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Abstract

Studying the interactions between CO₂-rich fluid and reservoir rock under reservoir temperature and pressure is important for investigating CO₂ sequestration and the CO₂-enhanced oil recovery processes. Using high-concentration CaCl₂-type formation water as an example, this study performed a CO₂-rich fluid–rock interaction experiment at 85℃ and compared the dissolution of calcite and sandstone samples, as well as sandstone powder and thin-slice samples. This study also investigated the effects of the sample surface area, the CO₂ partial pressure (PCO₂ = 10 and 20 MPa), and the composition of formation water (3 mol/kg NaCl and 1 mol/kg CaCl₂–2 mol/kg NaCl) on the water–rock interaction mechanism and process by weighing, ion chromatography, and scanning electron microscopy observations. The results showed that the injection of CO₂ resulted in the dissolution of reservoir minerals such as carbonate cements and feldspar. The mineral dissolution increased with increasing PCO₂. The dissolution of minerals such as calcite in the CaCl₂-type formation water was significantly decreased because of the high concentration of Ca²⁺. Under the same conditions, more sandstone dissolved than calcite and more sandstone powder dissolved than sandstone thin slices. Dissolution of the potassium feldspar occurred in the sandstone, whereas the albite was nearly unaffected. No new minerals formed during the experimental process. The experimental results and a PHREEQC calculation demonstrated that the injection of CO₂ causes a significant pH drop in the formation water, which improves the porosity and permeability of the reservoir, increases the capacity of the reservoir to store CO₂, and facilitates the progression of the CO₂-enhanced oil recovery process. However, if alkaline minerals in the caprocks of the reservoir are also dissolved by the CO₂-rich fluid, the sealing capacity of the caprocks may be reduced.

Keywords

water–rock interaction reaction mechanism

Introduction

Geological sequestration of carbon dioxide (CO₂) can reduce the CO₂ content of the atmosphere and is a feasible means to mitigate the greenhouse effect (Balat and Öz, 2007; Bertier et al., 2006; Cantucci et al., 2009; Chen et al., 2014; Holloway, 1997; Jun et al., 2012; Krevor et al., 2012; Lu et al., 2012; Parthasarathy et al., 2016). Depleted or nearly depleted petroleum reservoirs are important media for CO₂ geological sequestration (Leung et al., 2014; Worden and Smith, 2004). All petroleum reservoirs are proven to have the capacity to store fluids (Lu et al., 2012; Shukla et al., 2010). In addition, the injection of CO₂ into a petroleum reservoir will increase the internal pressure of the reservoir (Leung et al., 2014), reduce the viscosity of the crude oil (Holm and Josendal, 1974), and facilitate the flow of oil and gas in the rock pores, which could achieve CO₂-enhanced oil recovery (EOR) and simultaneously offset some of the economic costs of CO₂ geological sequestration (Bachu and Bennion, 2008; Chiaramonte et al., 2011). Thus, CO₂ sequestration in petroleum reservoirs has been widely used and successfully implemented in several oil and gas fields (Holtz et al., 2001). However, after being injected into a geological formation, large amounts of CO₂ can be easily dissolved in the formation water and form an acidic fluid, which will alter the chemical equilibrium between the formation water and the rocks and induce chemical reactions (dissolution or precipitation) that can change the geochemical characteristics of the formation water and the mineral composition and physical properties of the reservoir rocks (André et al., 2007; Gao et al., 2007; Kampman et al., 2014; Shao et al., 2010). These changes might have significant impacts on the effective implementation of CO₂ flooding and the long-term safety of CO₂ geological sequestration (Bertier et al., 2006). Therefore, before implementing CO₂-EOR or CO₂ geological sequestration, it is necessary to assess the effects of CO₂ injection on the properties of the formation water and the physical properties of the reservoir.

Previous researchers have performed extensive experimental studies on the mechanisms and characteristics of the water–rock reactions that occur during CO₂-EOR and CO₂ geological sequestration. Pressures of 1–30 MPa and temperatures from 21 to 120℃ have been used in experiments regarding the interactions between rock, CO₂, and saline water (Bertier et al., 2006; Fischer et al, 2010; Lamy-Chappuis et al., 2014; Lu et al., 2012; Shao et al., 2010; Zheng et al., 2015). In several studies, the experimental temperature (200℃) was set higher than the reservoir temperature to increase the reaction rate (Kaszuba et al., 2003, 2005; Lu et al., 2011). The main component of the reaction solution was sodium chloride (NaCl), and relatively low concentrations of NaCl have been used. Because of the differences in the reaction conditions, there have been several discrepancies between previous experimental results that affect the understanding of the actual water–rock reaction process. For example, several studies have demonstrated that the acidic fluid that forms after the injection of CO₂ into a geological formation will dissolve carbonate minerals such as calcite, dolomite, and siderite (e.g. Emberley et al., 2004; Kharaka et al., 2006; Sayegh et al., 1990; Shiraki and Dunn, 2000; Wigand et al., 2008). The dissolution of carbonate minerals is an important mechanism for the formation of secondary pores and can even lead to the formation of secondary dissolution pathways, which can increase the permeability of the rocks (Cao et al., 2016; Farquhar et al., 2015). This geological process can increase the CO₂ storage space and facilitate the flow of CO₂ in the reservoir (Lamy-Chappuis et al., 2014), which improves the efficiency of CO₂-EOR, but increases the risk of CO₂ leakage (Kharaka et al., 2006; Rathnaweera et al., 2016). In contrast to the dissolution of carbonate minerals, several researchers believe that the carbonate ions ( ${CO}_{3}^{2 -}$ ) that form from CO₂ dissolved in formation water will bind with certain cations to lead to the precipitation of carbonate, thereby sequestrating CO₂ in the reservoir in the form of minerals (Gunter et al., 2000; Kaszuba et al., 2005; Lu et al., 2011; Marbler et al., 2013; Xu et al., 2004). In addition, CO₂-rich fluids will dissolve silicate minerals (e.g. feldspar) to form clay minerals such as kaolinite and montmorillonite (Lu et al., 2013; Rochelle et al., 2004). The formation of secondary carbonate and clay minerals will block some pores and pathways, which decreases the permeability of the rocks and the efficiency of CO₂-EOR (Shiraki and Dunn, 2000; Xu et al., 2004). In summary, the dissolution and precipitation of minerals induced by the injection of CO₂ into formation water are important factors that affect the physical properties of reservoir rocks. However, the mechanisms of the dissolution and precipitation of minerals due to the interaction between CO₂-rich fluid and reservoir rock, as well as their effects on the physical properties of the reservoir, are still under debate. This debate resulted from several factors that affect the rock–CO₂–saline water interactions, such as the composition of the formation water, the rock type, and the reservoir pressure and temperature. Therefore, when studying water–rock reactions and the changes in the physical properties of a reservoir during CO₂-EOR and CO₂ sequestration, it is necessary to design experiments simulating the reservoir temperature and pressure. Additionally, the effects of the formation water and the rock composition should be considered.

Previous studies have mainly used low-concentration NaCl reaction solutions. However, the formation water of an actual oil reservoir is generally characterized by high salinity that can reach more than 300 g/l (Hanor, 1994). In addition, most formation water is calcium chloride (CaCl₂) type, and the concentration of CaCl₂ can reach 166.64 g/l (Guo, 2012). Thus, this study prepared two high-concentration reaction solutions: 3 mol/kg NaCl and 1 mol/kg CaCl₂–2 mol/kg NaCl solutions. Sandstones are common petroleum reservoir rocks, and sandstone aquifers are also the preferred target for CO₂ sequestration (Rathnaweera et al., 2016). The dissolution and precipitation of carbonate cements have a significant impact on the physical properties of sandstone reservoirs (Taylor, 1990). Calcite is the most common carbonate cement (Kaszuba et al., 2003). This study performed water–rock (CO₂-rich fluid–calcite and CO₂-rich fluid–sandstone with carbonate cement) reaction experiments at 85℃ and CO₂ partial pressures (PCO₂) of 10 and 20 MPa. The effects of the surface area of the sample, the pressure, and the formation water composition on the process and mechanism of the calcite–CO₂–saline water and the sandstone–CO₂–saline water interactions were also investigated. Then, we discussed the influence of the CO₂-rich fluid–rock interaction on the reservoir spaces. The results have significant implications for the research and implementation of CO₂-EOR and CO₂ geological sequestration.

Experimental section

Experimental samples

The experimental samples included calcite and sandstone powder and thin slices. Sandstones were collected from drill cores in the lower part of the first member of the Paleogene Shahejie Formation in the Pucheng oilfield. The Pucheng oilfield is in Fanxian County in Henan Province, which is in the northeastern part of the central uplift belt in the Dongpu Depression (Figure 1). The Dongpu Depression is a Cenozoic rift basin that developed on the Mesozoic–Paleozoic basement. It trends NNE over 5300 km². Burial history analysis showed that the Dongpu Depression uplifted in Mesozoic (depth of < 4000 m) and subsided in Cenozoic (depth of > 8000 m). The oilfield in the lower part of the first member of the Paleogene Shahejie Formation is in the northeast region of the Pucheng anticline; the trap type is a tectonic-lithologic trap (Peng et al., 2010; Xue and Gao, 2011; Zhou and Xu, 2007). The Pucheng oil field has already been in a high water-cut stage (Li and Cheng, 2011); therefore, CO₂ flooding is an effective means to enhance oil and gas recovery. The age at the bottom of the lower part of the first member of the Paleogene Shahejie Formation is ∼35 Ma. A tectonic uplift occurred in ∼22 Ma and then subsided in 17 Ma. The present buried depth is 2100–2437 m (Peng et al., 2010). The grain sizes of sandstones were in the range of 0.01–0.1 mm, and the roundness varied from subangular to subrounded. Sandstones are typically arkoses, exhibiting a grain-supported framework and a high degree of compositional and textural maturity (Figure 2). Microscopic identification showed that the sandstone was composed of ∼50% quartz, 25–30% feldspar, 10–15% carbonate cement, and small amounts of siderite and pyrite. The most important diagenesis that the reservoir experienced includes compaction and carbonate cementation. Mechanical compaction led to reorientation of detrital grains, resulting in planar to concavo-convex grain contacts. Some rigid grains like quartz are fractured under overburden pressure. The carbonate cementation in the sandstone reservoir was strong, and calcite was the main cement that filled the sandstone pores. Both compaction and cementation were the main reasons that primary pores reduced greatly.

Figure 1.

Schematic map of local structure in Dongpu Depression and the position of the Pucheng oilfield.

Figure 2.

Microscopic (a, perpendicular polarized light) and back scatter electron (b) images of the sandstone samples. Kfs represents potassium feldspar (K-feldspar). Cal, Qtz, and Ab denote calcite, quartz, and albite, respectively.

Calcite and sandstone samples were ground into a powder with particle sizes of 0.8–2 and <4 mm, respectively. Thin slices with thicknesses of 5–8 mm and a diameter of 25 mm were prepared from the sandstone core plug to observe the changes in the morphology of the minerals on the sandstone surface after dissolution. The dissolution of the sandstone powder and thin slices was also compared. Prior to the start of the experiment, all samples were placed in an oven (Hengchang Instrument Factory of Shanghai Hualian Environmental Test Equipment Company) and dried for 72 h at 55 ± 1℃.

The reaction solutions were prepared using chemical reagents (NaCl: purity ≥ 99.5%, Sinopharm Chemical Reagent Co., Ltd; CaCl₂: purity ≥ 96.0%, Nanjing Chemical Reagent Co., Ltd) and deionized water at different molalities, mol/kg (m). The compositions of the reaction solutions, which were prepared to simulate the formation water, were 3 m NaCl (175.32 g/l) and 1 m CaCl₂–2 m NaCl (111 g/l CaCl₂ and 227.88 g/l total mineralization). The CO₂ used in this study was 99.999% pure (Yangzhou Nanyang Gas Co., Ltd).

Experimental methods

Figure 3 is a schematic diagram of the experimental apparatus. During the experiment, the dried calcite particles, sandstone powder, and sandstone thin slices were measured using a Mettler-Toledo AL204 electronic balance with an analytical precision of 10⁻⁴ g. Then, the measured sample was placed in a reaction flask, which was filled with 100 ml reaction solution (3 m NaCl or 1 m CaCl₂–2 m NaCl). The flask was then placed in a high-pressure autoclave and sealed. The inner wall and lid of the autoclave were made of 1Cr18Ni19Ti alloy so that it could withstand the corrosion from weak acids and bases. The total volume of the autoclave is ∼1000 ml. The autoclave can hold pressures up to 50 MPa. A pressurization system was used to control the inner pressure of the autoclave. The detailed procedures of the pressurization were summarized as follows: (1) CO₂ was discharged from a CO₂ cylinder into the autoclave, which was equipped with a piston; (2) water was injected into the bottom of the autoclave using a pressure pump to reduce the volume of CO₂ above the piston, which can increase the CO₂ pressure; (3) high-pressure CO₂ was discharged into the autoclave to allow the pressure to be slightly lower than the target pressure (i.e. < 10 or 20 MPa). The pressure pump can generate pressures ranging from 0.1 to 70 MPa. All pressure control devices were purchased from Yangzhou Huabao Petroleum Instrument Co., Ltd. The pressurized autoclave was placed in a heating oven (Guangpin Test Equipment (Shanghai) Co., Ltd) and heated to 85℃. In addition, the pressure inside the autoclave was adjusted to the target value (10 or 20 MPa). The reactions ran for 20–200 h.

Figure 3.

Apparatus used for the rock–CO₂–saline water interaction experiments.

When the reaction time reached the preset value, rapid quenching and depressurization were performed. The autoclave was opened, and the reaction flask was removed from the reactor. The solution inside the flask was rapidly filtered using a Buchner funnel. The filtrate was collected, and 10 ml of diluted hydrochloric acid (HCl) was added to prevent the formation of carbonate precipitates (Kaszuba et al., 2005). The concentrations of sodium ions (Na⁺), potassium ions (K⁺), calcium ions (Ca²⁺), and magnesium ions (Mg²⁺) in the solution before and after the reaction were determined using a Thermo ICS-1100 ion chromatograph (analytical precision: 10⁻⁶ g). The calcite and sandstone powders and sandstone thin slices were washed 3–5 times using deionized water and then dried in a heating oven (55 ± 1℃, 72 h). The dried calcite and sandstone powders and sandstone thin slices were then weighed to determine the mass loss of each sample after the reaction. Subsequently, based on the volume of the reaction solution, the mass loss of each sample was converted to the dissolved amount (g/l), i.e. the mass of the minerals dissolved in each liter of the solution was used to reflect the intensity of dissolution

DA = (W_{0} - W_{1}) \times 10

where DA represents the dissolved amount, and W₀ and W₁ represent the mass of the samples before and after the reaction, respectively. The sandstone thin slices before and after the reaction were coated with platinum. Then, the morphology of the sample surface and the mineral compositions were analyzed using a ZEISS SUPRA 55 field-emission scanning electron microscope (accelerating voltage: 15 kV) with an energy dispersive spectrometer.

Results

Calcite–CO₂–saline water system

The weighing results showed that the amount of calcite that is dissolved in the 3 m NaCl solution increased slightly with increasing reaction time. In addition, the dissolution of calcite increased with increasing CO₂ partial pressure (PCO₂) (Table 1 and Figure 4(a)). The ion chromatography (IC) analysis showed that the concentration of dissolved Ca²⁺ increased rapidly to more than 400 mg/l when the reaction time reached 26 h, after which it remained nearly constant, indicating that the reaction had reached equilibrium (Figure 4(b)). When PCO₂ = 10 and 20 MPa, the maximum dissolved amounts of calcite were 1.2 and 1.8 g/l, respectively, and the concentrations of dissolved Ca²⁺ were approximately 400 and 500 mg/l, respectively (Table 1 and Figure 4(a)). In other words, the solubility of calcite in the 3 m NaCl solution was 0.01 and 0.0125 m when PCO₂ = 10 and 20 MPa, respectively. The solubility of calcite that was obtained by weighing was slightly higher than that obtained by the IC analysis. However, these data were of the same order of magnitude, indicating that these experimental data were reliable.

Table 1.

Experimental results of the dissolution of calcite in the 3 m NaCl and 1 m CaCl₂–2 m NaCl solutions.

Saline water	CO₂ partial pressure (MPa)	Reaction time (h)	W₀ (g)	W₁ (g)	Weight loss (g)	Dissolved amount (g/l)	Ca²⁺ (mg/l)
3 m NaCl	10	26	20.7374	20.6289	0.1085	1.085	453.9966
	10	48	20.921	20.8096	0.1114	1.114	390.7809
	10	64	20.3854	20.2655	0.1199	1.199	410.8238
	10	127					437.5465
	20	24					488.4225
	20	46	19.4399	19.2918	0.1481	1.481	472.6531
	20	72	20.104	19.9448	0.1592	1.592	397.2673
	20	122	21.9738	21.7906	0.1832	1.832	495.9279
1 m CaCl₂—2 m NaCl	10	22	18.764	18.7586	0.0054	0.054
	10	49	20.1555	20.1304	0.0251	0.251
	10	65	18.689	18.6869	0.0021	0.021
	10	168	20.0387	20.0339	0.0048	0.048
	20	61	17.392	17.3755	0.0165	0.165
	20	94	20.2366	20.2178	0.0188	0.188
	20	140	20.1506	20.1424	0.0082	0.082

Figure 4.

Dissolution of calcite in 3 m NaCl and 1 m CaCl₂–2 m NaCl solutions at 85 ℃ and 10, 20 MPa (a) weighing results expressed by dissolved amount; (b) IC analysis results for 3 m NaCl solution. IC: ion chromatography.

At the same PCO₂ and reaction time, the dissolved amount of calcite in the 1 m CaCl₂–2 m NaCl solution was significantly lower than that in the 3 m NaCl solution (Figure 4(a)). At PCO₂ = 10 and 20 MPa, the average dissolved amounts of calcite were 0.04 and 0.15 g/l, respectively. The extremely small amount of calcite that dissolved in the CaCl₂–NaCl solution can be attributed to the common ion effect, i.e. the concentration of Ca²⁺ in the reaction solution was excessively high, which prevented the dissolution of calcite. Due to the extremely high Ca²⁺ concentration, the post-reaction 1 m CaCl₂–2 m NaCl solution was not subjected to IC analysis.

Sandstone–CO₂–saline water system

Weighing and IC analyses

The dissolved amount of sandstone powder in the 3 m NaCl solution did not change significantly when the reaction time reached 60 h (Table 2 and Figure 5(a)). The IC analysis showed that the concentration of Ca²⁺ in the reaction solution fluctuated with the increase of experimental duration but remained relatively stable after 60 h of reaction (Figure 5(b)). These results suggest that the reaction reached equilibrium within a short period of reaction time. The dissolved amount of sandstone powder increased with increasing PCO₂. For example, the average dissolved amounts of sandstone powder were approximately 3 and 3.5 g/l at PCO₂ = 10 and 20 MPa, respectively; the concentrations of Ca²⁺ that dissolved from the sandstone powder were 400 and 560 mg/l, respectively. Thus, the dissolved amounts of calcite, which were obtained from the conversion of the concentrations of dissolved Ca²⁺, were 1.0 and 1.4 g/l, respectively; these values were significantly lower than the corresponding dissolved amounts of sandstone powder. These results indicate that minerals in the sandstone other than calcite also dissolved.

Table 2.

Experimental results of the dissolution of sandstone samples in the 3 m NaCl solution.

Sample	CO₂ partial pressure (MPa)	Reaction time (h)	W₀ (g)	W₁ (g)	Weight loss (g)	Dissolved amount (g/l)	Ca²⁺ (mg/l)	K⁺ (mg/l)	Mg²⁺ (mg/l)
Sandstone powder	10	26	20.5305	20.2077	0.3228	3.228	431.5699
	10	48					435.2654
	10	64	18.5689	18.2022	0.3667	3.667	388.7466
	10	127	16.4447	16.1738	0.2709	2.709	356.5145
	10	164	17.1224	16.8089	0.3135	3.135	377.3744
	20	24	19.8148	19.482	0.3328	3.328	567.9057	44.0116	44.5067
	20	44.5						71.6079	53.1443
	20	67.5	20.2753	19.8931	0.3822	3.822	538.9092	45.4575	29.614
	20	120	18.4303	18.0947	0.3356	3.356	567.1333	69.58	54.4456
	20	168	15.4715	15.085	0.3865	3.865	437.5704	46.0168	45.9742
Sandstone thin slice	20	24	5.2706	5.1934	0.0772	0.772	254.4634
	20	48	4.2838	4.1548	0.129	1.29	399.7313
	20	71	3.2873	3.1454	0.1419	1.419
	20	120	2.9209	2.7455	0.1754	1.754	445.7925
	20	192	5.237	5.0675	0.1695	1.695	538.6524

Figure 5.

Dissolution of sandstone powders and sandstone thin slices in 3 m NaCl solution (a) weighing results and (b) IC analysis results. IC: ion chromatography.

Compared to the sandstone powder, the contact area between the sandstone thin slices and the solution was relatively small. Therefore, although the dissolved amounts of the sandstone thin slices continuously increased with increasing reaction time, the dissolution rate gradually decreased. In addition, the dissolution equilibrium could not be reached within a short period of reaction time (Table 2 and Figure 5(a)). At PCO₂ = 20 MPa, the maximum dissolved amount of the sandstone thin slices was 1.75 g/l, which was significantly lower than that of sandstone powder under the same conditions. It can be deduced that the surface area of the sample had a significant impact on the dissolution process. Sandstone powder exhibited a larger dissolved amount because it had a large surface area and was in full contact with the reaction solution. In addition, variation in the concentration of dissolved Ca²⁺ with the reaction time was consistent with the changes in the dissolved amount of sandstone thin slices (Figure 5(b)). It is worth noting that at the same PCO₂ conditions, although more sandstone powder dissolved than calcite, the concentration of Ca²⁺ that dissolved from the sandstone powder was relatively consistent with that dissolved from the calcite. This result indicates that the dissolution of calcite had reached equilibrium. Furthermore, based on weighing and the IC analysis results, the dissolved amount of the sandstone thin slices was less than that of the sandstone powder, but the final Ca²⁺ concentrations in the reaction solutions of the two samples did not show an obvious difference.

Under the same PCO₂ conditions, the dissolved amount of sandstone in the 1 m CaCl₂–2 m NaCl solution was less than that in the 3 m NaCl solution (Table 3 and Figure 6). This result can also be partly ascribed to the high concentration of Ca²⁺ in the reaction solution, which inhibited the dissolution of calcite in the sandstone. The dissolved amount of sandstone powder in the 1 m CaCl₂–2 m NaCl solution also increased with increasing PCO₂; the dissolved amounts of sandstone powders were approximately 2.0 and 2.5 g/l at PCO₂ = 10 and 20 MPa, respectively. The dissolved amount of sandstone powder did not show an obvious relationship with reaction time, indicating that the dissolution of sandstone powder in the 1 m CaCl₂–2 m NaCl solution reached equilibrium within a short period of time (Figure 6). Similar to its dissolution behavior in the NaCl solution, the amount of the sandstone thin slices that dissolved in the 1 m CaCl₂–2 m NaCl solution increased gradually with increasing reaction time. It is worth noting that the dissolved amounts of sandstone powder and thin slices in the 1 m CaCl₂–2 m NaCl solution were both several times higher than those of calcite in the same solution. These results also indicate that minerals other than calcite dissolved.

Table 3.

Experimental results of the dissolution of sandstone samples in the 1 m CaCl₂–2 m NaCl solution.

Sample	CO₂ partial pressure (MPa)	Reaction time (h)	W₀ (g)	W₁ (g)	Weight loss (g)	Dissolved amount (g/l)
Sandstone powder	10	22.5	17.899	17.6245	0.2745	2.745
	10	30	12.5364	12.3121	0.2243	2.243
	10	65	18.6204	18.4424	0.178	1.78
	10	168	18.271	18.0026	0.2684	2.684
	20	24	17.9934	17.7309	0.2625	2.625
	20	45	18.6015	18.4009	0.2006	2.006
	20	72	15.0948	14.8483	0.2465	2.465
	20	94	16.6454	16.445	0.2004	2.004
Sandstone thin slice	10	25	8.2424	8.1665	0.0759	0.759
	10	46	5.7635	5.7098	0.0537	0.537
	10	72	8.9787	8.8262	0.1525	1.525
	10	120	5.8152	5.7732	0.042	0.42
	10	168	7.6284	7.4571	0.1713	1.713
	20	21	3.5724	3.5332	0.0392	0.392
	20	64	5.0428	4.9639	0.0789	0.789
	20	93	7.7465	7.6896	0.0569	0.569
	20	114	8.8148	8.7974	0.0174	0.174
	20	142	11.1916	11.1003	0.0913	0.913

Figure 6.

Dissolution of sandstone powder and thin slice in the 3 m NaCl and 1 m CaCl₂–2 m NaCl solutions at PCO₂ = 20 MPa.

IC analyses showed that, in addition to Ca²⁺, K⁺ and Mg²⁺ also dissolved from sandstone. For example, at PCO₂ = 20 MPa, approximately 60 and 50 mg/l of K⁺ and Mg²⁺, respectively, dissolved in the 3 m NaCl solution (Table 2 and Figure 7). K-feldspar and dolomite could be the source of dissolved K⁺ and Mg²⁺ ions.

Figure 7.

Concentration of ions that dissolved from sandstone powder in the 3 m NaCl solution ((a) concentration of K⁺ and (b) concentration of Mg²⁺).

Scanning electron microscopy (SEM) observations

To further investigate the changes in the mineral morphology and porosity during the water–rock interaction, the surfaces of sandstone thin slices were observed using SEM before and after the reaction. The results showed that the calcite cements exhibited nice crystalline form before the water–rock interaction (Figure 8(a) and (b)); the crystal surface was smooth and clean. However, the calcite was intensely dissolved in the 3 m NaCl solution. For example, at PCO₂ = 20 MPa, the calcite became loose and porous after the reaction had continued for 25 h. After 72 h, only serrated remnants of calcite remained due to dissolution, and the original morphology of the calcite was unrecognizable (Figure 8(c) and (d)). These results show that the dissolution of calcite in the sandstone thin slices intensified as the reaction time increased, which is consistent with the weighing and IC analysis results. The dissolution of calcite in the 1 m CaCl₂–2 m NaCl solution was not as strong as that in the 3 m NaCl solution (Figure 8(e) and (f)) due to the relatively high concentration of Ca²⁺.

Figure 8.

SEM images of calcite before and after dissolution in the 3 m NaCl and 1 m CaCl₂–2 m NaCl solutions when PCO₂ = 20 MPa. (a, b) Calcite cements before the reaction, (c) and (d) are calcites reacted in the 3 m NaCl solution for 25 and 72 h, respectively, and (e) and (f) are the calcites reacted in the 1 m CaCl₂–2 m NaCl solution for 21 and 114 h, respectively. Inserted are the EDS spectra for calcite. EDS: energy dispersive spectrometer; SEM: scanning electron microscopy.

The dissolution of K-feldspar was also observed. The K-feldspar had smooth and clean surfaces before the reaction (Figure 9(a)). However, after the reaction in the 3 m NaCl solution, the K-feldspar was dissolved by the acidic CO₂-rich fluid, and many pits formed on its surface (PCO₂ = 20 MPa; Figure 9(b)). However, there was no significant change in the crystalline morphology of albite (Figure 9(c) and (d)). The solubility of quartz was reported to be very low in the acidic solution that formed from the dissolution of CO₂ in the formation water (Hangx et al., 2013; Kaszuba et al., 2003). As a result, no significant dissolution of quartz was observed in the SEM images. Therefore, we could predict that when CO₂ is injected into a quartz sandstone reservoir, the effect of the acidic CO₂-rich fluid on the pure quartz sandstone reservoir is negligible because the dissolution of quartz is quite limited (Lu et al., 2012). The formation of secondary minerals due to mineral dissolution was not observed in this study.

Figure 9.

SEM images of sandstone thin slices in the 3 m NaCl solution when PCO₂ = 20 MPa (a) K-feldspar before dissolution, (b) K-feldspar after dissolution, (c) albite before dissolution, and (d) albite after dissolution. Inserted are EDS spectra for K-feldspar and albite. EDS: energy dispersive spectrometer; SEM: scanning electron microscopy.

Discussion

Processes and mechanism of CO₂-rich saline water–sandstone interaction

Previous studies reported that carbonate minerals dissolve relatively quickly in an acidic CO₂-rich fluid and that reaction equilibrium can be reached within several months or even several weeks (Hangx et al., 2013; Marbler et al., 2013). Miller (1952) found that the dissolution rate of calcite increased rapidly when CO₂ was injected into the CaCO₃–water system and then gradually decreased after 1 h, and the CaCO₃–CO₂–water system could reach complete equilibrium within several hours. The experimental results of this study show that the dissolution of calcite in the CO₂-rich formation water at the temperature and pressure conditions of a petroleum reservoir could reach equilibrium within 1–2 days. The solubility of CaCO₃ is generally believed to increase with increasing PCO₂ because an increase in PCO₂ results in an increase in the amount of CO₂ that is dissolved in the solution (e.g. Coto et al., 2012; Duan and Li, 2008; Ellis, 1959; Fan et al., 2011; Weyl, 1959), and the ionization of the resultant carbonic acid (H₂CO₃) generates more hydrogen ions (H⁺), thereby decreasing the pH of the solution and promoting the dissolution of calcite (Worden and Smith, 2004). Our experimental results are consistent with the above conclusions. The dissolved amounts of calcite in this study were slightly lower than those reported under similar temperature, pressure, and solution composition conditions but were still of the same order of magnitude (∼1.9 g/l; Miller, 1952).

The chemical composition of the reaction solution also had an obvious impact on the dissolution of sandstone. The inhibiting effect of Ca²⁺ on the dissolution of calcite could be used to explain why the dissolved amount of sandstone in the 1 m CaCl₂–2 m NaCl solution was lower than that in the 3 m NaCl solution. However, the dissolution of silicate minerals such as feldspar was nearly unaffected by the inhibiting effect of Ca²⁺. The reaction rate was largely controlled by the external surface area of the sample (Fan et al., 2007). Under the same conditions, the amount of dissolved sandstone powder was significantly higher than that of sandstone thin slices, but there was no significant difference between the concentrations of Ca²⁺ that dissolved from the sandstone powder and thin slices. The time that was required for the reaction to reach equilibrium varies among different minerals. Silicate minerals, such as feldspar, require more time to reach reaction equilibrium than carbonate minerals (Rathnaweera et al., 2016). Due to the relatively smaller surface areas of the sandstone thin slices, the dissolution of carbonate minerals could reach equilibrium quickly, but the silicate minerals were only dissolved slightly; the dissolution of silicate minerals did not reach equilibrium. As for the sandstone powder, its dissolution rate was significantly increased compared with that of the sandstone thin slice because the sandstone powder was in full contact with the reaction solution. Then, the reaction reached equilibrium relatively quickly. The dissolution process of the sandstone thin slices is very similar to the actual geological process; under geological conditions, the sandstone–CO₂–saline water interaction is slow. This result also indicates that the water–rock interaction is favored in porous stratum.

CO₂ was reported to exist in two forms after it is injected into the formation water: (1) interacting with the reservoir rocks and forming secondary minerals; and (2) dissolving in the formation water (Gunter et al., 2000). Whether carbonate precipitates can form after CO₂ is injected into formation water is mainly determined by the reservoir lithology (Xu et al., 2004). For example, Wigand et al. (2008) investigated water–rock interactions in the sandstone–CO₂–NaCl–H₂O system and found that the dolomite cement dissolved, but no secondary carbonate minerals formed. They believed that the formation of carbonate precipitates reported in previous simulation experiments was in close association with the dissolution of Ca-rich minerals such as anorthite and gypsum. The dissolution of these Ca-rich minerals provided a large amount of Ca²⁺ for the precipitation of carbonate minerals. The sandstone samples that were used by Wigand et al. (2008) did not contain anorthite and gypsum, and no other minerals could provide an excessive amount of Ca²⁺. Therefore, if the Na- and/or K-silicate minerals are the main silicates in a sandstone reservoir, the injection of CO₂ into the reservoir will not result in the generation of carbonate precipitates, and the injected CO₂ will exist mainly in the form of dissolved CO₂ (Emberley et al., 2004). However, our experimental results suggest that even if there is a relatively high concentration of Ca²⁺ in the formation water (i.e. 1 m CaCl₂), the injection of CO₂ will still result in the dissolution of carbonate minerals. Of course, the relatively high concentration of Ca²⁺ in the formation water will prevent the dissolution of calcite, indicating that the acidic fluid that forms after CO₂ is injected into CaCl₂-type formation water has a limited dissolution effect on carbonate minerals (e.g. calcite) and thus cannot significantly increase the storage space in the reservoir. CO₂ injection can induce the dissolution of carbonate minerals because H⁺ ions are generated from the ionization of the H₂CO₃ that forms from CO₂ and water. This process can decrease the pH of the formation water. PHREEQC simulation results (Tables S1 and S2) showed that the pH of both reaction solutions decreased with increasing PCO₂ at the same temperature and remained relatively low (∼3). However, when the samples were quenched from the autoclave, precipitates were observed in the filtrate within a short period without the addition of HCl. Bubbles formed after HCl were added to the filtrate, and the solution then became clear. These observations indicate that carbonate precipitated from the reaction solution after quenching and depressurization. The precipitation of these carbonate minerals can be ascribed to the escape of CO₂ from the reaction solution during quenching, which significantly increased the pH of the reaction solution (Kampman et al., 2014; Worden and Smith, 2004). The CO₂-EOR process from the reservoir to the surface is a depressurization process. It should be noted that the CO₂-escape-induced precipitation of carbonate may block or even destroy the pipelines during the implementation of CO₂-EOR.

The dissolution of K-feldspar was observed, whereas albite appeared to be resistant to the acidic solutions during the experiment. To investigate the factors controlling the dissolution behaviors of these two silicate minerals, the dissolution of the major minerals of the reservoir rocks in 3 m NaCl solution was simulated using PHREEQC software (Table S3). The simulation conditions were as follows: T = 85℃; PCO₂ = 10 and 20 MPa. The reservoir rocks were supposed to be mainly composed of calcite, dolomite, siderite, K-feldspar, and albite. The concentrations of Ca²⁺, Mg²⁺, and iron ion (Fe²⁺) that dissolved from the minerals were converted to the changes in the mass of the minerals calcite, magnesite, and siderite, respectively. The changes in the concentrations of the other ions were converted to the mass of the corresponding oxides. The sum of the mass of these carbonate minerals and oxides was used to indicate the total dissolved amount. The results showed that the total dissolved amount of minerals also increased with increasing PCO₂. The concentrations of Ca²⁺, Mg²⁺, and Fe²⁺ in the formation water increased somewhat after the reaction, which indicates that all the carbonate minerals underwent dissolution. However, the initial 3 m concentration of Na⁺ decreased somewhat after the reaction, which indicates that albite did not dissolve in the CO₂-rich acidic solutions. On the contrary, authigenic albite may have formed (Fischer et al., 2010; Wandrey et al., 2011). The simulation results for the dissolution of albite are consistent with the SEM observations. The negligible dissolution of albite can be ascribed to the high Na⁺ concentration of the reaction solution (i.e. 1 and 3 m). Considering that Na⁺ is a common and major component of the formation water, it can be predicted that the dissolution of Na-rich silicates is less significant than other silicates during the flooding of CO₂.

Implications for CO₂-EOR and CO₂ sequestration

Previous studies and the PHREEQC simulation results (Tables S1 and S2) indicated that the injection of CO₂ into a reservoir will cause a significant decrease in the pH of the formation water (Carroll et al., 2014; Kaszuba and Janecky, 2009; Rosenbauer et al., 2005; Yu et al., 2015). The acidic CO₂-rich fluid that forms from the CO₂ injection will dissolve minerals such as carbonates and silicates. This process results in the formation of secondary pores and changes in the pore structure, which can improve the physical properties of the reservoir. Our experimental results are consistent with those documented in Farquhar et al. (2015), where the dissolution of carbonates and K-feldspar was suggested to be the major result of the interaction between CO₂-rich acidic fluid and sandstone. The carbonate cements in the sandstone reservoir rocks dissolved in the acidic CO₂-rich fluid, which increased the permeability of the reservoir (Ross et al., 1982; Sayegh et al., 1990). Geological observations also indicate that the occurrence or dissolution of carbonate cement is vital to the physical properties of sandstone reservoirs. The Huangqiao region in the North Jiangsu Basin is a well-known CO₂ gas field. The interaction between the formation water rich in mantle-derived CO₂ and the feldspathic quartz sandstone in the Permian Longtan Formation resulted in the dissolution of minerals such as calcite and feldspar, which increased the porosity and permeability of the reservoir. For example, the Longtan Formation in the Xi-2 well is relatively insignificantly affected by the CO₂-rich fluid. Its sandstone section has an average porosity of 6.91% and an average permeability of 0.958 md, making this section an ultralow to low porosity and ultralow permeability reservoir. In contrast, the Longtan Formation in the Xi-3 well is significantly affected by the CO₂-rich fluid and has an average porosity of 9.92% and an average permeability of 128.017 md. Thus, the physical properties of the Longtan Formation reservoir in the Xi-3 well are much better than those in the Xi-2 well. The porosity and permeability of the reservoir rocks of the Kela-2 Gas Field in the Kuche Depression in the Tarim Basin (NW China) are negatively correlated with the amount of carbonate cements; the greater the amount of carbonates, the poorer the physical properties of the reservoir (Yu and Lai, 2006). During investigation of the distribution of the carbonate cements in the Paleogene Zhuhai Formation reservoirs in the Wenchang A Sag in the Pearl River Mouth Basin, You et al. (2012) found that when the content of the carbonate cement was greater than 5%, the porosity and permeability decreased with the increasing content of carbonate cement. Carbonate cementation was suggested to be a major cause of the deterioration in the physical properties of the deep Zhuhai Formation reservoir. You et al. (2012) also thought that the physical properties of the reservoir were significantly improved through the dissolution of carbonate cements by diagenetic acidic fluid. In summary, the dissolution of alkaline minerals, such as carbonate and feldspar, in a sandstone reservoir by a CO₂-rich fluid is favorable to the development of secondary pores. Dissolution of these alkaline minerals, especially the carbonate cements, can improve the physical properties of the reservoir and is favorable for the transport and extraction of oil and gas during the CO₂-EOR process.

Storing dissolved CO₂ in a trap is an important means of CO₂ sequestration. In a reservoir, the dissolution of minerals such as calcite in a CO₂-rich fluid can improve the porosity and permeability of the reservoir, which facilitates the transport and storage of CO₂ in the stratum (Lamy-Chappuis et al., 2014). When evaluating a CO₂ sequestration site, the lithology and the chemical compositions of the formation water should be considered. For example, under the same conditions, more sandstone dissolved in the NaCl-dominated solution than in the CaCl₂-dominated solution. If the formation water is rich in CaCl₂ (e.g. CaCl₂ type), the effect of mineral dissolution on the reservoir properties is limited because the high concentration of Ca²⁺ prevents the dissolution of calcite. Therefore, sandstone formations in which NaCl is the major component of the formation water are preferred for CO₂ geological sequestration. In addition, after a CO₂-rich fluid dissolves the alkaline minerals (e.g. carbonates) in a reservoir, dissolution pathways may form and lead to the transportation of the CO₂-rich solution. When CO₂-rich solution is transported to a fault or a fault zone, CO₂ will escape from the solution due to a sudden decrease in pressure. Then, the pH of the solution will increase, resulting in the precipitation of alkaline minerals such as carbonates in the fissures. This process can seal the fissures (Zhu et al., 2012), block the dominant migration pathways, and prevent further CO₂ leakage (Shukla et al., 2010). CO₂ will also be transported to the region below the caprocks of the reservoir and then start to accumulate in this region due to buoyancy. If the caprocks are somewhat permeable, the abnormally high local pressure that results from the continuous accumulation of CO₂ can be mitigated (Smith et al., 2012). Keating et al. (2014) thought that a certain level of CO₂ leakage did not affect the effectiveness of CO₂ sequestration and the water quality of the overlying aquifer. However, if the caprocks contain minerals that can easily be dissolved by a CO₂-rich fluid, such as calcite and K-feldspar, long-term water–rock reactions will result in a gradual increase of the permeability of the caprocks and a decrease in the compressive strength of the rocks (Zheng et al., 2015), which could reduce the sealing capacity of the caprocks. Consequently, CO₂ will leak and flow into the overlying shallow freshwater aquifer and even return to the ground (Xu et al., 2011). In addition to CO₂ leakage, deep saline water will also flow into the shallow rock layers. Then, the salts, organic matter, and trace metals that are carried by the deep saline water will severely pollute the freshwater aquifer (Jung et al., 2013; Keating et al., 2012). In summary, dissolution of the alkaline minerals in the reservoir rocks by CO₂-rich acidic formation water is favorable to CO₂-EOR and CO₂ geological sequestration, but it is also necessary to investigate the changes in the sealing capacity of the caprocks after the injection of CO₂ and assess the risk of CO₂ leakage.

Conclusions

Using calcite and carbonate-cement-bearing sandstone as the experimental materials, we performed CO₂-rich fluid–rock interaction experiments at the reservoir temperature (85℃). Combined with PHREEQC simulations, the effects of the sample surface area, the PCO₂ (10 and 20 MPa), and the composition of the formation water (3 m NaCl or 1 m CaCl₂–2 m NaCl) on the water–rock reaction were investigated. The following conclusions were obtained:

The CO₂ injection resulted in a significant decrease in the pH of the formation water, which induced the dissolution of alkaline minerals such as carbonate cements and K-feldspar. The type of formation water showed a significant impact on the dissolution of carbonate minerals such as calcite. The dissolution of calcite was significantly inhibited in the CaCl₂-type formation water. During the experiment, the amount of sandstone that dissolved was directly proportional to the surface area of the sample and increased with increasing PCO₂.

Under the experimental conditions, dissolution of the alkaline minerals in the reservoir rocks was the major result of the interaction between the CO₂-rich fluid and the reservoir rock, indicating that the injection of CO₂ into a stratum will improve the porosity and permeability of the reservoir and facilitate the progression of the CO₂-EOR process. In addition, increases in the porosity and permeability of a reservoir lead to an increase in the capacity of the reservoir to store CO₂. However, CO₂ leakage will result in an increase in the pH of the formation water and the precipitation of minerals such as carbonates, which may block the CO₂-EOR pathways.

If the caprocks contain alkaline minerals such as calcite, CO₂-rich formation water will dissolve these minerals. This process may result in an increase in the porosity and permeability of the caprocks and affect their sealing performance, thereby inducing the leakage of CO₂ and formation water. Consequently, the effectiveness of CO₂ sequestration will be weakened, and shallow freshwater aquifers may be polluted. Future research should further assess the effect of CO₂-rich fluids on the sealing capacity of the caprocks of reservoirs.

Footnotes

Acknowledgements

We thank Mr Haihong Cao from SINOPEC for his assistance during the high P–T experiments of CO₂-rich water–rock interaction. We also thank Prof. Yuzhuang Sun for his handling this manuscript, and Dr Pedram Masoudi and an anonymous referee for their careful review and constructive comments.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research, authorship, and/or publication of this article: This work was financially supported by the National Natural Science Foundation of China (Grant nos. 41230312 and 41573054) and the National Science and Technology Major Project of China (Grant no. 2016ZX05002-006-005).

Supplementary material

Supplementary material for this paper can be found at .

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Supplementary Material

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Supercritical CO 2 -involved water–rock interactions at 85℃ and partial pressures of 10–20 MPa: Sequestration and enhanced oil recovery

Abstract

Keywords

Introduction

Experimental section

Experimental samples

Experimental methods

Results

Calcite–CO2–saline water system

Sandstone–CO2–saline water system

Weighing and IC analyses

Scanning electron microscopy (SEM) observations

Discussion

Processes and mechanism of CO2-rich saline water–sandstone interaction

Implications for CO2-EOR and CO2 sequestration

Conclusions

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

Supplementary material

References

Supplementary Material

Calcite–CO₂–saline water system

Sandstone–CO₂–saline water system

Processes and mechanism of CO₂-rich saline water–sandstone interaction

Implications for CO₂-EOR and CO₂ sequestration