Abstract

Significant volumes of heavy oil remain in fractured carbonate reservoirs worldwide. Some of these reservoirs are good candidates for the application of thermally assisted gas-oil-gravity-drainage (TA-GOGD), a novel EOR technique. Unlike a normal steam flood, the steam is used as a heating agent only to enhance the existing drive mechanisms. The elegance of TA-GOGD is that the fracture network is both used for the distribution of steam (heat) and the recovery of the oil. The number of wells can therefore be kept to a minimum compared to conventional steam floods. Following encouraging pilot results in a field in Oman, a steam injection project is heading for implementation, a first of its kind on this scale. Studies to date indicate that recovery factors of 25–50% with Oil-Steam-Ratios of 0.2 -0.4 m3/ton of steam are feasible. The success of the project is critically dependent on the field-wide presence of conductive fractures and the ability to characterize them. Both stochastic and deterministic studies were tried, but the latter method is now favoured as it allows the use of geological and dynamic understanding as input to the modelling and honours existing faults, deformation mechanism and the conceptual model. Fracture characterisation is to some extent still an art and outputs are'only static scenarios'. Therefore results should be validated with dynamic data as much as possible. The dynamic models are thermal and dual permeability, with compositional dependencies: a complexity that is rarely encountered. Explicit fracture block models are used to verify that the heating rate and GOGD are captured properly, in particular for irregularly shaped fracture patterns. A new fully integrated workflow of fracture characterisation with static and dynamic modelling has enabled uncertainties and risks to be managed in a scenario based approach.

Introduction

Primary production performance such as that of Qarn Alam Qarn Alam Field is located in central Oman south of the Shuaiba is only expected to recover some 3–5% of the oil in western Hajar Mountains. This large oil accumulation is place over any reasonable time frame due to low matrix trapped in the Cretaceous Shuaiba, Kharaib and Lekhwair permeability and high oil viscosity on gravity drainage rates. limestone units at a depth of around 200–400m sub sea. The Recoveries via matrix floods of water, polymer or steam were anti-clinal structure is a result of a deep salt diaper, with discounted as development options due to the pervasive significant crestal faulting and fracturing.fracturing observed in the field which would encourage the flooding agents to completely bypass the matrix. The field was discovered in 1972 and placed on primary production in 1975. The produced oil was found to be 16 ° API with a viscosity of 220cP. During the primary production period from1975 to 1995, the first year showed a large peak in oil mainly from emptying of the fracture network with a minor contribution from fluid expansion due to pressure reduction.

At the end of the first year, production had declined to a very low sustainable rate interpreted to be from gravity drainage, from a combination of gas-oil (GOGD) from the secondary gas cap and oil-water (OWGD) below the fracture gas-oil contact (FGOC). The reservoir then consists of a matrix with very little drainage and a fracture network with a thin oil rim below the secondary gas cap and above the fracture oil-water contact (FOWC), figure1.

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