The wells in the Tuscaloosa trend in South Louisiana are high-pressure high-temperature (HPHT) wells reaching as deep as ±23,000 ft, with a bottomhole static temperature (BHST) as high as ±400°F. In the past these wells were completed using conventional cementing techniques. In some cases, soon after the wells were put on production, the intermediate casing annulus would show an increase in pressure. Historically, this pressure is manageable and can be easily reduced through current procedures and practices. However, a project was undertaken to understand the underlying cause and then subsequently deploy a solution to prevent pressure on the annulus side. The first task was to make sure that the annulus pressure was not caused by other problems such as wellbore stability, hole cleaning, and cement slurry placement. Then the next possible cause was damage to the cement sheath during subsequent well operations and production. A detailed study was done to investigate this possibility. Mechanical and thermal properties of the formation were derived from the log data and drilling data. Additionally, this data was evaluated to identify the depths and formations associated with significant gas shows at surface. Possible failure mechanisms in the previous conventional cement sheath were identified. The cement system was modified to prevent such failure and the new cement system was designed and tested. The modified cement system was deployed in the field in April 2006, and the well was put on production a few months later, and since then has been on line and producing without annular pressure problems. The techniques and solutions discussed in this paper can be applied to wells around the globe that have related problems. These solutions may help prevent annular pressure and improve the safety and economics of operating these wells. Introduction The cement sheath in the annulus is an important barrier that helps prevent formation fluid from entering the annulus and thus helps maintain well integrity. Well integrity could be compromised if the cement sheath is not able to withstand well operations and is damaged during the life of the well (Bosma et al. 1999; Fourmaintraux et al. 2005; Ravi et al 2002). This could result in tubular corrosion, interzonal communication, and annular pressure buildup and lead to an increase in operating costs and unsafe well conditions. In the worst case, the compromised well integrity may lead to casing collapse or a well blowout. There are compelling reasons to design and deliver a cement slurry that is placed in the entire annulus and to ensure that the cured cement sheath is not damaged during well operations. The general cementing practice in the industry has not considered the effect of well operations on the cement sheath during the life of the well. It is only recently, and only in a handful of wells the cement sheath integrity during well life has been considered as a design parameter. The results show that, in cases where the cement sheath integrity during well life is taken into account, there has been marked improvement in well performance. The operating cost of these wells has decreased while the long term integrity of the well leads to safer operating conditions (Heathman et al. 2006; Hunter et al. 2007; Moroni et al. 2008).

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.

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.