No abstract

Wellbore tortuosity is a potential source of friction, which can lead to problems while running casing and completions. Describing a smooth trajectory qualitatively as one with the least amount of bends is easy. However, quantitative tortuosity indices based on survey trajectory data alone have shortcomings that make comparisons and interpretation very difficult: Their computational results depend on the survey interval (averaging effect). While 90-ft surveys hide important wellpath features, short spacing surveys might yield alarmingly high tortuosity, which does not reflect the curvature of the pipe in the borehole. Varying stiffness of the pipe and clearance between the pipe and borehole can have different levels of negative consequences with the same survey data. Stiffness and clearance have a direct impact on physical bending moments and sideforces, which drive frictional losses when moving pipe in an out of a borehole. The scale of the wellbore undulations relative to the clearances is relevant to be able to distinguish relatively benign undulations from tortuosity that limits wellbore construction. In formulating a scaled tortuosity index we have taken into account that actual hole curvature is not the curvature of the pipe in that hole, which is governed by stiffness and clearance. The main driver for the index is the bending moment profile along the pipe as it is positioned in the wellbore. The proposed index describes the total amount of required elastic energy (originating from these bending moments) to bend all the components in the string in all the required configurations to move it to total depth. The index is linked to nominal hole and casing sizes, (i.e. 7in casing in 8.5in hole) to make it applicable and comparable. Hence this concept is different from the existing dimensionless wellbore energy index.

The increasing complexity of wells currently being drilled has led to considerable innovation in the oil and gas industry. The advent of rotary steerable systems has improved average rate of penetration (ROP), borehole quality, and, therefore, well construction times. In addition, the improvement in well placement technologies, such as deep resistivity measurements, has enables greater geological certainty in well placement. However, there is a trend towards increased trajectory complexity due to geosteering, which has led to the possibility of higher unplanned tortuosity. This will have an impact on the well construction as problems related to torque-and-drag can be expected to increase. These problems include increased casing and completion running times and possibly other types of problems, such as reduced wireline or logging-while-drilling (LWD) log quality and cementing problems. The improvement in continuous surveying techniques, which provide high-resolution surveys while drilling, enables a greater insight into the true trajectory of a wellbore and provides a more realistic input trajectory for torque-and-drag modeling.A study comparing wells with different drive mechanisms highlighted the difference between standard 30-m (90-ft) surveys and high-resolution surveys built from standard and continuous survey measurements in the context of torque-and-drag modeling. An analysis was conducted of the wellbore tortuosity described by high-frequency continuous survey using finite-element drillstring modeling. Identifying the impact of various drive mechanisms provided insight into the level of tortuosity that may be expected on typical horizontal geosteered wells, buildup sections, and tangent sections. Findings from this study were combined with those from previous papers published on tortuosity to deliver results based on multiple wells. Recommendations stemming from this work include torque-and-drag requirements and improvements to drilling practices that will enable an improved ability to drill for completion.

In the exploration and production (E&P) industry attempts at reducing the cost of the well construction by applying various well architecture slim designs has attracted attention from operators for decades. The recent industry downturn has further contributed to a renewed focus on this strategy. In this study we present a slim well design application within the FortunaCo project (a Joint Venture between OneLNG and Ophir), which aims at developing the Fortuna and Viscata fields in Deepwater offshore Equatorial Guinea. An advanced static nonlinear Finite Element engine is used in this process, which considers contact and friction; can handle large deformations and is therefore suitable to carry out buckling analysis. The top hole structural robustness is analyzed using this engine in the event of a worst case axial load, which for this study is assumed to be:The Conductor Pipe (CP) able to take its own weight only,The upper section of the surface casing (inside the CP) free of cement,The full buoyant weight of the Horizontal Christmas tree and Subsea Blowout Preventer applied onto the well. This paper demonstrates that the selected numerical model is suitable to estimate critical buckling loads and identify post-buckled modes exerted on surface structural casings. Furthermore, it is shown that the visualization capabilities and speed of the engine allow the operator to optimize the design iteratively in an efficient manner. We conclude that the selected methodology is suitable for the operator to validate a slim well design for a Deepwater development application at concept phase for minimal cost with the necessary level of confidence.

In the Dutch sector of the North Sea the Ommelanden Chalk formation commonly contains large amounts of chert, a very hard nodular rock. High friction exacerbates the harsh drilling conditions leading to mechanical dysfunction of the drilling process: severe downhole shocks, large torsional vibrations, bit and bottom hole assembly (BHA) wear and loss of directional steerability. Acceptance of these drilling conditions have long prevented drilling teams in the Netherlands to make significant drilling performance improvements. This case study shows a step-by-step optimization approach, where we evaluated various drilling systems and their interdependence at each step. Separately optimizing the individual drilling sub-systems: bit, BHA, fluids and the rig led to little overall improvements. The initial focus was on the bit and drive system, but their successful utilization was limited by the harsh drilling environment. Close examination and various attempts proved that a combination of non-aqueous based mud (NABM), lubricant and a rotary drive control system could deliver a stable drilling environment. This allowed us to select different bits and drive systems. After multiple attempts with new technology PDC bits we proved drilling the entire chalk interval in one run was possible. In addition, rotary steerable systems (RSS) enabled directional steering in any part of the 12 ¼-in section. The improvements led to fewer bit runs. The average progress rate through this section has been increased from 100 m/day to 300 m/day, with estimated savings of 10 to 15 rig days per well. In addition, the downside risk of equipment damage, inability to maintain trajectory control and related cost has been reduced significantly. Pursuing drilling optimization can take considerable time and effort. It is often not a single-step process, but requires a multidisciplinary approach. This case study demonstrates important process improvements and technology applications, which reduced operating risk and cost.