Quick method for gas pipeline sizing

The following equation can be used to estimate the gas flow in gas pipelines. For small gathering lines, the answer will be within 10% of that obtained by more elaborate methods.

Q d

L P P

= (500) ³ −

1 2

2 2

Where:

Q is flow rate (cu feet per day) P1 is inlet pressure (psia) P2 is the outlet pressure (psia) L is length (miles)

d is the pipe inside diameter (inch)

k =

1.41-4.08 _air ρ

ρ

© Penspen Group 5.

TWO PHASE FLOW

5.1 Introduction

The reservoir behaviour of a hydrocarbon system depends on the relationship of the phase envelope of the fluid in terms of the reservoir conditions of pressure and temperature.

The pressure-temperature (P-T) diagram is a very useful tool for describing the phase behaviour of oil and gas mixtures as they flow in a production system. Figure 2.0 shows a typical P-T diagram for a petroleum mixture found as an undersaturated oil at initial reservoir conditions.

A P-T diagram outlines the regions where a mixture behaves as a single phase and where it separates into two phases, gas and oil. The bubble-point curve defines the conditions when a mixture acts as a liquid and, if pressure is reduced, gas is liberated to form a two-phase system. The dew point curve defines the conditions when a mixture acts as a gas and, if pressure changes, liquid is condensed to form a two-phase system. The point joining the bubble-point and dew point curves is the critical point, and it represents a unique

thermodynamic conditions. A mixture at pressure and temperature lying outside the two-phase envelope is consider in an undersaturated state.

The dewpoint curve is usually divided into two regions, the retrograde and the normal segments. A drop in pressure for the retrograde dewpoint curve results in liquid

condensation, whereas an increase in pressure from the normal dewpoint curve results in liquid condensation. The point joining the two dewpoint segments is found at the highest temperature at which the mixture can exist as two phases (cricondentherm)

Figure 3.0 illustrates the diagram of the four general classification of hydrocarbon fluids (dry gas, gas condensate, volatile oil and black oil).

In a dry gas reservoir, no two phase mixture will be formed at the reservoir temperature as the reservoir pressure is reduced. In a black oil reservoir, the fluid in the reservoir will remain a single phase liquid until the reservoir pressure drops to the bubble point pressure.

As the pressure is further reduced gas will be generated in the reservoir which can rise to the top of the structure to form gas cap.

Gas/condensate and volatile oil reservoirs will also pass through the phase envelope as the reservoir pressures decrease. The composition of gas and volatile oil coming from the reservoir can be expected to change as the reservoir moves through the envelope.

© Penspen Group 5.2 Flow Regimes

When two phase gas and liquid are flowing slowly in a horizontal, or near horizontal, pipeline the effect of gravity is highly significant and the liquid runs to the bottom of the pipe like water in an open channel. If the gas and liquid velocities are high enough, however, flow becomes dispersed and gravitational forces are insignificant in determining the flow regime.

Between these extremes a number of flow phenomena may be observed.

5.2.1 Segregated - Stratified Smooth Flow

The first flow regime is a smooth flow of liquid in the bottom of the pipeline, an increase in the inclination of the pipe would tend to lead to higher liquid hold-ups and pressure drop, and possibly a change in flow regime (e.g. to intermittent).

5.2.2 Segregated - Stratified Wavy Flow

As the gas velocity increases it creates waves on the surface of the liquid wetting more of the pipe wall, and tending to cause some liquid droplets to be entrained in the gas flow. Liquid build up is less likely at gradual changes in elevation but is still likely at risers, and vibrations, if they do occur, will be more frequent.

5.2.3 Intermittent - Plug Flow

As velocities increase further the waves increase in height and the gas becomes separated into flowing pockets. If the cross-section remains predominantly liquid the gas pockets will run along the top of the pipe in a flow regime known as plug flow. This flow type will remain consistent over most terrain although the gas plugs may tend to combine at risers and create vibration in receipt facilities.

5.2.4 Intermittent - Slug Flow

If a large part of the average cross-section is gas, the liquid will tend to build up in batches in this velocity range, tending in the extreme case to form individual slugs. This type of flow can be affected by terrain but will tend to create vibrations at any change of direction in the route.

© Penspen Group 5.2.5 Distributed - Bubble Flow

At faster velocities in predominantly liquid lines the gas will be taken up in bubbles in the liquid and be barely affected by gravity. Even at risers there will be little tendency for slugs to form.

5.2.6 Distributed - Annular Dispersed Flow

At higher velocities the effects of gravity become less significant. The gas passes through the middle of the pipe displacing liquid to the pipe walls all round or carrying it in droplets of mist.

5.2.7 Distributed - Mist Flow

At very high velocities most of the liquid is taken up entirely in mist (or spray). Typical horizontal and vertical flow requires are shown in figures 4 and 5.