Oil Displacement Experiment for Enhancing Oil Recovery of Porous Type Carbonate Reservoir

Transcription

1 Oil Displacement Experiment for Enhancing Oil Recovery of Porous Type Carbonate Reservoir Haiyang Su, Changlin Liao Institution: Research Institute of Petroleum Exploration & Development, Petrochina Address: No.20 Xueyuan Road, Haidian District, Beijing, China ABSTRACT Different from many other carbonate reservoirs, the ones in the Middle East area obtain special characteristics with less fractures or caves and thus lower permeability. Considering the inherent disadvantages to the oil field development, experimental studies were performed to enhance oil recovery with injection of associated gas and CO 2 based on the analysis of the reservoir fluid properties. The studies showed that higher oil recovery is possible even under an immiscible flooding condition. This is because the associated gas injected into the oil leads to the oil volume swelling, viscosity deduction and mobility increase which are all favor to a higher oil recovery. Under the reservoir condition of Asab, CO 2 could get miscible with oil under a certain injection pressure at which the associated gas can t. Different oil displacement experiments were carried out, CO 2 -water alternate miscible flooding gave the highest oil recovery while significant improvement was also got by using CO 2 -water alternate miscible flooding after water flooding. However, CO 2 - water alternate miscible flooding after associated gas-water immiscible flooding did not improve much on oil recovery. KEYWORDS: Porous type; Carbonate Reservoir; Gas injection; Immiscible flooding; Miscible flooding; Water Alternate Gas INTRODUCTION In Middle East area, many carbonate reservoirs are porous types, this kind of reservoir has characteristic of few fractures and cave, low permeability [1]. The characteristic is different from that of fracture type and cave type carbonate reservoir [2-4]. Asab reservoir in UAE is of this type

2 Vol. 19 [2014], Bund. Z The lithology of Asab reservoir is bioclast; fracture and cave are not found. The depth of the reservoir is about 2500~2600m. The porosity is 16% and the average permeability is 7.5mD. Initial reservoir pressure is 25.5MPa, 11MPa higher than the saturation pressure. The development method for this kind of porous carbonate reservoir is much different from that of the fracture carbonate reservoir [5-8]. To develop the porous carbonate reservoir efficiently, some experiments on oil displacement method for enhancing oil recovery were taken and the results were discussed in this paper. First, solubility swelling experiment and slim tube experiment were taken to confirm the reservoir fluid s characteristic, and then a group of long core tests were taken to optimize the displacement method. The result could offer some guilds to the gas injection pilot [9-14]. RESERVOIR FLUID S CHARACTERISTICS The injected gases used in the experiments were associated gas and CO 2. In reservoir condition (25.5MPa/121 ), the formation volume factor of associated gas was m 3 /m 3. The compression factor was Oil viscosity was mpa s and oil density was 0.15g/cm 3. With reference to the industry standard SY/T , oil was made up based on the surface oil and solution gas composition, the saturation pressure of the configuration oil was 14MPa. The volume factor was 1.156m 3 /m 3 and oil viscosity was 0.248mPa s (Table 1). Table 1: component of injection gas and configuration oil Components N 2 CO 2 H 2 S C 1 C 2 C 3 i-c 4 n-c 4 i-c 5 n-c 5 C 6 C 7+ Components mole fraction of injection gas/% Components mole fraction of configuration oil/% Solubility Swelling Experiments Solubility swelling test was to evaluate the oil s swelling capacity and the change of oil properties with injected gas. As different amount of gas injected at the bubble point pressure of the system, the fluid properties and the saturation pressure differ. The test was carried out as follows: a portion of the oil sample was introduced to a high pressure visual cell at MPa and thermally expanded to the reservoir temperature 121. Then a measured portion of injection gas was added to the cell and the change in volume and other PVT properties due to the added gas were noted. When gas injection to the pressure of MPa, pressure decays by increase the system volume while the saturation pressure, volume factor and viscosity were determined. This test was repeated for 5 times (associated gas and CO 2 respectively), each time the saturation pressure, volume factor and viscosity were noted [15]. The tests were carried out at 121. The saturation pressure increased with the gas injected (Figure 1). The saturation pressure before gas injection was 14.03MPa. When the mole ratio of injected associated gas and oil was

3 Vol. 19 [2014], Bund. Z , the saturation pressure of the oil increased to 36.43MPa. Correspondingly, when the mole ratio of injected CO 2 and oil was , the saturation pressure increased to 28.28MPa. The saturation pressure increased 2.60 times and 2.02 times respectively. It can be concluded that under reservoir pressure 25.5MPa, oil displacement mechanism of associated gas injection is multi-contact immiscible displacement, while CO 2 injection is near-miscible and miscible displacement. The oil volume swelled with the gas injected (Figure 2). The oil volume factor before gas injection was When the mole ratio of injected associated gas and oil was , the oil volume factor increased to Correspondingly, when the mole ratio of injected CO 2 and oil was , the oil volume factor increased to The volume factor increased 69.9% and 76.2% respectively. The results showed that the oil has a strong swelling ability under the effect of injected gas, and the swelling factor under the effect of injected CO 2 is slightly higher than that under the effect of injected associated gas. The oil viscosity decreased with the gas injected (Figure 3). The oil viscosity before gas injection was 0.248mPa s. When the mole ratio of injected associated gas and oil was , the oil viscosity decreased to 0.134mPa s. Correspondingly, when the mole ratio of injected CO 2 was , the oil volume factor decreased to 0.123mPa s. The oil viscosity decreased 50.4% and 45.9% respectively. The results showed that effect of oil viscosity decreasing with the injected gas is obvious. Figure 1: relationship between saturation pressure and molar fraction of injected gas

4 Vol. 19 [2014], Bund. Z Figure 2: relationship between volume factor and molar fraction of injected gas Figure 3: relationship between oil viscosity and molar fraction of injected gas Minimum Miscible Pressure Experiments 1 Experiment Apparatus and Procedure Slim tube experiment was used to determine the minimum miscible pressure of injected gas (Figure 4) [16]. The experiment was carried out in a sand pack slim tube m long and 4.6mm inner diameter. The displacement pressures of CO 2 injection were 14.82MPa, 15.85MPa, 17.24MPa, 19.31MPa, 24.48MPa and 28.61MPa respectively, the displacement pressures of associated gas injection were 18.58MPa, 24.13MPa, 26.20MPa, 30.84MPa, 34.24MPa, and 37.92MPa respectively.

5 Vol. 19 [2014], Bund. Z Experiment Result At different displacement pressures, the final displacement efficiency distinguished obviously when gas was injected to 1.2PV. The relationship between displacement efficiency and displacement pressure was drawn in Figure 5, the intersection point of the two trend lines which represent immiscible and miscible interval respectively was the minimum miscible pressure point. It can be seen from figure 5 that the minimum miscible pressure with CO 2 injection was 17.94MPa, the minimum miscible pressure with associated gas injection was 30.79MPa, the reservoir pressure is 25.5MPa, so the oil displacement mechanism of CO 2 injection in Asab reservoir is miscible displacement, and that of associated gas injection is immiscible displacement. Figure 4: minimum miscible pressure experiment apparatus Figure 5: relationship between displacement efficiency and displacement pressure of two injected gas

6 Vol. 19 [2014], Bund. Z Oil Displacement Experiments 1 Experimental Apparatus and Procedure Different from tubule experimental apparatus, a one-meter three axes long core gripper was used in long core displacement experiment to replace sand tubule applied in the slim tube experiment. Technical indexes of the gripper were as follows: pressure range was 0 to 60MPa, temperature range was 0 to 200, core length was 0 to 1000mm. Then a series of regular short cores was adopted to make up long core according to a certain pattern (Table 2) [17]. Table 2: core ordering of long core displacement experiment in Asab reservoir Core Number Length/cm Diameter/cm Pore Volume/cm 3 Porosity/% Permeability/10-3 μm 2 ordering Outlet Σ Inlet The experiment was conducted under the reservoir condition (25.5MPa/121 ). Procedure was as follows: 1) cores were evacuated after they were assembled according to a certain pattern, then formation water was injected to the core until it was fully saturated and saturation capacity was noted. 2) Dead oil was used to displace water in the core until there s no water flowing out. Keep displacing after 14 hours till no more water flowing. The total water volume which was displaced by oil was noted to calculate irreducible water saturation and original oil saturation. 3) In order to prevent precipitation of BITM, 1PV decain was used to displace dead oil in the core. Then 2~3PV oil sample was used to displace decalin, establishing saturated status of formation oil under the irreducible water state. 4) Experiments were carried out under the formation condition. 5) Displacement time, injection pressure, confining pressure and back pressure of each experiment were noted. Produced gas-oil ratio and the isolated oil, gas and water volume were calculated. 6) The core was sufficiently rinsed after each group of the experiment finished. Then dry it with nitrogen. The core was evacuated with vacuum pump. Repeat step 1~3 and conducted the next set of experiment. 2 Experiment Scheme Four groups of experiments were designed in total: 1) CO 2 miscible displacement. CO 2 was injected at the speed of 0.074cm 3 /min steadily. 2) CO 2 -water alternate miscible flooding. Injection speed was 0.074cm 3 /min and ratio of the two slugs was 0.3PV:0.3PV. 3) CO 2 -water alternate

7 Vol. 19 [2014], Bund. Z miscible flooding after water flooding. First, water was injected at the speed of 0.074cm 3 /min. After water flooding, water and CO 2 slug were circularly and alternately injected according to the ratio of 0.3PV:0.3PV. 4) CO 2 -water alternate miscible flooding after associated gas-water alternate immiscible flooding. Water and associated gas slug were injected according to the speed of 0.074cm 3 /min and ratio of 0.3PV:0.3PV. After that, water and CO 2 were injected circularly and alternatively in according with the same speed and ratio. 3 Experiment Results Figure 6~9 show the relationship between the recovery, gas production, water production and pore volume of injected gas/water in the four experiments. Figure 6: recovery and gas production changes in CO 2 miscible flooding experiment Figure 7: recovery, gas and water production changes in CO 2 -water miscible flooding experiment

8 Vol. 19 [2014], Bund. Z Figure 8: recovery, gas/water production changes in CO 2 - water miscible flooding after water flooding experiment Figure 9: recovery, gas and water production changes in CO 2 -water miscible flooding after associated gas-water immiscible flooding experiment

9 Vol. 19 [2014], Bund. Z DISCUSSION Single Oil Displacement Method Compare these four different oil displacement methods of water flooding, associated gas-water alternate immiscible flooding, CO 2 miscible flooding and CO 2 -water alternate miscible flooding (figure 6~9). From the comparison of the four experiments of recovery, we can see that CO 2 -water alternate miscible flooding > CO 2 miscible flooding > associated gas-water alternate immiscible flooding >water flooding (Table 3). Therefore, CO 2 -water alternate miscible flooding is the most efficient way to displace oil. Its recovery is 19.9% higher than that of water flooding, 12.46% higher than that of associated gas-water alternate immiscible flooding, and 5.03% higher than that of CO 2 miscible flooding. This is because that crude oil mainly exists in the pore of the rock but throat size is the key factor to decide whether oil can be displaced from the pore. Porous type carbonate reservoir has strong anisotropy with extremely irregular throat radius. Water mainly displaces crude oil in the pore linked with large throats rather than the oil controlled by small throats. Besides, capillary pressure prevents water from flowing to small throats. However, under the formation condition, injected CO 2 and oil can be miscible, this effect lowers oil viscosity and reduces interfacial tension to zero which improves displacement efficiency much. Also, in miscible condition, the capillary pressure reduce greatly or even disappear when liquid flows in the small throat, which is conducive to the displacement of crude oil in the pore controlled by the small throat and largely improve sweep factor. This is the advantage of miscible flooding over water flooding and immiscible flooding. Also, as condition of miscible flooding, alternation of water and gas restrains gravitational differentiation and improves sweep factor, thus the effect of CO 2 -water alternate miscible flooding is better than CO 2 miscible flooding. Recovery of associated gas-water alternate immiscible flooding is 7.44% higher than that of water flooding. From the solubility swelling test, we can see that injection of associated gas will expand crude oil volume, reduce its viscosity and interfacial tension. Under immiscible condition, interfacial tension between gas and crude oil is much smaller than the one before injecting gas. It will help reduce capillary pressure when the two-phase fluid flows in the small throat and make gas easier enter the pore to displace oil. Displacement efficiency can also be improved. In addition, swelling of crude oil volume is beneficial to the displacement of oil from small throats. Therefore, compared with water flooding, immiscible flooding can also achieve better effect. We can consider immiscible flooding in the case that CO 2 is hard to obtain. Table 3: recovery of different displacement methods CO Displacement Water Associated Gas -Water CO 2 Miscible 2 -Water miscible Method Flooding Immiscible Flooding Flooding Flooding Recovery 60.79% 68.23% 75.66% 80.69%

10 Vol. 19 [2014], Bund. Z Assorted Oil Displacement Method Scheme 3 and 4 are assorted oil displacement method. Compare effects of scheme 2 which directly employ CO 2 -water alternate miscible flooding and 3 which increases one more step of water flooding before CO 2 -water displacement. (Figure 7 and figure 8). Recoveries of the two are basically the same. The former one is 80.69% and the latter is 80.33%. Hence, we can conclude that it will make no difference on the final recovery whether water is injected previously. Considering that cost of water flooding is much lower, we can firstly conduct water flooding, then CO2-water alternate miscible flooding to improve recovery in the practical application as for the porous type carbonate reservoir. Compare effects of scheme 2 which directly adopts CO 2 -water alternate miscible flooding and scheme 4 which increases one more step of associated gas-water alternate immiscible flooding before CO2-water displacement (figure 7 and figure 9). The final recovery of scheme 2 and 4 is 80.69% and 70.37% respectively. While recovery in the first phase of immiscible flooding of scheme 4 is 68.23%. Recovery of CO 2 -water alternate miscible flooding on the basis of immiscible displacement is only 2.14% higher than merely immiscible flooding and 10.32% lower than merely CO2-water displacement. We can see that miscible displacement is not so good at improving recovery in this experiment. This is because that mobility of associated gas is high enough to produce finger advance and thus form preponderance flow path. If we conduct CO2- water alternate miscible flooding after immiscible flooding, CO2 which flows only along the flow path formed by the associated gas will not sweep more residual oil. Therefore, its effect is much worse than merely CO2-water alternate miscible flooding. So it is not a good idea to combine miscible and immiscible flooding. CONCLUSION The mechanism of gas injection displacement contains miscible flooding, oil volume swelling and viscosity reduction. Initial reservoir pressure of Asab reservoir is lower than minimum miscible pressure with associated gas injection and higher than minimum miscible pressure with CO 2 injection. Therefore, the oil displacement mechanism of associated gas injection in Asab reservoir is immiscible flooding while that of CO 2 injection is miscible flooding. CO 2 -water alternate miscible flooding is the most effective way to improve recovery. Its recovery is higher than water flooding, CO 2 miscible flooding and associated gas-water alternate immiscible flooding. Associated gas-water alternate immiscible flooding can also improve recovery for that gas injection has the effect of swelling and viscosity reduction. 4. The final recovery of CO 2 -water alternate miscible flooding after water flooding is basically the same with merely CO 2 -water alternate miscible flooding. CO 2 -water alternate miscible flooding after associated gas-water immiscible flooding has no apparent effect in improving

11 Vol. 19 [2014], Bund. Z recovery. This is because that mobility of associated gas is high enough to produce finger advance and thus form preponderance flow path. The subsequent injected CO 2 flows only along this flow path and it will not sweep more residual oil. ACKNOWLEDGMENTS Dr. Liao Changlin is gratefully acknowledged for his active support and material contribution to this paper. REFERENCES [1] Guoping Bai (2007). Oil and Gas Geological Characteristics of Middle East Oil and Gas Fields. Beijing: China Petrochemical Industry Press, pp [2] Shudong Zhao (1997). Renqiu Carbonate Reservoir. Beijing: Petroleum Industry Press, pp [3] Yulin Ren, Jianglong Li, and Xiaote Huang (2004). Study on developmental technologic strategies in Tahe carbonate oil field. Petroleum Geology and Recovery Efficiency, Vol 11,No.5: pp [4] Zhongmin Lin (2002). Carbonate rock reservoir features and oil-gas accumulating conditions in the Ordovician of Tahe oil field in Northern Tarim Basin. Acta Petrolei Sinica,Vol 23, No.3,pp [5] Hui Liu, Junchang Dong, Yang Liu, (2013). Experiments on gas and water injection for enhance oil recovery in porous carbonate reservoir. Journal of China University of Petroleum Vol. 37, No.1, pp [6] Shilun Li, Ping Guo, Zhonglin Wang, (2007). Theory and application of gas injection enhanced oil recovery method in middle-low permeable reservoir. Beijing: Petroleum Industry Press, pp [7] Pingping Shen, Dong Han (2000). PVT and phase behavior of petroleum reservoir fluids. Beijing: Petroleum Industry Press, pp [8] Lun Zhao, Zifei Fan, Heng Song, (2009). Technologies for improving producing degree of low permeability carbonate reservoirs. Petroleum Exploration and Development, Vol 36, No.4, pp [9] Guo X, Du Z, Sun L, (2006). Optimization of tertiary water-alternate-co 2 flood in Jilin oil field of China: laboratory and simulation studies. SPE [10] Baljit S, Scott M (2001), Akanni S. Analysis of factors affecting microscopic displacement efficiency in CO 2 floods. SPE [11] Joachim M, Abbas F, Zhidong L, (2010). Experimental core flooding and numerical modeling of CO 2 injection with gravity and diffusion effects. SPE [12] Joachim M, Abbas F, Mohammad M (2009). A new approach to compositional modeling of CO 2 injection in fractured media compared to experimental data. SPE

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