Different Levels Of Thermal Maturity Research Articles

Characterizing petroleum in source-rock core samples using HRGC data

Solvent extracts obtained from center-cut horizontal core plugs selected in the Upper Wolfcamp (UW) and Eagle Ford source-rock (SR) beds contain unaltered volatile (i.e., gasoline range) hydrocarbon (HC) compounds because they are extracted in a closed vial. Therefore, a C7 source parameter, a C7 maturity parameter, and pristane/phytane ratios are used to compare the source and thermal maturity of these petroleum and oil samples produced from nearby wells landed in the same SR reservoirs. Five distinct pay zones previously identified in the UW SR reservoir using geologic criteria each contain slightly different kinds of petroleum generated at different levels of thermal maturity. A thick overlying carbonate reservoir contains the kind of petroleum generated by the kerogen present in one underlying SR pay zone. The same source and maturity parameters demonstrate that the oil-prone kerogen present in the Eagle Ford SR beds in core plugs selected from wells located ≈7.5 mi (12 km) apart on the San Marcos Arch in South Texas formed in different depositional environments. It is difficult to allocate commingled oil samples using only core-plug extracts because solvents extract the producible oil plus a component that does not readily flow from SR reservoirs because it is sorbed in kerogen and/or on clay minerals. However, because only saturate HC compounds are used to determine the C7 source and maturity parameters, they provide valuable insights about the nature of the free oil present in SR reservoirs and commingled oil samples.

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

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

Thermal maturity of the Hawasina units and origin of the Batinah Mélange (Oman Mountains): Insights from clay minerals

The Oman Mountains developed during Cretaceous to Cenozoic time by obduction of the Semail Ophiolite on top of the Arabian rifted margin. The tectonic pile of the orogenic system is composed of three major domains, which from bottom to top are: (i) the proximal domain of the Arabian rifted margin; (ii) the Hawasina Nappe, including rocks pertaining to the distal portions of the Arabian rifted margin; (iii) the Upper Cretaceous Semail Ophiolite. However, in NE Oman (Batinah Coastal Plain), exposures of Hawasina rocks are resting above the ophiolite.What is the origin of the uncommon structural position of Hawasina rocks in the Batinah Coastal Plain? To address this question, an extensive dataset of X-ray diffraction analyses from rocks of the Hawasina units has been used to reconstruct their thermal and burial history since the Late Cretaceous. Temperature-dependent clay minerals indicate that the Hawasina units experienced different levels of thermal maturity from early diagenetic to anchizone conditions depending on their structural position during orogenic build-up. Rocks from the Hawasina units resting above the ophiolite contain random-ordered mixed layer illite-smectite (I–S) with an illite content between 30 and 45% displaying low levels of thermal maturity reflecting early diagenetic conditions that were acquired because of limited sedimentary burial (600 m) and minor heating during the early Pliocene. Deep-water rocks of the Hawasina units below the ophiolite are characterized by long-range ordered mixed layer I–S with an illite content between 80 and 90% and by a mineralogical assemblage of rectorite and pyrophyllite displaying more evolved levels of thermal maturity in deep diagenetic/anchizone conditions that were acquired during the obduction of the 4100 to 5500 m thick Semail Ophiolite. We finally propose a new evolutionary scheme for the genesis of the Batinah Mélange, that was not buried by the ophiolite but was transported by gravity-driven mass transport on top of the ophiolite. Our results may further improve the assessment of thermal maturity of Arabian passive margin deposits for hydrocarbon exploration purposes.

Preliminary Investigation of the Effects of Thermal Maturity on Redox-Sensitive Trace Metal Concentration in the Bakken Source Rock, North Dakota, USA.

Samples were taken at different levels of thermal maturity in the unconventional Bakken source rock. Programmed pyrolysis derived Tmax, solid bitumen reflectance, liptinite group maceral UV fluorescence, and nuclear magnetic resonance spectroscopy as different thermal maturity indicators were utilized in order to compare redox-sensitive trace metal (TM) concentration to maturity variations and disclose any probable relationship. Comparing redox-sensitive TMs with total organic carbon revealed the presence of anoxic/euxinic conditions in the depositional environment of the Bakken Shale. Although some of the TMs (V and Mo) exhibit slightly positive correlations with some of the thermal maturity indices used in this study, the correlations between other redox-sensitive TMs with maturity were neutral. Collectively, this study demonstrates that thermal maturity may have an impact on some redox-sensitive TMs such as Mo and V concentrations in marine sediments. Additional samples spanning higher maturities will need to be included because there is a possibility that an increase in thermal maturity may lead to the release and liberation of some redox-sensitive TMs from the organic matter (OM) directly. Remineralization and decomposition of OM with thermal maturity advance could release sulfur as a source of thermogenic H2S, which could accelerate pore water/rock interaction and authigenic Fe-sulfides. This could enhance the capability of uptaking of most of the redox-sensitive TMs and increase their concentration in pore water.

The effect of thermal maturity on porosity development in the Upper Devonian –Lower Mississippian Woodford Shale, Permian Basin, US: Insights into the role of silica nanospheres and microcrystalline quartz on porosity preservation

Organic-matter pores are considered to be the dominant contributor to total porosity in many shale reservoirs, and consequently much attention has been paid to investigate the factors influencing their generation, especially thermal maturity. Recent studies have shown that in addition to maturation of organic matter, other diagenetic processes also play important roles in evolution of pore systems, including compaction, mineral dissolution, and quartz cementation. This study investigates the effect of thermal maturity on porosity development in the siliceous Woodford Shale by integrating multiple techniques including helium pycnometry, low pressure gas (N2) adsorption, mercury injection capillary pressure, and field emission scanning electron microscopy (SEM) analyses. We compare samples from two long cores from Woodford Shale at different levels of thermal maturity, one in the early oil window (average calculated Ro = 0.69%) and the other in the wet gas window (average calculated Ro = 1.34%).Porosity, pore size, type, and volume vary systematically with the thermal maturity increasing from early oil window to wet gas window. Porosity measured by helium pycnometry averages 4.1% for early oil window samples, and increased by approximately 50% for the wet gas window samples (average porosity =6.3%). Both pore size and pore throat size distributions display decreasing trends from early oil window to wet gas window. Petrographic examination of SEM images shows that pores developed between clay platelets dominate in the early oil window samples, and secondary organic-matter pores are the dominant pore type in wet gas window samples. Porosity shows no obvious correlation to TOC content in both oil window and gas window samples, but correlates positive to silica content, suggesting that silica content largely controls variations in porosity. Both silica nanospheres and microcrystalline quartz were observed and appear to be significant in preserving pores from compaction by forming rigid frameworks that prevent pores from collapsing. Generation of secondary organic-matter pores and preservation of primary pores by silica nanospheres account for the net porosity increase from early oil window to wet gas window.

Hydrocarbon-generating potential of the Eocene Thebes Formation, Gulf of Suez: 1D basin modeling as a supplementary tool for source rock evaluation

The present work provides high-resolution modeling of the thermal maturation of the Eocene Thebes Formation using a multi-1D approach. The model focuses not solely on the thermal maturity but also on timing of hydrocarbon generation (primary generation and secondary cracking), adsorption by organic matter, and expulsion. The time-lapse conceptual model was developed using well log data, geochemical analyses, and composite logs. The stratigraphic sequence of the Belayim Marine oil field was subdivided into a time series based on the tectonic framework of the Gulf of Suez. An elevated basal heat flow has been assigned throughout the rifting phases and basin evolution. The simulation developed for seven wells reveals variations in burial, thermal history, and accordingly the thermal maturity. The predicted thermal maturity ranges from immature to mature with a different tendency to generate hydrocarbons (both primary generation of oil and/or gas secondary cracking) dependent on kerogen type, basin development, and burial history. Hydrocarbon generation (oil) starts after the Messinian Time Event during the deposition of the Post-Zeit Formation. Hydrocarbon generation was related to burial rather than basin evolution for the 113-M-27, BM-23, BM-65, and BM-70 wells. Conversely, generation correlated principally to basin development particularly Messinian Time Event for the 113-M-34 well. Expulsion occurred subsequent to generation of thermogenic gas (secondary cracking of generated oil). It is not possible to investigate the relationship between the production index and thermal maturity as a consequence of expulsion that reduced the S1 values. The different levels of thermal maturity (potential, active, and effective source rock) allow for the differentiation of regions of potential hydrocarbon accumulation that were charged from the Thebes Formation.

Pyrolysis S2-peak characteristics of Raniganj shales (India) reflect complex combinations of kerogen kinetics and other processes related to different levels of thermal maturity

The Permian shales of the Raniganj basin, India, have experienced a dramatic burial history of rapid subsidence (Jurassic-Early Cretaceous) followed by igneous intrusion (Cretaceous) and rapid uplift and erosion (Late Cretaceous-Tertiary). This has left these shales with mixed kerogen macerals with a characteristic thermal signature, ranging from early mature to post mature, which is reflected in the characteristics of their pyrolysis S2 peak. Many of these shales are today at peak thermal maturity but reached that condition more than 100 million years ago. They have significant potential to be exploited as a shale gas resource and their S2 peak characteristics should help to identify sweet spots for such exploitation. Here we analyze single-rate and multi-rate heating ramp Rock-Eval data from a suite of these shales at varying stages of thermal maturity. The S2 peak shapes provide significant insight to the kerogen kinetics involved in their thermal evolution. However, detailed fitting of the peak shapes with kerogen-kinetic mixing models indicate that factors other than static first-order reaction kinetics are also involved in their S2-peak-shape characteristics. Such factors likely include the catalytic effects, influenced by sulfur and charcoal, on some kerogen components, and kerogen pore-size distribution changes during their complex burial and thermal maturation histories. It is likely that the peak-mature shales contain significant, already generated, gas trapped within some of the kerogen nanopores that may be released during the S2 pyrolysis heating ramp rather than during the S1 heating ramp. This causes the S2 peak to broaden in the mature shales, a characteristic that could be used as an exploration marker for zones best suited to shale gas exploitation. Cited as : Wood, D.A., Hazra, B. Pyrolysis S2-peak characteristics of raniganj shales (India) reflect complex combinations of kerogen kinetics and other processes related to different levels of thermal maturity. Advances in Geo-Energy Research, 2018, 2(4): 343-368, doi: 10.26804/ager.2018.04.01

Potential for analysis of carbonaceous matter on Mars using Raman spectroscopy

The ESA/Roscosmos ExoMars rover will be launched in 2018. The primary aim of the mission will be to find evidence of extinct or extant life by extracting samples from the subsurface of Mars. The rover will incorporate a drill that is capable of extracting cores from depths of up to 2m, a Sample Preparation and Distribution System (SPDS) that will crush the core into small grains and a suite of analytical instruments. A key component of the analytical suite will be the Raman Laser Spectrometer (RLS) that will be used to probe the molecular and mineralogical composition of the samples. In this work we consider the capability of the proposed Raman spectrometer to detect reduced carbon (possibly associated with evidence for extinct life) and to identify the level of thermal alteration/maturity. The Raman analysis of 21 natural samples of shale (originating from regions exhibiting different levels of thermal maturity) is described and it is shown that reduced carbon levels as low as 0.08% can be readily detected. It is also demonstrated that the Raman spectra obtained with the instrument can be used to distinguish between samples exhibiting high and low levels of thermal maturity and that reduced carbon can be detected in samples exposed to significant levels of oxidation (as expected on the surface of Mars).

Diamondoid and biomarker characterization of oils from the Llanos Orientales Basin, Colombia

Because of their thermal and biological resistance, diamondoids have been used to assess the thermal maturity of light oils and condensates. Combined with biomarker data, they have also been applied to the characterization of mixtures of oils with contrasting maturity levels from distinct migration pulses in a single petroleum accumulation. We analyzed 22 oils from a Colombian sedimentary basin using gas chromatography coupled with mass spectrometry (GC/MS) to identify and characterize their biomarker and diamondoid distributions. Ratios of diamondoids and biomarkers provide a more refined maturity assessment because most of the oils have been biodegraded. Our integrated interpretation of the biomarker and diamondoid data allowed us to recognize different levels of thermal maturity in the oils, as well as to consider possible mixtures of oils from distinct migration pulses.

Origin and occurrence of crude oil in the Niger delta, Nigeria

Ten crude oils samples from onshore and offshore Niger delta were characterized based on their biomarkers and isotopic composition by Gas chromatography–Mass spectrometry and Isotope mass spectrometry. Abundance of pentacyclic triterpanes of hopane and oleanane skeletons and C 27–C 29 steranes in the oils indicates that they were formed from a mixed source (marine and terrestrial kerogen). The oleanane concentrations permit source grouping of the oils into three families. Various maturity parameters computed for the oils, especially those of aromatic biomarkers and aromatic sulfur compounds (thiophenes) to some extent reveal an increasing thermal maturity with increasing reservoir depths. The carbon isotope values lacked sufficient variation to distinguish maturity differences in the oils. This observation is quite revealing in that oils whose associate gases had earlier revealed a consistent increase in maturity with increasing depths, also have similar maturity values. The implication of this is that the oils and associated gases might have been formed at different levels of thermal maturity before being pooled together during migration into their present habitat.

Acidic and neutral polar NSO compounds in Smackover oils of different thermal maturity revealed by electrospray high field Fourier transform ion cyclotron resonance mass spectrometry

Negative ion electrospray ionization (ESI) coupled with high field Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR-MS) allows for the direct detection of acidic NSO compounds in petroleum. The technique requires no chromatographic separation, is able to distinguish 18 different compound classes (e.g., neutral nitrogen, carboxylic acids and oxygenates), and can identify ∼14,000 distinct masses by ultra-high mass resolution and mass accuracy. We previously studied three crude oils from different geological origins [Organic Geochemistry 33 (2002b) 743–759]. Here, we expand our research by comparing two source-equivalent Smackover oils of different levels of thermal maturity. We observe clear differences in the distribution of NSO compound classes, types (number of rings plus double bonds within a class), and number of alkyl carbons. With increasing thermal stress, the relative amount of sulfur and oxygen containing compounds decreases, condensation and aromatization of the polar cores increase, and the number of alkyl carbons decreases, reflecting the distribution of saturated hydrocarbons.

Classification of Duvernay sourced oils from central and southern Alberta using Compound Specific Isotope Correlation (CSIC)

ABSTRACT A suite of 27 oils from predominantly Nisku reservoirs of the Western Canada Sedimentary Basin (WCSB), in central and southern Alberta, can be classified into six groups or families based on stable carbon isotope ratios of individual gasoline range (C5-C10) compounds. A novel analytical technique combining Solid Phase MicroExtraction (SPME) and Continuous Flow Isotope Ratio Mass Spectrometry (CF-IRMS) is employed to measure the 13C/12C ratios. The majority of oils show characteristics of generation from a common source rock, the Upper Devonian Duvernay Formation. Systematic isotope distributions in straight chain and branched alkanes can help to delineate a common source rock along with the influence of secondary alteration processes such as biodegradation, evaporation, and thermochemical sulfate reduction. A 1-2‰ enrichment in 13C between groups can distinguish different levels of thermal maturity during oil genesis. Numerous analytical challenges are inherent in obtaining accurate 13C measurements for gasoline range analytes, but when utilized in conjunction with biomarkers and other compound specific geochemical techniques, the isotopic composition of these compounds exhibits good potential as a correlation tool. End_Page 99-------------------------

Rock-Eval Tmax Suppression: Documentation and Amelioration

The Rock-Eval thermal maturation parameter (Tmax) may occasionally be suppressed relative to surrounding rock units. This is commonly assumed to result from either a bitumen contribution to the S2 peak or the presence of sulfur-rich (and hence thermally labile) kerogen. The phenomenon is frequently coincident with a high natural gamma-ray signature and elevated Rock-Eval hydrogen index (HI) and total organic carbon (TOC) contents. Determination of thermal maturity of such units relies either on the interpolation of Tmax from surrounding units or the direct estimation of the extent of suppression on a given sample. The latter may be required if the available samples are restricted to conventional or sidewall-core material representative of imited stratigraphic intervals. The Second White Speckled Shale (part of the Cretaceous Colorado Group) in the Alberta basin displays Tmax suppression over part of its thickness. A consistent relationship emerges from calculating a linear regression of Tmax as a function of either TOC or HI for several wells at different levels of thermal maturity. Below values of about 453°C (late oil window), Tmax is suppressed by about 1°C for every increase in HI of 50 mg hydrocarbon/g TOC. Thus Tmax suppression in the Second White Speckled Shale can be corrected by extrapolating all Tmax values to a constant HI of 100 to 150 mg hydrocarbon/g TOC, values typical of type III kerogen.

Character, origin and occurrence of natural gases in the Anadarko basin, southwestern Kansas, western Oklahoma and Texas Panhandle, U.S.A.

Natural gas production in the Anadarko basin comes from three geographically separated areas that can be differentiated by age of reservoir and by inferred nature of organic, thermal origin of the gases. In the central basin, non-associated gases are produced mainly from Upper Mississippian and Pennsylvanian sandstones. Gas samples are from reservoirs as much as 6588 m deep. Gases become isotopically heavier ( δ 13C 1-values range from −49.8 to −33.2‰) and chemically drier (C 2+-values range from 1–33%) with increasing level of thermal maturity. Gases were generated mainly from interbedded shales with type-III kerogen during the mature and post-mature stages of hydrocarbon generation. Deviations from the trend are due to vertical migration and mixing of gases generated at different levels of thermal maturity over the past 250 Myr. In the giant Panhandle-Hugoton field, non-associated gases are generally produced from Permian carbonates at depths of <900 m. Gases display little compositional variation (mean δ 13C 1-value is −43.2‰, mean C 2+-value is 14%). Because organic-rich, mature source rocks are not present in the area, gases probably were generated in the central basin from Pennsylvanian or older source rocks during the mature stage of hydrocarbon generation. This interpretation implies migration over distances as much as several hundred kilometers. In the Sooner Trend, associated gases are produced from Silurian, Devonian and Mississippian carbonates at depths as great as 2950 m and were generated from type-II kerogen during the mature stage of hydrocarbon generation. Associated oil usually correlates with extracts of the Upper Devonian and Lower Mississippian Woodford Shale. Gases are isotopically lighter (mean δ1 3C 1-value is −43.9‰) and chemically wetter (mean C 2+ value is 14%) than those derived from type-III kerogen at an equivalent level of thermal maturity.