The North American Gulf Coast offshore continental basin was formed following the breakup of the super continent Pangaea at the end of the Permian period and contains one of the largest known deposits of salt in the world. The salt encountered in this region is relatively soft, with negligible porosity, and may deform under temperature and pressure. Drilling salt in different regions requires different drilling practices and challenges. Because of the variable range of salt properties and because of salt's effect on nonproductive time, to date there has been no substitute for experience for successful salt drilling.The petroleum industry is continually pushing to drill longer, faster, and safer sections; salt drilling is no exception to this philosophy. The dramatic advancements in salt drilling performance over the last decade-from the use of traditional drilling practices with rotary systems, mud motors, and possibly turbines-have been used to slightly improve penetration rates. The first Schlumberger push-the-bit rotary steerable salt drilling run in the USA Gulf of Mexico was executed in 2000. Since then more than 150 runs and almost half a million feet have been drilled in salt with this type of rotary steerable system. This paper summarizes the analysis of the Schlumberger push-the-bit rotary steerable runs in the North American Gulf of Mexico. The analysis confirms the successful drilling assembly design and drilling techniques to yield optimum salt drilling performance toward a benchmark for today's salt drilling environment.

fax 01-972-952-9435. AbstractDrilling operators worldwide face increasingly complex and costly drilling challenges. In addition to difficult and sometimes harsh downhole environments, the driller is also faced with a dramatic increase in the quantity and quality of information available to optimize recovery. In many of these situations, there is little or no room for error and the cost of nonproductive time (NPT) due to a poor or less informed decision can significantly increase the final cost per barrel to the consumer.Advances in cost-effective satellite communication and the application of compression technology have removed the bandwidth limitation, and Internet transfer of continuous highvolume real-time data between the offshore installation and shore-based operations is almost seamless.With the current shortage of skilled personnel, most major oil and gas companies are exploring remote Operation Support Centers to support their real-time E&P business processes. With a combination of infrastructure, technology, services and processes, these support centers are consolidating their expertise in a collaborative environment so that informed realtime decisions can be made to improve drilling processes and reduce costs.The economic justification to management and partners for investing and building support centers is clear, but it is necessary to scale the effort and capital expenditure for support centers to each specific drilling operation. This paper describes the concept of low-cost remote support centers that have been used successfully in the Gulf of Mexico, and land drilling projects on the Alaska North Slope and in northern Mexico.A successful support center must quickly turn real-time data into useful information displayed with minimum latency in a format benefiting decision makers. This depends on the skill and experience of each participating engineer and the quality of the software answer products in this surveillance environment. This paper describes advanced real-time software answer products that take raw drilling data and filter it into different rig states, automatically generating logical outputs.

As hydrocarbon basins mature, reservoir pressure depletion caused by hydrocarbon production leads to severe pore pressure/fracture gradient anomalies that can reduce an otherwise sufficient mud weight window significantly. At the same time, reentries involving slim-hole sidetracks incur high annular losses that further widen the gap between equivalent static and circulating densities - ESD and ECD. In this situation, it is not possible to drill using normal overbalanced methods. The risk of formation fracturing and fluid losses, fluid influxes, and wellbore collapse would far outweigh the reward of increased production. The effective variation of static and circulating densities must be minimized. A major project in the Gulf of Mexico posed such a problem. Managed pressure drilling (MPD) was adopted as the solution to manage a tight hydraulic window and effectively drill reservoirs which would have been extremely challenging using conventional drilling methods. Traditional directional drilling with a positive displacement motor would normally create more pressure balance complications under a MPD environment due to the continuous fluctuations to the ECD when the motor is in sliding or steering mode. This paper outlines how new generation rotary steerable systems coupled with the interpretation from a downhole real time pressure while drilling sensor was engineered to maximize drilling performance for a directionally drilled well in MPD environment. This paper will also discuss the case histories and lessons learned and thoroughly review the range of opportunities these technologies have created in the maturing areas of the Gulf of Mexico. Introduction Conventional drilling using either steerable systems or rotary steerable systems utilizes drilling fluids which are overbalanced to suspend the drilled cuttings, clean the hole and maintain wellbore stability. The drilling fluid as it is circulated down the hole also cools and provides energy to the bit required to break the rock and drill ahead but most importantly applies overbalance pressures which is a combination of hydrostatic pressure and annular friction pressure to prevent formation fluid influx into the formation. This is illustrated in Figure 1.

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