Advanced Formation Testing and PVT Sampling in Deep Gas Condensate Reservoir: Case Study from Malaysia

Abstract

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractDownhole sampling in gas condensate reservoir is well known to be challenging due to the nature of near critical fluids. Reservoir fluid properties can change dramatically with slight changes in reservoir pressure and temperature. As a result, accurate and representative PVT data are essential for reservoir fluid modeling and field development planning but difficult to obtain using conventional sampling techniques. This paper presents the first successful downhole gas condensate sampling in a high pressure gas condensate field, offshore East Malaysia. Samples collected from the previous surface tests showed large variation in Condensate Gas Ratio (CGR) from 50 to 200 stb/mmscf. This resulted in large uncertainty in the dew point pressure, condensate yield, well productivity, and reservoir fluid type. There was strong need to acquire high quality downhole samples to reduce these uncertainties, which can potentially affect the entire field development plan. Through the use of new technology and an integrated team approach, it was possible to take representative single phase fluid sample using controlled drawdown and real time fluid analysis of downhole sample.There were several key challenges in this operation. The team had to take single phase gas sample, with minimum contamination in a High pressure High temperature (HPHT) well drilled with Oil Based Mud (OBM), station time had to be as short as possible to avoid tool getting stuck, and have an initial estimate of dew point pressure and Gas Oil ratio (GOR) from downhole measurements. This was achieved using real time data monitoring and control of the entire wellsite operation from PETRONAS Carigali office. The latest downhole fluid identification tool was used along with focused sampling to minimize OBM contamination. This paper will highlight the effective use of various elements of new technology and team work.Fluid density measurement was found useful in answering some of the questions. It allowed comparison with optical fluid analyzer to provide an improved fluid identification. It also allowed to optimize the number of pretests and hence reduce the rig time and cost. By measuring the change in fluid density during clean up, the in-situ density tool also complemented other spectrometer based optical analyzers in determining the contamination level during sampling process.In this complex gas reservoir, there were potential reservoir compartments of different gas composition. Fluid samples from different zones confirmed the presence of such compartmentalization. The deeper zones showed much leaner gas composition compared to the shallower intervals. The knowledge of in-situ dew point pressure from downhole fluid analyzer was used to ensure a single phase gas sample during wireline sampling. This information was later used to design a well test to keep flowing bottom hole pressure above dew point pressure and thus obtain representative surface fluid samples. This paper demonstrates how a proper job planning, r...