JOGMECは、2014年から非在来型資源の貯留層評価やそれに係る技術開発についてカナダ天然資源省（NRCan）と共同で研究を進めており、特にシェールやタイト貯留層に含まれる固体のビチュメンが貯留層性状に与える影響に着目して精緻に調査してきた。
本稿では、西カナダにおいて主要な開発対象となっている2つのシェール・タイト貯留層（三畳系Montney層とデボン系Duvernay層）を題材として、固体ビチュメンの含有量と孔隙の発達や保持の関係について調査した結果を紹介する。

Since 2014 JOGMEC has been collaborating with Natural Resources Canada (NRCan), along with industry partners, in the area of unconventional reservoir characterization and technology development. This article presents research from two major unconventional shale and tight reservoirs, the Upper Devonian Duvernay and Lower Triassic Montney formations in western Canada, and examines the differences between these two fundamentally different types of reservoirs. Solid bitumen strongly influences reservoir quality in both types of reservoirs but in very different ways. In tight reservoirs (i.e., Montney Formation) solid bitumen typically occludes pores and pore throats, while in shale reservoirs (i.e., Duvernay Formation) solid bitumen can be the primary host of porosity.

The global demand for natural gas is projected to increase significantly through 2040, as electricity demand increases, particularly in India and Asia, and coal-fired power plants are replaced with cleaner gas-fired power plants globally (IEA, 2019). A significant fraction of the global natural gas market, especially gas produced in North America, is sourced from shale and tight reservoirs, also known as unconventional reservoirs. Japanese companies actively explore, develop, and invest in these resources and Japan is one of the world’s top importers of natural gas (CIA World Factbook).

JOGMEC is actively involved in partnerships with Japanese companies, helping them to improve the efficiency and economics of their activities in unconventional shale and tight reservoirs. JOGMEC also collaborates with Japanese and non-Japanese research institutions in order to advance the fundamental scientific knowledge of unconventional reservoirs and share this knowledge with Japanese companies.

Since 2014 JOGMEC has been collaborating with Natural Resources Canada (NRCan) as well as industry partners in the area of unconventional reservoir characterization and technology development. This article will summarize our collaborative research on two unconventional reservoirs in western Canada (Fig. 1): the Montney Formation tight gas reservoir and the Duvernay Formation shale gas and oil reservoir. This article draws heavily from our recent publications (Akihisa et al., 2018; Knapp et al., 2020).

The geological and petrophysical properties of unconventional shale and tight reservoirs are highly variable (Jarvie, 2012) and the distinction of these two types of unconventional reservoirs has considerable implications for exploration and production strategies. The Duvernay Formation shale reservoir and Montney Formation tight siltstone reservoir of western Canada offer an excellent opportunity to compare these two types of unconventional reservoirs. Since shale reservoirs tend to be self-sourced, contain abundant primary organic matter, and reduced inorganic matrix porosity due to compaction, organic porosity (in kerogen and solid bitumen) tends to be a significant fraction of the total porosity (Loucks et al., 2009; Jarvie, 2012). This leads to positive correlations between total organic carbon (TOC) and porosity. In contrast, tight reservoirs generally show a negative correlation between TOC and porosity because the solid organic matter (solid bitumen) present in the reservoir is generated from migrated oil and occludes some of the primary inorganic pores and pore throats (Sanei et al., 2015; Wood et al., 2015, 2018). Shale reservoirs are typically most porous in intervals with moderate to high TOC, while tight reservoirs are most porous in intervals of low TOC.

Figure 1. Map of western Canada showing outlines of the Montney Formation and Duvernay Formation as well as study areas. Figure from Knapp et al. (2020).

The Lower Triassic Montney Formation is primarily composed of fine dolomitic sandstone and siltstone with minor amounts of shale (Davies, 1997; Zonneveld et al., 2010; Chalmers and Bustin, 2012). The unconventional section of the Montney Formation contains 449 TCF of marketable natural gas, 14.5 billion barrels of marketable natural gas liquids, and 1.1 billion barrels of marketable crude oil (NEB, 2013).

JOGMEC’s initial research into the Montney strived to define the controls on reservoir quality, particularly porosity and permeability. Wood et al. (2015), Sanei et al. (2015), and Akihisa et al. (2018) demonstrated that solid bitumen in the Montney reservoir was strongly detrimental to permeability. Sanei et al. (2015) and Wood et al. (2015, 2018) illustrated through the use of organic petrology and SEM imagery that solid bitumen exhibited pore-filling textures and suggested that solid bitumen formed as a secondary cracking product of oil that had migrated into the reservoir at an earlier time. Akihisa et al. (2018) showed that these relationships could also be identified using cuttings rather than core. This work helped to demonstrate the overlooked value of cuttings, which represent huge, continuous data sources for every well, without the high cost of coring.

Figure 2. (a) Regional Montney map from Wood and Sanei (2016) showing methane migration pathways based on calculation of excess methane. Excess methane is the “amount of methane greater than expected from the indigenous thermal maturity trend”. (b) Location of 2 horizontal wells studied by Akihisa et al. (2018) which intersect a proposed methane migration pathway. Map colors and contours are liquids-to-gas ratio from produced gas. Both wells were drilled from the same pad and extend in opposite directions. Pad location is indicated by the open circle. Combined figure from Akihisa et al. (2018).

Figure 3. Analysis of mud gas and cuttings properties in two horizontal Montney wells reveals that (a) solid bitumen saturation (Ssb) is negatively correlated to NMR permeability, (b) Ssb is positively correlated to mud gas wetness, and (c) that mud gas wetness is negatively correlated to permeability. Figures from Akihisa et al. (2018).

The Montney Formation has condensate-gas ratios (CGR) that deviate from the regional thermal maturity trend. Wood and Sanei (2016) suggested that areas of anomalously dry gas compositions (low CGR) were the result of up-dip migration of gas that was generated deeper in the basin (Fig. 2a). In a study of two horizontal wells in an area of high lateral CGR variation (Fig. 2b), Akihisa et al. (2018) integrated mud gas and cuttings analyses to examine the lateral variation in rock properties and mud gas composition at high resolution along the length of the horizontal sections. The study confirmed that gas composition was highly variable along the lateral sections, even within the same stratigraphic intervals and that solid bitumen concentration, permeability, and gas composition were strongly correlated (Fig. 3). In particular, areas with low solid bitumen concentration had high permeability and abnormally dry gas composition (excess methane), suggesting up-dip methane migration in these areas. Kato et al. (2017) was also able to map CGR distribution and methane migration pathways on a regional scale by analyzing well and seismic data.

The Duvernay Formation is an Upper Devonian calcareous-siliceous source rock and unconventional shale reservoir in the province of Alberta (Switzer et al., 1994; Knapp et al., 2017, 2019). The Duvernay Formation contains 76.6 TCF of marketable natural gas, 6.3 billion barrels of marketable natural gas liquids, and 3.4 billion barrels of marketable crude oil (NEB, 2017).

As the Duvernay Formation is a true source rock and self-sourced shale reservoir, organic-hosted porosity comprises a major fraction of the total porosity, and TOC and porosity are positively correlated (Fig. 4). However, high TOC samples have less porosity than expected, likely because the organic matter in these samples is load-bearing and compacted. Much of the scatter in the TOC-porosity relationship can be explained by considering the ratio of compaction-resistant biogenic silica to compressible organic matter (SiO2_bio/TOC ratio). Microcrystalline quartz is widespread throughout the matrix due to early dissolution of siliceous radiolarian skeletons and reprecipitation of silica (Knapp et al., 2017; Dong et al., 2018; Harris et al. 2018). This biogenic silica is positively correlated to hardness, brittleness, and Young’s modulus (Dong et al., 2018). High concentrations of rigid microcrystalline quartz relative to compressible organic matter (SiO2_bio/TOC) result in enhanced total porosity (Fig. 4) and increased organic pore size (Fig. 4 and Fig. 5). In highly siliceous samples, rigid load-bearing matrix frameworks that were created during early diagenesis likely limit compaction, resulting in greater preservation of primary inorganic porosity and secondary organic pores that were generated within ductile organic matter during thermal maturation.

Figure 4. TOC vs helium porosity, overlain by NMR T2 curves for samples from the “Fox” well. High SiO2_bio/TOC corresponds to higher total porosity per wt.% TOC (i.e. steeper slope). NMR T2 curves (green) are a proxy for pore size, with larger T2 representative of larger pores. Colored bands represent pore diameter ranges of 1-10 nm (green), 10-100 nm (pink), and 100-1000 nm (blue) based on fitting of NMR T2 and MICP pore throat size distribution curves. NMR T2 curves show that the upper, siliceous trend (red line) is dominated by pores in the 10-100 nm range, whereas the lower, less siliceous trend (black line) is dominated by pores with diameter <10 nm. Note: The Fox143 sample (low TOC, low porosity carbonate) was included in both datasets as a control point in the low porosity range. Its SiO2_bio/TOC is meaningless due to very low concentrations of both SiO2_bio and TOC. Figure from Knapp et al. (2020).

Figure 5. FIB-SEM images of samples with high (A) and low (B) SiO2_bio/TOC exhibit contrasting organic pore sizes. A) Solid bitumen (dark grey) within the intracrystalline space of a microcrystalline quartz-rich matrix (most of the light grey material). Large organic-hosted pores are preserved, potentially due to the compaction-resistant rigid siliceous framework. B) Solid bitumen in a less siliceous matrix contains much smaller pores, potentially due to the higher compressibility of the matrix and greater effective stress placed on the organic matter particles. Bright white colors are imaging artifacts from charge buildup on the sample surface. Figures from Knapp et al. (2020).

Organic matter has a strong influence on petrophysical properties in unconventional reservoirs. It is important to recognize that these relationships will not be the same in tight reservoirs and shale reservoirs. In the Montney tight gas reservoir solid bitumen is the remnant of migrated oil, and occludes pores and pore throats, limits permeability, and impacts produced gas CGR by influencing the location of up-dip methane migration. In the Duvernay self-sourced shale reservoir solid bitumen is a major host of porosity, leading to positive correlations between TOC and porosity. However, if TOC is too high relative to rigid matrix minerals such as biogenic silica, organic and inorganic porosity will be more prone to compaction. Ongoing research at JOGMEC-TRC in collaboration with NRCan continues to delineate the complex relationships between organic matter, minerals, and reservoir properties in various types of unconventional reservoirs.

References:

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（この報告は2020年1月28日時点のものです）