Roles of surfactants during soaking and post leak-off production

Aug 6, 2019 - ... leak-off production stages of hydraulic fracturing operation in tight ... Many experimental studies have been conducted in the recen...
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Roles of Surfactants during Soaking and Post Leak-Off Production Stages of Hydraulic Fracturing Operation in Tight Oil-Wet Rocks Srikanth Tangirala and James J. Sheng*

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Department of Petroleum Engineering, Texas Tech University, Lubbock, Texas 79409, United States ABSTRACT: Many experimental studies have been conducted in the recent past to assess the inclusion of different types of surfactant in a frac fluid in hydraulic fracturing of low-permeable formations. These lab studies either corresponded to spontaneous imbibition testing using Amott cells or dynamic core-flooding tests to assess the hydrocarbon permeability after the invasion of the frac fluid. Both these tests have been considered independently by different authors but have not been analyzed as one holistic approach to assess the oil recovery potential of a surfactant. It is prudent to understand the superiority of the specific interfacial mechanism of the surfactant that correlates to the best-case scenario of oil recovery by considering both the tests that lead to leak-off and follow the leak-off of frac fluid into the matrix. In this experimental study, two tests related to soaking and production processes are conducted simultaneously using surfactants with different interfacial properties of interfacial tension (IFT) reduction and wettability alteration for both low-permeable and high permeable core samples. The oil recovery from soaking tests are compared to the oil productivity of dynamic production tests assessed from the calculated parameters of effective permeability of oil recovered and flowback efficiencies. The results obtained in this study indicate that the surfactant which simultaneously reduces the IFT and alters the wettability of the low-permeable rock from oil-wet to waterwet is not conducive for oil productivity during dynamic production process despite it being very effective in oil recovery during the soaking process. Rather, a neutral-wetting surfactant seems to produce optimal results when the whole process of oil recovery from hydraulic fracturing is considered. The trend in the results for flowback efficiency and effective permeability of oil post leak-off observed in this study across the high and low-permeable rocks could be extended to unconventional shale rocks to safely infer that with regards to oil productivity, it would be beneficial to avoid any leak-off of the surfactant fluid, which showcases both IFT reduction and wettability alteration. The insights provided in this study motivate the reader to analyze beyond the common experimental methods of static imbibition testing in labs to embrace the methods that consider a complete hydraulic fracturing process for assessing enhanced oil recovery of low-permeable formations.

1. INTRODUCTION Hydraulic fracturing is a completion technique used for horizontal wells especially in shale and tight plays that led to an increased rate of U.S. hydrocarbon production in recent years. It is specifically evident from the fact that these shale and tight plays have accounted for 60% of U.S. total crude oil production in Dec 2018 against that of 12% in Dec 2008.1 In 2016, hydraulically fractured horizontal wells constituted 69% of all oil and natural gas wells drilled in the United States alone.2 Despite the proliferation of the technique’s application, the benefits are not long lasting as observed in the production trends of unconventional wells.3 The production decline behavior of fractured wells is very steep, and it can be attributed to the crippled matrix-dominated flow caused by the leak-off of fracture fluid into the matrix during the hydraulic fracturing operation.4 Therefore, there is a requirement to understand the merits and demerits of oil recovery techniques leading to leak-off as well as those following the leak-off of fracture fluid into the matrix. There have been many experimental studies in the past that showcased the oil recovery potential of surfactants using soaking of core samples or static imbibition techniques in the lab. For the case of conventional oil-wet rocks with millidarcy permeabilities, authors like Austad et al.,5 Chen et al.,6 Babadagli,7 Hirasaki and Zhang,8 Adibhatla and Mohanty,9 Salehi et al.,10 Delshad et al.,11 Chen and Mohanty12 have showcased that the spontaneous imbibition of surfactants, © XXXX American Chemical Society

which have the property of combined wettability alteration and interfacial tension (IFT) reduction, produced very high oil recovery factors from the soaked core samples due to the synergy of initial-time counter-current capillary driving force and the late-time co-current gravitational driving force. Even the static imbibition studies of oil recovery from tight oil-wet rocks of the Bakken region having microdarcy permeabilities, produced similar results as above.13−16 For the case of rocks with much tighter pore spaces having permeabilities in the range of nanodarcy like shales from Permian basin, Alvarez and Schechter17,18 have studied that it is prominent to use a wettability-altering surfactant that reduces the IFT to a moderate value for an efficient oil recovery. This is to ensure an initial diffusion of the surfactant into the pore space due to an IFT gradient which then sparks the wettability alteration mechanism by micellar solubilization to strip the oil from the rock surface producing substantial oil recovery from shales. Concurrently, Neog and Schechter19 have studied wolfcamp shale rocks and concluded that more is the wettability alteration along with IFT reduction, more is the oil recovery by spontaneous imbibition. Above studies exhibited the oil recovery from only a part of the hydraulic fracturing operation, Received: June 12, 2019 Revised: July 29, 2019 Published: August 6, 2019 A

DOI: 10.1021/acs.energyfuels.9b01913 Energy Fuels XXXX, XXX, XXX−XXX

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times, even though the end-point relative permeability of oil for water-wet rock at pore scale is higher than that of oil-wet rock, the presence of water block in water-wet rock creates an additional relative permeability impairment factor, thereby leading to lesser regained permeability (k′) for water-wet rock than oil-wet rock, but during late-time steady-state condition, the water-block migration in water-wet rock improves the effective permeability of oil to leverage its performance against the oil-wet rock. From these studies, it could be theorized that if a surfactant that reduces IFT moderately is used, then for a water-wet rock, the water-block removal would be slow due to the reduced capillary driving force for its movement, but for an oil-wet rock, the characteristic of relative permeability of oil could be improved. This contrast in the behavior helps us to frame a motive for research with regards to the oil productivity to understand the implications of invasion of an IFT reducing surfactant only against a combined IFT reducing and wettability-altering surfactant into an oil-wet rock. Especially, the need to understand the behavior of oil productivity after the invasion of the surfactant into a low-permeable tight formation is paramount. In our previous research studies on the conventional oil-wet35,36 and water-wet surfaces,37 we demonstrated experimentally that at substantially deep invasions, the surfactant, which reduces the IFT moderately, performs better in mitigating the invasion-induced formation damage than the fluid without any surfactant. But due to the limitations in the application of the methodology, we could not then study the wettability-altering properties of the surfactant and their impact on the lesser conductive porous materials. Based on the aforementioned motives, two experiments are planned to be conducted in the present work, with each experiment incorporating variations in rock permeability from conventional to tight rock and involving three different types of fluids, which give different properties related to surface phenomena. The first experiment elucidates the oil recovery from rocks during the soaking stage of the hydraulic fracturing process leading to a leak-off of the fracture fluid into the matrix. The second experiment studies the oil productivity behavior during the production stage of the hydraulic fracturing process that succeeds the process of invasion of the fracture fluid into the matrix. The results from these two experiments combined could be analyzed to better understand the applicability of a suitable category of the surfactant that enhances the oil recovery from an overall process of the hydraulic fracturing operation.

i.e., soaking phase in the absence of any viscous force of imbibition. A huff-puff type of oil recovery has even been studied recently by Yu and Sheng20 to forcibly inject water into the shale matrix by soaking the core sample in the fluid at high pressures and producing oil by reducing pressure gradually. A similar procedure has been applied by Alvarez et al.,21 to allow for the soaking of the frac fluid but using an axially cleaved shale core. They showed that for a moderate-IFT reducing surfactant, the more the alteration in the wettability, the more the penetration of the surfactant into the matrix and hence the more the recovery of oil by counter-current imbibition into the fractures. All these processes characteristically indicate the oil recovery associated to the invasion of the fracture fluid into the matrix. On the contrary, the invasion of the fracture fluid into the matrix could even lead to the formation damage resulting from proppant materials deposition, clay swelling,22 or even water-block formation due to capillary entrapment of water in the vicinity of the fracture.23−25 One method of assessing the hydrocarbon productivity after aqueous fluid invasion into the matrix is by investigating the evolution of the hydrocarbon’s effective permeability upon the application of a viscous driving force across the core sample. For a gas/water system in a slightly tight water-wet rock with 2−10 mD permeability, Dutta et al.26 and Odumabo et al.27 have shown that the gas productivity is a function of the rate of water-block migration away from the vicinity of the fracture− matrix interface. This rate is dependent upon two opposing driving factors, namely, the capillary drive acting away from the fracture−matrix interface and low pore throat conductivity restricting the movement of the water-block. The controlling parameters constitute the shut-in time after a fixed volume of leak-off and the volume of leak-off, both of which impact the regained permeability caused by water-block migration. Odumabo et al.27 even simulated to show that for a lesser permeable rock, it is undesirable to allow the migration of water into the previously uninvaded zone of the core. This is due to the factor of depressed relative permeability of gas with increased water saturation in tight rocks when compared to that of conventional rocks. Such a simulated result is physically observed by Yan et al.,28 who experimented on tight rocks (2− 18 μD) as well as Chakraborty and Karpyn, 29 who experimented with shales (10−200 nD). These authors even proved that it is detrimental for water to be further imbibed into the shale matrix by capillary redistribution due to the permeability impairment by clay swelling. Ibrahim and NasrEl-Din30 have recently even conducted similar experiments in tight sandstones (0.23 mD) and in Marcellus shales (3.16 nD) to show similar behavior of regained permeability to gas, as discussed above. Similarly, for an oil/water system in a lowpermeable water-wet rock (3−10 mD), the studies performed by Liang and co-workers31−33 have also demonstrated the migration of water-block phenomenon using high-resolution CT-scans. Liang et al.34 even concluded that for the case of an oil-wet rock, the water-block at the fracture−matrix interface does not exist but rather the end-point relative permeability for oil is subdued at the residual saturation of water due to the capillary entrapment of water in the bulk of the pore space and not along the walls of the pore space. From their experimental analysis, they compare the regained permeability (k′) during the production phase between an oil-wet rock and a water-wet rock, which are invaded by the same volume of water and observe that at initial times, k′water‑wet < k′oil‑wet, but at late-times (2.5 PV), the k′water‑wet > k′oil‑wet. It is explained that at initial

2. EXPERIMENTAL METHODOLOGY 2.1. Rock and Fluid Materials Needed. Two types of rock are studied in this work that are cut from the outcrop. A conventional rock, Berea sandstone, cut from the Upper Devonian formation with porosity around 18−20% and a tight rock, Crab Orchard, cut from the Pennsylvanian formation with porosity around 9−11% are utilized in this study. The Fourier transform infrared spectroscopy-based minerology of the above rock samples provided by the supplier, Kocurek Industries is shown in Table 1. The rocks are visually observed to be homogeneous in quality, as marketed to be on the supplier’s website (Figure 1). Dead oil from Wolfcamp shale reservoir is used as oil in the experiments. The specific gravity of crude oil is 0.845, and the dynamic viscosity is 8.5 cp at 72 °F. The Interfacial tension (IFT) between crude oil and water is 25 ± 1.2 mN/m as measured by a DuNuoy ring tensiometer. Since 0.2 wt % (2 gpt) is a common concentration of the surfactant used in the field, 0.2 wt % of the CELB B

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interface of rock-oil-surrounding liquid. This method of measurement is called the captive bubble method and is depicted in Figure 2.

Table 1. Minerology minerology (%) quartz calcite dolomite pyrite kaolinite montmorillonite illite feldspar chlorite TOC content%

Berea sandstone (conventional rock)

Crab Orchard (tight sand)

90.86

92.26

8.46 0.68

7.53 trace trace

Figure 2. Captive bubble method of contact angle measurement for wettability assessment. At least 15 contact angle measurements are taken from multiple regions on the chips to account for the variation in the heterogeneity of the texture. Based on Anderson’s38,39 contact angle classification for wettability of the rock, 0−70° is classified as water-wet rock, 70−105° as the neutral wet rock, and 105−180° as oil-wet rock. The summarized values of IFT and contact angle of rocks are mentioned in Table 2. For both the type of oil-saturated rocks, their interaction with water is termed as base-case, and their interaction with selected nonionic surfactant is termed as IFT reduction case, because the IFT reduces to a moderate value of 0.58 mN/m from 25 mN/m with wettability remaining as oil-wet. Finally, the interaction of rocks with the anionic surfactant is termed as both IFT reduction and wettability alteration case because of a combined moderate reduction in IFT from 25 to 0.68 mN/m as well as a change in wettability from oil-wet to water-wet state. The fluids for each case are designated C1, C2, C3 for conventional rock and T1, T2, T3 for the tight rock. A representation of the contact angle measured for each case is depicted in Figure 3. 2.3. Design of Experiments. Two types of experiments are designed to understand the superiority of a surfactant in enhancing the oil recovery during complete hydraulic fracturing operation involving soaking and even flowback of the fracture fluid. 2.3.1. Experiment 1: Soaking/Static Imbibition Test. Amott cells are used for this experiment operating at atmospheric pressure and temperature conditions where the oil-saturated rock samples are placed inside the cell with the surfactant solution as the surrounding fluid. The surrounding space around the rock resembles the fracture in which the fluid resides allowing for spontaneous imbibition of the surfactant into the matrix. To analogically complement the boundary condition of the core-flooding related experiment 2 (mentioned below), the top and bottom surfaces of the rock in this case are coated with an impervious epoxy material (Figure 4a). This prohibits the oil recovery by co-current gravity drainage allowing mostly for the capillary pressure to dictate the oil recovery mechanism.7,40 The effect of gravity drainage in experiment 2 (core-flooding) is even considered to be negligible due to closed boundary conditions (no-flow) in the direction perpendicular to axial direction besides having very small travel distances in the radial direction for the gravity effect to be substantial. Three oil-saturated rock samples of Berea sandstone and three samples of Crab orchard are placed in the Amott cells filled with the fluids, namely, C1−C3 and T1−T3, respectively (Figure 4b). 2.3.2. Experiment 2: Flowback and Post-Invasion Oil Production. The objective of experiment 2 is to understand the significance of the role played by a surfactant that exhibits characteristics of changing surface phenomena like IFT reduction and wettability alteration, in restricting the flow to hydrocarbon during production phase that is caused by the surfactant’s matrix invasion. Both the conventional and

Figure 1. (a) Conventional rock: Berea sandstone (b) Tight rock: Crab orchard. 217-123-8 nonionic surfactant (supplied by ChemEOR Inc.,) and 0.2 wt % of the Petrostep S-2 anionic surfactant (supplied by Stepan) are used in this study. Deionized water is used to dilute the surfactants to the required concentration. The interfacial tensions of these above fluids with the crude oil are 0.58 ± 0.06 and 0.68 ± 0.04 mN/m, respectively, as measured using a spinning drop tensiometer (M6500 model, purchased from Grace Instrument Company). It should be noted that only those chemicals, which restrict the IFT measurement to moderately low values, such as above, are only used, and the chemicals that give ultralow IFT values are not studied in this work. This is because the ultralow IFT chemicals mostly need optimum salinity conditions, and maintaining such conditions downhole amidst various other added chemicals could be difficult. Hence, for the ease of practicality, the results in this paper are generalized only for moderate-IFT reducing chemicals and not for ultralow IFT chemicals. 2.2. Initial Procedures. The preliminary tests performed before conducting experiments are described below. 2.2.1. Oil Saturation. Both the weighted conventional and tight core samples (dry weight = Wdry gms) are measured for their effective porosities using a helium porosimeter before being vacuum-saturated in a pressurized core vessel for initial oil saturation. These rocks placed in the vessel are vacuumed for 1 day, and, subsequently, crude oil is pumped and maintained in the vessel at 3000 psi for a week. After gradually depressurizing the vessel, the rocks are left soaked in the oil for another week. This ensures relevant aging of the cores to render them an initial oil-wet condition. The oil-saturated cores are weighted again (Wo), from which the degree of initial oil saturation is computed (Soi). 2.2.2. Wettability Assessment. The contact angle method is used in this study to analyze the wettability of the rocks. Small chips are cut from the oil-saturated core samples, which are then placed for 1 day in the flasks filled with the three fluids: deionized water, 0.2 wt % nonionic and 0.2 wt % anionic surfactant. This resting period allows for the surrounding fluid to alter the surface wettability of the chips, if possible. These chips are then placed on a sample holder inside a square glass container, which is filled with the aqueous fluid, and a crude oil droplet is dispensed from the u-shaped needle placed underneath the sample holder to measure the contact angle across the C

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Energy & Fuels Table 2. Interfacial Tension (IFT) and Wettability Measurements aqueous fluid DI water nonionic surfactant anionic surfactant DI water nonionic surfactant anionic surfactant

concentration (wt %)

IFT with oil (mN/m)

0.2

25 ± 1.2 0.58 ± 0.06

0.2

0.68 ± 0.04

0.2

25 ± 1.2 0.58 ± 0.06

0.2

0.68 ± 0.04

rock used

contact angle (°) 120.78 ± 17.79 145.62 ± 6.12

conventional Berea sandstone

41.76 ± 10.45 tight sandstoneCrab Orchard

112.81 ± 11.14 144.23 ± 10.48 44.05 ± 6.68

primary function of fluid

designated name for the fluid

base case IFT reduction

C1 C2

IFT reduction and wettability alteration base case IFT reduction

C3

IFT reduction and wettability alteration

T1 T2 T3

Figure 3. Top row pictures represent the contact angle of berea sandstone rocks between oil and (a) water, C1, (b) nonionic surfactant, C2, (c) anionic surfactant, C3. Bottom row pictures represent contact angle of crab orchard rocks between oil and (d) water, T1, (e) nonionic surfactant, T2, (f) anionic surfactant, T3. tight rocks are examined in this experimental setup to study the contrast in the production behavior due to reducing pore throat sizes. The schematic of the experimental setup is presented in Figure 5. The oil-saturated core is wound by the Teflon tape only on the curved surfaces to form a noninvasive seal to the rubber sleeve in which the core is held. The rubber sleeve is then placed inside the hassler core holder that is enclosed on both the sides by metal caps, which have engraved grooves to uniformly distribute the fluid across the crosssectional area of the core. A confining pressure of 1000 psi is applied over the core, subsequent to which the respective fluid is passed across the core axially from either side A or B of the core holder. Experiment 2 is operated in three different stages: Stage 1: Permeability assessment: The crude oil is injected at constant ΔP from side A of the core holder, and the effluent from side B is collected in a flask that is weighed continuously with time. This exercise is continued till the steady state is reached when the constant oil flow rate (qo1) is assessed from the differential increments in the collected weight of oil. Darcy’s equation is used to compute the effective permeability of the oil. Stage 2: Invasion: A 0.25 PV of the respective aqueous fluid is invaded into the rock sample from side B of the core holder at a very small pressure drop to prevent any viscous fingering of fluid caused by an unfavorable mobility ratio (M = 0.12). The weight of the core after the invasion (Winv) is also measured to evaluate the accuracy of the invaded volume by removing the core from the holder.

invasion % =

(Winv − Wo) × 100 Δρ × Vp × Soi

Stage 3: Flowback and Production: The fluid-invaded core is placed back in the core holder and oil is injected from side A of the holder at same constant ΔP as in stage 1 to represent the production stage of hydrocarbon. The effluent is collected in a flask and is continuously weighed on a scale. After at least 36 h of production for a tight rock case or 10 PV of production in a conventional rock case, a steady state is observed to be achieved where a constant increment in cumulative effluent weight collected is observed. The flow rate (qo2), thus, assessed from the differential of effluent weight with time can be estimated as the final steady-state flow rate of oil production after flowback of the fluid. The final weight of the core (Wflb) is measured again to assess the residual amounts of invaded fluid after flowback. The degree of effective oil permeability recovered post flowback (R) is a ratio between qo2 and qo1, which is calculated further to analyze the final impact of combined invasion into the matrix and flowback of the invaded solution from the matrix. R=

qo2 qo1

Flowback efficiency (Flb %) is also evaluated based on the weight difference ratios as follows D

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water-block in tight rocks and not in conventional rocks. Miscellaneously, this low and same pressure drop is applied across both high and low permeability rocks to facilitate the comparison of measured production parameters. The selection of the value of pressure drop (ΔP) across both the type of cores is limited by the relation for Rapoport−Leas number (ΔP/Pc) provided by Liang et al.31 Based on their study, they stated that under the conditional range of ΔP/Pc < 10, the water-block is formed across the interface of the matrix and the fracture that leads to a reduction in the effective permeability of hydrocarbon during the production stage. Therefore, conservatively choosing the underlying condition of ΔP/Pc =5, a semiempirical and iterative-explicit method of estimation of capillary pressure from permeability is employed to select the operating pressure drop. For this approach, an initial representative capillary pressure of 10 psi at median pore throat radius is chosen for crab orchard rocks based on the rock supplier’s marketed permeability data and empirical knowledge. This estimated value provides an operating ΔP of 50 psi for initial iteration pertaining to the underlying condition, as explained previously. Following the procedures mentioned in stage 1 above, a corresponding effective permeability of oil of 121.2 μD is obtained after performing the steady-state flow experiment. Based on this value, a representative capillary pressure of 14 psi at median pore throat radius is calculated using an average of values from equation (1) of Gdanski’s paper24 and equation (5) of Gao-Hu’s paper.41 Derivatively, this iterative approach provides a final selection for the operating pressure drop of ΔP = 70 psi that is chosen to be applied across all of the rocks for stage 3 of experiment 2.

3. RESULTS AND DISCUSSION 3.1. Experiment 1: Soaking/Static Imbibition Test. The tight Crab orchard core samples and conventional Berea sandstone core samples are evaluated for their helium porosities and, subsequently, oil-saturated according to the procedures already discussed in the initial procedures Section 2.2 above. These cores are then placed for 2 weeks in the respective fluid-filled Amott cells for soaking. A time frame of 2 weeks is chosen based on the general time frame frac-operators take to complete the well for production after hydraulic fracturing during which time the frac fluid soaks in the fractures adjacent to the rock matrix. The details of the setup are presented in Table 3. All of the mechanisms related to oil recovery from the soaking process in this experiment are counter-current capillary forces acting on all of the surfaces, co-current buoyant forces acting in a vertical direction, external hydrostatic head of the fluid in the Amott cell exerting pressure for intrusion, concentration gradient across fluid interface leading to

Figure 4. (a) Epoxy coating depiction on the top surface of the core. (b) Conventional and tight cores placed inside the Amott cells. Flb% =

Winv − Wflb × 100 Winv − Wo

It is to be noted that one of the motives of this experiment is to highlight the contrasting effect of high capillarity in tight rocks as compared to the conventional rocks when production behavior after leak-off is studied. Since capillary pressures are high in tight rocks than conventional rocks, the impact of the presence of water-block across the matrix−fracture interface is relatively more crucial to study in tight rocks. This distinguishing property limits us to design the laboratory operating pressure drop to be low enough to observe the effect of

Figure 5. Schematic of setup for experiment 2. E

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Energy & Fuels Table 3. Core Sample Characteristics Used in Experiment 1 rock type Crab Orchard

Berea sandstone

rock name

L (cm)

D (cm)

φ (%)

Wdry (g)

Wo (g)

Soi (%)

chemical soaked in

CO-5(2) CO-6(1) CO-5(1) BS-3 BS-2 BS-4

2.33 2.43 2.39 2.62 3.84 3.82

3.8 3.79 3.79 3.86 3.86 3.85

11.29 11.47 11.29 18.91 18.72 18.47

61.537 64.093 63.548 65.481 95.865 95.230

63.915 66.567 65.988 70.108 102.632 101.879

94.36 92.80 94.89 94.47 95.32 95.70

T1 T2 T3 C1 C2 C3

diffusion and surface tension gradient also called as the Marangoni effect.5 As discussed previously, the boundary conditions in this experiment need to be similar to those in experiment 2, and, therefore, an epoxy coating is used to seal off the top and bottom surfaces to prevent any buoyancyrelated extraction of oil. The inverse bond number (NB−1), as calculated based on Schechter et al.,42 also gave high values greater than 5 for each of the case in Table 3, indicating the dominance of capillary forces over the buoyant forces in oil recovery. The nonexistence of buoyancy-driven oil recovery (due to the density difference) can be seen in Figure 6, where

Figure 6. Oil droplets appearing only on sides and not on the top surface.

the oil droplets are seen only on sides and not on the top surface of the rock sample. The volume of oil recovered from each core sample is recorded on a day-to-day basis for the period of 2 weeks. The images of the net volume recovered from Amott cells are shown in Figure 7, and the continuous monitoring of the oil recovery factor from each core sample is depicted in Figure 8. The tight rock’s oil recovery factors are less than 30% in 14 days, whereas the conventional rock’s recovery factors range as high as around 45%. This is due to the reduction in the viscous mobility of fluids within the tight pore spaces of low permeability rocks. Conclusively from Figure 8, the highest oil recovery factor is attained in the case of T3 for the tight rock and C3 for the conventional rock, indicating that the effect of wettability alteration and IFT reduction is the bestcase scenario of oil recovery here during soaking operation of hydraulic fracturing. This could be attributed to the positive capillary pressure attained from the wettability alteration of the rock to water-wet by the anionic surfactant, whose entry into the matrix is assisted by both the IFT reduction and external hydrostatic head in the Amott cell. The nonionic surfactant retains both the rocks as oil-wet, but the slow and eventual low recovery observed is due to the IFT reducing effect on the fluid

Figure 7. (a) Oil recovery from tight rocks soaked in fluids T1, T2, T3. (b) Oil recovery from conventional rocks soaked in fluids C1, C2, C3.

interface leading to an IFT gradient driven oil recovery. Since water makes both the rocks attain a near-oil-wet to intermediate wet condition without reducing IFT, the oil recovery is observed to be driven by capillary pressure but not as prominent as seen in the case of completely water-wetting fluid as the anionic surfactant. The final summarized oil recovery factors from soaking operation after around 14 days for both the cases of lowpermeable and high permeable rocks are plotted in Figure 9 below and is indicative of the fact that a combined wettabilityaltering and IFT reducing surfactant fares better than either of IFT reducing surfactant only or fluid without the surfactant. But this covers only half the scope of net oil recovery as seen with respect to complete process of production from hydraulic fractures. The negative aspect of the soaking process is the invasion of the surfactant into the matrix that affects the production capacity of the reservoir. Hence, the results from experiment 2 are very relevant to understand the true potential F

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stages 1, 2 of the experiment are presented in Table 4. Based on the results, the effective permeabilities of oil that are calculated from Darcy’s equation are in the range of 130−190 μD for the tight rocks and 5−50 mD for conventional rocks. Stage 3 of the experiment involves flowback and oil production phase after the invasion of the fracture fluid into the matrix. Since the applied pressure drop ΔP = 70 psi is too low to measure the flow rate of effluent directly, the weight of the effluent is collected and measured using a weighing scale. The cumulative volume of effluent (Q_liq) is obtained by dividing the weights with the density of oil. This might lead to an error in the absolute value of the rate measurement during initial unsteady-state flow condition, but once the steady state is established, it is safe to assume that the flow is only due to oil with the core reaching to the state of irreducible saturation of the invaded fluid. Therefore, for the purpose of our analysis, a qualitative validity for the flow rate of oil production during initial times and a quantitative validity during the late steadystate period could be adjudged. For the case of low-permeable or tight rocks, the production is studied only for 36 h during which time the pore volumes of production vary from around 1 to 4 PV across the chosen cores, but for the case of conventional rocks, since the flow rate of production is considerably high, the constraint for the end of the experiment is taken to be 10 PV rather than the fixed time period of production. The performance of all three types of fluid cases for both tight and conventional rocks is depicted in the graphs shown in Figures 10 and 11, respectively. A semilogarithmic plot is presented in these figures for each case to highlight the occurrence of the breakthrough of oil, which is depicted by a sudden jump in the slope of the curve during the initial period and is marked on the graphs of Figure 10 as BT (breakthrough time). In the case of tight rocks, Figure 10a−c shows a clear contrast in the depiction of the period before the breakthrough and after the breakthrough of oil. This period is seen at around 5 h, 10 h, and 4.5 h for the three cores that are invaded with T1, T2, and T3 fluids, respectively. These values complement the absolute permeability differences exhibited by the cores among themselves. After 36 h of production, a clear and linear steady-state trend is seen indicating a constant and improved flow rate of effluent, which can be approximated as being purely oil production. The flow rates measured from the slope of graphs in Figure 10 are compiled in Table 5 along with the effective oil permeability recovery ratios (R). These calculated ratios indicate that the fluid T1, which renders the rock less oilwet to intermediate wet, is the best fluid to be invaded, whereas the fluid T3, which alters the wettability to water-wet and reduces the IFT between the fluids, is the least efficient fluid to be invaded into the rock. This observation can be

Figure 8. Oil recovery from the soaking process of experiment 1 for (a) tight rocks, (b) conventional rocks.

Figure 9. Summarized final oil recovery factor chart for experiment 1.

of a surfactant as the fracture fluid in recovering oil effectively from hydraulic fractured rocks. 3.2. Experiment 2: Flowback and Post-Invasion Oil Production. The volumes of invasion of frac fluid into all of the core samples for this experiment are kept the same at around 0.25 PV with a small variation due to the experimental error, so that the final computed oil permeability recovery ratio (R) and flowback efficiencies could be compared against each other’s performance with reasonable rationality. The initial saturation characteristics of the core samples and results from

Table 4. Core Sample Characteristics during Stage 1 and Stage 2 for Experiment 2 stage 1 rock type Crab Orchard

Berea Sandstone

rock name

L (cm)

D (cm)

Φ (%)

CO-1 CO-2 CO-3 BS-6 BS-7 BS-8

5.07 5.07 5.07 5.06 5.07 5.07

3.8 3.8 3.8 3.9 3.9 3.9

10.17 9.93 10.93 17.30 18.22 18.34

dry wt (g) 136.54 137.00 135.79 128.77 130.03 130.14

oil satd wt (g) 141.29 141.55 140.62 137.18 138.62 138.90 G

stage 2

Soi (%)

qo1 (cc/min)

ko (md)

fluid injected

Winv (g)

inv (PV %)

96.02 94.13 91.13 96.49 93.78 95.36

0.0136 0.0101 0.0137 1.9687 0.4586 3.8198

0.181 0.134 0.183 25.13 5.878 49.26

T1 T2 T3 C1 C2 C3

141.55 141.83 140.97 137.73 139.10 139.39

23.02 26.17 24.68 27.12 22.74 23.09

DOI: 10.1021/acs.energyfuels.9b01913 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels

Figure 11. Experiment 2 results for effluent characteristics from 3 different conventional rocks which are invaded by (a) C1 (b) C2 and (c) C3 designated fluids. All the graphs have primary y-axis as cumulative effluent volume collected, Q_liq in logarithmic scale and secondary y-axis as pore volumes in cartesian scale.

Figure 10. Experiment 2 results for effluent characteristics from 3 different tight rocks, which are invaded by (a) T1, (b) T2, and (c) T3 designated fluids. All of the graphs have primary y-axis as cumulative effluent volume collected, Q_liq in logarithmic scale, and secondary yaxis as pore volumes in cartesian scale.

ment in the permeability of oil due to the redistribution is compensated by the depression in relative permeability of oil due to the expansion of the fluid-invaded region inside the core, as similarly seen by Odumabo et al.27 for a gas−water system. Equivalent to the case of tight rocks, conventional rocks are also invaded with the relevant fluids, and the production behavior is analyzed in Figure 11. The constant pressure drop used is the same as in the previous case, i.e., ΔP = 70 psi, which would result in higher steady-state flow rates. Due to such high-pressure drop, any existence of water-block is not expected in conventional rocks during production. The primary purpose of using such conventional rocks in this experiment is to show the contrast in the behavior of effluent flow rate when compared to that using low-permeable rocks under similar operating conditions. Figure 11a−c represents the effluent flow characteristics for the case of conventional rock when using the three chosen fluids for invasion, i.e., C1, C2, and C3. The experimentation times range to less than 4 h corresponding to 10 PV of production when already a steady state is observed to be reached. Semilog plots do not reveal any sudden change in the flow rates as seen in the case of tight rocks after breakthrough. This could be either due to the high flow rates seen that minimizes the time for breakthrough and is undetected in Figure 11, or that the effective permeability of oil does not change drastically at any instant due to high flow rates. The stabilized flow rates after 10 PV are computed from the slopes

explained based on the changed capillary forces in the case of fluid T3, which increase the affinity of the invaded fluid to adhere to the small pore spaces inside the rock and hence reduce the effective permeability of oil due to higher irreducible invaded phase saturations. Fluid T1 does not show such strong affinity to the rock surface and, hence, does not cause much reduction in the effective permeability of oil during production. This analysis could also be extended to the observation of trends in the flowback efficiency, as seen in Table 5, where flowback efficiency is seen to be high for the case with fluid T1 compared to the case with fluid T3. Simultaneously, fluid T2 renders the rock more oil-wet, which can reduce the relative permeability of oil compared to the intermediate wet case at same saturations, and, hence, this could result in the smaller value of R compared to the case with fluid T1. The flowback efficiency for the case of T2 is seen to be similar to that of T1 but much higher than T3. This shows the negative impact of wettability alteration on the oil production in tight rocks. Many researchers have recently indicated that at very low flow rates of production, the invaded fluid redistribution away from the fracture face can lead to an improved effective oil permeability in the case of initial-waterwet rock. This behavior could not be detected in our case for a wettability-altering fluid, T3 even with a high residing time of fluid (approx. 15−20 h) inside the cores before stage 3 commencement. It could be either because of small improvements in the flow rate, which could not have been detected with the proposed experimental setup, or that the improveH

DOI: 10.1021/acs.energyfuels.9b01913 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels Table 5. Results from Experiment 2 rock type Crab Orchard (tight)

Berea sandstone (conventional)

rock name

chemical used

qo2 (cc/min)

CO-1 CO-2 CO-3 BS-6 BS-7 BS-8

T1 T2 T3 C1 C2 C3

0.0130 0.0041 0.0047 1.9455 0.3675 2.1338

Nca 6.4 8.8 7.9 5.4 4.2 2.1

× × × × × ×

R-ratio, % (R = qo2/qo1)

Wflb (g)

flowback (%)

95.58 40.14 34.49 98.82 80.14 55.86

141.36 141.65 140.87 137.28 138.73 139.05

71.67 62.08 34.99 82.41 78.24 70.03

10−7 10−6 10−6 10−5 10−4 10−3

lowest values for each parameter. In Figure 13, the contrast in the values of flowback efficiency for a conventional rock may not be as high as that seen in the tight rocks due to the higher capillary numbers in the range of 10−5 to 10−3 for conventional rocks leading to better capillary desaturation of the invaded fluid phase. But the negative impact of wettability alteration is distinctly seen in the values of permeability recovery ratio, R, in Figure 12. Qualitatively comparing Figure 9 with Figure 12, it can be observed that the presence of an IFT reducing and wettabilityaltering surfactant only provides best results for oil productivity during the soaking test (experiment 1) but not for the production tests after the invasion (experiment 2). The results from these two experiments are summarized in Table 6. Miscellaneously, these obtained results also translate to the analogy that the smaller amount of invaded phase trapped in the center of the oil-wet pore space is less detrimental to the effective permeability of oil than the larger amount of invaded phase trapped along the walls of the pore space for both the conventional and tight rock framework.

of graphs in Figure 11 and are compiled along with their permeability recovery ratios, R, and flowback efficiencies in Table 5. For the ease of visual analysis, bar charts for the parameters under observation are plotted for both tight and conventional rocks in Figures 12 and 13. The trends in the values of

Figure 12. Ratio-R (%) from experiment 2 for all invaded fluids used in the case of tight and conventional rocks.

4. CONCLUSION AND REMARKS The intent of this study is to obliterate the misunderstanding of the conventional wisdom that a wettability-altering with moderately IFT reducing surfactant is often the best surfactant to be used in the frac fluid in recovering oil from the matrix, albeit in the absence of ultralow IFT reducing surfactant. Soaking related oil recovery only justifies a part of the oil recovery process, but it does not provide a compelling solution to the effectiveness of the surfactant. Evidently, the invasion of the frac fluid due to soaking during the operation downtime or surface rig recompletion time can lead to the reduction in the effective permeability of oil during the production phase. The repercussions of the invasion are very much crucial for a broader understanding of oil recovery. The results from this study indicate that for any of the case of high permeability conventional rock and low permeability tight rock, the trend of the static imbibition test results does not match with that of the trend of dynamic production testing results after the invasion. This shows that the operator should

Figure 13. Flowback efficiency (%) from experiment 2 for all invaded fluids used in the case of tight and conventional rocks.

permeability recovery ratio (R) and flowback efficiency are observed to be similar for both rocks with fluid C1, i.e., basecase (water) producing the best-case scenario, and fluid C3, i.e., IFT reducing with wettability-altering surfactant producing Table 6. Summary of Experiment 1 and Experiment 2 Results

experiment 1 (soaking test) rock type Crab Orchard (tight)

Berea sandstone (conventional)

experiment 2 (production test)

chemical used

primary function of fluid

oil recovery (%)

R-ratio, % (R = qo2/qo1)

flowback (%)

T1 T2 T3 C1 C2 C3

base case IFT reduction IFT reduction and wettability alteration base case IFT reduction IFT reduction and wettability alteration

14.22 23.91 27.55 36.56 17.48 43.21

95.58 40.14 34.49 98.82 80.14 55.86

71.67 62.08 34.99 82.41 78.24 70.03

I

DOI: 10.1021/acs.energyfuels.9b01913 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels be extremely cautious in selecting the necessary frac fluid constituents besides choosing right operating conditions, which influence the invasion volumes of the frac fluid, bottom hole pressures applied, to name a few. The economics of the operation dictate many of the above factors at a macrolevel understanding, but it is very essential to take a wise decision based on microlevel technicalities by simulating the oil recovery process from hydraulic fracture operation as a whole in either lab or PC-based environment and not just performing soaking-based spontaneous imbibition tests in the lab, as has been done conventionally. Miscellaneously, the conclusions of this study can be applicable even to a much tighter rock-like shales. From the review of literature, it is well understood that only a wettabilityaltering fluid with an IFT reducing surfactant can provide the best-case results for oil recovery from soaking tests for such rocks due to a combined capillary and gravity drainage drive. But as could be seen in the trend of ratio-R (Figure 12) across permeability for this surfactant in this present study, more the tightness of the rock, less is the effective permeability recovery ratio of oil during the production stage after the invasion. A similar inference could be constructed from the trend of flowback efficiencies across permeability for such surfactant, as seen in Figure 13. Applicably, in a shale environment with nanodarcy permeability, any amount of invasion of wettabilityaltering surfactant fluid could be detrimental to the oil production, due to an expected value of extremely low flowback efficiency of the invaded fluid. Perhaps, based on the results from combined experiments, a base-case fluid, i.e., an intermediate wetting fluid, could be more efficient to be applied in the hydraulic fracturing process. In summary, a surfactant, which performs better in a test leading to leak-off (invasion), might not produce the optimal results for a flow test following the leak-off operation. The results of this paper assert the necessity to perform laboratory tests with combined invasion and flowback of the fracture fluid to assess the true potential of the fluid in estimating the ultimate oil recovery from the hydraulic fracturing process.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Tel.: +18068348477. ORCID

Srikanth Tangirala: 0000-0002-9182-953X James J. Sheng: 0000-0002-1778-1486 Notes

The authors declare no competing financial interest.

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K

DOI: 10.1021/acs.energyfuels.9b01913 Energy Fuels XXXX, XXX, XXX−XXX