Transients due to changes

The operation of oil and gas pipelines often involves changing the inlet or outlet flowrates for a number of reasons, namely:

l Start-up and shut-down.

l Fluctuating supply and demand, gas delivery changes.

l Switching wells on and off for maintenance or testing.

Such changes can have a considerable effect on the downstream processing plant as increases can give rise to high transient liquid production rates and potential gas surges, and reductions in flow can result in periods of low flow. This is illustrated by the follow-ing example. Figure 7.1 Marlin pipeline holdup profile

Figure 7.1 shows the predicted liquid content of the Marlin gas condensate pipeline as a func-tion of the gas flowrate. This is a 67 mile long, 20” diameter wet gas line operating with a liquid loading of around 65 It is seen that the general trend is that the liquid content reduces as the gas increases. Hence, if a gas increase is made, liquid will be removed from the pipeline as the new equilibrium liquid content is established. If the change in the gas is carried-out too fast, the excess liquid can be swept out as a large ‘slug’

which may overfill the downstream plant, whereas if the changes are made slowly, the liquid can be gradually swept out within the slug catcher capacity. It is also interesting to note in this Figure the wide variation in the predicted holdup obtained from using the various methods.

This may not be too much of a problem when calculating the amount of liquid swept out during a transient because it is the difference in the holdup that it most important. In this example the Eaton holdup correlation is expected to give reasonable answers. However, one should be wary of using the correlation approach rather than mechanistic models since they do not usual-ly predict the steep rise in holdup as the velocity and inter-facial friction reduces hence a gross underestimate can result when starting from low flowrates.

Section 7. Transient Flow

Figure 7.2 shows the liquid at the outlet of the Marlin gas condensate pipeline during an increase in the from 155 mmscfd to 258 mmscfd. During the test the gas rate was held constant at mmscfd for 52 hours in order to reach equilibrium conditions. The rate was then increased to 258 mmscfd in a period of one hour and held constant for a further 26 hours to obtain equilibrium conditions again. It is seen that during the transient the outlet liquid

is considerably higher than the final equilibrium value.

Marlin line rate change test

Transition period gas rate 258 MMscfd Condensate rates:

catchers, Final gas rate 258 MMscfd

Condensate rates:

1600 2000 2400 0400 0800 1200 1600 2000 2400 0400 0800 1200 1600

Oct. 12 Oct.13 Oct.14

Figure 7.2 Marlin rate change test

5000 11

Figure 7.3 Marlin comparison with

In the next section we shall outline a simple method for estimating the slug catcher size required to handle the liquid removed during increases. Such a method was used to determine the predicted profile shown in Figure 7.2. In later sections the use of tran-sient computer codes will be outlined. However, Figures 7.3 to 7.5 are provided here to illus-trate the potential accuracy of transient codes on the Marlin rate change data. This data has often been used as a test case as it is one of the few transient field data sources available in the the open literature.

Section 7. Transient Flow

II ,,

00 25 35 45 55 65 75

(hr)

Figure 7.4 Marlin comparison with PLAC

8 0 0

Measured flow, 3 pt moving average Measured flow, smoothed curve OLGA

II I I I I I I I I I I I

1600 2400 0800 1600 2400 0800 1600

12 13 14

Figure 7.5 Marlin comparison with OLGA

Pigging gas condensate pipelines can also result in large slugs. However, in many cases it is not feasible to design slug catchers of a sufficient size to handle the equilibrium slug produced by running pigs at low throughputs. In this case pigs must be run frequently to prevent the liq-uid holdup reaching equilibrium, which can incur high operating costs. Sometimes gas rates can be reduced during the pig arrival to allow the produced liquids to be processed, but in oth-ers the gas may be determined by the consumer, and the pigging operation carried out at the prevailing gas rate. In some situations pigs are only required on an infrequent basis for corrosion control or inspection, in which case the pipeline liquid content may be high and a pro-cedure must be put in place to handle the liquid swept-out by the pig. One way of doing this is to stop the pig offshore and ‘walk it’ into the slug catcher at a rate compatible with the liquid

processing capacity. This approach was successfully carried out at the restart of pigging oper-ations on the Amethyst pipeline where a liquid volume of over four times the slug catcher

Section 7. Transient Multiphase Design Manual

capacity was allowed to accumulate in the when the offshore pig launcher failed. In some instances it is possible to reduce the liquid content of the pipeline prior to pigging by con-trolled rate increases to remove liquid. In other cases pigging is not possible, and

changes must be controlled to prevent overfilling the downstream plant.

With these factors in mind it is seen that for gas condensate systems at least, it is often the transient ‘slug’ that determines the slug catcher volume. For oil and gas pipelines pigging may be required frequently for wax control etc, where the lines have reached equilibrium, hence this may determine the size of the slugcatcher. However for some developments, particularly sea, pigging is required less frequently and can be accomplished with some operating

Here it is often the longest normal slug or the transient rate change liquid sweep out that determines the required slug catcher surge volume. The next section outlines a simple calcula-tion method for estimating the liquid outflow profile due to rate change transients.