Abstract

We present a model for well inflow control devices (ICDs) that includes the effects of an annulus in which the flow between the ICDs is open or partially obstructed by the presence of packers, and we describe the application of this model in a full-field simulator. Flow in an open or partially obstructed annulus requires looped flowpaths to be modeled within the well. We describe the extension to the formulation of the well model together with considerations to ensure that the resulting equations have a Jacobian matrix that is invertible and explain the necessary modifications to the techniques used to solve the resulting linear system.

The effect of simulating flow in both the annulus and the tubing was investigated in two case studies involving ICDs: a synthetic case and a sector of a North Sea field model. Results showing significant differences between the inflow profiles of horizontal wells with and without packers in the annulus are presented.

Introduction

Advanced well completion solutions are becoming increasingly common in both onshore and offshore hydrocarbon reservoirs. Two main advanced well installations are inflow control devices (ICDs) and the flow control valves (FCVs). An ICD is a screen which passively regulates inflow so that high-velocity flow regions are choked back, resulting in a more uniform inflow profile along the well. The screen acts as a flowpath between the annulus and the tubing; flow from the reservoir enters the annulus and passes through the screen into the tubing. An FCV allows active and remote control of inflow or outflow in different zones along the wellbore or in the individual branches of multibranch wells. To optimize the design and operation of wells with these installations, their behavior must be represented in reservoir simulation tools.

Simulation tools that focus purely on the near-well region and wellbore flow can be used to design this type of advanced well. In these tools the well models can be very sophisticated, taking account of flow in the annulus for example, but their capability to model reservoir flow is often limited. Full-field reservoir simulators allow a much more detailed representation of the reservoir flow, and some of these simulators contain powerful well modeling tools such as multisegment wells (Holmes et al. 1998), which allow the representation of multilateral topology, the presence of inflow control devices, multiphase flow, wellbore storage, cross flow and friction effects. For an example of the multisegment well model being used to represent ICDs in field case reservoir simulations see Henriksen et al. (2006).

A former restriction of the multisegment well model was that it could not represent looped flowpaths within a well. Thus, while flow in an annulus could be modeled, the well segment topology had to be such that there was only one flowpath from each section of the annulus into the well tubing (Fig. 1a). This restriction limited the usefulness of the multisegment well model when investigating wells without packers in the annulus, or the effects of different packer installations, or leakage through packers. In this work we model devices requiring looped flowpaths by extending the multisegment well model in a full-field simulator (Schlumberger 2008a, 2008b). In the previous formulation of the model, each segment could have only one outlet. This restriction meant that only device models with a "gathering tree" topology could be represented, and loops were not permitted. This paper describes how the formulation has been extended, effectively to allow any number of outlets from a segment, thus enabling loops to be incorporated in the ICD model. We apply the extended model to investigate the effect of simulating flow in the annulus in two case studies involving horizontal wells with ICDs: a synthetic case and a sector of a North Sea field model. We compare cases with no flow in the annulus, flow in an open annulus (Fig. 1b), and flow in an annulus with packers at locations that isolate sands of different qualities.

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