Carbonate Source Rocks Research Articles

Evidence for mixed and biodegraded crude oils in the Socororo field, Eastern Venezuela Basin

This work presents a geochemical study of crude oils from the Socororo field (Socororo Major Area) in the Maturín Sub-basin of the Eastern Venezuelan Basin. The V+Ni total concentrations and V/(V+Ni) ratios suggest the presence of two oil groups. These oils are heavy aromatic–asphaltic and according to their sulfur content, API gravity and hydrocarbon compositions, fall into the same two groups established from the V and Ni proxies. Although the analyzed crude oils show evidence of biodegradation, it was possible to determine, based on various biomarkers parameters, that the oils originated from marine organic matter in a marine carbonate or marine marl source rock deposited under anoxic to suboxic conditions. The oils were generated near the peak of the oil window. Distributions of n-alkanes, isoprenoids, hopanes and steranes combined with a prominent unresolved complex mixture (UCM) indicate that the oils are biodegraded. Moreover, the presence of pristane and phytane, along with alteration of hopanes and steranes and the presence of 25-norhopanes, reveals that these oils are mixtures showing different levels of biodegradation. Sulfur content, V and Ni concentration and saturate, aromatic, resin and asphaltene (SARA) composition provide additional evidence for oil mixing. Such mixed oils originate from several episodes of charging and biodegradation in the reservoirs. The first charge was severely biodegraded and many biomarkers susceptible to degradation (n-alkanes, acyclic isoprenoids, terpanes, methyl hopanes, methyl steranes and steranes) were extensively altered or completely removed. The second oil charge was subjected to a lower degree of biodegradation and only the n-alkanes show significant biodegradation. Both oil charges seem to come from the same source rock, which was deposited under variable redox conditions. Moreover, due to their similar maturity, the generation and migration of these oils to reservoirs likely occurred close together in time.

Hydrocarbon potential, thermal maturation of the Jurassic sequences, and the genetic implication for the oil seeps in North Thrust Zone, North Iraq

The organic geochemistry is studied for the rocks of three Jurassic formations: Sargelu, Naokelekan, and Chia Gara from the north of Iraq. These rocks comprise bituminous carbonate and shale rocks. The hydrocarbon source rock potential is evaluated by using total organic carbon (TOC) and Rock-Eval Pyrolysis. The prevalence of high values of TOC (2.21–45.12 wt.%) associated with moderate to high values of HI (225–550 mg HC/g TOC), low OI (1–33 CO2/g TOC), and high S2 values (4.53–181.0) indicate very good to excellent source rock potential for these rocks with mostly type II kerogen and few mixed-type II/III kerogen of oil prone source rocks. This is supported by high values of S2/S3 ratios (>5). Tmax values range from 440 to 447 °C in agreement with the calculated R o values (0.76–0.90) infer early to peak thermally mature stage. Based on the TOC and pyrolysis data, the rocks of the three formations have indigenous hydrocarbon mature oil prone. The geochemical investigation of biomarker parameters were performed for oil samples from two oil seepages (Banik and Tawke) which are located in the same area using gas chromatography-mass spectrometry and stable carbon isotope measurements. The measured values of Pr/n-C17 for oil samples are low coupled with high values of Ph/n-C18 indicating marine organic matters with type II kerogen accumulated under marine reducing condition. The values and plots of δ13C (saturate and aromatic) also approve the prevalence of marine reducing condition. The source rocks for the oils of both seepages are interpreted to be carbonate rocks of Mesozoic age by the measured CV values which are 0.25. All these data are in consistent with marine carbonate source rocks for these oils. The paleoredox depositional environment for the source rocks is interpreted by the low value of Pr/Ph (0.74 in Banik) and high values of homohopane ratio C35S/C34S (1.21 in Banik and 1.13 in Tawke); the values of C29/C30 (norhopane/hopane >1) as well as the high sulfur content all indicate reducing condition during the deposition of the marine source rocks. The concentrations of C27, C28, and C29 reflect the prevalence of marine algal plankton organic matters. The measured Oleanane index equal zero which indicates age older than Lower Cretaceous for the source rocks. This documented by the calculated values of C28/C29 sterane ratio, and plots on Geomark Research database gives an age of Middle–Upper Jurassic for the source rocks. According to the characteristics of depositional environment of the source rocks, the paleoredox condition, and age estimation, the oils of Banik and Tawke could be derived from the rocks of Sargelu, Naokelekan, and Chia Gara Formations.

Novel applications of fluid inclusions and isotope geochemistry in unravelling the genesis of fossil travertine systems

AbstractThe Denizli Basin is a fault‐bounded Neogene–Quaternary depression located in the Western Anatolian Extensional Province, Western Turkey. The basin is a unique geological site with abundant active and fossil (Quaternary) travertine and tufa deposits. Fluid inclusion microthermometry and isotopic analysis were applied to study the genesis of the Ballık fossil travertine deposits, located in the south‐eastern part of the basin. Microthermometry on fluid inclusions indicates that the main travertine precipitating and cementing fluids are characterized by low salinity (<0·7 wt% NaCl equivalent) and variable temperatures that cluster at <50°C and ca 100°C. Fluids of meteoric origin have been heated by migration to the deeper subsurface, possibly in a local high geothermal gradient setting. A later uncommon cementation phase is related to a fluid with a significantly higher salinity (25·5 to 26·0 wt% bulk). The fluid obtained its salinity by interaction with Late Triassic evaporite layers. Strontium isotopes indicate that the parent carbonate source rock of the different travertine precipitates is very likely to be the Triassic limestone of the Lycian Nappes. Carbon isotopes suggest that the parent CO2 gas originated from thermal decarbonation of the Lycian limestones with minor contributions of magmatic degassing and organic soil CO2. Oxygen isotopes confirm the meteoric origin of the fluids and indicate disequilibrium precipitation because of evaporation and degassing. Results were integrated within the available geological data of the Denizli Basin in a generalized travertine precipitation model, which enhanced the understanding of fossil travertine systems. The study highlights the novel application of fluid inclusion research in unravelling the genesis of continental carbonates and provides several recommendations for hydrocarbon exploration in travertine‐bearing sedimentary basins. The findings suggest that travertine bodies and their parent carbonate source rocks have the potential to constitute interesting subsurface hydrocarbon reservoirs.

Pregnanes as molecular indicators for depositional environments of sediments and petroleum source rocks

Steroids with unconventional side chains have increasingly been applied as diagnostic markers for geological source and age assessments. However, one of the most distinctive characteristics, the abnormal abundance of pregnane and homopregnane in ancient sediments and petroleum, remains unresolved. Higher pregnane and homopregnane, as well as C23–C26 20-n-alkylpregnanes, relative to the regular steranes were observed in samples collected from different petroleum basins in China. These included Precambrian marine carbonate-derived petroleum (NW Sichuan Basin), Lower Paleozoic marine marl derived crude oils (Tarim Basin), and Eocene hypersaline lacustrine carbonate source rocks and associated petroleum (Bohai Bay Basin). However, all of the samples have many common biomarker characteristics, such as pristane/phytane ratios<1, low amounts of diasteranes and high C29/C30 hopane (∼0.6–1), C35/C34 hopane (mostly⩾1) and dibenzothiophene/phenanthrene (DBT/PHEN, mostly 0.5–1) ratios revealing a contribution from anoxic carbonate/marl source rocks deposited in restricted, clastic-starved settings. We suggest that 5α,l4β,l7β-pregnane and homopregnane, as well as their higher C23–C26 homologues, are geological products derived from steroids bound to the kerogen by a sulfurized side chain. Carbon or carbonate minerals are considered to be natural catalysts for this cracking reaction via preferential cleavage of the bond between C-20 and C-22. Similar distributions occur in the short chain analogues of 4-methylsterane, triaromatic steroid and methyltriaromatic steroid hydrocarbons, providing circumstantial evidence for this proposal. The ratio of pregnane and homopregnane to the total regular steranes and the ratio of C27 diasteranes to cholestanes can be sensitive indicators of sedimentary environments and facies. In general, high diasteranes and low pregnanes (with homologues) indicate an oxic water column or significant input of terrigenous organic matter in clay rich source rocks and some organic lean carbonate rocks. Low diasteranes with high pregnanes implies restricted, sulfur rich conditions, typical of anoxic carbonate source rocks. Furthermore, the two ratios may be useful to assess the variation of mineralogy and openness of source rock depositional settings.

Organic geochemistry of Carboniferous source rocks and their generated oils from the Eastern Junggar Basin, NW China

Carboniferous source rocks have been gaining increasing attention after the discovery of the Kelameili gasfield in the Eastern Junggar Basin in 2005. Two sets of source rocks within the Lower Carboniferous Dishuiquan Formation (C1d) and Upper Carboniferous Batamayineishan Formation (C2b), respectively, have been identified in this area. In this paper, clear differences between these two source rocks are demonstrated in molecular and carbon isotopic compositions. The C1d source rocks, in comparison with the C2b source rocks, have remarkably lower Pr/n-C17 ratio, higher Ts/(Ts+Tm) and C30 diahopane/(C30 diahopane+C30 hopane) ratios, lower concentration of C24 tetracyclic terpane relative to C23 and C26 tricyclic terpanes and higher gammacerane/C31 hopane ratio. δ13C values of individual n-alkanes decrease with carbon number for C1d source rocks while the opposite is true for C2b source rocks.Among the 10 oils collected from the studied area, four were generated exclusively from C1d source rocks while the others were mainly derived from C1d source rocks but contaminated by a small or trace amount of oil components which were derived from the C2b, Middle Permian Pingdiquan Formation (P2p) and Lower Jurassic source rocks.The free, adsorbed and inclusion oils from three oil-containing volcanic reservoir rocks within the C2b formation generally correlate with C1d source rocks based on molecular and carbon isotopic data. However, the three types of oil from the same reservoir rock vary significantly in molecular and carbon isotopic compositions, reflecting facies and maturity changes of charging oil during the reservoir filling.

Selenium and tellurium enrichment in palaeo-oil reservoirs

The exploration for selenium (Se) and tellurium (Te) will become intensified as the technological demand for these elements grows. It is known that they are enriched in organic-rich sedimentary rocks over crustal mean values. LA-ICP-MS measurement of pyrite in two biodegraded palaeo-oil reservoirs in central England shows that Se and Te are enriched in them, but not in other sulfide samples from the region and elsewhere. The Carboniferous source rock shales in the region are Se-rich, implying that this enrichment was conferred to the oil generated from them. The Se and Te are located in pyrite precipitated in the palaeo-reservoirs by microbial activity. Exhumed oil reservoirs merit further investigation for concentrations of these elements.

A thermogenic hydrocarbon seep in shallow Adriatic Sea (Italy): Gas origin, sediment contamination and benthic foraminifera

Gaseous and liquid hydrocarbons are seeping from sandy sea bottom ∼10 m deep, about 2.4 km NNE of Civitanova Marche harbour, in central Adriatic Sea (Italy). We investigated the origin of the gas, the presence of a wide range of aromatic and aliphatic hydrocarbons and trace metals in shallow sediments, as well as the stable carbon and oxygen isotope composition of benthic foraminifera. In absence of detailed seismic images and subsurface geochemical data, we tried to estimate the source rock type and maturity based only on seep gas geochemistry. Molecular and isotopic composition of gas bubbles showed that the CH4-rich gas is thermogenic (δ13CCH4∼ −55‰; δ2HCH4∼ −280‰; C1/(C2 + C3) < 100) with isotopic features that are compatible with low maturity source rocks belonging to the Emma-Scaglia (carbonate source rocks) Petroleum System (Upper Trias to Paleocene). Gas could then be stored in a biodegraded hydrocarbon pool, as suggested by 13C enrichment in propane (δ13C3: −24‰) and CO2 (δ13CCO2: +12‰). Fluid seepage might be due to a local fracture zone corresponding to the intersection of NNW–SSE thrust faults with a NE–SW regional transversal deformation belt. Compared to other shallow marine seeps in Europe, the amount of methane released into the atmosphere is negligible (102–103 kg of CH4 per year); but the seep also releases ethane and propane (103–104 L per year), which are photochemical pollutants and are not emitted by microbial gas seeps. Compared to a reference site one nautical mile far from the seep, the seabed sediments show higher concentrations of various classes of chemicals, such as benzene, toluene and ethylbenzene, semivolatile and non volatile aliphatic hydrocarbons (C10–C40), and phenols (2-methylphenol and 2,4-dichlorophenol). These compounds likely derive from the oil seepage. The sediments at the seepage site and those at the reference site have similar concentrations of trace metals (arsenic, barium, cadmium, chromium, copper, iron, manganese, nickel, lead, vanadium, zinc, mercury), typical of uncontaminated and shallow coastal areas. Finally, we provided the first data on foraminifera associated to thermogenic hydrocarbons. No endemic foraminifera species or authigenic carbonates occur in the sediments. Carbon isotopic composition of Quinqueloculina padana where oil slick prevails is less variable than in the gas bubbling site. However, thermogenic methane and oil do not apparently decrease the δ13C value of foraminifera carbonate shell.

Discovery of Carboniferous Oil Seepage in Qaidam Basin and Its Geological Significance

In this work, the oil seepage was found in calcite veins in Keluke formation of upper Carboniferous reservoirs. Based on the analysis of geochemical characteristics, the isomerization parameter of C29 sterane 20S/(20S + 20R) was obtained as 0.39 and Ts/Tm value as 1.12, indicating that the oil seepage was mature. The Pr/Ph value was 0.64 and the tricyclic terpane was characterized by high abundance of gamacerane, C27 > C29 sterane, and a normal distribution with C23 as the dominant peak. Moreover, the oil/oil and oil/source rock correlation of oil seepage and carboniferous source rock underground and surface indicated that the oil seepage was similar to crude in Mabei-2 well (1463 m) and Sin-3 well (1076 m) but was different from the other crude in north Qaidam basin. It is inferred that the oil seepage was authigenic crude in Carboniferous, and Carboniferous source rocks have contributed to the oils in Mabei-2 well (1463 m) and Sin-3 well (1076 m). This study offers new scientific evidence for the exploring of carboniferous in Qiandam basin.

Upper limit of maturity for hydrocarbon generation in carbonate source rocks in the Tarim Basin Platform, China

The upper limit of maturity for hydrocarbon generation (ULMHG) is represented by vitrinite reflectance (VR) that corresponds to the point at which the amount of further hydrocarbon generation is less than 1 % of the total hydrocarbon generation. Six methods were employed to study the ULMHG of the Cambrian and Ordovician carbonate source rocks in the Tarim Basin Platform (TBP), based on the mechanism of hydrocarbon generation, retention, and expulsion. These methods are reduction in atomic ratio for organic elements, variation in hydrocarbon generation potential, optimum simulation of organic materials based on material balance principle, thermal simulation experiment, variation in hydrocarbon retention amount, and variation in hydrocarbon expulsion amount. Studies showed that, although there are some differences between the results obtained using different methods, these differences are small. The ULMHG in the TBP varies from 4.10 to 4.84 % with an average value of 4.55 %, which is in good agreement with the characteristics of hydrocarbon generation under actual geological conditions. The VR of the Cambrian and Ordovician carbonate source rocks in the Tazhong uplift, the Bachu uplift, and the Tabei uplift ranges from 0.64 to 2.34 %, indicating that these areas have not reached the ULMHG. The VR in the Tadong area is very close to the ULMHG, and the VR of most source rocks in the Manjiaer sag has exceeded the ULMHG. In summary, the carbonate source rocks in the TBP have generated large amounts of hydrocarbons and still have high hydrocarbon generation potential to form large-scale oil and gas reservoirs, indicating good hydrocarbon exploration prospects in the deep parts of the TBP. Therefore, the study of ULMHG of carbonate source rocks is of great significance for evaluating the oil and gas resource potential and predicting favorable exploration areas in deep or carbonate rock formations.

Genesis of tight sand gas in the Ordos Basin, China

Based on molecular and stable carbon isotope composition of a large collection of gas samples and integrated with the geological context, this article discusses the genesis and migrational characteristics of natural gases from the giant tight sand gas fields of the Upper Paleozoic strata, Ordos Basin (UPOB). Our results show that the UPOB gas is mostly derived from coaly source rocks, with a minor contribution of oil-associated gas probably from the interbedded carbonate source rocks. Gas isotope data suggest that the Yulin–Zizhou gas field was likely formed from a single gas charge with no significant alteration, whereas the Sulige field contains a mixture of gases from successive charges with multiple maturity levels. The geographical variation in the observed gas composition is attributed primarily to the effect of source rock maturity, with no explicit geochemical fractionation caused by long distance lateral migration.

Prospect of Ultra-Deep Petroleum Onshore China

A series of breakthroughs have been achieved in the exploration of ultra-deep formations onshore China as geological understanding and technologies progress, such as Tarim Basin, Sichuan Basin, Bohai Bay Basin. Some new understandings are put forward suggesting that ultra-deep petroleum potential should be beyond expectation: hydrocarbons are controlled by rift valleys in the pre-Cambrian in China, conventional marine carbonate hydrocarbon source kitchens and scattered liquid hydrocarbons in source rocks are cracked to provide a large scale of gas, clastics in ultra-deep formations develop excellent source rocks, the low limit of gas generation is extended and the upper temperature limit for ultra-deep oil cracking without catalysis is beyond 230°C, the low pore radius limit is different for different types of reservoirs and hydrocarbon accumulating mechanisms. The preservation of three types of carbonate karst reservoirs and three types of clastic reservoirs as well as the physical properties of volcanics are slightly affected by burial depth, and it is predicted that favorable reservoirs are widely spread in ultra-deep formations. Carbonate karst, source rock and clastic reservoir interbeds are associated effectively in large ancient uplifts and slopes close to source rocks, faults control hydrocarbons and volcanics form accumulations nearby sources. This decides that ultra-deep carbonates, clastics and volcanics can all form large accumulations, but the abundance of reserve is relatively low. In Chinese ultra-deep formations, there are remaining petroleum resources of 162.9×108t, gas of 16.3×1012m3, nine practical exploratory areas, 14 relay exploratory areas, and a great potential of exploration. In future, ultra-deep carbonates are an important relay area for oil and gas, ultra-deep clastics are secondarily important, and ultra-deep volcanics are and important area for further study.

The Mishrif, Yamama, and Nahr Umr reservoirs petroleum system analysis, Nasiriya oilfield, Southern Iraq

Forty rock samples were taken from cores and cuttings, and five oil samples were taken from Mishrif, Nahr Umr, and Yamama formations in the Nasiriya oilfield wells, of longitudinal, asymmetrical anticline structure, of about 34 km length and 13 km width located at the unstable plat form, Mesopotamian basin zone. Three major oil reservoirs in the Nasiriya oilfield: (1) Late Cenomanian–Early Turonian Mishrif Formation with reserved oil approximately 1,009 million tons show measured porosities up to 40 % and the oils are aromatic, medium gravity, high sulfur content, and interpreted as being sourced from: type II/III carbonate rocks interbedded and deposited in a reducing marine environment with high salinity based on biomarkers and isotopic analysis; Middle–Upper Jurassic age is based on sterane ratios analysis of isoprenoids and isotopes, and thermally mature source rocks. (2) The reservoirs of the Albian Nahr Umr of approximately 68 million tons reserved oil show measured porosities up to 23 %. (3) Late Berriasian–Early Valanginian Yamama formations of 275 million tons reserved oil measured porosities up to 28.8 %. The Nahr Umr and Yamama reservoirs oils are saturated, light to medium API gravity, low to medium sulfur content which are usually derived from marine shale and carbonate source rocks (containing type II kerogen). The upper seal is the Middle Miocene anhydrites of the Lower Fars Formation and the lower regional seal is Upper Jurassic Gotnia anhydrites. Source rock geochemical analysis suggests for all Cretaceous source rocks samples, immature to mature, and shows that the Sulaiy and Yamama formations to be of good quality source rock with high total organic carbon (up to 8 wt% TOC). The Lower Cretaceous source rocks were deposited in a suboxic–anoxic basin and show good hydrogen indices, and are likely to have charged the reservoirs with low amounts of hydrocarbons, during the Miocene. The most likely source rock for the Mishrif-, Yamama-, and Nahr Umr-reservoired oils are the Middle–Upper Jurassic source rock. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching highly permeable reservoirs of the reservoir formations. Structural traps in the Mishrif, Nahr Umr, and Yamama formation reservoirs are likely to have formed in the Late Cretaceous.

Biomarker characteristics of certain crude oils and the oil-source rock correlation for the Kurdistan oilfields, Northern Iraq

The study herein analysed crude oil and source rock samples from Kurdistan oilfields, northern Iraq using various biomarker ratios. Biomarker characteristics are used to provide information on source organic matter input, depositional environment and the correlation between crude oils and Chia Gara source rocks. The relevant data include normal alkane and acyclic isoprenoids distributions, terpane and sterane aliphatic biomarkers and distribution of the aromatic biomarkers naphthalenes, phenanthrenes, dibenzothiophene and methyldibenzothiophenes. The Kurdistan’s oils characterized by low Pr/Ph ratio (<1.0), a relatively high C35 homohopane index, high C27 regular steranes abundance, the presence of tricyclic terpanes and relatively high dibenzothiophene/phenanthrene ratios. These data indicated that the oils were derived from a carbonate source rock contain a mixture of aquatic (algal and bacterial) organic matter with a minor terrigenous organic matter contribution that were deposited in a marine environment under highly reducing conditions and generated at low maturity. The biomarker characteristics also suggest that the oils were derived from the Upper Jurassic–Early Cretaceous age Chia Gara carbonates.

Geochemical studies of the Silurian oil reservoir in the Well Shun-9 prospect area, Tarim Basin, NW China

Commercial oil flow has been obtained from the sandstone reservoir of the Lower Silurian Kelpintag Formation in the Well Shun-9 prospect area. In the present studies, 10 Silurian oil and oil sand samples from six wells in the area were analyzed for their molecular and carbon isotopic compositions, oil alteration (biodegradation), oil-source rock correlation and oil reservoir filling direction. All the Silurian oils and oil sands are characterized by low Pr/Ph and C21/C23 tricyclic terpane (<1.0) ratios, “V”-pattern C27-C29 steranes distribution, low C28-sterane and triaromatic dinosterane abundances and light δ13C values, which can be correlated well with the carbonate source rock of the O3l Lianglitage Formation. Different oil biodegradation levels have also been confirmed for the different oils/oil sands intervals. With the S1k2 seal, oils and oil sands from the S1k1 interval of the Kelpintag Formation have only suffered light biodegradation as confirmed by the presence of “UCM” and absence of 25-norhopanes, whereas the S1k3-1 oil sands were heavily biodegraded (proved by the presence of 25-norhopanes) due to the lack of the S1k2 seal, which suggests a significant role of the S1k2 seal in the protection of the Silurian oil reservoir. Based on the Ts/(Ts+Tm) and 4-/1-MDBT ratios as reservoir filling tracers, a general oil filling direction from NW to SE has been also estimated for the Silurian oil reservoir in the Well Shun-9 prospect area.

The Maximum Burial Depth in Hydrocarbon Source Rocks on Kongquehe Slope in the Tarim Basin

The strata of the Kongquehe slope in the Tarim basin have suffered from long-term denudation, causing the determination of maximum ancient buried depth in mainly hydrocarbon source rocks to be very difficult. The denudation restricts the conduct of research into the hydrocarbon generation history of the source rocks. Through the use of drilling, seismic, logging, and geochemical data, calculation of the amount of denudation of the main unconformable surface, consideration of the present residual thicknesses of major hydrocarbon source rocks and other data, the authors determine maximum ancient buried depth in four major hydrocarbon source rocks and determines the time required to reach the maximum ancient buried depth. The authors have ascertained four main results through comprehensive analysis. (a) A majority of the Jurassic hydrocarbon source rock passed the hydrocarbon-generating threshold during the Neogene period and are now in the early-mature to mature stage. (b) Carboniferous hydrocarbon source rock is only distributed in the Caohu depression, having crossed the hydrocarbon-generating threshold in the Cretaceous period, and is now in the mature to late-mature stage. (c) Most of the middle-upper Ordovician hydrocarbon source rock crossed the hydrocarbon-generating threshold in the late Ordovician period and is now in the late-mature to over-mature stage. There are two blocks in the east research area that appear to contain the maximum ancient buried depth which may have experienced secondary hydrocarbon generation in the late Silurian. (d) Cambrian-Lower Ordovician hydrocarbon source rock is in the late-mature to over-mature stage and may have experienced secondary hydrocarbon generation in the Cenozoic period in most of Kongquehe area.

Recognition of the Source Rock Using Biomarkers From Eocene Reservoir Oils

The source rocks of 20 oils in Eocene reservoir from Lengdong oil field have been evaluated using geochemical biomarkers. Most of the oil samples have been undergone light to moderate biodegradation and four of these oil samples suffered heavy biodegradation. The oils were originated from low maturity source rocks within early to middle oil window according to the thermal-maturation-dependent biomarker ratios. Source-related biomarkers indicated that the oils originated from carbonate source rock possessed both high plants and algae organic matter input, while high plants' input was dominant in almost all the oils. The source rocks concerning the oils were deposited under anoxic to suboxic (low EH), salinity to hypersaline, and lacustrine environment with deep water.

Ternary Diagram of Fluorenes, Dibenzothiophenes and Dibenzofurans: Indicating Depositional Environment of Crude Oil Source Rocks

Fluorene (FL), dibenzothiophene (DBT) and dibenzofuran (DBF) and their alkylated homologues are important polycyclic aromatic compounds in crude oils and source rock extracts. They share the similar chemical structure and may have genetic relationships. The parent compounds (unsubstituted), methyl-, dimethyl- and ethyl-substituted isomers are identified by comparison with retention indices reported in literatures and correlation with co-injection of internal standards in gas chromatography-mass spectrometry (GC-MS) analysis. Therefore, their relative concentrations can be determined. Based on the large data sets, this paper preliminarily establishes a ternary diagram to interpret the depositional environment/lithology for oils and related source rocks. Five typical depositional environments/lithologies are distinguished on this ternary diagram. Data points from typical marine carbonate, fluvial/deltaic/fresh lacustrine shale and swamp fall into the DBTs, FLs and DBFs end-members, respectively. Oils from marine shale have subequal contents of FLs and DBFs and lie between the zones of fluvial/deltaic/fresh lacustrine shale and swamp, but have a little higher abundance of DBTs. The oils from brackish/saline lacustrine have intermediate contents of DBTs with a wide variety and some degree overlap with that of marine shale. On the basis of the ternary diagrams, two petroleum systems in the cratonic region of the Tarim basis are defined. The majority of discovered oils were derived from the Middle-Upper Ordovician carbonate source rocks. Whereas, some oils from wells TD2, T904, LK1 and TZ62 originated from the Cambrian and Lower Ordovician source rocks. Therefore, the ternary diagram of FLs, DBTs and DBFs is a useful method to interpret depositional environment/lithology for oils and related source rocks and to definite petroleum systems as well.

Evaluation of organic carbon content and source rock maturity using petrophysical logs and geochemical data: Case study of Horn Valley Siltstone source rock, Amadeus Basin, Central Australia

In this study, 30 samples from the Horn Valley Siltstone Formation from Amadeus Basin in Central Australia have been analyzed using geochemical method Rock-Eval (RE) pyrolysis. The analysis shows Total Organic Carbon between 0.21 to 2.74%wt . It also shows that kerogen type II, and a mixture of type II and III are the dominant kerogen. This type of kerogens are prone to oil and oil/gas production. The geochemical diagrams show that all samples are in the oil window, and they have good thermal maturation. The Horn Valley siltstone formation has been divided into 4 zones; Hv1, Hv2, Hv3 and Hv4. Although all zones are mature (i.e., have Tmax over 435 °C), Hv2 has a high organic carbon content and is located at the end of the oil window (Tmax between 450-470 °C). Also, to compare the results, petrophysical logs (Resistivity and Sonic) and ΔlogR method were used to determine the organic carbon content of source rock, and investigate zones with high pontentials to produce hydrocarbons. Zones have the potential to produce hydrocarbons was determined. And there was a close adaptation between the results of petrophysical method (ΔlogR) and Rock-Eval pyrolysis technique. The results show that Petrophysical method (ΔlogR) and the Rock-Eval pyrolysis technique have produced close results

Source rock potential and organic geochemistry of carboniferous source rocks in Santanghu Basin, NW China

Carboniferous source rocks identified by drilling in Santanghu (三塘湖) Basin were evaluated for their source potential, employing organic geochemistry and RockEval pyrolysis. The organic matter origin and depositional environment of these samples were also determined through biomarker analysis. Most of the Carboniferous source rocks in Santanghu Basin are characterised by high values of total organic carbon (TOC) content and high extractable organic matter content and hydrocarbon yields, indicating that they are organic-rich source rocks with high oil generative potential. The organic matter is predominantly Type I and Type II kerogen with a minor contribution of Type III kerogen, as demonstrated by its pyrolysis parameters and carbon isotope values. According to Ro (%) and T max values, most of the studied samples are at early- to middle-thermal mature stage; only a few of the samples are at a highly mature stage (past peak oil generation). The biomarker analysis reveals a dominance of algal/bacterial organic matter input, with a minor contribution of land plant material. Pr/Ph ratio supports a suboxic depositional condition, consistent with a neritic or marine-continental alternating environment proposed by predecessor.

Hydrocarbon occurrences and petroleum geochemistry of Albanian oils

Oil accumulations occur in the Ionian zone limestone section and in the Adriatic Basin sandstone reservoirs of Tortonian and Messinian age, respectively.A large set of geochemical compositional data of Albanian oils have been analysed. Oil entrapment occurred during two main phases: 1) during the Early Miocene, when the main part of source rocks were in the oil maturity window; 2) during the Pliocene, when the source rocks were in a more advanced stage of oil genesis. The multiphase genesis has resulted in hydrocarbon accumulations with a broad range of geochemical characteristics. Both individual fieldsand in field complexes, biodegraded and non-biodegraded heavy oils, light oils, condensates, wet and dry gas may occur. In general, oil density and sulphur content decrease with depth.Oil grouping is evident from the data set, although stable carbon isotope values suggest that the Berat Belt oils and the Adriatic Basin oils are slightly different from the majority of oils in the Kurveleshi Belt. No exact correlations between the oils and the individual carbonate source rock levels could be established.The Tertiary humid source rock has been matured probably in the early stage, and has generated dry gas and some immature condensates.The gas accumulations in the Adriatic Basin consist mostly in pure biogenic and mixed thermogenic/ biogenic gases. The deeper classic reservoirs contain relatively less dry gas.