As the reservoir pressure declines with time, production from a gas field drops. In order to meet delivery contracts, this invariably requires the addition of relatively expensive compression facilities that boost production by lowering the bottom-hole pressure and improving the drawdown across the sandface.

This paper analyzes the compressor installation costs and operating strategy required to meet the production goals over the life of a gasfield, and proposes a simulation solution based on optimizing overall profitability. Key elements of the objective function to be optimized include a time-dependent revenue stream based on the projected price of gas, capital costs associated with adding incremental compression at periodic intervals, and compressor fuel consumption costs that are typically a near-linear function of the operating horsepower.

The optimization model proposed is applied to an example gasfield for a fifteen-year operating strategy. The results demonstrate that an optimized compressor installation and operation strategy can improve overall field profitability considerably. The effect of varying gas price scenarios on the optimization solution is analyzed separately.


The wells and gathering lines in a typical gas field are connected in a "branch-and-tree" type configuration, with single-well flowlines leading into common "branch" lines which in turn flow into the main line leading to separation, treatment and compression facilities. There is usually significant hydraulic interaction between the wells, with back-pressures at separation and treatment facilities controlling the overall rate of production. Increased production from a well results in a correspondingly higher back-pressures on adjacent wells that share a common flowline. This in turn causes a reduction in their rates of production. Single-well nodal analysis-based methods for evaluating productivity must therefore be eliminated in favor of a network model of the overall gathering system.

As reservoir pressure declines, existing production from a field can only be maintained by adding compression. Long-term delivery contracts can require the operator to add compression several times over the life of the field.

In this paper, we develop a time-dependent network model of a gas field. The model includes the interaction between wells, flowlines, surface facilities, and the reservoir. The interactions with the latter are accomplished by incorporating simple relationships between pressure decline and reservoir inflow. An economic model is then generated from the field model. This is accomplished by defining a profit function that measures the difference between gas revenues and the compression costs that drive the production of gas. Lastly, we maximize the profit function by considering variations in compressor operational strategies that are consistent with a long-term contract for the field.

The optimization algorithm used is based on the Successive Quadratic Programming (SQP) technique, a nonlinear approach that has been applied successfully to problems with multiple decisions variables in the process simulation industry.

The field-wide, time-dependent network model, coupled with the economic model of the compressor operation strategy, and integrated with the SQP optimization algorithm, has been developed with NETOPTTM, a commercial field-planning and optimization tool for single-phase and multiphase production systems.


The field-wide simulation model is based on a generalized steady-state pressure-balance algorithm applicable to multiphase and single-phase production networks and pipeline systems. The network is defined in terms of sources (producing wells), sinks (delivery point), and junction nodes, that are connected by links. P. 511^

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