TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe determination of pore geometry and pore aperture size from mercury injection tests is a very helpful technique. Due to the amount of pressure data points that can be taken, a detailed characterization of the capillarity of the rocks can be accomplished. The size and geometry of the pores are related to variability in grain size, sorting and packing, as well as to factors such as the mineralogy and the diagenetic history of the formation. This paper presents the results of the integration of capillary pressure curves, conventional core analysis and petrographical Investigation, in a highly heterogeneous pore geometry, where a bimodal behavior of mercury-injection capillary pressure curves was identified, showing two main types of pore throat, one with a larger flow capacity than the other. This analysis was backed up by thin sections made in adjacent samples, where strong changes in sorting, grain size and increment in the percentage of clay matrix can be seen. The changes in pore geometry observed within such small distances, demonstrate the high heterogeneity of the reservoir rock.An attempt was made to classify the different rock types present in the reservoir, using the Winland (R35) relationship to calculate pore throat radius based on permeability and porosity. Despite the complexity of the pore system, it was found that R35 can appropriately represent the largest portion of the rock volume with the main pore throat radius that contributes to the flow.The fact that the mercury capillary pressure curves grouped by rock type always show the bimodal shape, was taken into account in order to understand the wells production in the reservoir, because the performance of the wells will depend on the volume of each main pore throat radius in the completed zones.

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Over the past decade, explosive development in downhole tools and measurement techniques has facilitated subsurface acquisition of rock and fluid data during drilling and testing. In addition to rock and rock-fluid data such as porosity, permeability, and fluid saturations, downhole tools enable measurement of fluid properties such as the gas/oil ratios (GOR), saturation pressure, fluid density and viscosity, compositions, and asphaltene gradient. Downhole fluid analysis (DFA) is accomplished through a combination of spectroscopic and fluorescence techniques coupled with density and viscosity measurements. Early acquisition of downhole rock and fluid data is extremely critical to appraising, planning, and executing fast-track projects to maximize the asset's potential. The potential benefits of early data acquisition demonstrate DFA technology as a quick solution for decision-making parameters in scoping productivity analysis. DFA results are later validated and adjusted by laboratory measurements for in-depth reservoir performance predictions. Furthermore, early DFA measurements aid in the acquisition of cleaner reservoir fluid samples, well testing and completion design, and establishing fluid gradients and reservoir connectivity. Proper planning, interpretation expertise, and knowledge of modeling techniques are necessary to exploit the information from DFA. Using field examples of DFA measurements and laboratory results, we found that GOR and fluid composition by DFA measurements are fairly accurate with low uncertainties for black oils in comparison with laboratory data. However, in the case of volatile oils and gas condensates, the uncertainty seems to increase as the GOR increases, which is confirmed by a close comparison of DFA data with laboratory analysis of companion fluid samples. We investigated likely sources for these discrepancies, particularly with reference to the spectroscopic data interpretation and the models used to translate the spectroscopic response into fluid compositions and GOR. Different approaches can be used to improve composition and GOR estimates from the DFA results, including enhanced modeling techniques of the spectroscopic data. Introduction The type of reservoir fluid and its pressure/volume/temperature (PVT) behavior plays a critical role in estimating in-place hydrocarbon volumes, planning for reservoir development strategies and production processes, facilities design, and the mitigation of flow-assurance problems. In addition, reservoir and facilities simulation studies to predict reservoir performance and facilities optimization require fluid models based on measured data to capture fluid property variations with changes in operating conditions. Thus, fluid properties data are vital for planning reservoir development very early in the exploration and predevelopment stages. However, acquisition of representative fluid samples and subsequent laboratory analysis usually take a long time, as much as 3 to 6 months, resulting in undesirable project delays. In this environment, downhole fluid analysis (DFA) (Mullins et al. 2005; Betancourt et al. 2007; Fujisawa et al. 2008) tools offer the significant advantage of obtaining fairly accurate in-situ fluid bulk properties such as fluid density, viscosity, and gas/oil ratio (GOR).

The Cakerawala, Bulan, Bumi and Suriya gas fields in the MTJDA, northern Malay Basin form a major new development hub for the region, with an estimated total GIIP of 9 Tcf. These large assets are very early in their field life with only 300 Bcf of production from Cakerawala field so far. There has however already been significant (USD 1-2 billion) development investment. There is significant subsurface uncertainty due to geological complexities and a detailed, integrated data gathering and interpretation effort was necessary to better understand the asset. The impact of the study is a deeper understanding of the fields' potential and an insight into how to optimally develop these complex resources. This study covers many aspects of the reservoir characterisation process with examples from the North Malay Basin and has application in other complex fields.The subsurface geology comprises a thick interval (more than 7,000 ft) of stacked, clastic, fine grained, often clay-rich reservoirs, deposited in an upper delta plain to shallow marine environment. Significant challenges exist in developing these fields due to the large development area, thick zones of interest, large number of reservoirs and challenging depositional setting. There are also petrophysical issues to overcome, including fine scale reservoir heterogeneity, complex mineralogy and the presence of low-resistivity low-contrast (LRLC) pay.An improved understanding of the factors controlling reservoir quality was achieved by adopting a holistic and multidisciplinary approach. This included the integration of stratigraphic, depositional and lithofacies information along with mineralogical and pore system data.Key lessons learnt include the importance of acquiring good subsurface rock data and the construction of robust databases. The novel application of Lorenz plots and Winland R35 analysis calibrated to test data provided key rock quality and heterogeneity information for inclusion in geo-engineering models. The definition of LRLC reservoirs proved to be an important milestone which led to the development of a water saturation cut-off for gas-productive reservoirs. These findings are now being incorporated into our forward development strategies in Block A-18 and other assets. Success was achieved on a highly complex problem due to the application of an integrated, multi-disciplinary work flow.

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