One of the key exploration risks along the margin is to understand the pressure regime. This understanding is both vital for well design but also for de-risking of traps for hydraulic breach for instance.
Clearly pressure prediction has proved problematical during the various phases of drilling in West Africa, as evidenced by the number of kicks taken, for instance, in the Niger Delta and Cameroon. This observation suggests that the pore pressure regime is not understood fully even in areas where existing well penetrations are present.
Figure 1 Example of a coupled geology-pressure model, West Africa. LHS where salt is relatively shallow, pore pressure builds below the salt. All reservoirs are un-drained and at shale background pressure. RHS, where the salt is deeper, suggesting higher sedimentation rates post-salt, abnormal pressure commences above the salt forming a pressure ramp. The depth of this ramp is controlled and can be predicted from basic understanding of loading rates. OP= overpressure (pore pressure minus the hydrostatic pressure at the same depth).
What are the reasons for these kicks?
- Part of the complexity of pressure prediction (and geomechanics) along the margin is due to the highly variable lithology. In Morocco, for instance, Jurassic carbonates are proving exploration targets. These are frequently associated with taking drilling losses. Eocene carbonates are also present. Carbonates of Albian/Aptian age can be very well developed in Kwanza Basin, Angola for instance. In carbonates (and indeed all non-shale lithologies) generally as a rule, there is no consistent porosity/stress relationship thus using seismic velocity data, often our only “hard” data available” to remotely estimate pore pressure is invalid.
- In Gabon, throughout the offshore, drilling is below the Ezanga salt. In some areas the pre-salt Gamba reservoirs are normally pressured, in others, highly overpressured – this is due to the presence of rubble zones and/or reservoir connectivity/isolation.
- In Mauritania, Cretaceous reservoirs in clastics have very variable pressure; the shale pressures are frequently much higher than their associated reservoir pressures.
- In the Niger Delta, the challenge is that due to the very deep drilling, the shales are very hot and secondary overpressure mechanisms are more likely, creating HP/HT conditions.
Thus, in order to produce models for pore pressure and so be able to de-risk our prospects for seal failure, the above all need to be acknowledged/understood and quantified.
One of the solutions presented in this paper is based on building a coupled geological-pressure model. This or these, simple models are the result of combining typical “geological” information such as basin stress, lithology, and temperature gradient and sedimentation rates, with knowledge of pressure generation mechanisms (Figure 1). Once done, accurate pore pressure can then be input into seal capacity relationships to establish likely risk of failure and migration of hydrocarbons out of a trap.
(i) Seal capacity; Accurate pore pressure can be related to a fracture pressure of the seal and seal capacity risked. Using this approach, potential column heights can also be calculated for a trap and areas of likely fractured/leaking seals can be determined. This drives acreage choice.
(ii) Hydrodynamic aquifers; If reservoirs are connected to the onshore, pressure can dissipate laterally and in this scenario, reservoir pressure is less than background shale pressure. By mapping reservoir overpressure in the aquifer, we can establish reservoir connectivity. This becomes much harder to ascertain if we are in a wildcat situation. In this situation, we can use pre-drill seismic velocities to see if they increase in the vicinity of a reservoir that we suspect may be draining – velocity increases as pressure drops approaching these reservoirs. One of the benefits of these “naturally” drained reservoirs is that they have enhanced seal capacity i.e. they can hold longer columns as the reservoir pressure is so much less than the seal. A field in the Niger Delta has an oil column of over 3000 feet as the reservoir is “laterally draining” as the seal/reservoir pressure difference is now large.
In order to predict pore pressure successful along the West Africa margin, and thus use these data to improve prospectivty, a “holistic” approach should be taken. Not all rocks are the same, and therefore, prior knowledge of which approaches to use dependant on lithology, geothermal gradient and stress can mitigate risk substantially. Over-reliance on seismic velocity data is a common issue – this can be useful in shales only so the construction of simple geological models is needed to predict the pressure in other lithologies. Once done, de-risking of traps can follow and prospectivty assessed.