Optimal Scheduling of Production and Compression in Gas Fields
Authors: Murray J.E. , Edgar T.F. 
Published: December 2007

Two new algorithms to optimize the well location and the sequence of flow rates and compressor duties at each well subject to a prespecified demand schedule have been developed. These algorithms can use any capitalization method and can be applied to either primary production or gas storage. A new method for approximating integer variables as continuous variables also is tested.

Introduction
Optimal reservoir development has been investigated often in recent years. This paper studies the optimal selection of well locations in a gas reservoir and discusses the sequential optimization of flow scheduling in a known gas reservoir constrained by allowable wellhead compressor duty. A model for the reservoir is required, and the production demand schedule must be known. All possible wellsites and compressors and their positions in the reservoir are specified discretely. positions in the reservoir are specified discretely. This discrete character and the continuous aspect of fluid flow from the individual wells are emphasized because both continuous variables and discrete or integer variables are accounted for in developing optimization techniques for a mixed integer programming problem.
Several studies on the optimization of the operation or design of gas storage systems and natural gas fields have been published. This research has investigated optimum production scheduling, well location, and design of gas production scheduling, well location, and design of gas wells and gathering systems. These studies fall into two groups: those that concentrate on the operation of the system, and those that focus on the design problem.
Most studies of optimum operation primarily have determined the best operating policy from several feasible schemes. In addition, the models usually are simplified and neglect well interference, reservoir heterogeneity, and time-varying behavior. Boyd and Millers and Duane have performed limited studies on optimizing well completions and a compressor schedule for a multiperiod reservoir. No rigorous optimization was attempted, and no well interference effects were considered. Linear programming has been applied to the scheduling of crude oil production over time from a single reservoir. Influence functions and superposition were used to obtain linear relationships between flow rate and pressure drop for a given time interval. Wattenbarger improved previous studies by using inmuence functions to simulate reservoir behavior. He used linear programming to optimize the production from a gas storage reservoir during the withdrawal period. This minimized the difference between the desired production and the actual production.
Cooksey et al. used a two-dimensional reservoir simulator to determine the best operating policies. Considering several fixed alternatives of operation, they studied the interaction between compressor operation and well flows. They determined intuitively that it is best to produce from high-deliverability wells because the produce from high-deliverability wells because the compressor costs would be less. Sharp et al. and Dempsey et al. simulated case histories of compression effects on field productivity. They also compared the economic cost of adding compression facilities at a fixed location with drilling new wells.
Optimal well location in the development of a gas field has been studied by several authors. Using trial-and-error solution, Henderson et al. indicated that new wells should be placed in the region of low permeability. Coats determined the order in which wells were to be drilled from a list of possible sites using the technique of enumeration, that is, considering every possibility.
JPT
P. 109