Wellbore instability has been experienced in areas of the Marcellus Shale and can become particularly troublesome in the superlaterals that are becoming more prevalent in that play. Often, the instability while drilling these very long lateral wells is minimal; problems are more likely to occur while tripping out after reaching total depth (TD). The most common instability events when pulling out of the hole are tight hole, packoff, and stuck pipe and are often accompanied by excessive cavings. These problems often worsen with time, indicating there is some time dependence to the failure mechanism. In order to develop effective mitigation strategies to combat the instability, it is imperative that the failure mechanism be correctly identified. Previous publications (Riley et al., 2012; Addis et al., 2016; Kowan and Ong, 2016) have suggested that bedding planes may play a role in some of the drilling problems experienced in the Marcellus Shale. This case study provides conclusive proof of weak bedding plane failure along a lateral well in the Marcellus Shale, where over 1,000 feet of anisotropic failure was captured with a logging-while-drilling (LWD) image tool. This image not only provided confirmation of the presence and failure of weak bedding planes in the Marcellus Shale, but was also used to validate an existing geomechanical model for the area. Validating the model gave the operator more confidence in the mitigation strategies developed from that geomechanical model, which had been based on the assumption that weak bedding was contributing to the difficulty experienced on multiple lateral wells when tripping out of the hole. This case study begins with an overview of the geomechanical model, including the drilling history, stress/pore pressure model, and rock properties. Next, some highlights from the image log, showing anisotropic bedding plane failure, are featured, as well as a comparison of the image to the geomechanical model. This case study concludes with proposed mitigation strategies that could be implemented to limit the risks posed by weak beds and to minimize instability when drilling laterals in the Marcellus Shale in this area or similarly complex areas.
The effective optimization of hydraulic fracture treatments in Coiled-Tubing Drilled (CTD) horizontal wells requires the integration of geomechanical modeling and properly designed hydraulic fracture treatments, including carefully selected stage and cluster placement. Tight sandstone reservoirs are often characterized by low productive potential due to low permeability, complex compartmentalization and limited reservoir energy resulting from low reservoir pressure. Well productivity may be optimized in both open-hole and cased-hole horizontal completions by minimizing the formation damage in these sandstone reservoirs through the application of true underbalanced CTD techniques, proper lateral configuration and optimized fracture stimulation design. In this study, geomechanical analyses were utilized to derive rock mechanical properties of tight sandstones, such as Young's Modulus and Poisson's Ratio using basic density, porosity and acoustic (compressional and shear) logs. General drilling experiences and mud weights were considered along with the logs to model pore pressure, overburden and horizontal stresses and a log-based minimum horizontal stress was calculated. The estimated in-situ stress and rock mechanical properties from the geomechanical model were used to investigate the pressures necessary to create hydraulic fractures in the tight sandstones and their propagation direction, in order to improve the flow capacity. Hydraulic fracturing models were developed to identify fracture geometry parameters (length, height, width, conductivity and permeability) for horizontal CTD wells in tight sandstones. Well performance analysis was performed to estimate potential production rates from CTD wells having various lateral lengths and numbers of frac stages by minimizing formation damage through true underbalanced CTD techniques and optimized stimulation design. Effective horizontal lateral length was determined as the combined length of each stage that was successfully treated. Modeling the open-hole and cased-hole multistage completion systems in the tight sandstones indicates longer laterals and an increased number of available stages are desirable to increase production. Our models suggest that a successful, efficient completion may be achieved in tight sandstone reservoirs through the application of true underbalanced CTD techniques coupled with optimized lateral geometry and fracture stimulation design.
We have developed a new analytical model for underbalanced drilling (UBD) that takes into account that rocks have scale dependent strengths, that the full stress concentration is not developed at a given depth in a well until sometime after the drill bit has passed, and that fluid flow into the advancing wellbore leads to a zone of locally lower pore pressure surrounding the well that extends beneath the drill bit. The model predicts regions within which compressive shear failure will occur and also provides predictions of where spalling (tensile failure) is a possibility. The results provide a more realistic and less conservative prediction of wellbore risk than models developed to study the stability of overbalanced wells. This new model can be applied to predict whether underbalanced operations are possible in a given well, and also the severity of wellbore instability as a function of underbalance. In addition, the model allows constraints to be placed on the in situ stress field (magnitudes and orientations) based on observations of wellbore failure in wells which have been drilled underbalanced. Wells designed utilizing model predictions were drilled without incident, and the model also provided reasonable predictions of the state of stress.
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