An Efficient Way to Characterize Complex Reservoirs Through Downhole Fluid Properties Measurement

Abstract

Reservoir connectivity and compartmentalization are main challenges during the field development plan. High resolution logs and seismic interpretation are usually used to characterize reservoir complexity. However, similar to other interpretation methods, they have some degree of uncertainties. Reservoir pressure and fluid communications are therefore crucial to prove reservoir connectivity, especially in complex reservoirs. In offshore Peninsular Malaysia, oil field X has a big structure covering an extensive area with East- West elongated anticline and North-South trending faults. The reservoirs are tidally influenced mouth bars deposited within estuarine or bay fill environment. The reservoir fluid is known to have large variation of CO2, waxy, viscous, and low Gas-Oil-Ratio (GOR) based on the early appraisal well production tests. Currently, the field is undergoing a series of appraisal wells drilling program for delineation and reservoir data acquisition. Apart from the data quality, cost and timing are the key consideration for getting early reservoir fluid properties as the field is geared for the early first oil. The challenge is to obtain critical reservoir fluid properties such as CO2, GOR, fluid density, fluid compositions i.e. C1 to C6+, quickly and efficiently. This information is required for reservoir modeling and it can also be used to confirm reservoir connectivity in terms of fluid communication between fault blocks as previously interpreted in the structure map. The conventional approach of collecting downhole or surface samples during Wireline Formation Tester (WFT) or production test and then have these samples sent for lab PVT analyses is expensive and time consuming. It involves contract preparation and bidding, lab queue system and also subject to samples quality and handling risks. Alternative ways to obtain in situ reservoir fluid properties quickly, accurately and representative of the reservoir have been explored, used and tested in this paper. This work illustrates the use of Downhole Fluid Analyzer (DFA) data to better characterize reservoir fluid complexity in such a way that it can completely change the current perspective of reservoir fluids. The new generation of WFT together with DFA data allows us to accurately quantify the CO2 content which is essential for facilities and pipeline designs and material selections. In addition, this technology provides high quality real time fluid properties with significantly less contamination. This is an excellent alternative way to obtain high quality reservoir fluid properties without production test and laboratory analysis. The small variance between the DFA and the lab measured data has increased our confidence to extend the application of this tool in the appraisal wells program where no production test or fluid sampling is planned. This has led to the early understanding of the reservoir fluids system in terms of GOR, light ends and heavy ends components, density/API, viscosity, CO2 variations vertically and areally without having to conduct unnecessary production test or downhole fluids sampling. It is a cost saving in a way.