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Volume 32 Issue 4
Aug.  2021
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Yanqi Zhang, Li Liu. Insights into the Formation Mechanism of Low Water Saturation in Longmaxi Shale in the Jiaoshiba Area, Eastern Sichuan Basin. Journal of Earth Science, 2021, 32(4): 863-871. doi: 10.1007/s12583-020-1353-3
Citation: Yanqi Zhang, Li Liu. Insights into the Formation Mechanism of Low Water Saturation in Longmaxi Shale in the Jiaoshiba Area, Eastern Sichuan Basin. Journal of Earth Science, 2021, 32(4): 863-871. doi: 10.1007/s12583-020-1353-3

Insights into the Formation Mechanism of Low Water Saturation in Longmaxi Shale in the Jiaoshiba Area, Eastern Sichuan Basin

doi: 10.1007/s12583-020-1353-3
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  • Investigating the variation of water content in shale reservoir is important to understand shale gas enrichment and evaluate shale gas resource potential. Low water saturation is widely spread in Longmaxi marine organic-rich shale. To illustrate the formation mechanism of low water saturation, this paper analyzed water saturation of Longmaxi shale reservoir, restored the history of natural gas carrying water capacity combining homogenization temperature and trapping pressure of fluid inclusion with simulated thermal history, and established a model to explain pore water displaced by natural gas during the thermal evolution. Results show that the gas-rich Longmaxi shale reservoir is characterized by low water saturation with measured values ranging from 9.81% to 48.21% and an average value of 28.22%. TOC in high-mature to over-high-mature Longmaxi organic-rich shale is negatively correlated with water saturation, indicating that well-connected organic pores are not available for water. However, quartz and clay mineral content are positively correlated with water saturation, which suggests that inorganic-matter-hosted pores are the main storage space for water formation. The water carrying capacity of natural gas varies as a function of gas generation and expulsion history, which displaces bound and movable water in organic pores that are part of bound and movable water from inorganic pores. The process can be divided into two phases. The first phase occurred due to the kerogen degradation into gas at Ro of 1.2%-1.6% with a water carrying capacity of natural gas ranging from 5 632.57-7 838.73 g/km3. The second phase occurred during the crude oil cracking into gas at Ro>1.6% with a water carrying capacity of natural gas ranging from 10 620.04 and 19 480.18 g/km3. The water displacement associated with natural gas generation and migration resulted in gas filling organic pores and gas-water coexisting in the brittle-mineral-hosted pores and clay-mineral-hosted pores.
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Insights into the Formation Mechanism of Low Water Saturation in Longmaxi Shale in the Jiaoshiba Area, Eastern Sichuan Basin

doi: 10.1007/s12583-020-1353-3

Abstract: Investigating the variation of water content in shale reservoir is important to understand shale gas enrichment and evaluate shale gas resource potential. Low water saturation is widely spread in Longmaxi marine organic-rich shale. To illustrate the formation mechanism of low water saturation, this paper analyzed water saturation of Longmaxi shale reservoir, restored the history of natural gas carrying water capacity combining homogenization temperature and trapping pressure of fluid inclusion with simulated thermal history, and established a model to explain pore water displaced by natural gas during the thermal evolution. Results show that the gas-rich Longmaxi shale reservoir is characterized by low water saturation with measured values ranging from 9.81% to 48.21% and an average value of 28.22%. TOC in high-mature to over-high-mature Longmaxi organic-rich shale is negatively correlated with water saturation, indicating that well-connected organic pores are not available for water. However, quartz and clay mineral content are positively correlated with water saturation, which suggests that inorganic-matter-hosted pores are the main storage space for water formation. The water carrying capacity of natural gas varies as a function of gas generation and expulsion history, which displaces bound and movable water in organic pores that are part of bound and movable water from inorganic pores. The process can be divided into two phases. The first phase occurred due to the kerogen degradation into gas at Ro of 1.2%-1.6% with a water carrying capacity of natural gas ranging from 5 632.57-7 838.73 g/km3. The second phase occurred during the crude oil cracking into gas at Ro>1.6% with a water carrying capacity of natural gas ranging from 10 620.04 and 19 480.18 g/km3. The water displacement associated with natural gas generation and migration resulted in gas filling organic pores and gas-water coexisting in the brittle-mineral-hosted pores and clay-mineral-hosted pores.

Yanqi Zhang, Li Liu. Insights into the Formation Mechanism of Low Water Saturation in Longmaxi Shale in the Jiaoshiba Area, Eastern Sichuan Basin. Journal of Earth Science, 2021, 32(4): 863-871. doi: 10.1007/s12583-020-1353-3
Citation: Yanqi Zhang, Li Liu. Insights into the Formation Mechanism of Low Water Saturation in Longmaxi Shale in the Jiaoshiba Area, Eastern Sichuan Basin. Journal of Earth Science, 2021, 32(4): 863-871. doi: 10.1007/s12583-020-1353-3
  • As global demand for natural gas intensifies, identifying and producing reserves from unconventional shale resources have gained considerable exploration interest and activity. One such unconventional shale gas system is the Longmaxi shale, which is both source rock and reservoir rock for the largest shale gas field in eastern Sichuan Basin.

    The variation of water content in shale reservoir plays an important role in controlling the occurrence and enrichment of shale gas. A previous study on the occurrence characteristics of coalbed methane by Tian and Li (2007) suggests that the effective adsorption sites of the inner coal surface available for gas molecules are certain. They go to suggest that when the water content in coal is high, there is a greater adsorption of methane, which reduces the potential of gas molecules adoption. Similarly, the higher the water content, the larger the pore space occupied by water, thus reducing the retention volume of free gas and the surface position of adsorbed gas on the mineral surface in the shale reservoir. Chalmers et al. (2012a) proposed that water occupied the surface of inorganic minerals, resulting in the reduction of the surface area for adsorbing methane, especially in the clay mineral pores. Ross and Bustin (2009) and Gasparika et al. (2014) suggested that, compared with dry condition, the methane adsorption capacity of mudstone and organic-rich shale was reduced by 65%–90% and 20%–60%, respectively, under the balanced water condition using 38 shale samples from the western Canada Basin, Barnett shale samples from the United States and 40 shale samples in the Alum region of Europe. Korb et al. (2014) found that in shale reservoirs, oil occurred in organic pores and water in inorganic pores, and the adsorption capacity of clay minerals (illite, kaolinite, montmorillonite) will be reduced by 80%–95% under water conditions, which involving the complex interaction of gas, liquid, and solid.

    Therefore, water has a significant impact on adsorption capacity of mudstone and organic-rich shale. Ross and Bustin(2009, 2007) found that, the adsorption capacity of shale decreased significantly when the water content was > 4%, and the adsorption capacity of water-saturation was 40% lower than a dry sample. In addition, the increasing water content in shale may lead to variation of the natural gas phase because the amount of natural gas dissolved in the pore water will increase with water content in shale, which occurs as a dissolved phase (Shen et al., 2019; Pommer and Milliken, 2015).

    Similar to the shale reservoirs in shale-gas-rich basins in the United States, the shale reservoirs of Wufeng Formation and Longmaxi Formation in the Jiaoshiba area are also characterized by high gas saturation, high single well production and low initial water saturation, where the original water saturation is lower than the irreducible water saturation (Gou and Xu, 2019). Previous studies by Liu and Wang (2013) and Fang et al. (2014) suggest that the initial water saturation (SWI) of the gas-rich Longmaxi shale reservoir was commonly lower than 50%, while the irreducible water saturation (Swirr) could be 75%–85%, suggesting that the initial water saturation of low porosity and low permeability shale reservoir is far lower than the irreducible water saturation. The previous study by Bryndzia (2012) suggest that the gas-rich shale from the Haynesville basin explains this phenomenon by using burial history, hydrocarbon generation, and expulsion processes. In 2006, Wang et al. first proposed that inorganic components participated in the transformation of organic matter during the hydrocarbon generation, where water promoted the reaction mechanism and provided hydrogen and oxygen from hydrocarbon and oxidation products, e.g., CO2. Lewan (1997) and Schimmelmann et al. (2001, 1999), found that water participating in the chemical reaction of hydrocarbon generation could increase the yields of hydrocarbons, CO2 and H2, especially the yields of methane during the high evolution stage. Secondly, the formation of shale gas requires considerable geological time, and the water content in shale reservoir depends on the formation temperature and pressure. The ability of water to carry natural gas in shale reservoir is continuously enhanced with increasing burial depth, temperature, and pressure. However, the formation mechanism of low water saturation in gas-rich Longmaxi shale reservoir is important yet poorly understood. Thus, this paper aims to investigate the characteristic and partly explain the formation mechanism of low water saturation in gas-rich Longmaxi shale reservoir through: analyzing fluid inclusion petrography, homogenization temperature and trapping pressure, restoring the variation of water-carrying ability of natural gas with increasing burial history, hydrocarbon expulsion process and establishing formation model of low water saturation, which provides insight into revealing shale gas accumulation mechanism and evaluating shale gas resource potential.

  • The Jiaoshiba area is part of the Jiaoshiba structure in the southeast of eastern Sichuan fold belt and is bounded by the west of the Qiyueshan fault belt, which is famous for the Fuling national shale gas demonstration zone (Fig. 1). It is a special positive structural unit in the Wanxian synclinorium. The Jiaoshiba structure is a broad box-shaped faulted anticline with NE- trending axial under the control of NE-trending and SW-trending faults, and is divided by fault uplift, fault depression and the Qiyueshan fault (Shen et al., 2020). It is different from the NE-trending or NS-trending faults, which have narrow and high- dipping anticlines on both sides. The main body of the Jiaoshiba structure is weakly deformed with uniform upper and lower structures that are characterized by box-like faulted anticline which have gentle, wide top, small dip angle, and dipping wings.

    Figure 1.  Sketch map showing the structure units of the Sichuan Basin, West China, and location of the study area.

    Most of the Palaeozoic can be found in the Jiaoshiba structure, however without the Devonian and only the Huanglong Formation in the carboniferous, while the Middle Triassic Jialingjiang Formation is exposed. The black and gray black marine shale primarily occurs at the Upper Ordovician Wufeng (O3w) and lower section of Lower Silurian Longmaxi Formation (S1l) with burial depth of 2 400–3 000 m (Fig. 2), which are considered as the most extensive and organic-rich shales in this petroliferous basin.

    Figure 2.  Generalized stratigraphic column showing lithology, strata classification and thickness in the study area (modified from Yang et al., 2016b).

    Rapidly rising global sea level resulted in deep water shelf deposits in the confined paleogeography of this study area during the Late Ordovician and Early Silurian, and consequently organic-rich O3w–S1l marine shale was deposited at the low- energy and anoxic sedimentary environment (Nie et al., 2018; Li et al., 2015). Specifically, the O3w shale was mainly deposited in the early highstand system tracts, while the lower S1l Shale overlaying conformably on the O3w shale was primarily deposited in the late highstand system tracts, respectively (Yang et al., 2016a; Chen et al., 2015). O3w–S1l marine shale varies slightly in thickness with the present-day thickness of about 89–102 m under the control of the sedimentary environment in the study area. The O3w shale is mainly black fine-grained carbonaceous shale with a thickness of about 5–8 m. S1l shale is dominated by black shale with abundant fossils, e.g., graptolites and radiolarian, with a thickness of 60–110 m. S1l shale can be subdivided into three units from bottom to top. The Lower S1l is dominated by black carbonaceous shale, carbonaceous mudstone, argillaceous siltstone, and siliceous shale. The middle unit is primarily gray siltstone interbedded with dark gray argillaceous siltstone with a thickness of 50–100 m. The upper unit is generally dark-gray mudstone and gray shale with fewer fossils with thickness of about 160 m.

    The S1l marine shale is characterized by high-over high mature (Ro: 2.5%–3.0%) and types Ⅰ and Ⅱ1 kerogen (Jiang et al., 2019; Song et al., 2019). The organic-rich marine shale is mainly deep-water deposit with TOC of 3.0%–6.0%. The shale interval is regarded as high-quality reservoir with high brittle mineral content and a high porosity of 2.8%–7.1%. The Longmaxi Formation gas is dominated by methane and has a methane content of 97.22%–98.47%, which was primarily derived from oil cracking. Over 100 drilling data show that pressure coefficients of the main structural unit are commonly in a range of 1.30 to 1.55, indicating the occurrence of high-saturation and overpressure in shale reservoir. The current temperature gradient is about 30.8 ℃/km.

  • Rock physical property data, e.g., porosity and permeability, and drilling data were collected from the Jianghan Oilfield, SINOPEC.

    The total organic carbon (TOC) was measured using a Leco CS230 carbon/sulfur analyzer. Samples were crushed and sieved into a powder with grain size less than 100 mesh, and then powered shale sample (1 g) in a porous crucible was treated using 5% HCl at 80 ℃ for 2 h to remove any carbonate. The samples were washed out using deionized water to remove residual HCl and then were dried overnight at 70 ℃ after water was drained from the crucible. With no vitrinite in the samples, the optical feature and bitumen reflectance were determined through observing polished surfaces of samples using MSP 200 microphotometer following the Chinese National Standards SY/T5124-2012. All TOC and bitumen reflectance measurements were carried out in the Experimental Research Center of Wuxi Research Institute of Petroleum Geology, SINOPEC.

    Bulk mineralogical compositions were determined from the X-ray diffraction patterns on 25 shale samples using Bruker D8 Advance instrument in the Experimental Research Center of Wuxi Research Institute of Petroleum Geology, SINOPEC. Powdered samples (1 g) were analyzed with a powder diffractometer, and the XRD patterns were measured over a 2θ interval of 3°–60° at 0.02° with voltage and current of 30 kv and 15 mA, respectively, using an internal standard operation procedure following the Chinese Oil and Gas Industry Standard (SY/T) 5163-2010. The quantitative mineralogy of samples was subsequently determined through examining the spectra with relative intensity ratio (RIR) method from Chung (1974).

    A total of 90 samples were collected from thin siltstone interlayer with quartz-calcite veins in the Lower Silurian Longmaxi organic-rich shale from 4 wells (well location in Fig. 1) to perform fluid inclusion analyses.

    Double-polished thin-sections (thickness of 0.2–0.3 mm) were prepared with 502 glue to investigate petrography of fluid inclusions through mono-polarizer and fluorescent light observation using an Olympus Microscope. The distribution, geometry, size and period of fluid inclusions were systemically studied. Microthermometry was measured using a Linkam THMS 600 heating-cooling stage (accuracy of ±0.1 ℃). Aqueous inclusions were heated from room temperature to the homogenization temperature using a heating rate of 10 ℃/min.

    This paper analyzed the laser Raman shift (wave number) of methane-saturated inclusions under different trapping temperature, since the laser Raman shift varied with temperature and pressure. The Laser Raman shift was used to determine the methane density of these inclusions, consequently, the internal pressure was calculated using the equations from Duan et al. (1992) and homogenization temperature. The Laser Raman microprobe analyses was carried out using a JY/Horiba LabRam HR800 Raman system equipped with a frequency doubled Nd: YAG laser (532.06 nm) and output laser power of 14 mW. Paleo pressure was restored through requiring the n0=2 917.80 cm-1 of Raman spectrometer with the laser Raman shift (wave number) of methane inclusions under 25 ℃ and 0.1 MPa. All these experiments were conducted in the Analysis and Testing Center in the CNNC Beijing Research Institute of Uranium Geology.

    Water saturations were determined on 113 samples through moisture-equilibrating the samples at constant humidity conditions (temperature of 24 ℃). Samples (10 g) were firstly crushed into powder with particle size of 0.5–1.0 mm, which was dried at 110 ℃ in vacuum to determine the dry weight, and then was equilibrated over a saturated salt water in an evacuated desiccator until weight constancy. Consequently, the water saturation was calculated using following equation.

    where Sw is the water saturation of shale reservoir, %, Md and Mw are the weight of dry samples and water-saturated samples, g.

    Thermal and burial evolution histories of JY A Well were modeled using one-dimensional (1D) inverse model section of PetroMod software under the control of the measured Ro and other geological data. Input data, e.g., depositional ages, formation thicknesses, erosion, and lithologies, were assigned from drilling data. Thermal maturity and hydrocarbon generation were simulated using the EASY% Ro model of Burnham and Sweeney (1989). The modeled thermal maturity was calibrated with the observed vitrinite reflectance (Ro%) data in JY A Well has been excellent matched with each other, which indicates that the maturity evaluating was acceptable in this study. The variation of paleo-water-depth (PWD) was assumed with sedimentary facies and corresponding sedimentary water depth. Sedimentary water interface temperature (SWIT) was determined by the global sedimentary water interface temperature-time template in software package with the location of Jiaoshiba area. Heat flow (HF) was set in "Create heatflow trend from McKenzie Model" in software package as input.

  • Data (Fig. 3) show that water saturation in the gas-rich Longmaxi shale reservoir ranges between 9.81%–48.21% with an average of 28.22%, indicating low water content in the shale reservoir.

    Figure 3.  Histograms of water saturation in the gas-rich Longmaxi shale reservoir.

    Microscopic observation of fluid inclusions shows that considerable methane-rich fluid inclusions occur in the quartz particles in the thin siltstone interlayer, coexisting with brine inclusions and hydrocarbon. The hydrocarbon inclusions are generally gray and dark gray, while brine inclusions with hydrocarbon are colorless or gray. Methane-rich fluid inclusions are commonly distributed in zonal or linear pattern in the microfracture across quartz grains and in the enlarged quartz edges (Fig. 4). Fluid inclusions are commonly regular in shape, e.g., ellipse-like and bubble-like in shape. The size of inclusions varies greatly, ranging from 1×5 μm–15×20 μm.

    Figure 4.  Photomicrographs showing the occurrence of gray hydrocarbon inclusions and associated colorless brine inclusions as group and belt in the Longmaxi shale. (a) JY A Well, 3 045.6 m, fluid inclusions in the microfracture across quartz grains; (b) JY B Well, 2 582.4 m, fluid inclusions in the enlarged quartz edges; (c) JY C Well, 2 263.5 m, fluid inclusions in the microfracture across quartz grains; (d) JY D Well, 2 263.5 m, fluid inclusions in the microfracture across quartz grains.

    Microthermometry analyses show that the homogenization temperature of gas-liquid two-phase brine inclusion coexisting with methane inclusions in Longmaxi Formation ranges from 140 to 210 ℃ with peak values at 160–170 and 180–200 ℃ (Fig. 5a), indicating two episodes of gas enrichment. The trapping pressure of methane inclusions is 38.30–98.28 MPa with two main peaks at 40–70 and 80–98.28 MPa (Fig. 5b).

    Figure 5.  Histograms of homogenization temperature (a) and capture pressure (b) for fluid inclusions in the siltstone in the Longmaxi shale.

    Experiments show that the laser Raman displacement (wave number) of high-purity methane fluid inclusions increases with temperature under constant pressure, and decreases with pressure under constant pressure and temperature. The micro petrographic observation and laser Raman spectrum analysis of the fluid inclusions detect considerable pure methane inclusions in the fluid inclusions, which can be used for the pressure recovery of the high-purity methane inclusions. The density ranges of the high-purity methane inclusions calculated by the laser Raman displacement is 0.226–0.289 g/cm3.

    Bennion et al. (1999) suggested that the evaporation and carrying water capacity of natural gas was 1 136.7 g/m3 at 27.57 MPa and 100 ℃, but only 14.0 g/m3 at 1.013 MPa and 15.6 ℃, which significantly increased with temperature and pressure. These data show the water carrying capacity of nature gas linearly increases with pressure (Fig. 6a) under certain temperature and exponentially grows with temperature under certain pressure (Fig. 6b), both of which have high correlation coefficient. An empirical formula was established using these data and the relationship between water carrying capacity and pressure/temperature in Fig. 6 (Eq. 1), which can be used to determine the water carrying capacity of nature gas in the Longmaxi shale. Results show that the water carrying capacity of natural gas is generally between 3 039.91 and 26 343.60 g/km3. Specifically, the water carrying capacity of natural gas determined by the two peaks can be divided into two groups with values ranging between 5 632.57–7 838.73 and 10 620.04–19 480.18 g/km3, indicating two episodes of carrying water by water vapor. A large amount of water in the shale reservoir is continuously evaporated and carried out with the migration of natural gas, which is conducive to the formation of ultra-low water saturation gas reservoir. Zhang et al. (2005) confirmed this conclusion using gas flooding experiments on water-saturated shale sample. The experiment was conducted at room temperature and pressure of 3 MPa firstly for 30 h and then at 70 ℃ for 30 h using N2 of 1 MPa. It is found that water saturation can reduce to 58%, which is equivalent to the original water saturation of gas-rich shale reservoir in the study area, indicating that the vaporization carrying water can result in ultra-low water saturation in shale reservoir.

    Figure 6.  Variation of water carrying capacity of natural gas with temperature and pressure (data from Dodson and Standing, 1944).

    where y is the water carrying capacity, g/km3, P and T are pressure and temperature, respectively, MPa and ℃.

    The simulated burial history shows that the Longmaxi shale experienced subsidence with a relatively low burial rate before the Permian and then subsided with increasing burial rate until the Later Cretaceous. Uplifts and erosional events affecting hydrocarbon generation and expulsion primarily occurred after the Later Cretaceous, namely, from 80 Ma to the present (Fig. 7).

    Figure 7.  Burial and thermal history of the Longmaxi shale in the Jiaoshiba area. The solid lines represent burial history and the dotted lines are isotherms. O. Ordovician; N. Neogene.

    The vitrinite reflectance of the organic matter in the Longmaxi shale was about 1.2%–1.4%, when the formation temperature was about 160–170 ℃ at the Middle Jurassic (Fig. 7), indicating the source rocks were at kerogen degradation into gas stage since the Longmaxi organic-rich shale was dominated by Type Ⅱ kerogen (oil prone). With increasing formation temperature (180–200 ℃) during the Later Jurassic, the vitrinite reflectance of the organic matter was > 1.6%, and the crude oil cracking into gas occurred in the Longmaxi shale, which was obviously later than the kerogen degradation. However, previous study from Modica and Lapierre (2012) suggested that gas volume derived from crude oil cracking was far larger than that from kerogen degradation, e.g., the former was commonly 4 times larger than the latter. This can well explain the large water volume carried by nature gas in the second phase.

    By comparing TOC and water saturation in the Longmaxi shale, it can be found that the water saturation of shale reservoir gradually decreases with increasing TOC (Fig. 8a). Previous studies suggest that the water content of kerogen varies as a function of its thermal maturity, indicating differences in the wettability of kerogen in organic matter at different thermal evolution stages, specifically, it is primarily hydrophilic at the low maturity stage, and is characterized by mixed wettability at the maturity stage, and is commonly oil wetting at the high to over-high maturity stage (Hu et al., 2016; Lan et a., 2015; Ruppert et al., 2013). Therefore, the organic matter at high-mature to over-high- mature Longmaxi shale are mainly oil wetting, and the organic pores in kerogen are inferred to be saturated with gas, and almost without water (Passey et al., 1990). Also, previous studies show that the capacity of natural gas carrying water in organic pores is partly controlled by pore connectivity (Wang et al., 2019; Lan et al., 2015; Chalmers et al., 2012b), the organic pores with good connectivity are generally oil-wetting, while the organic pores with poor connectivity are commonly water-wetting. Figure 8b shows a good positive correlation between measured TOC and permeability in the Longmaxi shale samples, indicating organic-matter-hosted pores are generally well connected with each other, which contributes greatly to the permeability. Therefore, these connected pores of different sizes and shapes can form a complex spatial network structure, which is conducive to the loss of formation water carried by natural gas.

    Figure 8.  TOC vs. water saturation (a) and permeability (b) of the Longmaxi shale in the Jiaoshiba area.

    The comparison between quartz content/clay mineral content and water saturation of Longmaxi shale shows that they have a good positive correlation with water saturation, indicating that inorganic mineral pores can provide storage space for water accumulation (Figs. 9a9b). However, there is controversy regarding the water content of clay mineral pores (Li et al., 2014; Ji et al., 2012; Ross and Bustin, 2009; Lu et al., 2015). Clay mineral is commonly dominated by micro pores between clay minerals. Because the surface of clay pore is typically hydrophilic, which preferentially adsorbs and stores water molecules, so clay mineral pore is regarded as the main storage space of bound water. Clay bound water can be further divided into membrane bound water on the surface of clay minerals and capillary bound water in micro pores (Li et al., 2014). Due to the electric charge on the clay mineral surface, water molecules and clay particles can be closely combined by hydrogen bond, electrostatic force and intermolecular force. Generally, there is water film with a thickness of about 3 Å. The combined water content of clay mineral in shale measured by TRA technology can reach 2.36%–7.19% of the total volume of the sample, which is close to the reservoir capacity of shale reservoir. Li et al. (2014) confirmed a strong positive correlation between the measured bound water porosity and clay content in shale gas reservoir, with a correlation coefficient of 0.89, which indicates that clay pores are the main storage space of bound water in shale gas reservoir. This also confirms that the pores related to clay minerals in the Longmaxi Formation are important reservoir spaces for formation water.

    Figure 9.  Water saturation vs. quartz content (a) and clay mineral (b) content of the Longmaxi shale in the Jiaoshiba area.

    Based on above analyses, this paper established a model showing a formation water displacement process associated with gas generation and expulsion during the thermal evolution of organic-rich shale without considering occurrence state of nature gas, which can explain the low water saturation in shale reservoir.

    The formation process of ultra-low water saturation of shale reservoir can be summarized as following. Kerogen in organic-rich shale reservoir is immature at early diagenetic stage, while the organic and inorganic pores in the reservoir are full of formation water was expelled by mechanical compaction (Fig. 10a). With increasing burial depth and thermal maturity, organic pores are developed in the organic matter, which can be continuously filled by generated natural gas, displacing the movable water in the organic pores. Also, water in complex kerogen network can be consumed by hydrocarbon generation (Bennion et al., 1999), which may work together with water displacing to reduce water content in shale. After the organic pores are completely occupied, nature gas migrates from organic pores to inorganic pores and displaces part of the movable water. With increasing temperature and pressure and the generation of large volume of nature gas, part of movable water and bound water on the surface of brittle particles is evaporated and gasified, which is carried out continuously by the migration of natural gas. At the same time, methane can be dissolved in the movable water and coexisted with water in the brittle-mineral-hosted pores. As well accepted, the surface of clay mineral is commonly covered by adsorbed water film, which can't be easily replaced by nature gas (Ross and Bustin, 2009), thus, only part of movable water can be displaced by natural gas, where gas and water coexist in clay-mineral-hosted pores (Fig. 10b). Previous study also shows that the fractures under abnormal high pressure provide a good channel for the "vaporization" migration, accelerate the vaporization and liquid carrying behavior, which increases the possibility of carrying formation water to the surrounding strata and facilitate the formation of ultra-low water saturation (Yao et al., 2014).

    Figure 10.  Diagram of formation water displaced by natural gas during the thermal evolution of organic-rich shale.

    Importantly, the variation of water content in source rocks is a complex process involving both chemical reaction and physical process. As mentioned above, water in source rock is an important supplier of hydrogen for hydrocarbon generation, indicating that water consumption during hydrocarbon generation is another mechanism responsible for low water saturation in Longmaxi shale. Therefore, natural gas carrying water may only partly explain the formation mechanism of low water saturation, which needs to be explored further.

  • Low water saturation can be found in the gas-rich Longmaxi shale reservoir, with measured value ranging from 9.81% to 48.21% and an average value of 28.22%.

    TOC in high-mature to over-high-mature Longmaxi organic-rich shale is negatively correlated with water saturation, while quartz and clay mineral content are positively correlated with water saturation. This phenomenon indicates that well- connected organic pores are not available for water occurrence, while pores associated with inorganic matter are main storage space for formation water.

    The water carrying capacity of natural gas varies as a function of gas generation and expulsion, displacing bound and movable water in organic pores and part of bound and movable water from inorganic pores. The process can be divided into two phases. The first phase occurred at the kerogen degradation into gas at Ro of 1.2%–1.6% with water carrying capacity of natural gas ranging from 5 632.57–7 838.73 g/km3. The second phase occurred during the crude oil cracking into gas at Ro > 1.6% with water carrying capacity of natural gas ranging from 10 620.04 and 19 480.18 g/km3. The water carrying associated with natural gas generation and migration resulted in organic pores full of gas and brittle-mineral-hosted pores and clay-mineral-hosted pores filled by coexisted gas-water.

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