The application of chromatographic gas ratio analysis in reservoir fluid evaluation of “Beta” field in the Congo basin

This study assessed the hydrocarbon generation potentials/timing of the Awgu source rock horizons encountered in Igbariam-1, Iji-1 and Ajire-1 wells drilled in the southern Benue Trough; using one-dimensional (1D) Genesis Zetaware basin modelling software. This software enabled the integration of burial and thermal influences on Awgu source rocks with kinetic parameters. Thermal and burial history models indicate that the Awgu source horizons encountered at 3249m in Igbariam-1 well (northern part of the basin), expelled 85mg/gtoc of oil and 12 mg/gtoc of gas and hydrocarbon generation began in early Eocene with maximum expulsion in the mid-Eocene (52my) at the rate of 7mg/gtoc/my. To the south of the basin, the Awgu source horizons were encountered at greater depths in Iji-1 and Ajire-1 wells and hydrocarbon generation began in the mid-Palaeocene and peaked in the late Palaeocene (58my) at the rate of 32–38mg/gtoc/my. This resulted in an increase in generated hydrocarbon volume to the south due to (a) increased burial depth and early maturation, and (b) changing source lithofacies -more marine. The fault system linking potential reservoirs such as the Agbani sandstone and the overlying Owelli sandstone to the source rock suggests a possible migration of the generated hydrocarbons to those reservoirs at that time.     

准噶尔盆地南缘侏罗系烃源岩排烃效率研究

准噶尔盆地南缘下部成藏组合勘探日趋重要,其主力烃源岩生烃潜力和排烃效率的研究亟待加强。根据排烃门限理论,利用生烃潜力法建立了准噶尔盆地南缘侏罗系烃源岩的生、排烃模式,并计算了烃源岩的生烃量、排烃量和排烃效率。研究表明,准噶尔盆地南缘侏罗系泥质烃源岩和煤层的排烃门限对应的镜质组反射率均为0. 7 %。侏罗系烃源岩的总生烃量为3 973. 84 x 108t,总排烃量为1 402. 71 x108t,其中八道湾组烃源岩排烃量占总排烃量的69.85%。准噶尔盆地南缘侏罗系烃源岩的平均排烃效率为35. 30%,不同层系不同岩性烃源岩,其排烃效率明显不同,泥质烃源岩排烃效率远大于煤层。综合分析认为,准噶尔盆地南缘侏罗系烃源岩生、排烃量大,排烃效率较高,下部成藏组合以侏罗系烃源岩为主力烃源岩,具有良好的资源潜力。     

Critical conditions for tight oil charging and delineation of effective oil source rocks in Lucaogou Formation,Jimusar Sag,Junggar Basin,northwest China

Although tight oil has great resource potential, studies of oil charging mechanisms in tight reservoirs are relatively few. Researchers have found that a force balance exists during oil charging, but quantitative analyses of conditions critical for tight oil charging are sparse. This study developed a formula to identify effective source rocks using oil expulsion intensity as the discrimination parameter based on quantitative expression of hydrocarbon-generation overpressure and force-balance conditions. Using this formula, critical oil expulsion intensity under conditions at various burial depths can be obtained. This method was applied in the tight reservoirs of the Jimusar Sag, Junggar Basin, China. The calculated critical oil expulsion intensity range was between 122.61 × 10⁴ t/km² and 620.01 × 10⁴ t/km². The distribution range of effective oil source rocks and total expelled oil can be determined on the basis of critical oil expulsion intensity at different burial depths. This method provides a new approach to predict favourable tight oil-bearing regions.     

Hydrocarbon Generation and Expulsion of the Upper Triassic T3x5 Source Rocks in the Western Sichuan Depression: Assessment for Unconventional Natural Gas

Tight-sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation(T3x5) in the Western Sichuan Basin(WSD) are currently regarded as the most prolific emerging unconventional gas plays in China. This study conducted a conventional evaluation of T3x5 source rocks in the WSD, and investigated their hydrocarbon generation and expulsion characteristics, including intensity, efficiency and amount. The results show that, the T3x5 source rocks are thick(generally 200 m), and have a high total organic content(TOC), ranging from 2.5 to 4.5 wt%. It is thus indivative of a great hydrocarbon generation potential when they underwent high thermal evolution(Ro1.2%) in the area. In addition, an improved method of hydrocarbon generation potential is applied, indicating that the source rocks reached a hydrocarbon expulsion threshold with vitrinite reflectance(Ro) reaching 1.06%, and that the comprehensive hydrocarbon expulsion efficiency is about 60%. The amount of hydrocarbon generation and expulsion from T3x5 source rocks is 3.14×1010 t and 1.86×1010 t, respectively, with a residual amount of 1.28×1010 t within them. Continuous-type tight-sand gas is predicted to have developed in the Jurassic in the Chengdu Sag of the WSD because of the good source-reservoir configuration; the Jurassic sandstone reservoirs are tight, and the gas expelled from the T3x5 source rocks migrates for very short distances vertically and horizontally. The amount of gas accumulation in the Jurassic reservoirs derived from T3x5 source rocks is up to 9.3×108 t. Geological resources of shale gas are up to 1.05×1010 t. Small differences between the amounts calculated by the volumetric method and those obtained by hydrocarbon generation potential method may be due to other gas accumulations present within interbedded sands associated with gas shales.     

Gas generation and expulsion characteristics of Middle–Upper Triassic source rocks,eastern Kuqa Depression,Tarim Basin,China: implications for shale gas resource potential

Frontier exploration in the Kuqa Depression, western China, has identified the continuous tight-sand gas accumulation in the Lower Cretaceous and Lower Jurassic as a major unconventional gas pool. However, assessment of the shale gas resource in the Kuqa Depression is new. The shale succession in the Middle–Upper Triassic comprises the Taliqike Formation (T₃t), the Huangshanjie Formation (T₃h) and the middle–upper Karamay Formation (T_2–3k), with an average accumulated thickness of 260 m. The high-quality shale is dominated by type III kerogen with high maturity and an average original total organic carbon (TOC) of about 2.68 wt%. An improved hydrocarbon generation and expulsion model was applied to this self-contained source–reservoir system to reveal the gas generation and expulsion (intensity, efficiency and volume) characteristics of Middle–Upper Triassic source rocks. The maximum volume of shale gas in the source rocks was obtained by determining the difference between generation and expulsion volumes. The results indicate that source rocks reached the hydrocarbon expulsion threshold of 1.1% VR and the hydrocarbon generation and expulsion reached their peak at 1.0% VR and 1.28% VR, with the maximum rate of 56 mg HC/0.1% TOC and 62.8 mg HC/0.1% TOC, respectively. The volumes of gas generation and expulsion from Middle–Upper Triassic source rocks were 12.02 × 10¹² m³ and 5.98 × 10¹² m³, respectively, with the residual volume of 6.04 × 10¹² m³, giving an average gas expulsion efficiency of 44.38% and retention efficiency of 55.62%. Based on the gas generation and expulsion characteristics, the predicted shale gas potential volume is 6.04 × 10¹² m³, indicating a significant shale gas resource in the Middle–Upper Triassic in the eastern Kuqa Depression.     

Source rock characterization and hydrocarbon generation modeling of the Middle to Late Eocene Mangahewa Formation in Taranaki Basin,New Zealand

The Middle to Late Eocene Mangahewa Formation of Taranaki Basin, New Zealand, has been evaluated in terms of organic matter abundance, type, thermal maturity, burial history, and hydrocarbon generation potential. Mangahewa Formation reflects the deposition of marine, marginal marine, shallow marine, and terrestrial strata due to alternative transgressive and regressive episodes in Taranaki Basin. The sediments of the Mangahewa Formation contain type II (oil prone), types II–III (oil-gas prone), and type III kerogens (gas prone), with hydrogen index values ranging from 58 to 490 mg HC/g total organic content (TOC). Vitrinite reflectance data ranging between 0.55 and 0.8 %R_o shows that the Mangahewa Formation is ranging from immature to mostly mature stages for hydrocarbon generation. Burial history and hydrocarbon generation modeling have been applied for two wells in the study area. The models have been interpreted that Mangahewa Formation generated oil in the Mid Miocene and gas during Middle to Late Miocene times. Interpretations of the burial models confirm that hydrocarbons of Mangahewa Formation have not yet attained peak generation and are still being expelled from the source rock to present.     

Basin modelling of gas migration and accumulation in volcanic reservoirs in the Xujiaweizi Fault-depression,Songliao Basin

The Xujiaweizi Fault-depression of Songliao Basin has developed typical and widespread volcanic gas reservoirs. We studied the formation process of volcanic gas reservoirs by using basin modelling software and evaluated the influence of volcanic porosity, the 3D spatial and temporal field of the thermal history, and the 3D fault patterns on the basin modelling results. The 1D basin modelling results indicate that hydrocarbon generation of deep layer source rocks has a relay characteristic in time (128–0 Ma) and space (sag and slope zone) in the Xujiaweizi Fault-depression. The 2D basin modelling results show that (i) the distribution of volcanic reservoirs was controlled by the volcanic apparatus, (ii) gas source faults facilitated the vertical migration of natural gas, and (iii) the development of volcanic porosity controlled the lateral migration and accumulation of natural gas in the carrier bed. The 3D basin modelling results demonstrate that JHM, JHC, KSHC, and KSHM (source rocks) started hydrocarbon generation during the late deposition of the Denglouku Formation (113 Ma), the main hydrocarbon expulsion period was during the deposition of the late Quantou Formation (100 Ma), when the largest volcanic gas reservoir was formed; and from 84 Ma to the present (0 Ma), the area of the volcanic gas reservoir has decreased gradually. The insight gained from the basin modelling results of the volcanic gas-bearing system of the Xujiaweizi Fault-depression is that volcanic porosity, the 3D spatial and temporal field of the thermal history, and the 3D fault patterns have important influences on gas reservoir formation history and accumulation location. We are the first to establish different patterns for relations between different volcanic lithofacies porosity and burial depth, and we expect to provide a reference for basin model of other volcanic oil- and gas-bearing systems.     

优质烃源岩评价标准及其应用: 以海拉尔盆地乌尔逊凹陷为例

“优质烃源岩控藏”的概念自提出后,正在逐步为勘探家所接受.但什么是优质烃源岩以及如何界定,则还缺乏共识和统一标准.针对这一难题,以海拉尔盆地乌尔逊凹陷为例,利用物质平衡原理计算的源岩排烃量与有机质丰度(TOC)关系曲线的拐点来确定优质烃源岩的有无及其下限标准.结果表明,在TOC较低时,所有源岩的排烃量有限,难以成为优质烃源岩;当TOC升高到某一阀值时,排烃量随着TOC的升高出现明显的增大.这一明显增大的拐点应该为优质烃源岩的下限,TOC高于该值的源岩即为优质烃源岩.虽然优质烃源岩的下限还与有机质的类型、成熟度等因素有关,但为简明实用,综合定量评价认识,推荐TOC＝2.0%作为确定优质油源岩的下限.该标准在研究区的应用表明,区内南二段、南一段优质烃源岩的生油贡献比例达到71%和87%,排油贡献比例更是高达85%和94%,优质源岩的分布与区内油藏的分布也有非常好的对应关系,证明了优质源岩的控藏作用.      

松辽盆地中浅层幕式排烃与断距增长耦合

超压盆地幕式排烃作用是盆地流体研究中热点问题,而源岩内排烃生长断层的报道很少.研究表明松辽盆地凹陷中央主力烃源岩青山口组发育排烃生长断层,这些浅层生长断层形成于嫩江组末期至明水组末期.这种排烃生长断层的形成机制是幕式排烃过程中由于"泵压效应"使含烃流体从源岩向储集层注入的结果.当源岩过剩压力达到源岩破裂极限时,源岩发生断裂或使原有断层再次开启增长,含烃流体发生向下或向上部储层的排烃作用,随着烃类的排出,过剩压力不断减小,排烃过程趋于停止伴随超压流体释放,研究区呈现向下排烃、向上排烃和上下双向排烃3种样式,由于这一排烃过程是多次出现的,随着多次反复的排烃,排烃断层的断距也不断增长,导致排烃期与断层断距增长具有良好的耦合关系,研究成果为超压封存箱上下层油气勘探提供了新的思路.     

烃源岩生排烃组分法模型研究与应用

本文提出了一种新的烃源岩生排烃组分法模拟模型。组分法生烃模型根据热模拟实验得到的组分产率曲线模拟烃源的生烃史。排烃模型包括开放体系模型和间歇开放体系模型，分别用于模拟以压实作用为主要动力的孔隙排烃和以异常高压为主要动力的微裂缝排烃。这一模型根据孔隙温度、压力和烃类组成，采用热力学方法模拟孔隙体系流体体积和相态的变化、不同组分在各相中的分布，并由此求出各组分的排出量和总排烃量。对陕甘宁盆地古生界源岩生排烃史的模拟结果表明，该模型具有实用价值。     

鄂尔多斯盆地上古生界灰岩烃源岩生烃潜力评价

对于鄂尔多斯盆地上古生界海陆过渡相灰岩能否生烃及生烃潜力有多大,目前研究较少.通过岩石热解、总有机碳测定、干酪根碳同位素及有机显微组分的测定实验,同时结合镜质体反射率的测定,综合评价了灰岩烃源岩,并分析了其生排烃特征.结果显示:从有机质丰度角度,本溪组为差的烃源岩,山西组为差-一般的烃源岩、太原组为一般-好的烃源岩;从有机质类型角度,本溪组为Ⅲ型,山西组以Ⅲ型为主同时混有少量Ⅱ₂型,太原组为Ⅱ₂-Ⅲ型;从有机质成熟度角度,本溪组处于成熟-高成熟阶段,太原组及山西组均处于高成熟阶段.根据排烃门限理论,认为R_o为1.6%时,天然气大量生成.考虑到灰岩烃源岩的特殊性、成熟度及其排烃特征,综合认为太原组灰岩可以成为天然气的有效烃源岩.      

柴达木盆地侏罗系煤系烃源岩生烃潜力分类评价

柴达木盆地侏罗系发育泥岩、炭质泥岩、煤和油页岩等多种类型煤系烃源岩。受沉积环境控制,不同类型烃源岩之间有机质丰度、有机质类型及生排烃模式等差别很大。传统的评价方法低估了炭质泥岩和煤的生烃潜力。提出了基于单位岩石烃源岩产烃率的定量评价方法,对不同类型烃源岩的总生烃量和总资源量定量预测表明:炭质泥岩对侏罗系生烃总量和油气资源的贡献率分别达到44.8%和41.7%,整体提升了柴达木盆地侏罗系烃源岩的资源潜力,煤型气的资源潜力大幅度提高,对柴达木盆地天然气勘探具有重要指导意义。      

库车坳陷的油气运移全定量模拟

为了给库车坳陷的油气勘探提供定量依据, 使用盆地模拟软件BASIMS对该坳陷的地史、热史、成岩史、生烃史、排烃史及运聚史进行了全定量模拟.其中油气初次运移的模拟使用简易而实用的方法, 即: 对于油气初次运移, 采用沉积压实渗流法求排油、物质平衡法求排气; 对于油气二次运移, 采用基于浮力驱动及达西定律的拟三维运聚模型.除了讨论这些数值方法的敏感性参数(参数敏感性与风险分析、排烃分配因子、断层及不整合面的渗透率、油气储集单元的确定) 外, 给出了排烃史和运聚史的模拟结果, 其聚集量的模拟结果不仅在数量上而且在位置上与实际情况符合, 尤其是预测出的几个有利勘探目标后来被勘探结果所证实      

Depositional environment,hydrocarbon generation and expulsion potential of the middle Permian Pingdiquan source rocks based on geochemical analyses in the eastern Junggar Basin,NW China

As the most important source rocks in the eastern Junggar Basin, the middle Permian Pingdiquan (P₂p) source rocks have attracted increasing attention after the discovery of tight oil in the Shazhang uplift. The P₂p source rocks are widely distributed (up to 7546 km²) and have an elevated thickness in the eastern Junggar Basin. To explore the P₂p tight oil resource in the eastern Junggar Basin, 113 core samples from 34 exploration wells were analysed geochemically and re-examined for their organic matter abundance, type and thermal maturity, hydrocarbon potential and sedimentary environment. Geochemical analysis results indicate that the P₂p source rocks are fair to good source rocks dominated by Type II kerogen, presently in a low mature–mature stage, and biomarkers and trace elements indicate deposition in a terrestrial to coastal environment under oxic to dysoxic, and fresh to brackish conditions, with possible intermittent seawater influence, implying proximity to the open sea. Based on hydrocarbon expulsion modelling, hydrocarbon expulsion began at 0.87% R_o, and the peak expulsion occurred at 1.1% R_o. Hydrocarbon generation intensities in the Shazhang uplift and the Wucaiwan sag are relatively large, with values centred at 4–6.5 million t/km² and 4–6 million t/km², respectively, with total hydrocarbon generation and expulsion from the P₂p source rocks approximately 4.56 × 10⁹ t and 1.44 × 10⁹ t, respectively, indicating significant tight oil exploration potential in the eastern Junggar Basin. The Shazhang uplift and the Wucaiwan sag are two hydrocarbon expulsion centres in the study area with the largest hydrocarbon expulsion intensity centred around the Shazhang uplift, exceeding 3 × 10⁶ t/km². We suggest that the area with high hydrocarbon expulsion intensities is a favourable target for tight oil accumulation and exploration.     

Hydrocarbon potential of the Sargelu Formation,North Iraq

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg?HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI?=?3^? to 3⁺, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R₂₈ steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.     

地质条件下湖相烃源岩生排烃效率与模式

烃源岩排烃研究是油气地球化学研究中最薄弱的环节,而排烃效率又是准确评价常规油气与非常规页岩油气资源的关键参数。目前对于烃源岩排烃效率的认识差异很大,尚未建立完整的各种类型有机质湖相烃源岩在地质条件下生排烃效率与模式。本文以中国渤海湾、松辽等4个大型湖相含油气盆地以及酒泉青西凹陷、泌阳凹陷等9个中小型湖相富油盆地/断陷为对象,通过15000余个湖相烃源岩样品在自然热演化过程中热解生烃潜力指数的变化研究,揭示了湖相烃源岩在地质条件下的生排烃特征,构建了湖相烃源岩在地质条件下的生排烃效率与模型。无论是大型湖相沉积盆地还是中小型断陷盆地,甚至是盐湖相沉积盆地,烃源岩生排烃特征基本一致。随着成熟度的增高,湖相烃源岩排烃效率逐渐增高,在低成熟阶段排烃效率较低,在成熟与高成熟阶段具有高或很高的排烃效率。Ⅰ型、Ⅱ型有机质类型烃源岩排烃模式相似,相对排烃效率在低成熟阶段小于45%,成熟生油高峰时达85%~90%,至生油窗下限时达90%以上;累积排烃效率在低成熟阶段小于10%,生油高峰时达50%~60%,生油窗下限时达75%~85%,主要的排烃阶段在镜质组反射率0.7%~1.2%之间,生油窗阶段生成并排出了绝大部分烃类。湖相Ⅲ型有机质烃源岩排烃效率明显低于Ⅰ、Ⅱ型有机质烃源岩,生油窗阶段累积排烃效率仅为50%左右,主要生排烃阶段在镜质组反射率0.8%~2.0%之间。控制湖相烃源岩排烃量和排烃效率的主要因素是有机质丰度、类型和成熟度,而盆地类型、断裂发育程度、烃源岩沉积环境、相邻输导层孔渗条件等因素均不影响烃源岩排烃与排烃效率。     

生排烃过程中正构烷烃单体碳同位素组成的变化特征及其研究意义

通过对生排烃模拟实验产物 (残留油和排出油 )中正构烷烃单体碳同位素组成的测定,揭示出生排烃过程中正构烷烃碳同位素组成的变化特征。研究表明,生烃初期,液态正构烷烃主要来自干酪根的初次裂解,它们的碳同位素组成不论是在排出油中还是在残留油中,随温度的变化都不明显,呈现较相似的分布特征;在生烃高峰期,早期形成的沥青质和非烃等组分的二次裂解以及高碳数正构烷烃可能存在的裂解,使得正构烷烃单体碳同位素组成明显富集13 C,尤其在高碳数部分呈现出较大的差异。另外,实验结果显示排烃作用对液态正烷烃单体碳同位素组成的影响不太显著。     

海拉尔盆地煤及煤系泥岩生排烃定量评价

海拉尔盆地具有多煤阶煤分布。煤系源岩生、排烃数据反映:最好的煤层是南上段,其次是大上段;最有利的煤系泥岩是铜钵庙组与南屯组。各凹陷煤系源岩生气量大小顺序为:呼和湖凹陷>贝尔凹陷>乌尔逊凹陷>呼伦湖凹陷。各凹陷煤系源岩生油量多少顺序为:乌尔逊凹陷>呼和湖凹陷>贝尔凹陷>呼伦湖凹陷。煤系源岩排油量大小顺序为:乌尔逊凹陷、贝尔凹陷、呼和湖凹陷、呼伦湖凹陷。可见,乌尔逊凹陷、贝尔凹陷、呼和湖凹陷具有良好的煤成油气勘探前景,是海拉尔盆地寻找煤成气、煤成油资源不可忽视的有利地区。      

Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.     

Hydrocarbon generation and expulsion characteristics of Lower Permian P1f source rocks in the Fengcheng area,northwest margin,Junggar Basin,NW China: implications for tight oil accumulation potential assessment

Combined with the actual geological settings, tight oil is the oil that occurs in shale or tight reservoirs, which has permeability less than 1 mD and is interbedded with or close to shale, including tight dolomitic oil and shale oil. The Fengcheng area (FA), at the northwest margin of the Junggar Basin, northwest China, has made significant progress in the tight oil exploration of the Fengcheng (P₁f) Formation recently, which indicates that the tight oil resources have good exploration prospects. Whereas the lack of recognition of hydrocarbon generation and expulsion characteristics of Permian P₁f source rocks results in the misunderstanding of tight oil resource potential. Based on the comprehensive analysis of geological and geochemical characteristics of wells, seismic inversion, sedimentary facies, tectonic burial depth, etc., the characteristics of P₁f source rocks were investigated, and the horizontal distributions of the following aspects were predicted: the thickness of source rocks, abundance and type of organic matter. And on this basis, an improved hydrocarbon generation potential methodology together with basin simulation techniques was applied to unravel the petroleum generation and expulsion characteristics of P₁f source rocks in FA. Results show that the P₁f source rocks distribute widely (up to 2039 km²), are thick (up to 260 m), have high total organic content (TOC, ranging from 0.15 to 4 wt%), are dominated by type II kerogen and have entered into low mature–mature stage. The modeling results indicate that the source rocks reached hydrocarbon generation threshold and hydrocarbon expulsion threshold at 0.5% Ro and 0.85% Ro and the comprehensive hydrocarbon expulsion efficiency was about 46%. The amount of generation and expulsion from the P₁f source rocks was 31.85 × 10⁸ and 15.31 × 10⁸ t, respectively, with a residual amount of 16.54 × 10⁸ t within the source rocks. Volumetrically, the geological resource of shale oil is up to 15.65 × 10⁸ t. Small differences between the amounts calculated by the volumetric method compared with that by hydrocarbon generation potential methodology may be due to other oil accumulations present within interbedded sands associated with the oil shales. Copyright © 2015 John Wiley & Sons, Ltd.