The folded belt of the Zagros Mountains presents a unique geological phenomenon characterized by concentric folding patterns, predominantly observed in the Cretaceous and younger units, featuring expansive anticlines and constricted synclines. Highlighted the prevalence of out-of-syncline thrusts, particularly in robust geological formations, evident in the intricate geological landscape illustrated in Fig. 1 and Fig. 2 [4].

Effective exploration and well planning within the Zagros Mountain belt demand a profound understanding of subsurface structural features. Stress the critical importance of this knowledge for planning and executing development and infill well projects, particularly in regions such as Gachsaran, Agha Jari, and Bibi Hakime within the Zagros belt [7]. Precise information about structural dip and fault patterns is indispensable for overcoming challenges posed by geological complexities, as seen in the Gachsaran oil field's example, specifically well GS-264 (Fig. 3).In the Gachsaran oil field, exemplified by well GS-264 (Fig. 3), challenges arise from geological complexities, including fractured reservoirs, varying layers of anhydrite and salt, (Fig. 4) and unanticipated variations in formation thickness. Strategic interventions like sidetracking are necessary to navigate these challenges and reach targeted reservoirs or oil columns [8].

Notably, employing water-based mud for drilling wells proves impractical in the majority of oil fields in the southwest of Iran, posing a challenge in obtaining geological information through conventional tools. A solution to this issue lies in the crucial role played by borehole image logs (OBMI-UBI) in facilitating proper reservoir characterization, especially in thinly laminated reservoirs, which is integral to successful field development [1]. During the coring process, samples are inserted into the tube relatively intact. Once in the laboratory, these samples undergo inspection and analysis using various techniques and equipment tailored to the desired data type [2]. To address this challenge, a combination of imaging tools designed for oil-based mud was employed, including the Oil-Based Microimager (OBMI), Ultrasonic Borehole Imager (UBI) tools, geological logs, and the versatile seismic Imager (VSI) for a vertical seismic profile (VSP). The utilization of oil-based mud image logs has evolved into a pivotal approach for assessing wells drilled with non-conductive drilling fluid, offering high- resolution directional datasets that significantly contribute to lithofacies classification [3,10]. UBI and OBMI, specifically designed for oil- based mud drilling, play a key role in characterizing oil reservoirs and providing quantitative resistivity of the invaded zone, aiding in the understanding of invasion profiles, particularly in carbonate and sandstone reservoirs [6]. Recent applications highlight the value of VSP surveys as litho-structural evaluation tools, capable of improving seismic imaging of fractured-cavernous carbonate reservoirs and aiding in the correction of interpretation results. This study focuses on a specific well targeting the Asmari formation in the Zagros Mountains, where drilling ceased at the middle Asmari due to reaching the predetermined total depth (TD). The study at hand employs UBI and OBMI tools to develop a comprehensive dip/structural model, subsequently utilized to construct a velocity model. Integration of these models with data from the versatile seismic imager (VSI) culminates in the generation of a vertical seismic profile (VSP). The interpretation of VSP findings aims to identify the root cause behind the well's inability to reach its intended target, emphasizing the significance of structural information and demonstrating the efficacy of borehole imaging tools in overcoming drilling challenges within complex geological settings.

Figure 1: Prominent anticline structures in the Foreland basin of the Zagros Mountains, trending from the northwest to the southeast [5].

Figure 2: Out-of-syncline thrust propagating along the synclinal axis in the Kuh-e-Dashtak (KED)-Kuh-e-Shah Nishin (KESN) structure, Zagros fold belt. The thrust terminates within the Miocene evaporites of the Gachsaran Formation [4].

Figure 3: location map of the well#GS-264 in the Gachsaran field.Source: (NIOC South UGC map).

Figure 4: All the informations and lithology display for Asmari and Sarvak reservoirs in Iran [9].

In this study, we employed the Full set and OBMI-UBI log data sets available in Geoframe software for a thorough analysis. To enhance the quality of the OBMI-UBI data, we utilized BorEid processing. All petrophysical logs and images were depth-matched to a reference log, and BorNor was applied to equalize and normalize images, thereby improving the visualization of formation features. In the representation of image logs, resistive units were highlighted in bright colors, while lower resistivity conductive units were depicted in dark colors.The interpretation process began with the manual selection of dips using sinusoidal techniques on oriented images displayed at a scale of 1:20 to minimize human error. Once selected, all dips were categorized into bed boundaries and fractures using Borview. Distinctions between open and closed fractures varied for oil-based mud imaging tools (OBMI and UBI) compared to water-based mud imaging tools (FMI). On OBMI images, open fractures were identified as those with low acoustic amplitude traces (dark) intersecting the sedimentary structure at a high angle, exhibiting a continuous trace with strong acoustic contrast and/or a wide apparent aperture. Closed fractures were discerned using UBI, being clear fractures visible on OBMI images but absent on UBI images (Fig. 5).Utilizing the dip data, a computer-based cross-section along the NNE-SSW plane was constructed in strucview. To extend the structural model beyond the well and achieve greater depth than the total depth (TD) with reasonable accuracy, a Vertical Seismic Profile (VSP) was conducted. The dip data obtained from borehole images played a crucial role in VSP processing, with accuracy dependent on the dip model applied to the area surrounding the studied well.

Figure 5: The study's workflow and presents a flow chart detailing the image processing chain for OBMI-UBI.

Structural Interpretation

Borehole imaging techniques, which encompass both electrical (OBMI) and acoustic (UBI amplitude) methods, provide a detailed examination of the upper section of the Asmari formation. These techniques reveal distinct layering and bedding features, shedding light on the geological characteristics of the subsurface. The identified layer and bed contacts exhibit a range of characteristics, including sharp, planar connections and vague, uneven contacts. The confidence levels associated with these contacts vary based on the sharpness and planarity of the features; high confidence is linked to sharp features, whereas low confidence is associated with less planar features.

Structural dip is calculated using the characteristics of these identified layer and bed contacts. Statistical analysis of bedding dips obtained from UBI and OBMI data reveals a prevailing dip azimuth of S18W and a strike ranging from S72E to N72W, with a spread of 25 degrees (Fig. 6&Fig. 7). The dip magnitude exhibits considerable variability, ranging from 34 to 63 degrees.

A continuous depth plot of bedding dips illustrates a concentration of all identified dips in the upper half of the logged interval, with no computed dips in the lower half. Additionally, the dip spread is more pronounced in the uppermost zone compared to the rest of the interval. Notably, the inclination of bedding dips increases with depth, transitioning from an average value of 45 degrees in the uppermost zone at 2120-2180m to 63 degrees in the middle part around 2490m(Fig. 11).

Despite the meticulous analysis conducted, no indications of fault presence were observed throughout the entire logged interval. This comprehensive examination using borehole imaging techniques provides valuable insights into the geological structure and layering of the Asmari formation in the specified depth range.

Figure 6: A) Header details. B) Presents images from OBMI (Oriented Bedding Microimager) and UBI (UltraBlue Imager), depicting the layering in a cross-section of the Asmari formation.

Figure 7: A statistical depiction of bedding dips, showcasing a variation ranging from 34 to 64 degrees. The strike orientation spans from N72W to S72E.

Fracture Analysis

To discriminate between open and closed fractures, the study employed OBMI (Oil-Based Micro-Imager) and UBI (Ultra-sonic Borehole Imager) amplitude images. UBI is primarily adept at identifying open fractures, whereas OBMI images depict open fractures with a resistive appearance. Within a specific depth range (2165-2220m), located 20-25m below the Cap Rock, a substantial occurrence of fracturing is conspicuous. In the remaining interval, the development of fractures is comparatively less pronounced. Most fractures manifest as low amplitude traces on UBI amplitude images and appear resistive on OBMI images, classifying them as open fractures. Further categorization of these open fractures is undertaken based on their continuity as continuous-open, discontinuous-open, and possible-open, determined by the persistence of their low-amplitude traces on UBI acoustic amplitude images. Closed fractures are not discernible; their potential presence would be identified by OBMI images, portraying them as resistive fractures with minimal visibility on UBI amplitude images (Fig. 8).

Figure 8: A. Header details are provided in B, Continuous and discontinuous open fractures shown by UBI and OBMI images in Asmari.

Continuous and discontinuous open fractures congregate densely in the northeastern (NE) region, falling within the 40 to 50 degrees inclination circle on the Schmidt Stereo net (upper hemisphere) and the dip-pole density contour diagram, displaying a broad range of dip azimuths. Continuous open fractures predominantly dip to N62E, with a 20-degree spread on either side, or strike dominantly at N28W-S28E with a similar azimuthal spread. Discontinuous open fractures exhibit a dominant azimuth around N58E with a 25-degree spread on one side, and on the strike azimuth rosette, they show a similar spread with the dominant strike azimuth of N32W-S32E. The dip inclination varies from 30 to 84 degrees, with the majority dipping at 34 to 60 degrees and a dominant dip inclination of 41 degrees (Fig. 9).

Figure 9: Statistical plots depicting the dip inclination of all open fractures. The dips range from 22 to 86 degrees, with an azimuth of N55E (averaging dominant values). The strike is oriented N35W-S35E.

The dip and strike rosettes of bedding and open fractures suggest that most fractures are oblique to the bedding, with only a small percentage aligning parallel to the bedding and dipping in the opposite direction, categorized as longitudinal fractures (Fig. 10).

Figure 10: The predominant strike lines, illustrating that most fractures display an oblique orientation to the bedding. Only a small subset of fractures align with the bedding's strike.

Open fractures are predominantly concentrated in the upper one-third section, with the highest density observed in the 2165-2220m range, approximately 20-25m below the Cap Rock .Areas of higher fracture density (number of fractures per meter) are identified at 2165-2175m, 2190-2220m, 2370m, and 2580m. Assuming that only open fractures contribute to production, a predictive productive profile for the Asmari carbonates intersected by the study well was established by integrating fracture density over the fractured interval. According to this analysis, the most productive interval is anticipated to be at 2165-2220m (Fig. 11).

Figure 11: A) Header details and B) a summary of fracture and structural analysis results in GS-264. Open fractures are predominantly observed in the upper one-third section.

Addressing Structural Complexity through Comprehensive Well Logging Analysis

According to the comprehensive report provided by the well site geologist, it was observed that the well encountered challenges in reaching the lower Asmari formation, specifically noting a deviation from the anticipated lower contact depth of 2588m, as initially forecasted (Fig. 12). Surprisingly, the true vertical depth (TVD) surpassed 2800m before reaching the target formation.This unexpected variance in depth prompted the National Iranian South Oil Company (NISOC) to initiate a more thorough investigation. Recognizing the importance of gaining a detailed understanding of the geological complexities involved, NISOC decided to employ advanced borehole imaging tools. This strategic move aims to enhance the precision and accuracy of the geological assessment, providing invaluable insights into the structural intricacies that may have contributed to the deviation from the projected well trajectory.

Figure 12: Proposed structural cross-section within the NE-SW plane encompassing the study well operated by NIOC South.

Therefore, it became imperative to seek an alternative explanation for the well's inability to successfully penetrate the lower Asmari formation. In order to delve deeper into this matter, a thorough examination of the bedding dip data was conducted in conjunction with a detailed analysis of the well trajectory.The trajectory of the well exhibited a noteworthy deviation pattern. It commenced with a deviation towards the northeast in the upper interval and gradually transitioned towards the southwest, maintaining this trajectory with a maximum deviation of 36 degrees until the total vertical depth (TVD) was reached. The challenge of not reaching the Lower Asmari and Pabdeh Formation at the expected depth necessitated a consideration of potential factors such as a high structural dip or the presence of a reverse fault. Upon closer inspection, borehole images captured in oil-based mud did not indicate the presence of a fault. However, they did reveal a steeper dip, which intensified as the well delved deeper into the subsurface. To visually represent these findings, please refer to Fig. 13 and Fig. 14. These images provide a comprehensive visualization of the well trajectory, structural dip, and other pertinent geological features.

Figure 13: The calculation of bedding dips is limited to the upper half (2120-2500m), revealing a progressively downward trend from an average of 45 degrees at the summit to approximately 60 degrees at 2500m. No dips were noted below the depth of 2500m.

Figure 14: A) A computer-generated structural cross-section derived from bedding dips calculated using OBM (Oil-Based Mud) images; B) Bedding dips are specifically computed in the upper half (2120-2500m), revealing a downward increasing trend from an average of 45 degrees at the top to approximately 60 degrees around 2500m. No dips were observed below the depth of 2500m.

The detailed examination of the on-scale cross-section, conducted along the N65E-S65W plane across the well, provided insights into its trajectory concerning the geological formations. The analysis revealed a consistent adherence to the dips of the formations upon entry into the Middle Asmari. Consequently, the well found itself confined within the Middle Asmari, unable to traverse the boundary between the Asmari and Pabdeh formations. This circumstance elucidates why the well did not intersect beds or layers, preventing the computation of dips in the lower half of the drilled section. Upon plotting cap rock and bedding dips alongside the well trajectory on the N65E-S65W plane, a clear alignment emerged. The well ran parallel to the dip of the Middle Asmari beds/layers in the lower half of the logged interval. This alignment was further substantiated by constructing a model that integrated bedding dips from oil-based mud images with the well trajectory projected onto the same S65W-S65E plane. In this model, the vertical axis represented true vertical depth (TVD), and the horizontal axis represented drift, both consistently plotted at a uniform scale. Remarkably, in the proximity of the Middle Asmari section, the well consistently paralleled the bedding, leading to its continuous penetration within the Middle Asmari formation until reaching total depth (TD). Consequently, the model serves as a valuable tool for elucidating why the well failed to penetrate the lower Asmari and why no bedding features were observed in the borehole images in the lower half of the logged interval. This comprehensive understanding is visually represented in Fig. 15, Fig. 16, and Fig. 17, providing a detailed depiction of the well's trajectory and its alignment with geological features.

Figure 15: Exemplifies the structural model developed along the S65W-N65E plane.

In the intricate realm of complex structural geometries within well environments, the efficacy of borehole seismic (VSP) data in delineating the surroundings of a well may be compromised when acquired in the absence of prior knowledge regarding the dip model. The significance of the dip model becomes apparent as processing outcomes can lead to misleading interpretations without an accurate representation of the actual dip model encompassing the well. To address this challenge, a meticulous approach was undertaken by conducting a rig source VSP using the Versatile Seismic Imager (VSI) on the deviated well GS-264 situated in the Gachsaran Field. In the pursuit of enhancing the reliability of the VSP data, a dip model derived from borehole images, as demonstrated in a preceding example, was integrated into the VSP data processing. This strategic utilization of the dip model yielded a high-quality seismic section, providing a discerning depiction of dipping reflectors and faults within the geological formation. Seeking additional insights, a Vertical Seismic Profile (VSP) was executed on the study well through the utilization of a 3-axis tool, namely the Versatile Seismic Imager (VSI) (Fig. 16).

Figure 16: A) Illustrates the structural model developed along the S65W-N65E plane. B) Preliminary results of VSP processing reveal robust, high-angle reflections both inside and at a distance from the well.

In regions characterized by intricate structural geometries, the application of borehole seismic (VSP) data for imaging well structures faced potential limitations in the absence of prior dip model knowledge. To circumvent this challenge, preliminary modeling was conducted using Oriented Borehole Micro Imager (OBMI) and Ultrasonic Borehole Imager (UBI) data, resulting in the development of a comprehensive Dip/Structural model. Subsequently, a velocity model was meticulously crafted based on this established model (Fig. 17).

Figure 17: A) Dip/structural model crafted from OBMI/UBI data, employed in the processing of VSP data.B) Velocity determined through the application of the OBMI/UBI dip/structural model for VSP processing.

Leveraging the refined Dip/Structural model and the data acquired from the Versatile Seismic Imager (VSI), a high-quality Vertical Seismic Profile (VSP) was generated to meticulously unravel the structural complexities surrounding the deviated well. The outcome of this processing was a superior seismic section, illuminating prominent dipping reflectors and faults within the geological strata.

Ultimately, the high-quality VSP section conclusively dispelled the notion of a fault as the causative factor, revealing that the issue stemmed from drilling the well parallel to the dip of the Middle Asmari beds/layers (Fig. 18 and Fig. 19). This comprehensive analysis, incorporating advanced modeling and seismic imaging techniques, elucidated the geological intricacies surrounding the well and provided valuable insights for future well planning and drilling endeavors.

Figure 18: Proves the VSP section both prior to and after using image log dip/structural model.

Figure 19: Interpreted Vertical Seismic Profile (VSP) section, revealing reflectors with a dip extending well below the Total Depth (TD) of the well. Additionally, fault pattern more than 500m away from the well trajectory of GS-264.

In summary, the structural dip exhibits a non-constant pattern, progressively increasing with depth while maintaining a consistent azimuth of S18W. Ranging from an average of 45 degrees in the uppermost section of Asmari to 63 degrees in the middle Asmari, this upward trend suggests a high structural dip. Despite the absence of faults according to borehole images in oil-based mud, the steeper dip observed indicates potential challenges in drilling deeper. The decision to discontinue drilling at this point prevents unnecessary expenditure of time and resources, as continued drilling under the same deviation would likely have hindered progress beyond the Middle Asmari layer. This study has successfully resolved structural complexities, leading to a precise determination of the well's location within the Asmari Reservoir. The dip classification based on geological logs has provided a clear and straightforward representation of the structural features. The research successfully tackles and resolves structural complexities, precisely identifying the well's location within the Asmari reservoir. This accomplishment hed noteworthy advantages, potentially leading to cost savings in drilling projects and facilitating the exploration of additional wells within the field. Furthermore, this study stands as a valuable reference for researchers, providing insights into previously uncharted areas of structural complexity within the reservoir.

Significance Statement

The comprehensive understanding gained about the Asmari structure has significantly contributed to enhancing the reservoir model employed by the operator. This advancement empowered NIOC South to more accurately assess reservoir potential and improves their proficiency in utilizing OBMI-UBI data, particularly in instances where 3D seismic data is either unavailable or of suboptimal quality. In essence, this study not only resolves critical structural issues but also elevates the operator's capacity to model and evaluate the Asmari reservoir, even in scenarios where conventional data sources are constrained.

Acknowledgment

Our sincere thanks go out to everyone who played a crucial role in making this project a success. Without their steadfast support, reaching this milestone would have been impossible. Special gratitude is extended to NIOC South for their generous provision of vital data and resources, which proved to be indispensable in the successful completion of our project.

Author’s Contributions

Each author contributed equally and significantly to the completion of this study.

 Ethics

The authors assert that they have no conflicts of interest.

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