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Dedication

This paper is dedicated to my amazing parents, Lombe Koama Bwalya and Prisca Musandi

Bwalya, who through thick and thin have showered me with love, encouragement and praise

that saw me through even the dark times. You provide your children with the best you have

and we are who we are today thanks to all your hard work and the sacrifices you made and

continue to make for us.

I also dedicate my paper to my crazy siblings, Adrian, Danny, Ray, Natasha, little Blessings

and my cousin Ruth. I cannot even begin to imagine what life would be like without you!

I love you all.

Acknowledgements

Firstly, I express a token of gratitude to my educational supervisor Mr Djlassi Fadhel who

has worked tirelessly helping all his students complete their work to the best of their ability

despite the time constraint. Your commitment, efforts, advice, just to mention a few is highly

esteemed.

I am truly grateful to my professional supervisor Ms Ben Ali Selma, BG Tunisia’s Lead

economics analyst, who even under a tight schedule was not only patient with teaching but

also committed to helping me complete my work. Many thanks to Mr Dhouib Mohamed,

BG’s finance manager whose support, time and advice I highly appreciate.

I thank the entire economics, finance and HR department, and all BG stuff at large, for

providing a friendly yet professional working environment that helped me easily integrate

during the few months I spent with them. In addition, I would like to express appreciation to

my family, including the one I made while studying in Tunisia, my friends and my church St

George’s. Many thanks to Talent Manyani, as well as everyone that has been a source of

support and encouragement. Finally and most important, I thank the Lord Yahweh, to whom I

owe it all to for each one of you.

General introduction

In the 21st century, nearly everything runs on petroleum and natural gas. These are arguably

the two widely used sources of energy around the world. These two sources are used to

provide electricity and heating for both the domestic and industrial sectors of the economy.

Furthermore, they are used as fuels for vehicles and other modes of transportation, equally

used industrially in the production of various chemicals such as in the manufacturing of

ammonia. The fact that these products are such a big part of our lives makes the demand for

oil and gas high and in turn, oil and gas companies have the task of meeting this demand. To

this end, oil and gas companies decide from time to time to service and repair their wells in

order to boost production. These services are usually referred to as work overs or more

generally, well interventions. Thus, oil and gas companies are in the business of drilling more

and more wells, and in turn are faced with the decision to renovate or strengthen existing

wells to satisfy the ever growing international demand. Additionally, companies may resort to

drilling new wells, though this is also viable, the main focus of this project is on reparations or

uplifts done on already known productive wells with the objective of accelerating production.

Well interventions could be performed on a scheduled maintenance basis or in the case of

unexpected equipment failure. They are also executed during the period of decline in

production, in the lifecycle of the well. The decline phase in the life cycle of a well is the

period of gradual decrease in the level of production, possibly leading to low-profitable

operations or in its worst case scenario, generating losses. Interventions or more specifically

work overs, are performed in order to accelerate and optimize the well’s production, and in

some cases extend the productive life of an oil or gas well. In short, the main objective of a

well intervention is to stimulate and enhance production. However, it is safe to say that work

overs usually do not increase profits, but in fact, accelerate production, that is to say, increase

production in the earlier years. It is via this acceleration of production that profits are gained,

taking into account the time value of money concept. By investing in well interventions,

companies can extend and optimize production.

Accordingly, this project focuses mainly on evaluating work overs, looking at the financial

analyses that are carried out to decide on the possibility and profitability of a work over.

These work overs are costly interventions and before a company decides to execute a work

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over, a number of analyses have to be done to determine whether it would generate the desired

changes in production or not.

However, these operations are not without compelling cost implications and technical

challenges. These uncertainties range from investing in a well that has less reserves than

estimated, additionally price volatility, high interest rates coupled with poor planning can

cause a work over to be unprofitably. Given all the risks and uncertainties associated with

work overs, the following central question may be asked: how does a company decide which

intervention projects to execute?

In order to get to the bottom of things, we break down this central question into subsidiaries

questions:

What steps are taken in the decision making process?

How does a company deal with the financial risks and economic uncertainties that are

associated with executing well intervention?

This project has been granted three objectives. The first one is to highlight the technical

complexities associated with well interventions. The second is to have a look at the economic

analysis of well interventions, focusing our attention on the procedure and economic

indicators used in the decision making. And finally, the last objective consists on carrying out

two case studies based on existing BG Tunisia projects, to bring to light the entire theoretic

framework that this paper will establish in the first and second chapters including the first

section in chapter three.

To answer the questions mentioned above, we organize our work in three chapters. The first

chapter gives a brief introduction to the oil industry and a few basic facts about petroleum and

natural gas. It additionally sheds light on BG Tunisia which is the company in which I did my

internship under the economics and finance department. The second chapter deals with well

interventions and the various risks and uncertainties associated with them. Finally, the third

chapter focuses on the economic evaluation process that helps analysts decide which projects

are feasible and justify the decision to carry out an intervention

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Chapter 1: Presentation of the Oil and Gas Industry and BG

Chapter 1: Presentation of the oil, gas industry and BG

Introduction

The recent drop in oil prices has stirred up a global concern and left many asking questions

like; what caused it? Is there a solution? And if so then how long will it take to stabilize it? To

date, oil and natural gas have been the major sources of the world energy and the fact that they

are non-renewable leads the world into a search for efficient alternative energy sources such

as nuclear and solar. Until then, oil and gas companies must continue to find ways to increase

production to meet the escalating demand. Hence the continued need to invest in well

intervention projects to enhance production, as well as exploration projects in order to

discover new reserves. This first chapter is divided into three sections; the first is concerned

with the formation of oil and natural gas, the world petroleum reserves as well as how they are

extracted and lastly the life cycle of an oil/gas field. The second section summarizes BG

group PLC and the third section focus on BG Tunisia; its activities and challenges.

Section 1 : Oil, gas: their origins and the current world reserves.

1.Formation and historical perspective of oil and natural gas

Oil and natural gas were formed millions of years ago from the remains of animals and plants

that lived in a marine environment. These decaying remains were compressed in sedimentary

rock over the years and were thus integrated into the forming rock. Exposure to specific

temperature and pressure deep in the earth’s crust, allowed for the eventual transformation of

the organic material into oil and gas. The oil and gas then flows from the source rock and gets

trapped in what is known as a reservoir rock. These reservoirs are simply layers of rock

containing relatively large quantities of oil and gas, hence they are our source of natural gas

and petroleum (rock oil or oil from the earth).Oil and gas are hydrocarbons because they are

compounds of hydrogen and carbon, they vary in color, consistency and composition

depending on the mixture of hydrocarbon molecules for example methane, ethane butane and

propane. The different levels of Hydrogen Sulphate (H2S) in the oil, determine whether the

oil is sweet or sour. Geographical location may also contribute to the differences in oil. In the

early writings of man, oil based products (Bitumen) were recorded to have been used in the

construction of the tower of Babel. Also, in India, Burma: pitch was used for buildings and as

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fuel for lamps while in North America native Indians had been collecting oil for use as a

medicine. (W.I. TEKNIK SDN. BHD, 2015). Today, oil and gas products are used more

broadly in everyday life, for heating and generating electricity, as transportation fuels, in the

production of plastic and synthetic material and a lot more.

2.World oil reserves

Oil reserves are the amount of technically and economically recoverable oil and depending on

their degree of certainty, different classifications of reserves exist.

Oil in place: The total estimated amount of oil in an oil reservoir, including both

producible and non-producible oil. However, due to reservoir characteristics and

limitations in petroleum extraction technologies, only a fraction of this oil can be

brought to the surface. Hence, it is this producible fraction that is considered to be the

reserves.1

Proven reserves: are those reserves claimed to have a reasonable certainty.This

means under existing economic and political conditions, and existing technology, there

is a 90% assurance of production.

Data from OPEC at the beginning of 2013 indicated that Venezuela holds 20% of the worlds

proved oil reserves including non-conventional oil deposits. Saudi Arabia comes in second

with 18%, Canada 13%, and Iran 9%. Other oil reserves in the world include Kuwait, Russia,

USA, Libya and Nigeria.

Figure 1: Top proved world oil reserves, 2014. (In billions of barrels)

1http://en.wikipedia.org/wiki/Petroleum_reservoir

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3.World gas reserves

According to the British petroleum (BP)2, the total world proved reserves of narural gas was

estimated at 185.7 trillion cubic metres (tcm)at the end of the year 2013. These reserves are

the quanitities whose geological and engineering informationindicate with reasonable

ceratinty can be recovered in the future.(BP Global, 2015)

Figure 2: Larges proven natural gas reserves holders countries.

There are disagreements on which country holds the largest proven gas reserves in the world.

BP, however credits Iran with reserves amounting to 33.1 to 33.8tcm making it holder of the

largest natural gas reserves. Russia comes in second place with 32.9tcm (1st place according to

other sources)(BP Global, 2015).

In descending order, Qatar, Turkmenistan, the United states of America, Saudi Arabia. Iraq,

Venezuala, Nigeria and Algeria are among the top ten countries with the highest proved

reserves of natural gas towards the start of 2014(BP Global, 2015).

2http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy/review-by-energy-type/natural-gas/natural-gas-reserves.html

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4.Exploration and extraction

The petroleum industry is divided into two main sectors namely the upstream and

the downstream. The upstream sector encompasses exploration and production (E&P) of the

raw material which involves discovering petroleum reservoirs, drilling wells and extracting

the oil and gas. Once a site is selected by the upstream, the area must be surveyed to

determine boundaries and environmental studies must be carried out to ensure the protection

of the ecosystem. Additionally, in the case of inland sites, the land is cleared to make way for

the rotary rig. The downstream on the other hand simply focuses on refining, processing,

transporting, distributing, and marketing the gas and petroleum products. This sector includes

all oil refineries and petrochemical plants, natural gas and petroleum distribution companies.

5.Oil and gas volume measurements and standard conversion.

It is important to know that oil production is measured in terms of barrels, usually

abbreviated as "bbl," (which is 42 U.S. gallons). Production can be described in terms of bbl

per day or per quarter. Therefore, 1,000 barrels is commonly denoted as "mbbl" and 1 million

barrels is denoted as "mmbbl". In the same way, Gas production is described in terms of

standard cubic feet, (which is a measure of gas quantity at 60 degrees Fahrenheit and 14.65

pounds per square inch of pressure). The term "mmscf" means 1 million cubic feet of gas

(billion cubic feet is denoted as "Bcf").

Additionally, gas production is often measured in units of barrels of oil equivalent (BOE). The

BOE is calculated by converting gas production into oil equivalent production using an

energy-equivalent basis; i.e. one BOE has the energy equivalent of approximately 6,000 cubic

feet of gas (one bbl to 6 mcf). In a similar manner, oil quantity can be converted into gas

quantity and gas producers often refer to production in terms of gas equivalency using the

term "mscf."

6.The life cycle of an oil/gas field

Generally, the processing life cycle of oil/gas fields consists of 5 stages3.(Getches-Wilkinson

Center for Natural Resources, Energy, and the Environment, 2015).

1. Exploration3 http://www.oilandgasbmps.org/resources/development.php

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This stage involves the search for rock formations associated with oil or natural gas deposits.

Surveys are carried out and data is collected, interpreted and analyzed in order to identify the

likelihood of an area containing hydrocarbons.

2. Appraisal

This stage is closely intertwined with the exploration and only takes place after exploration

has located an economically recoverable field. The objective in this phase is to obtain

information about the reservoir in order to make a decision on whether or not to proceed with

the development of the field.

3. Development stage

This stage targets production which is the process of extracting the hydrocarbons and

separating the mixture of liquid hydrocarbons, gas, water, and solids, removing the

constituents that are non-saleable, and selling the liquid hydrocarbons and gas. Production

sites often handle crude oil from more than one well and all operations must be in compliance

with the safety and environmental policies and procedures. Oil is nearly always processed at a

refinery and natural gas may be processed to remove impurities either in the field or at a

natural gas processing plant.

4. Decline

During this phase, the field experiences decrease in productivity as the oil and gas reserves

commence deteriorating. At this point, depending on whether it is profitable or not, the firm

may perform well interventions in order to enhance productivity.

5. Abandonment

Involves plugging the well(s) and restoring the site when a recently-drilled well lacks the

potential to produce economic quantities of oil or gas, or when an aging well is no longer

viable (Getches-Wilkinson Center for Natural Resources, Energy, and the Environment,

2015).

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Section 2: Genesis, growth and challenges of BG Group

1.Introduction and History

BG Group (PLC), is a British international energy company focused on exploration and

production of oil and gas. Its total resource base has increased from 3.6 billion barrels of oil

equivalent (BOE) to around 18 billion boe since 1997 when the company was formed.

Currently, BG has more than 5 200 employees and operations in 25 countries, making it

among the top 15 largest companies listed on the London Stock Exchange. British Gas was

privatized in 1986 and later separated into two different listed companies in 1997; BG PLC

and Centrica PLC. BG PLC took charge of the exploration, production, international

downstream operations of British Gas, as well as the British transmission and distribution

business (Transco); while Centrica PLC, took over the British retail business of the former

British Gas.(BG Group, 2015)

The year 2000 marks another demerger, in which two new companies were formed: BG

Group PLC and Lattice Group PLC, with Lattice group PLC inheriting the Transco business.

Following the second demerger, BG Group grew strong and developed a portfolio of high-

quality assets across the gas chain, including Egypt, Tunisia, Trinidad and Tobago,

Kazakhstan, as well as the UK. The group increasingly focused on producing two highly

distinctive capabilities: a world-class exploration business and a unique LNG (liquefied

natural gas) model which up to date facilitates BG’s commercial agility and remain central to

the group’s strategy.(BG Group, 2015)

2.Major growth projects

BG group’s major projects are located in Australia and Brazil. In Australia, potential to

develop new supplies of energy in the form of coal seam gas, which is a form of natural gas

high in methane was identified and is delivered to the Asia energy market in the form of LNG.

Between 2006 and 2009, 5 large fields were discovered deep beneath the ocean floor of the

Santos Basin offshore Brazil under two kilometres of salt. At the time, many companies were

risk averse to expensive exploration in ultra-deep waters in virgin territory. The payoff was

huge as the Santos Basin finds have given BG Group, net reserves and resources of six billion

boe, with an upside potential of eight billion boe net according to BG group. BG Group and

partner Petrobras, are today making good progress with the plan to deploy 15 floating

production, storage and offloading vessels by 2018. (BG Group, 2015)

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3.BG Group challenges

Like any other oil and gas company, BG group faces many different kinds of challenges;

some, specific to the group but most generally relating to the oil industry. The yearly increase

of demand for energy presents a tremendous opportunity to meet the world’s ever-rising

energy needs and at the same time initiates an increasingly complex range of operational,

economic, environmental and social challenges. Extracting natural gas and oil is a hazardous

business. It is BG’s first priority to create an incident and injury-free workplaces in all its

areas of operations. By combining strong safety, ethics, with safe work environments, BG

group identifies and implements the best solutions that reduce risk significantly.

These include well designed, constructed and operated facilities, trained and competent

people, and robust standards, procedures and management systems. The challenge of

mitigating the impact on the environment goes hand in hand with creating business value and

long-term sustainability and demands working at ensuring that the group use energy as

efficiently as possible, and minimize the impact upon biodiversity. Climate change is a critical

issue for governments, organizations and individuals. BG faces the challenge of meeting

rising energy demand to sustain economic growth and wider prosperity, while managing the

impact on the climate.

4.Strategy: How BG identifies projects of high returns and creates value

Choosing what project to venture in is crucial for any company, especially those involving

high risks. Usually, an investor will first compare investment costs to the expected profit and

thus identify the best decision. The task of identifying project benefits and estimating an

accurate return on investment (ROI) can be very challenging. The Group identifies high-value

markets that provide opportunities for growth and then finds competitively priced resources to

supply those markets.

This strategy is applied throughout the organization and is the basis of the region and asset

business plans (BP), which are used for the defining of individual roles and objectives.The

group has a flexible liquefied natural gas (LNG) portfolio enabling it to respond to rising

market opportunities. Such a portfolio enables the group to establish a diverse set of customer

relationships based on how well the Group is able to suit supply to customer needs free of

project-specific constraints and delivery timing. For BG, the New Ventures team is

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responsible for the identification and capture of new generation conventional oil and gas

fields that will allow the company’s continued growth.

In exploration, BG geoscientists are the most important asset and the purpose of the team is to

make sure the group continues to be the leading exploration company. They are responsible

for promoting and inspiring an entrepreneurial environment that fosters creativity and

collaboration, embraces new technology and maximizes knowledge sharing and capture and

also maintains a high quality Prospective Resources Inventory (PRI) with focused growth

options and a track record of successful execution to create substantial shareholder value. (BG

annual report 2014)

Section 3: BG in Tunisia; Main strategies

1.Where BG works in Tunisia, and company history

There are currently 57 international and Tunisian oil companies involved in 54 exploration

licences in Tunisia, with BG being the largest. BG Group’s first operation in Tunisia was set

in motion in 1989. Today, over 50% of BG Tunisia’s employees are local nationals.

Emphasizing on proactive localization and capability development, BG Tunisia spent around

$6.7 million between 2009 and 2013 on capability development and reduced by 50% its

number of expatriates. There has been an increase in the company’s national leadership as

over 90 local employees were promoted to managerial positions over the past 8 years. BG

Tunisia is currently working on 2 sites, namely the Miskar site and the Hasdrubal plant.

Figure 3: Where BG works in Tunisia, the Miskar site and the Hasdrubal plant.

Source: BG Archives

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2.Miskar gas field

The Miskar field which is located 125 Kilometres offshore, on the Gulf of Gabes was

discovered in 1975 and started production of natural gas and condensate in 1996 producing

around 200 million cubic feet daily at the time accounting for 50% of the nation’s supply. It

has total proven reserves of about 1.5trillion cubic feet. Processing takes place at the BG

group Hannibal plant, 21km south of Sfax and the gas is sold to the Tunisian state Electricity

and Gas Company (STEG). A condensate pipeline 60kmlong was constructed in 2007 in order

to facilitate transportation of Miskar condensate from the Hannibal plant to the terminal

storage in Skhira where it is exported to the international market.

Figure 4: BG Miskar plant

BG Tunisia Miskar current on shore operation in its 12th year of production

9


3. Hasdrubal gas field

The Hasdrubal south west-1 well was completed in August 2002. December 2009, marks the

commencement of gas production from the Hasdrubal field located 106 Kilometres offshore

Sfax. The Hasdrubal concession is a joint development between BG Tunisia and ETAP

(Entreprise Tunisienne d’Activités Pétrolières) with each party holding a 50% working

interest in the field. The production is transported to the terminal in Skhira through Miskar’s

Hannibal pipeline and the gas is sold to STEG while the LNG (Liquefied natural gas) and

condensate are sold together with Miskar’s production on the local and international

market.BG group through the Hasdrubal and Miskar operations supplies more than 60% of

Tunisia’s domestic gas production, making it the largest producer of natural gas and liquefied

petroleum gas (LPG) in the country.

Figure 5: BG Hasdrubal Site on shore operation.

Source: BG Archives

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4. BG Tunisia, Social Investment

Apart from the Miskar and Hasdrubal operations, BG Tunisia has other activities that it

actively engages in. BG Group in general, has a duty to act responsibly both towards its

employees and in the various communities in which it operates. Likewise, BG Tunisia works

to ensure that neighbouring communities benefit from its presence on an enduring basis. It

gives a listening ear to neighbouring communities, takes account of their interests, and

supports human rights within the firm’s areas of influence.

The group’s approach to social investment (SI) spending is to support projects that build

skills, employability and income-earning prospects within communities, so that enduring

benefits may be delivered to the residents.

BG’s smallest social investment portfolio proportion is dedicated to charitable or

philanthropic initiatives. It has an SI strategy that sets target on long-term investments,

particularly, multi-year projects and partnerships. Consequently, investment is concentrated in

three areas of strategic importance for the both the group and its host countries. These areas

are; Science, technology, engineering and mathematics (STEM) education; skills development

and improving people’s livelihoods. Annually, BG Tunisia invests an average of 3million

TND in social programmes such as community employment, the vocational training

component, infrastructure projects and donations.

Partnering with the Tunisian Company of Petroleum Activities (ETAP), the Governorate and

the Ministries of Health and of Education, BG Tunisia invested in the upgrade of the Nakta

health centre and 5 schools in Gargour. During the month of Ramadan, the group supports

several needy families by providing food boxes. Also, via BG’s livelihoods programme,

vocational training is provided for the local people. The project begun in 2010 placing 170

students under this training of which 20 had graduated by end 2012. 70 more students were

enrolled in 2013 and one of the goals is to determine if they secure full-time employment,

continue vocational training on the four-year course, or does not find employment or training.

(BG Tunisia, 2013)

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5. Health, safety, security and the environment (HSSE)

HSSE is one of BG Tunisia’s main priorities. BG Tunisia is concerned with continually

protecting the health of its employees and contractors. Its vision is to build a zero-injury

culture that adds value to the company.

BG Tunisia provides a safe and secure environment in order to protect not only its personnel

and physical assets but also the company’s reputation from harm. ‘We believe all accidents

are preventable. Our goal is zero injuries’ Frank Chapman (chief executive).In addition; BG

Tunisia takes the responsibility of minimizing the negative impacts on the local environment

caused by its operations. In order to effectively and efficiently carry out all these, BG has

strategies, policies and standards all its personnel are obliged to practice.

6. Tax and revenue to the Tunisian government

About 60% of BG Tunisia’s revenue goes back to the Tunisian government and that is non-

inclusive of investment costs, employment and social performance projects. To date, BG

Tunisia has invested over $900 million in the Republic of Tunisia and has had a significant

positive indirect and direct impact on the nation’s economy. Working with many local

suppliers has allowed the provision of indirect employment. The group contributed a total of

$410 million in royalties and $1,016 million in taxes between 2007 and 2013 alone.

7. Identifying new projects

Diversity has been a source of innovation and competitive advantage for BG group. In order

to mature a venture from an opportunity, through the development and project phases to an

operating asset, as well as create and realise value from markets, BG deems it necessary to

carry out the following fundamental activities effectively and completely:

7.1. Creation of the opportunity

Exploration and business development activities are performed to identify and capture new

sources of value.

7.2. Assessment and selection of the development

Multiple concepts are studied to develop the opportunity; the options are further evaluated and

the most valuable development concept is selected to be progressed as a project.

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7.3. Definition and execution of the project

After concept selection, a project is defined to the level of detail required for sanction.

Sanctioned projects are then built to deliver an operating asset.

7.4. Operation of the asset

To realise value, gas, LNG, Liquefied Petroleum Gas (LPG), condensate and oil are

produced, processed and transported; associated contracts are managed; and the asset is

maintained and improved.

7.5. Value creation

Value is created and realised, through understanding markets and specific customer needs,

connecting gas, LNG, LPG, condensate and oil to these markets, and then anticipating and

responding to changes in customer needs.

7.6. Markets

The market occurs in parallel with the activities listed above. Understanding market and

specific customer need is vital for the creation and realisation of value. In addition, delivering

gas, LNG, LPG, condensate and oil to these markets, and anticipating and responding to

changes in customer needs remains equally important. (BG Group, 2015)

8. Creation of value and current market performance.

Most of BG’s capital is funded by pension investors. These are long term investors and

shareholders. BG creates value through world-class exploration and its unique LNG model,

facilitated by its commercial agility. Areas or sites where BG group is already actively

operating or still exploring are what are referred to as ‘existing area’. Even in these areas, the

team looks for new opportunities by capitalising on infrastructure already in place, detailed

knowledge of local geology; and relationships with governments and others affected by or

involved in the company’s operations.

Currently, BG Group’s shares stand at £11.56 (23/05/2015) and this price is on the decline

following announcements that BG Group is going to be sold off to Shell. The current market

capitalization of BG Group is £39.48 Billion as of 23/05/2015.

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Find in figure 6, financial results for the 1st quarter of 2015, which shows that BG,S

production volumes actually increased by 1%. The earnings per share experienced a drop by

50% which could be explained by the fall in the company’s earnings of the period. However,

the total capital expenditure also decreased by $630 million in a matter of three months.

(London Stock Exchange, 2015)

Figure 6: BG Group Financial Results for the first quarter of 2015.(BG Group, 2015)

Source: BG Group Financial Statement Q14

Conclusion

With the world today depending almost entirely on oil and gas for energy supply, for

production of daily items including medicines and provision of employment for many, it

could be said that petroleum is the engine of the world’s economy. However, many of the

world’s leading oil and gas analysts and geologists have come to the 5conclusion that more

4 BG Group Financial Results for Q1, http://www.bg-group.com/68/investors/financial-results/5http://www.oildecline.com/

14


than 95% of the world’s recoverable reserves have been discovered. They have also

concluded the extracting of high quality and economically extractable oil is soon to become

even more challenging, as its consumption is more than twice as quick as it was discovered.

Though, this may not be for many years, it does not change the need for more research to be

done on alternative sources in order to reduce this dependence. Nevertheless, the oil and gas

industry still has to deal with reservoir decline due to depleting reserves. Thus, the need to

perform what is known as well interventions. The concept of well interventions is covered in

more detail in the second chapter of this research.

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Chapter 2: Technical Study of Well Interventions

Chapter 2: Technical Study of well interventions

Introduction

Having looked at the basic concepts of the oil and gas industry and a short peek into BG, we

are now able to develop the concept of well interventions. In this chapter under 3 sections, I

describe well interventions in detail, explain the different kinds of work overs and detail the

reasons and benefits of these well interventions. This chapter also tackles the risks associated

with this activity and some possible methods of managing these risks.

Section 1: definition, use and technical application of work overs.

An intervention is any work done on a well for various reasons ranging from simply cleaning

the well to a major repair or tube replacement operation. The main objective of executing an

intervention is to maintain production and/or increase production of the well to avoid its early

abandonment. The focus of this paper is essentially on performing interventions in order to

enhance production.

1. Reasons and objectives behind a well intervention

During production life, wells experience a drop in the production rate due to various reasons

including mechanical failure, problems with excess water and gas production and/or reserve

depletion. Though the production decline process may be rectified by different intervention

procedures, it is imperative that the most cost effective and efficient method is selected. These

different methods of well recovery, improvement and maintenance techniques are referred to

as well work overs. 6Well work overs are any kind of intervention performed on a well usually

with the objective of stimulating, prolonging, enhancing its production of hydrocarbons.

These interventions or work overs to be more specific are performed as incremental projects

on already operating wells.

Once the probability of making a profit over loss has been determined to be positive, firms

still have another loose end to tie before finally running an intervention be it light or heavy;

amount of profit likely to be made. The question is, how much more would be gained if a

6http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=work+over

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work over was performed in comparison to if nothing at all was done? What is the

incremental gain in this project?

Since mathematically speaking, an increment is the difference between two values of a

variable and the difference may be a negative, positive or in some cases a zero change, the

difference between the two graphs gives the incremental results.

The most common reason for and probably the most performed type of well work over is the

remedial work over done on problem wells. The objective is to control excessive gas/oil or

water production from problem wells, or simply repairing mechanical failure hence avoiding

production decline. Another reason for work on a well is to increase the productivity of non-

problem wells through well stimulation.

With the aim of generating higher income, firms take advantage of profit opportunities and

perform frequent WOs on productive wells. Work may also be done to recomplete a different

zone or reservoir, for evaluation purposes of potentially productive zones in a well, or to

service a well.

2.Incremental analysis

For a better understanding of the term ‘incremental projects’ we will first define the word

‘increment’. It is taken from the Latin word “incrementum” meaning to grow. It is a gain, an

increase, or the amount by which something grows. If a firm through evaluations and

forecasts concludes that the cash flow produced by a well intervention is more profitable than

the future cash flows if nothing was done to the well (do nothing case), it decides to carry out

a well intervention (do nothing + work over).Take the illustration below as an example:

Table 1: Example of an Incremental Project with volumes measured in mmboe

Sales Gas Condensate Fuel Total Gross

mmscf mstb mmscf mmboe2015 0.0 0.0 0.0 0.02016 966.3 21.0 42.5 0.22017 1239.1 24.7 98.9 0.22018 1052.3 19.4 84.0 0.22019 928.3 16.1 74.1 0.22020 796.0 13.2 63.5 0.22021 672.7 10.7 53.7 0.12022 601.7 9.2 48.0 0.1total 6256.4 114.1 464.6 1.2

Volumes

Source: Own calculations using the BG Case Study: Miskar site

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In this illustration, a company’s goal is to increase the production capacity of a well through

an intervention. For an accurate evaluation of this project, firstly, a ‘do nothing’ case has to be

established. A do nothing case is an analysis of the production of a well without or before any

well intervention. Secondly, a ‘do nothing + work over’ case is an analysis of a wells

production after a work over has taken place. Subtracting the second case from the first will

result in the incremental volumes which enable economists to predict whether or not a work

over will increase production. In the above illustration there is a total incremental volume of

1.2 mmboe7, signifying that the project will increase production significantly.

It is clear from the table though that most of the increase in production will happen in the first

2-3 years of the work over. A negative or very low incremental volume is an indicator to the

company that the work over will not bring the desired results. The difference in volumes can

be seen more clearly graphically.

Figure 7: Incremental comparison between a “do-nothing” and a “do nothing + WO” case

2015 2016 2017 2018 20190

1

2

3

4

5

Forecasted production volumes in mmboe for the years 2015-2019

Do nothing Do nothing+WO

Source: Example of an Incremental graph.

In the graph above, we see that the work over will increase production, but with time this

increase will decrease significantly, and might possibly rebound given different scenarios.

The incremental analysis simply serves to show clearly the impact of the intervention.

7Mmboe stands for million barrels of oil equivalent

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3.Costs and financing associated with Work Overs

Well interventions costs remain very high and do not affirm at 100% that the project will

generate the desired outcome (increase in production). Carrying out a work over requires a

separate vessel or work over rig and other related equipment to be brought to the site of the

well. This equipment and the technical expertise required to carry out the work over is costly

and can easily run into more $5 billion dollars as I will show in Chapter three and the Annexe

documents. The main sources of financing for oil and gas firms are bank loans, lease

agreements and capital shares. Therefore, the feasibility of projects must firstly be proven to

be profitable in order to be able to receive financial assistance from either financial

institutions or investors. Banks need to make sure there is a high probability of succeeding

and the risk of the inability to pay back is relatively low before loaning out capital.

This source of financing is more risky and expensive for a firm as it must provide security

over the value of the loan in order to reduce the banks risk in the occasion of a loss. Also the

higher the risk involved, the higher the rate of interest demanded. Likewise, shareholders must

be convinced of a higher probability of making a profit over the risk of failure before

permitting or financing an intervention.

BG group depends on investors who are its main source of financing. In order for an

intervention proposal to be approved and financed, it must meet the hurdle rate or standard set

by the group. The hurdle rate is simply the minimum rate of return on a project the company

is willing to accept.

4.The concept of the time Value of money,

The finance principle which states that ‘’all things being equal, money today is worth more

than money in the future’ due to its potential earning capacity is a concept acknowledged

globally. Interventions do not always lead to an increase in production volumes, but merely

accelerate the production. If interest rates are high on borrowed capital, such a decision may

be very beneficial as earning more revenue would enable companies to payback sooner. In

addition, the money earned could be invested for it to generate even more.

A technique known as discounting is used to equate the future cash flow streams to today’s

value also known as the net present value (NPV). It enables managers to make a comparison

between the forecasted cash flows and the present cost of the intervention.

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5.Benefits and impacts of work overs

Well intervention restores and enhances the production rate of gas/oil wells by cleaning out

accumulations of different substances that clog the production tubing. For a company that will

eventually have to abandon an aging well, delayed abandonment means continued production

and therefore inflow of revenue for the company. Since the process of shutting down and

abandoning dead wells incurs costs of its own, well interventions may be a better option for

such a company as they increase the net revenue generated from a given well before it is

finally filled in. Governments or land owners benefit from work overs via tax and royalties

since these are paid as soon as commercial production commences, thereby providing early

revenue to the government. Depending on the agreement, royalty can be received in kind

(actual gas or oil) or in value (money value). Payments in BG Tunis are scheduled monthly.

Shareholders and investors also benefit indirectly from work overs, given that these work

overs translate to an increase in production and subsequently increased revenue flows, giving

way to increased earnings per share (dividends paid out). It’s important to note though, that,

this acceleration in the production does not necessarily imply an increase in profits; it is

merely an acceleration of income.

Section 2: Reasons for reduced well production and the well intervention procedure.

1.Reasons for limited production rate

Limited production rate maybe as a result of low oil and gas reserves or it may be limited to a

particular portion of the reservoir in question due to wear and tear. Low reservoir pressure is

another reason for low production rate. Pressure drop may be due to pumping water through

smaller tubing that in turn may cause the formation of scales, asphaltenes and paraffin.

Another cause of low production rate is formation damage, which is defined as ‘any

impairment of well productivity or injectivity due to plugging within the wellbore, or in

fractures communicating with the wellbore’. Routine production operations like acidizing for

example may cause a drop in the production rate. Scale inhibitors, corrosion and work over

fluids are conjointly among other factors that may create damage to a well or worsen its

condition.

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2.Categories of interventions

There are two kinds of interventions; light interventions and heavy interventions. The more

equipment involved in the work over task the heavier the intervention. The degree of

intervention is a variable of operational complexity and time. Complexity indicates the

equipment and accessories needed to carry out the operations.

2.1. Light interventions

Are commonly used to describe operations that may be carried out inside the rig or through

the XT (Christmas tree) and completion tubing, for example, wire line and coiled tubing

operations.

a) Wire line method

This intervention technique is frequently used in performing a maintenance or service

operation. It is carried out by attaching a tool string to a wire and running it down into the

well by the force of gravity.

Figure 8: Wire line method

Source : BG archives

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b) Tubing method

Another commonly used method is the through- tubing technique. It is a technique by which a

continuous small pipe is run into a well and used to pump chemicals or gasses directly into the

well to relieve blockage and increase flow of hydrocarbons. Coiled tubing is by far the most

effective and versatile tool for well intervention because the tubing can be run in against

pressure and therefore the well does not necessarily have to be killed first (shut down).

Figure 9: Tubing Method


2.2. Heavy interventions

Heavy interventions usually mean operations requiring use of heavy drilling equipment.

Some examples of heavy interventions or work overs are rig work overs, and hydraulic work

overs.

a) Rig work overs

The difference between rig work overs and coil tubing is that for rig work over, the well must

first be killed and the completion string pulled. In onshore wells, a smaller workover rig with

fewer facilities than are normally associated with a full size drilling rig may be used

depending on the nature of workovers. However, on offshore platforms, workovers are

performed using the same rigs that drilled the wells in the first place.

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Rig workovers also known as convectional workovers are much more expensive than

alternative methods of interventions therefore selection of the correct size of rig is a relevant

aspect to cost control. Therefore, much diagnostic information as possible is required so as to

avoid an increase in basic cost and waste of time. Figure 10 shows an image of an onshore rig

work over.

Figure 10: Onshore drilling, well intervention


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Figure 11 on the other hand shows an image of an offshore rig work over.

Figure 11: Offshore drilling, well intervention


b) Hydraulic workover

8Hydraulic workover units can be used on land and off shore principally to perform heavy

well servicing jobs such as running and pulling production tubing, drilling bridge plugs,

squeeze and plug-back cementing and washing perforations or acidizing etc. Hydraulic

workover units are flexible and have less environmental impact compared to the other

intervention techniques. They are cost efficient, quick and easy to mobilize to the offshore

platform(Rigtrain Drilling & Well Service Training, 2002).

8 Hydraulic fracturing: the procedure of creating fractures in rocks and rock formations by injecting fluid into cracks to force them further open allowing more oil and gas to flow out of the formation and into the wellbore, from where it can be extracted. ‘Investopedia dictionary’.

24


Figure 12: Hydraulic offshore workover


3.Procedure of a well workover (intervention operation)

Workover operations differ depending on what exactly needs to be done, the purpose for

intervention, the equipment already installed and the condition it is in. As earlier stated, a

work over can be light hence generally referred to as an intervention or it can be heavy.

However, the general procedure taken during a work over operation is as follows:

3.1. Well and well site preparation

A thorough inspection of the well must be carried out. The status and condition of the well

and the equipment must equally be examined for efficiency. The well site must be made ready

for the arrival of the oil rig and various measures put in place to ensure a safe intervention

operation.

3.2. Setting up of the servicing or workover unit.

In accordance with the safety rules and obligations, the workover rig and all the required

equipment can be installed once the safety measures have been put in place.

3.3. Killing the well.

Well ‘killing’ according to the ‘Schlumberger dictionary’ simply means to stop a well from

flowing. The operation involves placing a column of heavy fluid into a well bore so that the

flow of reservoir fluids is prevented.

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3.4. Serving the Christmas tree

Generally, the 9Christmas tree (XT) which is an assembly of valves, spools, pressure gauges

and chokes fitted at the well head of a completed well to control production must be replaced

with a blowout preventer (BOP). (Schlumberger dictionary, 2015) A B-O-P is a large valve

that may be sealed off at the surface of the well being worked on to provide primary control.

This process of replacing a Christmas tree requires that the personnel be mobilized, the

equipment and appropriate tools checked and made ready in order for the operation to be

completed as quickly as possible.

3.5. Removal of completion equipment.

After removing the x-mas tree, installing and testing the BOPs, the completion string must be

pulled out of the well. The necessary procedure in the pulling out of the down-hole equipment

and performing remedial work depends on the type and state of these equipment.

3.6. Recompletion

Once the remedial process has been completed, the completion process begins and may

include re-stimulating and 10fracturing of the well. Equipment that facilitates the flow of

natural gas and oil are installed down the well. Thereafter, production is initiated and the well

is left to flow in order for it to be cleaned. Throughout every stage, the wells performance

must be carefully monitored. The rig may be pulled out before or after the well is producing

again. The same rules procedure, safety rules and regulations comply here as well.

Section 3: Risks associated with well interventions and risk management

1.Importance of risk reduction

The business dictionary defines risk as the probability or threat of damage, injury, liability,

loss or any other negative occurrence caused by external or internal vulnerabilities and that

maybe avoided through pre-emptive action. Simply put in the context of the oil and gas

industry, risk is the chance that an investment’s actual return will turn out to be different than

the expected. Risks can be reduced if managed well and the ability to manage risk well is one

of the factors that distinguish highly successful companies from underperforming ones.

9http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=christmas+tree10 Also known as hydraulic fracturing

26


Overall, it is of great importance to take into account all the possible risks that may arise in

any given venture.

This is because with different risks come different costs and sometimes these costs may

significantly affect the NPV (net present value) negatively, as the higher the cost, the lower

the NPV. Unexpected and unplanned situations are more expensive to resolve than those

planned for. Analysts take into consideration possible risks to better estimate the likeliness of

them occurring and what impacts they would have on the project if they did. For instance,

planning ahead of time for possible costs that may arise from casting repairs, allows managers

to make more realistic cost estimates and spend more efficiently and come up with more

accurate cash flow.

It is the aim of every enterprise to reduce cost as much as possible in order to generate the

highest achievable net cash flow. Before deciding whether or not to go ahead with an

intervention, all the possible risks, expected and unexpected are weighed and contemplated

on. Risk analysis makes it possible for the necessary measures to be taken in order to reduce

costs and ultimately conferring not only maximum value to the company but also profitable

returns to its shareholders. Therefore, a risk based analysis facilitates more efficient planning

and execution of well intervention operations.

2.Well Intervention associated risks.

Every project is subjected to a given degree of risk and uncertainty that even a combination of

careful evaluation, knowledge and years of experience cannot be able to overcome. Time,

location, size, equipment and complexity of the project for example all present factors of risk.

2.1. Technical (mechanical) risks

Instances of technical failure or breakdown of machines during interventions is likely to

happen. The repairing of damaged equipment or fishing out tools that may have fallen into the

well may generate an increase in costs and/or a loss in production. It is for this reason that

sufficient studies must be carried out prior to costly workovers to justify remedial work on the

well at that time. Technical faults also threaten health, safety and security and could possibly

lead to serious injury or even loss of life of the personnel.

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2.2. Risks of reserves,

Workover operations consume a lot of capital. On the other hand estimating quantities of

proved reserves and projecting future production rates is difficult. The accuracy of proved

reserve estimates depends on a number of factors, assumptions and variables. These could

include technical and economic data interpretation, projections of future rates of production

and costs etc.

With regard to this, workovers may involve unprofitable efforts should the wells fail to

produce sufficient net revenues to return a profit after an intervention has been performed. A

worked on well might as well reach decline stage earlier than estimated hence generating less

income than had been estimated beforehand and thus causing a loss for the enterprise.

2.3. Market risks,

Oil and gas prices are subject to fluctuations in response to relatively minor changes in supply

and demand, market uncertainty and a variety of other factors. Furthermore, production from

certain wells may be rendered non-economic with the drops in prices since the general

expenses remain unchanged while net production revenue deteriorates.

2.4. Time risk,

Getting the equipment out to the site requires a lot of planning and logistics. If a delay should

occur in between scheduled interventions, while the well has been stopped, the company

might incur huge losses in production. As a consequence, these delays and stops adversely

affect revenue and cash flow levels in varying degrees. It is therefore a firms target to meet all

scheduled objectives and respect the work over timeline without compromising any safety

regulations.

2.5. Environmental risks,

Blowouts, spills, sour gas releases, fires or leakages are prone to happen in at any moment

causing hazardous impacts on the environment. Large inventories of flammable hydrocarbon

gases and liquids escaping containment within pipelines cause fires and explosions.

Consequently, these fires and explosions cause substantial damage to the environment (water

pollution by oil or chemical spills in water bodies and air pollution through emission of

harmful gases into the atmosphere for example), production facilities and other equipment and

property.

28


All these risks and hazards are subject to environmental regulations imposed by various levels

of government. Compliance with strict government legislation can require significant

expenditures and a breach may result in the imposition of fines and penalties resulting in the

incurring of more costs. Unpredictable climate change also poses great risks especially for

offshore well. Sudden storms are likely to hinder the intervention procedure hence prolonging

the entire project and subsequently incurring an increase in costs.

2.6. Financial risk,

Occurrence of any of the above risks could have a negative effect on future cash flows,

liquidity as well as the firms’ financial status. Miscalculation, over estimation of reserves as

well as poor planning of work overs may lead to projects failing to pay out thereby deriving a

cash flow unable to meet the desired standard in the future.

Similarly, erroneous financial estimations, can cause the firm to incur huge losses, in cases of

overestimations of growth and production potential of the firm.

2.7. Economic risks,

There is an economic gamble in re-stimulating depleting wells as a balance must be struck

between optimizing both the cost and speed of workovers while increasing long-term

effectiveness and production. Though cases of wells underperforming after an intervention are

quiet uncommon, it does not rule out the possibility of it happening. One cannot be certain

whether the cost of capital in the long run will reduce or increase hence presenting a risk as

well.

3.Risk management

Running a sensitivity analysis determines by how much a model or calculation is altered by

the changes in the input data. It is a way to predict the outcome of a company’s decision

should the variables deviate from expectations. The use of such analyses enables firms

through exploring various scenarios to identify the key influences on the value of the project

and find the 11break point where the decision is likely to change, therefore making better and

more informing choices. It is possible that some of these key factors are correlated hence the

necessity to analyse the different possible scenarios. Regarding well workovers, the analysis is 11 Break-point or break even analysis is the level at which the gas/oil prices are no longer profitable or the amount of production needed in order to be profitable. The goal is to find the minimum level key factors continue to generate profits.

29


used for example to anticipate the different gas and/or oil price levels with combination of

different values of the other key variables; calculating the NPV under different scenarios.

The goal of sensitivity analysis is to help analysts better understand the consequences of any

changes in the input data as changing assumptions and estimating results enables to better

predict the outcome of decisions taken.

Though very helpful, the sensitivity analysis still presents a few setbacks. For instance, apart

from the fact that produced results will be ambiguous, some factors such as oil price and

industry activity are interrelated; therefore making future estimations of correlations is a

challenging task in evaluating a project.

Conclusion

The aim of WO planning is basically the maximization of current profits and future net

income, the minimization of the costs of workover while increasing the recovery of carbonate

products. Since we clearly understand some of the technical complexities and risks associated

with executing certain interventions, the importance of proper planning of intervention

programs, the importance cannot be ignored. Not only does proper planning maintain

optimum production conditions but also results in very high rate of return. Therefore,

investing in skilled engineering and geologic study time should be taken seriously and

promoted. Having looked at the technical aspects of well interventions, in the next chapter, we

study their economic evaluation and processes as well that eventually enables firms make the

most efficient decisions that add value to the firm.

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Chapter 3: Concepts and theories of workover economics


Introduction

This chapter is primarily for the analysis of the different economic indicators and economic

input as well as the process used to efficiently and effectively evaluate a project. To do this,

we will use the economic evaluation process of BG Tunisia, where I was an intern in the

economics and finance department as a guide. My task while there was mainly to analyse and

interpret data output of different projects and justifying why the board should invest in one

project and not the other. For a more vivid picture of the economic evaluation and calculation

process, some economic concepts, volumes and inputs have to be clearly understood.When

evaluating the efficiency of well interventionoperations on declining production wells, it is

imperative to model assumptions, sensitivities and ‘what-if’ analysis to understand what

exactly the outcomes of changes in the input or assumptions will be. Each with its own

advantages and disadvantages, economic decision measures are a scope of distinct indicators

defined and used in the comparison process of projects.

Section 1: Economic analysis of a well intervention; major indicators

1.Economic indicators evaluation and analysis

A number of different inputs and economic indicators are needed for an as close to accurate as

possible evaluation to be exercised. There are three main economic indicators used to judge

the viability of a project in BG Tunisia. These are the net present value (NPV), the profit to

investment ration (P/I) and the rate of return (ROR).The P/I and ROR take into consideration

the long-term profitability of most oil and gas operations hence the reason for their relevance

in the economics evaluation of oil/gas operation expenditures. These indicators are referred to

as value creation measures and are calculated from the basis of a discounted cash flow.

1.1. Net Present Value:

The present value (PV) is a fundamental concept in the financial world as it describes how

much future money is worth today, thereby making it the basis of financial modelling, stock

and bond pricing, banking, insurance and pension fund valuations. Its main influential

components are time, the expected rate of return and the size of the forecasted cash flow.

31


It is important as it estimates the price or amount to be paid in the present in order to have an

investment worth a given amount in the future as well as compares cash flows that do not

occur at the same period.

NPV is merely the sum of PVs cash flows over time. Formula;

1.2. Internal rate of return:

IRR, internal rate of return is the interest rate at which the NPV of all cash flows equals zero.

It is employed to measure an investments’ efficiency and to evaluate multiple project rates of

return relative to the investment requirements. The IRR enables analysts to compare the

profitability of investments and rank projects by the overall size of return. The IRR of a

company has to exceed its ROI in order for the project to be accepted as viable.

IRR isthe r❑' ' ' ' , that satifies ; NPV =∑

n=0

N Cn

(1+r )n =0

The higher the IRR, the higher the profitability of the investment holding some other factors

constant.(Investopedia, 2015)

1.3. Profit to investment ratio (P/I):

The profit to investment ratio (P/I) is the measure of the profitability of a project per unit of

capital investment. A high P/I ratio signifies a large NPV in comparison to the capital required

to generate it. However, caution is to be taken in cases where a project is based on leased

rather than purchased equipment as a low Capex yields a high P/I. The discounted P/I is the

NPV/total discounted real capital expenditure, (both the NPV and the capital expenditure have

been discounted at the same rate and to the same discount date) it is also known as the internal

32


rate of return (ROI). Also referred to as the discounted profitability index (DPI), it is

employed to measure an investments’ efficiency and to evaluate multiple project rates of

return relative to the investment requirements.

1.4. The payback period:

This is simply the time taken to return an investment. The payback period is calculated from

the net cash flow and the pay-out commences the moment the cumulative net cash flow

becomes positive.

Section 2: Economic evaluation process

In BG, project teams have to plan, execute and interpret a batch of evaluations designed to

address an agreed problem statement; ‘the why are we here?’ question using the appropriate

quality of input data. In other word, the initial reason for the proposed intervention.

1.The importance of the Cash Flow

Cash flow is the movement of money into and out of a business or a project over a period.

Cash flows are essential to solvency as they represent past performance records as well as

forecasted performance expectations. Economists and analysts often use the statement of cash

flows. The cash flow is very essential to a business because its measurements can be used for

calculating other economic parameters fairly essential in giving information about a firm’s

situation and value not only of the past and present, but in the future as well, via projected

forecasts. Hence, cash flows play a vital role in determining whether to carry out a specific

project or not.

2.The Discounted cash flow method of evaluating a workover project

It is perhaps the most popular and applied capital budgeting tool used by oil companies that

aims at forecasting relevant discounted future cash flows using the discount rate. The rate

presents the opportunity cost and risk. The DCF represent a cost benefit analysis that helps

find the expected present value of future income and costs, and compare this value with the

projects’ cost of investment. The difference between the two is what is famously known as the

NPV (net present value). The DCF is a method of valuing the intrinsic value of a project, in

other words, it tries to work out a projects present value based on projections of all the cash

that it could make available in the future. The advantage of this type of analysis is that it

produces the closest result to an intrinsic stock value and it depends more on the future

33


expectations rather than historical results. However, as the saying goes ‘garbage in, garbage

out’, small changes in the input can result in large changes in the forecasted profit of a project,

hence a DCF is only as good as the assumptions’ creating the valuation’s input.

3.Components of a BG - Cash flow

Generally, five basic elements make up a cash flow. These include; the production schedule,

the prices of products, costs of production, capital investments and operation costs. These

variables can be broken down into two groups, the inputs and the outputs. The cash flow

provides a foundation for determining the profitability of capital investments. The economic

limit is the production rate below which the net operating cash flow from a project is negative.

A well is said to have attained its economic limit when its most efficient production rate does

not cover the operating expenses. The inputs consist of the major cost drivers, while the

outputs are the revenues and the gains from a given project. Find here-below the main

components of both the inputs and outputs of a BG cash flow,

4.Inputs of a BG Cash Flow

4.1. Opex (operating expenditure);

Operating costs are all the daily costs of operating a property and maintaining production.

They are sometimes subdivided into fixed costs, variable costs, periodic and other costs. Fixed

costs are charges that remain generally stable and unchanged regardless of production

volumes, maintenance, water disposal as well as electric power costs.

Though they may in certain instances change over long periods of times, such costs are still

considered fixed for cash flow purposes. In contrast to fixed costs are variable costs. These

vary with volumes of production, number of wells worked on, well performance and

maintenance, labour needed etc. Periodic costs as the name suggests are expenses that occur

periodically, for example repairs, acidizing or other simulation and maintenance requirements.

As a result they are scheduled in a cash flow.

Other expenses added to operating costs include various distributed costs of environmental

and/or regulatory programs. Royalties and penalties for example could be classed under this

category.

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4.2. Capex (capital expenditure);

Broadly, capital expenditure is defined as relatively major charges that generally result in an

increase in production, a decrease in costs or both. In other words, capital investments are

funds invested with the purpose of furthering business objectives. Equity is generally the

preferred or most common form of capital funding; other sources encompass debt in the form

of loans from banks and other financial institutions.

4.3. Volumes;

These are the produced gas, water, natural gas liquids (LNG) or condensate. However, for

Miskar, the volumes include condensate and gas only while Hasdrubal includes butane and

propane as well. Volume information is obtained from the well reservoir engineers.

4.4. Penalties;

This is the fine paid by BG Tunisia to the Tunisian state government in the occasion of failure

to deliver the monthly agreed upon volumes.

5.Outputs of a BG Cash Flow

5.1. Revenue;

This is the income a company receives from its normal day to day operations, in other words,

the amount of money it receives in exchange for its goods and services. BG Tunisia calculates

its revenue by simply multiplying the produced volume sales and condensate by their price.

Pricing is simply the process of determining how much a company is ready to receive in

exchange for its products. Even in the oil industry, the price of a product is dependent on

various factors such as cost of production, competition, brand, market place and the quality of

the product in question.

5.2. Royalty;

BG Tunisia is obliged to pay the Tunisian government an agreed upon percentage of its

revenue, in exchange for operating in the country. The royalty is the product of the total

revenue by the royalty rate. The royalty rate is given by the R factor based (calculated) on the

economic model in peep. The R factor calculation is defined in the model by applying the

formula below:

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Figure 13: R factor calculator

R factor (calculating royalty)

Formula: R factor=( cumulative revenue n❑)−( cumulative tax+royalty n−1 )

Cumulative cost (n)

The R factor is simply the ratio of cumulative revenue from the sale of gas and condensate to

cumulative expenditure. The larger the R factor the more profitable the operation and the

higher the royalty rate; meaning the more the government receives. Once the R factor is

calculated, it is used to determine the tax and royalty rate. BG has different royalty rates for

the gas and condensate (liquid) it produces.

We see in the diagram above that for an R factor greater than 1.10, the royalty rates are 10%

and 8% for condensate and gas respectively. For an R factor equals to zero, the royalty rate

will be at 2% for both the condensate and gas.(Veasna, 2007)12

12http://siteresources.worldbank.org/INTOGMC/Resources/cambodia_oil_gas_newsletter_8.pdf

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5.3. Tunisia Tax ;

BG Tunisia differentiates between the Tunisian Tax and the UK tax. Tax is generally the

product of the operating income and the stipulated government tax rate. Tax is generally

calculated once an operating income has been established. At this point, tangible assets are

depreciated over time reducing the amount of income available for taxation.

Figure 14: Tax calculations

Source: Tax calculator BG Tunisia.

In BG, the same reasoning as in the case of determining the royalty is applied when

calculating Tunisian Tax; using the R factor. In this case, however, there is no difference

between the tax rate of gas and condensate, for example, for an R factor greater than 2.00,

3.50, the tax rate for both gas and condensate will be 50.00 and 65.00 respectively.

5.4. Depreciation cost

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As a result of most assets losing their value over time, depreciation must always be

considered. Depreciation is a non-cash reduction of an asset’s value due to age, wear or

obsolescence. It is the devaluing of a tangible asset investment over its projected life time.

6.BG economic well intervention analysis process

Choosing the most efficient intervention project is never an easy straight forward task. It

requires skilled project team members to each play their role to the best of their ability as

efficiently and effectively as possible.

Stage 1: The subsurface department after having collected the necessary well data, uses it to

assess the well and identify the feasible solution to dealing with the question at hand. This is

done by brainstorming on alternative strategies that are not only logical but distinctive as well.

The required data collected are referred to as inputs.

A comparison between actual inputs, which are the current production state of a given well

without intervening, and the forecasted inputs which is the estimated input data after an

intervention is carried out. In other words, this stage involves quantifying inputs. These inputs

include, the volumes, Opex, Capex, penalties, tax and the revenue which are explained in

detail under the components of cash flow.

Stage 2: The assumptions on which a given analysis is based on must be clearly elaborated,

for example, it may be assumed that the discount rate for the following two years will be at

3% and that it would take 20 days to perform a given work over at a cost of

$35000.Assumptions play a role in defining the economic model used to evaluate projects

viability. The assumed expenses of the work over (Capex and Opex) are prepared by the

finance department and the prices used in the calculations are decided by the board.All

assumptions must be rational as they greatly influence the end results of the analysis.

After all this information documented and in place, a cash flow is prepared and sent to the

economics department for evaluation.

Stage 3: The economics department is responsible for analysing the proposal, pinpointing

major uncertainties and scrutinizing it for pitfall, incoherencies or anything of the sort. After

cross checking all the data, economists run the case in using economic evaluation software

called peep.

38


Peep (petroleum economic evaluation program) is an economics and planning software

designed to enable exploration and production companies (E&P) to make better decisions by

allowing engineers and economists to produce accurate forecasts using production

projections, Capex, Opex and prices. The software plays an essential role in BG’s calculation

and evaluation of project proposals.

Economic valuations can be done for a single well, groups of wells, or even well fields as

well. The software preferences are set to customize view and calculation parameters according

to BG standards, one of which is the use of the royalty and tax regime.

The volumes, Capex, Opex, penalties and assumptions are extracted from excel into peep,

each entered in its respective tab as shown in the screen shot in the appendix. Peep then runs

consolidation and sensitivity analyses of the before and after workover cases. A range of

outcomes is generatedincluding the before-and after-tax cash flows and the main economic

indicators namely; the NPV, P/I and ROR which economists evaluate and interpret.

Stage 4: The results determine the viability of a proposed intervention and aide management

in making the best choices with a clear understanding of the risks involved in their execution.

The software makes easier the identification of key factors whose variation alters the results

of the project by using different scenario to perform rapid sensitivity analyses. These analyses

give economists an idea of what to expect given a difference in one or more of the

assumptions used in the base case.

Stage 5: The project if feasible is presented to the group and SPE economists are consulted

for further analyses where necessary. Figure 15 gives a summary of the economic evaluation

process;

Figure 15: BG economic evaluation process

39


Project Team

Project Economist

AssuranceEconomist

Documents Produced

Economic Model

Framing Document

Offer A

dvice

Quantify Inputs

Assumptions Book

Sensitivity Analysis

Present Insights to Project Team

Model Documentation

Generate Range of Outcomes

Further Analysis where Required

Decision to Proceed to Paper Submission

PrepareAssumptions Book

Framing Meeting *

Move to Economics Value Assurance Process

Project Team

Project Economist Economist

Documents Produced

Economic Model

Framing Document

Offer A

dvice

Quantify Inputs

Assumptions Book

Sensitivity Analysis

Present Insights to Project Team

Model Documentation

Generate Range of Outcomes

Further Analysis where Required

Decision to Proceed to Paper Submission

PrepareAssumptions Book

Framing Meeting

Source : BG economic evaluation frame work document

40


Section 3: Case studyBG Tunisia Miskar intervention

In this section, we study interventions on two different wells at the Miskar site. Using the

necessary data, we analyse the interventions for their viability. After collecting all the required

data concerning the wells and following the steps discussed in section 2 of this chapter, a

simple cash flow can be drawn up. The cash flow is essential in calculating economic

performance. Volumes, Opex, Capex and other well inputs and out puts for the corresponding

sites can be found in the appendix.13For the purposes of this study, we leave out the IRR as it

is prone to multiple results. Additionally, the payback period errs in calculating profitability

of a project as it fails to capture cash flows after the payback period. The estimated price tag is

$60/bbl and the discount rate is 10% for both Miskar A04 and Miskar A05.

1.Case one: Miskar-A04 hydraulic fracturing and commingling

In this first case, we evaluate the proposal to perform afracking (hydraulic fracturing) and

commingling intervention on the A04 well in order to stimulate production and promote the

production of reserves from a single well.

1.1. Assumptions

BG has 3 cases it bases its assumptions on; the low case, the high case and the base

case(between the high and low case). The type of case assumption is decided on by the well

engineering department.

Table 2: Assumptions for the A04 frackingwell intervention (base case)

Case Incremental vols Opex Capex

(mmscf/d)

do nothing Gas rate before intervention 5mmscf/d / SD days

Variable Opex based on 1.25/boe No additional Capex

Do nothing + frac Gas rate after intervention 8.5 mmscf/d (incremental gas rate 3.5mmscf/d) / SD days

Variable Opex based on 1.25/boe$35mm (30 days intervention / Frac boat rate per day $0.6mm) / $15 mm Items (Non time dependent)

Source: Case A04 Miskar peep output

This intervention is projected to last for 30 days, signifying zero production as the well will be

shut down during this period. Projections suggest that the intervention would increase the

13All the figures used in this section are close to reality (dummy) and do not reflect the true case scenario as such information is strictly confidential

41


production rate from 5mscf/d to that of 8.5mmscf/d. These projections are based on the firm’s

forecasted 2015 business plan.

1.2. Economic inputs

Table 3 shows the summary input of the incremental production profile of the A04 well

(consolidation of A04 and the A04 + frac and commingling).

Table 3: A04 Economics Summary Inputs

BG Tunisia Miskar A04 inputs

Performing the frac + commingling intervention is expected to increase volumes by 1.2

mmboe by the end of 2022.The cost of the intervention is estimated to be $35 millionwith

anoperating cost of $1.5 million. In addition, it is projected that theA04 intervention will

reduce penalties by $0.08 million.

Figure 16: Forecasted production volumes for the A05 site

2015 2016 2017 2018 2019 2020 2021 20220

0.20.40.60.8

11.21.4

Donothing Donothing+WO

Source: Forecasted production volumes for the A05 site.

42


1.3. Economic outputs

Using the forecasted input above, the cases; A04 and the A04+frac, assumptions as well as

other information such as the project start date were entered into the peep soft ware. Peep runs

a consolidation analysis for the two cases giving out different output including the non-

discounted cash flow, the ROR and the P/I.

Table 4: Non-discounted cash flow

BG peep output for case A04miskar well

Table 4 gives detail of the non-discounted cash flows for the projected wok over case over the

period 2015- 2023. Subtracting all the costs and tax from the total revenue, results in an NPV

of $14,906 million. A positive NPV is obtained, but bear in mind that this amount has not

been discounted yet. To judge whether this project is viable, we must discount the NPV

(discount rate of 10%).

Table 5: Summary table of economic indicators

Source: Peep output for A04

At a discount rate of 10%, the NPV gained from the performing the A04 well intervention

decreases from 14,906to 3,622 thousand dollars. The positive discounted NPV and P/I of 0.17

after tax indicate the operation’s viability.

43


Judging from its NPV and P/I which are all positive and significant, this project is viable. It’s

certainly a good opportunity for BG to increase profitability.

1.4. Production volumes sensitivity analysis

Based on the case’s assumptions, different scenarios are used to model the sensitivity of

variables in the peep case. The question posed is, ‘would the NPV still be positive given a

high well fracturing cost and lower produced volumes?’The objective of carrying out a

sensitivity analysis is to determine the consequence of changes in certain input variables on

the actual outcome of the whole project. To account for uncertainties, the well engineer

provides information concerning the lowest possible productionvolumes and the highest cost

of the intervention. The economic performance indicators are recalculated using the new

volumes and the peep software runs the case yielding the resultshere-below;

Table 6: Production volumes based sensitivity analysis

Source: Peep output for A04

In the worst case scenario of low productionvolumes, the non-discounted NPVis positive. For

this analysis, the Capex is increased to a cost of $40million, and volumes are dropped to

0.97mmboe in order to calculatehow this change will alter our economic indicators. From the

results it is clear that under the worst case scenario, the discounted NPV will be negative. The

higher the negative NPV, the more the company would suffer losses, and the more it will

revise and reconsider the intervention. Equally, the P/I at 10% is negative hence in the worst

case scenario, this work over will result in huge losses to the company. From the results of

this analysis, analysts can properly plan and manage uncertainties. Through this analysis, the

company has a clear view how much risk is involved in executing the intervention.

44


Case 2: Miskar A05- tubing change out and Frac

The second study involves a proposition to change the size of tubing of the Miskar A05 well

so as to increase the flow of the well, with the hopes of enhancing production. It involves

performing a tubing change out (TCO) intervention.

1.5. Assumptions

The production is forecasted to seize for a duration of 35 days and the price tag attached to it

is the same as for case one; $60/bbl at a discount rate of 10%. The tubing change out

intervention is assumed to increase the production rate by 4.5mmscf/d. Changingthe tubing is

estimated to cost$55million while thefracis forecasted at $20million.

Table 6:Assumptions on the intended well intervention on the A05 site.

Case Incremental vols Opex Capex

(mmscf/d)

do nothing Gas rate before intervention 4mmscf/d / SD days

Variable Opex based on 1.25/boe No additional Capex

Do nothing + frac Gas rate after intervention 8.5 mmscf/d (incremental gas rate 4.5 mmscf/d) / SD days

Variable Opex based on 1.25/boe$75mm (35 days intervention / Change the size of the tubing $55mm / $20 mm Frac

Source: Assumptions on the A05 site.

The variable Opex is the operating cost that varies with the volumes produced. Since

interventions increase volumes, operating costs likewise increase. According to the

assumptions, an increase of 1bbl will result in an increased variable Opex of $1.25.

The inputs and assumptions are run by peep are shown in table 7.

45


1.6. Peep economic inputs

Table 7: Peep summary input for the A05 site

Penalties Opex Capex

Sales Gas Condensate Fuel Total Gross Penalties +Tariff Variable Opex Frac cost

mmscf mstb mmscf mmboe in K$ in K$ in K$2015 0.0 0.0 0.0 0.02016 1246.6 37.6 64.8 0.3 121 320 750002017 1677.4 45.8 133.8 0.3 4352018 1395.9 35.4 111.4 0.3 3582019 1242.0 29.6 99.1 0.3 3162020 1094.3 25.0 87.3 0.2 2772021 953.0 21.1 76.0 0.2 2412022 870.3 18.5 69.4 0.2 219total 8479.6 212.9 641.9 1.7 121 2166 75000

Economics Inputs

Volumes

Source: Peep Summary input for the A05 site

The cost of the tubing change out and frac is quite high at $75 million. The total gross volume

increase in regards to such a costly investment is relatively low. The total gross volume

increase is forecasted be 1.7mmboe. The variables in Table 7 above are based on the assumed

base case. The table details the assumed volumes, Opex, Capex and penalties. The forecasted

incremental volumes are 1.7mmboe.

Figure 17: Forecasted production volumes for the A05 site.

2015 2016 2017 2018 2019 2020 2021 20220

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

Donothing Donothing+WO

Source: Total gross volumes for the A05 project

46


The graph illustrates an increase in production during the first two years of the intervention.

Notice the steep drop between 2017 and 2018. The increase in production is less significant in

the years that follow until the years 2021 to 2022 where there is actually no difference at all.

The reason maybe that there are limited reserves in the well or the particular workover to be

employed is not the most efficient. The variables in Table 7 above are based on the assumed

base case. It details the assumed volumes, Opex, Capex and penalties. The forecasted

incremental volumes are 1.7mmboe.

1.7. Peep economic output

The figure below shows the peep output cash flow calculated based on the volumes and input

above.

Table 8:Non-discounted cash flow for the A05 site

Source: Peep output for the A05 project site.

As suspected from the low volumes and high cost, thecash flow is negative (-$3.3 million).

Therefore all the discounted NPV’s at any rate will be negative as well, as shown in the table

below. The cash flow indicates that taking up this project will not be profitable to the

company. The table of economic performance indicators below further confirms this;

Table 9: Peep output economic indicators

Summary table of economic indicators

47


It can be concluded that not intervening is a better option than performing a workover.The

NPV @ 10% and P/I@ 10% are all negative. This leads to the conclusion that carrying out a

well intervention on site or well A05 on the base case scenario is non-profitable and must

either be thoroughly revised or abandoned.

1.8. Price sensitivity analysis

Even though the intervention generated a negative income, a sensitivity analysis is run to

discover whether changes in certain inputs may alter the results of the case in study. It is the

duty of an economist to try and discover the faults, errors and alternatives by carrying out

further investigations and analyses. In this case, the sensitivity is run on the price. It is

assumed that the price of volumes is likely to be higher than projected i.e. from $60/bbl to

$100/bbl. The cost of the TCO however, is left unchanged. The case is run again this time at

the new price and peep gives the following output;

Table 10: Price Sensitivity Analysis for the A05.

Source: Peep output for the A05 project.

At the price tag of $100, the NPV @%10, the ROR, as well as the P/I are all positive. The

project would generate a profit of 41,434 Thousand of dollars and is therefore feasible given

such a scenario. Therefore, in case the price tag was undervalued; the project has chances of

generating profits. This analysis enables the board to foresee the results of an intervention

should prices actually rise, therefore making known the opportunity cost.

Conclusion

Now that each case has been analyzed, using these economic indicators, analysts can better

identify which project is feasible. In addition, by comparing the discounted NPVs, analysts

are also able to clearly rank the projects in order of their viability. In the above case studies, it

is obvious that only project A04, is viable as it generates positive discounted net cash flows,

(positive NPV’s). Fluctuating prices can turn highly profitable projects into huge losses in a

matter of minutes. Even more, accidents or blockages and breakdowns during intervention

may bring production to a stop for a number of days leading to loss of large sums of money.

48


These risks and uncertainties are taken into consideration through sensitivity analyses run on

different variables. Sensitivity analyses enable the company to revise possible ways around

challenging situations by finding alternative means to increase the profit. They also allow the

company to estimate the risk associated with carrying out certain projects by calculating the

NPV, ROR and P/I of the worst case scenario. By way of conclusion, all this is essential as it

determines the decision of the board pertaining whether or not they should invest in a given

project and if they do invest, just how much would be at stake.

49

General conclusion

In this document, we have seen how complex it is to arrive to a decision on well interventions.

Each and every oil and gas company has its own manual, and due to the high uncertainty

associated with the interventions, the best that companies can do is to lower risk. Our study

shows that through better planning and project implementation, a company can reduce its

costs, and better manage risks. Thus, to answer the first question pertaining to how a company

decides which project is viable, it is clear from the study that to pull out a successful

intervention, an interdepartmental process or rather system is put in place. This system brings

well engineers, economic analysts, financial analysts, project managers and cost accountants

together, for the same objective and that is, makes a meaningful decision. The solution lies in

planning ahead and putting to use various economic models to reach the desired objective.

Hence, our main question pertains to how oil and gas companies identify projects of value and

also deal with the financial risks and economic uncertainties associated with executing them.

In the light of this, we have set the following objectives; on the one hand, the study of the

technical perspectives of well interventions and on the other, their economic evaluation.

To answer this question, fundamental knowledge concerning key concepts and guidelines of

not only the petroleum industry, but the financial world, as well as the economic sector are

essential. For an efficient and effective project evaluation, it is of high importance to gather all

the necessary data concerning the well that is to be intervened on. Historic data, present and as

well as forecasted input such as, Opex, Capex, production volumes and penalties are all

important as they are enable a company to efficiently plan interventions, select the best

suitable equipment, and make as close to accurate assumptions as possible. It’s worth noting

that inaccurate well information and assumptions greatly influence the results of the economic

indicators used to evaluate projects, hence the emphasis is led on using authentic well data

and rational assumptions.

At this stage, a discounted cash flow (DCF) can be constructed using the collated present and

forecasted inputs. The DCF is important because it reflects the value added (worth) of a given

project, based on projections of how much profit it is going to generate in the future. A

consolidation between the initial case before an intervention and the case based on the

assumptions of the initial case after the intervention is done. After getting the difference

50

between these two case, that is to say, the increment, it is run by PEEP which gives detail of

the projects profitability. Sensitivity analyses are carried out to analyse how much the

economic indicators vary with certain changes in the input data. By carrying out sensitivity

analyses, the uncertainties and risk as a result of possible changes in the economy and

differences in forecasted volumes or other inputs are taken into consideration.

The total discounted value of a series of present to future cash flows is the Net present value.

All things being equal, a positive NPV means a project is viable, hence the higher the NPV,

the more profitable the project. The second indicator is the profit to investment ratio (PIR),

also known as the profitability index (P/I). It allows oil firms to quantify the amount of value

(profit) created per unit of investment. A company chooses the minimum P/I that it is willing

to accept, anything below the decided upon ratio is considered non-economic and rejected.

The NPV and P/I must be positive. These economic indicators therefore allow oil companies

to evaluate the feasibility of an intervention, hence making decision making a much easier

task.

It is of paramount importance to take into account all the possible risks that may arise in any

given venture. This is because with different risks come different costs and sometimes these

costs may significantly affect the NPV negatively, as the higher the cost, the lower the NPV.

Therefore, through sensitivity analyses, firms can make more practical decisions while

bearing in mind what is at stake in the event of any changes. The escalating demand of oil and

gas will only increase in the foreseeable future and as companies search for new exploration

sites and better well intervention techniques, this document can save as a guideline, as it

explores the technicalities, the procedures and the economic analyses associated with well

interventions.

No project is without risk, but the economic performance indicators and methods do give the

decision makers an idea of what to expect out of an intervention. Clearly, as exposed in this

study, well work overs are costly, the A05 Case study project was going to cost $75 million, if

initiated, but thanks to economic analyses it was clear from the indicators that this project

would have been a loss for the company. Now, imagine, if the economic analysis wasn’t

initiated, how many companies would be investing into the unknown?

Obviously, well interventions are not always profitable, and economic analyses are also not

full proof, but the good lesson is running such studies gives us an idea of what our current

decision to invest today, will mean in the near future. Though inevitable, risks can be reduced

51

if managed well and the ability to properly manage risk and uncertainty is one of the factors

that distinguish highly successful companies from underperforming ones. In sum, unexpected

and unplanned situations are more expensive to resolve than those planned for. That’s why,

analyses that take into consideration possible risks allow planners to better estimate the

likeliness of them occurring and what impacts they would have on the project if they did. The

examples in my case study are basic and simple as the purpose is to allow the reader to easily

understand these indicators and significance. In reality, the evaluation is more complex and

requires skilled personnel to carry out the task.

In addition, these economic indicators have a number of disadvantages and limitations. While

the NPV is useful in valuating investment opportunities, it is highly sensitive to the discount

rate. As such, a small variation in the discount rate will have a considerable effect on the

NPV. Also, a project investment may not have the same level of risk throughout its life cycle;

making it difficult to accurately peg a discount rate to it. With regard to the ROR, it too does

not account for changing discount rate and is therefore un-suitable for long term projects with

varying discount rates. The ROR may have multiple values and it may give conflicting results

when compared to the NPV. It is for this reason that it was not considered in the case study.

The disadvantages and limitations of these indicators bring out the need to discover more

accurate and efficient methods of evaluating and comparing projects. With global and

economic changes becoming more unpredictable, more revised methods of evaluation are

necessary.

Though interesting, this research has been challenging due to the very limited sources of

information available despite the subject being of great importance. The limited access to

relevant articles and books, made it difficult to profoundly analyse and clearly elaborate my

project. Further, the sensitivity and confidentiality of most information made it difficult to

carry out a detailed case study. However, thanks to the valuable training I received, my

interest in project economic and financial evaluation is even more profound than before.

This project is in line with the activities I carried out during my training with BG Tunisia

more specifically within the economics department. Some of the tasks delegated to me,

among others include reconstruction of cash flows and economic templates using excel,

analysing the economic indicators as well as other output produced by PEEP and carrying out

sensitivity analyses in order to measure the impact of variation in inputs on the global results

of a project.

52

Still, more research is useful in the field by using a literature review of thrust, adopting other

tools, among others, the questionnaire and by integrating other data analysis methods.

References

53

BG Group. (2015, May 29). About us: BG Group. Retrieved from BG Group Web site: http://www.bg-group.com/index.asp?pageid=40

BG Group. (2015, May 29). About us: Our history, BG Group. Retrieved from Bg Group Web Site: http://www.bg-group.com/25/about-us/our-history/

BG Group. (2015, May 29). Investors : BG Group. Retrieved from BG Group Web Site: http://www.bg-group.com/68/investors/financial-results/

BG Tunisia. (2013). BG Tunisia and ETAP invest in Health and Education. Tunis: BG Tunisia.

BP Global. (2015, May 29). About us : Natural gas reserves BP Global. Retrieved from BP Global: http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy/review-by-energy-type/natural-gas/natural-gas-reserves.html

Getches-Wilkinson Center for Natural Resources, Energy, and the Environment. (2015, May 29). Resources: Getches-Wilkinson Center for Natural Resources . Retrieved from Getches-Wilkinson Center for Natural Resources Web Site: http://www.oilandgasbmps.org/resources/development.php

Investopedia. (2015, May 29). ROR : Investopedia. Retrieved from Investopedia Web Site: http://www.investopedia.com/terms/r/rateofreturn.asp#ixzz3b6v3s2LD

London Stock Exchange. (2015, May 29). BG Group: London Stock Exchange. Retrieved from London Stock Exchange Web Site: http://www.londonstockexchange.com/exchange/prices-and-markets/stocks/summary/company-summary/GB0008762899GBGBXSET0.html?lang=en

Rigtrain Drilling & Well Service Training. (2002). Well Servicing. Houston: Rigtrain.

Schlumberger dictionary. (2015, May 29). Oilfield Glossary : Schlumberger. Retrieved from Oilfield Glossary: http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=christmas+tree

Veasna, B. (2007, November 30). Contracts for Petroleum Development - Part 2. Petroleum Sector Briefing Note, p. 4.

W.I. TEKNIK SDN. BHD. (2015, May 29). About us : Oil and Gas Industry. Retrieved from W. I Teknik Web Site: http://site.witeknik.org/

Table of contents

General introduction.................................................................................................................1

54

Chapter 1: Presentation of the oil, gas industry and BG.....................................................1

Section 1 : Oil, gas: their origins and the current world reserves....................................1

1. Formation and historical perspective of oil and natural gas............................................1

2. World oil reserves............................................................................................................2

3. World gas reserves...........................................................................................................3

4. Exploration and extraction...............................................................................................4

5. Oil and gas volume measurements and standard conversion...........................................4

6. The life cycle of an oil/gas field.......................................................................................4

6.1. Exploration................................................................................................................5

6.2. Appraisal...................................................................................................................5

6.3. Development stage....................................................................................................5

6.4. Decline......................................................................................................................5

6.5. Abandonment............................................................................................................5

Section 2: Genesis, growth and challenges of BG Group..................................................6

1. Introduction and History..................................................................................................6

2. Major growth projects......................................................................................................6

3. BG Group challenges.......................................................................................................7

4. Strategy: How BG identifies projects of high returns and creates value.........................7

Section 3: BG in Tunisia; Main strategies...........................................................................8

1. Where BG works in Tunisia, and company history.........................................................8

2. Miskar gas field................................................................................................................9

3. Hasdrubal gas field......................................................................................................10

4. BG Tunisia, Social Investment....................................................................................11

5. Health, safety, security and the environment (HSSE).................................................12

6. Tax and revenue to the Tunisian government.............................................................12

7. Identifying new projects..............................................................................................12

7.1. Creation of the opportunity.....................................................................................12

7.2. Assessment and selection of the development........................................................12

7.3. Definition and execution of the project..................................................................13

7.4. Operation of the asset.............................................................................................13

7.5. Value creation.........................................................................................................13

7.6. Markets...................................................................................................................13

8. Creation of value and current market performance.....................................................13

Chapter 2: Technical Study of well interventions................................................................16

55

Section 1: definition, use and technical application of work overs.................................16

1. Reasons and objectives behind a well intervention........................................................16

2. Incremental analysis.......................................................................................................17

3. Costs and financing associated with Work Overs..........................................................19

4. The concept of the time Value of money,......................................................................19

5. Benefits and impacts of work overs...............................................................................20

Section 2: Reasons for reduced well production and the well intervention procedure.20

1. Reasons for limited production rate...............................................................................20

2. Categories of interventions............................................................................................21

2.1. Light interventions..................................................................................................21

2.2. Heavy interventions................................................................................................22

3. Procedure of a well workover (intervention operation).................................................25

3.1. Well and well site preparation................................................................................25

3.2. Setting up of the servicing or workover unit..........................................................25

3.3. Killing the well.......................................................................................................25

3.4. Serving the Christmas tree......................................................................................26

3.5. Removal of completion equipment.........................................................................26

3.6. Recompletion..........................................................................................................26

Section 3: Risks associated with well interventions and risk management....................26

1. Importance of risk reduction..........................................................................................26

2. Well Intervention associated risks.................................................................................27

2.1. Technical (mechanical) risks..................................................................................27

2.2. Risks of reserves,....................................................................................................28

2.3. Market risks,...........................................................................................................28

2.4. Time risk,................................................................................................................28

2.5. Environmental risks,...............................................................................................28

2.6. Financial risk,..........................................................................................................29

2.7. Economic risks,.......................................................................................................29

3. Risk management...........................................................................................................29

Chapter 3: Concepts and theories of workover economics.................................................31

Section 1: Economic analysis of a well intervention; major indicators..........................31

1. Economic indicators evaluation and analysis................................................................31

1.1. Net Present Value:..................................................................................................31

1.2. Internal rate of return:.............................................................................................32

56

1.3. Profit to investment ratio (P/I):...............................................................................32

1.4. The payback period:................................................................................................33

Section 2: Economic evaluation process............................................................................33

1. The importance of the Cash Flow..................................................................................33

3. Components of a BG - Cash flow..................................................................................34

4. Inputs of a BG Cash Flow..............................................................................................34

4.1. Opex (operating expenditure);................................................................................34

4.2. Capex (capital expenditure);...................................................................................35

4.3. Volumes;.................................................................................................................35

4.4. Penalties;.................................................................................................................35

5. Outputs of a BG Cash Flow...........................................................................................35

5.1. Revenue;.................................................................................................................35

5.2. Royalty;...................................................................................................................35

5.3. Tunisia Tax ;...........................................................................................................37

5.4. Depreciation cost....................................................................................................38

6. BG economic well intervention analysis process...........................................................38

Section 3: Case studyBG Tunisia Miskar intervention....................................................41

1. Case one: Miskar-A04 hydraulic fracturing and commingling......................................41

1.1. Assumptions............................................................................................................41

1.2. Economic inputs.....................................................................................................42

1.3. Economic outputs...................................................................................................43

1.4. Production volumes sensitivity analysis.................................................................44

Case 2: Miskar A05- tubing change out and Frac.................................................................45

1.5. Assumptions............................................................................................................45

1.6. Peep economic inputs.............................................................................................46

1.7. Peep economic output.............................................................................................47

1.8. Price sensitivity analysis.........................................................................................48

Conclusion................................................................................................................................48

General conclusion..................................................................................................................50

References..........................................................................................Erreur ! Signet non défini.

57

List of abbreviations

Bbl………………………………………………barrels

Bcf………………………………………………barrel of standard feet

Boe………………………………………………barrels of oil equivalent

BOP……………………………………………...blow out preventer

Btax…………………………………………… Before tax

Capex……………………………………………capital expenditure

DCF…………………………………………….Discounted cash flow

E&P…………………………………………….Exploration and production

EMV…………………………………………… Economic monetary value

ETAP……………………………………………Entreprise Tunisienne d’activités Pétroliers

Fracturing (frac)…………………………………hydraulicfracturing

H2S………………………………………………hydrogen sulphate

HSSE……………………………………………Health, safety, securityenvironment

Incvol……………………………………………Incremental volumes

LNG……………………………………………...Liquefied natural gas

LPG………………………………………………liquefied petroleum gas

Mcf……………………………………………… Millions of cubic feet

Mmbbl…………………………………………... millions of barrels

Mmboe…………………………………………...barrels of oil equivalent

Mmscf/d………………………………………… million standard cubic feet

Mmscf……………………………………………millions of standard cubic feet

Mscf………………………………………………thousands of standard feet

NPV……………………………………………… Net present Value

Opex………………………………………………operating costs

P/I…………………………………………………profit to investment ratio

PD…………………………………………………Proved developed

PEEP………………………………………………petroleum economic evaluation program

PRI…………………………………………………Prospective resources inventory

PUD………………………………………………..Proved under developed

ROI………………………………………………...Return on investment

ROR………………………………………………. rate of return

Sd………………………………………………….Shut down days

TCO……………………………………………… Tubing change out

WO………………………………………………...Work over

XT………………………………………………… Christmas tree

List of Figures

Figure 1: Top proved world oil reserves, 2014. (In billions of barrels)......................................2

Figure 2: Larges proven natural gas reserves holders countries.................................................3

Figure 3: Where BG works in Tunisia, the Miskar site and the Hasdrubal plant.......................8

Figure 4: BG Miskar plant..........................................................................................................9

Figure 5: BG Hasdrubal Siteonshore operation........................................................................10

Figure 6: BG Group Financial Results for the first quarter of 2015.(BG Group, 2015)...........14

Figure 7: Incremental comparison between a “do-nothing” and a “donothing +wo” case.......18

Figure 8: Wire line method.......................................................................................................21

Figure 9: Tubing Method..........................................................................................................22

Figure 10: Onshore drilling, well intervention..........................................................................23

Figure 11: Offshore drilling, well intervention.........................................................................24

Figure 12: Hydraulic offshore workover...................................................................................25

Figure 13: R factor calculator...................................................................................................36

Figure 14: Tax calculations......................................................................................................37

Figure 15: BG economic evaluation process............................................................................40

Figure 16: Forecasted production volumes for the A05 site.....................................................42

Figure 17: Forecasted production volumes for the A05 site.....................................................46

List of Tables

Table 1: Example of an Incremental Project with volumes measured in mmboe.....................17

Table 2: Assumptions for the A04 frackingwell intervention (base case)................................41

Table 3: A04 Economics Summary Inputs...............................................................................42

Table 4: Non-discounted cash flow...........................................................................................43

Table 5: Summary table of economic indicators.......................................................................43

Table 6:Assumptions on the intended well intervention on the A05 site.................................45

Table 7: Peep summary input for the A05 site..........................................................................46

Table 8:Non-discounted cash flow for the A05 site..................................................................47

Table 9: Peep output economic indicators................................................................................47

Table 10: Price Sensitivity Analysis for the A05......................................................................48

Appendix 1: A04 Case Study Donothing profile production volumes.

DONOTHING PROFILE

Sales Gas

Fuel Gas

Sales Cond

Sales gas Total condy

Fuel Total Gross

bcf bcf MMSTB Mmscf mstb mmscf mmboe

Jan-15 1.91 0.26 0.04 1906 41 259 0.40Feb-15 1.27 0.17 0.03 1274 27 174 0.27Mar-15 1.90 0.26 0.04 1897 40 259 0.40Apr-15 1.79 0.25 0.04 1792 38 247 0.38May-15 1.83 0.25 0.04 1827 39 253 0.39Jun-15 1.75 0.24 0.04 1748 37 243 0.37Jul-15 1.78 0.25 0.04 1785 38 250 0.38

Aug-15 1.76 0.25 0.04 1764 37 248 0.37Sep-15 1.52 0.21 0.03 1521 32 215 0.32Oct-15 1.20 0.17 0.03 1196 25 172 0.25Nov-15 1.69 0.24 0.04 1688 36 239 0.36Dec-15 1.71 0.24 0.04 1710 36 244 0.36Jan-16 1.63 0.24 0.03 1625 34 237 0.34Feb-16 1.45 0.21 0.03 1454 31 213 0.31Mar-16 1.59 0.23 0.03 1593 34 235 0.34Apr-16 1.53 0.23 0.03 1527 32 226 0.32May-16 1.56 0.23 0.03 1562 33 232 0.33Jun-16 1.50 0.22 0.03 1497 31 223 0.32Jul-16 1.45 0.22 0.03 1451 31 223 0.31


Aug-17 1.40 0.22 0.03 1401 29 219 0.30Sep-17 1.32 0.21 0.03 1321 28 209 0.28Oct-17 1.38 0.17 0.03 1381 28 169 0.29Nov-17 1.29 0.21 0.03 1293 27 207 0.28Dec-17 1.32 0.21 0.03 1323 28 213 0.28

2018 14.55 2.38 0.30 14551 303 2377 3.122019 13.43 2.32 0.28 13434 278 2319 2.902020 11.75 2.18 0.24 11747 243 2185 2.562021 10.40 2.05 0.21 10396 215 2049 2.292022 9.73 2.02 0.20 9727 201 2024 2.16

Total 113.23 18.77 2.36 113,225.70

2,360.79 18,774.54 24.36

Appendix 2: A04 Case Study Donothing + WO profile production volumes.

DONOTHING+WO PROFILE

Sales Gas

Fuel Gas

Sales Cond


Fuel Total Gross

bcf bcf MMSTB mmscf mstb mmscf mmboe





2018 15.60 2.46 0.32 15603 322 2461 3.332019 14.36 2.39 0.29 14363 294 2393 3.092020 12.54 2.25 0.26 12543 256 2248 2.722021 11.07 2.10 0.23 11068 225 2103 2.422022 10.33 2.07 0.21 10328 210 2072 2.28

119.48 19.24 2.47 119,482.11 2,474.92 19,239.09 25.60

Appendix 3: A04 Case Study Incremental Profile

INCREMENTAL PROFILE

Sales gas Total condy Fuel Total Gross

mmscf mstb mmscf mmboe

Jan-15 0 0 0 0.00Feb-15 0 0 0 0.00Mar-15 0 0 0 0.00Apr-15 0 0 0 0.00May-15 0 0 0 0.00Jun-15 0 0 0 0.00Jul-15 0 0 0 0.00

Aug-15 0 0 0 0.00Sep-15 0 0 0 0.00Oct-15 0 0 0 0.00Nov-15 0 0 0 0.00Dec-15 0 0 0 0.00Jan-16 0 0 0 0.00Feb-16 0 0 0 0.00Mar-16 0 0 0 0.00Apr-16 0 0 0 0.00May-16 89 2 7 0.02Jun-16 153 4 12 0.03Jul-16 150 3 12 0.03

Aug-16 143 3 11 0.03Sep-16 112 2 -26 0.02Oct-16 55 1 4 0.01Nov-16 134 3 11 0.03Dec-16 132 3 11 0.03Jan-17 118 2 9 0.02Feb-17 107 2 9 0.02Mar-17 113 2 9 0.02Apr-17 107 2 9 0.02May-17 81 2 6 0.02Jun-17 106 2 8 0.02Jul-17 106 2 8 0.02

Aug-17 105 2 8 0.02Sep-17 100 2 8 0.02Oct-17 101 2 8 0.02Nov-17 97 2 8 0.02Dec-17 98 2 8 0.02

2018 1052 19 84 0.212019 928 16 74 0.182020 796 13 64 0.162021 673 11 54 0.132022 601.7 9 48 0.12

Total 6,256.41 114.12 464.56 1.23

Appendix 4: A05 Case Study Donothing profile production volumes

DONOTHING PROFILE

Sales Gas

Fuel Gas Sales Cond Sales gas Total condy Fuel Total Gross






2018 14.55 2.38 0.30 14551 303 2377 3.122019 13.43 2.32 0.28 13434 278 2319 2.902020 11.75 2.18 0.24 11747 243 2185 2.562021 10.40 2.05 0.21 10396 215 2049 2.292022 9.73 2.02 0.20 9727 201 2024 2.16

Total 113.23 18.77 2.36 113,225.70

2,360.79 18,774.54

24.36

Appendix 5: A05 Case Study Donothing + WO profile production volumes

DONOTHING+WO PROFILE

Sales Gas

Fuel Gas

Sales Cond


Fuel Total Gross


1.91 0.26 0.04 1906 41 259 0.401.27 0.17 0.03 1274 27 174 0.271.90 0.26 0.04 1897 40 259 0.401.79 0.25 0.04 1792 38 247 0.381.83 0.25 0.04 1827 39 253 0.391.75 0.24 0.04 1748 37 243 0.371.78 0.25 0.04 1785 38 250 0.381.76 0.25 0.04 1764 37 248 0.371.52 0.21 0.03 1521 32 215 0.321.20 0.17 0.03 1196 25 172 0.251.69 0.24 0.04 1688 36 239 0.361.71 0.24 0.04 1710 36 244 0.361.63 0.24 0.03 1625 34 237 0.341.45 0.21 0.03 1454 31 213 0.311.59 0.23 0.03 1593 34 235 0.341.53 0.23 0.03 1527 32 226 0.321.56 0.23 0.03 1562 33 232 0.331.72 0.24 0.04 1724 39 241 0.371.67 0.24 0.04 1667 37 240 0.361.73 0.25 0.04 1729 38 245 0.371.10 0.16 0.02 1101 24 157 0.230.74 0.07 0.02 737 16 69 0.151.69 0.24 0.04 1690 37 239 0.361.70 0.24 0.04 1698 37 243 0.361.67 0.24 0.04 1668 36 241 0.351.54 0.22 0.03 1540 33 223 0.331.63 0.24 0.04 1625 35 237 0.351.55 0.23 0.03 1554 33 228 0.331.20 0.18 0.03 1204 26 179 0.261.54 0.23 0.03 1542 33 227 0.331.56 0.23 0.03 1561 33 232 0.331.54 0.23 0.03 1541 33 230 0.331.45 0.22 0.03 1454 31 220 0.311.52 0.18 0.03 1516 32 180 0.311.42 0.22 0.03 1422 30 217 0.301.45 0.22 0.03 1454 31 223 0.31

15.95 2.49 0.34 15947 338 2489 3.4114.68 2.42 0.31 14676 308 2418 3.1612.84 2.27 0.27 12841 268 2272 2.7911.35 2.13 0.24 11349 236 2125 2.4810.60 2.09 0.22 10597 219 2093 2.33

121.71 19.42 2.57 121,705.32

2,573.71 19,416.49

26.09

Appendix 6: A05 Case Study incremental profile production volumes

INCREMENTAL PROFILE

Sales gas Total condy Fuel Total Gross

mmscf mstb mmscf mmboe

Jan-15 0 0 0 0.00Feb-15 0 0 0 0.00Mar-15 0 0 0 0.00Apr-15 0 0 0 0.00May-15 0 0 0 0.00Jun-15 0 0 0 0.00Jul-15 0 0 0 0.00

Aug-15 0 0 0 0.00Sep-15 0 0 0 0.00Oct-15 0 0 0 0.00Nov-15 0 0 0 0.00Dec-15 0 0 0 0.00Jan-16 0 0 0 0.00Feb-16 0 0 0 0.00Mar-16 0 0 0 0.00Apr-16 0 0 0 0.00May-16 0 0 0 0.00Jun-16 227 7 18 0.05Jul-16 216 7 17 0.05

Aug-16 203 6 16 0.04Sep-16 149 4 -23 0.02Oct-16 79 2 6 0.02Nov-16 189 6 15 0.04Dec-16 185 5 15 0.04Jan-17 162 5 13 0.03Feb-17 147 4 12 0.03Mar-17 154 4 12 0.03Apr-17 146 4 12 0.03May-17 111 3 9 0.02Jun-17 143 4 11 0.03Jul-17 143 4 11 0.03

Aug-17 141 4 11 0.03Sep-17 133 4 11 0.03Oct-17 135 4 11 0.03Nov-17 129 3 10 0.03Dec-17 131 3 10 0.03

2018 1396 35 111 0.292019 1242 30 99 0.252020 1094 25 87 0.222021 953 21 76 0.192022 870.3 19 69 0.18

Total 8,479.62 212.92 641.95 1.73

Appendix 7: Peep Tab Example.