The paper shows that a downhole bending moment measurement combined with a simple mathematical model can provide a good estimate of the wellbore curvature, matching the results obtained from survey data analysis quite well. In addition, the bending moment measurement delivers wellbore curvature information at a much higher resolution than the standard Minimum Curvature method, which assumes a constant curvature between the survey stations. The paper presents numerous examples of downhole bending moment data measured in deployments with both rotary steerable and steerable motor BHAs and compares the dogleg severity estimates from the bending moment data with the dogleg severity derived from the survey measurements. Accuracy and limitations of the measurement and the model predictions are discussed. The paper also introduces a new method of analyzing cyclic hole effects applying FFT techniques to the depth-based bending data. Introduction Any drilling bottom hole assembly (BHA) in a directional wellbore is subjected to bending moments due to side forces acting on the BHA. These side forces may be caused by gravity, by dynamic effects, or by wall contacts of the BHA in curved wellbore sections. In the past, mathematical models have been developed5 to predict the side forces, bending moments and stresses that are introduced into a BHA in a given borehole curvature profile, usually derived from measured survey data. This paper discusses the application of mathematical models in the opposite direction: to predict the borehole curvature from measured bending moment data. The bending moment data have been acquired with a recently introduced drilling dynamics tool3 in a variety of different applications and tool configurations including rotary steerable systems (RSS) and steerable motor BHAs. The bending moment data can be both transmitted to the surface while drilling and recorded in on-board memory for post-run processing and detailed analysis. Bending moment data recorded during directional drilling operations have been published in 1989 by Cook et al.6; however, their analysis was limited to some qualitative statements. Hood et al.7 demonstrated recently how real-time bending information can successfully reduce the risk when drilling hard interbedded formations with an increased tendency to develop high local doglegs at the formation interfaces. Dogleg Severity The drilling industry uses the term dogleg severity (DLS) to describe the total curvature of a directional wellbore. The dogleg severity is derived from the directional survey data as explained in detail in Appendix A. All DLS calculations from survey data in this paper are based on the Minimum Curvature method. Here, the well path between two survey stations is assumed to be a circular arc with constant curvature, i.e. constant dogleg severity. Appendix B shows that the bending moment data constitute a measurement of the curvature of the BHA at the point of the bending moment sensors. With the assumption that the curvature of the BHA does not differ significantly from the curvature of the wellbore the BHA is in, an estimate of the wellbore curvature is obtained. The goal of this paper is to demonstrate the validity of this assumption for a variety of cases and to discuss the influencing parameters. The examples in the next section compare the DLS calculated from the survey data with the DLS estimated from the bending moment data. For better readability, the terms survey DLS and bending DLS are used from hereon. A sensitivity analysis in the section after next illustrates the influence of various factors on the accuracy of the bending DLS estimate.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractCurrent trends in the oil and gas industry are focused more in operational efficiency, production optimization, value, and environmental effects than ever before. The industry actively pursues technologies and techniques that offer improvement in these areas, which explains the increased interest in multilateral well designs. In highly sensitive areas, such as national parks and areas of geographical sensitivity, it has become extremely difficult to obtain permits to prepare well sites if this preparation requires the removal of forestry, permanent scarring of the landscape, or disturbances to the wildlife or to the people who live and work in the area.The Val d'Agri field in southern Italy is located within the boundaries of the Basilicata National Park. Consequently, Eni and its partners were challenged with reaching production targets while minimizing land disturbances. Eni evaluated and implemented multilateral technology to help meet the objectives.The forward thinking of Eni led the company to pre-install orientation devices in the casing string during the original construction of the well. This action made it possibile to perform multilateral solutions if/when needed, such as the TAML Level 5 implemented on well Agri-1 or B.The first orientation devices to be used were installed in well Cerro Falcone 3X or A in 2000 to construct a TAML Level 2 junction with re-entry capabilities through the completion. In 2003, the same technology was used on Agri-1 or A, where the orientation devices were installed in the 7-in. and 9-5/8-in. casings. When well Agri-1 or A was put on production, the produced fluid was found to be much more corrosive than expected. The well had to be shut in because the metallurgy of the equipment in the well was not suitable for the corrosivity of the produced fluid.Eni and Halliburton formed a team to evaluate the situation and design a suitable solution: to exit from the 9 5/8-in. orientation device and drill a secondary lateral. This secondary lateral required a TAML Level 5 junction with an Incoloy 925 completion to isolate the junction and to provide throughtubing access to all bores, including the existing Agri-1 or A.This paper focuses on the methodology and value this technology brought in the achievement of planned production targets.

Following the many successful applications of the "Lean Profile" (LP) technique, developed by Eni E&P some ten years ago, a further step towards production maximization with simultaneous increase of operational safety and decrease of the overall drilling cost has been recently achieved with the introduction of the "Extreme Lean Profile" (XLP).Compared to a conventional profile, the LP has allowed running an additional casing between the 18 5 / 8 " and 13 3 / 8 " strings, the XLP introduces a further casing also between the 13 3 / 8 " and 9 5 / 8 " strings.Previous papers have described this new concept. Instead, our main intent herein is to highlight how the use of the XLP can really make the difference for the success of drilling operations when it comes to drill long extended-reach wells.This is the case of the onshore well Cerro Falcone 4 Or in the Val D'Agri field (Italy), the first ever deviated well being drilled by applying the XLP concept, without which the target could not be reached with the borehole size required for constructing the planned multilateral well.The need to apply the XLP technology required overcoming many challenges due to the severe operational conditions experienced in drilling previous wells (hard, unhomogeneous and abrasive formations, hole instability, severe vibrations, mud losses).This paper provides a comprehensive description of the well profile requirements, the associated operational issues, the chosen solutions and the actual challenges encountered during drilling operations. The achieved results are also described.Based on the success of this XLP application, Eni E&P is considering to further develop this concept of narrow annuli, to insert additional casing strings: for instance a 8 1 / 8 " casing between the 9 5 / 8 " and 7" strings and a 5 3 / 4 " casing between the 7" and 4 1 / 2 " strings.

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