i

OFFSHORE OIL AND GAS FIELD DEVELOPMENT PLANNING

by

Zaw Htun

An internship report submitted in partial fulfillment of the requirements for

the degree of Master of Engineering (Professional)

in Offshore Technology and Management

Examination Committee: Dr. Gregory L.F. Chiu (Chair Person)

Dr. Pornpong Asavadorndeja (Member)

Dr. Jonathan Shaw (Member)

Nationality: Myanmar

Previous Degree: Bachelor of Engineering (Mechanical)

Mandalay Technological University

Mandalay, Myanmar.

Scholarship Donor: PTT Exploration and Production International Ltd.

Asian Institute of Technology

School of Engineering and Technology

Thailand

August 2010

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ACKNOWLEDGEMENTS

I would like to express my sincere thanks, gratitude and attentive appreciation to my advisor,

Dr. Gregory L.F. Chiu for his invaluable advice and enthusiastic encouragements. The

extended gratitude and appreciation are conveyed to my examination committee members,

Dr. Pornpong Asavadorndeja and Dr. Jonathan Shaw for their helpful and kind suggestions

and comments.

I would like to say great thanks to my mother department, Myanmar Oil and Gas Enterprise,

and PTT Exploration and Production International for providing me a great chance to study at

A.I.T for a professional master degree in offshore technology and management.

I would like to express my enormous gratitude and appreciation to my family and my beloved

wife, for their great help, encouragement and generosity.

Zaw Htun

st-110069

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TABLE OF CONTENTS

Chapter Title

Page

Title Page i

Acknowledgements ii

Table of Contents iii

List of Figures iv

Executive Summary vi

Abbreviations vii

Introduction 1

1.1 History of Oil Field 1

1.2 Objectives of the Study 1

1.3 Scope of the Study 1

1.4 Organization of the Report 2

Acquisition and Exploration 3

1.5 Fiscal Terms 3

1.6 Environmental data 3

1.7 Exploration 3

Appraisal and Conceptual Development Plan 11

1.8 Appraisal Drilling 11

1.9 Conceptual Development Plan 12

1.10 Surface and Surface Development Options 17

1.11 Market Evaluation 18

1.12 Project Evaluation 18

1.13 Risk Allocation 20

1.14 Feasibility Studies 21

Field Development Plan 23

1.15 Field Description 23

1.16 Future Reservoir Characterization 23

1.17 Drilling and Well Completion Plan 24

1.18 Facilities Descriptions 25

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1.19 Health, Safety and Environment 29

1.20 Decommissioning and Abandonment 30

1.21 Economic Evaluation 32

Engineering and Construction 34

1.22 Basic Design 34

1.23 Front End Engineering Design 34

1.24 Detailed Design 34

1.25 Operating Plan 35

Conclusion 37

References 38

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LIST OF FIGURES

Figure Title Page

2.1 A sample of 3D seismic interpretation 6

2.2 Illustration of offshore seismic survey 7

4.1 Offshore platforms 26

4.2 Floating liquefied natural gas facilities 28

4.3 Decommissioning Options 31

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EXECUTIVE SUMMARY

Many Oil and Gas E&P companies, both international and national, came into emphasize on

field development plan in last few decades. The very first stage of oil and gas exploration and

development project is field development plan. This report is trying to extend the knowledge

of field development planning for an offshore oil and gas industry.

This report reveals the general concept, influence parameters, steps and procedure which may

concern with offshore oil and gas field development. It is not a development plan of a specific

field but for general. The steps involved in this report are incredibly simple and following on

the oil and gas process workflow.

There are numerous considerable factors related with field development plan such as

reservoir, reservoir fluids, exploration and development facilities, available technologies,

economics, environmental, HSE and many other factors and their related risks and

uncertainties. Every developer needs to emphasize to all related factors to ensure sufficient

economic return and safety for both personnel and environment avoiding uneconomic

development.

This report presents a number of aspects concerned with offshore oil and gas Field

Development Plan, both technology and management. However, it is not a comprehensive

study because of the time constraint and many other factors. All expressions in this report are

based on the knowledge gained during the internship period in PTTEPI Myanmar Asset and

books I have read within the compass of my comprehension.

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Definitions and Abbreviations

Deepwater 1000ft (300m) to 5000ft (1500m)

Ultra Deepwater 5000ft (1500m) to >10000ft (3000m)

API American Petroleum Institute

BPD Barrels per day

BOE Barrels of oil equivalent

BTM Buoy Turret Mooring system

DP Dynamically Positioning system, or vessel.

EIRR Effective Internal Rate of Return

EMV Expected Monetary Value

EPCI Engineering Procurement Construction & Installation

EPS Early Production System

EU Expected Utility

FEED Front End Engineering Design

FEL Front End Loading

FPS Floating Production System

FPSO Floating Production Storage and Offloading vessel

FPU Floating Production Unit

FSO Floating Storage and Offloading

FSU Floating Storage Unit

GoM Gulf of Mexico

HSE Health, Safety and Environment

IRR Internal Rate of Return

ISO International Standard Organization

IEA International Energy Agency

M Thousand

MM Million

NPV Net Present Value

OTC Offshore Technology Conference

PLEM Pipeline End Manifold

SSP Sevan Stabilized Platform

TLP Tensioned Leg Platform

TTR Top Tensioned Riser

VLA Vertical Loaded Anchor

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Chapter 1

Introduction

1.1 History of Oil Field

Oil was once produced only from places that were easy to find and collect. Oil was use

all over the world as a medicine to cure numerous diseases such as scurvy, gout,

toothache and rheumatism in the old age. Since it is combustible and it also used as an

instrument of war and also used in lamps as fuel.

The beginning of the petroleum age was opened by finding of ―black goo‖ seeping in a

water well near Black Creek in Canada in the 1850s by Charles Tripp. The first well

was drilled on 27 August 1859 by Edwin L. Drake at Titusville, Pennsylvania, USA. It

was the first commercial oil well in North America. The oil rush that followed

prompted explorers to start looking beyond the ―easy‖ oil sources, searching deeper

below the Earth’s surface and farther around the globe. Some of the most promising

areas for petroleum development today are also in the most remote corners of the

world, with challenging geographic and climate conditions. In 1888, Karl Benz invented

the petrol engine. When the car entered the scene in the early 1900’s, the demand for

petroleum increased further. From 1900 to 1910, automobile production increased from 8

000 to 450 000 cars per year. This increase was heavily influenced by the mass-production

of the model T car by Henry Ford in 1909.

With the advance of technology and development of diesel engine, world’s demand of

petroleum oil rise up dramatically in the first days of 20th

century. Since those days, oil

has been explored and drilled out from deeper formation in onshore area and also in

offshore all over the world. Nowadays, almost all of the world inland basins and

continental shelf in offshore areas have been explored and exploited but the world’s

energy requirement is still rising up. Oil and gas industries have to face with the

technological and financial challenges to explore in far and deeper water offshore area.

Since oil and gas is the most profitable business but it’s also a most risky one, the role

of field development plan becomes vital.

1.2 Objectives of the study

The objectives of the study are:

to extend the knowledge of field development planning

to explain the planning and scheduling.

to reduce negative impact during operation.

to enhance performance in development project.

1.3 Scope of the study

This report is just about the general concept of an offshore oil and gas field

development plan. Only procedural approach used in this study.

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Before developing an oil and gas field, the developer or the operator company needs to

submit a field development plan to the local government to get approval. Field

development plan is the core business processes in upstream oil and gas industry. It

defines the project requirements and link between technical requirements and

commercial objectives to avoid the risk of taking inappropriate technical solutions. It

should be comprised of all activities and processes required to develop an oil and gas

field such as environmental impacts, geology, geophysics, reservoir engineering,

petroleum production engineering, infrastructures, well design and construction, well

completion design, surface and subsurface facilities, and economics and risk

assessment.

After acquiring concession rights and ensuring the existence of hydrocarbon, a

development plan must be prepared. According to the evaluation results of reservoir

analysis, planning of the field development evolving the facilities planning must be

established to optimize the hydrocarbon production. Hydrocarbon recovery is

maximized in development planning considering the production profile, hydrocarbon

fluid properties change over the lifetime of production. Additional development plan

might be required in the meanwhile of production phase. It is very important to

optimize development costs over the exploration and production life, including the

initial costs previously required until the start of production, the development period

prior to production and the facility extension, to accommodate the production profile

changes during the production life.

The production profile of the oil and gas field can be clearly identified by drilling

exploration wells, and conceptual development planning is performed while analyzing

the development plan developed in the initial stages. It is important to have sufficient

tolerance in the initial stage plan, for the development conditions have not been

sufficiently understood yet. However, too much wider tolerance, of course, could

increase the initial costs required. At the same time, it is also vital to study the

environmental impacts in the greater concerns of the global environmental

conservation. Since the reservoir performance varies with geological structure,

experience and successful outcomes related to field development are essential.

1.4 Organization of the report

The report was organized with six chapters as follows:

Chapter 1: Introduction

Chapter 2: Acquisition and Exploration

Chapter 3: Appraisal and Conceptual Development Plan

Chapter 4: Field Development Plan

Chapter 5: Engineering and Construction

Chapter 6: Conclusion

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Chapter 2

Acquisition and Exploration

2.1 Fiscal Terms

Petroleum taxation is one of the vital aspects of the oil and gas industry. Since oil and

gas is the most risky business it is important to study the fiscal term of local

government where there intended to invest. Fiscal systems for hydrocarbon exploration

and development have come a long way during the last 75 years. The current fiscal

systems are much more sophisticated as compared to the ones seven decades ago. The

ideal fiscal systems are designed in such a way that it is simple to apply and provide

the contractor with a fair rate of return (ROR) on investment commensurate with the

project risks, and provide the host government (HG) with an adequate resource for rent,

thereby resulting in a win-win situation. Some fiscal systems are unnecessarily

cumbersome and do not achieve the main objective.

There are two main petroleum fiscal systems in the world namely concessionary

system and contractual system. Concessionary system allows ownership or a free hold

interest of mineral resources. It is also called royalty/tax system. Some countries use

contractual system and it can be divided into production sharing contract system (PSC)

and service contract system according to their reserves. Contractual system does not

allow the mineral right. Government tries to guard their petroleum resources and used

to negotiate fiscal terms. Some countries use more than one fiscal system and so it is

used to say that there are more fiscal systems in the world than the countries in it.

However, the bottom line of them is a financial issue that measure how costs are

recovered and profits are divided.

The flexibility of the fiscal system can lead to a win-win situation for both local

government or NOC and the contractor or IOC. It is vital that the deep understanding

of fiscal terms of the government where the interested prospect is situated such as

signature bonuses, royalties, cost recovery limit, production sharing, taxes and

government participation before making an investment.

2.2 Environmental Data

It is one of the most important factors to be considered where the interested area to

explore is located and which kind of environmental hazards might be encounter.

According to the environmental data such as location, water depth, climate, weather,

and oceanographic data, the requirement of the facilities and technology may change.

The following data should be examined;

Water depth (as the water depth increase, more risky and more technological

challenges will encounter)

Location (how far from the nearest supply shore base)

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Target depth (rig capacity and Operating costs higher with depth)

Weather of the area (temperature, rainfall regime, wind speed, monsoon,

cyclone, etc. affect)

Oceanography (wind, wave, current, tide, sea water temperature, salinity,

marine growth etc.)

Seabed condition (bathymetry changes, solitons, sea-mounts, seabed soil

composition)

Seismic hazard (earthquake, volcanoes)

2.3 Exploration

Hydrocarbon exploration phase is subject to great uncertainties. The purpose of

exploration is to find out accumulation of hydrocarbons situated thousands of feet

underneath the earth surface. Exploration still remains as a high risk venture although

the development of excellent tools, such as 3D Seismic, 4D Seismic and growing of

information technology. It is because of today oil and gas business become complex

and sophisticated almost in every aspect such as politic, volatile stock market, taxation

systems, and environmental regulations.

2.3.1 Geology

Hydrocarbon is found in sedimentary basins in sedimentary rock, although many of the

sedimentary basins of the world contain no known significant accumulations. The

followings conditions may exist the accumulation of petroleum:

(1) rock layers in which organic matter that generated petroleum

(2) a mechanism of structure to move or migrate the petroleum

(3) A porous rock layers to allow petroleum fluid

(4) The seal layer of low-permeability or dense rock to trap and prevents further

migration.

There are four main branches of geology relevant in the exploring for hydrocarbons.

They are;

Sedimentology, the study of sedimentary rocks

Stratigraphy, the organization in time and space of sedimentary rocks

Structural geology, the study of deformations and fractures and

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Organic geochemistry, the study of the potential of rocks to produce

hydrocarbons.

Geologists analyze and synthesize the collected information into subsurface structure

maps on different scales. The most common geological maps are:

Equal thickness contours (isopachs)

Equal depths contours (isobaths) and

Physical rocks properties (lithofacies).

Geologists organize additional data obtained from exploration drilling to the subsurface

maps.

2.3.2 Surveys

Firstly, the area of interest is explored by airplanes or took satellite photographs

roughly. Then expert geologists study those photographs to discover the formations

that probably contain oil traps. These basic surveys permit the search to be narrowed

down and continued with more detailed explorations in smaller areas.

Image to identify the subsurface properties of a formation cannot be extrapolated from

surface characteristics and so it is need to be used geophysical methods. There are three

main types of survey oil and gas industries used to be carried out today for successful

prospecting. They are;

Magnetic survey

Gravity survey and

Seismic survey methods.

Magnetic survey method measures variations in the earth’s magnetic field usually from

an aircraft. This method indicates the subsurface distribution of crystalline formations,

which have no chance of containing hydrocarbons, and more promising sedimentary

formation.

Gravity survey method measures variations in gravitational fields which occur as a

result of the different densities of rock close to the surface. It provides indications of

the depth of the layers and their natures.

Seismic survey methods are the most popular and informative way of detecting and

defining subsurface structure. It involves ultrasound imaging of the subsoil by studying

the nature of wave propagation providing prospectors with information on the

subsurface structures and stratigraphy.To continue finding and to be able to view

hydrocarbon bearing reservoirs those are buried under far distance of sea or rock,

seismic surveys are conducted. Sound waves transmitted from water surface penetrate

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many layers of rock. When one layer meets another at a boundary, the waves are

reflected back to the surface. Each boundary reflects a part of the sound back to the

surface. The rest continues downward. On the surface, special devices called

hydrophones collect the reflected sound waves. Depending on the time taken to reflect

back to the surface, the type of geological formation can be detected. The sound carries

information of the subsurface structure. Cables from the geophones transmit the

collected information to the receiver devices. After that, the information is analyzed

and processed by using smart computers in the specially designed laboratories. Both 2-

D and 3-D images can be generated from the information from relevant survey type. 3-

D seismic is much more expensive than that of 2-D for it use several lines of

hydrophones in a grid to get detail record of signals. Those signals can be translated as

a virtual reality by using sophisticated computer software revealing the thicknesses and

densities of the sub-surface reservoir rock layers. It can also reveal the types of folds or

faults where there hydrocarbon might be trapped.

Nowadays, even 4-D images are created and used where the fourth dimension being

time. This allows a follow-up of the changes in a reservoir during its producing life.

The graphs are then interpreted by the experts to say where there is a possible

hydrocarbon trapping or not. Because of the reliability in these surveys, oil companies

can be quite sure that when drilling a well, it will produce oil or gas. The many

variables in sediment types, fossils, depositional environments, and geologic history,

structure, and deformation make each prospect unique.

Figure 2.1 A sample of 3D seismic interpretation. (source: Oil :from pores to the

pipeline. Schlumberger )

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An offshore seismic survey is conducted by a survey boat and hydrophones are long

trailed behind with cables. Waves source is a normally a compressed air gun. The

waves transmitted from the air gun pass through the sea water column and then reflect

and refracted back from the different layers of rock. Once, explosives used to be used,

but since they can harm marine life and so air guns have replaced them. Hydrophones

then pick up the information. The grid of cables can be very large, up to 1 km per 8 km.

Figure 2.2 Illustration of offshore seismic survey. (source: Oil :from pores to the

pipeline. Schlumberger )

The more challenging oil and gas reservoirs being searching for today do not usually

give any visible clues about where to find them. Instead, explorers must use indirect

survey methods to determine the best places to drill exploratory wells. These methods

look for the kinds of geological formations that are most likely to contain petroleum.

Measuring the magnetic properties of subsurface rocks can reveal the presence of

granite, or other types of rocks that might push petroleum upward into subsurface traps.

In magnetic surveys, a boat tows a magnetometer that can record magnetic distortions

in the Earth’s crust. Another device called a ―gravimeter‖ indirectly ―weighs‖ the

rocks. It can detect rocks that seal reservoirs, the porous materials in which petroleum

can lie, and formations like salt-domes that can trap hydrocarbons. Another test, called

geochemistry, involves taking soil samples and testing them for faint traces of

hydrocarbons that have seeped to the surface from underlying reservoirs.

2.3.3 Exploration Drilling

The prime objective of exploration wells is to define the nature of the fluids such as oil,

water or gas in the reservoir rock and to get preliminary data on the reservoir to make

further necessary measurement. Drilling is the last stage of the exploration process and

it can help making decision whether hydrocarbons are there or not obviously.

Knowledge getting from geological and geophysical surveys allows the potential of a

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prospect to evaluate broadly but the presence of suspected hydrocarbon resources

cannot be classified. Drilling is the only way that can establish the presence or absence

of oil and gas in a given subsurface formation. It also allows the chance to get pressure

and temperature of the reservoir and also allows taking sample of interested subsurface

formation to the surface for necessary analysis.

The main objective of the exploration wells is to identify the characteristics of reservoir

fluids and reservoir rock types and to get preliminary reservoir data to make further

studies and measurements. After accomplishing an exploration drilling, the following

data should have achieved accordingly;

- The nature and characteristics of the reservoir fluids originally in place such as

oil, gas and water

- The characteristics of the pay zones (sandstone, carbonate, shale content.etc.)

and especially the initial pressure, the initial temperature and the approximate

permeability, porosity and productivity.

By drilling exploration wells, operator got a chance to take a number of surveys by

means of electric wireline logging tools lowering down into the wellbore and also

possible to run temporary testing stream in order to perform production testing. A

number of physical data of the rock and reservoir fluids can be recorded by taking logs

which represent graphically as a function of depth or time. Production testing allows to

take formation samples and to record the variation of formation pressure and variation

of flow rate (Q).

Exploration drilling is related with lots of uncertainties and most risky process. For

offshore exploration the choice of drilling facilities depends on the depth of the water

at interested well location, expected target depth, climatic conditions, oceanography

and remoteness from the nearest logistic shore-based. It should be noted that the

majority of exploration wells will not encounter a commercial hydrocarbon

accumulation. Operator should have decided how many unsuccessful exploration wells

are necessary before proposing to relinquish the license. Nowadays, offshore

exploration drilling is very expensive. A typical offshore well of 4000 meters will cost

about 15 to 50 millions US dollar in shallow water, 30 to 70 millions dollar in deep

water and 50 to 100 millions in ultra deep water.

According to the information and data obtained from exploration drilling and the data

already received from geological and geophysical studies, a decision must be made

either develop the reservoir or not or to drill further more wells to get additional

information after a feasibility study whether technically or economically viable to

appraise the reservoir.

Surveys used in early exploration work can also identify potential hazards to vessels or

seafloor conditions that may be unsafe for the placement of exploration drilling rigs.

―Shallow hazard‖ surveys look for underwater peaks and valleys (topography) or man-

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made dangers like shipwrecks. In the Arctic, special surveys on conditions such as ice

gouges and strudel scours may be conducted to gather data for potential future oil and

gas production activities.

2.3.4 Rig Selection

According to the location and water depth of the area to be explored, suitable rig type

must be chosen. The following rig types are commonly used in oil and gas exploration

in the offshore area.

2.3.4.1 Floating Rigs

There are two main types of floating rigs: drillships and semi-submersibles. All mobile

offshore rigs float when moving from one location to the next, but these vessels are

labeled floating rigs because they remain buoyant while the well is drilled.

• Drillships

Drillships are the most mobile drilling units because they are shaped like ships and can

easily and rapidly move under their own power. This type of rig can operate in remote,

deep waters. A walled hole in the middle of the ship, called a ―moon pool,‖ is open to

the water’s surface so that the drill bit and other equipment can be lowered to the

seafloor. The rig holds its position over the top of a well either by being moored (using

wire or chain attached to anchors or piles in the seafloor) or by thrusters (directional

propellers mounted in the bottom of the ship’s hull) that counteract the forces of wind,

waves and ocean currents. Drillships are suitable for deep water and far miles offshore

areas and generally they can drill in water depths up to 12000 feet (3700 meters).

• Semi-Submersibles Rig

A semi-submersible rig consists of a platform on top of columns, which are connected

to pontoons. These pontoons can be partially filled with water, or ballasted, so that the

lower portion is submerged. This helps to stabilize the ―semi,‖ which is held in position

by huge anchors, allowing it to operate in ocean conditions that may be too challenging

for drillships. Because it does not sit directly on the seafloor, a semi can drill in deeper

waters than bottom-supported rigs. Once the drilling is complete, water is pumped from

the hull to re-float the vessel so that it can be self-propelled or towed away. Normally,

semi-submersible rig can be used in water depth ranging from 200 to 10,000 feet (60 to

3000 meters)

2.3.4.2 Bottom-Supported Rigs

There are two main types of bottom-supported rigs they are submersibles rigs and jack-

up rigs.

• Submersible Rigs

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Fully submersible rigs operate much like semis, except that they rest on the bottom and

are most suitable for shallow water. Some submerge the hull completely so that it rests

on the bottom with the main deck supported above the surface on rigid columns.

• Jack-up Rigs

Jack-ups rigs are floated out to the drilling area and have ―legs‖ lowered down to the

seafloor. Sometimes the legs are filled with water for extra stability so they can work in

open-ocean areas. Jack-ups can drill in slightly deeper water than submersibles and are

very portable. When its job is done, the legs are raised up out of the water so that the

rig once again becomes a floating barge that can be towed away or placed upon a large

transport ship. Jack-up rigs are typically used to drilled in water depths up to 450 feet

(140 meters).

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Chapter 3

Appraisal and Conceptual Development Plan

3.1 Appraisal Drilling

After drilling exploration wells and hydrocarbon accumulation is discovered, the

reserves need to be appraised to outline the reservoir and evaluate its potential

production. This appraisal stage essentially involves to carrying out the following tasks

iteratively:

• Mapping (making a more accurate evaluation of the size and position)

of reservoirs by mean of the seismic data and the data acquired from the

exploration drillings

• Reservoir Simulation

• Drilling Additional wells

The main objective of the appraisal phase is to acquire sufficient information at

minimum cost in making decision whether the development of a field is economically

viable or not. After implementing this phase the following information should have

been acquired.

a. Both the volume and nature of the hydrocarbon of the reservoir should be

calculated. It is important to know the OHIP, original hydrocarbon in place and

its type, oil or gas or gas condensate. Flow assurance is one of the most

important parameters in upstream development so that chemical composition of

the hydrocarbons in the reservoir should be identified.

b. Reservoir characteristics such as lithology, porosity, permeability and water

saturation and structure such as anticline or fault of the reservoir should be

known.

c. Drive mechanism of the reservoir, such as aquifer, gas cap drive, depletion

drive or combination drive, is most prominent factor effecting the recovery

factor of the formation.

d. Probable producing rate of the development wells should be guessed.

The appraisal stage is a period of high economic risk. On the other hand, a detailed

appraisal program needs to be drawn and targeted studies should be conducted so that

sufficient information will obtain to make the right decision. And it is important to

know when to stop this phase to avoid losses and abandon the program entirely, or to

proceed the field development and produce hydrocarbon as quickly as possible in order

to ensure the project profitable.

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When the field has been delineated, data are available on the following parameters:

The thickness of the reservoir and its porosity at the location of the wells

Oil and gas saturation rates

The composition of the effluent and

The reservoir pressure.

Many important investigations have to do to justify whether the field is commercial or

not and to decide when it should be developed and what kind of development plan

should be adopted. The understanding of reservoir engineering and the interplay of

geology, geophysics is very helpful in this case. The total recoverable resources will

depend on how recovery is to be affected: the production rate, the drainage methods

adopted, the number and positioning of the wells, etc. The overall economic context

(prices, taxes, etc.) and the circumstances of the company itself (financial resources)

are of course also relevant. These circumstances are subject to change.

For this reason the results from the exploration and appraisal stages and other sources

are studied by multidisciplinary teams comprising geologists, geophysicists, petroleum

architects, drillers, producers and reservoir engineers. They also take account of the

thinking of economists and financiers. These teams build up a detailed picture of the

size of the reservoir, its characteristics and of the resources present. This allows various

development scenarios to be considered and tested with the help of simulation models

and their value in economic terms evaluated.

These innovations have permitted to progressively extend the search for oil. Today

even difficult areas like the Arctic Sea are explored for oil. Another example is the

deep water drilling in the Gulf of Mexico.

3.2 Conceptual Development Plan

During the appraisal stage, conceptual development proposals are formulated in very

broad terms to be refined later and cast formally into firm development plans. They

must take into account the reservoir data, and predicted behavior as well as factors such

as location and environment (meteorological and oceanographic data).

The primary objectives of this phase are to estimate hydrocarbon volume in the

reservoirs to assess recoverable reserves, and to prioritize development based upon the

value of the various resource classes in the area to be developed. This process try to

classify whether the interested reservoir has enough business opportunity of

hydrocarbon bearing or not and so that can avoid excessive investment on poorly

conceived plan. First steps may be to delineate the extent of the reservoir, to estimate

the original hydrocarbon volume in place considering the depth of the resource (or

depths if there are multiple horizons), and to provide a preliminary analysis on the fluid

characteristics. Identifying both the viscosity (cP/Pa.s) and gravity (API) provides

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important input for selection of production methodologies as well as hydrocarbon

value.

3.2.1 Subsurface Studies

Following the basic target selection processes, a more thorough reservoir evaluation is

undertaken. The aim is to determine the potential recovery rate of a target reservoir.

This involves a first, significant data acquisition to provide a preliminary economic

valuation. The inputs would include more detailed rock and fluid property analysis and

a geologic model. These can be integrated to provide a full reservoir model, from

which possible recovery mechanisms are identified and predicted recovery rates

determined.

The nature of the reservoir being developed is vitally important in setting development

strategy. Understanding of the nature of the reservoir requires knowledge of the

geology, geophysics, rock, reservoir fluid properties and drive mechanisms.

3.2.1.1 Geophysics

Seismics

The interpretation of the development plan is based on the 2-D and 3-D seismic data

and data obtained from the exploration wells previously drilled. The synthetic

seismograms should be computed using both sonic and density logs. The VSP traces

and synthetic seismograms were then visually character matched to the surface seismic

data to give the final well to seismic correlations. Some data manipulation must be

done whether the seismic data provided a higher level of confidence in the structural

interpretation or not.

Structural Configuration

The structural configuration of the reservoir should be examined. A reservoir is

intrinsically deterministic. It has potentially measurable, deterministic properties and

features at all scales and it is the end product of many complex processes that occurred

over millions of years. Reservoir description is a combination of observations (the

deterministic component), educated aiming (geology, sedimentology, and the

depositional environment) and formalized guessing (the stochastic component).

3.2.1.2 Geology

The following geological reservoir parameters should be examined carefully for they

can impact OHIP, recovery factor and the remaining reserves.

• Structure

• Derive mechanism (depletion, gas-cap, aquifer, combination etc.)

• Vertical permeability across shale barrier

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• Sealing and reservoir compartmentalization

• Net pay thickness

• Relative permeability

• Reservoir fluid properties (gravity (API), viscosity, impurity composition etc.)

Diagenesis

Conventional core and sidewall core and cutting sample should be examined to

determine it diagenetic process could have created differences in formation

petrophysical attributes above and below the fluid contact which might form a barrier

to flow from aquifer (if the reservoir drive mechanism is aquifer drive). Diagenetic

process can change the original composition of the sediments and so that the porosity

and permeability of the reservoir should be emphasized.

Geochemical

Various geochemical analyses should be performed to help evaluate the vertical and

lateral continuity of the reservoir sand between the wells. Heterogeneity might be a key

challenge in developing heavy oil reservoirs for reservoir fluids can change

significantly over very short distances – both laterally and vertically. Geochemical

characterization can help reducing uncertainty of type of oil probably be encountered

during a new well drilling. Moreover, geochemical characterization can help to place

wells optimally for maximum productivity.

Stratigraphy

Sequence stratigraphy is used to establish chrono and litho-stratigraphic correlations in

different wells. The purpose of this investigation is to establish a stratigraphic frame

work which could be used for initial reservoir simulation of the field.

Geologic Model

The structural and sequence stratigraphic analyses determine general reservoir

architecture while the sedimentologic characterization control the distribution of

petrophysical properties. Geologic model should be developed to identify the depth of

the layer of reservoirs and to define whether the fluid contact (oil/water or gas/water

contact) is.

Before developing a field complete reservoir characterization can supply better Full

reservoir characterization, including geochemistry, prior to field development can

provide a better indication of the reservoir fluids and the most effective steam, solvent,

or other potential production method. Solvents can be used alone or as part of an

alternating steam/solvent cycle. Injecting an unsuitable solvent, or rushing steam

assisted gravity drainage (SAGD) operations, can kill a well. Geochemical pre-

characterization can aid the selection of appropriate solvents.

15

3.2.2 Formation Parameter

3.2.2.1 Petrophysical Interpretation

Quantitative log analysis should be performed by using various logs taken such as

density, neutron, sonic, focused resistivity, micro-sensitivity, natural and spectral

gamma ray and borehole televiewer to determine the shale volume, porosity and water

saturation of the formation. Shale volume can be calculated from environmentally

corrected gamma ray with a curved relationship, calibrated with Fourier transform

infrared spectrometry (FTIR) data from the exploration wells, between gamma ray

index and shale volume. Porosity can be calculated by cross-plotting shale and

hydrocarbon corrected neutron and density logs. And then water saturation should be

estimated by using Archie’s equation and Indonesian equation.

3.2.2.2 Fluid Contact

Oil/water contact or gas/water contact can be estimated based on pressure/depth

profiles from FMT and DST tests and visual inspection of effective water saturation

and resistivity curves.

3.2.3 Reservoir Fluid Parameters

3.2.3.1 PVT Analysis

PVT analysis examines the reservoir fluid parameter in a laboratory under different

temperatures, pressures and volumes determining the characteristics and behavior of

the fluid. It can help in determining compressibility factors (Z), viscosity factors of the

fluids and the formation volume factor (B).

3.2.3.2 Reservoir Fluid Analysis

The results from the recombined compositions of various well tests must be

incorporated into a design composition it can be used to determine hydrocarbon liquid

yields at varying surface operating conditions in the design of the surface separation

facilities.

Flow assurance should be deeply emphasized because it can be a very problematic one

in facilities design for hydrocarbon production. Flow Assurance is the engineering and

science of predicting and managing production behavior as it moves from a reservoir to

market through the changing environment of the production system. It means that

ensuring produced hydrocarbons flow from the reservoirs to the market place. It

includes all aspects of the production system and incorporates topics such as:

• Thermo-hydraulic Analysis encompasses all pressure and temperature related

aspects of flow behavior. This will include pressure loss or gain calculations for

applications such as deliverability optimization and pipeline sizing. It will also

include calculations of heat loss or gain that consider the pipeline surroundings,

thermal insulation, and active heating of pipelines.

16

• Operability is how the system reacts to changes in operating conditions. An

operability study might address concerns associated with terrain slugging or

slugs generated by pigging operations and the sizing of slug catchers required

by such operations. Thermal effects of start-up and shut-down operations or

limiting flow rates associated with a variety of operating conditions.

• Blockages is the result of deposition of hydrates, wax, asphaltenes, elemental

sulphur, sand, or other produced solids. The formation of such deposits is a

function of the operating conditions in the production system.

• PVT and Rheology classifies the properties of the fluids flowing in the system.

The phase behavior and physical properties of the fluids will significantly

impact on production operations. For the viscosity of produced fluids from

more conventional hydrocarbon-water mixtures to less common fluids such as

stable emulsions and foam will have a significant impact on the frictional

pressure losses in the system.

• Mechanical Integrity is the impact of corrosion and erosion on the physical

materials (e.g. steel) that make up the system. The nature of both the fluids in

the system and the manner in which they flow can influence on the corrosion

and erosion affecting the inside of the pipes

• Mitigation efforts is the nature of the flow in the pipe are influenced by the

chemical inhibition, operational procedures, or choking.

3.2.4 Reserves

3.2.4.1 Hydrocarbon Volume in Place

The most important parameter in oil and gas field development is the original

hydrocarbon volume in place and the recoverable reserve for development facilities

mainly depend on it. OHIP can be calculated from the following properties of the

reservoir determined by creating computer grids of them.

Reservoir layer structural top

Reservoir layer thickness above fluid contact

Average layer effective porosity and

Average layer initial hydrocarbon saturation.

3.2.4.2 Production Profiles

According to the recoverable reserves, production profile must be clearly identified.

Conceptual planning intended toward production should be conducted while the

development plan prepared in the previous stages is being revised. It is important to

have sufficient tolerance in the initial stages, because the development conditions and

17

other factors in these stages have not been fully understood yet. However, too much

wider tolerance leads to increase the higher initial costs than required. Moreover, it is

also important to study the environmental impacts in the greater interests of global

environmental conservation.

For a gas field, production profile will also depend on the current gas sale agreement.

Nowadays, many reservoir simulation softwares are available to determine recovery

efficiencies (ER) and can generate predicted production profile. Production profile is

important because it influences in determining the number of wells desired, well

design, and well completion strategy. According to the reserves and production profile,

design life of subsurface and surface facilities is considered.

There are many factors to be considered to choose the production profile and to

determine the number of wells relevant to it. The following necessary factors should be

emphasized in drawing a production profile.

Reservoir size, permeability barriers and the well drainage area

The drive mechanism

Flow capacity of individual well related to the reservoir characteristics, to oil

and/or gas properties, to fluid interface problems, to the drive mechanisms and

artificial lift intended to use.

Local regulations related with depletion rate, maximum flow rate of individual

well or multilayer reservoir production.

Economic factors such as development costs, operating costs, oil and gas price,

petroleum tax.

3.3 Surface and Subsurface Development Options

Various possible development alternatives should be identified and evaluated in order

to ensure that the selected concept represents the optimum solution. All identified

development concepts must be evaluated and screened against technical, consent and

approval acquisition, risk and economic criteria and HSE standard. After that a

recommended conceptual development plan for further study must be identified.

A review and challenge of the options and recommendations shall be undertaken prior

to final selection. To select a proper option a concept selection shall be emphasized on

the followings;

• The design basis data and assumptions used

• Detail of each option considered

• Technical evaluation

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• HSE evaluation

• Schedule and cost (Capex and Opex) evaluations of each option stating percent

accuracy and

• Preliminary risk assessments of each option.

3.4 Market evaluation

To determine the value of the hydrocarbons, crude oil or gas, in the marketplace,

downstream specialists should have been brought into the process. They use a full

hydrocarbon assay to better understand the processing needs, and they can decide the

options that would deliver the highest value per barrel. These would include selling the

―raw‖ crude or upgraded crude, and the costs versus value associated with processing

and transportation. Various economic and production variables and risks also need to

be factored into the analysis.

3.5 Project evaluation

At this point, a pilot study is designed and executed to thoroughly test the selected

production methodology from the sandface to the point of sale. This would include

various components of the design, such as engineering, both well and facilities

construction—according to the recovery methods selected and the transportation

requirements and limitations—as well as completions and artificial lift. There would

also be some element included for production monitoring. This phase is lengthy, as

concepts are being tested and proven or adjusted. The pilot well construction,

operation, and evaluation phase can take up to 10 years in some cases, depending on

the necessary infrastructure required, and it may continue to run concurrently with full-

scale commercial operations.

3.6 Economic Analysis

Economic analysis plays a key role in all phases of the life of a joint venture, from the

initial establishment of the venture to the final abandonment of facilities and the

winding up of the venture. During the joint venture lifetime the price of oil and gas will

vary, the understanding of the reservoirs and appropriate technologies will change,

government will change taxation and royalty arrangements and participation

arrangements may be introduced. Each change will require to be assessed to ensure that

the changed circumstances do not cause one or more of the joint venture partners to be

unable to meet their liabilities to the others.

In the early exploration and appraisal phases, exploration may proceed when the

economic analysis yields a positive value for the proposed well. Based on seismic data,

an estimate is made of the expected net income to be received from the prospect

assuming it is commercially viable. Both probabilistic and deterministic approaches

should be used to reduce the uncertainty range.

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The expected income stream is normally discounted at the firm’s cost of capital to

provide an estimate of its worth at the date of the calculation, Net Present Value.

The cost of capital can often be regarded as the weighted cost of equity and debt used

by the firm. The Net Present Value (NPV) is then compared with the anticipated cost of

exploration and appraisal (E) after the NPV is weighted by the probability of

exploration success (P). The Expected Monetary Value (EMV) is the difference of

P(NPV)-E.

The following forecast profiles should be included in the key elements of a field

economic study at the exploration and appraisal stages.

Production

Costs over time

- Development cost

- Operating cost

- Transportation cost (pipeline to shore terminal or tanker loading)

Oil and gas prices

Inflation rates

Exchange rates

The analysis should also include the effect of existing fiscal arrangements making due

allowance for the possible range of alternatives.

A typical capital investment project evaluation requires input variables such as future

product prices, production forecast over the economic life of the project, initial capital

expenditure and ongoing operating expenditures, useful lifetime of facilities, salvage

value at the end of the economic life of the project, and interest rates. The uncertainty

of some of the variables may be very detrimental to the profitability of the investment

as compared to the others. In oil and gas industry, the following analyses are used:

a. Sensitivity Analysis

Sensitivity analysis is a technique in which how much the profitability of a

project will change in response to a given random change in an input variable.

The most likely input values are used in the first stage of analysis stating from

base case situation. A specific percentage above and below the expected value

and profitability calculated change each variable at a time.

b. Scenario analysis

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It is a technique to consider the sensitivity of profitability of the investment to

changes in key variables and the range of likely variable values. In scenario

analysis, a bad set of circumstances (such as lower production, less ultimate

recovery, lower price, high operating cost, higher capital cost, and so on), an

average set, and a good or optimistic set are picked. The investment’s

profitability at these three conditions are then calculated and compared. The

worst-case scenario, most likely scenario, and best-case scenario refer the bad

set, average set and good set respectively in general.

c. Probability Approach I

The expected value of a decision criterion is used for each alternative and the

preferred course of action based on expected value is determined in probability

approach.

d. Probability Approach II

In this approach, an explicit measure of risk is used in addition to the expected

value.

e. Computer Simulation

Different combinations of uncertain variables are derived from probability

distributions of each variable in computer simulation. The outcome for

effectiveness of the profitability measure is determined for each combination.

Different combinations for each variable are normally tried randomly.

3.7 Risk Allocation

Many oil and gas investments involve a relatively high risk that the investment may not

achieve the desired results. On the other hand, some of these investments may possibly

generate better than the desired results or even a bonanza. Therefore, the investment

decisions have to be based on sound trade-offs between the risk of complete or partial

loss and the potential of significant gains. The nature of oil and gas industry itself,

taking out of volatile substances under extreme pressure in unreceptive environment,

has risk and sometime accidents and tragedies occur. So that it is a big issue to be

considered which party should take the responsibility for risks during the life of a

project. Where there is found to be a risk inherent in any aspect which might have

consequences for the success of the project, the parties will need to agree who will bear

the risk of such consequences. The considerable risks when structuring a decision

analysis problem are;

a) Geological Risks

There is the risk that petroleum reserves on a particular project may ultimately

prove to be recoverable at a far lower level than originally calculated. Dry hole,

bottom hole location, field size and reservoir heterogeneity (pay thickness,

21

permeability variation, porosity variation, faults, fracture, adequate reservoir

pressure, etc.) are related geological risks.

b) Financial Risks

Risks falling under this heading include price volatility, operating expenditure,

capital expenditure overruns, inflation, currency devaluation, taxes, discount

rates, etc.

c) Drilling and Completion Risks

While drilling exploration or appraisal wells blowout and casing collapse can

occur. Extended fishing, plug back and sidetrack and poor cementing resulting

in reservoir cross flow etc. are considerable risks in drilling.

d) Production Risks

Under this heading, risks related with reservoir management, lower than

expected production profile, lower ultimate recovery, water coning, facility

limitation etc. should be considered.

e) Catastrophes

Natural and man-made catastrophes such as blowout, fire, oil spill, chemical

leak, etc. are involved in this topic.

f) Political Risks

The possibility of regulatory intervention, change in tax rates, and

nationalization etc. are important political risks to be considered.

3.8 Feasibility Studies

Oil and gas field development involves huge capital investment and is a vital issue to

be decided, as it rules the future business operations. As such, it is essential to study the

technical and economic viability of the project before making the final decision of

investment. To avoid the risk of excessive work on poorly conceived plans, the

following general feasibility study terms should be studied.

1. Market survey

2. Site location

3. Technologies

4. Infrastructure

5. Environmental conversation

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6. Short specifications of equipment

7. Project schedule

8. Project implementation organization

9. Production plan

10. Necessary funds and financing

11. Financial assessment

12. Economical efficiency assessment

After feasibility studies have done, possible development options must be generated

these alternatives shall be identified and evaluated in order to ensure that the selected

concept represent the optimum solution. All identified concept should be evaluated

against technical, consent and approval acquisition, HSE, risk and economic criteria

and a recommended concept for further study shall be identified.

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Chapter 4

Field Development Plan

Field development plan is a comprehensive document describing the various aspects of

a planned field development. Conceptual development plans are still in fairly broad

terms because detailed design studies are not justified in this stage and so that detail

studies are needed to go to field development plan. There is a further process of

elimination to be done through in more detail from the technical, economical, political

and environmental point of view. Despite the plans in this stage are not detailed, a

sufficient amount of detail must be included to make the technical analysis and costing

realistic.

4.1 Field Description

This section present the description of the field on which the development has been

based and so provide a baseline for future modifications as development proceeds. The

section comprises:The following baseline for development proceedure are :

i. Seismic interpretation and structural configuration

ii. Geological interpretation and reservoir description

iii. Petrophysics and reservoir fluids

iv. Hydrocarbons-in-place

v. Well performance

vi. Reservoir units and modeling approach

vii. Improved recovery techniques

viii. Reservoir development and production technology

4.2 Future Reservoir Characterization

Development wells will help to confirm the structural, stratigraphic and petrophysical

model of the reservoir. Also, by taking selected conventional cores and using special

core analysis, more information on initial and residual hydrocarbon saturation can be

obtained as well as vertical to horizontal permeability rations. The two key elements

which could alter the recoverable reserves are new wells improving the confidence of

the layering the petrophysical properties associated with the layers. Integration of the

well results and with the 3-D seismic data may also assist in improving the confidence

of new hydrocarbons in place and reserve calculations.

24

Production from the field should confirm if the degree of compartmentalization

matches expectations. By monitoring the pressure from the wells the degree of the

drive mechanism support may be better estimated.

4.3 Drilling and Well Completion Plan

The main purpose of development wells is to bring the field on stream, with priority

going to their flow capacity, rather than to make measurements. However, it is also

important to test this type of well to access the condition of the well and check how

effective the completion has been and also to obtain further information about the

reservoir. There are three different types of development wells. They are:

Production wells

Injection wells and

Observation wells.

Production wells are drilled to produce hydrocarbon from the reservoir to the surface.

Injection wells are intended to promote hydrocarbon recovery by injecting water, hot

water, steam or gas. Observation wells are drilled to observe changes in the reservoir

fluid level and pressure changes over a period.

Basis well design should take into account experience from previous wells and the

function requirements for the development wells. Well design evolves over the pre-

production project phases and subsequently over the life of the field, in order to take

advantage of equipment development, new techniques and drilling experience.

Common factors influencing the well completion designs are:

Production fluids

Production rates

Multiple reservoirs

Sand control

Artificial lifting

Safety maintenance and

Cost

There are two main types of well completion. In this stage it is required to decide

which type of completion, open-hole completion (barefoot) or cased-hole completion,

will be utilized in accordance with the reservoir and market condition.

The most common parameter in designing the best possible completion in order to:

25

Optimize productivity or injective performance during the well’s complete

lifetime

Make sure that the field is produced reliably and safety

Optimize the implementation of an artificial lift process

Optimize equipment lifetime

Make it possible to change some or all of the well’s equipment at a later date

without too much difficulty so that it can be adapted to future operating

conditions

Minimize initial investment, operating costs and the cost of any work-over jobs.

To meet the objectives listed above, detail drilling plan and well completion strategy

must be set out in this stage. Drilling plan should cover the followings.

Number of wells in each development

Well spacing

Well pattern

Drilling schedule

Well types (conventional or horizontal)

Well completion methods

Drilling costs.

In this stage, the detailed drilling plan in accord with development phase and

completion methods chosen, with schedule must be involved.

4.4 Facilities Description

Water depth, weather, seafloor conditions, operational safety and efficiency all

determine what kind of vessels or platforms will be used for drilling. There are many

factors to be considered in designing development facilities relating to the environment

of the development area. According to the water depth of the development area,

suitable rig type and capacity must be selected also considering the rig cost and

operating cost. In exploration drilling, the rigs are usually mobile so they can move,

with crew, from one site to another. Some of these moveable rigs are floating units,

such as drillships or partially submerged platforms. Others are bottom-supported, using

legs to stand on the seafloor or hulls that rest on the bottom. How about arctic area?

4.4.1 Offshore Facilities

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4.4.1.1 Platforms

Fixed Platforms which built on concrete and/or steel legs anchored directly to the

seabed, sustaining a deck with space for drilling rigs, production facilities and crew

quarters, by asset of their immobility, planned for very long term use, for example the

Hibernia platform. Steel jacket, concrete caisson, floating steel and concrete are used.

Steel jackets that made of tubular steel members are usually piled into the seabed.

Concrete caisson structures, pioneered by the Condeep concept, often have in-built oil

storage in tanks below the sea surface. These tanks were used as a flotation capability,

allowing them to be built close to shore and then floated to their final position where

they are sunk to the seabed. Fixed platforms are economically viable for installation in

up to 1,700 feet (520 m) depth under sea level.

Compliant Towers are built of narrow, flexible towers. Its conventional deck is

supported by a piled foundation, for drilling and production operations. Compliant

towers are designed to sustain significant lateral deflections and force by. Typical

depths are varying from 1,500 to 3,000 feet (450 to 900 m).

Figure 4.1 Offshore platforms. (source: http://www.google.com: Images for offshore

drilling rigs)

Semi-submersible Platforms are floating buoyant structure build on two giant

pontoons to float. These rigs can be moved freely and can be adjusted it buoyant

structure by changing the amount of water in its buoyancy tanks. During drilling

operation, it can be stabilized by using cable anchors although the steerable thrusters

can be used to keep still in place. Semi-submersible rigs can be operated from 600 to

10,000 feet (180 to 3,000 m) depth.

Jack-up Platforms can be jacked up above the sea, by dint of legs these can be lowered

like jacks. These platforms are intended to move easily one place to another and are

27

designed to drill or work in relatively shallow water. Jack-up platforms can be used in

water depth up to 450 ft (150 m).

Drillships are marine vessels which have been equipped with drilling apparatus. They

are frequently used for exploration drilling wells in deep water and far remote area.

Drillship is built on a modified large tanker hull and equipped with a dynamic

positioning system to retain its position over the well.

Floating production systems are processing facilities equipped on large marine vessel

and can be moored to a location. Three types of floating production system are

Floating, Production, Storage, and Offloading system (FPSO), Floating Storage and

Offloading system (FSO), and Floating Storage Unit (FSU).

Tension-leg Platforms are floating rigs attached to the seabed to eliminate the vertical

movement of the structure. TLPs can be used in water depths up to about 6,000 feet

(2,000 m).

Seastars are kinds of tension-leg platforms and intend to use in water depths from 600

to 3,500 feet (200 and 1,100 meters). Sometime they are used as satellite production

platform for giant deepwater fields.

Spar Platforms can be moored like tension-leg platform to the seabed but spar use

conventional mooring line system. There are three main types of spar. Conventional

spar is made of one piece big cylindrical hull. Truss spar is composed of upper hard

buoyant tank and lower soft tank connected by truss elements. Cell spar is built by

combining several vertical cylinders. Spar are much cheaper than TLP but has more

stability because of its counterweight at the bottom conventional mooring system. Spur

platforms can be used in deep and ultra-deep water area.

4.4.1.2 Processing Facilities

Crude oil from the reservoir usually consists of a mixture of hydrocarbons having

varying molecular weights and differing from one another in structure and properties.

These various impurities need to be separated before transporting to the sale point.

The natural gas produced from the well contain many impurities such as H2S, Nitrogen,

CO2 etc. and these contaminants must be processed before delivering to the mainline

transportation system. Natural gas without processed that is not within certain specific

gravities, pressures, Calorific value (Btu) content range, or water content levels will

cause operational problems, pipeline deterioration, or can even cause pipeline rupture.

According to the field’s location, environmental and reserves conditions, relevant

processing facilities must be developed. For example, for a far miles remote gas field,

it might be technically feasible to install a pipeline system but economically not viable.

In this situation, FLNG system may be much cheaper than pipeline transportation

system and should be consider as an alternative. But there may have some

technological challenges to handle high pressure tankers and to have sound market.

28

Figure 4.2 Floating liquefied natural gas facilities. (source: http://www.google.com:

Images for FLNG)

4.4.2 Export facilities

The common facilities for offshore oil and gas transportation are pipelines and shuttle

tankers. There may be two categories in export facilities;

• Offshore export facilities and

• Onshore export facilities.

In offshore export facilities, according to the development plan, the following facilities

are used.

• Offshore export pipeline (mainline)

• FSO

• Offshore transport line (to FSO or storage facility)

• PLEM

• Cargo tanker

In onshore transport section, detailed of the following facilities should be involved.

• Landfall region (block valve station)

29

• Dock location

• Pipeline operations center (pressure reduction, pigging facilities, and

maintenance) and

• Metering station (metering and gas filtration)

It is vitally important for the production processing system and export facilities to have

sufficient flexibility for the further reservoir improvement and enhance recovery

process.

4.5 Health, Safety and Environment

HSE issues must be adequately identified in a timely manner at an early stage in the

project life cycle and effectively managed to avoid increased risk of adverse schedule

and cost impacts to the project as well as increased probability of operational accidents

and incidents, which could have a severe adverse impact on business.

Every project shall prepare and implement a Health, safety and Environment

Management Plan that shall demonstrate how HSE aspects will be managed on the

project in order to meet the requirements.

The HSE Plan shall be initiated at the concept selection stage and developed prior to

both Basic Engineering and project sanction. All pre-sanction design activities shall

include consideration of HSE issues. No project development, execution or activities

shall commence until an approved HSE plan is in place.

A series of goals shall be developed for the project and shall be listed here. They

should include requirements for, for example:

• Meeting or exceeding all international, national and company HSE standards in

both design and construction of the facilities

• Identifying and obtaining all HSE related permits, consents and approvals in a

timely manner

• Achieving HSE related risk levels which are as low as reasonably practicable

(ALARP), and satisfy ―Best Available Technology Not Entailing Excessive

Cost‖ (BATNEEC) criteria, and which compare favourably with industry

benchmarks by: - Identifying all SSHE design and operational hazards

- As far as reasonably practicable, designing them out

- Putting in place hardware, systems and procedures to reduce the residual

risk to ALARP levels

• Including HSE performance/capability in contractor selection

30

• Ensuring that all contractors and suppliers have acceptable HSE Plans in place

before commencing any project activities

• Incorporating HSE performance incentives into project contracts (where

Conducting an agreed number of HSE independent reviews/audits of both the

PMT and contractors/suppliers at critical points in the project schedule (e.g. end

of concept definition, FEED, etc.)

• Holding regular HSE review meetings and/or workshops involving Project

Management Team and Contractor personnel

• Timely and thorough investigation and feedback of all HSE-related incidents,

plus implementation of lessons learned

• Developing the project Safety Case and Environmental Impact Assessment

• Developing a full lifecycle HSE Management System

• Ensuring that HSE is never compromised by schedule and commercial

pressures

• Achieving safe and environmentally compliant project construction and

Commissioning Meeting the Project HSE Goals. For each of the listed goals, a

plan shall be presented to show how the goal will be met, including specific

activities and responsibilities, plus methods of monitoring and reporting. In

particular, due considerations must be given to meeting the varying HSE

resourcing needs throughout the project lifecycle.

4.6 Decommissioning and Abandonment

Decommissioning is the process for the removal of the old or unused platform after the

service life for navigation point. When many of the oil and gas installations are

reaching the end of their economic production life, and proposals for decommissioning

of them need to be prepared by the operators. After reaching the end of their production

life of oil and gas installations, the operators must prepared the proposal for

decommissioning.

The activities for abandonment and decommissioning are as follow:

• Killing and plugging of wells

• Depressurization and purging of process facilities

• Dismantling and removal of topside equipments

• Dismantling and removal of all support structures including module support

frames and jackets

31

• Clearance and inspection of the sea bed and

• The flushing, sealing and burying of pipelines or the removal of the pipelines.

The national and international regulations since forty years ago were needed to be

revised due to extremely high cost of decommissioning and removal off offshore

installations led. For example, the Convention on the Continental Shelf (Geneva,

1958) and the United Nations Convention on the Law of the Sea (Montego Bay,

1982) for removal of abandoned offshore installations totally.

The immediate and total removal of offshore structures mainly platforms must be

weighing up to 4,000 tons in the areas with less than 75 m depth and after 1998

change to less than 100 m depth. The upper parts from 55 m depth below surface

water must be removed and only structure in deeper water is allowed to remain in

place. After removing of the fragments, they must be transport to shore or buried in

the sea. The secondary use of abandoned offshore platforms can be possible for

other purposes.

Figure 4.3 Decommissioning Options

4.6.1 Secondary use of offshore fixed platforms

Decommissioning

Removal Leave in place

Complete Partial Toppling

Removed

Portions Removed

Portions

Residue

on Seabed

Reuse Inshore

Alternative

Use

Scrap Deep water

Dump Site

32

The reuse for abandoned platforms can be utilized in some purpose. Dokken, 1993;

Gardner, Wiebe, 1993 studied about an analysis of scientific potential of research

stations permanently based on abandoned oil platforms in the Gulf of Mexico. The

regulation of the marine populations and coral reproduction, making underwater

observations, monitoring the sea level, and collecting oceanographic and

meteorological information within the framework of international projects were

studied. Rowe ( 1993 ) mention that transformation of abandoned platforms into places

for power generation using wind/wave and thermal energy should be considered. Side

(1992) suggested that platforms could be utilized as bases for search and rescue

operations or centers for waste processing and disposal.

From the point of view of fisheries, the project has aim to convert the marine structures

into artificial reefs. Artificial reefs were widely and effectively used on the shelves of

many countries to provide additional habitats for marine life.

The offshore structures can attract many species. In particular, observations in the Gulf

of Mexico discovered a strong positive correlation between the amount of oil platforms

and commercial fish catches in the region. Positive impact of offshore oil and gas

developments on the fish populations and stock are occurred.

Environmental, health and safety issues need to be considered in the operation. Health

risks can cause usage of asbestos, dust from scale which normally present in the oil

reservoir. Handling of Waste materials should be careful and controlled. Concrete and

other non-recyclable materials such as wood, plastic and glass can be disposed in

landfill site. Incinerating can be done for oily residues and sludge.

4.7 Economics Evaluation

When the plans have been examined from all points of view, only a few will remain.

These are technically feasible plans which will now have to stand up to economic

evaluation. For this purpose the elements of the plan must be costed and the phasing of

expenditure and income determined. Cost must be broken down into capital and

revenue items and factors such as taxes and royalties taken into account.

The plan must be evaluated according to some common yardstick for the purpose of

comparison. Several ways are available such as Net Present Value (NPV) and Internal

Rate of Return (IRR). Normally, deterministic approach is used in the development

phase. It is vital that the economic assessment should consider the effect of possible

price changes, both facilities and products, and inflation in so far as these are

predictable.

It is important to develop an economic model in which the contractor and government

cash flow should be clearly examined. The details of cost and revenue must be clearly

identified and cost schedule must be provided together. Capital expenditure (Capex)

and Operational Expenditure (Opex) should be divided into:

- Pre-project costs (Seismic, Exploration Drilling, Appraisal Drilling, Studies and

Simulations in Money of the day)

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- Drilling Capex.

- Facilities Capex.

- Abandonment Expenditure.

- Field Opex, excluding tariffs.

- Tariff Opex.

- Details are required of the tariffing arrangements and gas agreements where

applicable.

Once the economic evaluations have been completed it is possible to rank the plans in

order of economic merit. The final ranking, however, may not be the same because of

non quantifiable factors which may be political or environmental, or even technical

risk. The ranking may well be subjective and calls for sound judgement and

experiences.

By the time that the development options have been ranked they will have been subject

to repeated scrutiny. Each review will contribute more information, better data, or more

precise ideas.

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Chapter 5

Engineering and Construction

Engineering and Design work is usually the first thing and the major activity for the

realization of an industrial facility and it is often the case that engineering is conducted

in a number of phases. Engineering and design may start with a Feasibility Study prior

to materialization of the project, followed by Basic Design, Front End Engineering

Design (FEED) and Detailed Design.

5.1 Basic Design

In the Basic Design phase, the process design employed for the facility and the various

basic concepts of the plant design are defined. In some cases, the Licensor (a

technology owner) undertakes a major role in this phase. Engineers will study the

material and heat balances, and define major equipments, control systems and

instrumentation for all parts of the process. This determines the basic functions of the

elements and provides the spatial requirements for the facility.

5.2 Front End Engineering Design

Following the basic process design, the FEED phase includes sizing of the major

components and layout design. The basic design of major components and layout may

be fed back to the process design to optimize functional requirements further refine the

skeleton and layout of the facilities. Basic design continues with mechanical

equipment, control and electrical systems; quotations may be obtained from vendors

for critical items during the FEED phase. Piping and civil engineers contribute to

develop the overall layout and define the outline of the necessary buildings, structures,

roads and other elements as required.

5.3 Detailed Design

During the Detailed Design phase, engineers will prepare a significant number of

construction drawings including foundation, steel frame, construction drawings for

electrical equipment, instrumentation and piping are prepared. These construction

drawings are prepared incorporating detailed information obtained from suppliers for

mechanical equipment, instruments, electrical and other equipment to be included in

the facility. Offshore oil and gas industries use a number of standards developed by

industry organizations. In order to standardize, international standards such as ISO

TC67, API, ISO or IEC standard are recommended to use.

In attached with detailed design the exact plan for procurement, fabrication and

construction, installation and hook-up and commissioning must be provided. The

detailed operation plan, cost estimation and time schedule for all engineering work

must be properly prepared. In this stage the accuracy for cost estimation should be

higher enough as much as possible.

5.3.1 Transport and facilities construction

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In the case of heavy oil production, there is always a requirement for the traditional

facilities. For thermal production techniques there are significant additional facilities

and processes needed for water handling and/or steam generation and transportation.

Also, thermal processes may create emulsions and sand issues that require more

extensive handling.

If heavy crude oil transport has to be provided by the producer then this will include

special pipeline construction with either heating or blending facilities. Sometimes

heavy oil projects require upgrading of the crude on site, or at some intermediate site,

before final delivery to a refinery. This will require full process engineering.

Commissioning the various facilities and recruiting and training staff to maintain

production levels while meeting safety and environmental standards will help ensure

consistent product quality throughout the operation. This is an essential part of

fulfilling sales contracts and generating revenues for the project. If contracts change,

then changes to the process will need to be implemented.

5.4 Operating Plan

In this stage the following activities need to be conducted and relevant document

reports should be delivered.

Hydrocarbon production

Benchmarking of produced hydrocarbon

Update reservoir management

Operation technical review

HSE evaluation

Risk management.

5.4.1 Operational optimization

The aim of oil and gas industry is to ensure a long term optimum production rate to

maximize the asset Net Present Value (NPV). To help ensure this, production processes

need to be refined, and systems which may include elements of remediation are

required to monitor, analyze and optimize injector and producer wells.

A significant part of the operation is to manage the production and recovery of oil from

the field. As wells are shut in, new wells have to be planned and drilled to maintain

production to planned levels. There is an ongoing process to fine-tune the

understanding of the reservoir and the production paradigm to enable an optimum

reservoir strategy to be executed.

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Ongoing operational optimization is only possible if there are adequate systems of data

management. These systems deliver information that enables accurate history matching

to update both the geologic and reservoir model and maintain planned production.

5.4.2 Project Evaluation

As part of the continuous process improvements, regular project auditing and reviews

are carried out. Performance improvement plans are implemented, if needed, through

systems of change management, and the balance between operational expenditures

versus returns is subsequently improved to ensure product value is optimized.

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Chapter 6

Conclusion

Oil and gas industry face with increasingly complex challenges in the exploration and

development of energy resources. Successful execution must consider many variables

such as technical, financial, environmental, regulatory, logistical and cultural.

In oil and gas development planning, normally decisions are made according to the

facilities at in which phase, facility capacities requirement, number of wells, locations

and completion method and drilling schedule. Before making decisions, Down-side

Risk and Up-side Potential (minimum and maximum recoverable reserves) and

variation in price (Capex and Opex) need to be considered.

Many kinds of uncertainties can be faced in making decision for oil and gas field

development planning. For example, geological uncertainties such as hydrocarbon

generation, Reservoir Seal, Reservoir Rock properties, Migration Path, Reservoir Trap,

Type of Hydrocarbon, OHIP, Reservoir Fluid Properties, Reservoir Drive Mechanism:

Engineering Uncertainties such as Performance of the well, Recovery Factor, Facilities

Design, Project Execution Start-up, Commercial Uncertainties, Political Uncertainties,

Market Uncertainties, Capital Expenditures, Operational Expenditures.

In conclusion, development strategy focuses on deriving the maximum profit from

available data sets and information ensuring adequate economic return and safety for

personnel, environment and reservoir avoiding uneconomic development.

Development strategy emphasizes to reduce uncertainties and its influence while trying

to optimize future opportunities.

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References

[1] Wilkinson, J. (1997): Introduction to Oil and Gas Joint Ventures. OPL

[2] Perrin, D. (1995): Well Completion and Servicing- Oil and Gas Development

Techniques. Editions Technip

[3] Gray, F. (1995): Petroleum Production in Nontechnical Language. PennWell

Books, Tulsa, Oklahoma

[4] Editions TECHNIP (2007): Oil and Gas Exploration and Production: Reserves,

costs, contracts. IFP Publications

[5] PTTEP (2010): PREP Management Standards- PREP-SD-01 Revision No:0

[6] PTTEP (2010): Project Realization Process- PREP-QM-01

[7] Mian, M.A. (2002): Project Economics and Decision analysis. Vol. I and II,

PennWell.

[8] Nguyen Ngoc Hoan (2004): Offshore Field Development Option and Strategy.

Proceeding of The 3rd

workshop of PPM Philippines case study,Baguio City.

[9] Mian, M.A. (2010).Designing Efficient Fiscal Systems.Society of Petroleum Engineers

SPE 130127.