Summary Casing-integrity failure, whether through parted casing, leaky collars, or some other issue, may result in less-effective stimulation work caused by abandonment of the plug-and-perforate method and/or completing through a frac liner. In more-extreme cases, it could result in lost reserves below the casing-failure point. Modern technology has provided a cost-effective solution to this problem. In this case, the operator confirmed parted 4 1/2-in. production casing at 9,761 ft (Fig. 1) in their northern Piceance basin acreage. The operator would have to repair the parted casing to fracture the lower six zones of the well. The plug-and-perforate method for zonal isolation was required to effectively complete the 2,825-ft vertical pay interval. To complete the stimulation program, the goals were to repair the short section of damaged casing and restore pressure integrity to the well while maintaining a sufficient inner diameter (ID) to allow composite frac plugs to pass through the repair and set in the base casing's larger ID below the split. After a corrugated patch failed to provide casing integrity, the solution was a 3 1/2-in. single-joint solid-expandable system that was expanded downhole to cover and seal the parted 4 1/2-in. casing in conjunction with the use of custom-made composite frac plugs. The 30-ft, 3 1/2-in. solid-expandable high-pressure/high-temperature (HP/HT) liner system was deployed and expanded in a single trip. This system provided the required pressure integrity to withstand the fracturing pressures needed in this area. The 3.261-in. drift ID of the expanded-solid liner allowed the operator to run custom 3.06-in.-outer-diameter (OD) composite frac plugs below the repaired section and successfully complete the well. This installation was a success because the operator had essentially written off 63% of the well's reserves caused by the casing part occurring above a majority of the pay interval. The operator is now realizing full production from the entire well. Moreover, this single-joint solid-expandable liner technology coupled with the special drillable composite frac plugs can be used in any HP/HT formation to repair the common issue of damaged casing to allow plug-and-perforage completions to continue.

Summary The Cannonball field is a 1 Tcf gas/condensate development offshore Trinidad producing at a sustained rate in excess of 800 MMcf/D from three wells. The completion design selected was 7⅝- in. production tubing with an openhole gravel pack. The initial well (CAN01) has produced at 333 MMcf/D. These rates are higher than typically experienced, which has raised concerns about the resultant potential for metal erosion. As a result, a rigorous erosion study was initiated. The objective was to evaluate erosion quantitatively at various rates over the life cycle of the well to design the completion appropriately and select the appropriate materials. The erosion nodes within the completion—changes in flow direction (e.g., a tee such as in the wellhead) and/or flow constric- tions—were identified as the tree, a landing-nipple profile near the surface, and a formation-isolation device (FID) positioned in the gravel-pack assembly. The key parameters were defined as particles of sharp sand, with a diameter of 50 μm, at a concentration of 0.1 lbm/MMcf. Erosion rates were calculated using the erosion model, Sand Production Pipe Saver (SPPS), developed by the Erosion/Corrosion Research Center (E/CRC) at the University of Tulsa, USA. Erosion rates were calculated over the life cycle, starting at initial rates of 280 and 400 MMcf/D. Erosion rates were also calculated with and without a liquid film (a protective layer on the pipe wall that can reduce the erosion rate). Erosion results (without a liquid film) at all nodes exceeded BP's erosion limit; however, the erosion results with a thin liquid film were mostly below the company's erosion limit. Determination of the presence and thickness of the liquid film was critical. A multiphasepipeline simulation calculated that a sufficient liquid film would exist at all critical areas. Erosion of the tree was assessed further by computation-fluid-dynamics (CFD) models, which identified several hot spots; thus, additional cladding of all flow-wetted surfaces and rounding of the outlet corner was required. The Cannonball completion design, including the tree, was determined to be capable of sustained rates up to a maximum of 400 MMcf/D. The three-well development, where initial rates have been as high as 333 MMcf/D, has been on production for several years without any erosion issues.

Summary This paper presents a new analysis method for stress-concentration factor (SCF) in rotary-shouldered connections (RSCs). The proposed method uses finite-element analysis (FEA) as a primary tool to explore the maximum peak-stress behavior in RSCs and calculate SCF to evaluate the connection performance. Key findings include facts that the maximum peak stress and SCF value are functions of connector geometry and loading condition. The paper defines SCF in RSCs and provides a thorough discussion about the SCF-analysis method and its characteristics in evaluating drillstring-connection designs. The paper compares maximum peak-stress behaviors and SCF values among various RSC designs to demonstrate their role in selecting connections for drilling-, completion-, and intervention-riser applications. Introduction In recent years, drilling programs have become significantly more aggressive in both onshore and offshore operations. Harsh conditions in deepwater, extended-reach, and ultradeepwater drilling often place severe axial, lateral, torsional, and pressure loads on the drillstring and its connections. As a result, RSCs often experience exceptional elevated-stress conditions. In some cases, RSCs are being used for applications beyond conventional drilling, such as completion operations and riser intervention. Meanwhile, advanced RSC designs incorporate features such as multiple shoulders and metal-to-metal seal features, adding further complexity to the stress distribution in the connection design. The need to understand the connection-stress behavior fully, especially the maximum peak-stress behavior for the various applications, is critical for properly selecting and safely using the drillstring connections. (For a comparison of a premium casing connection and a proprietary RSC, see Fig. 1). SCF is a useful parameter in terms of evaluating the connection maximum peak stress in response to the operation loads. In the past, SCF has been employed to characterize design strength and fatigue performance of premium casing, tubing threads, and some riser threads under anticipated operation loads. However, this has been applied only to RSCs, mainly for two reasons:the traditional SCF-analysis method is not designed for RSCs with high makeup preload anda lack of standardization of the SCF-analysis method within the industry for RSCs. Because of increasing aggressiveness of drilling conditions and merging of new applications, SCF analysis to predict stress behavior becomes necessary. This paper presents a series of evaluations that will explore various aspects of SCF analysis to find a logical and conservative approach to evaluate the maximum peak-stress behavior in RSCs, in response to operation loads. This approach will help to better understand RSC-loading limit, stress distribution, and fatigue characteristics for various existing and new applications.