Modeling Contact Angle vs. Temperature for the Quartz-Water-Decane System

SPE Journal ◽  
2021 ◽  
pp. 1-13
Author(s):  
Timothy S. Duffy ◽  
Isaac K. Gamwo ◽  
Russell T. Johns ◽  
Serguei N. Lvov

Summary Innovative approaches are needed to improve the efficiency of oil recovery technologies to meet the growing demands of fossil-fuel based energy consumption. Enhanced oil recovery (EOR) methods such as low-salinity waterflooding and chemically tuned waterflooding aim to optimize the reservoir’s wetting properties, detaching oil globules from rock surfaces and allowing easier oil flow through pore throats. This wetting behavior is commonly quantified by contact angle measurements of the rock-oil-brine interface, which have been thoroughly investigated and theorized for many systems at ambient temperatures and pressures. However, few studies exist for extending contact angle theories away from ambient conditions. In this paper, we model the contact angles of a quartz-water-decane system at elevated temperatures using the surface tension component (STC) approach. Temperature-dependent van der Waals [Lifshitz-van der Waals (LW)] interactions and hydrogen-bonding (acid-base) interactions were calculated and are incorporated into the model for the quartz-water-decane interface. The Hough and White procedure was used to create temperature-dependent dielectric functions of quartz, water, and normal decane for calculations of Hamaker coefficients. Hamaker coefficients calculated this way are highly linear with temperature and agree well with Israelachvili’s approximation. The acid-base interactions likely contribute the most to system wettability changes. Resulting contact angles of the quartz-water-decane system shift from water-wet (16°) to slightly water-wet (57.4°) as temperature increases. The model was also successfully verified for the quartz-air-water system. Our results can be used in future studies to determine optimal injected water compositions for specific rock-oil-brine and other systems with consideration of reservoir temperature.

2021 ◽  
Vol 303 ◽  
pp. 01001
Author(s):  
Yu Haiyang ◽  
Ji Wenjuan ◽  
Luo Cheng ◽  
Lu Junkai ◽  
Yan Fei ◽  
...  

In order to give full play to the role of imbibition of capillary force and enhance oil recovery of ultralow permeability sandstone reservoir after hydraulic fracturing, the mixed water fracture technology based on functional slick water is described and successfully applied to several wells in oilfield. The core of the technology is determination of influence factors of imbibition oil recovery, the development of new functional slick water system and optimization of volume fracturing parameters. The imbibition results show that it is significant effect of interfacial tension, wetting on imbibition oil recovery. The interfacial tension decreases by an order of magnitude, the imbibition oil recovery reduces by more than 10%. The imbibition oil recovery increases with the contact angle decreasing. The emulsifying ability has no obvious effect on imbibition oil recovery. The functional slick water system considering imbibition is developed based on the solution rheology and polymer chemistry. The system has introduced the active group and temperature resistant group into the polymer molecules. The molecular weight is controlled in 1.5 million. The viscosity is greater than 2mPa·s after shearing 2h under 170s-1 and 100℃. The interfacial tension could decrease to 10-2mN/m. The contact angle decreased from 58° to 22° and the core damage rate is less than 12%. The imbibition oil recovery could reach to 43%. The fracturing process includes slick water stage and linear gel stage. 10% 100 mesh ceramists and 8% temporary plugging agents are carried into the formation by functional slick water. 40-70 mesh ceramists are carried by linear gel. The liquid volume ratio is about 4:1 and the displacement is controlled at 10-12m3/min. The sand content and fracturing fluid volumes of single stage are 80m3 and 2500 m3 respectively. Compared with conventional fracturing, due to imbibition oil recovery, there is only 25% of the fracturing fluid flowback rate when the crude oil flew out. When the oil well is in normal production, about 50% of the fracturing fluid is not returned. It is useful to maintain the formation energy and slow down the production decline. The average cumulative production of vertical wells is greater than 2800t, and the effective period is more than 2 years. This technology overcoming the problem of high horizontal stress difference and lack of natural fracture has been successfully applied in Jidong Oilfield ultralow permeability reservoir. The successful application of this technology not only helps to promote the effective use of ultralow permeability reservoirs, but also helps to further clarify the role of imbibition recovery, energy storage and oil-water replacement mechanism.


Author(s):  
Dong-Lei Zeng ◽  
Biao Feng ◽  
Jia-Wen Song ◽  
Li-Wu Fan

Abstract Temperature-dependent wettability of water droplets on a metal surface in a pressurized environment is of great theoretical and practical significance. In this paper, molecular dynamic simulation is used to study this problem by relating the temperature-dependent apparent contact angles to the changes in solid-liquid and solid-vapor interfacial free energies and hydrogen bonds in the nano-sized water droplets with increasing the temperature. The temperature range of interest is set from 298 K to 538 K in a 20 K interval under a constant pressure of 7 MPa. The results show that the contact angle in general decreases with raising the temperature and decreasing trend can be divided into two sections with different slopes. The contact angle drops slowly when the temperature is below 458 K as a critical point. Beyond this point, the contact angle shows a much steeper decrease. The difference between solid-vapor and solid-liquid interfacial free energies is found to decrease slightly with temperature. Combining with that the surface tension drops with increasing the temperature, a decreasing trend of the contact angle is expected according to the Young’s equation. As the temperature increases, the number and average energy of the hydrogen bonds both decrease, and the hydrogen bonds tend to aggregate at the bottom of the nano-droplets.


2018 ◽  
Author(s):  
M. Elsharafi ◽  
K. Vidal ◽  
R. Thomas

Contact angle measurements are important to determine surface and interfacial tension between solids and fluids. A ‘water-wet’ condition on the rock face is necessary in order to extract oil. In this research, the objectives are to determine the wettability (water-wet or oil-wet), analyze how different brine concentrations will affect the wettability, and study the effect of the temperature on the dynamic contact angle measurements. This will be carried out by using the Cahn Dynamic Contact Angle. Analyzer DCA 315 to measure the contact angle between different fluids such as surfactant, alkaline, and mineral oil. This instrument is also used to measure the surface properties such as surface tension, contact angle, and interfacial tension of solid and liquid samples by using the Wilhelmy technique. The work used different surfactant and oil mixed with different alkaline concentrations. Varying alkaline concentrations from 20ml to 1ml were used, whilst keeping the surfactant concentration constant at 50ml.. It was observed that contact angle measurements and surface tension increase with increased alkaline concentrations. Therefore, we can deduce that they are directly proportional. We noticed that changing certain values on the software affected our results. It was found that after calculating the density and inputting it into the CAHN software, more accurate readings for the surface tension were obtained. We anticipate that the surfactant and alkaline can change the surface tension of the solid surface. In our research, surfactant is desirable as it maintains a high surface tension even when alkaline percentage is increased.


Author(s):  
Dandina N. Rao ◽  
Hussain H. Radwani

The engineering applications of spreading and adhesion phenomena involving fluids on solids are numerous. The adhesive and spreading interactions at the solid-fluid interfaces are well characterized by dynamic contact angles. This study reports on the results of an experimental investigation into the effect of solid surface roughness on dynamic contact angles in solid-liquid-liquid (S-L-L) systems. The experiment involved the use of Wilhelmy Plate apparatus to measure adhesion tension (which is the product of interfacial tension and cosine of the contact angle between the liquid-liquid interface and the solid surface), the DuNuoy tensiometer to measure the liquid-liquid interfacial tension, and a profilometer to characterize the roughness of the solid surfaces used. The components of the solid-liquid-liquid systems studied consisted of: (i) smooth glass, roughened quartz and an actual rock surface for the solid phase, (ii) normal-hexane and deionized water as the two immiscible liquid phases. The dynamic contact angles (advancing and receding angles) of the three-phase (rock-oil-water) system provide essential information about the wettability of petroleum resrvoirs. The wettability of a reservoir is an important parameter that affects oil recovery in primary, secondary, and enhanced recovery operations [1]. Contact angle measurements on smooth surfaces are generally used to characterize reservoir wettability. However pore surfaces within reservoir rocks are essentially rough and hence it is important to determine the effect of such roughness on measured contact angles. There is very little information in the open literature on the effect of surface roughness on dynamic contact angles in S-L-L systems. In the present work, four levels of roughness of solid surfaces of similar mineralogy (quartz and glass) were tested in hexane-deionized water fluid pair. The advancing and receding contact angles measured at ambient conditions were analyzed for wettability effects. It was found that as surface roughness increased, the dynamic contact angles also increased. The wettability of the rock-oil-water system shifted from weakly water-wet for the smooth glass to intermediate-wet for the roughened surface. The general trends observed in our study were found to be in good agreement with other published results. However, the generally held notion of increasing contact angle hysteresis with increasing roughness appears to be incorrect in solid-liquid-liquid systems.


SPE Journal ◽  
2010 ◽  
Vol 16 (02) ◽  
pp. 411-428 ◽  
Author(s):  
Hamidreza Salimi ◽  
Johannes Bruining

Summary We use upscaling through homogenization to predict oil recovery from fractured reservoirs consisting of matrix columns, also called vertically fractured reservoirs (VFRs), for a variety of conditions. The upscaled VFR model overcomes limitations of the dual-porosity model, including the use of a shape factor. The purpose of this paper is to investigate three main physical aspects of multiphase flow in fractured reservoirs: reservoir wettability, viscosity ratio, and heterogeneity in rock/fluid properties. The main characteristic that determines reservoir behavior is the Péclet number that expresses the ratio of the average imbibition time divided by the residence time of the fluids in the fractures. The second characteristic dimensionless number is the gravity number. Upscaled VFR simulations, aimed at studying the mentioned features, add new insights. First, we discuss the results at low Péclet numbers. For only small gravity numbers, the effect of contact angle, delay time for the nonequilibrium capillary effect, the heterogeneity of the matrix-column size, and the matrix permeability can be ignored without appreciable loss of accuracy. The ultimate oil recovery for mixed-wet VFRs is approximately equal to the Amott index, and the oil production does not depend on the absolute value of the phase viscosity but on viscosity ratio. However, large gravity numbers enhance underriding, aggravated by large contact angles, longer delay times, and higher viscosity ratios. Layering can lead to an improvement or deterioration, depending on the fracture aperture and permeability distribution. At low Péclet numbers, the fractured reservoir behaves very similarly to a conventional reservoir and depends largely on the viscosity ratio and the gravity number. At high Péclet numbers, after water breakthrough, the oil recovery appears to be proportional to the cosine of the contact angle and inversely proportional to the sum of the oil and water viscosity. In addition, the mixed-wetting effect is more pronounced; there are significant influences of delay time (nonequilibrium effects), matrix permeability, matrix-column size, and the column-size distribution on oil recovery. At low gravity numbers and an effective length/thickness ratio larger than 10, the oil recovery is independent of the vertical-fracture-aperture distribution. For the same amount of injected water, the recovery at low Péclet numbers is larger than the recovery at high Péclet numbers.


2021 ◽  
Author(s):  
Emad A. Al-Khdheeawi ◽  
Cut Aja Fauziah ◽  
Doaa Saleh Mahdi ◽  
Ahmed Barifcani

Abstract CO2 geological storage (CCS)isconsidered as the most promising technique to reduce atmospheric CO2emissions. However, due to the density variation between the injected supercritical CO2 and the formation water,CO2 tends to move vertically toward the air. This vertical CO2 leakage can be prevented by four trapping mechanisms (i.e. structural trapping,capillary trapping, solubility trapping, and mineral trapping). The capacities of structural and residual trapping are highly affected by rock wettability. Clay wettability is one of the crucial parametersin evaluation of CO2 geo-sequestration. However, the literature data show that there are many uncertainties associated with experimental measurements. One of these uncertainties is the influenceof the effect of gas density on the clay mineral wettability. Thus, here, we compared the wettability of a clay mineral (i.e. illite) of three different gas densities scenarios (i.e. low (Helium), moderate (Nitrogen), and high (CO2) gas densities). To do so, we measured the advancing and receding contact angle (i.e. wettability) of illite for CO2/water, nitrogen/water, and Helium/water systems at a constant (333 K) and four different pressures (5, 10, 15, and 20 MPa). The brine composition used was 4 wt% NaCl, 4 wt% CaCl2, 1 wt% MgCl2 and 1 wt% KCl, for all gas density scenarios. The results indicate that gas density has a significant effect on the clay mineral wettability and that both advancing and receding contact angles increase with an increase in gas density. The results show that a higher density gas scenario has a higher contact angle of illite, measured at the same temperature and pressure. For instance, the advancing contact angle of illite at 333 K and 20 MPa was 65° for the CO2/water system, 53° for the nitrogen/water system, and 50° for Helium/water Helium/water system. Thus, we conclude that the gas density affects the Clay wettability measurement and that the higher gas density leads to a higher contact angle measurements (i.e. a more CO2-wet system) of the clay and thus reduces the estimated CO2 geo-sequestration capacity and containment security.


1984 ◽  
Vol 24 (03) ◽  
pp. 342-350 ◽  
Author(s):  
Ronald L. Reed ◽  
Robert N. Healy

Abstract Advanced and receded contact angles have beenmeasured on various high- and low-energy substrates asfunctions of microemulsion-excess phase interfacialtensions (IFT's). Many experimental difficulties peculiar to these low-tension systems caused large measurementerrors. But with this constraint and with one exception, contact angles were hysteresis-free and independent ofthe substrate. For lower-phase microemulsions and high-energy substrates, it is proposed that the surfactant polar groupadsorbs on the solid and then a surfactant bilayer forms. This bilayer provides the effective substrate that relates to contact angle and IFT's through Young's equation. An optimal salinity for contact angles is defined andrelated to previously introduced optimal salinities, inparticular to that associated with best oil recovery. Results suggest the optimum attainable contact anglesfor microemulsion-based oil recovery may not be 0 degrees. Introduction IFT and contact angle do not occur explicitly in the macroscopic equations governing multiphase flowthrough porous media, rather their impact is manifested implicitly through the relative permeability and capillary pressure functions. This dependence has been established experimentally, but there is not yet a satisfactory theoretical treatment. It is partly for this reason that it is difficult to ascribe with confidence the individualand collective effects of these two parameters and partly because contact angles measured on idealized substratesmay not accurately imitate those obtained in situ. So far, attention has focused primarily on the roles played by independently specified IFT's and contactangles in the displacement of isolated residual oil ganglia. One conclusion of these studies is that themost favorable wettability condition for tertiary oil recovery is 100% water-wet (i.e. theta = 0 degrees)when measured through the aqueous displacing phase. However, as we have pointed out, oil mobilization isnot the central question. Rather, from the onset of oilbank formation, the essential problem is to "maintain continuity of the flowing oil filaments to as low a saturation as possible before they rupture and are irretrievably lost." Since the mechanism of this rupture-trapping process is different from that of oil mobilization, it is quite possible (in fact likely) that the effects of contact angle and IFT also aredifferent. The only specific proposal germane to this line of inquiry has been make by Morrow. In view of these considerations, the possibility mustbe entertained that theta = 0 degrees is not optimal fortertiary oil recovery. Measurement of contact angles for high-tensionsystems such as liquid/vapor or nonpolar liquid/water isexacting for a variety of reasons. For example. surface preparation is critical and requires meticulous attentionto asperity, heterogeneity. chemical composition. and contamination. Fluids must be scrupulously purified orbe at least of reproducible composition. Avoiding these pitfalls was a prime consideration inthis study. So first, a surface preparation technique was developed that guaranteed a clean smooth substrate. Second, it seemed obvious a priori that the presence of surfactant in high concentrations would completely dominate the usual laboratory contaminants. However, new difficulties attended contact angle measurements atthe low IFT's common to multiphase microemulsion systems, and these may have clouded results. The most that can be claimed is that a start has been made toward acquiring techniques needed to measure contact angles potentially pertinent to flow of microemulsions through porous media. Some trendshave been developed, correlations made, a model proposed, and a few conclusions and conjectures outlined, but much more and much better work will be required before significant advances in understanding are made. Terminology It is conventional to measure contact angles through themore dense phase. Thus, for a drop of oil against air, the contact angle is measured through the oil. For a drop ofthe same oil against water, the contact angle would be measured through the water. A similar convention holds in regard to moving interfaces; they are called advancing or receding dependingon motion of the more dense fluid with respect to substrate it has contacted. In the experiments reported here a drop is placed on a substrate previously equilibrated with cell fluid and allowed to spread. When the drop fluid is more dense than the cell fluid, contactangles obtained during spreading are advancing angles. Otherwise they are receding. Eventually, motion ceases and the contact angle adopts a constant value. This is therecorded value and, as suggested by Huh and Scriven, it is correspondingly labeled advanced or receded. SPEJ P. 342^


SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2615-2631 ◽  
Author(s):  
Mehdi Mohammadi ◽  
Siavash Riahi

Summary Waterflooding is known as an affordable method to enhance oil recovery after primary depletion. However, the chemical incompatibility between injected water and the water in the reservoir may cause the formation of mineral scales. The most effective method for managing such a problem is to use a variety of scale inhibitors (SIs) along with a waterflooding plan. It is necessary to perform a comprehensive study on the incompatibility scaling issue for the candidate-brine/SI formulations, and also their effect on the reservoir-rock/fluid characteristics. In this study, both in the absence and presence of polymeric, phosphonate, and polyphosphonate SIs, the scaling tendency (ST) of different brines is evaluated through experimental and simulation works. Drop-shape analysis (DSA), environmental-scanning-electronic-microscopy (ESEM) observation, energy-dispersive X-ray (EDX) analysis, and microemulsion phase behavior are also used to study the effect of different brine/SI formulations on the rock/fluid and fluid/fluid interactions, through wettability and interfacial-tension (IFT) evaluation. In summary, sulfate (SO42−) was identified as the most problematic ion in the formulation of injected water that causes the formation of solid scales upon mixing with the cation-rich formation water (FW). In the case of SIs, solid precipitation was shifted toward a lower value, with more pronounced effects at higher SI concentrations. At different ionic compositions, the inhibition efficiency (IE%) of all SIs ranged from 16 to 50% at [SI]  = 20 ppm and 38 to 81% at [SI] = 50 ppm. In general, phosphonates worked better (i.e., higher IE value) than polymeric SI. Measuring contact angles along with ESEM/EDX data also illustrated the positive effect of SIs on the wettability alteration of the aged carbonate substrates. In the absence of SIs, the contact angles for different brines were in the range of 70° ≤ θ ≤ 104°, whereas these values fell between 35 and 80° for systems containing 50 ppm of SI. In addition, phase-behavior study and IFT measurement illustrated a salinity-dependence effect of SIs on the interfacial behavior of the oil/water system.


SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1884-1894
Author(s):  
Zuoli Li ◽  
Subhash Ayirala ◽  
Rubia Mariath ◽  
Abdulkareem AlSofi ◽  
Zhenghe Xu ◽  
...  

Summary Polymer enhances the volumetric sweep efficiency through the increased viscosity of injection water and subsequently results in enhanced oil recovery. Most of the reported experimental studies focused on only evaluating polymer viscosifying characteristics and their associated significance for achieving adequate mobility control in porous media. The microscale effects of polymer on wettability alteration in carbonates are rarely studied. In this experimental investigation, the wettability of carbonates in the presence of polymer was measured using contact angle tests. In addition, the adhesion force between carbonate and crude oil droplets in polymer solutions was determined using a custom-designed integrated thin-film drainage apparatus equipped with a bimorph sensor. The liberation kinetics of crude oil from carbonate surfaces were also measured by an optical microscope-based liberation cell to understand the wettability alteration effects on oil recovery. All the experiments, except the adhesion force, which was measured at room temperature due to the restriction of bimorph sensor, were conducted at both ambient and elevated temperatures (70°C) using a sulfonated polyacrylamide polymer (SPAM) (at 500 and 700 ppm) in high-salinity injection water. Deionized (DI) water was used as a baseline to provide a representative comparison with the high-salinity brine. The contact angles of crude oil droplets on a carbonate surface were highest in DI water and decreased in brine. The addition of polymer decreased the contact angle further, with higher concentrations of polymer resulting in a lower contact angle. The adhesion force between crude oil and carbonate showed good agreement with contact angle data, and the oil adhesion was smallest on the carbonate surface in the presence of polymer. The crude oil liberation from the carbonate surface by flooding with brine and polymer was found to be more efficient at elevated temperature than at ambient temperature, consistent with lower contact angles measured in these aqueous solutions at high temperature. The equilibrium oil liberation degree with polymer solutions increased by more than two times when the temperature was increased from 23 to 70°C. The higher liberation degree obtained with polymer solutions also correlated well with the lowest adhesion force measured between crude oil and carbonate in the presence of polymer. These consistent results obtained from different experimental techniques indicated that the oil recovery improvements observed with polymer in dynamic liberation tests are not only related to the increase in water viscosity but are also due to favorable changes in wettability as inferred from both contact angle and adhesion force measurements. This experimental study, for the first time, characterized the microscale effects of polymer on wettability alteration and crude oil liberation in carbonates. The favorable effect of polymer on wettability alteration in carbonates revealed from this study has not been reported in the literature, and it can become a novel addition to the existing knowledge.


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