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Characteristics and origin of in-situ gas desorption of the Cambrian Shuijingtuo Formation shale gas reservoir in the Sichuan Basin, China
Fuel 187 (2017) 285–295
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Full Length Article
Characteristics and origin of in-situ gas desorption of the Cambrian Shuijingtuo Formation shale gas reservoir in the Sichuan Basin, China Xianglu Tang a,b, Zhenxue Jiang a,⇑, Shu Jiang b,⇑, Lijun Cheng c, Ye Zhang c a
State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China Energy and Geoscience Institute, University of Utah, Salt Lake City, UT 84108, USA c Chongqing Institute of Geology and Mineral Resources, Chongqing 400042, China b
h i g h l i g h t s
g r a p h i c a l a b s t r a c t
In-situ desorbed gas content and
desorption rate are different at two stages. In-situ shale gas is mainly desorbed within 300 min. The Shuijingtuo Formation shale is mainly sorbed gas. In-situ gas desorption is controlled by nano-pores and methane adsorption capacity.
a r t i c l e
i n f o
Article history: Received 20 July 2016 Received in revised form 8 September 2016 Accepted 25 September 2016 Available online 28 September 2016 Keywords: In-situ gas desorption Occurrence stage Methane adsorption ability Pore size distribution Shale gas reservoir
a b s t r a c t In-situ shale gas extraction provides direct evidence in response to gas-bearing evaluations and productivity predictions regarding shale gas reservoirs. The desorption characteristics and origin of in-situ shale gas extraction in the lower Cambrian Shuijingtuo Formation of the Sichuan Basin are studied via in-situ gas desorption tests. Tests are conducted at both reservoir (35 °C) and high temperatures (90 °C). The results indicate that most in-situ shale gas is quickly desorbed within 300 min at both the reservoir temperature desorption stage and the high temperature desorption stage. In both instances, the in-situ gas desorption rates decrease rapidly over time. In addition, the desorbed gas content and desorption rate at the reservoir temperature desorption stage are both clearly lower than the equivalent measures at the high temperature desorption stage. The in-situ desorbed gas from the reservoir temperature desorption stage is mainly free gas; the in-situ desorbed gas from the high temperature desorption stage, on the other hand, is mainly sorbed gas, which is the dominant form in the in-situ shale gas. The percentage of in-situ desorbed gas at these two stages is mainly controlled by gas adsorption, pore volume, and specific surface area. The desorption rate of in-situ shale gas is likely controlled primarily by average pore size and methane adsorption. Ó 2016 Elsevier Ltd. All rights reserved.
Abbreviations: TOC, total organic carbon, %; Ro, equivalent vitrinite reflectance, %; STP, standard conditions for temperature and pressure, 0 °C, and 101.325 kPa; Q1, in-situ desorbed gas content at the reservoir temperature (35 °C) desorption stage, m3/t; Q2, in-situ desorbed gas content at the high temperature (90 °C) desorption stage, m3/t; Q3, maximum adsorbed methane content, m3/t; Q4, adsorbed methane content at 35 °C, atmospheric condition, m3/t; P1, pore volume percent of pore size larger than 11 nm, %; P2, pore volume percent of pore size smaller than 11 nm, %; R1m, mean desorption rate at the reservoir temperature desorption stage, m3/t/min; R1h, highest desorption rate at the reservoir temperature desorption stage, m3/t/min; R2m, mean desorption rate at the high temperature desorption stage, m3/t/min; R2h, highest desorption rate at the high temperature desorption stage, m3/t/min. ⇑ Corresponding authors at: No. 18 Fuxue Road, Changping, Beijing, China (Z. Jiang). 423 Wakara Way, Suite 300, Salt Lake City, UT, USA (S. Jiang). E-mail addresses: [email protected] (Z. Jiang), [email protected] (S. Jiang). http://dx.doi.org/10.1016/j.fuel.2016.09.072 0016-2361/Ó 2016 Elsevier Ltd. All rights reserved.
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1. Introduction
2. Material and methods
At present, the production of shale gas accounts for a large proportion of unconventional oil and gas in North America. A variety of studies have been conducted to develop and utilize this relatively clean potential fuel source [1–3]. Evaluation of shale gas content will serve as the groundwork for resource potential evaluation, commercial development, and productivity predictions [4,5]. As a result of the gas occurrence state in the shale, shale gas can be divided, for the most part, into free gas and sorbed gas, where sorbed gas is composed of adsorbed gas and absorbed gas [6]. Free gas is stored primarily in shale pores, while the sorbed gas tends to be adsorbed on the surface of shale organic matter and clay mineral [7]. The ratio of free gas to sorbed gas, however, cannot be obtained directly, as they would interconvert in the shale [7,8]. Using the in-situ gas desorption test, though, the shale gas can be divided into lost gas, desorbed gas, and residual gas [9,10]. The lost gas is the gas that is lost before the core is loaded into the desorption canister [11]. The desorbed gas is the gas desorbed from the shale while core is loaded into in the desorption canister [12]. The residual gas is the gas remaining in the shale core after the in-situ gas desorption test [13]. The in-situ shale gas content is a more reliable measure and can be used for analysis geochemical characteristics of shale [10]. The free and sorbed gas in the in-situ shale gas reservoir exist in dynamic equilibrium [14]. When the shale sample is put into the desorption canister underground, the confining pressure is reduced, which leads to the quick release of free gas from the shale sample through interconnected pores. With the release of free gas, the equilibrium of the gas in the free stage and sorbed state is broken, and then the sorbed gas starts to convert into free gas. This continues until gas in the free and sorbed states reach a new equilibrium [15]. When the shale sample is heated to a high temperature, the adsorption capacity of shale gas is greatly reduced; more sorbed gas begins to convert into free gas [16]. Because the equilibrium of gas in the free stage and sorbed state is, again, broken, the free gas content in the shale begins to increase, leading to excess pressure in the shale. The free gas then releases until the gas in free and sorbed states, again, reach equilibrium. The in-situ gas desorption test was first used to measure coalbed methane content in the 1970s [17,18]. With the development of shale gas in recent years, the in-situ gas desorption test has been used for measuring shale gas content [27]. It is necessary that the in-situ gas desorption test be conducted immediately after that the shale core is retrieved from the wellbore; otherwise, the abundant gas would be lost [19]. In addition, the field environment is generally tough, and the researchers have limited to access the drilling process. Because of this, knowledge of in-situ desorbed gas of shale is also limited. Still, it is meaningful. At present, the in-situ gas desorption test of shale gas is rare, and studies of the characteristics of in-situ desorbed gas and its geological significance are weak [20,21]. The characteristics of in-situ gas desorption at different desorption conditions are also not clear. The relationships between in-situ gas desorption, gas content, and the state at which gas occurs are not clear. Solving these questions is crucial in working to understand the enrichment mechanism of shale gas and in predicting the future production of shale gas. In this study, 27 shale samples were selected from the YC-2 well, targeting the lower Cambrian Shuijingtuo Formation Shale in the Sichuan Basin. The in-situ gas desorption tests were conducted at both reservoir (35 °C) and high temperatures (90 °C). The desorption characteristics and origin of in-situ shale gas are discussed in reference to the test results of total organic carbon, thermal maturity, mineral composition, methane adsorption, and nitrogen adsorption.
2.1. Samples The shale samples were selected from the YC-2 well located in NE Sichuan Basin in SW China (Fig. 1). Samples were selected from the bottom to the top of the Shuijingtuo Formation; a total of 27 samples were selected. These representative samples should reflect the characteristics of the entire Shuijingtuo Formation shale gas reservoir. The YC-2 well is located on a narrow paleo-uplift between the Chengba and Wuping fault zones [22]; here, many NW trending folds and thrust nappe faults have developed [23]. Duplex anticlines associated with intensive thrust faults have deformed intensively, while duplicated synclines have remained relatively intact [24]. The strata reflect, in large part, a high angle that could be considered upright or even inverted [25]. The Shuijingtuo Formation of the YC-2 well is approximately 700 m thick; it occupies a shallow, marine environment, and the main lithofacies are black carbonaceous shale and gray mudstone [26].
2.2. In-situ gas desorption test During the coring process, pressure coring was used to prevent the gas from escaping. Once the core reached the ground, it was placed into the desorption canister within 5 min. The CQJC-QT-2 In-situ Gas Desorption System from the Chongqing Institute of Geology and Mineral Resources was used to carry out the in-situ gas desorption test (Fig. 2). The test was completed at reservoir temperature until there was effectively no measured gas exiting the core. The valve was then closed, and the canister was placed into acidified water. It remained in this water with the core sample as both were heated to 90 °C. Before the temperature reached 90 °C, it was assumed that no gas was released from the core since the core was well sealed in the desorption canister. The test was continued at a high temperature (90 °C) until there was effectively no measured desorbed gas. During the desorption process, it was assumed that the sample shape and size would not affect the gas desorption rate. The resolution of in-situ gas content measurement was 0.1 ml, while the resolution of temperature and pressure measurements were 0.1 °C and 0.01 MPa, respectively. The acidified water was used in this test to prevent the gas from being dissolved. The weight of the sample was not less than 0.8 kg; the total desorption time was not less than 2000 min. The measured in-situ gas content was converted in standard conditions of temperature and pressure (STP, 0 °C, and 101.325 kPa). For the purposes of comparative analysis, an average formation temperature of 35 °C was used as the reservoir temperature for all 27 samples. One limitation of the in-situ gas desorption test is that the sample can only be tested one time. After the test, the gas in the sample was released; the verification of the gas desorption process was not possible, as it could not be repeated. Furthermore, during the coring process, partial gas would release and this lost gas content could not be tested. Thus, it could only be estimated. To collect accurate data regarding in-situ shale gas, it is necessary to minimize the content of gas lost during the coring process and of residual gas trapped in the shale after the desorption tests have been completed. Because pressure coring was used in this study, and because the core was placed into the desorption canister within 5 min after the core was taken out, the lost gas content is very small and has little impact on the total in-situ shale gas content [10]. The samples were tested, on average, for more than 1500 min at 90 °C; therefore, the levels of residual gas are also very low compared to the total in-situ shale gas [27]. Therefore, lost and residual gas can be ignored in this study, as we have deemed it negligible; the desorbed gas, then, will represent almost all of the in-situ shale gas.
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Fig. 1. Location, tectonic setting, and stratigraphic column of the Sichuan Basin. (a) Map showing the location of the Sichuan Basin in China. (b) Geologic map showing distribution of strata and YC-2 well location in northeast Sichuan Basin. (c) Tectonostratigraphic framework showing intense tectonic deformation. (d) Tectonic events and depositional and stratigraphic evolution of the Sichuan Basin.
Fig. 2. Schematic of the measurement of in-situ desorbed gas volume by water displacement at different temperatures using an acidified water bath.
2.3. Geochemical tests After the in-situ gas desorption tests were performed, the 27 samples were tested for their thermal maturity (equivalent
vitrinite reflectance, Ro), total organic carbon (TOC) content, mineral composition, methane adsorption capacity, pore size distribution, and specific surface area. Since the sample size of these tests is generally smaller than that of in-situ gas desorption test and
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because samples need to be crashed into powder for some tests, it is assumed that each shale sample is homogenous. As a result, the sample size and weight would not affect the results. The Ro was obtained using a fluorescence microscope and an MPV-3 microphotometer. Since the Cambrian Shuijingtuo Formation Shale has no vitrinite, Ro was calculated based on the pyrobitumen reflectance (Rb), according to the equation Ro = (Rb + 0.2443)/ 1.0495 [28]. The TOC content was obtained through a Leco analyzer [29]. The sample was crashed into powder, and approximately 1 g of powder was tested. The relative standard deviation of the measurement was less than 0.5%. The mineral composition was obtained by a Bruker D8 Advance X-ray diffractometer with a Cu K-alpha radiation source. The sample was crushed into powder, and the powder was placed into a horizontal sample carrier. The vertical 2h goniometer was scanned from 3° to 45° [30]. The methane adsorption test was completed by a ZJ466 Rubotherm Isosorp HP Static III instrument, according to the Chinese Standard GB/T 19560-2008. The measurement range of pressure was 0–35 MPa. The measurement temperature was 35 °C. Based on the isotherm adsorption curve and the Langmuir adsorption model, the maximum adsorption content and adsorption content at different pressures can be obtained [31,32]. The pore size distribution and specific surface area were obtained by an N2 adsorption test using an Automated Pore Size Analyzer [33]. The minimum P/P0 was 0.0001. The greatest pore size range was 0.35–400 nm. The minimum pore volume was 0.00001 cm3/g, and the minimum specific surface area was 0.01 m2/g. According to the multi-point BET theory, the specific surface area can be obtained [34]. According to the BJH method of nitrogen adsorption isotherm, the pore size distribution can be
obtained [35]. Based on the BJH adsorption volume (V) and the BJH specific surface area (A), the average pore size (D) was calculated according to the equation D = 4 V/A [36].
3. Results 3.1. In-situ gas desorption characteristics 3.1.1. In-situ gas desorption curves The shapes of the in-situ gas desorption curves are clearly different for the 27 samples (Fig. 3). At the beginning of both the reservoir temperature desorption stage and the high temperature desorption stage, the in-situ gas was rapidly desorbed, and the desorbed gas volume increased rapidly. Then, the in-situ gas was desorbed slowly. The desorption time has little impact on the total in-situ desorbed gas content, as the samples generally desorbed most of the in-situ gas within 300 min in both stages. For example, sample YC2-15, with a very low total in-situ desorbed gas content, and sample YC2-27, with a very high in-situ desorbed gas content, were desorbed at approximately 86.2% and 95.1%, respectively, of their in-situ gas content within 300 min at the high temperature desorption stage. At the reservoir temperature desorption stage, the curves had two typical patterns (Fig. 4). One, a flat-straight pattern, which generally represents very low in-situ desorbed gas content (Fig. 4a). The other, a bend pattern, which tends to represent a relatively high in-situ desorbed gas content (Fig. 4b). At the high temperature stage, the curves have three typical patterns (Fig. 5). They are circular, transitional, and rectangular. For the 27 samples, most
Fig. 3. Characteristics of the in-situ gas desorption curves of the 27 shale samples from the YC-2 well. (a) In-situ gas desorption curves of samples YC2-1 to YC2-9. (b) In-situ gas desorption curves of samples YC2-10 to YC2-18. (c) In-situ gas desorption curves of samples YC2-19 to YC2-27.
Fig. 4. Two typical curve patterns of in-situ gas desorption at the reservoir temperature desorption stage. (a) Flat-straight pattern. (b) Bend pattern.
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Fig. 5. Three typical curve patterns of in-situ gas desorption at the high temperature desorption stage. (a) Circular pattern. (b) Transitional pattern. (c) Rectangular pattern.
illustrate the transitional pattern. The three patterns reflect the different desorption characteristics at the high temperature desorption stage. The circular pattern has a low desorption rate and a long desorption time. The rectangular pattern has a high desorption rate and a very short desorption time.
3.1.2. In-situ desorbed gas content and desorption rate According to the change in in-situ desorbed gas volume over time, we can calculate the desorption time, desorbed gas content, and desorption rate at the reservoir and high temperature desorption stages (Fig. 6). In general, all the samples had characteristics
Fig. 6. Desorption time, desorption rate, and desorbed gas content of the 27 shale samples at reservoir temperature (35 °C) desorption stage and high temperature (90 °C) desorption stage. Q1: desorbed gas content at reservoir temperature desorption stage, cm3/g. Q2: desorbed gas content at high temperature desorption stage, cm3/g. R1h: highest desorption rate at reservoir temperature desorption stage, cm3/g/min. R1m: mean desorption rate at reservoir temperature desorption stage, cm3/g/min. R2h: highest desorption rate at high temperature desorption stage, cm3/g/min. R2m: mean desorption rate at high temperature desorption stage, cm3/g/min. The mean desorption rate is the rate of the cumulative in-situ desorbed gas content from 10% to 90%.
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that indicated the desorbed gas content and desorption rate at the reservoir temperature desorption stage are lower than that at the high temperature desorption stage. At the reservoir temperature desorption stage, the in-situ desorbed gas content (Q1) accounted for approximately 16.6% of the total in-situ desorbed gas content, the mean desorption rate (R1m) was 0.0004 cm3/g/min (the mean desorption rate is the rate of the cumulative in-situ desorbed gas content from 10% to 90%), and the highest desorption rate (R1h) was 0.0025 cm3/g/min. At the high temperature desorption stage, the in-situ desorbed gas content (Q2) accounted for approximately 83.4% of the total in-situ desorbed gas content, the mean desorption rate (R2m) was 0.0043 cm3/g/min, which is approximately 10 times higher than that at the reservoir temperature desorption stage, and the highest desorption rate (R2h) was 0.0195 cm3/g/min. Therefore, Q1 made little contribution to the total in-situ desorbed gas content when compared to Q2. In addition, the samples may still include a high total of in-situ desorbed gas content although their measured Q1 is low. For example, sample YC2-3 had a Q1 of approximately 0.02 cm3/g but a total in-situ desorbed gas content of approximately 1.09 cm3/g (Fig. 3). 3.2. Geochemical characteristics The Shuijingtuo Formation shale has a high degree of thermal evolution, as the Ro averaged 1.9%. The TOC resulted in levels between 1.3% and 3.4%, with an average content of 2.6%. Thus, the Shuijingtuo Formation is composed of organic-rich shale. The main mineral in the Shuijingtuo Formation shale is quartz, with an average of 34.4%. Following are carbonate and clay minerals, with an average of 26.8% and 18.4%, respectively. The feldspar
content is low, with an average of 12.5% (Fig. 7). The mineral composition varies little throughout the whole formation, showing a stable depositional environment present when the stratum was deposited. Using the methane isothermal adsorption curves (Fig. 8), the maximum adsorbed methane content (Q3) and the adsorbed methane content at 35 °C, the atmospheric pressure (Q4) can be obtained. The Q3 measured between 1.52 and 4.67 cm3/g, with an average of 2.67 cm3/g, which indicated a high adsorption capacity of the shale. The Q4 measured between 0.41 and 1.25 cm3/g, with an average of 0.80 cm3/g, clearly lower than the Q3 (Table 1). Using the nitrogen adsorption curves, the specific surface area and pore size distribution can be obtained (Fig. 9, Table 1). The specific surface area measured between 1.48 and 8.77 m2/g, with an average of 5.16 m2/g. The average pore size measured between 4.15 nm and 5.80 nm, with an average of 5.10 nm. The pore volume measured between 0.0004 cm3/g and 0.0027 cm3/g, with an average of 0.0015 cm3/g. The pore volume percent of pores sized greater than 11 nm (P1) was approximately 58%, while the pore volume percent of pore size smaller than 11 nm (P2) was approximately 42% (Table 1). Thus, the pore space of these shale samples was mainly the result of pores larger than 11 nm in diameter. 4. Discussions 4.1. Occurrence state of in-situ shale gas The occurrence state of shale gas is important for gas production. The in-situ desorbed gas in the coalbed is mainly sorbed gas, while the in-situ desorbed gas in the shale is mainly free gas
Fig. 7. Characteristics of Ro, TOC, mineral composition, and desorbed gas content of the Shuijingtuo Formation shale of the YC-2 well. The Ro has an approximately 1.9% average. The TOC has an approximately 2.6% average. The mineral composition is similar throughout the whole Shuijingtuo Formation shale.
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Fig. 8. Absolute isotherms of methane on the 27 shale samples. The lines are Langmuir fitting results.
Table 1 Adsorbed methane content, specific surface area, average pore size, and pore volume of the 27 shale samples. Q3: maximum adsorbed methane content, cm3/g. Q4: adsorbed methane content at 35 °C, atmospheric condition, cm3/g. P1: Pore volume percent of pore size larger than 11 nm, %. P2: Pore volume percent of pore size smaller than 11 nm, %. Sample ID
Depth (m)
Q3 with error range (cm3/g)
Q4 with error range (cm3/g)
Specific surface area with error range (m2/g)
Average pore size with error range (nm)
Pore volume with error range (ml/g)
P1 (%)
P2 (%)
CQ2-1 CQ2-2 CQ2-3 CQ2-4 CQ2-5 CQ2-6 CQ2-7 CQ2-8 CQ2-9 CQ2-10 CQ2-11 CQ2-12 CQ2-13 CQ2-14 CQ2-15 CQ2-16 CQ2-17 CQ2-18 CQ2-19 CQ2-20 CQ2-21 CQ2-22 CQ2-23 CQ2-24 CQ2-25 CQ2-26 CQ2-27
409.7 457.4 469.2 519.4 567.2 619.8 719.8 769.4 778.1 840.6 850.0 860.3 869.5 900.8 919.3 958.4 971.2 979.8 990.1 1010.5 1020.2 1032.0 1071.6 1089.7 1101.3 1112.5 1139.3
2.41 ± 0.02 1.80 ± 0.02 3.10 ± 0.03 2.40 ± 0.03 4.00 ± 0.04 1.78 ± 0.02 2.00 ± 0.02 2.25 ± 0.02 3.71 ± 0.04 3.17 ± 0.03 1.96 ± 0.02 1.70 ± 0.02 2.26 ± 0.02 2.68 ± 0.03 4.67 ± 0.05 2.86 ± 0.03 1.52 ± 0.01 2.49 ± 0.03 2.48 ± 0.02 3.34 ± 0.03 3.38 ± 0.03 2.05 ± 0.02 2.48 ± 0.02 2.74 ± 0.03 2.55 ± 0.02 2.05 ± 0.02 4.16 ± 0.04
1.23 ± 0.02 0.41 ± 0.01 1.25 ± 0.02 0.63 ± 0.01 0.79 ± 0.01 0.58 ± 0.01 0.68 ± 0.01 0.78 ± 0.01 0.99 ± 0.02 0.73 ± 0.01 0.54 ± 0.01 0.48 ± 0.01 0.72 ± 0.01 1.13 ± 0.02 0.74 ± 0.01 1.07 ± 0.02 0.66 ± 0.01 0.62 ± 0.01 0.94 ± 0.01 0.74 ± 0.01 1.24 ± 0.02 0.64 ± 0.01 0.74 ± 0.01 0.68 ± 0.01 0.77 ± 0.02 0.84 ± 0.01 0.99 ± 0.02
8.16 ± 0.08 2.59 ± 0.03 7.00 ± 0.06 6.91 ± 0.07 8.12 ± 0.08 1.48 ± 0.01 5.30 ± 0.03 5.15 ± 0.04 7.84 ± 0.06 3.73 ± 0.03 1.74 ± 0.02 2.47 ± 0.02 3.88 ± 0.03 5.55 ± 0.06 5.93 ± 0.05 4.42 ± 0.06 3.57 ± 0.03 5.46 ± 0.06 8.77 ± 0.09 4.58 ± 0.05 4.66 ± 0.03 7.16 ± 0.07 6.91 ± 0.04 2.82 ± 0.01 6.13 ± 0.04 4.99 ± 0.02 3.93 ± 0.02
5.38 ± 0.02 5.63 ± 0.01 4.59 ± 0.01 5.44 ± 0.01 5.07 ± 0.02 4.60 ± 0.02 5.06 ± 0.03 5.62 ± 0.02 5.11 ± 0.02 5.24 ± 0.03 5.80 ± 0.03 5.74 ± 0.02 5.40 ± 0.02 4.80 ± 0.01 4.15 ± 0.01 4.54 ± 0.01 5.68 ± 0.02 5.07 ± 0.02 5.10 ± 0.01 4.97 ± 0.03 5.66 ± 0.02 4.55 ± 0.01 4.91 ± 0.01 4.56 ± 0.01 5.37 ± 0.02 5.04 ± 0.03 4.60 ± 0.02
0.00148 ± 0.00011 0.00087 ± 0.00005 0.00107 ± 0.00008 0.00196 ± 0.00014 0.00178 ± 0.00012 0.00042 ± 0.00002 0.00123 ± 0.00009 0.00118 ± 0.00013 0.00248 ± 0.00019 0.00187 ± 0.00012 0.00084 ± 0.00005 0.00092 ± 0.00007 0.00079 ± 0.00004 0.00123 ± 0.00011 0.00198 ± 0.00016 0.00138 ± 0.00010 0.00133 ± 0.00009 0.00150 ± 0.00010 0.00265 ± 0.00022 0.00178 ± 0.00014 0.00101 ± 0.00005 0.00167 ± 0.00017 0.00195 ± 0.00013 0.00143 ± 0.00009 0.00246 ± 0.00022 0.00147 ± 0.00012 0.00134 ± 0.00008
33.8 57.5 36.4 35.2 25.8 57.8 56.9 34.7 39.9 46.0 50.0 64.3 41.8 35.8 41.4 39.1 40.6 38.7 40.8 37.1 39.6 33.5 36.9 42.7 41.9 38.8 37.3
66.2 42.5 63.6 64.8 74.2 42.2 43.1 65.3 60.1 54.0 50.0 35.7 58.2 64.2 58.6 60.9 59.4 61.3 59.2 62.9 60.4 66.5 63.1 57.3 58.1 61.2 62.7
and sorbed gas [12]. For the coalbed methane, the in-situ desorbed gas content is generally lower than the methane adsorption content of isotherms [37]. However, for the gas-rich shale, the insitu desorbed gas content is generally higher than the methane adsorption content of isotherms [12]. When the total in-situ desorbed gas content of shale is similar to the methane adsorption content of isotherms, the in-situ desorbed gas is mainly sorbed gas. When the total in-situ desorbed gas content of shale is higher
than the methane adsorption content of isotherms, however, the in-situ desorbed gas is a mixture of free and sorbed gas [10,12]. The stable carbon isotopes of different in-situ gas desorption stages of shale can also be used to obtain the ratio of free to sorbed gas [21]. In this study, the in-situ desorbed gas content at the high temperature desorption stage (Q2) was positively correlated with methane adsorption content at 35 °C and atmospheric pressure
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Fig. 9. N2 adsorption curves and pore size distribution of the 27 shale samples. (a) N2 adsorption curves. (b) Pore size distribution.
(Q4) (Fig. 10). The Q2, which is the content of residual gas at the reservoir temperature desorption stage was slightly lower than the Q4, which is the greatest methane adsorption content at the reservoir temperature desorption stage (35 °C, atmospheric pressure). The Q2 was similar to the Q4, indicating that the Q2 was in an adsorbed state in the shale at reservoir temperature. Therefore, the in-situ desorbed gas from the high temperature desorption stage was mainly sorbed gas, and the in-situ desorbed gas from reservoir temperature desorption stage was mainly free gas. Because the Q2 accounted for approximately 83.4% of the total in-situ desorbed gas content and the formation pressure was higher than the atmospheric pressure, which is more advantageous for gas adsorption [38], the shale gas in the Shuijingtuo Formation was mainly sorbed gas, which was likely greater than 83.4%.
sorbed gas in the shale (Fig. 11a). The shale gas in the Shuijingtuo Formation was mainly sorbed gas, which is difficult to desorb at a reservoir temperature of approximately 35 °C. This is maybe the main reason why the Shuijingtuo Formation shale still had a high gas content (average 0.84 cm3/g), even after a burial time of more than 500 Ma [39]. The Q1 percentage was negatively correlated with the Q3 (Fig. 11b). It suggested that, as methane adsorption capacity becomes stronger, free gas is more easily converted into sorbed gas in shale, thereby reducing the proportion of free gas. One limiting factor surrounding methane adsorption capacity is that the gas is adsorbed in the subsurface of shale rock, while methane adsorption capacity is tested via crushed powder from shale samples. This makes it difficult to infer whether the methane adsorption capacity of the powder sample would be the same as the bulk subsurface shale sample.
4.2. Controlling factors of in-situ desorbed gas content
4.2.2. Nano-scale pores The Q2 value, comprised primarily of sorbed gas, indicated a positive correlation with pore volume, specifically the percentage of pores measuring smaller than 11 nm (P2). This implies that the higher proportion of P2, the higher the proportion of sorbed gas (Fig. 12a). The Q2 also indicated a positive correlation with total pore volume, implying that pores in the shale are conducive to the formation of sorbed gas (Fig. 12b). Further, the Q2 showed a positive correlation with specific surface area; as seen in Fig. 12c, as the specific surface area increased, the Q2 also increased significantly, showing that the specific surface area has an obvious and positive influence on the sorbed gas. The Q1 percentage, comprising primarily free gas, indicated a positive correlation with pore volume, particularly the percent of pores measured larger than 11 nm (P1). This indicated that the higher proportion of P1, the higher proportion of free gas (Fig. 12d). The Q1 was negatively correlated with total pore volume, though, indicating that pores in the shale are not conducive to the formation of free gas, as free gas is easier lost during burial time (Fig. 12e). Further, the Q1 showed a negative correlation with specific surface area, indicating that the higher the specific surface area, the more likely the free gas is to convert into sobbed gas in the shale (Fig. 12f). The major limitation of the nano-scale pores is that pores smaller than 1.8 nm or larger than 135 nm cannot be detected due to the limit of the N2 adsorption test in this study. Therefore, the effect of the undetected pores on the in-situ desorbed gas content cannot be inferred. However, since the Shuijingtuo Formation shale
4.2.1. Methane adsorption capacity The Q2 percentage was positively correlated with the maximum adsorbed methane content (Q3), suggesting that the stronger the gas adsorption capacity of shale, the higher the percentage of
Fig. 10. Relationship between Q2 and Q4. The Q2 has a good positive relationship with Q4, while the Q2 is slightly lower than the Q4. Q2: in-situ desorbed gas content at high temperature desorption stage, cm3/g. Q4: adsorbed methane content at 35 °C, atmospheric condition, cm3/g.
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Fig. 11. Relationships between in-situ desorbed gas percent and maximum adsorbed methane content. (a) A positive correlation between Q2 percent and Q3. (b) A negative correlation between Q1 percent and Q3. Q1: in-situ desorbed gas content at reservoir temperature desorption stage, cm3/g. Q2: in-situ desorbed gas content at high temperature desorption stage, cm3/g. Q3: maximum adsorbed methane content, cm3/g.
Fig. 12. Relationships between in-situ desorbed gas content percent and pore volume percent, total pore volume, and specific surface area. Q1: in-situ desorbed gas content at reservoir temperature desorption stage, cm3/g. Q2: in-situ desorbed gas content at high temperature desorption stage, cm3/g. P1: Pore volume percent of pore size larger than 11 nm, %. P2: Pore volume percent of pore size smaller than 11 nm, %.
gas is primarily sorbed gas and the sorbed gas is largely adsorbed on the surface of small pores, those pores larger than 135 nm may have limited effect on total gas content. 4.3. Controlling factors of in-situ gas desorption rate Many factors control in-situ gas desorption Yang et al. simulated the adsorption-desorption process using crushed shale samples of three different particle sizes; the study indicated that the gas desorption rate would increase as the particle size decreased [8]. In regards to coalbed methane, the initial desorption rate was dependent upon the total gas content [40]. The coalbed would have a high initial desorption rate if there existed a high total gas content [40]. In this study, at the high temperature desorption stage, both the mean desorption rate (R2m) and highest desorption rate (R2h) had no obvious relationships to the average pore size (Fig. 13a and b). We speculate that this is because many factors affect the desorption rate of sorbed gas, such as pore size, gas adsorption capacity, and total gas content [8,40]. At the reservoir temperature desorption stage, both the mean desorption rate
(R1m) and the highest desorption rate (R1h) illustrated good relationships with average pore size (Fig. 13c and d). In addition, as the average pore size is increased, the R1m and R1h will increase exponentially. This is likely because the in-situ desorbed gas at the reservoir temperature desorption stage was mainly composed of free gas, and free gas migrates into larger pores more easily. This also suggests that the Shuijingtuo Formation Shale has, in general, a high pore volume and low free gas percentage. The R1m and R1h were generally lower than the R2m and R2h. At the reservoir temperature desorption stage, the pressure was the major difference between the subsurface shale and the shale in the desorption canister on the ground. At the high temperature desorption stage, temperature was the major factor, particularly compared to the reservoir temperature desorption stage. Temperature is more sensitive than pressure in relation to the adsorptiondesorption of shale [41]. Therefore, the in-situ gas desorption rate at the high temperature was higher than that at the reservoir temperature. This analysis of in-situ gas desorption rate is limited because shale maturity has an important effect on desorption rate; gas
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Fig. 13. Relationships between in-situ shale gas desorption rates and average pore size. (a) R2m has no obvious correlation with average pore size. (b) R2h has no obvious correlation with average pore size. (c) R1m has a positive correlation with average pore size. (d) R1h has a positive correlation with average pore size. R1m is the mean desorption rate at reservoir temperature desorption stage. R1h is the highest desorption rate at reservoir temperature desorption stage. R2m is the mean desorption rate at high temperature desorption stage. R2h is the highest desorption rate at high temperature desorption stage.
desorbs from the pores and releases through the interconnected pores. The high-mature shale would have more organic pores than the low-mature shale, leading to a better connectivity [42]. Thus, the high-mature shale may have a higher desorption rate than that of the low-mature shale. However, only the high-mature Cambrian Shuijingtuo Shale was tested in this study. The low-mature Cambrian shale is more difficult to find in China; because of this, the gas desorption characteristics of the low-mature shale are still unknown. 5. Conclusions The average in-situ desorbed gas content of the Cambrian Shuijingtuo Formation shale measured 0.84 cm3/g. The in-situ desorbed gas content and desorption rate at the reservoir temperature (35 °C) desorption stage both measured lower than that at the high temperature (90 °C) desorption stage. The shale gas in the Shuijingtuo Formation was primarily sorbed gas. The in-situ desorbed gas percent of the two stages was mainly controlled by methane adsorption capacity, pore volume, and specific surface area. The in-situ gas desorption rate at the reservoir temperature desorption stage was mainly controlled by average pore size, while the in-situ gas desorption rate at the high temperature stage was, perhaps, primarily controlled by average pore size and methane adsorption capacity. Acknowledgments This work was supported by the National Natural Science Foundation of China [41472112 and U1562215] and the China Shale Gas Geological Survey [12120114046701]. We also acknowledge the support of Chongqing Institute of Geology and Mineral Resources, and we express our appreciation for their approval to publish the data. We thank Professor Ningning Zhong, Xun Zhou, and Lipeng Yao for their help to the work of the in-situ gas desorption test.
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Fuel journal homepage: www.elsevier.com/locate/fuel
Full Length Article
Characteristics and origin of in-situ gas desorption of the Cambrian Shuijingtuo Formation shale gas reservoir in the Sichuan Basin, China Xianglu Tang a,b, Zhenxue Jiang a,⇑, Shu Jiang b,⇑, Lijun Cheng c, Ye Zhang c a
State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China Energy and Geoscience Institute, University of Utah, Salt Lake City, UT 84108, USA c Chongqing Institute of Geology and Mineral Resources, Chongqing 400042, China b
h i g h l i g h t s
g r a p h i c a l a b s t r a c t
In-situ desorbed gas content and
desorption rate are different at two stages. In-situ shale gas is mainly desorbed within 300 min. The Shuijingtuo Formation shale is mainly sorbed gas. In-situ gas desorption is controlled by nano-pores and methane adsorption capacity.
a r t i c l e
i n f o
Article history: Received 20 July 2016 Received in revised form 8 September 2016 Accepted 25 September 2016 Available online 28 September 2016 Keywords: In-situ gas desorption Occurrence stage Methane adsorption ability Pore size distribution Shale gas reservoir
a b s t r a c t In-situ shale gas extraction provides direct evidence in response to gas-bearing evaluations and productivity predictions regarding shale gas reservoirs. The desorption characteristics and origin of in-situ shale gas extraction in the lower Cambrian Shuijingtuo Formation of the Sichuan Basin are studied via in-situ gas desorption tests. Tests are conducted at both reservoir (35 °C) and high temperatures (90 °C). The results indicate that most in-situ shale gas is quickly desorbed within 300 min at both the reservoir temperature desorption stage and the high temperature desorption stage. In both instances, the in-situ gas desorption rates decrease rapidly over time. In addition, the desorbed gas content and desorption rate at the reservoir temperature desorption stage are both clearly lower than the equivalent measures at the high temperature desorption stage. The in-situ desorbed gas from the reservoir temperature desorption stage is mainly free gas; the in-situ desorbed gas from the high temperature desorption stage, on the other hand, is mainly sorbed gas, which is the dominant form in the in-situ shale gas. The percentage of in-situ desorbed gas at these two stages is mainly controlled by gas adsorption, pore volume, and specific surface area. The desorption rate of in-situ shale gas is likely controlled primarily by average pore size and methane adsorption. Ó 2016 Elsevier Ltd. All rights reserved.
Abbreviations: TOC, total organic carbon, %; Ro, equivalent vitrinite reflectance, %; STP, standard conditions for temperature and pressure, 0 °C, and 101.325 kPa; Q1, in-situ desorbed gas content at the reservoir temperature (35 °C) desorption stage, m3/t; Q2, in-situ desorbed gas content at the high temperature (90 °C) desorption stage, m3/t; Q3, maximum adsorbed methane content, m3/t; Q4, adsorbed methane content at 35 °C, atmospheric condition, m3/t; P1, pore volume percent of pore size larger than 11 nm, %; P2, pore volume percent of pore size smaller than 11 nm, %; R1m, mean desorption rate at the reservoir temperature desorption stage, m3/t/min; R1h, highest desorption rate at the reservoir temperature desorption stage, m3/t/min; R2m, mean desorption rate at the high temperature desorption stage, m3/t/min; R2h, highest desorption rate at the high temperature desorption stage, m3/t/min. ⇑ Corresponding authors at: No. 18 Fuxue Road, Changping, Beijing, China (Z. Jiang). 423 Wakara Way, Suite 300, Salt Lake City, UT, USA (S. Jiang). E-mail addresses: [email protected] (Z. Jiang), [email protected] (S. Jiang). http://dx.doi.org/10.1016/j.fuel.2016.09.072 0016-2361/Ó 2016 Elsevier Ltd. All rights reserved.
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1. Introduction
2. Material and methods
At present, the production of shale gas accounts for a large proportion of unconventional oil and gas in North America. A variety of studies have been conducted to develop and utilize this relatively clean potential fuel source [1–3]. Evaluation of shale gas content will serve as the groundwork for resource potential evaluation, commercial development, and productivity predictions [4,5]. As a result of the gas occurrence state in the shale, shale gas can be divided, for the most part, into free gas and sorbed gas, where sorbed gas is composed of adsorbed gas and absorbed gas [6]. Free gas is stored primarily in shale pores, while the sorbed gas tends to be adsorbed on the surface of shale organic matter and clay mineral [7]. The ratio of free gas to sorbed gas, however, cannot be obtained directly, as they would interconvert in the shale [7,8]. Using the in-situ gas desorption test, though, the shale gas can be divided into lost gas, desorbed gas, and residual gas [9,10]. The lost gas is the gas that is lost before the core is loaded into the desorption canister [11]. The desorbed gas is the gas desorbed from the shale while core is loaded into in the desorption canister [12]. The residual gas is the gas remaining in the shale core after the in-situ gas desorption test [13]. The in-situ shale gas content is a more reliable measure and can be used for analysis geochemical characteristics of shale [10]. The free and sorbed gas in the in-situ shale gas reservoir exist in dynamic equilibrium [14]. When the shale sample is put into the desorption canister underground, the confining pressure is reduced, which leads to the quick release of free gas from the shale sample through interconnected pores. With the release of free gas, the equilibrium of the gas in the free stage and sorbed state is broken, and then the sorbed gas starts to convert into free gas. This continues until gas in the free and sorbed states reach a new equilibrium [15]. When the shale sample is heated to a high temperature, the adsorption capacity of shale gas is greatly reduced; more sorbed gas begins to convert into free gas [16]. Because the equilibrium of gas in the free stage and sorbed state is, again, broken, the free gas content in the shale begins to increase, leading to excess pressure in the shale. The free gas then releases until the gas in free and sorbed states, again, reach equilibrium. The in-situ gas desorption test was first used to measure coalbed methane content in the 1970s [17,18]. With the development of shale gas in recent years, the in-situ gas desorption test has been used for measuring shale gas content [27]. It is necessary that the in-situ gas desorption test be conducted immediately after that the shale core is retrieved from the wellbore; otherwise, the abundant gas would be lost [19]. In addition, the field environment is generally tough, and the researchers have limited to access the drilling process. Because of this, knowledge of in-situ desorbed gas of shale is also limited. Still, it is meaningful. At present, the in-situ gas desorption test of shale gas is rare, and studies of the characteristics of in-situ desorbed gas and its geological significance are weak [20,21]. The characteristics of in-situ gas desorption at different desorption conditions are also not clear. The relationships between in-situ gas desorption, gas content, and the state at which gas occurs are not clear. Solving these questions is crucial in working to understand the enrichment mechanism of shale gas and in predicting the future production of shale gas. In this study, 27 shale samples were selected from the YC-2 well, targeting the lower Cambrian Shuijingtuo Formation Shale in the Sichuan Basin. The in-situ gas desorption tests were conducted at both reservoir (35 °C) and high temperatures (90 °C). The desorption characteristics and origin of in-situ shale gas are discussed in reference to the test results of total organic carbon, thermal maturity, mineral composition, methane adsorption, and nitrogen adsorption.
2.1. Samples The shale samples were selected from the YC-2 well located in NE Sichuan Basin in SW China (Fig. 1). Samples were selected from the bottom to the top of the Shuijingtuo Formation; a total of 27 samples were selected. These representative samples should reflect the characteristics of the entire Shuijingtuo Formation shale gas reservoir. The YC-2 well is located on a narrow paleo-uplift between the Chengba and Wuping fault zones [22]; here, many NW trending folds and thrust nappe faults have developed [23]. Duplex anticlines associated with intensive thrust faults have deformed intensively, while duplicated synclines have remained relatively intact [24]. The strata reflect, in large part, a high angle that could be considered upright or even inverted [25]. The Shuijingtuo Formation of the YC-2 well is approximately 700 m thick; it occupies a shallow, marine environment, and the main lithofacies are black carbonaceous shale and gray mudstone [26].
2.2. In-situ gas desorption test During the coring process, pressure coring was used to prevent the gas from escaping. Once the core reached the ground, it was placed into the desorption canister within 5 min. The CQJC-QT-2 In-situ Gas Desorption System from the Chongqing Institute of Geology and Mineral Resources was used to carry out the in-situ gas desorption test (Fig. 2). The test was completed at reservoir temperature until there was effectively no measured gas exiting the core. The valve was then closed, and the canister was placed into acidified water. It remained in this water with the core sample as both were heated to 90 °C. Before the temperature reached 90 °C, it was assumed that no gas was released from the core since the core was well sealed in the desorption canister. The test was continued at a high temperature (90 °C) until there was effectively no measured desorbed gas. During the desorption process, it was assumed that the sample shape and size would not affect the gas desorption rate. The resolution of in-situ gas content measurement was 0.1 ml, while the resolution of temperature and pressure measurements were 0.1 °C and 0.01 MPa, respectively. The acidified water was used in this test to prevent the gas from being dissolved. The weight of the sample was not less than 0.8 kg; the total desorption time was not less than 2000 min. The measured in-situ gas content was converted in standard conditions of temperature and pressure (STP, 0 °C, and 101.325 kPa). For the purposes of comparative analysis, an average formation temperature of 35 °C was used as the reservoir temperature for all 27 samples. One limitation of the in-situ gas desorption test is that the sample can only be tested one time. After the test, the gas in the sample was released; the verification of the gas desorption process was not possible, as it could not be repeated. Furthermore, during the coring process, partial gas would release and this lost gas content could not be tested. Thus, it could only be estimated. To collect accurate data regarding in-situ shale gas, it is necessary to minimize the content of gas lost during the coring process and of residual gas trapped in the shale after the desorption tests have been completed. Because pressure coring was used in this study, and because the core was placed into the desorption canister within 5 min after the core was taken out, the lost gas content is very small and has little impact on the total in-situ shale gas content [10]. The samples were tested, on average, for more than 1500 min at 90 °C; therefore, the levels of residual gas are also very low compared to the total in-situ shale gas [27]. Therefore, lost and residual gas can be ignored in this study, as we have deemed it negligible; the desorbed gas, then, will represent almost all of the in-situ shale gas.
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Fig. 1. Location, tectonic setting, and stratigraphic column of the Sichuan Basin. (a) Map showing the location of the Sichuan Basin in China. (b) Geologic map showing distribution of strata and YC-2 well location in northeast Sichuan Basin. (c) Tectonostratigraphic framework showing intense tectonic deformation. (d) Tectonic events and depositional and stratigraphic evolution of the Sichuan Basin.
Fig. 2. Schematic of the measurement of in-situ desorbed gas volume by water displacement at different temperatures using an acidified water bath.
2.3. Geochemical tests After the in-situ gas desorption tests were performed, the 27 samples were tested for their thermal maturity (equivalent
vitrinite reflectance, Ro), total organic carbon (TOC) content, mineral composition, methane adsorption capacity, pore size distribution, and specific surface area. Since the sample size of these tests is generally smaller than that of in-situ gas desorption test and
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because samples need to be crashed into powder for some tests, it is assumed that each shale sample is homogenous. As a result, the sample size and weight would not affect the results. The Ro was obtained using a fluorescence microscope and an MPV-3 microphotometer. Since the Cambrian Shuijingtuo Formation Shale has no vitrinite, Ro was calculated based on the pyrobitumen reflectance (Rb), according to the equation Ro = (Rb + 0.2443)/ 1.0495 [28]. The TOC content was obtained through a Leco analyzer [29]. The sample was crashed into powder, and approximately 1 g of powder was tested. The relative standard deviation of the measurement was less than 0.5%. The mineral composition was obtained by a Bruker D8 Advance X-ray diffractometer with a Cu K-alpha radiation source. The sample was crushed into powder, and the powder was placed into a horizontal sample carrier. The vertical 2h goniometer was scanned from 3° to 45° [30]. The methane adsorption test was completed by a ZJ466 Rubotherm Isosorp HP Static III instrument, according to the Chinese Standard GB/T 19560-2008. The measurement range of pressure was 0–35 MPa. The measurement temperature was 35 °C. Based on the isotherm adsorption curve and the Langmuir adsorption model, the maximum adsorption content and adsorption content at different pressures can be obtained [31,32]. The pore size distribution and specific surface area were obtained by an N2 adsorption test using an Automated Pore Size Analyzer [33]. The minimum P/P0 was 0.0001. The greatest pore size range was 0.35–400 nm. The minimum pore volume was 0.00001 cm3/g, and the minimum specific surface area was 0.01 m2/g. According to the multi-point BET theory, the specific surface area can be obtained [34]. According to the BJH method of nitrogen adsorption isotherm, the pore size distribution can be
obtained [35]. Based on the BJH adsorption volume (V) and the BJH specific surface area (A), the average pore size (D) was calculated according to the equation D = 4 V/A [36].
3. Results 3.1. In-situ gas desorption characteristics 3.1.1. In-situ gas desorption curves The shapes of the in-situ gas desorption curves are clearly different for the 27 samples (Fig. 3). At the beginning of both the reservoir temperature desorption stage and the high temperature desorption stage, the in-situ gas was rapidly desorbed, and the desorbed gas volume increased rapidly. Then, the in-situ gas was desorbed slowly. The desorption time has little impact on the total in-situ desorbed gas content, as the samples generally desorbed most of the in-situ gas within 300 min in both stages. For example, sample YC2-15, with a very low total in-situ desorbed gas content, and sample YC2-27, with a very high in-situ desorbed gas content, were desorbed at approximately 86.2% and 95.1%, respectively, of their in-situ gas content within 300 min at the high temperature desorption stage. At the reservoir temperature desorption stage, the curves had two typical patterns (Fig. 4). One, a flat-straight pattern, which generally represents very low in-situ desorbed gas content (Fig. 4a). The other, a bend pattern, which tends to represent a relatively high in-situ desorbed gas content (Fig. 4b). At the high temperature stage, the curves have three typical patterns (Fig. 5). They are circular, transitional, and rectangular. For the 27 samples, most
Fig. 3. Characteristics of the in-situ gas desorption curves of the 27 shale samples from the YC-2 well. (a) In-situ gas desorption curves of samples YC2-1 to YC2-9. (b) In-situ gas desorption curves of samples YC2-10 to YC2-18. (c) In-situ gas desorption curves of samples YC2-19 to YC2-27.
Fig. 4. Two typical curve patterns of in-situ gas desorption at the reservoir temperature desorption stage. (a) Flat-straight pattern. (b) Bend pattern.
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Fig. 5. Three typical curve patterns of in-situ gas desorption at the high temperature desorption stage. (a) Circular pattern. (b) Transitional pattern. (c) Rectangular pattern.
illustrate the transitional pattern. The three patterns reflect the different desorption characteristics at the high temperature desorption stage. The circular pattern has a low desorption rate and a long desorption time. The rectangular pattern has a high desorption rate and a very short desorption time.
3.1.2. In-situ desorbed gas content and desorption rate According to the change in in-situ desorbed gas volume over time, we can calculate the desorption time, desorbed gas content, and desorption rate at the reservoir and high temperature desorption stages (Fig. 6). In general, all the samples had characteristics
Fig. 6. Desorption time, desorption rate, and desorbed gas content of the 27 shale samples at reservoir temperature (35 °C) desorption stage and high temperature (90 °C) desorption stage. Q1: desorbed gas content at reservoir temperature desorption stage, cm3/g. Q2: desorbed gas content at high temperature desorption stage, cm3/g. R1h: highest desorption rate at reservoir temperature desorption stage, cm3/g/min. R1m: mean desorption rate at reservoir temperature desorption stage, cm3/g/min. R2h: highest desorption rate at high temperature desorption stage, cm3/g/min. R2m: mean desorption rate at high temperature desorption stage, cm3/g/min. The mean desorption rate is the rate of the cumulative in-situ desorbed gas content from 10% to 90%.
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that indicated the desorbed gas content and desorption rate at the reservoir temperature desorption stage are lower than that at the high temperature desorption stage. At the reservoir temperature desorption stage, the in-situ desorbed gas content (Q1) accounted for approximately 16.6% of the total in-situ desorbed gas content, the mean desorption rate (R1m) was 0.0004 cm3/g/min (the mean desorption rate is the rate of the cumulative in-situ desorbed gas content from 10% to 90%), and the highest desorption rate (R1h) was 0.0025 cm3/g/min. At the high temperature desorption stage, the in-situ desorbed gas content (Q2) accounted for approximately 83.4% of the total in-situ desorbed gas content, the mean desorption rate (R2m) was 0.0043 cm3/g/min, which is approximately 10 times higher than that at the reservoir temperature desorption stage, and the highest desorption rate (R2h) was 0.0195 cm3/g/min. Therefore, Q1 made little contribution to the total in-situ desorbed gas content when compared to Q2. In addition, the samples may still include a high total of in-situ desorbed gas content although their measured Q1 is low. For example, sample YC2-3 had a Q1 of approximately 0.02 cm3/g but a total in-situ desorbed gas content of approximately 1.09 cm3/g (Fig. 3). 3.2. Geochemical characteristics The Shuijingtuo Formation shale has a high degree of thermal evolution, as the Ro averaged 1.9%. The TOC resulted in levels between 1.3% and 3.4%, with an average content of 2.6%. Thus, the Shuijingtuo Formation is composed of organic-rich shale. The main mineral in the Shuijingtuo Formation shale is quartz, with an average of 34.4%. Following are carbonate and clay minerals, with an average of 26.8% and 18.4%, respectively. The feldspar
content is low, with an average of 12.5% (Fig. 7). The mineral composition varies little throughout the whole formation, showing a stable depositional environment present when the stratum was deposited. Using the methane isothermal adsorption curves (Fig. 8), the maximum adsorbed methane content (Q3) and the adsorbed methane content at 35 °C, the atmospheric pressure (Q4) can be obtained. The Q3 measured between 1.52 and 4.67 cm3/g, with an average of 2.67 cm3/g, which indicated a high adsorption capacity of the shale. The Q4 measured between 0.41 and 1.25 cm3/g, with an average of 0.80 cm3/g, clearly lower than the Q3 (Table 1). Using the nitrogen adsorption curves, the specific surface area and pore size distribution can be obtained (Fig. 9, Table 1). The specific surface area measured between 1.48 and 8.77 m2/g, with an average of 5.16 m2/g. The average pore size measured between 4.15 nm and 5.80 nm, with an average of 5.10 nm. The pore volume measured between 0.0004 cm3/g and 0.0027 cm3/g, with an average of 0.0015 cm3/g. The pore volume percent of pores sized greater than 11 nm (P1) was approximately 58%, while the pore volume percent of pore size smaller than 11 nm (P2) was approximately 42% (Table 1). Thus, the pore space of these shale samples was mainly the result of pores larger than 11 nm in diameter. 4. Discussions 4.1. Occurrence state of in-situ shale gas The occurrence state of shale gas is important for gas production. The in-situ desorbed gas in the coalbed is mainly sorbed gas, while the in-situ desorbed gas in the shale is mainly free gas
Fig. 7. Characteristics of Ro, TOC, mineral composition, and desorbed gas content of the Shuijingtuo Formation shale of the YC-2 well. The Ro has an approximately 1.9% average. The TOC has an approximately 2.6% average. The mineral composition is similar throughout the whole Shuijingtuo Formation shale.
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Fig. 8. Absolute isotherms of methane on the 27 shale samples. The lines are Langmuir fitting results.
Table 1 Adsorbed methane content, specific surface area, average pore size, and pore volume of the 27 shale samples. Q3: maximum adsorbed methane content, cm3/g. Q4: adsorbed methane content at 35 °C, atmospheric condition, cm3/g. P1: Pore volume percent of pore size larger than 11 nm, %. P2: Pore volume percent of pore size smaller than 11 nm, %. Sample ID
Depth (m)
Q3 with error range (cm3/g)
Q4 with error range (cm3/g)
Specific surface area with error range (m2/g)
Average pore size with error range (nm)
Pore volume with error range (ml/g)
P1 (%)
P2 (%)
CQ2-1 CQ2-2 CQ2-3 CQ2-4 CQ2-5 CQ2-6 CQ2-7 CQ2-8 CQ2-9 CQ2-10 CQ2-11 CQ2-12 CQ2-13 CQ2-14 CQ2-15 CQ2-16 CQ2-17 CQ2-18 CQ2-19 CQ2-20 CQ2-21 CQ2-22 CQ2-23 CQ2-24 CQ2-25 CQ2-26 CQ2-27
409.7 457.4 469.2 519.4 567.2 619.8 719.8 769.4 778.1 840.6 850.0 860.3 869.5 900.8 919.3 958.4 971.2 979.8 990.1 1010.5 1020.2 1032.0 1071.6 1089.7 1101.3 1112.5 1139.3
2.41 ± 0.02 1.80 ± 0.02 3.10 ± 0.03 2.40 ± 0.03 4.00 ± 0.04 1.78 ± 0.02 2.00 ± 0.02 2.25 ± 0.02 3.71 ± 0.04 3.17 ± 0.03 1.96 ± 0.02 1.70 ± 0.02 2.26 ± 0.02 2.68 ± 0.03 4.67 ± 0.05 2.86 ± 0.03 1.52 ± 0.01 2.49 ± 0.03 2.48 ± 0.02 3.34 ± 0.03 3.38 ± 0.03 2.05 ± 0.02 2.48 ± 0.02 2.74 ± 0.03 2.55 ± 0.02 2.05 ± 0.02 4.16 ± 0.04
1.23 ± 0.02 0.41 ± 0.01 1.25 ± 0.02 0.63 ± 0.01 0.79 ± 0.01 0.58 ± 0.01 0.68 ± 0.01 0.78 ± 0.01 0.99 ± 0.02 0.73 ± 0.01 0.54 ± 0.01 0.48 ± 0.01 0.72 ± 0.01 1.13 ± 0.02 0.74 ± 0.01 1.07 ± 0.02 0.66 ± 0.01 0.62 ± 0.01 0.94 ± 0.01 0.74 ± 0.01 1.24 ± 0.02 0.64 ± 0.01 0.74 ± 0.01 0.68 ± 0.01 0.77 ± 0.02 0.84 ± 0.01 0.99 ± 0.02
8.16 ± 0.08 2.59 ± 0.03 7.00 ± 0.06 6.91 ± 0.07 8.12 ± 0.08 1.48 ± 0.01 5.30 ± 0.03 5.15 ± 0.04 7.84 ± 0.06 3.73 ± 0.03 1.74 ± 0.02 2.47 ± 0.02 3.88 ± 0.03 5.55 ± 0.06 5.93 ± 0.05 4.42 ± 0.06 3.57 ± 0.03 5.46 ± 0.06 8.77 ± 0.09 4.58 ± 0.05 4.66 ± 0.03 7.16 ± 0.07 6.91 ± 0.04 2.82 ± 0.01 6.13 ± 0.04 4.99 ± 0.02 3.93 ± 0.02
5.38 ± 0.02 5.63 ± 0.01 4.59 ± 0.01 5.44 ± 0.01 5.07 ± 0.02 4.60 ± 0.02 5.06 ± 0.03 5.62 ± 0.02 5.11 ± 0.02 5.24 ± 0.03 5.80 ± 0.03 5.74 ± 0.02 5.40 ± 0.02 4.80 ± 0.01 4.15 ± 0.01 4.54 ± 0.01 5.68 ± 0.02 5.07 ± 0.02 5.10 ± 0.01 4.97 ± 0.03 5.66 ± 0.02 4.55 ± 0.01 4.91 ± 0.01 4.56 ± 0.01 5.37 ± 0.02 5.04 ± 0.03 4.60 ± 0.02
0.00148 ± 0.00011 0.00087 ± 0.00005 0.00107 ± 0.00008 0.00196 ± 0.00014 0.00178 ± 0.00012 0.00042 ± 0.00002 0.00123 ± 0.00009 0.00118 ± 0.00013 0.00248 ± 0.00019 0.00187 ± 0.00012 0.00084 ± 0.00005 0.00092 ± 0.00007 0.00079 ± 0.00004 0.00123 ± 0.00011 0.00198 ± 0.00016 0.00138 ± 0.00010 0.00133 ± 0.00009 0.00150 ± 0.00010 0.00265 ± 0.00022 0.00178 ± 0.00014 0.00101 ± 0.00005 0.00167 ± 0.00017 0.00195 ± 0.00013 0.00143 ± 0.00009 0.00246 ± 0.00022 0.00147 ± 0.00012 0.00134 ± 0.00008
33.8 57.5 36.4 35.2 25.8 57.8 56.9 34.7 39.9 46.0 50.0 64.3 41.8 35.8 41.4 39.1 40.6 38.7 40.8 37.1 39.6 33.5 36.9 42.7 41.9 38.8 37.3
66.2 42.5 63.6 64.8 74.2 42.2 43.1 65.3 60.1 54.0 50.0 35.7 58.2 64.2 58.6 60.9 59.4 61.3 59.2 62.9 60.4 66.5 63.1 57.3 58.1 61.2 62.7
and sorbed gas [12]. For the coalbed methane, the in-situ desorbed gas content is generally lower than the methane adsorption content of isotherms [37]. However, for the gas-rich shale, the insitu desorbed gas content is generally higher than the methane adsorption content of isotherms [12]. When the total in-situ desorbed gas content of shale is similar to the methane adsorption content of isotherms, the in-situ desorbed gas is mainly sorbed gas. When the total in-situ desorbed gas content of shale is higher
than the methane adsorption content of isotherms, however, the in-situ desorbed gas is a mixture of free and sorbed gas [10,12]. The stable carbon isotopes of different in-situ gas desorption stages of shale can also be used to obtain the ratio of free to sorbed gas [21]. In this study, the in-situ desorbed gas content at the high temperature desorption stage (Q2) was positively correlated with methane adsorption content at 35 °C and atmospheric pressure
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Fig. 9. N2 adsorption curves and pore size distribution of the 27 shale samples. (a) N2 adsorption curves. (b) Pore size distribution.
(Q4) (Fig. 10). The Q2, which is the content of residual gas at the reservoir temperature desorption stage was slightly lower than the Q4, which is the greatest methane adsorption content at the reservoir temperature desorption stage (35 °C, atmospheric pressure). The Q2 was similar to the Q4, indicating that the Q2 was in an adsorbed state in the shale at reservoir temperature. Therefore, the in-situ desorbed gas from the high temperature desorption stage was mainly sorbed gas, and the in-situ desorbed gas from reservoir temperature desorption stage was mainly free gas. Because the Q2 accounted for approximately 83.4% of the total in-situ desorbed gas content and the formation pressure was higher than the atmospheric pressure, which is more advantageous for gas adsorption [38], the shale gas in the Shuijingtuo Formation was mainly sorbed gas, which was likely greater than 83.4%.
sorbed gas in the shale (Fig. 11a). The shale gas in the Shuijingtuo Formation was mainly sorbed gas, which is difficult to desorb at a reservoir temperature of approximately 35 °C. This is maybe the main reason why the Shuijingtuo Formation shale still had a high gas content (average 0.84 cm3/g), even after a burial time of more than 500 Ma [39]. The Q1 percentage was negatively correlated with the Q3 (Fig. 11b). It suggested that, as methane adsorption capacity becomes stronger, free gas is more easily converted into sorbed gas in shale, thereby reducing the proportion of free gas. One limiting factor surrounding methane adsorption capacity is that the gas is adsorbed in the subsurface of shale rock, while methane adsorption capacity is tested via crushed powder from shale samples. This makes it difficult to infer whether the methane adsorption capacity of the powder sample would be the same as the bulk subsurface shale sample.
4.2. Controlling factors of in-situ desorbed gas content
4.2.2. Nano-scale pores The Q2 value, comprised primarily of sorbed gas, indicated a positive correlation with pore volume, specifically the percentage of pores measuring smaller than 11 nm (P2). This implies that the higher proportion of P2, the higher the proportion of sorbed gas (Fig. 12a). The Q2 also indicated a positive correlation with total pore volume, implying that pores in the shale are conducive to the formation of sorbed gas (Fig. 12b). Further, the Q2 showed a positive correlation with specific surface area; as seen in Fig. 12c, as the specific surface area increased, the Q2 also increased significantly, showing that the specific surface area has an obvious and positive influence on the sorbed gas. The Q1 percentage, comprising primarily free gas, indicated a positive correlation with pore volume, particularly the percent of pores measured larger than 11 nm (P1). This indicated that the higher proportion of P1, the higher proportion of free gas (Fig. 12d). The Q1 was negatively correlated with total pore volume, though, indicating that pores in the shale are not conducive to the formation of free gas, as free gas is easier lost during burial time (Fig. 12e). Further, the Q1 showed a negative correlation with specific surface area, indicating that the higher the specific surface area, the more likely the free gas is to convert into sobbed gas in the shale (Fig. 12f). The major limitation of the nano-scale pores is that pores smaller than 1.8 nm or larger than 135 nm cannot be detected due to the limit of the N2 adsorption test in this study. Therefore, the effect of the undetected pores on the in-situ desorbed gas content cannot be inferred. However, since the Shuijingtuo Formation shale
4.2.1. Methane adsorption capacity The Q2 percentage was positively correlated with the maximum adsorbed methane content (Q3), suggesting that the stronger the gas adsorption capacity of shale, the higher the percentage of
Fig. 10. Relationship between Q2 and Q4. The Q2 has a good positive relationship with Q4, while the Q2 is slightly lower than the Q4. Q2: in-situ desorbed gas content at high temperature desorption stage, cm3/g. Q4: adsorbed methane content at 35 °C, atmospheric condition, cm3/g.
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Fig. 11. Relationships between in-situ desorbed gas percent and maximum adsorbed methane content. (a) A positive correlation between Q2 percent and Q3. (b) A negative correlation between Q1 percent and Q3. Q1: in-situ desorbed gas content at reservoir temperature desorption stage, cm3/g. Q2: in-situ desorbed gas content at high temperature desorption stage, cm3/g. Q3: maximum adsorbed methane content, cm3/g.
Fig. 12. Relationships between in-situ desorbed gas content percent and pore volume percent, total pore volume, and specific surface area. Q1: in-situ desorbed gas content at reservoir temperature desorption stage, cm3/g. Q2: in-situ desorbed gas content at high temperature desorption stage, cm3/g. P1: Pore volume percent of pore size larger than 11 nm, %. P2: Pore volume percent of pore size smaller than 11 nm, %.
gas is primarily sorbed gas and the sorbed gas is largely adsorbed on the surface of small pores, those pores larger than 135 nm may have limited effect on total gas content. 4.3. Controlling factors of in-situ gas desorption rate Many factors control in-situ gas desorption Yang et al. simulated the adsorption-desorption process using crushed shale samples of three different particle sizes; the study indicated that the gas desorption rate would increase as the particle size decreased [8]. In regards to coalbed methane, the initial desorption rate was dependent upon the total gas content [40]. The coalbed would have a high initial desorption rate if there existed a high total gas content [40]. In this study, at the high temperature desorption stage, both the mean desorption rate (R2m) and highest desorption rate (R2h) had no obvious relationships to the average pore size (Fig. 13a and b). We speculate that this is because many factors affect the desorption rate of sorbed gas, such as pore size, gas adsorption capacity, and total gas content [8,40]. At the reservoir temperature desorption stage, both the mean desorption rate
(R1m) and the highest desorption rate (R1h) illustrated good relationships with average pore size (Fig. 13c and d). In addition, as the average pore size is increased, the R1m and R1h will increase exponentially. This is likely because the in-situ desorbed gas at the reservoir temperature desorption stage was mainly composed of free gas, and free gas migrates into larger pores more easily. This also suggests that the Shuijingtuo Formation Shale has, in general, a high pore volume and low free gas percentage. The R1m and R1h were generally lower than the R2m and R2h. At the reservoir temperature desorption stage, the pressure was the major difference between the subsurface shale and the shale in the desorption canister on the ground. At the high temperature desorption stage, temperature was the major factor, particularly compared to the reservoir temperature desorption stage. Temperature is more sensitive than pressure in relation to the adsorptiondesorption of shale [41]. Therefore, the in-situ gas desorption rate at the high temperature was higher than that at the reservoir temperature. This analysis of in-situ gas desorption rate is limited because shale maturity has an important effect on desorption rate; gas
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Fig. 13. Relationships between in-situ shale gas desorption rates and average pore size. (a) R2m has no obvious correlation with average pore size. (b) R2h has no obvious correlation with average pore size. (c) R1m has a positive correlation with average pore size. (d) R1h has a positive correlation with average pore size. R1m is the mean desorption rate at reservoir temperature desorption stage. R1h is the highest desorption rate at reservoir temperature desorption stage. R2m is the mean desorption rate at high temperature desorption stage. R2h is the highest desorption rate at high temperature desorption stage.
desorbs from the pores and releases through the interconnected pores. The high-mature shale would have more organic pores than the low-mature shale, leading to a better connectivity [42]. Thus, the high-mature shale may have a higher desorption rate than that of the low-mature shale. However, only the high-mature Cambrian Shuijingtuo Shale was tested in this study. The low-mature Cambrian shale is more difficult to find in China; because of this, the gas desorption characteristics of the low-mature shale are still unknown. 5. Conclusions The average in-situ desorbed gas content of the Cambrian Shuijingtuo Formation shale measured 0.84 cm3/g. The in-situ desorbed gas content and desorption rate at the reservoir temperature (35 °C) desorption stage both measured lower than that at the high temperature (90 °C) desorption stage. The shale gas in the Shuijingtuo Formation was primarily sorbed gas. The in-situ desorbed gas percent of the two stages was mainly controlled by methane adsorption capacity, pore volume, and specific surface area. The in-situ gas desorption rate at the reservoir temperature desorption stage was mainly controlled by average pore size, while the in-situ gas desorption rate at the high temperature stage was, perhaps, primarily controlled by average pore size and methane adsorption capacity. Acknowledgments This work was supported by the National Natural Science Foundation of China [41472112 and U1562215] and the China Shale Gas Geological Survey [12120114046701]. We also acknowledge the support of Chongqing Institute of Geology and Mineral Resources, and we express our appreciation for their approval to publish the data. We thank Professor Ningning Zhong, Xun Zhou, and Lipeng Yao for their help to the work of the in-situ gas desorption test.
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