- Email: [email protected]
Effect of flue gas and n-hexane on heavy oil properties in steam flooding process
Fuel 187 (2017) 84–93
Contents lists available at ScienceDirect
Fuel journal homepage: www.elsevier.com/locate/fuel
Full Length Article
Effect of flue gas and n-hexane on heavy oil properties in steam flooding process Songyan Li ⇑, Zhaomin Li ⇑, Xiaona Sun College of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
a r t i c l e
i n f o
Article history: Received 7 July 2016 Received in revised form 13 September 2016 Accepted 14 September 2016 Available online 20 September 2016 Keywords: Flue gas n-Hexane Steam flooding Oil properties Production mechanism
a b s t r a c t Heavy-oil reservoirs with thin-pay and bottomwater can be exploited effectively by thermal recovery process assisted by flue gas and n-hexane. The interface properties between flue gas/n-hexane and heavy oil and viscosity reduction of the heavy oil were investigated by laboratory experiments. Steam flooding, flue gas assisted steam flooding, n-hexane assisted flooding and flue gas and n-hexane assisted steam flooding were conducted to research the displacement pressure difference, oil displacement efficiency and component variation of produced and residual oils. The results show that the flue gas dissolving in heavy oil can effectively reduce oil viscosity, increase the flow capability, and make the heavy oil swell. Higher pressure reduces surface tension of heavy oil and gas, and higher temperature increases surface tension. Compared with flue gas, n-hexane can reduce heavy oil viscosity and surface tension more obviously. The flue gas and n-hexane can effectively improve the development effect of the steam flooding. The pressure difference of steam flooding assisted by flue gas and n-hexane is the lowest, the oil production rate is greatest, and the oil recovery efficiency can reach 80%. Flue gas and n-hexane can effectively change crude oil properties. The heavy components, molecular weight of asphaltene and oil viscosity for the produced oil all reduced. The heavy components and molecular weight of asphaltene for the residual oil in sandpacks all increased. The effect of flue gas and n-hexane together on heavy oil is the greatest. The asphaltenes component in the residual oil is not as stable as that in produced oil. The experimental results not only show that flue gas and n-hexane can successfully improve the performance of steam flooding process, but also provide a deep understanding of properties changes of produced and residual oils for the flooding. Ó 2016 Elsevier Ltd. All rights reserved.
1. Introduction 1.1. Collection and utilization of flue gas for heavy oil production Global warming caused by the excessive emission of greenhouse gases has become one of the most significant environmental problems currently faced by society. According to the Kyoto Protocol and the Copenhagen International Conference on environmental requirements, each country has an obligation to reduce CO2 emissions. For the next 50 years, fossil fuels will remain as the main energy source for the world, and CO2 from fossil fuel combustion will account for approximately 80% of the total emissions. Flue gas from fossil fuel power plants is the greatest long-term emission source of CO2 [1–5]. Carbon capture and storage (CCS) has been widely regarded as an effective solution to reduce CO2 in the atmosphere to mitigate ⇑ Corresponding authors. E-mail addresses: [email protected] (S. Li), [email protected] (Z. Li). http://dx.doi.org/10.1016/j.fuel.2016.09.050 0016-2361/Ó 2016 Elsevier Ltd. All rights reserved.
global warming. However, the profit from CCS cannot compensate for its high cost. CO2-enhanced oil recovery, which has been widely used in oil field development, can reduce CO2 emissions and improve crude oil recovery efficiency. CO2-enhanced oil recovery is the option with the most potential for carbon capture, utilization and storage (CCUS) [6–10]. Crude oil production in the oilfield has provided abundant fossil fuel to the world, but it also consumes a large amount of energy. In the process of heavy oil production, a large proportion of heavy oil that is produced is used as fuel in the boiler for heating steam, which is then injected into a reservoir for thermal recovery. Flue gas from the boiler is a stable long-term CO2 emission source in the oilfield. Related research and field applications prove that flue gas injected into the reservoir with steam can greatly improve heavy oil development [11]. Flue gas collection also avoids the complex process of CO2 separation in CCS, which is suitable for a small-scale steam injection boiler. The collection and utilization of flue gas in a steam injection boiler will become an important method for reducing greenhouse gas emissions in oilfields.
85
S. Li et al. / Fuel 187 (2017) 84–93
1.2. Solvent and flue gas assisted steam flooding Heavy oil from thick-pay reservoirs is usually exploited with thermal recovery method. These methods related to steam injection are generally not suitable for thin reservoirs because of the heat loss to overburden and underburden or bottomwater zones [12–14]. China has tremendous heavy oil in Xinjiang, Liaohe and Shengli Oilfield, however, most Chinese heavy-oil reservoirs cannot be exploited economically by thermal recovery process because the reservoir formations are thin and there is usually active bottomwater or edgewater. In the literatures, some researches have been conducted to evaluate the recovery methods for these special reservoirs. Among the methods solvent-based processes are probably the most promising EOR techniques. In practice, the solvent can be CO2, flue gas, methane, ethane, propane, and butane. In a typical solvent-based process, the wellaccepted EOR mechanisms are oil viscosity reduction, oil swelling and interfacial tension reduction when a solvent dissolves into heavy oil [15–19].
PVT cell P
P
Falling-ball viscometer Flue gas and oil Flue gas
Controller Controller
p Pump
BPR
Fig. 1. Schematic diagram of the flue gas dissolving property apparatus.
1.3. Purpose of this paper Table 1 Properties of the heavy oil used in the experiments. Property
Unit
Value
Density at 20 °C Viscosity at 20 °C Saturate content Aromatic content Resin content Asphaltene content
kg/m3 mPa s wt% wt% wt% wt%
968.5 7.61 105 40.18 23.52 30.09 6.21
1000000
Viscosity (mPa·s)
Although many laboratory experiments have been conducted to evaluate the effect of CO2 on crude oil in a PVT cell and study EOR performance of the CO2 flooding, few attempts have been made to investigate effect of flue gas and n-hexane on the properties of the produced and residual oil during steam flooding process. It is wellaccepted that, in a CO2 flooding process, the injected CO2 is capable of extracting light and intermediate hydrocarbons from the reservoir oil [20–22]. The oil components alteration during solvent assisted steam flooding may cause the asphaltene precipitation and deposition in the reservoir. Therefore, it is important to evaluate the oil properties during the solvent assisted steam flooding process. In this study, surface properties of heavy oil and solvent and four sandpack flooding tests were carried out under different conditions. The properties of the produced oil at different periods were characterized. Furthermore, the residual oil was extracted from the inlet and outlet of the residual oil sands in the sandpacks. The residual oil saturation was calculated and the asphaltenes content of the residual oil was measured using saturates, aromatics, resins, and asphaltenes (SARA) analysis.
100000
10000
1000
2. Experimental methods 2.1. Apparatus
100 10
20
30
40
50
60
Temperature (
70
80
90
100
)
Flue gas dissolving properties in heavy oil were tested using a PVT cell (with a pressure range of 60 MPa, temperature range of 200 °C, and temperature accuracy of ±0.1 °C) and a falling-ball viscometer (with a pressure range of 50 MPa, temperature range of 220 °C, viscosity range of 100,000 mPa s, and temperature accuracy of ±0.1 °C), which are shown in Fig. 1. The surface tension of heavy oil and solvent were determined by a drop shape tensiometer (Tracker-H, Teclis, France, full scale of 20 MPa and 200 °C) [23]. The experimental apparatus for sandpack flooding has been shown in previous studies [24,25].
are 99.99 mol%. The purity of the n-C6H14 (Xilong, Inc., China) is >95%. Analytic pure CaCl2 and NaCl at concentrations of 790 mg/L and 36,000 mg/L were employed in the experiments to simulate the formation water. Distilled water served as the liquid. The density and viscosity of the brine at 20 °C are 1028 kg/m3 and 1.17 mPa s, respectively.
2.2. Materials
2.3.1. Experiment steps for dissolving properties testing
The heavy oil used in the experiments was produced from Shengli Oilfield of China. Its basic properties are shown in Table 1, and the viscosity-temperature curve is shown in Fig. 2. Flue gas was mixed with N2 and CO2 with the mole ratio of 8:2. The purity of N2 and CO2 (Tianyuan, Inc., China) used in this work
Fig. 2. Viscosity-temperature curve of the heavy oil.
2.3. Experimental procedures
(1) A certain volume of dead oil and flue gas were injected into the PVT cell according to the gas-oil ratio. (2) The pressure of the mixture of heavy oil and flue gas was firstly pumped to a high value, ensuring all of the flue gas was dissolved in the heavy oil. Then the pressure of the
86
S. Li et al. / Fuel 187 (2017) 84–93
mixture was decreased, and the pressures and volumes of the mixture were recorded and plotted in a figure. The saturation pressure could be determined by the inflection point in the pressure-volume curve. (3) Then a certain volume of live oil dissolved with flue gas was injected into the falling-ball viscometer with the backpressure greater than the saturation pressure. The viscosity of the live oil was measured for 5 times, and the averaged value was adopted.
illustrate that the saturation pressure increases with dissolved gas-oil ratio under the same temperature. When the saturation pressure increases from 0.4 MPa to 6.0 MPa at 80 °C, the dissolved gas-oil ratio increases from 5.73 sm3/m3 to 16.69 sm3/m3, however, at the same pressure range the dissolved gas-oil ratio increases from 2.82 sm3/m3 to 10.76 sm3/m3 at 200 °C. Under the same dissolved gas-oil ratio, the higher the temperature, the greater the saturation pressures is. The reason is that gas molecular motion increases under higher temperature, which inhibits flue gas dissolution in crude oil.
2.3.2. Experiment steps for surface properties testing (1) Before testing, the high temperature and high pressure vessel, syringe, needle and sample pool of the drop shape tensiometer were washed with acetone and ethanol. Then the syringe was filled with heavy oil, and placed in the vessel. (2) The vessel was flushed with flue gas for 3 times to drain the air. Then the vessel was heated to a certain temperature for 60 min. (3) An oil droplet was injected on the tip of the needle. The shape of the oil droplet was captured by a CCD camera and sent to the computer by data collection and analysis system. The surface tension of the crude oil and flue gas was calculated using Laplace equation [26–30]. The surface tension was measured for 3 times, and the averaged value was adopted. 2.3.3. Experiment steps for sandpack flooding (1) Sandpacks with permeabilities from 2069 mD to 2133 mD and porosities from 35.85% to 36.31% were prepared, as the physical properties are similar within these ranges. The length of the sandpack is 60 cm, and the diameter is 2.54 cm. The sandpack was evacuated for more than 4 h before it was saturated with brine, and the pore volumes and permeabilities were tested. The key properties of the sandpacks are listed in Table 2. (2) Then the sandpack was displaced with dead oil at a rate of 0.2 mL/min until water production ceased. The initial oil saturation and irreducible water saturation were calculated. (3) The temperatures of the sandpack and the steam were set to 90 °C and 200 °C, respectively. Steam flooding was conducted with the volume flow rate of 2 mL/min, and backpressure of 3.0 MPa. When the water cut of the produced fluid reached 98%, the flooding experiment would be sopped. The pressure difference of the sandpack, and oil production were recorded and analyzed. The parameters for steam flooding assisted by flue gas or/and n-hexane are shown in Table 2. 3. Experimental results and discussions 3.1. Viscosity reduction properties 3.1.1. Saturation pressure of flue gas The relationship of dissolved gas-oil ratio and saturation pressure under different temperatures is shown in Fig. 3. The results
3.1.2. Swelling factor for crude oil The relationship of dissolved gas-oil ratio and swelling factor for the heavy oil under different temperatures is presented in Fig. 4. The experimental results display that the volume of the heavy oil with flue gas dissolving can swell obviously. Under the same temperature, the swelling factor of the live oil increases gradually with the rising dissolved gas-oil ratio, which is approximately linear. When dissolved gas-oil ratio increases from 1 sm3/m3 to 15 sm3/m3, the swelling factor increases from 1.057 to 1.135 at 80 °C, and it increases from 1.033 to 1.108 at 200 °C. Under the condition of the same dissolved gas-oil ratio, the swelling factor decreases with the rising temperature. 3.1.3. Viscosity reduction properties using flue gas In order to analyze the effect of viscosity reduction of flue gas or n-hexane on heavy oil, viscosity reduction rate is defined by Eq. (1).
Y¼
X1 X2 100% X1
ð1Þ
where Y is viscosity reduction rate, %; X1 is the original viscosity of the heavy oil, mPa s; X2 is the viscosity of the live oil dissolved with flue gas or n-hexane, mPa s. The relationship of dissolved gas-oil ratio and viscosity reduction rate under different temperatures is shown in Fig. 5. The results demonstrate that under the same temperature, the viscosity reduction rate increases with the rising dissolved gas-oil ratio. When dissolved gas-oil ratio increases from 1 sm3/m3 to 15 sm3/ m3 at 80 °C, the viscosity reduction rate increases from 12.9% to 60.0%; however, the viscosity reduction rate increases only from 3.5% to 36.4% at 200 °C. Under the same dissolved gas-oil ratio, the rising temperature can decrease viscosity reduction rate, and viscosity reduction effect of flue gas on heavy oil is lowered. 3.1.4. Viscosity reduction properties using solvent Viscosity reduction effects of n-pentane, n-hexane and nheptane were evaluated under 50 °C, and the results are shown in Fig. 6. It can be seen that under the same experimental temperature, higher solvent concentration is better for viscosity reduction of heavy oil. The reason is that the contents of resin and asphaltene are high in the heavy oil, and adding solvent into heavy oil can increase the content of light components and decrease the viscosity of the heavy oil. When the concentration of solvent increases from 5 wt% to 10 wt%, viscosity decreases rapidly, and when the concentration increases further, the viscosity decreases slowly.
Table 2 Parameters of the sandpack flooding. Test No.
Flooding pattern
Permeability (mD)
Porosity (%)
Initial oil saturation (%)
Flow rate of steam (mL/min)
Flow rate of flue gas (mL/min)
Flow rate of n-hexane (mL/min)
1# 2# 3#
Steam flooding Steam flooding assisted by flue gas Steam flooding assisted by n-hexane Steam flooding assisted by flue gas and n-hexane
2133 2076 2069
36.31 36.18 36.02
87.86 88.64 89.50
2.0 1.4 1.8
0 0.6 0
0 0 0.2
2089
35.85
88.07
1.2
0.6
0.2
4#
87
S. Li et al. / Fuel 187 (2017) 84–93
100
200 140 80
16
Viscosity reduction rate (%)
Dissolved gas-oil ratio sm3/m3
20
12
8
4
0
90
80
70
60
50 0
1
2
3
4
5
6
n-C 5 H12 n-C 6 H14 n-C 7 H16
7
0
5
Fig. 3. Relationship of dissolved gas-oil ratio and saturation pressure under different temperatures.
1.16
200 140 80
1.14
Swelling factor
1.12 1.10 1.08 1.06 1.04 1.02 1.00
0
2
4
6
8
10
12
14
16
Dissolved gas-oil ratio (sm3/m3) Fig. 4. Relationship of dissolved gas-oil ratio and swelling factor under different temperatures.
Viscosity reduction rate (%)
80
80 140 200
60
10
15
20
25
Solvent concentration (wt%)
Saturation pressure (MPa)
40
Fig. 6. Relationship of solvent concentration and viscosity reduction rate.
after the formation of the oil droplet. In order to test the effect of gas dissolution on the surface properties the dynamic surface tensions were measured at 140 °C and 5 MPa, which is shown in Fig. 7. The composition of the flue gas is 80 mol% of N2 with 20 mol% CO2. The dynamic surface tensions can be divided into two stages. The first stage is the diffusion process of gas in heavy oil as a wave period. The dynamic surface tensions decrease gradually, which is about 100 s. The second stage is balanced period, and the surface tensions are almost constants. Under the same temperature and pressure, the surface tension of N2 and heavy oil is the maximum, and that of CO2 is the minimum. The surface tension of the flue gas and heavy oil is between the two. The balanced surface tensions of flue gas and heavy oil at 80 °C, 140 °C and 200 °C were tested respectively, which are shown in Fig. 8. When the pressure increases from 0.2 MPa to 6.0 MPa, the surface tension reduces from 23.25 mN/m to 20.25 mN/m at 80 °C, however, it decreases from 28.81 mN/m to 25.03 mN/m at 200 °C. The surface tension decreases with the rising pressure under the same temperature, which is a linear relationship. This is because higher pressure makes more flue gas dissolve in the heavy oil, and the property difference of heavy oil and flue gas decreases. The surface tension increases with the rising temperature, because higher temperature makes less flue gas dissolve in the heavy oil, and the property difference of heavy oil and flue gas increases. The surface tensions of heavy oil with CO2, N2 and flue gas were tested at 140 °C, which is presented in Fig. 9. The results show that the surface tensions all decreases with the rising pressure, which is
20
30
0
2
4
6
8
10
12
14
16
Dissolved gas-oil ratio (sm3/m3) Fig. 5. Relationship of dissolved gas-oil ratio and viscosity reduction rate under different temperatures.
Compared the effects of the three solvents at the same concentration, the effect of pentane is poorer, and that of n-hexane and n-heptane are almost the same.
Surface tension (mN/m)
28
0
26 24 22
Flue Gas CO2 N2
20 18
3.2. Surface properties 3.2.1. Surface tension of heavy oil and flue gas Dynamic surface tensions of heavy oil and gases were tested by the drop shape tensiometer. The flue gas can dissolve in heavy oil
16
0
500
1000
1500
2000
Time (s) Fig. 7. Dynamic surface tension at 140 °C and 5 MPa.
2500
88
S. Li et al. / Fuel 187 (2017) 84–93
28
30 200 140 80
26
Surface tension (mN/m)
Surface tension (mN/m)
28 26 24 22 20 18
24
CO2
22
N2
20
Flue Gas n-C6 H14
18 16
0
1
2
3
4
5
6
14 0.15
7
0.20
Pressure (MPa)
0.25
0.30
0.35
0.40
0.45
Pressure (MPa)
Fig. 8. Equilibrium surface tension for flue gas and heavy oil under different temperatures.
Fig. 10. Surface tension for n-hexane and heavy oil at 140 °C.
a linear relationship. The surface tensions are close to each other under low pressure, however, the difference becomes greater and greater with the rising pressure. When pressure increases from 0.2 MPa to 6.0 MPa, the reduction of surface tension for CO2 and heavy oil from 31.65 mN/m to 23.07 mN/m is the greatest, and that for N2 and heavy oil from 31.78 mN/m to 29.11 mN/m is the least. The surface tension of flue gas and heavy oil is between the two, which is related to the property of the flue gas.
linearly with the rising pressure, because of the greater dissolution of the n-hexane into heavy oil. At the highest pressures of 100 °C, 140 °C and 200 °C in the experiments, the surface tensions are 14.57 mN/m, 13.39 mN/m and 11.83 mN/m, respectively. With the temperature increasing, the surface tension rises, because higher temperature decreases the solubility of n-hexane in heavy oil, and thus lower the capability of surface tension reduction. The surface tensions of flue gas, n-hexane, and mixture of flue gas and n-hexane with heavy oil were tested at 140 °C, as shown in Fig. 12. The results illustrate that the surface tensions all decrease with different extents as pressure rising under the same temperature. Surface tension reduction of flue gas is limited, however, when 50 mol% n-hexane was added into the flue gas, the surface tension can be reduced significantly. Under the conditions of 140 °C and 0.3 MPa, the surface tension of flue gas with heavy oil is 26.11 mN/m, and it reduces to 17.22 mN/m when 50 mol% of n-hexane was added. The value is similar to that of pure nhexane with heavy oil, which is 16.55 mN/m.
3.2.2. Surface tensions of n-hexane and flue gas with heavy oil A large number of studies have shown that n-hexane can effectively improve the exploitation effect of heavy oil [31–35]. The surface tensions of n-hexane with heavy oil were tested at 140 °C, and compared with CO2, N2 and flue gas, which is presented in Fig. 10. In order to keep the gas state of n-hexane in the experiments, the pressure range is only from 0.2 MPa to 0.39 MPa under 140 °C. The results illustrate that the surface tensions of n-hexane with heavy oil are much lower than that of CO2, N2 and flue gas. When pressure is close to the saturated pressure of n-hexane, the surface tension is only half of that with flue gas. The reason is that the dissolution of n-hexane in heavy oil and extraction effect with light components are much greater compared with flue gas, which is significant to reduce the surface tension. The effects of the temperature and pressure on the surface tension of n-hexane with heavy oil were studied as shown in Fig. 11. Under the same temperature, the surface tension drops quickly and
3.3. Sandpack flooding Flue gas and n-hexane can reduce viscosity and surface tension of the heavy oil as the previous experiments revealed, which can assist steam flooding to improve the oil recovery efficiency. Four series of sandpack displacement experiments were performed. Steam flooding experiment was compared with steam flooding
34
24 22
Surface tension (mN/m)
Surface tension (mN/m)
32 30 28
CO2
26
N2 Flue Gas
24 22
20 18 16 14 12 10
0
1
2
3
4
5
6
7
Pressure (MPa) Fig. 9. Surface tensions for different gases and heavy oil at 140 °C.
8 0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
Pressure (MPa) Fig. 11. Surface tensions for n-hexane and heavy oil under different temperatures.
89
S. Li et al. / Fuel 187 (2017) 84–93
36
90
Surface tension (mN/m)
32
Oil recovery efficiency (%)
Flue Gas n-C6 H14 50 mol% n-C6 H14+50 mol % Flue Gas
28 24 20 16 12 0.0
75 60 45
Steam Flue gas + steam n-C6 H14 + steam Flue gas + n-C6 H14 + steam
30 15 0 0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.5
0.7
Pressure (MPa)
1.0
1.5
2.0
2.5
3.0
3.5
Injected volume (PV) Fig. 14. Oil recovery efficiency of different displacement patterns.
Fig. 12. Surface tensions with pressure for different gases at 140 °C.
assisted by flue gas, steam flooding assisted by n-hexane, and steam flooding assisted by both flue gas and n-hexane. Displacement pressure difference, oil recovery efficiency, oil production rate and oil properties were evaluated, revealing the effects of flue gas and n-hexane on steam flooding. 3.3.1. Pressure difference for flooding Pressure differences of the sandpack flooding with the injected fluid volume were tested and recorded by differential pressure transducers, which are presented in Fig. 13. The results display that the pressure differences all first increased rapidly, then fell down quickly, and leveled off finally. At the initial stages of displacement, there is only oil phase in the sandpack, and the displacement of oil by steam or/and gas needs a great pressure difference because of the relative permeability curve [36–39]. The pressure difference reached the maximum value at about 0.15 porous volume (PV), and with the further injection it decreased until 0.5 PV. After that the water cut of produced fluid reached 80%, and the pressure difference kept almost stable. The maximum and stable pressure differences for steam flooding are 2.13 MPa and 0.30 MPa respectively. Coinjection of steam with flue gas or n-hexane, pressure differences can be reduced. The reason is that the viscosity reduction effect of flue gas or n-hexane can improve the flow capability of heavy oil in porous media. The coinjection of flue gas and n-hexane has synergistic effect on heavy oil recovery, which can decrease the maximum pressure difference to 1.69 MPa, and decrease the stable pressure difference to 0.14 MPa.
3.3.2. Oil recovery efficiency for flooding The oil recovery efficiencies for the four series of sandpack displacements are shown in Fig. 14. The final oil recovery efficiencies for steam flooding, steam flooding assisted by flue gas, steam flooding assisted by n-hexane, and steam flooding assisted by both flue gas and n-hexane are 47.94%, 58.05%, 68.47% and 80.01% respectively. The oil recovery efficiency of steam flooding assisted by both flue gas and n-hexane is 1.7 times of that of steam flooding solely. The results are related to the viscosity and surface tension reduction effects as the previous experiments revealed. The oil production rates with injected fluid volume are shown in Fig. 15. The results display that the oil production rates for steam flooding, steam flooding assisted by flue gas, and steam flooding assisted by n-hexane can be divided into two periods, which are high and low production stages. The oil production rate for steam flooding assisted by flue gas and n-hexane can be divided into three periods, which are high, medium and low production stages. Flue gas and n-hexane together can prolong production time and improve the oil displacement efficiency of the heavy oil. 3.3.3. Component analysis for produced oil In order to study the effect of flue gas or/and n-hexane on the crude oil properties in the process of steam flooding, the samples of produced oil were analyzed. According to the flooding conditions, ten samples of the produced oil were collected from the four groups of flooding experiment, and the contents of saturate, aromatic, resin and asphaltene for each sample were measured. The parameters were tested for three times, the average values are presented in Table 3.
3.5
Steam Flue gas + steam n-C6 H14 + steam Flue gas + n-C6 H14 + steam
2.0
1.5
Oil production rate (mL/min)
Pressure difference (MPa)
2.5
1.0
0.5
3.0
Steam Flue gas + steam n-C6 H14 + steam Flue gas + n-C6 H14 + steam
2.5 2.0 1.5 1.0 0.5 0.0
0.0
0.0
0.5
1.0
1.5
2.0
2.5
Injected volume (PV) Fig. 13. Pressure differences of different displacement patterns.
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
Injected volume (PV) Fig. 15. Oil production rates of different displacement patterns.
90
S. Li et al. / Fuel 187 (2017) 84–93
Table 3 Properties of produced oil for the floodings. Test No.
Flooding pattern
Collection time
Saturate (wt%)
Aromatic (wt%)
Resin (wt%)
Asphaltene (wt%)
Molecular Weight of Asphaltene⁄ (g/mol)
Viscosity at 20 °C (105 mPa s)
1#
Steam flooding
Before water breakthrough After water breakthrough
40.12
23.68
30.12
6.08
2189
7.45
40.21
23.52
30.01
6.26
2228
7.67
2#
Steam flooding assisted by flue gas
Before gas breakthrough After gas and before water breakthrough After water breakthrough
40.15 40.83
23.51 24.01
30.16 30.09
6.18 5.07
2209 2104
7.57 6.21
41.04
24.47
30.32
4.17
1934
5.11
23.58
30.07
6.26
2199
7.67
3#
Steam flooding assisted by n-hexane
Before water breakthrough After water breakthrough
40.09 42.51
25.25
29.19
3.05
1897
3.94
4#
Steam flooding assisted by flue gas and n-hexane
Before gas breakthrough After gas and before water breakthrough After water breakthrough
40.21 42.32
23.36 24.68
30.23 29.97
6.20 3.03
2191 1891
7.60 4.11
43.04
25.18
29.44
2.34
1650
3.17
⁄
2600 2400
before gas breakthrough before water breakthrough after water breakthrough
2200 2000 1800 1600 1400 1200 1000
1#
2#
3#
4#
Displacement pattern Fig. 16. Molecular weights of asphaltene for produced oil.
are related the heavy composition contents. The higher the heavy composition contents are, the greater the viscosity is.
3.3.4. Component analysis for residual oil After the flooding experiment, the sand with residual oil was removed from the sandpacks as presented in Fig. 18. The sand color darkens gradually from inlet to outlet. Heavy oil in sandpacks flowed from the inlet to outlet because thermal effect of steam and
10
Oil viscosity (10 5 mPa.s)
It can be seen from Table 3 that the compositions of the produced heavy oil collected from different periods of the flooding experiments are different compared to that of the original heavy oil. For steam flooding, two oil samples were collected before and after water breakthrough. The results show that the compositions of the produced oils are almost the same to that of the original oil, because steam can only decrease the oil viscosity by increasing the temperature, and cannot extract light components from the heavy oil. For steam flooding assisted by flue gas, the mobility of flue gas was greater than that of water and heavy oil in the sandpack. There was a pure oil production period firstly with no gas and water production, then flue gas broke through, and at last water broke through. Three oil samples were collected before gas breakthrough, before water breakthrough and after water breakthrough. The compositions of the produced oil before gas breakthrough are almost the same to that of the original oil. The asphaltene content decreased after gas breakthrough, because flue gas has some effect of extract light components from the heavy oil. After water breakthrough, asphaltene content decreased further, and saturate and aromatic contents increase to a certain extent. For steam flooding assisted by n-hexane, the n-hexane was produced as liquid state with oil and water under backpressure. Two oil samples were collected before and after water breakthrough. The compositions of the produced oil before water breakthrough are almost the same to that of the original oil. The asphaltene content decreased obviously after water breakthrough, which is only 3.05%. The reason is that n-hexane has high solubility in heavy oil and greatly enhances the extraction of extract light components from the heavy oil. More light components of the heavy oil were produced. For steam flooding assisted by flue gas and n-hexane, three oil samples were collected before gas breakthrough, before water breakthrough and after water breakthrough. The compositions of the produced oil before gas breakthrough are almost the same to that of the original oil. The asphaltene content decreased after gas breakthrough, and after water breakthrough asphaltene content decreased further, which is the lowest value. The molecular weights of asphaltene content for each oil sample were measured as shown in Table 3 and Fig. 16. The results illustrate that co-injection of flue gas and n-hexane has the greatest effect for molecular weight reduction related to light component extraction. The molecular weight can be reduced to 1650 g/mol from the original value of 2217 g/mol. The viscosities of the produced oils were also tested as show in Fig. 17. The results
Molecular weight of asphaltene (g/mol)
The asphaltene molecular weight was measured by the vapor pressure osmometry (VPO) based on Raoul’s law. Toluene was used as a solvent in the testing pool, and the experimental temperature was 45 °C.
8
before gas breakthrough before water breakthrough after water breakthrough
6
4
2
0
1#
2#
3#
Displacement pattern Fig. 17. Oil viscosities for produced oil.
4#
91
S. Li et al. / Fuel 187 (2017) 84–93
60
Oil saturation (%)
50
inlet outlet
40 30 20 10 0
1#
2#
3#
4#
Displacement pattern Fig. 19. Oil saturations of different displacement patterns.
viscosity reduction due to flue gas and n-hexane dissolution. At the same position of the sandpack, the color of sand flooded by steam assisted by flue gas and n-hexane is the lightest, and that by steam solely is the darkest. The results show that the displacement efficiency of flue gas and n-hexane is the best, which is consistent with the oil recovery curves in Fig. 14. In order to analyze the effect of flue gas and n-hexane on heavy oil recovery, the sands at inlet and outlet of the sandpacks were collected, and oil saturation, oil component, and molecular weight of asphaltene were tested. The parameters were tested three times, the average values are shown in Table 4. The results display that the light component contents of saturate and aromatic are less at inlet of the sandpack, however, the heavy component contents of resin and asphaltene are greater. During the process of displacement, light components in crude oil are easy to flow from inlet to outlet of the sandpack, and the flow capability of heavy components are weak. More heavy components gathered in the inlet. The oil saturations at inlet and outlet of the sandpacks are shown in Fig. 19. The results display that the oil saturations at outlets are always greater than that of inlets for different flooding patterns. The reason is that in the process of displacement, the continuous injected fluid from the inlet carried oil to the outlet of the sandpack. At the end of the steam flooding, oil saturations at inlet and outlet are 40.80% and 51.07% respectively. At the end of the steam flooding assisted by flue gas, oil saturations are 31.24% and 38.25% respectively. Compared with steam flooding, the oil saturations decreased to some extent. For steam flooding assisted by n-hexane, the oil saturations decreased further, which
Molecular weight of asphaltene (g/mol)
Fig. 18. Sand samples removed from sandpacks after flooding. (a), (b), (c) and (d) are the sand samples flooded by steam, steam assisted with flue gas, steam assisted with n-hexane, and steam assisted with flue gas and n-hexane, respectively.
6000
inlet outlet
5000 4000 3000 2000 1000 0
1#
2#
3#
4#
Displacement pattern Fig. 20. Molecular weights of asphaltene for residual oil in sandpacks.
are 11.4% and 22.14%. For steam flooding assisted by flue gas and n-hexane, the oil saturations are the least, which are 7.88% and 16.34% respectively. The results reveal that flue gas and n-hexane have the best effect on improving oil recovery. The molecular weights of asphaltene at inlet and outlet of the sandpacks are shown in Fig. 20. The results display that molecular weights of inlets are greater than that of outlets, which is similar to the asphaltene contents of the residual oil in the sandpacks and opposite to that of the produced oil. The reason is that the light components with small molecular weight are easy to flow from inlet to outlet. Fig. 21 displays the asphaltene-to-resin ratio (ATR) for different heavy oil samples. The ATR ratio indicates asphaltene stability because of the presence of resins. Statistically, asphaltene is
Table 4 Properties of the residual oil in sandpacks. Test No.
Flooding pattern
Collection time
Saturate (wt%)
Aromatic (wt%)
Resin (wt%)
Asphaltene (wt%)
Molecular weight of asphaltene (g/mol)
Oil saturation (%)
1#
Steam flooding
Inlet Outlet
40.20 40.03
22.58 22.69
31.11 31.09
6.11 6.19
2167 2186
40.80 51.07
2#
Steam flooding assisted by flue gas
Inlet Outlet
36.07 37.69
21.99 21.64
33.23 33.05
8.71 7.62
3804 3193
31.24 38.25
3#
Steam flooding assisted by n-hexane
Inlet Outlet
33.14 36.70
20.33 19.02
34.26 34.06
12.27 10.22
4084 3286
11.40 22.14
4#
Steam flooding assisted by flue gas and n-hexane
Inlet Outlet
30.38 32.61
18.65 18.34
34.72 34.22
16.25 14.83
4644 3787
7.88 16.34
92
S. Li et al. / Fuel 187 (2017) 84–93
25
sity of Petroleum (East China) for their assistance with the experimental research.
ATR=0.67
Asphaltene content (wt%)
Unstable region
20
15
Transition region
Origional oil Produced oil, 1# Produced oil, 2# Produced oil, 3# Produced oil, 4# Residual oil, 1# Residual oil, 2# Residual oil, 3# Residual oil, 4#
10
5
References
ATR=0.4
Stable region
0 20
25
30
35
40
45
Resin content (wt%) Fig. 21. ATRs for the produced and residual oil samples.
expected to be unstable when the ATR ratio is >0.67, stable when the ATR ratio is <0.4, and in the transition region for 0.4 < ATR ratio <0.67 [40]. The results in Fig. 21 illustrate that all produced oils from the floodings are less than 0.4 and in the stable region. The reason is that the asphaltenes precipitation in the sandpack led to a relatively lower asphaltenes content in the produced oils. However, flue gas and n-hexane induced light component extraction and resulted in an increase in asphaltenes content in the residual oil. The ATRs of the residual oil 4# are greater than 0.4, locating in the transition region. This means that the asphaltenes component in the residual oils is not as stable as that in the produced oils, which may cause deposition of asphaltenes in the sandpack. 4. Conclusions (1) The flue gas dissolved in heavy oil can effectively reduce oil viscosity, increase the flow capability, and make the volume swell. Higher pressure reduces surface tension of heavy oil and gas, and higher temperature increases surface tension. Compared with flue gas, n-hexane can reduce heavy oil viscosity and surface tension more obviously, and adding small amount of n-hexane into flue gas can achieve good effect. (2) The flue gas and n-hexane can effectively improve the development effect of the steam flooding. The pressure difference of steam flooding assisted by flue gas and n-hexane is the lowest, the oil production rate is highest, and the oil recovery efficiency can reach 80%. (3) Flue gas and n-hexane can effectively change crude oil properties. The heavy component of heavy oil, molecular weight of asphaltene and oil viscosity for the produced oil all reduced. The heavy component and molecular weight of asphaltene for the residual oil in sandpacks all increased. The effect of flue gas and n-hexane together on heavy oil properties is the greatest. The asphaltenes component in the residual oil is not as stable as that in produced oil.
Acknowledgements Financial support is received by the National Natural Science Foundation of China (Nos. 51274228 and 51304229), the National Key Scientific and Technological Project for the Oil & Gas Field and Coalbed Methane (No. 2016ZX05031002-004-002) and the Fundamental Research Funds for the Central Universities (14CX02185A). We are grateful to the Foam Research Center at the China Univer-
[1] Wilson M, Monea M. IEA GHG Weyburn CO2 monitoring and storage project summary report 2000–2004. The 7th international conference on greenhouse gas control technologies, 5–9 September, 2004. [2] Kay D, André F, Wim T. Pathways towards large-scale implementation of CO2 capture and storage: a case study for the Netherlands. Int J Greenhouse Gas Control 2009;3:217–36. [3] Liu HW, Berenice GT, Tarek A, Murad B. The role of CO2 capture and storage in Saudi Arabia’s energy future. Int J Greenhouse Gas Control 2012;11:163–71. [4] Sander VE, Marko PH. Argument map for carbon capture and storage. Int J Greenhouse Gas Control 2012;11:S148–59. [5] Paul Z, Mike H. Permitting issues for CO2 capture, transport and geological storage: a review of Europe, USA, Canada and Australia. Int J Greenhouse Gas Control 2007;1:94–100. [6] Karaoguz OK, Topguder NNS, Lane RH, Kalfa U, Celebioglu D. Improved sweep in Bati Raman heavy-oil CO2 flood: bullhead flowing gel treatments plug natural fractures. SPE Reserv Eval Eng 2007;10:1–12. [7] Secaeddin S, Ulker K, Demet C. Bati Raman filed immiscible CO2 applicationatatus quo and future plans. In: Latin American & Caribbean petroleum engineering conference, 15–18 April, 2008, 2008, SPE 106575. [8] Kleinsteiber SW. The wertz tensleep CO2 flood: design and initial performance. J Petrol Technol 1988;42:630–6. [9] Agustssen H, Grinestafr GH. A study of IOR by CO2 injection in the Gullfaks field. In: SPE/DOE symposium on improved oil recovery, 17–21 April, 2004 Tulsa, Oklahoma, 2004, SPE 89338. [10] Siregar S, Mardisewojo P, Kristanto D, Tjahyadi R. Dynamic interaction between CO2 gas and crude oil in porous medium. In: SPE Asia Pacific improved oil recovery conference, 25–26 October, 1999, Kuala Lumpur, Malaysia, 1999, SPE 57300. [11] Zhang C, Li ZM, Wang HY, Wang SH, Yi HF, Xue XC, Yao YP. Performance of flue gas and foam assisted steam huff and puff with horizontal well in enhanced recovery of Fengcheng Oil field. In: SPE heavy oil conference-Canada, 10–12 June, 2014, Calgary, Alberta, Canada, 2014, SPE 170105. [12] Miller KA, Moore RG, Ursenbach MG, Laureshen CJ, Mehta SA. Proposed air injection recovery of cold-produced heavy oil reservoirs. J Canad Petrol Technol 2002;41:40–9. [13] Das SK, Butler RM. Mechanism of the vapor extraction process for heavy oil and bitumen. J Petrol Sci Eng 1998;21:43–59. [14] Frauenfeld T, Lillico D, Jossy G, Vilcsak G, Rabeeh S, Singh S. Evaluation of partially miscible processes for Alberta heavy oil reservoirs. J Canad Petrol Technol 1998;37:17–25. [15] Metwally M. Enriched gas pressure cycling process for depleted heavy oil reservoirs. J Canad Petrol Technol 1998;37:56–60. [16] Yang CD, Gu YA. A new method for measuring solvent diffusivity in heavy oil by dynamic pendant drop shape analysis (DPDSA). SPE J 2006;11:48–57. [17] Fairfield WH, White PD. Lloydminster fireflood performance, modifications promise good recoveries. Oil Gas J 1982;80:101–2. [18] Dyer SB, Huang SS, Farouq Ali SM, Jha KN. Phase behaviour and scaled model studies of Prototype Saskatchewan heavy oils with carbon dioxide. J Canad Petrol Technol 1994;33:42–8. [19] Dong MZ, Huang S, Hutchence K. Methane pressure-cycling process with horizontal wells for thin heavy-oil reservoirs. SPE Reserv Eval Eng 2006;9:154–64. [20] Luo P, Er V, Freitag N, Huang S. Recharacterizing evolving fluid and PVT properties of Weyburn oil-CO2 system. Int J Greenhouse Gas Control 2013;16: S226–35. [21] Cao M, Gu Y. Physicochemical characterization of produced oils and gases in immiscible and miscible CO2 flooding processes. Energy Fuel 2013;27:440–53. [22] Wang SH, Chen SN, Li ZM. Characterization of produced and residual oils in the CO2 flooding process. Energy Fuel 2016;30:54–62. [23] Sun Q, Li Z, Wang J, Li S, Li B, Jiang L, Wang H, Lü Q, Zhang C, Liu W. Aqueous foam stabilized by partially hydrophobic nanoparticles in the presence of surfactant. Colloids Surf A 2015;471:54–64. [24] Sun Q, Li Z, Wang J, Li S, Jiang L, Wang J, Wang P. Utilization of surfactantstabilized foam for enhanced oil recovery by adding nanoparticles. Energy Fuel 2014;28:2384–94. [25] Ravera F, Santini E, Loglio G, Ferrari M, Liggieri L. Effect of nanoparticles on the interfacial properties of liquid/liquid and liquid/air surface layers. J Phys Chem B 2006;110:19543–51. [26] Li HZ, Yang DY, Tontiwachwuthiku P. Experimental and theoretical determination of equilibrium interfacial tension for the solvent(s)-CO2-heavy oil systems. Energy Fuel 2012;26:1776–86. [27] Yang DY, Gu YA. Visualization of interfacial interactions of crude oil-CO2 systems under reservoir. In: SPE/DOE symposium on improved oil recovery, 17–21 April, 2004, Tulsa, Oklahoma, 2004, SPE 89366. [28] Yang DY, Tontiwachwuthikul P, Gu YA. Interfacial tensions of the crude oil + reservoir brine + CO2 systems at pressures up to 31 MPa and temperatures of 27 °C and 58 °C. J Chem Eng Data 2005;50:1242–9. [29] Zolghadr A, Escrochi M, Ayatollahi S. Temperature and composition effect on CO2 miscibility by interfacial tension measurement. J Chem Eng Data 2013;58:1168–75.
S. Li et al. / Fuel 187 (2017) 84–93 [30] Li HZ, Yang DY. Phase behavior of C3H8-n-C4H10-heavy oil systems at high pressures and elevated temperatures. In: SPE heavy oil conference Canada, 12– 14 June, 2012, Calgary, Alberta, Canada, 2012, SPE 157744. [31] Ayodele OR, Nasr TN, Ivory JJ, Beaulieu G, Heck G. Testing and history matching of ES-SAGD (using hexane). In: SPE western regional meeting, 27–29 May, 2010, Anaheim, California, USA, 2010, SPE 134002. [32] McCormack ME. Design of steam-hexane injection wells for gravity drainage systems. J Canad Petrol Technol 2009;48:22–8. [33] Hascakir B. Effective extraction of high viscosity and low API gravity hydrocarbon resources with solvent-steam processes. In: SPE western regional meeting, 23–26 May, 2016, Anchorage, Alaska, USA, 2016, SPE 180424. [34] Ardali M, Barrufet M, Mamora DD. Laboratory testing of addition of solvents to steam to improve SAGD process. In: SPE heavy oil conference Canada, 12–14 June, 2012, Calgary, Alberta, Canada, 2012, SPE 146993. [35] Ardali M, Mamora D, Barrufet MA. Experimental study of co-injection of potential solvents with steam to enhance SAGD process. In: SPE Western
[36]
[37] [38] [39] [40]
93
North American region meeting, 7–11 May, 2011, Anchorage, Alaska, USA, 2011, SPE 144598. Sigmund PM, McCaffery FG. An improved unsteady-state procedure for determining the relative-permeability characteristics of heterogeneous porous media. SPE J 1979;19:15–28. Tao TM, Watson AT. Accuracy of JBN estimates of relative permeability: part 1 – error analysis. SPE J 1984;24:209–14. Tao TM, Watson AT. Accuracy of JBN estimates of relative permeability: part 2 – algorithms. SPE J 1984;24:215–23. Li SY, Li ZM. Effect of temperature on the gas/oil relative permeability of Orinoco Belt foamy oil. SPE J 2016;21:170–9. Gonzalez RDL. Modeling of asphaltene precipitation and deposition tendency using the PC-SAFT equation of state. PhD dissertation, Rice University, Houston, TX; 2008.
Contents lists available at ScienceDirect
Fuel journal homepage: www.elsevier.com/locate/fuel
Full Length Article
Effect of flue gas and n-hexane on heavy oil properties in steam flooding process Songyan Li ⇑, Zhaomin Li ⇑, Xiaona Sun College of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
a r t i c l e
i n f o
Article history: Received 7 July 2016 Received in revised form 13 September 2016 Accepted 14 September 2016 Available online 20 September 2016 Keywords: Flue gas n-Hexane Steam flooding Oil properties Production mechanism
a b s t r a c t Heavy-oil reservoirs with thin-pay and bottomwater can be exploited effectively by thermal recovery process assisted by flue gas and n-hexane. The interface properties between flue gas/n-hexane and heavy oil and viscosity reduction of the heavy oil were investigated by laboratory experiments. Steam flooding, flue gas assisted steam flooding, n-hexane assisted flooding and flue gas and n-hexane assisted steam flooding were conducted to research the displacement pressure difference, oil displacement efficiency and component variation of produced and residual oils. The results show that the flue gas dissolving in heavy oil can effectively reduce oil viscosity, increase the flow capability, and make the heavy oil swell. Higher pressure reduces surface tension of heavy oil and gas, and higher temperature increases surface tension. Compared with flue gas, n-hexane can reduce heavy oil viscosity and surface tension more obviously. The flue gas and n-hexane can effectively improve the development effect of the steam flooding. The pressure difference of steam flooding assisted by flue gas and n-hexane is the lowest, the oil production rate is greatest, and the oil recovery efficiency can reach 80%. Flue gas and n-hexane can effectively change crude oil properties. The heavy components, molecular weight of asphaltene and oil viscosity for the produced oil all reduced. The heavy components and molecular weight of asphaltene for the residual oil in sandpacks all increased. The effect of flue gas and n-hexane together on heavy oil is the greatest. The asphaltenes component in the residual oil is not as stable as that in produced oil. The experimental results not only show that flue gas and n-hexane can successfully improve the performance of steam flooding process, but also provide a deep understanding of properties changes of produced and residual oils for the flooding. Ó 2016 Elsevier Ltd. All rights reserved.
1. Introduction 1.1. Collection and utilization of flue gas for heavy oil production Global warming caused by the excessive emission of greenhouse gases has become one of the most significant environmental problems currently faced by society. According to the Kyoto Protocol and the Copenhagen International Conference on environmental requirements, each country has an obligation to reduce CO2 emissions. For the next 50 years, fossil fuels will remain as the main energy source for the world, and CO2 from fossil fuel combustion will account for approximately 80% of the total emissions. Flue gas from fossil fuel power plants is the greatest long-term emission source of CO2 [1–5]. Carbon capture and storage (CCS) has been widely regarded as an effective solution to reduce CO2 in the atmosphere to mitigate ⇑ Corresponding authors. E-mail addresses: [email protected] (S. Li), [email protected] (Z. Li). http://dx.doi.org/10.1016/j.fuel.2016.09.050 0016-2361/Ó 2016 Elsevier Ltd. All rights reserved.
global warming. However, the profit from CCS cannot compensate for its high cost. CO2-enhanced oil recovery, which has been widely used in oil field development, can reduce CO2 emissions and improve crude oil recovery efficiency. CO2-enhanced oil recovery is the option with the most potential for carbon capture, utilization and storage (CCUS) [6–10]. Crude oil production in the oilfield has provided abundant fossil fuel to the world, but it also consumes a large amount of energy. In the process of heavy oil production, a large proportion of heavy oil that is produced is used as fuel in the boiler for heating steam, which is then injected into a reservoir for thermal recovery. Flue gas from the boiler is a stable long-term CO2 emission source in the oilfield. Related research and field applications prove that flue gas injected into the reservoir with steam can greatly improve heavy oil development [11]. Flue gas collection also avoids the complex process of CO2 separation in CCS, which is suitable for a small-scale steam injection boiler. The collection and utilization of flue gas in a steam injection boiler will become an important method for reducing greenhouse gas emissions in oilfields.
85
S. Li et al. / Fuel 187 (2017) 84–93
1.2. Solvent and flue gas assisted steam flooding Heavy oil from thick-pay reservoirs is usually exploited with thermal recovery method. These methods related to steam injection are generally not suitable for thin reservoirs because of the heat loss to overburden and underburden or bottomwater zones [12–14]. China has tremendous heavy oil in Xinjiang, Liaohe and Shengli Oilfield, however, most Chinese heavy-oil reservoirs cannot be exploited economically by thermal recovery process because the reservoir formations are thin and there is usually active bottomwater or edgewater. In the literatures, some researches have been conducted to evaluate the recovery methods for these special reservoirs. Among the methods solvent-based processes are probably the most promising EOR techniques. In practice, the solvent can be CO2, flue gas, methane, ethane, propane, and butane. In a typical solvent-based process, the wellaccepted EOR mechanisms are oil viscosity reduction, oil swelling and interfacial tension reduction when a solvent dissolves into heavy oil [15–19].
PVT cell P
P
Falling-ball viscometer Flue gas and oil Flue gas
Controller Controller
p Pump
BPR
Fig. 1. Schematic diagram of the flue gas dissolving property apparatus.
1.3. Purpose of this paper Table 1 Properties of the heavy oil used in the experiments. Property
Unit
Value
Density at 20 °C Viscosity at 20 °C Saturate content Aromatic content Resin content Asphaltene content
kg/m3 mPa s wt% wt% wt% wt%
968.5 7.61 105 40.18 23.52 30.09 6.21
1000000
Viscosity (mPa·s)
Although many laboratory experiments have been conducted to evaluate the effect of CO2 on crude oil in a PVT cell and study EOR performance of the CO2 flooding, few attempts have been made to investigate effect of flue gas and n-hexane on the properties of the produced and residual oil during steam flooding process. It is wellaccepted that, in a CO2 flooding process, the injected CO2 is capable of extracting light and intermediate hydrocarbons from the reservoir oil [20–22]. The oil components alteration during solvent assisted steam flooding may cause the asphaltene precipitation and deposition in the reservoir. Therefore, it is important to evaluate the oil properties during the solvent assisted steam flooding process. In this study, surface properties of heavy oil and solvent and four sandpack flooding tests were carried out under different conditions. The properties of the produced oil at different periods were characterized. Furthermore, the residual oil was extracted from the inlet and outlet of the residual oil sands in the sandpacks. The residual oil saturation was calculated and the asphaltenes content of the residual oil was measured using saturates, aromatics, resins, and asphaltenes (SARA) analysis.
100000
10000
1000
2. Experimental methods 2.1. Apparatus
100 10
20
30
40
50
60
Temperature (
70
80
90
100
)
Flue gas dissolving properties in heavy oil were tested using a PVT cell (with a pressure range of 60 MPa, temperature range of 200 °C, and temperature accuracy of ±0.1 °C) and a falling-ball viscometer (with a pressure range of 50 MPa, temperature range of 220 °C, viscosity range of 100,000 mPa s, and temperature accuracy of ±0.1 °C), which are shown in Fig. 1. The surface tension of heavy oil and solvent were determined by a drop shape tensiometer (Tracker-H, Teclis, France, full scale of 20 MPa and 200 °C) [23]. The experimental apparatus for sandpack flooding has been shown in previous studies [24,25].
are 99.99 mol%. The purity of the n-C6H14 (Xilong, Inc., China) is >95%. Analytic pure CaCl2 and NaCl at concentrations of 790 mg/L and 36,000 mg/L were employed in the experiments to simulate the formation water. Distilled water served as the liquid. The density and viscosity of the brine at 20 °C are 1028 kg/m3 and 1.17 mPa s, respectively.
2.2. Materials
2.3.1. Experiment steps for dissolving properties testing
The heavy oil used in the experiments was produced from Shengli Oilfield of China. Its basic properties are shown in Table 1, and the viscosity-temperature curve is shown in Fig. 2. Flue gas was mixed with N2 and CO2 with the mole ratio of 8:2. The purity of N2 and CO2 (Tianyuan, Inc., China) used in this work
Fig. 2. Viscosity-temperature curve of the heavy oil.
2.3. Experimental procedures
(1) A certain volume of dead oil and flue gas were injected into the PVT cell according to the gas-oil ratio. (2) The pressure of the mixture of heavy oil and flue gas was firstly pumped to a high value, ensuring all of the flue gas was dissolved in the heavy oil. Then the pressure of the
86
S. Li et al. / Fuel 187 (2017) 84–93
mixture was decreased, and the pressures and volumes of the mixture were recorded and plotted in a figure. The saturation pressure could be determined by the inflection point in the pressure-volume curve. (3) Then a certain volume of live oil dissolved with flue gas was injected into the falling-ball viscometer with the backpressure greater than the saturation pressure. The viscosity of the live oil was measured for 5 times, and the averaged value was adopted.
illustrate that the saturation pressure increases with dissolved gas-oil ratio under the same temperature. When the saturation pressure increases from 0.4 MPa to 6.0 MPa at 80 °C, the dissolved gas-oil ratio increases from 5.73 sm3/m3 to 16.69 sm3/m3, however, at the same pressure range the dissolved gas-oil ratio increases from 2.82 sm3/m3 to 10.76 sm3/m3 at 200 °C. Under the same dissolved gas-oil ratio, the higher the temperature, the greater the saturation pressures is. The reason is that gas molecular motion increases under higher temperature, which inhibits flue gas dissolution in crude oil.
2.3.2. Experiment steps for surface properties testing (1) Before testing, the high temperature and high pressure vessel, syringe, needle and sample pool of the drop shape tensiometer were washed with acetone and ethanol. Then the syringe was filled with heavy oil, and placed in the vessel. (2) The vessel was flushed with flue gas for 3 times to drain the air. Then the vessel was heated to a certain temperature for 60 min. (3) An oil droplet was injected on the tip of the needle. The shape of the oil droplet was captured by a CCD camera and sent to the computer by data collection and analysis system. The surface tension of the crude oil and flue gas was calculated using Laplace equation [26–30]. The surface tension was measured for 3 times, and the averaged value was adopted. 2.3.3. Experiment steps for sandpack flooding (1) Sandpacks with permeabilities from 2069 mD to 2133 mD and porosities from 35.85% to 36.31% were prepared, as the physical properties are similar within these ranges. The length of the sandpack is 60 cm, and the diameter is 2.54 cm. The sandpack was evacuated for more than 4 h before it was saturated with brine, and the pore volumes and permeabilities were tested. The key properties of the sandpacks are listed in Table 2. (2) Then the sandpack was displaced with dead oil at a rate of 0.2 mL/min until water production ceased. The initial oil saturation and irreducible water saturation were calculated. (3) The temperatures of the sandpack and the steam were set to 90 °C and 200 °C, respectively. Steam flooding was conducted with the volume flow rate of 2 mL/min, and backpressure of 3.0 MPa. When the water cut of the produced fluid reached 98%, the flooding experiment would be sopped. The pressure difference of the sandpack, and oil production were recorded and analyzed. The parameters for steam flooding assisted by flue gas or/and n-hexane are shown in Table 2. 3. Experimental results and discussions 3.1. Viscosity reduction properties 3.1.1. Saturation pressure of flue gas The relationship of dissolved gas-oil ratio and saturation pressure under different temperatures is shown in Fig. 3. The results
3.1.2. Swelling factor for crude oil The relationship of dissolved gas-oil ratio and swelling factor for the heavy oil under different temperatures is presented in Fig. 4. The experimental results display that the volume of the heavy oil with flue gas dissolving can swell obviously. Under the same temperature, the swelling factor of the live oil increases gradually with the rising dissolved gas-oil ratio, which is approximately linear. When dissolved gas-oil ratio increases from 1 sm3/m3 to 15 sm3/m3, the swelling factor increases from 1.057 to 1.135 at 80 °C, and it increases from 1.033 to 1.108 at 200 °C. Under the condition of the same dissolved gas-oil ratio, the swelling factor decreases with the rising temperature. 3.1.3. Viscosity reduction properties using flue gas In order to analyze the effect of viscosity reduction of flue gas or n-hexane on heavy oil, viscosity reduction rate is defined by Eq. (1).
Y¼
X1 X2 100% X1
ð1Þ
where Y is viscosity reduction rate, %; X1 is the original viscosity of the heavy oil, mPa s; X2 is the viscosity of the live oil dissolved with flue gas or n-hexane, mPa s. The relationship of dissolved gas-oil ratio and viscosity reduction rate under different temperatures is shown in Fig. 5. The results demonstrate that under the same temperature, the viscosity reduction rate increases with the rising dissolved gas-oil ratio. When dissolved gas-oil ratio increases from 1 sm3/m3 to 15 sm3/ m3 at 80 °C, the viscosity reduction rate increases from 12.9% to 60.0%; however, the viscosity reduction rate increases only from 3.5% to 36.4% at 200 °C. Under the same dissolved gas-oil ratio, the rising temperature can decrease viscosity reduction rate, and viscosity reduction effect of flue gas on heavy oil is lowered. 3.1.4. Viscosity reduction properties using solvent Viscosity reduction effects of n-pentane, n-hexane and nheptane were evaluated under 50 °C, and the results are shown in Fig. 6. It can be seen that under the same experimental temperature, higher solvent concentration is better for viscosity reduction of heavy oil. The reason is that the contents of resin and asphaltene are high in the heavy oil, and adding solvent into heavy oil can increase the content of light components and decrease the viscosity of the heavy oil. When the concentration of solvent increases from 5 wt% to 10 wt%, viscosity decreases rapidly, and when the concentration increases further, the viscosity decreases slowly.
Table 2 Parameters of the sandpack flooding. Test No.
Flooding pattern
Permeability (mD)
Porosity (%)
Initial oil saturation (%)
Flow rate of steam (mL/min)
Flow rate of flue gas (mL/min)
Flow rate of n-hexane (mL/min)
1# 2# 3#
Steam flooding Steam flooding assisted by flue gas Steam flooding assisted by n-hexane Steam flooding assisted by flue gas and n-hexane
2133 2076 2069
36.31 36.18 36.02
87.86 88.64 89.50
2.0 1.4 1.8
0 0.6 0
0 0 0.2
2089
35.85
88.07
1.2
0.6
0.2
4#
87
S. Li et al. / Fuel 187 (2017) 84–93
100
200 140 80
16
Viscosity reduction rate (%)
Dissolved gas-oil ratio sm3/m3
20
12
8
4
0
90
80
70
60
50 0
1
2
3
4
5
6
n-C 5 H12 n-C 6 H14 n-C 7 H16
7
0
5
Fig. 3. Relationship of dissolved gas-oil ratio and saturation pressure under different temperatures.
1.16
200 140 80
1.14
Swelling factor
1.12 1.10 1.08 1.06 1.04 1.02 1.00
0
2
4
6
8
10
12
14
16
Dissolved gas-oil ratio (sm3/m3) Fig. 4. Relationship of dissolved gas-oil ratio and swelling factor under different temperatures.
Viscosity reduction rate (%)
80
80 140 200
60
10
15
20
25
Solvent concentration (wt%)
Saturation pressure (MPa)
40
Fig. 6. Relationship of solvent concentration and viscosity reduction rate.
after the formation of the oil droplet. In order to test the effect of gas dissolution on the surface properties the dynamic surface tensions were measured at 140 °C and 5 MPa, which is shown in Fig. 7. The composition of the flue gas is 80 mol% of N2 with 20 mol% CO2. The dynamic surface tensions can be divided into two stages. The first stage is the diffusion process of gas in heavy oil as a wave period. The dynamic surface tensions decrease gradually, which is about 100 s. The second stage is balanced period, and the surface tensions are almost constants. Under the same temperature and pressure, the surface tension of N2 and heavy oil is the maximum, and that of CO2 is the minimum. The surface tension of the flue gas and heavy oil is between the two. The balanced surface tensions of flue gas and heavy oil at 80 °C, 140 °C and 200 °C were tested respectively, which are shown in Fig. 8. When the pressure increases from 0.2 MPa to 6.0 MPa, the surface tension reduces from 23.25 mN/m to 20.25 mN/m at 80 °C, however, it decreases from 28.81 mN/m to 25.03 mN/m at 200 °C. The surface tension decreases with the rising pressure under the same temperature, which is a linear relationship. This is because higher pressure makes more flue gas dissolve in the heavy oil, and the property difference of heavy oil and flue gas decreases. The surface tension increases with the rising temperature, because higher temperature makes less flue gas dissolve in the heavy oil, and the property difference of heavy oil and flue gas increases. The surface tensions of heavy oil with CO2, N2 and flue gas were tested at 140 °C, which is presented in Fig. 9. The results show that the surface tensions all decreases with the rising pressure, which is
20
30
0
2
4
6
8
10
12
14
16
Dissolved gas-oil ratio (sm3/m3) Fig. 5. Relationship of dissolved gas-oil ratio and viscosity reduction rate under different temperatures.
Compared the effects of the three solvents at the same concentration, the effect of pentane is poorer, and that of n-hexane and n-heptane are almost the same.
Surface tension (mN/m)
28
0
26 24 22
Flue Gas CO2 N2
20 18
3.2. Surface properties 3.2.1. Surface tension of heavy oil and flue gas Dynamic surface tensions of heavy oil and gases were tested by the drop shape tensiometer. The flue gas can dissolve in heavy oil
16
0
500
1000
1500
2000
Time (s) Fig. 7. Dynamic surface tension at 140 °C and 5 MPa.
2500
88
S. Li et al. / Fuel 187 (2017) 84–93
28
30 200 140 80
26
Surface tension (mN/m)
Surface tension (mN/m)
28 26 24 22 20 18
24
CO2
22
N2
20
Flue Gas n-C6 H14
18 16
0
1
2
3
4
5
6
14 0.15
7
0.20
Pressure (MPa)
0.25
0.30
0.35
0.40
0.45
Pressure (MPa)
Fig. 8. Equilibrium surface tension for flue gas and heavy oil under different temperatures.
Fig. 10. Surface tension for n-hexane and heavy oil at 140 °C.
a linear relationship. The surface tensions are close to each other under low pressure, however, the difference becomes greater and greater with the rising pressure. When pressure increases from 0.2 MPa to 6.0 MPa, the reduction of surface tension for CO2 and heavy oil from 31.65 mN/m to 23.07 mN/m is the greatest, and that for N2 and heavy oil from 31.78 mN/m to 29.11 mN/m is the least. The surface tension of flue gas and heavy oil is between the two, which is related to the property of the flue gas.
linearly with the rising pressure, because of the greater dissolution of the n-hexane into heavy oil. At the highest pressures of 100 °C, 140 °C and 200 °C in the experiments, the surface tensions are 14.57 mN/m, 13.39 mN/m and 11.83 mN/m, respectively. With the temperature increasing, the surface tension rises, because higher temperature decreases the solubility of n-hexane in heavy oil, and thus lower the capability of surface tension reduction. The surface tensions of flue gas, n-hexane, and mixture of flue gas and n-hexane with heavy oil were tested at 140 °C, as shown in Fig. 12. The results illustrate that the surface tensions all decrease with different extents as pressure rising under the same temperature. Surface tension reduction of flue gas is limited, however, when 50 mol% n-hexane was added into the flue gas, the surface tension can be reduced significantly. Under the conditions of 140 °C and 0.3 MPa, the surface tension of flue gas with heavy oil is 26.11 mN/m, and it reduces to 17.22 mN/m when 50 mol% of n-hexane was added. The value is similar to that of pure nhexane with heavy oil, which is 16.55 mN/m.
3.2.2. Surface tensions of n-hexane and flue gas with heavy oil A large number of studies have shown that n-hexane can effectively improve the exploitation effect of heavy oil [31–35]. The surface tensions of n-hexane with heavy oil were tested at 140 °C, and compared with CO2, N2 and flue gas, which is presented in Fig. 10. In order to keep the gas state of n-hexane in the experiments, the pressure range is only from 0.2 MPa to 0.39 MPa under 140 °C. The results illustrate that the surface tensions of n-hexane with heavy oil are much lower than that of CO2, N2 and flue gas. When pressure is close to the saturated pressure of n-hexane, the surface tension is only half of that with flue gas. The reason is that the dissolution of n-hexane in heavy oil and extraction effect with light components are much greater compared with flue gas, which is significant to reduce the surface tension. The effects of the temperature and pressure on the surface tension of n-hexane with heavy oil were studied as shown in Fig. 11. Under the same temperature, the surface tension drops quickly and
3.3. Sandpack flooding Flue gas and n-hexane can reduce viscosity and surface tension of the heavy oil as the previous experiments revealed, which can assist steam flooding to improve the oil recovery efficiency. Four series of sandpack displacement experiments were performed. Steam flooding experiment was compared with steam flooding
34
24 22
Surface tension (mN/m)
Surface tension (mN/m)
32 30 28
CO2
26
N2 Flue Gas
24 22
20 18 16 14 12 10
0
1
2
3
4
5
6
7
Pressure (MPa) Fig. 9. Surface tensions for different gases and heavy oil at 140 °C.
8 0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
Pressure (MPa) Fig. 11. Surface tensions for n-hexane and heavy oil under different temperatures.
89
S. Li et al. / Fuel 187 (2017) 84–93
36
90
Surface tension (mN/m)
32
Oil recovery efficiency (%)
Flue Gas n-C6 H14 50 mol% n-C6 H14+50 mol % Flue Gas
28 24 20 16 12 0.0
75 60 45
Steam Flue gas + steam n-C6 H14 + steam Flue gas + n-C6 H14 + steam
30 15 0 0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.5
0.7
Pressure (MPa)
1.0
1.5
2.0
2.5
3.0
3.5
Injected volume (PV) Fig. 14. Oil recovery efficiency of different displacement patterns.
Fig. 12. Surface tensions with pressure for different gases at 140 °C.
assisted by flue gas, steam flooding assisted by n-hexane, and steam flooding assisted by both flue gas and n-hexane. Displacement pressure difference, oil recovery efficiency, oil production rate and oil properties were evaluated, revealing the effects of flue gas and n-hexane on steam flooding. 3.3.1. Pressure difference for flooding Pressure differences of the sandpack flooding with the injected fluid volume were tested and recorded by differential pressure transducers, which are presented in Fig. 13. The results display that the pressure differences all first increased rapidly, then fell down quickly, and leveled off finally. At the initial stages of displacement, there is only oil phase in the sandpack, and the displacement of oil by steam or/and gas needs a great pressure difference because of the relative permeability curve [36–39]. The pressure difference reached the maximum value at about 0.15 porous volume (PV), and with the further injection it decreased until 0.5 PV. After that the water cut of produced fluid reached 80%, and the pressure difference kept almost stable. The maximum and stable pressure differences for steam flooding are 2.13 MPa and 0.30 MPa respectively. Coinjection of steam with flue gas or n-hexane, pressure differences can be reduced. The reason is that the viscosity reduction effect of flue gas or n-hexane can improve the flow capability of heavy oil in porous media. The coinjection of flue gas and n-hexane has synergistic effect on heavy oil recovery, which can decrease the maximum pressure difference to 1.69 MPa, and decrease the stable pressure difference to 0.14 MPa.
3.3.2. Oil recovery efficiency for flooding The oil recovery efficiencies for the four series of sandpack displacements are shown in Fig. 14. The final oil recovery efficiencies for steam flooding, steam flooding assisted by flue gas, steam flooding assisted by n-hexane, and steam flooding assisted by both flue gas and n-hexane are 47.94%, 58.05%, 68.47% and 80.01% respectively. The oil recovery efficiency of steam flooding assisted by both flue gas and n-hexane is 1.7 times of that of steam flooding solely. The results are related to the viscosity and surface tension reduction effects as the previous experiments revealed. The oil production rates with injected fluid volume are shown in Fig. 15. The results display that the oil production rates for steam flooding, steam flooding assisted by flue gas, and steam flooding assisted by n-hexane can be divided into two periods, which are high and low production stages. The oil production rate for steam flooding assisted by flue gas and n-hexane can be divided into three periods, which are high, medium and low production stages. Flue gas and n-hexane together can prolong production time and improve the oil displacement efficiency of the heavy oil. 3.3.3. Component analysis for produced oil In order to study the effect of flue gas or/and n-hexane on the crude oil properties in the process of steam flooding, the samples of produced oil were analyzed. According to the flooding conditions, ten samples of the produced oil were collected from the four groups of flooding experiment, and the contents of saturate, aromatic, resin and asphaltene for each sample were measured. The parameters were tested for three times, the average values are presented in Table 3.
3.5
Steam Flue gas + steam n-C6 H14 + steam Flue gas + n-C6 H14 + steam
2.0
1.5
Oil production rate (mL/min)
Pressure difference (MPa)
2.5
1.0
0.5
3.0
Steam Flue gas + steam n-C6 H14 + steam Flue gas + n-C6 H14 + steam
2.5 2.0 1.5 1.0 0.5 0.0
0.0
0.0
0.5
1.0
1.5
2.0
2.5
Injected volume (PV) Fig. 13. Pressure differences of different displacement patterns.
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
Injected volume (PV) Fig. 15. Oil production rates of different displacement patterns.
90
S. Li et al. / Fuel 187 (2017) 84–93
Table 3 Properties of produced oil for the floodings. Test No.
Flooding pattern
Collection time
Saturate (wt%)
Aromatic (wt%)
Resin (wt%)
Asphaltene (wt%)
Molecular Weight of Asphaltene⁄ (g/mol)
Viscosity at 20 °C (105 mPa s)
1#
Steam flooding
Before water breakthrough After water breakthrough
40.12
23.68
30.12
6.08
2189
7.45
40.21
23.52
30.01
6.26
2228
7.67
2#
Steam flooding assisted by flue gas
Before gas breakthrough After gas and before water breakthrough After water breakthrough
40.15 40.83
23.51 24.01
30.16 30.09
6.18 5.07
2209 2104
7.57 6.21
41.04
24.47
30.32
4.17
1934
5.11
23.58
30.07
6.26
2199
7.67
3#
Steam flooding assisted by n-hexane
Before water breakthrough After water breakthrough
40.09 42.51
25.25
29.19
3.05
1897
3.94
4#
Steam flooding assisted by flue gas and n-hexane
Before gas breakthrough After gas and before water breakthrough After water breakthrough
40.21 42.32
23.36 24.68
30.23 29.97
6.20 3.03
2191 1891
7.60 4.11
43.04
25.18
29.44
2.34
1650
3.17
⁄
2600 2400
before gas breakthrough before water breakthrough after water breakthrough
2200 2000 1800 1600 1400 1200 1000
1#
2#
3#
4#
Displacement pattern Fig. 16. Molecular weights of asphaltene for produced oil.
are related the heavy composition contents. The higher the heavy composition contents are, the greater the viscosity is.
3.3.4. Component analysis for residual oil After the flooding experiment, the sand with residual oil was removed from the sandpacks as presented in Fig. 18. The sand color darkens gradually from inlet to outlet. Heavy oil in sandpacks flowed from the inlet to outlet because thermal effect of steam and
10
Oil viscosity (10 5 mPa.s)
It can be seen from Table 3 that the compositions of the produced heavy oil collected from different periods of the flooding experiments are different compared to that of the original heavy oil. For steam flooding, two oil samples were collected before and after water breakthrough. The results show that the compositions of the produced oils are almost the same to that of the original oil, because steam can only decrease the oil viscosity by increasing the temperature, and cannot extract light components from the heavy oil. For steam flooding assisted by flue gas, the mobility of flue gas was greater than that of water and heavy oil in the sandpack. There was a pure oil production period firstly with no gas and water production, then flue gas broke through, and at last water broke through. Three oil samples were collected before gas breakthrough, before water breakthrough and after water breakthrough. The compositions of the produced oil before gas breakthrough are almost the same to that of the original oil. The asphaltene content decreased after gas breakthrough, because flue gas has some effect of extract light components from the heavy oil. After water breakthrough, asphaltene content decreased further, and saturate and aromatic contents increase to a certain extent. For steam flooding assisted by n-hexane, the n-hexane was produced as liquid state with oil and water under backpressure. Two oil samples were collected before and after water breakthrough. The compositions of the produced oil before water breakthrough are almost the same to that of the original oil. The asphaltene content decreased obviously after water breakthrough, which is only 3.05%. The reason is that n-hexane has high solubility in heavy oil and greatly enhances the extraction of extract light components from the heavy oil. More light components of the heavy oil were produced. For steam flooding assisted by flue gas and n-hexane, three oil samples were collected before gas breakthrough, before water breakthrough and after water breakthrough. The compositions of the produced oil before gas breakthrough are almost the same to that of the original oil. The asphaltene content decreased after gas breakthrough, and after water breakthrough asphaltene content decreased further, which is the lowest value. The molecular weights of asphaltene content for each oil sample were measured as shown in Table 3 and Fig. 16. The results illustrate that co-injection of flue gas and n-hexane has the greatest effect for molecular weight reduction related to light component extraction. The molecular weight can be reduced to 1650 g/mol from the original value of 2217 g/mol. The viscosities of the produced oils were also tested as show in Fig. 17. The results
Molecular weight of asphaltene (g/mol)
The asphaltene molecular weight was measured by the vapor pressure osmometry (VPO) based on Raoul’s law. Toluene was used as a solvent in the testing pool, and the experimental temperature was 45 °C.
8
before gas breakthrough before water breakthrough after water breakthrough
6
4
2
0
1#
2#
3#
Displacement pattern Fig. 17. Oil viscosities for produced oil.
4#
91
S. Li et al. / Fuel 187 (2017) 84–93
60
Oil saturation (%)
50
inlet outlet
40 30 20 10 0
1#
2#
3#
4#
Displacement pattern Fig. 19. Oil saturations of different displacement patterns.
viscosity reduction due to flue gas and n-hexane dissolution. At the same position of the sandpack, the color of sand flooded by steam assisted by flue gas and n-hexane is the lightest, and that by steam solely is the darkest. The results show that the displacement efficiency of flue gas and n-hexane is the best, which is consistent with the oil recovery curves in Fig. 14. In order to analyze the effect of flue gas and n-hexane on heavy oil recovery, the sands at inlet and outlet of the sandpacks were collected, and oil saturation, oil component, and molecular weight of asphaltene were tested. The parameters were tested three times, the average values are shown in Table 4. The results display that the light component contents of saturate and aromatic are less at inlet of the sandpack, however, the heavy component contents of resin and asphaltene are greater. During the process of displacement, light components in crude oil are easy to flow from inlet to outlet of the sandpack, and the flow capability of heavy components are weak. More heavy components gathered in the inlet. The oil saturations at inlet and outlet of the sandpacks are shown in Fig. 19. The results display that the oil saturations at outlets are always greater than that of inlets for different flooding patterns. The reason is that in the process of displacement, the continuous injected fluid from the inlet carried oil to the outlet of the sandpack. At the end of the steam flooding, oil saturations at inlet and outlet are 40.80% and 51.07% respectively. At the end of the steam flooding assisted by flue gas, oil saturations are 31.24% and 38.25% respectively. Compared with steam flooding, the oil saturations decreased to some extent. For steam flooding assisted by n-hexane, the oil saturations decreased further, which
Molecular weight of asphaltene (g/mol)
Fig. 18. Sand samples removed from sandpacks after flooding. (a), (b), (c) and (d) are the sand samples flooded by steam, steam assisted with flue gas, steam assisted with n-hexane, and steam assisted with flue gas and n-hexane, respectively.
6000
inlet outlet
5000 4000 3000 2000 1000 0
1#
2#
3#
4#
Displacement pattern Fig. 20. Molecular weights of asphaltene for residual oil in sandpacks.
are 11.4% and 22.14%. For steam flooding assisted by flue gas and n-hexane, the oil saturations are the least, which are 7.88% and 16.34% respectively. The results reveal that flue gas and n-hexane have the best effect on improving oil recovery. The molecular weights of asphaltene at inlet and outlet of the sandpacks are shown in Fig. 20. The results display that molecular weights of inlets are greater than that of outlets, which is similar to the asphaltene contents of the residual oil in the sandpacks and opposite to that of the produced oil. The reason is that the light components with small molecular weight are easy to flow from inlet to outlet. Fig. 21 displays the asphaltene-to-resin ratio (ATR) for different heavy oil samples. The ATR ratio indicates asphaltene stability because of the presence of resins. Statistically, asphaltene is
Table 4 Properties of the residual oil in sandpacks. Test No.
Flooding pattern
Collection time
Saturate (wt%)
Aromatic (wt%)
Resin (wt%)
Asphaltene (wt%)
Molecular weight of asphaltene (g/mol)
Oil saturation (%)
1#
Steam flooding
Inlet Outlet
40.20 40.03
22.58 22.69
31.11 31.09
6.11 6.19
2167 2186
40.80 51.07
2#
Steam flooding assisted by flue gas
Inlet Outlet
36.07 37.69
21.99 21.64
33.23 33.05
8.71 7.62
3804 3193
31.24 38.25
3#
Steam flooding assisted by n-hexane
Inlet Outlet
33.14 36.70
20.33 19.02
34.26 34.06
12.27 10.22
4084 3286
11.40 22.14
4#
Steam flooding assisted by flue gas and n-hexane
Inlet Outlet
30.38 32.61
18.65 18.34
34.72 34.22
16.25 14.83
4644 3787
7.88 16.34
92
S. Li et al. / Fuel 187 (2017) 84–93
25
sity of Petroleum (East China) for their assistance with the experimental research.
ATR=0.67
Asphaltene content (wt%)
Unstable region
20
15
Transition region
Origional oil Produced oil, 1# Produced oil, 2# Produced oil, 3# Produced oil, 4# Residual oil, 1# Residual oil, 2# Residual oil, 3# Residual oil, 4#
10
5
References
ATR=0.4
Stable region
0 20
25
30
35
40
45
Resin content (wt%) Fig. 21. ATRs for the produced and residual oil samples.
expected to be unstable when the ATR ratio is >0.67, stable when the ATR ratio is <0.4, and in the transition region for 0.4 < ATR ratio <0.67 [40]. The results in Fig. 21 illustrate that all produced oils from the floodings are less than 0.4 and in the stable region. The reason is that the asphaltenes precipitation in the sandpack led to a relatively lower asphaltenes content in the produced oils. However, flue gas and n-hexane induced light component extraction and resulted in an increase in asphaltenes content in the residual oil. The ATRs of the residual oil 4# are greater than 0.4, locating in the transition region. This means that the asphaltenes component in the residual oils is not as stable as that in the produced oils, which may cause deposition of asphaltenes in the sandpack. 4. Conclusions (1) The flue gas dissolved in heavy oil can effectively reduce oil viscosity, increase the flow capability, and make the volume swell. Higher pressure reduces surface tension of heavy oil and gas, and higher temperature increases surface tension. Compared with flue gas, n-hexane can reduce heavy oil viscosity and surface tension more obviously, and adding small amount of n-hexane into flue gas can achieve good effect. (2) The flue gas and n-hexane can effectively improve the development effect of the steam flooding. The pressure difference of steam flooding assisted by flue gas and n-hexane is the lowest, the oil production rate is highest, and the oil recovery efficiency can reach 80%. (3) Flue gas and n-hexane can effectively change crude oil properties. The heavy component of heavy oil, molecular weight of asphaltene and oil viscosity for the produced oil all reduced. The heavy component and molecular weight of asphaltene for the residual oil in sandpacks all increased. The effect of flue gas and n-hexane together on heavy oil properties is the greatest. The asphaltenes component in the residual oil is not as stable as that in produced oil.
Acknowledgements Financial support is received by the National Natural Science Foundation of China (Nos. 51274228 and 51304229), the National Key Scientific and Technological Project for the Oil & Gas Field and Coalbed Methane (No. 2016ZX05031002-004-002) and the Fundamental Research Funds for the Central Universities (14CX02185A). We are grateful to the Foam Research Center at the China Univer-
[1] Wilson M, Monea M. IEA GHG Weyburn CO2 monitoring and storage project summary report 2000–2004. The 7th international conference on greenhouse gas control technologies, 5–9 September, 2004. [2] Kay D, André F, Wim T. Pathways towards large-scale implementation of CO2 capture and storage: a case study for the Netherlands. Int J Greenhouse Gas Control 2009;3:217–36. [3] Liu HW, Berenice GT, Tarek A, Murad B. The role of CO2 capture and storage in Saudi Arabia’s energy future. Int J Greenhouse Gas Control 2012;11:163–71. [4] Sander VE, Marko PH. Argument map for carbon capture and storage. Int J Greenhouse Gas Control 2012;11:S148–59. [5] Paul Z, Mike H. Permitting issues for CO2 capture, transport and geological storage: a review of Europe, USA, Canada and Australia. Int J Greenhouse Gas Control 2007;1:94–100. [6] Karaoguz OK, Topguder NNS, Lane RH, Kalfa U, Celebioglu D. Improved sweep in Bati Raman heavy-oil CO2 flood: bullhead flowing gel treatments plug natural fractures. SPE Reserv Eval Eng 2007;10:1–12. [7] Secaeddin S, Ulker K, Demet C. Bati Raman filed immiscible CO2 applicationatatus quo and future plans. In: Latin American & Caribbean petroleum engineering conference, 15–18 April, 2008, 2008, SPE 106575. [8] Kleinsteiber SW. The wertz tensleep CO2 flood: design and initial performance. J Petrol Technol 1988;42:630–6. [9] Agustssen H, Grinestafr GH. A study of IOR by CO2 injection in the Gullfaks field. In: SPE/DOE symposium on improved oil recovery, 17–21 April, 2004 Tulsa, Oklahoma, 2004, SPE 89338. [10] Siregar S, Mardisewojo P, Kristanto D, Tjahyadi R. Dynamic interaction between CO2 gas and crude oil in porous medium. In: SPE Asia Pacific improved oil recovery conference, 25–26 October, 1999, Kuala Lumpur, Malaysia, 1999, SPE 57300. [11] Zhang C, Li ZM, Wang HY, Wang SH, Yi HF, Xue XC, Yao YP. Performance of flue gas and foam assisted steam huff and puff with horizontal well in enhanced recovery of Fengcheng Oil field. In: SPE heavy oil conference-Canada, 10–12 June, 2014, Calgary, Alberta, Canada, 2014, SPE 170105. [12] Miller KA, Moore RG, Ursenbach MG, Laureshen CJ, Mehta SA. Proposed air injection recovery of cold-produced heavy oil reservoirs. J Canad Petrol Technol 2002;41:40–9. [13] Das SK, Butler RM. Mechanism of the vapor extraction process for heavy oil and bitumen. J Petrol Sci Eng 1998;21:43–59. [14] Frauenfeld T, Lillico D, Jossy G, Vilcsak G, Rabeeh S, Singh S. Evaluation of partially miscible processes for Alberta heavy oil reservoirs. J Canad Petrol Technol 1998;37:17–25. [15] Metwally M. Enriched gas pressure cycling process for depleted heavy oil reservoirs. J Canad Petrol Technol 1998;37:56–60. [16] Yang CD, Gu YA. A new method for measuring solvent diffusivity in heavy oil by dynamic pendant drop shape analysis (DPDSA). SPE J 2006;11:48–57. [17] Fairfield WH, White PD. Lloydminster fireflood performance, modifications promise good recoveries. Oil Gas J 1982;80:101–2. [18] Dyer SB, Huang SS, Farouq Ali SM, Jha KN. Phase behaviour and scaled model studies of Prototype Saskatchewan heavy oils with carbon dioxide. J Canad Petrol Technol 1994;33:42–8. [19] Dong MZ, Huang S, Hutchence K. Methane pressure-cycling process with horizontal wells for thin heavy-oil reservoirs. SPE Reserv Eval Eng 2006;9:154–64. [20] Luo P, Er V, Freitag N, Huang S. Recharacterizing evolving fluid and PVT properties of Weyburn oil-CO2 system. Int J Greenhouse Gas Control 2013;16: S226–35. [21] Cao M, Gu Y. Physicochemical characterization of produced oils and gases in immiscible and miscible CO2 flooding processes. Energy Fuel 2013;27:440–53. [22] Wang SH, Chen SN, Li ZM. Characterization of produced and residual oils in the CO2 flooding process. Energy Fuel 2016;30:54–62. [23] Sun Q, Li Z, Wang J, Li S, Li B, Jiang L, Wang H, Lü Q, Zhang C, Liu W. Aqueous foam stabilized by partially hydrophobic nanoparticles in the presence of surfactant. Colloids Surf A 2015;471:54–64. [24] Sun Q, Li Z, Wang J, Li S, Jiang L, Wang J, Wang P. Utilization of surfactantstabilized foam for enhanced oil recovery by adding nanoparticles. Energy Fuel 2014;28:2384–94. [25] Ravera F, Santini E, Loglio G, Ferrari M, Liggieri L. Effect of nanoparticles on the interfacial properties of liquid/liquid and liquid/air surface layers. J Phys Chem B 2006;110:19543–51. [26] Li HZ, Yang DY, Tontiwachwuthiku P. Experimental and theoretical determination of equilibrium interfacial tension for the solvent(s)-CO2-heavy oil systems. Energy Fuel 2012;26:1776–86. [27] Yang DY, Gu YA. Visualization of interfacial interactions of crude oil-CO2 systems under reservoir. In: SPE/DOE symposium on improved oil recovery, 17–21 April, 2004, Tulsa, Oklahoma, 2004, SPE 89366. [28] Yang DY, Tontiwachwuthikul P, Gu YA. Interfacial tensions of the crude oil + reservoir brine + CO2 systems at pressures up to 31 MPa and temperatures of 27 °C and 58 °C. J Chem Eng Data 2005;50:1242–9. [29] Zolghadr A, Escrochi M, Ayatollahi S. Temperature and composition effect on CO2 miscibility by interfacial tension measurement. J Chem Eng Data 2013;58:1168–75.
S. Li et al. / Fuel 187 (2017) 84–93 [30] Li HZ, Yang DY. Phase behavior of C3H8-n-C4H10-heavy oil systems at high pressures and elevated temperatures. In: SPE heavy oil conference Canada, 12– 14 June, 2012, Calgary, Alberta, Canada, 2012, SPE 157744. [31] Ayodele OR, Nasr TN, Ivory JJ, Beaulieu G, Heck G. Testing and history matching of ES-SAGD (using hexane). In: SPE western regional meeting, 27–29 May, 2010, Anaheim, California, USA, 2010, SPE 134002. [32] McCormack ME. Design of steam-hexane injection wells for gravity drainage systems. J Canad Petrol Technol 2009;48:22–8. [33] Hascakir B. Effective extraction of high viscosity and low API gravity hydrocarbon resources with solvent-steam processes. In: SPE western regional meeting, 23–26 May, 2016, Anchorage, Alaska, USA, 2016, SPE 180424. [34] Ardali M, Barrufet M, Mamora DD. Laboratory testing of addition of solvents to steam to improve SAGD process. In: SPE heavy oil conference Canada, 12–14 June, 2012, Calgary, Alberta, Canada, 2012, SPE 146993. [35] Ardali M, Mamora D, Barrufet MA. Experimental study of co-injection of potential solvents with steam to enhance SAGD process. In: SPE Western
[36]
[37] [38] [39] [40]
93
North American region meeting, 7–11 May, 2011, Anchorage, Alaska, USA, 2011, SPE 144598. Sigmund PM, McCaffery FG. An improved unsteady-state procedure for determining the relative-permeability characteristics of heterogeneous porous media. SPE J 1979;19:15–28. Tao TM, Watson AT. Accuracy of JBN estimates of relative permeability: part 1 – error analysis. SPE J 1984;24:209–14. Tao TM, Watson AT. Accuracy of JBN estimates of relative permeability: part 2 – algorithms. SPE J 1984;24:215–23. Li SY, Li ZM. Effect of temperature on the gas/oil relative permeability of Orinoco Belt foamy oil. SPE J 2016;21:170–9. Gonzalez RDL. Modeling of asphaltene precipitation and deposition tendency using the PC-SAFT equation of state. PhD dissertation, Rice University, Houston, TX; 2008.