Copyright

by

Sandra Milena Wiegand

2011
 The Thesis Committee for Sandra Milena Wiegand
Certifies that this is the approved version of the following thesis:

An Analysis to the Main Economic Drivers for Offshore Wells

Abandonment and Facilities Decommissioning

APPROVED BY
SUPERVISING COMMITTEE:

Supervisor:
Steve Nichols

Manas Gupta
An Analysis to the Main Economic Drivers for Offshore Wells
Abandonment and Facilities Decommissioning

by

Sandra Milena Wiegand, B.S.

Thesis
Presented to the Faculty of the Graduate School of

The University of Texas at Austin

in Partial Fulfillment

of the Requirements

for the Degree of

Master of Science in Engineering

The University of Texas at Austin

August 2011
 Dedication

This thesis is dedicated to the two most important people in my life: my wonderful

father, Hugo Torres and my dear husband, Michael Wiegand. To my father who taught

me the meaning of unconditional love. Thank you for giving me the best you had and

helping me succeed in life and instilling in me the confidence that I am capable of doing

anything I put my mind to. I love you Daddy !. And to my husband, my soul mate and

confidant, for always being there for me. Thank you for you endless love, support and

patience as I went through this journey. I could not have made it through without you by

my side.
 Acknowledgements

I would like to express my gratitude to the following people:

Dr. Robert Duvic, for his guidance throughout the first stage of my thesis process.

To Dr. Farid Shecaira and Mr. Dalmo Barros for all their support as my managers

during these last two years.

To Mr. Manas Gupta for his contribution as the co-supervisor for this thesis.

To Ms. Solimar Rojas for her support and friendship.

To Ms. Ingrid Sellick for her valuable ideas and all the wonderful time we shared

during the two years in the master’s program.

To Mr. Don Porteous for all his time, support and guidance.

To Mr. Joseph Ayyoubi for sharing all his decommissioning knowledge and

experience with me, his input was very much appreciated during the elaboration of this

thesis.

v
 Abstract

An Analysis to the Main Economic Drivers for Offshore Wells

Abandonment and Facilities Decommissioning

Sandra Milena Wiegand, M.S.E.

The University of Texas at Austin, 2011

Supervisor: Steve Nichols

Decommissioning and abandonment is a relevant issue in the petroleum industry

because of the complex operations involved and the results after the decision has been
made. Several factors could lead to abandoning wells and decommissioning platforms,
among others hurricanes, production decline, economic limit, etc. Decommissioning and
abandonment operations have a great impact in the revenue stream which is either lost or
temporarily deferred depending on the situation. Every year between 100-150 platforms
are decommissioned and approximately 620 wells are abandoned in the Gulf of Mexico.
A case-by-case scenario should be revised on an annual basis and all the possible options
to be considered and submitted to the Government. This thesis presents an overview of
the topic and an analysis on when decommissioning and abandoning alternatives are
recommended for the optimization of the economical resources.

vi
 Table of Contents

List of Figures ........................................................................................................ ix

List of Illustrations...................................................................................................x

Chapter 1: Introduction ..........................................................................................1

1.1 Background ..............................................................................................3
1.2 Motivation ..............................................................................................7
1.3 Scope of the study ...................................................................................7
1.4 Objectives ...............................................................................................7
1.5 Methodology ............................................................................................8

Chapter 2: Literature Review..................................................................................9

2.1 Regulatory Framework .............................................................................9
2.2 Types of Platforms..................................................................................13
2.2.1 Facility Decommissioning Options ............................................16
2.2.1.1 Removal and Reuse ........................................................18
2.3 Topsides and Decks Removal Options ..................................................20
2.3.1 Heavy Lifts..................................................................................20
2.3.2 Small Piece Method ....................................................................21
2.3.3 Reverse Installation.....................................................................22
2.4 Pipeline Decommissioning ....................................................................23
2.5 Rigs-to-Reefs Program ..........................................................................24
2.6 Wells ......................................................................................................27
2.6.1 Abandonment Options ...............................................................28

Chapter 3: Relevant Issues that influence Economical Analysis Decisions .........30

3.1 Key Drivers for Cost Estimate...............................................................31
3.2 Accounting for Future Decommissioning..............................................39

Chapter 4: Conclusions .........................................................................................41

4.1 Summary ................................................................................................41
4.2 Recommendations...................................................................................42
vii
 4.3 Conclusions.............................................................................................43

Glossary ................................................................................................................44

Bibliography ..........................................................................................................46

Vita …...................................................................................................................50

viii
 List of Figures

Figure 1: Hurricane Damage Summary in the GoM ..........................................6

ix
 List of Illustrations

Illustration 1: Map of the Gulf of Mexico ...........................................................4

Illustration 2: Platforms damaged during Katrina Hurricane in 2005 .................5

Illustration 3: Different Deepwater System Types ............................................14

Illustration 4: Platform Decommissioning Alternatives ....................................16

Illustration 5: Heavy Lift Example ....................................................................21

Illustration 6: Heavy Lift Example....................................................................21

Illustration 7: Example Small Piece Method.....................................................22

Illustration 8: Artificial Reefs, Oases for Marine Life in the Gulf ....................25

Illustration 9: Typical GoM Plugged and Abandoned (P&A) Wellbore...........28

x
 Chapter 1: Introduction

Decommissioning could be defined as a multidisciplinary process of deciding

which one is the best way is to shut down production and operations for a facility once

the field has reached its economic life. Its main objective is to deliver all property free

from hazards for the environment and to restore the area to the original conditions, as per

the applicable regulations and company expectations.

Decommissioning involves a long term planning and covers several phases and

areas. Its phases are closing, plugging and abandoning the well(s) and pipelines, cleaning

the site, making the facilities and structural components safe, removing equipments,

disposing, reusing or recycling them, and finally, providing monitoring and surveillance

if needed. Among the areas for the planning are Health, Safety and Environmental

(HSE), economic appraisals, legal provisions, technical issues, stakeholders’

involvement, etc. Each platform or structure is different due to unique characteristics

such as location, design and installation, and they are operated for specific purposes at a

specific site, so a case-by-case evaluation is required. In general, decommissioning is

followed through on a case-by-case basis where several factors are carefully analyzed in

order to minimize risk to the personnel, environment and compliance with the

government regulations.

Many multinational companies that work in the oil and gas sector have

undertaken voluntary improvements to their environmental and social management

practices in order to take a more comprehensively approach to manage their business

1
risks throughout the project life cycle and comply with their own internal corporate social

responsibility policies and principles. These efforts have contributed to a better analysis

and mitigation of the anticipating effects expected from possible decommissioning

alternatives.

Decommissioning and abandonment could be challenging issues not easy to

predict because of mainly the following reasons: Nowadays, new technologies allow a

more efficient and extensive oil and gas recovery so this fact prolongs the life of a field;

the optimization of resources using new subsea systems that “tie back” to existing

platforms add value to a project so an infrastructure life expectancy is prolonged; the

volatility in the oil price determine whether it is economic or not to extract oil from a

particular field.

Since oil production started in the Gulf of Mexico (GoM) in 1947, more than

6,500 platforms have been designed, built and installed on the continental shelves of

more than 53 countries around the world (Thornton, 1997). The majority of these

platforms are located in the United States GoM which is one of the largest oil and gas

producers in the world. The GoM is part of the Outer Continental Shelf (OCS) which is

the submerged Federal land off the United States coasts that supplies the Nation’s energy

and non-energy mineral needs. The decommissioning market is forecast to be worth

about US$3 billion over the next 5 years. (Decommissioning Activity in the Gulf of

Mexico, 2009)

It is the operators and owners responsibility to supply government authorities with

all the information about each possible decommissioning option and to recommend the

2
best solution. The final decision on how the structure and wells are decommissioned is

made by the government authorities.

The decommissioning phase is the stage least enjoyable for the operator/owner of

the facilities and wells because means to face the abandonment and the end of the

productive life of a project. Once the aging fields reach their production and economic

limits the possibilities of well abandonments increase as well.

This project provides a general outlook of the many decommissioning related

issues that impact the economical results for wells and facilities. The study is focus on

scenarios that happen in the GoM and it will provide an insight about the impact of the

abandonment cost in the decision making process.

1.1 Background

Since exploration and production began in the GoM, thousands of wells have

been drilled in shallow, deep and ultra-deep waters. In general, the common water depth

classification for projects in the GoM is as follows: Projects in less than 1,200 ft water

depths are considered to be shallow-water, those in between 1,201 ft and 5,000 ft are

considered to be deepwater projects and those in greater than 5,001 ft are ultra-deepwater

projects. Illustration 1 shows the U.S. Gulf of Mexico overview.

As mentioned before, production started in the GoM in 1947 and the first

decommissioning operation took place in 1973 (Griffin, 1998). Today, decommissioning

frequency ranges from 100 to 150 installations per year (Watson, 1998) and over the past

decade 424 wells have been plugged and abandoned (Decommissioning activity in the

Gulf of Mexico, 2009). Approximately 6,976 platforms have been installed in the GoM,

3
by 2010 and there are 3,817 active and 3,000 already removed from the GoM (BOEMRE,

2011).

Illustration 1: Map of the Gulf of Mexico (Byrd, 2009)

The climatic conditions in the GoM play an important role to be considered

during the decision making process for the decommissioning. Due to the high volume of

oil and gas operations in the GoM and its weather exposure, this area is very vulnerable

to a range of physical damage and destruction, business interruption and pollution

liability. For example, during the Hurricanes Katrina and Rita, it has been reported that

an additional 150-200 platforms were removed as a result of the aftermath of these

4
hurricanes. The GoM has experienced 191 hurricanes since 1937 and 79 have passed over

or close to offshore oil and gas structures (National Hurricane Center, 2011).

Illustration 2: Platforms damaged during Katrina Hurricane in 2005 (Oil Field Diving,

2000)

Figure 1 illustrates the damage caused by the stronger hurricanes in the last two

decades. Therefore, the risk and cost involved in decommissioning destroyed structures

is more expensive than conventional abandonment due to the stretch of resources and the

time constrains during the recovery stage. Throw in the occasional devastating hurricane

and the huge impact this has had both in activity volume and cost, it is estimated the

annual industry worth between $377M and $825M. The total exposure for

decommissioning in the Gulf of Mexico is between $18bn and $57bn, this big range is

due to the unpredictability nature of the decommissioning activity (Decommissioning

Activity in the Gulf of Mexico, 2009).

5
 Hurricane Damage Summary
3500
Katrina &
Rita
3000

2500
# P latforms

Gustav &
Ike
2000

1500
Andrew Lily Ivan
1000

500

0
1992 2002 2004 2005 2008

Year

Platforms Affected Platforms Damaged Platforms Destroyed

Figure 1: Hurricane Damage Summary in the GoM (National Hurricane Center,

2011)

The decommissioning process can be described in four different phases:

Plugging and abandonment which is the process of plugging all exploration and

development wells. This phase involves a careful analysis of the producing zones,

isolating them and setting the proper concrete and plugs. Also, involves integrity tests

and cleaning of the well site. Pipeline decommissioning which must be done in order to

prevent leaks and safety hazards for the environment, navigation, and human lives.

Platform decommissioning which is executed according to the location and design of the

platform and should fully comply with the applicable laws. Site clearance is when all the

obstructions are removed from the location. This process may require divers to search

around the well bore, or seafloor scanning for verification of the clearance.

6
1.2 Motivation

Decommissioning and abandonment is a relevant topic in the oil and gas industry

due to the large investment that these activities involve and the exposure with all

stakeholders and government during the planning and execution phase. At the end of the

productive life of a field the cash flow is affected and yearly update in the expenses and

production forecast may affect the timing for the operations. Planning is important to

properly reserve the resources needed for the implementation of the plans. During the

lifetime of a field multiple scenarios may arise such as keeping production in a field or

the sale of the field and/or facilities before the depletion of the hydrocarbons.

1.3 Scope of the study

This research is limited to cases in the GoM, in shallow waters and in deep

waters. The information presented in this report could be used as a basic approach for a

person that wants to know more about decommissioning and the different factors that

affect the economics of that kind of projects. The results are solely applied for the gas

and oil industry and as decommissioning and abandonment are a case-by-case situation,

the objective is to illustrate a methodology that could be applied for future cases. Data

for economical analysis was sensitive to confidentiality so a more detailed economical

analysis is not presented.

1.4 Objectives

The objectives of this study are to provide an insight into the literature and

common practices in the industry for decommissioning, abandonment and to assess the

impact of the key drivers in the decommissioning job cost. But in order to achieve these

7
objectives is important to take in consideration the limitations and opportunities during

the planning of the jobs and their economical analysis. Relevant issues are examined and

it was analyzed how they affect the economical context of the different decommissioning

methods including the well plug and abandonment issues, using current available

technology. The following are the specific objectives:

1. Define and identify the main options available for decommissioning platforms

and wells abandonment in the GoM.

2. Evaluate the risk issues for the various decommissioning options and well

abandonment; identifying in the process key points to deal with similar situations.

3. Provide an overview of the current status and the market opportunity for the

decommissioning field.

1.5 Methodology

In order to accomplish with the objectives set for this study a methodology was

established. At first, the objectives and scope of work were identified and formulated.

Then literature review and industry cases were analyzed, this was helpful on the path to

pursue later. With the knowledge acquired from the literature reviewed and the economic

engineering class all information was examined under different scenarios. Finally, the

conclusions and recommendation for future cases were summarized and presented.

8
 Chapter 2: Literature Review

2.1 Regulatory Framework

By their very nature, resource extraction activities, in the oil and gas and mining

sectors in particular, have the potential to generate negative environmental, social, health

and safety impacts. Many of these impacts endure after the conclusion of commercial

exploitation. If not properly addressed and mitigated, these impacts can result in

significant legal and financial burdens to the operator(s), the local population, and the

host countries once exploitation ends (World Bank Multistakeholder Initiative, 2010).

The U.S. Department of Interior (USDOI) and the U.S. Bureau of Ocean Energy

Management Regulation and Enforcement (BOEMRE) (Formerly Minerals Management

Service (MMS)), are responsible for leasing the submerged Federal lands on the United

States OCS for minerals exploration, development, and production under the OCS Lands

Act Amendments of 1978. To meet this responsibility the BOEMRE has the following

priority goals: promote the minerals resource development on public land, protection of

the human, marine, and coastal environments, receipt of fair market value from the

development of mineral resources and preservation of free enterprise competition. The

BOEMRE’s oversight and regulatory framework ensure production and drilling are done

in an environmentally responsible manner, and done safely (BOEMRE, 2011).

In the GoM, the removed structures started being record in 1973 (Griffin, 1998)

and it is estimated that between 100-150 platforms are decommissioned annually

(Watson, 1998). Owners present all possible decommissioning and abandonment

scenarios and the BOEMRE makes the final decision on the best alternative. Once, a
9
final decision is made, the owner is the party responsible for the implementation of the

selected plan.

During the late 1980’s it became evident that an American Petroleum Institute

(API) process was required for assessing the structural integrity of existing jacket

platforms in the United States OCS. The approach would be different from the design of

new platforms and as such required a new section of the API Recommended Practice

(RP) 2A. The offshore community then established an API working group that developed

the assessment approach and released it in the mid 1990’s as “API RP 2A, Section 17 –

Assessment of Existing Platforms.” Since then, Section 17 has become the worldwide

recognized approach for assessing existing platforms. It has been used many times

around the world and particularly in the Gulf of Mexico. In August 2003, the MMS

released a Notice to Lessees and Operators (NTLs) requiring GoM platform owners to

assess their platforms to Section 17 requirements. (Wisch, 2004).

API RP 2A - Section 17 provides guidelines for performing a fitness-for-purpose

assessment of steel jacket platforms based on their consequences of failure. It

recommends a multi-stage assessment procedure for platforms in United States waters,

and the use of more sophisticated structural analysis methods to determine the strength of

platforms and their acceptability. The recommended procedure involves design level and

ultimate strength analyses. The ultimate strength analysis reduces conservatism and

attempts to provide mean estimates of platform system (global) capacities using the best

estimates of individual component (local) stiffnesses and capacities (PMB Engineering,

1997).

10
 From Friday October 15-2010, oil and gas operators in the Gulf of Mexico have

120 days to submit their plans to the Bureau of Ocean and Energy Management and

Regulatory Enforcement (BOEMRE), detailing how they intend to set permanent plugs in

nearly 3,500 non-producing wells, and dismantle roughly 650 idle oil and gas production

platforms (Idle Iron NTL, 2010).

Following every major hurricane, the BOEMRE send to platform owners a NTL

requesting to execute inspections to the infrastructures that were exposed to hurricane

winds. For platforms on the path of the hurricane that were exposed to strong winds,

operators are required to conduct a Level I surveys that are related to above water visual

inspections. Consequently, platform owners report the progress or results of the

inspections to the BOEMRE, and indicate if platforms had no damage, incurred minor or

major damage, or were destroyed (Kaiser, 2010). Level II is related to general visual

inspection to the whole structure; it is intended to detect excessive corrosion, accidental

or environmental overloading, seafloor instability, design or construction deficiencies,

excessive marine growth, etc. Level III and IV are more detailed inspections depending

on the risk found by previous ones. Level III analyzes pre-selected high risk areas where

damage is suspected and it requires cleaning of marine growth. Level IV uses more

detailed technology to find damage or confirm suspicion of it.

Regarding the international regulations, once a country is a party to Conventions,

the national laws are modified in order to include the intention of the international

agreements. Globally, the regulatory policy has evolved in the last decades establishing

equilibrium between the need to protect the environment, navigation, fishing, and other

11
users of the sea on the one hand, and to take into account the safety, technical feasibility,

and cost of decommissioning on the other (Griffin, 1999).

Geneva Convention on the Continental Shelf, 1958. It was the first international

removal standard that according to the very shallow water production of that time

considered in Article 5 the following:

‘‘Any installations which are abandoned or disused must be entirely removed.’’

(Convention on the Continental Shelf, 1994)

With time the inexpensive and easy removal process became more challenging in deeper

waters and changes were needed to reflect the current and future situation.

Currently the main international conventions that influence decommissioning are:

The United Nations Convention on the Law of the Seas (UNCLOS), 1982. This

convention in Article 60.3 allows partial removal of structures:

‘‘Any installations or structures which are abandoned or disused shall be removed

to ensure safety of navigation, taking into account any generally accepted
international standards established in this regard by the competent international
organization. Such removal shall also have due regard to fishing, the protection of
the Marine environment and the rights and duties of other States. Appropriate
publicity shall be given to the depth, position and dimensions of any installations
or structures not entirely removed.’’ (United Nations Convention on the Law of
the Sea, 1982)

The International Maritime Organization (IMO). This organization is responsible

to develop and maintain a comprehensive framework for removal of offshore installations

worldwide. The 1989 IMO guidelines require the complete removal of all structures in
12
water depths shallower than 100 m and jacket weight lighter than 4,000 tones. It allows

partial removal of installations in deeper waters, leaving a minimum 55 m of clear water

for navigations safety. All structures installed after January 1, 1998, must be designed to

allow complete removal. Some exceptions apply in case the installation will serve other

purposes if it is permitted to remain partially or wholly in place and when complete

removal is not feasible technically. The IMO consent the possibility for a Rigs-to-Reefs

programme or any other new secondary use of a structure (Griffin, 1999).

The London Convention (LC) or London Dumping Convention. This 1972

Convention (and the subsequent 1996 protocol) provided a generic guidance for any

waste that can be dumped at sea and specified its different classes, including platforms

and other man-made waste. The convention partially covers the conversion of platforms

to reefs. The new guidelines were adopted in 2000 (Towmey, 2010).

2.2 Types of Platforms

There are many different types of offshore facilities including fixed concrete base

platforms, steel-legged platforms and Floating Production, Storage and Offloading

system. The majority of installations that have been decommissioned to date are steel-

legged platforms which weight between 100-2,000 tons (BOEMRE, 2011). The

illustration 2 shows the different types of deepwater systems in the Gulf of Mexico.

13
Illustration 3: Different Deepwater System Types (Mustang, 2011).

The following is a brief description of the different types of deepwater systems

available in the GoM:

Fixed Platform (FP) consists of a jacket and a deck which make up the foundation

for the surface facilities. The jacket is a tall vertical section supported by piles that are

anchored into the seabed. The deck is located on the top of the structure and it is the

place where the living quarters, a drilling rig, and production facilities are placed. The

fixed platform is common in shallow water depths.

Compliant Tower (CT) is a slim tower and a piled foundation that can hold a

conventional deck for drilling and production operations. The difference between this

tower and the fixed is that the CT resists larger lateral forces, and is usually used in and

lower deep water depths.

Tension Leg Platform (TLP) is a floating structure held in place by a mooring

system. The set of tension legs or tendons (mooring system) are attached to the platform

and connected to a foundation on the seafloor. The larger TLP's have been successfully

used in deepwater depths.

14
 Mini-Tension Leg Platform (Mini-TLP) is a cost-efficient floating mini-tension

leg platform designed for production of smaller deepwater reserves that under other

conventional production systems will be uneconomic to produce. It can also be used in

the early production stage of a field. The world's first Mini-TLP was installed in the Gulf

of Mexico in 1998 (BOEMRE, 2011).

Seagoing Platform for Acoustic Research (SPAR) consists of a large diameter

single vertical and hollow cylinder structure supporting a deck. The drilling and

production equipment is located in the platform topside. This type of platform has three

types of risers (production, drilling, and export), and a hull with a lateral catenary system

of 6 to 20 lines keeps the spar on location. The SPAR's are presently used in deepwater

depths with the possibility of being used in ultra deep waters.

Floating Production System (FPS) consists of a semi-submersible unit that can

host drilling and production equipment. It is anchored in place with large, heavy anchors,

or through dynamic positioning. The production from subsea wells is transported to the

surface deck by flexible or rigid production. The FPS can be used in a wide range of

water depths from shallow to ultra deep water locations.

Subsea System (SS) could be use for single subsea wells producing to a nearby

platform to numerous wells producing through a manifold and pipeline system to a

distant facility. These systems are presently used in ultra deep water depths.

Floating Production, Storage & Offloading System (FPSO) is a floating tank

system able to receive, process and store production from nearby platforms. The oil and

gas production could be offloaded to a tanker or transported through a pipeline. FPSOs

are an alternative for marginally economic fields located in remote deepwater areas
15
where a pipeline infrastructure does not exist yet. Currently, there is one FPSO

approved for use in the Gulf of Mexico.

2.2.1 Facility Decommissioning Options

There are several decommissioning options allowed under International Laws, it

is up to the owner and the government to choose the option that best benefits all the

parties and stakeholders involved in the project. Illustration 3 refers to the different

decommissioning scenarios. Some practices are preferred depending on the location of

the structure, company policy or government regulations.

Illustration 4: Platform Decommissioning Alternatives (Carr, 2003)

16
 A platform jacket could be left in place but this option is frequently not possible

due to the international and national laws that require removing structures no longer

having ongoing operations. In addition, the owner will have to assume maintenance costs,

accident liability, collisions, and other possible navigational hazards that complicate this

option. This alternative is best suitable when substitute uses are associated to the platform

such as becoming a logistic emergency point, living quarters, a heliport, etc.

When the complete removal option is chosen then the structure has to be

completely removed and transported to onshore for recycling or disposal. Recycling

equipments is possible but recycling a platform has a lot of limitations that combined

with the economical effects may not be the best alternative at sometimes. Platforms are

designed for a specific operational condition, volumes, location and many alterations may

be needed that will increase the final cost if the recycling use is pursued.

The top portion of a platform could be removed to 20-30 meters subsurface and

the remaining lower portion left standing in place (“topping”). This partial removal

should allow safe navigation and it is permissible under IMO for large structures. The

jacket is cut to the required depth and the bottom portion stays on the seabed. The top

part may place next to the bottom portion of the jacket on the seafloor, recycle or

disposed onshore.

When the structure is toppled over in the same location is called “toppling”. The

upper portion of the jacket is toppled in-situ leaving an unobstructed water column. The

operations involved in this option require high degree of precision and control to ensure

the structure is safely toppled as planned.

17
 As mentioned previously, when structures are moved to a new location, the

opportunities for reuse of jackets in other field sites are limited as they are designed for

specific production requirements, water depth, environmental criteria, soil conditions, etc.

Also, degradation in the integrity of the structure such as fatigue and corrosion could

impact the performance. However, some owners still consider reusing jackets for

specific cases due to the potential cost and time reduction benefits.

2.2.1.1 Removal and Reuse

There are a number of options for the reuse of offshore production facilities,

rather than scraping them. Some of the Mobil Offshore Production System (MOPU) has

been reused on 4 or 5 different fields over a 25 year life of the system. The capital cost

per location steadily drops as facilities are reused, and the construction and installation

time goes from a year or two to several months (Proserv, 2009).

For a long time, conventional jacket type platforms have been reused in the GoM,

this is a practice that is not longer popular because of the production declination in

shallow waters. Instead of this jacket platform being reused in the GoM there is a market

in international waters that have enough reserves to justify the cost reconditioning them

and transporting them to the new location (For example, West Africa).

Some structures such like TLPs are quite simple to reuse in the GoM or an

international location, this option is economically much better than scraping them. Some

modifications in the tendons and anchoring system may be needed according to the new

conditions.

18
 Semisubmersibles units could be reused in the GoM or in areas with milder storm

activity. Again, modifications may be need in the mooring system in order to comply

with the new conditions.

SPARS are structures more difficult to reuse due to their limitations moving

around. They are very expensive so owners usually try to get the most out of them

producing several fields with tie backs.

Regarding the FPSOs are the easiest structures to relocate from one field to

another depending on similar characteristics such as (pressure, temperature, gas/oil ratio,

specific gravity, water cut, sour gas content, sand content, etc). If modifications to the

facility equipments are required then time should be allowed to re-engineering and refit

of the FPSO. Old tankers are typically converted to FPSOs and as FPSOs they could last

for many years more (additional 20-25 years).

Other equipments like subsea well heads, trees and production manifolds are

routinely decommissioned and removed. They could be modified and reused for future

projects. Reuse is an option mainly when they have high technical specifications that

allow them to have a longer production life.

Regarding the subsea pipelines the alternatives for reuse are not common.

Usually the procedure to handle a pipeline that will be decommissioned is to flush them

with water, proceed to disconnect and abandon them on site. The options for all other

electro hydraulic umbilical control cables are more frequently retrieved reeled up,

reconditioned, tested, recertified and reused.

19
 Practical cost effective solutions developed by individual operators or contractors

eventually evolve into accepted industry practices and trends. In addition to trends, new

lift techniques and technology have been or will be introduced to the GoM which will

potentially offer major costs savings.

It is concluded that re-usable production systems provide considerable potential

for cost effective field development In relatively shallow waters, the use of a concrete

platform combined with jack-up drilling provides a particularly cost efficient production

system, in particular if commercial available production systems are leased or if the

services of a competent subcontractor is being utilized. A thorough analysis of taxation

regimes is required. A careful involvement by company in supervising that the work be

performed according to company standard is furthermore required. (Gudmestad, 1993)

2.3 Topsides and Decks Removal Options

2.3.1 Heavy Lifts (Illustration 5 and 6)

The market challenges for the offshore heavy lifts industry have frequently been

formidable, given the historically wide fluctuations in the price of oil, the booms and

busts in the offshore industry, and the long lead times and huge capital commitments

required for new vessel construction (JPT, 2011).

Operators executing removal try to reduce the amount of work required offshore,

contracting vessels that perform as many lifts as possible without breaking down

anything offshore. The dismantle of the structure is done onshore. This is an efficient

and safer way that reduces risk.

20
Illustration 5: Heavy Lift Example (Versabar, 2011)

Illustration 6: Heavy Lift Example (Versabar, 2011)

2.3.2 Small Piece Method (Illustration 7)

It is a method used mainly in the North Sea for removal of offshore installations

and where simplicity is the key to cost efficient execution. This methods has the

following main advantages: Utilization of logistics chain to and from offshore

installation, decommissioning activities can be performed in parallel with P&A activities,

21
optimize front running team to logistic chain to and from shore, large pieces of the

platform can be lifted to the service vessel for further processing, reduce conflicts

between decommissioning and P&A activities by thorough combined planning, high

flexibility together with other removal methods, use of local labor and equipment and no

need for crane barges and marine vessels (AF Environment, 2011) .

Illustration 7: Example Small Piece Method (AF Environment, 2011).

2.3.3 Reverse Installation

Reverse installation is a misleading term as the removal of an installation is rarely

the same as its installation. The majority of topsides were installed by crane vessels.

Hence reverse installation of topsides will involve the use of crane vessels. The size of

the lifts and the lifting capacity of the crane vessel will determine the number of lifts

required to remove the modules and any module support frame. They would then be

placed on either the deck of the crane vessel or cargo barges to be taken to their final

destination. There are some fundamental governing factors that would need consideration

in the design of lifts, for example the structural integrity of the topside components, the

design of any module reinforcement, padeyes and lifting frames (Bayou, 1997).

22
 One of the advantages of this removal technique is that the technology and

procedures are proven but costs could be high and the operations involved for reuse may

not be as cost effective as other techniques involving less time and more integrated lifts.

An exception to this would be self-contained modules such as living quarters and drilling

equipment.

2.4 Pipeline Decommissioning

The main options for decommissioning offshore pipelines are either leaving the

pipeline in-situ of removing it to shore and disposing it on land. If the first option is

considered then it may be left in place or buried. If the removal is pursued then some of

the methods to remove it are the reverse lay barge recovery, J-lift recovery, sectional

recovery and tow recovery.

In the GoM is common to find most of the pipelines buried and abandoned in

place after cleaning and disconnection, very few have been removed (Nord Stream AG,

2009). For deepwater pipelines decommissioning the size and the depth are two factors to

be considered in order to calculate the volume to be cleaned. Technology has been

implemented to flush pipelines in water depths over 8,000 feet (Proserv Offshore, 2009).

After flushing and purging the pipeline the flushing fluids have to be properly disposed

(water treated to be discharged as per government requirements and oil/gas to be sold). If

the pipeline is going to be left in place, a diver or remotely operated vehicles (ROVs) in

deeper waters could cut the ends and plugged the pipeline.

It is been suggested that pipelines could be removed by a reverse lay process

using semi-submersible lay barges or by sea bed cutting and lift removal in appropriate

23
segment lengths. The reverse lay barge recovery is likely to be more cost effective

(Gorman, 1998).

There are no regulations that mandate the removal of subsea pipeline as far as

they do not obstruct navigation activities. In addition, to the high cost involved with the

removal and all the risk of all personnel that could participate in a removal job, the better

alternative is to leave the pipeline in place and reuse it if possible.

2.5 Rigs-to-Reef Program (RTR)

The underwater portion of the oil and gas platforms is typically a metal lattice

structure, which is anchored into the ocean floor. Within a short period of time of the

installation the underwater structures has a vast marine environment, invertebrates and

plants attached to it. Within a year the structure may be completely covered with all the

kind of organisms that attract fish species and other kind of invertebrates creating a

complex food chain (BOEMRE, 2011). Such structures could be toppled in site and

create artificial reefs that positively impact commercial and recreational fishing and

diminish the consequences of destroying the complete ecosystem once the structure is

completely removed. This idea started as an innovative way to use obsolete platforms

and create policies to artificial reef building. As seen in illustration 8, the marine life

around platform is vast.

24
Illustration 8: Artificial Reefs, Oases for Marine Life in the Gulf (Artificial Reefs,

2010)

Decommissioned oil platforms have been estimated to last as long as 300 years

and, when properly sited proved to be able to withstand hurricane force conditions. A

number of Gulf demonstration rigs-to reefs projects proved that platforms possessed the

needed characteristics of stability, durability, availability, and function and were quickly

recognized as the best material of opportunity for artificial reefs (Kasprzak 1998).

In August 1983, Secretary of Interior, James Watt, created the Recreation,

Environmental Enhancement and Fishing in the Sea (REEFS) task force with the

following objective:

25
 “Pave the way for aggressive movement towards a national rigs-to-reefs program
which will enhance fishery resources and improve recreational and sport
opportunities with in America’s offshore marine environments (DuBose, 1985).”

The primary agenda of the REEF task force was to assess the use of obsolete

platforms as artificial reefs as a means to enhance local fisheries and to develop policy

that set national standards for artificial reef building (Carr, 2003).

The entities that regulate the REEFS program are the States, the U.S. Army Corps

of engineers, and the BOEMRE which once the production has ceased regulates the use

of oil and gas structures as artificial reefs. The reef plan must comply with the criteria in

the National Artificial Reef Plan and the permitting requirements of the U.S. Army Corps

of Engineers. Artificial Reefing is encouraged by the BOEMRE.

A great amount of species could be found around oil and gas platforms, such as:

Loggerhead, hawksbill, green sea turtles, corals, octocorals, black coral, sponges,

bryozoans; and fish such as grouper, snapper, jacks, etc. (Boland, 2006). It is been

reported that 10,000- 30,000 adult fish reside around a single platform in an area about

half the size of a football field (Stanley, 2000).

The first use of an oil and gas structure for a reef occurred in 1979 with the

relocation of an Exxon experimental subsea production system from offshore Louisiana

to a permitted artificial reef site offshore Apalachicola, Florida (Dauterive, 2000). The

State of Louisiana is pioneer among the Gulf States in establishing the most

comprehensive artificial reef policy where the ownership and liabilities of the platforms

is transfer to the State once is decided that the platform is going to be decommissioned.

The Plan established an Artificial Reef Trust Fund for funding costs associated with each

26
artificial reef project (Kasprzak, 2000). When a platform donation is made to the REEFS

program the owners of the structure are asked to donate to the Artificial Reef Trust Fund

half of the cost savings related to avoided disposal costs. Historically, approximately 8%

of the platforms decommissioned in the Gulf OCS have become used in the Rigs-to-

Reefs program (Dauterive, 2000). Most reefs have been established off the coasts of

Louisiana and Texas, and few in Alabama.

In the GoM, liability is transferred to the state at the point the structure is accepted

by the state as an artificial reef, under the state’s respective artificial reef programs. The

oil structure is transferred to the state (or, in some cases, another public entity) after the

state has obtained a Corps of Engineers permit for an artificial reef development.

(McGinnins, 2001)

2.6 Wells

Once the wells are permanently abandoned, then the platform decommissioning

might start. During the productive life of a field, some wells may become inactive

because of decrease on the production and the economic returns. The inactivity could be

temporary, or permanent. The illustration 4 is a typical wellbore design of an abandoned

well in the GoM. The average cost for removing a structure sits at US$1.2M and to plug

a well it sits at $775,000 (Decommissioning activity in the Gulf of Mexico, 2009).

Since 1947 approximately 34,000 wells have been drilled in the GoM OCS

Region, and about half have been permanently abandoned (PA) according to the publicly

available MMS (now the BOEMRE) “borehole” database (Nichol, 2000). Of the

remaining wellbore, a significant number are non-producing.

27
Illustration 9: Typical GoM Plugged and Abandoned (P&A) Wellbore (Thornton, 2000)

2.6.1 Abandonment Options

The objective for any well abandonment is to isolate permanently all subsurface

formation in the well. This means properly abandoning all producing zones and

protecting aquifers while minimizing cost and risk. (Tettero, 2004). Planning is the key

factor in the well abandonment process, which involves a number of factors like for

example the geology conditions, the water depth, and the well design.

As per BOEMRE regulations for placing a well in temporary abandoned (TA) or

shut-in (SI) status, in addition to meeting the mechanical requirements (for plugging and

stub clearance) an operator must:

“……provide, within one year of the original temporary abandonment and at

successive one-year intervals thereafter, an annual report describing plans for
reentry to complete or permanently abandon the well.” (30 CFR Ch. II, 250.703)

28
In the case for shut-in wells, the current regulations are:

“…completions shut-in for a period of six months shall be equipped with either
(1) pump-through-type tubing plug; (2) a surface controlled Sub-surface Safety
Valve (SSSV), provided the surface control has been rendered inoperative; or (3)
an injection valve capable of preventing backflow.” (20 CFR Ch. II, 250.801 (f))

Over time, all the inactive wells represent a high risk to safety and environment;

this issue should be considered against the potential benefits of retaining them for future

recovery of hydrocarbons.

As a way to minimize abandonment cost, especially in shallow waters, rigless

practices are proven to be safe and cost effective to plug and abandon wells in the GoM.

Using Coiled Tubing units eliminate the need for a rig and operations could be completed

in shorter time than using traditional methods with rig interventions. This procedure

requires pumping the first plug and the intermediate plug through the tree. Both plugs are

tagged and tested before the tree is removed. The final plug is set after the well is secured

and the tree removed. (Thornton, 2000)

29
 Chapter 3: Relevant Issues that influence Economical Analysis
Decisions

The GoM is an active market for United States contractors involved in

decommissioning activities. According to the number of platforms and subsea equipment

the GoM is the largest hydrocarbon producing area in the world. The active hurricane

season and the consequences of destructions that bring to the economy in the world make

it even more relevant. Decommissioning is an unpredictable, challenge, potentially

hazardous and costly activity, due to this unpredictability high fluctuation is observed in

the cost and volume of the jobs. The government and major players in the GoM have

developed a more proactive approach and tighter regulations that are consistent with the

importance of the issue. Other factor that makes the topic relevant is the fact that more

deep waters platforms are being installed. Portfolios and risk analysis should reflect the

importance decommissioning is gaining in the economics of a project.

The economics of decommissioning are usually considered in terms of “least cost

liability” as opposed to “return on investment.” Decision criteria associated with

abandonment options thus generally favor minimum cost alternatives as the preferred

means of most disposals. The factors that determine when a structure will be removed, as

well as how it will be removed, are driven by engineering, economic and safety criteria

that is time, location, and operator specific (Kaiser, 2005).

Some major oil companies sell off depleted offshore fields to smaller ones that

could maximize economical return lowering operating cost and squeezing the last drops

out of the fields. There are a lot of justifications behind the decision of selling a field; one

30
of them could be to get rid of the decommissioning liabilities. In some cases the

decommissioning and abandonment costs take smaller companies to go bankrupt in

depleted uneconomic fields.

Actually, many of the aging offshore oil and gas fields in the world, mainly in the

GoM and the North Sea, are close to the end of their productive lives. Consequently, in

the next 25 years, it should be expected that over 6,500 installations would be

decommissioned. The estimated cost to decommission such installations ranges from

US$ 20 billion to US$ 40 billion (Coleman, 1997).

3.1 Key Drivers for Offshore Decommissioning and Abandonment Cost Estimate

There are several factors that are relevant when calculating the decommissioning

and abandonment costs. The main ones are listed below and every company evaluates

the relevancy of each when choosing an alternative.

The operator must research drilling, construction, production and operation files

to obtain as much historical information as possible. The research will determine the

installed condition of the wells, structure and equipment and identify any items that may

affect decommissioning operations. A field inspection should be conducted of the

platform to examine the wells, structure and equipment in order to prepare detailed

decommissioning procedures. As-built drawings should be verified during the field

inspection. The biggest challenge is that in many cases, the information desired is not

available and in some cases, portions of the information required are not even available.

The quality of the information used in planning directly affects the costs of the

decommissioning project. (Thornton, 2000). “One of the key aspects is the lack of

knowledge of the state of the facility and the integrity of the components you have to
31
remove”, said Bruce Gresham, vice president for North America at Heerema Marine

Contractors US. “When facilities are no longer producing, maintaining them becomes

less of a priority for an operator, certainly. And then it’s about record keeping, being

able to document things that have altered or significantly affected the facility. There is

just going to be –and this is our experience- a tremendous amount of uncertainties. Some

of the biggest challenges are the unknowns, the surprises, and how to establish a fair

balance of contractual risk between the contractor and the operator.” (JPT, 2011).

The contracting strategy should be analyzed carefully in order to optimize

resources and perform the job in a safe manner. Once the scope of work is defined, it

should up to the owner to determine if it is the best interest to bid the job as a whole or

splitting it in several contracts. Experienced companies should be invited to participate in

the bid process, since decommissioning is an operational type of activity. If the contract

is split could be an optimization in time and price. All cases are different so both

approaches should be considered. If the scope of work is split, then every phase has to be

breakdown in segments that address jobs. For the preparation phase an option could be to

award three different contracts as follows: Decommissioning of facilities, plug and

abandonment of the wells and hook-down of cables and piping. Second there is a

removal and dispose that include other engineering details and actual removal and

dispose of the equipments and flowlines. The terms and conditions should be revised by

a legal team and the remuneration structure should contain detailed information about

possible bonus, lumps sums, combination of this, or others. The compensation item

should reflect uncertainty such as weather, lack of information, etc. The lump sum

contracts do not provide incentives for HSE performance and the final deliverable, being
32
the environmental inventory account may suffer under a lump sum regime (Gram, 2011).

If using single lifts or small piece methods, either way, proper accounting methods have

to be implemented to trace materials between offshore and onshore.

Waste Management is one the key drivers when estimating costs and it is an issue

approached as per every company’s policy that should be analyzed in detail either if the

waste is going to be disposed at sea or onshore, reuse or recycled. Once the safety

inspections identify the hazardous materials, resources have to be delivered for their

proper collection and transportation. Asbestos, batteries, material contaminated by

mercury, hydrocarbons, heavy metals, etc. should be handled carefully to protect workers

and the environment.

The operating procedures are other key driver that should be done including all

the legal concerns involved during the decommissioning and abandonment, the health,

safety and environment (HSE), contract strategy, etc. Regarding the legal issues, they are

analyzed on a case-by-case as the decommissioning and abandonment process.

Companies have to comply with an extensive legal framework in order to remove and

dispose offshore installations. The legal framework intents to protect the environment,

navigation, fishing and other sea users, tanking into account safety, technical feasibility

and the cost of decommissioning.

Numerous HSE issues arise with the decommissioning of offshore platforms. The

use of explosives, diver exposure and multiple heavy lifts are some of the potential risky

jobs that could affect greatly the decommissioning and abandonment and increase the

cost. Offshore dismantling of steel structures involves significant hazards due to

uncertainty about the structural integrity and precise weights and centers of gravity of
33
components, especially when during the life of the installation several modifications to

the structure have been performed. Furthermore, risks to safety have been estimated to

be approximately 50% higher for total removal of a structure compared to partial

removal, due to the higher exposure of personnel to hazards during a total removal

(Anthony, 2000). During the HSE assessment a critical decommissioning impact is

related to the disposal process that impacts the sea, land and air, so a careful detailed

environmental assessment is required to deal with the issues, the concerns and the

alleviation of the impacts.

An appropriate balance has to be achieved between the safety, environmental and

financial risks. The likely environmental impact is largely independent of the choice

between decommissioning options. If this finding is true then the choice of which

decommissioning route to take hinges firmly on the safety and cost factors (Gorman,

1998).

Regarding pipelines decommissioning is important to note that their removal is a

high cost operation that varies from the pipeline location and the impacts on the

environment, especially from the marine environment are minor. Compared with the

abandon in place option, pipeline removal requires 70% more energy (Nord Stream AG,

2009)

During the operational life of an asset, the decommissioning and abandonment

costs are reviewed on an annual basis. New technologies and costs need to update the

cost estimation, a review of the reserves vs. the operational cost need to determine when

the best time to cease production is and the identification for additional opportunities that

could improve the economics of the field. Planning ahead and an effective project
34
management of the decommissioning job could significantly reduce the decommissioning

liabilities and optimize the recovery of an important portion of the overall expense of

removing an offshore structure. Platform size and water depth are two considerations

that dictate how much a decommissioning project will cost.

The cost to decommission the world’s offshore platforms has been estimated at

US$20-40 billion. The North Sea area accounts for approximately 60% of the worldwide

decommissioning costs, although it only includes about 9% of the platforms. This is

attributed to the size of the North Sea installations and the severe environmental

conditions of the area, making decommissioning efforts particularly difficult (Anthony,

2000).

Decommissioning costs are driven by the complicated logistics process for the

structure and equipments removal that are needed to ensure structural integrity, assurance

of spill free operations from harmful and hazardous materials, and the cost optimization

of all the services contracted. When decommissioning scenarios such as leaving fully or

partially structures in place are decided, the owners should plan for long-term monitoring

costs that go according to the location, complexity of the structure and the government

regulations.

The deeper the oil and gas fields are located the higher the costs, also the most

likely is that the complexity of the operations is higher which contributes to increase the

cost as well. As mentioned in several occasions through this study, the decommissioning

and abandonment process is a case-by-case so different decommissioning options will

generate different cost estimates based on the unique characteristics of the platforms and

wells. Options such as partial removal and toppling in situ have been estimated to offer
35
potential savings of 15-70% compared to total removal due to the reduced offshore

deconstruction time and thus, offshore spread utilization (The Oil Industry International

Exploration and Production Forum, 1995).

The marginal cost-effectiveness specifically for the scenario complete removal vs.

donation to an artificial reef program, is relatively little for shallow water platforms.

These marginal differences increase for deep-water platforms and because of this reason

and their larger donations to the artificial reef funds, decommissioning in deepwater

platforms as artificial reefs is more attractive to the parties, platform owners and program

managers.

The main cost elements related to a decommissioning project are the mobilization,

demobilization, project management, surveys pre and post removal, contractors, final

disposal, overhead and contingency plans.

Based on business statistics revealed from GoM and projects such as Odin

Platform in the North Sea, the money spent on total removal of offshore structures is

distributes as follow:

1. Lifting vessels and cargo boats (60%)

2. Site Clearance (18%)

3. Decommissioning (11%)

4. Mobilization and miscellaneous (7%)

5. Pipeline Abandonment (4%) (Alghamdi, 2005)

The Engineering and Planning phase of decommissioning cover several phases

from scope of work up to contract strategy that best suits the field. The cost will depend

on the kind of technology used, the complexity of the decommissioning and the
36
dismantling procedure to accomplish the decommissioning job. This phase includes the

proper planning for tasks such as permitting and regulatory compliance, the platform

preparation, the plugging and abandonment of the wells, the conductor severing and

removal, the mobilization and demobilization, the pipeline decommissioning and the

material disposal.

The different decommissioning options have to inevitably analyze the best options

that satisfy the different groups involved in a job of this magnitude. The principal

spheres of special interest are the environmental, health and safety, financial and

political. The literature and the established conventional wisdom has identified the Best

Environmental Option as the paradigm for accepting an abandonment strategy, but it is

necessary to examine what is Best Practicable from each spheres of interest. The

different options could be:

- Best Practicable Environmental Option

- Best Practicable Safety Option

- Best Practicable Financial Option

- Best Practicable Political Option (Gorman, 1998)

The conjunction of all of these options could be defined as the Best Practicable

Engineered Option. And the term “best” is relative to the company’s policies and their

stakeholders.

Alternatives such as “Mothballing” could be attractive in a certain moment of the

field, in order to decrease costs and find a potential user of the facility. This is an

alternative in small fields and when costs are higher than revenues. With volatile oil and

gas prices this choice could be analyzed in more detail.

37
 Due to the high cost the decommissioning cost brings to the economics of a field,

and adding the environmental and political concerns when a job of this kind is performed,

then the reuse of the facilities is a “green” alternative that affect the Net Present Value

(NPV) of the field to be decommissioned and the NPV of the new field. There are cash

flow and tax consequences when reuse happens.

The political importance for the petroleum and gas industry involves public and

private interests which affects the decision-making process. The Brent Spar events,

which was a high profile publicity case generated by Greenpeace in 1995 against the

disposal plan of the Shell operated North Sea oil storage and tanker loading buoy in the

Brent oilfield. This Greenpeace campaign on the Brent Spar case has demonstrate that it

is not up just to the regulators but also it is an issue that all stakeholders’ opinion should

be taken into account when performing a decommissioning job. Public opinion is volatile

and difficult to measure and it often neglected because lack of a proper methodology to

address the issues and find the way to quantify results. Risk assessment techniques can

help to evaluate the financial consequences that negative publicity could bring to a

project.

Oil companies –like the counterparts in other sectors- are struggling to meet the

ever rising expectations of corporate responsibility. As recently as a decade or so ago, a

“responsible” company was the one that made a profit without breaking any laws or

causing any high-profile disaster or scandals. The term now implies much greater

accountability for –as well as a higher degree of transparency on- the environmental and

social dimensions of a company’s operations (Aloisi, 1999).

38
 The oil industry has made an important progress identifying all kind of issues

related to external stakeholders. The basic principle underlying the “right-to-know”

(RTK) movement is that people deserve access to information about companies’ actions

that directly affect their welfare. Traditionally, the focus has been on environmental

health issues –but the RTK concept is expanding to encompass a company’s social and

economic effects as well, such as employment or land-use decisions. (Aloisi, 1999).

3.2 Accounting for Future Decommissioning

All the future cost related with the production facilities decommissioning and

wells plug and abandonment have to been reflected in the accounting books. Also, all

costs of bringing back and returning the place to the initial environmental conditions have

to be taken into account. An asset is considered retired when it is permanently out of

service, either through sale or disposal. Retirement obligations can be recognized when

the asset is placed in service or during its operating life at the point when its removal

obligation is incurred.

In June 2001, the Financial Accounting Standards Board (FASB) issued

Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset

Retirement Obligations” (ARO’s) for those companies listed on the New York Stock

Exchange. The SFAS No. 143 defines the criterion for decommissioning and

abandonment costs of production assets allocation and establishment, it provides

information about the way companies are required to report the cost allocation in the

company accounts which are auditable material. In general, companies are required to

recognize much sooner any legal liability associated with the future retirement of tangible

long-lived assets.
39
 Once a liability for retirement obligations is identified, the company should

capitalize the exact amount as part of the cost basis of the related long-lived asset and

allocate it to the Depletion, Depreciation and Amortization (DD&A) over the life of the

asset. Any changes in the obligation need to be recognized by modifications (up or down)

to the carrying value of the asset retirement obligation (ARO) and the related long-lived

asset.

40
 Chapter 4: Conclusions and Recommendations

4.1 Summary

Decommissioning is an important topic in the oil and gas industry and it is even

more relevant when a field has been producing for quite some time. Also, the active

weather in the Gulf of Mexico has a huge impact in the subject and requires a constant

revision of the decommissioning and abandonment plans.

Several alternatives for decommissioning and well abandonment have been

researched along this project; it is the operator/owner responsibility to present all

recommendations to the government. Each case should be evaluated on a case-by-case

basis and the government authorities are the ones who will make the final decision on the

most suitable proposal.

The cost of removal, as a function of depth, is the main factor in the

decommissioning and abandonment assessment phase. The Rigs-to-Reefs program has

provided a selection of decommissioning scenarios not available before. This program is

an alternative that could provide cost savings for certain cases in shallow and deepwater

projects. Legislation relieves platform owners of liabilities after the platform is donated

and they are satisfied with the idea that ecological benefits (artificial reefs) are obtained

as a consequence. The selection of this option strategy is taken by the owner who, for the

most part, selects the most efficient cost-benefit approach.

Decommissioning is a final and difficult stage for any field, because it means the

end of the productive life and the economic limit has been reached. But it is an important

topic when analyzing the economics of an oil and gas field. There are several

41
opportunities available that when combined with the economic analysis they will provide

benefits to the owners/operator, government or others (third parties). Possibilities of

selling a field when reaching economic limit could be explored and advantageous to third

parties that specialize in this kind of projects.

4.2 Recommendations

Collective collaboration between different platform owners could allow the

removal of several structures at the same time and maximize savings. The Government

could contribute to this initiative by promoting change in legislation to allow this

collaboration.

When dealing with small, marginal fields reusing equipments could provide a

competitive advantage and improve the economical view of a project. Regulations could

be implemented to incentive this option and all consequences should be analyzed to avoid

future issues in the commissioning of the equipments at the new site.

More emphasis should be put in place at the initial stage of a project when

designing facility equipments and platforms, in this way when the time to remove them

comes the decommissioning will be easier to handle. This could bring more cost-

effective and safer solutions during the decommissioning job.

Document control is very important during the any project management and

becomes a key issue during decommissioning since lack of information could prolong the

project and increase cost. The equipment inventory should be categorized and analyzed

to take the best approach for the decommissioning. Information becomes critical when a

field is near the end of the production life and when it is sold to other operators.

Sometimes the owner of a platform is not the one that was involved during the
42
construction phase, so basic information might be in their possession but detailed one is

forgotten to hand over causing uncertainties during the decommissioning phase.

Regulations and contractual provisions should address the transfer of data to new

operators to assist important operations such as decommissioning. As the fields in the

GoM mature the documentation control is a critical issue to address.

One challenge that the oil and gas industry have to overcome is the limitation in

experience base because although an increase in recent decommissioning activity has allowed the

industry some experience, there is still much to learn and accomplish on a larger scale, like for

example in deep waters. The industry should keep emphasizing in the importance of training

personnel and consider decommissioning an area as relevant as drilling, production, reservoir, etc.

because experienced personnel should facilitate such complex abandonment and

decommissioning operations.

Challenges ahead for the decommissioning industry include change in the

regulations, insurance issues, risk identification and mitigation plans, legal and

contractual structures to perform the job in the safer and environmental best manner,

reuse of equipments and deep waters decommissioning which is a whole new area to

explore that will bring new technology and lessons to learn from.

4.3 Conclusions

Decommissioning is a case-by-case study that involves a broad list of

requirements and issues to analyze. Unlike a new investment, decommissioning of an

existing platform cannot be avoided, but a company can select when the best moment to

perform the job is. When key parameters are unknown the best alternative is to continue

production, if possible, until the circumstances might be more favorable. It is thus part of
43
the ongoing value of the project. It is also the opportunity cost of decommissioning today

and can be used to determine the best time to decommission in the future.

Decommissioning in deep-waters as artificial reefs is more attractive to both

platform owners and program managers due to the relatively higher cost-savings to

platform owners and their greater contributions to artificial reef funds. However, other

factors could contribute to determine what decommissioning strategy is selected as the

best alternative for certain cases.

44
 Glossary

API American Petroleum Institute MOPU Mobil Offshore Production

ARO’s Accounting for Asset Retirement System

Obligations NPV Net Present Value

BOEMRE U.S. Bureau of Ocean NTLs Notice to Lessees and Operators

Energy Management Regulation and OCS Outer Continental Shelf

Enforcement PA Permanently Abandoned

CT Compliant Tower P&A Plugged and Abandoned

DD&A Depletion, Depreciation and REEFS Recreation, Environmental

Amortization Enhancement and Fishing in the Sea

FASB Financial Accounting Standards ROVs Remotely Operated Vehicles

Board RP Recommended Practice

FP Fixed Platform RTK Right-to-Know

FPS Floating Production System RTR Rigs-to-Reef Program

FPSO Floating Production, Storage and SFAS Statement of Financial

Offloading system Accounting Standards

GoM Gulf of Mexico SI Shut-in status

HSE Health, Safety and Environment SPAR Seagoing Platform for Acoustic

IMO International Maritime Research

Organization SS Subsea System

LC London Convention SSSV Sub-surface Safety Valve

MMS Minerals Management Service TA Temporary Abandoned

Mini-TLP Mini-Tension Leg Platform TLP Tension Leg Platform

45
UNCLOS United Nations Convention USDOI U.S. Department of Interior

on the Law of the Seas

46
 Bibliography

AF Environment Presentation. Decommissioning Summit. March 2011.

Alghamdi A. and Radwan A. Decommissioning of Offshore Structures: Challenges and

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 Vita

Sandra Milena Wiegand was born in Colombia. She attended Santa Dorotea High

School in Cali and graduated as valedictorian in 1993. In Fall of 1993, she was admitted

to the Universidad Surcolombiana in Neiva, Colombia. She received her Bachelor of

Science in Petroleum Engineering in March 2000. While at the Universidad

Surcolombiana she was granted a scholarship, and, consequently, she became an

exchange student at the University of Oklahoma during 1998-1999, where she obtained

her Certificate in Petroleum Engineering. In August 2009, while maintaining her full-

time employment, she entered the Graduate School at the University of Texas in Austin.

The author can be reached at: sandra_wiegand@yahoo.com

This thesis was typed by the author.

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