Anisotropy and heterogeneity in reservoir properties introduce challenges during the development of hydrocarbon reservoirs in naturally fractured reservoirs. In reservoir simulations, grid-block properties are frequently assigned to obtain reasonable history matches. Even then, accuracy with regard to some aspects of the performance such as water or gas cuts, breakthrough times, and sweep efficiencies may be inadequate. In some cases, this could be caused by the presence of substantial flow through natural fractures.In this work the fracture characterization and modeling was performed in a highly fractured carbonate reservoir in SW Iran. It was observed that reservoir simulation based on the generated fracture model present a more reasonable history matching of the production. The study indicates that NE-SW is the dominant orientation of critically stressed fractures that are most problematic for gas/water breakthrough.The primary objectives of this study are: a) construct a fracture 3D model to be used in reservoir simulation and b) distinguish the most problematic fractures in water/gas breakthrough. The steps of this study are as follows: -Constructing the 3D geological framework of the reservoir. -Identifying and characterizing natural fractures at the well level using borehole images.-Generating the 3D-stochastic model of discrete fracture network (DFN), incorporating image log data with outcrop analogies studies in the context of buckle folding mechanism.-Scaling up the fracture model with integration of well test results -Running reservoir simulation based on the scaled-up fracture model to validate the model and observe the history matching -Performing critically stressed fractures (CSF) analysis to distinguish problematic fractures.
Laminated units made up of alternating thin sand and mud layers are known to be very challenging in terms of reservoir characterization and evaluation. Alternation of thin sand and mud layers imposes natural anisotropy in the distribution of reservoir properties such as porosity and permeability. This anisotropy has been proved to be a major control on fluid flow within the reservoir which is of paramount importance to understand and consider in reservoir development planning. The aim of this work is to integrate geological information derived from borehole images into interval pressure transient test (IPTT) interpretation to analyze and explain the complex flow behavior resulting from a combination of formation dip and laminations.A wireline formation tester dual packer module was utilized in two offshore exploration wells to conduct an IPTT/miniDST (mini Drill Stem Test) in different lithofacies including laminated units. Several build up tests were performed to obtain valid reservoir pressure and permeability values. Consistency was observed in the log-log diagnostic plot from these build up tests and the pressure derivative behavior suggests multiple possible reservoir scenarios in this complicated geological setting. A detailed study on borehole images and 3D near-wellbore geological model revealed the effects of slanted wellbore, laminated units and dipping beds on the travel of pressure transient away from wellbore. With this information, a representative reservoir model was able to be constructed to match the IPTT data and to obtain the required reservoir parameters.This paper highlights the main challenges of formation characterization in laminated thin sand and mud layers. Special emphasis was given to resolve significant problems encountered in pressure transient test interpretation in highly deviated wells. Slanted wellbore sections are typical in Malaysia's offshore fields as the wells are drilled from offshore platform to intercept the formation at different angles, hence the pay zone and other petrophysical parameters are usually underestimated. Attempts are made to identify and classify these challenges, and recommendations are provided toward better resolution during interpretation.
Thin-bedded sands in shallow water clastic deposits are widely neglected as exploration targets simply due to conventional wisdom that focuses more on the "charismatic" blocky clean sand packages. In addition, the lack of a strong, characteristic motif on the log response and complexity in quantitative characterization of these thinly laminated sequences leads to even less attention to such sequences as potential targets. This can have significant impact on the certainty of realistic reserve calculation in exploration and development planning in regions such as Southeast Asia where these thin-bedded sands are a considerable portion of the stratigraphic column.This study has two phases; in the first phase, a novel technique is presented to identify and quantify thin sand laminations using borehole images and core. Both borehole image and core data is converted to binary data representing shale and sand facies. Then these images are used to quantify the total thickness of thinly-laminated sands on the basis of specific cutoff values. In the second phase, a comprehensive analysis of a local present-day analogue determines the possible hydrocarbon storage capacity of thin-bedded deposits. This is accomplished through an area/volume approach. In this approach, after locating the pertinent locality within the depositional environment that can be considered as the equivalent to the subsurface section under study, the sand volume vs. area of thin-bedded heterolithic facies is computed. This is used to estimate the storage capacity of these facies at the field-scale. Additionally, the storage capacity is compared to the capacity of channelfill sands as conventional targets in the same setting.Results of this study show that the new technique using high-resolution borehole images can successfully identify and quantify thin-bedded sands, and results have an excellent match with core data. Also, the core results confirm that these deposits have sufficient reservoir quality (porosity and permeability), particularly for gas production. This work demonstrates that, contrary to conventional belief, the storage capacity of thin-bedded sands can be significantly high and sometimes may even exceed that of blocky channel or mouth-bar sands. This implies that substantial quantities of pay are continuously bypassed in basins where these sequences are expected.
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