Hydrocarbon Generation Zone Research Articles

The Source of Thermophilic Bacteria in Lake Baikal Cold Sediments – Coastal Hydrotherms or Deep Fluids?

The sources of thermophilic bacteria revealed in cold Lake Baikal sediments are considered. Comparative analysis of the taxonomic position of thermophilic microorganisms from four terrestrial hot springs at Lake Baikal coast and from the bottom sediments associated with hydrocarbon discharge was carried out. The sequences of thermophilic microorganisms with the same taxonomic position were revealed both in the hot springs and bottom sediments. Some microbial species occurred only in the hydrotherm samples or only in those from the sediments. Gas-saturated fluids from the hydrocarbon generation zone at the depth of 4‒6 km are the most probable source of thermophilic microorganisms in the bottom sediments.

Lower and Middle Jurassic organic-rich rocks of W and SW Ukraine, NE Romania and S Moldova: occurrence, hydrocarbon generation zones and mineralogy

Lower and Middle Jurassic organic-rich rocks of W and SW Ukraine, NE Romania and S Moldova: occurrence, hydrocarbon generation zones and mineralogy

Use of Cluster Analysis to Group Organic Shale Gas Rocks by Hydrocarbon Generation Zones

In the last decade, exploration for unconventional hydrocarbon (shale gas) reservoirs has been carried out in Poland. The drilling of wells in prospective shale gas areas supplies numerous physicochemical measurements from rock and reservoir fluid samples. The objective of this paper is to present the method that has been developed for finding similarities between individual geological structures in terms of their hydrocarbon generation properties and hydrocarbon resources. The measurements and geochemical investigations of six wells located in the Ordovician, Silurian, and Cambrian formations of the Polish part of the East European Platform are used. Cluster analysis is used to compare and classify objects described by multiple attributes. The focus is on the issue of generating clusters that group samples within the gas, condensate, and oil windows. The vitrinite reflectance value (Ro) is adopted as the criterion for classifying individual samples into the respective windows. An additional issue was determining other characteristic geochemical properties of the samples classified into the selected clusters. Two variants of cluster analysis are applied—the furthest neighbor method and Ward’s method—which resulted in 10 and 11 clusters, respectively. Particular attention was paid to the mean Ro values (within each cluster), allowing the classification of samples from a given cluster into one of the windows (gas, condensate, or oil). Using these methods, the samples were effectively classified into individual windows, and their percentage share within the Silurian, Ordovician, and Cambrian units is determined.

Conditions for the formation and accumulation of hydrocarbons in oligocene-miocene sediments of Western Absheron

Oligocene-Miocene deposits, after the main oil-gas suit of Azerbaijan – the Productive Suit, are one of the most studied objects. This complex is classified as mature rocks and, according to the stratigraphic scale, is associated with Maykop, Chokrak, and diatom deposits. Therefore, studies of the conversion of organic substances to hydrocarbons under favourable sedimentation and thermobaric conditions are of great importance. In addition, the determination of hydrocarbon generation zones, the presence of appropriate paleotectonic and paleostructural conditions for their further migration and accumulation in traps are also important tasks requiring clarification. For this purpose, maps of the Maykop and Mid- and Upper Miocene sediments were constructed, models reflecting their paleostructural position by the end of the century of the productive stratum, and predicted paleotemperatures are indicated on the diagrams. As a result, it was found that the reducing-alkaline environment existing during sedimentation in the Maykop and Chokrak period was favourable for the conversion of organic substances into hydrocarbon. Keywords: Western Absheron; oligocene-miocene sediments; source rock; organic matter; oil window; vitrinite; geochemical condition; source of generation; migration; traps; paleostructure.

1D and 2D basin modeling, in evaluating the hydrocarbon generation-migration-accumulation potential, at coastal Fars Area, Southern Iran

One of the giant hydrocarbon generation zones in Iran has been developed in the south of the Zagros Mountain Range (i.e., South Zagros), located between the South Zagros and the Persian Gulf in a foreland basin known for high levels of exploration uncertainties (due to the presence of complex structures, multiple source layers, and migration pathways). In this basin, the Permotriassic formations provide for the main reservoir strata, while the hydrocarbon content is deemed to be derived from the “hot shales” of the Silurian-Ordovician Sarchahan Formation, serving as source rock. As the focus of the present research, the Coastal Fars region is developed along the shores of southern Iran and hosts a number of gas reservoirs that have been increasingly discovered since 1970. Developed in the Permotriassic siliciclastics and carbonates of the Faraghan, Dalan, and Kangan Formations, gas reservoirs have made the Coastal Fars a hot zone for exploration and production activities. In this research, one 2D and five 1D models of the basin (at five exploration wells) were constructed to evaluate the maturity of the main Silurian-Ordovician source rock and further investigate the hydrocarbon charge, timing, migration pathways, and accumulation sites. The models were then utilized to investigate the relationship between the presence of multiple shale layers and hydrocarbon content of the reservoir at one of the studied wells using Rock-Eval analysis. This study showed that an uplift that happened after the hydrocarbon generation has led to a dry hole in the study area. The results indicated that the Sarchahan Formation is probably the main source rock across the region, according to previous researches in this area its organic contents were dated back to the late Ordovician rather than the Silurian. The shale intercalations across the reservoirs (Kangan and Upper Dalan), especially in the Khayam Field, were found to produce more than 90% of their hydrocarbon generation potential. No non-indigenous hydrocarbon was identified across the study area, implying that the entire hydrocarbon content was generated by the identified source rocks. Laboratory analysis indicated the presence of type II and type III kerogen at a local heat flow rate of about 65 mW/m2 since the Cretaceous. In total, the Sarchahan Formation was found to reach a maximum burial depth of 6 km, making it matured to overmatured all over the study area.

Geothermal conditions of hydrocarbon prospects of Meso-Cenozoic formations in South Caspian Basin

Temperature data of oil and gas fields and prospecting sites in the South Caspian Basin (SCB) are summarized. From the array of measured temperatures and stratigraphy data from 190 offshore and onshore fields as function of depth, 3D interpolated maps of temperature fields and stratigraphic units of the area are constructed. Available data covers the stratigraphic interval from Neogene to Upper Cretaceous and include Pliocene productive formations and anticipated source rocks intervals (Oligocene and Upper Cretaceous suites). Geothermal modes (temperature-depth curves) for specific fields and for the region as a whole can be approximated by generalized parabolic type functions with fitted coefficients according to actual field data. The thermal mode of the South Caspian Basin is compared with similar major hydrocarbon fields worldwide. Specific features of the geological history and deposition, in particular, fast subsidence and avalanche sedimentation (sedimentation rate 1―2 km per MA) resulted in SCB being one of the coldest basin among giant hydrocarbon basins worldwide. This allows anticipating the availability of a hydrocarbon generation zone at depths up to 15―20 km, that is essentially below the sedimentary formations of the Pliocene Productive Suite and underlying Oligocene Maykop Suite, which nowadays are the most searched exploration targets. In particular, the results in conjunction with other research data from geochemistry, stratigraphy and tectonics, as well as backstripping simulations, allow us to expect large HC bearing structures in Mesozoic formations, including potential deposits at ultra big depths up to 12 km.

Experimental Transformation of Organic Matter by the Microbial Community from the Bottom Sediments of Akademichesky Ridge (Lake Baikal)

Abstract —We discuss the results of a model experiment on cultivation of the microbial community from the area of the Khoboy mud volcano (Akademichesky Ridge) conducted under conditions typical of the hydrocarbon generation zone (80 °C, 5 MPa). The cultivation under conditions of biomass enrichment with the Baikal diatom Synedra acus changed the composition of organic matter. The transformation degree of organic matter in the sediment after the experiment was 16%, whereas the concentration of phenanthrenes relative to methyl-substituted homologues, including retene, decreased, and the concentration of dibenzothiophenes relative to normal alkanes increased. We have identified tri- and monoaromatic steroids, including 17-dismethyl, 23-methyl monoaromatic steroids C27. An increase in the concentration of tri- and monoaromatic steroids in the sediments after the experiment might indicate that the biomass of the Baikal diatom S. acus was destructed, which led to an increase in the steroid concentration. In the control (sterile) sediment, we detected no changes in the composition of organic matter. Representatives of various taxa capable of surviving in anaerobic thermophilic conditions have been identified in the microbial community by molecular genetic methods. Their presence in the surface sediments might be due to the inflow of deep-seated mineralized fluids and breccia from deep-seated sedimentary rocks.

Abnormally high formation pressures in jurassic-cretaceous reservoirs of Arctic regions of Western Siberia

Results of the study of the structure of hydrodynamic fields in Arctic part of the West Siberian sedimentary basin have designated the main region-specific hydrodynamic feature consisting in the phenomenon of abnormally high formation pressures widely spread at depths of 2.8-6.0 km within Jurassic-Cretaceous reservoirs. The two types of natural pressurized water systems which have developed in the region are: 1) elision (geostatic and geodynamic) system most common in the interior regions, and 2) infiltration aquifer system inherent in the external, near edge zones. As the depth increases, two hydrodynamic zones are distinctly distinguished (from top downwards): hydrostatic and enhanced evolving into AHFD (abnormally high formation pressure). Most of the Aptian-Albian-Cenomanian aquifers belong to the first type. Hydrodynamic field stresses tend to increase in the lower lying Neocomian complex where the already elevated formation pressures gradually build up, to the extent of AHFP in the lower horizons. The Jurassic aquifer complexes in the central parts of the Yamal-Kara depression exhibit either enhanced or abnormally high formation pressures, which decline to hydrostatic levels towards the basin periphery. The anomaly coefficients of formation pressure reach the value of 2.2. The established piezo-minima zones extending along major petroleum charge zones, extending along the major hydrocarbon generation zones (Bolshaya Kheta and Kara megasyneclises) associated with the largest areas of petroleum accumulation (Vankor-Suzun, Bovanenkovo, Urengoy, etc.).

Hydrocarbon potential of cretaceous sediments from lower Indus Basin, Pakistan

ABSTRACTIn previous studies, Patala-Nammal Composite Total Petroleum System (TPS) was recognized as a potential source of hydrocarbon in the Upper Indus Basin, and Sembar-Goru Composite TPS in the Lower Indus Basin. However, petroleum source-rock potential of Cretaceous strata in the Indus Basin is poorly known. In the current study, Rock Eval and total organic carbon (TOC) analyses were conducted to investigate the thermal maturity and source-rock potential of Cretaceous unit in the Lower Indus Basin. The Parh Formation of the Lower Indus Basin is lean in organic contents (TOC < 0.73%) and consistent with immature type-III/IV kerogen. The Upper Goru Formation is fair in organic contents and presents similar characteristics to the Parh Formation with respect to the hydrocarbon generation zone. The Lower Goru Formation presents fair to very good organic contents. The members of Lower Goru Formation have enough organic matter (OM) and are mature, with the exception of Badin shales. The OM, throughout the formation, is predominantly gas prone. The Sembar Formation is fair in organic contents and mature with respect to hydrocarbons generation. These results support that the Lower Goru rocks are comparatively more prospective with respect to hydrocarbons.

Determination of hydrocarbon prospective areas in the Tuzgolu (Saltlake) Basin, central Anatolia, by using geophysical data

Tuzgolu Basin is the largest interior basin in Central Anatolia, Turkey, with significant hydrocarbon indications in outcrops and exploration wells. However, there is no commercial discovery since 1959 which is the beginning year of exploration activities. Because of the poor seismic quality, all available geological-geophysical data and methods should be used in integration with each other to carry out exploration activities. In previous studies, the basin was modeled three dimensionally (3D) using gravity data by the authors of this paper and results of the modeling study were published recently. The model results can be evaluated to determine probable hydrocarbon generation zones. Gravity anomalies in this region exhibit many inflections that could be prospective locations for hydrocarbons. In this study, the gravity data were subjected to the vertical derivative in order to isolate inflections and to determine concealed structurally high areas in the subsurface that could have hydrocarbon potential. These potential subsurface structures were also compared with the Analytical Signal map produced from the aeromagnetic anomalies to reveal if they are originated from a magmatic intrusion. Finally, it was determined that all exploration wells were drilled off-structure and none of these potential subsurface structures was tested. According to correlation of the previous well locations and determined subsurface structures in or around the hydrocarbon generation zones, it is possible to claim that the Tuzgolu Basin with no previous discovery remains prospective for hydrocarbon exploration activities in the future.

Genetic aspects of the petroleum resource potential of marine sedimentary basins

The historical-genetic method developed at the Institute of Oceanology of the Russian Academy of Sciences for the assessment of the petroleum resource potential is discussed with consideration of its main tasks and the successive procedures in its application. Such studies are crowned by a compilation of separate maps demonstrating scales of oil and gas generation and maps of hydrocarbon genesis zoning of basins with outlining centers of oil and gas generation and defining different-phase hydrocarbon-generation zones. The method was tested in over twenty continental-marginal and intracontinental basins studied to a different extent. The sedimentary basins of the Atlantic continental margin off Africa and the Caspian and Black seas were used as objects for applying the historical-genetic method for assessing their petroleum resource potential.

Hydrocarbon Generation in Heath Formation (Mississippian) in Montana Thrust Belt in Response to Tectonic Burial: ABSTRACT

The Heath Formation of the Big Snowy Group (Mississippian) in Montana and North Dakota consists of dark-gray to black, petroliferous shale and limestone with up to 19.9% total organic carbon (TOC) and 20 gal of oil per ton. The Heath is considered a source rock for the overlying Tyler Formation as well as a possible oil-shale deposit. Regionally, the Heath is immature to marginally mature with respect to hydrocarbon generation, except in the deeper part of the Williston basin, in a few deeply buried areas in the central Montana trough, and in the Montana thrust belt. Along the northern margin of the Helena salient of the Montana thrust belt, samples from the Heath contain 0.20-3.59 wt. % TOC, with most containing over 0.88%. Vitrinite reflectance ranges from 3.77 to 4.72% and the thermal alteration index is 4+ to 5, indicating that maturation proceeded beyond oil, wet gas, and dry gas preservation limits. Thus, the Heath Formation here passed through peak hydrocarbon generation zones and hydrocarbons may have been thermally destroyed. Modeling of the depositional and thermal history prior to thrusting, using the Lopatin method, indicates maturation slightly below the oil generation window. This suggests that hydrocarbon generation occurred after thrusting,more » probably in response to tectonic burial beneath thrust sheets. This conclusion is also supported by vitrinite reflectance values from the Heath in the thrust belt compared with reflectance of 0.48-0.67% east of the thrust belt in central Montana.« less

Characteristics of Hydrocarbon Deposits in the Green Tuff

Several hydrocarbon deposits have been found in volcanic rocks of the Nanatani stage (so-called Green Tuff) in the Niigata basin, Japan.Their characteristics are summarized as follows.1) Hydrocarbon deposits are formed in anticlinal structures and are mostly located close to depressions.2) Oil accumulations have been found in anticlinal structures which are formed in the early stage.3) All hydrocarbon deposits except for the Shiunji gas field are located in the Chuetsu sub-basin.4) Larger oil and gas fields are located in or close to the kitchen areas of oil and gas. This suggests the short lateral migration of hydrocarbons together with the distribution of oil and gas in neighboring areas of the Mitsuke oil field.5) In larger gas fields, the Teradomari formation shows a typical abnormally high pressur e, whereas the Geen Tuff is hydrostatical or slightly highly-pressured. On the other hand, formation pressure in the Mitsuke oil field increases toward lower straigraphic horizons that is similar to the pressure distribution in the Shiiya and Nishiyama reservoirs. These pressure patters are closely related to the manner of accumulation of oil and gas.6) The migration of oil and gas in larger oil and gas fields is thought to have occurred during and after the Nishiyama stage.7) The distributions of oil and gas in the Green Tuff depend rather on the kinetics of hydrocarbon expulsion from source rocks than on the type of organic matter. The kinetics of expulsion is controlled by the relative positions of the hydrocarbon generation zone and the overpressured zone.The Niigata basin can be sub-divided into three parts according to their geologic conditions: Kaetsu sub-basin, Kakuta-Sanjo uplift and Chuetsu sub-basin. Considering the combination of trap, source rock, reservoir and migration mechanism, it is concluded that the Chuetsu sub-basin is the most prospective for future exploration.

Temperature effects on kerogen and on molecular and isotopic composition of organic matter in Pierre Shale near an igneous dike

A suite of siltstone samples from the Upper Cretaceous Pierre Shale from the contact zone of a 130-cm thick igneous dike near Wolcott, Colorado, U.S.A., was taken from the contact to 170 cm from the dike to study the effects of temperature on the organic matter. The sampled bedding interval was about 10 cm thick, so variation in lithology and type of organic matter is minimal. Vitrinite reflectance values ( R 0) increase from 0.4 far from the dike, to 3.3% near the dike contact. Geochemical measurements show systematic thermal effects analogous to those often observed for catagenesis and metagenesis in the depth range of 1–4 km within a sedimentary basin. The H/C ratio of kerogen and the hydrogen index (Rock-Eval) decrease most rapidly in the 0.6–1.7% R 0 range, in which the transformation ratio (Rock-Eval) increases from 0.1 to 0.3. Based on extraction of C 15+ compounds, the main increase of hydrocarbons and total extractable organic matter occurs between 0.6 and 1.0% reflectance. The saturated/aromatic hydrocarbon ratio increases almost twofold in this range of maturity. However, the pristane/phytane ratio is essentially constant through the hydrocarbon generation zone but decreases slightly at high levels of thermal alteration ( R 0 > 1.2%). The δ 13 C values for aromatic and saturated hydrocarbons are about −27 and −29‰, respectively, and are constant to about 1.0% R 0, then both become heavier by about 2‰ at higher R 0 values.

Integrated Hydrothermal Model for Proposed Deep Crustal Borehole on Texas Gulf Coast--Origins of Geopressured Brines and Lead-Zinc, Uranium, Hydrocarbon, and Cap-Rock Deposits: ABSTRACT

Sediment accumulation over Jurassic salt in the Gulf coast has resulted in an interrelated sequential development of salt domes and diagenetic, hydrothermal, and hydrocarbon generation zones. Primary anhydrites within the salt with high /sup 87/Sr//sup 86/Sr ratios suggest early generation of underlying fluids rich in radiogenic strontium that were incorporated in the salt during its diapiric rise to the surface. Subsequently, late-stage, hydrocarbon-rich, saline hydrothermal fluids migrated up the margins of the salt domes, and caused precipitation of several generation of calcite cements, followed by uranium and Mississippi Valley-type lead-zinc-barite deposits near or at salt dome rims. Present fluids in the lower Frio (deeper than 4270 m or 14,000 ft) at the Pleasant Bayou geopressured-geothermal test well (Brazoria County, Texas) are highly saline and enriched in iron, manganese, lead, zinc, and carbon dioxide, and are saturated in methane. These lower Frio waters must have migrated into the area recently because they are not in isotopic equilibrium with diagenetic albite cements formed at temperatures greater than 120/sup 0/C (248/sup 0/F) less than 7.5 million years ago. Isotopic and geochemical data suggest that the fluids trapped by geopressure in the lower Frio at the Pleasant Bayou well are the parent fluids ofmore » those causing salt dome cap-rock mineralization.« less

Generation and Migration of Light Hydrocarbons

Light hydrocarbons (containing from 1 to 14 carbon atoms) are formed from disseminated organic matter in sediments at the parts-per-billion level by biological and low-temperature (< 50 degrees C) chemical reactions and at the parts-permillion level by high-temperature (> 50 degrees C) cracking reactions. The cooler reactions produce mainly branched hydrocarbons, whereas the hotter reactions yield more straight chains. Hydrocarbon generation zones in the subsurface can be recognized on the basis of hydrocarbon distribution patterns. Hydrocarbons with tertiary carbon atoms form at lower temperatures than those with quaternary carbons. Methane and ethane migrate vertically through fine-grained shales by diffusion and solution, whereas many of the C(3+) hydrocarbons show little or no vertical migration. Concentrations of light hydrocarbons, including methane, in fine-grained source rocks decrease to low values in deep, high-temperature (>200 degrees C) sediments. This decrease may be one reason why no economic accumulation of gas has been found to date deeper than 8.2 kilometers (27,000 feet).

Migration of C 1-C 8 hydrocarbons in marine sediments

Light hydrocarbon (C 1-C 8) profiles are compared for three wells of varying maturities: two immature DSDP wells (Site 397 near the Canary Islands and Site 530A near the Walvis Ridge in the south-east Atlantic) and a mature well, the East Cameron well in the Texas Gulf Coast. Primary migration of C 1 and C 2 appears to be occurring in all of the sedimentary rocks examined. Primary migration of C 3+ components becomes important only as fine-grained sedimentary rocks enter the catagenetic hydrocarbon generation zone or over short distances in more permeable sections. Lateral migration along bedding planes was more important than vertical migration in sedimentary rocks of all maturities. The lightest (methane, ethane and propane gases) hydrocarbon show greater fractionation than do the C 4-C 8 alkanes which generally show minimal fractionation during the migrational process. Subsurface diffusion coefficients for these p.p.b. quantities of C 2-C 5 alkanes from immature sediments from DSDP Site 530 are estimated to be several orders of magnitude less than values reported in the literature for diffusion of much larger amounts of these compounds from mature water wet sediments into air or sandstones. Since our calculations suggest light hydrocarbons are present in amounts less than their reported solubilities in pure water at 25°C, we postulate that the sediment organic matter has a substantial effect on retarding the movement of these light hydrocarbons.

Organic geochemistry of crude oils from the Vienna Basin and an assessment of their origin

A representative collection of oil samples and Neogene rock samples from the Vienna Basin has been analyzed by organic geochemical methods. The relatively high maturity of the crude oils and the characteristics of their hydrocarbon composition makes it unlikely that they are derived from the Neogene sediments of the Vienna Basin. Furthermore, investigation of the rock samples also showed that these sedimentary strata do not have the potential for generation of liquid hydrocarbons. However, there is some potential for gas generation. Even the deepest Neogene sediments (> 4000 m depth) just have reached the onset of the hydrocarbon generation zone. From these results it has to be concluded that the bulk of the oil found so far in the Vienna Basin originated from pre-Tertiary sediments below the Neogene basin.