In the Middle East, a significant amount of Non-Productive Time (NPT) has been associated with controlling wellbore instability caused by weak shale before reaching the reservoir. Due to limited availability of pad locations and complex well trajectories, operators are now forced to drill high angle wells through shale as compared to vertical or low angle wells in the past. This has resulted in a substantial increase in drilling complications in terms of controlling shale instability. Comprehensive geomechanical studies from various fields of Middle-East have helped to determine most plausible root causes of shale rock instability and to draw a holistic geomechanical approach to solve the problem. Shale samples (core and cuttings) were collected from multiple fields, and various types of lab tests were performed on these samples including XRD, XRF, chemical tests, rock mechanical tests etc. Geomechanical modeling and drilling analysis were performed to compare the drilling events to the shale characteristics in order to determine the mechanisms of rock failure. Chemoporoelastic and plane of weakness modeling techniques were also performed to understand some less-common failure mechanisms that were driving instability within these shales. It was noted from the analysis that not all shales behave in a similar fashion. A potential solution that may solve instability problem in a particular field/region might not be effective in the other field/region. Geomechanical analysis suggested that a range of shale instability mechanisms ranging from stress induced failures and planes of weakness to complex rock-fluid interaction were responsible for hole instability, and different mud and drilling parameters are required to keep the hole stable in different shales. Raising the mud weight exclusively during drilling of these shales with multiple failure mechanisms was found to be ineffective and potentially counter-productive. A customized solution along with real-time geomechanics monitoring can help to mitigate shale instability in drilling of high angle wells. A customized methodology for shale stability has been proposed in this paper based on integrated mechanical and chemical characteristics of most commonly encountered shales in the Middle East. This approach has helped to devise a comprehensive as well as practical approach to enhance drilling efficiency through shales in various fields in the region.

Zubair Formation is the deepest producing Cretaceous reservoir in North Kuwait. This 1,400 ft thick formation was deposited in deltaic to paralic depositional environment with complex sand/shale sequence, structural geometry, mineralogical composition and lateral extent. Drilling wells of any profile has witnessed high non-productive time due to severe wellbore instability issues in the form of stuck pipes, tight holes, hole pack-offs and jarring/fishing operations. So, a number of vertical wells were drilled to drain the reservoir– an economic challenge. Current strategic goal in this matured reservoir is to exploit multiple but thin pays by maximizing reservoir contact with high angle multi-lateral wells. An integrated 3D Geomechanics study was carried out in two phases. In the first phase, responsible failure mechanisms for wellbore instability were identified: stress induced breakouts, washouts and cavings, failure and fluid invasion associated with shale bedding planes at high deviation and osmotic pressure transmission between Zubair shales and drilling fluid system. Water sensitivity of clays and presence of micro-fractures were also studied on cores of this trouble making formation. In the second phase, calibrated well based 1D Geomechanical models; 3D structural model with high definition faults, facies models indicating lithological changes and drilling experience of latest high angle wells were integrated into a 3D Geomechanical model. The 3D model was tested with data from several offset wells and it was capable of explaining the wellbore failure of these wells. This 3D geomechanical model also helped in predicting mud weight window for any proposed high angle well trajectories. Mitigation measures from the study included drilling with Oil Based Mud or High performance water based mud systems with model derived mud weights, micronized sealing polymer to seal-off the laminations and micro-fractures, marble grade Calcium carbonate or resilient graphite to plug wider fractures and high salinity of mud to avoid time-sensitive osmotic flow. After implementing these recommendations, six horizontal wells have been drilled successfully. The study has given further confidence to implement an aggressive field development plan for optimal depletion. The paper discusses complex reservoir architecture, drilling complications and how the integrated study helped to achieve a breakthrough in development planning.

Laboratory derived geomechanical properties from core samples and well logs are always associated with some degree of uncertainty due to difficulties of mimicking actual reservoir conditions in the laboratory. Narrowing down this uncertainty is essential for proper design of drilling programs, surface water injection facilities and downhole completions, especially in the case of newly discovered and undeveloped reservoirs. For tight oil and gas reservoirs, where multistage hydraulic fracturing is being utilized for enhanced well productivity and injectivity through multiple transverse and longitudinal fractures, the success of field development depends directly on the ability to establish accurate geomechanical properties for use in the design of these fractures. In fact, achieving the right design parameters during hydraulic fracture execution using accurate rock mechanical properties has direct and positive effect on the productivity or injectivity of the fractured well. This paper presents a methodology of incorporating data from the microfracturing test into a comprehensive geomechanical model to determine the direction and magnitudes of in-situ reservoir stresses and other rock mechanical properties. A field case involving a recent microfracturing test conducted in a new tight oil reservoir under development in Saudi Arabia will be used to demonstrate how uncertainties in the geomechanical properties is significantly minimized to achieve better rock parameters for multistage fracture design. Finally, the results are validated with an actual hydraulic acid fracture job.

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The well design has been changed over last 55 years of development in Zubair Formation. It is the deepest producing Cretaceous reservoir in North Kuwait. This 1,400 ft thick formation was deposited in deltaic to Paralic depositional environments with complex sand/shale sequence, structural geometry, mineralogical composition and lateral extent. Drilling wells of any profile has been more difficult than the shallower reservoirs overlying it. The wells have witnessed high non-productive time due to severe wellbore instability issues in the form of stuck pipes, tight holes, hole pack-offs and jarring/fishing operations. During initial phase lasting over 4 decades, vertical wells were drilled to drain the oil column which was thicker in most part of the Field. With water encroachments from bottom and edge, thinner pay Sands in multiple but thin pays are needed to be exploited by maximizing reservoir contact with high angle multi-lateral wells for effective production. Drilling complications are inherent in Zubair since beginning even with vertical and deviated wells. Current transition to horizontal and high angle wells was possible with integrated studies. In the first phase of mitigating stability, responsible failure mechanisms for wellbore were identified: stress induced breakouts, washouts and cavings, failure and fluid invasion associated with shale bedding planes at high deviation and osmotic pressure transmission between Zubair shales and drilling fluid system. Water sensitivity of clays and presence of micro-fractures were also studied on cores of this trouble making formation. In the second phase, calibrated well based 1D Geomechanical models; 3D structural model with high definition faults, facies models indicating lithological changes and drilling experience of latest high angle wells were integrated into a 3D Geomechanical model. The model was tested with data from several offset wells and it was capable of explaining the wellbore failure of these wells. It was used predicting mud weight window for any proposed high angle well trajectories. Mitigation measures from the study included drilling with Oil Based Mud or High performance water based mud systems with model derived mud weights, micronized sealing polymer to seal-off the laminations and micro-fractures, marble grade Calcium carbonate or resilient graphite to plug wider fractures and high salinity of mud to avoid time-sensitive osmotic flow. The integrated study was implemented and six horizontal wells and a highly deviated well have been drilled successfully. The well designs and trajectories have been modified to drill along different azimuths of stress field with turns and up dip/down dip movements. Structurally complex and faulted blocks could be crossed effortlessly. The study has given further confidence to implement an aggressive field development plan for optimal depletion of undrained areas. Current strategy is to have vertical and deviated wells also for thicker reservoirs as they have the advantage of well interventions. The paper discusses complex reservoir architecture, drilling complications and how the integrated study helped to achieve a breakthrough in development planning.