Fast track development projects, with timely data acquisition plans for development optimization, are very challenging for tight and heterogeneous carbonate reservoirs. This paper presents the challenges and key learning from initial stages of reservoir development with limited available data. Focus of this study is several stacked carbonate reservoirs in a giant field located in onshore Abu Dhabi. These undeveloped lower cretaceous reservoirs consist of porous sediments inter-bedded with dense layers deposited in a near shore lagoonal environment. The average permeability of these reservoirs is in the range of 0.5-5 md. Mapping the static properties of these reservoirs is difficult since they are not resolved on seismic due to the low acoustic impedance contrast with adjacent dense layers. Petrophysical evaluation of thin porous bodies inter-bedded with dense layers in highly deviated wells pose significant challenges. Laterolog type LWD resistivity measurements which are less affected by environmental effects, offer more accurate formation resistivity compared to propagation type measurements. With limited suite of logs, some of the zones with complex lithology had to be evaluated innovatively as detailed in the paper. Integrated studies are initiated to improve reservoir description by carrying out accurate permeability mapping, SCAL, geomechanical and diagenesis & rock typing studies. Significant challenges exist regarding the development of thin, tight and highly heterogeneous reservoirs, in terms of recovery mechanism, well architecture, well count, drilling, well completion and economics. Static and dynamic models were used extensively to evaluate different development scenarios and conduct sensitivity studies to bracket uncertainties. Various geo-steering options were discussed and the paper also details maximizing the reservoir productivity using long reach MRC (Maximum Reservoir Contact) wells. Tight and heterogeneous reservoirs call for extensive and real time reservoir surveillance activities to assess well performance and reservoir connectivity. This paper highlights how these challenges are overcome through upfront surveillance planning and proactive well completion strategy.
Carbonate reservoirs often contain a complex mixture of pore sizes. In Bul Hanine field, Arab-DIII reservoir is almost entirely microporous throughout the field. Microporosity affects log responses and fluid flow properties. Proper identification and quantification of different porosity classes and their influence on the petrophysical parameters is crucial to accurately calculate hydrocarbon saturation. This paper presents the results of a multi-disciplinary workflow employed to identify and quantify the different porosity classes in the Arab-D reservoir.The workflow consists of core-and log-based analysis. The core-based analysis includes laser scanning confocal microscopy of thin sections from different reservoir facies, analysis of mercury injection data, and 3D pore network modeling. Confocal microscopy (0.25 micron resolution) quantified microporosity that cannot be seen or assessed through conventional petrography, while 3D pore network modeling helped evaluate the effect of the microporosity on the electrical parameters of the different reservoir facies. The log-based analysis includes analysis of Nuclear Magnetic Resonance logs (NMR) through spectral decomposition, interpretation of borehole images to evaluate the effects of diagenesis on the different reservoir facies, and other standard logs.Confocal microscopy demonstrated that pores smaller than 10 microns in diameter (micropores) in wackestone to packstone facies commonly comprise almost 100% of the total porosity. Burrowed, heterogeneous packstones and wackestones have 38 to 95% microporosity. Accurate quantification of microporosity from core using confocal microscopy permitted the computation of a continuous microporosity log using primarily NMR spectral decomposition and alternatively borehole images when NMR data is not available. After image to core calibration, rock fabric analysis using borehole images identified different bioturbation intensities with variable burrow sizes and varying burrow infill textures. Permeability enhancement can develop when burrowing architectures are well developed and filled with more permeable sediment, but diagenesis can also alter the porosity and permeability. The evaluation of electrical properties yielded insights into more effective rock property parameters, indicating that water saturation in these microporous networks may be lower than previously calculated. Pore network modeling showed that the microporosity fraction influences Archie's saturation exponent (ЉnЉ). By including a variable ЉnЉ value, weighted by the fraction of microporosity, water saturation computations can be reduced by 20%, therefore increasing volumetric and original oil in place.This workflow provides an innovative technique to characterize different porosity classes in heterogeneous carbonate reservoirs and quantify its impact on reservoir properties. It also provides a novel technique to calculate water saturation after correcting the effects of the microporosity presence in the different reservoir facies. This technique can be used...
Development of complex carbonate reservoirs requires a thorough evaluation of rock properties, especially when the reservoir has been highly influenced by diagenetic processes. Understanding the distribution of reservoir quality is a prerequisite to successful prediction of reservoir performance. This study focuses on the integration of diagenetic studies with reservoir rock-log typing. The objective was to understand the present day pore space system by evaluating the diagenetic overprint and its control on the studied reservoirs porosity, permeability and capillarity.In the cored intervals of the studied reservoirs the lithofacies indicate a high energy shallow, water platform environment prevailing during Early Cretaceous time. Both reservoir thicknesses vary between 20 and 30 feet in thickness. Average porosity and permeability are less than 20% and 20 mD, respectively.Detailed petrographic evaluation, stable isotope analysis, cathodoluminescence and fluid inclusion analysis were employed to develop the diagenetic model. The major controls on reservoir quality and diagenetic feature distribution were integrated and mapped within the sequence stratigraphic framework. Furthermore, a diagenetic facies scheme was established incorporating core description, petrography, RCA and MICP. The diagenesis evaluation was followed by a reservoir rock typing study to demonstrate the relationship between the identified diagenetic facies and established reservoir rock types using RCA, MICP and log data.Reservoir rock types were distinguished by their distinct storage and flow capacity characteristics from MICP and RCA. Multivariate statistical techniques were used to classify reservoir intervals into their reservoir rock types from the log data. Correspondence analysis was performed to corroborate relationships between the diagenetic facies and reservoir rock types. This was validated using saturation height functions within/between rock types. The results of this study will have lasting value to the asset. The geological and reservoir models being developed reveal controls and distribution of reservoir quality and can be updated and optimized with future planned data acquisition.
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