Reprint Vol (4) 7-12 (2011)
Reprint Vol (4) 7-12 (2011)
Reprint Vol (4) 7-12 (2011)
Capturing CO2 from flue gas streams in ammonia plant, waste generation as HSS and
its reclamation at CO2 recovery plant, NFCL, Andhra Pradesh (India)
R. Raghavan, G.V.S Anand, P.H.N Reddy, P. Chandra Mohan, V. Appala Raju* and Amar Nath Giri**
Quality & Environment Management System, NFCL, Nagarjuna Road, Kakinada - 533 003, India
*e-mail: varaju@nagarjunagroup.com, **amarnathgiri@nagarjunagroup.com
(Received: October 24, 2010; Revised received: February 05, 2011; Accepted: February 08, 2011)
Abstract: There are a number of different methods for Mitsubishi Heavy Industries (MHI) has concentrated its extensive research and development
programs on the use of sterically hindered amines and the post combustion, chemical absorption process in particular for treating flue gasses from natural
gas combustion. The CO2 recovery plant consists of three main sections: the flue gas cooler, the absorber (for CO2 recovery) and the stripper (for
solvent regeneration). In NFCL Kakinada, the flue gas from primary reformer enters in the flue gas quencher, where it is cooled to 40°C. The flue gas
is compressed to a pressure of 1.113 Ksca and enters in the CO2 absorber. The CO2 in flue gas is absorbed by KS-1 (Hindered amine) solvent, which
is distributed from top through packed bed system. The CO2 thus liberated is washed with DM water at the top of CO2 regenerator, cooled to ambient
temperature in an overhead condenser and sent to urea plants.
Key words: Flue gas, Carbon dioxide recovery plant, Chemical absorption, Heat stable salts
Materials and Methods absorbed by KS-1 Solvent, which is distributed from top through
packed bed system. Subsequent to contact with KS-1 solution
CO2 capture process in CDR plant: The flue gas genereted
the flue gas is further washed with DM water in the top section of
by natural gas fired application an FGD (Flue Gas
CO2 absorber. The flue gas after removal of CO2 is sent out to
Desulfurization) may not be required as the SO2 content in the
atmosphere through a stack provided at CO2 absorber top. The
gas stream is minimal. Therefore, depending on the fuel type, a
CO 2 rich solution at 55°C is pumped to the lean / rich heat
deep FGD process may or may not be necessary. The primary
exchanger. The lean solution is recycled back to CO2 Absorber.
objective of the flue gas water cooler (FGWC) is to further cool
The rich solution stream is heated up to 114 °C and sent to
the flue gas prior to entering the CO2 absorber. The lower flue
CO2 regenerator, where in CO2 is stripped off from rich solution
gas temperature increases the efficiency of the exothermic CO2
by providing necessary heat to reboiler using low pressure
absorption reaction and minimizes KS-1 solvent loss due to gas
steam. The CO2 thus liberated is washed with DM water at the
phase equilibrium increases. The optimum temperature range
top of CO 2 regenerator, cooled to ambient temperature in a
for CO2 recovery is between 95-113°F (35-45°C), however
overhead condenser and sent to urea plants. In view of
this is flexible in consideration of other factors such as water
adequate natural gas supply to NFCL by RIL, it was decided to
utility requirements and availability. The FGWC is designed and
switchover Unit-II operations to full NG mode from the present
constructed to not only to cool the flue gas, but to also further
operation of mixed feed / fuel (NG + Naphtha). Subsequent to
remove various impurities such as SOx, NOx, dust and
switchover from naphtha / NG mix to full natural gas mode in
suspended particulate matter (SPM).Clean-burning, natural gas
Unit-II, there will be shortfall of CO 2 which will be met through
typically has low concentrations of CO2 and impurities.
the CO2 production from CDR plant.
The CO2 absorber has two main sections, the CO2
The power and steam demand required for CDR plant is
absorption section (bottom section), and the treated flue gas
met through the existing offsite facilities. The flue gas having
washing section (top section). The conditioned flue gas from the
about 8 to 9% CO2 by volume is drawn from primary reformer
FGWC flows upward through structured, stainless steel packing
stack and cooled to 45°C or below in a direct contact cooler. It is
material while the CO2 lean KS-1 solvent is distributed evenly
then fed at the bottom of an absorber through a blower. The
from the top of the absorption section onto the packing material.
absorber is a packed tower. A solvent mainly KS-1 is fed on the
The flue gas comes into direct contact with the KS-1 solvent and
top of the absorber. The solvent and rising flue gas come in
CO2 in the flue gas is absorbed. The CO2 rich KS-1 solvent (rich
contact on the bed. The solvent absorbs CO2 from the flue gas
solvent) is pumped to the CO2 Regeneration unit for steam
and balance flue gas devoid of CO2 is vented from the top of the
stripping. The clean flue gas then moves up into the treated flue
absorber after washing. The solvent after absorption of
gas washing section of the absorber. This section is where
CO2 becomes rich and collected at the bottom of the absorber.
vaporized KS-1 solvent is removed and recycled and the flue
The rich solution is pumped to the top of a regenerator after heat
gas is again cooled to maintain water balance within the system
exchange where heat of regeneration is supplied through a re-
(the absorption of CO2 in the KS-1 solvent produces some rise
boiler. On heating, the solution liberates absorbed CO 2 and
in temperature). The clean flue gas then exits the top section of
solution gets regenerated for further absorption. The CO2 is
the CO2aabsorber. The rich solvent is pre-heated in a heat
collected from the top of the regenerator and sent to Urea plant
exchanger using heat from the hot lean solvent coming from the
through a booster compressor for further conversion to urea.
bottom of the CO2 stripper. The heated rich solvent is then
introduced into the upper section of the CO2sstripper, where it In this process some heat stable salts are generated
will come into contact with stripping steam of around 248°F due to minor decomposition of the solvent which is separated in
(120°C). The rich solvent is then stripped of its CO2 content and a reclaimer and disposed off.
is converted back into lean solvent. The high purity CO2
Solvent (KS-1 Solution) using for recovery in CDR plant
(>99.9%) exits the top of the stripper vessel and is compressed
and its environmental consequences: These factors
and dehydrated, prior to transportation. Once stripped, the now
contribute to the use of large equipment, high solvent consumption
lean solvent is cooled to the optimum reaction temperature of
and large energy losses - leading to increased operating costs.
approximately 104°F (40°C) before being reintroduced to the
During its comprehensive R and D phases, MHI tested more
top of the absorption section of the CO2 absorber unit.
than 130 different reagents. The most efficient solvents were
CDR plant opted at NFCL (Technology supplier: Mitsubishi critically examined in the final stage of pilot plant testing. Following
Heavy Industries (MHI), Japan and CO2 Absorbent: KS-1 this, a proprietary solvent KS- 1 was developed. In parallel with
solution, proprietary supply from MHI, Japan): The flue gas the development of the solvent, the process itself has also been
from primary reformer enters the flue gas quencher, where it is optimized, leading to superior, demonstrated performance of CO2
cooled to 40°C. The flue gas is compressed to a pressure of recovery from the flue gases of fossil fuel combustion processes.
1.113 Ksca and enters the CO2 absorber. The CO2 in flue gas is The development of KS-1 is seen as a breakthrough because
of the significant number of advantages it offers. KS-1 has an v Weight percent of solution HSS anions (strong acid anions)
exceptionally low corrosive nature and, unlike MEA, does not measured as weight percent of the total solution.
require a corrosion inhibitor. This factor means carbon steel
v As weight percent amine, this unit of measurement assumes
can be used for the majority of construction within the CO2 capture
that the HSS anions are bound to an amine cation (also
plant. Furthermore, the process operates at atmospheric
reported as HSAS). This number is determined by calculating
pressure (ensuring a safe work environment), has few exotic
the equivalent amount of amine cations that are tied up with
materials and a simple configuration. Additionally KS-1 offers
the HSS anion, and is expressed as weight percent of the
superior CO2 absorption and regeneration, lower degradation,
total solution.
lower circulation rate and, with other patented equipment, has
less solvent loss when compared to other amine based v As percent amine capacity (As percent total amine) HSS
systems. All of these features lead to decreased operating cost. expressed as weight percent amine divided by the amine
Importantly, KS-1 together with the patented “improved” CO 2 strength (free amine or alkalinity).
recovery process which utilizes the heat of the lean KS-1 solvent, Determination and analysis procedure of heat stable
effects a 30% reduction in steam consumption over the salts:
conventional MEA process.
Method: This method is intended to be used to determine the
HSS (Heat stable salt): Heat stable salts (HSS) have received quantity of heal stable salts present in used aqueous amine
a lot of attention in the industry. HSS are acid anions with a solutions. A weighed sample of solvent is passed through (or
stronger acid strength than the acid gases that are removed equivalent) a column of DOWEX* 50W-X8, 50-100 mesh
from the process gas. These anions may bind to the usable hydrogen form resin. The anions present are converted to the
amine and then therefore make it unavailable for acid gas corresponding acids, and the solvent is retained or the resin.
absorption. Heat stable amine salts (HSAS) refers to the salt The effluent containing the acid is then titrated, potentiomctricully,
formed by a HSS (anion) and a protonated amine molecule with a standard base.
(cation). HSAS may also be referred to in some instances as
bound amine (BA) Apparatus: pH meter, with a combination pH electrode, glass
column, ID 16 mm x 610mm L, or 100 ml ion exchange column,
HSS vs. HSAS: There has been much confusion about the stand for ion exchange column, magnetic stirrer with heater,
terminology of HSS versus HSAS. It is important to understand thermometer (0-100°C), beaker (capacity 200 ml, 500 ml),
that these HSS anions must be bound to a cation in solution so 31, automatic titrator, plastics funnel, electric balance, graduated
that the solution is balanced (Mother nature’s rule). One must at l mg
understand what cation forms a salt with the HSS anion to Reagents:
understand the disposition of the anions and their quantity in
solution. As referred to earlier, the sum of cations in solution must v 0.1N NaOH solution Dissolve 4~4.5g of NaOH in / liter of
equal the amount of anions in solution. water. Make standardization as follows.
Σ Cation.s = Σ Anions ⇒ Weigh 0.2~0.25g of sulfamic acid and dissolve the acid in
50 ml of water.
BA + SC = HSS + LL
⇒ Add 3 drops of Bromothymol blue (BTB) solution and
Where, BA = Bound amine (protonated amine molecule)
titrate the solution until the color of solution turns blue.
SC = Strong cations (sodium or potassium)
⇒ Normality of 0.1N NaOH solution is calculated as follows.
HSS = Heat stable salt anions
LL= Residual leanloading (H 2S or CO 2) N = SF/ 97.09 X 10 3 /V
From the above equation we can see that HSS will not Where: N= Normality of 0.1N NaOH solution (eq/1)
equal the Bound Amine (HSAS) if there is a substantial amount SF= weight to taken sulfamic acid (g)
of strong cations present in the amine solution. This is why we
recommend that the total level of HSS anions and strong cations V= 0.1N NaOH solution consumed; in titration (ml)
should be measured directly. Measuring the HSAS only may v 0.1% Bromothymol blue (BTB) indicator dissolve 0.1 g of
give a false low reading of the level of HSS anions in solution if BTB in 20ml of ethyl alcohol. Then, dilute to 100 ml with water.
strong cations are also present in the sample.
v Hydrochloric acid (5 or 10%)
It is also important to understand that HSS anions may v Cation exchange resin (hydrogen form)
be reported at least three different ways, and it is important to
understand the methodology employed to avoid confusion. v pH paper, range to include 6~8.