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An experimental study on application of nanoparticles in unconventional gas reservoir CO2 fracturing
Journal of Petroleum Science and Engineering 133 (2015) 238–244
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Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
An experimental study on application of nanoparticles in unconventional gas reservoir CO2 fracturing Yanzun Li a,b,n, David DiCarlo b, Xiangfang Li a, Jiali Zang a, Zhennan Li a a b
China University of Petroleum, Beijing, China University of Texas at Austin, USA
art ic l e i nf o
a b s t r a c t
Article history: Received 14 March 2015 Received in revised form 23 April 2015 Accepted 11 May 2015 Available online 20 June 2015
Gas production from low permeability unconventional reservoirs is still a challenge to the world. Although hydraulic fracturing has been successfully applied in unconventional gas production, its limitations are obvious, such as formation damage, water blocking, low stimulating effect and the requirement of sufficient water. To avoid these problems, liquid CO2 has been pumped as a fracturing fluid into unconventional reservoirs. But as a consequence of low density and viscosity of super critical phase CO2 in the formation, CO2 fracturing suffers from low sweep efficiency that manifests as viscous fingering. So various additives have been applied to improve CO2 fracturing effect. This paper introduces a novel additive, nanoparticles, and presents an experiment to evaluate its effect on CO2 fracturing. In this paper, a core flooding experiments was conducted to simulate the fracturing process, in which liquid CO2 was injected into a core to drainage brine or nanoparticles solution. During the process, CO2 distribution and pressure drop were real-time measured with a modified medical CT scanner and pressure transducers. A significant difference is observed between with and without nanoparticles. The saturation files show that CO2 fingering was decreased and the drainage area was improved with the action of nanoparticles. Meanwhile, the CO2 injecting pressure raised, which implies that nanoparticles could offer higher pore pressure in fracturing. These observations suggest that a nanoparticle-stabilized foam is formed between CO2 and nanoparticle solution, which suppress the viscous instability. The results provide nanoparticles are effective to enhance CO2 fracturing. Also, this experiment suggests an optimized protocol of CO2 fracturing with nanoparticles in unconventional reservoir stimulate. & 2015 Elsevier B.V. All rights reserved.
keywords: Nanoparticles CO2 Fracturing Unconventional Gas Reservoir
1. Introduction Over past three decades, the success of shale gas production in U.S. has triggered an increasingly worldwide interest in these unconventional resources. According to U.S. Energy Information Administration (EIA), low permeability gas shale was estimated to hold 800 trillion cubic feet of recoverable natural gas. Economically feasible application of advanced hydraulic fracturing and horizontal drilling technologies in tight gas shale enabled U.S. to surpass Russia to become the top producer of natural gas since 2009. Other countries, such as China, Poland, also possess abundant amount of unconventional reservoir resources. EIA estimates China has 1115 Tcf of risked technically recoverable shale gas resources, making it an important resource for China's future energy demand. n
Corresponding author at: China University of Petroleum, Beijing, China. E-mail address: [email protected] (Y. Li).
http://dx.doi.org/10.1016/j.petrol.2015.05.023 0920-4105/& 2015 Elsevier B.V. All rights reserved.
Most unconventional reservoirs are developed by hydraulic fracturing treatments (Morales et al., 2011; Cheng, 2012; King and King, 2010; King, 2012). In unconventional reservoir fracturing, various fracturing fluids have been applied, such as foam-based fluids, water-based fluids and waterless fluids (Fisher and Warpinski, 2012; Carl Montgomery, 2013). At present, slick water is the mainstay fracturing fluid in unconventional reservoir stimulate. Slick water is fresh water treated with up to 5% potassium chloride by volume. Water fracturing lacks gel particles, therefore it leaves no residues or filter cakes behind, and produces less damage to fracture conductivity compared to massive hydraulic fracturing with gelled fluids (Terracina et al., 2001). However, there are many disadvantages associated with hydraulic fracturing operations. Firstly, huge volume of water is required in hydraulic fracturing which is difficult to achieve in water deficient areas. Secondly, formation damage would occur since a large quantity of aqueous fluid is injected into reservoirs during hydraulic fracturing. Another deficiency is that slick water cannot permeate into the nano-
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molecules have greater sorption affinity compared to methane molecules. Thus, another promising application for CO2 is CO2 injection for enhanced gas recovery (Eshkalak et al., 2014). Additionally several simulation studies had optimized CO2 injection process for EOR (Sondergeld et al., 2010; Yu et al., 2014). In CO2 injecting to the formation, the less dense and less viscous of CO2 will cause the poor sweep efficiency by viscous fingering and gravity over-ride (Bae and Irani, 1993; Rossen, 1996; Wagner and Weisrock, 1986). In CO2 fracturing, as same as CO2 storage, the viscosity fingers reduce the fracturing fluids drainage area. Recently, there are many researches about using nanoparticles emulsions to enhanced oil recovery (Kotsmar, 2010; Zhang et al., 2009, 2010) And nanoparticle will form a film between CO2 and brine, which uniform the displacement front to prevent the fingering (Grigg and Schechter, 1997; Aminzadeh et al., 2012a, b; Aminzadeh et al., 2013; Binks, 2002,, 2007; Binks et al., 2008; DiCarlo et al., 2011) In this paper, we conducted an experiment to demonstrate the effect of nanoparticles on sweep efficiency and proposed a protocol of CO2 fracturing. Fig. 1. CO2 fracturing process.
2. Methodology
Table 1 The permeability of shale. Eagle ford shale (Gong, 2013)
Fracture permeability (D) Matrix permeability (mD) n
0.04–0.2
Bakken shale (Cho et al., 2013)
3–8
0.02–0.8 10
4
1.31–7.24 10
Barnett shale (Loucks et al., 2009)* 0.1–18
4
0.02–3.2
Calculated based on the data from reference.
Table 2 The character of core. Diameter (cm) Boise sandstone 7.2
Length (cm)
Porosity (%) Permeability (mD)
30
28.8
900
Table 3 Relevant fluid properties: viscosity m, density ρ, and interfacial tension with respect to brine s.
μ (cP) ρ (Kg/m3) σ (mN/m)
Brine
5% Nano
CO2
1.1 1010 N/A
1.2 1040 N/A
0.08 792 24
pores and micro-pores for its high viscosity, which would limit the stimulated reservoir volume (SRV). Therefore, a proposed fracturing fluid in hydraulic fracturing of unconventional reservoirs is liquid CO2 (Gupta and Bobier, 1998; Yost et al., 1993). Fig. 1 shows the process of CO2 fracturing. Liquid CO2 is more active on extending micro-fractures and connected them during fracturing in shale than water and slick water (Fang et al., 2014). Among the benefits of using liquid CO2 in hydraulic fracturing is less flow back water that needs to be treated or permanently disposed of. In addition, shale formations are known to preferentially adsorb CO2 over CH4 as noted by several researchers (Jessen et al., 2008; Nuttal et al., 2005; Kang et al., 2011; Schepers et al., 2009; Heller and Zoback 2013; Ismail et al., Zoback). Kalantari-Dahaghi (2010) had reported the study of CO2-EGR and concluded that the process is feasible since CO2
In this experiment, Boise sandstone was used instead of shale stone to evaluate the nanoparticle's effect on CO2 fracturing volume. Shale could be seen as dual-porosity media, including matrix pore system and fracture system. In the flow model, for ultralow permeability of matrix, it assumes that gas only flowing in fracture system (Apaydin et al., 2012; Hudson et al., 2012; Josh et al., 2012). The permeability and pore size of Boise sandstone are as same as micro fracture and macro pores in shale, potentially having the same conduction (Table 1). Hence, sandstone could be the appropriate media to observe the CO2 distribution during the injection. The core is a cylinder that is 7.2 cm in diameter and 30 cm in length. The permeability of core is 900 mD, and porosity is 28.8% ( Table 2). In order to avoid CO2 corrosion, the rock sample was wrapped in a heat-shrinkable Teflon tube, 4 layers of aluminum foil, another layer of Teflon heat-shrinkable tube, and an AFLAS rubber sleeve before it was placed into an aluminum core holder. The Teflon layers provide a barrier to water, while the aluminum foil prevents CO2 diffusion to the AFLAS sleeve. The wetting phase as formation water is brine with 2 wt% NaBr. In the accumulator, the brine was pre-equilibrated with CO2 by injecting 100 ml of CO2 per liter of brine, into the brine accumulator over 5 h and letting the wetting fluid to equilibrate with CO2 for 48 h before usage. In this experiment, CO2 would be kept in liquid phase at 8.3MPa and 25 °C (room temperature). And CO2 was saturated with brine by injecting brine (20 ml of brine per liter of CO2) into the CO2 accumulator over 5 h and allowing CO2 and brine to equilibrate for 48 h before usage. The fluids properties are showed in Table 3. The nanoparticles used in this experiment are made by silicon and coated with polyethylene glycol (PEG), which prevents the aggregation and retention of nanoparticles. The diameter of nanoparticle could ranges from 5 nm to 20 nm. In this experiment we selected 5 nm nanoparticles as test objects. They are small enough to transport into micro-pores of shale stone, which contributes to generate more fractures in matrix. In experiments, the nanoparticle dispersion was diluted to 5 wt% with NaBr aqueous phase whose total salinity is 2 wt%. 3. Procedure Fig. 2 shows a schematic of our experiment set-up. In this
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Fig. 2. Schematic diagram of CO2 fracturing set-up.
Table 4 The sequence and fluids of horizontal experiment Exp no.
1
2
Fluid 1 Fluid 2
Brine CO2
Nano CO2
Fig. 5. The images of CO2 saturation distribution along the core which initial saturated with brine when CO2 injection.
Fig. 3. The curves of CO2 saturation distribution along the core which initial saturated with brine during CO2 injection.
Fig. 4. The curves of CO2 saturation distribution along the core which initial saturated with nanoparticles solution during CO2 injection.
experiment, first, the core was preloaded with brine/nanoparticles solution after it was placed in coreholder under vacuum overnight. Then one pore volume of liquid CO2 was injected into the core at 2.5 ml/min at 25 °C. After that, one pore volume of brine/nanoparticles solution was injected into the core until CO2 saturation stable. The system remained constant at 8 MPa with a back pressure regulator (BPR). The in-situ saturation was captured in real time by placing the core horizontally in a modified medical scanner, which scanned the whole core at 1 cm intervals. CT scanning measured the local density of the materials occupying each voxel; since CO2 is less dense than the brine or nanoparticle suspension the measured density can be converted to saturation by a linear interpolation between CT values of the core saturated with the brine (or nanoparticle suspension) and CO2 (Apaydin et al., 2012; Hudson et al., 2012). At the outlet, a scale was installed to measure the liquid that flowed out. Based on the effluent data, the CO2 saturation of core can be calculated. We carried out two experiments to estimate the effect of nanoparticles solution. One is the control experiment, in which the core was preloaded by 2 wt% brine. In the other experiment, the core was preloaded by 5 wt% nanoparticle solution. The fluids used in the experiment are displayed in Table 4.
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Fig. 6. The images of CO2 saturation distribution along the core.
Fig. 7. The images of CO2 saturation distribution along the core which was initially saturated with brine when CO2 injection.
Fig. 8. The images of CO2 saturation distribution along the core which was initially saturated with nanoparticles when CO2 injection.
4. Results In the control experiment, the core was preloaded by 2 wt% brine. Fig. 3 is the CO2 saturation distribution plots along the core at different PV of CO2 injection, which based on the CT scanning. The CO2 saturation curves of PV¼0.02, PV ¼0.05, PV¼ 0.1, PV¼ 0.15, shows the formation of fingers. In particular, we notice that in the front of finger, the CO2 saturation kept in a low level until the fingerings broking through at 0.15PV. After breaking through, the CO2 saturation started to increase along the core. It reached the maximum saturation to 0.35 at 1.0PV. Fig.4 shows the CO2 saturation distribution plots along the core at different PV with nanoparticles solution during CO2 drainage. The curves of PV ¼0.02–0.3 present the CO2 saturation profiles before the front of CO2 broking through. It shows that the front of CO2 was uniform with high saturation¼0.3. And the breaking through time was delayed to PV ¼0.35. After the CO2 broke through, the CO2 saturation didnot change. Fig. 5 shows the pressure drop files during CO2 drainage. We notice that both curves had the same slopes at early uptrend,
Fig. 9. CO2 flow in the core. (a) CO2 drainage without nanoparticles. (b) CO2 drainage with nanoparticles
which implied that the CO2 had to overcome the capillary force to flow into the core. After that, the different trends of the curves are displayed. In the control experiment, the pressure drop had slow descending with the CO2 saturation of core increasing before
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Fig. 10. CO2 transform in the core pores.
Fig. 11. CO2 fracturing without nanoparticles solution. (a) Inject normal Pad Fluids (b) Inject super critical CO2 as fracturing fluids
Fig. 12. CO2 fracturing with nanoparticles solution. (a) Inject nanoparticles solution as pad fluids. (b) Inject super critical CO2 as fracturing fluids.
fingers breaking through. And in the experiment with nanoparticles solution, the pressure drop still raised to 4 psi, which was 2.7 times more than that without nanoparticles. Also, the pressure drop files show the breaking through time of CO2 according with the saturation files' results. After CO2 broke through, the pressure drop dropped rapidly. With the CT data, we also drew the images of CO2 saturation of each scanning slice (Figs. 6–8). The images show more details about what has happened inside the core during CO2 drainage. In Fig. 7, liquid CO2 first appeared at the high permeability zone. It suggests that liquid CO2 mainly flow through and
accumulates at the high permeability channel. As a result, was dominated by the heterogeneity of rock. After CO2 broke through, CO2 spread gradually to displace more brine out. Images of the slices show that brine in the area with lower permeability was replaced by CO2, and the saturation raised in the area where was filled with CO2. Fig. 8 shows the images of CO2 saturation slices with the core saturated by nanoparticles solution. The different flow type is showed in the images. With the nanoparticles, liquid CO2 flow appears to be slug flow. with the front of CO2 is uniform. It is also observed that CO2 saturation is much higher in areas where in
Y. Li et al. / Journal of Petroleum Science and Engineering 133 (2015) 238–244
where CO2 swept, even in the low permeability area.
5. Discussion According to the results of CO2 drainage experiment with and without nanoparticles in sandstone core, an applicable protocol of CO2 fracturing can be discussed as follows:
(a) During CO2 injection, nanoparticles both increased the CO2 sweep efficiency and saturation. In the experiment, the effect of nanoparticles was present: the CO2 saturation increased by 0.1; and CO2 swept more area even in the low permeability zone. Figs. 3 and 4 are the saturation profiles of CO2. In Fig. 3, without nanoparticles' action, the saturation curves shows the finger spread fast and lead a low saturation in the core. But with nanoparticles, as shown in Fig. 4, the displacement front of CO2 is uniform and stable. Behind the front, a high saturation of CO2 is observed. The images of CT scanning (Figs. 7 and 8) give us more information of the CO2 distribution in the core. In Fig. 7, we notice the fingers are formed in high permeability zone. With less percolating resistance in high permeability zone, the CO2 finger spread fast and limit the saturation increase (Fig. 9a). After CO2 break though, the saturation of CO2 is still low. The different flow types are present in Fig. 8. The CO2 displacement front is uniform and moves forward like a piston (Fig. 9b). In the drainage process, CO2 also accumulates in the low permeability zone, where the pore size is smaller. In Table 3, it points that the fluid's viscosity is not changed by nanoparticles. And after the experiment, we find that there is few residual nanoparticles in the core after 3 PV brine flush. Nanoparticles are not absorbed on the surface of medium or aggregate together. So the nanoparticles does not act as changing viscosity or blocking the larger pore. Considering the wettability of nanoparticles, the results suggest that nanoparticle will coat CO2 droplets (Fig. 10) and form a kind of foam between the CO2 and brine (Fig. 9b) (Binks et al., 2008). The foam will reduce the viscosity fingering and overcome the influence of heterogeneity. ● (b) With the nanoparticle, CO2 fracturing can offered a higher pressure drop to improve the effect of fracturing. Fig. 5 shows the pressure drop during CO2 injection. The early uptrends of both curves present the same trend. In this stage, CO2 overcome the capillary force to enter the pore. After this stage, different trends of the pressure drop are observed. The curve without the effect of nanoparticles shows that following the saturation of CO2 increasing, the pressure drop slowly drop down till fingers break though. This could be explained by twophase relative permeability. But when the nanoparticle present in the experiment, the curve keeps raising after CO2 enters. It suggests that another flow resistance acts on the two-phase flow. Based on the above discussion, we know that nanoparticles will form a foam layer in the CO2 displacement front. This foam layer block the large pores and reduce the fingering, which offers the additional flow resistance. Fig. 5 shows the pressure drop is 1.5 times of the pressure drop without nanoparticles. It proves that nanoparticles will increase the CO2 pressure in the formation. That means comparing with fracturing without nanoparticles, the pore pressure can meet the formation fracturing pressure with less volume super critical CO2. It will generates more fractures in matrix to improve the formation permeability. ● (c) Nanoparticles could flow into the nano-pores of matrix with super critical CO2 to improve the fracturing effect.
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In hydraulic fracturing, it will generates a larger number of micro-fractures in matrix (Krevor et al., 2012; Kianinejad et al., 2014; Gomaa et al., 2014; Xiao et al., 2011). When the formation pressure drops, the micro-fractures will close and the proppants cannot flow into the pores. The closure of these fractures brings unexpected problems, such as low effective stimulation and poor production performance. The diameter of nanoparticles is nano-size, which allows them to flow into nano-pores in matrix of shale. During liquid CO2 is pumped into the formation, nanoparticles will gather on the CO2 front. Then they are pushed into the pores of matrix, where the normal size proppants cannot reach. The nanoparticles will play a role of proppant in fracturing. It was reported that small size additives could improve the flow of fracturing fluid into micro-fractures, which tend to reduce the breakdown pressure and enhance fracture complexity (Cipolla et al., 2009). ● (d) The results of experiment suggest an optimized protocol of nanoparticle application in CO2 fracturing. The previous studies have pointed when injecting CO2 into the core preloaded by nanoparticles solution, nanoparticles would gather on the surface between CO2 and brine. Otherwise, nanoparticles would distract in the brine or super critical CO2. As the discussion above, nanoparticles would play its role as coating the CO2 droplets to form a foam layer at the CO2 front. In this experiment, the significant effect of nanoparticles was observed. It suggests the nanoparticles should be pumped into the formation before CO2 injection. In the practical CO2 fracturing, it is suggested injecting nanoparticles solution as pad fluids. The process shows as Figs. 11–12 present.
6. Summary and conclusions Unconventional reservoirs, such as shale gas, tight gas and tight oil, have pore sizes in the range of 1–300 nm (Wu et al., 2014). The tight formation will lead a low permeability in microdarcy to nanodarcy. Compared with hydraulic fracturing, CO2 fracturing has following advantages: in fracturing, CO2 molecules could permeate into the nano-pores in matrix for its low viscosity and density; with high compressibility, liquid phase CO2 can offer more energy to fracturing; it avoids the problems such as formation damage, water blocking, etc., which were caused by water flow back; CO2 can improve the production by competing adsorption with CH4. But the CO2 fingering will lead a result of low drainage in fracturing. To improve the fracturing effect, nanoparticles are applied as additives in CO2 fracturing. We conducted an experiment to evaluate the effect of nanoparticles. With the CT scanning technology, the details of CO2 flowing in the core were observed. The results show that with nanoparticles, the propagation of CO2 displacement front is altered. The CO2 finger is disappeared and the displacement front become more uniform. In addition, there is higher pressure drop with the presence of nanoparticles during CO2 injection. The results have been discussed that a CO2 droplets foam is generated at the CO2 front to keep the displacement uniform. The observations described prove that nanoparticles can improve the CO2 fracturing effect in unconventional reservoirs. The results of experiment suggest an optimized protocol of nanoparticle application in CO2 fracturing, that the nanoparticle solution should be injected as pad fluids in the fracturing.
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Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
An experimental study on application of nanoparticles in unconventional gas reservoir CO2 fracturing Yanzun Li a,b,n, David DiCarlo b, Xiangfang Li a, Jiali Zang a, Zhennan Li a a b
China University of Petroleum, Beijing, China University of Texas at Austin, USA
art ic l e i nf o
a b s t r a c t
Article history: Received 14 March 2015 Received in revised form 23 April 2015 Accepted 11 May 2015 Available online 20 June 2015
Gas production from low permeability unconventional reservoirs is still a challenge to the world. Although hydraulic fracturing has been successfully applied in unconventional gas production, its limitations are obvious, such as formation damage, water blocking, low stimulating effect and the requirement of sufficient water. To avoid these problems, liquid CO2 has been pumped as a fracturing fluid into unconventional reservoirs. But as a consequence of low density and viscosity of super critical phase CO2 in the formation, CO2 fracturing suffers from low sweep efficiency that manifests as viscous fingering. So various additives have been applied to improve CO2 fracturing effect. This paper introduces a novel additive, nanoparticles, and presents an experiment to evaluate its effect on CO2 fracturing. In this paper, a core flooding experiments was conducted to simulate the fracturing process, in which liquid CO2 was injected into a core to drainage brine or nanoparticles solution. During the process, CO2 distribution and pressure drop were real-time measured with a modified medical CT scanner and pressure transducers. A significant difference is observed between with and without nanoparticles. The saturation files show that CO2 fingering was decreased and the drainage area was improved with the action of nanoparticles. Meanwhile, the CO2 injecting pressure raised, which implies that nanoparticles could offer higher pore pressure in fracturing. These observations suggest that a nanoparticle-stabilized foam is formed between CO2 and nanoparticle solution, which suppress the viscous instability. The results provide nanoparticles are effective to enhance CO2 fracturing. Also, this experiment suggests an optimized protocol of CO2 fracturing with nanoparticles in unconventional reservoir stimulate. & 2015 Elsevier B.V. All rights reserved.
keywords: Nanoparticles CO2 Fracturing Unconventional Gas Reservoir
1. Introduction Over past three decades, the success of shale gas production in U.S. has triggered an increasingly worldwide interest in these unconventional resources. According to U.S. Energy Information Administration (EIA), low permeability gas shale was estimated to hold 800 trillion cubic feet of recoverable natural gas. Economically feasible application of advanced hydraulic fracturing and horizontal drilling technologies in tight gas shale enabled U.S. to surpass Russia to become the top producer of natural gas since 2009. Other countries, such as China, Poland, also possess abundant amount of unconventional reservoir resources. EIA estimates China has 1115 Tcf of risked technically recoverable shale gas resources, making it an important resource for China's future energy demand. n
Corresponding author at: China University of Petroleum, Beijing, China. E-mail address: [email protected] (Y. Li).
http://dx.doi.org/10.1016/j.petrol.2015.05.023 0920-4105/& 2015 Elsevier B.V. All rights reserved.
Most unconventional reservoirs are developed by hydraulic fracturing treatments (Morales et al., 2011; Cheng, 2012; King and King, 2010; King, 2012). In unconventional reservoir fracturing, various fracturing fluids have been applied, such as foam-based fluids, water-based fluids and waterless fluids (Fisher and Warpinski, 2012; Carl Montgomery, 2013). At present, slick water is the mainstay fracturing fluid in unconventional reservoir stimulate. Slick water is fresh water treated with up to 5% potassium chloride by volume. Water fracturing lacks gel particles, therefore it leaves no residues or filter cakes behind, and produces less damage to fracture conductivity compared to massive hydraulic fracturing with gelled fluids (Terracina et al., 2001). However, there are many disadvantages associated with hydraulic fracturing operations. Firstly, huge volume of water is required in hydraulic fracturing which is difficult to achieve in water deficient areas. Secondly, formation damage would occur since a large quantity of aqueous fluid is injected into reservoirs during hydraulic fracturing. Another deficiency is that slick water cannot permeate into the nano-
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molecules have greater sorption affinity compared to methane molecules. Thus, another promising application for CO2 is CO2 injection for enhanced gas recovery (Eshkalak et al., 2014). Additionally several simulation studies had optimized CO2 injection process for EOR (Sondergeld et al., 2010; Yu et al., 2014). In CO2 injecting to the formation, the less dense and less viscous of CO2 will cause the poor sweep efficiency by viscous fingering and gravity over-ride (Bae and Irani, 1993; Rossen, 1996; Wagner and Weisrock, 1986). In CO2 fracturing, as same as CO2 storage, the viscosity fingers reduce the fracturing fluids drainage area. Recently, there are many researches about using nanoparticles emulsions to enhanced oil recovery (Kotsmar, 2010; Zhang et al., 2009, 2010) And nanoparticle will form a film between CO2 and brine, which uniform the displacement front to prevent the fingering (Grigg and Schechter, 1997; Aminzadeh et al., 2012a, b; Aminzadeh et al., 2013; Binks, 2002,, 2007; Binks et al., 2008; DiCarlo et al., 2011) In this paper, we conducted an experiment to demonstrate the effect of nanoparticles on sweep efficiency and proposed a protocol of CO2 fracturing. Fig. 1. CO2 fracturing process.
2. Methodology
Table 1 The permeability of shale. Eagle ford shale (Gong, 2013)
Fracture permeability (D) Matrix permeability (mD) n
0.04–0.2
Bakken shale (Cho et al., 2013)
3–8
0.02–0.8 10
4
1.31–7.24 10
Barnett shale (Loucks et al., 2009)* 0.1–18
4
0.02–3.2
Calculated based on the data from reference.
Table 2 The character of core. Diameter (cm) Boise sandstone 7.2
Length (cm)
Porosity (%) Permeability (mD)
30
28.8
900
Table 3 Relevant fluid properties: viscosity m, density ρ, and interfacial tension with respect to brine s.
μ (cP) ρ (Kg/m3) σ (mN/m)
Brine
5% Nano
CO2
1.1 1010 N/A
1.2 1040 N/A
0.08 792 24
pores and micro-pores for its high viscosity, which would limit the stimulated reservoir volume (SRV). Therefore, a proposed fracturing fluid in hydraulic fracturing of unconventional reservoirs is liquid CO2 (Gupta and Bobier, 1998; Yost et al., 1993). Fig. 1 shows the process of CO2 fracturing. Liquid CO2 is more active on extending micro-fractures and connected them during fracturing in shale than water and slick water (Fang et al., 2014). Among the benefits of using liquid CO2 in hydraulic fracturing is less flow back water that needs to be treated or permanently disposed of. In addition, shale formations are known to preferentially adsorb CO2 over CH4 as noted by several researchers (Jessen et al., 2008; Nuttal et al., 2005; Kang et al., 2011; Schepers et al., 2009; Heller and Zoback 2013; Ismail et al., Zoback). Kalantari-Dahaghi (2010) had reported the study of CO2-EGR and concluded that the process is feasible since CO2
In this experiment, Boise sandstone was used instead of shale stone to evaluate the nanoparticle's effect on CO2 fracturing volume. Shale could be seen as dual-porosity media, including matrix pore system and fracture system. In the flow model, for ultralow permeability of matrix, it assumes that gas only flowing in fracture system (Apaydin et al., 2012; Hudson et al., 2012; Josh et al., 2012). The permeability and pore size of Boise sandstone are as same as micro fracture and macro pores in shale, potentially having the same conduction (Table 1). Hence, sandstone could be the appropriate media to observe the CO2 distribution during the injection. The core is a cylinder that is 7.2 cm in diameter and 30 cm in length. The permeability of core is 900 mD, and porosity is 28.8% ( Table 2). In order to avoid CO2 corrosion, the rock sample was wrapped in a heat-shrinkable Teflon tube, 4 layers of aluminum foil, another layer of Teflon heat-shrinkable tube, and an AFLAS rubber sleeve before it was placed into an aluminum core holder. The Teflon layers provide a barrier to water, while the aluminum foil prevents CO2 diffusion to the AFLAS sleeve. The wetting phase as formation water is brine with 2 wt% NaBr. In the accumulator, the brine was pre-equilibrated with CO2 by injecting 100 ml of CO2 per liter of brine, into the brine accumulator over 5 h and letting the wetting fluid to equilibrate with CO2 for 48 h before usage. In this experiment, CO2 would be kept in liquid phase at 8.3MPa and 25 °C (room temperature). And CO2 was saturated with brine by injecting brine (20 ml of brine per liter of CO2) into the CO2 accumulator over 5 h and allowing CO2 and brine to equilibrate for 48 h before usage. The fluids properties are showed in Table 3. The nanoparticles used in this experiment are made by silicon and coated with polyethylene glycol (PEG), which prevents the aggregation and retention of nanoparticles. The diameter of nanoparticle could ranges from 5 nm to 20 nm. In this experiment we selected 5 nm nanoparticles as test objects. They are small enough to transport into micro-pores of shale stone, which contributes to generate more fractures in matrix. In experiments, the nanoparticle dispersion was diluted to 5 wt% with NaBr aqueous phase whose total salinity is 2 wt%. 3. Procedure Fig. 2 shows a schematic of our experiment set-up. In this
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Fig. 2. Schematic diagram of CO2 fracturing set-up.
Table 4 The sequence and fluids of horizontal experiment Exp no.
1
2
Fluid 1 Fluid 2
Brine CO2
Nano CO2
Fig. 5. The images of CO2 saturation distribution along the core which initial saturated with brine when CO2 injection.
Fig. 3. The curves of CO2 saturation distribution along the core which initial saturated with brine during CO2 injection.
Fig. 4. The curves of CO2 saturation distribution along the core which initial saturated with nanoparticles solution during CO2 injection.
experiment, first, the core was preloaded with brine/nanoparticles solution after it was placed in coreholder under vacuum overnight. Then one pore volume of liquid CO2 was injected into the core at 2.5 ml/min at 25 °C. After that, one pore volume of brine/nanoparticles solution was injected into the core until CO2 saturation stable. The system remained constant at 8 MPa with a back pressure regulator (BPR). The in-situ saturation was captured in real time by placing the core horizontally in a modified medical scanner, which scanned the whole core at 1 cm intervals. CT scanning measured the local density of the materials occupying each voxel; since CO2 is less dense than the brine or nanoparticle suspension the measured density can be converted to saturation by a linear interpolation between CT values of the core saturated with the brine (or nanoparticle suspension) and CO2 (Apaydin et al., 2012; Hudson et al., 2012). At the outlet, a scale was installed to measure the liquid that flowed out. Based on the effluent data, the CO2 saturation of core can be calculated. We carried out two experiments to estimate the effect of nanoparticles solution. One is the control experiment, in which the core was preloaded by 2 wt% brine. In the other experiment, the core was preloaded by 5 wt% nanoparticle solution. The fluids used in the experiment are displayed in Table 4.
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Fig. 6. The images of CO2 saturation distribution along the core.
Fig. 7. The images of CO2 saturation distribution along the core which was initially saturated with brine when CO2 injection.
Fig. 8. The images of CO2 saturation distribution along the core which was initially saturated with nanoparticles when CO2 injection.
4. Results In the control experiment, the core was preloaded by 2 wt% brine. Fig. 3 is the CO2 saturation distribution plots along the core at different PV of CO2 injection, which based on the CT scanning. The CO2 saturation curves of PV¼0.02, PV ¼0.05, PV¼ 0.1, PV¼ 0.15, shows the formation of fingers. In particular, we notice that in the front of finger, the CO2 saturation kept in a low level until the fingerings broking through at 0.15PV. After breaking through, the CO2 saturation started to increase along the core. It reached the maximum saturation to 0.35 at 1.0PV. Fig.4 shows the CO2 saturation distribution plots along the core at different PV with nanoparticles solution during CO2 drainage. The curves of PV ¼0.02–0.3 present the CO2 saturation profiles before the front of CO2 broking through. It shows that the front of CO2 was uniform with high saturation¼0.3. And the breaking through time was delayed to PV ¼0.35. After the CO2 broke through, the CO2 saturation didnot change. Fig. 5 shows the pressure drop files during CO2 drainage. We notice that both curves had the same slopes at early uptrend,
Fig. 9. CO2 flow in the core. (a) CO2 drainage without nanoparticles. (b) CO2 drainage with nanoparticles
which implied that the CO2 had to overcome the capillary force to flow into the core. After that, the different trends of the curves are displayed. In the control experiment, the pressure drop had slow descending with the CO2 saturation of core increasing before
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Fig. 10. CO2 transform in the core pores.
Fig. 11. CO2 fracturing without nanoparticles solution. (a) Inject normal Pad Fluids (b) Inject super critical CO2 as fracturing fluids
Fig. 12. CO2 fracturing with nanoparticles solution. (a) Inject nanoparticles solution as pad fluids. (b) Inject super critical CO2 as fracturing fluids.
fingers breaking through. And in the experiment with nanoparticles solution, the pressure drop still raised to 4 psi, which was 2.7 times more than that without nanoparticles. Also, the pressure drop files show the breaking through time of CO2 according with the saturation files' results. After CO2 broke through, the pressure drop dropped rapidly. With the CT data, we also drew the images of CO2 saturation of each scanning slice (Figs. 6–8). The images show more details about what has happened inside the core during CO2 drainage. In Fig. 7, liquid CO2 first appeared at the high permeability zone. It suggests that liquid CO2 mainly flow through and
accumulates at the high permeability channel. As a result, was dominated by the heterogeneity of rock. After CO2 broke through, CO2 spread gradually to displace more brine out. Images of the slices show that brine in the area with lower permeability was replaced by CO2, and the saturation raised in the area where was filled with CO2. Fig. 8 shows the images of CO2 saturation slices with the core saturated by nanoparticles solution. The different flow type is showed in the images. With the nanoparticles, liquid CO2 flow appears to be slug flow. with the front of CO2 is uniform. It is also observed that CO2 saturation is much higher in areas where in
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where CO2 swept, even in the low permeability area.
5. Discussion According to the results of CO2 drainage experiment with and without nanoparticles in sandstone core, an applicable protocol of CO2 fracturing can be discussed as follows:
(a) During CO2 injection, nanoparticles both increased the CO2 sweep efficiency and saturation. In the experiment, the effect of nanoparticles was present: the CO2 saturation increased by 0.1; and CO2 swept more area even in the low permeability zone. Figs. 3 and 4 are the saturation profiles of CO2. In Fig. 3, without nanoparticles' action, the saturation curves shows the finger spread fast and lead a low saturation in the core. But with nanoparticles, as shown in Fig. 4, the displacement front of CO2 is uniform and stable. Behind the front, a high saturation of CO2 is observed. The images of CT scanning (Figs. 7 and 8) give us more information of the CO2 distribution in the core. In Fig. 7, we notice the fingers are formed in high permeability zone. With less percolating resistance in high permeability zone, the CO2 finger spread fast and limit the saturation increase (Fig. 9a). After CO2 break though, the saturation of CO2 is still low. The different flow types are present in Fig. 8. The CO2 displacement front is uniform and moves forward like a piston (Fig. 9b). In the drainage process, CO2 also accumulates in the low permeability zone, where the pore size is smaller. In Table 3, it points that the fluid's viscosity is not changed by nanoparticles. And after the experiment, we find that there is few residual nanoparticles in the core after 3 PV brine flush. Nanoparticles are not absorbed on the surface of medium or aggregate together. So the nanoparticles does not act as changing viscosity or blocking the larger pore. Considering the wettability of nanoparticles, the results suggest that nanoparticle will coat CO2 droplets (Fig. 10) and form a kind of foam between the CO2 and brine (Fig. 9b) (Binks et al., 2008). The foam will reduce the viscosity fingering and overcome the influence of heterogeneity. ● (b) With the nanoparticle, CO2 fracturing can offered a higher pressure drop to improve the effect of fracturing. Fig. 5 shows the pressure drop during CO2 injection. The early uptrends of both curves present the same trend. In this stage, CO2 overcome the capillary force to enter the pore. After this stage, different trends of the pressure drop are observed. The curve without the effect of nanoparticles shows that following the saturation of CO2 increasing, the pressure drop slowly drop down till fingers break though. This could be explained by twophase relative permeability. But when the nanoparticle present in the experiment, the curve keeps raising after CO2 enters. It suggests that another flow resistance acts on the two-phase flow. Based on the above discussion, we know that nanoparticles will form a foam layer in the CO2 displacement front. This foam layer block the large pores and reduce the fingering, which offers the additional flow resistance. Fig. 5 shows the pressure drop is 1.5 times of the pressure drop without nanoparticles. It proves that nanoparticles will increase the CO2 pressure in the formation. That means comparing with fracturing without nanoparticles, the pore pressure can meet the formation fracturing pressure with less volume super critical CO2. It will generates more fractures in matrix to improve the formation permeability. ● (c) Nanoparticles could flow into the nano-pores of matrix with super critical CO2 to improve the fracturing effect.
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In hydraulic fracturing, it will generates a larger number of micro-fractures in matrix (Krevor et al., 2012; Kianinejad et al., 2014; Gomaa et al., 2014; Xiao et al., 2011). When the formation pressure drops, the micro-fractures will close and the proppants cannot flow into the pores. The closure of these fractures brings unexpected problems, such as low effective stimulation and poor production performance. The diameter of nanoparticles is nano-size, which allows them to flow into nano-pores in matrix of shale. During liquid CO2 is pumped into the formation, nanoparticles will gather on the CO2 front. Then they are pushed into the pores of matrix, where the normal size proppants cannot reach. The nanoparticles will play a role of proppant in fracturing. It was reported that small size additives could improve the flow of fracturing fluid into micro-fractures, which tend to reduce the breakdown pressure and enhance fracture complexity (Cipolla et al., 2009). ● (d) The results of experiment suggest an optimized protocol of nanoparticle application in CO2 fracturing. The previous studies have pointed when injecting CO2 into the core preloaded by nanoparticles solution, nanoparticles would gather on the surface between CO2 and brine. Otherwise, nanoparticles would distract in the brine or super critical CO2. As the discussion above, nanoparticles would play its role as coating the CO2 droplets to form a foam layer at the CO2 front. In this experiment, the significant effect of nanoparticles was observed. It suggests the nanoparticles should be pumped into the formation before CO2 injection. In the practical CO2 fracturing, it is suggested injecting nanoparticles solution as pad fluids. The process shows as Figs. 11–12 present.
6. Summary and conclusions Unconventional reservoirs, such as shale gas, tight gas and tight oil, have pore sizes in the range of 1–300 nm (Wu et al., 2014). The tight formation will lead a low permeability in microdarcy to nanodarcy. Compared with hydraulic fracturing, CO2 fracturing has following advantages: in fracturing, CO2 molecules could permeate into the nano-pores in matrix for its low viscosity and density; with high compressibility, liquid phase CO2 can offer more energy to fracturing; it avoids the problems such as formation damage, water blocking, etc., which were caused by water flow back; CO2 can improve the production by competing adsorption with CH4. But the CO2 fingering will lead a result of low drainage in fracturing. To improve the fracturing effect, nanoparticles are applied as additives in CO2 fracturing. We conducted an experiment to evaluate the effect of nanoparticles. With the CT scanning technology, the details of CO2 flowing in the core were observed. The results show that with nanoparticles, the propagation of CO2 displacement front is altered. The CO2 finger is disappeared and the displacement front become more uniform. In addition, there is higher pressure drop with the presence of nanoparticles during CO2 injection. The results have been discussed that a CO2 droplets foam is generated at the CO2 front to keep the displacement uniform. The observations described prove that nanoparticles can improve the CO2 fracturing effect in unconventional reservoirs. The results of experiment suggest an optimized protocol of nanoparticle application in CO2 fracturing, that the nanoparticle solution should be injected as pad fluids in the fracturing.
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