Oil Geochemistry Research Articles

Biomarker geochemistry of Qaiyarah, Butmah and Ain Zala crude oils, northern Iraq: Implications for the Jurassic source rocks

Fifteen crude oils from the Qaiyarah, Butmah, and Ain Zala fields were investigated using organic geochemistry to infer organic matter maturity, redox conditions of the depositional environment, and lithology of the corresponding source rocks. Carbon isotope compositions and sulfur contents were measured for all samples and saturated and aromatic biomarkers were analyzed by GC-MS.Low pristane/phytane (0.68–0.82) and high C35 S/C34S (1.03–1.66) and homohopane indices (0.14–0.24) in the oil samples indicate anoxic or euxinic conditions for the corresponding source rocks. In addition, sulfur content, C30 norhopane/C30 hopane, and C31 R/C30 hopane, Ts/Tm and C27 diasteranes/regular steranes values suggest carbonate source rocks with variable amounts of clays. These source rocks contain mainly type II-S kerogen. Moretane/hopane, hopane and sterane isomerization ratios suggest generation from early mature organic matter. Hierarchical cluster analysis identified three families charged from carbonate source rocks with variable amounts of clays and maturity. Oil-source rock correlation (based on published data) and age-related biomarkers suggest that these oils were generated from Jurassic source rocks (Sargelu, Naokelekan, and/or Chia Gara formations). Jurassic rocks in Ain Zala and Butmah area have low potential for hydrocarbon generation, therefore, the Ain Zala and Butmah oils were charged from Jurassic formations outside the Ain Zala area, but within the neighboring area northeast of Butmah and Ain Zala.

Chemometric Classification and Geochemistry of Crude Oils in the Eastern Fukang Sag, Junggar Basin, NW China

Thirty oil samples collected from the eastern Fukang Sag were analyzed geochemically for their biomarkers and carbon isotopic compositions. The chemometric methods of principal component analysis and hierarchical cluster analysis, employed to thirteen parameters indicating source and depositional environment, classified the oil samples into three genetically distinct oil families: Family A oils were mainly derived from lower aquatic organisms deposited in a weakly reducing condition of fresh–brackish water, Family B oils came from a source containing predominantly terrigenous higher-plant organic matter laid down in an oxidizing environment of fresh water, and Family C oils received sources from both terrigenous and marine organic matter deposited in a weakly oxidizing to oxidizing environment of brackish water. Indirect oil–source correlations implied that Family A oils were probably derived from Permian source rocks, Family B oils originated mainly from Jurassic source rocks, and Family C oils had a mixed source of Carboniferous and Permian. Biomarker maturity parameters revealed that all three families of oils were in the mature stage. However, Family A oils were relatively less mature than Family B and Family C oils.

Biomarkers, light hydrocarbons, and diamondoids of petroleum in deep reservoirs of the southeast Tabei Uplift, Tarim Basin: Implication for its origin, alteration, and charging direction

The Atan Bulge in the southwestern Tabei Uplift of the Tarim Basin provides insights into the geochemistry of the oils and condensates in deep Ordovician reservoirs because its reservoir burial depth is generally greater than 6000 m. To investigate the oil origin, alteration, and migration pathways, the carbon isotopes, biomarkers, light hydrocarbons, and diamondoids of 16 oil and condensate samples from the Ordovician reservoirs in the Atan Bulge were analyzed. The results show that chain alkanes dominate the light hydrocarbons, followed by cycloalkanes and aromatic hydrocarbons. 1-methyladamantane (MA) dominates the diamondoids, followed by 1,3-dimethyldiamantane (DMD). The samples lacked biodegradation and thermochemical sulfate reduction signatures. Except for a few samples near the Manjiaer Depression, the evaporative fractionation caused by late natural gas charging is generally weak. The oil geochemistry suggests that the oils and condensates are primarily derived from lower Cambrian marine shale, and the organic matter is mainly type II. The equivalent vitrinite reflectance (Rc) calculated using thermal maturity indicators derived from methylphenanthrene, methyldiamantanes, and C5–C7 light hydrocarbons, respectively, is in the ranges of 0.78%–1.04%, 1.1%–1.5%, and 1.06%–1.48%. The samples' low (3-+4-)-methyldiamantane concentrations (36–76 μg/g) imply a low level of oil cracking. The carbon isotope distribution among oil fractions and different maturity ranges suggest that crude oil was generated and charged multiple times. The maturity of the samples decreases from SSE to NNE, indicating that the petroleum likely migrated from strike-slip faults during its primary charging period, with the Manjiaer Depression and its slope serving as the primary source kitchens.

The history of Madison Group exploration and production in the North Dakota Williston Basin with an update on Madison Group source rocks

The Williston Basin has proven to be a global super basin in terms of oil production and reserves (Sonnenberg, 2020). Although recent production in the basin has been dominated by the Middle Member of the Bakken Formation, the Madison Group has yielded over a billion barrels of oil since 1951. The Madison Group consists of the Charles, Mission Canyon, and Lodgepole formations with various members in each. These formations are found in both the United States and Canada and led Williston Basin production until 2008. As with many petroleum plays, the Williston Basin enticed oil men for many decades with the prospect of oil before finally yielding to success. Success, which is so often accompanied by a bit of good fortune, is a matter of finances, persistence, and technology, ultimately paving the way to successful commercial wells. Many factors contributed to the ongoing production results in the basin and include seismic, horizontal drilling, and completion technologies, and of course, good geological assessments. The history of production in the basin is also detailed by the history of petroleum geochemistry. Source rock and oil geochemistry progressed from scratch tests, test tube pyrolysis, and standard physicochemical properties, such as API gravity, to detailed chemical investigations including high resolution gas chromatography and biomarker analysis.

Geochemistry and accumulation of Jurassic oil in the central Junggar Basin, western China

The central Junggar Basin in western China is unique because it provides insights into the geochemistry of oil from Jurassic coal measures. The analysis of TOC, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), and carbon isotopes was performed to characterize the oil geochemistry and evaluate the hydrocarbon generation potential of source rocks in a coal-bearing formation. Fluid inclusions, fluorescence microscopy, and burial-thermal history were also used to study the oil generation and charging histories. The results show that the mudstone of the Badaowan Formation is the main source rock of the Jurassic and has relatively high hydrocarbon generation potential. The Jurassic oil in the Zhong-4 Block is moderately mature, with an equivalent Ro of about 0.75%. The oil is characterized by heavy carbon isotopes, a predominance of Pr over the Ph, low abundances of trisnorhopane (Ts), tricyclic terpanes and gammacerane, predominance of C29 steranes among regular steranes, a preponderance of naphthalene and its alkylated analogues in aromatic compounds, and abundant polycyclic compounds. Such geochemical data indicate a contribution of Jurassic humic type organic matter to the oil. The mudstone in the Badaowan Formation started generating hydrocarbons in the Early Cretaceous and reached the peak of hydrocarbon generation in the middle Cretaceous. One major hydrocarbon charging episode is suggested in the Late Cretaceous and another in the early Neogene. The Fukang Depression in the south is the source kitchen, and oil migrates in a direction of southwest to northeast through faults and sandstone carrier beds.

The significant meaning of biodegradation to the petroleum system of the Seram Basin, eastern Indonesia: evaluation on the basis of physio-chemical composition variation of Seram oils

It has been widely accepted since the 1980s that Seram crude oils belong to one family that originated from the Triassic carbonate source rock. Even though these oils share similar nature and origin, they exhibit wide physio-chemical composition variations in Seram Basin. Moreover, this variation is also noted within a similar oil field. Hydrocarbon alteration, especially biodegradation, a process of hydrocarbon destruction by microbial activities, has been attributed to this variation. However, the degree and extension of biodegradation in the Seram Basin are still poorly understood. Therefore, crude oils accumulated in main reservoirs, the Pre-Tertiary Manusela Carbonate and the Pliocene Fufa Clastic reservoirs, retrieved from Lofin, Oseil, Nief, and Bula Fields, are comprehensively studied. In addition, several oil seep samples were also utilized for this study together with crude oil geochemistry data compiled from previous publications. The occurrence of biodegradation is also validated with the geological conditions that include resevoir temperatures and salinities. Based on the geochemical signatures, there is a wide range of biodegradation degrees within the Seram Basin with the biodegradation degree tends to increase and more destructive to Bula Field which is situated in the northern part of the basin. The biodegradation pattern is linked to hydrocarbon generation and migration history. The Neogene deformation in eastern Indonesia is interpreted to be responsible for the different biodegradation process within Seram Basin. This process should be well understood and not be neglected during petroleum exploration, especially in eastern Indonesia. This study shows that such simple process has a deep meaning on the petroleum system history, especially the hydrocarbon preservation in the reservoir.

Organic geochemistry of Mongolian oils

The composition and distribution of biomarker hydrocarbons in the Tamsagbulag oil field (Mongolia) has been studied. A unique variety of “fingerprints” was found in unchanged oils and biodegraded differences (three homologous series of secohopanes, etc.). According to the composition of biomarkers, Mongolian oils are very close to Baikal oils.

Geochemistry of oils and condensates from the lower Eagle Ford Formation, south Texas. Part 2: Molecular characterization

Fifty-five petroleum samples from unconventional wells in the self-sourced lower Eagle Ford Shale were analyzed using routine geochemical methods. The samples are broadly distributed, geographically and vertically, and range in maturity from mid-oil to wet gas. Their physical and chemical properties span most of the range observed in the entire play. Two source facies are identified: west of San Marcos Arch is a marine marl facies deposited under anoxic to euxinic conditions containing abundant type II/IIS kerogen and east of the Arch is a marine shale to marl facies deposited under mostly oxic to anoxic conditions that received an additional input of terrigenous organic matter. The unconventional oils are too mature to detect any subtle differences that could distinguish a marl from a pure carbonate source facies. Saturated and aromatic biomarkers rapidly decrease with depth and are at or near the limits of detection below ∼9,000 feet. Condensates >13,500 ft show evidence of advanced hydrocarbon cracking. All properties and molecular parameters that are dependent on thermal maturity for oils/condensates west of the San Marcos Arch exhibit two trends with true vertical depth (TVD). One is defined by samples between the Karnes Trough area and the Maverick Basin; the other trend defined by samples near the Karnes Trough is offset with equivalent maturity occurring at deeper depths. This ∼2,000 ft offset is likely due to differences in the amount of uplift and erosion experienced in the two regions after the source rocks achieved their maximum maturity.

The Late Cretaceous X Reservoir petrophysics properties and its Oil Geochemistry in the Nameless Oilfield, Mesopotamian Basin, South Iraq

The X Formation, which dates from the Late Cenomanian to the early Turonian, is the largest carbonate reservoir in Iraq's South Mesopotamian Basin. There are two shallowing-up depositional periods in it, which begin with deep water mudstone associated with wackestone, which gradually shallows into rudist and is dominated by big foraminifera shoals and barriers, which are followed by lagoonal and intertidal facies. The identification of five distinct reservoir rock types, including mB2, mB1, CRII, mA, and CRI, was based on a combination of sediment types and diagenetic processes that influenced porosity types. The formation oil geochemical studies point to a Lower Cretaceous marine carbonate source depositional environment that is early mature and anoxic.

Geochemistry of Oils in the Middle Devonian–Lower Frasnian Terrigenous Petroleum System of the Timan–Pechora Basin

Geochemistry of Oils in the Middle Devonian–Lower Frasnian Terrigenous Petroleum System of the Timan–Pechora Basin

Geochemistry of formation waters and crude oils in the Shulu Sag, Bohai Bay Basin, NE-China, to assess quality and accumulation of hydrocarbons

Geochemical fingerprinting of formation waters and hydrocarbons can be utilized to track the migration, accumulation, and preservation of hydrocarbons. The present case study from the Shulu Sag, Bohai Bay Basin, NE-China analyzes the origin of the formation waters and the relationship between water chemistry and hydrocarbon preservation by combining the geochemical characteristics of formation waters and crude oils. There are three geochemical groups of formation waters with different origins, which represent different hydrodynamic environments and hydrocarbon preservation conditions. Group 1 waters are related to meteoric water with the lowest total dissolved solids (TDS), γ(Cl–Na)/γMg and the highest γNa/γCl, representing an open environment with poor hydrocarbon preservation conditions, accompanied by super heavy oils. Group 3 waters are connate water with the highest TDS, γ(Cl–Na)/γMg and the lowest γNa/γCl, representing a closed environment with the best hydrocarbon preservation conditions, accompanied by light oils. Group 2 waters are intermediate between Group 1 and Group 3 waters, representing a semi-open environment with intermediate hydrocarbon preservation conditions, accompanied by light, medium, and heavy oils. The clear corresponding relationship between oil quality and associated water type shows that water chemistry significantly affects the oil quality and accumulation in the Shulu Sag through secondary changes. Biodegradation is the dominant effect in the strata above 2100 m. Water washing is dominant in the depth range of 2100–3400 m, and there are no noticeable secondary changes in the strata below 3400 m. A model for the origin, evolution, and flow of formation waters in the Shulu Sag is established to analyze the hydrocarbon accumulation process. Meteoric waters flow into the buried hills from Ningjin Uplift as a result of gravity flow, resulting in modification of oil composition, destruction of the oil reservoirs, and the formation of Group 1 waters. During the hydrocarbon charging, the centrifugal flow driven by overpressure flows in two directions from the source rocks, one is to the western slope and mixes with meteoric waters to form Group 2 waters and heavy oil reservoirs, and the other is to the paleo-uplift to form Group 2 and Group 3 waters and light oil reservoirs. Water chemistry is sensitive to the hydrodynamic environment change and can be an important reference for oil and gas exploration. Buried hills with Group 3 waters should be the highest priority for further exploration, whose oil reservoirs are dominated by light oil with high commercial value. Although the oil quality is poor, buried hills with Group 2 waters in the slope can be secondary targets. In comparison, the buried hills with Group 1 waters should be avoided for oil and gas exploration. The geochemistry of formation waters helps understand the origin and evolution of formation waters, predict oil quality and distribution, and further aids oil and gas exploration.

Geochemistry of oils and condensates from the lower Eagle Ford formation, south Texas. Part 1: Crude assay measurements and SimDist modeling

Fifty-five oils and condensates produced from unconventional reservoirs in lower Eagle Ford Shale were characterized. Most of the samples are from the play area east of the Maverick Basin and west of the San Marcos Arch, while five samples are from wells east of the Arch. Crude assay measurements (API gravity, wt% sulfur, wt% nitrogen, viscosity at 25 and 40 °C, pour point, simulated distillation [SimDist] and C15+ chemical group-type fractionation) were conducted on dead oil samples using standard methods. All bulk properties were found to correlate well with each other. Relationships between crude assay measurement and production depth suggest that thermal maturation accounts for most of the variance in composition; however, different depth trends are observed in oils from the Karnes Trough area compared to locations west of that region.Refinery valuation and process models rely heavily on the fractional composition of crude feedstock defined by boiling point distribution. We constructed a model using seven crude assay parameters (API gravity, % S, % N, viscosity at 40 °C, and % C15+ saturates, % C15+ aromatics and % C15+ resins) as inputs for predicting SimDist boiling point curves. Using optimized parameters derived from this model, we found that SimDist curves can be modeled with nearly the same degree of accuracy using only API gravity and %S because of their strong correlation with the other bulk properties. This offers the prospect for refiners to identify wells producing specific grades of crude across the entire lower Eagle Ford play. The ability to construct a SimDist predictive model based only on the most basic assay measurements suggest that the compositional variations are due mostly to thermal maturity and the heterogeneity in source facies is insignificant in the lower Eagle Ford west of the San Marcos Arch. The SimDist predictive model is specific to the Eagle Ford shale oils and condensates, but the methodology could be used to construct formation specific models in other unconventional plays.

Geochemical characterization of crude oils and potential source rocks from southern coastal Ecuador: Hypothetical petroleum systems

This research paper encompasses an organic geochemical investigation on oils and sedimentary rocks from the southern coastal region of Ecuador that examines the hydrocarbon generation and accumulation in the strata of Progreso Basin Province. This petroliferous province represents an interesting area for an oil geochemistry study due to its non-elucidated petroleum systems. The present work focuses on the analysis of eighty-five oils and forty rock samples to determine kerogen types, depositional paleoenvironments, levels of thermal maturity, and in-reservoir petroleum biodegradation stages as well as to assess correlations between source facies and oil samples. Potential source rocks were selected and analysed from different outcrops and wells throughout the basin and the southern Gulf of Guayaquil. Classic biomarker, extended diamondoid, and isotope studies indicated that almost all oils from the Progreso Basin Province underwent biodegradation and were generated from multiple Tertiary source rocks deposited in a marine setting with significant influx of terrestrial organic material. Three families of oils were identified. Oil-source rock correlations suggest that the Socorro, Dos Bocas and San Eduardo formations can be considered as contributors to the studied oils. Geochemical data and previous thermal models point towards two probable hydrocarbon kitchens defined in the deepest parts of the basin as well as a third possible kitchen extended offshore beyond the Santa Elena Peninsula.

Sea bottom characteristics and geochemistry of oil and gas seeps in the Gulf of Mexico

From 2015 to 2018, TGS conducted a comprehensive multiclient oil and gas seep mapping survey in the Gulf of Mexico (GOM). The basis for identifying seeps on the sea bottom was a high-resolution multibeam echosounder survey, mapping approximately 880,000 km2 of the sea bottom deeper than 750 m water depth, at a bathymetric resolution of 15 m, and a backscatter resolution of 5 m. We identified more than 5000 potential oil and/or gas seeps, and of those, we cored approximately 1500 for hydrocarbon geochemical analysis. The sea bottom features best related to hydrocarbon seepage in the GOM are high backscatter features, mud volcanoes, pock marks, brine pools, “popcorn” texture, fault traces, and anticlinal crests. We also tracked gas plumes in the water column back to the sea bottom to provide an additional criterion for hydrocarbon seepage. Cores from sea bottom targets recovered liquid oil, tar, and gas hydrates. Oil extract and gas analyses of samples from most target types produced values substantially higher than background in both oil and gas.

Geochemistry of Oils and Condensates from the Lower Eagle Ford Formation, South Texas. Part 3: Basin Modeling

Geochemistry of Oils and Condensates from the Lower Eagle Ford Formation, South Texas. Part 3: Basin Modeling

Geochemistry and source of crude oils in the Wensu uplift, Tarim Basin, NW China

The Wensu uplift, to the northwest of the Tarim Basin, is located at the intersection of the marine Awati basin and the continental Kuche foreland basin. The origin and accumulation of hydrocarbons are complex processes in the Wensu uplift. The XWD 1 and 2 wells, drilled in the Wensu uplift in 2017, produced high-yield commercial oil flows from Neogene strata, thus realizing the first major breakthrough in the region's 50 years of oil and gas exploration. This discovery invited significant attention from the research community for shallow hydrocarbon accumulations along the margins of the Tarim Basin. This study focuses on the Neogene hydrocarbons of the Wensu uplift along with their geochemical characteristics and origin. We propose a hydrocarbon accumulation model, reconstructed by combining geology and geochemistry. The results show that crude oils from the Wensu uplift display typical lacustrine characteristics: 1) higher Pr/Ph values (1.68–2.04, average 2.33) that are indicative of an oxidizing sedimentary environment for the source rock; 2) higher content of rearranged steranes, C29Ts, and C30 diasteranes and lower DBT/P value (0.09–0.11), indicating that the source rock is shale with a high content of clay minerals; and 3) lower sterane/hopane ratios (0.14–0.15) indicating high inputs of bacteria and microorganisms. The above characteristics are distinct from the adjacent marine crude oils which feature relatively lower ratios of Pr/Ph (1.27–1.37) and higher ratios of DBT/P (0.62–0.82) and steranes/hopanes (0.87–0.90). The oil-oil and oil-rock correlations conducted using hydrocarbon biomarkers and carbon isotope ratios show that the oils in Wensu uplift contain contributions from the lacustrine source rocks of the Jurassic Qiakemake (J2q) and Triassic Huangshanjie (T3h) formations of the eastern Wushi–Baicheng sag, suggesting that the Wensu uplift oils have a mixed origin. The age of stratigraphic traps in the Wensu uplift coincides with that of hydrocarbon expulsion peak and the hydrocarbons accumulated along the slope by long-distance migration. The results of this study aim to serve as an important guide for further studies on petroleum accumulation mechanisms and shallow hydrocarbon explorations in basin margins devoid of local hydrocarbon source rocks.

Geochemical studies of gases from oil and gas fields in the southern part of the caspian basin and their correlation with the results of oil geochemistry

This article presents the results and interpretation of the compositional and isotopic analysis of carbon in 14 gas samples derived from oil and gas fields and structures (Liman, East Makat, North Kotyrtas, Zholamanov, S. Nurzhanov and West Prorva) of the southern part of Pre-Caspian basin. According to the results of this study, all gases have a thermogenic source and their organic matters were deposited in the marine environment, which is also consistent with the results of biomarker analysis of oils from these studied fields. A sharp enrichment of propane with heavy carbon isotope in gas №55 of East Makat field suggests its biodegradation, which is also confirmed by the results of gas chromatographic analysis of oil from this well. A star diagram of gases was plotted based on normalized values of carbon isotopic composition of C1-C5, according to the results of which the studied samples can be divided into 5 genetically different groups. The identified groups based on results of this gas analysis are also consistent with the results of «fingerprinting» of oil from these fields. Keywords: gas composition; gas isotopic composition; Rayleigh fractionation; Bernard diagram; Clayton diagram; Laurent diagram; Chung diagram; enrichment in heavy isotope.

Inorganic Geochemistry of Crude Oils of Northern Eurasia after ICP-MS Data as Clear Evidence for Their Deep Origin

The emergence of mass-spectroscopy with inductively-coupled plasma (ICP-MS) made it possible to study the microelement composition of crude oil and its derivatives with the limit of detection (LOD) at the ppt level. We have studied the crudes from West Siberian (Shaimsky, Sredneobsky and Oktyabrsky regions) and Tatarstan Romashinskoye oilfields with the ICP-MS method to detect 50 rare, rare-earth, and other microelements. The elemental composition is reasonably comparable to their concentrations in ultrabasites whereas the contents of most of the elements are low to the limit. On the diagrams of rare-earth elements, one can see the prevalence of light lanthanides and positive europium anomaly. Increased content of platinoids was found in Tatar oils; in some cases, the concentration of ruthenium reaches 0.06 g/t. The study shows that studied crudes have a specific microelement composition. Based on the elevated contents of transit elements and platinoids, a conclusion was made about the “ultrabasic” geochemical–metallogenic specialization of studied petroleum systems and the assumption about its origin was proposed.

Organic geochemistry of crude oils from Oligocene reservoirs in the Salin sub-basin, Myanmar: Insights into source, maturity, and depositional environment

Fourteen crude oil samples were collected from the South (Yenangyaung: YNG), Central (Chauk: CHK), and North (Letpando: LPDO) oilfields in the Salin sub-basin, Myanmar. This study investigated the organic geochemical characterization of crude oils from early to late Oligocene reservoir rocks. The saturated and aromatic hydrocarbons of selected oil samples were analyzed by integration of gas chromatography and gas chromatography-mass spectrometry methods to evaluate their origin, depositional environment, and thermal maturity. All the oils have moderate to high API gravity, showing medium to light oils. Crude oils were classified into three groups based on their biomarker compositions. The group I oils (Okhmintaung Formation, upper Oligocene, YNG Oil Field) mainly originated from planktons/algal materials with less contribution of terrestrial input, deposited under sub-oxic environments (lacustrine-marine setting). The group II oils (Padaung Formation, middle Oligocene, CHK Oil Field) were significantly generated from planktons/algal sources with minor input from terrestrial materials, deposited in an oxic/sub-oxic environment (fluvial/deltaic-marine setting). Group III oils (Shwezettaw Formation, lower Oligocene, LPDO Oil Field) were derived from a mixed contribution of planktons/algal materials and terrestrial input accumulated under an oxic environment (fluvial/deltaic-marine setting). Group I and Group II oils have reached peak oil window, while Group III oils indicate the early oil window. The results of stable carbon isotopic compositions for all analyzed oil samples indicate that the source rocks were derived from marine algae, and terrestrial and/or freshwater algal materials. Oil-oil correlation suggested that Oil Groups exhibit mixed source characterization during hydrocarbon accumulation processes.

Geochemical characteristics and genetic families of crude oil in DWQ oilfield, Kuqa Depression, NW China

As one of the most petroliferous oil producing area in Kuqa depression, Dawanqi (DWQ) oilfield is supplying with great attention. In this regard, the geochemical characteristics and oil families from DWQ field were investigated using molecular compounds analysis of GC, GC–MS techniques. The bulk geochemistry of oils from DWQ oilfield displays complicated molecular composition characteristics, including relative higher indices of Pr/Ph (1.4 ~ 4.26, with an average of 2.4), high concentration of light hydrocarbons and certain abundant pentacyclic triterpene and steranes. The C7 light hydrocarbon and isoprenoids ratios indicate the oils were derived from terrestrial and higher plant input in weak oxidizing and reducing environment. Most of the oils are among the mature oils in the study area, except a few samples that are identified as slightly biodegraded by C7 hydrocarbon. Three oil families are identified in DWQ oilfield of Kuqa depression by biomarker analysis and geochemical parameters. The family A shares the attributes with higher amount of tricyclic terpanes, such as C19- C20 tricyclic terpane, higher C24-tercyclic terpane, lower concentration of gammacerane (< 0.6) but poor diasteranes. Family C is characterized with lower content of C19-tricyclic terpane than C20 tricyclic terpane, low C24-tercyclic terpane than C23-tricycli terpane, relative high concentration of gammacerane (> 0.6) but poor diasteranes. The oils of family B are mixed from the two types, showing mixed features of family A and C. The results can shed light for the exploration of the studied area.