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Experimental investigation of trace element dissolution in formation water in the presence of supercritical CO2 fluid for a potential geological storage site of CO2 in Taiwan
Journal of Natural Gas Science and Engineering 23 (2015) 304e314
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Experimental investigation of trace element dissolution in formation water in the presence of supercritical CO2 fluid for a potential geological storage site of CO2 in Taiwan Jiin-Shuh Jean a, Chien-Lih Wang b, Hsing-I. Hsiang b, Zhaohui Li a, c, *, Huai-Jen Yang a, Wei-Teh Jiang a, Kenn-Ming Yang a, Jochen Bundschuh d a
Department of Earth Sciences, National Cheng Kung University, Tainan, Taiwan Department of Resources Engineering, National Cheng Kung University, Tainan, Taiwan Department of Geosciences, University of Wisconsin e Parkside, 900 Wood Road, Kenosha, WI 53144, USA d Faculty of Health, Engineering and Surveying & National Centre of Engineering in Agriculture, University of Southern Queensland, Toowoomba, Queensland 4350, Australia b c
a r t i c l e i n f o
a b s t r a c t
Article history: Received 27 October 2014 Received in revised form 5 February 2015 Accepted 6 February 2015 Available online
The Pliocene Yutengping Sandstone (depth 1642e1882 m) and its overlying caprock shale (depth 1395 e1642 m) in Hsinchu City, central Taiwan, were intended for a storage site of CO2. Formation water was collected from a gas well located at a depth of 1827e1846 m. This study investigated changes in water chemistry and dissolution of trace elements from the sandstone and shale at 25 MPa and 90 C in the presence and absence of supercritical CO2 (scCO2) over 7 days. The results showed substantial dissolution of V, Cr, Co, Cu, and Rb from the sandstone and shale into formation water in the presence of scCO2 fluid, while the release of Zn, Se, Mo, and Cd from the sandstone and shale was minimal. Desorption of V, Cr, Mn, Fe, Sr, and Ba was more pronounced from the sandstone than from shale, whereas Co, Ni, Cu, As, and Mo desorbed more from the shale. The concentration of As in formation water increased from 1.4 mg/L to 130 mg/L after in contact with scCO2. Such a high As concentration may present a significant threat to shallow groundwater quality in this region, particularly if leakage along faults and rock fractures in the region occurred. © 2015 Elsevier B.V. All rights reserved.
Keywords: Desorption Dissolution Fluid-rock interaction Mobilization Sequestration Supercritical CO2
1. Introduction The rise in carbon dioxide production and its release into the atmosphere over the last century has contributed significantly to global warming (IPCC (Intergovernmental Panel on Climate Change), 2013). To mitigate this effect, attention has paid to investigate the potentials for underground CO2 storage in geological formations. Geological sequestration may involve three processes: (1) hydrodynamic trapping of CO2 as a gas or supercritical fluid beneath a low permeability caprock; (2) solubility trapping with the dissolution of CO2 into fluid phases, including both aqueous brines and oil; and (3) mineral trapping incorporating CO2 into solid phases via precipitation of carbonate minerals (Oelkers
* Corresponding author. Department of Geosciences, University of Wisconsin e Parkside, 900 Wood Road, Kenosha, WI 53144, USA. E-mail address: [email protected] (Z. Li). http://dx.doi.org/10.1016/j.jngse.2015.02.006 1875-5100/© 2015 Elsevier B.V. All rights reserved.
and Schott, 2005). In order to achieve a safe sequestration of CO2 in the deep subsurface environment, the National Science Council of Taiwan allocated special funds to a number of universities in Taiwan, to conduct a three-year multidisciplinary integrated research for carbon dioxide capture and storage (CCS). One of the research targets was to assess any potential risks that may occur after the injection of CO2 into the deep subsurface environment. Although many researches were conducted on mineral trapping of CO2, which occurs via carbonate mineral precipitation (Oelkers and Schott, 2005), and the feasibility of geological sequestration of CO2 was proven, apart from literature data on modeling, still more research is needed to study the CO2ewatererock interactions induced by CO2 injection (Bertier et al., 2006). Under the experimental condition of 80e150 C and 0.1e15 MPa, negligible effect on the geochemical reactivity between supercritical CO2 (scCO2) and the caprock samples collected from Colorado and Charmotte was found over a 30 day period, but a trace dissolution occurred at 150 C after 45 days (Credoz et al., 2009). The experiments on CO2-
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water-rock interactions in the Utsira sand at Sleipner (North Sea) indicated that the dissolution of CO2 in the formation water could initiate a variety of geochemical reactions helping to chemically contain or trap the CO2 as dissolved species and by formation of new carbonate minerals (Rochelle et al., 2004). At 37 C and 10 MPa, dissolution of carbonate phases led to large and rapid increases in concentrations of Group II metals (Rochelle et al., 2004). Once the CO2 reaches a caprock, it may dissolve into the formation water of the caprock and subsequently diffuse further upward within the caprock (Gaus et al., 2005). Thus, caprock property is a very important factor for safe sequestration of CO2 in the deep subsurface environments, too. In addition, to cap rocks, CO2 sequestered in the subsurface will result in its dissolution in the brine and the dissolution of CO2 will make the brine denser (EASAC (European Academies Science Advisory Council), May 2013). After injection of 1600 tons of CO2 into the Frio Formation, Texas, USA, at depth of 1500 m, CO2 could mobilize heavy metals and lead to dissolution and/or desorption of trace elements from the mineral surfaces (Kharaka et al., 2006). Despite these recent researches, the study on the mobility of trace elements under the influence of CO2 is still lacking. And, data to assess the probability and the environmental impacts of CO2 leakage on groundwater quality are still limited (Karamalidis et al., 2013a). The Pliocene Yutengping Sandstone in Hsinchu City, NW Taiwan (Fig. 1) was considered as a potential site for CO2 storage in an interdisciplinary project. Its aquifer properties are similar to those of other existing ones in the world (Table 1). The formation water (depth ¼ 1827e1846 m) has a salinity of 16‰, which may affect the rate and amount of CO2 dissolution and precipitation, and leaching of trace elements from rock matrix, as observed at the Sleipner Gas Field, Norway (Rochelle et al., 2004). The dissolution of CO2 in water results in formation of carbonic acid with a decrease in pH. Thus, CO2erich fluids were capable of dissolving measurable amounts of trace elements in CO2 storage reservoirs (RempelLiebschner, 2011). The objectives of this study were to understand the changes in trace element chemistry as well as the differences in fluiderock interactions and the storage rock sandstone and its caprock shale under the storage conditions (anaerobic, at 90 C and 25 MPa) in the presence and absence of scCO2.
2. Geological settings The potential CO2 storage site was located in Hsinchu City, northern Taiwan (Fig. 1). The Chingtsaohu anticline (Fig. 1a) with the associated EeW trending high angle Hsinchu thrust is located in the outer part of foothills belt in northwestern Taiwan. The fold axis of the anticline is not parallel with but obliquely intersected with the thrust (Fig. 1a), indicating a right-lateral slip component along the high angle thrust (Yang et al., 2006). In the subsurface, the anticlinal structure is cut off by the high angle thrust, which is penetrated by drilled well C17 (Fig. 1b). The target reservoir considered for possible future CO2 storage is the Kuechulin Formation (Mkc), whose lowest part belongs to the youngest lithostratigraphic unit of the Miocene and the rest belonging to the Pliocene age. The formation is divided into three members (two sandstone and an interbedded shale members). The youngest member is the Yutengping Sandstone (Pytp) characterized by grey or greenish grey muddy sandstones occasionally interbedded with shale. It is overlaid by the Chinshui Shale (Pcs) Formation, mainly composed by greenish grey to dark grey shale, with interlayers of sandstones. This formation with a thickness of 140e170 m is regarded as a caprock and seal for the CO2 storage reservoir (Fig. 1).
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3. Materials and methods 3.1. Samples collection The formation water of Pytp was sampled at depth of 1827e1846 m on May 26, 2010 from an oil and water separation tank (Fig. 2) at the gas well C17 (Fig. 1b) and stored in a 14 L vacuum tank under anaerobic conditions. The physicochemical parameters of the formation water were measured on-site. The specific conductivity, salinity, and TDS were measured using a portable conductivity meter (Suntex; 162 WTW, LF320, Taiwan). The pH and EhS.H.E. were measured using a redox meter (SP701, Suntex, Kaohsiung, Taiwan). Sixteen sandstone (depth ¼ 1827e1846 m) and shale (depth ¼ 1630e1642 m) fragment samples (each 100 g) at the gas well C17 (Fig. 1b) were collected from the Typt Sandstone and its overlying PCs Shale on May 27, 2010 from the Geology Core Repository of China Petroleum Corporation, Miaoli, Taiwan. Both the formation water and rock samples were shipped to the Hydrogeology Laboratory, National Cheng Kung University (NCKU) within six hours after collection. 3.2. Experimental setup Within an anaerobic high pressure autoclave (# 6 in Fig. 3a, b, thereafter) (fabricated with assistance by the Asia Giant Engineering Co., Ltd., and the Metal Industries Research & Development Centre, Taiwan), 10 g of sandstone or shale fragment sample was placed in a glass beaker and 10 mL formation water was added (Fig. 3b). The CO2 from a gas tank (#1) was diverted to a condenser (# 7) and cooled to 8 C using a glycol cooling system (# 8). A total of 22.4 L CO2 fluid was delivered to a CO2 storage tank (# 3) through the pump (# 2) then the gas control valve (# 9) was opened to allow the liquid CO2 to be injected into the high pressure autoclave (# 6) where the injected CO2 fluid reacted with the formation water and rock for 7 days. The pressure and temperature inside the autoclave were set at 25 MPa and 90 C with the pressure and temperature controls (# 10 and 4), respectively. Dissolution in the absence of CO2 was also conducted by putting 10 g of sandstone or shale fragment sample and 10 mL formation water in a polypropylene vessel (id ¼ 2.6 cm, height ¼ 3.6 cm). The vessel was tightly sealed with a cap (outer diameter ¼ 3.6 cm, height ¼ 1.6 cm) and placed in the high-pressure autoclave filled with 12 L deionized water to maintain the desired pressure. The temperatures at different positions and depths inside the autoclave were measured to be constant nearly at 90 C. Heat at 99 C was emitted radially from the cylindrical reaction chamber of the autoclave (Fig. 3c), resulting in insignificant temperature gradients at different positions and depths. The temperature was set and maintained at 90 C while the reading from the temperature probe placed in the middle position of the autoclave was at 87.9 C (Fig. 3c). The experimental setup is shown in Fig. 3d and e, while an overview of all experiments and their roles in the study was illustrated in Fig. 4. 3.3. Dissolution experiments For this particular site, the reservoir conditions were 19 MPa and 75 C at depth of 1827e1846 m. Since the instrument was in high demand, and we were allocated limited time, each experiment lasted for seven days, in which the watererock interaction was considered to approach steady-state with the sample size of 10 g of rock and 10 mL of water. In compensation with the short duration, we set the high-pressure autoclave under a slightly elevated pressure and temperature conditions at 25 MPa and 90 C with or without scCO2 (Fig. 3). However, a new potential storage site was also identified nearby with a greater depth at 2333 m deep. Thus,
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Fig. 1. (a) Regional geological map of Chintsaohu structure; (b) Subsurface stratigraphic profile of Chintsaohu structures. The black circle in (a) shows the location of well C17 from which groundwater samples were collected and the red dot in (b) indicates the depth at which sandstone and shale samples were collected. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)
the elevated pressure and temperature conditions may produce preliminary experimental results for this new site. And it is different from a previous dissolution experiment set at 15 MPa and 62 C with 31 days of reaction time at depth of 1500 m for the Weyburn CO2 storage site in Canada (Karamalidis et al., 2013b). 3.4. Chemical analysis of formation water and rocks For whole rock analyses, 100 mg of sample powder was fluxed in a HFeHNO3 mixture at 190 C in a high-pressure bomb for at least
24 h. The samples were then heated to dryness; the residue was dissolved in HCl, and then converted to nitric form. For the analyses of extractable trace metals, the rock samples were extracted by 10 mL of 0.1 N HNO3. The concentrations of trace elements in the formation water were measured without any treatments (Table 2). All samples were diluted at a factor of 1000 using HNO3 before being analyzed by an inductively coupled plasma mass spectrometer (ICP-MS; Agilent 7500cs) for V, Cr, Mn, Fe, Co, Ni, Cu, Zn, As, Se, Rb, Sr, Mo, Cd, Ba. The US Geological Survey (USGS) standards PCC1, BCR-2, BIR-1, and AGV-1 were used to establish calibration
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Table 1 Properties of aquifers used for CO2 storage. Reservoir
P, MPa
T, C
Depth, km
pCO2, g/cm3a
References
Proposed site, Hsinchu, Taiwan Frio, USA Ketzin, Germany Sleipner, North Sea Snohvit, Nowegin Sea Weyburn, Canada
25 15 7e8 7e10 28.5 15
90 65 35 37 98 62
1.827e1.846 1.547 0.6e0.65 0.7e1.0 2.7 1.3e1.5
0.586 0.56 0.26 0.56 0.65 0.59
This study (Hovorka et al., 2006) (Forster et al., 2006; Würdemann et al., 2010) (Chadwick et al., 2004) (Estublier and Lackner, 2009) (Moberg et al., 2003; Karamalidis et al., 2013b)
a
Densities (pCO2) were calculated using the equation of state of Duan and Zhang (Duan and Zhang, 2006).
curves, while standard BHVO-1 was run as an external quality control standard to evaluate accuracy and precision. The results were within 5% of the recommended values (Credoz et al., 2009) and the precisions were within 10% for all analyzed elements, mostly 3%. After the seven-day experiments, the reacted rock-watersupercritical fluid samples in the beaker were filtered through 0.22 mm acetate cellulose membranes. After filtration, 1 g of reacted sandstone or shale sample was dried and ground to powder (sieve #200) and 10 mL of 0.1N HNO3 were added. The mixture was shaken for 24 h, before being filtered with 0.22 mm acetate cellulose membrane for trace element analyses. Meanwhile, 1 mL of reacted formation water was mixed with 0.1 N HNO3 to pH < 2 before being analyzed. The detection limit for all trace elements in 5% nitric solutions was <20 ng/L, except for Se and Zn (50e100 ng/L). A 10 mg/L multielement standard solution (High-Purity, USA) was diluted to element concentrations of 100, 50, 25, 10, 5, and 3 mg/L to establish calibration curves. The accuracy and precision were determined to be within ±5% for most elements by running a secondary standard (J T Baker, USA) every nine samples. 3.5. Mineralogy analysis of rocks Powder X-ray diffraction (XRD) analyses of bulk sandstone and shale specimens were carried out on a Bruker D8 Advance diffractometer with a Sol-X solid state detector and CuKa radiation
at 40 kV and 40 mA. Samples were scanned from 2 to 60 2q at 1 2q min1 with a scanning step of 0.01. A 0.6 mm divergent slit, 0.1 detector slit, and 0.6 mm anti-scattering slit on a goniometer of 600 mm in diameter were used. 4. Results and discussion 4.1. Parameters of formation water The formation water sampled at depth of 1853e1868.5 m had a pH of 8.45, a TDS of 2740 mg/L, an EC of 4.34 mS/cm, a salinity of 16‰, and an EhS.H.E. value of 114 mV (moderate reducing environment: 200 mV > EhS.H.E > 100 mV) and is a NaCl-dominant type of water. 4.2. Chemical properties of formation water and rocks Overall, the sandstone contained higher amounts of total trace elements in comparison to the shale. Mn, Ba, Sr, Rb, and V were the major trace elements in sandstone and shale, while the most acidextractable trace elements were Mn, Co, Ni, Cu, Zn, Ba, and Sr. Arsenic is one of the least extractable trace elements by 0.1 M HNO3, which accounted for its low concentration in formation water (1.4 mg/L). The acid-extractable trace elements accounted for 0e4% of the total trace elements in sandstone and up to 15% of the total trace elements in shale (Table 2).
Fig. 2. Formation water collected from an oil-water separation tank at the gas well C17.
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Fig. 3. Experimental setup for dissolution of trace elements in sandstone and shale.
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Fig. 4. A schematic diagram illustrating the overview of all experiments and their roles in this study.
4.3. Dissolution of trace elements in sandstone and shale When formation water is present in rocks in the absence of scCO2 fluid, the trace element components of both formation water and rocks could be changed. The contents of V, Mn, Zn, Rb, and Sr in sandstone decreased while their concentrations in formation water increased (Table 3a), suggesting that elevated temperature and pressure may enhance their dissolution or desorption. The concentrations of Co, Ni, Cu, As, Se, and Mo in sandstone increased by 1.5e2270% after reaction at higher temperature and pressure than those before the dissolution experiments and their mean concentrations in formation water increased, too (Table 3a). This may result from the dissolution of the mineral phases composed of the
Table 2 Mean concentrations of trace elements in formation water (gw), sandstone (Ss), and shale (Sh) before high pressure dissolution experiments in the absence of scCO2 fluid (each value is an average of triplicates). Elem.
Elem. in whole rock digested Ss before exper. (mg/kg)
Elem. in whole rock digested Sh before exper. (mg/kg)
Mean concen. of elem. in gw before exper. (mg/L)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
1144000 834000 3943000 e 163000 423000 262000 950000 149900 7300 1215000 1379000 6210 20 3876000
641000 429000 2822000 e 114000 252000 120000 872000 134300 5570 851000 918000 2590 20 926000
1.9 1.8 15.2 69.6 0.1 3.2 5.8 19.1 1.4 0.1 17.7 390.8 1.7 2.8 419.9
above elements into the formation water and transformation into other acid extractable phases, such as hydroxides and carbonates. It was found that the metal arsenosulfides (MAsS, M: Fe, Ni, Co, Cu) were decomposed to yield M2þ(aq) and H3AsO3(aq), which can be expressed with the following reaction (Eggins et al., 1997) (M stands for metal): 2 þ MAsS þ 7H2 O ¼ M2þ ðaqÞ þH3 AsO3ðaqÞ þ11H þ11e þSO4
(1)
M2þ þ2H2 O ¼ MðOHÞ2ðsÞ þ2Hþ
(2)
M(OH)2 (M: Fe, Co, Ni, Cu) have isoelectric points higher than 8 (Craw et al., 2003) and exhibit net positive charges in most geological environments, showing high affinity for As species. Eqs. (1) and (2) can lead to increases in mean concentrations of Co, Ni, Cu, As in both formation water and extractable fraction in the rocks after reaction. Note that both the extractable Fe content in the sandstone and mean Fe concentration in formation water decreased after the reaction. This can be explained by the fact that water can oxidize Fe(OH)2 to Fe(OH)3 whose solubility product is extremely low. In contrast to Fe, the oxidation capacity of H2O is not high enough to oxidize Cu(OH)2, Co(OH)2, and Ni(OH)2 and, as a result, the main reaction products after hydrothermal treatment were metal hydroxides rather than oxides (Cabanas and Poliakoff, 2001). For Se, its concentration in the formation water increased by 11,800% (Table 3a). Adsorption of Se species onto the Fe, Mn, and Al-oxyhydroxides surfaces played an important role in Se concentrations in formation water (Swaddle and Wong, 1978). The extractable Fe and Mn extents in sandstone after reaction decreased, suggesting the contents of Fe and Mn-oxyhydroxides in sandstone decreased, resulting in the dissolution of the adsorbed selenium species into formation water (Table 3a). For shale, only As, Sr, and Mo were dissolved from shale into formation water in the absence of scCO2 fluid (Table 3b), resulting in a decrease of their contents in shale and increase of their concentrations in formation water. More V, Cr, Co, Ni, Cu, Zn, Se, and Rb
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Table 3 Trace element contents in (a) sandstone (Ss) and (b) shale (Sh) containing formation water under elevated temperature and pressure but in the absence of scCO2 fluid (each value is an average of triplicates). (a) Sandstone Elements Extracted from Ss Extracted from Ss in Ss þ gw before exper. (mg/kg) mixture after reaction (mg/kg)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
5590.0 3540.0 153120.0 4890.0 2530.0 4050.0 4020.0 9220.0 546.0 52.1 1210.0 39000.0 0.6 12.2 7530.0
5530.0 3330.0 127190.0 4230.0 2830.0 4940.0 4080.0 8890.0 12950.0 53.9 1180.0 32300.0 0.9 13.8 5680.0
Desorption Mean concentration in gw Mean concen. in gw in Ss þ gw ()/Adsorption (þ) before exper. (mg/L) mixture after reaction (mg/L)
Difference
(mg/kg)
(mg/L)
(%)
60.0 1.1 1.9 210.0 5.9 1.8 25930.0 16.9 15.2 660.0 13.5 69.6 300.0 11.9 0.1 890.0 22.0 3.2 60.0 1.5 5.8 330.0 3.6 19.1 12404.0 2272 1.4 1.8 3.5 0.1 30.0 2.5 17.7 6700.0 17.2 390.8 0.3 50.0 1.7 1.6 13.1 2.8 1850.0 24.6 419.9
5.5 1.7 32.9 32.6 0.9 15.0 13.2 86.8 27.8 11.9 48.0 3610.0 14.7 0.0 29.1
(%)
3.6 189.5 0.1 5.6 17.7 116.5 37.0 53.2 0.8 800.0 11.8 368.7 7.4 127.6 67.7 354.4 26.4 1886 11.8 11800 30.3 171.2 3219.2 823.8 13.0 764.7 2.8 100.0 390.8 93
(b) Shale Elements Extracted from Sh before exper. (mg/kg)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
3640.0 2950.0 439180.0 5270.0 3710.0 6150.0 10080.0 10080.0 134.0 60.6 1790.0 46230.0 0.8 18.5 8590.0
Extracted from Sh in Sh þ gw mixture after reaction (mg/kg)
4710.0 3850.0 530350.0 5480.0 4920.0 7560.0 11450.0 14380.0 85.0 77.3 2010.0 42760.0 0.5 28.4 9610.0
Desorption ()/Adsorption (þ)
Mean concentration in gw Mean concen. in gw in Sh þ gw before exper. (mg/L) mixture after reaction (mg/L
(mg/kg)
(%)
1070.0 900.0 91170.0 210.0 1210.0 1410.0 1370.0 4300.0 49.0 16.7 220.0 3470.0 0.3 9.9 1020.0
29.4 1.9 30.5 1.8 20.8 15.2 4.0 69.6 32.6 0.1 22.9 3.2 13.6 5.8 42.7 19.1 36.6 1.4 27.6 0.1 12.3 17.7 7.5 390.8 37.5 1.7 53.5 2.8 11.9 419.9
in both shale and formation water were dissolved by 12e43% in the absence of scCO2 (Table 3b). The mean Fe concentration in formation water for shale decreased by 80%, similar to the result of sandstone. These results may be explained by a similar mechanism for sandstone. Similar increase in concentrations of Zn, Cu, was also found in Bunter Sandstone formation proposed for potential CO2 storage (Wigand et al., 2008). However, when scCO2 was present, the concentrations of chemical components of formation water and rocks could change due to interactions among scCO2, water, and rocks (Rochelle et al., 2004). The scCO2 dissolved up to 78% more Ni, As, Se, Mo, and Cd from sandstone in comparison to the raw rock (Table 4a). More V, Co, Ni, Cu, As, and Rb were dissolved from shale into formation water by scCO2 fluid (Table 4b). However, the contents of extractable Fe and Sr increased in shale but decreased in formation water; implying their adsorption from formation water or precipitation as Fe(OH)3 or SrCO3 with the extremely low solubility product (Kittaka and Morimoto, 1980). Similar to sandstone, the scCO2 fluid dissolved more Mn, Fe, Zn, Se, Sr, Mo, Cd, and Ba from shale by 0.9e36% in comparison to raw rocks (Table 4b). The experimental dissolution results in the present study have revealed that scCO2 fluid could corrode sandstone and shale and change the chemical components of formation water (Rochelle et al., 2004). In comparison with contents of extractable trace elements in
Difference
(mg/L) 4.6 1.8 13.8 14.0 0.7 9.1 21.4 95.2 4.5 26.0 35.0 504.0 352.0 0.0 9.9
(%)
2.7 142.1 0.0 0.0 1.4 9.2 55.6 80.0 0.6 600.0 5.9 184.4 15.6 269.0 76.1 398.4 3.1 221.4 25.9 25900 17.3 97.7 113.2 29.0 350.3 20606 2.8 100 410.0 97.6
sandstone containing formation water with or without scCO2 fluid (Table 5a), more V, Cr, Fe, Co, Ni, Cu, Zn, As, Rb, Sr, and Cd were desorbed or dissolved from sandstone into formation water in the presence of scCO2 fluid. In contrast, the desorption or dissolution of Mn, Se, and Ba from sandstone in the presence of scCO2 were lower than those in the absence of scCO2 (Table 5a). The concentrations of Cr, Mn, Zn, As, and Ba in formation water were 5.5e370% higher in the presence of scCO2 fluid than those in the absence of scCO2 fluid (Table 5a). As concentration in formation water increased by four folds from 27.8 mg/L in the absence of scCO2 fluid to 130 mg/L in the presence of scCO2 fluid (Table 5a). For shale, V, Cr, Co, Ni, Cu, Zn, As, Rb, and Cd tended to desorb or dissolve from shale into formation water in the presence of scCO2 fluid (Table 5b). The concentrations of Co, Ni, Zn, As, and Rb in formation water were higher in the presence of scCO2 fluid than in the absence of scCO2 fluid by 36e870%. Meanwhile, the As concentration in formation water increased from 4.5 mg/L to 43.8 mg/L in the presence of scCO2. From the differences in concentrations of trace elements in sandstone and shale before and after rockewater interactions in the absence and presence of scCO2 fluids (Tables 3a and 4a, Fig. 5a), it is found that desorpton of Mn from sandstone in the absence of scCO2 fluid was 25930 mg/kg, which is about 6% higher than its desorption from sandstone in the presence of scCO2 fluid (16390 mg/kg). Arsenic could be desorbed from sandstone by as
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Table 4 Trace element contents in (a) sandstone (Ss) and (b) shale (Sh) containing formation water under elevated temperature and pressure in the presence of scCO2 fluid (each value is an average of triplicates). (a) Sandstone Elements
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
Extracted from Ss before exper. (mg/kg)
Extracted from Ss in Ss þ gw mixture after reaction (mg/kg)
Desorption ()/Adsorption (þ) (mg/kg)
(%)
5590.0 3540.0 153120.0 4890.0 2530.0 4050.0 4020.0 9220.0 546.0 52.1 1210.0 39000.0 0.6 12.2 7530.0
4670.0 2780.0 136730.0 4150.0 2460.0 4060.0 3700.0 8180.0 969.0 56.5 1170.0 31020.0 0.9 13.4 7070.0
920.0 760.0 16390.0 740.0 70.0 10.0 320.0 1040.0 423.0 4.4 40.0 7980.0 0.3 1.2 460.0
16.5 21.5 10.7 15.1 2.8 0.3 8 11.3 77.5 8.4 3.3 20.5 50 9.8 6.1
Mean concentration in gw before exper. (mg/L)
Mean concen. in gw in Ss þ gw mixture after reaction (mg/L)
(mg/L)
(%)
1.9 1.8 15.2 69.6 0.1 3.2 5.8 19.1 1.4 0.1 17.7 390.8 1.7 2.8 419.9
5.0 2.3 36.1 13.9 0.90 12.0 11.2 125.0 130.0 5.40 37.4 2470.0 8.1 0.0 30.7
3.1 0.5 20.9 55.7 0.8 8.8 5.4 105.9 128.6 5.3 19.7 2079.2 6.4 2.8 389.2
163.2 27.8 137.5 80 800 275 93.1 554.4 9185.7 5300 111.3 532 376.5 100 92.7
Difference
(b) Shale Elements
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
Extracted from Sh before exper. (mg/kg)
Extracted from Sh in Sh þ gw mixture after reaction (mg/kg)
Desorption ()/Adsorption (þ) (mg/kg)
(%)
3640.0 2950.0 439180.0 5270.0 3710.0 6150.0 10080.0 10080.0 134.0 60.6 1790.0 46230.0 0.8 18.5 8590.0
3610.0 2560.0 594030.0 5960.0 3060.0 4660.0 8450 10170 83.4 81.8 1730.0 47820.0 1.0 25.1 10930.0
30.0 390.0 154850.0 690.0 650.0 1490.0 1630.0 90.0 50.6 21.2 60.0 1590.0 0.2 6.6 2340.0
0.82 13.2 35.3 13.1 17.5 24.2 16.2 0.9 37.8 35 3.3 3.4 25 35.7 27.2
much as 2200% more in the presence of scCO2 fluid, resulting in 9200% increase in As concentration in the formation water (Tables 3a and 4a). As for Sr, 6700 mg/kg were desorbed from sandstone in the absence of scCO2 fluid, which is 3.3% lower than 7980 mg/kg desorbed from sandstone in the presence of scCO2 fluid. More Sr (by 290%) was released into formation water in the absence of scCO2 fluid than in the presence of scCO2 fluid. Interestingly, Cd concentrations in formation water of sandstone and shale were not detectable before and after in contact with CO2. As for shale and formation water, the concentrations of Mo, Cd, and Ba changed slightly with or without scCO2 fluid. However, a much higher Zn desorption (4300 mg/kg) from shale was found in the absence of scCO2 fluid than in the presence of scCO2 fluid (90 mg/kg). More Mn was desorbed (154850 mg/kg) from shale in the presence of scCO2 fluid than in absence of the scCO2 fluid (91170 mg/kg) (Tables 3b and 4b, Fig. 5b), resulting in more Mn release into formation water by 270%. Moreover, 3470 mg/kg of Sr were desorbed from shale and released into formation water in the absence of scCO2 fluid, whereas Sr was not desorbed from shale but adsorbed about 93% from formation water in the presence of scCO2 fluid. Other elements (i.e., V, Cr, Fe, Co, Ni, Cu, As, Se, Rb, Mo, Cd, and Ba) did not have significant change before and after in contact with scCO2. For selenium in sandstone and shale, its adsorption increased by 144% (Table 5a) and 27% (Table 5b), respectively, in the presence of
Mean concentration in gw before exper. (mg/L)
Mean concen. in gw in Sh þ gw mixture after reaction (mg/L)
(mg/L)
Difference (%)
1.9 1.8 15.2 69.6 0.1 3.2 5.8 19.1 1.4 0.1 17.7 390.8 1.7 2.8 419.9
4.6 0.0 57.9 11.1 1.4 19.8 9.4 129.0 43.8 18.30 55.0 26.0 3.7 0.0 3.6
2.7 1.8 42.7 58.5 1.3 16.6 3.6 109.9 42.4 18.2 37.3 364.8 2.0 2.8 416.3
142.1 100 280.9 84 1300 518.7 62.1 575.4 3028.6 18200 210.7 93.3 117.7 100 99.1
CO2. Its adsorption was strongly pH-dependent. Selenium exists 2 mainly in anionic acids (SeO2 4 and SeO3 ) in solution (Zhang and Sparks, 1990). As pH decreased, protonation of the hydroxides or oxides resulted in positive surface charges, which enhanced the adsorption of selenium anionic species (Parida et al., 1997) and lead to a decrease of Se concentration in the formation water by 22% after reaction in the scCO2. The extractable As contents after reaction under scCO2 for sandstone and shale were all lower than those in the absence of scCO2. However, the As concentration in the formation water after reaction with scCO2 for sandstone and shale increased by 370% (Table 5a) and 870% (Table 5b), respectively, compared to those in the absence of scCO2. The drastic increase in As concentration could be attributed to (1) increased solubility of the As-containing minerals due to decreased pH resulting from the dissolution of CO2 in water (Vink, 1996); (2) changes in adsorbent as As tends to adsorb on metal (mostly iron and manganese) (oxy) (hydr)oxides, followed by clays and feldspars (Henke and HutchisonHenke, 2009), while in the presence of scCO2, dissolution of iron and manganese (oxy) (hydr)oxides and feldspar resulted in release of the adsorbed As; (3) changes in speciation of carbonate and bicarbonate preventing retention of adsorbed As on (oxy) (hydr)oxides (Appelo et al., 2002). A previous study showed that most of trace elements (e.g., Fe, Mn, Sr, Ba, and Pb) of sandstone increased in concentration during
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Table 5 Trace element contents in formation water of (a) sandstone (Ss) and (b) shale (Sh) under elevated temperature and pressure in the presence or absence of scCO2 fluid (each value is an average of triplicates). (a) Sandstone Elements Desorp. ()/Adsorp. (þ) in Ss þ gw (No CO2) (mg/ kg)
Desorp. ()/Adsorp. (þ) Difference in Ss þ gw þ CO2 (mg/ (mg/kg) (%) kg)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
920.0 760.0 16390 740.0 70.0 10.0 320.0 1040 423.0 4.4 40.0 7980 0.3 1.2 460.0
60.0 210.0 25930.0 660.0 300 890.0 60.0 330.0 12404 1.8 30.0 6700 0.3 1.6 1850
Mean concent. in gw in Ss þ gw (No CO2) (mg/ Mean concen. in L) Ss þ gwþ CO2 (mg/L)
860.0 1433 5.5 550.0 261.9 1.7 9540 36.8 32.9 80.0 12.1 32.6 370.0 123.3 0.9 880.0 98.9 15.0 380.0 633.3 13.2 710.0 215.1 86.8 11981 96.6 27.8 2.6 144.4 11.9 10.0 33.3 48.0 1280 19.1 3610.0 0.0 0 14.7 0.4 25 0.0 1390 75.1 29.1
5.0 2.3 36.1 13.9 0.9 12.0 11.2 125.0 130.0 5.40 37.4 2470.0 8.1 0.0 30.7
Difference (mg/L)
(%)
0.5 0.6 3.2 18.7 0.0 3.0 2.0 38.2 102.2 6.5 10.6 1140 6.6 0.0 1.6
9.1 35.3 9.7 57.4 0 20.0 15.1 44.0 367.6 54.6 22.1 31.6 44.6 0 5.5
(b) Shale Elements Desorp. ()/Adsorp. (þ) in Sh þ gw (No CO2) (mg/kg) V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
1070 900 91170 210 1210 1410 1370 4300 49 16.7 220 3470 0.3 9.9 1020
Mean concent. in gw in Sh þ gw (No Mean concen. in CO2) (mg/L) Sh þ gwþ CO2 (mg/L)
Desorp. ()/Adsorp. (þ) in Sh þ gw þ CO2 (mg/kg)
Difference (mg/kg)
(%)
30 390 154850 690 650 1490 1630 90.0 50.6 21.2 60 1590 0.2 6.6 2340
1100 1290 63680 480.0 1860 2900 3000.0 4210 1.6 4.5 280.0 5060 0.5 3.3 1320
102.8 4.6 143.3 1.8 69.8 13.8 228.6 14.0 153.7 0.7 205.7 9.1 219 21.4 97.9 95.2 3.3 4.50 26.9 26.0 127.3 35.0 145.8 504.0 166.7 352.0 33.3 0.0 129.4 9.9
the reaction with scCO2 fluid (Wigand et al., 2008). Rocks collected from US, Canada, and Algeria showed that Cr and Pb released from sandstone reservoir and shale cap rocks exceed the MCLs by an order of magnitude in the presence of scCO2 (Karamalidis et al., 2013a). Evidences have been found for a long history of CO2 migration in fault zones and leakage to the atmosphere (Benson and Cole, 2008). This process may be enhanced by the dissolution of low permeability rocks by acidic CO2-rich fluids (Balistrieri and Chao, 1990). The interaction of the acidic CO2-rich fluids with shale could provide the trace elements essential to trapping CO2 in carbonate minerals, while the leaching of these trace elements may increase the permeability of shale leading to the escape of CO2 to the atmosphere as suggested in a field (Hovorka et al., 2006). 4.4. Mineral assemblages after high pressure simulation experiments Powder XRD analyses of bulk sandstone showed that quartz was the principal constituent of all sandstone (Ss) samples with subordinate potassium feldspar, albite, and minor muscovite and chlorite (Fig. 6). The 8.9 peak of muscovite was slightly skewed towards the low angles, possibly consisting of a smectite mixedlayer component. Microcline occurred with variable abundance and as the dominant K-feldspar in most of the sandstone samples
4.6 0.0 57.9 11.1 1.4 19.8 9.4 129.0 43.8 18.3 55.0 26.0 3.7 0.0 3.6
Difference (mg/L)
(%)
0.0 0 1.8 100 44.1 319.6 2.9 20.7 0.7 100 10.7 117.6 12.0 56.1 33.8 35.5 39.3 873.3 7.7 29.6 20.0 57.1 478.0 94.8 348.3 99.0 0.0 0 6.3 63.6
except sample Ss-gw-90 (sandstone with formation water at 90 C) in which orthoclase was the second most abundant constituent. There was a small amount of calcite and dolomite and possibly trace stilpnomelane and gypsum in sample Ss. A trace amount of calcite occurred in samples Ss-25, Ss-90, and Ss-gw-25 as well. Sample Ss-gw-90 additionally contained a very small amount of goethite. Overall, the sandstone samples can be characterized by an assemblage of quartz þ Kfeldspar þ albite þ muscovite þ chlorite ± calcite ± dolomite ± stilpnomelane ± gypsum ± goethite. The shale samples (Sh) contained quartz, muscovite, chlorite, and albite as the major phases with small variable amounts of calcite, dolomite, and microcline (Fig. 6). It should be noticed that dolomite, stilpnomelane, and gypsum diminished in the mixed solution of sandstone and scCO2 fluid after reaction. Meanwhile, dolomite disappeared in the mixed solution of shale and scCO2 fluid after the reaction. 5. Environmental implication The dissolution of CO2 in the formation water can corrode the rocks (storage unit of CO2 and its caprock) and change the formation water compositions. This may induce an increase in porosity and permeability of the storage unit of CO2 and its caprock. Our
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313
Fig. 6. Powder X-ray diffraction patterns of bulk sandstone (Ss-90 and Ss-gw-90) and shale (Sh-90 and Sh-gw-90) samples. Chl ¼ chlorite; Mca ¼ muscovite; Gt ¼ goethite; Qz ¼ quartz; Or ¼ orthoclase; Mc ¼ microcline; Ab ¼ albite; Cal ¼ calcite; Dol ¼ dolomite.
Fig. 5. Differences in concentrations of trace elements in (a) sandstone and (b) shale before and after rockewater interactions in the absence and presence of scCO2 fluids.
experimental results indicate that the concentration of As in formation water increased from 1.4 mg/L to 130 mg/L (Tables 4a and 5a) after in contact with scCO2. Trace elements mobilized from the CO2 storage unit into the formation water and its caprock caused by increasing temperature, pressure, and concentration of scCO2 fluid after injection of CO2 may reach shallow aquifers and contaminate their groundwater resources (Karamalidis et al., 2013a). If there is a leakage along the high angle Hsinchu fault to the north of the proposed injection site, the fault zone could serve as conveying belt to transmit the groundwater with higher dissolved trace element concentrations and release stored CO2 into the atmosphere. A detailed investigation of the changes of porosity and permeability of the CO2 storage unit and its caprock after injection of CO2 must be carried out in the future to ensure a safe sequestration of CO2 in the deep subsurface environment. And the results from this and future studies may serve as parameters for future simulation of CO2 capture and mobility. 6. Conclusion Our experimental results showed that most trace elements in the sandstone and its overlying caprock shale can be mobilized and dissolved into formation water under elevated temperature and pressure and in the presence of scCO2 fluid. Among the trace metals, V, Cr, Co, Cu, and Rb tended to dissolve from sandstone and shale into formation water under elevated temperature and
pressure and in the presence of scCO2, whereas Zn, Se, Mo, and Cd were relatively recalcitrant from desorption from sandstone and shale. They absorb from formation water onto the solid matrix. In the presence of scCO2, the releases of Mo and As from sandstone and Mn, Fe, Zn, Se, Sr, Mo, Cd, and Ba from shale in the presence of scCO2 increased by 50e78% and 0.9e36%, respectively. The enhanced dissolution of As (nearly 100 fold) and its mobility under anaerobic conditions may indicate a significant potential threat to the shallow groundwater quality in this region. Conflict of interests The authors declare that there is no conflict of interests regarding the publication of this paper. Acknowledgment The authors would like to thank the National Science Council of Taiwan for financial support of this research (Grant no. NSC1003113-E-008-002). The authors are grateful to Mr. Po-Yu Wu and Mr. Chia-Chuan Chou and Pu-Yu Wu of Exploration and Development Research Institute, China Petroleum Corporation in Miaoli, Taiwan to help us collecting formation water and to Geology Core Repository of China Petroleum Incorporation to allow us to collect sandstone and shale core samples. The authors also thank PoHsiang Chang, Chiao-Ling Wong, Cheng-Yi Ho, Chun-Jung Guo, Huan-Wen Lin, Yi-Hua Chen, and Ms. Pei-Rung Du of National Cheng Kung University for helping with the experiments and data interpretation. Appreciations were also given to Dr. Ian Craig of University of Southern Queensland for his help in manuscript
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Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse
Experimental investigation of trace element dissolution in formation water in the presence of supercritical CO2 fluid for a potential geological storage site of CO2 in Taiwan Jiin-Shuh Jean a, Chien-Lih Wang b, Hsing-I. Hsiang b, Zhaohui Li a, c, *, Huai-Jen Yang a, Wei-Teh Jiang a, Kenn-Ming Yang a, Jochen Bundschuh d a
Department of Earth Sciences, National Cheng Kung University, Tainan, Taiwan Department of Resources Engineering, National Cheng Kung University, Tainan, Taiwan Department of Geosciences, University of Wisconsin e Parkside, 900 Wood Road, Kenosha, WI 53144, USA d Faculty of Health, Engineering and Surveying & National Centre of Engineering in Agriculture, University of Southern Queensland, Toowoomba, Queensland 4350, Australia b c
a r t i c l e i n f o
a b s t r a c t
Article history: Received 27 October 2014 Received in revised form 5 February 2015 Accepted 6 February 2015 Available online
The Pliocene Yutengping Sandstone (depth 1642e1882 m) and its overlying caprock shale (depth 1395 e1642 m) in Hsinchu City, central Taiwan, were intended for a storage site of CO2. Formation water was collected from a gas well located at a depth of 1827e1846 m. This study investigated changes in water chemistry and dissolution of trace elements from the sandstone and shale at 25 MPa and 90 C in the presence and absence of supercritical CO2 (scCO2) over 7 days. The results showed substantial dissolution of V, Cr, Co, Cu, and Rb from the sandstone and shale into formation water in the presence of scCO2 fluid, while the release of Zn, Se, Mo, and Cd from the sandstone and shale was minimal. Desorption of V, Cr, Mn, Fe, Sr, and Ba was more pronounced from the sandstone than from shale, whereas Co, Ni, Cu, As, and Mo desorbed more from the shale. The concentration of As in formation water increased from 1.4 mg/L to 130 mg/L after in contact with scCO2. Such a high As concentration may present a significant threat to shallow groundwater quality in this region, particularly if leakage along faults and rock fractures in the region occurred. © 2015 Elsevier B.V. All rights reserved.
Keywords: Desorption Dissolution Fluid-rock interaction Mobilization Sequestration Supercritical CO2
1. Introduction The rise in carbon dioxide production and its release into the atmosphere over the last century has contributed significantly to global warming (IPCC (Intergovernmental Panel on Climate Change), 2013). To mitigate this effect, attention has paid to investigate the potentials for underground CO2 storage in geological formations. Geological sequestration may involve three processes: (1) hydrodynamic trapping of CO2 as a gas or supercritical fluid beneath a low permeability caprock; (2) solubility trapping with the dissolution of CO2 into fluid phases, including both aqueous brines and oil; and (3) mineral trapping incorporating CO2 into solid phases via precipitation of carbonate minerals (Oelkers
* Corresponding author. Department of Geosciences, University of Wisconsin e Parkside, 900 Wood Road, Kenosha, WI 53144, USA. E-mail address: [email protected] (Z. Li). http://dx.doi.org/10.1016/j.jngse.2015.02.006 1875-5100/© 2015 Elsevier B.V. All rights reserved.
and Schott, 2005). In order to achieve a safe sequestration of CO2 in the deep subsurface environment, the National Science Council of Taiwan allocated special funds to a number of universities in Taiwan, to conduct a three-year multidisciplinary integrated research for carbon dioxide capture and storage (CCS). One of the research targets was to assess any potential risks that may occur after the injection of CO2 into the deep subsurface environment. Although many researches were conducted on mineral trapping of CO2, which occurs via carbonate mineral precipitation (Oelkers and Schott, 2005), and the feasibility of geological sequestration of CO2 was proven, apart from literature data on modeling, still more research is needed to study the CO2ewatererock interactions induced by CO2 injection (Bertier et al., 2006). Under the experimental condition of 80e150 C and 0.1e15 MPa, negligible effect on the geochemical reactivity between supercritical CO2 (scCO2) and the caprock samples collected from Colorado and Charmotte was found over a 30 day period, but a trace dissolution occurred at 150 C after 45 days (Credoz et al., 2009). The experiments on CO2-
J.-S. Jean et al. / Journal of Natural Gas Science and Engineering 23 (2015) 304e314
water-rock interactions in the Utsira sand at Sleipner (North Sea) indicated that the dissolution of CO2 in the formation water could initiate a variety of geochemical reactions helping to chemically contain or trap the CO2 as dissolved species and by formation of new carbonate minerals (Rochelle et al., 2004). At 37 C and 10 MPa, dissolution of carbonate phases led to large and rapid increases in concentrations of Group II metals (Rochelle et al., 2004). Once the CO2 reaches a caprock, it may dissolve into the formation water of the caprock and subsequently diffuse further upward within the caprock (Gaus et al., 2005). Thus, caprock property is a very important factor for safe sequestration of CO2 in the deep subsurface environments, too. In addition, to cap rocks, CO2 sequestered in the subsurface will result in its dissolution in the brine and the dissolution of CO2 will make the brine denser (EASAC (European Academies Science Advisory Council), May 2013). After injection of 1600 tons of CO2 into the Frio Formation, Texas, USA, at depth of 1500 m, CO2 could mobilize heavy metals and lead to dissolution and/or desorption of trace elements from the mineral surfaces (Kharaka et al., 2006). Despite these recent researches, the study on the mobility of trace elements under the influence of CO2 is still lacking. And, data to assess the probability and the environmental impacts of CO2 leakage on groundwater quality are still limited (Karamalidis et al., 2013a). The Pliocene Yutengping Sandstone in Hsinchu City, NW Taiwan (Fig. 1) was considered as a potential site for CO2 storage in an interdisciplinary project. Its aquifer properties are similar to those of other existing ones in the world (Table 1). The formation water (depth ¼ 1827e1846 m) has a salinity of 16‰, which may affect the rate and amount of CO2 dissolution and precipitation, and leaching of trace elements from rock matrix, as observed at the Sleipner Gas Field, Norway (Rochelle et al., 2004). The dissolution of CO2 in water results in formation of carbonic acid with a decrease in pH. Thus, CO2erich fluids were capable of dissolving measurable amounts of trace elements in CO2 storage reservoirs (RempelLiebschner, 2011). The objectives of this study were to understand the changes in trace element chemistry as well as the differences in fluiderock interactions and the storage rock sandstone and its caprock shale under the storage conditions (anaerobic, at 90 C and 25 MPa) in the presence and absence of scCO2.
2. Geological settings The potential CO2 storage site was located in Hsinchu City, northern Taiwan (Fig. 1). The Chingtsaohu anticline (Fig. 1a) with the associated EeW trending high angle Hsinchu thrust is located in the outer part of foothills belt in northwestern Taiwan. The fold axis of the anticline is not parallel with but obliquely intersected with the thrust (Fig. 1a), indicating a right-lateral slip component along the high angle thrust (Yang et al., 2006). In the subsurface, the anticlinal structure is cut off by the high angle thrust, which is penetrated by drilled well C17 (Fig. 1b). The target reservoir considered for possible future CO2 storage is the Kuechulin Formation (Mkc), whose lowest part belongs to the youngest lithostratigraphic unit of the Miocene and the rest belonging to the Pliocene age. The formation is divided into three members (two sandstone and an interbedded shale members). The youngest member is the Yutengping Sandstone (Pytp) characterized by grey or greenish grey muddy sandstones occasionally interbedded with shale. It is overlaid by the Chinshui Shale (Pcs) Formation, mainly composed by greenish grey to dark grey shale, with interlayers of sandstones. This formation with a thickness of 140e170 m is regarded as a caprock and seal for the CO2 storage reservoir (Fig. 1).
305
3. Materials and methods 3.1. Samples collection The formation water of Pytp was sampled at depth of 1827e1846 m on May 26, 2010 from an oil and water separation tank (Fig. 2) at the gas well C17 (Fig. 1b) and stored in a 14 L vacuum tank under anaerobic conditions. The physicochemical parameters of the formation water were measured on-site. The specific conductivity, salinity, and TDS were measured using a portable conductivity meter (Suntex; 162 WTW, LF320, Taiwan). The pH and EhS.H.E. were measured using a redox meter (SP701, Suntex, Kaohsiung, Taiwan). Sixteen sandstone (depth ¼ 1827e1846 m) and shale (depth ¼ 1630e1642 m) fragment samples (each 100 g) at the gas well C17 (Fig. 1b) were collected from the Typt Sandstone and its overlying PCs Shale on May 27, 2010 from the Geology Core Repository of China Petroleum Corporation, Miaoli, Taiwan. Both the formation water and rock samples were shipped to the Hydrogeology Laboratory, National Cheng Kung University (NCKU) within six hours after collection. 3.2. Experimental setup Within an anaerobic high pressure autoclave (# 6 in Fig. 3a, b, thereafter) (fabricated with assistance by the Asia Giant Engineering Co., Ltd., and the Metal Industries Research & Development Centre, Taiwan), 10 g of sandstone or shale fragment sample was placed in a glass beaker and 10 mL formation water was added (Fig. 3b). The CO2 from a gas tank (#1) was diverted to a condenser (# 7) and cooled to 8 C using a glycol cooling system (# 8). A total of 22.4 L CO2 fluid was delivered to a CO2 storage tank (# 3) through the pump (# 2) then the gas control valve (# 9) was opened to allow the liquid CO2 to be injected into the high pressure autoclave (# 6) where the injected CO2 fluid reacted with the formation water and rock for 7 days. The pressure and temperature inside the autoclave were set at 25 MPa and 90 C with the pressure and temperature controls (# 10 and 4), respectively. Dissolution in the absence of CO2 was also conducted by putting 10 g of sandstone or shale fragment sample and 10 mL formation water in a polypropylene vessel (id ¼ 2.6 cm, height ¼ 3.6 cm). The vessel was tightly sealed with a cap (outer diameter ¼ 3.6 cm, height ¼ 1.6 cm) and placed in the high-pressure autoclave filled with 12 L deionized water to maintain the desired pressure. The temperatures at different positions and depths inside the autoclave were measured to be constant nearly at 90 C. Heat at 99 C was emitted radially from the cylindrical reaction chamber of the autoclave (Fig. 3c), resulting in insignificant temperature gradients at different positions and depths. The temperature was set and maintained at 90 C while the reading from the temperature probe placed in the middle position of the autoclave was at 87.9 C (Fig. 3c). The experimental setup is shown in Fig. 3d and e, while an overview of all experiments and their roles in the study was illustrated in Fig. 4. 3.3. Dissolution experiments For this particular site, the reservoir conditions were 19 MPa and 75 C at depth of 1827e1846 m. Since the instrument was in high demand, and we were allocated limited time, each experiment lasted for seven days, in which the watererock interaction was considered to approach steady-state with the sample size of 10 g of rock and 10 mL of water. In compensation with the short duration, we set the high-pressure autoclave under a slightly elevated pressure and temperature conditions at 25 MPa and 90 C with or without scCO2 (Fig. 3). However, a new potential storage site was also identified nearby with a greater depth at 2333 m deep. Thus,
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Fig. 1. (a) Regional geological map of Chintsaohu structure; (b) Subsurface stratigraphic profile of Chintsaohu structures. The black circle in (a) shows the location of well C17 from which groundwater samples were collected and the red dot in (b) indicates the depth at which sandstone and shale samples were collected. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)
the elevated pressure and temperature conditions may produce preliminary experimental results for this new site. And it is different from a previous dissolution experiment set at 15 MPa and 62 C with 31 days of reaction time at depth of 1500 m for the Weyburn CO2 storage site in Canada (Karamalidis et al., 2013b). 3.4. Chemical analysis of formation water and rocks For whole rock analyses, 100 mg of sample powder was fluxed in a HFeHNO3 mixture at 190 C in a high-pressure bomb for at least
24 h. The samples were then heated to dryness; the residue was dissolved in HCl, and then converted to nitric form. For the analyses of extractable trace metals, the rock samples were extracted by 10 mL of 0.1 N HNO3. The concentrations of trace elements in the formation water were measured without any treatments (Table 2). All samples were diluted at a factor of 1000 using HNO3 before being analyzed by an inductively coupled plasma mass spectrometer (ICP-MS; Agilent 7500cs) for V, Cr, Mn, Fe, Co, Ni, Cu, Zn, As, Se, Rb, Sr, Mo, Cd, Ba. The US Geological Survey (USGS) standards PCC1, BCR-2, BIR-1, and AGV-1 were used to establish calibration
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Table 1 Properties of aquifers used for CO2 storage. Reservoir
P, MPa
T, C
Depth, km
pCO2, g/cm3a
References
Proposed site, Hsinchu, Taiwan Frio, USA Ketzin, Germany Sleipner, North Sea Snohvit, Nowegin Sea Weyburn, Canada
25 15 7e8 7e10 28.5 15
90 65 35 37 98 62
1.827e1.846 1.547 0.6e0.65 0.7e1.0 2.7 1.3e1.5
0.586 0.56 0.26 0.56 0.65 0.59
This study (Hovorka et al., 2006) (Forster et al., 2006; Würdemann et al., 2010) (Chadwick et al., 2004) (Estublier and Lackner, 2009) (Moberg et al., 2003; Karamalidis et al., 2013b)
a
Densities (pCO2) were calculated using the equation of state of Duan and Zhang (Duan and Zhang, 2006).
curves, while standard BHVO-1 was run as an external quality control standard to evaluate accuracy and precision. The results were within 5% of the recommended values (Credoz et al., 2009) and the precisions were within 10% for all analyzed elements, mostly 3%. After the seven-day experiments, the reacted rock-watersupercritical fluid samples in the beaker were filtered through 0.22 mm acetate cellulose membranes. After filtration, 1 g of reacted sandstone or shale sample was dried and ground to powder (sieve #200) and 10 mL of 0.1N HNO3 were added. The mixture was shaken for 24 h, before being filtered with 0.22 mm acetate cellulose membrane for trace element analyses. Meanwhile, 1 mL of reacted formation water was mixed with 0.1 N HNO3 to pH < 2 before being analyzed. The detection limit for all trace elements in 5% nitric solutions was <20 ng/L, except for Se and Zn (50e100 ng/L). A 10 mg/L multielement standard solution (High-Purity, USA) was diluted to element concentrations of 100, 50, 25, 10, 5, and 3 mg/L to establish calibration curves. The accuracy and precision were determined to be within ±5% for most elements by running a secondary standard (J T Baker, USA) every nine samples. 3.5. Mineralogy analysis of rocks Powder X-ray diffraction (XRD) analyses of bulk sandstone and shale specimens were carried out on a Bruker D8 Advance diffractometer with a Sol-X solid state detector and CuKa radiation
at 40 kV and 40 mA. Samples were scanned from 2 to 60 2q at 1 2q min1 with a scanning step of 0.01. A 0.6 mm divergent slit, 0.1 detector slit, and 0.6 mm anti-scattering slit on a goniometer of 600 mm in diameter were used. 4. Results and discussion 4.1. Parameters of formation water The formation water sampled at depth of 1853e1868.5 m had a pH of 8.45, a TDS of 2740 mg/L, an EC of 4.34 mS/cm, a salinity of 16‰, and an EhS.H.E. value of 114 mV (moderate reducing environment: 200 mV > EhS.H.E > 100 mV) and is a NaCl-dominant type of water. 4.2. Chemical properties of formation water and rocks Overall, the sandstone contained higher amounts of total trace elements in comparison to the shale. Mn, Ba, Sr, Rb, and V were the major trace elements in sandstone and shale, while the most acidextractable trace elements were Mn, Co, Ni, Cu, Zn, Ba, and Sr. Arsenic is one of the least extractable trace elements by 0.1 M HNO3, which accounted for its low concentration in formation water (1.4 mg/L). The acid-extractable trace elements accounted for 0e4% of the total trace elements in sandstone and up to 15% of the total trace elements in shale (Table 2).
Fig. 2. Formation water collected from an oil-water separation tank at the gas well C17.
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Fig. 3. Experimental setup for dissolution of trace elements in sandstone and shale.
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Fig. 4. A schematic diagram illustrating the overview of all experiments and their roles in this study.
4.3. Dissolution of trace elements in sandstone and shale When formation water is present in rocks in the absence of scCO2 fluid, the trace element components of both formation water and rocks could be changed. The contents of V, Mn, Zn, Rb, and Sr in sandstone decreased while their concentrations in formation water increased (Table 3a), suggesting that elevated temperature and pressure may enhance their dissolution or desorption. The concentrations of Co, Ni, Cu, As, Se, and Mo in sandstone increased by 1.5e2270% after reaction at higher temperature and pressure than those before the dissolution experiments and their mean concentrations in formation water increased, too (Table 3a). This may result from the dissolution of the mineral phases composed of the
Table 2 Mean concentrations of trace elements in formation water (gw), sandstone (Ss), and shale (Sh) before high pressure dissolution experiments in the absence of scCO2 fluid (each value is an average of triplicates). Elem.
Elem. in whole rock digested Ss before exper. (mg/kg)
Elem. in whole rock digested Sh before exper. (mg/kg)
Mean concen. of elem. in gw before exper. (mg/L)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
1144000 834000 3943000 e 163000 423000 262000 950000 149900 7300 1215000 1379000 6210 20 3876000
641000 429000 2822000 e 114000 252000 120000 872000 134300 5570 851000 918000 2590 20 926000
1.9 1.8 15.2 69.6 0.1 3.2 5.8 19.1 1.4 0.1 17.7 390.8 1.7 2.8 419.9
above elements into the formation water and transformation into other acid extractable phases, such as hydroxides and carbonates. It was found that the metal arsenosulfides (MAsS, M: Fe, Ni, Co, Cu) were decomposed to yield M2þ(aq) and H3AsO3(aq), which can be expressed with the following reaction (Eggins et al., 1997) (M stands for metal): 2 þ MAsS þ 7H2 O ¼ M2þ ðaqÞ þH3 AsO3ðaqÞ þ11H þ11e þSO4
(1)
M2þ þ2H2 O ¼ MðOHÞ2ðsÞ þ2Hþ
(2)
M(OH)2 (M: Fe, Co, Ni, Cu) have isoelectric points higher than 8 (Craw et al., 2003) and exhibit net positive charges in most geological environments, showing high affinity for As species. Eqs. (1) and (2) can lead to increases in mean concentrations of Co, Ni, Cu, As in both formation water and extractable fraction in the rocks after reaction. Note that both the extractable Fe content in the sandstone and mean Fe concentration in formation water decreased after the reaction. This can be explained by the fact that water can oxidize Fe(OH)2 to Fe(OH)3 whose solubility product is extremely low. In contrast to Fe, the oxidation capacity of H2O is not high enough to oxidize Cu(OH)2, Co(OH)2, and Ni(OH)2 and, as a result, the main reaction products after hydrothermal treatment were metal hydroxides rather than oxides (Cabanas and Poliakoff, 2001). For Se, its concentration in the formation water increased by 11,800% (Table 3a). Adsorption of Se species onto the Fe, Mn, and Al-oxyhydroxides surfaces played an important role in Se concentrations in formation water (Swaddle and Wong, 1978). The extractable Fe and Mn extents in sandstone after reaction decreased, suggesting the contents of Fe and Mn-oxyhydroxides in sandstone decreased, resulting in the dissolution of the adsorbed selenium species into formation water (Table 3a). For shale, only As, Sr, and Mo were dissolved from shale into formation water in the absence of scCO2 fluid (Table 3b), resulting in a decrease of their contents in shale and increase of their concentrations in formation water. More V, Cr, Co, Ni, Cu, Zn, Se, and Rb
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Table 3 Trace element contents in (a) sandstone (Ss) and (b) shale (Sh) containing formation water under elevated temperature and pressure but in the absence of scCO2 fluid (each value is an average of triplicates). (a) Sandstone Elements Extracted from Ss Extracted from Ss in Ss þ gw before exper. (mg/kg) mixture after reaction (mg/kg)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
5590.0 3540.0 153120.0 4890.0 2530.0 4050.0 4020.0 9220.0 546.0 52.1 1210.0 39000.0 0.6 12.2 7530.0
5530.0 3330.0 127190.0 4230.0 2830.0 4940.0 4080.0 8890.0 12950.0 53.9 1180.0 32300.0 0.9 13.8 5680.0
Desorption Mean concentration in gw Mean concen. in gw in Ss þ gw ()/Adsorption (þ) before exper. (mg/L) mixture after reaction (mg/L)
Difference
(mg/kg)
(mg/L)
(%)
60.0 1.1 1.9 210.0 5.9 1.8 25930.0 16.9 15.2 660.0 13.5 69.6 300.0 11.9 0.1 890.0 22.0 3.2 60.0 1.5 5.8 330.0 3.6 19.1 12404.0 2272 1.4 1.8 3.5 0.1 30.0 2.5 17.7 6700.0 17.2 390.8 0.3 50.0 1.7 1.6 13.1 2.8 1850.0 24.6 419.9
5.5 1.7 32.9 32.6 0.9 15.0 13.2 86.8 27.8 11.9 48.0 3610.0 14.7 0.0 29.1
(%)
3.6 189.5 0.1 5.6 17.7 116.5 37.0 53.2 0.8 800.0 11.8 368.7 7.4 127.6 67.7 354.4 26.4 1886 11.8 11800 30.3 171.2 3219.2 823.8 13.0 764.7 2.8 100.0 390.8 93
(b) Shale Elements Extracted from Sh before exper. (mg/kg)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
3640.0 2950.0 439180.0 5270.0 3710.0 6150.0 10080.0 10080.0 134.0 60.6 1790.0 46230.0 0.8 18.5 8590.0
Extracted from Sh in Sh þ gw mixture after reaction (mg/kg)
4710.0 3850.0 530350.0 5480.0 4920.0 7560.0 11450.0 14380.0 85.0 77.3 2010.0 42760.0 0.5 28.4 9610.0
Desorption ()/Adsorption (þ)
Mean concentration in gw Mean concen. in gw in Sh þ gw before exper. (mg/L) mixture after reaction (mg/L
(mg/kg)
(%)
1070.0 900.0 91170.0 210.0 1210.0 1410.0 1370.0 4300.0 49.0 16.7 220.0 3470.0 0.3 9.9 1020.0
29.4 1.9 30.5 1.8 20.8 15.2 4.0 69.6 32.6 0.1 22.9 3.2 13.6 5.8 42.7 19.1 36.6 1.4 27.6 0.1 12.3 17.7 7.5 390.8 37.5 1.7 53.5 2.8 11.9 419.9
in both shale and formation water were dissolved by 12e43% in the absence of scCO2 (Table 3b). The mean Fe concentration in formation water for shale decreased by 80%, similar to the result of sandstone. These results may be explained by a similar mechanism for sandstone. Similar increase in concentrations of Zn, Cu, was also found in Bunter Sandstone formation proposed for potential CO2 storage (Wigand et al., 2008). However, when scCO2 was present, the concentrations of chemical components of formation water and rocks could change due to interactions among scCO2, water, and rocks (Rochelle et al., 2004). The scCO2 dissolved up to 78% more Ni, As, Se, Mo, and Cd from sandstone in comparison to the raw rock (Table 4a). More V, Co, Ni, Cu, As, and Rb were dissolved from shale into formation water by scCO2 fluid (Table 4b). However, the contents of extractable Fe and Sr increased in shale but decreased in formation water; implying their adsorption from formation water or precipitation as Fe(OH)3 or SrCO3 with the extremely low solubility product (Kittaka and Morimoto, 1980). Similar to sandstone, the scCO2 fluid dissolved more Mn, Fe, Zn, Se, Sr, Mo, Cd, and Ba from shale by 0.9e36% in comparison to raw rocks (Table 4b). The experimental dissolution results in the present study have revealed that scCO2 fluid could corrode sandstone and shale and change the chemical components of formation water (Rochelle et al., 2004). In comparison with contents of extractable trace elements in
Difference
(mg/L) 4.6 1.8 13.8 14.0 0.7 9.1 21.4 95.2 4.5 26.0 35.0 504.0 352.0 0.0 9.9
(%)
2.7 142.1 0.0 0.0 1.4 9.2 55.6 80.0 0.6 600.0 5.9 184.4 15.6 269.0 76.1 398.4 3.1 221.4 25.9 25900 17.3 97.7 113.2 29.0 350.3 20606 2.8 100 410.0 97.6
sandstone containing formation water with or without scCO2 fluid (Table 5a), more V, Cr, Fe, Co, Ni, Cu, Zn, As, Rb, Sr, and Cd were desorbed or dissolved from sandstone into formation water in the presence of scCO2 fluid. In contrast, the desorption or dissolution of Mn, Se, and Ba from sandstone in the presence of scCO2 were lower than those in the absence of scCO2 (Table 5a). The concentrations of Cr, Mn, Zn, As, and Ba in formation water were 5.5e370% higher in the presence of scCO2 fluid than those in the absence of scCO2 fluid (Table 5a). As concentration in formation water increased by four folds from 27.8 mg/L in the absence of scCO2 fluid to 130 mg/L in the presence of scCO2 fluid (Table 5a). For shale, V, Cr, Co, Ni, Cu, Zn, As, Rb, and Cd tended to desorb or dissolve from shale into formation water in the presence of scCO2 fluid (Table 5b). The concentrations of Co, Ni, Zn, As, and Rb in formation water were higher in the presence of scCO2 fluid than in the absence of scCO2 fluid by 36e870%. Meanwhile, the As concentration in formation water increased from 4.5 mg/L to 43.8 mg/L in the presence of scCO2. From the differences in concentrations of trace elements in sandstone and shale before and after rockewater interactions in the absence and presence of scCO2 fluids (Tables 3a and 4a, Fig. 5a), it is found that desorpton of Mn from sandstone in the absence of scCO2 fluid was 25930 mg/kg, which is about 6% higher than its desorption from sandstone in the presence of scCO2 fluid (16390 mg/kg). Arsenic could be desorbed from sandstone by as
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Table 4 Trace element contents in (a) sandstone (Ss) and (b) shale (Sh) containing formation water under elevated temperature and pressure in the presence of scCO2 fluid (each value is an average of triplicates). (a) Sandstone Elements
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
Extracted from Ss before exper. (mg/kg)
Extracted from Ss in Ss þ gw mixture after reaction (mg/kg)
Desorption ()/Adsorption (þ) (mg/kg)
(%)
5590.0 3540.0 153120.0 4890.0 2530.0 4050.0 4020.0 9220.0 546.0 52.1 1210.0 39000.0 0.6 12.2 7530.0
4670.0 2780.0 136730.0 4150.0 2460.0 4060.0 3700.0 8180.0 969.0 56.5 1170.0 31020.0 0.9 13.4 7070.0
920.0 760.0 16390.0 740.0 70.0 10.0 320.0 1040.0 423.0 4.4 40.0 7980.0 0.3 1.2 460.0
16.5 21.5 10.7 15.1 2.8 0.3 8 11.3 77.5 8.4 3.3 20.5 50 9.8 6.1
Mean concentration in gw before exper. (mg/L)
Mean concen. in gw in Ss þ gw mixture after reaction (mg/L)
(mg/L)
(%)
1.9 1.8 15.2 69.6 0.1 3.2 5.8 19.1 1.4 0.1 17.7 390.8 1.7 2.8 419.9
5.0 2.3 36.1 13.9 0.90 12.0 11.2 125.0 130.0 5.40 37.4 2470.0 8.1 0.0 30.7
3.1 0.5 20.9 55.7 0.8 8.8 5.4 105.9 128.6 5.3 19.7 2079.2 6.4 2.8 389.2
163.2 27.8 137.5 80 800 275 93.1 554.4 9185.7 5300 111.3 532 376.5 100 92.7
Difference
(b) Shale Elements
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
Extracted from Sh before exper. (mg/kg)
Extracted from Sh in Sh þ gw mixture after reaction (mg/kg)
Desorption ()/Adsorption (þ) (mg/kg)
(%)
3640.0 2950.0 439180.0 5270.0 3710.0 6150.0 10080.0 10080.0 134.0 60.6 1790.0 46230.0 0.8 18.5 8590.0
3610.0 2560.0 594030.0 5960.0 3060.0 4660.0 8450 10170 83.4 81.8 1730.0 47820.0 1.0 25.1 10930.0
30.0 390.0 154850.0 690.0 650.0 1490.0 1630.0 90.0 50.6 21.2 60.0 1590.0 0.2 6.6 2340.0
0.82 13.2 35.3 13.1 17.5 24.2 16.2 0.9 37.8 35 3.3 3.4 25 35.7 27.2
much as 2200% more in the presence of scCO2 fluid, resulting in 9200% increase in As concentration in the formation water (Tables 3a and 4a). As for Sr, 6700 mg/kg were desorbed from sandstone in the absence of scCO2 fluid, which is 3.3% lower than 7980 mg/kg desorbed from sandstone in the presence of scCO2 fluid. More Sr (by 290%) was released into formation water in the absence of scCO2 fluid than in the presence of scCO2 fluid. Interestingly, Cd concentrations in formation water of sandstone and shale were not detectable before and after in contact with CO2. As for shale and formation water, the concentrations of Mo, Cd, and Ba changed slightly with or without scCO2 fluid. However, a much higher Zn desorption (4300 mg/kg) from shale was found in the absence of scCO2 fluid than in the presence of scCO2 fluid (90 mg/kg). More Mn was desorbed (154850 mg/kg) from shale in the presence of scCO2 fluid than in absence of the scCO2 fluid (91170 mg/kg) (Tables 3b and 4b, Fig. 5b), resulting in more Mn release into formation water by 270%. Moreover, 3470 mg/kg of Sr were desorbed from shale and released into formation water in the absence of scCO2 fluid, whereas Sr was not desorbed from shale but adsorbed about 93% from formation water in the presence of scCO2 fluid. Other elements (i.e., V, Cr, Fe, Co, Ni, Cu, As, Se, Rb, Mo, Cd, and Ba) did not have significant change before and after in contact with scCO2. For selenium in sandstone and shale, its adsorption increased by 144% (Table 5a) and 27% (Table 5b), respectively, in the presence of
Mean concentration in gw before exper. (mg/L)
Mean concen. in gw in Sh þ gw mixture after reaction (mg/L)
(mg/L)
Difference (%)
1.9 1.8 15.2 69.6 0.1 3.2 5.8 19.1 1.4 0.1 17.7 390.8 1.7 2.8 419.9
4.6 0.0 57.9 11.1 1.4 19.8 9.4 129.0 43.8 18.30 55.0 26.0 3.7 0.0 3.6
2.7 1.8 42.7 58.5 1.3 16.6 3.6 109.9 42.4 18.2 37.3 364.8 2.0 2.8 416.3
142.1 100 280.9 84 1300 518.7 62.1 575.4 3028.6 18200 210.7 93.3 117.7 100 99.1
CO2. Its adsorption was strongly pH-dependent. Selenium exists 2 mainly in anionic acids (SeO2 4 and SeO3 ) in solution (Zhang and Sparks, 1990). As pH decreased, protonation of the hydroxides or oxides resulted in positive surface charges, which enhanced the adsorption of selenium anionic species (Parida et al., 1997) and lead to a decrease of Se concentration in the formation water by 22% after reaction in the scCO2. The extractable As contents after reaction under scCO2 for sandstone and shale were all lower than those in the absence of scCO2. However, the As concentration in the formation water after reaction with scCO2 for sandstone and shale increased by 370% (Table 5a) and 870% (Table 5b), respectively, compared to those in the absence of scCO2. The drastic increase in As concentration could be attributed to (1) increased solubility of the As-containing minerals due to decreased pH resulting from the dissolution of CO2 in water (Vink, 1996); (2) changes in adsorbent as As tends to adsorb on metal (mostly iron and manganese) (oxy) (hydr)oxides, followed by clays and feldspars (Henke and HutchisonHenke, 2009), while in the presence of scCO2, dissolution of iron and manganese (oxy) (hydr)oxides and feldspar resulted in release of the adsorbed As; (3) changes in speciation of carbonate and bicarbonate preventing retention of adsorbed As on (oxy) (hydr)oxides (Appelo et al., 2002). A previous study showed that most of trace elements (e.g., Fe, Mn, Sr, Ba, and Pb) of sandstone increased in concentration during
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Table 5 Trace element contents in formation water of (a) sandstone (Ss) and (b) shale (Sh) under elevated temperature and pressure in the presence or absence of scCO2 fluid (each value is an average of triplicates). (a) Sandstone Elements Desorp. ()/Adsorp. (þ) in Ss þ gw (No CO2) (mg/ kg)
Desorp. ()/Adsorp. (þ) Difference in Ss þ gw þ CO2 (mg/ (mg/kg) (%) kg)
V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
920.0 760.0 16390 740.0 70.0 10.0 320.0 1040 423.0 4.4 40.0 7980 0.3 1.2 460.0
60.0 210.0 25930.0 660.0 300 890.0 60.0 330.0 12404 1.8 30.0 6700 0.3 1.6 1850
Mean concent. in gw in Ss þ gw (No CO2) (mg/ Mean concen. in L) Ss þ gwþ CO2 (mg/L)
860.0 1433 5.5 550.0 261.9 1.7 9540 36.8 32.9 80.0 12.1 32.6 370.0 123.3 0.9 880.0 98.9 15.0 380.0 633.3 13.2 710.0 215.1 86.8 11981 96.6 27.8 2.6 144.4 11.9 10.0 33.3 48.0 1280 19.1 3610.0 0.0 0 14.7 0.4 25 0.0 1390 75.1 29.1
5.0 2.3 36.1 13.9 0.9 12.0 11.2 125.0 130.0 5.40 37.4 2470.0 8.1 0.0 30.7
Difference (mg/L)
(%)
0.5 0.6 3.2 18.7 0.0 3.0 2.0 38.2 102.2 6.5 10.6 1140 6.6 0.0 1.6
9.1 35.3 9.7 57.4 0 20.0 15.1 44.0 367.6 54.6 22.1 31.6 44.6 0 5.5
(b) Shale Elements Desorp. ()/Adsorp. (þ) in Sh þ gw (No CO2) (mg/kg) V Cr Mn Fe Co Ni Cu Zn As Se Rb Sr Mo Cd Ba
1070 900 91170 210 1210 1410 1370 4300 49 16.7 220 3470 0.3 9.9 1020
Mean concent. in gw in Sh þ gw (No Mean concen. in CO2) (mg/L) Sh þ gwþ CO2 (mg/L)
Desorp. ()/Adsorp. (þ) in Sh þ gw þ CO2 (mg/kg)
Difference (mg/kg)
(%)
30 390 154850 690 650 1490 1630 90.0 50.6 21.2 60 1590 0.2 6.6 2340
1100 1290 63680 480.0 1860 2900 3000.0 4210 1.6 4.5 280.0 5060 0.5 3.3 1320
102.8 4.6 143.3 1.8 69.8 13.8 228.6 14.0 153.7 0.7 205.7 9.1 219 21.4 97.9 95.2 3.3 4.50 26.9 26.0 127.3 35.0 145.8 504.0 166.7 352.0 33.3 0.0 129.4 9.9
the reaction with scCO2 fluid (Wigand et al., 2008). Rocks collected from US, Canada, and Algeria showed that Cr and Pb released from sandstone reservoir and shale cap rocks exceed the MCLs by an order of magnitude in the presence of scCO2 (Karamalidis et al., 2013a). Evidences have been found for a long history of CO2 migration in fault zones and leakage to the atmosphere (Benson and Cole, 2008). This process may be enhanced by the dissolution of low permeability rocks by acidic CO2-rich fluids (Balistrieri and Chao, 1990). The interaction of the acidic CO2-rich fluids with shale could provide the trace elements essential to trapping CO2 in carbonate minerals, while the leaching of these trace elements may increase the permeability of shale leading to the escape of CO2 to the atmosphere as suggested in a field (Hovorka et al., 2006). 4.4. Mineral assemblages after high pressure simulation experiments Powder XRD analyses of bulk sandstone showed that quartz was the principal constituent of all sandstone (Ss) samples with subordinate potassium feldspar, albite, and minor muscovite and chlorite (Fig. 6). The 8.9 peak of muscovite was slightly skewed towards the low angles, possibly consisting of a smectite mixedlayer component. Microcline occurred with variable abundance and as the dominant K-feldspar in most of the sandstone samples
4.6 0.0 57.9 11.1 1.4 19.8 9.4 129.0 43.8 18.3 55.0 26.0 3.7 0.0 3.6
Difference (mg/L)
(%)
0.0 0 1.8 100 44.1 319.6 2.9 20.7 0.7 100 10.7 117.6 12.0 56.1 33.8 35.5 39.3 873.3 7.7 29.6 20.0 57.1 478.0 94.8 348.3 99.0 0.0 0 6.3 63.6
except sample Ss-gw-90 (sandstone with formation water at 90 C) in which orthoclase was the second most abundant constituent. There was a small amount of calcite and dolomite and possibly trace stilpnomelane and gypsum in sample Ss. A trace amount of calcite occurred in samples Ss-25, Ss-90, and Ss-gw-25 as well. Sample Ss-gw-90 additionally contained a very small amount of goethite. Overall, the sandstone samples can be characterized by an assemblage of quartz þ Kfeldspar þ albite þ muscovite þ chlorite ± calcite ± dolomite ± stilpnomelane ± gypsum ± goethite. The shale samples (Sh) contained quartz, muscovite, chlorite, and albite as the major phases with small variable amounts of calcite, dolomite, and microcline (Fig. 6). It should be noticed that dolomite, stilpnomelane, and gypsum diminished in the mixed solution of sandstone and scCO2 fluid after reaction. Meanwhile, dolomite disappeared in the mixed solution of shale and scCO2 fluid after the reaction. 5. Environmental implication The dissolution of CO2 in the formation water can corrode the rocks (storage unit of CO2 and its caprock) and change the formation water compositions. This may induce an increase in porosity and permeability of the storage unit of CO2 and its caprock. Our
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Fig. 6. Powder X-ray diffraction patterns of bulk sandstone (Ss-90 and Ss-gw-90) and shale (Sh-90 and Sh-gw-90) samples. Chl ¼ chlorite; Mca ¼ muscovite; Gt ¼ goethite; Qz ¼ quartz; Or ¼ orthoclase; Mc ¼ microcline; Ab ¼ albite; Cal ¼ calcite; Dol ¼ dolomite.
Fig. 5. Differences in concentrations of trace elements in (a) sandstone and (b) shale before and after rockewater interactions in the absence and presence of scCO2 fluids.
experimental results indicate that the concentration of As in formation water increased from 1.4 mg/L to 130 mg/L (Tables 4a and 5a) after in contact with scCO2. Trace elements mobilized from the CO2 storage unit into the formation water and its caprock caused by increasing temperature, pressure, and concentration of scCO2 fluid after injection of CO2 may reach shallow aquifers and contaminate their groundwater resources (Karamalidis et al., 2013a). If there is a leakage along the high angle Hsinchu fault to the north of the proposed injection site, the fault zone could serve as conveying belt to transmit the groundwater with higher dissolved trace element concentrations and release stored CO2 into the atmosphere. A detailed investigation of the changes of porosity and permeability of the CO2 storage unit and its caprock after injection of CO2 must be carried out in the future to ensure a safe sequestration of CO2 in the deep subsurface environment. And the results from this and future studies may serve as parameters for future simulation of CO2 capture and mobility. 6. Conclusion Our experimental results showed that most trace elements in the sandstone and its overlying caprock shale can be mobilized and dissolved into formation water under elevated temperature and pressure and in the presence of scCO2 fluid. Among the trace metals, V, Cr, Co, Cu, and Rb tended to dissolve from sandstone and shale into formation water under elevated temperature and
pressure and in the presence of scCO2, whereas Zn, Se, Mo, and Cd were relatively recalcitrant from desorption from sandstone and shale. They absorb from formation water onto the solid matrix. In the presence of scCO2, the releases of Mo and As from sandstone and Mn, Fe, Zn, Se, Sr, Mo, Cd, and Ba from shale in the presence of scCO2 increased by 50e78% and 0.9e36%, respectively. The enhanced dissolution of As (nearly 100 fold) and its mobility under anaerobic conditions may indicate a significant potential threat to the shallow groundwater quality in this region. Conflict of interests The authors declare that there is no conflict of interests regarding the publication of this paper. Acknowledgment The authors would like to thank the National Science Council of Taiwan for financial support of this research (Grant no. NSC1003113-E-008-002). The authors are grateful to Mr. Po-Yu Wu and Mr. Chia-Chuan Chou and Pu-Yu Wu of Exploration and Development Research Institute, China Petroleum Corporation in Miaoli, Taiwan to help us collecting formation water and to Geology Core Repository of China Petroleum Incorporation to allow us to collect sandstone and shale core samples. The authors also thank PoHsiang Chang, Chiao-Ling Wong, Cheng-Yi Ho, Chun-Jung Guo, Huan-Wen Lin, Yi-Hua Chen, and Ms. Pei-Rung Du of National Cheng Kung University for helping with the experiments and data interpretation. Appreciations were also given to Dr. Ian Craig of University of Southern Queensland for his help in manuscript
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