Hydraulic modeling is a fundamental piece of any Managed Pressure Drilling operation using multiphase gasified drilling fluids. MPD Engineers rely on hydraulic flow modeling systems to predict equivalent circulating densities. Models also allow designing and manipulating hydraulic parameters such as gas/liquid ratios, pressures and flow rates to achieve desired conditions. Therefore, the selection and calibration of the correct hydraulic model is critical for the success of any MPD Operation. The ECD calculation in an MPD operation is not the solely objective of using a complex modeling system. Today's downhole drilling tools technology makes available a variety of sensors capable of measuring actual downhole pressure values. Prediction of flow behavior is also an important step that will increase the ability of monitoring and keeping efficient hole cleaning, cutting transport and heat transfer efficiency, which are critical for all multiphase drilling operations. Actual measurement of downhole equivalent circulating density becomes now a critical new calibration value to compare hydraulic models performance and approximation to reality. This paper compares the two-phase hydraulic simulations results with the data gathered from a drillstring installed annular pressure sensor used while drilling a highly deviated well in a low pressure reservoir using nitrogen injection through concentric string technique in an MPD operation. This technique poses a series of new challenges for the MPD engineer that needs to predict hydraulic behavior created by the typical transient "U" tube effect caused by connections, trips and surveys in this kind of applications.The paper details the model and calibration process, findings and best practices gathered from multiple runs, real time transmission and high definition memory data. Actual results and conclusions and also discussed and analyzed in depth for the benefit of any further concentric job applications associated with use of downhole pressure sensors.

The oilfields in study are important assets for the National Oil Company and represent 14% of the total oil production of the country. Two wide different and drastically challenging scenarios can be found: HPHT wells with a narrow mud weight window; and highly depleted wells in fractured carbonates. In both cases, the cementing job in production casings is historically classified as very difficult as a direct consequence of high frictional pressure losses due to the small annulus and deep wells configuration which causes loss circulation problems. A close analysis of the offset wells identified the use of MPD as a possible partial solution to mitigate the usual loss circulation scenario.This document describes the successful implementation of the MPD technique as a supplemental aid for cementing jobs, eliminating cement losses, avoiding formation damage, reducing mud losses by also offering additional safety to this kind of operations. In the last two years MPD has been used in a number of cementing jobs in HPHT wells and also in low pressure wells; with equivalent circulating densities as high as 1.65 sg. in both single phase and multiphase drilling fluids MPD applications as low as 0.29 specific gravity.Paper will also detail recommended operational procedures and recommended practices to integrate the MPD technique along with conventional cementing operations. The annulus between the 5" liner and the 7" liner 38# is very small, this condition associated with a narrow mud weight window, makes quite impossible to do a successful cementing job without the aid of the MPD technique.

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.