Sage Journals: Discover world-class research

Abstract

Increasing petroleum explorations indicate that the formation of many reservoirs is in close association with deep hot fluids, which can be subdivided into three groups including crust-derived hot fluid, hydrocarbon-related hot fluid, and mantle-derived hot fluid. The crust-derived hot fluid mainly originates from deep old rocks or crystalline basement. It usually has higher temperature than the surrounding rocks and is characterized by hydrothermal mineral assemblages (e.g. fluorite, hydrothermal dolomite, and barite), positive Eu anomaly, low δ¹⁸O value, and high ⁸⁷Sr/⁸⁶Sr ratio. Cambrian and Ordovician carbonate reservoirs in the central Tarim Basin, northwestern China serve as typical examples. The hydrocarbon-related hot fluid is rich in acidic components formed during the generation of hydrocarbons, such as organic acid and CO₂, and has strong ability to dissolve alkaline minerals (e.g. calcite, dolomite, and alkaline feldspar). Extremely ¹³C-depleted carbonate cements are indicative of the activities of such fluids. The activities of hydrocarbon-related hot fluids are distinct in the Eocene Wilcox Group of the Texas Gulf Coast, and the Permian Lucaogou Formation of the Jimusaer Sag and the Triassic Baikouquan Formation of the Mahu Sag in the Junggar Basin. The mantle-derived hot fluid comes from the upper mantle. The activities of mantle-derived hot fluids are common in the rift basins in eastern China, showing a close spatial relationship with deep faults. This type of hot fluid is characterized by high CO₂ content, unique gas compositions, and distinct noble gas isotopic signatures. In the Huangqiao gas field of eastern China, mantle-derived CO₂-rich hot fluids have created more pore spaces in the Permian sandstone reservoirs adjacent to deep faults.

Keywords

Deep hot fluids classification identification reservoir alteration petroliferous basin

Introduction

It has been demonstrated that hot fluid activities are common in petroliferous basins and are of significant importance to the formation of petroleum reservoirs (e.g. Du et al., 2007; Jin et al., 2006a; Lv et al., 2005; Ma et al., 2010; Qian et al., 2006; Zhu et al., 2008). Hot fluid-altered reservoirs have been reported in the Tarim Basin in northwestern China (Jin et al., 2006a; Lv et al., 2005; Qian et al., 2006; Zhu et al., 2008), and the deep carbonate reservoirs in the Sichuan Basin in southwestern China were also suggested to have been reformed and optimized by hot fluids (Du et al., 2007; Ma et al., 2010). It is believed that the chert reservoir in the Parkland gas field in Canada was formed by hot activities as well (Packard et al., 2001). The proposition of “hydrothermal dolomite” stimulated more extensive studies of deep carbonate reservoirs, and an increasing number of hydrothermal dolomite-related reservoirs have been reported in recent years, further emphasizing the importance of hot fluids for the formation of deep reservoirs (Davies and Smith Jr, 2006; Hurley and Budros, 1990; Jiao et al., 2011; Lavoie et al., 2010; Luczaj et al., 2006; Smith Jr, 2006; Zhang et al., 2015). Deep petroleum reservoir is the new realm of hydrocarbon resources worldwide. In the past two decades, China has gained huge success in deep petroleum exploration; a series of giant petroleum reservoirs were discovered in the depth ranging from 4500 to 6000 m and even deeper (Jia et al., 2008; Jin, 2005; Liu et al., 2008; Zou et al., 2014). Thus, knowledge of the effect of deep hot fluids on the accumulation of hydrocarbons is important for future explorations.

Nevertheless, great difficulties still remain with the research on the origin of deep fluids in petroliferous basins, owing to a lack of identification features and/or the mixing of fluids from multiple sources in most cases. Accurate identification of fluid sources is of course essential for understanding the interactive processes between fluids and reservoirs and cannot be avoided during the research on hot fluid-related reservoirs. In this paper, hot fluids in petroliferous basins are classified into three types based on our related researches in the last 20 years. The first type is crust-derived hot fluids, which originate from old rocks or even the crystalline basement below the target reservoir. The second type is hydrocarbon-related fluids, referring to fluids formed during the hydrocarbon generation, crude oil cracking, and thermochemical sulfate reduction (TSR) reactions. These fluids are also formed within the earth’s crust but are specifically related to source rocks and hydrocarbon generation processes. The third type refers to fluids that derive directly from the mantle and is therefore termed as mantle-derived fluids. Combined with recent case studies, we will present the identification criteria of these three hot fluids and discuss possible reaction processes and corresponding reservoir characteristics. These findings will facilitate further studies on deep hot fluids in petroliferous basins.

Crust-derived hot fluids

Crust-derived hot fluids are common in petroliferous basins, and their flow paths are normally controlled by deep faults. Activities of crust-derived hot fluids can be caused by magmatic processes deep in the basin and are therefore usually associated with specific volcanic–magmatic events. For example, most hot fluid activities in middle to western China are related to the Emei mantle plume during Permian. In contrast, some hot fluid activities are caused merely by the introduction of deep-seated hot fluids to shallower regions through deep faults and exhibit no relations with volcanic–magmatic events. In consequence, crust-derived hot fluids in different regions may show distinctive characteristics, and there is no universal criteria to identify them. Here we take the Tarim Basin in northwestern China as an example and will summarize and discuss the characteristics of crust-derived hot fluid activities in this basin.

Characteristics of crust-derived hot fluids in the Tarim Basin

The Cambrian–Ordovician carbonate rocks in the Tarim Basin have experienced remarkable hydrothermal alterations in geological history. Significant amounts of dissolved pores and large numbers of reservoirs bedded, lenticular, or dendrite in shape were formed during the fluid activities, providing plenty of space for the storage of hydrocarbons (Jin et al., 2006a; Lv et al., 2005; Qian et al., 2006; Wang et al., 2004; Zhao et al., 2014; Zhu et al., 2005, 2008). Distinctive compositions and diagenesis of the reservoirs allow them to be divided into three types: fluoritized reservoir, silicified reservoir, and hydrothermally altered dolomite reservoir.

(1) Fluoritization of carbonate and related reservoir

Large-scale fluoritization was observed in the carbonates of the Middle-Upper Ordovician sequence from TZ-45 well. The drill cores between 6077.00 and 6150.00 m mainly contain grey granular-clast limestone and considerable amounts of fluorite white, pale yellow, or lavender in color. In particular, an approximately 14 m continuous fluorite layer occurs between 6093.50 and 6107.50 m (Zhu et al., 2005), accompanied by a number of fluorite veins in adjacent granular-clast limestone. The fluorite was suggested to be formed during metasomatism of carbonates by deep hot fluids, supported by a homogenization temperature of 260–310°C for the fluid inclusions hosted in the fluorite (Jin et al., 2006b). Meanwhile, significant amounts of dissolved pores were formed during the invasion of the hot fluids, providing important reservoir space. Further studies demonstrate more common occurrences of fluorite in the Ordovician carbonates, including those from TZ-1, TZ-12, TZ-16, and TZ-47 wells, as well as the Sanchakou and Kepingxikeer outcrops in Bachu area (Zhang et al., 2007).

The reservoir of TZ-45 well mainly comprises limestone and fluorite. Fluorite layers are believed to be an important part of the reservoir because of their high porosity and wide occurrences. The fluorite was formed through metasomatism of calcite by F-enriched hot fluids. Theoretical calculation indicates that the replacement of calcite by fluorite can introduce a decrease in volume by 33.5% (Zhu et al., 2005). As a result, plenty of intergranular spaces were formed during the metasomatic processes. The intergranular spaces further facilitated fluid activities and the formation of dissolved pores, resulting in better reservoir properties. Intergranular pores and dissolved pores provided major reservoir spaces in fluorite layers and were generally filled by migrated crude oils.

(2) Silicified reservoir

Silicified carbonate reservoirs were recently found in the Yingshan Formation of Ordovician from SN-4 well in the central Tarim Basin, with a daily natural gas production of 38 × 10⁴ m³ (Yun and Cao, 2014). The reservoir is strongly silicified and can be divided into three segments: lower silicified segment, middle limestone segment, and upper silicified segment. The upper and lower silicified segments are mainly composed of subhedral–euhedral quartz containing microcalcite inclusions, calcite, and minor amounts of pyrite. Its reservoir spaces include high-angle cracks, crack-related voids, and intergranular pores between quartz (Figure 1). The distribution of the reservoir spaces is heterogeneous, and the porosity of the silicified carbonate can reach 3–20.5%.

Figure 1.

Microscopic petrology and pore characteristics of silicified segment of Shunnan 4 well in Tazhong area. (a) Euhedral quartz grains are common in the fine-grained limestone. Strong recrystallization led to the formation of fine-grained calcite (plane polarized); (b) and (c) strong silicification and pervasive intergranular spaces between subhedral–euhedral quartz grains (plane polarized); (d) plenty of intergranular pores are partly filled with bitumen (plane polarized). Qtz, Cal, and Bitu indicate quartz, calcite, and bitumen, respectively.

δ³⁰Si (V-NBS28) and δ¹⁸O (V-SMOW) values of quartz in silicified carbonates range from 2.1 to 2.7‰ and from 16.5 to 23.5‰, respectively. δ¹³C (V-PDB) values of secondary calcites (euhedral calcite and macro-crystalline calcite) in silicified carbonates are −2.01‰ (N = 10) and −2.17‰ (N = 3), respectively; their δ¹⁸O (VPDB) values are −10.56‰ (N = 10) and −10.30‰ (N = 3), respectively. In addition, the ⁸⁷Sr/⁸⁶Sr ratio of the secondary calcite 0.709555 (N = 8). Compared with surrounding rocks (δ¹⁸O = 9.82, N = 9; ⁸⁷Sr/⁸⁶Sr = 0.708848, N = 4), the calcite is obviously more depleted in δ¹⁸O and enriched in ⁸⁷Sr. Fluid inclusion microthermometric measurements indicate a formation temperature of 150–190°C for the silicified carbonates. Generally, the fluid salinity decreases with the increasing homogenization temperatures.

In spite of similar fluid features and sources, the silicified reservoirs from SN-4 well exhibit characteristics distinctive from the chert reservoir in the Parkland gas field in Canada. It is believed that the SiO₂-enriched hot fluids associated with the silicified reservoirs are critically saturated for dolomite and strongly unsaturated for calcite (Packard et al., 2001). In the Tarim Basin, the SiO₂-bearing hot fluid was transported upward through NE strike-slip faults. Surrounding rocks were dissolved by the acidic hot fluid and crystalline quartz precipitated. Meanwhile, large amounts of CO₂ were released and silicified reservoirs were formed. Twisted positions of strike-slip faults were favorable for the interactions between hot fluids and carbonates, facilitating the formation of silicified reservoirs.

(3) Hot fluid-altered dolomite reservoir

Dolomite is widely distributed within the Lower Ordovician and Cambrian strata in the Tarim Basin. Dolomite reservoirs with certain amounts of hydrocarbons have been found in drilling wells of XH1, XH2, DG1, Z-4, TS-1, H-4, F-1, T-1, HT-1, ZS-1, TS-1, etc. In July of 2016, the deepest drill (8408 m) of Asia was completed in the northern Tarim Basin. The drilling work showed about 1524 m thick dolomite starting from the depth of 6884 m. Several segments of high-quality reservoirs were also discovered in the depth interval of 7000–8000 m, with minor amounts of light oil. These drilling wells not only provide valuable information for the research on dolomite reservoirs but also demonstrate profound exploration prospects in deep dolomite reservoirs in the Tarim Basin.

Detailed lithological, mineralogical, and geochemical investigations indicate that the Lower Palaeozoic dolomite has been extensively altered by deep hot fluids (Zhu et al., 2015a). Both experimental observations and thermodynamic calculations demonstrate that hot fluids can dissolve deep-buried carbonates and create more reservoir spaces, whereas fill up the voids in shallow-buried carbonates and reduce the porosity (Duan and Li, 2008; Zhu et al., 2015b). Therefore, hot fluids have the ability to dissolve carbonate in deep strata and precipitate carbonate in shallow strata during upward migration. In other words, deep dolomite strata can be good reservoirs under the impact of deep hot fluids. For example, the porosity of dolomite in TZ-1 well increases by 9.1% from 7000 to 8400 m. Hydrocarbon reservoirs have been discovered in deep-buried dolomite reservoirs in the Tarim Basin (ZS-1 and ZC-1C wells).

Identification criteria of deep hot fluids in the Tarim Basin

(1) Lithological and mineralogical characteristics

During the interactions between hydrothermal fluids and surrounding rocks, changes of temperature and pressure can result in the precipitation of new minerals that fill up the existing reservoir spaces or cracks. Such minerals include calcite, dolomite, quartz, fluorite, barite, sphalerite, chlorite, pyrite, etc. (Jin et al., 2006a, 2006b; Zhu et al., 2008). The mineralogy of the cements is mainly controlled by the compositions of hot fluids and the interactions between hot fluids and surrounding rocks.

Calcite and dolomite are the most common cements. For example, karst caves in Ordovician carbonates in the northern Tarim Basin are usually partly or completely filled up by macro-crystalline calcite. Geochemical analyses indicate that the origin of macro-crystalline calcite cements is in close association with hot fluids (Zhu et al., 2013). Quartz normally occurs in the form of crystal druses in fractures or vugs. Local siliceous metasomatism can also be observed in some cases. The other minerals, such as fluorite and sphalerite, usually occur in restricted areas.

Characteristic mineral assemblages can serve as effective indicators for the activities of deep hot fluids. For example, quartz–dolomite–fluorite is the dominant mineral assemblage indicating deep hot fluid activities in S-15 well in the northern Tarim Basin, TZ-45 well in the central Tarim Basin is characterized by the quartz–calcite–fluorite assemblage, and the major hydrothermal minerals in TZ-12 well in the central Tarim Basin are sphalerite–pyrite–chlorite.

(2) Fluid inclusion analyses

Deep hot fluids usually show higher temperature than that of the formation water. For example, hydrothermal dolomite is suggested to form at temperatures of at least 5–10°C higher than the surrounding rocks (Davies and Smith, 2006). Generally, the homogenization temperature (Th) of typical hydrothermal minerals (e.g. calcite, dolomite, and fluorite) in deep carbonate strata is higher than that of the formation water as well. In addition, fluid inclusion analyses indicate that hydrothermal fluids often have higher salinities than seawater.

In the northern Tarim Basin, most Ordovician calcite cements show a Th of 66.6–105.8°C, implying that they might mainly precipitate from formation water. Th values indicative of hydrothermal activities have only been detected in restricted areas of the northern Tarim Basin. For example, calcite cements in T737 and T740 wells are characterized by average Ths of 158.1 and 144.2°C, respectively. In addition, ice melting temperature measurements demonstrated that the cements precipitated from hot fluids with a salinity of 16.8 wt% NaCl eq. Compared with most area of the northern Tarim Basin, the Ordovician calcite cement in the central Tarim Basin mostly precipitated from fluids with higher temperatures and salinities, with a Th of 139.2–180.8°C and a salinity of 13.2–18.9 wt% NaCl eq. Consequently, it has been widely accepted that these calcite cements mainly precipitated from deep hydrothermal fluids. In conclusion, the Ordovician carbonates in the central Tarim Basin have experienced strong alterations by hydrothermal fluids, whereas weaker impacts of hydrothermal fluids have been identified on the Ordovician carbonate reservoirs in the northern Tarim Basin.

(3) Geochemical analyses

Hydrothermal minerals (e.g. calcite, dolomite, and quartz) normally inherit the geochemical characteristics of deep hot fluids. For example, hydrothermal minerals are often characterized by significantly low δ¹⁸O values, high ⁸⁷Sr/⁸⁶Sr ratios, high Fe or Mn contents, and abnormal enrichment of Ce (Hu et al., 2010; Jacquemyn et al., 2014; Jin et al., 2006a; Zhang et al., 2009; Zhu et al., 2013).

In the central Tarim Basin, Ordovician calcite veins yield δ¹⁸O (V-PDB) values ranging from −7.9 to −14.3‰. The ⁸⁷Sr/⁸⁶Sr ratios of the veins are much higher than that of coeval seawater (Veizer et al., 1999), ranging from 0.709049 to 0.719503. REE patterns of the veins are also distinctive from those of the surrounding rocks, represented by remarkable positive Eu anomalies (δEu) in the range of 1.39–76.03. Hot fluid-altered Cambrian dolomite in the central Tarim Basin exhibit δ¹⁸O (V-PDB) values ranging from −5.1 to −10.9‰, and ⁸⁷Sr/⁸⁶Sr ratios of 0.709361–0.709975. Besides, the dolomite is enriched in Fe, Mn, and Ba, of which the abundances can reach 3158, 173.5, and, 4000 ppm, respectively. These geochemical characteristics can all be used to trace the activities of deep hot fluids.

Hydrocarbon-related hot fluids

Origin and composition of hydrocarbon-related hot fluids

Under high temperatures and high pressures, organic acids (e.g. carboxylic acid) and acidic gases (e.g. CO₂) can be generated directly from thermal maturation of kerogen (Barth and Bjørlykke, 1993; Lewan and Fisher, 1994) or produced by the reaction between hydrocarbons and water, which can alter the quality of deep reservoirs through dissolution/precipitation processes (Surdam et al., 1985). In the presence of sulfate, H₂S and CO₂ can be generated through TSR; TSR may also modify reservoir spaces (Hao et al., 2015). In China, large superimposed sedimentary basins generally contain multiple layers of source rocks, and the reservoirs adjacent to the source rocks were commonly altered by hydrocarbon-related acidic fluids (Pang et al., 2012). This demonstrates that hydrocarbon-related hot fluids are common in petroliferous basins, emphasizing their potential role in the formation of deep petroleum reservoirs.

In the classical theory of hydrocarbon generation, certain amounts of organic acid and CO₂ can be generated during early to middle maturation stages (Tissot and Welte, 1984). Recent studies showed that CO₂ and carboxylic acids can be produced even in the late maturation stage (>160°C) when H₂O and inorganic minerals are involved in the generation of hydrocarbons (Pan et al., 2006; Seewald, 2003). In petroliferous basins with active source kitchens, the rise of CO₂ contents accompanies increasing burial depths and formation temperatures. For example, the CO₂ content increases nearly linearly with the formation temperature in the Texas Gulf Coast and the Norwegian continental shelf (Figure 2). In the Eocene Wilcox Group of the Texas Gulf Coast, the CO₂ content exceeds 4 mol% when the burial depth reaches 3048 m (Smith and Ehrenberg, 1989). These phenomena demonstrate that source rocks are an important source of acid fluids in petroliferous basins. Under deep burial conditions, hydrocarbon-related hot fluids are characterized by large amounts of carboxylic acids and CO₂, favorable for the modification of reservoir spaces and the migration of hydrocarbons.

Figure 2.

Cross-plots of CO₂ partial pressure and formation temperature of the Eocene Wilcox Group of the Texas Gulf Coast in Mexico and of the Triassic and Jurassic reservoirs of Norwegian continental shelf (Smith and Ehrenberg, 1989).

Indicators of hydrocarbon-related hot fluids

Hydrocarbon-related hot fluids can dissolve carbonates and alkali feldspars, leading to the precipitation of secondary minerals. Meanwhile, isotopic compositions of related rocks can be significantly altered via isotopic exchange with the hot fluids. Stable carbon and oxygen isotope signatures of some typical areas associated with hydrocarbon-related hot fluids are summarized in Figure 3. The δ¹³C and δ¹⁸O values of carbonate cements tend to decrease with increasing formation temperatures. Generally, the diagenetic calcite shows obviously negative δ¹³C signature when hydrocarbon-related hot fluids were involved. Therefore, the δ¹³C and δ¹⁸O signatures of carbonate cements/veins are to some extent instrumental to infer the activity of hydrocarbon-related hot fluids.

Figure 3.

(a) The δ¹³C–δ¹⁸O plots of carbonate cements from typical reservoirs altered by hydrocarbon-related fluids; (b) the relationship between formation temperature and δ¹³C–δ¹⁸O variations of carbonate cements from the US Gulf Coast (after Franks and Forester (1984)).

The activity of hydrocarbon-related hot fluids can be easily identified in clastic reservoirs because of low primary carbonate content in clastic rocks. In the Songliao Basin, the δ¹³C and δ¹⁸O values (V-PDB) of calcite cements in early Cretaceous Quantou Formation sandstone reservoirs range from −13.3 to −0.9‰ and from −21.7 to −12.1‰, respectively (Xi et al., 2015). Based on the isotopic signatures, it is suggested that these calcite cements precipitated from hydrocarbon-related hot fluids derived from adjacent mudstone layers (Xi et al., 2015).

Early diagenetic carbonate cements may be present in clastic reservoirs or mudstones. Under such circumstances, careful petrological observations and detailed geochemical analyses are needed to accurately evaluate the effects of hydrocarbon-bearing hot fluids. For example, carbonate cements are common in Early Cretaceous Bayingebi Formation conglomerate reservoirs in Chagan Sag (Wei et al., 2015). Calculated diagenetic temperatures based on δ¹⁸O signatures of the cements demonstrated that the calcite and ferrocalcite cements with δ¹³C values ranging from −4.5 to 0.38‰ were formed during early diagenetic stages, whereas the dolomite and ankerite cements with δ¹³C values ranging from −2.2 to −0.1‰ were possibly formed during late diagenetic stages. Compared with the positive δ¹³C values of the primary carbonate minerals in the mudstones (1.6–4.7‰), it is concluded that both the inorganic carbon in primary carbonate cements and the organic carbon in buried organic matters were released and then incorporated into secondary carbonate cements during diagenetic processes (Wei et al., 2015).

The Triassic Baikouquan Formation is an important conglomerate reservoir in the Mahu Sag of the Junggar Basin (Kang et al., 2018). Calcite cements in the conglomerates are characterized by extremely negative δ¹³C values as low as −70‰ (V-PDB; unpublished data). Considering the high formation temperature of 90–100°C, the formation of these calcite cements is suggested to be closely associated with the deep Permian source rocks. The Permian Lucaogou Formation in the southern Jimusaer Sag is an important tight oil reservoir in China (Wu et al., 2016). It is a dolomitic lacustrine sequence containing certain amounts of terrigenous sediments and tephra. In the segments rich in secondary dolomite, the δ¹³C values can be lowered by 4–6‰ (Figure 4), and the δ¹³C values decrease with increasing total organic carbon (TOC) contents (Wu et al., 2017). These isotopic signatures indicate that hydrocarbon-related hot fluids have participated in the dissolution of primary carbonates and the formation of dissolved pores, providing important reservoir spaces for tight oils.

Figure 4.

Microscopic feature and variation of δ¹³C and δ¹⁸O values of typical rocks of the Lucaogou Formation in the Jimusaer Sag, modified after Wu et al. (2017). (a) Photomicrograph showing secondary dolomite formed by hydrocarbon-related hot fluids (cross-polarized light); (b) characteristics of lithology, δ¹³C and δ¹⁸O, and TOC of typical section of Lucaogou Formation. TOC: total organic carbon; VPDB: vienna pee dee belemnite.

In carbonate reservoirs, the effect of hydrocarbon-related fluids on the δ¹³C values of carbonate rocks is buffered by the large amount of inorganic carbonates. Therefore, the δ¹³C value may not be an unambiguous parameter for identification of hydrocarbon-related fluids in carbonate sequences. Nevertheless, occasional studies indicate that δ¹³C values of carbonate sequences can also be altered by hydrocarbon-related fluids in some cases (Pueyo et al., 2011).

Mantle-derived hot fluids

Identification of mantle-derived fluids

Jin et al. (2009) reported the compositions of fluid inclusions in mantle xenoliths and corundum megacrysts. Their results showed that mantle-derived fluids are mainly composed of CO₂, CO, and H₂, with minor N₂, CH₄, C₂H₄, and C₂H₆. The activities of mantle-derived fluids are strong in the Cenozoic rift basins at eastern China. These mantle fluids are rich in CO₂, even economically viable CO₂ accumulations have been documented in the Huangqiao area of Jiangsu province, the Lishui sag of the Donghai Basin, and the Fuchangde area of the Songliao Basin (Jin et al., 2002; Su et al., 2014; Wei et al., 2009).

Gas compositions and noble gas isotopes have been used to trace the presence of mantle-derived fluids. Jin et al. (2007) reported that mantle-derived fluids are characterized by a CO₂/³He ratio ranging from 0.3 × 10⁹ to 30 × 10⁹, a CH₄/³He ratio ranging from 10⁵ to 10⁷, a N₂/Ar ratio ranging from 83.6 to 700, and a N₂/³He ratio ranging from 10⁵ to 10⁶. The crust is rich in organic matter and its CO₂/³He, CH₄/³He, N₂/Ar, and N₂/³He ratios are usually 2–4 orders of magnitude higher than those of the mantle (Jin et al., 2007). The helium and carbon isotope cross-plot has already been used to decipher the source and origin of corresponding fluids (Figure 5; Hu et al., 2009).

Figure 5.

Carbon and helium isotopic identification index of CO₂ from different sources (after Hu et al. (2009)). R refers to ³He/⁴He ratio of samples. Ra refers to ³He/⁴He ratio of atmosphere (1.4 × 10⁻⁶).

In fact, it is difficult to trace mantle-derived fluids in sedimentary basins; when the mantle-derived fluid enters a sedimentary basin, it will mix with preexisting fluids and leave little well-preserved information for its action. Sometimes, researchers can use typical secondary minerals to indirectly trace the activity of mantle-derived fluids. For example, high-concentration mantle-derived CO₂ can react with sandstone to form dawsonite (NaAlCO₃(OH)₂) in sandstone reservoirs (Gao and Liu, 2007).

Effect of CO₂-rich fluid on the evolution of sandstone reservoir in Huangqiao gas field

The activity of CO₂-rich mantle-derived fluids is believed to be common in the petroliferous basins in eastern China (Jin et al., 2002). The traces of the accumulation of mantle-derived CO₂ were obvious, even CO₂ gas reservoirs were explored and/or exploited in the Huangqiao area of the Subei basin, the Lishui sag of the Donghai Basin, and the eastern Fuchangde area of the Songliao Basin (Su et al., 2014; Wei et al., 2009). It has been accepted that the heat and favorable matters brought by mantle-derived fluids promoted the petroleum accumulations in eastern China (Jin et al., 2002; Su et al., 2014; Wei et al., 2009). In this study, Huangqiao CO₂ gas field is chosen as a case to discuss the effect of mantle-derived CO₂ on the evolution of pore spaces in sandstone reservoirs.

Huangqiao gas field is one of the largest exploited onshore CO₂ gas fields in China. The gas is mainly composed of CO₂, with minor condensate oil. The CO₂ was mainly ascribed to mantle origin, with contributions from shallow CO₂ of metamorphic origin and minor organic-derived CO₂ (Wang et al., 2008). The source rock of the condensate oil was suggested to be the mudstone of the Middle Permian Gufeng and the Upper Permian Longtan formations (Liu et al., 2014). CO₂ accumulated quickly at high temperatures, inducing local alteration and displacement of previously charged oil, which favored the extraction of the light component of oil into CO₂-rich fluids (Huang et al., 2012). The sandstone of the Upper Permian Longtan Formation is the major reservoir rock, exhibiting poor physical property and high heterogeneity. Clearly, CO₂ can play important roles during the alteration of reservoir quality and the accumulation of hydrocarbons, which explains the coexistence of CO₂ and condensate oil in the Huangqiao gas field.

Our observations showed that the activity of CO₂-rich fluids was in close association with faults. X3 and X2 wells were located near and far away from the fault zone, respectively (Figure 6). The straight-line distance between the X3 and X2 wells is about 1 km, and the physical properties of the reservoir rocks are quite different (Ren et al., 2017). The sandstone of X3 well is characterized by relatively higher porosity (9–13.12%, avg = 9.92%) and high permeability (0.337–815.68 md, avg = 128.02 md). The physical property of the sandstones in X2 well is relatively worse with an average porosity of 6.91% and an average permeability of 0.96 md. In X3 well, high-temperature mantle-derived CO₂ is suggested to have migrated into the reservoir section and accumulated. The presence of CO₂ can lower the pH of the formation water, resulting in intense dissolution of the carbonate cements and K-feldspar. The characterized mineral assemblage is authigenic quartz, dawsonite, siderite, and kaolinite (Figure 7(a) and (b)). Dawsonite is an indicative mineral of high partial pressure of CO₂ (Hellevang et al., 2005). Therefore, the pervasive distribution of dawsonite in the reservoir section of X3 well (Ren et al., 2017) indicates that large amounts of CO₂ charged into the reservoir during diagenetic stages. In X2 well, the influence of high-pressure and high-temperature mantle-derived fluids is much weaker. No obvious dissolution of alkaline minerals has been observed. On the contrary, prominent carbonate cementation has occurred in the reservoir section, represented by minerals of ankerite, siderite, and calcite (Figure 7(c) and (d)).

Figure 6.

A model for the formation of reservoir spaces influenced by mantle-derived CO₂-rich fluids: a case study from the sandstone of Upper Permian Longtan Formation in Huangqiao area, eastern China.

Figure 7.

The characteristic mineral assemblages in the Upper Permian Longtan Formation sandstones of Well X3 and X2. (a) A microscope photo showing the coexistence of quartz, kaolinite, siderite, and dawsonite from Well X3 (plane polarized); (b) a scanning electron microscope photo of the same sample as in (a), showing needle-like radial dawsonite; (c) a microscope photo showing the coexistence of quartz, calcite, and siderite from Well X2 (cross-polarized); (d) a backscattered electron image of the same sample as in (c). Kao, Sd, Daw, and Ank represent kaolinite, siderite, dawsonite, and ankerite, respectively.

Based on the above observations, we proposed a model for the formation of a special reservoir influenced by mantle-derived CO₂ (Figure 6). Mantle-derived CO₂ migrated to shallow reservoir rocks along faults. The CO₂-rich acid fluids could improve the porosity and permeability of adjacent reservoir rocks through intense dissolution of alkaline minerals (e.g. carbonate). It should be pointed out that the influence area of the CO₂-rich fluid is limited, and the reservoir quality can lower significantly away from the fault zone. Therefore, the hydrocarbon exploration should be focused on reservoir sections along the fault zone in similar regions worldwide.

Summary and conclusions

Hot fluids in petroliferous basins can originate from multiple sources, including supercritical fluids from the mantle (e.g. CO₂), deep fluids from old rocks or even the crystalline basement, and acidic fluids associated with generation of hydrocarbons (e.g. carboxylic acid, CO₂). These fluid activities can occur at different stages during basinal evolution and play important roles in the generation, migration, accumulation, and even preservation of hydrocarbons within the petroliferous basin.

The reservoir properties can be reformed and optimized by hot fluids. First, alkaline minerals (e.g. calcite and orthoclase) can interact with acidic hot fluids, leading to the formation of dissolved pores; second, additional residual pores can be formed by metasomatic reactions such as fluoritization, silicification, and hydrothermal dolomitization. In addition, hot fluids can also exhibit positive influence on the migration and accumulation of hydrocarbons. For example, mantle-derived supercritical CO₂ fluids were associated with the accumulation of light hydrocarbons in the Huangqiao gas field in eastern China.

Tracing the source of hot fluids involves comprehensive research works, including tectonic background analyses, observations of typical authigenic mineral assemblages, fluid inclusion studies, geochemical investigations of elemental or isotopic signatures, etc. In this study, we summarized the typical mineral assemblages and signatures of C, O, and Sr isotopes in representative basins where hot fluid activities are distinguishable. The current review can provide an instrumental reference for further research. Due to the different tectonic backgrounds and geological settings in different basins, as well as distinctive characteristics and reaction processes of hot fluids in different regions, great challenges currently still remain with the research on hot fluids in petroliferous basins.

Footnotes

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research, authorship and/or publication of this article: This study was financially supported by the National Natural Science Foundation of China (Grant No. 41230312) and the National Science and Technology Major Project (Grant No. 2016ZX05002006-005).

References

Barth

Bjørlykke

(1993) Organic acids from source rock maturation: Generation potentials, transport mechanisms and relevance for mineral diagenesis. Applied Geochemistry 8: 325–337.

Davies

Smith

(2006) Structurally controlled hydrothermal dolomite reservoir facies: An overview. AAPG Bulletin 90: 1641–1690.

Hao

Zou

et al . (2007) Effect of thermochemical sulfate reduction upon carbonate gas reservoir: An example from the Northeast Sichuan Basin. Acta Geologica Sinica (English Edition) 81: 119–126.

Duan

(2008) Coupled phase and aqueous species equilibrium of the H₂O–CO₂–NaCl–CaCO₃ system from 0 to 250°C, 1 to 1000 bar with NaCl concentrations up to saturation of halite. Geochimica et Cosmochimica Acta 72: 5128–5145.

Gao YQ and Liu L (2007) Basic characteristics of Dawsonite-bearing sandstone and its geologic significance. Geological Review 53(1): 104–111 (in Chinese with English abstract).

Franks

Forester

(1984) Relationships among secondary porosity, pore–fluid chemistry and carbon dioxide, Texas Gulf Coast: Part 1. Concepts and principles. AAPG M37: Clastic Diagenesis 59: 63–79.

Hao

Zhang

Wang

et al . (2015) The fate of CO₂ derived from thermochemical sulfate reduction (TSR) and effect of TSR on carbonate porosity and permeability, Sichuan Basin, China. Earth-Science Reviews 141: 154–177.

Hellevang

Aagaard

Oelkers

et al . (2005) Can dawsonite permanently trap CO₂? Environmental Science & Technology 39: 8281–8287.

Burnard

et al . (2009) Mantle-derived gaseous components in ore-forming fluids of the Xiangshan uranium deposit, Jiangxi province, China: Evidence from He, Ar and C isotopes. Chemical Geology 266: 86–95.

10.

Chen

Wang

et al . (2010) REE models for the discrimination of fluids in the formation and evolution of dolomite reservoirs. Oil and Gas Geology 31: 810–818 (in Chinese with English abstract).

11.

Huang

Zhang

Liu

et al . (2012) Study on Permian–Triassic hydrocarbon generation evaluation and history of late accumulation in Huangqiao–Jurong Area. Journal of Oil and Gas Technology 34: 44–48 (in Chinese with English abstract).

12.

Hurley

Budros

(1990) Albion–Scipio and Stony Point Fields–USA Michigan Basin. AAPG TR: Stratigraphic Traps 1 23: 1–37.

13.

Jacquemyn

Desouky

Hunt

et al . (2014) Dolomitization of the latemar platform: Fluid flow and dolomite evolution. Marine and Petroleum Geology 55: 43–67.

14.

Jia

Zhao

et al . (2008) Petro China key exploration domains: Geological cognition, core technology, exploration effect and exploration direction. Petroleum Exploration and Development 35: 385–396 (in Chinese with English abstract).

15.

Jiao

Surdam

Zhou

et al . (2011) A feasibility study of geological CO₂ sequestration in the Ordos Basin, China. Energy Procedia 4: 5982–5989.

16.

Jin

(2005) Particularity of petroleum exploration on marine carbonate strata in China sedimentary basins. Earth Science Frontiers 12: 15–22 (in Chinese with English abstract).

17.

Jin

Zhang

et al . (2007) Deep Fluid Activities and Effects on Hydrocarbon Accumulations. Beijing: Science Press, pp.13–35 (in Chinese).

18.

Jin

Zhang

Yang

et al . (2002) Primary study of geochemical features of deep fluids and their effectiveness on oil/gas reservoir formation in sedimental basins. Earth Science 27: 659–665 (in Chinese with English abstract).

19.

Jin

Zhu

et al . (2006a) Geological and geochemical signatures of hydrothermal activity and their influence on carbonate reservoir beds in the Tarim Basin. Acta Geologica Sinica 80: 245–253 (in Chinese with English abstract).

20.

Jin ZJ, Zhu DY, Hu WX, et al. (2009) Mesogenetic dissolution of the middle Ordovician limestone in the Tahe oilfield of Tarim basin, NW China. Marine and Petroleum Geology 26(6): 753–763.

21.

Jin

Zhu

Zhang

et al . (2006b) Hydrothermal fluoritized Ordovician carbonates as reservoir rocks in the Tazhong area, center Tarim Basin, NW China. Journal of Petroleum Geology 29: 27–40.

22.

Kang

Cao

et al . (2018) Selective dissolution of alkali feldspars and its effect on Lower Triassic sandy conglomerate reservoirs in the Junggar Basin, northwestern China. Geological Journal 53: 475–499.

23.

Lavoie

Pinet

Duchesne

et al . (2010) Methane-derived authigenic carbonates from active hydrocarbon seeps of the St. Lawrence Estuary, Canada. Marine and Petroleum Geology 27: 1262–1272.

24.

Lewan

Fisher

(1994) Organic acids from petroleum source rocks. In: Pittman ED and Lewan MD (eds) Organic Acids in Geological Processes. Berlin Heidelberg: Springer, pp.70–114.

25.

Liu

Jin

Luo

et al . (2014) Oil and source correlation in Huangqiao and Jurong areas, Lower Yangtze region. Petroleum Geology and Experiment 36: 359–364 (in Chinese with English abstract).

26.

Liu

Huang

Chen

et al . (2008) Primary study on hydrothermal fluids activities and their effectiveness on petroleum and mineral accumulation of sinian system Palaeozoic in Sichuan Basin. Journal of Mineralogy and Petrology 28: 41–50 (in Chinese with English abstract).

27.

Luczaj

Harrison

IIIWB

Williams

(2006) Fractured hydrothermal dolomite reservoirs in the Devonian Dundee Formation of the central Michigan Basin. AAPG Bulletin 90: 1787–1801.

28.

Yang

Xie

et al . (2005) Carbonate reservoirs transformed by deep fluid in Tazhong area. Oil and Gas Geology 26: 284–289 (in Chinese with English abstract).

29.

Cai

Zhao

et al . (2010) Formation mechanism of deep buried carbonate reservoir and its model of three element controlling reservoir: A case study from the Puguang Oil field in Sichuan. Acta Geologica Sinica 84: 1087–1094.

30.

Packard

Al-Aasm

Samson

et al . (2001) A Devonian hydrothermal chert reservoir: The 225 bcf Parkland field, British Columbia, Canada. AAPG Bulletin 85: 51–84.

31.

Pan

Liu

et al . (2006) Chemical and carbon isotopic fractionations of gaseous hydrocarbons during abiogenic oxidation. Earth and Planetary Science Letters 246: 70–89.

32.

Pang

Liu

et al . (2012) Dynamic field division of hydrocarbon migration, accumulation and hydrocarbon enrichment rules in sedimentary basins. Acta Geologica Sinica (English Edition) 86: 1559–1592.

33.

Pueyo

Sáez

Giralt

et al . (2011) Carbonate and organic matter sedimentation and isotopic signatures in Lake Chungará, Chilean Altiplano, during the last 12.3kyr. Palaeogeography Palaeoclimatology Palaeoecology 307: 339–355.

34.

Qian

Chen

et al . (2006) General characteristics of burial dissolution for Ordovician carbonate reservoirs in the northwest of Tazhong area. Acta Petrolei Sinica 27: 47–52 (in Chinese with English abstract).

35.

Ren QQ, Hu WX, Wang XL, et al. (2017) Experimental study of the fluid-rock interactions between CO2-rich fluid and sandstone and its application: A case study of the upper permian longtan formation in the huangqiao oil and gas reservoirs. Geological Journal of China Universities 23(1): 134–147 (in Chinese with English Abstract).

36.

Seewald

(2003) Organic–inorganic interactions in petroleum–producing sedimentary basins. Nature 426: 327–333.

37.

Smith

Ehrenberg

(1989) Correlation of carbon dioxide abundance with temperature in clastic hydrocarbon reservoirs: Relationship to Inorganic chemical equilibrium. Marine and Petroleum Geology 6: 129–135.

38.

Smith

Jr (2006) Origin and reservoir characteristics of Upper Ordovician Trenton–Black River hydrothermal dolomite reservoirs in New York. AAPG Bulletin 90: 1691–1718.

39.

Chen

Cao

et al . (2014) Genesis, source and charging of oil and gas in Lishui Sag, East China Sea Basin. Petroleum Exploration and Development 41: 523–532 (in Chinese with English abstract).

40.

Surdam

Crossey

Eglinton

et al . (1985) Organic-inorganic reactions during progressive burial: Key to porosity and permeability enhancement and preservation [and discussion]. Philosophical Transactions of the Royal Society of London A: Mathematical, Physical and Engineering Sciences 315: 135–156.

41.

Tissot

Welte

(1984) Petroleum Formation and Occurrence. Berlin: Springer–Verlag, pp.199–214.

42.

Veizer

Ala

Azmy

et al . (1999) ⁸⁷Sr/⁸⁶Sr, δ¹³C and δ¹⁸O evolution of phanerozoic seawater. Chemical Geology 161: 59–88.

43.

Wang

Liu

Qin

et al . (2008) Reservoir forming mechanism and origin characteristics in Huangqiao Carbon Dioxide Gas Field, North Jiangsu Basin. Natural Gas Geoscience 19: 826–834 (in Chinese with English abstract).

44.

Wang

Jin

Xie

(2004) Transforming effect of deep fluids on carbonate reservoirs in the Well TZ45 Region. Geological Review 50: 543–547 (in Chinese with English abstract).

45.

Wei

Song

et al . (2009) Formation and pool forming model of CO₂ gas pool in eastern Changde area, Songliao Basin. Petroleum Exploration and Development 36: 174–180 (in Chinese with English abstract).

46.

Wei

Zhu

Tan

et al . (2015) Diagenetic and porosity evolution of conglomerate sandstones in Bayingebi Formation of the Lower Cretaceous, Chagan Sag, China–Mongolia frontier area. Marine and Petroleum Geology 66: 998–1012.

47.

Cao

et al . (2016) A unique lacustrine mixed dolomitic–clastic sequence for tight oil reservoir within the middle Permian Lucaogou Formation of the Junggar Basin, NW China: Reservoir characteristics and origin. Marine and Petroleum Geology 76: 115–132.

48.

Tang

et al . (2017) The impact of organic fluids on the isotopic compositions of carbonate-rich reservoirs: Case study of the Lucaogou Formation of the Jimusaer Sag, Junggar Basin, NW China. Marine and Petroleum Geology 85: 136–150.

49.

Cao

Jahren

et al . (2015) Diagenesis and reservoir quality of the Lower Cretaceous Quantou Formation tight sandstones in the southern Songliao Basin, China. Sedimentary Geology 330: 90–107.

50.

Yun

Cao

(2014) Hydrocarbon enrichment pattern and exploration potential of the Ordovician in Shunnan area, Tarim Basin. Oil and Gas Geology 35: 788–797 (in Chinese with English abstract).

51.

Zhang

Qian

et al . (2009) Formation of saddle dolomites in Upper Cambrian carbonates, western Tarim Basin (northwest China): Implications for fault-related fluid flow. Marine and Petroleum Geology 26: 1428–1440.

52.

Zhang

Zhao

Jin

et al . (2009) Geochemical characteristics of rare earth elements in petroleum and their responses to mantle–derived fluid: An example from the Dongying Depression, East China. Energy Exploration & Exploitation 27: 47–68.

53.

Zhang

Huang

et al . (2015) Ultra-deep liquid hydrocarbon exploration potential in cratonic region of the Tarim Basin inferred from gas condensate genesis. Fuel 160: 583–595.

54.

Zhang

Luo

et al . (2007) The relationships of late Yanshanian–Himalayan oil/gas adjustment and hydrothermal activity in the central area of the Tarim Basin. Chinese Science Bulletin 52: 192–198 (in Chinese).

55.

Zhao

Shen

Zheng

et al . (2014) The porosity origin of dolostone reservoirs in the Tarim, Sichuan and Ordos basins and its implication to reservoir prediction. Science China: Earth Sciences 44: 1925–1939 (in Chinese with English abstract).

56.

Zhu

Song

et al . (2005) Fluoritization in Tazhong 45 reservoir: Characteristics and its effect on the reservoir bed. Acta Petrologica et Mineralogica 24: 205–215 (in Chinese with English abstract).

57.

Zhu

Jin

et al . (2008) Effects of deep fluid on carbonates reservoir in Tarim Basin. Geological Review 54: 348–354 (in Chinese with English abstract).

58.

Zhu

Meng

et al . (2013) Differences between fluid activities in the Central and North Tarim Basin. Geochimica 42: 82–94 (in Chinese with English abstract).

59.

Zhu

Meng

Jin

et al . (2015a) Formation mechanism of deep Cambrian dolomite reservoirs in the Tarim Basin, northwestern China. Marine and Petroleum Geology 59: 232–244.

60.

Zhu

Meng

Jin

et al . (2015b) Fluid environment for preservation of pore spaces in a deep dolomite reservoir. Geofluids 15: 527–545.

61.

Zhu

Jin

Lin

(2005) Relations between the early Permian magmatic rocks and hydrocarbon accumulation in the central Tarim. Petroleum Geology and Experiment 27: 50–54 (in Chinese with English abstract).

62.

Zou

et al . (2014) Formation, distribution, resource potential and discovery of the Sinian–Cambrian giant gas field, Sichuan Basin, SW China. Petroleum Exploration and Development 41: 278–293 (in Chinese with English abstract).

An overview of types and characterization of hot fluids associated with reservoir formation in petroliferous basins

Abstract

Keywords

Introduction

Crust-derived hot fluids

Characteristics of crust-derived hot fluids in the Tarim Basin

(1) Fluoritization of carbonate and related reservoir

(2) Silicified reservoir

(3) Hot fluid-altered dolomite reservoir

Identification criteria of deep hot fluids in the Tarim Basin

(1) Lithological and mineralogical characteristics

(2) Fluid inclusion analyses

(3) Geochemical analyses

Hydrocarbon-related hot fluids

Origin and composition of hydrocarbon-related hot fluids

Indicators of hydrocarbon-related hot fluids

Mantle-derived hot fluids

Identification of mantle-derived fluids

Effect of CO2-rich fluid on the evolution of sandstone reservoir in Huangqiao gas field

Summary and conclusions

Footnotes

Declaration of conflicting interests

Funding

References

Effect of CO₂-rich fluid on the evolution of sandstone reservoir in Huangqiao gas field