report final

Ministry Of Education And Training

PetroVietnam University

Petroleum Department

------------

INTERNSHIP REPORT

Summer Engineering Internship Jobs Of Oil

Exploration And Production Engineers At

Production Development Board Of PVEP

Period: From 6th

july to 31st july 2015

July 2015

Internship Unit:

PVEP- PetroVietnam Production

Exploration Corporation.

Instructor: Doctor Hoang Xuan Vu

Student:

Tran Xuan Truong

Student Number: 01PET110187

K1-KKT.01 Class

Trường Đại Học Dầu Khí Việt Nam Báo Cáo Thực Tập Sản Xuất

SV Thực Hiện: Trần Xuân Trường

THANK YOU

First of all, it is my sincere thank-you to the leadership board of PVEP who has

offered me the production internship from 6th

July to 31st July 2015. I want to say a

very thank you to everyone in development production board, who has been help me

alot and especially my internship instructor at PVEP- Doctor Hoang Xuan Vu (PVEP

senior production engineer) who has been very supportive and Mr Tran Van Ban (

PVEP development production board manager in HCM city) , they helped me a lot for

the comprehensive understanding related to production problems, also willing to share

with me his experiences to work as a production engineer which is very helpful to me

in the future. Not only Mr. Vu, but all of the staff at production board of PVEP have

also supported me a lot in having more reading materials in the field, also having an

orientation for my graduation thesis in my final year of university. I have to say that

I‟ve had a great time here to get experiences as if I am an already production engineer.

It is my truly honor to work in such a professional environment and with such

enthusiastic and friendly people. Besides, I also send my thank-you to Miss Le Hai

Linh – my lecturer at Petro Vietnam University, who is in charge of my internship

during the time I had worked at PVEP, Mr Hoang Thinh Nhan-Vice-Dean of

Petroleum Department of PetroVietnam University, who has introduced and made my

internship procedures available. Finally, thank you very much!

Ho Chi Minh City

30th

July 2015

Student: Tran Xuan Truong



PVEP INTRODUCTION

PVEP has been having a long tradition and the key unit of PVN in the oil

exploration and drilling in years. The process of establishment and development of

PVEP has associated with the oil history of Vietnam over the past fifty years.

Originating from companies of Petrovietnam II (PV-II, established in 5/1988) and

Petrovietnam I ( established in 11/1988), PVEP has many times changed its name and

structure to suit with different periods of development. In 1993, PVSC and PVEP were

established through reconstructing PV-II and PV-I, this was an important milestone to

mark one stride of Vietnam oil industry in effectively manage oil drilling and

exploration operations in Vietnam, also participating in both domestic and overseas oil

activities as an oil contractor in order to develop into a real oil company step by step.

The birth of PIDC based on PVSC in 2000 was a historical milestone for the

development of present PVEP with PIDC boosting investment, joining capitals into

domestic projects, getting first successes in controlling crucial exploration projects by

itself along with deploying overseas projects through joint projects with Iraq, Algeria,

Malaysia, Indonesia.

PVEP is established in 4th

May 2007 based on the combination of oil exploration

production company and oil investment-development company in order to reunite the

business and production activities in domestic and overseas.

Inheriting the accomplishments and experiences from precursor units, PVEP has

drastically developed and reaped lots of successes in the oil exploration and production

field. In the period of 2007-2012, PVEP exploited more than 40 million tons of oil and

condensate, 36.5 billion m3 of gas, announced the 27 oil explorations and put the new

16 reservoirs into production. The revenue during this period reached over 171.000

billion of Dong, submitting 59.000 billion of Dong for state budgets. Continuing the

role of pioneer unit of PVN in global economic integration, PVEP is now taking part

in tens of projects over 14 countries. By which some reservoirs of Cendor, D30 in

Malaysia and accelerating the production activities in Peru, Algeria,…The

accomplishments of PVEP along with PVN has significantly contributed to secure



national energy security, control the macroeconomics as well as the island sovereignty

of Vietnam.

1. Duties and functions of the boards

The boards have common functions as consultant to help the board of directors and

board member in the management and administration activities of the company

Taking responsibility to resolve work related directly to each department.

Participate in helping to resolve work of other department if relevant or when to be

asked

Support the implementation and monitoring of implementation, the project's operating

subsidiaries or unit members.

Building regulations, workflow process to ensures consistent and in accordance with

the provisions and the general operation of the company. Taking responsibility to

construct the statutes, policies, internal regulations of the company relating to the field

of activity of the board.

Building strategies, short, medium and long-term plans for the company.

Direct manage worker, salary, proposals awards, discipline for staff.

Ensure the principle of democratic concentration for each board, collective stick

construction group reviews, develop the capacity to work of the employee.

Report on activities of the department in time prescribe and irregular reports as the

bridge of the leadership Of the company, annual summary reports on field operations

of the board.

2. The mainly production activities and business of the company

Exploration and exploitation of oil and gas of PVEP currently vibrant take place in

both domestic and abroad. In the country, PVEP exploration activity in some places

include red river base, Phu Khanh base, Cuu Long base, Nam con son base, Malay

Tho Chu base. PVEP are projected in 13 countries of the region have the potential gas

oil in the Middle East, North and Central Africa, Latin America, South-East Asia.

2.1. The exploration

PVEP has built the target exploration strategic both in domestic and aboard according

to the period of 2011-2015. Striving for increase in capacity both at home and abroad



are 120 million tons of oil and fiend recovery period 2016-2025 and reached 200

reserves increase million tones of friend recovered oil.

2.2. Domestic exploration

The price of oil suddenly falling from 112 USD per barrel in June 2014, down to under

60 USD per barrel (mid-December, 2014), it record lowest level in the past 5 years,

plus the fluctuations in economic both in domestic and foreign countries has directly

impact on PVEP's activities.

In Vietnam, PVEP's business must face the hard difficult due to the tense situation on

the East Coast, some of the main mine are on the momentum of decline production of

small mines, mostly in deep water offshore areas-where always contains risks and

complex geology.

In the region has the potential of oil and gas has been proven to have high potential,

little risk, PVEP involved up to 100% of the shares or holds dominant stakes and direct

executives, especially in the Cuu Long base, Nam con son base, Red river base. In

addition, PVEP continue to study the subjects of traditional African exploration (non-

structural traps), study of the hot new deposits and new resources such as coal, gas,

shale gas ice fire.

2.3. Foreign exploration operations

Along with that is the fierce competition in the international oil and gas operations

makes the expand investment of PVEP met many obstacles. Moreover, the field of

investment in some countries have projects of PVEP continued negative changes.

PVEP actively invests on the principle of economic efficiency in order to offset the

lack of output shortages in the country and contribute to ensuring energy security for

the nation's economy.

In the period of 2015-2020, PVEP will select the potential areas with highly of oil and

gas, favorable political relations and cooperation with other oil and gas companies.

PVEP focuses on investments in the key areas of potential in Southeast Asia, Africa,

the Middle East, the countries of the former Soviet Union and Central/South America.



3. Production activity

According to the plan signed with PVN, PVEP's reserves increase during the year

2015 from 18 to 23 million tons of oil, the rules produced 5.86 million ( 4.71 million

tonnes of oil and 1.15 billion m3 of gas ), planning to produce three new field and

take signed 1-2 new contracts. However, due to oil price fluctuations, PVEP has

proactively reviewing and adjusting the project to match with the actual situation (cut

off 6 wells in home, three wells in the foreign, reduced investment of 480 million

USD, equivalent to 29%compared to the plan). PVEP also successfully reduced

operating costs, production (OPEX) down on the under 13%.

In the period 2012-2015 the total output of oil and gas extraction is expected on the

conversion 130 million tons and in the period 2016-2025 the total output of oil and gas

exploitation project above 400 million tons.



INDEX

CHAPTER I: PIPELINES ............................................................................................... 1

1. Pipelines ................................................................................................................... 1

2. Design Factors .......................................................................................................... 1

CHAPTER II: WELLHEAD ........................................................................................... 3

1. Wellhead Equipment ................................................................................................ 3

1.1. Xmas tree ........................................................................................................... 3

1.2. Down Hole Safety Valve ................................................................................... 4

2. Routine Operating Checks and Maintenance ........................................................... 5

3. Developing an Oil Field ........................................................................................... 5

4. Deviated Drilling ...................................................................................................... 6

5. Completing a Well ................................................................................................... 7

CHAPTER III: SEPARATOR ........................................................................................ 9

1. Objective .................................................................................................................. 9

2. Separation ................................................................................................................. 9

3. Flow patterns .......................................................................................................... 10

4. Separator Construction ........................................................................................... 11

5. Principles of separation: ......................................................................................... 12

6. The Separation Process: ......................................................................................... 12

6.1. Physical Separation .......................................................................................... 12

6.2. Flash Separation ............................................................................................... 12

6.3. Inlet Separation ................................................................................................ 12

6.4. Secondary Separation (Quieting Sections) ...................................................... 12

6.5. Residence Time ............................................................................................... 13

7. Separation and stabilisation PFD ........................................................................... 13

7.1. Separation Trains ............................................................................................. 13

7.2. The Ideal Separator .......................................................................................... 13

8. Separation systems ................................................................................................. 14

9. Reservoir to Process Train ..................................................................................... 14

10. Cooling after the final stage of separation: .......................................................... 15

11. Separator Instrumentation .................................................................................... 15



CHAPTER IV: PUMPS ................................................................................................ 18

1. Pumps ..................................................................................................................... 18

1.1. Centrifugal Pumps: .......................................................................................... 18

1.2. Positive Displacement Pumps: ........................................................................ 19

1.3. Pump Head ....................................................................................................... 20

1.4. Cavitation in Pumps: ........................................................................................ 20

Chapter V: Compresser ................................................................................................. 21

1. Objective ................................................................................................................ 21

2. Definition ............................................................................................................... 21

2.1. Gas ................................................................................................................... 21

2.2. Water Content: ................................................................................................. 21

2.3. Dew Point: ....................................................................................................... 21

2.4. Cricondenbar:................................................................................................... 21

2.5. Compression Ratio: ......................................................................................... 21

3. Methods of Compression ....................................................................................... 22

4. Reciprocating Gas Compressor .............................................................................. 24

5. Double-Acting compressors ................................................................................... 24

6. Lubricating System ................................................................................................ 24

7. Interstage Cooling .................................................................................................. 25

8. Centrifugal Type compressors ............................................................................... 26

9. Compressor Variables ............................................................................................ 28

10. Compressor Controls ............................................................................................ 29

11. Problems and solution .......................................................................................... 29

CHAPTER VI: VALVE, FLANGES AND PRODUCTION CHOKE ......................... 30

1. Valves ..................................................................................................................... 30

1.1. Common Types Of Valves: ............................................................................. 30

1.2. Working condition ........................................................................................... 30

1.3. Bolting Techniques .......................................................................................... 31

2. Flanges ................................................................................................................... 32

2.1. Type of glanges ................................................................................................ 32

2.2. Flange Bolt Tightening Sequences .................................................................. 34



2.3. Flange Facings ................................................................................................. 35

2.4. Insulated Flanges ............................................................................................. 35

3. Production Chokes ................................................................................................. 35

3.1. Purpose of chokes ............................................................................................ 35

3.2. Method of Choke Operation ............................................................................ 36

3.3. Problem and solution ....................................................................................... 36

3.4. Crrrosion .......................................................................................................... 36

CHAPTER VII: CHEMICAL INJECTION .................................................................. 37

1. Objective ................................................................................................................ 37

2. General ................................................................................................................... 37

2.1. Solids Deposition ............................................................................................. 37

2.2. Formation Of Emulsions .................................................................................. 37

2.3. Solids Deposits ................................................................................................ 37

3. Control .................................................................................................................... 37

3.1. Gas Hydrates .................................................................................................... 37

3.2. Sand control ..................................................................................................... 38

3.3. Scale control .................................................................................................... 38

3.4. Waxes and Ashphaltenes control ..................................................................... 38

4. Hydrate Prevention: ............................................................................................... 39

4.1. Wax Paraffin .................................................................................................... 39

5. Asphaltenes ............................................................................................................ 40

6. Chemical Injection System Design ........................................................................ 41

7. Chemical Injection ................................................................................................. 41

8. Scale Inhibition ...................................................................................................... 42

9. Emulsion Control ................................................................................................... 43

CONCLUSION ............................................................................................................. 44



LIST OF FIGURE AND TABLE

Figure 1. 1 Typical pipeline rotes .................................................................................... 1

Figure 2. 1 Typical layout of a north sea well ................................................................. 3

Figure 2. 2 Typical subsea wellhead ............................................................................... 4

Figure 2. 63 Typical both platform and subsea wells and manifolds .............................. 7

Figure 3. 1 Typical horizontal separator.......................................................................... 9

Figure 3. 2 Typical vertical separator ............................................................................ 10

Figure 3. 3 Three phases separator internals ................................................................. 11

Figure 3. 4 Three phases separator internals ................................................................. 11

Figure 3. 5 Separation and stabilisation PFD ................................................................ 13

Figure 3. 6 Typical three-phase separator ..................................................................... 14

Figure 3. 7 Reservoir to Process Train .......................................................................... 15

Figure 3. 8 Typical production train separator instrumentation ................................... 16

Figure 4. 1 Typical Pumbs ............................................................................................. 18

Figure 4. 2 Typical centrifugal pumps .......................................................................... 19

Figure 4. 3 Typical Displacement pumbs ...................................................................... 19

Figure 4. 4 Typical flow versus differential pressure .................................................... 20

Figure 5. 1 LP gas compression PFD ............................................................................ 22

Figure 5. 2 Reciprocating compresser ........................................................................... 23

Figure 5. 3 Centrifugal compressor ............................................................................... 23

Figure 5. 4 Double-Acting compressor ......................................................................... 24

Figure 5. 5 Lubricating System ..................................................................................... 25

Figure 5. 6 Interstage Cooling ....................................................................................... 26

Figure 5. 7 Centrifugal Type compressorsComponents ................................................ 26

Figure 5. 8 Casing of compressor .................................................................................. 27

Figure 5. 9 Centrifugal type compressors typical rotor ................................................. 27

Figure 5. 10 Centrifugal type compressor thrust direction ............................................ 28

Figure 5. 11 Centrifugal compressor balance drum thrust ............................................ 28

Figure 6. 1 typical bolt tightening sequences for flanges .............................................. 33





Figure 6. 4 Typical torge wrench .................................................................................. 34

Figure 6. 5 Production choke ......................................................................................... 35

Figure 6. 6 Choke operating ares ................................................................................... 36

Figure 7. 1 A large gas hydrate plug in a subsea pipline ............................................... 38

Figure 7. 2 Effect of gas composition on hydrate formation tempratures ..................... 39

Figure 7. 3 Wax Paraffin ............................................................................................... 39

Figure 7. 4 Asphaltenes ................................................................................................. 40

Figure 7. 5 Typical injection system ............................................................................. 41

Figure 7. 6 Chemical injection pumping system ........................................................... 42

Figure 7. 7 Typical scale deposition .............................................................................. 43

LIST OF TABLE

Table 6. 1 API Flange Temperature to Pressure Rating. .........................................................................31

Table 6. 2 API Flange Test and Working Pressures. ...............................................................................31


SV Thực Hiện: Trần Xuân Trường Page 1

CHAPTER I: PIPELINES

1. Pipelines

Pipelines are the most common way of transporting oil or gas. Pipelines are like any

flow line except that pipelines are

• Very long.

• As straight as is possible.

• Are welded (continuous).

• Have no sharp bends.

• Are often buried or inaccessible over the majority of their length

• Require regular cleaning and inspection.

• Are often very cold due to depth of water resulting in condensation and corrosion.

Figure 1. 1 Typical pipeline rotes

2. Design Factors

The design factors of the pipe line which must be considered are

• Physical and chemical properties of the fluid transported

• Maximum volume of fluid being transported

• Environment the pipeline will travel through

• Required delivery pressure



Heavy Crudes: Some crude oil with very high pour points or high wax content require

pipelines of special design or treatment to meet following needs such as

• Insulating and heat tracing the pipeline

• Heating the crude to high temperature

• Use high pressure pumping

• Injecting water

• Exporting an emulsion of crude and water

• Processing

• Adding a less dense stream of fluid, (condensate)

• Chemical injection



CHAPTER II: WELLHEAD

1. Wellhead Equipment

1.1. Xmas tree

This subsea Xmas tree is being lowered on a running tool. It is a „Horizontal‟ type tree

where the master and flow valves are out with the vertical opening of the tree. This

allows easy retrieval of the tubing through the tree. With previous types of tree, the

tree would have to be removed before the tubing could be removed. Thus the

Horizontal tree saves time money and is safer.

Figure 2. 1 Typical layout of a north sea well



Figure 2. 2 Typical subsea wellhead

1.2. Down Hole Safety Valve

It IS the first valve from bottom in a completion string

• Located at a depth of approximately 2000 feet from process deck.

• Hydraulically controlled from the surface

• Fail safe (closes with a spring on loss of hydraulic pressure)

• BaIl Type : Less Common, prone to Leakage, restricts

• Flapper Type: More common, seal protected, greater

Figure 2. 3 Down hole safety valve



2. Routine Operating Checks and Maintenance

• Annulus pressure will increase due to temperature when well is opened for first

time - blow down this pressure.

• Blow down to platform-specific limits

• Monitor fluids drawn off for type and volume

• Tubing Head Pressure

• Flowing and Static Pressures

• Greasing and Closure Tests

• Different greases for oil and gas

• Integrity Tests of the DHSSV, Upper Master Valve (U MV), and FWV

• Leakage rates monitored

3. Developing an Oil Field

• The extent of the field must be found and test wells drilled

• Several wells can be drilled and produced to one platform.

• Appraisal wells are drilled

• Core samples taken

• Properties of the rock determined (electrical, permeability, etc.)

• Test wells are flowed if possible

• The boundaries of the discovery are established

If the field is big enough to be economically viable, development wells are drilled and

used for production.

Figure 2. 4 Directional drilling from single platform



4. Deviated Drilling

• Economics demand that a single platform is capable of draining a large area of

reservoir or reservoir(s)

• Deviated drilling allows a single structure to reach the furthest expanses of the

reservoir

• Allows the reservoir to be drained more effectively

• Subsea Completions can also be tied back to the platform from outlying traps,

and secondary reservoirs

Figure 2. 5 Typical drilling rings



Figure 2. 63 Typical both platform and subsea wells and manifolds

5. Completing a Well

The well completion consists of decreasing diameters of tubing, each one drilled

deeper into the formation and cemented in position.

• Conductor - outermost casing

• Surface - forms outer wall of the “c” annulus

• Intermediate - drilled deep into the formation

• Production tubing - conducts reservoir fluids to the xmas tree

• The completion production tubing requires maintenance and work over.



Figure 2. 7 Perforated casing and liner completions



CHAPTER III: SEPARATOR

1. Objective

• Principle of separation

• Separation Process

• Separation systems

• Separator Types

• Separator Construction

• Separator Instrumentation

• Process Shutdown

• Crude Oil Coolers

• Nucleonic Level Devices

2. Separation

Separators separate a fluid mixture into its separate parts (phases) according to density.

Separators are classified by

• Shape or Position of the Vessel

• Number of Fluids (Phases) to be Separatea I

Two most common shapes are

• Horizontal

• Vertical

Figure 3. 1 Typical horizontal separator



Figure 3. 2 Typical vertical separator

3. Flow patterns

The flow in vertical and horizontal separators is similar

• A mixture of fluids enters at the side or end of the vessel

• Lighter components exit from the top (gas)

• Denser (heavier) components exit from the bottom (oil & water)

A three-phase Horizontal Separator uses a weir or „stilling pipe‟ to segregate the

heavier components into two streams.

• The weir acts as a barrier and holds the water phase behind it

• The oil floats on the water and cascades over the weir

• The weir acts as an interface (between oil and water) level control



Figure 3. 3 Three phases separator internals

Figure 3. 4 Three phases separator internals

4. Separator Construction

Separators are made of steel, and built according to rigid engineering specifications

• All seams are welded



• The separator may be lined against corrosion

• Internals are bolted for ease of inspection and repair

Separators corrode (rust) especially across oil/water interface.

Internals such as weirs also rust and can be the cause of water contamination ¡n oil and

level control problems.

5. Principles of separation:

• The fluids must not be soluble into each other.

• There must be a difference in density between the fluids

• The greater the difference in density, the easier fluids will separate

6. The Separation Process:

The separation of gas, oil, and water is largely achieved by

Physical Separation

Flash Separation

6.1. Physical Separation

• Settling due to different densities over „residence time‟

• Coalescence

• Filtration

• Velocity Changes

• Centrifugal Forces

• Impingement

6.2. Flash Separation

Acts be reducing pressure on crude mixture

Increased Temperature

Enlarge the Volume available to encourage gas out of solution

The effect of these processes can be optimised when:

• The separator makes use of as many processes as possible

• The separator has been sized to accommodate the maximum expected fluids

• Residence time in vessel is sufficient for efficient separation to take place

• Efficient separation of fluids takes place in a series of stages inside each

separator

6.3. Inlet Separation

• Bulk of gas/oil separation

• Diverter plate forces change of direction

6.4. Secondary Separation (Quieting Sections)

• Flow is slowed

• Flow is straightened



• Coalescing

• Chemical injection

6.5. Residence Time

Residence Time is the time the reservoir fluids take to pass through a separator It

usually takes between 2 and 4 minutes time for crude oil to pass through a separator.

7. Separation and stabilisation PFD

7.1. Separation Trains

The number of crude oil separation trains and the number of stages (separators of

decreasing pressure! temperature) varies with each installation. The principles of a

two-stage process apply equally to a four-stage process.

7.2. The Ideal Separator

An ideal separator reduces the pressure of thereservoir fluids to near atmospheric

pressure at the discharge of the separator . In practice, this ¡s rarely possible because

the crude mixture would foam uncontrollably (like a champagne bottle opening) and

the best approach is to use multiple stages, which reduce the pressure gradually - in

stages.

Figure 3. 5 Separation and stabilisation PFD



8. Separation systems

Separators are located downstream of the wellhead Xmas tree, choke, and manifolds

They provide the following services

• Clean up completions

• Test individual wells

The majority of separators offshore are three-phase separators.

The main difference between three and two- phase separation is the weir plate which

separated liquids, and the additional instrumentation needed to control an additional

interlace

Figure 3. 6 Typical three-phase separator

9. Reservoir to Process Train

The Separation System involve following stages:

• Stabilisation

• Stabilisation at First Stage

• Pressure and Temperature

• Stabilisation at Second Stage


• Stabilisation at Third Stage




Stabilisation means no more separation of gas/oil phases at that pressure and

temperature

Figure 3. 7 Reservoir to Process Train

10. Cooling after the final stage of separation:

• Stabilises the crude at the required vapour pressure

• Minimises the temperature gradient across the storage cell walls in concrete

bunkers

• Prevents vapour losses

• Reservoir to Test Separator

• Identical flow path to the main separation -all flows from the test separator are

measured

11. Separator Instrumentation

Within operational requirements-all separators are fitted with:

• Pressure Indication and Control

• Temperature Indication

• Pressure Safety Valve(s)



• Manual Blowdown Line

• Gas Outlet Line

• Gas Outlet Flow Meter

• Level Indication and Control

• Oil Outlet Line

• Drains

Figure 3. 8 Typical production train separator instrumentation

All Separators are fitted with the following protection facilities:



• High Level Shutdown (Level Switch Hi Hi, LSHH)

• High Level Alarm (LSH)

• Low Level Alarm (LSL)

• Low Level Shutdown (LSLL)

• High Pressure Shutdown (Pressure Switch Hi Hi, PSHH)

• High Pressure Alarm (PSH)

• Low Pressure Alarm (PSL)

• Low Pressure Shutdown (PSLL)

• Automatic Isolation Valves on All Inlets and Outlets (ESDV5)

Where the crude is cooled prior to the final stage separator the following instruments

are also used:

• High Temperature Shutdown (TSHH)

• High Temperature Alarm (TSH)

Pressure Control

Gas (used as means of pressure control) from the separators can go to either or both of

two routes;

• To flare during start-up and upsets

• To the compressors assigned to the separator stage

Level Control

Liquids under level control follows the same path regardless of the condition of the gas

compression. Level control is accomplished by use of a level sensor, and a transmitter

acting on one or more control valve



CHAPTER IV: PUMPS

1. Pumps

Pumps are used to provide energy to move fluids. These are two distinct types,

Centrifugal pumps and Positive displacement pumps (PD).

PD pumps are most often used where higher pressures and lower volumes are required.

Centrifugal pumps are used where lower pressure and higher volumes are required.

Figure 4. 1 Typical Pumbs

1.1. Centrifugal Pumps:

Are of simple construction and can also be known as Rotodynamic. The pumps consist

of vaned wheels called impellers

• Single Rotating Impeller (Can be Multi-Stage)

• Stationary Spiral Casing (Volute)

Centrifugal pumps are generally used for lower pressure, higher volume applications.



Figure 4. 2 Typical centrifugal pumps

1.2. Positive Displacement Pumps:

• Positive displacement (PD) pumps can be piston, screw or gear driven and are

not reliant on the suction pressure to attain discharge pressure.

• A positive displacement pump has an isolation valve system between inlet and

outlet section of the pump preventing backflow.

• PD pumps are most often used where higher pressures and lower volumes are

required

Figure 4. 3 Typical Displacement pumbs



1.3. Pump Head

Head‟ is the difference between the suction and the discharge pressure. Net Positive

Suction Head (NPSH) = The required head of fluid to flood the suction inlet and

prevent vapor locking.

• The minimum suction pressure is specified by manufacturer on a plate on the

machine

• Available suction pressure should be 1 - 10% above this minimum pressure

• PD pumps displace the same amount of fluid with each revolution, or stroke,

and are commonly used for chemical injection, lube oil supply, and metering

systems

Figure 4. 4 Typical flow versus differential pressure

1.4. Cavitation in Pumps:

Cavitation is the term used for liquid vaporizing inside the volute (pump inlet eye). It

creates small bubbles of vapor which collapse against the pump surface with shock,

„chipping‟ off particles of metal. Cavitation can be caused by a suction pressure lower

than the vapor pressure of the pumped fluid



Chapter V: Compresser

1. Objective

• Principles of Gas Compression

• Method of Gas Compression

• Types of Gas Compressor

• Problems of Gas Compression

• Lubricating System of Compressor

• Interstage Cooling System of Compressor

2. Definition

2.1. Gas

Is a matter, which has loosely bound molecules, and these molecules freely occupy

any amount of space

Gases can be compressed into a required volume or density and can be compressed to

a liquid state. Gases flow from higher pressure to lower pressure to find a balanced

state.

2.2. Water Content:

The amount of water contained within the gas usually measured at a certain pressure

and temperature (dew point)

2.3. Dew Point:

Is that temperature when the first drop of liquid condenses from a vapor

Operating Temperature: Required temperature to prevent liquid dropping out or

forming in the gas.

2.4. Cricondenbar:

The maximum pressure at which vapor and liquid may exist in equilibrium

2.5. Compression Ratio:

Compression Ratio (CR) is the ratio between the suction pressure (Absolute) and the

discharge pressure (Absolute) of a compressor.

Absolute Pressure:

Pressure measured by the pressure gauge + approx 15 psi



Principle of Gas Compression

PIVI = P2V2 (at constant Temperature).Where initial pressure and volume (pivi) is the

same ratio as increased or decreased pressure and volume (p2v2). when gas is

compressed, the following takes place: pressure rises, volume decreases, temperature

rises, external power is applied.

When gas is compressed, Absolute Pressure measurement is used for calculations. If

you wish to measure

• Absolute Pressure, the pressure exerted by the atmosphere ¡s not included in the

Gauge reading.

• Therefore, atmospheric pressure is added to the gauge reading to convert in to

an Absolute Pressure.

These common conversion values are used to calculate Absolute pressure: psig

(pounds per square inch gauge) = 14.7 psia (pounds per square inch absolute), kPag

(kiloPascals gauge) = 101 KPaa (kilo Pascals absolute). 1 barg (bar gauge) = 0 bara

(bar absolute), 0 bara (bar absolute) = -1 barg (bar gauge)

3. Methods of Compression

A gas compressor is a mechanical device that takes in a gas and increases its pressure

by squeezing a volume of it into a smaller volume. Usually this is done in several

stages. Below is a two-stage compression system.

Figure 5. 1 LP gas compression PFD

There are two Common ways to compress gas:



By Positive Displacement Compressor:

A fixed volume of gas is compressed using. Reciprocating Compressors, and a positive

displacement method is used. These compressors are used for relatively low flow and

high pressure operations.

Figure 5. 2 Reciprocating compresser

By Centrifugal Compressor:

Centrifugal Compressor imparts energy in to gas flow, by increasing the velocity of

the gas then changing the velocity to pressure. These compressors are used where

higher flow rates and volumes of gas is required, but at lower pressures.

Figure 5. 3 Centrifugal compressor



4. Reciprocating Gas Compressor

Used for low flow and high pressure operations.

Reciprocating Type :

• Connecting Rod

• Piston

• Crosshead

• Cylinder head

• Piston Rod

• Cylinder

• Suction Valves

• Discharge

• Suction Inlet

• Discharge Valve

The compressor has the following components as below:

• Packing

• Wrist Pin

• Crankshaft

5. Double-Acting compressors

Double-Acting compressors compress on both strokes of the piston.When multistage

machines are used, they are frequenUy cooled between the stages.

Figure 5. 4 Double-Acting compressor

6. Lubricating System

The purpose of the Lubricating System is to: Create an anti-friction film between

moving surfaces

• Reduce metal wear



• Cool by removing the heat generated by friction and compression • Provide a

degree sealing action

• Clean by removing the dirt and debris from the bearing surfaces • Protect metal

surface from corrosion

Figure 5. 5 Lubricating System

7. Interstage Cooling

Interstage cooling is necessary to protect the compressor from damage and to make the

compression process more efficient. Lnterstage cooling principles apply to both types

of compressors, (reciprocating and centrifugal) and has the following advantages:

• Reduction in horsepower by multi stage pressure increase

• Recovery of heavy hydrocarbon condensate by cooling and condensation

• Volume reduction of Machinery due to multi staging and greater efficiency

using cooled (denser) gas

• Protection of compressors and plant against extreme temperatures due to gas

compression heat.



Figure 5. 6 Interstage Cooling

8. Centrifugal Type compressors

Centrifugal Type compressors are used for high flow operations and where high

energy efficiency is required.

Figure 5. 7 Centrifugal Type compressorsComponents

• Casing : Is the housing for the rotating parts of the compressor

• Impeller: This is a rotating wheel which increases the gas flow

• Rotor and Shaft: Compressor equipped with two or more impellers has its shaft

I impeller assembly referred to as the Rotor

• Thrust Bearings : Locate the Rotor axially and absorb any axial rotor thrust

forces

• Balancing Drum :Uses machine discharge pressure to cancel out thrust forces.

• Diaphragm :ls the device that separates the stages in a multi stage compressor

• Inlet Guide vanes : The inlet guide vanes controls the flow rate of the gas in the

compressor. The performance of the compressor is affected by direction and

velocity of the gas enters the impeller eye.



• Main (Journal) Bearings: Maintain the rotor assembly ¡n its correct position,

especially when load or speed parameters changes.

Figure 5. 8 Casing of compressor

Figure 5. 9 Centrifugal type compressors typical rotor



Figure 5. 10 Centrifugal type compressor thrust direction

Centrifugal compressors thrust balancing drum

Gas pressure is routed to the downstream side of the balancing drum to counteract the

thrust pressure caused by the impellers upstream

Figure 5. 11 Centrifugal compressor balance drum thrust

9. Compressor Variables

Compressors are often arranged in stages to increase efficiency, and this depends on



• Compression Ratio

• Volumetric Flow Rate

• Pressure & Flow Characteristics of the System

Attached here is a stage table of compressors to give comparative study between the

number of impellers in use, increase in temperature and power consumption.

10. Compressor Controls

The following types of drivers used to drive Compressor

• Gas or Steam Turbines

• Variable direct voltage Electric Motor

• Variable alternating current frequency Electric Motor

• Fixed Speed drives

• Diesel Engines

Safety Systems and Controls

• Compressors are usually controlled locally by Programmable Logic Controller

(PLC) or computer systems.

• Critical signals from the Local Control Panels (LCP) are copied to the Central

Control Room displays for appropriate action.

• Manual start-up and shut-down procedures must be followed carefully

• Built-in protection systems contain, pre-lubricating and post- lubrication cycles

to protect bearings when cooling and heating.

• In case where electrical lubricating pumps fail, gravity fed lubrication is

provided for back-up protection of bearings and shafts.

• Additionally, the compressors will not start without certain recommended

permissive achieved: for instance lub oil temperature.

• Centrifugal Compressor Problems

11. Problems and solution

Two main operating problems : Surge and Stonewall

Surge occurs when the compressor ¡s operated at below its minimum capacity at

particular speed. It undergoes supply starvation and cannot provide sufficient

discharge pressure. The result is that reverse flow occurs. This reverse flow then

increases the discharge pressure and flow resumes forward, dropping the inlet pressure

once more. The cycle repeats rapidly and vibrations increase greatly. If the surge is not

controlled quickly, it can cause extensive damage to the compressor. Refer to

compressor operating curves for the comparative study.

Solution: Antisurge control.

Surge is an unstable operating condition, it is controlled by the recycling gas from the

discharge of the compressor and fed in to suction side of the compressor and this

maintains a minimum flow through the compressor



CHAPTER VI: VALVE, FLANGES AND PRODUCTION CHOKE

1. Valves

1.1. Common Types Of Valves:

1.1.1. Gate Valves:

These valves are fully open or shut in the operation and should not be throttled.

1.1.2. Ball and Plug Valves:

Fully opened or shut in the operation and should not be throftled.

1.1.3. Globe Valves:

Flow control valve, can be throttled and gives tight shut off.

1.1.4. Butterfly valves:

Used for lower flow rates I pressures. Risk of leaking usually cannot give full shut ¡n

under pressure

1.1.5. Relief Valves:

Spring or pilot operated to open at a given pressure to protect systems from

overpressure

1.1.6. Check valves:

To allow flow in one direction only (Should NOT be used for an Isolation).

1.1.7. Actuator operated:

Quick acting for emergency shut off, usually big size valves and remotely operated

1.1.8. Twin Seal:

Used for tight shutoff in both directions

1.1.9. Needle Valves:

Used in high pressure operations, where bleed off or isolation to instruments is

required.

1.1.10. Ball check valves

Used in the sight or gauge glasses, (for effective operation, the valve handle on the

sight glass should be fully open.)

1.2. Working condition

The number of the series relates to the maximum working pressure expressed in psi at

a temperature of100°F.



The maximum working pressure is affected by temperature and will be reduced by a

factor of 1.8% for each 50°F increase in temperature above 100°F to a maximum of

450°F.

The following table gives the maximum working pressure as a function of

temperature.

Table 6. 1 API Flange Temperature to Pressure Rating.

Temp °F API 2000 3000

5000

10000 15000

100

150

200

250

300

350

400

450

2000

1964

1928

1892

1856

1820

1784

1748

3000

2946

2892

2838

2784

2730

2676

2622

5000

4910

4820

4730

4640

4550

4460

4370

10000

9820

9460

9280

9100

8920

8740

8560

15000

14730

14460

14190

13920

13650

13380

13110

For flanges less or equal to 14” diameter, the hydrostatic test pressure is 2 times the

maximum working pressure (MWP).

For flanges of equal or more than 16” diameter the hydrostatic test pressure is 1.5

times the maximum working pressure (MWP).

Table 6. 2 API Flange Test and Working Pressures.

Series API Max WP psi

Test Pres Flanges

14” or Less

Test Pres for

Flanges >16”

2000

3000

5000

2000

3000

5000

4000

6000

10000

3000

4500

1.3. Bolting Techniques

There are three accepted ways of tightening a bolt, stud or fastener



1.3.1. Torque

The use of torque is the most widespread throughout industry. Torque can be achieved

through manual means, such as:

Flogging spanners, torque multipliers, or hydraulic, air or electric powered wrenches.

Torquing is the area where most mistakes are made

1.3.2. Tension

Tensioning Tools are usually hydraulically powered and used for multiple or simultaneous

tightening of bolts.(The bolt is stretched and then the nuts are added). They are more accurate

(if maintained properly) than using torque since friction factors are not involved.

New bolts should be used and not retightened ones.

1.3.3. Heating

Bolt heating is a specialised process and often used by the Power Generation Industry

for tightening turbine-casing studs. The studs have a pre-drilled hole down their centre

into which an electrically powered heating element or „wand‟ is introduced.

1.3.4. Differences between „Torque‟ and „Tension‟

Torque

• Used for common or standard length bolts/studs.

• Accuracy dependant on frictional effects.

• No strain losses.

• Suits short to medium length bolts.

• Usual to tighten one bolt at a time.

• Large tooling needed for high torques.

Tension (For applications using hydraulic bolt tensionsers.)

• Requires one extra diameter of bolt length.

• Accuracy independent of friction.

• Strain losses need accounting for.

• Suits medium to long bolts

• Any number of bolts can be tightened at the same time.

• Capable of large bolt loads in small spaces.

2. Flanges

2.1. Type of glanges

Below are typical bolt tightening sequences for flanges. Bolts are numbered in a

clockwise direction. The correct sequence prevents misalignment of the flanges and



ensures even energisation of the gasket seal across the flange gasket face.

Figure 6. 1 typical bolt tightening sequences for flanges





Correct numbering of bolts should result in all odd numbers on one side of the flange

and even numbers on the other side.

2.2. Flange Bolt Tightening Sequences

Tightening should be carried out in a minimum of four passes.

• Passes 1-3 following numbered bolt sequence.

• Pass 4 tightening adjacent bolts all round the flange.

If using a Torque Wrench:

• Ensure it‟s calibrated properly

• Make sure the bolts are clean and rust free

• Use a hand wrench first then finish with the torque

wrench

• Use correct lubricant to reduce unnecessary friction

• When Tightening Flange Bolt Don‟t:

• Draw the flange up tight using one or two close bolts

only. This will simply cause local crushing or pinching

of the gasket and result in leaks or failure

• Over-tighten bolts to weaken or strip the thread.

Especially smaller diameters (under 1 inch) Figure 6. 4 Typical torge

wrench



2.3. Flange Facings

2.3.1. Ring Type Joint

Used for more severe duties: gives a metal to metal seal.

2.3.2. Raised Face

• Flat non metallic gasket are used and fitted within the bolts of the flange.

• Faces should be clean but do not score the face when cleaning.

2.3.3. Flat Face

Sealing is achieved by compression of a flat non-metallic gasket. Used for lower

pressure applications.

2.4. Insulated Flanges

Are used to isolate an anti-corrosion electrical charge. An insulating sleeve is fitted

through both flange bolt holes over the bolts. Insulating washers are used beneath the

nuts. These separate a „live‟ pipeline section from a „dead‟ one.

3. Production Chokes

3.1. Purpose of chokes

The primary purpose of a Choke is to

• Control production flow

• Give precise repeatable control

• Tight shut off (varies with choke wear)

Figure 6. 5 Production choke



3.2. Method of Choke Operation

• Manual (local)

• Pneumatic (remote)

• Electro hydraulic (remote)

• Chokes are located downstream of the wing valve on a xmas tree and are used

to reduce pressure and absorb pressure differential.

Figure 6. 6 Choke operating ares

3.3. Problem and solution

Choke damage in operation has three main causes

3.4. Crrrosion

• Caused by corrosive and acidic fluids, bacteria.

• Prevented by maintenance and corrosion inhibitor and correct operating practice

3.4.1. Erosion

• Caused by high velocity solid particles after choke orifice

• Prevented by correct operating practice and optimum choice of type

3.4.2. Cavitation:

• Caused by pressure drop then pressure increase.

• Repair and maintenance required.



CHAPTER VII: CHEMICAL INJECTION

1. Objective

• Chemicals and their reactions

• Careful and Controlled use of Various Chemicals

• Scale Inhibition

• Prevention And Reduction of Corrosion

• Prevention of Hydrate Formation

• Hazards & Preventions of Normally Occurring Radioactive Material

• Corrosion Mechanism

• Chemical Injection Pumps

• Uses and Handlings of Chemicals

2. General

In order to achieve maximum efficiency, in the operation of an offshore installation,

careful and controlled use of various chemicals is employed. Chemical injection plays

a vital role in hydrocarbon recovery and is aimed primarily at:

• Reducing Production Costs

• Achieving Export Specifications

• Assisting Hydrocarbon Production

• Minimising Production Problems

The aim of this section is to try and understand what the chemicals are doing and how

they act and interact.

2.1. Solids Deposition

Solids depositions cause hydrate, wax, asphaltines, and scale which results in

equipment plugging, downtime, damage to the equipment and additional costs or

penalties

2.2. Formation Of Emulsions

Emulsions and foam results in high viscosities and separation problems Interfaces

During Operation stages Interface ¡s maintained between

2.3. Solids Deposits

Prevention & Reduction of Solids Deposits are carried out by following methods

3. Control

3.1. Gas Hydrates

• Chemical Inhibitors



• Temperature/Pressure

• Depressurisation

• Chemical Treatment

3.2. Sand control

• Completion Design

• Fraccing/ Polymers

• Separation

• Mechanical (Pigging)

3.3. Scale control


• Mechanical (Pigging, Scraping]

• Squeeze treatment

3.4. Waxes and Ashphaltenes control


• Temperature Management

• Mechanical (Pigging, Scraping)

Figure 7. 1 A large gas hydrate plug in a subsea pipline



The Graph Shows The Effect Of Adding Methanol In Various Dose Rates.

Figure 7. 2 Effect of gas composition on hydrate formation tempratures

4. Hydrate Prevention:

• Remove water at wellhead via sub sea separation

• Inject thermodynamic inhibitor, e.g. methanol and glycol

• Inject kinetic / threshold hydrate inhibitor (THI)

• Maintain system conditions outside hydrate formation envelope by operating at

appropriate pressure and temperature

4.1. Wax Paraffin

Some hydrocarbon components will solidify or liquefy when the pressure and

temperature are reduced. This reduction occurs when the fluid flows from a hot

reservoir to the colder surface. Wax is a very common problem and it coats the insides

of pipes and pressure vessels.

Figure 7. 3 Wax Paraffin



Wax/paraffin Characteristics:

• Hard/soft solid deposits

• Deposit highly dependant on oil heavy-end composition

• Characterised by increased pipeline pressure drop

• Can be formed in crude oil and condensate liquid

Wax Formation and Prediction:

• Wax Appearance Temperature (WAT) / cloud point from laboratory tests

• Engineers perform wax deposition modellin

Wax Mitigation I Control:

• Maintain system temperature above WAT

• Inject wax inhibitor chemical: selection very fluid system dependant

• Periodic removal by scraper pigs

• Can perform hot oil flushing

System Design Impacts:

• Insulation and burial requirements for pipelines

• Shutdown operation decision making

• Round trip pigging and flushing of system

5. Asphaltenes

Ashphaltenes are hard pellets of hydrocarbon material formed when pressure drops.

They appear when reservoir pressure is below bubble point due to change in crude oil

composition they create problems usually in reservoir or well bore (Treated by scraper

intervention, and soaking with solvent benzene I xylene)

Figure 7. 4 Asphaltenes



6. Chemical Injection System Design

System Design Impacts

• Oxygen Scavenger to remove oxygen and prevent corrosion

• Scale Inhibitor to reduce formation of scales

• Demulsifier to break emulsions and aid separation

• Corrosion inhibitor to prevent and reduce corrosion

• Biocide to kill micro-organisms or microbes (bugs)

• Methanol to prevent hydrate formation

• Hypochlorite to prevent organic growth

Figure 7. 5 Typical injection system

7. Chemical Injection

• Chemical Injection Pumps

The various chemical injection pumps with separate heads of duty and standby multi-

head injection pumps are driven by electric motors. Each pump has an adjustable

capacity or „stroke‟.



• Positive displacement diaphragm type pump has a discharge piping to the

relevant injection points

• Pump suction protected by a „Y‟ type of strainer.

• Pump capacity can be adjusted whilst pump is running or is stationary by means

of a hand-wheel in the gearbox, which varies the pump stroke length.

• Pump calibration carried out by timing the rate of usage of the chemical in the

calibration pot.

Figure 7. 6 Chemical injection pumping system

Setting of The Injection Rate:

The Setting of the injection rate is done using graduated cylinder. The graduated

cylinder is filled and then main tank is isolated, the pump rate in CCs, or litres per

minute then timed and calculated.

8. Scale Inhibition

Scale is a term loosely applied to the mineral salts which have precipitated from

an aqueous (water) solution and have been deposited on the surfaces of

production pipe work, vessels and other equipment.

Accumulation of such deposits can restrict flows through control valves,

exchangers, flow straighteners, and isolation valves. Scale can also restrict the

performance of metering systems, pumps and rotors.

Sulphate scales are deposited due to incompatibility of waters, e.g. injected

seawater / aquifer water



Severe plugging at well tubing is possible due to scale deposition

Treat deposition via regular scale squeeze operation

Figure 7. 7 Typical scale deposition

9. Emulsion Control

Two types: Oil-in-water or water-in-oil

Viscosity increases and there is increased pressure loss

Stability measurement is made by bottle tests

Interface with topsides production chemist needed



CONCLUSION

The one-month internship at the development production board of PVEP has given

me the overview about typical jobs of a production engineer. In which, I‟ve managed

to delve into fundamental knowledge for a production engineer such as pipelines,

wellhead tools, separator, pumps, compressors system..ect. Although, I am still yet to

practice these jobs in reality. However, it‟s wonderful to have some knowledge

relating to production management as a senior production engineer by which I‟ve been

taught how to read a production report or a daily production report as well as suggest

solutions to effectively and promptly solve the emergencies. Most importantly, the

instructor gave me orientations for the graduation thesis that is suitable with my

capacity and interest as well as introduced me useful information for job applications

in the future.

As said above, this internship has helped me orientate the graduation thesis in the

next year of 2016. Therefore, I very expect to get supports from leadership board of

PVU for an appropriate internship place in the future so that I could have a successful

graduation internship and thesis , making first premises for successful job applications

and further career development.

Eventually, thank you very much to all who have supported me during this

internship. I tried my bests to complete this report reflecting what I had done and

learned, shortcomings are inevitable though. It will be very helpful to me to have your

sincere remarks and assessments, so that I could have better preparations for the next

one.

report final

Documents

development of pvep

production board of

production internship

development of present

leadership board of

production engineers

production problems

oil drilling