Managed pressure drilling is a process that utilizes friction pressure and annular back-pressure in addition to conventional hydrostatic column pressure to allow drilling of difficult formations. There are many parameters that play a part in the managing of wellbore pressure during fluid flow. Wellbore pressures are impacted by fluid density and rheologic properties, injection rates, cuttings transport, influx while drilling, wellhead or choke pressure, hole geometry and drillstring configuration. The effects of these parameters on wellbore pressure are different, but interact with one another. Therefore, careful consideration is needed when choosing which parameter(s) should be adjusted to manage the wellbore pressure during any particular operation.
A good understanding of the effects of these operating parameters on wellbore pressure is essential in the optimum design of an MPD project. This is especially true of the rheologic properties of MPD fluids. Rheologic properties of drilling fluids play important roles in the variation of wellbore pressure during any MPD operation. Most drilling fluids (WBM, SBM, or OBM) currently used in the field have a nonzero yield point (YP). A non-zero YP causes a sudden bottom hole pressure (BHP) jump when fluid starts to move or when fluid is about to stop moving. It also causes a sudden BHP jump when the drillstring starts to move up or down during tripping or connections regardless of how slow the pipe moves. The sudden pressure jump makes it difficult to minimize BHP variations.
This paper discusses the effects of various operating parameters on wellbore pressure and provides guidelines for managing wellbore pressure by adjusting those operating parameters. A simple equation to predict the sudden pressure jump caused by YP is provided. Field cases are used to illustrate managing wellbore pressure by adjusting various operating parameters.
When preparing for MPD, careful consideration is required to choose the parameters that can be controlled to ensure those parameters that make the biggest difference are selected for control. Whether drilling or designing the MPD application, the interaction between all controllable parameters must be kept in mind during the process.
To better understand how the controllable parameters interact with one another, a typical offshore well will be used as an example (Figure 1). This well is located in approximately 5,900 ft of water. The wellbore interval used for illustration is the 8–1/2 in wellbore drilled directionally below 9–5/8 in casing from 9,300 ft MD to total depth of 15,775 ft MD (10,920 ft TVD.)
Often parameters that might otherwise be controllable are dictated or fixed prior to the realization that MPD will be required to enable the prospect to be drilled.
The prime example of such a parameter is the operating pressure window, which is not commonly considered a controllable parameter. The window itself is defined by a lower limit, which may be either pore pressure or wellbore stability (collapse) pressure and an upper limit, which in the case of most MPD is defined by the fracture gradient exposed to the wellbore.
Figure 2 shows the pressure window for the example wellbore. The upper limit, designated as fracture pressure in the figure, is simply sea water gradient down to the mud line. Below that point the upper limit of allowable pressure in the wellbore is the actual fracture gradient, while the lower limit is the pore pressure. The casing seat indicated at approximately 9,300 ft in the figure serves to isolate a narrow pressure operating window above that point from a wider window below that point.