Oil Reservoirs


    Gas Maturity


Stable isotope analysis is a critical technique for upstream reservoir exploration through well profiling. Understanding the origin of oil and gas in any new reservoir is an essential requirement for determining its feasibility and suitability for exploitation. As well as making oil-oil correlations for reservoir mapping possible, stable isotope analysis is a key function of any petrochemical service laboratory.

Beyond the exploration of conventional reservoirs, recent plays into unconventional “tight” resources such as shale gas and coal bed methane have a similar need for stable isotope analysis; evaluation of the carbon and hydrogen fingerprints enables petroleum geochemists further insight into this continuing drive for new opportunities.

Oil fractions & natural gases

Compound specific isotope analysis allows highly precise isotopic profiling of oil reservoirs and therefore evaluation of the source of the oil. Knowing the origin of the oil and the extent of its maturity allows the feasibility of any well site to be established. Combined with carbon and hydrogen isotope analysis of natural gases, our exceptional GC-IRMS system and IonOS software, you will find that these time consuming analyses are performed quickly and rapidly, improving your ROI.

Whole oils & sediments

Combining compound specific isotope analysis of oil fractions with bulk isotope analysis is highly complementary for understanding oil origins, but also allows nitrogen, sulfur and oxygen isotope analysis of NSO fractions. Our elemental analysers also offer excellent performance for more refractory samples such as sediments which are able to bring greater insight into basin geochemistry.

Carbonates & DICs

By analyzing sedimentary carbonates from a basin brings greater understanding of the burial processes and diagenesis environment that the oil reservoir has been subjected too. Our iso FLOW system is able to analyse sedimentary carbonates, dissolved inorganic carbonate as well as well waters with high precision. This flexible system is also capable of analysing dissolved nitrates allowing complete hydrogeology of the basin to be established.

Oil & Gas publications using our instruments

Our customers use our instruments to do some amazing research in the oil & gas application field. To show you how they perform their research and how they use our IRMS instruments, we have collected a range of peer-reviewed publications which cite our products. You can find the citations below and then follow the links to the publishing journal should you wish to download the publication.

If you would like to investigate our available citations in more detail, or email the citation list to yourself or your colleagues then take a look at our full citation database.

43 results:

Combined cluster and discriminant analysis: An efficient chemometric approach in diesel fuel characterization
Forensic Science International (2017)
Márton Novák, Dóra Palya, Zsolt Bodai, Zoltán Nyiri, Norbert Magyar, József Kovács, Zsuzsanna Eke

Combined cluster and discriminant analysis (CCDA) as a chemometric tool in compound specific isotope analysis of diesel fuels was studied. The stable carbon isotope ratios (δ13C) of n-alkanes in diesel fuel can be used to characterize or differentiate diesels originating from different sources. We investigated 25 diesel fuel samples representing 20 different brands. The samples were collected from 25 different service stations in 11 European countries over a 2 year period. The n-alkane fraction of diesel fuels was separated using solid-state urea clathrate formation combined with silica gel fractionation. The stable carbon isotope ratios of C10–C24 n-alkanes were measured with gas chromatography–isotope ratio mass spectrometry (GC–IRMS) using perdeuterated n-alkanes as internal standards. Beside the 25 samples one additional diesel fuel was prepared and measured three times to get totally homogenous samples in order to test the performance of our analytical and statistical routine. Stable isotope ratio data were evaluated with hierarchical cluster analysis (HCA), principal component analysis (PCA) and CCDA. CCDA combines two multivariate data analysis methods hierarchical cluster analysis with linear discriminant analysis (LDA). The main idea behind CCDA is to compare the goodness of preconceived (based on the sample origins) and random groupings. In CCDA all the samples were compared pairwise. The results for the parallel sample preparations showed that the analytical procedure does not have any significant effect on the δ13C values of n-alkanes. The three parallels proved to be totally homogenous with CCDA. HCA and PCA can be useful tools when the examining of the relationship among several samples is in question. However, these two techniques cannot be always decisive on the origin of similar samples. The initial hypothesis that all diesel fuel samples are considered chemically unique was verified by CCDA. The main advantage of CCDA is that it gives an objective index number about the level of similarity among the investigated samples. Thus the application of CCDA supplemented by the traditionally used multivariate methods greatly improves the efficiency of statistical analysis in the CSIA of diesel fuel samples.

Two new oxygen-containing biomarkers isolated from the Chinese Maoming Oil Shale by silica gel column chromatography and preparative gas chromatography
Journal of Separation Science (2016)
Xiangyun Zhang, Hong Lu, Jing Liao, Caiming Tang, Guoying Sheng, Ping'an Peng

Two biomarkers, 5,9-dimethyl-6-isopropyl-2-decanone (1) and 4,9,11-trimethyl-6-isopropyl-2-dodecanone (2), were isolated from Chinese Maoming Oil Shale by silica gel column chromatography and preparative gas chromatography. Their structures were elucidated by using spectroscopic techniques.

Journal of Petroleum Geology (2016)
H. A. Eltom, O. M. Abdullatif, L. O. Babalola, M. A. Bashari, M. Yassin, M. S. Osman, A. M. Abdulraziq

This study presents the results of chemostratigraphic analyses and spectral gamma-ray logging integrated with sedimentological data across the Permian-Triassic boundary at a measured outcrop section in central Saudi Arabia. The studied section encompasses the uppermost part of the Midhnab Member and the Lower and Upper Khartam Members of the Khuff Formation. Lithofacies were interpreted to have been deposited in subtidal, tidal to supratidal, lacustrine and meandering fluvial / flood plain, marginal marine and lagoonal depositional environments. Integration of bulk geochemical and carbon isotope (δ13C) data allowed the identification of a stratigraphic interval with a negative shift in δ13C ratio values, which was interpreted to correspond to the end-Permian mass extinction event. The end of this “first negative shift in δ13C values” is taken to mark the Permian-Triassic boundary. Above this boundary and just below an interval containing scattered thrombolites, a second negative shift in δ13C ratios was observed, and corresponds to an interval with long-term uranium depletion as indicated by the bulk sediment geochemical and spectral gamma-ray uranium data. The Permian-Triassic boundary (PTrB) was placed at the transition between marginal-marine and subtidal deposits. This stratigraphic position corresponds to the end of the “first negative δ13C shift” and the point of greatest uranium depletion. Although previous studies on outcrops of the Khuff Formation in Saudi Arabia identified a major sequence boundary between the Lower and Upper Khartam Members and interpreted it as the P TrB, no evidence is presented in this study for exposure and dissolution at this surface. Accordingly, the Permian-Triassic transition is placed in the transgressive portion of the Upper Khartam Member, while the sequence boundary below is interpreted to correspond to the end-Permian extinction. Correlation of Khuff time-equivalent units in the Arabian Plate is challenging, and this study will contribute to an improved understanding of this important stratigraphic unit, which contains prolific non-associated gas reservoirs. The identification of the Permian-Triassic boundary in central Saudi Arabia will help in the construction of a sequence-stratigraphic scheme for the Khuff, and with the correlation of lithofacies within this heterogeneous reservoir unit.

Petrologic and stable isotopic study of the Walloon Coal Measures, Surat Basin, Queensland: peat accumulation under changing climate and base level
International Journal of Coal Geology (2016)
A. Hentschel, J.S. Esterle, S.D. Golding, D.V. Pacey

The Late Jurassic Walloon Subgroup (recently dated as Oxfordian) is a productive, subbituminous coal seam gas source in the Surat Basin and can be subdivided from bottom to top into the Taroom Coal Measures, the Tangalooma Sandstone, the Lower and Upper Juandah Coal Measures, which have different coal character. The lower Taroom coals are commonly thick, associated with sandstones and interpreted to form as base level is rising, creating sodden anoxic conditions for peat accumulation. The middle Tangalooma to Lower Juandah contains fewer and thinner coals, and transitions upwards from a sandstone to siltstone dominated sequence responding to inundation with the development of floodplain lakes. The strata then coarsen upward in both grain size and coal thickness in the Upper Juandah Coal Measures, which may be eroded by an overlying unit, the Springbok Sandstone. This unconformable surface is basin wide and depending on age, can be tied into global changes in climate and base level. Existing models for peat growth under changing base level and the variability in terms of the conditions of peat formation through time, as well as throughout the basin, are tested. Environment of peat deposition and changes therein, are investigated by petrographic analysis of the Walloon coals, coupled with high resolution lithotype logging of core and organic stable carbon isotope analysis. Fine microlayering and abundance of root suberinite, telo- and detrovitrinite indicate precursory peat formation in a mostly herbaceous marsh to fen environment, in which bigger trees are either infrequent or absent, except for the lower seams of the Taroom Coal Measures and the upper seams of the Lower Juandah Coal Measures, where bright bands are thicker (≥10mm) and more frequent. No extended periods of dehydration-oxidation (<1vol.% mmf inertinite group macerals) are indicated until the deposition of the Upper Juandah Coal Measures that contain greater amounts (5 to 15vol.% mmf with rare 68vol.%) of inertinite group macerals. Suberinite is interpreted to reflect dense root mats that are resistant to decay by microbial activity. They leave behind their suberinised exoderms, which originally helped wetland plants to protect themselves from deleterious solutes or in case of a change to drier conditions provided protection from desiccation. The most common inertinite maceral found in the Upper Juandah Coal Measures is inertodetrinite, associated with detrovitrinite. After bush or swamp fires, pieces of charcoal on dried out peat surfaces are easily blown away by the wind and accumulate with sediment in standing water. Fusinites and semifusinites are mainly associated with telovitrinites and are likely to be the result of desiccation and (fungal) mouldering in addition to fire. Stable carbon isotopes of coal show a distinct positive shift in the Lower Juandah Coal Measures that sets in well before the increased inertinite content in the Upper Juandah Coal Measures. The enrichment in 13C could be linked to a change in climate during the high stand depositional cycle, marking the onset of late stage falling, where base level begins to drop, later creating exposures and water stress. A shift to a less humid climate in the Upper Juandah Coal Measures could have favoured the conditions for desiccation, mouldering and bush fires, which is reflected in the coal's maceral composition. The Surat Basin δ13C isotope trend follows the global trend found in marine carbonate samples from the same age interval that corroborates increasing enrichment towards the top of the coal measures (approximately middle Oxfordian), followed by a shift to more negative compositions, which corresponds to the onset of the Springbok Sandstone deposition on an unconformable surface.

Carbon and hydrogen isotope fractionation during methanogenesis: A laboratory study using coal and formation water
International Journal of Coal Geology (2016)
Rita Susilawati, Suzanne D. Golding, Kim A. Baublys, Joan S. Esterle, Stephanie K. Hamilton

Carbon and hydrogen isotope compositions of CH4 generated via methanogenesis in cultures of South Sumatra Basin (SSB) coalbed methane (CBM) formation waters grown on coal, acetate and H2+CO2 were investigated. CH4 production and molecular analysis confirmed the presence of active microbial communities that are able to convert coal into CH4 using both acetoclastic and hydrogenotrophic pathways. The representative bacterial sequences were dominated by Bacteroidetes, Firmicutes and Deltaproteobacteria, while Methanosaeta and Methanosarcina were the most prevalent archaeal methanogens present in the cultures. CH4 produced in this study's culturing experiments has δ13C values in the range of −50‰ to −20‰, with most values falling outside the current understanding of the carbon isotopic boundaries for biogenic CH4 (−110‰ to −30‰). However, the corresponding apparent carbon isotopic α factor (αc=1.02±0.006), and isotopic effect (εc=−20.1‰±15.3) showed that CH4 in SSB cultures was predominantly produced by acetoclastic methanogenesis, which is consistent with the results of molecular DNA analysis. In addition, the calculated contribution of CO2 reduction from the δ13C values of coal-treated cultures was overall <50%, further confirming the high contribution of the acetoclastic pathway to CH4 production in the SSB cultures. The outcome of this experimental study also suggests that δ2H-CH4 values may not provide a reliable basis for distinguishing methanogenic pathways, while apparent carbon isotopic fractionation factor (αc) and isotope effect (εc) are considered more useful indicators of the methanogenic pathway. The high δ13C-CH4 values (≥30‰) and the dominance of Methanosaeta over Methanosarcina indicate that methanogens within the SSB cultures were operating at low substrate concentrations. An unusually positive δ13C-CH4 suggests a substrate depletion effect, which is thought to be related to a decrease in the relative abundance of key bacterial coal degraders with formation water inoculum storage time. Closer observation of δ13C-CH4 values during the growth of cultures within a single experiment also showed a 13C-enrichment trend over time. At log phase of growth, the CH4 produced was 13C-depleted when compared to the stationary phase that also indicates substrate depletion effects. Finally, the δ13C-CH4 values encountered in this study (as high as −20‰) highlight the possible positive extension of δ13C-CH4 values of acetoclastic methanogenesis from those currently reported in the literature for natural and experimental samples (as high as −30‰).

Measurement of compound-specific carbon isotope ratios (δ 13 C values) via direct injection of whole crude oil samples
Rapid Communications in Mass Spectrometry (2016)
Craig D. Barrie, Kyle W. R. Taylor, John Zumberge

RATIONALE: Stable isotope analysis is a powerful tool in understanding the generation, history and correlation of hydrocarbons. Compound-specific δ13C measurements of oils allow detailed comparison of individual compound groupings; however, most studies of these sample materials separate and isolate individual fractions based on the chemistries of particular compound groups, potentially losing considerable valuable isotopic data. Even if all fractions are analyzed, this represents a large increase in the data-processing burden, effectively multiplying data evaluation time and effort by the number of fractions produced. Gas chromatography/isotope ratio mass spectrometry (GC/IRMS) of untreated, whole crude oils allows the immediate collection of a larger suite of valuable isotopic data for these studies. METHODS: Untreated (‘neat’, undiluted), whole crude oils were directly injected and measured on a GC/IRMS system, using split (40:1) injections and a 50 m HP-PONA column. The GC method, 97 min in duration, was designed to maximize baseline separation of target analyte peaks, while an additional oxygen flow was admitted into the combustion reactor to maximize the lifetime of the combustion chemicals. RESULTS: The method and setup utilized allow the measurement of a much greater range of the n-alkanes (n-C4 to n- C25+) than traditional methods, while also retaining important cycloalkane, aromatic and isoprenoid peaks within the same analysis. Carbon isotope (δ13C) evaluation of these additional compound classes reveals trends in maturity and origins which are not identifiable when exclusively assessing the traditional n-alkane package (>n-C12). CONCLUSIONS: The described setup and method open up new possibilities for assessing the origins and histories of crude oil samples. The data generated for the whole oil n-alkanes by this method is equivalent to that reported for isolated n-alkane studies, while also providing valuable additional data on many other important compounds. The end result of this method is a more complete assessment of the carbon isotopic composition of crude oils.

Sulfur isotopic compositions of individual organosulfur compounds and their genetic links in the Lower Paleozoic petroleum pools of the Tarim Basin, NW China
Geochimica et Cosmochimica Acta (2016)
Chunfang Cai, Alon Amrani, Richard H. Worden, Qilin Xiao, Tiankai Wang, Zvi Gvirtzman, Hongxia Li, Ward Said-Ahmad, Lianqi Jia

During thermochemical sulfate reduction (TSR), H2S generated by reactions between hydrocarbons and aqueous sulfate back-reacts with remaining oil-phase compounds forming new organosulfur compounds (OSC) that have similar δ34S values to the original sulfate. Using compound specific sulfur isotope analysis (CSSIA) of alkylthiaadamantanes (TAs), alkyldibenzothiophenes (DBTs), alkylbenzothiophenes (BTs) and alkylthiolanes (TL), we have here attempted to differentiate OSCs due to primary generation and those due to TSR in oils from the Tarim Basin, China. These oils were generated from Cambrian source rocks and accumulated in Cambrian and Ordovician reservoirs. Based on compound specific sulfur isotope and carbon isotope data, TAs concentrations and DBT/phenanthrene ratios, the oils fall into four groups, reflecting different extents of source rock signal, alteration by TSR, mixing events, and secondary generation of H2S. Thermally stable TAs, produced following TSR, rapidly dominate kerogen-derived TAs at low to moderate degrees of TSR. Less thermally stable TLs and BTs were created as soon as TSR commenced, rapidly adopted TSR- δ34S values, but they do not survive at high concentrations unless TSR is advanced and ongoing. The presence of TLs and BTs shows that TSR is still active. Secondary DBTs were produced in significant amounts sufficient to dominate kerogen-derived DBTs, only when TSR was at an advanced extent. The difference in sulfur isotopes between (i) TLs and DBTs and (ii) BTs and DBTs and (iii) TAs and DBTs, represents the extent of TSR while the presence of TAs at greater than 20 μg/g represents the occurrence of TSR. The output of this study shows that compound specific sulfur isotopes of different organosulfur compounds, with different thermal stabilities and formation pathways, not only differentiate between oils of TSR and non-TSR origin, but can also reveal information about relative timing of secondary charge events and migration pathways.

Interaction of coal and oil in confined pyrolysis experiments: Insight from the yields and carbon isotopes of gas and liquid hydrocarbons
Marine and Petroleum Geology (2016)
Erting Li, Changchun Pan, Shuang Yu, Xiaodong Jin, Jinzhong Liu

Isothermal confined (gold capsule) pyrolysis experiments were performed for coal alone, oil alone and coal plus oil with oil/coal ratios ranging from 0.006 to 0.171 at 315 °C, 345 °C and 375 °C, respectively and 50 MPa for 72 h. In the experiment for coal plus oil, the amounts and compositions of hydrocarbon gases are substantially different from those predicted from the results in the experiments for oil alone and coal alone. The results of these experiments demonstrate that kerogen and oil do not crack separately in the experiments of coal plus oil. The interaction between kerogen and oil components leads to the generation of hydrocarbon gases. With oil/coal ratio increasing, the amounts of individual and total hydrocarbon gases decrease at first, and then increase rapidly up to several times those calculated from the yields of these components in the experiments for oil alone and coal alone. The C1/ΣC1–5 ratios of hydrocarbon gases decrease and are increasingly lower than those calculated from the yields of hydrocarbon gases in the experiments for oil alone and coal alone. The amount and carbon isotopes of individual n-alkane demonstrate that the free liquid n-alkanes were incorporated into kerogen and replaced the bound liquid n-alkanes (covalently bonded alkyl groups in kerogen). Carbon isotopes of hydrocarbon gases further suggest that the bound liquid n-alkanes in kerogen preferentially crack into hydrocarbon gases.

Formation and evolution of solid bitumen during oil cracking
Marine and Petroleum Geology (2016)
Yongqiang Xiong, Wenmin Jiang, Xiaotao Wang, Yun Li, Yuan Chen, Li Zhang, Rui Lei, Ping’an Peng

Solid bitumen is widespread throughout lower Paleozoic paleo-reservoirs in southern China. However, the processes that control its formation and evolution remain unclear. Here, we document temporal changes in the yield and characteristics of solid bitumen generated during oil cracking using an experimental approach involving the anhydrous pyrolysis of crude oil. The results indicate that solid bitumen is predominantly produced in environments of high thermal maturity associated with the dry gas stage of oil cracking (i.e., during rapid methane generation and C2–C5 gaseous hydrocarbon destruction), with maximum solid bitumen yields up to about 42% of the original amount of crude oil. A near linear relationship exists between solid bitumen yields and methane abundance during the main stage of solid bitumen formation, although there is no clear variation in the δ13C values of solid bitumen produced at any stage of this process. This suggests that the isotopic composition and distribution of solid bitumen within a reservoir can be used to identify hydrocarbon sources, delineate the range of paleo-reservoirs, and assess the size of paleo-oil reservoirs and oil-cracked gas reservoirs within a basin.

The origin and evolution of thermogenic gases in organic-rich marine shales
Journal of Petroleum Science and Engineering (2016)
Yongqiang Xiong, Li Zhang, Yuan Chen, Xiaotao Wang, Yun Li, Mingming Wei, Wenmin Jiang, Rui Lei

In order to better understand the generation and primary source of mature thermogenic gas in shale, and to evaluate the residual gas generation potential of the shale at different maturity levels, we performed pyrolysis experiments on an organic-rich marine shale and its kerogens prepared by artificial maturation. The results indicate that the thermal maturation of organic matter in the shale can be divided into four stages: oil generation (<0.6–1.0% EasyRo), condensate generation (1.0–1.5% EasyRo), wet gas generation (1.5–2.2% EasyRo), and dry gas generation (2.2–4.5% EasyRo). Thermogenic methane is produced mainly during wet gas and dry gas generation, while most of the C2+ hydrocarbon gases are produced during condensate and wet gas generation. The kerogen at a thermal maturity of >3.0% EasyRo still has methane generation potential. Whether or not gas generation potential of a highly mature kerogen has a commercial significance depends on its organic matter richness, thermal maturity internal and some other geological factors, such as caprock sealing property, reservoir physical property, and tectonic movement. In addition to the gas produced from kerogen cracking, gas is also generated from the secondary cracking of residual bitumen as maturation progresses. Early hydrocarbon expulsion during oil generation likely has a considerable effect on the amount and δ13C values of the late-generated shale gas. The lower the oil expulsion efficiency of a shale, i.e., the more retained bitumen, then the higher the productivity of post-mature shale gas and comparative enrichment of the latter in 12C.