Exploration and development wells are increasingly drilled to deeper depths and lower porosities, in hotter formations. These conditions increase the challenges for Formation Tester's (FT's) to acquire accurate formation pressures in a timely and cost efficient manner. One of the most important constraints on current FT acquisition is the downhole formation temperature. The Pattani and North Malay basins in the Gulf of Thailand (GoT) are known to be one of the highest temperature locations where FT data is routinely acquired. Successful exploitation of the hydrocarbon resources in these basins is strongly driven by cost efficiency and the characterization of the many individual sands that are part of the complex fluvial stratigraphic framework. Reservoir pressure, fluid type, inflow performance and sand-to-sand correlation are some of the objectives for acquiring FT data and are used to manage the many wells drilled each year in these basins. Chevron (Thailand) E&P and PTTEP are the main operators in the GoT, drilling roughly 450 wells each year and over 80% of the wells have bottomhole temperatures in excess of 320 degF. Roughly 80% of the wells drilled require FT logging in the data acquisition program. The main challenge in this high temperature environment for formation testing acquisition is that pressure gauges need to be stabilized to eliminate a transient effect due to high temperature, in order to obtain an accurate pressure measurement. This can lead to longer logging times with the current tools available and lost efficiencies, particularly for wells with many individual hydrocarbon bearing sands (high pay counts).To improve efficiency and the actual formation pressure management, a proposal was made to develop a High Temperature FT tool in early 2009. This paper discusses the development challenges for FT's in this high temperature area, including gauge selection, gauge limitation, gauge temperature transient effects and logging procedures. After an intensive working period, a specially-made flask to cover certain parts of the tool for heat transfer and mitigation was introduced. Since then, this new FT service has been deployed in more than 20 wells in the Gulf of Thailand. This paper also presents the actual field data from the new tool in terms of data quality and accuracy compared to previous generations of FT, and the resultant efficiency gains from rig time savings. With this development, it is currently possible to obtain accurate formation pressure data, even in the extreme high temperatures found in the GoT, where satisfactory results were not possible in the past.

This paper focuses on the application of pre-stack seismic inversion to delineate gas reservoirs for development well targeting of the Muda Field in the Malay Basin. A comprehensive development well targeting workflow was established to integrate information from all related disciplines and convert them into an optimized well design. One of the key tasks in this workflow was to select an appropriate seismic attribute to identify the distribution of reservoir sands in this area. These reservoirs are generally characterized by thin sands inter-bedded with coals. Relative Poisson's Ratio (RPR) was used to identify reservoir targets prior to development drilling. Drilling results later indicated that a high proportion of the proposed anomalies (87%) correspond to gas sands. The remaining (13%) are related to highly saturated sands, Additional Zones of Interest (AZIs) or shale. Preliminary results therefore demonstrate that the RPR attribute can be used as an effective tool in development well targeting.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract As the Arthit development team was reviewing the Arthit field in-place volume and production data, a new way of looking at the hydrocarbon traps emerged that helped understanding the hydrocarbon distribution and well performance whilst at the same time offered a new way to optimally develop the field's resources. Integrating all geological, geophysical and petrophysical data with production information suggested that most of Arthit accumulations were located into combined structural-stratigraphic traps. Based on their structural configuration, those traps could be grouped into further categories that show distinct reservoir and fluid distributions in the various geological units. From then a trap style based resource assessment method was designed and fully integrated with the overall asset development workflow. When combined with reservoir geometry and direction statistics, a simple analysis of the trap configuration and orientation allows for a straight ranking of each prospect and also offers ways to de-risk development platforms and assists in optimizing the project economics by helping to define the optimal well spacing needed to maximize the gas resources. This concept has been recently successfully tested by Arthit development and infill wells in 2010. This new way of looking and quantifying at the traps resulted in a net increase in gas resource of approximately 30% by unlocking combined traps volumes and it is strongly believed that more such prospective resources can be discovered in other fields within the Gulf of Thailand since the reservoirs often share similarities, such as narrow compartments, short stacked hydrocarbon columns and discrete reservoir bodies with poor connectivity. This new workflow makes intensive use of the 3D integrated visualization, mapping and well planning software as it helped to significantly shorten turn-around time from prospect mapping, conceptual well planning to post-drill analysis. It has enabled a close cross-discipline co-operation and is being proactively pushed as a standard in PTTEP.

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