CO2storage is a greenhouse gas mitigation instrument for many countries. In this paper, we investigate the possibility of CO 2storage in the region of the Precaspian basin using the compositional ﬂow model that was veriﬁed by the data of the Frio pilot project, USA. We use local grid reﬁnement in the commercial reservoir simulator. In the reservoir simulation for data of the Frio Pilot project, we have achieved a good history matching of the well pressure. The different scenarios were tested and post-injection migration was shown for both case studies. The long-term reservoir simulation shows the potential amount of trapped CO 2by residual and dissolved trapping mechanisms in the Precaspian basin. Keywords CO2 storage compositional ﬂow model reservoir simulation 1 Introduction In the last few years there has been a growing interest in studying many mechanisms to achieve the reduction of the CO 2concentration in the atmosphere. The growing infrastructure of countries requires more consumption of fossil fuels that can lead to the greenhouse effect. Efforts of many countries in controlling Greenhouse Gas emissions were documented in the Paris agreement. One of the ways to mitigate the risk caused the CO 2emissions is to inject CO 2into depleted oil and APREPRINT - M ARCH 8, 2021 gas reservoirs or aquifer formations for the geological storage. The injection of CO 2should be at sufﬁcient depth to allow the CO 2to be in the supercritical state (in general, approximately the depth should be larger than 800 meters so that the pressure is above 7.4MPa and the temperature is above 31 degrees by Celsius) in which the storage capacity is maximized. CO 2has a liquid-like density and gas-like viscosity in the supercritical state and occupies approximately one hundredth of the volume it does as a gas, at standard conditions. The recognition of viable role of the carbon sequestration is increasing and the implementation of such technologies can be found in many projects of the world from the USA, UK, China, Norway, etc. In [25], it was proposed the method for evaluation of the CO 2storage capacity in the global context in order to achieve “two degree scenario" objective. The assessment of the storage capacity is sophisticated since there are many trapping strategies. We highlight main four trapping mechanisms of carbon dioxide in the aquifer such as the hydrody- namic trapping when CO 2migrates upwards and remains just below the cap rock (a structural or stratigraphic trap must exist), as immobile phase as a residual gas saturation during the imbibition process, dissolution in water, and the mineral trapping. The ﬁrst three trapping mechanisms are the most important instruments as the mineral trapping effects can be observed only after a long time (many years, maybe even thousand of years). The most desirable mechanisms for trapping are immobile phase and dissolution in water, because hydrodynamic trapping is risky as the cap rock can be partially sealing, hence, CO 2can migrate through it and the storage efﬁciency can be reduced. To address the modeling of the CO 2storage in the subsurface, many researchers have proposed various the numerical models with different realistic data [ 25,7,21,24]. There are many case studies of such mechanisms around the world such as Johansen formation [ 11], Utsira formation [22], Cranﬁeld pilot project [ 9,20], Frio pilot project [ 13] and others. The large-scale modeling helps to evaluate the behavior of the injected CO 2in the various scenarios and the models were veriﬁed by using the additional sources of ﬁeld project including the pressure measurements, seismic surveys, etc. 2 APREPRINT - M ARCH 8, 2021 Kazakhstan’s plan on fulﬁlling the Paris agreement may require additional actions to be able to achieve the goals to achieve the 25 %emission reduction strategy. According to [ 18] the current mitigation activities in Kazakhstan may not be enough to reach reduction 15 %(unconditional target) based on the BaU model. CO 2sequestration can be a solution for the country in the reduction of CO 2emission. Potential locations in Kazakhstan for CO 2storage was discussed in [ 14,23] and it was estimated around 1003 Mt CO 2storage capacity of the gas reservoirs of Kazakhstan in [ 1]. However, most of previous studies do not take into account numerical reservoir simulation of the CO 2storage in Kazakhstan. In this study, we investigate the reservoir simulation of CO 2storage in 3D using the compositional ﬂow model for the Frio CO 2project in the USA and the Precaspian Basin in Kazakhstan. We study the effect of parameters that can be essential in the modeling of CO 2storage evaluation in a potential subsurface of Kazakhstan. The model veriﬁcation is performed by the history matching of the well pressure proﬁle based on the data of Frio ﬁeld experiment. We utilize the commercial simulator Eclipse 300. To authors’ knowledge, 3D numerical simulation of CO 2sequestration in the Prescaspian formation has been scarcely investigated from the point of view evaluation of capacity. We propose the potential place of the CO 2storage and demonstrate the possible amount of trapped CO 2and present also the plume migration in the post-injection period. The remainder of the paper is organized as follows. Section 2 describes settings in the compositional ﬂow reservoir simulation. We use the data from the Frio CO 2project as a case study. Reservoir simulation results for regions from the Frio and the Precaspian formation are presented in Section 3. The compositional ﬂow model was veriﬁed and applied to Frio CO 2Project and then was applied to the Precaspian formation, Kazakhstan. Section 4 summarizes the results of this work and draws conclusions. 2 Model Description In this section, we make an overview of the upper part of the Frio formation in USA and describe the compositional ﬂow model set-up and input parameters for simulation. 3 APREPRINT - M ARCH 8, 2021 2.1 Overview of the Frio CO 2model The injection pilot project in Frio brine formation is used as a case study for reservoir simulation of CO 2sequestration. The Frio brine ﬁeld is a sandstone formation with high porosity and permeability located in Houston, Texas, USA. In this pilot project it was injected about 1600 tons of CO 2during 10 days into the formation 1500 m below the surface in [ 15]. The target for injection was upper Frio Formation (“C” sandstone) which is 23-meters thick brine-bearing interval above oil production zone. The upper part of “C” formation has porosity of 30 to 35 %and permeability of 2000 to 2500 md. There is also some ﬁner grained sandstone with porosity of 24 to 28 %and permeability of 70 to 120 md in the middle of this zone. Finally, there is a cap rock (seal) at the top of “C” formation and that’s why the injected CO 2can be trapped through a hydrodynamic trapping mechanism. The project consisted of two wells: one injection and one observation. The existing oil production well was plugged and recompleted in “C” formation as observation well. A new injector was completed in “C” formation for CO 2injection. There are no faults or fractures b/w injection and observation wells. The distance between wells is about 33 m and the dip angle is approximately 16 degrees. 2.2 Compositional reservoir simulation model set-up The compositional reservoir simulation was designed using ECLIPSE 300 simulator and was used to investigate the development of the larger scale CO 2storage experiment. There were two components present in the model: CO 2and water. In ECLIPSE 300 simulator, the solubility of CO 2in water was calculated using the procedure of Spycher and Pruess [ 28] which was based on fugacity equilibration between water and CO 2. The fugacities for water and CO2 were calculated using Henry’s law and the Redlick-Kwong equation of state respectively. The compositional model takes into account the important processes happening during the interaction of CO 2with water, namely the process of CO 2 dissolution in the water, density changes of CO 2-water mixture, trapping of the gas as the residual saturation and gas gravity effects leading to the hydrodynamic trapping by the cap rock. The corner point geometry grid was implemented using a Python script. Angle of 16 degrees was chosen during the construction of the grid, see Figure 1. 4 APREPRINT - M ARCH 8, 2021 Figure 1: Grid for Frio project The domain of the model was discretized by 150 15023 cells. The lateral width of each grid cell was 15 meters and layer thickness was 1 meter. As there were two sealing faults and salt dome based on the Frio geological model, the no-ﬂow boundary conditions were applied from all sides. The further description on the conﬁguration of the grid could be found in Section 3. Figure 2: Local grid reﬁnement around wells, 1- injection well and 2 - observation well The local grid reﬁnement (LGR) was used where ﬁner grids were set in the area where the CO 2 plume migration may occur in order to obtain accurate calculation, see Figure 2. The LGR allows to improve accuracy of the model and it was reported in many studies of the ﬂow and transport problems with error evaluations [ 5,26,4,19,6]. The 8 cells in the area of injection and observation wells were reﬁned laterally by the factor of 15 giving cells 1 meter in width and the further 2 cells from each side by the factor of 10 giving cells 1.5 meters in width. 5 APREPRINT - M ARCH 8, 2021 Rock compressibility value of 1.28e-4 1/bar was applied to the model [ 10]. The realistic porosity and permeability were digitized from [ 15] and were averaged over each 1 meter in the z-direction using Python script, see Figure 3. As there is data only from one well, the permeability and porosity is the same along the layers. Moreover, the horizontal permeability in both directions xandywere assumed to be the same, i.e. there was no anisotropy in xandydirections. (a) Porosity (b) Permeability Figure 3: The porosity and horizontal permeability curves from Frio ﬁeld and averaged values per meter The 3-parameter Peng Robinson equation of state was used in the model. Two components were considered in the model such as CO 2and water with density of 1026 kg/m3. The initial pressure and temperature were set as 152 bars and 57C, respectively. All equation of state parameters for CO 2component including Tcrit, Pcrit, ACF, MW, PARACHOR, SSHIFT and BIC were standard in the simulator that were speciﬁed in previous study [13]. In the model, the relative permeability and capillary pressure values were digitized and ﬁtted based on the data from [ 10] and the Corey function, for more details see equations (1)-(3), was used to reproduce these data for usage in reservoir simulation model and it was illustrated in Figures 4 and 5. The saturations of connate water and critical water were deﬁned to equal 15 %, the Corey coefﬁcient for drainage and imbibition gas curves ( Cg) was 2, for drainage water curve was 3 and for imbibition water curve ( Cw) was 2.5. Relative permeability and capillary pressure hysteresis options (both curves drainage and imbibition were used in the simulation model) were switched on 6 APREPRINT - M ARCH 8, 2021 (a) Drainage relative permeability (b) Imbibition relative permeability Figure 4: Relative permeability curves CO 2and water where Sw= 0:15. Corey function ﬁtted to drainage and imbibition relative permeability curves from [10] (a) Drainage capillary pressure (b) Imbibition capillary pressure Figure 5: Corey function ﬁtted to drainage and imbibition capillary pressure curves from [10] in the reservoir simulation model. The critical gas saturation was assumed to be 5 %. The formulas of the relative permeability ([8]) and the capillary pressure ([27]) were as follows, krg=krgmax1swsgcr 1swisgcrCg (1) where Swis the water saturation, Swiis the intial water saturation, Sgcris the critical gas saturation, Cgis the Corey gas exponent, krw=krwmaxswswcr swmaxswcrCw (2) where Swis the water saturation, Swmax is the maximum water saturation, Swcris the critical water saturation, Cwis the Corey water exponent, 7 APREPRINT - M ARCH 8, 2021 pc=cw SwSwr 1Swraw+cg SgSgr 1Sgrag (3) where Swis the water saturation, Swris the critical water saturation, Sgis the gas saturation, Sgris the critical gas saturation, Swis the water saturation, awandagare pore-size distribution coefﬁcients for water and gas ( aw= 0.4 and ag= 0.03 for drainage curve; aw= 0.34 and ag= 0.06 for imbibition curve), CwandCgare the entry capillary pressures for water and gas ( Cw= 0.347 and Cg= -0.307 for drainage curve; Cw= 0.33 and Cg= -0.3 for imbibition curve). 3 Numerical Results In this section we describe the history matching results of the compositional ﬂow model for the injection well pressure and CO 2plume migration for the Frio project in the USA. Moreover, we show the possibility of CO 2storage in proposed region of the Precaspain basin and provide compositional model set-up and simulation results. 3.1 History matching of the well pressure for Frio project The initial grid for the reservoir simulation of Frio project was set as square with equal sides of 2250 m (150 cells in each direction with lateral width of 15 meters) for the x-ydirection, see Figure 6. We should note that based on geological model of Frio ﬁeld in [ 10,13], there are no-ﬂow boundary conditions from 3 sides of the reservoir (salt dome from one side and two main faults from the remaining two sides). To improve the history matching, we tested different values of pore volume multiplier. As can be seen from Figure 8, the width of the reservoir seems to be ambiguous, as when the width of the reservoir is shortened to 855 meters (Figure 7), the BHP of injector started to deviate from the historically recorded pressure which was also observed in [ 17]. It seems that the width should be larger than width based on the geological model, and the deviation of BHP is shown in Figure 8. To achieve the history matching on injector’s BHP and to receive a consistent CO 2plume shape with width = 2250 meter, the different parameters were varied which are discussed below. 8 APREPRINT - M ARCH 8, 2021 Figure 6: Square model with length and width of 2250 m Figure 7: Rectangle model with width of 855 m and length of 2250 m Due to uncertainty of the permeability in reservoir, we conducted numerical experiments for the vertical to horizontal permeability ratio (kv/kh) from 0.01 to 0.1. We should note that the vertical direction of CO 2plume ﬂow towards the reservoir top can be impacted by this ratio. The various numerical experiments showed a small impact of kv/kh variation on injector’s BHP. Finally, the value of 0.1 was kept as a base case because it is commonly used in the industry ([ 12]) to account for vertical ﬂow restrictions. The horizontal permeability far from the injection well trajectory was key parameter for variation in order to match the injector’s BHP and CO 2plume migration. The simulations indicate that the value of BHP is increased when the value of horizontal permeability is decreased. Moreover, this 9 APREPRINT - M ARCH 8, 2021 slows down horizontal migration of CO 2plume from injector towards producer. The horizontal permeability in xandydirections was multiplied by 0.5 outside the injection well (but not for cells perforated by well, because the data in the well area is measured and known) to reach history match on injection well ﬂowing BHP. The alternative option is the change of productivity index (PI) of the well instead of changing horizontal permeability. However, the PI application will impact the perforated cells, which should be untouched because permeability was taken directly from the measured permeability curve. The critical gas saturation was one of the main parameter to history match the CO 2plume migration, as it can impact the movement of gas and the amount of gas left as a residual saturation. The values of this parameter such as 0, 1 %, 5%, 10%, 20%were tested using end point scaling (3-point scaling) in order to achieve a comparable CO 2plume to that of the conducted seismic survey from [ 16]. The value of 5 %was chosen as the best one to match available data. The pore volume multiplier on the edge cells of the model was the second most inﬂuential parameter on injectors’ BHP trend. The application of pore volume multiplier made the BHP trend consistent with observed BHP trend. Its value of 1000 was chosen based on the iteration process to get a BHP trend consistent with an observed one. The multiplier was applied only to edge cells at the opposite side of the salt dome. As shown in Figure 8 the excellent matching between measured and modeled BHP (black line) was achieved. It is important to note that the history match was improved by utilizing width of 2250 m. The CO 2plume from the history-matched reservoir simulation of the current study at different days is shown in Figure 9. The results are similar to CO 2plume migration from Fig. 7 of [17]. 10 APREPRINT - M ARCH 8, 2021 Figure 8: History match of injector’s BHP with width = 2250 m (black line) and width = 855 m (blue line) Figure 9: CO 2plume migration for the Frio project based on the history-matched simulation model 11 APREPRINT - M ARCH 8, 2021 3.2 Application of the CO 2storage model using data from Kazakhstan Kazakhstan has many sedimentary basins or formations which can be used for potential CO 2storage [1]. The largest basin among them is Precaspian basin which has a huge storage capacity compared to other basins and it was chosen for modelling to show the CO 2storage efﬁciency using the compositional ﬂow simulation. In the reservoir modeling, we consider a region of the postsalt formation, which is a good target for CO 2sequestration with the good reservoir characteristics where porosity is higher than 20 %and permeability varies from 30 mD to several hundred millidarcies [1], and with a presence of a good cap rock. As shown in ﬁgure 10, the proposed region is located in Cretaceous reservoir at depths of approximately 1000-2000 meters. As its depth is more than 800m, hydrostatic pressure is above 7.4 MPa and the temperature is above 31C, CO 2should be in supercritical state in which the storage capacity is maximized. Another advantage of the proposed region is from economic point of view as the potential cost for drilling a new well is lower with lower formation depth. In our model, the width and height of the region were set as 14 km and 450 m, respectively. A constant porosity value of 20 %and permeability of 100 mD were taken as input for reservoir model. PVT (equation of state) and the SCAL (relative permeability and capillary pressure curves) data were used based on analysis of the Frio ﬁeld model, since they were veriﬁed by the history matching process, and were applied to the Precaspian basin model. Similarly to Frio model, the local grid reﬁnement around the injector and potential CO 2distribution & migration area was used for the the Precaspian basin model to achieve a good resolution and accurate movement of CO 2plume, see Figure 11. Using digitization tool, the depth of the reservoir top was taken as 1073 m, see Figure 10. The pore pressure of 109 bar at that depth was calculated by the hydrostatic formula using the brine density of 1035 kg/m3. The reservoir temperature was taken as homogeneous in the reservoir, i.e. constant of 55.7C. It was calculated assuming the ambient surface temperature of 20C and average geothermal gradient of 27.5C/km. The gas injection rate was set as 120000 m3/day (223 tons/day). This value is approximately equal to the injection rate in the Frio CO 2project. The consideration of 12 APREPRINT - M ARCH 8, 2021 Figure 10: Potential reservoirs for CO 2storage in Precaspian basin adopted from [1] Table 1: Setting for Precaspian model Parameter Value Depth of reservoir top, m 1073 Top perforation depth, m 1121 Pore pressure at reservoir top depth, bar 109 Overburden pressure at 1073 m and 1121 m, bar 232, 242 Reservoir temperature, C 55.7 Porosity, % 20 Horizontal permeability, mD 100 Kv/Kh ratio 0.1 Number of cells in I and J directions 90 Number of layers 15 Cell dimensions in I and J directions, m 150 Layer thickness, m 30 Injection rate, tons/day 223 Injection period, years 100 Post injection period, years 130 Total amount injected, millon tons 8.14 13 APREPRINT - M ARCH 8, 2021 Figure 11: Grid with local grid reﬁnement in the center of the Precaspian model fracture pressure should be taken into account while injecting the CO 2into the Precaspian basin in order to avoid a generation of fractures around the well, which can act as a potential path for CO 2migration upwards to the surface. For several years, a great effort has been devoted to study of the properties of the fractured system such as pressure, geometry and other factors [ 3,2]. The fracture pressure was assumed as 65 %from overburden pressure. The 65 %of overburden pressure is potentially the minimum fracture pressure in the reservoir, but can be higher than this, achieving the overburden pressure itself. As Cretaceous formations are mostly consisted of clastic rocks, the average rock density was taken as 2200 kg/m3. The approximate overburden pressure at perforation depth of 1121 m is about 242 bar, hence, the minimum fracture pressure is 157 bar. In other words, the bottomhole pressure of injector should not increase the pressure of 157 bar. The amount of trapped CO 2which includes the dissolved CO 2in water, immobile residual gas saturation and remaining amount of CO 2in mobile phase, was computed using the reservoir model and is illustrated in ﬁgure 13. The most of the CO 2was left in immobile phase after 100 years, i.e. 80%of all injected CO 2(6.5 Mtons). 12 %of injected CO 2was dissolved in water (0.97 Mtons) and 8%was trapped as residual gas (0.68 Mtons). The reason for such amount of trapped residual CO 2 is that the saturation table of CO 2-water has only 5 %of irreducible gas saturation. Here, it should be noted that the residual CO 2saturation is one of the uncertain parameters and can be higher than 5%, which will deﬁnitely lead to the increased amount of trapped gas by capillary forces. 14 APREPRINT - M ARCH 8, 2021 Figure 12: CO 2migration in Precaspian model for 1, 10, 30, 50 and 100 years To model the post injection migration, we show the possible effect of residual gas trapping within 130 years after the end of injection. After stopping the CO 2injection, it continues to dissolve in water. From Figure 13 it can be seen that the amount of dissolved CO 2increased over time from 12%to 18 %(1.46 Mtons), and the amount of gas trapped as residual gas saturation increased from 8 to 10 %(0.79 Mtons). The total of 28 %of injected CO 2is trapped permanently, which is an indication of a good potential for CO 2storage. The remaining part of CO 2is in mobile gas phase, but also can be trapped by a sealed cap rock. To make it happen, the impermeable cap rock should exists. Moreover, the injection pressure should be monitored in order to not fracture the cap rock. In addition, the spill points should also be monitored in order to prevent the CO 2migration to other formations. We also should mention that the lower the injection point (the lower the perforations) the more contact area there is between CO 2and the formation water, leading to a better trapping efﬁciency. The usage of horizontal injection wells should also increase the contact area between CO 2and the formation water, however, the drilling of such wells should be considered from economic point of view as the drilling cost is more expensive. Another scenario for injection, is to control the well by constant bottomhole pressure of approx- imately 150 bars in order to be lower than fracture pressure. In this scenario with constant BHP, we can inject much more (64.6 million tons of CO 2) into the Precaspian formation. The total trapped amount of CO 2is also approximately 19 %(12.4 Mtons) from the injected amount. For that 15 APREPRINT - M ARCH 8, 2021 scenario, we need to know the stress state of the reservoir formation and accurate fracture pressure measurements. 8%12% 80% (a) 100 years10% 18% 72% (b) 130 years9%10% 81%CO2trapped as residual CO2dissolved in water CO2mobile in gas phase (c) 100 years with constant BHP Figure 13: Breakdown of CO 2amount by trapping mechanisms after indicated years in the Precaspian basin 4 Conclusion In this paper, we use the compositional ﬂow simulation to model CO 2storage process for Frio CO 2 project, USA, and a geological formation in Precaspian basin, Kazakhstan. We have a good history matching of the well pressure of the Frio project in the model. The impact of different parameters on the model behavior are studied and analyzed with provided data. The result of CO 2migration in the Frio formation is consistent with other study [ 17]. Next, we built the compositional ﬂow model for a region of the Precapsian basin using the equation of state and relative permeability curves from the veriﬁed Frio ﬁeld CO 2model. It has shown that approximately 8.14 million tons of CO 2 can be injected into the region of the Precaspian basin within 100 years with an injection rate of 223 tons/day. Furthermore, about 8 %from that injected gas is trapped as residual gas saturation and 12 %is dissolved in water within 100 years of injection. The next 130 years after the end of injection demonstrated that the amount of residual trapped gas increases to 10 %and dissolved gas increases to 18 %. If the injection rate is increased due to well control by bottomhole pressure which is below fracture pressure, we can achieve 64.6 million tons of injected CO 2. On the other hand, the results show that the most of injected CO 2remains in mobile gaseous phase and can be trapped only by hydrodynamic trapping due to cap rock. The ﬁndings suggest that this approach could be useful for decision makers to consider a CO 2sequestration project in Kazakhstan. 16 APREPRINT - M ARCH 8, 2021 5 Acknowledgement Authors wishes to acknowledge the research grant, No AP08052762, from the Ministry of Education and the Nazarbayev University Faculty Development Competitive Research Grant (NUFDCRG), Grant No 110119FD4502.