Petroleum systems capable of forming oil accumulations range from Archean to Neogene ^[1], including oil preserved in fluid inclusions in sandstones of ca. 2.9 Ga old ^[2], “live” oil shows reported in sedimentary rocks of ca. 1.4 Ga old^[3]. However, almost all reported reservoir oils that have been produced commercially are younger than 400 Ma ^[4⇓-6]. According to Miller ^[5], the median age for oil accumulations is only approximately 29 Ma, and over 75% of oil accumulations globally were charged within the last 75 Ma. Indeed, oil accumulations in geological history have been subject to various types of destruction and alteration, such as biodegradation and water washing, evaporative fractionation, thermal sulfate reduction (TSR), thermal cracking, tectonic activity, and fault leakage ^[7]. Tectonic reactivation and sealing capability are two fundamental factors impacting oil preservation after entrapment ^[8-9]. Thermal cracking exerts a significant effect on oil accumulation in the deep and ultra-deep reservoirs, often promoting the conversion of oil to condensate or gas ^[4,8]. The temperature at which oil cracking begins is generally believed to be greater than 160 °C^[10⇓-12].

The carbonate platform area of the Tarim Basin shows huge resource potential and is an important exploration frontier for deep and ultra-deep oil and gas exploration in China ^[13⇓-15]. The marine carbonate strata in the carbonate platform area are commonly situated in the lower stratigraphic interval of the Tarim Basin with old ages and large burial depths. After multiple cycles of tectonic activity, marine carbonate reservoirs have undergone complex destruction and alteration ^[15-16]. The discovery of the Shunbei-Yuecan oilfield marks a major breakthrough in the oil and gas exploration of ultra-deep marine carbonate rocks in the Tarim Basin in recent years ^[17⇓-19]. The target reservoir layers are the middle-lower Ordovician Yijianfang and Yingshan formations with burial depths of over 7000 m. Different from the weathering crust reservoirs in the Tahe area, the Ordovician reservoirs in the Shunbei-Yuecan area are characterized by the faulting-karsting type, characterized by pervasive occurrence of oil but isolated distribution of commercial oil accumulations along the fault zone ^[17]. Yang et al. ^[20] indicated that the Shunbei area mainly experienced two significant oil charge events, of which the first occurred during the late Caledonian Orogeny and the second during the mid-Hercynian Orogeny, respectively, and the oil reservoirs have been well preserved since then. In comparison, the understanding of the charge and evolution history of the Ordovician reservoirs in the Yuecan area is relatively limited.

Oil-bearing fluid inclusions are small aliquots of geofluids entrapped in rock-forming minerals ^[21], such as quartz, feldspar and calcite, which record the geological information related to oil reservoir formation, alteration and destruction (biodegradation and water washing, evaporative fractionation, thermal cracking, TSR, and fault leakage, etc.) ^[22-23], and are generally not affected by subsequent geological processes after trapping. Detailed fluid inclusion analysis can help deciphering geochemical fingerprints of oil charged at different times, and reveal the charge history and secondary alteration process of oil reservoirs. At the same time, in-situ laser-ablation U-Pb dating of carbonates is a high-precision dating method developed for minerals with low U contents, which can achieve accurate dating of multi-generation calcite cements. It has been widely used in delineating faulting events and reconstructing fluid evolution history ^{[24⇓⇓-27]}. In particular, when oil charge event coincides with the formation of calcite cement, a small amount of oil droplets can be entrapped in the lattice defects of calcite as primary fluid (oil) inclusions ^[28]. In this case, the timing of oil charge event can be obtained indirectly by determining the formation timing of calcite cement containing primary fluid (oil) inclusions. In addition, the Ordovician Yijianfang Formation reservoir in Well YJ1X has a continuous coring interval of nearly 90 m, which provides abundant materials for studying the charge and evolution history of the reservoir in this area. Hence, by integrating in-situ calcite U-Pb dating, molecular composition characteristics of hydrocarbons, and fluid inclusion analysis, the charge and evolution history of the Ordovician ultra-deep reservoir in Well YJ1X in the Yuecan area can be elucidated. The work can also offer an in-depth understanding of the evolution process of the Ordovician ultra-deep reservoir in the Tarim Basin and provide a reference for future ultra-deep oil and gas exploration in the area.

The Yuecan area is located in the southwestern part of the Tabei Uplift in the northern Tarim Basin, adjacent to the Shuntuoguole Low Uplift, and between the Awati Depression and the Manjiaer Depression along the east-west direction (Fig. 1a). The strata encountered in the study area sequentially from top to bottom include Quaternary, Neogene, Paleogene, Lower Cretaceous, Lower Jurassic, Triassic, Lower Permian, Lower Carboniferous, and Upper Devonian, Lower Silurian and Ordovician strata. Similar to the Shunbei area, the Lower Paleozoic marine carbonate strata in the Yuecan area constitute a complete source-reservoir-cap rock assemblage (Fig. 1b). The reservoirs rocks are composed mainly of the Ordovician Yijianfang Formation (O₂yj) and the upper part of the Yingshan Formation (O_1-2y), and the reservoir space types are dominated by fault-related dissolution caves, vugs, dissolution pores and fractures ^{[17, 19]}. The overlying Upper Ordovician Sangtamu Formation (O₃s) mudstone and limestone serve as regional cap rocks, and the Lower Cambrian Yuertusi Formation (—C₁y) shale is considered as the main source rock in the study area ^{[17-19, 29-31]}. The main oil-bearing layer of Well YJ1X (Fig. 1a) is within the Ordovician Yijianfang Formation at the depth interval between 7178.54 m and 7260.00 m (Fig. 2). The current reservoir formation temperature is 155.27 °C with a calculated geothermal gradient of 21.5 °C/km. The corresponding formation pressure of the reservoir is 81.83 MPa with an estimated pressure coefficient of 1.13. The reservoir formation water is typical of a CaCl₂ type, and has salinity values of 152 358-173 493 mg/L.

Thirty core samples in the Yijianfang Formation (O₂yj) were collected from the oil-bearing carbonate rocks of Well YJ1X over the depth interval of 7203.60 m to 7290.18 m (Fig. 1a). Analyses performed on these reservoir rocks include sequential Soxhlet extraction, calcite vein petrography, in-situ calcite U-Pb dating and fluid inclusion analysis. Because the calcite veins in the carbonate reservoirs in Well YJ1X are too fine to be dated using the in-situ calcite U-Pb dating technique, and considering that the Shunbei area and the Yuecan area share similar sedimentary environment and fluid evolution history, five core samples of the Ordovician Yijianfang Formation in Well SB5 (Fig. 1a) in the Shunbei area were selected (sampling depth: 7331.27 m to 7427.30 m) to assist in calcite vein characterization and in-situ calcite U-Pb dating. The oil sample used in this study was collected from the Ordovician oil layer in Well YJ1X (Fig. 2). The geochemical characteristics of the Ordovician reservoir oils in the Shunbei area are based on Yang et al. ^[20].

Sequential Soxhlet extraction experiments of crushed carbonate core samples were carried out at the State Key Laboratory of Organic Geochemistry, Guangzhou Institute of Geochemistry, Chinese Academy of Sciences. Following the procedure of Yu et al. ^[32], four carbonate core samples from Well YJ1X (Fig. 2) were sequentially extracted to obtain the free (extractable adsorbed) oils and inclusion oil extracts. The free oil and inclusion oil extracts from top to bottom in the present study are named as YJ-1A, YJ-2A, YJ-3A, YJ-4A and YJ-1B, YJ-2B, YJ-3B, YJ-4B, respectively. The free oils, inclusion oils and reservoir oil from Well YJ1X were then used for gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) analyses. Detailed experimental procedure follows that of Yang et al. ^[20].

In-situ calcite U-Pb dating was performed at the John de Laeter Centre, Curtin University, Perth, Australia, after an initial screening and identification of high-purity calcite grains via Tescan Integrated Mineral Analyzer (TIMA). Ablations utilized an ASI RESOlution-SE 193 nm excimer laser, and elemental abundances were determined using an Agilent 8900 QQQ quadrupole ICP-MS operated in single quad mode. Parameters include 10 Hz repetition rate, 4 J•cm^-2 laser energy, 87 μm spot diameter and 60 s ablation time at each data point. Raw data were processed using the Iolite 3.7 software. A natural calcite sample, WC-1 ((254.4±6.4) Ma), was used as the main reference standard ^[33]. U-Pb Tera-Wasserburg concordia plots were obtained using the IsoplotR program ^[34].

Ten core samples were characterized petrographically using a Zeiss Axio Imager A2m optical microscope and imaged by a Relion III cold-cathode device with beam voltages of up to 15 keV and an electric current of 500 μA. Twenty-five core samples were prepared as doubly polished wafers with approximately 80 μm in thickness for fluid inclusion petrography, fluorescence spectroscopy and microthermometry. Fluid inclusion petrography was carried out according to the FIA (Fluid Inclusion Assemblage) method proposed by Goldstein and Reynolds ^[21]. The abundance of oil inclusions in carbonate samples at different depths was characterized by the FOI (Frequency of Oil Inclusion) technique proposed by Eadington et al.^[35]. Fluorescence spectra of both oil inclusions and reservoir oil were obtained using a Horiba iHR320 imaging spectrometer. Microthermometry measurements of fluid inclusions were conducted on a Linkam THMSG600 heating-freezing stage using the cycling technique proposed by Goldstein and Reynolds ^[21]. The measurement precision is ±1 °C for the homogenization temperature and ±0.1 °C for the final ice melting temperature, respectively. The NaCl-equivalent salinity of aqueous inclusions was calculated based on an equation proposed by Bodnar ^[36].

The Ordovician ultra-deep oil reservoir in Well YJ1X of the Yuecan area is presently an undersaturated volatile oil reservoir overall. The reservoir oil has a density of 0.813 g/cm³, a viscosity of 3.25 mPa·s, a sulfur content of 0.20%, a wax content of 4.70%, and a production gas-oil ratio (GOR) of 141 m³/m³. It is classified as a light oil with low viscosity and low sulfur content. The abundances of saturated hydrocarbons, aromatic hydrocarbons, resin and asphaltene in the reservoir oil are 77.8%, 11.6%, 7.6% and 3.0%, respectively. In comparison, the abundances of saturated hydrocarbon, aromatic hydrocarbon, resin and asphaltene in the free oil obtained by core extraction are in the range of 41.0%-70.5%, 15.1%-18.9%, 10.5%-18.8% and 3.9%-23.6%, respectively. The abundances of the saturated hydrocarbons in the free oils gradually decrease with depth from 70.5% to 41.0%, while the abundances of resin and asphaltene show an opposite trend (Fig. 2).

The ratios of pristane/phytane for the oil, free oils and inclusion oils are all falling in the range of 0.30-0.92, indicating that the source rocks were deposited predominantly under anoxic conditions ^[1,37]. The ratios of pristane/nC₁₇ and phytane/nC₁₈ for the reservoir oil, free oils and inclusion oils range from 0.14 to 0.44, and 0.21 to 0.50, respectively, showing that the corresponding organic materials are dominated by marine organic matter (Type II) ^[38], which is similar to the geochemical characteristics of the Ordovician reservoir oils in the Shunbei area (Fig. 3). Abundant sterane compounds, including C₂₁ pregnane, C₂₂ homopregnane, diasterane, and C₂₇-C₂₉ regular steranes are detected in the reservoir oil, free oils and inclusion oils, and the relative abundances of C₂₇, C₂₈ and C₂₉ regular steranes show a typical V-shape distribution pattern. It can be seen from Fig. 4 that the relative content of C₂₉ regular sterane is the highest among the C₂₇-C₂₉ regular steranes, similar to the geochemical characteristics of Ordovician reservoir oils in the Shunbei area, indicating that green algae would be an important source for the organic matter ^[39]. The relative abundance of C₂₃TT (C₂₃ tricyclic terpene) in the reservoir oil of the Yijianfang Formation is the highest among all the terpenoids, and the values of C₂₀/C₂₃TT (ratio of C₂₀TT to C₂₃TT) and C₂₃TT/(C₂₃TT+C₃₀H) are 0.57 and 0.81, respectively. The values of C₂₀/C₂₃TT and C₂₃TT/(C₂₃TT+C₃₀H) for the free oils are in the range of 0.24-0.51 and 0.33-0.65, respectively. The terpene distribution of the inclusion oils is similar to that of the free oils, with corresponding values in the range of 0.26-0.99 and 0.21-0.65, respectively. It is worth noting that the relative content of tricyclic terpenes in the free oils and inclusion oils gradually decreases with depth, while the relative content of pentacyclic triterpenes shows an opposite trend. The values of C₂₃TT/(C₂₃TT+C₃₀H) in the free oils and inclusion oils decrease from 0.65 to 0.33 and 0.21, respectively, comparable to the trend of the relative content of saturated hydrocarbons in free oils decreasing with depth, while the relative content of resin and asphaltene increasing with depth (Fig. 2). The cross plot of DBT/P (dibenzothiophene/phenanthrene) and Pr/Ph indicates that the reservoir oil, free oils and inclusion oils are mainly located close to Zone 2 and Zone 3, similar to that of the reservoir oils in the Shunbei area (Fig. 5), manifesting that the corresponding source rocks may be shales deposited in a marine environment ^[40]. In summary, the geochemical characteristics of the oil, free oils and inclusion oils are similar to those of the reservoir oils in the Shunbei area, and they can be classified as one oil family. It is speculated that they were derived from marine source rocks deposited under similar depositional environments. The isomerization ratios of C₂₉ββ/(ββ+αα) and C₂₉20S/ (20S+20R) for the oil, free oils and inclusion oils are in the range of 0.47-0.57 and 0.45-0.55, respectively, indicating that the maturity of the source rock generating these oils would be close to or even greater than that of the peak stage of oil generation. Therefore, these parameters cannot be used as effective maturity indicators^[1]. MPI₁ and F₁ are common thermal maturity indicators used for characterizing high-mature hydrocarbons ^[41-42]. The cross plot of MPI₁ and F₁ shows that the oil, free oils and inclusion oils are all located in the lower left region, close to that of the early charged oil in the Shunbei area (Fig. 6). Based on the correlation of methylphenanthrene index MPI-1 and vitrinite reflectance ^[43-44], the calculated equivalent vitrinite reflectance values of the oil, free oil and inclusion oil range from 0.80% to 0.96%, comparable to that of the corresponding source rocks for the early charged oil in the Shunbei Ordovician oil reservoir ^[20]. In addition, the values of Ts/(Ts+Tm), MPI₁, F₁, and MDR for the free oils are quite close to that for the inclusion oils. These values vary less apparently in the vertical profile (Fig. 2), indicating that the hydrocarbons in the Ordovician reservoir in Well YJ1X have relatively consistent maturity.

Two generations of calcite cement (sequentially named as C1 and C2) based on paragenetic relationships were identified in the carbonate samples (Fig. 7a). The C1 calcite cement occurs as fracture fillings, mostly medium- coarse crystalline, and is characterized by blocky or mosaic aggregates with dark red cathodeluminescence or nonluminescence. The C2 calcite cement also occurs as fracture fillings and intersects the C1 calcite cement (Fig. 7b). It is composed mainly of blocky or mosaic calcite aggregates with orange cathodeluminescence. In-situ calcite U-Pb dating results show that the formation ages of C1 and C2 calcite cements are (446.1±4.4) Ma (Fig. 8a) and (425.7±14.0) Ma (Fig. 8b), respectively. These age results have verified the paragenetic relationships observed of calcite cements and provided constraints on the oil charge timing.

Fig. 2 shows the variation trend of frequency of oil inclusion (FOI) with depth in the reservoir in Well YJ1X. Oil inclusions are composed predominantly of diphasic (L_oil-V) and triphasic (S_bit-L_oil-V or L_oil-L_w-V) fluid inclusions, and a small number of multiphasic (S_bit-L_oil-L_w-V) and monophasic (L_oil) oil inclusions are also present (Fig. 9). Oil inclusions are commonly colorless or yellowish under plane-polarized light. Their fluorescence colors are dominated by yellowish white, near white, blue white and bright blue. Bitumen in oil inclusions usually occurs along the walls of oil inclusions or is suspended in the oil inclusions. Oil inclusions are primarily ellipse, elongated, square or irregular in shapes, 5-15 μm in diameters with vapor filling degrees varying from 5% to 20%. Two types of oil inclusion assemblages have been identified on the basis of differences in vapor filling degrees, fluorescence color and bitumen content in oil inclusions: Group I and II oil inclusion assemblages (Figs. 2 and 9). Group I oil inclusion assemblages are widely distributed, and were identified in almost all core samples. The occurrence range of Group II oil inclusion assemblages is relatively limited, which is confined to the current oil-producing interval.

Group I oil inclusion assemblages are characterized by bright blue fluorescing, diphasic (L_oil-V) fluid inclusions at room temperature with vapor filling degrees greater than 10% (Fig. 9a-9b). Most of Group I oil inclusion assemblages occur along annealed microfractures within calcite cements, and a small amount is concentrated along the growth zone of the C2 calcite cement or scattered within the calcite crystal (Fig. 9c), typical of primary fluid inclusions ^[21]. Group II oil inclusion assemblages emit blue-white, near-white and yellow-white fluorescence, have a vapor filling degrees of less than 5%, and are diphasic (S_bit-L_oil) or triphasic (S_bit-L_oil-V) at room temperature (Fig. 9d-g). Group II oil inclusion assemblages are mainly present along trails cutting across calcite crystal fabrics. Group II oil inclusion assemblages intersect Group I oil inclusion assemblages (Fig. 9h). The bitumen content in Group II oil inclusions increases with depth, while the vapor filling degrees decrease with depth. In the upper part of the reservoir in Well YJ1X, Group II oil inclusion assemblages are commonly composed of triphasic (S_bit-L_oil-V) fluid inclusions (Fig. 9d-9e); while in the lower part of the oil reservoir, Group II oil inclusion assemblages mainly consist of diphasic (S_bit-L_oil) fluid inclusions (Fig. 9f-9g), and often coexist with reddish-brown fluorescing solid bitumen in the pores.

The fluorescence spectral characteristics of the oil inclusions and oil investigated show systematic variations (Fig. 10). The λ_max and QF₅₃₅ values of Group I oil inclusions are in the range of 533.33-540.64 nm and 1.46-1.68, respectively. Comparatively, the λ_max and QF₅₃₅ values of Group II oil inclusions are 538.03-560.95 nm and 2.30-3.17, respectively. In addition, the λ_max and QF₅₃₅ values of the oil are 537.93 nm and 2.00, which are closer to that of Group II oil inclusions (Fig. 10a). Following the correlation between the QF535 parameter and the relative density of oils derived from the Tabei Ordovician oil reservoirs (Fig. 10b), the estimated relative densities of Group I and II inclusion oils are 0.808-0.815 g/cm³ and 0.825-0.862 g/cm³, respectively. Microthermometric measurements were carried out on 10 fluid inclusion assemblages, including a total of 133 oil inclusions and 63 aqueous inclusions (Table 1, Figs. 9i-9l and 11). Group I oil inclusions have T_h values ranging from 87.2 °C to 116.9 °C, with a mode of 90-95 °C (Fig. 11a). The coeval aqueous inclusions have T_h values of 90.5-115.6 °C, with T_m values between -7.5 °C and -3.5 °C (Fig. 11b). The obtained equivalent NaCl salinity lies in the range of 5.7%-11.1%, with an average of 8.5%. Group II oil inclusions have a wide range of T_h values, ranging from 28.0 °C to 70.2 °C with a mode of 50-55 °C (Fig. 11a). The T_h and T_m values of coeval aqueous inclusions are 85.2 to 111.5 °C and -14.9 °C to -14.2 °C (Fig. 11b), respectively. The equivalent NaCl salinities range from 18.0% to 18.6%, with an average of 18.3%.

Fluorescence color of inclusion oil has been widely used as a thermal maturity indicator ^[45], and generally exhibits a change from yellow to blue with increasing thermal maturity, and the corresponding fluorescence spectra exhibiting a "blue shift". It can be seen from Fig. 10a that the fluorescence spectra of Group I inclusion oil show an obvious "blue shift" compared with those of Group II inclusion oil and the oil, indicating that Group I inclusion oil corresponds to an apparent higher thermal maturity than Group II inclusion oil and the oil. However, such an interpretation clearly contradicts to the results of inclusion oil maturity calculated by aromatic hydrocarbon compounds aforementioned (Figs. 2 and 6). Indeed, the inclusion oils of YJ-1B, YJ-2B and YJ-3B are composed of both Group I and II inclusion oils, and the corresponding maturity of the inclusion oils calculated by aromatic hydrocarbon compounds should represent an "average" or "mixed" maturity of these inclusion oils. In comparison, the inclusion oil from the YJ-4B sample is composed mainly of Group I inclusion oil, which essentially represents the maturity related to Group I inclusion oil. However, the maturity-related geochemical parameters show an insignificant change trend in the vertical section (Figs. 2 and 6). It can thus be inferred that these two types of inclusion oils would have similar maturity and represent the same oil charge event.

Cheng et al. ^[46] and Ma et al. ^[47] indicated that the reservoir oils in the Shunbei and Yuecan areas have not been affected by biodegradation, water washing, evaporative fractionation or TSR. Therefore, all the above mechanisms cannot be involved in the process of reservoir alteration or destruction. Thermal cracking of oil is another important mechanism for the formation of these two types of oil inclusions. Crustal uplift and denudation and thermal events of magmatism are considered to be the main causes for the abnormal increase in temperature in the Tarim Basin during the Permian ^[48-49]. One dimensional basin modeling results showed that the current formation temperature represents the maximum value that has ever been experienced by the Ordovician reservoir rocks in the Shunbei area. The formation temperature in the current Ordovician oil reservoir in the Shunbei area is approximately 157.8-162.6 °C ^[20], close to the threshold temperature for thermal cracking of oil, indicating that the reservoir oils may have undergone slight thermal cracking. Likewise, the current formation temperature in the reservoir of Well YJ1X is 155.27 °C. In this case, severe thermal cracking of the reservoir oil in the oil reservoir in Well YJ1X is unlikely. Ping et al. ^[50] pointed out that thermal cracking of inclusion oil in the same fluid inclusion assemblage usually causes a "blue shift" in the fluorescence color of oil inclusions and an increase in the relative content of bitumen and vapor filling degrees. In our current study such features were not observed. Therefore, thermal cracking of reservoir oil/inclusion oil is not the main cause for the formation of Group I and II oil inclusion assemblages.

Fault leakage can cause a sudden and sharp drop in reservoir pressure, resulting in loss of light hydrocarbon components in reservoir oil and precipitation of resin and asphaltene ^[51⇓-53]. Group I oil inclusion assemblages are composed mainly of diphasic (L_oil-V) fluid inclusions at room temperature with vapor filling degrees greater than 10%. During the microthermometric measurements, these oil inclusions homogenize into liquid phase, indicating that these oil inclusions were entrapped as pure liquid phase. The distribution of T_h values of Group I oil inclusions is approximately consistent with that of the coeval aqueous inclusions (Table 1, Fig. 11a), indicating that these oil inclusions were entrapped in a gas-near-saturated state in the oil reservoir ^[49-50]. Group II oil inclusion assemblages consist mainly of diphasic (S_bit-L_oil) or triphasic (S_bit-L_oil-V) fluid inclusions at room temperature with vapor filling degrees of less than 5%. Bitumen in Group II oil inclusions usually occurs along the walls of oil inclusions or is suspended in the oil inclusions, and its relative content gradually increases with depth. Group II oil inclusions commonly change from three phases (S_bit-L_oil-V) to two phases (S_bit-L_oil) during microthermometric measurements, suggesting that they may be entrapped by heterogeneous phases. The T_h values of Group II oil inclusions are generally lower than those of the coeval aqueous inclusions (Table 1, Fig. 11a), which may indicate that the entrapped oil is under-saturated with gas ^[54-55]. The fluorescence characteristics of the oil are similar to that of Group II oil inclusions (Fig. 10). The lower boundary of the present YJ1X oil reservoir is consistent with the occurrence depth range of Group II oil inclusion assemblages (Fig. 2). These evidences would collectively suggest that the oil entrapped by Group II oil inclusions is basically the same as the oil in the present reservoir. Group II oil inclusion assemblages record the occurrence of the last oil charge, adjustment or alteration events inside the reservoir. Compared with Group I oil inclusion assemblage, the occurrence depth range of Group II oil inclusion assemblages is significantly reduced (Fig. 2), which may be caused by light hydrocarbon leakage. The relative contents of resin and asphaltene in the free oils and tricyclic terpenes and pentacyclic triterpenes in the free oils and inclusion oils as a function of depth also indicate that the reservoir oil has undergone gravitational segregation, with heavy resin and asphaltene components gradually accumulating in the lower part of the oil reservoir. Based on the above understandings, it is inferred that some micro-leakage along faults would be the main cause for the formation of the contrasting groups I and II oil inclusion assemblages. Group I oil inclusion assemblages record the charge process of the initial gas-saturated oil, while Group II oil inclusion assemblages reflect the characteristics of the gas-undersaturated oil in the current reservoir after a micro-leakage.

Some Group I oil inclusion assemblages in the C2 calcite cement show typical characteristics of primary fluid inclusions petrographically (Fig. 9c), indicating that the formation time of these oil inclusions may be coeval with the time when C2 cementation occurred. Therefore, the formation time of the C2 calcite cement (425.7±14.0 Ma) can indicate the hydrocarbon charge timing related to Group I oil inclusions. Indeed, hydrocarbon charge timing can be commonly determined by projecting the T_h values of the aqueous inclusions coeval with oil inclusions onto the basin burial history curve ^[56]. Considering the potential effect of fluid inclusion re-equilibration in calcite ^{[21,57⇓ -59]}, the minimum value of aqueous inclusions coeval with oil inclusions was chosen to represent its minimum trapping temperature in the present study. The trapping of Group I oil inclusions can thus be interpreted to have occurred in the Early Devonian (T₁, ~415 Ma; Fig. 12), which is quite comparable to the formation age of the C2 calcite cement; while the trapping of Group II oil inclusions occurred in the Middle Devonian (T₂, ~384 Ma), which represents the formation time of the residual/remaining oil reservoir after some gas and light hydrocarbon leakage. Combined with the tectonic evolution history of the study area, the formation and evolution history of the Ordovician ultra-deep reservoir in Well YJ1X can be divided into the following three periods.

In the Early Caledonian Orogeny (Cambrian-Early Ordovician), stable platform carbonate strata developed in the Tabei area. Under the influence of unconformity related to sedimentary discontinuity and meteoric water karstification, karsting reservoirs were widely developed in the Yuecan area. During the middle Caledonian Orogeny (Ordovician), affected by the overall uplift of the Tazhong and Tabei uplifts, the Yuecan area was characterized by a near north-south trending structural low uplift belt, along with the NE-trending and NW-trending strike-slip faults that cut through the Cambrian strata. In the Late Ordovician, accompanied by the deposition of the Sangtamu Formation (O₃s) mudstone, a complete source-reservoir-cap rock assemblage was in place in the Yuecan area ^[17,19,29]. During the late Caledonian Orogeny (Silurian), a rapid subsidence of the Lower Cambrian Yuertusi Formation (Є₁y) in the Yuecan area promoted the source rock to become mature and generate oils ^[19-20]. Oils migrated upward along the near vertical strike-slip faults and charged into the Ordovician and Silurian traps to form large-scale oil accumulations. The oil charge event in the reservoir in Well YJ1X occurred approximately 425 Ma, when the equivalent vitrinite reflectance value of the Cambrian source rock reached approximately 0.9%, close to an early oil window. The gas in the oil was close to saturation, and this oil charge event was recorded by Group I oil inclusion assemblages.

During the late Caledonian-early Hercynian Orogeny (Silurian-Devonian), the Yuecan area was uplifted as a whole, and a series of large strike-slip faults developed and extended upward to the Middle-Lower Devonian strata ^[17,19,29]. Strong tectonic uplift led to large-scale denudation in this area ^[60-61]. The overlying Silurian reservoirs experienced severe biodegradation due to their shallowness and lack of high-quality cap rocks, resulting in the widespread occurrence of the Silurian bituminous sandstones ^[62]. In contrast, the Ordovician oil accumulations underneath in the Yuecan area were not affected by biodegradation, due to their relatively deep burial and excellent preservation conditions. However, tectonic uplift and strike-slip fault activity in this area may have destroyed the integrity of the Ordovician reservoir and caused a sharp drop in formation pressure through the leakage of gas and light hydrocarbons. When the formation pressure dropped to the bubble point pressure of the reservoir oil, the light hydrocarbon components in the reservoir oil would leak upward along the fractures or relatively high-porosity and high-permeability conduits in the cap rocks. The volatilization of the light hydrocarbon components disrupted the equilibrium state of non-polar components in the reservoir oil, causing colloidal molecules to detach from the surface of asphaltene molecules to establish a new thermodynamic equilibrium. At the same time, the asphaltene molecules would flocculate in order to reduce the total surface free energy. When the degree of flocculation could overcome the Brownian suspension force, they would exsolve and precipitate ^[51-52]. These exsolved resins and asphaltenes precipitates gradually accumulated to the lower part of the oil reservoir under gravity, resulting in the enrichment of resins and asphaltenes in the lower oil of the reservoir. Therefore, more resins and asphaltenes can be found in the free oils as well as Group II oil inclusions in the lower part of the reservoir in Well YJ1X (Figs. 2 and 9d-9g). In addition, diffusion can also leak gas and light hydrocarbon components during the prolonged geological evolution process, resulting in changes in the composition of the reservoir oil.

In the Late Devonian, with an intrusion of seawater into the Yuecan area and the deposition of the Upper Devonian Donghetang Formation, the early Hercynian Orogeny ended ^[60]. Continued subsidence allowed the preservation of the residual/remaining oil reservoirs, but the oil column height was significantly reduced compared to that at the initial oil charge (Fig. 2). During the middle-late Hercynian Orogeny (Carboniferous-Permian), the Yuecan area changed from a tensional stress setting to a compressional stress setting, along with the development of compressional or compressive strike-slip faults, developing a tectonic pattern similar to that during the early Hercynian Orogeny. The mid-late Hercynian Orogeny is considered to be an important stage of oil charge in the Tabei area. Evidence of large-scale oil charge during this period has been found in the Yingmaili, Halahatang, Tahe and Shunbei oilfields ^{[7,20,63 -64]}. However, the contribution of oil charge during this period to the reservoir in Well YJ1X of the Yuecan area was little or absent with no obvious evidence being found in terms of reservoir geochemistry or oil inclusions. This may be attributed to the following two reasons ^[61,65]: Firstly, multiple sets of X-shape conjugate strike-slip faults were developed in the Yuecan area, but their main activation period was in the middle Caledonian to the early Hercynian Orogeny. During the middle-late Hercynian Orogeny, the fault activation was relatively weak, thus the oil charge intensity at this time was correspondingly low; Secondly, Well YJ1X is located on a secondary strike-slip fault, and the reservoir has poor connectivity with the underlying Є₁y source rock. During the Indosinian-Yanshan Orogeny (Triassic-Cretaceous), the Yuecan area continued to subside as a whole, and multiple episodes of tectonic movements did not exert any significant impact on the area. The present tectonic configuration of the Yuecan area was not developed until the late Himalayan Orogeny (Neogene-Quaternary) ^[17,29]. Because of the constantly decreasing heat flow in the Yuecan area ^[66-67], even though the depth of the Well YJ1X reservoir is more than 7000 m, the present formation temperature of the oil-producing reservoir interval is only around 155 °C. Under these conditions, the oil remains unaltered, devoid of significant thermal cracking. The formation water in the current reservoir is of CaCl₂ type and has a relatively high salinity of 152 358-173 493 mg/L, indicative of a well-preserved, closed hydraulic system. The formation water salinity is similar to that of the aqueous inclusions coeval to Group II oil inclusions (18.0%-18.6%), suggesting that the reservoir in Well YJ1X may have remained as a closed system since the trapping of Group II oil inclusions.

In summary, the reservoir in Well YJ1X only received one oil charge during the Early Devonian (~425 Ma) and has been basically well preserved except for some minor leakage of gas and light hydrocarbons in the Middle Devonian (~384 Ma). The reservoir is characterized by “early and shallow accumulation and late and deep preservation”. The preservation of the oil accumulation has been attributed to the stable tectonic environments, low geothermal conditions, and good sealing integrity and capability.

The reservoir oil, free (extractable adsorbed) oils and inclusion oils in the Ordovician ultra-deep oil reservoir in Well YJ1X can be classified as one oil family, derived from marine source rocks deposited under similar depositional environments. The reservoir oil, free oils and inclusion oils share similar maturities, with calculated equivalent vitrinite reflectance values in the range of 0.80%-0.96%.

Two types (groups I and II) of oil inclusion assemblages (OIAs) have been identified in the reservoir, of which Group I represents the original gas-saturated oil entering the reservoir during the initial oil charge, whereas Group II represents the undersaturated remaining/residual oil retained in the reservoir after a minor leakage of gas and light hydrocarbons. The Ordovician ultra-deep oil accumulation in Well YJ1X received only one oil charge during the Early Devonian around 425 Ma and has been well preserved after a minor leakage of gas and light hydrocarbons in the Middle Devonian (~384 Ma).

This study demonstrates that primary oil reservoirs can be preserved for over 400 Ma in some ancient craton basins with stable tectonic setting, low geothermal gradients and good sealing of cap rocks. The Ordovician ultra-deep oil accumulation in Well YJ1X is characterized by “early and shallow accumulation and later and deep preservation”. The evolution history of the oil accumulation provides some new insights into the charge, emplacement and preservation processes of ultra-deep oil accumulations in the Tarim Basin and elsewhere.

F₁—methylphenanthrene ratio;

FOI—frequency of oil inclusion, %;

MDR—methyldibenzothiophene ratio;

MPI₁—methylphenanthrene index;

QF₅₃₅—ratio of the integral area defined by 750 nm and 535 nm to that defined by 535 nm and 430 nm;

T₁—oil charge timing, Ma;

T₂—formation timing of residual reservoir, Ma;

T_h—homogenization temperature, °C;

T_m—final ice melting temperature, °C;

λ_max—wavelength at maximum fluorescence intensity, nm.