Wellbore instability challenges encountered while drilling the Nahr Umr Shale include, but are not limited to, hole collapse leading to hole enlargement. Wellbore instability leads to huge cost increases in the drilling process and in rare cases well abandonment. Observations from drilling data suggest that wellbore stability varies with different wellbore deviations and azimuths, especially in areas of highly laminated formations and anisotropic in-situ field stresses. Accurate information on the rock strength and rock failure behavior in shale has a major impact on the improvement of drilling efficiency. Knowledge of the mechanical properties of shale is essential to implement any 3D shale anisotropy borehole instability model (Crook AJL, et. al., 2002). Shale mechanical properties were evaluated from laboratory tests. Well-preserved core samples retrieved from the Nahr Umr Shale were put through several tests to describe the mechanical characteristics related to rock strength and in-situ stresses with the aim to determine the effect of the anisotropy and plane of weakness in drilling high-sailing angle trajectories. Strength anisotropy was assessed using the plane of weakness model (Jaeger, J.C., & Cook, N.G.W., 1979) which assumes that the heterogeneous media is composed of a matrix rock and a plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations). Shear failure occurs once the shear stress acting on the plane of weakness exceeds its shear strength. Laboratory tests include both extremely slow triaxial tests and multistress path testing performed on three orientations. Failure envelopes were created to develop the plane of weakness model to predict the orientation of the weakest plane and determine the magnitude of the strength reduction. Elastic anisotropy data from plugs is combined with advanced sonic logs, enabling a more robust evaluation of the formation anisotropy to improve both stress predictions and the allowable mud-weight windows during wellbore stability assessment.

This paper seeks to address the challenges of BHA dysfunctions in complex wells’ environment which impacted the drilling performance in Abu Dhabi Offshore. Drilling operations experienced various cases of BHA failures, which triggered the need for advanced tools to enhance the bit and BHA design analysis during the well preparation phase. Market research was conducted to identify the commercially available software for bit and BHA design analysis. It is to enable a systematic in-house analysis of the bit and BHA proposed by the service providers to ensure the directional drilling and performance goals can be achieved. A specific drilling software was identified as a fit-for-purpose solution. It offers 3D mechanical modelling of any directional system, sensitivity analysis on multiple BHA settings, hole characteristics, and operational parameters driven by a fast-numerical methodology. The acquired software package includes several key modules: BHA pre/post-analysis, PDC bit model, local doglegs, and vibration analysis. The plan was then put in place to enable implementation across fields. In-house training was conducted to introduce the software to end users. Data gathering for PDC bit and RSS modelling was conducted in collaboration with the service providers. The BHA pre-analysis workflow was then defined to enable comprehensive bit and BHA modelling analysis, covering directional drilling analysis and vibration modal analysis. An agreed BHA configuration and stabilization was identified, and boundaries of optimized operational parameters were determined. Drilling operation was then executed with the agreed bit and BHA following the recommended operating parameters. In after, the BHA post-analysis was conducted to calibrate the PDC bit and RSS modelling by utilizing real-time data and directional drilling information. It also captured the lessons learned for bit and BHA design future improvements. The workflow was implemented for 22 drilling BHA in 2021 with most of the focus in 6″ hole section, long lateral drain application. The BHA performance evaluation of the 6″ hole section demonstrated the improvement result, with 10 out of 12 BHA achieving the objective to complete the section in 1 run. The BHA specific polar plot and RPM driller roadmap provided in this analysis functions as a practical guide for BHA analysis during well preparation and execution.

Thin layering and micro-fracturing of the thin laminated layers are some possible reasons for the wellbore stability problems of the Nahr Umr shale. If the drilling fluid density is too low, collapsing of the borehole is possible, and if the drilling fluid density is too high, invasion of the shale can occur, weakening the shale, making boreholes prone to instability. These effects can be semi-quantified and assessed through the development of a geomechanical model. The application of a geomechanical model of a reservoir and overlaying formations can be very useful for addressing ways to select a sweet spot and optimize the completion and development of a reservoir. The geomechanical model also provides a sound basis for addressing unforeseen drilling and borehole stability problems that are encountered during the life cycle of a reservoir. Key components of any geomechanical model are the principal stresses at depth: overburden, minimum horizontal principle stress, and maximum horizontal principle stress. These determine the existing tectonic fault regime: normal, strike-slip, and reverse. Additional components of a geomechanical model are pore pressure, unconfined compressive strength (UCS) rock strength, tilted anisotropy, and fracture and faults from image logs and seismic. Unfortunately, models used to make continuous well logging depth-based stress predictions involve some parameters that are derived from laboratory tests, fracture injection tests, and the actual fracturing of a well—all contributing to the uncertainty of the model predictions. This paper addresses ways to obtain these key parameter components of the geomechanical model from well logging data calibrated to ancillary data. It is shown how stress, UCS, and pore pressure prediction and interpretation can be improved by developing and applying models using wellbore acoustic, triple combo, and borehole image data calibrated to laboratory and field measurements. The nahr umr shale and other organic mudstone formations exhibit vertical transverse isotropic (VTI) anisotropy in the sense that rock properties are different in the vertical and horizontal directions (assuming non-tilted flatbed layering), the horizontal acoustic velocity is different from that of vertical velocity. This necessitates the building of anisotropic moduli and stress models. The anisotropic stress models require lateral strain, which as shown in the paper, can be obtained from micro-frac tests and/or borehole breakout data.

We present a root-cause analysis of severe lost circulation and creation of its risk map in an offshore oil field, Abu Dhabi. Lost circulation of more than 100 barrel per hour (BPH) has occurred in sixteen (16) boreholes through the carbonate reservoir. Four (4) out of them experienced total loss. The authors investigated spatial distribution of lost circulation and allowable maximum overbalance based on review of drilling operation in nearly two hundred (200) boreholes. The critical overbalance to reactivate the natural fractures for the tensile-opening or shear-slip failures was analyzed by using geomechanical model. The present study clarified that most of severe lost circulations occurred at the specific sub-layers of the reservoir. The core observation showed that lost circulation occurred in the intervals in which fragmented rocks (rubbles) and fractures were distributed together. The fracture stability analysis revealed that the conductive fractures interpreted by borehole imager were geomechanically stable under conventional overbalance applied in drilling through the reservoir sections. Namely, the planer fractures were geomechanically stable under the current in-situ stress condition. The study concluded that the predominant root-cause of severe lost circulations in the carbonate reservoir was cave-related rocks (cave facies) and excessive overbalance applied to reservoir pressure. The cave facies were supposed to be formed by flank-margin cave system and its collapse due to deposition of overburden formations. A risk map of lost circulation defined the five areas with its potential risk. The risk map indicated not only the risk level of lost circulation but also practical recommendations on the depth to set casing and allowable maximum overbalance. It functions as a practical guide for the design of boreholes in the ongoing drilling campaign.

The paper seeks to address the challenges of drilling BHA dysfunction which impacted the drilling performance in Abu Dhabi Offshore. Drilling operations experience vibration and stick-slip which limited the ROP and often led to BHA failure cases. In addition, challenging trip out and casing running were observed which indicated unsatisfactory borehole quality. Enhancement of the drilling BHA is required to reduce vibration and improve borehole quality. In reference to study of Self-Excited Stick-Slip Oscillations of Drag Bits by Thomas Richard in 2001, reducing the amplitude of the vertical oscillations should lessen (if not eliminate) the severity of the coupling between the two modes of vibrations, and therefore, of the self-excited vibrations. This could be achieved by minimizing the upward motion of the BHA, by appropriately increasing the lateral friction between the BHA and the borehole wall. Appropriately means "without affecting too strongly the overall efficiency of the system." Friction Adjustable Stabiliser Technology (FAST) is designed with patented features to achieve the above-mentioned BHA condition. A series of runs with FAST incorporated into RSS drilling BHA were planned. A set of KPIs were put in place to evaluate BHA performance. The drilling BHA was simulated to obtain the optimum tool placement, in collaboration with BHA providers. The drilling results were then analysed and compared with analogue wells to demonstrate the deployment of this technology. The deployment of FAST was conducted in 12-¼″ and 6″ hole sections with a total of 7 runs. FAST was run with various RSS systems with low level of vibration in the majority of the runs and proven to minimize vibration/stick-slip during drilling by acting as the BHA contact point and delivering consistent and sufficient friction. As a result, the drilling BHAs were able to deliver the objective to TD and avoid additional trips due to BHA failure. Borehole quality was evaluated through trip out BHA and casing/tubing RIH performance. There is still room for improvement in trip out performance, as backreaming was still required in most of the runs. However, positive impact to performance of RIH casing or lower completion from good quality borehole drilled by BHA with FAST was confirmed from all runs. The saving from fit-for-purpose BHA design on average is 2 days, considering the average NPT for trip out the BHA. In addition, improvement in trip out performance in 6″ section is 0.4 days. Considering above, total saving from 6″ section is 2.4 rig days. The detailed BHA performance analysis and operation feedback from subsequent wells will be beneficial to assess the suitability of this technology to overcome future drilling challenges.