ABSTRACT

There are two major factors in the operation of offshore gas gathering systems that are critical to the economic success of these facilities. These factors are:

  1. The choice of production rates for existing wells and compression setpoints at the processing platforms.

  2. The selection and scheduling of new projects to maintain and/or increase capacity.

In order to operate a system economically, the correct setpoints and individual well production rates have to be adjusted to maximize the current Net Present Value of the field. In addition to normal operating decisions, potential projects for increasing capacity have to be time-tabled to maximize economic returns. We present a software system designed to automate as far as possible these longterm planning decisions. - Its main components are: A multiphase pipeline simulator able to simulate the hydraulics of both the gas and condensate flow within the gathering system. A flow optimizer, which adjusts the flow rates from the component wells and compression at the Central Processing Platforms to maximize the field's current economics. A project scheduler, which adds facilities to the network when required to increase capacity when the current network no longer meets demand. The entire system is packaged within a graphical user interface, designed to make the analysis of the complex hydraulics and economics intuitive to the planning and design engineer.

Description of the Production System

Unocal, Thailand Ltd. is responsible for the operation and development of several major gas fields in the Gulf of Thailand. The total production rate is on the order of 750 MMSCFD. The basic layout of the field is diagrammed in Figurel; Gulf of Thailand Schematic. There are forty-eight (48) wellhead platforms,(with thirty-six planned in the next five years). Each wellhead platform has'twelve well slots. These slots support varying numbers of wells and zones (up to five zones per well). Each zone may have several unique sands (or reservoirs), each with differing reserves, productivity, and fluid compositions. The zone is the smallest discrete unit capable of being analyzed because sands are commingled within zones. Consequently, pressure and fluid data are averaged for each zone. These zones are numerous and disconnected. That is, instead of having multiple wells producing a single interconnected reservoir, there are typically several discrete zones (or sands) to each well. Each of these zones behaves as a small separate reservoir. This allows the wells for the most part to be produced independently of each other. The zones also tend to be somewhat short-lived (on the order of three months to two years), so switching from a depleted zone to a new zone within a well is fairly frequent. There are currently eight offshore process facilities, including four remote production platforms and four Central Processing Platforms (CPPs). There is a fifth CPP planned for installation in 1996. The wellhead platforms are linked to these offshore process facilities by three-phase pipelines (gas-condensate-water).

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