Deriving global parameters for velocity-based pore pressure predictions in a complex overpressure origins regime is normally difficult and nonrobust. Applying large variations in Eaton’s exponent is an unsatisfactory work practice for velocity-based pore pressure prediction. This study investigates an alternative potential method to reduce the variation of Eaton’s exponent values in an environment of mixed disequilibrium compaction and fluid expansion overpressure mechanisms. Using 25 input wells, the fluid expansion components are estimated using velocity-vertical effective stress plot and then subtracted from the pressure measurements to obtain the disequilibrium compaction components. Eaton’s exponents are then derived only from the disequilibrium compaction components. The spatial variation of Eaton’s exponent is greatly reduced from the range of 1–5 to the range of 1–1.9 after removing the fluid expansion components from the raw overpressure data set. A constant Eaton’s exponent of 1.44 is used throughout the field to predict the disequilibrium compaction components and the fluid expansion components are predicted from gridding of the well data. The two components are combined to produce a final pore pressure prediction profile, which yields less uncertainty than the traditional Bowers method.
Three-dimensional seismic reflection data, well data, and analogues from areas with extensive shale tectonics indicate that the enigmatic deepwater “shale nappe or thrust sheet” region of northern offshore Sabah, Malaysia, now referred to as the North Sabah–Pagasa Wedge (NSPW), is actually a region of major mobile shale activity characterized by mini-basins and mud pipes, chambers, and volcanoes. A short burst of extensive mud volcano activity produced a submarine mud canopy complex composed of ~50 mud volcano centers (each probably composed of multiple mud volcanoes) that cover individual areas of between 4 and 80 km2. The total area of dense mud canopy development is ~1900 km2. During the middle Miocene, the post-collisional NSPW was composed predominantly of overpressured shales that were loaded by as much as 4 km thickness of clastics in a series of mini-basins. Following mini-basin development, there was a very important phase of mud volcanism, which built extensive mud canopies (coalesced mud flows) and vent complexes. The mud canopies affected deposition of the overlying and interfingering deposits, including late middle to early late Miocene deepwater turbidite sandstones, which are reservoirs in some fields (e.g., Rotan field). The presence of the extensive mud volcanoes indicates very large volumes of gas had to be generated within the NSPW to drive the mud volcanism. The Sabah example is only the second mud canopy system to be described in the literature and is the largest and most complex.
Seismic interpretation is the key process to support the evaluation of all petroleum system elements. With traditional interpretation workflow, seismic interpreters have to put a significant effort to ensure that interpreted reflection does tie at the intersecting lines. Since correcting seismic interpretation mis-tie is tedious, repetitive, and time-consuming, we have developed an in-house python toolkit to automatically identify and correct the interpretation mis-tie. To identify seismic interpretation mis-tie, first, we will loop over interpreting line intersections and extract the values of interpreted horizon near each intersection. Then, the statistical distributions of interpreted horizon from each interpreting line will be compared. Interpretation agreement will be justified based on the proximity of derived distributions. If their medians are closer than the averaged standard distribution, such locations will be classified as valid interpretations; otherwise, they will be marked as potential mis-ties. Eventually, identified mis-ties will be corrected to the new location suggested by interpolation of valid interpretation nearby. The toolkit has been validated and used to correct seismic interpretation from PTTEP oil fields onshore Thailand. The results are satisfying as the tool can correct most interpretation mis-tie errors in a few minutes, while manual correction would take up to a few weeks. Furthermore, we have assessed the volumetric difference from the maps with and without mis-tie correction. The result shows that the preliminary interpretation with remaining mis-ties yields 9.02% less gross rock volume (GRV) than the actual GRV from the final mapping. Meanwhile, the resulting map from the automated mis-tie correction yields 2.93% different from the actual GRV. By reducing volumetric uncertainty, the automated interpretation mis-tie corrector could lead to better decision-making on block evaluation/acquisition, well planning, and field development.
Combination and stratigraphic traps may contribute with significant gas reserves in Bongkot Field, Gulf of Thailand. However, such stratigraphic play cannot be easily defined as conventional seismic interpretation provides mainly structural information. To identify stratigraphic prospects in this area, a seismic pre-stack inversion and reservoir characterization study was carried out. The input dataset consisted of 365 km2 of 3D seismic, six wells, and interpreted time horizons. Following seismic pre-conditioning and rock physics analysis, wavelet extraction and well-ties were performed for each individual well, considering every input angle stack. Constrained by input time horizons, low frequency models were built based on well log and seismic stacking velocity. Inversion parameters were tested; subsequently, final inversion results were subjected to Bayesian classification to obtain a litho-facies volume. In addition, multi-linear regression was used to derive elastic-petrophysical relationships, to generate petrophysical property volumes. The final results included inverted elastic properties, classified litho-facies, computed effective porosity and Vshale volumes. By analyzing these results, several channel and deltaic/sand lobe features could be observed throughout the study area. Connected sand-filled channels with high porosity were mainly observed in the shallow section, as sand distribution appeared sparser and more isolated with increasing depth. Also, the predicted reservoirs in the deeper section were mostly filled with gas, while shallower sand bodies were mostly filled with brine. This observation implied that the high net-to-gross reservoir distribution in the shallow section can be a key factor that hinders effective trapping of hydrocarbons at this level. Since reservoir distribution plays a key role in hydrocarbon trapping mechanism, upside stratigraphic potential was identified from isolated gas-filled channels, mapped from seismic inversion products, to implement a more successful field development strategy in a mature field.
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