Every activity within a well alters the pressure being exerted on the open hole, and every mitigation technique attempts to maintain the desired pressure within acceptable limits. If the pressure becomes too low, kicks, borehole breakouts, and hole collapse are the primary consequences (Fig. 1). Pressure that is too high can damage the reservoir, induce fluid losses, and slow down operations. When these unfortunate events occur, remedial actions are usually necessary, increasing safety exposure, nonproductive time, and the overall costs of the project.
To mitigate these concerns, operators have used the techniques of managed-pressure drilling (MPD) to maintain annular pressure and create a pressure-tight barrier against drilling hazards and manage inflow from the formation during drilling. While conventional drilling uses the hydrostatic pressure of the drilling mud to manage the pressure of the wellbore, MPD uses a combination of surface pressure, hydrostatic pressure, and annular friction to balance the exposed formation. Over the decades, MPD has been associated as a technology that is used only on problematic wells and only as a last resort. However, recent developments have highlighted that managing pressure is not just for drilling operations or just the most challenging wells.
When integrated at the beginning of operations as part of a comprehensive well plan, managing pressure becomes a performance-enhancing solution for any type of well classification, including development, directional, multilaterals, and horizontals. Wellbore stability is maintained throughout the entire operation and pressure is dynamically altered in the annulus, enabling any operation to become faster with fewer challenges while delivering a more productive well and reducing overall costs and exposure to hazardous risks. The managed-pressure approach has even been leveraged to fully optimize a field/reservoir development program.
An example of how MPD techniques can be incorporated into an overall well plan occurred on an ultradeepwater exploration well drilled by TotalEnergies in the Mexican waters of the Gulf of Mexico (SPE 200503). The operator and the service providers wanted to manage the pressure during the entire well program—including drilling, tripping, running casing, and cementing—to address pore pressure uncertainty, pressure ramp increase, and a narrow pore pressure/fracture gradient (PP/FG) window.
The seafloor rested under 10,748 ft (3276 m) of water, and with the exploratory nature of the well, the conventional solution involved an excessive number of casing strings and an overbalanced mud weight (MW). Integrating MPD techniques enabled the operator to adjust the bottomhole pressure instantaneously, the result being a recognition that conventionally cementing a string of 13⅜ -in. casing to isolate the critical formation and safely continue drilling further stages of the well was impractical. To make the situation even more challenging, the engineers did not precisely know the size of the hole.
A collaboration between the engineering teams of the operator, the cementing service provider, and MPD professionals resulted in a generated plan. A tail slurry of 15.86 ppg (1.90 SG) followed a 12.52 ppg (1.50 SG) lead gas-tight slurry. At a total depth of 13,622 ft (4152 m), the combination kept the equivalent circulating density (ECD) at 9.18 ppg (1.10 SG) without exceeding 9.51 ppg (1.14 SG). At the casing shoe, located at 12,801 ft (3902 m), the plan called for a 9.01 ppg (1.08 SG) without exceeding 9.35 ppg (1.12 SG), as shown in Fig. 2.