Hydrocarbon Expulsion Research Articles

Modelling Primary Hydrocarbon Expulsion in a Synthetic Sedimentary Section: Relative Contributions of Edge Conditions and other Geological Factors

The effects of numerical edge conditions and of the relative contributions of geological processes or factors to primary hydrocarbon migration are studied using the GEOPETII program developed by the Basin Modeling Group at USC. Lateral edge conditions can have important effects on the results of modelled sedimentary sections. The absolute mass of an oil or gas accumulation varies with the section length modelled, while more vertical grids (pseudo-wells) along a section result in less lateral continuity of accumulated oil and gas. A modelled section with a highly permeable lithology at the two lateral edges produces lower excess pressure between the three left-edge pseudo-wells and between the three right-edge pseudo-wells, and tends to have less oil and gas accumulated in the section center. If the modelled section has a low-permeability lithology at the two edges, the opposite effect is produced. A modelled section which has a thick basal layer, high permeability, and relatively few horizontal subdivisions produces less excess pressure in a shale source rock above the basal layer, and has smaller oil and gas accumulations in a reservoir unit above the source rock. By contrast, a modelled section with more subdivisions, and a smaller time-step for each layer calculation, produces higher excess pressures and tends to have more oil and gas accumulated in reservoirs above the source rock. Accordingly, the ratio of the thickness deposited in a time-step to the subdivision thickness used in the calculation should be kept small (less than 0.4 for the code used here). Twelve major processes or factors control oil and gas expulsion: (1) buoyancy; (2) the solubility of hydrocarbons in connate waters; (3) the saturation of irreducible water in a source rock; (4) capillary pressure; (5) critical pressure for fracturing a source rock; (6) the viscosity of hydrocarbons; (7) the relative permeabilities of oil and gas; (8) the lithology-dependent permeability ratio in the vertical to horizontal direction; (9) the total organic carbon in the source rock; (10) the kerogen type; (11) the ages of the source-rock strata; and (12) the palaeoheat flux of the area. The Shongliao Basin, China has been intensively drilled, and two volumes of downhole data are available. Those data were used to set limits on the ranges of parameter values and on geological factors. In this way, an evaluation is given of the relative importance of the twelve contributions influencing primary hydrocarbon expulsion. Both separate-phase gas-expulsion efficiency and the absolute mass amount of gas expelled from the source rock increase with increases in: buoyancy, hydrocarbon saturation in irreducible water in the source rock, capillary pressure, relative permeability, total organic carbon, source-rock age, and palaeoheat flux. However, gas expulsion efficiency and the amount of gas expelled decrease with increases in: hydrocarbon solubility in mobile waters in the source rock, critical fracture pressure, the viscosity of the hydrocarbons, and with changes in kerogen type to a more oil-prone variety. The object of the work presented here is to investigate simultaneously all the processes thought to control primary hydrocarbon expulsion. The Shongliao Basin in China was chosen as a case study because copious, basin-wide data are available.

Air-Xe enrichments in Elk Hills oil field gases: role of water in migration and storage

Hydrocarbons from the Elk Hills Naval Petroleum Reserve (NPR#1), Bakersfield, CA, are enriched in heavy noble gases. The 132Xe/ 36Ar ratios are as high as ∼576 times the ratio in air and represent the largest relative Xe-enrichments ever observed in terrestrial fluids. The Xe isotopic composition is indistinguishable from air. We show that these samples cannot be explained by equilibration of oil with air saturated water and secondary enrichment via a Rayleigh distillation gas stripping process. Based on laboratory studies of others with potential petroleum source rocks, we believe the source of this enriched heavy noble gas component was adsorbed air initially trapped in/on the source rocks that was expelled and mixed with the hydrocarbons during expulsion and primary migration. Kr and Xe enrichments decrease with increasing 36Ar concentration. We propose a model in which an initial Kr–Xe-enriched hydrocarbon becomes diluted with noble gases extracted from air saturated groundwater during expulsion, migration, and storage. The model generates an integrated water/hydrocarbon ratio for the production fluid which indicates a minimal role for water in hydrocarbon expulsion and migration. The results are interpreted to provide time/geometrical constraints on the mechanisms by which hydrocarbons can migrate as a separate phase.

Oil-generating potential of Tertiary coals and other organic-rich sediments of the Nyalau Formation, onshore Sarawak

The oil-generating potential of coals and other organic-rich sediments from the Late Oligocene–Early Miocene Nyalau Formation, the offshore extension of which is believed to be a major source rock, is evaluated. Coals of the Nyalau Formation are typically dominated by vitrinite, with moderate and low amounts of exinite and inertinite, respectively. Significant amounts of clay minerals are present in these coals and those containing between 15 to 65% mineral matter by volume are termed carbargilite. The samples analysed range from sub-bituminous to high-volatile bituminous rank, possessing vitrinite reflectance in the range 0.42% to 0.72%. T max values range from 425°–450°C which is in good agreement with vitrinite reflectance data. Good oil-generating potential is anticipated from these coals and carbargilites with moderate to rich exinite content (15–35%). This is supported by their high hydrogen indices of up to 400 mgHC/gTOC, Py–GC (S2) pyrograms with n-alkane/alkene doublets extending beyond nC 30, and their being in the early to mid-mature oil-window range. Petrographically, the most significant evidence of the oil-generating potential of these coals is the generation of petroleum-like materials (exsudatinite) visible under the microscope. Exsudatinite is a secondary maceral, commonly considered to represent the very beginning of oil generation in coal, which is shown here to also have an important role to play in hydrocarbon expulsion. The precursor of exsudatinite in these coals is the maceral bituminite which readily expels or mobilizes to hydrocarbon-like material in the form of oil smears and/or exsudatinite as observed under the microscope. The maceral bituminite is considered to play a major generative role via early exsudatinite generation, which is considered to facilitate the overall expulsion process in coaly source rocks.

Petroleum systems of Alpine-Mediterranean foldbelts and basins

Abstract The Alpine-Mediterranean area hosts a number of large and smaller hydrocarbon provinces in platforms, rifts, foreland basins and the frontal parts of thrust belts. These hydrocarbon provinces are related to a wide range of source rocks occurring in Palaeozoic, Mesozoic and Cenozoic series. Source rocks are alternatively localized in prerift, syn-rift or passive-margin sequences, the age of which is highly variable. Moreover, syn-orogenic foreland basin sequences can contain important source-rocks and are frequently the locus of biogenic gas generation. Most Mesozoic passive margins of the Western Tethys were destroyed during the Alpine orogenic cycle and were overthrusted by or incorporated into orogenic wedges, the external parts of which host a number of highly diversified petroleum systems. Late Variscan and Alpine compressional intraplate deformation had severe repercussions on the hydrocarbon habitat of some of the Peri-Tethyan platforms. Late Cretaceous and Palaeogene intracratonic and back-arc rifts host some important petroleum provinces; the Euphrates, Abu Gharadig and Sirte basins rely for hydrocarbon charge on syn-rift source rocks whereas post-rift series contain the source rocks of the Black Sea back-arc basin. Oligocene and younger rift systems host the petroleum provinces of the Gulf of Suez, Pelagian Shelf, Valencia Trough and Rhine Graben; these rely variably on pre- and syn-rift source rocks. The Neogene Pannonian system of transtensional back-arc basins relies for hydrocarbon charge mainly on syn-rift source rocks whereas the Vienna Basin is exclusively charged by Mesozoic post-rift source rocks. The complex evolution of the Western Tethys belt, contrasted thermal regimes and successive episodes of sedimentary and tectonic burial account for the great diversity of its petroleum systems. Each hydrocarbon province is characterized by a very distinct scenario for the accumulation of source rocks, timing of their maturation, hydrocarbon expulsion and migration from effective kitchens to potential trapping domains, and the preservation of hydrocarbon accumulations. Future exploration in the external parts of the Alpine orogenic belts, their forelands and beneath the Neogene fill of the Pannonian Basin is likely to yield further oil and gas discoveries. In contrast to the Black Sea Basin, the hydrocarbon potential of the Algero-Provençal, Tyrrhenian and Aegean back-arc basins is questionable. The thick sedimentary sequences of the deep East Mediterranean Basin may contain effective source rocks.

Abstract: Generation, Expulsion and Distribution of Aromatic Hydrocarbon as Maturity-Dependent Process in Post-Santonian Shales and Coals of the Cretaceous Anambra Basin

Abstract: Generation, Expulsion and Distribution of Aromatic Hydrocarbon as Maturity-Dependent Process in Post-Santonian Shales and Coals of the Cretaceous Anambra Basin

Charge and overpressure modelling in the North Sea: multi-dimensional modelling and uncertainty analysis

Over the past one and a half decades developments in our understanding of earth physics and the increase in computer power have enabled quantitative modelling of subsurface temperature, hydrocarbon charge, migration, overpressures and palinspastics. The North Sea has provided the test bed for many of these efforts. Initial developments focused on one dimensional models of temperature and charge as these were computationally possible at that time, and by the late 80s such models were widely available. Despite the current availability of 2D charge modelling tools, most modelling carried out at present is still ID. Hydrocarbon generation is driven by the temperature field which depends on the heat flow, which is only truly vertical in exceptional circumstances. In principle, a whole lithosphere ID model will only agree with a 3D model for a horizontally layered section. Thermal conductivity anisotropy (lateral/vertical conductivity) of mudstones can reach three. Lateral differences in geology also promote changes in geothermal gradients and therefore lateral heat movement. At the lithosphere scale, differences in the depth to the convecting asthenosphere, and the distribution of hot spots may also cause lateral heat flow. In the North Sea, the complex geology particularly within the syn-rift section makes heat flow strongly 3D. In the Inner Moray Firth and Halten Terrace there are considerable differences between the predictions of fully transient 1D and 3D models for the temperature and hydrocarbon expulsion flux histories of the kitchen areas. Differences can exceed 15°C close to major faults: kitchen areas in the hanging walls are typically cooler than would be expected from ID models, whereas basement cored highs are typically hotter than might be expected. The differences between the predictions of ID and 3D models are driven by structural effects and are thus temporally variant. The importance of 3D effects in charge modelling is compounded in hydrocarbon migration models. Temporal changes in carrier bed interconnectivity, fault seal properties and basin structure influence migration, re-migration and even refilling of breached traps. For instance, hydrocarbons found in the Tertiary of the Central North Sea are derived from underlying Jurassic reservoirs where high overpressures have lead to hydrofracturing and hence leakage. Numerical models of overpressure generation, including rapid sedimentation (under-compaction), thermal expansion (aquathermal pressuring), smectite to illite transition (water generation), etc., tell only part of the story: in order for pressures to rise the fluids have to be contained by rocks with sufficiently low permeability. Furthermore, overpressures are transient and gradually diminish when generation ceases. These processes can be described by a relatively simple differential equation, which can be solved to predict overpressures in one or more dimensions. However, in the North Sea, widespread aquifers (e.g. the Fulmar Formation sands) allow pressure transmission out of synclines. Thus, simple ID models are of limited use, and pressure modelling requires prediction of the stratigraphy and temporal variations in aquifer connectivity resulting from structural movement. Palinspastic restoration is thus a prerequisite. In areas such as the Central North Sea, where there is good pressure calibration and relatively simple stratigraphy, modelling enables prediction of overpressure, trap integrity and reservoir continuity. One problem with physical models discussed above has been their inability to incorporate uncertainties. New models are capable of taking into account uncertainties in both model parameters (e.g. compaction coefficients) and input data (e.g. stratigraphic age) to calculate the uncertainty in the modelled variable (e.g. hydrocarbon flux history). Such models provide a much more realistic evaluation of wildcat prospects. The potential of basin models for prospect evaluation and field development is still in its infancy. From a commercial view point, in areas such as the North Sea where data are readily available to most competitors there is little advantage in having the same models as everybody else. The advantage lies in being able to evaluate acreage faster and with greater accuracy, both in the prediction and the uncertainties.

SEAL CAPACITY AND HYDROCARBON ACCUMULATION HISTORY IN DYNAMIC PETROLEUM SYSTEMS: THE EAST JAVA BASIN, INDONESIA AND THE TIMOR SEA REGION, AUSTRALIA

The East Java Basin, Indonesia, and the Timor Sea area and Yampi Shelf of the North West Shelf, Australia, are examples of dynamic petroleum systems where the processes of hydrocarbon generation, explusion, migration, accumulation and leakage are occurring today. Understanding the importance and relative balance of some or all these processes is a key step in reducing exploration uncertainty. In particular, seal effectiveness is a key factor controlling the prospectivity of traps within these petroleum systems.The seals in the East Java Basin are dynamic, rather than absolute, barriers to fluid flow. Empirical and experimental data from the largest producing gas field in the region, Pagerungan, suggest that it is a dynamically filling and leaking capillary trap, which may have been volumetrically larger at some time in the past.In the Timor Sea area, Neogene tectonism has caused both extensional faulting and basin formation. The faulting caused the partial to complete breaching of many of the traps in the region, whereas the subsidence in the newly created Neogene depocentres was the drive for a renewed phase of hydrocarbon expulsion and migration consisting principally of gas. In traps with high seal capacities, this charge of gas flushed preexisting oil accumulations. In other cases, completely breached traps were refilled with gas over periods as short as perhaps 2–3 My.On the Yampi Shelf, dry thermogenic gas is migrating actively across the shelf. Leakage rates to the sea floor are high, particularly as the regional seal thins against basement highs, and as the seal becomes thinner and sandier toward the margin. The risk of gas flushing of low-relief, oil-bearing traps in this area is ameliorated somewhat in a zone where seal capacity is low for gas (favouring gas leakage), but adequate for oil.

Hydrocarbon Expulsion Threshold: Significance and Applications to Oil and Gas Exploration

Hydrocarbon explusion threshold (HET) is the critical condition for hydrocarbon expulsion in separate phase from a source rock when the generated hydrocarbon amount has satisfied all needs for absorption by minerals, solution in water, and blocking of capillary pressure. Research results show that the HET varies mainly with three geological parameters: total organic carbon content (C%), kerogen type index (KTI) and thermal maturation degree (R0). Source rocks with low C% and KTI cross the HET at a high level of maturation degree (larger R0); source rocks with lower R0 and C% can also cross the HET if the kerogen has a larger KTI. Under general geological conditions, a source rock first crosses the methane expulsion threshold (HETgl), then the heavy hydrocarbon gas threshold (HETgn), and finally the liquid hydrocarbon expulsion threshold (HET0). In this paper the concept of HET, and its critical conditions, are applied to establish the scientific validity of the concept and grade the source rocks, to study the phases of hydrocarbons in migration and the mechanisms of hydrocarbon accumulation, and to divide the hydrocarbon expulsion into stages. Applications to different basins in China show that HET provides an accurate and efficient method to guide oil and gas prospecting.

Biomarker maturity parameters: the role of generation and thermal degradation

The effects of burial maturation upon seven molecular maturity parameters, and the concentrations of individual biomarkers employed in these parameters, have been studied in a well in the Barents Sea. The depth interval between 1400 and 3000 m comprises homogenous Eocene claystones with effectively uniform organic carbon content (0.4–0.6%) and kerogen type (HI of 100–200 mg HC/g TOC). The quantitative biomarker data thus contain minimal interference from organic facies, hydrocarbon expulsion effects and the presence of migrated hydrocarbons. Bulk geochemical data define the hydrocarbon generation threshold (or “oil window”) at around 2300 m. Molecular maturity parameters proceed to equilibrium, and in some cases demonstrate inversion at high maturity. These molecular changes are associated with major changes in biomarker concentrations. The % ββ hopane, %22 S C 31 αβ hopane and %20 S C 29 ααα sterane parameters proceed as a result of the balance between the relative rates of generation and thermal degradation of the different isomers. Increased concentrations of the individual isomers are interpreted to be the result of biomarker generation from the kerogen (mainly) and other macromolecular/polar fractions. The % αββ C 29 sterane parameter and the three parameters involving rearranged hopanes (%Ts, %29Ts and %diahopane) operate at higher maturity levels, and proceed as a result of the relative rates of thermal degradation of the compound pairs. Isomerisation in the bitumen may also influence the operation of the parameters involving stereoisomers, but must be a relatively minor contribution.

Summary of the AAPG Research Symposium on Lacustrine Basin Exploration in China and Southeast Asia

In this paper, we review the work presented at the AAPG-Shengli Petroleum Administration Research Symposium dealing with lacustrine basin exploration in China and southeast Asia. This meeting, held in the fall of 1995, revealed that there has been an expansion of the available knowledge base associated with these basins. This increase in information has resulted in a better understanding of lacustrine basin-fill properties and characteristics, even though many of the causal mechanisms for these properties have not yet been established. The many papers presented suggest that there are two primary causes for economic failure within many of these basins: (1) communication between source and reservoir and (2) the limited reservoir potential within the lacustrine sequence of these basins. More effective petroleum systems are found in basins where marine sandstones are in communication with lacustrine sources. The discussions also clearly demonstrated that lacustrine basins are sensitive to environmental changes, causing complex sedimentary facies successions. Each facies, however, displays unique characteristics that can be mapped. Several presenters also suggested that within extensional lacustrine settings the stratigraphic succession follows a distinct pattern. Although most of these basins are predominantly oil prone, several lacustrine basins within the region contain significant volumes of gas. Included within these gas reserves are biogenic accumulations that appear to have formed nearly penecontemporaneously with deposition. Recent work on several of the Chinese basins suggests the possibility for immature hydrocarbon generation and expulsion in a manner different than that associated with marine type II-S kerogens. Even with the progress that this symposium revealed there are several key questions that remain, including questions associated with how technology might be used to improve the economics of many of these systems that display limited reservoir potential.

Proterozoic Source Rocks: Sedimentology and Organic Characteristics of the Velkerri Formation, Northern Territory, Australia

The Velkerri Formation (~1.43 Ga) in northern Australia is one of the organically richest Pro terozoic successions in Australia and over the last 10 yr has been a target for oil exploration. This formation is predominantly a glauconitic marine shale deposited in restricted to anoxic conditions in a deep-water pro-delta slope to basin environment. The Velkerri Formation is composed of superimposed sediment couplets made up of laminated black organic-rich mud shales [total organic carbon (TOC) ~4-6%] and laminated gray-green organically lean mud shales (TOC <2%). The couplets stack at scales ranging from centimeters to meters. Of particular interest are three black organic-rich mud shales in the middle Velkerri Member, tens of meters thick and correlatable over much of the drilled area of the basin. Their high organic contents reflect changes in organic productivity vs. the rate of sediment supply, and not fluctuating oxygen levels in the bottom waters or changes in water depth. Extractability and Rock-Eval data show more efficient expulsion of hydrocarbons from the upper two of the three organic-rich units in the middle Velkerri. Evidence also exists for local, intraformational migration of hydrocarbons into siltstone layers. Nevertheless, the middle Velkerri has very low permeability and porosity, and still retains a significant fraction of its generated hydrocarbons, especially in the lower portions of the middle Velkerri where a volcanogenic provenance led to the early blocking of pore throats by clay diagenesis during early burial. This study emphasizes the high quality of Middle Proterozoic source rocks for petroleum exploration in northern Australia. The main problem is finding traps that can preserve hydrocarbons over the long periods of time since the rocks became charged with hydrocarbons.

A multidisciplinary approach to modelling secondary migration: a Central North Sea example

Abstract Numerical simulations assist in understanding secondary migration, and can help estimate which traps in a basin may have received a hydrocarbon charge. This is illustrated by a suite of numerical models used to track the secondary migration of hydrocarbons into an Upper Jurassic Fulmar discovery in the Central North Sea. The models include areal flow calculations using Exxon’s proprietary reservoir simulator, and cross-section calculations using TEMISPACK, a commercial basin modelling package. While the application of conventional reservoir simulation techniques to geologic time-scale problems is itself a novel approach, the most important development has been in the integration of fluid flow modelling with techniques for dating the timing of hydrocarbon charge. These techniques have been used to constrain and validate the model results. In addition, sensitivity studies permit evaluation of the required permeability for effective lateral migration. The areal calculations provide information about migration timing and the fill history of several traps. These fields are charged from mature Kimmeridge source rocks, mapped within the local drainage area. Several model runs were used to evaluate the sensitivity of migration timing to carrier bed permeability and capillary pressure characteristics. Calculations indicated that for reservoir quality carrier beds (permeability ≥ 1 mD) secondary migration can be geologically instantaneous, and that even low permeability silts can serve as effective migration pathways. A cross-sectional model was used to integrate cross-stratal and strata-parallel migration. The model included hydrocarbon expulsion from Kimmeridge source rocks into the Fulmar sandstone and lateral migration up the flank of the structure. Drilling results indicate that leakage into younger Tertiary strata has occurred. The calculation sugests a portion of the top seal breached by 10–20 Ma. Evidence of partial seal loss includes a seismic chimney interpreted above the predicted breached seal, and an appraisal well high on the Jurassic structure which encountered hydrocarbon-stained reservoir rocks with an apparent palaeohydrocarbon contact. Furthermore, hydrocarbons in the overlying Tertiary reservoirs can be geochemically tied to the remaining Jurassic accumulation. Finally, analysis of authigenic cements, particularly the K-Ar ages of fibrous illite, suggests that hydrocarbons occupied the trap until approximately 10 Ma. Analysis of Tertiary hydrocarbon fluid inclusions further indicates that hydrocarbons entered these Tertiary reservoirs approximately 10 Ma. These latter two techniques now enable the modeller to apply temporal constraints to hydrocarbon charge simulation. Such constraints allow ‘history matching’ analogous to field scale reservoir simulations.

Uncertainty analysis and the relative contributions of geological factors for the Qingshankou source rocks in the North Songliao Basin, northeastern China

Source rock evaluation is a critical factor in resource assessment of oil and gas. Models for evaluating source rocks are dependent on established geomathematical principles, the calculation of source-rock parameters, and geological data. The sensitivities and uncertainties associated with these models are a matter of concern. In this paper, the effects and relative contributions of 13 major geological factors, as well as their variations and distribution probabilities, have been analyzed for the source rocks in the North Songliao Basin in northeastern China. The geological factors include the time of formation of the regional caprock, composition of the regional caprock, the phases of hydrocarbons in migration, and those factors associated with the generation, retention, and expulsion of hydrocarbons and their effects on source-rock efficiency. Of the 13 factors analyzed, the most important are the source-rock depth, sedimentation rate, total organic content, and kerogen-type index; the relative contributions to the uncertainty of efficient gas/oil migration amounts for the most important factors are 37, 25, 19, and 1% for oil and 32, 17, 20, and 15% for gas, respectively. These most reflect the changes that have occurred in the Qingshankou source rocks.

Information gain in prospect assessment by using basin modeling

To enhance the quality of oil- and gas-resource assessments and to reduce the risks in oil and gas exploration, a number of assessment techniques have been developed. Unfortunately, these techniques have not always been effective in the timely transfer of information. The amount of time that is required for preparing assessments does not always allow for the necessary high-quality data to be generated. To overcome this problem, a method based on an analysis of the phase state of oil and the dynamics of fluids in secondary migration of hydrocarbons is proposed. The phase state of the oil and fluid potential for secondary migration is estimated initially for each prospect together with the extent of the drainage area. On the basis of these estimates, statistical calculations can be made for the generation and expulsion of hydrocarbons. As a result, more reliable data are available for prospect assessment. The application of this method has a practical significance in that it brings the role of basin modeling in prospect assessment into full play, increases the reliability of petroleum-resource assessments, and reduces the risks in exploration. A case study from the Beitang region in eastern China is presented.

Quantitative evaluation of coal as source rocks

Gas generated and expelled from coals often results in economic gas accumulations. As a consequence, it is important to consider the theoretical aspects of these processes and to develop methods that can be used to assess coal as a potential source rock. On the basis of results of modeling hydrocarbon generation, expulsion, and retention in coals, two comprehensive indexes are proposed for assessing the quality and the nature of coal as a potential source rock. Theoretical charts of the two indexes are used to assess coals as potential source rocks in the Turpan-Hami Basin in northwestern China.

Evidence of early generation of liquid hydrocarbon from suberinite as visible under the microscope

The early generation of liquid hydrocarbons from suberinite can be clearly observed under the microscope. The generation of this oil-like material, mainly in the form of exsudatinite, from the maceral suberinite occurs at a maturity level of about 0.4% vitrinite reflectance. Hydrocarbons appear to be naturally expelled from coal initially through sweating and agglomeration of suberinite which subsequently forms exsudatinite. It is suggested that extensive expulsion of exsudatinite causes cracks to develop in vitrinite whereas limited expulsion of exsudatinite will only impregnate the vitrinite matrix. If cracks are formed, it is possible they could progressively develop to form an exsudatinite-crack network. The formation of such a network is believed to represent an effective way of hydrocarbon expulsion from coal source rocks.

Main factors influencing the expulsion of oil derived from coal

THE expulsion of hydrocarbons from coal is controlled by two main factors. The first is theproperties inherited from coal itself and contains two implications. One is original potential ofhydrocarbon generation from coal, which determines the degree of oil-bearing saturability; the...

Relative Contributions of Geological Factors to Uncertainty of Hydrocarbon Expulsion from the Qingshahou Source Rock in the North Shongliao Basin, China

Hydrocarbon expulsion from a source rock is the basis of resource assessment of oil and gas. Model results for hydrocarbon expulsion from a source rock are dependent on the geomathematical models used, selected calculation parameters and available geological data; the sensitivity and uncertainty of the assessments are of greater and greater concern. This paper, applying basin modelling and uncertainty analysis methods to the SHONGLIAO basin, studied the effects and relative contributions of thirteen major geological factors to the uncertainty of model results for hydrocarbon expulsion, as well as examining the variations and distribution probabilities. Formation time of a regional caprock, composition conditions of source-reservoir-caprock, phases of hydrocarbons in migration, and all other geological factors associating with hydrocarbon generation, retention, have effects on the efficiency of hydrocarbon expulsion. The most important factors which result in the largest change of expulsion from the Qingshahou source rock in the North Shongliao basin are: depth of source rock (ZM), sedimentation rate (SR), total organic carbon (TOC %), and kerogen type index (KTI), with relative contributions (%) to the uncertainty of efficient gas/oil migration amounts at 37/32, 25/17, 19/20, and 1/15, respectively. Of these factors, KTI has a greater effect on oil migration than on gas, while SR and ZM have more effect on gas. Within the variation ranges of the thirteen major geological factors, the above four factors collectively contribute to efficient gas/oil migration amounts (m3/kg) from the Qingshahou source rock on a square (or cubic) meter basis as: 1010/1100 (3.0/3.26), 1300/1370 (3.86/4.07), 1460/1525 (4.33/4.53) and 2150/2200 (6.38/6.53), respectively, with corresponding cumulative probabilities of 16%, 50%, 68% and 84%, respectively.

97/03633 Present status and development of geochemical research on hydrocarbon expulsion effects

97/03633 Present status and development of geochemical research on hydrocarbon expulsion effects

97/01739 Recovery of highly viscous products from open or closed storage areas such as tanks and sumps

The mudstones in the third member of the Shahejie Formation (Es3) are the primary source rocks in the Banqiao Depression of Bohai Bay Basin. They are rich in organic matter with Total Organic Carbon (TOC) content up to 3.5%. The sandstones in the Es3 member are the deepest proven hydrocarbon reservoir rocks with measured porosity and permeability values ranging from 3.6% to 32.4% and from 0.01 md to 3283.7 md, respectively. One, two and three-dimensional basin modelling studies were performed to analyse the petroleum generation and migration history of the Es3 member in the Banqiao Depression based on the reconstruction of the burial, thermal and maturity history in order to evaluate the remaining potential of this petroleum province. The modelling results are calibrated with measured vitrinite reflectance (Ro), borehole temperatures and some drilling results of 63 wells in the study area. Calibration of the model with thermal maturity and borehole temperature data indicates that the present-day heat flow in the Banqiao Depression varies from 59.8 mW/m2 to 61.7 mW/m2 and the paleo-heat flow increased from 65 Ma to 50.4 Ma, reached a peak heat-flow values of approximately 75 mW/m2 at 50.4 Ma and then decreased exponentially from 50.4 Ma to present-day. The source rocks of the Es3 member are presently in a stage of oil and condensate generation with maturity from 0.5% to 1.8% Ro and had maturity from 0.5% to 1.25% Ro at the end of the Dongying Formation (Ed) deposition (26 Ma). Oil generation (0.5% Ro) in the Es3 member began from about 37 Ma to 34 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 30 Ma to 15 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Es3 member source rocks began from 31 Ma to 10 Ma with the peak hydrocarbon expulsion shortly after 26 Ma. Secondary petroleum migration pathways in the Es3 member of the Banqiao Depression are modelled based on the structure surfaces at 26 Ma and present-day, respectively. The migration history modelling results have accurately predicted the petroleum occurrences within the Es3 member of the Banqiao Depression based on the calibration with drilling results of 10 oil-producing wells, one well with oil shows and 52 dry holes. Six favorable zones of oil accumulations in the Es3 member of the Banqiao Depression are identified especially oil accumulation zones I and II due to their proximity to the generative kitchens, short oil migration distances and the presence of a powerful drive force.