American Oil and Gas Reporter - May 2015 - 86

SpecialReport: Gas Compression Technology
In a conventional oil field with vertical wells, oil typically is produced through
a manual choke into a low-pressure heatertreater (a vertical or horizontal threephase separator with a maximum pressure
of 75-125 psig). Oil and water are directed to tanks vented to the atmosphere, while
the resulting flash gas is sent to a gathering system, vented or flared (Figure 1A).

In contrast, Figure 1B shows a typical
horizontal pad with four wells, although
eight, 16 or even 32 wells can be included in a single facility. Multiwell pad production facilities include dual-stage horizontal separators; a high-pressure, twophase separation stage (HPS), followed by
a low-pressure, three-phase separation
stage (LPS). The bulk of the gas typical-

FIGURE 1A
Typical Traditional Well Pad (Single Vertical Well)
8

LEGEND
1: Wellhead
2: Well choke
3: Vertical heater treater
4: Oil storage tank

5
5:
6:
7:
8:

Water storage tank
Oil truck hauling
Water truck hauling
Emission combustion device

FIGURE 1B
Typical Multiwell Pad (Four Horizontal Wells)
11

10
8
2
1

9
2
1
4

2
1

1
6

6
7

LEGEND
1: Wellheads
2: Two-stage separator with choke
3: Vapor recovery tower
4: Oil storage tanks
5: Oil truck hauling
6: Water storage tanks

7:
8:
9:
10:
11:

Water truck hauling
Emission combustion device
Low-pressure vapor recovery unit
Low-pressure VRU
Gas lift compressor

86 THE AMERICAN OIL & GAS REPORTER

ly is produced in the high-pressure stage
at gathering system pressures ranging
from 50 to 500 psig. The LPS flash typically operates at 15-50 psig and produces smaller volumes of high-Btu gas,
which is then recovered by a vapor recovery unit.
Recovering Flash Gas

Produced oil from the separators carries
flash gas, and the large volumes of oil produced from multiple horizontal wells on a
single pad push the limits of allowable
volatile organic compound emissions.
The lowest-cost design option is to flash
the oil to the storage tanks, then recover the
vapors with a VRU compressor.
While VRUs can operate at tank pressures of less than one psig, it is nearly impossible to do so without creating a vacuum that pulls air into the flash gas. This
oxygen can exceed the typical 10 parts per
million pipeline specifications in midstream processing units. If the gas has
some amount of hydrogen sulfide, there is
additional risk of corrosion and solid sulfur deposition in downstream piping and
equipment.
Vapor recovery towers (VRTs) have
been introduced to provide a positive suction pressure to VRUs and act as a liquid
seal to prevent air ingress into the flash gas.
The towers are essentially empty vertical
vessels operating at three-five psig. Oil
flows into the top, the flash gas separates,
and the oil exits though a dip tube (or Ptrap) near the bottom of the vessel. The oil
flows up the dip tube and gravity drains to
the storage tanks, providing a positive seal
against air ingress into the flash gas.
A small amount of flash gas is generated as the oil flows into the tanks at essentially atmospheric pressure. Some additional flash gas may be generated from
tank weathering and incoming oil displacing gas, but this small amount of flash gas
is routed to enclosed combustion devices
(ECDs) to minimize VOC emissions.
The design shown in Figure 1B is one
of many variations in basic pad gas handling design. Gas handling technology is
evolving continually and designs can
vary significantly even among individual
companies in the same basin, depending
on specific requirements or restrictions.
Design variations include remote well pads
with individual liquids and gas flowlines

American Oil and Gas Reporter - May 2015

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