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Abstract

Dynamic well modelling can provide additional understanding and an improved process to:

1. ensure a well is going to naturally flow during initial kick-off, and/or

2. predict the watercut limits for the restart/kick-off of natural flowing wells after a shut-in period.

As reservoir pressure declines and watercut increases, naturally flowing wells often require gas-lift (artificial lift) in order to 'kick-off' and flow them continuously. These wells will generally encounter kick-off problems at a lower watercut than their natural flow limit due to fluid segregation effects in the wellbore under static conditions. Therefore determining the kick-off limit is of primary importance to determine the optimum gas-lift (artificial lift) implementation schedule and its economic impact.

Static (steady state) well modelling is of limited use in being able to predict the effects of fluid segregation on kick-off. Dynamic modelling of the wells during kick-off, however, will indicate the associated flowing tubing head pressure (FTHP) that will enable the well to attain steady state flow as a function of well productivity index (PI), reservoir pressure and watercut.

This paper describes how dynamic modelling of four undersaturated oil fields using OLGA 2000 has been used to effect timing decisions of gaslift installation.

In order to verify that OLGA 2000 was a reliable tool for the simulations, total mass flow rates (oil, water and gas) from well test data were compared with the mass flow rates predicted by OLGA 2000. The OLGA models were able to match the well test data, providing some evidence that OLGA 2000 can be used to model well behaviour.

Dynamic well modelling has been found to be a useful tool in optimising costly gaslift installation timing and improve well completion design. This should minimise potential deferred oil production and optimise reservoir recovery. Dynamic modelling is also useful in identifying and understanding the key flow assurance issues during the well's life cycle.

The time at which the wells will not naturally kick-off is dependent on productivity index (PI), reservoir pressure, and watercut. The reservoir fluid properties are critical to the results.

For the four oil fields studied, it was found that wells were predicted to experience kick-off problems at significantly lower watercuts - anywhere up to 26% less, than for steady state flow.

Dynamic well modelling should be considered during the early phases of concept selection studies to implement gaslift in oil fields.

Introduction

Fluid Segregation and Well Kick-Off Mechanism

A well producing oil, water, and gas will exhibit segregation of the three fluids in the tubing on shut-in. When the well is initially opened after the shut-in period the column of gas is produced from the tubing leaving a higher density mixture of oil, water, and new reservoir fluid. The flowing bottom hole pressure of the well reaches a maximum at the point the gas has been entirely produced from the tubing. In certain circumstances the weight of fluid in the tubing at this point in time does not allow the well to flow, and the well is deemed to have a kick-off problem. This sequence of events is shown in Fig. 1.

The watercut at which the kick-off problem is experienced is usually lower than the water-cut at which the well will naturally stop flowing.

Case Study

Four undersaturated oil fields with eight wells producing via a subsea system to the Cossack Pioneer FPSO, operated by Woodside Energy Ltd on behalf of the North West Shelf Joint Venture. Gas-lift is expected to be required at some time in the future in order to kick-off the Wanaea, Lambert and Hermes (WLH) production wells. The Cossack field already has gas-lift installed in the single producing well (Cossack #4).