American Oil and Gas Reporter - May 2015 - 95

line for adequate gas lift in wells with 23⁄8inch production tubing is 350-400 Mcf/d
per well, with pressures ranging from 600
to 1,400 psig. The facility engineer is normally responsible for designing gas lift surface equipment.
Typically, this involves installing compression on the well pad to compress a portion of the well's produced gas as lift gas.
This can lead to large numbers of small
(500-horsepower maximum), localized
compressors. Because step decline rates
give each well a limited production life
where gas lift is beneficial-ranging from
a few months to perhaps a few years-these
installations are temporary and the compressors tend to be leased.
Many companies are moving toward
more centralized gas lift compression using fewer, but higher-horsepower units to
reduce capital cost and lease cost per horsepower. Central compression does require
installing gas lift lines and larger gathering system capacities to handle the recycled lift gas, but these extra costs are balanced by allowing permanent gas lift
compression facilities and lower capital
costs to provide lift gas to new wells.
One of the drawbacks to central gas lift
systems is the potential for liquids handling
problems. Most gas from shale oil wells
is relatively rich (1,200-1,700 Btu/cubic
foot). At high operating pressures and low
ambient temperature conditions, this rich
gas can result in hydrate problems if it is
not dehydrated before leaving the central
compression site. Liquids also can condense over longer piping runs, creating liquids handling problems at the well pads.
These problems can be related to allocation and/or royalty difficulties as well as
physical handling problems.
Dew point units can be employed to
prevent liquids problems, and the recovered liquids can be a secondary income
source-especially for companies that deliver gas to third-party processors.
As shown in Table 5, dew pointing the
lift gas actually increases the total gas and
liquids delivered to downstream processing plants. This is because of the nature of
the lift gas system. The "dry" lift gas mixes with the produced oil and gas from the
well, effectively stripping some of the
lighter ends from the oil. This helps
slightly stabilize the oil and reduce its API
gravity. In this example, using processed
lift gas increases total MMBtu production
by 7 percent and total ethane-plus liquids
by 10 percent while reducing the total oil
volume by only 1 percent.

Optimizing Gas Handling

Even the best facility design can be
"sabotaged" by unforeseen mechanical details. The smallest item sometimes can create big operating problems. An example
is snap-acting oil and water dump valves,
which are standard on many separators.
Snap-acting control valves create flows in
vapor recovery systems that have wide
variations within short periods. The gas
handling equipment, especially VRUs,
need to be able to handle this.
A VRT does provide dampening of the
gas flows, but on pads with multiple wells,

the design needs to allow for a situation in
which all production separators dump oil at
the same time. Increasing the overall height
of the VRT (extra height above the highest
oil level), including a relatively large suction drum on the VRU inlet, and converting to throttling-style control valves all help
minimize potential carry-over problems.
VRT pressure control is critical also.
VRTs typically run at pressures of three-four
psig. Too much pressure will blow out the
liquid oil seal, letting the flash gas go directly into the tanks. A pressure control valve
set at six psig that sends the VRT flash gas

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American Oil and Gas Reporter - May 2015

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