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The most important mechanical properties of casing and tubing are burst strength, collapse resistance and tensile strength. These properties are necessary to determine the strength of the pipe and to design a casing string. If casing is subjected to internal pressure higher than external, it is said that casing is exposed to burst pressure loading. Burst pressure loading conditions occur during well control operations, casing pressure integrity tests, pumping operations, and production operations. The MIYP of the pipe body is determined by the internal yield pressure formula found in API Bull. This equation, commonly known as the Barlow equation, calculates the internal pressure at which the tangential (or hoop) stress at the inner wall of the pipe reaches the yield strength (YS) of the material.
Remedial cementing is undertaken to correct issues with the primary cement job of a well. Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs have the potential to force poor decisions and high risk. Good planning and risk assessment is the key to successful remedial cementing. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics.
Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs force poor decisions and high risk. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine (1) if a problem exists, (2) the magnitude of the problem, (3) if squeeze cementing will correct it, (4) the risk factors present, and (5) if economics will support it. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics. Squeeze cementing is a dehydration process.
Introduction The three primary functions of a drilling fluid--the transport of cuttings out of the wellbore, prevention of fluid influx, and the maintenance of wellbore stability--depend on the flow of drilling fluids and the pressures associated with that flow. For example, if the wellbore pressure exceeds the fracture pressure, fluids will be lost to the formation. If the wellbore pressure falls below the pore pressure, fluids will flow into the wellbore, perhaps causing a blowout. It is clear that accurate wellbore pressure prediction is necessary. To properly engineer a drilling fluid system, it is necessary to be able to predict pressures and flows of fluids in the wellbore. The purpose of this chapter is to describe in detail the calculations necessary to predict the flow performance of various drilling fluids for the variety of operations used in drilling and completing a well. Overview Drilling fluids range from relatively incompressible fluids, such as water and brines, to ...
During drilling operations, a pipe is considered stuck if it cannot be freed from the hole without damaging the pipe, and without exceeding the drilling rig's maximum allowed hook load. Pipe sticking can be classified under two categories: differential pressure pipe sticking and mechanical pipe sticking. Complications related to stuck pipe can account for nearly half of total well cost, making stuck pipe one of the most expensive problems that can occur during a drilling operation. Stuck pipe often is associated with well-control and lost-circulation events--the two other costly disruptions to drilling operations--and is a significant risk in high-angle and horizontal wells. Drilling through depleted zones, where the pressure in the annulus exceeds that in the formation, might cause the drillstring to be pulled against the wall and embedded in the filter cake deposited there (Figure 1).
The causes of mechanical pipe sticking are inadequate removal of drilled cuttings from the annulus; borehole instabilities, such as hole caving, sloughing, or collapse; plastic shale or salt sections squeezing (creeping); and key seating. Excessive drilled-cuttings accumulation in the annular space caused by improper cleaning of the hole can cause mechanical pipe sticking, particularly in directional-well drilling. The settling of a large amount of suspended cuttings to the bottom when the pump is shut down, or the downward sliding of a stationary-formed cuttings bed on the low side of a directional well can pack a bottomhole assembly (BHA), which causes pipe sticking. In directional-well drilling, a stationary cuttings bed may form on the low side of the borehole (see Figure 1). If this condition exists while tripping out, it is very likely that pipe sticking will occur.
During drilling operations, a pipe is considered stuck if it cannot be freed and pulled out of the hole without damaging the pipe and without exceeding the drilling rig ' s maximum allowed hook load. Differential pressure pipe sticking and mechanical pipe sticking are addressed in this section. If sticking does occur, common field practices for freeing the stuck pipe include mud-hydrostatic-pressure reduction in the annulus, oil spotting around the stuck portion of the drillstring, and washing over the stuck pipe. Some of the methods used to reduce the hydrostatic pressure in the annulus include reducing mud weight by dilution, reducing mud weight by gasifying with nitrogen, and placing a packer in the hole above the stuck point. Figure 1.2--Mechanical pipe sticking caused by drilled cuttings: (a) cuttings bed during drilling, and (b) cuttings jamming the drill bit during tripping out. Figure 1.3--Pipe sticking caused by wellbore instability.
All drilling challenges relate to the fundamental objective of maintaining a workable wellbore throughout the well-construction process. A workable wellbore can be drilled, logged, cased, cemented, and completed with minimal nonproductive time. The design of the drilling-fluid system is central to achieving this objective. With a poorly designed system there are some challenges that will occur. Most operational problems are interrelated, making them more difficult to resolve.
Wang, Xindong (CNPC Xibu Drilling Engineering Company Ltd) | Ke, Xue (CNPC Xibu Drilling Engineering Company Ltd) | Zhang, Shuxia (CNPC Xibu Drilling Engineering Company Ltd) | Zhang, Cheng (CNPC Xibu Drilling Engineering Company Ltd) | Li, Hui (CNPC Xibu Drilling Engineering Company Ltd) | Li, Pengfei (CNPC Xibu Drilling Engineering Company Ltd) | Li, Zhenchuan (CNPC Xibu Drilling Engineering Company Ltd) | Huang, Xingning (CNPC Xibu Drilling Engineering Company Ltd, formerly)
Abstract Drilling operations is risky due to narrow mud weight windows in deep wells. Different type of drilling events and wellbore instability have encountered frequently including inflow, drilling induced tensile fractures (DITF), losses and connection gas etc. As such to mitigate the problems, a robust pore pressure prediction is necessary with requires an understanding of the origins and distribution of overpressures in the area. The technical research process is divided into three steps: pre-drill pore pressure predication (PPP) modelling, real-time monitoring and post-drill validation. Efforts were made to understand the geological settings and temperature model. A pore pressure predication (PPP) model was built by integrating fully coupled geomechanical with thermodynamics modeling. Real-time monitoring information provides references and guidelines for PPP model optimization. During the post-drill stage, the updated PPP model was used to design a mud weight and casing program for the upcoming wells. The study area is located northwestern China, the deep formations that more than 7000 meters are ultra-high temperature (200-220 deg C). Thermal-related secondary pore pressure generating mechanism may become active leading to higher overpressure and difficulties in prediction. For the case study, an empirical relationship of overpressure impact factors versus temperature of sandstone and mudstone was proposed. An accurate PPP model is generated using available well-scale geomechanical model and overpressure impact factors. With an integrating fully coupled PPP model as foundation, the integrated approach helps to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems deep wells. A1 well was safely drilled guided by the study result and has no significant wellbore instability issues and has minimum reservoir damage due to optimal mud weight program. These findings will provide reference for overpressure mechanics study of deep wells. The multidisciplinary study results have created value by improving drilling performance and well delivery efficiency. It can also help operator reduce drilling costs and make development plan decisions.