Timing Of Hydrocarbon Generation Research Articles

Petroleum Systems of the Papuan Basin, Papua New Guinea, and their Exploration Potential: ABSTRACT

The Papuan Basin of Papua New Guinea is a mature basin with a complex geologic history. The basin was initiated during Permo-Triassic rifting of the northern margin of Australia. Passive margin sedimentation occurred until the Oligocene to Recent when the basin was compressionally inverted, resulting in the formation of the present-day fold and thrust belt. Numerous hydrocarbon fields, some commercial, occur in traps along the front of the thrust belt. In mature complex basins such as this, it is critical to fully characterize existing petroleum systems as well as deliberately search for new systems. A recent systematic synthesis of the available geochemical data has defined three systems. Most important is the Jurassic system which is responsible for most of the oil and gas fields and all commercial production. Cretaceous and Tertiary systems, newly discovered in the basin, are based on detailed isotope and biomarker analysis of numerous oil seep. These additional petroleum systems open up new plays for exploration. To better define the pre-thrust basin geometry and help constrain the timing of hydrocarbon generation and migration, a series of palinspastically-stored cross-sections were constructed. Maturity modelling at different basin locations along these cross-sections evaluated the relative importance of two important species:more » (1) pre-thrust generation from local kitchens behind the present thrust belt, and (2) syn-thrust generation by loading of stacked thrust sheets within the fold belt. The relative importance of re-migration from pre-thrust traps vs direct charging into present day fold belt traps was evaluated using oil composition data.« less

Numerical Simulations of Complex Temperature, Burial, and Erosion Histories for Sedimentary Basins and their Calibration: Examples from Western Germany: ABSTRACT

The detailed and reliable reconstruction of the geological and thermal evolution of sedimentary basins forms the indispensable basis of any simulation of generation, migration and accumulation of hydrocarbons. For this purpose - although often not taken into account - analysing and quantifying the uplift and erosion history is as important as the subsidence and temperature history. The reconstruction of the timing of hydrocarbon generation, petroleum expulsion and migration and the changing reservoir characteristics is only possible based on such an integrated approach. Applying this technique on the Carboniferous Ruhr Basin and the Lower Saxony Basin (western Germany) by utilising 1-D and 2-D forward modeling approaches resulted in important and new quantitative information on their temperature, subsidence and erosion histories which are of fundamental geological interest. The basin evolution models were calibrated using vitrinite reflectance data, fluid inclusion temperatures, and apatite and zircon fission track data. The detailed knowledge of the geological and thermal basin evolution then allowed in combination with a new kinetic model for gas generation from coals the modeling of generation, migration and accumulation of methane from Carboniferous coal seams.

A geochemical investigation of samples from the Volgian Bazhenov formation, Western Siberia, Russia

In this paper we present analyses of five core samples from the Volgian Bazhenov Formation. Three different organic facies (A, B, and C) are proposed based on microscopical, bulk and biomarker analyses. Facies A and B have much in common, including low hopane/sterane ratios, C 35/C 34 hopane ratios slightly above 1.0, small amounts of tricyclic terpanes, and a range of alkylthiophenes in their pyrolysates. However, Facies A and B show some differences. For example, Facies A shows a slight even/odd (C 22–C 27) n-alkane predominance in some of the samples, while Facies B lacks 28,30-bisnorhopane, and shows significantly different n-alkane/isoprenoid ratios. These findings contrast with those of Facies C, which shows very low organic sulfur, an odd/even predominance in the higher n-alkanes, a high C 29/C 27 sterane ratio, a very high hopane/sterane ratio, and is very low in tricyclic terpanes. The timing of hydrocarbon generation from Facies A, together with the type and amount of organic matter, appears to be similar to that of the Upper Jurassic of the Norwegian continental shelf. It appears that Facies A and B have similar types of organic matter, with a somewhat higher input of terrestrial debris in the latter and, contrastingly, in Facies C an even greater proportion of terrestrial organic matter.

Geopressure evolution, hydrocarbon generation and migration in the Beaufort-Mackenzie Basin, Canada: results from two-dimensional quantitative modelling

Three cross-sections of onshore and offshore areas of the Beaufort-MacKenzie Basin were used to simulate geopressure evolution, hydrocarbon generation and migration processes of the Tertiary section using a two-dimensional model. Two analytical approaches were used: (1) adjusting geological, geophysical and geochemical parameters to obtain the best fit between the model results and regional geological data in a one-dimensional manner; and (2) reconstructing the basin evolutionary history in a two-dimensional manner. The model results indicate that the present day distributions of geopressure and maturity levels at different locations have been modified by late Miocene uplift and erosion, followed by rapid deposition of the late Miocene-Pleistocene lperk sediments. Although the occurrence of oil and gas has no obvious relationship to geopressure at the present day, the evolution of geopressure in strata older than the Mackenzie sequence plays an important part in the maturation of Tertiary source rocks. Geopressure in these older formations caused an increase in thermal gradient and porosity in the deep formations. The analysis indicates that the timing of hydrocarbon generation and the evolution of geopressure are critical factors in the development of horizontal migration (Reindeer reservoirs) versus vertical migration (Kugmallit reservoirs).

Diagenetic History and Hydrocarbon Potential of Upper Permian Carbonate Buildups, Wegener Halvo Area, Jameson Land Basin, East Greenland (1)

The Upper Permian of Jameson Land includes two carbonate sequences, the Karstryggen and Wegener Halvo formations. The Karstryggen Formation contains hypersaline carbonates and localized evaporites that were heavily weathered and dissected prior to deposition of the overlying strata. The overlying Wegener Halvo Formation represents an abrupt and extensive marine inundation over the underlying karstified Karstryggen surface. Bryozoan-brachiopod-algal-cement buildups of the Wegener Halvo Formation are localized on karstic highs, and show up to 150 m of depositional relief. In-situ mound-core deposits are flanked by allodapic limestones, which pass laterally into intermound calcareous shales. The diagenetic histories of the core and flank facies are very different. Core facies porosity was intially obliterated by marine cements, but repeated meteoric exposure altered unstable core facies constituents. This alteration produced extensive secondary porosity through grain and cement leaching with local collapse brecciation. Flank strata, however, underwent little sea-floor diagenesis, and low permeability and mineralogically stable grain composition protected these strata from meteoric alteration. Early cementation and stabilization of core strata led to minimal burial-diagenetic porosity loss. Uncemented flank beds, however, underwent profound mechanical and chemical compaction during this stage. Thus, at the time of hydrocarbon generation, distal flank beds had less than 2% porosity, coarse upper flank beds had 5-10% remnant primary porosity, and core facies deposits had 8-12% secondary pore space. Hydrocarbons generated from surrounding marine shales charged many of the bioherms with oil. Subsequent fracturing and hydrothermal fluid flow, however, flushed hydrocarbons and filled pores with ferroan calcite, barite, fluorite, galena, and baroque dolomite. This heating and flushing is thought to have been especially intense in the Wegener Halvo region; thus, more basinal areas may still have reservoirs containing significant oil in equivalent Upper Permian limestones. If, as is likely, the sea level changes affecting the Greenland Permian were eustatic, then this study may provide significant clues to porosity development throughout the largely unexplored northern Zechstein basin and the Arctic basin of the Barent Sea. This study also provides some important connections to the probably time-equivalent Guadalupian carbonate reservoir rocks of west Texas-New Mexico and Wyoming.

Thermal and Tectonic History of Selected Taranaki Basin (New Zealand) Wells Assessed by Apatite Fission Track Analysis (1)

Apatite fission track analysis (AFTA) has been applied to samples from four hydrocarbon well sections to study the thermal and tectonic history and the hydrocarbon prospectivity of the southern part of the Taranaki basin (New Zealand). Data from three of the wells (1 Fresne, 1 North Tasman, 1 Surville) show that the successions were exposed to higher temperatures in the past through deeper burial. Cooling from elevated paleotemperatures was effected by late Miocene uplift and erosion of 3.0 + or - 0.3 km of section in 1 Fresne, < or = 2.0 + or - 0.5 km in 1 Surville, and 1.0 + or - 0.3 km in 1 North Tasman. In the fourth well, 1 Kupe, formations are currently at their maximum temperatures since deposition. AFTA provides unique constraints on the timing of hydrocarbon generation in relation to trap formation. The proposed source rocks in 1 Fresne passed through the oil formation window (100-150 degrees C) and into the zone of gas production (150-220 degrees C) during the middle Miocene, prior to the formation of potential trapping structures. Those in 1 North Tasman passed into the oil formation zone about the same time, and source rocks in 1 Surville have probably never been heated enough to produce oil. AFTA indicates considerable prospectivity remains in the region of 1 Kupe, where generation would have occurred after trap formation.

New Models of Thrust Kinematics and Implications for the Generation, Migration, and Entrapment of Hydrocarbons in Fold and Thrust Belts: ABSTRACT

The sequential development of thrusts is often more complicated than models commonly used in predicting the relative timing of hydrocarbon generation and entrapment in thrust belts and adjacent synorogenic foredeeps. Consequently, existing models may inadequately evaluate the potential of an unexplored basin or lead to missed opportunities in mature basins. In a common approach to burial history profiling, thrusts are modeled as advancing singly in a simple hinterland-to-foreland (piggyback) sequence. Such models will often predict that hydrocarbons are generated and migrate updip toward the basin margins at rates faster than the advance of the thrust front. However, a more detailed study of the stratigraphic and structural evidence in some basins reveals that two or more thrusts experienced major movements simultaneously. Subsidence profiling that incorporates simultaneous thrusting suggests that hydrocarbon traps will develop synchronously with hydrocarbon generation and migration. A thrust load toward the hinterland will push its footwall into the generating window, and accompanying movement on an adjacent up-dip thrust provides the necessary trap. During simultaneous thrusting, hydrocarbons may be trapped at depth within the basin, but an explorationist applying the piggyback thrust model would concentrate most of his or her effort on stratigraphic and structural traps on the basinmore » margins. Burial history modeling incorporating sequential thrusting suggests that hydrocarbons usually will migrate into an existing trap, which would be expected to exhibit planar oil-water contacts. In contrast, simultaneous thrusting should lead to tilted or folded oil-water contacts because hydrocarbon generation and thrusting occur concurrently in simultaneous thrusting.« less

Comparative behaviour of coal and maceral concentrates during artificial coalification

A series of experiments were performed in cold-seal autoclaves (confined-pyrolysis) to characterize the behaviour of individual macerais (vitrinite, inertinite, exinite) extracted from the same Lorraine Basin coal during artificial coalification. Rock-Eval pyrolysis, elemental analysis and weight loss determination provided the simple maturation indexes required. Emphasis was laid on the timing of hydrocarbon generation and on the possible similarities existing between inertinite and vitrinite of higher rank. Hydrocarbon potential and hydrocarbon yield were found to increase from inertinite to vitrinite and exinite, but similar mechanisms were involved during the thermal degradation of both inertinite and vitrinite.

HYDROCARBON POTENTIAL OF THE UPPER JURASSIC/LOWER CRETACEOUS OF THE AUSTRALIAN NW SHELF

Source‐rock richness, timing of hydrocarbon generation, and thicknesses of potential source shales of the Upper Jurassic/Lower Cretaceous section of the Australian NW Shelf have been examined in order to make predictions as to the hydrocarbon productive of liquid hydrocarbons: the Brows Basin, the Malita Graben/NW Bonaparte Gulf Basin, the Rowley Sub‐basin, and the Vulcan Sub‐basin/Sahul Syncline, respectively.Recent liquid hydrocarbon discorveries in the Vulcan Sub‐basin, probably source by the Upper Jurassic shales, upgrade all four of these areas, and lead to the conclusion that overall, drilling results on the NW Shelf have to date not been indicative the timing of generation as delineated in this study with the timing of structural development in order to improve chances of success, rather than relying on the size of Structures alone.A new method of presenting timing of generation, in the form of a “timing‐of‐generation map”, is introduced, where the timing of the progress of significant hydrocarbon generation is contoured over the NW Shelf for each source‐rock section.

STUDIES ON PETROLEUM GEOLOGY AND GEOCHEMISTRY, MIDDLE PROTEROZOIC, McARTHUR BASIN NORTHERN AUSTRALIA I: PETROLEUM POTENTIAL

Mature, rich, potential source beds and adjacent potential reservoir beds exist in the Middle Proterozoic sequence (1400-1800 Ma) of the McArthur Basin. The McArthur and Nathan Groups consist mainly of evaporitic and stromatolitic cherty dolostones interbedded with dolomitic siltstone and shale. They were deposited in interfingering marginal marine, lacustrine and fluvial environments. Lacustrine dolomitic siltstones form potential source beds, while potential reservoirs include vuggy brecciated carbonates associated with penecontemporaneous faulting and rare coarse-grained clastics. In contrast, the younger Roper Group consists of quartz arenite, siltstone and shale that occur in more uniform facies deposited in a stable marine setting. Both source and reservoir units are laterally extensive (over 200 km).Five potential source rocks at various stages of maturity have been discovered. Two of these source rocks, the lacustrine Barney Creek Formation in the McArthur Group and the marine Velkerri Formation in the Roper Group, compare favourably in thickness and potential with rich demonstrated source rocks in major oil-producing provinces. There is abundant evidence of migration of hydrocarbons at many stratigraphic levels. The geology and reservoir characteristics of the sediments in combination with the distribution of potential source beds, timing of hydrocarbon generation, evidence for migration and chances of preservation have been used to rank the prospectivity of the various stratigraphic units in different parts of the basin.

Generation and migration of hydrocarbons in the Maracaibo basin, Venezuela: An integrated basin study

The history of hydrocarbon generation and migration in the Maracaibo Basin, Venezuela, is closely related to its stratigraphic, structural and tectonic evolution during the Cretaceous and Cenozoic times. Geochemical evaluation of the possible source rocks within the Cretaceous and the Tertiary sequences indicates that the argillaceous limestones and calcareous shales of the La Luna Formation (Cenomanian-Coniacian) are the most important source rocks in the basin. These rocks contain organic carbon ranging from 1.5 to 9.6% ( c. original TOC 2.5–10.8%), have fluorescent amorphous marine, type II organic matter (oil prone) and have in the immature stage a H-index of 700 mg HC/g TOC and a H/C ratio of 1.5. The beginning of the oil window in these rocks occurs at a relatively low thermal maturity (Lopatin TTI about 10) and the peak of oil generation corresponds to a TTI value of 35. Geochemistry of oils from the different reservoirs (Cretaceous, Paleocene, Eocene and Miocene beds), and oil-oil and oil-source rock correlation studies based on biomarkers have identified three genetic types of oil in the basin: a marine type essentially derived from the La Luna source, a terrestrial type possibly originating either from the Cretaceous Lisure shales or the Paleocene shales, and a third type derived from the mixing of the first two types. The marine type oil is distributed extensively throughout the basin whereas the terrestrial as well as the mixed marine and terrestrial types are found only in the southwestern part of the basin. The marine type oils have been further subdivided based on their alteration and maturity. Reconstruction of the hydrocarbon generating areas at different geological times using TTI-maturity diagrams indicates that the generation of oil and gas in the basin took place during two periods; the first phase occured during the Middle to Upper Eocene times in the northeastern part of the basin, while the second phase occured during the Upper Miocene to Recent times in the central, western and southern parts of the basin. Based on organic geochemical and sedimentological characteristics, it is proposed that primary migration of oil from the La Luna source rocks took place by expulsion of hydrocarbons through abundant microfractures developed by the pore fluid overpressure during hydrocarbon generation. Mass balance considerations suggest that the expulsion probably occurred as a hydrocarbon single phase and the expulsion efficiency for oil in La Luna source rocks should have been very high (30–50%). Taking into consideration the development of oil and gas kitchens through time, the paleostructures at the time of hydrocarbon generation, and the characteristics of oils, the migration history of the oil and gas generated from the La Luna source has been outlined. Mixing of oils, derived at different times (Eocene and Miocene-Recent) from the La Luna source of different areas, appeared to have taken place in Block IV, Block 11, Lago-Lamar, Motatan and Bolivar Coastal fields.

Hydrocarbon source rock potential of the Devonian rocks of the Orcadian Basin

Synopsis Potential hydrocarbon source rocks are evaluated from the Devonian Orcadian Basin (plus a small suite from the Hornelen Basin, Norway) for organic matter richness, type and maturation level. Techniques used include total organic carbon determination, pyrolysis, visual kerogen typing, spore colour and vitrinite reflectance. The sequences of SE Shetland, the Walls Sandstone, Fair Isle and the Hornelen Basin only contain small amounts of organic matter and were probably thermally mature before any significant cover was established and any minor hydrocarbons generated were soon lost. The main development of the Orcadian Basin does contain significant Middle Devonian and minor Lower Devonian hydrocarbon source rocks with oil and gas prone materials which are still in the oil window for the majority of the succession. Speculations are made concerning the possibility of hydrocarbons accumulating from this part of the sequence and prospects include reservoirs in the Upper Old Red Sandstone, Eday Beds, John O9Groats Sandstone, and the Lower Old Red Sandstone although deep ‘weathering’ effects are probably detrimental to preservation. Aeolian beds associated with extensive organic rich units may also be significant. Possible sites for hydrocarbon accumulation are the offshore half graben structures beneath the Moray Firth and in the onshore Devonian sequence. The timing of hydrocarbon generation is thought to be early.

Thermal Subsidence of Santos and Sergipe-Alagoas Basins, Brazil--Application to Hydrocarbon Exploration: ABSTRACT

A uniform lithospheric extension model has been applied to the subsidence and thermal history of the Santos and Sergipe-Alagoas basins. Thermal subsidence curves were derived from more than 40 exploratory wells, complemented by seismic and gravity sections. In the Santos basin, the region landward of the hinge zone is dominated by Tertiary marine onlapping sediments. Seaward, rift (continental) and postrift (transitional and marine) sequences are present with predominance of the latter. Crustal thinning by 35% exists just east of the hinge zone and increases to 70% at the shelf break. Likewise, the hinge zone in the Sergipe-Alagoas basin overlies the largest gradient in crustal thinning, but unlike the Santos basin, rift-stage sediments dominate landward of this hinge zone. Seaward, the ratio of rift to postrift sediments is larger than in the Santos basin. Crustal thinning ranges from 20% to 60%, but this transition occurs over a short distance. Thermal and burial histories were used to estimate oil windows for potential source rocks in various parts of these basins. Maturation profiles are in good agreement with observed vitrinite reflectance and hydrocarbon maturity data. The areal distribution of maturation stages through time is variable and largely controlled by crustal thinning. Information on timing of hydrocarbon generation was applied to the prediction and evaluation of hydrocarbon accumulation. End_of_Article - Last_Page 243------------

Empirical Relation Between Carbonate Porosity and Thermal Maturity: An Approach to Regional Porosity Prediction

Data indicate that porosity loss in subsurface carbonate rocks can be empirically represented by the power function, ^Thgr = a (TTI)b, where ^Thgr is regional porosity, TTI is Lopatin's time-temperature index of thermal maturity, the exponent, b, equals approximately -0.372, and the multiplier, a, is constant for a given data population but varies by an order of magnitude overall. Implications include the following. 1. The decrease of carbonate porosity by burial diagenesis is a maturation process depending exponentially on temperature and linearly on time. 2. The exponent, b, is essentially independent of the rock matrix, and may reflect rate-limiting processes of diffusive transport. 3. The multiplying coefficient, a, incorporates the net effect on porosity of all depositional and diagenetic parameters. Within constraints, carbonate-porosity prediction appears possible on a regional measurement scale as a function of thermal maturity. Estimation of carbonate porosity at the time of hydrocarbon generation, migration, or trapping also appears possible.

HYDROCARBON GENERATION IN THE AMADEUS BASIN, CENTRAL AUSTRALIA

The Proterozoic to Devonian Amadeus Basin of central Australia contains two hydrocarbon fields — oil and gas at Mereenie and gas at Palm Valley, both within Ordovician sandstone reservoirs. Significant gas and oil shows have also been recorded from Cambrian sandstones and carbonates in the eastern part of the basin. The hydrocarbon generation histories of documented source rocks, determined by Lopatin modelling, largely explain the distribution of the hydrocarbons. The best oil and gas source rocks occur in the Ordovician Horn Valley Siltstone. Source potential is also developed within the Late Proterozoic sequence, particularly the Gillen Member of the Bitter Springs Formation, and the Cambrian.Consideration of organic maturity, relative timing of hydrocarbon generation and trap formation, and oil/source typing leads to the conclusion that the Horn Valley Siltstone charged the Mereenie structure with gas and oil. At Palm Valley, only gas and minor condensate occur because the trap was formed too late to receive an oil charge. Differences in organic facies may also, in part, account for the dry gas and lack of substantial liquid hydrocarbons at Palm Valley. In the eastern Amadeus Basin, the Ordovician is largely absent but Proterozoic sources are well placed to provide the gas discovered by Ooraminna 1 and Dingo 1. Any oil charge here would have preceded trap development.

Gas Versus Oil in Far East and Middle East: ABSTRACT

The Far East, including Australia, is largely a gas province (the USSR and China are excluded from our study). The Middle East is largely an oil province with respect to Tertiary and Mesozoic reservoirs, and a gas province with respect to lower Mesozoic and Permian reservoirs. The geologic and geochemical parameters which determine the predominance of gas over oil or oil over gas are well known. They include type of source rock, source rock position in the total sedimentary sequence, burial history, temperature gradients, timing of hydrocarbon generation, and trap formation, retention, and related geologic factors. In the Far East, the relation between coal or coaly matter as source rocks and the occurrence of natural gas is obvious. Australia is a striking example. In th Middle East, the Sargelu formation is one of the most prolific source rocks. It is of Middle to Late Jurassic age, kerogenous and fully marine, which, in combination with other factors, explains the predominance of oil in Tertiary and Mesozoic reservoirs in and around the Arabian Gulf. At deeper stratigraphic levels, huge quantities of gas are ascribed to Paleozoic sources, the nature of which has not yet been fully assessed. Much of this gas, especially in southwest Iran, can be regarded as thermally degraded oil. In areas of intense Neogene deformation (Tertiary basins of Indonesia and Burma), a large part of the gas phase has probably escaped, whereas the oil phase was largely retained. Many examples illustrate the validity End_Page 459------------------------------ of the general principles without ignoring the complexity of the gas versus oil problem. End_of_Article - Last_Page 460------------