The wide distributions of excellent source rocks and thick reservoirs in the Triassic Yanchang Formation from Ordos Basin are two key factors for the formation of large-area tight oil of the Yanchang Formation^{[1,2,3,4,5,6,7,8,9]}. Member 6 of the Triassic Yanchang Formation in the Jiyuan-Wuqi area (hereinafter shortened as Chang 6) is now a gentle west-dipping monoclinic slope with two major provenances, the northeastern and the northwestern in the early stage^[10,11]. It is a delta-shallow lake sedimentary system, with sandbodies in large area, furthermore, the underlying Member 7 of the Yanchang Formation (hereinafter shortened as Chang 7) has a sufficient hydrocarbon supply, and the overlying Member 4-5 of Yanchang Formation could act as good caprocks. Influenced by the tectonic stress and differential compaction, a series of low-amplitude structures have formed in the Chang 6 Member, which is favorable for generating large-area continuous or quasi-continuous oil and gas reservoirs, and large-scale oil reservoirs have been discovered in Chang 6 Member^{[12,13,14,15,16,17]}. But this kind of double-provenance sedimentary system has strong heterogeneity, complex source-reservoir relationship, complicated oil-water distribution and elusive hydrocarbon accumulation pattern, hindering further exploration and development of this area. Comprehensive analysis shows that the study area has the following issues: (1) The Chang 6 oil layer, in close contact with the Chang 7 high-quality source rock, has sufficient oil supply, according to the theory of 'near-source-continuous tight oil accumulation', the hydrocarbons should have been accumulated in a large scale^[18,19,20], but oil reservoirs discovered so far are mainly distributed in the Baoziwan-Majiashan in the lower part of slope (the western blocks) and the Xin’anbian-Northern Anbian in the high part of slope (the eastern blocks), while the middle of slope produces water. (2) The Chang 6 oil layer is divided into the Chang 6₃, Chang 6₂ and Chang 6₁ sublayers, of which the Chang 6₁ has an obviously higher hydrocarbon accumulation degree than the other two sublayers nearer to the source rock. (3) The middle of the study area is the part where deposits from the two provenances intersect, the sandbodies are thick cumulatively, the reservoirs have similar physical properties with the eastern and western oil-bearing areas, and the underlying high-quality source rock also exists, but this part has low hydrocarbon accumulation degree.

A lot of researches on the study area have been done before, but mostly focused on the sedimentary environment^[21,22], the origin and distribution of sandbodies^[23,24,25], the sedimentary reservoirs and other basic geology characteristics^[26,27,28]. Few scholars covered the complicated oil-water distribution or the hydrocarbon accumulation regularity. In this work, the factors causing hydrocarbon enrichment differences are sorted out by comparing the sandbody development scale, reservoir physical properties, argillaceous layers between source and reservoir and fracture development between the eastern and western oil-bearing areas and the middle water producing area, and the hydrocarbon migration model in double-provenance sedimentary system is established, in the hope of guiding the prediction of hydrocarbon enrichment zones and “sweet spot” in this area and similar areas.

The Jiyuan-Wuqi area, located in the midwest of the Ordos Basin, covers the Tianhuan sag and Shanbei slope^[29] two structural units (Fig. 1). The Chang 6 Member is a gentle west dipping monocline slope, simple in structure. It has local nose-like uplifts with the amplitude from 10 m to 20 m^[30].

The Upper Triassic Yanchang Formation in Jiyuan-Wuqi area is a set of inland lacustrine basin clastic deposit, and is divided into 10 members from the top to the bottom (Chang 1 to Chang 10). The basin reached into its heyday during the depositional period of Chang 7 Member, and started to shrink during the depositional period of Chang 6 Member, when the basin entered the stage of filling-up and convergent sedimentation with outstanding features of sufficient source supply in the northeast and obvious shrinkage of deep-lake part^[31]. The Chang 6 Member, about 120 m to 125 m thick, is largely made up of grey fine-medium feldspathic sandstone and clastic feldspar sandstone and in conformable contact with the underlying the Chang 7 source rock. The Chang 6 Member is divided into the Chang 6₃, the Chang 6₂ and the Chang 6₁ submembers with the thickness of 42-44 m, 39-41 m and 38-40 m respectively.

The oil-water distribution of the Chang 6 Member in the Jiyuan-Wuqi area has a large difference on the plane and in the longitudinal direction. The details are as follows:

The eastern part and the western part of study area are the major oil enrichment zones of the Chang 6 Member, while the middle part produces water with little oil and has a low oil and gas abundance and no scale reservoirs (Fig. 2). In longitudinal, the Chang 6₁, Chang 6₂ and Chang 6₃ differ widely in oil and gas enrichment degree, the Chang 6₁ has higher oil and gas enrichment degree than the Chang 6₃ and the Chang 6_2, while the latter two are similar in oil and gas enrichment degree. The reservoir distribution in each submember is very complicated too, especially in Chang 6₁. Although it has higher oil and gas enrichment degree on the whole, the oil-water distribution on the plane is very complex.

Statistics on formation testing and production data of the Chang 6 Member in 690 wells (sections) and oil saturation from logging interpretation of 503 wells in the eastern, the western and the middle parts show the sandbodies in the eastern and western parts have better oiliness, higher hydrocarbon enrichment degree and mainly oil layers, while the middle part has otherwise poorer oiliness, lower oil and gas enrichment degree and largely water layers. In the western part, the oil layers and oil-water layers account for up to 74.86%, while the water layers and dry layers only make up for 25.14%, and the sandbodies with oil saturation of over 30% account for up to 64.76%. In the eastern part, the oil layers and oil-water layers account for 66.73%, the water layers and dry layers account for 33.27%, and the sandbodies with an oil saturation of over 30% account for up to 55.13%. In the middle, the oil layers and oil-water layers take 66.73%, the oil layers and oil-water layers up to 68.75%, and sandbodies with an oil saturation of over 30% occupy only 31.24%.

Pristane and phytane are related to sedimentary environment, and therefore, they are biomarkers used commonly for oil-oil and oil-source correlation^[33]. Generally, the oxidability turns stronger with the increase of Pr/Ph^[34]. At present, sedimentary environment is often identified by using the Pr/Ph index put forward by Didyk, and Pr/Ph less than 1 indicates reductive environment while Ph/Ph over 3 indicates oxidative environment^[35]. But in practical application, as the continental sedimentary environment of China is complex, oil and gas produced by source rock in different blocks of the same horizon and basin could differ somewhat in this ratio. Especially for larger sedimentary lacustrine basins, the supply and exchange of oxygen in the center (deep lake facies) would be much more difficult than those in the margin near river entrance. Besides, some terrestrial higher plants would mix into the source rock in the margin of lacustrine basin, resulting in higher Pr/Ph of crude oil than that in the center of basin.

The analysis on Pr/Ph of crude oil from the Chang 6 Member in the Jiyuan-Wuqi area shows that the Pr/Ph ratio of different blocks have wide differences (Fig. 3a). In the eastern blocks, Pr/Ph of crude oil ranges from 1.17 to 1.39, with an average of 1.30, which is similar to that of the underlying Chang 7 source rock (with Pr/Ph from 1.06 to 1.65, 1.43 on average). In the western blocks, the Pr/Ph is from 0.76 to 1.06, and 0.95 on average, which is also similar to the underlying Chang 7 source rock in the western part, which has a Pr/Ph from 0.70 to 1.19, 0.96 on average. The Pr/Ph of the eastern and western parts have some discrepancy and are similar to the underlying source rock of the areas respectively, indicating that oil and gas in these parts mainly migrated vertically, with no large scale lateral migration. The Pr/Ph in the eastern part is much higher than that in the western part, indicating the organic matters producing oil in the eastern part deposited in more oxidizing environment than that of the western part. Based on Pr/Ph and Pr/nC₁₇ and Ph/nC₁₈ (Fig. 3b), the parent material of Chang 6 crude oil in the western part was formed in reduction environment while that in the eastern part was formed in weak-oxidation and weak-reduction environment, with some terrestrial higher plants mixed in.

During the deposition of Chang 7 Member, the Ordos Basin developed lacustrine delta system, of which the lake facies was divided into deep lake, semi-deep lake and shallow lake subfacies, and delta facies was divided as delta plain, delta front and pre-delta subfacies^[36]. Source rock formed in different sedimentary environments are different in distribution, organic matter abundance and type, in deep lake-semi-deep lake in the lacustrine center mainly developed oil shale with large thickness, while in shallow lake and pre-delta subfacies mainly deposited dark mudstone and silty mudstone and thinner oil shale^[37]. For large sedimentary basins like Ordos Basin, massive terrestrial water fed into the margin of basin, resulting in stronger oxidation of water in the margin than that in the center. Therefore, source rocks in different sedimentary positions have some minor differences in properties, and it can be speculated that Chang 6 crude oil in the western part is derived from Chang 7 source rock in the lacustrine center while that in the eastern part is derived from Chang 7 source rock in the margin.

In addition, Chang 7 source rocks in the eastern part and western part also have some differences in regular sterane (Fig. 4a, 4b). In the source rock of western part, the regular sterane has a higher C₂₇ content, ααα20RC₂₇/C₂₉ from 0.90 to 1.67, on average 1.32, and “L” distribution, indicating the parent materials are mainly derived from lower aquatic organisms. In the source rock of the eastern part, the regular sterane has higher C₂₉ content, ααα20RC₂₇/C₂₉ between 0.41 and 0.73, 0.58 on average, and “reverse L” distribution, which indicates that compared with the source rock in the western part, the source rock in the eastern part has more organic matter input from terrestrial higher plants.

Furthermore, extracts from Chang 6 reservoir in the eastern and western parts also have some minor differences in sterane distribution (Fig. 4c, 4d). Extract from Chang 6 sandstone in the eastern part has C₂₉>C₂₇>C₂₈, similar to the eastern source rock. In contrast, extract from the sandstone in the western part has C₂₉>C₂₇>C₂₈, similar to the western source rock. The sterane distribution of the eastern and western area suggests the crude oils in eastern and western parts come from different source rocks. The crude oil in the eastern part is originated from source rocks in the eastern margin of the lake, while crude oil in the western part is derived from western source rock in the center, which reveals the crude oil in the eastern part does not come from the lateral migration oil generated in the western part along the dipping slope.

The Chang 7 Formation in the study area is mainly lacustrine-delta deposit^[38]. Though the source rocks in the western, the eastern and the middle parts do have some differences in thickness (Fig. 5), they are all high-quality source rocks, with type Ⅰ-Ⅱ₁ organic matters, high organic matter content (average TOC of up to 4.40%), vitrinite reflectance of 0.88% on average, cumulative oil production intensity of (60-600)×10⁴ t/km² and cumulative oil discharge intensity of (2-18)×10⁴ t/km^2[39]. In addition, the overlying Chang 4-5 Member can act as good caprocks, constituting a favorable source reservoir cap-rock assemblage^[39,40]. The Chang 6 Member in the study area exactly overlies the high-quality source rock, but oil reservoirs in this member differ in enrichment degree on the plane, the eastern and western parts have large scale oil reservoirs, while the middle part produces water. Therefore, source rock is not responsible for the oil enrichment differences of the Chang 6 Member, and more factors including the sandbody scale, reservoir physical properties, source-reservoir contact and fracture development should be examined to sort out the cause.

4.2.1. Sandbody scale

When the Chang 6 Member started to deposit, the basement of Ordos Basin began to uplift, consequently, the sedimentation rate was higher than the settling rate, and the lacustrine basin entered shrinking stage^[29]. The Chang 6 Member in the study area had the northwestern and northeastern provenances, of which the northeastern one had stronger supply capacity. From the depositional period of Chang 6₃ to Chang 6₁, the lake shoreline pushed southward gradually, the semi-deep-deep-lake part in the south shrunk gradually, while the delta plain in the north gradually expanded, so the period was a delta construction period featuring lake retreat and sand advancing^{[12-14,27,29]}. Under the control of lacustrine sedimentary evolution^[38], the Chang 6 sandbodies from the bottom to the top get thicker and better in connectivity, and sandbody scale controls the oil and gas enrichment difference vertically. According to the well-connected profile (Fig. 6), the Chang 6 single sandbodies get thicker from bottom to top, which is consistent with the hydrocarbon enrichment degree, and the Chang 6₁ has the highest hydrocarbon enrichment degree with the thickest sandbody. Based on sandbody logging interpretation of 179 wells, sandbodies in Chang 6₁ are 4 m to 8 m thick each and 4.87 m thick on average, and production test shows the oil layers and oil-water layers account for up to 70%. The sandbodies in Chang 6₂ are 3 m to 6 m thick each and 3.86 m thick on average, and production test shows oil layers and oil-water layers take up to 48%. Sandbodies in Chang 6₃ are smaller and thinner, at 2 m to 4 m thick each and 3.05 m thick on average, and production test shows oil layers and oil-water layers only make up for 26%. From the perspective of single wells, the sandbody scale has a good correlation with the hydrocarbon enrichment degree, and the larger the sandbody scale, the higher the enrichment degree is. Taking Well A36 in the eastern part as an example, the Chang 6₃ about 45 m thick has sandbodies discontinuous and thin and large in number, with an average single sandbody thickness of 2.97 m, and sand and mudstone interbed frequently, and which was tested a water layer. The Chang 6₂ about 38 m thick with an average single sandbody thickness of 3.63 m, was tested a water layer. Chang 6₁ about 49 m thick, with an average single sandbody thickness of 4.74 m, was tested an oil layer with daily oil production of 8.75 t.

Core photographs show that the sandbodies in the Chang 6 of different blocks also differ widely in scale (Fig. 7), and the sandbody scale does control the hydrocarbon enrichment degree. For example, sandbodies in Chang 6₁ of Well H246 in the west and Well A36 in the east are continuous and thick, pure and low in shale content, and the cores are oil-rich. In contrast, the sandbodies in Chang 6₁ of Well C57 and Well L108 are thin and discontinuous, high in shale content, and rich in argillaceous layers, and the cores contain no oil. Logging interpretation of 179 wells in study area (Fig. 8) reveals that in the east, sandbodies are up to 6.5 m thick on average, pure and low in shale content (11.7%), and the exploration has achieved good results. In the western area, sandbodies are 4.1 m thick on average, pure and low in shale content too (13.4%), and oil reservoirs occur in large area. In the middle part, sandbodies are thinner with an average thickness of 3.8 m, high in shale content (16.0%), and rich in argillaceous layers, and most wells produce water.

In addition, statistics on interlayers in the 3 blocks (Table 1) show that the eastern and western parts have lower frequency of interlayers, the middle part where the provenances intersected has higher frequency of interlayer and stronger vertical heterogeneity of sandbody. The western block has an average stratification coefficient of 10.80 and interlayer frequency of 0.097/m. The eastern block has an average stratification coefficient of 9.78 and interlayer frequency of 0.094/m. The middle block has an average stratification coefficient of 13.20 and interlayer frequency of 0.131/m.

4.2.2. Reservoir physical properties

The low permeability-tight oil reservoir is characterized by large-area oil-bearing, local enrichment, and strong heterogeneity^[41]. Vertically, analysis of 1208 samples collected from 3 members of the Yanchang Formation shows the reservoir physical properties get better from the Chang 6₃ to the Chang 6₁. The Chang 6₁ has a porosity mainly between 8% and 18%, 15.04% on average, and a permeability of (0.5-3.0)×10^-3 μm² , 1.12×10^-3 μm² on average. The Chang 6₂ has a porosity between 9% and 15%, 13.12% on average, and permeability between (0.5-1.0)×10^-3μm², 0.85×10^-3 μm² on average. The Chang 6₃ has a porosity between 6% and 12%, 11.86% on average, permeability between (0.1-1.0)×10^-3 μm² and 0.78× 10^-3 μm² on average. The physical properties are consistent with oiliness vertically, the Chang 6₁ has the best physical properties and the highest oil enrichment degree. Take Well H76 for example, the 3 members are similar in scale, but different greatly in test results: the Chang 6₁ is an oil layer, while Chang 6₂ is a water layer and Chang 6₃ is a dry layer.

From the analysis of the 3 members, the Chang 6₁ tested as oil layer has the best physical properties, with an average porosity of 14.38% and average permeability of 1.26×10^-3 μm², the Chang 6₂ tested as a water layer comes second in physical property, with an average porosity of 12.63% and average permeability of 0.57×10^-3 μm²; the Chang 6₃ tested as a dry layer has the worst physical properties, with an average porosity of 8.52% and permeability of 0.13×10^-3 μm². Apparently, the reservoir physical properties control the oil enrichment difference vertically.

On the plane, the same layer in different areas also varies in physical properties. Analysis of Chang 6₁ physical properties shows there is a positive correlation between oil saturation and physical properties and heterogeneity, and the difference in reservoir physical properties and heterogeneity in different parts is consistent with the planar reservoir partition. In the eastern part, the reservoir has an average porosity of 15.47%, average permeability of 1.23×10^-3μm², coefficient variation of 0.26, permeability heterogeneity coefficient of 1.80, and range of 3.24, indicating good physical properties, weak heterogeneity and high oil saturation. In the western part, the reservoir has an average porosity of 15.18% and average permeability of 0.96×10^-3 μm², coefficient variation of 0.22, permeability heterogeneity coefficient of 1.67, and range of 2.71, denoting good physical properties, low heterogeneity and high oil saturation too. In the middle part where the provenances intersect, the reservoir has an average porosity of 14.54%, average permeability of 0.84×10^-3 μm², coefficient variation of 0.56, permeability heterogeneity coefficient of 2.28, and range of 32.74, indicating poor physical properties, strong heterogeneity and low oil saturation.

Besides, the difference in physical properties of the same reservoir section also controls the oiliness difference. Take Well H246 for example (2 084.60-2 085.75 m), the sandstone differs widely in oiliness (Fig. 9). The core with oil is grayish black, while the core without oil is grayish white. Thin sections of the two types were observed under microscope, grayish white sandstone has little fluorescence and poor oiliness, and low porosity and permeability (9.6% and 0.06×10^-3 μm²) correspondingly. The grayish black sandstone has strong green yellow fluorescence evenly distributed in pores and good oiliness, and higher porosity and permeability (14.16% and 0.98×10^-3 μm²).

The Jiyuan-Wuqi area, located in the northeastern part, has lacustrine deltaic deposit. The eastern and western oil-bearing areas are in the range of the northeastern and northwestern provenances respectively, while the water-bearing area is situated in the area where the two provenances intersected. These parts differ in sandbody scale and connectivity, reservoir physical properties and vertical heterogeneity. In the western and eastern areas near the provenances, the sandbodies are mainly composed of underwater distributary channels stacking over each other vertically. The sandbody is pure, thick, low in shale content, with few interlayers, so the reservoir has good physical properties and high oil and gas enrichment degree. In the middle area where two provenances intersected, where due to rapid drop of hydrodynamics, the deposit has higher shale content, more interlayers, sand in multiple thin layers, fast variation of lithology, and strong vertical heterogeneity, so the reservoirs have poor physical properties, inconducive to oil and gas accumulation^[42]. Hence, the favorable reservoir is crucial for tight oil accumulation in the Chang 6 Member. Sandbodies in the western and eastern area are thicker, and good in connectivity, so the reservoirs there are of high enrichment degree. In the middle part, the sandbodies have rich argillaceous laminae, small thickness and poor connectivity, and produce water largely.

From the above analysis, sources are different for the eastern and western oil-bearing areas. Oils in the two parts mainly come from the underlying source rocks through vertical migration with no large-scale lateral migration. For the reservoir with low porosity and permeability, charging force is a key element for high-yield oil and gas. Analyzing the reservoir accumulation of the Yanchang Formation, the Ordos Basin and the Lianggaoshan Formation of the Sichuan Basin, we found that the continental facies formations have strong heterogeneity both vertically and horizontally. During the deposition of sandbody when lake basin turned shallow, a series of tight laminated sandstone with high shale content would come about. This kind of sandstone has very poor physical properties and high oil expulsion pressure, without connection of fractures, they would severely obstruct vertical migration and accumulation of oil and gas^[43]. The middle part is the area where the northwestern and the northeastern provenances intersected, where the hydrodynamic force dropped drastically when the provenances and sediments met, and the muddy sediments increased, so large-scale tight laminated sandstone came about between the Chang 6 and Chang 7 Members (Fig. 10).

Argillaceous laminae are formed due to the fast changes of sedimentary environment, which would definitely influence the reservoir quality and permeability, blocking the migration and accumulation of oil and gas. Take the sandbody of 2270.77-2 274.50 m in Well C71 for example, the upper part (2 270.77-2 272.64 m), purer in sandbody with no laminae (Fig. 11), has better physical properties, with an average porosity of 14.87% and permeability of 0.97×10^-3 μm². The sandstone of lower part (2 272.64-2 274.50 m) with higher shale content and more argillaceous laminae, has poorer physical properties, with an average porosity of 4.95% and permeability of 0.12×10^-2 μm². Fluorescent analysis of the lower part shows the sandstone has poor fluorescence and hardly break through the tight sandstone with argillaceous laminae, and thus the overlying sandstone with better physical properties has poor oiliness.

From thin sections and mercury injection experiments of the pure sandbody and section with argillaceous laminae (Fig. 12), the pure sandbody has higher mercury saturation, lower median pressure and displacement pressure, indicating the reservoir has good pore structure, which is favorable for oil and gas charging. The sandstone has strong fluorescence under microscope and higher oil enrichment degree. The samples with muddy argillaceous laminae had lower mercury injection saturation and much higher displacement pressure, indicating poor pore structure is not conducive to oil and gas charge, and they had weak fluorescence under microscope. That is to say it is hard for the underlying hydrocarbon to break through the tight sandstone with argillaceous laminae, without fractures to connect, which seriously hinders the vertical migration of oil and gas. No surprise, the middle part has low oil and gas enrichment degree and produces water largely.

The Yanchang Formation of the area have abundant fractures, which are the most important migration channels in basin and dominant element for reservoir distribution^[44]. From core observation and thin section analysis (Fig. 13), the Chang 6 Member in the Jiyuan-Wuqi area has abundant fractures, mainly high-angle fractures, hardly any low-angle and horizontal fractures. The fractures mainly strike NEE-SEE and NE-SW. Some are filled with calcite and have oil on the surface, and strong fluorescence under the microscope, proving the fractures control the migration of oil.

Statistics on fractures in cores (33 wells) and well logging images (11 wells), the eastern and western part have more fractures, while the middle part has fewer fractures (Fig. 14). The eastern area has a line density of fractures between 0.20-0.35, and on average 0.24/m; the western area 0.15-0.25 and 0.18/m; while the middle part has fewer fractures with lower line fracture density of 0.04/m on average. Fracture development is consistent with the known reservoir distribution. In the western and the eastern area, the reservoirs are large-scale with more fractures and highly oil and gas-enriched. In contrast, the middle part with few fractures has low oil and gas enrichment degree and is water-bearing. Clearly, fracture development controls the reservoir distribution. Take Well C269 for example, the sandbody of the Chang 6₁ (2 410.1-2 450.0 m) is not pure with high shale content, but the cores contain high-angle unfilled vertical fractures (Fig. 13d). The fracture is seen to fill with oil under the microscope (Fig. 13f, 13g). The fractures provide effective migration paths, leading to a high hydrocarbon enrichment degree and good fluorescent shows. High-angle fractures are also seen in eastern area (e.g.: Well Y116, A126), which were found containing oil under microscope and high in oil and gas enrichment degree. The well had good drilling results (Fig. 13a, 13c). In contrast, Well C105 and Y128 Y112 in the middle part have few fractures, in addition, argillaceous laminate are abundant, severely blocking the hydrocarbon vertical migration, unsurprisingly, the wells had poor drilling results and test results, and produced water primarily.

The Chang 6 Member is a double-provenance sedimentary system with sandbody developed and is near the high quality source rock of the Chang 7 Member. But the reservoirs in the eastern and western area produce oil, and water in the middle area. The differential oil and gas accumulation is mainly controlled by the following elements: (1) The crude oils of the eastern and western parts have small geochemical differences, indicating the oil and gas mainly migrated vertically. (2) The western and eastern parts were controlled by the northwestern and northeastern provenances respectively, where the sandbodies are thicker, with few argillaceous laminae and abundant fractures conducive to oil and gas vertical migration, so the reservoirs there are higher in oil enrichment degree and good in drilling results. (3) The middle part is in the intersection area, where the sandbodies are thin, large in number and poorer in lateral connectivity, and vary fast in lithology and physical properties, not favorable for lateral hydrocarbon migration. Besides, muddy laminae exists between reservoirs and sources with few fractures, blocking the vertical migration of oil and gas. Therefore, this area has low oil-enrichment degree and poor drilling results, and produces primarily water (Fig. 15).

For the continental sedimentary lake basin, hydrodynamic force would become stronger gradually in the process of lake retreating and sand advancing. Argillaceous laminae with high displacement pressure are likely to form between the source rock and reservoir, seriously blocking the vertical migration of underlying hydrocarbon. Besides, the continental sandbodies have strong heterogeneity, making it difficult to form large- scale continuous marine reservoirs similar to those abroad. The multi-provenance sedimentary systems, in particular, have fast changes in lithology and physical properties, strong heterogeneity vertically and horizontally, making reservoir distribution all the more complex.

The oil samples from the Chang 6 Member in the eastern and western Jiyuan-Wuqi area differ somewhat in geochemical features. The oil from the eastern part has higher Pr/Ph ratio, C₂₉ slightly higher than C₂₇ in regular sterane, suggesting the oil was derived from the underlying source rock at the edge of lake basin. In comparison, the oil samples from the western part have lower Pr/Ph and higher C₂₇ content than C₂₉, indicating the oil of western part is mainly from the underlying source rock in the middle of lake basin. Apparently, the oil in the eastern part doesn’t come from large-scale lateral migration from the western slope.

The Chang 6 reservoir in the Jiyuan-Wuqi area experienced lake retreat and sand advance. From the depositional stage of Chang 6₃ to Chang 6₁, the sandbody enlarges in scale and gets better in physical properties, resulting in gradual increase of oil and gas enrichment degree from bottom up. On the plane, the western and eastern oil-bearing areas are respectively in the northwestern and northeastern provenance sedimentary systems, where the sandbodies are thicker, better in physical properties and connectivity, pure with fewer argillaceous laminae, and rich in fractures, which is favorable for the oil and gas generated by the underlying source rock to migrate and accumulate vertically, so these parts have higher oil enrichment degree. In middle part where two provenances met, the sandbodies have great cumulative thickness but are thin and multiple in layers, and vary fast in lithology and physical properties, so the reservoirs here have strong heterogeneity and poor lateral connectivity, unfavorable for large-scale lateral migration. In addition, the middle part have many argillaceous laminae between the source and reservoir with high displacement pressure and few fractures, seriously blocking the vertical migration of oil and gas, so this part has low oil and gas enrichment degree and produces water primarily.

For the continental complex tight reservoirs, the relationship of source rock and reservoir and the development of fractures are the key elements for oil accumulation. Especially for the multi-provenance sedimentary systems, the meeting of provenances causes great vertical and horizontal heterogeneity. The prediction of potential area and sweet spot should not only consider high quality source rock and reservoir, but also migration conditions like contact of source rock and reservoir and fractures.