Figure
1.
Structural map showing the sampling locations, note that sampling wells are located in the southeastern depression (Ma et al., 2007).
| Citation: | Xiaowen Guo, Tao Luo, Tian Dong, Rui Yang, Yuanjia Han, Jizheng Yi, Sheng He, Zhiguo Shu, Hanyong Bao. Quantitative Estimation on Methane Storage Capacity of Organic-Rich Shales from the Lower Silurian Longmaxi Formation in the Eastern Sichuan Basin, China. Journal of Earth Science, 2023, 34(6): 1851-1860. doi: 10.1007/s12583-020-1394-7
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The assessment of gas storage capacity is crucial to furthering shale gas exploration and development in the eastern Sichuan Basin, China. Eleven organic-rich shale samples were selected to carry out the high pressure methane sorption, low-pressure N2/CO2 gas adsorption, and bulk and skeletal density measurements to investigate the methane storage capacity (MSC). Based on the relative content of clay, carbonates, quartz + feldspar, we grouped the 11 samples into three lithofacies: silica-rich argillaceous shale (CM-1), argillaceous/siliceous mixed shale (M-2), and clay-rich siliceous shale (S-3). The total porosity of the shale samples varies from 3.4% to 5.6%, and gas saturation ranges from 47% to 89%. The measured total gas amount ranges from 1.84 mg/g to 4.22 mg/g with the ratio of free gas to total gas amount ranging from 52.7% to 70.8%. Free gas with high content in the eastern Sichuan Basin may be the key factor controlling amount of shale gas production. The TOC content critically controls the MSC of shales, because micropore, mesopore volumes and the specific surface areas associated with organic matter provide the storage sites for the free and adsorbed gas. The methane sorption capacities of samples from different lithofacies are also affected by clay minerals and moisture content. Clay minerals can provide additional surface areas for methane sorption, and water can cause a 7.1%–42.8% loss of methane sorption capacity. The total porosity, gas-bearing porosity, water saturation, free gas and adsorbed gas number of samples from different lithofacies show subtle differences if the shale samples had similar TOC contents. Our results suggest that, in the eastern Sichuan Basin, clay-rich shale lithofacies is also prospecting targets for shale gas production.
Gas produced from shales has become a major source of fossil energy and is expected to increase worldwide (Garum et al., 2020). The gas production from the organic-rich shale largely depends on the amount of free and adsorbed gas that might be either stored in pores/fractures or attached onto the surfaces of constituting components (Ambrose et al., 2012; Jarvie et al., 2007). Quantitative estimation of shale gas storage capacity is one of the most challenging tasks because the data of measured gas content is always limited (e.g., Childers and Wu, 2020; Hao et al., 2013; Strąpoć et al., 2010; Ross and Bustin, 2009, 2008; Curtis, 2002). Methane adsorption is intrinsically determined by the micropores because the micropores contain higher surface areas than mesopores and macropores (Dubinin, 1975). The relative proportion of adsorbed gas to total gas content is up to 85% in some America shale gas production areas (Montgomery et al., 2005), therefore, the amount of adsorbed gas is a major contributor to total gas content and critical to the evaluation of shale gas resource. The amount of adsorbed gas in shales can be influenced by temperature, pressure, TOC content, organic matter property, mineralogy, moisture content, and pore systems (Zhu et al., 2018; Gasparik et al., 2014, 2012; Rexer et al., 2014; Wang et al., 2013). The TOC content is very important for shale gas content because it can provide the source for gas generation and the major sites for free and adsorbed gas storage (Wu et al., 2020; Rodriguez and Paul, 2010; Hill et al., 2007; Lane et al., 1991). Several studies have documented the linear relationships between TOC content and sorption capacities, suggesting that micropores developd in organic matter largely control adsorbed gas amount in shales (Gasparik et al., 2014; Chalmers and Bustin, 2008, 2007). Some studies argued that type Ⅲ kerogen has the largest gas generating potential, because the vitrinite has higher sorption capacity than other maceral types (Zhang et al., 2012). Clay minerals with high internal surface area can provide additional gas sorption capacity. Montmorillonite has been proven to have much higher sorption capacity than other clay minerals (Ji et al., 2012). Moisture content has a strong diminishing effect on shale gas sorption (Crosdale et al., 2008; Krooss et al., 2002). The moisture content can dramatically reduce the adsorbed gas amount of shales until reaching the "critical moisture" content (Levy et al., 1997). The amount of free gas can be calculated using measured porosity combined with gas saturation, formation temperature, and pore fluid pressure data. However, the accurate parameter of gas saturation is difficult to be gained. The shale gas desorption and logging models have been used to predict the gas content and hydrocarbon saturation in the organic-rich shale respectively (Han et al., 2019; Tathed et al., 2018). However, lost gas during drilling processes is very difficult to estimate accurately. The purposes of this paper are to (1) evaluate the gas saturation by bulk density and the skeletal density measurement of fresh organic-rich shale; (2) investigate the effects of TOC, moisture content, mineralogical compositions, and pore structure on the amount of free gas and absorbed gas; and (3) estimate the MSC of organic-rich shales from the Longmaxi Formation.
The Sichuan Basin, located in Southwest China, is one of the most important natural gas producing basin in China. It is a rhomboid-shaped basin in the Yangtze Platform caused by the activation of faults in the northeast and northwest, and is surrounded by the Longmenshan fold belt to the northwest, the Micangshan uplift to the north, the Dabashan fold belt to the northeast, the Hubei-Hunan-Guizhou fold belt to the southeast, and the Emeishan-Liangshan fold belt to the southwest (Hao et al., 2008) (Fig. 1). Both marine strata and clastic sedimentary rocks were deposited in the Sichuan Basin, reaching a maximum thickness of 12 km (Zhu et al., 2015). Marine environment deposited shales and carbonates were the dominated sediments during the period from the Precambrian to the Middle Triassic. Several uplifts were developed from the Late Ordovician to Early Silurian (Zeng et al., 2011). The marine transgressions occurred during that period and caused anoxic depositional environment, therefore, most areas in the Sichuan Basin were filled with fine-grained organic-rich shales (Huang et al., 2011; Wang et al., 2009; Su, 1999). The Wufeng and Longmaxi formations marine shales deposited from the Late Ordovician to Early Silurian with high TOC, quartz and clay contents are the important targets for shale gas exploration (Zhang et al., 2020; Guo, 2013).
Eleven fresh core samples of the Longmaxi Formation, eastern Sichuan Basin were collected from Well J1 and J2 with depth ranging from 2 288.1 to 2 606.65 m (Fig. 1). To investigate the MSC of organic-rich shales with different lithofacies, an integrated analysis of TOC contents, X-ray diffraction techniques, bulk and skeletal density measurements, and methane adsorption were conducted to investigate the shale lithofacies, total porosity, gas saturation and free gas amount, and methane sorption capacity. The N2/CO2 gas adsorption was measured on all the shale sample to characterize the structure of micropore, mesopores and macropore. The detailed analytical methods on low-pressure gas adsorption, TOC contents, and XRD analysis were described by Guo et al. (2019).
The total porosity and gas saturation were calculated by the bulk and skeletal densities of the shale samples. A split of approximately 5 g of the collected fresh samples was used for skeletal density analysis, and approximately 8–10 g (i.e., 6–8 chips) was used for bulk density measurement. The bulk density was determined by dividing the weight by volume. We measured the weight in the air and the volume by submerging the samples in water. To determine the skeletal density of moist shale, approximately 5 g of the shale samples was crushed into the size between 180 and 250 μm, and then the buoyancy was measured rapidly by a Rubotherm Gravimetric Sorption Analyzer (Rubotherm GmbH, Bochum, Germany). To avoid loss of the moisture in the shale samples, the helium gas was injected after the samples were automatically degassed under vacuum at 30 ℃. When the buoyancy measurement was completed, the methane adsorption was measured on the samples of moist shale at 30 ℃. To investigate the skeletal density of dry shale, samples were firstly degassed under vacuum conditions at an approximate temperature over 110 ℃ to remove any moisture. Then the buoyancy measurement was conducted on the dry shale samples again. The MSC of dry samples were also measured to determine the effect of moisture on gas adsorption. The detailed buoyancy and high-pressure methane adsorption experimental methods were published in Tang et al. (2016). The amount of adsorbed gas in the marine samples with present-day formation temperature and pore fluid pressure were predicted by the modified simplified local density (SLD) model (Charoensuppanimit et al., 2015) according to the methane adsorption isothermal line of moist shale at 30 ℃. The free gas amount was calculated by real gas state equation combined with porosity, gas saturation, formation temperature, and pore fluid pressure.
Most of the shale samples display the relative high content of clay or quartz. The quartz contents for the selected Longmaxi shale samples range from 30.0% to 57.8% and the clay content vary from 26.6% to 50.0% (Table 1). The feldspar content is less than 11.5%. A small quantity of carbonates, calcite and dolomite was identified, ranging from 6.0% to 11.6%. Pyrite content ranges from 3.0% to 5.0%. Three lithofacies, including CM-1, M-2, and S-3 were identified in the shales according to the relative contents of silicate quartz, feldspar, carbonates and clay. Three shale samples from S-3 lithofacies have mineralogical compositions similar to the composition of the M-2 lithofacies. The eleven shale samples from Longmaxi Formation have TOC contents ranging from 1.92 wt.% to 5.39 wt.% (Table 1). Shale samples from CM-1 and M-2 lithofacies have TOC values similar to those of the samples from S-3 lithofacies, except for two samples with relatively high TOC contents (> 4.5 wt.%). The CM-1 and M-2 samples have TOC contents in the ranges of 1.92 wt.% to 3.77 wt.%, and 2.56 wt.% to 5.39 wt.%.
| Well | No. | Depth (m) | TOC (wt.%) | Quartz (%) | Feldspar (%) | Carbonate (%) | Pyrite (%) | Clay (%) | Lithofacies |
| J1 | J1-1 | 2 319.86 | 1.92 | 33.7 | 11.5 | 6.0 | 2.9 | 43.9 | M-2 |
| J1 | J1-2 | 2 325.13 | 3.12 | 36.0 | 5.0 | 6.0 | 3.0 | 50.0 | CM-1 |
| J1 | J1-3 | 2 334.95 | 3.16 | 38.4 | 8.6 | 8.5 | 3.2 | 41.3 | M-2 |
| J1 | J1-4 | 2 338.55 | 2.77 | 40.8 | 10.4 | 11.6 | 3.5 | 33.7 | S-3 |
| J1 | J1-5 | 2 340.41 | 3.56 | 40.0 | 5.0 | 7.0 | 3.0 | 45.0 | M-2 |
| J1 | J1-6 | 2 344.69 | 3.81 | 44.0 | 5.0 | 8.0 | 3.0 | 40.0 | S-3 |
| J1 | J1-7 | 2 349.17 | 5.39 | 57.8 | 5.7 | 6.8 | 3.1 | 26.6 | S-3 |
| J1 | J1-8 | 2 352.82 | 4.78 | 44.0 | 5.0 | 6.0 | 5.0 | 40.0 | S-3 |
| J2 | J2-1 | 2 579.27 | 2.56 | 38.3 | 10.7 | 6.6 | 4.0 | 40.4 | S-3 |
| J2 | J2-2 | 2 595.74 | 3.13 | 35.0 | 6.0 | 7.0 | 5.0 | 47.0 | CM-1 |
| J2 | J2-3 | 2 598.44 | 3.77 | 39.0 | 8.0 | 10.0 | 3.0 | 40.0 | M-2 |
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The measured density of the moist and dry samples from different lithofacies indicates that all the samples have bulk density higher than 2.5 g/cm3 (Fig. 2). The skeletal density of moist and dry samples ranges of 2.60–2.68 and 2.64–2.73 g/cm3, respectively. By combining bulk density and skeletal density data, the calculated total porosity varies between 3.4% and 5.6% (Fig. 3). It is noteworthy that samples from different lithofacies display subtle differences in total porosity. Two shale samples from S-3 lithofacies have porosity values of 4.0% and 4.8%, respectively. The total porosity of shale samples from M-2 lithofacies ranges from 3.7% to 5.5%, whereas shale samples from CM-1 lithofacies have total porosity ranging from 3.4% to 5.6%. The calculated gas porosity ranges from 1.8% to 4.3%, and the calculated gas saturation varies from 47% to 89% (Fig. 3).
The measured CO2 adsorption volume at maximum relative pressure shows a wide variation between 0.8 and 2.2 cm3/g (Fig. S1). The maximum CO2 adsorbed amounts for the shale samples from S-3 lithofacies vary between 0.9 and 2.2 cm3/g. There are only two samples from the S-3 lithofacies containing lower CO2 adsorbed amounts than other shale samples, which is less than 1.2 cm3/g. Samples from the M-2 and CM-1 show the maximum CO2 adsorbed amounts in the range of 0.8–1.7 and 1.1–1.6 cm3/g. Two shale samples from the M-2 lithofacies and one shale sample from the CM-1 lithofacies have low maximum adsorbed amounts within the range of 0.8–1.1 cm3/g.
By using the classifying method of IUPAC (Thommes et al., 2015), the isotherms of N2 adsorption and desorption can be defined as Type H4 (Fig. S1). The calculated volumes and surface areas of the micropore (< 2 nm), mesopore (2–50 nm), and macropore (50–300 nm) are shown in Fig. 3. Most of the samples display similar pore volumes and surface areas distribution. The total pore volumes vary between 0.018–0.029 cm3/g. Measured volumes of mesopores vary between 0.009–0.016 cm3/g. More than 50% to 60% of the total pore volume is contributed by the mesopore. The specific surface areas of the all shale samples vary from 14.3 to 32.1 m2/g. More than 60% of total surface area is contributed from micropores surface area, which ranges from 8.9–22.9 m2/g.
The methane sorption data and calculated absolute sorption isotherms at 30 ℃ for the 11 moist and dry shale are displayed in Fig. 4. Sorption isotherms of moist and dry shales have similar shape, although the maximum absolute methane sorption mass shows wide variation. The calculated absolute methane sorption isotherms indicate that methane sorption capacity increased rapidly from 0 to 10 MPa and then remained stable from 10 to 32 MPa. The dry shale samples have higher absolute methane sorption capacity than moist samples. Predicted sorption isotherms at formation temperature suggest that methane sorption capacity is significantly lower than that of the moist shale samples at 30 ℃. The dry shale samples have maximum methane sorption capacities ranging from 1.11 mg/g to 2.84 mg/g (Fig. S2). The maximum sorption capacities of moist shales vary from 0.89 mg/g to 2.01 mg/g. Water existing in the shale samples results in a 7.1%–42.8% loss of sorption capacity. Predicted sorption capacities of the shales from different lithofacies at formation temperature (86 ℃) vary from 0.64 mg/g to 1.61 mg/g, obviously lower than those of the samples at 30 ℃.
The amounts of free gas and adsorbed methane are affected by porosity, gas saturation, formation temperature and pore fluid pressure, pore structure, TOC content, organic matter type and maturity, mineral composition, and moisture content (Zhou et al., 2019; Gasparik et al., 2014, 2012; Rexer et al., 2014; Hao et al., 2013; Wang et al., 2013; Zhang et al., 2012; Ross and Bustin, 2009). The marine shale from Longmaxi Formation in the eastern Sichuan Basin has similar thermal maturity, and organic matter is dominated by types Ⅰ and Ⅱ1 kerogen (Guo and Zhang, 2014). Overpressure was identified in the Longmaxi shale reservoir with the pressure coefficient ranging from 1.35 to 1.55 (Guo and Zhang, 2014), and the measured formation temperature from 84 to 88 ℃. By combining these data, the relative contents of free and adsorbed gas were investigated for the shale from Longmaxi Formation, eastern Sichuan Basin. The effects of TOC contents and pore structure on free gas and the effects of TOC contents, clay minerals, moisture content and pore structure on adsorbed gas was discussed in the following.
The relationship between total porosity and TOC content suggests that pore developed in organic matter is the major pore type for the shale from Longmaxi Formation (Fig. 5). Shale samples from CM-1 lithofacies have total porosity and gas-bearing porosity similar to those of the samples from M-2 and S-3 lithofacies with TOC contents less than 4.0 wt.%. Two shale samples (TOC > 4.5 wt.%) from S-3 lithofacies have higher porosity than the other samples. The gas-bearing porosity also displays a positive correlation with TOC content, suggesting that free gas storage space is dominated by organic matter pores. Therefore, TOC is a crucial factor to control pore development and gas saturation.
To determine the effect of TOC content on free gas, TOC-normalized (1.0 wt.%) porosity and gas-bearing porosity are plotted against TOC content for all samples (Fig. 6). The TOC- normalized total porosity and gas-bearing porosity of the samples range from 0.95% to 1.91%, and from 0.53% to 1.37%, respectively. Both the TOC-normalized total porosity and the gas-bearing porosity have negative correlations with TOC content. Organic matter pores may be destroyed with increasing TOC content, probably caused by mechanical compaction. The increased TOC content may cause a reduction of the overall supporting capability provided by the rigid framework formed by mineral grains (Guo et al., 2019). The weak negative relationship between TOC content and TOC-normalized gas-bearing porosity indicates that organic matter pores are important for free gas storage for all the samples regardless of shale lithofacies.
The relationships between volumes of micropore, mesopore and macropore and total porosity and gas-bearing porosity are displayed in Fig. 7. Both porosity and gas-bearing porosity display positive correlations with micropore volume and mesopore volume, indicating that the most important contributors are micropores and mesopores, which provide most of the pore space for free gas storage. Two shale samples from CM-1 lithofacies have micropore and mesopore volumes similar to those of samples from M-2 and S-3 lithofacies. There is no linear relationship between the macropore volume and total porosity or gas-bearing porosity, suggesting that macropores contribute little to total pore space and are not important storage space for free gas. Therefore, it can be deduced that micropores and mesopores developed within organic matter are the primary pore for free gas storage.
TOC was regarded as one of the most critical factors controlling the MSC in shale reservoirs (Ross and Bustin, 2009), because organic matter develops abundant nanometer-scale pores and has high surface area, which provide large amounts of sorption sites for methane molecules. The maximum methane sorption capacities of dry and moist samples at 30 ℃ display positive relationships with TOC content (Fig. 8), implying that organic-rich samples can absorb more methane and TOC content dominantly controls methane sorption capacity. Most of the water in the shale samples may fill in inorganic pores. For samples with the same lithofacies, such as M-2 and S-3, the maximum methane sorption capacities increased with increasing TOC, suggesting that TOC is more important than mineralogical composition in controlling methane sorption capacity.
Clay minerals are important constituent components of shales and can contribute to sorption capacity. Clay content for dry and moist samples from different lithofacies were plotted against TOC-normalized methane sorption capacities (Fig. S3). A weak positive relationship between clay content and TOC-normalized sorption capacity was observed for the shale samples, indicating that clay minerals contribute to the methane sorption capacity. The presence of water in shales may occupy sorption sites, and therefore reduce the sorption capacities of methane (Ross and Bustin, 2009). The TOC-normalized sorption capacities of moist samples increase with increasing clay mineral content, implying that clay can provide additional space for methane sorption.
It was widely recognized that moisture content in shale had a negative impact on methane sorption due to water occupied sorption sites. The measured moisture contents in this study range from 0.5% to 2.4%, and water saturation content ranges from 11% to 53% (Fig. 9). By comparing the measured methane sorption of dry samples with that of the moist samples, it is inferred that water in the Longmaxi shale samples could cause a 7.1%–42.8% loss of methane sorption capacity. There are no correlations between water saturation content and decreased proportion of maximum methane sorption capacity at 30 ℃ (Fig. 9). The "critical moisture" content is not identified in shale samples. The effect of moisture content in shales on methane sorption is minor for samples from different lithofacies.
The shales sorption capacity can be affected by concentrations of organic matter and clay minerals because of their high internal surface area. The linear relationship between macropore surface area and maximum methane sorption at 30 ℃ for the dry or moist samples was not observed (Fig. S4), suggesting that macropores contribute little to total surface area for adsorbed gas storage. Micropore and mesopore surface areas show a positive relationship with maximum methane sorption amount for dry samples. It indicates that most of the total surface area is contributed by micropores and mesopores. However, there are weakly positive relationships between micropore, mesopore surface areas and maximum methane sorption capacity for the moist samples. We ascribe this to the reason that some micropores and mesopores were filled with water prior to the samples being degassed and caused the methane sorption capacity decreasing.
The relationships between TOC content and free adsorbed gas suggest that TOC is the most critical factor controlling MSC, because organic matter can provide significant pore space and surface area for free and adsorbed gas storage. The contents of free and adsorbed gas of samples are displayed in Fig. 10. The free and adsorbed gas amounts increase with increasing TOC contents. The amount of adsorbed gas displays a positive correlation with TOC content. The free and total gas amounts increase rapidly with the TOC range of 1.9 wt.% to 3.2 wt.%, and then increase slowly in the TOC range of 3.2 wt.% to 5.4 wt.%. The total gas number of samples from different shale lithofacies ranges from 1.84 mg/g to 4.22 mg/g. There is no distinct difference between shale samples from the CM-1 and S-3 lithofacies. Two shale samples from the CM-1 lithofacies have total gas amount similar to that of samples from the M-2 and S-3 lithofacies. 29.2% to 47.3% of total gas amount is contributed by adsorbed gas. The free gas amount ranges from 1.37 to 2.99 mg/g, which contributes 52.7% to 70.8% of the total gas amount. Therefore, the content of free gas is higher than that of adsorbed gas. The high content free gas amount may be the critical factor for the high-yield industrial shale gas for Longmaxi Formation in the eastern Sichuan Basin.
The factors controlling methane storage capacity, including free and adsorbed gas, in the Longmaxi shales are documented by integrated techniques, including bulk and skeletal density measurements, N2/CO2 gas adsorption, and methane sorption analysis. Some conclusions can be drawn.
(1) Shale samples from CM-1, M-2, and S-3 lithofacies in the study area show total porosity ranging from 3.4% to 5.6%, and gas saturation ranging from 47% to 89%. The total pore volume is contributed by a combination of fractional pore, whereas the total surface area is largely contributed by micropore and mesopore.
(2) The free gas amount of shale samples from different lithofacies ranges from 1.37 mg/g to 2.99 mg/g, and TOC content was the key geologic factor controlling the free gas amount, because micropores and mesopores developed within organic matter can provide significant pore space for free gas storage.
(3) The methane sorption capacity is affected by several geologic factors, including TOC content, clay, moisture content, and pore structure. The maximum methane sorption capacity increases with increasing TOC and clay content. Water in the shale samples could cause a 7.1%–42.8% loss of methane sorption capacity. Micropore and mesopore surface areas provide significant sorption sites for methane sorption.
(4) The total gas amount of different shale lithofacies from the Longmaxi Formation ranges from 1.84 to 4.22 mg/g, and the proportion of free gas to total gas amount ranges from 52.7% to 70.8%, which is higher than that of adsorbed gas.
(5) TOC content is the most critical geologic factor controlling the methane storage capacity of the Longmaxi shales in the eastern Sichuan Basin. Parameters including total porosity, gas-bearing porosity, pore structure, water saturation, free gas amount, and adsorbed gas amount of shale samples from different lithofacies display subtle differences if there is no difference for the TOC contents.
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Xiaowen Guo, Tao Luo, Tian Dong, Rui Yang, Yuanjia Han, Jizheng Yi, Sheng He, Zhiguo Shu, Hanyong Bao. Quantitative Estimation on Methane Storage Capacity of Organic-Rich Shales from the Lower Silurian Longmaxi Formation in the Eastern Sichuan Basin, China. Journal of Earth Science, 2023, 34(6): 1851-1860. doi: 10.1007/s12583-020-1394-7
| Well | No. | Depth (m) | TOC (wt.%) | Quartz (%) | Feldspar (%) | Carbonate (%) | Pyrite (%) | Clay (%) | Lithofacies |
| J1 | J1-1 | 2 319.86 | 1.92 | 33.7 | 11.5 | 6.0 | 2.9 | 43.9 | M-2 |
| J1 | J1-2 | 2 325.13 | 3.12 | 36.0 | 5.0 | 6.0 | 3.0 | 50.0 | CM-1 |
| J1 | J1-3 | 2 334.95 | 3.16 | 38.4 | 8.6 | 8.5 | 3.2 | 41.3 | M-2 |
| J1 | J1-4 | 2 338.55 | 2.77 | 40.8 | 10.4 | 11.6 | 3.5 | 33.7 | S-3 |
| J1 | J1-5 | 2 340.41 | 3.56 | 40.0 | 5.0 | 7.0 | 3.0 | 45.0 | M-2 |
| J1 | J1-6 | 2 344.69 | 3.81 | 44.0 | 5.0 | 8.0 | 3.0 | 40.0 | S-3 |
| J1 | J1-7 | 2 349.17 | 5.39 | 57.8 | 5.7 | 6.8 | 3.1 | 26.6 | S-3 |
| J1 | J1-8 | 2 352.82 | 4.78 | 44.0 | 5.0 | 6.0 | 5.0 | 40.0 | S-3 |
| J2 | J2-1 | 2 579.27 | 2.56 | 38.3 | 10.7 | 6.6 | 4.0 | 40.4 | S-3 |
| J2 | J2-2 | 2 595.74 | 3.13 | 35.0 | 6.0 | 7.0 | 5.0 | 47.0 | CM-1 |
| J2 | J2-3 | 2 598.44 | 3.77 | 39.0 | 8.0 | 10.0 | 3.0 | 40.0 | M-2 |
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