Leakage Mitigation During CO2 Geological Storage Process

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Thermodynamics, Transport, and Fluid Mechanics 2

Leakage mitigation during CO geological storage process using CO triggered gelation 2

DEXIANG LI, Liang Zhang, Shaoran Ren, and Hongxing Rui Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.8b05049 • Publication Date (Web): 01 Feb 2019 Downloaded from http://pubs.acs.org on February 4, 2019

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Industrial & Engineering Chemistry Research

Leakage mitigation during CO2 geological storage process using CO2 triggered gelation Dexiang Li1*, Liang Zhang2, Shaoran Ren2, Hongxing Rui1 1. School of Mathematics, Shandong University, Jinan 250100, China 2. School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China

AUTHOR INFORMATION Corresponding Author *E-mail: [email protected] Tel.: +8613730981950 Address: 27 Shanda Nanlu, Jinan, P.R. China 250100

Abstract: CO2 leakage is a fatal issue for the successful application of CO2 geological storage. In this paper, a method using CO2 triggered gelation is proposed to control the CO2 leakage during CO2 geological storage process. The mechanisms of CO2 triggered gelation was illustrated schematically. The effectiveness of this method for blocking CO2 leakage was evaluated by experimental works using sand-pack model. Reactive flow simulations were conducted to reproduce the experimental results and investigate field-scale feasibility of this method. The results show that this method can control the assumed leakage and the blocking performance was reproduced well by the lab-scale reactive flow simulation model. The results of simulation indicate that gel can be formed and absorbed more easily near the injection point. Feasibility of this method in field-scale were demonstrated with different scenarios of pre-placed gel system. Infill drilling and monitoring method with high accuracy are recommended to assist this method.

Keywords: CO2 triggered gelation; leakage mitigation; reactive flow simulation; CO2 geological storage

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1. Introduction CO2 capture and storage (CCS) is an important way to reduce the greenhouse gas emissions in the control of global warming and has attracted more and more attentions worldwide.1-3 In the near future, people’s dependence on fossil fuel cannot be easily changed due to social development. Although clean energy can mitigate some negative effects of traditional energy, it is difficult to replace the fossil fuel thoroughly with the technical limitations and economic costs so far .4 CCS provides a promising way to prevent CO2 building up in the atmosphere which is mainly caused by consumption of traditional fossil fuel or other anthropogenic emissions.5,6 The importance of greenhouse gas control was also emphasized during the 21st session of the conference of the parties (COP21). Injecting CO2 into geologic structures for storage is an important part of CCS which can slow down the release rate of CO2 to the atmosphere. The geological structures for CO2 storage include depleted oil and gas reservoir, deep saline aquifer and unminable coal seams etc.7-10 There is a difference in density of CO2 and pore fluid which causes buoyancy force that can induce upward migration of CO2 thorough pores, fractures and open faults in the rock. Therefore, a sufficiently impermeable seal layer is vital to the success of CO2 storage project. CO2 storage in oil and gas reservoir can be an attractive option with the demonstrated long-term caprock integrity.11,12 At the same time, the existing infrastructure in oil and gas field makes it more feasible for CO2 storage with the relatively lower costs.13 From a technical perspective, the economic and safety issues restrict the large-scale promotion and application of CO2 storage. The economic efficiency can be improved through technological innovation and implementation of carbon tax. However, the society always worries and doubts the potential risk of leakage associated with CO2 storage project. Hence, it is essential to monitor and control the CO2 leakage from the geological structures to ensure the storage security.14 The technologies for monitoring and controlling CO2 leakage, i.e. analysis of leakage risk, monitoring method and leakage blocking technology, have been paid more and more attentions during the demonstration projects of CO2 storage.15,16 In fieldscale CO2 sequestration, monitoring of the CO2 leakage is required before taking approaches to block the leakage. Frequently time-lapse seismic surveys have been widely applied to monitor CO2 migrations during


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the sequestration.17,18 From the viewpoints of geological trapping mechanisms, injecting CO2 into depleted oil and gas should be relatively safer than other structures with demonstrated seal performance for trapping oil and gas over long geologic time. CO2 storage using deep saline aquifer has great potential with competitive storage capacity and wide distributions. Although relatively permanent storage target can be achieved by trapping mechanisms such as solubility trapping, residual trapping and mineral trapping, integrity of most saline aquifers has not been demonstrated which indicates the existence of potential leakage pathways. Owing to the natural or man-made geologic activity, it is inevitable to exist or induce some leakage pathways through the seal layer. There are mainly three kinds of leakage pathways which include injection or production well, undiscovered and induced faults or geological fissures, and leakage pathways within caprock or seal layer.19,20 CO2 leakage may generate some negative effects on the environment. Unwanted leakage eliminates the environmental benefits of CO2 storage and will increase CO2 contents in the air, soil, shallow water or the ocean which may damage the human environment and ecosystems. Many structures for CCS are not only overlain by effective seal caprock, but also Underground Sources of Drinking Water (USDWs). Water quality in potable aquifers may be influenced by acidification and trace metal mobilization due to CO2 leakage.21,22 Hence, it is of great significance to research and develop leakage control technology, given that the storage safety determines the success or failure of whole project. Some research works have been carried out to investigate methods of leakage control during CO2 storage process. Réveillère et al.23 presented and discussed key issues associated with hydraulic barrier technology for leakage control and evaluated the applicability for blocking the CO2 leakage from deep saline aquifers through simulation works. The results showed the suitability of hydraulic barrier for controlling CO2 leakage in the low transmissivity overlying aquifers. Batôt et al.24 carried out experimental research on the use of foams for blocking CO2 leakage pathways, by injecting water and appropriate surfactants in the direction of the leakage paths. Their study showed that the use of foams in a CCS context can be adapt for emergency

remediation

with

effective

and

stable

properties.

Whatever

the

pressure

and

permeability/porosity, the relative foam viscosity can be described as a power law vs. the shear rate



evaluated from an empirical law established for polymer systems in which the interstitial velocity, permeability and porosity are the main variables. Ho et al.25 studied the effectiveness of a kind of pHtriggered polymer gelant to block CO2 leakage through cement fractures. The blocking effect of this pHtriggered gelation was demonstrated under high-pH conditions. Ito et al.26 showed a method to reduce the permeability of leakage pathways using CO2 reactive grout. The results indicated that this method can lead to a 99% permeability reduction and their simulation works reproduced the experimental results. The silica precipitation, which was produced from the reaction, can fill up pores of leakage paths and provide a barrier to block the CO2 migration. Tongwa et al.27 investigated four candidate fracture-sealing materials for blocking CO2 leakage, including paraffin wax, polymer-based gel, silica-based gel, and micro-cement. Their works showed that all these four materials can reduce the permeability of the leakage pathways and the micro-cement exhibited most effective sealing performance. Phillips et al.28 conducted research works on a strategy using biofilm-induced calcium carbonate precipitates to seal simulated fracture. The study suggested that the biofilm-induced precipitates can block the CO2 leakage paths potentially. Mitchell et al.29 applied biofilms directly as barrier to reduce the permeability of CO2 leakage pathways and investigated the utility. The observations showed that engineered biofilm barrier has the potential to enhance the performance of the CO2 geological storage. It is competitive to use CO2 triggered gelation to control the CO2 leakage. The gel can only form with the presence of CO2 and relatively high temperature (reservoir temperature), which indicates that this method has good controllability and effective mobility before gel solution encounters CO2. The gel exhibits its effect of blocking leakage by reducing the relative permeability of CO2 or brine. This method can be served as an assistant technology before cement injection or a blocking method itself. In summary, corresponding CO2 leakage mitigation methods have not been adopted or enabled in CO2 geological storage demonstration projects, which means the success of storage projects depends on the integrity of the formation. In the case of CO2 leakage, conventional leakage mitigation methods, including cement injection, hydraulic barriers and other mechanical sealing methods, can play a role in leakage control to a certain extent. However, chemical methods should be taken into consideration to assist


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conventional leakage mitigation methods or adopted independently with some limitations of conventional leakage mitigation methods. Especially for narrow leakage channels (aperture less than 400µm), conventional leakage mitigation methods exhibit poor performance in selectivity, operability, adaptability and economy. For example, cement system with high viscosity cannot be easily injected or squeezed into this kind of leakage channel, which reduces the effectiveness of leakage control. In this paper, a mixture of polymer and crosslinker carrier with relatively low viscosity, which can be triggered for gelation with the presence of CO2 and relatively high temperature (reservoir temperature), was applied to block the CO2 leakage and its chemical mechanisms were exhibited. Its blocking performance was evaluated through experimental works. The experimental results were reproduced by reactive flow simulation using CMGSTARS.30 Finally, the feasibility of this method in field scale was investigated by the reactive flow simulation. The proposed CO2 leakage mitigation method can be used to assist the remediation process using cement system or applied alone in target zone with small aperture size of leakage path. 2. CO2 triggered gelation In this study, a modified polyacrylamide-methenamine-resorcinol gel system was applied as the CO2 triggered sealant for blocking CO2 leakage during geological storage process. Its economic efficiency has been demonstrated by successful oilfield application as a water shutoff system. The chemical mechanisms of this gel system are described below. With the presence of acid environment and reservoir temperature, methenamine can release formaldehyde. The released crosslinker (formaldehyde) can react with polyacrylamide (PAM) and resorcinol to generate phenolic resin. PAM can further react with the generated phenolic resin, which produces linear polymers. The product, i.e. phenolic resin and linear polymer, acts as the sealant for blocking the potential CO2 leakage paths. In these reactions, the methenamine can be regarded as crosslinker carrier and the crosslinkers will be released when the acid environment and relative high temperature present. In the CO2 leakage paths, CO2 dissolves in the solution and reduces its pH to an acidic environment when CO2 confronts the injected gel system. The reservoir condition can provide a relatively



higher temperature (reservoir temperature). Then the gelation can be triggered to block or control CO2 leakage with the generation of gel.31 A schematic of CO2 triggered gelation is exhibited in Figure 1.

Without CO2 Polymer

Crosslinker carrier

With CO2 at High Temperature Released Crosslinkers

Polymer

Gel

Figure 1. Schematic of CO2 triggered gelation.

3. Lab-scale experiments and reproduction by reactive flow simulation 3.1. Materials Modified PAM was purchased from the Sinopharm Chemical Reagent Co., Ltd, with an average molecular weight over 3 × 106 and solid content above 85.0 %. Methenamine, resorcinol, CaCl2 and NaCl2 were also achieved from the Sinopharm Chemical Reagent Co., Ltd. CO2 (purity ≥ 99.8 %) and N2 (purity ≥ 99.999 %) were supplied by Qingdao Tianyuan Gas Co., Ltd, China. Deionized water was made in lab and used in the experiments. The formation water was synthesized by deionized water, NaCl2 and CaCl2 with total salinity of 20, 000 ppm that included 1000 ppm of CaCl2. Quartz sand was applied to make the sand pack model, which can form the leakage pathways with the porous media. 3.2. Experimental apparatus and procedures Figure 2 shows the experimental set-up for evaluating the blocking performance based on CO2 triggered gelation. The set-up mainly consists of sand pack model, injection system, data acquisition system, monitoring system, and pressure and temperature control system. The sand pack tube is a stainless steel


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vessel. The injection system includes a constant flow pump and several piston cylinders. The constant flow pump can provide power to inject the respective fluids into the sand pack model. The floating piston cylinders are used to accumulate CO2, saline and gel system, respectively. An air bath is employed to simulate the reservoir condition and control the experimental temperature. A backpressure valve is adopted to maintain a simulated reservoir pressure. Monitoring system consists of temperature sensors and pressure transducers, which can measure the inner temperature and pressure drop across the sand pack model. All pressure and temperature values are recorded digitally by the data acquisition system. The experimental conditions for the leakage blocking test are showed in Table 1. The procedure of the experiment is summarized as follows. (1) The sand pack was filled up with quartz sands carefully with corresponding pressure being put on the top of sand body to avoid large voids between the sands. (2) The sand was then saturated with the simulated formation water, and backpressure and temperature were raised to 10.28 MPa and 80 °C. The water was injected into the sand pack model at a constant rate of 1 mL/min. The pressure difference across the sand pack model, ∆P1, was measured for calculating the initial permeability when the pressure difference became stable. (3) CO2 was injected into the sand pack until a complete gas leakage occurred at the outlet of the sand pack and the steady pressure difference across the sand pack, ∆P1C, was collected at the same time. (4) A slug of the gel system was injected into the sand pack model (0.3 pore volume (PV)). The composition of this system is shown in Table 2. (5) CO2 of volume equivalent to 0.3 PV was injected into the sand pack and all the valves were shut off for gel reaction. (6) After 8 hours, the formation water or CO2 was injected into the sand pack at an injection rate of 1mL/min, and the pressure difference for water (∆P2) or CO2 (∆P2C) was measured after 2 PV of fluid (water or CO2) was injected into the sand pack for calculating permeability reduction or resistance factor towards CO2. The permeability reduction, KR, can reflect the capability of gel for water shutoff, which is defined as



KR 

k1  k2  100% k1

(1)

where k1 is the initial permeability before the gel treatment; k2 is the permeability after the gel treatment. In this paper, because the injection rate was kept constant before and after the gel treatment, based on the relation of permeability with flow rate and pressure difference Eq. (1) can be expressed as the flowing equation: KR 

P2  P1  100% P2

(2)

where KR is also a measure of the water flow resistance with the formation of gels in the simulated leakage zone. The apparent resistance factor, Z, is usually applied to evaluate the blocking performance of gel towards gas such as CO2 which leaks from the storage structures. This factor can be expressed as follows: Z

P2C P1C

(3)

where Z represents the resistance towards CO2 after the gel formation in the sand pack model. Data acquisition system

Pressure transducer

Pressure transducer Air bath Backpressure regulator Sand pack

Gel system

Brine

Valve

CO2

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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Constant flow pump Measuring cylinder

Figure 2. Schematic diagram of the apparatus for evaluating the blocking performance.


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Table 1. Experimental Conditions for Evaluating the Blocking Performance Parameter

Value

Length of the sand pack model, cm

60

Inner diameter of the sand pack model, cm

2.5

Porosity

0.34

Pore volume, mL

100.1

Permeability, 10-3 µm2

30

Initial water saturation

1

Temperature, °C

80

Backpressure, MPa

10.28

Water salinity

20,000 ppm (1000 ppm Ca2+)

Table 2. Composition of the Gel System Component

Concentration, wt%

Modified PAM

1.0

Methenamine

0.4

resorcinol

0.1

3.3. Basic principles of reactive flow simulation After successful experimental verification of this leakage mitigation method based on the CO2 triggered gelation, its applicability to field scale leakage of CO2 should be modelled by numerical simulation. Before the model can be used in field scale, it needed to be validated by the experimental results. The reservoir simulation software, CMG-STARS, was applied here for the reactive flow simulation using this CO2 triggered gelation.



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After the gel formed in porous media, the relative permeability of water or CO2 can be reduced in simulation. The relative permeability change as a result of gel formation and adsorption in porous media is directly tied to the blocking performance. The relative permeability reduction or equilibrium blockage is given by kef  

kr  kabs Rk

(4)

where kefα is the effective permeability of phase α, kabs is the absolute permeability of the porous media or leakage paths, krα is the relative permeability of phase α and Rkα is permeability reduction factor. The permeability reduction factor in Eq. (4) can be expressed as follows:

Rk  1   RRF   1 

Ad Ad max t

(5)

where Rkα is permeability reduction factor; RRFα is the residual resistance factor to the phase α; Ad is the adsorption of gel to be used in CMG-STARS, gmol/cm3; Admax is the maximum adsorption capacity, gmol/cm3. 3.4. Lab-scale model As exhibited in Figure 3, a one-dimensional Cartesian grid model with 24 × 1 × 1 was built in terms of experimental sand pack model, and the grid dimensions in X, Y and Z directions are 2.5 cm, 2.215 cm and 2.215 cm, respectively. The injection point was placed in the grid (24, 1, 1), and the production point was placed in the grid (1, 1, 1). The other initial conditions were set according to the experimental works as summarized in Table 1.

Production point

Injection point

(1, 1, 1)

(24, 1, 1)

Figure 3. One dimensional Cartesian grid model.


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3.5. Experimental and simulation results Experimental data are plotted with filled circles in Figure 4 and Figure 5. Formation water saturated with CO2 may leak from the storage bodies with the presence of leakage paths when the condition changes cannot induce sufficient release of CO2 from the formation water. Figure 4 shows that the formed gel can increase resistance to water flow with reducing the relative permeability of water by more than 85 %, which indicates that this CO2 triggered gel can block leakage paths effectively. It is notable that the formed gel has remarkable resistance to washout with the final relative permeability reduction remained at 85 % after 2 PV formation water injected. 100 90 80 70 60

KR, %

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


50 40 30

Experimental data

20

Numerical simulation data

10 0 0

0.5

1

1.5

2

2.5

Injection Pore Volume, PV

Figure 4. Changes and history matching KR in the last run of water injection.

In some cases, CO2 may leak from storage structures in single phase. Gaseous or super critical CO2 can accumulate under the caprock or seal layer when the injected CO2 is excessive or has some other incentives because of the existence of buoyancy. Hence, it is important to evaluate the performance of this CO2 triggered gel to block CO2. As seen in Figure 5, the formed gel exhibited good blocking performance towards CO2 with the final resistance factor larger than 29. Although the curve of apparent resistance factor (Z) changing with CO2 injection pore volume showed fluctuation, the resistance factor kept a relatively high



level with 2 PV CO2 injected, which implied that the formed gel can reduce the mobility of CO2 effectively with good stability. 50 45 40 35 30

Z

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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25 20 15

Experimental data

10

Numerical simulation data

5 0 0

0.5

1

1.5

2

2.5

Injection Pore Volume, PV

Figure 5. Changes and history matching Z in the last run of CO2 injection.

The results of reactive flow simulation are shown in Figure 4 and Figure 5 with a solid line. The simulated blocking performance, which was exhibited by parameter of KR and Z, reproduced well the injection pore volume variation of the measured blocking performance. As it can be seen in Figure 4 and Figure 5, the formed gel provided effective resistance to the fluids which may leak from the storage body. The stability and remarkable resistance to scouring were also reproduced by the simulation works with the final KR of 85.4 % and Z of 29.6 after injection of 2 PV formation water or CO2. As it can also be seen in Figure 6, the adsorption of formed gel varied with injection pore volumes in different grid during the last run of water injection for gel strength testing. Maximum adsorption can be more quickly achieved with the grids being closer to the injection point. The adsorption distribution results of formed gel with the injection of 2 PV formation water are shown in Figure 7. The grids, which are closer to the injection point, showed larger maximum adsorption. The changes of pressure during the last run of formation water injection are exhibited in Figure 8. The propagation of pressure was achieved and pressures


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can be maintained at constant levels in different grids with injection of more formation water. Pressure difference across the sand pack model signified the blocking performance with the formed gel and determined the parameter of KR. Pressure differences in different grid intervals with the injection of 2 PV formation water are plotted in Figure 9. Pressure differences in the grid intervals which are closer to the injection point contributed more to the total pressure difference across the sand pack model. This phenomenon indicates that the blocking barrier can form near the leakage zone and limit the leakage of CO2 to a small range, which will eliminate the negative effects of CO2 leakage. 0.06 0.05

Adsorption mass density, lb/ft3

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


0.04 0.03 0.02 0.01 0.00 0

0.5

1

1.5

2

2.5

3

Injection pore volume, PV 24,1,1 18,1,1 12,1,1 6,1,1

23,1,1 17,1,1 11,1,1 5,1,1

22,1,1 16,1,1 10,1,1 4,1,1

21,1,1 15,1,1 9,1,1 3,1,1

20,1,1 14,1,1 8,1,1 2,1,1

19,1,1 13,1,1 7,1,1 1,1,1

Figure 6. Injection pore volume variations of the adsorption mass density in different grids.



Adsorption mass den, lb/ft3

0.06 0.05 0.04 0.03 0.02 0.01 0.00 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1

Grid number in X direction

Figure 7. Adsorption results in different grids with injecting 2 PV formation water. 2890 2690 2490

Pressure, psi

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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2290 2090 1890 1690 1490 0

0.5

1

1.5

2

2.5

3

Injection pore volume,PV 24,1,1 18,1,1 12,1,1 6,1,1

23,1,1 17,1,1 11,1,1 5,1,1

22,1,1 16,1,1 10,1,1 4,1,1

21,1,1 15,1,1 9,1,1 3,1,1

20,1,1 14,1,1 8,1,1 2,1,1

19,1,1 13,1,1 7,1,1 1,1,1

Figure 8. Injection pore volume variations of the pressure in different grids.


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160 140

Pressure difference, psi

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


120 100 80 60 40 20 0 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9

8

7

6

5

4

3

2

1

Number of grid interval

Figure 9. Pressure differences in different grid intervals.

4. Field-scale simulation 4.1. Leakage mitigation technology Pre-placed technologies, i.e. scale squeeze treatment, attract more and more attentions in oil and gas industry. In order to deal with the significant flow assurance problem such as oilfield scale deposition, the method of pre-placed scale inhibitor, which is also known as scale squeeze treatment, has been commonly applied in the oilfield operations with the advantage of control/preventing the formation of oilfield mineral scale. It consists of the injection of scale inhibitor solution into the reservoir through the producing well. The chemical then will be back produced protecting all locations from the wellbore to the topside facilities. The success of squeeze treatment mainly depends on the interaction between the chemical and the rock formation, which retains the chemical, allowing a gradual release in the produced brine over an extended period. Its feasibility and economic efficiency have been demonstrated by the applications in the oilfield.32,33 Hence, this technology is also adopted to evaluate the feasibility of the leakage blocking method based on CO2 triggered gelation with field scale in this study. The assumed aquifer overlaying the leakage path has



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been filled with CO2 triggered gel system in advance of the occurrence of CO2 leakage. The CO2 triggered gel system fills the lateral region sufficiently for building a barrier to block the migration of CO2. The schematic of the pre-placed technology for blocking CO2 leakage is shown in Figure 10. CO2 triggered gel system

Formed gel with CO2

CO2 injection well

Leakage path

CO2

Reservoir

CO2

Figure 10. Schematic of pre-placed CO2 triggered gel system for remediation of CO2 leakage.

4.2. Field-scale model The existence of high permeability paths across a sealing layer may induce considerable leakage of CO2 from a reservoir to an aquifer or other kinds of layers overlaying the sealing layer. Therefore, a 3-D caprockaquifer system was assumed here as exhibited in Figure 11. The blank area between two colour layers represents an impermeable layer (caprock). The assumed aquifer overlaying the caprock is 304.8 m in length, 152.4 m in width and 9.144 m in thickness, respectively. The length, width and thickness of the reservoir for CO2 storage are the same as the aquifer. The CO2 storage reservoir is covered with a caprock of 30.48 m thick. The caprock contains a vertical leakage paths with the permeability of 1000 mD. Initial porosity and permeability of the reservoir and aquifer are set to be 0.15 and 20 mD, respectively. Moreover, initial reservoir temperature and pressure are set to be 80 ºC and 10.28 MPa, respectively. The distance between the CO2 injector and leakage path is 30.48 m. All the layers in the reservoir are perforated. Injection


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of CO2 in a liquid phase was started at January 21, 2000 through all the perforated layers in the reservoir and continued over a period of 90 days with the total amount of injected CO2 to be 10507.2 ft3 (297.53 m3).

Figure 11. 3-D concept model to simulate leakage of CO2 in an assumed caprock-aquifer system.

4.3. Results of field-scale reactive flow simulation As exhibited in Figure 12, the leakage of CO2 was serious with the presence of leakage path at 40th day during CO2 injection and 1890th day after ceasing injection, which represented two typical situations during CO2 injection and after shut in CO2 injection well. Figure 12a showed that the leakage can occur even during the injection process with close distance between CO2 injection well and leakage path. As it can be observed in Figure12b, CO2, which leaked from the reservoir through the leakage path, migrated laterally in the aquifer overlaying the caprock after shut in CO2 injection well. Although the CO2 injection process was carried out only 90 days, the pressure propagation from the reservoir to the overlaying aquifer lasted over the whole simulation period with the small scale of the assumed leakage path (0.2ft in width). The continuous pressure propagation induced the phenomenon of lateral CO2 migration. It is notable that CO2



migration is asymmetrical around the leakage path with higher CO2 saturation on the right side, which is induced by the close distance between the leak path and left boundary of aquifer.

(a) 40 days during CO2 injection

(b) 1890 days after shut in CO2 injection well

Figure 12. CO2 saturation without treatment.

In order to block or control the leakage of CO2, pre-placed technology was adopted which has been illustrated in section 4.1. In scenario 1, an injection well was located on the left side of the leakage path for injecting CO2 triggered gel system into the assumed aquifer overlaying the caprock in advance of the occurrence of CO2 leakage as shown in Figure 13. The effect of leakage control is shown by comparison of its results with the scenario without any treatment. However, a small amount of CO2, which leaked from the storage reservoir, migrated in the opposite direction with the formation of gel barrier.


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(a) CO2 saturation with injecting gel system using left injection well in semi-global scale (left) and local enlarged view (right)

(b) Adsorption of gel (lb/ft3) with left injection well in semi-global scale (left) and local enlarged view (right) Figure 13. Scenario 1 with left injection well of gel (1890 days after shut in CO2 injection well).

In scenario 2, the injection well was located in front of the leakage path as shown in Figure 14. As can be seen in Figure 14, this method in scenario 2 can also provide effective barrier for the leakage of CO2 with smaller scale of CO2 leakage in the aquifer overlaying the caprock. But it is not as powerful as the effect of controlling CO2 leakage in scenario 1 with relatively worse distribution of formed gel.



(a) CO2 saturation using gel system injection well in front of leakage path in semi-global scale (left) and local enlarged view (right)

(b) Adsorption of gel (lb/ft3) with gel system injection well in front of leakage path in semi-global scale (left) and local enlarged view (right) Figure 14. Scenario 2 with gel system injection well in front of leakage path (1890 days after shut in CO2 injection well).

In scenario 3, three injection wells for injecting gel system were assumed around the leakage path as shown in Figure 15. The injection rate in each well was set to 1/3 of the injection rate in the scenario with single injection well such as scenario 1 and 2. By comparing the leakage status (CO2 distribution in aquifer overlaying caprock) in scenario 1 and 2, the leakage of CO2 in scenario 3 was inhibited more effectively. The distribution of formed gel in scenario 3 is much more uniform around the leakage path than that in


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scenario 1 and 2. It implied that infill drilling around the leakage path can enhance the performance on blocking CO2 leakage based on this pre-placed technology using CO2 triggered gelation.

(a) CO2 saturation with injecting gel system using three injection wells in semi-global scale (left) and local enlarged view (right)

(b) Adsorption of gel (lb/ft3) with three injection wells in semi-global scale (left) and local enlarged view (right) Figure 15. Scenario 3 with three injection well (1890 days after shut in CO2 injection well).

For the purpose of evaluating the influence of distance between the injection well for injecting gel system and leakage path, an injection well was placed closer to the leakage path than that in scenario 1 as exhibited in Figure 16. The leakage scale of CO2 was reduced significantly with closer distance between injection



well and leakage path. As seen in Figure 16b, CO2 triggered gelation occurred more in the leakage path with the closer distance between gel system injection well and leakage path, which indicated that more gel system can transport into the leakage path with the closer distance. It is recommended that monitoring method with high accuracy should be incorporated in this remediation method in order to drill relief well as close as possible to the leakage path.

(a) CO2 saturation with injecting gel system using left injection well closer to leakage path in semi-global scale (left) and local enlarged view (right)

(b) Adsorption of gel (lb/ft3) with left injection well closer to leakage path (left) or relatively farther to leakage path (right) Figure 16. Scenario 4 with left injection well closer to leakage (1890 days after shut in CO2 injection well).


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Although the relatively higher temperature can accelerate the gelation process, the formed gel will become unstable with the presence of extreme high temperature. Meanwhile, severe leakage scenario with excessive pressure difference also restricts the application of this method. Hence, extreme temperature and pressure conditions should be taken into consideration before applying this remediation approach. 5. Conclusions CO2 leakage eliminates the benefits from the CO2 storage and may harm the ecological environment. A method based on CO2 triggered gelation is proposed for controlling CO2 leakage and the feasibilities of this method in lab and field scale were evaluated through experimental and reactive flow simulation works. Following conclusions can be drawn from this study. 1. The experimental results showed that effective performances on blocking leakage were achieved both in the tests with CO2 and formation water using the method based on CO2 triggered gelation. 2. The blocking performance was reproduced well by reactive flow simulation works using a onedimensional Cartesian grid model with the final KR of 85.4 % and Z of 29.6 after injection of 2 PV formation water or CO2. 3. Pressure differences in the grid intervals, which are closer to the injection point, contribute more to the total pressure difference across the sand pack model with adsorption of more formed gels. Gel can be achieved or adsorbed more easily near the leakage path which may limit the CO2 leakage to a small range. 4. Feasibility of this method for blocking CO2 leakage using CO2 triggered gelation was also demonstrated in field-scale reactive flow simulation. Without any remediation on the assumed CO2 leakage, large scale CO2 migrated to the assumed aquifer overlaying the caprock through the leakage path. Infill drilling and monitoring method with high accuracy are recommended to be incorporated in this remediation method to enhance the blocking performance.

Acknowledgment The authors would like to acknowledge the National Postdoctoral Program for Innovative Talents (Grant No. BX20180182) for the support of this research. This research is also partially financed by China



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Polymer

CO2 injection well

Crosslinker carriers

CO2 Leakage path Crosslinkers CO2 Gel

ACS Paragon Plus Environment

CO2

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Leakage Mitigation During CO2 Geological Storage Process

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