The Neogene carbonate succession on the island of Bonaire (Netherland Antilles) shows complex geometries associated with a sequence of depositional and erosional events which reflects the history of this isolated platform and the interaction between eustasy and tectonics. Three major episodes of carbonate platform deposition are defined which show contrasting depositional styles: 1) aggradational platform (Lower-Middle Miocene) with sediments showing a fining-upward trend from mixed coral rudstone to medium-grained coralgal grain/packstone, partly dolomitized and tilted by tectonic deformation; 2) 2 prograding platform (Upper Miocene-Pliocene) which is formed of several shallowingupward prograding units mainly composed of reworked red algal grain/packstone, with significant dolomitization, passing upward to shoreline and aeolian deposits formed of coralgal grain/packstone and large benthic foraminifera grainstone, and 3) flat-topped platform (Pleistocene) with a reefal framework composed of a rich variety of corals in a bioclastic pack/wackestone matrix. These platform episodes exhibit contrasting stacking patterns and are separated by erosional unconformities. Overprinting this depositional succession is a series of Quaternary near-horizontal shoreline erosional terraces and vertical cliffs which have been cut into the island stratigraphy and complicate the stratal field relationships. However, this terrace morphology clearly does not represent depositional episodes, as has been suggested before. The internal architecture of each of the three carbonate platform episodes reflects interaction of the dynamics of sedimentation with allogenic controls. The latter relate to major oceanographic and tectonic events in the region, including changing ocean circulation as a result of the closure of the Panama isthmus, and Caribbean plate dynamics that affected sea-floor and island topography. The Bonaire succession provides a model for understanding and predicting isolated carbonate platform development, as well as architecture, facies and potential diagenetic changes, in an active tectonic setting.
Calculating subsurface pressures and predicting overpressured zones, in particular for safe drilling operations, is an integrated approach based on data and assumptions from various sources. Uncertainties arise from the input data and assumptions, but also from the pore-pressure modeling workflow including shale discrimination and the definition of a normal compaction trend line. These stages are usually performed manually by an expert and are prone to subjective, human interpretation. The quantification of pore-pressure uncertainty associated with the manual modeling stages is, therefore, challenging. Algorithms were developed to account for and quantify the resulting uncertainty and enable automated user support of at least parts of the workflow, thus introducing more objectivity into the modeling steps. The first algorithm performs a statistical analysis on gamma ray logs to discriminate between shale and nonshale formations. The second algorithm calculates a series of normal compaction trend lines from porosityindicating logs from which average pore-pressure models and uncertainty envelopes can be determined. Furthermore, the behavior of trend-line envelopes from the series of trend lines was quantified by a parameter Q, which turned out to become constant in the overpressure region. The algorithms were applied to 23 data sets from different regions worldwide. Pore-pressure uncertainty was identified to be in the range of up to 8% for shale discrimination and less than 20% for normal compaction trendline setting. In addition, pore-pressure uncertainty in the overpressure zone correlated with the Q-factor, which can be used to estimate pore-pressure uncertainty at greater depth from whiledrilling measurements in the normal compaction zone. The results also exemplify regional uncertainty variations, which imply that modeling parameters need to be adjusted for specific regions. Moreover, the examples demonstrate that automated algorithms are beneficial methods to add objectivity and reproducibility to the modeling procedure.
We developed a seismic geomorphology‐based procedure to enhance traditional trajectory analysis with the ability to visualize and quantify lateral variability along carbonate prograding‐margin types (ramps and rimmed shelves) in 3D and 4D. This quantitative approach analysed the shelf break geometric evolution of the Oligo‐Miocene carbonate clinoform system in the Browse Basin and delineated the feedback between antecedent topography and carbonate system response as controlling factor on shelf break rugosity. Our geometrical analysis identified a systematic shift in the large‐scale average shelf break strike direction over a transect of 10 km from 62° to 55° in the Oligo‐Miocene interval of the Browse Basin, which is likely controlled by far‐field allogenic forcing from the Timor Trough collision zone. Plotting of 3D shelf break trajectories represents a convenient way to visualize the lateral variability in shelf break evolution. Shelf break trajectories that indicate contemporaneous along‐strike progradation and retrogradation correlate with phases of autogenic slope system re‐organization and may be a proxy for morphological stability of the shelf break. Shelf break rugosity and shelf break trajectory rugosity are not inherited parameters and antecedent topography does not dictate long‐term differential movement of the shelf margin through successive depositional sequences. The autogenic carbonate system response to antecedent topography smooths high‐rugosity areas by filling accommodation and maintains a relatively constant shelf break rugosity of ~150 m. Color‐coding of the vertical component in the shelf break trajectory captures the creation and filling of accommodation, and highlights areas of the transect that are likely to yield inconsistent 2D sequence stratigraphic interpretations.
Pore pressure related wellbore instability is a recognized drilling challenge requiring attention as early as possible to mitigate and remediate severe drilling hazards such as kicks. Methods exist to quantify the effects of certain input parameters on pore pressure models, but the effect of the different, partly manual stages in pore pressure modeling on the uncertainty has rarely been addressed in the past. This paper highlights uncertainty sources associated with the basic stages in pore pressure modeling: shale discrimination using the gamma ray log and definition of the normal compaction trend line, either manually or using a regression analysis. Furthermore, filtering of the data prior to trend line definition may also add to some amount of uncertainty. These uncertainties in pore pressure prediction introduced by the modeling stages is demonstrated on an example data set from an offshore well. In particular, we show that applying different shale discrimination approaches can introduce pore pressure variations. Furthermore, a variation in depth intervals over which the trend line is automatically determined by linear regression can add more uncertainty to the pore pressure model. An approach is presented to quantify pore pressure uncertainty by automatically analyzing the variation in normal compaction trend lines. The application of the proposed method aims to constrain and quantify the error associated in modeling pore pressure in real-time, based on surface and subsurface (MWD and LWD) data. Modeling both pore pressure and its uncertainty creates additional value for safer drilling, because rig and remote monitoring personnel are made aware of a dynamic updated pore pressure range in addition to the possible pressure regimes interpreted during pre-drill modeling.
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