Multiphase flow can be present in all aspects of underbalanced drilling. This paper outlines the ways in which multiphase flow pressure loss calculations can be used by drilling engineers in the design and optimization of underbalanced drilling operations. Then, detailed field measurements for several horizontal wells drilled underbalanced with coiled tubing are used to evaluate the application of existing pressure loss calculation methods to this unique application. Introduction Underbalanced drilling (UBD) is rapidly gaining popularity in the oil and gas industry. The Alberta Energy and Utilities Board ID94–3(1) defines underbalanced drilling as follows: "When the hydrostatic head of a drilling fluid is intentionally designed to be lower than the pressure of the formation being drilled, the operation will be considered underbalanced drilling. The hydrostatic head of the drilling fluid may be naturally less than the formation pressure or it can be induced. The induced state may be created by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether induced or natural, this may result in an influx of formation fluid which must be circulated from the well and controlled at surface." Benefits of Underbalanced Drilling Maintaining the pressure in the wellbore below the reservoir pressure allows reservoir fluids to enter the wellbore while UBD operations proceed, thus preventing flow of drilling fluids (and associated solids) into the formation, thereby minimizing or even eliminating formation damage. This is of particular importance in the drilling of horizontal wells as the formation is exposed to the drilling fluids for an extended period of time. Although formation damage reduction is the most widely recognized benefit of underbalanced drilling, several additional benefits are outlined below: Increased Penetration Rates Underbalanced drilling can achieve higher rates of penetration due to reduced "chip holdown" and decreased hydrostatic pressure at the bit face. Reduction in "chip holdown" refers to easier removal of drilled solids from the vicinity of the drill bit due to the flow of drilling and reservoir fluids, thus allowing the bit to drill into fresh rock continuously. The decreased hydrostatic pressure at the bit face reduces stress in the rock being drilled, allowing it to fail more easily. The experience of drilling engineers(2) familiar with UBD is that the rate of penetration can be increased by between three and ten times that of conventional drilling. Minimal Lost Circulation Underbalanced drilling gives better control in situations where fractured, low pressure, or high permeability formations may lead to the loss of drilling fluids and the associated problems that can cause. Evaluation While Drilling Data acquired in real time during underbalanced drilling operations allow for both the short term on site optimization of the UBD operation, and the longer term assessment of the well's potential. On site, the data acquired can be used to optimize drilling parameters such as the well's horizontal length, vertical depth, and orientation. Other data that can be obtained, useful both on site and long term, include fluid properties, productivity, and geological interpretations of the formation.

fax 01-972-952-9435. AbstractUnderbalanced drilling techniques have been applied to avoid or mitigate formation damage, reduce lost circulation risks, and increase the rate of penetration. However, drilling with a bottomhole pressure less than the formation pore pressure will usually increase the risk of borehole instability due to shear or tensile failure of the rock adjacent to the borehole. The extent of rock failure is very sensitive to the pressure in the annulus between the drill pipe, collars or BHA and the formation. The capacity of the drilling fluids to effectively circulate cuttings and cavings to surface is also strongly sensitive to the annular flow velocity. This paper describes the coupling of two popular software packages STABView™ and WELLFLO7™ to solve the complex interaction of borehole instability, rock yielding, collapse, detachment, and wellbore hydraulics during underbalanced drilling operations. In particular, a profile of the average borehole diameter can be predicted that accounts for hole enlargement in weak rock formations, and its consequences for annular pressures and flow velocities.The use of these two models running in a coupled mode is illustrated with two examples. The first one is a case study of a sidetracked well that was drilled underbalanced using coiled tubing technology in western Canada. Severe tight hole problems and poor hole cleaning had been experienced during drilling operations, and ultimately the bottomhole assembly became stuck. Subsequent borehole stability analyses indicated that significant hole enlargement was occurring in two weak shaley intervals. Wellbore hydraulics analyses showed that the liquid velocities achieved in the enlarged intervals of this well were low, which led to an accumulation of cuttings and cavings, thus resulting in the stuck pipe. A second, hypothetical horizontal well case is also described in order to illustrate the procedures for characterizing the operating envelope (i.e., optimal annular pressures and flow rates) prior to drilling an underbalanced well. This example demonstrates additional features of the two software programs for simulating the complexities of hole failure, erosion and enlargement in an annulus with a twophase fluid for both strong and weak rock cases.

Drilling deviated and horizontal wells is commonly used in the oil and gas industry for different purposes. Particularly in unconventional reservoirs such as gas shales or tight formations, horizontal wellbores provide a larger exposure to the formation, which enhances the production from such tight formations. The increase in torque and drag forces downhole in deviated borehole trajectories is one of the technical challenges that needs to be carefully studied during the design phase. There have been a number of different approaches to the way that torque and drag has been modelled in the industry. These include the soft string and stiff string approach and accounting for the effects of viscous fluid flow. The soft string model treats the drill string as a cable and assumes that it lies against the low side of the wellbore, meaning that the stiffness of the drill string is not accounted for. On the other hand, stiff string models take into account the stiffness and bending moment in the drill string and the radial clearance in the wellbore. Fluid flow during drilling results in the loss of the normal component of fluid pressure on the drill string as the flowing condition becomes dynamic. There is also an additional tangential component caused by viscous drag on the drill string due to the fluid flow.In this paper we will present the findings of a study aimed at determining the most appropriate type of torque and drag modelling approach that should be applied for Norwest Energy's Redhill South-1 well and future wells of similar nature. Redhill South-1 was directionally drilled to test the gas potential of the Permian sands in a fault dependent structural closure. Both soft and stiff string approaches will be studied. The necessity to account for viscous drag effects will also be analysed.