Reservoir Wettability Research Articles

Enhanced oil recovery through synergy of the interfacial mechanisms by low salinity water alternating carbon dioxide injection

During this study, a comprehensive investigation of low salinity water alternating CO2 injection was performed for enhanced oil recovery in oil-wet carbonate reservoirs. A synergy of interfacial mechanisms such as IFT, wettability alteration, CO2 solubility, oil swelling, water shielding effect, and rock dissolution was considered in two and three-phase systems. Results showed that the monovalent ions, such as NaCl or KCl, inhibit the dissolution of carbon dioxide in brine in excess of divalent salt solutions, e.g. CaCl2 or MgCl2 due to the salting-out effect. In addition, more water shielding effect was observed in low salinity formation water than it in low salinity seawater. The significant change in the reservoir wettability of oil/brine/CO2 system compared to oil/brine referred to the CO2 solubility in brine which could cause stronger carbonated water in the reservoir. Consequently, the low salinity alternating CO2 injection overpowers the late-production problem that occurred commonly in conventional WAG injection.

Numerical modeling of frequency-dependent velocity and attenuation in a fractured-porous rock saturated with two immiscible fluids

The dispersion and attenuation of seismic-wave propagation induced by ‘squirt flow’ effects in hydrocarbon-saturated reservoirs are significantly affected by their rock properties and fluid content. In this study, we analyse the frequency-dependent velocity, attenuation, and seismic responses when fractured porous rock is saturated with two immiscible fluids. First, when considering reservoir wettability, we calculate the effective fluid viscosity using a stable parameter, the capillary pressure, and a lattice Boltzmann model (LBM)-based relative permeability equation, which is a function of the saturation and viscosity ratio of the immiscible two-phase fluid. Then, we explore the frequency-dependent effects of fractured porous rocks saturated with two immiscible fluids under different cases of viscosity ratios and capillary pressure parameters by employing the Chapman model from the dynamic equivalent-medium theory. Then, we use a four-layer model to analyse the frequency-dependent seismic responses. The results show that the characteristics of frequency-dependent velocity and attenuation are both affected by the wettability, capillary pressure parameter, saturation, and viscosity ratio. The frequency-dependent features are greatly influenced by the capillary pressure parameter and viscosity ratio. For a larger viscosity ratio and lower capillary parameter, a dispersive effect can occur in the seismic frequency band. This indicates that the velocity dispersion anomalies are sensitive to wettability, capillary pressure parameter and viscosity ratio and should not be neglected. Synthetic seismic records demonstrate that the seismic reflection signatures, such as the waveform, amplitude, and reflective travel time, at the interfaces for saturated reservoirs are significantly affected by wettability and saturation. The numerical modeling helps to improve the wave propagation in rocks saturated by two immiscible fluids.

Synergy of surface modified nanoparticles and surfactant in wettability alteration of calcite at high salinity and temperature

The surface of silica nanoparticles (NPs) was modified by chemical grafting of ligands to: (1) achieve colloidal stability in concentrated brine at salinities up to 25.7 % total dissolved solids (TDS) and temperatures up to 90 °C and (2) change the wettability of carbonate reservoirs from oil-wet to water-wet. The ligand precursors included low molecular weight cationic N-trimethoxysilylpropyl-N, N, N-trimethylammonium chloride or nonionic 3-glycidyloxypropyl trimethoxysilane. The water-phase contact angle θw of a crude oil droplet on calcite was measured for binary mixtures of the modified NPs combined with different types of surfactants, for a heavy and a light crude oil. For two types of reservoir conditions (16.7 % TDS at 55 °C and 25.7 % TDS at 90 °C), positively charged NPs with quaternary nitrogens (QNP) at 1 wt% altered the wettability of the calcite surface from strongly oil-wet (θw = 125° to 159°) to intermediate wet with a θw = 69° to 85° for light crude oil and θw = 71° to 107° for heavy crude oil. Meanwhile, cationic surfactants tetradecyltrimethylammonium bromide (TTAB) at 1 wt% altered the wettability to water-wet with a θw = 41° to 59° for light crude oil and θw = 70° to 90° for heavy crude oil. Synergy between the QNP and TTAB was observed in lowering the θw by another 10°. The reduced θw is beneficial for secondary oil recovery from carbonates, along with a significant decrease in the viscoelasticity of the crude oil-brine interface that helps destabilize undesirable water-in-crude oil emulsions.

Pore-scale simulation of gas-water two-phase flow in volcanic gas reservoir based on Volume of Fluid method

Understanding the transport process of gas-water flow in volcanic gas reservoir is of key importance for natural gas production. However, there is still limited evidence on the precise influence of volcanic reservoir type, capillary number and wettability. We thus performed gas-water flow simulations (using Volume of Fluid method) at different capillary numbers under different wettability conditions directly on microcomputed tomography (μ-CT) images. The simulation results demonstrated that the eddy current in dead-end corners is the main mechanism for the formation of residual gas. The gas phase near the wall of fractured porous medium was mainly dominated by drag force, resulting in lower residual gas saturation. Moreover, it is generally believed that a low capillary number facilitates the displacement of residual gas in dead-end corners. However, we found that under high temperature (>100 °C) and high pressure (>100 MPa), less residual gas distributed in dead-end corners at higher capillary number. This showed that the conventional percolation law was unlikely to provide reliable predictions in fluid distribution under high temperature and high pressure. The wettability of rock affected the shape of displacement front. The water-gas flow dynamics under water-wet condition was piston like. However, fingering flow occurred under non-hydrophilic condition, and snap-off trapping was more likely to occur, resulting in higher residual gas saturation. This work provides fundamental data on the influence of pore structure, capillary number and wettability on gas-water flow and aids in the further advancements of improved nature gas recovery in volcanic reservoirs.

Time domain NMR: An alternative for study of the asphaltenes precipitated in petroleum.

During the oil production and processing stages, the asphaltene precipitation is one of the great operation problems of oil industry. It can precipitate in the formation, tubing, or surface, causing operating problems, such as reduction in oil recovery by changing the reservoir permeability and wettability, clogging of the pipelines, and difficulty in separations process. The quantification of asphaltenes in petroleum by ASTM D6560 standard method is very laborious and use of a larger solvent volume than necessary. The present work proposes the use of time domain nuclear magnetic resonance (TD-NMR) as new methodology to quantify the asphaltene precipitated in crude oil. Three (light, medium, and heavy) crude oils with asphaltenes content of 0.97, 1.88, and 7.00 wt% were mixed with n-heptane in different R (ml of solvent/g of oil) values and analyzed by means of transverse relaxation time (T2 ). According NMR results, the R values enough for complete asphaltene precipitation for the oils A, B, and C were, respectively, equal to 16.50, 23.00, and 39.50 ml g-1 . These outcomes represent a reduction of 58.75%, 42.50%, and 1.25% in the solvent volume per mass of oil for the oil A, B, and C, respectively, compared to the ASTM D6560 method, which imposes 40 ml g-1 . Therefore, it has been shown that TD-NMR can be applied to estimate the amount of asphaltene precipitated in petroleum and have potential to be applied in routine analysis with advantages of saving time and costs.

Low-field NMR investigation on interaction of ZnO nanoparticles with reservoir fluids and sandstone rocks for enhanced oil recovery

The use of nanoparticles (NPs) can considerably benefit enhanced oil recovery (EOR) by changing the wettability of the rock, improving the mobility of the oil drop, and decreasing the interfacial tension (IFT) between oil and water. Prior to the application of nanoparticles in oil fields, it is essential to conduct measurements at the laboratory scale. However, the estimation of reservoir wettability is difficult in most laboratory experiments. Practicably, ZnO NPs were used to modify the rock surface wettability, lower the IFT at the oil/water interface, and reduce the interaction of chemical adsorption, such as (surfactant) onto reservoir rock surface to solve various challenges in oil production and EOR operations. Upon confining both ZnO-based nanofluid and the crude oil into sandstone, deviations from the corresponding pure bulk dynamical behaviors were observed with low-field nuclear magnetic resonance (LF-NMR) relaxometry. The expected deviations from the pure bulk behaviors were attributed to the well-known confinement effect. The wettability test results before and after surface variations of formation water (FW) with the addition of three different NP concentrations (0.05, 0.075, and 0.1) wt% ZnO reflected significant changes to its wettability. Among the treatments of Berea sandstone cores with ZnO NPs, the percentage of clay-bound H2O/free fluid index was maximum in 1.0 pore volume (PV) NP treatment. The ratio of NMR relaxations, which determines the affinity of fluids toward solids, by the 1.0 PV NP treatment is reported to have the most potential with higher affinity for FW and less affinity for crude oil toward the pore walls. Hence, LF-NMR allows monitoring of nanofluid and crude oil characteristics in the pores of rock samples and may potentially be applied in further EOR studies.

Synergistic effects of CO2 density and salinity on the wetting behavior of formation water on sandstone surfaces: Molecular dynamics simulation

Reservoir wettability is very important to predict the structure and residual capture capacity, potential CO2 leakage accidents and improve the risk assessment and sequestration safety during CO2 geological sequestration. The wetting behavior of fluid on reservoir rock surface is actually an interface phenomenon caused by the interaction of different fluid molecules on rock surface. At present, it is difficult for laboratory experiments to observe the microscopic interface phenomena at the molecular scale under reservoir conditions, while molecular dynamics simulations can characterize the microscopic changes in wetting behavior and analyze the interaction between the fluid and the rock surface. In this study, molecular dynamics simulations are used to study the effects of different CO2 densities and different salinities on the wetting behavior of formation water on the sandstone surface during CO2 geological sequestration. The results show that both salinity and CO2 density have significant effects on the wettability of quartz surfaces. However, the increase in salinity can only weaken the wettability, while the increase in CO2 density can transform the wettability of the quartz surface. Both CO2 molecules and H2O molecules form two adsorption layers at 3.5 Å and 6.9 Å away from the quartz surface. CO2 molecules will replace the positions originally occupied by water molecules on the quartz surface, reducing the contact area between water droplets and the quartz surface. The CO2 density mainly affects the interface behavior between the components in the system, while the NaCl concentration mainly affects the interaction between H2O molecules and ions in the system. The research results can further improve the understanding of the wettability of fluid on the pore surface of reservoir rocks during CO2 geological sequestration.

Hydrogen wettability in carbonate reservoirs: Implication for underground hydrogen storage from geochemical perspective

Hydrogen has been considered as a promising renewable source to replace fossil fuels to meet energy demand and achieve net-zero carbon emission target. Underground hydrogen storage attracts more interest as it shows potential to store hydrogen at large-scale safely and economically. Meanwhile, wettability is one of the most important formation parameters which can affect hydrogen injection rate, reproduction efficiency and storage capacity. However, current knowledge is still very limited on how fluid-rock interactions affect formation wettability at in-situ conditions. In this study, we thus performed geochemical modelling to interpret our previous brine contact angle measurements of H2-brine-calcite system. The calcite surface potential at various temperatures, pressures and salinities was calculated to predict disjoining pressure. Moreover, the surface species concentrations of calcite and organic stearic acid were estimated to characterize calcite-organic acid electrostatic attractions and thus hydrogen wettability. The results of the study showed that increasing temperature increases the disjoining pressure on calcite surface, which intensifies the repulsion force of H2 against calcite and increases the hydrophilicity. Increasing salinity decreases the disjoining pressure, leading to more H2-wet and contact angle increment. Besides, increasing stearic acid concentration remarkably strengthens the adhesion force between calcite and organic acid, which leads to more hydrophobic and H2-wet. In general, the results from geochemical modelling are consistent with experimental observations that decreasing temperature and increasing salinity and organic acid concentration increase water contact angle. This work also demonstrates the importance of involving geochemical modelling on H2 wettability assessment during underground hydrogen storage.

Wettability of Tight Sandstone Reservoir and Its Impacts on the Oil Migration and Accumulation: A Case Study of Shahejie Formation in Dongying Depression, Bohai Bay Basin

The migration and accumulation of oil in tight sandstone reservoirs are mainly controlled by capillary force. Due to the small pore radius and complex pore structure of tight sandstone reservoirs, the capillary force is very sensitive to wettability, so wettability significantly affects oil migration and accumulation. However, the study of oil migration and accumulation in tight sandstone reservoirs often needs to combine multiple methods, the process is complex, and the research methods of wettability are not uniform, so the mechanism of wettability affecting oil migration and accumulation is not clear. Taking the tight sandstone of the Shahejie Formation in the Dongying sag, Bohai Bay Basin, as the research object, the wettability characteristics of a tight sandstone reservoir and their influence on oil migration and accumulation were analyzed by means of a pore permeability test, XRD analysis, micro-CT experiment, contact angle tests, spontaneous imbibition experiments, and physical simulation experiments on oil migration and accumulation. The results show that the reservoir is of the water-wet type, and its wettability is affected by the mineral composition. Wettability in turn affects the spontaneous imbibition characteristics by controlling the capillary force. Oil migration in tight sandstone reservoirs is characterized by non-Darcy flow, the oil is in the non-wetting phase and subject to capillary resistance. The key parameters to describe the oil migration and accumulation characteristics include the kickoff pressure gradient, the critical pressure gradient, and ultimate oil saturation. Wettability affects oil migration characteristics by controlling the capillary force. The more oil-wet the reservoir is, the more favourable it is to oil migration and oil accumulation and therefore the higher the reservoir’s ultimate oil saturation is.

Modelling the effects of reservoir parameters and rock mineralogy on wettability during low salinity waterflooding in sandstone reservoirs

Low salinity waterflooding has been reported to yield incremental oil recovery from both field applications and laboratory experiments compared to regular waterflooding. Crude oil-brine-rock (COBR) interactions dictate wettability alteration during low salinity waterflooding in sandstones. In this work, triple-layer surface complexation modelling (TLM) is utilised to simulate the interactions at rock-brine and oil-brine interfaces, while accommodating the crucial role of sandstone mineralogy in surface chemistry. Derjaguin-Landau-Verwey-Overbeek (DLVO) theory is applied to characterise the COBR stability. Moreover, we propose the use of the maximum energy barrier (MEB) parameter, which is calculated from the DLVO theory's interaction potential, as an indicator of reservoir wettability.Correlating the MEB with the experimentally measured contact angles revealed an abrupt increase in contact angles as the MEB drops below the zero-value thereby leading to a less water-wet COBR system. Results analyses showed that the different clays affect the rock-brine zeta potential and wettability distinctly based on their surface site densities and specific surface areas. And the studied clays cause the zeta potential to become more negative in the order: smectite > montmorillonite > illite > chlorite > kaolinite. Subsequently, further investigation employing the developed TLM and MEB revealed that higher amounts of kaolinite will make the reservoir more oil-wet.Lastly, the sensitivity analysis performed on reservoir wettability indicated that the ionic composition is the most important factor to affect rock wettability followed by pH and temperature. Moreover, the presence of CaCl2 salt in the formation water significantly supresses the areas of strong water wettability under varying reservoir conditions compared to NaCl salt.The work conducted in this study presents a novel approach to model the individual and combined effects of sandstone minerals, specifically, quartz, kaolinite, chlorite, illite, montmorillonite and smectite, on the overall sandstone zeta potential behaviour. Furthermore, a new method was proposed to characterise reservoir wettability as a function of the maximum energy barrier which allowed us to obtain valuable insights into the most affecting reservoir parameters on COBR wettability. These findings will have practical implications to efficiently design the low salinity waterflooding processes for sandstone reservoir applications.

Study of the Adsorption Behavior of Surfactants on Carbonate Surface by Experiment and Molecular Dynamics Simulation.

Surfactants adsorption onto carbonate reservoirs would cause surfactants concentrations decrease in surfactant flooding, which would decrease surfactant efficiency in practical applications of enhanced oil recovery (EOR) processes. Different surfactants could be classified as cationic surfactants, anionic surfactants, non-ionic surfactants according to the main charge, or be classified as chemical surfactant and bio-surfactant according to the surfactant origin. However, the research on different type surfactants adsorption on carbonate reservoirs surface differences was few. Therefore, five representative surfactants (CTAB, SDS, TX-100, sophorolipid, rhamonilipid) adsorption effect onto carbonate reservoirs surface was studied. Owing to the fact that the salinity and temperature in underground carbonate reservoirs were high during the EOR process, it is vital to study the salinity effect and temperature effect on surfactant adsorption. In this study, different surfactants species, temperature and salinity adsorption onto carbonate reservoirs were studied. The adsorption isotherms were fitted by Langmuir, Freundlich, Temkin and Linear models, and the first three models fitting effect were good. The results showed that cationic surfactants adsorption quantity was higher than anionic surfactants, and the non-ionic surfactants adsorption quantity was the lowest. When the temperature increased, the surfactants adsorption would decrease, because the adsorption process was exothermic process, and increasing temperature would inhibit the adsorption. The higher salinity would increase surfactants adsorption because higher salinity could compress electric double layer. In order to decrease surfactants adsorption, SiO2 nanoparticles and TiO2 nanoparticles were added to surfactants solutions, and then surfactants could adsorb onto nanoparticles surface, then the steric hindrance between surfactant molecules would increase, which could decrease surfactants adsorption. Contact angle results indicated that surfactants adsorption made the carbonate reservoir wettability alteration. In the end, surfactants (with or without SiO2 nanoparticles) adsorption onto carbonate reservoirs mechanism were studied by molecular dynamics simulation. The simulation results indicated that the surfactants molecules could adsorb onto SiO2 nanoparticles surface, and then the surfactants adsorption quantity onto carbonate rocks would decrease, which was in accordance with the experiments results.

First-principles calculations of carboxylic acid adsorption on carbonate surfaces: Chain size and aqueous interface effects

In enhanced oil recovery (EOR), low salinity water (LSW) is an essential condition to change wettability in carbonate reservoirs for organic compound desorption. However, the nature of the water–oil–carbonate interactions remains challenging. Accordingly, we performed first-principles calculations to determine the adsorption energies of the propanoic and octanoic acids on the calcite and dolomite surfaces with water interface and implicit solvation medium. Our results confirm that the Mg sites are less selective for adsorption of both acidic oil components, whereas the Ca sites keep retaining the acid molecules. The differentiated influence from the carbonate surfaces is enhanced through the aqueous environment. In presence of Mg, the aqueous environment may act mainly on the unoccupied electronic levels of the dolomite carbonate sites instead of the Ca sites in calcite, which in turn has a stronger interaction with the acid molecules. The effect of the acid chain size is less pronounced. The acid desorption process could be then reached from the carbonate sites as the surface hydrophilicity is mainly increased in dolomite, which has a favourable ionic exchange and water adsorption. Therefore, our simulation models help to shed light on some important interaction properties in complex water–oil–carbonate interfaces under LSW conditions for EOR.

An understanding of oil–water replacement mechanism based on interfacial tension gradient during the well shut-in

Spontaneous imbibition behavior of fracturing fluid retained in reservoirs is considered to be one of the important mechanisms of spontaneous oil–water displacement in tight reservoirs. However, the mechanism of imbibition displacement in oil-wet rocks remains unclear. Inspired by the principle of the Marangoni effect, a mathematical model of oil displacement driven by an interfacial tension gradient in an oil-wet capillary tube was established, and the effects of osmotic pressure and hydraulic mechanical dispersion were coupled in the model. The results show that the key component of this mechanism is the breakdown of the initial capillary equilibrium state due to the diffusion of solute, which changes the pressure distribution in the capillary and drives the water to drive oil out of the pores. This can explain the spontaneous imbibition of low-salinity fracturing fluid into the oil-wet tight sample and displace oil without any external force, despite its low permeability. In addition, the related factors were analyzed, including initial concentration, contact angle, solute type, osmotic behavior, and size of the capillary. The results show that for an oil wet reservoir with high salinity, the connate water interfacial tension gradient plays an important role in oil displacement, and the coupling effect of osmotic pressure and hydromechanical dispersion considerably improves recovery. This can provide new insight into the mechanism of spontaneous imbibition of fracturing fluid.

Impact of salinity and temperature variations on relative permeability and residual oil saturation in neutral-wet sandstone

Low-salinity water flooding has become one of the major emerging enhanced oil recovery techniques where lower salinity water is flooded into a hydrocarbon reservoir in order to increase oil recovery. It’s been widely reported that reservoir wettability alteration from oil-wet to water-wet in a low-salinity water process improves oil recovery. Many factors control system wettability, however, role and intensity of each factor is not completely understood. Therefore, several reported affecting factors on wettability alteration were eliminated in the present work in order to determine the impact of different low-salinity water on oil and water relative permeability curves and residual oil saturation. A series of experiments were performed where three simulated brine solutions were injected into oil saturated thoroughly cleaned neutral-wet sandstone core plugs. The effect of injected brine temperature on oil and water relative permeability curves and residual oil saturation was also determined by injecting 115,000 ppm salinity brine at three different temperatures. Results indicate that decreasing flooded water salinity alters the wettability preference of the rock towards favorable water-wetting conditions. Water-wet conditions decrease water mobility and enhance oil mobilization leading to better oil microscopic displacement efficiency and reduced residual oil saturation. Elevated temperature reduces water relative permeability and residual oil saturation. Cited as: Mahmud, W. M. Impact of salinity and temperature variations on relative permeability and residual oil saturation in neutral-wet sandstone. Capillarity, 2022, 5(2): 23-31. https://doi.org/10.46690/capi.2022.02.01

A Novel Empirical and Deep Ensemble Super Learning Approach in Predicting Reservoir Wettability via Well Logs

Accurately measuring wettability is of the utmost importance because it influences several reservoir parameters while also impacting reservoir potential, recovery, development, and management plan. As such, this study proposes a new formulated mathematical model based on the correlation between the Amott-USBM wettability measurement and field NMR T2LM log. The exponential relationship based on the existence of immiscible fluids in the pore space had a correlation coefficient of 0.95. Earlier studies on laboratory core wettability measurements using T2 distribution as a function of increasing water saturation were modified to include T2LM field data. Based on the trends observed, water-wet and oil-wet conditions were qualitatively identified. Using the mean T2LM for the intervals of interest and the formulated mathematical formula, the various wetting conditions in existence were quantitatively measured. Results of this agreed with the various core wettability measurements used to develop the mathematical equation. The results expressed the validity of the mathematical equation to characterise wettability at the field scale. With the cost of running NMR logs not favourable, and hence not always run, a deep ensemble super learner was employed to establish a relationship between NMR T2LM and wireline logs. This model is based on the architecture of a deep learning model and the theoretical background of ensemble models due to their reported superiority. The super learner was developed using nine ensemble models as base learners. The performance of nine ensemble models was compared to the deep ensemble super learner. Based on the RMSE, R2, MAE, MAPD and MPD the deep ensemble super learner greatly outperformed the base learners. This indicates that the deep ensemble super learner can be used to predict NMR T2LM in the field. By applying the methodology and mathematical formula proposed in this study, the wettability of reservoirs can be accurately characterised as illustrated in the field deployment.

EVALUATION OF SURFACTANT WITH THIN FILM SPREADING MECHANISM FOR EOR IMPLEMENTATION

Wettability plays an important role of two phase Àuids Àow in porous media. The displacement efficiency of oil by injected Àuid is also dictated by wettability characteristic of reservoir rocks. This papers contents a highlight of the reservoir wettability modification by injecting TFSA (Thin Film Spreading Agent) surfactant for EOR applications through a laboratory study . TFSA used in this study is called Coconut Ethanolamide with a HLB (Hydrophilic-Lipophilic Balance) level around 13 to 15 which is very suitable for TFSA purposes. Several laboratory evaluations have been done to screen this surfactant with the aim of getting the best properties that fulfill the criteria for EOR chemical injection. Then TFSA solution tests have been carried out including compatibility, thermal stability, phase behavior, and filtration test. The results suggest that all measured parameters are suitable for chemical injection. Others parameters measuring rock Àuid interactions for instance: adsorption, wettability, imbibition, relative permeability, and core Àood experiments has been done to find the quantitative numbers for screening this surfactant. All experiment results categorize as moderate levels for passing the screening criteria for chemical injection except for the adsorption which is excellent. Even though the results of laboratory tests show this TFSA is valid for chemical injection, improvement by adding some chemicals is still suggested to find a better TFSA formula.

Influence of long-term stored oil on wettability and its recovery in depleted petroleum reservoirs

Underground oil storage is a viable technique to increase energy security in the context of global concern for oil demand and supply. When the economic conditions permit, it makes sense to store oil in water-flooded, water-wet sandstone reservoirs that are geographically ubiquitous and abundant, structurally safe, and cost-effective for storing large amounts of crude oil safely. Due to long-term restoring oil contacting with the surface of rocks in such reservoirs, the property of the reservoir rocks may be changed, and the performance of oil reproduction may be different. These important factors are related to the change of wetting behavior of reservoirs, which directly affects the recovery rate of stored oil and the relative permeability characteristic of oil and water flow during the reproduction of stored crude oil in a water-wet depleted petroleum reservoir. Unfortunately, there is a lack of study on these research areas. This study investigates the change of wettability in such reservoirs and its influence on the production of stored oil by a second water flooding process. Several experimental techniques, including NMR and centrifuge measurements (USBM), and two-phase flow relative permeability measurement, are employed to investigate wetting behavior in crude oil/water/rock systems and two-phase flow characteristics when the crude oil is reinjected and stored oil is reproduced by water flooding in the present work.Based on the results of NMR and centrifuge experiments, the wettability of the core aged with crude oil was altered from strongly water-wet to weakly water-wet with an increase in aging time. NMR and USBM wettability indexes showed a good agreement suggesting a change into weakly water wetness. It is consistent with the change of relative permeability characteristics for first and second water flooding. We also reported that 77.5% of stored oil is recovered by second water flooding. Oil recovery factors and the characteristic parameters, Swi, Ko(Swi), Soi, Sor, Sw(max), and Kw(Sor) were experimentally determined for initial and second water flooding. Although not all of the stored crude oil has been recovered due to wettability change and oil film left the pore’s surface on the rock, the desired recovery factor has been achieved during the second water flooding.

Evaluation of pore-scale wettability in the tight sandstone reservoirs of the Upper Triassic Yanchang Formation, Ordos Basin, China

Wettability is a key factor influencing multiphase fluid distributions and flow behavior in the reservoirs. The microscopic characteristics of the mixed wettability which is a special wettability type are unclear in sandstone reservoirs. An integrated study of petrographic, petrophysical and pore-scales wettability by Environmental Scanning Electron Microscope (ESEM) using the water condensation method were carried out on typical sandstone samples in the Chang-6 interval of Yanchang Formation, southeastern Ordos Basin, and the characteristics of mixed wettability were investigated. It shows that the oil-free sandstones are water-wet in general, while the oil-bearing sandstones are apparently mixed-wet. In the mixed-wet sandstones, the walls of different pores or even the same one pore display different wetting states. The mixed wetting nature of the tight sandstones was probably caused by the early phase oil charge. After oil charged into the reservoir, chlorite surfaces in contacting with pores adsorbed the polar compounds in the crude oil, and their wettability was altered locally from water-wet to oil-wet states. However, pore walls surrounded by quartz and feldspars mainly remained water-wet after oil charge.

Effects of cleaning process using toluene and acetone on water-wet-quartz/CO2 and oil-wet-quartz/CO2 wettability

Acetone, toluene, and heptane have been perceived as the conventional cleaning agents for the preservation of original water-wet rock reservoir wettability, and for restoration of oil-wet core to its initial wetting condition, prior to measurement of contact angles of CO 2 -brine-rock systems. However, these organic solvents could be adsorbed on rock surfaces, which modifies the wettability of the reservoir rock and thus triggers uncertainties of the CO 2 containment estimation. Presently, there is scarcity of data in literature on the impact of cleaning agents on the wettability of rock/CO 2 /brine/systems and its attendant effect on CO 2 storage capacities. To provide insights on the impact of cleaning agents on CO 2 wettability of sandstone, water-wet and oil-wet quartz substrates were aged in acetone, toluene, and heptane, respectively. Advancing and receding contact angles of CO 2 -brine-quartz systems were measured at a constant temperature (323 K) and varying pressures (5–20 MPa). Impact of cleaning the minerals surfaces with air plasma, N 2 and oven after cleaning with either toluene or acetone on CO 2 wettability was also assessed and compared. The results show that chemicals that are used quite often to clean mineral surfaces can alter the rock wettability. Significant alterations in wetting conditions were observed when oil wet-rock was cleaned with toluene and water-wet rock was cleaned with acetone. Our results suggest that to preserve the original wettability, we will need to use toluene to clean the water-wet rock and acetone to clean the oil-wet rock. Heptane is only suitable for wettability modification of the oil-wet cores and not for restoration of oil-wet core to its original reservoir wettability. The results confirm that air plasma is the only way to remove surface contamination and organic carbon from the quartz substrates. Cleaning minerals surfaces or rock samples by toluene, acetone and heptane without air plasma will lead to incorrect contact angle and bias wettability measuments. Equilibrium brine contact angles for CO 2 /brine on quartz substrate as a function of pressure at constant temperature (323 K) for clean (pure), aged in crude oil, soaked in toluene after ageing in crude oil, and soaked in acetone after aging in crude oil. • Effects of toluene, acetone and heptane on CO 2 -brine-quartz wettability was studied. • Toluene preserved the original wettability of water-wet rock. • Acetone preserved the original wettability of oil-wet rock. • Heptane is not suitable for restoration of oil-wet core to original wetting state. • Air plasma is the only way to remove organic carbon from the quartz substrates.

Reproducing wettability in sandstone reservoir core material in laboratory core restorations

Replicating initial reservoir wettability conditions in core restoration by core cleaning and fluid restoration in the laboratory is of great importance. There are several core cleaning and restoration protocols used in the oil industry and academia that include the usage of different equipment, techniques, and materials. Strong solvents used in core cleaning can remove material that is part of the rock phase leading to more water–wet behavior. Large volumes of crude oil exposure in core restorations can result in high adsorption of polar organic components onto the mineral surfaces giving less water–wet behavior. Therefore, sufficient core cleaning should be targeted, involving no physical damage to the solid rock phase and effective crude oil exposure securing realistic water saturations, avoiding overexposure of crude oil. The objective of this study was to establish an optimum core restoration process in terms of cleaning solvents and the amount of crude oil exposure, to re-establish the same core wettability from one core restoration to the next. Seven sandstone cores from a reservoir on the Norwegian Continental Shelf underwent a series of core restorations. Two different core cleaning procedures were used, in which mild (kerosene/heptane) and strong (toluene/methanol) solvents were involved, and furthermore, the cores were exposed to various volumes of crude oil. Spontaneous imbibition experiments showed that mild core cleaning in combination with 5 pore volumes or more crude oil exposure rendered the cores less water-wet in successive core restorations. More rigorous cleaning with 5 pore volumes of crude oil exposure rendered the cores more water-wet in successive core restorations. From spontaneous imbibition results it was concluded that an optimum core restoration procedure involving mild cleaning and only 1 pore volume of crude oil exposure successfully reproduced core wettability in successive experiments.