Wettability of Reservoir Rocks Having Different Polarity by a Model

Jan 15, 2018 - A linear dependence between the equivalent height of capillary rise and the square root of imbibition time was observed at ... drilling...
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Wettability of Reservoir Rocks Having Different Polarity by a Model Nonionic Surfactant: Fluid Imbibition Study into Crushed Rock Packs Andrei S. Zelenev* and Zlata Grenoble Global Research and Innovation Center, Flotek Industries, Inc., 8846 N. Sam Houston Pkwy. W., Suite 150, Houston, Texas 77064, United States ABSTRACT: The imbibition of solutions of a model nonionic surfactant into packed beds of crushed reservoir rocks was studied using the Washburn technique. A linear dependence between the equivalent height of capillary rise and the square root of imbibition time was observed at different stages of imbibition experiments. It has been shown that, under the conditions when surfactants did not alter the polarity of rocks, the imbibition rate of surfactant solutions correlated well with the nondispersion (polar) component of the surface free energy of the rocks. It was possible to compare data obtained for different rocks by normalizing the slopes of imbibition curves over the corresponding slopes determined for a completely wetting fluid, hexamethyldisiloxane (HMDS). Such a normalization allowed one to account for substantial differences in the morphology of crushed rock powders. Overall, the observed trends in the imbibition behavior were qualitatively similar to the trends reported previously for the rise of surfactant solutions in single capillaries. The largest qualitative impact of nonionic surfactant was observed in the imbibition into hydrophobic oily sandstone, in which case a surfactant-induced shift to hydrophilicity was observed. Overall, high concentrations were needed in order to observe the impact of surfactant on the imbibition rate.

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INTRODUCTION The main goal in hydrocarbon production is to facilitate the movement of trapped oil and gas through the rock matrix and to bring them to the surface via the wellbore. In the course of drilling and completing the well, the reservoir is exposed to large amounts of aqueous fluids. During hydraulic fracturing a large portion of injected fluid stays in the rock matrix creating water blocks which restrict the flow of hydrocarbons to the wellbore. This posthydraulic fracturing water retention is especially pronounced in tight shale reservoirs, where only a small fraction of injected fluid can be recovered during the flowback. For example, in the Eagle Ford formation in the United States, less than 20% of injected fracturing fluid is produced over the lifetime of the well.1 Between different formations, the extent of water imbibition into the matrix and its production during the flowback can vary significantly and in a complex way, depending on gas-to-oil ratio, connectivity of pore networks, saturations, and other properties of reservoirs.2,3 The tendency to form water blocks depends on the difference in wettability of the rock matrix by oil and water. In the most general sense wettability can be defined as the affinity of a given liquid phase (polar or nonpolar) toward a given solid phase and is closely related to the balance between the works of adhesion and cohesion which are in turn governed by dispersion and nondispersion intermolecular forces.4 Wettability, along with the interfacial tension (or surface tension in the case of dry gas) and pore radius, defines the capillary pressure, Pc, which controls spontaneous fluid imbibition in both conventional and unconventional reservoirs. Although the use of surfactants for lowering the capillary pressure appears to be straightforward, the knowledge of the exact mechanisms of their action downhole is still incomplete in view of the complexity and a large variety of phenomena governing the propagation of liquids in the porous media.2 The situation may be complicated even further if in addition to © XXXX American Chemical Society

surfactant the surface active treatment also contains solubilized solvent, as in the case of microemulsions.5,6 Surfactant selection for use in well stimulation applications is often based on their physical properties, such as their solubility in brines and the surface tension of their aqueous solutions at a given temperature, or based on the experiments designed to evaluate their impact on wettability in a given rock matrix. Typical experiments involve spontaneous imbibition of aqueous surfactant solutions into shale cores pre-aged in oil and determining the amount of oil released.7−10 Due to a very low permeability of shale, the volumes of imbibed aqueous phase and displaced oil are typically rather small, and the spontaneous imbibition process itself is quite slow (on the order of days), as has been illustrated in recent studies.9,10 Furthermore, in these types of studies one needs to be concerned about core-to-core variability, as no two cores are identical. Wettability is also often characterized by the direct goniometric contact angle measurements at the interfaces of macroscopic pieces of core or rock with air11,12 or with the oil.8−10 Results of direct contact angle measurements need to be used and interpreted cautiously, as they may not reflect the true wettability existing in the pore space.2,7,13 Neither imbibition into tight cores nor goniometric measurements take into consideration the fact that, when pumped downhole, the surfactant solutions come in contact with a very large surface area of fractured rock. The impact of surface area, and hence of surfactant adsorption, can be accounted for more effectively, if wettability experiments are conducted with crushed rocks. In this case, the surface area in the packing can be varied by utilizing particles of different size fractions. Furthermore, conducting studies with crushed rock Received: October 30, 2017 Revised: January 12, 2018 Published: January 15, 2018 A

DOI: 10.1021/acs.energyfuels.7b03345 Energy Fuels XXXX, XXX, XXX−XXX

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and the height of fluid rise, h. Changes in θ and γ are governed by the corresponding adsorption isotherms and by the adsorption kinetics. Many mechanistic insights into the wettability of porous media by surfactant solutions were established via numerous studies in single capillaries, which also confirmed linear dependence between the height of capillary rise and t1/2.21−23 One of the main objectives of the present work was to examine the imbibition of solutions of a model nonionic surfactant into porous media composed of crushed reservoir rocks significantly varying in their polarity, and to compare our findings with those established for hydrophilic and hydrophobic single capillaries. The rocks included in the study are hydrophilic and water-wet Berea sandstone, hydrophobic, water nonwet oily (bituminous) sandstone, and two rocks with intermediate polarity: Canadian oily dolostone and a sample from the Fayetteville shale outcrop in Arkansas. The polarity of these rocks was characterized via surface free energy measurements as described in our previous study.12

allows one to focus on the interaction between the solid matrix and the wetting (or nonwetting) fluid. In this case the pore network structure existing in the intact cores accounting for a high degree of variability in the data between different cores is destroyed. A comparison of imbibition into crushed and intact cores has been described in recent studies.7,13 It has been shown that there is a significant difference in the connectivity of oil-wet and water-wet pores in the intact cores and in the packs of crushed core material. In contrast to the intact rock samples, crushed samples have been shown to consistently imbibe more oil than water.7 The possibility of using crushed rock also appears to be attractive because in many cases only rock cuttings or rock outcrop samples, rather than intact cores, are available for conducting laboratory studies. This is the case in the present study. In a typical experiment on fluid imbibition into powder packs, a cylindrical tube with a permeable filter at the bottom is filled with the powdered material, the packed plug is placed in contact with the liquid, and fluid uptake into the pack is monitored.14,15 Depending on the experimental setup, either the height of liquid rise or the mass of imbibed fluid can be measured as a function of time. For pure liquids, under the conditions when hydrostatic pressure can be neglected, a linear relationship between the square of imbibed mass, m, and time, t, is established, and is described by a well-known Lucas− Washburn equation:16,17

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THEORY In order to be able to compare the results of imbibition studies into crushed rocks with the results of capillary rise studies in single capillaries,21−23 eq 1 needs to be transformed into a dimensionally similar form. It is apparent that kγ cos θ m2 = VL 2 = (Vtotφ)2 = L t 2 η ρ

2

m2 =

kρ γL cos θ η

t

(1)

(2)

where VL is the volume of imbibed liquid at time t and Vtot is the total volume in the Washburn cell at time t, Vtot = VL + VS, and φ is the porosity. VS is the volume of the solid phase (crushed rock) in the cell. Under the assumption that there is no fingering taking place and that the permeability of crushed rock grains is negligible, the effective height of capillary rise, h, which is dimensionally equivalent to the length of the liquidfilled part of a capillary, can be estimated as

where γL, ρ, and η are the surface tension, density, and viscosity of imbibing fluid, respectively; θ is the contact angle established in the pore space by the meniscus contact line; and k is the socalled “capillary constant”, which is in fact a product of various parameters characterizing given porous media and the given geometry of the measuring cell (see below). Provided that one can pack the powder into a Washburn cell in a reproducible manner, the capillary constant, k, can be obtained from a separate experiment with a completely wetting, low surface tension liquid for which cos θ = 1. In the present study hexadimethylsiloxane (HMDS) was used as such a liquid. Equation 1 is derived on the basis of Poiseuille’s law combined with the Laplace equation.14,15 A similar linear dependence between the square of imbibed fluid volume and time can also be obtained on the basis of the analysis of pistonlike imbibition into the porous media using Darcy’s equation in combination with capillary pressure and continuity equations.18 For pure liquids eq 1 can be used to evaluate contact angles from the linear dependence of m2 as a function of time. Despite the seeming simplicity, the characterization of wetting on the basis of the Washburn equation is in fact ambiguous. The ambiguity is related not only to the need to determine the capillary constant k in a separate experiment, but also to the actual meaning of the contact angle in the Washburn equation. Due to the dynamic nature of the imbibition process, θ represents the dynamic advancing contact angle, which depends on the fluid velocity,19 and in tortuous porous media can exhibit strong anisotropy.20 The analysis is complicated even further in the case of wetting of powders by aqueous surfactant solutions. In this case both the surface tension of surfactant solution and the contact angle established by the imbibing liquid meniscus are not constant. Throughout the imbibition process they are both functions of imbibition time

h(t ) =

Vtot(t ) 2

πR

=

VL(t ) φπR2

(3)

where R is the radius of the Washburn cell base. Taking this into account the Washburn equation can be written as h(t ) =

r *γL cos θ ηφ 2R4π 2

t =K t (4)

from where the rigorous meaning of k in eqs 1 and 2 becomes evident: k=

r* φRπ

2 4 2

(5)

The parameter r* has the units of length and describes the radius of the pores. For the case of a single capillary it is simply a radius of capillary, r* = rc, while for porous media it has the meaning of the effective pore radius defined as14,24 r* =

(RD)2 RS

(6)

where RS is the static (volumetric) pore radius, and RD is the dynamic pore radius which depends on the roughness and wettability of the surface. For an ideally smooth surface with no surface slip, RD is equal to RS. In principle, in a well-defined B

DOI: 10.1021/acs.energyfuels.7b03345 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels Table 1. Properties of Oil-Bearing Reservoir Rocksa surface free energy12,25 (erg/cm2) porosity Berea sandstone oily dolostone Fayetteville shale oily sandstone a

0.29 0.43 0.48 0.55

−3

density (g cm )

water contact angle b

2.65 2.83 2.20 2.25

hini the rate of fluid uptake transitioned to that described by Kfin, while in some instances there was an additional transition range between these two limits. In the case of Berea sandstone the slopes at the initial stage of the uptake appeared to be slightly lower than the slopes at the end of uptake, while for other rocks the trends were the opposite. Overall, the largest qualitative changes due to the D

DOI: 10.1021/acs.energyfuels.7b03345 Energy Fuels XXXX, XXX, XXX−XXX

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Figure 8. Height of surfactant solution rise, hini, corresponding to the point at which the slope of h versus t1/2 plot changes from the value of Kini either to that described by Kfin or to that described by some transition value. For oily dolostone only the points at which hini could be determined are shown, which explains the breaks in the lines.

Figure 6. Imbibition of C12EO7 solutions of different surfactant concentrations into crushed Fayetteville shale. Data are presented according to eq 4.

Figure 7. Imbibition of C12EO7 solutions of different surfactant concentrations into crushed oily (bituminous) sandstone. Data are presented according to eq 4.

Figure 9. Slopes Kini and Kfin normalized over the corresponding slopes for HMDS, KHMDS,ini and KHMDS,fin (Table 2) as a function of surfactant concentration for the imbibition of surfactant solutions into different rocks (Figures 4−7).

addition of surfactant were observed with oily sandstone. A very clear inflection point appeared at h = hini for C12EO7 > 3 gpt (Figure 7), and the value of hini increased with increasing surfactant concentration. At a concentration of 50 gpt C12EO7 the imbibition curve is qualitatively similar to the curves obtained for Berea sandstone (Figure 4). In order to properly compare the imbibition data obtained with different rocks, the slopes obtained from Figures 4−7 needed to be normalized by the slopes obtained with HMDS (Table 2). In this case relative slopes were calculated as Kini/ KHMDS,ini and Kfin/KHMDS,fin, respectively. These data are shown in Figure 9 as a function of surfactant concentration. Overall, very small differences were observed between Kini/KHMDS,ini and Kfin/KHMDS,fin for the corresponding conditions. The relative order of the curves with respect to K/KHMDS agreed with the relative polarity data of the rocks expressed as the difference in the nondispersion component of the surface free energy, γsnd,

summarized in Table 1. Indeed, K/KHMDS had the highest value for polar Berea sandstone, the lowest value for nonpolar oily sandstone, and intermediate values for Fayetteville shale and oily dolostone, both of which are rocks with an intermediate polarity. Furthermore, the curves for Fayetteville shale and oily dolostone are very close to each other. Figure 8 shows the height of rise, hini, corresponding to the first observed change in slope. For the oily dolostone, this slope change was observed only at some surfactant concentrations, which explains why not all the data points in Figure 8 are connected. Viscosity Measurements. The surfactant solutions exhibited Newtonian behavior with near-water values of viscosity. Very slight increase in viscosity was observed for all samples at shear rates above 200 s−1 most likely attributed to turbulence. E

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different rock packs. This explains why the impact of surfactant on the imbibition rate started to become visible at different concentrations for different rock species. Furthermore, the change in slopes from Kini and Kfin can be attributed to the decrease of both the surface and meniscus concentrations of a surfactant as the solutions propagated along the rock pack.21 In the case of Berea sandstone the uptake was very rapid and practically independent of surfactant concentration. Fluid uptake for this system was much faster than that observed with other rocks. Berea sandstone is predominantly composed of quartz grains held together by silica particles,27 and as such is completely hydrophilic and water-wet. In this case fluid rise was dominated by a complete wetting with water, rather than by surfactant adsorption. This behavior is qualitatively similar to surfactant solution rise in a hydrophilic capillary.23 However, at sufficiently high surfactant concentration, C12EO7 can increase the hydrophobicity of Berea surface, which would slow down the uptake. The onset of such behavior is observed in Figure 9 at C12EO7 concentrations higher than 1 gpt. Large surface area available to surfactant adsorption probably allowed maintaining a uniform surfactant concentration at the meniscus and did not produce a surfactant concentration gradient between the meniscus and the bulk. This explains why a maximum in the height of rise previously observed in hydrophilic capillaries was not detected in the Berea sandstone pack. It is also worth commenting that eq 4 yielded very large values of limiting height of liquid rise for Berea sandstone. The obtained values are comparable to the dimensions of the Washburn cell itself. This suggests that at least some of the porous nature of Berea sandstone was preserved, and the −70/+140 mesh grains were in fact somewhat permeable to the fluid. However, this discrepancy does not affect the generality of the present analysis. In the cases of oily dolostone and Fayetteville shale the rate of surfactant solution imbibition was slower than in the case of Berea sandstone, which correlates well with the “intermediate wettability” suggested by comparable contributions from γd and γnd to the surface free energy (Table 1). In both cases imbibition rate was essentially independent of surfactant concentration over a broad range of concentrations, and differed very little from that of pure water. These data suggest that at low surfactant concentrations the fluid uptake was governed by water wettability and not by the surfactant transport. The rate of water uptake was slower than in the case of Berea sandstone due to an increased nonpolar character of these rocks. The surfactant adsorption, however, started to play a role at high concentrations, as evidenced by the change in the slopes (Figures 5 and 6). This is especially well seen in the study with Fayetteville shale (Figure 6), in which case an extended range of surfactant concentrations was examined. The observed change in the slope is likely related to the point at which the surfactant concentration at the meniscus fell below the cmc due to adsorption.21 At the concentrations below the cmc, the meniscus became impoverished of surfactant molecules at rather short penetration heights, and the fluid penetration rate became comparable to that of pure water. One needs to keep in mind that due to adsorption the apparent cmc of a surfactant in the porous media is expected to shift to higher concentrations as compared with the bulk cmc. The spikes in hini observed in Figure 8 are most likely indicative of the concentration at which the cmc was reached and were caused by small spikes in capillary pressure. These spikes may be relevant to the minimum in surface tension of surfactants

The viscosity values determined in the shear rate range between 20 and 200 s−1 were averaged for each sample. These values are summarized in Table 3, which shows a steady increase in the Table 3. Viscosity of C12EO7 Solutions η (Pa s)

surfactant concn (gpt) 0 5 10 20 50 75 100

(8.66 (9.88 (1.01 (1.08 (1.27 (1.48 (1.81

± ± ± ± ± ± ±

0.09) 0.09) 0.05) 0.09) 0.09) 0.05) 0.09)

× × × × × × ×

10−4 10−4 10−3 10−3 10−3 10−3 10−3

value of viscosity with the increase in surfactant concentration, but the magnitude of the observed changes was significant only at doses above 20 gpt.

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DISCUSSION The differences in the imbibition rates of a completely wetting HMDS fluid are well explained by the differences in the appearance of crushed rocks (Figure 3). The observed difference would indeed be expected for naturally occurring rocks. These data indicate that, in conducting studies with crushed mineral rocks, one should not rely strictly on the results of sieving and should not ignore a drastic difference in morphology of crushed material. However, it appears that the differences in the morphology of the packing can be adequately accounted for by normalizing the h versus t1/2 slopes of surfactant solutions over the corresponding slopes of a low surface tension liquid, such as HMDS. This is the same principle that is typically utilized in the determination of contact angles by the Washburn method.26 Before discussing in detail the results of the imbibition of surfactant solutions into different rocks, let us point to a good agreement between the rock polarity expressed as dispersion and nondispersion surface free energy values and the relative order of K/KHMDS curves shown in Figure 9. These data indicate that under the conditions when added surfactants did not cause a significant change in rock polarity the normalized imbibition rate correlated well to the nondispersion component of the surface free energy (Table 1). Interaction of Reservoir Rocks with Surfactants. The results clearly show that there are essentially two metrics that adequately characterize the imbibition of surfactant solution into the crushed rock beds: the slopes of the h = f(t1/2) curves and the height of rise at a given time. The presentation of imbibition data in the form of h = f(t1/2) allows one to qualitatively compare the results of the present studies with the results of studies of capillary rise in single capillaries21−23 and use the findings reported in these studies to explain the trends in the data. The principal difference between the present results and the results of studies carried out in single capillaries is the exposure of surfactant solutions to a large surface area, meaning that surfactant adsorption influenced the results of liquid rise to a much larger extent than in single capillaries. The surfactant concentration was highest at the entrance to the cell and decreased as surfactant solutions propagated further upward. The extent of adsorption depends on the nature of the rock, available surface area, and surfactant concentration. Although the surface area of crushed rock samples was not measured, the images in Figure 3 suggest that it was very different across F

DOI: 10.1021/acs.energyfuels.7b03345 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels frequently observed around the cmc.28 The decrease in the uptake rate seen in Fayetteville shale at high surfactant concentrations is likely a combined result of an increased viscosity of surfactant solutions (Table 3) and a possible increase in shale hydrophobicity, similarly to the case of Berea sandstone. However, a decrease in the rate of fluid uptake at high surfactant concentrations may also take place due to the dispersion and movement of fine shale particles (Figure 3). The largest qualitative impact of surfactant on the imbibition rate was seen with oily (bituminous) sandstone. This rock contained a large amount of bitumen which could be readily extracted by contacting the rock with a solvent, such as chloroform or D-limonene.29 Since the contact angle of water on bituminous sandstone was above 100°, one would have expected to see negative capillary pressure and no imbibition at all take place in the Washburn cell. However, this was not the case (Figures 7 and 9): a small amount of water did get imbibed at a very low rate. The penetration of water into a nonwetting capillary is in general possible provided that a suitable ratio of droplet size to the capillary radius can be reached under the nonwetting conditions.30 There is also a possibility that crushing bituminous sandstone produced a small amount of hydrophilic quartz grains that were wetted by water. Indeed, close examination of oily sandstone images revealed that not all of the grains were covered by bitumen. While hydrophilic surfaces may not be present in the oil-wet reservoir initially, they may be generated in the course of hydraulic fracturing. Similarly to the case with other rocks, at low concentrations the impact of surfactant on the imbibition rate was minimal and overall indistinguishable from that of pure water. However, at concentrations exceeding 3 gpt, a significant increase in the penetration height of a solution was observed. This behavior can be attributed to the change of the rock surface from water nonwet to water-wet. The change in the value of hini seen in Figure 8 indicates that the wetting boundary between water-wet and nonwet regions moved upward with increasing surfactant concentration. Similarly to other cases, the inflection point at which the slope of the uptake curves changes most likely corresponds to the height at which the surfactant concentration at the meniscus dropped below the cmc. Once micelles disintegrated due to the adsorption of surfactant molecules at the rock surface, the concentration of surfactant in the meniscus region became lower and the rate of penetration slowed down. At the highest surfactant concentration of 50 gpt, the fluid uptake profile became similar to that observed for Berea sandstone. However, the overall uptake rate remained low and was comparable to that observed with oily dolostone and Fayetteville shale (Figure 9). This suggests that, even in the case of reversibility of rock surface wetting, fluid imbibition was controlled by surfactant diffusion to the solid surface, rather than by the propagation of a water film on a hydrophilic surface. One significant finding of the present study is that very high concentrations of surfactants were necessary to overcome the impact of adsorption and to experimentally observe changes in the liquid uptake caused by them. These concentrations were up to 2 orders of magnitude above the concentrations at which surfactants are typically added to fracturing fluids. These results indicate that the loss of surfactant from a solution due to adsorption can significantly impair the ability to differentiate the imbibition of surfactant solutions from the imbibition of brines and should not be disregarded in conducting screening tests aimed at selecting proper surfactant treatments for a given

reservoir. In this respect, the studies carried out with a Washburn technique allow one to take into account the effect of surface area of the porous media, which is limited in the goniometric contact angle measurements or core imbibition studies involving very small liquid volumes.8,9,12 It is worth pointing out that using very high surfactant concentrations in the laboratory screening of fracturing fluid additives may be a good way to simulate the situation in the near-wellbore zone. When fracturing fluid is pumped into the reservoir, the portions of reservoir close to the injection points are exposed to multiple pore volumes of a flowing surfactant solution which would gradually saturate the rock surface with surfactant, while more distant portions of reservoir are exposed to fluid that had already lost surfactant due to adsorption.

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CONCLUSIONS It has been shown that, at low concentrations the imbibition rate of solutions of a model nonionic surfactant into crushed reservoir rocks well correlated with the nondispersion component of surface free energy, once the slopes of imbibition curves were normalized over the corresponding slopes determined for a completely wetting fluid (HMDS). Such normalization allowed one to account for the differences in the morphology of crushed rock powders. The observed trends in the imbibition into beds packed with crushed rocks were qualitatively similar to the trends reported previously for the rise of surfactant solutions in single capillaries. The findings of these previous studies could be used to explain the observed behavior. The largest qualitative impact of nonionic surfactant was observed in the imbibition into hydrophobic oily sandstone. A surfactant-induced change in the rock polarity was observed in this case. A significant and surprising finding of the present study was the magnitude of the impact of surfactant adsorption on the imbibition rate: very high concentrations of surfactants were necessary to overcome the impact of adsorption and to experimentally observe changes in the liquid uptake caused by them. In order to observe the essential phenomena, the experimental work included surfactant concentrations that were several orders of magnitude above the levels typically used in the petroleum industry.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: azelenev@flotekind.com. ORCID

Andrei S. Zelenev: 0000-0002-1730-9798 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors are indebted to Flotek Industries for allowing us to conduct and publish this work. The authors also would like to thank their colleagues Dr. James Silas, Dr. Keith Dismuke, Dr. Randal Hill, Dr. Siwar Trabelsi, and Dr. Carl Aften for useful discussions. The help of Dr. Phillip Sullivan and Mrs. Nicole Mast in measuring viscosities is also kindly appreciated.

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DOI: 10.1021/acs.energyfuels.7b03345 Energy Fuels XXXX, XXX, XXX−XXX