Waterflooding is a proven secondary recovery mechanism for hydrocarbon production while maintaining reservoir pressures. To achieve the desired voidage replacement ratio, each injector well is designed to inject at a certain rate to support its paired producer. From a safety perspective, it is essential to avoid 1) injection above shale fracture pressure that could result in top seal failure and 2) injection above fault propagation pressure that could result in fault reactivation/propagation. The potential consequences of these hazards are out of zone injection or loss of containment. Following recent major oil spill incidents around the world (e.g. Macondo disaster in the Gulf of Mexico), regulations have become more stringent on well designs pertaining to wellbore stability and reservoir geomechanics. This paper will showcase an integrated effort at assessing the injection pressure margin and the impact on the detailed injector well designs for a deepwater turbidite field development in the Gulf of Guinea (Nigeria). The technique applied requires a good understanding of the fracture pressures, rock strength, failure mechanism and good drilling and completion practices. To test different scenarios, one well injecting to a deep reservoir and another well injecting to a shallow reservoir were selected for this assessment. Pore pressure, fracture pressure, and injection pressure along the wellbore were analyzed to ascertain the margin between the downhole injection pressure and fracture pressures above and at the proposed casing shoe setting depths.  The results of this study provided basis for injector well designs, justification for full field geomechanics modeling, and recommendations for data acquisition while drilling and well reservoir monitoring throughout the injection/production period.

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.

The use of quantitative techniques in the evaluation of pore and fracture pressures across entire well path plays an important role in successful well delivery. The ability to correctly predict geo-pressures before drilling and manage them during drilling is a critical success factor to safe drilling of wells and cost reduction especially in deepwater environments. Compressional velocities have been used to provide indirect estimate of pressures prior to drilling; the method is well established Rodney Littleton et al, (74487). Vertical effective stress-Compressional velocity models in offset wells when fitted with empirical models can be applied to calibrated seismic velocities in prospect well locations to predict pore pressures. The accuracy of this method however depends on factors not limited to geology, compaction trend, seismic anisotropy, consistent velocity picking/gridding, input to gathers, over pressure prediction, etc. To raise the confidence level in the seismic based prediction, a simple yet pragmatic methodology has being used to demonstrate how combining velocity based pressures with pressure cell modeling can yield formation pressures across entire well paths with much higher degree of certainty. This work therefore discusses a study done on a deep water Nigeria field; where Seismic velocities have been used to predict pore pressures. The outcome was combined with pressure cell based methodology (standard method for pore pressure prediction in sands) to reduce the inherent uncertainties in sand pore pressure predictions. The results shared in this paper have already been used in effective design of several deep water wells in offshore Nigeria.