Detection and Modeling of Natural Fractures: Real Life Detection Examples and Workflows for Implementing Fractures in Simulation Models

r of separate quantified data sets having a great variety of scales, ranging from core samples to seismic scale, are required to calibrate all the accessible information. The main challenge is the need to integrate all the available data sets, static and dynamic, in a consistent way, to allow construction of appropriate detailed geologic models and upscaled simulation models, with sufficient accuracy to allow history matching of all the available field dynamic data. The history matched simulation models are utilized to generate prediction scenarios of future oil and water production. Many hydrocarbon bearing reservoirs are faulted, and often little information is available about the actual physical characteristics of the faults. Some faults are known to be sealing and others are non-sealing to migration of hydrocarbons. While sealing faults block fluid and pressure communication with other regions of a reservoir, infinite-conductivity faults act as pressure support sources and allow fluid transfer across and along the fault planes. Finite-conductivity fault falls between these two limiting cases of sealing and totally non-sealing faults, and are believed to include the majority of faulted systems in many reservoirs of several prolific fields. Understanding of fluid flow in fractured reservoirs is important since a large percentage of the world’s oil reserves are situated in geological formations dominated by natural fractures. A quantitative description of fractures and their distribution is essential for the development and reservoir management of a reservoir. Preferential occurrence of the fractures is systematically dictated by key controlling geologic factors. The giant field described in this study is located at in the Eastern Province of the Kingdom of Saudi Arabia. The field production is primarily from two Jurassic-age fractured carbonate reservoirs, the Upper reservoir and the Lower reservoir, which are separated by a 500 ft (150m) thick, non-reservoir limestone formation (Fig. 1). The field has been in production since 1946. The Upper reservoir is prolific with excellent reservoir properties throughout the whole field. The Lower reservoir has low matrix permeability (1-2 mD) and is only hydrocarbon bearing in a high relief structural dome located toward the southern part of the field. The Lower reservoir well productivity is controlled predominantly by near wellbore fractures. Extensive stimulation treatments are required after drilling or workover operations to attain satisfactory well performance from Lower reservoir oil producers and water injectors. Vertical communication between the two reservoirs is evident from reservoir pressure data, and is believed to be caused by faults and extensive fracture corridors (fairways) that cut through the non-reservoir formation (Fig. 1).