Calculating Volume Fraction of Clay, Silt and Sand from Nmr Logs
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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.)
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.)
The analysis of shaly sand gas reservoirs with low and variable formation water salinity presents specific challenges. These formations usually exhibit low resistivity contrast between water and hydrocarbon zones, and high apparent clay content. Calculated water saturations are high, and need to be accurately split between clay-bound, capillary-bound and free water. In addition to these reservoir characterization problems, we observe effects caused by the drilling process, such as gas dissolution in OBM filtrate, and time-lapse effects between LWD and Wireline logs. NMR measurements of porosity, bound fluid volume, pore size distribution, and direct fluid identification can be applied to resolve the challenges mentioned above. We demonstrate the use of NMR data to calculate total and effective porosity, and volume of irreducible water in productive reservoir sands and in shales, to validate the petrophysical model. We also present a method based on NMR analysis to estimate net producible pay and its uncertainty. We apply fluid typing from NMR Relaxation and Diffusion maps to quantify small volumes of gas present in the water zone. This analysis enables us to calculate the fluids composition in the invaded zone and to improve the accuracy of density porosity, even when LWD and Wireline logs are combined. We also show how the NMR measurement of gas volume in the invaded zone can be correlated to sonic measurements for quantitative fluid substitution. We identify gas in thin and shaly reservoirs from NMR standalone fluid typing, and present examples of successful sampling with wireline tester in these elusive reservoirs. The various examples presented in this paper describe practical petrophysical methods used to improve the formation evaluation of shaly gas reservoirs in fresh formation water, and demonstrate how the NMR data can be integrated into an existing petrophysical analysis, improving the accuracy of results in this challenging environment.
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