1. The document describes the operations and processes at Medco Singa CPP, an LNG processing facility in South Sumatra. It separates and purifies natural gas from four wells. 2. The CPP consists of several gas processing units including separation, acid gas removal, and dehydration systems. It also has supporting utilities like thermal fluid and water treatment systems. 3. The raw gas from the wells is processed to meet specifications for delivery to PGN, including reducing CO2 levels from 38% to 4% and H2S from 0.03% to 4 ppm. This is achieved through amine absorption and membrane units in the acid gas removal section.

1. CHAPTER II
MEDCO SINGA CPP DESCRIPTION
2.1. OPERATIONS and PROCESS
LNG processing facility Singa Central Processing CPP is the operating phase of the separation and
purification of natural gas from four (4) existing wells in field. STAGEs of processing operations of gas flow
from the well done aims to meet the specifications of the desired gas by Perusahaan Gas Negara (PGN)
unit area of South Sumatra. Production capacity at Singa Field CPP each well by 30 MMSCFD.
1. the Gas processing Unit Singa CPP consists of:
a. Gas Gathering System,
b. Separation System
c. Acid Gas Removal System
d. Dehydration Unit System,
e. Thermal Unit Oxidasi,
f. Sales Gas Pipeline and Pagardewa Receiving Facilities
2. Supporting Utilities Unit consisting of:
g. the Thermal Fluid System,
h. Closed Drain System.
i. Water Treatment Unit * Fire Water,
j. Produced Water/Disposal
k. Unit Power generators, Diesel Fuel System
Specification of gas supplied from wells and processed at the Processing Unit based on gas composition
of Singa CPP Wells. is as follows:
Pressure psig 1270
Temperature F 250
Component
Methane (% mol) 61.20
Ethane (% moll) 0.17

2. Propane (% mol) 0.01
i-Butane (% mol) 0.01
CO2 (% vol) 38.41
N2 (% mol) 0.03
H2S (% mol) 0.035
H2O (% mol) -
Molar Flow
93
MMSCFD
(Dry
Basis) HP
Case
Tabel-1 Gas Supplied Specification
2.2 Specifications Gas Products‐Gas products from Singa CPP sent to Surrender Station Pagardewa must
meet specifications request buyer, in this case the Perusahaan Gas Negara (PGN). The flow of gas products
received by PGN through terminal facilities at Pagardewa acceptance is as follows:
Pressure psig 1050
Temperature F 98.5
HC dew Point,
max. pada
1050psig
oF 55
Methane %-mol 96.2693
Ethane %-mol 0.2778
Propane %-mol 0.0165
i-Butane %-mol 0.0165
CO2 %-vol 4
N2, max. %-mol 5
H2S, max. ppm-vol 4
H2O Lb/MMSCF 8

3. Molar Flow
50
MMSCFD
HP Case
Sources of gas well production comes from four well with the amount of 116.8 MMSCFD at a temperature
of 250 ° F and 375 psig pressure with specification as aforesaid. Each of the well done analysis of
composition and condensate content periodically, alternating for 4 hours with Test Separator. The Gas
produced from the well production is that the corrosive gas elements due to its high content of CO2. Of
the four streams of gas wells walked into the gathering system or system of manifold. There are 3 manifold
or header for which the supply of gas flow from the well came in, the first a header/manifold blowdown
serves to transfer or release pressure in the system when the primary process occurs the excesses of
pressure or problems on the gas plant. The System is equipped with a blowdown valve (BDV) to cope with
emergencies. the BDV on blowdown line will open automatically and siphon the gas to the Flare
KNOCKOUT Drum, so on gas flow to the Flares, while the shutdown valve (SDV) on line main process will
close so that no gas was flowing into the gas plant. Second is the manifold/header for on‐site sampling
routine. The Gas flows into the separation tank test 31‐MBD‐102 after through the inlet separator 31‐
MBD‐127 and water cooler blower 31‐201. Manifold/header to‐3 or called with production manifold, here
also passed inlet gas flow separator tank 31‐MBD‐127, water cooler blower 31‐201 and production
separator. The inlet separator 31‐MBD‐126 and 31‐MBD‐109, flushing occurs due to the high‐pressure
flow of gas towards lower pressure causing the liquid phase separation occurs in the gas phase. Phase
liquid in the gas so we refer to as condensate, containing heavy hydrocarbon and water. The condensate
is accommodated in the inlet separator 31‐MBD‐127, test separator 31‐MBD‐102 and production
separator 31‐MBD‐101 each vessel have a level controller for controlling the level/flow unit condensate
Produced Water Disposal System. The gas Separation Unit output feedback to CO2 Removal with the
condition of the process:
Pressure 1235 psig 1055 psig
Temperature 119.3 oF 119.3 oF
Component % mole % mole
Methane 61.1923 61.1788
Ethane 0.1700 0.1699
Propane 0.0100 0.0100
i-Butane 0.0100 0.0100
CO2 38.2936 38.2928
N2 0.0300 0.0300
H2S 0.0346 0.0346
H2O 0.2595 0.2739
Standard Gas
Flow
93
MMSCFD
HP Case
90
MMSCFD
LP Case

4. 2.3 CO2 Removal Unit and Membrane
Acid Gas Removal Unit (AGRU) consists of the Amine unit and Membrane units that operate in parallel.
The function of this unit in goal to lower the concentration of CO2 and H2S in gas flow feed. The content
of CO2 and H2S in gas feed, each about 38% and 0.03% mole. As the desired gas flow product has content
of CO2 and H2S out AGRU respectively 4% mole maximum and 4 ppmv. Feed the gas into the system
through the gas filter AGRU separator 35‐MAJ‐103 which filter out particles of solids > 10 micron. Gas
flow exit gas filter separator part towards the membrane unit and amine units.
1. Absorber (35‐MAF‐104)
on the Amine unit, CO2 and H2S in the flow of acid gas (sour gas) absorbed by amine solution
through two STAGEs, namely through the lean amine stream of spring and the lean amine. The
flow of gas from the Gas Filter (35‐JANG‐103) enters from the bottom of the absorber Tower (35‐
MAF‐104) in 1194 psig and flows into the 118oF meliwati 4 STAGE tower over the bed, packing
the absorber is going with the flow of gas between the contact spring lean and lean amin in
opposite direction (counter current). CO2 and H2S is absorbed and react chemically with a
solution of methyldiethanolamine (aMDEA). Gas flow out of the top of the Tower the absorber
(sweet gas) into the Sweet Gas KO drums 35‐MBD‐109 with van plate (pack) on top of it with the
size of the diameter of 10 glow aims to prevent dew bubble liquid amine/MDEA (losses) carried
by the gas flow. Out of amine loop system, due to the flow of sweet gas is saturated with water
then the need to separate the content of water in a stream of sweet gas.
2. Amine System
Solution out of the base of the absorber is called Rich amine. Flows out of the base of the column
to the Amine Flash Column 35‐MBF‐105. Flow rate set by the level controller on the basis of the
absorber opens and closes a control valve 35‐LV‐104 to keep high fluid (level) of rich amine
constant. Rich amine on the basis of flash column in the into two streams, 85% of the total stream
flow into the Semi Lean Pumps 35‐PBA‐331A/B/C and 15% goes to Rich Pumps 35‐PBA‐333A/b.
Rich amine Solution of Flash Column on 13 psig and 168 0F, flows into the Lean/Rich Amine
Exchangers 35‐HZZ‐204 through Rich Pump 35‐PBA‐333A/B and in the heat to temperature 218
0F. The exchangers are used is the type of plate frames. The flow of rich amine into the Amine
Regenerator 35‐NAF‐107 the top column after pressure was lowered from 30 to 20 psig with no
flow valve 35‐FV‐714. This column ran on the top column pressure psig 12 and 14 psig pressure
at the base of the column, liquid accumulated inside the accumulator tray Amine Regenerator
flows into Reboiler Amine 35‐HBC‐205. In the reboiler, liquid heated with hot oil. Part of the
liquid evaporates. Steam coming out from the top of reboiler in regenerator base and headed out
of the regenerator. The Liquid overflow through the top of the weir is a solution of acid gas
content with lean to be grilled more on TOX and Flare. The flow of liquid out of the boiler flowing
back gravity to the regenerator. Reboiler uses hot oil as a heating source. The heat entered the
reboiler set with control 35‐FV‐716 on hot oil line. Incoming heat controlled by setting the set
point flow controler. Hot lean amine regenerator flows out of the base into the lean Amine
Exchange through the Lean side Booster Pumps 35‐PBA‐337A/B in which heat is exchanged with
the cold rich amine from the flash column. Lean amine in chill temperature to 125 0F with Lean
Cooler 35‐HAL‐202. Lean amine has been in the refrigerator through the lean Amine cooler then
headed into the Absorber 35‐MAF‐104. Before entering the absorber, through 35‐FIC‐712 10%
lean amine from Booster Pumps are intended to the Amine Particulate filter‐35‐JANG‐108, 40%

5. of the flow of the lean amine in transferred to the Amine Charcoal Filter 35‐JANG‐109 and Amine
Particulate After filter‐35‐JANG‐111 to take contaminant particles and later transferred to both
Amine Absorber using pump 35‐PBA‐334A/B.
3. Acid Gas System
Acid gas out of the flash column on 12 psig and 161 oF and cooled with condenser 35‐HAL‐203 to
temperature 140 oF. The flow out of the condenser is a mixture of water and acid, into the
accumulator 30‐MBD‐109 which served as a gas‐liquid separator. Acid gas passing through the
accumulator to the Thermal Oxidizer (T‐Ox). The water that goes into the bottom of the
accumulator flow Flash Column using a reflux pump 35‐PBA‐332A/B. Acid gas is burned inside
the chimney Thermal Oxidizer before safely and in accordance with the gas quality emissions
government regulation role to be released into the atmosphere through the vent stack.
A. Antifoam Injection System
Antifoam Injection System was installed to minimize Antifoam injection of foam (foam) in the
amine system. Flow injection antifoam are:
• Suction of the Reflux Pumps (35‐PBA‐332A/B)
• Suction of Rich Pumps (35‐PBA‐333A/B)
• Suction of Lean Pumps (35‐PBA‐334A/B)
B. Membrane Unit
STAGE I Membrane Pre Treatment System of gas filter Gas Feed 45 MILLION towards the
membrane unit and the rest flows to the amine unit. The Feed gas at 1230 psig and 119 0F entered
the tube side of the Gas/Gas Exchanger 35‐HBG‐281 in the chill to the temperature of the gas
residue 88 oF Membrane Skid Package STAGE I. A Gas has on the chill in the First STAGE Filter
Coalescer 35‐MAJ‐175 to eliminate the water and the condensed hydrocarbons. Vapor at 1223
psig and 87oF streamed to the First STAGE Electrical Heater 35‐NAP‐681 to raise the temperature
to 109 oF. The Feed gas is then transferred to the First STAGE Guard bed 35‐MBA‐182 and First
STAGE Particle Filter 35‐JANG‐183 for the first.
B.1. STAGE I Membrane Skid Package Each membrane is made up of four skids of bank with 7
pieces of tube, membrane tube has four nozzle: A nozzle the inlet feed‐gas. ‐One nozzle for
residual gas outlet. ‐Two nozzle to permeate outlet gas. Separex membrane elements made from
cellulose acetat which has two layers: the thick micro porous layer and a thin active layer on top
of the micro porous layer. The Feed gas into the tube membrane and distributed into membrane
meliwati high pressure channel spacer. Along the way the gas inside the tube membrane, CO2,
H2S, and other materials which are highly permeable to quickly penetrate the membrane to reach
into a permeate channel spacer. Components permeate this move with spiral patterns in a tube
to permeate tube. Components with such a small permeable methane power missed in high
pressure channel spacer next element flows into or out of the membrane tube, go to residual
header. The flow of incoming feedback flow freely from the element to the element on the eve
of the U‐cup seal installed in upstream side of each element. Each tip out the covered with epoxy
membrane elements. The Feed gas enters Membrane Skid Package STAGE I in 1210 psig and
109oF. Unit membrane lowers CO2 and H2S from the gas feed 38.4 mole% down to 4% mole and
H2S 346 ppm‐v down to 18 ppm‐v, each producing gas 24.7 MMSCFD. Then the gas is heated by
Gas/Gas Exchanger 35‐HBG‐281 up to 111 oF. Due to the high content of H2S is still high, mounted

6. two H2S scavenger units 35‐MBA‐187A/B to reduce the content of H2S below 4 ppm‐v to fit the
sales gas specification before it is combined with outlet flow of gas Dehydration Unit.
2.4 Dehydration Unit (DHU)
Dehydration Unit (DHU) of sweet gas from the Amine Absorber is saturated with water equilibrium. Then
on the next process aimed at making the content of the water in the stream of sweet gas. Dehydration
unit used a solution of Triethylene glycol (TEG) as absorben to absorb water. This Unit consists of two
parts, dehydration and regeneration.
a. TEG Contactor 36‐MAF‐112 gas dehydration Process feed takes place in counter current in the Glycol
Contactor between lean TEG with high pressure gas feed. Gas flow which is rich in moisture content (wet
gas) through a series of internal part a mist pad on top to prevent contactor glycol loss. Gas with a
moisture content of smaller 8 lb/MMSCFD later in the chill by lean TEG up to temperature in contact
through 25oF the Gas Glycol Heat Exchanger 36‐HBG‐206. Rich TEG 93.72% wt in 1183 psig out through
the bottom TEG contactor, then in flash to 85 psig pressure and flow to the Glycol Still Column 36‐HBA‐
209.
b. TEG Regeneration System Rich TEG 93.72% wt on 1183 psig out through the bottom Glycol Contactor,
flash up to 85 psig pressure and flow to the Glycol Flash Separator 36‐MBD‐109 via level control 36‐LV‐
112A. A large part of hydrocarbons is not dissolved and sour gas from the liquid in the flash TEG into flash
drum. Rich TEG (containing water) from the flash drum into two‐STAGE filter system. TEG Particulate
Filter 36‐JANG‐116 take the particles larger than 5 microns, and heavy hydrocarbons not dissolved and
organic contaminant in the Carbon Filter TEG take on 36‐JANG‐117. Clean, rich TEG then flows into the
Hot Glycol/Glycol Exchanger 36‐HBG‐207A. Rich TEG heated to temperature 329 ° F via the exchange of a
hot, lean TEG of Glycol Reboiler Surge Tank 36‐MBD‐109 and then into the low pressure still column 36‐
HBA‐209. The flow of rich TEG entry and flow down in the TEG still column, a number of hydrocarbons in
water and evaporating of glycol with heat still column packing.
TEG into reboiler is heated under a temperature of boiling glycol. Lean TEG on 385 ° F flowing towards a
surge vessel, the liquid level is maintained by using a weir in the reboiler, TEG then flow by the gravity of
the reboiler flow through the shell side Hot Glycol/Glycol exchanger 36‐HBG‐207A and Cold Glycol/Glycol
Exchanger 36‐HBG‐207B, cooled to 170 ° F by interchanging with the rich TEG. Lean TEG out heat
exchangers and gravity flow toward Lean TEG Pumps 36‐PBA‐337A/b. Lean TEG then dipompakan
Gas/Glycol Exchanger 36‐HBG206 and cooled down to 138.4 ° by exchanging heat with effluent dry gas
from the TEG Contactor. Cool lean TEG (98.83% wt‐TEG) and then flows into the tray top contactor.
2.4 Thermal Oxidizer (T‐Ox)
Waste gas from the permeate Membrane Units and acid gas from the Amine Unit burned (oxidation) first
before released into the atmosphere. Thermal Oxidizers function to burn exhaust gases and absorb heat
to hot oil used for heating in the Waste Heat Recovery Unit. The Thermal Oxidizer unit consists of:
• Main Burner
• Incinerator
• Stack
• Induced and Forced Draft Fan
• Waste Heat Recovery Unit (WHRU)
Josh
Digitally signed by Josh
DN: cn=Josh, o, ou,
email=joser.mbo@gmail.
com, c=ID
Date: 2013.06.11 11:54:18
+07'00'

7. 2.3.5 Sales Gas Header, Pig Launcher Pagardewa Station Receiver Sales gas outlet DHU combined with
Sales of H2S Gas Scavenger sent to Pagardewa through pipe 12 "is 42 km from CPP Medco Lematang EP.
To equalize the pressure between the two outlets, mounted a pressure valve 38‐PV‐702 with a pressure
drop of about 30 psi on the Dehydration Unit. Sales Gas header in complete with a Pig Launcher for
pigging line transfer gas from the Singa to the CPP Pagardewa metering station.
The pressure on the line pipe sales gas is maintained using a control valve 38‐PV‐701. A portion of the
amount of gas delivered to flare gas if the pressure exceeds the set point of sales. At Pagardewa Station,
line is equipped with: 2 instruments online analyzer H2O, H2S, and GC online.