Source Rock Thermal Maturity Research Articles

Letter from editor

<div class="page" title="Page 1"><div class="section"><div class="layoutArea"><div class="column"><p>Welcome to Earth Sciences Research Journal, Volume 18, Number 1. More than 20 years have passed since we decided to be part of the scientific world in geology, seismology, geophysics, geodesy, meteorology, oceanography, planetary sciences, and so many other fields. We raised our voice to say to the world that in Colombia, there is a Journal committed to providing the highest level of manuscript in Earth Sciences.</p><p><span>It has been not an easy road, but we are here. This 2014 has been full of challenges moving us to find the best ways to present new manuscripts. Our Volume 18 was made possible by the non-profit cooperation of authors and reviewers working hand-in- </span><span>hand with us. </span></p><p><span>In this volume, we are presenting to the eyes of scientific world nine papers coming from three different continents, with contributions by people from seven countries. Our first paper comes from Egypt, about an aeromagnetic data analysis in the region of Fayoum-Cairo. This work regarding the October 12, 1992 earthquake, suggests how the new tectonics of Africa’s northeast is predominant in this area. From Turkey, our second manuscript obtained a new, important, more up-to-date and more reliable relationship between surface wave magnitude and rupture length for earthquakes in that country. The results obtained in this study will give some useful and up-to-date information to authors whose studies are focused in this area. </span></p><p><span>In the field of hydrogeology, the third article analyzes the hydrogeochemistry of shallow groundwater in the Yellow River alluvial plain. The results suggest that the shallow groundwater in the study area is fresh to moderately mineralized water. The assessment of samples shows how this water is acceptable for agricultural use but is not potable. From China, too, an interesting paper about the petrography and mineralogy of biotites within the Wushan granodiorite is presented. The formation conditions of these biotites are also determined and the significance of these minerals in terms of petrogenesis and mineralization is </span><span>discussed. </span></p><p><span>From India, where climate change is a topic trend, a study attempts to provide information on climate variability and its impacts on runoff in the Kosasthaliyar sub-basin. From Nigeria, a work related to aromatic biological markers are used for assessing thermal maturity of source rocks in the Campano-Maastrichtian Mamu formation. Results of this study show how these maturity values indicate that the coal and shale extracts are marginally mature for hydrocarbon generation. </span></p></div></div></div></div><div class="page" title="Page 2"><div class="layoutArea"><div class="column"><p><span>We invite you to read also three South American papers. From Colombia, the manuscripts titled “Enhancing time resolution by stabilized inverse filter and Q estimated on instantaneous spectra” and “Hydrocarbon Production Scenarios in Colombia. Review of Field Sizes, Hydrocarbon Reserves and Expectations of Conventional and Unconventional Resources” are presented. From Chile comes the paper “Uncertainty in rainfall input data in a conceptual water balance model: effects on outputs and implications for predictability”. </span></p><p><span>Thanks to every one of you and enjoy this issue of the ESRJ. </span></p></div></div></div>

MODELING OF HYDROCARBON POTENTIAL AND THERMAL MATURITY OF GONGILA SHALE, CHAD BASIN, NORTHEASTERN NIGERIA

The Bornu Basin, which represents a part of the Chad Basin in Nigeria, makes one-tenth of the total area of the Chad Basin that extends to the Republic of Niger, Chad and Cameroun. This basin is a sediment-filled broad depression straddling northeastern Nigeria and adjoining parts of the Republic of Chad. The cumulative thickness of the sedimentary rocks exceeds 3,600 metres. The Nigerian share of the Chad Basin is supposed to be a poten- tial hydrocarbon-producing basin. This is because commercial petroleum accumulations totalling over 120 billion barrels have been discovered in some parts of the basin outside Nigeria (largely in the Republic of Chad) in structurally related contiguous basins. The Gongila Formation (in the Chad Basin) is a transitional sequence between the underlying continental Bima sandstone and the overlying marine Fika shale. Determining whether the shale beds present in the Gongila Formation are matured enough to generate hydrocarbons, nine wells were used and the petro- physical parameters such as total organic carbon (TOC) and total organic matter (TOM) were calculated for each of the wells. The heat flow history of the basin was calculated by establishing the relationship between the modeled thermal maturity curve and the equivalent observed maturity parameter (vitrinite reflectance). Thereafter this calculated heat flow is used to predict thermal maturity of source rocks and the timing of hydrocarbon generation. The result obtained reveals that TOC and TOM of shale sequences in each well range from 3.58 to 27.48 wt% and from 1.15 to 8.79 wt%, respectively. Thus, TOC of the Gongila Formation exceeds the kerogen threshold of 0.5 wt% for the generation of hydrocarbons while TOM exceeds the kerogen threshold of 1 wt%. The heat flow was computed from the heat generation and was estimated to range between 33 and 75 mW/m 2 . The modeled vitrinite reflectance ranges between 0.56 and 0.76%Ro. It is concluded that the Gongila shale is a potential petroleum source rock. The temperature history is the factor controlling the maturation of organic compounds into fossil fuels. The Gongila Formation's thermal maturity,

Stable carbon and hydrogen isotopes of natural gases sourced from the Xujiahe Formation in the Sichuan Basin, China

The compound specific hydrogen and carbon stable isotope ratios of alkanes in natural gases from the Xujiahe and Jurassic formations in the western Sichuan Basin were investigated to distinguish between coal-derived and oil-associated gases. All gases were determined to be coal-derived and sourced from the Xujiahe Formation. Thermal maturities of the source rocks are expected to vary from 0.8–1.8% vitrinite reflectance (% R o) according to the empirical relationship between the measured δ 13C CH4 values and % R o, which is within the scope of the maturities of source rocks (0.7–2.1%). In particular, C 1–3 alkanes of primary coal-derived gases which have not undergone any secondary alteration become more enriched in deuterium with increasing molecular mass and the δD CH4 values increase with increasing thermal maturity of source rocks. In the Sichuan Basin, δD values of coal-derived gases sourced from terrigenous source rocks of the Xujiahe Formation are more negative than those of oil-associated gases sourced from marine organic matter of the Sinian, Permian and Triassic formations.

Diamondoid hydrocarbons as a molecular proxy for thermal maturity and oil cracking: Geochemical models from hydrous pyrolysis

A series of isothermal hydrous pyrolysis experiments was performed on immature sedimentary rocks and peats of different lithology and organic source input to explore the generation of diamondoids during the thermal maturation of sediments. Oil generation curves indicate that peak oil yields occur between 340 and 360 °C, followed by intense oil cracking in different samples. The biomarker maturity parameters appear to be insensitive to thermal maturation as most of the isomerization ratios of molecular biomarkers in the pyrolysates have reached their equilibrium values. Diamondoids are absent from immature peat extracts, but exist in immature sedimentary rocks in various amounts. This implies that they are not products of biosynthesis and that they may be generated during diagenesis, not just catagenesis and cracking. Most importantly, the concentrations of diamondoids are observed to increase with thermal stress, suggesting that they can be used as a molecular proxy for thermal maturity of source rocks and crude oils. Their abundance is most sensitive to thermal exposure above temperatures of 360–370 °C ( R 0 = 1.3–1.5%) for the studied samples, which corresponds to the onset of intense cracking of other less stable components. Below these temperatures, diamondoids increase gradually due to competing processes of generation and dilution. Calibrations were developed between their concentrations and measured vitrinite reflectance through hydrous pyrolysis maturation of different types of rocks and peats. The geochemical models obtained from these methods may provide an alterative approach for determining thermal maturity of source rocks and crude oils, particularly in mature to highly mature Paleozoic carbonates. In addition, the extent of oil cracking was quantified using the concentrations of diamondoids in hydrous pyrolysates of rocks and peats, verifying that these hydrocarbons are valuable indicators of oil cracking in nature.

The effect of allochthonous salt evolution and overpressure development on source rock thermal maturation: a two-dimensional transient study in the northern Gulf of Mexico Basin

Sequential two-dimensional forward modelling of source rock maturation along a north–south 600 km megaregional profile across the northern Gulf of Mexico Basin illustrates the coupled influence of allochthonous salt evolution and overpressure development on source rock maturation. Model results indicate that allochthonous salt evolution strongly affected local and regional source rock maturation, while overpressure development had a minor impact. Within the lower slope portion of the profile (south of the Sigsbee escarpment to the Tabular Salt/Minibasin province), localized thermal lows associated with salt stock development locally retarded the maturation of source rocks, while the slow development of overpressures effected little influence on the maturation. Within the centre of the profile (offshore Louisiana shelf), however, the evolution of allochthonous salt sheets and shallow salt structures locally and regionally lowered the oil generation window. The timing of overpressures in this region, related to the progradation of the Cenozoic marine depocentre, may have accelerated the maturation of middle Eocene source rocks, although the deeper Turonian source rocks had reached maturation at the time of greatest overpressure development. In the northern portion of the profile (southern Louisiana), the Terrebonne salt sheet lowered the oil generation window and retarded the maturation of the middle Eocene source rocks.

Are vanadyl porphyrins products of asphaltene/kerogen thermal breakdown?

The idea was examined that during early stages of thermal maturation of source rocks or petroleums, the release of bound vanadyl (VO 2+) porphyrins (P) from the immature asphaltenes or kerogen could contribute to an increase in extractable VO 2+-P. To simulate such a change in the laboratory, the Dead Sea ‘floating’ asphalt and total organic (bitumen + kerogen) fractions of the La Luna and Serpiano carbonaceous sedimentary rocks were heated at controlled temperatures (100, 200, 300 and 400°C) for different periods of time. Residual (and altered) asphaltenes or kerogens were then separated from the heated products and analysed for VO 2+-P content by electron spin resonance. Three conclusions were reached: (1) thermal degradation of immature asphaltenes or kerogen generated no or very little (<1 wt%) extractable VO 2+-P during simulated maturation of petroleums or source rocks and thus by inference during natural maturation; (2) petroleum VO 2+-P by far are those that were saved from incorporation into asphaltenes or kerogen precursors (or young asphaltenes or kerogen) during diagenesis; and (3) a high VO 2+-P content of a petroleum is not an indication of its immaturity.

Seismic Detection of Juvenile Reservoir Character Under Fluid Cushions (Including Mobile Salt and Geopressuring): ABSTRACT

Surface layers which can flow or release pressure via fluid leakage, and which support overburden in the subsurface most often represent difficult drilling. The incentive for penetrating such formations is typically high quality reservoirs which lie below them. We now begin to understand that if the fluid layer can move laterally or {open_quotes}leak{close_quotes} they effectively {open_quotes}shield{close_quotes} deeper units from some measure of the overburden induced compaction process. Of course, we know from the higher conductivity of the fluid layer and temperature profile that thermal maturation of source rocks below this fluid zone would be retarded as well. Hence we can anticipate that target reservoirs may exhibit juvenile reservoir character relative to their actual geologic age and depth. We may wish to use both well logs as well as seismic data in attempts to develop a method to detect such enhanced reservoir condition in advance of the drill. Emphasis here will focus on this measurement procedure rather than on the physics and mechanics of the flow and deformation process involved. Clearly these are worthy of study as well, but in our view at some later date.

Multiple Oil Families in the West Siberian Basin

Two major oil families are identified in the West Siberian basin. Twenty-six of 32 analyzed oils occur in Jurassic and Cretaceous reservoirs and are derived from anoxic marine Upper Jurassic Bazhenov source rock, based on geochemical comparison of oils and source rock extracts. These oils are widely distributed both north and immediately south of the Ob River, and their biomarker ratios indicate a wide range of source rock thermal maturity from early to middle oil window (Van-Egan, Russkoye, Samotlor, Sovninsko-Sovyet, Olyenye, Ozynornoye, and Kogolym), to peak oil window (Srednekhulym, Yem-Yegov, Vostochno-Surgut, Khokhryakov, Fedorov, and Urengoi), to late oil window (Salym). Some of these oils have been mildly (e.g., Fedorov 75) to heavily (e.g., Russkoye) biodegraded n the reservoir. The Bazhenov-sourced oils show different compositions that support regional variations of organic facies in the source rock. For example, the anoxic marine Bazhenov facies, which generated the oils in the Samotlor, Fedorov, and nearby fields, was particularly clay poor and sulfur rich. Six nonbiodegraded, highly mature oils show geochemical characteristics that suggest they were derived from clastic-rich lacustrine or nearshore marine source rocks dominated by terrigenous higher plant input like those in the Lower to Middle Jurassic Tyumen Formation, although no correlation was observed between the oils and a single rock sample (Yem-Yegov 15) from the formation. The six oils occur in the Tyumen (Taitym, Geologiche, and Cheremshan) and fractured basement/Paleozoic (Gerasimov, Yagyl Yakh, and Verchnekombar) reservoirs in positions readily accessible to any oil migrating from the Tyumen source rock. For example, at the Gerasimov location, the Tyumen Formation lies unconformably on weathered basement-Paleozoic reservoir rocks. Most of the probable Tyumen-sourced oils ar from south of the Ob River, but the occurrence of Geologiche oil to the north suggests that related oils may be widespread in the basin.

Quantitative Models for the Influence of Salt-Associated Thermal Anomalies on Hydrocarbon Generation, Northern Gulf of Mexico Continental Margin

ABSTRACT Salt and related structures are important in initiating and storing hydrocarbons along the northern Gulf of Mexico. Using models which allow for both conduction and convection of heat, an examination is given of the thermal patterns associated with various salt features. The focusing and defocusing of heat (due to 2-3 times greater thermal conductivity of salt compared to sediments) are incorporated into the modeling. Results for present day salt and sediment distributions indicate a 30°C greater anomaly above salt features due to thermal focusing, and as much as a 50°C contrast between temperatures within a salt diapir/ridge and a regional sediment column. Calculated rates of salt motion are up to 7 and 17 cm/yr (salt wedge migrating uniformly during Plio-Pleistocene and only during lowstands, respectively during the past 2.5 M. Y.) for slope domains, and of order cms/1000 yrs for salt pillows under the inner shelf, coastal plain, and interior basins. Slow moving salt features advance leisurely enough to permit thermal maturation of source rocks, concomitantly with the moving salt. Source and reservoir could therefore be in the same site. Rapidly migrating salt moving at about a km in 10,000 yrs may outdistance recently produced hydrocarbons. Reservoirs associated with the moving salt (and possibly with fracture-induced permeability as a consequence of the passage of the salt) could then act to entrap the migrating hydrocarbons even though the reservoirs may be in the immature thermal zone.

Maturation thermique des roches mères dans les bassins des basses-terres du Saint-Laurent et dans quelques buttes témoins au sud-est du Bouclier canadien

Caradocian source rocks belonging to the Utica Group occur around and overlay the southeastern part of the Canadian Shield from the Ottawa embayment, in the southwestern part of St. Lawrence Lowlands, to the Anticosti Island basin. The kerogen of the source rocks is mainly made up of amorphous organic matter (transmitted light), resembling a solid bitumen framework in reflected light, and contains a small portion of zooclasts (graptolites and chitinozoans). The kerogen is often too mature to have preserved the structure of the original constituents, except those of graptolites and chitinozoans. Otherwise, UV fluorescent colonial alga and tasmanites are observed. In the eastern half of the St. Lawrence Lowlands, stratigraphic and tectonic burial is the main control of source rock thermal maturation. From an area located 50 km west of Quebec City, the estimated vitrinite reflectance ( R o-Std) of the source rock increases in both northeastern (Montmorency Falls) and southwestern (St. Maurice River) directions, from R o-Std of 1.2 to 1.5 and 1.7%, respectively. The source rocks of the Ottawa embayment and Montreal area (western half of the basin) are overmature due to hydrothermal and igneous activities (2.3%< R o-Std<2.8%).. In Chicoutimi and Lac Saint-Jean outliers, the source rocks show reflectances between 0.9 and 1.2%, slightly less than reflectance values in the Quebec City area ( R o-Std between 1.2 and 1.5%). On Anticosti Island, the thermal maturation is related to burial only and increases downdip of the inclined platform, from the northeast toward the southwest ( R o-Std between 0.9 and 2.1%). These observations suggest that the St. Lawrence platform and the southeastern Canadian Shield were buried by at least 3.5 km of Paleozoic strata prior to erosion to Grenville basement. This implies that most potential hydrocarbon fields are presumably also lost by erosion.

Salt Emplacement and Its Impact on the Thermal Maturation of Source Rocks: Application of a Modified 1-D Thermal Indicator Tomography

The presence of salt in various shapes in the subsurface can have a significant impact on the subsurface temperature distribution and thermal maturation of source rocks, due to the contrast in thermal conductivity between salt and typical sedimentary formations. An anomaly can be induced in reconstruction of the thermal and hydrocarbon generation histories for the basin when contrasting the temperature data and maturity markers from salt structures with the areas distant from salt. Results of using an updated thermal indicator tomography 1-D modeling system that deals with salt emplacement demonstrate that a thermal anomaly and excess maturity can be caused solely by the presence of a salt layer. Further, the timing of salt emplacement and the variation of salt thickness can be determined. As a case history, the technique is applied in the Sogne basin Lulu 1 well, located in the northeast part of the Danish Central graben. By following the regional heat flow pattern for the Sogne basin and considering the effect of salt (maximum thickness about 3,000 m) in the well on thermal maturity anomalies, the modeled maturity and hydrocarbon generation become more reliable and accurate.

Relationships Among Oil Density, Gross Composition, and Thermal Maturity Indicators in Northeastern Williston Basin Oils and Their Significance for Expulsion Thresholds and Migration Pathways

Oil density ({degree}API), gross composition, and biological market thermal maturity variations in northeastern Williston basin have stratigraphic and geographic significance controlled by migration pathways and source rock composition as it affects hydrocarbon generation and expulsion characteristics. When the depth and density of oil pools is compared to relationships predicted using the correlation between source rock thermal maturity and oil density, several different migration pathways can be inferred. Winnipegosis source oils indicate four paths. Most small pinnacle reef pools are sourced locally, but larger coalesced reefs contain oils migrated long distances through the Lower Member Winnipegosis Formation. Among oils that have migrated past Prairie salts, both locally sourced oils, like those on the flank of the Hummingbird Trough, and more mature, longer migrated oils in Saskatchewan Group reservoirs can be identified. Bakken oils have the longest migration pathways, controlled primarily by a lowstand shoreline sandstone on the eastern side of the basin. Lodgepole-sourced oils dominate Madison Group plays. Northwest of Steelman field, oil density increases primarily due to thermal maturity differences but also because of increasing biodegradation and water-washing that affect the western edge of the play trend. Along the margin of the Hummingbird Trough are a number of deep, medium-gravitymore » pools whose oil compositions are entirely attributable to low thermal maturity and local migration pathways.« less

Ancestral Nesson Anticline and Associated Geothermal Anomalies: Enhanced Hydrocarbon Generation Controlled by Crustal Structure: ABSTRACT

Hydrocarbon generation in the Williston basin is influenced by crustal motions and geothermal gradient anomalies associated with the ancestral Nesson anticline, a long-lived crustal structure located along 103{degree} longitude. This structure and its effects are particularly important in Canada where most petroleum source rocks were not sufficiently buried to have generated hydrocarbons in a normal geothermal gradient environment. High geothermal gradients associated with this structure raise the oil window and expand the region of source rock thermal maturity. Ancestral Nesson structure subsided differentially throughout the Phanerozoic, controlling paleobathymetry and facies over its crest. During the Upper Ordovician the structure was positive; rich potential petroleum source rocks were deposited on the western flank of the structure, generally excluding them from the zone of elevated heat flows. The total petroleum potential of this oil-source system exceeds 5.5 billion bbl of oil equivalent in Canada alone. Unfortunately, its exclusion from the maturation anomaly results in no more than 200 million bbl of oil being expelled from these sources. During the Middle Devonian, the structure was a negative feature that formed a starved subbasin separating the Winnipegosis and Elm Point carbonate shelves. Rich potential petroleum source rocks that accumulated on the crest of themore » structure at that time now overlie the region of elevated heat that flows and enhanced hydrocarbon maturation. Two billion barrels of oil are estimated to have been expelled from this source rock. Understanding the history and tectonics of the ancestral Nesson anticline is fundamental to a correct appraisal of hydrocarbon resources in the Williston basin.« less

Maturation and Source Rock Evaluation of Kimmeridge Clay, Norwegian North Sea

Using a slightly modified version of the Lopatin method of determining the level of thermal maturation of source rocks, it is found that major hydrocarbon generation from the Kimmeridge Clay began in the Late Cretaceous/early Paleocene along the deeper parts of the Viking and Central grabens. Throughout the Tertiary, maturation progressed as subsidence and deposition continued. As the maturation in the deep graben areas passed from the oil generation stage into wet-gas and/or condensate generation and finally into the dry-gas stage, the areas of strong active oil generation migrated from the graben areas into shallower areas toward the continental craton. Applying the results of the maturity calculations in conjunction with chemical analyses of the Kimmeridge Clay allows computations of the original generative capacity, hydrogen index, total organic carbon, kerogen type, and the volume of hydrocarbons generated. The Kimmeridge Clay is mainly characterized by Type II kerogen, with Type I kerogen occurring in the deeper graben areas, and Type III in the platform areas. It is heterogeneous as a source, with original generative capacities ranging from essentially zero to over 35,000 ppm, and averaging about 13,300 ppm.

Source and Time of Generation of Hydrocarbons in Fossil Basin, Western Wyoming Thrust Belt: ABSTRACT

Oil trapped in Triassic-Jurassic reservoir rocks in fields along the Ryckman Creek-Pineview structural trend on the Absaroka thrust plate was generated in source rocks in the footwall Cretaceous sequence which was overridden by the thrust plate. This conclusion is supported by data from a variety of analytic techniques used to make oil-to-oil and oil-to-source rock correlations. The source of hydrocarbons in Paleozoic reservoirs in the Whitney Canyon-Carter Creek trend on the Absaroka plate is more difficult to identify with certainty. The accumulations in the Paleozoic rocks are dominantly gas with some condensate, and a significant amount of H2S is present in contrast to the low-sulfur sweet oil and gas in the Ryckman Creek-Pineview trend. The identical sul ur content and chromatographic character of condensate from the Paleozoic and the Triassic-Jurassic reservoirs suggest that both are from the same source. Reconstruction of the maturation history and measurement of present levels of thermal maturation of source rocks in different structural settings in the Fossil basin demonstrate that peak generation and migration of hydrocarbons from Paleozoic source rocks predated the Absaroka fault which was formed about 75 m.y.B.P. Cretaceous source rocks beneath the Absaroka plate were immature when overridden by the fault and have reached a high level of maturity since that time. Most of the hydrocarbons were generated and expelled from source rocks in the footwall sequence during the last 60± m.y., after the hanging-wall structural traps involving both Mesozoic and Paleozoic reservoirs were formed. End_of_Article - Last_Page 800------------