Coreflood Tests Research Articles

Experimental Investigation of the Effects of the Sizes and Concentrations of SiO2 Nanoparticles on Wettability Alteration and Oil Recovery

The use of silica nanoparticles for enhanced oil recovery has recently attracted the attention of investigators, and the disjoining pressure has been found to be a promising mechanism for removing residual oil. Previous studies have found that decreasing the particle size and increasing the concentration of nanoparticles improves the disjoining pressure, which enables the oil to be removed more easily. However, these studies were not designed for a reservoir environment. In the present work, our goal is to investigate the effects of the sizes and concentrations of nanoparticles by performing experimental wettability tests and core-flooding tests under reservoir conditions and by calculating the disjoining pressure. Our results demonstrate that both wettability alteration and oil recovery are higher with smaller particle sizes. However, we observed no correlation between wettability alteration and concentration. In contrast, the oil-displacement rate was better in the early stages of oil recovery for increased nanoparticle concentrations, suggesting that the disjoining pressure may be more effective then. These results demonstrate that particle sizes and concentrations are essential parameters for enhanced oil recovery using nanoparticles, even in a reservoir environment.

Spontaneous imbibition and core flooding analysis of pH adjusted alkali and surfactant system in high salinity sandstone reservoir

Some of the limitations of a cost-effective alkaline surfactant flooding method include chemical precipitation and other formation damage issue which has greatly affected the application of chemical flooding especially in high salinity reservoirs. This study ascertains the chelating attributes of Ethylene-diamine-tetracetic Acid-(EDTA/NaOH), investigates the ability of EDTA/NaOH and an anionic surfactant to improve oil recovery in heavy oil sandstone formation. Petrophysical analysis of the crude oil and core samples were performed. Hard brine at 5.1% optimal salinity and 0.2 wt.% surfactant imbibition were performed on the sandstone core plug for over 240 hrs. and the volume of oil recovered was determined using Amott imbibition cells. Sandstone core flooding test was thereafter conducted using the alkaline -surfactant solution at optimal salinity. Spontaneous imbibition results showed that surfactant imbibition (26.6%) produced a higher recovery than hard brine recovery (18.7%) after 240hrs. Sandstone core flooding results showed increased heavy oil recovery of 37% OOIP with alkaline-surfactant solution and additional 8% recovery was achieved by performing a final chase brine flooding, totaling 45% indicating that traces of alkaline-surfactant, in the core, aided the final imbibition process. This study underpins and complements several research solutions concerned with flooding in harsh oilfield terrains, thus making the overall process cost-effective and less time- consuming.

Laboratory Study of Enhanced Oil Recovery with Used Palm Oil Surfactant Injection

Currently the waste generated from public consumption in Indonesia is very high. One such waste is used palm oil from households and food companies. Utilization of this waste in this research is by recycling waste oil into surfactants which will be used in the Enhanced Oil Recovery (EOR) process. The surfactant concentrations used were 1.3%, 1.5%, 2%, 2.2% and 2.5%. The research began with refining used cooking oil with banana peels for 24 hours. In order to make surfactants, the oil is mixed with KOH and distilled water. Additionaly, brine was made with a salinity of 15,000 ppm. With the interfacial tension test, a solution with an optimum surfactant concentration of 2.2% was obtained. The core flooding test was carried out using waterflooding followed by surfactant flooding at a temperature of 70 oC. From the test results obtained an incremental oil recovery factor of 8.57% and a total oil recovery factor of 47.43%.

Nanoparticles assisted polymer flooding: Comprehensive assessment and empirical correlation

Conventional Polymer flooding is considered the most promising chemical-enhanced oil recovery by reducing water mobility, and hence increasing the sweep efficiency. However, there are certain drawbacks associated with polymer flooding as the degradation of its molecular structure in severe reservoir environments. Recently, it is experimentally adopted that attachment of nanoparticles (NPs) toward polymer macromolecule may ameliorate the flooding performance and hence increase the oil recovery further than conventional polymer flooding. The potential of NPs assisted polymer flooding has been extensively studied in porous media through core flooding. The target of this work is to statistically scrutinize the previous core flooding experiments and investigate the parameters that affect the incremental oil recovery by NPs assisted polymer flooding. To accomplish this target, a robust investigation of the outcome of over 350 core-flood tests from the literature was gathered to investigate the impacts of rock-oil properties, flooding conditions, polymer, and NPs characteristics on incremental oil recovery. Additionally, Fractional factorial design (FFD) was used to analyze core flood results and screen the effects of reservoir rock, fluid, polymer, and NPs properties on the performance of assisted polymer flooding. Furthermore, an empirical model was built using an Artificial neural network (ANN) to predict the incremental oil recovery for polymeric nanofluid. The results of the investigation indicated that NPs assisted polymer flooding with optimum concentration of both polymer and NPs may result in an incremental recovery of 18% of oil-in-place. Furthermore, the results of FFD revealed that NPs concentration, polymer concentration, and rock permeability are the most significant parameters of oil recovery. The results outcome showed that there is an optimal concentration of both polymer and NPs assisted polymer. In addition, the results revealed that core-flooded viscous oil needs a highly permeable rock to guarantee successful flooding. The coefficient of determination (R2) between the real and calculated incremental oil from the ANN model was established to be 0.953 and 0.952 with an error of 5.6 and 8.7% respectively for the training and testing approaches. Such statistical investigations and ANN approaches afford new insights and guidelines for preliminary assessment, designing, and execution of Nanohybrid polymer upcoming projects on a field scale.

Effect of modification degrees on the interfacial properties and EOR efficiency of amphiphilic Janus graphene oxide

Asymmetrically modified Janus graphene oxide (JGO) has attracted great attention due to its unique physical chemistry properties and wide applications. The modification degree of Janus nanosheets inevitably affects their interfacial activity, which is essential for their performances in enhanced oil recovery (EOR). In this study, the interfacial properties of Janus graphene oxide (JGO) with various modification degrees at liquid-liquid and liquid-solid interfaces were systematically evaluated via the measurements of interfacial tension (IFT), dilatational modulus, contact angle, and EOR efficiency was further assessed by core flooding tests. It is found that JGO-5 with higher modification degree exhibits the greater ability to reduce IFT (15.16 mN/m) and dilatational modulus (26 mN/m). Furthermore, JGO can construct interfacial and climbing film with the assistance of hydrodynamic power to effectively detach the oil from the rock surface and greatly enhance oil recovery. Moderately modified JGO-2 can highly improve recovery of residual crude oil (11.53%), which is regarded as the promising EOR agent in practical application. The present study firstly focuses on the effects of modification degrees on the JGO interfacial properties and proposes diverse EOR mechanisms for JGO with different modification degrees.

Experimental Study to Investigate the Effect of Polyacrylamide Gel to Reduce the Lost Circulation

One of the challenging issues encountered during drilling operations is the lost circulation. Numerous issues might arise because of losses, such as wasting of time and higher drilling cost. Several types of lost circulation materials have been developed and are being used to limit mud losses and avoid associated issues. Each solution has benefits and drawbacks. In this study, a core flooding test was performed to study the effectiveness of polyacrylamide (PAM) granular gel on the reduction of the circulation lost. One common type of fracture characteristic is fractures with tips, commonly known as partially open fracture (POF). However, PAM gel therapy in POFs received little attention in prior research. Models of partly open fractures were built using a cylindrical core. A series of processes are performed on a core to get a POF model. Overall, the PAM gel can decrease plug permeability, making it a useful material for lost circulation. The results indicate that the Polyacrylamide granular gel can decrease the permeability up to 193 times.

Key parameters and dominant EOR mechanism of CO2 miscible flooding applied in low-permeability oil reservoirs

CO2 miscible flooding is a prospective production method to enhance oil recovery (EOR), especially in low-permeability reservoirs. However, there is a lack of comprehensive and systematic understanding of the key parameters and dominant EOR mechanism of CO2 miscible flooding. In this work, the sensitivity of key parameters, such as oil viscosity, permeability, permeability ratio, and pressure, is analyzed by CO2 flooding physical simulation experiments. The adjuvants for CO2 miscible flooding of the Changqing crude oils are evaluated and optimized. The production performance of overpressure CO2 miscible flooding is studied by CO2 core flood test, and the oil micro-distribution before and after CO2 miscible flooding is characterized using nuclear magnetic resonance (NMR), and the micro EOR mechanism of CO2 miscible flooding is revealed. The results show that CO2 immiscible flooding is suitable for the development of low-viscosity crude oil (<50 mPa s), especially for oil viscosity of less than 10 mPa s. CO2 miscible flooding is advisable for low-permeability and medium and high-permeability reservoirs, especially for reservoir permeability of higher than 10 mD. Above the MMP, the oil recovery factor is over 85% and the increase rate slows down with pressure, CO2 miscible flooding is preferred for the high-pressure reservoir. CO2 miscible flooding is applicable for reservoirs with a permeability ratio of less than 2.5, especially for a permeability ratio of less than 2. Compared with 0.8 times MMP pure CO2 flooding, the time of gas channeling, and oil recovery for CO2 miscible flooding is delayed from 0.69 PV to 0.76 PV, and enhanced to 93.04% from 72.61%, respectively, with the help of adjuvants for CO2 miscible flooding, NP-9. The adjuvants for CO2 miscible flooding could effectively promote the realization of miscible flooding for CO2 and crude oils with an injection pressure of less than the MMP. CO2 has excellent oil displacement ability in low-permeability reservoirs, especially for miscible flooding, and the core oil saturation is obviously reduced. Overpressure CO2 miscible flooding could expand the swept volume and more efficiently displace oil in low-permeability reservoirs compared to an injection pressure of 1.0 times MMP. After overpressure CO2 miscible flooding, the residual oil in the low-permeability cores is distributed more evenly.

Wettability Alteration with Weak Acid-Assisted Surfactant Flood

Summary Oil-wetness and heterogeneity are two key reasons for low oil recovery by waterflooding in carbonate reservoirs. Surfactants have been effective in altering the oil-wet matrix to a more water-wet condition and initiating spontaneous imbibition. Because it takes time for the surfactant to alter wettability, oil recovery from the tight matrix is slow and sometimes not economically feasible. Acids have the potential of dissolving minerals, which may alter wettability. In this study, the enhanced oil recovery (EOR) performance of an acid-assisted surfactant solution, a novel technique, was evaluated for low-temperature applications. A set of acids and their acetates were tested. Bulk rock-acid reaction, wettability alteration (WA) tests, and spontaneous imbibition measurements were conducted at reservoir temperature (35°C) to identify effective candidates. Coreflood tests were then performed to evaluate the selected acid-surfactant formulations. Before and after a coreflood test, the core was scanned using micro-computed tomography (CT) to investigate pore structure alteration. Bulk reaction measurements showed that weak acids, especially acetic acid (AA), have the desired low reaction rates at 35°C. WA tests showed that AA can remove the crude oil off the rock surface and alter wettability through mineral dissolution. The surfactant can reduce contact angles from 160° to 58°; adding acid into the surfactant can further reduce it to 52°. Spontaneous imbibition experiments showed the synergy between the acid and the surfactant; the AA-surfactant solution had the highest oil recovery (62.6%) among acid-surfactant formulations. The acid improves the WA efficiency by the surfactant through surface mineral dissolution and lower ζ-potential. The imbibition transports the acid-surfactant solutions into the matrix, which minimizes face dissolution. Coreflood tests show that the AA-surfactant flood can increase the oil recovery rate and recover about 8% more oil compared to the surfactant flood. Micro-CT showed that a few mineral particles were transported along the core and partially plugged pore throats, which reduced permeability and diverted flow leading to improved oil recovery. The transport of the acid in reservoirs and the potential plugging issues have to be carefully evaluated in future studies.

Gas channeling control with an in-situ smart surfactant gel during water-alternating-CO2 enhanced oil recovery

Undesirable gas channeling always occurs along the high-permeability layers in heterogeneous oil reservoirs during water-alternating-CO2 (WAG) flooding, and conventional polymer gels used for blocking the “channeling” paths usually suffer from either low injectivity or poor gelation control. Herein, we for the first time developed an in-situ high-pressure CO2-triggered gel system based on a smart surfactant, N-erucamidopropyl-N,N-dimethylamine (UC22AMPM), which was introduced into the aqueous slugs to control gas channeling in WAG processes. The water-like, low-viscosity UC22AMPM brine solution can be thickened by high-pressure CO2 owing to the formation of wormlike micelles (WLMs), as well as their growth and shear-induced structure buildup under shear flow. The thickening power can be further potentiated by the generation of denser WLMs resulting from either surfactant concentration augmentation or a certain range of heating, and can be impaired via pressurization above the critical pressure of CO2 because of its soaring solvent power. Core flooding tests using heterogeneous cores demonstrated that gas channeling was alleviated by plugging of high-capacity channels due to the in-situ gelation of UC22AMPM slugs upon their reaction with the pre- or post-injected CO2 slugs under shear flow, thereupon driving chase fluids into unrecovered low-permeability areas and producing an 8.0% higher oil recovery factor than the conventional WAG mode. This smart surfactant enabled high injectivity and satisfactory gelation control, attributable to low initial viscosity and the combined properties of one component and CO2-triggered gelation, respectively. This work could provide a guide towards designing gels for reducing CO2 spillover and reinforcing the CO2 sequestration effect during CO2 enhanced oil recovery processes.

Assessment of a surface-active ionic liquid formulation for EOR applications: Experimental and simulation studies

This study aims to assess a surfactant blend for enhanced oil recovery from carbonate rocks. Due to the abundance of these reservoirs, their profitable exploitation would ensure our petrochemical needs are met, and maintain current quality of life. The objective of this work is to increase the technology readiness level of our previous proposal based on the use of a blend of pure sodium dodecylbenzene sulfonate and the surface-active ionic liquid cocosalkylpentaethoximethyl ammonium methylsulfate. To that aim, the method was adapted for its application with a commercially available petrochemical surfactant (RECOLAS103, a mixture of lineal alkyl benzene sulfonates), and reservoir simulations were carried out to evaluate its effectiveness. Phase behavior, stability, dynamic interfacial tension, adsorption and core flooding were the experimental tests carried out. An optimized formulation consisting of 1 wt% of blend (40 wt% RECOLAS103) in synthetic sea water was found stable and able to reduce water-oil interfacial tension down to 0.02 mN/m. The dynamic blend adsorption in carbonate rocks was found to be 0.60 mg/grock, a promising value for the application. Core flooding tests were conducted at 25 and 120 °C and additional oil recoveries achieved ranged from 10.2 to 12.7% of the original oil in place, the lowest production obtained at the highest temperature. This work offers an advance in the application of surfactants for EOR in carbonate reservoirs, since it improves previous proposals that show stability or high adsorption problems. Moreover, a chemical injection optimization was also carried out by simulation with the CMG-STARS software. Results point to the possibility of reaching higher oil recoveries than those obtained experimentally if the extraction method is optimized.

Silica Nanoparticles in Xanthan Gum Solutions: Oil Recovery Efficiency in Core Flooding Tests.

Polymer flooding is one of the enhanced oil recovery (EOR) methods that increase the macroscopic efficiency of the flooding process and enhanced crude oil recovery. In this study, the effect of silica nanoparticles (NP-SiO2) in xanthan gum (XG) solutions was investigated through the analysis of efficiency in core flooding tests. First, the viscosity profiles of two polymer solutions, XG biopolymer and synthetic hydrolyzed polyacrylamide (HPAM) polymer, were characterized individually through rheological measurements, with and without salt (NaCl). Both polymer solutions were found suitable for oil recovery at limited temperatures and salinities. Then, nanofluids composed of XG and dispersed NP-SiO2 were studied through rheological tests. The addition of nanoparticles was shown to produce a slight effect on the viscosity of the fluids, which was more remarkable over time. Interfacial tension tests were measured in water-mineral oil systems, without finding an effect on the interfacial properties with the addition of polymer or nanoparticles in the aqueous phase. Finally, three core flooding experiments were conducted using sandstone core plugs and mineral oil. The polymers solutions (XG and HPAM) with 3% NaCl recovered 6.6% and 7.5% of the residual oil from the core, respectively. In contrast, the nanofluid formulation recovered about 13% of the residual oil, which was almost double that of the original XG solution. The nanofluid was therefore more effective at boosting oil recovery in the sandstone core.

Experimental study on self–emulsification of shale crude oil by natural emulsifiers

Self–emulsification can be accomplished by enhanced oil recovery (EOR), the realization of the exploration of natural emulsifiers, which is a crucial task to understand the mechanism of crude oil self–emulsification, albeit it is, of course, accompanied by difficulties, during the development of shale crude oil. In this study, we separated the active components of crude oil, and with the help of modern characterization and laboratory tests, coupled with nuclear magnetic resonance of core flooding method, we fully explored the independent and synergistic effects of crude oil active components, and deepened the understanding of the mechanism of crude oil self–emulsification. Among the active components of crude oil, asphaltene and resin have vital effects on its self–emulsification, which is shown in the amphiphilic structure of asphaltene and the effect of resin solvent. Asphaltene can reduce oil–water interfacial tension to 19 mN/m, and the resin significantly increase the viscosity of emulsion. Meanwhile, resin and asphaltene stabilize the viscoelasticity of oil–water interface films and affect the phase transition of emulsions in different water oil ratio environment. As a result, the active components of crude oil are closely related to formation and stabilization of the emulsion, which together endue the inherent conditions of its self–emulsification. Core flooding test confirmed that some emulsions in nanoscale size are produced in shale porous media, and the average emulsion diameter size is 181 nm. This study explored the effects of natural emulsifiers on the self–emulsification of crude oil, thereby promising new potential opportunities for EOR of shale oil.

Green surfactant in oil recovery: Synthesis of a biocompatible surfactant and feasibility study of its application in foam-based enhanced oil recovery

Increasing demand for chemical additives in the petroleum industry has raised environmental consequences that limit their usage due to governmental guidelines. Nowadays, the design and production of chemical formulas that match environmental considerations is the trend in scientific societies and is growing fast. In this study, we developed a novel biocompatible surfactant and analyzed its applications in surfactant-stabilized foam. Our surfactant can be used in chemical enhanced oil recovery while it has comparable results with the two common surfactants previously used in literature. Our experimental procedure comprises two main parts: surfactant synthesis and feasibility study of its implementation in the EOR process. In the first part, the surfactant molecules were generated via a set of chemical reactions, and then characterization tests such as FT-IR, H NMR, and CHNSO were used to identify surfactant structure and validate the synthesis process. The critical micelle concentration of the surfactant was then measured to be 2521 ppm, and its behavior in the fluid–fluid interface was assessed in different salinity conditions and oil types. The second part presents the foam-forming ability of the surfactant. Foam stability was examined in different surfactant concentrations, salinities, oil types, oil concentration, and pH, and the synergic effects of these parameters with temperature were also studied in detail. In the end, four sets of core flooding tests were used to describe foam behavior in porous media. Our results reveal that the generated surfactant has the potential to be applied in comprehensive laboratory and field studies because the foam can yield 15 % extra oil in water-wet foam flooding and can produce 11 % more oil from the water flooded oil-wet rock.

Structure-modified polymeric carbon-dots with lowered retention and enhanced colloidal stability in porous media for tracer application at extreme reservoir condition

Tracer technology has been increasingly used in inter-well tests to investigate reservoir performance, reservoir connectivity and residual oil saturation for providing useful information to improve decision making in reservoir management. Stable nanoparticle tracers with high-sensitive real-time detectability are highly desired, and as one of the nanoparticles tracers, carbon dots (C-dots) have been studied and tested in field trial for reservoir monitoring. In this research, we report a modified method to synthesize fluorescent C-dots which fluorinated, sulfonated or zwitterionic functional groups were incorporated into the C-dots. The synthesis reactions occurred at hydrothermal conditions with inexpensive starting materials and are readily to scale up for industrial application. The synthesized C-dots are readily dispersible in brines and exhibit improved colloidal stability in high salinity and at high temperature and lowered retention in reservoir rock. Optical properties of the synthesized colloidal C-dots were studied by UV–visible and fluorescence spectroscopies, and the difference in fluorescence between the C-dots hydrothermally treated at different temperatures enables them to be used as multicolor tracers with fluorescence barcodes. Retentions of the C-dots in porous rocks were evaluated by adsorption in crushed calcite and core flooding tests with limestone, and near zero retention of the modified C-dots in reservoir rock were revealed. In molecular dynamics (MD) simulations, results show the C-dot adhesions on calcite surface follow the decreasing order: plain > sulfonated > zwitterionic > fluorinated C-dots, consistent well with experiments that the functionalized C-dots all have lowered adsorption on limestone. In comparison with those C-dots reported in literature, our results suggest that the synthesized C-dots using the modified procedure have excellent fluorescence properties, improved thermal stability, photostability, and water dispersibility, enabling their use as optically detectable nano-agent tracers for oilfield application.

Effect of UiO-66-NH2/TiO2 nano-fluids on the IFT reduction and their use for wettability alteration of carbonate rocks

One new technique to change the wettability of rocks (carbonate) is sea water (SW) flooding and nano-composite flooding. In this regard, this study investigated the performance of a new synthetic nano-composite called UiO-66-NH2/TiO2 (UT). In this study, this nano-composite is used next to SW. Generally, scanning electron microscopy (SEM), X-ray Powder Diffraction (XRD), Energy Dispersive X-ray Spectroscopy (EDS), and Brunauer-Emmett-Teller (BET) analyses investigated synthetic nano-composite physical and chemical properties. A comparative study of the effect of the synthesized Nano-fluids was performed using interfacial tension (IFT), contact angle (CA), and core flooding experiments. In this experimental study, SW contains Ca2+ and SO42− ions. Generally, nano-composite samples with differents concentrations (0.03 wt% and 0.3 wt%) dispersed in a base-fluid (BF) with varied salinities were prepared. Results showed that this sea-water (SW) + 0.3 wt%UT could reduce interfacial tension from 22 (mN/m) to 3.3 (mN/m) and CA from 118° to 37°. Generally, the interfacial tension between nano-fluids and crude oil is also a function of nano-fluid concentration and BF salinities. On the other hand, oil recovery results using the core flooding test show that SW and 0.3 wt% UT are high efficient than other concentrations. Thus, by injecting this nano-fluid (SW + 0.3 wt% UT), the ratios of oil recovery through the flooding process in the first and second core plugs to the total oil recovery increased by 24.8% and 26%, respectively. In the end, SW + 0.3 wt% UT showed the best performance in relation to increased oil recovery. This study offers new findings that can help oil recovery by understanding SW technology with nano-composite in carbonate reservoirs.

Spontaneous Imbibition and Core Flooding Experiments of Enhanced Oil Recovery in Tight Reservoirs with Surfactants

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. Petrophysical investigations were performed on the samples prior to the imbibition and core-flooding experiments. The composition of the minerals was examined using the XRD technique. To investigate the pore-size distribution and microstructures, nitrogen adsorption and SEM techniques were applied. The next step involved brine and surfactant imbibition for six Bakken cores and two Berea sandstone cores. The core samples were completely saturated with Bakken crude oil prior to the experiments. The core plugs were then submerged into the brine and surfactant solutions. The volume of recovered oil was measured using imbibition cells as part of experiments involving brine and surfactant ingestion into oil-filled cores. According to the findings, oil recovery from brine imbibition ranges from 4.3% to 15%, whereas oil recovery from surfactant imbibition can range from 9% to 28%. According to the findings, core samples with more clay and larger pore diameters produce higher levels of oil recovery. Additionally, two tight Bakken core samples were used in core-flooding tests. Brine and a separate surfactant solution were the injected fluids. The primary oil recovery from brine flooding on core samples is between 23% and 25%, according to the results. The maximum oil recovery by second-stage surfactant flooding is approximately 33% and 35%. The anionic surfactants appear to yield a better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations, especially clays, according to both the core-scale imbibition and flooding experiments. For studied samples with larger pore sizes, the oil recovery is higher. The knowledge of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks is improved by this study.

Nanofluid based on 1-dodecylpyridinium chloride for enhanced oil recovery

The use of nanoparticles is considered promising for enhanced oil recovery (EOR), especially when they are combined with surfactants. However, the combination of nano-sized material with surface-active ionic liquids (SAILs) is an unexplored EOR method. In this work, the advantages of mixing Al2O3 nanoparticles with the SAIL 1-dodecylpyridinium chloride were investigated. Stable nanofluids in brine could only be achieved using the polymer polyvinylpyrrolidone (PVP) as a stabilizing agent. It was found that the addition of nanoparticles (and PVP) to the surfactant formulation helped to: slightly increase its viscosity, enhance its water-oil interfacial tension (IFT) reduction capacity, and reduce the adsorption on carbonate rocks (adsorption on sandstone was found to be excessive). IFT was selected as target property to minimize for the design of EOR formulations. Core flooding tests were carried out with surfactant (0.5 wt% [C12py]Cl), surfactant-polymer (0.5 wt% [C12py]Cl, 1.0 wt% PVP) and nanofluid (0.05 wt% Al2O3, 1.0 wt% PVP, 0.5 wt% [C12py]Cl) formulations in brine (0.5 wt% NaCl). Additional oil recoveries of 3.4%, 7.4% and 12.0% OOIP were achieved, respectively, the nanofluid formulation being the most promising for the application. Moreover, it was found capable of changing the wettability of carbonate rocks from oil-wet to intermediate-wet. The significance of this work lies in showing the new possibilities resulting from the combination of SAILs and nanoparticles for EOR, specifically the combination of [C12py]Cl with Al2O3.

Hydrothermal Stability and Transport Properties of Optically Detectable Advanced Tracers With Carbonate Rocks in the Presence of Oil

Summary The use of tracer technology to illuminate reservoir characteristics such as well connectivity, volumetric sweep efficiency, and geological heterogeneity for the purpose of improving history-matching fidelity and enriching production optimization algorithms has gained momentum over the last decade. Herein, we report the stringent laboratory qualification of a novel class of fluorescent molecules, optically detectable down to ultratrace levels (&amp;lt;ppb) in produced water, as competent crosswell water tracers for use in highly retentive carbonate reservoirs with harsh salinity and temperature requirements. Tracer molecules, with state-of-the-art fluorobenzoic acids (FBAs) as a benchmark, exhibiting requisite hydrothermal stability and nonretentive behavior in simulated reservoir conditions coreflood tests are scheduled to be field-trialed. Our novel fluorescent tracer material systems, based on dipicolinic acid (DPA) and naphthalene sulfonates, rely on time-resolved luminescence and/or advanced chromatographic separation to eliminate the interfering fluorescent background issue in produced water for near real-time analysis. We systematically evaluated the novel tracer molecules at 95°C in high-salinity injection brine over 4 months, with periodic sampling and analysis by liquid chromatography to ascertain their hydrothermal stability. Coreflood tests at reservoir conditions were conducted to determine their interactions with carbonate rock surfaces with and without residual crude oil. All qualification tests were performed using a reference water tracer 2-FBA and/or a model partitioning tracer 4-chlorobenzyl alcohol as benchmark. Finally, reservoir simulations were performed to study both nonpartitioning and partitioning tracer transports in realistic field conditions. Hydrothermal stability tests indicated that our novel tracers are stable for 132 days in brine under reservoir conditions. Coreflood tests without residual oil revealed that the novel fluorescent tracer materials, such as FBAs, exhibit negligible retention in carbonate rocks (almost 100% recovery of the tracers). Coreflood experiments with residual oil suggested that all tracer materials, including the FBAs, possibly reversibly interact with the rocks, resulting in lower tracer materials recovery. While the overall retention of tracer materials is minimal in the presence of residual oil, these values were found to be relatively higher to that measured without residual oil. We observed no significant change in core permeability due to tracer injection. Field-scale reservoir simulation sensitivity studies in companion with coreflood experiments indicated minimum interferences for consecutive tracer injections in the field trial settings. We believe this is the first time such direct comparative study has been performed in the existing research to evaluate the interaction of both water and partitioning tracers in carbonate rocks at reservoir conditions with and without the presence of residual crude oil. Reducing the burden of analysis is critical in the implementation of this technology to obtain high-fidelity tracer data that can be used to improve waterflood optimization, increasing hydrocarbon recovery by a few percent per well without using additional resources for drilling or production. The ability to use presently commercialized tracer technologies, such as FBA-based molecules, in conjunction with this novel optically detectable fluorescent tracer platform will be a force multiplier to enable large tracer campaigns that provide high-fidelity tracer data for a production optimization algorithm.

Laboratory Testing of Nanosilica-Reinforced Silicate and Polyacrylamide Gels

Summary One of the most common methods used to reduce excessive water production is water shutoff operations. These types of operations include injection of gel for flow profile modification. The most widely used gels are polyacrylamide- and silicate-based gels. As a way to improve and optimize gel characteristics, nanosilica can be added to the gelant solution. In this paper, laboratory testing of nanosilica-reinforced silicate and polyacrylamide gels is presented. Bulk gelation and capillary tubing tests were used for determination of gelation time, and core flooding tests on low permeability carbonate core samples were conducted as a way to assess gel-plugging ability. Tests showed that gelation time for both types of gels was faster when nanosilica was added. The strength of the polyacrylamide-based gel was enhanced. Silicate gel samples with nanosilica led to a 17% higher reduction in permeability compared to pure silicate gel, and polyacrylamide gel with the addition of nanosilica has almost 43% higher permeability reduction compared to pure polyacrylamide gel.

Effect of modified montmorillonite particles on generation of in-situ W/O emulsion and oil displacement mechanism in enhanced heavy oil recovery

Water-in-oil (W/O) emulsions can enhance the sweep efficiency and control the mobility ratio of oil and water simultaneously in heavy oil development. However, the W/O emulsions formed by heavy oils and injected fluids are prone to be with low phase inversion point and low maximum internal phase volume, which leads to serious tonguing and fingering especially in heterogeneous reservoirs. The authors thus proposed a new method of stabilizing W/O emulsions with modified montmorillonite particles (MMPs) to increase the phase inversion point as well as the internal phase volume to enable economically viable recovery of heavy oils. This paper evaluated the emulsions injected with different types of MMPs in terms of stability, maximum internal phase volume, and rheology. The optimal contact angle and particle concentration for modification were 105° and 3000 ppm, and under such conditions, the maximum internal phase volume fraction of the emulsions was increased to 85% and the viscosity by 40 times. In addition, the selected MMPs were then injected into multiple homogeneous cores of different permeabilities to verify the injectability and the viability to form W/O emulsions via pressure curves and NMR two-dimensional spectrum. The results showed that the modified particles can be injected into cores with permeability above 200 mD, but only in cores with permeability above 500 mD can a significant W/O emulsion be observed. Finally, three sets of heterogeneous core flooding tests were conducted in an online NMR system to determine the reasonable timing for injection of the MMPs and to verify its ability to enhance sweep efficiency by monitoring variations in NMR imaging, oil recovery, water cut, and pressure. Our work provides useful insights into the enhancement of sweep efficiency in heterogeneous heavy oil reservoirs by particle-stabilized W/O emulsions.