Developing HP/HT prospects can require overcoming some formidable drilling challenges. HP/HT wells require a higher density fluid, which typically requires high solids loading. High solids loading and 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

Figure 1. New Chandler 7600 viscometer meets design criteria of 40,000 psig/600°F and is capable of accurate measurements in fluids containing ferromagnetic material. (Photo courtesy of Baker Hughes Drilling Fluids)
cases, pressure, temperature and acid gas levels can limit the selection and function of downhole tools and fluid selection. These limitations can be so severe that MWD/LWD tools become unusable, rendering downhole annular pressure measurements used for pressure management, unavailable. This places additional demands on the drilling fluid and temperature/hydraulic models as they become the best — if not the only — source for downhole pressure information. These models are based on surface inputs and laboratory-measured fluid properties under downhole conditions. During the planning stage for several potential record-depth deep gas wells, not only did this information not exist, but also laboratory equipment capable of operation at the required temperatures and pressures didn’t exist.

Pressure/volume/temperature (PVT)
Downhole fluid pressures are commonly calculated using true vertical depth (TVD) 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 measurements under expected downhole conditions which, until recently, ranged from 15 psi/75°F (23.8°C) to about 20,000 psi/350°F (176.5°C). HP/HT drilling pressures and temperatures can far exceed this envelope, thus the behavior of fluids under extreme conditions was largely unknown. Recognizing this shortcoming, Baker Hughes Drilling Fluids extended PVT testing on a number of base oils to 500ºF (259.7°C) and 30,000 psi.

Temperature modeling
On an HP/HT well, the need to predict flow line temperature (FLT) and bottomhole circulating temperature (BHCT) are important for the planning process with regard to types of equipment necessary to drill the well. From a safety aspect the FLT needs to remain within the temperature limits of the blowout preventer (BOP), usually below 200°F. From a cost perspective the BHCT is important with regard to the downhole tools used for formation evaluation and geosteering and usually limited to about 350°F before heat damage occurs.
A temperature model should allow the user to input variables such as thermal conductivity and heat capacity of all the materials in contact with the drilling fluid. Other functionalities should include the modeling of mud coolers, mechanical heat sources, multiple lithologies with variable thermophysical properties and cooling effects from surface area of the active mud system.

HP/HT viscometer
With the depth horizons of HP/HT drilling expanding, a technology gap was recognized in the measurement of fluid viscosity at downhole conditions.

Historical viscometer technology is limited to measurements at 500°F/20,000 psig, insufficient for HP/HT wells under development that have bottomhole conditions approaching 550°F (287.5°C) and 30,000 psig. This was identified as a major technology gap, and fluid behavior had never been evaluated at these extreme conditions. So the service company set out to develop a new viscometer suitable for HP/HT drilling. Criteria for the new HP/HT viscometer included:
• Working pressure up to 40,000 psig;
• Working temperature up to 600°F (315°C) ; and
• A magnetic coupling design that allows accurate viscosity measurements on fluids containing magnetic materials (ferromagnetic and magneto-rheological fluids).

The service company began working on the development project with a partner engineering firm and after six months of design review meetings and fabrication a new HP/HT viscometer capable of testing fluids under extreme conditions was made available to the industry. Figure 1 shows this new viscometer, the Chandler 7600, which meets design criteria of 40,000 psig/600°F and is capable of accurate measurements in fluids containing ferromagnetic material.

Drilling fluid formulation
Invert emulsion fluids have been used for drilling HP/HT wells, and the technology is adequate for temperatures up to 500°F, but recent HP/HT activity presents even harsher environments. To meet the need for fluids with higher temperature stability, the service company set developed a line of products capable of withstanding extended exposure up to 600°F and engineered to withstand the extreme bottomhole temperature conditions of wells drilled beyond 25,000 ft (7,625 m) TVD.

Table 1 illustrates the generic name and functions of the specialty additives used in the formulation of HP/HT invert emulsion fluids. These systems can use either synthetic, low aromatic/low toxicity base fluids or diesel oil. The new additives perform well in these base fluids and are designed to be stable to temperatures in excess of 550ºF. The invert emulsion system can be weighted to densities above 19.5 lb/gal using barite or alternative weight materials, such as ilmenite, hematite or manganese tetraoxide.

Hydraulics modeling and well monitoring
As wells get deeper, temperatures increase beyond the thermal limits of downhole tool components, rendering the tools unusable. Yet adequate knowledge of downhole pressure is essential to adequately manage kicks, prevent lost circulation and stuck pipe and to reach deep reservoir targets safely. Accurate hydraulics software can provide the operator with some of these pressure-related parameters such as Equivalent Circulating Density (ECD), Equivalent Static Density (ESD), swab/surge pressures and overall system pressure losses for Stand Pipe Pressure (SPP) predictions. Accuracy of the model is dependent on the accuracy of the input variables and a sound theoretical approach.

Alternate weighting materials
HP/HT applications require special drilling fluids with low ECD and reduced sag tendencies to avoid downtime for mud conditioning and to prevent rigs from having to operate at or near hydraulic limits. Such fluids would also be less likely to result in downhole losses and the often considerable cost of lost circulation. New weighting materials that have higher specific gravity and/or finer particle size that address solids loading and sag problems are currently available.

Other considerations
Because trip time increases with depth, exposure of the drilling fluid to temperature and pressure under static conditions also increases. Staging into the hole after a trip not only helps minimize surge pressures but also helps normalize fluid temperature and density by circulation. Running to bottom and circulating cooler, denser fluid around can significantly increase the chances of fracturing the formation. The swabbing effect when tripping out also generally increases with depth, but has also been shown to occur when tripping in the hole, due to drillstring elasticity and oscillation. Hydraulic modeling can help optimize trip speed to prevent formation fracture or influx.

High flow line temperatures are also a concern with regard to rig crew safety and well control equipment elastomers. Mud coolers or chillers have made significant contributions to reducing mud temperatures while circulating. This temperature reduction also benefits downhole tools and temperature-sensitive mud products while reducing the possibility of the drilling fluid reaching its flash point at the surface. Mud coolers should be used prudently, however to prevent over-cooling the fluid and reducing formation fracture pressure.

Conclusion
Due to the inherent conditions of HP/HT wells, rigorous laboratory testing is necessary to generate detailed engineering guidelines for HP/HT drilling fluids. PVT behavior of the base fluid, rheological properties at extreme conditions, proper formulation of specialty products, temperature and pressure effects on hydraulic calculations, and alternate weighting materials are some of the more important considerations.

Effectively engineering and formulating a reliable HP/HT fluid system depends also on experience. Servicing previous HP/HT wells not only provides experience for fluid engineers but also offers valuable opportunities to field test new products, equipment, and validate modeling software under operating conditions.

EDITOR’S NOTE: This article is based on a paper presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, 13-15 November 2006.