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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:

Carbon isotope analyses of n -alkanes released from rapid pyrolysis of oil asphaltenes in a closed system
Rapid Communications in Mass Spectrometry (2016)
Shasha Chen, Wanglu Jia, Ping'an Peng

Rationale Carbon isotope analysis of n-alkanes produced by the pyrolysis of oil asphaltenes is a useful tool for characterizing and correlating oil sources. Low-temperature (320–350°C) pyrolysis lasting 2–3 days is usually employed in such studies. Establishing a rapid pyrolysis method is necessary to reduce the time taken for the pretreatment process in isotope analyses. Methods One asphaltene sample was pyrolyzed in sealed ampoules for different durations (60–120 s) at 610°C. The δ13C values of the pyrolysates were determined by gas chromatography/combustion/isotope ratio mass spectrometry (GC/C/IRMS). The molecular characteristics and isotopic signatures of the pyrolysates were investigated for the different pyrolysis durations and compared with results obtained using the normal pyrolysis method, to determine the optimum time interval. Several asphaltene samples derived from various sources were analyzed using this method. Results The asphaltene pyrolysates of each sample were similar to those obtained by the flash pyrolysis method on similar samples. However, the molecular characteristics of the pyrolysates obtained over durations longer than 90 s showed intensified secondary reactions. The carbon isotopic signatures of individual compounds obtained at pyrolysis durations less than 90 s were consistent with those obtained from typical low-temperature pyrolysis. Several asphaltene samples from various sources released n-alkanes with distinct carbon isotopic signatures. Conclusions This easy-to-use pyrolysis method, combined with a subsequent purification procedure, can be used to rapidly obtain clean n-alkanes from oil asphaltenes. Carbon isotopic signatures of n-alkanes released from oil asphaltenes from different sources demonstrate the potential application of this method in ‘oil–oil’ and ‘oil–source’ correlations.
Tags: carbon , oilg , gaschrom

Carbon isotope analyses of n -alkanes released from rapid pyrolysis of oil asphaltenes in a closed system
Rapid Communications in Mass Spectrometry (2016)
Shasha Chen, Wanglu Jia, Ping'an Peng

Rationale Carbon isotope analysis of n-alkanes produced by the pyrolysis of oil asphaltenes is a useful tool for characterizing and correlating oil sources. Low-temperature (320–350°C) pyrolysis lasting 2–3 days is usually employed in such studies. Establishing a rapid pyrolysis method is necessary to reduce the time taken for the pretreatment process in isotope analyses. Methods One asphaltene sample was pyrolyzed in sealed ampoules for different durations (60–120 s) at 610°C. The δ13C values of the pyrolysates were determined by gas chromatography/combustion/isotope ratio mass spectrometry (GC/C/IRMS). The molecular characteristics and isotopic signatures of the pyrolysates were investigated for the different pyrolysis durations and compared with results obtained using the normal pyrolysis method, to determine the optimum time interval. Several asphaltene samples derived from various sources were analyzed using this method. Results The asphaltene pyrolysates of each sample were similar to those obtained by the flash pyrolysis method on similar samples. However, the molecular characteristics of the pyrolysates obtained over durations longer than 90 s showed intensified secondary reactions. The carbon isotopic signatures of individual compounds obtained at pyrolysis durations less than 90 s were consistent with those obtained from typical low-temperature pyrolysis. Several asphaltene samples from various sources released n-alkanes with distinct carbon isotopic signatures. Conclusions This easy-to-use pyrolysis method, combined with a subsequent purification procedure, can be used to rapidly obtain clean n-alkanes from oil asphaltenes. Carbon isotopic signatures of n-alkanes released from oil asphaltenes from different sources demonstrate the potential application of this method in ‘oil–oil’ and ‘oil–source’ correlations
Tags: carbon , oilg , gaschrom

Multiphase dolomitization of deeply buried Cambrian petroleum reservoirs, Tarim Basin, north-west China
Sedimentology (2016)
Lei Jiang, Chunfang Cai, Richard H. Worden, Stephen F. Crowley, Lianqi Jia, Ke Zhang, Ian J. Duncan

Cambrian dolostone reservoirs in the Tarim Basin, China, have significant potential for future discoveries of petroleum, although exploration and production planning is hampered by limited understanding of the occurrence and distribution of dolomite in such ancient rocks buried to nearly 8 km. The study herein accessed new drill core samples which provide an opportunity to understand the dolomitization process in deep basins and its impact on Cambrian carbonate reservoirs. This study documents the origin of the dolostone reservoirs using a combination of petrology, fluid-inclusion microthermometry, and stable and radiogenic-isotopes of outcrop and core samples. An initial microbial dolomitization event (D1) occurred in restricted lagoon environments and is characterized by depleted δ13C values. Dolomicrite (D2) from lagoonal and sabkha facies, some fabric-retentive dolomite (D3) and fabric-obliterative dolomite (D4) in the peloidal shoal and reef facies show the highest δ18O values. These dolomites represent relatively early reflux dolomitization. The local occurrence of K-feldspar in D2 indicates that some strontium was contributed via terrigenous input. Most fabric-retentive dolomite (D3) may have precipitated from seawater at slightly elevated temperatures, suggested by petrological and isotopic data. Most fabric-obliterative dolomite (D4), and medium to coarse dolomite cement (D5), formed between 90°C and 130°C from marine evaporitic brine. Saddle dolomite (D6) formed by hydrothermal dolomitization at temperatures up to 170°C, and involved the mixing of connate brines with Sr- enriched hydrothermal fluids. Intercrystalline, moldic, and breccia porosities are due to the early stages of dolomitization. Macroscopic, intergranular, vuggy, fracture, and dissolution porosity are due to buial-related dissolution and regional hydrothermal events. This work has shown that old (for example, Cambrian or even Precambrian) sucrosic dolomite with associated anhydrite, buried to as much as 8000 m, can still have a high potential for hosting large hydrocarbon resources and should be globally targeted for future exploration.
Tags: carbon , geol , oilg , gashead

A THIRD-ORDER UNCONFORMITY WITHIN LOWER ORDOVICIAN CARBONATES IN THE TARIM BASIN, NW CHINA: IMPLICATIONS FOR RESERVOIR DEVELOPMENT
Journal of Petroleum Geology (2016)
Gao Zhiqian, Fan Tailiang, Ding Qunan, Hu Xiaolan

This paper presents outcrop, petrographic, geochemical, well log and seismic data which together characterise the third-order T78 unconformity located between the carbonate-dominated Lower Ordovician Penglaiba and Yingshan Formations in the Tarim Basin, NW China. Unconformities in Lower Palaeozoic carbonates in this basin are of increasing interest because major reserves of hydrocarbons have recently been discovered at the North Slope field (> 1000 × 106 brls oil and ∼ 3050× 108 m3 gas). The reservoir here consists of karstified Lower Ordovician carbonates bounded by a third-order unconformity. The T78 unconformity in Tarim Basin represents a short-term exposure surface (< 1 Ma) controlled both by sea-level changes and by palaeogeographic location within the basin, and the intensity of karstification varies laterally. The unconformity has had a major influence on porosity development in the underlying Penglaiba Formation carbonates. At two measured outcrop sections at the NW basin margin (Penglaiba and Shuinichang), dissolution porosity was observed in karstified and dolomitised carbonates below the T78 unconformity surface. A seismic profile shows the presence of reflection anomalies below the unconformity which are interpreted as karst-related palaeo-caverns. Geochemical data indicate that the T78 unconformity is associated with anomalies in stable isotope ratios and in heavy mineral and trace element profiles. Thus there are negative excursions in δ13C and δ18O ratios within the carbonate rocks immediately below the unconformity surface. Similarly, concentrations of major and trace elements such as Li, K, Ti, Rb, Th, Sr, V and Ni are significantly reduced in the underlying carbonates, while there is an anomalously high content of haematite-limonite.
Tags: carbon , oxygen , geol , oilg , gashead

A THIRD-ORDER UNCONFORMITY WITHIN LOWER ORDOVICIAN CARBONATES IN THE TARIM BASIN, NW CHINA: IMPLICATIONS FOR RESERVOIR DEVELOPMENT
Journal of Petroleum Geology (2016)
Gao Zhiqian, Fan Tailiang, Ding Qunan, Hu Xiaolan

This paper presents outcrop, petrographic, geochemical, well log and seismic data which together characterise the third-order T78 unconformity located between the carbonate-dominated Lower Ordovician Penglaiba and Yingshan Formations in the Tarim Basin, NW China. Unconformities in Lower Palaeozoic carbonates in this basin are of increasing interest because major reserves of hydrocarbons have recently been discovered at the North Slope field (> 1000 × 106 brls oil and ∼ 3050× 108 m3 gas). The reservoir here consists of karstified Lower Ordovician carbonates bounded by a third-order unconformity. The T78 unconformity in Tarim Basin represents a short-term exposure surface (< 1 Ma) controlled both by sea-level changes and by palaeogeographic location within the basin, and the intensity of karstification varies laterally. The unconformity has had a major influence on porosity development in the underlying Penglaiba Formation carbonates. At two measured outcrop sections at the NW basin margin (Penglaiba and Shuinichang), dissolution porosity was observed in karstified and dolomitised carbonates below the T78 unconformity surface. A seismic profile shows the presence of reflection anomalies below the unconformity which are interpreted as karst-related palaeo-caverns. Geochemical data indicate that the T78 unconformity is associated with anomalies in stable isotope ratios and in heavy mineral and trace element profiles. Thus there are negative excursions in δ13C and δ18O ratios within the carbonate rocks immediately below the unconformity surface. Similarly, concentrations of major and trace elements such as Li, K, Ti, Rb, Th, Sr, V and Ni are significantly reduced in the underlying carbonates, while there is an anomalously high content of haematite-limonite.
Tags: carbon , oxygen , geol , oilg , gashead

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.

Fluid flow and related diagenetic processes in a rift basin: Evidence from the fourth member of the Eocene Shahejie Formation interval, Dongying depression, Bohai Bay Basin, China
AAPG Bulletin (2016)
Kenneth A. Eriksson Benben Ma, Benjamin C. Gill

The purpose of this paper is to relate diagenetic processes in deeply buried sandstones in the fourth member of the Eocene Shahejie Formation interval, Bohai Bay Basin, China, to pore-fluid flow changes with progressive burial. Based on petrographic, mineralogical, and geochemical analysis, distribution patterns of authigenic minerals are recognized that reflect (1) the sources and patterns of fluid flow and (2) fluid flow in an evolving open-to-closed system. Partial to extensive precipitation of calcite and dolomite at or near mudstone–sandstone contacts during eogenesis was a result of large-scale mass transfer between sandstones and adjacent mudstones. This process was driven by steep diffusion gradients from adjacent mudstones in a relatively open geochemical system on the local scale. Support for this model is provided by large sulfur isotope fractionation between framboidal pyrite and precursor gypsum. Dissolution of feldspar grains and dissolution of nonferroan carbonate cements during early mesogenesis are spatially associated with quartz and ferroan carbonate cementation, respectively. This process was related to organic carbon dioxide expelled from adjacent source rocks and indicates a relatively open system. During late mesogenesis, dissolution of evaporitic cements related to thermochemical sulfate reduction (TSR) generated ankerite and nodular pyrite cements in adjacent pores. A lack of sulfur isotope fractionation between parent anhydrite and late-stage, nodular pyrite during TSR supports a relatively closed fluid-flow system. Because the velocities of pore-fluid flow were low during mesogenesis, large-scale thermal convection and advection probably did not occur. Instead, diffusion over short distances is inferred as the predominant transport mechanism for dissolved solids that were precipitated as other phases either in situ or in adjacent pores.

Origin of crude oils from oilfields in the Zagros Fold Belt, southern Iraq: Relation to organic matter input and paleoenvieromntal conditions
Marine and Petroleum Geology (2016)
Mohammed Hail Hakimi, Ahmed Askar Najaf

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterised by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (< 1), high values of the C35 homohopane index and C31-22R/C30 hopane ratios, relatively high C27 sterane concentrations, and the predominance of C29-norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition. The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks.

Source rock potential of lower-middle miocene lacustrine deposits: Example of the küçükkuyu formation, NW Turkey
Oil Shale (2015)
Ayşe Bozcu

The purpose of this study was to examine the geological, stratigraphic and organic geochemical features of the Küçükkuyu Formation outcropping on Biga Peninsula, NW Turkey. The Lower-Middle Miocene formation crops out around the Gulf of Edremit and near Bayramiç-Çan in the north of the Kazdağ Mountains. The unit is composed of shale, siltstone and sandstone intercalations. The shale is bituminous and represents a potential source rock in the region. Shale samples from the formation were investigated. Rock-Eval pyrolysis, vitrinite reflectance (Ro %), gas chromatography (GC), stable C isotope and total sulfur measurements were carried out. The shale is characterized by high total organic carbon (TOC) values (0.27 to 7.44 wt%, average 1.69 wt%), indicating a good potential source rock. The kerogen types are II and III, indicating the shale to be gas and oil-prone. Tmax values are between 352 and 453 °C, the average value suggesting early catagenesis. The pristane/ phytane (Pr/Ph) values reveal suboxic and anoxic environments. Carbon preference index (CPI) and C isotope values reveal terrestrial OM. Geological and stratigraphic evaluations and total sulfur (TS) figures indicate that the Küçükkuyu Formation was deposited in a suboxic-anoxic, freshwater environment (lacustrine), developing brackish water conditions from time to time.
Tags: carbon , oilg , gaschrom

Microbial controls on the origin and evolution of coal seam gases and production waters of the Walloon Subgroup; Surat Basin, Australia
International Journal of Coal Geology (2015)
K A Baublys, S K Hamilton, S D Golding, S Vink, J Esterle

The Walloon Subgroup coal seam gas (CSG) play in the Surat Basin, Queensland, is Australia's pre-eminent onshore gas field. Concerted multi-disciplinary research is underway investigating the distribution, origin and composition of waters and gases in this dominantly microbial CSG reservoir, to guide both continued production and potential microbially enhanced coal bed methane (MECoM) applications. However, prior to the present research, a detailed study of co-produced waters and gases from across the Surat Basin was not available in the public domain. This study tested whether co-produced water compositional and stable isotopic data show relationships with production gas stable isotope compositions, to elucidate further evidence for microbial CO2 reduction and explore the down-dip geochemical evolution of Walloon coal bed waters and gases. A total of 41 wells were sampled with 50 water and 25 gas samples spanning the 3 major production areas of the Surat Basin. Detailed isotopic and hydrochemical analysis of these samples revealed distinct spatial trends between the different production locales. Water compositions were distinct for each of the production regions reflecting the different lithologies of adjacent recharge zones, differing fluid–rock interactions, likely different microbial consortia, and the extent of methanogenesis. On the western side of the basin near Roma, waters were the ‘freshest’ with the lowest median values for alkalinity (861 mg/L), and Cl− (588 mg/L) and a δ13CDIC of 14.2‰. On the eastern side of the basin, the Kogan Nose waters were the most saline with the highest median values for Na+ (1955 mg/L), Cl− (2280 mg/L) and δ13CDIC (20.0‰). Also in the east, in the present gas fairway, the Undulla Nose waters had the highest median alkalinity (1841 mg/L) and were found to have a Na+ excess (median = 1050 mg/L) and a lower than expected median δ13CDIC (14.0‰). Co-mingled, produced methane carbon isotope values (δ13C − 57.0‰ to − 44.5‰) from both the upper (Juandah) and lower (Taroom) coal measures plot within the mixed ‘thermogenic/microbial’ genetic field. By contrast, deuterium isotopic difference [Δ2H(H2O–CH4)] values and cross-plots of δ2H–H2O and δ18O–H2O suggest that microbially mediated CO2 reduction is the dominant methane generation process in situ. At a given depth, the Undulla Nose waters in the east are more depleted in 2H and 18O than elsewhere in the Surat Basin, which may suggest these samples have been more heavily impacted by water–rock–microbial reactions. 14C values from the 3 production regions (0.115 to 1.769 pmC; age: 32,400 to > 50,000 years before present (B.P.)) suggest that Walloon coals likely recharged in the last ~ 50,000 years (limit of radiocarbon dating). Consistent with these dates, δ2H–H2O and δ18O–H2O values for the Surat Basin (δ2H − 32‰ to − 56‰, δ18O − 5.9‰ to − 9.0‰) echo the stable isotopic composition of meteoric waters during the initial part of the last glacial period in southeast Queensland. Based on a strong correlation between δ2H–CH4 and δ2H–H2O, we suggest that methane was generated since the Late Pleistocene. PCA analysis showed a degree of positive correlation between total alkalinity and both the δ13CDIC (median 14.2‰) and δ13C–CH4 (median − 52.1‰) vectors that is consistent with finite reservoir effects. The results inform ongoing studies of gas distribution and origins and MECoM potential in the Surat Basin, and underpin a broader study examining aquifer interactions.
Tags: carbon , hydrogen , geol , oilg , gaschrom