Oil-source Correlation Research Articles

Hydrocarbon resource evaluation of deep Paleogene source rock in Dongying Sag

The exploration breakthrough of well Fengshenxie 101 once again shows the great potential of sandy conglomerate in deep northern belt of Dongying sag. Based on the oil source correlation, it is confirmed that the condensate oil in this well mainly sourced from the lower part of Es4. The resource of the source rocks are the key factors affecting the exploration of this hydrocarbon system. Based on restoration of original organic matter abundance, the hydrocarbon resources are calculated using genetic method. The total are 4.67 × 108t, indicating that the deep layers of the Dongying sag still have great exploration potential.

Geochemical studies on high-efficiency hydrocarbon expulsion of Triassic lacustrine shale in the Ordos Basin, China: implications for tight and shale oil accumulation

The organic-rich sediments developed at the bottom of Chang7 Member of the Upper Triassic Yanchang formation, which can be divided into oil shale and black mudstones, are dominate source rocks for low permeability and tight oil reservoirs in Mesozoic petroleum system of Ordos Basin. The hydrocarbon expulsion characteristics of the organic-rich sediments have been investigated by geology and geochemistry data. By comparison with the geochemical parameters of crude oil samples and mudstone extracts, Chang7 shale has many geochemical evidences on high rates of hydrocarbon expulsion. Lower conversion rate of chloroform extracted bitumen “A”, especially for the samples with TOC higher than 10%; lower productivity indexes and lower hydrogen indexes reducing with TOC increasing; lower ratios of saturates/aromatics but higher contents of polar components for residual bitumen “A”; heavier stable carbon isotopes of residual hydrocarbons. It should be noted that the source rock evaluation and oil-source correlation would be misunderstood based on these abnormal geochemical data caused by high-efficiency hydrocarbon expulsion. Calculation for rock samples have shown that the expelled rates of the shale samples averaging 70% are significantly higher than those of the mudstone samples. Chang 7 shale with large amounts of hydrocarbons generated and expelled is critical for hydrocarbon accumulation in low-permeability and tight oil reservoirs. Also, Chang7 organic-rich rocks is an important exploration field of shale oil in the future.

Oil origins, mixing and biodegradation in southwestern Junggar Basin, NW China

The southwestern Junggar Basin is an attractive region for oil exploration. A major discovery of high oil production rate from a recently drilled borehole stimulated a new round of extensive petroleum exploration in this region. The potential source beds are within the Permian, Triassic, Jurassic, Cretaceous and Paleogene strata, but no effective oil-prone source rock samples have been drilled so far due to deep burial, leading to that oil source correlation remains controversial in the region. A total of 38 crude oils and the free, adsorbed and inclusion oils obtained from 18 oil-containing reservoir rocks from the southwestern and southern Junggar Basin were analyzed by GC, GC–MS and GC–IRMS for the purpose to classify oil groups, determine oil origins, and identify effective source beds in sags. Crude oils in the southwestern Junggar Basin can be classified into two end groups and an intermediate group, namely PO, JO and PJO oils, which were originated from the Permian lacustrine source beds, Jurassic terrigenous source beds and both, respectively. Ratios of C19/C20 tricyclic terpanes and C24 tetracyclic/(C24 tetracyclic + C26 tricyclic) terpanes are the most sensitive parameters to distinguish these three groups of oils. These two ratios increase from PO, PJO to JO oils. JO oils can be further classified into two subgroups, i.e. J1O and J2O. J2O oils have substantially higher amounts of C27 and C28 steranes relative to C29 steranes, higher amount of gammacerane, lower amount of C29 diasteranes, and lower isomerization ratios of steranes, compared with J1O oils. J1O oils were exclusively originated from the Jurassic source beds while J2O oil were mainly originated from the Jurassic source beds mixed with minor oils generated from the Paleogene and Cretaceous lacustrine source beds. In the Chepaizi uplift, the major PO oils and extracted oils from 14 reservoir rocks were mainly originated from source beds within the Lower Wuerhe Formation of Middle Permian (P2w). However, the remaining minor oil samples and extracted oils from the other four reservoir rocks were clearly originated from source beds in the Fengcheng Formation of Lower Permian (P1f) on the basis of molecular parameters and δ13C values of individual n-alkanes, indicating the presence of effective oil-prone source beds within the Fengcheng Formation in the Shawan sag. In shallow reservoirs within the Neogene Shawan Formation (N1s), PO, PJO and J1O oils are severely biodegraded while J2O oils have nearly no biodegradation effect because the former entered the reservoirs much earlier than the latter.

An integrated sequence stratigraphic–geochemical investigation of the Jurassic source rocks in the North Yellow Sea Basin, eastern China

The North Yellow Sea Basin (NYSB) is one of the petroliferous basins in the offshore region of eastern China. An integrated sequence stratigraphic–geochemical investigation was carried out to identify and assess the effective source rocks of recent oil discoveries in the NYSB. A total of four third-order sequences (the first [J2SQ1] and second [J2SQ2] third-order sequence within the Middle Jurassic, and the first [J3SQ1] and second [J3SQ2] third-order sequence within the Upper Jurassic) were identified in the Jurassic succession, in which four types of probable source rocks were distinguished, namely, lacustrine deep-water mudstones, lacustrine shallow-water mudstones, prodeltaic mudstones, and deltaic-plain mudstones. The lacustrine deep-water mudstones are widely distributed within the J2SQ1, J2SQ2, and J3SQ2 sequences in the gentle tectonic slope and depression area. They are characterized by moderate total organic carbon (TOC) contents (0.79−3.72 wt. %, with an average of 1.71 wt. %), lower hydrocarbon potential indexes (the amount of free hydrocarbons before analysis [S1] and the amount of hydrocarbons that results from cracking of kerogen [S2], i.e., S1+ S2, in a sample during Rock-Eval pyrolysis) (0.97 mg HC/g rock < S1 + S2 < 7.89 mg HC/g rock, with an average of 3.10 mg HC/g rock), and predominantly type II to type III kerogen. In contrast, the prodeltaic mudstones in J3SQ2 have higher TOC contents (1.5−4.0 wt. %, with an average of 2.71 wt. %), higher S1 + S2 (5.83−25.51 mg HC/g rock, with an average of 14.89 mg HC/g rock), and predominantly type I to type II kerogen. The oil–source correlation results indicate that the oils discovered in the NYSB mainly originated from the prodeltaic J3SQ2 mudstones. The effective source kitchen is mainly located in the northwestern part of the study area. The factors controlling the occurrence of high-quality prodeltaic source rocks are a sufficient supply of nutrients and terrigenous organic matter, high depositional rates, and a suboxic environment.

Application of Rare-Earth Elements and Comparison to Molecular Markers in Oil–Source Correlation of Tight Oil: A Case Study of Chang 7 of the Upper Triassic Yanchang Formation in Longdong Area, Ordos Basin, China

The biomarker features of 10 Chang 7 crude oil samples were investigated by gas chromatography–mass spectrometry (GC–MS), and the rare-earth element (REE) compositions of 16 Chang 7 and Chang 8 crude oil samples were determined by inductively coupled plasma–mass spectrometry (ICP–MS) for the first time in Longdong area. Oil–source correlation analysis was improved by biomarkers and REEs. The distribution and relative ratios of a series of biomarker parameters in saturated hydrocarbons and aromatic hydrocarbons of crude oil samples indicate that Chang 7 tight oil has already reached the mature stage. The organic matter mainly comes from lower aquatic organisms of algae, with some contribution of micro-organisms and bacteria, while the forming environment of tight oil is mainly the transitional environment of sub-oxidizing to sub-reducing. The V/(V + Ni) and Ni/Co ratios of crude oil samples suggest that the specific redox conditions of Chang 71 and Chang 72 samples were slightly oxic, while Chang 73 and Chang 8 samples were formed under an anoxic environment. The results of both biomarker-based and REE-based oil–source correlation analysis indicate that Chang 71 and Chang 72 tight oils come from Chang 7 mudstone, while most of the Chang 73 tight oils are from Chang 7 oil shale, with part of mixed from Chang 7 mudstone. This recognition may indicate that Chang 7 mudstone and oil shale are two relatively independent hydrocarbon self-generation and near-storage systems. The analysis results demonstrate that the REE composition in crude oil is an efficient and accurate tool for oil–source correlation in the petroleum system.

Geochemical characterization and origin of crude oils in the Oriente basin, Ecuador, South America

The Cretaceous oil reservoir located in eastern slope belt of the Oriente basin accounts for most of the discoveries in last decade in Ecuador, which makes the Oriente basin one of the most important oil exploration targets in South America. Crude oil samples (n = 31) in 31 wells together with mudstone and limestone source rocks (n = 18) from Cretaceous Napo Formation in 16 wells were analyzed to evaluate the geochemical characteristics of the oil reservoir oil.Geochemical analyses included measurements of total organic carbon (TOC) content, Rock-Eval Pyrolysis, gas chromatography (GC), and gas chromatography-mass-spectrometry (GC-MS).All the oil samples have pre-uimodal n-alkane distribution dominated by lower molecular weight components (peak at C15–C17) with a small peak at C25–C30. The carbon preference index (CPI) and odd-over-even predominance (OEP) values range between 1.0 and 1.34, and 1.0–1.21 respectively; Pr/Ph ratios range from 0.67 to 1.16; high Pr/n-C17 (0.80–3.47) and Ph/n-C18 ratios (0.82–7.86) values and dominate C27 regular steranes, all these biomarkers show that the oil derived from marine algal material. Furthermore, all oils have similar Terpanes and Steranes distribution shape, peak at C23TT, and low at C22TT (TT = tricyclic terpanes), relative low C22/C21, C24/C23 and C26/C25 tricyclic terpane ratios, higher C27R (R = regular steranes) content than C29R and C28R. These biomarkers demonstrate that all the oils are from same genetic family although they came from different zones. There are two kinds of source rocks in the Oriente basin, shale and argillaceous bioclastic limestone of Napo Formation. These rocks are good-excellent mature according to TOC and Rock-Eval assessment. The two source rocks show obvious different Terpanes and Steranes distribution shape in mz191 and mz217 maps. The Oil-Source correlation analysis demonstrates that the crude oils have similar Terpane and Steranes distribution shape and biomarker value, especially the C27R–C28R–C29R ratio, with argillaceous bioclastic limestone of Napo Formation. This new geochemical data suggests that the argillaceous bioclastic limestone is the major source rock in the Oriente basin. Thus, distribution of this stratigraphic unit should be the key point for future exploration.

The hydrocarbon generation and expulsion features of source rocks and tight oil potential of the second member of the Qiketai Formation, Shengbei area in the Turpan–Hami Basin, NW China

Significant progress in tight oil exploration has been reported in the second member of the Qiketai Formation (J2q2) in the Shengbei area of the Turpan–Hami Basin. Geochemical analyses were conducted to assess the quality of the J2q2 source rocks. The improved hydrocarbon generation potential method was utilized to quantify the hydrocarbon generation and expulsion features of the source rocks. The results showed that J2q2 source rocks were deposited in a reduced lacustrine setting with a high palaeoproductivity. The J2q2 source rocks are widely distributed (approximately 1,000 km2) and have a thickness that varies from 50 to 130 m. Moreover, they can be identified as a set of high‐quality source rocks (thermally mature rocks with Ro values &gt;0.5%, consisting mainly of types I and II kerogen and possessing an average total organic carbon content of 2.68%). The oil–source correlation results reveal that the source of crude oil in the studied area is J2q2. The improved hydrocarbon generation potential method is established for different kerogen types to limit the influence of the kerogen type on the calculation. The hydrocarbon expulsion threshold of the type I model is located at Ro = 0.6%. The type II kerogen rocks have different characteristics, and the hydrocarbon expulsion threshold is located at Ro = 0.62%. The maximum hydrocarbon generation and expulsion intensities are 700 × 104 t/km2 and 400 × 104 t/km2, respectively. The hydrocarbon generation and expulsion amount of the J2q2 source rocks are 21.4 × 108 t and 12.3 × 108 t, respectively. The tight oil potential of the J2q2 tight oil in the Shengbei area is 4.09 × 108 t. The SB10 and SB6 well areas are favourable J2q2 tight oil exploration areas in the Shengbei area. The SB10 well area has the highest hydrocarbon generation and expulsion intensities in the study area and is the best tight oil exploration target.

Effective hydrocarbon-bearing geological conditions of the Permian strata in the South Yellow Sea Basin, China: Evidence from borehole CSDP-2

For nearly 60 years, petroleum geologists have been puzzled by oil and gas exploration in the South Yellow Sea basin, which is considered to have broad oil and gas prospects, but no commercial hydrocarbon reservoirs have been obtained. The hydrocarbon-bearing geological conditions of the Permian strata with good exploration prospects also have never been systematically investigated. To solve the problem, a series of experiments was conducted on core samples obtained from borehole CSDP-2, the first exploration well with continuous coring in the South Yellow Sea Basin, including petrology analysis, geochemical testing, pore-throat testing, hydrocarbon-charging analysis, and sealing-ability evaluation. Vitrinite reflectance (Ro), total organic carbon (TOC), pyrolysis, extractable organic matter (EOM) and kerogen microscopic examination were carried out to evaluate the quality of the Permian source rocks. Porosity, permeability, thin section, scanning electronic microscopy (SEM) and rate-controlled mercury injection (RCMI) analyses were combined to verify the effectiveness of sandstone reservoirs. The sealing capacity of caprock was mainly evaluated by the displacement pressure. And according to the fluid-inclusion analysis and oil-source correlation, the hydrocarbon accumulation events were determined. After comprehensive analysis, we clarified the effective hydrocarbon-bearing geological conditions and favorable prospects in the Permian of the South Yellow Sea Basin. Furthermore, the main controlling factors pertaining to favorable source rocks and tight sandstone reservoirs were ascertained in this paper.The results show that two sets of the Lower Permian Qixia and Gufeng Formation (P1q-g) and the Upper Permian Longtan and Dalong Formation (P2l-d) source rocks, along with the P2l-d tight sandstone reservoirs, compose two types of hydrocarbon accumulation assemblages, which are effectively sealed by the Lower Triassic Qinglong Formation (T1q) roof caprock. One type represents the ‘lower-generation and upper-accumulation’ between the P1q-g source rocks and the P2l-d sandstones, and the other type represents the ‘self-generation and self-accumulation’ in the Upper Permian strata. Vertical stacking between the Permian source rocks and sandstone reservoirs ensures the near-source hydrocarbon accumulation, and faults and microcracks can be regarded as beneficial channels for hydrocarbon migration. In addition, we find that the quality of source rocks is improved by large-scale marine transgression, high bio-productivity, and tectonic–thermal events. The quality of tight sandstone reservoirs is more dependent on throats with relatively larger radius than pores. This study provides important enlightenment for exploring marine hydrocarbons in the South Yellow Sea Basin, and can be useful in understanding the dominant geological factors affecting favorable source rocks and sandstone reservoirs.

Geochemical characteristics of crude oil and oil-source correlation in the western Qaidam Basin, China

The Cenozoic in the western Qaidam Basin is rich in oil and gas resources and has good prospects for exploration. The maturity, sedimentary environment, and biological source of the crude oil in the western Qaidam Basin are discussed based on the composition characteristics of biomarkers in crude oil and source rocks. The above is performed to classify the genetic types of crude oil and determine the oil source relationship. It is found that the crude oil shows the characteristics of low mature–mature and is formed in the reducing environment with high salinity. The organic matter is from the mixed source with dominant aquatic plants input. According to the sedimentary environment, parent material types, and maturity characteristics, the crude oil in the western Qaidam Basin can be classified into four types. (1) Type I is from the Shizigou-Yuejin areas, which have a high content of gammacerane, a low value of Pr/Ph, C27 sterane predominance, and “tail-upwarping” phenomenon. (2) Type II is from the Qiekelike-Zhahaquan and Nanyishan-Youquanzi areas, which have C27 sterane predominance and no “tail-upwarping” phenomenon. Its content of gammacerane is lower than type I. (3) Type III is from the Dafengshan and Huangguamao areas, which have C29 sterane predominance and no “tail-upwarping” phenomenon. (4) Type IV is from the Kaitemilike area, which has a C27 sterane predominance, no “tail-upwarping” phenomenon, and lower content of gammacerane than that of others. The result of the oil-source correlation shows that the crude oil is dominantly derived from source rocks of the lower Ganchaigou Formation (E3) and the upper Ganchaigou Formation (N1).

Bound hydrocarbons and structure of pyrobitumen rapidly formed by asphaltene cracking: Implications for oil–source correlation

The pyrobitumen in conventional petroleum reservoirs is a thermally altered product of ancient oil pools, which may provide valuable source information using its molecular and isotopic signatures. Pyrobitumen formation is often associated with thermal alteration of asphaltene or polar-rich components rather than that of oil as a whole. Although asphaltenes are useful in source correlation of altered oils, the geochemical characteristics of asphaltene-derived pyrobitumen are poorly understood. In this study, artificial pyrobitumen formation through oil asphaltene cracking was performed at different thermal simulation (i.e., pyrolysis) temperatures. Systematic variations in the amounts and distributions of extractable and bound hydrocarbons, released by catalytic hydropyrolysis of the artificially produced pyrobitumen were studied. Pyrobitumen production yield was high at pyrolysis temperatures corresponding to post oil peak maturities, with a maximum yield of ∼70 wt% of asphaltene being reached in the early condensate–wet-gas stage. The molecular structure of pyrobitumen varied only slightly over the high maturity range (EasyRo 1.64–2.51%). Compared with the parent asphaltene, the pyrobitumen had a low biomarker (e.g., regular steranes and terpanes) content, and even the carbon isotopic values of the more stable bound n-alkanes were strongly altered. Thermal cracking of asphaltene alone, rather than whole oil, accelerates cross-linking of aromatic units, and cleavage or condensation of molecules bound in the pyrobitumen. These molecular changes suggest that care is needed when using the geochemical characteristics of bound hydrocarbons in natural pyrobitumen for source determinations. Nevertheless, the carbon isotopic ratios of bulk pyrobitumen hydropyrolysate were similar to those of bulk oil or pyrobitumen, even at very high maturities, suggesting these may be reliable indices for source tracing. A comparison of carbon isotopic compositions between pyrobitumen-bound and solvent-extractable n-alkanes could be useful in determining whether they have the same origin. Furthermore, the compositional and isotopic characteristics of bound hydrocarbons in pyrobitumen may provide information on the stage of maturity under geological conditions. The investigation of free and bound molecules may thus elucidate pyrobitumen genesis as related to its source, thermal maturity, and possible later hydrocarbon charging.

Geochemical characteristics of Middle-Upper Ordovician source rocks in the Kalpin outcrop profiles and marine oil-source correlation, Tarim Basin, NW China

The Middle-Upper Ordovician source rocks developed in six outcrop profiles in the Kalpin area, Tarim Basin, NW China were analyzed using an organic geochemical screening method. Most TOC values of source rocks of Salgan Formation of Middle-Upper Ordovician developed in the Dawangou, Kamatikan, and Tonggusibulong outcrop profiles are greater than 1.0%, whereas the TOC value of the source rocks of Yingan Formation of Upper Ordovician only developed in the Dawangou outcrop ranged from 0.14% to 1.29%, with an average value lower than that of the Salgan Formation source rocks. Combined with the analysis results of source rocks of Yuertusi Formation of Lower Cambrian developed in the Xiaoerbulake, Sugaite and West Yuti outcrop profiles, the source rocks of Yuertusi, Salgan and Yingan Formations showed similar molecular geochemical characteristics, with low Pr/Ph value, C23 greater than C21 tricyclic terpane, high gamacerane and C28 sterane content. The similarity in molecular compounds of Cambrian to Ordovician source rocks in the Kalpin area may be a result of the high maturity. In the relative distribution of C27–C29 regular steranes, the marine oils with C28 sterane lower than 25% showed great difference with that of the source rocks of Lower Cambrian Yuertusi Formation. In the distribution of carbon isotopic curves, the source rocks of Lower Cambrian Yuertusi Formation have lighter carbon isotopes, compared with that of the Middle-Upper source rocks, especially in kerogen carbon isotopes, Lower Cambrian Yuertusi Formation lighter 5‰ than that of Middle-Upper Ordovician source rocks. Overall, the carbon isotopes fractionation of saturate, bitumen, aromatic fraction, resin, asphaltene, and kerogen is small in source rocks from Middle-Upper Ordovician Salgan and Yingan Formations in the Kalpin area. It is suggested that the carbon isotope of kerogen of source rocks can be used as a parameter for oil-source correlation excluding the TSR of the oil reservoirs.

Reservoir alteration of crude oils in the Junggar Basin, northwest China: Insights from diamondoid indices

Reservoir alteration of crude oils is ubiquitous in petroleum reservoirs. Alteration can change the composition and physicochemical properties of crude oils, and complicate oil–source correlations and origin studies of crude oils. Thus, the identification and assessment of reservoir alteration could provide a better understanding of the formation and evolution of crude oils. In this study, the effects of reservoir alteration (e.g., biodegradation, gas washing, water washing, and mixing) on oils in the Junggar Basin, northwest China, were identified and assessed by combining diamondoid indices with other commonly studied crude oil properties. The results indicate that: (1) diamondoid indices can be used to evaluate the intensity of reservoir alteration on oils (e.g., slight biodegradation and water washing has no effect on diamondoids; moderate biodegradation and water washing can result in a marked increase in diamondoid concentrations; severe biodegradation and water washing significantly changes diamondoid concentration and isomerization ratios); (2) diamondoid indices can assist in determining the type of reservoir alteration of oils (e.g., condensate formed by gas washing has a lower diamondoid concentration than that generated by thermal cracking; differing from biodegradation and water washing, gas washing can affect diamondoid ratios; mixing can be identified by a combination of diamondoid concentrations and other parameters, such as API gravity and biomarker indices in oils). Therefore, diamondoids provide specific information as to the reservoir alteration of oils, which is useful in further understanding of the origin and evolution of crude oils in the Junggar Basin.

Reevaluating the source and accumulation of tight oil in the middle Permian Lucaogou Formation of the Junggar Basin, China

Abstract The middle Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China, is a world-class example of tight oil accumulations in lacustrine sedimentary sequences. Previous studies have indicated that the main oil accumulation mechanism in this system is near-source accumulation within upper and lower “sweet spots” (i.e., reservoirs). Here we reveal the complexity of oil source and accumulation in this tight oil system is greater than previously thought. A set of mudstones are developed between the upper and lower sweet spots of the Lucaogou Formation and are thus termed the middle section mudstones. They have previously been little studied as few intervened reservoir rocks are developed within the sequences. Here we report their oil generation and contribution for the first time. The mudstones are 97–182 m thick and have total organic carbon contents of 0.67–12.31 wt%. The kerogen is mainly type II, with small amounts of types I and III, and is in the mature stage. These data suggest that the middle section mudstones have good hydrocarbon generation potential. Oil–source correlations reveal a complex history of tight oil migration and accumulation. The oils generated in the upper part of the middle section mudstones migrated northward to the basin margins and southeastward to the basin center. In contrast, oil generated in the lower part of the middle section mudstones migrated westward to the west–central and central regions. The oil migration resulted in complex tight oil accumulation, which reflects the reservoir heterogeneity. Our data suggest that such reservoir heterogeneity appears to be typical of tight oil accumulations in continental lacustrine basins. In the study area, future evaluation, exploration, and exploitation of tight oil should also focus on the middle section mudstones and associated sweet spots in addition to the commonly-acknowledged upper and lower sweet spots.

Multivariate Statistical Analysis Reveals the Heterogeneity of Lacustrine Tight Oil Accumulation in the Middle Permian Jimusar Sag, Junggar Basin, NW China

Tight oil and gas accumulation commonly has heterogeneities within the reservoir formation. This heterogeneity, however, is hard to investigate by conventional geological and (organic) geochemical tools and thus is critical and challenging to study. Here, we attempted multivariate statistical analysis to reveal the heterogeneity based on a case study in the lacustrine tight oil accumulation in the middle Permian Lucaogou Formation of the Jimusar sag, Junggar Basin, NW China. Clustering heat maps and multi-dimensional scaling analysis revealed the heterogeneity of tight oil accumulation. The heterogeneity is reflected by the complex relationship between the two reservoir sweet spots as well as the oil migration and accumulation vertically and spatially, rather than the previous thoughts that it is a closed system associated with proximal hydrocarbon accumulation patterns. Multiple biomarkers show that the source rocks and reservoirs have similar characteristics in the lower part of the formation, reflecting a proximal hydrocarbon accumulation pattern in the lower sweet spot (near-source accumulation, abbreviated as NA). This represents a relatively closed system. However, the upper sweet spot and the middle section mudstone sequence intervening the two sweet spots are not a completely closed system in a strict sense. These sequences can be divided into three tight oil segments, i.e., lower, middle, and upper from deep to shallow. The lower segment is sited in the lower part of the middle section mudstone sequence. The middle segment is composed of the upper part of the middle section mudstone sequence and the lower part of the upper sweet spot. The upper segment is composed of the upper part of the upper sweet spot and the overlying upper Permian Wutonggou Formation reservoirs. Oils generated in the lower segment migrated vertically to upper sweet spot reservoirs through faults/fractures, and laterally to distal reservoirs. Oils generated in the middle segment were preserved in reservoirs of the upper sweet spot. Oils in the upper segment require accumulation by vertical and lateral migration through faults/fractures. As such, the tight oil accumulation is complex in the Lucaogou Formation. From base to top, the accumulation mechanisms in the Lucaogou Formation were NA, VLMA (vertical and lateral migration and accumulation), NA and VLMA, thereby showing strong heterogeneities. Our data suggest that these processes might be typical of tight oil accumulations universally, and are important for future exploration and exploitation in the region to consider the heterogeneities rather than a closed system. The multivariate statistical analysis is an effective tool for investigating complex oil-source correlations and accumulation in petroleum basins.

埕岛东斜坡主力烃源岩判定及油气来源分析

埕岛东斜坡主力烃源岩判定及油气来源分析

Genesis and evaporative fractionation of subsalt condensate in the northeastern margin of the Amu Darya Basin

This paper studied the origin and the maturity of the Jurassic subsalt condensate in the northeastern margin of the Amu Darya Basin and analyzed its formation condition and mechanism through conducting geochemical analysis of biomarkers, carbon isotopes and light hydrocarbons of condensate and source rock. Combining geology and geochemistry analysis, this paper compared the components of natural gas and associated condensate, and conducted oil-source correlation as well as analyzed condensate maturity in nine gas reservoirs. The genesis and geological conditions of condensate in the northeastern margin of the Amu Darya Basin were analyzed and a geological model of condensate accumulation was thereby established. The results show that natural gas in the northeastern margin of the Amu Darya Basin is dry gas with residual oil and oil intrusion. Parameters, e.g., saturated hydrocarbon distribution, sterane and terpane biomarkers and isotopes, suggest that the condensate was primarily derived from the Upper Jurassic marine source rocks. Mature condensate was identified using maturity parameters, e.g., heptane and isoheptane, light hydrocarbons 2,4-DMP/2,3-DMP(Dimethyl Pentane), C29sterane isomerization and aromatic hydrocarbon methylphenanthrene index. The relationship between light hydrocarbon paraffinicity and aromaticity indicates that the condensate was derived from evaporative fractionation. Comprehensive analysis draws the conclusion that condensate at subsalt reservoir in the northeastern margin of the Amu Darya Basin was contributed by evaporative fractionation. Oil generated by the Upper Jurassic marine source rocks at early stage was concentrated in the subsalt carbonate strata. Considerable dry gas was generated by Middle and Lower Jurassic coal-bearing source rocks in the late stage migrated to the Upper Jurassic reservoirs and displaced crude oil due to the absence of interlayers. And the light hydrocarbons in the oil were dissolved in natural gas and therefore formed condensate. The evaporative fractionation under subsalt was contributed by: (1) two sets of source rocks, e.g., one is gas-prone and the other is oil-prone, (2) no obvious barriers between these source rocks, (3) excessive natural gas generated.

The Jurassic oil-source correlation of Dishuiquan Oilfield in Junggar basin, Northwest China

There are many hydrocarbon generation sags around Dishuiquan Oilfield, such as Dishuiquan Sag, Dongdaohaizi Sag, Wucaiwan Sag, etc. But there is no result which hydrocarbon generation sag the Jurassic oil of Dishuiquan Oilfield is sourced from. Through comparisons on carbon isotopes, sterane distributions and maturities of source rocks and crude oil, the result shows that the geochemical characteristics of Jurassic crude oil in Dishuiquan Oilfield are highly consistent with those of Permian source rocks in Dongdaohaizi Sag and have obvious differences with other sags, which indicates the crude oil comes from the Permian source rocks in Dongdaohaizi Sag.

Geochemical characteristics and sources of the crude oil of Yan’an formation Yan 9 in Zhao’an area, Ordos Basin, China

A certain scale of Yan 9 reservoir was found in Zhao’an area, but the oil source is not clear. The geochemical characteristics of Yan 9 crude oil and potential source rocks were analyzed by using gas chromatograph-mass method. Analysis results showed that the parent materials of Yan 9 crude oil were sourced from lower aquatic organism and higher terrigenous plants and formed in freshwater- brackish water lacustrine facies. Oil-source correlation results showed that Yan 9 crude oil was derived from the source rocks of Chang 7.

Geochemical characteristics and origins of the crude oil of carboniferous formation in Dajing area, Junggar basin, China

Dajing area is one of the key exploration areas in Junggar basin. In this paper, based on scientific exploration and exploitation, the geochemical characteristics of the carboniferous crude oil and potential source rocks were analyzed using gas chromatograph-mass method. The correlation of biomarkers showed that the parent materials of the carboniferous crude oil formed in freshwater-mildly brackish water environment and were sourced from low grade aquatic organisms and terrigenous higher plants. Oil-source correlation results showed that the carboniferous crude oil in Dajing area was derived from the source rocks of Songkaersu.

Investigation of fluid inclusion and oil geochemistry to delineate the charging history of Upper Triassic Chang 6, Chang 8, and Chang 9 tight oil reservoirs, Southeastern Ordos Basin, China

Abstract The Chang 6, Chang 8, and Chang 9 reservoirs of the Upper Triassic Yanchang Formation in the Zhenjing area of the Ordos Basin are characterized by low porosity, low permeability, high oil saturation, and large oil reserves, which indicate huge tight oil potential. To comprehensively investigate the hydrocarbon contributors and charging history, fluid inclusions were systemically studied coupled with basin modeling and oil geochemical analysis. According to the petrographic characteristics, two episodes of fluid inclusions occurred in each of the three reservoirs. Microthermometry analysis suggests that the hydrocarbon inclusions of the first episode in each reservoir are distributed mainly along overgrowth quartz or secondary microcracks and exhibit light yellow or light brown fluorescence; the coeval aqueous inclusions display low homogenization temperature (Th) peaks with 80–100 °C. The hydrocarbon inclusions of the second episode in each reservoir are mainly distributed in microcracks that cut across or within quartz grains and exhibit light green or bluish-green fluorescence; the coeval aqueous inclusions are characterized by high Th peaks with 110–120 °C. The different characteristics of the two episodes of the fluid inclusions imply the existence of two episodes of hydrocarbon charging events. The burial and geothermal histories of the various reservoirs were reconstructed using one-dimensional basin modeling and pressure–volume–temperature–composition (PVTX) simulation coupled with the authigenic illite K–Ar dating. The reconstruction implied the time of the two hydrocarbon charging episodes to be Early Cretaceous and Late Cretaceous. Oil-source correlation studies illustrate that the Chang 6, Chang 8, and Chang 9 crude oils all originate from the Chang 7 source rock. The migration characteristics and directions were comprehensively analyzed by using maturity parameters. This explanation of the charging history and oil migration pathway of the Upper Triassic Yanchang Formation in the Zhenjing area provides a theoretical basis for further exploration.