First EAGE Basin & Petroleum Systems Modeling Workshop

1D, 2D and 3D hydrocarbon charge modeling and source rock characterization had been performed in the Komombo area to re-evaluate the exploration potential in the development area and to evaluate the poorly explored regions in the northwestern part of the basin, and to address uncertainties about the potential prospects in the block.

1D models helped to understand the burial and thermal history and the impact of multiple erosion on timing of maturity and hydrocarbon generation. 2D modeling (in the development area) provided information on timing of hydrocarbon generation, on the effect of fault sealing capacities and litho-facies distribution on migration and accumulation of hydrocarbons. In addition different migration methods were applied, which helped to understand the petroleum systems of the Komombo basin. This gained insight was used for the 3D petroleum system model of the greater Komombo basin. The main objective of 3D modeling was to understand hydrocarbon migration and accumulation and its timing.

Maturity and hydrocarbon generation are mainly controlled by Late Cretaceous to Eocene burial and the second heat pulse at ∼40 Ma; another key parameter is the Tertiary erosion thickness. Only in the deepest part of the basin Komombo-B source rocks are already in oil window during Early Cretaceous.

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Basin and petroleum system modeling of northeast part of the Black Sea have been performed in order to estimation of the oil and gas prospects of the region. Mesozoic traps of Shatski rige can be considered as a promising object for hydrocarbons prospecting. Main risks associated to the investigated hypothetical petroleum system related to presence of quality hydrocarbon reservoirs, therefore additional investigations are required.

Pre-Westphalian layers are considered as potential source rocks in the Netherlands. However, there is little amount of information available on their maturity. 3D basin modelling is carried out on Central Onshore Netherlands to investigate the maturity of the deep Carboniferous source rocks. A detailed 3D geological model is used as input which is based on the results of the recent mapping activities in the Netherlands. Heat flow is modelled in the study area based on the tectonic evolution of the structures. The Permian uplift (Saalian event) and the associated magmatic activities are taken into account. This event has resulted in a thermal peak depicted as a peak in heat flow in the Permian. The thermal peak has influenced the maturity of the Carboniferous source rocks causing early maturity and hydrocarbon generation. Upper Carboniferous source rocks (Westphalian formations) seem to have produced some hydrocarbons in later stages which could be responsible for charging the gas fields.

In quartzose sandstones with low thermal maturities, porosity evolution during burial is controlled primarily by effective stress (compaction). Many workflows assume that the effective stress may be approximated by the vertical effective stress (VES). This simplification is not appropriate in compressive (SH > Sh ≥ SV) or strike-slip (SH > SV ≥ Sh) regimes where horizontal stress components are equal to, or exceed, the vertical stress. Despite abundant published field evidence, many explorationists continue to underestimate sediment compaction in compressive regimes.

In order to illustrate the problem, we:

1. estimated the magnitudes of the principal stress components using Anderson’s faulting theory,
2. transformed them into a single parameter - “equivalent mean effective stress (p*)”- using the Modified Cam Clay model.
3. applied p* in place of VES in the basin and reservoir modeling workflow.
4. calculated multiple porosity predictions in Touchstone™ for sand samples from NW Borneo assuming realistic compaction parameters and various modified VES histories.

As a rough rule of thumb, rocks near reverse faults experience the highest lateral stress and their porosities are ∼8 % (relative to bulk rock) lower than in normally compacted sediments. Increasing VES 2–3 times in existing modeling tools yields approximately correct porosities in this environment.

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We have developed a specific workflow to evaluate prospects in gas/oil shale exploration which integrates Rock-Eval data, TOC log interpretation, basin modeling and prospect evaluation using a single working platform (OpenFlow Suite). This workflow is based on a combination of modified classical approaches and recent or newly developed ones.

These new and modified approaches are innovative because they focus on what “remains” in the source rocks. Accordingly, Rock-Eval, still a fast tool for source rock evaluation, has now a new experimental protocol which is able to better evaluate the S1 peak.

Estimation of organic content (Carbolog) is now available in our well log interpretation software (EasyTrace)). As part of an integrated workflow, all the data and results are easily transferred between the different tools (EasyTrace, TemisFlow) thanks to a transverse data base under OpenFlow Suite. This shared platform makes log interpretation, map construction and numerical modeling (1D, 2D, 3D or Multi1D) easier.

Basin simulator has also been improved in order to be more predictive both on the fluids (mobile and adsorbed phases) and on the solid matter which are still present is the source rock, making calibration phases faster and easier.

All these developments are making breakthroughs for unconventional source rock evaluation.

Recent exploration activities in two of the largest deltas in the world, the still active Nile delta and the Cenozoic Southern North Sea (SNS) deltas, proved the potential of shallow gas resources. However, shallow gas production is still limited due to a lack of understanding of this gas system. For both the Nile and the SNS delta, there is an on-going debate about the origin of the gas. For both settings, the origin of shallow gas may be deep subsurface thermogenic sources, microbial sources in shallower strata, or a mixture of both. The origin of shallow gas was studied in the Dutch SNS delta as part of a comprehensive multidisciplinary workflow developed and applied to enhance the quantitative knowledge and understanding of the shallow gas play in the delta ( Ten Veen et al., 2014 ). Timing and quantification of microbial gas generation in the SNS delta was studied using a combination of different modeling approaches, and included new detailed basal and surface thermal boundary conditions. Modeling results indicate that intra SNS delta deposits are an important source of microbial gas that are able to fill most of the available traps in the Dutch SNS delta.

Recent publications promote one-run, open-system pyrolysis using a single heating rate (ramp) and fixed frequency factor to determine petroleum generation kinetics of source rock samples. Comparison of kinetic models derived from single and multiple ramp experiments for a 53-sample suite of worldwide source rocks shows that one-ramp kinetics are generally unreliable. Kinetic results based on three pyrolysis temperature ramps closely approximate those from six runs, provided that the three ramps span an appropriate range. Ramps of 30 and 50 degrees C/min are generally too fast to obtain a good kinetic fit using Pyromat II® data due to delayed heat transfer between the sample and thermocouple. Therefore, at least three pyrolysis ramps are recommended that span a ten-fold variation of comparatively slow rates, such as 1, 3, and 10 degrees C/min or 1, 3, 5, and 10 degrees C/min. Replicate analyses are best, particularly for the highest and lowest heating rates within the range because they dominate the calculated kinetic results.

The next generation of basin modeling software is probably going to witness a revolution in the output and visualization of data at a bulk or a molecular scale, where users will be able to extract organic geochemical fingerprints of candidate source-rocks and compare them with accumulation fingerprints. Having access to a tentative estimate of the concentrations of various organic compounds (a general estimate of the shape of their chromatogram) can provide valuable shortcuts for upgrading and fine-tuning modeling results. The modeler could get a preview of the distribution of various geochemically-important components within any cell from a given source-rock layer (i.e. mass chromatograms at various m/z ratios). Addition of this new dimension to the modeling procedure will have some important implications for model-calibration, organic geochemical correlations and comprehensive monitoring of the alteration of hydrocarbons.