TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractWells drilled in the Tuscaloosa Trend located near Baton Rouge have long been recognized for the extreme nature of the High-Pressure / High-Temperature (HP/HT) operating environment and potential for well control problems 1 . The current focal point, however concerns drilling the highly abrasive formations contained within the intermediate and drilling liner sections to depths of ± 20,000-ft. These sections have been a major cause of bit, directional tool and drill string failures. The directional complexity of the wells has increased exponentially in recent years due to surface location constraints and reservoir compartmentalization. New drills are therefore primarily directional in order to penetrate multiple stacked targets, fault-out depletion; which would otherwise result in drilling differentials in excess of 13,000 pounds per square inch (psi) and adhere to regulatory constraints imposed upon building surface locations in certain areas.Directional control in the intermediate hole section is challenging as it requires drilling through the abrasive and damaging Wilcox formation and still risks the wellbore drifting out of the target. However, below the intermediate section we encounter significant directional tool constraints as in situ temperatures range from 300-ºF to 400-ºF. Poor directional response, low penetration rates as well as increased motor failures due to stator deterioration have traditionally resulted in long and costly sections. The impact of conducting directional operations in the intermediate or drilling liner hole sections has resulted in an incremental spend of up to $3.0-MM on some wells and a 30-day to 45-day delay in first production.This paper focuses on the improvements which have been achieved over a 5-year period due to the implementation of Powered Rotary Steerable Systems (PRSS) coupled with Rotary Steerable Bit Technology. The step-change in performance has been evidenced by reduction in days per 10,000-ft (D/10K) drilled from 86-D/10K to 55-D/10K. The improved time to first production has been attributed to the systematic learning and the successes of several office based, well site and third party teams.

Objectives/Scope The bottom hole circulating temperature of horizontal wells can be higher than those of vertical wells. That risk is compounded in HPHT slim-hole applications where static geothermal temp can reach 320°-350° F. The combination of horizontal wellbore geometry, HPHT conditions, and slim-hole design results in significant challenges to achieving the primary objectives of drilling and data acquisition. This paper describes a technical workflow established through collaboration between the operator and service providers to manage high temperature risks to ALARP (As Low As Reasonably Possible) with effective design optimizations. Methods, Procedures, Process The workflow consists of risk assessment, offset data analysis, HT (high temperature) model calibration, model-based sensitivity analysis, and design optimization on BHA, hole size, and parameters. Multiple modelling software are used to support this physics-based design approach. Results, Observations, Conclusions The established workflow identified a set of effective risk mitigations through bottom hole assembly (BHA) redesign, hole size change, drilling parameter adjustment, and a decision-based TD criterion. The previously identified HT risks are reduced to ALARP and can be managed during execution. Novel/Additive Information The target well will be the first horizontal HPHT deepwater well to be drilled in GOM deepwater. The workflow described in this paper can help reinforce the physics-based design optimizations, and avoid HT related damages to critical downhole tools with limited supply and long replacement lead times due to current market constraints.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractWells drilled in the Tuscaloosa Trend located near Baton Rouge have long been recognized for the extreme nature of the High-Pressure / High-Temperature (HP/HT) operating environment and potential for well control problems 1 . The current focal point, however concerns drilling the highly abrasive formations contained within the intermediate and drilling liner sections to depths of ± 20,000-ft. These sections have been a major cause of bit, directional tool and drill string failures. The directional complexity of the wells has increased exponentially in recent years due to surface location constraints and reservoir compartmentalization. New drills are therefore primarily directional in order to penetrate multiple stacked targets, fault-out depletion; which would otherwise result in drilling differentials in excess of 13,000 pounds per square inch (psi) and adhere to regulatory constraints imposed upon building surface locations in certain areas.Directional control in the intermediate hole section is challenging as it requires drilling through the abrasive and damaging Wilcox formation and still risks the wellbore drifting out of the target. However, below the intermediate section we encounter significant directional tool constraints as in situ temperatures range from 300-ºF to 400-ºF. Poor directional response, low penetration rates as well as increased motor failures due to stator deterioration have traditionally resulted in long and costly sections. The impact of conducting directional operations in the intermediate or drilling liner hole sections has resulted in an incremental spend of up to $3.0-MM on some wells and a 30-day to 45-day delay in first production.This paper focuses on the improvements which have been achieved over a 5-year period due to the implementation of Powered Rotary Steerable Systems (PRSS) coupled with Rotary Steerable Bit Technology. The step-change in performance has been evidenced by reduction in days per 10,000-ft (D/10K) drilled from 86-D/10K to 55-D/10K. The improved time to first production has been attributed to the systematic learning and the successes of several office based, well site and third party teams.