fax 01-972-952-9435. AbstractCarbonate rocks are diverse, and their pore space complex. Petrophysical evaluation of carbonates with techniques developed for siliciclastic environments often fall short.In this paper, we present a new methodology that combines diverse texture and facies sensitive measurements. The method parametrizes the pore structure in terms of a multiporosity system of fractures, vugs, inter-and intragranular porosities, and evaluates the parameters from the measurements. The process is based on physics and relies minimally on empirical correlations.The first step is to separate the fracture from the matrix using borehole images and then quantify mineral volumes and porosity through nuclear magnetic resonance (NMR) and/or nuclear logs with new mineral standards. Next, we classify the lithology with a self-organizing-map (SOM) algorithm using a vector of log-inputs. Following this, the vug fraction is estimated using shear modulus data and borehole image analysis. Finally, we separate the inter-and intragranular components using NMR data. This analysis includes molecular diffusion between different pore types. The NMR processing scheme also depends on lithology. The porosity components and the relevant length scales enable us to predict resistivity and permeability using an effective medium theory in an internally consistent manner.Our interpretation methodology was validated successfully with core/log data from the Middle East. The facies ranged from mudstone to grainstone. * Trademark of Schlumberger

A new model is proposed for interpreting two-dimensional diffusion-relaxation nuclear magnetic resonance (2D NMR) maps by including the effects of restriction on the diffusion of water in a connected porous medium. The model's theoretical underpinnings are reviewed and a correlation derived between the diffusion and relaxation of restricted water molecules, i.e., the expected 'water line' where the water signal should appear on 2D NMR maps. The main application discussed in this paper is to improve the quantitative separation of different fluids in the formation, leading to better prediction of water and hydrocarbon saturations. In many carbonate formations, the effects of restriction may be quite pronounced making the standard fluid characterization with diffusion-relaxation maps questionable. The restricted-diffusion model is applied to laboratory measurements on carbonate core plugs and to an example log from a Middle East carbonate well where the saturations obtained with the new model are compared against other measures of saturation available in the dataset.

The MicroPilot* is a log-inject-log technique providing a single-well in-situ measurement of enhanced oil recovery flood geometry and changed residual oil saturation. The fluid to be injected is transported downhole in a sample chamber and injected into the formation through a pencil sized hole. Borehole electric images and high resolution saturation logs are recorded before and after fluid injection. The logs show the change of residual oil saturation. The dimensions of the swept zone and surrounding oil bank are visible on the borehole image. These dimensions and saturations can be used to history match the reservoir simulation of the EOR process.

This paper presents a logical approach to ensure successful nuclear magnetic resonance (NMR) logging for fluid-characterization purposes. Numerous examples are shown in a three-stage process consisting ofplanning,processing and interpretation, andvalidation and integration. First, modeling is performed to assess the NMR contrast, using any available information concerning anticipated fluid types. Knowledge of downhole conditions also allows the estimation of the NMR signal-to-noise ratio (SNR) from which the sensitivity and statistical error can be evaluated. The outcome of the planning process is a suite of NMR pulse sequences that optimizes resolution of the different fluids and minimizes error with the shortest possible acquisition time. Interpreting fluid-characterization NMR logs is relatively straightforward when the fluids have large NMR contrast and obey the standard correlations. However, dissolved gas, wettability variations, internal field gradients, and restricted diffusion can cause deviations from model behavior and have significant effects on NMR relaxation data. These effects need to be recognized and accounted for. To gain insights into the NMR-based fluid evaluation process, we have developed a model-independent technique that gives various sets of D-T1-T2 maps. The maps are analogous to the crossplots commonly used in log interpretation practices and are indispensable in the interpretation of the data. We also explain quantitative interpretation techniques from D-T2 maps. Integrating NMR fluid-characterization results with other information and openhole logs constitutes the final step. As with any technique, results need to be crosschecked with other log data for consistency. The answer gives a water saturation that can be verified with other tools and techniques such as the dielectric log, resistivity logs, and the density magnetic resonance technique method. Introduction Current methods to analyze fluids using suites of NMR measurements employ model-based inversions. Two examples of the forward-modeling approach are the MACNMR1 and Magnetic Resonance Fluid (MRF) characterization methods.2 The MRF technique is based on physical laws that are calibrated empirically to account for the downhole fluid NMR responses. By using realistic fluid models, MRF aims to minimize the number of adjustable parameters to be compatible with the information content of typical NMR log data. Since the model parameters are by design related to the individual fluid volumes and properties, determination of the parameter values (i.e., data-fitting) leads directly to estimates of the fluids petrophysical quantities. Any forward-model approach relies on the validity of the fluid models employed. In "non-ideal" situations where the fluid NMR response deviates from the model behavior (such as internal gradient, oil-wet rocks, restricted diffusion etc.), these techniques may lead to erroneous answers. In some circumstances, "non-ideal" responses may be identified by a poor fit-quality of the echo data, in which case the fluid models can be adjusted by modifying the appropriate model parameters. However, it may not be obvious which element of the fluid model should be modified and what modification is needed to get the desired answer. The maximum entropy principle (MEP) method is a model-independent inversion that provides a simple graphical representation of NMR data for fluid analysis in all environments. The graphical representations (i.e., multi-dimensional distributions) can themselves be used directly for interpretation or, alternatively, they may be used to guide the selection of parameters for model-based processing such as MRF. It is important to recognize that the MEP technique as well as the methods to interpret D-T2 maps are applicable to both CPMG (Carr, Purcell, Meiboom, and Gill) and DE (diffusion editing)3 measurements.

TX 75083-3836, U.S.A., fax 01-972-952-9435. Near wellbore effects Effect on shallow nuclear logging Deviated wells Acid effect Effect on Σ Lithology