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The study on permeability reduction during steam injection in unconsolidated porous media
Journal of Petroleum Science and Engineering 106 (2013) 77–84
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Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
The study on permeability reduction during steam injection in unconsolidated porous media Zhanxi Pang a,b,n, Huiqing Liu a,b a b
Faculty of Petroleum Engineering, China University of Petroleum, Fuxue Road No. 18, Changping District, Beijing 102249, China MOE Key Laboratory of Petroleum Engineering, China University of Petroleum, Beijing 102249, China
art ic l e i nf o
a b s t r a c t
Article history: Received 28 September 2012 Accepted 26 April 2013 Available online 14 May 2013
The effluents from steam generators usually have low salinity and high pH level during steam injection. Steam and its condensate can cause particle migration and hydrothermal reactions. Those largely decrease production potential of heavy oil resulting from permeability reduction. The flow experiments were conducted in sand-pack filled with unconsolidated sands. This paper presented the experimental results to evaluate the influence of pH level and temperature on permeability reduction. Meanwhile, a series of hydrothermal reactions were conducted to analyze solubility of solid particles in steam condensate. The experimental results showed that steam condensate irreversibly reduced the permeability up to 43.52%, but the permeability was only restored to 66.32%. Sandstone interaction with high pH condensate leads to a serious dissolution of formation minerals and subsequent precipitation of new minerals. Particle migration and hydrothermal reaction constitute the primary damage mechanisms when steam and condensate of low salinity and high temperature are injected into unconsolidated porous media. & 2013 Elsevier B.V. All rights reserved.
Keywords: permeability reduction steam particle migration hydrothermal reaction experiment
1. Introduction Heavy oil is a kind of important petroleum resource that plays an increasingly great role in daily life and industry production (Niu and Hu, 1999; Farouq, 2003; Frances, 2006). Heavy oil resources are total 10 trillion barrels, nearly three times the conventional oil in the world (Renato, 2011). Thermal recovery methods, especially steam stimulation and steam flooding, are proven as the most effective enhanced oil recovery technologies (Tayfun, 2003; Pathak et al., 2011).
expansion, mineral generation, particle migration and scale precipitation, asphalt deposition and wettability reversion (Pahlavan and Rafiqul, 1985; Leonataritis and Mansoori, 1988; Faure et al., 1997; Fan et al., 2002; Schembre and Kovscek, 2004). Particle migration, scale precipitation and fine plugging cause serious sand production to accelerate formation damages (Hajdo and Clayton, 1994; Mohan et al., 1999). Dissolution and generation of formation minerals promote the degree of formation damage during steam injection in heavy oil reservoirs. 1.2. Particle migration and hydrothermal reaction
1.1. Formation damage of steam injection Steam and condensate cause chemical reactions which could decrease production potential by reducing permeability and porosity (Bagci et al., 2000; Diabira et al., 2001). McCorriston et al. (1981) observed that alkaline effluents from steam generator irreversibly reduced the permeability of cores by up to 70% in their experiments. Okoye et al. (1991) conducted many experiments of steam temperatures and pH levels influencing formation damage in heavy oil reservoirs. During steam injection, the primary mechanisms on formation damages include clay n Corresponding author at: Faculty of Petroleum Engineering, China University of Petroleum, Fuxue Road No. 18, Changping District, Beijing 102249, China. Tel.: +86 18201281464. E-mail address: [email protected] (Z. Pang).
0920-4105/$ - see front matter & 2013 Elsevier B.V. All rights reserved. http://dx.doi.org/10.1016/j.petrol.2013.04.022
Petroleum productivity decline is often caused by particle migration and formation plugging (Bagci et al., 2000; Schembre and Kovscek, 2004). Almost all formations contain significant amount of clay minerals. Meanwhile, most of the heavy oil reservoirs belong to unconsolidated formations. Thermal recovery operations in these formations often lead to particle mobilization due to chemical reaction between reservoir minerals and injected fluids (McCorriston et al., 1981; Okoye et al., 1991; Hajdo and Clayton, 1994; Schembre and Kovscek, 2004). Particle migration and resultant plugging of pore-throats is one of the primary reasons for the reduction in permeability during steam injection. Permeability damage due to particle migration could be caused by mechanical or chemical effects (Rosario et al., 1996). Mechanical effects are controlled by many factors, such as flow rate, viscosity, particle size and pore size (Moghadasi et al., 2004). Chemical
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effects are observed when a chemically incompatible fluid is introduced into reservoirs, which could cause clay minerals to disperse and to migrate (McCorriston et al., 1981; Okoye et al., 1991). During steam injection, large volumes of saturation steam are injected into heavy oil reservoirs at high pressure and elevated temperature. A new chemical equilibrium between minerals and formation fluids is reached to be reflected by mineral dissolution, variation of water chemistry, generation of new minerals, scale precipitation and particle migrations, that is, hydrothermal reactions (Gruesbeck and Collins, 1982; Bouddour et al., 1996; Chang and Civan, 1997; Faure et al., 1997). Reed (1980) in an earlier experiment noted sandstone dissolution during steam injection. Okoye et al. (1991) reported that quartz and other siliceous minerals were hardly dissolved at room temperature, but the solubility sharply increased at elevated temperature. Some studies found the fact that injection of lower salinity water than formation water could cause dispersion, expansion and transformation of clay minerals (Gruesbeck and Collins, 1982; Bennion and Thomas, 1992; Hajdo and Clayton, 1994; Schembre and Kovscek, 2004). Mohnot et al. (1987) observed that alkaline solution could cause clay migration and expansion resulting in permeability reduction. Effluent with high pH level and low salinity content from steam generator could cause many formation damages to decrease productivity by reducing permeability (Amaefule et al., 1984; Lefebvre and Hutcheon, 1986; Okoye et al., 1991; Geilikman and Dusseault, 1997; Schembre and Kovscek, 2004). 1.3. Purpose of this study During thermal recovery, saturation steam and its condensate are injected into heavy oil reservoirs. Steam condensate from steam generator often has high pH level above 12 and low salinity content. The hydrothermal reactions between injected fluids and formation minerals can promote permeability reduction during steam injection. In this article, a series of flow experiments were employed to investigate particle migration and permeability reduction during steam condensate flowing in unconsolidated porous media. Meanwhile, some experiments of hydrothermal reactions were conducted to analyze migration mechanisms of solid particles during steam injection in unconsolidated porous media.
Table 1 Component analysis of formation minerals in Lian II of Qi 40. Rock
Clay
Component
Percent (%)
Component
Percent (%)
Quartz Feldspar Calcite Dolomite Rock debris Total amount
33.5 32.0 0.0 0.0 23.7 89.2
Smectite Kaolinite Illite Chlorite Mixed layer clays Total amount
7.0 2.0 1.8 0.0 0.0 10.8
2.2. Experimental apparatus A schematic of experimental apparatus used in flow experiments is shown in Fig. 1. The apparatus included one constant temperature oven, one sand-pack, one injection pump and other affiliated devices. The oven was used to control experimental temperature from 50 1C to 200 1C. The sand-pack was 30 cm long and 3.8 cm in inner diameter. Three pressure taps and three temperature taps were symmetrically welded on the surface of the sand-pack. The sand-pack was filled with unconsolidated rock grains and clay minerals to establish different permeability. A water tank was filled with brine solution on behalf of formation water. An alkali solution tank was filled with NaOH solution of 0.4% by weight (pH ¼ 13) on behalf of steam condensate. A network of pipelines and valves was used to inject brine solution or alkali solution into the sand-pack. The data of temperature and pressure were transmitted to a computer by temperature sensors and pressure sensors. Kerosene was injected into a brine solution tank or alkali solution tank in order to drive the experimental liquids into the sand-pack by the injection pump. In order to prevent the caustic fluid from entering into the pressure sensors, three small buffer containers were equipped between pressure taps and pressure sensors. The containers were small hollow tanks containing distilled water. At the outlet of sand-pack, a backpressure valve was utilized to control the outlet pressure.
2.3. Experimental procedures 2. Flow experiment 2.1. Mineral and fluid samples The rock samples were obtained from Lian II Layer of Qi 40 in Liaohe Oilfield, China. The rock minerals are mainly composed of quartz and feldspars. The average content of quartz is 33.5%. The average content of feldspars is 32%. The average content of clay minerals is 6.75%. The clay minerals are mainly composed of smectite, kaolinite and illite. The content of mineral components is listed in Table 1. Water samples were used in experiments from Lian II Layer of Qi 40 in Liaohe Oilfield. Formation water contains high concentration bicarbonate. It is different from the effluents from steam generator. Steam condensate is a strong caustic solution. The analysis of water sample is listed in Table 2. The salinity of formation water is about 2000–8000 mg/L. The cations mainly are K+ and Na+, but the contents of Ca2+ and Mg2+ are lower in formation water. Cl− and HCO−3 are the primary anions but 2− SO2− 4 and CO3 are relatively poorer. In our experiments, steam condensate was replaced by alkali solution. The concentration of alkali solution was 0.4% by weight (pH is about equal to 13).
A new experimental method, the positive and reverse injection, was employed to analyze particle migration and permeability reduction in unconsolidated porous media (Archer and Hurst, 1987). Firstly, a certain fluid was injected into porous media until it reached a steady state to measure absolute permeability. That was called the positive injection. Then the same fluid was injected into the porous media from the other end until a steady state to measure the permeability again. That was called the reverse injection. The positive injection often causes the reduction of permeability resulting from particle migration in porous media. If the permeability gradually increases or first increases and then decreases during the reverse injection, then it shows that solid particles begin to migrate in porous media. If the permeability remains constant or continues to reduce during the reverse injection, then it shows that the reduction of permeability is not just from particle migration in porous media. In order to research the influence of temperature and pH level on permeability, two kinds of flow experiments were conducted. The brine solution or the alkali solution was injected into the sand-pack in the experiments. The parameters of sand-pack are listed in Table 3.
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Table 2 Component analysis of water sample of Qi 40. Steam generator
Water sample
Na++K+ (mg/L)
Ca2+ (mg/L)
Cl− (mg/L)
SO42− (mg/L)
HCO3− (mg/L)
CO32− (mg/L)
OH− (mg/L)
Salinity (mg/L)
pH
Qi 40-3
Feed Condensate
199.6 786.6
7.3 9.7
0.0 0.0
70.9 301.3
48.0 67.2
319.1 0.0
63.0 690.6
0.0 231.2
707.9 2086.6
7.1 11.5
Qi 40-4
Feed Condensate
195.3 722.2
4.9 6.1
0.0 0.0
62.0 381.1
28.8 57.6
399.1 0.0
0.0 240.0
0.0 271.2
690.1 1678.2
7.1 12.0
Qi 40-5
Feed Condensate
190.2 759.9
12.2 17.0
0.0 4.0
70.9 390.0
48.0 105.7
350.9 0.0
31.2 753.0
0.0 151.1
703.4 2180.7
7.2 11.6
Mg2+ (mg/L)
Brine solution tank
Valve Injection Pump
Sand-pack Buffer container
Pressure gauge Alkali solution tank
Kerosene
Data acquisition m system
Computer
Backpressure valve
Temperature sensor
Constant temperature oven
Liquid cylinder
Pressure transducer
Fig. 1. Schematic diagram of displacement experiment.
Table 3 Parameters of sand-pack in flow experiments. Parameter
Temperature 50 (1C)
Diameter (cm) Length (cm) Permeability ( 10−3 μm2) Porosity (%) Pore volume (cm3)
100
150
200
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
3.8 30.0 2200.2 32.5 110.6
3.8 30.0 2205.4 31.4 106.8
3.8 30.0 2120.5 30.8 104.8
3.8 30.0 2101.7 31.1 105.8
3.8 30.0 2064.7 30.6 104.1
3.8 30.0 2047.3 29.8 101.4
3.8 30.0 2036.8 33.4 113.6
3.8 30.0 2074.9 31.3 106.5
2.3.1. Flow experiments of brine solution Firstly, the sand-pack was saturated with brine solution. Then the sand-pack and corresponding pipelines were equipped in the experimental system. Experimental temperatures were controlled at 50 1C, 100 1C, 150 1C and 200 1C. Until the whole system got to be isothermal, the brine solution was injected into the sand-pack at the corresponding temperature. After injecting about 10 PV of brine solution, the flow direction was reversed and the additional 10 PV of brine solution was injected into the sand-pack. During solution injection, flow rate and pressure difference were recorded by the computer with an interval of 1 min. Then the permeability could be calculated according to the flow rate, pressure difference and other parameters of sand-pack.
2.3.2. Flow experiments of alkali solution De-ionized formation water is utilized to produce high temperature steam during thermal recovery in oilfield. A part of steam is condensed into hot water, that is, condensate resulting from heat loss in formation. The pH of condensate is up to over 12 in oilfield. In our experiments, firstly, the sand-pack was saturated with brine solution. Then it was equipped in the experimental system. The temperature of the oven was controlled at 50 1C, 100 1C, 150 1C and 200 1C. When it got to the given temperature, NaOH solution was injected into the sand-pack at the given temperature. The concentration of solution was 0.4% by weight, corresponding to a pH of 13. About 10 PV of alkali solution was injected into the sand-pack in the positive direction. Then an
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additional 10 PV of solution was injected into the sand-pack in the reverse direction, that is, the outlet of the sand-pack. During experiments flow rate and pressure difference were recorded by the computer with an interval of 1 min. Then the permeability could be calculated. The procedures followed to conduct the flow experiments are as follows: (1) the sand-pack filled with mineral samples was firstly equipped in the experimental system. Then the sand-pack and the pipelines were vacuumized by a vacuum pump for 4 h. (2) The brine solution was injected into the sand-pack until it was fully saturated to measure pore volume and porosity. Several pore volumes of brine solution were continuously injected into the sand-pack to measure the absolute permeability. (3) The oven and the liquid tank were controlled to an experimental temperature, such as 50 1C, 100 1C, 150 1C and 200 1C, for over 2 h. (4) A backpressure of about 0.5 MPa higher than steam saturation pressure was applied to maintain liquid phase state for injected fluids. Then brine solution or alkali solution was injected into the sand-pack by the pump until 10 PV. (5) The injection direction was reversed and an additional 10 PV of brine solution or alkali solution was injected into the opposite end of the sand-pack. (6) A new sand-pack was replaced in the experimental system to conduct another experiment as the former procedures (1)–(5).
3. Experimental results 3.1. Flow experiment The permeability trend curves of injecting brine solution and alkali solution at 50 1C are shown in Fig. 2. It is shown that the permeability gradually decreases as injection volume of the brine solution increases for the positive injection. The permeability decreases to 1.88 μm2 from 2.2 μm2 after injecting 10 PV of brine solution into the sand-pack. But the results of the reverse injection experiments show that the permeability gradually increases as injection volume of brine solution increases at 50 1C. It presents that the permeability only has a very small loss in reverse injection. The results tell us that permeability variation was only subject to particle migration during injection of brine solution at 50 1C. However, when the alkali solution is injected into the sandpack, the permeability decreases sharply as injection volume increases for the positive injection. After injecting 10 PV of alkali solution of 0.4% by weight, the permeability decreases from 2.21 μm2 to 1.43 μm2. In the processes of reverse injection, the permeability could not be restored to the initial level. At the end of reverse injection, the final permeability could only be restored to
1.69 μm2. Therefore, formation damage results from not only particle migration in porous media but also some chemical reactions between minerals and alkali solution. The permeability trend curves of injecting brine solution and alkali solution at 100 1C are shown in Fig. 3. The results show that the permeability gradually decreases with injection of brine solution for the positive injection. The permeability decreases from 2.12 μm2 to 1.71 μm2 after injecting 10 PV of brine solution. The final permeability is slightly lower at 100 1C than 50 1C at the end of positive injection. The results of reverse injection show that the permeability gradually increases from 1.71 μm2 to 1.87 μm2 as injection volume of brine solution increases at 100 1C. The final permeability of reverse flow could not return to the initial level. It shows that the chemical reactions between minerals and steam condensate decrease permeability except for particle migration during brine solution injection at 100 1C. When the alkali solution is injected into the sand-pack, the permeability decreases sharply as injection volume increases for the positive injection. After injecting 10 PV of alkali solution (0.4% by weight), the permeability decreases from 2.10 μm2 to 1.34 μm2. At the end of the reverse injection, the final permeability could not be restored to the initial level, and it is only restored to 1.59 μm2. Therefore, the alkali solution could cause two effects, such as particle migration and hydrothermal reaction in unconsolidated porous media. It was presented that the permeability greatly decreases with injection of brine solution for the positive injection at 150 1C, as shown in Fig. 4. The permeability decreases from 2.06 μm2 to 1.275 μm2 at the end of positive injection for the brine solution. The decline degree of permeability is larger at 150 1C than 50 1C and 100 1C at the end of positive injection. The results show that the permeability is finally restored to 1.87 μm2 at the end of reverse injection at 150 1C. The permeability could not return to the initial level. When the alkali solution is injected into the sandpack, the permeability decreases sharply as injection volume increases for positive injection. After injecting 10 PV of alkali solution (0.4% by weight), the permeability decreases from 2.05 μm2 to 1.11 μm2. At the end of reverse injection, the final permeability could not be restored to the initial level. It is only restored to 1.36 μm2. The permeability trend curves of injecting brine solution and alkali solution at 200 1C are shown in Fig. 5. The results show that the permeability gradually decreases with injection of brine solution for the positive injection. The permeability decreases from 2.04 μm2 to 1.53 μm2 after injecting 10 PV of brine solution. The results show that the permeability gradually increases from 1.53 μm2 to 1.70 μm2 during injection of brine solution at 200 1C in
2200
2400
2000
Permeability (×10-3μm2)
Permeability (×10-3μm2)
2200 2000
1800
1600 1400 Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
1200
1800
1600
1400 Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
1200
1000
1000 0
2
4
6
8
10
12
14
16
18
PV Fig. 2. Permeability trend of different fluid injections at 50 1C.
20
0
2
4
6
8
10
12
14
16
18
PV Fig. 3. Permeability trend of different fluid injections at 100 1C.
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81
2200 Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
Permeability (×10-3μm2)
2000
Pressure gauge P
Valve
High pressure pump
1800
1600
Pump
1400
NaOH solution tank
1200 Condensator
Kerosine tank
Water tank
Reaction oven
1000 0
2
4
6
8
10
12
14
16
18
20
Fig. 6. The schematic diagram of solubility experiment.
PV
Fig. 4. Permeability trend of different fluid injections at 150 1C. Table 4 Solubility of clay minerals and rock grains at different temperatures and pH levels. 2200
No. Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
Permeability (×10-3μm2)
2000
1800
1600
1400
1200
1000 0
2
4
6
8
10
12
14
16
18
20
PV Fig. 5. Permeability trend of different fluid injections at 200 1C.
the reverse injection. The permeability of reverse injection could not return to the initial level. The results show that minerals could react with steam condensate except for particle migration to decrease permeability during the brine solution injection at elevated temperature. When the alkali solution is injected into the sand-pack, the permeability decreases sharply as injection volume increases for the positive injection. After injecting 10 PV of alkali solution (0.4% by weight), the permeability decreases from 2.07 μm2 to 1.17 μm2. At the end of reverse injection, the permeability could not be restored to the initial level, and it is only restored to 1.535 μm2. 3.2. Hydrothermal reaction Hydrothermal reaction results from the chemical reaction between steam condensate and formation minerals in heavy oil reservoirs during steam injection. The reaction could cause dissolution of formation minerals and precipitation of new minerals, such as CaCO3, zeolites and etc., to result in formation damage. Based on the former flow experiments, a reaction oven was employed to research the solubility of rock grains and clay minerals at different temperatures and pH levels, as shown in Fig. 6. Finally, the mechanisms of migration and retention were analyzed for solid particles in unconsolidated porous media at elevated temperature and high pH level. The mineral samples were chosen from Lian II Layer of Qi 40 in Liaohe Oilfield. The samples were naturally unconsolidated sands from the production
Mineral
Temperature (1C)
Initial pH
Time (h)
Solubility (mg/L)
Final pH
1 2 3 4 5 6 7 8 9
Clay
100 200 300 100 200 300 100 200 300
8.0 8.0 8.0 10.0 10.0 10.0 13.0 13.0 13.0
48 48 48 48 48 48 48 48 48
1273 2574 3466 1371 2353 3302 2019 3217 5387
6.5 7.5 7.2 7.5 8.0 7.5 12.0 12.0 10.0
10 11 12 13 14 15 16 17 18
Rock
100 200 300 100 200 300 100 200 300
8.0 8.0 8.0 10.0 10.0 10.0 13.0 13.0 13.0
48 48 48 48 48 48 48 48 48
819 1266 886 920 2253 1913 1313 12,614 11,530
7.5 7.5 7.5 9.5 9.5 9.5 12.0 12.0 12.0
wells of steam stimulation. Rock grains were separated through the precipitation method. The reaction oven simulated thermal recovery conditions in oilfield to conduct solubility experiment of rock grains at different temperatures and pH levels. Meanwhile, 1 g of clay minerals through precipitation separation was put into the alkali solution in the oven. A series of experiments were completed to analyze clay mineral solubility at different temperatures and pH levels. The experimental results are listed in Table 4. The results show that the solubility of rock grains sharply increases as the temperature increases at the same pH level. But when pH was over 10, the solubility of rock grains slightly decreases as temperature increases. At the same temperature, the solubility of rock grains greatly increases as pH level of solution increases. The solubility of clay minerals gradually increases as temperature and pH level increase, as shown in Table 4. The final pH presents a decline trend after hydrothermal reaction for both experiments of rock solubility and clay solubility. But the pH level is basically lower in clay experiments than in rock experiments. It shows that a stronger hydrothermal reaction occurs for clay minerals under the conditions of elevated temperature and high pH level. When the temperature is lower than 200 1C, the solubility of rock grains is lower than that of clay minerals at the same pH level. But when the temperature reaches 300 1C, the solubility of rock grains sharply increases and is much higher than clay minerals in strong
Z. Pang, H. Liu / Journal of Petroleum Science and Engineering 106 (2013) 77–84
4. Discussion 4.1. Permeability loss analysis In order to analyze permeability reduction from steam condensate at different temperatures and pH levels, two new definitions, the permeability damage degree and the permeability restoration degree, were introduced in this article. The permeability damage degree could be defined as a percentage of the ratio between the permeability difference, which is the initial permeability and the final permeability of positive injection, and the initial permeability, that is Dk ¼
K i −K p 100% Ki
formation minerals, especially clay minerals, hardly react with formation water. Therefore, the permeability reduction is only subject to particle migration without mineral dissolution and precipitation at lower temperature. However, steam condensate, on the one hand, could cause the amount of solid particles to migrate in porous media; on the other hand, it accelerates the solubility of reservoir minerals and precipitation of tiny new fines to plug pore-throats (Reed, 1980; Amaefule et al., 1984; Schembre and Kovscek, 2004). Irreversible damage is caused in unconsolidated sandstone.
ð1Þ
where Dk is the permeability damage degree, dimensionless; Ki is the initial permeability, μm2; and Kp is the final permeability of positive injection, μm2. The permeability restoration degree could be defined as a percentage of the ratio between the final permeability of reverse injection and the initial permeability, that is Kr Rk ¼ 100% Ki
60
50
Damage degree (%)
caustic solution. These results agree with the findings of McCorriston et al. (1981).
40
30
20
Alkali solution
10
Brine solution 0
ð2Þ
0
50
100
150
200
250
Temperature (°C)
where Rk is the permeability restoration degree, dimensionless; and Kr is the final permeability of reverse injection, μm2. The values of permeability under different conditions are listed in Table 5. The results show that the final permeabilities of positive injection are much less than the initial permeabilities in all the experiments. The final permeabilities of reverse injection present as an increasing trend compared with the final permeabilities of positive injection, but they could not be restored to the initial values. The permeability damage degree is much higher in alkali solution than brine solution, as shown in Fig. 7. When temperature is over 150 1C, the results show that the permeability damage degree gradually increases for both brine solution and alkali solution, but the damage degree sharply increases for alkali solution. The permeability is reduced to 35.26% at 50 1C but to 43.52% at 200 1C when the alkali solution is injected into the sandpack. The results show that formation damage greatly increases at elevated temperature and high pH level. Fig. 8 presents that the permeability restoration degree gradually decreases as temperature increases and the restoration degree is lower in alkali solution than in brine solution. The permeability restoration is only 66.32% at 200 1C when the alkali solution is injected into the sand-pack. The results show that the permeability was damaged irreversibly during hot condensate injection. At reservoir temperature,
Fig. 7. Permeability damage degree vs. experimental temperature.
100
90
Restoration degree (%)
82
80
70
60
Brine solution Alkali solution
50 0
50
100
150
200
250
Temperature (°C) Fig. 8. Permeability restoration degree vs. experimental temperature.
Table 5 Permeability loss in brine solution and alkali solution at different temperatures. Parameters
Temperature 50 (1C)
Initial permeability ( 10−3 μm2) Final permeability of positive injection ( 10−3 μm2) Final permeability of reverse injection ( 10−3 μm2)
100
150
200
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
2200.2 1880.1
2205.4 1427.7
2120.5 1713.2
2101.7 1343.8
2064.7 1590.4
2047.3 1275.3
2036.8 1534.6
2074.9 1171.8
2050.5
1724.6
1869.4
1585.9
1768.9
1468.2
1696.5
1676.0
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83
Fig. 9. Scanning electron micrographs of new minerals.
4.2. Particle migration mechanisms Generally, saturation steam could effectively enhance heavy oil recovery, but steam condensate could cause a certain degree of formation damage resulting from some characteristics, such as elevated temperature, high flow rate, low salinity and high caustic concentration. Solid particles are driven by steam and its condensate to migrate in unconsolidated porous media. The particles could plug narrow throats to decrease permeability in porous media. When solid particles migrate in porous media, larger diameter particles directly plug pore-throats to decrease permeability. The particles gradually attach to the surface of pores to decrease pore size, that is, flow resistance of liquid phase increases in porous media (Civan, 2000). Steam condensate, namely, hot alkali solution could cause a series of formation damages, such as rock dissolution, clay expansion, new mineral generation, and tiny fine precipitation. All the damages could seriously decrease the permeability of porous media. Mineral dissolution provides an amount of mobile particles under the elevated temperature and strong caustic conditions. The hydrothermal reactions between formation minerals and steam condensate gradually strengthen as temperature and alkali concentration increase, as shown in the former experiments. The dissolution of rock grains not only decreases particle size, but also sharply increases the quantity of tiny particles. On the one hand, the permeability reduction is caused by clay expansion, clay dispersion, particle migration and blockage; on the other hand, the dissolved minerals begin to precipitate and gather when steam condensate, which contains an amount of mineral components, reaches a colder zone in reservoirs. The hydrothermal reactions could cause the dissolution of dolomite and kaolinite and the generation of new minerals, such as cubicite, calcspar, montmorillonite, chlorite and etc., as shown in Fig. 9. The new minerals cover the surface of pores or plugged the throats of porous media to sharply decrease permeability (Reed, 1980; Amaefule et al., 1984; Bennion and Thomas, 1992; Hajdo and Clayton, 1994; Fan et al., 2002).
5. Conclusions In unconsolidated porous media, permeability reduction gradually increased as temperature increased during steam injection, especially when it was over 150 1C. At the same temperature, permeability damage sharply increased as pH level increased. The permeability was reduced to 43.52% and the restoration degree was only 66.32% at 200 1C when the alkali solution was injected into unconsolidated porous media. During steam injection, amount of solid particles followed with steam and its condensate at elevated temperature and high flow rate in heavy oil reservoirs. The mobile solid particles plugged the narrow throats or precipitated on the surface of pores to cause
permeability reduction. Meanwhile, a series of hydrothermal reactions occurred under the elevated temperature and strong alkali conditions. Steam condensate not only caused clay expansion, but also accelerated the dissolution and generation of minerals, which could provide amount of mobile particles resulting in extremely serious formation damage.
Acknowledgments The study was supported by the National Natural Science Foundation of China (51104165), the Research Fund for the Doctoral Program of Higher Education (20110007120003) and the Science Foundation of China University of Petroleum, Beijing (KYJJ2012-02-19). References Amaefule, J.O., Padilla, P.C., McCaffery, F.G., Teal, S.L., 1984. Steam condensate: formation damage and chemical treatments for injectivity improvement. In: Proceedings of the SPE 12499, February 13–14. Bakersfield, CA, pp. 245–256. Archer, J.S., Hurst, A., 1987. Evaluation of formation damage in heterogeneous reservoirs. Mar. Pet. Geol. 4, 119–126. Bagci, S., Kok, M.V., Turksoy, U., 2000. Determination of formation damage in limestone reservoirs and its effect on production. J. Pet. Sci. Eng. 28, 1–12. Bennion,D.B., Thomas, F.B., 1992. Formation damage due to mineral alteration and wettability changes during hot water and steam injection in clay-bearing sandstone reservoir. In: Proceedings of the SPE 23783, February 26–27. Lafayette, LA, pp. 165–177. Bouddour, A., Auriault, J.L., Mhamdi-alaoui, M., 1996. Erosion and deposition of solid particles in porous media: homogenization analysis of a formation damage. Transp. Porous Media 25, 121–146. Chang, F.F., Civan, F., 1997. Practical model for chemically induced formation damage. J. Pet. Sci. Eng. 17, 123–137. Civan, F., 2000. Reservoir Formation Damage: Fundamentals, Modeling, Assessment, and Mitigation, first ed. Gulf Publishing Company, Houston. Diabira, I., Castanier, L.M., Kovscek, A.R., 2001. Porosity and permeability evolution accompanying hot fluid injection into diatomite. Pet. Sci. Technol. 19, 1167–1185. Fan, H.F., Liu, Y.J., Zhang, L.Y., Zhao, X.F., 2002. The study on composition changes of heavy oils during steam stimulation processes. Fuel 81, 1733–1738. Farouq, A.S.M., 2003. Heavy oil—evermore mobile. J. Pet. Sci. Eng. 37, 5–9. Faure, M., Sardin, M., Vitorge, P., 1997. Release of clay particles from an unconsolidated clay–sand core: experiments and modelling. J. Contam. Hydrol. 26, 169–178. Frances, J.H., 2006. Heavy oil and oil (tar) sands in North America: an overview & summary of contributions. Nat. Resour. Res. 15, 67–84. Geilikman, M.B., Dusseault, M.B., 1997. Fluid rate enhancement from massive sand production in heavy-oil reservoirs. J. Pet. Sci. Eng. 17, 5–18. Gruesbeck, C., Collins, R.E., 1982. Entrainment and deposition of fine particles in porous media. Soc. Pet. Eng. J. 22, 847–856. Hajdo, L.E., Clayton, C.A., 1994. Formation damage of an unconsolidated reservoir during steamflooding. In: Proceedings of the SPE 27385, February 7–10. Lafayette, LA, pp. 413–427. Lefebvre, R., Hutcheon, I., 1986. Mineral reactions in quartzose rocks during thermal recovery of heavy oil, Lloydminster, Saskatchewan, Canada. Appl. Geochem. 1, 395–405. Leonataritis, K.J., Mansoori, G.A., 1988. Asphaltene deposition: a survey of field experiences and research approaches. J. Pet. Sci. Eng. 1, 229–239. McCorriston, L.L., Demby, R.A., Pease, E.C., 1981. Study of reservoir damage production in heavy oil formation due to steam injection. In: Proceedings of the SPE 10077, October 5–7. San Antonio, TX, pp. 1–11.
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Moghadasi, J., Muller-Steinhagen, H., Jamialahmadi, M., Sharif, A., 2004. Theoretical and experimental study of particle movement and deposition in porous media during water injection. J. Pet. Sci. Eng. 43, 163–181. Mohan, K.K., Reed, M.G., Fogler, H.S., 1999. Formation damage in smectitic sandstones by high ionic strength brines. Colloids Surf. A 154, 249–257. Mohnot, S.M., Bae, J.H., Foley, W.L., 1987. A study of mineral/alkali reactions. Soc. Pet. Eng. J. 2, 653–663. Niu, J.Y., Hu, J.Y., 1999. Formation and distribution of heavy oil and tar sands in China. Mar. Pet. Geol. 16, 85–95. Okoye, C.V., Onuba, N.L., Ghalambor, A., Hayatdavoudi, A., 1991. Formation damage in heavy oil formation during steamflooding. In: Proceedings of the SPE 22980, November 4–7. Perth, Australia, pp. 309–322. Pahlavan, H., Rafiqul, I., 1985. Laboratory simulation of geochemical changes of heavy crude oils during thermal oil recovery. J. Pet. Sci. Eng. 12, 219–231.
Pathak, V., Tayfun, B., Edmunds, N.R., 2011. Heavy oil and bitumen recovery by hot solvent injection. J. Pet. Sci. Eng. 78, 637–645. Reed, M.G., 1980. Gravel pack and formation sandstone dissolution during steam injection. J. Pet. Technol. 32, 941–948. Renato, G., 2011. Worldwide cheap and heavy oil productions: along-term energy model. Energy Policy 39, 5572–5577. Rosario, F., Louvisse, A.M.T., Saraiva, S.M., Gonzalez, G., Oliveira, J.F., 1996. A model system to study the precipitation and migration of colloidal particles in porous media. J. Colloid Interface Sci. 181, 1–10. Schembre, J.M., Kovscek, A.R., 2004. Thermally induced fines mobilization: its relationship to wettability and formation damage. In: Proceedings of the SPE 86937, March 16–18. Bakersfield, CA, pp. 1–16. Tayfun, B., 2003. Evaluation of EOR methods for heavy-oil recovery in naturally fractured reservoirs. J. Pet. Sci. Eng. 37, 25–37.
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Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
The study on permeability reduction during steam injection in unconsolidated porous media Zhanxi Pang a,b,n, Huiqing Liu a,b a b
Faculty of Petroleum Engineering, China University of Petroleum, Fuxue Road No. 18, Changping District, Beijing 102249, China MOE Key Laboratory of Petroleum Engineering, China University of Petroleum, Beijing 102249, China
art ic l e i nf o
a b s t r a c t
Article history: Received 28 September 2012 Accepted 26 April 2013 Available online 14 May 2013
The effluents from steam generators usually have low salinity and high pH level during steam injection. Steam and its condensate can cause particle migration and hydrothermal reactions. Those largely decrease production potential of heavy oil resulting from permeability reduction. The flow experiments were conducted in sand-pack filled with unconsolidated sands. This paper presented the experimental results to evaluate the influence of pH level and temperature on permeability reduction. Meanwhile, a series of hydrothermal reactions were conducted to analyze solubility of solid particles in steam condensate. The experimental results showed that steam condensate irreversibly reduced the permeability up to 43.52%, but the permeability was only restored to 66.32%. Sandstone interaction with high pH condensate leads to a serious dissolution of formation minerals and subsequent precipitation of new minerals. Particle migration and hydrothermal reaction constitute the primary damage mechanisms when steam and condensate of low salinity and high temperature are injected into unconsolidated porous media. & 2013 Elsevier B.V. All rights reserved.
Keywords: permeability reduction steam particle migration hydrothermal reaction experiment
1. Introduction Heavy oil is a kind of important petroleum resource that plays an increasingly great role in daily life and industry production (Niu and Hu, 1999; Farouq, 2003; Frances, 2006). Heavy oil resources are total 10 trillion barrels, nearly three times the conventional oil in the world (Renato, 2011). Thermal recovery methods, especially steam stimulation and steam flooding, are proven as the most effective enhanced oil recovery technologies (Tayfun, 2003; Pathak et al., 2011).
expansion, mineral generation, particle migration and scale precipitation, asphalt deposition and wettability reversion (Pahlavan and Rafiqul, 1985; Leonataritis and Mansoori, 1988; Faure et al., 1997; Fan et al., 2002; Schembre and Kovscek, 2004). Particle migration, scale precipitation and fine plugging cause serious sand production to accelerate formation damages (Hajdo and Clayton, 1994; Mohan et al., 1999). Dissolution and generation of formation minerals promote the degree of formation damage during steam injection in heavy oil reservoirs. 1.2. Particle migration and hydrothermal reaction
1.1. Formation damage of steam injection Steam and condensate cause chemical reactions which could decrease production potential by reducing permeability and porosity (Bagci et al., 2000; Diabira et al., 2001). McCorriston et al. (1981) observed that alkaline effluents from steam generator irreversibly reduced the permeability of cores by up to 70% in their experiments. Okoye et al. (1991) conducted many experiments of steam temperatures and pH levels influencing formation damage in heavy oil reservoirs. During steam injection, the primary mechanisms on formation damages include clay n Corresponding author at: Faculty of Petroleum Engineering, China University of Petroleum, Fuxue Road No. 18, Changping District, Beijing 102249, China. Tel.: +86 18201281464. E-mail address: [email protected] (Z. Pang).
0920-4105/$ - see front matter & 2013 Elsevier B.V. All rights reserved. http://dx.doi.org/10.1016/j.petrol.2013.04.022
Petroleum productivity decline is often caused by particle migration and formation plugging (Bagci et al., 2000; Schembre and Kovscek, 2004). Almost all formations contain significant amount of clay minerals. Meanwhile, most of the heavy oil reservoirs belong to unconsolidated formations. Thermal recovery operations in these formations often lead to particle mobilization due to chemical reaction between reservoir minerals and injected fluids (McCorriston et al., 1981; Okoye et al., 1991; Hajdo and Clayton, 1994; Schembre and Kovscek, 2004). Particle migration and resultant plugging of pore-throats is one of the primary reasons for the reduction in permeability during steam injection. Permeability damage due to particle migration could be caused by mechanical or chemical effects (Rosario et al., 1996). Mechanical effects are controlled by many factors, such as flow rate, viscosity, particle size and pore size (Moghadasi et al., 2004). Chemical
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effects are observed when a chemically incompatible fluid is introduced into reservoirs, which could cause clay minerals to disperse and to migrate (McCorriston et al., 1981; Okoye et al., 1991). During steam injection, large volumes of saturation steam are injected into heavy oil reservoirs at high pressure and elevated temperature. A new chemical equilibrium between minerals and formation fluids is reached to be reflected by mineral dissolution, variation of water chemistry, generation of new minerals, scale precipitation and particle migrations, that is, hydrothermal reactions (Gruesbeck and Collins, 1982; Bouddour et al., 1996; Chang and Civan, 1997; Faure et al., 1997). Reed (1980) in an earlier experiment noted sandstone dissolution during steam injection. Okoye et al. (1991) reported that quartz and other siliceous minerals were hardly dissolved at room temperature, but the solubility sharply increased at elevated temperature. Some studies found the fact that injection of lower salinity water than formation water could cause dispersion, expansion and transformation of clay minerals (Gruesbeck and Collins, 1982; Bennion and Thomas, 1992; Hajdo and Clayton, 1994; Schembre and Kovscek, 2004). Mohnot et al. (1987) observed that alkaline solution could cause clay migration and expansion resulting in permeability reduction. Effluent with high pH level and low salinity content from steam generator could cause many formation damages to decrease productivity by reducing permeability (Amaefule et al., 1984; Lefebvre and Hutcheon, 1986; Okoye et al., 1991; Geilikman and Dusseault, 1997; Schembre and Kovscek, 2004). 1.3. Purpose of this study During thermal recovery, saturation steam and its condensate are injected into heavy oil reservoirs. Steam condensate from steam generator often has high pH level above 12 and low salinity content. The hydrothermal reactions between injected fluids and formation minerals can promote permeability reduction during steam injection. In this article, a series of flow experiments were employed to investigate particle migration and permeability reduction during steam condensate flowing in unconsolidated porous media. Meanwhile, some experiments of hydrothermal reactions were conducted to analyze migration mechanisms of solid particles during steam injection in unconsolidated porous media.
Table 1 Component analysis of formation minerals in Lian II of Qi 40. Rock
Clay
Component
Percent (%)
Component
Percent (%)
Quartz Feldspar Calcite Dolomite Rock debris Total amount
33.5 32.0 0.0 0.0 23.7 89.2
Smectite Kaolinite Illite Chlorite Mixed layer clays Total amount
7.0 2.0 1.8 0.0 0.0 10.8
2.2. Experimental apparatus A schematic of experimental apparatus used in flow experiments is shown in Fig. 1. The apparatus included one constant temperature oven, one sand-pack, one injection pump and other affiliated devices. The oven was used to control experimental temperature from 50 1C to 200 1C. The sand-pack was 30 cm long and 3.8 cm in inner diameter. Three pressure taps and three temperature taps were symmetrically welded on the surface of the sand-pack. The sand-pack was filled with unconsolidated rock grains and clay minerals to establish different permeability. A water tank was filled with brine solution on behalf of formation water. An alkali solution tank was filled with NaOH solution of 0.4% by weight (pH ¼ 13) on behalf of steam condensate. A network of pipelines and valves was used to inject brine solution or alkali solution into the sand-pack. The data of temperature and pressure were transmitted to a computer by temperature sensors and pressure sensors. Kerosene was injected into a brine solution tank or alkali solution tank in order to drive the experimental liquids into the sand-pack by the injection pump. In order to prevent the caustic fluid from entering into the pressure sensors, three small buffer containers were equipped between pressure taps and pressure sensors. The containers were small hollow tanks containing distilled water. At the outlet of sand-pack, a backpressure valve was utilized to control the outlet pressure.
2.3. Experimental procedures 2. Flow experiment 2.1. Mineral and fluid samples The rock samples were obtained from Lian II Layer of Qi 40 in Liaohe Oilfield, China. The rock minerals are mainly composed of quartz and feldspars. The average content of quartz is 33.5%. The average content of feldspars is 32%. The average content of clay minerals is 6.75%. The clay minerals are mainly composed of smectite, kaolinite and illite. The content of mineral components is listed in Table 1. Water samples were used in experiments from Lian II Layer of Qi 40 in Liaohe Oilfield. Formation water contains high concentration bicarbonate. It is different from the effluents from steam generator. Steam condensate is a strong caustic solution. The analysis of water sample is listed in Table 2. The salinity of formation water is about 2000–8000 mg/L. The cations mainly are K+ and Na+, but the contents of Ca2+ and Mg2+ are lower in formation water. Cl− and HCO−3 are the primary anions but 2− SO2− 4 and CO3 are relatively poorer. In our experiments, steam condensate was replaced by alkali solution. The concentration of alkali solution was 0.4% by weight (pH is about equal to 13).
A new experimental method, the positive and reverse injection, was employed to analyze particle migration and permeability reduction in unconsolidated porous media (Archer and Hurst, 1987). Firstly, a certain fluid was injected into porous media until it reached a steady state to measure absolute permeability. That was called the positive injection. Then the same fluid was injected into the porous media from the other end until a steady state to measure the permeability again. That was called the reverse injection. The positive injection often causes the reduction of permeability resulting from particle migration in porous media. If the permeability gradually increases or first increases and then decreases during the reverse injection, then it shows that solid particles begin to migrate in porous media. If the permeability remains constant or continues to reduce during the reverse injection, then it shows that the reduction of permeability is not just from particle migration in porous media. In order to research the influence of temperature and pH level on permeability, two kinds of flow experiments were conducted. The brine solution or the alkali solution was injected into the sand-pack in the experiments. The parameters of sand-pack are listed in Table 3.
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Table 2 Component analysis of water sample of Qi 40. Steam generator
Water sample
Na++K+ (mg/L)
Ca2+ (mg/L)
Cl− (mg/L)
SO42− (mg/L)
HCO3− (mg/L)
CO32− (mg/L)
OH− (mg/L)
Salinity (mg/L)
pH
Qi 40-3
Feed Condensate
199.6 786.6
7.3 9.7
0.0 0.0
70.9 301.3
48.0 67.2
319.1 0.0
63.0 690.6
0.0 231.2
707.9 2086.6
7.1 11.5
Qi 40-4
Feed Condensate
195.3 722.2
4.9 6.1
0.0 0.0
62.0 381.1
28.8 57.6
399.1 0.0
0.0 240.0
0.0 271.2
690.1 1678.2
7.1 12.0
Qi 40-5
Feed Condensate
190.2 759.9
12.2 17.0
0.0 4.0
70.9 390.0
48.0 105.7
350.9 0.0
31.2 753.0
0.0 151.1
703.4 2180.7
7.2 11.6
Mg2+ (mg/L)
Brine solution tank
Valve Injection Pump
Sand-pack Buffer container
Pressure gauge Alkali solution tank
Kerosene
Data acquisition m system
Computer
Backpressure valve
Temperature sensor
Constant temperature oven
Liquid cylinder
Pressure transducer
Fig. 1. Schematic diagram of displacement experiment.
Table 3 Parameters of sand-pack in flow experiments. Parameter
Temperature 50 (1C)
Diameter (cm) Length (cm) Permeability ( 10−3 μm2) Porosity (%) Pore volume (cm3)
100
150
200
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
3.8 30.0 2200.2 32.5 110.6
3.8 30.0 2205.4 31.4 106.8
3.8 30.0 2120.5 30.8 104.8
3.8 30.0 2101.7 31.1 105.8
3.8 30.0 2064.7 30.6 104.1
3.8 30.0 2047.3 29.8 101.4
3.8 30.0 2036.8 33.4 113.6
3.8 30.0 2074.9 31.3 106.5
2.3.1. Flow experiments of brine solution Firstly, the sand-pack was saturated with brine solution. Then the sand-pack and corresponding pipelines were equipped in the experimental system. Experimental temperatures were controlled at 50 1C, 100 1C, 150 1C and 200 1C. Until the whole system got to be isothermal, the brine solution was injected into the sand-pack at the corresponding temperature. After injecting about 10 PV of brine solution, the flow direction was reversed and the additional 10 PV of brine solution was injected into the sand-pack. During solution injection, flow rate and pressure difference were recorded by the computer with an interval of 1 min. Then the permeability could be calculated according to the flow rate, pressure difference and other parameters of sand-pack.
2.3.2. Flow experiments of alkali solution De-ionized formation water is utilized to produce high temperature steam during thermal recovery in oilfield. A part of steam is condensed into hot water, that is, condensate resulting from heat loss in formation. The pH of condensate is up to over 12 in oilfield. In our experiments, firstly, the sand-pack was saturated with brine solution. Then it was equipped in the experimental system. The temperature of the oven was controlled at 50 1C, 100 1C, 150 1C and 200 1C. When it got to the given temperature, NaOH solution was injected into the sand-pack at the given temperature. The concentration of solution was 0.4% by weight, corresponding to a pH of 13. About 10 PV of alkali solution was injected into the sand-pack in the positive direction. Then an
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additional 10 PV of solution was injected into the sand-pack in the reverse direction, that is, the outlet of the sand-pack. During experiments flow rate and pressure difference were recorded by the computer with an interval of 1 min. Then the permeability could be calculated. The procedures followed to conduct the flow experiments are as follows: (1) the sand-pack filled with mineral samples was firstly equipped in the experimental system. Then the sand-pack and the pipelines were vacuumized by a vacuum pump for 4 h. (2) The brine solution was injected into the sand-pack until it was fully saturated to measure pore volume and porosity. Several pore volumes of brine solution were continuously injected into the sand-pack to measure the absolute permeability. (3) The oven and the liquid tank were controlled to an experimental temperature, such as 50 1C, 100 1C, 150 1C and 200 1C, for over 2 h. (4) A backpressure of about 0.5 MPa higher than steam saturation pressure was applied to maintain liquid phase state for injected fluids. Then brine solution or alkali solution was injected into the sand-pack by the pump until 10 PV. (5) The injection direction was reversed and an additional 10 PV of brine solution or alkali solution was injected into the opposite end of the sand-pack. (6) A new sand-pack was replaced in the experimental system to conduct another experiment as the former procedures (1)–(5).
3. Experimental results 3.1. Flow experiment The permeability trend curves of injecting brine solution and alkali solution at 50 1C are shown in Fig. 2. It is shown that the permeability gradually decreases as injection volume of the brine solution increases for the positive injection. The permeability decreases to 1.88 μm2 from 2.2 μm2 after injecting 10 PV of brine solution into the sand-pack. But the results of the reverse injection experiments show that the permeability gradually increases as injection volume of brine solution increases at 50 1C. It presents that the permeability only has a very small loss in reverse injection. The results tell us that permeability variation was only subject to particle migration during injection of brine solution at 50 1C. However, when the alkali solution is injected into the sandpack, the permeability decreases sharply as injection volume increases for the positive injection. After injecting 10 PV of alkali solution of 0.4% by weight, the permeability decreases from 2.21 μm2 to 1.43 μm2. In the processes of reverse injection, the permeability could not be restored to the initial level. At the end of reverse injection, the final permeability could only be restored to
1.69 μm2. Therefore, formation damage results from not only particle migration in porous media but also some chemical reactions between minerals and alkali solution. The permeability trend curves of injecting brine solution and alkali solution at 100 1C are shown in Fig. 3. The results show that the permeability gradually decreases with injection of brine solution for the positive injection. The permeability decreases from 2.12 μm2 to 1.71 μm2 after injecting 10 PV of brine solution. The final permeability is slightly lower at 100 1C than 50 1C at the end of positive injection. The results of reverse injection show that the permeability gradually increases from 1.71 μm2 to 1.87 μm2 as injection volume of brine solution increases at 100 1C. The final permeability of reverse flow could not return to the initial level. It shows that the chemical reactions between minerals and steam condensate decrease permeability except for particle migration during brine solution injection at 100 1C. When the alkali solution is injected into the sand-pack, the permeability decreases sharply as injection volume increases for the positive injection. After injecting 10 PV of alkali solution (0.4% by weight), the permeability decreases from 2.10 μm2 to 1.34 μm2. At the end of the reverse injection, the final permeability could not be restored to the initial level, and it is only restored to 1.59 μm2. Therefore, the alkali solution could cause two effects, such as particle migration and hydrothermal reaction in unconsolidated porous media. It was presented that the permeability greatly decreases with injection of brine solution for the positive injection at 150 1C, as shown in Fig. 4. The permeability decreases from 2.06 μm2 to 1.275 μm2 at the end of positive injection for the brine solution. The decline degree of permeability is larger at 150 1C than 50 1C and 100 1C at the end of positive injection. The results show that the permeability is finally restored to 1.87 μm2 at the end of reverse injection at 150 1C. The permeability could not return to the initial level. When the alkali solution is injected into the sandpack, the permeability decreases sharply as injection volume increases for positive injection. After injecting 10 PV of alkali solution (0.4% by weight), the permeability decreases from 2.05 μm2 to 1.11 μm2. At the end of reverse injection, the final permeability could not be restored to the initial level. It is only restored to 1.36 μm2. The permeability trend curves of injecting brine solution and alkali solution at 200 1C are shown in Fig. 5. The results show that the permeability gradually decreases with injection of brine solution for the positive injection. The permeability decreases from 2.04 μm2 to 1.53 μm2 after injecting 10 PV of brine solution. The results show that the permeability gradually increases from 1.53 μm2 to 1.70 μm2 during injection of brine solution at 200 1C in
2200
2400
2000
Permeability (×10-3μm2)
Permeability (×10-3μm2)
2200 2000
1800
1600 1400 Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
1200
1800
1600
1400 Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
1200
1000
1000 0
2
4
6
8
10
12
14
16
18
PV Fig. 2. Permeability trend of different fluid injections at 50 1C.
20
0
2
4
6
8
10
12
14
16
18
PV Fig. 3. Permeability trend of different fluid injections at 100 1C.
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81
2200 Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
Permeability (×10-3μm2)
2000
Pressure gauge P
Valve
High pressure pump
1800
1600
Pump
1400
NaOH solution tank
1200 Condensator
Kerosine tank
Water tank
Reaction oven
1000 0
2
4
6
8
10
12
14
16
18
20
Fig. 6. The schematic diagram of solubility experiment.
PV
Fig. 4. Permeability trend of different fluid injections at 150 1C. Table 4 Solubility of clay minerals and rock grains at different temperatures and pH levels. 2200
No. Positive injection of brine solution Reverse injection of brine solution Positive injection of caustic solution Reverse injection of caustic solution
Permeability (×10-3μm2)
2000
1800
1600
1400
1200
1000 0
2
4
6
8
10
12
14
16
18
20
PV Fig. 5. Permeability trend of different fluid injections at 200 1C.
the reverse injection. The permeability of reverse injection could not return to the initial level. The results show that minerals could react with steam condensate except for particle migration to decrease permeability during the brine solution injection at elevated temperature. When the alkali solution is injected into the sand-pack, the permeability decreases sharply as injection volume increases for the positive injection. After injecting 10 PV of alkali solution (0.4% by weight), the permeability decreases from 2.07 μm2 to 1.17 μm2. At the end of reverse injection, the permeability could not be restored to the initial level, and it is only restored to 1.535 μm2. 3.2. Hydrothermal reaction Hydrothermal reaction results from the chemical reaction between steam condensate and formation minerals in heavy oil reservoirs during steam injection. The reaction could cause dissolution of formation minerals and precipitation of new minerals, such as CaCO3, zeolites and etc., to result in formation damage. Based on the former flow experiments, a reaction oven was employed to research the solubility of rock grains and clay minerals at different temperatures and pH levels, as shown in Fig. 6. Finally, the mechanisms of migration and retention were analyzed for solid particles in unconsolidated porous media at elevated temperature and high pH level. The mineral samples were chosen from Lian II Layer of Qi 40 in Liaohe Oilfield. The samples were naturally unconsolidated sands from the production
Mineral
Temperature (1C)
Initial pH
Time (h)
Solubility (mg/L)
Final pH
1 2 3 4 5 6 7 8 9
Clay
100 200 300 100 200 300 100 200 300
8.0 8.0 8.0 10.0 10.0 10.0 13.0 13.0 13.0
48 48 48 48 48 48 48 48 48
1273 2574 3466 1371 2353 3302 2019 3217 5387
6.5 7.5 7.2 7.5 8.0 7.5 12.0 12.0 10.0
10 11 12 13 14 15 16 17 18
Rock
100 200 300 100 200 300 100 200 300
8.0 8.0 8.0 10.0 10.0 10.0 13.0 13.0 13.0
48 48 48 48 48 48 48 48 48
819 1266 886 920 2253 1913 1313 12,614 11,530
7.5 7.5 7.5 9.5 9.5 9.5 12.0 12.0 12.0
wells of steam stimulation. Rock grains were separated through the precipitation method. The reaction oven simulated thermal recovery conditions in oilfield to conduct solubility experiment of rock grains at different temperatures and pH levels. Meanwhile, 1 g of clay minerals through precipitation separation was put into the alkali solution in the oven. A series of experiments were completed to analyze clay mineral solubility at different temperatures and pH levels. The experimental results are listed in Table 4. The results show that the solubility of rock grains sharply increases as the temperature increases at the same pH level. But when pH was over 10, the solubility of rock grains slightly decreases as temperature increases. At the same temperature, the solubility of rock grains greatly increases as pH level of solution increases. The solubility of clay minerals gradually increases as temperature and pH level increase, as shown in Table 4. The final pH presents a decline trend after hydrothermal reaction for both experiments of rock solubility and clay solubility. But the pH level is basically lower in clay experiments than in rock experiments. It shows that a stronger hydrothermal reaction occurs for clay minerals under the conditions of elevated temperature and high pH level. When the temperature is lower than 200 1C, the solubility of rock grains is lower than that of clay minerals at the same pH level. But when the temperature reaches 300 1C, the solubility of rock grains sharply increases and is much higher than clay minerals in strong
Z. Pang, H. Liu / Journal of Petroleum Science and Engineering 106 (2013) 77–84
4. Discussion 4.1. Permeability loss analysis In order to analyze permeability reduction from steam condensate at different temperatures and pH levels, two new definitions, the permeability damage degree and the permeability restoration degree, were introduced in this article. The permeability damage degree could be defined as a percentage of the ratio between the permeability difference, which is the initial permeability and the final permeability of positive injection, and the initial permeability, that is Dk ¼
K i −K p 100% Ki
formation minerals, especially clay minerals, hardly react with formation water. Therefore, the permeability reduction is only subject to particle migration without mineral dissolution and precipitation at lower temperature. However, steam condensate, on the one hand, could cause the amount of solid particles to migrate in porous media; on the other hand, it accelerates the solubility of reservoir minerals and precipitation of tiny new fines to plug pore-throats (Reed, 1980; Amaefule et al., 1984; Schembre and Kovscek, 2004). Irreversible damage is caused in unconsolidated sandstone.
ð1Þ
where Dk is the permeability damage degree, dimensionless; Ki is the initial permeability, μm2; and Kp is the final permeability of positive injection, μm2. The permeability restoration degree could be defined as a percentage of the ratio between the final permeability of reverse injection and the initial permeability, that is Kr Rk ¼ 100% Ki
60
50
Damage degree (%)
caustic solution. These results agree with the findings of McCorriston et al. (1981).
40
30
20
Alkali solution
10
Brine solution 0
ð2Þ
0
50
100
150
200
250
Temperature (°C)
where Rk is the permeability restoration degree, dimensionless; and Kr is the final permeability of reverse injection, μm2. The values of permeability under different conditions are listed in Table 5. The results show that the final permeabilities of positive injection are much less than the initial permeabilities in all the experiments. The final permeabilities of reverse injection present as an increasing trend compared with the final permeabilities of positive injection, but they could not be restored to the initial values. The permeability damage degree is much higher in alkali solution than brine solution, as shown in Fig. 7. When temperature is over 150 1C, the results show that the permeability damage degree gradually increases for both brine solution and alkali solution, but the damage degree sharply increases for alkali solution. The permeability is reduced to 35.26% at 50 1C but to 43.52% at 200 1C when the alkali solution is injected into the sandpack. The results show that formation damage greatly increases at elevated temperature and high pH level. Fig. 8 presents that the permeability restoration degree gradually decreases as temperature increases and the restoration degree is lower in alkali solution than in brine solution. The permeability restoration is only 66.32% at 200 1C when the alkali solution is injected into the sand-pack. The results show that the permeability was damaged irreversibly during hot condensate injection. At reservoir temperature,
Fig. 7. Permeability damage degree vs. experimental temperature.
100
90
Restoration degree (%)
82
80
70
60
Brine solution Alkali solution
50 0
50
100
150
200
250
Temperature (°C) Fig. 8. Permeability restoration degree vs. experimental temperature.
Table 5 Permeability loss in brine solution and alkali solution at different temperatures. Parameters
Temperature 50 (1C)
Initial permeability ( 10−3 μm2) Final permeability of positive injection ( 10−3 μm2) Final permeability of reverse injection ( 10−3 μm2)
100
150
200
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
Brine solution
Alkali solution
2200.2 1880.1
2205.4 1427.7
2120.5 1713.2
2101.7 1343.8
2064.7 1590.4
2047.3 1275.3
2036.8 1534.6
2074.9 1171.8
2050.5
1724.6
1869.4
1585.9
1768.9
1468.2
1696.5
1676.0
Z. Pang, H. Liu / Journal of Petroleum Science and Engineering 106 (2013) 77–84
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Fig. 9. Scanning electron micrographs of new minerals.
4.2. Particle migration mechanisms Generally, saturation steam could effectively enhance heavy oil recovery, but steam condensate could cause a certain degree of formation damage resulting from some characteristics, such as elevated temperature, high flow rate, low salinity and high caustic concentration. Solid particles are driven by steam and its condensate to migrate in unconsolidated porous media. The particles could plug narrow throats to decrease permeability in porous media. When solid particles migrate in porous media, larger diameter particles directly plug pore-throats to decrease permeability. The particles gradually attach to the surface of pores to decrease pore size, that is, flow resistance of liquid phase increases in porous media (Civan, 2000). Steam condensate, namely, hot alkali solution could cause a series of formation damages, such as rock dissolution, clay expansion, new mineral generation, and tiny fine precipitation. All the damages could seriously decrease the permeability of porous media. Mineral dissolution provides an amount of mobile particles under the elevated temperature and strong caustic conditions. The hydrothermal reactions between formation minerals and steam condensate gradually strengthen as temperature and alkali concentration increase, as shown in the former experiments. The dissolution of rock grains not only decreases particle size, but also sharply increases the quantity of tiny particles. On the one hand, the permeability reduction is caused by clay expansion, clay dispersion, particle migration and blockage; on the other hand, the dissolved minerals begin to precipitate and gather when steam condensate, which contains an amount of mineral components, reaches a colder zone in reservoirs. The hydrothermal reactions could cause the dissolution of dolomite and kaolinite and the generation of new minerals, such as cubicite, calcspar, montmorillonite, chlorite and etc., as shown in Fig. 9. The new minerals cover the surface of pores or plugged the throats of porous media to sharply decrease permeability (Reed, 1980; Amaefule et al., 1984; Bennion and Thomas, 1992; Hajdo and Clayton, 1994; Fan et al., 2002).
5. Conclusions In unconsolidated porous media, permeability reduction gradually increased as temperature increased during steam injection, especially when it was over 150 1C. At the same temperature, permeability damage sharply increased as pH level increased. The permeability was reduced to 43.52% and the restoration degree was only 66.32% at 200 1C when the alkali solution was injected into unconsolidated porous media. During steam injection, amount of solid particles followed with steam and its condensate at elevated temperature and high flow rate in heavy oil reservoirs. The mobile solid particles plugged the narrow throats or precipitated on the surface of pores to cause
permeability reduction. Meanwhile, a series of hydrothermal reactions occurred under the elevated temperature and strong alkali conditions. Steam condensate not only caused clay expansion, but also accelerated the dissolution and generation of minerals, which could provide amount of mobile particles resulting in extremely serious formation damage.
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