Article pubs.acs.org/EF
Cite This: Energy Fuels 2018, 32, 279−286
3D Experimental Investigation on Enhanced Oil Recovery by Flue Gas Coupled with Steam in Thick Oil Reservoirs Zhengbin Wu,* Huiqing Liu, and Xue Wang State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, PR China S Supporting Information *
ABSTRACT: Flue gas mainly consists of N2 and CO2 and is applied in petroleum industry as a kind of displacement agents. In this paper, flue gas was introduced into the thermal recovery process of thick heavy oil reservoir. First, the PVT experiments under different conditions were carried out to research the dissolution of flue gas in crude oil. Then, a series of 3D physical simulations were performed to study the oil displacement characteristics of flue gas coupled with steam flooding in a thick reservoir with consideration of the important production parameters including oil production, oil-to-steam ratio (OSR), water cut, and oil recovery in both the steam-flooding process and the process of steam flooding coupled with flue gas. Finally, the enhanced oil recovery mechanisms of flue gas coupled with steam flooding for thick heavy oil reservoirs were summarized on the basis of the experimental results. This study provided a reference that the reasonable use of flue gas can improve recovery of thick heavy oil reservoirs while reducing greenhouse gas emissions.
1. INTRODUCTION The global emissions from fossil fuel combustion is reported to be 3.57 × 1010 tons in 2015, and Chinese annual greenhouse gas emissions is estimated to be 9.52 × 109 tons, accounting for about 26.59% of the world’s total emissions.1,2 The chemical composition of flue gas typically contains about 80% of N2 and 20% of CO2 and other impurities.3,4 CO2 emission has been a major contributor to the atmospheric issues.5,6 The technique of carbon capture and storage, e.g., CO2 injection into deep saline aquifers,12−14 depleted oil and gas reservoirs,15,16 and unexploited coal layers,17−19 has a large potential for removing flue gas.7−11 However, the treatment of CO2 or flue gas using the traditional absorption method is considered costly and complicated. Heavy oil and bitumen are important hydrocarbon resources that play an increasingly great role in petroleum supply over the world.20−22 There are abundant heavy oil reserves in China, most of which are buried from 900 to 1500 m in depth. The crude oil viscosity ranges from 200 to 50000 mPa·s under reservoir conditions.20 It has been verified that thermal recovery methods that decrease oil viscosity and increase oil mobility are the most effective enhanced oil recovery techniques for heavy oil.22 The conventional thermal recovery methods mainly include cyclic steam stimulation (CSS), steam flooding, steam-assisted gravity drainage (SAGD), and in situ combustion. However, it is difficult to introduce conventional steam injection techniques to offshore heavy oil production at present because the available area on platform is limited to accommodate steam generator and auxiliary equipment.23,24 Therefore, a special compact gas (steam and flue gas) generator in which steam and flue gas are involved is invented to develop offshore heavy oil. Liu et al.25 reported some field tests of multithermal fluid stimulation in the Bohai offshore oilfield, China and considered the co-injection of flue gas and steam a new and more-efficient development method for offshore thick heavy oil reservoirs. As a matter of fact, the flue gas has been treated as a more economical alternative to © 2017 American Chemical Society
other inert gases since the 1980s. Redford investigated the addition of gases and solvents to steam for improving bitumen recovery in a cyclic drive process.26 He found that oil recovery could be substantially improved by mixing CO2 with steam, and sweep area of flue gas was much larger than that of pure steam injection for the same injection volume. However, a higher gas concentration would reduce heat transfer and increase relative permeability of the gas phase to decrease heavy oil recovery. Balog et al. summarized the benefits of steam−gas mixtures for steam injection applications.27 Ali and Flock conducted a set of experiments with the purpose of investigating possible improvements in recovery of heavy oil by the addition of CO2 or flue gas in steam flooding.28 In addition, the effects of injection strategies on the performance of steam−CO2 system and the immiscible displacement mechanisms of the simultaneous injection of steam and CO2 in heavy oil reservoirs also attracted attention of many researchers.29−32 However, most of the reported literatures describe the injection of flue gas can improve oil recovery but do not further explain why. Especially for thick heavy oil reservoir, steam override occurs much more easily, and the EOR mechanisms of flue gas injection will be more complex and should be paid more attention. In this paper, the PVT experiments under different conditions were carried out to research the dissolution of flue gas in crude oil. Then, a set of 3D physical simulations were performed to investigate the development characteristics of flue gas coupled with steam flooding. Finally, the enhanced oil recovery mechanisms of flue gas coupled with steam flooding for thick heavy oil reservoir were summarized by the analysis of the variation of temperature field, the properties of heavy oil and the distribution of remaining oil. Received: October 11, 2017 Revised: December 7, 2017 Published: December 7, 2017 279
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
Article
Energy & Fuels
2. EXPERIMENTS 2.1. PVT Tests. The apparatus used in the PVT test experiments is illustrated in Figure S1. A falling sphere viscometer with the measuring range from 0.5 to 100,000 mPa·s was adopted for oil viscosity measurement. A vacuum pump was used to eliminate the influence of air on the experiments. The PVT cell with a magnetic mixer was to make gas adequately dissolve in crude oil under the given temperature and pressure. The fluid sampler was to collect the mixed fluid to measure its viscosity at required temperature and. After the experimental apparatus was assembled, the experiments could be conducted as following procedures: (1) The degassed oil and flue gas was stored in the oil sample tank and gas tank, respectively. (2) A certain amount of degassed oil sample and flue gas were injected into the sample preparation device on the basis of the dissolved gas−oil ratio. Then, the oil−gas mixture was stirred for 30 minutes to make the oil and gas fully mixed. (3) The mixture fluid sample was transferred into PVT cell to test the physical properties. 2.2. 3D Experiments. 2.2.1. Experimental Apparatus. The experimental system for 3D thermal recovery simulation is shown in Figure S2. It mainly consisted of five subsystems, i.e., the injection system, the 3D physical model, the production system, the data acquisition system, and the auxiliary system. The 3D physical model is shown in Figure 1.
Figure 2. Schematic diagram of production well and injection well in 3D physical model. in Figure 2. The length of horizontal well in actual oilfield was 500 m, so the length of the horizontal well in the experiments should be 177.8 cm. However, the actual inner width of the model was 40 cm. Therefore, the calculated length of horizontal well was 4.44 times of that in the physical model. The calculated model parameters are listed in Table S2 and the injection-production parameters are presented in Table S3.
r(L) =
xm h = m xp hp
(1)
where x was well spacing (m) and h was net pay (m). The subscript m represented model size and p represented practical size. 2.2.3. Experimental Procedures. After the experimental apparatus was assembled, the experiments were performed as following procedures: (1) After filling with quartz sands, the physical model was tested gas tightness with nitrogen under high pressure for 30 min. (2) The 3D physical model was placed in the constant temperature oven at 50 °C. After heating for 48 h, the crude oil was injected into the model at a rate of 5 mL/min to make the inner pressure of the model reach the required value. The real-time temperature and pressure values of all sensors were recorded via the data acquisition system. (3) During the CSS process, the steam temperature was 250 °C and the steam quality was 70%. The steam injection rate were 11 mL/min and the soak time was 2 min. The injection time in the three cycles was 5, 6, and 7 min, respectively. The back pressure of the three cycles were 8, 6, and 3 MPa, respectively. The termination condition of each cycle was no liquid was produced from the well. During the whole CSS process, the temperature field of each cycle was monitored and the production liquid was collected and measured (4) Steam flooding was performed following CSS. The steam temperature was 250 °C, steam quality was 70%, steam injection rate was 25 mL/min, and the back pressure was 3 MPa. The steam flooding process ended as the OSR was below 0.1. Similar to the CSS process, the temperature field of steam flooding process was also monitored and the production liquid was collected and measured. (5) Flue gas coupled with steam was injected into the model followed steam flooding. The fluid flux was 25 mL/min and the volume ratio between steam and flue gas was 3:2 under 3 MPa. The realtime water cut and liquid production were measured and analyzed, as well as the temperature field. The experiment was completed as the OSR was below 0.1 again. 2.3. Experimental Materials. The crude oil in the experiments was degassed oil from LD5−2N block in Bohai offshore oilfield, China. The oil density is 0.97 g/cm3 and the oil viscosity was 28469.6 mPa·s at 50 °C. The viscosity−temperature relationship of the crude oil is shown in Figure S3. The salinity of the formation water varied from 2130 to 5491 mg/L. The flue gas used in the experiments was a mixture of N2 (volume percentage of 80%) and CO2 (volume percentage of 20%). As shown in Figure S4, the oil layer was filled with quartz sands of 40 mesh (Figure S4a), and the top and bottom of the model were filled with compacted and impermeable clay (Figure S4b). The other four inner
Figure 1. Picture of 3D physical simulation model. The inner chamber was 40 cm in width and 40 cm in depth. The injection well was installed on the right side of the physical model and the production well was installed on the left side. The highest affordable pressure and temperature was 20 MPa and 300 °C, respectively. Injection wells and pipelines were all bounded by electric heating belts that prevented heat loss during steam injection. The temperature was set as the steam temperature to prevent steam from condensing before it flowed into the 3D physical model. In the production system, a visual window was adopted to observe the occurrence and migration of oilfoam. 2.2.2. Experimental Parameters. The experimental parameters were designed according to the actual geological properties of LD5-2N block, a thick extra heavy oil reservoir of Bohai offshore oilfield in China, by using the similarity criterion method to simulate the different production processes including cyclic steam stimulation (CSS), steam flooding, and flue gas coupled with steam flooding. The oil sample was dehydrated and degassed heavy oil from LD5-2N block. The experimental temperature and pressure were both in accordance with that of LD5−2N block. Given the assumption that the thermal physical properties of oil sands used in the experiment were identical to the rock in the actual reservoir, and then the experimental parameters could be calculated according to the similarity criterion numbers in Table S1 and eq 1. The actual well spacing and the actual net pay were, respectively, 112 and 40 m. The inner width of the physical model was 40 cm. Therefore, the thickness of the physical model was 16 cm, as shown 280
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
Article
Energy & Fuels sides of the physical model were sealed with a kind of temperatureresistant fluorine rubber (Figure S4c) to form a heat-insulating layer. The photos of Figure S4b−d were taken with a Leica camera.
largely at the last stage of the second period. The appearance of this phenomenon was because that with the continuous injection of high-temperature steam, the thermal front gradually moved to production well from the injection well. As shown in Figure 4e, the thermal front finally reached the production well during the second period of steam flooding so that the reservoir was heated on the whole, leading to a decrease in oil viscosity and an increase in oil production. Finally, oil production decreased quickly and water cut increased largely. The contour plots of temperature field are as shown in Figure 4d,f. When the injected volume of steam reached 0.22 PV, steam chamber gradually expanded from the injection well to the center of the reservoir, as shown in Figure 4d. When the injected volume was 1.07 PV, the front of steam chamber reached the production well (that was, steam channeling occurs), as shown in Figure 4e. The steam flooding process ended as the steam was injected 2.38 PV when the OSR was lower than 0.1, as shown in Figure 4b. The reservoir pressure was basically stable (as shown in Figure 4c) during the steam flooding process, and the ultimate recovery was 41.54%. Figures 5−7, revealed the temperature distribution during the three periods of steam flooding, respectively. In Figure 5, the steam chamber gradually expanded and moved to production well during the first period. Meanwhile, steam flowed towards the upside of the reservoir, while the condensed water migrated to the bottom due to gravity segregation. The temperature front exceeded the center of the reservoir at 174 min and an obvious steam override was observed. After the first period, the oil recovery increased by 11.32% 4.97% to 16.29%.
3. RESULTS AND DISCUSSIONS 3.1. PVT Tests. In this part, the physical properties of crude oil-flue gas system under different temperature and pressure conditions are investigated to analyze the influence of flue gas on heavy oil. The experimental temperatures were 30, 50, 80, 120, and 180 °C, while the experimental pressures were 0.1, 2, 4, 8, and 12 MPa. It could be seen from Figure 3 that with the increase of temperature, the solubility of flue gas and the swelling factor of heavy oil−flue gas system were both reduced. At a certain temperature, the increasing pressure would make CO2 dissolve in crude oil to form a miscible phase, thus further decreasing oil viscosity (Figure 3d) and generating solution gas drive as the reservoir pressure declined. 3.2. 3D Experiments. 3.2.1. CSS Process. Table S4 presents the production characteristics of the CSS process. The oil recovery after each cycle during the CSS process was 1.55%, 2.88%, and 4.97%, respectively. The reservoir pressure varied from 10 to 3 MPa during the CSS process, meeting the condition to conduct steam flooding. 3.2.2. Steam Flooding Process. As revealed in Figure 4a,b, the steam flooding process could be divided into three typical periods, e.g., the ascent, the stability, and the descent of oil production. First, both oil production and water cut largely increased. Then, oil production was basically stable, and water cut slightly increased. However, the oil production increases
Figure 3. Curve of crude oil properties after dissolved by flue gas. 281
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
Article
Energy & Fuels
Figure 4. Experimental results of production performance during 3D physical simulation: (1) the ascent of oil production, (2) the stability of oil production, and (3) the descent of oil production.
prevent heat loss from the reservoir top. Meanwhile, most injected flue gas would be trapped at the top of reservoir, thus decreasing the greenhouse gas emissions.33 As shown in Figure 4, after flue gas coupled with steam flooding, oil production increases largely from 2.3 to 5.9 mL/min, while the water cut decreases dramatically from 91.87% to 81.44%. The ultimate oil recovery is 49.49% at the end of 3D physical simulation, 7.95% higher than steam flooding. The photographs of produced oil in different displacement processes are shown in Figure 9. The initial crude oil was extraheavy oil and was pure black, as shown in Figure 9a. After steam flooding, some tiny bubbles were dispersive in oil that appeared light black, as shown in Figure 9b. The bubbles mainly came from the light components dissolved in crude oil, which became gasphase under high temperature. After the flue gas was coupled with steam flooding, lots of bigger bubbles appeares in oil that presents as brown. The oil mobility was increased significantly, and the crude oil expanded obviously as a result of flue gas dissolution.34,35 Table S5 shows the variation of oil properties during different displacement periods. It can be seen that after
In Figure 6, the steam chamber mainly expands horizontally during the second period. The heated area was enlarged greatly, and the temperature front reached the bottom as a result of amount of steam condensing to hot water at the front. Consequently, oil recovery in this period shows increases linearly from 16.29% to 38.05% under the expansion of steam chamber. In Figure 7, steam channeling occurred at 740 min. During this period, the oil production and the OSR declined greatly, and water cut increased obviously. Oil production decreased from 12.6 to 2.4 mL/min, while water cut increased from 83.2% to 92.3%. The steam chamber was stable, but the steam override was obvious above the injection well. When steam was injected for 825 min, the OSR was below 0.1. The ultimate oil recovery was 41.54%, which was 3.49% higher than that of the second period. 3.2.3. Flue Gas Coupled with Steam Flooding. The temperature field of the reservoir with the injection of flue gas is shown in Figure 8 The injected flue gas migrated upward due to density difference between gas and steam to displace remaining oil at the top and to form a heat insulation layer to 282
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
Article
Energy & Fuels
Figure 5. Temperature distribution during the first period.
Figure 6. Temperature distribution during the second period.
Figure 7. Temperature distribution during the third period.
steam flooding and flue gas coupled steam flooding, the oil density and viscosity both decrease. The four components analysis results also present an increase in hydrogen components (saturates and aromatics) and a decrease in nonhydrocarbon
components (resins and asphaltene). As with the injection of flue gas, each index changed more obviously. The variation of oil density, viscosity, and the components illustrate that the flue gas is helpful to further reduce oil viscosity and improve oil mobility. 283
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
Article
Energy & Fuels
Figure 8. Temperature distribution during flue gas coupled with steam flooding.
Figure 9. Appearances of crude oil during different periods.
During flue gas coupled with steam flooding, the photographs of crude oil and oil-foams captured in the visual window are shown in Figure 10. From Figure 10a, it could be seen how the crude oil at the inlet of visual window was fully swept by flue gas. On both sides of the flowing path, some large bubbles are scattered in the oil-rich region. In Figure 10b, there was a large quantity of oil at the center of visual window. A lot of tiny bubbles were dispersed in oil that appeared darker. In Figure 10c, there were large number of microbubbles with almost uniform size at the outlet, and the microbubbles migrated with the oil phase out of the visual window together. These pictures visually illustrated the morphological variation of heavy oil after flue gas injection and revealed the solution gas drive process, demonstrating that the injection of flue gas was beneficial for enhancing oil recovery. In addition, the produced emulsions were transported through a flash separator and the gas volume was calculated by a gas flowmeter under atmosphere. The result indicated that the gas flowed through the gas flowmeter was about 1960 mL. The flue gas is injected about 480 min, as shown in Figure 8, and the flue gas injection rate was 10 mL/min, as revealed in Table S3. Therefore, the total volume of injected flue gas under atmosphere
was 4800 mL, demonstrating that most injected gas was trapped in the 3D physical model and dissolved in the produced oil. The distribution remaining oil after flue gas coupled with steam flooding is shown in Figure S5. From Figure S5a, the remaining oil saturation was reduced largely after flue gas assisted steam flooding. However, the oil sands above the injection well were darker and harder because of the existence of remained heavy components. The oil sands at the center of the physical model were obviously lighter than that at the side, which presented higher higher oil displacement efficiency, as shown in Figure S5b,c. The oil sands at the bottom of the model were completely black, as shown in Figure S5d. The distribution of oil saturation was shown in Figure S6. The remaining oil saturation of the top layers was lower than that at the bottom, and the oil recovery of the bottom layer was the lowest especially near the production well, where the remaining oil saturation was almost the same as the initial oil saturation, demonstrating that gas override was advantageous to displace oil at the top of heavyoil reservoirs during steam or flue gas injection.36,37 However, condensed water flooding lead to a lower oil displacement efficiency at the bottom of thick heavy oil reservoirs. 284
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
Article
Energy & Fuels
Figure 10. Appearances of oil bubbles at different positions of visual window.
■
4. CONCLUSIONS
ACKNOWLEDGMENTS The authors acknowledge National Natural Science Foundation of China (nos. 51274212 and 51474226), National Program on Key Basic Research Project (no. 2015CB250906), and Important National Science & Technology Specific Projects (no. 2016ZX05047004001).
(1) The influence of flue gas on the physical properties of heavy oil was investigated by studying the PVT performance of an oil−flue gas system under different temperatures and pressures. The experimental results indicated that the dissolution of flue gas in heavy oil could increase oil expansibility and further reduce oil viscosity. (2) Steam flooding process could be divided into three periods, i.e., the ascent of oil production, the stability of oil production and the descent of oil production. The ultimate recovery of flue gas coupled with steam flooding was 49.49%, 7.95% higher than that of steam flooding in thick extra-heavy oil reservoirs. (3) CO2 dissolved in crude oil gradually separated out from heavy oil to form microbubbles dispersed in the oil phase as pressure declined, which effectively improved heavy oil mobility while it increased gas-phase flow resistance. The injected flue gas, as a kind of noncondensate gas, was beneficial to displace the remaining oil at the top of the reservoir and to decrease heat loss from the reservoir to the upper rock. In addition, flue gas gathered at the top that was not produced, thus decreasing greenhouse gas emissions.
■
■
ASSOCIATED CONTENT
S Supporting Information *
The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.energyfuels.7b03081. Tables showing the similarity criterion, a comparison of field parameters, parameters for the 3D physical simulation experiment, the development characteristics of different CSS styles, and the variation of oil properties. Figures showing schematic diagrams, a viscosity−temperature relationship curve, the materials used to fill the layers, and the distribution of the remaining oil. (PDF)
■
REFERENCES
(1) He, P.; Zhang, X. B.; Peng, X. L.; Wu, J.; Jiang, X. M. Effect of fly ash composition on the retention of mercury in coal-combustion flue gas. Fuel Process. Technol. 2016, 142, 6−12. (2) Pawelec, A.; Chmielewski, A. G.; Licki, J.; Han, B.; Kim, J.; Kunnummal, N.; Fageeha, O. I. Pilot plant for electron beam treatment of flue gases from heavy fuel oil fired boiler. Fuel Process. Technol. 2016, 145, 123−129. (3) Szulc, P.; Tietze, T.; Wójs, K. Numerical analysis of a waste heat recovery process with account of condensation of steam from flue gases. Archives of Civil and Mechanical Engineering 2015, 15 (4), 1017−1023. (4) Maalouf, S.; Ksayer, E. B.; Clodic, D. Investigation of direct contact condensation for wet flue-gas waste heat recovery using Organic Rankine Cycle. Energy Convers. Manage. 2016, 107, 96−102. (5) Zimmermann, R.; Blumenstock, M.; Heger, H. J.; Schramm, K. W.; Kettrup, A. Emission of nonchlorinated and chlorinated aromatics in the flue gas of incineration plants during and after transient disturbances of combustion conditions: delayed emission effects. Environ. Sci. Technol. 2001, 35 (6), 1019−1030. (6) Trojan, M.; Taler, D. Thermal simulation of superheaters taking into account the processes occurring on the side of the steam and flue gas. Fuel 2015, 150, 75−87. (7) Kang, S. P.; Lee, H. Recovery of CO2 from flue gas using gas hydrate: thermodynamic verification through phase equilibrium measurements. Environ. Sci. Technol. 2000, 34 (20), 4397−4400. (8) Seo, Y. T.; Moudrakovski, I. L.; Ripmeester, J. A.; Lee, J. W.; Lee, H. Efficient recovery of CO2 from flue gas by clathrate hydrate formation in porous silica gels. Environ. Sci. Technol. 2005, 39 (7), 2315−2319. (9) Liu, Y. M.; Ye, Q.; Shen, M.; Shi, J. J.; Chen, J.; Pan, H.; Shi, Y. Carbon dioxide capture by functionalized solid amine sorbents with simulated flue gas conditions. Environ. Sci. Technol. 2011, 45 (13), 5710−5716. (10) Wang, J. S.; Ryan, D.; Anthony, E. J.; Wigston, A.; Basava-Reddi, L.; Wildgust, N. The effect of impurities in oxyfuel flue gas on CO2 storage capacity. Int. J. Greenhouse Gas Control 2012, 11, 158−162. (11) Tian, S. C.; Jiang, J.G. Sequestration of flue gas CO2 by direct gas−solid carbonation of air pollution control system residues. Environ. Sci. Technol. 2012, 46 (24), 13545−13551. (12) Chadwick, A.; Arts, R.; Bernstone, C.; May, F.; Thibeau, S.; Zweigel, P. Best practice for the storage of CO2 in Saline Aquifers − observations and guidelines from the SACS and CO2 STORE Projects; British Geological Survey: Nottingham, U.K., 2007.
AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. ORCID
Zhengbin Wu: 0000-0003-1507-673X Notes
The authors declare no competing financial interest. 285
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
Article
Energy & Fuels (13) Arts, R. J.; Chadwick, A.; Eiken, O.; Thibeau, S.; Nooner, S. Ten years of experience with CO2 injection in the Utsira Sand at Sleipner (offshore Norway). First Break 2008, 26, 65−72. (14) Ofori, A. E.; Engler, T. W. Effects of CO2 sequestration on the petrophysical properties of an aquifer rock. Canadian Unconventional Resources Conference; Society of Petroleum Engineers: Alberta, Canada, 2011. (15) Seeberger, F.; Hugonet, V. Barriers and consequence analysis for subsurface containment in Barendrecht CO2 storage. Energy Procedia 2011, 4, 4100−4108. (16) Arts, R. J.; Hofstee, C.; Vandeweijer, V. P.; Pluymaekers, M. P. D.; Loeve, D.; Kopp, A.; Plug, W. J. The feasibility of CO2 storage in the depleted P18−4 gas field offshore the Netherlands (the ROAD project). Int. J. Greenhouse Gas Control 2012, 11, s10−s20. (17) Kaveh, N. S.; Rudolph, E. S. J.; Wolf, K. H. A. A.; Ashrafizadeh, S. N. Wettability determination by contact angle measurements: hvbB coal−water system with injection of synthetic flue gas and CO2. J. Colloid Interface Sci. 2011, 364, 237−247. (18) van Bergen, F.; Krzystolik, P.; van Wageningen, N.; Pagnier, H.; Jura, B.; Skiba, J.; Winthaegen, P.; Kobiela, Z. Production of gas from coal seams in the Upper Silesian Coal Basin in Poland in the postinjection period of an ECBM pilot site. Int. J. Coal Geol. 2009, 77, 175− 187. (19) Mazzotti, M.; Pini, R.; Storti, G. Enhanced coal bed methane recovery. J. Supercrit. Fluids 2009, 47, 619−627. (20) Yang, C.-Z.; Han, D.-K. Present status of EOR in the Chinese petroleum industry and its future. J. Pet. Sci. Eng. 1991, 6, 175−189. (21) Wu, Z. B.; Liu, H. Q.; Pang, Z. X.; Wu, C.; Gao, M. Pore-scale experiment on blocking characteristics and EOR mechanisms of nitrogen foam for heavy oil: a 2D visualized study. Energy Fuels 2016, 30, 9106−9113. (22) Thomas, S. Enhanced oil recovery−an overview. Oil Gas Sci. Technol. 2008, 63, 9−19. (23) Sun, Y. T.; Zhong, L. G. Enhance offshore heavy oil recovery by cyclic steam-gas-chemical co-stimulation. Proceedings of the SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, December 12−14, 2011; SPE: Alberta, Canada, 2011. (24) Liu, D.; Zhao, C.; Su, Y.; Li, Y.; Zhang, F.; Huang, Y. New research and application of high efficient development technology for offshore heavy oil in China. Proceedings of the Offshore Technology Conference, Houston, Texas, April−3 May, 2012; Infield: London, U.K., 2012. (25) Liu, Y. G.; Yang, H. L.; Zhao, L. C.; Sun, Y. T.; Cui, G.; Zhao, M. G.; Hu, S. B.; Zhong, L. G. Improve offshore heavy oil recovery by compound stimulation technology involved thermal, gas and chemical methods. Proceedings of the 2010 Offshore Technology Conference, Houston, Texas, May 3−6, 2010; Infield: London, U.K., 2010. (26) Redford, D. The Use of solvents and gases with steam in the recovery of bitumen from oil sands. Journal of Canadian Petroleum Technology 1982, 21 (1), 45−53. (27) Balog, S. E.; Kerr, R. K.; Pradt, L. A. The wet air oxidation boiler for enhanced oil recovery. Journal of Canadian Petroleum Technology 1982, 21 (5), 73−79. (28) Ali, S. M. F.; Flock, D. L. Steamflood performance in the presence of carbon dioxide and nitrogen. Journal of Canadian Petroleum Technology 1983, 22 (5), 30−37. (29) Pebdani, F. N.; Shu, W. R. Heavy oil recovery process using cyclic carbon dioxide steam stimulation: U.S. Patent 4565249, September 20, 1984. (30) Hornbrook, M. W.; Dehghani, K.; Qadeer, S.; Ostermann, R. D.; Ogbe, D. O. Effects of CO2 addition to steam on recovery of West Sak crude oil. SPE Reservoir Eng. 1991, 6 (4), 278−286. (31) Srivastava, R. K.; Huang, S. S.; Mourits, F. M. A laboratory evaluation of suitable operating strategies for enhanced heavy oil recovery by gas injection. Journal of Canadian Petroleum Technology 1997, 36 (2), 33−41. (32) Leung, L. C. Numerical evaluation of the effect of simultaneous steam and carbon dioxide injection on the recovery of heavy oil. JPT, J. Pet. Technol. 1983, 35 (9), 1591−1599.
(33) Mimura, T.; Shimojo, S.; Suda, T.; Iijima, M.; Mitsuoka, S. Research and development on energy saving technology for flue gas carbon dioxide recovery and steam system in power plant. Energy Convers. Manage. 1995, 36 (6−9), 397−400. (34) Srivastava, R. K.; Huang, S. S.; Dong, M. Z. Comparative effectiveness of CO2 produced gas and flue gas for enhanced heavy-oil recovery. SPE Reservoir Eval. Eng. 1999, 2 (3), 238−247. (35) Trevisan, O. V.; Laboissiere, P.; Monte-Mor, L. S. Laboratory study on steam and flue gas co-injection for heavy oil recovery. Proceedings of the SPE Heavy Oil Conference Canada, Calgary, Canada, June 11−13, 2013; SPE: Houston, TX, 2013. (36) Frauenfeld, T. W. J.; Ridley, R. K.; Nguyen, D. M. Effect of an initial gas content on thermal EOR as applied to oil sands. JPT, J. Pet. Technol. 1988, 40 (3), 333−338. (37) Li, Z.; Lu, T.; Tao, L.; Lin, B.; Zhang, J.; Li, J. CO2 and viscosity breaker assisted steam huff and puff technology for horizontal wells in a super-heavy oil reservoir. Pet. Explor. Dev. 2011, 38 (5), 600−605.
286
DOI: 10.1021/acs.energyfuels.7b03081 Energy Fuels 2018, 32, 279−286
