Our Reference: P1508 

OCS Study BOEM 2016-052 

FINAL REPORT 

Updates to Fault Tree Methodology and Technology 

for Risk Analysis 

Liberty Project

BOEM Contract Number M11PC00013 

May, 2016

By 

Bercha International Inc. 

Calgary, Alberta, Canada 

 U.S. Department of the Interior

   Alaska Outer Continental Shelf Region

   Environmental Sciences Management
OCS Study BOEM 2016-052 

FINAL REPORT 

Updates to Fault Tree Methodology and Technology 

for Risk Analysis 

Liberty Project

BOEM Contract Number M11PC00013 

May 2016

Principal Investigator: Dr. Frank G. Bercha, PEng 

Bercha International Inc. 

2926 Parkdale Boulevard NW 

Calgary, Alberta, T2N 3S9, Canada 

Email: berchaf@berchagroup.com 

Study concept, oversight, and funding were provided by the U.S. Department of the Interior, 

Bureau of Ocean Energy Management, Environmental Studies Program, Washington, DC 

under Contract Number: M11PC00013. 

DISCLAIMER 

The opinion, findings, conclusions, or recommendations expressed in this report or product are 

those of the authors and do not necessarily reflect the views of the U.S. Department of the 

Interior, nor does mention of products constitute endorsement or recommendations for use by the 

Federal Government. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

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i

ABSTRACT 

The present document deals with the evaluation of oil spill potential associated with a proposed 

development at the Liberty prospect (the Project), generally located in the South Beaufort Sea in 

the landfast ice zone, inside the barrier islands, approximately 9 km (5 miles) offshore as. The 

Project is proposed to be a self-contained offshore drilling and production facility located on an 

artificial gravel island with a pipeline to shore. Detailed information on the Project used in this 

work, is based primarily on the Liberty Development Plan by Hilcorp Alaska, Inc. 

Oil spill occurrence estimates were generated for the Project. Because sufficient historical data 

on offshore oil spills for this region do not exist, an oil spill occurrence model based on fault tree 

methodology was developed and applied. Using the fault trees, base data from the Gulf of 

Mexico and Pacific OCS as well as North Sea data on well control incidents including the 

variability of the data, were modified and augmented to represent expected Arctic offshore oil 

spillage frequencies. Because the proposed pipeline to shore is a pipe in pipe conduit and 

historical loss of containment data is very sparse, additional reliability analysis was conducted to 

generate loss of containment probabilities. 

Three principal spill occurrence indicators, as follows, were quantified for each year of each 

scenario, as well as scenario life of field averages: 

Spill frequency per 1,000 years 

Spill frequency per 109 barrels produced 

Spill index, the product of spill size and spill frequency 

These indicators were quantified for the following spill sizes: 

 Small (S): 50 - 99 bbl 

 Medium (M): 100 - 999 bbl 

 Large (L): 1,000 - 9,999 bbl 

 Huge (H): >= 10,000 bbl 

Quantification was carried out for each future year for the Project scenario, with a range of 

development parameters, in duration up to 25 years. In addition, a comparative scenario for nonArctic locations was formulated and analyzed for oil spill occurrence. Generally, it was found 

that the non-Arctic spill indicators were likely to be higher than those for similar scenarios in the 

Arctic. The computations were carried out using a Monte Carlo process to permit the inclusion 

of uncertainties in the base and scenario data and Arctic effects and resultants. A wide range of 

details for each scenario was generated, including the following: 

Expected time history of spill occurrences over the scenario life. 

Spill occurrence variations by spill volumes in the above spill size ranges. 

Spill occurrence variation by spill cause such as work boat anchoring or ice gouging. 

Spill occurrence contribution from each main facility type, including pipelines, the 

island, and wells. 

Comparison of spill occurrence predictions between Arctic and non-Arctic scenarios. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

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ii

Life of field averages of spill occurrence estimators. 

The variability in the results due to uncertainties in the inputs was expressed as 

cumulative distribution functions and statistical measures. 

In this final report, a detailed description of the methodology, results, and conclusions and 

recommendations is given, as well as a section on constraints of the study. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

iii

ACKNOWLEDGEMENTS 

Grateful acknowledgement for funding and direction is made to BOEM, Alaska OCS Region. In 

particular, the following BOEM personnel are acknowledged together with their roles: 

Heather Crowley, Contracting Officer’s Representative Advisor 

Rebecca Kruse, Contracting Officer 

This work was carried out by Bercha International Inc (Bercha). Key Bercha personnel on the 

project team were as follows: 

Dr. Frank G. Bercha, Project Manager and Principal Engineer 

Milan Cerovšek, Reliability Engineering Specialist 

Wesley Abel, Offshore Engineering Specialist 

Susan Bercha, Editorial and Word Processing Manager 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

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EXECUTIVE SUMMARY 

A. Introduction 

The United States Department of the Interior, Bureau of Ocean Energy Management (BOEM) 

Alaska Outer Continental Shelf (OCS) Region uses oil spill occurrence estimates for National 

Environmental Policy Act assessments for all parts of their area of assessment, ranging from near 

shore through shallow water, to deeper water. Although land to 3 nautical miles is not within 

BOEM jurisdiction, it is included in the BOEM environmental impact analysis; hence it is also 

included in the study area here. 

B. Summary of Work Done 

Oil spill occurrence estimates were generated for the proposed offshore drilling and production 

facility located on an artificial gravel island with a pipeline to shore at the Liberty prospect (the 

Project), located in the South Beaufort Sea in the landfast ice zone, inside the barrier islands, 

approximately 9 km (5 miles) offshore. Because sufficient historical data on offshore oil spills 

for this region do not exist, an oil spill occurrence model based on fault tree methodology was 

developed and applied. Using the fault trees, base data from the Gulf of Mexico and Pacific OCS 

and, for losses of well control also from the North Sea, including the variability of the data, were 

modified and augmented to represent expected Arctic offshore oil spillage frequencies. Because 

the proposed subsea pipeline is a pipe-in-pipe, for which historical data are not available, a 

reliability analysis was carried out to develop loss of containment frequencies applicable to 

pipeline. 

Three principal spill occurrence indicators, as follows, were quantified for each year of each 

scenario, as well as scenario life of field averages: 

Spill frequency per 1,000 years 

Spill frequency per 109

 barrels produced 

Spill index, the product of spill size and spill frequency 

These indicators were quantified for the following spill sizes: 

 Small (S): 50 - 99 bbl 

 Medium (M): 100 - 999 bbl 

 Large (L): 1,000 - 9,999 bbl 

 Huge (H): >= 10,000 bbl 

Quantification was carried out for each future year for the Project scenario, with a range of 

development parameters, in duration up to 25 years. In addition, a comparative scenario for nonArctic locations was formulated and analyzed for oil spill occurrence. Generally, it was found 

that the non-Arctic spill indicators were likely to be higher than those for similar scenarios in the 

Arctic. The computations were carried out using a Monte Carlo process to permit the inclusion 

of uncertainties in the base and scenario data and Arctic effects. A wide range of details for each 

scenario was generated, including the following: 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

v

 Expected time history of spill occurrences over the scenario life. 

Spill occurrence variations by spill volumes in the above spill size ranges. 

Spill occurrence variation by spill cause such as work boat anchoring or ice gouging. 

Spill occurrence contribution from each main facility type, including pipelines, the 

island, and wells. 

Comparison of spill occurrence predictions between Arctic and non-Arctic scenarios. 

Life of field averages of spill occurrence estimators. 

The variability in the results due to uncertainties in the inputs was expressed as 

cumulative distribution functions and statistical measures. 

In this final report, a detailed description of the Project, the methodology, results, and 

conclusions and recommendations is given, as well as a section on constraints of the study. 

C. Conclusions 

C.1 General Conclusions 

Oil spill occurrence indicators were quantified for the proposed Liberty Development Project 

(the Project) in the south Beaufort Sea. The quantification included the consideration of the 

variability of historical and future scenario data, as well as that of Arctic effects in predicting oil 

spill occurrence indicators. Consideration of the variability of all input data yields both higher 

variability and a higher expected value of the spill occurrence indicators. The three types of spill 

occurrence indicators were: annual oil spill frequency, annual oil spill frequency per billion 

barrels produced, and annual spill index – additionally, the Project year 15 and life of field 

(LOF) averages for each of these three oil spill indicators were assessed. 

C.2 Oil Spill Occurrence Indicators by Spill Size and Source 

How do spill indicators for the Project scenario and for its non-Arctic counterpart vary by spill 

size and source? Table C.1 summarizes the Life of Field average spill indicator values by spill 

size and source. The following can be observed: 

Spill frequency per 103 years and per 109 barrels produced decreases with increasing spill 

size for all Arctic and non-Arctic scenarios. 

The spill index increases with spill size for all Arctic and non-Arctic scenarios. 

All non-Arctic scenario spill indicators are greater than their Arctic counterparts. 

The island contributes the most (82%) to the two spill frequency indicators. 

Pipelines are second in relative contribution to spill frequencies (15%). 

Wells are the lowest contributors to frequency indicators (4%) but highest contributors to 

spill index (83%) 

It can be concluded that the island is likely to have the most, but smaller spills, while 

wells will have the least number but larger spills. Pipelines will be in between, with more 

spills than wells. 

Table C.2 gives the contributions to spill indicators for substantial (>=1,000 bbl) spills only; 

although trends are similar, the contribution percentages are different. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

vi

Table C.1 

Summary of Life of Project Field Average Spill Indicators by Spill Source and Size 

Liberty Liberty Non Arctic 

Spill Indicators 

LOF Average 

Spill 

Frequency 

per 103 years 

Spill 

Frequency 

per 109 bbl 

produced 

Spill 

Index 

(bbl) 

Spill 

Frequency 

per 103

years 

Spill 

Frequency 

per 109 bbl 

produced 

Spill Index 

(bbl) 

Small and Medium Spills 1.947 0.397 0.867 3.397 0.692 1.512 

50-999 bbl 87% 87% 6% 89% 89% 8% 

Large Spills 0.160 0.033 0.859 0.253 0.052 1.353 

1,000-9,999 bbl 7% 7% 6% 7% 7% 7% 

Huge Spills 0.123 0.025 12.133 0.178 0.036 15.447 

=>10,000 bbl 6% 6% 88% 5% 5% 84% 

Substantial Spills 0.283 0.058 12.992 0.431 0.088 16.799 

=>1,000 bbl 13% 13% 94% 11% 11% 92% 

2.230 0.454 13.859 3.827 0.780 18.311 All Spills 100% 100% 100% 100% 100% 100% 

0.331 0.067 0.830 0.640 0.130 1.537 Pipeline Spills 15% 15% 6% 17% 17% 8% 

1.818 0.370 1.457 3.087 0.629 2.297 Island Spills 82% 82% 11% 81% 81% 13% 

0.080 0.016 11.572 0.100 0.020 14.476 Well Spills 4% 4% 83% 3% 3% 79% 

1.898 0.387 13.029 3.187 0.649 16.773 Island and Well Spills 85% 85% 94% 83% 83% 92% 

2.230 0.454 13.859 3.827 0.780 18.311 All Spills 100% 100% 100% 100% 100% 100% 

Table C.2 

Summary of Life of Project Spill Indicators for Substantial Spills by Facility and Well Type 

Spill Source Liberty 

LOF Average 

Substantial Spills 

=> 1,000 bbl 

Spill Frequency 

per 103 years 

Spill Frequency 

per 109 bbl 

produced 

Spill Index 

(bbl) 

0.100 0.020 0.740 Pipeline 35% 35% 6% 

0.123 0.025 0.691 Island 43% 43% 5% 

0.060 0.012 11.562 Wells 21% 21% 89% 

0.183 0.037 12.252 Island and Wells 65% 65% 94% 

0.283 0.058 12.992 All 100% 100% 100% 

0.027 0.005 5.092 Production Wells 

44% 44% 44% 

0.034 0.007 6.469 Development Wells Drilling 56% 56% 56% 

0.060 0.012 11.562 All Wells 100% 100% 100% 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

vii

C.3 The Variance of Oil Spill Occurrence Indicators 

A Monte Carlo analysis of the Project annual and Life of Field average spill indicators was 

conducted to evaluate the effects of input uncertainties on these indicators. The Cumulative 

Distribution Functions (CDF) presented in the report contain extensive information on the 

statistical properties of the spill indicators. Generally, the following can be observed from the 

analysis: 

 The variance of the frequency spill indicators (frequency and frequency per barrel produced) 

generally decreases as spill size increases for pipelines and the island. For example, pipeline 

huge spills are less variable than small, medium, or large spills. For the island, small and 

medium spills are more variable than large and huge spills. 

 For wells, huge spills show greater variance than smaller ones. 

 For all facilities, the frequency spill indicators for small and medium spills show 

significantly more variability than those for large and huge spills. 

 The variability of the spill index for the pipeline, unlike the frequency spill indicators, shows 

a greater variance for large and huge spills than for small and medium spills. The opposite 

occurs for the island (ie, small and medium spills are the most variable). 

 For wells, the variance in huge spills spill index dominates. There is very little variance in 

large, medium, and small spills. 

 For all facilities, the spill index for huge spills is more variable than for smaller spills. 

D. The Methodology and its Applicability 

An analytical tool for the prediction of oil spill occurrence indicators for systems without 

history, such as future offshore oil production developments in the Beaufort Sea, has been 

developed based on the utilization of fault tree methodology. Although the results generated are 

voluminous, they are essentially transparent, simple, and easy to understand. The analytical tool 

developed is also quite transparent, very efficient in terms of computer time and input-output 

capability. In addition, the predictive model is setup so that input variables can be entered as 

distributions to yield result distributions. 

A wealth of information that can be utilized for the optimal planning and regulation of future 

developments is generated by the analytical tool. Key aspects of the analytical tool capability 

may be summarized as follows: 

Ability to generate expected and mean values as well as their variability in rigorous 

numerical statistical format. 

Use of verifiable input data based on BSEE and BOEM or other historical spill data and 

statistics. 

Ability to independently vary the impacts of different causes on the spill occurrences as well 

as add new causes such as some of those that may be expected for the Arctic or other new 

environments. 
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Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

viii

Ability to generate spill occurrence indicator characteristics such as annual variations, 

facility contributions, spill size distributions, and life of field (LOF) averages. 

Ability to generate comparative spill occurrence indicators such as those of comparable 

scenarios in more temperate regions. The model developed provides a basis for estimating 

each Arctic effect’s importance through sensitivity analysis as well as propagation of 

uncertainties. 

Capability to quantify uncertainties rigorously, together with their measures of variability. 

E. Suggested Improvement to the Methodology and Results 

During the work, a number of areas were identified where future improvements could be made, 

including: the input data, the scenarios, the application of the fault tree methodology, and finally 

the oil spill occurrence indicators themselves have been identified. These suggestions are 

summarized in the following paragraphs. 

Two categories of input data were used; namely the historical spill data and the Arctic effect 

data. Although a verifiable and optimal historical spill data set has been used, the following 

shortcomings may be noted: 

Gulf of Mexico and Pacific (OCS) historical databases were compiled by BSEE and BOEM 

for pipelines and facilities, and were used as a starting point for the fault tree analysis. 

Although these data are adequate, a broader population base would be expected to give more 

robust statistics. For well loss of well control (LOWC) data, both the BSEE and BOEM and 

the proprietary SINTEF data were used, providing a wider data sample. 

The Arctic effects include modifications in causes associated with the historical data set as 

well as additions of spill causes unique to the Arctic environment. Quantification of existing 

causes for Arctic effects on historical statistics was done in a relative cursory way restricted 

to engineering judgment. However, the additive or Arctic unique effects, were evaluated 

more rigorously. 

Upheaval buckling effect assessments were included on the basis of professional judgment 

used in previous studies; no engineering analysis was carried out for the assessment of 

frequencies for Beaufort Sea locations to be expected for these effects. 

The following comments can be made on constraints associated with the indicators that have 

been generated: 

The model generating the indicators is fundamentally a linear model which ignores the 

effects of scale, of time variations such as the learning and wear-out curves (Bathtub curve), 

climate change, and production volume non-linear effects. 

With current methodology, the likelihood of different spill size distributions is assumed 

constant throughout all production years even though the production decreases from 

approximately 60,000 barrels per day (BPD) to 2,000 BPD over the project life cycle. One 

can speculate that the potential for Large and Huge spills varies together with the production 

rate. Although this was not investigated in this study, it is recommended that it be addressed 

in future studies due to the large variation in production volumes from start to end of 

production. However, as done here, the results are conservative. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

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ix

F. Recommendations 

The following recommendations based on the work may be made: 

Continue to utilize the Monte Carlo spill occurrence indicator model for new Arctic OCS 

scenarios to support BOEM needs, as it is currently the best predictive spill occurrence 

model available. 

Utilize the oil spill occurrence indicator model to generate additional model validation 

information, including direct application to existing non-Arctic scenarios, such as GOM and 

PAC projects, which have an offshore oil spill statistical history. 

Utilize the oil spill occurrence indicator model in a sensitivity mode to identify the 

importance of different Arctic effect variables introduced to provide a prioritized list of those 

items having the highest potential impact on Arctic oil spills. 

Generalize the model so that it can be run both in an adjusted expected value and a 

distributed value (Monte Carlo) form with the intent that expected value form can be utilized 

without the Monte Carlo add-in for preliminary estimates and sensitivity analyses, while for 

more comprehensive rigorous studies, the Monte Carlo version can be used 

Conduct calculations of the spill indicators as a function of the variable annual oil production 

rates as spill size and frequency distributions are likely to be a function of these variable 

production rates. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

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TABLE OF CONTENTS 

CHAPTER PAGE 

Abstract................................................................................................................................ i 

Acknowledgements............................................................................................................. iii 

Executive Summary.............................................................................................................iv 

Table of Contents .................................................................................................................x 

List of Tables..................................................................................................................... xii 

List of Figures.................................................................................................................. xiii 

Glossary of Terms and Acronyms......................................................................................xv 

1 Introduction ........................................................................................... 1.1 

1.1 General Introduction.............................................................................................1.1 

1.2 Study Objectives ...................................................................................................1.2 

1.3 Project Overview ..................................................................................................1.3 

1.4 Analysis Background............................................................................................1.5 

1.5 Technical Approaches...........................................................................................1.5 

1.6 Scope of Work ......................................................................................................1.6 

1.7 Work Organization................................................................................................1.7 

1.8 Outline of Report ..................................................................................................1.9 

2 Historical Data and Statistics .................................................................. 2.1 

2.1 Approaches to Historical Data..............................................................................2.1 

2.2 Pipeline Spills .......................................................................................................2.1 

2.3 Pipe in Pipe (PIP) Spills........................................................................................2.3 

2.4 Platform Spills ......................................................................................................2.6 

2.5 Loss of Well Control (LOWC) Data.....................................................................2.7 

2.6 Arctic Effects Statistics.........................................................................................2.9 

2.6.1 General Approaches to the Quantification of Arctic Effects ....................2.9 

2.6.2 Ice Gouging...............................................................................................2.9 

2.6.3 Strudel Scour...........................................................................................2.10 

2.6.4 Upheaval Buckling..................................................................................2.11 

2.6.5 Thaw Settlement......................................................................................2.12 

2.6.6 Summary of Pipeline Arctic Unique Effects ...........................................2.12 

2.6.7 Platform Arctic Unique Effects...............................................................2.12 

2.7 Historical Spill Size Distribution........................................................................2.13 

3 Liberty Development Project Information ............................................ 3.1 

3.1 Liberty Project Summary......................................................................................3.1 

3.2 Liberty Drilling and Production Island (LDPI) ....................................................3.4 

3.3 Oil and Gas Wells .................................................................................................3.7 

3.4 Subsea Oil Pipeline...............................................................................................3.9 

3.5 The Project .....................................................................................................3.11 
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4 Fault Tree Analysis for Arctic Oil Spill Frequencies............................ 4.1 

4.1 General Description of Fault Tree Analysis .........................................................4.1 

4.2 Fault Tree Methodology .......................................................................................4.1 

4.2.1 Fault Tree Analysis Basics .......................................................................4.1 

4.2.2 Current Application of Fault Trees ..........................................................4.3 

4.2.3 Monte Carlo Simulation............................................................................4.5 

4.2.4 Distribution Derived from Historical Data for Monte Carlo Analysis ....4.7 

4.2.5 Approaches to Assessment of Arctic Spill Frequency Variability ............4.9 

4.3 Pipeline Fault Tree Analysis.................................................................................4.9 

4.3.1 Arctic Pipeline Spill Causal Frequency Distributions .............................4.9 

4.3.2 Arctic Pipeline Fault Tree Frequency Calculations...............................4.11 

4.4 Island Fault Tree Analysis ..................................................................................4.15 

4.4.1 Arctic Island Spill Causal Frequency Distributions...............................4.15 

4.4.2 Arctic Island Fault Tree Spill Frequency Calculations..........................4.15 

4.5 Loss of Well Control (LOWC) Arctic Frequency Analysis ...............................4.19 

4.5.1 LOWC Arctic Effects...............................................................................4.19 

4.5.2 Arctic LOWC Spill Frequency Calculation ............................................4.19 

4.6 Spill Volume Distributions .................................................................................4.19 

5 Oil Spill Occurrence Indicator Quantification...................................... 5.1 

5.1 Definition of Oil Spill Occurrence Indicators.......................................................5.1 

5.2 Oil Spill Occurrence Indicator Calculation Process .............................................5.1 

5.3 Summary of Project Oil Spill Occurrence Indicators ...........................................5.2 

5.3.1 Project Oil Spill Occurrence Indicators...................................................5.2 

5.3.2 Comparative Non-Arctic Indicator Assessment.....................................5.17 

5.4 Summary of Representative Oil Spill Occurrence Indicator Results .................5.19 

6 Conclusions and Recommendations ....................................................... 6.1 

6.1 Conclusions .......................................................................................................6.1 

6.1.1 General Conclusions.................................................................................6.1 

6.1.2 Oil Spill Occurrence Indicators by Spill Size and Source........................6.1 

6.1.3 The Variance of Oil Spill Occurrence Indicators.....................................6.6 

6.2 Conclusions on the Methodology and Its Applicability .....................................6.10 

6.3 Suggested Improvements to the Methodology and Results................................6.11 

6.4 Recommendations...............................................................................................6.12 

References........................................................................................................ R.1 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

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LIST OF TABLES 

TABLE PAGE 

2.1 Analysis of GOM and PAC OCS Pipeline Spill Data for Causal Distributions and 

 Spill Size (1972-2010) ..........................................................................................2.2 

2.2 Distribution and Frequency of Historical Pipeline Spills (1972-2010) ................2.2 

2.3 GOM and PAC OCS Pipeline Spills Statistics Summary (1972-2010)................2.3 

2.4 PIP Small and Medium Spill Frequency Derivation ............................................2.4 

2.5 PIP Large and Huge Spill Frequency Derivation .................................................2.5 

2.6 PIP Pipeline Spill Frequency Distribution Properties ..........................................2.5 

2.7 Analysis of GOM and PAC OCS Platform Spill Data by Causal Distribution 

 and Spill Size (1972-2010) ...................................................................................2.6 

2.8 Causal and Spill Size Distribution of GOM and PAC OCS Platform Spills 

 (1972-2010) .....................................................................................................2.7 

2.9 Platform Historical Spill Frequency Variability (1972-2010)..............................2.7 

2.10 Well LOWC Historical Spill Size Distribution (1980 - 2011) .............................2.8 

2.11 Well LOWC Historical Spill Probability and Size Variability (1980 - 2011)......2.8 

2.12 Liberty Pipeline Ice Gouging Frequency Calculation ........................................2.10 

2.13 Liberty Pipeline Strudel Scour Frequency Calculation ......................................2.11 

2.14 Summary of PIP Pipeline Arctic Unique Effect Inputs ......................................2.11 

2.15 Summary of Platform Unique Arctic Effect Inputs ............................................2.12 

2.16 Historical Pipeline Spill Volume Distribution Parameters.................................2.13 

2.17 Historical Platform Spill Volume Distribution Parameters ................................2.13 

2.18 Historical LOWC Spill Volume Distribution Parameters ..................................2.13 

3.1 LDPI Plan (Figure 3.4) Facility Description ........................................................3.6 

3.2 Subsea Pipeline Properties....................................................................................3.9 

3.3 Drilling and Production Schedule.......................................................................3.12 

4.1 PIP Pipeline Spill Frequency Distribution Properties ..........................................4.8 

4.2 Island Spill Frequency Distribution Properties.....................................................4.8 

4.3 LOWC Frequency Distribution Properties ...........................................................4.8 

4.4 PIP Pipeline Arctic Effect Derivation Summary ................................................4.10 

4.5 PIP Pipeline Arctic Effect Causal Distribution Derivation Summary................4.12 

4.6 Expected Value Summary of Arctic PIP Pipeline Spill Frequencies .................4.14 

4.7 Island Arctic Effect Derivation Summary ..........................................................4.16 

4.8 Arctic Island Effect Distribution Derivation Summary......................................4.16 

4.9 Arctic Island Spill Frequency Expected Value Summary ..................................4.18 

4.10 LOWC Fault Tree Analysis Arctic Effect Summary..........................................4.19 

4.11 Arctic LOWC Frequencies .................................................................................4.20 

4.12 Pipeline Spill Volume Parameters ......................................................................4.21 

4.13 Island Spill Volume Parameters .........................................................................4.21 

4.14 LOWC Spill Volume Parameters........................................................................4.22 

5.1 Project Year 15 – Monte Carlo Results ................................................................5.9 

5.2 Composition of Project Spill Indicators – Life of Field Average.......................5.11 

5.3 Summary of Spill Indicators for All Scenarios...................................................5.15 

6.1 Summary of Life of Project Field Average Spill Indicators by Spill Source and Size6.2 

6.2 Summary of Life of Project Spill Indicators for Substantial Spills by Facility 

 and Well Type .......................................................................................................6.2 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

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LIST OF FIGURES 

FIGURE PAGE 

1.1 Project Location Map............................................................................................1.2 

1.2 Project Detailed Location Map.............................................................................1.4 

1.3 Calculation Flow Chart.........................................................................................1.8 

3.1 Project Location Map............................................................................................3.2 

3.2 Project Detailed Location Map.............................................................................3.3 

3.3 Rendering of LDPI................................................................................................3.4 

3.4 Plan of LDPI and Facilities...................................................................................3.5 

3.5 Block Diagram of Oil Production System ............................................................3.7 

3.6 Project Drilling Schedule......................................................................................3.8 

3.7 Subsea Pipeline Cross Section............................................................................3.10 

4.1 Fault Tree Basics ..................................................................................................4.2 

4.2 Example of Fault Tree to Transform Historical (GOM and PAC) to Arctic Spill 

 Frequencies .......................................................................................................4.4 

4.3 Monte Carlo Technique Schematic.......................................................................4.6 

4.4 Spill Frequencies for Arctic PIP Pipeline...........................................................4.13 

4.5 Expected Value Summary of Arctic PIP Pipeline Spill Frequencies .................4.14 

4.6 Spill Frequencies Liberty Island Fault Tree .......................................................4.17 

4.7 Arctic Island Spill Frequency Expected Value Bar Chart ..................................4.18 

4.8 Drilling LOWC Frequencies...............................................................................4.20 

4.9 Production Well LOWC Frequencies .................................................................4.21 

5.1 Calculation Flow Chart.........................................................................................5.2 

5.2 Project Spill Frequency per 1,000 Years ..............................................................5.3 

5.3 Project Spill Frequency per 109 Barrels Produced................................................5.4 

5.4 Project Spill Index ................................................................................................5.4 

5.5 Project Spill Indicators – Pipeline ........................................................................5.5 

5.6 Project Spill Indicators – Island............................................................................5.6 

5.7 Project Spill Indicators – Wells ............................................................................5.7 

5.8 Project Spill Indicator Distributions – Year 15 ..................................................5.10 

5.9 Project Life of Field Average Spill Frequency Variability.................................5.12 

5.10 Project Life of Field Average Spills per 109

 Barrels Produced ..........................5.13 

5.11 Project Life of Field Average Spill Index Variability ........................................5.14 

5.12 Project Life of Field Spill Indicators - By Spill Size..........................................5.16 

5.13 Project Life of Field Spill Indicators- By Source Composition..........................5.16 

5.14 Arctic and Non-Arctic Project Spill Frequency..................................................5.17 

5.15 Arctic and Non-Arctic Project Spill Frequency per 109

 Barrels Produced ........5.18 

5.16 Arctic and Non-Arctic Project Spill Index .........................................................5.18 

5.17 Project – Year 15 – Spill Indicator Composition by Source and Spill Size .......5.21 

5.18 Project – Life of Field Average Spill Indicator Composition by Source and Spill Size..5.22 
Liberty Final Report – P1508 

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BOEM May 2016 

xiv

6.1 Project Life of Field Spill Indicators – By Spill Size ...........................................6.3 

6.2 Project Life of Field Spill Indicators – By Source Composition..........................6.3 

6.3 Project – Year 15 – Spill Indicator Composition by Source and Spill Size .........6.4 

6.4 Project – Life of Field Average Spill Indicator Composition by Source 

 and Spill Size .......................................................................................................6.5 

6.5 Project Life of Field Average Spill Frequency Variability...................................6.7 

6.6 Project Life of Field Average Spills per 109

 Barrels Produced Variability..........6.8 

6.7 Project Life of Field Average Spill Index Variability ..........................................6.9 
Liberty Final Report – P1508 

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xv

GLOSSARY OF TERMS AND ACRONYMS 

Bbbl Billion Barrels

BOEM Bureau of Ocean Energy Management, Department of the Interior

BOP Blowout Preventer

BPD Barrels Per Day

BSEE Bureau of Safety and Environmental Enforcement, Department of 

the Interior 

CDF Cumulative Distribution Function 

Consequence The direct effect of an accidental event. 

DPP Development and production plan

GOM Gulf of Mexico OCS

Hazard A condition with a potential to create risks such as accidental 

leakage of natural gas from a pressurized vessel 

MMbbl Million Barrels 

LDPI Liberty drilling and production island

LOC Loss of Containment

LOF Life of Field

LOFn Loss of Function 

LOWC Loss of Well Control 

MMS Minerals Management Service. On October 1, 2011, the Bureau of Ocean 

Energy Management, Regulation and Enforcement (BOEMRE), formerly the Minerals 

Management Service (MMS), was replaced by the Bureau of Ocean Energy Management 

(BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) as part of a 

major reorganization

Monte Carlo A numerical method for evaluating algebraic combinations of 

statistical distributions. 

OCS Outer Continental Shelf

PAC Pacific OCS 

PIP Pipe in pipe

QRA Quantitative Risk Assessment 
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xvi

Risk A compound measure of the probability and magnitude of adverse 

effect. 

RLS Release 

SINTEF The Foundation for Scientific and Industrial Research at the 

Norwegian Institute of Technology 

Spill Frequency The number of spills of a given spill size range per year. Usually 

expressed as spills per 1,000 years (and so indicated). 

Spill Frequency per 

Barrel Produced 

 The number of spills of a given spill size range per barrel 

produced. Usually expressed as spills per billion barrels produced 

(and so indicated). 

Spill Index The product of spill frequency for a given spill size range and the 

mean spill size for that spill size range. 

Spill Occurrence Characterization of an oil spill as an annual frequency and 

associated spill size or spill size range. 

Spill Occurrence 

Indicator 

 Any of the oil spill occurrence characteristics; namely, spill 

frequency, spill frequency per barrel produced, or spill index 

(defined above). 

Spill Sizes Small (S): 50 - 99 bbl 

Medium (M): 100 - 999 bbl 

Large (L): 1,000 - 9,999 bbl 

Huge (H): >=10,000 bbl 

Substantial >=1,000 bbl 
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BOEM May 2016 

1.1

CHAPTER 1 

INTRODUCTION 

1.1 General Introduction

The United States Department of the Interior, Bureau of Ocean Energy Management 

(BOEM) Alaska Outer Continental Shelf (OCS) Region uses oil spill occurrence 

estimates for National Environmental Policy Act assessments for all parts of their area of 

assessment, ranging from nearshore through shallow water, to deeper water. Although 

land to 3 nautical miles is not within BOEM jurisdiction, it is included in the BOEM 

environmental impact analysis; hence it is also included in the study area here. In 2002, 

2006, 2008, and 2014 studies were carried out by Bercha International Inc. [13, 16, 17, 

18, 19] * to assess and quantify oil spill occurrence indicators for the Chukchi and 

Beaufort seas. In the present study, the latest methodologies based on fault tree analysis 

developed for the assessment of oil spill rates associated with exploration and production 

facilities and operations in OCS Arctic waters [13] are applied to a specific Scenario; 

namely, the Liberty Development Project, hereinafter called the Project. 

The prediction of the reliability (or failure) of systems without history can be approached 

through a variety of mathematical techniques, with one of the most preferable and 

accepted being fault trees [1, 6, 10, 23, 32, 61], and their combination with numerical 

distribution methods such as Monte Carlo simulation [6, 16]. In the previous studies [13, 

16, 17], fault tree methodology was applied to the prediction of oil spill rates for oil and 

gas developments in the Beaufort and Chukchi Sea. 

As there are limited offshore Arctic oil spill occurrences, associated data worldwide and 

from the Gulf of Mexico (GOM) and Pacific (PAC) OCS data [15] were used as a 

starting point to develop a simulation model of oil spill occurrence probabilities. The 

model for non-Arctic occurrence probabilities was then modified to include Arctic effects 

and their variabilities. In the early studies [19], variability in the non-Arctic input data 

was considered; but variability of the future development scenario physical facility 

parameters, such as miles of subsea pipeline, was not considered. In the present study, as 

well as in the preceding fault tree studies [13, 16] both the historical data variability and 

that of the future development scenario characteristics is included in calculation of oil 

spill occurrence probabilities. 

The present document deals with the evaluation of oil spill potential associated with a 

possible development at the Liberty prospect (the Project), generally located in the South 

Beaufort Sea in the landfast ice zone, inside the barrier islands, approximately 9 km (5 

miles) offshore as shown in Figure 1.1. Information on the Project used in this work, 

including Figure 1.1, is based primarily on the Liberty Development Plan by Hilcorp 

Alaska, Inc. [28]. 

 

*

 Numbers in square brackets refer to citations listed in the “References” section of this report. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC0013 

BOEM May 2016 

1.2

Figure 1.1: Project Location Map [28]

1.2 Study Objectives 

The Contractor for this work, Bercha International Inc. (Bercha), has the principal 

objective to conduct a fault tree analysis and associated outputs as generally described 

below, using the Liberty Development and production plan (DPP) information [28]. 

Improvements to fault tree methodology, any revisions in Arctic and GOM spill 

occurrence factors developed and provided by Contractor are to be included. The work is 

to include the quantification of robustness of the statistics and predictions, (Confidence 

Limits on spill occurrence estimates), and precision or variance of estimates. Spill 

occurrence rates (occurrence rates) for multiple size ranges of crude and diesel spills 

should be projected. The primary focus should be in terms of the number of spills of at 

least 1,000 bbl that is projected to occur. Generation of life-of-field spill occurrence 

estimators and spill occurrence estimators converted to number of spills per billion 

barrels produced over the life of the development and production scenario shall be 

included. 
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BOEM May 2016 

1.3

The specific objectives of this study are as follows: 

 Assimilate North Sea and U.S. OCS oil spill statistics [14, 15], and evaluate their 

applicability to the Project. 

 Develop the fault trees for estimating oil spill occurrences from the proposed Project 

associated with spills of different size categories. 

 Using the fault tree approach in a Monte Carlo simulation, develop alternative oil 

spill indicators and assess their variability, including effect of variability of both the 

historical data and the future development scenario parameters. 

 Evaluate the variability of alternative oil spill indicators for a similar development 

scenario in a non-Arctic location. 

1.3 Project Overview 

The Project location is the Beaufort Sea Outer Continental Shelf (OCS) as generally 

illustrated in Figure 1.1. Of interest is the offshore area from landfall to approximately 

the 6 m (19 feet) isobaths 

The Project will be a self-contained offshore drilling and production facility located on an 

artificial gravel island with a buried pipeline to shore. As shown in Figure 1.1, the island 

will be located approximately 9 km (5.5 miles) offshore in Foggy Island Bay of the 

Beaufort Sea OCS in approximately 6 meters (19 feet) of water, roughly 3.2 km (2 miles) 

west of the Tern Island shoal. A subsea pipeline from the island to shore, and then 

onshore to the Badami pipeline will deliver the produced crude oil. Figure 1.2 shows the 

pipeline route from the island to shore and to the Badami pipeline. 

The Project and its principal functional Project components described and analyzed in the 

present study are: 

 The Liberty drilling and production island (LDPI) 

 Oil and gas wells 

 The subsea pipeline 

 The Project as integrated 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC0013 

BOEM May 2016 

1.4

 

Figure 1.2: Project Detailed Location Map [28] 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC0013 

BOEM May 2016 

1.5

Following the review phase, the Project execution schedule [28 (Executive Summary, 

Section 3)] includes the following principal milestones: 

 Year 1: Start 2017 estimated 

 Year 2-5: Island, facilities, and pipeline construction. 

 Year 3-5: Drilling operations

 Year 4-5: Production operations startup 

 Year 4-25: Oil production 

 Year 25: End of oil production 

1.4 Analysis Background 

The final reports [13, 16, 17, 18, 19] described the methodology and results of the Bercha 

fault tree method for the evaluation of oil spill occurrence estimators for the Beaufort and 

Chukchi seas. The focus of the first report [19] was on the initial development of a fault 

tree method to model both non-Arctic GOM spill causes as well as Arctic causes and 

effects that would be encountered in the Beaufort and Chukchi Seas OCS Regions. The 

variability of the parameters associated with Arctic effects was developed in order to 

provide an estimate of the variance in the spill occurrence predictions resulting directly 

from variances in the Arctic effects. In addition, in 2006 [17, 18] and 2008 [16], and 2014 

[13], variance in the Gulf of Mexico (GOM) and other historical data was incorporated. 

In the most recent reports [13, 16], the variability of the future development scenario 

parameters is also considered. In the present study, all variances are considered in a 

manner analogous to that of the October 2014 [13] study. These variances were 

numerically incorporated through the use of Monte Carlo simulation for the fault tree 

model numerical predictions. 

1.5 Technical Approaches 

Uncertainties in the results of oil spill occurrence predictions generated in this study can 

be attributed to uncertainties in input data, scenario characterization, and the occurrence 

model. In the original 2002 study [19], uncertainties in input data were quantified for the 

Arctic effects only. Uncertainties in the scenario were included through the choice of 

scenarios representing the expected and maximum development levels. In the 2014 

Chukchi Sea Lease Sale 193 study [13], uncertainties in the non-Arctic input data were 

also included. Thus the principal sources of uncertainty in the occurrence results were 

those caused by uncertainties in both the Arctic and non-Arctic input parameters. 

The non-Arctic input parameters fall under two principal categories as follows: 

 Spill frequencies 

 Spill volumes 
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Oil Spill Occurrence Estimators BOEM Contract No.: M11PC0013 

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1.6

These spill frequencies and volumes as used in the study were derived from the following 

principal sources: 

 Pipeline spills – GOM and PAC OCS data and PIP reliability analysis 

 Platform spills – GOM and PAC OCS data 

 Well (drilling and production) Loss of Well Control (LOWC) spills – GOM and 

North Sea data 

Because the subsea pipeline proposed [28] is a pipe in pipe (PIP) or double walled 

pipeline, and no applicable historical date for such pipelines are available, it was 

necessary to also conduct a reliability analysis for subsea PIP containment failure rates 

and release size distributions for input into the fault tree analysis. 

The specific sources of all data and the PIP reliability analysis are described in detail in 

Chapter 2 of this report. The inclusion of variability of the input data, including Arctic 

effects, is intended to provide a realistic estimate of the spill occurrence indicators and 

their resultant variability. 

The following main facility parameters were used as expected values: 

 Number of wells drilled 

 Number of production wells 

 Subsea pipeline length 

1.6 Scope of Work 

Task 1: Data Assimilation and PIP Reliability analysis 

a) Update of GOM and PAC pipeline and platform spill statistics [4, 

15]. 

b) Reliability analysis of PIP in GOM environment similar to that of 

pipeline historical data 

c) Loss of Well Control (LOWC) statistics [4, 14]. 

d) Assimilation and update of Project information [28]. 

Task 2: Development of Arctic Spill Frequency Causal Event and Total 

 Probability Distributions 

a) Development of Arctic spill frequency causal event probability 

distributions associated with pipeline spills. 

b) Development of Arctic spill frequency causal event probability 

distributions associated with platform spills. 

c) Development of Arctic spill frequency causal event probability 

distributions associated with well drilling and production well 

LOWCs. 
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Oil Spill Occurrence Estimators BOEM Contract No.: M11PC0013 

BOEM May 2016 

1.7

Task 3: Development of Non-Arctic Total Annual Spill Frequency and Volume 

 Probability Distributions 

a) Development of non-Arctic total annual spill frequency and 

volume distribution for pipeline. 

b) Development of non-Arctic total annual spill frequency and 

volume distribution for island. 

c) Development of non-Arctic total annual spill frequency and 

volume distribution for well drilling and production wells. 

Task 4: Generation of Oil Spill Occurrence Estimator Probability Distributions 

a) Variability in future development scenario parameters. 

b) Monte Carlo model runs for Arctic Project scenarios. 

c) Monte Carlo model runs for comparative non-Arctic scenario. 

Task 5: Reporting 

a) Preliminary results following completion of Tasks 1, 2, 3, and 4 in 

Technical Reports #1, 2, and 3. 

b) Draft Final Report and Final Report. 

1.7 Work Organization 

The present study consists of statistical and reliability investigations, followed by 

numerical simulation. Although the assimilation of historical and future scenario data is 

of key importance to the work, the salient contribution consisted primarily of the 

analytical work involving fault trees and oil spill occurrence indicator generation. 

Although the individual calculations are relatively simple, the subdivision of the 

calculations into realistic representative categories of facilities, spill sizes, and water 

depth for different variables in the scenario resulted in a relatively complex mix of 

computations, and they are generally illustrated in the flow chart in Figure 1.3. 

The flow chart in Figure 1.3, of course, does not show all the different combinations and 

permutations; rather, it indicates the typical calculations for one case, and suggests the 

balance by dotted lines. Moving from left to right; initially historical data were obtained 

for each of three principal facility categories, pipeline, platform (island in the figure), and 

wells. Wells were categorized in two ways: according to producing wells and the drilling 

of exploration and development wells. For each of the above facility subcategories, spill 

causes were analyzed for small, medium, large, huge, and substantial spills, defined as 

follows: 

 Small (S): 50 to 99 bbl 

 Medium (M): 100 to 999 bbl 

 Large (L): 1,000 to 9,999 bbl 

 Huge (H): >= 10,000 bbl 

 Substantial (SB): >= 1,000 bbl 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC0013 

BOEM May 2016 

1.8

Figure 1.3: Calculation Flow Chart 

Substantial spills, which are spills of 1,000 bbl or more (Large and Huge), are also 

identified. Fractional spill sizes were rounded up or down to the nearest whole number, 

with rounding up for any decimal ending in 5. For example, a spill of 99.5 bbl is taken as 

100 bbl; 99.42 is taken as 99 bbl. 

For well Loss of Well Control (LOWC) releases, one additional category of spill volumes 

is added: spills >= 150,000 bbl [4, 14]. 

In the interests of conciseness and clarity, the above main categories of spill sizes will 

generally be designated by either their name (small, medium, large, huge, substantial) or, 

when space is limited, by their acronym (S, M, L, H, and SB) in the balance of this 

report. 

The proposed Liberty future development scenario as defined in the DPP [28], as well as 

a comparable non-Arctic (hypothetical) scenario were analyzed. The hypothetical nonArctic scenario was developed for comparative purposes on the assumption that it was 

located with the same facility and water depth distribution as the Project in a non-Arctic 

area such as the GOM OCS. This permitted the comparison of the spill indicator results 

with and without the application of the fault tree analysis to account for Arctic effects. 

Fault Tree Analysis Hazard Scenarios Spill Occurrence

Spill Size

Frequency and Cause Arctic Spill Frequency Annual Annual 

Small Spill 50-99 bbl Shallow Water Frequency

Medium Spill 100-999 bbl Frequency per 109

 bbl Produced

Large Spill 1,000-9,999 bbl Spill Index 

Huge Spill >= 10,000 bbl LOF Average Frequency

Small and Medium Spills LOF Av Freq per 109

 bbl Produced

Large and Huge Spills LOF Average Spill Index

Small and Medium Spills

Large Spill 

Spill 10,000-149,999 bbl

Spill >=150,000 bbl

Exploration Well Drilling

Development Well Drilling

Production Well

Liberty Development

Non Arctic

Historical Data Analysis

Island

Liberty Development

Facility

Pipeline
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1.9

Finally, for each of the scenarios considered, four principal oil spill occurrence indicators 

were generated, as follows: 

 Oil spill frequency 

 Oil spill frequency per billion barrels produced 

 Spill index, which is the product of the oil spill frequency and the mean spill 

size (for the particular category under consideration) 

 Life of Field Average Indicators for each of the 3 indicator types above. 

1.8 Outline of Report 

Following this brief introductory chapter, Chapter 2 summarizes the historical data 

assimilation and analysis detailed in [14, 15] and the PIP reliability analysis, Chapter 3 

defines the Project development scenario used. Chapter 4 details the fault tree analysis to 

obtain Arctic oil spill frequencies. Chapter 5 summarizes the results of the oil spill 

occurrence indicator computations and their statistical distributions. Chapter 6 

summarizes conclusions and recommendations including a section on the benefits of, and 

future recommendations derived from the present study. Extensive references and 

bibliography are given in the References. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

2.1

CHAPTER 2 

HISTORICAL DATA AND STATISTICS 

2.1 Approaches to Historical Data 

Historical data on offshore oil spills from pipelines, platforms, and Loss of Well Control 

(LOWC) were utilized as a numerical starting point for predicting Arctic offshore oil spill 

characteristics. Because statistics on Arctic offshore oil spills do not exist, oil spill 

statistics for temperate offshore locations were utilized, and subsequently analytically 

adjusted to represent the Project Arctic conditions. Although Arctic offshore exploration 

and production was started in the early 1970s, operations have been sporadic, with very 

few spills, so that a statistical history cannot be generated [12, 27]. 

The following data sets or databases were utilized: 

(a) GOM and PAC OCS Pipeline Spills (1972-2010) 

(b) GOM and PAC OCS Platform Spills (1972-2010) 

(c) LOWC, GOM and North Sea Data (1980-2011) 

The GOM and PAC pipeline and platform statistics categories of data are discussed in 

detail in the GOM and PAC update report [15], while the LOWC data are based on the 

results of an ongoing BOEM analysis [14], summarized in the recently published paper 

[4]. The contents of the balance of this chapter are restricted to the presentation of only 

those data sets utilized in the present study. 

2.2 Pipeline Spills 

The pipeline spill statistics generated in this update are basic spill statistics. First, the 

number of spills by size occurring for each causal category is given. Next, spill causes by 

two principal spill size categories are given, and transformed to spill frequencies per 

kilometer-year by dividing the number of kilometer-years exposure. And finally, the spill 

frequency distribution for spills of different size categories, by pipe diameter is 

determined. Table 2.1 summarizes the spill occurrences by size for each of the principal 

causes reported in the Bureau of Safety and Environmental Enforcement (BSEE) 

database. Both the exact spill size in barrels and the spill size distribution by each of the 

spill size categories are given in Table 2.1. 

Table 2.2 gives the pipeline hydrocarbon spill statistics by cause. These statistics are 

given as the probability of occurrence per kilometer-year of operating pipeline. Thus, for 

example, approximately 13.44 spills per 100,000 km-yrs in the small and medium size 

category are projected. Of these, it is expected that approximately 6.7% or 0.90 per 

100,000 km-yrs can be attributed to pipe corrosion. 

Finally, Table 2.3 summarizes the pipeline spill statistics by spill size and pipe diameter. 
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2.2

Table 2.1 

Analysis of GOM and PAC OCS Pipeline Spill Data 

for Causal Distribution and Spill Size 

(1972-2010) 

Spill Size 

(bbl) Number of Spills 

Cause Classification 

Number 

of Spills 

1972-

2010 1 2 3 4 5 6 7 8 9 10 11 12 13 S M L H SM LH

CORROSION 4 1 2 1 3 1 

External 1 80 1 1 

Internal 3 100 5000 414 2 1 2 1 

THIRD PARTY IMPACT 20 2 7 8 3 9 11

Anchor Impact 13 19833 65 50 300 900 323 15576 2000 800 1211 2240 870 1500 2 5 4 2 7 6 

Jackup Rig or Spud 

Barge 2 200 3200 1 1 1 1 

Trawl/Fishing Net 5 4000 100 14423 4569 4533 1 3 1 1 4 

OPERATION IMPACT 4 3 1 3 1 

Rig Anchoring 1 50 1 1 

Work Boat Anchoring 3 50 5100 50 2 1 2 1 

MECHANICAL 3 3 3 

Connection Failure 2 135 150 2 2 

Material Failure 1 210 1 1 

NATURAL HAZARD 28 9 15 4 24 4 

Mud Slide 3 250 80 8212 1 1 1 2 1 

3500 1720 671 126 200 250 260 95 123 960 50 55 132 8 14 3 22 3 Storm/ Hurricane 25 50 75 100 862 67 108 69 108 56 1316 209 268 

UNKNOWN 3 119 190 188 3 3 

TOTALS 62 15 30 14 3 45 17

Table 2.2 

Distribution and Frequency of Historical Pipeline Spills (1972-2010) 

Small and Medium Spills 

50-999 bbl 

Large and Huge Spills 

>=1,000 bbl Cause Classification 

1972-2010 Historical 

Distribution 

(%) 

Number 

of Spills 

Exposure 

(km-years) 

Frequency 

(spill per 105

km-year) 

Historical 

Distribution

(%) 

Number 

of Spills 

Exposure 

(km-years) 

Frequency

(spill per 105

km-year) 

CORROSION 6.67 3 0.896 5.88 1 0.299 

External 2.22 1 0.299 0 0 0 

Internal 4.44 2 0.597 5.88 1 0.299 

THIRD PARTY IMPACT 20.00 9 2.688 64.71 11 3.286 

Anchor Impact 15.56 7 2.091 35.29 6 1.792 

Jackup Rig or Spud Barge 2.22 1 0.299 5.88 1 0.299 

Trawl/Fishing Net 2.22 1 0.030 23.53 4 1.195 

OPERATION IMPACT 6.67 3 0.896 5.88 1 0.299 

Rig Anchoring 2.22 1 0.299 

Work Boat Anchoring 4.44 2 0.597 5.88 1 0.299 

MECHANICAL 6.67 3 0.896 

Connection Failure 4.44 2 0.597 

Material Failure 2.22 1 0.299 

NATURAL HAZARD 53.33 24 7.169 23.53 4 1.195 

Mud Slide 4.44 2 0.597 5.88 1 0.299 

Storm/ Hurricane 48.89 22 6.572 17.65 3 0.896 

UNKNOWN 6.67 3 0.896 

TOTALS 100.00 45 

334,764 

13.442 100.00 17 

334,764 

5.078 
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2.3

 

Table 2.3 

GOM and PAC OCS Pipeline Spills Statistics Summary (1972-2010) 

Spill 

GOM and PAC OCS Pipeline Spills, Statistics

Categorized 1972-2010 (Number of 

Spills) 

Exposure 

(km-years) 

Frequency 

(spills per 

105 km-years) 

< = 10" 38 222,716 17.062 By Pipe Diameter > 10" 24 112,047 21.420 

Small <100 bbl 15 334,764 4.481 

Medium 100 - 999 bbl 30 334,764 8.962 

Large 1000 - 9999 bbl 14 334,764 4.182 By Spill Size

Huge >=10000 bbl 3 334,764 0.896 

Small <100 bbl 11 222,716 4.939 

Medium 100 - 999 bbl 19 222,716 8.531 

Large 1000 - 9999 bbl 7 222,716 3.143 <=10" 

Huge >=10000 bbl 1 222,716 0.449 

Small <100 bbl 4 112,047 3.570 

Medium 100 - 999 bbl 11 112,047 9.817 

Large 1000 - 9999 bbl 7 112,047 6.247 

By Diameter, By Spill Size

> 10" 

Huge >=10000 bbl 2 112,047 1.785 

2.3 Pipe in Pipe (PIP) Spills 

Tables 2.4 and 2.5 give the derivation of PIP loss of containment frequencies for the 

GOM and PAC OCS conditions (same as historical conditions). The frequencies given 

are per 105

 km-yr. Table 2.4, for Small and Medium spills, gives a PIP loss of 

containment (LOC) frequency of 4.449 from a historical single pipe frequency of 13.442. 

Table 2.5, for Large and Huge spills, gives a PIP LOC frequency of 1.105 from a 

historical single pipe frequency of 5.078. 

Tables 2.4 and 2.5 give both the LOC and LOFn frequencies. LOC occurs when both 

pipes fail so that oil spills into the ocean environment. Loss of Function (LOFn) occurs 

when either pipe fails as it initiates a shutdown of the pipeline, so that it does not 

function. 

Table 2.6 gives the derived values for the present study. For example, if there were 30 

data points [15], the upper 90% (or high value) was the third highest, while the lower 

90% (or low value) was selected as the third lowest, which was invariably zero, as 

numerous years had no spills. Next, the third highest value was divided by the historical 

value to get the high factor. Finally, the high factor was used to obtain the high value by 

multiplying the applicable historical frequency by this high factor. The mode is 

calculated from the triangular distribution relationship [31], as follows: 

Mode = 3 x Historical - High - Low (2.1) 
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2.4

Table 2.4 

PIP Small and Medium Spill Frequency Derivation 

Small and Medium Spills 

50-999 bbl 

Cause 

Classification 

1972-2010 

Historical 

Distribution 

(%)

Historical 

Frequency 

(spill per 

105km-year) 

NPS 12 

Frequency 

(spill per 

105km-year) 

NPS 16 

Frequency 

(spill per 

105km-year) 

Loss of 

Containment 

(LOC) 

Frequency 

(spill per 

105km-year) 

PIP Pipeline 

Loss of 

Containment 

(LOC) 

Frequency 

Distribution 

(%) 

PIP Pipeline 

Loss of 

Function 

(LOFn) 

Frequency 

(spill per 

105km-year) 

PIP Pipeline 

PIP Pipeline 

Frequency Change 

Explanation 

 CORROSION 6.67 0.896 0.627 0.358 < 0.001 0.00 0.985 LOC due to internal NPS12 and 

external NPS16 per km-yr 

 External 2.22 0.299 0.030 0.299 < 0.001 0.00 0.329 90% reduced external corrosion on 

NPS12 due to inert annulus 

 Internal 4.44 0.597 0.597 0.060 < 0.001 0.00 0.657 90% reduced internal corrosion of 

NPS16 due to inert annulus 

 THIRD PARTY IMPACT 20.00 2.688 0.717 2.688 0.597 13.43 3.405 

 Anchor Impact 15.56 2.091 0.418 2.091 < 0.001 0.00 2.509 80% reduction in NPS12 failure if 

external NPS16 occurs 

 Jackup Rig or 

 Spud Barge 2.22 0.299 0.299 0.299 0.597 13.43 0.597 

Both pipes fail sequentially if impacted

P(LOC)=P(NPS16)+P(NPS12), 

conservatively evaluated with an 

“OR” gate. 

 Trawl/Fishing Net 2.22 0.299 0.000 0.299 0.000 0.00 0.299 Trawl/Fishing Net will only fail external

NPS16 pipe 

 OPERATION IMPACT 6.67 0.896 0.209 0.896 0.209 4.70 1.105 

 Rig Anchoring 2.22 0.299 0.149 0.299 0.149 3.36 0.448 LOC occurs 50% of NPS16 failure. 

P(LOC) = 0.5P(NPS16) 

 Work Boat 

 Anchoring 4.44 0.597 0.060 0.597 0.060 1.34 0.657 LOC is 10% of NPS 16. P(LOC) = 0.1P(NPS16) 

 MECHANICAL 6.67 0.896 0.896 0.896 0.000 0.00 1.792 

 Connection Failure 4.44 0.597 0.597 0.597 < 0.001 0.00 1.195 

LOC only if both occur so P(LOC) is 

product of the independent pipe 

LOCs. 

 Material Failure 2.22 0.299 0.299 0.299 < 0.001 0.00 0.597 LOC only if both occur so P(LOC) is 

product of the independent pipe LOCs

 NATURAL HAZARD 53.33 7.169 7.169 7.169 3.346 75.20 14.338 

 Mud Slide 4.44 0.597 0.597 0.597 0.060 1.34 1.195 LOC is 10% of NPS 16. P(LOC) = 

0.1P(NPS16) 

 Storm/ Hurricane 48.89 6.572 6.572 6.572 3.286 73.86 13.144 LOC is 50% of NPS 16. P(LOC) = 

0.5P(NPS16) 

 UNKNOWN 6.67 0.896 0.896 0.896 0.297 6.67 0.896 Adjusted to be the same as Historical 

% 

TOTALS 100.00 13.442 10.514 12.905 4.449 100.00 22.523 
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Table 2.5 

PIP Large and Huge Spill Frequency Derivation 

Large and Huge Spills 

>=1,000 bbl 

Cause 

Classification 

1972-2010 

Historical 

Distribution 

(%) 

Historical 

Frequency 

(spill per 

105km-year) 

NPS 12 

Frequency 

(spill per 105kmyear) 

NPS 16 

Frequency 

(spill per 

105km-year) 

Loss of 

Containment 

(LOC) Frequency

(spill per 

105km-year) 

PIP Pipeline 

Loss of 

Containment 

(LOC) 

Frequency 

Distribution 

(%) 

PIP Pipeline 

Loss of Function

(LOFn) 

Frequency 

(spill per 

105km-year) 

PIP Pipeline 

PIP Pipeline 

Frequency Change 

Explanation 

 CORROSION 5.88 0.299 0.597 0.030 < 0.001 0.00 0.896 LOC due to internal NPS12 and 

external NPS16 per km-yr 

 External 0.00 0.000 0.000 0.000 0.000 0.00 0.000 

 Internal 5.88 0.299 0.299 0.030 < 0.001 0.00 0.329 90% reduced internal corrosion of 

NPS16 due to inert annulus 

 THIRD PARTY IMPACT 64.71 3.286 0.657 3.286 0.597 54.05 3.943 

 Anchor Impact 35.29 1.792 0.358 1.792 < 0.001 0.00 2.151 80% reduction in NPS12 failure if 

external NPS16 occurs 

 Jackup Rig or 

 Spud Barge 5.88 0.299 0.299 0.299 0.597 54.05 0.597 

Both pipes fail sequentially if impacted

so P(LOC)=P(NPS16)+P(NPS12), 

conservatively evaluated with an 

“OR” gate. 

 Trawl/Fishing Net 23.53 1.195 0.000 1.195 0.000 0.00 1.195 Trawl/Fishing Net will only fail external

NPS16 pipe 

 OPERATION IMPACT 5.88 0.299 0.030 0.299 0.030 2.70 0.329 

 Rig Anchoring 0.00 0.000 0.000 0.000 0.000 0.00 0.000 

 Work Boat 

 Anchoring 5.88 0.299 0.030 0.299 0.030 2.70 0.329 LOC is 10% of NPS 16. P(LOC) = 

0.1P(NPS16) 

 MECHANICAL 0.00 0.000 0.000 0.000 0.000 0.00 0.000 

 Connection Failure 0.00 0.000 0.000 0.000 0.000 0.00 0.000 

 Material Failure 0.00 0.000 0.000 0.000 0.000 0.00 0.000 

 NATURAL HAZARD 23.53 1.195 1.195 1.195 0.478 43.24 2.390 

 Mud Slide 5.88 0.299 0.299 0.299 0.030 2.70 0.597 LOC is 10% of NPS 16. P(LOC) = 

0.1P(NPS16) 

 Storm/ Hurricane 17.65 0.896 0.896 0.896 0.448 40.54 1.792 LOC is 50% of NPS 16. P(LOC) = 

0.5P(NPS16) 

 UNKNOWN 0.00 0.000 0.000 0.000 0.000 0.00 0.000 

TOTALS 100.00 5.078 2.479 4.809 1.105 100.000 7.557 

Table 2.6 

PIP Pipeline Spill Frequency Distribution Properties 

GOM and PAC OCS Pipeline Spills, 

Categorized 1972-2010 

NPS > 10" 

Frequency Unit Low 

Factor 

High 

Factor Historical Low Mode High 

Small (50-99 bbl) Spill per 105 km-years 0 2.81 1.182 0 0.224 3.320 

Medium (100-999 bbl) Spill per 105 km-years 0 2.81 3.249 0 0.617 9.130 

Large(1,000-9,999 bbl) Spill per 105 km-years 0 2.81 1.360 0 0.258 3.821 

Huge (=>10,000 bbl) Spill per 105 km-years 0 2.81 0.388 0 0.074 1.092 
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2.6

2.4 Platform Spills 

The primary island or platform spill statistical information required is the spill frequency 

distribution by different causes and spill sizes, and the spill rate per well year. The 

historical data used here is that given for platforms, but modified later specifically for 

Arctic effects on the Liberty island. Table 2.7 summarizes the spill size distribution 

among the principal reported causes. As can be seen, the major cause attributable to over 

50% of the spills is that of Hurricanes. Also, hurricanes caused many of the larger spill 

volumes, giving the largest spill volume total. The largest single spill, however, is the 

tank failure which caused a spill of nearly 10,000 barrels [15]. From a review of the 

platform spill data [15], it can be seen that platform spills as defined here, are limited to 

those caused from process, storage, or transfer equipment losses of containment, so that 

they do not include LOWCs, which are dealt with subsequently here in Section 2.5. 

Table 2.7 

Analysis of GOM and PAC OCS Platform Spill Data 

by Causal Distribution and Spill Size (1972-2010) 

Spill Size (bbl) Number of Spills 

Cause 

Classification 

Number 

of Spills 

1972-

2010 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 S M L H SM LH

9,935 130 50 300 77 104 321 60 95 83 118 210 50 228 600 

77 320 200 77 107 50 643 50 58 52 50 55 400 55 280 Equipment 

Failure 36 

50 75 435 62 127 50 

19 16 1 35 1 

Human Error 13 95 120 286 58 400 100 60 64 100 600 170 60 264 5 8 13 

Collision 1 119 1 1 

Weather 7 7,000 239 100 1,500 80 214 100 1 4 2 5 2 

1,456 66 497 741 52 55 264 106 66 510 141 242 204 195 325 

380 130 110 195 307 71 159 94 51 101 51 50 51 97 614 

1,572 77 2,000 181 188 101 1,494 67 659 166 53 51 63 528 59 

133 51 54 685 103 62 205 52 513 200 550 140 50 127 70 

Hurricane 67 

194 170 196 72 58 54 62 

27 36 4 63 4 

TOTALS 124 52 65 7 117 7 

The spill rate data, given here using an exposure variable of production well-years [15], is 

shown in Table 2.8, again, by causal distribution as well as for two broad spill size 

categories of small and medium spills and large and huge spills. Here, it becomes 

immediately evident that the largest spill potential in terms of volume is attributable to 

hurricanes, which are responsible for roughly 57% of the large and huge spills. Finally, 

Table 2.9 gives the fault tree analysis statistical input data derived from Table 2.8. It 

should be noted that for platforms, only the two spill size categories given in Table 2.9 

have been assessed [15]. 
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Table 2.8 

Causal and Spill Size Distribution of GOM and PAC OCS Platform Spills (1972-2010) 

Small and Medium Spills 

50-999 bbl 

Large and Huge Spills 

Cause Classification >=1,000 bbl 

1972 – 2010 

(no LOWC) 

Historical 

Distribution 

(%) 

Number 

of Spills

Exposure 

(well-years)

Frequency 

(spill per 

104well-year) 

Historical 

Distribution 

(%) 

Number 

of Spills 

Exposure 

(well-years) 

Frequency 

(spill per 

104well-year) 

Equipment Failure 29.91 35 1.426 14.29 1 0.041 

Human Error 11.11 13 0.530 

Collision 0.85 1 0.041 

Weather 4.27 5 0.204 28.57 2 0.081 

Hurricane 53.85 63 

245,486 

2.566 57.14 4 

245,486 

0.163 

TOTALS 100.00 117 4.766 100.00 7 0.285 

Table 2.9 

Platform Historical Spill Frequency Variability (1972-2010) 

Spill Size Frequency Unit Low 

Factor 

High 

Factor Historical Low Mode High 

Small and Medium 

Spills (50-999 bbl) 

Spill per 

104 well-year 0 3 4.766 0.000 0.000 14.298 

Large and Huge Spills 

(>= 1,000 bbl) 

Spill per 

104 well-year 0 3 0.285 0.000 0.000 0.855 

2.5 Loss of Well Control (LOWC) Data 

The development scenarios considered under this study include both the drilling of 

exploratory and development wells, and the production wells producing oil. In earlier 

studies [18, 10], to identify a basis for the non-Arctic historical oil well blowout statistics, 

a number of sources were reviewed including the Northstar and Liberty oil development 

project reports [51], a study by Scandpower giving the cumulative distribution function 

for oil blowout releases [54, 55], as well as the book by Per Holand entitled “Offshore 

Blowouts” [31], which gives risk analysis data from the SINTEF worldwide offshore 

blowout database [30]. 

However, the recent work for BOEM on LOWC statistics [4, 14] was used as the 

principal data source for the present work. Table 2.10 gives a summary of the historical 

data analysis for production wells and the drilling of exploratory and development wells 

based on GOM data. The combination of these statistics together with the cumulative 

distribution function for LOWC release volumes given in [4, 20], results in the LOWC 

spill volume frequency distribution as summarized in Table 2.11. 
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Table 2.10 

Well LOWC Historical Spill Size Distribution (1980 - 2011) 

Small and 

Medium Spills

50-999 bbl 

Large Spills 

1,000-9,999 

bbl 

Small, 

Medium, and 

Large Spills 

50-9,999 bbl 

Spills 

10,000-149,999 

bbl 

Spills 

>=150,000 bbl All Spills Event Frequency 

Unit 

Historical Frequency 1980-2011 BSEE Data 

Production Well spills per 

104 well-year 0.028 0.011 0.039 0.007 0.005 0.051 

Exploration Well 

Drilling 

spills per 

104 wells 1.330 0.539 1.869 0.350 0.217 2.436 

Development Well 

Drilling 

spills per 

104 wells 0.283 0.115 0.398 0.075 0.046 0.519 

Table 2.11 

Well LOWC Historical Spill Probability and Size Variability (1980 - 2011) 

Frequencies

Spill Size Event Frequency Unit Low 

Factor

High 

Factor Historical Low Mode High

Production Well spill per 104 well-year 0.448 1.545 0.028 0.012 0.028 0.043

Exploration Well Drilling spill per 104 wells 0.439 2.036 1.330 0.584 0.698 2.708

Small and 

Medium Spills 

50-999 bbl 

Development Well Drilling spill per 104 wells 0.437 1.760 0.283 0.124 0.227 0.498

Production Well spill per 104 well-year 0.448 1.545 0.011 0.005 0.011 0.017

Exploration Well Drilling spill per 104 wells 0.439 2.036 0.539 0.237 0.283 1.097 Large Spills 

1000-9,999 bbl 

Development Well Drilling spill per 104 wells 0.437 1.760 0.115 0.050 0.092 0.202

Production Well spill per 104 well-year 0.448 1.545 0.039 0.017 0.039 0.060

Exploration Well Drilling spill per 104 wells 0.439 2.036 1.869 0.821 0.981 3.805

Small, Medium 

and Large Spills 

50-9,999 bbl 

Development Well Drilling spill per 104 wells 0.437 1.760 0.398 0.174 0.320 0.700

Production Well spill per 104 well-year 0.448 1.545 0.007 0.003 0.007 0.011

Exploration Well Drilling spill per 104 wells 0.439 2.036 0.350 0.154 0.184 0.713 Spill 

10,000-149,999 bbl 

Development Well Drilling spill per 104 wells 0.437 1.760 0.075 0.033 0.060 0.131

Production Well spill per 104 well-year 0.448 1.545 0.005 0.002 0.005 0.007

Exploration Well Drilling spill per 104 wells 0.439 2.036 0.217 0.095 0.114 0.442 Spill 

>=150,000 bbl 

Development Well Drilling spill per 104 wells 0.437 1.760 0.046 0.020 0.037 0.081
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2.9

2.6 Arctic Effects Statistics 

2.6.1 General Approaches to the Quantification of Arctic Effects 

There are essentially two main categories of Arctic effects; namely, those that are unique 

to the Arctic, such as marine ice effects, and those that are the same types of effects as 

those in temperate areas, but occurring with a different frequency, such as fishing net 

impacts on subsea pipelines. The first will be termed “unique” effects; the second, 

“modified” effects. Modified Arctic effects are dealt with in conjunction with the fault 

tree analysis described in Chapter 4. Only those Arctic effects or hazards unique to the 

Arctic, and potentially having a historical occurrence database, such as ice gouging, are 

discussed in the balance of this section. 

2.6.2 Ice Gouging 

Ice gouging occurs when a moving ice feature contacts the sea bottom and penetrates into 

it, generally as it moves against a positive sea bottom slope. The ice feature can be a 

multiyear ridge, a hummock, or ice rafting formation. Various studies have been 

conducted on the frequency and depth distribution of ice gouges [2, 11, 25, 36, 42, 47, 

62], and a number of assessments of the likelihood of resultant subsea pipeline failure 

[44, 62] have also been carried out. Pipeline failure frequencies at different water depth 

regimes as a result of ice gouging in this study have been estimated on the basis of the 

historical ice gouge characteristics [2, 29] together with an analytical assessment [2, 44, 

62] of their likelihood to damage a pipeline. 

According to Weeks [65, 66], a relationship between the expected probability of pipeline 

failure from ice gouging and ice gouging local characteristics may be expressed as 

follows: 

N = e-kx HS · F · T · LP · sinФ (2.2)

Where: 

N = Number of pipeline failures at burial depth of cover x (meters) 

k = Inverse of mean scour depth (m-1) 

x = Depth of cover (m) 

HS = Probability of pipeline failure given ice gouge impact or hit 

F = Scour flux per km-yr 

T = Exposure time (years) 

LP = Length of pipeline (km) 

Ф = Gouge orientation (degrees) from pipeline centerline 

The following basis was used for the gouging frequency calculations given in Table 2.12: 

 Section 7.2.1 of the DPP [28] gives a minimum depth of 2.29 m, a maximum depth of 

3.35m, and a mode of 3.05m. 

 Vaudrey [63] formula used: N = e-kx HS · Hs · F · sinФ
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 Liedersdorf [36] gives mean scour depth of 0.2m, flux of 2/km-yr, and conditional 

single pipeline failure probability of 0.83. 

 Vaudrey [63] gives an average gouge depth of 0.43 ft or 0.13 m (Table 6.4, page 48 

[63]). The greater gouge depth of 0.2 m is used here. 

 PIP pipeline failures from gouging were estimated to be as 50% of single wall 

failures. 

Table 2.12 

Liberty Pipeline Ice Gouging Frequency Calculation 

Number of 

Single Wall 

Pipeline 

Failures 

Number 

of PIP 

Pipeline 

Failures

PIP 

Small 

Spills 

PIP 

Medium 

Spills 

PIP 

Large 

Spills

PIP 

Huge 

Spills

Depth 

of 

cover 

(m)

Inverse 

of Gouge 

depth 

(per m)

Conditional 

Pipeline 

Failure 

Probability 

Gouge 

flux 

(per kmyear)

Gouge 

Orientation

(degrees) 

(per 105 km-year) Value 

X 

K 

(1/mean 

depth) 

Hs F Ф

Value

Ns N 20% 20% 50% 10% 

MAX 3.35 5 0.83 2 45 MIN 0.0062 0.0031 0.0006 0.0006 0.0016 0.0003

MODE 3.05 5 0.83 2 45 MODE 0.0280 0.0140 0.0028 0.0028 0.0070 0.0014

MIN 2.29 5 0.83 2 45 MAX 1.2500 0.6250 0.1250 0.1250 0.3125 0.0625

2.6.3 Strudel Scour 

When water collects on top of the landfast ice, generally from rivers running into the 

Arctic seas, and drains through a hole in the ice, its hydrodynamic effect on the ocean 

floor below forms a depression which is called a strudel scour. Numerous studies have 

been conducted on strudel scour [25, 33, 35, 48], so that a prediction on the number of 

strudel scours per unit area can be made on the basis of historical data. Strudel scours are 

restricted to shallower water such as the Liberty location. 

The following basis was used for the Liberty strudel scour frequency calculation given in 

Table 2.13: 

 Upstream Technology Group [62], T5.9, page 120, gives a basis for the calculations used 

here. Inputs are given for 1.8 mile Base Case, and converted here to unit per km. 

 In addition as for ice gouging, it is estimated PIP pipeline failures are 50% of single wall 

pipeline failures. 

 Spill size distribution is weighted to large spills [62] and P2.12 of Bercha International 

Inc., OCS Study MMS 2008-035 [16]. 
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Table 2.13 

Liberty Pipeline Strudel Scour Frequency Calculation 

Number of 

Critical 

Scours 

Number of 

Scours 

Number of Single 

Wall Pipeline 

Failures 

Number of PIP 

Pipeline 

Failures 

PIP 

Small 

Spills 

PIP 

Medium 

Spills 

PIP 

Large

Spills

PIP 

Huge

Spills

(per 105 km-year) 

Value 

(per 105 km-year) 

Conditional Pipeline 

Failure Probability 

100% 100% 20% 20% 50% 10% 

MIN 1.60 0.5523 0.02 0.0110 0.0055 0.0011 0.0011 0.0028 0.0006

MODE 3.40 1.1736 0.02 0.0235 0.0117 0.0023 0.0023 0.0059 0.0012

MAX 20.00 6.9037 0.02 0.1381 0.0690 0.0138 0.0138 0.0345 0.0069

2.6.4 Upheaval Buckling 

Upheaval buckling occurs in a pipeline as a result of its thermal expansion which causes 

it to buckle upwards to accommodate the extra length generated from thermal effects. 

Unfortunately, there appears to be no defensible analytical method for calculating the 

probability of upheaval buckling of Arctic subsea pipelines in general. Accordingly, 

upheaval buckling has been taken simply as a percentage of the strudel scour effects 

quantified in previous work [16, 17]. Assuming that upheaval buckling occurs 20% as 

often as strudel scour, the distribution shown in Table 2.14 can be derived. Upheaval 

buckling is expected to be independent of water depth; accordingly, the same values have 

been used for each water depth range. Other Arctic effects have been incorporated on the 

basis of values used in preceding studies [16, 17]. 

Table 2.14 

Summary of PIP Pipeline Arctic Unique Effect Inputs 

PIP LOC Frequency 

Increment 

per 105 km-year ARCTIC Spill 

Size 

Min Mode Max 

REASON 

S 0.0006 0.0028 0.1250 

M 0.0006 0.0028 0.1250 

L 0.0016 0.0070 0.3125 Ice Gouging 

H 0.0003 0.0014 0.0625 

Ice Gouge Failure Rate calculated using exponential failure 

distribution for 3.05 m cover, 0.2 m average gouge depth, 2 

gouges per km-yr flux. 

S 0.0011 0.0023 0.0138 

M 0.0011 0.0023 0.0138 

L 0.0028 0.0059 0.0345 Strudel Scour 

H 0.0006 0.0012 0.0069 

Average Frequency of 3.4 critical scours/105 km-yr and 100 

ft of bridge length with 2% conditional P/L failure probability. 

The same spill size distribution as above. 

S 0.0002 0.0005 0.0028 

M 0.0002 0.0005 0.0028 

L 0.0006 0.0012 0.0069 Upheaval Buckling 

H 0.0001 0.0002 0.0014 

The Failure Frequency is 20% of that of Strudel Scour. 

S 0.0001 0.0002 0.0014 

M 0.0001 0.0002 0.0014 

L 0.0003 0.0006 0.0035 Thaw Settlement 

H 0.0001 0.0001 0.0007 

The Failure Frequency is 10% of that of Strudel Scour. 

S 0.0002 0.0006 0.0143 

M 0.0002 0.0006 0.0143 

L 0.0005 0.0015 0.0357 Other Arctic 

H 0.0001 0.0003 0.0071 

To be assessed as 10% of all arctic effects. 
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2.6.5 Thaw Settlement 

Thaw settlement occurs when a permafrost lens or formation over which the pipeline was 

installed melts as a result of the heat generated by the pipeline and ceases to support the 

pipeline so that the pipeline overburden loads the pipeline and causes it to deflect 

downwards [39]. Thaw settlement LOC for the PIP has been taken at 10% of the 

probability of strudel scours. 

2.6.6 Summary of Pipeline Arctic Unique Effects 

Table 2.14 summarizes Arctic unique effects for the Liberty PIP pipeline, in accordance 

with the discussion on the derivation of these effects given in the above subsections. In 

addition, distribution of the effects among four spill size categories is given. 

2.6.7 Platform Arctic Unique Effects 

This section covers potential causes of platform spills (other than LOWC’S, which are 

included under wells) that are uniquely associated with the Arctic, are ice forces and low 

temperature effects. Although the possibility that ice forces will cause spills varies 

greatly from facility to facility, some broad assumptions have been made in regard to the 

likelihood of spills being caused by ice force effects. Specifically, it was assumed that the 

platforms are designed for a 10,000 year return period with a reliability level of 99%, in 

accordance with the ISO 19906 Arctic Structures, Reliability, Section 7.2.2.3 [34]. That 

is, 1% of the time, the 10,000 year return period ice force can cause a spill. Further, it 

was assumed that 85% of spills so caused are small and medium, with large and huge 

spills associated with 15%. In regards to facility low temperature, a percentage of 

historical facility releases was taken. Specifically, it was assumed that the facility low 

temperature effects will cause small and medium spills at a rate of 6% of that of total 

historical small and medium spills, and large and huge spills at a rate of 3% of that 

associated with large and huge historical spills. Finally, other Arctic unique causes were 

assumed to constitute another 10% of the sum of the above spill rates in each of the spill 

categories. Table 2.15 summarizes the resultant Arctic unique effect frequencies derived 

for platforms on a per well-year exposure basis. 

Table 2.15 

Summary of Platform Unique Arctic Effect Inputs 

Arctic Unique Cause Size Min Mode Max Reason 

SM 0.001 0.009 0.085 

Ice Force 

LH 0.000 0.002 0.015 

Assumed 10,000 year return period ice force 

causes spill 1% of occurrences (99% reliability). 

85% of the spills are SM as due to ride-up impact 

only. 

SM 0.043 0.086 0.128 

Facility Low Temperature LH 0.000 0.000 0.001 

Assumed fraction of Historical Equipment Failure 

release frequency with 6% for SM and 1% for LH 

spill sizes. 

SM 0.004 0.009 0.021 

Other Arctic 

LH 0.000 0.000 0.002 

10% of sum of above. 
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2.13

2.7 Historical Spill Size Distribution 

Tables 2.16, 2.17, and 2.18 give the historical spill volume distributions obtained from 

available historical data. In each case, the mode was taken as the historical average spill 

size in each spill size category, while the high and low values were taken to be the upper 

and lower bounds of each spill size category. The high values for Huge spills were 

chosen on the basis of the upper 90% confidence interval spill volumes in the databases. 

Table 2.16 

Historical Pipeline Spill Volume Distribution Parameters 

Spill Size Small Spills 

50-99 bbl 

Medium Spills 

100-999 bbl 

Large Spills 

1,000-9,999 bbl

Huge Spills 

=>10,000 bbl

Spill 

Expectation Low Mode High Low Mode High Low Mode High Low Mode High 

Pipeline 

Diameter 

<= 10" Spill 

50 58 99 100 226 999 1,000 4,436 9,999 10,000 14,423 20,000 

Pipeline 

Diameter 

> 10" Spill 

50 58 99 100 387 999 1,000 3,932 9,999 10,000 17,705 20,000 

Table 2.17 

Historical Platform Spill Volume Distribution Parameters 

Spill Size Small and Medium Spills 

50-999 bbl 

Large and Huge Spills 

=>1,000 bbl 

Spill 

Expectation Low Mode High Low Mode High 

Platform Spill 50 158 999 1,000 6,130 10,000 

Table 2.18 

Historical LOWC Spill Volume Distribution Parameters 

Spill Size

Small and Medium 

Spills 

50-999 bbl

Large Spills 

1,000-9,999 bbl

Spills 10,000-149,999 

bbl Spills =>150,000 bbl

Spill 

Expectation Low Mode High Low Mode High Low Mode High Low Mode High 

Well Spill 50 500 999 1,000 4,500 9,999 10,000 20,000 150,000 150,000 200,000 1,000,000
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CHAPTER 3 

LIBERTY DEVELOPMENT PROJECT INFORMATION 

3.1 Liberty Project Summary 

Information on the Liberty Development Project (the Project) is largely based on the

Liberty Development Plan by Hilcorp Alaska, Inc. [28]. 

The geographical study area is the Beaufort Sea Outer Continental Shelf (OCS) as 

generally illustrated in Figure 3.1. Of interest is the offshore area from landfall to 

approximately the 6 m (20 ft) isobath. This area is selected due to the proposed future oil 

and gas development within it [28]. 

The Liberty Development will be a self-contained offshore drilling and production 

facility located on an artificial gravel island with a pipeline to shore. The island will be 

built about 9 km (5.6 mi) offshore in Foggy Island Bay of the Beaufort Sea OCS in 

approximately 6 m of water, about 3 km (2 mi) west of the Tern Island shoal. 

Infrastructure and facilities necessary to drill wells and process and export approximately 

60,000 to 70,000 BPD to shore will be installed on the island. There will be slots for 16 

wells, which include accommodations for 5-8 producing wells, 4-6 water and/or gas 

injection wells, and up to two disposal wells at surface wellhead spacing of 15 feet 

between wellheads. Produced gas will be used for fuel gas, artificial lift, and re-injection 

into the reservoir. Seawater will be treated and used to waterflood the Liberty reservoir. 

Following waterflood breakthrough, produced water will be commingled with seawater 

and re-injected for reservoir support. A nominal 12 inch sales oil pipeline inside 16 inch 

outer pipe will transport crude oil to the Badami Sales Oil Pipeline. The offshore portion 

of the pipeline will be approximately 9 km (5.6 mi) long, and the overland portion will be 

approximately 2.4 km (1.5 mi) long to the Badami pipeline tie-in point as shown in 

Figure 3.2. 

Associated onshore facilities to support the project will include use of permitted water 

sources, construction of gravel pads to support the pipeline tie-in location and Badami ice 

road crossing, ice roads and ice pad construction, hovercraft shelter, small boat dock, and 

development of a gravel mine site west of the Kadleroshilik River. In addition, existing 

North Slope infrastructure will be used to support this project. 

The Liberty Drilling and Production Island (LDPI) will be constructed to recover reserves 

from two federal leases (OCS-71585) in Foggy Island Bay in the Beaufort Sea, northeast 

of the Prudhoe Bay Unit, and east of the Duck Island Unit. The LDPI will be located 

approximately 8 km (5 mi) north of the Kadleroshilik River and 7.3 miles southeast of the 

SDI. The LDPI will be built in approximately 6 m (19 ft) of water, elevation of the top of 

the LDPI will be +4.6 m (15 ft) Mean Low Water (MLLW). The LDPI location is shown 

in Figure 3.2. 
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Figure 3.1: Project Location Map [28] 

The Project and its principal functional Project components described herein and 

analyzed in the present study are: 

 The Liberty drilling and production island (LDPI) 

 Oil and gas wells 

 The subsea pipeline 

 The Project as integrated 

The project life cycle, following hearings and approvals, spans approximately 25 years, 

as described in Section 3.3.6. 

Salient details on the Project and its components follow. 
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Following the review phase, the Project execution schedule [h-Executive SummarySection 3] includes the following principal milestones: 

 Year 1: Start 2017 estimated 

 Year 2-5: Island, facilities, and pipeline construction. 

 Year 3-5: Drilling operations

 Year 4-5: Production operations startup 

 Year 4-25: Oil production 

 Year 25: End of oil production 

Figure 3.2: Project Detailed Location Map [28]
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3.2 Liberty Drilling and Production Island (LDPI) 

This section gives a brief description of the LDPI and its facilities to facilitate a general 

understanding of the report; details are given in Sections 6 and 9 in [28]. As was shown n 

Figure 3.2, the Liberty Drilling and Production Island (LDPI) will be will be an artificial 

gravel island located approximately 8 km (5 mi) north of the Kadleroshilik River and 7.3 

miles southeast of the SDI as was shown in Figure 3.2. The LDPI will be built in 

approximately 6 m (19 ft) of water, elevation of the top of the LDPI will be +4.6 m (15 

ft) Mean Low Water (MLLW). 

A conceptual rendering of the LDPI is shown in Figure 3.3. As can be seen, it is semirectangular in shape, with sloped sides armored to protect it from ice scour and impact. 

Figure 3.4 shows a plan view of the island giving principal dimensions and locations of 

the main facilities. 

Figure 3.3: Rendering of LDPI [28]

As can be seen in Figures 3.3 and 3.4, oil storage (Area 19) and oil production (Area 12) 

are located in the southern and central parts of the island, where there is less potential for 

ice or storm effect incursions. The relief well (Area 2) is located away from the 

production area as it needs to remain intact in case of a well control incident. Oil spills 

from the island facilities are limited by containment berms surrounding tankage and 

process facilities, location of containment well within island protective perimeter, and 

island stability including protection against ice incursions and loading. Table 3.1 lists 

more detailed information on each area shown in Figure 3.4. 

Figure 3.5 gives a simplified block diagram of the production process. Basically, oil 

produced from the wells is metered, the water and gas are separated, and the sales oil is 

again metered and sent to the pumps to flow into the pipeline to shore. 
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Figure 3.4: Plan of LDPI and Facilities [28, page 154] 
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Table 3.1: LDPI Plan (Figure 3.4) Facility Description [28]

AREA 1 1 HELI-PAD AREA 14 34 TRAIN #7 PRODUCTION MODULE 

4 HANGER/ARKTOS STORAGE 35 TRAIN #6 PRODUCTION MODULE 

5 FREEZER/DRY STORAGE MODULE AREA 15 36 TRAIN #5 PRODUCTION MODULE 

6 MAIN CAMP 37 TRAIN #4 PRODUCTION MODULE 

19 GRAVEL STORAGE 55 PRODUCTION MANIFOLD MODULE 

AREA 2 7 RELIEF WELL LOCATION AREA 16 38 TRAIN #3 PRODUCTION MODULE 

AREA 3 2 FIRE & RESCUE 39 TRAIN #2 PRODUCTION MODULE 

3 POTABLE WATER STORAGE MODULES 56 GAS LIFT/INJECTION MANIFOLD MODULE 

8 SEWAGE PLANT AREA 17 40 TRAIN #1 PRODUCTION MODULE 

11 STANDBY GENERATOR MODULE 41 FG & INJECTION COMPRESSION MODULES 

12 DIESEL STORAGE AREA 18 42 SALES OIL PUMP & LACT MODULES 

18 INCINERATOR 43 PIPELINE/PIGGING MODULE 

AREA 4 10 WELDING SHOP 46 FIRE WATER TANK-5000BBL 

14 GENERAL SHOP 47 SALES OIL TANKS-15000BBL 

15 WAREHOUSE STORAGE AREA 19 44 PRODUCED WATER & SEA WATER 

17 ELECTRICAL SHOP TANKS-15000BBL 

- RELIEF RIG RESERVED SPACE 45 SLOP TANK 

AREA 5 16 DRILLERS’ CAMP 48 UTILITY MODULE 

21 VEHICLE SHELTER & STORAGE 49 CHEMICAL TANK FARM 

AREA 6 22 CONTROL ROOM MODULE #1 AREA 20 51 P.W. TREATMENT MODULES #1 - #3 

23 CONTROL ROOM MODULE #2 52 P.W. TREATMENT MODULES #4 - #7 

62 MICROWAVE COMMUNICATION TOWER 53 VRW 

66 DIESEL TANK FARM 57 WATER INJECTION/OFFSPEC PUMP MODULE 

AREA 7 - RIG SKID BEAMS 59 S.W. TREATMENT MODULES 

AREA 8 - RIG SKID BEAMS (SW ACCELERATES) 

AREA 9 31 DRILLING RIG/UTILITY MODULE AREA 21 54 COMPRESSION TRAIN #1 MODULE 

AREA 10 24 SWITCHGEAR 55 COMPRESSION TRAIN #2 MODULE 

25 MCC #1 56 COMPRESSION TRAIN #3 MODULE 

26 MCC #2 60 FLARE BOOM 

27 POWER GENERATOR #1 61 FLARE KNOCK-OUT DRUM 

28 POWER GENERATOR #2 57 COMPRESSION TRAIN #4 MODULE 

29 POWER GENERATOR #3 9 C-CAN-LAYDOWN AREA 

30 POWER GENERATOR #4 13 C-CAN LAYDOWN AREA 

58 POWER GENERATOR #5 83 SEA WTER INTAKE CAISSON 

AREA 11 33 PRODUCTION & INJECTION WELL AREA 54 SEA WATER INJECTION PUMP MODULE 

59 DRILLING CEMENT SILOS 

AREA 12 32 DRILLING SUPPORT BUILDING 

33 PRODUCTION & INJECTION WELL AREA

70 DRILLING MUD SILOS 

AREA 13 20 GRIND INJECTION FACILITY 
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Figure 3.5: Block Diagram of Oil Production System [28]

3.3 Oil and Gas Wells 

As described in Section 3.1, infrastructure and facilities necessary to drill wells and 

process and export approximately 60,000 to 70,000 BPD to shore will be installed on the 

island. There will be slots for 16 wells, which include accommodations for 5-8 producing 

wells, 4-6 water and/or gas injection wells, and up to two disposal wells at surface 

wellhead spacing of 15 feet between wellheads. Produced gas will be used for fuel gas, 

artificial lift, and re-injection into the reservoir. Seawater will be treated and used to 

waterflood the Liberty reservoir. Following waterflood breakthrough, produced water 

will be commingled with seawater and re-injected for reservoir support. 

The drilling schedule, shown in Figure 3.6, is integrated into the project schedule as 

described subsequently in Section 3.5. 

Flare

Vapor Fuel Fuel Injection Gas Gas

Recovery Gas Gas Compression Injection

Unit Compression Users (3rd Stage) Well

Production

Production Multiphase Production Facilities

Wells Meters Manifold FWKD AC Grid Treater

Host Treater

Crude Pigging Badami

Oil & Pipeline

Tanks ESO

Produced Water

Treatment

De‐Oiler

Treater

Gas

Lift Gas

Compression

(1st & 2nd Stage)

Crude

3

Oil

Phase Fluid

Pump

Sales Oil

& Metering
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Figure 3.6: Project Drilling Schedule [28]

The LDPI drilling unit will be designed with the following safety equipment [28]: 

 Well control equipment, including surface hole diverter system, main BOP 

stack, choke manifold, accumulator closing system, and control panels. The 

BOP stack will include shear rams. All blowout preventer equipment (BOPE) 

will meet regulatory standards. 

 Flow monitoring system to detect downhole flow. 

 Pit volume totalizer system to monitor drilling mud volumes in the drilling 

unit pits to allow detection of possible influx volume from downhole 

formations. 

 Trip tank to monitor for proper hole fill when running drill pipe into and out 

of the well. Trip tank can help detect potential influxes from swab pressures 

and potential mud losses form surge pressures. 

 Mud gas separator and vacuum degasser. 

 Drill string and tubular BOP devices including inside blowout preventer 

(IBOP), full opening safety valve, upper and lower Kelley valves. 

 Hydrogen sulfide (H2S) and combustible gas detector and alarm systems. 

 Fire detection and suppression system 

 Crown savers, mud pump pressure relief valves, and torque limiters. 

 First aid equipment and supplies. 

The primary well control mechanism for the Liberty Development drilling program will 

be the hydrostatic pressure exerted by the drilling fluid. The optimal mud weight used 

will be based on information gathered on offset wells including Liberty No. 1, the Tern 

Island wells, and wells drilled at the Endicott field. Other engineering decisions that 

factor into the primary well control plan include casing setting depths, casing burst 

ratings, fracture gradient of the exposed shoe, and pressure losses while circulating. All 

data of a geologic and engineering essence have been included in the drilling design 
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basis, which defines the proposed mud weights, casing design, and proposed circulating 

system practices. Note: the drilling fluid program will be designed and implemented in 

accordance with 30 CFR 250.455-459. 

The secondary well control mechanism for the Liberty Development drilling program 

equipment is a BOP system, which includes the equipment, personnel, and procedures 

used to detect a kick and control a well that has been exposed to an underbalance 

condition. 

3.4 Subsea Oil Pipeline

As summarized in Section 3.1, a nominal 12 inch sales oil pipeline inside 16 inch outer 

pipe or pipe in pipe (PIP) will transport crude oil to the Badami Sales Oil Pipeline. The 

offshore portion of the pipeline will be approximately 9 km (5.6 mi) long, and the 

overland portion (not analyzed herein) will be approximately 2.4 km (1.5 mi) long to the 

Badami pipeline tie-in point as shown in Figure 3.2, in Section 3.1. 

Based upon the soil characteristics and the predicted environmental loading conditions 

along the pipeline route, such as permafrost thaw settlement, seabed ice gouging, strudel 

scour, and upheaval buckling, the mechanical design of the pipelines will be based on a 

limit-state design approach. The primary design considerations for the limit-state design 

include critical strains in bending and the burst pressure for individual lines. For example, 

the compressive and tensile strain limits -- engineering critical analysis (ECA) weld flaw 

sizes -- for the pipelines will be evaluated in detail. 

Historical local and regional data are being used for the purpose of ice gouge and strudel 

scour design for 100-year exceedance probability events. The preliminary target trench 

depth range is 11 feet to 13 feet with a minimum 7.5 feet of depth of cover to the top of 

the pipe. Analyses will be performed for ice gouge, strudel scour, and permafrost to 

evaluate the maximum strain in the pipelines over this trench depth range. Approximately 

7 feet is the estimated maximum trench bottom width. The physical parameters of 

pipeline design are further described below in Table 3.2 and Figure 3.7. 

Table 3.2: Subsea Pipeline Properties [28]

Design Property Specification 

Design flowrate 65,000 BPD 

Maximum operating pressure 1415 psig 

OD of inner export pipe 12.78” (12” nominal) 

Nominal wall thickness, inner PIP 0.500” 

Grade of inner PIP API-5L X52 

OD of outer PIP 16.00” 

Nominal wall thickness, outer PIP 0.625” 

Grade of outer PIP API-5L X52 

Nominal diameter of coiled tubing spare 4.0” 

Nominal wall thickness 0.300” 

Grade of coiled tubing API-5LCP X65 
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Figure 3.7: Subsea Pipeline Cross Section [28]

A number of issues are addressed in routing, design, and monitoring to mitigate potential 

risk to pipeline integrity, such as thaw settlement. Key design advantages include: 

 Limit-state design, including finite element analysis of the pipeline bundle, to 

determine the maximum longitudinal strains (axial and bending) in the 

pipelines, based on predicted permafrost thaw settlement and the expected 

environmental and operational loadings. 

 The use of a vacuum insulated PIP configuration for the single-phase 

production pipeline to reduce heat transfer into the surrounding soils and to 

provide a secondary leak detection system by annulus pressure monitoring. 

 Fiber optic cable distributed temperature sensing system. 

 Straight line route to minimize route length. 

 The use of thaw stable gravel bedding beneath the pipeline at the shore and 

LDPI approach transitions. 

Mass balance and pressure monitoring leak detection systems will be incorporated into 

the export pipeline design. These systems work in parallel and provide redundant 

measurements to ensure accuracy. It is expected that under optimal conditions, these 

systems would be capable of detecting a leak 1 percent of the volumetric flow in the 

pipeline over a 24-hour period. Custody transfer metering will be located on the LDPI 

and a flow meter will be located at the tie-in with the Badami Pipeline to enhance the 
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performance of the leak detection system. Communication links to interface with Badami 

and Endicott pipeline leak detection systems and controls will also be provided. 

Specific provisions for ice effects, including scour, gouging, thaw settlement, and 

upheaval buckling as quantified for the risk assessment were included in the subsea 

pipeline design. 

3.5 The Project 

The Project life cycle, following hearings and approvals, spans approximately 25 years. 

Thus, following the review phase, the Project execution schedule [28, Executive 

Summary, Section 3] includes the following principal milestones: 

 Year 1: Start 2017 estimated 

 Year 2-5: Island, facilities, and pipeline construction. 

 Year 3-5: Drilling operations

 Year 4-5: Production operations startup 

 Year 4-25: Oil production 

 Year 25: End of oil production 

The principal project input for the analysis is the drilling and production schedule. This 

was established with BOEM and Hilcorp, and is given in Table 3.3.
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Table 3.3 

Drilling and Production Schedule 

Development Wells Drilling 

Year 

Waste 

Disposal 

W or G 

Injector Producer Total 

Producing

Wells 

In-use 

Pipeline 

Length 

(km) 

Annual 

Production

(bbl) 

2 1 1 

3 3 3 6 

4 1 2 3 5 9.01 23,038,204 

5 5 9.01 19,956,844 

6 5 9.01 12,427,316 

7 5 9.01 8,362,712 

8 5 9.01 7,443,660 

9 5 9.01 6,427,520 

10 5 9.01 4,995,928 

11 5 9.01 4,585,928 

12 5 9.01 4,081,184 

13 5 9.01 3,585,232 

14 5 9.01 3,206,432 

15 5 9.01 2,990,872 

16 5 9.01 2,805,536 

17 5 9.01 2,581,504 

18 5 9.01 2,288,624 

19 5 9.01 2,059,248 

20 5 9.01 1,797,176 

21 5 9.01 1,364,208 

22 5 9.01 1,156,176 

23 5 9.01 1,005,080 

24 5 9.01 854,328 

25 5 9.01 784,792 

Total 1 4 5 10 117,798,504
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4.1

CHAPTER 4 

FAULT TREE ANALYSIS FOR 

ARCTIC OIL SPILL FREQUENCIES 

4.1 General Description of Fault Tree Analysis 

Fault trees are a method for modeling the probabilities of the occurrence of failures. They 

are used when an adequate history is not available to provide failure statistics. Developed 

initially by Rasmussen for the U.S. Nuclear Regulatory Commission in the early 1970s 

[61], fault trees have become a popular risk analytic tool for predicting risks, assessing 

relative risks, and quantifying comparative risks [6, 10, 12]. In 1976, Bercha first used 

fault trees to quantify oil spill probabilities in the Canadian Beaufort Sea for the Canadian 

Department of the Environment [12]. In the present study they are used for the 

transformation of historical oil spill statistics for non-Arctic regions to predictive oil spill 

statistics for Arctic regions for the Liberty Project. 

4.2 Fault Tree Methodology 

4.2.1 Fault Tree Analysis Basics 

The basic symbols used in the graphic depiction of simple (as used here) fault tree 

networks are illustrated in Figure 4.1(a). As may be seen, the two types of symbols 

designate logic gates and event types. The basic fault tree building blocks are the events 

and associated sub-events, which form a causal network. The elements linking events are 

the AND and OR gates, which define the logical relationship among events in the 

network. The output event from an OR gate occurs if any one or more of the input events 

to the gate occurs. The output event from an AND gate occurs only if all the input events 

occur simultaneously. 

The basic structure of a fault tree is illustrated in Figure 4.1(b). Because of their 

connection through an AND gate, Event D and Event E must both occur for the resultant 

Event B to occur. An OR gate connects Events B and C; therefore, the occurrence of 

either one or both of Events B and C results in the occurrence of the resultant Event A. 

As may be seen, the principal fault tree structures are easy to apply; however, the 

representation of complex problems often requires very large fault trees, which become 

more difficult to analyze and require more advanced techniques such as minimal cut-set 

analysis [1, 6, 10]. For the present application, a simple system connected through OR 

gates only will be used. 
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4.2

SYMBOL DESCRIPTION 

A. LOGIC 

EITHER / OR GATE 

AND GATE 

B. EVENT 

RESULTANT EVENT 

BASIC EVENT 

(a) Basic Fault Tree Symbols 

(b) Basic Fault Tree Structure 

Figure 4.1: Fault Tree Basics 
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4.3

Computationally, the probability of input events joined through an AND gate are 

multiplied to calculate the probabilities of the output event. The probabilities of input 

events joined through an OR gate are added to calculate the probability of the output 

event. The relevant equations and associated assumptions may be summarized as follows: 

 

For AND Gate: (4.1a)

 

 Example: Output Event Probability = Px 

 Input Events failure probabilities, P1, P2, .... 

 (4.1b)

For OR Gate: (4.2a)

 Example: Output Event Probability = Py 

 Input Event failure probabilities, P1, P2, ... 

 

 (4.2b)

In more complex fault trees, it is necessary to assure that base events which affect more 

than one fault tree branch are not numerically duplicated. This is done through the use of 

minimal cut-set theory [1, 6]. However, as indicated earlier, the fault trees used in this 

study are sufficiently simple in structure and level of detail to exclude the requirement of 

using minimal cut-set theory in their computation algorithms. 

4.2.2 Current Application of Fault Trees 

Figure 4.2 illustrates a two-tier fault tree that can be used to develop pipeline large spill 

frequencies for the Arctic study area from the historical frequencies. Note that this 

example is illustrative of the process only, and does not correspond to the same numerical 

values used in computations later. The type of fault tree shown, to be used extensively 

later, is a relatively simple fault tree showing the resultant event, the spill, generated from 

a series of subresultant events corresponding to the pipeline spill causal classification, 

such as that shown in Table 2.3. The upper tier of numbers (marked “H”) below each of 

the events in the fault tree represents the historical frequency (per 100,000 km-yr) while 

the lower one (marked “A”) represents the modified frequency for Arctic operations. As 

these fault trees are composed entirely of OR gates, the computation of resultant events is 

quite simple – consisting of the addition of the probabilities of events at each level of the 

fault tree to obtain the resultant probability at the next higher value. 

i

i

n

P P

1

 

( )( ) Px  P1 P2 P3

1 (1 )

1

i

i

n

P     P 

1 (1 )(1 )(1 ) P P1 P2 P3 n y      

Py  P1  P2  P3 ; for Pi  0.1
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4.4

Figure 4.2 

Example of Fault Tree to Transform Historical (GOM and PAC) to Arctic Spill Frequencies1 

1 The input data used here are only illustrative and do not represent the inputs used later in this study. 
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4.5

For example, to obtain the “Natural Hazard” Arctic (“A”) probability of 0.151, add 0.043 

and 0.108. Essentially, the fault tree resultant (top event) shows that the Arctic frequency 

of spills (for the example pipeline category, location, and spill size) is approximately 

1 in 100,000 km-yr or 1.015 x 10-5/km-yr. The non-Arctic historical frequency for this 

spill size, by comparison, is 2.799 x 10-5/km-yr, or approximately 2.8 times higher. Both 

frequencies are for illustrative purposes only. 

4.2.3 Monte Carlo Simulation 

A type of numerical simulation, called Monte Carlo simulation [9] can be used to obtain 

the outcome of a set of interactions for equations in which the independent variables are 

described by distributions of any arbitrary form. The Monte Carlo simulation is a 

systematic method for selecting values from each of the independent variable 

distributions and computing all valid combinations of these values to obtain the 

distribution of the dependent variable. Naturally, this is done utilizing a computer, so that 

thousands of combinations can be rapidly computed and assembled to give the output 

distribution. 

Consider the example of the following equation: 

X = X1 + X2 (4.3) 

Where X is the dependent variable (such as the resultant spill frequency) and X1 and X2

are base event probabilities joined through an OR gate. Suppose now that X1 and X2 are 

some arbitrary distributions that can be described by a collection of values x1 and x2. 

What we do in the Monte Carlo process, figuratively, is to put the collection of the X1

values into one hat, the X1 hat, and the same for the X2 values – into an X2 hat. We then 

randomly draw one value from each of the hats and compute the resultant value of the 

dependent variable, X, using Equation 4.3. This is done several thousand times. Thus, a 

resultant or dependent variable distribution, X, is estimated from the computations of all 

valid combinations of the independent variables (X1 and X2). 

Generally, the resultant can be viewed as a cumulative distribution function as illustrated 

in Figure 4.3. Such a cumulative distribution function (CDF) is also a measure of the 

accuracy or, conversely, the variance of the distribution. As can be seen from this figure, 

if the distribution is a vertical line, no matter where one draws on the vertical axis, the 

same value of the variable will result – that is, the variable is a constant. At the other 

extreme, if the variable is completely random then the distribution will be represented as 

a diagonal straight line between the minimum and maximum value. Intermediate 

qualitative descriptions of the randomness of the variable follow from inspection of the 

CDF in Figure 4.3. 
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4.6

Figure 4.3: Monte Carlo Technique Schematic 
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4.7

There are two other important concepts related to the CDF that enter into Monte Carlo 

modeling: namely, auto-correlation and cross-correlation. Suppose the variables X1 can 

vary only within a specified interval over the simulation time increment. Then, after the 

first random draw, the next draw would be restricted within certain limits of the initial 

draw simply as a result of the physical restrictions of the problem. Such a restriction is 

represented as an auto-correlation coefficient. Now, suppose that not only are the X1

restricted, but also the X2. Suppose further, however, that given a certain X1, a restriction 

were placed on the range of X2 associated with that X1. Say, only small X1 could 

associate with the full range of X2, while large X1 could only be associated with certain 

lower X2. Then, such a relationship would be expressed as a cross-correlation factor and 

certain limits would be imposed for the drawing on both X1 and associated X2. In the 

present analysis, all distributed variables are considered to be independent – so that auto 

and cross-correlations need not be invoked. 

4.2.4 Distribution Derived from Historical Data for Monte Carlo Analysis 

In order to model the variability of the base data and its distribution through the Arctic 

effects, using the Monte Carlo approach, an appropriate distribution needs to be derived. 

As in the previous study [16, 17], a Triangular Distribution was selected. 

According to [31, 43], the Triangular Distribution is typically used as a descriptor of a 

population for which there is only limited sample data, as is the current case. The 

distribution is based on a knowledge of a minimum and maximum, which was derived 

from the historical data here, and an educated guess as to what the modal value might be. 

Here, the modal value was chosen to be a function of the average historical value, as 

given in Equation 2.1. Despite being a simplistic description of a population, the 

Triangular Distribution is a very useful one for modeling processes where the relationship 

between variables is understood, but data are scarce. 

Also, when combining several variables in a functional relationship utilizing numerical 

methods, as is done in Monte Carlo Simulation, the Triangular Distribution is a preferred 

one due to its simplicity and relatively accurate probabilistic resultant when evaluated by 

a large number of random draws, as occurs in the Monte Carlo process. The data used 

here typifies sparse data with a preferred or modal value and an easily identifiable 

maximum and minimum. Then, for the case of the simple upper and lower 100% 

confidence interval (called High and Low), the expected value E (or mean value) of the 

Triangular Distribution can be expressed as: 

E = (High + Mode + Low) / 3 (4.4) 

For maximum and minimum which are not at the 100% confidence interval level – such 

as those at 90% confidence levels – a Monte Carlo computation is used to evaluate the 

expected value of each distribution. Based on the historical data presented earlier in 

Chapter 2 the Triangular Distribution expected values computed from the low, mode, and 

high values at 90% confidence intervals are given in Tables 4.1, 4.2, and 4.3, for 

pipelines, the island, and wells, respectively. The modes from high and low values were 

calculated as described in Section 2.2. 
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4.8

Table 4.1 

PIP Pipeline Spill Frequency Distribution Properties 

GOM and PAC OCS 

Pipeline Spills, 

Categorized 1972-2010 

NPS > 10" 

Frequency Unit Low 

Factor 

High 

Factor Historical Low Mode High Expected 

Small (50-99 bbl) Spill per 105 km-years 0 2.81 1.182 0 0.224 3.320 1.482 

Medium (100-999 bbl) Spill per 105 km-years 0 2.81 3.249 0 0.617 9.130 4.076 

Large(1,000-9,999 bbl) Spill per 105 km-years 0 2.81 1.360 0 0.258 3.821 1.706 

Huge (=>10,000 bbl) Spill per 105 km-years 0 2.81 0.388 0 0.074 1.092 0.487 

Table 4.2 

Island Spill Frequency Distribution Properties 

Spill Size Frequency Unit Low 

Factor 

High 

Factor Historical Low Mode High Expected 

Small and Medium Spills 

(50-999 bbl) 

Spill per 

104 well-year 0 3 4.766 0.0000 0.0000 14.298 6.355 

Large and Huge Spills 

(>= 1000 bbl) 

Spill per 

104 well-year 0 3 0.285 0.0000 0.0000 0.855 0.380 

Table 4.3 

LOWC Frequency Distribution Properties 

Frequencies Spill Size Event Frequency Unit Low 

Factor 

High 

Factor Historical Low Mode High Expected

Production Well spill per 104 well-year 0.448 1.545 0.028 0.012 0.028 0.043 0.028 

Exploration Well Drilling spill per 104 wells 0.439 2.036 1.330 0.584 0.698 2.708 1.530 

Small and Medium 

Spills 

(50-999 bbl) Development Well Drilling spill per 104 wells 0.437 1.760 0.283 0.124 0.227 0.498 0.299 

Production Well spill per 104 well-year 0.448 1.545 0.011 0.005 0.011 0.017 0.011 

Exploration Well Drilling spill per 104 wells 0.439 2.036 0.539 0.237 0.283 1.097 0.620 

Large Spills 

(1,000-9,999 bbl) 

Development Well Drilling spill per 104 wells 0.437 1.760 0.115 0.050 0.092 0.202 0.122 

Production Well spill per 104 well-year 0.448 1.545 0.039 0.017 0.039 0.060 0.039 

Exploration Well Drilling spill per 104 wells 0.439 2.036 1.869 0.821 0.981 3.805 2.150 

Small, Medium 

and Large Spills 

(50-9,999 bbl) Development Well Drilling spill per 104 wells 0.437 1.760 0.398 0.174 0.320 0.700 0.421 

Production Well spill per 104 well-year 0.448 1.545 0.007 0.003 0.007 0.011 0.007 

Exploration Well Drilling spill per 104 wells 0.439 2.036 0.350 0.154 0.184 0.713 0.403 

Spill 

(10,000- 

149,999 bbl) Development Well Drilling spill per 104 wells 0.437 1.760 0.075 0.033 0.060 0.131 0.079 

Production Well spill per 104 well-year 0.448 1.545 0.005 0.002 0.005 0.007 0.004 

Exploration Well Drilling spill per 104 wells 0.439 2.036 0.217 0.095 0.114 0.442 0.250 

Spill 

(=>150,000 bbl) 

Development Well Drilling spill per 104 wells 0.437 1.760 0.046 0.020 0.037 0.081 0.049 
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4.2.5 Approaches to Assessment of Arctic Spill Frequency Variability 

The method for assessment of Arctic spill frequency variability consists of systematically 

perturbing the variability of all the causal events, plus that of the Arctic unique effects. In 

this approach, the non-Arctic variable distribution is multiplied by an adjustment or 

correction distribution to obtain the Arctic variable distribution. 

4.3 Pipeline Fault Tree Analysis

4.3.1 Arctic Pipeline Spill Causal Frequency Distributions 

The effects of the Arctic environment and operations are reflected in the effect on facility 

failure rates in two ways; namely, through “Modified Effects”, those changing the 

frequency component of certain fault contributions such as anchor impacts which are 

common to both Arctic and temperate zones, and through “Unique Effects” or additive 

elements such as ice gouging which are unique to the Arctic offshore environment. Table 

4.4 shows the frequency modifications (in %) and frequency increment additions (per 

105

 km-yr) developed for Arctic pipelines for different spill sizes throughout the three 

relevant water depth ranges. The right hand column of the table gives a summary of the 

reasoning behind the effects. For the Arctic unique effects, both the mode value (from 

Table 2.14) and the expected value, determined through the Monte Carlo analysis, are 

given. The mode values differ from the expected values due to skewness of the 

distributions introduced through the assigned values of the upper and lower bounds 

(Table 2.14). The following comments can be made for each of the causes described: 

 External corrosion – Due to the low temperature, limited biological and lowered 

chemical effects are expected. Coatings will be state of art and high level of quality 

control will be used during pipeline installation resulting in high integrity levels of 

coating to prevent external corrosion. 

 Internal corrosion – Additional (above historical levels) inspection or smart pigging 

is anticipated. 

 Anchor impact – The very low traffic densities of third party shipping in the area 

justify a 50% reduction in anchor impact expectations on the pipeline. 

 Jack-up rig or spud barges – Associated or other operations are going to be 

substantially more limited than they are in the historical data population in the GOM 

and PAC OCS. 

 Trawl/Fishing net – Less fishing is expected in the Beaufort Sea. 

 Rig anchoring – Although it is anticipated that no marine traffic except possibly 

icebreakers will occur during the ice season, an increased traffic density during the 

four month open water season to resupply the platforms is expected, justifying only a 

20% decrease in this failure cause. 

 Work boat anchoring – The same applies to work boat anchoring as to rig anchoring. 

 Mechanical connection failure or material failure – No change was made to account 

for Arctic effects. 
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Table 4.4 

PIP Pipeline Arctic Effect Derivation Summary 

PIP Pipeline Arctic LOC Frequency Change % REASON CAUSE 

CLASSIFICATION 

1972-2010 

Spill 

Size 

Min Mode Max Expected Note: Reduction in Frequency in either NPS 12 or 16 will 

reduce PIP LOC Frequency 

CORROSION 

External All (90) (30) (10) (45.91) Low temperature NPS16, state of art coating. 

Internal All (90) (40) (10) (47.93) Dehydrated oil, regular pigging internal pipe. 

THIRD PARTY IMPACT 

Anchor Impact All (90) (50) (10) (50.00) Low traffic, patrols and warnings. 

Jackup Rig or Spud Barge All (90) (60) (10) (52.07) Low facility density, unlikely presence of jackup or barge 

as drilling is from island. 

Trawl/Fishing Net All (90) (40) (10) (47.93) Low fishing activity, warning signs. 

OPERATION IMPACT 

Rig Anchoring All (90) (70) (10) (54.09) No rig anchoring as island used as drill platform. No rigs 

planned near pipeline. 

Work Boat Anchoring All (70) (40) (10) (40.00) Low work boat traffic especially during ice season (8 

months). 

MECHANICAL 

Connection Failure All No change 

Material Failure All No change 

NATURAL HAZARD 

Mud Slide All (90) (80) (10) (55.97) Sea bottom gradient low. 

Storm/ Hurricane All (90) (85) (10) (56.76) Fewer severe storm effects inside barrier islands. 

PIP LOC Frequency Increment per 105 kmARCTIC year Spill 

Size 

Min Mode Max Expected 

REASON 

S 0.0006 0.0028 0.1250 0.0517 

M 0.0006 0.0028 0.1250 0.0517 

L 0.0016 0.0070 0.3125 0.1292 Ice Gouging 

H 0.0003 0.0014 0.0625 0.0258 

Ice Gouge Failure Rate calculated using exponential 

failure distribution for 3.05 m cover, 0.2 m average gouge 

depth, 2 gouges per km-yr flux. 

S 0.0011 0.0023 0.0138 0.0065 

M 0.0011 0.0023 0.0138 0.0065 

L 0.0028 0.0059 0.0345 0.0161 

Strudel Scour 

H 0.0006 0.0012 0.0069 0.0032 

Average Frequency of 3.4 critical scours/105 km-yr and 

100 ft of bridge length with 2% conditional pipeline failure 

probability. The same spill size distribution as above. 

S 0.0002 0.0005 0.0028 0.0013 

M 0.0002 0.0005 0.0028 0.0013 

L 0.0006 0.0012 0.0069 0.0032 Upheaval Buckling 

H 0.0001 0.0002 0.0014 0.0006 

The Failure Frequency is 20% of that of Strudel Scour. 

S 0.0001 0.0002 0.0014 0.0006 

M 0.0001 0.0002 0.0014 0.0006 

L 0.0003 0.0006 0.0035 0.0016 

Thaw Settlement 

H 0.0001 0.0001 0.0007 0.0003 

The Failure Frequency is 10% of that of Strudel Scour. 

S 0.0002 0.0006 0.0143 0.0060 

M 0.0002 0.0006 0.0143 0.0060 

L 0.0005 0.0015 0.0357 0.0150 

Other Arctic 

H 0.0001 0.0003 0.0071 0.0030 

To be assessed as 10% of all Arctic effects. 
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 Mudslide – Low gradient resulting in limited mudslide potential.

 Storms – Considerably fewer severe storms are anticipated on an annual basis in the 

Arctic particularly shoreward of the barrier islands than in GOM or PAC, due to 

damping of the ocean surface by ice cover and reduction of fetch by barrier islands in 

open water season. 

 Arctic unique effects – Arctic effects are effects which are unique to the Arctic and 

are not reflected in the historical fault tree itself. Arctic effects were discussed in 

detail in Chapter 2, Section 2.6. The discussion in that section is summarized in the 

right hand column of Table 4.4. The frequency increments in this table are again 

given as both the “mode” values and the “expected” values. The mode values are the 

mode values given in Table 2.14. The expected values, however, are those calculated 

using the Monte Carlo method with the low, mode, and high values from Table 2.14, 

as inputs to the Monte Carlo. The expected values are clearly considerably higher 

than the mode or most likely values. This lack of coincidence between expected and 

mode values is due to the skewness of the distribution. 

Derivation of the Arctic effect distributions is accomplished through the construction of a 

secondary triangular distribution by which the historical causal frequency distributions 

are multiplied to provide the resultant Arctic effect distribution. This secondary 

distribution utilizes the value of mode adjustments from Table 4.4, with appropriate 

second order perturbations for the upper and lower 90% confidence interval bounds. 

Table 4.5 summarizes these Arctic effect distributions. For the Arctic modified effects, 

given in the top of the table, the secondary distribution is simply the frequency change 

used as the mode of the distribution, and 90% upper and lower confidence interval 

changes given under the Min and Max columns. For the Arctic unique effects, total 

frequency increments are given, with the upper confidence interval value at 

approximately 45 times the mode, and the lower bound value at approximately 1

/5 of the 

modal value in the case of S (small) spill Ice Gouging. 

4.3.2 Arctic Pipeline Fault Tree Frequency Calculations 

Incorporation of the frequency effects as variations in and additions to the historical 

frequencies can be represented in a fault tree, as shown for the large spill size for Arctic 

pipelines in Figure 4.4. In this figure, the historical frequency as well as those associated 

with S, M, L, and H spill sizes are shown under each of the event boxes. 

The PIP frequency calculation fault tree shown is in Figure 4.4. Consider the bottom line 

for Huge Spills. This tells us that the Huge spill frequency for PIP pipelines was 0.487 

(per 105

 km-yr) as derived by a reliability analysis based on historical data. With the first 

and second order frequency changes attributable to Arctic effects, this frequency is 

reduced to 0.258 for Huge spills for the Liberty PIP pipeline. 

Table 4.5 gives the detailed fault tree inputs. Table 4.6 summarizes the fault tree output 

expected values of the pipeline spill frequencies for each spill size for the historical \pip 

and the Liberty PIP, and Figure 4.5 graphically depicts these results. Clearly the Liberty 

PIP LOC frequency is lower than historical frequencies. 
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Table 4.5 

PIP Pipeline Arctic Effect Causal Distribution Derivation Summary 

SMALL SPILLS 

50-99 bbl 

MEDIUM SPILLS 

100-999 bbl 

LARGE SPILLS 

1,000-9,999 bbl 

HUGE SPILLS 

>= 10,000 bbl 

CAUSE 

 CLASSIFICATION 

1972-2010 

Historical PIP Pipeline % Frequency spills 

per 105km-year 

Frequency Change 

New Frequency 

New Distribution 

 % 

Frequency spills 

per 105km-year 

Frequency Change 

New Frequency 

New Distribution 

 % 

Historical PIP Pipeline % Frequency spills 

per 105km-year 

Frequency Change 

New Frequency 

New Distribution 

 % 

Frequency spills 

per 105km-year 

Frequency Change 

New Frequency 

New Distribution 

 % 

CORROSION 0.00 0.000 (0.000) 0.000 0.00 0.000 (0.000) 0.000 0.00 0.00 0.000 (0.000) 0.000 0.00 0.000 (0.000) 0.000 0.00 

External 0.00 0.000 (0.000) 0.000 0.00 0.000 (0.000) 0.000 0.00 

Internal 0.00 0.000 (0.000) 0.000 0.00 0.000 (0.000) 0.000 0.00 0.00 0.000 (0.000) 0.000 0.00 0.000 (0.000) 0.000 0.00 

THIRD PARTY IMPACT 13.43 0.199 (0.104) 0.095 12.27 0.547 (0.285) 0.262 12.98 54.05 0.922 (0.480) 0.442 46.32 0.263 (0.137) 0.126 48.86

Anchor Impact 0.00 0.000 (0.000) 0.000 0.00 0.000 (0.000) 0.000 0.00 0.00 0.000 (0.000) 0.000 0.00 0.000 (0.000) 0.000 0.00 

Jackup Rig or Spud Barge 13.43 0.199 (0.104) 0.095 12.27 0.547 (0.285) 0.262 12.98 54.05 0.922 (0.480) 0.442 46.32 0.263 (0.137) 0.126 48.86

Trawl/Fishing Net 

OPERATION IMPACT 4.70 0.070 (0.035) 0.035 4.48 0.192 (0.096) 0.096 4.73 2.70 0.046 (0.018) 0.028 2.90 0.013 (0.005) 0.008 3.06 

Rig Anchoring 3.36 0.050 (0.027) 0.023 2.94 0.137 (0.074) 0.063 3.11 

Work Boat Anchoring 1.34 0.020 (0.008) 0.012 1.54 0.055 (0.022) 0.033 1.62 2.70 0.046 (0.018) 0.028 2.90 0.013 (0.005) 0.008 3.06 

MECHANICAL 0.00 0.000 0.000 0.00 0.000 0.000 0.00 

Connection Failure 0.00 0.000 0.000 0.00 0.000 0.000 0.00 

Material Failure 0.00 0.000 0.000 0.00 0.000 0.000 0.00 

NATURAL HAZARD 75.20 1.115 (0.632) 0.482 62.03 3.065 (1.739) 1.326 65.58 43.24 0.738 (0.418) 0.319 33.47 0.211 (0.120) 0.091 35.30

Mud Slide 1.34 0.020 (0.011) 0.009 1.13 0.055 (0.031) 0.024 1.19 2.70 0.046 (0.026) 0.020 2.13 0.013 (0.007) 0.006 2.24 

Storm/ Hurricane 73.86 1.095 (0.621) 0.473 60.91 3.010 (1.709) 1.302 64.39 40.54 0.691 (0.392) 0.299 31.34 0.198 (0.112) 0.085 33.06

ARCTIC 0.066 0.066 8.50 0.066 0.066 3.27 0.165 0.165 17.31 0.033 0.033 12.78

Ice Gouging 0.052 0.052 6.65 0.052 0.052 2.56 0.129 0.129 13.54 0.026 0.026 10.00

Strudel Scour 0.006 0.006 0.83 0.006 0.006 0.32 0.016 0.016 1.69 0.003 0.003 1.25 

Upheaval Buckling 0.001 0.001 0.17 0.001 0.001 0.06 0.003 0.003 0.34 0.001 0.001 0.25 

Thaw Settlement 0.001 0.001 0.08 0.001 0.001 0.03 0.002 0.002 0.17 0.000 0.000 0.12 

Other Arctic 0.006 0.006 0.77 0.006 0.006 0.30 0.015 0.015 1.57 0.003 0.003 1.16 

UNKNOWN 6.67 0.099 0.099 12.71 0.272 0.272 13.44 

TOTALS 100.00 1.482 (0.705) 0.777 100.00 4.076 (2.054) 2.021 100.00 100.00 1.706 (0.752) 0.954 100.00 0.487 (0.229) 0.258 100.00
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Figure 4.4 

Spill Frequencies for Arctic PIP Pipeline 

Historical Arctic

S 1.482 0.777 Small Spill (50-99 bbl)

M 4.076 2.021 Medium Spill (100-999 bbl)

L 1.706 0.954 Large Spill (1,000-9,999 bbl)

H 0.487 0.258 Huge Spill (=> 10,000 bbl)

Historical Arctic Historical Arctic Historical Arctic Historical Arctic Historical Arctic Historical Arcti

S 0.000 0.000 S 0.199 0.095 S 0.070 0.036 S 0.000 0.000 S 1.115 0.482 S 0.099 0.09

M 0.000 0.000 M 0.547 0.282 M 0.192 0.096 M 0.000 0.000 M 3.065 1.326 M 0.272 0.27

L 0.000 0.000 L 0.922 0.442 L 0.046 0.028 L 0.000 0.000 L 0.738 0.319 L 0.000 0.00

H 0.000 0.000 H 0.263 0.126 H 0.013 0.008 H 0.000 0.000 H 0.211 0.091 H 0.000 0.00

Historical Arctic Historical Arctic Historical Arctic Historical Arctic Historical Arctic Histori

S 0.000 0.000 S 0.000 0.000 S 0.050 0.023 S 0.000 0.000 S 0.020 0.009 S 0.00

M 0.000 0.000 M 0.000 0.000 M 0.137 0.063 M 0.000 0.000 M 0.055 0.024 M 0.00

L 0.000 0.000 L 0.000 0.000 L 0.000 0.000 L 0.000 0.000 L 0.046 0.020 L 0.00

H 0.000 0.000 H 0.000 0.000 H 0.000 0.000 H 0.000 0.000 H 0.013 0.006 H 0.00

Historical Arctic Historical Arctic Historical Arctic Historical Arctic Historical Arctic Histori

S 0.000 0.000 S 0.199 0.095 S 0.020 0.012 S 0.000 0.000 S 1.095 0.473 S 0.00

M 0.000 0.000 M 0.547 0.282 M 0.055 0.033 M 0.000 0.000 M 3.010 1.302 M 0.00

L 0.000 0.000 L 0.922 0.442 L 0.046 0.028 L 0.000 0.000 L 0.531 0.299 L 0.00

H 0.000 0.000 H 0.263 0.126 H 0.013 0.008 H 0.000 0.000 H 0.196 0.085 H 0.00

Historical Arctic 

S 0.000 0.000 

M 0.000 0.000 

L 0.000 0.000 

H 0.000 0.000 

PIP Pipeline Spill

CORROSION

External

Internal Jackup Rig or Spud Barge

MECHANICAL

Work Boat Anchoring

THIRD PARTY IMPACT OPERATION IMPACT

Expected Values per 105 km-year

Trawl/Fishing Net

Anchor Impact

Connection Failure

Material Failure

Rig Anchoring

S

NATURAL HAZARD

Mud Slide

Storm/ Hurricane

UNKNOWN
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Table 4.6 

Expected Value Summary of Arctic PIP Pipeline Spill Frequencies 

Spill Frequency 

per 105 km-year 

Expected Spill Frequency 

per 105 km-year Pipeline Spill Size Historical 

Pipeline 

Historical PIP 

Pipeline 

Historical PIP 

Pipeline 

Arctic 

PIP Pipeline 

Small Spills 

50-99 bbl 3.570 1.182 1.482 0.777 

Medium Spills 

100-999 bbl 9.817 3.249 4.076 2.021 

Large Spills 

1,000-9,999 bbl 6.247 1.360 1.706 0.954 

Huge Spills 

=>10,000 bbl 1.785 0.388 0.487 0.258 

Figure 4.5: Expected Value Summary of Arctic PIP Pipeline Spill Frequencies 
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4.4 Island Fault Tree Analysis

4.4.1 Arctic Island Spill Causal Frequency Distributions

Table 4.7 summarizes the variations in the modified and unique Arctic effect inputs for 

the island. As for pipeline unique effects, both the Triangular Distribution expected and 

modal values are given. 

The first two modified cause classifications, equipment failure and human error modes 

were reduced by 30 and 20%, respectively, primarily as a result of the state-of-the-art 

engineering, construction, and operational standards and practices expected. Collisions 

were reduced by 80% based on low vessel traffic expectations. As before, storms tend to 

be less severe in the Arctic, and certainly during the ice season would have limited 

impact on the facility, resulting in an 85% reduction in hurricane causes. However, 

weather in general, including very low temperatures, have been increased by 20%. 

Unique effects are also included. Increments in facility spills were attributed to ice force, 

low temperature effects, and unknown effects which were taken as a percentage of the 

other unique Arctic effects. Ice force effect calculations were based on the 1/10,000 year 

ice force causing spills, predominantly small and medium. Increase of low temperature 

effects was estimated as 6% for S and M spills, and 1% for L and H spills (as large spills 

are highly unlikely from the island process facilities) of historical process facility spill 

rates. 

Changes in frequency distribution attributable to Arctic effects were calculated using the 

secondary effect probability distribution, as was done for pipelines. Table 4.8 summarizes 

the principal distribution parameters for both the Arctic modified and Arctic unique effect 

distributions. 

4.4.2 Arctic Island Fault Tree Spill Frequency Calculations

Figure 4.6 shows the fault tree developed for the island Arctic spills for small and 

medium (SM), and large and huge spill (LH) sizes in accordance with [15]. Again, the 

fault tree gives the historical value, together with the calculated values for these spill 

sizes. Table 4.9 summarizes the historical and derived Arctic expected values of island 

spill frequencies, and Figure 4.7 gives a bar chart with these values. 
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Table 4.7 

Island Arctic Effect Derivation Summary 

Island Arctic 

Spill Frequency Change % 

CAUSE 

CLASSIFICATION 

1972 – 2010 

(no LOWC) Min Mode Max Expected 

REASON 

EQUIPMENT 

FAILURE All (60) (30) (10) (33.96) State of the art, High QC, High Inspection and 

Maintenance Requirements 

HUMAN ERROR All (60) (20) (10) (31.96) More qualified personnel 

COLLISION All (90) (80) (10) (55.97) Low traffic density, island resistant to ship impacts 

WEATHER All 10 20 30 20.00 Cold Temperatures, rapid changes or cycling 

HURRICANE All (90) (85) (10) (56.76) Fewer severe storm effects inside barrier islands. 

Spill Frequency Increment 

per 10 ARCTIC UNIQUE 4 well-year Spill 

Size Min Mode Max Expected 

REASON 

SM 0.001 0.009 0.085 0.0362 

Ice Force 

LH 0.000 0.002 0.015 0.0064 

Assumed 10,000 year return period ice force 

causes spill 1% of occurrences (99% reliability). 

85% of the spills are SM as due to ride-up impact 

only. 

Facility Low SM 0.043 0.086 0.128 0.0855 

Temperature LH 0.000 0.000 0.001 0.0004 

Assumed fraction of Historical Equipment Failure 

release frequency with 6% for SM and 1% for LH 

spill sizes. 

SM 0.004 0.009 0.021 0.0121 

Other Arctic 

LH 0.000 0.000 0.002 0.0007 

10% of sum of above. 

Table 4.8 

Arctic Island Spill Size Frequency Distribution 

SMALL AND MEDIUM SPILLS 

50-999 bbl 

LARGE AND HUGE SPILLS 

=>1,000 bbl 

CAUSE CLASSIFICATION 

1972 - 2010 (no LOWC) 

Historical Distribution % 

FREQUENCY 

spills per 104well-year 

Frequency Change 

New Frequency 

New Distribution % 

Historical Distribution % 

FREQUENCY 

spills per 104well-year 

Frequency Change 

New Frequency 

New Distribution % 

EQUIPMENT FAILURE 29.91 1.901 (0.646) 1.255 33.94 14.29 0.054 (0.018) 0.036 13.40 

HUMAN ERROR 11.11 0.706 (0.226) 0.480 12.99 

COLLISION 0.85 0.054 (0.030) 0.024 0.65 

WEATHER 4.27 0.272 0.054 0.326 8.81 28.57 0.109 0.022 0.130 48.71 

HURRICANE 53.85 3.422 (1.942) 1.480 40.00 57.14 0.217 (0.123) 0.094 35.10 

ARCTIC 0.134 0.134 3.619 0.007 0.007 2.791 

Ice Force 0.036 0.036 0.98 0.006 0.006 2.39 

Facility Low Temperature 0.086 0.086 2.31 0.000 0.000 0.15 

Other Arctic 0.012 0.012 0.33 0.001 0.001 0.25 

TOTALS 100.00 6.355 (2.656) 3.699 100.00 100.00 0.380 (0.113) 0.268 100.00 
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Figure 4.6 

Spill Frequencies Liberty Island Fault Tree 

Historical Arctic

SM 6.355 3.699 Small and Medium Spill (SM)

LH 0.380 0.268 Large and Huge Spill (LH)

Historical Arctic Historical Arctic Historical Arctic Historical Arctic Historical Arctic 

SM 1.901 1.255 SM 0.706 0.480 SM 0.054 0.024 SM 0.272 0.326 SM 3.422 1.480 SM 

LH 0.054 0.036 LH 0.000 0.000 LH 0.000 0.000 LH 0.109 0.130 LH 0.217 0.094 L

Historical Arctic Historical Arctic 

SM 0.000 0.036 SM 0.000 0.086 SM 

LH 0.000 0.006 LH 0.000 0.000 L

Island Spill

WEATHER HURRICANE EQUIPMENT FAILURE HUMAN ERROR COLLISION

Expected values per 104 well-year

Facility Low Temperature Ice Force
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Table 4.9 

Arctic Island Spill Frequency Expected Value Summary 

Spill Frequency

per 104 well-year 

Expected Spill Frequency 

per 104 well-year Island Spill Size 

Historical Historical Arctic 

SMALL AND MEDIUM SPILLS 

50-999 bbl 4.766 6.355 3.699 

LARGE AND HUGE SPILLS 

=>1,000 bbl 0.285 0.380 0.268 

Figure 4.7: Arctic Island Spill Frequency Expected Value Bar Chart 
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4.5 Loss of Well Control (LOWC) Arctic Frequency Analysis 

4.5.1 LOWC Arctic Effects 

The historical data, as described in Chapter 2, were modified for each well type, spill 

size, and water depth range for Arctic effects (on historical values), as described in Table 

4.10. No Arctic unique effects were introduced for LOWC. 

Table 4.10 

LOWC Fault Tree Analysis Arctic Effect Summary 

Spill Size Event Frequency Unit 

Historical 

Frequency Change 

%

Reason 

Production Well spill per 104 well-year (30) State of the art, High QC, High Inspection and Maintenance standard 

Exploration Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

Small and Medium Spills 

50-999 bbl

Development Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

Production Well spill per 104 well-year (30) State of the art, High QC, High Inspection and Maintenance standard 

Exploration Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

Large Spills 

1,000-9,999 bbl

Development Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

Production Well spill per 104 well-year (30) State of the art, High QC, High Inspection and Maintenance standard 

Exploration Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

Spill 

10,000-149,999 bbl

Development Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

Production Well spill per 104 well-year (30) State of the art, High QC, High Inspection and Maintenance standard

Safety culture dedicated to avoid large spills in Arctic 

Exploration Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

Spill 

>=150,000 bbl

Development Well Drilling spill per 104 wells (10) Highly qualified drilling contractor. Better logistics support 

4.5.2 Arctic LOWC Spill Frequency Calculation 

Table 4.11 gives the details of the frequency calculation for LOWC. No fault tree was 

required here, as only base events with no causal distributions were modeled for each 

case. The modifications given in Table 4.10 were applied to historical values to yield the 

values summarized in Table 4.11. 

Figures 4.8 and 4.9 give, respectively, the well drilling and production well historical and 

Project LOWC frequency bar charts. 

4.6 Spill Volume Distributions 

Tables 4.12, 4.13, and 4.15 summarize the spill volume distribution parameters for each 

project component, including the expected value that was calculated utilizing a Monte 

Carlo calculation. The spill volume parameters were derived from the historical data 

described in Section 2.7. No Arctic effects are factored into the spill volume values. 
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Table 4.11 

Arctic LOWC Frequencies 

Spill Size Event Frequency Unit Historical 

Frequency 

Frequency 

Change 

Middle Shelf 

New Frequency 

Middle Shelf 

Production Well spill per 104 well-year 0.028 (0.008) 0.019 

Exploration Well Drilling spill per 104 wells 1.530 (0.153) 1.377 

Small and Medium 

Spills 

50-999 bbl Development Well Drilling spill per 104 wells 0.299 (0.030) 0.269 

Production Well spill per 104 well-year 0.011 (0.003) 0.008 

Exploration Well Drilling spill per 104 wells 0.620 (0.062) 0.558 Large Spills 

1,000-9,999 bbl Development Well Drilling spill per 104 wells 0.122 (0.012) 0.109 

Production Well spill per 104 well-year 0.007 (0.002) 0.005 

Exploration Well Drilling spill per 104 wells 0.403 (0.040) 0.362 Spill 

10,000-149,999 bbl Development Well Drilling spill per 104 wells 0.079 (0.008) 0.071 

Production Well spill per 104 well-year 0.004 (0.001) 0.003 

Exploration Well Drilling spill per 104 wells 0.250 (0.025) 0.225 Spill 

>=150,000 bbl Development Well Drilling spill per 104 wells 0.049 (0.005) 0.044 

Figure 4.8: Drilling LOWC Frequencies 
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Figure 4.9: Production Well LOWC Frequencies 

Table 4.12 

Pipeline Spill Volume Parameters 

Spill Size Small Spills 

50-99 bbl 

Medium Spills 

100-999 bbl 

Large Spills 

1,000-9,999 bbl 

Huge Spills 

=>10,000 bbl 

Spill Expectation Low Mode High Expected Low Mode High Expected Low Mode High Expected Low Mode High Expected

Pipeline Diameter 

> 10" Spill 50 58 99 71 100 387 999 516 1,000 3,932 9,999 5,176 10,000 17,705 20,000 15,552 

Table 4.13 

Island Spill Volume Parameters 

Spill Size Small and Medium Spills 

50-999 bbl 

Large and Huge Spills 

=>1,000 bbl 

Spill Expectation Low Mode High Expected Low Mode High Expected 

Island Spill 50 158 999 452 1,000 6,130 10,000 5,631 
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Table 4.14 

LOWC Spill Volume Parameters 

Spill Size Small and Medium Spills 

50-999 bbl 

Large Spills 

1,000-9,999 bbl Spills 10,000-149,999 bbl Spills =>150,000 bbl 

Spill Expectation Low Mode High Expected Low Mode High Expected Low Mode High Expected Low Mode High Expected

Well Spill 50 500 999 519 1,000 4,500 9,999 5,292 10,000 20,000 150,000 68,349 150,000 200,000 1,000,000 502,734 
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5.1

CHAPTER 5 

OIL SPILL OCCURRENCE INDICATOR QUANTIFICATION 

5.1 Definition of Oil Spill Occurrence Indicators 

Four primary oil spill occurrence indicators (generally referred to as “spill indicators” 

after this) were quantified in this study. These are as follows: 

 Frequency in spills per 1,000 years. 

 Frequency in spills per 109 barrels produced in each year. 

 Spill index, the product of spill frequency and associated average spill size. 

 Life of field indicators. 

The spill indicators defined above are subdivided for the Project as follows: 

 By facility type (3 types). 

 By spill size (4 sizes). 

 By year (2 to 25, which is 24 years inclusive). 

The above combinations translate into 12 sets of spill indicators per year. Given that 

these are calculated for each year, with the scenario lasting for 24 years, gives 288 sets of 

indicators. In this chapter, we will present and describe the salient results of the indicator 

evaluation. 

5.2 Oil Spill Occurrence Indicator Calculation Process 

The oil spill occurrence indicator calculation process is shown in the flow chart presented 

as Figure 5.1. This chapter discusses the spill occurrence indicator calculations as shown 

in the right hand column (“Spill Occurrence”) in Figure 5.1. Previous chapters covered 

the balance of the items in that figure. 

Essentially, this chapter addresses the combining of the development scenario described 

in Chapter 3 with the unit-spill frequency distributions presented in Chapter 4 to provide 

measures of oil spill occurrence, the oil spill indicators for the Project. Although the 

calculation is complex because of the many combinations considered, it is a simple 

process of accounting. Essentially, the quantities of potential oil spill sources are 

multiplied by their appropriate unit oil spill frequency to give the total expected spill 

distributions. To develop the probability distributions by the Monte Carlo process, each 

of the combinations needs to be sampled, in this case a sampling of 3,000 iterations was 

carried out for each combination studied. This translates into roughly 12 million 

arithmetic operations to generate the Monte Carlo results. 
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5.2

Chapter 5

Figure 5.1: Calculation Flow Chart 

5.3 Summary of Project Oil Spill Occurrence Indicators 

5.3.1 Project Oil Spill Occurrence Indicators 

Each of the principal annual total Project oil spill occurrence indicators including those 

for the pipeline, island, and wells by spill size for each year is given in Figures 5.2, 5.3, 

and 5.4. As can be seen, each of these figures spans the development scenario from year 

2 to 25, as described earlier in Table 3.3. Next, Figures 5.5, 5.6, and 5.7 give spill 

indicators by spill size for the pipeline, island, and wells, respectively. 

Each of the indicators has been subdivided into three segments for each year, those 

corresponding to spills 50-999 bbl (small and medium), spills 1,000-9,999 bbl (large), 

and spills >=10,000 bbl (huge). It should be noted that the spill frequency associated with 

each spill size is only the shaded increment shown in each of the bars. The horizontal axis 

gives Project years starting in Year 2 the first year with spill potential. Thus, for example, 

in Figure 5.2 for the year 10, small and medium spills are approximately 2.1 per thousand 

years. Next, in that year, large spills are approximately 0.16 per thousand years, as shown 

in the second bar increment. Finally, the top increment corresponds to huge spills, and is 

approximately 0.11 per thousand years. The same form of presentation applies for the 

spills per 109

 barrels produced and for the spill index shown in Figures 5.3 and 5.4. For 

years in which no production exists (2 and 3), the spills per 109

 barrels produced (Figure 

5.3) are not applicable. The spills per 109

 barrels produced continue to rise exponentially 

to the final production year (25), because the facility quantities (and hence spill rate) 

Fault Tree Analysis Hazard Scenarios Spill Occurrence

Spill Size

Frequency and Cause Arctic Spill Frequency Annual Annual 

Small Spill 50-99 bbl Shallow Water Frequency

Medium Spill 100-999 bbl Frequency per 109

 bbl Produced

Large Spill 1,000-9,999 bbl Spill Index 

Huge Spill >= 10,000 bbl LOF Average Frequency

Small and Medium Spills LOF Av Freq per 109

 bbl Produced

Large and Huge Spills LOF Average Spill Index

Small and Medium Spills

Large Spill 

Spill 10,000-149,999 bbl

Spill >=150,000 bbl

Exploration Well Drilling

Development Well Drilling

Production Well

Liberty Development

Non Arctic

Historical Data Analysis

Island

Liberty Development

Facility

Pipeline
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5.3

remain relatively high, while production volumes decrease considerably for each of the 

last few years. Clearly, the spill index (Figure 5.4) is dominated by the huge spills. The 

reader should note that following this detailed presentation of the total Project spill 

indicators in separate figures, each facility three spill indicators will be given in one 

figure in order to conserve space and make the report a little more concise. 

Spill indicators by facility type were also quantified. All three spill indicators for 

pipelines are shown in Figure 5.5. Figure 5.6 shows the spill indicators for the island 

(only for the two spill size categories available from the base data [15]), and Figure 5.7 

shows the spill indicators for drilling of wells and producing wells. Numerous 

conclusions can be drawn from the comparison of these spill indicators. For example, it 

can be seen that the major contributors to spill frequency is from the island (Figure 5.6), 

as for platforms in earlier studies [13, 16]. However, the largest of the facility spill 

expectations, as represented by spill index, is from the wells (Figure 5.7). 

Figure 5.2: Project Spill Frequency per 1,000 Years 

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Spill Frequency per 1,000 years

Liberty- Spill Frequency

Huge Spills

=>10,000 bbl

Large Spills

1,000-9,999 bbl

Small and Medium Spills

50-999 bbl
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Figure 5.3: Project Spill Frequency per 109 Barrels Produced 

Figure 5.4: Project Spill Index 
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5.5

Figure 5.5: Project Spill Indicators – Pipeline 

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Spill Frequency per 1,000 years

Liberty - Spill Frequency - P/L Huge Spills

=>10,000 bbl

Large Spills

1,000-9,999 bbl

Small and Medium Spills

50-999 bbl

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

0.50

2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Spill Frequency per 109 bbl produced

Liberty - Spill Frequency per 109 bbl Produced - P/L

Huge Spills

=>10,000 bbl

Large Spills

1,000-9,999 bbl

Small and Medium Spills

50-999 bbl
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Figure 5.6: Project Spill Indicators – Island 
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Figure 5.7: Project Spill Indicators – Wells 
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5.8

Finally, as part of the assessment of the Project scenario, a Monte Carlo analysis was 

carried out for each year, with the distributed inputs described earlier. The tabular results 

of the Monte Carlo simulation are summarized in Table 5.1 for the Project year 15. This 

table gives the statistical characteristics of the calculated indicators for each of three spill 

size ranges, as well as a tabular summary of their cumulative distribution curves. Figure 

5.8 shows graphs of the calculated cumulative distribution functions. Basically, the 

vertical axis gives the probability in percent that the corresponding value on the 

horizontal axis will not be exceeded. Thus, for example, referring to the right-hand 

central graph, for substantial spills >= 1,000 bbl (large and huge), there is a 50% 

probability that a spill frequency will be no more than 0.085 per billion barrels produced 

in year 15. In other words, there is a 50% chance that large and huge spills will occur at a 

rate of 0.085 per billion bbl or less. 

The frequency spill indicator variability can be estimated from the upper (95%) and 

lower (5%) bound values. For example, for large spill frequency (from Table 5.1), the 

lower bound (0.038) is 23% of the mean (0.163); the upper bound (0.332), 203% of the 

mean. The flattening or decrease in slope of the CDFs above 90% and below 10% can be 

attributed to the use of the triangular distribution with designated limits at corresponding 

(± 10%) levels. 

In addition, the Life of Field (LOF) averages were calculated. Table 5.2 shows the 

composition of the spill indicators for the Project Life of Field average, and includes all 

principal sources combined. The variability of the spill indicators for the Life of Field 

averages is shown in the following figures for all principal sources individually and 

combined. Figure 5.9 illustrates the variability of the spill frequency. Figure 5.10 shows 

variability of frequency per billion barrels produced. Figure 5.11 shows the variability of 

the Spill Index. 

Figures 5.12 and 5.13 give the bar graphs of the Project LOF spill indicators by spill size 

and source, respectively, for both the project and its non-Arctic counterpart. 

Table 5.3 gives the summary of spill indicators by spill size and source facility for both 

the project and its non-Arctic counterpart, to be discussed further in Section 5.3.2. 
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5.9

Table 5.1 

Project Year 15 – Monte Carlo Results 

Liberty 

Year 15 

Small and Medium 

Spills (50-999 bbl) 

Large Spills 

(1,000-9,999 bbl) 

Huge Spills 

(=>10,000 bbl) 

Substantial Spills 

(=>1,000 bbl) 

All Spills 

Small and Medium 

Spills (50-999 bbl) 

Large Spills 

(1,000-9,999 bbl) 

Huge Spills 

(=>10,000 bbl) 

Substantial Spills 

(=>1,000 bbl) 

All Spills 

Small and Medium 

Spills (50-999 bbl) 

Large Spills 

(1,000-9,999 bbl) 

Huge Spills 

(=>10000 bbl) 

Substantial Spills 

(=>1000 bbl) 

All Spills 

 Frequency 

Spills per 103 years 

Frequency 

Spills per 109 bbl Produced 

Spill Index 

(bbl) 

Mean = 2.115 0.163 0.109 0.272 2.387 0.707 0.054 0.037 0.091 0.798 0.940 0.874 6.245 7.119 8.058 

Std Deviation = 1.635 0.090 0.062 0.138 1.651 0.547 0.030 0.021 0.046 0.552 1.036 0.619 3.618 3.729 3.876 

Variance = 2.672 0.008 0.004 0.019 2.726 0.299 0.001 0.000 0.002 0.305 1.074 0.383 13.091 13.902 15.021

Skewness = 0.913 0.759 0.743 0.711 0.917 0.913 0.759 0.743 0.711 0.917 2.078 1.291 1.067 1.005 0.924 

Kurtosis = 3.511 3.576 3.325 3.372 3.539 3.511 3.576 3.325 3.372 3.539 8.890 5.334 4.141 4.044 3.855 

Mode = 0.644 0.128 0.080 0.186 1.175 0.215 0.043 0.027 0.062 0.393 0.155 0.515 4.390 5.990 4.980 

 

Minimum = -0.754 -0.036 -0.011 -0.040 -0.528 -0.252 -0.012 -0.004 -0.013 -0.176 0 -0.532 -0.356 0.003 0.379 0.353 

5% Perc = 0.106 0.038 0.027 0.082 0.361 0.036 0.013 0.009 0.028 0.121 5 0.015 0.142 1.792 2.387 2.998 

10% Perc = 0.311 0.057 0.038 0.110 0.559 0.104 0.019 0.013 0.037 0.187 # 0.074 0.218 2.347 3.001 3.711 

15% Perc = 0.490 0.072 0.047 0.131 0.753 0.164 0.024 0.016 0.044 0.252 # 0.128 0.289 2.765 3.502 4.275 

20% Perc = 0.658 0.084 0.055 0.149 0.922 0.220 0.028 0.018 0.050 0.308 # 0.182 0.354 3.174 3.947 4.768 

25% Perc = 0.825 0.095 0.062 0.167 1.092 0.276 0.032 0.021 0.056 0.365 # 0.242 0.418 3.558 4.356 5.195 

30% Perc = 0.999 0.107 0.069 0.185 1.258 0.334 0.036 0.023 0.062 0.421 # 0.296 0.483 3.915 4.746 5.618 

35% Perc = 1.180 0.117 0.076 0.202 1.440 0.395 0.039 0.025 0.068 0.482 # 0.358 0.545 4.277 5.148 6.044 

40% Perc = 1.380 0.127 0.083 0.218 1.650 0.461 0.043 0.028 0.073 0.552 # 0.427 0.607 4.638 5.557 6.485 

45% Perc = 1.565 0.138 0.091 0.235 1.841 0.523 0.046 0.030 0.079 0.616 # 0.505 0.671 5.046 5.954 6.902 

50% Perc = 1.782 0.149 0.099 0.253 2.059 0.596 0.050 0.033 0.085 0.689 # 0.591 0.739 5.439 6.384 7.357 

55% Perc = 2.003 0.161 0.109 0.271 2.268 0.670 0.054 0.036 0.091 0.758 # 0.692 0.813 5.910 6.838 7.849 

60% Perc = 2.233 0.173 0.117 0.290 2.503 0.747 0.058 0.039 0.097 0.837 # 0.809 0.894 6.404 7.348 8.347 

65% Perc = 2.462 0.187 0.127 0.310 2.750 0.823 0.062 0.042 0.104 0.919 # 0.932 0.977 6.931 7.864 8.890 

70% Perc = 2.765 0.201 0.137 0.333 3.032 0.924 0.067 0.046 0.111 1.014 # 1.101 1.077 7.508 8.482 9.482 

75% Perc = 3.104 0.216 0.148 0.356 3.354 1.038 0.072 0.050 0.119 1.121 # 1.299 1.184 8.220 9.144 10.205

80% Perc = 3.474 0.235 0.161 0.384 3.762 1.162 0.079 0.054 0.128 1.258 # 1.539 1.316 9.015 9.919 11.045

85% Perc = 3.910 0.257 0.175 0.420 4.198 1.307 0.086 0.059 0.141 1.404 # 1.855 1.482 9.989 10.948 12.062

90% Perc = 4.425 0.286 0.194 0.464 4.729 1.479 0.096 0.065 0.155 1.581 # 2.286 1.706 11.298 12.361 13.488

95% Perc = 5.262 0.332 0.224 0.529 5.589 1.759 0.111 0.075 0.177 1.869 # 3.083 2.072 13.381 14.412 15.454

Maximum = 9.078 0.651 0.373 0.995 9.464 3.035 0.218 0.125 0.333 3.164 # 9.725 5.076 25.254 27.212 28.260
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5.10

Figure 5.8: Project Spill Indicator Distributions – Year 15 

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

Spill Frequency - Liberty- Year 15

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl
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5.11

Table 5.2 

Composition of Project Spill Indicators –Life of Field Average 

Liberty 

Small and Medium 

Spills (50-999 bbl) 

Large Spills 

(1,000-9,999 bbl) 

Huge Spills 

(=>10,000 bbl) 

Substantial Spills 

(=>1,000 bbl) 

All Spills 

Small and Medium 

Spills (50-999 bbl) 

Large Spills 

(1,000-9,999 bbl) 

Huge Spills 

(=>10,000 bbl) 

Substantial Spills 

(=>1,000 bbl) 

All Spills 

Small and Medium 

Spills (50-999 bbl) 

Large Spills 

(1,000-9,999 bbl) 

Huge Spills 

(=>10000 bbl) 

Substantial Spills 

(=>1000 bbl) 

All Spills 

All years 

Average LOF 

Frequency 

Spills per 103 years 

Frequency 

Spills per 109 bbl Produced 

Spill Index 

(bbl) 

Mean = 1.946 0.160 0.123 0.283 2.229 0.397 0.033 0.025 0.058 0.454 0.866 0.860 12.148 13.008 13.874

Std Deviation = 1.493 0.082 0.058 0.127 1.507 0.304 0.017 0.012 0.026 0.307 0.943 0.568 6.774 6.834 6.906 

Variance = 2.230 0.007 0.003 0.016 2.271 0.093 0.000 0.000 0.001 0.094 0.889 0.323 45.885 46.700 47.697

Skewness = 0.910 0.696 0.688 0.634 0.915 0.910 0.696 0.688 0.634 0.915 2.075 1.259 1.044 1.022 1.002 

Kurtosis = 3.572 3.421 3.201 3.200 3.605 3.572 3.421 3.201 3.200 3.605 8.982 5.307 4.028 3.986 3.964 

Mode = 0.716 0.120 0.087 0.185 0.836 0.146 0.024 0.018 0.038 0.170 0.136 0.449 5.964 9.165 10.188

 

Minimum = -0.704 -0.026 -0.005 -0.007 -0.549 -0.144 -0.005 -0.001 -0.001 -0.112 -0.743 -0.199 0.522 0.568 1.019 

5% Perc = 0.097 0.045 0.044 0.105 0.354 0.020 0.009 0.009 0.021 0.072 0.017 0.177 3.877 4.580 5.252 

10% Perc = 0.292 0.063 0.056 0.132 0.557 0.059 0.013 0.011 0.027 0.114 0.073 0.259 4.830 5.571 6.332 

15% Perc = 0.453 0.076 0.064 0.153 0.727 0.092 0.016 0.013 0.031 0.148 0.122 0.323 5.601 6.387 7.158 

20% Perc = 0.606 0.088 0.072 0.171 0.882 0.123 0.018 0.015 0.035 0.180 0.171 0.383 6.312 7.127 7.920 

25% Perc = 0.765 0.099 0.079 0.187 1.047 0.156 0.020 0.016 0.038 0.213 0.222 0.443 6.990 7.836 8.670 

30% Perc = 0.927 0.109 0.086 0.203 1.207 0.189 0.022 0.018 0.041 0.246 0.279 0.499 7.684 8.529 9.388 

35% Perc = 1.091 0.119 0.093 0.219 1.373 0.222 0.024 0.019 0.045 0.280 0.337 0.556 8.385 9.231 10.120

40% Perc = 1.272 0.129 0.100 0.235 1.550 0.259 0.026 0.020 0.048 0.316 0.403 0.613 9.091 9.979 10.860

45% Perc = 1.455 0.139 0.107 0.251 1.738 0.297 0.028 0.022 0.051 0.354 0.475 0.675 9.858 10.743 11.633

50% Perc = 1.651 0.150 0.114 0.267 1.930 0.336 0.031 0.023 0.054 0.393 0.555 0.740 10.628 11.541 12.447

55% Perc = 1.854 0.160 0.122 0.284 2.138 0.378 0.033 0.025 0.058 0.436 0.644 0.806 11.517 12.422 13.331

60% Perc = 2.071 0.171 0.130 0.301 2.350 0.422 0.035 0.026 0.061 0.479 0.747 0.880 12.496 13.370 14.290

65% Perc = 2.301 0.184 0.139 0.321 2.587 0.469 0.037 0.028 0.065 0.527 0.872 0.959 13.514 14.414 15.301

70% Perc = 2.557 0.197 0.148 0.341 2.838 0.521 0.040 0.030 0.069 0.578 1.021 1.051 14.622 15.497 16.433

75% Perc = 2.842 0.211 0.159 0.363 3.126 0.579 0.043 0.032 0.074 0.637 1.194 1.155 15.871 16.792 17.722

80% Perc = 3.167 0.227 0.171 0.388 3.452 0.645 0.046 0.035 0.079 0.703 1.411 1.274 17.403 18.296 19.215

85% Perc = 3.550 0.247 0.185 0.417 3.847 0.723 0.050 0.038 0.085 0.784 1.691 1.422 19.275 20.163 21.109

90% Perc = 4.050 0.272 0.204 0.457 4.342 0.825 0.056 0.041 0.093 0.885 2.096 1.628 21.742 22.658 23.560

95% Perc = 4.821 0.311 0.230 0.516 5.125 0.982 0.063 0.047 0.105 1.044 2.776 1.954 25.454 26.405 27.315

Maximum = 9.264 0.612 0.401 0.977 9.570 1.887 0.125 0.082 0.199 1.950 10.390 5.571 47.745 48.317 49.605
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5.12

Figure 5.9: Project Life of Field Average Spill Frequency Variability 

0

10

20

30

40

50

60

70

80

90

100

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Pipeline

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island + Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - All

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Pipeline

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island + Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - All

Substantial Spills

=>1000 bbl

All Spills
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.13

Figure 5.10: Project Life of Field Average Spills per 109 Barrels Produced 

0

10

20

30

40

50

60

70

80

90

100

0.00 0.05 0.10 0.15 0.20 0.25 0.30

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Pipeline

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.00 0.05 0.10 0.15 0.20 0.25 0.30

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Pipeline

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.000 0.005 0.010 0.015 0.020 0.025 0.030

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty Case LOF Average - Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.000 0.005 0.010 0.015 0.020 0.025 0.030 0.035

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island + Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island + Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty Case LOF Average - All

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - All

Substantial Spills

=>1000 bbl

All Spills
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.14

Figure 5.11: Project Life of Field Average Spill Index Variability

0

10

20

30

40

50

60

70

80

90

100

0.0 0.5 1.0 1.5 2.0 2.5 3.0

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Pipeline

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.5 1.0 1.5 2.0 2.5 3.0

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Pipeline

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0123456

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0123456

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island + Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island + Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - All

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - All

Substantial Spills

=>1000 bbl

All Spills
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.15

Table 5.3 

Summary of Spill Indicators for All Scenarios 

Liberty Liberty Non Arctic 

Spill Indicators 

LOF Average 

Spill 

Frequency 

per 103 years 

Spill 

Frequency 

per 109 bbl 

produced 

Spill 

Index 

(bbl) 

Spill 

Frequency 

per 103

years 

Spill 

Frequency 

per 109 bbl 

produced 

Spill Index 

(bbl) 

Small and Medium Spills 1.947 0.397 0.867 3.397 0.692 1.512 

50-999 bbl 87% 87% 6% 89% 89% 8% 

Large Spills 0.160 0.033 0.859 0.253 0.052 1.353 

1,000-9,999 bbl 7% 7% 6% 7% 7% 7% 

Huge Spills 0.123 0.025 12.133 0.178 0.036 15.447 

=>10,000 bbl 6% 6% 88% 5% 5% 84% 

Substantial Spills 0.283 0.058 12.992 0.431 0.088 16.799 

=>1,000 bbl 13% 13% 94% 11% 11% 92% 

2.230 0.454 13.859 3.827 0.780 18.311 All Spills 100% 100% 100% 100% 100% 100% 

0.331 0.067 0.830 0.640 0.130 1.537 Pipeline Spills 15% 15% 6% 17% 17% 8% 

1.818 0.370 1.457 3.087 0.629 2.297 Island Spills 82% 82% 11% 81% 81% 13% 

0.080 0.016 11.572 0.100 0.020 14.476 Well Spills 4% 4% 83% 3% 3% 79% 

1.898 0.387 13.029 3.187 0.649 16.773 Island and Well Spills 85% 85% 94% 83% 83% 92% 

2.230 0.454 13.859 3.827 0.780 18.311 All Spills 100% 100% 100% 100% 100% 100% 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.16

Figure 5.12: Project Life of Field Spill 

Indicators – By Spill Size 

Figure 5.13: Project Life of Field Spill 

Indicators – By Source Composition 

Spill Frequency

Per 109 bbl produced

Spill Frequency

Per 109 bbl produced

Spill Frequency

per 1,000 years

Spill Frequency

per 1,000 years
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.17

5.3.2 Comparative Non-Arctic Indicator Assessment 

To give an idea of the effect of the frequency variations introduced in Chapter 4, the 

Project scenario was also modeled utilizing unaltered historical frequencies. That is, no 

changes to incorporate the Arctic effects were introduced in the spill indicator 

calculations. Put yet another way, it was assumed that the facilities of the scenario would 

behave as if they were designed for and located in the Gulf of Mexico environment rather 

than in the Arctic environment, with the same facility quantities and production rates as 

their Arctic counterparts. Figures 5.14, 5.15, and 5.16 show the total values calculated for 

each of the three spill indicators. The dark histogram bar on the right side corresponds to 

the Arctic spill indicator, while, that on the left, corresponds to the computation based on 

non-Arctic frequencies only. Spill frequency in an absolute sense is considerably higher 

for the non-Arctic situation, roughly by 40%. Thus, spills per 109 barrels produced for the 

Arctic development scenarios can also be expected to have a 40% lower oil spill 

occurrence rate than similar development scenarios would have in the GOM. 

Figure 5.14: Arctic and Non-Arctic Project Spill Frequency 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.18

Figure 5.15: Arctic and Non-Arctic Project Spill Frequency per 109 Barrels Produced 

 

Figure 5.16: Arctic and Non-Arctic Project Spill Index 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.19

5.4 Summary of Representative Oil Spill Occurrence Indicator Results 

How do spill indicators for the Project and for its non-Arctic counterpart vary by spill 

size and source? Table 5.3 summarized the Life of Field average spill indicator values by 

spill size and source. The following can be observed: 

 Spill frequency per 103 years and per 109 barrels produced decrease with increasing 

spill size for both regions. 

 The spill index increases with spill size for both regions. 

 All non-Arctic region spill indicators are greater than their Arctic counterparts. 

 The island contributes the most (82%) to the two spill frequency indicators. 

 Pipelines are second in relative contribution to spill frequencies (15%). 

 Wells are the lowest contributors to both frequency spill indicators (4%) and the most 

to spill index (83%). 

 It can be concluded that the island is likely to have the most, but smaller spills, while 

wells will have the least number but larger spills. Pipelines will be in between, with 

more spills than wells. 

Figures 5.14 to 5.16 compare spill indicators for Arctic and Non-Arctic spills 

Figures 5.17 and 5.18 show relative contributions by source and spill size for year 15 and 

Life of Field average spill indicators, respectively. Although Life of Field average 

absolute values are smaller than the year 15 values, the proportional contributions by spill 

facility source and spill size are similar. “TOTAL” in the figures designates the sum of 

the spill indicators for all spill sizes and sources. 

Figures 5.9, 5.10, and 5.11, earlier, showed the Cumulative Distribution Functions (CDF) 

the Project Life of Field average spill indicators. Generally, the following can be 

observed from the figures: 

 The variance of the frequency spill indicators (Figures 5.9 and 5.10) generally 

decreases as spill size increases for pipelines and the island. For example, in the top 

left-hand graph of Figure 5.9, the pipeline huge spills plot has a much steeper (less 

variable) slope than that of small and medium spills, and is steeper than that of large 

spills. For the island, small and medium spills are more variable than large and huge 

spills. 

 For wells, huge spills show much greater variance than smaller ones. 

 For all facilities, as seen in Figure 5.9 (left side bottom graph), the frequency spill 

indicators for small and medium spills show significantly more variability than those 

for large and huge spills. 

 The variability of the spill index (Figure 5.11) for the pipeline, unlike the frequency 

spill indicators, shows a greater variance for large and huge spills than for small and 

medium spills. The opposite occurs for the island (ie, small and medium spills are the 

most variable). 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.20

 For wells, the variance in huge spills spill index dominates, with very little variance 

in the large, medium, and small spills, which are plotted nearly vertically in Figure 

5.11 (third graph from top on left side). 

 For all facilities, the spill index for huge spills is more variable than for smaller spills 

(Figure 5.11 left side bottom graph). 

The Cumulative Distribution Functions contain extensive information on the statistical 

properties of the spill indicators. For example, from Figure 5.9 and more exactly from 

Table 5.2, for substantial spills, the Life of Field average 50% value is 0.267 (spills per 

1,000 years), and the range is between 0.105 at the lower 5% confidence level and 0.516 

at the upper 95% confidence level. A similar percentage variation is shown for the Life of 

Field average spill frequency per 109

 barrels produced. The spill index variability shown 

in Figure 5.11 is proportionally higher. For example, in Figure 5.11 (bottom right graph) 

the substantial spill Life of Field average 50% value is 11.541 (bbl), and the range is 

between 4.580 at the lower 5% confidence level and 26.405 at the upper 95% confidence 

level. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.21

BY SPILL SOURCE BY SPILL SIZE 

Figure 5.17: Project – Year 15 – Spill Indicator Composition by Source and Spill Size 

 

15%

83%

2%

Liberty - Year 15

Spill Frequency per 103 years

Pipeline

Island

Wells TOTAL 2.383

15%

83%

2%

Liberty - Year 15

Spill Frequency per 109 bbl produced

Pipeline

Island

Wells TOTAL 0.797

11% 20%

69%

Liberty- Year 15

Spill Index [bbl]

Pipeline

Island

Wells TOTAL 8

88%

7%

5%

Liberty - Year 15

Spill Frequency per 103 years

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 2.383

88%

7%

5%

Liberty - Year 15

Spill Frequency per 109 bbl produced

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 0.797

12%

11%

77%

Liberty - Year 15

Spill Index [bbl]

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 8
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

5.22

BY SPILL SOURCE BY SPILL SIZE 

Figure 5.18: Project – Life of Field Average Spill Indicator Composition 

by Source and Spill Size 

15%

81%

4%

Liberty LOF Average

Spill Frequency per 103 years

Pipeline

Island

Wells TOTAL 2.230

15%

81%

4%

Liberty LOF Average

Spill Frequency per 109 bbl produced

Pipeline

Island

Wells TOTAL 0.454

6%

11%

83%

Liberty LOF Average

Spill Index [bbl]

Pipeline

Island

Wells TOTAL 14

87%

7%

6%

Liberty LOF Average

Spill Frequency per 103 years

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 2.230

87%

7%

6%

Liberty LOF Average

Spill Frequency per 109 bbl produced

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 0.454

6% 6%

88%

Liberty LOF Average

Spill Index [bbl]

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 14
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.1

CHAPTER 6 

CONCLUSIONS AND RECOMMENDATIONS 

6.1 Conclusions 

6.1.1 General Conclusions 

Oil spill occurrence indicators were quantified for the proposed Liberty Development 

Project (the Project) in the south Beaufort Sea. The quantification included the 

consideration of the variability of historical and future scenario data, as well as that of 

Arctic effects in predicting oil spill occurrence indicators. Consideration of the variability 

of all input data yields both higher variability and a higher expected value of the spill 

occurrence indicators. The three types of spill occurrence indicators were: annual oil spill 

frequency, annual oil spill frequency per billion barrels produced, and annual spill index 

– additionally, the Project year 15 and life of field (LOF) averages for each of these three 

oil spill indicators were assessed. 

6.1.2 Oil Spill Occurrence Indicators by Spill Size and Source 

How do spill indicators for the Project scenario and for its non-Arctic counterpart vary by 

spill size and source? Table 6.1 and Figures 6.1 and 6.2 summarize the Life of Field 

average spill indicator values by spill size and source. The following can be observed: 

 Spill frequency per 103 years and per 109 barrels produced decreases with 

increasing spill size for all Arctic and non-Arctic scenarios. 

 The spill index increases with spill size for all Arctic and non-Arctic scenarios. 

 All non-Arctic scenario spill indicators are greater than their Arctic counterparts. 

 The island contributes the most (82%) to the two spill frequency indicators. 

 Pipelines are second in relative contribution to spill frequencies (15%). 

 Wells are the lowest contributors to frequency indicators (4%) but highest 

contributors to spill index (83%) 

 It can be concluded that the island is likely to have the most, but smaller spills, 

while wells will have the least number but larger spills. Pipelines will be in 

between, with more spills than wells. 

Table 6.2 gives the contributions to spill indicators for substantial (>=1,000 bbl) spills 

only; although trends are similar, the contribution percentages are different. 

Figures 6.3 and 6.4 show relative contributions by source and spill size for year 15 and 

Life of Field average spill indicators, respectively. Although Life of Field average 

absolute values are smaller than the year 15 values, the proportional contributions by spill 

facility source and spill size are similar. “TOTAL” in the figures designates the sum of 

the spill indicators for all spill sizes and sources. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.2

Table 6.1 

Summary of Life of Project Field Average Spill Indicators by Spill Source and Size 

Liberty Liberty Non Arctic 

Spill Indicators 

LOF Average 

Spill 

Frequency 

per 103 years 

Spill 

Frequency 

per 109 bbl 

produced 

Spill 

Index 

(bbl) 

Spill 

Frequency 

per 103

years 

Spill 

Frequency 

per 109 bbl 

produced 

Spill Index 

(bbl) 

Small and Medium Spills 1.947 0.397 0.867 3.397 0.692 1.512 

50-999 bbl 87% 87% 6% 89% 89% 8% 

Large Spills 0.160 0.033 0.859 0.253 0.052 1.353 

1,000-9,999 bbl 7% 7% 6% 7% 7% 7% 

Huge Spills 0.123 0.025 12.133 0.178 0.036 15.447 

=>10,000 bbl 6% 6% 88% 5% 5% 84% 

Substantial Spills 0.283 0.058 12.992 0.431 0.088 16.799 

=>1,000 bbl 13% 13% 94% 11% 11% 92% 

2.230 0.454 13.859 3.827 0.780 18.311 All Spills 100% 100% 100% 100% 100% 100% 

0.331 0.067 0.830 0.640 0.130 1.537 Pipeline Spills 15% 15% 6% 17% 17% 8% 

1.818 0.370 1.457 3.087 0.629 2.297 Island Spills 82% 82% 11% 81% 81% 13% 

0.080 0.016 11.572 0.100 0.020 14.476 Well Spills 4% 4% 83% 3% 3% 79% 

1.898 0.387 13.029 3.187 0.649 16.773 Island and Well Spills 85% 85% 94% 83% 83% 92% 

2.230 0.454 13.859 3.827 0.780 18.311 All Spills 100% 100% 100% 100% 100% 100% 

Table 6.2 

Summary of Life of Project Spill Indicators for Substantial Spills by Facility and Well Type 

Spill Source Liberty 

LOF Average 

Substantial Spills 

=> 1,000 bbl 

Spill Frequency 

per 103 years 

Spill Frequency 

per 109 bbl 

produced 

Spill Index 

(bbl) 

0.100 0.020 0.740 Pipeline 35% 35% 6% 

0.123 0.025 0.691 Island 43% 43% 5% 

0.060 0.012 11.562 Wells 21% 21% 89% 

0.183 0.037 12.252 Island and Wells 65% 65% 94% 

0.283 0.058 12.992 All 100% 100% 100% 

0.027 0.005 5.092 Production Wells 

44% 44% 44% 

0.034 0.007 6.469 Development Wells Drilling 56% 56% 56% 

0.060 0.012 11.562 All Wells 100% 100% 100% 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.3

Figure 6.1: Project Life of Field Spill Indicators

– By Spill Size 

Figure 6.2: Project Life of Field Spill Indicators

– By Source Composition 

Spill Frequency

Per 109 bbl produced

Spill Frequency

per 1,000 years

Spill Frequency

Per 109 bbl produced Spill Frequency per 1,000 years
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.4

BY SPILL SOURCE BY SPILL SIZE 

Figure 6.3: Project – Year 15 – Spill Indicator Composition by Source and Spill Size 

15%

83%

2%

Liberty - Year 15

Spill Frequency per 103 years

Pipeline

Island

Wells TOTAL 2.383

15%

83%

2%

Liberty - Year 15

Spill Frequency per 109 bbl produced

Pipeline

Island

Wells TOTAL 0.797

11% 20%

69%

Liberty- Year 15

Spill Index [bbl]

Pipeline

Island

Wells TOTAL 8

88%

7%

5%

Liberty - Year 15

Spill Frequency per 103 years

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 2.383

88%

7%

5%

Liberty - Year 15

Spill Frequency per 109 bbl produced

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 0.797

12%

11%

77%

Liberty - Year 15

Spill Index [bbl]

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 8
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.5

BY SPILL SOURCE BY SPILL SIZE 

Figure 6.4: Project – Life of Field Average Spill Indicator Composition 

by Source and Spill Size 

15%

81%

4%

Liberty LOF Average

Spill Frequency per 103 years

Pipeline

Island

Wells TOTAL 2.230

15%

81%

4%

Liberty LOF Average

Spill Frequency per 109 bbl produced

Pipeline

Island

Wells TOTAL 0.454

6%

11%

83%

Liberty LOF Average

Spill Index [bbl]

Pipeline

Island

Wells TOTAL 14

87%

7%

6%

Liberty LOF Average

Spill Frequency per 103 years

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 2.230

87%

7%

6%

Liberty LOF Average

Spill Frequency per 109 bbl produced

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 0.454

6% 6%

88%

Liberty LOF Average

Spill Index [bbl]

Small and Medium Spills

50-999 bbl

Large Spills

1,000-9,999 bbl

Huge Spills

=>10,000 bbl

TOTAL 14
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.6

6.1.3 The Variance of Oil Spill Occurrence Indicators 

Figures 6.5, 6.6, and 6.7 show the Cumulative Distribution Functions (CDF) for the 

Project Life of Field average spill indicators. Generally, the following can be observed 

from the figures: 

 The variance of the frequency spill indicators (Figures 6.5 and 6.6) generally 

decreases as spill size increases for pipelines and the island. For example, in the top 

left-hand graph of Figure 6.5, the pipeline huge spills plot has a much steeper (less 

variable) slope than that of small, medium, and large spills. For the island, small and 

medium spills are more variable than large and huge spills. 

 For wells, huge spills show greater variance than smaller ones. 

 For all facilities, as seen in Figure 6.5 (left side bottom graph), the frequency spill 

indicator for small and medium spills show significantly more variability than those 

for large and huge spills. 

 The variability of the spill index (Figure 6.7) for the pipeline, unlike the frequency 

spill indicators, shows a greater variance for large and huge spills than for small and 

medium spills. The opposite occurs for the island (ie, small and medium spills are the 

most variable). 

 For wells, the variance in huge spills spill index dominates, with very little variance 

in the large spills and small spills and medium spills which are plotted nearly 

vertically in Figure 6.7 (third graph from top on left side). 

 For all facilities, the spill index for huge spills is more variable than for smaller spills 

(Figure 6.7 left side bottom graph). 

The Cumulative Distribution Functions contain extensive information on the statistical 

properties of the spill indicators. For example, from Figure 6.5 for all substantial spills 

(bottom right graph), the Life of Field average 50% value is 0.3 (spills per 1,000 years), 

and the range is between 0.1 at the lower 5% confidence level and 0.5 at the upper 95% 

confidence level. A similar percentage variation is shown for the Life of Field average 

spill frequency per 109

 barrels produced in Figure 6.6. The spill index variability shown 

in Figure 6.7 is proportionally higher. For example, in Figure 6.7 (bottom right graph) the 

Life of Field average 50% value is 11.5 (bbl), and the range is between 4.6 at the lower 

5% confidence level and 26.4 at the upper 95% confidence level. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.7

Figure 6.5: Project Life of Field Average Spill Frequency Variability 

0

10

20

30

40

50

60

70

80

90

100

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Pipeline

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island + Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - All

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Pipeline

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - Island + Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

012345678

CDF %

Spill Frequency per 1,000 years

CDF Liberty LOF Average - All

Substantial Spills

=>1000 bbl

All Spills
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.8

Figure 6.6: Project Life of Field Average Spills per 109 Barrels Produced 

0

10

20

30

40

50

60

70

80

90

100

0.00 0.05 0.10 0.15 0.20 0.25 0.30

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Pipeline

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.00 0.05 0.10 0.15 0.20 0.25 0.30

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Pipeline

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.000 0.005 0.010 0.015 0.020 0.025 0.030

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty Case LOF Average - Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.000 0.005 0.010 0.015 0.020 0.025 0.030 0.035

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island + Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - Island + Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty Case LOF Average - All

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

CDF %

Spill Frequency per 109 bbl Produced

CDF Liberty LOF Average - All

Substantial Spills

=>1000 bbl

All Spills
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.9

Figure 6.7: Project Life of Field Average Spill Index Variability 

0

10

20

30

40

50

60

70

80

90

100

0.0 0.5 1.0 1.5 2.0 2.5 3.0

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Pipeline

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0.0 0.5 1.0 1.5 2.0 2.5 3.0

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Pipeline

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0123456

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0123456

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island + Wells

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30 35 40 45 50

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - Island + Wells

Substantial Spills

=>1000 bbl

All Spills

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - All

Small and Medium Spills

50-999 bbl

Large Spills

1000-9999 bbl

Huge Spills

=>10000 bbl

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

CDF %

Spill Index [bbl]

CDF Liberty LOF Average - All

Substantial Spills

=>1000 bbl

All Spills
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.10

6.2 Conclusions on the Methodology and its Applicability 

An analytical tool for the prediction of oil spill occurrence indicators for systems without 

history, such as future offshore oil production developments in the Beaufort Sea, has 

been developed based on the utilization of fault tree methodology. Although the results 

generated are voluminous, they are essentially transparent, simple, and easy to 

understand. The analytical tool developed is also quite transparent, very efficient in terms 

of computer time and input-output capability. In addition, the predictive model is setup so 

that input variables can be entered as distributions to yield result distributions. 

A wealth of information that can be utilized for the optimal planning and regulation of 

future developments is generated by the analytical tool. Key aspects of the analytical tool 

capability may be summarized as follows: 

 Ability to generate expected and mean values as well as their variability in rigorous 

numerical statistical format. 

 Use of verifiable input data based on BSEE and BOEM or other historical spill data 

and statistics. 

 Ability to independently vary the impacts of different causes on the spill occurrences 

as well as add new causes such as some of those that may be expected for the Arctic 

or other new environments. 

 Ability to generate spill occurrence indicator characteristics such as annual variations, 

facility contributions, spill size distributions, and life of field (LOF) averages. 

 Ability to generate comparative spill occurrence indicators such as those of 

comparable scenarios in more temperate regions. The model developed provides a 

basis for estimating each Arctic effect’s importance through sensitivity analysis as 

well as propagation of uncertainties. 

 Capability to quantify uncertainties rigorously, together with their measures of 

variability. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.11

6.3 Suggested Improvement to the Methodology and Results 

During the work, a number of areas were identified where future improvements could be 

made, including: the input data, the scenarios, the application of the fault tree 

methodology, and finally the oil spill occurrence indicators themselves have been 

identified. These suggestions are summarized in the following paragraphs. 

Two categories of input data were used; namely the historical spill data and the Arctic 

effect data. Although a verifiable and optimal historical spill data set has been used, the 

following shortcomings may be noted: 

 Gulf of Mexico and Pacific (OCS) historical databases were compiled by BSEE and 

BOEM for pipelines and facilities, and were used as a starting point for the fault tree 

analysis. Although these data are adequate, a broader population base would be 

expected to give more robust statistics. For well LOWC data, both the BSEE and the 

proprietary SINTEF data were used, providing a wider data sample. 

 The Arctic effects include modifications in causes associated with the historical data 

set as well as additions of spill causes unique to the Arctic environment. 

Quantification of existing causes for Arctic effects on historical statistics was done in 

a relative cursory way restricted to engineering judgment. However, the additive or 

Arctic unique effects were evaluated more rigorously. 

 Upheaval buckling effect assessments were included on the basis of professional 

judgment used in previous studies; no engineering analysis was carried out for the 

assessment of frequencies for Beaufort Sea locations to be expected for these effects. 

The following comments can be made on constraints associated with the indicators that 

have been generated: 

 The model generating the indicators is fundamentally a linear model which ignores 

the effects of scale, of time variations such as the learning and wear-out curves 

(Bathtub curve), climate change, and production volume non-linear effects. 

With current methodology, the likelihood of different spill size distributions is 

assumed constant throughout all production years even though the production 

decreases from approximately 60,000 barrels per day (BPD) to 2,000 BPD over the 

project life cycle. One can speculate that the potential for Large and Huge spills 

varies together with the production rate. Although this was not investigated in this 

study, it is recommended that it be addressed in future studies due to the large 

variation in production volumes from start to end of production. However, as done 

here, the results are conservative. 
Liberty Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC00013 

BOEM May 2016 

6.12

6.4 Recommendations 

The following recommendations based on the work may be made: 

 Continue to utilize the Monte Carlo spill occurrence indicator model for new Arctic 

OCS scenarios to support BOEM needs, as it is currently the best predictive spill 

occurrence model available. 

 Utilize the oil spill occurrence indicator model to generate additional model 

validation information, including direct application to existing non-Arctic scenarios, 

such as GOM and PAC projects, which have an offshore oil spill statistical history. 

 Utilize the oil spill occurrence indicator model in a sensitivity mode to identify the 

importance of different Arctic effect variables introduced to provide a prioritized list 

of those items having the highest potential impact on Arctic oil spills. 

 Generalize the model so that it can be run both in an adjusted expected value and a 

distributed value (Monte Carlo) form with the intent that expected value form can be 

utilized without the Monte Carlo add-in for preliminary estimates and sensitivity 

analyses, while for more comprehensive rigorous studies, the Monte Carlo version 

can be used 

 Conduct calculations of the spill indicators as a function of the variable annual oil 

production rates as spill size and frequency distributions are likely to be a function of 

these variable production rates. 
Liberty R.1 Final Report – P1508 

Oil Spill Occurrence Estimators BOEM Contract No.: M11PC0013 

BOEM May 2016 

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BOEM May 2016 

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BOEM May 2016 

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