SPE Members

Abstract

A computer model has been developed which accurately describes transient heat transfer in buried multiphase pipelines. The model is used primarily to estimate hydrate and paraffin potential during startup, shutdown, and blowdown in subsea oil/gas flowlines. Other uses include specification of minimum temperature requirements for pipeline materials that may be exposed to high-pressure blowdown. The model development is described, and examples of application are presented.

Introduction

Two problems that may need to be addressed in subsea flow systems are the possibility of paraffin and hydrate formation. A knowledge of the temperature and pressure along the full length of a pipeline is required in order to accurately determine the formation potential. Often the temperature in the pipeline will be above the hydrate formation or cloud point temperature under normal operating conditions. However, when the pipeline is shutin, the temperature drops, and over time, the pipeline approaches sea bed temperature. For example, in the North Sea during the winter time, the sea bed temperature reaches values approaching 40F (5C). Figure 1 shows a hydrate formation curve for a typical North Sea associated gas. If no inhibitor is used and the temperature is at sea bed conditions, hydrates will begin forming at a relatively low pressure of 160 psi (1000 kPa). Increasing the pressure above 160 psi will result in an increase in the amount of hydrate formed.

Because of the hydrate or paraffin potential during shutdown and startup, chemical inhibition or some other active means of removal, i.e., pigging, may be required until the pipeline temperatures rise above problematic levels. In most cases, one would like to limit the amount of time that chemical inhibition is required in order to minimize cost. For example, in a subsea development, the inhibitor inventory at the wellhead may be limited, and to increase this capacity may require a large capital investment.

The purpose of this paper is to illustrate the development and use of a computer model capable of predicting temperatures in a multiphase pipeline under transient conditions.

MODEL

The model developed in this study consists of two parts. The first part uses a version of the OLGA multiphase flow simulator which has been enhanced by CONOCO and is called ConOLGA. An example of one of the enhancements is a model which calculates the transport of corrosion inhibitor. The second part of the thermal model was developed in this study and consists of a transient heat conduction numerical model which tracks how soil material around the pipeline stores and releases thermal energy.

OLGA MODEL

The OLGA code is a dynamic, multiphase flow simulator capable of modeling hydrocarbon (liquid/ gas) in pipelines and pipeline networks. OLGA was developed in Norway by SINTEF/IFE for a joint industry consortium.

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