Accurate knowledge of drilling fluid behavior under actual conditions is required to maximize operational efficiency and to minimize cost and drilling fluid related risks on extreme high-pressure / high-temperature (HP/HT) wells.
This paper identifies and discusses the major HP/HT drilling fluid challenges, recent innovations in fluid viscosity measurements under HP/HT conditions, drilling fluid designs stable to extreme HP/HT conditions, and other considerations in HP/HT drilling.
Worldwide demand for energy continues to increase and is projected to average 2.0% per year out to 2030. Demand is widespread geographically but the most rapid growth is projected for nations outside the Organization for Economic Cooperation and Development (non-OECD nations) averaging 3.7% per year for non-OECD Asia.1 Providing adequate supply is driving the industry to explore areas previously unexplored, or minimally explored. A subset of this activity is HP/HT drilling. HP/HT drilling is not rigorously pursued during times of price uncertainty or low commodity pricing due to the relatively high lifting cost. The resurgence in HP/HT drilling stretches globally and encompasses areas such as the deep Gulf of Mexico Continental Shelf, northern India, Saudi Arabia, and Brunei. Historical HP/HT basins such as Indonesia, Thailand and northern Malaysia have also seen a selective increase in HP/HT activity.
Several factors have combined to make deep gas increasingly attractive worldwide:
Abundant infrastructure in the way of platforms, producing facilities, and pipelines that would allow new production to flow quickly to market.
New technology such as 3D seismic and faster computers to locate potential formations.
Developing HP/HT prospects can require overcoming some formidable drilling challenges. Rigs capable of HP/HT drilling are larger due to requirements such as hook load, mud pumps, drill pipe and surface mud capacity to name a few. Due to these requirements, these rigs are more expensive. HP/HT wells, by definition, require a higher density fluid which typically requires high solids loading. High solids loading, the resulting higher pressures, combined with the competency of rock at depth, lead to low penetration rates, extending time on location and added drilling costs. In extreme cases, pressure, temperature, and acid gas levels can limit the selection and function of down-hole tools and fluid selection. These limitations can be so severe that MWD/LWD tools become unusable, rendering down-hole annular pressure measurements used for pressure management, unavailable. This places additional demands on the drilling fluid and temperature/hydraulic models as they become our best, if not our only source for down-hole pressure information. These models are based on surface inputs and laboratory measured fluid properties under down-hole conditions. During the planning stage for several potential record depth deep gas wells currently drilling or recently TD'd, not only did this information not exist, laboratory equipment capable of operation at the required temperatures and pressures didn't exist.
Down-hole pressures are commonly calculated using TVD (true vertical depth) and surface measured mud weight reported from the rig. While this approach is adequate for less demanding wells, critical applications such as HP/HT and deepwater wells require adjustments for the pressure and temperature driven compression and expansion characteristics of the whole drilling fluid. These compression and expansion effects are quantified in fluid PVT measurement under expected down-hole conditions which, until recently, ranged from 15 psi/75°F to about 20,000 psi/350°F which covered industry needs. HP/HT drilling pressures and temperatures, however, can far exceed this envelope. Figure 1 illustrates isobaric PVT results on a commonly used base-fluid.