Imbibition Tests Research Articles

Seeds of the threatened dry rainforest tree Cadellia pentastylis (Surianaceae) are non-dormant

AbstractCadellia pentastylis (Surianaceae) is an Australian endemic threatened rainforest tree. Irregular flowering and fruiting events coupled with high rates of infertility and insect predation has meant that seed testing has not been possible for this species. Seeds were opportunistically collected from a wild population in early 2021, which allowed for the first germination tests to be conducted. In this study, the presence of physical dormancy was examined by performing an imbibition test using scarified and non-scarified seeds. We also investigated whether a 5-min heat shock treatment at temperatures ranging from 60 to 120°C improved germination success. The presence of physiological dormancy was also examined by recording germination success following a gibberellic acid or smoke-water pre-treatment. Both scarified and non-scarified seeds readily imbibed water over a 72-h period, and several seeds had germinated in both treatments after 48 h. Final germination proportion and t50 following a heat shock, gibberellic acid or smoke-water pre-treatment did not significantly differ from the controls. We conclude that C. pentastylis seeds are non-dormant. Although a palisade cell layer has been reported in the endocarp, our results suggest that this layer may not be sufficiently formed to restrict germination. We recommend that seeds are collected from populations following dispersal and propagated shortly after or stored as conservation collections in ex situ Seedbanks.

Novel Analytical Model of Shale Spontaneous Imbibition Considering the Hydration Effect

Shale gas has enormous potential and has become a hotspot in recent decades. To exploit shale gas, a variety of working fluids (drilling fluid, fracturing fluid, etc.) have to be applied in drilling and well-completion engineering. When fluid contacts with shale, spontaneous imbibition occurs, affecting wellbore stability, fracturing fluid loss, and shale gas production. In the past few years, numerous researchers conducted studies on shale spontaneous imbibition, yet the vast majority of their works are derived from conventional method based on sandstone and carbonate. One of the characteristics of shale is strong hydration, which has been widely reported. During the interaction between liquid and shale, spontaneous imbibition is accompanied by hydration. Shale hydration mainly involves two aspects, i.e., osmotic pressure and hydration structural damage. Now there is still no research on studying the hydration effect during spontaneous imbibition, and how hydration affects spontaneous imbibition is still not fully understood. Therefore, in this paper, considering osmotic pressure and hydration structural damage, spontaneous imbibition in shale formation has been investigated. Besides, according to the Hagen–Poiseuille law, a novel analytical model has been established by coupling imbibition and hydration. In comparison to experimental data of spontaneous imbibition, practicability of this spontaneous imbibition model has been verified. On the basis of this new model and spontaneous imbibition test, influences of salinity and hydration on shale spontaneous imbibition have been systematically discussed. Results indicate that salinity reduces spontaneous imbibition by lowering the driving force of imbibition and restricting hydration damage. Hydration structural damage is its major influencing mechanism for shale spontaneous imbibition. In the shale exploitation, this model can offer guidance for evaluating fracturing fluid loss and hydration damage, which are practical for drilling and hydraulic fracturing design. Besides, the outcome of this paper is beneficial for improving our understanding on spontaneous imbibition in shale formation.

A systematic research on spontaneous imbibition of surfactant solutions for low permeability sandstone reservoirs

Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 °C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C12 surfactants), which was mainly depending on better IFT reduction ability of C16 surfactants than C12 surfactants. Appropriate IFT reduction, such as 10−1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10−2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs.

Descriptive statistical analysis of experimental data for wettability alteration with surfactants in carbonate reservoirs

Surfactants have been the widely used agents to alter the wettability of carbonate rocks to more water-wet and enhanced oil recovery (EOR). As one of major EOR methods, an effective surfactant huff-puff application design requires comprehensive guidelines about where, how, and when this method could be applied. In order to construct such guidelines, a dataset including 338 effective surfactant imbibition tests is established by collecting information from nearly 50 publications. Based on this dataset, descriptive statistical analysis methods are used to conduct data analysis, including three main parts. The first part establishes the application guidelines for surfactant huff-puff treatments which displays suitable application ranges of critical parameters regarding rock, oil, and water. Results show that surfactants can be effectively applied in wide ranges: porosity from 3.1 to 51.7%, permeability from 0.04 to 1458 mD, starting oil saturation from 37.7 to 100%, temperature from 20 to 100 °C, average contact angle from 55 to 180°, oil gravity from 22 to 75.2 °API, oil viscosity from 0.3 to 23 cp, acid number from 0 to 4.5 mg KOH/g oil, base number from 0 to 1.83 mg KOH/g oil, asphaltene concentration from 0 to 10.7 wt%, salinity of connate water and imbibition water from 0 to 263.7 g/l, divalent cations concentration of connate water and imbibition water from 0 to 24.6 g/l. The second part discusses several aspects about design of surfactant huff-puff treatments. Results show that anionic, cationic, and nonionic surfactants have been applied in 83% of tests. Among them is cationic surfactants which have the most frequency. Surfactant concentration is suggested to be remained close or above a critical concentration to obtain the best performance. It is shown that 97% of tests are conducted with surfactant concentration less than 2.0 wt%. In addition, blends of different surfactants and usage of additives could enhance the effectiveness of surfactants. The last part evaluates the performance of surfactant imbibition tests. Results show that surfactants are capable to improve oil recovery either from secondary phase or tertiary phase. In general, the range of oil recovery from secondary phase and tertiary phase are similar, which covers from 1.0 to 93%. However, the average oil recovery from secondary phase is 39.1% which is higher than 32.2% from tertiary phase. Based on this, it is recommended that the treatment timing should be considered in the design of treatments.

Continuous Recording of Viscoelastic Relaxation Processes at a Constant Ultrasonic Frequency Due To Wave‐Induced Fluid Flow in a Microporous Carbonate Rock

AbstractIn a set of water injection, imbibition and drying tests on the Obourg Chalk, relaxation processes induced by variations in water saturation were continuously recorded at a constant ultrasonic frequency, with a peak in attenuation concomitant to a velocity increase from a lower to an upper bound. This behavior is well described by standard viscoelastic models, considering a continuously changing relaxation frequency which at water saturation above 80% matches the frequency of our ultrasonic pulse generator. Using a patchy saturation model, we show that the heterogeneity in fluid distribution is responsible for this relaxation phenomenon which could be observed at the ultrasonic frequency, thanks to the very fine scale of the rock microstructure combining low permeability and high porosity. We believe that our detailed data set can feed new models or help improve existing ones for a better understanding of wave‐induced fluid flow processes in reservoir rocks.

Wettability Changes Due to Nanomaterials and Alkali-A Proposed Formulation for EOR.

We investigated the usage of two silica nanomaterials (surface-modified) and alkali in enhanced oil recovery through Amott spontaneous imbibition tests, interfacial tension (IFT) measurements, and phase behavior. We evaluated the wettability alteration induced by the synergy between nanomaterials and alkali. Moreover, numerical analysis of the results was carried out using inverse Bond number and capillary diffusion coefficient. Evaluations included the use of Berea and Keuper outcrop material, crude oil with different total acid numbers (TAN), and Na2CO3 as alkaline agent. Data showed that nanomaterials can reduce the IFT, with surface charge playing an important role in this process. In synergy with alkali, the use of nanomaterials led to low-stable IFT values. This effect was also seen in the phase behavior tests, where brine/oil systems with lower IFT exhibited better emulsification. Nanomaterials’ contribution to the phase behavior was mainly the stabilization of the emulsion middle phase. The influence of TAN number on the IFT and phase behavior was prominent especially when combined with alkali. Amott spontaneous imbibition resulted in additional oil recovery ranging from 4% to 50% above the baseline, which was confirmed by inverse Bond number analysis. High recoveries were achieved using alkali and nanomaterials; these values were attributed to wettability alteration that accelerated the imbibition kinetics as seen in capillary diffusion coefficient analysis.

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.

Nanofluids of silica nanoparticles in low salinity water with surfactant and polymer (SMART LowSal) for enhanced oil recovery

Spontaneous imbibition is a common phenomenon noticed in low permeability reservoirs during oil recovery. A considerably good amount of oil can be recovered by imbibition of efficient injection fluid for a prolonged time. Recent interest on the low salinity water injection (LSWI/LowSal) has prompted the development of SMART LowSal injection fluid for enhanced oil recovery (EOR). In this work, novel hybrid silica-based nanofluids (NFs) of varying concentrations of silica nanoparticles (SiO2 NPs) in diluted seawater with anionic surfactant (AOT) and polymer (PVP-K30) (referred to as SMART LowSal) were used as an imbibition agent. Interfacial tension (IFT) and contact angle measurements were carried to understand the impact of novel hybrid NFs on the IFT of oil-NFs system and wettability of rock. Berea sandstone cores were used to understand the efficacy of novel SMART LowSal injection fluid for EOR through spontaneous imbibition. The aged oil saturated cores were analyzed with X-ray computed tomography (CT) and energy dispersive X-ray (EDAX). Amott cell was used for imbibition test to evaluate the efficiency of the novel hybrid NFs for EOR. The oil recovery due novel hybrid NFs is found to be significantly higher than that of LSW and deionized water. The oil saturated core surfaces were analyzed with scanning electron microscopy (SEM) and EDAX before and after oil recovery to understand the surface properties of the cores. The novel hybrid NFs showed excellent potential for enhanced oil recovery (EOR). This is one of the first study of its kind using surfactant, polymer and nanoparticles in diluted seawater to prepare NFs and its use for enhanced oil recovery. This study provides vital information about the hybrid NFs as an alternative injection fluid for EOR applications.

Enhanced oil recovery by spontaneous imbibition of imidazolium based ionic liquids on the carbonate reservoir

Wettability alteration plays an important role in the enhanced oil recovery (EOR), particularly for the oil-wet carbonate reservoir in harsh environments. It is essential to alter the native oil-wet characteristics of the rock matrix into water-wet or intermediate-wet in an attempt to achieve the favorable EOR process. The rate of water imbibition can be greatly improved by altering the rock wettability and by reducing oil–water interfacial tension. This can be achieved by using smart water, surfactants, oilfield chemicals, functionalized nanoparticles, or a combination of these to enhance water imbibition and oil displacement. In this study, a suite of spontaneous imbibition tests was run and investigated the efficacy of eco-friendly imidazolium-based ionic liquids (ILs) on the oil-wet carbonate sample and evaluated their effectiveness for the enhanced oil recovery with the minimal concentration of ILs (≤500 ppm). In this, we have studied the various affecting parameters including; type of ILs, ILs concentration (0–500 ppm), aging time (0–8 weeks), and rock permeability (45 and 250 mD). Subsequently, two conventionally used surfactants (SDS and CTAB) were also screened for the same study in order to set the reference case. All these experiments were performed on the Indiana limestone core samples, and experimental condition was set as high temperature (100 °C) and high brine salinity (TDS: 240, 000 ppm) in order to represent the typical Saudi Arabian reservoir condition. Overall, it was observed that a maximum of 34% increment of oil recovery was recorded for IL case over the seawater. Whereas only 11% of increased recovery was achieved with the use of conventional surfactants than the seawater. It is also noted that the longer chain containing ILs had shown better recovery (34%) than the shorter chain containing ILs (27%). Furthermore, NMR T2 relaxation distribution and NMR T2D responses were acquired for the same study. This helps to estimate the rate of water invasion and oil recovery both qualitatively and quantitatively. NMR measurements confirm that seawater was ineffective in all the pores, however a very little recovery was contributed from the macropores. At the same time, ILs showed almost double the recovery compared to seawater, and all types of pores (micro-, meso, and macropores) contributed to the recovery. This suggests that ILs diffused in all type of pores due to their greater diffusiophoresis tendency than the seawater case. NMR T2D measurements correlated well with the gravimetric Amott cell imbibition test results in regards to oil and brine saturations and recovery at different stages of the imbibition process. Overall, this can be concluded that ILs are potentially strong EOR agent, which has the capability to increase the oil recovery at harsh reservoir conditions and it is cost-effective and more economically viable when compared to other conventional chemicals.

Evaluation of Coal Pore Connectivity Using N2 Sorption Isotherm and Spontaneous Imbibition Tests

Pore structure and connectivity of coal are critical factors in coal gas migration and production, which can be characterized by studying the kinetics of capillary imbibition behaviour within the pore spaces. In order to investigate them, six typical coal samples from different collieries in China (Yangcun, Changcun, Gengcun, Yanbei, Dongxia, and Yuwu coal) are selected to carry out N2 sorption isotherm and spontaneous imbibition tests. Results from N2 sorption isotherm tests show that there is a great difference between the total specific surface area and total pore volume among the six coal samples. Their total specific surface area varies from 0.302 to 3.275 m2/g, and the total pore volume varies from 1.782 to 10.94 mm3/g. The pore volume relationship of coal sample among them is in order from the large to small: Dongxia>Yangcun>Gengcun>Yuwu>Changcun>Yanbei coal, and the specific surface area is in order from the large to small: Yangcun>Dongxia>Changcun>Yuwu>Gengcun>Yanbei coal. The imbibition characters of six coal samples were matched using explicit the short-time limit t ⟶ 0 and long-time limit t ⟶ ∞ models by Zhmud et al., respectively. The results show that the long-time limit t ⟶ ∞ model is better. Combined with pore structure analysis, it can be qualitatively analyzed that the imbibition capacity of six coal samples is positively correlated with the connectivity of coal pores, which is ranked as Changcun>Yanbei>Gengcun>Yangcun>Dongxia>Yuwu coal. This work will help understand the mechanism controlling fluid loss and ultimate gas/oil recovery in unconventional hydrocarbon exploration.

Water-Oil Displacement in Shale: New Insights from a Comparative Study Integrating Imbibition Tests and Multiscale Imaging

SummaryWater-oil displacement is an important process that occurs in a shale matrix after hydraulic fracturing and in water-based enhanced oil recovery. Current understanding of this displacement process is limited because of the complicated pore structure and surface properties in shale. In this work, this process and its controlling factors are investigated through a comparative study of three shale samples that have different types of pore systems and wettability. An integrated method of imbibition and multiscale imaging was applied, and a modified oleic tracer that can better represent oil flow was used in imbibition testing and micro-computed tomography (CT) imaging. Scanning electron microscope (SEM) pore characterization was then performed under high magnification with guidance from the micro-CT images showing the changes caused by oil or water imbibition. New insights were obtained on the importance of both wettability and pore size effect on oil recovery and the distribution of residual oil after water-oil displacement. Connectivity of pores with different wettability is also discussed based on 3D analysis and SEM pore characterization. Collectively, these new findings improve the understanding of the complicated process of water-oil displacement and the role of influencing factors. Important implications for improved oil recovery strategy in shale are discussed for different types of reservoir rocks. The integrated imaging and imbibition technique provides a new path for further investigation of improved oil recovery in shale.

Prediction of Wetting Hydraulic Characteristics of Compacted Bentonites in Isochoric Conditions

Unsaturated hydraulic characteristics of compacted smectite clays are essential in many engineering applications. The knowledge of the accurate soil-water characteristic curve (SWCC) and hydraulic conductivity function (HCF) is vital for simulating the transient water flow through bentonites. HCFs are routinely estimated from SWCCs using the statistical models that consider probabilistic soil pore-size models. Recent studies, however, emphasize a strong influence of adsorption saturation on the wetting of smectite clays. In this work, the hydraulic diffusivities of four different bentonites at different compaction densities were estimated by back-analysis from water imbibition tests. A constant hydraulic diffusivity with water content was found to be a good approximation, and the diffusivity was equivalent to the self-diffusion coefficient of water due to the influence of adsorption forces in bentonites. A novel procedure is proposed based on the identified dominant mechanism to predict the HCFs and diffusivities directly from the wetting SWCCs of compacted bentonites. The proposed approach was used to predict the HCFs, and transient water flows of four Indian bentonites at dry densities of 1, 1.4, and 1.6 Mg/m3 and other bentonites from the literature. The proposed approach was superior to the existing statistical methods and provided excellent agreement with the back-estimated conductivity data from the water imbibition tests. On the other hand, the existing statistical models severely underpredicted the conductivities, especially in the higher suction range, due to the dominant influence of adsorption saturation.

Experimental and modeling study of enhanced oil recovery from carbonate reservoirs with smart water and surfactant injection

Many studies have been performed in the field of smart water injection and its combination with chemical methods to improve oil recovery. However, there has been less previous evidence for the efficiency of a mixture of cationic and nonionic surfactants combined with smart water for enhanced oil recovery in carbonate reservoirs. Therefore, in the current study, we aimed to investigate the effects of such a combination to enhance oil recovery from a fractured carbonate reservoir. Phase behavior experiments, IFT, and contact angle measurements were performed to design the optimal solution for EOR experiments. Then, through a series of flooding experiments, imbibition tests and simulations, and dimensionless analysis, the efficiency of the designed smart water-surfactant solution was examined. The results demonstrate a strong synergy between low salinity water and surfactant for recovering oil from carbonate reservoirs, as their optimal combination could recover up to 51.1% and 41.25% of the original oil-in-place in the core flood and imbibition experiments, respectively.

Spontaneous imbibition characteristics of carbon nanofluids in carbonate reservoirs

Altering the wettability of the rock–oil–brine system plays a substantial role in the oil recovery process from carbonate reservoirs. Hence, there arises a need for understanding the wetting and wettability alteration of this system. In this study, we ran a suite of spontaneous imbibition tests and investigated the efficiency of Carbon nanodots (CND) and an in-house cationic Gemini surfactant (GS8) on the wettability alteration of and recovery from oil-wet carbonate rock samples. The study considered the effects of additives concentrations, sample aging, initial water saturation, and rock permeability. Both CND and GS8 proved efficient at concentrations below 200 ppm. At 200 ppm, separately CND in seawater and GS8 in seawater demonstrated each about 22%–25% incremental oil recovery over neat seawater. Low field nuclear magnetic resonance (NMR) measurements supported this observation. NMR T2 distribution and NMR T2D fluid typing measurements helped evaluate the recovery in terms of the pore size distribution and the oil and brine water saturation at different imbibition stages. CND exhibited a strong positive effect on the wettability of all tested samples, and accordingly, on the imbibition characteristics and oil recovery. It altered the wettability from strongly oil-wet to water-wet with equal efficiency in all pore systems making it a strong candidate for enhanced oil recovery (EOR). GS8, on the other hand, was most efficient in the macropores. Unlike CND, the efficiency of GS8 decreased in the mesopores and more so in the micropores. Rock–oil–brine surface contact angle and oil–brine interfacial tension measurements supported the imbibition test results and helped interpret the recovery mechanism. Overall, CND proved effective for EOR in the harsh carbonate reservoir environment and demonstrated itself as a viable and economical substitute to the more costly and complex oilfield chemicals for recovery operations.

Performance prediction of ion-engineered water injection (EWI) in chalk reservoirs using Response Surface Methodology (RSM)

Ion-engineered water injection (EWI) is one of the advantageous enhanced oil recovery (EOR) techniques that gained considerable attention in recent years. Many mechanisms have been proposed for additional oil recovery with modified seawater composition when injected into carbonate formations. However, the prediction of EWI is a big challenge due to complex rock/fluid interactions at pore level and related mechanisms. Thus, an efficient design method for water composition is required. This study investigates the optimization of EWI through the concentration of the active and non-active ions in injection water at laboratory scale for chalk core samples by considering the most dominant design parameters. Data from many imbibition tests of chalk core samples were selected. The Response Surface Methodology (RSM) was used to screen the significant contributing parameters. The sensitivity analysis showed that the four most important design parameters are crude oil acid number (TAN), crude oil base number (TBN), temperature, and injected water salinity. An optimum EWI design was suggested, and the predicted responses were validated using other experimental results that have not been used for model development with high accuracy. The model can be applied for experimental design and optimum water composition.

Micro- and Nanoscale Pore Structure Characterization of Carbonates from the Xiaoerbulake Formation in the Tarim Basin, Northwest China

The evaluation of pore structure is an essential part in the assessment of carbonate reservoirs. The structures (geometry and connectivity) of nm to μm-scale pore networks in outcrop samples of carbonates from Xiaoerbulake Formation in Tarim Basin of China were studied by using optical microscopy, field emission-scanning electron microscopy (FE-SEM), as well as mercury intrusion porosimetry (MIP) with fractal analyses of the data, and spontaneous imbibition tests (distilled water). The results demonstrate that the lithologies are micritic dolomites, fine-to-medium-to-coarse crystalline dolomites, microbial dolomites, and dolarenite. At micro- to nanoscales in size, pore types are dominated by intergranular, intercrystalline, and intragranular (e.g., dissolution) pores. These pore networks have pore-throat diameters from 0.01 to >10 μm. Compared with a nanoscale pore network, the μm-scale pore networks are relatively well connected and serve as the most important permeability pathways. Although the pore volume accounts for most of the total porosity, the permeability of nanoscale pore networks is low. The existence of micro-nano-fractures could improve connectivity, especially for the nanoscale pore networks, by linking the intragranular (dissolution) pores which are mostly in the range of nm-scale.

Investigation of smart water imbibition assisted with microwave radiation as a novel hybrid method of enhanced oil recovery

This research aims to investigate the efficiency of a new hybrid method of smart water imbibition assisted with microwave (MW) radiation. Some experiments including the contact angle measurement, attenuated total reflectance (ATR), zeta potential evaluation, oil viscosity measurement, and smart water imbibition were studied to find the effect of the MW radiation on the performance of the smart water imbibition. To capture the controlling mechanisms, it was essential to sustain the temperature in some of the MW treatments. Hence, the rock sections were treated by two methods of dry (MW treating the sections without immersion in the brine water) and immersed (MW treating the sections when they are immersed in the brine water) treatments. It was shown that the contact angle of an aged rock section could be reduced from 170° at the initial condition to almost 37° due to treating by smart water and the MW radiation. Divalent cations of Mg2+ and SO42- were discovered to be more efficient in the wettability improvement than Ca2+, and this fact was discussed in detail from thermodynamic and kinetic points of view. Also, it was found that the MW thermal effect is not the only reason for the wettability improvement and organic compound desorption, but also the MW treatment could destabilize the organic compounds on the rock surface through generating oscillating electric fields. This fact was confirmed by the results of the immersed MW treatment, where the contact angle reduction was found to be almost as efficient as the dry MW treatment. Based on the ATR spectrums, the MW radiation can desorb the polar and non-polar compounds in two different mechanisms of thermal desorption and destabilization caused by oscillating electric fields. Furthermore, it was shown that the oil viscosity was reduced due to temperature rising caused by the microwave treatment, but when the temperature of the oil sample reduced to the room temperature, the viscosity reduction was not observed. The oil viscosity, after the treatment for 2 min, with the radiation power of 20, 40, 60, 80, and 100 maximum power increased to 52.5, 53.1, 55.5, 54.2, and 53.1 cp, respectively. Finally, it was shown that the oil recovery was increased 9% during the MW radiation for 16 min in the smart water imbibition test. Based on the observed results in this research, it is concluded that the hybrid of smart water imbibition assisted with MW radiation could be considered as a novel EOR method resulting in more oil recovery.

Screening of African Yam Bean Accessions for Imbibition and Seed Physiological Quality

African yam bean is a nutritionally-important but neglected food crop with several health benefits. But its large scale cultivation and consumption are still limited by lack of systematic genetic improvement and breeding programme for the crop. Preliminary studies have established that the inherent field establishment potential of African yam bean is low. Hence the need to screen available accessions to identify those with outstanding seed physiological qualities for selection as parental materials for further improvement. Thirty-four African yam bean accessions were collected from different farmers in five states of Southeastern Nigeria. Seed physiological quality (viability and vigour) was assessed using hundred seed weight, water imbibition, standard germination, accelerated ageing and conductivity tests. The mean squares due to varietal effect were significant (p < 0.05) for germination index and highly significant (p < 0.01) for all other traits. Accessions ENAGag, ENAGmg 1 and, ENAGmg 2 had high standard (> 80%) and accelerated ageing (> 70%) germination percentages. Only 11 of the accessions had an accelerated ageing germination percentage of above 50%. All but one of the 34 accessions had conductivity values less than 5.00 µScm-1 g-1. On the average, African yam bean seeds require up to 76.9% moisture of their initial weight over a period of approximately 53 hours prior for the commencement of germination process. Accessions ENAGag, ENAGmg 1, ENAGmg 2, ENNKob, ENNSog, IMISis, IMOKeo 1 and IMOKeo 3 were outstanding and are therefore potential candidates for genetic improvement of seed quality in African yam bean.

Fluoro-chemical foam injection for wettability alteration of sandstone and carbonate reservoirs rocks towards gas-wet state

In gas condensate reservoirs, when fluid pressure decreases below its dew point pressure, it contributes to condensate build-up around the wellbore. Due to liquid condensation, gas and condensate relative permeability and mobility significantly drop and well productivity is considerably decreased. Several approaches have been recommended to mitigate condensate banking. Wettability alteration of the reservoir rock surface towards gas-wet is considered as one of the promising techniques for alleviating condensate banking. In this communication, a fluoro-chemical foam treatment technique is introduced to alleviate the condensate banking. To evaluate the effectiveness of the foam injection technique for the gas-wetting alteration of sandstone and carbonate cores, the contact angle measurement, liquid imbibition, and core displacement tests were conducted in the gas-liquid-core system. The adsorption of the fluoro-chemical solution on sandstone and carbonate samples was verified by surface analysis techniques including SEM, FTIR, and EDXS. The results show that the contact angles of brine and hexadecane droplets on the treated sandstone substrate increased from 0° and 0° to to135° and 103°, respectively. Moreover, treatment of carbonate substrate with fluoro-chemical solution resulted in an increase of 0° to 130° and 0° to 123° for brine and hexadecane contact angles, respectively. After treatment, the imbibition of brine and hexadecane liquids into the cores decreased significantly. Finally, the results of dynamic two-phase core flooding in sandstone and carbonate cores show that the chemical foam treatment can improve the end-point gas relative permeabilities by the factors of 1.704 and 1.69 for sandstone and carbonate cores, respectively.

Experimental Investigation of Polymer-Coated Silica Nanoparticles for EOR under Harsh Reservoir Conditions of High Temperature and Salinity

Laboratory experiments have shown higher oil recovery with nanoparticle (NPs) flooding. Accordingly, many studies have investigated the nanoparticle-aided sweep efficiency of the injection fluid. The change in wettability and the reduction of the interfacial tension (IFT) are the two most proposed enhanced oil recovery (EOR) mechanisms of nanoparticles. Nevertheless, gaps still exist in terms of understanding the interactions induced by NPs that pave way for the mobilization of oil. This work investigated four types of polymer-coated silica NPs for oil recovery under harsh reservoir conditions of high temperature (60 C) and salinity (38,380 ppm). Flooding experiments were conducted on neutral-wet core plugs in tertiary recovery mode. Nanoparticles were diluted to 0.1 wt.% concentration with seawater. The nano-aided sweep efficiency was studied via IFT and imbibition tests, and by examining the displacement pressure behavior. Flooding tests indicated incremental oil recovery between 1.51 and 6.13% of the original oil in place (OOIP). The oil sweep efficiency was affected by the reduction in core’s permeability induced by the aggregation/agglomeration of NPs in the pores. Different types of mechanisms, such as reduction in IFT, generation of in-situ emulsion, microscopic flow diversion and alteration of wettability, together, can explain the nano-EOR effect. However, it was found that the change in the rock wettability to more water-wet condition seemed to govern the sweeping efficiency. These experimental results are valuable addition to the data bank on the application of novel NPs injection in porous media and aid to understand the EOR mechanisms associated with the application of polymer-coated silica nanoparticles.