Hydrocarbon Processing - August 2021 - GP-25

ENGINEERING AND DESIGN
Verification of SWS performance
and capacity restoration
M. R. TARIQ and T. B. ABANG, Saudi Aramco, Dhahran, Saudi Arabia
A book by Lieberman1
stresses that it is essential to make
existing units work adequately and efficiently. Equipment that
malfunctions or operates inefficiently limits production and
does not permit optimal energy and equipment utilization.
This, in turn, leads to higher environmental degradation, not
to mention plant downtime and lost production costs. Lieberman
concludes that good troubleshooting and adequate repair
of malfunctioning units are central to efficiently utilizing
available resources.1
Due to an increase in the produced water feedrate at a Saudi
Aramco gas plant, there was a need to install a new sour water
stripper (SWS) unit to accommodate additional produced
water. Based on operational experience, the existing SWS was
not performing as required, and a plan was made to install a
new SWS to accommodate the total sour water feedrate. The
validation of the actual capacity of the existing SWS was important
to confirm the processing capacity of the new SWS
unit under new project investment. An assessment was conducted
through design review and process simulation. Additional
verification was performed by conducting field capacity
tests jointly with the gas plant and the lab team.
Based on the assessment findings, it was concluded that
the existing SWS unit was capable of handling 5,000 bpd of
sour water as per nameplate capacity, while maintaining H2
S
specification in the treated water. Although the existing SWS
unit is capable of processing the sour water feed at its original
design capacity, some challenges, limitations, design deficiencies
and key operational issues needed to be addressed to sustain
performance in the unit. Based on the assessment study, it
was recommended to utilize the existing SWS with proposed
design changes and to install a new, smaller SWS to treat the
additional water stream. This approach resulted in CAPEX
savings for the company.
The authors present their experience and lessons learned
with the SWS that initially failed to achieve its design goals
due to multiple issues. The problems were correctly identified
in a short, systematic and effective investigation that combined
field measurements and testing with efficient hydraulic
analysis. The unit was successfully repaired and optimized,
which helped the company avoid a CAPEX investment.
Process description. Produced water is water trapped in underground
formations that is brought to the surface along with
oil or gas. It is the largest-volume byproduct or waste stream
associated with oil and gas production. Management of produced
water presents challenges and costs to operators. Sour
water must be processed, typically in an SWS, before it can be
used or disposed of in a variety of ways.
The typical inlet area facility at gas plants (FIG. 1) is designed
to receive the raw feed gas with associated hydrocarbon
condensate and water from multiple wells. The first equipment
in the inlet area is a slug catcher, which separates the bulk of
the water and hydrocarbon condensate from the gas phase.
The separated hydrocarbon condensate is stabilized in the
condensate stabilizers to achieve the required true vapor pressure
(TVP) and then injected into the neat condensate line.
The SWS is used to treat sour water flowing from the boot side
of the slug catchers and three-phase separators.
The main function of the SWS is to strip out acid gases
S and CO2) from the sour water where the acid gases are
(H2
being recovered in the acid flare through the flare gas recovery
system (FGRS). Treated water is routed to an evaporation
pond after being treated in a pre-flash drum and an SWS, as
shown in FIG. 2. Water from the slug catcher is collected in a
single header and flows to the pre-flash drum to facilitate hydrocarbon
separation. Acid gas flashing (mainly H2
S) takes
place at a pressure of 65 psig.
Water flows from the bottom of the pre-flash drum. During
normal operation, water is pumped through a feed filter
and then enters the top section of the SWS column. The column
was equipped with random packing with a height of 10 ft.
Feed entered at the top inlet nozzle. The column was designed
Nonassociated gas
Slug catcher
LP DGA train
HP DGA train
Sour water
Three-phase
seperators
Condensate
SWS
Condensate
stabilization
FIG. 1. Inlet area slug catchers and three-phase separators.
Gas Processing & LNG | JULY/AUGUST 2021 25
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Hydrocarbon Processing - August 2021

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