Hydrocarbon Processing - February 2022 - GP-16

SPECIAL FOCUS: TREATING SOLUTIONS
stream units operation (GOSPs, inlet
area and feed gas filter-separators), the
main findings included:
* Normal operation at all GOSPs.
Several factors contributed
to periods with unexpected
gas compressors shutdowns;
however, no direct impact on
the downstream facility could be
noticed. The number of shutdowns
was significantly reduced later.
FIG. 2. Hydrocarbon layer in an amine
contactor.
FINDINGS AND ANALYSIS
Plant design and simulation. A thorough
review of Plant A design revealed
the following:
* The field has cap gas that represents
more than 60% of the produced gas
at the GOSPs. This cap gas is mixed
with the crude inside the reservoir.
During plant design, the GOSPs
were simulated based on crude oil
samples representing the north and
south part of the field; however,
only the cap gas composition for
the south field was used. This
resulted in lower acidity in the
final simulation. Late samples
revealed that the north field cap
gas has a higher acid gas content;
therefore, it has a major impact on
produced gas acidity.
* The compositions and flowrates of
the gas produced from the GOSPs
are not identical. To some extent,
more gas is produced from the
north field (hence the higher acid
gas content).
* The gas simulation of the GOSPs
without the north field cap gas data
resulted in low acid gas content
(1.2 mol%-1.4 mol%) in the
GOSPs' associated gas. However,
when the north field (higher acid gas
content) data was used, the acid gas
content in the GOSPs' associated
gas increased to 2.1 mol%.
Upstream GOSPs and inlet area.
Based on the team assessment of up*
Steady operation of the triethylene
glycol (TEG) dehydration unit.
The four GOSPs are comprised
of nine upstream TEG units.
Their operation was steady except
for one of the units, where low
performance was noticed-this
was due to operational issues in
the TEG regeneration section. The
impact of this will be related to water
carryover with the gas, which has
no direct contribution to foaming.
The subject TEG unit performance
was significantly improved later. The
TEG units were excluded as a direct
cause of the foaming issue.
* High operating temperature of
the TEG units at the GOSPs.
The GOSPs area experiences
high ambient temperature during
summer: it is difficult to cool the
associated gas and maximize heavy
ends condensation. This results in
intermittent TEG carryover and
high hydrocarbon dewpoint of the
produced gas. The original facility
was designed in the 1990s without
NGL recovery, so no refrigeration
unit was built. NGL recovery
was introduced in 2015, so it was
infeasible to install refrigeration
units at the GOSPs.
* High acid gas and C6
+ content.
Many gas samples during summer
and winter were collected from the
outlet of the four GOSPs, the inlets
to the Plant A slug catchers and the
inlets to the two AGRUs. All samples
confirmed high acid gas content of
1.8 mol%-2.1 mol% of acid gas
(H2
S and CO2) and slightly higher
C6+ levels of 0.7 mol%
The presence of hydrocarbons in
AGRU equipment. The pure amine solution
does not foam easily, but foaming
can be initiated by many factors, such as
hydrocarbon liquid, corrosion inhibitor
16 JANUARY/FEBRUARY 2022 | GasProcessingNews.com
and amine degradation products. Plant A
experienced several foaming events at different
intervals in the amine contactors in
both AGR trains. The foaming resulted in
excessive amine losses and off-specification
product gas, in addition to sudden reductions
of feed gas flows. Frequent liquid
hydrocarbon accumulation occurred in
the amine contactor at both AGR trains.
At peak times, the Plant A operation team
drained the amine contactor several times
per day to skim the liquid hydrocarbon
that was accumulating in the system.
During the summer of 2017, numerous
foaming incidents took place, so the
team investigated the amine contactor
and flash drum operations. It was confirmed
that there was significant liquid
hydrocarbon carryover to the AGRU
unit. This was proven through:
* Visual inspection of the
equipment sight glass, which
showed a significant layer of
hydrocarbons (FIG. 2)
* Excessive skimming of both the
amine contactor and flash drum,
multiple times a day
* Amine samples collected
that showed the presence of
hydrocarbons in lean amine solution.
Amine solvent quality. Monitoring the
amine solvent quality is crucial to assess
the AGR unit performance. The Plant A
lab and several third-party labs analyzed
the lean amine solution quality for both
AGR trains. TABLES 1 and 2 show the analyses
results:
* H2
S and CO2
in the lean amine
for both trains are below the
recommended range of 0.0005
mol/mol-0.003 mol/mol, which
indicates over-stripping of rich
amine. The presence of H2
S at
low levels (typically 300 ppmv) is
important to provide an iron sulfide
protection layer against corrosion.
* The samples showed that amine
solvent concentration (MDEA +
PZ) is within the recommended
range of 50 wt%-57 wt%.
* All analyses results showed TEG
content in the amine samples, the
impact of which is discussed here.
TEG contamination in the amine solvent
loop has a negative impact on the
gas treat unit capacity, as it can replace
the active amine. The GOSPs TEG systems
are designed to dehydrate the sour
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Hydrocarbon Processing - February 2022

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