complex and require a tailored study for a given reservoir. Researchers have examined several CEOR methods and screening standards. To the best of our knowledge, however, there is no thorough review paper to provide a detailed workflow for transitioning laboratory studies into best practices to field project execution and operations. We analyze and highlight more than thirty publications published between 2018 and 2021 in order to give the readers the latest information about different CEOR methods. We also present a summary of both conventional and cutting-edge CEOR technologies. This provides the readers, researcher, and chemical suppliers with a better understanding of the novel hybrid techniques that are currently being developed. We present several tools for ranking and selecting the CEOR methods, such as techniques for selecting chemicals, screening guidelines, laboratory workflow, injection parameters, chemical formulations, and economic parameters. Our survey's findings indicate that scaling up from laboratory scale to field deployment has many challenges and barriers. These barriers include; project cost, history match and forecast simulations, surveillance, facilities, hybrid method considerations, standardization of performance metrics, the onset of CEOR projects, chemical manufacturing, and the environmental impacts of CEOR operations. Finally, based on these findings, we have proposed a new workflow for practical implementation of CEOR projects. In summary, this paper provides a practical strategy for developing, implementing, and assessing CEOR field operations.

Technology Focus: EOR Modeling (January 2023)

The oil and gas industry is facing unprecedented responsibility and expectations to keep fueling the world’s economies and social developments with reliable, accessible, safe, and affordable energy sources while responding to the global urgency to safeguard natural resources and protect the environment. Most major oil and gas companies have announced decarbonization strategies for low-carbon or net-zero emissions associated with their business operations. Consequently, reducing the carbon intensity of oil production [kilograms of carbon dioxide (CO2) equivalent emitted per produced barrel of oil] will be pivotal to meeting the environmental mandate. On the other hand, approximately 70% of the world’s counties have set targets to reach net zero within the next 3–5 decades, including emissions from burned hydrocarbon, which is a major challenge. Within this exigent mission to transition the industry, a major question arises about the merit and the role of enhanced oil recovery (EOR). With a share below 3% of the global oil production, field-scale EOR deployment and contribution have been modest despite substantial investments made in research and development and piloting in the last 4 decades. This underperformance of EOR has been attributed mostly to competitive alternatives (waterflooding), high cost, complex infrastructure and supply chains, fluctuating oil prices, and others. In the era of thirst for sustainability in our industry, there are reviving opportunities for selective EOR methods that can achieve efficient oil production with low carbon intensity. For instance, CO2 EOR is intuitively a win/win technology. This method may not be feasible everywhere for various reasons, however, including the availability and proximity of CO2 sources and the suitability of reservoir conditions. Chemical EOR methods, such as low-salinity, polymer-, and surfactant-based methods with low chemical usages have the potential to reduce water usage and enhance recovery factors, particularly from tight oil reservoirs. In contrast, EOR methods that are inherently associated with high carbon intensity, such as thermal EOR, will face stricter constraints to perform, including prohibitive costs for carbon offsetting. Advanced modeling and optimization, including guided machine learning and data analytics, will be crucial to maximizing recovery, quantifying uncertainties, and managing risk while preserving resources and reducing costs. The selected papers in this feature include examples of innovative approaches for developing efficient EOR schemes and advanced modeling and optimization. In one inclusion, optimized water chemistry is engineered for various EOR schemes (e.g., polymer, surfactant, CO2) to improve efficiency while reducing chemical usage. The second inclusion demonstrates an integrated core-to-field work flow to design surfactant-based EOR for a tight formation at the laboratory scale and demonstrate its performance using field-scale simulations. An integrated optimization approach for a Permian CO2-EOR field is demonstrated in the third paper, where an advanced Bayesian framework is used to capture uncertainties. Our industry has consistently demonstrated resilience, adaptivity, and creativity. In the era of industry transition to low-carbon operations, opportunities exist for selective EOR methods to revive and contribute. Recommended additional reading at OnePetro: www.onepetro.org. SPE 208121 Polymer Injection To Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large-Scale Polymer Project by Clement Fabbri, ADNOC, et al. SPE 208127 The World’s First Offshore Gravity-Assisted Simultaneous Water-Alternating-Gas EOR Full-Field Implementation by Ahmad Khanifar, Petronas, et al. SPE 207449 Numerical Optimization of Water-Alternating-Gas Injection in a Sandstone Field Using a Coupled Surface and Subsurface Model by Thaer I. Ismail, Khalifa University of Science and Technology, et al.

A Critical Overview of ASP and Future Perspectives of NASP in EOR of Hydrocarbon Reservoirs: Potential Application, Prospects, Challenges and Governing Mechanisms.

Oil production from depleted reservoirs in EOR (Enhanced Oil Recovery) techniques has significantly increased due to its huge demands in industrial energy sectors. Chemical EOR is one of the best approaches to extract the trapped oil. However, there are gaps to be addressed and studied well for quality and cost consideration in EOR techniques. Therefore, this paper addresses for the first time a systematic overview from alkaline surfactant polymer ((ASP)) and future perspectives of nano-alkaline surfactant polymer ((NASP)), its synergy effects on oil recovery improvement, and the main screening criteria for these chemicals. The previous findings have demonstrated that the optimum salinity, choosing the best concentration, using effective nano-surfactant, polymer and alkaline type, is guaranteed an ultra-low IFT (Interfacial Tension). Core flood results proved that the maximum oil is recovered by conjugating nanoparticles with conventional chemical EOR methods (surfactant, alkaline and polymer). This work adds a new insight and suggests new recommendation into the EOR application since, for the first time, it explores the role and effect of nanotechnology in a hybrid with ASP. The study illustrates detailed experimental design of using NASP and presents an optimum micro-model setup for future design of NASP flow distribution in the porous media. The presence of nano along with other chemicals increases the capillary number as well as the stability of chemicals in the solution and strengthens the effective mechanisms on the EOR.

Applicability of Nanoparticle Flooding Process in a Carbonate Rock of Kurdistan Region: Experimental Investigation of Interfacial Tension and Wettability

Enhanced oil recovery (EOR) has long proven to be a good method to mobilize the residual oil that is by passed and capillary trapped by secondary recovery methods. Chemical EOR methods enhance the microscopic and macroscopic efficiency, and ultimately the overall oil recovery is improved. However, the adsorption rate of the surfactant, low resistance to high temperature and salinity are some of the factors that would turn chemical flooding impractical and uneconomic in many cases. Lately, the application of nanotechnology in enhanced oil recovery has showcased some good and prolific results in terms of incremental oil recovery. In this study, the applicability of Nanoparticle flooding in carbonate rocks of Pilaspi formation was probed through a series of tests such as thin section analysis, x-ray diffraction, x-ray fluorescence, interfacial tension and contact angle measurements. The results showed that the composition of the carbonate rocks is predominantly calcite (CaCO3) with minor traces of quartz and dolomite. From the interfacial tension (IFT) measurements, it was figured out that the silica and alumina Nanofluids lowered the IFT by 27% and 42% with the light oil, and 43% and 49% with the heavy oil, respectively. The contact angle measurements revealed that the Alumina Nano-fluid at 0.25 wt. % reduced the contact angle on the surface of the light and heavy oil aged thin sections from 169◦ and 115◦ to nearly 119◦ and 78◦. On the other hand, the silica nanoparticle at 0.25 wt. % reduced the contact angles on both thin section types to around 129◦ and 80◦, respectively.

Factors affecting the effectiveness of the application gel-forming dispersed compositions in chemical methods of oil recovery improvement

The use of enhanced oil recovery (EOR) methods has a significant impact on the current level of hydrocarbon production. Therefore, the issue of maintaining the high efficiency of their application remains relevant at all stages of field development. Currently, in the field of flow diverting technologies (FDT) and technologies for leveling the injectivity profile many different reagents and compositions of EOR have been developed, as well as approaches and methods of their application. The choice of using certain methods of influencing a productive formation depends on its geological and physical conditions (HFC), therefore, the correctness of this choice has a direct impact on the effectiveness of the use of EOR technologies. This article is devoted to an analysis of the effect of certain HFCs on the efficiency of FDT use with the use of GFS gel-forming systems, heat-resistant GFS (T) gel-forming systems and GFS-1AS gel-forming systems with fillers. As a result of the analytical work carried out, the main trends in the efficiency of the application of the above technologies were predetermined from different indicators, such as the effective thickness of the formation, its reservoir properties, the volume of injected reagents, the compartmentalization of the formation, the injectivity of wells before treatment and the change in their mode of operation after treatment. The main conclusion, which is obtained based on the results of the work carried out, is that at the moment there is a need to search for or develop new approaches to the implementation of physical and chemical enhanced oil recovery methods, which will allow solving two main problems: improving the rheological characteristics of cross-linked polymer systems and reducing the cost of the work performed.

Sustainable wastewater management from shale oil production wells: emerging opportunities and barriers

During the production from shale oil formations, the produced water has been dedicated to different procedures such as chemical enhanced oil recoveries, drilling mud making (e.g., for various purposes of lubrication and cooling) and hydraulic fracturing. One of the main challenges of wastewater treatment corresponds to (TDS) total dissolved solids. To measure the required water needed for different processes, it is necessary to proceed with every step saving and then make an average to calculate the required freshwater. In this regard, we have selected five different oil wells with the same rock and reservoir characteristics. SOW#3 has the highest rate of treatment (26%) and SOW#1 has the minimum treated wastewater during hydraulic fracturing processes. It corresponds to the large volume of solid and oil particles, which remained in the treatment devices. However, it is observed that SOW#1 has the highest rate of treatment (32%) and SOW#4 has the minimum treated wastewater (14%) in chemical enhanced oil recovery methods. On the other hand, SOW#3 has the highest rate of treatment (27%) and SOW#5 has the minimum treated wastewater from drilling mud preparation and other well facilities. It is observed that SOW#1 has the highest rate of treatment (27%) and SOW#5 has the minimum saving water during hydraulic fracturing processes, SOW#1 has the highest rate of treatment (38%) and SOW#4 has the minimum saving water (9%).

New insight to polymer transport in porous media to enhance heavy oil recovery: Lab experiment and numerical simulation

Polymer molecules gain a great attention in enhanced oil recovery (EOR) in both light and heavy oil reservoirs. However, understanding of polymer transport in porous media is still challenging. In this study, the rheological behaviour of partially hydrolyzed polyacrylamide (HPAM) was investigated using both rotational and oscillatory rheometry. To observe the effect of radius gyration of the HPAM solutions on improving oil recovery, low and high permeability unconsolidated sand-pack were tested. Furthermore, the numerical simulation was applied to forecast the laboratory sand-pack flooding experiments. The results showed that the polymer transport in porous media is mainly related to the ratio of the radius gyration of polymer molecule to the pore size distribution of porous media. The unexpected excess pressure of HPAM solution during single-phase and two-phase HPAM flooding in low permeability porous media was related to the confinement phenomenon of polymer chains in a channel. In the numerical simulation, we successfully predicted oil recovery and pressure data by considering polymer adsorption and new retention model. The outcomes of this study will help petroleum scientists to design efficient chemical enhanced oil recovery methods.

Statistical Analysis of Treated Flow-Back Water Measurements: An Industrial Insight for a Shale Reservoir

Water production from unconventional reservoirs especially shale reservoirs has always been considered as the major challenges for petroleum industries that needs special requirements and facilities to treat the flow-back water and reinject to the reservoirs. The objective of this paper is to statistically measure the provided freshwater from treated water that is produced from reused water. The treated water is provided from different processes such as hydraulic fracturing, chemical enhanced oil recovery methods (such as polymer, surfactant, and foam flooding that are the main important techniques in recovery processes) from eight wells in Bangestan field in South of Iran. Moreover, photofenton-flotation separation methods are used in this field to treat the produced water from different processes. As a result, saving water percentage in the studied field for hydraulic fracturing processes is about 82% and therefore, the required fresh water is about 18%. Moreover, saving water percentage in the studied field for chemical recovery techniques is about 70% and therefore, the required fresh water is about 29%. The findings of this study can help for better understanding of the required fresh water for 1000 inhabitants can be saved through this system.

Experimental analysis of oil displacement by hybrid engineered water / chemical EOR approach in carbonates

Fast depletion in oil reserves has steered the petroleum industry towards developing novel enhanced oil recovery (EOR) techniques. The standalone EOR methods have associated merits and demerits. For example, the chemical EOR (CEOR) methods have very limited applications in high salinity, high temperature carbonate reservoirs because of increased chemical adsorption and high project costs. In this study, hybrid approaches utilizing engineered water (EW) and CEOR were investigated for carbonate reservoirs. The synergetic effects of EW and chemicals such as polymer, alkali, and surfactant were analyzed. Phase behavior analysis, aqueous stability study, surfactant static adsorption test, and polymer rheological characterization were conducted to select the optimum alkali/surfactant/polymer formulation. To evaluate the increase in oil recovery, wettability alteration, and extent of mobility control, various EW/CEOR combinations were designed for oil displacement experiments, including EW/surfactant flooding (EWSF), EW/polymer flooding (EWPF), EW/surfactant/polymer flooding (EWSPF), and EW/alkali/surfactant/polymer (EWASP) flooding. The EWASP flooding was executed in both continuous and slug-wise injection modes, and the best hybrid EW/CEOR design was selected. 10 times diluted Caspian seawater spiked with optimized active ions was used as the EW. Based on phase behavior and static adsorption tests, 1 wt% Soloterra 113-H was used as a surfactant, while 1 wt% sodium carbonate was used as an alkali. Flopaam 5115 was employed as a polymer with an optimum concentration of 1500 ppm, as established from rheological experiments. The best combination in terms of oil recovery, stability of polymer and surfactant, and chemical consumption was the hybrid EWASP flooding in slug-wise injection mode. This injection scheme resulted in 36% OOIP incremental recovery, 7% higher than the EWPF and EWSPF scenarios and 3% higher than hybrid EWASP flooding in continuous injection mode. Hybrid designs proved to be more effective in recovering residual oil because of better mobility control, reduced capillary trapping, wettability modification, lower surfactant adsorption, and ultra-low interfacial tension (IFT). Our studies showed that the application of hybrid EW/CEOR for carbonate formations, as a novel approach, can expand the application envelope of chemical methods to challenging carbonate formations by making the EOR projects technically and economically viable.

Improving Oil Recovery Efficiency in Niger Delta Reservoirs Using Corn Starch as a Local Polymer

Polymer flooding is a chemical enhanced oil recovery method that improves the recovery of oil by controlling the mobility of water to oil phase. It uses polymer solutions to increase the viscosity of the displacing water thereby decreasing water/oil mobility ratio (Speight, 2013). The volumetric and displacement sweep efficiencies are positively affected by polymer flooding. The viscosity of the aqueous phase is increased due to the molecular size and structure of the polymer used. The main objective of this research was to study the ability of cornstarch (local polymer) to recover additional oil after conventional water flooding. The objective was successfully achieved by injecting four different unconsolidated samples (sand pack) with cornstarch solution at varying concentration of 500ppm, 1000ppm, 3000ppm, and 9000ppm. From the results of the experiment conducted, it was deduced that Cornstarch has the ability to recover an additional volume of oil about half the volume of oil recovered during conventional water flooding (i.e. if 50% of oil initially in place was recovered during water flooding, cornstarch can recover an additional 25% of the residual oil after water flooding). Also, higher concentrations of cornstarch reduce the recovery factor due to polymer adsorption on the rock surfaces which alters the rock wettability. To reduce the adsorption effect of Cornstarch, it is recommended that the concentration of Cornstarch be measured after the flooding experiments for a better understanding of the adsorption mechanism of cornstarch.

PERFORMANCE EVALUATION OF ALPHA-OLEFIN SULFONATE (AOS), COCO GLUCOSIDE AND DECANE IN CREATING WINSOR TYPE-III MICROEMULSION

Enhanced oil recovery (EOR) shows great potential in maximizing the recovery of bypassed oil remains unrecovered in the reservoir after applying conventional oil recovery methods. Surfactant injection is a chemical enhanced oil recovery method that can improve the overall displacement efficiency and increase hydrocarbon production. The application of surfactant flooding is challenging due to the complexity of the design. On top of that, most of the utilized surfactants are not environmentally friendly. The formulation of the microemulsion system directly impacts the success of a surfactant injection process. Good understanding on the phase behaviours of the microemulsion system is essential to create Winsor Type-III microemulsion that has the ability to reach ultralow Interfacial Tension (IFT) with the addition of co-surfactant. The performance of the microemulsion also highly depends on factors such as salinity, surfactant type, surfactant concentration, and temperature. Extensive laboratory investigation along with phase behaviour studies are vital in formulating an efficient green microemulsion system for tertiary recovery processes. This project evaluates and presents the performance of anionic surfactant, Alpha-Olefin Sulfonate (AOS), Coco Glucoside, and decane in creating Winsor Type-III microemulsion. The performance of the formulated microemulsions under various salinities, surfactant concentrations, co-surfactant concentrations and temperature are investigated through stages of phase behavior studies to optimize the parameters. The optimized formulation of AOS-Coco Glucoside microemulsion consists of 3 wt% salinity, 1 wt% AOS, and 1 wt% Coco Glucoside as the widest range and maximum volume of Winsor Type-III was observed at this condition. IFT of the microemulsion system was measured at 25°C and 70°C using a spinning drop tensiometer. It is concluded that the formulated microemulsion system with the optimized parameters reaches low IFT instead of ultralow. The temperature has no significant effect on the IFT performance of the formulated microemulsion system, and the critical micelle concentration is determined to be at 0.05 wt% of the aqueous phase.Keywords: Surfactant flooding, microemulsion system, ultralow interfacial tension, environmental friendly surfactants

Experimental Microemulsion Flooding Study to Increase Low Viscosity Oil Recovery Using Glass Micromodel

The growing demand for clean energy can be met by improving the recovery of current resources. One of the effective methods in recovering the unswept reserves is chemical flooding. Microemulsion flooding is an alternative for surfactant flooding in a chemical-enhanced oil recovery method and can entirely sweep the remaining oil in porous media. The efficiency of microemulsion flooding is guaranteed through phase behavior analysis and customization regarding the actual field conditions. Reviewing the literature, there is a lack of experience that compared the macroscopic and microscopic efficiency of microemulsion flooding, especially in low viscous oil reservoirs. In the current study, one-quarter five-spot glass micromodel was implemented for investigating the effect of different parameters on microemulsion efficiency, including surfactant types, injection rate, and micromodel pattern. Image analysis techniques were applied to represent the phase saturations throughout the microemulsion flooding tests. The results confirm the appropriate efficiency of microemulsion flooding in improving the ultimate recovery. LABS microemulsion has the highest efficiency, and the increment of the injection rate has an adverse effect on oil recovery. According to the pore structure’s tests, it seems that permeability has little impact on recovery. The results of this study can be used in enhanced oil recovery designs in low-viscosity oil fields. It shows the impact of crucial parameters in microemulsion flooding.

Capillary Desaturation Tendency of Hybrid Engineered Water-Based Chemical Enhanced Oil Recovery Methods

Several studies have shown the synergetic benefits of combining various chemical enhanced oil recovery (CEOR) methods with engineered waterflooding (EWF) in both sandstones and carbonate formations. This paper compares the capillary desaturation tendency of various hybrid combinations of engineered water (EW) and CEOR methods with their conventional counterparts. Several coreflood experiments were conducted, including EW-surfactant flooding (EWSF), EW-polymer flooding (EWPF), EW-alkali-surfactant flooding (EWASF), EW-surfactant-polymer flooding (EWSPF), and EW-alkali-surfactant-polymer flooding (EWASP). Capillary numbers (Nc) and corresponding residual oil saturation (Sor) for each scenario are compared with capillary desaturation curves (CDC) of conventional CEOR methods from the literature. The results indicate that hybrid EW–CEOR methods have higher capillary desaturation tendency compared to conventional methods. The capillary numbers obtained by standalone polymer flooding (PF) are usually in the range from 10−6 to 10−5, which are not sufficient to cause a significant reduction in Sor. However, the hybrid EW-polymer flooding approach considerably reduced the Sor for the same Nc values, proving the effectiveness of the investigated method. The hybrid EWASP flooding caused the highest reduction in Sor (23%) against Nc values of 8 × 10−2, while conventional ASP flooding reduced the Sor for relatively higher Nc values (3 × 10−3 to 8 × 10−1). Overall, the hybrid methods are 30–70% more efficient in terms of recovering residual oil, compared to standalone EWF and CEOR methods. This can be attributed to the combination of different mechanisms such as wettability modification by EW, ultralow interfacial tension by alkali and surfactant, reduced surfactant adsorption by alkali addition, and favorable mobility ratio by polymer. Based on the promising results, these hybrid techniques can be effectively implemented to carbonate formations with harsh reservoir conditions such as high salinity and high temperature.

Laboratory studies of oil-displacing characteristics of emulsion solutions in the pore space of reservoir rocks

Chemical enhanced oil recovery methods are widely used in field development. One of the methods for leveling injectivity is emulsion-based technologies. The mechanism of this technology is to create an increased filtration resistance of the most depleted reservoir intervals. To establish the actual oil-displacing characteristics of the emulsifier grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory filtration studies was carried out on high-permeability core models at the AS12 horizon of the Nizhne-Sortymskoye oil field.Processing laboratory data after filtration of ready-to-use emulsions through core samples gives an increase in the oil displacement coefficient by water from 1.31 to 10.79 %. When constructing their correlation dependence, it is possible to identify the range of the final dynamic viscosity (from 5 to 9 mPa∙s) of the compositions of the emulsion-based technology, which is optimal for the most effective application on groups of AS formation.Based on the laboratory studies of rocks, it was established that carrying out geological and technical measures using the emulsifier Neftenol-NZ, which has proven itself in high efficiency from well treatments, will give a large volume of additional oil production, in comparison with the currently emulsifier Sinol-EM.

Investigating the impact of a walnut-extracted surfactant on oil-water interfacial tension reduction and wettability alteration in carbonate rocks

ABSTRACT Various types of Enhanced Oil Recovery (EOR) methods have generally been used to recover the residual oil left in the pores after secondary recovery processes. Surfactant flooding has been in use for quite a long time and has shown to be an efficient chemical EOR method. However, chemical surfactants usually result in a high cost and unfavorable environmental impacts. On the other hand, natural surfactants can be a good and promising alternative to the use of conventional surfactants. This paper introduces a newly extracted surfactant from the leaves of a walnut tree and was named UKHS. The ultimate aim of this paper is to experimentally study the applicability of the walnut extracted surfactant in lowering interfacial tension (IFT) and altering wettability in the carbonate rock of the Kurdistan Region at a reservoir temperature of 80°C.In contrast to most other studies, we have used a synthesized reservoir brine, as the aqueous phase, and a light crude oil sample (from an oil reservoir in the Kurdistan Region), during the IFT measurements. Moreover, carbonate samples of Pilaspi formation in the Kurdistan Region were employed with the crude oil sample to measure the contact angles to determine the wettability.The results show that the UKHS solution at a CMC of only1 weight% has significantly lowered the contact angle from a strongly oil-wet state of nearly 165⁰ to a fairly water-wet state of 56.7⁰. On the other hand, the IFT reduction was trivial as it has reduced from solely 11.18 mN/m to 2.54 mN/m. The obtained results of the wettability alteration at a low CMC of 1 wt% witness the higher efficiency of UKHS in comparison to other natural surfactants. Thus, UKHS can be considered as a promising EOR agent to mobilize the residual oil within pores, mainly via the wettability alteration mechanism, whereas the contribution from the IFT reduction is rather small.

Synergetic effect between in-situ mobility control and micro-displacement for chemical enhanced oil recovery (CEOR) of a surface-active nanofluid

Environmentally friendly and high cost-effective chemical enhanced oil recovery (CEOR) techniques have been the center of attention in oil industry. In this context, we tested a synergy between in-situ mobility control and micro-displacement of a surface-active nanofluid that was simply created using silica nanoparticles and nonionic surfactant via a combination of batch measurements at oil-water-rock interfaces, microfluidic and heterogeneous core flooding tests. Results show that the surface-active nanofluid imposes a positive curvature upon the oil−water interface, inducing Pickering emulsions with in-situ mobility control at a wide range of water saturation. These Pickering emulsions are thermodynamically unstable but kinetically stable, suggesting a static demulsification of oil well produced liquids. Meanwhile, the surface-active nanofluid yields 10−2 mN/m order magnitude of interfacial tension between oil and brine, and alters the oil-wet rock towards weak water-wet rock. Therefore, the capillary number of the surface-active nanofluid is 103 order magnitude to brine and has a higher value at higher water saturation condition, implying a self-regulating mobility control of the surface-active nanofluid. 0.6 pore volume of the surface-active nanofluid yields 29.2% of additional oil recovery with cumulative oil recovery of 70.9% under heterogeneous condition due to the mobility control of the in-situ Pickering emulsion and the micro-displacement behavior. CEOR potential of this nanofluid is comparable with alkali-surfactant-polymer flooding that has been a common knowledge of high CEOR method for decades. Moreover, the surface-active nanofluid can be easily prepared and injected using existing oilfield injection system with low-energy cost.

Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement.Graphic abstractHighlightsThe difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration.The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics.A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.