The calculation of equilibrium and sphered liquid volumes and, to a lesser extent, that of the pressure and temperature drop in gas-condensate systems is very sensitive to fluid composi-tion. For instance, the liquid loading of the line may double due to small changes in the propor-tion of the heavier components, leading to an increase in the predicted sphered slug volume of more than a factor of two.
Given the importance of using the correct fluid composition, black oil correlations are not suit-able for gas-condensate design. Instead the FLODAT module of the GENESIS flowsheet simu lator should be used to produce a compositional which is then accessed by FLO.
To ensure that the correct pipeline composition is used for the production of the compositional any saturated water and offshore processing must be taken into account.
4.5.1 Water Content
Normally the compositional data will be available for the dry wellstream only. However, the gas is normally saturated with water at reservoir conditions. To determine the actual water content of the fluid, GENESIS can be used to add water to the dry wellstream composition. By using the ASAP program in GENESIS, this wet composition can then be flashed at reservoir condi-tions, to determine the actual water content of the gas.
Although most gas wells have no free water at reservoir conditions, later in field life water break-through can occur and free water must be taken into account.
If the gas is dehydrated offshore using a glycol contactor, negligible water remains and the dry wellstream composition can be used.
However, if free water knock-out is used, the water fraction in the is the saturated water content at the pressure and temperature of the water knock-out equipment.
4.5.2 Addition of Inhibitors
The liquid loading of a gas-condensate can be substantially increased by the addition of inhibitors at the upstream end of the flowline. To ensure the correct liquid loading is used for gas-condensate calculations these inhibitors must be added to the composition. Unfortunately, GENESIS cannot correctly partition corrosion inhibitors between the oil and water phases. It must therefore be assumed that the inhibitors are contained entirely within the water phase.
This can be carried out by substituting water for the inhibitor in the same volume ratio to the gas, and adding this to the composition determined in 4.51 by using ASAP.
4.5.3 Combined Compositions
Obviously if the production from more than one field is to be transported by a gas-condensate flowline, the combined composition must be used. Thus, compositional datapacks must be prepared for each ratio of flowrates from the two fields.
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Topography
The predictions of the Mechanistic Model, and also a second simpler mechanistic type model called Segreg, can be sensitive to the topography at low flowrates. This sensitivity is a real effect and cannot be ignored. Thus, although empirical methods, such as those Oliemans for pressure drop and Eaton for liquid hold-up, are not sensitive to the line topography, this is due to their inability to correctly model the changes in flow regime and liquid level between hori-zontal and uphill sections of pipeline.
To ensure that the predictions of liquid hold-up and pressure drop are accurate it is therefore important to ensure that as detailed a topography as possible is used. It is generally the case that the liquid hold-up will increase asymptotically to the final value as the number of line segments is increased. Thus, calculations based on a simple approximation to the topography will usually lead to an under-estimate of the liquid hold-up.
The errors incurred by using an over-simplified approximation to the real topography will not be significant for flowlines in which inclinations are small (of the order of or if gas velocities are high (greater than 30 However, if large inclinations or low gas velocities are encoun-tered the errors can be large. An example of this is the North East Frigg flowline. The depth of this varies by up to 90 feet over its 11 mile length, with inclinations of between and -3.7”. Three topographies were used to model the section, consisting of 1, 9 and 18 pipeline segments respectively. For the lowest flowrate, giving a gas superficial velocity of approximately 2.5 the calculated pressure drops for these three topographies were 35, 57 and 74 psi respectively and the liquid hold-up values were 101, 1284 and 2496 bbls. The measured values, which are themselves only approximate, were 72 psi and 2410 bbls in close agreement with the most detailed topography used.
It is possible that the predictions would increase further if an even more accurate topography were available. However, as the 18 segment topography covered all the major inclination changes, any further increases in the predictions are likely to be small.
For reference the Olieman pressure drop correlation combined with the Eaton hold-up correla-tion predict a line pressure drop of 40 psi and liquid hold-up of 500 bbls with the detailed topography.
The North East Frigg example is an extreme case of low and large upward inclinations.
However, it leads to the recommendation that all topography changes which result in a pipeline section that slopes upwards at more than should be included in the topography to ensure reliable results.
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