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    Oil Reservoirs
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    Gas Maturity

Exploration

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:

Source Identification of Oil Spills Using Compound-Specific Carbon Isotope Analysis Based on “7–16” Oil Spill in Dalian, China
Aquatic Procedia (2015)
Min Wang, Chuanyuan Wang, Shiji He

A set of sequentially weathered oils residue in sediments collected from Dalian Bay in different time after “7-16” oil spill accident, were analyzed by Gas chromatography–mass spectrometry (GC-MS) and Gas chromatography–isotope ratio mass spectrometry (GC-IRMS) to analyze the weathering process and evaluated the possibilities of GC-IRMS as a correlation tool in oil spill identification. Although some temporal variation was observed, no significant temporal shifts in the δ13C values for n-alkanes were measured in moderated weathered oils. The standard deviations of δ13C values of individual n-alkanes varied from 0.07% to 0.20%, which showed that the weathering has no significant effect on values of individual n-alkanes over 120 days. The results suggest that stable carbon isotope profile of n-alkanes can be a useful tool for tracing the source of an oil spill, particularly for the weathered oils absence of sterane and terpane biomarkers.

Source rock potential of lignite and interbedded coaly shale of the Ogwashi–Asaba Formation, Anambra basin as determined by sequential hydrous pyrolysis
International Journal of Coal Geology (2015)
Samuel O. Akande, Michael D. Lewan, Sven Egenhoff, Olabisi Adekeye, Olusola J. Ojo, Arndt Peterhansel

Outcrops in the Anambra Basin in southern Nigeria contain Paleogene Imo Shale (marine), the Neogene paralic Ogwashi–Asaba and the continental Benin Formations, representing equivalents of the subsurface successions in the Niger Delta Basin. Thirty-three samples of lignite and the interbedded coaly shale of the Ogwashi–Asaba Formation were investigated petrologically before Rock-Eval screening. Two selected samples of lignite and coaly shale were subjected to sequential hydrous pyrolysis (HP) at 330°C for 72h and at 355°C for 72h to characterize their oil and gas potential. The lignite sample has a Rock-Eval hydrogen index (HI) of 481mg/g TOC and a mean vitrinite reflectance of 0.36% Rom. The total amount of expelled oil generated in the sequential HP experiments is 259mg/g of original total organic carbon (TOCorig). This expelled waxy oil has abundant high-molecular-weight n-alkanes and an extremely high pristane/phytane ratio of 6.5, typical of crude oils generated from coals as observed in some onshore and shallow offshore accumulations of the Niger Delta. The overlying coaly shale has a lower HI of only 191mg/g TOC. The total amount of expelled oil generated in the sequential HP experiments is only 15mg/g TOCorig. This oil is not waxy and has a pristane/phytane of 2.6, which is more typical of a marine source rock. These results are contrary to the idea that coaly shale associated with coal is the main source of oil. The greater yields of expelled oil from the coal relative to the coaly shale are attributed to the higher liptinite content in the former and the possibility that the organic matter in the latter was oxidized prior to deposition. δ13C of the methane generated at 355°C for 72h is −39.5‰ for the lignite and −35.0‰ for the coaly shale. This suggests different methane precursors in these two lithologies. The data set reveals remarkable differences in the characteristics of the two types of source rocks in the Ogwashi–Asaba Formation and their potential to contribute a mixture of hydrocarbons derived from intervals that are stratigraphically only meters apart. These results suggest that coal and coaly shale within the thermally mature stratigraphic levels of the Agbada Formation in the sub-surface are potential source rocks for liquids and gaseous hydrocarbons in the Niger Delta.

Gas generation of shale organic matter with different contents of residual oil based on a pyrolysis experiment
Organic Geochemistry (2015)
Haifeng Gai, Xianming Xiao, Peng Cheng, Hui Tian, Jiamo Fu

The generation of gas in organic rich shales with different oil expulsion efficiencies is receiving more attention because of increased global shale gas exploration and development. In this study, a low maturity shale was used to prepare a suite of shale organic matter samples with different contents of residual oil (representative of different oil expulsion efficiencies). These samples were pyrolyzed to investigate the influence of residual oil contents on gas generation and gas chemical and carbon isotopic compositions. The results indicate that with increasing residual oil contents, the total hydrocarbon gas yield (C1–5), heavy hydrocarbon gas yield (C2–5) and gas wetness (C2–5/C1–5) increase, the methane carbon isotopic value (δ13C1‰) becomes lighter, and the Ro (vitrinite reflectance) range of the gas window (defined by the main stage of gas generation in the present study) decreases. Through a comparison between the measured data and calculated theoretical values of the hydrocarbon gas yield and methane carbon isotopic values, it is believed that there are interactions between the kerogen and residual oil during gas generation. Although these interactions did not substantially change their hydrocarbon gas potential, there was an influence on the gas generation evolution of the shale organic matter, resulting in a maturity hysteresis of the primary cracking of residual oil to form C2–5 hydrocarbons and a promotion of secondary cracking of the C2–5 hydrocarbons to form methane. These interactions also inhibited the early cracking of kerogen, resulting in more methane generation in the late pyrolysis stage.

High heat flow effects on a coalbed methane reservoir, East Kalimantan (Borneo), Indonesia
International Journal of Coal Geology (2014)
Tim a. Moore, Michael Bowe, Chairul Nas

The Balikpapan Formation (Miocene age) in Sangatta, East Kalimantan is thick (> 1500 m) containing abundant coal seams that range in thickness from less than a meter to over 5 m. Coal seams are distributed throughout the section and may represent 5 to 7% of the total formation thickness. Measured gas contents range from < 1 to 13 m3/t (as received basis). The variation is both stratigraphically and geographically controlled. In samples from three drill cores, trends of vitrinite reflectance, calorific value, and moisture content indicate that rank increases down hole. Measured gas content also increases down hole in each core locations. However the rate of change down hole for all of those parameters increases with proximity to the southwestern corner of a geological feature known locally as the Pinang Dome. The Sangatta area has a higher geothermal gradient (50 °C/km) than most other parts of East Kalimantan (25–40 °C/km). It is well documented that the southwest part of the Pinang Dome has elevated organic maturation levels. It is concluded that there is higher heat flow in this area and thus coal beds in proximity have been thermally altered. This is evident not just in the increased rank and measured gas contents but also in the higher CO2 and C2 + gas composition found adjacent to the southwest corner of the Pinang Dome. It is hypothesized that the gas origin in the higher rank area could be thermogenic while gas isotopes from the well furthest from the Pinang Dome, with the lowest rank coals, indicate biogenic origins.

The effect of origin and genetic processes of low molecular weight aromatic hydrocarbons in petroleum on their stable carbon isotopic compositions
Organic Geochemistry (2014)
P. Le Métayer, K. Grice, C.N. Chow, L. Caccetta, E. Maslen, D. Dawson, L. Fusetti

Stable carbon isotopic compositions of individual low molecular weight aromatic hydrocarbons, such as alkylbenzenes, alkylnaphthalenes and alkylphenanthrenes, were measured from a set of oils, mostly from the North-West shelf of Australia, of varying age, facies type and thermal maturity. The objective was to assess the influence of thermal maturity and source during generation of these aromatics on their stable carbon isotopic compositions. For most of the oils studied, δ13C of the aromatic components show a 13C depletion as the degree of methylation increases. For the alkylnaphthalenes, the 13C depletion is most pronounced for low maturity oils compared to high maturity oils. δ13C of the methyl groups of these alkylnaphthalenes were calculated and the resulting data display significant differences between ‘mature’ and ‘immature’ oils, suggesting that isotopically lighter methyl groups are ‘released’ as thermal maturation proceeds. Therefore, we propose an isotopic fractionation associated with the methyl transfer mechanisms affecting low molecular weight aromatic hydrocarbons during diagenesis

Conceptual exploration targeting for microbially enhanced coal bed methane (MECoM) in the Walloon Subgroup, eastern Surat Basin, Australia
International Journal of Coal Geology (2014)
S.K. Hamilton, S.D. Golding, K.a. Baublys, J.S. Esterle

The sustainable in situ regeneration of microbial (biogenic) methane or microbially enhanced coal bed methane (‘MECoM’) is an emerging concept being investigated globally. Promising results and recommendations of a preliminary culture study of Walloon Subgroup co-produced coal seam gas (CSG) waters from the Surat Basin, Queensland established the presence of viable methanogens and suggested that in situ methanogenesis could be stimulated using physical and chemical reservoir treatments. This paper represents the culmination of a stepwise basin analysis project ultimately aimed at siting potential in situ bioreactor locations in the eastern Surat Basin. The integration of stratigraphically located data on the molecular and isotopic composition of desorbed gases, host coal properties and spatially associated waters through the core production zone has allowed the spatial variability and relative influence of hydro-geological factors on methanogenesis to be evaluated in detail for the first time. Higher gas contents and systematically enriched CH4 and CO2 carbon isotopic compositions in the stratigraphically central coal seams (oldest-youngest: in the upper Taroom Coal Measures, Tangalooma Sandstone lower Juandah Coal Measures) are best explained by increased rates of microbial CO2 reduction and substrate depletion. There is a building case to trial MECoM in the central coal seams in a depleted/underperforming well in an area of high permeability. Integrated microbiological, chemical engineering, hydro-chemical and geological studies are ongoing to further enhance understanding of Walloon Subgroup CSG and the bioreactor potential of the Surat Basin.

Stable isotopic and molecular composition of desorbed coal seam gases from the Walloon Subgroup, eastern Surat Basin, Australia
International Journal of Coal Geology (2014)
S.K. Hamilton, S.D. Golding, K.a. Baublys, J.S. Esterle

This study used compositional and stable isotopic analysis to test hypotheses on the distribution and origins of Walloon Subgroup coal seam gas (CSG) in the eastern Surat Basin, Queensland, Australia. The Middle Jurassic Walloon Subgroup play differs from many other low-rank CSG plays—particularly in methane carbon isotopic signature, i.e., the CSG is not as ‘microbial’ as could be expected. The carbon isotope compositions of desorbed methane from three cored appraisal wells fall within the generally accepted range for thermogenic or mixed gas (δ13C − 58.5‰ to − 45.3‰). The δ13C–CH4 values from stratigraphically placed coal core samples increased (became more ‘thermogenic’) from the top of the upper (Juandah) coal measures to the base of the Tangalooma Sandstone. Below the Tangalooma Sandstone, in the lower (Taroom) coal measures, the δ13C–CH4 values decreased with increasing depth. These positively parabolic δ13C profiles tracked total measured gas content in two out of the three wells studied. The third well displayed lower variance of δ13C–CH4 and gas content increased uniformly with depth. A genetic classification based on methane stable carbon isotopes alone might interpret this pattern as a transition from microbially- to thermogenically-sourced methane in the central coal seams. However, a δ13C–CO2 profile for one well tracks total gas content and δ13C–CH4, and exhibits an inverse relationship with δD–CH4. These results, together with the mostly dry nature of the gas samples [(C1/(C2 + C3)) ratios up to ~ 10,000] and relatively uniform δD–CH4 values (δD − 238‰ to − 202‰), suggest that microbial CO2 reduction is the primary source of Walloon Subgroup methane. As such, stratigraphic variations in gas content mainly reflect the extent of microbial methanogenesis. We suggest that peak microbial utilisation of H2–CO2 occurred at the Tangalooma Sandstone level, enriching the residual CO2 pool and derived methane in 13C. Carbon [Δ13C(CO2–CH4)] and deuterium isotopic differences [ΔD(H2O–CH4)], and cross-plots of δD–H2O and δ18O–H2O are also consistent with kinetic isotope fractionation during microbial-mediated carbonate reduction. The results are relevant for applying microbially enhanced coal bed methane (MECoM) in the Surat Basin.

Geochemical signature related to lipid biomarkers of ANMEs in gas hydrate-bearing sediments in the Ulleung Basin, East Sea (Korea)
Marine and Petroleum Geology (2013)
Dong-Hun Lee, Ji-Hoon Kim, Jang-Jun Bahk, Hye-Youn Cho, Jung-Ho Hyun, Kyung-Hoon Shin

The emission of methane as a greenhouse gas is controlled by the anaerobic oxidation of methane (AOM), which plays an important role in the biogeochemical methane cycle. During the Second Ulleung Basin Gas Hydrate Drilling Expedition (UBGH2), the distribution of lipid biomarkers and their compound-specific stable carbon isotope ratios related to methane were investigated in venting and non-venting sites (UBGH2-3, UBGH2-10) of gas-hydrate-bearing sediments in the Ulleung Basin. The objective of this study was to understand the microbial signatures related to methane cycling in organic-rich sediment in a marginal sea (East Sea/Japan Sea) of the western North Pacific. The concentrations of methane-related specific biomarkers (archaeol and sn-2-hydroxyarchaeol) at the sulphate–methane transition zone (SMTZ; sediment depth in UBGH2-3: 1–2 mbsf, in UBGH2-10: 6.8 mbsf) are typically higher than in other sediment sections and their δ 13C valuesare apparently depleted (−73.3‰ to −102.7‰) in the UBGH2-3 and UBGH2-10 study sites. However, the δ13C values of archaeol and sn-2-hydroxyarchaeol (between −59.6‰ and −66.5‰) are not depleted with the increased methane concentration in the sediments below the SMTZ in UBGH2-3, compared to the δ 13C values (about −60‰) of in situ methane. This suggests that methane production processes should be dominant in the deeper sediment sections (2.7–3.8 mbsf) rather than methane consumption by anaerobic methanotrophs (ANMEs) at the corresponding sediment depths. There were also higher δ 13C values (−47‰ to −32‰) for archaeol and sn-2-hydroxyarchaeol in the 3–6 mbsf sections at UBGH2-10, suggesting the prevalence of methanogenic activities. However, the δ13C values (−89.0‰ to −92.2‰) of archaeol and sn-2-hydroxyarchaeol were unexpectedly depleted in the deeper sediment section (5.2 mbsf) of the venting site (UBGH2-3), indicating that the past AOM occurred under low sulphate concentrations in the corresponding pore water. This study used the biomarker ratio (sn-2-hydroxyarchaeol/archaeol) of Archaea as a tool to demonstrate the different ANME communities, which was supported by 16S rRNA analysis in the sediments of venting and non-venting sites (UBGH2-3, UBGH2-10). Consequently, the biochemical signatures of methanotrophic and methanogenic activity were found at varying sediment depths at both sites.

Biomarker and isotope evidence for microbially-mediated carbonate formation from gypsum and petroleum hydrocarbons
Chemical Geology (2013)
G. Aloisi, M. Baudrand, C. Lécuyer, J.-M. Rouchy, R.D. Pancost, M.a.M. Aref, V. Grossi

Along the western coast of the Gulf of Suez large amounts of evaporitic gypsum of Miocene age have been microbially transformed into carbonates and elemental sulfur in the presence of petroleum. Similar diagenetic transformations have been described from numerous sites worldwide but the role of petroleum, specifically as a carbon source for the sulfate-reducing microbial community, remains elusive. We carried out a geochemical investigation of microbial carbonates from the Gulf of Suez that suggests the presence of a community of sulfate-reducing bacteria thriving on carbon substrates contained in petroleum. Specifically, a set of non-isoprenoidal macrocyclic glycerol diethers (McGDs), that we tentatively ascribe to sulfate-reducing bacteria, have a stable carbon isotope composition close to that of petroleum n-alkanes associated with the carbonates. The presence of archaeol that is 13C-enriched relative to bacterial lipids suggests that Archaea are present but either indirectly involved or not involved in the transformation of petroleum-derived carbon. The lipid biomarker pattern we observe is distinct from those observed in settings where sulfate reduction is coupled to the anaerobic oxidation of methane. Our results suggest that petroleum migration has triggered the microbial transformation of gypsum into carbonates in the Gulf of Suez. By extension, the involvement of petroleum in the microbial transformation of gypsum into carbonates in other settings, which was suggested by more indirect, geological and inorganic geochemical evidence, seems very likely
Tags: carbon , oxygen , geol , oilg , mulitcarb

Tracing the evolution of seep fluids from authigenic carbonates: Green Canyon, northern Gulf of Mexico
Marine and Petroleum Geology (2013)
Youyan Bian, Dong Feng, Harry H. Roberts, Duofu Chen

Authigenic carbonates from hydrocarbon seeps are unique long-term archives of past fluid flow. The studied samples were collected from Green Canyon block 140 at a water depth of 260m in the Gulf of Mexico. Petrography, X-ray diffraction, stable isotopes and 14C dating were applied to assess the evolution of seep activity and potential driving forces. The carbonates are dominated by high-Mg calcite (HMC) and aragonite, with a minor amount of low-Mg calcite (LMC) and dolomite. Petrographically, peloids, clotted microfabric, acicular aragonite and a variable content of bioclasts were observed. Three types of carbonates are recognized. Structure I carbonates, with 14C ages from 46.5ka to 25.8ka BP, are characterized by ??13C values from-23.2??? to 5.1???, suggesting multiple carbon sources that include thermogenic methane, biodegraded crude oil, seawater and residual CO2 from methanogenesis at greater depth. In contrast, Structure II carbonates formed between 17.6ka and 11.7ka BP and have ??13C values varying from-22.2??? to-8.8???, suggesting carbon sources similar to those of Structure I carbonates but with a negligible influence of residual CO2 from methanogenesis. In addition, the presence of LMC in this type of carbonate may be associated with brine seepage. Structure III carbonates among the youngest of the samples analyzed with 14C ages of 1.2ka BP. These carbonates have the most negative ??13C values ranging from-36.1??? to-26.8???, suggesting that thermogenic methane is the primary carbon source. The majority carbonates of both Structure I and II are slightly 18O-enriched, which is most likely related to the incorporation of water from dehydration of clay minerals. The considerable range of mineralogical and isotopic variations of the studied carbonates highlights the local control of the seepage flux. It is proposed that factors affecting the activity of hydrocarbon seeps are sea level changes and salt movement. The combination of petrography, stable isotopes, and dating approach used here, highlights that these are valuable tools to assess the variability of past fluid flow at hydrocarbon seeps. ???Authigenic carbonates are excellent archives of past fluid flow at cold seeps. ?? 2013 Elsevier Ltd.
Tags: carbon , oxygen , geol , oilg , gashead