a Key Laboratory of Petroleum Resources Research, Gansu Province/Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics, Chinese Academy of Sciences, Lanzhou 730000, China
bUniversity of Chinese Academy of Sciences, Beijing 100049, China.
In order to reveal the methane adsorption capacity influenced by the geological factors in the process of thermal evolution, a shale sample from Chang-7 Member of the Yanchang Formation in the southeastern part of the Ordos Basin was collected. Seven different samples were acquired to simulate burial depths through the thermal simulation experiment. The organic geochemical parameters, mineral composition, pore structure, and methane adsorption capacities were measured. According to this research, influence factors on methane adsorption capacity considering thermal evolution can be divided into three kinds: Physical factors such as specific surface area and pore diameter, organic geochemical factors such as TOC and thermal maturity, as well as mineral composition factors such as clay minerals and andreattite. Geological factors have intricate impacts on the methane adsorption capacity. Considering each factor was combined together, it may increase the significance of the adsorption amount and influence factors. Micro-pore is the most important factor, it has a positive correlation with the methane adsorption capacity. The adsorption quantity increases when TOC decreases due to the thermal evolution of organic produced micro-pores which increases the adsorption space. In addition, the adsorption capacity of shale has a negative correlation to the burial depth. The deeper it's buried the faster the adsorption capacity decreases.
Shale gas mainly exists in black shale through free and absorbed gases. Several studies show that absorbed gas is the main occurring state [1-3], accounting for more than 50% of shale gas content. Thus, it is critical to study the geological factors influencing the methane adsorption capacity in shale. To date, numerous scholars have conducted studies on the controlling factors of methane adsorption and have made significant accomplishments. Summarized factors that influence the methane adsorption capacity are the content of total organic carbon (TOC ), the organic matter type, maturity, the mineral composition of shale, the pore size distribution, and the water content [4-15]. Chalmers et al.  found the TOC content has a positive relationship with adsorbed gas which makes it the primary factor controlling the methane adsorption in the lower Cretaceous shale, British Columbia, Canada. Zhang et al.  proved that the better the organic matter type is, the stronger adsorption capacity is; the difference in maturity has no obvious effect on methane adsorption capacity. Ross et al.  discovered that the methane adsorption capacity increases with the increase of the TOC content as well as micropore in the Mississippi shale, Western Canada sedimentary basin. Ji et al. [19,20] used a Scanning Electronic Microscope (SEM) to observe the different pore distribution characteristics of clay-rich rock samples which are composed of clay minerals (illite, smectite, kaolinite, andreattite, etc.). Combining this with the methane adsorption experiment, it was found that the clay mineral adsorption capacity has a positive relationship with porosity and specific surface area; the adsorption capacity of various clay minerals follows the order smectite >> andreattite > kaolinite > chlorite > illite.
However, previous researches were independent and dispersed which lacked comprehensive evaluations of various controlling factors associated with geological conditions. The related researches about the effect of kerogen's thermal maturity on shale adsorption capacity are few [21,22]. Our current study simulated the processes of thermal evolution of shale by hydrous pyrolysis, and it analyzed the changes of the various parameters and their effects on the methane absorption ability by conducting organic geochemistry, petrology, and adsorption test on the artificially matured. Lastly, results were summarized and factors were classified on how they control methane adsorption capacity.
The samples in this research were taken from Upper Triassic Chang 7 Member Zhangjiatan shale in an open-cut mine of Hejiafang area, southwest Ordos Basin. The samples were organic-rich, it possessed a TOC of 28.8%. The Rock-Eval pyrolysis presented a hydrocarbon index (IH) of 631 mg/gTOC, an oxygen index (IO) of 2 mg/gTOC, and a T-max of 438 C. The values of S1 (dissolved hydrocarbon) and S2 (pyrolysed hydrocarbons) peak were 9.32 mg/g, 201.16 mg/g, respectively. The kerogen type for the experiment samples were TypeⅠ. The vitrinite reflectance (RO) was about 0.53%. To avoid destroying the original pore structure, the 7 samples were placed in a ⌀25 mm cylinder. As a requirement of the pyrolysis, samples were drilled from a bulk core and were labeled HJF-0 to HJF-6. Data are plotted according to the geological conditions corresponding to the different buried depths, the simulated experiment conditions (temperature, pressure, time) as shown on Table 1.
The pyrolysis experiments were conducted in the Lanzhou Institute of Geology, Chinese Academy of Sciences (LIG-CAS). Utilizing a WYMN-3 HTHP simulation instrument, this can imitate the lithostatic pressure and the hydrodynamic pressure by a hydraulic control system and deionized water. The equipment would maintain isothermal heating of samples with automatic pressure compensation and eventual expulsion of hydrocarbon right after the simulation temperature has reached the temperature point set in the first 2 h. Once the constant temperature time is over, the yields of the expelled oil, water, and gaseous hydrocarbon were collected and analyzed. Organic geochemistry, petrology, and Nitrogen adsorption measurement tests were conducted to evaluate the solid residues. All seven samples were collected from the same block to ensure freshness and to guarantee the consistency. In order to make the simulation experiment closer to the actual geological process we considered the hydrodynamic pressure of the geological evolution process and then designed the automatic pressure compensating device.
The primary factors influencing the methane adsorption capacity are TOC, the organic matter type, maturity, mineral composition, and pore size distribution, all of which changed with the evolution of thermal maturity. In order to study concrete changes of the various geological factors as well as the effects on the methane adsorption capacity, the organic carbon content, the vitrinite reflectance (RO), the whole rock analysis, clay minerals analysis with X-Ray diffraction (XRD), Scanning Electron Microscope (SEM), and nitrogen adsorption measurements were conducted on the original and thermal simulation samples after all the samples completed the experimental process of washing oil-out.
The experimental results of TOC and maturity are shown in Table 2. The total organic content as a whole decreased with the increase of thermal maturity. The Ro value of HJF-0, whose original Ro value was 0.53%, increased with the increase of temperature, pressure, and constant temperature. This caused the Ro value to reach its peak of 1.07%, which is consistent to the maturity stage of the organic matter evolution together with the decrease of the aliphatic chain structure of kerogen and the increase of aromatic structure. The increase of modeling temperature and thermal evolution degree caused the content of brittle mineral (quartz, feldspar and pyrite etc.) to change slightly (Fig. 1). The insignificant difference presented maybe caused by inhomogeneity of the original samples. The clay mineral compositions were mainly illite smectite mixed-layer and illite.
Nitrogen adsorption measurements were used to analyze the pore size and specific surface area. The measurements were carried out by an ASAP 2020 for the surface area, as well as a meso- and micro-pores analyzer. The working principle of the instrument was the isothermal physical adsorption static volumetric method. Prior to hydrous pyrolysis, shale samples were crushed and sieved to 40-60 mesh. The isothermal physical absorption-desorption experiment would begin under a low temperature experimental condition of 195.8 C, subsequently vacuum degassing takes place via heating and injecting high purity nitrogen gas. Afterwards, a density functional theory (DFT) analysis and a multi-point Brunauere Emmette Teller (BET) analysis regression model were used to acquire the pore size distribution and specific surface (Fig. 2).
At present, the most commonly used methods to test absorptive gas quantity are volumetric method and weight method. The weight method measures weight changes of pretest posttest samples to acquire the absorptive quantity of a specific gas via a magnetic suspension balance controlled by a temperature pressure control system. The broad acceptance of this weight method is primarily due to its outstanding advantages, such as better precision, intuitive data acquisition, and automatic pressure maintenance which could avoid consequences caused by gas leak. The isothermal adsorption experiments were conducted with Chongqing Mineral Resources Supervision & Test Center under the Ministry of Land and Resources' adsorption-desorption instrument Isosorp HP Static III magnetic suspension balance made by Rubotherm. The isothermal adsorption experiments were divided into two groups. The first group included the HJF-1, HJF-2, HJF-3, HJF-4, and HJF-5 under the experiment temperature of 50 C and pressure of 0-35 MPa. The second group included HJF-0, HJF-2, HJF-4, and HJF-6. The samples in group two represented the adsorption characteristics of various simulated buried depths. The specific experimental conditions of both groups were shown in Table 3.
Fig. 3 shows the isothermal adsorption curves of the first group. The methane adsorption quantity increased with the increase of pressure. All five samples reached adsorption equilibrium when pressure was increased to 25 MPa. Throughout the process of pressure increasing, the adsorbing gas quantity follows the order HJF-4 > HJF-2 > HJF-5 > HJF-0 > HJF-3.
Fig. 4 shows the isothermal adsorption curves of the second group. The methane adsorption quantity decreased with the increase of simulated burial depth. The adsorption quantity has a negative relationship with the micropore content and a positive correlation with the TOC content. Under the experimental simulation conditions representing the actual geological buried depth, the samples reach adsorption equilibrium except for HJF-0 which represents the buried depth of 1300 m. Analyzing the isothermal curve, the adsorption equilibrium pressures were 16 MPa, 30 MPa, 19 MPa, 21 MPa, these correspond to the samples HJF-6, HJF-4, HJF-2, and HJF-0, respectively. These curves generally present the trend that the adsorption equilibrium pressure decreases with the increase of simulated buried depth.
The shale geochemical parameters, physical parameters, and mineral compositions changed with the increased thermal evolution level. The calculated correlation coefficient values between various altered factors and adsorption quantity are shown in Table 4. The highest relationship between adsorption quantity and micropore, as shown in Table 4, had a correlation coefficient of 0.9268, followed by TOC of 0.4222 and a specific surface area of 0.4017. The correlation coefficient values of the other factors were lower than 0.3; quartz content and thermal maturity presented the lowest correlation. Various factors have a positive correlation with the adsorption capacity, but the TOC, RO, and quartz content, presents a negative correlation. It is worth noting that previous studies consistently showed that TOC is the primary factor influencing the methane adsorption capacity in the shale play, it also has a positive correlation with the adsorption capacity on a condition nearly similar to RO value [23-5]. However, in this search we attest that TOC has a negative correlation with the adsorption capacity in regards with the thermal evolution. The main whys and wherefores for this phenomenon are as follows: the shale thermal evolution increased with the decrease of TOC value in addition to the change of mineral composition; pore structure; specific surface area; conversion process of organic matter to oil produced a large number of micropore that's capable in providing adsorption space for methane. Therefore, this study presents the negative correlation between the TOC content and methane adsorption ability.
We analyzed the principal component of various geological factors using the orthogonal rotation accompanied by the Kaiser standardized method. We were able to obtain three principal components after five iteration converges (Table 5). According to the principal component load standard (>0.85), it can be seen that the first principal component mainly represents the physical factors (specific surface area, porosity, etc.). The second principal component represents the organic geochemical factors (TOC, maturity, etc.), and the third principal component represents the mineral compositions such as the content of clay minerals and andreattite. Consequently, we can classify the factors influencing the methane adsorption capacity into three types: physical factors, organic geochemical factors, and mineral compositions.
Various geological factors change through the thermal evolution, the factors influencing the methane adsorption ability should have extensive consideration. The TOC content is considered to be the primary factor to influence the methane adsorption ability. Hence, we introduce the concept “the adsorption quantity per unit of TOC” to analyze the relationship between the adsorption quantity per unit of TOC, along with specific surface area and porosity (Fig. 5). We found that the correlation coefficient increased at different degrees with the thermal evolution. The correlation coefficient of the specific surface area and porosity increased from 0.4017 to 0.7581, and 0.2569 to 0.5243, respectively. The correlation coefficients between the other geological factors and adsorption quantity per unit of TOC present the same trends.
Fig. 6 shows the three dimensional relationship between the adsorption quantity and geological factors. All the correlation coefficients were above 0.85, this shows a large scale increase compared to the single factor. Although the correlation coefficient between the RO value and adsorption quantity is 0.0065, the three dimensional correlation coefficient between RO, micropore, and adsorption quantity reached 0.9527. The correlation coefficient between RO, TOC, and adsorption quantity also reached a soaring value of 0.8850. Examining the three dimensional correlation coefficients in contrast among the other factors like micropore and adsorption quantity, the correlation coefficient of micropore is much greater than the others. This pointed out that micropore is the primary influence factor on the adsorption ability. In addition, by analyzing the two linear correlation equations of TOC-adsorption quantity and RO-adsorption quantity, both values have negative correlation with adsorption quantity regardless of a close correlation coefficient.
As the burial depth of shale accounts increased in support of the increase of temperature and pressure, the thermal evolution of shale amplified as well. According to the second group's isothermal adsorption experiment, we found that the adsorption quantity gradually decreased with the increase of simulated burial depth; the rate of descent is higher in large buried depth than in the shallow one's. Pressure had a considerable influence on the adsorption quantity. On the low pressure condition, pressure became the main influence factor. The adsorption quantity increased rapidly with the increase of pressure. On a relatively high-pressure condition, temperature had a bigger impact on adsorption quantity. The lower the temperature, the higher adsorption quantity. When the formation pressure reaches its maximum value because of the increasing simulated buried depth, the adsorption quantity is mainly decided by temperature, adsorption capacity then presents the negative correlation with buried depth. In the comparison results of the two groups' isothermal adsorption experiments, the adsorption quantity increased with the increase of pressure. The adsorption quantity in the first group is higher than in the second for the same sample because the adsorption ability has a negative correlation with the temperature [26-28].
(1) By combining the thermal simulation experiment with the isothermal adsorption experiment, the factors influencing the methane adsorption ability with thermal evolution are classified into three types: physical factors, organic geochemical factors, and mineral compositions.
(2) The methane adsorption ability is influenced greatly by various geological factors. Micropore is the primary factor influencing the adsorption quantity. The greater the micropore content, the higher the adsorption quantity. The TOC value has a negative correlation with the adsorption ability. Clay minerals and illite have a positive relationship with the adsorption quantity.
(3) The buried depth has a negative correlation with the adsorption quantity. The adsorption quantity decreased faster with the increase of large simulated buried depth. Scrutinizing the main reason brought about that the adsorption ability has a negative correlation with the temperature; the increased simulated buried depth brings temperature to rise.
Supported by National Natural Science Foundation of China (41272144); Chinese Academy of Sciences Strategic Leading Science and Technology Project (Class B) (XDB10010300); the National Natural Science Foundation for Youg Scientists of China (41402130); Light of the Western Project, Gansu Province Science and Technology Plan (1309RTSA041).
The authors declare no conflict of interest.
Authors: Jiaai Zhonga,b, Guojun Chena, Chengfu Lva, Wei Yanga,b, Yong Xua,b, Shuang Yanga,b, Lianhua Xuea
Received 25 November 2015; revised 28 December 2015, Available online 3 May 2016
This is English translational work of an article originally published in Natural Gas Geoscience (in Chinese). The original article can be found at:10.11764/j.issn.1672-1926.2015.07.1414.
* Corresponding author.
E-mail address: email@example.com (G. Chen).
Peer review under responsibility of Editorial Office of Journal of Natural Gas Geoscience.
2468-256X/Copyright © 2016, Lanzhou Literature and Information Center, Chinese Academy of Sciences AND Langfang Branch of Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
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