Summary Typical shale well completions involve massive, multistage fracturing in horizontal wells. Aggressive trajectories (with up to 20°/ 100 ft doglegs), multistage high-rate fracturing (up to 20 stages, 100 bbl/min), and increasing temperature and pressure of shale reservoirs result in large thermal and bending stresses that are critical in the design of production casing. In addition, when cement voids are present and the production casing is not restrained during fracturing, thermal effects can result in magnified load conditions. The resulting loads can be well in excess of those deemed allowable by regular casing design techniques. These loads are often ignored in standard well design, exposing casing to the risk of failure during multistage fracturing. In this work, the major factors influencing normal and special loads on production casing in shale wells are discussed. A method for optimization of shale well production casing design is then introduced. The constraints on the applicability of different design options are discussed. Load-magnification effects of cement voids are described, and a method for their evaluation is developed. Thermal effects during cooling are shown to create both bending stress magnification and annular pressure reduction caused by fluid contraction in trapped cement voids. This can result in significant loads and new modes of failure that must be considered in design. The performance of connections under these loads is also discussed. Examples are provided to illustrate the key concepts described. Finally, acceptable design options for shale well production casing are discussed. The results presented here are expected to improve the reliability of shale well designs. They provide operators with insight into load effects that must be considered in the design of production casing for such wells. By understanding the causes and magnitude of load-augmentation effects, operators can manage their design and practices to ensure well integrity.

A new approach to drilling and completing long horizontal open-hole gravel packed intervals in a subsea West African Field development using oil-based drilling fluid throughout the well trajectory has resulted in significant cost savings and increased well productivity. Without this successful change and the use of horizontal wells, many of the subsea wells drilled in 50'- 2200' of water would have been uneconomical. Previously, the upper, non-pay portions of the subsea wells were drilled with oil-based drilling fluids while the horizontal reservoir sections were drilled with a sized calcium carbonate-polymer drill-in fluid. To remove filter cake damage following gravel packing, acidization of the entire horizontal interval was required. Operations associated with changing the drill-in fluid and acidizing added significant cost and complexity to well completions. In addition to higher completion costs, the water-based drill-in fluid reduced drilling flexibility in the target channel sands resulting in more sidetracks and in some cases less than optimal completed intervals. It was recognized that continued use of oil-based fluids through the reservoir section would overcome these limitations, however, the damage potential of using oil-based drilling fluids prior to gravel packing was unknown. This paper presents the development, application, and results of the new drilling and completion practice for horizontal, gravel-packed, oil wells offshore West Africa. Large and small scale laboratory testing will be described, including formation damage core testing, development of displacement and cleanup procedures and fluid compatibility. Integration of technical advisors, laboratory personnel, and field operations led to rapid implementation of the new technologies. A pilot hole test was conducted in the field followed by successful application in three wells. The new procedures have resulted in improved drilling, considerable cost savings, and observed PI's 2–3 times higher than similar wells using water-based drill-in fluids. Introduction Initial wells developed in the field were vertical with cased-hole gravel packs. To improve well productivity, well completions were changed to open-hole highly deviated and/or horizontal well trajectories.1 At the beginning of the open-hole completion program, the wells were drilled with oil-based fluid to the top of the pay interval. The horizontal section was then drilled with a water-based drill-in fluid and gravel packed with a water-based carrier fluid. Previous laboratory tests showed that the drill-in fluid, weighted with acid soluble CaCO3, created a relatively thick filter cake and "fluff" on the formation wall. During simulated gravel pack operations, the thick cake remained attached to the formation and became embedded between the gravel pack sand and the formation. Laboratory testing showed that direct sustained contact with HCl was required; however, others have seen that acidizing was not required with this type of drill-in fluid.2,3 In field operations, acidizing with HCl was required to remove the filter cake and reduce damage. 1 Comparison of cased-hole vertical and horizontal open-hole well productivity indicated significant improvement, but in some cases, the residual damage was severe enough to offset the productivity gains of the longer horizontal pay intervals. One reason for the limited success was the difficulty in achieving uniform acid contact through long horizontal gravel pack completions.