Water sorption behaviour of gas shales: I. Role of clays

Zolfaghari, Ashkan; Dehghanpour, Hassan; Holyk, Jordan

doi:10.1016/j.coal.2017.05.008

Cited by 121 publications

(79 citation statements)

References 37 publications

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“…This may be attributed to the strong electrostatic force between the clay and water. Clay has more affinity to attract and adsorb water than nitrogen molecules, so it is also difficult to replace clay bond water by N 2 [14,45,46]. In contrast, organic matter has low attractive force to water due to the carbon and graphite surface chemistry that comprises organic matter, and the weak carbon/water dispersive attraction and strong water/water associated interactions.…”

Section: Low N 2 Pressure Adsorption Resultsmentioning

confidence: 99%

Influence of Water Immersion on Pore System and Methane Desorption of Shales: A Case Study of Batu Gajah and Kroh Shale Formations in Malaysia

et al. 2018

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Abstract:The influence of water on the pore system and gas desorption in shale remains an open question that is not yet fully understood. In this study, we present the effect of water on the shale pore system and recovered desorbed gas through a series of measurements on shale samples. We utilized the Brunauer-Emmett-Teller (BET) low pressure N 2 adsorption and Field Emission Scanning Electron Microscopy (FE-SEM) to observe and analyze the effects of water immersion and moisture on the pore system of shale samples from Batu Gajah (BG) and Kroh shale formations in Malaysia. The impact of water on desorption was then measured using the United States former Bureau of Mines (USBM) modified method. The results showed that the micropore and mesopore volumes of the Batu Gajah (BG) and Kroh (KH) shale samples were reduced by 64.84% and 44.12%, respectively, after the samples were immersed in water. The BET-specific surface area declined by 88.34% and 59.63% for the BG and KH sample, respectively. Desorption results showed that the methane desorbed volume was (KH: 1.22 cc/g, BG: 0.94 cc/g) for the water immersed sample, and (KH: 0.72 cc/g, BG: 0.60) for the equilibrated sample. The difference can be attributed to the proportion of the organic (total organic carbon) and inorganic (clay) content found in the two shale samples. The total organic carbon (TOC) existing in the KH sample was 12.1 wt %, which was greater than the organic carbon content of the BG sample (2.1 wt %). The clay content was found to be more dominant in the BG shale when compared to the KH shale.

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Section: Low N 2 Pressure Adsorption Resultsmentioning

confidence: 99%

Influence of Water Immersion on Pore System and Methane Desorption of Shales: A Case Study of Batu Gajah and Kroh Shale Formations in Malaysia

et al. 2018

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“…X-ray diffraction is a common method to measure the mineral and clay components, which is especially important for the study of unconventional reservoirs. The clay content in shale formations is relatively high, which can easily cause hydration, and then affect the pore characteristics [39][40][41]. The atomic composition and arrangement of different minerals is different, so the X-rays scattered by different atoms interfere with each other and produce strong X-ray diffraction in some special directions.…”

Section: X-ray Diffractionmentioning

confidence: 99%

The Effect of Hydration on Pores of Shale Oil Reservoirs in the Third Submember of the Triassic Chang 7 Member in Southern Ordos Basin

et al. 2019

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Shale oil is an unconventional kind of oil and gas resource with great potential. China has huge reserves of shale oil, and shale oil resources are abundant in the third submember of the Triassic Chang 7 member in the southern Ordos Basin. At present, this area is in the initial stage of shale oil exploration and development. The reservoir pore is one of the key factors affecting oil accumulation, drilling safety, and oil production. It is also an important reservoir parameter that must be defined in the exploration stage. In general, the clay content in the shale section is high, and is prone to hydration. In order to study the effect of fluid on the pore type, structure, and distribution of shale oil reservoirs, experiments using X-ray diffraction, a porosity-permeability test, mercury porosimetry, rock casting thin section, and scanning electron microscopy were carried out. The experimental results show that the content of clay and quartz is very high in the studied formation. The pore porosity and permeability of the rock is highly heterogeneous because of the obvious stratigraphic bedding and interbeds. Microstructural observation of rocks shows that the main pore types are intergranular pores, intragranular pores, intercrystalline pores, and organic pores. Crack types are dissolution cracks, contraction cracks of organic matter, and abnormal pressure structural cracks. After hydration, the porosity of rock will increase in varying degrees, and pore size, pore content in different sizes, and pore structure will also change. The results show that the pores of tuff mainly changes at the initial stage of hydration, and the pore change of tuff is the most obvious within 6 hours of soaking in clear water. The influence of hydration on the pore of shale is greater than that of tuff, but the main change stage is later than tuff, and the pore change of shale is the most obvious within 12 to 24 hours of soaking in clear water. The soaking experiment of water-based drilling fluid (WBM-SL) shows that it can plug a certain size of holes and cracks and form a protective layer on the rock surface, thus effectively reducing hydration. In actual construction, multisized solid particles should be allocated in drilling fluid according to the formation pore's characteristics, and the stability of the protective layer should be guaranteed. This can reduce the accident of well leakage and collapse and is conducive to the efficient and safe development of shale oil.

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“…Clay interparticle pores are among the major contributors to pore volumes with widths <100 nm [25]. Clay swelling may produce natural fractures in the shale sample and create additional pore volume [34]. In samples with low feldspar content (<10%), the total porosity decreased with carbonate content (Figure 3e).…”

Section: Relationship Between Compositions and Ccp Porositymentioning

confidence: 99%

Total Porosity Measured for Shale Gas Reservoir Samples: A Case from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China

Chen

Duan

et al. 2018

Minerals

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Measuring total porosity in shale gas reservoir samples remains a challenge because of the fine-grained texture, low porosity, ultra-low permeability, and high content of organic matter (OM) and clay mineral. The composition content porosimetry method, which is a new method for the evaluation of the porosity of shale samples, was used in this study to measure the total porosity of shale gas reservoir samples from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China, based on the bulk and grain density values. The results from the composition content porosimetry method were compared with those of the Gas Research Institute method. The results showed that the composition content porosimetry porosity values of shale gas reservoir samples range between 2.05% and 5.87% with an average value of 4.04%. The composition content porosimetry porosity generally increases with increasing OM and clay content, and decreases with increasing quartz and feldspar content. The composition content porosimetry results are similar to the gas research institute results, and the differences between the two methods range from 0.05% to 1.52% with an average value of 0.85%.Minerals 2019, 9, 5 2 of 12 and fossil fragment pore [15]. At present, the techniques available for the measurement of micro-pore characteristics of shale samples are divided into two categories: the radiation method and the penetration fluids method [16].The radiation methods include scanning electron microscopy (SEM), field emission scanning electron microscopy (FE-SEM), backscatter mode (BS), transmission electron microscopy (TEM), small-angle neutron scattering (SANS), ultra-small-angle neutron scattering (USANS), three-dimensional (3D) reconstruction technology, and computed tomography (CT). Most provide direct visual observation of microscopic features in shale samples [17][18][19][20][21]. 3D image reconstruction technology can be used to investigate shale microstructure and analyze the characteristics of pores. For the radiation methods, a higher resolution corresponds to a smaller sample size [22], and the smaller samples are less representative given shale's heterogeneity [16,19]. The penetration fluid methods include low temperature nitrogen adsorption/desorption (LTNA), mercury intrusion porosimetry (MIP), and nuclear magnetic resonance (NMR). The first two methods refer to injecting non-wetting fluid into a shale sample and recording the fluid volume and injection pressure. Then, the pore size distribution and specific surface area are calculated using several theoretical models [17,[23][24][25]. Due to the differences in experimental environment (temperature and pressure) and injected fluid properties, LTNA and MIP methods have different detection ranges. The nanometer-to micrometer-scale pore systems in shale samples were evaluated by combining their results [17,23]. However, LTNA and MIP methods can only reflect interconnected pores, as the injected fluids cannot access isolated pores [16]. The result of the MIP method reflects the pore volu...

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Water sorption behaviour of gas shales: I. Role of clays

Cited by 121 publications

References 37 publications

Influence of Water Immersion on Pore System and Methane Desorption of Shales: A Case Study of Batu Gajah and Kroh Shale Formations in Malaysia

Influence of Water Immersion on Pore System and Methane Desorption of Shales: A Case Study of Batu Gajah and Kroh Shale Formations in Malaysia

The Effect of Hydration on Pores of Shale Oil Reservoirs in the Third Submember of the Triassic Chang 7 Member in Southern Ordos Basin

Total Porosity Measured for Shale Gas Reservoir Samples: A Case from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China

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