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Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability. This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments. The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.

Oxidative degradation of polymers is caused by combination of Fe2+ and O2 resulting in viscosity loss. During lab tests, synthetic brine without Fe2+ is commonly used. However, most lab and field set-ups are made of stainless steel (SS) which is a possible source of Fe. Therefore, this study investigates the impact of Fe2+ and O2 contents on polymer stability with/without contact of SS in presence/absence of protective packages (ITW and oxygen scavenger). Polymer stability tests were conducted for 1 week at ambient temperature under different O2 concentrations. Four polymer systems were evaluated (without additives, with ITW, with oxygen scavenger and with ITW+oxygen scavenger). Samples were stored in SS and glass bottles. Different Fe2+ concentrations were added to the solutions in the glass bottles. The viscosity of the polymer solutions was measured at anaerobic conditions at different intervals. Viscosity results for polymer samples aged in glass bottles showed that ITW alone or in combination with oxygen scavenger is able to maintain polymer stability up to Fe2+ and O2 levels of 2.5 ppm and 1500 ppb, respectively. At atmospheric condition, these systems were found efficient as the maximum obtained viscosity loss was < 14%. While samples containing only oxygen scavenger maintained polymer stability up to Fe2+ and O2 levels of 2.5 ppm and 500 ppb, respectively, but experienced severe degradation when exposed to atmosphere. Similarly, blank samples experienced severe degradation after exposure to atmosphere and the stability was maintained up to Fe2+ and O2 levels of 0.5 ppm and 500 ppb, respectively. Polymer solutions stored in SS cells experienced noticeable viscosity loss indicating that Fe is released from the SS and contribute to polymer degradation. The blank samples and samples containing oxygen scavenger were stable up to O2 level of 500 ppb. Addition of ITW into these polymer solutions boosted its viscosity stability up to O2 level of 1500 ppb. Exposing polymer samples containing either ITW or oxygen scavenger to atmosphere resulted in severe degradation of around 42% which is higher than the viscosity loss of the blank sample (28%). However, when both ITW and oxygen scavenger were added to the polymer solution and exposed to atmosphere, the viscosity loss was reduced to 26%. This study showed that polymer stability in presence/absence of protective packages can be maintained at initial O2 level of 500 ppb. These findings are directly related to polymer stability during polymer preparation which needs to be considered in any polymer flood design. As protective packages might come handy for maintaining polymer stability in the reservoir, this study can aid in selection of the most feasible protective packages and water treatment requirements.

Alteration of rock wetting preference toward a more favorable wetting state has been identified as the primary mechanism of oil recovery from intermediate and oil-wet carbonate rocks. In order to produce a favorable wetting state, it is critical to have a clear picture of the initial wetting properties of the rock surface. This study aimed to improve the understanding of carbonate wettability by examining the impact of acid, base, and their mixture on wettability of calcite surfaces using different analytical tools (contact angle measurements, zeta potential test, Fourier transform infrared spectroscopy, interfacial tension measurements, and fluorescence ultraviolet spectroscopy). The acid number (AN) and the ratio of the basic component (quinoline) to the acidic component (stearic acid) were systematically varied in model oil solutions to elucidate the effect of simultaneous presence of the acid and base on the wettability alteration process. The results showed that as the acid concentration increases, the wettability alteration toward the oil-wet state is enhanced. However, the impact of the base was significant at high concentrations, where the wettability was changed toward the neutral state. Addition of the basic compound to the acidic model oil hindered the impact of stearic acid on wettability alteration. Although the impact of the basic component on wettability alteration of calcite seems to be weaker than that of the acidic component, presence of the base can alter the wetting characteristics of the surface. Acid and base concentrations and their ratio dictate the extent of calcite wettability alteration. Slight impact of the base on the wettability alteration process was observed for a system with an AN of 0.25. However, at higher ANs, an increase in the base number (BN) to AN ratio from 0 to 1 resulted in a remarkable reduction in the contact angle; while the contact angle increased again when the BN to AN ratio was 4. Further investigations (for systems with AN = 1) revealed that at the BN to AN ratio of 0.25 and 1, adsorption of the basic component on the surface was unlikely to happen. Formation of an acid–base complex could hinder the access of stearate ions to the calcite surface. At the BN to AN ratio of 1, the quinoline concentration was equal to that for stearic acid, which may enhance the acid–base interactions; hence, more stearic acid would be involved in acid–base complexes. However, once the base concentration became higher than the acid concentration (BN to AN = 4), an excess amount of the base, which was not involved in the complex mixtures with acid molecules, might adsorb on the surface.

The average oil recovery by conventional water flooding from oil-wet and naturally fractured carbonate reservoirs is often less than 30%. Removal of adsorbed acidic components and/or asphaltene from the carbonate surface results in wettability alteration towards water-wet which is an effective approach to enhance oil recovery. Long chain fatty acids, long chain naphthenic acids and asphaltene are major components in crude oil which are responsible for wettability alteration in carbonate reservoirs while unsaturated acids have minor effect. In this study, a more accurate quantification of the effects of different types and structures of polar components that contribute to the initial oil-wetting extent of the reservoir rocks were used (aliphatic saturated acids, aliphatic unsaturated acids, naphthenic acids, aromatic acids and asphaltene). Different analytical tools (contact angle, zeta potential, Fourier transform infrared spectroscopy and thermal analysis) were utilized for all acids in order to study surface characteristics. The results indicated that polar organic compounds act in different ways according to their structure and properties. Presence of double bond could make the acid molecule more polar, reactive and less hydrophobic. In addition, it can affect the spatial arrangement of the molecule and hence its orientation on the surface. Presence of benzene ring increases the reactivity and polarity of carboxylic group. Moreover, it enhances hydrophilic properties of the acid due to electrons of π double bonds that can resonate over aromatic carbon atoms. The results revealed that, in the presence of water film, combination of acid dissociation in water, surface activity of acid and water solubility controls the acid adsorption and hence wettability alteration of the surface during aging process. Chemisorption of carboxylic acids/asphaltene changes the wettability of calcite surface. In addition to chemical adsorption, some acids adsorb physically on the surface. Physical adsorption of polar compounds may happen via hydrogen bonding between carboxylic groups and carbonate ions on the surface. Although physical adsorption is reversible and forms weak bonds between adsorbate and adsorbent, it may partially contribute to wettability alteration.

Modifying the concentration of potential determining ions (PDIs) in the brine can result in alteration of the surface wetting properties towards more water-wet state, which is the desired wetting state in fractured carbonate reservoirs. However, few studies have discussed the interactions between these PDIs and their mechanisms of wettability alteration. Accordingly, the aim of this study was to investigate the concomitant effect of PDIs at different molar ratios on the wettability of oil-wet calcite surfaces as well as the interactions between the ions. Two combinations of wettability modifying agents (Mg2+/SO42−) and (Ca2+/SO42−) were considered. Contact angle and zeta potential measurements were performed to evaluate the effect of these combined ions and explore possible wettability alteration mechanisms. Results revealed that both PDIs groups were able to reduce the contact angle significantly and expel carboxylate group from the surface. Besides, combinations of PDIs were more effective in wettability alteration compared to those ions alone. It was also observed that equal concentrations of magnesium and sulfate provide more water-wet state. However, for combinations of calcium and sulfate, the most water-wet state was achieved when lower concentrations of calcium and higher concentrations of sulfate were used. Zeta potential measurements showed that the performance of each PDI in changing surface wettability is critically affected by the concentration of the other ions present in the same solution. Results indicated that when low concentration of magnesium ions is used, the adsorption of sulfate ions on the rock surface and the interaction of magnesium ions with the carboxylate group is the main mechanism of wettability alteration by magnesium and sulfate ions. However, at high concentration of magnesium ions, no adsorption of sulfate ions was detected which means that sulfate serves as a catalyst for wettability alteration by Mg2+/SO42− and the formation of a complex Mg-carboxylate group is the dominant mechanism. Moreover, the use of cationic surfactant along with the combined PDIs resulted in strong water-wet conditions.

Direct contact membrane distillation (DCMD) was investigated for the treatment of oil-field produced water using a hydrophobic polypropylene (PP) membrane with 0.2 mu m pore size. The DCMD performance was studied under different feed temperatures ranged from 40 degrees C to 80 degrees C while the cooling temperature was maintained at 23 degrees C. Increasing the feed water temperature resulted in a higher permeate water flux. Stable and reliable DCMD membrane performance was observed for all used membranes. The obtained results indicated the great potential of DCMD to treat hypersaline oil-field produced water with an overall rejection of salts higher than 99.9% and that of total organic carbon (TOC) greater than 93.3%. This was due to the presence of volatile organic compounds in oil-field water. Pre-treatment of produced water using 0.45 mu m filter did not show much effect on the DCMD performance. A slight gradual reduction of the permeate flux was observed due to fouling phenomenon. A simple washing the membrane with de-ionized water was found to be an effective method for cleaning the membrane and restoring the permeate flux indicating the absence of irreversible fouling.

Microalgae in the Middle East can theoretically address food security without competing for arable land, but concerns exist around scalability and durability of production systems under the extreme heat. Large-scale Chlorella sorokiniana production was developed in outdoor raceway ponds in Oman and monitored for 2 years to gather data for commercial production. Biological and technical challenges included construction, indoor/outdoor preculturing, upscaling, relating productivity to water temperature and meteorological conditions, harvesting, drying, and quality control. Small cultivation systems required cooling for initial scale-up, but, despite maximum temperatures of 49.7 °C, water temperatures were at acceptable levels by evaporative cooling in larger raceway ponds. Contamination with Vampirovibrio chlorellavorus was identified by 16S rDNA amplicon sequencing and addressed by culture replacement. Productivities ranged from 8 to 30 g-dry weight m-2d-1, with estimated annual productivity of 16 g-dry weight m-2d-1 as functions of solar intensity and water temperature, confirming that the region is suitable for commercial microalgae production.

Wettability alteration toward a more water-wet state was found to be a promising approach for oil recovery improvement in oil-wet and naturally fractured carbonate reservoirs. This approach has bee...

Wettability alteration of the reservoir rock toward a favorable wetting state is one of the main recovery mechanisms during enhanced oil recovery (EOR) processes. A clear understanding of the initial wettability of the reservoir rock can be considered the first step toward a successful wettability alteration during any applied EOR technique. The present study investigates the impact of stearic acid on the wetting properties of several carbonate surfaces (calcite, limestone, and dolomite). A systematic experimental approach was followed in which contact angle measurements, Fourier transform infrared (FTIR) spectroscopy, energy dispersive X-ray spectroscopy (EDXS), scanning electron microscopy (SEM), thermo-gravimetric analysis (TGA), and zeta potential measurements were conducted on fresh carbonate samples as well as treated samples with stearic acid. Contact angle results revealed that all fresh carbonate surfaces were strongly water-wet. Aging in the model oil altered the wettability of the carbonates toward oil-wetness with an average contact angle of 159°, 151°, and 137° for calcite, limestone, and dolomite surfaces, respectively. FTIR and EDXS results demonstrated the adsorption of stearic acid on the carbonate surfaces. Moreover, TGA results showed that the amount of adsorbed stearic acid on carbonate surfaces decreases in the following order: calcite (158.3 μmol/g) > limestone (116.1 μmol/g) > dolomite (46.4 μmol/g). Zeta potential measurements revealed a shift toward more negative values after aging the carbonate surfaces in the model oil which confirms the adsorption of the stearic acid on surfaces. Despite the similarities between carbonate surfaces, the experimental observations clearly highlighted the significant impact of the mineralogical composition of the carbonate surface on the electrical and wetting properties of the surfaces. More positively charged surface of calcite resulted in more electrostatic attraction between the calcite and stearate ions which led to superior affinity of stearic acid toward calcite as compared with limestone and dolomite. The presence of other minerals with calcite on the carbonate surfaces affected the adsorption of stearic acid and the electrical properties of the surface.

Equilibrium molecular dynamics simulations by all-atom model have been employed to investigate the adsorption properties and temperature dependence of the shear viscosity of ethanol molecules confined in narrow single-walled carbon nanotubes (SWCNTs). Since the properties of the narrow tubes (diameters Calculations of shear viscosity of the nanofluid using Green–Kubo method reveal that the relative viscosity of the confined ethanol decreases with increasing temperature. All the CNT@ethanol fluids have lower viscosity than the base liquid ethanol at all temperatures and the viscosity increases with the increase of CNT radius and endo-adsorption. Chirality of the CNTs has minor effects on shear viscosity and endo-adsorption and the main factor is CNTs diameter. The results of the present work provide deep understanding of the viscosity changes with temperature at the nanofluids and can describe the mechanisms for base fluid property modifications caused by adding nanoparticles. These results are applicable in design and preparation of diesohols and fuel-grade ethanol.

Our goal in this work was to study the effect of graphene nano-sheets’ size on the graphene/water nanofluid viscosity using molecular dynamics simulation. Prior to the calculation of the viscosity of the nanofluid, a validation of the computational strategy and the simulation model was tested and the results of the viscosity and density of water molecules with SPC/E, TIP3P and TIP4P potentials at 298 K were compared to the experimental data. It was found that the TIP3P potential gives better result for the viscosity, hence was used in our further calculations. Simulations were conducted at room temperature (298 K) and atmospheric pressure with the Berendsen algorithm. The system was initially run for 300 ps under the NVT conditions. Finally, the production steps of 2 ns with the integral step of 1 fs were performed. Two graphene sheets of the sizes of 20 × 20 and 10 × 10 nm2 were considered. It was observed that the viscosity of nanofluids containing smaller particles is higher than that of the nanofluids containing higher-diameter particles. Moreover, to obtain a better insight into the local structure and organization of the studied system, the site–site and center of mass radial distribution functions (RDFs) were studied. RDFs of oxygen and hydrogen atoms of water molecules were calculated. The obtained RDFs showed that distinct layers of water molecules are formed near the graphene sheet. The observed peaks in the RDF graphs show strong interactions between water molecules and graphene sheet.

Combining low salinity water (LSW) and chemicals to enhance oil recovery has recently received more attention in the oil industry. In this study, a systematic experimental procedure was conducted to evaluate the performance of low salinity nonionic surfactant with/without anionic surfactant in wettability alteration and oil recovery of oil-wet carbonate having high salinity formation water (FW) (196 g/L) and moderate temperature (75 °C). A polyethoxylated nonionic surfactant (C13EO12) and two anionic surfactants: sulfonate (IOS 20–24) and carboxylate (AEC 938) were used in this study. Contact angle (CA) results showed that low salinity nonionic surfactant was effective in altering the wettability of oil-wet calcite toward water-wet state. While the low salinity anionic surfactants' systems were only able to reduce the oil-wetness of the oil-wet calcite. When nonionic surfactant is mixed with anionic surfactant, the wettability of oil-wet calcite was altered toward intermediate-wet or only a reduction of its oil-wetness occurred depending on the type of the anionic surfactant. Spontaneous imbibition tests using oil-wet limestone cores showed that among the low salinity single surfactants’ systems, carboxylate anionic surfactant resulted in the highest oil recovery (61% of oil initially in place (OIIP)) and sulfonate anionic surfactant resulted in the lowest oil recovery (31% of OIIP). The low salinity nonionic surfactant recovered 51% of OIIP by spontaneous imbibition. Addition of sulfonate anionic surfactant to the nonionic surfactant resulted in an oil recovery of 49% of OIIP while addition of carboxylate anionic surfactant to the nonionic surfactant considerably improved the oil recovery to 74% of OIIP. Hence, selection of proper surfactant class is crucial for a successful oil recovery.

A large amount of the discovered oil reserves are reserved in carbonate formations, which are mostly naturally fractured oil-wet. Wettability alteration towards more water-wet state reduces the capillary barrier, hence improving the oil recovery efficiency in such reservoirs. In this study, wettability alteration towards favorable wetting state was investigated by combining modified low salinity brine with surfactant during water flooding. The diluted brine was modified by increasing the concentration of Mg 2+ and SO 4 2− , individually as well as both ions in combination. Different brine formulations were tested experimentally through the observations of contact angle measurements and spontaneous imbibition tests for oil-wet limestone core samples both in the presence and absence of surfactant. Contact angle measurements revealed that both magnesium and sulfate ions can act as wettability modifying agents for the oil-wet calcite and all of the modified low salinity brine solutions changed the wettability of oil-wet surface towards more water-wet state. In the presence of cationic surfactant, utilizing both wettability influencing ions and surfactant molecules resulted in more water-wet surfaces. The spontaneous imbibition results showed that the combination of salting-in effect, mineral dissolution and electric double layer expansion, cause wettability alteration towards more water-wet state and result in critical increase in oil recovery efficiency during spontaneous imbibition of diluted brine into limestone core sample. Modified brine which contains a higher concentration of sulfate ions was more efficient in wettability alteration in comparison to the brine modified with magnesium ions. High oil recovery efficiency can be achieved by optimizing the brine composition without using costly surfactant solutions. However, the combination of the effect of wettability influencing ions (Mg 2+ and SO 4 2 − ) along with the cationic surfactant can result in a remarkable oil production during the spontaneous imbibition process.

The effect of Na2CO3 on the cloud point in Na2CO3/surfactant/brine was investigated using two series of nonionic surfactants, C13EO x and C17EO x . The cloud point, T cp, was found to decrease linearly with increasing Na2CO3 concentration. This was attributed to Na+ and particularly to CO3 2−salting-out effect. The slope a = dTcp/d[Na2CO3] became more and more negative as the degree of ethoxylation is increased, suggesting that the higher the number of ethylene oxide (EO) groups the stronger is the cloud point depression for a given increment in Na+and CO3 2−ions in solution. This was also illustrated by the linear variation of ΔT cp = T cp,0 − T cp,[Na2CO3] with the surfactant degree of ethoxylation.

The selection of the right polymer chemistry in chemical enhanced oil recovery operations is key for a successful field implementation. Operators require guarantees on polymer robustness and efficiency in order to optimize their polymer flooding processes, especially in the current context of low oil price. We evaluated different thermo-responsive polymers dedicated to Oman fields conditions in this perspective.Several thermo-responsive polymers were considered in this study, the properties and performances of which were assessed. The purpose was to make sure that gain in dosage brought by these structured polymers is not detrimental to polymer stability and injectivity. Consequently, polymers were characterized in terms of rheological properties, thermal stability and propagation through porous media.Thermo-responsive polymers are characterized by a LCST (Lower Critical Solution Temperature). They behave like regular polymers below this specific temperature and like associative polymers above it. The LCST varies with several parameters, including thermo-responsive moieties composition, content and molar mass, as well as brine salinity. The viscosifying properties and overall performances of such polymers are subsequently strongly driven by field conditions. Several thermo-responsive polymers were thus designed to fit model field conditions representing Oman oil fields. Rheological properties were firstly evaluated in stationary and dynamic modes, what permitted to emphasize the unique behavior of such polymers and the gain in dosage they can bring. Core flooding tests were then performed to assess polymer injectivity in porous medium. Interestingly, thermo-responsive polymers can display very high resistance factor compared to regular ones while maintaining good transport properties. The polymer retention in the core remained low. Core flood tests also gave an idea of this chemistry limitations for an use in Oman oil fields. Polymers thermal stability was determined in several conditions, fully anaerobic or in presence of O2 and H2S. The efficiency of two protective packages against H2S induced degradation was evaluated. The results after one year aging highlight the importance to avoid oxygen ingress in the system in presence of H2S. However, it is still possible to keep an acceptable level of viscosity by fine-tuning protective additives.This study demonstrates the applicability and limitations of thermo-responsive polymers, especially in conditions that mimic Oman oil fields. These new thermo-responsive polymers are promising candidates to keep CEOR economically viable in tough conditions.

In the Sultanate of Oman, oil and natural gas related activities have the most important shares of the nation׳s gross domestic product (GDP) and are also the primary cause of greenhouse gas (GHG) emissions within the country. In this study, the CO2 inventory for Oman was developed over the last forty two years (from 1972 to 2013) in accordance with the IPCC reference approach. The results indicated that over the years, the amount of crude oil and natural gas produced and locally consumed in Oman have drastically increased. As a result, CO2 GHG emissions resulting from the consumption of crude oil and natural gas in Oman have also greatly increased. This study aims to assist Oman in monitoring its progress in the reduction of CO2 emissions.

Over 60% of the world’s discovered oil reserves are held in carbonate reservoirs, which are mostly naturally fractured. Conventional water flooding results in low oil recovery efficiency in these reservoirs as most of them are oil-wet. On account of negative capillary forces, injected brine cannot penetrate simply into an oil-wet matrix of fractured formations to force the oil out. Wettability alteration of the rock surface to preferentially more water-wet state has been extensively studied using both smart water and surfactants separately. This study aims to study the effects of Mg2+ as one of the most important wettability influencing ions on the wetting properties of oil-wet carbonate surfaces in the presence and absence of cationic surfactant. Different analytical tools were utilized to examine the interactions between calcite surface, Mg2+ and surfactant. Results show that, magnesium ions are able to remove the strongly adsorbed carboxylate group from the surface and change the wettability of calcite surface to more water wet status. However, the presence of surfactant improves this process and enhances the wettability alteration toward more water wet. It has been demonstrated that the interaction of magnesium ions with adsorbed carboxylate on the surface hence forming a complex with carboxylate group as well as ion–pair formation between cationic surfactant and adsorbed carboxylate are the main mechanisms of wettability alteration which has resulted in removing the carboxylate from the calcite surface.

Standard industry practice to correct absolute gas permeability for what is known as the Klinkenberg effect is to perform single point gas permeability measurement and use assumptions or existing correlations. Available correlations for Klinkenberg-correction of gas permeability are based on measurements of sandstone samples. However, correlations developed for specific fields/formations may not be applicable for other reservoirs of different lithology due to the difference in the pore geometry. The present experimental investigation was conducted for the purpose of establishing one or several correlations for correcting single point gas permeability measurements (standard conventional core analysis) for the Klinkenberg effect for the Shuaiba Formation (carbonate) as well as to learn whether there is any significant difference between the sandstone-based correlation and the new results for the Shuaiba limestones. Measurements were made on 175 core-plug samples from the Shuaiba Formation. This limestone unit (Shuaiba) was chosen for study as it is an important oil reservoir in Oman and in the Middle East. Multi-point gas permeability ( K g ) was measured for each sample at four different mean pressures and extrapolated to infinite pressure to obtain the Klinkenberg-corrected gas permeability ( K L ). Correlation between K L and K g was then established. The robustness of the derived correlation has been validated using existing data (95 additional samples) from another study conducted in parallel to this study on core samples from similar formation (Shuaiba). The results can be useful for directly applying Klinkenberg-correction to other gas permeability data measured at only a single pressure.

Worldwide, many countries are being affected by greenhouse gas (GHG) emissions. The Sultanate of Oman is no exception. In Oman, both oil- and natural-gas-related activities have the most important shares of the nation's Gross Domestic Product (GDP). Hence, they are expected to be the primary cause of GHG emissions within the country. In this study, the greenhouse carbon dioxide emissions (CO 2 ) released from the fossil fuels (i.e., oil and natural gas) used in the country for energy production purposes was computed by using the Intergovernmental Panel on Climate Change (IPCC) reference approach for National Greenhouse Gas Inventories. The objective was to develop the CO 2 emissions for Oman over the last 40 years starting from year 1972. The obtained results indicated that Oman has a growth in its CO 2 GHG emissions. This study is very important and essential, as it will assist Oman to monitor its progress in reducing CO 2 emissions. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

Polymer-enhanced-oil-recovery (EOR) operation has been implemented for the production of oil from difficult mature oil fields in Oman. The polymer used to sweep oil toward production wells in this EOR technique is resulting in the generation of polymer-flood produced water (PFPW) of increasing viscosity. Current methods of treating oilfield produced water must be reconsidered for the effective treatment of PFPW of such changing quality. In a previous study, the use of polyaluminum chloride (PAC) was proposed for the coagulation of oil in produced water to be separated by flotation and filtration. As such, laboratory tests were conducted to evaluate the applicability of PAC and other chemicals for treatment of PFPW with higher viscosity than ordinary oilfield-produced water. These tests indicated clearly that aluminum sulfate (AS) was more effective for treatment of such higher-viscosity water. A pilot plant developed during the earlier study was used to conduct coagulation/flocculation-, flotation-, filtration-, and adsorption-treatment trials for PFPW from an oil field at which polymer EOR was under way. For the final trial, the inlet PFPW viscosity was 1.4 cp at 40°C and oil concentration was greater than 200 mg/L. AS was applied for the coagulation/flocculation and flotation stages, and was found to be effective in reducing oil concentration to 1 mg/L. Filtration and adsorption stages resulted in further improvement of water quality. Most of the polymer used for EOR was believed to have been removed along with oil and suspended solids.

Due to the presence of non-sulfonated residual alkyl ether (AE), sodium alkyl ether sulfonate (SAES) may exhibit clear point-cloud point solubilization behavior in brine. Accordingly, the effect of temperature on the compatibility of iC17EOxS (x = 7 and 10), nC17EO10S, along with their analogous nonionic surfactants iC17EOxH (x = 7 and 10) and nC17EO10, in addition to iC9EO14 in brine has been investigated. Depending on their molecular structures, these surfactants exhibited concentration-dependent clear point and cloud point solubilization behavior. The cloud point was associated with the AE component whereas the clear point was attributed to the sulfonated one. Interestingly, an increase in the cloud point of the nonionic component with respect to the corresponding nonionic AE (100 % active) was observed. Adding iC9EO14 (100 % active) to iC17EO7S (x an = 0.0–0.362) resulted in a significant decrease in the clear point of iC17EO7S from above 100 °C to below 22 °C with a concomitant increase in iC17EO7/iC9EO14 mixture cloud point from 68 °C. (x an = 0) to 72 °C (x an = 0.325). This relatively modest increase by 4 °C was attributed to the interrelationship of different competitive mechanisms, namely an increase in mixed micelle charge with increasing x an, the dehydration of OE groups via ion (SO3 −)-dipole (O → CH2) interactions, and possible shielding of SO3 − groups by iC9EO14 nearby extended EO groups. To the best of our knowledge, this is the first instance where dual anionic-nonionic solubilization behavior of SAES in brine characterized by high salinity and hardness is being reported.

A study of rheological behavior and mechanical degradation of hydrolyzed polyacrylamides (anionic) used in EOR/IOR applications under low-to-medium shear rates (γ

High-molecular-weight (HMW) polyacrylamide and its derivatives are widely used in oilfield applications ranging from drilling fluids, enhanced oil recovery (EOR), and treatment of oil sand tailings. In these applications the adsorption characteristics of these polymers are essential since it would affect their applicability and efficiency. In this study, adsorption of three high-molecular-weight polymers (nonionic (NPAM), partially hydrolyzed (HPAM), and sulfonated (SPAM) polyacrylamides on silica surfaces from 2% KCl) is characterized using a quartz crystal microbalance with dissipation monitoring (QCM-D) and an AFM-based colloidal probe apparatus. QCM-D measurements show that semiequilibrium for adsorption on silica surfaces is reached within 3 h. The adsorbed amount and adsorption rate are highest for NPAM and lowest for SPAM. AFM experiments revealed that after 20 min of incubation in solution, HPAM induced bridging attraction on approach (i.e., compression). On the other hand, only a weak attraction ...

The aim of this study is to develop and optimize a low tension water flood (LTWF) as an option for enhanced oil recovery in a tightcarbonate oilfield using a mixture of formation brines as injection water (total salinity: 165.9 g/L, Ca2+: 12.3 g/L, Mg2+: 2.0 g/L, and T = 70 °C.). In our approach, a combination of an anionic surfactant (alkyl ether sulfonate, C17EO7S(C17EO7) and a nonionic surfactant (alkyl ether, iC13EO10) were used to formulate clear and stable surfactant solutions at reservoir conditions. Formulation and optimization of a LTWF at a very low total surfactant concentration (0.01 wt%) was achieved through surfactant/brine compatibility tests (target: clear and stable surfactant solution), surfactant solution/oil interfacial tensions (target: ~ 10-3 mNm-1), phase behavior (target: type II(-) oil-in-water microemulsion) and core flooding experiments. Compatibility tests showed that the cloud point of the nonionic surfactant (0.01 wt%)is lower than the reservoir temperature (70 °C) whereas the clear point of the anionic surfactant is above the boiling point of water, suggesting that both surfactants cannot be used alone at reservoir conditions. On the other hand, clear and stable mixture of anionic/nonionic surfactants in the composition range fw = 0.1 – 0.8 (fw being the weight fraction of the nonionic surfactant) at 0.01 wt% total surfactant concentration were generated above 70 °C. Clear, transparent and gel-free oil-in-water phase behavior with relatively high oil solubilization parameters (σo ~ 125) were observed for surfactant mixture (0.01 wt%, fw = 0.1-0.8). These phase behaviors tests were validated by interfacial tension (IFT) measurements. Ultralow IFT (~ 10-3mN/m) was achieved at fw = 0.2. This optimum system was selected for core flooding experiments. Injecting surfactant (0.5PV) slug into a fully water flooded carbonate core sample resulted in additional oil recovery of 10 % of OOIP. This is a very significant result owing to the low surfactant concentration used (0.01 wt%). In another experiment, injecting a surfactant slug (0.5 PV) before water injection resulted in a total recovery of 75% of OOIP. In addition, Amott-Harvey test showed that wettability indices of the core plug samples used in the experiments changed within a narrow range (– 0.231 to + 0.164); suggesting an alteration of wettability from slightly oil-wet to weakly water-wet state.

This study investigates the effect of two alkali metal cations (Li + , K + ) on the adsorption of high-molecular-weight, nonionic polyacrylamide on glass surfaces using a colloidal force probe. The effect of two different anions (Cl − , NO 3 − ) on polymer adsorption is also presented. There is a general consensus that hydrogen bonding is the main mechanism by which nonionic polyacrylamides adsorb to silica and glass surfaces. In the current study, the adsorption of the polymer is found to result in repulsion on approach as early as 20 min of incubation in polymer solutions using both 0.27 M lithium and potassium chlorides. On the other hand, adhesion on retraction occurs in both solutions but with higher magnitudes for the polymer solution prepared in potassium chloride. Adhesion on retraction in potassium chloride solutions occurs even after 24 h of incubation, whilst the adhesion disappears in lithium chloride after 24 h of incubation. The force at hard contact measured in the potassium chloride solution is generally one order of magnitude lower than those measured in lithium chloride. This indicates that the adsorbed polymer molecules in potassium chloride solutions attain flatter conformation than the ones in lithium chloride. This is attributed to the higher ability of the potassium cation to increase the adsorption energy of the polymer to the glass surface. This higher adsorption energy results in the adsorbed amount of the polymer in KCl being higher than in LiCl. Because of their lower hydration and larger size compared to lithium, potassium cations decrease the hydration of the glass surface and they have the ability to bind with the oxygen atoms in the polymer molecule to the negatively-charged sites on the glass surface. With potassium nitrate, the approach–retraction measurements indicate different adsorption kinetics of polyacrylamide compared to potassium chloride. The nitrate enhances the extension of the adsorbed polymer molecules away from the surface, reflected by the longer ranged steric repulsion in the approach measurements conducted during 24 h of incubation. This is probably attributed to the large size of the nitrate anion, its lower hydration and different chemical structure, which allow it to form H-bonds with the polymer. Hence, the polymer is prohibited from forming H-bonds with the surface allowing it to extend away from the surface. This also negatively affects the adsorbed amount, which is found to be lower than in LiCl.

Two sets of adsorbents were prepared from locally available raw materials, characterized and tested. The first set consists of crushed natural attapulgite and crushed attapulgite mixed with petroleum tank-bottom sludge and carbonized at 650 °C. Another set was prepared using trunk of date palm tree (Phoenix dactylifera) activated at 700 and 800 °C. Both sets were characterized using BET surface area and pore distributions, FTIR, XRD, SEM and TEM. Natural attapulgite and attapulgite/sludge composite exhibited different characteristics and adsorptive capacities for oil removal from oily water. Adsorptive capacities were calculated from the breakthrough curves of a column test. An oily water solution of about 500 mg-oil/L was passed through both the attapulgite and attapulgite/sludge columns until the column effluent concentration exceeded a reference limit of 10 mg-oil/L. Uptake was calculated at this limit at 155 and 405 mg-oil/g-adsorbent, respectively. This was lower than the performance of a commercial activated carbon sample (uptake calculated at 730 mg-oil/g-adsorbent). Relatively, the date palm, carbonaceous-based adsorbent samples showed less significant differences in both bulk and surface properties. Uptake significantly improved to 1330–1425 mg-oil/g-adsorbent. Attempt was made to associate this performance with the difference in the surface areas between the two sets. However, other factors are found to be important as the second set has a range of surface area less than that of the commercial sample. As evidenced by FTIR, XRD and TEM, the activated carbonaceous materials developed porous structures which form defective graphitic sheet ensembles that serve as additional adsorption sites in the sample.

Reservoir studies that are based on simulation techniques require data of absolute liquid permeability for static initialization of the dynamic model. Standard industry practice for determining permeability is to perform single point gas permeability measurements and use assumptions or correlations to get Klinkenberg-corrected gas permeability to be used in the dynamic model as the value for absolute liquid permeability or use values of liquid permeability based on a limited number of measured brine permeability. Corrected gas permeability is always higher than the absolute liquid permeability. A series of brine permeability measurements has been carried out on core samples from the Shuaiba formation with the objective of establishing a correlation between these data and previously measured Klinkenberg-corrected gas permeability data on the same core samples. This correlation is potentially useful for converting Klinkenberg-corrected gas permeability data from the Shuaiba formation to liquid permeability for input to the dynamic model.

Water table dynamics, dissolved oxygen (DO) content, electrical resistivity (ER) in monitoring wells and air pressure in the vadose zone are monitored in air sparging (AS) accompanied by soil vapor extraction (SVE) at a hydrocarbon-contaminated groundwater site in Oman, where a diesel spillover affected a heterogeneous unconfined aquifer. The formation of a groundwater mound at the early stage of air injection and potential lateral migration of contaminants from the mound apex called for an additional hydrodynamic barrier constructed as a pair of pump-and-treat (P&T) wells whose recirculation zone encompassed the AS and SVE wells. In all monitored piezometers the phreatic surface showed a rapid and distinct peak, which is attributed to the time of air breakthrough from the injection point to the vadose zone and a relatively mild recession limb interpreted as a decay of the mound. Tracer tests showed a layer of a relatively low hydraulic conductivity at an intermediate depth of the screened interval of the wells. Increased levels of DO and borehole air pressure that have been observed (as far as 50 m away) are likely mitigated by SVE and P&T. Radius of influence can be indirectly inferred from ER and DO changes in the AS operation zone. Salt tracer tests have shown that groundwater velocity within the AS zone decreases with the increase of air injection rate.

Yibal oil reservoir, a fractured carbonate formation located in the north of Oman and characterized by high salinity brine and high temperatures, is a potential candidate for enhanced oil recovery (EOR) projects. This experimental study focused on the possibility to use surfactant injection as an EOR process in the Yiabl field. On the basis of the results from our previous investigations, ethoxylated sulfonates and amphoteric surfactants were used in this study. Selected surfactants showed a great tolerance to high salinity and temperatures. All surfactant systems displayed dynamic interfacial tension (IFT) behavior, in which transient ultra-low IFTs were detected. Dilute surfactant solutions (0.1 wt %) were considered for core-flooding tests on limestone plugs. In one set of experiments, surfactant solutions were injected into a fully water-flooded core (surfactant tertiary recovery). In another set, surfactant solutions were injected without pre-water-flooding (surfactant-modified water-flooding or surf...

The effect of surfactant concentration on the occurrence and detection of transient ultralow interfacial tension (IFT) between crude oil and formation water at 75 °C has been investigated using a series of novel sodium alkyl ether sulfonates having various increasing molecular weights and degrees of ethoxylation. All surfactant systems displayed dynamic interfacial tension (DIT). Transient ultralow DIT (DITmin) were detected only within an intermediate surfactant concentration. This behavior was attributed to an implicit concentration-related length scale required for the added surfactant to diffuse from the bulk phase to the freshly prepared oil–water interface. In the high surfactant concentration range, this length scale is relatively short and results in an instantaneous (and undetectable) occurrence of DITmim in a relatively very short time scale, well beyond the detection limit of the spinning drop tensiometer (~2–3 min). Interestingly, DITmin were detected only in systems above the surfactant’s critical micelle concentration, suggesting that DITmin occurs as a result of the diffusion (subsequent to the adsorption) of the oil acidic species from the interface to the bulk phase to form mixed micelles with the added surfactant. Measurements of DITs in the presence of decane showed no evidence for DITmin, confirming the general belief that DITmin is indeed due to the interaction of the added surfactant with the oil acidic components. Finally, the effect of surfactant concentration on the equilibrium IFT (γeq) showed evidence for relatively low values (~10−2 mNm−1) for some surfactant systems.

The present study addresses the efficiency of an integrated air sparging, soil vapor extraction, and pump and treat system in the remediation of a diesel contaminated site in Oman. Cleanup efforts have targeted groundwater and soil in fractured formations. Site hydrogeological characterization was conducted including sampling and analysis of water and soil. Within seven months of the start of the treatment system, benzene gas in the unsaturated zone fell from an initial range of 15–60 ppm to below detection level, while total petroleum hydrocarbon in the groundwater dropped from 25–50 ppm to less than 0.5 ppm. Treatment processes have ceased while groundwater and soil are being monitored. Thus far, benzene gas has been undetected for the past 18 months, but total petroleum hydrocarbon in groundwater has rebounded to 1.2 ppm during the last four months.

The carbonization of coal/KOH mixtures were investigated to identify the influence of potassium distributions on characteristics of the final products. The products were characterized using TGA, BET, TEM and adsorption of lead from its aqueous solutions with initial concentrations of 10–100 ppm. For the activated carbon obtained at 600 °C, the potassium distribution affected both the BET surface areas (661–1994 m2/g) and the meso- and micro-pore volumes ratios (0.48–0.91). There were also evolutions of nanostructures of both straight and curved tubular morphologies as evidenced by TEM micrograph. The samples exhibited different adsorptive capacities when tested in adsorption of lead from aqueous solutions. The adsorption followed second order kinetics and the equilibrium data were better described by empirical Freudlich isotherm model. The amount of lead adsorbed ranges from 4.3 to 47.3 mg/g. Thus, different degrees of potassium effects led to activated carbons with different surface and adsorptive properties.

Samples of lignocellulosic material, stem of date palm (Phoenix dactylifera), were carbonized at different temperatures (400–600 °C) to investigate the effects of their impregnation with aqueous solution of either phosphoric acid (85 wt%) or potassium hydroxide (3 wt%). The products were characterized using BET nitrogen adsorption, helium pycnometry, Scanning Electron Microscopy (SEM) and oil adsorption from oil–water emulsion (oil viscosity, 60 mPa s at 25 °C). True densities of the products generally increased with increase in carbonization temperature. Impregnated samples (acid/base) showed wider differences in densities at 400 (1.978/1.375 g/cm3) than at 600 °C (1.955/2.010 g/cm3). Without impregnation, the sample carbonized at 600 °C showed higher density of 2.190 g/cm3. This sample has impervious surface with BET surface area of 124 m2/g. Acid-impregnated sample carbonized at 500 °C has the highest surface area of 1100 m2/g and most regular pores as evidenced by SEM micrographs. The amounts of oil adsorbed decreased with increase in carbonization temperature. Without impregnation, sample carbonized at 400 °C exhibited equilibrium adsorption of 4 g/g which decreases to about a half for sample carbonized at 600 °C. Impregnation led to different adsorptive capacities. There are respective increase (48 wt%) and decrease (5 wt%) by the acid- or base-impregnated samples carbonized at 600 °C. This suggests higher occurrence of oil adsorption-enhancing surface functional groups such as carbonyl, carboxyl and phenolic in the former sample.

Activated carbon samples of different porosities and other characteristic features have been prepared using bituminous coal–KOH feedstocks of different degrees of pre-drying. The feedstocks were subjected to thermogravimetric analysis from 30 to 1000 °C. Different weight loss profiles and carbon burnt-off were obtained. This was associated with different level of potassium intercalations in the coal matrix and concomitant different extent of reactions with carbon. Another set of feedstocks was carbonized at 600 or 800 °C to obtain samples of activated carbon. The activated carbons were characterized using BET surface area, SEM, FTIR and XRD. These reflected the effects of pre-drying on the products. The surface area and Vmeso/Vmicro ratio increase with increase in duration of pre-drying. XRD profiles indicated lower proportion of aromatic stacking in the sample with highest surface area (1994 m2/g) and Vmeso/Vmicro ratio (0.91) than in the other samples. The pre-drying could be used as a key variable for obtaining activated carbons of different porosities.

A mechanism of a commingled Huff 'n Puff cycles of gas cross flow from a highly pressurized lower formation into a depleted upper formation has proven to be effective in reducing gas-well productivity losses due to near-wellbore condensate dropout. Compositional simulation was used to evaluate the performance of gas wells hampered by liquid dropout and to assess ways of producing the gas field. As a result of liquid re-vaporization the study shows that an appropriate scheduling of huff 'n puff shut-in and production cycles lead into a decline of in-situ liquid dropout and an increase in surface liquid recovery.

Heavy crude oil from the Mukhaizna oil field in Oman was emulsified with water in an attempt to decrease its viscosity. The oil has a kinematic viscosity of 7160 mm2/s at 30 °C, density of 0.9571 g/cm3 at 15 °C, and asphaltene content of 4.7 wt %. The effects of changes in water content (20−30 wt %), type and concentration of surfactant, addition of a water-soluble polymer, and agitation temperatures (25 and 42 °C) were studied in order to identify the optimum viscosity and stability for transporting the oil. The stability was measured by the water separation rate from the emulsion. For the Mukhaizna heavy crude oil, 21−22 wt % of water content and 0.4 wt % of nonylphenol ether type or higher alcohol alkylene oxide type surfactant were found to be optimum for a stable emulsion with a concomitant significant decrease in viscosity to about 1/3−1/4 that of the original crude oil. This improves the transportability of the heavy crude oil and makes it suitable for use as a power generation fuel.

In this study, Huff 'n Puff technique is used as a production mechanism to revaporize liquid dropout in the Saih Rawl retrograde condensate gas field, Oman. During the huff cycle, a number of wells were shut in to achieve revaporization. The same wells were put on stream, during the puff cycle. Liquid dropout induced a mechanical skin around the wellbore and hampered gas production capabilities but has been revaporized through pressurization. The pressure buildup in the rich-gas condensate reservoir was due to a cross flow originating from a deeper highly pressurized lean-gas bearing formation. The pressure communication was taken place through the wellbore during shut-in cycles. A compositional simulation model was used to confirm the theory of condensate revaporization. Simulation results indicated that Huff 'n Puff is a viable production technique. The technique improved gas deliverability and enhanced gas–liquid production by minimizing the skin caused by gas–liquid dropout.

A novel technology has been developed for in-depth profile control based on thermo-gelling polymers (refers as THR). This technology differs from the ones currently used through different aspects. Thermo-gels polymers spontaneously gel when they reach a threshold temperature. Below this temperature, the product behaves as low-viscosity fluid, with good injectivity in reservoir rock. The system is single-component, and does not require any additive, contrary to classical gel systems which need to mix a polymer with a cross-linker (and often additives) to control gelation time. It is thus of easy control and does not face the drawbacks of two- or multi-component gel systems. Moreover this family of products is bio-sourced, thus environmentally friendly (some are CEFAS approved). Different THRs have been developed whose gel temperature varies between 25 and 85°C. The present work details laboratory evaluation of different THRs, including rheological properties, gel kinetics, gel strength, long-term stability and coreflood experiments. Main results are as follows: i) gel temperature can be optimized by varying brine salinity and THR type and/or concentration; ii) gel kinetics is very rapid once the gel temperature is reached, iii) THRs remain stable over period of time superior to one year in reservoir conditions; iv) coreflooding experiments in sandstone rocks show moderate adsorption (around 50 μg/g), good injectivity below gel temperature and strong pressure build-up once gel temperature is reached. Gel strength can be as high as 35 bar/m.