Forced Imbibition Experiments Research Articles

Experimental study on characteristics of water imbibition and ion diffusion in shale reservoirs

During the soaking process of shale gas reservoirs, due to the imbibition of fracturing fluid and the dissolution of solid substances in the reservoir, the flowback rate is low, and the salinity of the flowback fluid increases. The effects of different salt solutions, surfactants, and boundary conditions on spontaneous imbibition and ion diffusion were studied through comparative experiments. Forced imbibition experiments were conducted to investigate the effect of external pressure. The results show that the pressure applied to the fluid can increase the imbibition rate, but has little effect on ion diffusion. In the same concentration of salt solution, K+ has a stronger inhibitory effect on imbibition and ion diffusion than Na+. Both sodium alcohol ether sulfate (AES, anionic surfactant) and alcohol ethoxylate (AEO-9, non-ionic surfactant) will inhibit imbibition and ion diffusion. The controlled experiments show that AEO-9 inhibits imbibition more obviously, and the ion pair ionized by AES inhibits ion diffusion. Compared with the two-ends-closed (TEC) and two-ends-open (TEO) boundary conditions, all-faces-open (AFO) has the largest exposed areas and is the most favorable for imbibition and ion diffusion. The imbibition and the ion diffusion rates of the 15 cores are roughly linearly correlated, and the ion diffusion is a synchronous process with imbibition. Compared with previous experiments on spontaneous imbibition and ion diffusion of sandstone and hydrate sediment in distilled water, the imbibition rates of shale are the slowest, and the ion diffusion rates are between hydrate sediment and sandstone. This study is of great significance for understanding the mechanism of soaking stimulation in shale gas reservoirs.

Design and development of CaCO3 nanoparticles enhanced fracturing fluids for effective control of leak-off during hydraulic fracturing of shale reservoirs

This research presents new information about the nanoparticles (NPs) use as a filtrate reducer in the hydraulic fracturing of shale reservoirs. An experimental study was conducted to determine the filtration loss control effectiveness (FLCE) of CaCO3 NPs as an additive in fluids used for hydraulic fracturing of the shale reservoirs. The main objectives were (i-) to determine the mechanisms controlling the NPs enhanced fracturing fluid leak-off rate; (ii-) to determine the optimum NPs concentration, which yields the best FLCE. Spontaneous and forced imbibition experiments (to determine imbibition index) as well as the pressure transmission tests (to determine liquid permeability) were conducted using water based fracturing fluids enhanced by CaCO3 NPs. The imbibition index and the apparent liquid permeability measurements were then used to determine the impact of the NPs concentration (i.e. 0.0, 0.5, 1.0, 2.0 wt%) on the FLCE. In order to understand the filtration control mechanisms of the NPs enhanced fracturing fluids, we have analyzed the field emission scanning electron microscope (FESEM) images of the shale samples, which provided detailed description of how NPs are attached to the shale surface. The experimental results indicated that the CaCO3 NPs have excellent FLCE. The imbibition index and the apparent liquid permeability decreased significantly along with the increasing NPs concentration. The optimum NPs concentration was found to be 1.0 wt%. Analyses of the FESEM images demonstrated that the distribution of the NPs on shale surface is selective. The NPs mainly attached on the rough areas of the shale surface. The process of the NPs adsorption-sealing leads to the reduction of the path of the fluid flow into the shale matrix, and in turn, controls the fracturing fluid filtration. Ultimately, four kinds of sealing patterns were observed including (i-) plugging, (ii-) bridging, (iii-) plugging and accumulation, (iv-) bridging and accumulation.

Subpore‐Scale Trapping Mechanisms Following Imbibition: A Microfluidics Investigation of Surface Roughness Effects

AbstractSurface roughness is ubiquitous in subsurface formations due to weathering and diagenesis. Yet micromodel studies of porous media have not sufficiently addressed the impact of pore‐wall roughness on multiphase fluid displacement. We investigate the influence of pore‐wall roughness on capillary trapping by implementing surface roughness into glass micromodels and conducting imbibition experiments. Time‐lapse fluorescence microscopy, micromolding in capillaries, and scanning electron microscopy are used to examine flow behavior during spontaneous and forced imbibition experiments with capillary numbers between 10−6 and 10−4. It is found that surface roughness causes interface pinning and irregular displacement fronts within a single pore, promotes latent pore filling following imbibition, enhances snap‐offs, and contributes to interface relaxation. Furthermore, we verify a cooperative effect between corner flow and surface roughness that causes pore filling to occur at over 10 times the channel width ahead of the main bulk front. Consequently, a significant increase in trapped air saturation of up to 60% is observed, especially at lower capillary numbers and narrower pores. Effects of surface roughness also decrease the rate of spontaneous imbibition, which is slower than the prediction from Washburn's equation. Our results emphasize the importance of surface roughness in building conceptual models for capillary trapping when the ratio of surface roughness‐to‐pore size reaches a critical value of about 0.1. Above this critical threshold value, subpore‐scale trapping mechanisms contribute significantly to capillary trapping, which theoretical and numerical models should consider for accurate quantification of fluid‐transport processes.

Adsorption of natural CaCO3 nanoparticles on the reservoir rock surfaces in the enhanced oil recovery process: equilibrium, thermodynamics, and kinetics study

The major challenges in using nanoparticles in oil and gas industry projects are high investment costs and environmental problems. Bio-nanoparticles provide a solution to environmental and economic challenges in the nano-assisted EOR processes. In this work, the potential of natural calcium carbonate nanoparticles containing chitin for wettability alteration in enhanced oil recovery was studied. The adsorption behavior of bio-nanoparticles onto calcite-dolomite rock surface was distinguished through kinetics, equilibrium, and thermodynamics assessments. Besides, oil recovery is measured through forced imbibition experiments. The Taguchi experimental design was conducted to optimize the parameters influencing oil recovery factor in forced imbibition experiments, including nanofluid concentration, temperature, and oil type. Results of the adsorption experiment showed that adsorption kinetics of bio-Ca nanoparticles onto calcite-dolomite surface follows the pseudo-second-order model and monolayer, Langmuir adsorption of bio-nanoparticles. The endothermic heat of physical adsorption (physisorption) was found 3.32 kJ/mol. Based on the experimental design, the optimum parameters that can rise to additional oil displacement are a nanofluid concentration of 0.05 wt.%, normal heptane as liquid phase, minimum salinity (Milli-Q-water), and ambient temperature. The oil recovery factor increased by 17.52% at an optimum nanofluid concentration of 0.05 wt.% in comparison to a base fluid without nanoparticle. The results indicate that synthesized bio-Ca nanoparticles have proper EOR potential in both light oil and heavy oil reservoirs at certain conditions.

Amino Acid as a Novel Wettability Modifier for Enhanced Waterflooding in Carbonate Reservoirs

SummaryReservoir wettability plays an important role in waterflooding, especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and β-alanine. Contact angle experiments with oil-aged calcite were conducted at room temperature with deionized (DI) water, and then at 368 K with three saline solutions: 243 571-mg/L salinity formation brine (FB), 68 975-mg/L salinity injection brine 1 (IB1), and 6898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the β-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. The primary mechanism is that the glycine solution weakens the interaction between polar oil components and positively charged rock surfaces when the solution pH is between glycine's isoelectric point (pI) and the surface's point of zero charge (pzc). The secondary mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.The amino acids tested in this research are nontoxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution's pH, and rock's pzc.

Effect of Nanoscale Surface Textures on Multiphase Flow Dynamics in Capillaries.

Multiphase flow through porous media is important in a wide range of environmental applications such as enhanced oil recovery and geologic storage of CO2. Recent in situ observations of the three-phase contact line between immiscible fluid phases and solid surfaces suggest that existing models may not fully capture the effects of nanoscale surface textures, impacting flow prediction. To better characterize the role of surface roughness in these systems, spontaneous and forced imbibition experiments were carried out using glass capillaries with modified surface roughness or wettability. Dynamic contact angle and interfacial speed deviation, both resulting from stick-slip flow conditions, were measured to understand the impact these microscale dynamics would have on macroscale flow processes. A 2 k factorial experimental design was used to test the ways in which the dynamic contact angle was impacted by the solid surface properties (e.g., wettability, roughness), ionic strength in the aqueous phase, nonaqueous fluid type (water/Fluorinert and water/dodecane), and the presence/absence of a wetting film prior to the imbibition of the wetting phase. The analysis of variance of spontaneous imbibition results suggests that surface roughness and ionic strength play important roles in controlling dynamic contact angle in porous media, more than other factors tested here. The presence of a water film alone does not affect dynamic contact angle, but its interactions with surface roughness and aqueous chemistry have a statistically significant effect. Both forced imbibition and spontaneous imbibition experiments suggest that nanoscale textures can have a larger impact on flow dynamics than chemical wettability. These experimental results are used to extend the Joos and Wenzel equations relating apparent static and dynamic contact angles to roughness, presence of a water film, and water chemistry. The new empirical equation improves prediction accuracy by taking water film and aqueous chemistry into account, reducing error by up to 50%.

The forced imbibition model for fracturing fluid into gas shales

Understanding the factors controlling the fracturing fluid leak-off due to forced imbibition during the hydraulic fracturing operations is critical for the accurate assessment of the fracturing fluid invasion depth and the extent of the formation damage in gas shales.Here, we present results of an experimental and a modeling study of the factors controlling fracturing fluid forced imbibition into the organic rich shale gas reservoirs. The main objectives of the study were to: i-) Experimentally investigate the forced imbibition of the brine and the slick water (SW) into the shale; ii-) Develop an analytical model of the fracturing fluid forced imbibition into the shale matrix.The shale samples collected from Silurian Longmaxi (SL) Shale Formation, which is located in Southern Sichuan Basin in China, were used to conduct the forced imbibition experiments. Effects of varying fluid properties (i.e., the viscosity and the surface tension), the direction of the imbibition with respect to the shale bedding plane/lamination, and the fluid pressure across the shale face on the cumulative mass of the imbibed fluid per unit area over time were investigated.A new analytical model of the forced imbibition into a shale rock was developed. The Hagen-Poiseuille law and the capillary tube bundles model were used to describe flow through tortuous capillary. The new model also considered the effects of the fluid pressure across the rock face (i.e., forced imbibition) and the viscous pressure loss in the capillary. Comparison of the model predictions with the experimental results indicated that the effects of the fluid pressure and viscous pressure loss on the imbibed fluid mass are not negligible. The close agreement with the model predictions and experimental results in the direction parallel to shale lamination confirmed that the new model accurately describes the process of fracturing fluid forced imbibition into the shale matrix in the direction parallel to shale bedding plane.The new model could potentially be used for the field scale prediction of the average depth of fluid invasion into the shale matrix in the direction parallel to lamination due to the forced imbibition of the fracturing fluid.

Eliminate the role of clay in sandstone: EOR low salinity water flooding

Low-salinity (LS) water flooding mechanism enhanced oil recovery (EOR) method in sandstone has been extensively debated in the literature. Many mechanisms have been proposed, but these proposed mechanisms remain a topic of debate. In this study, we propose to quantify control of mineral composition and water chemistry on water/rock interactions and wettability change during low-salinity waterflooding of spatially heterogeneous sandstone porous media. We intended to identify the dominant process of wettability alteration through considering water–rock interaction mechanisms containing/non-containing clays. Water chemistry partially determines the dominant wettability alteration. This includes salinity, type of ions, and possibly pH. Sandstone core and free clay sand core were prepared in chromatography columns and were water flooded with high/low/high-salinity water at different temperatures. Brine with high salinity 100,000 ppm was injected to simulate formation water, then, inflow low-salinity water 1100 ppm at different temperatures. Concentrations of Ca2+ and CH3COO− and pH were recorded. The core contains quartz only, to investigate the role of clay in the mechanism of smart water EOR. The results proved that during flooding the free clay core by low-salinity water the carboxylic acid detached from the sand, albeit not as great as that of the clay-containing cores. On the other hand, ICP-OES showed a noteworthy desorption of Ca2+ from the free clay core surface. That indicates further RCOO− recovery in the absence of clay. It has been observed that during flooding by LS water, the pH increased significantly. Also, as the temperature increased the pH of the LS water decreased and amount of Ca2+ decreased in the effluent. This work presents the results of forced imbibition experiments to examine the effect of clay in sandstone during LS flooding EOR.

Shale-fluid interactions during forced lmbibition and flow-back

One way to minimize the need for disposal of flow-back waters produced during the hydraulic fracturing of unconventional reservoirs is, potentially, to recycle these fluids by recovering and re-injecting them during hydraulic fracturing of nearby new wells. These flow-back waters contain, however, large concentrations of dissolved salts. During hydraulic fracturing of unconventional reservoirs, a well may undergo extended shut-in periods, following the initial hydraulic-fracture stimulation. The concern here, therefore, is that the salts dissolved in the re-injected flow-back waters may precipitate in the subsurface, thus promoting scale formation; or alternately, because of their high salinity, these same fluids may cause the dissolution of various minerals present in the subsurface. Large divalent cations (e.g., Ca2+, Ba2+ and Sr2+) and anions (e.g., CO32− and SO42) may chemically interact with and cause the swelling of clay fractions, thus blocking pores in certain pore size ranges. All these phenomena (i.e., scale formation, clay swelling, minerals dissolution) can influence the petrophysical properties of the formation, including its permeability, porosity, contact angle, etc. One way to potentially overcome some of these technical challenges, is to pre-treat these flow-back waters, prior to re-injection (e.g., via chemical precipitation, followed by membrane filtration) in order to remove unwanted salts. However, such pre-treatment is costly, and the degree of salt removal needed to prevent formation damage is important in determining the economic viability of flow-back water recycle via re-injection. A key focus of this work, therefore, is to study the impact that the injection of flow-back waters, that have undergone varying degrees of pre-treatment and clean-up, will have on the flow-through characteristics of a tight-gas reservoir, particularly of the Marcellus Shale formation. To do so, we have carried-out forced-imbibition experiments with shale samples from various depths in the Marcellus formation, whose properties span high to low ranges of TOC, clay content and matrix permeabilities. We have studied the forced-imbibition characteristics, at an injection pressure of 24,233 kPa (3500 psig), of various flow-back fluids into shale cores saturated with methane at a pore pressure of 17,338 kPa (2500 psig) and a confining stress of 27,680 kPa (4000 psig). Following the forced imbibition experiments, we analyzed the cores for potential changes in permeability and porosity. Quantification of the ion content of the injected and recovered fluids was also performed using Ion Chromatography (IC). The IC analysis of the recovered fluids indicates substantial interactions and geochemical reactions between the invading fluids and the shale cores. The injection of flow-back fluids shows significant impact on the flow-through characteristics, with untreated flow-back fluids, which have the highest cation and anion content, also exhibiting the highest observable reductions in permeability (>90%).

Sequential injection mode of high-salinity/low-salinity water in sandstone reservoirs: oil recovery and surface reactivity tests

The aim of this paper is to quantify the effect of low-salinity (LS) water on oil recovery from sandstone cores at different temperatures and at various permeabilities, oil viscosities, and Ca2+ concentrations in the formation water. Six sandstone cores were waterflooded with high-salinity (HS) and LS water at various temperatures ranging from 25 to 90 °C. Four cores were allocated to oil recovery experiments, and the other two were dedicated to surface reactivity tests. The Swi and Sor of the cores were established, and then the cores were pre-aged for 3 days at 70 °C with oil in a closed container. We examined the effect of different ionic solutions (HS water, LS water, and double Ca2+ HS water) at different temperatures. The surface reactivity test cores were flooded with the same HS and LS brines that were used in oil recovery forced-imbibition experiments. During flooding, samples of the effluent were analyzed for pH and Ca2+. The absence of an oil phase enabled us to isolate and quantify the important water–rock reactions. Ca2+ desorption from the core that was aged in the double Ca2+ concentration was larger than that desorbed from the other core, but pH and pressure was less than the other core during surface reactivity tests. Due to dehydration at high temperatures, the desorption of Ca2+ decreased as the temperature increased. Also, as the temperature increased, the pH gradient between the HS and LS water effluents decreased. Oil recovery forced-imbibition experiments with a double Ca2+ concentration showed a small LS water effect at all temperatures, meaning that the cores became more water-wet; however, the LS water effect was much greater when the amount of Ca2+ in the HS water was decreased by half. Furthermore, as the core permeability and oil viscosity increased, our tests showed a greater positive effect from the LS water. This work attempts to isolate the separate effects and thus examines the oil recovery achieved with the most important LS waterflood factors, which are temperature, ion exchange, and pH.

Novel Insights Into Mechanisms of Oil Recovery by Use of Low-Salinity-Water Injection

Summary The underlying mechanism of oil recovery by low-salinity-water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature, but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct-flow-visualization investigations (Emadi and Sohrabi 2013) have revealed that a physical phenomenon takes place when certain crude oils are contacted by low-salinity water, leading to a spontaneous formation of micelles that can be seen in the form of microdispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude-oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include direct-flow (micromodel) visualization, crude-oil characterization, coreflooding, and spontaneous-imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface-active components of crude oil, and the improvement in oil recovery because of LSWI. We present the results of a series of spontaneous- and forced-imbibition experiments carefully designed with reservoir cores to investigate the role of the microdispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing an LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared with high-salinity-water injection (HSWI) in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude-oil/brine-interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicate that the natural surface-active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research can be applied to oil recovery from both sandstone and carbonate oil reservoirs because they are mainly derived from fluid/fluid interactions that control wettability alteration in both sandstone and carbonate rocks.

Velocity‐saturation relation in partially saturated rocks: Modelling the effect of injection rate changes

ABSTRACTThe relationship between P‐wave velocity and fluid saturation in a porous medium is of importance for reservoir rock characterization. Forced imbibition experiments in the laboratory reveal rather complicated velocity–saturation relations, including rollover‐like patterns induced by injection rate changes. Poroelasticity theory‐based patchy saturation models using a constant fluid patch size are not able to describe these velocity–saturation relations. Therefore, we incorporate a saturation‐dependent patch size function into two models for patchy saturation. This recipe allows us to model observed velocity–saturation relations obtained for different and variable injection rates. The results reveal an increase in patch size with fluid saturation and show a reduction in the patch size for decreasing injection rate. This indicates that there can exist a distinct relation between patch size and injection rate. We assess the relative importance of capillarity on velocity–saturation relations and find that capillarity stiffening impairs the impact of patch size changes. Capillarity stiffening appears to be a plausible explanation when a decrease in the injection rate is expected to boost the importance of capillarity.

Forced imbibition into a limestone: measuring P‐wave velocity and water saturation dependence on injection rate

ABSTRACTQuantitative interpretation of time‐lapse seismic data requires knowledge of the relationship between elastic wave velocities and fluid saturation. This relationship is not unique but depends on the spatial distribution of the fluid in the pore‐space of the rock. In turn, the fluid distribution depends on the injection rate. To study this dependency, forced imbibition experiments with variable injection rates have been performed on an air‐dry limestone sample. Water was injected into a cylindrical sample and was monitored by X‐Ray Computed Tomography and ultrasonic time‐of‐flight measurements across the sample. The measurements show that the P‐wave velocity decreases well before the saturation front approaches the ultrasonic raypath. This decrease is followed by an increase as the saturation front crosses the raypath. The observed patterns of the acoustic response and water saturation as functions of the injection rate are consistent with previous observations on sandstone. The results confirm that the injection rate has significant influence on fluid distribution and the corresponding acoustic response. The complexity of the acoustic response —‐ that is not monotonic with changes in saturation, and which at the same saturation varies between hydrostatic conditions and states of dynamic fluid flow – may have implications for the interpretation of time‐lapse seismic responses.

Experiments and Analysis of Multiscale Viscous Fingering During Forced Imbibition

Summary Immiscible displacement of one fluid by another in porous media has practical applications when viscous oil is produced by water injection. A greater understanding of the flow patterns that evolve during such unstable displacements yields insights into improving predictive capability and increasing oil recovery. Immiscible multiphase displacement exhibits a wide range of behaviors depending on the relative magnitude of viscous, capillary, and gravity forces. Using flow-visualization images from forced-imbibition experiments carried out in etched-silicon micromodels, we show that the conventional Darcy-type modeling of fluid flux is not predictive under unstable, immiscible, forced-imbibition conditions at the scale of interest. When a less viscous fluid displaces a more viscous fluid at low capillary numbers, the displacement patterns show viscous instabilities in the form of fingers and local capillary control of interface movement. We show that such complex displacement patterns are well modeled using statistical theories. We derive a scaling model to describe quantitatively the functional forms for saturation, fractional flow, and capillary dispersion profiles using the self-similar characteristics inherent in the displacement patterns. For the specific range of flow rates (Nc ~ 10−7) and oil/water viscosity ratios (M ~ 8–400) considered in our experiments, both capillary and viscous forces are important, and the displacement pattern indicates fractal features. Results show that functional relations of the scaling model are in considerable agreement with our experimental data.

Capillary Pressure and Wettability Behavior of CO2 Sequestration in Coal at Elevated Pressures

SummaryEnhanced coalbed-methane (ECBM) recovery combines recovery of methane (CH4) from coal seams with storage of carbon dioxide (CO2). The efficiency of ECBM recovery depends on the CO2 transfer rate between the macrocleats, via the microcleats to the coal matrix. Diffusive transport of CO2 in the small cleats is enhanced when the coal is CO2-wet. Indeed, for water-wet conditions, the small fracture system is filled with water and the rate of CO2 sorption and CH4 desorption is affected by slow diffusion of CO2. This work investigates the wetting behavior of coal using capillary pressures between CO2 and water, measured continuously as a function of water saturation at in-situ conditions. To facilitate the interpretation of the coal measurements, we also obtain capillary pressure curves for unconsolidated-sand samples. For medium-and high-rank coal, the primary drainage capillary pressure curves show a water-wet behavior. Secondary forced-imbibition experiments show that the medium-rank coal becomes CO2-wet as the CO2 pressure increases. High-rank coal is CO2-wet during primary imbibition. The imbibition behavior is in agreement with contact-angle measurements. Hence, we conclude that imbibition tests provide the practically relevant data to evaluate the wetting properties of coal.