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In a reservoir with high oil content but insufficient permeability, hydraulic fracturing operation is essential to increase the permeability. To perform such an operation, one of the challenges is to identify appropriate intervals of the reservoir for hydraulic fracturing. Therefore, this paper proposes a new workflow for intelligent identification and 3D modeling of suitable intervals for hydraulic fracturing. In this study, geomechanical and petrophysical parameters were clustered using hierarchical method for 30 wells in Sarvak reservoir at an N–S trending oil field in southwest (SW) of Iran. Five clusters were identified, which according to their characteristics have a different priority for hydraulic fracturing. It was observed that cluster 1 has the most suitable characteristics for the hydraulic fracturing. The clusters were modeled three-dimensionally using sequential indicator simulation (SIS) method. Based on the 3D model, cluster 1 is extended broadly in the northern part of the oil field.

In this study, an integrated geomechanical analysis was carried out for the Sarvak carbonate reservoir in three wells of one of the oil fields in Abadan Plain, SW Iran. The static Young’s modulus (ES), unconfined compressive strength (UCS), cohesion (C), and angle of internal friction (Φ) were determined directly, using rock mechanics tests. Subsequently, some correlations were introduced based on tests-to-logs relationships. The 1D geomechanical models were constructed for three wells in the north, center, and south of the studied field. The results show that the stress state is not uniform for the studied wells, as it is strike-slip normal in northern well, strike-slip in central well, and strike-slip reverse in southern well. Likewise, the stability of the wells was evaluated using Mohr-Coulomb and Mogi-Coulomb criteria, and it was observed that the Mogi-Coulomb criterion could more accurately estimate the breakout pressure. According to the recognized borehole breakouts in image logs, the SHmax direction is to NE-SW in all three wells. Based on the wellbore stability analysis, it was concluded that the more stable directions for drilling are NW-SE in the northern part, E-W and N-S in the central part, and NE-SW in the southern part of the studied oil field.

Fracture network modeling for hydrocarbon reservoirs plays an important role in dynamic simulation within the porous media. This modeling is traditionally performed using stochastic methods, which often are based on image logs run in very few wells. Accordingly, using such stochastic methods cannot satisfactorily provide reliable models for the fracture networks of the reservoir, which in turn result in unrealistic predictions of either fluid flow or production behaviour. In this paper, an algorithm is developed based on the initially and the secondary variables involving upscaled fracture attributes, including a new introduced variable named Cumulative Aperture (CA), and petrophysical data, respectively. Our introduced variable (CA) corresponds to the fracture volume which is defined as the multiplying of the fracture density by the fracture aperture. The introduced CA is correlated with the secondary porosity obtained from the conventional well logs. In addition, based on our experimental results, the other correlated variables are the aperture and the resistivity obtained from the image logs and the conventional logs, respectively. Following that, all correlated variables are jointly simulated using the turning bands co-simulation method at the target grid cells. The outcomes, at the end, are post-processed which led to a fracture network model. The resulting fracture network agrees with geological concepts and consequently is deemed reliable.

Borehole image logs are kind of the modern logs which are frequently used to detect small-scale fractures intersecting well in fractured reservoirs. Electrical imaging tools like FMS (Formation MicroScanner) and FMI (Fullbore Formation MicroImager), electrically scan the borehole wall and deliver a pseudo-picture of the formation. Characteristics of fractures such as type, aperture and orientation can be determined by interpreting these logs. In this paper, we attempt to evaluate the ability of electrical image logs in detecting fractures and other geological features of a carbonate reservoir (Asmari) and explain the possible reasons of mismatch between the image log and core. To achieve this goal, we have compared the FMS of a well with the core. The results are verified with FMI and core data from seven nearby wells. Comparison of the FMS with the core revealed that FMS, as representative of electrical image logs, is robust in detecting open fracture and anhydrite; it is average in detecting bedding plane and flexural slip and is weak in detecting filled fracture, fault and compactional feature in carbonate reservoirs.

Asmari is a heterogeneous carbonate reservoir, which fractures play main role in hydrocarbon production. The main goal of present study is evaluation of FMS’s ability in detecting fractures and other geological features of Asmari formation. More than 380 m whole core that cut from Asmari described in order to extract structural features. FMS of this interval has also been processed and interpreted. Then, in order to evaluate and compare structural features on both core materials and image logs, the frequency logs (as frequency per 0.5 m) (for fractures, compactional features, beddings and anhydrite),orientation plots (for fractures and beddings) and aperture log (For open fractures) have been generated. Results checked by fractures data of seven wells (five image logs and two cores) of studied field and one well of neighbor field that obtained from core and image logs. Comparison of core and FMS revealed that they have excellent correlation for open fracture. FMS rarely detects filled fractures and faults of Asmari in studied well. It also is average in detecting bedding plains. Most of the 940 compaction features observed in core could not be recognized in FMS. Anhydrites in Asmari determined by FMS had good correlation with core.

Production from the Asmari carbonates of the Dezful Embayment, southwest Iran, provides a textbook example of the dynamic behavior of fractured reservoirs. In these reservoirs, fracture modeling is therefore a key task of any characterization workflow. This study presents recent findings on the relationship between fracturing, diagenesis and folding in the Zagros Foreland Basin and their practical consequences on fractured reservoirs modeling workflows. Based on the structural description of outcrops, the synthesis of image log interpretations and the analysis of fracture filling (both in outcrop and subsurface), we first propose a chronologic framework for the fracturing events in relation to paragenetic sequence in the Asmari Formation. This emphasizes the pre-folding origin of the main fracture sets affecting the formation. During these early events, the pre-Hercynian NS basement trends that affected the Arabian Plate, strongly controlled the spatial distribution of fractures. This stage of fracturing was associated to the growth of burial stylolites and successive stages of dolomite and calcite cementations. In a second stage, during folding, most of the deformation was accommodated by reactivation of pre-existing fractures. These fractures were associated with the precipitation of ferroan calcite in the exposed rocks, anhydrite in the reservoir and the first stages of hydrocarbon emplacement. A 100 x 100 square km 3-D model, which includes outcrops and reservoirs, will be discussed. Contrary to the growing use of such a method to control fracture density, we advocate that it better provides a good proxy for fracture reactivation potential and associated flow paths.