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Combining carbon dioxide and strong emulsifier in-depth huff and puff with DCA microsphere plugging in horizontal wells of high-temperature and high-salinity reservoirs
Journal of Natural Gas Science and Engineering 42 (2017) 56e68
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Combining carbon dioxide and strong emulsifier in-depth huff and puff with DCA microsphere plugging in horizontal wells of hightemperature and high-salinity reservoirs Chang-chun Yang a, b, *, Xiang-an Yue a, b, Chao-yue Li a, b, Rui Xu a, b, Jie-mai Wei a, b a b
Key Laboratory of Petroleum Engineering, Ministry of Education, China University of Petroleum, Beijing, 102249, PR China College of Petroleum Engineering, China University of Petroleum, Beijing, 102249, PR China
a r t i c l e i n f o
a b s t r a c t
Article history: Received 16 October 2016 Received in revised form 20 February 2017 Accepted 26 February 2017 Available online 1 March 2017
The profile control and water shutoff are still considered as technical problems for high-temperature and high-salinity reservoirs. A composite technique combining carbon dioxide and strong emulsifier in-depth huff and puff with water shutoff in the horizontal wells of high-temperature and high-salinity reservoirs was proposed. The composite technique comprised a strong emulsifier technique, a water shutoff agent technique, and technical injection of working fluid slug. The strong emulsifier technique included emulsifier screening. The ability of strong emulsifier served as the performance index. The strong emulsifier had two roles. When the strong emulsifier reached the oil, the entire system could be emulsified to activate the plugging system in situ and in real time. During the migration of oil and water, the emulsion system could improve volumetric sweep efficiency and microscale displacement efficiency. Carbon dioxide had a good emulsifying capability. The water shutoff agent technique included research on the high-temperature resistance and high-salinity resistance of polymer microspheres. The residual resistance coefficients of positive injection and back injection of polymer microspheres were still greater than 2. The working fluid included the slug of the system of polymer microspheres, the slug of the strong emulsifier and the slug of the carbon dioxide. Three kinds of slugs could improve volumetric sweep efficiency and microscale displacement efficiency during production. The key process of the proposed technique was the sequential injection of carbon dioxide and the strong emulsifier into the producer well of horizontal well. Upon injecting of polymer microspheres of the water shutoff agent, the microspheres aggregated to physical plugging and bridging by the effect of covalent bonds on one another after reaching the deep reservoir. The carbon dioxide and strong emulsifier were shut by the microspheres in the high-permeability formation. When water (bottom water, edge water, or injected water) approached the oil well along the high-permeability zone, the carbon dioxide and strong emulsifier would be carried by the water into the middle-permeability and low-permeability zone with higher oil saturation during production. Optimizing the injection method of the working fluid slug, a composite technique that combined carbon dioxide and a strong emulsifier with polymer microspheres was also proposed. Laboratory results showed that the rate of enhanced oil recovery increased by 38.50% based on water flooding recovery (10.00%) by using carbon dioxide in-depth huff and puff and polymer microsphere plugging after the first round. The rate of enhanced oil recovery increased by 17.75% based on the water flooding recovery of the first round by using carbon dioxide and strong emulsifier in-depth huff and puff and polymer microsphere plugging. In this paper the results of physical simulation experiments further prove that combining carbon dioxide and strong emulsifier in-depth huff and puff with divinylbenzeneco-acrylamide (DCA) microsphere plugging is a potential technical direction for controlling water cut and increasing oil recovery in horizontal well of high-temperature and high-salinity reservoirs. © 2017 Elsevier B.V. All rights reserved.
Keywords: High-temperature and high-salinity Horizontal well Carbon dioxide Strong emulsifier Polymer microspheres Huff and puff and water shutoff
1. Introduction * Corresponding author. Key Laboratory of Petroleum Engineering, Ministry of Education, China University of Petroleum, Beijing, 102249, PR China. E-mail address: [email protected] (C.-c. Yang). http://dx.doi.org/10.1016/j.jngse.2017.02.036 1875-5100/© 2017 Elsevier B.V. All rights reserved.
Few studies have been conducted on the implementation trials of stabilizing oil production and controlling the water in horizontal wells of high-temperature and high-salinity reservoirs (AlQuraishi
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et al., 2011; Puerto et al., 2010; Dai et al., 2010; Alkhaldi et al., 2011; Chen et al., 2013). The Shizigou reservoirs of the Qinghai Oilfield comprises low-temperature and ultra-high-salinity reservoirs for domestic production (Zhao et al., 2005; Mo et al., 2011). The Zaoyuan reservoirs of Dagang Oilfield has low-high-temperature and low-high-salinity reservoirs (Li et al., 2014). The lowpermeability reservoirs of the Changqing Oilfield has lowtemperature and medium-salinity reservoirs (Yu et al., 2011). The Jin-45 Fault Block reservoirs of the North China Oilfield has medium-high-temperature and medium-high-salinity reservoirs (Ren, 2008). The Gasikule E13 reservoirs of Qinghai Oilfield has highhigh-temperature and ultra-high-salinity reservoirs (Yang et al., 2013). The eastern Wenliu Block 25 reservoirs of Zhongyuan Oilfield has medium-high-temperature and high-high-salinity reservoirs (Lou et al., 2012). The Lunnan reservoirs of Tarim Oilfield has high-high-temperature and ultra-high-salinity reservoirs (Yang et al., 2014). The clastic rock reservoirs of Tahe Oilfield has highhigh-temperature and ultra-high-salinity reservoirs (Wu et al., 2013). Profile control and water shutoff of the above reservoirs have been implemented, and various technical have had different effects. No further reports have been presented on the continuous promotion and large-scale application of these technologies. Thus, profile control and water shutoff are still considered as technical problems for high-temperature and high-salinity reservoirs. Water-plugging techniques of oil wells have traditionally been used to improve volumetric sweep efficiency; however, they do not improve microscale displacement efficiency (Dai et al., 2005). A new composite technique combining carbon dioxide and strong emulsifier in-depth huff and puff with water shutoff in horizontal wells was proposed in this study to utilize adequately the advantages of each technique. The composite technique included a strong emulsifier technique, a water shutoff agent technique, and technical injection of working fluid slug. The key process of the proposed technique was the sequential injection of carbon dioxide and the strong emulsifier into the oil well of the horizontal well. When injecting divinylbenzene-co-acrylamide (DCA) microspheres of the water shutoff agent, the DCA microspheres aggregated to physical plugging and bridging by the effect of covalent bonds on one another after reaching the deep reservoirs. The carbon dioxide and strong emulsifier would be shut by the DCA microspheres in the high -permeability formation (Kashiwabara et al., 1995; Tuncel &Piskin, 1996). When water (bottom water, edge water, or injection water) approached the oil well along the high-permeability formations, the carbon dioxide and strong emulsifier would be carried by the water into the middle-permeability and lowpermeability formations with higher oil saturation during the production. The strong emulsifier had a dual role. When the strong emulsifier contacted with the oil, the entire system could be emulsified to activate the plugging system in situ and in real time (Ghosh and Rousseau, 2011; Zeidani et al., 2008; Kassim et al., 2002; Buret et al., 2009). In the process of the migration of oil and water, the emulsion system could improve volumetric sweep efficiency and microscale displacement efficiency. Carbon dioxide emulsified effectively enough to improve volumetric sweep efficiency and microscale displacement efficiency, thereby enhancing oil recovery under the interaction of the plugging agent of DCA microspheres and the plugging system of the strong emulsifier. 2. Screening emulsifying capability of strong emulsifier 2.1. Emulsion plugging mechanism Strong emulsifiers have a good emulsifying capacity. When a strong emulsifier makes contact with oil, the entire system can be emulsified to form an emulsified zone of profile control and oil
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displacement and to activate a plugging system in situ and in real time. The viscosity of an emulsifying agent should below, and it can be injected into the low-permeability cores to make contact with the oil to form an emulsion. The emulsion first enters the macropores that have relatively low resistance. If the size of the emulsion droplets is smaller than the pore size, then the droplets can flow smoothly through the pores. If the particle diameter of the emulsion is larger than the pore size or if they are condign, then plugging can occur in the pores. The subsequent fluid will generate a microscopic flow around the pore entrance. The mechanism of emulsion plugging is shown in Fig. 1 (a). When a larger pore is plugged by larger droplets of the emulsion, the subsequent fluid will selectively flow through the pore that has either relatively less resistance or a small size. The particle size distribution of emulsion droplets must be in the second largest scale to plug the abovementioned pore. The subsequent fluid will selectively flow through the pore that has a relatively smaller size. Therefore, large droplets of the emulsion plug larger pores, whereas small droplets of the emulsion plug smaller pores to form a self-adaptive plugging process. The macro performance of the preceding process shows that the emulsion droplet plugs high-permeability layer so that subsequent fluid selectively migrates into the low-permeability layer that has a smaller pore size. Thus, the residual oil in lowpermeability layer is swept and displaced. When the number of the emulsion droplets is high, numerous droplets flow through the pores and plug the pore simultaneously even if the diameter of a droplet is smaller than the pore size of the porous medium (Zhao et al., 2011; Ambrosone et al., 2007; Tzoumaki et al., 2011; Vashisth et al., 2010; Nesterenko et al., 2014). The mechanism of emulsion plugging is shown in Fig. 1 (b). 2.2. Injection and emulsifying capability The strong emulsifier, which was named as HA, was screened by ultrasonic emulsification. The injection and emulsifying capability of HA were evaluated using an artificial homogeneous columnar core with a diameter of 2.5 cm and length of 30 cm. The permeability of an artificial homogeneous columnar core simulated the permeability of the oilfield matrix. The gas permeability was 300 103 mm2. Oil and brine samples were collected from a domestic oilfield. The salinity of simulated water was 269,000 mg/L. The experimental temperature was simulated at a target reservoir temperature of 115 C. The temperature of constant temperature box was set. The artificial homogeneous columnar core was placed in the holder. The experimental apparatus scheme was shown in Fig. 2. Each device was connected. The more detailed description of each step of procedure and its sequence were as followings: 1 The saturation of oil of the artificial homogeneous columnar core. The core need be in a vacuum by vacuum pump, the saturation of formation water and the saturation of oil. Depending on the amount of saturated water and oil, pore volume (PV) and initial oil saturation were calculated. The pore volume (PV) was 20.85 mL and initial oil saturation was 71.9%. 2 The phase of water displacing oil. The flooding speed of the ISCO advection pump was 0.34 mL/min (1 m/d). The distribution location of the measurement pressure points of the core was 0, 5, 10, 15, and 20 cm and was monitored in real time. The results were shown in Fig. 3. The water flooding could not be terminated until the produced fluid did not contain oil and the water cut reached 100%. The simulated water injected the amount of 1.5 PV. 3 The phase of the injection HA. The flooding speed was 0.34 mL/ min (1 m/d). The pressure distribution along the cylindrical core was monitored in real time. HA injected the amount of 0.95 PV.
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Fig. 1. Mechanism of emulsion plugging. ((a): If the particle diameter of the emulsion droplet is larger than the pore size or if they are condign, then plugging can occur in the pores; (b): When the number of the emulsion droplets is high, numerous droplets flow through the pores and plug the pore simultaneously even if the diameter of a droplet is smaller than the pore size of the porous medium).
Fig. 2. The experimental apparatus scheme of injection and emulsifying capability.
4 The phase of subsequent water flooding. The flooding speed was 0.34 mL/min (1 m/d). Subsequent water flooding injected the amount of 1.31 PV. The appearance of produced liquid and the microstructure at different injection stages were shown in Fig. 4 and Fig. 5. When the water flooding injected an amount of 1.3 PV, water cut reached 100% in the test tubes and a passage of water channeling
Fig. 3. Pressure distribution with PV each measurement point at different stages of injection.
was formed. When injecting strong emulsifier, the strong emulsifier still flowed into the passage of water channeling due to the low saturation in the passage of water channeling. When the strong emulsifier injected an amount of 1.7 PV, the oil-water interface of the produced liquid was clear in the first test tube (Fig. 4 (a)) and did not form an emulsion system. The pressure distribution decreased in each measuring point along the cylindrical core. The main reason was that the factor of reducing the interfacial tension between the oil and water was dominant. As the amount of injected strong emulsifier increased, the produced fluids formed an increasingly obvious emulsion system in the second test tubes. As shown in Fig. 5 (a), the microstructure of the emulsion system was observed by using an optical microscope, and the average particle size of the emulsion droplets was 3.25 mm. When the strong emulsifier injected an amount of 1.1 PV, the strong emulsifier swept the entire water channel. During the subsequent water flooding, pressure distribution showed an increasing trend at each measuring point. The strong emulsifier was diluted by formation water, and the molecules of the strong emulsifier desorbed from the rock surface. The reducing pressure and increasing injection of the emulsion system were only conducted as HA was injected. Fig. 4 (c) and Fig. 5 (b) showed that the produced fluids of the subsequent water flooding formed an obvious emulsion system in the test tubes. However, the average particle size of the emulsion droplets increased to 3.70 mm. Given the Jamin effect and the aggregation effect of emulsion droplets, the pressure distribution increased in each measuring point along the cylindrical core in the stage of subsequent water flooding. This conclusion indirectly confirmed the existence of the aforementioned mechanism.
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Fig. 4. Appearance of produced liquid at different stages of injection.
Fig. 5. Microstructure of produced liquid at different stages of injection.
3. DCA microspheres of the plugging agent 3.1. Design ideas and microstructure of DCA microspheres To achieve a better plugging effect, the requirements of the following special characteristics are proposed for the material of the deep profile control and water shutoff: “injection in reservoirs,” “better plugging effect,” “better migration,” and “long life.” In “injection in reservoirs,” the materials must have good stability in water. In “better plugging effect,” the microspheres implement bridging and plugging through the covalent bonds between the surface molecular chain of the microspheres in the pore and throat to generate flow resistance. In “better migration,” polymer microspheres can break, migrate, and enter the deep reservoir under certain conditions of pressure. In “long life,” the material degradation of the microspheres does not occur under the conditions of high temperature and high salinity. Nanometer and micrometer DCA microspheres were synthesized by emulsion polymerization based on the requirements listed above (Sun et al., 2006; Lin et al., 2011; He et al., 2012, 2015). Nanometer and micrometers DCA microspheres were synthesized by emulsion polymerization based on the above technical ideas. The scanning electron microscopy (SEM) photograph of the microstructure of microspheres and crushed microspheres is shown in Fig. 6 (a)-(c). Fig. 6 (a)-(b) showed that the particle size of the DCA microspheres was 25 mm, and that the DCA microspheres were hollow. In line with the performance requirements of “injection in reservoirs,” the thickness of the cross-linked polymer layer was 12.79 mm. The initial judgment of the DCA microspheres showed that they had
good suspension in line with the performance requirements of “injection in reservoir”. The shells of the microspheres comprised nanoporous materials. The emulsion droplets were in oil-in-water form during the pre-emulsification phase. As the reaction continued, water resulted in extremely small solvation of the oligomers of the excluded acrylamide (AM) and those containing AM structural units. Compared with the condition without water, the length of the critical precipitation chain was basically unchanged. Thus, the oligomers of the excluded AM and those containing an AM structural unit first precipitated from the solution and participated in nucleating during the reaction. Two types of oligomers contained more structural units of divinylbenzene (DVB). Thus, the formation of putamen was closer. However, with the progress of the reaction, the oligomer, which did not precipitate and later precipitated AM structural units or more pure AM and monomer free radicals, was constantly trapped by the microsphere core from the solvent to achieve the particle size growth of the microspheres. These trapped oligomers had longer molecular chains, and fewer DVB structural units. The oligomers could not be closely integrated with the putamen. Thus, the formation of microspheres ultimately had a close putamen and a loose shell. As shown in Fig. 6 (c), the shell surface had the structure of the hydration layer of an AM segment. 3.2. Particle size and distribution of DCA microspheres Size distribution is the most basic characterization of polymer microspheres. The particle size and distribution of DCA microspheres were measured by using a Mastersizer laser particle size analyzer, as shown in Fig. 7.
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Fig. 6. SEM photograph of microstructure of DCA microspheres.
The experimental data were fitted by the following normal distribution function:
" f ðdÞ ¼ a1 exp
d b1 c1
2 # (1)
Where f ðdÞ is the normal distribution density, a1 is the shape parameter, b1 is the mean and is higher than or equal to 0, and c1 is the standard deviation. The fitting results show that the values of a1 , b1 , and c1 were 11.5, 490.9, and 274.1, respectively. The R2 value of the correlation coefficient was 0.912. Accordingly, the particle size and distribution of DCA microspheres were unimodal and approximately normal distribution. The particle size of the DCA microspheres ranged from 0.7 mm to 50 mm. For sandstone reservoirs, the porosity distribution ranged from 12.5% to 20%, and the permeability distribution ranged from 50 10 3 mm2 to 1600 10 3 mm2. According to the following Equation (2) (Dullien, 1979), the average diameter of the pore throat ranged from 2.8 mm to 20 mm.
sffiffiffiffiffiffiffi 8K r¼ f
(2)
Where r is the average diameter of the pore throat in micrometers, mm; K is the permeability in Darcy, and f is the porosity and is a dimensionless coefficient. The above results showed that the particle size of the DCA microspheres and the average diameter of the pore throat were at the micron level. A certain matching relationship thus existed between the two variables. 9.00
Distribution density//%
8.00 7.00 6.00
Fitting curve
5.00
Experimental curve
4.00 3.00 2.00 1.00 0.00 1
10 Size/μm Fig. 7. Particle size and distribution of DCA microspheres.
100
3.3. Injection and plugging capability of DCA microspheres To determine the plugging capability of DCA microspheres for large pores and cracks, the injection and plugging capability at 115 C were evaluated by using an artificial homogeneous columnar core with a diameter of 2.5 cm and a length of 30 cm. The gas permeability was 1600 10 3 mm2. The concentration of the DCA microspheres was 1000 mg/L. The diameter distribution of the DCA microspheres was applied to the experiment, as shown in Fig. 8. The microstructure of the DCA microspheres when the original liquid and produced liquid were injected is shown in Fig. 9 (Tang et al., 2004; Yang et al., 2016; Vasquez et al., 2003). To qualitatively determine the migration distance of the DCA microspheres in the homogeneous columnar core, the columnar core was cut into thin slices at different positions, and the end surface was observed via SEM. The morphologies of the DCA microspheres at different positions were shown in Fig. 9 (a)-(c). As shown in Figs. 8 and 9, the produced fluid contained a small amount of DCA microspheres. The majority of DCA microspheres remained inside the core pores and was detained. As a result, the DCA microspheres had a better injection capability. The positions of the end surface at 1.5, 5, and 10 cm were located at the core, and the DCA microspheres could be observed. This phenomenon further illustrated that the DCA microspheres could migrate into the pores deeply. The plugging capability of DCA microspheres was characterized by a residual resistance coefficient and was calculated with the following Equation (3):
Rk ¼
K3 Q mL=ADp3 Dp1 ¼ ¼ K1 Q mL=ADp Dp3
(3)
1
Where Rk is the residual resistance coefficient; K1 is the permeability of the core before injecting microspheres, Darcy; K3 is the permeability of the core after injecting microspheres, Darcy; Dp1 is the differential pressure of adjacent measurement points when the core permeability is measured in the stage of water flooding, 101 MPa; Dp3 is the differential pressure of adjacent measurement points when the permeability is measured in the stage of subsequent water flooding, 101 MPa; Q is the flowing rate of the fluid through the core, cm3/s; A is the cross-sectional area of the core, cm2; L is the length of the core, cm; m is the viscosity of the fluid through the core, mPa$s. After evaluating the injection and plugging capability, the long core holder was reversed to conduct aback injection experiment that could further verify the feasibility of water shutoff. The result is shown in Fig. 10. The microspheres had a stable plugging capability for migrating into all the measure points, thereby achieving deep plugging. The residual resistance coefficients of positive injection and back injection were still greater than 2; thus, the DCA
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Fig. 8. Microstructure of DCA microspheres in injection original liquid and produced liquid.
Fig. 9. Morphologies of DCA microspheres at different positions.
microspheres had strong deep plugging in reservoirs and demonstrated their potential for water shutoff. The microspheres mainly generated flow resistance by bridging and plugging through the covalent bonds between the surface molecular chain of the microspheres in the pore and throat. 4. Composite methods of controlling water and increasing oil of horizontal wells The composite methods of using carbon dioxide in-depth huff and puff after DCA microsphere plugging and using carbon dioxide and strong emulsifier in-depth huff and puff after DCA microsphere
plugging were researched (Inamullah et al., 2016). 4.1. Physical simulation system and establishing a model of horizontal wells A flooding experiment was simulated in a pressure chamber to verify the feasibility and effectiveness of each technique. The temperature resistance and pressure resistance of the pressure chamber were 150 C and 60 MPa, respectively. The physical simulation system of the horizontal well comprised the power equipment of displacement, a pressure chamber with high temperature and high pressure, a physical model, an
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Residual resistance coefficient
10000.00
placed in the middle of the top of the core. The length of the horizontal well was 30 cm, and the diameter was 2 mm. The acquisition device of pressure data included pressure sensors and a computer terminal. The pressure change was measured in real-time by using pressure sensors during the experiment. The data from the pressure sensor were automatically recorded and saved by the professional software of the computer terminal. The collection device of the produced fluid was connected to the sample tube, to measure the volume of the produced fluids.
positive injection
1000.00
back injection
100.00
10.00
4.2. Research methods on the distribution of the remaining oil and the sweep scope of water flooding
1.00 0
5
10
15
20
25
30
Distance along the core/cm Fig. 10. Residual resistance coefficient change with the distance along the core.
acquisition device of pressure data, and a collection device for produced fluid, as shown in Fig. 11. The power equipment of displacement comprised a constantpressure and constant-flow pump, and the intermediate container to provide power for the experiments. The physical model constituted the bottom water (edge water or injected water) systems, a planar heterogeneous core, and a model of horizontal well. The core, which was independently developed in a laboratory, was used in the physical simulation experiments. The length, width, and height of the core were 30, 3, and 7 cm, respectively. The change in the permeability simulated the planar heterogeneity in the direction of the horizontal well. The experimental model included three parts in the direction of the horizontal well, and the length ratio was 2: 1: 2. The intermediate zone of the model had a high permeability of 1600 10 3 mm2. Both sides of the model had a low permeability of 300 10 3 mm2. The horizontal well was
The water saturation within the model was measured to obtain the distribution of the remaining oil and the sweep scope of water flooding. The crude oil was generally not electrically conductive in the rock matrix and the pores of the reservoir. When the connectivity of the pore and the salinity of formation water were constant, the value of the testing resistance depended on the water saturation of the fluid in the pore. Therefore, the resistance value within the model reflected the ratio of the content of oil and water. A relationship between the contents of water saturation and the resistance value was established. A total of 21 pairs of electrodes were arranged in the model of planar heterogeneity. Each pair of electrodes was placed on both sides of the model to measure the value of the instantaneous resistance. The resistance-measuring points of planar heterogeneity were distributed as shown in Fig. 12. The saturation measuring device could automatically record the resistance value measured by each pair of electrodes during the experiment. The time interval of the measurement was set depending on the specific situations. After the experiment, the water saturation of the 21 pairs of measuring points was obtained by the standard relationship between water saturation and the
Fig. 11. Schematic diagram of experimental devices of horizontal wells in bottom water reservoir.
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Fig. 12. Distribution of resistance-measuring points of planar heterogeneity.
resistance value. The distribution of saturation data of measuring points was discrete in space. The distribution characteristics of the saturation could not be characterized visually. The continuous distribution of saturation data was obtained by Kriging interpolation. The saturation distribution on the core was researched using these data to draw the contour-map of the saturation. The laboratory results were shown in Fig. 17 and Fig. 21.
Fig. 13. Design mechanism of the amount of each slug.
4.4. Method of carbon dioxide in-depth huff and puff and DCA microsphere plugging 4.3. Design of the amount of each slug The design mechanism of the amount of each slug, which included carbon dioxide, strong emulsifier HA, and DCA microspheres, in reservoirs is shown in Fig. 13. The view of design mechanism included front view and left side elevation view. The amount of each slug was designed with reference to Equations (4) (5), and (6). The amounts of carbon dioxide, strong emulsifier HA, and DCA microspheres were optimized and to 0.18, 0.07, and 0.11 PV, respectively.
Q0 ¼ bh2 $tg q 2 $Lb $f
(4)
Q1 ¼ b1 h21 h22 $tg q 2 $Lb $f =
(5)
Q2 ¼ b2 h22 $tg q 2 $Lb $f
(6)
=
=
where Q0 is amount of the slug of carbon dioxide by the volume, m3; Q1 is amount of the slug of strong emulsifier HA by the volume, m3; Q2 is amount of the slug of DCA microspheres by the volume, m3; b is inter-porosity flow parameter of carbon dioxide; b1 is interporosity flow parameter of strong emulsifier HA; b2 is interporosity flow parameter of DCA microspheres; h is injection height of carbon dioxide, m; h1 is injection height of strong emulsifier HA, m; h2 is injection height of DCA microspheres, m; q is the break though angle of the inter-porosity flow parameter; Lb is the width of the inter-porosity flow parameter, m; f is the porosity.
The following are the experimental major steps on the method of carbon dioxide in-depth huff and puff and DCA microsphere plugging: evacuation, saturation with brine, and injection with oil were implemented by the planar heterogeneity. The experiment was completed after the water cut reached 98% in the bottom water flooding, edge water flooding, or injected waterflooding. The injection amount of the carbon dioxide slug, which was the agent of in-depth huff and puff, was 0.18 PV. After the horizontal well was shut in for 24 h, the injection amount of the DCA microsphere slug was 0.11 PV. Finally, the slug of fresh water, which was the displacement fluid, was injected. The model of planar heterogeneity stimulated the production of bottom water reservoirs in horizontal well. The mechanism of the carbon dioxide in-depth huff and puff and DCA microsphere plugging was shown in Fig. 14. The water cut and oil recovery change with PV on the method of carbon dioxide in-depth huff and puff and DCA microsphere plugging was shown in Fig. 15. The appearance of produced liquid at different injection stages was shown in Fig. 16. The distribution of remaining oil and the sweep scope of water flooding at bottom water flooding stage before the deep plugging and the puff stage of carbon dioxide after the deep plugging were shown in Fig. 17. Fig. 15 showed that the rate of enhanced oil recovery reached 10% at the bottom water flooding stage. Based on the oil recovery of bottom water flooding, the rate of enhanced oil recovery increased by 38.50%, and its effect was obvious in the stages of puff of carbon dioxide after DCA microsphere plugging. The appearance of the produced liquid was clearly distinguished at the different bottom water flooding and puff stages of carbon dioxide. The produced liquid presented significant emulsification at the stage of puff of carbon dioxide in Fig. 16. The crude displacement with carbon
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Fig. 16. Appearance of produced liquid at different stages of injection.
Fig. 14. Mechanism of method of carbon dioxide in-depth huff and puff and DCA microsphere plugging.
dioxide enhanced the oil recovery, and this conclusion verified that the emulsion was an important mechanism in enhancing oil recovery. The DCA microspheres flowed into the high-permeability layer preferentially at 1600 103 mm2. The chain of the AM molecule of the DCA microsphere surface was bridged and blocked in the pore constriction through a covalent bond. The shell of the microspheres had nanometer-sized pores. These shells absorbed a small amount of water and exhibited weak swelling properties in producing flow resistance. Fig. 17 (a) showed the distribution of remaining oil and sweep scope at bottom water flooding stage before DCA microsphere plugging. The blue color in the red circle represented the sweep scope at bottom water flooding stage. The sweep scope was small at
Fig. 15. Water cut and oil recovery change with PV on method of carbon dioxide indepth huff and puff and DCA microsphere plugging.
bottom water flooding stage. Fig. 17 (b) showed distribution of remaining oil and sweep scope of bottom water flooding at the stage of puff of carbon dioxide after DCA microsphere plugging. The blue color in the red circle represented the sweep scope at bottom water flooding stage. The sweep scope plugging became larger remarkably at the stage of puff of carbon dioxide after DCA microsphere. Fig. 17 (b) showed that the sweep volume at the bottom water flooding stage before deep plugging was much larger than that at the puff stage of carbon dioxide after the deep plugging. The injected bottom water subsequently flowed into the middle- and low-permeability zones (300 10 3 mm2) on both sides of the model; these zones were not involved in starting the residual oil at the puff stage of carbon dioxide after the deep plugging. The improving sweep volume was an important mechanism in enhancing oil recovery. Fig. 14 (b) showed the mechanism and technical idea of method of carbon dioxide in-depth huff and puff and DCA microsphere plugging. Fig. 14 (b) showed that the mechanism and technical idea were hypothetical. The mechanism and technical idea of carbon dioxide in-depth huff and puff and DCA microsphere plugging is verified in Fig. 17 (b). 4.5. Method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging The following are major steps in carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging. Evacuation, saturation with brine, and injection with oil were implemented by the planar heterogeneity. The experiment was ended after the water cut reached 98% in bottom water flooding, edge water flooding, or injected water flooding. The injection mount of the carbon dioxide slug, which was the agent of in-depth huff and puff, was 0.18 PV. After the horizontal well was shut in for 24 h, the injection amount of the slug of strong emulsifier was 0.07 PV. The injection amount of DCA microsphere slug was 0.11 PV. Finally, the slug of fresh water, which was the displacement fluid, was injected. The model of planar heterogeneity simulated the production of bottom water reservoirs in the horizontal well. The mechanism of the carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging was shown in Fig. 18. The water cut and oil recovery change with PV when using carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging was shown in Fig. 19. The appearance of the produced liquid at different injection stages was shown in Fig. 20. The distribution of the remaining oil and the sweep scope of water flooding at the bottom water flooding stage before deep plugging and the puff stage of carbon dioxide and strong emulsifier after deep plugging were shown in Fig. 21. When the injected strong emulsifier made contact with the
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Fig. 17. Distribution of remaining oil and sweep scope of bottom water flooding at the different stages.
residual oil, an emulsion system was formed for temporary plugging. The emulsion system might prevent the subsequent injection of the DCA microspheres from being contaminated by the middlepermeability and low-permeability zones in the horizontal well in Fig. 18. Fig. 19 showed that based on the oil recovery of bottom
Fig. 18. Mechanism of method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging.
water flooding, the rate of enhanced oil recovery increased by 38.50% at the stage of puff of carbon dioxide after DCA microsphere plugging. Based on the puff stage of carbon dioxide after DCA microsphere plugging, the rate of enhanced oil recovery increased by 17.75% at the stage of carbon dioxide and strong emulsifier indepth huff and puff and DCA microsphere plugging. The appearance of produced liquid was clearly distinguished at different bottom water flooding and puff stages of carbon dioxide and strong emulsifier. The produced liquid exhibited considerable emulsification at the puff stage of carbon dioxide and strong emulsifier in Fig. 20. This phenomenon verified that the emulsion of carbon dioxide and the strong emulsifier was an important mechanism in enhancing oil recovery. When the strong emulsifier made contact with the oil at the puff stage of carbon dioxide and strong emulsifier, the entire system could be emulsified to form an emulsified zone of profile control and oil displacement and to activate the plugging system in situ and real time. DCA microspheres had strong deep plugging in reservoirs. As bottom water flooding proceeded, Fig. 21 showed that the sweep volume increased constantly at the stage of puff of the carbon dioxide and strong emulsifier. The sweep volume at the puff stage of carbon dioxide and strong emulsifier after deep plugging was much greater than that at the puff stage of carbon dioxide after the deep plugging. The injected bottom water subsequently flowed into the middle-permeability and low-permeability zones (300 103 mm2) on both sides of the model; these zones were not involved in starting the residual oil. The improving sweep volume was an important mechanism in enhancing oil recovery. Fig. 18(b) showed that the mechanism and technical idea were hypothetical. The mechanism of the method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging was verified in Fig. 21(b). The system of DCA microspheres had two roles. Firstly, DCA microspheres usually plugged high permeability channels by bridging and adsorption through the pore and throat in Fig. 22(a)
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Fig. 19. Water cut and oil recovery change with PV on method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging.
Fig. 20. Appearance of produced liquid at different stages of injection.
and Fig. 22(b). The salinity of simulated water was 269,000 mg/L. The content of calcium ions and magnesium ions was 20,240 mg/L. The chain of the acrylamide molecule of DCA microsphere surface combined with calcium ions and magnesium ions to bridge and plug in the pore constriction through a covalent bond. A proposed
plugging mechanism was shown in Fig. 23. The cross-linked 3D networks structure was built by covalent bond not coordinate bond, so DCA microspheres had many advantages compared with other polymer type deep profile control agent. DCA microspheres could improve volumetric sweep efficiency. Secondly, nanometer and micrometers DCA microspheres were synthesized by the method of emulsion polymerization. The product of DCA microspheres contained the surfactant that was not involved in the reaction, so the system of DCA microspheres could also improve microscale displacement efficiency. Therefore, the system of DCA microspheres could improve volumetric sweep efficiency and microscale displacement efficiency during production. The strong emulsifier had two roles. Firstly, when the strong emulsifier reached the oil, the entire system could be emulsified to activate the plugging system in situ and in real time during the migration of oil and water. The plugging mechanisms of strong emulsifier are shown in Fig. 1 (a) and Fig. 1 (b). If the particle diameter of the emulsion droplet is larger than the pore size or if they are condign, then plugging can occur in the pores; When the
Fig. 21. Distribution of remaining oil and sweep scope of bottom water flooding at the different stages.
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DCA microsphere
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Fig. 22. Plugging mechanism of DCA microspheres by bridging and adsorption.
O
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Fig. 23. Plugging mechanism of DCA microspheres by covalent bond.
number of the emulsion droplets is high, numerous droplets flow through the pores and plug the pore simultaneously even if the diameter of a droplet is smaller than the pore size of the porous medium. The emulsion system could improve volumetric sweep efficiency. Secondly, the strong emulsifier HA is the surfactant, so the emulsion system could also improve microscale displacement efficiency. Therefore, the strong emulsifier could improve volumetric sweep efficiency and microscale displacement efficiency during production. The carbon dioxide had two roles. Firstly, the appearance of the produced liquid was clearly distinguished at the different bottom water flooding and puff stages of carbon dioxide in Fig. 16. The produced liquid presented significant emulsification at the stage of puff of carbon dioxide. Then plugging can occur in the pores. So carbon dioxide could improve volumetric sweep efficiency. Secondly, the carbon dioxide could extract the light component from the oil, so carbon dioxide could also improve microscale displacement efficiency. Therefore, the carbon dioxide could improve volumetric sweep efficiency and microscale displacement efficiency during production. The working fluid included the slug of the system of DCA microspheres, the slug of the strong emulsifier and the slug of the carbon dioxide. Three kinds of slugs could improve volumetric sweep efficiency and microscale displacement efficiency during production. So the laboratory experiments applied this new
method and the rate of enhanced oil recovery increased by 56.25%. This paper proposed an innovative technical idea for controlling water and increasing oil recovery, carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging in the horizontal wells of high-temperature and high-salinity reservoirs. 5. Conclusions (1) A Strong emulsifying agent, which was named as HA, was screened by ultrasonic emulsification. The injection and emulsifying ability of the emulsifying agent HA was evaluated. During the subsequent water flooding, the pressure distribution showed an increasing trend in each measuring point. This phenomenon indirectly confirmed the existence of the mechanism of the Jamin effect and the temporarily plugging effects of the strong emulsifier. (2) A plugging agent of DCA microspheres was created. The particle size of DCA microspheres and the average diameter of the pore throat were at the micron level. A certain matching relationship with each other was confirmed. The residual resistance coefficients of positive injection and back injection were still greater than 2; therefore, DCA microspheres had a strong deep plugging effect in reservoirs and can be used for water shutoff.
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(3) The rate of enhanced oil recovery increased by 38.50%, and its effect was obvious in the stages of puff of carbon dioxide after DCA microsphere plugging. Based on the puff stage of carbon dioxide after DCA microsphere plugging, the rate of enhanced oil recovery increased by 17.75% at the stage of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging. This paper proposed an innovative technical idea for controlling water and increasing oil recovery, carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging in the horizontal wells of high-temperature and high-salinity reservoirs. Acknowledgment This research was financially supported by National Key Scientific and Technological Project (Grant No.2011ZX05009-004), National Basic Research Program of China (973Program) (Grant No.2011CB707305), Project of Tarim Oilfield of China National Petroleum Corporation (041013110096), National Natural Science Foundation of China (Grant No.51334007) and National Key Scientific and Technological Project (Grant No. 2016ZX05050012). References Alkhaldi, M.H., Saudi, A., Ghosh, B., Ghosh, D., 2011. A Novel Enzyme Breaker for Mudcake Removal in High Temperature Horizontal and Multi-lateral Wells. The SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers. AlQuraishi, Abdulrahman, A., Alsewailem, Fares, D., 2011. Adsorbtion of guar, xanthan and xanthan-guar mixtures on high salinity, high temperature reservoirs. The 10th Offshore Mediterranean Conference and Exhibition in Ravenna, OMC 2011 Programme Committee. Ambrosone, L., Mosca, M., Ceglie, A., 2007. Impact of edible surfactants on the oxidation of olive oil in water-in-oil emulsions. Food Hydrocolloid 21, 1163e1171. Buret, S., Nabzar, L., Jada, A., 2009. Water quality and well injectivity: do residual oil-in-water emulsions matter?. In: The 8th European Formation Damage Conference. Society of Petroleum Engineers. Chen, Y.S., Elhag, A.S., Poon, B.M., Cui, L.Y., Ma, K., Liao, S.Y., Reddy, P.P., Worthen, A.J., Hirasaki, G.J., Nguyen, Q.P., Biswal, S.L., Johnston, K.P., 2013. Switchable nonionic to cationic ethoxylated amine surfactants for CO2 enhanced oil recovery in high-temperature, high-salinity carbonate reservoirs. In: The SPE Improved Oil Recovery Symposium. Society of Petroleum Engineers. Dai, C., You, Q., Zhao, F.L., Xiong, W., 2010. Study and field application of profile control agent in high temperature and high salinity reservoir. In: The Trinidad and Tobago Energy Resources Conference. Society of Petroleum Engineers. Dai, C.L., Feng, D.C., Gao, H.D., He, L., Zhao, F.L., 2005. An integrated production well treating technology combining highly effective oil displacement agent huffingpuffing and water shutoff. Oilfield Chem. 22 (3), 43e44. Dullien, F.A.L., 1979. Porous Media Fluid Transport and Pore Structure, first ed. Academic Press, New York, pp. 157e230. Ghosh, S., Rousseau, D., 2011. Fat crystals and water-in-oil emulsion stability. Curr. Opin. Colloid 16, 421e431. He, J., Yue, X.A., Sun, Y., Feng, X.G., Tan, X., 2015. Preparation of uniform poly (Acrylamide- co-DVB) microspheres in a low toxicity solvent by dispersion polymerization. Aust. J. Chem. 68, 1276e1281. He, X., Wu, W.M., Li, L., Liu, G.Y., 2012. Application of polymer microspheres in water plugging of clastic rock horizontal wells with high temperature and high salinity. Complex Hydrocarb. Reserv. 5 (4), 82e84. Inamullah, B., Khadija, Q., Khairul, S.N.K., Aqeel, A.B., Abdul, W.B., Faizan, A., Moonyong, L., 2016. Innovative method to prepare a stable emulsion liquid
membrane for high CO2 absorption and its performance evaluation for a natural gas feed in a rotating disk contactor. J. Nat. Gas. Sci. Eng. 34, 716e732. Kassim, Riyamy, A., Sharma, M.M., 2002. Filtration properties of oil-in-water emulsions containing solids. In: SPE International Symposium and Exhibition on Formation Damage Control Held in Lafayette. Society of Petroleum Engineers. Kashiwabara, M., Fujimoto, K., Kawaguchi, H., 1995. Preparation of monodisperse, reactive hydrogel microspheres and their amphoterization. Colloid Polym. Sci. 273, 339e345. Li, D.S., Yu, T., Wang, J.J., Peng, W., Zhang, J.C., Chen, M.H., 2014. The study of deep profile control in complex fault block high temperature and salinity reservoirs in DaGang oilfield. Pet. Geol. Eng 28, 134e136. Lin, W.M., Chen, Y.H., Cao, M., Dong, J.Y., 2011. Evaluation and application of YG polymer microspheres as deep profile control agent. Oilfield Chem. 28 (3), 327e330. Lou, Z.B., Li, D.S., Fan, A.X., Du, Z.H., Song, X.B., 2012. Study and application of precross linked polymer particle flooding in eastern Wenliu Block 25 of Zhongyuan oilfield. Fault-Block Oil Gas Field 19 (5), 646e650. Mo, Z.T., Liu, K., Wu, J., Zhong, Y., 2011. The application of profile control technology in lion ditch oilfield in Qaidam Basin. Qinghai ShiYou 29 (1), 6e9. Nesterenko, A., Drelich, A., Lu, H.L., Clausse, D., Pezron, I., 2014. Influence of a mixed particle/surfactant emulsifier system on water-in-oil emulsion stability. Colloids Surf. A 457, 49e57. Puerto, M., Hirasaki, G.J., Miller, C.A., Barnes, J.R., 2010. Surfactant systems for EOR in high-temperature, high-salinity environments. In: The 2010 SPE Improved Oil Recovery Symposium. Society of Petroleum Engineers. Ren, C.L., 2008. Study and Practice on Oil Production Technology of Complex Profile Control and Flooding (MS Thesis). Tianjin Polytechnic University. Sun, H.Q., Wang, T., Xiao, J.H., Chen, H., 2006. Novel technique of in-depth profile control step by step by polymer microspheres. Pet. Geol. Recovery Effic. 13 (4), 77e79. Tang, X.F., Liu, Y.Z., Qin, H., 2004. A new method of in-depth profile modification for high-temperature and high-salinity reservoir. In: SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers. Tuncel, A., Piskin, E., 1996. Nonswellable and swellable poly (EGDMA) microspheres. J. Appl. Polym. Sci. 62, 789e798. Tzoumaki, M.V., Moschakis, T., Kiosseoglou, V., Biliaderis, C.G., 2011. Oil-in-water emulsions stabilized by chitin nanocrystal particles. Food Hydrocolloid 25, 1521e1529. Vashisth, C., Whitby, CaP., Fornasiero, D., Ralston, J., 2010. Interfacial displacement of nanoparticles by surfactant molecules in emulsions. J. Colloid Interface Sci. 349, 537e543. Vasquez, J., Civan, F., Shaw, T.M., Dalrymple, E.D., Eoff, L., Reddy, B.R., Brown, D., 2003. Laboratory evaluation of high temperature conformance polymer systems. In: SPE Production and Operations Symposium. Society of Petroleum Engineers. Wu, W.M., Qin, F., Ou, Y.D., He, L., 2013. Study on water plugging technology in fractured -cavity carbonate reservoirs in Tahe oilfield. Pet. Geol. Recovery Effic. 20 (6), 104e107. Yang, C.C., Yue, X.A., Zhou, D.Y., He, J., Zhao, J., Zhou, J.L., Li, C.Y., 2016. Performance evaluation of polymer microsphere with high temperature resistance and high salinity tolerance. Oilfield Chem. 33 (2), 254e260. Yang, S.L., Chen, H., Feng, J.L., Zhou, D.Y., Li, F.F., Zhang, X., 2014. A brief discussion on some scientific issues to improve oil displacement during gas injection in Tarim oilfield. Pet. Geol. Recovery Effic. 24 (1), 40e44. Yang, Z.J., Dou, H.M., Zhang, Q.H., Liu, Y.P., Zeng, L.J., 2013. Study of deep profile control in E13 reservoir of Gasikule oilfield. QingHai ShiYou 31 (1), 45e51. Yu, G.M., Gao, C.N., Wu, P.C., Li, W.H., Li, A.Q., 2011. Weak polymer gels flooding experiment in low permeability and high salinity oil reservoir. J. Southwest Pet. Univ. (Sci. Technol. Ed.) 33 (4), 125e129. Zeidani, K., Poikar, M., Huang, H.B., Boyd, J.W., 2008. Blocking mechanism for sealing the near wellbore region. J. Can. Pet. Technol. 47 (5), 40e47. Zhao, F.L., Dai, C.L., Wang, Y.F., 2005. Development trend on chemical flooding of high temperature and salinity reservoir. In: Li, Z.T. (Ed.), EOR on High Temperature and Salinity Reservoir. Petroleum Industry Press, Beijing, pp. 43e44. Zhao, Q.M., Lu, J., Li, X.J., Zhao, X.J., Yue, X.A., 2011. Experimental study on profile control mechanism of oil-in-water emulsion in heterogeneous model. Pet. Geol. Recovery Effic. 18 (1), 41e43.
Contents lists available at ScienceDirect
Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse
Combining carbon dioxide and strong emulsifier in-depth huff and puff with DCA microsphere plugging in horizontal wells of hightemperature and high-salinity reservoirs Chang-chun Yang a, b, *, Xiang-an Yue a, b, Chao-yue Li a, b, Rui Xu a, b, Jie-mai Wei a, b a b
Key Laboratory of Petroleum Engineering, Ministry of Education, China University of Petroleum, Beijing, 102249, PR China College of Petroleum Engineering, China University of Petroleum, Beijing, 102249, PR China
a r t i c l e i n f o
a b s t r a c t
Article history: Received 16 October 2016 Received in revised form 20 February 2017 Accepted 26 February 2017 Available online 1 March 2017
The profile control and water shutoff are still considered as technical problems for high-temperature and high-salinity reservoirs. A composite technique combining carbon dioxide and strong emulsifier in-depth huff and puff with water shutoff in the horizontal wells of high-temperature and high-salinity reservoirs was proposed. The composite technique comprised a strong emulsifier technique, a water shutoff agent technique, and technical injection of working fluid slug. The strong emulsifier technique included emulsifier screening. The ability of strong emulsifier served as the performance index. The strong emulsifier had two roles. When the strong emulsifier reached the oil, the entire system could be emulsified to activate the plugging system in situ and in real time. During the migration of oil and water, the emulsion system could improve volumetric sweep efficiency and microscale displacement efficiency. Carbon dioxide had a good emulsifying capability. The water shutoff agent technique included research on the high-temperature resistance and high-salinity resistance of polymer microspheres. The residual resistance coefficients of positive injection and back injection of polymer microspheres were still greater than 2. The working fluid included the slug of the system of polymer microspheres, the slug of the strong emulsifier and the slug of the carbon dioxide. Three kinds of slugs could improve volumetric sweep efficiency and microscale displacement efficiency during production. The key process of the proposed technique was the sequential injection of carbon dioxide and the strong emulsifier into the producer well of horizontal well. Upon injecting of polymer microspheres of the water shutoff agent, the microspheres aggregated to physical plugging and bridging by the effect of covalent bonds on one another after reaching the deep reservoir. The carbon dioxide and strong emulsifier were shut by the microspheres in the high-permeability formation. When water (bottom water, edge water, or injected water) approached the oil well along the high-permeability zone, the carbon dioxide and strong emulsifier would be carried by the water into the middle-permeability and low-permeability zone with higher oil saturation during production. Optimizing the injection method of the working fluid slug, a composite technique that combined carbon dioxide and a strong emulsifier with polymer microspheres was also proposed. Laboratory results showed that the rate of enhanced oil recovery increased by 38.50% based on water flooding recovery (10.00%) by using carbon dioxide in-depth huff and puff and polymer microsphere plugging after the first round. The rate of enhanced oil recovery increased by 17.75% based on the water flooding recovery of the first round by using carbon dioxide and strong emulsifier in-depth huff and puff and polymer microsphere plugging. In this paper the results of physical simulation experiments further prove that combining carbon dioxide and strong emulsifier in-depth huff and puff with divinylbenzeneco-acrylamide (DCA) microsphere plugging is a potential technical direction for controlling water cut and increasing oil recovery in horizontal well of high-temperature and high-salinity reservoirs. © 2017 Elsevier B.V. All rights reserved.
Keywords: High-temperature and high-salinity Horizontal well Carbon dioxide Strong emulsifier Polymer microspheres Huff and puff and water shutoff
1. Introduction * Corresponding author. Key Laboratory of Petroleum Engineering, Ministry of Education, China University of Petroleum, Beijing, 102249, PR China. E-mail address: [email protected] (C.-c. Yang). http://dx.doi.org/10.1016/j.jngse.2017.02.036 1875-5100/© 2017 Elsevier B.V. All rights reserved.
Few studies have been conducted on the implementation trials of stabilizing oil production and controlling the water in horizontal wells of high-temperature and high-salinity reservoirs (AlQuraishi
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et al., 2011; Puerto et al., 2010; Dai et al., 2010; Alkhaldi et al., 2011; Chen et al., 2013). The Shizigou reservoirs of the Qinghai Oilfield comprises low-temperature and ultra-high-salinity reservoirs for domestic production (Zhao et al., 2005; Mo et al., 2011). The Zaoyuan reservoirs of Dagang Oilfield has low-high-temperature and low-high-salinity reservoirs (Li et al., 2014). The lowpermeability reservoirs of the Changqing Oilfield has lowtemperature and medium-salinity reservoirs (Yu et al., 2011). The Jin-45 Fault Block reservoirs of the North China Oilfield has medium-high-temperature and medium-high-salinity reservoirs (Ren, 2008). The Gasikule E13 reservoirs of Qinghai Oilfield has highhigh-temperature and ultra-high-salinity reservoirs (Yang et al., 2013). The eastern Wenliu Block 25 reservoirs of Zhongyuan Oilfield has medium-high-temperature and high-high-salinity reservoirs (Lou et al., 2012). The Lunnan reservoirs of Tarim Oilfield has high-high-temperature and ultra-high-salinity reservoirs (Yang et al., 2014). The clastic rock reservoirs of Tahe Oilfield has highhigh-temperature and ultra-high-salinity reservoirs (Wu et al., 2013). Profile control and water shutoff of the above reservoirs have been implemented, and various technical have had different effects. No further reports have been presented on the continuous promotion and large-scale application of these technologies. Thus, profile control and water shutoff are still considered as technical problems for high-temperature and high-salinity reservoirs. Water-plugging techniques of oil wells have traditionally been used to improve volumetric sweep efficiency; however, they do not improve microscale displacement efficiency (Dai et al., 2005). A new composite technique combining carbon dioxide and strong emulsifier in-depth huff and puff with water shutoff in horizontal wells was proposed in this study to utilize adequately the advantages of each technique. The composite technique included a strong emulsifier technique, a water shutoff agent technique, and technical injection of working fluid slug. The key process of the proposed technique was the sequential injection of carbon dioxide and the strong emulsifier into the oil well of the horizontal well. When injecting divinylbenzene-co-acrylamide (DCA) microspheres of the water shutoff agent, the DCA microspheres aggregated to physical plugging and bridging by the effect of covalent bonds on one another after reaching the deep reservoirs. The carbon dioxide and strong emulsifier would be shut by the DCA microspheres in the high -permeability formation (Kashiwabara et al., 1995; Tuncel &Piskin, 1996). When water (bottom water, edge water, or injection water) approached the oil well along the high-permeability formations, the carbon dioxide and strong emulsifier would be carried by the water into the middle-permeability and lowpermeability formations with higher oil saturation during the production. The strong emulsifier had a dual role. When the strong emulsifier contacted with the oil, the entire system could be emulsified to activate the plugging system in situ and in real time (Ghosh and Rousseau, 2011; Zeidani et al., 2008; Kassim et al., 2002; Buret et al., 2009). In the process of the migration of oil and water, the emulsion system could improve volumetric sweep efficiency and microscale displacement efficiency. Carbon dioxide emulsified effectively enough to improve volumetric sweep efficiency and microscale displacement efficiency, thereby enhancing oil recovery under the interaction of the plugging agent of DCA microspheres and the plugging system of the strong emulsifier. 2. Screening emulsifying capability of strong emulsifier 2.1. Emulsion plugging mechanism Strong emulsifiers have a good emulsifying capacity. When a strong emulsifier makes contact with oil, the entire system can be emulsified to form an emulsified zone of profile control and oil
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displacement and to activate a plugging system in situ and in real time. The viscosity of an emulsifying agent should below, and it can be injected into the low-permeability cores to make contact with the oil to form an emulsion. The emulsion first enters the macropores that have relatively low resistance. If the size of the emulsion droplets is smaller than the pore size, then the droplets can flow smoothly through the pores. If the particle diameter of the emulsion is larger than the pore size or if they are condign, then plugging can occur in the pores. The subsequent fluid will generate a microscopic flow around the pore entrance. The mechanism of emulsion plugging is shown in Fig. 1 (a). When a larger pore is plugged by larger droplets of the emulsion, the subsequent fluid will selectively flow through the pore that has either relatively less resistance or a small size. The particle size distribution of emulsion droplets must be in the second largest scale to plug the abovementioned pore. The subsequent fluid will selectively flow through the pore that has a relatively smaller size. Therefore, large droplets of the emulsion plug larger pores, whereas small droplets of the emulsion plug smaller pores to form a self-adaptive plugging process. The macro performance of the preceding process shows that the emulsion droplet plugs high-permeability layer so that subsequent fluid selectively migrates into the low-permeability layer that has a smaller pore size. Thus, the residual oil in lowpermeability layer is swept and displaced. When the number of the emulsion droplets is high, numerous droplets flow through the pores and plug the pore simultaneously even if the diameter of a droplet is smaller than the pore size of the porous medium (Zhao et al., 2011; Ambrosone et al., 2007; Tzoumaki et al., 2011; Vashisth et al., 2010; Nesterenko et al., 2014). The mechanism of emulsion plugging is shown in Fig. 1 (b). 2.2. Injection and emulsifying capability The strong emulsifier, which was named as HA, was screened by ultrasonic emulsification. The injection and emulsifying capability of HA were evaluated using an artificial homogeneous columnar core with a diameter of 2.5 cm and length of 30 cm. The permeability of an artificial homogeneous columnar core simulated the permeability of the oilfield matrix. The gas permeability was 300 103 mm2. Oil and brine samples were collected from a domestic oilfield. The salinity of simulated water was 269,000 mg/L. The experimental temperature was simulated at a target reservoir temperature of 115 C. The temperature of constant temperature box was set. The artificial homogeneous columnar core was placed in the holder. The experimental apparatus scheme was shown in Fig. 2. Each device was connected. The more detailed description of each step of procedure and its sequence were as followings: 1 The saturation of oil of the artificial homogeneous columnar core. The core need be in a vacuum by vacuum pump, the saturation of formation water and the saturation of oil. Depending on the amount of saturated water and oil, pore volume (PV) and initial oil saturation were calculated. The pore volume (PV) was 20.85 mL and initial oil saturation was 71.9%. 2 The phase of water displacing oil. The flooding speed of the ISCO advection pump was 0.34 mL/min (1 m/d). The distribution location of the measurement pressure points of the core was 0, 5, 10, 15, and 20 cm and was monitored in real time. The results were shown in Fig. 3. The water flooding could not be terminated until the produced fluid did not contain oil and the water cut reached 100%. The simulated water injected the amount of 1.5 PV. 3 The phase of the injection HA. The flooding speed was 0.34 mL/ min (1 m/d). The pressure distribution along the cylindrical core was monitored in real time. HA injected the amount of 0.95 PV.
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Fig. 1. Mechanism of emulsion plugging. ((a): If the particle diameter of the emulsion droplet is larger than the pore size or if they are condign, then plugging can occur in the pores; (b): When the number of the emulsion droplets is high, numerous droplets flow through the pores and plug the pore simultaneously even if the diameter of a droplet is smaller than the pore size of the porous medium).
Fig. 2. The experimental apparatus scheme of injection and emulsifying capability.
4 The phase of subsequent water flooding. The flooding speed was 0.34 mL/min (1 m/d). Subsequent water flooding injected the amount of 1.31 PV. The appearance of produced liquid and the microstructure at different injection stages were shown in Fig. 4 and Fig. 5. When the water flooding injected an amount of 1.3 PV, water cut reached 100% in the test tubes and a passage of water channeling
Fig. 3. Pressure distribution with PV each measurement point at different stages of injection.
was formed. When injecting strong emulsifier, the strong emulsifier still flowed into the passage of water channeling due to the low saturation in the passage of water channeling. When the strong emulsifier injected an amount of 1.7 PV, the oil-water interface of the produced liquid was clear in the first test tube (Fig. 4 (a)) and did not form an emulsion system. The pressure distribution decreased in each measuring point along the cylindrical core. The main reason was that the factor of reducing the interfacial tension between the oil and water was dominant. As the amount of injected strong emulsifier increased, the produced fluids formed an increasingly obvious emulsion system in the second test tubes. As shown in Fig. 5 (a), the microstructure of the emulsion system was observed by using an optical microscope, and the average particle size of the emulsion droplets was 3.25 mm. When the strong emulsifier injected an amount of 1.1 PV, the strong emulsifier swept the entire water channel. During the subsequent water flooding, pressure distribution showed an increasing trend at each measuring point. The strong emulsifier was diluted by formation water, and the molecules of the strong emulsifier desorbed from the rock surface. The reducing pressure and increasing injection of the emulsion system were only conducted as HA was injected. Fig. 4 (c) and Fig. 5 (b) showed that the produced fluids of the subsequent water flooding formed an obvious emulsion system in the test tubes. However, the average particle size of the emulsion droplets increased to 3.70 mm. Given the Jamin effect and the aggregation effect of emulsion droplets, the pressure distribution increased in each measuring point along the cylindrical core in the stage of subsequent water flooding. This conclusion indirectly confirmed the existence of the aforementioned mechanism.
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Fig. 4. Appearance of produced liquid at different stages of injection.
Fig. 5. Microstructure of produced liquid at different stages of injection.
3. DCA microspheres of the plugging agent 3.1. Design ideas and microstructure of DCA microspheres To achieve a better plugging effect, the requirements of the following special characteristics are proposed for the material of the deep profile control and water shutoff: “injection in reservoirs,” “better plugging effect,” “better migration,” and “long life.” In “injection in reservoirs,” the materials must have good stability in water. In “better plugging effect,” the microspheres implement bridging and plugging through the covalent bonds between the surface molecular chain of the microspheres in the pore and throat to generate flow resistance. In “better migration,” polymer microspheres can break, migrate, and enter the deep reservoir under certain conditions of pressure. In “long life,” the material degradation of the microspheres does not occur under the conditions of high temperature and high salinity. Nanometer and micrometer DCA microspheres were synthesized by emulsion polymerization based on the requirements listed above (Sun et al., 2006; Lin et al., 2011; He et al., 2012, 2015). Nanometer and micrometers DCA microspheres were synthesized by emulsion polymerization based on the above technical ideas. The scanning electron microscopy (SEM) photograph of the microstructure of microspheres and crushed microspheres is shown in Fig. 6 (a)-(c). Fig. 6 (a)-(b) showed that the particle size of the DCA microspheres was 25 mm, and that the DCA microspheres were hollow. In line with the performance requirements of “injection in reservoirs,” the thickness of the cross-linked polymer layer was 12.79 mm. The initial judgment of the DCA microspheres showed that they had
good suspension in line with the performance requirements of “injection in reservoir”. The shells of the microspheres comprised nanoporous materials. The emulsion droplets were in oil-in-water form during the pre-emulsification phase. As the reaction continued, water resulted in extremely small solvation of the oligomers of the excluded acrylamide (AM) and those containing AM structural units. Compared with the condition without water, the length of the critical precipitation chain was basically unchanged. Thus, the oligomers of the excluded AM and those containing an AM structural unit first precipitated from the solution and participated in nucleating during the reaction. Two types of oligomers contained more structural units of divinylbenzene (DVB). Thus, the formation of putamen was closer. However, with the progress of the reaction, the oligomer, which did not precipitate and later precipitated AM structural units or more pure AM and monomer free radicals, was constantly trapped by the microsphere core from the solvent to achieve the particle size growth of the microspheres. These trapped oligomers had longer molecular chains, and fewer DVB structural units. The oligomers could not be closely integrated with the putamen. Thus, the formation of microspheres ultimately had a close putamen and a loose shell. As shown in Fig. 6 (c), the shell surface had the structure of the hydration layer of an AM segment. 3.2. Particle size and distribution of DCA microspheres Size distribution is the most basic characterization of polymer microspheres. The particle size and distribution of DCA microspheres were measured by using a Mastersizer laser particle size analyzer, as shown in Fig. 7.
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Fig. 6. SEM photograph of microstructure of DCA microspheres.
The experimental data were fitted by the following normal distribution function:
" f ðdÞ ¼ a1 exp
d b1 c1
2 # (1)
Where f ðdÞ is the normal distribution density, a1 is the shape parameter, b1 is the mean and is higher than or equal to 0, and c1 is the standard deviation. The fitting results show that the values of a1 , b1 , and c1 were 11.5, 490.9, and 274.1, respectively. The R2 value of the correlation coefficient was 0.912. Accordingly, the particle size and distribution of DCA microspheres were unimodal and approximately normal distribution. The particle size of the DCA microspheres ranged from 0.7 mm to 50 mm. For sandstone reservoirs, the porosity distribution ranged from 12.5% to 20%, and the permeability distribution ranged from 50 10 3 mm2 to 1600 10 3 mm2. According to the following Equation (2) (Dullien, 1979), the average diameter of the pore throat ranged from 2.8 mm to 20 mm.
sffiffiffiffiffiffiffi 8K r¼ f
(2)
Where r is the average diameter of the pore throat in micrometers, mm; K is the permeability in Darcy, and f is the porosity and is a dimensionless coefficient. The above results showed that the particle size of the DCA microspheres and the average diameter of the pore throat were at the micron level. A certain matching relationship thus existed between the two variables. 9.00
Distribution density//%
8.00 7.00 6.00
Fitting curve
5.00
Experimental curve
4.00 3.00 2.00 1.00 0.00 1
10 Size/μm Fig. 7. Particle size and distribution of DCA microspheres.
100
3.3. Injection and plugging capability of DCA microspheres To determine the plugging capability of DCA microspheres for large pores and cracks, the injection and plugging capability at 115 C were evaluated by using an artificial homogeneous columnar core with a diameter of 2.5 cm and a length of 30 cm. The gas permeability was 1600 10 3 mm2. The concentration of the DCA microspheres was 1000 mg/L. The diameter distribution of the DCA microspheres was applied to the experiment, as shown in Fig. 8. The microstructure of the DCA microspheres when the original liquid and produced liquid were injected is shown in Fig. 9 (Tang et al., 2004; Yang et al., 2016; Vasquez et al., 2003). To qualitatively determine the migration distance of the DCA microspheres in the homogeneous columnar core, the columnar core was cut into thin slices at different positions, and the end surface was observed via SEM. The morphologies of the DCA microspheres at different positions were shown in Fig. 9 (a)-(c). As shown in Figs. 8 and 9, the produced fluid contained a small amount of DCA microspheres. The majority of DCA microspheres remained inside the core pores and was detained. As a result, the DCA microspheres had a better injection capability. The positions of the end surface at 1.5, 5, and 10 cm were located at the core, and the DCA microspheres could be observed. This phenomenon further illustrated that the DCA microspheres could migrate into the pores deeply. The plugging capability of DCA microspheres was characterized by a residual resistance coefficient and was calculated with the following Equation (3):
Rk ¼
K3 Q mL=ADp3 Dp1 ¼ ¼ K1 Q mL=ADp Dp3
(3)
1
Where Rk is the residual resistance coefficient; K1 is the permeability of the core before injecting microspheres, Darcy; K3 is the permeability of the core after injecting microspheres, Darcy; Dp1 is the differential pressure of adjacent measurement points when the core permeability is measured in the stage of water flooding, 101 MPa; Dp3 is the differential pressure of adjacent measurement points when the permeability is measured in the stage of subsequent water flooding, 101 MPa; Q is the flowing rate of the fluid through the core, cm3/s; A is the cross-sectional area of the core, cm2; L is the length of the core, cm; m is the viscosity of the fluid through the core, mPa$s. After evaluating the injection and plugging capability, the long core holder was reversed to conduct aback injection experiment that could further verify the feasibility of water shutoff. The result is shown in Fig. 10. The microspheres had a stable plugging capability for migrating into all the measure points, thereby achieving deep plugging. The residual resistance coefficients of positive injection and back injection were still greater than 2; thus, the DCA
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Fig. 8. Microstructure of DCA microspheres in injection original liquid and produced liquid.
Fig. 9. Morphologies of DCA microspheres at different positions.
microspheres had strong deep plugging in reservoirs and demonstrated their potential for water shutoff. The microspheres mainly generated flow resistance by bridging and plugging through the covalent bonds between the surface molecular chain of the microspheres in the pore and throat. 4. Composite methods of controlling water and increasing oil of horizontal wells The composite methods of using carbon dioxide in-depth huff and puff after DCA microsphere plugging and using carbon dioxide and strong emulsifier in-depth huff and puff after DCA microsphere
plugging were researched (Inamullah et al., 2016). 4.1. Physical simulation system and establishing a model of horizontal wells A flooding experiment was simulated in a pressure chamber to verify the feasibility and effectiveness of each technique. The temperature resistance and pressure resistance of the pressure chamber were 150 C and 60 MPa, respectively. The physical simulation system of the horizontal well comprised the power equipment of displacement, a pressure chamber with high temperature and high pressure, a physical model, an
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Residual resistance coefficient
10000.00
placed in the middle of the top of the core. The length of the horizontal well was 30 cm, and the diameter was 2 mm. The acquisition device of pressure data included pressure sensors and a computer terminal. The pressure change was measured in real-time by using pressure sensors during the experiment. The data from the pressure sensor were automatically recorded and saved by the professional software of the computer terminal. The collection device of the produced fluid was connected to the sample tube, to measure the volume of the produced fluids.
positive injection
1000.00
back injection
100.00
10.00
4.2. Research methods on the distribution of the remaining oil and the sweep scope of water flooding
1.00 0
5
10
15
20
25
30
Distance along the core/cm Fig. 10. Residual resistance coefficient change with the distance along the core.
acquisition device of pressure data, and a collection device for produced fluid, as shown in Fig. 11. The power equipment of displacement comprised a constantpressure and constant-flow pump, and the intermediate container to provide power for the experiments. The physical model constituted the bottom water (edge water or injected water) systems, a planar heterogeneous core, and a model of horizontal well. The core, which was independently developed in a laboratory, was used in the physical simulation experiments. The length, width, and height of the core were 30, 3, and 7 cm, respectively. The change in the permeability simulated the planar heterogeneity in the direction of the horizontal well. The experimental model included three parts in the direction of the horizontal well, and the length ratio was 2: 1: 2. The intermediate zone of the model had a high permeability of 1600 10 3 mm2. Both sides of the model had a low permeability of 300 10 3 mm2. The horizontal well was
The water saturation within the model was measured to obtain the distribution of the remaining oil and the sweep scope of water flooding. The crude oil was generally not electrically conductive in the rock matrix and the pores of the reservoir. When the connectivity of the pore and the salinity of formation water were constant, the value of the testing resistance depended on the water saturation of the fluid in the pore. Therefore, the resistance value within the model reflected the ratio of the content of oil and water. A relationship between the contents of water saturation and the resistance value was established. A total of 21 pairs of electrodes were arranged in the model of planar heterogeneity. Each pair of electrodes was placed on both sides of the model to measure the value of the instantaneous resistance. The resistance-measuring points of planar heterogeneity were distributed as shown in Fig. 12. The saturation measuring device could automatically record the resistance value measured by each pair of electrodes during the experiment. The time interval of the measurement was set depending on the specific situations. After the experiment, the water saturation of the 21 pairs of measuring points was obtained by the standard relationship between water saturation and the
Fig. 11. Schematic diagram of experimental devices of horizontal wells in bottom water reservoir.
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Fig. 12. Distribution of resistance-measuring points of planar heterogeneity.
resistance value. The distribution of saturation data of measuring points was discrete in space. The distribution characteristics of the saturation could not be characterized visually. The continuous distribution of saturation data was obtained by Kriging interpolation. The saturation distribution on the core was researched using these data to draw the contour-map of the saturation. The laboratory results were shown in Fig. 17 and Fig. 21.
Fig. 13. Design mechanism of the amount of each slug.
4.4. Method of carbon dioxide in-depth huff and puff and DCA microsphere plugging 4.3. Design of the amount of each slug The design mechanism of the amount of each slug, which included carbon dioxide, strong emulsifier HA, and DCA microspheres, in reservoirs is shown in Fig. 13. The view of design mechanism included front view and left side elevation view. The amount of each slug was designed with reference to Equations (4) (5), and (6). The amounts of carbon dioxide, strong emulsifier HA, and DCA microspheres were optimized and to 0.18, 0.07, and 0.11 PV, respectively.
Q0 ¼ bh2 $tg q 2 $Lb $f
(4)
Q1 ¼ b1 h21 h22 $tg q 2 $Lb $f =
(5)
Q2 ¼ b2 h22 $tg q 2 $Lb $f
(6)
=
=
where Q0 is amount of the slug of carbon dioxide by the volume, m3; Q1 is amount of the slug of strong emulsifier HA by the volume, m3; Q2 is amount of the slug of DCA microspheres by the volume, m3; b is inter-porosity flow parameter of carbon dioxide; b1 is interporosity flow parameter of strong emulsifier HA; b2 is interporosity flow parameter of DCA microspheres; h is injection height of carbon dioxide, m; h1 is injection height of strong emulsifier HA, m; h2 is injection height of DCA microspheres, m; q is the break though angle of the inter-porosity flow parameter; Lb is the width of the inter-porosity flow parameter, m; f is the porosity.
The following are the experimental major steps on the method of carbon dioxide in-depth huff and puff and DCA microsphere plugging: evacuation, saturation with brine, and injection with oil were implemented by the planar heterogeneity. The experiment was completed after the water cut reached 98% in the bottom water flooding, edge water flooding, or injected waterflooding. The injection amount of the carbon dioxide slug, which was the agent of in-depth huff and puff, was 0.18 PV. After the horizontal well was shut in for 24 h, the injection amount of the DCA microsphere slug was 0.11 PV. Finally, the slug of fresh water, which was the displacement fluid, was injected. The model of planar heterogeneity stimulated the production of bottom water reservoirs in horizontal well. The mechanism of the carbon dioxide in-depth huff and puff and DCA microsphere plugging was shown in Fig. 14. The water cut and oil recovery change with PV on the method of carbon dioxide in-depth huff and puff and DCA microsphere plugging was shown in Fig. 15. The appearance of produced liquid at different injection stages was shown in Fig. 16. The distribution of remaining oil and the sweep scope of water flooding at bottom water flooding stage before the deep plugging and the puff stage of carbon dioxide after the deep plugging were shown in Fig. 17. Fig. 15 showed that the rate of enhanced oil recovery reached 10% at the bottom water flooding stage. Based on the oil recovery of bottom water flooding, the rate of enhanced oil recovery increased by 38.50%, and its effect was obvious in the stages of puff of carbon dioxide after DCA microsphere plugging. The appearance of the produced liquid was clearly distinguished at the different bottom water flooding and puff stages of carbon dioxide. The produced liquid presented significant emulsification at the stage of puff of carbon dioxide in Fig. 16. The crude displacement with carbon
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Fig. 16. Appearance of produced liquid at different stages of injection.
Fig. 14. Mechanism of method of carbon dioxide in-depth huff and puff and DCA microsphere plugging.
dioxide enhanced the oil recovery, and this conclusion verified that the emulsion was an important mechanism in enhancing oil recovery. The DCA microspheres flowed into the high-permeability layer preferentially at 1600 103 mm2. The chain of the AM molecule of the DCA microsphere surface was bridged and blocked in the pore constriction through a covalent bond. The shell of the microspheres had nanometer-sized pores. These shells absorbed a small amount of water and exhibited weak swelling properties in producing flow resistance. Fig. 17 (a) showed the distribution of remaining oil and sweep scope at bottom water flooding stage before DCA microsphere plugging. The blue color in the red circle represented the sweep scope at bottom water flooding stage. The sweep scope was small at
Fig. 15. Water cut and oil recovery change with PV on method of carbon dioxide indepth huff and puff and DCA microsphere plugging.
bottom water flooding stage. Fig. 17 (b) showed distribution of remaining oil and sweep scope of bottom water flooding at the stage of puff of carbon dioxide after DCA microsphere plugging. The blue color in the red circle represented the sweep scope at bottom water flooding stage. The sweep scope plugging became larger remarkably at the stage of puff of carbon dioxide after DCA microsphere. Fig. 17 (b) showed that the sweep volume at the bottom water flooding stage before deep plugging was much larger than that at the puff stage of carbon dioxide after the deep plugging. The injected bottom water subsequently flowed into the middle- and low-permeability zones (300 10 3 mm2) on both sides of the model; these zones were not involved in starting the residual oil at the puff stage of carbon dioxide after the deep plugging. The improving sweep volume was an important mechanism in enhancing oil recovery. Fig. 14 (b) showed the mechanism and technical idea of method of carbon dioxide in-depth huff and puff and DCA microsphere plugging. Fig. 14 (b) showed that the mechanism and technical idea were hypothetical. The mechanism and technical idea of carbon dioxide in-depth huff and puff and DCA microsphere plugging is verified in Fig. 17 (b). 4.5. Method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging The following are major steps in carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging. Evacuation, saturation with brine, and injection with oil were implemented by the planar heterogeneity. The experiment was ended after the water cut reached 98% in bottom water flooding, edge water flooding, or injected water flooding. The injection mount of the carbon dioxide slug, which was the agent of in-depth huff and puff, was 0.18 PV. After the horizontal well was shut in for 24 h, the injection amount of the slug of strong emulsifier was 0.07 PV. The injection amount of DCA microsphere slug was 0.11 PV. Finally, the slug of fresh water, which was the displacement fluid, was injected. The model of planar heterogeneity simulated the production of bottom water reservoirs in the horizontal well. The mechanism of the carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging was shown in Fig. 18. The water cut and oil recovery change with PV when using carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging was shown in Fig. 19. The appearance of the produced liquid at different injection stages was shown in Fig. 20. The distribution of the remaining oil and the sweep scope of water flooding at the bottom water flooding stage before deep plugging and the puff stage of carbon dioxide and strong emulsifier after deep plugging were shown in Fig. 21. When the injected strong emulsifier made contact with the
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Fig. 17. Distribution of remaining oil and sweep scope of bottom water flooding at the different stages.
residual oil, an emulsion system was formed for temporary plugging. The emulsion system might prevent the subsequent injection of the DCA microspheres from being contaminated by the middlepermeability and low-permeability zones in the horizontal well in Fig. 18. Fig. 19 showed that based on the oil recovery of bottom
Fig. 18. Mechanism of method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging.
water flooding, the rate of enhanced oil recovery increased by 38.50% at the stage of puff of carbon dioxide after DCA microsphere plugging. Based on the puff stage of carbon dioxide after DCA microsphere plugging, the rate of enhanced oil recovery increased by 17.75% at the stage of carbon dioxide and strong emulsifier indepth huff and puff and DCA microsphere plugging. The appearance of produced liquid was clearly distinguished at different bottom water flooding and puff stages of carbon dioxide and strong emulsifier. The produced liquid exhibited considerable emulsification at the puff stage of carbon dioxide and strong emulsifier in Fig. 20. This phenomenon verified that the emulsion of carbon dioxide and the strong emulsifier was an important mechanism in enhancing oil recovery. When the strong emulsifier made contact with the oil at the puff stage of carbon dioxide and strong emulsifier, the entire system could be emulsified to form an emulsified zone of profile control and oil displacement and to activate the plugging system in situ and real time. DCA microspheres had strong deep plugging in reservoirs. As bottom water flooding proceeded, Fig. 21 showed that the sweep volume increased constantly at the stage of puff of the carbon dioxide and strong emulsifier. The sweep volume at the puff stage of carbon dioxide and strong emulsifier after deep plugging was much greater than that at the puff stage of carbon dioxide after the deep plugging. The injected bottom water subsequently flowed into the middle-permeability and low-permeability zones (300 103 mm2) on both sides of the model; these zones were not involved in starting the residual oil. The improving sweep volume was an important mechanism in enhancing oil recovery. Fig. 18(b) showed that the mechanism and technical idea were hypothetical. The mechanism of the method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging was verified in Fig. 21(b). The system of DCA microspheres had two roles. Firstly, DCA microspheres usually plugged high permeability channels by bridging and adsorption through the pore and throat in Fig. 22(a)
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Fig. 19. Water cut and oil recovery change with PV on method of carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging.
Fig. 20. Appearance of produced liquid at different stages of injection.
and Fig. 22(b). The salinity of simulated water was 269,000 mg/L. The content of calcium ions and magnesium ions was 20,240 mg/L. The chain of the acrylamide molecule of DCA microsphere surface combined with calcium ions and magnesium ions to bridge and plug in the pore constriction through a covalent bond. A proposed
plugging mechanism was shown in Fig. 23. The cross-linked 3D networks structure was built by covalent bond not coordinate bond, so DCA microspheres had many advantages compared with other polymer type deep profile control agent. DCA microspheres could improve volumetric sweep efficiency. Secondly, nanometer and micrometers DCA microspheres were synthesized by the method of emulsion polymerization. The product of DCA microspheres contained the surfactant that was not involved in the reaction, so the system of DCA microspheres could also improve microscale displacement efficiency. Therefore, the system of DCA microspheres could improve volumetric sweep efficiency and microscale displacement efficiency during production. The strong emulsifier had two roles. Firstly, when the strong emulsifier reached the oil, the entire system could be emulsified to activate the plugging system in situ and in real time during the migration of oil and water. The plugging mechanisms of strong emulsifier are shown in Fig. 1 (a) and Fig. 1 (b). If the particle diameter of the emulsion droplet is larger than the pore size or if they are condign, then plugging can occur in the pores; When the
Fig. 21. Distribution of remaining oil and sweep scope of bottom water flooding at the different stages.
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DCA microsphere
DCA microspheres
pore
67
pore
(a)
(b)
Fig. 22. Plugging mechanism of DCA microspheres by bridging and adsorption.
O
O
O
O
Ca2+ O
O
O
O
DCA microsphere
2+
Ca
DCA microsphere
O
O
O O
O
O
O
O
O
O
O
Ca2+
Ca2+
O
O
O
O
O
DCA microsphere
Ca2+
O DCA microsphere
O
O
O
O
O
Ca2+ O
O
Fig. 23. Plugging mechanism of DCA microspheres by covalent bond.
number of the emulsion droplets is high, numerous droplets flow through the pores and plug the pore simultaneously even if the diameter of a droplet is smaller than the pore size of the porous medium. The emulsion system could improve volumetric sweep efficiency. Secondly, the strong emulsifier HA is the surfactant, so the emulsion system could also improve microscale displacement efficiency. Therefore, the strong emulsifier could improve volumetric sweep efficiency and microscale displacement efficiency during production. The carbon dioxide had two roles. Firstly, the appearance of the produced liquid was clearly distinguished at the different bottom water flooding and puff stages of carbon dioxide in Fig. 16. The produced liquid presented significant emulsification at the stage of puff of carbon dioxide. Then plugging can occur in the pores. So carbon dioxide could improve volumetric sweep efficiency. Secondly, the carbon dioxide could extract the light component from the oil, so carbon dioxide could also improve microscale displacement efficiency. Therefore, the carbon dioxide could improve volumetric sweep efficiency and microscale displacement efficiency during production. The working fluid included the slug of the system of DCA microspheres, the slug of the strong emulsifier and the slug of the carbon dioxide. Three kinds of slugs could improve volumetric sweep efficiency and microscale displacement efficiency during production. So the laboratory experiments applied this new
method and the rate of enhanced oil recovery increased by 56.25%. This paper proposed an innovative technical idea for controlling water and increasing oil recovery, carbon dioxide and strong emulsifier in-depth huff and puff and DCA microsphere plugging in the horizontal wells of high-temperature and high-salinity reservoirs. 5. Conclusions (1) A Strong emulsifying agent, which was named as HA, was screened by ultrasonic emulsification. The injection and emulsifying ability of the emulsifying agent HA was evaluated. During the subsequent water flooding, the pressure distribution showed an increasing trend in each measuring point. This phenomenon indirectly confirmed the existence of the mechanism of the Jamin effect and the temporarily plugging effects of the strong emulsifier. (2) A plugging agent of DCA microspheres was created. The particle size of DCA microspheres and the average diameter of the pore throat were at the micron level. A certain matching relationship with each other was confirmed. The residual resistance coefficients of positive injection and back injection were still greater than 2; therefore, DCA microspheres had a strong deep plugging effect in reservoirs and can be used for water shutoff.
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