For a green field, estimating fluid contacts can be challenging when there is large uncertainty due to the lack of fluid contact penetration by the appraisal wells, insufficient pressure data in oil or water legs, or ambiguous seismic amplitude shut off. For reserves booking, SEC Rule 4-10(a)(22) states that "In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless Geosciences, Engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty." One way to ensure reasonable certainty conditions are met for contacts beyond LKH and to increase confidence for probable and possible fluid contacts that may be estimated using regional pressure trends is to analyze the seal capacity to check whether the seal would hold the hydrocarbon column associated with the proposed contacts.There are two methods for testing seal capacity within the framework of a capillary pressure model. One method uses the capillary entry pressure for a sealing layer (P seal ) to compute the maximum hydrocarbon column (H max_seal ) that a sealing layer (e.g. shale, silt, salt, anhydrite, etc.) can sustain without leaking. However, P seal data are usually not available since such lab measurements are not typically made with the sealing layers. The other method uses the shale fracture pressure (P frac ) estimated from a model that incorporates leak of pressure measurements across sealing layer to compute the H max_frac that the shale layer above the reservoir can sustain without fracturing.This presentation is aimed at sharing the approach using fracture pressure to analyze seal capacity, establishing reasonable certainty associated with proposed fluid contacts. Application of this method will be shown using examples from a Deepwater Nigeria field.