Page 412 - Compression Machinery for Oil and Gas

Midstream Chapter 9 391

status, pressure, and temperature readings may all be used to assess the status of
the pipeline at any one time.
Pipelines can be cleaned and inspected while still in service using “Pipeline
Inspection Gauges” or “PIGS.” Some PIGS can identify pipe damage or corro-
sion and are used to separate different products. PIG launchers and receivers are
located at stations to insert or extract the PIG.
Multiple different products can be sent down a single pipeline by sending
each product in “batches.” This is often done for refined oil products (gasoline,
jet fuel, and diesel) as an example. Batches can be separated by PIGS or allowed
to mix at the interfaces.
A few onshore pipelines worldwide make use of the added compressibility
of the gas at pressures above approximately 14MPa, depending on gas compo-
sition, and operate as ‘dense phase’ pipelines at pressures between 12.5 and
18MPa. Most applications that use CO 2 , transport CO 2 in its dense phase, at
pressures above 14bar, in particular to avoid two-phase flows when ambient
temperatures drop.
Most pipelines have large block valves located approximately every
32–48km (or as close at 8km). These valves can isolate the pipeline segments
for maintenance or to isolate a leak. Each valve usually has smaller diameter
bypass piping that is routed above grade.
Pipelines can be vulnerable to a number of potential risks, both intentional
and nonintentional. Examples of intentional damage include vibration/fatigue
failures, overpressurization, excavation or accidental physical damage, corro-
sion, weld or material defects, compressor or pumping equipment failures, ther-
mal expansion loads, earthquakes, flooding, lightening or wind, material and
weld degradation over time due to age. Intentional damage could include either
some type of physical attack or cyberattack.
There can be a many serious consequences to a pipeline failure, including
leaks, fire and explosions, injury and loss of life, loss of product to region, envi-
ronmental contamination, hazardous gas release, grid disruption, theft of prod-
uct, financial impact, and pipeline/station downtime. Other risks include
shutdown of plants using product, poor relations with neighbors, influence
on nearby communities, costs to prevent future occurrence, increased regula-
tions and restrictions, prevention of building new pipelines, social and political
impacts, increased cost to customer, and long lead times for replacement equip-
ment (from days to over a year).
To manage the gas pipeline system, the pipeline operator needs to know the
quantity of gas in the system. Metering stations, for custody transfer purposes,
are also installed at all entrance and exit points in the operating company’s pipe-
line system. Often when exchanging natural gas from one operator to another, a
specified maximum pressure is required. Therefore many meter stations also
have pressure regulation equipment installed to limit maximum pressures.
To balance seasonal demands, gas must be stored when supply exceeds
demand. Due to its high pressure, natural gas is stored in underground reservoirs