Oil Recovery Performance and CO2 Storage Potential of CO2 Water

China University of Petroleum, Beijing 102249, People's Republic of China ... *Telephone: +86-151-1694-6951. ..... and a small number of injected ...
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Oil Recovery Performance and CO2 Storage Potential of CO2 WaterAlternating-Gas Injection after Continuous CO2 Injection in a Multilayer Formation Hao Lei,*,† Shenglai Yang,† Lihua Zu,‡ Zhilin Wang,† and Ying Li† †

Key Laboratory of Petroleum Engineering of the Ministry of Education, China University of Petroleum, Beijing 102249, People’s Republic of China ‡ Research Institute of Exploration and Development, Huabei Oilfield Company, China National Petroleum Corporation (CNPC), Renqiu, Hebei 062552, People’s Republic of China ABSTRACT: In this study, oil recovery performance and carbon dioxide (CO2) storage potential of a CO2 water-alternating-gas (CO2-WAG) injection after continuous CO2 injection process for multilayer formation were experimentally determined under immiscible and miscible conditions. First, a slim-tube apparatus was used to measure the minimum miscibility pressure (MMP) of a CO2−crude oil system (MMP = 22.79 MPa), which was applied as a guide for follow-on investigations. Afterward, the CO2WAG injection after the continuous CO2 injection for a triple-layer system, horizontally placed and parallel-connected, was conducted to evaluate the capacity of enhanced oil recovery and CO2 storage potential of the multilayer formation at different operating pressures and a reservoir temperature of 98 °C. Results revealed that the oil recovery of the entire system was determined by the recovery of a layer with the highest permeability, which was more than 90% of the entire system recovery provided by the highest permeability layer in the continuous CO2 injection. The ensuing CO2-WAG injection could further enhance the oil recovery of the system after the continuous CO2 injection. The contribution of the recovery produced by the highest permeability from 90 to 98.3% could also be reduced for the entire system recovery. The oil recovery factor of the multilayer system increased as the operating pressure increased (i.e., from 33.01% of the system at Pop = 15 MPa to 39.42% of the system at Pop = 25 MPa). From a view of CO2 storage potential, the ensuing CO2-WAG injection at immiscible and miscible conditions could also double the amount of stored CO2 after the continuous CO2 injection for the multilayer system. More than 75−80% of stored CO2 for the multilayer system was contributed by the highest permeability layer at the end of the CO2-WAG the CO2-WAG injection after the continuous CO2 injection process under immiscible and miscible conditions. Therefore, for a multilayer formation, such as the Jilin oilfield, the layer with medium and low permeability should be further developed after CO2-WAG injection.

1. INTRODUCTION CO2, which is also known as a greenhouse gas,1−3 has a serious impact on the global environment.4,5 Since the 1990s, many studies have suggested that the CO2 concentration in the atmosphere may rise from 0.028−0.035% in 1994 to 0.05% in 2050 as a predicted value,6,7 thereby accelerating the effects of global warming.4,8,9 These scenarios indicate the urgent need to reduce the atmospheric concentration of CO2. Storing CO2 underground through a geological formation is regarded as an effective and safe method for industry-derived CO2.10−13 Previous numerical simulations and field tests have already demonstrated that the formation with fossil fuel, as an ideal site, is often used for the geological sequestration of CO2,14 which can substantially improve oil production and considerably reduce the CO2 concentration in air by the oil displaced.1,2 This phenomenon is attributed to the tight caprock at the top of an oil-bearing formation, which can prevent the hydrocarbon migration. CO2 enhanced oil recovery (CO2-EOR), also known as CO2 injection, has wide applications in oil formation.15−17 These CO2-EOR techniques mainly consist of continuous CO2 injection, carbonated water injection (CWI), water-alternating-gas (WAG) injection, CO2 cycle solvent injection (CSI), and CO2 huff and puff.18,19 Numerous laboratory studies have © XXXX American Chemical Society

indentified some of the distinct advantages and weaknesses of commonly recognized CO2-EOR techniques.20,21 For example, continuous CO2 injection has high oil displacement efficiency, and injected CO2 is dissolved in crude oil to reduce its viscosity.22 However, it produces an untimely CO2 breakthrough (BT) caused by viscous fingering, gravity segregation mechanisms, and permeability reduction as a result of the combined effect of asphaltene deposition and inorganic deposition.23−26 The CO2 huff-and-puff method is a good candidate for light-oil formation, tight reservoir, and matrixfractured formation.1,2,21 Abundant injected CO2 and oil production are simultaneously produced in the huff-and-puff process, which increases the cost related to CO2 collection and separation. An optimal EOR method for a reservoir significantly improves oil recovery and reduces the development cost. Therefore, the CO2-WAG injection after the continuous CO2 injection process, which is the so-called ensuing WAG injection after the BT of continuous CO2 flooding, is used to improve the effective amount of injected CO2, enlarge sweep volume, and improve oil-driving efficiency. This method was proven by Received: May 30, 2016 Revised: August 5, 2016

A

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Energy & Fuels many laboratory experiments and field tests.27−29 The CO2WAG injection process further increases the oil recovery and amount of stored CO2 after the CO2 BT of continuous CO2 flooding and reduces the amount of produced CO2. However, it has several limitations, such as water blocking, deposition of insoluble metal carbonates and asphaltene, and pipeline corrosion.23−25,30 These limitations may potentially lead to the Jamin effect, permeability reduction, and shutdown of the gas injection well. Numerous laboratory studies and field logging experiments have been shown that the actual oil-bearing formation consists of a layer with different permeabilities separated by a restraining barrier.31,32 In theory, the amount of stored CO2 via multilayer injection technology differs from the results obtained from the simulated experiment via single-layer injection. This discrepancy is attributed to the altered flow resistance of CO2, which depends upon the capillary force in the multilayer formation.33 Similar to the storage amount of CO2, the oil recovery of each layer through the multilayer injection technology is different compared to the result obtained from a single-layer injection. In the past few decades, single core-flooding tests have been frequently used to evaluate the oil recovery factor (RF) and CO2-stored potential. This simulated method possesses the advantages of convenience and short period. However, the results measured from the single core-flooding experiment require more accuracy to reflect the real underground situation. Therefore, a new core-flooding apparatus is required to study the real formation during multilayer co-injection and separated layer production. The oil RF of CO2-EOR methods and its potential of CO2 storage for a homogeneous reservoir are well-recognized. However, the recovery and storage amount of CO2-EOR technology for the multilayer formation, which corresponds to the actual formation, require further investigation and analysis. Studies on the oil recovery and CO2 storage potential of CO2EOR in the multilayer formation have been lacking thus far. In this study, the oil performance and CO2 storage potential of the CO2-WAG injection after the continuous CO2 injection in the multilayer formation were determined under miscible and immiscible conditions in this paper. The minimum miscibility pressure (MMP) of the CO2−crude oil system was determined by applying a slim-tube apparatus. For realistic simulations, two CO2-WAG injection after continuous CO2 injection tests in the multilayer system were designed and performed at miscible and immiscible pressures (i.e., Pop > MMP and Pop < MMP, respectively) and at a formation temperature of 98 °C. The oil recovery and the amount of stored CO2 in the multilayer system were evaluated and compared at different operating pressures. Producing gas−oil ratio (GOR), producing water− oil ratio (WOR), and producing CO2 volume to stored CO2 volume ratio were also measured at different operating pressures.

Table 1. Compositional Analysis Results of the Crude Oil Sample with the n-C5-Insoluble Asphaltene Content of 3.43 wt % at Atmospheric Pressure and T = 25 °C carbon number

wt %

carbon number

wt %

CO2 N2 C1 C2 C3 iC4 n-C4 iC5 n-C5 C6 C7 C8 C9 C10

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.677 0.129 0.682 1.195 3.283 3.762 3.321

C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24

3.130 3.472 3.222 2.956 3.450 3.000 3.200 3.167 3.000 3.000 3.000 2.833 2.833 2.767

carbon number

wt %

C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 C36+ total

2.550 2.500 2.525 2.375 2.250 2.250 1.875 1.725 1.650 1.500 1.443 21.278 100.00

Table 2. Compositional Analysis Results of the Dissolved Gas Sample at Atmospheric Pressure and T = 25 °C carbon number

wt %

carbon number

wt %

CO2 N2 C1 C2 C3 iC4 n-C4 iC5 n-C5 C6 C7 C8 C9 C10

1.095 6.303 53.524 18.869 12.287 1.281 4.141 0.491 0.947 0.573 0.356 0.129 0.004 0.000

C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

carbon number

wt %

C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 C36+ total

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 100.00

formation temperature of 98 °C. The obtained results of the viscosity as a function of pressure are plotted in Figure 1. The viscosity of the

2. EXPERIMENTAL SECTION 2.1. Materials. In this study, the stock-tank crude oil (STO) collected from the low-permeability formation of H-79 block in Jilin, China, was used. The gas chromatography (GC) compositional analyses of the STO and dissolved gas were tabulated in Tables 1 and 2, respectively. The content of n-C5 (normal heptane)-insoluble asphaltene was measured to be 3.43 wt % by appling the standard ASTM D2007-03 method. The Ruska pressure−volume−temperature (PVT) apparatus equipped with a capillary viscometer was used to recombine the live oil (e.g., solution GOR of 36.7:1) and determine the viscosity of crude oil (live oil) at different pressures and the

Figure 1. Measured viscosities of crude oil as a function of the pressure at a formation temperature of 98 °C. B

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cm3/min). Thereafter, the setup pressure was enhanced to the experimental pressure using the ISCO pump and equilibrated for all day at the formation temperature. CO2 was then displaced into the slim-tube apparatus with a constant flow rate of qCO2 = 0.4 cm3/min under a constant operating pressure. The experiment was terminated by injecting 1.20 hydrocarbon pore volume (HCPV) of pure CO2.34 The amount of produced oil at different periods of injection times was collected to calculate the oil RF. 2.3. CO2 Injection Tests. Figure 3 depicts a schematic diagram of the multilayer and high-pressure coreflood setup used for CO2-WAG injection after continuous CO2 injection tests in this study. The setup mainly consisted of the following components: (1) Three stainlesssteel core holders (Haian, China; P, 70 MPa; T, 150 °C), parallel connection type and horizontally positioned, were used to simulate the CO2-EOR and storage potential in real formation. Each core holder has a length, inner diameter, and outer diameter of 1.2 m, 2.50 cm, and 4.00 cm, respectively. A strong acid-resistant and hot-resistant rubber sleeve (Huada, China) was used to insulate the core in the system. As a physical porous medium, the core samples were used to form a composite core. The obtained absolute permeability and porosity of the core plugs were in the range of 0.016−41.66 mD and 2.74− 20.34%, respectively. These core plugs were placed into the different core holders, including a high-permeability layer (i.e., core-holder 1), a medium-permeability layer (i.e., core-holder 2), and a low-permeability layer (i.e., core-holder 3), to establish a parallel system. (2) An ISCO syringe pump (260D, ISCO, Lincoln, NE; flow-rate range, 0.001−50 mL/min; operating pressure range, 0−51.7 MPa) was used to displace brine, crude oil, and CO2 into the multilayer core plugs.35 (3) A backpressure regulator (Huada, China; maximum pressure, 40 MPa; pressure accuracy, 0.01 MPa) connected to the end of the core holder was used to maintain the desired production pressure. (4) A separate layer production device, including three different gas flow meters and an oil sample collector, was used to distinguish measurements and collect the produced product (i.e., brine, oil, and CO2) from different core holders. (5) An automatic temperature controller (Haian, China; temperature, 150.0 °C; temperature accuracy, 0.1 °C) with two electric heat guns was used to heat and maintain the system temperature.35 Prior to each experiment, the core plugs were cleaned using a Soxhlet extractor (SXT-02, Shanghai Ping Xuan Scientific Instrument Co., Ltd., China) for 20−30 days. Then, the core samples were vacuumed and saturated with the formation brine. Thereafter, the crude oil was pumped into every core holder at a constant flow pressure of 7 MPa to achieve the initial oil saturation (Soi) and the connate water saturation (Swc) at the formation temperature of 98 °C. During the process of core plug saturation, each of composite core plug was terminated after 30 HCPV of crude oil was injected. The measured physical properties of the composite core plugs were presented in Table 4. After the continuous process of saturating the cores by oil, all core holders should be maintained for the whole day to attain a suitable equilibrium condition at a formation temperature of 98 °C. The preceding process was repeated every time in view of CO2WAG injection after continuous CO2 injection experiments conducted at different operating pressures. The general procedure for the CO2-WAG injection after the continuous CO2 injection process is briefly introduced as follows. First, CO2 was co-injected with a constant flow rate of 0.05 cm3/min into the parallel system (i.e., multilayer system) from the same inlet, and the production of different layers was separated and collected. This step was stopped after injection of CO2 BT and no more oil was produced from the parallel system. Afterward, the ensuing step of the WAG technique with WAG slug size of 0.10 HCPV and WAG slug ratio of 1:1 was performed to enhance the oil recovery and storage capacity of CO2 at a constant flow rate of 0.05 cm3/min. At this stage of the experiment, the ensuing WAG injection was stopped until no more oil was produced from the parallel system.

live oil was measured to be 2.16 mPa s under reservoir conditions (P = 24.5 MPa and T = 98 °C). The density and formation volume factor of the live oil were determined to be 0.7615 g/cm3 and 1.1723 at the initial formation pressure of 24.5 MPa and T = 98 °C, respectively. The physicochemical properties of the formation brine sample were measured using the standard ASTM D511, ASTM D512, and ASTM D516 methods. These physicochemical properties are tabulated in Table 3. High-purity CO2 (99.99%) was used in this study.

Table 3. Physicochemical Properties of the Reservoir Brine Sample at Atmospheric Pressure and T = 25 °C test name

reservoir brine

density at 25 °C (g/cm ) viscosity at 25 °C (cP) pH at 25 °C chloride (mg/L) potassium (mg/L) sodium (mg/L) calcium (mg/L) magnesium (mg/L) sulfate (mg/L) bicarbonate (mg/L) 3

1.004 1.02 7.04 4481.600 1124.800 2127.500 50.500 28.100 1049.500 2055.800

2.2. Slim-Tube Tests. A slim-tube apparatus (CFS-100, Core Lab, Tulsa, OK), as depicted in Figure 2, was used to measure the MMP of

Figure 2. Schematic diagram of the experimental apparatus applied for the MMP of CO2−oil system measurements at various equilibrium pressures and a formation temperature of 98 °C. the CO2−crude oil system in this study. It mainly consisted of a hightemperature and high-pressure long stainless steel packed with silica sand (Shengfa Mining Industry Co., Ltd., China). The apparatus had a length, inner diameter, pore volume (PV), and porosity of 15.28 m, 4.00 mm, 57.18 cm3, and 31.05%, respectively. A Teledyne ISCO pump (260D, ISCO, Lincoln, NE; flow-rate range, 0.001−50 mL/min; operating pressure range, 0−51.7 MPa) was used to inject crude oil, CO2, and pure water into the slim tube and the back-pressure regulator (Huada, China; maximum pressure, 40 MPa; pressure accuracy, 0.01 MPa), which was applied to maintain the system pressure. The apparatus was cleaned and dried prior to each test. In this study, a total of six slim-tube tests were conducted to determine the MMP of the CO2−crude oil system at different pressures of 12−40 MPa and at a formation temperature of 98 °C. First, the slim-tube apparatus was saturated with crude oil at a constant flow rate (qoil = 0.2

3. RESULTS AND DISCUSSION 3.1. MMP. In this study, the six slim-tube tests were conducted to determine the MMP of the injected CO2−crude C

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Figure 3. Schematic diagram of the high-pressure and multilayer CO2 coreflood setup.

Table 4. Basic Physical Properties of the Composite Core Plugs and Operating Conditions of Two CO2-WAG Injection Tests Conducted at a Reservoir Temperature of 98 °C test

1

2

core holder

1

2

3

1

2

3

porosity, Φ (%) absolute permeability, k (mD) length (cm) diameter (cm) connate water saturation, Swc (%) operating pressure, Pop (MPa) miscibility condition

18.56 15.93 90.916 2.508 38.17

14.58 3.24 79.478 2.514 35.93 16.04 immiscible

14.56 0.15 76.540 2.516 34.02

18.56 15.93 90.916 2.508 37.76

14.58 3.24 79.478 2.514 33.56 25.69 miscible

14.56 0.15 76.540 2.516 35.94

oil system at different pressures from 12 to 40 MPa and a constant temperature of 98 °C. The measured ultimate oil RFs at different operating pressures are illustrated in Figure 4. As expected, the oil RF increases as the amount of injected CO2

increases. The ultimate oil RF is increased with the operating pressure. This phenomenon is mainly caused by the accelerated rate of CO2 extraction and strong dissolution to reduce oil viscosity at a high pressure,1 thereby leading to the low capillary resistance of the CO2−oil system. Afterward, the obtained ultimate oil RF versus the operating pressure, as depicted in Figure 5, is plotted to determine the MMP of Jilin crude oil and

Figure 4. Oil recovery factors of the CO2 injection tests conducted using the slim-tube apparatus at the operating pressure from 12 to 40 MPa and a temperature of 98 °C.

Figure 5. Variation of the cumulative oil recovery factor determined at 1.20 pore volume of CO2 injected at different operating pressures. D

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flow resistance of the two-phase flow at the beginning and the reduction of crude oil viscosity caused by CO2 dissolution. In the ensuing CO2-WAG injection process, the pressure drop increased monotonously in each period of water slug injection because the viscosity of injected water was higher than the viscosity of injected CO2. 3.2.2. Oil RF, GOR, and GWR. In this study, two CO2-WAG injection after continuous CO2 injection experiments in the multilayer formation were performed under immiscible (Pop = 15 MPa and T = 98 °C) and miscible (Pop = 25 MPa and T = 98 °C) conditions. In each experiment, the continuous injection of CO2 was performed in the multilayer formation. This process was terminated when oil was no longer produced. Then, as an improved CO2-EOR method, the ensuing CO2WAG injection was applied in the multilayer formation to increase the oil recovery over the continuous CO2 flooding. It is worth noting that the oil recovery of continuous CO2 injection was mainly determined by the layer with high permeability. Figure 7 shows the measured ultimate oil RF of the three discrete formations with different permeabilities versus the HCPV injected with CO2 and water. Figure 7a shows that, in the multilayer system, the recovery of the layer with high permeability (i.e., core-holder 1) was considerably higher than that of the layer with medium permeability (i.e., core-holder 2) and of the layer with low permeability (i.e., core-holder 3). This finding is attributed to the low flow resistance mechanism in the high-permeability layer. Before CO2 BT (0.2 HCPV), the measured oil recoveries of the three different permeability layers were found to be 49.5, 3.54, and 0%, respectively. This result indicated that the high-permeability layer in the continuous CO2 injection process contributed significantly to the oil recovery of the entire formation, accounting for more than 90% of the entire system oil recovery; this proportion decreases as the HCPV injection of CO2 increases (Figure 8a). With regard to the ensuing WAG injection, the oil recovery for the multilayer system, particularly the high-permeability layer, enhanced substantially from 49.5 to 71.38% as the WAG cycle increased. This increase resulted from the profile control mechanism and the mobility control of CO2.18 For the medium- and low-permeability layers, the ensuing CO2-WAG injection did not lead to a noticeable increase in oil production, and the recovery of the medium- and low-permeability layers was only a nominal increase from 3.54 to 11.37% and from 0 to 2.24%. This phenomenon was mainly attributed to the high capillary force in the lower permeability layer compared to that in the higher permeability layer, which offsets the increase of oil recovery via the CO2-WAG injection. Similarly, although slightly pronounced, the same trends were measured in the multilayer system under miscible conditions (Figure 7b). The miscible injection led to early BT compared to the immiscible injection in the multilayer system. After CO2 BT of the CO2 injection, the oil recovery of the multilayer system was obviously decreased because of the reducing miscibility effect and the gas channel formed. Therefore, for the EOR in the multilayer formation, the time of the CO2 BT in the multilayer system should be delayed. The measured oil RF of the entire formation and the contribution rate of different layers at different operating pressures are depicted in Figure 8. As reported before, the recovery of the entire formation was determined by the RF of the layer with the highest permeability in the continuous CO2 injection process. In the ensuing CO 2-WAG injection processes, the contribution of the highest permeability layer

CO2. The figure shows that the intersection point of the two fitting curves represents the MMP of the CO2−crude oil system, which was 22.79 MPa and can be used to as a guide for choosing the miscible pressure for the ensuing experiments. 3.2. Oil RF. 3.2.1. Differential Pressure of the System. The measured differential pressures between the injection and production of the multilayer system under immiscible and miscible conditions are drawn in Figure 6. As expected, the

Figure 6. Measured differential pressure (ΔP) between the inlet and outlet of the multilayer system versus the HCPV of injected CO2 and water under (a) immiscible conditions and (b) miscible conditions.

continuous CO2 injection process under miscible conditions had the lower pressure drops because of the lower interfacial tension of the crude oil−CO2 system than that under immiscible conditions. In the continuous CO2 injection processes, the pressure drop under miscible and immiscible conditions increased at first and decreased subsequently. This phenomenon was caused by the combined effects of the strong E

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Figure 8. Cumulative oil recovery factors of the entire formation and the contribution ratios of different layers versus pore volume of injected CO2 and water for CO2-WAG injection after continuous CO2 injection tests under (a) immiscible conditions and (b) miscible conditions.

Figure 7. Cumulative oil recovery factors of the different layers versus injected pore volume of CO2 and water for CO2-WAG injection after continuous CO2 injection tests under (a) immiscible conditions and (b) miscible conditions. The HCPV is calculated by the effective pore volume of the multilayer system.

high-permeability layer.36 Therefore, using the multilayer system has a practical guiding significance for the field. The GOR and WOR of the multilayer formation, which represented the layer with the highest permeability, under immiscible and miscible conditions are plotted in Figure 9. As seen from this figure, no produced water was obtained during the continuous CO2 injection process under immiscible and miscible conditions. This finding indicated that the water saturation remained unchanged in this process. The measured GOR under immiscible and miscible conditions increased drastically after the CO2 BT and reached its nearly maximum value of GOR = 85 at miscible conditions and GOR = 68 at immiscible conditions. Afterward, the GORs rapidly decreased and remained constant. This scenario was attributed to the new added oil recovery produced by the medium- and lowpermeability layers in the ensuing WAG injection. The produced water under immiscible and miscible conditions was both produced at the third WAG cycle. The WORs under immiscible and miscible conditions were increased at first and

for the multilayer system RFs was reduced slowly from 94.8% (i.e., in the continuous CO2 injection process) to 87.39% (i.e., in the WAG injection process) under immiscible conditions. In contrast, it dropped significantly from 98.3% (i.e., in the continuous CO2 injection process) to 77.41% (i.e., in the WAG injection process) under miscible conditions. This outcome is caused by a combination of the miscible displacement mechanism and the profile control mechanism. The results for the CO2-WAG injection process also indicated that the oil RFs of the multilayer depend highly upon the RF of the highest permeability layer. The recovery of the entire system was not very high, and 33.01% (15 MPa) and 39.43% (25 MPa) were obtained in comparison to literature results (RF = 78.8%). According to the field production data and predicted results,11 the results obtained using the multilayer system correspond more to actual values. This finding is mainly caused by the heterogeneity of the reservoir and the fingering effect in the F

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Figure 10. Comparison between measured recovery oil factors of the multilayer system for CO2-WAG injection after continuous CO2 injection tests under immiscible and miscible conditions.

Figure 9. Producing GOR and WOR of two CO2-WAG injection after continuous CO2 injection tests performed under (a) immiscible conditions and (b) miscible conditions. Figure 11. Comparison between measured recovery oil factors of the single-layer system (MMP = 7.45 MPa) and the multilayer system (MMP = 22.79 MPa) for continuous CO2 injection tests under immiscible and miscible conditions.

decreased subsequently as the HCPV of the injected CO2 and water increased. The ultimate WORs of the two experiments under immiscible and miscible conditions were found to be 5.56, and 1.78, respectively. 3.2.3. Effect of Permeability Heterogeneity. Figure 10 compares the measured oil RFs of the multilayer system under immiscible and miscible conditions. The measured oil RFs of the single-layer system (ie., homogeneous formation) and the multilayer system (i.e., heterogeneity formation) are drawn and compared in Figure 11. Figure 11 shows that, in the continuous CO2 injection processes, the miscible injection in EOR had no obvious superiority compared to the CO2-immiscible injection in the multilayer system. In addition, it also found that, for the continuous CO2 injection processes, the oil RF of the singlelayer system (i.e., homogeneous formation) measured at immiscible conditions was significantly lower (RF = 59.7%) than the results (RF = 81.7%) measured at miscible conditions. This finding was caused by the low interface tension and efficient extraction of CO2 at miscible conditions.1−3,5 This scenario reflected that the miscibility effect can substantially increase the oil recovery of the reservoir and the amount of injected CO2 (i.e., the amount of stored CO2). However, whether under the miscible conditions or under the immiscible conditions, the result of the oil RF for the multilayer system (i.e., heterogeneity formation) was considerably lower than the

result obtained from the single-layer system (i.e., homogeneous formation). Figures 10 and 11 combined show that the permeability heterogeneity of the formation could decrease the miscibility effect. Moreover, it was also found (Figure 10) that, in the ensuing CO2-WAG injection, 17.75% of residual oil was produced under the miscible conditions, which was more than 11.66% under immiscible conditions. This phenomenon was mainly caused by the improved volumetric sweep efficiency, which was determined by the permeability heterogeneity of the formation. It is also revealed that the miscible injection has played an important role in EOR of the multilayer system by the reducing reservoir heterogeneity compared to the immiscible injection. Therefore, the permeability heterogeneity of the formation was the most significance factor in the development of the multilayer CO2 co-injection process, followed by the miscibility effect. This trend could certainly influence the CO2 storage in the multilayer system. 3.3. CO2 Storage. In this study, in addition to the CO2EOR experiments, the storage potential of the CO2-WAG injection after continuous CO2 injection process in the multilayer formation as practically simulated at different G

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Energy & Fuels operating pressures was also evaluated. Figure 12 shows the cumulative volume of stored CO2 for the different layers and

Figure 13. Comparison between stored CO2 of the multilayer system for two CO2-WAG injection after continuous CO2 injection tests conducted at various operating pressures and a reservoir temperature of 98 °C.

mentioned earlier, this was attributed to effectively improve the injection profile of CO2 by reducing gas relative permeability.18 The retention factor (RtF) and the ratios of cumulative stored CO2 to cumulative produced CO2 for the multilayer formation at different operating pressures are compared and tabulated in Table 5. The retention factor is the ratio of the stored CO2 volume to the produced oil volume, which is given by R tF = VCO2,stored /Vo,prod

(1)

Table 5. Retention Factor and Ratios of Cumulative Stored CO2 to Cumulative Produced CO2 for the Multilayer Formation at Different Operating Pressures and a Reservoir Temperature of T = 98 °C

Figure 12. Difference between stored CO2 for each layer formation and produced CO2 of the multilayer system performed under (a) immiscible conditions and (b) miscible conditions.

produced CO2 for the CO2-WAG injection after continuous CO2 injection experiment under immiscible and miscible conditions. As expected, the CO2 storage capacity of the multilayer system is nearly determined by the CO2 storage capacity of the layer with the highest permeability, and more than 80% of injected CO2 was stored in the highest permeability layer. This result clearly indicated that the multilayer system, particularly the layer with medium and low permeability in the formation, has an immense potential to increase the amount of CO2 stored. Figure 13 depicts the cumulative volume of stored CO2 for the multilayer formation at different operating pressures. As seen from this figure, the amount of stored CO2 under the miscible conditions was considerably larger than that stored CO2 under immiscible conditions; in particular, the former was nearly twice that of the latter. This phenomenon was caused by the CO2 storage mechanisms of capillary trapping and solubility/dissolution trapping in the formation, which is increased as the pressure increased. In addition, in immiscible and miscible conditions, the ensuing CO2-WAG injection after CO2 BT could increase the amount of stored CO2 1-fold. As

test

1

2

operating pressure, Pop (MPa) retention factor, RtF cumulative stored CO2/cumulative produced CO2

16.04 196.98 30.83

25.69 328.30 52.31

Table 5 reveals that the retention factor obtained at Pop = 15 MPa (RtF = 196.78) was significantly lower than that measured at Pop = 25 MPa (RtF = 328.30). The results also clearly revealed that injected CO2 was nearly stored in the multilayer system and a small number of injected CO2 was produced in the process of WAG injection, which not only reduces the risk of produced CO2 leakage but also drops the cost related to CO2 collection. In addition, the injected CO2 storage in the oilbearing formation was mainly controlled by the dissolution and capillary trappings.33 In the CO2 injection process, the amount of injected CO2 stored by the dissolution trapping mechanism in the injection region is considerably more than that of the production well because the pressure gradient existed in the injection and production well. When the injection process was terminated, injected CO2 in the injection region was migrated to the production well until the formation reached an equilibrium state. This phenomenon was mainly caused by the pressure gradient and the concentration difference of CO2 in the injection and production regions.37 H

DOI: 10.1021/acs.energyfuels.6b01307 Energy Fuels XXXX, XXX, XXX−XXX

Energy & Fuels

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4. CONCLUSION In this study, first, the MMP of Jilin oilfield oil with CO2 is determined by applying the slim-tube apparatus; the obtained MMP was found to be 22.79 MPa. Then, two CO2-WAG injection after continuous CO2 injection experiments using a triple parallel core set are performed to evaluate the oil recovery and the CO2 stored potential of the multilayer system at different operating pressures and at the formation temperature of 98 °C. The considerable difference among the oil RFs of the three different permeability layers indicates that the oil recovery of the multilayer formation depends mainly upon the output of the highest permeability layer. Unlike that in CO2 immiscible injection, the oil recovery for the single layer, particularly the high-permeability layer, increases drastically in the continuous CO2 miscible injection. However, for the multilayer formation, the miscibility condition (i.e., Pop > MMP) does not significantly enhance the recovery oil in the continuous CO2 injection process. The results also obviously show that the ensuing CO2-WAG injection process after the continuous CO2 injection process can remarkably increase the entire formation recovery whether in immiscible conditions or in miscible conditions. In particular, the effect of reservoir heterogeneity on recovery factor of CO2 injection process is significant for the multilayer formation. The amount of stored CO2 in the multilayer formation depends mainly upon the storage capacity of the highest permeability layer. The ensuing CO2-WAG injection process after CO2 BT can be used to increase the storage capacity of the multilayer formation 1-fold. The amount of stored CO2 at the operating pressure surpassing the MMP increases dramatically compared to that of stored CO2 at the pressure lower than the MMP. The obtained results of the multilayer formation demonstrate that a tremendous amount of crude oil in the layer with medium and low permeability in the multilayer system can be further produced to enhance the oil recovery after the CO2WAG injection. From an environmental point of view, injecting a profile modification agent with high-strength property into the high-permeability layer or applied excluder in a waterinjecting well is a reasonable choice for the produced multilayer formation, such as Jilin oilfield, to improve the capacity of CO2 stored in the multilayer formation.

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5. FUTURE WORK Experiments on the effect of WAG slug sizes and slug ratios will be conducted on the multilayer system in our next work. Furthermore, experiments on the optimization of EOR methods for the multilayer system will be conducted.

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AUTHOR INFORMATION

Corresponding Author

*Telephone: +86-151-1694-6951. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This research is supported by the National Science and Technology Major Project of the Ministry of Science and Technology of China (Grant 2016ZX05016006). I

DOI: 10.1021/acs.energyfuels.6b01307 Energy Fuels XXXX, XXX, XXX−XXX

Article

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DOI: 10.1021/acs.energyfuels.6b01307 Energy Fuels XXXX, XXX, XXX−XXX