Oil-wet Conditions Research Articles

Numerical Investigation on Low-Salinity Augmented Microbial Flooding within a Sandstone Core for Enhanced Oil Recovery under Nonisothermal and pH Gradient Conditions

Summary In an era of increasing energy demand, declining oil fields, and fluctuating crude oil prices globally, most oil companies are looking forward to implementing cost-effective and environmentally sustainable enhanced oil recovery (EOR) techniques such as low salinity waterflooding (LSWF) and microbial EOR (MEOR). The present study numerically investigates the combined influence of simultaneous LSWF and microbial flooding for in-situ MEOR in tertiary mode within a sandstone core under spatiotemporally varying pH and temperature conditions. The developed black oil model consists of five major coupled submodels: nonlinear heat transport model; ion transport coupled with multiple ion exchange (MIE) involving uncomplexed cations and anions; pH variation with salinity and temperature; coupled reactive transport of injected substrates, Pseudomonas putida and produced biosurfactants with microbial maximum specific growth rate varying with temperature, salinity, and pH; relative permeability and fractional flow curve variations owing to interfacial tension (IFT) reduction and wettability alteration (WA) by LSWF and biofilm deposition. The governing equations are solved using finite difference technique. Operator splitting and bisection methods are adopted to solve the MIE-transport model. The present model is found to be numerically stable and agree well with previously published experimental and analytical results. In the proposed MIE-transport mechanism, decreasing injection water (IW) salinity from 2.52 to 0.32 M causes enhanced Ca2+ desorption rendering rock surface toward more water-wet. Consequently, oil relative permeability (kro) increases with >55% reduction in water fractional flow (fw) at water saturation of 0.5 from the initial oil-wet condition. Further reducing IW salinity to 0.03 M causes Ca2+ adsorption shifting the surface wettability toward more oil-wet, thus increasing fw by 52%. Formation water (FW) salinity showed minor impact on WA with <5% decrease in fw when FW salinity is reduced from 3.15 to 1.05 M. During low-salinity augmented microbial flooding (LSAMF), biosurfactant production is enhanced by >63% on reducing IW salinity from 2.52 to 0.32 M with negligible increase on further reducing IW and FW salinities. This might be owing to limiting nonisothermal condition (40 to 55°C), dispersion, sorption, and microbial decay. During LSAMF, maximum biosurfactant production occurs at microbial maximum specific growth rate of 0.53 h-1, mean fluid velocity of 2.63×10-3 m h-1 and initial oil saturation of 0.6, thus resulting in significant WA, increase in kro by >20%, and corresponding fw reduction by >84%. Moreover, the EOR efficiency of LSAMF is marginally impacted even on increasing the minimum attainable IFT by two orders of magnitude from 10-3 to 10-1 mN m-1. Though pH increased from 8.0 to 8.9, it showed minor impact on microbial metabolism. Formation damage owing to bioplugging observed near injection point causing increase in fw by ~26% can be mitigated by adopting suitable well-stimulation strategies during the LSAMF run time. The present study is a novel attempt to show synergistic effect of LSAMF over LSWF in enhancing oil mobility and recovery at core scale by simultaneously addressing complex crude oil-brine-rock (COBR) chemistry and critical thermodynamic parameters that govern MEOR efficiency within a typical sandstone formation. The present model with relatively lower computational cost and running time improves the predictive capability to preselect potential field candidates for successful LSAMF implementation.

Wettability alteration and improved oil recovery in unconventional resources

The ultimate recovery factor in tight and shale resources is limited and is usually in the range of 5–10%. Although high-intensity fracturing and refracturing can increase recovery, an enormous amount of oil will remain in place, hence the desirability of enhanced oil recovery methods. Many of the shale reservoirs are oil-wet with negligible water uptake. By altering the wettability, water can spontaneously imbibe into the formation matrix, creating a counter-current flow that forces the oil out. Here, we assess the likelihood of increased oil recovery by modifying the fracturing-fluid composition (salinity and ion concentration) that transforms the formation wettability into a more water-wet state.Oil wetting of tight formations is usually controlled by the adhesion of oil droplets on the surface of clay minerals. When clay minerals are not predominant, the oil attached to carbonate minerals can significantly control rock wettability. In this study, we first identify the primary reactions that define the initial wettability of the rock depending on the formation mineralogy, formation water composition, and oil type. Second, we build a geochemical model considering the surface complexation of various minerals to mimic the wettability state of the reservoir. Third, we validate our method on zeta-potential, contact angle, and imbibition data from a previously published study using different fluids with different salinities. Finally, we present a mechanistic approach to model the wettability-alteration impact on spontaneous imbibition and compute the incremental oil recovery contributed by different fracturing fluid compositions.Based on the studied case, the oil adhesion to clay can be reduced by tuning the fracturing fluid salinity. The ionic concentrations of 2.5 wt % of NaCl and 5.0 wt % of CaCl2 induced the smallest contact angles of 44.7 and 51.2°. We observe that further brine dilution increases the contact angle. For example, distilled water shows the most oil-wet condition with a contact angle to 93.4°. We argue that the main factors that maximize water wetting for the reported optimum salinities are the contrast in the rock and oil surface potential and the sodium concentration. Spontaneous-imbibition simulations indicate that the low salinity fluids promote a change in water-oil capillary pressure, leading to increased water uptake in the cores and improved oil recovery compared to distilled water. The agreement between the developed model and experimental data implies that the wettability in shale and tight formations can be quantitatively predicted and regulated.

Microfluidics experimental investigation of the mechanisms of enhanced oil recovery by low salinity water flooding in fractured porous media

Spontaneous imbibition of water from fracture into the matrix is considered as one of the most important recovery mechanisms in the fractured porous media. However, water cannot spontaneously imbibe into the oil-wet rocks and as a result oil won’t be produced, unless the capillary pressure barrier between fracture conduits and matrix is overcome. Wettability alteration is known as the main affecting mechanism for low salinity water flooding (LSWF), however, its effectiveness in fractured porous media has been less investigated, especially in the case of possible pore scale displacement mechanisms. In this study, the effectiveness of LSWF (diluted seawater) on oil recovery is compared to the formation water (FW) and seawater (SW) in four different fractured models. Each of these fractured models is representing a different sub scale of the NFR. In addition to the effect of fracture geometry, the effect of wetting conditions was studied. Contact angles, Interfacial Tension (IFT) and zeta potentials are measured to have more insight on the Crude-oil/Brine/Rock system under investigation.The results of micromodel experiments show a positive effect of LSWF in both water-wet and oil-wet states. Sessile drop and pendant drop tests show that contact angle alteration and IFT reduction cannot be the dominant mechanisms. Visual investigations on dynamic displacement tests, suggest that the formation of micro-emulsions and elastic oil/water interface are the main mechanisms of recovery in the case of LS and FW injections, respectively. Elastic FW/oil interface causes discontinuous water phase in the fracture, which in turn reduces the mobility of the FW in the fracture and facilitates the diversion of the flow from fracture towards the matrix. This mechanism results in better sweep efficiency for the case of FW compared to the case of SW. Nevertheless, the dominant formation of microemulsion in the case of LSW is more effective in the diversion of the flow from fracture into the matrix (compared to the effect of interface elasticity in the case of FW). This mechanism along with slightly better imbibition (less oil-wet state) in the case of LSWF enhances its recovery performance compared to the FW in both water-wet and oil-wet systems.

A calibrated surface complexation model for carbonate-oil-brine interactions coupled with reservoir simulation - Application to controlled salinity water flooding

Vast majority of past studies that have been conducted on controlled salinity water flooding (CSWF) use diffuse layer model (DLM) that calculates only the surface potential, which can be significantly different from the ζ-potential of the interface. Importantly, stability of the water-film (between the oil and the rock surface) which dictates ultimate oil recovery is related to ζ-potential. As such, using DLM calculated surface potential (directly) for CSWF can be misleading. Additionally, most of the existing DLMs use integer charges instead of fractional charges to model carbonate-brine interactions, which may not represent the actual carbonate crystallographic. We present a triple layer surface complexation model (TLM) which offers the option to locate and distribute charge of the adsorbing ion(s) at three locations. TLM can therefore calculate potentials at three different locations within the Stern layer. To the best of our knowledge, only few authors have used TLM to simulate CSWF. However, some surface reactions were ignored in these models. For instance, adsorption of monovalent ions such as Na + and Cl − ions was ignored in some of the few available TLMs. Also, the effect of basic-oil components was not considered in some TLMs, and lastly, some TLMs used integer charges for the carbonate surface group. This study introduced a comprehensive TLM that includes all these complexities. Moreover, we introduced a new wettability indicator (WI) that is related to the electrostatic forces between the oil-brine and the rock-brine interfaces. That is, WI was calculated from ζ-potentials at the oil-brine and rock-brine interfaces. The TLM, built in a geochemical simulator, PHREEQC, was then coupled with UTCHEM, a multiphase reservoir simulator. The developed simulator based on the TLM-CSWF model was tested against several experimentally measured oil recovery data sets. Results of the model suggest that Oil basic component significantly impacts oil-brine interface ζ-potential irrespective of temperature, brine composition, and ionic strength. On the otherhand, Na + ions in brine may influence oil-brine ζ-potential, and this relates to temperature, brine composition, and ionic strength. The results further suggest that injection of (sulfate-free) diluted brine in chalk resulted to increased oil adhesion, shifting the reservoir to oil-wet condition. Hence, no additional oil is recovered with this brine injected at tertiary oil recovery stage. Finally, the results showed that wettability is related to ζ-potentials at the oil-brine and rock-brine interfaces, and the carbonate rock would be strongly oil-wet or water-wet only at significantly large magnitude of ζ-potentials at the interfaces. • A new triple-layer surface complexation model developed to characterize carbonate-brine-oil interactions. • The model is tested against several experimentally measured zeta potential and oil recovery data sets. • The model suggests that SO 4 −2 ion adsorption tends to decrease CO 3 −2 adsorption at the rock surface and vice-versa. • The model showed that only a small fraction of the carbonate-oil-brine reactive sites are involved in the geochemical reactions.

An experimental investigation of the foam enhanced oil recovery process for a dual porosity and heterogeneous carbonate reservoir under strongly oil-wet condition

In this study, we investigate the feasibility of foam enhanced oil recovery (EOR) for a dual porosity and heterogeneous carbonate reservoir in the Middle East with medium temperature (55 °C) and high formation salinity (16% TDS). An Alkyl Poly-Glycoside (APG) surfactant was firstly selected based on the solubility tests and bulk foam tests. Afterwards, a series of 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 actual formation. In these foam tests, the influence of surfactant concentration, foam quality, injection velocity, brine composition, injection mode and permeability on foam strength and incremental oil recovery were systematically investigated. The optimal foam quality is found to be around 60–70% from foam quality scan tests in the absence of crude oil. Moreover, foam can still be generated in Estaillades under strongly oil-wet conditions, and the foam strength in the high-quality regime is largely dependent on surfactant concentration. More than 10% original oil in place (OOIP) of the water flooded residual oil was recovered after co-injecting 2.0 total pore volume (TPV) of nitrogen and 0.5 wt% APG surfactant (in synthetic seawater brine) at 65% foam quality and 4 ft./d. Interestingly, it was observed that the presence of lauryl betaine (LB) can significantly enhance the stability of APG foam in the presence of crude oil, though LB surfactant itself is not a good foamer. At last, the three phase co-injection tests proved the presence of foam at approximately 70% oil saturation. The results of this study may provide insights into the foam transport behavior in a dual porosity and heterogeneous porous media under strongly oil-wet condition.

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.

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.

Alteration effect on petrophysical properties of reservoirs rocks by drilling fluid emulsifiers

Surfactants formulated into oil-based mud can adsorb to pore surfaces causing changes in rock wettability, which are widely believed to impair formation permeability when oil-based mud invades the near-wellbore region. In the present study, the effects of oil-based mud with Versawet and Versacoat surfactants, on the petrophysical properties and wettability of drilling cutting samples from sandstone reservoirs were investigated through relative permeability, wettability index, and adsorption measurements at standard conditions in a micromodel device. The X-ray analysis and flame photometer were used to characterize the drilling cuttings samples, and the functional groups of surfactants were identified by the infrared spectroscopy. Relative permeability was studied using the unsteady state method, and the wettability index was measured by the Amott method after the aging with drilling formulation for 24 to 720 h and then the adsorption behavior of surfactants using Langmuir isotherm. The results show that drilling cutting is mainly composed of quartz 71.9%. Surfactant in oil-based mud reduces permeability and causes a change in wettability to a more oil-wet state, and these effects become more pronounced as the contact period with the surfactant increases. The wettability of a reservoir rock was altered due to surfactant adsorption and the formation of a hydrophobic layer on the surface of drilling cutting samples. The adsorption and retention of polar part of the surfactants -NH2 for Versawet and -COOH for Versacoat on the silanol groups and the calcium atoms included in the structure of the reservoir rocks. They are the key interactions in the wettability alteration process.

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.

Catalytic Effects of Temperature and Silicon Dioxide Nanoparticles on the Acceleration of Production from Carbonate Rocks.

The use of engineered water (EW) nanofluid flooding in carbonates is a new enhanced oil recovery (EOR) hybrid technique that has yet to be extensively investigated. In this research, we investigated the combined effects of EW and nanofluid flooding on oil-brine-rock interactions and recovery from carbonate reservoirs at different temperatures. EW was used as dispersant for SiO2 nanoparticles (NPs), and a series of characterisation experiments were performed to determine the optimum formulations of EW and NP for injection into the porous media. The EW reduced the contact angle and changed the rock wettability from the oil-wet condition to an intermediate state at ambient temperature. However, in the presence of NPs, the contact angle was reduced further, to very low values. When the effects of temperature were considered, the wettability changed more rapidly from a hydrophobic state to a hydrophilic one. Oil displacement was studied by injection of the optimised EW, followed by an EW-nanofluid mixture. An additional recovery of 20% of the original oil in place was achieved. The temperature effects mean that these mechanisms are catalytic, and the process involves the initiation and activation of multiple mechanisms that are not activated at lower temperatures and in each standalone technique.

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.

Enhancing oil recovery using silica nanoparticles: Nanoscale wettability alteration effects and implications for shale oil recovery

Enhanced oil recovery (EOR) techniques have the potential to improve recovery in unconventional shale oil reservoirs which have prolific short-term success but elusive near-to-long term outlook. The use of silicon dioxide nanoparticles for enhancing shale oil recovery has recently gained significant attention in the oil industry. However, the technique remains novel partly due to inadequate fundamental understanding of oil release mechanisms. Herein, the oil recovery potential of untreated and treated silica nanoparticles is investigated using an atomic force microscope (AFM) by studying nanoscale interactions between different crude oil functional species and substrates of pure minerals found in a shale oil reservoir. Quartz and muscovite mica (clay substitute) were employed as substrates as these are the dominant rock minerals identified in the most productive zone of Tuscaloosa Marine Shale (TMS). Thiolates of undecane (CH3) and phenyl (C6H5) compounds were used to simulate alkane and aromatic fractions of TMS crude oil respectively, while undecanoic acid (COOH) thiol was used to represent carboxylic acid found in asphaltene and resin components. Following our in-house experimental protocol for liquid cell force spectroscopy, adhesion forces and surface energies between functionalized AFM probes and mineral substrates were characterized in untreated and amino-treated silica nanoparticle dispersions. Zeta potential of respective nanofluid solutions was measured and AFM adsorption data were supported with scanning electron microscope (SEM) micrographs of TMS rock samples. Results showed that aqueous dispersions of hydrophilic silicon dioxide nanoparticles promote wettability towards a less oil-wet state by significantly lowering the adhesion force and energy barrier to spontaneously detach oil molecules from clay and quartz mineral surfaces in shale reservoirs, shown at the nanoscale with AFM studies. However, the grafting of aminosilanes onto surfaces of silica nanoparticles generally increased adhesion forces and surface energies due to surface charge effect and hydrophobicity. Findings pertinent to nanoparticle silanization were consistent in molecular interactions on mica in nanofluids but not necessarily predictable with quartz surfaces, highlighting mineralogical effects. The irreversible adsorption of silica nanoparticles was also observed. Adhesion force and energy are resolved in various intermolecular forces such as electric double layer repulsion, non-electrostatic interaction and structural forces. The scientific significance and broad engineering implications of results were comprehensively discussed in the context of previously reported core-to-field scale observations of nanofluid EOR. This study pitches new light on the scientific understanding of silica-based nanofluid EOR by probing nanoscale wetting effects of silica nanoparticles with implications for shale oil recovery. The findings herein can help for better understanding of the design of nanofluid EOR reagents and the conditions that favor application of silica nanofluid EOR.

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.

Two-phase modelling of the effects of pore-throat geometry on enhanced oil recovery

This study presents computational fluid dynamics (CFD) analysis of the effects of wettability, viscosity and interfacial tension (IFT) for enhanced oil recovery (EOR) with varying pore configuration. A more realistic pore-throat geometry is studied which was motivated by oil-containing rock configuration that indicates the importance of pore geometry in EOR. The results are compared with those obtained for a simple geometry. Both saturated and unsaturated conditions are considered while the IFT varies. For both geometries, the saturated condition presents 99% of oil recovery, for the water-wet and intermediate states while it is about 88% for the oil-wet state. However, there is a significant difference in the temporal evolution of the oil recovery factor, as the complex model is 1.4 to 3 times slower than the simplified one to achieve maximum oil recovery factor under the same conditions. For unsaturated conditions, two different initial oil volumes were considered to explore the combined effect of low IFT and change in wettability. Similarly, the oil recovery process is significantly slower for the complex geometric configuration. The study of very low IFT values (10, 35, 65 and 75 µN/m) for the complex configuration in the unsaturated oil condition revealed that highest oil recovery is achieved at the IFT of 75 µN/m. The results confirm that geometric configuration plays an important role in EOR. The impact of pore structure becomes more significant in the unsaturated oil state demonstrating that very low values of IFT slow the oil recovery process.

Application of SEM Imaging and MLA Mapping Method as a Tool for Wettability Restoration in Reservoir Core Samples for SCAL Experiments

In reservoir engineering, special core analysis experiments (SCAL) are performed in the lab to evaluate the production capabilities of an oil reservoir. A critical component of SCAL experiments is core wettability restoration to its original wettability, i.e., oil wet condition. Typically, aging is performed by saturating the core with oil and aging at reservoir temperature where time is the variable in question dictating whether the resulting restored core is strongly or weakly oil-wet. In the lab, core wettability is often experimentally validated using contact angle measurements or USBM (United States Bureau of Mines) wettability tests, which are often time consuming, expensive and prone to error. In this study we developed a novel method by using Scanning Electron Microscope (SEM) and mineral liberation analysis (MLA) imaging (at low vacuum conditions) to determine the wettability of rocks saturated with reservoir fluids such as oil and brine. For this work a systematic approach was applied with comparing the SEM-MLA method against conventional methods to quantify the degree of uncertainty linked to a) wettability estimation and b) the aging time. We have used a comprehensive suite of core samples such as Berea, Silurian Dolomite and Chalk to represent the bulk of oil reservoirs in the world.

Displacement behavior and mechanism of long-term water flooding in sandstone oil reservoirs

Sandstone oil reservoirs with huge bottom water and high permeability are generally developed with high flow rate. After long-term water flooding (LTWF), the water flooding characteristics are quite different from that of original reservoir. In this paper, the effects of the PV number, viscosity, and displacement rate during LTWF are studied through experiments. The mechanism is analyzed based on analysis of changes in oil composition, rock mineral composition and wettability. The oil-water relative permeability curves, oil recovery and wettability were obtained with new experiments methods, which avoids the oil metering error by measuring oil and water separately. The research indicates that when the viscosity increases, the water phase permeability decreases, the residual oil saturation increases, and the water content rate increases earlier. A higher water flooding rate results in a higher ultimate recovery. A higher asphaltene content results in a higher viscosity and more oil-wet reservoir conditions. After LTWF, the wettability tends to water-wet, which is more favorable for heavy oil recovery. Moreover, LTWF reduces the clay content, which creates a more water-wet surface and a larger reservoir pore throat environment. This research provides insightful characteristics of offshore sandstone oil reservoirs, which can be used to enhance oil recovery.

Experimental investigation on synergic effect of salinity and pH during low salinity water injection into carbonate oil reservoirs

Interaction between rock-fluid and fluid-fluid can have a significant effect on oil recovery. Changing the wettability of reservoir rock toward more water-wet or less oil-wet state is one of the expected mechanisms during low salinity water injection (LSWI). pH and salinity are of the most eminent factors of injection water controlling the wettability state of a crude oil/brine/rock system during any waterflooding operation. A small change in pH can affect the surface charges at the rock/water and oil/water interfaces leading to wettability alteration in a porous medium. In this study, the synergic effect of salinity and pH on the wettability state of carbonate rocks is evaluated through adhesion bottle tests for two different carbonate rock types and two different crude oils. The experimental results reveal that non-adhesion (water wet) state is achieved more easily during LSWI (4160 ppm) in a broader pH range compared to that in high salinity water injection (166,400 ppm). Also, it is shown that the acquired wettability maps strongly depend on the rock and crude oil surface charges which are directly affected by the rock mineralogy and crude oil effects. The wettability of rock particles in higher pH values is controlled by the rock mineralogy effect, while the wettability is influenced by the crude oil effect in lower pH ranges. It has been shown in this study that the wettability of carbonate rocks strongly is in proportion to the surface charges and electrical double layer (EDL) theory. The findings herein give insight into the underlying mechanism of LSWI contributing undeniably to effectively optimize and control the Low Salinity Effect (LSE) in the porous media.

Investigating the Effect of Wettability on Sand Production in the Presence of Smart Water and Smart Nanofluid: an Experimental Study

In recent years, research activity to increase oil recovery from hydrocarbon reservoirs by smart water (SW) injection has risen sharply. Smart water injection is one of the most efficient and low-cost methods in the improved and enhanced oil recovery (IOR/EOR) process. One of the active mechanisms of smart water to increase the oil production is wettability alteration of the rock surface from oil-wet to water-wet conditions. Recently smart water injection into unconsolidated sandstone reservoirs due to disturbance of the rock surface equilibrium causes instability of formation particles and sand production. One of the main factors disturbing the equilibrium and sand production is the sandstone surface's wettability alteration mechanism caused by disjoining pressure and stresses on the rock surface. Reduction of the reservoir permeability and closure of fluid flow paths and consequent reduction of oil production are among the main damages of sand production. In this study, a complete study on optimum smart water design based on the least sedimentation due to mixing has been done by formation water compatibility tests and analysis on divalent ions through the Taguchi design. Then the water wet sandstones were converted to oil-wet condition by model oil (stearic acid + normal heptane) in different concentrations. The wettability effect of water wet, neutral wet oil-wet on the amount of sand production in the presence of smart water in the reservoir conditions was fully investigated. To prevent sand production, a very effective chemical method of nanoparticles was used. By stabilizing silica nanoparticles (SiO2) with an optimum concentration of 2000 ppm in smart water (pH = 8), according to the results of the zeta potential and Dynamic light scattering (DLS) test, the effect of wettability on sand production in the presence of smart nanofluid was fully investigated. The test results show a significant reduction in sand production and a rapid wettability alteration towards smart nanofluids' water-wet conditions. This indicates the improvement of fluid for enhanced oil recovery processes in unconsolidated sandstone reservoirs.