Abstract

As the mechanical devices involved in production become more sophisticated so must the simulation models used to represent their behavior. In the last decade advanced well inflow control devices were developed and installed in real fields [1]. This paper describes the techniques that have been used to model them. Firstly, we introduce the multisegment well model, which is a state-of-the-art technique that allows wells to be modeled with a high level of detail. Next, we show how inflow control devices can be incorporated into the multisegment well model with particular focus on recent extensions for spiral and autonomous inflow control devices. Finally, we conclude with results from an example simulation that illustrate how the model works.

Reservoir simulation

Reservoir simulation uses numerical models to predict the future production and development of real world reservoirs. It is an essential tool for reservoir management that aids determination of the optimal production strategy. Decisions regarding well placement, production and injection rates, and completion strategies are all influenced by the outcome of such simulations. It is also useful for asset valuation, facilitating accurate determination of recoverable reserves.

A reservoir model is created by discretizing the reservoir into a series of grid blocks. Equations governing the conservation of mass and momentum are solved simultaneously in each grid block to determine the fluid flows throughout the reservoir. This reservoir model is coupled to a well model that calculates the transport of fluids from the reservoir to the surface (or vice-versa). Since the ultimate goal of almost all reservoir simulation is to predict the volume of fluids at the surface, accurate modeling of the well and its interaction with the reservoir is crucial.

The simplest (and hence usually the computationally fastest) way of modeling a well involves treating the entire well as a single entity that connects to the reservoir at multiple locations (defined by the well completions). The fluid produced at the top of such a well is assumed to be a mixture of the fluid entering the well at each completion.

The well has a single solution variable - its pressure - which is assumed to decrease hydrostatically upwards from the bottom-hole pressure reference depth. Such an approximation works adequately for straightforward vertical wells but cannot be used for more complicated systems such as horizontal wells or those that contain inflow control devices. In these cases, pressure changes other than the hydrostatic gradient are important for accurately determining the fluid flow in the wellbore and, therefore, must be incorporated. The following section describes a sophisticated method for modeling wells that enables inflow control devices to be represented accurately.

Multisegment well model

The multisegment well model [2, 3] breaks the well into a series of contiguous sections referred to as segments (Fig. 1). Each segment has zero, one, or more connections with the reservoir grid blocks. For each segment there are four equations (assuming a three phase blackoil simulation): three material balance equations and a pressure drop equation. The pressure drop equation includes hydrostatic, acceleration and friction effects. The equations are solved to obtain the pressure, flow rate, and fluid composition in each segment.

The most obvious advantage of the multisegment well model over the conventional well model is the ability to define multilateral topology. Because the composition of the fluid is tracked in each segment, there is also significantly improved modeling of multiphase flow as well as the ability to model complex crossflow effects including branch-to-branch crossflow. The key advantage for this work is that segments can be configured to represent flow control devices, making use of the multiple levels of branching allowed by the multisegment well model.

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