i

Table of Contents
List of Figures...........................................................................................................................iii

List of Table..............................................................................................................................iv

1. Introduction........................................................................................................................1

1.1. Overview.....................................................................................................................1

1.2. Objective......................................................................................................................2

1.3. Internship Program Details..........................................................................................2

2. Company Profile................................................................................................................3

2.1. PT. PERTAMINA (Persero).......................................................................................3

2.2. PT. PERTAMINA (Persero) RU VI Balongan...........................................................6

2.2.1. PT. PERTAMINA (Persero) RU VI Balongan Organization Structure..............7

3. Distillation Column Maintenance and Prevention of Corrosion......................................12

3.1. Distillation Column...................................................................................................12

3.2. Corrosion...................................................................................................................12

3.2.1. Type of Corrosion..............................................................................................12

3.2.2. Corrosion Rate...................................................................................................12

3.2.3. Remaining life....................................................................................................12

3.3. Prevention and Maintenance.....................................................................................12

ii
List of Figures
Figure 1 PT. PERTAMINA (Persero) Organization Structure.................................................7

iii
List of Table
Table 1 chronology of the history of the establishment of PT. PERTAMINA (Persero).........4

Table 2 PT. Pertamina Refinery Unit List.................................................................................5

Table 3 PT. PERTAMINA Vision and Mission........................................................................5

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 Chapter 1

1. Introduction

1.1. Overview

Along with the development of science and technology, it causes the level of human

needs to increase. One of the most significant needs in today's technological era is the need

for fuel. One of the fuels most often used today is oil and natural gas. As is well known,

almost all human technology requires fossil fuels in order to work. Starting from motor

vehicle fuels, power plants, diesel engines, gas stoves, and others, all of that comes from

petroleum and natural gas.

In Indonesia, the oil and gas industry is a very important industrial sector. Badan

Usaha Milik Negara (BUMN) that is responsible for meeting the fuel oil and gas needs of the

people in Indonesia is PT. PERTAMINA (Persero) which is divided into six units, namely

Refinery Units (RU) II to VII which are scattered in several places. One of PERTAMINA's

largest crude oil processing units is located in Balongan, Indramayu, West Java. This unit has

an important role in meeting the needs of fuel oil and gas in West Java and DKI Jakarta.

To process raw fuel which is obtained from several sources, PT. PERTAMINA

(Persero) RU VI Balongan has several important tools that are interconnected to process and

produce fuel that is ready for distribution. One of the important tools in the processing of raw

fuel is the distillation column. This tool serves to separate oil and natural gas into several

types such as asphalt, oil, diesel, kerosene, gasoline, avtur, and gas. In order for the tool to

produce good results and avoid malfunctions and leaks that can cause fires and dangerous

conditions, maintenance and inspection are required. One of the causes of malfunction and

damage to these tools is corrosion.

1
 Therefore, through an apprenticeship program, the author tries to review the corrosion

problem in distillation column. The internship program is carried out at PT. PERTAMINA

(Perserao) RU VI Balongan for one month (1 November - 30 November 2020). It is hoped

that this report can be understood and implemented well.

1.2. Objective

Internship report writing at PT. PERTAMINA (Persero) Refinery Unit VI

Balongan is as follows:

1. To review the corrosion problems that occur in the distillation column.

2. To review the remaining life and corrosion rate of distillation column.

3. To review the locations most prone to corrosion.

1.3. Internship Program Details

The internship program is implemented virtually by PT. PERTAMINA (Persero) RU

VI Balongan, with the following details:

Time : 1 November – 30 November 2020

Internship method : Work from home

Function : Maintenance Planning and Support

Section : Stationary and Statutory Inspection Engineer

2
 Chapter 2

2. Company Profile

2.1. PT. PERTAMINA (Persero)

Oil and natural gas are one of the main commodities in Indonesia, almost all sectors

of society use derivatives of these commodities to support their needs. PT. PERTAMINA is a

state-owned company that is responsible for processing such oil and gas. The management of

these natural resources is regulated by the state in Article 33 paragraph 3 of the 1945

Constitution. This aims to avoid monopoly practices and excessive exploitation to process

these resources.

Oil drilling was first carried out in Indonesia in 1871 by Jan Raerink in Cibodas, West

Java but failed. Furthermore, Aeilo Jan Zykler managed to find the first commercial oil

source in Indonesia while drilling in Telaga Tiga, North Sumatra on June 15, 1885. Since

then, petroleum sources have been discovered in Kruka, East Java (1887), Ledok Cepu,

Central Java. (1901), Pramusian Tarakan, North Kalimantan (1905) and Talang Akar

Pendopo, South Sumatra (1921). With these discoveries, various foreign companies are

interested in participating in the oil drilling business in Indonesia.

After Indonesian independence, the management system of oily companies in

Indonesia began to change. On December 10, 1957, by order of Major General Dr. Ibnu

Soewoto, PT. EMTSU was changed to PT Perusahaan Minyak Nasional (PT PERMINA).

PT. PERMINA later became PN PERMINA after the PP. 198/1961. After that on August 20,

1968, based on PP. 27/1968, PN PERMINA merged with PN PERTAMIN to become the

Perusahaan Negara Pertambangan Minyak dan Gas Bumi Nasional (PN PERTAMINA).

Furthermore, PN PERTAMINA changed to PT. PERTAMINA since the emergence of Law

3
N0. 8/1971 on September 15, 1971, and became a Persero after the emergence of PP.

31/2003. This company is the only national oil company authorized to manage all forms of

activities in the Indonesian petroleum industry. The table below will show the chronological

history of the establishment of PT. PERTAMINA (Persero).

Table 1 chronology of the history of the establishment of PT. PERTAMINA (Persero)

Waktu Deskripsi

1945 The first oil company in Indonesia was established in Tarakan under

the name Perusahaan Tambang Minyak Milik Negara Republik

Indonesia (PTMNRI)

April 1954 PTMNRI moved to North Sumatra and changed its name to

Tambang Minyak Sumatera Utara (TMSU)

10 Desember 1957 Then TMSU changed to PT Perusahaan Minyak Nasional (PT

PERMINA)
1 Januari 1959 NVNIAM which was originally owned by the Netherlands, changed

to PT Pertambangan Minyak Indonesia (PT PERMINDO)

Februari 1961 PT PERMINDO changed to become the Perusahaan Negara

Pertambangan Minyak (PN PERTAMIN) and became the only oil

distributor in Indonesia
1 Juli 1961 PT PERMINA was made PN PERMINA based on PP. 198/1961
20 Agustus 1968 PN PERMINA and PN PERTAMIN become one company to

become the Perusahaan Pertambangan Minyak dan Gas Bumi

Nasional (PN PERTAMINA) in accordance with PP. 27/1968

15 September 1971 PN PERTAMINA changed to PT. PERTAMINA based on Law no.

8/1971
17 September 2003 PT. PERTAMINA to become PT. PERTAMINA (Persero) in

accordance with PP. 31/2003

4
 PT. PERTAMINA (Persero) is an important element in meeting the fuel demand in

Indonesia. With the increasing demand for fuel, PT. PERTAMINA (Persero) must be able to

maintain the stability of the fuel supply. Therefore, PT. Pertamina has three important roles,

namely:

1. Provide and ensure the fulfillment of fuel needs.

2. As a source of foreign exchange.

3. Providing job opportunities as well as implementing technology and knowledge

transfer.

To achieve the goal and maintain fuel stability in Indonesia, PT. PERTAMINA

established several oil processing units in various regions in Indonesia. To date, there have

been six refinery units as shown in the following table.

Table 2 PT. Pertamina Refinery Unit List

No Unit Capacity (MBSD)

1 RU II Dumai 170.0
2 RU III Plaju 133.7
3 RU IV Cilacap 348.0
4 RU V Balikpapan 260.0
5 RU VI Balongan 125.0
6 RU VII Kasim 10.0

In carrying out their duties, PT. PERTAMINA has the following vision and mission:

Table 3 PT. PERTAMINA Vision and Mission

Visi To be a World Class National Energy Company

Misi To run oil, gas and new and renewable energy businesses in an

integrated manner, based on strong commercial principles.

5
6
2.2. PT. PERTAMINA (Persero) RU VI Balongan

The oil refinery in Balongan was established to deal with the problem of crude oil

from the Duri area and to anticipate fuel needs. In the 1990s, Duri crude oil was of poor

quality as raw material for refineries and had a lower price. The low quality of crude oil is

due to the very high residual content of up to 78%, with high content of heavy metals, carbon

and nitrogen. Prior to the Balongan refinery, the technology from the previous refinery was

not able to process the raw material effectively when the oil growth from Duri increased.

Currently, the feed used at the Balongan refinery is a mixture of Duri, Minas, and Nile Blend

crude oil with a ratio of 45:35:24.

The oil refinery in Balongan was established in 1991 under the name Export Oriental

Refinery I (EXOR I). In subsequent developments, the operation of the refinery changed its

name to PERTAMINA Refinery Unit VI Balongan. The refinery was inaugurated on January

24, 1995 by President Soeharto, who had previously been delayed (January 30, 1995) due to

damage to the Residue of Catalytic Cracking (RCC) which was the most important part of the

damage.

This RCC unit converts the residue into more valuable oil (about 62% of the total

feed). By utilizing this residue, you will get more profit, because the residue you wasted can

be minimized. The capacity owned by this unit is around 83,000 BPSD which is the largest in

the world at this time. With the Balongan oil refinery, the domestic oil refinery production

capacity becomes 1,074,300BPSD. Production of the Balongan oil refinery accounts for

about 34% of the fuel marketed in Jakarta and its surroundings.

In carrying out its duties, PT. PERTAMINA (Persero) RU VI Balongan has a vision

and mission as follows:

7
Visi Menjadi Kilang Terkemuka di Asia Tahun 2025
Misi 1. Mengolah crude dan naptha untuk memproduksi BBM, BBK,

Residu, NBBM dan Petkim secara tepat jumlah, mutu, waktu dan

berorientasi laba serta berdaya saing tinggi untuk memenuhi

kebutuhan pasar.

2. Mengoperasikan kilang yang berteknologi maju dan terpadu

secara aman, handal, efisien dan berwawasan lingkungan.

3. Mengelola aset RU VI Balongan secara profesional yang

didukung oleh sistem manajemen yang tangguh berdasarkan

semangat kebersamaan, keterbukaan dan prinsip saling

menguntungkan.

8
2.3. PT. PERTAMINA (Persero) RU VI Balongan Organization Structure

Figure 1 PT. PERTAMINA (Persero) Organization Structure

PT. PERTAMINA (Persero) RU VI Balongan has an organizational structure that has

its respective functions. The purpose of making the organizational structure is to clarify and

reinforce the position of a division in carrying out tasks. Thus, organizational goals can run

more organized and easier. The organizational structure of RU VI Balongan as shown in the

picture above has the following functions and responsibilities:

1. General Manager

The main task of the General Manager is to direct, monitor, and evaluate all activities

in Refinery Unit VI in accordance with the business unit's vision and mission which includes

processing development activities, managing refinery operations, refinery reliability, refinery

9
development, supply chain operations, procurement, and other supporting activities for

achieve the company's target in Refinery Unit VI.

2. Senior Man. Op & Manufacturing

Senior Man's main duties. Op & Manufacturing is to direct, monitor, and evaluate the

preparation of refinery operation plans, refinery operation activities, equipment condition

assessment, turn around / overhoul maintenance, routine and non-routine maintenance,

procurement of goods and services, procurement of raw materials, intermedia, and gas,

revenue, distribution, storage management, management of the oil flow accounting system,

and HSE operations as well as demonstrating HSE's commitment to every activity / business

process so that operations run smoothly and safely at Refinery Unit VI.

3. Production-I Manager

The main duties of the Production-I Manager are to direct, monitor, and evaluate the

system and work procedures of refinery operations, plan for operations and activities of

refinery operations, procurement of products, goods and services, revenue management,

distribution and storage management, management of the oil flow system, management HSE

program quality and operations in order to support all refinery operational activities in

processing crude oil into BBM / NBBM products in a productive, efficient, safe and

environmentally friendly manner, as well as demonstrating HSE's commitment in every

business activity / process according to company planning at the Refinery Unit VI.

4. Production-II Manager

The main duties of the Production-II Manager are to direct, monitor, and evaluate the

system and work procedures of refinery operations, plan for operations and activities of

refinery operations, procurement of products, goods and services, management of revenues,

distribution and storage management, management of the oil flow system, management

quality, and shows HSE's commitment in every activity / process business operation of the

10
HSE program in order to support all refinery operational activities in processing crude oil

into BBM products, NBBM, productively, efficiently, safely and environmentally friendly in

accordance with company planning in the Refinery Unit VI

5. Refinery Planning & Optimization Manager

The main duties of the Refinery Planning & Optimization Manager are to direct,

coordinate and monitor the evaluation of planning, development / management of raw

materials and refinery products based on economic studies, refinery capabilities and market

conditions; evaluation of procurement, acceptance, and distribution of raw materials;

evaluation of refinery operations; product development evaluation; Linear Programming

management and customer relationship management in order to support the most effective,

efficient and safe operational activities as well as demonstrating HSE's commitment to every

activity / business process at Refinery Unit VI.

6. Maintenance Planning & Support Manager

The main duties of the Maintenance Planning & Support Manager are to direct,

monitor, and evaluate maintenance activities and demonstrate HSE's commitment to every

activity / process business of refinery equipment which includes company strategy plans,

quality management, strategies and plans and reliability, assessment of refinery conditions,

maintenance activities, vendor management, budget, and data maintenance of all refinery

equipment to provide assurance of the feasibility of operating equipment according to

government regulations and / or standards & codes as well as the applicable HSE aspects so

that equipment can be operated on schedule to meet the planned production targets at

Refinery Unit VI.

7. Maintenance Execution Manager

The main duties of the Maintenance Execution Manager are to direct, monitor, and

evaluate turn around and overhaul (plant stop) activities, routine & non-routine maintenance

11
of refinery equipment, construction and maintenance of building assets, social facilities and

other public facilities, heavy equipment, transportation, rigging, scaffolding, optimizing the

quality management of workshop tools, correcting actions during refinery operations to

ensure refinery equipment is ready to operate with the highest level of reliability, optimal

equipment performance, becoming a role model, and demonstrating HSE's commitment in

every activity and fulfilling HSE excellence in the Refinery Unit .

8. T/A (Turn-Around) Manager

The main task of the T / A Manager is to coordinate, direct, control, monitor, and

evaluate all stages of the work process turn-around (TA / PS / COC) and over-haul (OH)

equipment, starting from the preparation / planning, implementation & process stages. start-

up, to post TA-OH according to best practice / TA guidelines, guidelines for procurement of

goods & services, government regulations, applicable standards & codes in an effort to

support the reliability of operation of refinery equipment so that all the repaired and

overhauled equipment can be operate safely and reliably until the next TA-OH schedule, to

support meeting the planned production targets at Refinery Unit VI.

9. Engineering & Development Manager

The main duties of the Engineering & Development Manager are to direct, monitor,

control, and evaluate the preparation of a refinery operation work system if there is a

modification / revamp / new unit, refinery development activities, technology development,

product development, management of refinery operations, management of procurement of

goods and services, management HSE program, management of investment budgets to

support processing operations based on the results of identification of potential risks so that

an excellent performance can be managed that makes a positive contribution to the company

and is customer-oriented, productivity, and safety of the Refinery Unit VI refinery.

10. REL Manager

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 The main duties of the REL Manager are to coordinate, plan, monitor, and evaluate

the implementation of refinery reliability including the establishment of refinery maintenance

strategies (budget, strategy and plans), technology development, assessment / inspection of

refinery conditions, planned refinery maintenance (including TA and OH) and procurement

of goods. and services related to the operational needs of refinery maintenance as well as

demonstrating HSE's commitment in every activity / process business in an effort to achieve

an optimal level of refinery reliability and safety in accordance with the work procedures

applicable in the Refinery Unit

11. Procurement Manager

The main task of the Procurement Manager is to direct, monitor, and evaluate the

system of work procedures for procurement, procurement of goods and services,

management, receipt of goods and services, distribution, warehouse management, service

procurement cooperation agreements and facility support and demonstrate HSE's

commitment in every activity in the function. Procurement Refinery Unit VI.

12. HSE Manager

The main task of the HSE Manager is to direct, monitor, and evaluate the

implementation of HSE aspects in Refinery Unit VI which includes preparation, socialization

& recommendations for HSE policies & STK, identification of HSE risk, mitigating HSE

risk, enhancing HSE culture, implementing HSE program operations, HSE investigations,

provision of HSE equipment and facilities, HSE regulation & standard code compliance as

well as HSE audits so that prevention and response to emergency, environmental

preservation, occupational safety and health activities can be achieved in accordance with the

plan in order to achieve HSE excellence.

13. General Affairs

13
 The main task of General Affairs is to direct, monitor and evaluate activities related to

relations with regulators, the media and stakeholders, customer relations (internal &

external), company credibility, external and internal communication, Corporate Social

Responsibility (CSR) / Community Development (CD ) / Community Relations (CR),

corporate documents and literature, corporate activity, security management, security culture,

operational security programs, emergency programs, management of security equipment and

facilities, as well as security regulation compliance to support operational activities to run

effectively and optimally in function Refinery Unit VI.

2.4. Production Process

2.4.1. Hydro Skimming Complex Unit (HSC)

2.4.1.1. Distillation and Treating Unit (DTU)

DTU consists of a Crude Distillation Unit (Unit 11), Amine Treatment (Unit 23), Sour

Water stripper (Unit 24), Sulfur Plant (Unit 25) and Caustic Soda (Unit 64). DTU is the first

unit in a series of processing crude oil into its products and there are also several treating

units that process gas and water flows to reduce and water to reduce sulfur and ammonia

content.

1. Unit 11: Crude Distillation Unit (CDU)

The CDU was built to process the Indonesian oil mixture of 125,000 MBSD (828.1

m3 / hour). This crude oil mixture consists of 50% Crude Oil Duri and 50% Crude Oil Minas.

The unit built by Pertamina's EXOR-1 project consists of two sections, namely:

a. Crude Distillation

Designed to distill crude oil mixtures to produce condensed overhead distillate, gas oil

and residue. The CDU inlet in the form of a mixture of Minas crude and thorns is pumped

14
using P-101 A / B to V-101 A and V-101 B and has passed 5 Heat Exchangers (HE) arranged

in series E-101 ~ 105 where crude is heated to reach temperature 147 °C using waste heat

from the products produced by the fractionator. In V-101 A and V-101 B crude is washed

from salts which can damage the catalyst and the reaction in the reactor. The washer used is a

mixture of Service Water (SW) and Stripped Sour Water (SSW). The mixture of oil and

water will form an emulsion, so that additional chemical compounds are needed as a

demulsifier. This washer unit consists of two vessels, namely V-101 A and V-101 B. Fresh

water as a washer first enters the V-101B because the oil in the vessel has less salt content

because it has been washed in V-101 A with washer derived from V-101 B, so it is hoped that

the unsaturated fresh water can bind the residual salt more effectively.

Crude oil that has been clean of salt undergoes preheating through 5 HE pieces before

entering the furnace, the temperature reaches 280 °C before entering the furnace. Preheating

is needed to prevent cracks in the furnace due to too high a temperature and can reduce the

amount of fuel used in the furnace. Crude that comes out of the furnace reaches a temperature

of 364 oC, then enters the main fractinator on tray 31.

b. Overhead fraksinasi dan Stabilizer

Designed for the continued distillation of overhead condensate into LPG, Naphtha and

kerosene products. This unit is also designed to process a mixture of wild naphtha from gas

oil and Light Cycle Oil (LCO) Hydrotreater. This unit can operate well in capacities between

50-100% of design capacity with an On Stream factor of 0.91. The products produced from

CDU are naphtha, kerosene, Light Gas Oil (LGO), Heavy Gas Oil (HGO) and Atmospheric

Residue.

2. Unit 23: Amine Treatment Unit

Unit ini berfungsi untuk mengolah sour gas serta untuk menghilangkan kandungan

H2S yang terikat dalam sour gas. Proses yang dipakai adalah SHELL ADIP, dengan larutan

15
DIPA (Diisopropanolamine) sebagai larutan penyerap. Kadar larutan DIPA yang digunakan

adalah 2 kgmol/ m3.

This unit is consist of three main components:

a. Off Gas Absorber, to process off gas from CDU, ARHDM, GO HTU. The results are

used for the fuel gas system and the Hydrogen Plant gas feed. Capacity 18522 N m3 /

hour.

b. Residue Catalytic Cracking (RCC) Unsaturated Gas to process sour gas from the RCC

unit and the output to the fuel gas system. The capacity is 39252 N m3 / hour.

c. Amine Regenerator which functions to regenerate the amine solution that has been

used in the two absorbers above, with a capacity of 100% of the gas that comes out of

the two absorption towers.

The product specification is that the H2S content that comes out of each tower is a

maximum of 50 ppm in volume.

3. Unit 24: Sour Water Stripper Unit

The SWS unit is broadly divided into two SWS sections and a Spent Caustic Treating

section.

a. Sour Water Stripper (SWS)

The SWS section consists of two trains whose differences are based on the feed in the

form of treated wastewater. The processing capability is designed for train no.1 of 67 m 3 /

hour and for train no.2 of 65.8 m3 / hour.

i Train no.1: processing waste water from CDU, ARHDM and LCO HTU.

ii Train no.2: processing wastewater originating from the RCC Complex.

The function of the two trains is to remove H 2S and NH3 in the remaining process

water. Then the treated water is channeled to the Effluent Treatment Facility or asked to

16
return to the CDU and ARHDM. Meanwhile, gas that has a high enough H 2S content (sour

gas) is used as feed in the Sulfur Plant.

b. Seksi Spent Caustic Treating

This section has a capacity of 17.7 m3 / day. Spent Caustic section originating from

several operating units, then the entire spent caustic is neutralized with sulfuric acid (H2SO4)

and channeled to the effluent facility.

Judging from the processed Caustic Spent source, this section can be divided into two

types, namely:

i Spent caustic that is routinous and intermittent originating from the following

units:

a) LPG Treater Unit (LPGTR).

b) Gasoline Treater Unit (GTR).

c) Propylene Recovery Unit (PRU).

d) Catalityc Condensation Unit (Cat. Cond.).

ii Spent Caustic is regeneration from units:

a) Gas Oil Hydrotreater.

b) Light Cycle Oil Hydrotreater.

4. Unit 25: Sulphur Plant

Sulfur Plant is a unit for taking sulfur elements from the “off gas” amine treatment

unit and H2S Stripper train no.1 Unit SWS. This unit consists of a Claus unit which functions

to produce sulfur liquids and a solid sulfur loading or warehouse facility.

In this unit there is a payment facility to process the residual gas from the Claus unit,

which also burns gases that contain a lot of NH 3 from the SWS unit. The capacity of this unit

is designed to produce sulfur with a capacity of 30 tons per day.

17
2.4.1.2. Naphtha Processing Unit (NPU)

NPU is a new project of PT. PERTAMINA (Persero) RU VI Balongan which is

known as the Balongan Blue Sky Refinery Project (KLBB). This unit was built to process

and increase the octane value of napthta. Increasing the octane number is done by removing

impurities that can decrease the octane value such as propane, butane, and pentane. NPU is

composed of three units, namely the Naphtha Hydrotreating Unit (Unit 31), Platforming and

Continuous Catalyst Regeneration (Unit 32), and Penex (Unit 33).

1. Unit 31: Naphtha Hydrotreating Unit (NTU)

The Naphtha Hydrotreating Process (NHDT or NTU) unit with code 31 facilities is

designed to process naphtha with a capacity of 52,000 BPSD or (345 m3 / hour) of straight

run naphtha. The main function of NHDT can also be called cleaning operation. Thus, this

unit is critical for the next (downstream) unit operation, namely platfoming and penex. The

Platformer results are in the form of naphtha with an octane value of> 98, while the Penex

results have an octane value of> 82, so that the two can be mixed according to product needs.

For Premium an octane number of 88 is needed, for Pertamax an octane number is needed for

92, and for Pertamax Turbo an octane number is needed for 98. The NHDT unit consists of 4

parts, namely the Oxygen Stripper, Reactor Section, Naphtha Stripper, and Naphtha Splitter.

2. Unit 32: Platforming (PLT)

The Platforming process unit with code 32 facility is designed to process 29,000

BPSD (192 m3 / hour) heavy hydrotreated naphtha received from the NHDT process unit

(facility code 31). The purpose of the platforming process unit is to produce aromatics from

naphtha and paraffin for use as motor fuel because it has high octane number (> 98). The

Platforming Unit consists of a reactor section, a net gas compressor section, a debutanizer

section, and a recovery plus section.

3. Unit 32: Continuous Catalyst Regeneration (CCR)

18
 The task of the CCR unit is to regenerate the activated catalyst due to the reforming

reaction in the platforming section.

4. Unit 33: Penex

The purpose of the Penex unit (Pentane Heptane Isomerization) is to carry out the

catalytic isomerization of pentane, hexane and a mixture of the CCR Process Unit. The

reaction that occurs uses hydrogen at atmospheric pressure, and takes place in the fixed

bedcatalyst at certain operations that can direct the isomerization process and minimize the

hydrocracking process. This process is very simple and hassle free. Operation at low

pressure, low temperature, high LHSV, and low partial hydrogen pressure.

2.4.2. Distillation and Hydrotreating Complex Unit (DHC)

2.4.2.1. Atmospheric Residue Hydrodemetallization (Unit 12/13)

The ARHDM unit is a unit that processes Atmospheric Residue (AR) from the CDU

into products that are prepared as feeds for RCC. The ARHDM unit operates with a capacity

of 58,000 BPSD (384 m3 / hour). Apart from processing residues, this unit also functions to

reduce the metal content of nickel (Ni), vanadium (V), and carbon (C) carried by the residue

from the CDU unit.

The ARHDM unit consists of 2 twin modules, namely modules 12 and 13 which have

the same unit arrangement and consist of three reactors. The two modules meet in the

fractionator input stream. The raw material used is AR.

1. feed

Namely, preheating and filtering the dirt on the feed using a filter before it is

distributed to the surge drum feed. The AR feed used is obtained directly from the bottom of

19
the CDU with a temperature of 145 °C (Hot AR) or AR from a 42-T-104 A / B tank with a

temperature of 50 °C (Cold AR).

After the two feeds are combined and heated, the feed passes through HE until it

reaches a temperature of 273 °C and then goes to a filter which cleans the crude from the

solid containment which can cause deposits on the surface of the catalyst in the first reactor to

reduce the reactor load. In this section there are 3 filters that work automatically based on

pressure, consisting of two 25 micron filters, and one temporary filter, which is a

modification of the design with a larger pore size so that the flow rate is larger and the

filtration is imperfect. . This temporary filter is not used under normal conditions because it

can accelerate the increase in ΔP in the reactor.

The filtered feed is streamed to the Filtered Feed Surged Drum 12-V-501 which

functions as a reservoir for the initial feed to be pumped into the furnace. Then the feed is

heated back to the furnace before being flowed in parallel to modules 12 and 13. The furnace

works based on the Catalyst Average Temperature (CAT) which is determined by the

expected catalyst performance, namely the percentage of Micro Carbon Residue (MCR) in

oil.

2. Reaction

Each module consists of three reactors arranged in series with the same specifications.

Because the Hydrotreating reaction is exothermic, the temperature of the oil / gas mixture

will rise when it reacts. To control the temperature and to control the reaction speed, cold

quench recycle gas is injected. The reactor effluent is then fed to the cooling and separation

section.

3. Cooling and Separation

20
 The first cooling is carried out in the exchanger where some of the heat is taken by the

combine feed reactor, then the effluent feed reactor flows to the Hot High Pressure Separator

(HHPS).

The function of the HHPS is to take the residueoil from the effluent reactor before it is

cooled, because the residue containing aluminum deposits can clog the exchanger in the

effluent vapor cooling train. With a temperature of 37 °C the residue has enough sources to

separate napha, kerosene and gas oil products in the Atmospheric Fractionator.

The hot liquid flow from HHPS flows to the Hot Flow Pressure Separator, where the

steam which is separated from the Hot Liquid in this HHPS contains a lot of H2, NH 3, CH4,

light gases, hydrocarbons and other hydrocarbon liquids. The steam is then cooled in the Heat

Reactor, where the heat from this HE will be transferred to the Combine Feed Reactor. After

that, the steam mixture stream is flowed to the Effluent Air Cooler into the Cold Hight

Pressure Separator (CHPS). Recycle Gas, which is rich in hydrogen and separated from oil

and water, goes to the recycle gas compressor and partially to the Hydrogen Membrane

Separator unit for purification.

Because it is possible that some oil and water are not entirely separated in CHPS, not

all oil and water from CHPS are flowed to the Cold Low Pressure Separator (CLPS). The

water collected in the CLPS bottom drum is flowed to SWS, while the oil is heated first with

HE before flowing into Atmospheric Fractionator.

Liquid from the bottom of the HHPS is flashed in the Hot Low Pressure Separator

(HLPS). The H2-rich steam is separated for recovery and the heavy oil product is combined

with the HLPS module 13 product which is flowed to the fractionator. Flash gas from HLPS

modules 12 and 13 is cooled through an exchanger and air cooler before flashing Cold Low

Pressure Drum (CLPFD), Flash H2-rich CLPFD gas is channeled into the make-up gas

21
compressor to be compressed and returned to the ARHDM unit. The light liquid is flashed

back together with the liquid from the CHPS to the CLPS.

4. Recycle Gas

The hydrogen rich gas stream from the CHPS is halved, partly returned to the reactor

by the Recycle Gas Compressor and part of the flow (Bleed Stream) to the Membrane

Separation Unit.

5. Fractionation

The fractionation section separates ARHDM products into naphtha, kerosene, diesel

and Hydrodemetallized Atmospheric Residue (DMAR). Obtained with an Atmospheric

Fractionator assisted by two strippers. Before being shipped out, the naphtha is purified in the

naphtha stabilizer and kerosene in a clay treater.

Atmospheric Fractionator consists of two sections, namely the roof section (top) has

32 trays with a diameter of 3.2 m, the bottom section has 15 trays with a diameter of 3.66 m.

The distance between the trays in the two sections in the column is 610 mm. Heavy Oil

products from HLPS enter the fractionator on tray 33. Cold Feed from CLPS enters the

fractionator on tray 28 (tray above the flash zone). In the further section (superheated steam)

in the convection section of the furnace.

Atmospheric Fractionator Products:

a. Sour gas

b. Unstabilized Naphtha

c. Kerosene

d. Gas Oil

e. DMAR as RCC feed

Overhead vapor from the fractionator is partially condensed in the Fractionator

Overhead Air Cooler. The vapor and liquid are flowed to the overhead Accumulator. The

22
pressure of the vapor from the Air Cooler is increased by turning off the gas compressor. This

compressor has two stages where the stage 1 compressor outlet is cooled at the interstage

cooler and the liquid condensate is separated in the interstage KO drum, then the vapor is

compressed on the second stage of the compressor. Unstabilized Naphtha from the Overhead

Accumulator is mixed with the compressed vapor stream. This two-phase stream is further

cooled in a cooler. Unstabilized Naphtha, sour water and net off gas are separated in Sour

Gas Separator. Off Gas goes to fuel gas treating, while unstabilized naphtha is heated before

treating in the Naphtha Stabilizer then cooled and then sent to the tank.

Feed for Gas Oil Stripper is taken from tray 24 and refluxed to tray 22. The product

gas oil can be sent directly to the Gas Oil Hydrotreating Unit and then to the product tank.

Kerosene is flowed from the down comer on the tray to 10 fractionators. Then it is

reheated with a Bottom Fractionator Stripper Vapor on the keroseneside cut stripper to be

returned to the fractionator through the 9th tray, then processed in a clay treater to improve

color stability before being sent to the storage tank.

The Bottom Fractionator that produces the DMAR is pumped and divided into two

flows:

a. The most flow is used to heat the cold feed of the fraksinator and then heat the

AR which will enter the Feed Filter.

b. A slight stream is used to heat the Kerosene Stripper Reboiler.

i. Hydrogen and Desulfurization

The purpose of this process is to remove the sulfur content in the feed gas

having sulfur content as allowed to enter the Reformer, because sulfur is toxic

to the catalyst in the Reformer.

ii. Steam Reforming

23
 Aims to process or change the hydrocarbon gas that is reacted with steam into

hydrogen, CO and CO2 gas. Production depends on the speed of the feed to

the reformer and the degree of conversion achieved.

iii. Hydrogen Purification

Hydrogen purification is carried out in two stages, namely:

a) High Temperature Shift Converter (HTSC), aims to convert CO into

CO2 by reaction:

CO + H2O CO2 + H2

b) Pressure Swing Adsorption (PSA)

After going through the reaction in HTSC, the feed is cooled and the

condensate in the feed gas is separated in the Raw Gas KO Drum before

entering the PSA unit. PSA plant is designed to purify hydrogen gas

continuously. The flow out of the PSA unit is:

1. High pressure pure hydrogen.

2. Tail gas containing impurities at low pressure.

The two streams above combine and can be sent directly to the RCC unit or further

cooled before dispensing to the tank. Part of the bottom fractionator in the down stream is

used as a back wash in the feed filter and then recombines with the DMAR product stream to

the RCC and tank.

2.4.2.2. Hydro Treating Unit (HTU)

1. Hydrogen Plant (Unit 22)

Hydrogen Plant (Unit 22) is a unit at PT. PERTAMINA (Persero) RU VI Balongan

which is designed to produce hydrogen with 99% purity as much as 76 MMSFSD with feed

and capacity according to design. This plant is designed with feed from Refinery Off Gas and

Natural Gas.

24
 The main function of this unit is to reduce or eliminate impurities included with

petroleum or its fractions by the hydrogenation process, which is to react these impurities

with hydrogen produced from the Hydrogen Plant. Crude oil contains relatively high

impurities, including nitrogen, organic sulfur compounds and metal compounds.

Hydrogen gas products from the Hydrogen Plant are used to meet the needs of the

ARHDM unit, the LCO Hydrotreater Unit and the Gas Oil Hydrotreater Unit.

The basic process of the Hydrogen Plant includes:

a. Hydrogenation and Desulfurization

b. Stream Reforming

c. Hydrogen Purification

2. Gas Oil Hydrotreater

This unit processes unstable and corrosive Gas Oil (containing sulfur and nitrogen)

with the help of a catalyst and hydrogen into gas oil that meets market requirements with a

capacity of 32,000 BPSD (212 m3 / hour).

Feed for gas oil is obtained from the Crude Distillation Unit (CDU) and Atmospheric Residue

Hydrometalization Unit (ARHDM). The hydrogen make-up will be supplied from a hydrogen

plant that has been pre-treated by the steam methane Reformer and Pressure Swing

Adsorption (PSA) unit. The hydrtreating catalyst used contains nickel / molybdenum oxide in

a round alumina base or extrudate.

GO HTU consists of two sections, namely:

a. Reactor section, for the reaction process with a catalyst and hydrogen.

b. Fractionation section, to separate the reaction gas oil from other products, such as

off gas, wild naphtha, hydrotreated gas oil.

3. Light Cycle Hydrotreating Unit (Unit 21)

25
 LCO HTU is a refinery that processes Light Cycle Oil from the RCC unit which still

contains a lot of organic compounds, including sulfur and nitrogen.

The aim of this unit is to remove sulfur and nitrogen from the feed without significant

changes in the boiling range, so that the products produced meet marketing requirements and

specifications. The capacity of this LCO HTU unit is 15,000 BPSD (99.4 m 3 / hour) using a

UOP S-19 M catalyst.

The process flow in this unit includes:

a. Feed

This feed unit is Light Cycle Oil from the RCC unit and storage tank. The LCO

from RCCU passes through the feed filter to remove solid particles larger than 25

microns, then enters the feedsurge drum 21-V-101. Meanwhile, the LCO from the

tank goes directly to the surge drum feed 21-V-101.

The water following the LCO from the tank will be separated in the bottom feed

of the surge drum and what is not separated will be retained by a blanket wire

mesh so that it flows into the suction feed pump. After that the water is flowed to

the Sour Water Header. LCO together with recycled hydrogen gas into the

Combined Feed Exchanger 21-E-101 A / B.

b. Reactor

Feed and recycle gas are preheated by the effluent reactor in the Combined Feed

Exchanger 21-E-101 A / B, then the LCO and hydrogen mixture combines and

goes directly to the charge heater 21-F-101 and heated to the reaction

temperature. The feed then enters the top of Reactor 21-R-101 and is evenly

distributed over the surface of the catalyst bed through the inlet of the vapor /

liquid tray. Because of the exothermic reaction that occurs in the reactor, the

26
 temperature of the feed that comes out of the reactor will be higher than the feed

that enters the reactor.

Before leaving, water is injected into the reactor effluent to dissolve the

ammonium salt formed by combining H2S and NH3 in the reactor, because

ammonium can poison the catalyst if it accumulates enough in the recycle gas.

c. Compressor

This section consists of two parts, namely the Make-up Compressor and the

Recycle Gas Compressor. The pressure in the reactor is controlled by hydrogen

imported from the H2 plant with increased pressure using a 2 stage Make-up

Compressor and the H2 is fed to the discharge Recycle Gas Compressor.

The make-up stream of hydrogen gas enters the reactor section to maintain the

pressure in the High Pressure Separator. The make-up gas H2 and recycle gas go

together to the Combined Feed Exchanger 21-E-101 A / B and as a quench to

Reactor 21-R-101 between the two catalyst beds.

d. Fractionation

This section serves to separate LCO from the reaction results from other products

such as off gas, wild naphtha and hydrotreated light cycle oil.

The LCO effluent that leaves the reactor then enters the separator through the

distributor inlet where the liquid hydrocarbons, water and gas are released and

will separate by themselves. The hydrocarbons collected in the separator, then

separated by fractionation, the LCO hydrotreated product enters the Coalescer to

separate it from water and is dried into a vessel containing salt before being sent

to the storage tank.

The distribution of feeds and processed products from this LCO HTU unit

includes:

27
 i. The LCO Stock Feed was obtained from the RCC complex.

ii. UOP Hydrotreating catalyst contains nickel / molybdenum (S-12) and

cobalt / molybdenum (S-19 M) oxides in an alumina base and is made round

or extrude.

iii. Hydrogen will be supplied from the hydrogen plant unit.

LCO HTU products, are:

i. LCO that has been processed is immediately stored in the tank to be ready

to be marketed.

ii. Hydrotreated Light Cycle Oil is used for product blending without having

to be processed again.

iii. Off Gas is sent to the Refinery Fuel Gas System

iv. Wild naphtha is sent to the CDU or RCC unit for further processing.

2.4.3. Residue Catalytic Cracking Complex Unit (Unit Complex RCC)

The RCC complex is a combination of several units at the RU VI Balongan refinery

that functions to process Reduced Crude into high-value petroleum products, such as: LPG,

Gasoline, Light Cycle Oil, Decant Oil, Propylene and Polygasoline.

This unit functions as an advanced oil refinery (Secondary Process) to obtain added

value from residue processing by cracking using a catalyst. This unit is closely related to the

Unsaturated Gas Plant Unit which will manage the peak products of the RCC Main Column

Unit into Stabilized Gasoline, LPG and Non Condensable Lean Gas. Products produced from

the RCC Complex unit are Overhead Vapor Main Column, Light Cycle Oil and Decant Oil.

RCC is designed to process Treated Atmosperic Residue from ARHDM units with a

design of 29,500 BPSD (35.5% vol.) And Untreated Atmospheric Residue from CDU units

with a design of 53,000 BPSD (64.5% vol.). installed capacity is 83,000 BPSD.

28
 In this RCC unit, there is a reactor, regenerator, column fractionator, catalyst cooler,

main blower and CO Boiler. The hydrocarbon feed to the unit is heated by product flow and

is cracked by the heater brought by the Regenerated Catalyst in the reactor system.

This cracking reaction occurs in the reactor riser. After reacting with the feed, the

catalyst is separated from the hydrocarbons to minimize secondary cracking and then sent to

the regenerator to be regenerated, where the coke deposited on the catalyst can be reactivated

to process the next hydrocarbon.

The hydrocarbon vapor leaves the top riser reactor to the main column in the

fractionation section. The catalyst spent flows from the stripper reactor into the upper

regenerator where the coke formed is burned with air.

The carbon in the coke form sticks to the catalyst as a byproduct of cracking. The

presence of coke on the catalyst reduces the activity of the catalyst. By using high heating

and enough air, the coke is in the upper regenerator and it is adjusted so that the coke

becomes CO (Partial Combustion) so that the heat generated is not too high.

Fuel gas containing CO exits the upper regenerator through the cyclone where the

following catalyst particles are removed. High pressure steam is produced in the CO Boiler

from the heat from combustion of CO to become CO2. The existence of a catalyst cooler

takes excess heat from the Boiler Feed Water (BFW) regenerator and converts it into steam.

The excess air in the Lower Regenerator is used to burn the remaining coke on the catalyst

and direct the combustion to CO2.

The hot catalyst is then flowed from the lower regenerator to the riser reactor, then it

is circulated back from the reactor to the regenerator. The catalyst flow in the rector-

regenerator system is the count of the RCC unit. The hydrocarbons resulting from the

cracking reaction are flowed from the reactor to the column fractionator, to be separated into

29
Overhead Vapor, Light Cycle Oil (LCO) and DCO. The overhead vapor is then sent to unit

16 (unsaturated gas plant) to be separated into Unsaturated LPG, naphtha RCC.

2.4.4. Light End Unit (LEU)

LEU is a follow-up unit after the RCU (Residue Catalytic Unit) which functions to

process RCU output products into final products with sale value. LEU consists of five units

with different tasks and end products. The five units are the Unsaturated Gas Plant (Unit 16),

the LPG Treatment Unit (Unit 17), the Naphtha Treatment Unit (Unit 18), the Propylene

Recovery Unit (Unit 19), and the Catalytic Condensation Unit (Unit 20).

1. Unit 16: Unsaturated Gas Plant

This unit serves to separate the over-head product of the RCCU column into stabilized

naphtha, LPG and non-condensable lean gas, some of which will be used as gas lift before

being processed in the Amine Unit as off gas. The products produced from this unit are

Gasoline (RCC Naphtha), Untreated LPG and Non-condensable Lean Gas / Off Gas.

The Unsaturated Gas Plant is designed to process 83,000 BPSD AR. This unit produces

Sweetened Fuel Gas which is sent to the Refinery Fuel Gas System for further processing.

The unit also produces Untreated LPG which will be further processed in the LPG Treatment

Unit (Unit 17) and naphtha which will be further processed at the Naphtha Treatment Unit

(Unit 18).

Overhead products from RCCU are off gas (a mixture of methane, ethane, and H2S), LPG (a

mixture of propylene and propane) and naphtha (a mixture of butane, butylene and C5 +) into

the 16 V-101 vessel, while heavy fractions will be pumped in. into column 16 C-101.

The light fraction of 15 V-106 will enter the Wet Gas Column (WGC) two levels then to HE

until finally into the 16 V-104 vessel. The light fraction will enter the absorber 16 C-101

while the heavy fraction will be pumped into the stripper 16 C-103 after going through HE 16

E-108. In the stripper, the light fraction that is still included in the incoming heavy fraction

30
will be returned to the 16 V-104 vessel, while the heavy fraction that has been stripped (LPG

and naphtha) will enter the 16 C-104 debutanizer. In this debutanizer, LPG and naphtha will

be separated for further processing in Units 17 and 18, respectively.

The heavy fraction of the 15 V-106 vessel will combine with the light fraction of the 16 V-

104 vessel in the 16 C-101 absorber to extract the heavy fraction. The ascorbent used was

naphtha from the debutanizer. Because the absorption process will occur well at low

temperatures, the naphtha as an absorbent is first cooled by chilled water using freon. The

light fraction from the absorber is flowed into the 16 C-102 absorber so that more heavy

fraction is taken up. The absorbent used is LCO. Inside this absorber there is a foul ring

which functions to increase the contact surface area between the fraction to be absorbed and

the absorbent. The light fraction of its output will enter the amine unit and some will become

off gas. Meanwhile, the heavy fraction of the absorber will enter the vessel 16 V-104 towards

the stripper.

2. Unit 17: LPG Treatment Unit

This unit functions to purify LPG products from Unsaturated Gas Plant by taking

mercaptan compounds and other organic sulfur and turning them into disulfide compounds.

The product of this unit is Treated Mixed LPG which is then sent to the Propylene Recovery

Unit (Unit 19). The LPG Treatment Unit is designed to process 22,500 BPSD of feed from

the Debutanizer product at the Unsaturated Gas Plant.

Process Description:

a. H2S Extraction System

Unsaturated LPG passes through strainers 17 S-101 to remove solid particles

larger than 150 microns. Then enter the H2S Fiber Film Contactor where there

will be contact with caustic (NaOH). This Fiber Film Contactor is in the form of

31
 hair-like fibers made of metal whose purpose is to expand the contact surface

between untreated LPG and NaOH. The reactions that occur are:

NaOH + H2S → Na2S + H2O

The NaOH used is 14% wt and will only be discarded when it becomes 7% wt

because the NaOH cannot be regenerated. Separation between the LPG phase and

the caustic solution takes place in the separator, where the used NaOH is

discarded, while the LPG which has been removed from the H2S is channeled into

the mercaptan extraction system.

b. Mercaptan Extraction System

The LPG from the H2S extraction system then enters the mercaptan extraction

system which consists of two levels. The contractor used is Fiber Film with a

mercaptan binder in the form of caustic (NaOH) as well. The reactions that occur

are:

NaOH + RSSH → Na2SR + H2O

The NaOH used can be regenerated with oxygen and a catalyst in a 17 V-105

vessel, the reaction is:

Na2SR + O2 + H2O → DSO + NaOH

DSO which is formed from the above reaction is shaped like oil and dissolves in

naphtha so that to separate DSO from NaOH you can use Fiber Film Contactor

with absorbent in the form of naphtha. NaOH that has been cleared from DSO

can be recycled.

c. Aquafining
32
 The LPG that has been free from mercantile will be washed with water to remove

a small amount of caustic entrainment. The LPG enters the top of the contactor

where it comes in contact with metal fibers which are wetted by circulating water.

The LPG and the circulated water solution flow counter current and through the

Shoud Contactor where the bound caustic is removed. The washed LPG is then

further processed at the Propylene Recovery Unit.

3. Unit 18: Naphtha Treatment Unit

This unit is designed to extract H2S and oxidize mercaptan sulfur in untreated

naphtha. To obtain product results with specifications including Doctor Test Negative,

mercaptan sulfur content <15 ppm-wt. The content of Na + (as sodium) is a maximum of 0.1

wt%. The product produced from this unit is Treated Naphtha.

This unit is designed to process 47,500 BPSD untreated RCC naphtha produced by

Unit 16 (Unsaturated Gas Plant) with a maximum content of 5 ppm-wt H2S and 90 ppm-wt

mercaptan. This unit is designed to operate at reduced capacity of up to 50%.

Process Description:

a. Oxidation and Extraction

Untreated RCC naphtha enters the caustic treating system through a parallel

basket strainer set, 18-S-101 A / B to remove any subsequent solids> 150 microns

in size. Air for oxidation is injected in the Upstream Fiber FilmContactor 18-A-

201/204 through the Air Sparger 18-M-101/102. Process air is filtered with Air

Filter 18-S-102 A / B, 104 A / B to remove sized solids. <5 micron.

RCC naphtha passes through the mercaptan extraction stage at the peak of 18-A-

201/204 then contacts the film material wetted by circulating caustic from the 18-

P-102 A / B caustic recycle pump. Circulating flow ± 20% vol. An untreated

RCC naphtha flow. The reactions that occur are:

33
 2RSH + 2NaOH → 2NaSR + 2H2O

Separation of naphtha and caustic RCC phases in Phase Separator 18-V-101/102.

Hydrocarbons and caustic solutions enter down through 18-A-201/204 where H2S

extraction and mercaptan oxidation occur. The reactions that occur are:

2NaSR + ½H2O → RSSR + 2NaOH

2RSH + ½O2 → RSSR + H2O

2NaOH + H2S → Na2S + 2H2O

2Na2S + 2O2 + H2O → Na2S2O3 + 2NaOH

The caustic stream falls down and adheres to the fibers and flows into the dilute

phase at 18-V-101/102 to collect into one of the stored caustic solutions. The

naphtha RCC flows in the opposite direction to the caustic between the fiber

chambers and the discharge above the contactor.

At 18-V-101/102, the RCC naphtha stream passes through the coalescerPad 18-

A-202/205 to remove more caustic particles and then flows out of the separator at

the end. This combined parallel flow became a stream of treated naphtha after

joining a spent solvent from the regenerator system. The 18-A-201/204 and 18-V-

101/102 operate at pressures of 4.9 kg / cm3.g and temperatures of 38 oC.

Approximately 0.5% of the treated naphtha flow from 18-V-101/102 is used as

fresh solvent Unit 17. Spent solvent Unit 17 returns to RCC naphtha after back

pressure control valve goes to naphtha tank. Mercaptan and a little H2S contained

in RCC naphtha were extracted by caustic soda 6.6% wt. The extraction and

oxidation processes that occur produce excess water which can reduce the NaOH

concentration.

b. Caustic Replacement

34
 Fresh caustic 6.6% wt is replaced if the content decreases to 3.3% wt. Caustic

replacement does not interfere with unit operation. Spent caustic is discharged

through line spent caustic before suction from pump 18-P-102 A / B, 104 A / B

and collected in the spent caustic reservoir.

The 6.6% wt fresh caustic solution is pumped from the distribution header

manually through the 18-S-103/105 (Aqueus Basket Strainer) to 18-P-102 A / B

and 104 A / B until normal operating levels are sufficient. The 18-S-103/105

basket strainer removes particles> 150 microns in size.

The oxidation of sulfur mercaptide compounds is obtained from the extraction of

mercaptans by caustic solutions which are required in catalyst oxidation. The

concentration of oxidized catalyst in the caustic circulation is 200 ppm wt for the

first time, then the catalyst is injected per day as much as 0.45 kg / 20,000 bbls to

replace the lost and inactive by using a catalyst tube 18-A-203/206.

c. Aquafining

For entrainment washing in RCC LPG products with water continuously. Also,

water may be required in the phase separator if the RCC of naphtha becomes

cured and the caustic solution becomes water deficient.

Water is stored in the Water Break Tank (18-V-104). If necessary, the water is

pumped in a manual setting using the 18-P-101 (Water Addition Pump) pump to

18-V-101/102 via the 18-P-102 A / B and 104 A / B suction pipes. The pump can

also be used to service the H2S extraction and solvent wash systems in Unit 17.

The Aquafining System in the RCC LPG Treatment Unit is also serviced by 18-

V-104, pumped by 17-P-105 A / B (Water Metering Pump). Inhibitors are used to

help sweeten the naphtha, slow down gum formation and leave the alkyl

compounds behind the anti-knocking compounds in naphtha. The injection of this

35
 chemical is stored in the 18-V-103 inhibitor tank where it can store ± 0.5 m 3. each

tank refill takes every two days. The inhibitor is injected in places around the

upstream and downstream of each train treater with 18-P-105 A / B and C

(¬Inhibitor Injection Metering Pump).

4. Unit 19: Propylene Recovery Unit

This unit functions to separate Mixed Butane and process LPG C3 and C4 from Unit 16 to

obtain high purity propylene products (minimum 99.6%) which can be used as raw material

for the manufacture of Propylene Unit. The products produced from this unit are propylene

with an installed capacity of 7150 BPSD, propane and a mixture of butane. The process used

is the Selective Hydrogeneration Process (SHP) with the Huels reactor.

Feed originating from LPG Treatment which is a mixture of propane, propylene and a

mixture of C4 is pumped to C3 / C4Splitter, 19-C-101. The C4 mixture obtained from the

splitter is put into the storage tank and some are sent to Unit 20, while the propane and

proplen mixture enters the C3 / C4Splitter Condenser. The condensate formed enters the C3 /

C4 Splitter Receiver, where some of the C3 mixture is refluxed to the C3 / C4 Splitter and the

other causes are sent to the Solvent Settler.

In the Solvent Settler, the C3 mixture is removed from its sulfur content using caustic MEA.

Water in the Water Boot is sent to the Water Degassing Drum, then to the Sour Water

Stripper unit (Unit 24).

From the Solvent Settler, the C3 mixture was sent to the Wash Water Column to be contacted

with the phosphate solution in the opposite direction (Counter Current). The top product of

this column is separated from the water in the Sand Filter, while the bottom product is

partially recycled and partially stored in the Water Degassing Drum to be sent to unit 24.

The C3 mixture from the Sand Filter, is dried in C3 Feed Driers because the specification is

25 ppm. The output of Feed Driers is checked for moisture content for drier regeneration

36
purposes. The C3 mixture is then separated on the C3 Splitter, propylene vapor is formed in

the overhead and propane at the bottom. The propane is then sent to the holding tank, while

part of the propylene is refluxed and partially compressed to heat the propane in the C3

Splitter Flash Drum. The propylene formed was separated from its COS content in COS

removal, and separated from the metal in the Metal Treater.

From Metal Treater, propylene is fed to the SHP reactor to convert existing diene and

acetylene content into Mono Olefin to meet production requirements. The reactor output

propylene is cooled and sent to the storage tank with a propane content analysis.

5. Unit 20: Catalytic Condesation Unit

This unit functions to process the butane mixture from the Propylene Recovery Unit (Unit 19)

into gasoline with high octane number. The products produced from this unit are

Polygasoline and Butane.

This unit is designed to produce high molecular weight products using Soid Phosporus Acid

catalysts. It has a capacity of 13,000 BPSD with three parallel reactors. UOP Catalytic

Condensation is a unit designed to process Unsaturated Mixed Butane from LEU units.

The butane mixture feed from Unit 19 consisting of butylene, butane and propylene, enters

the Wash Water Column to be washed with a counter current phosphate solution. The butane

mixture together with the rectifier stream is pumped into the reactor so that the polymeration

reaction occurs into long chains C8 to C10. Because the polymeration reaction is an

exothermic reaction that releases heat, the reactor temperature will continue to increase. To

prevent coke from forming, the catalyst bed temperature is kept below 20 oC.

After leaving the reactor, the hydrocarbon chain enters the Flash Rectifier where part of it is

returned to the reactor and partly to the stabilizer. From the stabilizer, the bottom product in

37
the form of polygasoline is cooled and sent to the storage tank, while the overhead product,

which is butane, is washed with caustic and dried before entering the storage tank.

38
 Chapter 3

3. Corrosion in Distillation Column

3.1. Distillation Column

A distillation column is an essential item used in the distillation of liquid mixtures to

separate the mixture into its component parts, or fractions, based on the differences in

volatilities. Fractionating columns are used in small scale laboratory distillations as well as

large scale industrial distillations.

There are many types of distillation columns, each designed to perform specific types

of separations, and each design differs in terms of complexity which will be described as

follows:

1. Batch columns

In batch operation, the feed to the column is introduced batch-wise. That is, the column is

charged with a 'batch' and then the distillation process is carried out. When the desired

task is achieved, a next batch of feed is introduced.

2. Continuous columns

In contrast, continuous columns process a continuous feed stream. No interruptions occur

unless there is a problem with the column or surrounding process units. They are capable

of handling high throughputs and are the most common of the two types.

3.1.1. Main Components

Distillation columns are made up of several components, each of which is used either

to transfer heat energy or enhance material transfer. A typical distillation contains several

major components:

39
  a vertical shell where the separation of liquid components is carried out

 column internals such as trays/plates and/or packings which are used to enhance

component separations

 a reboiler to provide the necessary vaporization for the distillation process

 a condenser to cool and condense the vapor leaving the top of the column

 a reflux drum to hold the condensed vapor from the top of the column so that liquid

(reflux) can be recycled back to the column

The vertical shell houses the column internals and together with the condenser and

reboiler, constitute a distillation column. A schematic of a typical distillation unit with a

single feed and two product streams is shown below:

Figure 2 Distillation Unit Structure

3.1.2. Basic Operation

The liquid mixture that is to be processed is known as the feed and this is introduced

usually somewhere near the middle of the column to a tray known as the feed tray. The feed

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 tray divides the column into a top (enriching or rectification) section and a bottom (stripping)

section. The feed flows down the column where it is collected at the bottom in the reboiler.

Heat is supplied to the reboiler to generate vapor. The source of heat input can be any

suitable fluid, although in most chemical plants this is normally steam. In refineries, the

heating source may be the output streams of other columns. The vapor raised in the reboiler is

re-introduced into the unit at the bottom of the column. The liquid removed from the reboiler

is known as the bottoms product or simply, bottoms.

The vapor moves up the column, and as it exits the top of the unit, it is cooled by a

condenser. The condensed liquid is stored in a holding vessel known as the reflux drum.

Some of this liquid is recycled back to the top of the column and this is called the reflux. The

condensed liquid that is removed from the system is known as the distillate or top product.

Thus, there are internal flows of vapor and liquid within the column as well as external flows

of feeds and product streams, into and out of the column.

3.2. Corrosion

Corrosion comes from the Latin "Corrodere" which means the destruction of metal or

rust. The definition of corrosion is the process of degradation / deteorization / destruction of

material that occurs by the surrounding environment. The term corrosivity also applies to

non-metallic materials, such as ceramic, plastic, rubber. For example, damage to rubber paint

due to sunlight or chemical exposure, melting of layers of steel-making cups, solid metal

attack by molten metal.

corrosion can also be interpreted as a thermodynamic system of metals with the

environment (water, air, soil) that is trying to achieve balance. This system is categorized as

equilibrium when the metal has formed oxides or other chemical compounds that are more

stable (lowest energy). As for the corrosion process that occurs, in addition to ordinary

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chemical reactions, the electro-chemical process is more common. What is meant by its

environment can be in the form of air with sunlight, dew, fresh water, sea water, lake water,

river water and land in the form of agricultural land, swamps, lime soil and sandy / rocky soil.

Corrosion is also called an illness in the engineering world, although it does not directly

include engineering products. The study of corrosion is a kind of damage control effort so

that the attack is as low as possible and can exceed its economic value, or that no metal

becomes junk prematurely. With preventive maintenance to prevent corrosion. This method

is better than repressive repairs that will cost far more.

In the fuel processing industry, petroleum contains the main elements carbon and

hydrogen, as well as other by-products such as nitrogen, sulfur and oxygen. Crude oil from

these wells has a very large water content, as well as other components in the form of sand,

mineral salts, asphalt, CO2 and H2S gases, which can cause corrosion and can cause leaks in

petroleum pipes. Since it is almost impossible to prevent corrosion, controlling the corrosion

rate can be the most cost-effective solution.

3.2.1. Type of Corrosion

It is easier to classify corrosion by the form that manifests itself; the basis for this

classification is the appearance of corroded metals. 27]. Visual observation identifies each

form. There are eight unique corrosion forms, but all are interrelated. The eight forms are

uniform attack, galvanic, crevice corrosion, pitting, intergranular corrosion, selective

leaching, erosion-corrosion, and stress corrosion.

(1) Uniform attack

Uniform or general attack is the most common form of corrosion. It happens while a

chemical or electrochemical reaction that proceeds uniformly over the entire exposed

surface or a large area. For example, the reaction between zinc and sulfuric acid, the zinc

will usually dissolve at a uniform rate over its entire surface. This form attack represents

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 the most significant destruction of metal on a tonnage basis. It can be prevented or

reduced by proper materials, including coatings, inhibitors, cathodic protection.

(2) Galvanic

corrosion or two-metal corrosion is one of type of corrosion form. It potentially exists

between two dissimilar metals when they are immersed in a corrosive or conductive

solution.

(3) Crevice Corrosion

Intense localized corrosion often occurs in cracks and other protected areas on metal

surfaces affected by corrosion. This type of attack is due to the small volume of the

stagnant solution caused by the hole, gasket surfaces, lap joints, surface deposits, and

gaps under the head of bolts and rivets. So, caused by that condition crevice corrosion or

gaskets is appear.

(4) Pitting

Pitting is one of the most damaging and dangerous forms of corrosion. It causes the

equipment to fail due to perforation, with only a slight per cent reduction in the weight of

the entire structure. It is often challenging to detect pits because of their small size and

because the pits are often covered with corrosion products. Also, it is difficult to measure

quantitatively and compare hole levels because the depth varies and the number of holes

that can occur under identical conditions. Pitting is also challenging to predict by

laboratory tests. Sometimes the pits require long time-several months or a year appears in

the actual service. Pitting is very fierce because it is a form of local and intense corrosion,

and failure often occurs with extreme suddenness.

(5) Intergranular corrosion

Dirt can cause corrosion between grains at the enrichment of one of the alloying

elements, grain boundaries, or depletion of one of these elements in the grain boundary

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 area. Small amounts of iron in aluminum, where iron solubility is low, cause intergranular

corrosion and separate in grain boundaries. It has been shown that based on surface

tension considerations, the zinc content is higher in grain boundaries. The depletion of

chromium in grain boundary regions results in intergranular corrosion of stainless steel.

(6) Selective Leaching

Selective leaching is the reduction of one element of a solid alloy by corrosion. The

most common example is dezincification. A similar process occurs in other alloy systems

where aluminum; iron, cobalt, chromium, and other elements are removed. Careful

washing is a general term to describe these processes, and their use prevents the creation

of terms such as dealuminumification, decobaltification. Separation is a metallurgical

term that is sometimes applied, but careful washing is preferred.

(7) Erosion corrosion

Erosion corrosion is characterized by curves, gutters, waves, round holes, and valleys

and usually shows directional patterns. In many cases, failure due to erosion-corrosion

occurs in a relatively short time, and that is especially unexpected because the evaluation

of corrosion tests is carried out under static conditions or because the erosion effect is not

considered.

(8) Stress corrosion

During cracks, the metal or alloy is hardly encased in most surfaces, while fine cracks

pass through it. This phenomenon of cracking has serious consequences because it can

occur at pressures in the typical design stress range. Exposure to MgCl2 boiling at 310 ° F

(154 ° C) has been shown to reduce material strength at 1200 ° F.

Two classic cases of crack-cracking are cracking "crack season" of brass and "caustic

embrittlement" of steel. These two obsolete terms describe the current environmental

conditions, which cause cracking, corrosion cracking. Season cracking refers to the

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 failure of cracking corrosion on brass cartridge cases. During periods of heavy rain,

especially in the tropics, cracks are observed in brass crates at the point where it shrinks

into bullets. It was later found that a crucial environmental component in season cracking

was ammonia produced from the breakdown of organic matter.

3.2.2. Corrosion Rate

3.2.3. Remaining life

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 Chapter 4

4. Corrosion Rate Result and Analysis

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