Tertiary Mode Research Articles

Surfactant-Nanoparticle Formulations for Enhanced Oil Recovery in Calcite-Rich Rocks.

Aqueous surfactant-nanoparticle mixtures have received great attention recently for promoting a more sustainable and efficient enhanced oil recovery (EOR) process. However, colloidal stability under reservoir conditions is considered a great challenge. In addition, the way synergy operates in EOR is not clearly understood. This study aims to formulate a cost-effective surfactant-nanoparticle mixture in a formation brine for efficient EOR in calcite-rich oil reservoirs. For this, bare silica nanoparticles were covalently grafted using an epoxysilane and blended with two commercial surfactants, namely a zwitterionic alkyl hydroxysultaine (AHS) and a binary zwitterionic-nonionic (ZN) surfactant, for both additional steric stabilization and EOR. The effects of additives alone or their mixtures were examined at solid-fluid and fluid-fluid interfaces to explore their impact on EOR. The surfactant-nanoparticle blend often showed a pH-responsive behavior at solid-fluid and fluid-fluid interfaces with particles serving as carriers or surface activity improvers for surfactant resulting in different extents of rock wettability alteration and emulsification. In oil recovery tests, optimum surfactant concentrations were found to significantly increase crude oil recovery of formation brine by 36 ± 1% original oil in place (OOIP) in secondary spontaneous imbibition which was further enhanced by 14 ± 0.5% OOIP upon adding a low particle concentration (0.01 wt %). The surfactant-nanoparticle formulation was also efficient in producing residual crude oil in tertiary mode (6% OOIP additional oil recovery after formation brine). The oil recovery results disclosed a high dependence on the emulsification ability of the blends with AHS-particle dispersions producing more stable emulsions and thus more crude oil compared to that of ZN.

Production Optimization of Heavy Oil Recovery Utilizing Mo-Ni Based Liquid Catalysts: A Simulation Approach

In recent years, the demand for heavy oil has increased due to its abundant availability and low cost. However, the extraction of heavy oil poses a significant challenge due to its high viscosity and low mobility. Therefore, various methods have been developed to enhance the recovery of heavy oil, including the use of catalysts. This study has created a unique simulation approach that uses liquid catalysts (LCs) to improve heavy oil recovery. In this work, laboratory testing dataset and numerical simulation studies were used to examine the potential of applying LCs as an alternative chemical agent for enhancing heavy oil recovery. CMG-STARS and CMOST modules were used to historical match the laboratory scale results of two sand-pack flooding experiments (water flooding and liquid catalyst flooding in tertiary recovery mode). Moreover, a sensitivity study was conducted to apply a wide range of assumptions to determine the most effective process controlling parameters. Finally, oil production optimization is performed using a genetic algorithm (particle swarm optimization) by selecting the optimum-operating parameters. In comparison to typical water flooding, the results revealed a discernible rise in the heavy oil recovery factor (RF) when injecting LCs. The simulation results showed that the optimized production strategy could increase the ultimate oil recovery by up to 45.06%. The injection rate, slug size, and injection temperature were found to be significant factors in optimizing the production of heavy oil. This simulation approach can be used to optimize the production of heavy oil using acidic Mo-Ni based liquid catalyst in different reservoirs.

Empirical Orthogonal Function Analysis on Long-Term Profile Evolution of Tidal Flats along a Curved Coast in the Qiantang River Estuary, China

Abstract: Tidal flats are dynamic coastal ecosystems continually reshaped by natural processes and human activities. This study investigates the application of Empirical Orthogonal Function (EOF) analysis to the long-term profile evolution of tidal flats along the Jiansan Bend of the Qiantang River Estuary, China. By applying EOF analysis to profiles observed from 1984 to 2023, this study identifies dominant modes of variability and their spatial and temporal characteristics, offering insights into the complex sediment transport and morphological evolution processes. EOF analysis helps unravel the complex interactions between natural and anthropogenic factors shaping tidal flats, with the first three eigenfunctions accounting for over 90% of the observed variance. The first spatial eigenfunction captures the primary trend, while the subsequent two eigenfunctions reveal secondary and tertiary modes of variability. A conceptual model developed in this study elucidates the interplay between hydrodynamic forces and morphological changes, highlighting the rotation and oscillation of tidal flat profiles in response to seasonal variations in hydrological conditions. The findings emphasize the effectiveness of EOF analysis in capturing significant geomorphological processes and underscore its potential in enhancing the understanding of tidal flat dynamics, thereby informing more effective management and conservation strategies for these critical coastal environments.

Tertiary wake mode in flows past elliptic cylinders

Linear stability analysis of the steady flow past elliptic cylinders of different aspect ratio (Ar) has been conducted for the flow Reynolds number (Re) in the range 30–200. A new unstable mode, which we refer as tertiary wake mode, has been discovered. Two other unstable modes (the primary wake mode and the secondary wake mode), already reported in the literature, are also found. The critical Re for the onset of instability of these modes and the corresponding Strouhal number (St) have been reported. Modes that have large growth rates tend to come close to the cylinder surface, and the extent to which they spread downstream in the wake is less compared to the weaker modes. The size of the vortical structures in a mode is inversely related to its St. The change in the characteristics of these modes with respect to change in Ar and Re, as well as their evolution leading to the fully developed flow, has been studied. Selective suppression of the unstable modes is effected using a slip-plate placed on the wake centerline. For Re = 150, it is shown that selective suppression of the unstable modes leads to different fully developed unsteady flows.

How does the presence of an oleic phase influence salt transport during polymer-enhanced low-salinity waterflooding?

Our preceding single-phase experiments demonstrated that polymer enhanced low-salinity waterflooding (PELS) can significantly reduce salt dispersion and improves low-salinity waterflooding (LSWF) performance. In this paper, we extended the research to two-phase fluid flow conditions in the presence of an oleic phase. To assess this quantitatively, a series of two-phase coreflooding experiments using artificial cores were conducted. To eliminate the impact of fluid–fluid and rock–fluid interactions associated with LSWF on salt dispersion, a model, non-polar oleic phase was chosen. The salinity breakthrough results of two-phase corefloods were interpreted using a non-Fickian model based on the Mobile-Immobile Model to infer salt dispersion coefficient. The impact of Partially-Hydrolyzed Polyacrylamide (HPAM) concentration, injection rate, salinity difference, and flooding mode (secondary or tertiary) on salt transport and dispersion through porous media were studied. The results revealed an increase in the salt dispersion coefficient under two-phase conditions by as much as sixfold; taking significantly larger times to displace the high salinity brine. Thus, the optimal HPAM concentration required to effectively suppress mixing was found to be twice (∼400 ppm) as much under the single-phase flow. Reduction of salinity difference also resulted in the reduction of the salt dispersion coefficient by 32%. Moreover, it was observed that in tertiary mode injection where the starting water saturation of the core is higher due to a prior high salinity flooding, the salt dispersion can be increased by more than 21%. These new two-phase results and insights support the possibility of mixing-control under two-phase condition by using PELS and provides a solution to facilitate field implementation.

The impact of grain size heterogeneity on the performance of low-salinity waterflooding in carbonate formations

Low-salinity waterflooding (LSWF) is a proven enhanced oil recovery method for many target fields. The efficiency of this technique depends on both operational factors as well as reservoir settings such as heterogeneity. Micro-scale rock heterogeneity can critically affect the performance of LSWF as it governs the flow path of the injected water, oil-brine-rock contacts and trapping mechanisms, thus sweep efficiency. However, there exist lack of experimental data and detailed understanding of the effect of grain size heterogeneity on LSWF performance. To address this gap, a systematic series of coreflooding experiments were designed using artificial calcite core plugs to investigate the effect of micro-scale heterogeneity, such as grain size and grain heterogeneity, on oil recovery factor by high-salinity waterflooding (HSWF) and LSWF. High salinity formation water, seawater, and diluted seawater were used as injection brines. For this purpose, two relevant grain size ranges (a) from 38 to 75 µm and (b) from 75 to 125 µm were considered to fabricate homogeneous plugs. Heterogeneous core plugs were made by mixing (a) and (b) grain samples. The artificial cores were initialized with the formation brine and crude oil, and aged to restore wettability. Then a set of coreflooding experiments were performed using the mentioned brine samples, in both secondary and tertiary modes by considering a shut-in period.The results reveal that grains size (or micro-scale) heterogeneity has a significant negative impact on both HSWF and LSWF performance and reduces the oil recovery efficiency of HSWF by approximately 15%. This is primarily attributed to the bypassing and entrapment of oil in heterogeneous cores. Moreover, the results show that regardless of the grain size, LSWF in homogeneous plugs result in almost similar recovery factors. The key finding of this study is that LSWF in heterogeneous plugs is more effective and recovers almost 10% more oil compared to HSWF. This is attributed to wettability alteration as indicated by the reduction of water relative permeability endpoint and delay of breakthrough time. The improvement in oil recovery was consistent with the results obtained from the flotation tests and dynamic IFT measurements. However, although LSWF outperforms HSWF in heterogeneous cores, the ultimate recovery factor becomes less in these plugs. Besides, superior performance of secondary flooding was observed compared to tertiary mode for LSWF, especially in cores with heterogeneous grain sizes, leading to almost 10% higher recovery factor.The novel insights gained through this research help identify the proper targets for LSWF in terms of small-scale heterogeneity and can be potentially applied in other water-based EOR techniques.

FRP–soil interfacial mechanical properties with molecular dynamics simulations: Insights into friction and creep behavior

AbstractThe fiber‐reinforced polymer (FRP) has attracted much attention in civil engineering due to its durability and cost‐effectiveness. The soil–FRP structure interface plays an essential role when the FRP is adopted in geotechnical engineering, but its fundamental interfacial behavior remains unclear. In the present study, the atomistic models of silica representing sand, water film representing the lubricated condition, and cross‐linked epoxy representing FRP are constructed to investigate the FRP–sand interfacial properties at the nano‐scale through molecular dynamics (MD) simulations. The epoxy model geometry and forcefield are first validated by comparing the thermodynamic and mechanical parameters with experimental and simulation measurements. The silica–epoxy interfacial tribological and rheological behavior is then explored by conducting friction and creep simulations under dry and lubricated conditions. The friction force has been found linearly dependent on the normal load and increases with the sliding velocity while decreasing against water content. The modified Amontons law for the adhering surface could describe the silica–epoxy interfacial friction well. The shear stress level influences the creep characteristics with primary, secondary, and tertiary (or rupture) creep modes. The results of this study at the nano‐scale can be further developed to enhance the current contact laws of sand–FRP structure in micromechanics‐based modeling approaches.

Investigating the impact of wettability heterogeneity on tertiary oil recovery by foam flooding: A macroscopic visualization study

The gas injection is a widely used technique for improving oil recovery; however, in reservoirs with heterogeneous characteristics, the injection of gas in the form of foam is more promising. Due to the heterogeneous nature of oil reservoirs, we compared the foam flow performance at the tertiary mode with that of gas injection using an anionic surfactant AOS and a cationic surfactant CTAB. Glass bead packed models were used with different patterns of wettability heterogeneity including oil-wet, water-wet, stripe, layer, and quadrant. While gas injection in heterogeneous models produced only 10–15% of the waterflood residual oil, foam injection could control the gas mobility and recover almost 30–50% of the residual oil. The most stable foam was formed in the water-wet porous medium whereas the lowest stable foam was visually observed in the oil-wet porous medium due to the presence of more residual oil. However, the synergistic effect of wettability alteration and piston-wise displacement of the foam front improved oil recovery even in the oil-wet medium compared to the gas injection scenarios. Among all heterogeneous models, the highest oil recovery was achieved in the layer model and its oil recovery profile was compatible with that of the water-wet homogeneous model. Conversely, we found that positioning an oil-wet layer strongly declined foam flow performance as was observed in both layer and quadrant models. Compared to the AOS foam, the CTAB foam was more stable and efficient in recovering waterflood residual oil in the models under study.

Novel sulfonated rGOHfO2/PVDF hybrid nanocomposite ultrafiltration membrane towards direct potable reuse water production

Using wastewater to produce safe and reliable reclamation water is a sustainable means of reducing water scarcity. Membrane technology can be a viable path for producing advanced treated water from wastewater. Numerous three-dimensional metal oxide nanoparticles with graphene oxide (GO) have been evaluated in membrane fabrication. On the other hand, there are no reports on the use of GO combined with hafnium oxide (HfO2) for the fabrication of ultrafiltration (UF) membranes to produce direct potable reuse (DPR) water. In this study, rGOHfO2 (reduced GOHfO2) was synthesized using a microwave method. A novel sulfonated rGOHfO2 (SrGOHfO2) nanocomposite was fabricated and added to the polyvinylidene fluoride (PVDF) to develop advanced nanohybrid UF membranes toward the production of DPR water and improve dispersibility and hydrophilicity. The incorporation of SrGOHfO2 into PVDF membranes had very positive effects on hydrophilicity, MWCO, and morphology. The P-SGOHf-2 membrane (0.2 wt % SrGOHfO2) exhibited excellent pure water flux of approximately 301 ± 3% and 133.3 ± 2% than PVDF and P-GOHf membrane, respectively. The P-SGOHf-2 membrane showed high separation efficiency up to 94 ± 1% and 98 ± 04% towards humic acid (HA) and bovine serum albumin (BSA), respectively. The superior antifouling properties were observed in the SrGOHfO2 incorporated membranes compared to the P-GOHf and PVDF membranes, with a 2.9% irreversible fouling ratio (Rir) and a 97.1% flux recovery ratio (FRR) for the P-SGOHf-2 membrane. The excellent performance of the P-SGOHf-2 membrane was attributed to the larger number of sulfonic acid groups (-SO3H) in the SrGOHfO2 nanocomposite. In the tertiary UF membrane filtration mode operation using the secondary effluent of the field-scale wastewater treatment plant, the P-SGOHf-2 membrane performed high flux with reliable effluent quality (154 ± 5L m−2 h−1, 0.26 ± 0.03 NTU, no pathogens), while it exhibited lower membrane resistances during filtration. These advanced nanohybrid membranes can be a sustainable, viable alternative technology compared to the traditional tertiary treatment processes that utilize expensive and complex multi-step processes to produce DPR water.

Insights into the Effects of Pore Structure, Time Scale, and Injection Scenarios on Pore-Filling Sequence and Oil Recovery by Low-Salinity Waterflooding Using a Mechanistic DLVO-Based Pore-Scale Model

Summary Despite the proven advantage of the low-salinity waterflooding (LSWF) technique, mechanistic understanding of the underlying phenomena at pore-scale remains uncertain. Hence, the corresponding models have limited predictability. In this study, wettability alteration via electrical double-layer (EDL) expansion is captured in a pore-scale model using a multispecies, multiphase computational fluid dynamics simulator. A combination of a pore-doublet and snap-off model is used to evaluate the low-salinity effect (LSE) in two geometries with different pore-throat size distributions. Contact angle is calculated intrinsically within the model using the concept of disjoining pressure through the implementation of the Derjaguin-Landau-Verwey-Overbeek (DLVO) theory and augmented Young-Laplace equation. The results illustrate that even in a simple pore structure, various pore-filling sequences and recoveries are obtained based on the pore geometrical factors, time effects, backward mixing, and injection scenarios. Secondary LSWF results in higher ultimate oil recovery since both small and large pores are accessible to flow and breakthrough is delayed, giving more time for more efficient displacement. Regarding the pore-throat geometry, the case with larger pores connected via larger throats generally exhibits higher ultimate recoveries. However, the geometry with larger pores connected by small throats results in higher incremental recovery via tertiary LSWF. Moreover, an optimal time scale exists in secondary LSWF due to the snap-off phenomenon, while faster LSE results in higher recovery in tertiary mode. The proposed model is capable of mechanistically capturing and predicting LSE and its subsequent flow dynamics, which exhibits a higher recovery factor by LSWF compared to the commonly used linear wettability model. Thus, this approach improves the predictive capability of the previous models as it does not require contact angle data and arbitrary interpolation schemes.

Carbonated Smart Water Injection for Optimized Oil Recovery in Chalk at High Temperature

Finding cost-efficient ways of increasing oil production with a low carbon footprint is the new challenge for the petroleum industry that wants to meet the net-zero emission goals by 2050. Smart water injection is an EOR process that increases oil production and delays water breakthrough by wettability alteration. Seawater is a smart water in chalk reservoirs, being especially effective at high temperatures. Different studies have shown that the effectiveness of seawater can be further improved by modifying the ion composition before injection. Carbonated water (CW) has been proposed as a potential EOR fluid. In addition to producing extra oil, the reduction of greenhouse gas (CO2) in the atmosphere can be achieved by using carbonated smart water as an injection fluid. The main mechanism behind increased oil recovery by injecting carbonated water is believed to be oil viscosity reduction and swelling, as the CO2 is transferred from the aqueous phase to the oil phase. Wettability alteration has also been proposed as a possible mechanism, and this hypothesis is further investigated in this study along with other proposed mechanisms. Stevns Klint outcrop chalk was used in this study, this material is recognized as an excellent analogue for North Sea chalk reservoirs. Optimized oil recovery by carbonated water in chalk was investigated at a high temperature (130°C) by flooding carbonated formation water (CFW) and carbonated seawater (CSW), to be compared with high saline formation water (FW) and seawater (SW) flooding. The oil/brine/rock/CO2 interactions were tracked by measuring the pH of the produced water (PW) and by identifying any mineralogical changes by SEM (Scanning Electron Microscope) and EDX (Energy Dispersive X-Ray) analyses. The solubility of CO2 in different brines was measured and compared with simulation data performed by PHREEQC. The diffusion of CO2 from the aqueous phase to the oil phase was analysed to check if enough CO2 can be diffused from the carbonated water into the oil phase. By flooding CSW in both secondary and tertiary modes, a slight increase in the oil recovery was observed and was found to be the best performing brine. The oil recovery was also slightly increased using CFW in tertiary mode after FW which does not behave like smart water for carbonates. The solubility of CO2 was low and increased by increasing pressure and decreasing brine salinity. The acidity of CW did not increase by increasing pressure. No changes in pore surface minerals were observed after CW flooding, confirming limited mineral dissolution. A mass transfer of CO2 from the brine phase to the oil phase was confirmed in the experimental work, but a significant amount of CO2 remained in the brine phase. The main mechanism behind this extra oil observed using CW is most likely not linked to oil swelling and viscosity reduction or mineral dissolution which could affect the porosity and the permeability of the rock system. Wettability alteration is a more likely explanation but needs to be looked further into for confirmation.

Laboratory Investigation of Nanofluid-Assisted Polymer Flooding in Carbonate Reservoirs

In the petroleum industry, the remaining oil is often extracted using conventional chemical enhanced oil recovery (EOR) techniques, such as polymer flooding. Nanoparticles have also greatly aided EOR, with benefits like wettability alteration and improvements in fluid properties that lead to better oil mobility. However, silica nanoparticles combined with polymers like hydrolyzed polyacrylamide (HPAM) improve polymer flooding performance with better mobility control. The oil displacement and the interaction between the rock and polymer solution are both influenced by this hybrid approach. In this study, we investigated the effectiveness of the injection of nanofluid-polymer as an EOR approach. It has been observed that nanoparticles can change rock wettability, increase polymer viscosity, and decrease polymer retention in carbonate rock. The optimum concentrations for hydrolyzed polyacrylamide (2000 ppm) and 0.1 wt% (1000 ppm) silica nanoparticles were determined through rheology experiments and contact angle measurements. The results of the contact angle measurements revealed that 0.1 wt% silica nanofluid alters the contact angle by 45.6°. The nano-silica/polymer solution resulted in a higher viscosity than the pure polymer solution as measured by rheology experiments. A series of flooding experiments were conducted on oil-wet carbonate core samples in tertiary recovery mode. The maximum incremental oil recovery of 26.88% was obtained by injecting silica nanofluid followed by a nanofluid-assisted polymer solution as an EOR technique. The application of this research will provide new opportunities for hybrid EOR techniques in maximizing oil production from depleted high-temperature and high-salinity carbonate reservoirs.

Ion Composition Effect on Spontaneous Imbibition in Limestone Cores

Studies on low salinity oil recovery have accelerated in recent years. Detailed focus has been put on understanding competing underlying mechanisms behind observed improved oil recovery. The main aim in this work is to tune the ionic composition of imbibing brine to maximize the oil recovery from spontaneous imbibition experiments on limestone outcrop cores, as an analogue for an offshore Brazilian carbonate reservoir. Improved spontaneous imbibition experiments with smooth natural brine exchange between primary, secondary, and tertiary fluid imbibition cycles at high temperatures were accomplished, reducing systematic errors in the recovery data. Contact angle, zeta potential, and interfacial tension measurements completed the data set. It was observed through improved oil recovery from tertiary imbibition that holistic dilution of synthetic seawater (10 times) had limited the impact on improved oil recovery on our limestone cores. However, selective dilution of synthetic seawater with respect to the NaCl content resulted in significantly improved oil recovery. In line with this observation, brines depleted in NaCl and enriched in Mg2+ and SO42– ions were tested and resulted in improved oil recovery in tertiary modes. A positive test on the role played by the SO42– ion was recorded when synthetic seawater was enriched 2 and 4 times in SO42– ion concentration; however, substantial recovery increases required an increased Mg2+ content. Contact angle measurements on polished rock chips, cut and shaped from the same rock material and aged in brines at 96 °C, confirmed the observed results, where zeta potential measurements at both 25 and 70 °C showed inconclusive results.

Enhanced oil recovery in carbonate rocks using seawater spiked with copper chloride: Imbibition experiments

It is widely accepted that oil recovery during waterflooding can be improved by modifying the composition of the injected brine, typically by depleting the total salinity or altering potential determining ions (PDI) such as: Ca2+, Mg2+, and SO42− concentration. Numerous laboratory experiments and field tests have demonstrated this effect in both clastic and carbonate rock Samples and reservoirs. However, some authors have found alternative ions, such as phosphate (PO42−) and borate (B(OH)4-) which, in some cases, presented additional recovery and have thus opened the discussion for potential alternative ions to enhanced oil recovery. With this in mind, copper ion's potential for enhanced oil recovery (EOR) was studied, combining different conditions usually employed on smart water experiments, such as depleting the total salinity and removing the PDI to highlight the real effect of copper on additional oil recovery. The investigation was carried out with Brazilian pre-salt reservoir Samples in imbibition experiments using Amott cells at ambient pressure and 63 °C. The evaluation of the copper effect on oil recovery for coreflooding was proved in a previous paper by Bernadinelli et al. (2021), however the analysis with imbibition experiments in this study aim to clarify the effect of copper on the capillary pressure, by analyzing the eventual additional oil production. These Samples were prepared and aged, and the oil production was monitored during the experimental time. The experiments were carried in four sequences to evaluate the effect of copper on oil recovery, consisting first of salinity reduction from 0% of sodium chloride to 100% of the original amount in the seawater (SW), followed by the removal of PDI salts, the study of the production mode (secondary or tertiary), and the analysis of the copper chloride concentration on the final recovery. The results using copper at the secondary recovery showed remarkable increases (from 6.3% to 10.0%) of the original oil in place (OOIP) compared to the oil recovered from the formation water (FW). In tertiary mode, the best recoveries occurred at salinities between 8 and 18 kppm and copper chloride (1 g/L), and presented increasing recoveries 3.9%, 5.8%, and 9.3% of OOIP. This work presents an initial investigation on the use of copper as an active ion for the smart water effect and sheds light on its effect on both secondary and tertiary modes for strategies of recovery that use soaking methods and also for fractured reservoirs.

Experimental study of secondary and tertiary modes combined low salinity water and polymer flooding in sandstone porous media

AbstractCombined low salinity water (LSW) and polymer (LSP) flooding is the most attractive method of enhanced oil recovery (EOR). Considerable research has investigated effective mechanisms of LSP flooding. In this study, 10 laboratory core flood tests were carried out to evaluate the effects of LSW injection into samples without any clay particles, the timing of LSW injection, and the advantages of adding polymer to the injection water for EOR. Secondary and tertiary LSW injections were performed on sandpack samples with different wettability states and water salinity. Tertiary LSW injection after secondary synthetic seawater (SSW) injection in oil‐wet samples resulted in 13% more oil recovery, while the water‐wet sample showed no effect on the oil recovery. Secondary LSW injection in oil‐wet porous media improved oil recovery by 8% of the original oil in place (OOIP) more than secondary SSW injection. Tertiary LSP flooding after secondary SSW injection in the oil‐wet sample provided a recovery of 67.3% of OOIP, while secondary LSW injection followed by tertiary LSP flooding yielded the maximum ultimate oil recovery of about 77% of OOIP. The findings showed that the positive EOR effects of LSW and LSP flooding were the results of wettability alteration, pH increase, improved mobility ratio, better sweep efficiency, and oil redistribution. In addition, results showed that wettability alteration is possible without the presence of clay particles. The findings of this study can help for a better understanding of fluid propagation through the porous media and an investigation of delays in reaching ultimate oil recovery.

Relevance of zeta potential as a tool for predicting the response of controlled salinity waterflooding in oil–water-carbonate systems

Zeta potential has been proposed as a key parameter for predicting the response of controlled salinity waterflooding, as correlation with additional oil recovery has previously been established. However, it is unclear if there is a causal effect and if this parameter can be used as a unique predictive tool. We provide new insights with a detailed investigation into the role of the change of polarities of oil/water/rock interfaces on the additional oil recovery. Core flooding experiments with streaming potential and electrophoretic mobility measurements were performed to obtain insights into the electrostatic interactions that occur during oil recovery on Estaillades rock. Two different injection scenarios were followed in one crude oil/brine/rock (COBR) system: one conventional injection with decreasing salinity and one inverse injection with increasing salinity.Results indicated that oil recovery in secondary mode was more important using formation brine compared to low salinity brine. Also, almost no additional oil recovery was observed in tertiary mode irrespective of the injection scenario. Rock/water zeta potential was found positive in formation brine, and negative in the low salinity brines. The determination of oil/water polarity was more difficult as many inconsistencies between streaming potential and electrophoretic mobility measurements were observed. We propose several explanations for these discrepancies, including that the difference in zeta potential at fully water saturation and at residual saturation is not necessarily dependent on oil polarity as it can be induced by a change in rock exposed surface and in the distribution in water flow paths during measurements. The overall results suggest that zeta potential cannot be used as a unique indicator to predict the low salinity response of a COBR system.

An analytical model for performance prediction of miscible flooding methods

The main target of this study is to develop fast and efficient analytical model that can predict reservoir performance under the implementation of miscible flooding processes. The developed model uses upgraded fractional flow theories and several areal sweep efficiency models. Unlike previous attempts in this topic, the developed model accounts for reservoir instability factors such as reservoir heterogeneity, viscous fingering behavior and gravity segregation. In addition, it accounts for different Enhanced Oil Recovery (EOR) injection strategies including continuous solvent injection and simultaneous Water Alternate Gas (WAG) injection in both secondary and tertiary miscible displacement modes. Moreover, the model has been extended to account for different injection patterns including line drive and 5-spot. The model was validated against two actual field applications: (1) the WAG injection pilot project of Slaughter field, and (2) the miscible flooding pilot project of Garber field. The results of the model deviate from the results of the field measurements with a range of 7.3 to 20.4%. This match demonstrated the ability and the strength of the developed model. The model utilizes a limited set of input data that is available in the field at the early stages of the reservoir life. Therefore, it can be used as a pre-simulation tool to support the decision-making during the critical technology selection phase.

Analysis of the Composition of Substrate for Industrial Fermentation of Agaricus bisporus Based on Secondary and Tertiary Fermentation Mode Composition Analysis of Industrial Fermentation Substrates of A. bisporus

In this study, changes in metabolites during the fermentation of Agaricus bisporus compost under the Shanghai Lianzhong secondary fermentation method and Jiangsu Yuguan tertiary fermentation method were analysed by applying gas chromatography–mass spectrometry (GC–MS) to understand the differences in metabolites under different fermentation methods and find metabolic markers at different fermentation stages in different fermentation methods. The results showed that 1002 compounds were identified. Based on the differential metabolites from pathways of significant enrichment, it was found that L-aspartic acid and 5-aminobenzolevulinic acid could be used as potential metabolic markers to evaluate the phase 2 fermentation method of Shanghai Lianzhong and the phase 3 fermentation method of Jiangsu Yuguan, respectively. This study provides a reference for the preparation of quality-stable fermentation materials and further understanding of the cultivation of A. bisporus with fermentation materials.

The Role of Immiscible Fingering on the Mechanism of Secondary and Tertiary Polymer Flooding of Viscous Oil

Immiscible viscous fingering in porous media occurs when a low viscosity fluid displaces a significantly more viscous, immiscible resident fluid; for example, the displacement of a higher viscosity oil with water (where μo > > μw). Classically, this is a significant issue during oil recovery processes, where water is injected into the reservoir to provide pressure support and to drive the oil production. In moderate/heavy oil, this leads to the formation of strong water fingers, bypassed oil and high/early water production. Polymer flooding, where the injected water is viscosified through addition of high molecular weight polymers, has often been applied to reduce the viscosity contrast between the two immiscible fluids. In recent years, there has been significant development in the understanding of both the mechanism by which polymer flooding improves viscous oil recovery, as well as in the methodologies available to directly simulate such processes. One key advance in modelling the correct mechanism of polymer oil recovery in viscous oils has been the development of a method to accurately model the “simple” two-phase immiscible fingering (Sorbie in Transp Porous Media 135:331–359, 2020). This was achieved by first choosing the correct fractional flow and then deriving the maximum mobility relative permeability functions from this. It has been proposed that central to the polymer oil recovery is a fingering/viscous crossflow mechanism, and a summary of this is given in this paper. This work seeks to validate the proposed immiscible fingering/viscous crossflow mechanism experimentally for a moderately viscous oil (μo = 84 mPa.s at 31 °C; μw = 0.81 mPa.s; thus, (μo/μw) ~ 104) by performing a series of carefully monitored core floods. The results from these experiments are simulated directly to establish the potential of our modified simulation approach to capture the process (Sorbie, et al., 2020). Both secondary and tertiary polymer flooding experiments are presented and compared with the waterflood baselines, which have been established for each core system. The oil production, water cut and differential pressure are then matched directly using a commercial numerical reservoir simulator, but using our new “fractional flow” derived relative permeabilities. The use of polymer flooding, even when applied at a high water cut (80% after 0.5 PV of water injection), showed a significant impact on recovery; bringing the recovery significantly forward in time for both tertiary and secondary polymer injection modes—a further 13–16% OOIP. Each flood was then directly matched in the simulator with excellent agreement in all experimental cases. The simulations allowed a quantitative visualisation of the immiscible finger propagation from both water injection and the banking of connate water during polymer flooding. Evidence of a strong oil bank forming in front of the tertiary polymer slug was also observed, in line with the proposed viscous crossflow mechanism. This work provides validation of both polymer flooding’s viscous crossflow mechanism and the direct simulation methodology proposed by Sorbie et al. (Transp Porous Media 135:331–359, 2020). The experimental results show the significant potential for both secondary and tertiary polymer flooding in moderate/heavy oil reservoirs.

Qualitative assessment of improved oil recovery and wettability alteration by low salinity water injection for heterogeneous carbonates

This study aims to evaluate the qualitative potential for low salinity water injection (LSWI) to alter the wettability and increase oil production in heterogeneous oil-wet coquina cores (one of the facies of Pre-Salt reservoirs) in relevant conditions of brine salinity, temperature, and initial wettability. We also aimed to verify the impact of micro-porosity fraction on oil recovery. Finally, we verified whether the presence of micro-dispersion in the oil phase upon contact with low salinity would have a positive correlation with improved oil recovery due to low salinity water injection.To achieve these objectives, we performed zeta-potential experiments to evaluate the charges at the oil-brine and brine-rock interfaces that affect rock wetting state and contact tests to test for the presence of micro-dispersions in the oil phase and potential for LSWI. A series of spontaneous imbibition and coreflood experiments were performed to calculate the Amott index and evaluate wettability of coquinas in core-scale as a function of brine salinity. Tertiary and secondary low salinity waterfloods were carried out to investigate whether a diluted desulfated seawater would increase oil production in coquina cores. The effect of predominance of macro-, meso-, and micro-porosity on secondary low salinity waterflood was also evaluated. Our results have shown that heterogeneity had a greater impact on recovery factor compared to brine salinity. Oil recovery for low salinity brine for a core with predominance of macro-pores was smaller than for cores with higher fraction of micro-pores flooded with FW and DSW. Low-salinity oil recovery was also smaller than high-salinity was for core with microporosity but with presence of dead-end pores. Secondary injection of low-salinity using the same core with large fraction of micro-porosity showed that it accelerated oil production compared to high-salinity brine. We have also observed that LSWI resulted in increased oil recovery in coquinas both in tertiary mode (average 10%) compared to FW/DSW and secondary mode using the same core (18% compared to FW) due to wettability alteration. This result was supported by spontaneous imbibition as well as zeta-potential results. The contact test between crude oil and low salinity brine resulted in a micro-dispersion ratio of 11.7, showing that a positive oil is likely to result in improved oil recovery due to low salinity injection. Despite the increased oil recovery seen during the tests, the results showed that oil production in tertiary mode was significantly delayed (after 4 PV), likely due to adverse oil/water viscosity ratio and water dispersion due to mixing between low- and high-salinity brines. We observed that for the shorter more oil-wet core significant oil production was measured during bump flow with both high-salinity and low-salinity brines, due to capillary end effects. This could mean that residual oil saturation was not achieved during high-salinity water injection and an overestimation of recovery factor due to low-salinity was seen.