From Static Model to Asset Action Plan: a Field Case Successful Journey With Innovative Modeling Approach

Ben Amor, Faical (Schlumberger Overseas S. A.) | Amari, Mustafa (Schlumberger Overseas S. A.) | Sharifzadeh Najafi, Ahmad (Schlumberger S. A.) | Dashti, Qasem M (Kuwait Oil Company) | Al-Saffar, Ali Mahmoud (Kuwait Oil Company)

OnePetro 

Abstract

A hybrid natural fractured reservoir static geomodel using a wide range of 2D/3D seismic, geometrical and petrophysical attributes has enabled a reasonable 3D representation of three sets of fractures in the SA field, part of North Kuwait Jurassic Complex (NKJC). Based on well and seismic data, the three sets are fracture corridors associated with geophysically interpreted faults; medium scale layer-bound geomechanically controlled fractures; and folding- related fractures. The new hybrid fracture model, which is made of a discrete fracture network (DFN) and an implict fracture model (IFM), was calibrated using production logging tool (PLT), modular formation dynamics tester (MDT), and pressure buildup (PBU) data from 27 wells.

The calibrated hybrid fracture model has shortened the process of the history match significantly, requiring only very small adjustments/alterations to the initial static model. Achieving a smooth and timely history match resulted in significant CPU time gain and an optimized well count that went into the Asset Action Plan.

Introduction

Characterisation of naturally fractured reservoirs is a challenge, with substantial modelling uncertainties increasing away from well locations. Significant heterogeneities in the data often mean that traditional modelling approaches can be limited as they are largely based on statistical fracture populations rather than directly on the well data.

SA field is located in a challenging exploration and development environment of dual-porosity heterogeneous carbonate reservoirs, dominated by low porosity and permeability in deep HP/HT conditions. The target in SA field is a gas condensate carbonate reservoir, in which natural fractures proved to contribute significantly to reservoir productivity. The field is composed of a highly fractured crestal area under pseudosteady-state conditions and a platform area characterized by a transient pressure flow period. The main drive mechanisms across SA field are fluid expansion and pore volume compressibility. SA field covers a total area of 155 km2, with the highly fractured crestal part only covering 24 km2, which is the source of most of the production.

The SA structure was formed as graben during the Jurssic rifting phase, which developed during the Tertiary transpressional Alpine phase into a tight inverted ridge with southern horsetail. The conceptual structural model of the field (Richard et al., 2014) consists of three main sets of fractures related to three successive main phases of deformation as seen in the well SA-2 core (Fig.1). PTA data were used to check the validity of the conceptual fracture model and to construct the numerical model, and the hydraulic communication between the crestal and platform blocks has been confirmed by interference and buildup tests.These fracture sets are expected to be associated with various fracture intensities, as follows:

  • An overall N-S fracture set developed during the Jurassic phase of extension. These fractures have a tendency to be concentrated in fault damage zones, and their intensity is expected to increase with increasing fault dimensions and in specific structural locations like fault relays.
  • An overall NW-SE fracture set developed during the Cretaceous phase of transtension (Alpine 1). These fractures have a tendency to be located within the earlier Jurassic graben and reactivated in transtension and in the extensional horsetails of SA field.