Hydrocarbon Processing - December 2021 - GP-21

SPECIAL FOCUS: PLANT DESIGN
AND PROCESS CONTROL
Simulation and optimization study
for a condensate recovery system
Z. K. LIEW and D. C. Y. FOO, University of Nottingham Malaysia, Semenyih, Malaysia;
and M. B. L. OOI, NGLTech, Kuala Lumpur, Malaysia
This article discusses a simulation and
optimization study for a low-pressure
condensate recovery system used on an
oil and gas platform for the extraction of
valuable hydrocarbons from flare gas for
sale. Due to the possibility of hydrates
formation, methanol is used as a hydrate
inhibitor in this case.
A base case simulation model was conto
structed,
using commercial softwarea
identify high-risk points where methanol
injection is to be performed. The use of
methanol entails increased operating cost;
therefore, it is necessary to determine the
relationship between the methanol flowrate
and condensate recovery, as well as
the operating temperature of the cold separator.
The latter has a significant effect on
the condensate recovered.
The optimum methanol flowrate was
determined by maximizing the profitability
of the system through an optimization
model, which is a linear program (LP).
The LP model was solved using Microsoft
Excel Solver. The optimum temperature
was determined to be -21.6°C, with a
net profit of $18,000/d. The system was
determined to have an emissions avoidance
of approximately 39,000 tpy of CO2
through the recovered condensate.
The three major sources of natural gas
in the oil and gas industries are oil, gas and
condensate wells. Natural gas found in oil
wells is termed as associated gas and is either
dissolved in the oil phase or remains
as cap gas above the oil.1,2
The associated
gas may have a similar composition to that
of natural gas, but the specific composition
can vary significantly based on the production
location and the properties of the well.
Heavy investment has been reported for
the further processing of this gas. However,
some of this gas is flared due to technical or
economic limitations. It has been reported
that more than 17,000 oil production facilities
worldwide have flared approximately
140 Bm3
/yr of natural gas, resulting in the
emissions of more than 350 MMt of CO2
(along with other pollutants).2
The oil and gas industries continue to
work diligently toward CO2
abatement.
The contribution from large industry
players such as ExxonMobil, Shell and BP
contributed to a CO2
12% between 2010 and 2015.3
emissions.4
reduction of about
The World
Bank has initiated " Zero routine flaring
by 2030 " and encourages global oil companies
to endorse the efforts in mitigating
CO2
Different attempts have
been reported to reduce flaring, e.g., re-injection
into oil reservoirs to maintain pressure
and to increase oil recovery,2
ing during startup,5
system,6
zero flarcondensate
recovery
etc. In particular, the low-pressure
condensate recovery system (LP-CRS)
has been reported to extract valuable hydrocarbons
from flare gas under low pressure
with minimal rotating equipment.
Background. The Tembikai oil and gas
field is located 150 km offshore the east
coast of Peninsular Malaysia. It includes
three production wells and a central processing
platform (CPP). The oil from
the CPP is sent to a floating storage and
offloading (FSO) vessel through a flexible
subsea pipeline.7
The associated gas from
the Tembikai CPP has been flared in the
traditional practice. The flared gas consists
predominantly light hydrocarbons
[e.g., methane (C1
significant quantities of pentane (C5
heavier components (C5
) to butane (C4
+).
)] and
) and
An LP-CRS has been installed that is
+ components. The LP-CRS
In
specifically tailored for the extraction of
valuable C5
makes use of a turboexpander coupled
with a Joule Thomson (JT) valve, allowing
the system to perform at a lower temperature
to maximize condensate recovery.8
this work, optimization is performed for
the LP-CRS to minimize the amount of
methanol required for the prevention of
hydrates formation in the pipelines.
The associated gas is produced from
a reservoir where it stays in equilibrium
with water-the low operating temperature
may lead to the formation of hydrates,
which are formed through the crystallization
process where the gas molecules are
trapped in crystalline cells formed from
the hydrogen bonds of water molecules.
A high-pressure and low-temperature
environment assists the formation of hydrates.9
Hydrates
reduce the diameter and
ultimately block the pipeline, downhole
tubing, tree and manifold piping, flowlines
and risers. The plugs can be difficult
to locate and remove, leading to significant
losses in production and revenues.
Dehydration can be used to eliminate
the formation of a condensed water
phase.10
However, in certain cases, dehydration
may be impractical or economically
feasible. Therefore, inhibition is
commonly used to prevent the formation
of hydrates. Thermodynamic inhibitors-
typically methanol or glycol injection-
lower the hydrate formation temperature
at a given pressure. For cases of below ambient
temperature, methanol injection is
preferable to avoid the viscosity and freezing
issues of glycol. However, the methanol
content should be kept at its minimum
level, as it incurs additional operating cost
to the system. It also impacts downstream
processes and presents environmental
limitations on overboard discharge.11
Base case process simulation. FIG. 1
shows the base case simulation model of
a condensate recovery system simulated
using commercial softwarea
using PengRobinson
as its thermodynamic model.
Peng-Robinson presented the worst-case
Gas Processing & LNG | NOVEMBER/DECEMBER 2021 21
Hydrocarbon Processing - December 2021

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