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.
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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.
19
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:
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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
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• 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
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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
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