American Oil and Gas Reporter - May 2017 - 60

SpecialReport: Gas Compression Technology

"In re-engineering and recommissioning the Ramsey plant,

the project team's foremost responsibility was to provide a
plant that minimized field downtime, was reliable upon startup,
and considered process safety in all aspects of operations. All
of these goals were achieved with the resurrected plant's reliable,
efficient and safe processing capabilities, underscoring
the success of the Ramsey redesign effort.

plant's north end to progress in parallel
with the reconstruction efforts and provided ample space for the new HP stabilizer system.
Because the full gas stream was richer
and not as sweet as Phase 0, greater
liquid slug capacity and amine treating
were required prior to resuming full gas
flow into the plant. A new slug catcher
was the major piece of inlet equipment
required for Phase 1 and subsequent phases. Fortunately, a Western Gas booster
compression station was being constructed
five miles south of the Ramsey plant,
which included a 2,000 barrel harp slug
catcher that was under fabrication. The
slug catcher was repurposed for the Ramsey project and a duplicate slug catcher
was ordered for the booster station without
materially impacting the booster plant's
project schedule.
Liquids Handling System
The new inlet liquids handling system
had to be engineered from the ground
up. To bring the plant online quickly, a
method for handling as much as 5,000
bbl/d of HP drip condensate was needed
as a temporary solution to allow gas flow
as soon as possible while the HP stabilizer
project was being designed and constructed
at the plant's southern end.
Different design options were considered to temporarily handle the drip condensate, but all required an LP recycle
compression system to deal with flashed
vapors associated with the condensate.
The Cambrian compressor station, which
already was under construction within a
mile of the plant, could provide the recompression for vapors produced from
the condensate handling system. The station consisted of a single Caterpillar
3516™-driven unit that could compress
60 THE AMERICAN OIL & GAS REPORTER

as much as 4 MMcf/d of gas back to the
plant inlet. The amine flash gas also
could utilize the station, once the 1,400
gallon/minute amine unit was on line.
The design ultimately selected utilized
the intact Ramsey II equipment along
with activated carbon beds to treat the
condensate to a quality that could be
pumped and blended with the cryogenic
plant liquids to meet a Y-grade spec. This
option eliminated all liquids trucking
from the facility and allowed producers
to receive full value from the drip condensate. Eliminating truck loading mitigated risks associated with weather-related
events and increased process safety. The
design simplicity enhanced system reliability and eased the operational burden
of processing the drip condensate, while
minimizing capital costs.
The temporary liquids handling system
was utilized from March to November
2016 and remained in service until the
permanent HP stabilizer was commissioned. It took HP NGLs from the inlet
slug catchers and routed them to a threephase flash vessel operating at 450 psig.
The water was separated and the remaining
NGLs were routed to a surge tank in the
Ramsey II plant (Ramsey II had sustained
damage, but the plant's liquids handling
equipment was largely undamaged).
The flashed vapors from both the
three-phase vessel and the NGL surge
tank were routed to the Cambrian compressor station for recycling back to the
plant inlet. The surge tank's pressure was
maintained to ensure the NGL product
met both the methane and CO2 requirements of the Y-grade specification, while
still maintaining a high liquid product
phase. Ramsey II NGL product pumps
were used to pump the liquids through a
carbon bed skid and into the pipeline.

The activated carbon bed effectively
removed color impurities stemming from
lube oil and heavy hydrocarbon contaminants and allowed the product to meet
pipeline specifications. The activated carbon beds also provided the ability to remove minor sulfur impurities. Temporary
bullet tanks were kept on the east portion
of the plant to provide a temporary backup
in the case of operational issues with the
liquid treating system. The temporary
bullet tanks were never needed and no
trucks were required to transport processed
liquids from the facility.
The liquids handling system enabled
an expedited startup of the plant and the
ability to resume operations in a safe, reliable and efficient manner without limiting
the plant's throughput, while upgrading
the value of the drip condensate liquids.
When the system was decommissioned,
it had processed more than 500,000 barrels
of NGLs and avoided the need for more
than 2,500 truck loading operations.
With the success of the temporary liquids handling system, the HP stabilizer
was modified to include a single-tower
operational mode with a carbon bed skid
to provide the flexibility to produce a
single low-ethane Y-grade product from
the drip condensate for processing economic considerations, or in the event of
equipment downtime in the downstream
portion of the stabilizer system. The plant
currently is operating in a two-tower
mode to increase the condensate's product
value. The HP stabilizer has increased
liquids handling capacity, increased
throughput, and further upgraded the
liquid products produced from the drip
condensate.
Amine Treating Design
The reconstruction effort also entailed
a redesigned amine treating system. The
downward-trending CO2 percentages allowed the amine plant to be engineered
to eliminate turndown issues and design
a more flexible treating system. The 1,400
gallon/minute amine system under construction at the time of the incident provided
enough amine regeneration capacity to
treat the plant's full build-out throughput.
Therefore, the decision was made to decommission and remove the damaged 475

American Oil and Gas Reporter - May 2017

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