Introduction Drillers must, as far as possible, avoid kicks, wellbore instability, and loss of circulation through fractures, usually by selecting an appropriate mud weight. Knowledge of formation pore pressure and fracture gradient is essential for selection of a safe range of mud weights. If the mud pressure (mud weight times the vertical depth) falls below the local pore pressure in a highly permeable formation, then a kick is taken; if this happens in a soft but essentially impermeable formation, the well may collapse. This consideration provides a lower limit on mud weight in terms of safety, although in many cases drillers will drill underbalanced to increase rate of penetration (ROP). If the mud pressure exceeds the local tensile breakdown pressure for the formation (fracture gradient times vertical depth), a fracture is formed. With loss of circulation, the fracture propagates if the mud pressure exceeds the minimum horizontal earth stress (more accurately, the least principal stress). This provides an upper limit on mud weight. Normally, the horizontal stresses are significantly larger than the pore pressure, so a suitable safe range of mud weight usually can be found, even though potential shear failure of the wellbore provides other constraints on mud weight, especially in highly deviated wells. Clearly, abnormally high pore pressures or weak formations present potential problems for drillers. Abnormally high or low earth stresses also can lead to unexpected difficulties. Pore Pressure In normal situations, pore fluids are assumed to be in hydrostatic equilibrium all the way from the surface to the depth attained. Apart from some uncertainty in pore-fluid density, this provides a simple prediction of the pore pressure (i.e., for a water density of 9 Ibm/gal, the gradient will be 0.47 psi/ft) that will always lie below a realistic mud pressure gradient, because the mud will be more dense than water. In abnormal situations, however, pore fluids will not be in equilibrium hydrostatic contact with the surface, such as when a caprock provides a totally impermeable barrier isolating fluids beneath it or when relatively impermeable sedimentary rocks have not reached pore-pressure equilibrium. In such cases, pore pressures often are abnormally high and can exceed what otherwise are safe mud pressures. Drillers need warning of this situation. On what can they base their estimates of pore pressure? Clearly, periodic direct measurements are desirable. These measurements are possible in sufficiently permeable formations where a wireline tool (e.g., a Formation TesterSM tool) can be placed in hydrostatic contact with the formation pore fluid long enough to reach pressure equilibrium. Well-testing techniques can be used to interpret the pressure transients sensed before full pressure equilibrium is reached, thereby speeding up the testing process. However, this technique. is not carried out during drilling. It clearly lacks accuracy in low-permeability formations, especially when the pore fluid is multiphase. Additional direct information is provided when minor kicks are taken, particularly during tripping into or out of the hole. The formation pore pressure is roughly equal to the pressure of the mud adjacent to the formation from which the kick was taken (although deciding where this occurred takes some care). Strictly speaking, this provides only a lower bound on the pore pressure; in certain tight gas sands, for example, large overpressures can be sustained during drilling. The mud weight used to kill a kick may be several pounds per gallon greater than the pore pressure, and so using this system as a measure may result in a significant overestimation of pore pressure. More generally, the driller can use experience with what leads to overpressuring and indicators of its occurrence. These indicators are lithology-dependent and often are based on formation physical behavior (sonic, nuclear, electrical) measured by wireline logs. See Refs. 1 through 3 for discussions of overpressure and its causes: undercompaction, dehydration of gypsum, clay diagenesis or osmosis, gas generation, aquathermal expansion, or tectonic stresses.
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Feb 1, 1999
Hélène Massol + 1
Open Access