Investigation of Oil Potential in Saline Lacustrine Shale: A Case Study

May 17, 2017 - Gas Production Plant, Jilin Oilfield, PetroChina, Songyuan 138000, China. ∥ PetroChina Xinjiang Oilfield Company, Karamay 834000, Chi...
0 downloads 0 Views 3MB Size
Download PDF
Article pubs.acs.org/EF

Investigation of Oil Potential in Saline Lacustrine Shale: A Case Study of the Middle Permian Pingdiquan Shale (Lucaogou Equivalent) in the Junggar Basin, Northwest China Zhe Cao,†,‡ Jin Gao,†,‡,§ Guangdi Liu,*,†,‡ Jingya Zhang,†,‡ Yuhua Kong,∥ and Bin Yue§ †

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China College of Geosciences, China University of Petroleum, Beijing 102249, China § Gas Production Plant, Jilin Oilfield, PetroChina, Songyuan 138000, China ∥ PetroChina Xinjiang Oilfield Company, Karamay 834000, China ‡

ABSTRACT: The Pingdiquan shale (Lucaogou equivalent) is a typical saline lacustrine deposit in China and is one of the most significant petroleum source strata for the oil and natural gas fields in the Junggar Basin in northwestern China, which is widely acknowledged to have a large shale hydrocarbon potential. This article characterizes the Pingdiquan shale in the eastern Junggar Basin from the geochemical and geological perspectives, describes its oil potential, and compares the results with those from freshwater lacustrine shales. The Pingdiquan shale is highly heterogeneous in its mineral composition, with a big variation in each composition compared to that of freshwater lacustrine shales. The Pingdiquan shale can generally be classified into clastic shale and dolomite shale, where the clastic shale is distributed across the eastern Junggar Basin and thins from north to south, whereas the dolomite shale is developed only in the Jimusaer Sag and at the foot of the Kelameili Mountains. The Pingdiquan shale (both the clastic shale and dolomite shale) has a good petroleum potential and primarily consists of types II and III organic matter with thermal maturity ranging from early to late mature. The oil content (S1) of clastic shale and dolomite shale ranges from 0.01 to 4.96 mg/g and 0.02 to 3.23 mg/g, respectively. The oil content and oil saturation index (OSI) of the Pingdiquan shale reach a maximum value at the early to peak mature zone (Tmax of 445−450 °C). Similar trends can be observed in some typical freshwater lacustrine shales. In the Pingdiquan Formation, the dolomite shale has a higher total organic carbon content and genetic potential (S1 + S2) than the clastic shale; however, its oil content and OSI are lower than those of the clastic shale, as is its production index (PI). The results of one-dimensional basin modeling show that the dolomite shale and clastic shale have had almost the same petroleum transformation ratio values throughout geological history. However, the permeability of dolomite shale is orders of magnitude larger, which allows for more petroleum to be expelled from source rocks. In addition, positive correlations between specific surface areas and OSI and clay content are observed, indicating that high clay content also assists in maintaining the petroleum within the rocks. Therefore, less oil can be retained within dolomite shale than in clastic shale.

1. INTRODUCTION The successful shale gas production in the United States has raised interest in unconventional shale gas resources worldwide,1−4 and the oil produced from shale reservoirs in the United States has encouraged exploration of shale oil resources.5−11 Shale oil is defined as an unconventional oil that is stored in organic-rich shales or juxtaposed lithofacies.5 It has been estimated that there are potentially 6753 billion barrels of risked shale oil in-place globally and 335 billion barrels of risked, technically recoverable shale oil resources.12 China has 638 and 32 billion barrels of the risked shale oil in-place and technically recoverable shale oil, respectively, which is the third largest amount worldwide.12 In China, organic-rich shales deposited in marine, transitional marine, and lacustrine environments, with ages from the Precambrian to the Tertiary, are widespread.13−19 Lacustrine organic-rich shales are the source rocks for commercial oil fields in most of the basins in China;13 these organic-rich shales show wide variations in their depositional environments (from freshwater lacustrine to hypersaline lacustrine).13,20 Previous studies on lacustrine shales have mostly focused on freshwater deposits and have provided a deep understanding of gas capacity, © 2017 American Chemical Society

pore structure, mineral composition, and resource potential in this environment.21−26 However, there are also widespread saline lacustrine shales in China27−30 that have proven to be effective source rocks because of their relatively closed sedimentary system, which is favorable for organism accumulation and preservation.29,30 Geological and geochemical features of saline lacustrine shale are diverse compared to those of freshwater lacustrine systems. For example, evaporate rocks such as carbonates and sulfates could be formed in a saline environment ascribed to its arid and semiarid climate.28 In addition, biomarker assemblage characteristics and geochemical significance of source rocks and crude oils in saline lacustrine are also different from those in freshwater lacustrine.31 It is thus pertinent to conduct detailed studies and gain an understanding of this unconventional petroleum resource. The Junggar Basin is one of the most important petroliferous provinces in China. It has developed several hydrocarbon Received: January 27, 2017 Revised: May 11, 2017 Published: May 17, 2017 6670

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

Figure 1. (A) Location of the Junggar Basin in northwestern China. (B) Map showing the geologic setting and main structural elements of the Junggar Basin. 1, basin boundary; 2, first-order structural unit boundary; 3, secondary-order structural unit boundary; 4, study area; 5, locations of experimental samples provided by Xinjiang Oilfield; 6, locations of samples for XRD analysis and Rock-Eval pyrolysis performed in this study; 7, locations of basin modeling wells.

(the term “shale” is used for shales and mudstones in this paper).

source formations that have the potential for the formation of large unconventional oil and gas resources.11,12,15,32−35 A plethora of research on unconventional petroleum resources has been conducted. For example, studies of the tight oil resources in the Middle Permian Lucaogou Formation (also known as Pingdiquan in the eastern Junggar Basin36) in the Jimusaer Sag in the eastern Junggar Basin have already been initiated in recent years, and some amount of oil has been produced from the tight reservoirs; a bright future can be expected.37−42 Furthermore, the shale oil and gas resources in the Junggar Basin are considerable. As outlined by Stevens et al.(2013),33 the Permian and Triassic are the most favorable strata for shale gas and shale oil accumulation in the Junggar Basin. An initial assessment has shown that the Permian strata have 172 trillion (1012) cubic feet (Tcf) of risked original gas in place (OGIP) and 109 billion (109) barrels of oil (BBO) of original oil in place (OOIP). For the Triassic strata, OGIP and OOIP are 187 Tcf and 134 BBO, respectively (EIA, 2013).12 It is also likely that the Middle Permian Pingdiquan shale (also known as Xiawuerhe in the northwest basin and Lucaogou in the Jimusaer Sag and southern Junggar Basin36) along the northwestern margin, which is characterized by its thickness, moderate burial depth, high total organic carbon (TOC) content, and suitable thermal maturity, is the most significant prospective shale oil target. In the eastern Junggar Basin, the Pingdiquanshale also presents a high oil-generation potential,37,41 such that shale oil prospects can be expected. In this study, we characterize the basic geological and geochemical features of the Pingdiquan shale in the eastern Junggar Basin. In the study area, the Pingdiquan shale was developed in a saline lacustrine environment.40,42 In addition to clastic shale, dolomite shale was reported to be welldeveloped.37,38,43 Therefore, we investigate the oil content of the Pingdiquan shale in detail and discuss its oil potential before summarizing the unconventional oil potential of saline lacustrine shale. It is anticipated that this work will provide useful insights into the petroleum potential of lacustrine shale

2. GEOLOGICAL BACKGROUND The Junggar Basin is located in northwestern China and covers an area of 13 × 104 km2 (Figure 1A). It is an upper Paleozoic, Mesozoic, and Cenozoic basin superimposed at the junction of the Kazakhstan Block, the Siberia Block, and the Tarim Block.44 The Delun, Halaalate, and Zhayier Mountains form the northwest boundary of the Junggar Basin, which reaches the Yilinheibiergen Mountains in the southwest, the Qinggelidi and Kelameili Mountains in the northeast, and the Bogeda Mountains in the southeast. Tectonically, the basin can be divided into six first-order structural units and several secondorder structural units (Figure 1B). Multiple sets of source rocks are developed in the Junggar Basin ranging from Carboniferous to Neogene. Of these source rock formations, the Middle Permian Pingdiquan shale is widely distributed and has been proven to be the most important source of oil and natural gas.36,45−48 The focus of this study area is the Eastern Uplift in the Junggar Basin, which covers an area of approximately 4.4 × 104 km2 with a generalized stratigraphy consisting of Carboniferous, Permian, Jurassic, Paleogene, Neogene, and Quaternary strata (Figure 2). The Middle Permian Pingdiquan shale is well-developed in this region. 3. SAMPLES AND EXPERIMENTAL METHODS 3.1. Organic Geochemistry. A database comprising 194 core samples (including TOC content, Rock-Eval pyrolysis parameters, and vitrinite reflectance) was provided by the Xinjiang Oilfield Company of PetroChina (Appendix). It was used to help determine the geochemical characteristics of the Middle Permian Pingdiquan shale in the eastern Junggar Basin and to evaluate its petroleum potential (the locations of the sampled wells are shown in Figure 1). In addition, lithofacies of those samples have been identified by the Xinjiang Oilfield Company, PetroChina and are shown in Table A1. 6671

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

Figure 2. Stratigraphic column in the eastern Junggar Basin. In addition, 16 core samples including 13 clastic shale and 3 dolomite shale samples from 6 wells were used for the TOC, Rock-Eval, and mineral composition analysis (X-ray diffraction) in this study. The locations of the sampled wells are shown in Figure 1B. The core samples were pulverized to 100 mesh in preparation for the Rock-Eval pyrolysis and total organic carbon (TOC) content analysis. First, the TOC content of the core samples was determined using a LECO CS-400 analyzer. Rock-Eval pyrolysis was performed using a Rock-Eval II instrument. The parameters measured included free hydrocarbon (S1), which is thermally released from a sample at 300 °C; the remaining hydrocarbon generative potential (S2), which arises during progressive heating from 300 to 600 °C;49,50 and the temperature of maximum pyrolysis yield (Tmax). 3.2. X-ray Diffraction. The X-ray diffraction (XRD) technique was used to identify the mineral composition of the 16 core samples at Bangda New Technology Co., Ltd., Renqiu, China. The experimental temperature and humidity were 24 °C and 35%, respectively. Crushed samples ( 600 is identified as type I OM; HI = 300−600 is identified as type II OM; HI = 50−200 is identified as type III OM; and HI < 50 is identified as type IV OM (inert), which has no petroleum generation potential. (Adapted with permission from ref 60. Copyright 1994 American Association of Petroleum Geologists.)

the Soxhlet extract, because it is more effective at quantifying the more volatile fractions of petroleum.65 Because a previous study showed a good correlation between these two parameters,37 we thus used S1 to evaluate the oil content of the shale intervals. Figure 10A shows that the oil content of most of the dolomite shale samples increases with Tmax, reaching a maximum value of approximately 1.5 mg/g in the peak mature zone (Tmax of 445−450 °C) and tending to decrease in the late mature zone (Tmax of 450−470 °C). Similarly, the oil content of the clastic shale samples increases when in the mature zone, reaching a maximum value of approximately 5 mg/g in the early to peak mature zone (Tmax of 435−450 °C) and then decreasing with an increase in the thermal maturity. In addition, Jarvie (2012)5 proposed an oil saturation index (OSI) to evaluate the oil content of shale reservoirs that considers the organic background. If the absolute value of S1 in a sample exceeds that of TOC, it is considered to have producible oil. Figure 10B shows that OSI values also vary with Tmax and reach a maximum value in the early to peak mature zone. Some of clastic shale samples have high OSI values that are located in the zone of oil show and oil crossover. However, almost none of the dolomite shale samples present oil show. A similar trend between the oil content (S1 and OSI) and thermal maturity level (Tmax) can also be observed in typical freshwater lacustrine shales (Figure 10C,D). The Yanchang shale in the Ordos Basin and the Qingshankou shale in the Songliao Basin have a high oil content in the immature zone and reach a maximum value in the early to peak mature zone. The Lower Cretaceous shale in the Erlian Basin has a slightly lower oil content. In summary, the oil content of lacustrine shales (in both freshwater and saline environments) is more promising in the early to peak mature stage. As presented in section 4.3.1, dolomite shale has a higher TOC content and genetic potential than clastic shale. However, the oil content of dolomite shale is lower than that of the clastic shale.

Figure 7. HI versus OI plot for the Pingdiquan shale. (Adapted with permission from Van Krevelen plot in ref 61. Copyright 2012 American Association of Petroleum Geologists.)

The oil content is then measured by extract content, a ratio of the chloroform extract mass to rock sample mass, as described in Baker (1962).64 Taking the volatilization of the light components into account during the process of chloroform volatilization, Rock-Eval S1 is then applied and compared with 6677

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

Figure 8. Plots of Tmax and Ro vs depth for the Pingdiquan shale. Data points located in the black dashed line represent abnormal values that might be caused by regional uplift. In plot B, the x-axis range is adjusted to 400−500 °C to better display the main distribution of samples’ Tmax values, and eight samples with values over 500 °C are not shown. Thermal maturity zones are divided according to Peters and Cassa (1994).60

Figure 9. Ternary diagrams of mineral composition of the Pingdiquan shale and other typical lacustrine shales in China:21,25,26,62,63 (A) bulk mineral composition and (B) bulk clay composition.

shale is 20% lower than that of clastic shale. This could be one of the reasons why dolomite shale has a low oil content. The petroleum TR (or the conversion ratio) is also determined using basin modeling. To investigate the role of lithology on TR (the lithology is shown in Table 1), the Pingdiquan Formation in the model was defined as being composed of clastic shale (organic-rich shale) mixed with different contents of dolomite; using this model and the measured Ro data, the thermal maturity histories of two selected wells were reconstructed.

Therefore, the oil content of dolomite shale is not as high as was expected; the oil generated from pyrolysis (S2) determines (to a great extent) its high genetic potential and TOC content. The production index [PI; S1/(S1 + S2)] is an index used to describe the ratio of the generated petroleum to the genetic potential.59,60 Figure 11 illustrates that within the mature window, the PI of dolomite shale is 0.2 (or more) lower than that of the clastic shale at similar Tmax values, which may indicate that the conversion ratio of OM to oil for dolomite 6678

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

Figure 10. Plots of Tmax vs S1 and Tmax vs OSI used to investigate the oil potential of the Pingdiquan shale (A and B) and some typical lacustrine shales (C and D). In plots A and B, the blue line represents the trend between the S1(OSI) and Tmax of clastic shale; the black dashed line represent the trends of the dolomite shale. In plots B and D, OSI over 70 and 100 mg/g are identified as oil show and oil crossover, respectively.5 In plots C and D, pyrolysis data of typical lacustrine shales including Yanchang shale in the Ordos Basin,23,62,63,67,68 Qingshankou shale in the Songliao Basin,25,69−71 and Lower Cretaceous Shale in the Erlian Basin17 in China are involved in this study.

clastic shale, dolomite shale-1, and dolomite shale-2 decreased from −0.46, 0.17, and 1.4 lg(mD) to −5.27, −4.86, and −3.27 lg(mD), respectively. The vertical permeability of clastic shale, dolomite shale-1, and dolomite shale-2 decreased from −2.46, −1.81, and −0.53 lg(mD) to −7.27, −6.84, and −5.2 lg(mD), respectively (Figure 14A). Similar trends are found between the curves of the different lithologies in well J30 (Figure 14B). It is evident that an increasing content of dolomite can largely affect the permeability (both horizontal and vertical) at a given geological condition. The permeability of the dolomite shale was orders of magnitude greater throughout geological history, which thus enabled an easy expulsion of generated petroleum from the rocks. Therefore, less petroleum remains within the dolomite shale than within the clastic shale. In addition, an abundance of clay minerals may help maintain petroleum within rocks. Clay minerals have larger surface areas66 that enhance the petroleum sorbed in rocks. Figure 15A shows a relatively positive correlation between the specific surface area and the clay content of the lacustrine shales (light yellow zone). Shale samples with a high clay content can provide more sites for petroleum to remain. Figure 15B shows that except for a few samples, the OSI of shale samples generally increases with clay content, thereby proving that clastic shale, which is characterized by a high clay content, is capable of retaining more petroleum than dolomite shale. In this study, Rock-Eval pyrolysis results are utilized to describe geochemical characteristics including OM richness, OM type, and thermal maturity of the Pingdiquan shale in the eastern Junggar Basin. However, previous studies show that

Figure 11. Production index (PI) of the Pingdiquan shale.

The results showed a good match between the measured data and the modeled lines (Figure 12), but the results of the modeling of the two wells contradicted the PI values. However, the transformation curves for the clastic shale and dolomite shale were almost overlapped in the two modeled wells, and the gaps between the curves were less than 1% throughout their geological history, implying a similar petroleum generation rate. It was thus determined that TR is not the main reason for the low oil content and PI values of dolomite shale (Figure 13). According to the results of basin modeling, the dolomite shale and clastic shale have exhibited different expulsion conditions throughout geological history. Permeability is always related to petroleum expulsion and migration. The modeled results show the horizontal permeability of clastic shale in well D7, where 6679

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

Figure 12. Reconstructed stratigraphic burial and thermal maturity history of the Pingdiquan shale in two wells. Calculated Ro = 0.018 × Tmax − 7.16,72 with Tmax less than 420 °C or higher than 500 °C; Tmax with S2 less than 0.5 mg/g was not calculated.53

Jimusaer Sag and at the foot of the Kelameili Mountains. The Pingdiquan shale is primarily characterized by types II and III OM, with good OM richness (TOC content averaging 2.82 wt %; petroleum genetic potential averaging 10.92 mg/g), and most of the samples lie in the early to late mature window. The dolomite shale samples have a better TOC content (averages 3.28 wt %) and genetic potential (averages 17.10 mg/g) than the clastic shale (TOC averages 2.59 wt %; genetic potential averages 9.98 mg/g) Unlike the typical lacustrine shales deposited in freshwater environments, which are characterized by a homogeneous mineral

Rock-Eval pyrolysis alone might not be sufficiently precise to evaluate OM type and thermal maturity for its limitations.73,74 Therefore, we are planning to combine some other experiments to characterize the Pingdiquan shale further.

6. CONCLUSION The Pingdiquan shale is a typical saline lacustrine deposit in China, and dolomite shale is well-developed here in addition to clastic shale. The clastic shale is widely distributed across the study region with thicknesses ranging from tens to hundreds of meters. The dolomite shale is mainly well-developed in the 6680

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

Figure 13. Computed transformation ratios for D7 and J30 in the eastern Junggar Basin.

Figure 14. Computed permeability for D7 and J30 in the eastern Junggar Basin. 6681

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

Figure 15. Specific surface area (A) and OSI (B) vs clay content for lacustrine shales.22,42,62,63,68 In plot A, to obtain accurate specific surface area, samples that were measured after extraction are compiled.

orders of magnitude greater than that of clastic shale, which can lead to more petroleum being expelled from the source rocks after generation. In addition, the strong correlation between specific surface area and OSI and clay content indicates that a high clay content also helps maintain petroleum within rocks. Therefore, less oil exists within the dolomite shale than in the clastic shale. Consequently, the clastic shale is capable of retaining more oil than the dolomite shale in a saline lacustrine shale system.

composition, the Pingdiquan shale has a heterogeneous mineral composition. The oil content (S1 and OSI) of both freshwater lacustrine shale and saline lacustrine shale generally increases with thermal maturity and reaches a maximum value (oil show or oil crossover) in the early to peak mature window (Tmax of 445−450 °C). Therefore, the oil content for both freshwater lacustrine shale and saline lacustrine shale is more promising in the early to peak mature stage. The oil content of the dolomite shale is lower than that of the clastic shale. The results of the 1D basin modeling show that dolomite shale and clastic shale have almost the same petroleum transformation ratio (TR) values throughout geological history. However, the permeability of dolomite shale is

■

APPENDIX

See section 3.1 for a description of the data contained in Table A1.

Table A1. TOC, Rock-Eval Pyrolysis, and Ro for Characterizing the Pingdiquan Shale Provided by the Xinjiang Oilfield, PetroChina well name

depth (m)

C25 C25 C25 C25 C27 C27 C27 C27 C3 C4 C4 C46 C46 C46 C46 C46 C46 C46 C46 C46 C5 C5 C7 D5 D7 D7

2424 2618 2618.11 2809.12 2239.15 2423.74 2424 2425 1877.51 1995.06 2095.96 3072.59 3072.94 3074.22 3075 3208.6 3210.26 3226.04 3227.38 3228.54 1896.38 2065.76 1657.87 1446.22 2498 2498.19

sample no.

TOC (wt %)

Tmax (°C)

R99-03172 R96-10798 R2000-06526 R2000-06525 R2000-06528 R2000-06527 R96-10800 R99-03171 R99-03170 R2001-01230 R99-03169 R2003-07543 R2003-07542 R2003-07544 R2003-07545 R2003-07546 R2003-07547 R2003-07548 R2003-07549 R2003-07550 R2001-01232 R2001-01233 R2001-01235 R96-10623 R2001-01829 R2001-01856

2.23 2.14 1.96 6.25 0.84 8.08 9.64 5.83 1.66 0.94 2.30 1.60 1.32 2.69 3.80 6.91 1.41 0.88 5.50 2.22 3.37 4.77 6.34 0.61 4.71 3.48

445.00 442.00 437.00 443.00 438.00 446.00 442.00 444.00 440.00 432.00 437.00 435.00 438.00 440.00 437.00 438.00 438.00 438.00 438.00 440.00 443.00 440.00 432.00 494.00 445.00 444.00

S1 S2 S3 (mg/g) (mg/g) (mg/g) 0.39 0.14 0.12 0.94 0.08 1.35 3.05 1.57 0.16 0.18 0.36 0.61 0.31 1.40 2.71 4.04 2.84 0.45 3.81 1.98 1.04 1.97 3.23 0.04 1.23 2.40

0.61 0.81 0.38 28.41 0.08 35.19 46.48 12.00 0.36 0.56 1.28 5.01 0.38 13.60 18.80 26.21 1.78 0.50 24.01 5.73 7.61 15.74 21.85 0.16 14.72 10.71

− 0.26 − − − − 0.76 − − − − − − − − − − − − − − − − 0.13 − − 6682

S1 + S2 (mg/g) 1.00 0.95 0.50 29.35 0.16 36.54 49.53 13.57 0.52 0.74 1.64 5.62 0.69 15.00 21.51 30.25 4.62 0.95 27.82 7.71 8.65 17.71 25.08 0.20 15.95 13.11

HI OI (mg HC/g (mg HC/g TOC) TOC) 27.35 37.85 19.39 454.56 9.52 435.52 482.16 205.83 21.69 59.57 55.65 313.13 28.79 505.58 494.74 379.31 126.24 56.82 436.55 258.11 225.82 329.98 344.64 26.23 312.53 307.76

− 12.15 − − − − 7.88 − − − − − − − − − − − − − − − − 21.31 − −

OSI (mg HC/g TOC)

Ro (%)

lithology

17.49 6.54 6.12 15.04 9.52 16.71 31.64 26.93 9.64 19.15 15.65 38.13 23.48 52.04 71.32 58.47 201.42 51.14 69.27 89.19 30.86 41.30 50.95 6.56 26.11 68.97

2.23 2.14 1.96 6.25 0.84 8.08 9.64 5.83 1.66 0.94 2.30 1.60 1.32 2.69 3.80 6.91 1.41 0.88 5.50 2.22 3.37 4.77 6.34 0.61 4.71 3.48

clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale dolomite shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale dolomite shale clastic shale clastic shale clastic shale

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels Table A1. continued well name

depth (m)

D7 D7 D7 D7 D7 D7 D7 D7 D7 D7 D7 D7 D7 D7 D7 D7 D8 D8 D8 D8 D8 D8 D8 D8 D9 D9 D9 D9 DJ1 DJ1 DJ1 DJ1 DJ1 DJ1 DJ1 DJ1 DJ1 DJ2 DJ2 DJ2 DJ2 DN1 DN1 DN1 DN1 DN3 DN3 DN3 DN3 DN3 DN3 DN3 DN3 DN3 DN7 DN7 DN7 DN7 DN7

2498.94 2500.55 2642.25 2666.8 2667.82 2255 2302 2378 2416 2478 2498.99 2500.4 2510 2526 2642.55 2666.57 2650.14 2699.46 2505 2568 2648.1 2678 2710 2752 1534 1600 1648 1668 1583.61 1583.93 1584.75 1584.93 1586.11 1596 1622 1694 1818 1592.91 1593.1 1593.64 1594.6 2659.91 2672.17 2674.82 2864 2244 2258 2274 2276 2288 2356 2390 2402 2436 3480 3504 3550 3598 3620.77

sample no.

TOC (wt %)

Tmax (°C)

R2000-04952 R2000-04953 R2000-04955 R2000-04959 R2000-04960 R2011-04202 R2011-04203 R2011-04205 R2011-04206 R2011-04208 R2011-04221 R2011-04223 R2011-04209 R2011-04210 R2011-04222 R2011-04224 R2002-03088 R2002-02179 R2011-04228 R2011-04229 R2011-04249 R2011-04231 R2011-04232 R2011-04233 R2006-11048 R2005-19966 R2005-19967 R2006-11049 R2009-15062 R2009-09327 R2009-15063 R2009-09328 R2009-09329 R2011-04259 R2011-04260 R2011-04261 R2011-04264 R2010-05527 R2010-06324 R2010-05528 R2010-05529 R2000-06531 R2000-06530 R2000-06529 R96-10617 R2000-06532 R2000-06533 R2000-06534 R2000-06535 R2000-06536 R2000-06537 R2000-06539 R2000-06540 R2000-06541 2011-07542 2011-07543 2011-07544 2011-07545 2011-10792

3.63 5.98 3.10 1.87 0.72 0.94 0.77 1.57 1.36 0.91 3.20 4.03 1.61 2.52 2.37 3.05 0.87 6.44 1.17 1.20 0.73 1.32 3.17 3.58 1.45 2.00 1.81 1.83 1.04 0.98 1.19 1.04 11.52 0.24 0.77 0.15 0.89 0.34 0.32 0.40 0.83 1.91 1.55 0.29 2.39 0.28 0.23 0.35 3.49 0.31 0.46 1.39 1.87 1.10 1.35 2.86 9.42 2.44 3.52

446.00 450.00 446.00 449.00 448.00 422.00 422.00 427.00 423.00 442.00 445.00 448.00 445.00 442.00 449.00 450.00 443.00 439.00 436.00 440.00 444.00 442.00 433.00 440.00 442.00 444.00 443.00 443.00 448.00 507.00 524.00 501.00 446.00 420.00 438.00 427.00 444.00 481.00 461.00 576.00 499.00 445.00 445.00 449.00 446.00 446.00 445.00 449.00 437.00 444.00 439.00 452.00 437.00 441.00 444.00 451.00 445.00 443.00 458.00

S2 S3 S1 (mg/g) (mg/g) (mg/g) 4.96 4.73 0.84 3.22 0.32 0.09 0.08 0.46 0.26 0.18 2.40 2.59 0.71 1.07 0.55 4.11 0.16 0.72 0.64 0.54 0.06 0.40 1.42 1.06 0.03 0.04 0.06 0.05 0.02 0.02 0.03 0.02 0.12 0.08 0.11 0.12 0.08 0.02 0.01 0.02 0.03 0.10 0.09 0.02 0.20 0.03 0.02 0.01 0.03 0.02 0.02 0.06 0.05 0.05 0.61 1.06 4.26 1.09 0.71

16.85 20.00 1.91 5.37 2.07 0.31 0.25 0.85 0.51 0.91 13.08 23.78 2.96 8.11 2.15 21.38 1.37 27.19 1.00 2.45 0.80 1.28 13.68 25.50 0.67 1.26 1.22 1.66 0.28 0.20 0.28 0.11 20.95 0.04 0.26 0.10 0.36 0.07 0.04 0.07 0.15 0.43 0.52 0.02 1.02 0.04 0.03 0.01 2.77 0.02 0.06 1.05 0.44 0.42 1.53 3.60 18.64 3.18 3.65

− − − − − − − − − − − − − − − − − − 15.28 11.90 21.43 16.20 31.57 20.39 − − − − − − − − − 1.76 9.82 1.68 12.21 − − − − − − − 0.46 − − − − − − − − − − − − − − 6683

S1 + S2 (mg/g) 21.81 24.73 2.75 8.59 2.39 0.40 0.33 1.31 0.77 1.09 15.48 26.37 3.67 9.18 2.70 25.49 1.53 27.91 1.64 2.99 0.86 1.68 15.10 26.56 0.70 1.30 1.28 1.71 0.30 0.22 0.31 0.13 21.07 0.12 0.37 0.22 0.44 0.09 0.05 0.09 0.18 0.53 0.61 0.04 1.22 0.07 0.05 0.02 2.80 0.04 0.08 1.11 0.49 0.47 2.14 4.66 22.90 4.27 4.36

HI OI (mg HC/g (mg HC/g TOC) TOC) 464.19 334.45 61.61 287.17 287.50 32.98 32.47 54.14 37.50 100.00 408.75 590.07 183.85 321.83 90.72 700.98 157.47 422.20 85.47 204.17 109.59 96.97 431.55 712.29 46.21 63.00 67.40 90.71 26.92 20.41 23.53 10.58 181.86 16.67 33.77 66.67 40.45 20.59 12.50 17.50 18.07 22.51 33.55 6.90 42.68 14.29 13.04 2.86 79.37 6.45 13.04 75.54 23.53 38.18 113.33 125.87 197.88 130.33 103.69

− − − − − − − − − − − − − − − − − − 1305.98 991.67 2935.62 1227.27 995.90 569.55 − − − − − − − − − 733.33 1275.32 1120.00 1371.91 − − − − − − − 19.25 − − − − − − − − − − − − − −

OSI (mg HC/g TOC)

Ro (%)

lithology

136.64 79.10 27.10 172.19 44.44 9.57 10.39 29.30 19.12 19.78 75.00 64.27 44.10 42.46 23.21 134.75 18.39 11.18 54.70 45.00 8.22 30.30 44.79 29.61 2.07 2.00 3.31 2.73 1.92 2.04 2.52 1.92 1.04 33.33 14.29 80.00 8.99 5.88 3.13 5.00 3.61 5.24 5.81 6.90 8.37 10.71 8.70 2.86 0.86 6.45 4.35 4.32 2.67 4.55 45.19 37.06 45.22 44.67 20.17

3.63 5.98 3.10 1.87 0.72 0.94 0.77 1.57 1.36 0.91 3.20 4.03 1.61 2.52 2.37 3.05 0.87 6.44 1.17 1.20 0.73 1.32 3.17 3.58 1.45 2.00 1.81 1.83 1.04 0.98 1.19 1.04 11.52 0.24 0.77 0.15 0.89 0.34 0.32 0.40 0.83 1.91 1.55 0.29 2.39 0.28 0.23 0.35 3.49 0.31 0.46 1.39 1.87 1.10 1.35 2.86 9.42 2.44 3.52

clastic shale clastic shale clastic shale dolomite shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale dolomite shale dolomite shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels Table A1. continued well name

depth (m)

DN7 DN7 H1 H11 H11 H3 H3 H3 HB1 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HB2 HN1 HN1 HN5 HN5 HN5 HN5 HN6 HN6 HX2 S106 S106 S106 S106 S106 S106 SD1 SN2 SN4 SQ2 SQ8 SQ8 SQ8 SQ8 SQ8 SQ8 SQ8 SQ8 J7 J7 J7 J7

3621.99 3622 1541.3 1487.57 1629.99 2690.85 2935.46 3025.35 2532.12 2374 2410 2478 2524 2544 2560 2594 2622 2624.94 2652 2674 2702 2716 2728 2740 2762 2764.91 2767.84 2776 1666.18 1809.12 1937.44 1947.23 1972.3 1992.2 1955.77 2044.91 1589.2 2606.59 2607.75 2614.68 2617.42 2617.95 2621.68 1427.11 2040.85 1892.1 2597.35 2520 2520.2 2522.35 2334 2380 2413 2455 2557 2059 2062.2 2069 2069.36

sample no.

TOC (wt %)

Tmax (°C)

2011-10794 2011-09838 R98-10695 R96-10693 R90-10552 R98-10698 R98-10697 R98-10699 R2002-09034 2011-11732 2011-11733 2011-11735 2011-11736 2011-11737 2011-11738 2011-11739 2011-11740 2012-00854 2011-11741 2011-11742 2011-11743 2011-11744 2011-11745 2011-11746 2011-11747 2012-00855 2012-00856 2011-11748 R2001-01238 R2001-01239 R98-10543 R98-10544 R96-10628 R98-10545 R96-10632 R96-10633 R98-10707 R98-10847 R98-10848 R98-10849 R98-10850 R98-10851 R98-10852 R2001-01248 R2001-01245 2011-13045 R90-10519 R98-11067 R98-11101 R98-11102 R2011-04295 R2011-04297 R2011-04298 R2011-04299 R2011-04302 R96-10687 R96-10685 R94-10619 R90-11028

4.07 3.88 2.33 1.44 7.28 6.39 2.49 7.97 1.76 0.45 1.20 2.06 4.33 1.30 1.94 1.33 1.40 9.03 2.45 1.21 0.98 1.26 1.72 0.88 1.75 1.60 0.52 1.17 2.25 1.29 2.13 11.45 6.34 11.94 0.67 4.54 2.13 0.67 1.14 10.20 2.32 3.41 1.59 1.10 1.09 0.88 4.66 2.46 2.20 3.01 0.45 1.29 0.72 0.91 3.67 3.71 1.44 7.12 5.84

460.00 464.00 439.00 436.00 441.00 447.00 452.00 456.00 441.00 430.00 440.00 444.00 447.00 442.00 445.00 445.00 447.00 451.00 445.00 447.00 442.00 441.00 439.00 446.00 453.00 448.00 442.00 447.00 449.00 433.00 440.00 439.00 439.00 440.00 437.00 437.00 432.00 463.00 443.00 435.00 440.00 437.00 442.00 438.00 446.00 447.00 440.00 444.00 447.00 447.00 440.00 452.00 438.00 443.00 445.00 434.00 433.00 434.00 439.00

S2 S3 S1 (mg/g) (mg/g) (mg/g) 0.60 0.58 0.16 0.25 0.92 0.74 0.59 0.95 0.07 0.42 0.33 0.39 1.11 0.30 0.34 0.24 0.19 0.69 0.47 0.33 0.33 0.52 0.22 0.22 0.25 0.30 0.09 0.14 0.40 0.81 0.24 3.53 1.28 4.73 0.09 1.16 0.12 0.02 0.03 2.69 2.24 0.35 1.08 0.38 0.12 0.18 0.87 0.32 0.23 0.41 0.09 0.26 0.15 0.22 1.00 0.55 0.32 1.97 1.25

2.55 2.48 1.64 0.75 31.72 14.52 1.21 15.38 4.78 1.01 3.17 5.25 17.18 2.98 6.89 2.97 2.83 60.42 5.87 3.02 2.08 4.17 3.26 1.61 5.77 3.09 0.62 2.52 0.62 1.06 3.31 21.30 25.80 30.35 0.75 21.76 1.07 0.05 0.21 23.17 7.17 11.38 1.02 0.72 0.13 1.17 19.70 5.03 4.06 8.80 0.22 0.74 0.30 1.46 22.32 14.06 4.67 37.40 32.96

− − − 1.02 − − − − − − 0.29 0.47 1.52 0.27 0.60 0.27 0.25 − 0.53 0.28 0.20 0.39 0.29 0.15 0.50 0.28 0.06 0.22 − − − − 0.92 − 0.35 0.92 − − − − − − − − − − − − − − − − − − − 0.67 0.69 0.58 0.50 6684

S1 + S2 (mg/g) 3.15 3.06 1.80 1.00 32.64 15.26 1.80 16.33 4.85 1.43 3.50 5.64 18.29 3.28 7.23 3.21 3.02 61.11 6.34 3.35 2.41 4.69 3.48 1.83 6.02 3.39 0.71 2.66 1.02 1.87 3.55 24.83 27.08 35.08 0.84 22.92 1.19 0.07 0.24 25.86 9.41 11.73 2.10 1.10 0.25 1.35 20.57 5.35 4.29 9.21 0.31 1.00 0.45 1.68 23.32 14.61 4.99 39.37 34.21

HI OI (mg HC/g (mg HC/g TOC) TOC) 62.65 63.92 70.39 52.08 435.71 227.23 48.59 192.97 271.59 224.44 264.17 254.85 396.77 229.23 355.15 223.31 202.14 669.10 239.59 249.59 212.24 330.95 189.53 182.95 329.71 193.13 119.23 215.38 27.56 82.17 155.40 186.03 406.94 254.19 111.94 479.30 50.23 7.46 18.42 227.16 309.05 333.72 64.15 65.45 11.93 132.95 422.75 204.47 184.55 292.36 48.89 57.36 41.67 160.44 608.17 378.98 324.31 525.28 564.38

− − − 70.83 − − − − − − 24.17 22.82 35.10 20.77 30.93 20.30 17.86 0.00 21.63 23.14 20.41 30.95 16.86 17.05 28.57 17.50 11.54 18.80 − − − − 14.51 − 52.24 20.26 − − − − − − − − − − − − − − − − − − − 18.06 47.92 8.15 8.56

OSI (mg HC/g TOC)

Ro (%)

lithology

14.74 14.95 6.87 17.36 12.64 11.58 23.69 11.92 3.98 93.33 27.50 18.93 25.64 23.08 17.53 18.05 13.57 7.64 19.18 27.27 33.67 41.27 12.79 25.00 14.29 18.75 17.31 11.97 17.78 62.79 11.27 30.83 20.19 39.61 13.43 25.55 5.63 2.99 2.63 26.37 96.55 10.26 67.92 34.55 11.01 20.45 18.67 13.01 10.45 13.62 20.00 20.16 20.83 24.18 27.25 14.82 22.22 27.67 21.40

4.07 3.88 2.33 1.44 7.28 6.39 2.49 7.97 1.76 0.45 1.20 2.06 4.33 1.30 1.94 1.33 1.40 9.03 2.45 1.21 0.98 1.26 1.72 0.88 1.75 1.60 0.52 1.17 2.25 1.29 2.13 11.45 6.34 11.94 0.67 4.54 2.13 0.67 1.14 10.20 2.32 3.41 1.59 1.10 1.09 0.88 4.66 2.46 2.20 3.01 0.45 1.29 0.72 0.91 3.67 3.71 1.44 7.12 5.84

clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale dolomite shale clastic shale clastic shale clastic shale dolomite shale clastic shale clastic shale clastic shale clastic shale clastic shale dolomite shale dolomite shale clastic shale dolomite shale dolomite shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale dolomite shale clastic shale clastic shale dolomite shale

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels Table A1. continued well name J7 J7 J7 J7 J7 J7 J7 J22 J22 J22 J22 J22 J22 J22 J22 J22 J22 J22 J22 J22 J22 J22 J22 J34 J34 J34 J34 J34 J34 J34 J34 J34 J34 J34 J34 J34 J34 J30 J30 J30 J30 J30 J30 J30 J30 J30 J30 J30 J30 J30 J30

■

depth (m) 2160 2160.2 2161.36 2204.26 2287.22 2287.45 2288.01 2514 2524 2530 2538 2542.9 2546 2552.67 2553.27 2554.8 2556 2572 2582 2592 2610 2620 2624 3643.4 3644.54 3671.93 3672.36 3672.6 3685.79 3781.4 3781.58 3781.85 3782.89 3783.2 3783.5 3784.52 3785.24 4042.18 4045.47 4045.9 4046.64 4051.2 4053.53 4149.74 4154.65 4156.69 4054.76 4148.06 4148.92 4155.81 4042.18

sample no.

TOC (wt %)

Tmax (°C)

R94-10620 R90-11079 R90-11029 R96-10686 R99-03173 R90-11080 R90-11030 2011-11686 2011-11687 2011-11688 2011-11689 R2010-11521 2011-11690 R2010-11522 R2010-11523 R2010-11524 2011-11691 2011-11692 2011-11693 2011-11694 2011-11695 2011-11696 2011-11697 2013-02705 2013-02706 2013-02707 2013-02708 2013-02709 2013-02712 2013-02679 2013-02714 2013-02715 2013-02716 2013-02717 2013-02718 2013-02719 2013-02720 2012-14799 2012-14804 2012-14805 2012-14806 2012-14812 2012-14815 2012-14824 2012-14828 2012-14830 2012-14816 2012-14822 2012-14823 2012-14829 2012-14799

5.25 1.19 0.44 0.93 1.40 0.51 0.55 2.05 3.71 4.65 5.14 4.71 2.78 4.25 1.68 7.01 3.81 1.73 1.77 4.41 2.37 2.04 2.82 7.36 2.45 2.58 6.64 10.14 5.51 0.80 7.11 3.86 0.49 1.14 6.94 0.82 0.91 0.37 2.89 1.63 0.49 1.05 4.69 1.53 2.54 1.24 1.08 5.14 1.89 1.14 0.37

428.00 443.00 440.00 445.00 433.00 436.00 434.00 443.00 444.00 444.00 441.00 449.00 441.00 448.00 449.00 446.00 447.00 446.00 449.00 448.00 450.00 446.00 446.00 448.00 441.00 444.00 449.00 448.00 448.00 437.00 448.00 449.00 444.00 441.00 448.00 443.00 447.00 450.00 453.00 451.00 447.00 446.00 452.00 451.00 450.00 452.00 447.00 450.00 451.00 448.00 450.00

S2 S3 S1 (mg/g) (mg/g) (mg/g) 1.79 0.12 0.06 0.84 0.23 0.05 0.09 0.58 0.87 1.54 1.84 1.04 0.96 1.07 0.44 2.15 0.79 0.14 0.17 0.70 0.37 0.34 0.29 0.07 0.13 0.08 0.09 0.37 0.02 0.16 0.11 0.15 0.05 0.17 0.15 0.03 0.04 0.02 0.03 0.03 0.01 0.06 0.08 0.04 0.08 0.09 0.60 0.08 0.05 0.10 0.02

31.96 2.91 0.60 4.53 8.82 0.42 1.18 9.62 18.47 24.89 31.97 24.44 12.00 15.59 1.85 38.54 19.23 3.61 5.51 25.58 8.50 5.19 7.85 56.86 10.97 23.32 47.97 74.53 25.18 1.91 50.79 19.71 0.54 5.79 30.37 1.79 1.17 0.56 8.89 1.30 1.10 0.47 23.32 2.34 10.10 2.64 1.33 27.68 2.62 1.58 0.56

0.40 0.71 0.55 0.63 − 0.61 0.45 − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − −

AUTHOR INFORMATION

Corresponding Author

■

S1 + S2 (mg/g) 33.75 3.03 0.66 5.37 9.05 0.47 1.27 10.20 19.34 26.43 33.81 25.48 12.96 16.66 2.29 40.69 20.02 3.75 5.68 26.28 8.87 5.53 8.14 56.93 11.10 23.40 48.06 74.90 25.20 2.07 50.90 19.86 0.59 5.96 30.52 1.82 1.21 0.58 8.92 1.33 1.11 0.53 23.40 2.38 10.18 2.73 1.93 27.76 2.67 1.68 0.58

HI OI (mg HC/g (mg HC/g TOC) TOC) 608.76 244.54 136.36 487.10 630.00 82.35 214.55 469.27 497.84 535.27 621.98 518.90 431.65 366.82 110.12 549.79 504.72 208.67 311.30 580.05 358.65 254.41 278.37 772.55 447.76 903.88 722.44 735.01 456.99 238.75 714.35 510.62 110.20 507.89 437.61 218.29 128.57 151.35 307.61 79.75 224.49 44.76 497.23 152.94 397.64 212.90 123.15 538.52 138.62 138.60 151.35

7.62 59.66 125.00 67.74 − 119.61 81.82 − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − − −

OSI (mg HC/g TOC)

Ro (%)

lithology

34.10 10.08 13.64 90.32 16.43 9.80 16.36 28.29 23.45 33.12 35.80 22.08 34.53 25.18 26.19 30.67 20.73 8.09 9.60 15.87 15.61 16.67 10.28 0.95 5.31 3.10 1.36 3.65 0.36 20.00 1.55 3.89 10.20 14.91 2.16 3.66 4.40 5.41 1.04 1.84 2.04 5.71 1.71 2.61 3.15 7.26 55.56 1.56 2.65 8.77 5.41

5.25 1.19 0.44 0.93 1.40 0.51 0.55 2.05 3.71 4.65 5.14 4.71 2.78 4.25 1.68 7.01 3.81 1.73 1.77 4.41 2.37 2.04 2.82 7.36 2.45 2.58 6.64 10.14 5.51 0.80 7.11 3.86 0.49 1.14 6.94 0.82 0.91 0.37 2.89 1.63 0.49 1.05 4.69 1.53 2.54 1.24 1.08 5.14 1.89 1.14 0.37

dolomite shale dolomite shale dolomite shale clastic shale clastic shale dolomite shale dolomite shale clastic shale dolomite shale dolomite shale dolomite shale clastic shale clastic shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale clastic shale clastic shale clastic shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale dolomite shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale clastic shale dolomite shale dolomite shale dolomite shale dolomite shale clastic shale

ACKNOWLEDGMENTS

The work presented in this paper is supported by the National Natural Science Foundation of China Project “Effectiveness of micro-nano pore throat system to oil charging in tight sandstone and its control on oil accumulation” (No. 41472114). The authors appreciate Xinjiang Oilfield Company, PetroChina for providing well information, experimental data, and core samples.

*E-mail: [email protected]. ORCID

Zhe Cao: 0000-0002-8378-348X Notes

The authors declare no competing financial interest. 6685

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels

(13) Hao, F.; Zou, H. Y.; Lu, Y. C. Mechanisms of shale gas storage: Implications for shale gas exploration in China. AAPG Bull. 2013, 97, 1325−1346. (14) Ju, Y. W.; Wang, G. C.; Bu, H. L.; Li, Q. G.; Yan, Z. F. China organic-rich shale geologic features and special shale gas production issues. J. Rock Mech. Geotech. Eng. 2014, 6, 196−207. (15) Zou, C. N.; Dong, D. Z.; Wang, S. J.; Li, J. Z.; Li, X. J.; Wang, Y. M.; Li, D. H.; Cheng, K. M. Geological characteristics and resource potential of shale gas in China. Pet. Explor. Dev. 2010, 37, 641−653. (16) Ding, X. J.; Liu, G. D.; Zha, M.; Huang, Z. L.; Gao, C. H.; Lu, X. J.; Sun, M. L.; Chen, Z. L.; LiuZhuang, X. X. Relationship between total organic carbon content and sedimentation rate in ancient lacustrine sediments, a case study of Erlian basin, northern China. Journal of Geochemical Exploration. J. Geochem. Explor. 2015, 149, 22−29. (17) Ding, X. J.; liu, G. D.; Zha, M.; Huang, Z. L.; Gao, C. H.; Wang, P. G.; Qu, J. X.; Lu, X. J.; Chen, Z. L. Characteristics and origin of lacustrine source rocks in the Lower Cretaceous, Erlian Basin, northern China. Mar. Pet. Geol. 2015, 66, 939−955. (18) Ding, X. J.; Liu, G. D.; Zha, M.; Gao, C. H.; Huang, Z. L.; Qu, J. X.; Lu, X. J.; Wang, P. G.; Chen, Z. L. Geochemical characterization and depositional environment of source rocks of small fault basin in Erlian Basin, northern China. Mar. Pet. Geol. 2016, 69, 231−240. (19) Katz, B.; Lin, F. Lacustrine basin unconventional resource plays: Key differences. Mar. Pet. Geol. 2014, 56, 255−265. (20) Hackley, P. C.; Fishman, N.; Wu, T.; Baugher, G. Organic petrology and geochemistry of mudrocks from the lacustrine Lucaogou Formation, Santanghu Basin, northwest China: Application to lake basin evolution. Int. J. Coal Geol. 2016, 168, 20−34. (21) Gao, J.; Liu, G. D.; Yang, W. W.; Zhao, D. R.; Chen, W.; Liu, L. Geological and geochemical characterization of lacustrine shale, a case study of Lower Jurassic Badaowan shale in the Junggar Basin, Northwest China. J. Nat. Gas Sci. Eng. 2016, 31, 15−27. (22) Li, J.; Zhou, S. X.; Li, Y. J.; Ma, Y.; Yang, Y. N.; Li, C. C. Effect of organic matter on pore structure of mature lacustrine organic-rich shale: A case study of the Triassic Yanchang shale, Ordos Basin, China. Fuel 2016, 185, 421−431. (23) Tang, X.; Zhang, J. C.; Jin, Z. J.; Xiong, J. Y.; Lin, L. M.; Yu, Y. X.; Han, S. B. Experimental investigation of thermal maturation on shale reservoir properties from hydrous pyrolysis of Chang 7 shale, Ordos Basin. Mar. Pet. Geol. 2015, 64, 165−172. (24) Tang, X.; Zhang, J. C.; Wang, X. Z.; Yu, B. S.; Ding, W. L.; Xiong, J. Y.; Yang, Y. T.; Wang, L.; Yang, C. Shale characteristics in the southeastern Ordos Basin, China: Implications for hydrocarbon accumulation conditions and the potential of continental shales. Int. J. Coal Geol. 2014, 128−129, 32−46. (25) Wang, M.; Xue, H. T.; Tian, S. S.; Wilkins, R. W.; Wang, Z. W. Fractal characteristics of upper Cretaceous lacustrine shale from the Songliao Basin, NE China. Mar. Pet. Geol. 2015, 67, 144−153. (26) Yang, Y. T.; Liang, C.; Zhang, J. C.; Jiang, Z. X.; Tang, X. A developmental model of lacustrine shale gas genesis: a case from T3y7 shale in the Ordos Basin. J. Nat. Gas Sci. Eng. 2015, 22, 395−405. (27) Carroll, A. R.; Bohacs, K. M. Lake-type controls on petroleum source rock potential in nonmarine basins. AAPG Bull. 2001, 85, 1033−1053. (28) Jin, Q.; Zhu, G. Y. Progress in research of Deposition of oil source rocks in saline lakes and their hydrocarbon generation. Geol. J. China Univ. 2006, 4, 483−492 (in Chinese with English abstract). (29) Liu, C. L.; Li, H. H.; Zhang, X.; Zheng, S. J.; Zhang, L.; Guo, Z. Q.; Liu, J.; Tian, J. X.; Zhang, Y.; Zeng, X. Geochemical Characteristics of the Paleogene and Neogene Saline Lacustrine Source Rocks in the Western Qaidam Basin, Northwestern China. Energy Fuels 2016, 30, 4537−4549. (30) Zhu, G. Y.; Jin, Q.; Dai, J. X.; Zhang, S. C.; Zhang, L. Y.; Li, J. Investigation on the Salt Lake Source Rocks for Middle Shasi Column of Dongying Depression. Geol. J. China Univ. 2004, 10, 257−266 (in Chinese with English abstract). (31) Zhang, Z. H.; Yang, F.; Li, D. M.; Fang, Z. L. Biomarker assemblage characteristics of source rocks and associated crude oil in

We also sincerely thank reviewers for constructive comments on improving the manuscript.

■

NOMENCLATURE BBO = billion (109) barrels of oil HI = hydrogen index, S2 × 100/TOC (mg HC/g TOC) I/S = mixed illite/smectite OGIP = original gas in place OI = oxygen index, S3 × 100/TOC (mg CO2/g TOC) OM = organic matter OOIP = original oil in place OSI = oil saturation index, S1 × 100/TOC (mg HC/g TOC) PI = production index, S1/(S1 + S2) Ro = vitrinite reflectance (%) S1 = free hydrocarbons present in the rock (mg/g) S2 = petroleum generated by pyrolysis (mg/g) S1 + S2 = petroleum genetic potential (mg/g) Tmax = the temperature at peak evolution of S2 hydrocarbons (°C) Tcf = trillion (1012) cubic feet TOC = total organic carbon (wt %) TR = transformation ratio (%) XRD = X-ray diffraction

■

REFERENCES

(1) Arthur, J. D.; Langhus, B.; Alleman, D. A Review of Modern Shale Gas Development in the United States; ALL Consulting: Tulsa, OK, 2008; pp 14−17. (2) Bowker, K. A. Barnett shale gas production, Fort Worth Basin: issues and discussion. AAPG Bull. 2007, 91, 523−533. (3) Curtis, J. B. Fractured shale-gas systems. AAPG Bull. 2002, 86, 1921−1938. (4) Horsfield, B.; Schulz, H. M. Shale gas exploration and exploitation. Mar. Pet. Geol. 2012, 31, 1−2. (5) Jarvie, D. M. Shale resource systems for oil and gas: Part 2 Shale-oil resource systems. In Shale ReservoirsGiant Resources for the 21st Century; Breyer, J. A., Ed.; AAPG Memoir 97; American Association of Petroleum Geologists: Tulsa, OK, 2012; pp 89−119. (6) Li, J. J.; Wang, W. W.; Cao, Q.; Shi, Y. L.; Yan, X. T.; Tian, S. S. Impact of hydrocarbon expulsion efficiency of continental shale upon shale oil accumulations in eastern China. Mar. Pet. Geol. 2015, 59, 467−479. (7) Li, S. F.; Hu, S. Z.; Xie, X. N.; Lv, Q.; Huang, X.; Ye, J. R. Assessment of shale oil potential using a new free hydrocarbon index. Int. J. Coal Geol. 2016, 156, 74−85. (8) Misch, D.; Gross, D.; Mahlstedt, N.; Makogon, V.; Sachsenhofer, R. F. Shale gas/shale oil potential of Upper Visean Black Shales in the Dniepr-Donets Basin (Ukraine). Mar. Pet. Geol. 2016, 75, 203−219. (9) Song, J. L.; Littke, R.; Weniger, P.; Ostertag-Henning, C.; Nelskamp, S. Shale oil potential and thermal maturity of the Lower Toarcian Posidonia Shale in NW Europe. Int. J. Coal Geol. 2015, 150− 151, 127−153. (10) Xie, X. M.; Li, M. W.; Littke, R.; Huang, Z. K.; Ma, X. X.; Jiang, Q. G.; Snowdon, L. R. Petrographic and geochemical characterization of microfacies in a lacustrine shale oil system in the Dongying Sag, Jiyang Depression, Bohai Bay Basin, eastern China. Int. J. Coal Geol. 2016, 165, 49−63. (11) Zou, C. N.; Yang, Z.; Cui, J. W.; Zhu, R. K.; Hou, L. H.; Tao, S. Z.; Yuan, X. J.; Wu, S. T.; Lin, S. H.; Wang, L.; Bai, B.; Yao, J. L. Formation mechanism, geological characteristics and development strategy of nonmarine shale oil in China. Pet. Explor. Dev. 2013, 40, 15−27. (12) U.S. Energy Information Administration. Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries outside the United States; U.S. Department of Energy/EIA: Washington, DC. 2013. 6686

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels saline lake facies of Cenozoic in China. Acta Sedimentol. Sin. 1998, 16, 119−131 (in Chinese with English abstract). (32) Jia, C. Z.; Zheng, M.; Zhang, Y. F. Unconventional hydrocarbon resources in China and the prospect of exploration and development. Pet. Explor. Dev. 2012, 39, 139−146. (33) Stevens, S. H.; Moodhe, K. D.; Kuuskraa, V. A. China shale gas and shale oil resource evaluation and technical challenges. In Society of Petroleum Engineers Report 165832, Presented at the Society of Petroleum Engineers Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia. 2013. (34) Carroll, A. R. Upper Permian lacustrine organic facies evolution, southern Junggar Basin, NW China. Org. Geochem. 1998, 28, 649−667. (35) Carroll, A. R.; Bohacs, K. M. Lake-type controls on petroleum source rock potential in nonmarine basins. AAPG Bull. 2001, 85, 1033−1053. (36) Xiang, B. L.; Li, E. T.; Gao, X. W.; Wang, M.; Wang, Y.; Xu, H.; Huang, P.; Yu, S.; Liu, J. Z.; Zou, Y. R.; Pan, C. C. Petroleum generation kinetics for Permian lacustrine source rocks in the Junggar Basin, NW China. Org. Geochem. 2016, 98, 1−17. (37) Cao, Z.; Liu, G. D.; Zhan, H. B.; Kong, Y. H.; Niu, Z. C.; Zhao, D. S. Geological control factors of micro oil distribution in tight reservoirs. Mar. Pet. Geol. 2016, 77, 1193−1205. (38) Cao, Z.; Liu, G. D.; Kong, Y. H.; Wang, C. Y.; Niu, Z. C.; Zhang, J. Y.; Geng, C. B.; Shan, X.; Wei, Z. P. Lacustrine tight oil accumulation characteristics: Permian Lucaogou Formation in Jimusaer Sag, Junggar Basin. Int. J. Coal Geol. 2016, 153, 37−51. (39) Cao, Z.; Liu, G. D.; Xiang, B. L.; Wang, P.; Niu, G.; Niu, Z. C.; Li, C. Z.; Wang, C. Y. Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusaer sag, Junggar Basin. AAPG Bull. 2017, 101, 39−72. (40) Kuang, L. C.; Tang, Y.; Lei, D. W.; Chang, Q. S.; Ouyang, M.; Hou, L. H.; Liu, D. G. Formation conditions and exploration potential of tight oil in the Permian saline lacustrine dolomitic rock, Junggar Basin. NW China. Pet. Explor. Dev. 2012, 39, 700−711. (41) Qiu, Z.; Tao, H. F.; Zou, C. N.; Wang, H. Y.; Ji, H. J.; Zhou, S. X. Lithofacies and organic geochemistry of the Middle Permian Lucaogou Formation in the Jimusar Sag of the Junggar Basin, NW China. J. Pet. Sci. Eng. 2016, 140, 97−107. (42) Zhang, Y. J.; Qi, X. F.; Cheng, X. S. On the repositional environment and correlation of Pingdiquan Formation (P2) of Zhangpenggou Area in the Eastern part of Junggar Basin. Geol. J. China Univ. 1992, 3, 217−226. (43) Wang, C. Y.; Kuang, L. C.; Gao, G.; Cui, W.; Kong, Y. H.; Xiang, B. L.; Liu, G. D. Difference in hydrocarbon generation potential of the shaly source rocks in Jimusaer Sag, Permian Lucaogou Formation. Acta Sedimentol. Sin. 2014, 32, 387−390 (in Chinese with English abstract). (44) Jin, Z. J.; Cao, J.; Hu, W. X.; Zhang, Y. J.; Yao, S. P.; Wang, X. L.; Zhang, Y. Q.; Tang, Y.; Shi, X. P. Episodic petroleum fluid migration in fault zones of the northwestern Junggar Basin (northwest China): evidence from hydrocarbon-bearing zoned calcite cement. AAPG Bull. 2008, 92, 1225−1243. (45) Cao, J.; Wang, X. L.; Sun, P. A.; Zhang, Y. Q.; Tang, Y.; Xiang, B. L.; Lan, W. F.; Wu, M. Geochemistry and origins of natural gases in the central Junggar Basin, northwest China. Org. Geochem. 2012, 53, 166−176. (46) Chen, J. P.; Liang, D. G.; Wang, X. L.; Zhong, N. N.; Song, F. Q.; Deng, C. P.; Shi, X. P.; Jin, T.; Xiang, S. Z. Mixed oils derived from multiple source rocks in the Cainan oilfield, Junggar Basin, Northwest China. Part I: genetic potential of source rocks, features of biomarkers and oil sources of typical crude oils. Org. Geochem. 2003, 34, 889−909. (47) Xiang, B. L.; Zhou, N.; Ma, W. Y.; Wu, M.; Cao, J. Multiplestage migration and accumulation of Permian lacustrine mixed oils in the central Junggar Basin (NW China). Mar. Pet. Geol. 2015, 59, 187− 201. (48) Yu, S.; Wang, X. L.; Xiang, B. L.; Liao, J. D.; Wang, J.; Li, E. T.; Yan, Y. H.; Cai, Y. L.; Zou, Y. R.; Pan, C. C. Organic geochemistry of Carboniferous source rocks and their generated oils from the Eastern Junggar Basin, NW China. Org. Geochem. 2014, 77, 72−88.

(49) Espitalié, J.; Laporte, L. J.; Madec, M.; Marquis, F.; Leplat, P. J.; Boutefeu, A. Méthode rapide de caractérisation des roches méres de leur potential petrolier et de leur degréd’ évolution. Rev. Inst. Fr. Pet. 1977, 32, 23−42. (50) Tissot, B. P.; Welte, D. H. Petroleum Formation and Occurrence; Springer-Verlag: New York, 1984; pp 699. (51) Ufer, K.; Stanjek, H.; Roth, G.; Dohrmann, R.; Kleeberg, R.; Kaufhold, S. Quantitative phase analysis of bentonites by the Rietveld method. Clays Clay Miner. 2008, 56, 272−282. (52) Hakimi, M. H.; Abdullah, W. H. Thermal maturity history and petroleum generation modeling for the Upper Jurassic Madbi source rocks in the Marib-Shabowah Basin, western Yemen. Mar. Pet. Geol. 2015, 59, 202−216. (53) He, M.; Graham, S.; Scheirer, A. H.; Peters, K. E. A basin modeling and organic geochemistry study in the Vallecitos syncline, San Joaquin Basin, California. Mar. Pet. Geol. 2014, 49, 15−34. (54) Kuhn, P. P.; di Primio, R.; Hill, R.; Lawrence, J. R.; Horsfield, B. Three-dimensional modeling study of the low-permeability petroleum system of the Bakken Formation. AAPG Bull. 2012, 96, 1867−1897. (55) Littke, R.; Buker, C.; Luckge, A.; Sachsenhofer, R. F.; Welte, D. H. A new evaluation of palaeo-heat flows and eroded thicknesses for the Carboniferous Ruhr basin, western Germany. Int. J. Coal Geol. 1994, 26, 155−183. (56) Ondrak, R.; Gaedicke, C.; Horsfield, B. Combining 2D-basin and structural modeling to constrain heat transport along the Muroto Transect, Nankai Trough, Japan. Mar. Pet. Geol. 2009, 26, 580−589. (57) Fang, S. H.; Xu, H. M.; Song, Y.; Li, J. M.; Liu, L. J.; Zhang, J. Characteristics and evolution of the composite petroleum system in Jimusaer Depression, Eastern Junggar Basin. Acta Geosci. Sin. 2005, 26, 259−264 (in Chinese with English abstract). (58) Qiu, N. S.; Yang, H. B.; Wang, X. L. Tectono-thermal evolution in the Junggar Basin. Chin. J. Geol. 2002, 37, 423−429. (59) Tan, J. Q.; Horsfield, B.; Fink, R.; Krooss, B.; Schulz, H. M.; Rybacki, E.; Zhang, J. C.; Boreham, C. J.; Van Graas, G.; Tocher, B. A. Shale gas potential of the major marine shale formations in the Upper Yangtze Platform, South China, Part III: Mineralogical, lithofacial, petrophysical, and rock mechanical properties. Energy Fuels 2014, 28, 2322−2342. (60) Peters, K. E.; Cassa, M. R. Applied Source Rock Geochemistry. In The Petroleum System-from Source to Trap; Magoon, L. B., Dow, W. G., Eds.; AAPG Memoir; American Association of Petroleum Geologists: Tulsa, OK, 1994; Vol. 60, pp 93−120. (61) Hackley, P. C. Geological and geochemical characterization of the Lower Cretaceous Pearsall Formation, Maverick Basin, south Texas: A future shale gas resource? AAPG Bull. 2012, 96, 1449−1482. (62) Guo, H. J.; Jia, W. L.; Peng, P. A.; Lei, Y. H.; Luo, X. R.; Cheng, M.; Wang, X. Z.; Zhang, L. X.; Jiang, C. F. The composition and its impact on the methane sorption of lacustrine shales from the Upper Triassic Yanchang Formation, Ordos Basin. Mar. Pet. Geol. 2014, 57, 509−520. (63) Ji, W. M.; Song, Y.; Jiang, Z. X.; Wang, X. Z.; Bai, Y. Q.; Xing, J. Y. Geological controls and estimation algorithms of lacustrine shale gas adsorption capacity: a case study of the Triassic strata in the southeastern Ordos Basin, China. Int. J. Coal Geol. 2014, 134-135, 61− 73. (64) Baker, D. R. Organic geochemistry of Cherokee Group in southeastern Kansas and northeastern Oklahoma. AAPG Bull. 1962, 46, 1621−1642. (65) Jarvie, D. M.; Baker, D. R. Application of the Rock-Eval III oil show analyzer to the study of gaseous hydrocarbons in an Oklahoma gas well. Presented at 187th ACS National Meeting, St. Louis, Missouri, April 8−13, 1984. (66) Passey, Q. R.; Bohacs, K.; Esch, W. L.; Klimentidis, R.; Sinha, S. From oil-prone source rock to gas-producing shale reservoir Geologic and petrophysical characterization of unconventional shale gas reservoirs. In International Oil and Gas Conference and Exhibition in China. Society of Petroleum Engineers, 2010; DOI: 10.2118/ 131350-MS. 6687

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688

Article

Energy & Fuels (67) Han, S. B.; Horsfield, B.; Zhang, J. C.; Chen, Q.; Mahlstedt, N.; di Primio, R.; Xiao, G. L. Hydrocarbon Generation Kinetics of Lacustrine Yanchang Shale in Southeast Ordos Basin, North China. Energy Fuels 2014, 28, 5632−5639. (68) Liu, G. H.; Huang, Z. L.; Jiang, Z. X.; Chen, J. F.; Chen, F. R.; Xing, J. Y. Gas adsorption capacity calculation limitation due to methane adsorption in low thermal maturity shale: A case study from the Yanchang Formation, Ordos Basin. J. Nat. Gas Sci. Eng. 2016, 30, 106−118. (69) Dong, T.; He, S.; Yin, S. Y.; Wang, D. X.; Hou, Y. G.; Guo, J. G. Geochemical characterization of source rocks and crude oils in the Upper Cretaceous Qingshankou Formation, Changling Sag, southern Songliao Basin. Mar. Pet. Geol. 2015, 64, 173−188. (70) Feng, Z. H.; Fang, W.; Li, Z. G.; Wang, X.; Huo, Q. L.; Huang, C. Y.; Zhang, J. H.; Zeng, H. S. Depositional environment of terrestrial petroleum source rocks and geochemical indicators in the Songliao Basin. Sci. China: Earth Sci. 2011, 54, 1304−1317 (in Chinese). (71) Xu, J. J.; Liu, Z. J.; Bechtel, A.; Meng, Q. T.; Sun, P. C.; Jia, J. L.; Cheng, L. J.; Song, Y. Basin evolution and oil shale deposition during Upper Cretaceous in the Songliao Basin (NE China): Implications from sequence stratigraphy and geochemistry. Int. J. Coal Geol. 2015, 149, 9−23. (72) Jarvie, D. M.; Lundell, L. L. Amount, type and thermal transformation of organic matter in the Miocene Monterey Formation. In The Monterey FormationFrom Rocks to Molecules; Isaacs, C. M., Rullkötter, J., Eds.; Columbia University Press: New York, 2001; pp 268−295. (73) Katz, B. Limitations of ‘Rock-Eval’ pyrolysis for typing organic matter. Org. Geochem. 1983, 4, 195−199. (74) Hackley, P. C.; Cardott, B. J. Application of organic petrography in North American shale petroleum systems: A review. Int. J. Coal Geol. 2016, 163, 8−51.

6688

DOI: 10.1021/acs.energyfuels.7b00294 Energy Fuels 2017, 31, 6670−6688