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Permeability Evolution in Sandstone due to CO2 Injection Ahmed Zarzor Al-Yaseri, Yihuai Zhang, Mohsen Ghasemiziarani, Mohammad Sarmadivaleh, Maxim Lebedev, Hamid Roshan, and Stefan Iglauer Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 05 Oct 2017 Downloaded from http://pubs.acs.org on October 5, 2017

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Permeability Evolution in Sandstone due to CO2 Injection

Ahmed Al-Yaseri1*, Yihuai Zhang 1, Mohsen Ghasemiziarani1, Mohammad Sarmadivaleh1, Maxim Lebedev2, Hamid Roshan3, and Stefan Iglauer1 1

Curtin University, Department of Petroleum Engineering, 26 Dick Perry Avenue, 6151

Kensington, Australia 2

Curtin University, Department of Exploration Geophysics, 26 Dick Perry Avenue, 6151

Kensington, Australia 3

School of Petroleum Engineering, University of New South Wales, Kensington, Sydney,

Australia *email address of the corresponding author: [email protected]

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Abstract Permeability variation is one of the key factors influencing the injectivity of CO2 in CO2 sequestration projects. Despite the research carried out on the subject, the results are highly inconsistent. In this study, the injection of brine (5wt% NaCl+ 1wt% KCl), CO2-saturated (live) brine and supercritical CO2 were performed on three homogenous Berea with low clay content and two Bandera Gray sandstone with high clay content at reservoir conditions (10MPa and 323K). Porosity and permeability of the samples were measured using NMR (nuclear magnetic resonance T2 relaxation time), and dynamic (during flooding) permeability measurement technique respectively at different injection rates and injection durations. Mercury intrusion test was also performed on each sample to further evaluate its pore throat size distributions. From the results of this study, it was revealed that CO2 injection rate is unlikely to affect the permeability significantly. It was also shown that the permeability can be influenced depending on sandstone pore throat size distribution and the distribution/structure of the clay minerals in the sample.

Keywords CO2 sequestration; Permeability Evolution; carbonic acid; sandstone; clay minerals


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1. Introduction CO2 emission has been recently recognized as a major cause of climate change1. Growing demand for energy due to industrialization is leading to further increase in fossil fuel consumption and consequently generation of CO21-2. CO2 injection into hydrocarbon reservoirs to enhance oil and gas recovery3-4 and the CO2 sequestration (CGS) in deep sandstone saline aquifers, on the other hand, have offered an opportunity to reduce CO2 emission1. It is, however, important to understand the nature of the interaction between fluid and rock in order to safely store CO2 in the ground5-8. Such interactions affect the aquifer permeability and consequently the injectivity9. Therefore, permeability and permeability alteration need to be carefully evaluated to properly design CO2 injection facilities. Injected CO2 dissolves in formation water producing a weak carbonic acid6,7,10. This acid reacts with rock minerals leading to ions dissolution-precipitation as well as forming secondary minerals11. Sandstone formations are amongst the best candidates for CO2 sequestration1. Sandstones typically contain different components (cement, clays) other than quartz12, and these impurities in particular calcite cement usually have a substantially higher reactivity in an acidic environment than quartz7,13. In fact, the presence of CO2 at reservoir condition lowers the pH to about 3-4 (live brine)14-15 where the impact of such acidic environment on the permeability and pore morphology can be significant. The main reactions that occur during the dissolution of CO2 in water are5: CO2 + H2O

H2CO3

(1)

H2CO3

HCO3- + H+

(2)

HCO3-

CO32- + H+

(3)


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On the other hand, CO2 can be trapped in the pore space for several hundreds of years due to the slow dissolution kinetics triggered by limited mixing between the CO2 and the brine16. In initial attempts to investigate such variability, Sayegh et al.5 tested five sandstone reservoir samples from the Cardium formation in the Pembina Oil Field area of Western Canada at pressure of 13.8MPa, temperature of 318 K and flow rate of 0.3 cm3/min for carbonated brine (5wt% NaCl+ CO2) i.e. the average permeability and porosity of the sample was measured as 0.04mD and 0.13 respectively and the XRD analysis showed quartz (~ 50%), chert, siderite and calcite as dominant minerals. Sayegh et al.5 reported that the permeability of the samples dropped by almost 93%; however, it increased and approached the initial permeability value after 25 to 50 hours of the flooding time. Furthermore, the calcium ion content (150 and 250 ppm) slightly increased in the collected effluent while the level of sodium ions stayed unchanged during the test (no significant amount of magnesium ion was observed). In addition, one more sample was flooded by noncarbonated-brine (without CO2) in their experiment and no calcium or magnesium ions were observed. Sayegh et al.5 concluded that the initial permeability reduction occurred by fines migration through pore throat blocking mechanism. The fines blocking the pore throats were later dissolved and permeability was therefore increased. Ochi and Vernoux17 observed a permeability decline by more than 50% due to injection of synthetic (no CO2) brines (0.01 to 0.5M NaCl) into Berea sandstone plugs (from Ohio, the USA with average permeability ̴ 380mD) at reservoir conditions (pressure 22MPa and temperature 363K). They observed a higher permeability reduction by increasing the injection rates (≥ 3.6 cc/sec). It was therefore hypothesised that the permeability reduction is linked to fine migration and resultant plugging which initiated by the chemical reaction between the injected fluid and the rock. It was further shown that a critical flow rate exists above which the permeability decreases as a consequence of the hydrodynamic release of 4 ACS Paragon Plus Environment

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particles. This critical flow rate is found to be higher than those reported in the literature. The filtering or size exclusion appeared to be the principal cause of permeability decrease at high injection flow rates. They concluded that the hydrodynamic effect can reduce the permeability by more than 50%, but is less severe than the chemical effect. Interestingly, a significant reduction in CO2 injectivity (from 10 to 100%) has been reported in field trials

19-20

. Wellman et al.18 however reported that the overall mineral dissolution is

relatively uniform and the surface reaction rate was quite slow during the CO2 injection into sandstone rocks. Moreover, Raistrick et al.21 observed an increase in Ca2+, Mg2+, K+, SO4 2, HCO3-, and CO2 concentrations in produced brines after CO2 injection (for EOR purpose) into a sandstone reservoir (Weyburn oil field in Canada). These observations were due to dissolution of calcite, dolomite, and K-feldspars. In addition, Nightingale et al.6 tested different sandstone samples from the Cardium formation in the Pembina field (Alberta, Canada) and found residual clays and feldspar particles in the rock sample after CO2 flooding. Mohamed et al.22 tested Berea samples (XRD showed 79.61wt% quartz, 7.21wt% kaolinite, and 4.11wt% illite) at constant pressure (8.96MPa) and flow rate (5.0 cm3/min) while the temperature ranged from 294 to 394 K. A considerable reduction in cores permeabilities were observed (35 to 55% loss) due to CO2 injection (WAG cycles of CO2 and brine, or continuous CO2 injections). In their experiments, the calcium ion concentration slightly increased (from 5.023 to 7.393 wt%) in the effluent brine while the concentration of sodium and magnesium ions did not vary significantly. Furthermore, for longer WAG injection (less brine volume injected per cycle and low temperature) less permeability reduction was noted. The permeability damage was explained by precipitation of the reaction products and migration of clay particles.


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On the other hand, Pini et al.23 did not observe any change in the permeability (no change in pressure drop across the core) of Berea samples (280mD) due to CO2-saturated brine injection. Their experiments were carried out at reservoir conditions (9 MPa pore pressure, 12 MPa confining pressure, 298 and 323K temperatures and flow rates varying from 1 to 50 ml/min); however, their Berea sandstone samples were heated to 973 K for 2 hours to stabilize swelling clay minerals initially. Ma and Morrow24 clarified that no clay minerals were observed in Berea after heat treatment (≥973K). Therefore the permeability alteration by clay destabilization was supposed not to occur in Pini et al.23 study5,11. Iglauer et al.25 reported permeability reduction (up to 35%) in one Berea sandstone (95wt% quartz) sample due to CO2-saturated or unsaturated brines injection at CO2 storage condition (10MPa and 323K) i.e. the permeability reduction was more significant at higher injection rates (≥ 10 cc/min). The permeability, however, was not significantly affected in Fontainebleau sample (100wt% quartz) for the same testing conditions in their experiments. Fine migration was therefore hypothesised as the main mechanism of permeability reduction in Berea sandstone sample. However, it has been well-documented that the reaction kinetic rate between the clay minerals and acid is very slow26-31 emphasising that the clay particle detachment should reduce in acidic environment. In addition, Schembre and Kovscek32 carried out theoretical and experimental studies on Berea sandstone at moderate salinity (0.01–0.05M NaCl) and alkaline pH (7–10) conditions. They demonstrated that when increasing the temperature, alkalinity, or reducing salinity, fine mobilization was increased. Gabriel and Inamdar33 also found that mechanical particle mobilization kicks off as soon as critical flow velocity is exceeded (0.007 cm/sec for Berea sandstone, 150 mD permeability) i.e. permeability will decrease if the flow rate increases.


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It is therefore evident that there is not yet a solid understanding in terms of the factors controlling the permeability alteration (of sandstone) during core flooding, with CO2 as the working fluid. Thus in this study three sister Berea (low clay content) and two Bandera Gray (high clay content) sandstone plugs have been flooded by dead brine, live brine and scCO2 at reservoir storage conditions with different injection rates, to investigate the effect of clay content, type of injection fluid, and flow rate on sandstone rock physical properties. 2. Experimental Methodology Sample preparation Three Berea and two Bandera Gray sandstone plugs, which are homogeneous in porosity and permeability, were used in this study. The mineral composition of these samples was measured by XRD (with a Bruker-AXS D8 instrument). Berea sandstone was composed of ̴ 80wt% quartz and 1.4wt% chlorite, 7.3wt% kaolin, 2.9wt% albite, 1.7wt% ankerite and 6.7wt% microcline and Bandera Gray sandstone was composed of ̴ 58.2wt% quartz, 5.7wt% chlorite, 6.8wt% kaolin, 12.4wt% albite, 15.3wt% ankerite, 1.6wt% muscovite. In addition, the samples’ petrophysical properties were measured and listed in Table 1 (the porosity and nitrogen permeability was measured by AP-608 Coretest instrument and the NMR porosity was measured with a 20 MHz Bruker Minispec (1H resonance) instrument). Additionally, the mercury intrusion was conducted on sub-sample of each main sample to obtain the pore size distribution using a PoreMaster GT instrument. In order to prepare the sample, the core plugs were wrapped in PTFE tape, Aluminum foil, and again PTFE tape and then sealed with a PTFE heat shrink sleeve and finally placed in a rubber sleeve (ends were open) which was housed in a high pressure and temperature core holder, Figure 1. All samples were initially vacuumed for more than 20 hours. The effluents


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were also collected during each test and analyzed using XRD. The surface morphology of the samples was also captured using SEM analysis.

Water bath, 323K I S C O I S C O

Pressur e Sensor

Pressur e Sensor

Core holder

Pore Press. 10MPa

Back Press. 10MPa

Valv

Data

I S C O

CO2 Cylinde r

Conf. Press. 15MPa

Reactor Controll er

10MPa and 323K

Figure 1. Schematic of the core flooding apparatus used in this study.

Test scenarios In order to simulate the reservoir condition before and after injection of CO2, the injection of dead brine (5wt% NaCl + 1wt% KCl in deionized water1, pH = 7.85) was first performed (because saline aquifers are initially saturated with brine), followed by injection of live brine (dead brine saturated by CO2 prepared by a mixing reactor34, pH = 3-414-15) because CO2 will mix with the formation brine after injection and subsequently supercritical CO2 to simulate the near wellbore area which will be saturated with only supercritical CO21. The flow rate was varied for each fluid: 1, 5, 10 ml/min. The pore pressure of 10MPa, confining pressure of 8 ACS Paragon Plus Environment

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15MPa and temperature of 323K were kept during the tests with a high precision syringe pump (ISCO 500D; pressure accuracy of 0.1% FS). In the first set of tests, each of three Berea samples was first flooded with approximately five pore volumes of dead brine (initially with 1 ml/min, followed by 5 and then 10 ml/min), then live brine and supercritical CO2 with the same flow rates and volume. A final injection of dead brine with 5ml/min for all Berea samples was performed mostly to measure the final permeability. In the second set of tests, the same procedure (injection of dead brine, live brine, and supercritical CO2 at different flow rates and a final flooding with dead brine with 0.5ml/min flow rate at the same reservoir conditions) was adopted for two Bandera Gray samples. Finally, the same core plugs were exposed to live brine for 7 days under reservoir conditions (15MPa confining stress, 323K temperature, 10MPa pore pressure, and flow rate of 0.005 ml/min) to test the long term storage of CO2 (dissolved in brine)11. The three Berea samples were then flooded with live brine and dead brine again with 1, 5, and 10 ml/min and two Bandera Gray samples were flooded with 0.5 ml/min of dead brine. A high accuracy pressure sensors (Keller33X, accuracy = ±1500Pa) were used to measure the pressure drop continuously across the core plug, and the dynamic brine permeability was calculated using Darcy’s law17,25 subsequently. In addition, NMR and Nitrogen Permeability-Porosity measurements were performed before and after 7 days of exposure to live brine for permeability analysis.


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Result and discussion Figures 2, 3, and 4 show the pressure drop with time measured at 1 ml/min flow rate with different fluids (dead brine, live brine, and scCO2) for the Berea #1-3 samples respectively.

12

dead brine

live brine

sc-carbon dioxide

Pressure drop [kPa]

11 10 9 8 7 6 5 4 0

10000

20000

30000

40000

50000

60000

Time [Sec]

Figure 2. Average pressure drop (standard deviation ≈ 0.37 KPa) across the Berea sample #1 vs time for dead brine, live brine and scCO2 injections at l ml/min injection rate.

12 11

Pressure drop [kPa]

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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dead brine

live brine

sc-carbon dioxide

10 9 8 7 6 5 0

10000

20000

30000 Time [Sec]

40000

50000

60000

Figure 3. Average pressure drop (standard deviation ≈0.37 KPa) across the Berea sample #2 vs time for dead brine, live brine and scCO2 injections at l ml/min injection rate.


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12 11

Pressure drop [kPa]

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dead brine

live brine

sc-carbon dioxide

10 9 8 7 6 5 0

10000

20000

30000 Time [Sec]

40000

50000

60000

Figure 4. Average pressure drop (standard deviation ≈ 0.37KPa) across the Berea sample #3 vs time for dead brine, live brine and scCO2 injections at l ml/min injection rate.

The dynamic permeability as a function of time for the three Berea samples for cases a) before any flooding, b) after flooding with dead-brine, live-brine and Supercritical CO2 and c) after 7 days of exposure to live brine at reservoir conditions (pore pressure 10 MPa, confining pressure 15MPa and temperature 323K) and then flooded with dead brine are presented in Figures 5, 6, and 7.


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100

initial at 1 ml/min after flooding at 1 ml/min after exposure at 1 ml/min after exposure at 5 ml/min after exposure at 10 ml/min

90 Permeability [md]

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80

70

60 0

5000

10000

15000

20000

Time [Sec]

Figure 5. Average brine permeability (standard deviation ≈4 mD) of the Berea sample #1 as a function of dead brine injection time.


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110

100

initial at 1ml/min after flooding at 1 ml/min after exposure at 1 ml/min after exposure at 5 ml/min after exposure at 10 ml/min

Permeability [md]

90

80

70

60

50

Figure 6. Average brine permeability (standard deviation ≈4 mD) of the Berea sample #2 as a function of dead brine injection time

110

initial at 1 ml/minl after flooding at 1 ml/min after exposure at 1 ml/min after exposure at 5 ml/min after exposure at 10 ml/min

100 90

Permeability [md]

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80 70 60 50 40 30 0

5000

10000

15000

20000

Time [Sec]

Figure 7. Average brine permeability (standard deviation ≈ 4 mD) of the Berea sample #3 as a function of dead brine injection time. 13 ACS Paragon Plus Environment

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Berea #1 (Figure 5) shows a slight increase in permeability (from 69 to 76 mD) after flooding with approximately five pore volumes of dead brine, live brine and scCO2 at flow rates 1ml/min (marked as “after flooding” on the figure) and also after exposure to live brine for 7 days (permeability increase from 69 to 80 mD). Berea #2 (Figure 6) permeability very slightly decreased (from 67 to 63 mD) after flooding; however, the permeability increased by ̴ 37% (from 67 to 90 mD) after exposure to live brine. Berea #3 (Figure 7) shows a decrease in permeability after flooding (from 64 to 49 mD) and an increase in permeability after exposure to live brine (from 64 to 85 mD). The permeabilities for all Berea samples were not significantly influenced by fluid types or the injection rates (Figures 5 to 7). Moreover, the independent nitrogen permeability measurements showed consistent permeability results for all Berea samples, Table 1. Furthermore, porosity remained constant for all three above mentioned samples (see Table 1). Figures 8 and 9, show the permeability evolution versus time for the Bandera Gray samples (high clay content) at reservoir conditions (pore pressure 10 MPa, confining pressure 15MPa, temperature 323K and flow rate 0.5ml/min) after flooding. Insignificant change in permeability; similar to the low clay content samples were measured: Bandera Gray #1(from 8.63 to 8.9mD) and Bandera Gray #2 (from 9 to 7.3mD) i.e. porosities remained constant, (see Table 1).


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10

Permeability [md]

initial after flooding after exposure

9

8 0

5000

10000

15000

20000

Time [Sec]

Figure 8. Average brine permeability (standard deviation ≈ 2 mD) of the Bandera Gray #1 as a function of dead brine injection time (0.5 ml/min injection rate).

10

initial after flooding after exposure

9

Permeability [md]

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8

7

6 0

5000

10000

15000

20000

Time [Sec]

Figure 9. Average brine permeability (standard deviation ≈ 2 mD) of the Bandera Gray #2 as a function of dead brine injection time (0.5 ml/min injection rate).


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Civan35 reported that particle bridging can only occur if the ratio (β) of pore throat to particle diameter is less than seven36-39. As a result, the permeability can decreases if β7 5,32,33,35,40 owing to changes in pore throat size as a result of

fine migration. Changes in permeability are thus often expected when clay minerals are present in the sample. However, the detachment of the clay minerals into the bulk fluid is a strong function of the spatial distribution and structure of the clay minerals in the rock matrix, and the physicochemical conditions (such as temperature, pH, type of clay minerals and type of ions along with their ionic strength). Clay minerals can be a) structurally embedded within the rock grains or b) dispersed on the pore wall (pore surface coating) as well as in the pore space. Obviously, dispersed clay minerals especially in the pore space are much more likely to be mobilized compare to structural clay where clay minerals are in the rock grains. The microstructural analysis of the sample using SEM imaging showed that the clay minerals in Berea and Bandera Gray core samples were mostly structural clays placed within the rock matrix (Figures 10 and 11) i.e. the clay minerals are not dispersed in the pore space or coated the pore walls but rather embedded in the quartz grains. In addition, the effluent was collected and filtered through filter paper (pore size 1µ41) and then analysed by XRD (figure 12). The effluent sample contained traces of quartz and calcite with some Mg substation (the calcite peak shifted, indicating substitution of Mg into the calcite structure) and kaolinite; however, the majority of the sample appears to be a regularly interstratified mixed layer clay with diffraction peaks at 7.74, 3.86, 2.60 Angstroms). Figure 13 shows the SEM of collected particles with an average diameter of 0.16 µm. With this size (0.16µm), any fine should be able to migrate within pore throats without major blocking (see the permeability Berea 1 and 2 (Figures 5 and 6) as well as Bandera Gray


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samples (Figures 8 and 9) after flooding) or with slight blocking (see the permeability of Berea 3 (Figure 7) after flooding - which slightly decreased and then increased again). It, however, should be kept in mind that the amount of collected solid particles in effluent are insignificant compare to total clay content of the samples and no significant permeability changes occurred, even for Bandera Gray sandstone with total weight (wt) of 41% clay content. In addition, the MICP pore size distribution analysis for both Berea and Gray samples showed quite a similar pore throat sizes (average pore throat size 10 µm) (Figure 14a and b). This supports the abovementioned discussion that clay particle detachment was minimal and migration of slight detachment was not able to impair the permeability in both samples significantly due to size of pore throats. The slight dispersed clays in the samples was not also significantly destabilised due to the fact that clay minerals stay quite stable in acidic environment and solution with high ionic strength. This has been widely seen in many works related to shale and shale gas reservoirs where clay-rich rocks are of interest. As an example, Roshan et al42 observed that shale with almost 40 wt% clay minerals did not show significant structural changes in 5% NaCl solution, while the identical sample was completely disintegrated in deionized water. They also reported that solution imbibition into shale is a strong function of ionic strength, ion type and clay type with a variation of the thickness of the diffuse double layer as the mechanism43. It is also documented that the presence of acidic environment stabilizes the clay minerals44 . Therefore it is contured-intuitive to expect that clay minerals stay quite stable in the experiments conducted herein where the system has high ionic strength and is acidic. The concepts proposed in this study are applicable to any other clay-rich system and resultant clay destabilization. If clay minerals are dispersed and the exposed solution can also destabilise the clay minerals, the particle detachment is expected; such particle detachment will impair the permeability if the pore throat is sufficiently narrow. Impaired permeability can obviously 17 ACS Paragon Plus Environment

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recovers with time if the viscous force (induced by the flowing fluid) washes the fines out of the pores or the change in exposed solution can deflocculate the clay particles. Table 1: The petrophysical properties of the sandstone plugs before and after experiments (porosity and permeability values were measured at 15MPa effective stress). Before experiment sample

Porosity

NMR

Klinkenberg

Brine

length

diameter

[%]

Porosity

permeability

permeability

[mm]

[mm]

[%]

[mD]

[mD]

Berea 1

20

21

218

69

50.88

30.78

Berea 2

20

20

209

67

60.02

30.78

Berea 3

20

18.

211

64

60.07

30.78

Bandera

20

18

19

8.6

60.32

30.80

20

18

17

9

60.35

30.81

Porosity

NMR

Klinkenberg

Brine

length

diameter

[%]

Porosity

permeability

permeability

[mm]

[mm]

[%]

[mD]

[mD]

Gray 1 Bandera Gray 2

After experiment sample

Berea 1

20.

21

226

80

50.88

30.78

Berea 2

20

20

232

90

60.02

30.78

Berea 3

20

20

239

85

60.07

30.78

Bandera

20

18

21

8.90

60.32

30.80

20

18

15

7.35

60.35

30.81

Gray 1 Bandera Gray 2


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Clay

Quartz Quartz

Quartz

Quartz

Clay

Quartz Quartz

Quartz 20µm

100µm

m

Clay

Quartz Quartz

Clay Clay

Clay

Quartz Quartz

20µm

20µm

Figure 10. SEM images displaying the mineralogical composition and morphology of Berea sample


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Guartz Guartz

Clay

Clay

Guartz

Clay

Clay

Guartz 20µm

100µm

Clay Clay Clay Guartz

Guartz Guartz Clay 20µm

Clay

Clay

20µm

Figure 11. SEM images displaying the mineralogical composition and morphology of Bandera Gray sample


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Sample ID 7.739

40

6.164

32

Intensity (Counts) X 100

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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24 3.349 4.899 3.860

3.020 2.603

2.483

16

2.337

8

10.00

20.00

30.00

40.00

50.00 2-Theta Angle (deg)

File Name: c:\data\michael\ahmed alyaseri - curtin\clay1.cpi

Figure 12. X-ray diffraction analysis of the fine particles collected from effluent brine.

Figure 13. SEM images of fines appeared in the effluent


Energy & Fuels

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a

b Figure 14. a) Pore throat size distribution of Berea sample obtained by MICP analysis and b) pore size distribution of Gray sample obtained by MICP analysis.


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Conclusions Previous studies5,6,17-20,22,25 have shown a change in permeability and/or porosity of the sandstone rocks after CO2 injection due to clay dissolution and migration. However, our analysis on Berea (low clay content) and Bandera Gray (high clay content) showed that permeability changes are minimal in both samples in the tested conditions. For instance, the permeability of Berea samples #1 and #2 increased by 11% and 23% respectively after CO2 exposure while Bandera Gray samples permeability did not change. Also, an increase in CO2 injection rate (from 1 to 10 ml/min) did not affect the permeability significantly. It was found that the salt type, salt concentration, acidity and distribution/structure of the clay minerals in the rock are the main controlling factors affecting the permeability and/or porosity change other than the quantity of clay. This insight can significantly enhance the fundamental understanding of CO2 storage and hydrocarbon recovery such as low salinity flooding. The results revealed that the structure of the clay minerals in the rock skeleton is a key factor when the stability of clay minerals is of interest44. Dispersed clay minerals will be readily detached and move into the bulk fluid compare to structurally imbedded clay minerals in the rock matrix. In addition, the pore throat of the hosting rock will define bridging-blocking of the pores by detached clay minerals35. Also, the physicochemical factors, in particular, the ionic strength and pH, determine the clay minerals instability (i.e. acidic environment will make the clay minerals more stable)42,44. A combination of abovementioned concepts can define as to what permeability changes should be expected during-after CO2 injection projects.


Energy & Fuels

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Permeability Evolution in Sandstone due to CO2 ... - ACS Publications

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