A Computer Model for Planning the Development of an Offshore Gas Field
Authors: Sullivan J. 
Published: December 2007

This paper describes a gasfield planning model developed and used to select a plan for future development of a partially depleted offshore gas field. The model succeeds in integrating physical constraints of reservoir behavior and gas flow in wells, surface pipes, and compressors with variables that describe possible development activities. This enables a development plan that maximizes the economic worth of the gas resources to be found. The mathematical techniques of mixed integer programming (MIP) are used to find the optimal plan.

Introduction

The gasfield planning model has been developed as a means of finding a development strategy that maximizes the economic worth of a gas field. The model development was undertaken for application to a group of four offshore North Sea reservoirs managed by one operator.

Production from the field began in 1977 with the commissioning of two production platforms serving two of the reservoirs. Since then, two more platforms have been commissioned for the other two reservoirs, and compressors have been installed on one of the original platforms. Installation of compressors on one other platform is planned.

Current production is achieved through 16 wells producing from the Middle Bunter and Rotliegendes formations. The surface gathering system consists of two branches. Each branch comprises a pipeline of diameter 10 in. connecting two platforms. A pipeline 19 in. in diameter transports the gas to a commonly owned trunkline for flow to a shore terminal. The distances between the two pairs of connected platforms are 6 and 2 miles, respectively, and the minimum pressure maintained at the trunkline inlet is 1,200 psi.

The gas from all four reservoirs is dry, with a high proportion of methane. The relative gravity varies between 0.63 and 0.64. The production history suggests that all the reservoirs behave as independent closed systems with negligible water influx. Thus, the average reservoir pressure divided by the gas compressibility can be predicted as a linear function of cumulative gas production from the reservoir.

Total field production is limited by the sales contract quantity. However, within a few years, with the currently installed facilities and the planned additional compressors, production is expected to decline below the contract plateau. This provides the opportunity for further investment to boost the declining rate.

Several available options for increasing the production rate are described in the following.

Workovers

Of the 16 producing wells, five have significantly lower rates than other wells in the same reservoir and, thus, could be considered for workover. Workover operations are expected to raise these rates to be comparable with the other similar wells. However, the total improvement expected is small, perhaps adding only 10% to the total rate at current pressures.

New Wells

The scope for increasing production by drilling additional wells is considerable. All the platforms have at least three well slots as yet unused, and where this is insufficient, additional wellhead platforms can be installed at a reasonable cost.

Workovers

Of the 16 producing wells, five have significantly lower rates than other wells in the same reservoir and, thus, could be considered for workover. Workover operations are expected to raise these rates to be comparable with the other similar wells. However, the total improvement expected is small, perhaps adding only 10% to the total rate at current pressures.

New Wells

The scope for increasing production by drilling additional wells is considerable. All the platforms have at least three well slots as yet unused, and where this is insufficient, additional wellhead platforms can be installed at a reasonable cost.