Investigation of the effects of low-salinity waterflooding for improved oil recovery in carbonate reservoir cores

Water injection for both pressure maintenance and oil displacement is the most important secondary recovery method in sandstones. It has also been implemented with success in a few carbonate reservoirs, but because the most carbonate reservoirs worldwide are characterized as neutral to preferential oil-wet, normal waterflooding is usually not successful as an enhanced oil recovery (EOR) technique. It has been proved that seawater can be used as an EOR fluid for hot, fractured carbonate oil reservoirs since it is able to modify the wetting conditions and to enhance the oil recovery. The potential determining ions in seawater such as Ca²⁺, Mg²⁺, and SO₄^2- played a crucial role in altering the wettability from oil-wet to more water-wet condition because of their reactivity towards the carbonate surface. In this paper, the potential of low-salinity brine to enhance the oil recovery has been studied. Four flooding tests were conducted on both limestone cores containing anhydrite and chalk core containing no sulfate. It is observed that low-salinity brine had only effect on rocks containing anhydrite. The dissolution of anhydrite, CaSO₄, which is the source for SO₄^2-, is depending on salinity/composition of brine and the temperature. The dissolution of anhydrite normally increases as the temperature decreases. Lowering the salinity of injection brine increases the reactivity of the surface-active ions SO₄^2- and Ca²⁺.     

Impact of wettability on storage and recovery of hydrogen gas in the lesueur sandstone formation (Southwest hub project,Western Australia)

Geological storage has been proposed as a new technology to temporarily store significant amounts of hydrogen (H₂) gas in depleted gas reservoirs, underground salt caverns, or saline aquifers. Often, such subsurface reservoirs naturally contain trace amounts of organic acids, and these compounds can considerably alter the wettability of reservoir rocks, causing them to become less water-wet. We carried out Molecular Dynamics (MD) simulations of contact angles in a quartz-brine-H₂ system to evaluate wettability in realistic subsurface situations. MD simulations suggest that Humic acid makes quartz more hydrophobic, which can affect the overall behaviour of the storage reservoir. For the first time, this effect was experimentally investigated for a natural sandstone reservoir from the South West Hub Project, i.e., the Lesueur Sandstone (LS) formation. Multi-stage core flooding experiments were conducted on the same LS plug to investigate the impact of wettability alteration on initial and residual hydrogen saturation/trapping at depth. First, consecutive brine-H₂ drainage-imbibition cycles were carried out on the natural sample; the result indicated that the rock-brine-H₂ system was essentially water-wet. Then, the sample was aged in Humic acid with a molarity of 10⁻² M for 42 days at 5 °C and 0.1 MPa. The wettability of the storage system shifted toward a less water-wet state, i.e., more hydrophobic. As a result of Humic acid ageing, the initial hydrogen saturation reduced from 29% to 15%, and the residual hydrogen trapping reduced from 23% to 11%. This is attributed to a change induced in the capillary force (i.e., snap-off) controlled by wettability and pore size. In addition, the wettability change induced by Humic acid increased the hydrogen recovery rate from 20.7% to 26.7%.     

Impacts of pore structure and wettability on distribution of residual fossil hydrogen energy after imbibition

Due to the heterogeneity of the pore structure, there is still much residual fossil hydrogen energy in the pore space. In this study, the distribution of residual fossil hydrogen energy after imbibition with liquid nanofluid (LNF) has been studied through the. Firstly, relevant properties of the LNF were tested, including particle size, wettability alteration, and interfacial tension (IFT). Then, one micromodel under both oil-wet and water-wet conditions was used to elucidate the difference of residual oil after imbibition. Moreover, the difference of imbibition processes with oil-wet and water-wet models was further studied. Finally, the influence of dimensions and coordination numbers of pores was investigated. Besides, the impact of fluid type on imbibition efficiency was also compared through microfluidic experiments. Results show that the residual oil saturation is significantly higher in the oil-wet micromodel than in the water-wet micromodel, even the wettability alteration additive was used. There are four kinds of locations for residual oil after imbibition in water-wet micromodel, while only three kinds of locations for residual oil in oil-wet micromodel. The imbibition rate and residual oil saturation in small pores are higher than the larger ones. Due to the unbalanced force at pore throats, a micromodel with a high coordination number has lower residual oil saturation. Besides, the lower residual oil saturation is obtained by adding the LNF. This paper provides a micro-visual method to understand the imbibition process under different wettability and pore structures in fossil hydrogen reservoirs.     

Interfacial tension and contact angle measurements for hydrogen-methane mixtures/brine/oil-wet rocks at reservoir conditions

In this study, we measured the interfacial tensions (IFTs) of brine/hydrogen-methane (H₂–CH₄) mixtures. We also measured the static contact angles of H₂–CH₄ mixtures in contact with brine and oil-wet sandstone and limestone rocks at reservoir conditions. The measurements were conducted using pendant drop and rising/captive bubble techniques. The techniques were first validated for pure gas/brine IFT and contact angle systems. Then, the impacts of temperature and H₂–CH₄ mixture fraction in contact with oil-wet rocks were investigated systematically. IFT values of H₂–CH₄ mixture/brine diminished with increasing temperature and decreasing hydrogen fraction. It is revealed that, under the studied conditions, H₂–CH₄ mixtures exhibit comparable weakly water-wet behavior on oil-wet sandstone and limestone rocks with contact angles ranged within [52.42°-71.1°] independent of temperature. The results also indicated that IFT of H₂–CH₄ mixture/brine decreases with increased temperature and methane fraction. Finally, the mechanisms accountable for the observed rock-fluid interaction behaviors at different conditions were discussed.     

Adsorption of a nonionic surfactant onto a silica surface

Chemical flooding is technically feasible to increase oil recovery from depleted sandstone reservoirs with low pressure. Polymer-surfactant flooding is a potential process in the chemical flooding methods for enhanced oil recovery (EOR) in sandstone porous media. However, chemical additive cost and surfactant loss due to adsorption on the reservoir rock are the main concerns in this type of EOR processes. This paper presents adsorption equilibrium of a natural surfactant, Zyziphus spina-christi, onto a real sandstone reservoir. Batch adsorption experiments were carried out to figure out the impacts of adsorbent dose on adsorption performance. The equilibrium adsorption data were analyzed with two common adsorption models and it was found that the Freundlich model is a pretty good fit for adsorption equilibrium of Z. spina-christi based on the value of determination coefficient (R²). Results from this study are instructive for appropriate selection of surfactants in design of EOR processes and reservoir stimulation plans for sandstone reservoirs.     

Surfactant tunable hierarchical nanostructures of CdIn2S4 and their photohydrogen production under solar light

The hierarchical nanostructures of CdIn₂S₄ were selectively prepared through hydrothermal process in the presence of different surfactants. Structural study demonstrated existence of cubic spinel structure and micro structural study shown a pretty marigold flower like morphology without any surfactant. The effect of surfactants on the morphology and microstructure of CdIn₂S₄ has been studied by using Polyvinyl pyrrolidone (PVP) and Cetyltrimethyl ammonium bromide (CTAB) as a surfactants. The CdIn₂S₄ bipyramids with length of 0.7-1 μm have been obtained using PVP. Interestingly, the nanopetals (thin and transparent) of CdIn₂S₄ are self assembled into hollow spheres in the presence of CTAB. Considering the importance of these unique nanostructures, the growth mechanism has also been proposed. The optical properties demonstrated the band gap in the range of 2.12-2.29 eV which is well within the visible region. In this contest, photocatalytic activity for hydrogen production using the above nanostructures under visible light was also demonstrated. The prima-fascia observations shows that the bipyramidal CdIn₂S₄ exhibit excellent photocatalytic activity for hydrogen production (3238 μmolh⁻¹) than other nanostructures. Being a nanostructured semiconductor chalcogenide with a good stability will also have potential applications in solar cells and LED.     

Experimental studies of ionic surfactant adsorption onto carbonate rocks

One of the main factors in chemical-based enhanced oil recovery, especially surfactant flooding, is a surfactant adsorption loss onto the reservoir rock. The main aim of this article is performing systematically a study on the adsorption behavior of an industrial ionic surfactant, which is currently employed in petroleum upstream. It is worth mentioning that sodium dodecyle sulphate was employed as an ionic surfactant in this study. Moreover, adsorption density at equilibrium condition was determined. Crushed carbonate rocks were used as rock samples. To determine adsorption behavior of the aforementioned surfactant onto carbonate surface, various surfactant concentrations were created in the range of 500 to 5,000 ppm. Furthermore, via using an electrical conductivity measurement, the surfactant concentration in each solution before and after contacting with carbonate rocks was determined. Two well-known adsorption isotherms, including Freundlich and Langmuir, were employed to specify the adsorption mechanism. Based on the experimental results the Freundlich adsorption isotherm can predict the adsorption behavior of SDS onto carbonate rock surface.     

Effects of relative permeability change resulting from interfacial tension reduction on vertical sweep efficiency during the CO2-LPG hybrid EOR process

The addition of liquefied petroleum gas (LPG) to the CO₂ stream reduces interfacial tension (IFT) between the injected gas and the reservoir oil, and it changes the gas-liquid relative permeability by making it more water-wet, which affects not only the oil mobility, but also the vertical sweep efficiency. The reduction of the IFT decreases vertical sweep efficiency because it enhances the relative permeability of the solvent, resulting in an increase in the viscous gravity number. For CO₂-LPG enhanced oil recovery (EOR), oil recovery is enhanced by up to 47%, as compared to CO₂ flooding, when the relative permeability change caused by the IFT is not considered. By taking the vertical sweep-out caused by IFT and relative permeability change into consideration, this increase is reduced to 40%. These results indicate the importance of considering the relative permeability and IFT change when predicting the performance of the CO₂-LPG EOR process.     

Salinity,temperature and pressure effect on hydrogen wettability of carbonate rocks

Hydrogen had been injected into the geologic formations, and the geologic formation wettability would influence the hydrogen storage. Hydrogen wettability of sandstone reservoirs (quartz), mica and other rocks have been explored in the previous study. However, the research on hydrogen wettability of carbonate rocks was lacked. In this study, we studied the carbonate rock wettability alteration when exposed to the hydrogen environments. Salinity, temperature and pressure effect on H₂/carbonate rock/brine wettability were explored. When the solutions ions concentration increased, the advancing/receding contact angle would increase, and divalent ions could make the contact angle higher than monovalent ion, which was because ions could compress the electric double layer. The carbonate rock powder in brine showed negative charge, and the zeta potential increased with higher ions concentration. When temperature increased and the pressure decreased, the contact angle would decrease, which was related to the H₂ gas density and molecular interactions.     

Application of SiO2 and TiO2 nano particles to enhance the efficiency of polymer-surfactant floods

Polymer-surfactant flooding is one of the most novel chemical enhanced oil recovery methods. Application of Nano particles in enhanced oil recovery has attracted much interest as well. This work concerns the application of Nano particles to increase the efficiency of polymer-surfactant flooding in heavy oil five-spot systems. In this investigation, micromodel setup was used to monitor the role of Nano particles on wettability alteration during polymer-surfactant floods. Two common Nano particles, SiO₂ and TiO₂ as well as HPAM and SDS as commercial chemicals in enhanced oil recovery, were used to create five solutions containing Nano particles at different levels of concentration. Then, contact angle tests and flooding tests were performed by taking microscopic/macroscopic pictures. According to the results, since SiO₂ Nano particle decrease the contact angle more severely, it results in a higher oil recovery. Although this decrease is more when SiO₂ is dispersed in water, due to its better absorption on a surface, the wettability alteration is more obvious during polymer-surfactant flooding because of the presence of a thinner oily film that intensifies mass transformation from fluid to the surface. In addition, an increase in the concentration of Nano particles leads to an increase in the efficiency of oil recovery and wettability alteration. Furthermore, according to the microscopic pictures, pulling and emulsification mechanisms are more effective than the wettability alteration mechanism.     

Immiscible CO2 Flooding through Horizontal Wells

Abstract

The CO₂ immiscible process is a potentially viable method of enhanced oil recovery (EOR) for heavy oil reservoirs. In an immiscible CO₂ process, part of the injected CO₂ is absorbed into the reservoir fluids and part forms a free-gas phase in the reservoir. Three groups of well configurations were mainly used: (1) vertical injection and vertical production wells, (2) vertical injection and horizontal production wells, and (3) horizontal injection and horizontal production wells. In immiscible CO₂ injection, highest recovery was obtained by vertical injection-horizontal production (VI-HP), followed by vertical injection-vertical production (VI-VP), and the least by horizontal injection-horizontal production (HI-HP). In VI-HP well configuration, the best recovery was obtained as 15.1% OOIP. In continuous CO₂ injection experiments, oil recovery for the VI-HP well configuration was higher than that of the other well configurations. The lowest ultimate recovery was obtained from HI-HP well configuration. The distance between the horizontal injector and horizontal producer was another important factor for the displacement of oil. In all runs, CO₂ breakthrough occurred very early, showing the dominance of viscous forces and relatively small effect of mass transfer between CO₂ and oil. The total oil recovery varied considerably because of the differences in injection rates and because of the unstable displacement. As a whole, oil recovery increased with an increase in the injection rate of CO₂. The cumulative gas-oil ratio (GOR) appeared to be sensitive to the gas injection rate for all well configurations. An increase in oil recovery with injection rate during initial stages of the runs was affected by the cumulative GOR.     

Experimental and theoretical study of asphaltene deposition and permeability impairment in low-permeability carbonate cores

Asphaltene deposition is one of the problems that oil industries face during oil production, processing, transport, and refining. Deposition of asphaltene flocculation on reservoir rock can plug pore spaces and cause permeability impairment. Carbonate rock, which has low permeability, tend to adsorb asphaltene causing more loss of permeability. In this study, three miscible CO₂ injection core tests were conducted at reservoir conditions and the effects of asphaltene content on the amount of formation damage in carbonate cores with low permeability were investigated. High asphaltene content oil has been used in the experiments. Results show that permeability reduction was more than porosity losses. An empirical model for permeability impairment was derived based on experimental data by considering the activation of the two mechanisms simultaneously. The results may be useful for understanding permeability impairment mechanisms during gas injection in low-permeability carbonate cores.     

Enhancing the photocatalytic hydrogen evolution of copper doped zinc sulfide nanoballs through surfactants modification

In this study, copper-doped zinc sulfide nanoballs were successfully synthesized in DI water and ethanol solvent by a sonochemical approach using surfactants in aqueous medium, such as citric acid (CIT), sodium dodecyl sulfate (SDS), cetyltrimethylammonium bromide (CTAB), cetylpyridinium bromide (CPBr), polyethylene glycol (PEG), polyvinyl pyrrolidone (PVP), and polyvinyl butyral (PVB). Since surfactants are usually organic compounds that are amphiphilic molecules and surface-active agents with unique properties stemming from their exclusive structure with a hydrophobic tail and hydrophilic head, they can self-organize to form colloidal aggregates of different morphologies. TEM images show that copper doped ZnS crystallites without surfactant have a hollow-sphere-like self-assembled nanostructure. When 2.0Cu/ZnS was prepared with CTAB surfactant, it had a flower-like microspheres. The other surfactants would make copper-doped zinc sulfide exhibit the nanospheric structure. The surfactant plays an important role on the transfer of photogenerated electrons and holes and prevents non-radiative recombination of electrons and holes at surface sites. Therefore, surfactants could significantly improve the photocatalytic activity. Hydrogen evolution from an aqueous solution containing 0.1 M Na₂S at pH 3 and 0.15 g L⁻¹ of 2.0Cu/ZnS photocatalyst with PVB surfactant had the maximum of 1137.5 μmol h⁻¹ g⁻¹.     

Use of surfactants to mitigate precipitation of nonstable asphaltensdes

In this work, we examine the effectiveness inhibition of three different surfactants (cationic, anionic, and non-ionic) with respect to aggregation of the most unstable fraction, asphaltenes, obtained from Algerian crude oil that flocculates and precipitates during oil transport and storage. Their efficacy is compared with native resins that are extracted from the same oil. We reveal from the results that the cationic surfactant didodecyl dimethyl ammonium bromide (DDAB) displayed the highest capacity to inhibit asphaltenes aggregation. This surfactant can shift considerably the aggregation onset of asphaltenes with respect to the non-ionic octylphenopoly(ethyleneglycolether)_X (TX-100) and anionic dodecyl benzene sulfonic acid (DBSA) surfactants. This finding is explained by the presence of both double alkyl chain and basic head polar (positive charge) in surfactant structure on one hand and the structural properties of studied asphaltenes (rich oxygenated negative charge sites and low aromaticity) on the other hand. Finally, the comparison between the effectiveness of native resin and the studied surfactants indicate the following order: DDAB > resin> TX-100> DBSA.     

适合大庆油田的无碱表面活性剂性能评价研究

随着油田不断开发,大庆油田开发对象正逐渐从一类油层向渗透率低、黏土矿物含量较高的二、三类油层转变,但逐步进入工业化推广阶段的三元复合驱中碱的存在会加剧对二、三类油层的伤害,因此弱碱化、无碱化成为了复合驱技术的发展方向.针对大庆油田二类油层油水条件,采用AFS-A和AFS-B无碱表面活性剂复合体系开展了二元复合驱室内研究.实验结果表明:这两种无碱表面活性剂复合体系均可在活性剂浓度为0.05％～0.3％(质量分数)范围内与大庆原油形成10-3,N/m数量级界面张力,但AFS-B复合体系亲水性较强,AFS-A复合体系亲油性较强,AFS-B复合体系抗吸附性能要好于AFS-A复合体系;驱油效率方面,在水驱基础上,AFS-A复合体系化学驱平均采收率为17.28％,AFS-B复合体系化学驱平均采收率为19.81％.     

The effect of capillary-trapped CO2 on oil recovery and CO2 sequestration during the WAG process

This study investigated capillary-trapped CO₂ depending on the consideration of hysteresis effect in relative permeability for various water-alternation-gas (WAG) operating conditions to ascertain the oil production process. From the simulation results of CO₂ WAG flooding method, the trapped CO₂ led to prevent water-flow, in which CO₂ acts as a gas blocker near the well. It caused the injection pressure increase during water injection period. As the trapped CO₂ in pores increased, the reservoir pressure was also increased and maintained above minimum miscibility pressure (MMP). Ultimately, it was concluded that the reservoir was kept under miscible conditions throughout WAG process, reducing residual oil and increasing oil recovery.     

A comparative study of the carbon dioxide and nitrogen minimum miscibility pressure determinations for an Iranian light oil sample

Miscible gas injection is an approved profitable process that could significantly enhance oil recovery from different types of reservoirs while the major factor affecting its efficiency would be the minimum miscibility pressure (MMP) value. A recent experimental technique, known as vanishing interfacial tension (VIT), can estimate the MMP for gas–oil mixtures by measuring interfacial tension values and extrapolating them to zero at a sequence of pressures. Compositional simulation models are also useful in MMP determination by tuning an equation of state to compute the realistic phase behavior of reservoir fluid. In this paper, the capability and quality of MMP prediction via different methods such as laboratory slim tube tests, VIT technique, compositional simulation, and various empirical correlations were examined using a light oil sample taken from an Iranian carbonate reservoir, employing two pure gases of CO₂ and N₂ as the injectants. The accuracy and validation of the mentioned methods were then confirmed successfully by obtaining negligible overall absolute deviation percentages (AD%) compared with the conducted slim tube tests results.     

The numerical simulation and wellbore modelling of steam injection and stored heat recovery from light oil reservoir

ABSTRACT

Steam injection and thermal recovery of oil from the reservoir are increasing day by day. However, the recovery of the heat remained stored in the steam-flooded oil reservoir is nor in practice neither researched previously. A novel concept of steam injection and energy recovery from a light oil reservoir is presented in this paper. Reservoir numerical model of an actual oil field was generated and simulated with steam injection. Different parameters of thermal properties of geologic formations were discussed and adopted as per actual geology of the study area for more realistic simulation of heat storage, dissipation, and losses. After the optimum oil recovery, water was circulated through the same injection well into the reservoir to extract the energy in the form of heat, stored during the steam injection phase. The effects of different completion schemes of injection well were also simulated, discussed and pointed out for optimum oil recovery. Oil recovery factor is the most important parameter from both research and field development point of views. The comparative analysis was also carried out with the oil production without steam injection and found that steam flooding increased oil recovery factor up to more than 15% by decreasing the production time period up to 40% as compared to without steam injection oil production. The transmission of heat through conduction and convection mechanisms in the porous media, and through advective, dispersive and diffusive processes in the fluid was modeled. To fully investigate the feasibility of the concept presented in this paper, the production wellbore modeling was also carried out and temperature profile of recovered heat energy at the wellhead was obtained by acknowledging the thermal losses and found to be very useful for any direct and indirect utilization of heat throughout the energy recovery period of the reservoir.