Oil Families Research Articles

Geochemical Characteristics of Three Oil Families and Their Possible Source Rocks in the Sub-Sag A of Weixinan Depression, Beibuwan Basin, Offshore South China Sea.

Three oil families from the sub-sag A of the Weixinan Depression are identified by integrated analysis of physical properties, stable carbon isotopes, and gas chromatography–mass spectrometry (GC–MS). Their similarities and differences in relative thermal maturities, depositional environments, and biological sources of organic matter (OM) are investigated. A possible oil–source correlation of this area is established. Group A1 oils, defined as low-maturity oils, are characterized by high density and high viscosity. They contain more terrigenous OM deposited in a freshwater environment with unstratified water columns reflected by a relatively high terrestrial/aquatic ratio and Pr/Ph values, low abundance of C30 4-methlysteranes, and low δ13C values. They are derived from the upper hydrocarbon supply combination. Group A2 oils are characterized by moderate density and viscosity and medium stable carbon isotope values. This group of oils has lower terrestrial/aquatic ratios and Pr/Ph values and a medium concentration of C30 4-methlysteranes and δ13C values, suggesting that the oils are derived from the shales which have more contribution from the algal input and are formed in a weakly oxidizing environment. They are a mixture generated from the source rocks in the middle and lower hydrocarbon supply combination. Groups A3 oils, defined as light oils, have low density and viscosity. The geochemical data of the A3 oils, including a less-negative stable carbon isotope, high abundance of C30 4-methylsteranes, low Pr/Ph values, and highest Ts/(Ts + Tm) ratios (Ts represents C27 18α(H)-22,29,30-trisnorneohopane and Tm represents C27 17α(H)-22,29,30-trisnorhopane), suggest that they are generated from the source rocks deposited in a subanoxic environment with the large input of dinoflagellates. The A3 oils are generated from the shales from the lower hydrocarbon supply combination. The oil–source correlation results can be further supported by the distribution of faults and structural ridge as the migration channel of petroleum developed around the sub-sag A.

Chemometric investigation of oil families and geochemical characterization of crude oils in the Northern Dezful Embayment Zone, SW Iran

Chemometric analysis was performed on 19 crude oil samples from 14 different oil fields to reveal oil families and their distributions in the Northern Dezful Embayment Zone. The geochemical characteristics and candidate source rock(s) of the defined oil families were also investigated in this study. The chemometric classification revealed three different oil families in the studied area. Group I includes Naft Sefid, Ramin, Kupal, Marun, and Aghajari oil fields. Group II comprises Ziloie, Masjid-e Soleyman, Karanj, Haftkel, Balarud, Qale Nar, and Karoun oil fields, and group III contains Azar and Dehluran oil fields. All studied samples were expelled from open marine settings with anoxic conditions, type II kerogen, and marine organic matter inputs. The group I oil fields have C29/C30 > 1, TAR<1, moderate C22/C21 and C24/C23 tricyclic terpanes, an insignificant amount of Oleanane, mid-oil window maturity, and an average carbon isotope of −26.98‰, which were charged from the Kazhdumi source rock. The group II oil family has C29/C30H < 1, moderate C22/C21 tricyclic terpanes, TAR<1, moderate C24/C23 tricyclic terpanes, and a high Oleanane Index (average of 22%), mid-oil window maturity, and average carbon isotope of −25.35‰. These oils were originated from the Pabdeh Formation. The group III samples have C29/C30H > 1, high C22/C21 tricyclic terpanes, TAR<1, low C24/C23 tricyclic terpanes, mid-oil window maturity, and an average carbon isotope of −27.67‰, which were originated from the Garau or Sargelu settings.

Oil Family Typing Using a Hybrid Model of Self-Organizing Maps and Artificial Neural Networks.

Identifying the number of oil families in petroleum basins provides practical and valuable information in petroleum geochemistry studies from exploration to development. Oil family grouping helps us track migration pathways, identify the number of active source rock(s), and examine the reservoir continuity. To date, almost in all oil family typing studies, common statistical methods such as principal component analysis (PCA) and hierarchical clustering analysis (HCA) have been used. However, there is no publication regarding using artificial neural networks (ANNs) for examining the oil families in petroleum basins. Hence, oil family typing requires novel and not overused and common techniques. This paper is the first report of oil family typing using ANNs as robust computational methods. To this end, a self-organization map (SOM) neural network associated with three clustering validity indexes was employed on oil samples belonging to the Iranian part of the Persian Gulf oilfields. For the SOM network, at first, 10 default clusters were selected. Afterward, three effective clustering validity coefficients, namely, Calinski–Harabasz (CH), Silhouette (SH), and Davies–Bouldin (DB), were studied to find the optimum number of clusters. Accordingly, among 10 default clusters, the maximum CH (62) and SH (0.58) were acquired for 4 clusters. Similarly, the lowest DB (0.8) was obtained for four clusters. Thus, all three validation coefficients introduced four clusters as the optimum number of clusters or oil families. According to the geochemical parameters, it can be deduced that the corresponding source rocks of four oil families have been deposited in a marine carbonate depositional environment under dysoxic–anoxic conditions. However, oil families show some differences based on geochemical data. The number of oil families identified in the present report is consistent with those previously reported by other researchers in the same study area. However, the techniques used in the present paper, which have not been implemented so far, can be introduced as more straightforward for clustering purposes in oil family typing than those of common and overused methods of PCA and HCA.

Molecular and isotopic evidence for the origin of light oils and associated gases in the onshore northeast Nile Delta

The Nile Delta is a prolific hydrocarbon province in Egypt and the eastern Mediterranean region, particularly for gas resources. However, the origin of discovered hydrocarbons from the onshore Nile Delta has not been comprehensively studied. Fourteen condensates and 10 natural gas samples retrieved from Oligocene–Pliocene pay zones in the onshore northeast Nile Delta were studied for their molecular and isotopic composition to infer origin, source lithology, organic facies, depositional environment, thermal maturity, and reservoir secondary alteration. The isotopic compositions of the analyzed condensates indicate non-marine waxy oils. Results show that these condensates have high Pr/Ph ratios (1.86–6.46), abundant C19 and C20 tricyclic terpane contents relative to the C23 homologue, elevated oleananes, paucity of gammacerane, high hopane/sterane ratios, very low abundance of homohopanes, low dibenzothiophene/phenanthrene ratios and high C29/C27 sterane ratios. Clay-rich source rocks with abundant Type-III terrigenous organic materials deposited in an oxic fluvio-deltaic setting are suggested for these condensates. Light hydrocarbon (C7) compositions indicate that all investigated condensates, except the Allium-1 sample, suffered evaporative fractionation within their reservoirs. Chemometric analysis based on 14 biomarker and isotopic results suggests 3 genetic oil families for these condensates. These oil families have geochemical characteristics that indicate various contributions of terrigenous and marine organic matter and different levels of thermal maturity. The molecular and isotopic results indicate that the onshore Nile Delta natural gases are wet-thermogenic in origin with no signs of microbial biodegradation. These gases were generated by secondary cracking of associated oils derived from Type-III and Type-II/III or Type-II kerogen. The condensate and associated gas samples from Oligocene pay zones have different geochemical signatures than those from Miocene reservoirs, suggesting derivation from different source rocks with variable levels of thermal maturity or the presence of multiple charge systems from a common source in the onshore Nile Delta.

The Geochemical Study of Oil-Oil and Oil-Source Rock Correlations in the Wushi Sag of the Beibu Gulf Basin, South China Sea

Chemometrics has been widely used to cope with the problems of oil-oil and oil-source correlations because of its unique advantages in the comprehensive consideration of multiple parameters and the classification of samples or variables. In this paper, three chemometric methods, especially multidimensional scaling, were used to revisit the genetic oil family and the relationship between the crude oil and the source rock, because the oil source in the Wushi Sag, a significant petroliferous sag in the Beibu Gulf Basin of South China Sea, is still controversial. Two genetic families of crude oils, namely group A and group B, have been identified based on chemometric results. Group A oils are characterized by relatively higher Pr/Ph ratios and a high abundance of C27 ααα 20R steranes and C30-methylsteranes than those of group B oils, suggesting that this group of oils was deposited under a more oxic condition with more contribution of algae organic matter. Group A oils have been interpreted to be a mixture derived from the member 2 and member 3 of the Liushagang Formation (LS-2 and LS-3), whereas group B oils can be ascribed to the LS-2 member. The contribution of LS-3 mudstone member to the Wushi oils in previous studies may have been underestimated to some extent, which was inferred from the chemometric oil-source correlation results. The results of oil-source rock correlation may be used to guide future petroleum exploration activities with the incorporation of geological evidence. The spatial distribution of oil and gas reservoirs varies with burial depth. Taking into consideration other geological evidence, we may infer that the reservoir in eastern Wushi Sag was mainly distributed in the deep of Liushagang Formation, whereas the reservoir in southeast Wushi Sag was likely located in the shallow Liushagang Formation.

Organic geochemical signatures of source rocks and oil-source correlation in the Papuan Basin, Papua New Guinea

The Papuan Basin is the largest petroliferous basin in Papua New Guinea (PNG), where developed several sets of potential source rocks (SRs). The Jurassic SRs are clay-rich shales, whose organic matter (OM, mainly type Ⅱ 2 -Ⅲ) is predominantly derived from terrestrial higher plants deposited in a more oxic environment with relatively high maturity (0.35% < Ro < 2.03%). The Cretaceous SRs contain mixed inputs of terrigenous and marine OM (type Ⅱ 2 -Ⅲ) formed in sub-oxidized to oxidized depositional conditions with moderate maturity (0.33% < Ro < 1.58%). Whereas the Paleocene-Miocene SRs are predominant marine calcareous shales with subsidiary terrigenous OM inputs. These SRs containing type Ⅲ kerogen are mostly immature (0.21% < Ro < 0.70%). The Papuan Basin oils were classified into three distinct genetic families based on biomarkers and stable carbon isotopes. Family A oils, with heavy carbon isotopes, low Pr/Ph ratios, C 29 /C 27 ααα 20 R sterane <1.0, are likely originated from autochthonic Paleogene-Neogene mature marine OM. Family B oils have the characteristics of high Pr/Ph, moderate carbon isotopes, the dominance of C 29 ααα 20 R sterane, and are predominantly derived from autochthonous Jurassic SRs. Family C oils in the Eastern Papuan Fold Belt (EPFB) can be further subdivided into three subtypes by more subtle differences in specific biomarkers. Type C 1 oils, most likely stemmed from the Lower Cretaceous SRs, are characterized by light stable carbon isotopes, Pr/Ph > 2, the mild dominance of C 29 ααα 20 R sterane and the absence of oleanane ± lupane. Type C 2 oils can be clearly distinguished from Type C 3 by C 19 /(C 19 + C 23 ) tricyclic terpane <0.5, while the latter ones have higher abundances of oleanane ± lupine and diahopanes as well as C 24 tetracyclic/C 23 tricyclic terpane ratios. Type C 2-3 oils are originated from calcareous SRs that deposited in Late Cretaceous or younger age. • The organic geochemical signatures of the Papuan Basin SRs were elaborated. • Biomarkers, stable carbon isotopes, n -alkanes and iso-alkanes were used. • The oil samples in the Papuan Basin can be classified into three genetic families. • The likely origin of diverse oil families in the Papuan Basin were discussed.

Light hydrocarbons and diamondoids in deep oil from Tabei of Tarim Basin: Implications on petroleum alteration and mixing

The Tuofutai Bulge in central Tabei of northern Tarim Basin provides insights into the complex geochemical processes of deep oil accumulations. Fifteen crude oil samples collected from deep Ordovician reservoirs were tested and analyzed with light hydrocarbons (LHs) and diamondoids to evaluate the oil family, secondary alteration, and mixing processes. Results show that the oil samples share similar distribution characteristics of LHs and diamondoids and contain low concentrations of methyldiamantanes, suggesting that they belong to one group and have not been significantly altered by thermal cracking. Geochemistry of LHs and diamondoids indicate that the thermochemical sulfate reduction is limited and negligible, whereas some samples are severely altered by biodegradation. The phase fractionation is mainly related to the leakage of light hydrocarbon caused by geological activities such as tectonic uplift and fault activity, and some samples show weak evaporative fractionation. The biodegradation causes the increase in the values of methyladamantane to adamantane (MAs/A) and the concentrations of (1 + 2)-methyladamantane and (3 + 4)-methyldiamantane. The thermal maturity of oil calculated on the basis of LHs and diamondoids is generally higher than that calculated using saturated and aromatic fractions. The difference of various maturity parameters related to saturated hydrocarbon, aromatic hydrocarbon, LHs and diamondoids records multiple oil charging and mixing processes.

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.

A NEW OIL SEEPAGE IN THE OMAN MOUNTAINS AND ITS GEOLOGICAL, GEOCHEMICAL AND PETROLEUM SYSTEMS CONTEXT

A minor natural oil seepage is described from an unlikely setting in the Oman Mountains. The host rocks are fractured pelagic limestones of the lower member of the Triassic – Lower Jurassic Matbat Formation of the Hamrat Duru Group in the lower part of the allochthonous Hawasina Complex. This paper summarises Oman's established oil families and documents previously recorded oil seepages as context for describing the new seepage, its geochemistry, and possible source rock. The seep oil is different to those known from Oman's oil fields and probably derived from a poor quality, Mesozoic clastic source rock containing a mix of terrigenous and marine organic matter. The most likely source appears to be the Toarcian turbiditic upper member of the Matbat Formation, equivalent to the clastic Mafraq Formation of the Arabian Platform. The occurrence of source rocks in the allochthonous sediments of the NeoTethyan Hawasina Basin has been suspected previously, though their commercial significance remains to be established.

Organic geochemistry, oil-source rock, and oil-oil correlation study in a major oilfield in the Middle East

In this study several major source rocks: Kazhdumi, Pabdeh, and Gurpi formations, along with crude oils from the Asmari and Bangestan reservoirs in the Gachsaran oilfield, southwestern Iran, were investigated from the organic geochemistry point of view. Results indicate that the Kazhdumi and Pabdeh formations have excellent generation potential and are mature and immature source rocks, respectively. In contrast, the Gurpi Formation has lower petroleum generation potential. The organic matter in the Kazhdumi and Pabdeh formations in the neighboring synclines within the Gachsaran oilfield is in the late and peak oil generation stages, respectively. SARA composition by Liquid Chromatography performed on four crude oils produced from these source rocks suggest a paraffinic-naphthenic composition. The source rocks had carbonate and shale lithology. Distinct biomarkers point to an open marine environment characterized by marine kerogen Type II and mixed Types II/III deposited under anoxic-suboxic depositional conditions, although. The presence of relatively high amounts of oleanane in the oils points to contribution from a terrigenous source. Based on biomarkers, the four oils exhibit similar thermal maturity, which is equivalent to the primary stage of oil generation. The star diagrams of various normal alkanes and biomarker ratios show that the four crude oil have high similarities, which suggests a single source origin. Nonetheless, utilizing different ML methods of K-means Clustering, Fuzzy C-means clustering (FCM), Comptlayar Neural Network, Construction of agglomerative clusters, and the obtained dendrogram all suggest that there are two oil families in the Gachsaran oil field. Furthermore, geochemical parameters including specific biomarkers denote the contribution of the Kazhdumi and Pabdeh formations in the Gachsaran oil field whereby charges of mixed origins at different reservoir horizons of Asmari and Bangestan can be identified. Ultimately, two scenarios for the presence of oleanane in Bangestan reservoir are envisaged: 1) connectivity of the Asmari and Bangestan reservoirs as a result of natural fracturing, and 2) emplacement of the Pabdeh Formation near the vicinity of the Bangestan reservoir as a result of thrust faulting. Overall, this study demonstrated that integration of data analytics (ML) methods with conventional geochemical techniques can precisely delineate the correlation between the generated oil and the source rocks. • Geochemical analysis performed on two rarely studied major source rocks in Middle East: kazhdumi and Pabdeh Formations. • Several machine learning (ML) algorithms were implemented to identify existing oil families from these two source rocks. • These two oil families were also confirmed by detection of the Oleanane biomarker in separated oil groups.

The origins of biodegraded oils in sandstone reservoirs in the Termit Basin

Systematic geochemical analysis of 39 crude oils from the Termit Basin, Niger, all belonging to the same oil family, reveals distinct differences in bulk properties and molecular compositions, which were undoubtedly caused by differences in the extent of biodegradation. Various degrees of microbial alteration were identified in crude oils, which were classified as non-, slightly, moderately, or heavily degraded oils, according to their physical properties, bulk chemical compositions, and certain molecular biomarker characteristics. Examination of the possible origins and geological backgrounds of the biodegraded oils shows that reservoirs with deeper burial depths (greater than 1800 m), thicker caprocks (>100 m), relatively higher stratigraphic temperatures (>80 °C), and which have been subject to the influence of silent faults had not suffered significant biodegradation. The burial depth of reservoirs is therefore considered to be the main factor controlling the biodegradation process, and may offset other factors if the depth is sufficient. The Paleogene reservoirs in the Dinga Step-Fault Zone (DSFZ) that meet all of these conditions are therefore dominated by normal oils. Degraded oils of varying degrees are widely distributed in other tectonic units where at least one of these factors is absent. This study may have practical application for further petroleum exploration, prediction of petroleum properties, and the reduction of production risk. • Oils in the Termit Basin were subjected different extent of biodegradation. • 1800 m is the safety burial depth threshold for biodegradation in the Termit Basin. • Biodegraded oil was also affected by the activity Paleogene faults systems. • The seal rock >100 m in thickness is beneficial to oil quality stabilization.

Chemometric Classification of Oil Families in the Laizhouwan Depression, Bohai Bay Basin, Eastern China.

A suite of oil-sand bitumen and crude oil samples, collected from the Laizhouwan depression, Bohai Bay basin, were geochemically investigated for molecular compositions. Three oil families (A, B, and C) were classified by hierarchical cluster analysis (HCA) and principal component analysis on nine typical biomarker ratios. Typically, family A oils are characterized by relatively low values of gammacerane/C31 homohopane 22R (G/H31, 0.13–0.76) and C35/C34 homohopane (H35/H34, 0.39–0.78), suggesting a source from freshwater depositional environments. In contrast, family C oils show a relatively high G/H31 (2.49–5.41) and H35/H34 (1.43–2.45) ratios, indicating a source from hypersaline water depositional environments. Family B oils display ratios of G/H31 and H35/H34 in-between the range of families A and C, suggesting mixed origin. In addition, family A oils can be further classified into four subfamilies (A1, A2, A3, and A4) and family B oils into two subfamilies (B1 and B2) by HCA. The A1 oils characterized by a high C24 tetracyclic terpane/C26 tricyclic terpane (TeT24/TT26) ratio (1.02–1.39) are mainly distributed in the northeast, B1 oils characterized by relatively low TeT24/TT26 ratio are in the west, and A2, A3, and A4 oils with an intermediate TeT24/TT26 ratio are in the center of the depression. Oils in well L16-1-2 in the southern depression, however, show vertical variations with family C oils in the deeper reservoirs, subfamily B2 oils in the shallower reservoirs, and subfamily A4 oils in the middle-depth reservoirs. Based on the biomarker compositions, at least three oil charges were indicated: family C oils are likely sourced from the Es4 rock in the southern sag, B2 oils may be a mixture of family C with family A oils, and A4 oils without biodegradation influence may be the latest charge derived from the Es3 source rock in the northern sag. The oil families and/or subfamilies with typical genetic affinities, as well as the regular occurrence in different blocks, may indicate two major petroleum systems or multiple subsidiary oil systems existing in the Laizhouwan depression.

Organic geochemical heterogeneity of the Cretaceous Abu Gabra Formation and reassessment of oil sources in the Sufyan sub-basin, Sudan

The Lower Cretaceous Abu Gabra Formation (AG) is considered to contain the major source rocks in the Sufyan sub-basin, Sudan. Although prior studies have established the presence of organic-rich lacustrine mudstones, the geochemical heterogeneity of organic facies, thermal maturity, and molecular nature of individual members of the Abu Gabra Formation are insufficiently characterized for oil-source rock correlation. Here, we report on geochemical analysis of 228 cutting samples utilizing Rock-Eval pyrolysis and TOC measurements, from which twenty samples were chosen for investigation of saturated biomarkers. The well cutting samples are from four members (AG1, AG12, AG22 and AG3) comprising the Abu Gabra Formation. These analyses were compared to eleven oils produced from the Abu Gabra sandstones to establish member-specific oil-source correlation. The AG22 and AG3 members have the greatest source potential, containing a higher content of oil-prone organic matter and more favorable maturity than those of the AG12 and AG1 members. Biomarker data for the AG22 and AG3 source rocks indicate that deposition occurred under a moderately stratified and somewhat saline water column with a predominance of algal/bacterial input (Type I kerogen). The AG22 and AG3 source rocks have entered the window of oil generation. In contrast, the AG1 and AG12 source rocks were possibly deposited in fresh to slightly saline water conditions, have a greater input of terrigenous organic matter input, and are immature to marginally mature. Oil-oil and oil-source rock correlations suggest that the crude oils in the Sufyan sub-basin are genetically homogenous, belong to a single oil family, and are mainly derived from the AG22 and AG3 source rocks. Contribution from the AG1 and AG12 source rocks is not apparent from the molecular distributions and is considered to be negligible. The current study provides valuable guidance of source rock evaluation and oil-source rock correlation, which can be a benefit to future petroleum exploration work in the Sufyan sub-basin.

The characterisation and provenance of crude oils stranded on the South Australian coastline. Part II: Potential parent petroleum systems

In 2014–2016 more than 600 specimens of semi-solid crude oil were recovered from 30 ocean beaches along the coastline of South Australia, as part of the recently completed Great Australian Bight Research Program. All are believed to be products of submarine oil seepage. Their source-specific biomarker signatures provide the basis for their assignment to sixteen oil families, some previously unrecognised. Two of these families (asphaltite and asphaltic tar) likely originated from Cretaceous marine source rocks in the offshore Bight Basin. The others comprise waxy oils of lacustrine, fluvio-deltaic and marine source affinity. Their biomarker characteristics do not match those of any Australian crude oil. However, they are strikingly similar to those of oils found in Cenozoic and Mesozoic basins throughout the Indonesian Archipelago and elsewhere in Southeast Asia.

GEOCHEMISTRY OF OILS IN THE TEREK‐CASPIAN FOREDEEP AND PRIKUMSK SWELL, NE GREATER CAUCASUS, SOUTHERN RUSSIA

Hydrocarbon reserves of the order of 1140 MM brl oe have been identified in the northern foreland of the eastern Greater Caucasus, principally in the Terek‐Caspian fold‐and‐thrust belt and the Prikumsk Swell in the north of the Terek‐Caspian foredeep. Despite the great economic significance of these areas and their long exploration history, the origin of the hydrocarbons is still poorly understood. In the present paper, geochemical data from 73 oil samples representing 28 fields are used to investigate the presence of oil families and to correlate the oils with potential source rocks.Biomarker composition of oils in Cretaceous and Miocene reservoirs in the Terek‐Caspian fold‐and‐thrust belt is mainly controlled by reservoir depth (100‐5700 m) and maturity (0.70‐1.15 %Ro), and it is therefore difficult to separate maturity and facies effects. For example, a downward increase in diasterane/sterane ratios may indicate a change in source rock facies or may be attributed to increasing maturity. Some shallow oils are biodegraded. The presence of short‐chain n‐alkanes in biodegraded oils indicates recent hydrocarbon migration. Biomarker data (e.g. the presence of oleanane) and compound‐specific isotope data suggest that the Khadum Formation in the lower part of the Maikop Group is the main source rock. However data from Cretaceous and Paleogene organic‐rich rocks, which may also have contributed to the accumulated oils, are urgently needed in order to quantify their possible input.In the Prikumsk Swell, at least two oil families, characterized by low and high C28/C29 sterane ratios respectively, can be distinguished in reservoir rocks of Triassic to Cretaceous age. Most oils are characterized by low C28/C29 sterane ratios and the absence of oleanane (“Group B oils”). These characteristics suggest a pre‐Upper Cretaceous source for the oils, which is also supported by the geological setting. Hierarchical cluster analysis suggests the presence of four sub‐groups (Sub‐Groups B1 to B4). Typically, biomarker ratios in oils in Cretaceous reservoirs are more uniform than those in Triassic and Jurassic reservoirs. Potential source rocks include Lower Triassic deep‐water clayey limestones and shales as well as Middle Jurassic and Aptian‐Albian marine shales. Three oil samples from Triassic and Cretaceous reservoirs form a separate oil family (“Group A”), which is genetically related to oils from the Terek‐Caspian fold‐and‐thrust belt. Group A oils have high C28/C29 sterane ratios and in general contain at least some oleanane. A contribution by Cenozoic source rocks to Group A oils is likely.

Application of biomarkers and oil fingerprinting for genetic classification of oil families and prediction of oil migration pathways in Nuraly field

This paper presents the interpretation of the results of biomarker analysis and oil fingerprinting of all producing wells (36 samples) of Nuraly field for genetic typing and fluid communication assessment within the field, followed by predicting the hydrocarbon migration pathways. According to the biomarker study, it was revealed that the oils of central and western Nuraly have genetically different origins, and the petroleum accumulation in the southern part of West Nuraly was formed by the continuous secondary migration of HC from the northeastern and northwestern directions. Oils from central Nuraly field have higher thermal maturity and lower density than those of western Nuraly do. The thermal maturity of samples from Central Nuraly decreases from the northeastern part of Nuraly towards the southwestern part, which may also attest to hydrocarbon migration pathways. The presence of gas caps in the northeastern part of Central Nuraly may be due to their high thermal maturity.

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.

Geochemical significance of β-carotane in lacustrine oils from the Shahejie Formation of the Dongying Depression, eastern China

Oils reservoired in the third (Es3) and fourth (Es4) members of the lacustrine Shahejie Formation from the Dongying Depression, Bohai Bay Basin, eastern China have been analyzed by gas chromatography–mass spectrometry. Two oil families have been classified by the data assessed using chemometric analysis, including hierarchical cluster and principal component analysis. The Family I oils from the Es4 reservoirs were mainly generated from source rocks of the Es4 Member whereas Family II oils in the Es3 and Es4 reservoirs have source input mainly from the Es3 Member inferred from a series of biomarkers, including β-carotane, phytane, gammacerane and their deried abundance ratios. Parameters derived from β-carotane, such as the ratios: β-carotane/C24 tetracyclic terpane, β-carotane/(C19 + C20) tricyclic terpanes, and β-carotane/(18α(H)-22,29,30-trisnorneohopane + 17α(H)-22,29,30-trisnorhopane), are most useful for distinguishing the oils derived from different depositional environments. β-Carotane has a high resistance to biodegradation to at least PM level 5. The abnormally high concentration of β-carotane in a few severely biodegraded oils is attributed to the removal of most vulnerable components by biodegradation, resulting in relatively concentrated β-carotane.

Geochemical advances in Arctic Alaska oil typing – North Slope oil correlation and charge history

The Arctic Alaska petroleum province is geologically and geochemically complex. Mixed hydrocarbon charge from multiple source rocks and/or levels of thermal maturity is common within an individual oil pool. Biomarker and chemometric statistical analyses were used to correlate twenty-nine oils to five oil families derived from: (1) Triassic Shublik Formation (calcareous organofacies), (2) Triassic Shublik Formation (shaly organofacies), (3) Jurassic Kingak Shale, (4) Cretaceous shale (pebble shale unit and Hue Shale), and (5) Paleogene shale (Canning Formation). Age-diagnostic and source-related oil biomarker parameters establish clear genetic relationships between the normal oil-window components and their putative source designations. However, application of diamondoid analyses reveals mixed-oil accumulations with postmature charge contributions (diamondoid-rich and biomarker-poor) in many oils.Most sampled reservoirs contain a predominant charge derived from a single oil-window source plus a minor contribution from one or more higher maturity source(s). Variations in source organofacies also are recognized in the Shublik, Kingak, and Cretaceous oil families. In some cases, oils from multiple pools within a single field display relatively homogeneous geochemical profiles, suggesting a common source and migration pathway. For example, oil from the significant Pikka discovery is inferred to originate mainly from the calcareous Shublik Formation. In other cases, variability among oils from multiple pools within a single field (e.g., Milne Point, Colville River, and Northstar) likely indicates a more complex source, migration, and charge history. Results may be useful for anticipating the composition of oil charge in stratigraphic traps with low-permeability sandstone reservoirs, where oil gravity and other chemical parameters may influence economic viability.

Advances in sediment geochemistry and chemostratigraphy for reservoir characterization

Sedimentary sequences preserve the records of changes in major controls of sedimentation namely, tectonics, climate, relative sea level and sediment production and preservation. The potential to characterize these changes in spatial and temporal scales has led to the development of the branch of chemostratigraphy. Chemostratigraphic study of sedimentary sequences commenced from recognizing identical/contrasting geochemical features across major geochronological boundaries, and evolved into one of the essential tools in exploration, characterization, and well development strategies. Chemostratigraphy incorporates applications on continuous, real-time geochemical mapping and direction of lateral drilling, and machine learning, among others. As the sedimentary systems operate on a variety of temporal scales that range from few hours (tidal cycles) to few tens of millions of years, within which many perturbations such as catastrophic and diagenetic events take place, that lead to unique geochemical signature which can be correlated at appropriate spatial and temporal scales. The application of chemostratigraphic technique in hydrocarbon exploration and reservoir characterization has gained momentum in recent years, particularly with the advent of developments in analytical instrumentation. This has also led to the integration of a variety of data from field sedimentary structures, mineralogy, major, trace and isotopic chemical compositions of whole rock, selected components of rocks, organic and inorganic components of oil and gas, etc., for reservoir characterization more accurately than ever. The geochemical fingerprinting of oil and gas reservoir components plays a major role in the identification of source rocks, discrimination of oil families, characterization of reservoir, source, and seal segments in petroleum systems. Future trends indicate the relevance and growing applications of machine learning techniques, artificial intelligence in real-time assessment, monitoring and planning of hydrocarbon exploration and production.