Saudi Aramco operates several deep gas reservoirs in the Kingdom of Saudi Arabia (KSA). Both vertical and horizontal K2 gas development wells have long 16-in. vertical sections. The 16-in. section is drilled as quickly as possible through several mid-depth hydrocarbon reservoirs to a competent seat in a dolomitic limestone. Since this section is fairly long (±5,000 ft) it represents one of the biggest challenges in the continuous drive for better rate of penetration (ROP) as well as reliability of downhole drilling assemblies. These sections are typically drilled with various positive displacement motors (PDM) in a simple performance bottomhole assembly (BHA) setup with two roller-reamer type stabilizers to mitigate mechanical stuck pipe risks. Drilling through the interbedded formations with varying hardnesses using very aggressive 16-in. bits has proven to be challenging in terms of wear and tear on the drilling motors. Damage to the motors, such as stator chunking, bearing failures and even catastrophic connection twistoffs have occurred during these drilling operations. One service provider currently uses 9½-in. motors in the 16-in. wellbores. To address tool integrity issues, the service provider upgraded to their standard offering, 12¾-in. motors. While incidences of housing and stator failure were eliminated, the combination of large, high flow rate tools in a land-based operation has not delivered the required performance on bottom. The drilling rigs currently employed for gas development drilling were not capable of pumping more than 1,300 gpm while optimum performance from the standard 12¾-in. motor comes with flow rates above 1,500 gpm. As a result, bit speed was too low, and ROP did not meet or exceed the 9½-in. motor runs and the standard 12¾-in. tools did not find widespread acceptance from the client.

Increasing BHA and wellbore complexity create a need for case specific engineering modeling software. Hence, mathematical modeling of the mechanical and dynamical behaviour of BHAs under various downhole conditions such as different wellbore curvatures has become routine. This paper discusses an advanced engineering model and the verification of its predictions with downhole measurements. First the mathematical model and the downhole dynamics measurement sub are introduced. Next, three examples comparing measured and predicted steady state bending loads are presented. While the predicted and measured results match well, detail and accuracy of input parameters such as wellbore curvature are proven essential. Lateral natural frequencies of the model are compared to the peaks in the measured frequency spectrum. In conclusion, the general validity of the model regarding bending loads and vibrations is evaluated. Backward whirl dynamics is evaluated by comparing downhole measurements with time domain model simulations. The predictions meet the downhole measurements both in frequency and magnitude. Introduction The benefits of applying mathematical models to analyze the mechanical behaviour of bottom hole assemblies (BHAs) in the design phase prior to actual drilling operations are obvious. A multitude of different downhole scenarios can be investigated very efficiently leading to an optimized bottomhole assembly design which is not susceptible to mechanical failures related to high static or dynamics forces exceeding the specifications of the downhole equipment. However, this approach will only be successful if the model can be trusted and its predictions are accurate. As such, the verification of a mathematical model with field measurements and observations are a key requirement. In the past, surface dynamics measurements were used to verify model predictions[1,2,3]. However, the problem with surface measurements, in particular in the case of lateral vibration problems, is that the measurements are taken at a huge distance away from the point where the vibrations actually occur. As such, the accuracy and applicability of these measurements for verification purposes are limited mostly to axial and torsional vibration problems. Earlier publications have shown that the verification process can be significantly improved if surface and downhole measurements are available[6,7]. Today, advanced downhole dynamic measurement subs are routinely used in drilling operations[4,5]. These subs measure the actual downhole forces including the downhole bending loads and provide an ideal data source for the verification of mathematical BHA models. This paper focuses on an advanced mathematical model capable of predicting the bending load of a BHA and its verification with downhole bending moment measurements. The paper starts with an introduction of the mathematical model and its application modes: static load prediction, natural frequency analysis and detailed time domain simulation. A short overview introduces the downhole measurement sub with focus on the downhole bending moment measurement. In the main part of the paper several examples are presented where the model predictions are compared with equivalent downhole measurements. The accuracy of the model predictions, the source of observed disagreements and the limitations of the mathematical models are discussed. Mathematical Model The theory behind the mathematical model used in this paper is described in detail in reference 8. The model is based on the finite element method utilizing a geometrically nonlinear three dimensional beam element. This beam element is character-ized by its outer and inner diameter, its length, its modulus of elasticity and its density. More complex cross sections can be modeled by defining equivalent stiffness and mass correction factors.

This paper introduces bending tool face, a new measurement with applications in directional drilling. The measurement is derived from two perpendicular bending moment sensors in the BHA and identifies the orientation of BHA bending with respect to gravity high side while drilling, both in rotating and sliding modes. The paper presents the underlying theory and motivation for the measurement, describes its implementation into a downhole MWD tool and shows measurement examples from field applications. Furthermore, the paper outlines the use of the data for directional calculations. The paper concludes with a discussion of applications in which the bending tool face information adds value, such as reducing uncertainty in casing exit applications and improving directional control in challenging 3-D well profiles. The discussion is supported with field results.

The myriad drilling problems associated with dynamic dysfunctions, including substandard performance and premature bit and downhole tool failure, have been well documented in the literature. Alleviating these problems and potential failures requires a systems approach that brings together improvements in the bit, BHA, and operating practices. This paper describes one such approach where a new-generation 16-in. PDC drill bit was applied in tandem with a newly engineered 12 ¾-in. positive displacement motor (PDM) and hard rock drilling techniques. Further, the high RPM and low weight-on-bit (WOB) recommendations inherent in old-school shale drilling gave way to hard rock parameters that maximized depth of cut. Consequently, impact fractures and abrasive wear were reduced, thereby maintaining the bit in an overall sharper and more efficient condition. Through this systems approach, the operator successfully avoided premature bit and motor damage and achieved record ROP and reduced costs in a Saudi Arabia project. Historically, most sections have required a cleanout run with a roller cone bit, followed by a PDC bit for drilling the first 4,800 ft, and another PDC bit to complete the interval. The combination of the new tools and precise drilling techniques has eliminated the complexity and costliness of such runs. In a rare shoe-to-shoe run, the combination drilled out the 18 5/8-in. casing to TD at a record ROP of 33.8 ft/hr, replacing the three planned bit runs and saving the operator US $249,000. The authors will explain the advances in PDC bit technology that focused on minimizing cutter damage, thus allowing bits to drill further at faster ROP. Further, they will examine ongoing initiatives aimed at improving performance and reliability in demanding drilling conditions that resulted in the development of the new and more robust PDM that provides higher torque output at available flow rates and pressures. They will describe how the new PDC bit technology and higher torque PDMs, combined with a change in operating procedures that focused on minimizing dynamic dysfunctions, resulted in a step change in performance.

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