Introduction
As the theory of petroleum system suggests, source rock, carrier bed, reservoir and trap are the most important elements of a petroleum system, which have clear functions and boundaries, and are interrelated under the unified time-space framework [1]. In conventional petroleum systems, source rocks cannot be reservoirs, and carrier beds are generally located under the oil-water or gas-water boundary, or under the cap rocks, and occupy minor space within reservoirs [2], so they cannot be reservoirs either.
Since the 1970s, with the rapid development and successful application of horizontal well and large-scale hydraulic fracturing technology and equipment, unconventional hydrocarbons (e.g. shale gas and tight gas) have entered a stage of rapid development, promoting the revolutionary progress of traditional petroleum geological theory, and challenging the mechanisms of hydrocarbon generation, migration, accumulation and preservation [3]. Commercial development of deep-water shelf shale oil and gas in North America and China suggests that oil and gas can exist in the source rocks with micro-nano pores. For instance, the Barnett and Woodford shales in North America and the Wufeng-Longmaxi shale in the Sichuan Basin of China are of very low matrix permeability, generally less than 0.1×10-3 μm2 [4], but contain tremendous organic pores with minor pore diameter, good connectivity and low heterogeneity, which can provide the storage space for hydrocarbons and the permeability necessary for natural gas molecules to migrate within shale layers, forming effective shale reservoirs [5-6]. The new understandings of unconventional petroleum geology have promoted the rapid development of shale gas in the Sichuan Basin, where the shale gas production in 2021 was more than 200×108 m3, accounting for nearly 30% of the total gas production in the basin.
Tight sandstone gas is a main type of unconventional gas. The tight sandstone gas reservoirs contain gas universally, but have low porosity and extremely low permeability, with nano-scale pore throats in dominance. For instance, the Upper Triassic Xujiahe Formation in the Western Sichuan depression reflects the porosity of 2%-5%, the permeability of (0.01-0.10)×10-3 μm2 (smaller than 1×10-3 μm2 for 90%-95% of the samples), and the volume percentage of pore throats with radius smaller than 1 μm up to 98.8% [7]; the Xujiahe Formation in the Tongjiang-Malubei area, eastern Sichuan Basin, has the porosity of 1%-3% and the permeability of (0.01-0.10)×10-3 μm2 [8]. Reservoirs of the Xujiahe Formation in the Sichuan Basin are generally dense, resulting in low production per well, difficult beneficial development, slow exploration and development progress.
In 2019, Hough and Breyer first proposed the concept of carrier-bed reservoirs [9], indicating that Mancos shale of Bisti field in San Juan Basin of New Mexico in America and low-permeability light Halo reservoir of Pembina field in Canada are unconventional carrier-bed reservoirs associated with conventional reservoirs [10], and the Codell Sandstone Member of Upper Cretaceous Carlile shale in the Denver Basin and the Turner Sandy Member of the Carlile of the Powder River Basin have been proved to be low-permeability carrier-bed reservoirs [11]. Carrier beds (shale or tight sandstone) within such gas reservoirs have poor physical properties. Oil and gas generated from the source rocks enter the carrier beds under the source rock-reservoir pressure difference [12] and gradually flow into the reservoir. With the increase of migration distance, hydrocarbon accumulation dynamics will decrease, oil and gas will finally be detained and accumulated within carrier beds due to self-sealing process [3]. So most of tight sandstone gas reservoirs, such as the deep-basin tight sandstone gas reservoirs in North America [13-14], the Upper Paleozoic tight sandstone gas reservoirs in the Ordos Basin [15-16], and the Upper Triassic Xujiahe Formation [17-18] and Jurassic tight sandstone gas reservoirs in the Sichuan Basin [19], are located in the path of hydrocarbon migration from the source rocks to conventional reservoirs and can be classified as carrier-bed reservoirs.
The Cambrian Qiongzhusi Formation in southern Sichuan Basin demonstrated low production of shale gas according to the exploration idea for the Longmaxi Formation, and the Triassic Xujiahe Formation in the Western Sichuan depression revealed no production by conventional development strategy. To solve these problems, since 2020, according to the hydrocarbon accumulation theory of carrier-bed reservoirs and the geological characteristics of the Qiongzhusi Formation and the Xujiahe Formation, the exploration targets have changed from black shale (source rock) to low-TOC silty shale (carrier bed) in the Qiongzhusi Formation and from tight sandstone (reservoir) to trinity of carrier beds (the organic combination of fault-fracture zone and source rock-tight sandstone layers with high and low permeability) in the Xujiahe Formation. This has facilitated breakthroughs of shale gas exploration and tight sandstone gas development in southern and western Sichuan Basin. Accordingly, the carrier-bed unconventional gas reservoirs are proved with great potential. Thus, breaking through the traditional idea to search for shale gas in organic-rich shales and for tight gas in tight sandstones, the exploration targets have transited from source rock and reservoir to carrier beds. This enriches theories of unconventional hydrocarbon accumulation and provides reference for the discovery of similar gas reservoirs in the future.
1. Accumulation of carrier-bed shale gas
Whether shale is rich in organic matter is the main basis of shale gas exploration to select target areas and layers. For example, in the Silurian Longmaxi Formation, the sweet-spot interval of deep-water shelf shale with high TOC, high porosity, high gas content, high brittleness and thickness of 5-10 m is determined as the horizontal well’s target window. Initially, the Cambrian Qiongzhusi Formation was explored, according to the strategy for the Longmaxi Formation, in black shales; however, only low production of shale gas was obtained, because the Qiongzhusi Formation is obviously different from the Longmaxi Formation in geological characteristics (Fig. 1 a, 1b; Table 1 ). In the past several years, the existing wells and regional structural and sedimentary characteristics were further investigated to optimize the exploration strategy. It was newly recognized that shallow-shelf silty shales with low TOC in the Qiongzhusi Formation could be carrier beds for hydrocarbons, which are more likely to accumulate oil and gas if there are effective source rocks and good preservation conditions. So the silty shales were chosen as exploration horizons and turned out to be high-production shale gas. This changes the traditional idea to explore shale gas in organic-rich shale and enables breakthroughs for shale gas exploration in new region, horizon and type.
Fig. 1. Study areas and bottom structure maps of target horizons. (a) Tectonic units and study areas in Sichuan Basin; (b) Bottom structure map of the Qiongzhusi Formation in Jingyan-Qianwei area; (c) Bottom structure map of the second member of Xujiahe Formation in Xinchang structural zone in Western Sichuan depression. |
Table 1. Comparison of characteristics between Qiongzhusi Formation and Longmaxi Formation |
| Formation | Sedimentary setting | Sequence | Microfacies | Formation thickness with TOC >3%/m | Formation thickness with TOC >2%/m | Mineral composition/% | Clay composition/% | Porosity/ % | Pore composition/ % | Pore volume/ (mL·g-1) | Gas content/ (m3·t-1) |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Qiongzhusi Formation (Jingyan- Qianwei area) | Intracratonic sag | 3 cycles and 3 sets of shale | Deep-water muddy shelf | 0 | 2-3 | Low content of calcium (5%), high content of silica (70%) | Illite, 46%; I/S, 40% | 2-4 | Organic pores 15%; minor brittle mineral pores; clay mineral pores, 84% | 0.006 | 0.6-2.3 |
| Longmaxi Formation (Weiyuan area) | Craton | 1 cycle and 1 set of shale | Deep-water siliceous and calcium-siliceous shelf | Continuous thickness of 7-10 m | Continuous thickness of 24-35 m | Medium content of calcium (15%), high content of silica (45%) | Illite, 34%; I/S, 61% | 6-8 | Organic pores, 65%; brittle mineral pores, 8%; clay mineral pores, 47% | 0.012 | 5-6 |
1.1. Sedimentary characteristics and types of shale
1.1.1. Sedimentary characteristics
The sedimentary setting of Qiongzhusi Formation in the Sichuan Basin varies regionally [20-21] (Fig. 2 a). In the study area, the Qiongzhusi Formation was deposited in shallow-water to deep-water shelf, and comprises 3 cycles from the bottom to top. Similar to the Longmaxi Formation, the bottom of each cycle is deep-water shelf black shale with Th/U smaller than 2 (Figs. 2b and 3a), which contains rich organic carbon and high content of silica, but has small thickness varying from 0 to 8 m. The overlying is black gray to gray shallow-water shelf silty shale with Th/U of 2-7 and TOC of 0.2%-1.5%. Due to the great impact of foreign provenance, the lower cycle is characterized by frequently interbedded silty shales and argillaceous siltstones with well-developed horizontal bedding and wavy bedding (Figs. 2b and 3b). Deposited in a relatively quiet water environment and with less impact of foreign provenance, the middle cycle develops laminated silty shales (Fig. 3 c and 3d). With little impact of foreign provenance, the upper cycle is well developed with gray to ash black argillaceous shales with discontinuous calcareous laminae (Fig. 3 e and 3j).
Fig. 2. (a) Facies model of Qiongzhusi Formation in Sichuan Basin and (b) stratigraphic column of Qiongzhusi Formation in the study area. |
Fig. 3. Lithologic characteristics of Qiongzhusi Formation. (a) Well JS103, 3581.04-3581.20 m, black organic-rich siliceous shale with nodular pyrite in Layer ①; (b) Well JS103, 3522.20-3522.42 m, dark gray calcareous silty shale interbedded with gray calcareous argillaceous siltstone in Layer ④; (c) Well JS103, 3371.00-3371.22 m, dark gray argillaceous silty shale with laminae in Layer ⑦; (d) Well JS103, 3359.19-3359.40 m, massive gray siliceous silty shale with laminae in Layer ⑦; (e) Well JS103, 3313.94-3314.12 m, dark gray argillaceous shale in Layer ⑩; (f) Well JSH1, 3384.03 m, black organic-rich siliceous shale with calcareous laminae in Layer ①; (g) Well JS103, 3520.50 m, dark gray calcareous silty tight shale with obvious calcite-cemented laminae in Layer ④; (h) Well JS103, 3371.36 m, gray argillaceous silty shale with laminae in Layer ⑦; (i) Well JS103, 3359.03 m, gray siliceous silty shale with even silt distribution and silica content up to 65%-70% in Layer ⑦; (j) Well JS103, 3313.44 m, ash black argillaceous shale with calcareous carbonate-cemented laminae in Layer ⑩. |
By systematic whole-rock mineral analysis of the study area, the Qiongzhuzi Formation shales are roughly divided into three types, namely organic-rich siliceous shale, silty shale and argillaceous shale, and the silty shale can be subdivided into calcareous silty shale, argillaceous silty shale and siliceous silty shale.
1.1.2. Types of shales
Black organic-rich siliceous shale is developed at the bottom of the 3 cycles, with the grain size of 4-25 μm, silica content of 50%-70%, clay mineral content of 20%-40% dominated by illite, and organic matter content of 2%-4% distributed in clumps (Fig. 3 f).
Silty shale is widespread in the lower and middle cycles, with the grain size of 10-70 μm dominated by mud-sized to silt-sized particles (0.010 0-0.062 5 mm) (Table 2 ), and well-developed lamellation and laminae, similar to the first member of Longmaxi Formation (Long 1 Member) in the Changning area [22]. The silty shale is dominated by terrigenous quartz (about 70%). Specifically, the calcareous silty shale is mainly distributed in the lower cycle (Fig. 3 b and 3g), with relatively high content of carbonate minerals (15%-20%) and obvious cemented laminae; the argillaceous silty shale (Fig. 3 c and 3h) and siliceous silty shale (Fig. 3 d and 3i) are mainly distributed in the middle cycle, containing carbonate minerals (5%-10%, with calcite in dominance) and stripped, crumby and scattered organic matters (0.2%-1.5%). Illite and illite/smectite (I/S) are the main clay minerals, and argillaceous silty shale has more clay minerals with content of 5%-10%.
Table 2. Particle-size identification result of Qiongzhusi Formation in Well JS103 |
| Layer | Lithology | Depth/m | Particle size ratio/% | |
|---|---|---|---|---|
| Silt-sized | Mud-sized to silt-sized | |||
| Layer ⑦ | Silty shale | 3362.77 | 2.04 | 97.96 |
| Silty shale | 3363.93 | 100.00 | ||
| Silty shale | 3372.54 | 10.99 | 89.01 | |
| Silty shale | 3374.93 | 14.44 | 85.56 | |
Argillaceous shale is located in the middle-upper part of the upper cycle, with the clay content of 55%-60%, silica content of 15%-20%, carbonate mineral content of 15%-20% dominated by calcite, and low content of organic matter (0.1%-0.8%) (Fig. 3 e and 3j).
1.2. Geochemical characteristics
As one of the two sets of major source rocks in the Lower Palaeozoic, the Qiongzhusi Formation has been studied greatly [23⇓⇓-26]. The study area is located at the western slope of the intracratonic sag, with high-quality source rocks poorly developed and low TOC. According to the standard of organic matter abundance proposed by Charles Boyer et al. [27], only black organic-rich siliceous shale with thickness of 8-15 m (discontinuous thickness of Layers ①, ⑤ and ⑨, with TOC>0.5%) in the Qiongzhusi Formation is capable of hydrocarbon generation, while the silty shale and argillaceous shale are limited in hydrocarbon generation capacity due to the average TOC of 0.38% (Fig. 4 ). The organic matter is mainly Type I, from lower aquatic planktons (algae), with the kerogen δ13C ranging from -37.7‰ to -31.3‰ and the equivalent Ro of 2.70%-2.82% (avg. 2.76%), indicating the stage of over-mature evolution.
Fig. 4. Longitudinal distribution of experiment parameters of Qiongzhusi Formation in Well JS103. |
The Qiongzhusi Formation exhibits a high hydrocarbon expulsion efficiency (89.45% at Ro of 2.17%), but still has tremendous gas detained, about 1.85 m3/t, which can supply gas for adjoining reservoir after the shutoff of hydrocarbon generation.
1.3. Reservoirs
Helium porosity test indicates that the porosity of Qiongzhusi Formation is low, mainly 1.0%-2.0%. Typically, the porosity of argillaceous silty shale and siliceous silty shale in Layers ⑦ and ⑧ in the middle cycle is relatively high, with the average up to 2.95% (Fig. 4 ), and obviously segmented. Other (calcareous) silty shale layers are of low porosity (0.93%-1.39%), suggesting that the silty shales in the middle cycle have relatively good reservoir conditions. Reservoir space is mainly composed of widespread and diverse inorganic pores, including residual intergranular pores and intragranular dissolution pores of brittle minerals (Fig. 5 a), interlamellar pores and fractures of clay minerals (Fig. 5 b, 5c and 5e), and intercrystalline pores of pyrite (Fig. 5 d), as more than 80%. Due to low TOC, organic pores are less and scattered (Fig. 5 c), so the silty shales in the Qiongzhusi Formation in the study area do not demonstrate a relation between porosity and TOC as good as the Longmaxi Formation shales [28-29] (Fig. 6 ).
Fig. 5. Types of reservoir space within silty shales of Qiongzhusi Formation in Well JS103. (a) 3348.18 m, dissolution pores on surface of feldspar particles; (b) 3348.19 m, interlamellar pores and fractures of clay minerals; (c) 3349.80 m, organic pores and interlamellar pores and fractures of clay minerals; (d) 3349.80 m, intercrystalline pores of strawberry pyrite; (e) 3353.49 m, interlamellar pores of clay minerals; (f) 3357.90 m, shrinkage fractures at edges of stripped organic matters; (g) 3360.56 m, shrinkage fractures of clay minerals connected with microfractures; (h) 3362.76 m, interlamellar pores and fractures of clay minerals connected with microfractures; (i) 3367.39 m, organic matters filling mineral particles, with organic pores and shrinkage fractures. |
Fig. 6. Relation between TOC and porosity of silty shales in Qiongzhusi Formation. |
The permeability of the silty shales in the Qiongzhushi Formation is extremely low, (0.000 03-0.048 26)×10-3 μm2, with an average of 0.004 66×10-3 μm2, and less fractures are observed in the whole interval, very different from the organic-rich siliceous shales in the Longmaxi Formation.
1.4. Gas content
Gas content is an important parameter to evaluate resource potential of shale gas and exploitation potential of target horizons. Total gas content of the Qiongzhusi Formation in the study area is low. The average gas content of black shales is larger than 2 m3/t; specifically, the gas content of Layers ①, ⑤ and ⑨ is relatively high, with the maximum of Layer ① up to 3.30 m3/t (Well JS103) and the maximum of Layer ⑨ up to 4.69 m3/t (Well JY1). The average gas content of silty shales is smaller than 1%; specifically, the average gas content of Layers ⑥-⑧ in Well JS103 is only 0.61-0.92 m3/t (Fig. 4 ). The gas content of the Qiongzhusi Formation is apparently less than that of the Longmaxi Formation (1.52-8.85 m3/t, Well JY1), and that of the productive silty shale does not match the testing production and oil/gas shows. It is necessary to consider how to evaluate the gas content of such shales.
1.5. Controlling factors for enrichment and high-yield
1.5.1. Enlightenment from old wells
Due to small continuous thickness, the black shales in the Qiongzhusi Formation are much inferior to the Wufeng-Longmaxi black shales with high TOC in reservoir property and hydrocarbon-generating capacity, and several prospecting wells targeting the Qiongzhusi black shales fail to achieve commercial gas flow. Thus, the exploration strategy for the Wufeng-Longmaxi black shales cannot be coped in the study area. The contrastive analysis of existing wells shows that the silty shales in the middle of Qiongzhusi Formation are continuous and have revealed high hydrocarbon. The distribution of wells with gas is independent of structural morphology, and can be found at structural high part, saddle or flank (Well PY1 is structurally 600 m lower than Well JSH1), indicating that silty shales have very good gas content. For example, Well JSH1 exhibits the maximum total hydrocarbon value (THV) of 24.76% when the drilling fluid density is 1.55 g/cm3, Well JY1 exhibits the maximum THV of 12.55% when the drilling fluid density is 1.45 g/cm3, and Well PY1 exhibits the maximum THV of 7.71% when the drilling fluid density is 1.49 g/cm3. So the study suggests that the hydrocarbon signals are only related with the distribution of silty shales, which can form reservoirs.
1.5.2. Silty shales being both carrier beds and reservoirs
From the perspective of conventional-shale oil and gas exploration, the silty shales in the middle cycle in the study area are low in TOC and cannot be high-quality source rocks worthy of shale gas exploration. This set of silty shales has low porosity and ultra-low permeability, not meeting the standards of conventional reservoir exploration. Moreover, the reservoir space includes a low proportion of organic pores, which is inconsistent with the characteristics of well-developed organic pores in shale. Nonetheless, drilling results have shown a good gas content in the silty shales, which cannot be explained effectively by the current strategies and methods for conventional and unconventional exploration. Despite of the extremely low permeability, this set of silty shales could play the role of carrier beds in the geological history due to the following 4 advantages:
(1) The silty shales have certain hydrocarbon generating capacity and reservoir space. Overall, the silty shales has low TOC (avg. 0.38%) and no massive hydrocarbon generating capacity; however, some samples are found with TOC greater than 0.5% (max. 1.6%, as 18% of total samples) and can generate hydrocarbons. The small amount of hydrocarbons generated can be preferentially stored in the silty shales, protecting the reservoir space for the migration and accumulation of tremendous hydrocarbons subsequently generated from the adjacent high-quality source rocks.
(2) The silty shales are close to high-quality source rocks. Black shales with high TOC are distributed horizontally and vertically close to this set of silty shales, showing connatural advantages. When black shales generating hydrocarbons, abnormal high pressure forms and results in microfractures, promoting the silty shale to play the role of carrier beds.
(3) The silty shales demonstrate good physical properties. They are mainly composed of argillaceous silty shale and siliceous silty shale, which have higher porosity than calcareous silty shales and higher permeability and larger thickness than black shales, thus conducive to large-scale oil and gas transportation.
(4) The silty shales correspond to good preservation condition. As carrier beds, they have key factors as shown in Fig. 7 . Well ZY1 and Well GS17 indicate that hydrocarbons generated by high-quality source rocks in the Qiongzhusi Formation in the intracratonic sag migrate to high positions on both sides. In Well GS1 area in the east, hydrocarbons could migrate through well-developed faults to conventional carbonate reservoirs and accumulate there. In the west, due to the lack of migration pathways like faults but good sealing capacity of the overlying formations, hydrocarbons that migrate upward and laterally are detained in carrier beds with relatively good porosity and cannot migrate into the conventional reservoirs of Longwangmiao Formation. This has been proved by Well JY1 where high-quality reservoirs turned out to be water layers.
Fig. 7. Accumulation model of conventional gas and shale gas on both sides of intracratonic sag in Sichuan Basin. |
Based on the above understanding, Well JS103 was deployed targeting the lower part of Layer ⑦ which is a carrier bed with better physical properties among Layers ⑥-⑧. Given the drilling fluid density of 1.6 g/cm3, the well revealed the maximum THV of 3.74% and a high-yield shale gas flow of 25.86×104 m3/d, recording a breakthrough in exploration of Cambrian low-TOC silty shales. Organic combination of effective source rocks, large-scale carrier beds and good preservation condition are the key to form this kind of reservoirs.
2. Accumulation and enrichment of carrier body tight sandstone gas
Among conventional gas, shale gas and tight gas in the Sichuan Basin, only tight sandstone gas demonstrates the production inconsistent with its huge resources and reserves. Particularly, the tight sandstone gas in the Xujiahe Formation has been discovered with considerable reserves but not yielded commercial production. Since 2021, the concept of shale gas and conventional gas has been integrated and the exploration and development ideas have been changed. The enrichment model of carrier body tight sandstone gas plays, which are characterized by “Three in One” (i.e., trinity of fault, fracture, and tight sandstone reservoirs), is proposed. This model has facilitated the continuous breakthroughs of tight sandstone gas exploration in the Xujiahe Formation.
2.1. Effectiveness of source rocks
2.1.1. Source rocks
During the Late Triassic when the Xujiahe Formation was deposited, the centers of sedimentation, subsidence and hydrocarbon generation in the Sichuan Basin were located in the Western Sichuan depression. According to previous studies of gas-source correlation, the gas in the second member of the Xujiahe Formation (Xu 2 Member) in the Western Sichuan depression was mainly sourced from the underlying Xiaotangzi Formation and Xu 2 Member shales [30-31]. The Xiaotangzi Formation is dominated by transitional deposits and the Xu 2 Member is dominated by coal-bearing continental deposits [32]. The organic matters of Xiaotangzi Formation are mainly types I and II, with Type III locally. The organic matters of the Xu 2 Member are dominated by Type III, with a small amount of Type II (Fig. 8 ). The average TOC is 1.34% for the Xiaotangzi Formation shale and 2.08% for the Xu 2 Member (Fig. 9 ), both having good hydrocarbon generation potential. The thermal maturity of the Xiaotangzi Formation and Xu 2 Member source rocks is relatively high, with Ro of 1.7%-2.3%, averaging 2.2% and 1.9%, respectively. In general, the source rocks are in the high- to over-mature evolution stages (Fig. 10 ).
Fig. 8. Kerogen types in the Xu 2 Member and Xiaotangzi Formation of Western Sichuan depression. |
Fig. 9. TOC of Source rocks in the Xiaotangzi Formation and Xu 2 Member of Western Sichuan depression. |
Fig. 10. Maturity of source rocks in the Xu 2 Member and Xiaotangzi Formation of Western Sichuan depression. |
2.1.2. Evolution of hydrocarbon generation of source rocks
The experimental modeling of hydrocarbon-generation process shows that the thermal evolution products of type III kerogen at the lower maturity stage (Ro<1.2%) are similar to those of types I and II, with liquid hydrocarbons being the major products. The peak oil generation occurs at Ro of 1.2%, and then the yield of liquid hydrocarbons decreases with the increase of temperature and the yield of gas hydrocarbons increases significantly[33-34]. Based on the determined residual and erosion thicknesses in the Western Sichuan depression, together with the geochemical data, the hydrocarbon generation and expulsion processes of the Xiaotangzi Formation and Xu 2 Member source rocks were studied by basin modeling.
The Xiaotangzi Formation and Xu 2 Member source rocks entered into the low-mature stage (Ro of 0.5%-0.7%) at the end of Early Jurassic, and generated oil dominantly (stage 1 in Fig. 11 ). In the late stage of Late Jurassic, the source rocks reached the mature stage (Ro of 0.7%-1.0%), and mainly generated oil and gas with low maturity (stage 2 in Fig. 11 ). During the middle to late stage of Late Cretaceous, the source rocks reached the high-mature stage (Ro of 1.0%-2.0%) and the peak of gas generation, with high-mature gas generated (stage 3 in Fig. 11 ). Since then, due to the uplift of the strata caused by the Himalayan tectonic movement, the gas generation rate of the source rocks has gradually decreased (stage 4 in Fig. 11 ).
Fig. 11. Burial and thermal maturity history of the Xu 2 Member of Well X1 in Western Sichuan depression. |
The experimental modeling results reveal that the hydrocarbon expulsion efficiency of types I and II source rocks is generally lower than 30% in the low-mature stage, and 30%-60% in the high-mature stage [35]. The hydrocarbon expulsion efficiency of type III is lower due to its strong adsorption capacity [36]. Therefore, most of the liquid hydrocarbons generated in the low mature to mature stages are retained within the source rocks, with a part migrating and entering into the Xu 2 reservoirs in the form of dispersed liquid hydrocarbons. When the source rocks reach high-mature stage, they continue to evolve and generate a large quantity of gaseous hydrocarbons, while the preexisting liquid hydrocarbons in the source rocks begin to crack and form massive gas. The successful commercial development of shale gas in the Silurian Longmaxi Formation marine source rocks in the Sichuan Basin has also confirmed that there is a large quantity of gas formed by cracking of early retained liquid hydrocarbons in the source rocks [37-38]. In addition, the widely distributed liquid hydrocarbons within the reservoir begin to crack and form oil cracking gas in the high-mature stage. After the Cretaceous, the Himalayan tectonic movement created regional uplift and temperature gradually decreased. Although the reduction of temperature can reduce the gas generation rate, the source rocks could still continue to generate hydrocarbons during the early uplift period [39], and the liquid hydrocarbons retained in the source rocks were capable of continuously cracking to form gas at high temperature.
In summary, the multi-stage and full cycle hydrocarbon generation and expulsion of the Xiaotangzi Formation and Xu 2 Member source rocks in the Western Sichuan depression could cause "successive generation of natural gas" [40-41], thus continuously supplying gas to be accumulated and enriched in the Xu 2 Member carrier bodies.
2.1.3. Coupling characteristics of source-reservoir-pool
A lot of studies have been conducted on the densification process of the Xu 2 Member in the Western Sichuan depression [32,42⇓ -44]. It is commonly believed that the Xu 2 Member witnessed a gradual reduction of porosity due to compaction and cementation since it was initially deposited, and the reservoirs were basically densified in the early Late Jurassic. The accumulation processes and characteristics of the Xu 2 gas pools are determined by the spatial-temporal coupling of reservoirs and source rocks:
(1) From the Late Triassic to the Late Jurassic, the Ro values are less than 1.0%, corresponding to low-mature to mature stages. The source rocks generated oil predominantly and a small amount of low-mature gas (stage 1 and stage 2 in Fig. 11 ). A large amount of liquid hydrocarbons retained in the source rocks. Meanwhile, low-mature oil and gas and acidic fluids migrated along faults, fractures and sand bodies and charged into the reservoirs. Oil, gas and water were differentiated in the fracture zones and reservoirs. Acidic fluids led to the early dissolution pores. The reservoirs were not dense completely. A large number of liquid hydrocarbon/asphalt inclusions and a small amount of gas hydrocarbon inclusions could be observed in the reservoirs (stage 1 and stage 2 in Fig. 12 ).
Fig. 12. Relationship between homogenization temperature and salinity of inclusions in Xu 2 Member in Western Sichuan depression. |
(2) From the Early Cretaceous to the late stage of Late Cretaceous, the Ro values range from 1.0% to 2.0%, corresponding to high-mature stage. A large amount of high-mature gas was generated by kerogen degradation and the liquid hydrocarbons retained in the source rocks began to crack into gas (stage 3 in Fig. 11 ). At this stage, the reservoirs were generally tight with underdeveloped fractures. Because buoyancy and difference in pressure between source rock and reservoir are less than the capillary resistance, oil, gas and water filled in the reservoirs during the early stages were sealed, and a large amount of high-mature gas was retained in the source rocks. Small-scale fractures could be formed in reservoirs adjacent to high-quality source rocks by high pressure from hydrocarbon generation and high-mature gas was charged locally, forming lithologic gas reservoirs. At the same time, dispersed liquid hydrocarbons distributed in the reservoirs began to crack into gas. Since the reservoirs became generally dense at this stage, inclusions are rarely seen in the closed and non-flowing environments (stage 3 in Fig. 12 ).
(3) From the late stage of Late Cretaceous to the present, the Ro values are greater than 2.0%, corresponding to high- to over-mature stage. The temperature and pressure continued to decrease due to tectonic uplift. Although the hydrocarbon generation rate of the source rocks decreased and the hydrocarbon generation process stopped gradually under the lifting background, the source rocks could still generate high-mature gas by kerogen degradation and cracking of oil during the early lifting stage (stage 4 in Fig. 11 ). At this stage, abundant faults existed and numerous fractures were formed by erosion and unloading. With the decrease of temperature and pressure, a large amount of free gas, adsorbed gas and dissolved gas retained in the source rocks would expand, desorb and de-solubilize, generating the escaping force from the interior of the source rocks [18]. High-mature gas migrated vertically and laterally along the carrier bodies composed of faults, fractures and high-permeability matrix reservoirs. With the increase of migration distance and the deterioration of reservoir physical properties, the driving force for migration and accumulation would be less than the resistance, and hydrocarbons would detain and accumulate within the carrier bodies. A large number of gas hydrocarbon inclusions associated with medium to high homogenization temperature and low salinity can be observed in the reservoirs (stage 4 in Fig. 12 ).
According to the geochemical data of natural gas in the Xu 2 gas reservoirs in the Western Sichuan depression, the gas has high maturity (the average methane content of 97.4%), and is a mixture of kerogen degradation gas and oil cracking gas (Fig. 13 ). Gas filled in multiple stages. The tight reservoirs of the Xu 2 Member are mainly filled with early low mature oil and gas, while the carrier beds, composed of faults, fractures and high-permeability matrix reservoirs, are mainly filled with highly mature kerogen degradation gas and oil cracking gas.
Fig. 13. Relationship between ln (C1/C2) and ln (C2/C3) of natural gas in Xu 2 Member of Western Sichuan depression (according to Ref. [45]). |
2.2. Efficiency of carrier bodies
2.2.1. Characteristics of carrier bodies
The carrier bodies of the Xujiahe Formation in the Western Sichuan depression are mainly composed of faults, fractures and high-permeability matrix reservoirs.
(1) Faults
The faults in the Xujiahe Formation of Western Sichuan depression are widely developed, which were created by multiple tectonic movements during the Indosinian, Yanshanian and Himalayan periods [31]. Taking the Xu 2 Member of Xinchang structural belt as an example, there are three types of reverse faults trending in S-N, E-W and N-E. In the middle and late Indosinian, influenced by S-N compressive stress, a series of E-W faults were formed, mainly in the Gaomiao-Fenggu area. In the late Yanshan, the Longmen Mountain was strongly uplifted, and the tectonic differentiation was gradually enhanced due to the tectonic stress. The E-W faults were universal in the entire Xinchang structural belt, especially the Xinchang and Hexingchang areas. In the early and middle Himalayan, the Qinghai-Tibet Plateau was uplifted and laterally compressed. Influenced by the E-W compressive stress, a large number of S-N faults and fault-related folds were formed. Faults are most developed in the Xinchang, Hexingchang and Xiaoquan areas (Fig. 1 c). The faults are mainly classified as fourth-order and fifth-order, and cut downward to the Middle Triassic Leikoupo Formation and upward to the Xu 3/4 member.
(2) Fractures
According to the statistics of core fractures, three types of fractures are identified in the Xu 2 Member of Western Sichuan depression, including low-angle fractures (Fig. 14 a), oblique fractures (Fig. 14 b) and high-angle fractures (Fig. 14 c). The apertures of core fractures range from 0.1 to 2.0 mm. Microscopically, fractures can be divided into apparent fractures and fissures. The apparent fractures are usually oriented, implying the action of tectonic stress, and exhibit the widths of tens of microns (Fig. 14 d and 14e). Some samples contain clastic particles not obviously fragmented, but present only certain fissures (Fig. 14 f). The fractures in the carrier bodies of the Xujiahe Formation are commonly high-angle, followed by low-angle. The fractures trend mainly in two directions: E-W and NE-SW. Tectonic fractures are predominant in the Xujiahe Formation and were formed during three tectonic periods, i.e., Late Indosinian, Middle-Late Yanshanian and Himalayan [46]. Most of early fractures are filled with calcite and quartz, while late fractures are semi-filled or unfilled, mainly trending in E-W, parallel to the present maximum principal stress direction.
Fig. 14. Fracture characteristics of Xu 2 Member in Western Sichuan depression. (a) Well A12, 4814.63-4814.76 m, horizontal fractures; (b) Well S1, 4485.86-4486.26 m, oblique fractures; (c) Well S1, 4485.86-4486.26 m, high-angle fractures; (d) Well A8, 5009.00 m, oriented structural fractures, unfilled; (e) Well A12, 4828.44 m, unfilled fractures; (f) Well G4, 4892.41 m, particle crack; (g) Well F1, 4759.60 m, gaseous hydrocarbon inclusions distributed as bands along the microfissures of quartz grains; (h) Well G5, 4674.40 m, gaseous hydrocarbon inclusions distributed as bands along the microfissures through quartz grains; (i) Well F1, 4526.77 m, light grey hydrocarbon-bearing brine inclusions distributed as belts along the microfissures of calcite veins. |
(3) High-permeability matrix reservoirs
The sandstone reservoirs of the Xujiahe Formation in the Sichuan Basin are typical tight gas reservoirs with low porosity and low permeability. Matrix reservoirs with high permeability are developed locally. In the Xinchang structural belt, for example, the Xu 2 sandstones exhibit the porosity of 2%-6% (avg. 3.4%) and the permeability of (0.01-0.10)×10-3 μm2. Microfractures can improve the reservoir permeability by an order of magnitude, and thus cause high-permeability matrix reservoirs with the permeability of (0.1-1.0)×10-3 μm2.
2.2.2. Dominant migration pathways of oil and gas
At present, gases produced from the Xujiahe Formation carrier bodies are mainly characterized by high maturity. For example, the average methane/ethane ratio (C1/C2) of gas from the Xu 2 Member in the Xinchang Structure is as high as 120, corresponding to Ro of 1.8%-2.0%, which indicates that the gas produced today is mainly high-mature gas generated in the late stage. According to the evolution of source rocks and reservoirs, a large amount of high-mature gas was formed after the reservoir became tight. The high-mature kerogen degradation gas and oil cracking gas preferentially migrated vertically and laterally along faults, fractures and high-permeability matrix reservoirs, in an order of faults, large-medium- small scale fractures, and micro-nano matrix fractures. Most of hydrocarbon-bearing fluid inclusions distribute in linear and stripped pattern in the secondary fissures in quartz grains, demonstrating that fractures and fissures are effective pathways for hydrocarbon migration (Fig. 14 g-14i). According to the analysis of sealed cores of the Xu 2 Member in Well S4, the gas saturations of the high-permeability matrix reservoirs are 60%-80%, with an average of 70%, while the gas saturations of low-permeability matrix reservoirs are only 30%-60%, with an average of 50% (Fig. 15 ). Therefore, faults, fractures and high-permeability matrix reservoirs are not only the dominant migration pathways of oil and gas, but also the important storage spaces for high-mature gas.
Fig. 15. Vertical variation in permeability and gas saturation of sealed cores of Well S4 in Western Sichuan depression. |
2.3. Voluminosity of carrier bodies
2.3.1. Voluminosity of faults and fractures
Previous studies have shown that faults are composed of three parts, i.e. fault sliding surface, sliding damage zone and induced fracture zone [47]. The sliding damage zone and induced fracture zone can extend to 400 m on both sides of the fault sliding surface, with medium- to high-angle fractures particularly developed within 200 m, and exhibiting wide distribution in space [48].
Based on the data from image logs, cores and thin sections, a large number of fractures with different scales are developed in the carrier bodies, with fracture apertures ranging from tens of microns to several millimeters, and the maximum extension length exceeding 5 m. The volume of the fractures at the damage zone might be much larger than the observed results. For example, 5 lost circulations have happened in the Xu 2 Member of Well S2, with the cumulative loss of drilling fluid up to 926 m3. In addition, the occurrence of secondary minerals with diameters of nearly centimeter during logging also demonstrates that wide fractures may be widely developed in the formation (Fig. 16 ). The large fracture network system composed of different scales of fractures is capable of providing storage space considerably.
Fig. 16. Secondary minerals filled in the fractures of Xu 2 Member in Western Sichuan depression. (a) Well S1, 4762- 4787 m, secondary quartz, semi-idiomorphic crystal - idiomorphic crystal; (b) Well S2, 4776-4778 m, secondary calcite, semi-idiomorphic crystal - idiomorphic crystal. |
Compared with the widely distributed matrix reservoirs, faults and fractures may take a lower total volume proportion. However, as faults and fractures are the dominant migration pathways of oil and gas, their gas saturations should be significantly higher than those of the matrix reservoirs. According to the gas saturation measurements of the sealed cores of Well S4, the average gas saturation of high-permeability matrix reservoirs is 70% (Fig. 15 ). Therefore, the gas saturation of faults and fractures should be much higher than 70%, and the amount of natural gas within them should not be ignored.
2.3.2. Voluminosity of high- and low-permeability matrix reservoirs
Faults and associated brittle fracture zones have significant constructive effect on low-permeability tight sandstones. On the one hand, faults and fractures can provide pathways for acid fluid migration, enhance the intensity of dissolution, and thus improve the physical properties of sandstones. On the other hand, fractures are able to connect isolated pores effectively and, consequently, increase the proportion of effective pores and the seepage capacity of tight sandstones. High-permeability matrix reservoirs are generally formed by two ways: isolated pores formed in the early stage are connected through fractures and fracture-related dissolution pores are formed in the late stage.
High-permeability matrix reservoirs are defined as those reservoirs with permeability greater than 0.1×10-3 μm2. The proportion of high-permeability matrix reservoirs in the Xu 2 Member in the Western Sichuan depression is about 30%. Thus, the proportion of natural gas in high- and low-permeability matrix reservoirs in unit volume of rock can be approximately calculated. The gas content in the high-permeability matrix reservoirs of 1 m3 rock is 0.0084 m3, as calculated by 1 m3 (rock volume) ×30% (the proportion of the high-permeability matrix reservoirs)×4% (average total porosity)×70% (average gas saturation). The gas content in the low- permeability matrix reservoirs is 0.014 m3, as calculated by 1 m3 (rock volume)×70% (the proportion of the low-permeability matrix reservoirs)×4% (average total porosity)×50% (average gas saturation). Hence, the gas content proportions of high- and low-permeability matrix reservoirs are 38% and 62%, respectively. As discussed above, late gas with high maturity (Ro of 2.0%) and early gas with low maturity (Ro of 0.8%-1.0%) are generally stored in high- and low-permeability matrix reservoirs, respectively. Based on the calculation of the gas content proportions in high- and low-permeability matrix reservoirs, the maturity of produced gas should correspond to Ro of 1.4%-1.5% approximately, which is much lower than the maturity of actually produced gas (Ro of 1.8%-2.0%) (Fig. 13 ). This means that, without considering the storage capacity of fault damage zones and different scales of fractures, the proportion of high-mature gas would be underestimated. According to the maturity of the gas produced today, it can be inferred that the proportion of high- and low-mature gases is about 6:4 to 7:3, respectively. When deducting the contribution of high-permeability matrix reservoirs to high-mature gas (about 40 %), 20% to 30% high-mature gases are stored in fault damage zones and fractures, demonstrating that a large amount of high-mature gas is stored in the fault damage zones and fractures.
The productions and pressure build-up curves of the high-yield wells in the Xu 2 Member in the Western Sichuan depression indicate that both fractures and high-permeability matrix reservoirs supply gases and are characterized by dual-medium production. For example, since Well S1 was put into production in 2014, the daily gas production has been stable at 5×104 m3/d, and the cumulative gas production has been 1.2×108 m3. The pressure build-up curve of Well S1 illustrates the feature of dual-medium production and suggests gas supplies from fractures and high-permeability matrix reservoirs (Fig. 17 ). In the past one year, more than 10 economic wells with high and stable productions and pressures have been achieved and the production of each single well exceeds 1.0×108 m3. Thus, the gas supply from multiple sources including faults, fractures and matrix reservoirs helps solve the conundrums of low production in tight sandstones and unstable production in fractured reservoirs, making it feasible to achieve long-term high and stable gas productions in tight sandstones.
Fig. 17. Pressure build-up curve of Xu 2 Member of Well S1 in Western Sichuan depression. |
The gas contained in low-permeability matrix reservoirs can be an effective supplement for gas enrichment. Low-permeability tight reservoirs are mainly charged with early low-mature oil and gas, which enables the distribution of gas-bearing sandstones with low gas saturation in the Xujiahe Formation. The gas content analysis of the sealed cores of Well S4 shows that the average gas saturation of the low-permeability matrix reservoirs is 50% (Fig. 15 ) and the gas content measured under standard conditions is 1.63 cm3/g, which confirms that a large amount of gas stored in the low-permeability matrix reservoirs.
2.4. Enrichment model
Based on the analysis of effectiveness of source rocks, and efficiency and voluminosity of carrier bodies, the understanding of enrichment and high yield rules in tight sandstone reservoirs is further deepened. Different from the traditional strategy of finding tight gas in tight sandstones, the tight sandstone gas of the Xujiahe Formation in the Sichuan Basin can be found in various reservoirs. In addition to widespread low-permeability matrix reservoirs, the carrier bodies, which were previously regarded as pathways for high-speed gas migration, are able to provide important storage spaces for gas accumulation. The continuous effectiveness of source rocks in the Xiaotangzi Formation and Xu 2 Member provides sufficient hydrocarbons that were subsequently enriched in the Xu 2 Member. The carrier bodies, which are composed of faults, fractures, and high-permeability matrix reservoirs, provide efficient pathways for vertical and lateral gas migration. The voluminosity of carrier bodies provides sufficient storage spaces for gas accumulation and thus the formation of large-scale gas pools (Fig. 18 ).
Fig. 18. High-yield enrichment model of tight sandstone gas reservoirs in Xujiahe Formation, Sichuan Basin. T3x3—third member of Xujiahe Formation; T3x2—second member of Xujiahe Formation; T3m+t—Maantang and Xiaotangzi formations. |
The progress of engineering technologies, such as directional wells and large-scale sand fracturing, can increase the connectivity between matrix reservoirs and carrier bodies, and thus the effective contact area between wellbore and carrier bodies. Consequently, high recoverable reserves of single well and high and stable gas productions can be achieved in tight gas sandstone reservoirs.
3. Conclusions
The two new types of unconventional reservoirs found in the Sichuan Basin enrich the types of gas accumulation, but also greatly expand the exploration field.
Isotopic composition analysis proves that the shale gas from Well JS103 came from the Qiongzhusi Formation. The composition and texture analysis of rocks indicates that the shale gas producing layer is mainly low-TOC silty shale of shallow-water shelf. The achievements made in Well JS103 represent breakthrough in new areas, new layers and new types of shale gas. This breaks the traditional approach to find shale gas only in black shales, and realizes a transformation of exploration and development from single-layer system (Longmaxi Formation) to multi-layer system in the Sichuan Basin. Moreover, this expands the exploration area and scope of shale gas and enhances the shale gas exploration and development potential greatly.
Choosing carrier bodies as exploration and development targets has solved the problems such as low production within tight sandstone and unstable production within fracture zone in the Xujiahe Formation. This strategy promotes the transformation of tight sandstone gas from reserves without production to effective recovery, and enhances the exploration and development potential of tight sandstone gas.
Based on the gas content analysis of cores taken with pressure preserved in deep strata and the geochemical analysis of produced gas, it is believed that the gas content of carrier beds (bodies) composed of faults, fractures and high-permeability reservoirs can be 60%-70%. By organically combining the concepts of shale gas and conventional gas and breaking the traditional idea of taking fault/fracture zone as carrier beds and tight sandstone as reservoirs, it is proposed that carrier beds (bodies) are reservoirs and integrity of carrier beds and reservoirs, and the model of unconventional gas accumulation in carrier beds is established, which features the spatio-temporal superimposition of effective source rocks, carrier systems and tight sandstones (shales).