3D Experimental Investigation on Enhanced Oil Recovery by Flue Gas

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3D Experimental Investigation on Enhanced Oil Recovery by Flue Gas Coupled with Steam in Thick Oil Reservoirs Zhengbin Wu, Huiqing Liu, and Xue Wang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03081 • Publication Date (Web): 07 Dec 2017 Downloaded from http://pubs.acs.org on December 16, 2017

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3D Experimental Investigation on Enhanced Oil Recovery by Flue Gas Coupled with Steam in Thick Oil Reservoirs Wu Zhengbin*, Liu Huiqing, Xue Wang State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, PR China

Abstract: Flue gas is a kind of non-condensate gas that mainly consisted of CO2 (volume percentage about 20%) and N2 (volume percentage about 80%), and is applied in petroleum industry as a kind of displacement agents. In this paper, flue gas is introduced into the thermal recovery process of thick heavy oil reservoir. First, the dissolution characteristics of flue gas in crude oil were researched through the PVT experiments under different conditions. Then, a series of 3D physical simulations were carried out to analyze the oil displacement effect of flue gas coupled with steam flooding in thick reservoir with the consideration of the important production parameters including oil production, water cut, oil-steam ratio and oil recovery in both steam flooding process and the flue gas coupled with steam flooding process. Finally, the EOR mechanisms of flue gas coupled with steam flooding were summarized by analyzing the variation of temperature field, the properties of heavy oil and the distribution of remaining oil. This study provided a reference that the reasonable use of flue gas can improve recovery of thick heavy oil reservoir while reducing greenhouse gas emissions. Key words: heavy oil reservoir; steam flooding; flue-gas; EOR; physical simulation

1 Introduction In 2015, global emissions from fossil fuel combustion reached 3.57×1010 t and Chinese annual greenhouse gas emissions is estimated to be 9.52×109 t 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 900m to 1500m in depth. The crude oil viscosity ranges from 200 mPa·s 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 equipments.23-24 Therefore, a 1

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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 multi-thermal fluid stimulation in 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 other inert gases since 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. But a higher gas concentration would reduce heat transfer and increase relative permeability of 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 easier, the EOR mechanisms of flue gas injection will be more complex and should be paid more attention. In this article, PVT experimental apparatus was first employed to analyze the properties of heavy oil-flue gas under different temperature and pressure conditions. Then, 3D physical simulation was used to research the development effect and the storage volume of flue gas after steam flooding in thick extra heavy oil reservoirs. Finally, the EOR mechanisms of flue gas coupled with steam flooding were summarized according to the experimental results.

2 Experimental Apparatus and Procedures 2.1 PVT Experiments The PVT experimental apparatus is shown in Figure S1. A vacuum pump is used to remove air in PVT experimental apparatus in order to eliminate its influence on experiment. A falling-sphere-viscometer with the measuring range from 0.5 to 100,000 mPa·s and the highest affordable pressure of 70 MPa is adopted for the measurement of oil viscosity. The PVT cell with magnetic mixer is to make gas adequately dissolve in crude oil under high pressure and high temperature. The fluid sampler is to collect the mixed oil and gas to measure the viscosity of fluids under required pressure and temperature. Therefore, the gas solubility and the viscosity of oil dissolved with gas can be measured under the required conditions. The experimental procedures are shown as following: 1) The degassed oil and flue gas is stored in the oil sample tank and gas tank, respectively. 2) A certain amount of degassed oil sample is injected into the sample preparation device, and according to the dissolved gas/oil ratio of the oil sample, a certain amount of flue gas is injected into the sample preparation device from gas tank. Then, the oil–gas mixture is stirred for 30 minutes under the required temperature and pressure. 3) After the gas is fully dissolved into the crude oil, the sample is transferred into the sampler and PVT cell to test the physical properties.

2


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2.2 3D Physical Simulation 2.2.1 Experimental apparatus The experimental system for 3D thermal recovery simulation is shown in Figure S2. It mainly consists of five parts, i.e. the injection system, reservoir model, production system, data acquisition system and auxiliary system. The injection system includes injection pumps, steam generator, nitrogen cylinder, gas mass flowmeter, electric heating belts, storage tanks and etc. Reservoir model includes a 3D physical model and a constant temperature oven. Production system includes visible windows of high pressure, back pressure valve, and cylinder etc.. Data acquisition system mainly includes pressure sensors, temperature sensors, data sensors and a computer. Auxiliary system mainly includes drying box, viscometer and an electronic balance. The 3D physical model is shown in Figure 1. The inner chamber is 40 cm in width and 40 cm in depth. The highest affordable pressure and temperature is 20 MPa and 300 °C, respectively. The top and the bottom of the model are filled with impermeable clay to simulate the cap-rock and the bottom layer. Injection wells and pipelines are all bounded by electric heating belts which can avoid heat loss during steam injection. The temperature is set as the steam temperature to prevent steam from condensing before it flows into the 3D physical model. In production system, the visible window is adopted to study the influence of flue gas on heavy oil properties and to analyze the characteristics of oil-foam occurrence and migration.

Figure 1. The picture of 3D physical simulation model

2.2.2 Experimental parameters In terms of the rock and fluids properties in LD5-2N block, a thick extra heavy oil reservoir of Bohai offshore oilfield in China, the experimental parameters are designed to simulate the different production periods including cyclic steam stimulation (CSS), steam flooding and flue gas coupled with steam flooding. The oil sample is dehydrated and degassed heavy oil from LD5-2N block. The experimental temperature and pressure are both in accordance with that of LD5-2N block. Given the assumption that thermal physical properties of oil sands used in the experiment is identical to the rock in the actual reservoir, then the experimental parameters can be calculated according to the similarity criterion of steam injection, as shown in Table S1. The horizontal injection well is installed on the right side of the 3D physical model and the horizontal production well is 3


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installed on the left side. According to the similarity criterion in Table S1 and the actual size of LD5-2N, the simulation size of the model can be calculated according to the equation (1). The actual well spacing and the actual net pay are respectively 112m and 40m. And the inner width of the physical model is 40cm. Therefore, the thickness of the physical model is 16cm, as shown in Figure 2. The length of horizontal well in actual oilfield is 500m, so the horizontal well of the experiment should be 177.8cm in length. However, the actual inner width of the model is 40 cm. Therefore, the calculated length of horizontal well is 4.44 times as long as that in the physical model.

r ( L) =

xm hm = x p hp

(1)

Where x is well spacing, m; h is net pay, m. m represents model size and p represents practical size.

11cm Injection well

Production well

16cm

5cm

40cm

Figure 2. The schematic diagram of production well and injection well in 3D physical model

The experimental parameters are listed in Table S2. The CSS process is performed for three cycles. During each cycle, the termination condition of CSS is no liquid produced. When the third cycle is over, the average pressure declines to 3MPa, then steam flooding begins to be conducted. During steam flooding, the back pressure is always maintained under 3MPa at the outlet of production well. It is turned to flue gas assisted steam flooding until the oil-steam ratio is lower than 0.1. During the stage of flue gas assisted steam flooding, the back pressure is still maintained under 3MPa at the outlet. The whole experiment is terminated until the oil-steam ratio is lower than 0.1 again. The injection-production parameters are listed in Table S3. 2.2.3 Experimental procedures 1) According to the experimental design, quartz sands of appropriate particle size are prepared to fill the physical model. 2) After accuracy checking, the temperature and pressure sensors, along with the two horizontal wells are installed at the aimed locations of the physical model. Then, the mixture of quartz, crude oil and formation water is filled into the physical model. 3) The physical model is placed in the constant temperature oven at 50 ℃. After heating for 48 hours, the crude oil is injected into the model by pump at low rate to make the inner pressure of the model meet the experimental design. The temperature and pressure values of all sensors in the model can be acquired through the data acquisition system. 4) During the CSS process, the steam temperature is 250 ℃ and the steam quality is 70%. In the first cycle, steam is injected at the rate of 11 mL/min for 5 minutes. Then the two wells are shut for 2 minutes. Afterwards, the back pressure is 4


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adjusted to 8MPa to conduct the first cycle production. In the second cycle, steam is injected at 11 mL/min for 6 minutes and then the wells are shunt in for 2 minutes. The back pressure is adjusted to 6 MPa. In the third cycle, steam is injected at 11 mL/min for 7 minutes. After shunt in for 2 minutes, the back pressure is adjusted to 3 MPa for production. The termination condition of each cycle is no liquid is produced from the well. During the whole CSS process, the temperature field of each cycle is monitored and the production liquid is collected and measured. 5) Steam flooding is performed following CSS. The steam temperature is 250 °C, steam quality is 70%, steam injection rate is 25 mL/min, and the back pressure of 3 MPa. The steam flooding process is completed until the oil-steam ratio is lower than 0.1. Similar to the CSS process, the temperature field of steam flooding process is also monitored and the production liquid is collected and measured. 6) After the steam flooding, flue gas coupled with steam is injected into the model. The fluid flux is 25mL/min and the volume ratio of steam and flue gas is 3:2 under 3 MPa. Liquid production and water cut are measured in real time. Temperature field is also recorded by the data collection device. The experiment is completed until the oil-steam ratio is lower than 0.1.

2.3 Experiment Materials 2.3.1 Reservoir Fluids The crude oil in the experiments is degassed oil from LD5-2N block in Bohai offshore oilfield, China. The oil density is 0.97 g/cm3. The oil viscosity is 28469.6 mPa·s at 50 °C, which belongs to extra heavy oil. The curve of viscosity-temperature relationship is shown in Figure S3. The salinity of the formation water varies from 2130 mg/L to 5491 mg/L. In this paper, flue gas used for enhancing steam flooding is a mixture of N2 (80%) and CO2 (20%). 2.3.2 Formation Rocks As shown in Figure S4, the oil layer is filled with quartz sands of 40 mesh (Figure S4a), and the top and bottom of the model are filled with compacted and impermeable clay (Figure S4b). The other four inner sides of the physical model are sealed with a kind of temperature-resistant fluorine rubber (Figure S4c) to form a heat-insulating layer. The photos of Figure S4b-S4d are took with a Leica camera.

3 Results and discussions 3.1 PVT Experiment 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 are chosen as 30 °C, 50 °C, 80 °C, 120 °C and 180 °C while the experimental pressures are chosen as atmosphere pressure (0.1 MPa), 2 MPa, 4 MPa, 8 MPa and 12 MPa. The PVT test results of heavy oil–flue gas system are shown in Figure 3(a)–(d). It can be seen that with the increase of temperature, the solubility of flue gas and the swelling factor of heavy oil-flue gas system are both reduced. That is because higher temperature increases molecular movement of flue gas. At a certain temperature, the increasing pressure makes CO2 dissolve in crude oil to form miscible phase, thus further decreasing oil viscosity (Figure 3d) and generating solution gas drive 5


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as the reservoir pressure declines. 40

1.08

35

1.07

2MPa 8MPa

25 Solubility(m 3 /m 3 )

4MPa

Volumetic expansion coefficient

30

12MPa

20 15 10 5

1.06

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1.05 1.04 1.03 1.02 1.01 1.00

0 0

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(b)Volume expansion coefficient of heavy oil–flue gas system

(a) Solubility of flue gas in heavy oils

100

1000000 Degassed oil

2MPa

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90

The percentage of viscosity reduction (%)

100000

Viscosity (mPa·s)

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12MPa 10000

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(d) The percentage of viscosity reduction of heavy oil

(c) Viscosity of heavy oil–flue gas system

Figure 3. The curve of crude oil properties after dissolved by flue gas

3.2 3D Physical Simulation 3.2.1 Cyclic steam stimulation Table S4 presents the production characteristics of the CSS process. The oil recovery after each cycle during the CSS process is 1.55%, 2.88% and 4.97% respectively. The reservoir pressure varies from 10 MPa to 3 MPa during the CSS process, meeting the condition to conduct steam flooding. 3.2.2 Steam flooding As shown in Figure 4 (a) and (b), the production process of steam flooding is divided into three typical periods, e.g. the ascent, the stability, and the descent of oil production. Firstly, both oil production and water cut largely increase. Then, oil production is basically stable and water cut slightly increases. However, the oil production increases largely at the last stage of the second period. The appearance of this phenomenon is because that with the continuous injection of high-temperature steam, the thermal front gradually moves to production well from the injection well. As shown in Figure 8e, the thermal front finally reaches the production well during the second period of steam flooding so that the reservoir is heated on the whole, leading to a decrease in oil viscosity and an increase in oil production. Finally, oil production decreases quickly and water cut increase 6


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largely. The contour plots of temperature field are as shown in Figure 4 (d)-(f). When the injected volume of steam reaches 0.22 PV, steam chamber gradually expands from the injection well to the central of the reservoir, as shown in Figure 4 (d). When the injected volume is 1.07 PV, the front of steam chamber reaches the production well, that is, steam channeling occurs, as shown in Figure 4 (e). When steam is injected 2.38 PV, the oil-steam ratio is lower than 0.1, as shown in Figure 4 (b), and the steam flooding process is completed. The ultimate recovery is 41.54%. During steam flooding process, the pressure of reservoir is basically stable, as shown in Figure 4 (c). 25

100 Flue gas assisted steam flooding

Steam flooding

80

15

60

Oil production Water cut

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(d) Thermal front reaches the center during the first period

(a) Oil production and water cut vs. PV 60

1.0 Flue gas assisted steam flooding

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(e) Thermal front reaches production well during the second period

(b) Oil recovery and oil-steam ratio vs. injected PV 12 Steam flooding

CSS

Flue gas assisted steam flooding

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Pressure (MPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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(f)steam channeling during the third period

(c) Pressure vs. time ① The ascent of oil production;

The stability of oil production;

The descent of oil production

Figure 4. The experimental results of production performance during 3D physical simulation

Figure 5-11 reveal the temperature distribution during the three periods of steam flooding, respectively. In Figure 5, the steam chamber gradually moves to production well from injection well during the first period. Meanwhile, steam flows to the top of the reservoir while the condensed water migrates to the bottom due to gravity segregation. The temperature front 7


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exceeds the central of the reservoir at 174 min and an obvious steam override is observed. After the first period, the oil recovery increases from 4.97% to 16.29%.

3 min of steam flooding




Figure 5. The temperature distribution during the first period

In Figure 6, the steam chamber mainly expands horizontally during the second period. The oil production the oil-steam ratio become stable. The heated area is enlarged greatly and the temperature front reaches 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.





Figure 6. The temperature distribution during the second period

In Figure 7, steam channeling occurs at 740 min. In this period, the oil production and the oil-steam ratio decline greatly, and water cut increases obviously. Oil production decreases from the largest value of 12.6 mL/min to 2.4 mL/min and water cut increases dramatically from 83.2% to 92.3%. The steam chamber is stable, but there is an obvious steam override above the injection well. When steam flooding has been conducted for 825 min, the oil-steam ratio is equal to 0.09. The ultimate oil recovery is 41.54% which is enhanced by 3.49% than the second period.

8


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Figure 7. The temperature distribution during the third period

3.2.3 Flue gas coupled with steam flooding (1) Production performance The temperature field of the reservoir is shown in Figure 8 after flue gas injection. In the early stage of flue gas injection, flue gas is able to promote steam migrating to production wells, which further increases oil production and reduces water cut. In addition, flue gas migrates upward due to density difference between gas and steam to displace remaining oil at the top and to form a heat insulation layer to prevent heat loss from the reservoir top. Meanwhile, most flue gas will 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 mL/min 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 end of steam flooding (860 min of steam flooding) 60 min of flue gas injection (a) The expansion of thermal front

120 min after flue gas injection

180 min of flue gas injection

240 min of flue gas injection 480 min of flue gas injection (b) The promotion of steam chamber

Figure 8. The temperature distribution during flue gas coupled with steam flooding

9


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(2) Properties of crude oil The photographs of produced crude oil in different displacement processes are shown in Figure 9. The initial degassed crude oil is extra-heavy oil with high viscosity and is pure black as shown in Figure 9a. After steam flooding, some tiny bubbles are dispersive in oil which appears light black as shown in Figure 9b. The bubbles mainly come from the light components dissolved in crude oil which become gas-phase under high temperature. After flue gas coupled with steam flooding, a large amount of bigger bubbles appear in oil which presents brown. The mobility of crude oil is increased significantly and the crude oil expands obviously as a result of flue gas dissolution.34-35 Table S5 presents the variation of oil properties during different displacement periods. It can be seen that after 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). And with the injection of flue gas, each index changes more obviously. The variation of oil density, viscosity and components illustrate that the flue gas is helpful to further reduce oil viscosity and improve oil mobility.

(a) Initial degassed oil

(b) After steam flooding

(c) After flue gas injection

Figure 9. The 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 10 (a), the crude oil at the inlet of visual window is fully swept by flue gas. On both sides of the flowing path, some large bubbles are scattered in oil-rich region. In Figure 10 (b), there is much more oil at the center of visual window than that at the inlet. A large number of tiny bubbles are scattered in oil which appears darker. There is also a wide range of dispersed gas at the center. While in Figure 10 (c), there are large number of micro-bubbles with almost uniform size at the out let and the micro-bubbles steadily migrates with oil-phase together. These pictures visually present the morphological variation of heavy oil after flue gas injection and reveal the solution gas drive process, demonstrating that the injection of flue gas is beneficial for enhancing oil recovery. In addition, the produced emulsions are transported through a flash separator and the gas volume is calculated by a gas flowmeter under atmosphere. The result indicates that the gas flows through the gas flowmeter is about 1960 mL. The flue gas is injected about 480 min as shown in Figure 8, and the flue gas injection rate is 10 mL/ min as revealed in Table S3. Therefore, the total volume of injected flue gas under atmosphere is 4800 mL, demonstrating that most injected gas is trapped in the 3D physical model and dissolves in the produced oil.

10


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(a) The inlet

(b) The center

(a) The outlet

Figure 10. The appearances of oil bubbles at different positions of visual window

(3) Distribution of remaining oil The distribution remaining oil after flue gas coupled with steam flooding is shown in Figure S5. From Figure S5 (a), at the top of the physical model, the remaining oil saturation has been reduced largely after flue gas assisted steam flooding. But the oil sands above the injection well shows darker and harder due to remained heavy component. At the center of the physical model, the color of oil sands is obviously lighter than that at the side, which presents higher oil displacement efficiency, as shown in Figure S5 (b) and (c). The color of oil sands is whole black in the bottom of the physical model, as shown in Figure S5 (d). The distribution of oil saturation is shown in Figure S6. The remaining oil saturation of the top two layers is obviously lower than that at the bottom and the oil recovery of the bottom layer is lowest especially near the production well whose remaining oil saturation is as almost same as the initial oil saturation, demonstrating that gas override is advantageous to displace oil at the top of heavy oil reservoirs during steam or flue gas injection.36-37 However, condensed water flooding leads to a lower oil displacement efficiency at the bottom of thick heavy oil reservoirs.

3.4 EOR Mechanisms (1) Flue gas contains 20% of CO2 and 80% of N2, and is a non-condensate gas under reservoir conditions. CO2 can be fully dissolved into heavy oil to reduce oil viscosity and enhance its mobility. The solubility of N2 in crude oil is weak, but it can effectively maintain reservoir pressure to increase displacement force. Compared with steam flooding, flue gas coupled with steam flooding further improves oil displacement efficiency and reduces residual oil saturation. (2) During the displacement process, flue gas preferentially flows to the top of reservoir to displace remaining oil left by steam injection. Moreover, the flue gas gathering at the top form a heat insulation layer because of low thermal conductivity to prevent heat loss. Meanwhile, the condensate water primarily migrates to the bottom due to gravity segregation, which is beneficial to displace remaining oil at the top. (3) As pressure declines, CO2 dissolved in crude oil gradually separates out from oil-phase to form micro-bubbles dispersed in oil-phase. Flue gas forms dispersed gas-phase and flows with oil-phase together, which effectively improves the heavy oil mobility while increases gas-phase flow resistance.

4 Conclusions (1) The main components of flue gas include N2 and CO2. The influence of flue gas on the physical properties of heavy oil is investigated by studying the PVT performance of oil-flue gas system under different temperatures and pressures. The experimental results indicate that the dissolution of flue gas in heavy oil can increase oil expansibility and further reduce oil viscosity. 11


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(2) Steam flooding can 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 is 49.49%, 7.95% higher than that of steam flooding in thick extra heavy oil reservoirs. (3) CO2 dissolved in crude oil gradually separates out from heavy oil to form micro-bubbles dispersed in oil-phase as pressure declines, which effectively improves heavy oil mobility while increases gas-phase flow resistance. The injected flue gas, as a kind of non-condensate gas, gradually gathers at the top of the reservoir, which is beneficial to displace remaining oil and decreases heat loss from the reservoir to upper rock. In addition, flue gas gathers at the top that is not produced, thus decreases greenhouse gas emissions.

Acknowledgement The authors would like to acknowledge National Natural Science Foundation of China (No.51274212 and No. 51474226), National Program on Key Basic Research Project (No. 2015CB250906), and Important National Science & Technology Specific Projects (2016ZX05047004001).

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3D Experimental Investigation on Enhanced Oil Recovery by Flue Gas

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