Water-wet Conditions Research Articles

Electro-kinetically tailored interfaces for chemical enhanced oil recovery in carbonates

SmartWater flooding through the injection of optimized chemistry water has lately become an attractive proposition for improved/enhanced oil recovery (IOR/EOR) in carbonate reservoirs. The wettability alteration towards water-wet conditions caused by favorable surface charge alteration is identified as the main mechanism responsible for oil recovery. In this experimental investigation, the impact of SmartWater/surfactant synergy on wettability alteration was thoroughly studied by measuring zeta-potentials at calcite/brine and crude oil/brine interfaces using electrophoresis technique. Different types of surfactants are considered including: anionic, amphoteric and non-ionic. Four different low salinity water recipes including SmartWater (10-times reduced high salinity water) as well as the high salinity water (HSW) were chosen for zeta potential measurements. The results showed that both anionic surfactants increased the magnitude of the negative zeta-potentials at the interfaces by almost same order of magnitude. The negative zeta-potentials were increased the most with anionic surfactants in the low salinity NaCl brine, from (−15 to −21 and up to −37 mV) at the calcite interface and from (−6 to −19 mV) at the oil interface. SmartWater showed relatively higher negative zeta-potentials for calcite when compared to low salinity Na2SO4 brine and HSW in the presence of anionic surfactant. These results indicate that both NaCl brine and SmartWater can synergistically combine with anionic surfactants for effective wettability alteration in carbonates. Amphoteric surfactant showed a negligible impact on electrical double layer (EDL) expansion and consequently the wettability alteration. The nonionic surfactant induced electrostatic repulsion forces at both calcite/brine by shifting the zeta potentials from (+5.9 to −6.3 mV) and crude oil/brine interface from (−0.2 to −4.7 mV) respectively in high salinity water. As a result, nonionic surfactant can be considered as the best chemical formulation to reduce interfacial tension and cause wettability alteration in conventional chemical flooding processes. The negligible impact of adding surfactant chemicals on the measured di-electric constant of different brines confirmed the robustness of zeta-potential values reported in this study. This work for the first time evaluated the synergistic effects of different brines including the SmartWater with surfactant chemicals by measuring zeta-potentials at calcite/brine and oil/brine interfaces. The optimally suited water recipes were identified to synergistically combine with these chemicals to enhance wettability alteration in carbonates. The new knowledge gained from this electro-kinetic study will provide practical guidance on how to design efficient chemical flooding processes for wettability alteration and enhanced oil recovery in carbonates.

Wettability effects on mobilization of ganglia during displacement

Mobilization of trapped ganglia is of fundamental importance in two-phase displacement. Wettability alteration could be an effective approach to mobilizing ganglia, yet its feasibility as well as the impact of wettability in general lacks study. We investigate the wettability effects on trapped ganglia by theoretical analysis and numerical simulations for both fixed and altering wettability. For fixed wettability, it is found out that the critical pressure to mobilize trapped ganglia is symmetric about and usually peaks at the neutrally wet conditions (for simplicity, the invading and defending fluid are referred to as water and oil), but mobilized ganglia favor more water-wet conditions to be further displaced. This is due to the difference in the evolvement of ganglia after initial mobilization under different wetting conditions: water-wetness contributes to the cooperative advancing of multiple interfaces, making ganglia continue moving as a whole, while oil-wetness leads to Haines jump in a single throat, which easily breaks up ganglia into smaller ones and leaves them trapped again. For altering wettability from oil-wet to water-wet through the transport of certain solute, we for the first time identify two crucial factors for the mobilization of ganglia. First, only the heterogeneous wetting state during the dynamic altering process enables the initial mobilization, whereas a step-wise alteration has little effect. Second, ganglia have to be able to merge with one another during the time window of the altering process for further displacement. Otherwise, an isolated trapped ganglion can only have limited mobilization at first by wettability alteration, and gets trapped again when the alteration is complete.

Triple-layer surface complexation modelling: Characterization of oil-brine interfacial zeta potential under varying conditions of temperature, pH, oil properties and potential determining ions

Low salinity water flooding (LSWF) is a popular enhanced oil recovery technique. Among factors that affect the performance of LSWF, geochemical interaction at the oil-brine interface and the associated enterokinetic properties plays a prominent role. This work presents a triple-layer surface complexation model for predicting the zeta potential of the oil-brine interface. We improve upon previous modelling studies by incorporating the effects of (1) temperature variation, (2) basic (-NH) oil surface group interactions (3) adsorption of sodium ions on outer and inner Helmholtz planes and (4) the presence of sulphate ions in brine. Model validation against published experimental data shows model accuracy between 66% and 99%. The model displays higher accuracies at lower salinities (making it particularly suited for LSWF applications), intermediate pH and higher total acid number. In addition, a correlation between (-NH) site density and total acid/base numbers is proposed. A sensitivity study performed utilising the developed model showed that higher sulphate concentration in the brine and elevated temperature makes the zeta potential at the oil-brine interface more negative. In addition, the sensitivity study indicates that a higher concentration of basic polar oil compounds is less favourable as it may result in less water-wet conditions in the reservoir.

Wettability alteration of locally synthesized cationic gemini surfactants on carbonate rock

Carbonate reservoirs are mostly oil-wet and tend to be naturally fractured, leaving a large portion of oil inside the rock matrix after secondary recovery. Cationic surfactants that combine interfacial tension (IFT) reduction, wettability alteration, and low adsorption are potential efficient materials for carbonate reservoirs. Gemini surfactants are known for reducing IFT and altering wettability at a much lower concentration than conventional surfactants. This study focuses on the wettability alteration performance of 14 locally synthesized cationic gemini surfactants and the influencing factors. Contact angle results showed that, due to molecular structural differences, their wettability alteration performance varied widely from weak to strong. Surfactant with one phenyl group in the spacer had the best wettability alteration performance that changes oil-wet rock to water-wet condition. An increase in carbon atom number in the straight-chain spacer had negligible influence. However, when unsaturation was introduced to the spacer, the wettability alteration of surfactant changed from good to poor. Compared to the spacer structure, counter-ion had a less significant influence. Br- showed better influence on wettability alteration than Cl-. Wettability alteration performance of surfactants was also influenced differently by different salts. For low permeability carbonate rock, the wettability alteration performance of surfactants is an important parameter. Surfactants that showed better wettability alteration performance obtained a higher oil recovery rate from spontaneous imbibition experiments.

Coupled influence of wettability alteration and geometry on two-phase flow in porous media

The objective of this paper is to investigate the interplay between wettability alteration and domain geometry in influencing the pore-scale displacement and trapping mechanisms of two-phase flow in porous media. A new wettability alteration algorithm is introduced to quantify and track the spatial and temporal variability of the wettability state of every pore. Simulations in an initially oil-wet domain are conducted using the lattice Boltzmann model while utilizing the wettability alteration algorithm to capture the new wettability states. The simulations are then resumed under the new generated wettability states to investigate the coupled impacts of wettability alteration and domain topology on the resulting pore-scale displacement behavior. We observe varying degrees of improvements in the oil phase fractional flow as the wettability state is varied towards water-wet conditions influenced by the domain geometry, capillary number, and phase saturation. Significant heterogeneity, increased surface roughness, and the prevalence of narrower pore spaces in the rock sample in comparison to the spherepack increase the percentage of trapped oil ganglia. As a result, wettability alteration results in varying degrees of oil remobilization events, followed by coalescence with the main flow path, especially at higher capillary numbers. Moreover, oil phase fractional flow at higher oil saturation becomes influenced primarily by the increased phase connectivity, and improvements due to wettability alteration become less significant. Similar displacement mechanisms are observed in both domains, controlled primarily by the wettability distribution and the local pore geometry. However, the resulting flow pathways, which dictate the overall flow behavior, are controlled by the frequency of various displacement mechanisms and are a function of the domain geometry. The observations in this study highlight the complex interactions between wettability heterogeneity and pore geometry in influencing pore-scale two-phase flow. The wettability alteration algorithm introduced can be used to optimize pore-scale displacement processes by providing a framework to track the locations and the relative degree of wettability alteration, enable automatic wettability alteration, and detect trapped ganglia without the need for post-processing.

Assessment of two-phase relative permeability hysteresis models for oil/water, gas/water and gas/oil systems in mixed-wet porous media

Accurate determination of relative permeability curves and their hysteresis is vital for reliable prediction of the performance of oil and gas reservoirs under enhanced recovery processes. Two out of the three available approaches to simulate three-phase relative permeability hysteresis are based on two-phase hysteresis. A few options (e.g., Carlson, Killough and Jargon models) are available in commercial reservoir simulators to account for hysteresis in relative permeability curves under two-phase flow. These models are based on the assumptions of water-wet state of the rocks, while most of the reservoir rocks are mixed-wet. As a result the aim of the present work is to evaluate the performance of these hysteresis models for mixed-wet systems. In addition to the above models, more recent ones such as Beattie et al., Kjosavik et al., Spiteri et al. are also evaluated by coupling an in-house MATLAB code with the Eclipse simulator. The assessments of models are performed by comparing their predictions with those of previously reported comprehensive set of experimentally measured relative permeabilities for different two-phase systems. All possible two phase fluid/fluid systems i.e. oil/water, gas/water and gas/oil are considered. The interfacial tension in the case of oil/gas system is extra low (i.e. 0.04 mN.m−1) and it represents near-miscible condition. It is concluded that hysteresis models developed by Killough and Carlson are unable to accurately predict hysteresis effect on relative permeability in oil/gas system under extra low IFT and mixed-wettability. However, either of Killough and Carlson models could provide satisfactory results in gas/water and oil/water systems, respectively. Beattie et al. model that is not used in Eclipse gave a better fit to experimental data in oil/gas system, but it couldn't provide a suitable fit with experimental data in the cases of gas/water and oil/water systems. For different fluids systems, Kjosavik et al. model results were approximately close to the Killough model during the imbibition process and Beattie et al. during the drainage process. Even the results of the best models in each category of the two phase systems are not very satisfactorily. This study highlights the lack of a versatile hysteresis model to capture the hysteresis effect in all possible two phase systems for the mixed-wettability. As a result it is vital that modified or even novel hysteresis models in the case of mixed-wet system be developed.

Impact of oil and wettability on foam-assisted conformance control in a Middle Eastern carbonate reservoir

Gas injection has been evaluated and implemented in the large carbonate oil field located offshore Qatar as water alternating gas or WAG. It has been seen that WAG is economically viable and a robust enhanced oil recovery (EOR) method for homogenous formations. However, using WAG in heterogeneous parts of the field has not been attempted due to issues like early gas breakthrough and unfavourable sweep efficiency. Hence, it was decided to design a foam-assisted WAG system that can provide the required conformance control to mitigate those issues and expand the use of WAG. A complete laboratory programme was carried out to screen the best foaming surfactant formulation that resulted in the selection of environmentally friendly, Alkyl polyglucoside (APG) surfactant. Surfactant testing involved foamability in porous media under oil-wet and water-wet conditions in presence of residual oil to gas flood. The chosen surfactant showed good foam strength in both cases with effective mobility reduction factors (MRF) above 20. The impact of mobile oil was also observed by co-injecting oil during linear core flood experiments, which clearly showed that good foam strength could be achieved in a lower flow fraction of mobile oil with foam. Additionally, boosting of foam strength using amphoteric Lauryl Betaine (LB) surfactant was also performed. The formulation with APG/LB (70%/30%) gives foam boosting of 2.5 times compared to foam strength using APG alone. Additionally, it was shown that altering wettability using a nonionic Tergitol surfactant (TGT-1) as pre-flush and then injecting APG-5 surfactant and methane resulted in foam strength, which is 1.5 times higher than observed in oil-wet conditions.

Pore Network Modeling of Oil–Water Flow in Jimsar Shale Oil Reservoir

The oil–water two-phase flow mechanism is the critical issue for producing shale oil reservoirs after huge-volume hydraulic fracturing treatment. Due to the extremely low permeability of the shale matrix, the two-phase experimental measurement is impossible for shale samples. In this work, a pore network model is proposed to simulate steady-state oil–water flow with mixed wettability under consideration. The model is first applied in Berea sandstone, and the calculated relative permeabilities are validated with experimental studies for different wettability scenarios. Then, the three-dimensional FIB-SEM imaging of the Jimsar shale sample is used to extract a representative shale pore network with 13,419 pores and 31,393 throats. The mean values of pores and throats are 29.75 and 19.13 nm, and the calculated absolute permeability is 0.005 mD. With our proposed model, the calculated relative permeability curves show a high residual oil saturation for all the wettability conditions. Specifically, the oil-wet and mixed-wet conditions yield lower residual oil compared with the water-wet condition. For 50–50 mixed-wet conditions, the water phase relative permeability is much higher for smaller pores being oil-wet than the larger pores being oil-wet.

Synergistic effects between anionic and amphoteric surfactants on promoting spontaneous imbibition in ultra-low permeability reservoirs: Study of mechanism and formula construction

Faster spontaneous imbibition in ultra-low permeability reservoirs ensures higher productivity. Surfactants can promote spontaneous imbibition by creating a strong water-wet condition while keeping the oil-water interfacial tension (IFT) at an intermediate level. In this paper, A surfactant mixture composed of Alpha Olefin Sulfonate (AOS, an anionic surfactant) and Cocoamidopropyl-Hydroxysulfobetaine (CHSB-35, an amphoteric surfactant)CHSB-35 was proposed to promote the spontaneous imbibition rate of Chang 9 reservoir, a sandstone reservoir with high salinity, and ultra-low permeability. The synergistic effects between AOS and CHSB-35 as well as the functional mechanisms were clarified by conducting spontaneous imbibition tests. Experimental results show that when the total surfactant concentration locates in the range of 0.20–0.35 wt%, the oil-water IFT can be lowered to an ultra-low level at a salinity of 11.2 wt%. However, the spontaneous imbibition rate was found to be higher at a total surfactant concentration around 0.10–0.15 wt% with intermediate IFTs and contact angles around 35°. Our results indicated that once surfactant changes the rock wettability from an oil-wet state to a water-wet state, ultra-low IFTs are unnecessary or should be avoided in ultra-low permeability reservoirs. Spontaneous imbibition tests show that the oil production rate of AOS-CHSB-35 mixture is four times faster than simulated water and two times faster than each single surfactant.

Probing the Effect of Wettability on Transport Behavior of Foam for Enhanced Oil Recovery in a Carbonate Reservoir

Foam for enhanced oil recovery in carbonate reservoirs is generally challenging because the oil-wet formation is not favorable for generating and stabilizing the lamellae. With an alkyl-polyglucoside surfactant, a series of foam core flooding experiments both in the absence and in the presence of crude oil were performed on Estaillades limestone, a dual porosity and heterogeneous carbonate presenting reasonable similarities with the reservoir formation. The effects of wettability, surfactant concentration, and foam quality on foam strength were systematically investigated. It is found that the foam strength in the presence of oil is generally smaller than that in the absence of oil, and the foam strength in the oil-wet condition is typically lower than that in the water-wet condition. However, for the water-wet condition, the foam strength can be greatly improved by increasing the surfactant concentration, which is getting closer to that in the absence of crude oil at a sufficiently high surfactant concentration. The combined effect of a high remaining oil saturation and the disadvantageous wettability can further destabilize foam, thereby greatly reducing the foam strength at oil-wet conditions. As a result, the foam flooding under the water-wet condition outperforms that at the oil-wet condition. Furthermore, it is found that the foam behavior at a high gas fraction is more sensitive to the wettability of rock and the foam hysteresis effect.

Exsolution effects in CO2 huff-n-puff enhanced oil recovery: Water-Oil-CO2 three phase flow visualization and measurements by micro-PIV in micromodel

CO2 huff-n-puff is one of the most important methods to enhanced oil recovery, which can simultaneously improve oil production and achieve CO2 geological storage. Due to the fluctuation of formation pressure, water-oil-CO2 three phase migration in porous structures was affected significantly by supercritical CO2 exsolution and expansion. However, the existing research on phase distribution is not enough to understand the mechanism of three-phase migration and the essential processes beneath the phase distribution are still not clear. Here, we developed a high-temperature and high-pressure micro-PIV (Particle Image Velocimetry) and fluorescence visualization experimental system (10 MPa, 50°C), which realized the simultaneous measurement of the velocity field and phase distribution of the water-oil-CO2 three-phase. The multiphase migration process under different wettability conditions during the supercritical-subcritical CO2 exsolution were captured. The results showed that the exsolution induced CO2 bubbles expansion in aqueous and oil phase blocked the preferential migration passage and dominated different multiphase migration mechanisms under different wettability. It was found that in water-wet condition, the aqueous phase can still migrate downstream through the water film between the CO2/oil and the wall, unable to further drive CO2/oil downstream. While in oil-wet condition, the aqueous phase eventually broke through the oil phase blocked at throats and formed a new preferential migration passage, pushing part of the oil phase encapsulating CO2 bubbles downstream. Our research reveals the multiphase migration mechanism beneath the phase distribution under different wettability during the exsolution process of the huff-n-puff, which provides a new insight for CO2 enhanced oil recovery and geological storage.

Full-scale fatigue simulation of the deterioration mechanism of reinforced concrete road bridge slabs under dry and wet conditions

This study investigates the deterioration process and mechanism of reinforced concrete (RC) slabs in road bridges under dry and stagnant water (wet) conditions. Previous studies used a simple-plate model (SPM) to predict the fatigue life of RC decks by considering conservative assumptions for safer assessment under different environmental processes. To obtain a more detailed analysis and clarify the deterioration result and mechanism, a full-scale superstructure of a realistic bridge is used in this study. The simulation results reveal differences between the full-scale model (FSM) and SPM due to size effects and boundary conditions. The findings also demonstrate that the failure mechanism in the FSM simulations differs between dry and wet conditions. In dry cases, damage easily occurs at the bottom surface of the bridge slab. However, in wet cases, horizontal cracks and disintegration occur below the top surface near the upper rebar layer of the slab during the early stage over a very short time period, which cannot be visually investigated according to current bridge slab inspection regulations. These results successfully reproduce the deterioration phenomenon that occurred on site, which indicates the credibility of the simulation. Then the effect of two wheel-loading on RC slabs is studied to assess the slab continuity at adjacent panels. This study provides a useful reference for more rational design and maintenance of RC slabs of road bridges.

Influence of carbonate impurities on smartwater effect: Evaluation of wettability alteration process by geochemical simulation

Low salinity water flooding (LSWF) has been considered as a promising technique for enhanced oil recovery (EOR). The wettability alteration towards a more water-wet state is recognised as the main mechanism for the positive LSWF effect. Electrokinetic interactions occurring at crude oil/brine and rock/brine interfaces affect the wettability alteration. Most of the studies reported in the existing knowledge considered synthetic calcite to understand the electrokinetics of natural carbonate with brines. The mineral impurities present in natural carbonate could influence the electrokinetics and subsequently wettability alteration. In this study, the surface complexation model, thermodynamic equilibrium model, and extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory were combined to evaluate the effect of impurities (dolomite and anhydrite) in natural carbonate on wettability alteration. The surface complexation modelling parameters were first estimated by fitting the calculated zeta potential to that of measured value in various brines and then validated in smartwater. The thermodynamic equilibrium of impurities is largely insensitive to crude oil/brine interface properties. However, the calculated carbonate/brine surface or zeta potential changed from positive to negative with anhydrite equilibrium in the brines containing Ca2+ or Mg2+ ions. The attractive or repulsive forces between crude oil and carbonate were estimated from disjoining pressure using extended DLVO theory and compared with measured adhesion forces. The computed disjoining pressure was used as an indicator to evaluate wettability alteration. It is found that brine with SO42- ions can result in highest water-wet condition, followed by smartwater (brine with Ca2+, Mg2+, and SO42-) and brine with either Ca2+ ions or Mg2+ ions. The de-ionic (DI) water is unfavourable for wettability alteration. The effect of impurities equilibrium and the crude oil surface site densities on the disjoining pressure were also discussed.

Experimental Investigation of the Effect of Acid and Base on Wettability Alteration of a Calcite Surface

Wettability alteration toward a favorable wetting condition is one major mechanism of enhancing oil recovery in carbonates. Obtaining the desired wettability stipulates that a clear understanding of the original wetting properties of the rock surface be provided. In fact, the aim of this study is to elucidate the effect of acid and base upon the wettability alteration of a calcite surface by investigating the individual effects of an organic acid (stearic acid) and a base (N,N-dimethyldodecylamine, N,N-DMDA) at different concentrations as well as their combinations on calcite wetting properties. Contact angle, ζ-potential, Fourier transform infrared spectroscopy, and thermogravimetric analysis (TGA) were conducted to determine changes in wetting properties of the calcite surface. Moreover, interfacial tension (IFT) measurements were used to evaluate the interfacial activity of the model oil systems. Overall, the results revealed that by increasing the acid concentration, wettability of a calcite surface shifted toward more oil-wetness and adsorption of stearic acid on a calcite surface increased. Treating calcite surfaces with the base revealed that a low concentration of N,N-DMDA was able to shift the calcite wettability from a water-wet state to a slightly oil-wet state. In addition, TGA results showed low adsorption of the base with a high surface area occupied by the base molecule, indicating a horizontal orientation of the base on the calcite surface. For acid–base mixtures, at a constant acid concentration, the wettability alteration toward oil-wetness increased in the presence of the base, as the base-to-acid ratio increased up to 1, as a result of which oil-wetness decreased. Moreover, IFT measurements indicated lower IFT of acid–base mixtures compared to those of individual acidic and basic model oil solutions, which could be attributed to the synergistic effect between the acid and base by forming acid–base complexes. The presence of the base hindered acid adsorption on the calcite surface. However, the basic component could contribute to wettability alteration by forming acid–base complexes. These complexes could adsorb on the calcite surface and affect its wetting preferences. In addition, the base molecules may adsorb on the calcite surface at high base-to-acid ratios. The results suggested that the ratio of base to acid would determine the contribution of acid molecules, base molecules, and acid–base complexes in wettability alteration of calcite surfaces. Hence, possible mechanisms of wettability alteration by acid–base combinations were proposed at different base-to-acid ratios.

Assessment on hybrid jute/coir fibers reinforced polyester composite with hybrid fillers under different environmental conditions

In this work, synergistic impact of hybrid fibers and hybrid fillers on mechanical, moisture absorption and morphological properties of polyester matrix composites at dry and wet conditions was examined. The hybrid composite laminates were fabricated by compression molding technique, using new combinations of jute and coir fibers as primary reinforcements as well as waste eggshell powder (ESP) and montmorillonite nanoclay (MMTK10-NC) as secondary reinforcements in a polyester matrix. The fillers, ESP and NC were added to the jute and coir fiber blended hybrid composite in different amounts. Maximum tensile strengths of the hybrid composites were estimated to be 24.57, 21.77 and 22.63 MPa when fillers were added at equal weight percent (wt.%) of 1.5 for dry, river and sea water (wet) conditions, respectively. Under same dry, river and sea water conditions, flexural strengths of 46.97, 44.85 and 42.36 MPa as well as impact strengths of 2.697, 2.572 and 2.607 J were obtained, respectively. Occurrence of swelling, agglomeration and porosity on the hybrid composites were observed to be crucial factors, which caused their strength reduction. It was evident from the results obtained that addition of hybrid fillers to the hybrid composites in different weight proportions increased their mechanical performances higher than that of non-filler hybrid composites. Mechanical properties diminished with wet condition, due to deterioration between the fibers and matrix interface. Also, scanning electron microscopy (SEM) images indicated that it was due to weak fiber–matrix adhesion. With addition of hybrid filler to the hybrid composites, the moisture absorption rate was reduced. Importantly, the optimal/best hybrid composite sample S4 with equal filler content of 1.5 wt% can be used as an alternative sustainable material for low load bearing structural components in building construction industries, such as trusses and frames, wooden flooring and scaffold.

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.

Compositional simulation model and history-matching analysis of surfactant-polymer-nanoparticle (SPN) nanoemulsion assisted enhanced oil recovery

BackgroundSimulation plays a pivotal role in the design of enhanced oil recovery (EOR) processes based on reservoir and in-situ fluid conditions. A robust compositional model, using a complicated multi-component nanoemulsion injection fluid, was developed to describe the performance of nanoemulsion flooding to predict their feasibility for pilot oilfield projects. MethodGemini surfactant/polymer/nanoparticle stabilized Pickering nanoemulsions were prepared by high-energy method and characterized to assess core-flooding performance. During simulation, a Cartesian grid model with fixed bulk volume, injection flow rate, well completion parameters and rock-fluid properties was employed. Core-flooding experiments were performed in steps, involving ~2.16 pore volume (PV) brine injection, ~0.90 PV nanoemulsion injection and ~1.50 PV chase water injection. Significant findingsOil saturation map and relative permeability data analyses showed that the wetting nature of sandstone core altered from intermediate-wet to strongly water-wet condition. Tertiary recoveries were obtained in the range of 21-27% of the original oil in place (OOIP) for different surfactant/polymer/nanoparticle (SPN) compositions of injected nanoemulsion fluids. Flooding simulation studies showed good history matching of production data within ± 6% between experimental and simulated results. In summary, the efficacy of SPN nanoemulsions as an EOR fluid was corroborated with the aid of numerical simulation analyses.

Styrene intermolecular associating incorporated-polyacrylamide flooding of crude oil in carbonate coated micromodel system at high temperature, high salinity condition: Rheology, wettability alteration, recovery mechanisms

Polymer flooding is one of the most well-known research interests in the enhanced oil recovery (EOR) due to the excess oil production and limited petroleum reserve. Commercial polymers such as polyacrylamide (PAM) and its hydrolyzed form (HPAM) can be easily degraded at high temperature, high salinity, and high shear rate in attempt to the EOR purposes for the harsh reservoir conditions. In this work, a hydrophobically modified copolymer consisting of acrylamide and styrene (HSPAM) was produced via inverse emulsion polymerization as a wettability modifier and viscosifying agent, applicable under harsh reservoir conditions to direct insights into the synergic oil recovery pore scale mechanisms and overcoming the aforementioned challenges through the EOR process. In the first part of this study, a set of analytical techniques including FTIR, NMR, TGA, and molecular weight measurement was carried out, confirming successfully incorporation of styrene monomer in water-soluble skeleton and higher thermal resistivity of HSPAM compared with HPAM. By analyzing the rheological behavior of HSPAM under harsh reservoir conditions, it was found that the viscosity of HSPAM aqueous solution was increasingly influenced by the total dissolved solids, even up to 40,572 mg/L. In the second part, stability tests, contact angle (CA), interfacial tension (IFT), and carbonate coated glass micromodel flooding experiments were conducted by deionized water (DIW), seawater (SW) and formation brine (FB) in the absence and presence of HSPAM and HPAM. HSPAM illustrated a great stability in seawater and formation brine in comparison with HPAM after 120 days at 80 °C. The presence of HSPAM in seawater resulted in a more water-wet state up to 42° compared to HPAM by contact angle of 31° after 72 h. Findings provided synergic oil recovery mechanisms approved by emulsification and coalition phenomena to show a better wettability alteration and IFT reduction for HSPAM in spite of HPAM alongside drastically improving the brine-based flooding performance, yielding an ultimate recovery of about 82% original oil in place (OOIP).

Distinguishing the Effect of Rock Wettability from Residual Oil on Foam Generation and Propagation in Porous Media

One of the common challenges of applying foam for enhanced oil recovery is the foam instability in the presence of crude oil and nonwater-wet surfaces. In this experimental study, we systematically distinguish the effect of rock surface wettability from that of crude oil saturation on foam rheology under reservoir conditions. Neutral-wet Berea and reservoir sandstone cores are prepared by aging with crude oil, followed by the wettability index measurements. Transient foam generation and steady-state foam quality scans are conducted in neutral-wet cores, with/without water-flood residual oil. Nuclear magnetic resonance imaging is also utilized to measure the remaining oil saturation at the end of the foam-flood. It is shown that strong foam can be generated in a neutral-wet core with no residual oil because of the solubilization of the adsorbed crude oil components and the wettability alteration toward more water-wet conditions. However, in a neutral-wet core containing residual oil, foam generation is initially hindered. Foam generation occurs after injecting several pore volumes of surfactant solution and increasing the superficial velocity to overcome the minimum pressure gradient required for in situ foam generation. The findings from this study suggest that surface wettability in the presence of bulk oil saturation significantly affects transient foam generation. The final steady-state foam strength becomes comparable to the water-wet and oil-free case once the residual oil saturation is adequately reduced.

Effect of wettability on immiscible viscous fingering: Part I. Mechanisms

Most immiscible viscous-fingering experiments have been conducted using Hele-Shaw cells or linear displacements with high permeabilities. In linear displacement experiments, the effect of varying velocity profiles on viscous fingering is not tested. Only a limited number of studies have been conducted in five-spot displacement patterns. These studies have not provided any comparative insight into fingering length scales during high-IFT imbibition and drainage in water-wet and oil-wet porous media, respectively. To eliminate the limitations of previous studies, high-IFT, adverse-viscosity-ratio, water–oil displacements are conducted in a quarter-five-spot pattern with a relatively intermediate permeability under water-wet and oil-wet conditions, respectively. Statistically representative fingering patterns are captured by devising experimental techniques and image analysis algorithms to correlate statistical information including the evolution of the fingering length scales with time in water-wet and oil-wet micromodels. Mechanistic regimes of viscous fingering in imbibition and drainage are proposed. The patterns of fingering suggest a profound effect of wetting properties on the complex interplay between several pore-scale mechanisms during high-IFT, adverse-mobility-ratio imbibition and drainage, including the interfacial energy effects, capillary invasion, transverse flow, viscous crossflow, bypassing, film flow, and tip splitting, shielding, and spreading.