Abstract
The subject High Pressure High Temperature (HPHT) well proved extremely challenging with reservoir BHT of 334°F and approximate 13, 900 psi reservoir pressure. Managed Pressure Drilling (MPD) was originally selected to avoid a classic "Kick-Loss-Kick" scenario while drilling deep Austin Chalk formation wells in East Texas. While a secondary goal of MPD ("to ascertain the downhole pressure environment limits") was accomplished, the greatest benefit of MPD was seen while handling several well control incidents that occurred in the HPHT reservoir section. Optimal control of these incidents was facilitated by modification to the MPD technique and reconfiguration of the BOPE to allow for more appropriate application of the MPD equipment.
During drilling, a combination of high temperature and fluid properties (drilling fluid and reservoir fluid) resulted in repeated failures of the annular preventer and at least one variable bore ram (VBR) element failure at low pressure relative to the equipment rating. Ultimate integration of BOPE and MPD equipment allowed drilling with MW at or near balance to reservoir pressure.
Following and during trips, allowance had to be made for mud property changes caused by heating or cooling effects at both the surface and downhole. The mud property changes affected Equivalent Circulating Density (ECD) while drilling and tripping. Mud monitoring proved critical.
As HPHT and drilling technology mature, the line between flow control and well control begins to blur. Rather than transitioning from one to the other and back, the drilling and well control activities tend to become parts of a single process. This process, as described in the paper, must take into account the effect of variations in drilling fluid properties. Knowledge of the exposure limitations to pressure, temperature and other parameters and the effects on composition of pressure sealing elements in all surface and downhole tools is critical. The operator must also account for the effect of HPHT on specialty equipment such as RCDs, extra choke manifolds or manifold elements, and additional monitors. Adjustments in utilization and acquisition of slow pump rate information, use of the entire active pit system while circulating out kicks, and handling uncertainties in the downhole pressure regime are also part of this process. How alternative casing design affects well control while circulating a kick (influx) and using other unconventional drilling techniques will also be described.
