Get 20M+ Full-Text Papers For Less Than $1.50/day. Start a 14-Day Trial for You or Your Team.

Learn More →

Investigation of flue gas water-alternating gas (flue gas–WAG) injection for enhanced oil recovery and multicomponent flue gas storage in the post-waterflooding reservoir

Investigation of flue gas water-alternating gas (flue gas–WAG) injection for enhanced oil... Flue gas flooding is one of the important technologies to improve oil recovery and achieve greenhouse gas storage. In order to study multicomponent flue gas storage capacity and enhanced oil recovery (EOR) performance of flue gas water-alternating gas (flue gas–WAG) injection after continuous waterflooding in an oil reservoir, a long core flooding system was built. The experimental results showed that the oil recovery factor of flue gas–WAG flooding was increased by 21.25% after continu- ous waterflooding and flue gas–WAG flooding could further enhance oil recovery and reduce water cut significantly. A novel material balance model based on storage mechanism was developed to estimate the multicomponent flue gas storage capacity and storage capacity of each component of flue gas in reservoir oil, water and as free gas in the post-waterflooding reservoir. The ultimate storage ratio of flue gas is 16% in the flue gas–WAG flooding process. The calculation results of flue gas storage capacity showed that the injection gas storage capacity mainly consists of N and CO , only N exists as free gas 2 2 2 phase in cores, and other components of injection gas are dissolved in oil and water. Finally, injection strategies from three perspectives for flue gas storage, EOR, and combination of flue gas storage and EOR were proposed, respectively. Keywords Flue gas storage · Enhanced oil recovery · Flue gas water-alternating gas · Material balance model · Injection strategy 1 Introduction Flue gas is one of the primary sources of human-made greenhouse gases, which contains a large amount of N , CO , and SO emitted in the process of fuel combustion and 2 2 Edited by Yan-Hua Sun during cement production (Majeed and Svendsen 2018). The composition of the flue gas is varied with different combus- * Bo-Wen Sun tion materials in the combustion process, which is mainly sbwswpu@163.com composed of N and C O , and the air-polluting components 2 2 * Ping Guo such as N O , CO, H S, and dust may also exist in flue gases x 2 guopingswpi@vip.sina.com (Bürkle et al. 2018). State Key Laboratory of Oil and Gas Reservoir Geology CO and non-CO emissions generated by fuel combus- 2 2 and Exploitation, Southwest Petroleum University, tion process can be sequestered in underground geologic Chengdu 610500, Sichuan, China formations such as deep saline aquifers (Bachu 2015), coal, Research Institute of Exploration and Development, oil, and gas reservoirs (Agartan et al. 2018; Li et al. 2006a, PetroChina Tarim Oilfield Company, Korla 841000, b), even fractured shale formations (Edwards Ryan et al. Xinjiang, China 2015). The geological sequestration has been proved to be Research Institute of Experiment and Detection, PetroChina a feasible technique for reducing greenhouse gas and help- Xinjiang Oilfield Company, Karamay 834000, Xinjiang, ing tackle climate change. There are four basic mechanisms China 4 required for long-term successful geological CO storage: Xinjiang Laboratory of Petroleum Reserve in Conglomerate, stratigraphic/structural, residual, solubility, and mineral Karamay 834000, Xinjiang, China Vol:.(1234567890) 1 3 Petroleum Science (2021) 18:870–882 871 trapping (Santibanez-Borda et al. 2019). If there is a good shrinkage. Bachu et al. (2007) proposed a correlation for seal, CO will be trapped permanently and will be immobile estimating CO storage capacity in coal beds, oil and gas 2 2 with the contribution of these mechanisms. Many studies reservoirs, and deep saline aquifers. Following these correla- in the literature discuss C O storage and EOR (Bachu et al. tions, new C O storage capacity correlations in deep saline 2 2 2004; Ettehadtavakkol et al. 2014; Farajzadeh et al. 2020; aquifers based on material balance equation were proposed Gozalpour et al. 2005; Godec et al. 2011; Jia et al. 2019; (Kopp et al. 2009a; b; van der Meer and Yavuz 2009; Zheng Zhang et al. 2015) that have been proved to be effective et al. 2010; Zhou et al. 2011). As examples of numerical techniques due to their high displacement efficiency, low simulation, Li et  al. (2006a, b) used CMG simulator to cost, and high efficiency in reducing global warming phe- study the C O sequestration in depleted oil and gas reser- nomenon. However, only a few pieces of research have been voirs; they found that once the reservoir pressure reaches investigated on flue gas injection in reservoirs (Dong and a certain high level, only increasing the injection pressure Huang 2002; Fong et al. 1992; Fossum et al. 1992; Liu et al. cannot effectively enhance the storage capacity. However, 2011; Srivastava et al. 1999; Shokoya et al. 2005; Trivedi much more capacity can be achieved by removing a portion and Babadagli 2005; Trevisan et al. 2013). The majority of the remaining water. of flue gas injection studies were focused on maximizing Injection of CO or flue gas for the purpose of coupled the oil recovery, not flue gas storage. Recently, many stud- sequestration–EOR process is appealing due to the fact that ies have been conducted to remove CO and SO from flue both goals of final recovery enhancement and greenhouse 2 2 gas independently (Lee et al. 2002; Liu et al. 2009; López gas control would be established by employing this scheme et al. 2007; Sumathi et al. 2010a, b; Yi et al. 2014). How- (Berg et al. 2010, 2013). Some authors have published works ever, the methods proposed in these studies have the disad- addressing economic analysis of C O –EOR projects (Ghom- vantages of either high-energy consumption or expensive ian et al. 2007; Jahangiri and Zhang 2011; Leach et al. 2011). equipment cost. Injecting raw flue gas into oil reservoirs is Forooghi et al. (2009) proposed a methodology to optimize very attractive because these reservoirs have structural seals the coupled CO –EOR process. His work is based on simula- that are well studied and characterized for trapping. Flue gas tion of C O injection into North Sea chalk field. They inves- can remain stored securely by virtue of following trapping tigated the effect of six parameters, namely injection scheme, mechanism: trapping beneath an impermeable layer, reten- injector and producer well type, well control mode, slug size tion as an immobile phase in pore space of porous storage and the WAG ratio, on the coupled C O –EOR and sequestra- formations, dissolution into formation fluids and adsorption tion process. They concluded that the water-alternating gas on the organic matter in shale or coal reservoirs (Nasralla injection scheme using a mixture of C O and hydrocarbon et al. 2015). Thus, injecting flue gas into oil reservoirs may gas is the optimum case. Zangeneh et al. (2013) optimized result in incremental oil recovery and make the storage pro- carbon dioxide sequestration and enhanced gas recovery in ject more feasible. The project economic viability is deeply a natural gas reservoir in Iran. They concluded that injection dependent on the availability of the flue gas source. of carbon dioxide at optimized conditions resulted in perma- Methods used to determine the storage capacity of injec- nent storage of carbon dioxide in addition to production of tion gas in gas flooding processes include experimental residual gas in the reservoir. Bender and Akin (2017) studied measurement, theoretical model, semiempirical formulas, the efficiency of flue gas injection compared to CO injection and numerical simulation. Han et al. (2018) studied flue gas for simultaneous EOR and storage by a 3D compositional displacement and storage capacity after the waterflooding simulation model and investigated the effect of injected gas in a full-diameter long core taken from Xinjiang Oilfield in type, gas solubility, and operating parameters on flue gas China; they found that flue gas flooding after waterflooding storage and oil recovery. Snippe et al. (2020) studied the can further enhance oil recovery, but the key factor to obtain wormholing effect during CO storage and water-alternating good development effect is to choose the right timing for gas injection. They reported new experimental and modeling gas injection. Zhou et al. (2019) investigated CO storage work that provides the means for qualitative-to-quantitative in the heavy oil reservoirs through long core experiments; field-scale predictions of these effects for all the different they found that the C O storage ratio increases with cycle combinations of CO –water injection of interest. 2 2 numbers and the reservoir pressure. For each test, the last After the literature review, most research is related to pure cycle is the best choice for CO storage, and the CO storage gas (CO ) storage and EOR, and there is little work pub- 2 2 2 ratio can reach as high as 60% under the injection pressure lished on multicomponent flue gas storage in reservoirs. The 5000  kPa. For theoretical model and semiempirical cor- majority research of u fl e gas storage is carried out by numer - relations, Shaw and Bachu (2002) proposed a correlation ical simulation, and there is little simple theoretical model to determine C O storage capacity in oil reservoirs during for multicomponent flue gas storage. This work is targeting CO flooding processes, which is a function of oil recovery multicomponent flue gas storage capacity, individual compo- factor, the volume of original oil in place (OOIP), and oil nent storage capacity distribution characteristics, and EOR 1 3 872 Petroleum Science (2021) 18:870–882 of flue gas–WAG injection after continuous waterflooding to the left side of the core holder. A cathetometer monitored in oil reservoir. First, a long core experiment system for flue the volume of the injection sample. A low-temperature sepa- gas–WAG injection tests after continuous waterflooding rator arranged at the end of the core holder was utilized to was built. Second, a novel material balance model based separate oil and gas. To ensure the accuracy of the measure- on storage mechanism was developed to estimate flue gas ment, the temperature readers, the pressure transducers, and storage capacity and individual component storage capacity the volume of the injection pump were calibrated frequently distribution characteristics in the reservoir. Third, injecting before the start of the experiment; the error ranges of tem- strategies from three perspectives for flue gas storage, EOR, perature, pressure, and volume are ± 0.1  °C, ± 0.05  MPa, and combination of flue gas storage and EOR were studied. and ± 0.1 cm , respectively). The outcome of this work provides an experimental evalua- tion method for flue gas storage and EOR in flue gas drive.2.2 Materials Materials used in this work include long cores, reservoir fluids, 2 Experimental flue gas, and reservoir brine. The long cores were collected from Well H18 drilled in Karamay Oilfield, northwest China. 2.1 Experimental apparatus The total length of the long core is 90.55 cm, and it is com- posed of 14 sandstones and conglomerate cores. The average To perform a flue gas storage experiment, we set up a long permeability of the assembled long core is 348.12 mD, and the core displacement device. It mainly includes an injection pore volume (PV) and hydrocarbon pore volume (HCPV) are system, a core holder system, and a recovery system. A sche- 232.9 and 137 cm , respectively. More information about the matic of the experimental setup is presented in Fig. 1. The long cores is listed in Table 1. Crude oil and gas were collected key part of the apparatus is the core holder, manufactured by from a medium-permeability oil reservoir in China (Karamay Hai-An Petroleum Equipment Manufacturing Co., Jiangsu, Oilfield) using the separator sampling method. The reservoir China, which is installed in an air bath oven with a tem- temperature, pressure, and gas/oil ratio (GOR) are 42 °C, 3 3 perature range from 0 to 200 °C and the maximum working 8 MPa, and 36.9 m /m , respectively. The reservoir fluid was pressure of 70 MPa. The reservoir fluids, injection gas, and prepared in a laboratory by recombining the separator oil and reservoir brine were injected into the core holder by three separator gas according to a Chinese standard (GB/T 26981- Ruska automatic pumps, respectively, which were connected 2011). The compositions of separator gas, separator oil, and Back pressure pump Air bath Core holder Back pressure Gasometer Chromatograph valve Separator Reservoir Gas Oil brine Confining pump Injection pump Injection pump Injection pump Fig. 1 Schematic of experimental setup for flue gas water-alternating gas injection test 1 3 Petroleum Science (2021) 18:870–882 873 Table 1 Physical properties of the cores used No. Lithology Length, cm Diameter, cm Porosity, % Permeability, mD 1 Sandstone 6.297 3.791 23.65 254.78 2 conglomerate 4.738 3.794 22.80 285.08 3 Sandstone 7.318 3.644 25.64 238.08 4 Sandstone 7.470 3.642 22.45 208.32 5 Sandstone 7.771 3.647 23.63 199.94 6 Sandstone 6.449 3.638 21.38 194.82 7 Sandstone 7.303 3.649 23.41 190.65 8 Conglomerate 7.158 3.782 23.16 423.06 9 Sandstone 6.454 3.635 25.34 152.14 10 Conglomerate 6.170 3.795 24.20 506.61 11 Sandstone 7.513 3.645 22.15 146.24 12 Conglomerate 5.527 3.798 26.07 835.52 13 Conglomerate 5.673 3.798 24.56 657.12 14 Conglomerate 4.714 3.805 23.13 952.04 according to the composition of the real reservoir brine taken Table 2 Compositions (mol%) of separator gas, separator oil, and from well H18, and its composition is listed in Table 4. recombined reservoir fluid Component Separator gas Separator oil Recombined 2.3 Flue gas–WAG injection tests reservoir fluid CO 1.14 0.000 0.321 In this work, to improve the accuracy of the experimental N 1.11 0.000 0.312 results, petroleum ether was used to clean the flow line. Then, C 96.2 0.000 27.054 the setup was dried with high-pressure nitrogen after cleaning. C 0.99 0.088 0.639 The pumps, pressure gauges, and the thermometers were cali- C 0.14 0.344 0.991 brated under the test conditions. First, the cores were cleaned i-C 0.09 0.209 0.463 with toluene to remove organic material, and then the core n-C 0.07 0.801 1.700 was blow-dried with nitrogen and evacuated. All experimental i-C 0.03 0.296 0.508 devices were connected according to Fig. 1 with valves closed. n-C 0.01 1.515 2.563 The experimental procedures are as follows: C 0.01 6.885 9.743 C 0.23 1.495 1.883 (1) After the assembled long cores (filter paper was placed C 0.00 3.932 4.197 at the core joint to weaken capillary end effect) were C 0.00 4.357 4.142 successively stored in the core holder, the temperature C 0.00 7.712 6.608 of the oven was increased to reservoir temperature C 0.00 72.366 38.880 11+ gradually. (2) The long core was saturated with filtered reservoir brine. Next, the inner pressure and confining pressure of the cores were increased gradually using the injec- the recombined reservoir fluids are listed in Table  2. Flue gas tion pump and confining pressure pump until the inner was prepared by special gas reservoir laboratory of Southwest pressure was equal to the reservoir pressure, where Petroleum University in China, and the composition of flue gas the confining pressure of the cores was approximately is listed in Table 3. Brine used was prepared in the laboratory 5 MPa greater than the inner pressure. Table 3 Compositions of flue gas Component N CO CO O CH H 2 2 2 4 2 Content, mol% 83.913 0.24 14.67 0.49 0.42 0.267 1 3 874 Petroleum Science (2021) 18:870–882 Table 4 Composition and salinity of reservoir brine taken from Well H18 −1 −1 Component, mg L Total salinity, mg L Water type pH + + 2+ 2+ − 2- − 2− K + Na Ca Mg Cl SO HCO CO 4 3 3 4739.16 140.16 110.24 6407.52 28.50 2488.07 0 13,913.65 NaHCO 7.34 (3) The prepared reservoir fluids were injected into core (3) Chemical reactions between injection and reservoir flu- holder to replace the reservoir water in cores using an ids and rocks are not considered. injection pump at an injection rate of 0.1 cm /min until (4) Under the same temperature and pressure, the dissolu- the water in the separator did not increase to ensure the tion order of injection gas is determined according to cores only contained bound water and prepared reser- the solubility of pure component gas. voir fluids. (5) The phase effect between injection gas and dissolved (4) Waterflooding was carried out until the water cut gas of production gas is not included. reached 100% (no oil production); afterward, the flue gas–WAG flooding with WAG slug size of 0.1 HCPV 3.1 Flue gas storage capacity was performed until the oil phase did not increase at the exit of the core holder, and the injection volume of Flue gas storage capacity was estimated according to the flue gas–WAG flooding is 1.4 HCPV. The volume of relationship between GOR (production gas oil ratio) and injected water, flue gas, and produced fluid (oil, gas, GOR (initial gas oil ratio). If GOR ≤ GOR , we can obtain i p i water) with each injection of 0.1 HCPV was recorded, that the injection gas is not produced, which is completely and the production gas oil ratio of the exit of the core stored in cores. Here, the storage capacity of injection gas is holder at different times was determined. The meas- equal to cumulative injection gas volume. If GOR > GOR , p i urement uncertainties include the following: First, the it indicates that the injection gas has been produced at the pipeline volume has a certain influence on the quantita- exit of the holder. At the moment, the produced gas is com- tive injection; second, the dead volume at both ends of posed of the gas dissolved in oil and the produced injection the core and the core holder should also be considered. gas; the storage capacity of injection gas in reservoir can be calculated: V = V − V ⋅ B (1) 3 Evaluation methodology sto,inj,g cum,inj,g pro,inj,g g Many theoretical models or semiempirical models of CO 2 V = V − GOR ⋅ V pro,inj,g pro,g i pro,o (2) storage are proposed based on the material balance equa- tion. The basic assumption is that the theoretical capacity where V is the storage capacity of injection gas in sto,inj,g for CO storage in oil reservoirs is equal to the volume pre- cores, cm ; V is the cumulative injection gas volume, 2 cum,inj,g viously occupied by the produced oil and water. The rel- cm ; and V is the volume of injection gas produced, pro,inj,g 3 3 3 evant researchers from USDOE, European Commission and cm ; B is the volume factor of injection gas, cm /cm ; V g pro,g the Carbon Sequestration Leadership Forum (CSLF) have is the produced gas volume, cm ; and GOR is initial gas oil 3 3 3 further investigated the calculation methods for C O stor- ratio, m /m ; V is produced oil volume, cm . 2 pro,o age capacity in reservoir (U.S. DOE 2008; Bachu 2008), which were not involved in flue gas storage and waterflooded 3.2 Storage capacity of each component of flue gas oil reservoirs. However, many oil fields are developed by in reservoir oil, water and as free gas waterflooding. Therefore, a new material balance model for estimating flue gas storage capacity and storage capacity Solubility of pure gas in reservoir oil and water is an of each component of flue gas in waterflooded oil reservoir important parameter for estimating storage capacity of was developed. The model was constructed according to the each component of flue gas in reservoir (Ding et al. 2018). following assumptions: In this study, the solubility of C O, CH, N and O in 2 4 2 2 reservoir oil and water was determined respectively at (1) The injection and crude oil reach equilibrium instanta- 42 °C and 8 MPa using single-flash method according to neously. the composition of injection gas. Meanwhile, considering (2) The injection of gas and reservoir fluids contact com- the risk of CO and H , the solubility of CO and H was 2 2 pletely. 1 3 Petroleum Science (2021) 18:870–882 875 calculated by PVT Sim. The solubility of pure component V = S ⋅ (V − V ) ⋅ B sto(in water),com com(in water) cum,inj,w cum,pro,w com (6) gas in reservoir brine and crude oil is provided in Table 5 Storage capacity of each component of flue gas in res- (3) Storage capacity of each component of flue gas in res- ervoir can be calculated. ervoir oil can be calculated: When the theoretical storage capacity of a component V =[V ⋅ 1 − S − V ] ⋅ S ⋅ B sto(in oil),com p wi cum,pro,o com(in oil) com (7) is greater than the cumulative injection volume of that, which indicates that the storage capacity of the component 3 where V is the pore volume of long cores, cm ; S is p wi as free gas phase in cores is 0. the bound water saturation of long cores, %; V cum,pro,o Storage capacity of each component of flue gas in res- 3 is the cumulative volume of produced oil, cm ; and ervoir brine can be calculated: S is the solubility of individual component in com(in oil) 3 3 reservoir oil, cm /cm . V = S ⋅ (V − V ) ⋅ B sto(in water),com com(in water) cum,inj,w cum,pro,w com (3) If GOR > GOR , the storage capacity of each compo- p i where V is the storage capacity of each compo- sto(in water),com nent of flue gas in cores can be calculated by the following nent in reservoir brine, cm ; S is the solubility of com(in water) equations: 3 3 each component in reservoir brine, cm /cm ; and V is cum,inj,w the cumulative volume of injection water, cm ; V is cum,pro,w (1) Storage capacity of each component of flue gas as free the cumulative volume of produced water, cm ; B is the com gas phase in cores can be calculated: 3 3 volume factor of each component gas, cm /cm . V = V ⋅ X − V − V Storage capacity of each component of flue gas in res- sto(as free gas),com sto,inj,g com sto(in water),com sto(in oil),com (8) ervoir oil can be calculated: (2) Storage capacity of each component of flue gas in res- V = V ⋅ X − V sto(in oil),com cum,inj,g com sto(in water),com (4) ervoir brine can be calculated: where V is the storage capacity of each component sto(in oil),com V = S ⋅ (V − V ) ⋅ B sto(in water),com com(in water) cum,inj,w cum,pro,w com (9) in reservoir oil, cm and X is the mole fraction of each com component of the injection gas. (3) Storage capacity of each component of flue gas in res- If GOR ≤ GOR , the storage capacity of each compo- ervoir oil can be calculated: p i nent of flue gas in the cores can be calculated by the fol- V =[V ⋅ 1 − S − V ] ⋅ S ⋅ B sto(in oil),com p wi cum,pro,o com(in oil) com lowing equations: (10) (1) Storage capacity of each component of flue gas as free gas phase in cores can be calculated: 4 Results and discussion V = V ⋅ X − V − V sto(as free gas),com cum,inj,g com sto(in water),com sto(in oil),com (5) In this study, continuous waterflooding experiment and flue where V is the storage capacity of each sto(as free gas),com gas-water-alternating injection after continuous water injec- component as free gas phase in cores, cm . tion experiment were performed to study the flue gas stor - (2) Storage capacity of each component of flue gas in res- age and EOR. In a continuous waterflooding experiment, ervoir brine can be calculated: the continuous injection of water was performed until the water cut is 100% (no more oil is produced). Then, as an improved flue gas–EOR method, the flue gas–WAG flooding was applied to increase the oil recovery over the continuous Table 5 Solubility of different gases in reservoir oil and brine (42 °C, waterflooding. More details about the experimental data and 8 MPa) results are listed in Table 6. 3 3 Component Solubility in oil, m /m Solubility in 3 3 water, m /m 4.1 EOR of flue gas–WAG flooding CO 51.40 27.42 CH 11.86 1.65 Compared with waterflooding, the EOR mechanism of flue N 4.22 0.97 gas–WAG flooding is that water-alternating flue gas injec- O 8.57 0.0268 tion can change the water oil mobility ratio and strengthen CO 5.27 0.0196 the exchange, diffusion, and imbibition of oil, gas, and H 3.82 0.0115 water three-phase molecules. With the effect of gravity 1 3 876 Petroleum Science (2021) 18:870–882 Table 6 Experimental data and results of waterflooding and flue gas–WAG flooding Cumulative injection volume, Production gas oil ratio, m / Water cut, % Cumulative oil recovery fac- Injection medium HCPV m tor, % 0.1 37 0.00 9.97 Water 0.2 37 0.00 19.43 Water 0.3 37 1.83 29.00 Water 0.4 37 1.13 39.83 Water 0.5 37 61.55 44.19 Water 0.6 31 87.74 45.66 Water 0.7 37 88.09 46.90 Water 0.8 37 93.88 47.65 Water 0.9 37 95.12 48.15 Water 1 (0) 37 98.89 48.27 Water 1.1 (0.1) 37 97.44 48.77 Flue gas 1.2 (0.2) 35 80.21 49.82 Water 1.3 (0.3) 39 74.19 51.55 Flue gas 1.4 (0.4) 35 69.40 53.86 Water 1.5 (0.5) 36 69.22 56.85 Flue gas 1.6 (0.6) 43 56.46 60.21 Water 1.7 (0.7) 128 77.73 62.78 Flue gas 1.8 (0.8) 458 54.52 64.03 Water 1.9 (0.9) 514 84.83 65.02 Flue gas 2 (1.0) 453 58.65 66.52 Water 2.1 (1.1) 562 86.96 68.01 Flue gas 2.2 (1.2) 630 61.58 69.26 Water 2.3 (1.3) 4764 96.73 69.51 Flue gas 2.4 (1.4) 55,357 99.30 69.52 Water The number in brackets in the first column is the cumulative injection volume of flue gas–WAG flooding differentiation, the high-permeability zone is sealed by of the waterflooding process reaches 48.27% at 1.0 HCPV. injection water, and the micropores are swept by injection In the flue gas–WAG flooding process, before the flue gas gas. The process of flue gas–WAG flooding is a dynamic breakthrough (1.7 HCPV), the oil recovery factor is increas- process, the binding state of water in pores is constantly ing gradually with an increase in the WAG injection volume. broken and rebuilt, the alternating plugging of macropo- Meanwhile, the water cut decreases significantly. The water res by injected water weakens the breakthrough effect of cut declines from 98.89% to 56.46%. This result indicates injection gas, the water injection profile is improved, the that flue gas–WAG flooding can significantly reduce water water breakthrough time is delayed, and the oil recovery is cut and increase oil recovery factor. When the cumulative improved. For the reservoir with serious heterogeneity, the injection volume reaches 1.7 HCPV, the production gas–oil 3 3 dynamic plugging produced by flue gas–WAG flooding can ratio increases to 128  m /m , which means that flue gas further improve the effect of WAG flooding. As shown in breakthrough occurs. The corresponding oil recovery factor Fig. 2, in the waterflooding process, the oil recovery fac- at gas breakthrough is 62.78%. Similar to the waterflooding tor increases with an increase in injection volume. When process, once gas breakthrough occurs in the core, the oil the cumulative injection volume reaches 0.5 HCPV, the recovery factor will be affected. After the flue gas break - water cut increases significantly to 61.55%. The water cut through (1.7 HCPV), the water cut fluctuates greatly with an increase is an indication of water breakthrough occurring in increase in the WAG injection volume. The ultimate recov- the cores, and the oil recovery factor at water breakthrough ery factor of the WAG flooding process reaches 69.52%. is 44.19%. After water breakthrough, the oil recovery factor Compared with the waterflooding process, the oil recovery increases slightly. Further water injection does not signifi- factor of flue gas–WAG flooding is increased by 21.25%. cantly improve oil recovery. The ultimate recovery factor Therefore, we can conclude that flue gas–WAG flooding 1 3 Petroleum Science (2021) 18:870–882 877 (b) (a) 100 100 WAG Water Gas BT Water 80 #1 #2 #3 #4 #5 #6 #7 80 60 60 Water BT Gas BT WAG 40 40 #4 #5 #6 #7 #1 #2 #3 Water BT 20 20 0 0 00.4 0.81.2 1.62.0 2.4 00.4 0.81.2 1.62.0 2.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV Fig. 2 Oil recovery factor and water cut of waterflooding and flue gas–WAG flooding process (BT: breakthrough) combines the advantages of the microscopic displacement linear decline trend. At the end of the flue gas–WAG flood- efficiency of gas flooding and the macroscopic sweep effi- ing process, the flue gas storage ratio is only 16%. The rea- ciency of waterflooding. Flue gas–WAG flooding after con- son for significant decrease in storage ratio is that when the tinuous waterflooding can further enhance oil recovery and injection gas breakthrough occurs in the cores, partial free reduce the water cut, but the efficiency of the flue gas–WAG gas is displaced by water slug, and a large amount of injec- flooding is strongly dependent on the injection volume. tion gas is produced. These results demonstrated that once the injection volume reached a certain critical level, the sole 4.2 Flue gas storage increase in injection volume is not effective in enhancing the storage capacity. Therefore, determination of the injection 4.2.1 Total storage capacity volume of gas breakthrough occurrence is important for flue gas storage in the flue gas–WAG flooding. We can determine the flue gas storage capacity according to Sect. 3.1 to investigate flue gas storage in the flue gas–WAG 4.2.2 Storage capacity of each component of flue gas flooding process. The flue gas storage ratio is defined as the storage capacity (reservoir condition) of flue gas in cores The method for calculating the theoretical storage capacity divided by the cumulative injection volume (reservoir con- of each component of flue gas in reservoir oil, water, and ditions) of flue gas. The storage ratio and storage capacity as free gas is based on the model in Sect. 3.2. Thus, the of flue gas in the flue gas–WAG flooding process are shown theoretical storage capacity of each component of flue gas in Fig. 3. is defined as follows: It can be seen from Fig. 3 that before gas breakthrough V = V + V + V (0.7 HCPV), the flue gas storage ratio is almost maintained sto(thoretical),com sto(as free gas),com sto(in water),com sto(in oil),com (11) at 100%. This shows that the injection gas is completely stored in cores, and the flue gas storage capacity increases where V is the theoretical storage capacity of sto(theoretical),com gradually. Afterward, with an increase in injection vol- each component of flue, cm . ume, when the cumulative injection volume reaches 0.7 The calculation process of N storage capacity was dem- HCPV, the flue gas storage ratio starts to decrease gradu - onstrated as an example. First, the N storage capacity in ally. When the injection gas breakthrough occurs, injection reservoir oil and reservoir water is determined by Eqs. (3) gas no longer dissolves in oil and water, which results in and (4). If theoretical storage capacity of N (volume of N 2 2 flue gas storage ratio decrease. The storage capacity of flue dissolved in reservoir water plus volume of N dissolved in gas reaches 50.89 cm , which is the maximum of storage oil) is less than the cumulative injection volume, it means capacity in the flue gas–WAG flooding process. After gas N exists as free gas in cores. Second, if GOR ≤ GOR , the 2 p i breakthrough occurs at 0.7 HCPV, the storage ratio does not volume of N dissolved in oil and water and the volume of decline significantly, which still maintains at a high level N as free gas phase in cores are calculated by Eqs. (5)–(7). (0.93). Afterward, the flue gas storage ratio shows a nearly If GOR > GOR , the volume of N dissolved in water and p i 2 1 3 Oil recovery factor, % Water cut, % 878 Petroleum Science (2021) 18:870–882 As shown in Fig. 5, in the early period of flue gas–WAG flooding, the storage capacity of the individual component increases with an increase in injection volume. After gas breakthrough, the storage capacity of the individual com- Storage capacity of injection gas ponent decreases gradually. It is seen that the storage capac- Cumulative volume of 60 produced injection gas ity of N is the largest among all components in the flue Storage ratio 60 gas–WAG flooding process. Moreover, the storage capac- ity of individual component reaches a maximum all at 0.7 HCPV. The storage capacity values of individual component are 42.7, 7.47, 0.25, 0.21, 0.14, and 0.12 cm for N, CO , 2 2 O, CH, H , and CO, respectively. Thus, the storage capac- 2 4 2 ity of injection gas mainly consists of N and C O . From 2 2 Fig. 6, only N exists as free gas phase in cores and other 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 components of injection gas are distributed in oil and water. Cumulative injection volume, HCPV It is clear that, except for N , the storage capacity of other components in oil is larger than that in water in the flue Fig. 3 Flue gas storage capacity in the flue gas–WAG flooding gas–WAG flooding process; the reason is that the solubil- ity of these components in crude oil is larger than that in reservoir brine. However, after gas breakthrough, the stor- oil and the volume of the N as free gas phase in cores are age capacity of N in oil is lower than that in water because calculated by Eqs. (8)–(10). Third, the storage capacity of N the injection volume of N is much larger than the theoreti- is equal to the sum of the volume of N dissolved in oil and cal storage capacity of N at any time. The reservoir fluids water and the volume of N as free gas phase in cores; then, are N saturated. With the production of oil and water, the the calculation of storage capacity of other components can storage capacity of N in oil decreases with an increase in refer to the N calculation process. The results are shown in injection volume; however, due to the supplement of injected Fig. 4. Except N , the theoretical storage capacities of other water, the water in cores does not decrease significantly and gases are larger than their actual injection volume, which the storage capacity of N in water is maintained at a rela- means that only N exists as free gas phase in cores. Other tively stable and low level. Moreover, the storage capacity of gases are only dissolved in reservoir brine and crude oil. 50 5 50 6 (a) (b) N N CO 2 2 2 CO CH O 2 4 2 O2 H CO 5 40 4 40 CH4 H2 CO 30 3 30 20 2 20 10 1 10 0 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV Fig. 4 Injection volume and theoretical storage capacity of each component of flue gas in the flue gas–WAG flooding 1 3 Underground volume of gas, cm Injection volume, cm Storage ratio, % Injection volume, cm Theoretical storage capacity, cm Theoretical storage capacity, cm Petroleum Science (2021) 18:870–882 879 0.30 with the waterflooding process, the ultimate oil recovery N2 CO2 factor of flue gas–WAG flooding is increased by 21.25%. O2 0.25 CO CH4 30 0.20 5 Conclusions 0.15 A long-core experimental device was designed and built for evaluating flue gas storage and EOR of flue gas–WAG 0.10 flooding after continuous waterflooding in oil reservoirs, by which the relationship between flue gas storage and EOR is 0.05 investigated. A novel material balance model based on dif- ferent storage mechanisms is proposed. The storage capacity 0 0 of multicomponent flue gas and storage capacity of each 0 0.2 0.4 0.6 0.81.0 1.21.4 component of flue gas in reservoir oil, water and as free gas Cumulative injection volume, HCPV in flue gas–WAG flooding can be described. First, an oil recovery factor as high as 69.52% is obtained Fig. 5 Storage capacity of each component of flue gas in the flue gas– in the flue gas–WAG flooding process applied in a post- WAG flooding waterflooding reservoir. This result indicates that the flue gas–WAG flooding can be an efficient approach to enhance N is mainly composed of that as free gas phase, and its stor- oil recovery. age capacity as free gas phase reaches as high as 39.55 cm Second, in the flue gas–WAG flooding process, the stor - at 0.7 HCPV in the flue gas–WAG flooding process, in which age capacity of flue gas increases with an increase in injec- the total storage capacity of N is 42.7 cm . tion volume; after the gas breakthrough occurs, the storage capacity of flue gas declines gradually. This indicates that 4.3 Injection strategies for flue gas storage and EOR once the injection volume reaches a certain critical level, a continuous increase in injection volume alone is not effective In this study, we can obtain that it is very important to deter- in enhancing the storage capacity. Thus, it is very important mine the time of flue gas breakthrough in cores for flue gas to determine the time of flue gas breakthrough in cores for storage. 0.7 HCPV is the reasonable injection volume to flue gas storage. obtain the maximum storage capacity of flue gas while main- Third, in the flue gas–WAG flooding process, only N taining a higher oil recovery factor in the flue gas–WAG exists as free gas phase in cores and other gases are only flooding process. The corresponding maximum storage dissolved in reservoir brine and crude oil. The storage capac- capacity of flue gas (50.89 cm ) and a high oil recovery ity of injection gas mainly consists of N and CO , and the 2 2 factor (62.78%) are obtained. From the perspective of flue storage capacity of N is much higher than that of other gas storage, the maximum storage ratio of flue gas (100%) components of injection gas. occurs up to 0.6 HCPV in the flue gas–WAG flooding pro- Fourth, in the flue gas–WAG flooding process, for the cess and the injection volume of 0.6 HCPV is worth con- maximum storage ratio of injection gas, the injection volume sidering. From the perspective of maximizing oil recovery of 0.6 HCPV is the best. For the maximum oil recovery fac- degree, the ultimate oil recovery factor reaches as high as tor, when the injection volume reaches 1.4 HCPV, the oil 69.52% and the injection volume of 1.4 HCPV is the best recovery factor is as high as 69.52%. For the combination choice in the flue gas–WAG flooding process. Compared of flue gas storage and EOR, the recommended injection 1 3 Storage capacity, cm Storage capacity, cm 880 Petroleum Science (2021) 18:870–882 (a) (b) 3.0 6 CO2 in water 40 CO in oil 2.5 5 2.0 30 4 1.5 3 1.0 2 0.5 N2 in water 1 N in oil N2 as free gas phase 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV (c) (d) 0.30 0.0030 0.20 O2 in oil CH4 in water O in water CH in oil 2 4 0.25 0.0025 0.15 0.20 0.0020 0.15 0.0015 0.1 0.10 0.0010 0.05 0.05 0.0005 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV (e) (f) 0.150 0.0020 0.15 0.0020 H2 in oil CO in oil H in water CO in water 0.125 0.12 0.0016 0.0015 0.100 0.09 0.0012 0.075 0.0010 0.06 0.0008 0.050 0.0005 0.03 0.0004 0.025 0 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV Fig. 6 Storage capacity of each component of flue gas in the flue gas–WAG flooding Acknowledgements This work was supported by the Department of volume is 0.7 HCPV and the corresponding flue gas storage Science and Technology of Sichuan Province (2019YFG0457), the ratio and oil recovery factor remain at a high level of 62.78% National Natural Science Foundation of China (5183000045), the and 93%, respectively. National Major Science and Technology Project of CNPC "Research and Application of Key Technologies for Benefit Development of 1 3 Storage capacity, cm Storage capacity, cm 3 Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Petroleum Science (2021) 18:870–882 881 Volcanic Rock Reservoirs” (2017E-04-05), and the PetroChina Major Ettehadtavakkol A, Lake LW, Bryant SL. C O -EOR and storage design Science and Technology Project (2018E-1805). optimization. Int J Greenh Gas Control. 2014;25:79–92. https :// doi.org/10.1016/j.ijggc .2014.04.006. Farajzadeh R, Eftekhari AA, Dafnomilis G, et  al. On the sustain- Open Access This article is licensed under a Creative Commons Attri- ability of C O storage through C O —enhanced oil recovery. bution 4.0 International License, which permits use, sharing, adapta- 2 2 Appl Energy. 2020;261:114467. https ://doi.org/10.1016/j.apene tion, distribution and reproduction in any medium or format, as long rgy.2019.11446 7. as you give appropriate credit to the original author(s) and the source, Fong WS, Tang RW, Emanuel AS, et al. EOR for California Diato- provide a link to the Creative Commons licence, and indicate if changes mites: CO , flue gas and water corefloods, and computer simula- were made. The images or other third party material in this article are 2 tions. In: SPE western regional meeting, 30 March–1 April, 1992, included in the article’s Creative Commons licence, unless indicated Bakersfield, California. https ://doi.org/10.2523/24039 -MS. otherwise in a credit line to the material. If material is not included in Forooghi A, Hamouda AA, Eilertsen T. Co-optimization of CO the article’s Creative Commons licence and your intended use is not 2 EOR and sequestration process in a North Sea chalk reservoir. permitted by statutory regulation or exceeds the permitted use, you will In: SPE/EAGE reservoir characterization and simulation con- need to obtain permission directly from the copyright holder. To view a ference, 19–21 October, 2009, Abu Dhabi, UAE. https ://doi. copy of this licence, visit http://creativ ecommons .or g/licenses/b y/4.0/. org/10.2118/12555 0-MS. Fossum B, Blaker T, Brendsdal E, et  al. Numerical simulation of hot-water and flue-gas injection under typical North Sea Res- ervoir conditions. In: SPE/DOE enhanced oil recovery sym- References posium, 22–24 April, 1992, Tulsa, Oklahoma. https ://doi. org/10.2118/24168 -MS. Agartan E, Gaddipati M, Yip Y, et al. C O storage in depleted oil Ghomian Y, Pope GA, Sepehrnoori K. Economical co-optimization and gas fields in the Gulf of Mexico. Int J Greenh Gas Control. of CO sequestration and enhanced oil recovery. In: Sixth annual 2018;72:38–48. https ://doi.org/10.1016/j.ijggc .2018.02.022. conference on carbon capture and sequestration proceeding, 7–10 Bachu S. Comparison between methodologies recommended for esti- May, 2007, Pittsburgh, PA. mation of CO storage capacity in geological media by the CSLF Godec M, Kuuskraa V, Leeuwen TV, et al. CO storage in depleted task force on CO storage capacity estimation and the USDOE oil fields: the worldwide potential for carbon dioxide enhanced capacity and fairways subgroup of the regional carbon sequestra- oil recovery. Energy Procedia. 2011;4:2162–9. https ://doi. tion partnerships program, phase III report. In: Carbon sequestra-org/10.1016/j.egypr o.2011.02.102. tion leadership forum (CSLF), 21 April, 2008, Washington, DC. Gozalpour F, Ren SR, Tohidi B. CO EOR and storage in oil reservoir. Bachu S. Review of CO storage efficiency in deep saline aquifers. Int J Oil Gas Sci Technol. 2005;60(3):537–46. https:// doi.org/10.2516/ Greenh Gas Control. 2015;40:188–202. https://doi.or g/10.1016/j.ogst:20050 36. ijggc .2015.01.007. Han HS, Li S, Ma DS. Investigation of flue gas displacement and stor - Bachu S, Shaw JC, Pearson RM. Estimation of oil recovery and age after the water flooding in a full diameter conglomerate long- CO storage capacity in CO EOR incorporating the effect of core. Pet Explor Dev. 2018;45(5):903–9. https://doi.or g/10.11698 2 2 underlying aquifers. In: SPE/DOE symposium on improved /PED.2018.05.10. oil recovery, 17–21 April, 2004, Tulsa, Oklahoma. https ://doi. Jahangiri HR, Zhang, DX. Optimization of the net present value of car- org/10.2118/89340 -MS. bon dioxide sequestration and enhanced oil recovery. In: Offshore Bachu S, Bonijoly D, Bradshaw J, et al. C O storage capacity esti- technology conference, 2–5 May, 2011, Houston, Texas. https :// mation: methodology and gaps. Int J Greenh Gas Control. doi.org/10.4043/21985 -MS. 2007;1(4):430–43. https://doi.or g/10.1016/S1750-5836(07)00086 Jia B, Tsau JS, Barati R. A review of the current progress of CO -2. injection EOR and carbon storage in shale oil reservoirs. Fuel. Bender S, Akin S. Flue gas injection for EOR and sequestration: case 2019;236:404–27. https ://doi.org/10.1016/j.fuel.2018.08.103. study. J Pet Sci Eng. 2017;157:1033–45. https://doi.or g/10.1016/j. Kopp A, Class H, Helming R. Investigations on C O storage capacity petro l.2017.07.044. in saline aquifers-Part 2: estimation of storage capacity coeffi- Berg S, Oedai S, Landman AJ, et al. Miscible displacement of oils cients. Int J Greenh Gas Control. 2009a;3(3):277–87. https ://doi. by carbon disulfide in porous media: experiments and analysis. org/10.1016/j.ijggc .2008.10.001. Phys Fluids. 2010;22:113102. https://doi.or g/10.1063/1.3516614 . Kopp A, Class H, Helming R. Investigations on C O storage capac- Berg S, Oedai S, Ott H. Displacement and mass transfer between ity in saline aquifers. Part 1. Dimensional analysis of flow pro- saturated and unsaturated CO –brine systems in sandstone. Int J cesses and reservoir characteristics. Int J Greenh Gas Control. Greenh Gas Control. 2013;12:478–92. https ://doi.org/10.1016/j. 2009b;3(3):263–76. https ://doi.org/10.1016/j.ijggc .2008.10.002. ijggc .2011.04.005. Leach A, Mason CF, Veld KVT. Co-optimization of enhanced Bürkle S, Becker LG, Dreizler A, et al. Experimental investigation oil recovery and carbon sequestration. Resour Energy of the flue gas thermochemical composition of an oxy-fuel Econ. 2011;33(4):893–912. https ://doi.or g/10.1016/j.r esen swirl burner. Fuel. 2018;231:61–72. https ://doi.org/10.1016/j. eeco.2010.11.002. fuel.2018.05.039. Lee JS, Kim JH, Kim JT, et al. Adsorption equilibria of CO on zeolite Ding SW, Xi Y, Jiang HQ. C O storage capacity estimation in oil 13X and zeolite X/activated carbon composite. J Chem Eng Data. reservoirs by solubility and mineral trapping. Appl Geochem. 2002;47:1237–42. https ://doi.org/10.1021/je020 050e. 2018;89:121–8. https ://doi.or g/10.1016/j.apg eo c hem.2017.12.002. Li ZW, Dong MZ, Li SL, et al. CO sequestration in depleted oil and Dong M, Huang S. Flue gas injection for heavy oil recovery. J Can gas reservoirs—caprock characterization and storage capac- Pet Technol. 2002;41(9):44–50. https://doi.or g/10.2118/02-09-04. ity. Energy Convers Manag. 2006a;47:1372–82. https ://doi. Edwards Ryan WJ, Celia MA, Bandilla KW, et al. A model to esti-org/10.1016/j.encon man.2005.08.023. mate carbon dioxide injectivity and storage capacity for geo- Li ZW, Dong MZ, Li SL, et  al. CO sequestration in depleted oil logical sequestration in shale gas wells. Environ Sci Technol. and gas reservoirs-caprock characterization and storage capac- 2015;49:9222–9. https ://doi.org/10.1021/acs.est.5b019 82. ity. Energy Convers Manag. 2006b;47(11):1372–82. https ://doi. org/10.1016/j.encon man.2005.08.023. 1 3 882 Petroleum Science (2021) 18:870–882 Liu QY, Liu ZY, Wu WZ. Ee ff ct of V O additive on simultaneous SO Sumathi S, Bhatia S, Lee KT, et  al. Adsorption isotherm models 2 5 2 and NO removal from flue gas over a monolithic cordierite-based and properties of SO and NO removal by palm shell activated CuO/Al O catalyst. Catal Today. 2009;147:S285–9. https ://doi. carbon supported with cerium (Ce/PSAC). J Hazard Mater. 2 3 org/10.1016/j.catto d.2009.07.013. 2010a;162:194–200. https ://doi.org/10.1016/j.cej.2010.05.028. Liu RG, Zhang JG, Meng L, et al. Feasibility study of steam/flue gas Sumathi S, Bhatia S, Lee KT, et al. Selection of best impregnated mixture injection in low permeability reservoir. In: SPE project palm shell activated carbon (PSAC) for simultaneous removal of and facilities challenges conference at METS, 13–16 February, SO and NO . J Hazard Mater. 2010b;176:1093–6. https ://doi. 2 X 2011, Doha, Qatar. https ://doi.org/10.2118/14234 3-MS.org/10.1016/j.jhazm at.2009.11.037. López D, Buitrago R, Sepúlveda-Escribano A, et al. Surface com- Trevisan OV, Laboissiere P, Monte-Mor S. Laboratory study on steam plexes formed during simultaneous catalytic adsorption of NO and flue gas co-injection for heavy oil recovery. In: SPE heavy oil and SO on activated carbons at low temperatures. J Phys Chem conference-Canada, 11–13 June, 2013, Calgary, Alberta. https :// C. 2007;111:1417–23. https ://doi.org/10.1021/jp063 544h.doi.org/10.2118/16552 3-MS. Majeed H, Svendsen HF. Characterization of aerosol emissions from Trivedi JJ, Babadagli T. CO and flue gas sequestration during ter - CO capture plants treating various power plant and industrial tiary oil recovery: optimal injection strategies and importance flue gases. Int J Greenh Gas Control. 2018;74:282–95. https://doi. of operational parameters. In: Canadian international petro- org/10.1016/j.ijggc .2018.04.016. leum conference, 7–9 June, 2005, Calgary, Alberta. https ://doi. Nasralla RA, Snippe JR, Farajzadeh R. Coupled geochemical-reservoir org/10.2118/2005-042. model to understand the interaction between low salinity brines U.S.DOE (U.S. Department of Energy). Carbon sequestration Atlas of and carbonate rock. In: SPE Asia Pacific enhanced oil recovery the United States and Canada. 2nd ed. Pittsburgh, PA: National conference, 11–13 August, 2015, Kuala Lumpur, Malaysia. https Energy Technology Laboratory; 2008. ://doi.org/10.2118/17466 1-MS. van der Meer LGH, Yavuz F. C O storage capacity calculations for the Santibanez-Borda E, Govindan R, Elahi N. Maximising the dynamic Dutch subsurface. Energy Procedia. 2009;1(1):2615–22. https :// CO storage capacity through the optimisation of C O injection doi.org/10.1016/j.egypr o.2009.02.028. 2 2 and brine production rates. Int J Greenh Gas Control. 2019;80:76– Yi HH, Wang ZX, Liu HY, et al. Adsorption of SO , NO, and CO 2 2 95. https ://doi.org/10.1016/j.ijggc .2018.11.012. on activated carbons: equilibrium and thermodynamics. J Chem Shaw J, Bachu S. Screening, evaluation, and ranking of oil reser- Eng Data. 2014;59:1556–63. https ://doi.org/10.1021/je401 1135. voirs suitable for CO flood EOR and carbon dioxide seques- Zangeneh H, Jamshidi S, Soltanieh M. Coupled optimization of tration. J Can Pet Technol. 2002;41(9):51–61. h ttp s : //d oi. enhanced gas recovery and carbon dioxide sequestration in natural org/10.2118/02-09-05. gas reservoirs: case study in a real gas field in the south of Iran. Int Shokoya OS, Mehta SA, Moore RG, et al. Effect of oil and flue-gas J Greenh Gas Control. 2013;17:515–22. https://doi.or g/10.1016/j. compositions on oil recovery in the flue-gas/light-oil injection ijggc .2013.06.007. process. In: SPE annual technical conference and exhibition, 9–12 Zhang L, Ren B, Huang HD, et al. CO EOR and storage in Jilin oilfield October, 2005, Dallas, Texas. https://d oi.org/10.2118/97262- MS. China: monitoring program and preliminary results. J Pet Sci Eng. Snippe J, Berg S, Ganga K, et al. Experimental and numerical inves- 2015;125:1–12. https ://doi.org/10.1016/j.petro l.2014.11.005. tigation of wormholing during C O storage and water alternating Zheng Z, Larson ED, Li Z, et al. Near-term mega-scale CO capture 2 2 gas injection. Int J Greenh Gas Control. 2020;94:102901. https:// and storage demonstration opportunities in China. Energy Environ doi.org/10.1016/j.ijggc .2019.10290 1. Sci. 2010;3:1153–69. https ://doi.org/10.1039/B9242 43K. Srivastava RK, Huang SS, Dong MZ. Comparative effectiveness of Zhou D, Zhao ZX, Liao J, et al. A preliminary assessment on C O stor- CO produced gas, and flue gas for enhanced heavy-oil recov - age capacity in the Pearl River Mouth Basin offshore Guangdong. ery. SPE Reservoir Eval Eng. 1999;2(3):238–47. https ://doi. China Int J Greenh Gas Control. 2011;5(2):308–17. https ://doi. org/10.2118/56857 -PA.org/10.1016/j.ijggc .2010.09.011. Test method for reservoir fluid physical properties: GB/T 26981-2011. Zhou X, Yuan QW, Rui ZH, et al. Feasibility study of CO huff ‘n’puff Research Institute of Petroleum Exploration and Development process to enhance heavy oil recovery via long core experiments. 2012. Beijing: Standards Press of China. Appl Energy. 2019;236:526–39. https ://doi.org/10.1016/j.apene rgy.2018.12.007. 1 3 http://www.deepdyve.com/assets/images/DeepDyve-Logo-lg.png Petroleum Science Springer Journals

Investigation of flue gas water-alternating gas (flue gas–WAG) injection for enhanced oil recovery and multicomponent flue gas storage in the post-waterflooding reservoir

Download PDF
13 pages

Loading next page...
 
/lp/springer-journals/investigation-of-flue-gas-water-alternating-gas-flue-gas-wag-injection-LFNtCBXmeh

References (51)

Publisher
Springer Journals
Copyright
Copyright © The Author(s) 2021
ISSN
1672-5107
eISSN
1995-8226
DOI
10.1007/s12182-021-00548-z
Publisher site
See Article on Publisher Site

Abstract

Flue gas flooding is one of the important technologies to improve oil recovery and achieve greenhouse gas storage. In order to study multicomponent flue gas storage capacity and enhanced oil recovery (EOR) performance of flue gas water-alternating gas (flue gas–WAG) injection after continuous waterflooding in an oil reservoir, a long core flooding system was built. The experimental results showed that the oil recovery factor of flue gas–WAG flooding was increased by 21.25% after continu- ous waterflooding and flue gas–WAG flooding could further enhance oil recovery and reduce water cut significantly. A novel material balance model based on storage mechanism was developed to estimate the multicomponent flue gas storage capacity and storage capacity of each component of flue gas in reservoir oil, water and as free gas in the post-waterflooding reservoir. The ultimate storage ratio of flue gas is 16% in the flue gas–WAG flooding process. The calculation results of flue gas storage capacity showed that the injection gas storage capacity mainly consists of N and CO , only N exists as free gas 2 2 2 phase in cores, and other components of injection gas are dissolved in oil and water. Finally, injection strategies from three perspectives for flue gas storage, EOR, and combination of flue gas storage and EOR were proposed, respectively. Keywords Flue gas storage · Enhanced oil recovery · Flue gas water-alternating gas · Material balance model · Injection strategy 1 Introduction Flue gas is one of the primary sources of human-made greenhouse gases, which contains a large amount of N , CO , and SO emitted in the process of fuel combustion and 2 2 Edited by Yan-Hua Sun during cement production (Majeed and Svendsen 2018). The composition of the flue gas is varied with different combus- * Bo-Wen Sun tion materials in the combustion process, which is mainly sbwswpu@163.com composed of N and C O , and the air-polluting components 2 2 * Ping Guo such as N O , CO, H S, and dust may also exist in flue gases x 2 guopingswpi@vip.sina.com (Bürkle et al. 2018). State Key Laboratory of Oil and Gas Reservoir Geology CO and non-CO emissions generated by fuel combus- 2 2 and Exploitation, Southwest Petroleum University, tion process can be sequestered in underground geologic Chengdu 610500, Sichuan, China formations such as deep saline aquifers (Bachu 2015), coal, Research Institute of Exploration and Development, oil, and gas reservoirs (Agartan et al. 2018; Li et al. 2006a, PetroChina Tarim Oilfield Company, Korla 841000, b), even fractured shale formations (Edwards Ryan et al. Xinjiang, China 2015). The geological sequestration has been proved to be Research Institute of Experiment and Detection, PetroChina a feasible technique for reducing greenhouse gas and help- Xinjiang Oilfield Company, Karamay 834000, Xinjiang, ing tackle climate change. There are four basic mechanisms China 4 required for long-term successful geological CO storage: Xinjiang Laboratory of Petroleum Reserve in Conglomerate, stratigraphic/structural, residual, solubility, and mineral Karamay 834000, Xinjiang, China Vol:.(1234567890) 1 3 Petroleum Science (2021) 18:870–882 871 trapping (Santibanez-Borda et al. 2019). If there is a good shrinkage. Bachu et al. (2007) proposed a correlation for seal, CO will be trapped permanently and will be immobile estimating CO storage capacity in coal beds, oil and gas 2 2 with the contribution of these mechanisms. Many studies reservoirs, and deep saline aquifers. Following these correla- in the literature discuss C O storage and EOR (Bachu et al. tions, new C O storage capacity correlations in deep saline 2 2 2004; Ettehadtavakkol et al. 2014; Farajzadeh et al. 2020; aquifers based on material balance equation were proposed Gozalpour et al. 2005; Godec et al. 2011; Jia et al. 2019; (Kopp et al. 2009a; b; van der Meer and Yavuz 2009; Zheng Zhang et al. 2015) that have been proved to be effective et al. 2010; Zhou et al. 2011). As examples of numerical techniques due to their high displacement efficiency, low simulation, Li et  al. (2006a, b) used CMG simulator to cost, and high efficiency in reducing global warming phe- study the C O sequestration in depleted oil and gas reser- nomenon. However, only a few pieces of research have been voirs; they found that once the reservoir pressure reaches investigated on flue gas injection in reservoirs (Dong and a certain high level, only increasing the injection pressure Huang 2002; Fong et al. 1992; Fossum et al. 1992; Liu et al. cannot effectively enhance the storage capacity. However, 2011; Srivastava et al. 1999; Shokoya et al. 2005; Trivedi much more capacity can be achieved by removing a portion and Babadagli 2005; Trevisan et al. 2013). The majority of the remaining water. of flue gas injection studies were focused on maximizing Injection of CO or flue gas for the purpose of coupled the oil recovery, not flue gas storage. Recently, many stud- sequestration–EOR process is appealing due to the fact that ies have been conducted to remove CO and SO from flue both goals of final recovery enhancement and greenhouse 2 2 gas independently (Lee et al. 2002; Liu et al. 2009; López gas control would be established by employing this scheme et al. 2007; Sumathi et al. 2010a, b; Yi et al. 2014). How- (Berg et al. 2010, 2013). Some authors have published works ever, the methods proposed in these studies have the disad- addressing economic analysis of C O –EOR projects (Ghom- vantages of either high-energy consumption or expensive ian et al. 2007; Jahangiri and Zhang 2011; Leach et al. 2011). equipment cost. Injecting raw flue gas into oil reservoirs is Forooghi et al. (2009) proposed a methodology to optimize very attractive because these reservoirs have structural seals the coupled CO –EOR process. His work is based on simula- that are well studied and characterized for trapping. Flue gas tion of C O injection into North Sea chalk field. They inves- can remain stored securely by virtue of following trapping tigated the effect of six parameters, namely injection scheme, mechanism: trapping beneath an impermeable layer, reten- injector and producer well type, well control mode, slug size tion as an immobile phase in pore space of porous storage and the WAG ratio, on the coupled C O –EOR and sequestra- formations, dissolution into formation fluids and adsorption tion process. They concluded that the water-alternating gas on the organic matter in shale or coal reservoirs (Nasralla injection scheme using a mixture of C O and hydrocarbon et al. 2015). Thus, injecting flue gas into oil reservoirs may gas is the optimum case. Zangeneh et al. (2013) optimized result in incremental oil recovery and make the storage pro- carbon dioxide sequestration and enhanced gas recovery in ject more feasible. The project economic viability is deeply a natural gas reservoir in Iran. They concluded that injection dependent on the availability of the flue gas source. of carbon dioxide at optimized conditions resulted in perma- Methods used to determine the storage capacity of injec- nent storage of carbon dioxide in addition to production of tion gas in gas flooding processes include experimental residual gas in the reservoir. Bender and Akin (2017) studied measurement, theoretical model, semiempirical formulas, the efficiency of flue gas injection compared to CO injection and numerical simulation. Han et al. (2018) studied flue gas for simultaneous EOR and storage by a 3D compositional displacement and storage capacity after the waterflooding simulation model and investigated the effect of injected gas in a full-diameter long core taken from Xinjiang Oilfield in type, gas solubility, and operating parameters on flue gas China; they found that flue gas flooding after waterflooding storage and oil recovery. Snippe et al. (2020) studied the can further enhance oil recovery, but the key factor to obtain wormholing effect during CO storage and water-alternating good development effect is to choose the right timing for gas injection. They reported new experimental and modeling gas injection. Zhou et al. (2019) investigated CO storage work that provides the means for qualitative-to-quantitative in the heavy oil reservoirs through long core experiments; field-scale predictions of these effects for all the different they found that the C O storage ratio increases with cycle combinations of CO –water injection of interest. 2 2 numbers and the reservoir pressure. For each test, the last After the literature review, most research is related to pure cycle is the best choice for CO storage, and the CO storage gas (CO ) storage and EOR, and there is little work pub- 2 2 2 ratio can reach as high as 60% under the injection pressure lished on multicomponent flue gas storage in reservoirs. The 5000  kPa. For theoretical model and semiempirical cor- majority research of u fl e gas storage is carried out by numer - relations, Shaw and Bachu (2002) proposed a correlation ical simulation, and there is little simple theoretical model to determine C O storage capacity in oil reservoirs during for multicomponent flue gas storage. This work is targeting CO flooding processes, which is a function of oil recovery multicomponent flue gas storage capacity, individual compo- factor, the volume of original oil in place (OOIP), and oil nent storage capacity distribution characteristics, and EOR 1 3 872 Petroleum Science (2021) 18:870–882 of flue gas–WAG injection after continuous waterflooding to the left side of the core holder. A cathetometer monitored in oil reservoir. First, a long core experiment system for flue the volume of the injection sample. A low-temperature sepa- gas–WAG injection tests after continuous waterflooding rator arranged at the end of the core holder was utilized to was built. Second, a novel material balance model based separate oil and gas. To ensure the accuracy of the measure- on storage mechanism was developed to estimate flue gas ment, the temperature readers, the pressure transducers, and storage capacity and individual component storage capacity the volume of the injection pump were calibrated frequently distribution characteristics in the reservoir. Third, injecting before the start of the experiment; the error ranges of tem- strategies from three perspectives for flue gas storage, EOR, perature, pressure, and volume are ± 0.1  °C, ± 0.05  MPa, and combination of flue gas storage and EOR were studied. and ± 0.1 cm , respectively). The outcome of this work provides an experimental evalua- tion method for flue gas storage and EOR in flue gas drive.2.2 Materials Materials used in this work include long cores, reservoir fluids, 2 Experimental flue gas, and reservoir brine. The long cores were collected from Well H18 drilled in Karamay Oilfield, northwest China. 2.1 Experimental apparatus The total length of the long core is 90.55 cm, and it is com- posed of 14 sandstones and conglomerate cores. The average To perform a flue gas storage experiment, we set up a long permeability of the assembled long core is 348.12 mD, and the core displacement device. It mainly includes an injection pore volume (PV) and hydrocarbon pore volume (HCPV) are system, a core holder system, and a recovery system. A sche- 232.9 and 137 cm , respectively. More information about the matic of the experimental setup is presented in Fig. 1. The long cores is listed in Table 1. Crude oil and gas were collected key part of the apparatus is the core holder, manufactured by from a medium-permeability oil reservoir in China (Karamay Hai-An Petroleum Equipment Manufacturing Co., Jiangsu, Oilfield) using the separator sampling method. The reservoir China, which is installed in an air bath oven with a tem- temperature, pressure, and gas/oil ratio (GOR) are 42 °C, 3 3 perature range from 0 to 200 °C and the maximum working 8 MPa, and 36.9 m /m , respectively. The reservoir fluid was pressure of 70 MPa. The reservoir fluids, injection gas, and prepared in a laboratory by recombining the separator oil and reservoir brine were injected into the core holder by three separator gas according to a Chinese standard (GB/T 26981- Ruska automatic pumps, respectively, which were connected 2011). The compositions of separator gas, separator oil, and Back pressure pump Air bath Core holder Back pressure Gasometer Chromatograph valve Separator Reservoir Gas Oil brine Confining pump Injection pump Injection pump Injection pump Fig. 1 Schematic of experimental setup for flue gas water-alternating gas injection test 1 3 Petroleum Science (2021) 18:870–882 873 Table 1 Physical properties of the cores used No. Lithology Length, cm Diameter, cm Porosity, % Permeability, mD 1 Sandstone 6.297 3.791 23.65 254.78 2 conglomerate 4.738 3.794 22.80 285.08 3 Sandstone 7.318 3.644 25.64 238.08 4 Sandstone 7.470 3.642 22.45 208.32 5 Sandstone 7.771 3.647 23.63 199.94 6 Sandstone 6.449 3.638 21.38 194.82 7 Sandstone 7.303 3.649 23.41 190.65 8 Conglomerate 7.158 3.782 23.16 423.06 9 Sandstone 6.454 3.635 25.34 152.14 10 Conglomerate 6.170 3.795 24.20 506.61 11 Sandstone 7.513 3.645 22.15 146.24 12 Conglomerate 5.527 3.798 26.07 835.52 13 Conglomerate 5.673 3.798 24.56 657.12 14 Conglomerate 4.714 3.805 23.13 952.04 according to the composition of the real reservoir brine taken Table 2 Compositions (mol%) of separator gas, separator oil, and from well H18, and its composition is listed in Table 4. recombined reservoir fluid Component Separator gas Separator oil Recombined 2.3 Flue gas–WAG injection tests reservoir fluid CO 1.14 0.000 0.321 In this work, to improve the accuracy of the experimental N 1.11 0.000 0.312 results, petroleum ether was used to clean the flow line. Then, C 96.2 0.000 27.054 the setup was dried with high-pressure nitrogen after cleaning. C 0.99 0.088 0.639 The pumps, pressure gauges, and the thermometers were cali- C 0.14 0.344 0.991 brated under the test conditions. First, the cores were cleaned i-C 0.09 0.209 0.463 with toluene to remove organic material, and then the core n-C 0.07 0.801 1.700 was blow-dried with nitrogen and evacuated. All experimental i-C 0.03 0.296 0.508 devices were connected according to Fig. 1 with valves closed. n-C 0.01 1.515 2.563 The experimental procedures are as follows: C 0.01 6.885 9.743 C 0.23 1.495 1.883 (1) After the assembled long cores (filter paper was placed C 0.00 3.932 4.197 at the core joint to weaken capillary end effect) were C 0.00 4.357 4.142 successively stored in the core holder, the temperature C 0.00 7.712 6.608 of the oven was increased to reservoir temperature C 0.00 72.366 38.880 11+ gradually. (2) The long core was saturated with filtered reservoir brine. Next, the inner pressure and confining pressure of the cores were increased gradually using the injec- the recombined reservoir fluids are listed in Table  2. Flue gas tion pump and confining pressure pump until the inner was prepared by special gas reservoir laboratory of Southwest pressure was equal to the reservoir pressure, where Petroleum University in China, and the composition of flue gas the confining pressure of the cores was approximately is listed in Table 3. Brine used was prepared in the laboratory 5 MPa greater than the inner pressure. Table 3 Compositions of flue gas Component N CO CO O CH H 2 2 2 4 2 Content, mol% 83.913 0.24 14.67 0.49 0.42 0.267 1 3 874 Petroleum Science (2021) 18:870–882 Table 4 Composition and salinity of reservoir brine taken from Well H18 −1 −1 Component, mg L Total salinity, mg L Water type pH + + 2+ 2+ − 2- − 2− K + Na Ca Mg Cl SO HCO CO 4 3 3 4739.16 140.16 110.24 6407.52 28.50 2488.07 0 13,913.65 NaHCO 7.34 (3) The prepared reservoir fluids were injected into core (3) Chemical reactions between injection and reservoir flu- holder to replace the reservoir water in cores using an ids and rocks are not considered. injection pump at an injection rate of 0.1 cm /min until (4) Under the same temperature and pressure, the dissolu- the water in the separator did not increase to ensure the tion order of injection gas is determined according to cores only contained bound water and prepared reser- the solubility of pure component gas. voir fluids. (5) The phase effect between injection gas and dissolved (4) Waterflooding was carried out until the water cut gas of production gas is not included. reached 100% (no oil production); afterward, the flue gas–WAG flooding with WAG slug size of 0.1 HCPV 3.1 Flue gas storage capacity was performed until the oil phase did not increase at the exit of the core holder, and the injection volume of Flue gas storage capacity was estimated according to the flue gas–WAG flooding is 1.4 HCPV. The volume of relationship between GOR (production gas oil ratio) and injected water, flue gas, and produced fluid (oil, gas, GOR (initial gas oil ratio). If GOR ≤ GOR , we can obtain i p i water) with each injection of 0.1 HCPV was recorded, that the injection gas is not produced, which is completely and the production gas oil ratio of the exit of the core stored in cores. Here, the storage capacity of injection gas is holder at different times was determined. The meas- equal to cumulative injection gas volume. If GOR > GOR , p i urement uncertainties include the following: First, the it indicates that the injection gas has been produced at the pipeline volume has a certain influence on the quantita- exit of the holder. At the moment, the produced gas is com- tive injection; second, the dead volume at both ends of posed of the gas dissolved in oil and the produced injection the core and the core holder should also be considered. gas; the storage capacity of injection gas in reservoir can be calculated: V = V − V ⋅ B (1) 3 Evaluation methodology sto,inj,g cum,inj,g pro,inj,g g Many theoretical models or semiempirical models of CO 2 V = V − GOR ⋅ V pro,inj,g pro,g i pro,o (2) storage are proposed based on the material balance equa- tion. The basic assumption is that the theoretical capacity where V is the storage capacity of injection gas in sto,inj,g for CO storage in oil reservoirs is equal to the volume pre- cores, cm ; V is the cumulative injection gas volume, 2 cum,inj,g viously occupied by the produced oil and water. The rel- cm ; and V is the volume of injection gas produced, pro,inj,g 3 3 3 evant researchers from USDOE, European Commission and cm ; B is the volume factor of injection gas, cm /cm ; V g pro,g the Carbon Sequestration Leadership Forum (CSLF) have is the produced gas volume, cm ; and GOR is initial gas oil 3 3 3 further investigated the calculation methods for C O stor- ratio, m /m ; V is produced oil volume, cm . 2 pro,o age capacity in reservoir (U.S. DOE 2008; Bachu 2008), which were not involved in flue gas storage and waterflooded 3.2 Storage capacity of each component of flue gas oil reservoirs. However, many oil fields are developed by in reservoir oil, water and as free gas waterflooding. Therefore, a new material balance model for estimating flue gas storage capacity and storage capacity Solubility of pure gas in reservoir oil and water is an of each component of flue gas in waterflooded oil reservoir important parameter for estimating storage capacity of was developed. The model was constructed according to the each component of flue gas in reservoir (Ding et al. 2018). following assumptions: In this study, the solubility of C O, CH, N and O in 2 4 2 2 reservoir oil and water was determined respectively at (1) The injection and crude oil reach equilibrium instanta- 42 °C and 8 MPa using single-flash method according to neously. the composition of injection gas. Meanwhile, considering (2) The injection of gas and reservoir fluids contact com- the risk of CO and H , the solubility of CO and H was 2 2 pletely. 1 3 Petroleum Science (2021) 18:870–882 875 calculated by PVT Sim. The solubility of pure component V = S ⋅ (V − V ) ⋅ B sto(in water),com com(in water) cum,inj,w cum,pro,w com (6) gas in reservoir brine and crude oil is provided in Table 5 Storage capacity of each component of flue gas in res- (3) Storage capacity of each component of flue gas in res- ervoir can be calculated. ervoir oil can be calculated: When the theoretical storage capacity of a component V =[V ⋅ 1 − S − V ] ⋅ S ⋅ B sto(in oil),com p wi cum,pro,o com(in oil) com (7) is greater than the cumulative injection volume of that, which indicates that the storage capacity of the component 3 where V is the pore volume of long cores, cm ; S is p wi as free gas phase in cores is 0. the bound water saturation of long cores, %; V cum,pro,o Storage capacity of each component of flue gas in res- 3 is the cumulative volume of produced oil, cm ; and ervoir brine can be calculated: S is the solubility of individual component in com(in oil) 3 3 reservoir oil, cm /cm . V = S ⋅ (V − V ) ⋅ B sto(in water),com com(in water) cum,inj,w cum,pro,w com (3) If GOR > GOR , the storage capacity of each compo- p i where V is the storage capacity of each compo- sto(in water),com nent of flue gas in cores can be calculated by the following nent in reservoir brine, cm ; S is the solubility of com(in water) equations: 3 3 each component in reservoir brine, cm /cm ; and V is cum,inj,w the cumulative volume of injection water, cm ; V is cum,pro,w (1) Storage capacity of each component of flue gas as free the cumulative volume of produced water, cm ; B is the com gas phase in cores can be calculated: 3 3 volume factor of each component gas, cm /cm . V = V ⋅ X − V − V Storage capacity of each component of flue gas in res- sto(as free gas),com sto,inj,g com sto(in water),com sto(in oil),com (8) ervoir oil can be calculated: (2) Storage capacity of each component of flue gas in res- V = V ⋅ X − V sto(in oil),com cum,inj,g com sto(in water),com (4) ervoir brine can be calculated: where V is the storage capacity of each component sto(in oil),com V = S ⋅ (V − V ) ⋅ B sto(in water),com com(in water) cum,inj,w cum,pro,w com (9) in reservoir oil, cm and X is the mole fraction of each com component of the injection gas. (3) Storage capacity of each component of flue gas in res- If GOR ≤ GOR , the storage capacity of each compo- ervoir oil can be calculated: p i nent of flue gas in the cores can be calculated by the fol- V =[V ⋅ 1 − S − V ] ⋅ S ⋅ B sto(in oil),com p wi cum,pro,o com(in oil) com lowing equations: (10) (1) Storage capacity of each component of flue gas as free gas phase in cores can be calculated: 4 Results and discussion V = V ⋅ X − V − V sto(as free gas),com cum,inj,g com sto(in water),com sto(in oil),com (5) In this study, continuous waterflooding experiment and flue where V is the storage capacity of each sto(as free gas),com gas-water-alternating injection after continuous water injec- component as free gas phase in cores, cm . tion experiment were performed to study the flue gas stor - (2) Storage capacity of each component of flue gas in res- age and EOR. In a continuous waterflooding experiment, ervoir brine can be calculated: the continuous injection of water was performed until the water cut is 100% (no more oil is produced). Then, as an improved flue gas–EOR method, the flue gas–WAG flooding was applied to increase the oil recovery over the continuous Table 5 Solubility of different gases in reservoir oil and brine (42 °C, waterflooding. More details about the experimental data and 8 MPa) results are listed in Table 6. 3 3 Component Solubility in oil, m /m Solubility in 3 3 water, m /m 4.1 EOR of flue gas–WAG flooding CO 51.40 27.42 CH 11.86 1.65 Compared with waterflooding, the EOR mechanism of flue N 4.22 0.97 gas–WAG flooding is that water-alternating flue gas injec- O 8.57 0.0268 tion can change the water oil mobility ratio and strengthen CO 5.27 0.0196 the exchange, diffusion, and imbibition of oil, gas, and H 3.82 0.0115 water three-phase molecules. With the effect of gravity 1 3 876 Petroleum Science (2021) 18:870–882 Table 6 Experimental data and results of waterflooding and flue gas–WAG flooding Cumulative injection volume, Production gas oil ratio, m / Water cut, % Cumulative oil recovery fac- Injection medium HCPV m tor, % 0.1 37 0.00 9.97 Water 0.2 37 0.00 19.43 Water 0.3 37 1.83 29.00 Water 0.4 37 1.13 39.83 Water 0.5 37 61.55 44.19 Water 0.6 31 87.74 45.66 Water 0.7 37 88.09 46.90 Water 0.8 37 93.88 47.65 Water 0.9 37 95.12 48.15 Water 1 (0) 37 98.89 48.27 Water 1.1 (0.1) 37 97.44 48.77 Flue gas 1.2 (0.2) 35 80.21 49.82 Water 1.3 (0.3) 39 74.19 51.55 Flue gas 1.4 (0.4) 35 69.40 53.86 Water 1.5 (0.5) 36 69.22 56.85 Flue gas 1.6 (0.6) 43 56.46 60.21 Water 1.7 (0.7) 128 77.73 62.78 Flue gas 1.8 (0.8) 458 54.52 64.03 Water 1.9 (0.9) 514 84.83 65.02 Flue gas 2 (1.0) 453 58.65 66.52 Water 2.1 (1.1) 562 86.96 68.01 Flue gas 2.2 (1.2) 630 61.58 69.26 Water 2.3 (1.3) 4764 96.73 69.51 Flue gas 2.4 (1.4) 55,357 99.30 69.52 Water The number in brackets in the first column is the cumulative injection volume of flue gas–WAG flooding differentiation, the high-permeability zone is sealed by of the waterflooding process reaches 48.27% at 1.0 HCPV. injection water, and the micropores are swept by injection In the flue gas–WAG flooding process, before the flue gas gas. The process of flue gas–WAG flooding is a dynamic breakthrough (1.7 HCPV), the oil recovery factor is increas- process, the binding state of water in pores is constantly ing gradually with an increase in the WAG injection volume. broken and rebuilt, the alternating plugging of macropo- Meanwhile, the water cut decreases significantly. The water res by injected water weakens the breakthrough effect of cut declines from 98.89% to 56.46%. This result indicates injection gas, the water injection profile is improved, the that flue gas–WAG flooding can significantly reduce water water breakthrough time is delayed, and the oil recovery is cut and increase oil recovery factor. When the cumulative improved. For the reservoir with serious heterogeneity, the injection volume reaches 1.7 HCPV, the production gas–oil 3 3 dynamic plugging produced by flue gas–WAG flooding can ratio increases to 128  m /m , which means that flue gas further improve the effect of WAG flooding. As shown in breakthrough occurs. The corresponding oil recovery factor Fig. 2, in the waterflooding process, the oil recovery fac- at gas breakthrough is 62.78%. Similar to the waterflooding tor increases with an increase in injection volume. When process, once gas breakthrough occurs in the core, the oil the cumulative injection volume reaches 0.5 HCPV, the recovery factor will be affected. After the flue gas break - water cut increases significantly to 61.55%. The water cut through (1.7 HCPV), the water cut fluctuates greatly with an increase is an indication of water breakthrough occurring in increase in the WAG injection volume. The ultimate recov- the cores, and the oil recovery factor at water breakthrough ery factor of the WAG flooding process reaches 69.52%. is 44.19%. After water breakthrough, the oil recovery factor Compared with the waterflooding process, the oil recovery increases slightly. Further water injection does not signifi- factor of flue gas–WAG flooding is increased by 21.25%. cantly improve oil recovery. The ultimate recovery factor Therefore, we can conclude that flue gas–WAG flooding 1 3 Petroleum Science (2021) 18:870–882 877 (b) (a) 100 100 WAG Water Gas BT Water 80 #1 #2 #3 #4 #5 #6 #7 80 60 60 Water BT Gas BT WAG 40 40 #4 #5 #6 #7 #1 #2 #3 Water BT 20 20 0 0 00.4 0.81.2 1.62.0 2.4 00.4 0.81.2 1.62.0 2.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV Fig. 2 Oil recovery factor and water cut of waterflooding and flue gas–WAG flooding process (BT: breakthrough) combines the advantages of the microscopic displacement linear decline trend. At the end of the flue gas–WAG flood- efficiency of gas flooding and the macroscopic sweep effi- ing process, the flue gas storage ratio is only 16%. The rea- ciency of waterflooding. Flue gas–WAG flooding after con- son for significant decrease in storage ratio is that when the tinuous waterflooding can further enhance oil recovery and injection gas breakthrough occurs in the cores, partial free reduce the water cut, but the efficiency of the flue gas–WAG gas is displaced by water slug, and a large amount of injec- flooding is strongly dependent on the injection volume. tion gas is produced. These results demonstrated that once the injection volume reached a certain critical level, the sole 4.2 Flue gas storage increase in injection volume is not effective in enhancing the storage capacity. Therefore, determination of the injection 4.2.1 Total storage capacity volume of gas breakthrough occurrence is important for flue gas storage in the flue gas–WAG flooding. We can determine the flue gas storage capacity according to Sect. 3.1 to investigate flue gas storage in the flue gas–WAG 4.2.2 Storage capacity of each component of flue gas flooding process. The flue gas storage ratio is defined as the storage capacity (reservoir condition) of flue gas in cores The method for calculating the theoretical storage capacity divided by the cumulative injection volume (reservoir con- of each component of flue gas in reservoir oil, water, and ditions) of flue gas. The storage ratio and storage capacity as free gas is based on the model in Sect. 3.2. Thus, the of flue gas in the flue gas–WAG flooding process are shown theoretical storage capacity of each component of flue gas in Fig. 3. is defined as follows: It can be seen from Fig. 3 that before gas breakthrough V = V + V + V (0.7 HCPV), the flue gas storage ratio is almost maintained sto(thoretical),com sto(as free gas),com sto(in water),com sto(in oil),com (11) at 100%. This shows that the injection gas is completely stored in cores, and the flue gas storage capacity increases where V is the theoretical storage capacity of sto(theoretical),com gradually. Afterward, with an increase in injection vol- each component of flue, cm . ume, when the cumulative injection volume reaches 0.7 The calculation process of N storage capacity was dem- HCPV, the flue gas storage ratio starts to decrease gradu - onstrated as an example. First, the N storage capacity in ally. When the injection gas breakthrough occurs, injection reservoir oil and reservoir water is determined by Eqs. (3) gas no longer dissolves in oil and water, which results in and (4). If theoretical storage capacity of N (volume of N 2 2 flue gas storage ratio decrease. The storage capacity of flue dissolved in reservoir water plus volume of N dissolved in gas reaches 50.89 cm , which is the maximum of storage oil) is less than the cumulative injection volume, it means capacity in the flue gas–WAG flooding process. After gas N exists as free gas in cores. Second, if GOR ≤ GOR , the 2 p i breakthrough occurs at 0.7 HCPV, the storage ratio does not volume of N dissolved in oil and water and the volume of decline significantly, which still maintains at a high level N as free gas phase in cores are calculated by Eqs. (5)–(7). (0.93). Afterward, the flue gas storage ratio shows a nearly If GOR > GOR , the volume of N dissolved in water and p i 2 1 3 Oil recovery factor, % Water cut, % 878 Petroleum Science (2021) 18:870–882 As shown in Fig. 5, in the early period of flue gas–WAG flooding, the storage capacity of the individual component increases with an increase in injection volume. After gas breakthrough, the storage capacity of the individual com- Storage capacity of injection gas ponent decreases gradually. It is seen that the storage capac- Cumulative volume of 60 produced injection gas ity of N is the largest among all components in the flue Storage ratio 60 gas–WAG flooding process. Moreover, the storage capac- ity of individual component reaches a maximum all at 0.7 HCPV. The storage capacity values of individual component are 42.7, 7.47, 0.25, 0.21, 0.14, and 0.12 cm for N, CO , 2 2 O, CH, H , and CO, respectively. Thus, the storage capac- 2 4 2 ity of injection gas mainly consists of N and C O . From 2 2 Fig. 6, only N exists as free gas phase in cores and other 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 components of injection gas are distributed in oil and water. Cumulative injection volume, HCPV It is clear that, except for N , the storage capacity of other components in oil is larger than that in water in the flue Fig. 3 Flue gas storage capacity in the flue gas–WAG flooding gas–WAG flooding process; the reason is that the solubil- ity of these components in crude oil is larger than that in reservoir brine. However, after gas breakthrough, the stor- oil and the volume of the N as free gas phase in cores are age capacity of N in oil is lower than that in water because calculated by Eqs. (8)–(10). Third, the storage capacity of N the injection volume of N is much larger than the theoreti- is equal to the sum of the volume of N dissolved in oil and cal storage capacity of N at any time. The reservoir fluids water and the volume of N as free gas phase in cores; then, are N saturated. With the production of oil and water, the the calculation of storage capacity of other components can storage capacity of N in oil decreases with an increase in refer to the N calculation process. The results are shown in injection volume; however, due to the supplement of injected Fig. 4. Except N , the theoretical storage capacities of other water, the water in cores does not decrease significantly and gases are larger than their actual injection volume, which the storage capacity of N in water is maintained at a rela- means that only N exists as free gas phase in cores. Other tively stable and low level. Moreover, the storage capacity of gases are only dissolved in reservoir brine and crude oil. 50 5 50 6 (a) (b) N N CO 2 2 2 CO CH O 2 4 2 O2 H CO 5 40 4 40 CH4 H2 CO 30 3 30 20 2 20 10 1 10 0 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV Fig. 4 Injection volume and theoretical storage capacity of each component of flue gas in the flue gas–WAG flooding 1 3 Underground volume of gas, cm Injection volume, cm Storage ratio, % Injection volume, cm Theoretical storage capacity, cm Theoretical storage capacity, cm Petroleum Science (2021) 18:870–882 879 0.30 with the waterflooding process, the ultimate oil recovery N2 CO2 factor of flue gas–WAG flooding is increased by 21.25%. O2 0.25 CO CH4 30 0.20 5 Conclusions 0.15 A long-core experimental device was designed and built for evaluating flue gas storage and EOR of flue gas–WAG 0.10 flooding after continuous waterflooding in oil reservoirs, by which the relationship between flue gas storage and EOR is 0.05 investigated. A novel material balance model based on dif- ferent storage mechanisms is proposed. The storage capacity 0 0 of multicomponent flue gas and storage capacity of each 0 0.2 0.4 0.6 0.81.0 1.21.4 component of flue gas in reservoir oil, water and as free gas Cumulative injection volume, HCPV in flue gas–WAG flooding can be described. First, an oil recovery factor as high as 69.52% is obtained Fig. 5 Storage capacity of each component of flue gas in the flue gas– in the flue gas–WAG flooding process applied in a post- WAG flooding waterflooding reservoir. This result indicates that the flue gas–WAG flooding can be an efficient approach to enhance N is mainly composed of that as free gas phase, and its stor- oil recovery. age capacity as free gas phase reaches as high as 39.55 cm Second, in the flue gas–WAG flooding process, the stor - at 0.7 HCPV in the flue gas–WAG flooding process, in which age capacity of flue gas increases with an increase in injec- the total storage capacity of N is 42.7 cm . tion volume; after the gas breakthrough occurs, the storage capacity of flue gas declines gradually. This indicates that 4.3 Injection strategies for flue gas storage and EOR once the injection volume reaches a certain critical level, a continuous increase in injection volume alone is not effective In this study, we can obtain that it is very important to deter- in enhancing the storage capacity. Thus, it is very important mine the time of flue gas breakthrough in cores for flue gas to determine the time of flue gas breakthrough in cores for storage. 0.7 HCPV is the reasonable injection volume to flue gas storage. obtain the maximum storage capacity of flue gas while main- Third, in the flue gas–WAG flooding process, only N taining a higher oil recovery factor in the flue gas–WAG exists as free gas phase in cores and other gases are only flooding process. The corresponding maximum storage dissolved in reservoir brine and crude oil. The storage capac- capacity of flue gas (50.89 cm ) and a high oil recovery ity of injection gas mainly consists of N and CO , and the 2 2 factor (62.78%) are obtained. From the perspective of flue storage capacity of N is much higher than that of other gas storage, the maximum storage ratio of flue gas (100%) components of injection gas. occurs up to 0.6 HCPV in the flue gas–WAG flooding pro- Fourth, in the flue gas–WAG flooding process, for the cess and the injection volume of 0.6 HCPV is worth con- maximum storage ratio of injection gas, the injection volume sidering. From the perspective of maximizing oil recovery of 0.6 HCPV is the best. For the maximum oil recovery fac- degree, the ultimate oil recovery factor reaches as high as tor, when the injection volume reaches 1.4 HCPV, the oil 69.52% and the injection volume of 1.4 HCPV is the best recovery factor is as high as 69.52%. For the combination choice in the flue gas–WAG flooding process. Compared of flue gas storage and EOR, the recommended injection 1 3 Storage capacity, cm Storage capacity, cm 880 Petroleum Science (2021) 18:870–882 (a) (b) 3.0 6 CO2 in water 40 CO in oil 2.5 5 2.0 30 4 1.5 3 1.0 2 0.5 N2 in water 1 N in oil N2 as free gas phase 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV (c) (d) 0.30 0.0030 0.20 O2 in oil CH4 in water O in water CH in oil 2 4 0.25 0.0025 0.15 0.20 0.0020 0.15 0.0015 0.1 0.10 0.0010 0.05 0.05 0.0005 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV (e) (f) 0.150 0.0020 0.15 0.0020 H2 in oil CO in oil H in water CO in water 0.125 0.12 0.0016 0.0015 0.100 0.09 0.0012 0.075 0.0010 0.06 0.0008 0.050 0.0005 0.03 0.0004 0.025 0 0 0 0 0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 00.2 0.40.6 0.81.0 1.21.4 Cumulative injection volume, HCPV Cumulative injection volume, HCPV Fig. 6 Storage capacity of each component of flue gas in the flue gas–WAG flooding Acknowledgements This work was supported by the Department of volume is 0.7 HCPV and the corresponding flue gas storage Science and Technology of Sichuan Province (2019YFG0457), the ratio and oil recovery factor remain at a high level of 62.78% National Natural Science Foundation of China (5183000045), the and 93%, respectively. National Major Science and Technology Project of CNPC "Research and Application of Key Technologies for Benefit Development of 1 3 Storage capacity, cm Storage capacity, cm 3 Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Storage capacity, cm Petroleum Science (2021) 18:870–882 881 Volcanic Rock Reservoirs” (2017E-04-05), and the PetroChina Major Ettehadtavakkol A, Lake LW, Bryant SL. C O -EOR and storage design Science and Technology Project (2018E-1805). optimization. Int J Greenh Gas Control. 2014;25:79–92. https :// doi.org/10.1016/j.ijggc .2014.04.006. Farajzadeh R, Eftekhari AA, Dafnomilis G, et  al. On the sustain- Open Access This article is licensed under a Creative Commons Attri- ability of C O storage through C O —enhanced oil recovery. bution 4.0 International License, which permits use, sharing, adapta- 2 2 Appl Energy. 2020;261:114467. https ://doi.org/10.1016/j.apene tion, distribution and reproduction in any medium or format, as long rgy.2019.11446 7. as you give appropriate credit to the original author(s) and the source, Fong WS, Tang RW, Emanuel AS, et al. EOR for California Diato- provide a link to the Creative Commons licence, and indicate if changes mites: CO , flue gas and water corefloods, and computer simula- were made. The images or other third party material in this article are 2 tions. In: SPE western regional meeting, 30 March–1 April, 1992, included in the article’s Creative Commons licence, unless indicated Bakersfield, California. https ://doi.org/10.2523/24039 -MS. otherwise in a credit line to the material. If material is not included in Forooghi A, Hamouda AA, Eilertsen T. Co-optimization of CO the article’s Creative Commons licence and your intended use is not 2 EOR and sequestration process in a North Sea chalk reservoir. permitted by statutory regulation or exceeds the permitted use, you will In: SPE/EAGE reservoir characterization and simulation con- need to obtain permission directly from the copyright holder. To view a ference, 19–21 October, 2009, Abu Dhabi, UAE. https ://doi. copy of this licence, visit http://creativ ecommons .or g/licenses/b y/4.0/. org/10.2118/12555 0-MS. Fossum B, Blaker T, Brendsdal E, et  al. Numerical simulation of hot-water and flue-gas injection under typical North Sea Res- ervoir conditions. In: SPE/DOE enhanced oil recovery sym- References posium, 22–24 April, 1992, Tulsa, Oklahoma. https ://doi. org/10.2118/24168 -MS. Agartan E, Gaddipati M, Yip Y, et al. C O storage in depleted oil Ghomian Y, Pope GA, Sepehrnoori K. Economical co-optimization and gas fields in the Gulf of Mexico. Int J Greenh Gas Control. of CO sequestration and enhanced oil recovery. In: Sixth annual 2018;72:38–48. https ://doi.org/10.1016/j.ijggc .2018.02.022. conference on carbon capture and sequestration proceeding, 7–10 Bachu S. Comparison between methodologies recommended for esti- May, 2007, Pittsburgh, PA. mation of CO storage capacity in geological media by the CSLF Godec M, Kuuskraa V, Leeuwen TV, et al. CO storage in depleted task force on CO storage capacity estimation and the USDOE oil fields: the worldwide potential for carbon dioxide enhanced capacity and fairways subgroup of the regional carbon sequestra- oil recovery. Energy Procedia. 2011;4:2162–9. https ://doi. tion partnerships program, phase III report. In: Carbon sequestra-org/10.1016/j.egypr o.2011.02.102. tion leadership forum (CSLF), 21 April, 2008, Washington, DC. Gozalpour F, Ren SR, Tohidi B. CO EOR and storage in oil reservoir. Bachu S. Review of CO storage efficiency in deep saline aquifers. Int J Oil Gas Sci Technol. 2005;60(3):537–46. https:// doi.org/10.2516/ Greenh Gas Control. 2015;40:188–202. https://doi.or g/10.1016/j.ogst:20050 36. ijggc .2015.01.007. Han HS, Li S, Ma DS. Investigation of flue gas displacement and stor - Bachu S, Shaw JC, Pearson RM. Estimation of oil recovery and age after the water flooding in a full diameter conglomerate long- CO storage capacity in CO EOR incorporating the effect of core. Pet Explor Dev. 2018;45(5):903–9. https://doi.or g/10.11698 2 2 underlying aquifers. In: SPE/DOE symposium on improved /PED.2018.05.10. oil recovery, 17–21 April, 2004, Tulsa, Oklahoma. https ://doi. Jahangiri HR, Zhang, DX. Optimization of the net present value of car- org/10.2118/89340 -MS. bon dioxide sequestration and enhanced oil recovery. In: Offshore Bachu S, Bonijoly D, Bradshaw J, et al. C O storage capacity esti- technology conference, 2–5 May, 2011, Houston, Texas. https :// mation: methodology and gaps. Int J Greenh Gas Control. doi.org/10.4043/21985 -MS. 2007;1(4):430–43. https://doi.or g/10.1016/S1750-5836(07)00086 Jia B, Tsau JS, Barati R. A review of the current progress of CO -2. injection EOR and carbon storage in shale oil reservoirs. Fuel. Bender S, Akin S. Flue gas injection for EOR and sequestration: case 2019;236:404–27. https ://doi.org/10.1016/j.fuel.2018.08.103. study. J Pet Sci Eng. 2017;157:1033–45. https://doi.or g/10.1016/j. Kopp A, Class H, Helming R. Investigations on C O storage capacity petro l.2017.07.044. in saline aquifers-Part 2: estimation of storage capacity coeffi- Berg S, Oedai S, Landman AJ, et al. Miscible displacement of oils cients. Int J Greenh Gas Control. 2009a;3(3):277–87. https ://doi. by carbon disulfide in porous media: experiments and analysis. org/10.1016/j.ijggc .2008.10.001. Phys Fluids. 2010;22:113102. https://doi.or g/10.1063/1.3516614 . Kopp A, Class H, Helming R. Investigations on C O storage capac- Berg S, Oedai S, Ott H. Displacement and mass transfer between ity in saline aquifers. Part 1. Dimensional analysis of flow pro- saturated and unsaturated CO –brine systems in sandstone. Int J cesses and reservoir characteristics. Int J Greenh Gas Control. Greenh Gas Control. 2013;12:478–92. https ://doi.org/10.1016/j. 2009b;3(3):263–76. https ://doi.org/10.1016/j.ijggc .2008.10.002. ijggc .2011.04.005. Leach A, Mason CF, Veld KVT. Co-optimization of enhanced Bürkle S, Becker LG, Dreizler A, et al. Experimental investigation oil recovery and carbon sequestration. Resour Energy of the flue gas thermochemical composition of an oxy-fuel Econ. 2011;33(4):893–912. https ://doi.or g/10.1016/j.r esen swirl burner. Fuel. 2018;231:61–72. https ://doi.org/10.1016/j. eeco.2010.11.002. fuel.2018.05.039. Lee JS, Kim JH, Kim JT, et al. Adsorption equilibria of CO on zeolite Ding SW, Xi Y, Jiang HQ. C O storage capacity estimation in oil 13X and zeolite X/activated carbon composite. J Chem Eng Data. reservoirs by solubility and mineral trapping. Appl Geochem. 2002;47:1237–42. https ://doi.org/10.1021/je020 050e. 2018;89:121–8. https ://doi.or g/10.1016/j.apg eo c hem.2017.12.002. Li ZW, Dong MZ, Li SL, et al. CO sequestration in depleted oil and Dong M, Huang S. Flue gas injection for heavy oil recovery. J Can gas reservoirs—caprock characterization and storage capac- Pet Technol. 2002;41(9):44–50. https://doi.or g/10.2118/02-09-04. ity. Energy Convers Manag. 2006a;47:1372–82. https ://doi. Edwards Ryan WJ, Celia MA, Bandilla KW, et al. A model to esti-org/10.1016/j.encon man.2005.08.023. mate carbon dioxide injectivity and storage capacity for geo- Li ZW, Dong MZ, Li SL, et  al. CO sequestration in depleted oil logical sequestration in shale gas wells. Environ Sci Technol. and gas reservoirs-caprock characterization and storage capac- 2015;49:9222–9. https ://doi.org/10.1021/acs.est.5b019 82. ity. Energy Convers Manag. 2006b;47(11):1372–82. https ://doi. org/10.1016/j.encon man.2005.08.023. 1 3 882 Petroleum Science (2021) 18:870–882 Liu QY, Liu ZY, Wu WZ. Ee ff ct of V O additive on simultaneous SO Sumathi S, Bhatia S, Lee KT, et  al. Adsorption isotherm models 2 5 2 and NO removal from flue gas over a monolithic cordierite-based and properties of SO and NO removal by palm shell activated CuO/Al O catalyst. Catal Today. 2009;147:S285–9. https ://doi. carbon supported with cerium (Ce/PSAC). J Hazard Mater. 2 3 org/10.1016/j.catto d.2009.07.013. 2010a;162:194–200. https ://doi.org/10.1016/j.cej.2010.05.028. Liu RG, Zhang JG, Meng L, et al. Feasibility study of steam/flue gas Sumathi S, Bhatia S, Lee KT, et al. Selection of best impregnated mixture injection in low permeability reservoir. In: SPE project palm shell activated carbon (PSAC) for simultaneous removal of and facilities challenges conference at METS, 13–16 February, SO and NO . J Hazard Mater. 2010b;176:1093–6. https ://doi. 2 X 2011, Doha, Qatar. https ://doi.org/10.2118/14234 3-MS.org/10.1016/j.jhazm at.2009.11.037. López D, Buitrago R, Sepúlveda-Escribano A, et al. Surface com- Trevisan OV, Laboissiere P, Monte-Mor S. Laboratory study on steam plexes formed during simultaneous catalytic adsorption of NO and flue gas co-injection for heavy oil recovery. In: SPE heavy oil and SO on activated carbons at low temperatures. J Phys Chem conference-Canada, 11–13 June, 2013, Calgary, Alberta. https :// C. 2007;111:1417–23. https ://doi.org/10.1021/jp063 544h.doi.org/10.2118/16552 3-MS. Majeed H, Svendsen HF. Characterization of aerosol emissions from Trivedi JJ, Babadagli T. CO and flue gas sequestration during ter - CO capture plants treating various power plant and industrial tiary oil recovery: optimal injection strategies and importance flue gases. Int J Greenh Gas Control. 2018;74:282–95. https://doi. of operational parameters. In: Canadian international petro- org/10.1016/j.ijggc .2018.04.016. leum conference, 7–9 June, 2005, Calgary, Alberta. https ://doi. Nasralla RA, Snippe JR, Farajzadeh R. Coupled geochemical-reservoir org/10.2118/2005-042. model to understand the interaction between low salinity brines U.S.DOE (U.S. Department of Energy). Carbon sequestration Atlas of and carbonate rock. In: SPE Asia Pacific enhanced oil recovery the United States and Canada. 2nd ed. Pittsburgh, PA: National conference, 11–13 August, 2015, Kuala Lumpur, Malaysia. https Energy Technology Laboratory; 2008. ://doi.org/10.2118/17466 1-MS. van der Meer LGH, Yavuz F. C O storage capacity calculations for the Santibanez-Borda E, Govindan R, Elahi N. Maximising the dynamic Dutch subsurface. Energy Procedia. 2009;1(1):2615–22. https :// CO storage capacity through the optimisation of C O injection doi.org/10.1016/j.egypr o.2009.02.028. 2 2 and brine production rates. Int J Greenh Gas Control. 2019;80:76– Yi HH, Wang ZX, Liu HY, et al. Adsorption of SO , NO, and CO 2 2 95. https ://doi.org/10.1016/j.ijggc .2018.11.012. on activated carbons: equilibrium and thermodynamics. J Chem Shaw J, Bachu S. Screening, evaluation, and ranking of oil reser- Eng Data. 2014;59:1556–63. https ://doi.org/10.1021/je401 1135. voirs suitable for CO flood EOR and carbon dioxide seques- Zangeneh H, Jamshidi S, Soltanieh M. Coupled optimization of tration. J Can Pet Technol. 2002;41(9):51–61. h ttp s : //d oi. enhanced gas recovery and carbon dioxide sequestration in natural org/10.2118/02-09-05. gas reservoirs: case study in a real gas field in the south of Iran. Int Shokoya OS, Mehta SA, Moore RG, et al. Effect of oil and flue-gas J Greenh Gas Control. 2013;17:515–22. https://doi.or g/10.1016/j. compositions on oil recovery in the flue-gas/light-oil injection ijggc .2013.06.007. process. In: SPE annual technical conference and exhibition, 9–12 Zhang L, Ren B, Huang HD, et al. CO EOR and storage in Jilin oilfield October, 2005, Dallas, Texas. https://d oi.org/10.2118/97262- MS. China: monitoring program and preliminary results. J Pet Sci Eng. Snippe J, Berg S, Ganga K, et al. Experimental and numerical inves- 2015;125:1–12. https ://doi.org/10.1016/j.petro l.2014.11.005. tigation of wormholing during C O storage and water alternating Zheng Z, Larson ED, Li Z, et al. Near-term mega-scale CO capture 2 2 gas injection. Int J Greenh Gas Control. 2020;94:102901. https:// and storage demonstration opportunities in China. Energy Environ doi.org/10.1016/j.ijggc .2019.10290 1. Sci. 2010;3:1153–69. https ://doi.org/10.1039/B9242 43K. Srivastava RK, Huang SS, Dong MZ. Comparative effectiveness of Zhou D, Zhao ZX, Liao J, et al. A preliminary assessment on C O stor- CO produced gas, and flue gas for enhanced heavy-oil recov - age capacity in the Pearl River Mouth Basin offshore Guangdong. ery. SPE Reservoir Eval Eng. 1999;2(3):238–47. https ://doi. China Int J Greenh Gas Control. 2011;5(2):308–17. https ://doi. org/10.2118/56857 -PA.org/10.1016/j.ijggc .2010.09.011. Test method for reservoir fluid physical properties: GB/T 26981-2011. Zhou X, Yuan QW, Rui ZH, et al. Feasibility study of CO huff ‘n’puff Research Institute of Petroleum Exploration and Development process to enhance heavy oil recovery via long core experiments. 2012. Beijing: Standards Press of China. Appl Energy. 2019;236:526–39. https ://doi.org/10.1016/j.apene rgy.2018.12.007. 1 3

Journal

Petroleum Science – Springer Journals

Published: Feb 8, 2021

Keywords: Flue gas storage; Enhanced oil recovery; Flue gas water-alternating gas; Material balance model; Injection strategy

There are no references for this article.