A new comprehensive, mechanistic model that allows more precise predictions of wellbore pressure and two-phase flow parameters for underbalanced drilling (UBD) is proposed. The model incorporates the effects of fluid properties and pipe sizes and, thus, is largely free of the limitations of empirically based correlations.The model is validated against actual UBD field data and fullscale experiments in which the gas and liquid injection flow rates as well as drilling fluid properties were similar to those used in common UBD operations. Additionally, a comparison against two different commercial, empirically based UBD simulators shows better performance with the mechanistic model. IntroductionIt is generally accepted that the success of UBD operations is dependent on maintaining the wellbore pressure between the boundaries determined by formation pressure, wellbore stability, and the surface equipment's flow capacity. Therefore, the ability to accurately predict wellbore pressure is critically important for both designing the UBD operation and predicting the effect of changes in the actual operation.Because of the complex nature of the hydraulic system of UBD operations in which two or more phases (liquid, gas, and solids) commonly flow, the prediction of pressure drop and flow parameters, such as liquid holdup and in-situ liquid and gas velocities, are performed mainly with empirical, two-phase flow methods. The Beggs and Brill 1 correlation is the most popular among the current, commercial UBD simulators. However, it is recognized by the petroleum industry that most of these empirical correlations were developed from experimental databases, thereby making extrapolation hazardous. 2 Moreover, the Beggs and Brill 1 correlation has been shown to overpredict or fail to predict bottomhole pressures for both vertical and horizontal UBD operations. 3,4 Since the mid-1970s, significant progress has been made in understanding the physics of two-phase flow in pipes and production systems. This progress has resulted in several two-phase flow mechanistic models to simulate pipelines and wells under steadystate as well as transient conditions. Consequently, mechanistic models, rather than empirical correlations, are being used with increasing frequency for designing multiphase production systems. Based on this trend of improvement, the application of mechanistic models to predict wellbore pressure and two-phase flow parameters seems to be the solution to increasing the success of UBD operations by improving such predictions.Literature Review. Bijleveld et al. 5 developed a steady-state UBD program to assist well engineers in planning and executing underbalanced operations. This in-house computer program uses the mechanistic two-phase flow approach. However, there is almost no technical information in the literature about implementing the mechanistic models in UBD operations.Hasan and Kabir 6 developed a mechanistic model to estimate the void fraction during upward concurrent two-phase flow in

fax 01-972-952-9435. AbstractMaintaining underbalanced conditions from the beginning to the end of the drilling process is necessary to guarantee that underbalanced drilling (UBD) operations successfully avoid formation damage and potential hazardous drilling problems such as lost circulation and differential sticking. However, maintaining these conditions during operations with jointedpipe is an unmet challenge that continues motivating not only research but also technological developments.This paper proposes an improved UBD flow control procedure as an economical method for maintaining continuous underbalanced conditions in jointed-pipe UBD operations by maximizing the use of natural energy available from the reservoir through the proper manipulation of nitrogen and drilling fluid injection flow rates and choke pressure. It is applicable to wells that can flow without artificial lift and within appropriate safety limits.The flow control procedure is based on the results of a new comprehensive, mechanistic steady-state model, validated with both field data and full-scale experimental data, and on the results of a simplified, time dependent, mechanistic model, which numerically combines the accurate mechanistic, steadystate model, the conservation equations approximated by finite difference, and a well deliverability model.

It is generally accepted that the success of underbalanced drilling (UBD) operations is dependent on maintaining the wellbore pressure between boundaries determined by the formation pressure, wellbore stability, and the flow capacity of the surface equipment. Therefore, the ability to accurately predict wellbore pressure is critically important for both designing the UBD operation and predicting the effect of changes in the actual operation. Most of the pressure prediction approaches used in current practice for UBD are based on empirical correlations, which frequently fail to accurately predict the wellbore pressure. Consequently, the current trend is toward increasing use of prediction methods based on phenomenological or mechanistic models. This paper presents an improved, comprehensive, mechanistic model for pressure predictions throughout a well during UBD operations. The comprehensive model is composed of a set of state-of-the-art mechanistic steady-state models for predicting flow patterns and calculating pressure and two-phase flow parameters in bubble, dispersed bubble, and slug flow. In contrast to other mechanistic methods developed for UBD operations, the present model takes into account the entire flowpath including downward two-phase flow through the drill string, two-phase flow through the bit nozzles, and upward two-phase flow through the annulus. Additionally, more rigorous, analytical modifications to the previous mechanistic models for UBD give improved wellbore pressure predictions for steady state flow conditions. The results of using the new, comprehensive model were validated against two real wellbore configurations with different flow areas. Field data from a Mexican well, drilled with the simultaneous injection of nitrogen and a non-Newtonian fluid and full-scale experimental data from the literature validate the improved model predictions. Additionally, a comparison of the model results against two commercial UBD simulators, which rely on empirical correlations, confirm the expectation that mechanistic models perform better in predicting two phase flow parameters in UBD operations. Introduction Because of the complex nature of the hydraulic system of UBD operations in which two or more phases (liquid, gas, and solids) commonly flow, the prediction of pressure drop and flow parameters such as liquid holdup and in-situ liquid and gas velocities are mainly performed using empirical two-phase flow methods. The Beggs and Brill1 correlation is the most popular among the current commercial UBD simulators. However, it is recognized by the petroleum industry that most of these empirical correlations were developed from large experimental databases, thereby making extrapolation hazardous 2. Moreover, the Beggs and Brill1 correlation has been shown to over predict or fail to predict bottom hole pressures for both vertical or horizontal UBD operations3,4. Since the mid 1970's, significant progress has been made in understanding the physics of two-phase flow in pipes and production systems. This progress has resulted in several two-phase flow mechanistic models to simulate pipelines and wells under steady state as well as transient conditions. Consequently, mechanistic models, rather than empirical correlations, are being used with increasing frequency for design of multiphase production systems. Based on this trend of improvement, the application of mechanistic models to predict wellbore pressure and two-phase flow parameters seems to be the solution to increase the success of UBD operations by improving such predictions. Literature Review. Bijleveld et al5 developed a steady state UBD program to assist well engineers in planning and executing underbalanced operations. This in-house computer program uses the mechanistic two-phase flow approach. However, there is almost no technical information in the literature about the implementation of the mechanistic models in UBD operations.

It has been forecast that by the end of the first decade of this millennium, offshore applications of underbalanced drilling (UBD) tools and technology will play a significant role in the petroleum industry, particularly in deep waters. Since implementing the UBD technique in offshore operations requires serious efforts and very high expenses, knowledge gained from UBD onshore operations must carefully be studied before being implemented into offshore applications. Even though the UBD technique has successfully been used to minimize operational problems and to achieve drilling to the planned depth, without down time and on budget, the petroleum industry recognizes that the greatest advantage of drilling underbalanced is to increase well productivity through the formation damage prevention during the drilling process. The use of bottomhole pressure (BHP) sensors during UBD, represents one indispensable alternative to optimize the UBD process while simultaneously achieving both purposes, drilling to planned depth and avoiding formation damage. Operational process improvement, actual underbalanced condition, nitrogen injection optimization, actual pressure drop, reservoir pressure while drilling, and hydraulic model evaluation represented some of the benefits obtained with the BHP sensors during their very first application in Mexican UBD operations. This work presents the recent results obtained by using BHP memory tools during the ongoing Mexican UBD program. Also, it shows a systematic analysis of the potential savings in terms of cost and time factors that could be obtained if the UBD technique were used to simultaneously achieve drilling to the designed depth and avoiding formation damage. Introduction Ever since 1992 UBD technology has been recognized as a mean of drilling wells that are not economically viable if drilled using conventional (overbalanced) tools and methods. So far, this technology has been extensively used to drill thousands of onshore wells around the world and offshore applications have consequently been increased. Considering that a drilling engineer defines a successful well as one that is drilled to depth according to plan without any down time and on budget, and that a production or reservoir engineer defines a successful well as one that yields maximum productivity1, the general acceptance of this technology has predominantly been justified and documented from two different points of view. Mainly, from a drilling engineering point of view, on the bases of improving drilling performance, enhancements such as increasing rate of penetration2–4, reduction in lost circulation5,6, and virtual elimination of differential sticking problems6,7 have considerably been documented with actual field examples. However, from a production or reservoir-engineering point of view there is a comparative lack of documentation on the improvements attainable from production optimization and reservoir engineering aspects. This is due to the fact that very little material has been published on well data enhancements8 and no real evidence of a formation damage evaluation has been reported after a UBD operation.

In the past, wells drilled in Crater field required an average of 310 days to reach total depth (TD), mainly because of operational problems, including drillstring twist-off, stuck pipe, unplanned sidetracks, excessive directional complexity when drilling, and under-reaming. Low rates of penetration (ROP) while drilling the Eocene and Paleocene intervals also impacted drilling time. Design optimization provided by a major service company allowed the operator to finish the recent Crater-52 well 95 days ahead of plan and 155 days ahead of the average duration for previous wells. This achievement significantly reduced operating costs and helped facilitate an anticipated production of 285,000 barrels of oil. Key achievements are summarized below: Drilled the 17.5-in. section 500 m deeper than the original design using 5.5-in. drillpipe instead of the traditional 5-in. Set 9.875-in. casing at the Medium Eocene Level, which made it possible to drill the 8.5-in. section with a much lower differential pressure, increasing ROP from 1 to 5 m/hr. Saved $3.4 MMUSD in operational costs and recovered 285,000 barrels of oil ahead of schedule. Reduced non-productive time (NPT) from 30% to 5.5%. Lithological characterization, calibration, and updating of the geo-mechanical model helped the operator drill 500 m deeper in the 17.5-in. section, which eliminated the need for hole enlarging in two problematic sections. Using 5.5-in. drill pipe improved hole cleaning, with faster ROPs as a direct consequence. Drilling the 12.25-in. section to the Medium Eocene made it possible to drill the 8.5-in. section with lighter mud weights, decrease differential pressure, and elevate ROP. Lost circulation risks were also minimized. The NPT was 83% lower than the field average. Based on these results, future Crater field well designs will also be optimized, and the drilling team is evaluating the feasibility of applying the optimized design in other fields. The improved hydraulics parameters helped increase hole-cleaning effectiveness and ROP while preventing operational incidents in the 17.5-in. and 12.25-in. intervals.