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Abstract

The Manas mining area is the main enrichment region for coal seams of the Xishanyao formation on the southern margin of the Junggar Basin. This paper discusses the geologic conditions necessary for coalbed methane occurrence, gas accumulation, adsorbability, dual porosity, and permeability of coal reservoirs based on coal samples and field data from Wells MMC1 and MMC2. The endogenetic cracks are development in the major commercial seams of Manas. Pores in commercial seams are mainly micropores, and the porosity is approximately 7.10%. The results of low-temperature nitrogen adsorption showed that the BET specific surface area is 1.6276 m²/g on average. Coal reservoirs exhibit heterogeneity and low permeability despite overall good reservoir properties and interconnectivity. The Langmuir volume is large, which is favorable for coalbed methane adsorption. However, the Langmuir pressure is low, and the field coalbed gas content may reach 6.4 m³/t. Coal reservoir characteristics may be related to coal rank and maceral as well as mineral content. In general, coal reservoir properties are good in Manas, which is beneficial for coalbed methane accumulation and high yield.

Keywords

Manas coalbed methane reservoir characteristics heterogeneity

Introduction

As coal seams have been treated as source rocks in recent years, coalbed methane (CBM) exploration work has begun to be studied only recently. Due to the successful commercial production of low-rank CBM in the US and advances in CBM exploration and production in China, there has been considerable recent interest in low-rank CBM in Xinjiang (Cui et al., 2007; Liu et al., 2008; Wang et al., 2013; Wei et al., 2016; Yu et al., 2008). The Junggar Basin is an inland basin with typical CBM in low-rank coal in China (Pang et al., 2015). The first demonstration base in Xinjiang was built in the Baiyanghe mining area in the eastern part at the southern margin of the Junggar Basin, but there are no breakthroughs in the western part.

The Manas mining area is the main enrichment region of Xishanyao coal seams on the southern margin of the Junggar Basin. Although the potential of CBM may be large (Chen et al., 2010; Hu and Zhou, 1990; Jiang et al., 2010; Peng et al., 2010), related research has not yet been conducted. With little exploration conducted and no data on gas content, the first and second CBM parameter wells, MMC1 and MMC2, were deployed from 2015 to 2016 by Oil and Gas Survey, CGS. Based on coal samples and field data of MMC1 and MMC2, this paper systematically focuses on coal reservoir characteristics including coal petrology and quality, porosity, permeability, and gas-bearing properties. The objective is to present information for the further evaluation of CBM resources and potential production.

Geological conditions of CBM

Structural setting

The Manas mining area at the western part of the Zhunnan coal field (Figure 1(a)) extends from the Horgos River in the west to the Hutubi River in the east (Xiao et al., 2015). The field is 90 km long in the east–west direction and 10–20 km wide in the north–south direction; the total area is approximately 1200 km². This field is a north-inclined monoclinal structure that is referred to as the Ningjiahe-Santunhe monoclinal structural belt in the middle sections of the Huomatu anticlinal belt and Qigu faulted-fold belt. This structural belt extends in a NW–SEE direction and is bounded by the south marginal fault in the Junggar block to the south and the south marginal depression to the north. The structural setting is relatively simple (Chen et al., 2007; Wei et al., 2010; Yang et al., 2012) (Figure 1(b)). The syncline and anticline between the Manas River and Qingshuihe River, which are the major structures in the field, formed in the Yanshanian-Himalayan. The axial direction is in 80–85°, and the angle of both wings is approximately 30°, where stable coal seams occur with beneficial conditions for CBM accumulation.

Figure 1.

(a) Location map of Manas in the Junggar Basin, (b) structure outline map of Manas, and (c) column of a Jurassic stratigraphic section in the Manas; the target strata of CBM in the Xishanyao Formation strata are presented. CBM: coalbed methane.

Coalbed distribution

Subsurface formations in the field include the Carboniferous, Permian, Triassic, Jurassic, Cretaceous, Paleogene, Neogene, and Quaternary Systems from the bottom up. The Jurassic Xishanyao formation is the major coal-bearing layer and CBM source bed. Due to minimal magmatic activity since the Jurassic Period, the coal-forming period in the Zhunnan coal field, coal properties have been well preserved without breaking (An, 2012; Li et al., 2017; Tian and Yang, 2011).

The coal-accumulating center in the Xishanyao formation is around the Manas River and Daxi River. Coal seams generally extend in the east–west direction and are thick in the north and east and thin in the south and west (Figure 2). The Xishanyao formation is buried at 800–1500 m in the field. There are 13–21 commercial seams with exploitable thicknesses of 27.84–50.34 m; for seven major commercial seams, the single-layer exploitable thickness may be greater than 7 m. The number of major commercial seams decreases from west to east. Despite the small number of major commercial seams, large single-layer exploitable thickness is favorable for CBM accumulation and production, and the ^#2 and ^#5 seams are the target layers for CBM exploration and production (Figure 1(c)).

Figure 2.

Total coalbed isopach map, Manas.

Coal reservoir properties

Dual-porosity characteristics

(1) Method

Coal seams have a dual-porosity system that consists of pores and cracks. CBM accumulates in pore space, while cracks function as the pathway for fluid migration and determine reservoir permeability. Coal core samples were acquired from boreholes in the coal field and CBM parameter wells. Conventional and nondestructive unconventional testing techniques (Kara and Okandan, 2000; Karl-Heinz et al., 2008; Lv et al., 2014, 2017; Pitman et al., 2003; Tao et al., 2012; Yao et al., 2009), including SEM, mercury injection, and low-temperature nitrogen adsorption, were used to investigate pore genetic types, pore structure, and the distribution of micropores and fine pores in coal reservoirs. We used a VEGA 3 EPH SEM manufactured by Czech Tescan Company to analyze the cracks and pores in coal, a Quadrasorb 2-SI-KR/MP automatic aperture analyzer manufactured by US Quantachrome Company to analyze the pore diameter, and an AutoPore IV 9500 mercury injection apparatus manufactured by US Micromeritics Company to analyze the specific surface.

(2) Cracks

Many endogenetic cracks and a few exogenous cracks could be observed on coal core samples collected from the coal mine. Shell-like fractures were often observed. According to SEM observation, irregular net-shaped and cataclastic exogenous cracks, which may be filled with minerals, often destroy or cut through organic macerals throughout the whole sample without specific directivity. Endogenetic cracks mainly occur inside vitrinite without penetrating residual cell cavities or other maceral laminae, which are conditioned by uniform internal composition. These endogenetic cracks with distinct directivity mostly run perpendicular to bedding and are seldom filled with minerals (Figure 3). The average density of endogenetic cracks is 6–22 mm⁻¹; crack length is 0.1–3.4 mm; crack height is 0.1–11 mm; crack width is 1–45 µm. The average density of secondary cracks is 26–69 mm⁻¹; crack length is 0.1–9.0 mm; crack height is 0.1–9.2 mm; crack width is 1–45 µm. Cracks exhibit medium interconnectivity. Macro-cracks may be filled with minerals, mainly calcite; pyrite and other minerals seldom occur.

Figure 3.

SEM photos of microcracks, ^#2 coal seam, Manas. (a) Extensional cracks and (b) static pressure cracks in vitrinite. SEM: scanning electron microscope.

(3) Pores

Pores in coal seams may be of different genetic types, geometries, and sizes, and there are different standards for genetic type classification. Meng et al. (2015) and Zhang and Tang (2001) divided coal pores into four classes and nine types according to the genetic type. As indicated by SEM photos (Figure 4), the Manas mining area has various types of pores, including tissue pores and dissolved pores as well as irregular intergranular pores and friction pores, which are partially filled with minerals.

According to the standards proposed by BB Xohot (1966), coal pores were classified into four types, i.e. macropores (with a pore diameter >1000 nm), mesopores (with a pore diameter 100–1000 nm), fine pores (with a pore diameter 10–100 nm), and micropores (with a pore diameter <10 nm). According to mercury injection tests and additional data available (Table 1), the average porosity in Manas is 7.10%. Coal seams have good reservoir properties and interconnectivity, but there is some heterogeneity. Pore diameters range between 1 and 1000 nm, and micropores and fine pores with diameters less than 100 nm account for the largest percentage, followed by mesopores. The largest mercury saturation was 64.41% on average, while the efficiency of mercury withdrawal was 27.49% on average. This result indicates high porosity and interconnectivity of coal reservoirs; however, pore distribution is not uniform. Most pores are inkbottle-shaped pores, and thus, the efficiency of mercury withdrawal was low (Figure 5).

Figure 4.

SEM photos of micropores, ^#2 coal seam, Manas. (a) Intergranular pores, (b) tissue pores, (c) tissue pores and intergranular pores, (d) friction pores, (e) dissolved pores, and (f) tissue pores. SEM: scanning electron microscope.

Table 1.

Statistics of mercury injection results in Manas.

Sample	Permeability 10⁻³ µm²	Porosity (%)	Mercury saturation (%)		Max. efficiency of mercury withdrawal (%)	Displacement pressure (MPa)	Pore diameter (µm)			Percentage
Sample	Permeability 10⁻³ µm²	Porosity (%)	Max.	Residual	Max. efficiency of mercury withdrawal (%)	Displacement pressure (MPa)	Max.	Avg.	Median	Micropore + fine pore	Mesopore	Macropore
DX-1	0.187	5.11	68.300	51.547	24.529	0.282	2.610	0.352	0.023	56.67	31.61	11.72
DX-5	0.009	3.62	82.542	55.131	33.209	0.217	3.382	0.900	0.095	63.01	33.59	3.39
SG-4	0.109	8.74	52.630	39.266	25.392	4.169	0.176	0.070	0.011	58.53	28.70	12.78
SG-5	0.109	10.32	54.160	39.619	26.849	4.143	0.178	0.073	0.013	38.48	24.90	36.63

Figure 5.

Curves of mercury injection, Manas.

Figure 6.

Relationship between the pore diameter and specific surface area of typical samples from Manas.

Specific surface area is an important indicator that reflects the micropore structure and adsorbable surface of coal seams (Karl-Heinz et al., 2008). As shown in Table 2, the BET specific surface area ranges between 0.624 and 9.585 m²/g with an average of 3.407 m²/g. The BJH total pore volume is 0.00601 ml/g on average, and the average pore diameter is 5.83 nm. As shown in Figure 6, micropores with a diameter less than 10 nm contribute most to the specific surface area; this may be attributed to the greater adsorption of methane by micropores than by fine pores and mesopores (Chen et al., 2013; Zhao and Tang, 2001). Consequently, the volume of adsorbed methane linearly increases with the pore specific surface area, and adsorption saturation linearly decreases with the pore specific surface area. In other words, a large specific surface area is favorable for methane adsorption (Meng et al., 2015). This study determined that the pore conditions of coal seams in Manas are relatively good. The pore space in coal seams is mainly composed of micropores and fine pores, which is favorable for CBM adsorption.

Table 2.

Statistics of low-temperature nitrogen adsorption results in Manas.

Sample	Coal seam	Coal mine	BET specific surface area (m²/g)	BJH total pore volume (ml/g)	Average pore diameter (nm)
TF-2	No. 5	Tianfu	1.586	0.004959	10.757
SG-4	No. 5	Shawan-Hengyuan	1.507	0.003636	4.010
SG-5	No. 5	Baye	0.624	0.001841	3.219
HG-1	No. 2	Dahonggou	2.788	0.006707	4.028
KG-1	No. 2	Kuan'gou	2.988	0.005854	7.458
KG-2	No. 2	Kuan'gou	4.774	0.008611	6.880
XG-1	No. 2	Shitizi-Xigou	9.585	0.010456	4.448

Permeability

(1) Method

The permeability of coal seams is a matter of concern in CBM production because the coefficient of recovery is dependent on permeability if the gas content reaches a critical recoverable limit in situ. Accurate permeability measurements are commonly obtained through an injection/fall-off test. As there was only one well, MMC2, involved in well testing, additional information about permeability came from lab tests of coal samples from the coal mine.

(2) Analysis of experimental results

Injection/fall-off tests were conducted for several thick coal seams drilled in MMC2, ^#10, ^#5, and ^#2, which extend over a large area. The permeability of ^#2, ^#5, and ^#10 was determined to be 0.0350 × 10⁻³, 0.2686 × 10⁻³, and 1.9286 × 10⁻³ µm², respectively. The permeability of coal samples was measured to be 0.009–0.187 × 10⁻³ µm² (Table 3). In conclusion, the permeability in Manas is lower than that in Urumchi and Fukang. Permeability varies with pore size, as macropores and mesopores usually have greater permeability. As shown in Figure 7, pores with a diameter of 0.6–2.5 µm contribute most to permeability. This analysis demonstrates that the low permeability in the field may be attributed to the small pore size.

Table 3.

Statistics of coalseam permeability in Manas.

Sample	Coal seam	Coal mine	Permeability (×10⁻³ µm²)	Porosity (%)
SG-4	No. 5	Shawan-Hengyuan	0.109	8.74
SG-5	No. 5	Shawan-Baye	0.109	10.32
DX-1	No. 5	Xiaogan'gou	0.187	5.11
DX-5	No. 2	Xiaoxi'gou	0.009	3.62
KG-2	No. 2	Kuan'gou	0.035	6.07
XG-1	No. 2	Shitizi-Xigou	0.021	6.83

Figure 7.

Porosity contribution to permeability of samples SG-4 and SG-5, Manas.

Adsorption features and gas content

(1) Method

The Langmuir volume indicates the maximum adsorptive capacity of coal; in other words, adsorptive capacity increases with Langmuir volume. The Langmuir pressure indicates whether or not CBM could be easily exploited and preserved; a high Langmuir pressure is favorable for the output of adsorbed gas in the process of pressure drop, although it is unfavorable for gas preservation (Lin et al., 2016; Lu et al., 2014; Ma et al., 2011; Wang et al., 2016). An ISO-300 isothermal adsorption instrument manufactured by US Geo-Tek Energy Resources, Inc. was used for the isothermal adsorption tests.

(2) Analysis of the experimental results

The tests show that the Langmuir volume at Well MMC2 is 7.31–16.94 m³/t (dry and ash-free basis), with an average of 2.58 m³/t; the Langmuir pressure ranges from 1.54 to 4.47 MPa, with an average of 3.57 MPa (Figures 8 and 9). In the tests of the supplementary coal samples (Table 4), the Langmuir volume ranges from 6.38 to 27.68 cm³/g (dry and ash-free basis), and the Langmuir pressure ranges from 2.82 to 6.83 MPa. These similar results show an increased Langmuir volume and pressure from east to west. In general, the Langmuir volume in Manas is large and favorable for CBM adsorption; however, the Langmuir pressure is low and unfavorable for CBM production.

Figure 8.

Data map showing isothermal adsorption tests for several coal seams in Well MMC2.

Figure 9.

Isothermal adsorption curves of ^#10 and ^#5 coal seams in Well MMC2. (a) #10 coal seam (1150.00–1153.00 m) and (b) #5 coal seam (1335.20–1341.17 m).

Table 4.

Langmuir volume and pressure of isothermal adsorption tests in Manas.

Sample		MX-4	SG-4	KG-1	KG-3	XG-1	XG-3
Langmuir volume (cm³/g)	Air-dried basis	26.78	15.15	12.60	15.57	7.29	6.38
Langmuir volume (cm³/g)	Dry ash-free basis	27.68	17.43	13.46	16.98	8.49	7.06
Langmuir pressure (MPa)	Air-dried basis	6.83	4.25	3.45	4.55	3.70	2.82
Langmuir pressure (MPa)	Dry ash-free basis	6.83	4.25	3.45	4.55	3.70	2.82

According to the on-site analysis of gas content in coal seams Nos. 1–14 in the Xishanyao formation, the gas content at Well MMC1 is 1.6–6.4 m³/t, with an average of 3.92 m³/t; the methane concentration in CBM is 78.89% on average. The gas content at Well MMC2 is 0.89–5.23 m³/t, with an average of 2.32 m³/t. These data indicate a large number of coal seams in which gas accumulates pervasively and gas content increases with buried depth (Figure 10). In addition, high methane concentration indicates that potential CBM resources may be promising in the future.

Figure 10.

Relationship between CBM content and coal seam burial depth of the Xishanyao formation at Well MMC1. CBM: coalbed methane.

Figure 11.

Langmuir volume versus R_o, max.

Figure 12.

Langmuir volume versus water content (M_ad%).

Figure 13.

Pore features versus vitrinite content.

Figure 14.

Pore features versus inertinite content.

Figure 15.

Pore features versus exinite content.

Table 5.

Statistics of coal properties and macerals in Manas.

Coalseam	R_0,max (%) (avg.)	Proximate analysis (mass fraction) (%)			Maceral (volume fraction) (%)
Coalseam	R_0,max (%) (avg.)	M_ad	A_d	V_daf	Vitrinite	Inertinite	Exinite
B₁	0.65	4.06	9.64	34.97	45.30	40.70	0.30
B₂	0.73	4.36	8.93	31.50	31.40	59.30	0.50
B₃	0.63	4.34	9.67	36.00	49.60	39.20	0.40
B_4-1	0.61	4.15	13.88	39.19	76.50	10.50	0.30
B_4-2	0.74	4.77	6.44	31.99	38.20	56.50	0.40

Coal reservoir property controls

Coal metamorphism

In general, higher-rank coal adsorbs more gas (Zhang et al., 2002). The adsorptive capacity is also related to maceral, coal reservoir porosity, pore structure, and specific surface area. The study area is mainly enriched with bituminous coal of low rank, which formed in a lacustrine facies coal-forming environment. According to the latest data from each well field (Table 5), the Manas mining area is enriched with long-flame coal and noncaking coal of extremely low to low ash content, medium to high volatile content, extremely low to low sulfur content, and medium to high caloricity. The maximum vitrinite reflectance, R_0, max, ranges from 0.5 to 0.8%; R_0, max at primary minable coal seams is 0.5–0.65%, which denotes that the evolution degree is low. In addition, the main coals are low-coalification bituminous coals including long-flame coal and gas coal, which are low-rank and medium-rank coals, respectively.

As shown in Figures 11 and 12, with respect to the correlation among Langmuir volume, R_o, max and the water content, the maximum adsorption volume decreases with increased degree of metamorphism for low-rank coal. Due to the definite internal surface area for gas adsorption and greater amount of water adsorbed than methane in the coal, there is a negative correlation between water content and Langmuir volume; hence, less methane adsorbed in higher-rank coal is mainly due to higher water content.

Pore diameter is also closely dependent on coal rank and may vary regularly with coal rank. Cai et al. (2013) proposed that low-rank coal contains more micropores than higher-rank coal. According to the tests made by Lin et al. (2013) and Lv et al. (1991), micropores may adsorb more gas than other pore types in low-rank coal because of the existence of more adsorption space in micropores. In addition, Langmuir pressure is positively related to the existence of micropores, while Langmuir volume is positively related to micropores and mesopores. Pyun and Rhee (2004) reported that the specific surface area of coal has a larger impact on Langmuir volume than pore volume, which signifies that the specific surface area dominates gas adsorption potential and adsorption sites increase with specific surface area. This principle applies to high-rank coal and low-rank coal (Chen et al., 2013), and adsorptive capacity increases with total pore volume and specific surface area as well as micropore specific surface area. Micropores and fine pores comprise the greatest percentage of the coal reservoir in the study area, followed by mesopores; thus, the specific surface area and consequently Langmuir volume are large, which is favorable for gas adsorption. The test data in this study are in agreement with previously held notions.

Petrographic composition

Petrographic composition, on the basis of coal rank, has a similar impact on the micropore system. According to the maceral testing results and other data from the coal field, organic matter content exceeds 90%; the average vitrinite content is 39.28%, the average inertinite content is 55.21%, and the average exinite content is 0.93%. In total, similar vitrinite and inertinite contents occupy the large contents, and small exinite contents are favorable for gas generation. CBM is closely related with maceral compositions (Sun and Horsfield, 2005).

Zhang et al. (1997) proposed that maceral of coal is an internal factor that dominates pore distribution. Vitrinite was observed to have minimum pores with diameters ranging from 2 to 20 nm in bituminous coal with high volatile yield under a transmission electron microscope, while inertinite was observed to have the most pore types with diameters ranging from 5 to 50 nm (Harris and Yust, 1976). Inertinite was formed by wildfire (Sun et al., 2017) and cell was well preserved. Thus, inertinite was considered to have higher porosity than vitrinite, and exinite may have the smallest porosity (Mahajan and Walker, 1970). We analyzed the relationships between porosity, pore volume percentage (of micropore-fine pore, mesopore, and macropore), distribution of adsorbed pores (<100 nm, micropores and fine pores), and seepage pores (>100 nm, mesopores and macropores), and macerals. As shown in Figures 13, 14 and 15, it was concluded that vitrinite content is inversely correlated with porosity. In contrast, inertinite content is positively correlated with porosity, while exinite content is inversely correlated with porosity in general.

Based on the above study, we can conclude that vitrinite has the smallest porosity and inertinite has the most pore types, which is true for both high-rank coal and low-rank coal. The slope of the porosity-exinite content is steeper than that of the porosity-inertinite content, which implies that exinite contains fewer pores than inertinite. In addition, the volume ratio of seepage pores increases with vitrinite and exinite contents, while the volume ratio of adsorbed pores decreases with vitrinite and exinite contents. An increase in inertinite content may lead to an increased volume ratio of seepage pores.

As shown in Figure 16, there is a positive correlation between vitrinite content and Langmuir volume and a negative correlation between inertinite content and Langmuir volume at a low coal rank. In addition, exinite content is not correlated with Langmuir volume. Zhi and Liu (2013) attributed the differences in various maceral adsorptive capacities to two factors: adsorption heat (the heat released when adsorbing 1 mol gas; adsorptive capacity increases with adsorption heat) and pore specific surface area. As stated above, inertinite has a higher porosity than vitrinite. The present study revealed that vitrinite pores may have a larger specific surface area or adsorption heat than inertinite pores; hence, inertinite content is inversely correlated with Langmuir volume.

Figure 16.

Scatter diagram showing the relationships between Langmuir volume and maceral.

Mineral content

Inorganic minerals, including clay minerals and some pyrite and carbonatite, have a great impact on coal porosity despite their low content because they often fill in fusain cell lumen, intergranular pores, and microcracks (Zhong and Zhang, 1990). In the study region, inorganic minerals are mainly disseminated or thinly laminated clay minerals.

Minerals have two primary effects on porosity; first, macropores and mesopores may be filled with minerals, and thus, total pore volume will decrease, which is considered the major effect of minerals. The other effect is that minerals themselves may contain pores such as intercrystalline pores, which may slightly increase porosity (Chen et al., 2010; Zhou and Guan, 1995). As shown in Figure 17, the adsorbed pore (<100 nm) volume ratio is inversely correlated with clay mineral content, and the seepage pore volume ratio is positively correlated with relative clay mineral content. When clay mineral content becomes large, some small pores may be entirely filled, and thus the volume ratio of micropores and fine pores will decrease. Comparatively, the volume ratio of macropores and mesopores will increase. In general, the specific surface area will diminish, and consequently, porosity will also decrease.

Figure 17.

Clay mineral content versus pore volume ratio.

Conclusions

The tectonic setting in Manas is simple. The commercial seams of medium to large thickness are composed of low-rank bituminous coals (long-flame coal and gas coal). Macerals mainly include vitrinite and inertinite. The CBM geological condition is good in the study area, and coal seams have strong gas generation ability and gas accumulation conditions.

The major commercial seams have a limited number of exogenous cracks and abundant endogenetic cracks as well as tissue pores and dissolved pores. Endogenetic pores mainly consist of mesopores and fine pores. Coal seams feature large porosity, specific surface area, and pore volume; good reservoir properties and interconnectivity; moderate heterogeneity; and low permeability.

The high Langmuir volume indicates strong adsorptive capacity of CBM in Manas, while the low Langmuir pressure is unfavorable for CBM production. Gas occurs pervasively in coal seams, and methane concentration is high. The CBM content increases with burial depth of the coal seam.

The formation and development of pore systems and CBM adsorption in major commercial seams are mainly related to coal rank and coal composition. Mineral content also has an influence.

In summary, the Manas mining area may have potential for the exploitation of CBM resources; the geologic and reservoir properties are favorable for CBM enrichment and high production. In the future, CBM target optimization, exploration, and production should focus on those optimal spots in Manas, such as a moderate burial depth, simple tectonic setting, thick coal seams, high permeability, high gas saturation, and high gas content.

Footnotes

Declaration of conflicting interests

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

Funding

The author(s) disclosed receipt of the following financial support for the research,authorship,and/or publication of this article: This study was financially supported by the China Geological Survey Project of Chinese Oil and Gas Strategic Petroleum Prospects Investigation and Evaluation,No. 1211302108025-2 and No. DD20160204.

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