Annual report 2011 SINTEF Offshore Blowout Database Final_tcm109-486730.pdf

SINTEF REPORT TITLE

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Blowout and Well Release Characteristics and Frequencies, 2011

NO-7465 Trondheim, NORWAY S P Andersens veg 5 +47 73 59 27 56 +47 73 59 28 96 AUTHOR(S)

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Per Holand, ExproSoft CLIENT(S)

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Espen Fyhn Nilsen, Statoil

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\\Bombay\es201016\BLOWOUT\Tekst 2011\Annual report 2011 SINTEF Offshore Blowout Database Final.docx

Per Holand

Lars Bodsberg

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DATE

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2011-12-29

Lars Bodsberg, Research Director

ABSTRACT

This report is based on the 2011 Version of the SINTEF Offshore Blowout Database. The report gives an overview of offshore blowout and well release characteristics and frequencies. Blowout data from the US Gulf of Mexico Outer Continental Shelf, the Norwegian waters, and the UK waters from the period 1980-01-01 until 2009-12-31 have been focused on.

KEYWORDS

ENGLISH

NORWEGIAN

GROUP 1

Marine Technology

Marin Teknikk

GROUP 2

Offshore

Offshore

SELECTED BY AUTHOR

Risk Blowout

Risiko Utblåsning Frekvenser

Frequencies

Blowout and Well Release Characteristics and Frequencies, 2011 version

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PREFACE This report is based on the SINTEF Offshore Blowout Database, version 2011. The intention of the report is to give an overview of blowout/well release characteristics and frequencies, and not to analyse and evaluate the different blowout types. The format of the report is similar to the report that was issued last year. Three new tables concerning drilling rig type vs. water depth have been added. Table 2.8, page 19 (concerning incident occurrences), and Table 6.7 and Table 6.8 on page 68 and 69 (concerning exposure data). A new Phase of operation has been defined. The new phase is “other”. This phase was defined because a couple of incidents have been observed were abandoned wells having developed leaks after many years. A new Installation type has been defined. The new installation type is “other”. This installation type was defined because one incident occurred during well intervention with a service vessel. Appendix 1 to this report lists criteria used for the database fields in general. Some key updates from 2010 version Software Some minor bug fixes have been carried out. Exposure data The exposure data has been updated also to include the 2009 exposure data. New Blowouts Eight new blowouts/well releases have been added to the database (ID612 – ID619). They were observed for the following countries and years: Table 0.1 New blowouts/well releases 2010 version Blowout ID Country 612 US/GOM OCS 613 US/GOM OCS 614 UK 615 US/GOM NOT OCS 616 US/GOM NOT OCS 617 AZERBAIJAN 618 NETHERLANDS 619 BRAZIL

Main Category Well release Blowout (surface flow) Well release Blowout (surface flow) Well release Blowout (surface flow) Well release Blowout (surface flow)

Phase Production Workover Completion Production Workover Production Workover Expl.drlg

Well depth Deep Deep Deep Deep Deep Deep Deep Deep

Date 07.10.2010 16.01.2011 23.12.2009 27.07.2010 01.12.2010 17.09.2008 01.04.2010 08.12.2011

Edited Blowouts Twelve blowouts/well releases have been significantly edited. Table 0.2 shows where and when these blowouts/well releases occurred.

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Table 0.2 Edited blowouts and well releases Blowout ID Country 378 US GoM OCS 495 UK 497 UK 498 UK 499 UK 500 UK 530 UK 595 UK 596 UK 597 UK 598 UK 610 US GoM OCS

Main Category Diverted Well Release Blowout (surface flow) Well release Well release Well release Well release Blowout (surface flow) Well release Well release Well release Well release Well release

Deleted Blowouts, 2011 No blowouts have been deleted in 2011

Phase Dev.drlg Expl.drlg Workover Workover Completion Unknown drlg Wireline Dev.drlg Production Workover Workover Other

Well depth Shallow Shallow Deep Deep Deep Deep Deep Deep Deep Deep Deep Deep

Date 10.05.1990 12.11.1992 11.05.1995 09.06.1997 14.08.1997 28.10.1998 01.05.2000 17.11.2007 04.06.2007 15.07.2007 13.12.2007 20.11.2007


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LIST OF CONTENTS PREFACE

..................................................................................................................................................... 3

1. ABOUT THE DATABASE ................................................................................................................................ 7 1.1 PARTICIPANTS ...................................................................................................................................................7 1.2 DATABASE STRUCTURE .......................................................................................................................................7 1.3 IMPORTANT DEFINITIONS ....................................................................................................................................9 1.4 CATEGORY AND SUB-CATEGORY .........................................................................................................................10 1.5 PHASE OF OPERATION.......................................................................................................................................11 1.6 NORTH SEA STANDARDS ...................................................................................................................................11 2. OVERVIEW OF BLOWOUTS/WELL RELEASES INCLUDED IN THE DATABASE ................................................ 13 2.1 INTRODUCTION ...............................................................................................................................................13 2.2 DATA QUALITY................................................................................................................................................13 2.3 OVERVIEW OF COUNTRIES REPRESENTED IN THE DATABASE .....................................................................................14 2.4 DURING WHAT OPERATIONAL PHASES DO BLOWOUTS/WELL RELEASES OCCUR? .........................................................16 2.5 NO. OF BLOWOUTS/WELL RELEASES PER YEAR ......................................................................................................17 2.6 WATER DEPTH VS. BLOWOUTS/WELL RELEASES.....................................................................................................18 2.7 INSTALLATION TYPE VS. WATER DEPTH FOR DRILLING INCIDENTS ...............................................................................18 3. BLOWOUTS VS. WELL RELEASES ................................................................................................................ 21 4. OVERALL BLOWOUT/WELL RELEASE EXPERIENCE ...................................................................................... 23 4.1 BLOWOUT/WELL RELEASE VS. FLOW MEDIUM .....................................................................................................23 4.2 BLOWOUT/WELL RELEASE VS. FLOW-RATES .........................................................................................................24 4.3 SEVERITY .......................................................................................................................................................24 4.4 IGNITION OF BLOWOUTS/WELL RELEASES ............................................................................................................24 4.5 BLOWOUT/WELL RELEASE DURATION .................................................................................................................26 4.6 BLOWOUT/WELL RELEASE FLOW-PATHS AND RELEASE POINTS ................................................................................27 4.7 BLOWOUT/WELL RELEASE CAUSES .....................................................................................................................31 4.8 OPERATIONS AND ACTIVITIES WHEN BLOWOUT/WELL RELEASE OCCURS....................................................................35 4.9 EXPLORATION WILDCATS VS. EXPLORATION APPRAISAL BLOWOUTS/WELL RELEASES ....................................................39 4.10 BLOWOUTS FROM AUSTRALIA, CANADA EAST COAST, THE NETHERLANDS, AND US/CALIFORNIA OCS ..........................39 5. “NORMAL” DRILLING AND PRODUCTION EXPOSURE DATA ....................................................................... 41 5.1 DRILLING EXPOSURE DATA ................................................................................................................................41 5.1.1 US GoM OCS .......................................................................................................................................41 5.1.2 United Kingdom ..................................................................................................................................43 5.1.3 Norway ...............................................................................................................................................43 5.1.4 The Netherlands .................................................................................................................................46 5.1.5 Canadian East Coast ...........................................................................................................................47 5.1.6 US Pacific OCS .....................................................................................................................................49 5.1.7 Australia .............................................................................................................................................50 5.1.8 Denmark .............................................................................................................................................52 5.1.9 Compiled Drilling Exposure Data ........................................................................................................52 5.2 PRODUCTION EXPOSURE DATA...........................................................................................................................54 5.2.1 US GoM OCS .......................................................................................................................................54 5.2.2 United Kingdom ..................................................................................................................................55 5.2.3 Norway ...............................................................................................................................................56 5.2.4 US Pacific OCS .....................................................................................................................................57 5.2.5 Compiled Production Exposure Data ..................................................................................................58 6. VARIOUS EXPOSURE DATA ........................................................................................................................ 61 6.1 WELL DEPTH RELATED EXPOSURE DATA ..............................................................................................................61 6.1.1 US GoM OCS Wells ..............................................................................................................................61 6.1.2 Norwegian Wells ................................................................................................................................62 6.2 WATER DEPTH RELATED DRILLING EXPOSURE DATA ...............................................................................................64

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6.3 DRILLING INSTALLATION TYPE VS. WELL TYPE AND WATER DEPTH ............................................................................. 68 6.4 SHUT-IN WELLHEAD PRESSURE RELATED EXPOSURE DATA ...................................................................................... 69 6.4.1 US GoM OCS Drilling Wells ................................................................................................................ 69 6.4.2 Norwegian Drilling Wells ................................................................................................................... 71 6.4.3 US GoM OCS Wells in Production ....................................................................................................... 72 6.5 PRODUCTION RATES AND GAS OIL RATIO DATA, US GOM OCS.............................................................................. 73 6.5.1 Production Rates ................................................................................................................................ 73 6.5.2 Gas Oil Ratio ...................................................................................................................................... 75 6.6 WORKOVER FREQUENCY EXPOSURE DATA ........................................................................................................... 76 6.7 WIRELINE FREQUENCY EXPOSURE DATA .............................................................................................................. 77 6.8 COILED TUBING AND SNUBBING EXPOSURE DATA ................................................................................................. 78 7. OVERALL BLOWOUT/WELL RELEASE FREQUENCIES ................................................................................... 81 REFERENCES .................................................................................................................................................. 85 APPENDIX 1 BLOWOUT DATABASE STRUCTURE AND CODING ........................................................................ I A1. OVERALL DATABASE STRUCTURE .......................................................................................................................... II A2. DESCRIPTION OF DATABASE FIELDS AND ASSOCIATED CODES .................................................................................... IV FIELD 3 CATEGORY ......................................................................................................................................... IV FIELD 4 SUB CATEGORY....................................................................................................................................V FIELD 5 COUNTRY .......................................................................................................................................... VI FIELD 10 INSTALLATION TYPE ............................................................................................................................. VI FIELD 12 WELL STATUS ..................................................................................................................................... VI FIELD 18 MTSIP (MAKS THEORETIC SHUTIN WH PRESSURE) ................................................................................. VI FIELD 24 ROCK TYPE ...................................................................................................................................... VIII FIELD 25 FORMATION AGE .............................................................................................................................. VIII FIELD 27 PHASE............................................................................................................................................. VIII FIELD 28 OPERATION ....................................................................................................................................... IX FIELD 29 ACTIVITY ........................................................................................................................................... XI FIELD 30 EXTERNAL CAUSE ............................................................................................................................... XII FIELD 31 LOSS OF BARRIER 1 ............................................................................................................................ XII FIELD 32 LOSS OF BARRIER 2 ........................................................................................................................... XIV FIELD 34 NORTH SEA STANDARDS .................................................................................................................... XIV FIELD 35 FLOWPATH ....................................................................................................................................... XV FIELD 36 RELEASE POINT.................................................................................................................................. XV FIELD 37 FLOW MEDIUM ................................................................................................................................ XVI FIELD 41 IGNITION TYPE.................................................................................................................................. XVI FIELD 42 CONSEQUENCE CLASS ....................................................................................................................... XVII FIELD 44 POLLUTION ..................................................................................................................................... XVII FIELD 48 CONTROL METHOD .......................................................................................................................... XVII FIELD 50 DATA QUALITY ................................................................................................................................ XVII


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1. About the Database 1.1 Participants The SINTEF Offshore Blowout Database was initiated in 1984. There are two new participants in 2011, URS Energy and Construction, Inc and Maersk Drilling. One participant, Mide Technology Corporation, has left the project. By December 2 2011 the following companies were sponsoring the database: 1. Statoil 2. BP Norge 3. Safetec Nordic A/S 4. Total E&P Norge AS 5. Scandpower AS 6. Shell Research Limited 7. DNV 8. Lilleaker Consulting a.s. 9. Eni Norge AS 10. ConocoPhillips Norge 11. BHP Billiton 12. Torus Insurance Marketing Limited 13. Husky Energy 14. AconaWellpro AS 15. Proactima 16. URS Energy and Construction, Inc 17. Maersk Drilling 1.2 Database Structure The SINTEF Offshore Blowout Database includes blowout/well release descriptions, drilling and production exposure data for certain areas in the world. Blowout/ well release descriptions The database contains 51 different fields describing each blowout/well release. The various fields are grouped in six different groups. They are: 1. 2. 3. 4. 5. 6.

Category and location Well description Present operation Blowout causes Blowout Characteristics Other

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Category and location Includes information related to the incident category (blowout vs. well leak), offshore installation such as location, operator, installation name and type, and water depth. Well description Includes well and casing depths, last casing size, mud weight, bottom hole- and shut in pressure, GOR, formation age and rock type. Present operation Includes the phase (exploration drilling, development drilling, workover etc.), the operation presently carried out (for example casing running) and the present activity (for example cementing) Blowout causes Include external cause (stating if an external cause contributed to the incident), loss of the primary barrier, loss of the secondary barrier (describing how primary and secondary barrier were lost) and human error. It should be noted that the field regarding human error in general holds low quality information. Human errors are frequently masked. A field named North Sea standards highlights if the development of the blowout could have been avoided if North Sea type equipment had been used (for instance in other parts of the world a blind shear ram is not required in surface BOP stacks) Blowout characteristics Twelve fields are included comprising flow-path, flow medium, flow-rate (low quality), release point, ignition type, time to ignition, lost production (low quality), duration, fatalities, consequence class, material loss and pollution Other In the Other screen five fields is included, they are: control method, remarks (includes a description of the incident, data quality (includes an evaluation of the source data quality), last revision date and references. Exposure data The various areas represented with exposure data area shown in Table 1.1. Table 1.1 Overview of exposure data included in the database Country US GoM OCS Norway United Kingdom The Netherlands Canada East Coast Australia US Pacific Denmark

Drilling exposure data Yes Yes Yes Yes Yes Yes Yes Yes

Production exposure data Yes Yes Yes No No No Yes No

Search possibilities and reporting facilities Almost any type of search may be performed to select specific blowout /well release event types. Search criteria may be established by selecting predefined codes, specific numeric values, specific free text, or any combinations of these. The predefined codes are spelled out to ease understanding.


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The database program counts and presents the events satisfying the search criteria. The selected data may be viewed, printed or copied to separate Excel files for further analyses. The exposure data and the blowout data are not linked. Blowout frequencies can therefore not directly be established. 1.3 Important Definitions The following main definitions have been utilised when categorising the blowouts/well releases in categories and sub-categories. Blowout definition NPD came up with a blowout definition in their proposal for the new regulations. (“Aktivitetsforskriften, eksternt høringsutkast av 3.7.2000, høringsfrist 3.11.2000”). Med utblåsing som nevnt i denne paragrafen første ledd, menes formasjonsfluid som strømmer ut av brønnen eller mellom formasjonslagene etter at alle definerte tekniske brønnbarrierer eller operasjon av disse har sviktet. Translated to English the definition will be: A blowout is an incident where formation fluid flows out of the well or between formation layers after all the predefined technical well barriers or the activation of the same have failed. The definition has however not become a part of the Petroleum Safety Authority Norway regulation, but remains the database blowout definition. Well release definition: The reported incident is a well release if oil or gas flowed from the well from some point were flow was not intended and the flow was stopped by use of the barrier system that was available on the well at the time the incident started. Shallow gas definition: Any gas zone penetrated before the BOP has been installed. Any zone penetrated after the BOP is installed is not shallow gas (typical Norwegian definition of shallow gas). All shallow gas incidents in the database have at the extent possible been categorised according to the typical Norwegian definition of shallow gas. This definition is not relevant for all US GoM incidents because:    

US GoM OCS reservoirs vary highly in depth. Some reservoirs were as shallow as 200 meters. For some incidents they had sat a full BOP stack, but had no intention to use it because it would likely cause a blowout outside the casing and a possible crater. For some incidents they had drilled very deep without running an extra casing string and the BOP. And for some incident they had used a combination of a BOP and a diverter.

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Further, for many of the incidents the description of the incident in the sources is insufficient, and some assumptions have to be made. A general comment is that it is not easy to categorise all the incidents in shallow and deep incidents because of the above. It should further be noted that it is in many cases difficult to determine if a shallow gas incident shall be regarded as a blowout or not. In February 2007 a report was published, named “Shallow Gas Project, Shallow gas events 1984 – 2006 in the Norwegian Sector”, by AGR – Triangle. The report was prepared for the Petroleum Safety Authority Norway. This report describes 44 shallow gas events. These 44 events have been reviewed, and some blowouts were added to the database, and many incidents were disregarded. Typically incidents that were reported with a strong seafloor flow, or the diverter was used, were regarded as blowouts. Incidents only referring to gas bubbles were disregarded. This report is enclosed the West Vanguard Blowout (Blowout ID 278) in the database.

1.4 Category and Sub-category The categories and subcategories utilised when classifying the incidents in the SINTEF Offshore Blowout Database are shown in Table 1.2. Table 1.2 Main

Blowout and well release

Main categories and subcategories for the incidents in the SINTEF Offshore Blowout database Category Blowout (surface flow)

Blowout (underground flow)

Sub category 1. Totally uncontrolled flow, from a deep zone 2. Totally uncontrolled flow, from a shallow zone 3. Shallow gas “controlled” subsea release only 4. Underground flow only 5. Underground flow mainly, limited surface flow

Well release

6. 7.

Diverted well release Unknown

8.

Limited surface flow before the secondary barrier was activated Tubing blown out of well, then the secondary barrier is activated

Shallow gas controlled flow (diverted) Unknown

Comments/Example Totally uncontrolled incidents with surface/subsea flow. Typical the diverter system fails Typical incident is that riserless drilling is performed when the well starts to flow. The rig is pulled away The limited surface flow will be incidents were a minor flow has appeared, but typical the BOP has been activated to shut the surface flow Typical incident will be that flow is through the drillpipe and the shear ram is activated Typical incident occurring during completion or workover. Shear ram is used to close the well after the tubing has been blown out of the well. All incidents were the diverter system functioned as intended. Unknown may be selected for both the category and the subcategory

The list of sub-categories, shown in Table 1.2, may be extended if found appropriate. One option will be to split the sub category for Well release further down to highlight incidents with an ignition potential.


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1.5 Phase of operation Each of the blowout/well releases in the database is categorised in the phase of operation they occurred. Table 1.3 shows the pre-set codes used for phase of operation. Table 1.3

Phase of operation

Description Completion Dev.drlg Expl.drlg Production Unknown drlg Unknown Wireline Workover

Remarks Activities associated to well completion activities Development drilling Exploration drilling, includes wildcats and appraisal wells Production, injection, closed in wells When it is not known whether it is dev.drlg or expl.drlg Unknown Wireline operations in connection with a production/injection well, not wireline operations carried out as a part of well drilling, well completion or well workover Workover activities, not including wireline operations. Snubbing and coiled tubing operations

1.6 North Sea Standards The intention with the field North Sea Standards is to identify blowout/well release incidents that likely would have been prevented in North Sea operations because the procedures or equipment utilised when the incident occurred are different from North Sea equipment or procedures. Table 1.4 presents the coding used for this field. Table 1.4

North Sea standards Description

Yes No, no shear ram No, BOP not North Sea standard No, two barrier principle not followed Sometimes not relevant, BOP removed to install casing seal Unknown Not evaluated

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2. Overview of Blowouts/Well releases Included in the Database 2.1 Introduction The SINTEF Offshore Blowout Database does per December 2010 include information about 584 offshore blowouts/well releases that have occurred world-wide since 1955. The number of blowouts/well releases related to the different periods is presented in Table 2.1 Table 2.1

Number of blowouts/well releases related to the different periods Period 1950-ties

No. of blowouts/well releases 9

1960-ties

54

1970-ties

114

1980-ties

177

1990-ties

119

2000 – 2009-12-31

112

2010 and 2011 Total

7 592

Blowouts/well releases that have occurred in the period 1980-01-01 - 2009-12-31 in US GoM OCS, UK, and Norway are focused on. Blowouts/well releases that have occurred after 200912-31 are not included in this report at all. Blowouts/well releases from before 1980 and the rest of the world are only briefly included. 2.2 Data Quality SINTEF's intention is to collect data from all occurring blowouts. However, it is a fact that many blowouts/well releases occurring in this period have never been recorded in the database. This because, public sources, which are the main source of information for blowouts/well releases occurring outside US GoM OCS, and UK, and Norway, do frequently not describe blowouts/well releases with small consequences. Therefore, several blowouts/well releases are believed to be missing from the database. It is SINTEF's belief that from 1980-01-01 most blowouts occurring in the US Gulf of Mexico (GoM) Outer Continental Shelf (OCS), the UK, and Norway have been included in the database. The quality of data related to blowouts occurring after 1970-01-01 is significantly better than the data from before 1970. However, for many blowouts the quality still is low because proper descriptions of the incidents are lacking. Blowout information is frequently hidden from the public.

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For each of the blowout/well release records in the database the quality of the source material is given. Table 2.2 shows an overview of the data quality for the blowouts/well releases that have occurred in the period 1980-01-01 – 2009-12-31. Table 2.2

Quality of blowout/well release data source material

Quality of blowout/well All blowouts except US GoM OCS, UK, Only US GoM OCS, UK, and Norwegian release data source and Norwegian blowouts in the period blowouts in the period 1980-01-01 – material 1980-01-01 – 2009-12-31 2009-12-31 Very good 9 65 Good 11 55 Fair 20 61 Low 36 54 Very low 79 18 Total 155 253

2.3 Overview of Countries Represented in the Database In Table 2.3 shows an overview of the number of blowouts and well releases for the countries represented in the database.


Table 2.3

Page: 15

Overview of countries represented in the database

COUNTRY ANGOLA AUSTRALIA AZERBAIJAN BRAZIL BRUNEI BURMA CABINDA CANADA EAST CANADA NORTH CHINA CONGO DENMARK DUBAI EGYPT EQUATORIAL GUINEA ETHIOPIA GABON GERMANY INDIA INDONESIA IRAN ITALY LIBYA MALAYSIA MEXICO NETHERLANDS NIGERIA NORWAY PAPUA NEW GUINEA PERU PHILLIPPINES QATAR SAUDI ARABIA SOUTH KOREA SPAIN TAIWAN THAILAND TRINIDAD UK UNKNOWN US US/ALASKA State US/CALIFORNIA OCS US/CALIFORNIA state US/GOM NOT OCS US/GOM OCS USSR VENEZUELA VIETNAM YUGOSLAV Total

50ties

60ties

70ties 3

80ties 1 1

2 1

1 1 1 2

90ties 1

1Jan 00 31 Dec 09 1 3

3 1 1 2 2 2 2 1 3

1 2 2 1

later than 31 Dec 09

1

1

1

1 1

3

1 1 1

1 1

4 4 1 1 2

3

3 3

1

3 11 7 1 2 6 1 2 13 1

5 2 1 1

5 1

2

2

1 15

1 4

1

2 1 2 1

3

1 1

1

4

3 1

1 8

2 2 1 11

2 15

1

1 3

10 52

9 58

1

2 6

1 1 1

1

5 30

17 58 2 1

3 2 7 77 6 3

2 3

1 1

9

1 54

114

177

119

112

7

Total 1 7 5 6 4 1 2 2 2 4 3 1 3 7 1 1 1 1 8 22 14 3 1 3 12 2 10 35 2 2 1 2 5 1 1 2 2 7 39 1 2 5 5 2 52 284 8 5 1 1 592

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2.4 During what Operational Phases do Blowouts/Well Releases Occur? In Table 2.4 and Table 2.5 no. of blowouts/well releases have been related to the operational phases. Table 2.4

No. of blowouts/well releases experienced during different operational phases (including all blowouts/well releases until 2009-12-31)

PERIOD

Dev. drlg

Before 1980

43 24,3 % 95 23,3 % 138 23,6 %

1980 to 2009-12-31 Total

Table 2.5

Expl. drlg 75 42,4 % 141 34,6 % 216 36,9 %

Completion

1 0,6 % 9 2,2 % 10 1,7 %

Workover

12 6,8 % 26 6,4 % 38 6,5 %

Production

18 10,2 % 64 15,7 % 82 14,0 %

20 11,3 % 45 11,0 % 65 11,1 %

Wireline

Unknown/ other 3 5 1,7 % 2,8 % 9 19 2,2 % 4,7 % 12 24 2,1 % 4,1 %

Total

177 408 585

Area specific overview of no. of blowouts/well releases experienced during different operational phases (including all blowouts/well releases 01-01-1980 2009-12-31)

AREA

US GoM OCS

Dev. drlg 54

Expl. Unk. Comp- WorkProduction drlg ** drlg letion over External No ext. cause* cause* 53 13 39 8 11

28,9 % 28,3 %

UK, and Norwegian waters Rest of the world Total

9

33

7,0 %

1

13,6 % 50,0 % 1,5 %

32

55

8

20,6 % 35,5 % 5,2 %

95

141

9

23,3 % 34,6 % 2,2 %

* **

Unk. drlg

20,9 %

4,3 %

7

9

1

10,6 %

13,6 %

1,5 %

6

16

3,9 %

10,3 %

26 6,4 %

64 15,7 %

Wire- Unline known/ other 5 4

5,9 % 2,7 %

2

187 66

12

11

15

7,1 %

9,7 % 100,0 %

21

24

5,9 % 2,2 %

9

65

0,0 % 100,0 %

7,7 % 5,1 %

Total excl. ext. cause* 179

2,1 % 100,0 %

4

3,0 % 6,1 %

Total

19

155 408

143 387

4,7 % 100,0 %

External causes are typical; storm, military activity, ship collision, fire and earthquake. One of the Expl. drilling blowouts in the "rest of the world” was caused by volcanic activities

When reading and Table 2.5, it is important to note that the most thorough data is from the US GoM OCS, UK, and Norway. In the US GoM OCS they have experienced a relatively high no. of blowouts/well releases during development drilling compared to exploration drilling. This is explained by the fact that in US GoM OCS they are drilling relatively more development wells than exploration wells, compared to UK and Norway. Further, the relatively high no. of well workover blowouts/well releases in US GoM OCS area does indicate that the number of workovers in that area is high. It should, further, be noted that external causes were involved in approximately 50% of the production blowouts. External causes are discussed in Section 4.7, on page 31.


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2.5 No. of Blowouts/Well releases per Year Table 2.6 shows a year-to-year overview of no. of blowouts/well releases for US GoM OCS, UK, and Norway in the period 1980-01-01 - 2009-12-31. Table 2.6 Year

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

*

Dev. Drlg

Year to year overview of no. of blowouts/well releases for US GoM OCS, UK, and Norway in the period 1980-01-01 – 2009-12-31

UnComp- WorkProduction Wire- UnTotal known letion over No ext. External line known/ drilling other cause* cause* 2 1 2 1 9 2 5 2 11 5 1 4 1 11 7 2 3 1 1 14 1 6 1 8 2 2 6 2 12 1 1 2 1 2 1 1 2 1 8 1 3 1 1 6 4 5 2 3 2 1 17 3 3 2 3 1 12 4 1 3 1 1 10 2 2 1 1 3 9 2 2 2 6 1 1 1 1 4 1 1 2 4 1 2 2 1 6 3 1 5 2 2 13 3 1 1 1 2 1 9 3 2 5 3 2 3 1 1 1 11 3 1 1 2 4 2 13 2 1 1 1 1 1 7 2 1 1 1 1 1 7 2 1 3 6 2 1 1 4 3 1 4 1 1 5 2 1 10 1 2 3 1 1 8 2 2 1 1 1 7 33 51 2 13 9 63 1 20 48 9 4 253 External causes are typical; storm, military activity, ship collision, fire and earthquake. Appraisal 1

Expl. Drlg WildUncat known 2 2

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2.6 Water depth vs. Blowouts/Well releases Table 2.7 shows the water depth vs. blowouts/well releases for US GoM OCS, UK, and Norway in the period 1980-01-01 - 2009-12-31. Table 2.7

Water depth vs. blowouts/well releases for US GoM OCS, UK, and Norway in the period 1980-01-01 – 2009-12-31

Water depth grouped (m) Phase

MainCategory

Deep or Shallow <50

Deep Shallow Develop- Blowout (underground Deep flow) Shallow ment drilling Diverted well release Shallow Deep Well release Shallow Total Deep Blowout (surface flow) Shallow Blowout (underground Deep flow) Exploration Diverted well release drilling Shallow Deep Well release Shallow Unknown Deep Total Unknown Well release drilling Total Blowout (surface flow) ComDiverted well release pletion Well release Total Blowout (surface flow) WorkWell release over Total Blowout (surface flow) Blowout (underground flow) Production * Well release Total Blowout (surface flow) Wire-line Well release Total Blowout (surface flow) UnBlowout (underground flow) known/ Well release other Total Total * External causes not included. Blowout (surface flow)

Un50 - 100 - 200 - 400 - 600 - 1000 - 1500known/ Total 100 200 400 600 1000 1500 2500 other 2 4 1 1 8 6 12 4 1 23 2 1 1 4 1 1 4 9 6 19 3 2 1 6 1 1 2 14 30 15 3 1 63 13 6 2 1 1 23 9 11 6 2 2 1 1 32 3

3

2 1

2

7 2

2 1 1

1 2 1 8

3

1 1 1

1 1

27

1 30

12

6

3

1

2 8 15 10 25 6 1 2 9 2 3 5 1 1 1 3 91

3 6 4 8 12 2 1 1 3

1 2 3 4 7 1

3

1

1

1

2 1 1

1

1 1

1

1 1

1

1 1

2 2

1 1 1 2

1 1

1 1 82

39

13

5

5

1

1

7

8 1 12 7 2 1 87 1 1 10 1 9 20 23 25 48 9 3 13 4 5 9 1 1 2 4 244

2.7 Installation type vs. Water depth for drilling incidents Table 2.8 shows the installation type vs. water depth for drilling incidents for US GoM OCS, UK, and Norway in the period 1980-01-01 - 2009-12-31.


Page: 19

Table 2.8 Installation type vs. Water depth for drilling incidents for US GoM OCS, UK, and Norway in the period 1980-01-01 - 2009-12-31 Installation Phase II Type Deep Drillship Jacket

Expl.drlg Dev.drlg

Dev.drlg Jackup

Expl.drlg Unknown drlg Dev.drlg

Semisubmersible Expl.drlg Submersible Total Shallow Drillship

Jacket

Expl.drlg

Expl.drlg Dev.drlg Expl.drlg Dev.drlg

Jackup Expl.drlg Dev.drlg Semisubmersible Expl.drlg Total Total all

Main Category

Diverted well release Blowout (surface flow) Blowout (underground flow) Well release Blowout (surface flow) Blowout (underground flow) Well release Blowout (surface flow) Blowout (underground flow) Unknown Well release Blowout (surface flow) Blowout (underground flow) Well release Blowout (surface flow) Blowout (underground flow) Well release Blowout (surface flow) Blowout (underground flow)

Blowout (surface flow) Blowout (surface flow) Blowout (underground flow) Diverted well release Well release Blowout (surface flow) Blowout (surface flow) Diverted well release Blowout (surface flow) Diverted well release Blowout (surface flow) Blowout (surface flow) Diverted well release Well release

50 – 100

<50

100 200

Water depth grouped (m) 200 - 400 - 600 - 1000 - Un400 600 1000 1500 known 1

1

1 2 12 2

3 1 1

1 1 1

1

1 5 1 1 1 1 1 1 1 2 2

1 1 20

1 2

1

1

2 2

20

6

6

4

2 1 7 1 1

1

1

1

3

1

1

1

2

1

1

8 1

5 2 8 2 1

7 1 2 7 1 9

20 40

40 60

1 2 5 1 1 22 28

2 1 1 5 11

2

1

2 3

1 4

1

1

1 3

Total 1 5 1 3 2 2 1 17 3 1 1 1 1 2 5 4 7 1 1 59 1 7 1 16 2 1 12 3 10 10 4 20 2 2 91 150

Page: 20



Page: 21

3. Blowouts vs. Well Releases As explained in Section 1.4 on page 10, the incidents in the database has been categorised in blowouts and well releases. When excluding the blowouts with external causes the database includes 244 blowouts/well releases for the US GoM OCS, Norway and UK in the period January 1980 until December 2009. Table 3.1 shows an overview of the no. of blowouts/well releases within the main phases of operation, categories and sub categories. Table 3.1

Overview of the no. of incidents within the main phases of operation, categories and sub categories for US GoM OCS, Norway and UK blowouts/well releases in the period Jan. 1980 until Dec. 2009

According to North Dev. Expl. Unk. Comp- Work- Prod- Wire- Other/UnSea standard? (See Total drlg drlg drlg letion over uction line known Table 1.4 page11) No, no acoustic backup BOP control system 1 1 No, no shear ram 1 3 5 7 16 No, two barrier principle 1 1 2 Totally uncontrolled flow, not followed from a deep zone Sometimes not relevant, BOP removed to install casing seal 2 1 1 4 Unknown 4 4 Blowout (surface Yes 5 18 4 11 8 4 50 flow) No, BOP not North Sea standard 1 1 Totally uncontrolled flow, Sometimes not relevant, from a shallow zone BOP removed to install casing seal 1 1 2 Yes 22 18 1 41 Shallow gas "controlled" Yes subsea release only 12 12 Total 31 55 10 23 9 4 1 133 Underground flow only Yes 4 6 1 1 12 Blowout Underground flow (undermainly, limited surface Yes ground flow 1 2 3 flow) Total 5 8 1 1 15 Shallow gas controlled Yes 19 12 31 Diverted flow (diverted) well Other (Kick in riser Yes release above BOP) 1 1 2 Total 19 13 1 33 String blown out of well, then the secondary Yes 1 1 7 9 barrier Limited surface flow Yes 6 8 1 8 17 3 5 48 Well before the secondary release No, no shear ram 1 1 barrier was activated Other Yes 1 1 2 3 Total 8 9 1 9 25 3 5 2 62 Unknown Yes 1 1 Unknown Total 1 1 Total all incidents 63 86 1 20 48 13 9 4 244 Incident category

Sub category

Page: 22



Page: 23

4. Overall Blowout/Well Release Experience 4.1 Blowout/Well Release vs. Flow Medium Table 4.1 shows an overview of the blowout/well release flow medium for the different incidents. Only US GoM OCS, UK, and Norwegian incidents in the period 1980-01-01 2009-12-31 are included. Table 4.1 Incident category

Blowout/well release flow medium for US GoM OCS, UK, and Norway in the period 1980-01-01 - 2009-12-31

Wire- Other/- Total line unknown Condensate, Gas (deep) 7 Condensate, Gas (deep), water 1 Gas (deep) 2 15 9 4 43 Gas (deep), Mud, Water 1 1 Gas (deep), Water 1 1 Mud 1 1 Oil 1 1 Oil, Gas (deep) 2 1 1 4 3 2 13 Oil, Gas (deep), H2S 1 1 Blowout (surface Oil, Gas (deep), Mud 1 1 flow) Oil, Gas (deep), Water 1 1 2 Shallow water 19 26 45 Shallow gas 1 3 4 Shallow gas H2S 1 3 1 5 Shallow gas, Water 1 1 Shallow, unknown fluid 1 1 Unknown 1 1 1 3 Water 1 1 2 Total 31 55 10 23 9 4 1 133 Condensate, Gas (deep) 1 1 Gas (deep) 3 4 7 Blowout Oil, Gas (deep) 1 1 2 (underShallow gas 1 1 ground Unknown 2 1 3 flow) Water 1 1 Total 5 8 1 1 15 Gas (deep), Mud 1 1 2 Diverted Shallow gas 15 10 25 well Shallow gas, Mud 3 1 4 release Shallow gas, Water 1 1 2 Total 19 13 1 33 Condensate, Gas (deep) 1 1 Condensate, Gas (deep), water 1 1 Gas (deep) 1 3 6 1 2 13 Gas (deep), Methanol 1 1 Gas (deep), Mud 2 1 1 4 Gas (gas lift gas) 1 1 Gas (trapped gas) 1 1 Mud 1 1 2 4 8 Well Oil 1 2 3 release Oil, Gas (deep) 1 1 8 1 11 Oil, Gas (deep), Mud 2 1 3 Oil, Gas (deep), Water 1 1 Oil, Water 1 1 2 Shallow gas 1 2 3 Shallow gas, Mud 1 1 Unknown 1 1 1 4 1 8 Total 8 9 1 9 25 3 5 2 62 Gas (deep) 1 1 Unknown Total 1 1 Total 63 86 1 20 48 13 9 4 244 * Blowouts caused by external loads are excluded (storm, military activity, ship collision, fire and earthquake). ** Stems from a blowout outside the casing from a shallow zone during production Flow medium

Dev. drlg 2

Expl. Drlg

Unk. Drlg

Completion

Workover 4 1 13

Production* 1

Page: 24


4.2 Blowout/Well Release vs. Flow-rates The blowout/well release flow-rates from the actual incidents described in the database are poorly documented. For some blowouts flow-rate figures exist, but for most blowouts they do not exist. The database has, however, three fields that describe the flow-rates during well tests for the actual well or close by wells. These fields are Gas volume, Oil volume and Water volume. Flow-rates are important figures in risk and environment analyses. To establish a realistic distribution of flow-rates to expect for specific fields, field specific productivity data should be compared to blowout/well release experience with respect to remaining restrictions in the wells during the blowout/well release situations. For several blowouts/well releases there are significant flow restrictions that will reduce the flow. 4.3 Severity The blowout/well release database contains a specific field describing blowout/well release severity. The quality of the information in this field is relatively low. These data are therefore not presented in this report. However, it should be noted that most of the blowouts/well releases do cause relatively small damages. 4.4 Ignition of Blowouts/Well Releases In Table 4.2 and Table 4.3 experienced data related to ignition of blowouts/well releases are presented. Only incidents from the period 1980-01-01 - 2009-12-31 have been included. It has been chosen to separate US GoM OCS, UK, and Norwegian blowouts/well releases from the rest of the world. Blowouts caused by external loads (storm, fire etc. are not included) Please note that it should not be differed between ignition probability for an oil blowout/well release and a gas blowout, because for oil blowouts the volume of gas blowing is very high compared to the volume of oil blowing.


Table 4.2

Main category

Experienced ignition for US GoM OCS, UK, and Norwegian blowouts/well releases in the period 1980-01-01 - 2009-12-31. Blowouts caused by external loads (storm, fire etc.) are not included Phase Dev.drlg Expl.drlg

Blowout (surface flow)

Deep or shallow Deep Shallow Deep Shallow

Completion Workover Production Wireline Other/Unknown Total Dev.drlg


Expl.drlg Production Other/Unknown

Deep Shallow Deep

Total Dev.drlg Diverted well release

Expl.drlg

Shallow Deep Shallow

Completion Total Dev.drlg Expl.drlg

Well release

Unknown drlg Completion Workover Production Wireline Other/Unknown

Deep Shallow Deep Shallow Deep

Total Expl.drlg Unknown

Deep

Total

Total

Table 4.3

No ignition 5 17 17 31 7 18 9 4 1 109 82,0 % 4 1 8 1 1 15 100.0% 19 1 11 1 32 97,0 % 6 1 7 2 1 9 23 3 5 2 59 95,2 % 1 1 100,0 % 215 88,5 %

Immediate ignition (<5 mins) 2 2 2

5 mins – 1 hour 2

Delayed Ignition 1 hour – 6 hrs – 6 hrs 24 hrs 1 1 4

>24 hrs 1

1 2 1

9 6,8 %

1 1

3 2,3 %

3

2 1,5 %

6 4,5 %

4 3,0 %

2 0,8 %

6 2,5 %

4 1,6 %

1 1 3,0 % 1

2

3 4,8 %

12 4,9 %

4 1,6 %

Total 8 23 23 32 10 23 1 4 1 133 100,0 % 4 1 8 1 1 15 100.0% 19 1 12 1 33 100,0 % 6 2 7 2 1 9 25 3 5 2 62 100,0 % 1 1 100,0 % 244 100,0 %

Experienced ignition for rest of the world (US GoM OCS, UK, and Norway are not included) blowouts/well releases in the period 1980-01-01 - 2009-12-31. Blowouts caused by external loads are not included.

PHASE

Development drilling Exploration drilling Unknown drlg Completion Workover Production Unknown Total

Page: 25

No ignition 17 39 5 1 9 7 10 88 62,0 %

Ignited blowouts Immediate ignDelayed ition (<5mins) ignition 8 4 8 3 1 2 3 1 3 3 1 1 3 1 27 15 19,0 % 10,6 %

Total Unknown 3 4 1 1 2 1 12 8,5 %

32 54 8 6 16 11 15 142 100,0 %

Page: 26


If comparing Table 4.2 and Table 4.3, far more ignited blowouts/well releases in the material for the "rest of the world". The main reason is probably that from "rest of the world" blowouts with small consequences are more seldom reported. 4.5 Blowout/Well Release Duration In Table 4.4 the experienced blowout/well release duration is presented. Only US GoM OCS, UK, and Norwegian blowouts/well releases in the period 1980-01-01 - 2009-12-31 have been included. Blowouts caused by external loads (storm, fire etc.) are not included. It should be noted that bridged or depleted are listed as primary cause for regaining well control for 31 out of the 55 exploration drilling Blowout (surface flow), and 14 of the 31 development drilling Blowout (surface flow). For the diverted well releases (both exploration and development drilling) bridged or depleted are listed as primary cause for regaining well control for 15 out of the 32 well releases.


Table 4.4

Page: 27

Blowout/well release duration for US GoM OCS, UK, and Norwegian blowouts/well releases in the period 1980-01-01 - 2009-12-31. Blowouts caused by external loads (storm, fire etc.) are not included

Phase

Shallow or deep

Blowout (surface flow) Deep Dev.drlg Shallow Deep Expl.drlg Shallow Completion Workover Production Wireline Other/Unknown

T ≤10 mins

1

1 3 1 2

1 1 1 0,8 %

Total

10min < 40min < 12 hrs < 2 days < 2 hrs < T T≤ T≤ 2 T≤2 T≤5 ≤ 12 hrs 40min hrs days days

2 2 1,5 %

7 5,3 %

Blowout (underground flow) Deep Dev.drlg Shallow Expl.drlg Deep Production Other/Unknown

30 22,6 %

1

2 1 1 4 12,1 %

Total

17 12,8 %

1 4 6 2 3 9 4 1

1 4 4 7 1 2 2

21 15,8 %

1

Total Diverted well release Dev.drlg Shallow Expl.drlg Deep Shallow Completion

2 2 2 4 1 4

5 1 7 21,2 %

4 1 1 5 15,2 %

1

T>5 days 1 4 4 8 4 4 2

27 20,3 % 1 1 4 1

2 6 6 8 1 3 1 1 28 21,1 % 2 2 1 5 33,3 %

1 6,7 %

1 6,7 %

1 6,7 %

3

2

1

2

5

2

1

1

2 6,1 %

3 9,1 %

8 24,2 %

4 12,1 %

7 46,7 %

Unknown

Total

8 23 23 32 10 23 9 4 1 133 0,8 % 4 1 8 1 1 15 100,0 % 19 1 12 1 33 100,0 %

Well release Dev.drlg Expl.drlg Unknown drlg Completion Workover Production Wireline Other/Unknown

Deep Shallow Deep Shallow Deep

2 1

1 1,6 %

2 6 9,7 %

6 2 7 2 1 9 25 3 5 2 62 100,0 %

35 14,3 %

1 1 100.0% 43 17,6 %

1 1 100.0% 244 100,0 %

1 1

1 9 21

1

1

1

2 2

1

5 47 75,8 %

Total Unknown Expl.drlg

4 2 5

2 3,2 %

1 1,6 %

3 4,8 %

2 3,2 %

Deep

Total All blowuts/well releases

52 21,3 %

11 4,5 %

13 5,3 %

29 11,9 %

37 15,2 %

24 9,8 %

4.6 Blowout/Well Release Flow-paths and Release Points In Table 4.5 – Table 4.7 the experienced release point vs. the final blowout/well release flow paths for the various phases of operation are presented. Only US GoM OCS, UK, and Norwegian blowouts/well releases in the period 1980-01-01 – 2009-12-31 have been included. Blowouts caused by external loads (storm, fire etc.) are not included.

Page: 28

Table 4.5


Release point vs. final flow-path for drilling shallow gas blowouts and well releases

Incident main Final flow-path  type  Release point  Blowout (surface flow) Diverted and BOP valve outlet Diverter syst.leak - line eroded Diverter syst.leak - line parted Diverter syst.leak - main diverter Drillfloor - through rotary From wellhead Subsea - outside casing Subsea wellhead Development Total drilling shallow gas Blowout (underground flow) From wellhead incidents Total Diverted well release Diverted Total Well release Drillfloor - through rotary From wellhead Total Development drilling total Blowout (surface flow) Diverter syst.leak- line eroded Diverter syst.leak- line parted Diverter syst.leak-main diverter Drillfloor - through rotary Drillfloor - top of drill string From wellhead Subsea - outside casing Subsea crater Exploration drilling shallow Subsea wellhead Unknown gas incidents Total Diverted well release Diverted Total Well release Subsea wellhead Total Exploration drilling total TOTAL ALL SHALLOW GAS INCIDENTS

Through Through UnderThrough Outside Undrill outer ground annulus casing known string annulus blowout 1 1 2 2 2

1 1 6

1 4

1 8

1 9

4

1

1

1 1 16 16

3 3

19 19

1 1 13

1

1 1 2 45

1 1

3 1 2 1 1 3 4 1 15 1 32

4

2

3 1 2 1 1 3 4 1 15 1

21

4

5

12 12

1 1

1 1 34 59

1 1 2 3 3 7 4 2 23 1 1

1 1 25

Total

12 12 1 1 5 18

5 9

2

1 2

2 2 46 91

Most shallow gas blowouts/well releases have their final flow-path through the well bore annulus. The flow is either diverted without any problems, the diverter system fails, or the flow is released through the subsea wellhead.


Table 4.6

Release point vs. final flow-path for “deep” drilling blowouts and well releases

Final flow-path  Through Through Through Through Outside UnderUndrill test outer ground Release point  annulus casing known string string annulus blowout Blowout (surface flow) Drillfloor - through rotary 1 Drillfloor choke manifold 1 From wellhead 1 3 Subsea - outside casing 1 Unknown 1 Total 4 3 1 DevelopBlowout (underground flow) ment No surface flow 4 drilling, deep Total 4 Well release Drillfloor - through rotary 1 3 Subsea - outside casing 1 Unknown 1 Total 1 3 1 1 Dev.drlg total 1 7 3 2 4 1 Blowout (surface flow) Bop valve outlet 1 Diverter syst.leak- line parted 1 Drillfloor - through rotary 2 1 Drillfloor - top of drill string 2 From wellhead 3 3 Shaker room 1 Subsea - outside casing 5 Subsea BOP 2 Subsea crater 1 Subsea wellhead 1 Total 2 10 4 7 Blowout (underground flow) No surface flow 6 ExploraSubsea - outside casing 1 tion Unknown 1 drilling, Total 1 6 1 deep Diverted well release Drillfloor - through rotary 1 Total 1 Well release Diverted 1 Drillfloor - through rotary 3 Drillfloor - top of drill string 2 Drillfloor - tubing valve 1 Total 2 1 5 Unknown Unknown 1 Total 1 Expl.drlg total 4 1 15 4 8 6 2 Well release Unknown Drillfloor - through rotary 1 drilling, Total 1 deep Unknown drlg total 1 Total all deep 4 2 23 7 10 10 3 Incident main type

Page: 29

Total

1 1 4 1 1 8 4 4 4 1 1 6 18 1 1 3 2 6 1 5 2 1 1 23 6 1 1 8 1 1 1 3 2 1 7 1 1 40 1 1 1 59

Through annulus is the most common final flow-path for both exploration and development drilling “deep” blowouts/well releases. Forty percent of the deep drilling blowouts/well releases was flowing through the annulus. Ten incidents came outside the casing, causing subsea releases. One of them also ignited when the gas reached the surface (64 meter of water). Also for one of the two subsea BOP releases (94 meter of water) the gas ignited. In general subsea releases are more frequent for exploration well blowouts than for development well blowouts. This was also observed for the shallow gas blowouts. Eleven incidents only caused underground flow. Probably more of these incidents occur than reported in the database.

Page: 30

Table 4.7


Release point vs. final flow-path for completion, workover, production and wireline blowouts and well releases

Through Through Through Through Outside UnderFinal flow-path  Through Coiled drill outer ground Total Release point  tubing annulus annulus casing blowout tuning string Blowout (surface flow) Drillfloor - drillpipe valve 1 1 Drillfloor - through rotary 1 1 2 Drillfloor - top of drill string 3 1 4 Drillfloor - top of tubing 1 1 From x-mas tree 1 1 Mud room 1 1 Total 5 4 1 10 CompDiverted well release letion Diverted 1 1 Total 1 1 Well release Drillfloor - through rotary 1 4 5 Drillfloor - top of tubing 1 2 3 Shaker room 1 1 Total 3 2 4 9 Completion total 8 6 6 20 Blowout (surface flow) BOP valve outlet 4 4 Drillfloor - through rotary 2 2 Drillfloor - top of drill string 4 4 Drillfloor - top of tubing 1 2 3 Drillfloor - tubing valve 1 1 From wellhead 1 1 2 From x-mas tree 1 1 2 Mud room 1 1 Subsea - outside casing 2 2 Subsea wllhead 1 1 Workover Unknown 1 1 Total 1 5 5 9 1 2 23 Well release BOP valve outlet 3 3 Drillfloor - through rotary 1 13 14 Drillfloor - top of drill string 1 1 Drillfloor - top of tubing 3 3 From above x-mas tree 1 1 2 From x-mas tree 1 1 2 Total 7 18 25 Workover total 1 5 12 27 1 2 48 Blowout (surface flow) From wellhead 1 1 1 3 From x-mas tree 2 2 Subsea - outside casing 2 2 Subsea crater 1 1 Subsea x-mas tree 1 1 Total 4 1 1 3 9 ProdBlowout (underground flow) uction No surface flow 1 1 Total 1 1 Well release From x-mas tree 2 2 Subsea x-mas tree 1 1 Total 3 3 Production total 7 1 1 3 1 13 Blowout (surface flow) Drillfloor 1 1 From above x-mas tree 2 2 From x-mas tree 1 1 Total 3 1 4 Well release Wireline Drillfloor -Wireline stuffing box/BOP 1 1 From above x-mas tree 2 2 From x-mas tree 1 1 Unknown 1 1 Total 1 4 5 Wireline total 1 7 1 9 Blowout (surface flow) From wellhead 1 1 Total 1 1 Other/ Blowout (underground flow) UnNo surface flow 1 1 known Total 1 1 Well release 2 2 Subsea wellhead 2 2 Unknown total 2 1 1 4 Total 1 14 32 36 4 5 2 94 Phase


Page: 31

Most blowouts during completion result in flow through the tubing or the drill string/work string. It is important to note that for several of these blowouts the BOP stack did not include a blind-shear ram (Table 3.1 on page 21). With a blind-shear ram these blowouts could have been stopped at an earlier stage, and they would in many cases not have been categorised as a blowout. It is not mandatory to use blind-shear rams in US OCS surface BOPs. The normal flow-paths for workover blowouts/well releases are either through the drill string/tubing or through the annulus. It is important to note that also for several of these blowouts the BOP stack did not include a blind-shear ram (Table 3.1 on page 21). Further, the drill string/tubing blowouts are mostly released from the top of the drill string/tubing hanging in the rotary table slips. Annulus blowouts do mostly come through the rotary. Wireline blowouts typically flow through the tubing and the release point is above the X-mas tree. Eight of the twelve production blowouts came to the air in the wellhead/X-mas tree area. 4.7 Blowout/Well Release Causes Normally to experience a blowout, at least one primary and one secondary barrier have to fail. For drilling, workover and completion blowouts the primary barriers are usually the hydrostatic pressure from the mud column and the secondary barrier is the mechanical barriers, either subsea or on the installation. For production wells the primary and secondary barriers are mechanical barriers. It should be noted that when drilling in shallow zones there is normally only one blowout barrier. The installations do, however, have means for forcing the gas away from the installation. In this report those means are treated as a secondary barrier. The blowout database does contain fields for describing the blowout/well release causes, i.e. why were the primary and secondary barrier lost? Further, the database contains one field that describes whether the blowout/well release was "caused" by an external load. Out of the 253 blowouts/well releases from US GoM OCS, UK, and Norway in the period 1980-01-01 - 2009-12-31, nine were "caused" by an external load (Table 2.6, page 17). It is, however, important to note that an external load normally only ruins the topside barrier. To experience a blowout, the downhole barrier also has to fail. So an external load will not be the single blowout cause. Typically the external load ruins the wellhead/X-mas tree barriers of an active well, and the downhole barrier fails to activate or is leaking.

Page: 32


Table 4.8 shows an overview of blowouts caused by external loads. Table 4.8

Overview of blowouts caused by external loads for US GoM OCS, UK, and Norway in the period 1980-01-01 - 2009-12-31

Water OperPhase depth (m) ation 6 Closed Prodin gas uction well

Activity

External cause Ship collision

143 Prod- ProducFire/Gas lifting uction ing oil explosion 12 10

13

10

15 40

52

Prod- Produc- Regular Ship uction ing gas production collision Prod- Produc- Regular Storm uction ing oil production Prod- Produc- Regular Storm uction ing oil production Prod- Produc- Regular Storm uction ing oil production Prod- Produc- Regular Storm uction ing oil production Closed Surface Prodin gas mainten- Storm uction well ance Closed ProdWait on in gas Storm uction repair well

Primary barrier C5.SCSSV/storm choke failure (Not enough surge to close valve) C5.SCSSV/storm choke failure & C4.Tubing to annulus communication, equipment or nipple failure (5 to 6 wells failed) C5.SCSSV/storm choke failure (not installed?) C5.SCSSV/storm choke failure (Assumed, may also have been a tubing annulus communication) C5.SCSSV/storm choke failure (Assumed, may also have been a tubing annulus communication) C5.SCSSV/storm choke failure (Assumed, may also have been a tubing annulus communication) C5.SCSSV/storm choke failure C5.SCSSV/storm choke failure C5.SCSSV/storm choke failure (Trapped hydraulic in control line)

Secondary barrier A8.X-mas tree failed (leakage between tubing head flanges and master valve)

Flowmedium Oil, Gas (deep)

A8.X-mas tree failed (all Oil, Gas trees failed due to topside (deep) fire) A8.X-mas tree failed (due to collision)

Oil, Gas (deep)

A8.X-mas tree failed (damaged by storm)

Oil


Oil


Oil

B4.Wellhead failed (hurricane damage) A8.X-mas tree failed (damaged by Hurricane Ike) A8.X-mas tree failed (damaged by Hurricane Ike)

Oil Gas (Deep) Gas (Deep)

Table 4.9 and Table 4.10 show the different causes for losing the primary and secondary barriers, as reported in the database.


Table 4.9 Category

Page: 33

Primary barrier failure causes listed in the database for the US GoM OCS, UK, and Norwegian blowouts/well releases in the period Jan. 1980 - Dec. 2009 Primary barrier failure

Too low mud weight Annular losses While cement setting Cmt preflush weight low Trapped gas Unknown why Too low hyd. head Swabbing Gas cut mud Improper fill up Disconnected riser Unexp. high well pressure Reservoir depth uncertainty Poor cement Formation breakdown Blowout Packer leakage (surface Stripper BOP failure flow) Tubing plug failure Snubbing equipment failure X-mas tree failure Packer plug failure Tubing leakage/burst Tubing equipm./nipple leak SCSSV/storm choke failure Well test string barrier failure Wireline stuffing box failure Wireline lubricator failure Unknown Total No. of primary barrier failures Incidents with two prim. barrier failures Blowout (surface flow) Total Too low mud weight Annular losses Too low While cement setting Blowout hyd. head Unknown why (underground Unexp. high well pressure flow) Tubing leakage Unknown Blowout (underground flow) Total Too low mud weight Annular losses While cement setting Too low Trapped gas hyd. head Unknown why Diverted well release Swabbing Unexp. high well pressure Total No. of primary barrier failures Incidents with two prim. barrier failures Diverted well release Total Too low mud weight Annular losses Drilling into neighbor well Trapped gas Too low hyd. head Unknown why Swabbing Gas cut mud Unexp. high well pressure Poor cement Coiled tubing failure. Tubing plug failure Casing plug failure Snubbing equipment failure Well release X-mas tree failure Packer plug failure Tubing to annulus leak - tubing burst Tubing leakage SCSSV/storm choke failure Well test string barrier failure Wireline stuffing box failure Wireline lubricator failure Other Unknown Total No. of primary barrier failures Incidents with two prim. barrier failures Well release Total Unknown Unknown Unknown Total Total all

Dev.drlg Expl.drlg Unk drlg Comp- Work- Prod- WireUnTotal Deep Shal. Deep Shal. Deep letion over uction line known 2 3 3 2 4 14 1 1 4 1 1 8 3 9 4 3 1 20 1 1 1 1 1 4 2 6 1 1 15 6 2 3 2 4 17 2 2 4 2 1 3 1 1 2 1 2 10 1 14 1 1 2 1 2 1 1 5 1 1 2 1 1 1 1 1 1 2 4 4 1 1 1 1 2 2 3 1 1 2 1 1 5 7 1 1 1 1 2 2 1 1 2 8 24 26 32 10 23 9 4 1 136 1 3 3 8 23 23 32 10 23 9 4 1 133 1 1 2 1 1 1 1 2 2 4 1 2 3 1 1 2 1 3 4 1 8 1 1 15 1 2 3 4 1 5 4 1 5 1 1 1 1 2 9 9 3 7 10 21 1 12 1 35 2 2 19 1 12 1 33 1 1 1 1 4 1 1 2 1 1 1 7 8 1 2 1 4 1 1 1 3 3 9 1 1 3 1 1 1 6 1 1 2 1 1 1 1 2 2 2 2 1 1 1 1 3 3 1 1 2 2 2 6 1 1 2 1 1 1 1 2 1 3 1 1 2 6 2 7 2 1 9 27 3 5 2 64 2 2 6 2 7 2 1 9 25 3 5 2 62 1 1 1 1 18 45 40 46 1 20 48 13 9 4 244

Page: 34


Table 4.10 Secondary barrier failure causes listed in the database for the US GoM OCS, UK, and Norwegian blowouts/well releases in the period Jan. 1980 - Dec. 2009. Category Secondary barrier failure String safety valve failed String safety valve not available Failed to stab kelly valve SCSSV/storm choke failed X-mas tree failed Failed to close BOP Diverted - no problem Failed to operate diverter Diverter failed after closure Drilling without riser Disconnected riser Annulus valve failed Not sufficient frictional backpressure BOP failed after closure Blowout BOP/diverter not in place (surface Wellhead failed flow) Casing head failed Tubing to annulus communication Poor cement Casing valve failure Wellhead seal failed Outer casing failed Inner casing failed Fracture at csg shoe Casing leakage Formation breakdown Not relevant Unknown Total no. of secondary barrier failures Incidents with two sec. barrier failures Blowout (surface flow) total Failed to close BOP Diverted - no problem Fracture at csg shoe Blowout Casing leakage (underFormation breakdown ground Unknown flow) Total no. of secondary barrier failures Incidents with two sec. barrier failures Blowout (underground flow) total Diverted Failed to close BOP well Diverted - no problem release Diverted well release total String safety valve failed String safety valve not available Failed to stab kelly valve Wireline BOP/lubricator not installed Wireline BOP/lubricator failed SCSSV/storm choke failed X-mas tree failed Coiled tubing stuffing box failed Failed to close BOP Diverted - no problem Well Drilling without riser release Not sufficient frictional backpressure BOP failed after closure Wellhead failed Wellhead seal failed Outer casing failed Fracture at csg shoe Not relevant Other Unknown Well release total Unknown Unknown Unknown total Total no. of secondary barrier failures Incidents with two sec. barrier failures Total

Dev.drlg Deep Shal.

Expl.drlg Unk drlg Comp- Work- Prod- WireUnDeep Shal. Deep letion over uction line known 1 1 2 1 1 2 1 3 3 1 1 5 2 2 1 3 7 1

1 3 7 2

1

8 11 1 1 1

2 3

1 4

5 3 2 1

1 2

1

1 3

3 1

1 1 1 1 1 1

1

8

1 1 2 1 25 2 23

1

1 1

1

8

2 1 4 4

2 1 1 19 19

2 4

27 4 23 1

4 1

2

4 1 34 2 32

2 10 10

1 2 2 3 9 1 8 1 1 1

1 1 2

26 3 23

10 1 9

1 4

1

4

1

1

1

1 1

1

1

1 12 12

1 1

2

1

1 1

4

1 1 1 1 7

1

3

1 1

1

1 1

1 1

1 1

1

1

6 2

1 1

1 1

1 1 1 6

18 18

1

2

48 3 45

1 7 1 1 45 5 40

2

1

1 9

48 2 46

1

20

1

20

2

25

1 3

51 3 48

14 1 13

1 1 5

2

9

4

9

4

2

Total 4 4 7 1 8 14 1 3 16 13 1 1 1 9 13 3 2 2 6 2 1 1 2 7 10 2 8 3 145 12 133 1 1 3 3 4 5 17 2 15 2 31 33 2 1 4 1 1 2 3 1 17 1 1 9 2 1 2 1 1 4 3 5 62 1 1 258 14 244


Page: 35

4.8 Operations and Activities when Blowout/Well Release Occurs In Table 4.11 to Table 4.16 an overview of the operations and activities in progress when the blowouts/well releases occurred is presented for the various operational phases. The data is from the US GoM OCS, UK, and Norwegian blowouts/well releases in the period 1980-01-01 - 2009-12-31. Table 4.11 Operations and activities in progress when the shallow gas blowouts/well releases occurred Operation  Activity  Blowout (surface flow) Actual drilling Well suspended Tripping out Out of hole Coring Milling Cementing casing Wait on cement Install BOP Nipple down BOP Changing equipment Wait on weather Unknown Total no. of activities No. of blowouts listed with two activities No. of blowouts (surface flow) Blowout (underground flow) Wait on cement No. of blowouts (underground flow) Diverted well release Actual drilling Tripping out Circulating Casing running Cementing casing Wait on cement Unknown No. of diverted well releases Well release Actual drilling Tripping out Leak off test Unknown No. of diverted well releases Total no. of activities No. of incidents listed with two activities Total no. of incidents

Drilling activity Casing running Dev.

Expl.

3

15

Dev.

Expl.

Other/unknown operations Dev. Expl.

Dev. 3 1 6

1 6

Total

2 1 1 1 1 9

1 3

1 9 1

1

4 24

10

24

11 1 10

4

1 1 3

1 1 4

4

3

4

1 1 4 8 1

1 2 24 1 23

9 1

4 8 1 2

1

9

6

1 1 5 32 32

55

2 1 1 1 1 3 1

1 1 9 1

1

4

4 1 2

1

1

19

1 12

1 1

1 1

1 1 24

1 34

24

34

1 1 19 1 18

5

3

1 7

5

3

7

1 2 46 1 45

Total 18 1 8 1 1 1 2 12 1 1 1 2 7 56

1 1

2

13

15

1

1 1 10

Expl.

2 46 46

13 9 1 2 1 4 1 31 1 1 1 1 4 92 1 91

Page: 36


Table 4.12 Operations and activities in progress when the “deep” drilling blowouts/well releases occurred Operation  Activity  Blowout (surface flow) Actual drilling Tripping out Out of hole Circulating Casing running Cementing casing Wait on cement Cement squeeze Install BOP Nipple down BOP Actual well test Pull wireline Unknown Total no. of activities No. of blowouts listed with two activities No. of blowouts (surface flow) Blowout (underground flow) Actual drilling Logging Unknown No. of blowouts (underground flow) Well release Actual drilling Tripping out Circulating Pulling casing Pull/drill out well plugs Actual well test Gravel pack Maintenance surface equipment Well closed in Unknown Total no. of activities No. of well release listed with two activities No. of well releases Unknown Unknown No. of unknown incidents Total no. of incidents

Drilling activity Casing running Dev.

Expl.

1

10 3 1

Dev.

Expl.

Other/unknown operations Unk. Dev. Expl. drlg

Total Dev. Expl. 1

3

1 1 1 3 1

3

1

1

2

1

8

1 4

2

15

4

3 1

4

4

1 2

1 1 1 8

1 15

9 2 7

3 1

1 5

3 3

4

4

2 25 2 23 4 4 8

7 1 4 12

1

4 1 2 1 2 2 1 1 1 1 16 1 15

1

1 1 59

4 1 1 1

1 1

1

6

1

6

1 1 1 1 1 1 1 1 1 9 1 8

18

1 1 40

1 1

1

1 1

1

1

5

2

1

5

2

1

1 1 7 1 6

3

1 1 11

11

11 3 1 1 1 1 6 1 1 2 1 3 1 33 2 31

2 1

2

10 3 1 1 1 1 3 1

1 2

1

Unk. Total drlg

22

4

7

1

1

1


Page: 37

Table 4.13 Operations and activities in progress when the completion blowouts/well releases occurred Operation  Activity  Blowout (surface flow) Tripping out Circulating Killing Perforating Gravel pack Cleaning well Other , bleed off pressure above SCSSV Unknown No. of blowouts (surface flow) Diverted well release Circulating No. of diverted well releases Well release Tripping out Tripping in Flow check Pull tubing Perforating Gravel pack Cleaning well Maintenance well equipment Total no. of activities No. of well releases listed with two activities No. of well releases Total no. of incidents

Running/- Well testing installing well incl. equipment preparations

Circulating

Perforating

Coiled tubing

Other/Total unknown 2

1 3

2 1 1 1 2 1 1 1 10

1 1

1 1

1

2 1 1 1 1 1 1 2 10 1 9 20

1 1 1 2 1 1 4

2

1

1 1 1

1 1 1 1 1 3 3 7

2 1 1 1

1

1

1 1

2

3

1 2

1 1

2 6

Page: 38


Table 4.14 Operations and activities in progress when the workover blowouts/well releases occurred Operation  Activity  Blowout (surface flow) Tripping out Tripping in Out of hole Circulating Pulling casing Cement squeeze Set well plug Pull tubing Perforating Gravel pack Cleaning well Coiled tubing operation Snubbing in Other Unknown Total no. of activities No. of blowouts with two activities No. of blowouts (surface flow) Well release Circulating Pulling casing Install BOP Pull/drill out well plugs Nipple down x-mas tree Snubbing out Pull tubing Acidizing Run coiled tubing Coiled tubing operations Changing equipment No. of well releases Total no. of incidents

RunPulling InstWell Wirening Circ- PerAban- Temp well alling testing Snubb- Coiled line well ulat- fordon pluequipequip- incl. ing tubing operaequiping ating well gged ment ment prepare tions ment

Total

2

2 1 1 2 1 1 1 2 1 1 2 2 4 2 1 24 1 23

1 1 1 1

1 1 1

1

1 1 1 1 1

5

1

2

1

2

1

1 3

5

1

2

1

2

1

3

1 1

1 1 2

1 1 2

4 1 3

5 5

1

2 1 1 4 1 2 10 1 1 1 1 25 48

1 1

1

1

1

1 1

1 1

1 2 8

2 1 1 1

11 16

1

1 2 4

1

2

2 3

2 5

2 5

4 9

Table 4.15 Operations and activities in progress when the production blowouts/well releases occurred Operation  Producing Producing Producing oil condensate gas Activity  BLOWOUT Maintenance well equipment Regular production 1 4 Failure diagnosing 1 4 No. of blowouts BLOWOUT (UNDERGROUND FLOW) Failure diagnosing No. of blowouts (underground flow) WELL RELEASE Regular Production 2 1 2 1 No. of well releases TOTAL NO. OF INCIDENTS 1 2 5

Closed in gas/condensate well

Unknown

1 1 2 3

1

Total

1 6 2 9

1 1

1 1

4

3 3 13

1


Page: 39

Table 4.16 Operations and activities in progress when the wireline blowouts/well releases occurred Operation  Activity  BLOWOUT (SURFACE FLOW) Run wireline Pull wireline Logging No. of blowouts WELL RELEASE Changing Equipment Run wireline Pull Wireline Unknown No. of well releases Total no. of incidents

Rigging up wireline equipment

Running wireline operations

Total

2 1 1 4

2 1 1 4

2 1 1 4 8

1 2 1 1 5 9

1

1 1

One of the blowout listed with “Unknown” as Phase was a Blowout (underground flow) with no information related to operation and activity. The other blowout listed with “Unknown” as Phase was a Blowout (surface flow) with installing equipment listed as operation and nipple down BOP as activity. 4.9 Exploration Wildcats vs. Exploration Appraisal Blowouts/well releases The incidents occurring during drilling in exploration wells for the US GoM OC, UK waters and Norwegian waters are also categorized in exploration wildcats and exploration appraisal incidents. Table 4.17 shows the number of exploration wildcats and exploration appraisal blowouts/well releases. Table 4.17 Exploration wildcats and Exploration appraisal blowouts/well releases for the US GoM OCS, UK, and Norwegian in the period Jan. 1980 - Dec. 2009 Main category

Shallow or deep Deep

Blowout (surface flow) Shallow

Exploration well type Appraisal Wildcat Appraisal Wildcat Unknown

Blowout (surface flow) total Blowout (under-ground flow)

Deep

Appraisal Wildcat

Blowout (underground flow) total Deep Diverted well release

Shallow

Wildcat Appraisal Wildcat

Diverted well release total Deep Well release Shallow Well release total Unknown Unknown total Total all exploration incidents

Deep

Appraisal Wildcat Unknown Appraisal Wildcat Appraisal

No of incidents 10 13 12 19 1 55 1 7 8 1 5 7 13 3 3 1 1 1 9 1 1 86

4.10 Blowouts from Australia, Canada East Coast, The Netherlands, and US/California OCS Exposure data from Australia, Canada East Coast, The Netherlands and US/California OCS has been included in this report (Section 5). The associated blowouts and well releases are,

Page: 40


however, not included in the previous chapters of the report. Table 4.18 and Table 4.19 list key data for the observed blowouts in these areas in the period 1980-01-01 - 2009-12-31. Table 4.18 Key data for blowouts observed blowouts/well releases for the Canadian East Coast, and Australian waters Id_no Country

259 Canada East Coast

266 268 Canada East Australia Coast Phase Expl.drlg Expl.drlg Production Category Blowout (surface flow) Blowout Blowout (surface (underground flow) flow) Sub category Totally uncontrolled flow, from a Underground flow Totally uncontrolled deep zone only flow, from a deep zone Date 22-Feb-84 20-Sep-84 17-Dec-84 Flow medium Condensate, Gas (deep) Gas (deep) Oil, Gas (deep) Ignition type NO NO NO Duration days 10 270 10 Loss of C14.Casing plug failure (HP A8.Too low hyd. C4.Tubing to primary barrier zone isolating bridge plug broke head annulus comat 5200 meters) unexpected high munication well pressure equipm./nip-ple failure (assumed) Loss of B1.Failed to close BOP (First D2.Casing D2.Casing leakage secondary annular, obstruction in BOP,then leakage (assumed) barrier S/R,- to little power to cut, then acoustic close failed) Operation D4.Well testing (preparing to test D1.Drilling activity P1.Producing oil shallow zone) Activity B1.Circulating A7.Fishing P1.Regular production Data quality Very good Fair Very low

548 Australia

590 Australia

Expl.drlg Blowout (underground flow) Underground flow only

Dev.Drlg Blowout (surface flow)

07-Feb-1991 Gas (deep) NO Unknown A15.Too low hyd. head unknown why

Totally uncontrolled flow, from a deep zone 21-Aug-2009 Oil, Gas (deep) Yes 73 C14.casing plug failure

D3.Formation breakdown

Not relevant

Unknown

A10.well suspended D7.temporary plugged Very good

Unknown Low

Table 4.19 Key data for blowouts observed blowouts/well releases for the Dutch waters and US California OCS Id_no Country

405 Netherlands

Phase Category Sub category

Production Workover Blowout (surface Well release flow) Totally uncontrolled Limited surface flow, from a deep flow before the zone secondary barrier was activated

Date Flow medium

15-May-83 Gas (deep)

01-April 2010 Gas (deep)

Ignition type Duration days

NO

NO 10

Loss of primary C3.Tubing to barrier annulus communication tubing leakage

Loss of secondary barrier Operation Activity Data quality

618 Netherlands

10 minutes (assumed) C15. Snubbing equipment failure

449 US/California OCS Workover Well release

475 US/California OCS Workover Well release

482 US/California OCS Dev.drlg Well release

539 US/California OCS

Limited surface flow before the secondary barrier was activated 7-Mar-98 Gas (deep), Water NO Unknown

Limited surface flow before the secondary barrier was activated 19-Nov-00 Oil, Water

24-Mar-01 Mud

18/11/2004 Gas (deep)

NO

NO 0.1042 (2.5 hrs)

A15.Too low hyd. head unknown why

C13.Tubing plug failure

D2.Casing leakage B1.Failed to close Not relevant BOP. Closed after string ejected from the well P2.Producing gas W8.snubbing W1.Pulling well equipment P1.Regular F9.snubbing in A2.Tripping out production Fair Low Fair

NO Unknown

Workover Blowout (surface flow) Shallow gas Totally uncontrolled controlled flow, from a deep flow (diverted) zone

0.0104 (15 mins) A10.Too low hyd. head annular losses

Not relevant

B10.Diverted - no problem

W1.Pulling well equipment D6.Pull/drill out well plugs Low

D1.Drilling activity Unknown Good

A10.Too low hyd. head - annular losses. (Stop pumping for 30 minutes for removal of lock down pin) B4.Wellhead failed (removed lock down pin) W3.Installing equipment G4.Maintenance surface equipment Very good


Page: 41

5. “Normal” Drilling and Production Exposure Data The exposure date in this section of the report includes yearly well drilling and no. of wells in production for some specific areas. The offshore drilling wells are from Norway, UK, US GoM OCS, East Coast of Canada and the Netherlands. The production data stems from Norway, UK, and US GoM OCS. The format of the exposure data varies for the different areas. 5.1 Drilling Exposure Data 5.1.1 US GoM OCS The drilling exposure data for the US GoM OCS stems from a computerised list of all wells drilled (/1/). A version from November 2011 was used for this report. The file includes information on borehole activities such as drilling activity, counts on the number of boreholes completed, and number of shut-in's. Additional information includes the lease number, well name, and spud date, the well class, surface area/block number, well depths, and statistics on well status summary. Per November 2011 the data-file includes information from more than 51 700 wells drilled all time in the US GoM OCS. The number of wells drilled in the US GoM OCS area is presented in Table 5.1.

Page: 42

Table 5.1


Number of drilled wells in US GoM OCS area

Exploration wells Development wells Wildcat* Appraisal* Total Spud All wells SideAll wells SideAll wells Side- Completed All wells Side- Completed year inc. tracked inc. tracked inc. tracked inc. tracked wells** sidetracks wells*** wells** sidetracks wells*** sidetracks wells*** sidetracks wells*** 1980 140 11 253 21 393 32 104 904 118 529 1981 162 10 218 22 380 32 99 965 125 571 1982 204 22 217 27 421 49 112 912 100 560 1983 187 16 230 29 417 45 112 828 142 511 1984 371 35 254 34 625 69 161 816 151 511 1985 312 28 238 48 550 76 147 745 157 439 1986 169 27 117 17 286 44 77 483 109 286 1987 213 30 220 36 433 66 116 496 104 301 1988 342 51 240 47 582 98 154 481 106 302 1989 228 26 254 43 482 69 132 558 115 348 1990 281 33 240 38 521 71 141 621 197 377 1991 168 21 179 20 347 41 98 475 142 285 1992 113 14 115 15 228 29 57 372 115 223 1993 179 20 182 45 361 65 98 624 218 385 1994 230 21 208 34 438 55 120 661 262 379 1995 201 36 194 52 395 88 110 765 337 431 1996 263 42 200 49 463 91 127 775 335 463 1997 291 58 254 69 545 127 153 905 453 565 1998 267 79 229 101 496 180 149 646 383 446 1999 201 55 169 69 370 124 121 669 370 462 2000 223 53 219 53 442 106 146 938 602 659 2001 229 56 182 56 411 112 123 851 542 531 2002 174 43 135 35 309 78 112 633 358 337 2003 200 62 154 57 354 119 114 539 306 309 2004 201 55 162 66 363 121 132 553 301 322 2005 191 66 164 64 355 130 109 457 273 251 2006 242 79 171 81 413 160 153 359 196 212 2007 178 59 122 52 300 111 102 316 174 186 2008 128 44 139 75 267 119 91 299 189 168 2009 91 30 56 30 147 60 46 173 103 99 Total 6379 1182 5715 1385 12094 2567 3516 18819 7083 11448 * To differ between Wildcats and Appraisal wells the following has been assumed; All exploration wells drilled in certain areas are numbered from 1 and further, where well number 1 is the first well drilled. For US GoM OCS all exploration wells numbered as 1 have been regarded as Wildcats, while all the other wells are regarded as Appraisal wells. This may be inaccurate, but this will likely lead to an underestimation of no. of Wildcats compared to no. of Appraisal wells for the US GoM OCS ** In the 2000 version and earlier versions of this report the number of completed wells as listed in the source file was used directly for this column. Closer investigation showed that when a production well is abandoned it would be re-categorized to abandoned. This will lead to an underestimation of number of completed wells. To adjust the figure to a more correct number 30 % of all exploration wells and 70% of all development wells are assumed to be completed each year for the whole period 1980 – 1999. These figures stems from the average in the period 1992 – 1997. *** No. of sidetracks are from 2011 version based on the API numbering instead of a well Status code as used in earlier version. This has caused an approximately reduction in the number of side tracked wells for exploration wells and an increase for development wells

As seen from Table 5.1 many of the US GoM wells are side-tracked. The wells in the Gulf of Mexico are primarily side-tracked for deflecting the direction of the borehole to encounter an alternate target horizon or potential productive interval at a selected aerial location. Deviation of a well bore to bypass junk in the hole is not classified as a side-track. Quite a number of wells in the Gulf of Mexico are completed in producing intervals at subsea depths between 1000 feet and 10 000 feet. In areas where the geology and formation pressures have previously been established, such development wells are routinely drilled in from 1 to 10 days, due to the unconsolidated nature of the formations at depths above 10 000 feet. It should further, be noted that the drilling period for many of the US GoM wells is of very short duration. If looking at all the wells (1980 – 2006);  Approximately 26 % of the development wells were drilled in less than 10 days.  Approximately 20 % of the exploration wells were drilled in less than 10 days.


Page: 43

5.1.2 United Kingdom The drilling exposure data for UK is based on the Department of Trade and industry web page (https://www.og.decc.gov.uk/information/bb_updates/appendices/Appendix4.htm). The number of wells drilled in the UK area is presented in Table 5.2. It should be noted that a change of data source have increased the number of wells drilled with approximately 3%, compared to the number of wells reported the previous years. Table 5.2 Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Number of drilled wells in UK offshore sector Exploration wells Wild cat Appraisal All wells inc. Sidetrack- All wells inc. Sidetracksidetracks ed wells sidetracks ed wells 32 1 22 0 47 0 26 1 68 5 48 5 79 7 56 8 107 5 84 7 91 4 63 1 75 4 43 5 74 5 69 12 93 7 79 18 94 7 83 13 157 12 67 11 103 3 78 21 77 13 55 15 51 2 60 12 61 2 39 14 60 10 34 8 71 4 42 10 59 2 36 12 46 4 32 16 18 2 17 3 27 4 34 12 24 3 35 19 16 2 29 11 26 2 19 9 30 4 34 12 41 8 37 15 29 1 41 17 34 2 77 35 44 3 61 26 23 2 41 22 1757 130 1441 370

Development wells Total 54 73 116 135 191 154 118 143 172 177 224 181 132 111 100 94 113 95 78 35 61 59 45 45 64 78 70 111 105 64 3198

All wells inc. sidetracks 142 146 133 102 123 149 99 140 175 154 124 150 170 169 208 266 283 255 289 237 225 286 260 207 167 228 202 165 170 131 5555

Sidetracked wells 16 10 11 12 13 16 12 18 6 12 17 25 29 37 54 62 84 80 102 91 84 118 129 83 69 98 83 82 99 53 1605

5.1.3 Norway The drilling exposure data for Norway is based on the NPD Borehole list as published on the Internet (http://www.npd.no/engelsk/cwi/pbl/en/index.htm). NPD has from 2001 changed the well naming. This is also reflected in their borehole lists published on the Internet. The tables presenting number of drilled wells in earlier versions of this report have been based on the number of wellbores. A wellbore is now categorized as;   

Initial well bore Re-entry Sidetrack

Page: 44


Earlier another category named technical sidetrack also was included. This category is not used anymore. The practical effect is that the number of wells drilled has been reduced. The NPD wellbore categorizing can be downloaded from the NPD homepage. The number and type of development wells are presented in Table 5.3. Table 5.4 presents the exploration wells drilled in the Norwegian area alongside the total number of development wells and the type of well bore. Table 5.5 shows the number of Norwegian wells drilled within each main NCS area Table 5.3

Norwegian development wells drilled

Spud year

Oil

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

20 8 12 14 16 25 37 25 38 45 35 50 55 69 71 59 84 73 87 89 110 123 106 111 96 100 92 101 81 84 1916

Gas

Production Gas/- Other/Oil/conden ungas sate known

6 5 6 1 10 11 4 13 4 3 4 1 7 7 6 11 20 19 10 8 16 13 9 7 4 9 8 5 7 8 241

1 2 3 1

2

1 2 3 5 4 10 28

2 6 10 2 5 5 10 40

1 3 2 2 2 1

1 3 3 25

Total

Water

26 13 18 15 26 36 41 38 42 48 39 51 62 76 78 72 107 93 97 98 131 138 117 122 108 121 105 117 100 115 2250

1 3 6 7 10 7 9 12 16 19 12 15 15 25 19 9 5 14 17 14 15 15 14 10 8 9 15 15 17 353

Injection Other/Water/Gas unTotal gas known 2 2 2 3 2 5 3 9 1 8 2 12 2 9 1 10 1 13 3 19 2 21 1 13 1 16 3 18 4 29 3 1 23 5 3 17 10 1 1 17 8 1 23 3 6 26 10 2 26 4 2 2 23 6 2 2 25 2 6 3 25 4 14 2 1 11 5 3 2 19 1 1 2 19 4 6 2 27 1 5 23 92 37 23 505

Observation

1 8 11 13 14 20 26 19 25 29 39 26 18 16 18 25 17 11 25 361

All wells 28 16 23 24 34 48 50 48 55 67 60 65 86 105 120 109 144 136 139 149 186 200 168 165 138 150 149 153 138 163 3116


Table 5.4

Number of drilled wells and type of well bore in Norwegian offshore sector

Drilled year Initial 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Page: 45

10 15 13 10 13 20 12 11 8 5 9 11 10 7 2 10 8 8 6 6 4 5 2 6 4 3 8 9 6 8 249

Exploration wells Development Appraisal Wildcat Total Initial Multi- SideTotal lateral track developRe- Side- Total Initial Re- Side- Total exploration ment entry track entry track 1 11 26 5 31 42 27 0 1 28 1 16 24 3 27 43 16 0 0 16 1 1 15 35 2 37 52 21 0 2 23 2 12 30 30 42 21 0 3 24 3 16 33 3 1 37 53 31 0 3 34 1 21 30 2 32 53 47 0 1 48 2 1 15 22 5 1 28 43 35 0 15 50 3 1 15 24 3 27 42 36 0 12 48 2 3 13 18 18 31 46 0 9 55 4 2 11 21 3 24 35 47 0 20 67 4 2 15 25 6 31 46 43 0 17 60 7 3 21 33 3 36 57 52 0 13 65 5 15 27 2 1 30 45 65 0 21 86 4 11 19 4 1 24 35 75 0 30 105 3 1 6 17 3 1 21 27 78 1 41 120 1 4 15 22 3 25 40 73 0 36 109 1 2 11 20 1 21 32 92 1 51 144 1 4 13 33 4 5 42 55 81 1 54 136 2 2 10 15 3 18 28 90 3 46 139 1 1 8 12 1 3 16 24 94 1 54 149 2 6 18 3 21 27 108 10 68 186 2 4 11 24 3 1 28 39 91 19 90 200 2 3 7 11 1 3 15 22 74 18 76 168 2 2 10 12 2 2 16 26 59 32 74 165 4 8 10 10 18 60 29 49 138 2 5 9 9 14 56 33 61 150 1 9 14 1 4 19 28 57 37 55 149 4 13 19 19 32 52 38 63 153 9 15 37 4 41 56 43 37 58 138 14 22 40 1 3 44 66 49 34 80 163 53 74 376 680 64 33 777 1153 1719 294 1103 3116

Page: 46


Table 5.5 Norwegian drilled wells separated on main NCS area Development wells Exploration wells Spud Barents North Norwegian Barents North Norwegian year Total Total Sea Sea Sea Sea Sea Sea 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

1 8 1

10

28 16 23 24 34 48 50 48 55 67 60 65 84 94 107 104 132 119 113 117 155 167 150 145 115 115 122 134 119 135 2745

2 11 13 5 12 17 26 32 31 33 18 20 22 27 26 19 19 28 361

28 16 23 24 34 48 50 48 55 67 60 65 86 105 120 109 144 136 139 149 186 200 168 165 138 150 149 153 138 163 3116

2 3 4 6 7 8 4 5 4 4 1 3 3 2

4 4

3 6 3 8 84

39 38 43 29 39 29 22 23 21 28 35 46 37 25 22 32 24 36 21 13 12 21 17 20 12 6 13 20 32 48 803

1 2 5 7 7 16 17 14 6 3 10 8 5 8 5 8 8 19 7 11 11 14 5 6 6 5 9 9 16 18 266

42 43 52 42 53 53 43 42 31 35 46 57 45 35 27 40 32 55 28 24 27 39 22 26 18 14 28 32 56 66 1153

Total all wells 70 59 75 66 87 101 93 90 86 102 106 122 131 140 147 149 176 191 167 173 213 239 190 191 156 164 177 185 194 229 4269

5.1.4 The Netherlands The drilling exposure data for The Netherlands is based on information from the NL Oil and Gas Portal (http://www.nlog.nl/nl/activity/activity.html). The number of wells drilled in the Dutch Continental Shelf is presented in Table 5.6.


Table 5.6 YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Page: 47

Number of drilled wells on the Dutch Continental Shelf Exploration wells Exploration Appraisal Total 26 5 31 15 17 32 35 10 45 31 12 43 26 7 33 36 7 43 25 5 30 22 5 27 21 5 26 23 5 28 29 6 35 43 2 45 19 1 20 13 1 14 10 2 12 5 3 8 24 5 29 21 10 31 17 3 20 12 2 14 6 6 12 15 4 19 16 3 19 7 4 11 11 2 13 4 1 5 9 3 12 5 2 7 8 3 11 7 3 10 541 144 685

Development wells 7 5 20 15 24 35 15 13 21 17 14 18 15 17 10 16 6 13 13 6 9 12 13 13 6 8 16 12 13 11 413

Total all wells 38 37 65 58 57 78 45 40 47 45 49 63 35 31 22 24 35 44 33 20 21 31 32 24 19 13 28 19 24 21 1098

5.1.5 Canadian East Coast Table 5.7 shows the number of wells drilled on the Canadian East Coast. Before 1980 approximately 225 wells were drilled. (http://basin.gdr.nrcan.gc.ca/index_e.php). There has in addition been drilled approximately 160 well in the Northern areas all time. No detailed data has, however, been made available from this area. Some drilling activity is also carried out on the West Coast of Canada.

Page: 48


Table 5.7 Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Number of drilled wells on the Canadian East Coast

Wild cat Original Re-entry drilling 8 4 11 2 15 5 14 6 21 4 13 9 9 3 4 1 6 2 1 1 1 4

1 1 1 5 6 6 7 7 2 4 4 1 1 153

1

Exploration Delination Original Re-entry drilling 5 1 3 2 1 1 4 1 5 8 7 4 1 4 2 2 4

1 4 5 1 2

38

3 8 3 2

1 1

65

21

Development Total 18 18 22 25 30 37 17 11 14 2 1 4

1 1 2 9 12 6 8 9 2 7 13 4 3 1 277

Original Re-entry drilling

1 1

4 4 10 2 1 2 6 21 15 15 12 25 19 22 16 12 8 8 8 212

Total

Total

1 1

1 3 1 4 2 1 7 22 23 8 8 12 11 17 13 6 5 5 149

5 7 11 6 3 3 6 28 37 38 20 33 31 33 33 25 14 13 13 361

18 18 22 25 31 38 17 11 14 2 1 9 7 11 6 3 4 7 30 46 50 26 41 40 35 40 38 18 16 14 638


Page: 49

5.1.6 US Pacific OCS Table 5.8 shows the number of wells drilled on the in the US Pacific OCS area. The data stems from MMS Pacific Division. Table 5.8 Number of drilled wells in the US Pacific OCS area Year

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

*estimated

Expl. wells spudded

10 14 27 38 19 6 5 4 3 4

130

Dev. wells spudded

40 50 58 44 45 39 34 39 29 15 17 8 5 21 25 19 31 29 19 11 13 16 21 18 20 23 17 12 5 7* 730

Total

50 64 85 82 64 45 39 43 32 19 17 8 5 21 25 19 31 29 19 11 13 16 21 18 20 23 17 12 5 7 860

Page: 50


5.1.7 Australia Table 5.9 shows the number of wells drilled on the in Australian waters. The data from 1980 to 2005 stems from Geoscience Australia. Geoscience Australia is the national agency for geoscience research and geospatial information. The data from 2006 stems from Australia and APPEA (Australia Petroleum Production and Exploration Association Limited) Quarterly Drilling Reports. Table 5.9 Number of drilled wells in Australian waters Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Exploration Wildcat Appraisal Original Side Original Side Total Total hole track hole track 15 3 18 2 2 13 13 5 5 42 5 47 4 4 41 3 44 4 4 29 3 32 12 12 23 23 18 18 20 20 7 7 9 1 10 6 6 27 5 32 9 1 10 32 10 42 10 4 14 46 8 54 19 6 25 34 5 39 6 4 10 28 3 31 13 2 15 36 1 37 14 3 17 28 6 34 20 1 21 32 2 34 23 2 25 34 9 43 15 15 39 1 40 19 2 21 61 5 66 10 1 11 45 5 50 9 9 60 10 70 4 4 48 3 51 10 10 31 4 35 16 3 19 44 5 49 16 16 36 36 14 4 18 45 3 48 14 1 15 32 3 35 10 1 11 37 37 24 2 26 49 5 54 16 16 48 48 20 1 21 1064 108 1172 369 38 407

Development Total Original hole 20 6 18 16 51 12 48 29 44 42 41 18 27 19 16 21 42 13 56 26 79 18 49 17 46 14 54 18 55 28 59 32 58 34 61 81 77 41 59 35 74 22 61 24 54 26 65 32 54 41 63 33 46 27 63 27 70 45 69 43 1579 840

Side track 1

1

1 6 5 1 3 6 8 4 14 8 3 3 7 8 12 7 8 2 1 8 3 120

Total 7 16 12 29 43 18 19 21 13 27 24 22 15 21 34 40 38 95 49 38 25 31 34 44 48 41 29 28 53 46 960

Total all wells 27 34 63 77 87 59 46 37 55 83 103 71 61 75 89 99 96 156 126 97 99 92 88 109 102 104 75 91 123 115 2539

Government of Western Australian, Department of Mines and Petroleum, reports number of wells drilled in the Western Australia (https://wapims.doir.wa.gov.au/dp/index.jsp). Approximately 50% of the Australian offshore wells drilled since 1980 have been drilled in Western Australia. Table 5.10 shows the number of wells drilled on the in the Western Australian waters.


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Table 5.10 Number of drilled wells in Western Australian waters Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Development well

3 4 4 5 4 2 6 14 7 4 12 17 10 18 13 5 10 14 16 9 8 21 15 24 19 33 21 318

Extension well 1 3 1 1 6 9 3 3 2 4 9 4 7 6 14 9 8 14 7 5 4 5 13 17 17 16 14 14 19 22 257

New Field Wildcat 11 3 20 21 14 9 9 3 8 10 14 20 15 20 10 19 21 24 34 37 44 33 24 39 22 28 29 40 22 34 637

New Water Injector Pool well Wildcat

2 3 2

2

6 5 4 4 4 28

Total 12 6 21 25 24 22 17 10 12 20 37 31 26 38 41 38 49 51 49 54 62 54 46 64 60 65 72 77 78 81 1242

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5.1.8 Denmark Table 5.11 shows the number of wells drilled on the offshore Denmark. The data stems from The Danish Energy Authority (http://www.ens.dk/EN-US/OILANDGAS/REPORTOILGAS/Sider/Forside.aspx) Table 5.11 Number of drilled wells offshore Denmark Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Exploration and appraisal 1 4 5 14 8 14 7 8 3 4 2 6 11 2 2 1 4 8 6 9 12 15 9 8 10 2 6 4 7 2 194

Development 7 9 18 13 15 18 3 3 13 9 15 14 15 30 15 16 13 15 23 17 17 29 27 24 23 10 20 20 15 14 480

Sum 8 13 23 27 23 32 10 11 16 13 17 20 26 32 17 17 17 23 29 26 29 44 36 32 33 12 26 24 22 16 674

5.1.9 Compiled Drilling Exposure Data Table 5.12 below is based on Table 5.1 to Table 5.4, and shows compiled offshore drilled wells in Norway, UK and US GoM OCS.


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Table 5.13 is based on Table 5.6 to Table 5.11 and shows compiled offshore drilled wells in the Netherlands, Canada East Coast, Australia, US Pacific OCS, and Denmark. Table 5.12 An overview of offshore drilled wells in Norway, UK, and US GoM OCS Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

US GoM OCS Expl. Dev. 393 380 421 417 625 550 286 433 582 482 521 347 228 361 438 395 463 545 496 370 442 411 309 354 363 355 413 300 267 147

904 965 912 828 816 745 483 496 481 558 621 475 372 624 661 765 775 905 646 669 938 851 633 539 553 457 359 316 299 173

12094

18819

UK Expl. Dev. 54 142 73 146 116 133 135 102 191 123 154 149 118 99 143 140 172 175 177 154 224 124 181 150 132 170 111 169 100 208 94 266 113 283 95 255 78 289 35 237 61 225 59 286 45 260 45 207 64 167 78 228 70 202 111 165 105 170 64 131 3198 5555

Norway Expl. Dev. 42 28 43 16 52 23 42 24 53 34 53 48 43 50 42 48 31 55 35 67 46 60 57 65 45 86 35 105 27 120 40 109 32 144 55 136 28 139 24 149 27 186 39 200 22 168 26 165 18 138 14 150 28 149 32 153 56 138 66 163 1153 3116

Total Expl. Dev. 483 1074 496 1127 589 1068 594 954 869 973 757 942 447 632 618 684 785 711 694 779 791 805 585 690 405 628 507 898 565 989 529 1140 608 1202 695 1296 602 1074 429 1055 530 1349 509 1337 376 1061 425 911 445 858 447 835 511 710 443 634 428 607 277 467 16445 27490

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Table 5.13 An overview of offshore drilled wells in Canada East Coast, the Netherlands, Australia, US Pacific OCS, and Denmark Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Dutch Canada E. Coast Australia Expl. Dev. Expl. Dev. Expl. Dev. 18 31 7 20 7 18 32 5 18 16 22 45 20 51 12 25 43 15 48 29 30 1 33 24 44 43 37 1 43 35 41 18 17 30 15 27 19 11 27 13 16 21 14 26 21 42 13 2 28 17 56 27 1 35 14 79 24 4 5 45 18 49 22 7 20 15 46 15 11 14 17 54 21 6 12 10 55 34 3 8 16 59 40 1 3 29 6 58 38 1 6 31 13 61 95 2 28 20 13 77 49 9 37 14 6 59 38 12 38 12 9 74 25 6 20 19 12 61 31 8 33 19 13 54 34 9 31 11 13 65 44 2 33 13 6 54 48 7 33 5 8 63 41 13 25 12 16 46 29 4 14 63 28 7 12 11 13 3 13 70 53 10 11 1 13 69 46 685 413 277 361 1579 960

US Pacific OCS Expl. Dev. 10 40 14 50 27 58 38 44 19 45 6 39 5 34 4 39 3 29 4 15 17 8 5 21 25 19 31 29 19 11 13 16 21 18 20 23 17 12 5 7 130 730

Denmark Expl. Dev. 1 7 4 9 5 18 14 13 8 15 14 18 7 3 8 3 3 13 4 9 2 15 6 14 11 15 2 30 2 15 1 16 4 13 8 15 6 23 9 17 12 17 15 29 9 27 8 24 10 23 2 10 6 20 4 20 7 15 2 14 194 480

Total Expl. Dev. 80 61 86 80 150 108 168 101 134 128 141 111 86 71 66 76 88 76 94 68 117 70 104 67 77 57 70 100 69 90 68 94 92 91 101 158 105 132 91 109 110 102 101 108 90 128 93 130 79 130 77 115 77 107 78 86 91 99 82 91 2865 2944

5.2 Production Exposure Data 5.2.1 US GoM OCS The production exposure data for US GoM OCS is shown in Table 5.14. The data is based on MMS Ogor A files from 1986 – 2009 (/1/). These files list the well individual activity for each month. It was selected to use the data from December each year. All the production wells listed with production in December are counted as active wells.


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Table 5.14 Producers in the US GoM OCS area. Year

Oil production Flowing Gas lift Total

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

NA NA NA NA NA 2 695 2 523 2 461 2 382 2 230 2 283 2 206 2 195 2 216 2 228 2 189 2 016 2 002 1 936 1 712 1 723 1 523 1 327 1 160 1 060 719 990 1 084 744 993 (44597)

NA NA NA NA NA 1 101 1 206 1 284 1 361 1 270 1 246 1 339 1 311 1 326 1 286 1 258 1 424 1 434 1 364 1 538 1 590 1 716 1 782 1 926 1 539 786 1 333 1 607 1116 1436 (34579)

3 165 3 260 3 412 3 539 3 688 3 796 3 729 3 745 3 743 3 500 3 529 3 545 3 506 3 542 3 514 3 447 3 440 3 436 3 300 3 250 3 313 3 239 3 109 3 086 2 599 1 505 2 323 2 691 1 860 2 429 96 240

Gas production

Total production

3 023 3 106 3 223 3 243 3 355 3 229 3 239 3 311 3 364 3 429 3 682 3 580 3 346 3 458 3 483 3 430 3 444 3 467 3 315 3 282 3 308 3 217 2 993 3 043 2 804 1 977 2 457 2 597 1560 2005 92 970

6 188 6 366 6 635 6 782 7 043 7 025 6 968 7 056 7 107 6 929 7 211 7 125 6 852 7 000 6 997 6 877 6 884 6 903 6 615 6 532 6 621 6 456 6 102 6 129 5 403 3 482 4 780 5 288 3 420 4 434 189 210

Water injection (active or inactive) 107 121 143 187 219 327 327 320 327 311 320 323 325 315 307 305 294 270 261 248 246 225 207 205 199 195 195 186 185 163 7 363

Gas injection (active or inactive)

100 88 105 100 91 89 80 80 72 72 70 61 52 51 50 45 34 27 30 35 15 21 16 13 10 1 407

5.2.2 United Kingdom The production/injection exposure data for UK is shown in Table 5.15. The figures are valid for the number of wells that have been in service for the listed year. The data from before 1991 is based on well data systematically collected in the SINTEF study "Reliability of Well Completion Equipment" SINTEF report STF 75 F92019, "Development of the Oil and Gas resources of the United Kingdom" 1980, 1992 and 1993 edition, North Sea Field Development Guide, 4th edition, OPL and coarse assumptions where well data are missing. The data is therefore not exactly correct. The data from 1991 to 1999 is based on statistics from Health & Safety Executive (HSE). HSE has now stopped reporting this information on an individual well basis. They now report the production data for each field. Deal Data Registry for UK Offshore Oil & Gas (http://www.ukdeal.co.uk/) reports individual well information, but the quality of information is variable. During the work with the 2011 release an updated version of the data was downloaded. The data was analysed with the objective to update the production exposure data for the UK. The quality was however low and the data cannot be used for our purpose. The main problems for 20% of the wells the detailed data is not released, further that many wells seems to be active producers, but the platform has been decommissioned, i.e. they should have been categorised as plugged and abandoned. It is believed that many of the wells the database indicates as active are plugged and abandoned.

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The Department of Industry was contacted in October 2004 and in January 2007 but they are referring to Deal that now has the responsibility of reporting on an individual well level. The last year these data was collected by the Department was in 1999. All they could suggest was that the oil companies that operate the field or well could be approached and requested for data. This will be a too time-consuming task. The exposure data for 2000 - 2009 has therefore been estimated based on the production rates per year and the number of active wells in 1999. It is assumed that the coarse formula estimates a too low number of wells in production, because it is likely that the average production from each well declines every year. Table 5.15 Producers and injectors in the UK waters Year

Production wells Injection wells Total wells Oil Gas/con Total Gas Water Total 1980 291 249 540 10 92 102 642 1981 318 252 570 11 104 115 685 1982 349 256 605 13 116 129 734 1983 399 258 657 17 140 157 814 1984 448 266 714 22 170 192 906 1985 456 298 754 21 194 215 969 1986 525 322 847 27 206 233 1080 1987 558 355 913 29 218 247 1160 1988 550 390 940 35 217 252 1192 1989 575 419 994 35 227 262 1256 1990 599 474 1073 37 249 286 1359 1991 844 344 1188 68 350 418 1606 1992 918 502 1420 68 363 431 1851 1993 968 549 1517 66 369 435 1952 1994 1041 598 1639 62 399 461 2100 1995 1131 703 1834 60 413 473 2307 1996 1215 695 1910 69 428 497 2407 1997 1252 725 1977 68 434 502 2479 1998 1160 713 1873 58 369 427 2300 1999 1118 678 1796 37 345 382 2178 2000* 1027 742 1769 37 345 382 2151 2001* 953 723 1676 37 345 382 2058 2002* 943 706 1649 37 345 382 2031 2003* 867 699 1566 37 345 382 1948 2004* 777 656 1432 37 345 382 1814 2005* 685 604 1289 37 345 382 1671 2006* 622 548 1170 37 345 382 1552 2007* 624 497 1122 37 345 382 1504 2008* 584 484 1068 37 345 382 1450 2009* 560 407 967 37 345 382 1349 Total 22357 15114 37471 1183 8853 10036 47507 * Data are no longer available from HSE. The number of wells in production has been assumed to be relative to the UK annual oil and gas production. Injection wells remain unchanged.

5.2.3 Norway Table 5.16 shows the production/injection exposure data for the Norwegian waters. The

figures are valid for the number of wells in service per December 31 the listed year. The data is from the NPD Annual reports 1980 – 1999, and for the year 1999 and later the data stems from the NPD Borehole list as published on the Internet (http://www.npd.no/engelsk/cwi/pbl/en/index.htm).


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Table 5.16 Production/injection exposure data for the Norwegian waters Year

Producers Injection/- Suspended/Total closed Gas Other/Total observation in/plugged unknown 1980 84 29 47 160 8 23 191 1981 89 34 48 171 11 26 208 1982 114 35 47 196 13 24 233 1983 113 32 53 198 17 37 252 1984 128 31 61 220 23 42 285 1985 145 29 61 235 32 60 327 1986 160 38 64 262 41 71 374 1987 176 41 60 277 41 102 420 1988 201 43 65 309 59 110 478 1989 235 38 48 321 74 151 546 1990 258 33 31 322 88 191 601 1991 285 31 33 349 109 207 665 1992 324 29 30 383 116 247 746 1993 371 31 32 434 136 280 850 1994 385 32 34 451 163 357 971 1995 434 35 24 493 180 409 1 082 1996 494 33 53 580 189 459 1 228 1997 519 31 62 612 194 544 1 350 1998 535 25 64 624 211 649 1 484 1999 746 25 83 854 259 549 1 662 2000 787 25 85 897 259 701 1 857 2001 813 21 95 929 266 833 2 028 2002 820 32 101 953 257 1 030 2 240 2003 849 30 97 976 261 1 111 2 348 2004 848 32 97 7 984 264 1 244 2 492 2005 831 3 120 7 961 269 1 411 2 641 2006 863 9 124 11 1 006 278 1 576 2 860 2007 886 12 129 10 1 038 282 1 644 2 964 2008 910 15 135 10 1 070 285 1 712 3 067 2009 1078 22 143 8 317 1 639 1251 3 207 Total 14 481 856 2 126 53 17 516 4 702 17 439 39 657 Note! NPD stopped listing the number of wells in production in the annual reports in 1999. From 1999 the no. of oil producers seems high, and the no. of closed in/suspended wells seems low, compared to the earlier years. Oil

Cond

5.2.4 US Pacific OCS The production exposure data for US Pacific OCS is shown in Table 5.17. The data is based on MMS Ogor A files (/1/). These files list the well individual activity for each month. It was selected to use the data from December each year. All the production wells listed with production in December are counted as active wells.

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Table 5.17 Producers in the US Pacific OCS area. Year 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Oil production Flowing Gas lift Total 262 79 341 280 81 361 284 83 367 293 79 372 305 72 377 321 65 386 340 49 389 337 54 391 322 79 401 300 104 404 287 118 405 289 107 396 285 100 385 264 100 364 264 103 367 255 105 360 257 120 377 256 122 378 251 121 372 239 127 366 251 121 372 241 141 382 252 130 382

256

125

6691

2385

381 9076

Gas production 20 20 16 13 19 20 19 20 17 17 13 17 19 18 16 17 16 15 15 16 15 8 9

Total Water injection Gas injection production (active or inactive) (active or inactive) 361 79 6 381 84 6 383 88 4 385 83 4 396 83 4 406 84 5 408 84 4 411 88 4 418 93 4 421 94 6 418 84 7 413 87 9 404 93 13 382 93 14 383 83 15 377 74 11 393 97 11 393 98 12 387 100 14 382 104 13 387 109 12 390 109 14 391 117 16

10 385

391 9461

127 2235

15 223

5.2.5 Compiled Production Exposure Data Table 5.18 is based on Table 5.14, Table 5.15 and Table 5.16, and shows overall production data for the Norway, UK and US GoM OCS. The figures are valid for number of wells in service per December the listed year. Note that it has been selected not to include data from the US Pacific OCS.


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Table 5.18 Overall production data for the US GoM OCS, UK, and Norway based on Table 5.14, Table 5.15 and Table 5.16. Year

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

US GoM OCS United Kingdom Norway Production wells InjectProduction wells InjectProduction wells ion ion Oil Gas/- Total Oil Gas/- Total Oil Gas/- Total wells wells cond cond cond 3 165 3 023 6 188 107 291 249 540 102 84 76 160 3 260 3 106 6 366 121 318 252 570 115 89 82 171 3 412 3 223 6 635 143 349 256 605 129 114 82 196 3 539 3 243 6 782 187 399 258 657 157 113 85 198 3 688 3 355 7 043 219 448 266 714 192 128 92 220 3 796 3 229 7 025 427 456 298 754 215 145 90 235 3 729 3 239 6 968 415 525 322 847 233 160 102 262 3 745 3 311 7 056 425 558 355 913 247 176 101 277 3 743 3 364 7 107 427 550 390 940 252 201 108 309 3 500 3 429 6 929 402 575 419 994 262 235 86 321 3 529 3 682 7 211 409 599 474 1073 286 258 64 322 3 545 3 580 7 125 403 844 344 1188 418 285 64 349 3 506 3 346 6 852 405 918 502 1420 431 324 59 383 3 542 3 458 7 000 387 968 549 1517 435 371 63 434 3 514 3 483 6 997 379 1041 598 1639 461 385 66 451 3 447 3 430 6 877 375 1131 703 1834 473 434 59 493 3 440 3 444 6 884 355 1215 695 1910 497 494 86 580 3 436 3 467 6 903 322 1252 725 1977 502 519 93 612 3 300 3 315 6 615 312 1160 713 1873 427 535 89 624 3 250 3 282 6 532 298 1118 678 1796 382 746 108 854 3 313 3 308 6 621 291 1027 742 1769 382 787 110 897 3 239 3 217 6 456 259 953 723 1676 382 813 116 929 3 109 2 993 6 102 234 943 706 1649 382 820 133 953 3 086 3 043 6 129 235 867 699 1566 382 849 127 976 2 599 2 804 5 403 234 777 656 1432 382 848 129 977 1 505 1 977 3 482 210 685 604 1289 382 831 123 954 2 323 2 457 4 780 216 622 548 1170 382 863 133 996 2 691 2 597 5 288 202 624 497 1122 382 886 141 1027 1 860 1560 3 420 198 584 484 1068 382 910 150 1060 2 429 2005 4 434 173 560 407 967 382 1078 165 1243 96 240 92 970 189 210 8 770 22 357 15 114 37 471 10 036 14 481 2 982 17463

Total InjeProduction wells ction Oil Gas/- Total wells cond 8 3 540 3 348 6 888 11 3 667 3 440 7 107 13 3 875 3 561 7 436 17 4 051 3 586 7 637 23 4 264 3 713 7 977 32 4 397 3 617 8 014 41 4 414 3 663 8 077 41 4 479 3 767 8 246 59 4 494 3 862 8 356 74 4 310 3 934 8 244 88 4 386 4 220 8 606 109 4 674 3 988 8 662 116 4 748 3 907 8 655 136 4 881 4 070 8 951 163 4 940 4 147 9 087 180 5 012 4 192 9 204 189 5 149 4 225 9 374 194 5 207 4 285 9 492 211 4 995 4 117 9 112 259 5 114 4 068 9 182 259 5 127 4 160 9 287 266 5 005 4 056 9 061 257 4 872 3 832 8 704 261 4 802 3 869 8 671 264 4 224 3 589 7 812 269 3 021 2 704 5 725 278 3 808 3 138 6 946 282 4 201 3 235 7 437 285 3 354 2 194 5 548 317 4 067 2 577 6 644 4 702 133 078 111 066 244 144

Injection wells 217 247 285 361 434 674 689 713 738 738 783 930 952 958 1 003 1 028 1 041 1 018 950 939 932 907 873 878 880 861 876 866 865 872 23 508

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6. Various Exposure Data This section includes various exposure data. Limitations related to the exposure data are explained where the data is presented. The exposure data presented in this section covers the following: 1. Well Depth Related Exposure Data  US GoM OCS Wells  Norwegian Wells 2. Water depth related drilling exposure data  US GoM OCS Wells  UK Wells  Norwegian Wells 3. Shut-in Wellhead Pressure Related exposure data  US GoM OCS Drilling Wells  Norwegian Drilling Wells  US Wells in Production 4. Gas Oil Ratio Related Exposure Data 5. Workover Frequency Exposure Data 6. Wireline Frequency Exposure Data 7. Coiled Tubing and Snubbing Exposure Data Data from the US Mineral Management Service (MMS) and NPD has formed the main input to this section.

6.1 Well Depth Related Exposure Data 6.1.1 US GoM OCS Wells The information in this sub-section stems from the BOEM Borehole file (/1/). The drilling vertical depths for the exploration and development wells in the US GoM OCS are presented in Figure 6.1. Approximately 0.8 % of the exploration wells and 1.3% of the development wells were not listed with a True Vertical Depth (TVD). These wells are not included in Figure 6.1. The deepest exploration well has been drilled to a depth of 10411 m TVD, while the deepest development well has been drilled to 9881 mTVD.

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Well depth, US GoM OCS (1980 - 2009) 11000

10000

TVD (m) development wells TVD (m) exploration wells

9000 8000

Meters (TVD)

7000 6000 5000 4000

3000 2000

1000 0

0%

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

Percentage Distribution

Figure 6.1 All exploration and development wells drilled in 1980 – 2004 listed with true vertical depth

6.1.2 Norwegian Wells For Norwegian wells True Vertical Depth (TVD) of wells is available for neither exploration nor development wells drilled before 1995. Measured Depths (MD) is, however, available. For most exploration wells the MD is a good approximation for the TVD. For development wells the MD will not be a good approximation. Figure 6.2 shows the true vertical depth for production wells drilled in the period 1995 – mid 1998. Figure 6.3 shows the measured depth for development wells drilled in the period 1980 – 2004. Figure 6.4 shows the measured depth for exploration wells drilled in the period 1980 - 2004. The data shown in Figure 6.2 stems from the NPD Daily Drilling Report system, Figure 6.3 and Figure 6.4 stems from the NPD well files as published on the Internet.


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True vertical depth, production wells, (mainly drilled in 95 - mid 98) 5000 4500 4000

TVD (m RKB)

3500 3000 2500 2000 1500 1000 500 0 0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Percentage distribution (total 478 wells)

Figure 6.2 True Vertical Depth, Norwegian production wells

Development wells, Norwegian waters (1980 - 2004) 12000

Measured depth (m)

10000 8000 6000 4000 2000 0 0%

10%

20%

30%

40%

50%

60%

Percentage distribution

Figure 6.3 Measured depth for development wells 1980 – 2004

70%

80%

90%

100%

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Exploration wells, Norwegian waters (1980 - 2004) 9000 8000

Measured depth

7000 6000 5000 4000 3000 2000 1000 0 0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Percentage distribution

Figure 6.4 Measured depth, Norwegian exploration wells 1980 – 2004.

6.2 Water Depth Related Drilling Exposure Data The past years some deepwater blowouts have occurred. This section presents the water related drilling exposure data. Table 6.1 and

Table 6.2 present the water depth specific no. of exploration and development wells drilled in the US GoM OCS.


Table 6.1 Spud year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Exploration wells drilled in the US GoM OCS vs. water depth (/1/)

Number of wells drilled within water depth range (m) <50 50-100 100-200 200-400 400-600 600-1000 1000-1500 1500-2000 2000- 2500 2500- 3000 >3000 232 126 19 14 1 1 220 113 29 9 9 287 94 24 9 7 277 85 29 17 8 1 362 136 41 36 32 16 2 275 118 61 47 27 22 133 56 39 20 17 21 230 96 51 18 12 16 6 2 2 314 104 66 34 25 31 5 1 2 253 107 48 20 22 26 5 1 286 112 51 15 13 32 9 2 1 182 91 25 19 5 18 6 1 103 91 14 11 4 3 2 194 97 39 12 11 6 2 247 107 26 15 6 26 9 2 194 99 34 22 14 22 8 2 223 112 28 22 10 32 29 5 2 239 127 43 27 20 27 53 5 4 228 120 23 16 30 33 39 2 4 147 97 19 7 14 27 26 26 7 216 91 18 9 12 34 34 9 17 2 165 58 26 18 7 39 55 24 16 3 149 48 8 7 12 23 25 17 17 3 176 62 17 9 8 19 29 21 6 6 1 174 45 18 19 8 22 27 21 17 12 179 47 15 9 7 27 38 17 10 6 216 48 15 11 11 30 40 22 19 1 123 56 6 3 8 41 28 21 13 1 119 26 12 5 2 23 37 22 16 3 2 52 7 3 2 1 18 25 20 19 6195 2576 847 482 363 635 538 244 173 37 3

Table 6.2 Spud year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

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Total 393 380 421 417 625 550 286 433 582 482 521 347 228 361 438 395 463 545 495 370 442 411 309 354 363 355 413 300 267 147 12093

Development wells drilled in the US GoM OCS vs. water depth (/1/)

<50 419 535 500 487 474 349 196 278 224 264 275 208 188 327 336 364 380 442 323 307 446 417 303 307 329 244 202 153 154 67 9498

Number of wells drilled within water depth range (m) 50-100 100-200 200-400 400-600 600-1000 1000-1500 1500-2000 2000- 2500 >2500 371 73 41 315 81 34 328 64 20 259 61 21 261 62 19 294 63 37 2 190 63 33 1 127 47 40 4 152 58 31 14 2 165 64 45 18 2 186 108 24 27 1 148 94 14 7 4 102 31 41 1 9 212 43 36 5 1 233 49 34 5 4 277 67 30 19 6 1 1 249 79 36 7 22 2 310 68 25 27 24 6 1 2 185 62 36 11 11 16 1 1 219 45 29 11 27 25 5 1 302 48 42 8 22 60 9 1 225 69 35 17 23 36 23 6 146 21 34 9 24 76 11 9 90 33 20 8 18 48 12 1 2 105 33 15 8 15 13 16 19 135 21 12 14 19 10 1 1 73 17 9 8 6 36 6 2 71 28 3 6 13 10 7 25 73 41 3 10 15 3 32 19 3 12 22 6 11 1 5835 1612 796 242 274 376 101 78 7

Total 904 965 912 828 816 745 483 496 481 558 621 475 372 624 661 765 775 905 646 669 938 851 633 539 553 457 359 316 299 173 18819

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Table 6.3 and Table 6.4 present the water depth specific no. of exploration and development wells drilled in Norwegian waters. Table 6.3 Exploration wells drilled in UK waters vs. water depth (http://www.ukdeal.co.uk/) Number of wells drilled within water depth range (m)* Total 50-100 100-200 200-400 400-600 600–1000 1000–1500 1500–2000 Unknown 1980 15 49 2 1 3 1 71 1981 2 28 58 2 2 92 1982 23 41 64 2 1 131 1983 34 39 74 2 149 1984 47 65 86 4 6 1 1 210 1985 41 43 81 4 7 176 1986 30 39 61 2 132 1987 43 39 68 2 152 1988 58 46 86 2 192 1989 58 44 95 2 199 1990 60 50 129 2 3 244 1991 48 57 104 1 3 213 1992 29 45 67 1 5 147 1993 31 35 51 6 123 1994 36 25 27 3 11 1 3 106 1995 25 32 33 5 9 4 5 113 1996 28 34 53 3 2 3 1 124 1997 23 23 50 5 1 102 1998 16 24 39 3 2 1 85 1999 6 12 25 1 1 1 46 2000 11 10 29 1 1 3 2 1 58 2001 10 20 46 2 1 79 2002 10 13 17 1 1 2 44 2003 12 14 14 3 1 44 2004 12 15 40 1 3 1 3 75 2005 17 19 51 87 2006 19 31 38 2 2 92 Total 729 858 1535 43 69 25 14 3 10 3286 * Note, the no. of wells is 13% higher than in Table 5.2, page 43 because different sources of information have been used. Spud year

< 50

Table 6.4 Development wells drilled in UK waters vs. water depth (http://www.ukdeal.co.uk/) Number of wells drilled within water depth range (m)* Total < 50 50-100 100-200 200-400 400-600 600–1000 1000–1500 1500–2000 Unknown 1980 9 11 130 150 1981 12 12 126 150 1982 14 19 105 138 1983 15 15 75 105 1984 26 20 81 2 129 1985 41 20 93 154 1986 35 3 61 99 1987 41 20 81 142 1988 57 33 87 177 1989 59 13 83 1 1 157 1990 41 14 69 2 1 127 1991 48 38 70 1 157 1992 58 32 79 4 173 1993 35 26 105 3 169 1994 40 39 114 1 2 16 212 1995 48 43 146 1 5 21 264 1996 30 68 168 5 12 283 1997 21 56 179 3 3 262 1998 33 67 167 10 7 284 1999 38 55 125 2 12 232 2000 33 37 148 6 4 228 2001 32 41 195 3 9 280 2002 35 51 171 7 6 270 2003 40 44 111 3 8 1 207 2004 13 44 105 2 3 167 2005 33 55 135 4 9 236 2006 17 59 124 7 207 Total 904 935 3133 57 90 3 37 5159 * Note, the no. of wells is 6% higher than in Table 5.2, page 43 because different sources of information have been used. Spud year


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Table 6.5 and Table 6.6 present the water depth specific no. of exploration and development wells drilled in Norwegian waters. Table 6.5

Exploration wells drilled in Norwegian waters vs. water depth

Spud year <50 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Table 6.6

1

1

Development wells drilled in Norwegian waters vs. water depth

Spud year <50 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total

Number of wells drilled within water depth range (m) 50–100 100-200 200-400 400-600 600-1000 1000-1500 1500-2000 9 13 20 8 22 13 18 19 15 6 14 22 12 12 29 3 16 34 5 13 24 1 4 16 19 3 9 7 13 2 11 14 9 1 19 12 15 21 13 22 1 10 11 23 1 10 11 14 4 12 10 7 24 9 7 5 19 1 13 19 19 1 1 2 4 11 10 3 3 5 15 1 2 7 15 2 1 1 16 19 2 1 2 10 7 1 1 1 6 11 7 2 1 8 9 1 2 9 1 1 5 6 15 1 1 8 10 11 2 1 12 11 23 5 1 4 5 30 26 2 1 2 226 380 495 24 10 15 2

1

1

Number of wells drilled within water depth range (m) 50 - 100 100 - 200 200 - 400 400 - 600 600 - 1000 21 7 10 6 5 18 9 15 13 21 12 36 25 25 25 23 35 20 34 30 3 27 25 8 31 24 10 25 50 11 31 48 26 38 40 42 26 43 40 27 61 56 29 43 64 28 47 64 16 60 72 1 19 79 88 26 89 85 27 73 67 1 30 66 69 30 51 56 39 43 68 39 55 48 6 30 66 55 2 33 51 50 4 45 52 63 3 785 1267 1045 2 15

Total 1000 - 1500

1

1

28 16 23 24 34 48 50 48 55 67 60 65 86 105 120 109 144 136 139 149 186 200 168 165 138 150 149 153 138 163 3116

Total 42 43 52 42 53 53 43 42 31 35 46 57 45 35 27 40 32 55 28 24 27 39 22 26 18 14 28 32 56 66 1153

Page: 68


6.3 Drilling installation type vs. Well type and Water depth Exposure data related to type of drilling installation type used have not been reported in the previous years because it has not been practical to establish this data set. However in 2004 US MMS/Boemre/Boeem started to publish APDs (Application for Permit to Drill) as a part of their public E-well reporting. In these applications the drilling installation types are listed. This information has been combined with the BOEM Borehole file (/1/) to establish an overview of the drilling vessel types used vs. the water depth and main well type. Table 6.7 shows the drilling installation type vs. well type and water depth (US GoM OCS, 2005 – 2009). Table 6.7 Drilling installation type vs. Well type and Water depth (US GoM OCS, 2005 – 2009) Well type and drilling installation type

50 100

<50

Water depth grouped (m) 100 - 200 - 400 - 600 - 1000 - 1500 - 2000 - 2500 >3000 Total 200 400 600 1000 1500 2000 2500 3000

Development wells Barge Dp semisubmersible Drillship Jackup Platform Semisubmersible Submersible Total development Exploration wells Barge Dp semisubmersible Drillship Jackup Platform Semisubmersible Submersible Total exploration Total all

2

679 7 25 713

269 62

331

2 5

5 21

3 9

2 16 36 964 250 86 25 1379

6 1

16 101 1

14 4

15 10

21 14

28 22

2 3

29

3

118

18

25

42

76

17

35

4

3 5

37 28

44 23

24 22

1 8

1 29

29

2

24

70 607

169

36

21

26

124

151

97

75

11

24 111 86 682 42 304 70 2 1319

1320

500

154

39

51

166

227

114

110

15

2 2698

512 1

155 14

15 7 14

21

2 24

7 109

10 76

2

It should be noted that for the years 2007 - 2009, nearly all wells drilled are included. For 2005 and 2006 some wells are missing. NPD are presently (autumn 2011) in the progress of launching new fact pages. The well files in the fact pages includes a column specifying the drilling installation type. Table 6.8shows the drilling installation type vs. well type and water depth (Norway NCS, 1980 – 2009).


Page: 69

Table 6.8 Drilling installation type vs. Well type and Water depth (Norway NCS, 1980 – 2009) Well type and drilling installation type

50 100

<50

100 200

Water depth grouped (m) 200 400 600 1000 400 600 1000 1500

> 1500

Total

Development wells Condeep Drillship Jacket Jack-up Semisubmersible TLP Total development Exploration wells Condeep Drillship Jacket Jack-up Semisubmersible Total exploration Total all

34

458

120 24

1

612 25 1003 288 1199 123 3250

1

490 245 45

512 43 299

814

1312

1

2 7

1

1

5 60 165 231

7 1 14 9 353 384

487 496

24 25

10 10

13 15

2 2

10 11 19 70 1054 1164

2

1045

1696

1591

27

35

16

2

4414

1

1

852 123 1095

2

1

2

25

1

2

6.4 Shut-in Wellhead Pressure Related Exposure Data All data for the US GoM OCS wells stems from (/1/). Only data for wells that are completed as producers are included. For the Norwegian wells the main source of information has been a list of HPHT wells from NPD combined with the NPD Borehole list. For the UK wells no pressure related data is presented. 6.4.1 US GoM OCS Drilling Wells The shut-in wellhead pressure exposure data for drilling wells (both development and exploration wells) are all based on the first production well test carried out on the well. In US GoM OCS many exploration wells are completed as producers (see Table 5.1). It should also be noted that many development wells are not completed as producers, because they are dry. Since the shut-in wellhead pressures have been recorded more frequent the last 5 to 10 years than the previous years it was selected to only include data from wells that have been spudded after January 1988 Development drilling There were in total 1417 development wells listed with a shut-in wellhead pressure on the first well test after completion.

Page: 70


In Figure 6.5 the development wells shut-in wellhead pressures have been plotted against the well depth.

Development wells Shut-in pressure v.s. well depth, sorted 24000

Well depth (feet)/Shut-in pressure (psi)

22000 20000 18000 16000 14000 12000 10000 8000 6000 4000 2000 0

0

10

20

30

40

50

60

70

80

90

Cumulative percent Shut-in test pressure (psi)

True vertical depth (ft)

Expon. (True vertical depth (ft))

Figure 6.5 Development wells shut-in wellhead pressures plotted against well-depth

Exploration drilling There were in total 508 exploration wells listed with a shut-in wellhead pressure on the first well test after completion. In Figure 6.6 the exploration wells shut-in wellhead pressures have been plotted against the well depth.


Page: 71

Exploration wells Shut-in pressure v.s. well depth, sorted 24000

Well depth (feet)/Shut-in pressure (psi)

22000 20000 18000 16000 14000 12000 10000 8000 6000 4000 2000 0

0

20

40

60

80

100

Cumulative percent Shut-in test pressure (psi)

True vertical depth (ft)

Expon. (True vertical depth (ft))

Figure 6.6 Exploration wells shut-in wellhead pressures plotted against well depth

When looking at Figure 6.6 it is important to note that the number of wells drilled is based on only the exploration wells that have been completed as producers and listed with a well test with a positive pressure. If looking at the Mobile area, 33 exploration wells have been drilled to more than 20000 feet (6100 meters) in the period 1980 - 1996. These wells are likely all HPHT (more than 10000 psi) wells. In the Destin Dome Blocks six wells have been drilled in the same formation as the Mobile wells. In the Pensacola one well has been drilled. In addition 401 exploratory wells have a well depth between 16000 – 20000 feet. By reviewing the test pressures for development wells drilled in the same block and evaluating shut-in test pressure and the well spud dates, at least 57 of these were likely to be HPHT wells (close to 10000 psi or above). Further, some of the wells drilled to less than 16000 feet have been HPHT wells. It is then likely that it has been drilled in the range of 100 to 200 exploration HPHT wells in the US GoM OCS in the period 1980 - 1998.

6.4.2 Norwegian Drilling Wells The number of HPHT wells drilled in Norway is shown in Table 6.9. The data from before 1996 stems from the NPD daily drilling report system (DDRS). The data from 1996 and later stem from the report ”Utvikling i risikonivå norsk sokkel”, hovedrapport, Fase 6 – 2005, www.ptil.no .

Page: 72

Table 6.9


Number of HP/HT wells drilled in the Norwegian waters sorted on years o

Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Total

No. of HPHT wells (>690 bar and/or > 150 C) Exploration Production 3 2 2 0 3 3 8 7 9 5 3 2 3 4 5 1 2 1 4 2 2 3 3 2 2 1 2 10 3 20 76 41

6.4.3 US GoM OCS Wells in Production The pressure exposure data for production wells are based on all the well tests with a listed shut-in wellhead pressure in the period 1980 – 1996 (/1/). Totally 48264 tests were listed with a positive wellhead shut-in pressure. Many well tests were not listed with well test pressures. The distribution of well tests in four different pressure ranges is presented in Table 6.10. Table 6.10 Pressure ranges in production wells in US GoM OCS wells Pressure range No. of Relative well tests distribution below 6000 psi (414 bar) 46928 97,23 % 6000 – 8000 psi pressure 926 1,92 % 8000 – 10000 psi 336 0,70 % more than 10000 psi (690 bar) 74 0,15 % Total 48264 100,00 %

In Figure 6.7 the development wells shut-in wellhead pressures have been plotted against the well depth.


Page: 73

Figure 6.7 All well tests performed 1980-1996 and listed with a shut-in wellhead pressure

6.5 Production Rates and Gas Oil Ratio Data, US GoM OCS This section is based on MMS Ogor A files from 1980 – 1999 (/1/). These files list the well individual production amount (gas, oil and water) for each month. Only the December data each year has been used to reduce the amount of information to handle 6.5.1 Production Rates Figure 6.8 and Figure 6.9 show the production rate for the US GoM OCS oil and gas wells respectively. The production rate data has been grouped in two different groups, the 80-ties and the 90-ties.

Page: 74


Oil production (m3/day)

200 180

Daily Oil Volume in the 80's

160

Average 80's

140

Daily Oil Volume in the 90's Average 90's

120 100 80 60 40 20

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

0

Perecentage of oil wells Figure 6.8 Oil well production rates, US GoM OCS wells, 1980 - 1999

The number of wells in production in the December month was slightly higher in the 90's than in the 80's. The average produced amount of oil was 41 m3/day in the 90's and 36 m3/day in the 80's per oil well that produced in the December month. In the end of the 90's some wells have experienced flow-rates of more than 3000 m3/day. The highest flow-rate seen was 5600 m3/day (or approximately 35 000 bbls). The wells are only those wells categorized as oil wells in the MMS files (some of them were only producing gas, and no oil). Nearly 99% of these wells have also produced gas, in average 13013 Sm3/day. Water production was also listed for 88% of these wells. On average for all wells the water production was 49.5 m3/day, i.e. more water was produced than oil.


Page: 75

500000 Daily Gas Volume 80's

Gas production (Sm3/day)

450000

Daily Gas Volume 90's

400000

Average 80's Average 90's

350000 300000 250000 200000 150000 100000 50000

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

0

Perecentage of gas wells Figure 6.9 Gas well production rates, US GoM OCS wells, 1980 - 1999

The number of wells in production in the December month was slightly higher in the 90's than in the 80's. The average produced amount of gas was 108 000 Sm3/day in the 90's and 124 000 Sm3/day in the 80's per gas well that produced in the December month. The best producers produced nearly one million Sm3/day. The wells are only those wells categorized as gas wells in the MMS files (some few of them were only producing oil, and no gas). Approximately 66% of these gas wells also produced oil, in average 7.3 m 3/day for all the wells. Water production was also listed for 67% of these wells. In average for all wells the water production was 18.2 m3/day. 6.5.2 Gas Oil Ratio The gas oil ratio data has been grouped in two different groups, the 80-ties and the 90-ties.

Page: 76


4000 3500 GOR 80's (Sm3/Sm3)

Sm3/Sm3

3000

GOR 90's (Sm3/Sm3)

2500 2000 1500 1000 500

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

0

Perecentage of oil wells Figure 6.10 Well test GOR data sorted on period 100000

(Sm3/Sm3)

80000

GOR 90's (Sm3/Sm3)

60000

GOR 80's (Sm3/Sm3)

40000

20000

90%

100%

Perecentage of gas wells

80%

70%

60%

50%

40%

30%

20%

10%

0%

0

Figure 6.11 Well test GOR data sorted on period

6.6 Workover Frequency Exposure Data Very little statistical material related to number of workovers carried out exists. From the SINTEF study "Reliability of Surface Controlled Subsurface Safety Valves, Phase III", SINTEF report STF 75 F89030, it was observed 498 workovers on a total of 7790 well years. The data was mainly collected in the period 1985 - 1989 for North Sea wells. This gives in average:


Page: 77

15.6 well years per workover The NPD Annual reports from 1980 to 83 lists the number of workovers carried out the actual year alongside the number of production wells. A total of 88 workovers were listed and a total of 731 production well years. This gives in average: 8.3 well years per workovers In the autumn 2001 a search in the NPD Daily Drilling Report System (DDRS) was carried out. The search criteria specified:   

Traditional type of equipment was used (i.e. the permanently installed drilling rig and not a coiled tubing or snubbing unit). The main operation was Workover Sub operation was completion string (i.e. involved pulling of the completion string).

Each well that had at least on occurrence with the above combinations within one year was counted as a workover. This means that if two workovers were carried out the same year it will be counted as one workover only. On the other hand if the workover starts in December one year and is completed in January the next year it will be counted as two workovers. This count of workovers has been possible for the period after 1995 when NPD introduced some new codes in the DDRS. Seventy-six workovers were carried out in the year 2000. The result from this count for the years 1996 to 1999 is shown in Table 6.11. Table 6.11 Workover frequencies in Norwegian waters Year 1996 1997 1998 1999 Total

No. of workovers 56 72 86 59 273

No. of production wells 580 612 624 854 2670

No. of inject- Sum no. of No of well years per workover ion wells wells 13.7 189 769 11.2 194 806 9.7 211 835 18.9 259 1113 853 3523 12.9

It seems that the workover frequencies related to conventional workovers has decreased since the beginning of the 1980-ties when comparing with the above results. It is recommended that 10.6 well years per workover is used for the estimates related to blowout/well release frequencies per workover operation. This value will represent the average for the period 1980 - 2000. 6.7 Wireline Frequency Exposure Data Very little statistical material related to number of wireline runs exists. To establish an estimate for wireline exposure data, experience from the Ekofisk field in 1992 has been used. In 1992, 135 wells were in service (production and injection). A total of 220 wireline jobs were carried out. If in average each wireline job includes 2.5 wireline runs a total of 550 wireline runs were carried out for the 135 wells. This gives in average: 4.2 wireline runs per well year or 1.7 wireline jobs per well year

Page: 78


It is important to note that the Ekofisk field mainly has wireline retrievable SCSSVs, and not tubing retrievable SCSSVs that most operators prefer when completing new wells today. It should further, be noted that most likely several minor incidents (small gas releases) during wireline jobs have never been recorded as blowouts.

6.8 Coiled Tubing and Snubbing Exposure Data Table 6.12 lists the number of coiled tubing and snubbing workovers that have been carried out in the Norwegian waters in the period 1984 - 1995. The NPD Daily Drilling Report System (DDRS) was used to extract the data. The data may not be exact because the DDRS did not include a specific code for these operations before 1995. The results are based on a search in the activity description for all production wells stored in the database. Coiled tubing and snubbing activities during regular drilling and completion are not included in Table 6.12. Coiled tubing and snubbing operations carried out, as a part of a conventional workover, is included. These operations should not have been included because they were only a sub-operation during a conventional workover. Therefore the activity level as listed in Table 6.12 probably is 10 – 20% higher than the real figures. Table 6.12 Coiled tubing and snubbing workover exposure data for the Norwegian sector of the North Sea, 1984 - 1995 Year 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 Total

Snubbing workovers 1 5 5 7 8 12 4 15 28 21 33 49 188

Coiled tubing workovers 0 1 3 5 3 13 16 13 19 32 38 48 191

In the autumn 2007 a search in the NPD Daily Drilling Report System (DDRS) was carried out. The search criteria specified that either a snubbing or a coiled tubing unit was used. The main operation was Workover and Drilling and the sub operation was not specified. Each well that had at least on occurrence with the above combinations within one year was counted as a snubbing workover , a coiled tubing workover, or coiled tubing drilling. This means that if two operations of one kind were carried out the same year it will be counted as one operation only. On the other hand if the operation starts in December one year and is completed in January the next year it will be counted as two operations. If dedicated snubbing or coiled tubing units are used in association with a conventional workover they will be regarded as separate operations, i.e. the total number of operations indicated in Table 6.13 may be some higher than the real figures. The result from this count for the years 1996 to 2006 is shown in Table 6.13.


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Table 6.13 Coiled tubing and snubbing workover exposure data for the Norwegian sector of the North Sea, 1996 - 2000 Year 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Total

Snubbing workovers 42 39 32 30 24 15 8 6 8 3 1 167

Coiled tubing workovers 83 81 83 49 50 50 57 74 37 37 44 346

Coiled tubing drilling 5 7 31 21 23 21 17 19 11 11 10 176

Page: 80



Page: 81

7. Overall Blowout/Well Release Frequencies Only overall blowout/well release frequencies for the different operational phases have been calculated. If required, analyses that are more detailed can be carried out by using the information presented in the various tables in the previous sections and/or the SINTEF Offshore Blowout Database. The listed frequencies in this section are based on the experience from US GoM OCS, UK and Norway in the period 1980-01-01 - 2009-12-31 only. The blowout frequencies during the different operational phases are presented in Table 7.1 to Table 7.6. The four blowouts listed with the phases “Unknown” and Unknown drilling” are not included. Please also note that blowouts caused by external loads are disregarded when calculating the blowout/well release frequencies. Table 7.1

Blowout/well release frequencies during completion (based on Table 4.4, Table 5.1, Table 5.2, and Table 5.4)

No. of completions No. of incidents per incident per completion Blowout (surface flow) 23 635 10 2364 0,00042 Blowout (underground flow) 23 635 0 0 Diverted well release 23 635 1 23 635 0,00004 Well release 23 635 9 2626 0,00038 Total 23 635 20 1182 0,00085 * Based on total number of wells completed in Table 5.1, number of developments wells drilled in Table 5.2, and Table 5.4. Category

Table 7.2

No. of completions*

No. of incidents

Blowout/well release frequencies during development drilling (based on Table 4.4 and Table 5.12)

Type of incident Blowout (surface Deep flow) Shallow Deep Blowout (underground flow) Shallow Deep Diverted well release Shallow Deep Well release Shallow Total Category

No. of dev. wells drilled 27490 27490 27490 27490 27490 27490 27490 27490 27490

No. of incidents 8 23 4 1 0 19 6 2 63

No. of drilled wells per incident 3436 1195 6873 27490 1447 4582 13745 436

No. of incidents per drilled well 0,00029 0,00084 0,00015 0,00004 0,00000 0,00069 0,00022 0,00007 0,00229

Page: 82

Table 7.3


Blowout/well release frequencies during exploration drilling (based on Table 4.17, Table 5.1, Table 5.2, and Table 5.4) Type of incident Deep

Category

Blowout (surface flow)


Diverted well release

Shallow

Total Deep Total Deep Shallow Total Deep

Well release

Shallow Total Deep

Unknown Total Deep All

Shallow

Total exploration drilling

Table 7.4

Exploration No. of. wells No. of No. of drilled wells No. of incidents well type drilled incidents per incident per drilled well Appraisal 7 532 10 753 0,00133 Wildcat 8 913 13 686 0,00146 Appraisal 7 532 12 628 0,00159 Wildcat 8 913 19 469 0,00213 Unknown 1 16 445 55 299 0,00334 Appraisal 7 532 1 7 532 0,00013 Wildcat 8 913 7 1 273 0,00079 16 445 8 2 056 0,00049 Appraisal 7 532 0 0 Wildcat 8 913 1 8 913 0,00011 Appraisal 7 532 5 1 506 0,00066 Wildcat 8 913 7 1 273 0,00079 16 445 13 1 265 0,00079 Appraisal 7 532 3 2 511 0,00040 Wildcat 8 913 3 2 971 0,00034 Unknown 1 Appraisal 7 532 1 7 532 0,00013 Wildcat 8 913 1 8 913 0,00011 16 445 9 1 827 0,00055 Appraisal 7 532 1 7 532 0,00013 Wildcat 8 913 0 0 16 445 1 16 445 0,00006 Appraisal 7 532 15 502 0,00199 Wildcat 8 913 24 371 0,00269 Unknown 1 Appraisal 7 532 18 418 0,00239 Wildcat 8 913 27 330 0,00303 Unknown 1 16 445 86 191 0,00523

Blowout/well release frequencies during production (based on Table 4.4 and Table 5.18). Blowouts caused by external loads (storm, fire etc.) are disregarded

No. of well years in service Blowout (surface flow) 244 144 Blowout (underground flow) 244 144 Diverted well release 244 144 Well release 244 144 Total 244 144 Category

Table 7.5

No. of incidents 9 1 0 3 13

No. of well years per incident 27 127 244 144 81 381 18 780

0,000012 0,000053

Blowout/well release frequencies during well workover (based on Table 4.4, Table 5.18 and Section 6.6)

No. of No. of workover per incidents incident Blowout (surface flow) 23 032 23 1 001 Blowout (underground flow) 21 882 0 Diverted well release 21 882 0 Well release 23 032 25 921 Total 23 032 48 480 * Based on in average one workover per 10.6 production well years (Section 6.6) Category

No. of incidents per well year 0,000037 0,000004

No. of workovers*

No. of incidents per workover 0,00100 0 0 0,00109 0,00208


Table 7.6

Blowout/well release frequencies during wireline (based on Table 4.4, Table 5.18 and Section 6.7)

No. of wireline No. of No. of wireline jobs jobs* incidents per incident Blowout (surface flow) 415 045 4 103 761 Blowout (underground flow) 403 818 0 Diverted well release 403 818 0 Well release 415 045 5 83 009 Total 415 045 9 46 116 * Based on in average 1.7 wireline jobs per production well years (Section 6.7) Category

Page: 83

No. of incidents per wireline job 0,000010 0 0 0,000012 0,000022

Page: 84



Page: 85

REFERENCES 1

Files retrieved from/bought from BOEM in the US (former MMS (Mineral Management Service) and Boemre):  http://www.gomr.mms.gov/homepg/pubinfo/freeasci/freedesc.html (used for downloading files related to well drilling and well production data)  File: 5137 Historical Well Test by Area and Block ASCII (bought from MMS)  Ogor A, Well production files bought from MMS (1980 –1996)  Ogor A, Well production files downloaded from MMS (1996 –2009) US GoM region  Ogor A, Well production files downloaded from MMS (1986 –2009) US Pacific region

Blowout and Well Release Characteristics and Frequencies, 2011 version, Appendix 1

Page: i

Appendix 1 Blowout Database Structure and Coding LIST OF CONTENTS A1. OVERALL DATABASE STRUCTURE .............................................................................................................. II A2. DESCRIPTION OF DATABASE FIELDS AND ASSOCIATED CODES ................................................................. IV FIELD 3

CATEGORY ................................................................................................................................... IV

FIELD 4

SUB CATEGORY ............................................................................................................................. V

FIELD 5

COUNTRY..................................................................................................................................... VI

FIELD 10

INSTALLATION TYPE ..................................................................................................................... VI

FIELD 12

WELL STATUS ............................................................................................................................... VI

FIELD 18

MTSIP (MAKS THEORETIC SHUTIN WH PRESSURE)....................................................................... VI

FIELD 24

ROCK TYPE .................................................................................................................................VIII

FIELD 25

FORMATION AGE .......................................................................................................................VIII

FIELD 27

PHASE ........................................................................................................................................VIII

FIELD 28

OPERATION ................................................................................................................................. IX

FIELD 29

ACTIVITY ...................................................................................................................................... XI

FIELD 30

EXTERNAL CAUSE ........................................................................................................................ XII

FIELD 31

LOSS OF BARRIER 1 ..................................................................................................................... XII

FIELD 32

LOSS OF BARRIER 2 ....................................................................................................................XIV

FIELD 34

NORTH SEA STANDARDS............................................................................................................XIV

FIELD 35

FLOWPATH .................................................................................................................................XV

FIELD 36

RELEASE POINT ...........................................................................................................................XV

FIELD 37

FLOW MEDIUM..........................................................................................................................XVI

FIELD 41

IGNITION TYPE ...........................................................................................................................XVI

FIELD 42

CONSEQUENCE CLASS ...............................................................................................................XVII

FIELD 44

POLLUTION ...............................................................................................................................XVII

FIELD 48

CONTROL METHOD ...................................................................................................................XVII

FIELD 50

DATA QUALITY..........................................................................................................................XVII

Page: ii


A1. Overall database structure The database contains 51 different fields describing each blowout/well release. The various fields are grouped in six different groups. They are: 1. 2. 3. 4. 5. 6.

Category and location Well description Present operation Blowout causes Blowout Characteristics Other

Category and location Includes information related to the incident category (blowout vs. well leak), offshore installation such as location, operator, installation name and type, and water depth. Well description Includes well and casing depths, last casing size, mud weight, bottom hole- and shut in pressure, GOR, formation age and rock type. Present operation Includes the phase (exploration drilling, development drilling, workover etc.), the operation presently carried out (for example casing running) and the present activity (for example cementing) Blowout causes Include external cause (stating if an external cause contributed to the incident), loss of the primary barrier, loss of the secondary barrier (describing how primary and secondary barrier were lost) and human error. It should be noted that the field regarding human error in general holds low quality information. Human errors are frequently masked. A field named North Sea standards highlights if the development of the blowout could have been avoided if North Sea type equipment had been used (for instance in other parts of the world a blind shear ram is not required in surface BOP stacks) Blowout characteristics Twelve fields are included comprising flow-path, flow medium, flow-rate (low quality), release point, ignition type, time to ignition, lost production (low quality), duration, fatalities, consequence class, material loss and pollution Other In the Other screen five fields are included, they are: control method, remarks (includes a description of the incident, data quality (includes an evaluation of the source data quality), last revision date and references. Each field and a brief description of the field content are shown in Table A 1.


Table A 1 Blowout database fields Field Drop Field Name no. down list? 1 No Id_no 2 No Date 3 Yes Category 4 Yes Sub_category 5 Yes Country 6 No Field 7 No Water depth 8 No Operator 9 No Installation_name 10 Yes Installation_type No Slots 11 No Well depth 12 Yes Well status 13 No Casing size 14 No Casing depth 15 No Mud weight 16 No B.h. pressure 17 No MMSIP 18 No MTSIP 19 No 20 No 21 No 22 No 23 No 24 Yes 25 Yes 26 No 27 Yes 28 Yes 29 Yes 30 Yes 31 Yes 32 Yes 33 No 34 Yes 35 Yes No 36 Yes 37 Yes 38 No 39 No 40 Yes 41 Yes 42 No 43 Yes 44 No 45 No 46 No 47 Yes 48 No 49 Yes 50 No 51 No

Gas volume Oil volume Water_volume Gas/oil_ratio API_grade Rock_type Formation_age Formation_name Phase Operation Activity External cause Loss of barrier 1 Loss of barrier 2 Human error North_Sea_standards Flowpath Finflowpat Release point Flow medium Flow rate Ignit time Ignit type Consequence class Material loss Pollution Lost production Fatalities Duration Control method Revision date Data quality References Remarks

Page: iii

Brief description Chronological input no. (ID no.) Date of incident (dd-mm-yy) Classification of incident in Blowout, underground blowout, or well leak Related to the main category Country in which incident occurred Specification of offshore field Water depth (meter) (0=unknown) Name of responsible for the operations Rig name or installation name Type of installation Not included in database program Well depth (meter)(0=unknown) Killed or alive Size of deepest casing (inches)(0=unknown) Position of deepest casing shoe (meter)(0=unknown) Mud weight (kg/m3)(0=unknown) Bottom hole pressure (bar)(0=unknown) Max Measure ShutIn Pressure (bar)(0=unknown) Maks Theoretic ShutIn WH Pressure, Based on coarse estimates if not given in the source Gas Volume pr 24 hours (measured by a well test) Oil Volume pr 24 hours (measured by a well test) Water Volume pr 24 hours (measured by a well test) Based on the above gas and oil volume fields Sm3/Sm3 Related to the blowout medium Sandstone or limestone Age of formation (Jurassic etc.) Local name of formation Drilling, production, workover etc. Main operation when incident occurred Present activity External cause if any, else NO Loss of primary barrier Loss of secondary barriers Human errors States if blowout barriers were not according to North Sea standards Main flow path Not included in database program Release point Type of blowout flow medium Blowout flowrate (m3/day) (0=unknown) Time to ignition from start of blowout (hours) Type of ignition (No, fire, explosion, not relevant) Consequence classification Material losses (Million US$)(0=unknown) Spill to sea Lost production (production facilities only) Number of lives lost because of the blowout Duration of blowout (days)(0=unknown) The method used to stop the blowout Date for last update of database record Quality of reference data Refers to the sources of information Verbally description of incident

Page: iv


A2. Description of database fields and associated codes Field 3

Category

For the field Category the Table A 2 shows the pre-defined fields. Table A 2 Category fields ID Description 1 Blowout (surface flow) 2 Blowout (underground flow) 3 Well release 4 Diverted well release 5 Unknown 20 Not evaluated

The following main definitions have been utilised when categorising the blowouts/well releases in main categories and sub-categories. Blowout definition NPD came up with a blowout definition in their proposal for the new regulations. (“Aktivitetsforskriften, eksternt høringsutkast av 3.7.2000, høringsfrist 3.11.2000”). Med utblåsing som nevnt i denne paragrafen første ledd, menes formasjonsfluid som strømmer ut av brønnen eller mellom formasjonslagene etter at alle definerte tekniske brønnbarrierer eller operasjon av disse har sviktet. Translated to English the definition will be: A blowout is an incident where formation fluid flows out of the well or between formation layers after all the predefined technical well barriers or the activation of the same have failed. The definition does however not seem to have become a part of the final new NPD regulation, but remains the database blowout definition. Well release definition: The reported incident is a well release if oil or gas flowed from the well from some point were flow was not intended and the flow was stopped by use of the barrier system that was available on the well at the time the incident started. Shallow gas definition: Any gas zone penetrated before the BOP has been installed. Any zone penetrated after the BOP is installed is not shallow gas (typical Norwegian definition of shallow gas). All shallow gas incidents in the database have at the extent possible been categorised according to the typical Norwegian definition of shallow gas. This definition is not relevant for all US GoM incidents because: 

US GoM OCS reservoirs vary highly in depth. Some reservoirs were as shallow as 200 meters.


  

Page: v

For some incidents they had sat a full BOP stack, but had now intention to use it because it would likely cause a blowout outside the casing and a possible crater. For some incidents they had drilled very deep without running an extra casing string and the BOP. And for some incident they had used a combination of a BOP and a diverter.

Further, for many of the incidents the description of the incident in the sources is insufficient, and some assumptions have to be made. A general comment is that it is not easy to categorise all the incidents in shallow and deep incidents because of the above. Field 4

Sub Category

For the field Sub category the Table A 3 shows the pre-defined fields. Table A 3 Sub category ID Description 1 Totally uncontrolled flow, from a deep zone 2 Totally uncontrolled flow, from a shallow zone 3 Shallow gas “controlled” subsea release only 4 Underground flow only 5 Underground flow mainly, limited surface flow 6 Limited surface flow before the secondary barrier was activated 7 String blown out of well, then the secondary barrier is activated 8 Shallow gas controlled flow (diverted) 9 Unknown 10 Other 20 Not evaluated

Table A 4 shows the link between the category and sub category. Table A 4 Categories and subcategories for the incidents in the SINTEF Offshore Blowout database Main

Blowout and well release

Category Blowout (surface flow)


Sub category 1. Totally uncontrolled flow, from a deep zone 2. Totally uncontrolled flow, from a shallow zone 3. Shallow gas “controlled” subsea release only 4. Underground flow only 5. Underground flow mainly, limited surface flow

Well release

6. 7.

Diverted well release Unknown

8.

Limited surface flow before the secondary barrier was activated Tubing blown out of well, then the secondary barrier is activated

Shallow gas controlled flow (diverted) Unknown

Comments/Example Totally uncontrolled incidents with surface/subsea flow. Typical the diverter system fails Typical incident is that riserless drilling is performed when the well starts to flow. The rig is pulled away The limited surface flow will be incidents were a minor flow has appeared, but typical the BOP has been activated to shut the surface flow Typical incident will be that flow is through the drillpipe and the shear ram is activated Typical incident occurring during completion or workover. Shear ram is used to close the well after the tubing has been blown out of the well. All incidents were the diverter system functioned as intended. Unknown may be selected for both the category and the subcategory

The list of sub-categories shown in Table A 3 may be extended if found appropriate. One option will be to split the sub category for Well leakage further down to highlight incidents with an ignition potential.

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Field 5

Country

All countries that have experienced an offshore blowout are included in the dropdown list. It should be noted that for US several options for Country exist, depending on the area. Field 10

Installation Type

This is a pre-coded field. Table A 5 shows the existing installation types. Table A 5 Installation types Description BARGE DRILLSHIP JACKET Includes Condeep JACKUP SATELLITE One well structure SEMISUBMERSIBLE SUBMERSIBLE SUBSEA PROD TENSION LEG Other UNKNOWN

Field 12

Comments

Well Status

Table A 6 shows the Well status classification used. Table A 6 Well status ID Description 0 ALIVE 1

KILLED

2

UNKNOWN

Field 18

Remarks Mainly production and wireline, may also in some cases apply for workover Drilling, workover, completion) applies when the wellhead normally should only be exposed to hydrostatic pressure.

MTSIP (Maks Theoretic Shutin WH Pressure)

This field was developed when working with a project focusing HP HT blowout risk. The information included stems from various sources and estimates. NOTE:  High shut-in wellhead pressure wells have been focused:  Blowouts/well leaks listed with 345 bar shut-in pressures are wells were the shut-in pressure is unknown, but less than 345 bars  Blowouts/well leaks listed with 1 bar shut-in pressures are wells were the shut-in pressure is Not relevant  Blowouts/well leaks listed with 0 bar shut-in pressures are wells were the shut-in pressure is Unknown The most used pressure definition for a HPHT well in Norway is that wells with a shut-in well head pressure above 690 bar (10000 psi) are to be regarded as a HPHT wells. The maximum Shut-in wellhead pressures are normally not listed in the sources of information used for the blowout input data, so these pressures had to be deducted from other sources or


Page: vii

parameters for the given blowout/well leak. The following three main approaches were: 1. Review the blowout description in the database records and in the files to see if any specific wellhead shut-in pressures were given. 2. Find the actual shut-in wellhead pressures in the US GoM OCS well test database (/1/), or for close by wells at approximately the same depth. This was for US blowouts/well leaks only. 3. Estimate the shut-in wellhead pressure based on information about the mud weight and the true vertical depth, or the down hole well pressure, and assuming the well was filled with methane gas The shut-in well head pressures have been divided in the following four main groups For the blowouts/well leaks that obviously did have a shut-in wellhead pressure below 345 bar (5000 psi) it has not been made any attempts to find the approximate maximum shut-in wellhead pressure. The blowout was just categorised in that group. For the other blowouts/well leaks more efforts were used. When reviewing the well tests data file including shut-in wellhead pressures for approximately 48 000 well tests, some pressures could directly be found, while for other an approximate pressure was found. For the blowouts/well leaks were the down hole pressure were given in the source this was used for estimating the shut-in wellhead pressure. For the blowouts/well leaks where a mud weight was given the shut-in pressures were estimated based on the mud weight and the true vertical well depth. Either the mud weight when the blowout occurred or the mud weight after the well control was re-established were used. It was then estimated that the complete well bore was filled with methane with a density of 0,71 kg/m3 at atmospheric pressure The formula used was as follows (only metric units were used): PSI = Pbottom - methane * g * DTVD * (Pbottom + PSI)/ (2 * PATM) the solution for PSI will then be: PSI = Pbottom (1- methane * g * DTVD/ 2 * PATM)/(1 + methane * g * DTVD/ 2 * PATM) Where; DTVD Pbottom methane mud g PSI PATM

= True vertical depth = Bottom hole pressure = listed or = mud * g * DTVD = density of methane at atmospheric pressure = 0,71 kg/m3 = density of mud = gravity force = Shut-in wellhead pressure = Atmospheric pressure

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Field 24


Rock Type

Rock type describes the type to rock the blowout flows from. The Rock type codes used are shown in Table A 7. Table A 7 Rock type ID Description 0 A.SANDSTONE 1 B.LIMESTONE 2 NOT RELEVANT 3 UNKNOWN

Field 25

Formation Age

Formation age gives the geological name of the formation. Table A 8 shows the codes used for formation age. Table A 8 Formation age ID Description 0 A.PLIOCENE 1 B.MIOCENE 2 C.OLIGOCENE 3 D.ECOCENE 4 E.UPPER CRETACEOUS 5 F.CRETACEOUS 6 G.LOWER CRETACEOUS 7 H.UPPER JURASSIC 8 I.MIDDLE JURASSIC 9 J.LOWER JURASSIC 10 K.TRIAS 11 L.PERMIAN 12 M.CARBONIFEROUS 13 N.DEVONIAN 14 NOT RELEVANT 15 O.SILURIAN 16 P.CAMBRIAN 17 Q.PRECAMBRIAN 18 R.ARCHEAN 19 UNKNOWN 20 AA.PLEISTOCENE

Field 27

Phase

PHASE refers to the main type of activity. The following preset codes used are shown in Table A 9.


Page: ix

Table A 9 Phase

Description

COMPLETION DEV.DRLG EXPL.DRLG

EXPL.DRLG WILDCAT* EXPL.DRLG APPRAISAL* PRODUCTION UNKNOWN DRLG WIRELINE WORKOVER

Activities associated to well completion Development drilling Exploration drilling, includes wildcats and appraisal wells (for incidents where appraisal or wiuldcat well has not or can not be determined. Exploration drilling, wildcat wells Exploration drilling, appraisal wells Production, injection, closed in wells When it is not known whether it is DEV.DRLG or EXPL.DRLG Wireline operations in connection with a production/injection well, not wireline operations carried out as a part of well drilling, well completion or well workover Workover activities, not including wireline operations. Snubbing and coiled tubing operations

Other UNKNOWN

To differ between Wildcats and Appraisal wells the following has been assumed; - For Norwegian waters the NPD classification has been used as it is. - For the UK waters all wells classified as Exploration wells are regarded as Wildcats, while the wells classified as Appraisal wells are of regarded as Appraisals. - For the US GoM OCS a different approach has been used. All exploration wells drilled in certain areas are numbered from 1 and further, where well number 1 is the first well drilled. For US GoM OCS all exploration wells numbered as 1 have been regarded as Wildcats, while all the other wells are regarded as Appraisal wells. This may be inaccurate, but this will likely lead to an underestimation of no. of Wildcats compared to no. of Appraisal wells for the US GoM OCS. Field 28

Operation

This field includes preset codes that describe the main operation carried when starting to loose well control. Table A 10 shows the available selections.

Page: x


Table A 10 Operation ID Description 0 C1.RUNNING WELL EQUIPMENT 1 C2.INSTALLING EQUIPMENT 2 C3.PRESSURE TESTING 3 C4.WELL TESTING INCL.PREPARATIONS 4 C5.CIRCULATING 5 C6.HANDLING TECHNICAL PROBLEMS 6 C7.PERFORATING 7 D1.DRILLING ACTIVITY 8 D2.CASING RUNNING 9 D3.INSTALLING EQUIPMENT 10 D4.WELL TESTING 11 D5.PRESSURE TESTING 12 D6.ABANDON WELL 13 D7.TEMPORARY PLUGGED 14 D8.HANDLING TECHNICAL PROBLEMS 15 D9.CIRCULATING 16 OTHER 17 UNKNOWN 18 W1.PULLING WELL EQUIPMENT 19 W10.TEMPORARY PLUGGED 20 W11.HANDLING TECHNICAL PROBLEMS 21 W12.PERFORATING 22 W13.FISHING 23 W14.KILLING 24 W15.COILED TUBING 25 W2.RUNNING WELL EQUIPMENT 26 W3.INSTALLING EQUIPMENT 27 W4.PRESSURE TESTING 28 W5.WELL TESTING INCL.PREPARATIONS 29 W6.CIRCULATING 30 W7.DRILLING ACTIVITY 31 W8.SNUBBING 32 W9.ABANDON WELL 33 WL1.RIGGING UP WIRELINE EQUIPMENT 34 WL2.RUNNING WIRELINE OPERATIONS 35 WL3.HANDLING TECHNICAL PROBLEMS 36 P1.PRODUCING OIL 37 P2.PRODUCING GAS 38 P3.PRODUCING CONDENSATE 39 P4.INJECTING GAS 40 P5.INJECTING WATER 41 P6.CLOSED IN OIL WELL 42 P7.CLOSED IN GAS WELL 43 P8.CLOSED IN CONDENSATE WELL

Remarks These main operation alternatives exist for the completion phase (PHASE = COMPLETION):

These main operation alternatives exist for the drilling phase (PHASE = EXPL.DRLG, DEV.DRLG or UNKNOWN DRLG):

General These main operation alternatives exist for the workover phase (PHASE = WORKOVER):

These main operation alternatives exist for the workover phase (PHASE = WIRELINE) These main operation alternatives exist for the production phase (PHASE = PRODUCTION):


Field 29

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Activity

The field "Activity" is intended to give a more complete coded description of the present operation carried out. Table A 11 shows the codes used for the activity field. Table A 11 Activities ID Description 0 A1.ACTUAL DRILLING 1 A10.WELL SUSPENDED 2 A2.TRIPPING OUT 3 A3.TRIPPING IN 4 A4.OUT OF HOLE 5 A5.CORING 6 A6.MILLING. 7 A7.FISHING 8 A8.STUCK PIPE 9 A9.PLUGGED PIPE 10 B1.CIRCULATING 11 B2.WEIGHT UP MUD 12 C1.CASING RUNNING 13 C2.CEMENTING CASING 14 C3.WAIT ON CEMENT 15 C4.PRESSURE TEST CASING 16 C5.DRILLING OUT CASING 17 C6.PULLING CASING 18 C7.CEMENT SQUEEZE 19 C8.LEAK OFF TEST 20 D1.INSTALL BOP 21 D2.NIPPLE DOWN BOP 22 D3.TEST BOP 23 D4.MAINTENANCE BOP 24 D5.SET WELL PLUGS 25 D6.PULL/DRILL OUT WELL PLUGS 26 D7.NIPPLE DOWN X-MAS TREE 27 E1.SURVEYING 28 E2.LOGGING 29 E3.ACTUAL WELL TEST 30 F1.RUN TUBING 31 F10.SNUBBING OUT 32 F11.KILLING 33 F2 PULL TUBING 34 F3.PERFORATING 35 F4.STIMULATING 36 F5.GRAVEL PACK 37 F6.ACIDIZING 38 F7.CLEANING WELL 39 F8.PULL COILED TUBING 40 F9.SNUBBING IN 41 G1.CHANGING EQUIPMENT 42 G2.PRESSURE TEST SURF. EQUIPMENT 43 G3.PRESSURE TEST WELL EQUIPMENT 44 G4.MAINTENANCE SURFACE EQUIPMENT 45 G5.MAINTENANCE WELL EQUIPMENT 46 G6.MAINTENANCE OTHER 47 O1.WAIT ON REPAIR 48 O2.WAIT ON WEATHER

Remark When the bit is on bottom

Actual running the casing in the hole

Page: xii


ID 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66

Field 30

Description O3.WAIT ON ORDER O4.DISCONNECT RISER OTHER P1.REGULAR PRODUCTION P2.REGULAR INJECTION P3.PRODUCTION TESTING P4.SURFACE MAINTENANCE P5.TESTING SAFETY VALVES P6.GAS LIFTING P7.FAILURE DIAGNOSING P8.GAS LIFTING UNKNOWN W1.RUN WIRELINE W2.PULL WIRELINE W3.FISH FOR WIRELINE F8b.RUN COILED TUBING F8c.COILED TUBING OPERATIONS E4. FLOW CHECK

Remark

External Cause

The field External cause indicates if the incident was caused by an External cause, and if so what type of, external cause. Table A 12 shows the used external causes. Table A 12 External cause ID Description Remarks 0 NO No external cause 1 A1.STORM 2 A2.SHIP COLLISION 3 A3.TRAWL/ANCHOR 4 A4.FIRE/EXPLOSION 5 A5.EARTHQUAKE 6 A6.SABOTAGE/MILITARY ATTACK 7 UNKNOWN

Field 31

Loss of Barrier 1

The field Loss of barrier 1 describes the primary barrier lost. Table A 13 shows the codes used for loss of barrier 1.


Table A 13 Loss of barrier 1 ID Description 0 A1.TOO LOW HYD. HEAD - TOO LOW MUD WEIGHT 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

A10.TOO LOW HYD. HEAD - ANNULAR LOSSES A11.TOO LOW HYD. HEAD - WHILE CEMENT SETTING A12.TOO LOW HYD. HEAD - CEMENT PREFLUSH WEIGHT TOO LOW A13.TOO LOW HYD. HEAD - DRILLING INTO NEIGHBOUR WELL A14.TOO LOW HYD. HEAD - TRAPPED GAS A15.TOO LOW HYD. HEAD - UNKNOWN WHY A16.TOO LOW HYD. HEAD - SQUEEZED PERF. BROKE DOWN A2.TOO LOW HYD. HEAD - SWABBING

Page: xiii

Remarks/criteria When too low mudweight is stated in the source, many of these incidents may actually be caused by an unexpected high well pressure When the kick occur in the first period after the cementing operation is completed When stated in the source

When stated in the source

When swabbing is stated in the source, or the blowout occur when pulling out of the hole A3.TOO LOW HYD. HEAD - GAS CUT MUD When gas cut mud is stated in the source A4.TOO LOW HYD. HEAD - WATER CUT MUD When water cut mud is stated in the source A5.TOO LOW HYD. HEAD - IMPROPER FILL UP When improper fill-up is stated in the source A6.TOO LOW HYD. HEAD - DISCONNECTED RISER When stated in the source A7.TOO LOW HYD. HEAD - RISER LEAK A8.TOO LOW HYD. HEAD - UNEXPECTED HIGH When stated in the source, or if the kick occur WELL PRESSURE when actual drilling A9.TOO LOW HYD. HEAD - RESERVOIR DEPTH When stated in the source, some unexpected UNCERTAINTY high well pressure incident is likely caused by reservoir depth uncertainty B1.POOR CEMENT Typical when gas starts to flow/bubble outside or in between casing, not in connection with cementing operations B2.FORMATION BREAKDOWN C1.PACKER LEAKAGE C10.SHEAR VALVE FAILURE C11.COIL TUBING FAILURE C12.ANNULUS SAFETY VALVE FAILURE C13.TUBING PLUG FAILURE C14.CASING PLUG FAILURE C15.SNUBBING EQUIPMENT FAILURE C16.X-MAS TREE FAILURE C17.PACKER PLUG FAILURE C18.WELLHEAD FAILURE C2.TUBING TO ANNULUS COMMUNICATION TUBING BURST C3.TUBING TO ANNULUS COMMUNICATION TUBING LEAKAGE C4.TUBING TO ANNULUS COMMUNICATION EQUIPM./NIPPLE FAILURE C5.SCSSV/STORM CHOKE FAILURE C6.WELL TEST STRING BARRIER FAILURE C7.WIRELINE STUFFING BOX FAILURE C8.WIRELINE LUBRICATOR FAILURE C9.WIRELINE BOP FAILURE OTHER UNKNOWN C11a. STRIPPER BOP FAILURE

Page: xiv

Field 32


Loss of Barrier 2

The field Loss of barrier 2 describes the secondary barrier lost. Table A 14 shows the alternatives for loss of barrier 2. Table A 14 Loss of barrier 2 ID Description 0 A1.STRING SAFETY VALVE FAILED 1 A2.STRING SAFETY VALVE NOT AVAIL 2 A3.FAILED TO STAB KELLY VALVE 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33

Field 34

Remarks When stated in the source When stated in the source When stated in the source, or when the flow comes through the drillstring an no attempts to stab the valve is mentioned

A5.WIRELINE BOP/LUBRICATOR NOT INST A6.WIRELINE BOP/LUBRICATOR FAILED A7.SCCSV/STORM CHOKE FAILED A8.X-MAS TREE FAILED B1.FAILED TO CLOSE BOP B10.DIVERTED - NO PROBLEM B11.FAILED TO OPERATE DIVERTER B12.DIVERTER FAILED AFTER CLOSURE B13.DRILLING WITHOUT RISER B14.DISCONNECTED RISER B15.ANNULUS VALVE FAILED B16.NOT SUFFICIENT FRICTIONAL BACKPRESSURE B17.NO PUMPING B2.BOP FAILED AFTER CLOSURE B3.BOP NOT IN PLACE B4.WELLHEAD FAILED B5.CASING HEAD FAILED B6.TUBING TO ANNULUS COMMUNICATION C1.BAD CEMENT C2.CASING VALVE FAILED C3.WELLHEAD SEAL FAILED C4.OUTER CASING FAILED C5.INNER CASING FAILED D1.FRACTURE AT CSG SHOE D2.CASING LEAKAGE D3.FORMATION BREAKDOWN NOT RELEVANT - ONLY ONE BARRIER PRESENT NOT RELEVANT OTHER UNKNOWN A9.COILED TUBING STUFFING BOX FAILED

North Sea Standards

The field North Sea Standards is intended for highlighting crucial differences between the well control equipment involved in the incident and what is required equipment in North Sea operations. This is a pre-coded field and the alternatives are listed in Table A 15.


Page: xv

Table A 15 North Sea standards ID Description 1 Yes 2 No, no shear ram 3 No, BOP not North Sea standard 4 No, two barrier principle not followed 5 Sometimes not relevant, BOP removed to install casing seal 6 Unknown 20 Not evaluated

Field 35

Flowpath

Flowpath gives information related to the blowout flowpath. This is a pre-coded field and the alternatives are listed in Table A 16. Table A 16 Flowpath ID Description 0 A.THROUGH DRILL STRING/TUBING 1 B.THROUGH ANNULUS 2 C.THROUGH OUTER ANNULUS 3 D.OUTSIDE CASING 4 E.UNDERGROUND BLOWOUT 5 UNKNOWN

Field 36

Release Point

Release point gives information related to the release point. This is a pre-coded field. The pre-coded alternatives are shown in Table A 17. Table A 17 Release point ID Description 0 BOP VALVE OUTLET 1 DIVERTED 2 DIVERTER SYST.LEAK 3 DRILLFLOOR - CHOKE MANIFOLD 4 DRILLFLOOR - DRILL PIPE VALVE 5 DRILLFLOOR - THROUGH ROTARY 6 DRILLFLOOR - TOP OF DRILL STRING 7 DRILLFLOOR - TOP OF TUBING 8 DRILLFLOOR - TUBING VALVE 9 FROM ABOVE X-MAS TREE 10 FROM WELLHEAD 11 FROM X-MAS TREE 12 NO SURFACE FLOW 13 NOT EVALUATED 14 SHAKER ROOM 15 SUBSEA - OUTSIDE CASING 16 SUBSEA CRATER 17 SUBSEA WELLHEAD 18 SUBSEA X-MAS TREE 19 TEST SEPARATOR 20 UNKNOWN 21 MUD ROOM 22 SUBSEA BOP

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Field 37


Flow Medium

Flow medium gives information related to the blowout flow medium. This is a pre-coded field and the alternatives are listed in Table A 18. Table A 18 Flow medium ID Description 10 Shallow gas 20 Shallow gas H2S 30 Shallow gas, Oil 40 Shallow gas H2S, Oil 50 Shallow gas, Water 60 Shallow gas H2S, Water 70 Shallow gas, Mud 80 Shallow water 90 Shallow water, other 100 Gas (deep) 105 Gas (deep), H2S 110 Gas (gas lift gas) 120 Gas (trapped gas) 130 Gas (deep), Water 135 Gas (deep), Water, H2S 140 Gas (deep), Mud 143 Gas (deep), Methanol 145 Gas (deep), Mud, Water 150 Condensate, Gas (deep) 155 Condensate, Gas (deep), water 160 Oil 165 Oil, Shallow gas, H2S 170 Oil, Gas (deep) 175 Oil, Gas (deep), H2S 177 Oil, Gas (deep), Mud 180 Oil, Gas (deep), Water 185 Oil, Gas (deep), Condensate 190 Oil, Water 200 Mud 205 Water 210 Unknown

Field 41

Remarks/criteria Definition of shallow gas: -

Any gas zone penetrated before the BOP has been installed. Any zone penetrated after the BOP is installed is not shallow gas.

*See page iv, shallow gas definition

Ignition Type

Ignition type describes whether the blowout was ignited or not. Table A 19 shows the possible ignition type selections. Table A 19 Ignition type ID Description 0 NO 1 EXPLOSION 2 FIRE 3 UNKNOWN


Field 42

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Consequence Class

Consequence Class gives a consequence classification of the various incidents. The consequence types are listed in Table A 20. Table A 20 Consequence type ID Description 0 NO 1 DAMAGE 2 SEVERE 3 SMALL 4 TOTAL LOSS 5 UNKNOWN

Field 44

Remarks Material loss > $ 0.5 M Material loss > $ 3 M

Pollution

Table A 21 shows the classification for oil/condensate pollution to the sea. Table A 21 Pollution ID Description 0 NO 1 LARGE 2 MEDIUM 3 SMALL 4 UNKNOWN

In case the amount of oil/condensate pollution has been determined it is commented under remarks Field 48

Control Method

Control method includes information related to the method used to stop the blowout. Table A 22 shows the possible key words. Table A 22 Control method ID Description 0 BOP 1 BRIDGED 2 CAPPED 3 CEMENTED 4 DEPLETED 5 INSTALLED 6 MUD 7 RELIEF WELL 8 UNKNOWN 9 CEASED

Field 50

Remarks

Equipment, e.g. VALVE Killed with mud

Data Quality

The Data quality field gives an indication of the reference data quality. Table A 23 shows the alternatives.

Page: xviii


Table A 23 Data Quality ID Description Remarks/criteria 3 VERY GOOD is used if the data record is based on the authorities or the companies investigation report 1 GOOD Is used if the incident is well documented through technical articles or other sources 0 FAIR If the source list an overall description of the incident 2 LOW If the quality of the source information is low, but some crucial facts are described 4 VERY LOW When the source material is very scarce

Annual report 2011 SINTEF Offshore Blowout Database Final_tcm109-486730.pdf

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