Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs

Petroleum Science, Apr 2017

The ability of a novel nonionic CO2-soluble surfactant to propagate foam in porous media was compared with that of a conventional anionic surfactant (aqueous soluble only) through core floods with Berea sandstone cores. Both simultaneous and alternating injections have been tested. The novel foam outperforms the conventional one with respect to faster foam propagation and higher desaturation rate. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, has been tested in the laboratory. Strong foam presented without delay. It is the first time the measured surfactant properties have been used to model foam transport on a field scale to extend our findings with the presence of gravity segregation. Different injection strategies have been tested under both constant rate and pressure constraints. It was showed that novel foam outperforms the conventional one in every scenario with much higher sweep efficiency and injectivity as well as more even pressure redistribution. Also, for this novel foam, it is not necessary that constant pressure injection is better, which has been concluded in previous literature for conventional foam. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, gave the best performance, which could lower the injection and water treatment cost.

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Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs

Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs Guangwei Ren 0 1 Quoc P. Nguyen 0 1 0 Present Address: Total E&P R&T USA , Houston, TX , USA 1 Petroleum and Geosystems Engineering Department, University of Texas at Austin , Austin, TX , USA The ability of a novel nonionic CO2-soluble surfactant to propagate foam in porous media was compared with that of a conventional anionic surfactant (aqueous soluble only) through core floods with Berea sandstone cores. Both simultaneous and alternating injections have been tested. The novel foam outperforms the conventional one with respect to faster foam propagation and higher desaturation rate. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, has been tested in the laboratory. Strong foam presented without delay. It is the first time the measured surfactant properties have been used to model foam transport on a field scale to extend our findings with the presence of gravity segregation. Different injection strategies have been tested under both constant rate and pressure constraints. It was showed that novel foam outperforms the conventional one in every scenario with much higher sweep efficiency and injectivity as well as more even pressure redistribution. Also, for this novel foam, it is not necessary that constant pressure injection is better, which has been concluded in previous literature for conventional foam. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, gave the best performance, which could lower the injection and water treatment cost. Foam; CO2-soluble surfactant; Sweep efficiency; Gravity segregation; Optimal injection strategy - & Guangwei Ren 1 Introduction Gases have been used as driving fluids in improved oil recovery processes since 1900 (Lake 1989), in which CO2 flooding has attracted a lot of attention because of its proven miscible-like displacement (Stalkup 1983), high availability, and environmental concerns. However, this process frequently experiences viscous fingering, gravity override, and gas channeling because of reservoir heterogeneity as well as low density and viscosity of CO2, which results in a decreased oil recovery (Rossen and Renkema 2007). Fortunately, the use of foam can reduce gas mobility and effects of heterogeneity and therefore increase sweep efficiency (Rossen 1995). This was first proposed in 1958 by Bond and Holbrook (1958). Carbon dioxide (CO2) foams in porous media with aqueous soluble surfactants have been widely studied in connection with their application in enhanced oil recovery (EOR) (Lee and Heller 1988; Du et al. 2007). These experimental and theoretical studies have contributed to the success of several field foam applications (Patzek 1996), especially for carbonate reservoirs (Hoefner et al. 1995; Stevens 1995). Unfortunately, field experiences have shown that conventional foams with only aqueous soluble surfactants have some important limitations. For example, the injected surfactant slugs do not improve the CO2-oil contact. Gravity override and macroscopic heterogeneity also challenge the success of surfactant placement into theft zones where the presence of foam is desired. Gravity segregation leads to poor sweep efficiency and has received great attention because of its importance in EOR processes involving gas injection. An analytical model developed by Stone (1982) for gravity segregation of water and gas provided a conceptual framework for understanding gravity segregation without foam. He assumed that gas was incompressible and there were negligible gradients of capillary pressure. After a steady state was established, there were three zones in the reservoir (Fig. 1): a gas zone at the top with gas, a water zone at the bottom with only water, and a mixed zone with both gas and water flowing. Jenkins (1984) extended this study and provided a solution to determine the saturation profile and shapes of three zones. Rossen and van Duijn (2004) showed that the theoretical justifications presented by Stone and Jenkins for their models were incorrect, but they can be derived rigorously with only some assumptions (Rossen et al. 2006; Rossen and Shen 2007; Jamshidnezhad et al. 2008a). Stone’s model may be applied to foam processes that obey the ‘‘fixed limiting capillary pressure’’ (Rossen et al. 1994, 1995b). Therefore, Shi and Rossen (1996) proposed that for foam in a cylindrical reservoir: 2RgHkx Override zone Underride zone Fig. 1 Three zones during gas injection (Rossen and Shen 2007). Because of nonuniform mobility in the foam bank for surfactant solution alternating gas (SAG) and the differences between processes, the criteria for gravity override with co-injection (Shi and Rossen 1996) cannot be simply applied to SAG (Shi et al. 1998). In addition to water flooding, pure gas flooding, water alternating gas (WAG) (Ma and Youngren 1994), and simultaneous WAG (SWAG) (Sanchez 1999), heretofore, some additional injection strategies in the presence of foam can be classified as: Co-injection: simultaneous injection of surfactant solution with gas Most of the laboratory experiments were conducted in this manner (Svorstol et al. 1996; Mohd Shafian et al. 2015), even though it was tried in only few fields (Blaker et al. 1999) since it may lead to fractures due to high back pressure. Chen et al. (2012) and Elhag et al. (2014) demonstrated that apparent viscosities of foams measured with a capillary viscometer were more than 8 cP at variable temperatures and foam qualities with a switchable ethoxylated cationic CO2-philic surfactant. They found that the delivery media of CO2-soluble surfactant imposed less impact. Later, further tests on a 1.2 Darcy glass bead pack and a 49-mD dolomite core gave apparent viscosities of foams as high as 390 and 100 cP, respectively (Chen et al. 2015). Xing et al. (2012) and McLendon et al. (2014) measured the pressure drop across a Berea sandstone core as the CO2/surfactant solution was injected with selected branched ethoxylated CO2-soluble surfactants, which gave a weak foam with a mobility reduction factor around five. Through simulation with an analytical model, Rossen et al. (2006) drew a series of conclusions concerning the optimal injection strategy for co-injection with conventional water-soluble surfactants, regarding longer gravity segregation length. Recently, Zeng et al. (2016) demonstrated a spreading effect caused by different partition coefficients of CO2-soluble surfactants based on published data (Ren et al. 2013) through 1D simulation during co-injection. Surfactants were injected with brine even though they are CO2-soluble. SAG or foam-assisted WAG (FAWAG) WAG with dissolved surfactant (WAGS) Relative to the conventional SAG, WAGS delivers the surfactant in the CO2 phase, which may increase the CO2– oil contact. Le et al. (2008) conducted both SAG and WAGS at the same conditions, which resulted in similar ultimate oil recoveries and pressure drops. Novel CO2 injection: CO2 continuous injection with dissolved CO2-soluble surfactant alcohol or dipropylene tertiary butyl alcohol. The IFT between CO2/brine could reach 1.93 to 4.2 mN/m. The surfactant used here was a new branched nonionic hydrocarbon surfactant with suitable combination of PPO (poly(propylene oxide)) and PEO (poly(ethylene oxide)). The notion of applying a CO2-soluble surfactant during an EOR process to generate C/W mobility control foams was suggested by Bernard and Holm (1967). Soong et al. (2009) probed two strategies for using CO2-soluble compounds to decrease the mobility of scCO2, ‘‘direct thickening’’ of CO2 which is accomplished by a macroemulsion formed by an associated thickener in scCO2, and in situ foam generation. Several laboratory experiments with distinct CO2-soluble surfactants have been conducted with variable injection strategies, which will be reviewed below. Either liquid or CO2 phase could be used to delivery those novel surfactants. A field trial was carried out in west Texas using surfactant injection in the CO2 phase to create a CO2-in-water emulsion or foam to improve vertical conformance and create in-depth mobility control (Sanders et al. 2012). Results indicated a 30% CO2 trapping improvement in situ. In a previous publication (Le et al. 2008), a novel foam concept was proposed and a surfactant concentration of 0.1wt% in CO2 at ambient temperature and 1800 psi was roughly determined. Oil recoveries with variable injection strategies were presented briefly. In our earlier work (Ren et al. 2014), solubility and partition coefficients of a series of nonionic CO2-soluble surfactants have been tested at varying pressures, temperatures, and salinity in our laboratory. Preliminary probes have revealed superiorities of CO2-soluble surfactant foam over conventional aqueous soluble surfactant foam through laboratory core floodings of Silurian dolomite carbonate and field scale simulations (Ren et al. 2013). However, the conclusions drawn previously deserve to be further examined with broader rock types and injection strategies. Moreover, some conclusions from prior literature based on conventional surfactants, such as optimal injection strategy, could be updated or modified in the presence of CO2-soluble surfactants. Through laboratory experiments and field scale simulations, in the current paper, we will peruse the following goals: demonstrate the remarkable advantages of CO2soluble surfactant on the laboratory scale with co-injection, alternating injection, and novel pure CO2 injection with dissolved surfactant; with field scale simulation, exhibit the considerable superiorities of CO2-soluble surfactant over conventional aqueous surfactant through SAG and co-injection with variable perforation interval or slug size; investigate the unique characteristics of the novel CO2 foam, including surfactant delivery media, optimal injection strategy, and some additional considerations; and then, examine whether previous conclusions in the literature for conventional surfactants were still valid for this novel foam with our practical postulations. 2 Experimental section 2.1 Materials A 2-ethylhexanol (2-EH) alkoxylate nonionic hydrocarbon surfactant, which has been used in a previous study (Ren et al. 2013) and named S, and a commercially available anionic surfactant (CD 1045) which is not soluble in CO2, were used in this study. The properties of S at variable pressures, temperatures, and salinity, such as solubility in CO2, partition coefficient between brine and CO2, and aqueous stability have been studied in earlier work (Ren et al. 2014). The adsorptions of the used surfactants are neglected due to negative surface charges of sandstone samples at neutral pH (Lawson 1978; Mannhardt et al. 1993) and without the presence of clay in used outcrop. Except for novel CO2 continuous injection with dissolved CO2-soluble surfactant, in all other core flood experiments, the surfactant solution containing 0.2wt% surfactant and 3wt% NaCl (analytical grade quality) was used to stabilize supercritical CO2 foam generated in 1-ft-long Berea sandstone cores. The same NaCl concentration was used to saturate the core with brine before injection of the surfactant solution and CO2. The purity of the liquid CO2 was 99.5%. The rock permeability to brine was around 300 mD. 2.2 Experimental apparatus and procedures A schematic of the core flood setup is shown in Fig. 2. It is comprised of three main modules: a fluid injection system, core holder and pressure transducers, and a back pressure and effluent collection system. Fluid injection system A TELEDYNE ISCO Model 500D syringe was used to directly inject brine or surfactant solution into the cores. CO2 was displaced into the core by deionized (DI) water through a high pressure accumulator that had a piston to separate water from CO2. Core holder and pressure transducers A Phoenix Hassler-type core holder with capacity for 2-inch-diameter core was mounted vertically, and fluids were injected from the top to the bottom. Hydraulic oil was used as an overburden fluid, which compressed and sealed the 0.25-inchthick rubber sleeve to assure the axial flow of the injection fluids, and to prevent leakage. There were five pressure taps along the side of the core holder in the vertical direction, which connected two absolute pressure transducers (Channel 1 and 5) and three differential transducers (Channel 2, 3 and 4). The differential transducers detected Surfactant / brine Pressure gauge ISCO pump Accumulators Hydraulic pump Quizix pump Heating tape Channel 1 Channel 2 Channel 3 Channel 4 Channel 5 Electronic balance Fig. 2 Schematic of an experimental setup for core flooding the pressure drops over sections along the core from the top, whose lengths were 2, 4, and 4 inches and denoted as Sect. 1, 2, and 3, respectively. Back pressure regulator (BPR) and effluent collector Two BPRs were used in series to maintain a constant back pressure of 1500 psig during core flooding. The first BPR placed immediately at the outlet of the core holder was set at 1500 psig, and the second BPR set at 1100 psig. Core preparation The core was cleaned and dried in a convection oven at 110 C for 48 h. It was then wrapped in three layers of aluminum foil and a thin Teflon heat shrink tube to prevent CO2 diffusion and penetration. The wrapped core was placed in the core holder and evacuated for 10 h before the core was saturated with brine (3wt% NaCl) for porosity measurement. The permeability of the brinesaturated core was determined from Darcy’s law. Foam flooding All core floods were conducted at 35 C and 1500 psi back pressure. Three injection strategies were examined without using the pre-generator. These were simultaneous injection of CO2 and surfactant solution, alternating injection, and CO2 continuous injection with dissolved CO2-soluble surfactant. Except for the last one, surfactants were always injected with brine even though the novel surfactant is CO2-soluble. It will partition into CO2 instantaneously when two phases contact. The impact of delivery media on the novel foam performance is out of the scope of this study and will be discussed in a separate publication. To obtain a fixed injection foam quality of 75% for co-injection, the injection rates of the surfactant solution (containing 0.2 wt% surfactant) and CO2 were fixed at 0.1 cc/min and 0.3 cc/min, respectively. Through adjusting injection time individually, slug sizes of the surfactant solution and gas in alternating injection were kept at 0.1 PV and 0.2 PV, respectively. For the third novel strategy, 0.6 cc/min was employed for CO2 injection. The surfactant needed in CO2 in the container was determined by the known container volume, CO2 density (0.494 g/cc under experimental conditions), and fluid injection rates, to maintain the mass injection rate the same as in other scenarios. After calculation, 0.1wt% in CO2 was used to maintain the same amount of surfactant per minute to be injected in different strategies. Pressure drops over the three sections of the core were recorded. Water saturation was determined based on the difference in cumulative mass between the injected and the produced waters. 3 Simulation description 3.1 Reservoir model artificial gas back flow (Namdar Zanganeh and Rossen 2013). The radial grid size increases from 3 ft for the first 30 grids from the injector to 5 ft for the remaining grid blocks. Leeftink et al. (2013) found that a fine grid resolution near the injection well is important to prevent underestimating the effects of dry-out increasing injectivity in a SAG process in finite-difference simulations. The schematic is shown in Fig. 3. The reservoir is isothermal at 35 C, and the initial reservoir pressure is 1500 psi. For the sake of simplification, only the water phase is present in the reservoir initially (Kloet et al. 2009) since foam is only beneficial to sweep efficiency. All simulations were conducted with the Computer Modeling Group’s STARS simulator. The heuristic foam model built in CMG/STARS has been introduced in the literature (Zeng et al. 2016) and widely used in foam process simulation (Farajzadeh et al. 2015). Model parameter values fitting through different algorithms have been discussed by several researchers (Ma et al. 2014; Rossen and Boeije 2015). In our current work, the surfactant concentration and dry-out effects are considered and some typical values are chosen, as shown in Table 1. Here, we chose 100 for fmmob, which is less than these employed by earlier researchers, such as 1000 (Rossen et al. 2006), 3000 (Rossen and Shen 2007; Jamshidnezhad et al. 2008a), or 5000 (Cheng et al. 2000; Rossen and Renkema 2007; Kloet et al. 2009), because we believe too strong foam used previously masked some details in the foam process, which is crucial for the novel foam. Meanwhile, it is also much less than the result of coreflood matching (Ma et al. 2013) because the foam in 3D is much weaker than in 1D, which has been demonstrated by Li et al. (2006). In simulations, we made fmsurf equal to the injected surfactant concentration (3.34 9 10-5, molar fraction) (Hanssen et al. 1994; Rossen and Renkema 2007). A linear dependence between foam strength and surfactant concentration was chosen (epsurf = 1) (Rossen and Renkema 2007). Here, we set the Table 1 Foam model parameters used in field scale foam process simulation 3.34 9 10-5 fmdry as 0.15, which is more than irreducible water saturation. The reasons that we do not attempt to derive those parameters from laboratory scale history matching are threefold. The first, heretofore, the empirical model used in STARS is based on pseudo-steady-state assumption that the local equilibrium is achieved instantaneously without accounting for transient behavior of foam (Fisher et al. 1990; Rossen and Renkema 2007; Jamshidnezhad et al. 2008a). Therefore, it is suspected that the model may be more suitable for field scale simulation but not for laboratory scale. The second, there is no consensus on how to scale up foam behavior and corresponding parameters from laboratory to field. Hence, typical values are chosen. The third, it is of most importance to examine the relevant foam behavior discrepancy between different injection strategies and surfactants, rather than absolute performances, as long as the same parameter values are used. 3.2 Injection scheme constant pressure mode. In each mode, SAG, co-injection, and CO2 continuous injection with dissolved CO2-soluble surfactant are presented, as summarized in Table 2. Relative to a previous publication (Le et al. 2008), it is the first time that the measured surfactant partition coefficients of CO2-soluble surfactant between two phases (Ren et al. 2014) have been used in field scale simulations. The first strategy is the alternating injection of the surfactant solution and gas (surfactant alternating gas, SAG), in which the novel surfactant is injected with brine even though it is CO2-soluble. The liquid/gas slug size ratio is kept at 1:1 in volume. Two different slug sizes are tested, 36.5 and 182.5 days, respectively. Then, co-injection is examined, either two phases in the same intervals (simultaneous injection through all perforation, SIAP, or simultaneous injection through partial perforation, SIPP), or water into the upper part while gas into the lower part (separate injection no barrier, SINB, or separate injection with barrier, SIWB). Stone (2004a, b) proposed injection of water in an interval above the gas to increase reservoir sweep, which is called ‘‘modified SWAG’’ by Algharaib et al. (2007). The main goal of separate injection is to reduce the effect of gravity segregation commonly encountered in gas–liquid flow in reservoirs with high vertical communication (Rossen et al. 2006; Liu et al. 2011). A schematic of the four strategies is shown in Fig. 4. For constant pressure mode, only the best case selected from the constant rate mode, SINB, is displayed. Injection strategies Alternating injection SIWB Alternating injection Co-injection SINB Novel CO2 All injection perforation 115,714.3 – Fig. 4 Four different injection strategies for simultaneous injection of the surfactant solution and CO2 (G gas, W water) At last, the novel strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, was conducted for both modes with variable perforations. This is a unique one in which the surfactant concentration in CO2 after splitting between phases during injection should be lower than its maximum solubility (Ren et al. 2014). Table 2 summarizes the design parameters for the injection strategies described above. CO2 and water injection rates are chosen so as to achieve approximately 75% foam quality under reservoir conditions. Doubled injection time is employed to inject the same amount of fluids. The selection of injection pressure at the constant pressure injection mode is discussed in details in the corresponding section. Injection surfactant concentration, molar fraction 3.34 9 10-5 9.54 9 10-5 3.34 9 10-5 3.34 9 10-5 9.54 9 10-5 5.76/8 5.76/8 5.76/8 5.76/8 5.76/8 5.76/8 5.76/8 We employ the CO2 storage, Rg (gravity segregation length), and CO2 utilization ratio as evaluation criteria. The CO2 storage is defined as CO2 staying in the reservoir at the end of injection under surface conditions, which directly reflects the sweep efficiency. CO2 utilization ratio is defined as the ratio of CO2 storage over cumulative CO2 injection, which would be more useful to reflect the economic concern. 4 Results and discussion 4.1 Experimental results 4.1.1 Co-injection (a) 120 4.1.2 Alternating injection (b) 120 10 15 20 25 30 Injection volume (water & CO2), PV (a) 90 10 15 20 25 30 Injection volume (water & CO2), PV Fig. 6 Average water saturation in the core during simultaneous injection 4 6 8 10 12 Injection volume (water & CO2), PV the literature with other CO2-soluble surfactants (Xing et al. 2012; McLendon et al. 2014; Sagir et al. (2014c, d). Correspondingly, the residual water saturation after foam propagation has been lowered from 0.42 (conventional) to 0.31 (novel), as shown in Fig. 8, and the displacement efficiency has been improved almost 20%. At the same time, we also notice that relative to simultaneous injection (Fig. 6), the alternating injection does promote the foam generation and injectivity (Li and Rossen 2005) for both types of foams indicated by the quick strong foam propagation and lower pressure drops. (b) 90 4 6 8 10 12 Injection volume (water & CO2), PV Fig. 10 Gas production rate of small slug size (36.5 days) every section. As early as 0.5 IPV, the strong foam propagated into Sect. 2 and then toward into Sect. 3 after 1.1 IPV. Much quicker foam propagation is attributed to the ability of the surfactant to dissolve in CO2 without interference from water injection as well as inlet gas trapping. Foam collapsed when water saturation reached the critical value regionally. However, a huge amount of gas trapped in the core indicated by the residual pressure drops as high as 4 psi across the whole core is beneficial enough to the gas mobility control. Correspondingly, after gas breakthrough and weak foam propagation at 0.5 IPV, the strong foam developed in following sections drops the water saturation to 0.25 as early as 2.4 IPV and then levels off. This novel injection strategy really displays the superior surfactant transportation and foam propagation ability of this CO2-soluble surfactant. In addition, the foam strength here in apparent viscosity was at least one magnitude higher than published data of other soluble surfactants (Xing et al. 2012; McLendon et al. 2014), which confirmed the superior capacity to stabilize the bubbles by the currently employed novel surfactant. 4.2 Simulation 4.2.1 Constant rate injection mode (a) 12 (b) 1.00 4 6 Injection volume (CO2), PV 4 6 Injection volume (CO2), PV in the override zone has been reduced greatly and effective diversion occurred. Furthermore, this particular surfactant partitioning improves not only sweep efficiency, but also well injectivity with significantly reduced surfactant concentration near the wellbore. Here, one may have the suspicion that whether the superiority of the novel foam comes from the foam model effect. It is true that we employ the surfactant concentration in the water phase as the scale for gas mobility reduction in the simulation. Theoretically, we should supervise the concentration in the whole cell (global) because surfactant will act at the interface regardless of its partition in the gas phase. In reality, a comparison between corresponding plots (Figs. 12 vs. 13) tells us they display exactly the same trend except for the magnitude, which is attributed to the mass conservation and constant partition coefficient of injected fluids. Hence, in the following parts, we will only employ and illustrate the surfactant concentration in the aqueous phase. With a larger injection cycle (182.5 days), for the conventional foam (Fig. 11a, c), an increase in the slug size significantly improves the vertical sweep efficiency by extending the distance Rg that the injected gas–water mixture flows before complete segregation but at the cost propagation and fluid redistribution. For the conventional surfactant, the high pressure gradient is concentrated only within the near-wellbore region and expands somewhat from the wellbore as the fluid cycle increases (Shan and Rossen 2004). However, it spreads much further into the reservoir for CO2-soluble surfactant indicating by a more even pressure gradient distribution. The variations of CO2 storage and Rg with slug size are summarized in Table 3 as well as Fig. 16. With slug size increasing, the gravity segregation lengths do enlarge for both types of foams. However, the sweep efficiency varies differently, 11% reduction for the novel foam and 111% improvement for the conventional one. Therefore, we confirm the previous conclusion for the conventional foam the larger slug size was beneficial to the foam process for cylindrical homogeneous reservoirs (Shan and Rossen 2004; Rossen and Shen 2007; Rossen and Renkema 2007). For the novel foam, insensitivity to injected slug size gives less restriction for operation. With CO2-soluble surfactant, the contradiction between gravity segregation length and CO2 storage tells us again that Rg is only one criterion for fighting gravity segregation and not the sufficient condition. Water and gas injection through the same intervals (SIAP and SIPP) Fig. 14 Gas well BHP of large slug size (182.5 days) Table 3 CO2 storage and gravity segregation length Novel Conventional Novel Conventional 10 9 8 0 Alternating Alternating SIWB Fig. 16 Summary of CO2 storages for alternating and simultaneous injection with constant rate injection mode SIAP, conventional SIAP, novel SIPP, conventional SIPP, novel Time, day Fig. 17 Gas production rate during SIAP and SIPP superior over the conventional one with respect to sweep efficiency and injectivity. This is in accordance with the previous conclusion that relative to SAG with constant injection rate, a foam process with continuous foam injection performs even worse, because most of the wellto-well pressure drop was dissipated in the near-well region (Shi et al. 1998; Shan and Rossen 2004; Rossen and Shen 2007). The results in this case tell us gas override takes precedence in importance over water slumping in fighting gravity segregation (Shan and Rossen 2004). Table 4 summarizes CO2 storage (Fig. 16) and gravity segregation length for SIAP and SIPP. It is obvious that the novel foam gives much higher sweep efficiency than the conventional one. Here, we do confirm the close Rg with alternating injection for SIPP, but not for SIAP, which is expected as the cycle size decreases (Shan and Rossen 2004). In addition, we do not reach the conclusion that Rg for constant rate injection is not sensitive to the simultaneous injection of gas and water into either a partially (SIPP) or a fully completed well (SIAP) (Rossen et al. 2006; Rossen and Shen 2007; Jamshidnezhad et al. 2008b). Injection of water into the top part and gas into the bottom part (SINB and SIWB) SIAP, conventional SIAP, novel SIPP, conventional SIPP, novel Time, day Fig. 20 Well bottom-hole pressures during SIAP and SIPP distribution in the reservoir (Fig. 26). Now, relative to the conventional foam, the novel surfactant extends the high pressure gradient much further into the reservoir with more even pressure distribution. Table 4 also summarizes CO2 storage (Fig. 16) and gravity segregation lengths for those two separate injections. It is obvious that the novel foam still gives much higher sweep efficiency than the conventional one. We do achieve the same Rg for SINB and SIWB as well as the higher injection pressure for the latter (Rossen et al. 2006; Rossen and Shen 2007; Jamshidnezhad et al. 2008b). However, the sweep efficiency improvement was not remarkable, particularly for the novel foam. Relative to water and gas injection through the same intervals (SIAP and SIPP), the distance to the point of complete segregation Rg increases by a factor of about 1.5 and higher injectivity (Figs. 20, 23) has been achieved for separate injection (SINB and SIWB). This result agrees with the theoretical prediction of Rg as a function of water fractional flow reported in the literature (Rossen et al. 2006; Rossen and Shen 2007). From above analysis we can find, for novel foam, gravity segregation length is a less precise representative parameter of sweep efficiency. Table 4 Comparison of CO2 storage and gravity segregation length among alternating and simultaneous injection CO2 storage, 107 scf Novel Conventional 1.16 0.874 1.06 Novel 130 54 115 Conventional 130 30 115 4.2.2 Constant pressure injection mode Time, day Fig. 22 Gas production rate during SINB and SIWB SINB, conventional SINB, novel SIWB, conventional SIWB, novel SINB, conventional SINB, novel SIWB, conventional SIWB, novel Time, day Fig. 23 Well bottom-hole pressure during SINB and SIWB saturation approaching the critical value (Rossen et al. 1995); thus with relatively high mobility ahead of and behind the displacement front, a pressure-constrained SAG process can force the entire reservoir pressure drop into the region of low mobility at the displacement front, i.e., more even pressure drop distribution is expected instead of most of them dissipating in a short distance. However, our results show that the improvement is very limited, with respect to gas saturation (Fig. 28a), surfactant concentration (Fig. 29a), and pressure distribution (Fig. 30a). All of those are extremely similar to the results before with the constant rate mode (Figs. 11a, 12a). Hence, we deduce the injection mode may not be the crucial parameter as long as injection mass conservation is honored. On the other hand, from the point view of sweep efficiency, alternating injection with constant pressure mode tends to amplify the superiority of the novel foam over the conventional one, characterized by a vertically expanded gas saturation profile (Fig. 28b), uniform surfactant distribution (Fig. 29b), and much deeper extended high pressure gradient (Fig. 30b), even though more gas has been produced (Fig. 31a). In addition, it seems that the constant pressure mode does able the enhancement of the sweep efficiency tremendously for the novel foam (Figs. 11b, 28b), which deserves further discussion below. Meanwhile, unequal amount of gas injection requires us to employ another parameter, CO2 utilization ratios, for the economic consideration, which are also listed in Table 5. Therefore, there is no question that for alternating injection, constant pressure injection mode is beneficial to conventional foam with respect to both sweep efficiency and CO2 utilization ratio even though the improvement is trivial. For the novel foam, operators need to balance the extra profits from 50% sweep efficiency improvement against the ascending injection cost from 29% deducted gas utilization even though it is still more than four times higher than that of conventional foam. slightly higher than those in the constant rate mode. This is consistent with the deduction we did for the conventional foam. Thus, the improved CO2 storage and reduced CO2 utilization above just result from more fluid injections. In other words, for both types of foams, the injection mode is of less importance as long as a close average injection rate or pressure is fulfilled. In the constant rate mode section, we already concluded that the novel foam was insensitive to the slug size for CO2 storage, 107 scf Constant rate CO2 utilization ratio Constant rate 36.5 days 182.5 days 36.5 days 182.5 days 36.5 days 182.5 days 36.5 days 182.5 days (a) 8.00e+5 (b) 8.00e+5 Constant pressure Gas (1581 Gas (1548 Gas (1581 psi) psi) psi) Water Water Water (1547 psi) (1553 psi) (1547 psi) Novel 7.36 Conventional 1.16 Constant pressure Gas (1581 Gas (1548 Gas (1581 psi) psi) psi) Water Water Water (1547 psi) (1553 psi) (1547 psi) 0.249 0.0933 0.199 0.046 0.105 0.096 The unique injection strategy, CO2 continuous injection with dissolved novel surfactant, was examined. For sake of comparison, analogous to the manipulation in core flooding, CO2 injection rate is the summary of two phases in alternating and co-injection strategies under surface conditions. Accordingly, the surfactant concentration is lowered to maintain the same amount of surfactant injected. Two perforation location scenarios are investigated as well as both injection constraints, as shown in Table 2. (a) 8.00e+5 (b) 8.00e+5 Conventional Novel Conventional Novel identical gas production rate (Fig. 40), BHP in the injector (Fig. 41), gas saturation (not shown), surfactant concentration (not shown), and pressure distribution (not shown). Hence, we could take full completion for further discussion. CO2 storage, 107 scf Constant rate Constant pressure Gas (1608 psi) Water (1598 psi) Gas (1585 psi) Water (1595 psi) Novel Conventional 8.9 1.73 12.3 Injection rate, conventional Production rate, conventional Injection rate, novel Production rate, novel Time, day Fig. 32 Gas injection and production rates of novel and conventional foams for SINB with constant pressure constraint Fig. 34 Gas saturation of novel foam for SINB with constant pressure constraint Fig. 33 Gas saturation of conventional foam for SINB with constant pressure constraint Fig. 35 Surfactant concentration of conventional foam for SINB with constant pressure constraint CO2 utilization ratio Constant rate 0.338 0.066 Constant pressure Gas (1608 psi) Water (1598 psi) 0.142 0.0554 Gas (1585 psi) Water (1595 psi) Fig. 36 Surfactant concentration of novel foam for SINB with constant pressure constraint Fig. 37 Pressure distribution of conventional foam for SINB with constant pressure constraint Fig. 38 Pressure distribution of novel foam for SINB with constant pressure constraint CO2 is not zero. With a huge amount of gas flow, bubbles will collapse when the water saturation approaches the critical value. Here, without interference from water, the novel surfactant can be delivered much deeper into the reservoir and foam is generated in situ with formation water. It is straightforward to deduce that the injection pressure would be compellingly low among all the studied cases, as shown in Fig. 41, in which the partial completion gives a little higher value. The superiority of this novel strategy is also evidenced by the pressure distribution in the reservoir (Fig. 44). A high pressure gradient extends into the reservoir deeply, characterized by the extremely evenly distributed zones and steep contour lines, which stand for the high power utilization efficiency. In summary, this novel injection strategy is almost incomparably better with respect to saved water injection cost and highly improved sweep efficiency and gas utilization. CO2 storage, 107 scf Alternating injection (36.5-day slug size) Novel Conventional 7.36 1.16 SINB CO2 continuous injection with CO2-soluble surfactant CO2 utilization ratio Alternating injection (36.5-day slug size) 0.338 0.066 CO2 continuous injection with CO2-soluble surfactant Conventional Novel Conventional (a) 14 (b) 0.40 Alternating (36.5-day slug size) CO2 continuous injection with novel surfactant Alternating (36.5-day slug size) CO2 continuous injection with novel surfactant Full completion Partial completion through 10 layers Gas injection rate Gas production rate of full completion Gas production rate of partial completion Time, day Fig. 40 Gas injection and production rates of CO2 continuous injection with dissolved CO2-soluble surfactant with full completion and partial completion Time, day Fig. 41 Bottom-hole pressure in the gas injector of CO2 continuous injection with dissolved CO2-soluble surfactant with full completion and partial completion Fig. 42 Gas saturation of CO2 continuous injection with dissolved CO2-soluble surfactant with full completion Fig. 43 Surfactant concentration of CO2 continuous injection with dissolved CO2-soluble surfactant with full completion Fig. 44 Pressure distribution of CO2 continuous injection with dissolved CO2-soluble surfactant with full completion conclusions highly improve the robustness of foam application according to field fluid requirement and facility availability. 5 Summary In summary, the inherently superior properties of the novel surfactant make it outperform conventional surfactant in every injection strategy. The restriction of constant rate injection mode does not exist anymore. Injection constraint cannot solve the intrinsic problem that causes gas channeling because the constant pressure mode still arranges the pressure distribution through adjusting the injection rate (Boeije and Rossen 2014). Previous researchers (Shi and Rossen 1996, 1998; Shan and Rossen 2004; Rossen et al. 2006; Rossen and Shen 2007) have demonstrated that for conventional foam, the override zone will not expand downwards greatly and the only possible change is that the mixed zone spreads to a producer with stronger foam or higher injection pressure, as shown in Fig. 49 (black dash vs red dot dash lines), which will deteriorate injectivity. The red dot dash line indicates the cross-point of three zones could only move horizontally and this is the reason the gravity segregation length has attracted so much attention. Now, relative to the conventional foam, this novel foam tends to weaken the foam near the wellbore and strengthen it on the top layers with migration of surfactants with gas. In other words, the conflict between sweep efficiency and injectivity encountered by the conventional foam (Namdar and Rossen 2013) has been reduced significantly by the novel foam. Continuously supplying enough surfactants to the top layer is crucial for gas diversion to increase the volume of the traditionally defined override and mixed zones (Fig. 49 in blue solid line). Hence, Rg is only a criterion for fighting gravity segregation but not a sufficient condition to evaluate an injection strategy. The volume of the override zone and gravity segregation height play an important role in determining the sweep efficiency, which requires not only even pressure distribution but also steep pressure contour lines. The novel foam can perform well even with short segregation length or early gas breakthrough because they do not reflect the successive stages of gas diversion. Intrinsic superiority of the novel surfactant replaces the injection mode to dominate the foam process and gives more freedom to injection arrangement according to CO2 acquirement. CO2 storage, 107 scf Constant rate Novel 11.7 Constant pressure Gas (1585 psi) Gas (1610 psi) Production Injection CO2 utilization ratio Constant rate Constant pressure Gas (1585 psi) Fig. 45 Gas injection and production rates of CO2 continuous injection with dissolved CO2-soluble surfactant under constant pressure constraint (1585 psi) Fig. 47 Surfactant concentration of CO2 continuous injection with dissolved CO2-soluble surfactant under constant pressure constraint (1585 psi) Time, day 6 Conclusions The novel CO2-soluble surfactant provides better film stabilization ability than the conventional aqueous surfactant. In turn, when simultaneously injecting, the novel foam propagates faster and demonstrates higher pressure drop and sweep efficiency. Gas (1610 psi) Fig. 48 Pressure distribution of CO2 continuous injection with dissolved CO2-soluble surfactant under constant pressure constraint (1585 psi) Alternating injection does improve the foam propagation and injectivity regardless of surfactant type. Alternating injection also promote the superiority of the novel foam over the conventional one in quicker and stronger foam generation. It is the first time the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, has been tested in consolidated cores, Traditional override zone Vertically extended override zone by novel foam with CO2 soluble surfactant Conventional foam with aqueous soluble surfactant Conventional foam with aqueous soluble surfactant for stronger foam or higher injection pressure Novel foam with CO2-soluble surfactant Fig. 49 Schematic plot of conventional and novel foams on fighting gravity segregation which demonstrates superior surfactant transportation ability, in turn improving the foam propagation and displacement rate significantly. With field scale simulation, for all tested injection strategies, regardless of constant rate or pressure constraint, the novel foam significantly outperforms conventional foam in terms of much higher sweep efficiency, injectivity and much more even pressure distribution resulting from intrinsic property of the novel surfactant. The novel foam performance is a function of injection strategy, injection rate or pressure, and partition coefficient (not discussed here); for a fixed injection strategy and with the novel surfactant, regardless of injection constraint, sweep efficiency is a monotonic function of injection rate or pressure, but the gas utilization ratio demonstrates a parabolic shape. Injection constraint, i.e., constant rate or pressure, is of much less importance to both types of foams, as long as similar amount of fluids have been injected. From the point view of sweep efficiency, for alternating injection, constant pressure mode tends to amplify the superiority of the novel foam over the conventional one due to higher injectivity. Relative to conventional foam, the novel foam tends to increase the segregation height and volume of the traditionally defined override zone through gas diversion instead of solely increasing gravity segregation length and delaying gas breakthrough time. The latter two are of less importance in performance evaluation for the novel foam. For alternating injection, relative to conventional foam that is preferential to lager slug, the novel foam is not sensitive to injection fluid slug size regardless of injection constraint. The optimal slug size of novel foam with respect to gas utilization is a function of injection rate or pressure and partition coefficient. Co-injection does lower the injectivity for conventional foam relative to alternating injection while this problem has been greatly reduced with the novel foam owing to surfactant concentration deduction by gas extraction. For simultaneous injection through same sections (SIAP and SIPP), relative to full completion, partial completion lowers the injectivity and improves the sweep efficiency for both foams, while for separate injection (SINB and SIWB), the novel foam really reduces the distinction between them with respect to sweep efficiency and injectivity. The separate injection (SINB and SIWB) is able to give longer gravity segregation lengths and higher injectivity than simultaneous injection through same sections (SIAP and SIPP). The novel injection strategy, continuous CO2 injection with dissolved surfactant, gives the best foam performance among all the tested scenarios regardless of completion sections and injection constraint. This may dramatically lower the water injection/treatment cost and improve the robustness of foam application. Acknowledgements The authors would like to thank Hang Zhang (University of Texas at Austin, currently at Schlumberger Houston) for his dedicated help with laboratory experiments. 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Guangwei Ren, Quoc P. Nguyen. Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs, Petroleum Science, 2017, 330-361, DOI: 10.1007/s12182-017-0149-2