29
December
2014
HYDROCARBON
ENGINEERING
Overcoming the
design challenge:
Part one
R
ameshni & Associates Technology & Engineering (RATE) was
recently awarded a contract to license a new grass roots
sulfur recovery project including design of the acid gas
removal and the sulfur recovery unit, tail gas treating, water
dew point control unit, thermal oxidiser (incineration system) and the
liquid sulfur degassing units for a sour gas field development (SGFD) in
Asia.
The challenge in this project was to deal with a wide range of feed
gas compositions of H
2
S and CO
2
while also dealing with a lot of
impurities such as COS, heavy hydrocarbons, mercaptans, and BTEX.
The feed gas composition to the acid gas removal unit (AGRU)
consisted of a number of cases. The design had to be able to operate in
all of these cases while achieving a stable operation and meeting the
performance guarantees and environmental regulations.
The H
2
S concentration to the AGRU varies from 2.3 - 5%, the CO
2
concentration varies from 3 - 6%, benzene from 40 - 90 ppmv, toluene
from 45 - 220 ppmv, xylene from 20 - 150 ppmv, COS from
25 - 70 ppmv, and heavy hydrocarbons up to C50+, mercaptans from
15 - 50 ppmv, plus many pseudo components according to the gas
analysis frommore than 100 wells. The H
2
S concentration to the sulfur
recovery unit varies from 30 - 47% and CO
2
ranges varies from 58 - 43%
respectively. The gas pressure was approximately 100 barg at 50 °C.
The sales gas has to meet the following performance guarantees.
n
H
2
S, 4 ppmv.
n
CO
2
less than 1.7% maximum.
n
COS 4 ppm wt maximum.,
n
Organic sulfur 50 ppmw maximum, total sulfur 60 ppmw
maximum.
The sulfur recovery, tail gas treating, thermal oxidiser, and liquid
sulfur degassing have to meet the following performance guarantees.
n
Sulfur recovery minimum 96%.
n
Overall SRU+ TGU less than 50 ppmv of SO
2
at stack.
n
Liquid sulfur degassing, less than 10 ppmw of H
2
S.
In this article, design features of the units and the reasons why they
were selected will be discussed.
Project description
RATE executed a new sour gas field development project by
developing new schemes to meet all high H
2
S cases of the feed
compositions and to achieve a stable operation by evaluating all
commercial solvents and the most economical schemes by using the
best possible technologies.
Acid gas removal
The highest H
2
S case in the design basis concentration was selected as
the design controlling case. In order to meet the specification of the
treated gas, a solvent was needed. Generic solvents such as MDEA and
all formulated selective solvents chemical, physical, and hybrid
solvents commercially available to meet the following specifications
were considered.
As part of the acid gas removal scheme configuration, hot flash
configuration, two stage regeneration system and lean/semi lean
configuration were also considered.
The hot flash gas configuration evaluation was conducted by heating
the amine further before entering the flash drum. This feature has been
used to flash the amine and to recover the hydrocarbons. In this scheme,
after the first flash drum the rich amine enters the lean/rich exchanger
and then enters to another heater to heat up then enters to the second
flash drum to flash the gas. The gas leaving the second flash drum is
cooled and enters an additional flash absorber to separate the
hydrocarbon using lean solvent. Adding several pieces of equipment to
the amine unit would result in higher capital cost, thus it was concluded
that the hydrocarbon recovery is not significant and it is not cost
effective.
In addition, by selecting the proper solvent, there is no need for the
two stage regeneration scheme and there is no need for lean/semi lean
scheme. Additional equipment would increase the capital cost.
After extensive technical and cost evaluation, it was concluded that
formulated basedMDEA chemical solvent can meet all of the project
requirements and will remove CO
2
, H
2
S and COS tomeet requested
specifications to less than 150 ppmv CO
2
, H
2
S less than 1 ppmv and COS
to less than 4 ppmv in the treated gas. RATE performed the extended
evaluation on the solvent selection from generic to formulated or
selective solvents by all solvent suppliers and a recommendation was
formulated: MDEA based chemical solvent versus hybrid solvent, where
this solvent has the flexibility tomeet the product specification for all
cases.
The proposed solvent unit resembles a conventional amine type
acid gas removal flow scheme, but utilises a formulatedMDEA based
solvent (45 wt%), and employs proprietary RATE technology. The thermal
or flash regenerated solvent process removes CO
2
, H
2
S and other sulfur
components. Hydrocarbon losses are minimal in the process due to their
low solubility in the selected solvent.
The advantages of the formulatedMDEA based chemical solvent
versus hybrid are:
n
Meet the project specification for all cases.
n
No need for polishing unit before or after amine unit.
n
Less circulation and less capital cost.
n
A proven technology and optimised design based on over 50 years
operating experience.
n
Ability to handle a wide range of inlet H
2
S and CO
2
concentrations
with minor operating adjustments and no hardware modifications.
n
No need for two stage regeneration, and no need for lean/semi
lean configuration, no need for hot flash configuration.
n
System designed for high reliability, flexibility and required design
turndown without the need for hardware modifications.
n
Availability of the solvents at regional supply facilities for fast
response to customer needs.
n
Capability and availability of sharing operational data from other
facilities using the same solvent.
Figure 1 represents a typical amine unit where the sour gas
flows through a gas filter prior to entering the absorber. The
bottom of the absorber rich solvent flows to the rich amine
Stephen Santo and Mahin Rameshni,
Rameshni & Associates Technology
& Engineering (RATE), USA,
discuss
how the challenges involved in
designing sulfur recovery units with a
wide range of H
2
S concentrations can
be overcome.
