Samaria field in southern Mexico is one of the oldest light oil producers. Reservoir pressures can be classified as highly depleted in cretaceous, the use of nitrogen injection thru the drill pipe to lighten the mud column is a common practice to reach low equivalent circulating densities and avoid massive loss circulation and related hole cleaning problems. Large amounts of nitrogen injection rates are also a common scenario in this specific field many times reaching the technical limit of a multiphase Managed Pressure Drilling application avoiding the friction dominated side of pressure curves. Natural tendency to achieve more production is to drill horizontal wells as demonstrated by the production results of a number of attempts made in the past. However, the presence of high N2 injection rates thru the drill pipe represents a serious challenge for measuring and logging while drilling pulse type downhole tools frustrating the possibility of achieving a full directional control in the reservoir section. Dowhole temperatures are also higher than conventional drilling because of the presence of high gas vs liquid ratios, reaching very fast the technology limits. This document presents the engineering process, planning and design for the drilling with concentric casing nitrogen injection technique in a horizontal well with directional control in real time, into a low pressure reservoir. The technique allowed building up and correcting the well trajectory successfully reaching the proposed targets. (Horizontal length, Drain Area) The steady stable and transient simulations to validate stabilization are also presented along with the final results in terms of production and skin damage. Introduction The well presented in this document belongs to the Bermudez Complex (Samaria Field) located in the south the Mexico as shown in Figure 1. The reservoir is formed by carbonates and dolomites from upper, Medium and Lower Cretaceous at vertical depths ranging between 4200 m - 4500 m. The original reservoir pressure was originally equivalent to 1,3 gr/cc (7500 psi), however because of the production rates and exploitation time, today's formation pressure is around 2200 psi (0,4 gr/cc), about 30 % of the original pressure. Because of the actual low reservoir pressure and typical problems associated with it (loss circulation, Differential sticking). The near balance technique using multiphase fluids (nitrified) was implemented. This technique was the right solution but was limited to vertical and low angle wells, mainly because high nitrogen volumes attenuate the MWD telemetry through Drill pipe, therefore neither tool face nor formation evaluation data, can be obtained while drilling in order to steer within reservoir. The high Gas/Liquid Ratio used with large amounts of the N2 injected to avoid mud looses, caused the annular temperature around directional tools to increase rapidly, above 150 C, as friction increases with the drill pipe rotation, generation electronic failures. Additionally N2 gas penetrates the motor stator eleastomer at certain temperature and pressure conditions causing dohwnhole motor elastomers failures. These limitations condemned most of the high angle wells to be drilled "blind" with conventional assemblies where neither directional control nor formation evaluation data was delivered in real time or memory format. This situation was of course a huge technical limitation for the operator which requires both service on this field and ones that have similar environments to increase production rates. Wired Drill pipe Technology was tested in a similar field, however very low N2 volume were injected compared to ones that are currently used in the Samaria field. During the well execution several tool failures were reported in wired rotary steerable systems, mostly associated to high temperatures.

Different oil operators have faced technical and economic challenges while drilling in Neuquén basin. Drilling in a tectonic active setting creates problems ranging from influxes and stuck pipe incidents to circulation losses. The presence of natural fractures with an abnormally high pore pressure environment in Quintuco formation increases the gas kicks risks during drilling. Drilling nearby wells has evidenced many severe events, like many days to control a hydrocarbon influx with simultaneous losses. Stuck pipe is the responsible for lost BHAs and considerable NPT spent on freeing the pipe, performing additional wiper trips and hole cleaning. Minimizing non-productive time associated with wellbore instability reduces the risk of dangerous accidents at the wellbore site and it is required to complete the well on time and within the budget. This article describes a methodology to reduce drilling risks, in complex pore pressure conditions at Quintuco formation in Neuquén Basin. The proposed method is based on two main assumptions: the 3D pore pressure characterization based on elastic wave velocities on two different levels in Quintuco formation; and the intensity of the influx events is characterized by the presence of fracture corridors. The value added by the integrated team's efforts was demonstrated by drilling the next two wells with significant reductions in costs and nonproductive time.

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractIn high profile applications, an advanced drillstring dynamics modeling system has been used to mitigate downhole vibrations and improve penetration rates (ROP). The capability of virtually drilling a well with computer software allows the engineer to identify the root causes of damaging vibrations and ROP limiters before drilling commences. Consequently, the conventional trial-and-error methodology can be replaced by a cost-effective optimization process. This technology provides an efficient platform to optimize the total drilling system including bit selection, bottom-hole-assembly (BHA) design, operating parameters and the placement of individual BHA components. The utilization of this software has delivered significant economic benefits associated with increased total footage, higher ROP and fewer downhole tool failures. Offset well data are used to calibrate the simulation for each application including:Physical characteristics of the drillstring, BHA and drill bit Operating parameters, weight-on-bit (WOB) and revolutions per minute (RPM) Rock properties; in some cases, core samples from an offset well are tested Well trajectory and hole diameter from directional surveys and caliper logsThe authors believe this technology has the potential to be a central optimization platform for a broad range of worldwide drilling applications.

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