Heterogeneity Effect on Polymer Injection: a Study of Sumatra Light Oil

The production of oil and gas is heavily dependent on the heterogeneity of the reservoir. Opti�mizing the production plan and maximizing recovery from the reservoir depends on an understanding of how heterogeneity affects fluid flow and recovery. Techniques such as water flooding and polymer flooding were used to increase oil production from reservoirs while evaluating the impact of reservoir heterogeneity. Numerical simulations in homogeneous and heterogeneous models were performed in this research to identify the optimal operational parameters that will optimize oil recovery and assess the effect of heterogeneity in the reservoir on the recovery factor of the reservoir. The result showed that the homogeneous model obtained 59.86% of the oil recovery factor, while the heterogeneous reservoirs for Lk = 0.2, 0.4, and 0.6 resulted from 45.83%, 69.27%, and 80.46% of oil recovery after twenty years of production, respectively. The heterogeneous reservoir with Lk = 0.6 indicated the highest sweep efficiency compared to other scenarios, while the reservoir with Lk = 0.2 showed the lowest sweep efficienc

Accelerated spreading of inviscid droplets prompted by the yielding of strongly elastic interfacial films

The complexity associated with droplets spreading on surfaces has attracted significant interest for several decades. Sustained activity results from the many natural and manufactured systems that are reliant on droplet-substrate interactions and spreading. Interfacial shear rheology and its influence on the dynamics of droplet spreading has to date received little attention. In the current study, saponin β-aescin was used as an interfacial shear rheology modifier, partitioning at the air-water interface to form a strongly elastic interface (G’/G” ∼ 6) within 1 min aging. The droplet spreading dynamics of Newtonian (water, 5 wt% ethanol, 0.0015 wt% N-dodecyl β-D-glucopyranoside) and non-Newtonian (xanthan gum) fluids were shown to proceed with a time-dependent power-law dependence of ∼0.50 and ∼0.10 (Tanner’s law) in the inertial and viscous regimes of spreading, respectively. However, water droplets stabilized by saponin β-aescin were shown to accelerate droplet spreading in the inertial regime with a depreciating time-dependent power-law of 1.05 and 0.61, eventually exhibiting a power-law dependence of ∼ 0.10 in the viscous regime of spreading. The accelerated rate of spreading is attributed to the potential energy as the interfacial film yields as well as relaxation of the crumpled interfacial film during spreading. Even though the strongly elastic film ruptures to promote droplet spreading, interfacial elasticity is retained enhancing the dampening of droplet oscillations following detachment from the dispensing capillary

Dewetting Dynamics of Heavy Crude Oil: Contributions from Surface and Interfacial Forces

The research considers the dewetting dynamics of heavy crude oil on solid substrates in the presence of chemical additives and at elevated temperatures and pressures. Increasing the temperature from 40 to 80 °C was found to increase the initial receding rate of an oil droplet on substrate from 0.07 to 3.73 °/s, a consequence of the reduced oil viscosity. Higher temperatures also induced release of natural surfactants and thus decreased the oil-water interfacial tension (σ_OW), promoting increased oil droplet dewetting (equilibrium contact angle (θ) decreased from 63.7° to 51.3°), with the effect described by the Young’s equation. At high pressure (200 bar at 140 °C), asphaltenes partition less at the oil-water interface leading to slightly higher σ_OW (14.4 mN/m at 10 bar to 17.6 mN/m at 200 bar). Increase in σ_OW led to less oil dewetting as the θ increased from 17.9° to 23.1°. Adding a surfactant demonstrated the benefit of reducing σ_OW and increasing oil-substrate electrostatic repulsion. At high surfactant concentration the oil droplet attained low θ, and eventually pinched-off from the surface when the ultra-low oil-surface adhesion was exceeded by droplet buoyancy. Oil droplet dewetting was studied in brine fluids at 60 °C where the addition of salt was shown to change σ_OW depending on the synergistic interfacial adsorption of salt ions and native surface-active species (i.e. naphthenic acids and asphaltenes). However, the oil droplet contact angles in brines were more influenced by the disjoining pressure and not σ_OW as described by the Young’s equation. Increased oil droplet dewetting (θ: 43.2° in water → 18.1°) was observed in low-salinity NaCl fluid (2,000 ppm), with hydration forces strongly influencing repulsion between the oil droplet and substrate. In contrast, attractive hydrophobic forces, as measured in CaCl2 brines, acting between the oil droplet and hydrophobised substrate (via divalent cation bridging), reduced the oil droplet dewetting rate and increased θ (≥ 27.2° at 60 °C). Initial droplet receding rates were increased by a strong oil-substrate repulsion and low steady-state θ, without the influence of changing σ_OW. Surface-active nanoparticles, poly(N-isopropylacrylamide) (PNIPAM), were synthesised to study their effect on lowering σ_OW and enhancing the dewetting dynamics in the presence of surfactant. Blends of PNIPAM and SDS (1:1 mass ratio) were considered at different bulk concentrations. At low concentration (5 × 10-4 wt%), SDS interfacial adsorption was greater than PNIPAM with the dominance reversed at high concentration (5 × 10-3 wt%). The difference in interfacial activity was shown to influence the oil dewetting process, but is not fully described by the Young’s equation. Increased oil dewetting by nanoparticles was shown at low concentration, with the PNIPAM and SDS blend displacing the oil droplet at 5.66 °/s and attaining low θ (37.0°), while σ_OW remained relatively high (25.3 mN/m). This was due to PNIPAM particles remaining in the bulk fluid and self-assembling in the oil-water-substrate “wedge”, thus inducing a structural disjoining pressure, which promoted oil dewetting. In the presence of NaCl (2,000 ppm), contributions from PNIPAM induced further structural forces that led to a gradual liberation of oil from the substrate, even though the droplet buoyant force was less than the oil-substrate adhesion force

Evaluation of effecting factors on oil recovery using the desirability function

Abstract The new method to evaluate the contribution of the related factors to the oil recovery is proposed by using the desirability model. The related factors are re-scaled and combined to be a single parameter in order to correlate with an indicator of oil recovery. The correlated result could be able to predict a trend of the factors and oil recovery as an empirical approach if a good correlation is achieved. Three published works of the coreflooding experiments are examined the effectivenesses and limitations of the proposed model. The analysed plots of desirability and the oil recovery imply an insight into the oil recovery mechanisms by indicating the dominant factors. The results meet a good agreement with the published works. Although the dominant factors are indicated and the correlation trend is able to be determined, the accuracy of the proposed method needs a high number of data sets to increase the statistical reliability

Data associated with 'Selective separation of cesium contaminated clays from pristine clays by flotation'

Raw data of publication 'Selective separation of cesium contaminated clays from pristine clays by flotation', including sorption isotherm and modeling, XPS, XRD, Zeta potential, QCM-D, contact angle, flowCAM and flotation data, etc

Geomechanics Contribution to CO₂Storage Containment and Trapping Mechanisms in Tight Sandstone Complexes:A Case Study on Mae Moh Basin

Recognized as a not-an-option approach to mitigate the climate crisis, carbon dioxide capture and storage (CCS) has a potential as much as gigaton of CO2 to sequestrate permanently and securely. Recent attention has been paid to store highly concentrated point-source CO2 into saline formation, of which Thailand considers one onshore case in the north located in Lampang – the Mae Moh coal-fired power plant matched with its own coal mine of Mae Moh Basin. Despite a large basin and short transport routh from the source, target sandstone reservoir buried at deeper than 1000 m is of tight nature and limited data, while question on storing possibility has thereafter risen. The current study is thus aimed to examine the influence of reservoir geomechanics on CO2 storage containment and trapping mechanisms, with co-contributions from geochemistry and reservoir heterogeneity, using reservoir simulator – CMG-GEM. With the injection rate designed for 30-year injection, reservoir pressure build-ups were ~77% of fracture pressure but increased to ~80% when geomechanics excluded. Such pressure responses imply that storage security is associated with the geomechanics. Dominated by viscous force, CO2 plume migrated more laterally while geomechanics clearly contributed to lesser migration due to reservoir rock strength constraint. Reservoir geomechanics contributed to less plume traveling into more constrained spaces while leakage was secured, highlighting a significant and neglected influence of geomechanical factor. Spatiotemporal development of CO2 plume also confirms the geomechanics-dominant storage containment. Reservoir geomechanics as attributed to its respective reservoir fluid pressure controls development of trapping mechanisms, especially into residual and solubility traps. More secured storage containment after the injection was found with higher pressure, while less development into solubility trap was observed with lower pressure. The findings reveal the possibility of CO2 storage in tight sandstone formations, where geomechanics govern greatly the plume migration and the development of trapping mechanisms