This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170584, “Dynamic Fault-Seal-Breakdown Investigation - A Study of Egret Field in the North Sea,” by P.P. Obeahon, SPE, G. Ypma, and O.U. Onyeagoro, SPE, Shell, and A.C. Gringarten, SPE, Imperial College London, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.
The ability to predict the effect of faults on locating remaining hydrocarbon is critical to optimal well-placement, reservoir-management, and field development decisions. The tools and techniques available for realistic differentiation between sealing and nonsealing faults have presented a great challenge to the industry. This paper discusses the results of an integrated study that incorporated detailed geology and reservoir engineering to understand production behavior of a complexly faulted high-pressure/high-temperature field in the North Sea.
Predicting fault-seal breakdown is a challenging task because it involves many interrelated factors and complex relationships. Knowledge of these factors is both nonunique and subjective. Most faulting processes have been studied in isolation, and the relationships among many of the processes are understood poorly.
Reservoir depletion can, in principle, induce stress paths capable of reactivating intrareservoir faults and, hence, potentially cause breakdown of their sealing integrity. Fault-seal breakdown may also be invoked falsely where oil/ water contacts change across a fault (i.e., the fault is a capillary seal) but the fault does not compartmentalize pressures in production. This apparent seal failure can arise because of pressure communication in the water leg below the oil column. It is not clear why pressure depletion should cause capillary-seal failure. However, publications exist that attempt to attribute production behavior observed in fields to fault-seal breakdown in a production realm, because of pressure depletion on one side of a fault.
The first attempts to incorporate geologically reasonable fault properties into production-simulation models involved the calculation of transmissibility multiplier on the basis of absolute permeability and thickness of fault rocks. These calculations do not capture the multiphase behaviors of fault rocks. A key problem with this approach is that a huge number of pseudofunctions needs to be calculated to take into account the large variation in fault properties (e.g., thickness, absolute permeability) and flow rates and whether the fault is going through drainage or imbibition during production. The second attempt involved calculating transmissibility multipliers (also known as seal factors) on the basis of fault permeability. The key problem with this approach is that fault permeability depends on shale gouge ratio and fault displacement alone. The calculation does not capture the impact of reservoir permeability on fault permeability.