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Deepwater turbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sands vary in thickness from millimeter to meters in thickness. The reservoirs are highly permeable, but the silt and clay laminations affect the reservoir permeability in each layer, resulting in changes in the well productivity and sweep properties. We illustrate the applications of NMR, borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology, the geometry, and the net producible fraction of these reservoirs: We demonstrate that the partitioning of NMR T2 distribution is a robust method for calculating independent volumes of clay, silt and sand. We present the experimental set-up and the application of a novel method to calculate the thin sand fraction of a laminated reservoir from NMR free fluid volume. The results of this method are compared to the sand counts from a high resolution borehole image and from core images. This comparison reveals the effect of the lamination geometry on the formation evaluation. We illustrate the effects of thin silt and clay laminations on wireline formation tests, and on the productivity and flow profile of a production test. The dynamic reservoir information obtained from these measurements enables to understand the fluid flow behaviour and potential productivity in such a reservoir. These techniques reduce the uncertainty of hydrocarbon volume and productivity computations in a highly laminated deepwater reservoir. The field example used in this paper is a turbidite sand from North West Borneo. The techniques demonstrated here are also applicable to the analysis of other categories of thinly bedded, shaly sand reservoirs. Introduction Recent advances in NMR technology and signal processing have focused on measuring reservoir fluids volumes and properties in-situ and on identifying reserves in thinly laminated reservoirs, thereby extending the range of NMR applications beyond the volumetric estimates of moveable fluids. Care must be taken to ensure that productive sand units are not discounted by formation evaluation in volumetric estimates of deepwater siliciclastic depositional settings with largely laminated succession of rock layers of varying thicknesses. This issue is becoming increasingly important in Miocene turbidite fans of the North Western Sabah province of Borneo, where many wells logs indicate sequences dominated by thinly laminated layers with low resistivity contrast between sand and shale layers. These beds are often too thin to be properly resolved with conventional logging tools. The acquisition of new technology logging services, such as tri-axial resistivity, high resolution oil-base borehole images and nuclear magnetic resonance (NMR) logs, as well as acquiring rotary and fullbore cores has increased over recent years. New logging techniques and interpretation methods have been applied to improve the evaluation of these thin-bedded reservoirs. This paper highlights efforts placed on the use of NMR logging to delineate reservoir properties to a finer resolution than convention tools. In addition, the use of images and wireline formation testing from the example well, provides the appropriate benchmark for improving estimation of net producible sand thickness in thinly bedded reservoirs. Passey et al. (Ref. 1) define petrophysical thin beds as contiguous units of rocks with thicknesses between 1 in. (2.5 cm) and 2ft (61 cm), that exhibit a narrow distribution of petrophysical properties, but are bounded above and below by other units with significantly different petrophysical properties. These 2 limits represent the currently accepted limits of logging technology: 2 ft is the vertical resolution of a conventional logging tool, and 1 in. is the minimum bed thickness resolved by a borehole imager. (The vertical resolution of modern logging technology actually reaches 1 ft [30.5 cm] for logs, and 0.4 in. [1 cm] for borehole images.)

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fax 01-972-952-9435. AbstractExploration and appraisal campaigns for deepwater environments are a continuous challenge in today's operations. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be put in place. New technology, real time monitoring and integrated reservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of vertical heterogeneity and varying layer flow properties.Wireline formation testers have been commonly used to acquire formation pressures pressure and reservoir fluid samples for a number of decades. Many hardware technologies and interpretation methods have been developed to acquire better quality reservoir information. Dual packer wireline formation testers offer an alternative an additional way to selectively straddle a section of a reservoir and provide the capability to conduct controlled local production and interference as well as to enable the capture of reservoir fluids. Formation permeability, anisotropy, skin factor, vertical connectivity and zonal productivity index are additional reservoir information that can be obtained from a mini-Drill Stem Test (mini-DST) and a Vertical Interference Test (VIT).Pressure transient analysis of a mini-DST data however in such reservoirs is challenging due to the associated uncertainties such as layer flow compartments and flowing fluid viscosity. This paper discusses the use of integrated reservoir information obtained from Downhole Fluid Analyzers (DFA), borehole images, and numerical simulation models to minimize these uncertainties. A systematic pressure transient analysis method for mini-DSTs is also introduced. * Currently with Santos Ltd.Reservoir parameters obtained from mini-DSTs in thinly laminated deepwater reservoirs are then compared with other available static and dynamic reservoir information such as petrophysical data, core analysis, well tests, production logs, and single probe wireline formation tests in order to obtain accurate interpretation results of highest consistency.Field examples will be discussed which show that smaller scale pressure transient tests often have an advantage over full scale well tests testing in terms of providing detailed layer flow behavior, vertical connectivity and flow potential in thinly bedded environments. It will also be noted that the radius of investigation of a mini-DST is limited, typically within tens of feet. This paper demonstrates using field examples that reservoir boundaries can be detected when sufficient radius of investigation is achieved. In addition, the understanding of limitations and advantages will allow the proper selection of test types in order to meet specific objectives and maximize the full potential use of acquired data for field development plans in thinly laminated deepwater environments.

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