The oils from the cratonic region of the Tarim Basin are derived from the Cambrian-Ordovician source rocks, providing an excellent example to examine the influence of source facies on the concentrations and compositions of polynuclear aromatic hydrocarbons (PAH). Quantitative GC-MS analysis of PAH was performed on 137 oils from this region for oil source and maturity assessments. From marine mudstone to carbonate facies, concentrations of eight selected PAH (dimethylnaphthalenes, trimethylnaphthalenes, tetramethylnaphthalenes, pentamethylnaphthalenes, dibenzothiophene, methyldibenzothiophenes, fluorene and methylfluorenes) increase while concentrations of five other selected PAH (phenanthrene, methylphenanthrenes, chrysene, methylchrysenes and methyldibenzofurans) decrease. Subsequently, 40 PAH source facies ratios were selected. The studied oils were classified into three families using chemometric analysis (hierarchical cluster analysis and principal component analysis) integrating the 40 PAH facies ratios. Family I oils are mainly in the Tabei (Northern Tarim) Uplift and are interpreted to have been derived from source rocks with marine mudstone facies. Family II and III oils are only in the Tazhong (Central Tarim) Uplift and are interpreted to have been derived from source rocks with carbonate and marl facies. This result is consistent with the new finding of mudstone source rocks with high TOC within the lower Cambrian Yuertusi Formation from deep borehole LT1 in the Tabei Uplift. The Family II and III oils have lower PAH maturity ratios including DNR, TMNr, TeMNr, MPI1 and MDR than Family I oils. These maturity ratios likely reflect the maturity at the moment when PAH were released from kerogen in source rocks, and maintained nearly unchanged with increasing maturity after PAH release, suggesting that the PAH of Family II and III oils were released from kerogen at lower maturities compared with those in Family I oils. In particular, methyldibenzothiophenes in Family II and III oils were mainly generated at low maturities (calculated %Ro 0.64-0.90). The 40 PAH facies ratios are virtually not influenced by maturities from the oil generation window to post mature, and are resistant to oil biodegradation up to a high level. Thus, they provide more choices and opportunities for oil source facies assessment and oil source correlation for oil and condensate reservoirs in the Tarim Basin and elsewhere.

More than 2 × 109 tonnes of proved oils have been found in the cratonic region of the Tarim Basin. The source rocks for these oils remain unresolved although the source rocks are marine facies within the Cambrian and Ordovician strata with total thickness over 5 km. So far, there is no systematic classification of these oils on the basis of source facies. In this study, a practical approach was presented to select effective and sensitive biomarker parameters for source facies and maturity assessments for the studied oils on the basis of biomarker classification by hierarchical cluster analysis (HCA). Twenty-one terpanes and steranes in oils from both the Tabei (Northern Tarim) and Tazhong (Central Tarim) uplifts were classified into three groups using HCA on the basis of terpane and sterane concentrations. The result of biomarker grouping mainly reflects the differences in thermal stabilities among biomarkers for the 45 Tabei oils, providing a general thermal stability sequence for terpanes and steranes that helps the selection of effective maturity parameters. However, biomarker grouping suggests that both source facies and thermal stability have major influences on relative biomarker concentrations for the 75 Tazhong oils. The Tabei oils are mainly derived from a single source with relatively homogeneous facies while the Tazhong oils are derived from multiple sources or a single source with more heterogeneous facies. Based on the HCA results, twelve terpane and sterane ratios were selected as source facies parameters for the Tabei and Tazhong oils. These studied oils were consequently classified into four families by HCA and principle component analysis (PCA) integrating the twelve selected facies parameters of terpanes and steranes along with Pr/n-C17 and Ph/n-C18 ratios. Family 1 and 2 oils are mainly in the Tabei uplift while Family 3 and 4 oils are almost in the Tazhong uplift. Family 1 and 2 oils are derived from source rocks located at the northern, central and southern areas of the Northern Depression and the Tabei Uplift with marine mudstone facies. Family 3 and 4 oils are derived from source rocks located mainly at the southern area of the Northern Depression and the Tazhong Uplift with carbonate and evaporite facies. This study provides a practical approach to trace oil origins for oil and condensate reservoirs in the Tarim Basin and elsewhere.

对塔里木盆地台盆区未遭受生物降解的138个原油样品进行甾、萜烷定量分析,展示原油甾、萜烷浓度随成熟度变化特征.C23三环萜烷/(C23三环萜烷+C30藿烷)值与甾、萜烷浓度图版显示各类甾、萜烷具有不同的热稳定性.依据热稳定性的差异将甾、萜烷分为3类:第1类包括Tm、C29藿烷和C30藿烷等五环三萜烷,随成熟度增高,这类化合物浓度降低较快,具有相对较低的热稳定性;第2类既包括Ts、C29Ts和C30重排藿烷等五环三萜烷,也包括C27和C29规则甾烷各异构体,随成熟度增高,这类化合物浓度降低较慢,具有中等热稳定性;第3类包括C27重排甾烷、C21甾烷和C23三环萜烷,随成熟度增高,这类化合物浓度先增高、后降低,降低速率低于前2类化合物,表明其热稳定性相对较高.在常用的甾、萜烷成熟度指标中,Ts/(Ts+Tm)、C29Ts/(C29Ts+C29藿烷)和C30重排藿烷/(C30重排藿烷+C30藿烷)是基于第1类和第2类化合物之间的热稳定性差异;C27重排甾烷/(C27重排甾烷+C27规则甾烷)和C21/(C21+∑C29)甾烷是基于第2类与第3类化合物之间的热稳定性差异;C23三环萜烷/(C23三环萜烷+C30藿烷)则是基于第1类与第3类化合物之间的热稳定性差异,具有更好的应用效果.

库车坳陷东部油气地质条件复杂,天然气成因与油气充注时间存在争议,油气充注史不明,制约其油气勘探进程.利用天然气组分、碳同位素组成、流体包裹体岩相学与均一温度等分析测试数据,结合沉积埋藏史及构造演化史,研究了库车坳陷东部吐格尔明地区天然气地球化学特征、天然气成因类型及油气充注时间,分析了油气充注成藏过程.结果表明:吐格尔明地区天然气组分以甲烷为主,甲烷含量为75.56％～90.11％,干燥系数为0.79～0.93;δ13C1和δ13C2值为-35.73‰～-33.80‰和-26.41 ‰～-25.30‰,天然气成因类型属于成熟阶段的煤成气.吐格尔明地区侏罗系砂岩储层发育两类流体包裹体,分别为黄色液态烃包裹体和蓝白色荧光的气液烃包裹体、灰色的气烃包裹体,表明该区存在两期油气充注,第一期为13～7 Ma的原油充注,第二期为2.6 Ma以来的天然气充注.康村组早中期,吐格尔明地区烃源岩形成的原油充注至宽缓背斜圈闭中保存;库车组晚期,侏罗系克孜勒努尔组与阳霞组发育良好的源储组合,天然气近距离充注成藏.

The tectonic belt in northern Kuqa Depression has a long period of fault activity and multi-stage superposition, which has an important influence on hydrocarbon accumulation.Through the combination of growth index profile method, typical profile elongation (or compression ratio) method and structural equilibrium profile method, the development characteristics, active periods and hydrocarbon accumulation significance of faults in the northern Kuqa Depression are studied.The results show that there are three types of faults in the northern Kuqa Depression: early thrust fault, late thrust fault and long-term active fault.There are five periods of fault activity, which are paleogene (E), Neogene Jidike Formation (N1j), Kangcun Formation (N1k), Kuqa Formation (N2k) and Quaternary (Q) respectively.N1j, N1k and N2k are the key periods of fault activity.The fault activity will lead to the thickening of the source rocks in the Kezilenuer Formation (J2kz), which is conducive to the formation of multiple types of structural and lithologic traps.The fault active periods (N1j, N1k, N2k) match well with the main hydrocarbon generation and expulsion periods (E, N1j, N1k, N2k) of source rocks.The fault activity is beneficial to the formation and accumulation of oil and gas reservoir Yinan 2 and Tundong 2, but it also lead to the escape of oil and gas escape from Yinan 4 and Yishen 4 Wells, resulting in the destruction of reservoir forming and preservation conditions.The fingdings are of great significance to the analysis of hydrocarbon accumulation process in this area.

甫沙4井位于塔里木盆地塔西南坳陷昆仑山前冲断带的柯东构造带上,北部和东部分别发育有柯克亚和柯东1井油气田.为研究甫沙4井原油来源与充注过程,对原油样品和连续抽提后的含油砂样各组分(游离态、束缚态、包裹体)进行GC、GC?MS和GC?IRMS分析,与柯克亚凝析油气田油样进行油—油对比.结果表明:甫沙4井晚期充注原油组分具有C29?32重排藿烷、重排甾烷和Ts相对含量高,C27?29甾烷ααα20R分布呈反"L"型,以及正构烷烃单体碳同位素值较低等特征,与柯克亚凝析油气田来源于二叠系普司格组(P2?3p)烃源岩的主体原油(I类)地球化学特征一致.而早期充注的原油组分具有重排藿烷、重排甾烷和Ts相对含量较低,C27?29甾烷ααα20R分布呈"V"型,以及正构烷烃单体碳同位素值较高等特征,与柯克亚凝析油气田来源于中—下侏罗统湖相泥岩的II类原油地球化学特征一致.甫沙4井经历3个阶段成藏过程:①在上新世,二叠系烃源岩于生油晚期阶段生成的I类原油运移至柯克亚构造带或柯东构造带深部形成油藏;②在更新世早期,侏罗系烃源岩于生油早—中期生成的II类原油运移至甫沙4井白垩系储层;③在第四纪,强烈的构造作用使深部I类原油沿断裂调整进入甫沙4井白垩系储层.最终造成甫沙4井白垩系储层II类原油先充注,I类原油后充注的特殊现象.

Because of the huge potential of hydrocarbon, the Jurassic strata in the Tugeerming area has become a significant exploration target in the Kuqa Depression of the Tarim Basin. However, accumulation characteristics and controlling factors for the Tugeerming gas reservoir need to be further developed. In the present study, the accumulation characteristics were discussed using geochemical techniques, and the controlling factors for the generation and accumulation of gas reservoir were summarized. The gas generation intensity in Tugeerming reservoir is about 20-60 x 10(8) m(3)/km(2), suggesting that source rocks could generate sufficient natural gas for the reservoir. Sandstone reservoirs with relatively good physical properties (Improved by fractures and dissolution) provide favorable condition for the gas accumulation. This oil charging period of the Early Neogene (N(1)j) and the gas charging period of the Pliocene (N(2)k) occurred in the reservoir and the periods were 23-8 Ma and 5.2-1.64 Ma, respectively. Continuous production of natural gas is beneficial to accumulation. Faults and fractures provide migration channels for oil and gas. Fractures optimize the physical properties of the reservoir. Moreover, the assemblages of source-reservoir-caprock in Tugeerming area provided good condition for hydrocarbon preservation. Tugeerming gas reservoir is defined as a structure-lithologic type, which is lower generation and upper storage mode. The conclusions are critical to further oil and gas exploration.

塔里木盆地北部坳陷周缘发现的大量油气主要来源于下寒武统泥质烃源岩.坳陷西部下寒武统发育玉尔吐斯组,东部发育西大山和西山布拉克组,两者在有机质丰度、类型和成熟度等方面存在明显不同,微量元素显示玉尔吐斯组具有较高的古生产力,总体反映西部水体较深的强还原斜坡相沉积环境,而东部则反映为水体更深、还原程度更高的盆地相沉积环境.通过地震标定及解释,刻画了下寒武统烃源岩厚度图,发现了满西、满东两个沉积凹陷,结合总有机碳(TOC)分布图,对下寒武统烃源岩生烃潜力进行了计算及成图.北部坳陷生烃量巨大,而目前已发现油气仅占很小一部分,所以北部坳陷及周缘下步勘探潜力巨大.

Quantitative GC-MS analysis was performed on 138 oils from the cratonic regions of the Tarim Basin, northwestern China. Crossplots of (1) biomarker concentrations versus maturity ratios, (2) diamondoid concentrations versus sterane concentrations, (3) ratios of (Pr + Ph)/(n-C-17+n-C-18), and (4) Sigma n-C15-35/Sigma n-C9-14, were constructed and compared with oil densities, GOR and gas dryness. The results clearly show oil mixing resulting from a very complex charging history. At least four oil/gas charging episodes can be identified. One episode is represented by oils which have relatively high biomarker concentrations with maturity ratios suggesting an early to middle oil window source. There is second charge resulting in intermediate to low biomarker concentrations in many of the oils indicating a charge generated in the mid-to late-oil window. The third charge can be seen in oils in which biomarkers are absent indicating that they were sourced at late oil to wet gas levels of thermal maturity. Finally, the fourth charge is indicated by the high diamondoid concentrations in virtually every oil in this study. This charge was generated from very deeply buried source rocks at dry gas levels of thermal maturity where extensive oil to gas cracking has taken place. The fact that the oils show varying concentrations of biomarkers from low to high and yet similar low-maturity biomarker ratios suggests oil mixing to various extents, in which the biomarkers are predominantly derived from the least mature source, but they are differentially diluted by higher-maturity liquids poor in biomarkers. Furthermore, the deep charge represented by the high diamondoids concentrations is present in virtually every sample. Our results suggest that the oils in this study are all mixtures containing varying percentages of components derived from these four charges.

塔里木盆地台盆区海相烃源岩的分布是制约油气勘探的主控因素,在构造—古地理背景分析基础上,通过典型井地球化学分析结合测井标定与地震追踪,重新厘定寒武系主力烃源岩分布。结果表明,东部烃源岩主要分布在中-下寒武统泥页岩中,西部烃源岩主要分布在下寒武统泥页岩中,中-上寒武统—下奥陶统碳酸盐岩缺乏有效烃源岩,单井纵向厚度标定东部低于100 m、西部低于40 m,远低于早期预测厚度。寒武系烃源岩并非满盆分布,主要分布在满东凹陷、满西台内洼,并发现塔西南南缘可能发育大面积陆缘斜坡烃源岩,而巴楚—麦盖提、塘古—塔中、塔北等基底古隆起区缺乏烃源岩。受控前寒武纪古隆起与寒武纪弱伸展背景影响,寒武系发育4种构造背景下的烃源岩:主要为台间盆、台内洼烃源岩,以及可能存在被动陆缘斜坡、板块边缘裂谷烃源岩。

The source of marine oils from the deep Tarim Basin is still in debate due to several alteration processes of source indicators. A series of trimethyl-alkylbenzenes has been detected in marine oils from this old, composite basin, besides the reported aryl isoprenoids with 2,3,6-trimethyl substitution (AIPs). They are characterized by regular gas chromatography elution pattern, which is similar to that of n-alkylbenzenes, and suggest a strong possibility of n-alkyl side chains. C15 trimethyl-n-alkylbenzenes were synthesized by Friedel–Crafts acylation of trimethylbenzene isomers to determine their structures. Based on the chromatography and mass spectra data and the coinjection of synthesized compounds, this series of compounds has been assigned as the 2,4,5-trimethyl-n-alkylbenzenes that coeluted with 2,3,5-trimethyl-n-alkylbenzenes, and other trimethyl-n-alkylbenzene isomers were also detected. This series of trimethyl-n-alkylbenzene (AAs) shows much higher relative abundances in light and waxy oils than in normal and heavy oils, which is opposite to the variation in relative abundances of aryl isoprenoids. The ratios of these trimethyl-n-alkylbenzenes to the aryl isoprenoids (AA/AIP ratio) generally show a good correlation with the maturity indicators for most of studied oils despite of some outliers (mainly condensates). The pyrolysis of asphaltenes has confirmed these trends. These results support an important control of thermal stress on the molecular compositions of marine oils from the deep Tarim Basin, besides other secondary alteration processes (such as oil mixing and migration fractionation, among others). These factors should be given a full consideration for the source determination of deep and ultradeep oils.

Petrography microthermometry of fluid inclusion, quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract(QGF-E) are used to study the paleo-fluid characteristics and hydrocarbon charging history of Jurassic reservoir in Dibei gas field, Kuqa depression, Tarim Basin.The results show that the Jurassic reservoirs in Dibei gas field develop inclusions with two stages:the first stage is liquid inclusion with yellow-green color, which indicats the filling of early oil;the second stage is gas-liquid inclusion with blue-white fluorescence color and gas inclusions with non-fluorescence color, which indicats that the late gas was charged.The homogenization temperature of inclusions indicats the two stages of hydrocarbon charging. QGF and QGF-E show that the oil in the Jurassic reservoir of the Dibei gas field may be a mixture of different origins or different maturity.Combined with the sedimentary history of Dibei gas field, it is suggested that the Dibei gas field has experienced two stages of oil and gas charging.The first is the filling of oil between 18~16 Ma.Gas charging period in the second stage is 5~3 Ma.Since the Xiyu period, the tectonic movement has been strong and the gas field accumulate at low parts.

The geochemical feature and evolutionary history of hydrocarbons from the deep Cretaceous Bashijiqike (K 1 bs) Formation tight sandstone reservoir in the Dabei Gas Field, Kuqa Depression were investigated using gas chromatography, gas chromatography–mass spectrometry, inclusions petrography and micro-thermometry, laser Raman spectroscopy, and quantitative grain fluorescence. The result indicates that natural gases from the deep sandstone reservoir are mainly composed of alkanes and belong to dry gases, of which methane accounts for 94.30–97.20% (avg. 95.64%), and ethane is 1.23–2.45% (avg. 1.95%). The stable carbon isotopic value of methane and ethane is −31.9‰ to −29.3‰ (avg. −30.3‰) and −24.2‰ to −19.4‰ (avg. −21.7‰), respectively, and this reflects the features of high-mature coal-derived gases. In addition, natural gases in the Dabei Gas Field have characteristics of coal-derived gases which were sourced from Jurassic coal measures. Oils in the Dabei Gas Field predominately originated from Triassic Huangshanjie (T 3 h) Formation mudstones with some contributions from Jurassic coaly rocks. Petrological and micro-thermometry results of fluid inclusions suggest that the K 1 bs Formation tight sandstone reservoirs have experienced two phases of hydrocarbons charge histories, namely “early oil and later gas.” The quantitative grain fluorescence analysis indicated that sandstone samples with quantitative grain fluorescence index value >5 and quantitative grain fluorescence-extraction intensity >40 pc in Wells DB101 and DB2 can be used as indicators for the paleo oil layers or the migration channels of later charged natural gas. The aforementioned analyses and burial and thermal histories of K 1 bs sandstone reservoir demonstrated that oil charged at 10 Ma and natural gas charged at approximately 3 Ma in the study area. Furthermore, paleo-tectonic evolution enabled source rocks to mature and expel hydrocarbons, and the structurally related faults and traps provided pathways and places for hydrocarbon migration and accumulation.

Oil asphaltenes have been used to characterize the source(s) and timing of expulsion of early charged oils. However, the application on asphaltene in a complex petroleum basin have been limited. Marine oils from the Tarim Basin, NW China, were selected to release asphaltene-bound molecules by the catalytic hydropyrolysis technique (Hypy). The analyzed samples were 10 heavy oils from two major oil-production regions (the Tabei and Tazhong uplifts) in the basin. The asphaltenes may be mixed products from multiple hydrocarbon charging stages, if we consider the main oil filling events and the regional geothermal histories of corresponding reservoirs. However, the similar molecular and isotopic characteristics of the hydropyrolyzates indicate contributions from one major source rock (possibly lower Cambrian mudstone) during relatively early periods, based on the presently known source characteristics. The preservation of asphaltenes probably reflects a low reservoir temperature after charging. The asphaltenes were derived from marine algae deposited in a strongly reducing environment, given the biomarker data (e.g., relatively abundant aryl isoprenoids and low Pr/Ph) and carbon isotopic data (−35.5‰ to −34.4‰). Asphaltenes were expelled around the oil generation peak. Moreover, molecular ratios indicative of maturity (e.g., tricyclic terpanes/hopanes), derived by Hypy of asphaltenes, suggest that the asphaltenes of the Tazhong Uplift are generally more mature than those of the Tabei Uplift. Moreover, this is mainly related to different maturities when the oil was expelled. The free hydrocarbons in the Tazhong Uplift show greater molecular and isotopic variations than those in the Tabei Uplift. This might be attributed to more complex accumulation processes in the former. Late oils with a range of maturities, mixing proportions with early biodegraded oils, and degrees of alteration by thermochemical sulfate reduction could all have played a role in generating this variability. The results indicate that the hydrocarbons released from oil asphaltenes by Hypy can provide insights into multiple charging processes in an old composite petroleum basin.

近年来塔里木盆地的深层油气勘探取得突破,有必要对寒武系高-过成熟烃源岩的有机质碳同位素组成进行深入研究,已有工作对干酪根催化热解产物中正构烷烃碳同位素组成的关注不多.本文对来自塔里木盆地内钻井和西缘露头的8个寒武系烃源岩干酪根进行了催化加氢热解实验.结果表明,氢解产物无论碳数分布还是分子碳同位素组成特征都表现出较大的变化.盆地内钻井烃源岩干酪根催化加氢热解产物中低碳数正构烷烃(C14～C20)具有明显的偶碳优势,部分样品C22正构烷烃优势明显;而柯坪地区露头样品干酪根催化加氢热解产物中正构烷烃不具有或具有微弱的偶碳数优势.钻井和柯坪露头烃源岩干酪根催化加氢热解产物中正构烷烃的碳同位素组成均随碳数增加逐渐变轻,低碳数正构烷烃(C14～C20)碳同位素组成没有明显偶碳数偏重的分布特征.此外,柯坪露头烃源岩正构烷烃的碳同位素组成(-34.5‰ ～-31.5‰)明显比盆地内钻井烃源岩中的正构烷烃(-32.3‰ ～-26.4‰)偏轻,这一变化与干酪根总碳同位素组成的变化一致.正构烷烃及其碳同位素分布特征的差异可能主要反映了烃源岩沉积时期,分层水体导致有机质母源或沉积环境的变化.除了寒武、奥陶系烃源岩有机质碳同位素组成上的差异,如何利用同位素手段对中-下寒武统烃源岩自身变化进行油源判识,也是亟需考虑的问题.

利用天然气组分定量、稳定碳同位素组成、流体包裹体显微测温和生烃动力学实验数据,对塔里木盆地库车坳陷克深大气田深层天然气的地球化学特征及成因、储层流体包裹体特征与均一温度、油气充注时间及成藏过程进行研究.结果表明:库车坳陷克深大气田深层天然气以烷烃气为主,甲烷含量占87.30％～98.33％,重烃(C2+)含量占0～0.66％,干燥系数达0.99％～1.0％;δ13 C1值、δ13C2值分别为-29.3‰～-26.4‰、-21.4‰～-16.1‰,属于过成熟的煤成气.克深大气田白垩系巴什基奇克组储层发育2期烃类包裹体:第Ⅰ期为发蓝白色荧光的液态烃包裹体,指示早期轻质油充注;第Ⅱ期为无荧光的气态烃包裹体,与其共生的盐水包裹体均一温度为145～160℃,为晚期天然气充注.克深大气田主要经历了库车组沉积期末(约2.5 Ma)以来的天然气大量充注,气源主要来自克深井区和拜城凹陷生气中心的侏罗系煤系烃源岩,为深埋快速生烃、强源储压差作用下晚期聚集成藏.

柯坪褶皱冲断带位于塔里木盆地西北缘,勘探程度低,地表、地下构造变形复杂,构造模型存在多解性.本文通过对最新地震资料的解释,结合地质露头和钻井资料,建立起该地区新的构造模型.柯坪褶皱冲断带构造变形具有东西分段、南北分带的特征.东西向具有“跷跷板式”的沉积特征.中部皮羌段中寒武统盐层厚度大,主要发育盐下冲断构造和盐上反向滑脱构造;东、西两段主要发育基底卷入构造.石炭纪柯坪褶皱冲断带存在一期古隆起构造.晚石炭世一早二叠世沉积的康克林组具有填平补齐的特征.皮羌段发育两期断裂.早期为海西期断裂,晚期为喜山期断裂.石炭纪古隆起受控于早期断裂.喜山期形成的盐上滑脱构造对下伏潜在的古油藏具有封闭和保存作用.

The Tugeerming area is located in the eastern part of the Kuqa Depression, Tarim Basin. In recent years, prolific oil and gas flow in the Jurassic Yangxia Formation of Well Tudong 2 indicates broad prospects of exploration in the said area. This paper carries out the oil-gas and source correlation in the Tugeerming area. The findings acquired as briefed as follows. The biomarker characteristics of the crude oil of the Yangxia Formation of the Tugeerming Jurassic group showed that the hydrocarbon precursor types were a typical freshwater source of terrestrial organic matters with in the Yangxia Formation. The natural gas of the group is coal-type condensate with associated gas. The maturity of the natural gas is the same as that of the crude oil, where both of them are derived from the same hydrocarbon source rocks. In this paper, the biomarker comparison technique, n-alkane carbon isotope comparison technique, and kerogen carbon isotope-crude carbon isotope comparison technology system were used to study the Jurassic Yangxia Formation oil in the Tugeerming area, as well as the hydrocarbon source rocks of Jurassic and Triassic in the area. The differences between the source rocks are comprehensive. The results show that there is a maternal relationship between the Yangxia Formation crude oil and the source rocks of the Jurassic Yangxia and Kezilenur formations, which provides an important reference for the evaluation of oil and gas resources in this area.

采用包裹体岩相学、均一温度、盐度、含油包裹体丰度、储层颗粒荧光定量实验分析方法,对库车坳陷克深大气田白垩系巴什基奇克组储层致密砂岩样品进行测试,剖析克深大气田深层致密砂岩储层古流体地球化学特征与油气充注.结果表明,克深大气田发育两期油气包裹体,分别为发亮蓝色荧光的轻质油包裹体与灰黑色的气态烃包裹体.克深大气田包裹体均一温度分布存在130～140℃与150～160℃两个主峰值,相应的古盐度值为16％ ～10％与12％ ～4％,表明有两期烃类流体充注,其中天然气高强度充注发生在2.5 Ma以来.含油包裹体丰度分布在2.1％ ～13.4％之间,QGF指数为2.2～9.6,QGF-E强度为20～38 pc,揭示克深大气田形成过程中曾经存在强度较弱的轻质油充注.

We conducted a chemical and isotopic study of oilfield waters from Ordovician limestone reservoirs in the Tazhong oilfield (Tarim Basin, China) to trace the origin and evolution of the waters, and to demonstrate their possible relationship with hydrocarbon charging. The elemental chemistry (Cl, Br, SO4, I, K, Na, Ca, Mg, and Sr) and multiple isotopic compositions (δD, δ18O, 87Sr/86Sr, and 129I/I) of the oilfield waters were determined. The results show that these oilfield waters contain basinal brines that infiltrated in three stages, along with a lesser contribution from meteoric water. The meteoric water appears to have infiltrated downwards during the late Silurian and Carboniferous. The earliest brine had very low I contents (<5.65 mg/L) and migrated upwards from organic-poor Cambrian to Lower Ordovician dolostones during the Late Ordovician. The second brine had high I contents (>50 mg/L), was derived from Cambrian argillaceous source rocks, and migrated upwards into Ordovician reservoirs. This stage was related to the main period of migration of crude oils out of the source rocks into reservoirs during the Silurian and Devonian. Both of these brines incorporated constant levels of fissiogenic 129I from the limestone reservoir rocks (11.8–47.0 atom/μL). Finally, brine with very low I contents, but higher 129I (106–491 atom/μL), began to migrate upwards and infiltrate reservoirs. Given the relatively high fissiogenic 129I, this stage may have occurred during the late Cenozoic, and was associated with migration of dry gas from the same source rocks. Our results, combined with those of a previous study of other oilfields in the basin, suggest that the evolutionary of oilfield waters can be used to constrain hydrocarbon accumulation events, and both of which were ultimately controlled by regional tectonism and local geological factors.