The last decade of nuclear magnetic resonance (NMR) logging has been dominated by T2 measurements and sparse sampling of polarization (differential spectrum) or diffusion (shifted spectrum) effects. Recent literature has expanded on the utility of NMR logging using T1 measurements to provide information on long time constants that are difficult or impossible to derive from T2 measurements using gradient tools. NMR logging modes have typically been designed to focus on a single specific NMR response, either very fast or very slow diffusion, or long T1 times, to identify either oil or gas. However, fluid properties can vary widely and often unpredictably downhole. A small number of NMR measurements that focus on just one NMR parameter may not provide sufficient information to identify and quantify fluid volumes, particularly when several different fluids are present. Achieving accurate fluid properties often requires data acquisition that simultaneously measures T1, T2, and diffusion contrasts. Inversion is most effective when all three NMR properties, T1, T2 and D, are obtained. We review the relative merits of T1, T2, and diffusion-based measurements in the light of petrophysics and instrumentation limitations. The relative merits of forward-model inversion and model-free analysis are discussed with reference to data sets recorded in a broad range of environments. Introduction A trend that has continued throughout the development of NMR fluid typing methods has been the increasing reliance on molecular diffusion (D) to identify and characterize different fluids.1–5 Recognizing the importance of diffusion, Hürlimann and coworkers6 developed diffusion editing (DE) acquisition and 2D NMR (2DNMR) methodology.7 The introduction of DE measurements represents an important advance in NMR logging because the method provides a substantial improvement in diffusion sensitivity relative to the conventional Carr-Purcell-Meiboom-Gill (CPMG) train.8 Also important has been the introduction of 2DNMR analysis. This analysis method invokes a model-independent inversion to generate 2D maps that display multimeasurement NMR data in an easily understandable format. Early examples of 2DNMR used DE data suites with different echo spacings to correlate diffusion rates and transverse relaxation times (T2).5,9 The resulting D- T2 maps provided clear separation of oil and water signals, allowing accurate determination of the fluid saturations and oil properties. Although DE acquisition and 2DNMR inversion processing were developed jointly, it was later demonstrated that the 2DNMR approach could also be extended to sequences comprised entirely of CPMG measurements10 if DE data were not available. As experience with 2DNMR methodology was gathered, it became clear that improvements in both acquisition efficiency and data analysis could be achieved by extending the technique to include longitudinal relaxation (T1). The resulting 3D approach (3DNMR) accounts for all relevant NMR properties, (i.e., T2, T1, and D) in a single comprehensive analysis of multimeasurement NMR data. The remainder of this paper provides a description of multimeasurement NMR analysis. The first section describes in more detail how the various maps (e.g., D-T2, D- T1) are generated and explains the relationships between them. It also discusses the effects of noise and regularization on the resolution and precision of 3DNMR inversion results. Sections two and three outline the application of 3DNMR to fluid typing in wells drilled with water-based mud (WBM) and oil-based mud (OBM) respectively. Field examples are used to illustrate points concerning the processing and interpretation. 3D NMR (3DNMR) Analysis There are several benefits offered by multidimensional NMR acquisition and analysis. First, the contour maps (e.g., D-T2, D-T1, T1- T2), provide a convenient and understandable means of visualizing complex NMR data, allowing identification of different fluids and calibrating their NMR response. From an operational perspective, the multimeasurement approach allows definition of a small set of acquisition sequences that are applicable in a wide range of environments. This approach simplifies NMR job planning, because there is no longer a need to define acquisition parameters for each job.

The petrophysical evaluation of carbonate reservoirs in terms of predicting the hydrocarbon potential is trivial. However, it is difficult to correctly predict the fluid flow in the absence of proper characterization of the different flow units encountered in these reservoirs. The process of identifying the flow units becomes non-trivial in the presence of extensive diagenesis process affecting the original depositional texture. The conventional triple combo logs gives an average response when logged against diagenetically altered zone thus overlooking or under-estimating diagenetic features occurring in micro scale. It becomes imperative to look at both micro and macro scale heterogeneity for evaluation of such reservoirs, which has a direct impact on the production, and water injection scheme of such reservoirs. The NMR data and image based secondary porosity estimation recorded in this well were used for partitioning the porosity into micro, meso and macro porosity. Borehole image logs have been interpreted in terms of defining the connectivity of the features seen on the image. This is then used to define a high-resolution connectivity index. An integrated approach using the NMR and the image is being proposed to identify such high permeability streaks that can explain the production performance or the water injection behavior at a later stage of development of the field. Based on the porosity partitioning technique an improved permeability estimate is made. The production results confirm the findings of this study. Introduction In order to link log data to the hydraulic properties of carbonate reservoirs, the oil industry is seeking better methods for characterizing the carbonates. This lead to the development of a method of carbonate rock classification keeping in mind the following key objectives and needs. Permeability prediction from logs is always difficult since no logging tool is available which can make direct continuous permeability measurements. Logging tools, instead, measure a surrogate for it such as a textural estimate from bore hole imaging logs or a pore size estimation from NMR logs. The interplay of multiple properties of the rock such as pore size distribution and texture influence the permeability to the extent to which pore throats are plugged with cement or other materials Numerous studies have shown that there is no direct relationship between the porosity and the permeability of the carbonate system. To understand the permeability of the reservoir a pore classification method may have to be resorted which can explain the production behaviour. The pore system classification would also help in designing a water injection program for such reservoirs. This study uses an integrated approach using the NMR and the micro-resistivity bore hole images for identifying and quantifying the secondary porosity and their impact on the permeability. This technique was validated from the dynamic behaviour of a well and shows promise in understanding the performance of the water sweep at the later stage of field development.

Thinly laminated formations can be significant hydrocarbon reservoirs, particularly in turbiditic and fluvial environments. However, often such formations exhibit low resistivities when measured with conventional resistivity tools. These are known in the literature as classical low-resistivity pay and often are anisotropic in resistivity. Over the past decade, studies have shown that electrical anisotropy greater than three in these layered formations is caused by thin water-bearing beds, such as shale layers, alternating with the oil sands. Initial laboratory studies have shown that alternating variations in water saturation is a major contributor to resistivity anisotropy, but detailed laboratory research is needed before this can be generalized to all shaly-sand reservoirs. Since their introduction in the early 1950s, wireline induction tools measured mainly the horizontal resistivity (Rh). Consequently, when confronted with a potential reservoir containing thinly laminated sand/shale sequences, it was a challenging task to decipher the thin hydrocarbon-bearing sands in the apparent low-resistivity hydrocarbon-bearing layer. The low-resistivity reading had to be corrected, usually by adding a shale-contribution term using one of the many published equations. More recently, technologies have been developed to measure the vertical dimension of this resistivity problem, or the vertical resistivity (Rv), which can be evaluated using three tools: logging-while-drilling resistivity tools when the apparent angle between the tool and the formation is high; joint inversion of array laterolog and array-induction; and the triaxial induction tool, the focus of this article. North Africa Case Study In a North Africa well, array-induction, nuclear magnetic-resonance (NMR), and nuclear (density-neutron and gamma ray) tools were run initially. The target interval was a deepwater turbiditic levee/overbank deposit, consisting of highly organized thin layers of high-quality gas-bearing sands. Layer thicknesses ranged from almost a meter to less than a centimeter, with most of the layers being in the centimeter range. The logged well encountered two gas-filled channel systems separated by a pressure barrier (Fig. 1). The lower system was a more proximal levee/overbank facies, of which the reservoir portion was made up of organized layers of high-quality coarse-grained sand interbedded with shales and some mudstones. Conversely, the upper system consisted of a levee/overbank facies having thin layers of finer-grained sands with shales and small amounts of mud. Regular array-induction logs did not show noticeable invasion profile in this formation. The porosity (including clay- bound water) was 35%, and the effective porosity (without clay-bound water) was 25%. The separation between density and neutron showed a high amount of shale except in three places (X150–X155 ft, X188–X192 ft, and X268–X271 ft), where the cross-over between density and neutron indicated gas, also confirmed there by the higher resistivity measured by the regular induction log (Fig. 2). From the deep array-induction log, water saturation (Sw) was computed with a dual-water equation to correct for clay conductivity. The data analysis, based on the array-induction tool and a dual-water shaly-sand approach, led to unreasonably high water saturations, with all resulting Sw values being close to unity, except in the three higher resistivity depths.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThrough-tubing carbon-oxygen (C/O) logging is a popular means for reservoir monitoring since a slim logging-insidecasing tool was introduced. The tools are available in 2.5 inch and 1.6875 inch outer diameters. Both the tools log inside of casing to quantitatively determine fluid saturation within the formation. In the absence of any other external information, the C/O technique has limitations when the survey is carried out inside the tubing. However, at times this becomes necessary when the reservoir to be evaluated is covered with both tubing and casing. There has been limited use of the slim logging-inside-casing tool for completions with both tubing and casing. This application has augmented the C/O methods of saturation estimation for measurements made inside the tubing. The present work documents the results of a pulse neutron logging operation carried out for estimation of the remaining oil saturation of a reservoir covered with tubing and casing. Both the inelastic capture and the sigma survey were recorded in this well. Careful planning was carried out for achieving an oil saturation precision of around 7 saturation units. The interpretation of the lithology from both the open and the cased hole logs is discussed. A new method was used for estimating the permeability from the cased hole spectroscopy logs. The saturation profile estimated from the C/O log is integrated with the estimated permeability results. The saturation results are in agreement with field observations and also demonstrate that bypassed reserves can be estimated on the basis of pulse neutron logging carried out inside tubing.

Open hole log evaluation has been traditionally used for formation evaluation purposes and is commonly used for reservoir characterization. Adverse hole conditions precluded use of these services. Under these circumstances, it becomes necessary to acquire the necessary log data after the well is cased for reservoir evaluation. Cased hole logs provide answers with acceptable uncertainty in characterized formations. However, in cased wells, which are not well characterized, the results tend to have a higher uncertainty. In one of the wells in Egypt the operator could not acquire the data in the open hole section because of adverse hole conditions. High quality cased hole data was acquired in the interesting section even in difficult borehole condition (heavy wash outs etc). The measurements are compared with the available open hole data and the responses explained. All the data which could have been acquired in the open hole was acquired in the cased hole with the available cased hole sensors.. Based on the data from the cased hole the bore hole condition at the time of casing the well was predicted. We also demonstrate that gaseous hydrocarbon can be identified from the cased hole epithermal neutron measurements which compared well with the resistivity and the density neutron separation. Reliable matrix density values have been estimated from the cased hole spectroscopy providing a reliable porosity values from the cased hole density. Reservoir parameters have been estimated in the cased hole section. It was possible to devise cost effective planning for completing the well based on these parameters. The ability to provide cased hole measurements helped the operator in avoiding a costly side track. Introduction Open hole formation evaluation from open hole logs has been the standard in formation evaluation for many years. During the last five years we have seen a trend in using some of the open hole services in cased hole for making a meaningful formation evaluation. These measurements have also been strengthened with the addition of tools exclusively for cased hole services. E & P companies always prefer to have the open hole logs for estimating the reservoir parameters. On numerous occasions, the risk of open hole logging is high. It makes economic sense to conduct logging operations after the well has been cased under those conditions. This paper describes the results of the analysis behind casing carried out for one of the operators in Egypt. The operator could not record open hole logs in the zone of interest because of bad bore hole conditions. The alternative was to side track the well so that necessary data can be acquired in the zone of interest. This was not a viable alternative since there was no guarantee that the well condition would improve while drilling the side track. After carrying out a detailed techno economic evaluation it was decided to case the well and run the fairly comphrensice suite of analysis behind casing services (ABC) for detailed formation evaluation. The basic services consist of the cased hole formation resistivty (CHFR(*), cased hole formation density (CHFD*), cased hole formation porosity (CHFP*). In addition to these basic services the client also reorded the DSI* and the ECS* for estimating the sonic slownesses and derivingt the lithology from the spectral measurements respectively. In this article we discuss the comparison of the basic open hole and the cased hole logs are discussed. The petrophysical results from the open and the cased hole are analyzed. A "synthetic density" log was also computed from the continuous grain density estimated from the spectroscopy measurements. There was a good correspondence of the match between the synthetic density and the cased hole density. The CHFP was also used for identification of gas bearing zone from zones and were confirmed by testing results.