Diesel Hydrotreating Unit

Essar Oil Limited, Vadinar Refinery, Jamnagar

1st July – 31st July, 2015

Project Report

Calculative Analysis of Reactor,

Charge Heater, Recycle Gas Compressor and

Charge Pump in DHDT

Under the Mentorship of

Mr. Mukesh Patel Deputy General Manager

Operations, Diesel Hydrotreating Unit, EOL

Submitted By:

Priyaranjan Das B.tech Chemical Engineering

(Specialization in Refining & Petrochemicals)

University of Petroleum and Energy Studies, Dehradun

CERTIFICATE

This is to certify that Mr. Priyaranjan Das, a student of B.tech Chemical Engineering

with specialization in Refining and Petrochemicals from University of Petroleum

and Energy Studies, Dehradun has successfully completed his Vocational Training at

Essar Oil Limited, Vadinar Refinery, Jamnagar during the following time period – 1st

July, 2015 to 31st July, 2015.

During his term as a Vocational Trainee in Diesel Hydrotreating Unit, Mr.

Priyaranjan Das effectively accomplished four projects. His calculations included

Measurement of Catalyst Deactivation Rate in DHDT Reactor, Evaluation of Charge

Heater Efficiency, Prediction of Power Requirements for Centrifugal Pump and

Tabulation of Polytropic & Mechanical Efficiency of the Recycle Gas Compressor.

His analysis, procedural approach and recommendations were meticulous. During the

entire course of his training, his dedication, punctuality and involvement was

impressive. I commend his sincere approach and wish him the very best for his future.

Place: DHDT Operations, EOL, Vadinar

Date: 31st July, 2015

Mr. Mukesh Patel

Deputy General Manager

Operations, Diesel Hydrotreating Unit

Essar Oil Limited, Vadinar

ACKNOWLEDGEMENT Industrial Training is an integral part of the engineering curriculum and provides students with an opportunity to gain practical knowledge and learn about the applicative aspects of the education gained at the college and get acquainted with the rudiments of the industry. It gives me immense pleasure to have completed the course of my vocational training at Essar Oil Limited, Vadinar Refinery, Jamnagar. I wish to place on record my deep sense of gratitude to Mr. Mukesh Patel for granting me the permission to visit the operational area of the DHDT plant and assisting me throughout the program with industrial data and valuable inputs. He has been a wonderful mentor and a guiding force behind the successful completion of my projects. I also thank Mr. Abhijit Gogoi for his renowned direction and supervision. I am sincerely grateful to Mr. Kirubanandan for his perpetual support and guidance throughout the training module. He constantly supported me by sharing his knowledge and resources and ensured the clearance of my doubts. My work bears the impact of all the staff members of the DHDT plant who despite of their multiple responsibilities explicated the operational methodology of the plant and I feel hugely gratified at their cooperation. I am highly appreciative of Mr. Harender Singh who coordinated my training with remarkable precision. I am indebted to the efforts made by Mr. Prashant Arya and Mr. Neeraj Kumar for granting approval for my Vocational Training. Regards. Priyaranjan Das B.tech Chemical Engineering (specialization in Refining and Petrochemicals) University of Petroleum & Energy Studies Dehradun

PREFACE

The summer training program at Essar Oil Limited, Vadinar, helped me to gain a hands-on experience pertaining to the practical operations that take place in the industry. I got an opportunity to learn the various applicative aspects of the courses taught within the curriculum of B.tech in Chemical Engineering, especially related to Mass Transfer, Heat Transfer and Fluid Mechanics. I was allotted the Diesel Hydrotreating Unit (DHDT) for my internship program. With a tight schedule comprising of Lectures and Field Visits, I managed to complete four projects under the eminent mentorship of Mr. Mukesh Patel. At the operational area, the working staff members were kind enough to explicate the entire process being performed and provided us with appropriate data assisting us in obtaining a profound understanding of the operational methodology of the plant. All my doubts were cleared with utter diligence. In the report, I have tried to summarize all that I have learnt at the EOL Refinery with major emphasis on DHDT. This study has primarily been undertaken by me with a view to evaluate proper working process in the organization. Priyaranjan Das B.tech Chemical Engineering (specialization in Refining and Petrochemicals) University of Petroleum & Energy Studies Dehradun

INDEX

Essar Group: Profile

Essar Refinery: Overview

Essar Refinery: Processes

DHDT: Process Overview

Project Report: Evaluation of Catalyst Deactivation Rate in

Reactor

Project Report: Determining Polytropic Efficiency in Recycle Gas

Compressor

Project Report: Calculation of Charge Heater Efficiency

Project Report: Prediction of Power Requirements in Charge

Pump.

Safety in Essar Refinery

References

1. ESSAR GROUP: PROFILE

1.1. Introduction

The Essar Group is one of India's largest corporate houses with interests spanning the

manufacturing and service sectors in both old and new economies: steel, power,

shipping, constructions, oil & gas and telecom. The Group has an asset base of US$ 4.4

bn (Rs.200 billion) and a turnover of over US$ 2.08 bn (Rs.95 billion). It employs 20000

people in 50 locations worldwide. Strategic investments made by the group over the

past decade have resulted in the creation of tangible and intangible assets that are at

the heart of the Indian Economy.

The Group takes pride in being a high-performance multinational organization,

providing world-class services and products. Manned by a highly efficient and dynamic

team of employees, the Group is growing stronger every day. A committed corporate

citizen, the group provides unwavering support to the community as well as initiates

various social and ecological drives that have a positive impact on society.

All the groups investments have been consolidate under Essar Global Ltd. With its six

sectors holding companies:

ESSAR Steel Holdings Ltd.

ESSAR Power Holdings Ltd.

ESSAR Energy Holdings Ltd.

ESSAR Communication Holdings Ltd.

ESSAR Shipping & Logistics Ltd.

ESSAR Construction FZE.

Essar brand names include:

Vodafone Essar

Algoma Steel

ESSAR Group is headed by Chairman Shashi Ruia & Vice Chairman Ravi Ruia.

1.2 Mission

To create enduring value for customers and stakeholders in core manufacturing and

service businesses, through world class operating standards, state of the art technology

and the ‘Positive attitude’ of our people.

1.3 Major Achievements of Essar Group

Built the world's largest gas-based sponge iron plant

Pioneered the laying of offshore oil and gas pipelines in India

Built India's first and longest is land break water.

Set up India’s first new generation independent power plant with a 515 MW

combined cycle capacity at Hazira.

2. ESSAR REFINERY: OVERVIEW

2.1 Story of Essar Refinery

The Essar Oil Ltd Refinery in Gujarat, India (started in 1996) was completed and

commissioned in 2006 (commissioned in third quarter). The refinery project was

delayed several times due to environmental concerns and financial problems, including

initial cost overruns and a shortfall in equity contributions.

According to company reports, the refinery was 60% complete in 1998 but had the

misfortune to be struck by a cyclone that caused considerable damage. The refinery

currently has the capacity to produce 4,00,000 barrels a day (20 million metric tons

per annum) and plans are underway to increase the capacity to 680,000 barrels a day

(34 mmtpa) by the end of fiscal 2018. The refinery employs over 1,000 personnel (the

construction process required between 3,000 and 4,000).

The refinery is now the second largest in India after the Reliance Jamnagar refinery on

an adjacent site which can produce over 64 mmtpa.

Essar Oil focuses on producing middle distillates such as high-grade Kerosene oil and

low sulfur high-speed Diesel, which form over 60% of India's domestic consumer

demand. Substituting imports will help conserve India's foreign exchange. The refinery

also produces LPG and lead-free Gasoline of various octane levels for the domestic

markets and high-octane lead-free Gasoline for export. Essar Oil has 1,300 retail

stations with plans to add another 150 outlets by the end of 2010.

2.2 Refinery Start-up

In November 2006, Essar Oil started operations in its Vadinar grass roots refinery and

trial production with a capacity of 7.5 mmtpa. In December 2006, the plant dispatched

its first cargo of 35,000 tonne vacuum gas oil.

Essar shut down the plant for three weeks in July 2007 to upgrade the capacity to

210,000 bpd as well as to add secondary units. After the start of the commercial

production of 10.5 mmtpa in May 2008, Essar Oil reported a gross sale of Rs100bn for

the first two months of its commercial operations. The profit for the quarter ending 30

June 2008 was INR 4.34bn. Essar posted a gross turnover of INR 418bn between May

2008 and March 2009. Since then, it has reportedly increased by 19.7% in the first

quarter of 2010.

2.3 Commissioning Process

The units commissioned in the first phase were the CDU, VDU, Sulfur Recovery Unit,

Naphtha Hydrotreater Unit, Catalytic Cracker Unit and Visbreaker Unit. The Fluid

Catalytic Cracker Unit and a Diesel Hydro Desulfurization Unit were commissioned in

November 2006. The FCC and DHDS plants were modified so as to be compliant with

the cleaner Euro III and Euro IV fuels. The refinery configuration lends itself well to

debottlenecking and its capacity is enhanced to 20 mmtpa. The refinery is fully

integrated with its own dedicated 77 MW power plant, which it plans to expand to

1,200 MW plant.

The docking facilities include an SBM capable of handling vessels up to 350,000 DWT

with a capacity of 25 mtpa, tankages with interconnecting pipelines of 20 mtpa capacity,

marine product dispatch capacity of 12 mtpa and rail-car and truck-loading facilities.

2.4 Crude supply

Ahead of the commissioning, the company received one million barrels at the Vadinar

port in Gujarat in August 2006. The crude was a Saharan blend suitable for refining in

the Essar Oil's refinery. The company also received a second cargo from Vitol in West

Asia. Both cargos were of sweet crude.

The annual requirement of crude oil at the refinery is in the region of 20 mmtpa. The

refinery is configured to allow flexibility to process diverse varieties and qualities of

crude. The refinery is primarily designed to handle a crude mix of Arabian Light and

Heavy in a 70:30 ratio. However, adequate flexibility has been provided to handle a

variety of crude mixes at refinery processing units from sweet-light crude to heavy high

sulfur sour and bituminous crude.

The refinery refines crude oil to produce diesel, gasoline, jet fuel, kerosene, fuel oil and

bitumen to suit market requirements. Imported crude oil is discharged from a single

buoy mooring situated off a coastal site at a distance of 8 km. A submarine / onshore

pipeline transfer’s crude to onshore storage tanks.

2.5 Contractors and Construction

The principal contractor and project manager for the project since it was started is ABB

Lummus Global of the Netherlands (ABB put Rs 9300 into the project). The company

responsible for detailed engineering, procurement and construction (EPC) is TCE.

Larsen and Toubro is another engineering company involved in the project. Semb Co

E&C has secured contracts worth $350 m for engineering, procurement, project

management and construction management for the project.

The TCE remit for construction includes offsite facilities, storage and transfer of crude,

intermediates and products, blending facilities, dispatch facilities, fuel oil / gas system,

effluent treatment and disposal facilities. Utilities include power / steam generation

facilities (two 38.5 MW / three 150 t per hour) with distribution network, compressed

air (three 3,120 Nm³ per hour) and nitrogen system (1,900 Nm³ per hour),

demineralizing plant (775 m³ per hour), desalination plant (two 390m³ per hour), salt

cooling water facilities (64,000 m³ per hour) and tempered water facilities.

A refinery-wide integrated Distributed Control System (DCS), safe guarding system, fire

and gas detection system and electrical control system is provided with hardware

located in satellite buildings and operator consoles provided in the crude oil tank

control building and central control building. A sophisticated Tank Gauging System

(TGS) has been provided – one each for crude oil tank farm, product and intermediate

tank farm and dispatch tankages – comprising radar, servo and hydrostatic systems.

Over 700 motor-operated valves with intelligent actuators are connected to DCS and

emergency shutdown systems. The dispatch automation system is integrated with the

TGS and DCS systems.

The refinery is being constructed with a view to the future since it will have sufficient

infrastructure for a low-cost expansion to a production capacity of 27 mmtpa. The

refinery also has two desalination plants each with a capacity to produce 8,450 m³ a day

of less-than-5 ppm total dissolved solids (TDS) from feed water of 40,000 ppm TDS (sea

water).

2.6 Port and shipping

The refinery has its own port and terminal facilities. Vadinar port is an all-weather,

deep-draft, natural port with loading facilities for railcars and trucks.

Vessels up to 350,000 DWT can be handled through single point mooring (SPM) and

there is also a marine product dispatch with a capacity of 14 mtpa.

Essar Shipping has an agreement with Essar Oil to ship crude oil as required by the

refinery. Essar Oil has set up a new company, Vadinar Oil Terminal, to administer all

affairs of the new deep-water port on behalf of Essar Oil and Essar Shipping.

2.7 Pipelines

The refinery is ideally located on the west coast of India at Vadinar, Gujarat, close to

both suppliers and customers. This is the nearest point to the Middle East, which is a

major source of crude supply. The site is linked to the Kandla-Bhatinda product pipeline

through the Vadinar-Kandla pipeline, giving it easy access to the key markets of North

India.

Essar constructions have bagged several pipeline projects over the past few years. The

projects include the INR 2 bn Baroda – Ahmadabad – Kalol gas pipeline project, Rs.

740m product pipeline project in Tamil Nadu, Rs 1.3 bn gas pipeline project from GAIL

and most recently Rs 1.9 bn, 504 km pipeline project. Essar Oil also has a stake in the

pipe-holding company Petronet India.

2.8 Financing

Funding for the project, which amounts to an estimated INR 98,740 cr ($2.26bn), has

been a complicated arrangement. Financial closure by Essar Oil has now been achieved

for the project. In January 2005, Essar Projects raised Rs. 3750 crores through Global

Depository Receipts (GDR) and Essar Shipping raised $213m through the issuing of

Foreign Currency Convertible Bonds (FCCB), to make a total of $299m (this was a

condition of the remaining funds being released). The financial institutions, including

ICICI bank, the Industrial Development Bank of India (IDBI) and the Industrial Finance

Corporation of India (IFCI) bank, then released the remainder of the Rs 80000 crores

funding held in escrow for the project.

In October 2008, Essar Oil ordered four steam turbine generators from Siemens Energy

for the Vadinar Oil refinery in Gujarat. The $50m deal includes two steam turbines each

rated at 105MW, two 93 MW steam turbines and four generators. Delivery of the steam

turbine generators was scheduled by the third quarter of 2010.

2.9 Expansion

Essar Oil Refinery will be expanded in two phases to achieve a capacity of 36 mmtpa.

The first phase comprises capacity expansion to 20 mmtpa. An investment of Rs78 bn is

being made in the first phase, which was commissioned by March 2012. By the end of

the first half of 2009, 33% of phase I had been completed.

In phase II, there are plans for establishing a new processing unit with a capacity of

18mmtpa. An investment of $4bn is being made in the phase II expansion, which is

expected to be completed by March 2018. Essar's construction arm, Essar Construction

(I), is undertaking the expansion of the refinery. As of January 2010, 28% of the

construction was completed and overall refinery expansion of 41% was achieved. On

completion, Essar oil will produce products in compliance with International

environmental norms Euro IV and V.

3. ESSAR REFINERY: PROCESSES

3.1 Segments

The refinery at Essar Oil Limited, Vadinar is comprised of the following segments:

OSBL: Outside of Battery Limits

Utilities

Off sites

ETP

Interconnecting Lines

Other facilities

COT: Crude Oil Tankage

It fulfills the storage requirements for crude oil.

ISBL: Inside of Battery Limits

CDU: Crude Distillation Unit

VDU: Vacuum Distillation Unit

FCCU: Fluid Catalytic Cracking Unit

UGS: Gas Concentration Unit

VBU: Vis Breaker Unit

NHT: Naphtha Hydro Treating Unit

CCR: Continuous Catalytic Reformer

DHDS: Diesel Hydro Desulfurization

SRU: Sulfur Recovery Unit

HMU: Hydrogen Manufacturing Unit

PIT: Process Intermediate Tank

DHDT: Diesel Hydro Treating Unit

ISOM: Isomerization Unit

VGOHT: Vacuum Gas Oil Hydro Treating Unit

DCU: Delayed Coker Unit

3.2 Primary Processes

Crude Distillation

Primary unit to separate different boiling point fractions such as LPG, Naphtha,

Kerosene, HSD, RCO etc.

Distillation conducted at slightly higher than atmospheric pressure.

Unit design for specific crude with flexibility to process a few other crudes.

Vacuum Distillation:

Sub atmospheric distillation of atmospheric column bottoms for production of fuels

or lube stocks.

Fuels Production: Metal contents, CCR, Final boiling point etc. critical.

Lubes Production: More stringent fractionation requirements

3.3 Secondary Processes

Further conversion of Vacuum Gas oils and Residue required maximizing production of

more useful products. Such processes are called secondary or bottoms upgradation

processes.

Catalytic Hydro Processing (Hydrocracking)

Catalytic cracking of vacuum gas oils in presence of Hydrogen

High pressure and temperature

Can produce Fuels / Lubes

No further treatment required for fuel products

Fluid Catalytic Cracking (FCC)

Catalytic cracking of vacuum gas oils or residues at high Temperature

Fluidized catalytic bed with continuous regeneration of catalyst

Cracked products contain unsaturated and hence need further treatment

Visbreaking (Thermal Cracking)

Thermal cracking of vacuum residue at high temperature

Provide residence time in coil (coil type) or outside in separate vessel (soaker type)

Gas oil & Naphtha are products

Delayed Coking

Coking occurs in the Reactor Drum

Coke removed by water jetting

Coke Drum operation in batches

Naphtha , gas oils are other products

Solvent De-asphalting

Extraction of useful oil from Vacuum residue

Propane – Butane mixture used as solvent

Useful oil can be cracked in FCC or Hydrocracker or can be converted into Bright

Stock (lubes)

Asphalt byproducts can be removed into Bitumen

Partial Oxidation

Partial oxidation of vacuum residue or asphalt

Produces Synthesis Gas or Hydrogen

Synthesis gas can be converted into power

Hydrogen consumed in refinery

3.4 Miscellaneous Processes

Catalytic Reforming Unit

Increases octane number of gasoline

Produces hydrogen

Semi regenerative (regeneration during shut downs) or

Continuous type

Treating Units

Merichem/Merox

1. Removes H2S, Mercaptans from LPG, Gasoline, and Kerosene/ATF.

Desulfurization

1. Catalytic Desulphurization of Naphtha, Diesel

2. Also improves Cetane number of Diesel

3. Diesel Hydro Desulfurization Unit produces Diesel as per Indian usage.

4. Diesel Hydro Treating Unit produces Diesel as per Euro IV and Euro V norms.

Lube processing Units

Aromatic Extraction

1. De-waxing

2. Hydro treating

3. Catalytic Processes

Processes to Meet Environment Regulation

Sulfur Recovery

Water Treatment

Flue Gas Desulphurization

3.5 Auxiliary Operation and Facilities

Steam and Power Generation

Flares and relief system

Process and fire water system

Furnaces and heater , pumps and valves

Supply of steam, air, nitrogen and other plant gases

Alarms and sensors ; noise and pollution control

Sampling, testing and inspecting ; laboratory, control room, maintenance and

administrative facilities

4. DHDT: PROCESS OVERVIEW

4.1. Introduction

Hydrotreating is an important refinery process, in which the oil stream is upgraded to

meet the required environment specification and physical properties. The process uses

a catalytic hydrogenation method to upgrade the quality of petroleum distillate

fractions by decomposition the contaminants, with a negligible effect on the boiling

range of the feed. This process is designed primarily to remove sulfur and nitrogen. In

addition, the process does an excellent job of saturating olefin and aromatic compounds

while reducing Conradson Carbon and removing other contaminants such as

oxygenates and organ metallic compounds. The desired degree of hydro treating is

obtained by processing the feedstock over a fixed bed of catalyst in the presence of large

amount of hydrogen at temperature and pressure dependent on the nature of the feed

and the amount of contaminant removal required. The same catalyst in varying

quantities can be used to hydrotreat straight run naphtha, vacuum gas oil and

catalytically and thermally cracked distillates. The widespread use of catalytic

reforming unit has made available large quantities of excess hydrogen, making it

feasible to hydrotreat many or all the distillates produces by the refinery.

The various processing steps involved in the process are:

Pumping of Feed to the desired pressure.

Mixing Recycle Gas with Feed.

Heating of Feed and Recycle Gas Mixture to the desired temperature.

Contacting the Feed and Recycle Gas Mixture with catalyst.

Cooling the Reactor Effluent.

Separating Liquid and Vapor from the Reactor Effluent.

Recycling the Separated Gases to reactors inlet.

Stripping the liquid reactor effluents to remove lower boiling fractions as wild

naphtha.

Cooling and polishing of products before sending to storage.

4.2. Process Principles

The process is carried out at elevated temperature and pressure in a hydrogen atmosphere.

Plant capacity: 3.8 MMTPA with 8000 hours on stream per year.

Temperature Range: 290 °C - 425 °C

Pressure Range: 35-92 kg/cm2g

Catalyst used: The varying amounts of nickel or cobalt with molybdenum oxides on

an alumina base.

The specific catalyst system and unit-design parameters will be evaluated on an

economic basis for each unit. Each design will be based on feed quality, desired product

properties, ease of operation, desired cycle length, operating flexibility, construction

schedule and operating costs.

4.3. Reaction Chemistry

Hydrotreating reactions are catalyzed by the metal sites on the catalyst. The primary

Hydrotreating reactions are sulfur and nitrogen removal as well as olefin saturation.

The products of these reactions are the corresponding contaminant- free hydrocarbon,

along with H2S and NH3. Other treating reactions include oxygen, metals and halide

removal, and aromatic saturation. In each of these reactions, hydrogen is consumed and

heat is liberated. Some of these reactions are outlined below.

Desulfurization

Typical feedstock to the Hydrotreating unit will contain simple mercaptans, sulfides and

disulfides. These compounds are easily converted to H2S. However, feedstocks

containing heteroatomic aromatic molecules are more difficult to process.

Desulfurization of these compounds proceeds by initial ring opening and sulfur removal

followed by saturation of the resulting olefin. Thiophene is considered five times more

difficult to process compared to diethyl sulfide.

Denitrification

Denitrification is generally more difficult than desulfurization. Side reactions may yield

nitrogen compounds more difficult to hydrogenate than the original reactant. Saturation

of heterocyclic nitrogen-containing rings is also hindered by large attached groups.

Oxygen Removal

Organically combined oxygen is removed by hydrogenation of the carbon-hydroxyl

bond forming water and the corresponding hydrocarbon.

Olefin Saturation

Olefins are a significant component in cracked feeds such as coker gas oils and catalytic

cycle oils. Olefins are highly reactive under Hydrotreating conditions resulting in high

heat release and temperature rise in the top beds of the reactor.

Aromatic Saturation

Aromatic Saturation reactions are the most difficult. The reactions are influenced by

process conditions and are often equilibrium limited. Unit design parameters would

consider the desired degree of saturation for each specific unit. The saturation reaction

is highly exothermic.

Metal Removal

The mechanism of the decomposition of organo-metallic compounds is not well

understood; however, it is known that metals are retained on the catalyst by a

combination of adsorption and chemical reaction. The catalyst has a certain maximum

tolerance or capacity for retaining metals. Removal of metals normally occurs in plug

flow fashion with respect to the catalyst bed. Typical organic metals native to most

crude oils are nickel and vanadium. Iron can be found concentrated at the top of catalyst

beds as iron sulfides that are corrosion products. Contaminants, Such as sodium,

calcium and magnesium are sometimes present as a result of contact of the feed with

salt water or additives. Improper use of additives to protect Fractionator overhead

systems from corrosion or to control foaming can account for the presence of

phosphorus and silicon. Lead may also deposit on the Hydro treating catalyst from

reprocessing leaded gasoline through the crude unit. The useful life of the catalyst may

be determined by the amount of metals that are accumulated on it during the course of

operation. Metal removal is essentially complete above temperatures of 315°C (600°F)

to a metals loading of 2-3 wt. % of the total catalyst. Above this level, the catalyst begins

to approach equilibrium saturation and metal breakthrough is likely. The total metal

retention of the catalyst system can be increased by using a guard reactor or a guard

bed of catalyst specifically designed for demetallization.

Halide Removal

Organic- halides, such as chlorides and bromides, are decomposed in the reactor. The

inorganic ammonium halide salts that are produced when the reactants are cooled are

then dissolved by injecting water into the reactor effluent or they leave with the

stripper off-gas. Decomposition of organic halides is considered difficult with a

maximum removal of 90%.

4.4. Reaction Rates

The relative reaction difficulty for several major Hydrotreating reactions is indicated

below.

The approximate relative heats of reaction per unit of hydrogen consumption for these

reactions are shown below.

Table: Approximate Relative Heats of Reaction per Unit of Hydrogen Consumption

Desulfurization 1

Olefin Saturation 2

Denitrification 1

Aromatics Saturation 1

All of the reactions discussed above are exothermic and result in a temperature rise

across the reactor. Olefin saturation and some desulfurization reactions have similarly

rapid reaction rates, but it is the saturation of olefins which generates the greatest

amount of heat. The temperature rise expected for a given charge stock along with the

desired product quality will play a very important role in determining the number, size,

and arrangement of the reactors, heat exchange, and hydrogen circulation rate.

NOTE:

The hydrogen consumed by the Diesel Hydrotreater reactions is supplied externally and

must be compressed to reaction system pressure. If the hydrogen is obtained from a

Naphtha Reforming unit, purity may vary from 70% to 90% H2. Unionfining units are

not designed to operate at hydrogen purities below 70% because of the adverse effect

on the catalyst performance and excessive compressor horsepower. The amount of

hydrogen required to complete the above reactions will vary depending upon feed and

desired product quality.

4.5. Process Description

The DHDT unit reduces the Sulphur Content of Diesel by treating it with Hydrogen at

High Temperature and Pressure over a bed of Catalyst to convert the bound Sulphur in

the diesel to H2S. The DHDT unit will be designed to hydrotreat a feed blend containing

straight run gas oils, vacuum gas oils, and Coker gas oils to reduce sulfur to less than 8

wt ppm and improve the Cetane index to 48 minimum at start of run (SOR) conditions.

This DHDT Hydrotreating Unit has five main sections:

1. Feed section

2. Reactor section

3. Separation section

4. Recycle and make-up gas section

5. Fractionation section

Feed Section

Fresh Feed System

The fresh feed is brought into the unit from an upstream unit and/or storage. It is

preferable to Route feed directly from upstream unit without going to intermediate

storage. When storage facilities are used, UOP recommends gas blanketing with

nitrogen or floating roof tanks with torroidal seals to prevent gum formation resulting

in possible equipment fouling. The fresh feed passes through filters to remove

particulate matter and then enters the gas blanketed feed surge drum. Since the feed

surge drum temperature is considered high, a separate feed coalescer specified for feed

from storage. Here the feed filters are automatic backwash type. Twenty-five micron

backwash filters may be specified if the feed contains an appreciable quantity of solid

material as is usually the case with Coker gas oils. Filtering this material effectively

removes the majority of the particulate matter that would accumulate in the reactor and

cause pressure drop build-up.

The reactor charge pumps take suction from the feed surge drum and pumps the

material to the combined feed exchangers. The charge pumps are high head machines

capable of pumping large volumes of oil at pressures of over 117 kg/cm2g. The

manufacturer's instructions must be consulted before operating the charge pumps since

special care must be taken to avoid damage due to low flow, high temperatures,

vibration, etc. Proper lubrication and cooling must be maintained at all times both for

the pump and its driver if serious damage is to be avoided. This type of pump should

never be operated against a blocked discharge, or at flow rates below the minimum

recommended by the manufacturer. Maintenance spillback as well as process spillback

provided to maintain minimum flow at reduced throughput or start-up.

Feed Heat Exchange

In a more commonly used heat recovery scheme, the reactor charge is preheated by the

reactor effluent in a series of feed-effluent exchangers before entering the reactor

charge heater. This attempts to recover as much heat as possible from the heat of

reaction. Liquid feed may be preheated separately with reactor effluent exchange before

combining with the recycle gas depending upon the heat integration system. The

combined feed stream typically enters a mixed phase heater to reach the desired

reactor inlet temperature. Charge heater outlet/Reactor inlet temperature control by

fuel gas/fuel oil firing. Fresh feed bypass around exchangers is provided to better

control of the charge heater outlet temperature. Austenitic stainless steel materials are

normally used in the hottest heat exchangers and associated piping (piping to the

charge heater, charge heater tubes, heater transfer line, reactor lining and reactor outlet

piping). These materials provide the best resistance to the corrosive atmosphere and

severe operating conditions. However, they are subject to stress corrosion when

exposed to air and moisture. This type of corrosion can be avoided by neutralizing the

sulphide scale on the tube walls and by avoiding the condensation of moisture in the

tubes.

Reactor Section

Once the feed and recycle gas have been heated to the desired temperature, the

reactants enter the top of the reactor. As the reactants flow downward through the

catalyst bed, various exothermic chemical reactions occur and the temperature

increases. Each bed contains 3 element radial thermocouple assemblies at the top of

reactor bed. Multiple thermocouples re provided at catalyst beds for better temperature

control. Reactor skin thermocouples (14 each bed) are provided at the bottom of each

bed and on the bottom reactor head, for monitoring the reactor wall temperature.

Specific reactor designs will depend upon several variables. Reactor diameter is

typically set by the cross-sectional liquid flux. As the unit capacity increases, the reactor

diameter increases to the point where two parallel trains would be considered. Reactor

height is a function of the amount of catalyst and number of beds required. Other local

factors may also influence the reactor design including seismic activity and weight

limitations. Crane, bridges and road capacities are also factors. The reactors are

typically divided into individual catalyst beds (four nos.) supported on a beam and grid

support system. The support system is separated from the next bed of catalyst by a

quench gas distributor, a reactant mixing chamber and a vapour/liquid distribution

tray.

The reasons for separating a reactor into separate beds are the following: If the radial

temperature profile becomes skewed part way through a reactor, the reaction rates will

be different in different parts of the catalyst bed. This overworks the part of the catalyst

that is hotter and under-utilizes the part of the catalyst bed that is cooler. It is also

potentially hazardous if the hotter portion becomes significantly higher than the bulk

temperature and forms a hot spot, especially if the hot spot is next to the reactor wall.

Mixing of the reactants re-establishes thermal equilibrium and thus, after every quench

zone, assures that all the catalyst is efficiently utilized. In certain situations the heat of

reaction will be large enough that the temperature increase across a reactor will be

greater than the design. If this were allowed to happen, a reaction could become

unstable and result in a temperature runaway. Therefore, cold recycle gas at about 40-

66°C (100-150°F) is brought into the reactor at the inter-bed quench points in order to

cool the reactants and thus control the reaction rate. A graded catalyst bed may be

installed at the top of the first catalyst bed to collect corrosion products and other

particulates without an excessive increase in pressure drop. The graded bed provides a

graduation of catalyst activity and pellet sizes to minimize fouling and provide void

volume for solid deposition. Good distribution of reactants at each reactor inlet and at

the top of each catalyst bed is essential for optimum catalyst performance. UOP's

proprietary reactor internals are used to accomplish this distribution.

The various components of reactor internals are given below:

Inlet Diffuser

Top Vapour/Liquid Distribution Tray

Quench Section

Lower Vapour/Liquid Distribution Tray

Reactor Outlet Basket

Reactor Effluent Cooling

Due to the exothermic nature of the reactions taking place in the reactor, the

temperature of the material leaving will be greater than the reactor inlet temperature.

The heat of reaction as well as a large portion of the heat contained in the reactor feed is

recovered in a series of heat exchangers. The reactor effluent used to preheat the

combine feed, recycle gas and stripper feed.

Reactor Effluent Water Wash

Final cooling of the reactor effluent is obtained in air fin coolers and/or water trim

coolers. Water is injected into the stream before it enters the coolers in order to prevent

the deposition of salts that can corrode and foul the coolers. The sulfur and nitrogen

contained in the feed are converted to hydrogen sulphide (H2S) and ammonia (NH3) in

the reactor. These two reaction products combine to form ammonium salts which can

solidify and precipitate as the reactor effluent is cooled. Likewise, ammonium chloride

may be formed if there is any chloride in the system. The purpose of the water is to

dissolve these salts before they precipitate. Water is normally injected in a vertical run

of pipe through an injection quill that facilitates mixing of the water with the reactor

effluent.

Make up hydrogen and Recycle gas system

Make-Up Hydrogen System

Make-up H2 is typically obtained from a naphtha reforming unit, and/or a hydrogen

manufacturing plant at a pressure of 14-28 kg/cm2g (200-400 psig). Since the

Unionfining DHDT reactor section pressure may be ~ 90 kg/cm2g, the make-up gas

must be compressed before it can join the system. Reciprocating compressors are used

to raise the pressure of the gas, with the number of compression stages varying in

accordance with the difference between the supply and reaction section pressures.

From the discharge of the second stage of compression, the makeup gas joins the recycle

gas compressor suction. In Diesel Hydrotreater Make up gas is available at 21 kg/cm2g

(400 psig), its pressure can be raised to 46.5 kg/cm2g in first stage of compression and

up to 90 kg/cm2g in second stage of compression. The spillback gases, used to control

the inter-stage suction drum and make up suction drum pressures, also need to be

cooled before being returned to the suction drums. Reciprocating compressors, whether

used in make-up and/or recycle gas service, may be driven by electric motors, steam

turbines or gas engines. A suction drum is provided on the suction line of each stage of

compression to knock out condensed liquids. A cooler is provided on the discharge of

each stage to remove the heat generated by compression. The manufacturer's

instructions for the start-up, shutdown and care of these units must be studied and well

understood, in general, close attention must be paid to the compression ratio across

cylinder as well as the suction and discharge temperatures. Excessive compression

ratios must be avoided since they will lead to high cylinder discharge temperatures,

rapid wear, low compressor efficiency, and a possible overloading of the drive. The

cylinder discharge temperatures give a very good indication of the performance of the

machine and should be recorded on a regular basis. Higher than normal temperatures

show that cylinder or inter-stage cooling may be inadequate, or that the compressor

valves are faulty. In such cases, quick remedial action must be taken in order to avoid

overheating and damaging the cylinders. It must be remembered that higher than

design compression ratio and high molecular weight gases (as indicated by a reduction

in H2 purity) will increase the load on the driver. Excess load can be particularly

dangerous where motor drivers are used, since the motor will trip out once the

amperage through the windings reaches a predetermined maximum. The maximum

allowable motor amps should be obtained from the manufacturer and posted on the

compressor panel.

The flow of makeup gas through the compressor and into the unit is controlled by a

complex system of pressure controllers on the high pressure separator and the suction

drums. The basic philosophy of the control scheme is to control the flow of gas as the

demand for hydrogen dictates (as determined by the pressure in the high pressure

separator). As hydrogen is consumed in the reactors, the pressure in the high pressure

separator will start to decrease. This will in turn call for more makeup gas by closing the

control valve in the spillback line from the discharge to suction and more gas flows

forward into the process. In the event that the unit is calling for more makeup gas than

is available (hydrogen consumption is too high), the pressure control system essentially

works in reverse. The suction drum pressure will start falling because there is not

sufficient gas available from the hydrogen plant to replace what is being pumped out of

the suction drum. When this happens, the pressure controller on the suction drum

senses the decrease in pressure and, in order to protect the compressor from excessive

compression ratio, high pressure separator pressure will start decreasing. At this point

the operator will recognize that hydrogen consumption is exceeding supply and must be

reduced either by decreasing reactor temperatures or feed rate or both. Alternatively,

the hydrogen supply may be increased. It is very important for operating personnel to

become familiar with the mode of control used so that pressures beyond the capability

of the equipment may be avoided. The maximum allowable compressor temperatures

and compression ratios should be obtained from the manufacturer and posted in the

control room or near the compressors.

Recycle Hydrogen System

After separation of the gas and liquid phases in the high pressure separator, the gas

leaves from the top of the high pressure separator and flows to the suction of the

recycle gas compressor. In DHDT, recycle gas will be first sent to an amine scrubber to

remove H2S. The recycle gas compressor is a separate centrifugal machine. In any case,

the recycle gas compressor is designed to pump a large volume of gas at a relatively low

compression ratio. The bulk of the recycle gas is normally joined by the makeup gas.

The makeup gas joins the recycle gas before the recycle gas compressor suction drum

through PV21. The combined makeup and recycle gas is divided into passes which are

normally flow controlled into the combined feed passes going to the combined feed

exchangers. The object is to maintain equal gas flow to each reactor charge heater pass

at a sufficiently high rate to avoid overheating the tubes. From this point until it returns

to the high pressure separator, the gas flows along with the liquid through the reactor

circuit in the same manner previously described.

Recycle Gas Scrubbing

The recycle gas stream will contain H2S. The H2S reduces the hydrogen partial pressure

and suppresses catalyst activity. This effect is more pronounced with high sulfur

containing feed streams. For these cases, a recycle gas amine scrubber may be specified.

Recycle gas scrubbing is very unit specific, but would typically only be specified when

the recycle gas would contain > 3 volume % H2S. Depending upon the exact design, the

high pressure separator gas may be cooled with either lean amine or cooling water

before entering a knock out drum. The gas from the KO drum enters the bottom of the

scrubber and is contacted countercurrent with amine. The tower is divided by a liquid

tight accumulator tray into a lower amine scrubbing section followed by a water wash

section. Lean amine is pumped to the tower by booster pumps and enters at the top of

the scrubbing section. The amine temperature is usually maintained ~5°C (~10°F)

above the gas temperature to minimize foaming. The amine and the gas flowing up the

tower come into contact over the trays where intimate mixing between the two is

achieved and H2S is absorbed by the amine. The rich amine falls to the bottom of the

scrubber from where it is sent on level control to the amine regeneration section. The

H2S free gas goes into the top section of the scrubber for entrained amine removal

through a demister pad. The amine free recycle gas then goes to recycle gas compressor

suction.

Separator System

The exact method of separating vapour and liquid will vary pending the Optimum heat

integration flow scheme and various design considerations. A typical flow scheme may

use one separator to disengage and individually remove vapour, water and hydrocarbon

liquid. A flash drum may also be specified for units operating over 90 kg/cm2g. The

water is collected in a boot attached to a separator and is removed on level control and

sent to a waste water stripping unit. This water contains a large concentration of highly

toxic H2S and NH3, and should not be drained to the sewer for any length of time. The

hydrogen-rich separator off-gas is combined with the make-up hydrogen, recompressed

and returned to the reactor section. In some cases, recycle gas may be sent to an amine

scrubber to remove H2S as discussed previously. A compressor suction knockout drum

may also be provided depending upon the type of compressor used. If multiple catalyst

beds have been specified, some recycle gas would be used for inter-bed quench.

Stripper/Fractionation Section

The function of the stripper section is to separate sour strip light ends from DHDT

product. This can be accomplished with a stripper column. The hydrocarbon liquid

collected in the vapour/liquid separation system is sent to a stripper column on level

control. Feed being preheated in Fractionator bottom-flash drum liquid exchanger,

Effluent Flash drum liquid cold exchanger and Effluent-flash drum liquid hot exchanger.

Steam added to the bottom of the tower by flow control helps strip light ends from the

bottoms. The vapours leaving the stripper are cooled and flow into the overhead

receiver. Condensed hydrocarbon is returned to the stripper as reflux. The water phase

is separated in the overhead receiver and sent to the non-phenolic sour water stripping

unit. The non-condensable gases leave the overhead receiver on pressure control and

are routed to the VGO Hydrotreater unit. Corrosion inhibitor injection is done on

stripper over head to prevent corrosion and scaling problems.

4.6. Operating Variables

Catalyst Temperature

The reactor inlet temperature is the process variable most easily and commonly

controlled by the operator to adjust the amount of sulfur (or nitrogen) removed from

the feed. The reactor outlet temperature is a function of the feed quality and cannot be

easily varied except by changing the reactor inlet temperature. The inlet temperature

must be controlled at the minimum required to achieve the desired product properties.

The weight average bed temperature (WABT) is typically used to compare the relative

activity of the catalyst. The rate of increase in WABT is referred to as the deactivation

rate expressed as °C per m3 of feed per kilogram of catalyst (°F per barrel of feed per

pound of catalyst), or more simply as °C per day (°F per day). During the course of an

operating cycle, the temperature required to obtain the desired product quality will

increase as a result of catalyst deactivation.

Fresh feed Quality

The amount of catalyst loaded into the reactors as well as other design parameters are

based on the quantity and quality of feedstock the unit is designed to process. While

minor changes in feed type and charge rate can be tolerated, wide variations should be

avoided since they will tend to reduce the useful life of the catalyst. In general,

increasing the amount of organic nitrogen and sulfur compounds contained in the feed

results in an increase in severity of the operation. The sulfur content of the feed for a

normal vacuum gas oil charge stock can vary up to as high as 2.5 to 3.0 weight percent.

Fresh Feed Rate (LHSV)

The amount of catalyst loaded into the reactors is based on feedstock properties,

operating conditions, and product quality required. The variable that is normally used

to relate the amount of catalyst to the amount of feed is termed liquid hourly space

velocity (LHSV). LHSV is the ratio of volumetric feed rate per hour to the catalyst

volume. A simplified kinetic expression based on sulfur and/or nitrogen removal

determines the initial liquid hourly space velocity for most feedstocks and processing

objectives. This initial value may be modified due to other considerations such as unit

size, extended catalyst cycle life, abnormal levels of feed metals and requirements of

other processing units in the refinery flow scheme. An increase in the LHSV will require

higher reactor temperature to achieve a constant level of desulfurization, as well as

higher recycle gas rate to maintain a constant ratio of H2 to hydrocarbon.

Hydrogen Partial Pressure

The reactor section operating pressure is controlled by the pressure that is maintained

at the high pressure separator. This pressure, multiplied by the H2 purity of the recycle

gas, determines the partial pressure of H2 in the reactor. The hydrogen partial pressure

required for the operation of the unit is chosen based on the degree of sulfur (or

nitrogen) removal that must be achieved and is an economic optimum that balances

initial investment and operating costs against catalyst life. Hydrogen partial pressure is

also a critical design parameter for achieving the desired degree of feed saturation.

Recycle Gas Rate

In addition to maintaining a prescribed partial pressure of hydrogen in the reactor

section, it is equally important to maintain the physical contact of the hydrogen with the

catalyst and hydrocarbon so that the hydrogen is available at the sites where the

reaction is taking place. This is accomplished by circulating the recycle gas throughout

the reactor circuit continuously with the recycle gas compressor. The amount of gas that

must be recycled is a design variable again set by the design severity of the operation.

The standard measure of the amount of gas required is the ratio of the gas being

recycled to the rate that fresh feed is being charged to the catalyst. As with hydrogen

partial pressure, the recycle gas to feed ratio should be maintained at the design ratio. A

gradual reduction in recycle gas rate may be observed during the course of an operating

period as a result of higher reactor system pressure drop. This effect is especially

pronounced on units that use a centrifugal recycle gas compressor. Such a reduction in

the recycle gas rate is acceptable as long as the calculated gas-to-oil ratio does not fall

below the design value.

Recycle Gas Hydrogen Purity and Make-up Hydrogen

The effective completion of the hydrogenation reactions occurring over the catalyst

requires that a certain quantity of hydrogen be present at a minimum partial pressure.

As noted previously, the quantities, gas-to-oil ratio and partial pressure are both

dependent upon the hydrogen content, i.e. purity, of the recycle gas. Practical

considerations, such as the cost of compression, catalyst life, etc., limit the purity of the

recycle gas to a minimum value usually in the range of 70-80 mol%. Lower hydrogen

purities are detrimental to the performance of the unit -since higher temperatures must

be used to achieve the desired product quality.

The purity of the recycle gas is determined by the following factors:

The purity of the makeup gas.

The amounts of light hydrocarbons and H2S that are allowed to accumulate in the

recycle gas.

Catalyst Deactivation Rate in Reactor

1. Problem Statement

To calculate the Catalyst Deactivation Rate in the Reactor installed at Diesel

Hydrotreating Unit for the month of April, 2015.

2. Review of Literature

Hydrotreating catalysts deactivate slowly during unit operation and regeneration is

required to revitalize or replace the catalyst when the reactor End-of-Run (EOR)

temperature is reached. Catalyst deactivation is caused by a deposition and a

physical blocking of the surface by coke, a carbon rich and hydrogen deficient

polynuclear aromatic molecule. During the operation cycle, refiners must make two

important decisions. The first one is how to operate the reactor best to achieve the

processing objectives, and the second, is to make plans for regeneration or

replacement for the next cycle. It is therefore essential to determine the catalyst life

to make future plans.

When a Hydrotreating catalyst is purchased, the catalyst manufacturer provides the

process product yields and qualities, and the expected cycle length for a given

process objective, design feedstocks, operating conditions and other process unit

information by the refiner. For a given catalyst operation cycle, refiners can deviate

from the design parameters to process heavier or lighter feedstock to optimize the

process performance based on the unit economics. The run length can be optimized

based on the cost of the catalyst replacement, and the benefit of either shortening or

extending the run length within the overall economics of the refinery.

Reactions taking place in a Hydrotreating unit are hydrodesulfurization,

hydrodenitrogenation, aromatic hydrogenation and olefin hydrogenation. The latter

one is more important for the Hydrotreating of cracked feedstocks coming from

refining process units such as Coking, Fluid catalytic cracking, Visbreaking, etc. The

hydrodesulfurization reaction is the limiting reaction constraining operation of the

Essar Diesel Hydrotreating Unit and is therefore monitored throughout the cycle.

The hydrodenitrogenation reaction is important when dealing with cracked

feedstocks because nitrogen causes fuel stability problems at a high concentration.

Since the nitrogen content in the feedstock is at low levels, hydrodenitrogenation

reactions are not studied in this work.

3. Operational Parameters Weight Average Bed Temperature

The weight average bed temperature (WABT) is typically used to compare the

relative activity of the catalyst. The rate of increase in WABT is referred to as the

deactivation rate expressed as °C per m3 of feed per kilogram of catalyst (°F per

barrel of feed per pound of catalyst), or more simply as °C per day (°F per day).

During the course of an operating cycle, the temperature required to obtain the

desired product quality will increase as a result of catalyst deactivation.

Liquid Hourly Space Velocity

The amount of catalyst loaded into the reactors is based on feedstock properties,

operating conditions, and product quality required. The variable that is normally

used to relate the amount of catalyst to the amount of feed is termed liquid hourly

space velocity (LHSV). LHSV is the ratio of volumetric feed rate per hour to the

catalyst volume and is defined as:

LHSV = Volume of charge per hour Volume of catalyst.

Normalized WABT

Normalized WABT can be used to measure catalyst activity. Feed/Product

properties may vary from day to day, causing variations in WABT. Normalizing

temperatures accounts for variations in the process. Normalized temperature plots

show how WABT changes over time, at reference (fixed) feed, product, and

operating conditions.

Allows comparing cycles

Indicates deactivation for prediction of remaining cycle length

Helps to identify operating changes (feed quality, upsets, etc.)

4. Data Sampling

Month: April, 2015

Reaction Order (n) - 1.4

Activation Energy (Ea) Cal/mole 27000

Gas Constant (R) Cal/gmole/degK 1.987

Catalyst Volume (V) M3 649.5

Sulfur feed @ SOR ppm 14800

Sulfur product @ SOR ppm 4

LHSV @ SOR 1/hr 0.83

WABT @ SOR °C 362

5. Process Methodology

Calculate Liquid Hourly Space Velocity for current data in each day.

LHSV = Hourly Liquid Volume Feed Rate/Catalyst Volume

Calculate Percentage Conversion for Sulfur feed to Product.

Calculate Kcurrent or Actual Rate Constant using the given formula.

Here, Reaction order (n) is taken as 1.4

Calculate Kreference or Targeted Rate Constant using the given formula.

For Kreference, we use the SOR (start of run) Reference values for LHSV, Sfeed, Sproduct

and Reaction order (n) is taken as 1.4

Calculate Normalized WABT using the given formula.

Here, Tcurrent signifies the actual or current WABT values for each day and Ttarget

signifies the normalized WABT values.

Calculate WABTDelta for each data by subtracting SOR WABT from normalized

WABT values.

WABTDelta = Normalized WABT – SOR WABT

Plot a graph between WABTDelta and number of days in April 2015, i.e. the

given time cycle.

Here, the slope of the curve given by the trend line equation gives the actual

deactivation rate of the catalyst in °C/day for the Reactor installed in Diesel

Hydrotreating Unit.

6. Observations and Calculations

Date Feed Rate (m3/h) LHSV (1/h) Feed Sulfur (in ppm)

Product Sulfur (in ppm)

% Conversion (Sulfur)

1 Apr'15 447.43 0.68888 15800 10.97 99.931

2 Apr'15 490.74 0.75557 17100 9.00 99.947

3 Apr'15 490.39 0.75503 17200 8.75 99.949

4 Apr'15 463.28 0.71329 16900 8.29 99.951

5 Apr'15 436.21 0.67161 18000 8.96 99.950

6 Apr'15 436.57 0.67216 17800 8.75 99.951

7 Apr'15 436.58 0.67218 17500 8.29 99.953

8 Apr'15 436.60 0.67221 17700 9.21 99.948

9 Apr'15 433.63 0.66764 17500 9.84 99.944

10 Apr'15 416.02 0.64052 17300 8.66 99.950

11 Apr'15 435.10 0.66990 16600 9.91 99.940

12 Apr'15 439.51 0.67669 14300 9.00 99.937

13 Apr'15 335.40 0.51640 12400 5.88 99.953

14 Apr'15 354.61 0.54597 15600 9.54 99.939

15 Apr'15 371.64 0.57219 16600 11.25 99.932

16 Apr'15 375.66 0.57838 16500 15.04 99.909

17 Apr'15 367.34 0.56557 16700 14.95 99.910

18 Apr'15 362.15 0.55758 16700 11.17 99.933

19 Apr'15 363.80 0.56012 16900 8.42 99.950

20 Apr'15 356.84 0.54941 16000 8.71 99.946

21 Apr'15 362.36 0.55791 15200 8.54 99.944

22 Apr'15 365.26 0.56237 15400 10.17 99.934

23 Apr'15 361.33 0.55632 15700 11.96 99.924

24 Apr'15 349.44 0.53801 15600 14.58 99.907

25 Apr'15 341.55 0.52587 14300 12.79 99.911

26 Apr'15 339.15 0.52217 13000 9.21 99.929

27 Apr'15 333.24 0.51307 12400 8.50 99.931

28 Apr'15 339.30 0.52240 12300 10.60 99.914

29 Apr'15 338.48 0.52114 12700 16.64 99.869

30 Apr'15 345.61 0.53212 13000 7.14 99.945

Rate Constant (k) - Current

Rate Constant (k) - Targeted @ 4 ppm

Current WABT (°C)

Current WABT (K)

Normalized WABT (K)

Normalized WABT (°C)

Delta WABT

24.8686 45.6716 355.52 628.67 646.86 373.71 11.71

29.7018 45.6716 359.12 632.27 645.19 372.04 10.04

30.0378 45.6716 360.88 634.03 646.67 373.52 11.52

29.0181 45.6716 358.79 631.94 645.56 372.41 10.41

26.4784 45.6716 356.01 629.16 645.45 372.30 10.30

26.7596 45.6716 356.03 629.18 645.15 372.00 10.00

27.3646 45.6716 355.89 629.04 644.32 371.17 9.17

26.1885 45.6716 355.08 628.23 644.81 371.66 9.66

25.2902 45.6716 354.35 627.5 645.11 371.96 9.96

25.5963 45.6716 351.99 625.14 642.25 369.10 7.10

25.2717 45.6716 351.73 624.88 642.36 369.21 7.21

26.4999 45.6716 352.13 625.28 641.34 368.19 6.19

24.1185 45.6716 345.29 618.44 636.95 363.80 1.80

20.9016 45.6716 344.64 617.79 640.55 367.40 5.40

20.4603 45.6716 345.72 618.87 642.36 369.21 7.21

18.2816 45.6716 346.63 619.78 646.79 373.64 11.64

17.9280 45.6716 348.18 621.33 649.08 375.93 13.93

20.0008 45.6716 349.65 622.8 647.30 374.15 12.15

22.6386 45.6716 349.58 622.73 643.42 370.27 8.27

21.8671 45.6716 349.59 622.74 644.49 371.34 9.34

22.3664 45.6716 349.24 622.39 643.43 370.28 8.28

20.9498 45.6716 349.24 622.39 645.43 372.28 10.28

19.3586 45.6716 346.09 619.24 644.45 371.30 9.30

17.2070 45.6716 345.12 618.27 647.01 373.86 11.86

17.7434 45.6716 346.51 619.66 647.58 374.43 12.43

20.2067 45.6716 347.12 620.27 644.25 371.10 9.10

20.5176 45.6716 347.10 620.25 643.76 370.61 8.61

19.0197 45.6716 346.54 619.69 645.48 372.33 10.33

15.6595 45.6716 347.26 620.41 652.29 379.14 17.14

22.9273 45.6716 347.38 620.53 640.69 367.54 5.54

7. Results and Findings

The Deactivation rate for the Catalyst in DHDT Reactor in April, 2015 was found to

be 0.0302 °C/Day.

Similar procedure was adopted for calculation of Deactivation rate using data from

April 2012 to May 2015. The Deactivation rate was found to be 0.29 °C/Month.

According to the recommendations made by Albemarle, the catalyst was found to be

stable as the deactivation rate was less than 0.5 °C/Month.

The Catalyst Proprietor Albemarle recommended that for maximizing Catalyst Life

cycle, the peak temperatures for each catalyst bed in the reactor must be same.

y = 0.0302x + 9.0621

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

0 5 10 15 20 25 30 35

Delta WABT versus Time

8. Conclusions and Recommendations

For over three decades, refiners worldwide have been implementing various projects in

their facilities to accommodate a variety of regulations to improve the quality of

transportation fuels in order to reduce vehicle emissions. One of the key areas of

interest has been the reduction of sulfur in diesel fuel to very low levels. The catalyst

deactivation is very important for the operator of a hydrotreating unit in the planning of

regeneration or the replacement of catalysts. Deterioration in feedstock quality

increases the rate of catalyst deactivation and decreases the product quality and it is

important to monitor the feedstock quality during the cycle. Process economics should

determine the optimum utilization of the unit.

Most Refineries leave plenty of activity on their catalyst fills when the time comes to

change their Hydrotreater reactors. It goes without saying that this wastes a lot of

money. Despite the large opportunity cost of unused catalyst activity, many refiners

struggle to find the right balance between the run length reliability and unit

performance. On one extreme of the spectrum, refineries can lose a significant amount

of profit if their catalyst beds deactivate too quickly.

There are three main components required to develop the right catalyst fill and run

length management strategy for a Hydroprocessing reactor.

Understand the run length requirement.

Establish proper deactivation monitoring tools.

Define a prioritized list of catalyst activity management handles.

Each of the three components mentioned above require in-depth collaboration between

multiple groups within the refinery, thus failure to maximize the value of each catalyst

load results from a gap in communication.

After understanding the Hydrotreater run length requirement, a process engineer

should establish monitoring tools. These monitoring tools should not only trend the

changing temperature of reactor beds over time but should normalize the different

factors of feed qualities and unit operating parameters. Normalization is critical as this

ensures that engineers can differentiate routine catalyst deactivation from other drivers

of high reactor severity, such as aromatic saturation or lower unit pressure.

If we have determined from our catalyst monitoring tools that we have excess activity

beyond our target end of run date, then we can consider the following handles to

improve operational efficiency or increase profit capture.

Increase unit feed rates by increasing diesel endpoint.

Increase processing of challenged feedstocks such as Coker Light Gas Oils (CLGO),

FCC Light Cycle Oil (LCO), etc.

Reduce Hydrogen partial pressure to save energy or improve hydraulic capacity.

Reduce Unit Operating Pressure.

Reduce Recycle Hydrogen Rate.

Surely, many of the handles above have risks, but they are not as risky as many believe

if adjustments are made in small incremental steps and monitored appropriately.

Planning analyst involvement becomes critical when determining which operational

handles to optimally adjust.

At the end of the day, a refinery can increase profitability by properly monitoring hydro

processing catalyst activity and making operational changes to utilize excess run length.

We can minimize financial risk by making small changes and actively monitoring these

changes. In the grand scheme of things, catalyst costs are still relatively cheap compared

to the margin capture that they enable. Even for Hydroprocessing reactors that do not

have stringent run length requirements, it often pays off to utilize your catalyst to the

maximum capability allowed.

Efficiency Computation in RGC

1. Problem Statement

To calculate the Polytropic Efficiency in Recycle Gas Compressor and Mechanical

Efficiency of the Steam Turbine.

2. Review of Literature

A gas compressor is a mechanical device that increases the pressure of a gas by

reducing its volume. Compressors are similar to pumps: both increase the pressure

in a fluid and both can transport the fluid through a pipe. As gases are compressible,

the compressor also reduces the volume of a gas. Liquids are relatively

incompressible; while some can be compressed, the main action of pump is to

pressurize and transport liquids.

Centrifugal compressors use a rotating disk or impeller in a shaped housing to force

the gas to the rim of the impeller, increasing the velocity of the gas. A diffuser

(divergent duct) section converts the velocity energy to pressure energy. They are

primarily used for continuous, stationary service in industries such as oil refineries,

chemical and petrochemical plants and natural gas processing plants. Their

application can be from 100 horsepower (75 kW) to thousands of horsepower. With

multiple staging, they can achieve extremely high output pressures greater than

10,000 psi (69 MPa). Many large snowmaking operations (like ski resorts) use this

type of compressor. They are also used in internal combustion engines as

superchargers and turbochargers. Centrifugal compressors are used in small gas

turbine engines or as the final compression stage of medium sized gas turbines.

Diesel Hydrotreater Unit has one Recycle Gas Compressor (138K-001). Recycle gas

compressor (138K-001) is used to circulate Hydrogen gas/Recycle gas to the

Reactor section to provide required amount of Hydrogen for the reaction and to

provide quench gas for Reactor bed temperature control. RGC is provided with lube

oil and dry gas seal systems. Process gas and Nitrogen are used as Buffer gas. RGC is

driven by a Steam Turbine (138KB-001).The capacity of the Compressor is 461000

Nm3/hr. RGC is a 10 stage Centrifugal compressor (Model No: 29MB10) driven by a

back pressure steam turbine (Model No: SRV-3). Both are supplied by M/s Elliott

Ebara Turbo Corporation (EETC). HP Steam is used to drive the back pressure

turbine (Model No: SRV-3) and LP Steam is exhausted from the other end. It is a

Multi Stage Multi valve Turbine. Turbine casing consists of a high pressure cast

steam chest, an intermediate barrel section and a separate exhaust casing.

When any of the following parameters – molecular weight, ratio of specific heat,

suction or discharge pressure or temperature change with respect to flow, a

different point is reached on the head capacity curve for any given compressor

because the compressor develops head and not pressure. Centrifugal compressors

and blowers follow the “fan laws “regarding variation in capacity and head as a

function of speed.

N1/N2= Q1/Q2 = (H1/H2)1/2

Where N is speed, Q is volumetric capacity & H is head

Thus the most efficient way to match the compressor characteristics to the required

output is to change the speed in accordance with the above equation. This is one of

the principal advantages of using steam turbines as drivers for compressors; they

are inherently suited to variable speed operation. The speed can be controlled

manually by an operator adjusting the speed governor on the turbine. The speed

adjustment can also be made automatically by a pneumatic or electronic controller

that changes the speed in response to flow or pressure signal.

3. Operational Parameters

Centrifugal compressors have variable head capacity characteristics. These are used

for handling large volume of gas at relatively intermediate discharge pressure. These

are simples, have less maintenance and longer reliability factors.

There are two ways in which the thermodynamics calculations are performed by

assuming:

Isentropic Reversible Path: A process during which there is heat added to or

removed from the system and entropy remains constant. PVk = constant.

Polytropic Reversible Path: A process in which in gas characteristics during

compression are considered. PVn = constant.

Polytropic head

Head calculated along a reversible path, along which reversible head and reversible

heat are added in constant proportion to raise the pressure and temperature of gas

from the initial values to the desired pressure and actual outlet pressure.

Polytropic efficiency

Ratio of polytropic head versus the enthalpy rise from the initial pressure and

temperature to the final pressure and temperature.

Volumetric efficiency

The ratio of the inlet volume flow rate of a reciprocating compressor stage versus

the piston displacement of that stage. Piston displacement is the product of the

cylinder swept volumes and compressor speed in revolution per minute. Swept

volume of a cylinder is the product of piston area and stroke for each acting end of

the cylinder.

Compressor gas power

The gas power of compressor section is equal to the rate of energy added to the gas

stream plus the energy rejected to cylinder cooling and similar integral compressor

and cooling system.

Efficiency

As this compressor is Turbine driven the efficiency is the ratio of Gas power to

Turbine power.

4. Process Methodology Determine Average Molecular weight of the mixture.

Calculation of Cp

Here, ‘T’ is Outlet Temperature. Values of constants A, B, C and D are taken from

Enthalpy Tables.

Centrifugal Compressor Polytropic Efficiency hp

Where,

Calculation of Polytropic Head

Where,

Zavrg = (Z1 + Z2)/2

The values of compressibilities Z1 and Z2 are to be taken from Design Data Sheet

for Recycle Gas Compressors.

Calculation of Mass Flow Rate

Mass Flow Rate in kg/hr = Given Flow Rate * 0.85 * (Mol.wt. / 22.4)

0.85 is the safety factor adopted for flow conditions.

Calculation of Gas Power

Gp is in KW.

Calculation of Turbine Power

Turbine power, tp =

,

Hin and Hout are Enthalpy Values for Superheated Steam at a given Temperature

and Pressure; Qs is steam feed rate in kg/hr.

Calculation of Efficiency

Efficiency =

5. Data Sampling

26 June, 2015

Name %mol MW %MW A B C D Temp in K

Cp in J/mol*K

%Cp in mixture

C1 1.3 16.0 0.2 1.7 9.1 -2.2 0.0 351.3 38.5 0.5

C2 0.2 30.1 0.1 1.1 19.2 -5.6 0.0 351.3 59.8 0.1

C3 0.2 44.1 0.1 1.2 28.8 -8.8 0.0 351.3 85.1 0.1

C6 0.0 86.2 0.0 3.0 53.7 -16.8 0.0 351.3 164.8 0.0

H2 98.2 2.0 2.0 3.2 0.4 0.0 0.1 351.3 28.8 28.3

iC4 0.1 58.1 0.0 1.7 37.9 -11.9 0.0 351.3 112.2 0.1

iC5 0.0 72.2 0.0 2.5 45.4 -14.1 0.0 351.3 138.5 0.0

N2 0.2 28.0 0.0 3.3 0.6 0.0 0.0 351.3 29.3 0.0

nC4 0.0 58.1 0.0 1.9 36.9 -11.4 0.0 351.3 112.2 0.0

O2 0.0 32.0 0.0 3.6 0.5 0.0 -0.2 351.3 30.2 0.0

H2S 0.0 34.1 0.0 3.9 1.5 0.0 -0.2 351.3 35.5 0.0

100.0 2.4 29.1

3 July, 2015

Name %mol MW %MW A B C D Temp in K

Cp in J/mol*K

%Cp in mixture

C1 1.6 16.0 0.3 1.7 9.1 -2.2 0.0 356.0 38.7 0.6

C2 0.3 30.1 0.1 1.1 19.2 -5.6 0.0 356.0 60.4 0.2

C3 0.1 44.1 0.1 1.2 28.8 -8.8 0.0 356.0 86.0 0.1

C6+ 0.1 86.2 0.0 3.0 53.7 -16.8 0.0 356.0 166.5 0.1

H2 97.7 2.0 2.0 3.2 0.4 0.0 0.1 356.0 28.8 28.1

iC4 0.0 58.1 0.0 1.7 37.9 -11.9 0.0 356.0 113.4 0.0

iC5 0.0 72.2 0.0 2.5 45.4 -14.1 0.0 356.0 139.8 0.0

N2 0.2 28.0 0.1 3.3 0.6 0.0 0.0 356.0 29.3 0.1

nC4 0.0 58.1 0.0 1.9 36.9 -11.4 0.0 356.0 113.3 0.0

nC5 0.0 72.2 0.0 2.5 45.4 -14.1 0.0 356.0 139.8 0.0

100.0 2.5 29.2

10 July, 2015

Name %mol MW %MW A B C D Temp in K

Cp in J/mol*K

%Cp in mixture

C1 1.0 16.0 0.2 1.7 9.1 -2.2 0.0 354.7 38.7 0.4

C2 0.2 30.1 0.1 1.1 19.2 -5.6 0.0 354.7 60.3 0.1

C3 0.1 44.1 0.0 1.2 28.8 -8.8 0.0 354.7 85.7 0.1

C6+ 0.0 86.2 0.0 3.0 53.7 -16.8 0.0 354.7 166.0 0.1

H2 98.6 2.0 2.0 3.2 0.4 0.0 0.1 354.7 28.8 28.4

iC4 0.0 58.1 0.0 1.7 37.9 -11.9 0.0 354.7 113.1 0.0

iC5 0.0 72.2 0.0 2.5 45.4 -14.1 0.0 354.7 139.5 0.0

N2 0.1 28.0 0.0 3.3 0.6 0.0 0.0 354.7 29.3 0.0

nC4 0.0 58.1 0.0 1.9 36.9 -11.4 0.0 354.7 113.0 0.0

nC5 0.0 72.2 0.0 2.5 45.4 -14.1 0.0 354.7 139.5 0.0

100.0 2.3 29.1

23 July, 2015

Name %mol MW %MW A B C D Temp in K

Cp in J/mol*K

%Cp in mixture

C1 1.2 16.0 0.2 1.7 9.1 -2.2 0.0 363.9 39.2 0.5

C2 0.3 30.1 0.1 1.1 19.2 -5.6 0.0 363.9 61.5 0.2

C3 0.1 44.1 0.1 1.2 28.8 -8.8 0.0 363.9 87.5 0.1

C6+ 0.0 86.2 0.0 3.0 53.7 -16.8 0.0 363.9 169.2 0.1

H2 98.0 2.0 2.0 3.2 0.4 0.0 0.1 363.9 28.8 28.2

iC4 0.0 58.1 0.0 1.7 37.9 -11.9 0.0 363.9 115.3 0.0

iC5 0.0 72.2 0.0 2.5 45.4 -14.1 0.0 363.9 142.2 0.0

N2 0.3 28.0 0.1 3.3 0.6 0.0 0.0 363.9 29.3 0.1

nC4 0.0 58.1 0.0 1.9 36.9 -11.4 0.0 363.9 115.2 0.0

O2 0.0 32.0 0.0 3.6 0.5 0.0 -0.2 363.9 30.4 0.0

100.0 2.4 29.2

6. Results and Findings

Compressor

Date Inlet T (K) Outlet T (K) Inlet pressure (kg/cm2a)

Outlet pressure (kg/cm2a)

Mass flow rate (kg/hr)

26 June, 2015 332.3000 363.0700 84.2600 97.2100 25005.9038

03 July, 2015 334.3700 353.6400 84.1800 98.9400 28328.8323

10 July, 2015 334.6700 365.5000 84.2600 97.7300 22401.9953

23 July, 2015 334.1500 363.9400 83.8800 104.3900 30411.7826

n Cp k hp Hp, (J/kg) Gp, (KW)

1.6360 29.1220 1.3995 0.7341 178668.2866 1690.6480

1.6340 29.2500 1.3971 0.7326 185083.9060 1988.0550

1.6440 29.1050 1.3998 0.7295 182393.3557 1555.8410

1.6400 29.1840 1.3983 0.7297 259231.7050 3001.1030

Turbine

Inlet T (K) Outlet T (K) Inlet pressure (kg/cm2g)

Outlet pressure (kg/cm2g)

Steam flow rate (kg/hr)

632.08 472.23 40.04 3.83 26147.49

643.00 477.46 39.86 3.83 30458.80

639.11 476.19 39.96 3.69 25219.24

651.15 464.15 40.00 3.87 38380.00

Hin (kJ/kg)

Hout (kJ/kg)

ΔH Turbine power

Efficiency Efficiency (%)

3114.85 2855.12 259.73 1886.469 0.89619 89.619

3141.97 2866.26 275.71 2332.721 0.85224 85.224

3132.28 2864.25 268.03 1877.642 0.82861 82.861

3161.43 2837.57 323.86 3452.707 0.869202 86.920

7. Conclusion and Recommendations

A compressor is a fluid handling mechanical device capable of efficiently

transferring energy to the fluid medium so that it can be delivered in large quantities

at elevated pressure conditions. Based on the design characteristics, DHDT Recycle

Gas Compressor should have polytropic efficiency in the range of 77-79 %. In order

to achieve this, feed throughput needs to be increased with proper monitoring and

variation of inlet & outlet Pressure-Temperature variations.

Estimation of Fired Heater Efficiency

1. Problem Statement

To calculate the efficiency of Fuel Gas Fired Heater.

2. Review of Literature

Furnaces are a versatile class of equipment where heat is liberated and transferred

directly or indirectly to a solid or fluid mass for the purpose of effecting a physical or

chemical change. In industrial practice many and varied types of furnaces are used

which may differ in function, overall shape or mode of firing, and furnaces may be

classified accordingly on the basis of their function such as smelting or roasting, their

shape such as crucibles, shafts and heaths or they may be classified according to their

mode of firing into electrical, nuclear, solar, and combustion furnaces.

Combustion furnaces are two general types:

Fired heaters and

Converters

A converter is a type of furnaces in which heat is liberated by the oxidation of impurities

or other parts of the material to be heated. Fired heaters, on the other hand, are

furnaces that produce heat as a result of the combustion of fuel. The heat liberated is

transferred to the material to be heated directly (in internally heated furnaces) or

indirectly (in externally heated furnaces). Tubular fired heaters are generally built with

two distinct heating sections: a radiant section, variously called a combustion chamber

or firebox, and a convection section followed by the stack. The hot flue gases arising in

the radiation section flow next into the convection section where they circulate at high

speed through a tube bundle before leaving the furnace through the stack. A third

section, known as a shield or shock section, separates the two major heating sections. It

contains those tubes close to the radiation section that shield the remaining convection

section tubes radiation. The shield section normally consists of two to three rows of

bare tubes that are directly exposed to the hot gasses and flame in the radiant section,

but the arrangement varies widely for the many different heater designs. In certain fired

heater designs, known as the all-radiant type, there is no separate convection section.

Fired heaters are usually classified as vertical cylindrical or box-type heaters depending

on the geometrical configuration of the radiant section. In box-type heaters, the radiant

section has generally a square cross section (as in older furnaces, where the reduced

height is compensated for by a larger construction site) or a rectangular cross section

(with its height equal to 1.5 to 2.5 times its width) as in cabin-type heaters. The

configuration of the type heater with horizontal tubes may have a so- called hip, or the

radiant section may be just a rectangular box.

Radiant section

The tubes in the radiant section may be arranged horizontally or vertically along the

heater walls including the hip and the burners are located on the floor or on the lower

part of the longest side wall where there are no tubes. A fire wall is often built down the

center of the combustion chamber in heaters from the sides.

Box-type furnaces are best suited for large capacities and large heat duties. This makes

such furnaces particularly suitable for topping units where it is possible to increase tube

length in both the radiation and convection sections reducing thereby the required

number of headers or return bends. It is possible in such furnaces to open the headers

for cleaning, something which makes cleaning the tubes in the radiation section easier;

this is especially significant in furnaces used to heat easily- cooking oils.

In the cylindrical-type furnace, the radiation section is in the shape of a cylinder with a

vertical axis, and the burners are located on the floor at the base of the cylinder. The

next exchange area covers the vertical walls and therefore exhibits symmetry with

respect to the heating assembly. In the radiant section, the tubes may be in a circular

pattern around the walls of the box or they may be in a cross or octagonal design which

will expose them to firing from both sides. Older designs have radiating cones in the

upper part of the radiant section as well as longitudinal fins on the upper parts of tubes.

The shield and convection tubes are normally horizontal. Cylindrical heaters with

vertical tubes are commonly used in hot oil services and other process where the duties

are small, but larger units, 100 million KJ/hr and higher, are not uncommon. Cylindrical

heaters are often preferred to box-type heaters. This is mainly due to the more uniform

heating rate in cylindrical heaters and higher thermal efficiency. Furthermore,

cylindrical heaters require smaller foundations and construction areas and their

construction cost is less. High chimneys are not essential in cylindrical furnaces because

they normally produce sufficient draught.

Analysis and evaluation of Heat transfer

In the usual practice, the process fluid is first heated in the convection section preheated

coil which is followed by further heating in the radiant section. In both sections heat is

transferred by both mechanisms of heat transfer, viz. radiation and convection, where

radiation is the dominant predominates in the convection section where the average

temperature is much lower. Most of the heat transferred to the process fluid takes place

in the radiant section while the convection serves only to make up the difference

between the heat duty of the furnace and the part absorbed in the radiant section.

Convection Section

The feed charge enters the coil inlet in the convection section where it is preheated

before transferring to the radiant tubes. The convection section removes heat from the

flue gas to preheat the contents of the tubes and significantly reduces the temperature

of the flue gas exiting the stack. Too much heat picked up in the convection section is a

sign of too much draft. Tube temperature is taken in both convection and radiant

sections.

Shield Section

Just below the convection is the shield (or shock tube) section, containing rows of

tubing which shield the convection tubes from the direct radiant heat. Several

important measurements are normally made just below the shield section. the bridge

wall or break wall temperature is the temperature of the flue gas after the radiant heat

is removed by the radiant tubes and before it hits the convection section.

Stack and Breeching

The transition from the convection section to the stack is called the breeching. By the

time flue gas exits the stack, most of the heat should be recovered and the temperature

is much less. From a measurement point of view, this location places fewer demands on

the analyzer but is much less desirable for the ability to control the process.

Measurement of stack emission for compliance purposes is normally made here.

3. Process Calculations and Methodology

The net thermal efficiency is equal to the total heat absorbed divided by the total heat

input. The heat absorbed is equal to the total heat input minus the total heat losses from

the system.

Efficiency of heater is given by

=

=

Where,

LHV= lower heating value of fuel, Kcal/kg of fuel

Ha = sensible heat input of air, Kcal/kg of fuel

Hf = sensible heat input of fuel, Kcal/kg of fuel

Qs = calculated stack heat losses of fuel, Kcal/kg of fuel

Qr = assumed radiation heat loss, Kcal/kg of fuel

Tt = combustion air temperature,

Td = datum temperature,

Tf = fuel gas temperature,

Date: 21 July, 2015

Equipment: DHDT Heater (138F-001)

Description IP Tag Value (Given) UOM

FG supply flow rate 138FI0831B 54.30 kg/hr

FO supply flow rate 0.00 kg/hr

Flue Gas Oxygen 138AI0833A 2.60 %

Ambient Air Temperature 33.14 Deg C

Exit Flue Gas Temp 138TI0806 155.90 Deg C

Fuel Oil Temperature 0.00 Deg C

Atomizing Medium Temperature 0.00 Deg C

Fuel Gas Temp 137TI0852 58.30 Deg C

Total FO+FG 54.30 kg/hr

Wt fraction of FO 0.00

Wt fraction of FG 1.00

Datum Temp 15.00 Deg C

Atomizing Steam Consumption 0.00 Kg/Kg FO

Relative Humidity of Air 43.00 %

Vapor pressure of water at ambient temperature

0.72 Psia

Radiation Heat Loss 2.50 %

FO Lower Heating Value 9748.50 Kcal/Kg

Carbon to Hydrogen Ratio 8.10

Atomizing Steam Enthalpy Difference (Between Steam Temp & Datum Temp)

0.00 Kcal/Kg

Combustion Calculations

Basis-1 Kg of FO+FG Wt Fraction FO

0.00 Wt Fraction FG

1.00

Fuel Component MW Vol. Fraction FO

Component Wt. FO

Wt. Fraction FO

Carbon 12.00 88.39 10.6068 0.96

1-3 Butadiene 54.09 0.00 0.0000 0.00

Methane 16.04 0.00 0.0000 0.00

Ethane 30.07 0.00 0.0000 0.00

Ethylene 28.05 0.00 0.0000 0.00

Acetylene 26.04 0.00 0.0000 0.00

Propane 44.10 0.00 0.0000 0.00

Propylene 42.08 0.00 0.0000 0.00

Butylene 56.11 0.00 0.0000 0.00

N Hexane C6+ 86.18 0.00 0.0000 0.00

Cis Butylene 56.11 0.00 0.0000 0.00

CO 28.01 0.00 0.0000 0.00

CO2 44.01 0.00 0.0000 0.00

H2 2.02 10.92 0.2201 0.02

H2S 34.08 0.00 0.0000 0.00

IC4 58.12 0.00 0.0000 0.00

Iso Butylene 56.11 0.00 0.0000 0.00

Iso Pentane 72.15 0.00 0.0000 0.00

Nitrogen 28.01 0.00 0.0000 0.00

NC4 58.12 0.00 0.0000 0.00

N Pentane 72.15 0.00 0.0000 0.00

Oxygen 32.00 0.00 0.0000 0.00

Trans 2 Butene 56.11 0.00 0.0000 0.00

Sulfur 32.00 0.69 0.2208 0.02

Total 100.00 11.0477 1.000

Vol. Fraction FG Component Wt. FG

Wt. Fraction FG

Total Wt. FO+FG

Air Required

Kg Kg/Kg Component

0.00 0.00 0.0000 0.000 11.608

0.00 0.00 0.0000 0.000 14.169

42.95 6.89 0.3186 0.319 17.391

17.26 5.19 0.2400 0.240 16.232

4.26 1.20 0.0553 0.055 14.907

0.00 0.00 0.0000 0.000 13.378

3.37 1.49 0.0687 0.069 15.810

2.29 0.96 0.0446 0.045 14.906

0.06 0.03 0.0016 0.002 14.906

0.17 0.15 0.0068 0.007 15.369

0.11 0.06 0.0027 0.003 14.906

0.83 0.23 0.0108 0.011 2.484

0.44 0.19 0.0090 0.009 0.000

16.43 0.33 0.0153 0.015 34.783

0.03 0.01 0.0005 0.001 6.138

1.77 1.03 0.0459 0.046 15.592

0.00 0.00 0.0000 0.000 14.906

0.19 0.14 0.0063 0.006 15.458

7.79 2.18 0.1009 0.101 0.000

2.07 1.20 0.0556 0.056 15.592

0.13 0.09 0.0043 0.004 15.458

0.70 0.22 0.0104 0.010 0.000

0.11 0.06 0.0027 0.003 14.877

0.00 0.00 0.0000 0.000 4.348

100.96 21.665 1.0000 1.000

Total Air Required CO2 Produced

H2O Produced

N2 Produced Total Air Required

Kg Kg/Kg Component

Kg/Kg Component

Kg/Kg Component

Kg

0.000 3.67 0.00 8.759 0.00

0.000 3.25 1.00 10.692 0.00

5.541 2.75 2.24 13.123 5.54

3.896 2.93 1.80 12.249 3.90

0.824 3.14 1.28 11.249 0.82

0.000 3.38 0.69 10.095 0.00

1.086 2.99 1.63 11.930 1.09

0.665 3.14 1.28 11.248 0.66

0.024 3.14 1.28 11.248 0.02

0.105 3.06 1.46 11.597 0.10

0.040 3.14 1.28 11.248 0.04

0.027 1.57 0.00 1.874 0.03

0.000 0.00 0.00 0.000 0.00

0.532 0.00 9.00 26.247 0.53

0.003 0.00 0.53 4.632 0.00

0.716 3.03 1.55 11.766 0.72

0.000 3.14 1.28 11.248 0.00

0.097 3.05 1.50 11.665 0.10

0.000 0.00 0.00 0.000 0.00

0.867 3.03 1.55 11.766 0.87

0.066 3.05 1.50 11.665 0.07

0.000 0.00 0.00 0.000 0.00

0.040 3.14 1.28 11.226 0.04

0.000 0.00 0.00 3.281 0.00

14.529 14.529

Total CO2 Produced

Total H2O Produced

Total N2 Produced

Kg Kg Kg

0.00 0.00 0.00

0.00 0.00 0.00

0.88 0.71 4.18

0.70 0.43 2.94

0.17 0.07 0.62

0.00 0.00 0.00

0.21 0.11 0.82

0.14 0.06 0.50

0.01 0.00 0.02

0.02 0.01 0.08

0.01 0.00 0.03

0.02 0.00 0.02

0.00 0.00 0.00

0.00 0.14 0.40

0.00 0.00 0.00

0.14 0.07 0.54

0.00 0.00 0.00

0.02 0.01 0.07

0.00 0.00 0.00

0.17 0.09 0.65

0.01 0.01 0.05

0.00 0.00 0.00

0.01 0.00 0.03

0.00 0.00 0.00

2.497 1.716 10.964

Component Combustion Reaction Moles of O2

required

Moles of CO2

required

Moles of H2O required

Hydrogen H2+ 0.502 → H20 0.5 0 1

Carbon Monoxide CO+0.5O2 → CO2 0.5 1 0

Hydrogen sulfide H2S+1.5O2→SO2+ H2O 1.5 0 1

Methane CH4+2O2→CO2+2H2O 2 1 2

Ethane C2H6+3.5O2

→2CO2+3H2O

3 2 3

Ethylene C2H4 +3O2 →

2CO2+2H2O

3.5 2 2

Propane C3H8+5O2

→3CO2+4H2O

5 3 4

Propylene C3H6+4.5O2 → 3CO2

+3H2O

4.5 3 3

I-Butane C4H10+6.5O2 →

4CO2+5H2O

6.5 4 5

n-butane C4H10+6.5O2 →

4CO2+5H2O

6.5 4 5

Butylene C4H8+6O2

→4CO2+4H2O

6 4 4

I-pentane C5H12+8O2 →

5CO2+6H2O

8 5 6

n-pentane C5H12+8O2 →

5CO2+6H2O

8 5 6

n-hexane C6H14+9.5O2

→6CO2+7H2O

9.5 6 7

Sulfur dioxide S+1.5O2→SO2+H2O 1.5 0 1

In our calculations, we have assumed a basis of 1 kg FO+FG. FO stands for Fuel Oil

and FG stands for Fuel Gas. Fuel Oil is assumed to be negligible.

Based on stoichiometric calculations, we have found out the Component weight for

Fuel Gas.

Based on the combustion reactions, we can find the quantity of Air required, Oxygen

Required, Nitrogen produced, Carbon dioxide produced and Water Vapor produced.

For eg. Consider the Combustion reaction for Methane.

CH4 + 2O2 → CO2 + 2 H2O

16 kg Methane requires 64 kg Oxygen to produce 44 kg Carbon dioxide and 36 kg

Water.

So, 1 kg Methane requires 64/16 kg Oxygen to produce 44/16 kg Carbon dioxide

and 36/16 kg Water. Similarly, we can calculate for the rest of the components.

Now, total quantity produced/required for each will be calculated by multiplying the

above calculated values by their respective weight fractions in Fuel Gas.

We must remember that Air contains Nitrogen 78.03 % by volume and 75.46 % by

mass. Air contains 21 % by volume and 23 % by mass. Nitrogen produced, Air and

Oxygen required will be calculated stoichiometrically using these facts.

Correction for relative humidity

Total Air Required 14.529 Kg

Moisture in Air 0.013 Kg Moisture/ Kg of Air

Kg of wet air/ Kg of fuel 14.723 Kg air/ Kg of Fuel

Kg of Moisture (along with air) 0.194 Kg water/ Kg of Fuel

Kg of H2O per kg of fuel (without excess air correction)

1.91 Kg water/ Kg of Fuel

Correction for excess air

Kg of Excess Air per Kg of Fuel 2.42

Excess Air (Wt %) (from graph) 16.67 %

Total H2O corrected for excess air

1.915 Kg Water/ Kg of Fuel

Stack Loss (Calculated from Graph)

Component

kg/ Kg of Fuel

Enthalpy at Stack

Temp

Enthalpy at Stack Temp

Heat Content

Btu/lb of Componen

t

Kcal/Kg of Component

Kcal/Kg of Fuel

Carbon Dioxide 2.497 51.130 28.424 70.98

Water Vapor 1.915 101.290 56.309 107.81

Nitrogen 10.964 64.750 35.996 394.64

Air 2.422 56.340 31.321 75.86

Total 17.80 152.05 649.29

Heat Corrections

Components Wt. Fraction Cp Temp In Temp Out Heat duty (Q)

UOM Kg of component/kg

Kcal/kg C Deg C Deg C Kcal

of fuel

Air Sensible Heat Correction (a) 17.14 0.24 15.00 33.14 74.64

Fuel Oil Sensible Heat Correction (fo)

0.00 0.50 15.00 0.00 0.00

Fuel Gas Sensible Heat Correction (fg)

1.00 0.54 15.00 58.30 23.38

Atomizing Enthalpy Difference 0.00

Fuel Gas LHV Calculation

Basis-1 Kg of FO+FG

Wt Fraction

FO

0.00 Wt Fraction FG

1.00

Fuel Component Mole % Mol. Wt.

Component Wt.

Wt. Fraction

Pure Components NCV

Component NCV

Kcal/kg Kcal/kg

Methane 42.95 16.04 6.89 0.32 11944 3804.37

Ethane 17.26 30.07 5.19 0.24 11344 2722.11

Ethylene 4.26 28.05 1.19 0.06 11272 622.74

Propane 3.37 44.10 1.49 0.07 11072 760.78

Propylene 2.29 42.08 0.96 0.04 10939 487.36

Butylene 0.06 56.11 0.03 0.00 10789 16.79

N Hexane C6+ 0.17 86.18 0.15 0.01 10772 72.97

Cis Butylene 0.11 56.11 0.06 0.00 10784 30.77

Carbon Monoxide 0.83 28.01 0.23 0.01 2414 25.95

Carbon Dioxide 0.44 44.01 0.19 0.01 0 0.00

Hydrogen 16.43 2.02 0.33 0.02 28667 439.88

Hydrogen Sulfide 0.03 34.08 0.01 0.00 3639 1.72

Iso Butane 1.77 56.11 0.99 0.05 10905 500.73

Iso Pentane 0.19 72.15 0.14 0.01 10821 68.58

Nitrogen 7.79 28.01 2.18 0.10 0 0.00

N Butane 2.07 58.12 1.20 0.06 10933 608.14

N Pentane 0.13 72.15 0.09 0.00 10843 47.02

Oxygen 0.70 32.00 0.22 0.01 0 0.00

Trans 2 Butene 0.11 56.11 0.06 0.00 10780 30.76

Total 21.63 1.00 10240.67

Correction for Relative Humidity

Moisture in Air

= (Relative Humidity of Air * Vapor Pressure of Water at Ambient Temperature * 18) /

(Normal Pressure in psia * 100 * Molecular wt. of Air)

Kg of wet air/kg of fuel

= Total Air required / (1- Moisture in Air)

Kg of Moisture along with Air

= (Kg of wet air/kg of fuel) – Total Air required

Total Moisture

= Atomizing Steam Consumption + Kg of Moisture along with Air + Total H2O Produced

Correction for Excess Air

Kg of Excess Air per Kg of Fuel

= (Total Air Required * Excess Air wt. percent)/100

Excess Air wt. percent

Calculated from Graph

Graph showing relationship between O2 % in Flue Gas and Excess Air Wt. %

Total H2O corrected for Excess Air

= (((Kg of Excess Air per kg of Fuel)/100) * (Kg of Moisture along with Air)) + Kg of H2O per

kg of Fuel without excess Air correction

Calculation of Stack Losses

Enthalpy at Stack Temperature

Here, Stack temperature is found to be 151.2 °C or 304.16 °F. Enthalpy is calculated using

Enthalpy-Temperature graph. Stack Enthalpy is found in Btu/lb which is converted to

Kcal/kg.

1 Btu/lb = 0.55592 Kcal/kg

Heat Content

= Kg/kg of Fuel * Enthalpy at Stack temperature in Kcal/kg.

Heat Correction

These values are found out using the relation H = M*Cp* (Tout – Tin)

Fuel Gas LHV Calculation

Component LHV = Pure Component LHV * Wt. Fraction of Components

Fuel Gas LHV = Ʃ (Component LHV)

Radiation Loss

= 2.5 % of Fuel Gas LHV

4. Results and Findings

Efficiency Calculations

Total Fuel LHV 10240.67

Radiation loss 256.02

Stack loss (S) 649.29

Total Heat Input 10338.69

Radiation loss +Stack Loss 905.30

Net Thermal Efficiency

91.24

5. Conclusions and Recommendations

Increasing the thermal efficiency of a Fired Heater reduces the heater’s carbon footprint

and operating costs. For example, assuming a Fired Heater with a heat release of 100

MBTU/hr, an increase in efficiency of 1% will result in a savings of $38K/yr at a fuel

cost of $4 per MBTU.

There are two areas that determine the heat losses from a Fired Heater:

Stack losses are related to the temperature of the flue gas and the amount of flue gas

leaving the stack.

The heat losses are also due to radiation from the Fired Heater casing.

Excess air influences stack loss by decreasing or increasing the stack gas flow rate. To

minimize the flue gas flow rate, the excess air to the burners should be minimized. This

can be accomplished by first testing the Fired Heater to determine the minimum excess

air level at which it can safely operate.

Fired Heaters typically operate at an internal pressure which is less than atmospheric or

negative. Therefore, any openings in the Fired Heater will allow ambient air to be

infiltrated or leaked into the box. The result of this leakage has the same effect on flue

gas rates as operating at high excess air levels through the burners. To reduce the air

infiltration, the openings should be sealed. To determine the amount of air being leaked,

a portable O2 analyzer should be used to measure the O2 entering and leaving the

convection section. The openings typically occur at tube penetrations and header boxes

which are mostly located in the convection section. A visual inspection should be made

of these areas, and also of the radiant section around peep doors and outlet piping.

A focused audit done by an experienced fired equipment engineer can often quickly

identify things that may easily be done to improve thermal efficiency without making

any capital investments.

Thermal efficiency depends upon various factors like fuel gas temperature, combustion

efficiency, and other losses. We understand that radiation and stack losses are

unavoidable but their heat content can be utilized for other purposes like air pre-heater

to prevent heat and capital cost.

The performance objectives of process heaters are to maximize heat delivery of the

process-side feed while minimizing fuel consumption, maximize heat delivery with

varying fuel quality, minimize heater structural wear, minimize stack emissions and

maximize safety integrity levels. Energy costs represent up to 65% of the cost of

running a chemical/petrochemical/refining complex. Furnace and heater fuel is the

largest component of this cost. Correct use and placement of gas analyzers can conserve

the amount of fuel used and maximize heater efficiency. When waste fuel was cheap, the

excess was often flared with little reason to seek efficiency improvements. Today many

refinery processes require hydrogen and a lot of the hydrogen-rich off-gases, which

were previously used as heater fuel, are needed to meet this demand. Natural gas, which

is now very expensive, is used to make up shortfalls. The more energy that can be

squeezed from existing plant fuels, the less supplementary natural gas is required.

Stringent emission limits require greater control of NOx and other stack components.

Operating the heater at optimum efficiency, with low excess air firing is the simplest

and least expensive way to reduce NOx emissions.

Gases with widely varying calorific content are now widely used as fuel for heaters. This

can produce large variations in heat delivered in the radiant section, and therefore, to

greater demands on control of combustion to maintain the product or feed temperature.

Localized heating can lead to coking and a drop in capacity. Temperature control of the

process tubes and reactions is critical in reforming and cracking operations.

Operators often feel that it is sufficient to maintain thermal objectives and this can be

done by controlling the excess air from an oxygen analyzer. Even the smallest heater

benefits from fast response O2 and ppm combustibles because slugs of waste gas with

poor BTU value can hit the burners at any time causing major and rapid changes to the

combustion parameters. Oxygen and combustibles analyzers can help meet heater

performance objectives with minimal investment cost. Benefits include improved

efficiency, reduced emissions, increased heater and tube life, consistent product quality

and optimum throughput.

The analyzer provides the information needed for proper control during start-up and

operation. It is a window into the process to monitor burner performance and avoid

problems due to air and tube leaks. Low NOx burners are sensitive to changing

combustion parameters and benefit from increased flue gas information. Even older

heaters with manual secondary air adjustments can benefit from optimization made

possible by reliable oxygen and combustibles measurements from the correct location.

Carmagen. All the right people in all the right places. www.carmagen.com

Figure 1 – Enthalpy of H2O, CO, CO2, and SO2

Figure 2 – Enthalpy of Air, O2, and N2

Prediction of Power Requirements for Centrifugal Pump

1. Problem Statement

To calculate the power requirements for operating the Charge pump installed in Diesel

Hydrotreating Unit and hence, evaluate its performance.

2. Review of Literature

A centrifugal pump is one of the simplest pieces of equipment in any process plant. Its

purpose is to convert energy of a prime mover (a electric motor or turbine) first into

velocity or kinetic energy and then into pressure energy of a fluid that is being pumped.

The energy changes occur by virtue of two main parts of the pump, the impeller and the

volute or diffuser. The impeller is the rotating part that converts driver energy into the

kinetic energy. The volute or diffuser is the stationary part that converts the kinetic

energy into pressure energy. All of the forms of energy involved in a liquid flow system

are expressed in terms of feet of liquid i.e. head.

The process liquid enters the suction nozzle and then into eye (center) of a revolving

device known as an impeller. When the impeller rotates, it spins the liquid sitting in the

cavities between the vanes outward and provides centrifugal acceleration. As the liquid

leaves the eye of the impeller a low-pressure area is created causing more liquid to flow

toward the inlet. Because the impeller blades are curved, the fluid is pushed in a

tangential and radial direction by the centrifugal force. The key idea is that the energy

created by the centrifugal force is kinetic energy. The amount of energy given to the

liquid is proportional to the velocity at the edge or vane tip of the impeller. The faster

the impeller revolves or the bigger the impeller is, then the higher will be the velocity of

the liquid at the vane tip and the greater the energy imparted to the liquid. This kinetic

energy of a liquid coming out of an impeller is harnessed by creating a resistance to the

flow. The first resistance is created by the pump volute (casing) that catches the liquid

and slows it down. In the discharge nozzle, the liquid further decelerates and its velocity

is converted to pressure according to Bernoulli’s principle.

3. Pump Terminology

Impeller — the moving element in a pump that drives the liquid.

Volute — the spiral-shaped casing surrounding a pump impeller that collects the liquid

discharged by the impeller.

Head — A measure of the pressure or force exerted by water expressed in feet.

Centrifugal pump curves show pressure as head, which is the equivalent height of water

with specific gravity = 1.

Static Head — the vertical height difference from the surface of a water source to the

centerline of the impeller. The vertical height difference from the centerline of the

impeller to the discharge point is called discharge static head, while the vertical height

difference from the surface of the water source to the discharge point is known as total

static head.

Total Head / Total Dynamic Head — the total height difference (total static head) plus

friction losses and demand pressure from nozzles etc. (total discharge head) = total

dynamic head.

Capacity/Flow — the rate of liquid flow that can be carried, typically measured in

gallons per minute (gpm).

Net Positive Suction Head — how much suction lift a pump can achieve by creating a

partial vacuum. Atmospheric pressure then pushes liquid into pump. A method of

calculating if the pump will work or not.

Cavitation — cavities or voids in liquid. Bubbles take up space leading to a drop in

pump capacity. Collapsing bubbles can damage the impeller and volute, making

cavitation a problem for both the pump and the mechanical seal.

Specific Gravity — the weight of liquid in comparison to water at approximately 20°C

(SG equal to 1).

Specific Speed — a measure of the function of pump flow, head, and efficiency.

Vapor Pressure—the force exerted by the gas released by a liquid in a closed space. If

the vapor pressure of a liquid is greater than the surrounding air pressure, the liquid

will boil.

Viscosity — a measure of a liquid’s resistance to flow (i.e., how thick it is). The viscosity

determines the type of pump used, how fast it can run, and with gear pumps, the

internal clearances required.

Friction Loss — the amount of pressure / head required to force liquid through pipes

and fittings.

Pump Efficiency — the ratio of energy delivered by the pump to the energy supplied to

the pump shaft. Some pump curves will show you the percent of efficiency at the best

efficiency point. The number varies with impeller design and numbers from 60 percent

to 80 percent are normal.

Best Efficiency Point — the point of highest efficiency of the pump.

4. Process Methodology

Specific Gravity

= Density of fluid at T °C / Density of Water at 4 °C

Pump Head (m)

= (((Discharge Pressure – Suction Pressure) * 10.2)/ (Specific Gravity)) + (Pump

Discharge Elevation – Pump Suction Elevation)

Hydraulic Power (kW)

= (Flow Rate (or capacity) in m3/hr * Pump Head * Specific Gravity)/367

Pump Efficiency

It is calculated from the Pump Curve as per the design data sheet.

Shaft Power (kW)

= Hydraulic power / Pump Efficiency

Electric Power (kW)

= Shaft Power / Motor Efficiency at ¾ FL

Current Output (Amp)

= (Electric Power * 1000) / (1.732 * Rated Voltage in V * Power Factor)

Actual Electrical Power (kW)

= Rated Current * 1.732 * Power Factor * Rated Voltage in kV

5. Data Sampling

Given Data (28 July, 2014)

Suction Pressure kg/cm2g 3.255

Discharge Pressure kg/cm2g 117.8

Temperature(T) ˚C 153

K 426.15

Flow Rate(Q) m3/hr 550

Pump Suction Elevation(hs) m 0

Pump Discharge Elevation(hd) m 0

Density of Fluid at T ˚C kg/m3 858

Water Density at 4˚C kg/m3 999.972

6. Observations and Findings

Specific Gravity 0.858024025

Pump Head

H 1361.685648 m

Hydraulic Power

hp 1750.94673 kW

At Capacity Q

Pump Efficiency Ƞp 0.76 (from Graph)

Shaft Power

Shaft Power 2303.877277 kW

Electrical Power

For Motor

Pump motor capacity 3000 KW

Rated Voltage 11000 V

Rated Current 134 amp

Rated Power 2702 kW

Max Power @ rated impeller 2942 KW

Power Factor(3/4FL) 0.91

Efficiency (3/4FL) 0.967

Electric Power 2382.499769 kW

Current O/P 137.4203031 Amp

Actual Electrical Power 2323.20088 kW

7. Conclusions and Recommendations

The process engineer is normally responsible for specifying the process requirements of

the pump, including the conditions and physical properties of the liquid, and, most

importantly, the flow rate, pressure, density and viscosity. The flow rate determines the

capacity of the pump, and the head depends on the density and viscosity of the liquid. In

general, the required flow rate is determined by the material and energy balances.

Design margins, typically between 0–25 percent, are added to the material-balance flow

rate to account for unexpected variations in properties or conditions, or to ensure that

the overall plant meets its performance criteria. Also, minimum flow protection is often

added as continuous circulation. Occasionally, the required flow rate (including design

margins) may fall in the low range of that for centrifugal pumps. In such cases, a

minimum-size pump rated for continuous service is specified, and the extra pump

capacity is typically consumed by circulation from the discharge to the source.

Pump suppliers set the NPSH required (NPSHR) for a given pump. The NPSHR takes into

account any potential head losses that might occur between the pump’s suction nozzle

and impeller, thus ensuring that the fluid does not drop below its vapor pressure.

NPSHA must exceed the NPSHR set by the supplier. There are a few options available to

increase NPSHA, should it be at or below the NPSHR. Increasing the source pressure or

reducing the fluid vapor pressure (by cooling) is rarely feasible.

Therefore, there are two process variables remaining that can be adjusted — the static

head and friction losses.

Static head can be raised by three methods:

Raise the elevation of the source point. This may prove impossible in some cases

(e.g., a tank that is set at grade).

Lower the elevation of the pump inlet. This is a less appealing option because

pumps are typically located just above ground level, and lowering the inlet may

require the suction nozzle to be below grade. This usually results in a much more

expensive pump.

Raise the level of fluid in the suction vessel. The acceptability of this approach

varies from company to company and should not be used without first consulting

company procedures.

Friction losses can be reduced either by increasing the diameter of the pump suction

piping and/or reducing the equivalent length of the suction line. In a grassroots plant,

friction losses should already be minimal, so raising static head is more viable. Reducing

friction loss is usually more appealing for suction lines in existing plants where

throughput has been increased above the original nameplate capacity.

There are also a few options to reduce the NPSHR of the pump, which include using a

larger, slower-speed pump, a double-suction impeller, a larger impeller inlet (eye) area,

an oversized pump and an inducer, which is a secondary impeller placed ahead of the

primary impeller.

Low-suction-pressure switches interlocked into the plant control system sometimes

trip the pump or prevent its startup when the suction pressure is below a set value.

High-pressure switches can be installed on the pump discharge so as not to exceed the

maximum allowable output pressure (dead-heading the pump). The motor is usually

tripped or is not allowed to start under these conditions. Similarly, low-flow switches on

the discharge are used to alarm and trip the motor when a low-flow condition has

occurred. This interlock is often bypassed (manually or with a timer) during pump

startup to allow the flow to reach its normal operating point, at which time the bypass is

removed. Currently, industry is changing from switches to transmitters for increased

accuracy and easier failure diagnosis.

A minimum throughput needs to be maintained for optimized production. Hence, a

given power consumption is mandatory for pumping of feed through the Charge pump

upstream of the Charge Heater and the Reactor. Reducing Cavitation and Maintaining

the NPSH up to a certain designated value reduces the constraints that increase the

power consumption unnecessarily.

Energy conservation in pumping systems can be achieved to a certain extent if we pay

heed to the following guidelines.

When actual operating conditions are widely different (head or flow variation by

more than 25 to 30%) than design conditions, replacements by appropriately sized

pumps must be considered.

Operating multiple pumps in either series or parallel as per requirement.

Reduction in number of pumps (when System Pressure requirement, Head and Flow

requirement is less).

By improving the piping design to reduce Frictional Head Loss.

• By reducing number of bends and valves in the piping system.

• By avoiding throttling process to reduce the flow requirement.

• By Trimming or replacing the Impellers when capacity requirement is low.

• By using Variable Speed Drives.

Pump over-sizing causes the pump to operate to the far left of its best efficiency point

(BEP) on the pump head -capacity curve. Variable speed drives, assuming a low static

head system, allow the pump to operate near its best efficiency point (BEP) at any head

or flow. In addition, the drive can be programmed to protect the pump from mechanical

damage when away from BEP -- thereby enhancing mechanical reliability. Furthermore,

excessive valve throttling is expensive and not only contributes to higher energy and

maintenance cost, but can also significantly impair control loop performance.

Employing a throttled control valve, less than 50% open, on the pump discharge may

accelerate component wear, thereby slowing valve response.

6. SAFETY IN ESSAR REFINERY

6.1 Life Saving Rules in Essar Refinery

Work with a valid work permit when required.

Conduct a Gas test when required.

Obtain authorization before entering in a confined space.

Verify isolation before work begins and use the specified life protecting equipment.

Obtain authorization before overriding or disabling safety critical equipment.

Protect yourself against a fall when working at a height.

While Driving: Do not use mobile phones, Do not exceed Speed Limits, Must wear

Seat Belt.

Do not Smoke.

No drugs or Alcohol allowed on site.

Do not walk under a Suspended load.

6.2 Safety against Hydrogen Sulfide

TBRA (Task Based Risk Assessment) shall be carried out by the shift in-charge along

with other responsible members for the specific activities, such as draining of sour

water or where H2S presence is suspected.

It is advisable to work under supervision of Field Officer or other responsible

persons.

The Receiver and Contractor Supervisor must educate (Tool Box Talk) and make

aware all the crew members about barrication of suspected H2S exposure/marked

area.

Field Officer has to ensure about barricade of suspected H2S exposure area to avoid

unauthorized entry.

Authorized person or group working in the suspected H2S area must carry H2S

personal detector duly calibrated.

Apart from all the mandatory PPEs, SCBA (Self Contained Breathing Apparatus) shall

be used. Escape Masks shall be used for escape purpose only. Trolley mounted

Airline Masks should be used for maintenance or process related work.

Immediately remove the victim from the affected area to a well-ventilated place and

loosen victim’s clothes. If a body part comes in contact with H2S, wash the affected

part under safety shower for at least 15 minutes. If required, trained personnel may

administer oxygen and/or provide Cardio-Pulmonary Resuscitation (CPR).

Immediately tae the victim to nearest medical centre.

6.3 Personal Protective Equipments (PPEs)

PPE is equipment that will protect the Refiner against health or safety risks at work.

PPEs are compulsory to be used while working in the field/operational area of the

Refinery.

PPEs include Safety Helmet, Safety Goggles, Safety Shoes, Safety Gloves and Ear

Plugs.

Ensure the PPEs used have CE marking on them in compliance with the Personal

Protective Equipment Regulations, 2002. CE marking signifies that the PPE satisfies

certain basic requirements for safety and has been tested and certified by an

independent authorizing body.

6.4 Intrically Safety Procedures

Unit Design

Selection of MOC (Materials of Construction)

Interlocks and ESD (Emergency Shutdown Systems)

Alarm Systems

DCS Installation.

Online Analyzers.

Standby Arrangements and equipment.

Corrosion Allowances.

PSVs (Pressure Safety Valves), PRVs (Pressure Relief Valves), NRVs (Non-Return

Valves)

Nitrogen Blanketing.

Purge Systems.

Hydro-testing of equipments before installation.

Stress Analysis.

6.5 Fire Safety Practices at Essar Refinery

Fire is a chemical reaction, in which the substance (fuel) combines with oxygen. The

reaction is exothermic and usually associated with the emission of light and smoke.

Oxygen + Heat + Fuel = Fire

Remove Anyone = No Fire

Fire Extinguishing Media at Essar Refinery

Water

It absorbs the heat from fire and provides cooling effect. Water extinguishes the fire

by cooling as well as smothering sometime due to generation of large amount of

steam.

Foam

It extinguishes fire in three ways.

Separating: Creates a barrier between the fuel and the fire.

Cooling: Lowers the temperature of the fuel and adjacent surfaces.

Smothering: Prevents the release of flammable vapors, thereby reducing the

possibility of re-ignition.

DCP

DCP extinguishes the fires by developing a thin layer over the burning surface and

inhibition of chain reaction in flaming zone.

CO2

CO2 extinguishes fire by reduction of oxygen concentration.

Fire Protection Systems at Essar Refinery

Passive Fire Protection Systems

Compartmentalization of the overall building through the use of fire-resistance rated

walls, floors, ceilings, etc.

Eg. Fire Proofing/Fire Doors/Fire Walls/Dyke Walls/Drainage/Fire Resistance

Paints and Packing, etc.

These components are not actively participating in actual fire fighting operations.

They are basically employed for limiting building damage and providing more time

to the building occupants for emergency evacuation.

Active Fire Protection Systems

Fixed Fire Protection Systems

A system which has its own Fire fighting media or have continuous media

availability.

Eg. Deluge Systems, Inergen Systems, Rim Seal Package Systems, etc.

Semi-Fixed Fire Protection Systems

A system which requires external source to feed the fire-fighting media.

Eg. Foam System

Mobile Fire Protection Systems

All Foam Tenders, Water/Foam LRM, Foam Trolleys come under this category.

Portable Fire Protection Systems

All types of Fire Extinguishers, Fire Buckets, Portable Monitors, etc. fall under this

category.

Fire and Gas Detection Systems at Essar Refinery

Smoke Detectors

Flammable Gas Detectors

Flame Detector

Toxic Gas Detector

Heat Detectors

MCP

6.6 Miscellaneous Safety Practices at Essar Refinery

Beacons

Red Light: Fire

Yellow Light: Flammable Gas

Blue Light: Toxic Gas

Emergency Siren and Hot Lines

Assembly Points and Escape Routes

Wind Socks

Always assemble perpendicular to the wind direction.

REFERENCES

DHDT Operating Manual, Essar Oil Ltd. Vadinar.

Chemical Engineering Design, Volume 6, R.K. Sinnott, Elseiver Publication.

Perry’s Chemical Engineering Handbook, 7th Edition, Robert H. Perry and Don W.

Green.

Grundfos Centrifugal Pump Manual.

Datasheet of the instruments, Essar Oil Ltd. Vadinar

Increasing Fired Heater Thermal Efficiency, Lester W. Davis, Carmagen

Engineering Inc. E-news Report, Dated March, 2011.

Clean Diesel Hydrotreating, Ed Palmer, Stan Polcar and Anne Wong, Mustang

Engineering.

Understanding the basics of Centrifugal Pump, Kimberly Fernandez.