Fault zones in porous sandstones are commonly divided into two parts: a fault core and a damage zone. Both fault-zone elements could influence subsurface fluid flow and should be incorporated in a geologically realistic model. The fault core can be implemented in the model as a transmissibility multiplier (TM), while the damage zone can be implemented by modifying the grid permeability in the cells adjacent to the model faults. Each of the input parameters used in calculating the TM and damage-zone permeability modification is subject to geological uncertainty. Here an iterative workflow is employed to define probability distribution functions for each of the input parameters, with the result being many fault-model realizations. Here two methods are examined for ranking and selecting the fault-model realizations for further analysis: (i) calculating the flow-indicator fault properties (effective cross-fault transmissibility and effective cross-fault permeability) from the static model; and (ii) employing a simplified flow-based connectivity calculation, returning dynamic measures of model connectivity. The aims are to outline the methodology and workflow used, evaluate the impact of the different input parameters on the results, and examine the results of the static and dynamic approaches to understand how the ranking and selection of models compares between the two.Our results are dependent on the structural model. In a strongly compartmentalized model based on the Gullfaks Field, North Sea, fluid-flow-indicator fault properties are weakly correlated with measures of dynamic behaviour. In particular, models with low fault transmissibility show a much greater range of dynamic behaviour, and are less predictable, than models with high fault transmissibility. In a weakly compartmentalized model with strongly channelized fluvial facies based on the Whitley Bay area in NE England, there was a strong correlation between flow-indicator fault properties and measures of dynamic behaviour. We ascribe these results to the greater complexity of flow paths expected when a highly compartmentalized model contains faults that are likely to be baffles to cross-fault flow.Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019
We present the results of a 3D fault-seal analysis across the central part of the Jasmine Field, Gulf of Thailand. Two techniques were applied; a stochastic juxtaposition analysis across thin, stacked, laterally variable reservoirs and then a comparison of fluid contacts and reservoir capillary pressure against predicted fault clay content. The two methodologies can be compared to better understand how they provide insights into reservoir behaviour. Our objective was to estimate capillary threshold pressures for fault-seal calibration in exploration prospects in the Gulf of Thailand. First, the stochastic juxtaposition analysis workflow evaluated whether known oil/water contact (OWC) levels in the key reservoir intervals could be explained by crossfault juxtaposition patterns. Second, modeling was used to calibrate fault capillary threshold pressure against predicted fault clay content. Fault clay content is estimated from the shale gouge ratio (SGR) and compared to the reservoir capillary pressure estimated from known OWC levels and fluid densities for each reservoir interval. The maximum capillary threshold pressure for a given clay content can be estimated and calibrated to trend curves for fault seal across the basin. For 12 key reservoir zones examined, stochastic juxtaposition analysis cannot explain observed OWC levels by crossfault juxtaposition for all reservoir intervals. Therefore, control by structural spillpoints and/or capillary membrane sealing across faults is required. Estimated capillary pressure information is combined with measured mercury-air capillary threshold pressure from Jasmine A reservoir samples and published data to create clay content-capillary threshold pressure curves to estimate fault-sealing capacity across the Jasmine Field. The results can be applied to other fields and prospects in the Gulf of Thailand. Fault-seal analysis and estimation of fault properties in areas with multiple stacked, laterally variable reservoirs is notoriously problematic because of the large uncertainties involved. Our approach of stochastic juxtaposition analysis combined with capillary pressure modeling allows the uncertainties to be addressed while providing concise and usable input to decision-making.
Compartmentalization of reservoirs in operating fields is commonly caused by sealing of faults (Cerveny et al., 2004; Davies and Handschy, 2003;Davies et al., 2019; Knipe, 1992; Yielding et al., 1997; Yielding et al., 2010). Calibrating this seal, however, is difficult without adequate subsurface data. A local region across the central part of the Jasmine Field, Jasmine A, along the northern extent of the Pattani basin in the Gulf of Thailand, was selected in this study for detailed fault-seal analysis calibration. The objective was to present the details of the fill and spill history from a juxtaposition analysis across the faults. The large number of well penetrations with fluid and lithofacies data and the 3D models of mapped permeability distribution provided a subsurface framework to reduce the uncertainty and allow a more comprehensive analysis of the crossfault reservoir juxtaposition and fluid contact levels. Crossfault flow behavior and fill and spill history were evaluated by examining fluid contacts in a strike view of the fault, with the properties juxtaposed. The Jasmine Field is a narrow structural high that is cut by many NE-SW and NNW-NNE trending faults forming fault-bounded compartments. Reservoirs in the field are typically thin, stacked high-permeability fluvial sandstones of primarily Miocene age separated by thin shale beds that occur over a depth range of several thousand meters. Many of the sands have unique hydrocarbon-water contacts of oil or gas and water. Reservoir juxtaposition across the faults suggests that fault seal plays a major role in the trap. By comparing fluid contacts in each fault block, cases with different contacts across the fault likely represent a fault membrane seal. Contacts occurring at the same height suggest crossfault leakage. The evaluation was done by estimating permeability distributions across the fault. These results, however, were not adequately determined simply from the fluid contacts on either side of the fault: fill histories in adjacent fault blocks and lateral structural controls also had to be accounted for. The results together allowed a unique fill and spill history to be defined. The results of the juxtaposition analysis for the main faults bounding the local structural trap in Jasmine A provided a calibration for a 3D analysis of the faults, including estimation of fault-rock properties.
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