Hydrocarbon Processing - February 2022 - GP-15

SPECIAL FOCUS: TREATING SOLUTIONS
Feed gas quality limits
acid gas removal unit capacity
S. H. AL-MUDAIBEGH, M. A. AL-HARBI and M. R. TARIQ, Saudi Aramco, Dharan, Saudi Arabia
Plant A is a gas processing and natural
d of sour assogas
liquids (NGL) recovery facility designed
to process 2.53 Bsft3
ciated gas received from four segregated
gasoil separation plants (GOSPs). The
separated gas is a mixture of solution gas
(originally in crude) and cap gas (present
in an upper dome over the crude and representing
more than 60% of the separated
associated gas from the GOSPs).
The sour gas is processed for NGL
recovery, and some 1.5 Bsft3
d of residue
gas is recycled back to the GOSPs for
reinjection. 260 MMbpd of C2
+ NGL is
sent to Saudi Aramco's downstream facility
through pipelines for further processing.
Plant A consists of the following main
process areas (FIG. 1 shows an overall process
description):
* Inlet facility
* Acid gas removal units (AGRUs)
* Molecular sieve dehydration units
* NGL recovery units
* Acid gas compression
* Reside gas compression
* Injection gas compression.
Sour feed gas streams from the GOSPs
combine in a common manifold and enter
the Plant A inlet area, which consists of
three parallel slug catchers with a capacity
of 950 MMsft3
d each. These slug catchers
were designed as a three-phase separator
to handle the slug during the pipeline
scrapping operation and to separate the accumulated
water and hydrocarbon liquids
from the sour gas. According to the original
design of the gas plant, no free liquid
was anticipated during normal operation.
Sour gas from the slug catchers is
joined again through a common manifold
before it splits into two streams to feed
the two identical AGRUs, which have a
capacity of 1.253 Bsft3
d each. The AGRU
uses formulated methyl diethanolamine
(MDEA) with piperzine (PZ) (50 wt%
FIG. 1. Overall process description.
MDEA, 4 wt% PZ and 46 wt% water)
to achieve a sweet gas specification of
4 ppmv hydrogen sulfide (H2
ppmv carbon dioxide (CO2
S) and 50
).
Sour gas is fed to the amine contactor
where treated sweet gas is routed to the
NGL recovery units for further processing.
The rich amine is sent to the amine
regenerator where acid gas is stripped off
and sent to acid gas compressors for reinjection
into the reservoir. The regenerated
lean amine is recycled back and cooled
by fin-fan coolers before it enters the top
section of the amine contactor to remove
acid gas from the feed sour gas.
Since its startup, Plant A experienced
unstable feed gas quality that consequently
impacted plant sustainability and resulted
in capacity limitations and frequent
foaming incidents. An engineering team
performed extensive troubleshooting
and investigation efforts to address these
challenges, along with an action plan to
mitigate the impact. The plant evaluation
revealed that unit capacity limitation was
mainly caused by increased acid gas content
(H2
S and CO2) in the feed sour gas
by more than 50%. The presence of heavy
hydrocarbons in the feed sour gas contributed
to the foaming incidents in the acid
gas absorber. Foaming resulted in excessive
amine losses and off-specification
product gas, as well as sudden reductions
of feed gas flows. The issue was more severe
during summer, when the unit experienced
several incidents of foaming on a
weekly basis. The impact resulted in more
than a 50% reduction in plant processing
capacity on a temporary basis.
Methodology and study basis. The
comprehensive
engineering efforts to
evaluate and troubleshoot the capacity
limitation of Plant A considered the following
during the assessment:
* Review of the plant design,
including the basis of design and
original simulations.
* Review of the inlet area, AGRU
and upstream GOSPs operation,
which included main parameters
changes, equipment failure and
main streams conditions.
* Process data from the inlet area,
AGRU and upstream GOSPs.
This included historical process
input and trends, operations
records, routine/non-routine
streams analyses, and visual
inspection of main equipment in
the field during operation.
* Collecting different gas and amine
samples and performing simulation
based on design and actual data.
Gas Processing & LNG | JANUARY/FEBRUARY 2022 15
Hydrocarbon Processing - February 2022

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