INTERNSHIP REPORT

Pakistan Pertroleum Limited

Prepared by:

Sadia Urooj

Submitted to:

Dr. Shujjat Ahmed,

Manager Process Engineering (MPrE).

University of Karachi

Pakistan Petroleum Limited

ACKNOWLEDGEMENT

All praise unto Almighty Allah, the Lord of all worlds, who endowed me with the ability to

complete successfully this period as internship.

“My Lord, I have never been unblessed in my prayer to you.”

I am extremely thankful for the co-operation and help provided byDr. Shujjat Ahmed

(MPrE), Mr. Farooq Azam Shah (DCE Pr), Mr. Imran Bukhari (EPr), Mr. Athar (TrE

Chem) for spending their valuable time and responding to my queries and giving me an

insight how an organization is run, what are the important principles of a working

environment, how projects are designed, their implementation and what are the softwares

used in executing these tasks. I feel myself an opportunist after served the high tech

environment in PPL which shall be a guideline in my future career.

Last but not the least, I am thankful to all those who always have guided me at their best.

Sadia Urooj

Student, Chemical Engineering (Batch 2009)

University of Karachi

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TABLE OF CONTENTS

S.No

DESCRIPTION Page#

1. Introduction

1.1.General (Oil & Gas Industry Work Flow)1.2.Plant Operations1.3. PPL Process Engineering Department major scope:

- Technical Services- Process Design

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2. Introduction With Process Engineering

2.1. Fundamentals of Process Design 2.2. Standards and Codes Frequently used in Process Design &

Their Application 2.3. Introduction with Unit Operation & Unit Processes in PPL Plants

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3. Preparation Of Process Design Documents & Their Standard Requirements

3.1. Schematic 3.2. PFDs 3.3. H&MB 3.4. P & IDs 3.5. Plot Plan 3.6. Process Simulation (HYSYS)

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4. Process Design Calculation Of Pipelines System & Major Process Units

4.1. Introduction with Transient Flow Regimes 4.2. Hydraulic Calculation of Process Piping 4.3. Separators (2-Phase, 3-Phase, Knock Out, Scrubbers etc.) 4.4. Heat Exchangers (S&T, Air Coolers etc.) 4.5. Towers (De-Ethanizer, De-Butanizer, Stripper) 4.6. Pumps (Centrifugal, Reciprocating etc.) 4.7. Compressors (Centrifugal, Reciprocating etc.) 4.8. Storage (LPG, NGL, Diesel, Water etc.)

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ConclusionReferencesAnnexures

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ANNEXURES

Annexure A: Electrical standards and approved codes of practice

Annexure B: Block Flow Process Diagram

Annexure C: Block Flow Plant Diagram

Annexure D: Process Flow Diagrams (PFDs)

Annexure E: Piping and Instrumentation Diagram (P&IDs)

Annexure F: Plot Plan

Annexure G: Separator Sizing

Annexure H: Compressor Design

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INTRODUCTION

Pakistan Petroleum Limited

Pakistan Petroleum Limited invariably known as PPL is the pioneer in the gas production of

the country, contributing about one fourth of total gas supplies, besides producing crude oil,

condensate and LPG. Pakistan Petroleum Limited has been in the business of exploration

and production since 1950 with the establishment of a public limited company through

major shareholding of a Britain based company (Burmah Oil Company). 

Presently PPL's share in the country's total natural gas production stands at around 24

percent. The company operates the largest gas field at Sui and five others at Kandhkot,

Hala, Chachar, Adhi, and Mazarani. It holds working interest in 12 partner operated fields

including Qadirpur, Sawan, Nashpa, Latif etc. PPL-operated fields produce an average of

one bcfd which is sold to the company's main clients: Wapda, SSGC and SNGPL. 

The exploration portfolio of the company consists of 35 exploration blocks including

offshore block Indus-G. Pakistan Petroleum Limited is the operator in 19 of them, while it

has working interest in 15 of them as well. These numbers also include the exploration

license in Yemen, which is a joint venture between PPL, OMV and Yemen General

Corporation for Oil and Gas. However, due to security issues, progress in this regard has

been halted completely in recent times. 

1.1. General (Gas Industry Work Flow)

Oil and gas field production and processing operations are primarily defined by the

following activities:

Exploration and production (E&P) ;

Processing;

Storage and transport; and

Wastewater.

1.1.1. EXPLORATION AND PRODUCTION

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The oil and gas field production and processing operations begin with exploration to locate

new sources of crude oil and natural gas. Seismic and other geophysical methods are used

to locate subterranean formations that signal the potential presence of oil and gas

reservoirs. When potential sources are located, wells are drilled to confirm the presence of

oil or gas and to determine whether the reserves are economically sufficient to support

production.

Once a well has been completed and is producing crude oil or natural gas, an arrangement

of high-pressure valves termed a "Christmas tree" is installed to control production. As the

well ages, an artificial lift device may be needed to help bring product to the well surface.

1.1.2. PROCESSING

1.1.2.1. CHEMICAL INJECTION SKIDS

Chemical agents employed in field processing include drilling fluid additives, methanol

injection for reservoir stimulation, glycol injection for hydrate inhibition, produced water

treatment chemicals, foam and corrosion inhibitors, de-emulsifiers, desalting chemicals and

drag reduction agents (DRAs). Chemicals are frequently administered by way of chemical

injection skids.

1.1.2.2. WELL STREAM SEPARATION

The first step in processing the well stream is to separate the crude oil, natural gas and

water phases into separate streams.

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1.1.2.3. FIELD STORAGE TANKS

Crude oil, natural gas liquids (NGLs) and water are stored in oil and gas fields. Field

storage consists of smaller vessels associated with oil, gas and water processing.

1.1.2.4. WATER PROCESSING

Water collected from process operations contains hydrocarbon concentrations too high for

safe discharge thus it requires treatment. Suspended hydrocarbon droplets in water also

hinder well-injection.

1.1.2.5. CRUDE DEHYDRATION, DESALTING & STABILIZATION

Separated crude may contain up to 15% water which exists in an emulsified form. De-

emulsification processes are accomplished using chemical agents and heat. Crude

desalting removes both salt and the residual free water.

By removing dissolved gases and hydrogen sulfide, crude stabilization and sweetening

processes diminish safety and corrosion problems.

1.1.2.6. VAPOR RECOVERY UNIT

If allowed to escape into the atmosphere, hydrocarbon vapors diminish income through loss

of hydrocarbon volume and create fire hazards and pollution problems. A Vapor Recovery

Unit (VRU) collects vapors from storage and loading facilities, reliquefies the vapors and

returns the liquid hydrocarbons back to storage. Methods to recover vapors include

absorption, condensation, adsorption and simple cooling.

1.1.2.7. GAS DEHYDRATION

Natural gas dehydration removes hydrates which can grow as crystals and plug lines and

retard the flow of gaseous hydrocarbon streams. Dehydration also reduces corrosion,

eliminates foaming, and prevents problems with catalysts downstream. Natural gas is

dehydrated according to the customer’s specifications for maximum water content.

1.1.2.8. SOUR GAS TREATMENT

Pipeline specifications require removal of the harmful acid gases carbon dioxide (CO2) and

hydrogen sulfide (H2S). H2S is highly toxic and corrosive to carbon steels. CO2 is also

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corrosive and reduces a gas’s BTU value. Gas sweetening processes remove these acid

gases and make natural gas marketable and suitable for transportation.

1.1.2.9. NGL RECOVERY

Separating the hydrocarbons and fluids from pure natural gas produces pipeline quality dry

natural gas. The two principle techniques for removing Natural Gas Liquids (NGLs) are the

absorption and the cryogenic expander method.

1.1.2.10. PUMPS & COMPRESSORS

Pumps are used throughout field operations for moving drilling fluids, crude oil and

produced water. Compressors increase the pressure of natural gas to facilitate pipeline

transport.

1.1.2.11. LIQUID AND GAS FLOW

The flow of process liquids and natural gas in field operations must be monitored for safety

and efficiency.

1.1.2.12. TANK BLANKETING

Nitrogen is commonly used as a tank blanketing gas in order to prevent ignition of

flammable liquids, provide an oxygen and moisture barrier, inhibit vapor loss and maintain a

tank’s pressure balance.

1.1.2.13. FLARE STACKS & HEADERS

Hydrocarbon gases are often flared in a high-temperature oxidation process which burns

combustible components of waste.

1.1.3. STORAGE AND TRANSPORT

Storage tanks are used to store crude oil, liquefied natural gas (LNG), water or brine,

process condensate, as well as other materials used or generated during the production of

oil and natural gas. Crude oil is transported from production operations to refineries by tank

trucks, rail cars, tankers, barges, and pipelines. Loading methods include splash loading,

submerged pipe fill, and bottom loading. Natural gas is transported by pipeline.

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Pipeline pigging operations are conducted to assist in product transfer and product

separation, as well as for maintenance activities. A pig is a physical device which varies in

size and shape and can be made of a variety of materials such as plastic, urethane foams,

and rubber. Pigs can be solid, inflatable, foam, or made of a viscous gel. The specific

design of a particular pig depends upon the pipeline as well as the purpose of the pigging

operation.

Three types of pigging operations occur in pipelines at oil and gas field production and

processing facilities: product transfer, product separation, and maintenance. Pigging

following product transfer is used to remove residual product from the pipeline after loading

occurs. Pigs can also be used for product separation to transport more than one product,

such as oil, gas, or condensate as well as for maintenance activities such as pipeline

cleaning, gauging, or dewatering. During pigging operations, a pig is inserted into the

pipeline and is forced through the pipeline by a compressed gas, such as nitrogen. When

the pig gets to the end of the line, it is trapped in a receiver. The gas is then bled off from

behind the pig. Depending on the specific pigging operation, waste removed from the

pipeline may also be an issue.

1.1.4. WASTEWATER

During oil and gas field production and processing operations, wastewater is generated

from processes such as product separation and glycol dehydration. The wastewater may be

treated on-site or it may be forwarded to an approved wastewater treatment facility.

Many types of units are used to treat, store, and transfer wastewater on-site. Some of these

units include sumps, pits, storage tanks, brine tanks, and oil/water separators which may be

in primary, secondary or tertiary treatment service.

1.2. Plant Operations

Operation is a complex of activities performed by the operating staff to ensure safe and

reliable operation of the plant equipment.

Plant operation has certain objectives.

Specifications: To meet the sales specifications.

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Capacity: Run at the designed flow rates.

Flexibility: If operating ranges change, it can operate yet.

Regulations: By-products specifications should be met. All effluents must meet the

environmental conditions based upon NEQS.

Safety system: Overall Occupational Health and Safety (OHSAS).

There are three types of plant operations, normal operations, shutdown and start up, and

trouble-shooting.

NORMAL OPERATION

It’s based on SOPs. Standard operating procedures should cover three main areas of

operation.  First is the safety considerations associated with the process. The operator

must understand the process flow sheet and have a mental picture of how the plant is

structured and how it operates.  He must know where the pressure relief valves and

rupture disks are located and where the releases will go in the event their operation is

triggered by an upset in the process. The second element that needs to be covered in

written standard operating procedures is a description of the control system. The third

element in standard operating procedures involves specifying the standard operating

conditions.

SHUTDOWN AND START UP

As takeoff and landing are most hazardous operations for an aircraft so in a process plant

the hazard is greater during start-up and shut-down.

Column Startup and Shutdown

A column startup usually consists of the following steps:

1. Commissioning

2.Pressure-up

3.Column Heating (and/or cooling)

4.Introduction of feed

5. Introducing heating and cooling sources

6. Bringing column to desired operating conditions

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Similarly, column shutdown usually consists of the following steps:

1. Reducing column rates

2. Shutting down heating and cooling sources

3. Stopping feed

4. Draining liquids

5. Cooling (or heating) the column

6. Bringing the column to atmospheric pressure

7. Eliminating undesirable materials

8. Preparing for opening to atmosphere

Other activities required for carrying out a proper startup or shutdowns include:

Preparation of operating, startup, shutdown (normal and emergency) and maintenance

procedures and checklists for each phase

Selection and training of startup/shutdown team

Planning and coordinating all activities, developing individual tasks and objectives, etc

Securing any raw materials, catalysts, equipment, and spare parts required.

TROUBLE-SHOOTING

Trouble-shooting is equipment based. Trouble-shooting is more in rotary equipments than

stationary equipments. In trouble-shooting, we do root cause analysis.

Trouble-Shooting Checklist for Amine Systems

Dirty Amine

Cyanides

Amine color and solids concentration

Inadequate filtering

Corrosive amines

Regenerator feed temperature too high

High velocities

Stress cracking

Reboiler corrosion

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Corrosion inhibitor

Condensate backup in channel head

Regenerator reflux rate too low

Superheated reboiler steam

Reclaimer operation

High S2O3 levels

Soda ash addition rate

Diluent water rate

Tubes not submerged in liquid

Energy reduction

Minimize CO2 recovery

Cut amine circulation

Reduce reboiler steam

Foaming in scrubbers

High N2 in refinery effluent

Scrubber pressure drop

Dirty amine

Excessive concentrations of silicone or inhibitor

Charcoal filter

Condensing hydrocarbons

Extraneous surfactants

Plugged level control traps

Liquid-liquid scrubbers

Loss in amine strength

Amine cooler leaking

Reboiler or reclaimer leaking

Condensate make-up or valve open

Test with tracer chemical

Poor sweetening

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Leaking cross exchanger

Regenerator reflux rate too low

Amine degraded

COS in treated propylene

1.3. PPL Process Engineering Department Major Scope

1.3.1. TECHNICAL SERVICES

As a process engineer the overall objective is to ensure optimum running of theprocessing

units in terms of capacity utilization, energy efficiency, equipment life, to provide timely

assistance to operational problems, production planning, economic operating modes and

quality control.

Process simulation techniques are used for optimizing and troubleshooting the process of

the plant through one of the major simulation tool HYSYS.

Designing, evaluation and modifications for the plants to ease the operation and optimize

the performance requiring good knowledge of hydraulic calculations. Updating daily plant

monitoring sheet and wellness report of the department.

1.3.2. PROCESS DESIGN

As a process engineer , the design of any process contribute a great deal in the

development of industrial output and satisfactory as well as safe operation of the  plant. The

process engineering department of PPL contribute a lot in designing , increasing

production, assisting new projects , meeting the standards , gathering data from standard

procedure and coming up with adequate and economical plant design.

INTRODUCTION WITH PROCESS ENGINEERING

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2.1. Fundamentals of Process Design

In business a process is any sequence of events or actions that transforms inputs into

outputs. For example, a car business takes in metal and labor and transforms it into cars

through a process of car manufacture. Processes are designed so as to make most efficient

use of resources, including time, labor and capital.

2.2.1. DESIGN BRIEF

The first stage in process design is the design brief. The design brief is usually achieved

through extensive consultation among the clients who will be using the process, and

whoever will be implementing the process. The design brief includes information about the

requirements, specifications, costs, schedule and objectives of the process.

2.2.2. SPECIFICATION

Included within the design brief is the specification. The specification is a detailed

description of the properties that the process needs to possess. The specification will

establish in detail the criteria by which the success or failure of the design of the process

will be judged.

2.2.3. CONCEPT

The concept is a high-level description of how the process will function. The concept stage

of process design involves a great deal of abstraction. Complex subsystems of the process

are presented as "black boxes" with certain inputs and certain outputs. The goal of the

concept stage of process design is simply to ensure that the design as specified is feasible,

and to identify any major problems with implementing the specified process design.

2.2.4. DETAILS

After the concept has been established, the subsystems can be removed from their black

boxes and the work of designing the process at a detailed level can begin. This part of

designing processes generally takes the longest, as consideration has to be made of all the

detailed elements of the process subsystems.

2.2.5. TESTING

As the process is implemented, each subsystem has to be tested to ensure it works

properly. Once all the subsystems of the process have been implemented, testing has to

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happen to ensure that everything works as required by the specification. If things do not

work as required by the specification, then they have to be altered so they do.

2.2.6. ONGOING MONITORING

Even once the process is set up and operational, there is still scope for ongoing monitoring

and improvement of the system. Systems like Kaizen offer a means to extend the process

design process over the entire lifetime of the system, ensuring that the process is

constantly being developed and inefficiencies are removed.

2.2.STANDARDS AND CODES

STANDARDS

A technical standard is an established norm or requirement. It is usually a formal document

that establishes uniform engineering or technical criteria, methods, processes and

practices.

CODES

A code is a set of rules and specifications for the correct methods and materials used in a

certain product, building or process. Codes can be approved by local, state or federal

governments and can carry the force of law.  The main purpose of codes is to protect the

public by setting up the minimum acceptable level of safety for buildings, products and

processes.

2.2.1. AMERICAN PETROLEUM INSTITUTE (API)

The American Petroleum Institute (API) maintains more than 500 documents that apply to

many segments of the oil and gas industry - from drill bits to environmental protection. API

standards advocate proven, sound engineering and operating practices and safe,

interchangeable equipment and materials.

API standards include manuals, standards, specifications, recommended practices,

bulletins, guidelines and technical reports.

2.2.2. ASTM INTERNATIONAL

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ASTM International is comprised of more than 132 technical standards writing committees

and publishes over 9,100 standard specifications, tests, practices, guides, and definitions

relating to materials, products, systems, and services. Topics range from chemical products

and fossil fuels to forensic sciences and medical devices.

2.2.3. INTERNATIONAL ORGANIZATION FOR STANDARDIZATION (ISO)

ISO, the International Organization for Standardization, is a nonprofit organization that

develops and publishes standards of virtually every possible sort, ranging from standards

for information technology to fluid dynamics and nuclear energy. Headquartered in Geneva,

Switzerland, ISO is composed of 162 members, each one the sole representative for their

home country

2.2.4. NFPA STANDARDS AND CODES

NFPA develops, publishes, and disseminates more than 300 consensus codes and

standards intended to minimize the possibility and effects of fire and other risks. Virtually

every building, process, service, design, and installation in society today is affected by

NFPA documents.

2.2.5. OSHA STANDARDS

The Occupational Safety and Health Administration (OSHA) regulates worker safety in the

United States and its territories. Health and safety standards are contained in Title 29 of the

Code of Federal Regulations (29 CFR), and are available online. In the OSHA CFR, there

are several different sections (also called parts) of safety and health standards (also called

regulations) applicable to the various types of workplaces regulated by this agency. There

are OSHA standards (Part 1903) regulating OSHA inspections, citations, and penalties for

all affected workplaces, as well as specific standards for reporting and recording OSHA-

recordable injuries and illnesses(Part 1904) that apply to all affected employers who do not

fall into the exemptions for size or low-risk industries (although they must still comply with

all other applicable OSHA regulations).

2.2.6. ELECTRICAL STANDARDS AND APPROVED CODES OF PRACTICE

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There are some commonly used electrical standards and approved codes of practice

shown in annexure. Additional standards and codes of practice would generally be needed

to satisfy a specific application - it is the responsibility of the specified to select and apply

these. You should ensure that the standard you use is the current one.

The standards are organized into a number of topic areas and are ordered with the lowest

number at the top of each table:

Electrical and Power

Electrical Appliances

Electromagnetic Compatibility

Flammable Atmospheres

Machinery

2.3.Introduction with Unit Operation & Unit Operation in PPL Plants

The company operates the largest gas field at Sui and five others at Kandhkot, Hala,

Chachar, Adhi, and Mazarani. It holds working interest in 12 partner operated fields

including Qadirpur, Sawan, Nashpa, Latif etc. PPL-operated fields produce an average of

one bcfd which is sold to the company's main clients: Wapda, SSGC and SNGPL. 

2.3.1. SUI GAS FIELD (PPL SHARE 100%)

Since its discovery in 1952, the Sui Gas Field remains an important source of gas

supply,meeting substantial part of gas demand of the country. Reservoirs in SUI are SUL,

SML, HRL, Pab formation. SUL has no H2S, less CO2 so it undergoes dehydration only.

Pab has a lot of H2S and CO2. H2S is upto 1000-1500 ppm. CO2 is maximum 7 mole%. As

per sales gas requirement, H2S should be till 4 ppm and CO2 should be 3 mole% so it

undergoes gas sweetening as well.

SUI Plant is divided into three parts.

SUI Compression Station

HRL (small plant )

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Capacity: 30 MMscfd

SCFGCS (large plant )

Capacity: 900-950 MMscfd

SUI Purification Plant

Capacity: 900-950 MMscfd

SUI Dehydration Plant

Capacity: 200-300 MMscfd

2.3.2. KANDHKOT GAS FIELD (PPL SHARE 100%)

Gas from Kandhkot Field is mainly supplied to WAPDA and SNGPL for use at Guddu

Thermal Power Station. A nominal quantity of gas is also supplied to SSGCL for Kandhkot

Town.

The unit operations at Kandhkot include compression and dehydration at Compression

Station and Dehydration Plant.

2.3.3. ADHI FIELD (PPL SHARE 39%)

PPL / OGDCL / POL JOINT VENTURE

Adhi has 3 plants. Plant 1 called LPG/NGL recovery plant was established in 1991. Plant 2

called EPL (Early Production Liquid) was established in 2006 and plant 3 will be established

in 2014. Plant 1 and 2 requires no sweetening. Thus, plant 1 which is the main plant

undergoes gas dehydration only and recovers LPG/NGL and plant 2 has a capacity of 5000

MMscfd.

A total of eleven wells are in production at Adhi. Two wells are producing crude oil from

Sakesar formation and the remaining are Tobra / Khewra wells producing oil, NGL and gas.

LPG is also extracted from the Plant feed and sold to customers.

2.3.4. MAZARANI GAS FIELD (PPL SHARE 87.5%)

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PPL / GHPL JOINT VENTURE

Mazarani gas field comprises of Gas Processing Plant and an 8” dia. 75 Km long gas

transmission pipeline for injection of Mazarani gas into SSGCL's Indus Right bank

transmission system.

A total of four wells have been drilled to-date in Mazarani Field. Out of these four wells,

Well Maz-1 was plugged and abandoned whileMaz-2(L), Maz-3(L) and Maz-4(L) have been

completed in Laki formation and are in production.

The unit operations and unit processes at Mazarani include

Gas compression

Amine unit

Dehydration

2.3.5. CHACHAR GAS FIELD (PPL SHARE 75%)

PPL / GHPL JOINT VENTURE

The field is in the East of Kandhkot Gas Field.A total of four wells have been drilled in

Chachar Field, of which Chachar 1 and 2 are in normal operation and Chachar-4 is

intermittently in operation due to water loading, while Chachar-3 is completely shut-in due

to high water production.Cathodic Protection System has been installed and commissioned

at Chachar-1, 2, 3 and 4 wells.

The unit operations and unit processes at Chachar include

Gas compression

Amine unit

Dehydration

2.3.6. HALA GAS FIELD (PPL SHARE 65%)

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MGCL / PPL JOINT VENTURE

PPL had drilled first exploratory well Adam X-1 in Hala Block during 2007 which resulted in

a gas / condensate discovery. Plant is operating at reduced rate due to change in reservoir

behavior; water and sand production started from Upper Basal formation. For optimizing the

production and to mitigate sand problem, a sand trap was installed in July 2011 and it has

been recently de-commissioned in view of well behavior. Hala is basically LPG recovery

field.

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PREPARATION OF PROCESS DESIGN DOCUMENTS

3.1. The Block Flow Diagrams (BFDs)

BFD shows overall processing picture of a chemical complex, flow of raw materials and

products may be included on a BFD.

BFD can either be

Block Flow Process Diagram

Block Flow Plant Diagram

BLOCK FLOW PROCESS DIAGRAM

Block Flow Process Diagram is similar to sketches in material and energy balances.

BLOCK FLOW PLANT DIAGRAM

Block Flow Plant Diagram gives a general view of a large complex plant.

3.2. The Process Flow Diagrams (PFDs)

PFD (or SFD- System Flow Diagram) shows relationship between major components in a

system. A PFD also tabulates process design values for the components in different

operating modes, typical minimum and maximum values. A PFD shouldn’t show minor

components, the piping systems, piping ratings and designations.

3.3. Heat and Material Balance (H&MB)

Heat and mass balance is a document produced by process design engineers while

designing a process plant. A heat and mass balance sheet represents every process

stream on the corresponding PFD in terms of the process conditions.

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3.4. The Piping and Instrumentation Diagrams (P&IDs)

P&ID displays ‘the interconnection of process equipment and the instrumentation used to

control the process’.

3.5. The Plot Plans

Plan or map drawn looking down on plant (drawn to scale with all major equipment

identified).

3.6. Process Simulation

Process simulation is a model-based representation of chemical, physical, biological, and

other technical processes and unit operations in software. The software has to solve

the mass and energy balance to find a stable operating point. The goal of a process

simulation is to find optimal conditions for an examined process. This is essentially

an optimization problem which has to be solved in an iterative process.

.They include CAMCAD, HYSYS, Aspen Plus ,Ascend , Hysim ,distil simu, MASSBAL etc.

I practiced HYSYS for the certain Oil and Gas processing unit and it helped me to get

familiar with simulation environment and its working tools.

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PROCESS DESIGN CALCULATION OF PIPELINES SYSTEM & MAJOR PROCESS UNITS

4.1. Introduction with Transient Flow Regimes

Slug flow can pose serious problems to the designer and operator of two-phase flow

systems. Prediction of slug characteristics is essential for the optimal, efficient and safe and

economical feasible design and operation of two-phase gas-liquid slug flow systems.

Some operations causing slugging include slugging caused by pigging, large pressure

impacts, pigging problems, fatigue, high frictional pressure loss, end of production when low

flow rates

SLUG PHENOMENA

When liquid and gas are flowing together in a pipeline, the liquid can form slugs that are

divided by gas pockets. The formation of liquid slugs can be caused by a variety of

mechanisms:

1. Hydrodynamic effects (surface waves)

2. Terrain effects (dip in pipe layout)

1. Hydrodynamic effects

Hydrodynamic or normal slug flow occurs at moderate gas and liquid flow rates, and hence

is commonly encountered in multiphase pipelines. Hydrodynamics slug-flow is

characterized by a series of Taylor bubbles (gas pockets) separated by liquid slugs. In

upward flow, the Taylor bubbles are symmetrical.

2. Terrain effects

Terrain-induced slugging and riser-induced slugging are both classified as severe slugging,

and characterized by liquid accumulation at low points. The gas upstream is compressed

until it overcomes the gravitational head of the liquid; thereby creating a long liquid slug that

is pushed in front of the expanding gas upstream.It is worth noticing that terrain slugging

occurs for relatively low liquid and gas flow rates.

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4.2. Hydraulic Calculations of Process Piping

4.2.1. HYDRAULIC DESIGN

1. Hydraulic balance

2. Pressure drop of piping

3. Pipe inside diameter

4. Pressure drop hand calculation by funning equation

5. Line sizing

6. Calculation of Le

7. Pressure drop of others

8. Pressure drop and flow control by control valve

9. Max suction pressure and max shut-off pressure

10.NPSH

11.HFD (hydraulic flow diagram)

12.Hydraulic hand calculation

4.3. Separators

Separators can be vertical, spherical, or horizontal, and typically employ a series of baffles

to separate the gas from the liquid hydrocarbons. A horizontal separator is used when the

gas-to-liquid hydrocarbons ratio is large; a vertical separator is used when the gas-to-liquid

hydrocarbon ratio is small; and a spherical separator is used when the gas-to-liquid

hydrocarbon ratio is in the intermediate range. When wellhead pressures are high, a series

of separators may be operated at sequentially reduced pressures. Three principles used to

achieve physical separation of gas and liquids or solids are momentum, gravity settling, and

coalescing. The purpose of separators is to split the flow into desirable fractions.

Gravity Separation

The followings are formulas for Stokes Law, Intermediate and Newton's

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4.3.1. SPECIFYING SEPARATORS

Separator designers need to know pressure, temperature, flow rates, and physical

properties of the streams as well as the degree of separation required. It is also prudent to

define if these conditions all occur at the same time or if there are only certain combinations

that can exist at any time. If known, the type and amount of liquid should also be given, and

whether it is mist, free liquid, or slugs.

4.3.2. DESIGN APPROACH

Calculate gas and liquid density. Calculate mass flow rate. Calculate particle diameter. Calculate drag coefficient (C’) (appendix A) Calculate Reynolds no. On the basis of Reynolds use Stokes’ law, Intermediate law, Newton’s law . Calculate terminal velocity and gas flow Assume diameter based, calculate length. Now based on L/D ratio check the feasibility of the separator. See Annexure G

2 5

4.4.Heat exchangers

A heat exchanger is a specialized device that assists in the transfer of heat from one fluid to

the other. In the most efficient heat exchangers, the surface area of the wall between the

fluids is maximized while simultaneously minimizing the fluid flow resistance.

There are two major different designs of heat exchangers: shell and tube, and plate heat

exchanger. The most typical type of heat exchanger is the shell and tube design while plate

heat exchanger is typically more efficient than the shell and tube design.

SHELL & TUBE EXCHANGER

A shell and tube heat exchanger is a class of heat exchanger designs. It is the most

common type of heat exchanger in oil refineries and other large chemical processes, and is

suited for higher-pressure applications. It consists of a tube bundle enclosed in a cylindrical

casing called a shell. One fluid runs through the tubes, and another fluid flows over the

tubes (through the shell) to transfer heat between the two fluids.

There are two basic types of shell-and-tube exchangers. The first is the fixed tube sheet

unit, in which both tube sheets are fastened to the shell and the tube bundle is not

removable. The second type of shell-and-tube unit has one restrained tube sheet, called the

stationary tube sheet, located at the channel end. Differential expansion problems are

avoided by use of a freely riding floating tube sheet at the other end or the use of U tubes.

Shell-and-tube exchangers are designed and fabricated according to the standards of the

Tubular Exchanger Manufacturers Association (TEMA).

4.4.2. DESIGN GUIDELINES

References: Hewitt et al “Process Heat Transfer” p267, Kern “Process Heat Transfer”

Chapter 7, p127 and Perry Section 11 p11-0 to p11-19

Definitions

Heat exchanger configurations are defined by the numbers and letters established by the

Tubular Exchanger Manufacturers Association (TEMA). Refer to Appendix V for full details.

For example: A heat exchanger with a single pass shell and multi-pass tube is defined as a

2 6

1-2 unit. For a fixed tube-sheet exchanger with removable channel and cover, bonnet type

rear head, one-pass shell 591mm (231/4in) inside diameter with 4.9m (16ft) tubes is defined

SIZE 23-192 TYPE AEL.

Tube Diameter

The most common sizes used are 3/4"od and 1"od

Use smallest diameter for greater heat transfer area with a normal minimum of 3/4"od tube

due to cleaning considerations and vibration.1/2"od tubes can be used on shorter tube

lengths say < 4ft.

The wall thickness is defined by the Birmingham wire gage (BWG) details are given in

Appendix XI (Kern Table 10)

Tube Number and Length

Select the number of tubes per tube side pass to give optimum velocity 3-5 ft/s (0.9-1.52

m/s) for liquids and reasonable gas velocities are 50-100 ft/s(15-30 m/s).

If the velocity cannot be achieved in a single pass consider increasing the number of

passes.

Tube length is determined by heat transfer required subject to plant layout and pressure

drop constraints. To meet the design pressure drop constraints may require an increase in

the number of tubes and/or a reduction in tube length.

Long tube lengths with few tubes may give rise to shell side distribution problems.

Tube Layout, Pitch and Clearance

Definitions and Nomenclature

B baffle spacing (pitch)

PT tube pitch

C clearance

do tube outside diameter

2 7

D shell inside diameter

Tube pitch is defined as

PT = do + C

Triangular pattern provides a more robust tube sheet construction.

Square pattern simplifies cleaning and has a lower shell side pressure drop.

Typical dimensional arrangements are shown below, all dimensions in inches.

Tube od (in) Square Pitch (in) Triangular Pitch (in)

5/8 7/8 Note 1 25/32 Note 1

3/4 1 Note 2 15/16 or 1 Note 12

1 11/4 11/4

11/4 19/16 19/16

11/2 17/8 17/8

Note 1 for shell ≤12” pitch (square) 13/16

Note 2 for shell ≤12” pitch (square) 15/16

Table above uses minimum pitch 1.25 times tube diameter i.e. clearance of 0.25 times tube

diameter.

Smallest pitch in triangular 30º layout for turbulent / laminar flow in clean service.

For 90º or 45º layout allow 6.4mm clearance for ¾ tubes for ease of cleaning.

Shell Diameter

The design process is to fit the number of tubes into a suitable shell to achieve the desired

shell side velocity 4ft/s(1.219m/s) subject to pressure drop constraints. Most efficient

conditions for heat transfer is to have the maximum number of tubes possible in the shell to

maximize turbulence.

Preferred tube length to shell diameter ratio is in the range 5 to 10.

Tube count data are given in Perry Table 11-3 where the following criteria have been used

2 8

1) Tubes have been eliminated to provide entrance area for a nozzle equal to 0.2 times

shell diameter

2) Tube layouts are symmetrical about both the horizontal and vertical axes

3) Distance from tube od to centerline of pass partition 7.9mm (5/16) for shell id <559mm

(22in) and 9.5mm (3/8) for larger shells.

Heat Transfer Area

Using the maximum number of tubes, subject to adequate provision for inlet nozzle, for a

given shell size will ensure optimum shell side heat transfer in minimizing tube bundle

bypassing.

The heat transfer area required design margin is then achieved by adjusting the tube length

subject to economic considerations. On low cost tube materials it may be more economical

to use standard lengths and accept the increased design margin.

It is a common practice to reduce the number of tubes to below the maximum allowed

particularly with expensive tube material. In these situations the mechanical design must

ensure suitable provision of rods, bar baffles, spacers, baffles to minimize bypassing and to

ensure mechanical strength.

Baffle Design – Definitions

Shellside cross flow area as is given by

Where

D shell i.d.

B baffle spacing

C clearance between tubes

PT tube pitch

Minimum spacing (pitch)

2 9

Segmental baffles normally should not be closerthan 1/5th of shell diameter(ID) or

50.8mm(2in) whichever is greater.

Maximum spacing (pitch)

Spacing does not normally exceed the shell diameter.

Tube support plate spacing determined by mechanicalconsiderations e.g. strength and

vibration.

Maximum spacing is given by

Most failures occur when unsupported tube length greater than 80% TEMA maximum due

to designer trying to limit shell

side pressure drop. Refer to attachments.

Baffle cut

Baffle cuts can vary between 15% and 45% and are expressed as ratio of segment opening

height to shell inside diameter. The upper limit ensures every pair of baffles will support

each tube.

Kern shell side pressure drop correlations are based on 25% cut which is standard for liquid

on shell side When steam or vapour is on the shell side 33% cut is used.

Baffle pitch and not the baffle cut determines the effective velocity of the shell side fluid and

hence has the greatest influence on shell side pressure drop.

Horizontal shell side condensation require segmental baffles with cut to create side to side

flow.

To achieve good vapour distribution the vapour velocity should be as high as possible

consistent with satisfying pressure drop constraints and to space the baffles accordingly.

Baffle clearances

3 0

The edge distance between the outer tube limit (OTL) and the baffle diameter has to be

sufficient to prevent tube

breakthrough due to vibration. For example fixed tube-sheet clearances are shown below.

Refer to Perry p11-11 for floating head clearances.

Shell inside diameter mm (in) Clearance shell id and OTL mm (in)

254(10) to 610(24) 11(17/16)

≥ 635(25) 13(1/2)

Tube-sheet Layout (Tube Count)(Ref 4, page 577)

Bundle diameterDb can be estimated using constants shown:

Where do tube o.d.

Nt number of tubes

Triangular Pitch pt= 1.25 do

Number

Passes

1 2 4 6 8

K1 0.319 0.249 0.175 0.0743 0.0365

n 2.142 2.207 2.285 2.499 2.675

Square Pitch pt= 1.25 do

Number

Passes

1 2 4 6 8

K1 0.215 0.156 0.158 0.0402 0.0331

n 2.207 2.291 2.263 2.617 2.643

Fouling Considerations

Typical fouling coefficients are shown inAppendix VII. It can be shown that the design

margin achieved by applying the combined fouling film coefficient is given by:

3 1

Where AC is the clean HTA , Af is the dirty or design HTA and UC is the clean OHTC.

Results for Typical Fouling Coefficients (British Units)

Fouling Resistances Fouling Coefficients Clean

OHTC

Design

MarginInside Outside Inside Outside Combined

0.002 0.001 500 1000 333 50 1.15

0.002 0.001 500 1000 333 100 1.3

0.002 0.002 500 500 250 50 1.2

0.001 0.001 1000 1000 500 50 1.1

Corrosion Fouling

Heavy corrosion can dramatically reduce the thermal performance of the heat exchanger.

Corrosion fouling is dependent on the material of construction selection and it should be

possible to eliminate altogether with the right choice. However if economics determine that

some corrosion is acceptable and no data is available from past experience an allowance of

1/16in (1.59 mm) is commonly applied.

Design Margin

The design margin to be applied to the design is based onthe confidence level the designer

has regarding the specific application and the future requirements for multipurpose

applications. Design of condensers for multipurpose use, where a wide possible variation in

flow conditions can exist, provides a particular problem in this regard.

It is standard practice to apply a design margin of 15% to the design (dirty) heat transfer

area with the result that this is applied to the design margin resulting fromthe application of

the fouling film coefficients discussed previously giving an added safety factor.

Pressure Drop

For process design using a simulation the following preliminary conservative estimates are

given for pressure drops due to friction. Note an additional pressure change occurs if the

exchanger is placed vertically.

3 2

Initial Process Design Pressure Drop Estimates

Process Description Pressure Drop (psi) Pressure (kPa)

Liquid streams with no

phase change

10 70

Vapor streams with no

phase change

2 14

Condensing streams 2 14

Boiling streams 1 7

AIR COOLED HEAT EXCHANGER

The Air-cooled heat exchanger is a device for rejecting heat from a fluid or gas directly to

ambient air. When cooling both fluids and gases, there are two sources readily available,

with a relatively low cost, to transfer heat to air and water.

4.4.3. DESIGN GUIDELINES

The basic heat transfer relationships that exist for shell and tube exchangers also apply to

the design of an air-cooled heat exchanger. However, there are more parameters to be

considered in the design of an air-cooled exchanger.

Since the air-cooled heat exchanger is exposed to changing climatic conditions, problems

of control of the air cooler become relevant. A decision must be made as to what the actual

ambient air temperature to be used for the design.

Some of the governing factors in the design of the air cooler are:

Tube diameter

Tube length

Fin height

Number of tube rows

Number of passes

Face area

Horse power availability

Plot area

3 3

Since there are many variables, normally there many solutions, however the designer

attempts to find the optimum economic design given these factors.

4.5.Towers

Towers are used for fractionation. Fractionation is a unit operation utilized to separate

mixtures into individual products. Fractionation involves separating components by relative

volatility (α). The difficulty of a separation is directly related to the relative volatility of the

components and the required purity of the product streams.

DE-ETHANIZER

De-ethanizer is the distillation column in a gas processing plant where ethane is separated

from a natural gas or natural gas liquids. It is separated from the natural gas liquids to

stabilize the liquid petroleum gas. The ethane is returned to the gas stream.

DE-BUTANIZER

A debutanizer is a type of fractional distillation column used to separate butane from natural

gas during the refining process. Fractional distillation, as occurs in a debutanizer, is the

separation of a fraction — a set of compounds that have a boiling point within a given range

— from the rest of the mixture.

STRIPPING TOWERS

VOCs, once in the ground, can be present for a very long time. Even when they reach an

aquifer, the speed of flow is often measured in just a few minutes per year.

Contamination may be found by chance in springs and wells or when dewatering

construction sites. Or it may be surveyed and quantified when pollution, recent or long past,

is known to have occurred. The necessity for remediation is most immediate where a spring

or well is needed for use, or where excavation water is too polluted to be disposed of

without treatment. Stripping by packed tower aeration offers an effective and economical

3 4

approach to many VOC contamination scenarios and Forbes has considerable experience

in the design and fabrication of stripping installations.

4.5.1. DESIGN

In order to determine the design parameters for a fractionation problem, the following

method is recommended:

1. Establish feed composition, flow rate, temperature, and pressure.

2. Make product splits for the column and establish condenser temperature and column

pressure. From column pressure, calculate the reboiler temperature.

3. Calculate minimum number of theoretical stages from the Fenske equation from Eq 19-3

illustrated in the GPSA manual

4. Calculate minimum reflux rate from the Underwood equations from Eq 19-7 and 19-8

illustrated in the GPSA manual.

5. Obtain theoretical stages/operating reflux relation from Fig. 19-7 illustrated in the GPSA

manual.

6. Adjust actual reflux for feed vaporization if necessary from Eq 19-9 and 19-10 illustrated

in the GPSA manual.

4.6.Pumps

The most common types of pumps used in gas processing plants are centrifugal and

positive displacement. Occasionally regenerative turbine pumps, axial-flow pumps, and

ejectors are used.

Modern practice is to use centrifugal rather than positive displacement pumps where

possible because they are usually less costly, require less maintenance, and less space.

POSITIVE DISPLACEMENT PUMPS

Positive displacement (PD) pumps work by allowing a fluid to flow into some enclosed

cavity from a low-pressure source, trapping the fluid, and then forcing it out into a high-

pressure receiver by decreasing the volume of the cavity. Some examples of PD pumps

3 5

are: fuel and oil pump in most automobiles, the pumps on most hydraulic systems, and the

heart of most animals.

Some general types of the positive displacement pump areas below:

a) Reciprocating Pump

Reciprocating pumps create and displace a volume of liquid, their “displacement volumes”,

by action of a reciprocating element. Liquid discharge pressure is limited only by strength of

structural parts. A pressure relief valve and a discharge check valve are normally required

for reciprocating pumps.

Reciprocating pumps can be further classified into three types of pump as below,

i) Piston Pumps

ii) Packed Plunger Pumps

iii) Diaphragm Pumps

b) Rotary Pump

Rotary pumps function with close clearances such that a fixed volume of liquid is displaced

with each revolution of the internal element. Rotary pumps include:

i) Gear Pump

ii) Lobe Pump

iii) Vane Pump

iv) Screw Pump

CENTRIFUGAL PUMPS

Centrifugal pumps are dynamic pumps. A centrifugal pump raises the pressure of the liquid

by giving it a high kinetic energy and then converts it into pressure energy before the fluid

exits the pump. It normally consists of an impeller (a wheel with blades), and some form of

housing with a central inlet and a peripheral outlet. The impeller is mounted on a rotating

shaft and enclosed in a stationary casing. Casings are generally of two types: volute and

circular. The impeller design and the shape of the casing determine how liquid is

accelerated though the pump.

Centrifugal pumps are used in more industrial applications than any other kind of pump.

This is primarily because these pumps offer low initial and upkeep costs. Traditionally these

pumps have been limited to low-pressure-head applications, but modern pump designs

3 6

have overcome this problem unless very high pressures are required. The single-stage,

horizontal, overhung, centrifugal pump is by far the most commonly type used in the

chemical process industry.

SELECTION OF PUMP

Basically, pump selection is made on the flow rate and head requirement and with other

process considerations, such as material of the construction pumps for the corrosive

chemical service or for the fluid with presence solids in the stream.

PERFORMANCE CURVE

Operating characteristics of centrifugal pumps are expressed in a pump curve. Depending

on impeller design, pump curves may be "drooping," "flat," or "steep." Pumps with drooping

curves tend to have the highest efficiency but may be undesirable because it is possible for

them to operate at either of two flow rates at the same head. The influence of impeller

design on pump curves is discussed in detail in Hydraulic Institute Standards.

4.6.1. DESIGN

Process Requirements Parameters

In designing the pump, the knowledge of the effect of parameters; such as pump capacity,

NPSH, pumping maximum temperature, specific gravity, fluid viscosity, fluid solid content,

and the other process requirements are very important. All of these parameters will affect

the selection and design of the pump which will affect the performance of the pump in the

process.

Flow Rate

Pump capacity is a parameter plays an important role when selecting the pump.

Capacity means the flow rate with which liquid is moved or pushed by the pump to the

desired point in the process. It is commonly measured in either gallon per minute (gal/min)

or cubic meters per hour (m3/hr). The capacity usually changes with the changes in

operation of the process. A minimum required flow rate need to be specified, this is

important to determining if a minimum flow bypass is required for the selected pump to

avoid pump overheating and mechanical damage.

3 7

NPSHNPSH as a measure to prevent liquid vaporization or called cavitation of pump. Net Positive

Suction Head (NPSH) is the total head at the suction flange of the pump less the vapor

pressure converted to fluid column height of the liquid. The design engineer should always

remember that pumps can pump only liquids, not vapors because when a liquid vaporizes

its volume increases greatly. For example: 1ft

3 of water it will vaporize to produce 1700ft3 of steam. This will cause the rise in

temperature and pressure drop in the fluid and pump will stop functioning because it has

not sufficient suction pressure present.

Design TemperaturePumping maximum temperatures is important in deciding pump construction style and

pump cooling and mechanical seal requirements. The minimum operating temperature is to

ensure that the material has adequate impact strength.

Specific GravitySpecific gravity is parameter determines the pump head required to produce a desired

pressure increase. For pumps with limited head capability such as centrifugal pumps, it

affects pressure rise capability. Pump power requirements are also affected by specific

gravity.

Viscosity

Viscosity is important in the selection of pump type and has a significant effect on

centrifugal pump performance. Minimum values of viscosity are important in determining

rotary pump (positive displacement pump) performance, while maximum viscosity is

important in determining debits to centrifugal pump performance.

AbrasivesFluid solid content will affect the pump design. It affected the aspects of the design for the

flow characteristic, consideration design of erosion resistance, flow passage size, impeller

style, peripheral speed, design features to disintegrate large particles, and shaft sealing

design. This parameter has to be added in the data sheet for design.

FlexibilityOther process requirement such as flexibility for expansion should be consider as well.

3 8

This is important for future capacity expansion; it helps to minimize the cost of expansion

because to replace the pump will be a large sum of money. Working capacity of pump

should always be design for more than 20% extra design capacity.

4.7.Compressors

RECIPROCATING COMPRESSORS

Reciprocating compressor ratings vary from fractional to more than 40,000 hp per unit.

Pressures range from low vacuum at suction to 30,000 psi and higher at discharge for

special process compressors.

Reciprocating compressors are furnished either single-stage or multi-stage. The number of

stages is determined by the overall compression ratio. The compression ratio per stage

(and valve life) is generally limited by the discharge temperature and usually does not

exceed 4, although small-sized units (intermittent duty) are furnished with a compression

ratio as high as 8.

CENTRIFUGAL COMPRESSORS

A multi-wheel (multi-stage) centrifugal compressor is normally considered for inlet volumes

between 500 and 200,000 inlet acfm. A single-wheel (single stage) compressor would

normally have application between 100 and 150,000 inlet acfm. A multiwheel compressor

can be thought of as a series of single wheel compressors contained in a single casing.

Most centrifugal compressors operate at speeds of 3,000 rpm or higher, a limiting factor

being impeller stress considerations as well as velocity limitation of 0.8 to 0.85 Mach

number at the impeller tip and eye. Recent advances in machine design have resulted in

production of some units running at speeds in excess of 40,000 rpm.

Centrifugal compressors are usually driven by electric motors, steam or gas turbines (with

or without speed-increasing gears), or turbo expanders.

4.7.1. DESIGN

There is an overlap of centrifugal and reciprocating compressors on the low end of the flow

range according to Fig-13-3 titled “Compressor Coverage Chart”, illustrated in the GPSA

3 9

manual. The selection of an appropriate compressor is based upon it. This figure covers the

normal range of operation for compressors of the commercially available types. Using this

chart it is inferred that Compressor K-103, based on an inflow of 92.73 ACFM and

discharge pressure of 1175 psig, can be designed either as a single-stage Centrifugal

pump or a multi-stage Reciprocating pump. See Annexure H.

4.8.Storage

The selection section contains the explanation for the suitability of types of tank system

used in processing industries, which are based on the environmental regulations, location,

and process materials involved.

4.8.1. GENERAL DESIGN CONSIDERATIONS

Storage vessels containing organic and non organic liquids and vapors can be found in

many industries, including;

(1) Petroleum producing and refining,

(2) Petrochemical and chemical manufacturing,

(3) Bulk storage and transfer operations, and

(4) Other industries consuming or producing liquids and vapors.

Liquids and vapors in the bulk storage and transfer operations can be organic or

hydrocarbon in nature. All those chemical should keep in the right storage tank. Design

and safety concern has come to a great concern as reported case of fires and explosion for

the storage tank has been increasing over the years and these accident cause injuries and

fatalities.

LPG STORAGE TANK

The two main forms of LPG are commercial butane and commercial propane. LPG may be

liquefied by moderately increasing the pressure or by reducing the temperature.

4 0

Refrigerated storage is used by gas suppliers to store large volumes of LPG. The main form

of LPG storage is in special tanks known as 'pressure tanks'. Commonly these pressure

tanks are termed 'bulk tanks' or LPG Bullets. because LPG has a high coefficient of

expansion in its liquid phase, the tanks are never completely filled with liquid (tanks are

filled to approximately 85% of their water capacity), the remaining space being taken up

with vapor (often referred to as the vapor space) to facilitate expansion without allowing the

liquid to become 100% full (often known as hydraulically full).

Most LPG storage tanks in standby-plant service are steel, non-refrigerated pressure

vessels. Tanks are available in many sizes for both aboveground and underground service.

New propane tanks are built to ASME standards and are designed for at least 250 psig

working pressure. Common tank sizes and approximate dimensions are shown in the chart

below. Larger industrial and commercial applications generally use 18,000 gallon and larger

tanks.

Technical SpecificationStandard Design As per ASME sec VIII Div 1 Pressure

Vessel Code

Pressure Design 18.0  bar

Design Temperature (atm) range -20 / +50 °C

Hydraulic Test Pressure 25.0 bar

Joints efficiency 0.85

Radiographs 100 %

Manhole 1

Flanging # ASA 300

Gates 8

Thickness 6 mm to 50 mm

Diameter 600 mm to 3000 mm

Length Up to 18 Meters Long

Weight 3000 To 80000 Kg

Typical sizes available2, 4 & 6 tons

8 & 10, Tons

4 1

12 & 15 Tons

18 & 20 Tons

26 & 30 Ton

36 & 40 Tons

NGL STORAGE TANKS

Natural gas processing plants remove NGLs in the natural gas stream due to liquid and Btu

content. The very low temperatures or high pressures required to keep natural gas in its

liquid state for storage.

DIESEL STORAGE TANKS

There are no specific legal requirements on how to store diesel or the quantity allowed

either in workplaces or domestic premises. It is not, from a health and safety point of view,

a particularly hazardous substance within the meaning of the Dangerous Substances and

Explosive Atmospheres Regulations 2002 - its vapor flash point is too high. This means that

its vapor will not ignite at normal room temperatures.

Diesel does not require a Location Test Certificate or an approved handler. 

When stored in a bulk storage tank of more than 5,000 litres, a Stationary Container Test

Certificate is required.  This is also the case if the diesel is used in connection with an oil

burning installation or an internal combustion engine, such as a generator.  In this case, the

threshold could be as low as 60 litres.  There are exceptions where the diesel is used in a

domestic oil burning installation.

Diesel may be kept in a store room in a building, but the store room must have a fire

resistance rating and the quantities allowed are limited, as is the package size.

CONCLUSION

4 2

Training at Pakistan Petroleum Ltd. is really a true learning experience. It has just not

taught the utilization of bookish knowledge into practical field but also the ethics of

professional life. This internship would remain the part of magnificence memories for the

reason of PPL’s hospitality & efforts of my seniors to teach their activities. It is expected that

this technical guidance & professional knowledge would be helpful in my future studies.

4 3

REFERENCES

http://www.ehow.com/list_7472499_fundamentals-process-design.html

http://www.msoe.edu/library/resources/standards/index.shtml

http://www.ihs.com/products/industry-standards/organizations/api/index.aspx

http://www.techstreet.com/info/astm.tmpl

http://www.nfpa.org/categoryList.asp?categoryID=124&URL=Codes%20&%20Standards

http://www.hse.gov.uk/electricity/standards.htm

http://www.osha.net/federal-osha-standards-and-regulations.html

http://oilgasprocessing.com/Gravityseparation.htm

http://www.engineeringtoolbox.com/pfd-process-flow-diagram-d_865.html

Gas Processing Suppliers Association (U.S.) Engineering data book : SI version / published

as a service to the gas processing and related process industries by the Gas Processors

Suppliers Association; compiled and edited in co-operation with the Gas Processors

Association, 12th ed.Tulsa, Oklahoma : Gas Processors suppliers Association, 2004.

Viska Mulyandasari, Heat Exchanger Selection and Sizing (Engineering Design Guideline), KLM Technology Group, Rev 03 November 2010.

R. Mukherjee, Shell-and-tube heat exchangers, Chem. Eng. Progress, Feb 1998.

4 4

ANNEXURES

Annexure A

Electrical standards and approved codes of practice

ELECTRICAL AND POWER

Standard Year Description

BS EN 61439 (many parts) 2009 - 2012 Low-voltage switchgear and controlgear assemblies

BS 5266 Parts 1 to 10 also BS

EN 50172

1999 - 2008 Code of practice for emergency lighting

BS 5424 Parts 2 and 3, also

IEC 60158 part 3

1985 - 1988 Specification for low voltage control gear

BS EN 60422 2008 Monitoring and maintenance guide for mineral insulating oils in

electrical equipment

BS 5839 Parts 1 - 11, also

PD6531:2010

1988 - 2010 Fire detection & alarm systems for buildings

BS EN 60079-30-2 2007 Electric surface heating

BS 6423 1983 Code of practice for maintenance of electrical switchgear and

controlgear for voltages up to and including 1 kV

BS 6626 2010 Code of practice for maintenance of electrical switchgear and

controlgear for voltages above l kV and up to and including 36 kV

BS EN 62305, 4 parts 2006-2011 Code of practice for protection of structures against lightning

BS 7375 2010 Code of practice for distribution of electricity on construction and

building sites

BS 7430 1998 Code of practice for earthing

BS 7671 2008 - 2011 Requirements for electrical installations. IEE Wiring Regulations.

Seventeenth edition

BS 7909 2008 - 2011 Code of practice for temporary electrical systems for entertainment and

related purposes.

BS EN 50110 Parts 1 and 2 2004 - 2010 Operation of electrical installations

IEC 60479 Parts 1-4, also

PD6519

1994-2005 Guide to effects of current on human beings and livestock.

BS EN 60529 1992 Specification for degrees of protection provided by enclosures (IP

code)

BS EN 60947 Parts 1-8 2001 - 2011 Specification for low voltage switch gear and control gear

ELECTRICAL APPLIANCES

4 5

Standard Year Description

BS 1362 1973 Specification for general purpose fuse links for domestic and similar

purposes (primarily for use in plugs)

BS 1363 Parts 1 -5 1995 - 2008 13 A plugs, socket-outlets and adaptors.

BS EN (IEC) 60309, Parts 1,2,

4

1999 - 2007 Plugs, socket-outlets and couplers for industrial purposes.

BS EN 60320, Parts 1, 2 1999 - 2009 Appliance couplers for household and similar general purposes.

BS EN 60335, Many parts   Specification for safety of household and similar electrical appliances

ELECTROMAGNETIC COMPATIBILITY

Standard Year Description

BS EN 61000-6-3,4 2007 - 2011 Electromagnetic compatibility. Generic emission standard.

BS EN 61000-6-1,2 2005 - 2007 Electromagnetic compatibility. Generic immunity standard.

BS EN (IEC) 60801, Part 2 1993 Electromagnetic compatibility for industrial-process measurement and

control equipment. Electrostatic discharge requirements

FLAMMABLE ATMOSPHERES

Standard Year Description

EEMUA 181 1995 Guide to risk based assessments of in-situ large Ex e & Ex n machines

EEMUA 186 1997 A Practitioners handbook – electrical installation & maintenance in

potentially explosive atmospheres

BS EN 1127, Parts 1,2 2007 -2008 Explosive atmospheres. Explosion prevention and protection.

Basic concepts and methodology for mining

PD CLC/TR 50404: 2003 Code of practice for avoidance of hazards due to static electricity.

BS EN 61241 2004, 2005 Electrical apparatus with protection by enclosure for use in the

presence of combustible dusts.

PD CLC/TR 50427 2004 Assessment of inadvertent ignition of flammable atmospheres by radio-

frequency radiation. Guide

BS EN ISO 10497 2004 Testing of valves. Specification for fire type-testing requirements

BS 7535 1992 Guide to the use of electrical apparatus complying with BS 5501 or BS

6941 in the presence of combustible dusts

BS EN 60079, many parts 2004 Electrical apparatus for potentially explosive atmospheres. Replaced

by BS EN 60079, but remains current.

BS EN 60079-6 2007 Explosive atmospheres. Equipment protected by oil immersion "o"

BS EN 60079-2 2007 Explosive atmospheres. Equipment protected by pressurized

enclosures"p"

BS EN 60079-5 2007 Explosive atmospheres. Equipment protected by powder filling "q"

BS EN 60079-1 2007 Explosive atmospheres. Equipment protected by flameproof

enclosures 'd'

BS EN 60079-7 2007 Explosive atmospheres. Equipment protected by increased safety 'e'

BS EN 60079-11 2007 Explosive atmospheres. Equipment protected by intrinsic safety 'i'

4 6

BS EN 60079-22-2 2007 Explosive atmospheres. Gas detection. Selection, installation, use and

maintenance of detectors for flammable gases or oxygen

Energy Institute Model Code

Of Safe Practice, Part 1 (IP1)

2010 Electrical Safety Code

Energy Institute Model Code

Of Safe Practice, Part 15

(IP15)

2005 Area classification code for installations handling flammable fluids

Energy Institute Model Code

Of Safe Practice, Part 21

(IP21)

2002 Guidelines for the control of hazards arising from static electricity

MACHINERY

Standard Year Description

BS EN ISO 13850 2008 Safety of machinery. Emergency stop. Principles for design.

BS EN 953 1997 - 2009 Safety of machinery. Guards. General requirements for the design and

construction of fixed and movable guards

BS EN 13849 2008 Safety of machinery. Safety related parts of control systems. General

principles for design

BS EN 982 1996  -2008 Safety of machinery. Safety requirements for fluid power systems and

their components. Hydraulics

BS EN 983 1996  -2008 Safety of machinery. Safety requirements for fluid power systems and

their components. Pneumatics

BS EN 1037 1996  -2008 Safety of machinery. Prevention of unexpected start-up

BS EN  ISO 12100 2010 Safety of machinery. General principles for design. Risk assessment

and risk reduction.

BS EN 1088 2008 Safety of machinery. Interlocking devices associated with guards.

Principles for design and selection.

PD 5304 2005 Safe use of machinery

BS EN 60204 many parts   Safety of machinery. Electrical equipment of machines.

BS EN 61069, Parts 1-8 1991-1999 Industrial-process measurement and control. Evaluation of system

properties for the purpose of system assessment.

BS EN 61310, Parts 1,2,3 2008 Safety of machinery. Indication, marking and actuation.

BS EN 61496, 3 parts 2004 - 2008 Safety of machinery. Electro-sensitive protective equipment.

PIAC 1988 Printing industry advisory committee - safety at power operated paper

cutting guillotines

4 7

Annexure B

Block Flow Process Diagram

4 8

Annexure C

Block Flow Plant Diagram

4 9

Annexure D

Process Flow Diagrams (PFDs)

5 0

Annexure E

5 1

Piping and Instrumentation Diagram (P&IDs)

Annexure F

5 2

Plot Plan

5 3

Annexure G

Separator Sizing

Separator Vessel

Gas flow rate 60 MMSCFDGas Specific Gravity 0.75

Gas MW 21.72

Operating pressure 500 psigOperating temperature 100 oF

Compressibility 0.9Viscosity .012 cp

Flowing gas density, dG 2.07 lb/ft3Flowing oil density, dL 31.2

Separator type Horizontal, two-phase

Mass flow, M 39.8 lb/secParticle diameter, Dp 4.92*10-4 ft

C’(Re)2 4738From Fig. 7-4 GPSADrag Coefficient, C’ 1.40

Terminal Velocity, Vt 0.399 ft/sGas flow, Q 19.2 ft3/sAssume Dv 3.5 ft

Vessel length, L 17.5 ft

Diameter Length L/D3.5 17.5 54 15.315 3.82

4.5 13.615 3.0255 12.25 2.45

N.B. L/D ratio for horizontal separator is typically in the range of 2.5-5.

5 4

Annexure H

Compressor Design

5 5

Compressor K-103

Compressor Type Multi-stage

Reciprocating

with inter-cooling

Number of stages 2

Polytropic exponent 1.284

Polytropic efficiency 78.23%

Inlet stream Outlet stream

Stream name 14 16

Vapor fraction 0.9994 1.0000

Temp. (oF) 28.7549 236.25

Pressure (psig) 250 1175

Molar flow (MMSCFd) 2.9197 2.9197

Mass flow (lb/h) 7805.64 7805.6

Molar enthalpy (Btu/lbmole) 38.62 38.62

Overall compression ratio 4.5

Compression ratio of 1st stage 2.12

Compression ratio of 2nd stage 2.14

Discharge temp. of 1st stage 129.6 oF

Discharge pressure of 1st stage 561.2 psi

Suction pressure of 2nd stage 556.2 psi

Intercooler inlet temp. 129.6 oF

Intercooler outlet temp. 125 oF

Intercooler duty 3.16 hp

Total calculated compressor

duty

130.8 hp

Safety margin in compressor

duty for mechanical losses

5%

Total HYSYS compressor duty 135 hp