Faculty of Science and Technology

MASTER’S THESIS
Study program/ Specialization: Spring semester, 2017
Master of science in
Industrial Economics/
Open access
Contract Administration

Writer:
Stian André Wittberg ……...………………………………
(Writer’s signature)

Faculty supervisor:

Dr. Mahmoud Khalifeh

External supervisor:

Maxime Maouche

Thesis title:
Expanding the Well Intervention Scope for an Effective P&A Operation

Credits (ECTS): 30

Key words:
Plug and Abandonment (P&A) Pages: 118
Rigless
Through tubing + enclosure: 23 pages
Well intervention
Case study
Electric plasma miller Stavanger, June 14th 2017
Thermite plug
Expanding the Well Intervention Scope for an Effective P&A operation

Master’s thesis

by

Stian André Wittberg

Faculty of Science and Technology

Department of Industrial economics, risk management and planning

2017
Abstract

Over 2500 wells on the Norwegian Continental Shelf (NCS) will at some point have to be
permanently plugged and abandoned. As the drill rig rate contributes to 40-50% of the total
plug and abandonment (P&A) cost, the potential savings in shifting operations towards a rigless
approach could be significant. The main objective during a P&A operation is to restore cap rock
functionality, by creating a cross-sectional barrier. The conventional way of plugging wells on
NCS is to use a rig, to allow pulling tubing, section milling or perforate, wash and cement
operations to be executed.

This thesis presents an alternative approach to P&A using well intervention equipment in
combination with some emerging high-energy technologies intended for rigless P&A. Wireline
and coiled tubing with associated equipment and tools are used together with an electric
plasma miller and/or thermite to create a cross-sectional barrier in a through tubing and X-mas
tree P&A operation. A case study is presented where three wells are plugged using a rigless
approach. The wells have an increasing P&A complexity, where lack of annular barrier
traditionally requires a rig.

The case study identified several challenges with the presented rigless approach. A through
tubing operation will leave the tubing as a major restriction in the well. All tools have to pass
through the tubing before reaching the required plugging interval. Azimuthal bond logging tools
intended for logging production casing cement will have particular difficulty passing tubing of 5-
1/2” and smaller. Additionally, placing enough thermite to comply with current NORSOK D-010
specifications was found challenging. New revisions of NORSOK D-010 should allow the
implementation of new technology and rigless P&A to open up for a leaner approach to P&A.
The majority of the wells studied were not fully suited for a complete rigless P&A operation, but
the approach could be used to install permanent reservoir barriers. By completing parts of the
plugging operation using well intervention equipment, the P&A scope for a rig could be
minimized and thereby potentially saving cost.

I
Acknowledgement
This thesis is submitted in fulfillment of the requirements for the degree of Master in Science at
the University of Stavanger. It has been written at the offices of Archer in Stavanger, Norway.

I would like to thank Egil Thorstensen for offering to assist me in the writing process. His
enthusiasm on the topic and the thesis has motivated me throughout the semester. Our
discussions and his feedback resulted in a more reflected and thorough thesis. Thanks for
sharing network and putting me in contact with the right people.

I would also like to thank Dr. Mahmoud Khalifeh, my supervisor at the University of Stavanger. I
am grateful that he accepted to supervise my work, although I was not part of the Institute of
Petroleum Technology. His guidance and feedback throughout the semester has helped me
becoming a better academic. He always had an open door and prioritized meetings with his
master students on short notice. Also, when I wanted to choose the easy way out, he always
challenged me not to. For example, when I wanted to use imaginary wells for the case study, he
insisted in using real well data, which definitely brings more credibility to the thesis.

Thanks to Roy Kristiansen at Archer for providing me with a challenging topic, but still giving me
freedom to take the thesis in the direction I wanted. I am also grateful that Archer provided an
office with excellent working environment for carrying out the project. I would also like to
thank Maxime Maouche, my external supervisor at Archer, for good discussions and assistance
when needed.

In addition I would like to thank Lars Hovda and Paal-Espen Johnsroed in ConocoPhillips, Martin
Straume and Luca Carazza in AkerBP, Ørjan Finnseth in Repsol and Tore Fjågesund in
Wellbarrier for their contribution to the thesis. Without their contribution the project could not
have been carried out.

Finally, I would like to thank my wife Linn, for her support and patience throughout the writing
process.

Stian A. Wittberg

Stavanger, Norway

June 2017

II
Table of Contents
Abstract .......................................................................................................................................................... I
Acknowledgement ........................................................................................................................................ II
List of Figures ............................................................................................................................................... VI
List of Tables ................................................................................................................................................ IX
1. Introduction .......................................................................................................................................... 1
1.1 Introduction to P&A ......................................................................................................................... 1
1.1.1 General .................................................................................................................................. 1
1.1.2 Norwegian Oil & Gas Association – P&A Forum ................................................................... 5
1.1.3 NORSOK D-010 and requirements ........................................................................................ 6
1.1.3.1 Well barrier ........................................................................................................ 7
1.1.3.2 Well barrier schematic ...................................................................................... 8
1.1.3.3 Well barrier requirements in P&A ..................................................................... 9
1.2 Conventional approach to P&A in Norway .................................................................................... 12
1.3 A revolutionary approach to P&A .................................................................................................. 14
2. Technologies ....................................................................................................................................... 17
2.1 Wireline.......................................................................................................................................... 17
2.1.1 Well integrity logging .......................................................................................................... 23
2.1.1.1 Multifinger caliper log ..................................................................................... 23
2.1.1.2 Ultrasonic technology for leak and annular flow detection ............................ 25
2.1.1.3 Electromagnetic defectoscope for corrosion detection.................................. 26
2.1.1.4 Cement evaluation .......................................................................................... 28
2.2 Bullheading cement through tubing .............................................................................................. 30
2.2.1 Improved through XT cement plug placement method ..................................................... 31
2.3 Coiled tubing .................................................................................................................................. 34
2.3.1 Cementing through Coiled Tubing ...................................................................................... 36
2.3.2 Coiled tubing wellbore cleanout ......................................................................................... 39
2.3.3 Abrasive cutter deployed via Coiled Tubing ....................................................................... 41
2.4 Section milling ................................................................................................................................ 42
2.5 Perforate, Wash and Cement ........................................................................................................ 43
3. Emerging P&A technologies ................................................................................................................ 47

III
 3.1 Electric plasma miller ..................................................................................................................... 47
3.1.1 Electric plasma .................................................................................................................... 47
3.1.2 Plasma miller for P&A ......................................................................................................... 52
3.1.3 Research and development of electric plasma miller......................................................... 56
3.2 Thermite plug ................................................................................................................................. 58
3.2.1 Thermite .............................................................................................................................. 58
3.2.2 Thermite for wellbore sealing in P&A ................................................................................. 63
3.2.3 Research and development of thermite plug ..................................................................... 65
4. Case studies ........................................................................................................................................ 69
4.1 Plug and abandonment of well A-1 ............................................................................................... 71
4.1.1 Conventional approach to P&A A-1 .................................................................................... 75
4.1.2 Rigless approach to P&A A-1 using emerging technologies ............................................... 77
4.1.2.1 Discussion on rigless approach to P&A A-1 .......................................................... 79
4.2 Plug and abandonment of well A-2 ............................................................................................... 81
4.2.1 Conventional approach to P&A A-2 .................................................................................... 85
4.2.2 Rigless approach to P&A A-2 using emerging technologies ............................................... 87
4.2.2.1 Discussion on rigless approach to P&A A-2 .......................................................... 90
4.3 Plug and abandonment of well A-3 ............................................................................................... 93
4.3.1 Conventional approach to P&A A-3 .................................................................................... 97
4.3.2 Rigless approach to P&A A-3 using emerging technologies ............................................. 100
4.3.2.1 Discussion on rigless approach to P&A A-3 ........................................................ 101
5. Results and Discussion .......................................................................................................................... 103
5.1 Electric plasma miller ...................................................................................................................... 103
5.2 Thermite plug .................................................................................................................................. 104
5.3 Rigless P&A using Well Intervention equipment ............................................................................ 106
6. Summary ............................................................................................................................................... 109
7. Future research ..................................................................................................................................... 111
8. Reference list ........................................................................................................................................ 112
Appendix ................................................................................................................................................... 119
Appendix A: WBS status prior to P&A................................................................................................... 119
Appendix B: WBS status after pre-P&A operation................................................................................ 120

IV
Appendix C: WBS status prior to P&A, BOP installed ........................................................................... 121
Appendix D: WBS status permanent P&A completed .......................................................................... 122
Appendix E: Time estimate A-1 Jack-up rig operation .......................................................................... 123
Appendix F: Detailed step list for A-1 Rigless P&A approach ............................................................... 124
Appendix G: Time estimate A-2 Jack-up rig operation ......................................................................... 129
Appendix H: Detailed step list for A-2 Rigless P&A approach............................................................... 130
Appendix I: A-2 Partial Rigless approach to P&A .................................................................................. 136
Appendix J: Time estimate A-3 Jack-up rig operation........................................................................... 138
Appendix K: A-3 Partial Rigless approach to P&A ................................................................................. 139

V
List of Figures

Figure 1.1: P&A square. .................................................................................................................. 2

Figure 1.2: Statoil P&A improvement plan ..................................................................................... 4
Figure 1.3: Statoils well configuration complexity pie chart with regards to future P&A. ............. 5
Figure 1.4: PAF Roadmap for new P&A technologies ..................................................................... 6
Figure 1.6: Example of a well barrier schematic ............................................................................. 8
Figure 1.7: Cross-sectional barrier sealing both vertically and horizontally .................................. 9
Figure 1.8: Common well barrier – cement plug. ......................................................................... 10
Figure 1.9: Rowan Gorilla P&A operation on Ekofisk A 2016 ....................................................... 12
Figure 2.1: Slickline, braided line, monoconductor and multiconductor cable, respectively. ..... 19
Figure 2.3: Example WBS when running WL through surface XT ................................................. 21
Figure 2.4: Wireline rig up illustration. ......................................................................................... 22
Figure 2.5 Picture of a 24 and 40 finger multifinger caliper tool.................................................. 24
Figure 2.6 Sample of a caliper survey in a sliding side door with 3D view. .................................. 24
Figure 2.7: Possible leak points and flow paths detectable by the Point system ........................ 25
Figure 2.8: Leak detection example. ............................................................................................. 26
Figure 2.9: (Top) Electromagnetic defectoscope tool design; (Bottom) Tool specifications ....... 27
Figure 2.10: Displacement sequence in cement squeeze bullheading ........................................ 30
Figure 2.11: (Left) Schematic of cement spool; (right) Spool rigged up ....................................... 31
Figure 2.12: (Left) Upper and lower wiper plugs; (Right) Illustration of cross-sectional barrier
formed by the method ............................................................................................ 33
Figure 2.13: (Left): Typical coiled tubing rig up. (Right): Hydraulic power driven chain. Injector
head consists of two chains clamping around the coil. .......................................... 34
Figure 2.14: Idealized cement placement procedure ................................................................... 37
Figure 2.15: Cementing dart. ........................................................................................................ 36
Figure 2.17: Typical stages of a wiper trip clean-out method ...................................................... 40
Figure 2.18: CT abrasive perforation head after completed job .................................................. 41
Figure 2.19: (Left) Cutter/“knife”; (Right) section mill tool ......................................................... 42
Figure 2.21(a): PWC using jet system and two trip approach. Step 1-4 ....................................... 44
Figure 2.21(b): PWC using jet system and two trip approach. Step 5-7....................................... 45
Figure 3.1: Difference in plasma shape, (Left) narrow conventional plasma flow – (Right) Electric
arc area-wide plasma flow. ..................................................................................... 48
Figure 3.2: Spectra analysis hierarchy .......................................................................................... 48
Figure 3.3a: Illustration of different volumetric thermal expansion of multilayered structures in
a microstructural perspective.................................................................................. 50

VI
Figure 3.3b: Mechanical stress due to temperature increase on a microstructural level, leading
to disintegration of metal, caused by difference in thermal expansion coefficient
between layers. ....................................................................................................... 50
Figure 3.4: Alternative solution to section milling by use of plasma miller conveyed by CT ....... 52
Figure 3.5: Umbilical for testing of plasma miller ........................................................................ 53
Figure 3.6a: (Left) Cuttings generated during plasma milling in water environment;
(Right) Cuttings size distribution. ............................................................................ 54
Figure 3.6b: (Left) Typical shape of cuttings;(Right) Cuttings distribution in brine environment 55
Figure 3.6c: Samples of cuttings after test done in high pressure (20MPa) brine environment. 55
Figure 3.7: Time evolution of casing milling in air environment .................................................. 56
Figure 3.8: Water environment casing milling setup and results. ............................................... 56
Figure 3.9: Plasma-based milling generator submerged in brine environment; milling specimen
on far right .............................................................................................................. 57
Figure 3.10: Illustration of the activation energy needed to initiate the thermite reaction . ..... 59
Figure 3.11: Combustion velocity of (2Al + Fe2O3) diluted with 30 wt% (Al2O3) as a function of
inert ambient pressure . .......................................................................................... 60
Figure 3.12: Pressure-temperature phase diagram showing the critical point and area of
supercritical fluid .................................................................................................... 60
Figure 3.13: Granitic intrusion in a metamorphosed sedimentary rock ..................................... 61
Figure 3.14: Fractional crystalization according to temperature. ................................................ 62
Figure 3.15: (Left) Factors affecting melting temperature of rocks. (Right) Granite pegmatite
vein. ......................................................................................................................... 62
Figure 3.16: (Left): Plug emplacement technique, (Right): Illustration of the resulting plug using
a thermite reaction . ................................................................................................ 63
Figure 3.17: (Left) Adiabatic reaction temperature as a function of dilution by aluminum oxide.
Plateau at 2100°C represents the melting temperature of aluminum. (Right)
Thermal plug sample removed from granite block test very fine matric structure
due to diluted mixture ............................................................................................ 65
Figure 3.18: Increasing dilution of the system with a low melt temperature oxide (silica) yielded
low permeability in confined tests .......................................................................... 66
Figure 3.19: Pressure cell built to simulate wellbore environment to research reaction in well
condition ................................................................................................................. 67
Figure 3.20: Pilot well verification method and acceptance criteria ........................................... 68
Figure 3.21: Thermite plug field trial results as of October 2016 ................................................ 68
Figure 4.1: Well schematic A-1. .................................................................................................... 71
Figure 4.2: WBS of A-1 prior to P&A operation. ........................................................................... 74
Figure 4.3: WBS of A-1 after jack-up rig plugging operation. ....................................................... 76
VII
Figure 4.4: WBS of A-1 after rigless P&A operations. ................................................................... 78
Figure 4.5: Well schematic A-2. .................................................................................................... 81
Figure 4.6: WBS for status of A-2 prior to P&A operation. ........................................................... 84
Figure 4.7: WBS of A-2 after jack-up rig plugging operation. ....................................................... 86
Figure 4.8: WBS of A-2 after rigless P&A operation. .................................................................... 89
Figure 4.9: Rigless approach to plug reservoir using thermite plug set on WL. .......................... 92
Figure 4.10: Well schematic of A-3. .............................................................................................. 93
Figure 4.11: WBS of A-3 prior to P&A operation. ......................................................................... 96
Figure 4.12: WBS of A-3 after jack-up rig plugging operation. . ................................................... 99
Figure 4.13: WBS of A-3 after rigless P&A of reservoir and OBF #1.. ......................................... 102

VIII
List of Tables

Table 1.1: Tabulated P&A square ................................................................................................... 2

Table 1.2: P&A phases. Adapted from Oil & Gas UK ..................................................................... 3
Table 1.3: Summary of P&A WBE requirements and key notes stated in the Element Acceptance
Criteria (EAC) ............................................................................................................... 11
Table 1.4: Jack-up rig based P&A advantages and limitations. .................................................... 14
Table 2.1: List of typical wires used in a wireline operation, examples of jobs performed and
advantages and limitations for the different cables. ................................................... 18
Table 2.2: Wireline advantages and limitations ........................................................................... 22
Table 2.3. List of available multifinger calipers and their measurement range ........................... 23
Table 2.4 Multifinger Caliper tool advantages and limitations .................................................... 24
Table 2.5: Ultrasonic leak and flow detection tool advantages and limitations .......................... 26
Table 2.6: Smallest metal losses and corrosion degree detected by the electromagnetic
defectoscope ................................................................................................................ 27
Table 2.7: Electromagnetic defectoscopy corrosion detection tool advantages and limitations 28
Table 2.8: Cement evaluation tool advantages and limitations ................................................... 29
Table 2.9: Bullheading cement through X-mas tree, advantages and limitations ....................... 31
Table 2.10: Bullhead cement TT & XT using wiper plugs, advantages and limitations. ............... 33
Table 2.11: Coiled Tubing advantages and limitations ................................................................. 35
Table 2.12: Typical freefall flow rates and velocities for cement and water in CT ...................... 37
Table 2.13: Coiled Tubing cementing advantages and limitations ............................................... 38
Table 2.14: Coiled Tubing hole cleaning advantages and limitations........................................... 40
Table 2.15: Coiled Tubing abrasive cutter advantages and limitations ........................................ 41
Table 2.16: Section milling advantages and limitations ............................................................... 43
Table 2.17: Perforate, Wash and Cement advantages and limitations ........................................ 45
Table 3.1: Electric plasma miller advantages and limitations ...................................................... 57
Table 3.2: Ultimate unconfined compressive strength of thermite plug samples. ...................... 66
Table 3.3: Thermite plug advantages and limitations .................................................................. 68
Table 4.1: Challenges with rigless P&A and possible solutions .................................................... 70
Table 4.2: A-1 Well summary table............................................................................................... 72
Table 4.3: A-2 Well summary table............................................................................................... 82
Table 4.4: A-2 Pore pressure and fracture pressures given in equivalent mud weight ............... 82
Table 4.5: A-3 well summary table ............................................................................................... 94
Table 4.6: A-3 Pore pressure and fracture pressures given in equivalent mud weight. Minimum
setting depth calculated, as for A-1, and given in table............................................... 95

IX
Abbreviates

A: Ampere

ASV: Annulus safety valve

BHA: Bottom hole assembly

BOP: Blow out preventer

bpm: Barrels per minute

CBL: Cement bond log

CIV: Chemical injection valve

Csg.: Casing

CT: Coiled tubing

DECT: Downhole electric cutting tool

DHPG: Down hole pressure gauge

DHSV: Down hole safety valve

DP: Drill pipe

FIT: Formation integrity test

Fm.: Formation

GLV: Gas lift valve

HC: Hydrocarbon

HUD: Hold up depth

ID: Inner diameter

JIP: Joint industry project

kg: Kilo gram

LOT: Leak off test

X
LPM: Liters per minute

m/min: Meters per minute

m: Meter

MD: Measured depth

MFC: Multifinger caliper

MJ: Mega joule

MW: Megawatt

NCS: Norwegian continental shelf

NOG: Norwegian Oil & Gas Association

NOK: Norwegian kroner

NPD: Norwegian Petroleum Directorate

NUI: Normally Unmanned Installation

OBF: Overburden formation

OD: Outer diameter

P&A: Plug and abandonment

PAF: P&A Forum

PCE: Pressure control equipment

PDM: Positive displacement motor

ppf: Pounds per foot

PSA: Petroleum Safety Authority

PT: Pressure test

PWC: Perforate, Wash & Cement

R&D: Research and development

RCT: Radial cutting torch

XI
RKB: Rotary kelly bushing

ROP: Rate of penetration

s: Second

SBT: Segmented Bond Tool

SCP: Sustained casing pressure

SPF: Shot per foot

SPM: Side pocket mandrel

SRR: Steel removal rate

TD: True depth

TOC: Top of cement

TT: Through tubing

UiS: Universitetet i Stavanger

V: Volt

VDL: Variable density log

W: Watt

WBE: Well barrier element

WBM: Water based mud

WBS: Well barrier schematic

WEG: Wireline entry guide

WHP: Well head pressure

WL: Wireline

WOC: Wait on cement

XT: X-mas tree

XII
 1. Introduction

1.1 Introduction to P&A

Over 2500 wells on the Norwegian Continental Shelf (NCS) will at some point have to be
permanently plugged and abandoned (Spieler and Monge Øia 2015). Well plug and
abandonment (P&A) activities are estimated to contribute up to 50% of the total
decommissioning cost of oil & gas fields (Oil & Gas UK 2016). Cost estimates as high as 900
billion Norwegian kroner (NOK) have been presented based on the P&A operations taking in
excess of 40 years to complete using today’s technology (Myrseth et al. 2017). Because of the
current Norwegian tax regulations the state will have to indirectly pay 78% of the upcoming
P&A cost. Although most of the attention has focused on the time and cost of P&A, it is
important to remember that the primary objective of a P&A operation is to restore the cap rock
functionality with a barrier, which can withstand for eternity.

1.1.1 General
By combining some of the definitions in NORSOK D-010 (2013a) and Oil & Gas UK (2012) one
could say that a permanent plug and abandonment operation is: A sequence of planning and
execution of tasks, which are carried out to secure a well by installing required well barriers,
permanently sealing a source of inflow to obtain a well status where the well will not be used or
re-entered again. A well can be temporarily or permanently plugged and abandoned. In this
thesis, P&A is referred to permanent P&A unless otherwise specified.

When working in accordance with NORSOK D-010 (2013a) the key feature is the annular barrier.
This needs to be in place and verified. If this is not the case, a series of activities must be
executed to get access to the annulus to establish a cross-sectional barrier.

1
A major operator on the NCS has implemented the “P&A square” to visualize the process and
steps needed to obtain a permanent well barrier, Figure 1.1 (Hovda 2017).

Figure 1.1: P&A square (Hovda 2017).

Each of the elements in the P&A square, with explanation of possible operations to achieve the
objective, are shown in more detail in Table 1.1.

Table 1.1: Tabulated P&A square

P&A square objective Possible activity to obtain objective
 Pull tubing
Remove or open steel  Section mill casing to access formation
 Perforate casing to access formation
Clean out the plug setting  Clean out run after section mill
area  Cup or Jet wash behind perforations
Set the plug  Cementing
 Pressure test
Verify the result  Dress off and tag
 Drill out and log after PWC operation

2
With the requirements listed in NORSOK D-010 (2013a) and the current technologies most P&A
operations are drill pipe (DP) based to complete all sides of the P&A square. Some through
tubing (TT) technologies are available, but none can yet do the whole operation. Although TT
technologies can place the reservoir plugs in some wells, in most cases the intermediate plugs
still need a rig to complete the whole P&A square. The P&A operations can be divided into
three phases as presented in Table 1.2 (Oil & Gas UK 2012).

Table 1.2: P&A phases. Adapted from Oil & Gas UK (2012)
Phase Operations included
Primary and secondary permanent
barriers are set to isolate all reservoir
producing or injecting zones. The tubing
Phase 1 - Reservoir abandonment
may be left in place, partly or fully
retrieved. Complete when the reservoir
is fully isolated from the wellbore.
Includes: milling and retrieving casing,
and setting barriers to intermediate
hydrocarbon or water bearing zones
and potentially installing near-surface
Phase 2 - Intermediate abandonment
cement. The tubing may be partly
retrieved, if not done in phase 1.
Complete when no further plugging is
required.
Phase 3 - Wellhead and conductor Wellhead and conductors are cut and
removal removed.

As phase 2 requires a rig for pulling tubular and milling, the rig is commonly used for phase 1 as
well. The drilling rigs choice will be dependent on infrastructure, whether to choose the existing
platform drilling derrick (if installed), a modular rig or a jack-up rig. In the continuation of this
thesis conventional P&A will refer to a jack-up rig P&A operation.

The cost estimations mentioned above are based on a well taking 35 rig days on average to
complete (Myrseth et al. 2017). In the past decade, great improvements have been done with
regards to the time spent on a P&A operation. From the section milling based operation in 2008
taking 65 days on average (Scanlon et al. 2011), to the perforate, wash & cement (PWC)
presented by Ferg et al. (2011) reducing the plug setting time from 10.5 days to 2.6 days, and
ending up with the Statoil P&A statistics for 2016 with an average of 17.6 days per well
(Hemmingsen 2017). The numbers presented might not be fully representative for the NCS as a
whole, but provides a picture of the improvements made. A key question in the P&A industry is:

3
What is the technical limit for a rig based P&A approach, and will a TT option be competitive on
time and cost once the technical limit is reached?

Figure 1.2: Statoil P&A improvement plan (Hemmingsen 2017)

Figure 1.2 illustrates Statoil’s three levels of improvement in P&A.

 Level 1 Improvement: Finding the best practice and procedures for conventional P&A
operations. Improving efficiency.
 Level 2: Technical Limit: Incremental technologies, finding a more effective way of
completing a task. PWC is a good example where time used for P&A is reduced
drastically.
 Level 3: Game changing: Radical technologies will include some of the solution
proposed for rigless P&A operations.

As technology improves and a Game changing approach becomes commercially viable, several
wells could possibly be plugged TT. By categorizing well plugging complexity, as done by Statoil
in Figure 1.3, candidate wells for a rigless approach will emerge. Approximately 45% of the
wells are categorized as “simple”, while 25% are regarded “medium” complexity. The major
part of these wells could possibly be plugged utilizing a rigless approach. More complex wells
might still need a rig also in the future.

4
Figure 1.3: Statoil’s well configuration complexity pie chart with regards to future P&A. Pie
showing Statoil platform wells only (Hemmingsen 2017)

1.1.2 Norwegian Oil & Gas Association – P&A Forum

The Norwegian Oil & Gas (NOG) P&A Forum (PAF) was established in 2009 after an initiative
from a single operator hosting a P&A workshop (Straume 2012). One of PAF's focus areas is
improvement in technical solutions for upcoming P&A operations. In 2015 the Roadmap for
New P&A Technologies was presented at the PAF Seminar (Straume 2015). The roadmap
illustrates the focus areas for the coming years with regards to technology innovation. Well
intervention technology for P&A and Rigless P&A are some of the main areas of improvement,
as highlighted in Figure 1.4. The potential savings could be significant as the rig rate contributes
to 40%-50% of the total P&A cost (Straume 2016). With that in mind, this thesis will focus on
using well intervention technology to P&A wells without the use of rig. Both existing and
emerging technologies, such as futuristic high energy solutions and extreme concepts, will be
presented in chapters 2 and 3. The aim is to plug wells through X-mas tree (XT) and through
tubing. Leaving the X-mas tree in place will enable it to be used as a part of the well barrier
envelope during P&A operations.

5
 Figure 1.4: PAF Roadmap for new P&A technologies. Well Intervention technology for P&A
and Rigless P&A highlighted and will be further investigated throughout this thesis
(Straume 2016)

1.1.3 NORSOK D-010 and requirements

Before suggesting through tubing P&A solutions one needs to have an in-depth knowledge of
the current regulations and requirements. The regulations refer to norms and industry
standards indicating the features which solutions are expected to meet as a minimum
(Gundersen 2017). One such industry standard is NORSOK D-010 (2013a), Well integrity in
drilling and well operations. Compliance with NORSOK D-010 (2013a) will also comply with the
Norwegian regulations. Similarly Oil & Gas UK (2012a) has implemented a P&A guideline called
Guidelines for Suspension and Abandonment of Wells. These standards and guidelines are
essentially similar and aim for the prevention of (Khalifeh 2016):

 Hydrocarbon and water leakage to the surface

 Hydrocarbon movement between strata
 Contamination of water-bearing zones
 Pressure breakdown (fracture initiation) of shallow formations.

As this thesis will review P&A operations in Norway the following sections will focus on the P&A
barrier requirements set in NORSOK D-010 rev. 4 (2013a).

6
 1.1.3.1 Well barrier
To achieve the objectives listed in the above section, it is necessary to install a well barrier. A
well barrier is an envelope of one or several well barrier elements. A well barrier element (WBE)
is a physical element which in itself does not prevent flow, but in combination with other
elements will form a well barrier. The well barriers shall be independent of each other and one
should avoid having common WBEs to the extent possible. Barriers used in P&A shall have a
specific set of characteristics, and elastomers are not allowed as sealing component (NORSOK
2013a).

NORSOK D-010 (2013a) states that there shall be minimum two barriers for hydrocarbon
bearing formations and in abnormally pressured formations with potential to flow to surface.
These two barriers are referred to as primary and secondary barrier, as illustrated in Figure 1.5.
Primary and secondary barrier is defined as; first-, and second well barrier that prevents flow
from a potential source of inflow, respectively (NORSOK 2013a). A simpler way to describe this
is; Primary: in direct contact with the pressure, Secondary: “Your last defense” (Fjågesund
2017). The reason for calling it the last defense is that in many well operations several barriers
exist that can act as secondary barriers, but only the last defense is listed and defined as a
secondary barrier. For example in a drilling well control situation, in most cases one can close
the annular barrier to regain control, but only the shear and seal ram is defined as the
secondary barrier.

Figure 1.5: The two barrier philosophy is often referred to as “Hat over hat principle”. The
figure shows the secondary barrier as a red hat over the primary barrier blue top hat
(Fjågesund 2017).

7
 1.1.3.2 Well barrier schematic
A well barrier schematic (WBS), illustrated in Figure 1.6, is used to define the well barriers in
any phase of a well life cycle. The WBS shows all WBE in place, their acceptance criteria and
monitoring and/or verification method (NORSOK 2013a). In addition, it shows the envelope
present for both the primary (blue) and the secondary (red) well barriers. The well barrier
schematics have several advantages (Fjågesund 2017):

 Clear description of WBE and envelopes

 Clear graphics will help discussions and to see challenges
 Clear description of qualification and monitoring methods
 Consistent graphics and language
 Common understanding, everyone sees the same picture
 Document compliance

Figure 1.6: Example of a well barrier schematic (NORSOK D-010 2013).

8
 1.1.3.3 Well barrier requirements in P&A
When designing a P&A well barrier, it shall withstand the maximum differential pressure to
which it may become exposed to. In addition it needs to be pressure tested and tagged, as
tabulated in Table 1.3. According to NORSOK (2013a) a permanently abandoned well shall be
plugged with an eternal perspective with regards to chemical and geological processes and re-
charge of formation pressure.

A full cross-sectional barrier is one of the main principles when plugging wells. The barrier shall
extend all the way from the formation, including all annuli, and sealing both horizontally and
vertically as shown in Figure 1.7 (NORSOK 2013a). It is important that the barrier is placed
adjacent to an impermeable formation with sufficient formation strength to withstand
maximum anticipated pressure. Formation strength data is collected during the drilling phase
by performing leak off test (LOT) or formation integrity test (FIT). Another important note is the
removal of downhole equipment to achieve a full cross-sectional barrier. Control lines and
cables shall not form a part of a permanent well barrier (NORSOK 2013a). This requirement
along with the verification of annular barrier are the main challenges when aiming for rigless
and TT P&A.

Figure 1.7: Cross-sectional barrier sealing both vertically and horizontally (NORSOK
2013a).

External WBE. To obtain a cross-sectional barrier one of the key challenges when working in
accordance with NORSOK D-010 (2013a) is the annular barrier and its verification. It is accepted
to use the same casing cement as a WBE in both primary and secondary barrier, as long as it is
logged and verified with 2 x 30m measured depth (MD) intervals of bonded cement. If the
cement is not logged, the requirement is 50m with sufficient formation integrity at the base of

9
the interval. If sustained casing pressure is observed, the seal of the casing cements shall be
verified (NORSOK 2013a).

Internal WBE. The internal barrier plug shall be placed over the same area as the external
barrier to create a cross-sectional barrier. A minimum of 50 m is to be set when using a
mechanical plug as foundation for the cement plug. It is possible to use a continuous cement
plug, sometimes referred to as a “back-to-back” plug, as both primary and secondary barrier
inside the casing as well. In these cases the plug is called a common well barrier element. A
continuous cement plug, as illustrated in Figure 1.8, will have to be drilled out until hard
cement is confirmed for plug verification (NORSOK 2013a).

Figure 1.8: Common well barrier – cement plug (NORSOK 2013a).

Table 1.3 lists requirements set in NORSOK D-010 (2013a) for cement WBE. The table will help
determine if a rigless approach could place a barrier according to the given standard. With the
table in mind the next section will present how a typical NCS platform well is permanently
plugged using a jack-up rig.

10
Table 1.3: Summary of P&A WBE requirements and key notes stated in the Element
Acceptance Criteria (EAC) (NORSOK 2013a):
Length Verification General
External WBE requirement method requirements
Displacement Placed above a
50m MD calculations from potential source of
primary cement job inflow.
Single barrier
Formation integrity
Annular Cement

30m MD Bond logs

shall exceed the
maximum expected
Displacement pressure at base of
2 x 50m MD calculations from each interval
primary cement job
Dual barrier

2 x 30m MD Bond logs

Length Verification General

Internal WBE requirement method requirements
Minimum 50m MD
Single barrier 100m MD Tagging above any source of
Open hole cement plug

inflow
Single barrier Minimum 50m MD
Tagging and above and below
in transition
100m MD pressure testing casing shoe. PT to 70
from open
(PT) bar above LOT
hole to casing
Set on a foundation
2 x 100m MD with
(True depth (TD) or a
Dual barrier 50m MD into the Tagging and PT
cement plug). PT to
casing
70 bar above LOT
Cased hole cement plug

50m MD if set on Only tagging if set

mechanical/cement on pressure tested
Single barrier plug as foundation, foundation,
otherwise 100m otherwise tag and
MD PT
Drill out cement Set on a pressure
Dual barrier 2 x 50 m MD until hard cement tested foundation.
confirmed.
50m MD if set on a Pressure test to 35
Open
mechanical plug, bar
hole to Single barrier Tagging and PT
otherwise 100m
surface
MD

11
 1.2 Conventional approach to P&A in Norway
The requirement for a cross-sectional barrier and the verification criteria will, in most P&A
operations, reveal the need of a rig. As there is no dual-string casing cement (annular barrier)
logging tool qualified, the production tubing has to be pulled to access the casing in question
(Moeinikia et al. 2014). Another reason for pulling tubing is the control lines or cables
connected to downhole pressure gauge (DHPG) or other downhole equipment needs to be
removed. They shall not form part of a P&A plug as stated in section 1.1.3.3. If there is no
annular barrier present in the desired plug setting interval then either section milling or
perforate, wash & cement (PWC) technology must be applied to achieve the desired cross-
sectional barrier (Ferg et al. 2011). Both section milling and PWC are rig based technologies in
need of torque, relatively high axial load capacity and fluid circulation for hole cleaning. Figure
1.9 shows a jack-up rig skidded over a platform for P&A purposes.

Figure 1.9: Rowan Gorilla P&A operation on Ekofisk A 2016 (Hovda 2017)
12
In a platform environment with a vertical XT the XT needs to be replaced with a drilling BOP
before any rig based P&A operation can commence. As the XT is a part of the barrier envelopes
during the production phase, a series of activities needs to be executed before it can be
replaced. This operation, performed to comply with the two barrier philosophy, could be
referred to as a pre P&A phase or secure well for P&A. This part of the operation is not specified
in UK Oil & Gas (2012) P&A phase coding, Table 1.2.

During batch platform P&A, the pre P&A phase is typically a stand-alone well intervention
operation. An advantage of stand-alone preparations for P&A is that the rig is free to do other
work meanwhile, or to arrive at a later stage to continue the P&A operation. Wireline can be
used to prepare the well for the planned P&A by setting a series of plugs and cutting the tubing.
The primary barrier when nippling up the drilling BOP could either be obtained by bullheading
cement through XT and tubing to squeezing perforations, or by setting a bridge plug in the tail
pipe. A potential step list for mentioned operation is listed below:

 Bullhead seawater or kill fluid into the well.

 Bullhead cement to the reservoir and liner interval.
 Pressure test cement plug.
 Rig up wireline (WL)
 Drift well to hold up depth (HUD)
 Optional: Run a multifinger caliper (MFC) for well diagnostics (Moeinikia et al. 2014)
 Optional if cement plug does not qualify as barrier: Set bridge plug in tail pipe below
production packer. Pressure test plug
 Punch and cut tubing above production packer
 Displace annulus to seawater or kill fluid
 Set shallow “pump open” bridge plug and test same
 Rig down WL

The well is now ready for phase 1-3 of the P&A operation. A rig will be skidded over the well
and a drilling BOP nippled up before commencing. WBS examples with the well status before
and after the pre-P&A phase, before phase 1 and after phase 3 can be found in the Appendix A
through D, respectively. These WBS also include tubular sizes corresponding to the step list.

 Nipple down XT, nipple up and test drilling BOP

 Displace well to kill mud
 Pull tubing
 Log annular barrier in 9 5/8” production casing
 Run 9 5/8” clean out run

13
  Optional if no annular barrier in place: PWC or section mill 9 5/8”
 Set primary and secondary reservoir plug
 Set primary and secondary intermediate plug
 Cut and pull 9 5/8” casing (surface plug depth)
 Log 13 3/8” annular barrier if not already verified
 Run 13 3/8” clean out run
 Optional if no annular barrier in place: PWC or section mill 13 3/8”
 Set surface plug
 Cut and pull casing and conductors subsea

A similar P&A procedure is also presented by Moeinikia et al. (2014), although for a subsea well
from a semi-sub rig most of the subsurface activities will be the same for a platform well. A list
of advantages and limitations on rig based approach to phase 1-3 P&A are presented in Table
1.4.

Table 1.4: Jack-up rig based P&A advantages and limitations.

Advantages Limitations
 High axial pulling capacity  Cost
for pulling tubular  High rig cost will lead to cost
 Torque capability for steel of having backup equipment
Jack-up rig P&A operation

removal for all contingencies on site

 Pumping capability for (overhead cost)
clean out runs and debris  Mobilization/demobilization
transportation time
 Mud system to handle open  Availability depending on
hole conditions (pore market
pressure/hole stability)
 Brings its own
infrastructure, deck space,
accommodation etc.
 Efficient at rig activities like
tripping pipe

1.3 A revolutionary approach to P&A

A rigless through tubing approach could be a cost effective solution for a large portion of the
upcoming P&A operations on the NCS. Fit for purpose P&A, based on the P&A operation
complexity, will according to Statoil be a focus area in the future (Hemmingsen 2017). Different
P&A approaches are used for different wells, and some of the wells categorized as simple in the
configuration complexity pie chart Figure 1.3, could be candidates for a rigless approach. The
main objective of a P&A operation is to place cross-sectional barriers and verify them. To be

14
able to verify the annular barrier, access to the casing in question is needed. The production
tubing needs to be removed somehow downhole without pulling it. Another solution could be
to create a completely new cross-sectional barrier, without use of the existing annular WBE.
Both these approaches could be obtained using technology in the Rigless P&A; High energy
solutions box of the NOG technology roadmap in Figure 1.4. By using field proven off-the-shelf
technologies in combination with some of the emerging technologies in the high energy branch
a rigless approach could be achieved. In Chapter 2 a series of conventional and field proven
technologies and techniques will be presented. Chapter 3 will present two emerging high
energy technologies intended to be applied for rigless P&A. A case study will be presented,
using real well data, where a rigless P&A approach is proposed as an alternative to conventional
P&A.

To limit the scope of this thesis some assumptions and simplifications have been made:

Simplifications:

 Case study done on Norwegian Continental Shelf wells. Plugging method to comply with
NORSOK D-010 (2013a)
 All wells in case study are platform wells
o Based on availability of well data
 Missing data in provided data package are estimated or collected from
NPD fact pages (NPD 2017) for relevant field.
o Well intervention simplified on platform wells, no need for semi-sub rig or light
well intervention vessel and associated equipment
o All case study comparison done to jack-up rig based P&A
o Time estimates of jack-up rig P&A operation are presented in Appendix E, G and
J and are based on a limited number of operations done by a limited number of
operators.
 Only subsurface activities will be thoroughly investigated
o Deck space, accommodation, crane capacity, etc. on platforms is not main part
of the study. These constrains could impose challenges on normally unmanned
installations (NUI) and small wellhead platforms

Assumptions:

 Futuristic/high energy technologies presented are assumed to work as intended once

commercialized.
 These techniques and technologies will be qualified for P&A operations.

15
Intentionally left blank

16
 2. Technologies
A well intervention consists of a well servicing operation conducted within a completed
wellbore (NORSOK 2013b). A series of more or less conventional technologies that could be
interesting in a rigless TT P&A perspective will be briefly described below. This chapter is meant
to give an overview with a short introduction, of what is available today. Most of these
technologies have been thoroughly described by other in the past, and the interested reader is
referred to the reference literature for a more detailed description. Advantages and limitations
regarding the various technologies for P&A applications are tabulated in the end of every
section.

2.1 Wireline
WL could be referred to as a cabling technology used to convey equipment into the well for
well intervention purposes. A wireline unit with associated equipment is used to deploy a tool
string to desired depth by use of gravity. A wireline package is relatively small and easy to rig up
compared to other well intervention alternatives such as coiled tubing (CT) or snubbing units.
One could say that wireline is a light well intervention, while CT and snubbing are medium- and
heavy well intervention, respectively. A typical WL package will consist of a WL unit with cables,
pressure control equipment (PCE) with pumps and panels (known as surface equipment) and
downhole tools. A range of different cables could be installed into the WL unit depending on
the planned operation. Wireline cables could be divided into three sub divisions; slickline,
braided line and electric line, pictured in Figure 2.1. Each cable has its own applications and
limitations, according to Table 2.1.

17
 Table 2.1: List of typical wires used in a wireline operation, examples of jobs performed
and advantages and limitations for the different cables (Camesa 2016).
Breaking
Typical
strength Typical job Advantages Limitations
size
[lbs]
Mechanical wireline
- Drift run - High tripping - Low breaking
- Set/pull plug/DHSV – speed strength
Side pocket mandrel - Low cable weight - Limited lifetime
(SPM) operations - Optimal for
Slickline 0.125" 3800
- Memory logging tool manipulation work
conveyance (jarring)
- No grease head
- Low cost
- Heavy mechanical - High breaking - Lower tripping
jobs in deep wells strength compared speed
Braided line 7/32" 8800
- Fishing to slickline - Need of grease
injection head
Electrical wireline
- Correlation for depth - Real time data - Limited telemetry
verification transfer. bandwidth
E-line,
5/16" 12000 - Caliper log - Designed for PCE compared to
Monoconductor - Tractor conveyance compatibility (flow slammer cable.
- Perforation tubes)
- Annular Cement - High telemetry - Challenge to run
E-line,
0.46" 19100 logging bandwidth due to in live high
Multiconductor - Open hole logging several conductors. pressure wells

18
 Figure 2.1: Slickline, braided line, monoconductor and multiconductor cable, respectively.

A slickline can be described as a small continuous solid strand of steel, Figure 2.1. A set of
rubber packings in the stuffing box seal around the slick surface and contains the well pressure.
Mechanical wires, as slickline and braided line, have a safe pull in the range of 50% to 75% of
breaking strength based on service company policies. Braided- and electric lines are stranded
wires. Because of the voids between the strands, the use of a rubber seal is not possible.
Instead a seal is created by a grease injection head where the wire is run through several flow
tubes, which have between 0.004”-0.006” larger inner diameter (ID) than the wire outer
diameter (OD). By constantly pumping a high viscous fluid (wireline grease), the small clearance
in combination with the high viscosity fluid will create a pressure drop over the flow tubes. The
typical safe pull for e-line cables is 50% of breaking strength. In some regions of the world, all
mechanical wireline operations are referred to as slickline while e-line operations are referred
to as wireline. In the continuation of this thesis, wireline will be referring to both slickline and e-
line operations.

19
With mechanical wireline, a set of jars are used in combination with weight bars (stems) to
manipulate downhole tools by use of gravitational impact force. It is also possible to include
jars for upward impact. By adding an accelerator to the tool string, potential energy is stored in
the accelerator springs and released in combination with the jar activation. Upward impact
force in excess of 200.000 lbs can be achieved with the correct cable and tool string setup,
mostly for fishing applications. Conventional mechanical wireline is normally limited to a
maximum of 65° well inclination due to frictional resistance between tool string and tubing wall.
Tool strings have been deployed to deviations of more than 82° inclination assisted by gravity
alone using low friction rollers (Al-Dhufairi et al. 2008). On a general basis extended reach and
high deviation wells, in excess of 65°, require a well tractor.

A well tractor is a wireline-deployed self-propelled robotic device that will transport the tool
string to the end of the wellbore if it is not possible to reach by gravity (Schwanitz and
Henriques 2009). Before it was introduced in the late 90s, access to horizontal boreholes was
only possible by coiled tubing or snubbing units. Well intervention in high deviation wells
quickly shifted towards wireline tractor once it was introduced, Figure 2.2. In 2003, mechanical
services on WL tractor were introduced including milling and stroker. The wireline stroker, a
hydraulic piston, is normally used for setting and pulling plugs and can provide an axial force of
up to 33,000 lbs (Schwanitz and Henriques 2009).

Figure 2.2: The changing composition of Statoil`s well interventions. (Schwanitz and
Henriques 2009)

20
The high flexibility of a modular based wireline package makes it possible to rig up almost
anywhere. Wireline can be rigged up stand-alone using a WL mast, through a CT tower or in a
drilling derrick. The WL PCE is rigged directly on top of XT, consisting of stuffing box or grease
injection head, lubricator, BOP and riser. This setup makes it possible to lubricate in and run
tool strings in live pressurized wells while working in accordance with the two-barrier
philosophy, illustrated in Figure 2.3. A typical setup showing WL unit and the PCE rig up with
mast is pictured in Figure 2.4.

Figure 2.3: Example WBS when running WL through surface XT (NORSOK D-010 2013a)

Some of the applications available by wireline will be presented in the following sections. A
brief introduction to some relevant well integrity logging methods can be found in section 2.1.1.
Basic applications like plug setting, depth correlation and mechanical runs like drift will not be
presented.

21
 Figure 2.4: Wireline rig up illustration. Courtesy of Archer.

Table 2.2: Wireline advantages and limitations

Advantages Limitations
 Relatively quick to rig up.  Relatively low available pull
Wireline Operation

 High tripping speed. force.

 Logging abilities through e-line.  No pumping capability.
 High flexibility on rig-up.  Need for tractor in highly
 Relatively small foot-print and deviated wells.
low unit weights.
 Operated by limited crew.

22
 2.1.1 Well integrity logging
Jain et al. (2016) define Well integrity as: “The ability of a well to function normally within its
design safety factors and to maintain a leak free envelope such that there is no unplanned flow
of fluids from or to any of the strata which the well penetrates or to external environment”.
Several tools can be deployed by wireline for well logging purposes. The results from many of
these logging techniques can be used in well diagnostics to verify well integrity.

2.1.1.1 Multifinger caliper log

The multifinger caliper (MFC) log can provide valuable information regarding tubular shape and
wear. A series of equi-angular-spaced tungsten carbid-tipped fingers are extended until they
contact the tubular inner surface (Sawaryn et al. 2015). By pulling up the tool the individual
moving fingers will survey the well surface and identify pits, holes, perforations or even gross
anomalies like casing deformation caused by tectonic stresses. This makes the caliper survey
ideal for pipe integrity condition monitoring (Farina et al. 2015). Depending on the tubing ID to
be surveyed calipers with 24, 40, 60 or 80 fingers are available as shown in Table 2.3 (Sawaryn
et al. 2015). Calipers do not provide 100% coverage of the well bore as there are gaps between
the fingers, as illustrated in Figure 2.5. At the expense of log resolution and circumferential
spacing extended fingers can be fitted, mostly used when operations require slim tool strings
for well access. Caliper data can be presented as a 2D colored pixel map over some lengths of
the tubing interior or as a 3D image, Figure 2.6. (Farina et al. 2015). Although an excellent tool
for inner casing measurement, it has its limitations as it is a mechanical interface log. It cannot
detect metal loss in the presence of scale, nor can detect corrosion on the pipe outer surface.
Combining the caliper with an ultrasonic or electromagnetic wall-thickness measurement
device could provide corrosion monitoring (Sawaryn et al. 2015). MFC can be run in real-time
surface readout mode on e-line or in memory mode on a mechanical wire.

Table 2.3. List of available multifinger calipers and their measurement range
(Sawaryn et al. 2015).

23
Figure 2.5 Picture of a 24 and 40 finger multifinger caliper tool (Courtesy of Archer).

Figure 2.6 Sample of a caliper survey in a sliding side door with 3D view (Farina et al.
2015).

Table 2.4 Multifinger Caliper tool advantages and limitations

Advantages Limitations
 Precise measurement of tubular  100% coverage not possible
ID. due to spread in fingers
Multifinger caliper tool

 Easy to operate and use, well  Not able to detect metal loss
known technology. in presence of scale. Scale
 Operates in wide range of well buildup could lead to
conditions, insensitive to misinterpretation.
borehole fluid.  Not able to measure casing
 Can be run in combination with (steel) thickness.
other tools to conceal some of  Not able to measure outer
its limitations. surface corrosion.
 WL tool

24
 2.1.1.2 Ultrasonic technology for leak and annular flow detection
The leak detection tool is a passive listening tool capable of mapping flowing fluids across pipe
walls, but also alongside pipes, as illustrated in Figure 2.7. An ultrasonic sensor, using a
piezoelectric crystal sensing device, can detect a spectrum of frequencies typically produced by
a leak or flow (Johns et al. 2006). A differential pressure across a leak point will produce
powerful ultrasonic acoustic energy. Ultrasonic energy can propagate through steel, water and
compressed gas allowing a radial investigation range of up to 3m. Although ultrasonic energy
will experience high attenuation through these media, the attenuation helps accurately detect
the leak within 1-2 inches, Figure 2.8. The same concept can be applied for annular flow
detection while logging through tubing. The ultrasonic spectrum for annular flow detection will
not only be dependent on differential pressure, leak geometry and rate, but it is also due to
bubble oscillations, bubble collapse, moderate flow, gas breaking out of solution and diameter
of the flow path (Zakaria et al. 2010). The exclusive set of frequencies within the ultrasonic
window can be detected by attuning the sensor to either horizontally leak detection (across
pipe) or vertical annular flow detection (alongside pipe). It is important that the leaks or flows
must be active at the point of logging to be detected. The tool can be run both surface readout
and in memory mode (Zakaria et al. 2010). In the presence of sustained casing pressure (SCP),
this technology could be vital in well diagnostics to categorize the well P&A complexity with
regards to a rigless approach, or not.

Figure 2.7: Possible leak points and flow paths detectable by the Point system (Courtesy of
Archer)

25
Figure 2.8: Leak detection example. Two leaks identified at tubing collars, as per CCL. Three
ultrasonic frequencies are monitored showing the unique spectrum created by active leaks
(Zakaria et al. 2010)

Table 2.5: Ultrasonic leak and flow detection tool advantages and limitations
Advantages Limitations
 Leak and flow  Need active leak or flow. Can
investigation through usually be obtained by
Point technology

several tubulars. manipulating surface

 Locates barrier leaks and pressures.
flow paths downhole.  Data interpretation, high
 Provide clear picture of degree of well
integrity status. understanding and
 WL tool petroleum engineering
needed for flow path
determination.

2.1.1.3 Electromagnetic defectoscope for corrosion detection

The electromagnetic defectoscope can be used to locate and quantify metal loss through as
many as three concentric tubulars. The scanning tool records magnetization decay induced by
high-power electromagnetic pulses. Different pipe diameter will produce different
magnetization decay which makes it possible to distinguish and determine their individual
thicknesses (Ansari et al. 2015). Three concentric pipes can be investigated for corrosion,
erosion or other types of metal loss damages using the technology, but with an increasing error
margin as tabulated in Table 2.6. For triple-barrier logging three sensors are utilized, Figure 2.9,
generating short, medium or long electromagnetic pulses that can be detected. According to

26
Ansari et al. (2015) the operation of the time-domain defectoscope is based on generating
square pulses equivalent to the infinite number of harmonic oscillations. During these pulses
the generating coil will magnetize metal around it. After the pulse ends the magnetization
starts decaying, this is captured as induced current by the receiving coils. Magnetization decay
has a complex time profile and depends on the diameter, electrical conductivity, magnetic
permittivity and thickness of each pipe. The logging data is processed through an algorithm
which will supply a set of data for all three pipes containing; thickness data, conductivity-
permittivity product indicating the metal grade and pipe decentralization profile. Corrosion
detection in two nearby barriers (pipes) can be challenging as the first barrier magnetization
decay is significantly higher than second or third. A defect in the first barrier will complicate the
thickness determination for the second and third barrier (Ansari et al. 2015). The 1-11/16” tool
can be run as a memory tool and can be used for well diagnostic purposes in advance of a P&A
operation. Casing condition can be verified when exposed to sour well fluids such as H2S and
CO2 throughout the casings life time.

Figure 2.9: (Top) Electromagnetic defectoscope tool design; (Bottom) Tool specifications
(Ansari et al. 2015).

Table 2.6: Smallest metal losses and corrosion degree detected by the electromagnetic
defectoscope (Ansari et al. 2015).

27
 Table 2.7: Electromagnetic defectoscopy corrosion detection tool advantages and
limitations
Advantages Limitations
 Insensitive to non-  Slow logging speed (2-4
magnetic scale. m/min).
Electromagnetic defectoscopy

 Can detect metal loss  Insensitive to internal or

(corrosion) in not only external metal loss. Will
tubing, but also second supply absolute average
and third concentric pipe metal loss circumferentially.
(production casing and  Cannot detect holes
intermediate casing).  Defect in first tubular will
 WL tool complicate thickness
detection of 2nd and 3rd pipe
 Two nearby sized tubulars
can be a challenge to
distinguish on log

2.1.1.4 Cement evaluation

One of the methods stated in NORSOK D-010 (2013) for annular barrier verification is logging.
Interpretation of cement evaluation logs is usually based on sonic and ultrasonic principles,
each with its applications and limitations. By combining the cement bond log (CBL) and variable
density log (VDL) technology with ultrasonic azimuthal logs, a more comprehensive cement
evaluation can be achieved (Padilha and Araju 1997). Although initially intended for cement
integrity verification, the CBL/VDL in combination with ultrasonic azimuthal logs have been
applied for creeping shale annular barrier verification (Williams et al. 2009).

Cement Bond Log and Variable Density Log. CBL and VDL are acquired using sonic logging tools
with a monopole transducer and a monopole receiver. The CBL and VDL receivers are placed 3
and 5 ft from the transmitter, respectively. The sonic transmitter emits a low frequency (10-
20kHz) omni-directional pulse that will induce a longitudinal vibration in the pipe. The recorded
data represents an average value over the whole pipe circumference. Generally the CBL logs
the casing-cement bond while the VDL log the cement-formation bond. Bonded casing will lead
to a high attenuation and low amplitude, while a free-pipe will omit “ringing” signals (low
attenuation). The transit time, time taken for the wave to travel from transmitter to receiver, is
used for quality control purposes (Williams et al. 2009).

28
Segmented Bond Tool (SBT) is an alternative to CBL. The SBT uses six pads to measure the
cement bond in six sixty degree segments around the borehole (Tyndall 1990; Bigelow et al.
1990). These pads are in direct contact with the casing wall, and the tool will therefore be less
affected by de-centralization and wellbore fluids. The SBT averages over each segment,
resulting in a more accurate log compared to the CBL which averages over the whole pipe
circumference. The tool can utilize in-line centralizers and log casing sizes in the range of 4-1/2”
to 13-3/8” with the same setup.

Ultrasonic azimuthal bond log use a high frequency pulse echo method to excite the casing
into resonance mode. A rotating transducer that operates from 200 to 700kHz provides a full
coverage of the cement and casing quality, at relatively high vertical and horizontal resolution.
Processing these measurements will yield the casing thickness, internal radius, inner wall
smoothness and an azimuthal image of the acoustic impedance of the material behind the
casing (from signal resonance decay). The acoustic impedance is then classified as that of gas,
liquid or solid depending on readings (Williams et al. 2009)

Although ultrasonic azimuthal logs in general need a multi-conductor cable for high-speed
telemetry, small-diameter circumferential acoustic scanning tools for mono-conductor cable
have been developed (Mandal and Quintero 2010). Most of the data processing job is done
downhole using a digital signal chip and efficient computational algorithms. A mono-conductor
cable usually has better well control performance when running through WL PCE than a
multiconductor cable. In a rigless through tubing P&A perspective the mono-cable compatible
tool could be a viable choice to save time on rigging and drum changes.

Table 2.8: Cement evaluation tool advantages and limitations

Advantages Limitations
 Enables annular barrier  Dependent on skilled personnel for
CBL/VDL and ultrasonic azimuthal bond

verification. log interpretations.

 Technologies fulfill each  Should be run in combination to give a
other. clear picture of barrier status.
 Well proven technology  Ultrasonic azimuthal tools can have
 WL tool challenge in high density mud.
 Ultrasonic azimuthal log rotating head
log

size vs. tubing ID in through tubing

application.
 Sensitive to de-centralization while
logging
 Conventional tools not built for
through tubing applications.

29
 2.2 Bullheading cement through tubing
The pumping operation where fluids are forced down the well by overcoming the reservoir
pressure is called bullheading. Cement squeeze reservoir isolation by bullheading cement
through XT and tubing could be an effective method to place a temporary primary barrier, or
even establishing the primary permanent barrier. High fluid loss rate cement is preferable for
reservoir squeeze jobs to ensure a proper squeeze (Nessa 2012). The lower completion will
affect the applicability of cement bullheading as sand screens and gravel packed wells might
not be the appropriate candidates. Volume control is crucial for a successful cementing job, and
data obtained during a MFC run can be used in well volume calculations. Nessa (2012) describes
the pumping sequence as following: Spacer is pumped ahead of the cement, then fresh water,
then the cement, then fresh water behind the cement. After the fresh water, displacement fluid
will be pumped to displace the fluid “train” down the tubing to the target depth. The sequence
is illustrated in Figure 2.10

Figure 2.10: Displacement sequence in cement squeeze bullheading (Nessa 2012)

30
 Table 2.9: Bullheading cement through X-mas tree, advantages and limitations
Advantage Limitations
 Cost effective way to plug  Cement settling in tubing
Bullhead cement TT reservoir section of a well. and/or XT
 Seals off reservoir  Relatively high risk of
perforations cement contamination
 Need well injectivity
 Not optimal for
screens/gravel pack

2.2.1 Improved through XT cement plug placement method

With certain well conditions it is possible to set the primary P&A barrier using a hybrid
cementing technique. The method is based on some of the principles in cement bullheading
(described above) used in combination with cementing wiper plugs. Some of the well
conditions required are; good injectivity and a verified annular barrier element in the desired
plug setting area (Olsen et al. 2017). A cement spool is connected directly on top of the XT and
can be part of a well intervention rig up. The spool consists of a plug container body and is
equipped with three plug release plungers and a manifold, Figure 2.11.

Figure 2.11: (Left) Schematic of cement spool; (right) Spool rigged up (Olsen et al. 2017)

31
A retrievable packer, set by wireline in the bottom of the desired plug setting area, has a seal
bore landing profile in the top. This landing profile fits the lower dart, Figure 2.12, used in the
concept and creates a seal acting as a base for the cement slurry above. The lower dart also has
a burst disc installed that will burst if the cement plug does not hold a pressure test. The wiper
darts, launched from the cement spool, are designed to separate the cement from the
displacement fluid (Olsen et al. 2017). Pumping cement through XT also introduces the risk of
cement settling in the XT numerous valves and cavities. To reduce this risk, a high-viscosity
strongly cement-retarding post-flush pill is spotted inside the XT. The purpose of this fluid is to
help remove any leftover cement slurry while also retarding any remaining cement (Olsen et al.
2017).

Operation step list summary after Olsen et al. (2017):

 Rig up cement spool and wireline equipment.

 Run the retrievable packer on wireline and set in tubing/liner.
 Install the lower dart and upper dart in cement spool.
 Mix cement slurry, release lower dart and pump slurry through manifold. Release upper
dart once cement pumping complete and follow with displacement fluid.
 Monitor WHP while pumping.
 Pump retarder fluid to be spotted in XT.
 Land lower wiper plug in seal bore. The cement now sits at the desired plug area, Figure
2.12.
 WOC
 Pressure test cement plug, exceeding lower dart burst pressure to verify plug integrity.

32
Figure 2.12: (Left) Upper and lower wiper plugs (Olsen et al. 2017); (Right) Illustration of
cross-sectional barrier formed by the method (Courtesy of Statoil).

Table 2.10: Bullhead cement TT & XT using wiper plugs, advantages and limitations.
Advantages Limitations
 Less chance of cement  Chance of cement settling in XT
Bullhead cement TT & XT

contamination compared to  Risk of stuck cement dart in well

using wiper plugs

conventional cement restrictions.

bullheading.
 Better cement placeability

33
 2.3 Coiled tubing
Coiled tubing (CT) can be defined as any continuously-milled tubular product manufactured in
lengths that require spooling onto a take-up reel, during primary milling or manufacturing
process (ICoTA 2005). The tube is usually straightened prior to entering the wellbore and is
recoiled once spooled back on the reel. CT diameters range from 0.75” to 4” and steel tubes
have yield strengths ranging from 55.000 to 120.000 psi. A CT unit consists of four basic
elements (ICoTA 2005):

 Reel – for storing and transporting CT

 Injector head – to provide snubbing and pulling force, Figure 2.13
 Control Cabin – from which the equipment operator monitors and control the CT
 Power pack – to generate hydraulic and pneumatic power needed to operate

Figure 2.13: (Left) Typical coiled tubing rig up. Power pack, control cabin and safety head
are not shown; (Right) Hydraulic power driven chain. Injector head consists of two chains
clamping around the coil. (Nessa 2012)

CT operations on many offshore platforms are constrained by the lifting capacity of the rig
cranes, as well as deck space and deck load limitations. A loaded reel is often the heaviest
component (ICoTA 2005). A typical CT rig up is illustrated in Figure 2.13. Pressure control
equipment (PCE) is another key component, as the majority of CT jobs are performed on live
wells. A typical PCE setup from top to bottom can be; side door stripper, radial stripper, quick
latch, CT BOP, risers and safety head. The strippers, containing elastomer seals, provide the
primary seal around the slick tube.

34
Coiled tubing diameters have grown to keep pace with the strength requirements in new
applications. CT up to 2-7/8” is common for routine use. The rigidity and strength of modern CT
allows it to be pushed or pulled through highly deviated or horizontal wells (ICoTA 2005). This
was a common application prior to introduction of WL tractor. Some of the present day major
applications are well unloading, cleanouts, aziding/stimulation and fracturing. CT can also be
fitted with internal electrical conductors or hydraulic conduits, which enables tool
communication. Flow-activated or hydraulic tools are also common as it is possible to circulate
with the CT (ICoTA 2005). Directly above the BHA a dual flapper check valve is situated. This
valve will prevent well fluids from entering the CT (NORSOK 2013b). Flappers are used to allow
ball drop operations as some of the flow-operated tools use balls to redirect flow.

Table 2.11: Coiled Tubing advantages and limitations

Advantages Limitations

 Pumping capabilities  Fatigue issues related to the CT

 Ability to circulate fluids also itself and mechanical failure.
while running in and pulling out of  Limited flow rate capacity
hole. compared to rig. Leading to poor
 High pulling force compared to solids/debris transportation:
WL Cannot have high flowrates due to
Coiled tubing

 High deviation accessibility hydraulic friction.

(limited need for tractor)  High hydraulic friction loss due to
 Rigless the fluid needs to travel through
 Mobile whole CT length.
 Relatively quick to rig up  Production tubing wear in kick-off
point on several consecutive runs.
 No torque available without use of
a positive displacement motor
(PDM)

35
 2.3.1 Cementing through Coiled Tubing
Cementing through coiled tubing is an operation that is conducted daily throughout the world.
Typical CT cementing applications are small volume remedial jobs like (Portman 2004):

 Blocking off or squeeze perforations

 Wellbore isolation for abandonment purposes
 Cement placement through holes in completion string to produce “cement packers”
 Forming plugs for drilling sidetracks

The main goal for these operations is to place uncontaminated cement slurry at a desired point
in the well. Sørgård et al. (1999) state that CT perhaps is the optimum way of setting cement
plugs. It enables the cement to be pumped as the coil is pulled out of the hole, ensuring
minimum contamination, as pictured in Figure 2.14.

Figure 2.14: Idealized cement placement procedure (Portman 2004).

36
Some special considerations however have to be made when cementing through CT. First, a
standard cement recipe cannot be used in CT cementing due to the limited inner diameter. A
special cement slurry with longer thickening time, lower fluid loss and a lower viscosity is
needed. Thickening time is a function of temperature, but could also be affected if the slurry is
contaminated by brine used as spacer (Portman 2004). Secondly, a CT cement plug should be
set on a base. Because cement typically has a higher density than the surrounding well fluid, it
will not sit on top of a non-rigid substance. Well bottom, a cross-linked gel plug or a mechanical
plug can form acceptable bases. Similar to cement bullheading through tubing (section 2.2)
liquid freefall could be a challenge also in CT cementing, as listed in Table 2.12. Free-falling
slurry will in most cases lead to it being contaminated. High pump rates or shearable cementing
darts, as pictured in Figure 2.15, can be used as mitigating measures (Portman 2004).

Table 2.12: Typical freefall flow rates and velocities for cement and water in CT
(Portman 2004).

Figure 2.15: Cement dart (Portman 2004)

In the late 1990s CT was used in a North Sea operation to create two temporary cement
barriers in 10 3/4” Casing (9.66”ID). The barriers were placed to secure the well for BOP repairs.
Two independent 100m+ cement plugs were placed through 2” CT, on a mechanical “umbrella”

37
plug base. After BOP repairs, both plugs were drilled out by a rig, confirming hard cement over
the intervals. Some of the key findings from this job were (Sørgård et al. 1999):

 CT is the most optimum way of setting cement plugs. Due to its ability to pull out of the
hole while displacing, minimizing contamination and ensuring precise placement.
 It is possible to set gas tight cement plugs in large diameter holes (9.66”) through a 2”
CT even at low flow rates of 250 liters per minute (LPM) when the proper design is
employed.
 Mechanical “umbrella” base used is excellent as base for cement, illustrated in Figure
2.16, and represents an improvement in cementing technology.
 Computer simulations used in cement displacement are essential for verifying the
cement design.

Figure 2.16: «Umbrella» Cement Base Operating Principle (Sørgård et al. 1999)

Table 2.13: Coiled Tubing cementing advantages and limitations

Advantages Limitations
 Rigless  Limited flowrate through CT
 Time saving o More pumping time needed and adding
Coiled tubing cementing

 Plug placement of retarder to cement slurry which has a

 Minimum contamination detrimental effect on cement properties
o Could lead to poor mud
removal/displacement due to laminar
flow in annulus
 No possibility to dress off cement without motor
 Tagging with minimum 10 T could be a challenge
 Cement settling inside CT

38
 2.3.2 Coiled tubing wellbore cleanout
Through tubing cleanout using fluids and tools conveyed by CT is considered standard industry
practice. Different cleanout systems have been developed over the years employing several
different techniques and approaches. Both forward and reverse circulation is used throughout
the world for well cleanup. Stationary circulation, wiper trip, reverse circulation, sand
vacuuming and various bailers are some of the methods available. This thesis will focus on
wiper trip hole cleaning, as this technology has well proven large wellbore cleaning ability. It is
therefore most relevant for NCS P&A applications. In conventional sand cleanout operations,
severe loss to the perforations can be experienced in depleted reservoirs. This leads to low
annulus velocity and related poor solids transportation (Li et al. 2008). In a P&A operation, loss
to the reservoir would not be a problem as it could be isolated prior to the cleanout operation.
The wiper trip method, illustrated in figure 2.17, is based on a specialized tool used in
combination with a solid-transportation simulation for CT. The tool offers the option of
downward facing high energy jetting nozzles or a positive displacement motor (PDM) to ensure
sufficient energy for hard solids penetration (Li et al. 2008). Once the solids have been
penetrated, the tool allows the cleanout fluid to be directed upwards in some low energy
nozzles. This also stops the fluid flow to the PDM and jetting nozzles. Pumping through the
upward facing nozzles, while carefully pulling out of hole, the solids will be “swept” out with
almost 100% efficiency (Li et al. 2008). The constant upward facing nozzle flow will agitate the
solids and entrain the particulates in suspension for transportation out of hole. Solids are
always located directly above the BHA, and the correct wiper speed is extremely important.
Common circulation fluids for sand cleanout is formation water, sea water, brine, diesel or
crude oil, which all can be mixed with nitrogen to lower the hydrostatic head if necessary (due
to low reservoir pressure and high fluid loss rate). Fluids with improved solids suspension
capabilities, such as biopolymers and foam, are available but also have their advantages and
disadvantages. One of the biopolymer disadvantages is that once a cutting bed is created on
low side, it is very hard to agitate as the coiled tubing does not rotate. This makes the particles
stick to each other.

39
 Figure 2.17: Typical stages of a wiper trip clean-out method (Li et al. 2008)

Li et al. (2008) presents a relevant case study from the Norwegian sector of the North Sea. A
1350m section of a wellbore, mostly 7” but also included a 341m 9-5/8” section, needed to be
cleaned out. The reservoir was isolated by a kill pill preventing fluid losses, as the reservoir
pressure was relatively low. The 9-5/8” section was successfully cleaned out using the wiper
trip method and a tripping speed of 2-3 m/min. 2-3/8” CT and a sea water based cleanout fluid
containing hydraulic friction reducer were used to obtain highest possible pump rates. 8-10
bottoms-up was pumped before any solids were confirmed at surface. This confirmed that
circulation rates up to 850 LPM and CT stationary on bottom is not enough for solids removal.
The solids must be suspended, and held suspended above BHA while pulling out. A total of
6000-8000kg of solids was recovered in this operation using the wiper method (Li et al. 2008)

Table 2.14: Coiled Tubing hole cleaning advantages and limitations

Advantages Limitations
 Rigless  Stationary circulation for hole
 Proven for sand clean out in
Hole cleaning
Coiled tubing

cleaning is challenging
large wellbore ID  Limited flowrate
 No need for mud  Slow progress on wiper trip
method in large ID clean out

40
 2.3.3 Abrasive cutter deployed via Coiled Tubing
The pumping capability of coiled tubing make it possible to use abrasive cutters. An abrasive
cutter use cutting particles (such as sand or glass beads) mixed with water. This mixture is
pumped through a rotating cutting head with nozzles, and the abrasion erodes the steel. A key
component in the system is the sealed bearing pack positive displacement motor (PDM) (Loving
et al. 2005). The PDM drives the rotating cutting head with its nozzles. A successful abrasive cut
relies on proper nozzle selection and is determined by CT flowrate and hydraulic calculations.
During testing a 2.875” 8.7 ppf P-110 tubing was cut in 4 minutes using a pump rate of 4 bpm
(635 LPM). Successful multiple simultaneous casing cuts on 13-3/8” and 9-5/8” have been
performed in P&A applications (Loving et al. 2005). In addition abrasive perforations, as
illustrated in Figure 2.18, are possible using the same technology by removing the rotating head.

Figure 2.18: CT abrasive perforation head after completed job (Loving et al. 2005)

Table 2.15: Coiled Tubing abrasive cutter advantages and limitations

Advantages Limitations
 No explosives  Abrasive cutting particles
Coiled tubing abrasive cutter

 Cuts through several casings needed

in same cut  Large surface spread
required for abrasive
particles
 Tool washout
 Time to clean out abrasives
from well

41
 2.4 Section milling
Section milling will not form part of the rigless approach to P&A, but it is an important
technique used in conventional P&A and is addressed here for completeness. In addition, one
of the emerging technologies presented in Chapter 3 is a new approach to section milling, a
brief introduction is therefore provided below.

In the absence of an annular barrier, the conventional approach to create a cross-sectional

barrier is to remove the casing by section milling, clean the open hole section, under-ream to
expose virgin formation and set a balanced cement plug (Ferg et al. 2011). A mill is deployed to
the desired depth. The section mill tool features several “knives” on pivots which swing out of
the tool once a cone is actuated by hydraulics. Considerable force is exerted from the cone,
acting on the knives to mill through the casing. Once milled through the casing wall and fully
extended the knives are locked in position. Weight is applied from the surface to mill the
desired interval of casing, exposing an open hole (Stowe and Ponder 2011). Downhole metal
cutting is a challenge due to the high level of axial, lateral and torsional vibrations exhibited by
a drill string. A typical P&A interval of 50m needs an average of 1.55 trips to complete using
tungsten carbid knives, Figure 2.19 (Stowe and Ponder 2011).

Figure 2.19: (Left) Cutter/“knife”; (Right) section mill tool (Stowe and Ponder 2011)

42
Section milling tools with active stabilizers to reduce vibrations have been introduced, reducing
the total number of trips required (Ghegadmal and Ponder 2016). Fluids used with section
milling need sufficient density to keep the open hole interval stable and a suitable viscosity to
suspend and transport swarf (metal cuttings produced from mill) and debris. The equivalent
circulating density (ECD) exerted by this fluid could lead to the exposed open hole section
exceeding its fracture pressure (Ferg et al. 2011).

Table 2.16: Section milling advantages and limitations

Advantages Limitations
 Will create a full radial rock-  Swarf handling downhole.
to-rock barrier plug  Swarf handling at surface.
Section milling

 Continuous plug with no  Well control due to swarf

metal as part of Well Barrier handling. (BOP)
Envelope  High ECD due to density
and high viscosity fluid.
 Time consuming.

2.5 Perforate, Wash and Cement

The Perforate, Wash and Cement (PWC) method was developed for wellbore barrier placement
in un-cemented casing intervals, as an alternative to traditional section milling (Delabroy et al.
2017). The method is used by major operators on the NCS in conventional P&A. It could also be
a viable rigless application using CT or snubbing unit in the future. The rigless PWC approach is
not part of this thesis but the conventional approach will be briefly discussed below.

A bottom hole assembly (BHA) consists of perforation guns, a washing tool and a cement
stinger. The concept allows placement of a cross-sectional barrier in an un-cemented casing in
one trip. 50 m of drill pipe conveyed perforating guns, with 12 shots per foot (SPF) in 135/45-
degree phasing, Figure 2.20, are placed at the desired intervals and drop when firing (Ferg et al.
2011). Once the guns are dropped, circulation and conditioning of the mud to account for the
actual pore pressure can be done. After the desired fluid properties have been obtained a ball
drop is conducted to re-direct the fluid flow out through two cups. These cups will direct the
fluid through the perforations for a washing operation in a top-down direction (Ferg et al. 2011).
After the washing sequence, a cement spacer is pumped before the washing assembly is
disconnected by a ball drop, to function as a base for cement. Cement is pumped while rotating

43
the string to agitate the cement for better displacement behind perforations. The BHA remains
in hole during WOC for washing down and testing the plug (Ferg et al. 2011). A further
development of the method is described by Arsalan et al. (2016) for improved washing and
cementing using jetting tool, illustrated in Figure 2.21a and 2.21b. As PWC is not described in
NORSOK D-010 (2013a), a qualification matrix has been developed and described by Delabroy
et al. (2017).

Figure 2.20: Perforation pattern and phasing (Ferg et al. 2011)

Figure 2.21(a): PWC using jet system and two trip approach. Step 1-4 (Arslan et al. 2016)

44
Figure 2.21(b): PWC using jet system and two trip approach. Step 5-7 (Arslan et al. 2016)

Table 2.17: Perforate, Wash and Cement advantages and limitations

Advantages Limitations
 Un-cemented casing annuli can be  Relatively new technology –
Perforate, Wash and Cement method

effectively isolated. needs implementation to

 No swarf handling both downhole regulations/guidelines/standards
and on surface.  Long cement plug placement in
 Well control enhanced. BHA at one run (in a plug verification
depth during operation and no perspective)
swarf in BOP.  Removal of existing mud or
 Significant time saving compared to settled barite behind csg.
section milling.  Plug qualification method is not
available in current NORSOK D-
010 rev 4 (2013a)

45
Intentionally left blank

46
 3. Emerging P&A technologies
In sections 3.1 and 3.2, two non-commercialized emerging P&A technologies will be presented.
The aim is to perform a case study using these technologies in a rigless P&A approach to
platform well plugging. The case study is presented in chapter 4.

3.1 Electric plasma miller

3.1.1 Electric plasma

Plasma is defined as: “A highly ionized gas in which the number of free electrons is
approximately equal to the number of positive ions. Sometimes described as the fourth state of
matter, … ” (Oxford U. 2009)

The concept was initially meant as an innovative non-contact tool for accessing sources of
geothermal energy (Kocis et al. 2015). A set of prototypes was built and the oil & gas industry
showed interest. A joint industry project (JIP) was initiated in 2013 including operating
companies and service providers to further develop the technology. The original scope of the
JIP project was to develop a plasma based drilling solution, but during the years several other
possible applications have emerged including steel and cement milling being one of the main
focus areas today (Kocis et al. 2015).

Electric plasma brings some advances in comparison to conventional plasma torch and other
thermal non-contact approaches (Kosic et al. 2015):

 The electric arc, with temperatures of more than 10,000 Kelvin (K), heats the surface of
the disintegrated material directly with minimum heating of the intermediate gas (which
reduces the effectiveness of heat transfer in conventional plasma torches).
 The heat flow is area-wide, shown in Figure 3.1, and relatively homogeneous by
applying a long arc on the whole surface for a high-intensity disintegration process.
 The rotating spiral arc has a “built-in” centrifugal pump function for disintegrated
material removal, in addition to the thermal influence.
 Direct electric arc plasma technology allows use of an electrohydraulic phenomenon
that generates shock- and pressure waves for destruction and transportation of
disintegrated materials away from the BHA. Conventional plasma torch does not have
this ability.
 High intensity short current pulses generate pressure waves. These pulses are
accumulated allowing an increase in instantaneous pulse disintegration effect with
power pulses in megawatt (MW) scale.

47
 Figure 3.1: Difference in plasma shape, (Left) narrow conventional plasma flow – (Right)
Electric arc area-wide plasma flow (Kocis et al. 2015).

Electric plasma for hard rock drilling is based on thermal rock disintegration in a non-contact
process (Kocis et al. 2015). The thermal characteristics such as; boiling point, melting point and
thermal conductivity of the rock will determine rate of penetration (ROP) in a given rock.
Spallation, melting and evaporation are modes of disintegration and distinguishable by the
plasma temperature. As melted and evaporated rock elements produce relatively high intensity
radiation a real-time analysis through a spectroscope could be possible using the technology as
shown in Figure 3.2.

Figure 3.2: Spectra analysis hierarchy (Kocis et al. 2015).

48
Electric plasma for casing milling uses a similar approach (Kocis et al. 2015). Commercial
available oxy-fuel flame cutters or high temperature plasma jets, using argon/hydrogen/oxygen
plasma, could be used for casing milling. However these technologies have a narrow cross-
sectional interaction area with the target metal surface, which is optimal for simple metal plate
cutting. This does however impose a time and technical limitation for total metal removal. By
combining a high temperature large cross-section plasma torch and a rotating electric arc a new
generation of plasma generator was created, proving to be an effective tool for casing milling
(Kocis et al. 2015). The technology is based on a hybridized plasmachemical and
thermochemical process resulting in a fast metal degradation and removal in a water steam
environment. The processes involved in steel removal are (Kocis et al. 2015):

 Oxidation
 Melting
 Evaporation

A necessary note is that oxidation is active in both melting and evaporation process for steel
temperatures up to 3500K. Several studies on water steam and temperature in steel removal
conclude that temperature and heat transfer play a key role in steel removal rate (Kocis et al.
2015). The proportional contribution of thermochemical and thermophysical processes
resulting in steel removal effect therefore varies with changing temperature and brings the
following basic features (Kocis et al. 2015):

 Oxidative part of steel structural degradation is an exothermic process leading it to

supply additional energy for all steel removal sub-processes.
 Steel oxidation and evaporation rate rises with increasing plasma temperature, power
density through the plasma-steel interface and plasma enthalpy.
 Oxidation and evaporation rate of steel is most efficient in water steam and air/steam
mixtures (with regards to energy consumption).
 At a narrow temperature window, 3330-3660K, enthalpy liberated from the oxidative
process is raised by the factor of three. I.e. three times more energy is supplied into the
steel removal process without the increase of external power to the plasma generator.
This window should be available for all alloys of steel since at these temperatures all
compounds are in gaseous phase.
 Steel surface temperature in excess of 3660K will lead to a total dissociation and
evaporation occurrence. Metal etching effect is the result from plasma particles (in form
of active ionic atoms) impact to the steel surface. It is important not to forget that
oxidation is still active during melting and evaporation process.

49
Cuttings from experiments done on carbon steel show a microstructure with clear dominant
presence of iron(II) oxide. Analysis showed structural heterogeneity between oxidized and
metallic layers in cuttings. The difference in thermal expansion coefficient of metal/oxide
systems at the boarder of a metallic and oxide layer results in a hydrodynamic destruction of
such weak multilayers, as illustrated in Figure 3.3a-b (Gajdos et al. 2015a). In the case of alloy
steel, thermal expansion properties of steel/oxide differ even more, because of the higher
grade of chemical heterogeneity in the microstructure.

Figure 3.3a: Illustration of different volumetric thermal expansion of multilayered

structures in a microstructural perspective (Al Furati 2016).

Figure 3.3b: Mechanical stress due to temperature increase on a microstructural level,

leading to disintegration of metal, caused by difference in thermal expansion coefficient
between layers (Al Furati 2016).

Metal disintegration has a high-energy consumption. During experiments at different boundary

conditions metal cutting effectiveness could be categorized by one parameter,  (Gajdos et al.
2015a).  describes the energy needed to remove a mass of steel under certain conditions. The
parameter describes the liberated energy coming from an exothermic iron oxidation process
and real electric energy input to the plasma generator, where  always is lower than consumed
electric energy.

50
 𝑈∙𝐼∙𝑡
𝜀= (3.1)
𝑚

where:

 [J/kg] : net energy requirement per unit mass of steel removed

UI [W] : electrical power to plasma generator ([V][A] = [W])

t [s] : time of process

m [kg] : mass of removed steel

A steel removal rate (SRR) could be estimated based on casing conditions in water environment
at low temperatures. Gajdos et al. (2015a) estimates a SRR of 210 kg/h leading to a cutting rate
of 2.0 – 4.5 m/h for a 9-5/8” casing section. This estimate is based on an  of 3 MJ/kg, a power
output of 250kW and plasma efficient of 70%. Expression 3.2 is the same as 3.1 solved for mass
over time [kg/s], including plasma torch efficiency and converted to hours.

𝑈∙𝐼∙3.6∙103
𝑆𝑅𝑅 = ℎ (3.2)
𝜀

where:

SRR [kg/h] : steel removal rate

UI [W] : electrical power to plasma generator ([V][A] = [W])

3.6103 : seconds per hour

 [J/kg] : net energy requirement per unit mass of steel removed

h : plasma torch efficiency (01)

Estimating a constant power output of 100kW during downhole operations, based on umbilical
max constant power transfer of 150kW (Figure 3.5), the effective SRR will be 84 kg/h.

Cutting rate for a typical NCS 5-1/2” 20ppf (29.76 kg/m) tubing, using the estimated SRR input
of 84 kg/h, will be 2.82 m/h.
𝑘𝑔
𝑆𝑅𝑅 [ ] 84 𝑚
ℎ
𝐶𝑢𝑡𝑡𝑖𝑛𝑔 𝑟𝑎𝑡𝑒 = 𝑘𝑔 = 29.76 = 2.82 [ ℎ ] (3.3)
𝑡𝑢𝑏𝑖𝑛𝑔 𝑤𝑒𝑖𝑔ℎ𝑡[ ]
𝑚

51
 3.1.2 Plasma miller for P&A
A plasma miller could be a viable rigless alternative to pulling tubing and section milling once
commercialized. The plasma miller is planned to be deployed using a CT unit as this will provide
the ability for through XT and tubing operations. Gajdos et al. (2015a) presents a P&A case
study where a plasma miller is proposed as an alternative solution to section milling. The
conventional approach is similar to that presented in section 1.2. The alternative approach to
cross-sectional barrier placement is presented below:

Figure 3.4: Alternative solution to section milling by use of plasma miller conveyed by CT
(Gajdos et al. 2015a)

 Rig-up on well and set bridge plug as base for reservoir cement plug (allow for milling
debris sump)
 RIH with plasma miller to mill desired window through tubing, Figure 3.4 a & b
 Run in on same trip to mill same interval of casing and cement, Figure 3.4 c & d
 Set reservoir barrier

52
  Set mechanical base for intermediate cement plug above permeable zone with potential
 RIH with plasma miller to mill desired window through tubing, casing and cement,
Figure 3.4
 Set intermediate cement barrier
 Set environmental barrier
 Sever and retrieve tubulars and wellhead from below mudline.

If casing and cement have integrity, it would be possible to log (and verify) the casing cement,
and not remove it. The verified annular barrier could form part of the cross-sectional barrier.
Keeping the cement and casing in place would also simplify the operation. When removing
casing and cement the formation is exposed. Several considerations have to be addressed while
working with an open hole section. Hole-stability and pore pressure are some of the concerns,
and dealt with through the use of drilling mud. By leaving the casing in place, use of mud and
exposure to formation could be avoided.

Power supply is one of the main challenges related to the downhole operation of the plasma
miller (Gajdos et al. 2016). A specialized umbilical, illustrated in Figure 3.5, is planned to supply
the needed power in addition to fluids and data transferability. The umbilical is made for
deployment using a CT unit, and could be compared with electrical submersible pump (ESP)
installation using CT. In ESP installation an electric power umbilical lowered with CT enables
fluid circulation and weight support of the power cable and ESP through an anchor to the coiled
tubing (Gajdos et al. 2016). The choice of a coiled tubing approach also enables operations on
live wells, TT and XT. A possible challenge using a CT umbilical will be weight limitations on
cranes and deck. These limitations will not be part of the viability consideration in this thesis.

Figure 3.5: Umbilical for testing of plasma miller (Courtesy of GA Drilling)

53
Disintegration of eccentric tubing and the possible damage to the casing caused by heat during
milling was researched in experiments (Kristofic et al. 2016). Two steel plates, electrically
connected to the same potential, were set up with 1mm, 5mm and 10 mm space between
them. This setup simulated different degrees of pipe eccentricity. Only a small amount of
melting and low temperature oxidation was observed on the 1mm specimen while the 5mm
and 10mm specimens had no melting and only minor oxidation on surface (Kristofic et al. 2016).
This was according to expectations as the milling process using the electric arc is restricted to
the active electrodes.

Cuttings size and shape produced by the plasma miller is a major benefit compared to section
milling. Where section milling produces swarf, the plasma miller produces small particles with a
majority of them smaller than 5mm. Cuttings from several experiments have been analyzed.
Different milling environments produce different cutting distributions. Cuttings from tests done
in fresh water, brine and in a high pressure brine environment are shown in Figure 3.6 a-c,
respectively. The cuttings have a shape that will render possible collection in the sump/rat hole
created above the cement base plug. Alternatively, they could be collected and brought to
surface.

Figure 3.6a: (Left) Cuttings generated during plasma milling in water environment; (Right)
Cuttings size distribution (Gajdos et al. 2015a).

54
 Figure 3.6b: (Left) Typical shape of cuttings in 0.7-1.0mm range (image from optical
microscope); (Right) Cuttings distribution in brine environment (Gajdos et al. 2015b).

Figure 3.6c: Samples of cuttings after test done in high pressure (20MPa) brine
environment. The irregularl shape large aggregates were found to be several cuttings
clustered together (Kristofic et al 2016).

55
 3.1.3 Research and development of electric plasma miller
The findings and progress during research and development (R&D) have been presented and
published in papers throughout the period. A brief overview of the R&D and technology
verification in different environments is presented below. The interested reader is referred to
references.

 Kocis et al. (2015) presents tubular milling in air at atmospheric pressure, Figure 3.7.

Figure 3.7: Time evolution of casing milling in air environment (Kocis et al. 2015)

 Gajdos et al. (2015a) presents tubular milling in a water environment at atmospheric

pressure, Figure 3.8.

Figure 3.8: Water environment casing milling setup and results. During the same
experiment it was shown that 3.5” tool was capable of milling 4.5” 5.5” and 7” casing
(Gajdos et al. 2015a)

56
  Gajdos et al. (2015b) presents milling of casing and cement in a brine environment at
atmospheric pressure, Figure 3.9.

Figure 3.9: Plasma-based milling generator submerged in brine environment; milling

specimen on far right (Gajdos et al. 2015b)

 Gajdos et al. (2016) presents experiments done in a pressurized (2 – 20 MPa) brine

environment.

 Kristofic et al. (2016) presents the latest publication available. Tests of milling steel with
mud contaminated cement behind and its effect on the process in a pressurized (25 – 42
MPa) brine environment.

An offshore field trial is scheduled for first half of 2018 (Kristofic et al. 2016). At the present
time the main focus is testing of longer section milling as well as testing the complete system in
high pressure environment. This will include full scale BHA and a test well.

Table 3.1: Electric plasma miller advantages and limitations

Advantages Limitations
 Steel removal downhole  Not commercialized
 Casing access without pulling tubing  No field trials
 Rigless, well intervention setup  High energy consumption
Electric plasma miller

 Advantageous cuttings size and  Transferability of energy to tool

shape compared to swarf downhole could be challenging
 3.5” tool capable of milling 4.5”,  Specialized umbilical needed for
5.5” and 7” tubular. plasma milling operation
 Heat-effect from milling on
surrounding casing and cement
not known
 Weight of umbilical CT reel

57
 3.2 Thermite plug
Using thermite for wellbore sealing by melting materials in the wellbore and its vicinity is a
radical idea. A Norwegian company presented the idea for P&A purposes in 2012 with the aim
for rigless operations. The purpose of the technology is to make an impermeable “man-made
rock” with a smooth transition between formation and plug (Mortensen 2016). A JIP was
initiated in 2014 including several major NCS operating companies and the Norwegian Research
Council. Very little scientific data have been published on their approach and R&D progress.
This thesis will therefore mainly focus on an American research company’s approach for
wellbore sealing using thermite for nuclear waste management (Lowry et al. 2015). Although
nuclear waste is stored in granite rock the analogies to an oil & gas well are evident, as plug
placement and interaction with formation will be based on the same principles.

3.2.1 Thermite
“Thermit” was first described by Hans Goldschmidt in 1908 as an exothermic reaction involving
reduction of metallic oxides with aluminum to form aluminum oxide and metals (Wang et al.
1993). A large heat release that will heat the products above their melting point is what
categorizes these reactions. Temperatures in excess of 3000°C (3273K) can be obtained during
an aluminum and iron-oxide reaction, which is above the melting point for the products of this
reaction. Originally used as a method for forming metal alloys in a carbon free environment, it
has also been used in railroad welding, steel structure demolition and military applications
(Lowry et al. 2015). Today thermite is used in a broader description and can be defined as an
exothermic reaction which involves a metal reacting with a metallic or non-metallic oxide to
form a more stable oxide and the corresponding metal or non-metal of the reactant oxide
(Weng et al. 1993). It is a self-oxidizing reaction with high specific heat and the ability to react
under water (Lowry et al. 2015). This oxidation-reduction reaction can be written in general
form as:

𝑀 + 𝐴𝑂 → 𝑀𝑂 + 𝐴 + ∆𝐻 (3.4)

Where M is a metal, and A is either a metal or a non-metal. AO and MO are their corresponding
oxides and ∆H describes the heat generated (enthalpy). Goldschmidts reaction, containing
aluminum and iron-oxide is described below:

2𝐴𝑙 + 𝐹𝑒2 𝑂3 → 2𝐹𝑒 + 𝐴𝑙2 𝑂3 + ∆𝐻 (3.5)

This reaction is the most relevant for wellbore sealing in a commercial and safety point of view
as the reacting agent is readily available and the oxide is chemically and physically stable. The
reaction (3.5), above, has an adiabatic combustion temperature of 3622K. The iron and
aluminum-oxide products have melting points of 1809K and 2315K, respectively (Weng et al.

58
1993). This means that all elements included in the process will be in a melted state. The self-
sustained nature of a thermite reaction can be adjusted by adding an inert diluent or salts of
alkali metals. Alkali metals such as NaF or KCl or alkaline earth metals such as AIF3 will
effectively increase the combustion rate of the reaction (Weng et al. 1993). An inert diluent,
such as Al2O3, will slow down the reaction and lead to a lower combustion temperature (Lowry
et al. 2015). The adiabatic combustion temperature does not only give a quantitative measure
of the exothermicity of the reaction, it also gives a quick determination of the reactions ability
to self-propagate. A general rule is that an adiabatic temperature above 2000K will lead to a
self-propagating thermite reaction (Weng et al. 1993). Once the reaction is complete a rigid hot
plug of metal and oxide is formed, a ceramic-like material (Lowry and Dunn 2016).

Initiation. Weng et al. (1993) describes four different classifications for the physical and
chemical stability of the reactant oxides. Oxides in the reaction, listed in equation 3.5 above,
are classified as physical and chemical stable. “Stable” means it is one of the reactions needing
the most energy for initiation, as illustrated in Figure 3.10. Thermite reactions can be initiated
by a combustion wave from a chemical reaction, an electric current, radiation energy (laser) or
mechanical impact. Sparks created by a hammer striking an aluminum residue on rusty mild
steel have been blamed for initiating thermite reactions in chemical plants and mines (Weng et
al. 1993).

Figure 3.10: Illustration of the activation energy needed to initiate the thermite reaction
(Mortensen 2016).

Combustion. Weng et al. (1993) state that “The high exothermic energy associated with
thermite reactions and, in general, the condensed nature of the reactants and products at the
reaction temperature make many thermite systems examples of reactions in the gasless
combustion regime”.

59
Gasless combustion defining criteria is:

𝑃(𝑇𝑐 ) ≪ 𝑃0 (3.6)

Where P is the vapour pressure of the most volatile component at combustion temperature T c,
and P0 is the external gas pressure. The reaction described in equation 3.5 diluted with its
product (Al2O3) is an example of a gasless combustion. Experiments have been done showing
the reactions combustion rate independence to inert gas pressure, Figure 3.11.

Figure 3.11: Combustion velocity of (2Al + Fe2O3) diluted with 30 weight% (Al2O3) as a
function of inert ambient pressure (Weng et al. 1993).

Although the thermite reaction itself does not create gas during combustion the surrounding
fluids in a well will be affected by the combustion temperature. Saturated water has a critical
temperature (Tcr) of 374.14°C (648.29K) and a saturation pressure (Psat) of 22,090 kPa (220.9
bar) (Çengel et al. 2012). Well fluids in close vicinity to the reaction will reach a supercritical
fluid state on typical NCS reservoir barrier depths, illustrated in figure 3.12. At lower pressures
(shallower depth) the well fluid in surrounding area to the reaction would still reach a gaseous
phase also called superheated vapour.

Figure 3.12: Pressure-temperature phase diagram showing the critical point and area of
supercritical fluid (Mortensen 2016).

60
Solids from melts. Before trying to create a man-made rock barrier, one must understand how
nature creates rock. Rock solidified from magma is called igneous rocks. One of the founding
fathers of geology, James Hutton, discovered a granite layer cutting across and disrupting a
sedimentary rock. The granite, which is an igneous rock, had somehow fractured and invaded
the sedimentary rock, Figure 3.13. By closer investigation it became evident that the
mineralogy of the sedimentary rock close to the granite was different. These changes he
concluded were a result from great heat (Grotzinger and Jordan 2010).

Figure 3.13: Granitic intrusion in a metamorphosed sedimentary rock (Grotzinger and

Jordan 2010)

Magma is rock in fluid form. By lowering its temperature it starts to crystalize and solidify, much
like water when it freezes to ice. The rate of solidification (cooling) will affect the crystal
structure and size. The exact mechanisms of rock melting and solidification are not yet fully
understood, but it is known that a rocks melting point depends on its chemical and mineral
composition, and pressure and temperature (Grotzinger and Jordan 2010). A rock does not melt
completely at once, its different minerals with its different melting points is leading to partial
melting, illustrated in the crystallization process in Figure 3.14. It is also dependent on water
content, which will lower its melting point, according to Figure 3.15. Water content is a

61
significant factor in sedimentary rock melting, as it contains more water in its pores than
igneous or metamorphic rocks (Grotzinger and Jordan 2010). Igneous rocks typically have a
melting temperature of 700-1200°C ( 1̴ 000-1500K), and sedimentary rocks will be in the same
region depending on composition.

Figure 3.14: Fractional crystalization according to temperature. Crystallization settling rate

can be calculated using Stoke`s law (Grotzinger and Jordan 2010).

Figure 3.15: (Left) Factors affecting melting temperature of rocks. (Right) Granite
pegmatite vein. The center of the intrusion (upper right) cooled more slowly and
developed coarser crystals. The margin of intrusion (lower left) has finer crystals due to
more rapid cooling (Grotzinger and Jordan 2010).

All of the above mentioned aspects need to be considered when aiming to create a cross-
sectional barrier using thermite. A key area of research will be how to create a smooth interface
between thermite plug and the surrounding rock.

62
 3.2.2 Thermite for wellbore sealing in P&A
As described above the concept uses thermite as a means of restoring cap rock functionality.
The reactants need to be placed adjacent to the formation in which it is supposed to form a seal
with. The concept is to lower thermite powder in a container to desired depth by means of
wireline or coiled tubing where it will rest on a pre-set heat-insulated platform, as illustrated in
Figure 3.16 (Skjold 2013; Lowry and Dunn 2016). Upon reaction initiation, it will reach
temperatures above its melting point and the material compacts into the borehole volume,
where it sets and cools. Lowry et al. (2015) list some important factors that influence the
performance of a thermal plug:

 The plug matrix formed is of low porosity and low permeability

 Effective bonding of plug to the borehole wall. Bonding both mechanical and sealing.
 Thermal/structural impact to the surrounding rock. Minimal or no impact is preferred.

Figure 3.16: (Left): Plug emplacement technique (Lowry et al. 2015), (Right): Illustration of
the resulting plug using a thermite reaction. The heat insulating material on top of plug is
also shown (Log 2016).

For a TT and XT WL conveyance placing barrier plugs according to NORSOK D-010 (2013) several
runs would be needed. Skjold (2013) estimate 1.85 m3 of heat generating mixture is needed to
form a 50m barrier in 9-5/8” (0.037m3/m) casing. Estimating a WL container tool with internal
diameter of 3” (0.0762m) and a length of 20m, approximately 20 runs would be needed to
place the mixture. The length specifications in NORSOK (2013a) have been made with cement
plugs in mind, so the need for 50m thermite plug could be discussed. In this thesis case study
the plugs will be placed according to NORSOK D-010 (2013).

𝑉𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝑝𝑙𝑢𝑔 𝑉9−5/8" 1.85𝑚3

𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑟𝑢𝑛𝑠 = = 𝜋∗𝐷2
= = 20.3 𝑟𝑢𝑛𝑠 (3.7)
𝑉𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝑐𝑜𝑛𝑡𝑎𝑖𝑛𝑒𝑟 ∗𝐿 0.0912𝑚3
4

63
In the following section the techniques described by Lowry and Dunn (2016) and Skjold (2013)
to place a thermite plug with the above mentioned factors will be reviewed.

Applying a vertical load on top of the reaction will lead to a less porous product. A weight of
approximately 500-1500kg is resting on top of the thermite reaction, compressing it and
assisting the melt forcing its way into well surface irregularities. A relatively high porous plug
will reduce its potential strength and cause it to be permeable. By adding a diluent to the
reaction, like metal oxides or eutectic materials, lowering the reaction temperature the plug
will stay in a liquid or viscous state for longer. This will insure the plug being firmly pressed
towards the surrounding rock (Lowry and Dunn 2016).

Diluting the thermite mixture will effectively reduce the peak reaction temperature. The
stoichiometric mix of red iron oxide (Fe2O3) and aluminum powder is approximately 3:1 by mass,
respectively (Lowry and Dunn 2016). This reaction will, in atmospheric conditions, have a
relatively fast and violent reaction which could be difficult to contain. In wellbore sealing,
containment is vital in creating a monolithic plug material. Dilution can reduce the above
mentioned reaction peak temperature from 3000°C (3273K) to less than 1700°C (1973K). The
dilution will lead to a lower burn rate of 0.1 cm/s in comparison to raw mixture 10-100cm/s.
The lower temperature is also proposed in a layered thermite plug setup, where different
dilutions are used for different purpose in the same plugging operation. The first mixture is set
up to expand radially and effectively swage the casing outwards to the borehole wall in case of
un-cemented annulus (Lowry and Dunn 2016). The next mixture in the layered setup creates
the plug.

Radial expansion of the plug is preferred before axial expansion. A thermite reaction will
expand in the direction of reaction propagation. An axial length expansion of 10-20% will occur
on a cylindrical plug ignited in one end with very little expansion in the radial direction. By
igniting the mixture by means of a hot wire running along the center axis of the cylindrical plug
one would achieve radial expansion ensuring a tight fit inside the borehole (Lowry and Dunn
2016).

In addition, other means of ignition and placement are proposed in the literature. Lowry and
Dunn (2016) presents a self-feeding reaction from a cylindrical container. As it is ignited in
bottom, it will self-feed by gravity. Skjold (2013) also presents plug placement by fluid mixture
and circulation. A fluid placement by CT would be preferred looking at the number of WL runs
needed when working in accordance with NORSOK D-010 (2013). The mixture could also be
ignited by a timer, regardless of it being circulated in place or not (Skjold 2013).

64
 3.2.3 Research and development of thermite plug
Several aspects of the thermite plugs ability to create a seal in granite rock have been
presented by Lowry et al. (2015). This research is mostly in regards to sealability in granite rock
for nuclear waste disposal, but analogies can be drawn to oil & gas well sealing.

The effects of diluting a thermite mixture to obtain beneficial properties were a key aspect in
the initial development phase. Dilutions by as much as 1:1 with silica and alumina proved to
lower the peak temperature of the reaction, Figure 3.17. The mixture proved to be self-
sustained in dilutions up to 51%, resulting in a slower and more controllable reaction.
Compressive strength tests of the samples showed the effect of dilution, where silica proved to
produce a relatively weaker matrix according to Table 3.2. On the other hand silica diluted
matrix showed favorable results with regards to permeability, Figure 3.18. In addition
simulations on radial temperature effects and the cooling have been done, showing that plug-
rock interface cooled to 700-800°C ( ̴1000-1100K), within an hour after the reaction (Lowry et
al. 2015)

Figure 3.17: (Left) Adiabatic reaction temperature as a function of dilution by aluminum

oxide. Plateau at 2100°C represents the melting temperature of aluminum. (Right) Thermal
plug sample removed from granite block test very fine matric structure due to diluted
mixture (Lowry et al. 2015)

65
Table 3.2: Ultimate unconfined compressive strength of thermite plug samples (Lowry
et al. 2015).

Figure 3.18: Increasing dilution of the system with a low melt temperature oxide (silica)
yielded low permeability in confined tests (Lowry et al. 2015).

66
The R&D company developing thermite plug for oil & gas well P&A has also researched the
effects of fluids reaching super critical state during the exothermic reaction in a pressurized
wellbore. To better understand the reaction in wellbore environment a test cell was built,
Figure 3.19, capable of reaching 100°C and 700 bar (Mortensen 2016). The cell was built with an
integrated accumulator able to handle the gaseous superheated fluids. No results from these
tests have been published.

Figure 3.19: Pressure cell built to simulate wellbore environment to research reaction in
well condition (Mortensen 2016)

In 2016, a field test on two land wells in Canada was performed. In these trial wells the tubing
was pulled, using heavy equipment, to gain direct access to a cemented casing interval. This is a
step in R&D towards setting the thermite mixture inside tubing and creating a rock-to-rock
barrier. After the tubing was pulled, the thermite mixture was successfully placed and ignited,
creating a solid barrier (Log 2016). The results were encouraging, as the plug was set in a
controlled manner without incidents. In the first well, two consecutive plugs were set as the
first was not holding pressure. A total of 3 plugs were set in two different wells. The verification
methods and criteria are presented in Figure 3.20. The results are presented in Figure 3.21 (Log
2016). The future plan is to monitor the wells over a longer period and modify the tool for
better control of internal pressure (Log 2016). Further test are also planned.

67
 Figure 3.20: Pilot well verification method and acceptance criteria (Log 2016)

Figure 3.21: Thermite plug field trial results as of October 2016 (Log 2016).

Table 3.3: Thermite plug advantages and limitations

Advantages Limitations
 Possible to create a “man-made  Not commercialized
rock” for wellbore cross-sectional  WL concept not practical when
sealing complying with NORSOK D-010
 Can obtain a favorable plug (2013a)
design/properties by diluting  Uncertainty with regards to its
Thermite plug

thermite ability to create a cross-sectional

 WL based concept barrier in presence of fluid filled
 Rigless, through tubing annulus, as concept aim for
 Encouraging field trials placement in tubing
 Un-intended ignition on surface
could lead to incidents
 Not implemented in current P&A
regulations

68
 4. Case studies
In this chapter, three wells will be plugged as a case study. The candidate wells are provided by
NCS operating companies, but anonymized for the purpose of this thesis. These wells have
already been plugged, as part of batch P&A campaigns. Chapter 4 will present the wells and the
conventional approach used for P&A purposes of each respective well. The conventional
approach will only be presented briefly. The chapter will also investigate the possibility for a
rigless through tubing P&A approach using some of the emerging technologies presented in
Chapter 3 combined with the conventional technologies presented in Chapter 2. Well barrier
schematics will be presented for the wells prior to and after P&A for a better visualization of
the operations.

When aiming for a through tubing (TT) P&A approach several challenges arise. One obvious
challenge is that the drilling rig with associated mud handling equipment is removed. Over-
balanced mud and drilling BOP are often used as barriers during conventional P&A operations.
In addition to its potential barrier function, mud contributes to hole stability and hole cleaning
in open-hole operations. A rigless approach should aim to be mud-less using brine as well fluid
instead of mud as mud handling equipment will use a lot of deck space. A mud-less operation
should be performed in cased hole only, as hole stability and pore pressure will not pose the
same challenge in a cased hole- as in an open hole operation. A TT P&A cased hole operation
can utilize the existing XT in addition to well intervention pressure control equipment (PCE) as
WBE.

In most cases, leaving the tubing in the well is not an option. The need for annular barrier
verification, often in combination with control lines passing through the plug setting area,
identify the need to remove the tubing. In a TT P&A perspective a section of the tubing will
have to be removed somehow. By removing only a section of tubing, the tubing hanger and
tubing with all of its components will form a restriction throughout the operation. All tool used
in the TT P&A operation will have to pass these restrictions to reach the plug setting area. In
Table 4.1 the challenges with regards to a rigless P&A operation and possible solutions are
listed.

All depths in this chapter will be referring to measured depth (MD) rotary kelly bushing (RKB)
unless otherwise specified. Phase 3 P&A, wellhead and conductor removal, will not be part of
case study.

69
 Table 4.1: Challenges with rigless P&A and possible solutions
General challenges Possible solution Possible challenges with the
proposed solution
 No drilling rig with  Run operation with well  If a cased hole operation is
associated equipment intervention equipment not possible then a rigless
to supply mud as over- as primary barrier and approach should be
balanced fluid column XT intact. reconsidered.
during P&A operation.
Mud need pits, pumps  Well filled with  If annular barriers in
and shakers. NCS P&A brine/seawater. desired plugging area are
operations are not in-place, it could be
commonly run with  Rigless P&A run as difficult to provide a cross-
over-balanced mud as cased hole operation sectional barrier using a
Rigless P&A

well fluid. Mud will only (will not have to rigless approach.
contribute to well consider pore pressure
control in addition to and hole stability).  Hole cleaning will be
its functions with difficult due to relatively
regards to hole  By keeping the low circulation rate and
stability and hole operation cased hole low viscous fluid (brine).
cleaning. (and mud free) a lot of Hole cleaning in a "drilling
deck space is saved. perspective" (formation
cuttings) not needed due
to cased hole operation.
Some hole cleaning in plug
setting area might be
beneficial.

 Not able to log  Remove section of  Tool OD vs. Tubing

annular barrier tubing to gain access to restrictions ID.
(cement) through casing/cement in
tubing wall. Needs question, to log it.  Centralization of tool in
Rigless through tubing P&A

access to casing wall. casing ID (centralizer to

pass tubing ID and still
 All tools used in rigless centralize tool in csg. ID.)
through tubing P&A
must be able to pass  Distance between csg. ID
tubing restrictions. and slim logging tool OD
(might affect logging
quality).

 Re-entering tubing while

POOH with tools.

70
 4.1 Plug and abandonment of well A-1
The well was completed as an oil producer. It was shut in because of high water-cut and
decided to be plugged in a batch P&A operation. The well schematic is presented in Figure 4.1
and summarized in Table 4.2. The overburden formation (OBF) of A-1 consists of one formation
with potential to flow and a water bearing zone. These formations are given numbers for an
easier overview.

Figure 4.1: Well schematic A-1. Produced with Wellbarrier software.

71
 Table 4.2: A-1 Well summary table
Description Depth
13-3/8" csg. Shoe @ 1328m / 1294mTVD
TOC @ 136m
9-5/8" csg Shoe @ 3648m / 2902mTVD
TOC @ 2650m
5-1/2" Liner Hanger @ 3565m
Shoe @ 3818m
TOC@ 3565m
5-1/2" prod. tubing DHSV @ 412m
ASV @ 445m
GLV @ 3297m
DHPG @ 3329m
CIV @ 3361m
Prod. Packer @ 3516m
WEG 3568m
Reservoir top @ 3677m / 2886mTVD
Perforation interval 3677 - 3709m
Formation (Fm) with potential in overburden. Fm top @
OBF #1 3320m / 2540mTVD
Formation without potential, but water bearing. Fm top @
OBF #2 1070m
Estimation of minimum setting depth based on:
Gas density 0.23 s.g
LOT 1.72 s.g 1294mTVD
FIT 1.64 s.g 2902mTVD

Gradient curves showing pore pressure and fracture pressure were not available as part of the
data package received for well A-1. Minimum setting depth was estimated based on available
information. Pore pressure in OBF #1 was estimated from reservoir pressure, minus hydrostatic
head of seawater.

Estimated minimum setting depth for base of secondary reservoir barrier:

𝑅𝑒𝑠𝑒𝑟𝑣𝑜𝑖𝑟 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 − ℎ𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 ℎ𝑒𝑎𝑑 𝑜𝑓 𝑔𝑎𝑠 ≤ 𝐹𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛 𝑓𝑟𝑎𝑐𝑡𝑢𝑟𝑒 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒

320𝑏𝑎𝑟 − 0.23𝑠𝑔 ∗ 0.0981 ∗ (2886𝑚𝑇𝑉𝐷 − 𝑋) ≤ 1.64𝑠𝑔 ∗ 0.0981 ∗ 𝑋

𝑋 ≥ 1872.8𝑚 𝑇𝑉𝐷

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Estimated minimum setting depth for base of secondary intermediate barrier:

𝑃𝑜𝑟𝑒 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 − ℎ𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 ℎ𝑒𝑎𝑑 𝑜𝑓 𝑔𝑎𝑠 ≤ 𝐹𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛 𝑓𝑟𝑎𝑐𝑡𝑢𝑟𝑒 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒

285𝑏𝑎𝑟 − 0.23𝑠𝑔 ∗ 0.0981 ∗ (2540𝑚𝑇𝑉𝐷 − 𝑋) ≤ 1.64𝑠𝑔 ∗ 0.0981 ∗ 𝑋

𝑋 ≥ 1646.2𝑚 𝑇𝑉𝐷

Well status pre-P&A:

 Oil/water/gas in tubing, injection gas in annulus-A

 Downhole safety valve (DHSV) tested OK
 Annulus safety valve (ASV) tested OK
 Downhole pressure gauge (DHPG) and chemical injection valve (CIV) with no control line
issue.
 Side pocket mandrel (SPM) with gas lift valve (GLV) installed.
 Reservoir temperature: 127°C
 Reservoir pressure: 320 bar
 No sustained casing pressure (SCP) observed.
 Injectivity test performed OK

The well status is illustrated in the well barrier schematic (WBS) Figure 4.2.

73
Figure 4.2: WBS of A-1 prior to P&A operation. Produced with Wellbarrier software.

74
 4.1.1 Conventional approach to P&A A-1
As part of a batch P&A campaign it is common to prepare the well for P&A using stand-alone
well intervention. This pre-P&A phase include temporarily plugging the well to be able to
remove XT and installing drilling BOP. The pre-P&A operation step list will be as follow:

 Rig up wireline equipment

 Drift well
 Bullhead tubing to seawater
 Install deep set bridge plug in 5.5” liner above top reservoir and pressure test same
 Punch ASV and pressure up to release
 Run tubing cutter and cut tubing above production packer
 Install hold open sleeve in DHSV
 Install shallow set “pump open” bridge plug and test same.
 Rig down wireline equipment
 Displace well to kill mud

The well is now secured and the XT can be removed. A “pump open” bridge plug could either be
set up to open at a given pressure, or with a smart sub opening and closing at certain pressure
cycles. The following sequence is rig based and in this case performed by a jack-up rig. A step
list with an associated time estimate is presented in Appendix E. Phase 1 and 2 for reservoir and
intermediate permanent plugging will for A-1 be as follows:

 Skid rig, nipple down XT and nipple up BOP

 Retrieve tubing down to P&A depth
 Clean out run in 9-5/8” casing. Clean plug setting area.
 Run ultrasonic cement bond log
o Confirm TOC and Check for creeping shale above cement.
 Set a continuous (back-to-back) cement plug above tubing cut to act as primary and
secondary barrier for reservoir and overburden formation number one (OBF #1). TOC to
be minimum 100m above top of OBF #1
 Dress off and tag cement. Pressure test plug to LOT + 70bar.
 Cut 9-5/8” casing in area above 13-3/8” csg. shoe.
 Set casing bridge plug in 13-3/8” and pressure test same
 Displace well to seawater
 Set a cement plug above 13-3/8” bridge plug to act as primary barrier for OBF #2 and as
open hole to surface barrier. TOC to be minimum 50m above top OBF #2
 Pressure test plug to LOT + 70bar.

75
The well status after P&A operation is showed in WBS Figure 4.3.

Figure 4.3: WBS of A-1 after jack-up rig plugging operation. Produced using Wellbarrier
software
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 4.1.2 Rigless approach to P&A A-1 using emerging technologies
In this section, an operational step list will be presented using well intervention equipment and
plasma miller. The aim is to plug the well according to NORSOK D-010 (2013a) requirements.
Status prior to P&A will be exactly the same, as presented in Figure 4.2. In this approach, there
is no need for a pre-P&A temporary plugging activity as all operations are run through XT. The
surface equipment for this operation will consist of: wireline package, CT unit and a cement unit
with associated pits. The CT unit must be set up with both conventional CT reel and a reel for
plasma bit umbilical.

Operational step list for rigless TT P&A approach on A-1:

A more detailed step list and calculations performed are attached in Appendix F

1) Rig up wireline
2) Drift well for bridge plug and plasma bit
3) Bullhead tubing to seawater
4) Set bridge plug in 5-1/2” Liner above perforations. Pressure and inflow test plug.
a. Alternatively bullhead cement into reservoir up to liner hanger.
5) Punch tubing above production packer
6) Displace annulus gas (lift gas) to seawater
7) Disintegrate tubing using plasma bit. Remove minimum 100m tubing above top of OBF
#1.
8) Jet wash plug setting area using CT.
9) Run ultrasonic bond log with multifinger caliper for cement evaluation
10) Set inflatable plug to act as base for cement plugs, and test same.
11) Set 50m cement plug acting as primary barrier for reservoir and OBF #1.
12) Tag and pressure test primary cement plug to LOT + 70 bar.
13) Set a 50m cement plug, on top of primary cement plug, to act as secondary barrier for
reservoir and OBF #1.
14) Tag and pressure test secondary cement plug to LOT + 70 bar.
15) Disintegrate minimum 50m of 5-1/2” tubing in area above top of OBF #2.
16) Disintegrate minimum 50m of 9-5/8” production casing in same area.
17) Jet wash plug setting area
18) Set inflatable plug to act as cement base in 13-3/8” casing.
19) Set a 50m cement plug to act as both primary barrier for OBF #2 and open hole to
surface plug.
20) Tag and pressure test plug to LOT + 70 bar
21) Rig down equipment

77
The well barrier schematic in Figure 4.4 shows the well status after the operational sequence
listed above.

Figure 4.4: WBS of A-1 after rigless P&A operations. Produced using Wellbarrier software

78
4.1.2.1 Discussion on rigless approach to P&A A-1
Some of the operations and possible challenges or decisions to be made will be further
discussed below.

Plasma miller. The plasma miller is the key component in the rigless approach presented for A-
1. The radial reach of the plasma is possible to control to some extent, but heat will affect the
production casing, laying on low side, as shown in lab experiments presented in Chapter 3. In
addition, the casing cement may be deteriorated due to the generated heat. The production
casing and the casing cement used as WBE in the case study should be affected as little as
possible. Undesired disintegration of production casing and heat induced cracks in annulus
cement could be the result from this approach, and should be investigated further. In addition,
metal disintegration is a time consuming operation, and with a steel removal rate of 84 kg/h
the tool will have to operate several days to remove the required sections. As plasma milling
produce cuttings which are meant to drop into a sump or rat-hole, the volume of such sump
should be estimated. A-1 estimates are available in Appendix F. The porosity of both the
disintegrated material and the porosity of the cuttings bed are conservative estimates, and
needs to be further researched. Calculations show that the cuttings bed height is a factor to be
taken into account. In operations with a limited impermeable formation interval for plug setting,
cuttings may have to be removed. The preferred solution would be to circulate out most of
these cuttings to be able to set cement plugs at desired depth. Lift calculations should be made
with more accurate input data to check the possibility to lift cuttings using CT and normal
circulation. The wiper method could be a possibility if simulations show it is possible. Reverse
circulation using CT could also be a solution, but NORSOK (2013b) specifies that the CT shall
include check valves. Venturi baskets or bailers are also possibilities, but time consuming
considering the calculated cuttings volumes.

Cement evaluation. The tubing hanger and tubing leaves a major restriction that the tools need
to pass before entering the logging interval. In A-1, these tools need to pass the DHSV ID of
4.56”. In addition to limiting the choice of desired ultrasonic bond tool rotating head, the key
challenge is tool centralization. The lower density well fluid will somewhat compensate for the
smaller rotating head chosen to pass the tubing. Associated centralizers, on the other hand, are
not meant to pass restrictions smaller than the ID to be logged. More rigid centralizers will
hinder the tools while running in through the tubing, and weaker centralizers will affect
centralization once the casing to be logged is reached. Jobs have been performed running
through 7” tubing to log 9-5/8” casing, but tubing sizes of 5-1/2” and smaller could be a
challenge.

79
Alternative tools, like the Segmented Bond Tool (SBT), are available and would not have the
same issues with regards to centralization and rotating head OD. SBT might not give as accurate
log results with regards to cement channeling, but could be a viable alternative in TT P&A
applications. The SBT has a 3-3/8” OD and will log casing size in range of 4-1/2” to 13-3/8” with
same tool setup.

An alternative to cement logging could be to perforate and pressure test in steps. Coiled tubing
with two packers could be used for this purpose, although not presented in this thesis. Another
solution could be to run the thermite plug in the interval, creating a cross-sectional barrier
without the need of annular WBE.

Cement barrier and formation definitions. As listed in Table 1.3, a single cement barrier needs
to be minimum 100m unless set on a mechanical/cement plug. In the case study an inflatable
plug is considered a tested mechanical plug. An alternative to the inflatable plug could be either
a shorter cement interval, or possibly a thermite plug to act as a base. A continuous (back-to-
back) plug is not regarded a possibility on this rigless approach as it needs to be drilled to hard
cement for verification (NORSOK D-010 2013a). A CT drilling motor (PDM) could be an option,
but drilling cuttings will have to be managed. The relatively low circulation rates of CT and large
casing ID will make hole cleaning difficult. Drilling debris collection at depth could be an
alternative, although not presented in this thesis.

In the rigless approach to P&A A-1, OBF#1 and the reservoir are regarded as one reservoir.
According to NORSOK D-010 (2013a), two reservoirs in the same pressure regime could be
regarded as one. In case of pressure differences, a cross flow barrier shall be set. Depending on
these definitions, A-1 could be plugged with two, three or four cement plugs. The least time
consuming would be to set primary and secondary cement plug above overburden formation
#1, as done in the case study.

Surface equipment. Although stated that this thesis would not look into the surface equipment
issue of a rigless approach to P&A, some aspects are worth mentioning. The suggested
approach would need a wireline package in addition to CT unit and cementing pump and pits.
The proposed step list includes a lot of rigging back and forth between the different
technologies, as clarified in detailed step list in Appendix F. A more streamlined surface setup
would make the proposed solution more efficient. In addition to deck space, accommodation
for well intervention crew must be considered. On bigger NCS platforms this might not be an
issue at all, but on smaller wellhead platforms it could be factor to take into account. Shuttling
personnel to and from these wellhead platforms/normally unmanned installations (NUI) will
result in a lower operational efficiency compared to platforms with accommodation.

80
 4.2 Plug and abandonment of well A-2
The well was shut in and plugged as part of a batch P&A operation. The well schematic is
presented in Figure 4.5 and summarized in Table 4.3. As the data package received on A-2 was
incomplete, some of the well data is estimated while other data is collected from the
Norwegian Petroleum Directorate (NPD) fact page for the relevant field (NPD 2017).

Figure 4.5: Well schematic A-2. Produced with Wellbarrier software.

81
 Table 4.3: A-2 Well summary table
Description Depth
13-3/8" csg. Shoe @ 1600m / 1555mTVD
TOC @ wellhead
9-5/8" csg Shoe @ 3260m / 3020mTVD
TOC @ 3165m
5-1/2" Liner Hanger @ 2920m
Shoe @ 3565m
TOC @ 2920m
4-1/2" prod. tubing DHSV @ 165m
Prod. Packer @ 2960m
WEG 2985m
Reservoir top @ 3265m /3030mTVD
Perforation interval 3290 - 3510m
Formation (Fm) with potential in overburden. Fm top @
OBF #1 1765mTVD
Estimation of minimum setting depth based on:
Gas density 0.23 s.g Overburden
Oil density 0.662 s.g Reservoir
LOT 1.98 s.g 1555mTVD
Estimated formation strength 1.86 s.g 3020mTVD

Data in minimum setting depth Table 4.4 have been extracted from gradient curves showing
pore- and fracture pressure. The presented depths are estimated using oil gradient for reservoir
and gas gradient for OBF#1.

Table 4.4: A-2 Pore pressure and fracture pressures given in equivalent mud weight.
Minimum setting depth calculated, as for A-1, and given in table.
Formation Depth Pore pressure Fracture Minimum setting depth
pressure
Reservoir 3030 mTVD 1.67 sg 1.86 sg 2550 mTVD
OBF #1 1765 mTVD 1.65 sg 1.86 sg 1538 mTVD

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Well status pre-P&A:

 Perforations squeezed by bullheading cement through tubing. Cement plug tested and
qualified as temporary primary barrier.
 Displacement fluid from cement squeeze in tubing
 Completion fluid in annulus-A
 WL retrievable downhole safety valve installed.
 Reservoir temperature estimate: 133°C
 Reservoir virgin pressure: 483 bar
 Sustained casing pressure observed in annulus-B, between 13-3/8” and 9-5/8” csg.

The well status is illustrated in the WBS in Figure 4.6.

83
Figure 4.6: WBS for status of A-2 prior to P&A operation. Produced using Wellbarrier
software.

84
 4.2.1 Conventional approach to P&A A-2
Similar to A-1, A-2 was part of a batch P&A and preparation for rig activities were done by a
stand-alone wireline operation. The pre-P&A phase includes the following steps:

 Rig up wireline equipment

 Pull DHSV
 Drift well to hold up depth (HUD)
 Punch hole in tubing for tubing cutter
 Cut tubing in area above production packer/below scab liner hanger.
 Set shallow bridge plug with “pump open” sub in area below wellhead.
 Rig down wireline equipment
 Displace well to kill mud

The well is at this stage secured, and barriers are in place for nippling. A jack-up rig is used for
the remaining operation, including P&A phase one and two.

 Skid rig. Nipple down XT, nipple up and test drilling BOP
 Retrieve tubing down to P&A depth
 Run ultrasonic cement bond log including MFC
o Confirming no cement above scab liner top packer
o No creeping formation found in overburden
 Clean out run in 9-5/8” csg. Clean plug setting area.
 Set a 100m continuous (back-to-back) cement plug, using PWC, to act as primary and
secondary barrier for reservoir.
o Set on top of tested mechanical base
 Dress off and tag cement. Pressure test plug to LOT + 70 bar.
 Set 50 m cement plug using PWC, to act as primary barrier for OBF #1.
o Set on top of tested mechanical bridge plug
 Tag and pressure test cement plug to LOT + 70 bar.
 Set secondary cement plug in 13-3/8” shoe area using PWC.
o Ref. minimum setting depth 1538m TVD for secondary intermediate barrier.
 Tag and pressure test cement plug to LOT + 70 bar.
 Cut and pull 9-5/8” casing from required surface plug depth.
 Set surface cement plug.
o Set on top of tested mechanical bridge plug.
 Tag and pressure test cement plug to LOT + 35 bar.

85
The above sequence places two primary and secondary barriers in a well with missing annular
barrier elements in plug setting area. Status after the operation is illustrated in WBS Figure 4.7.

Figure 4.7: WBS of A-2 after jack-up rig plugging operation. Produced using Wellbarrier
software.

86
 4.2.2 Rigless approach to P&A A-2 using emerging technologies
On first review this well looks as a complex plugging operation and might not be a rigless
candidate. A-2 does not have the desired 9-5/8” TOC in sufficient height above production
packer. In A-1 this annular cement was used as a well barrier element for the reservoir plugs.
The lack of this WBE will make a rigless operation more challenging. The aim of this rigless
approach is to stay in a cased hole environment, but A-2 is a typical section mill/PWC candidate
to create a rock-to-rock barrier. Lowry and Dunn (2016) proposed a diluted thermite mixture to
swage the casing outwards into the un-cemented annulus, in combination with setting a
thermite plug internally in the casing. The amount of thermite needed for compliance with
NORSOK D-010 (2013a) results in the rigless approach presented below. A more practical use of
thermite for well plugging is presented in section 4.2.2.1, although not NORSOK D-010 (2013a)
compliant. The status prior to P&A will be same as for the conventional approach. The surface
equipment needed for the rigless approach will be the same as A-1, and all operations are
performed using CT or WL.

Operational step list for rigless TT P&A approach on A-2:

A more detailed step list and calculations performed are attached in Appendix H

1) Rig up wireline
2) Drift well for plasma bit
3) Punch tubing above production packer.
4) Displace well to seawater
5) Disintegrate tubing using plasma bit. Remove minimum 100m tubing above scab liner
top packer.
6) Set inflatable plug and heat insulating material above scab liner packer in 9-5/8” csg.
Pressure test plug.
7) Place diluted thermite to swage casing into formation and create a 50m cross-sectional
primary reservoir barrier.
8) Tag plug and pressure test primary thermite plug to LOT + 70 bar.
9) Place diluted thermite to create a 50m cross-sectional secondary reservoir barrier.
10) Tag plug and pressure test secondary thermite plug to LOT + 70 bar.
11) Disintegrate minimum 100m of tubing in area above OBF #1.
12) Set and pressure test an inflatable plug with heat isolating material to act as base for
thermite mixture.
13) Place diluted thermite to swage casing into formation and create a 50m cross-sectional
primary intermediate barrier.
14) Tag plug and pressure test to LOT + 70 bar.

87
 15) Place diluted thermite to swage casing into formation and create a 50m cross-sectional
secondary intermediate barrier
16) Tag plug and pressure test to LOT + 70 bar
17) Disintegrate minimum 50m of tubing using plasma bit in area above 20” csg. shoe.
18) Disintegrate 9-5/8” production casing in same area using plasma bit.
19) Set and pressure test an inflatable plug with heat insulating material to act as base for
thermite mixture.
20) Place thermite to create a 50m cross-sectional barrier in 13 3/8” casing. This will act as
open hole to surface barrier.
21) Tag plug and pressure test to LOT + 35 bar
22) Rig down equipment

Figure 4.8 illustrates the well barrier status after the rigless P&A approach listed above.

88
Figure 4.8: WBS of A-2 after rigless P&A operation. Produced using Wellbarrier software.

89
4.2.2.1 Discussion on rigless approach to P&A A-2
Some aspects of the operation and possible challenges are further discussed below.

Diluted thermite to swage casing. The concept of using thermite to plastify the casing, making
it extend radially and swage against the borehole wall, was presented by Lowry and Dunn
(2016). No research has been published on the matter, and it could perhaps not be possible at
all. The production casing annulus would most likely consist of settled mud at the desired depth,
and the proposed swaging operation might not be needed. Verifying settled material in this
annular space by logging would be difficult due to the small tubing ID.

Assuming that swaging the casing using thermite is not possible, and that the casing will be in a
molten state after thermite initiation, then creation of a cross-sectional barrier can be difficult.
Internally in the casing the thermite mixture is set on top of a plug with a heat insulating
material placed between the plug and thermite, as illustrated in Figure 3.16. This plug will act as
a base and will not be affected by the thermite reaction heat. If the un-cemented casing is
molten and not plastified then the molten plug material might be displaced to a lower depth in
the annulus. This displacement may occur due to the lower density annular fluid in the un-
cemented void space and the higher density molten thermite mixture. The desired cross-
sectional barrier interval would not be achieved if such a displacement occurs.

A fluid filled annulus might not be as great a challenge as assumed in this thesis, and should be
investigated further. This investigation might also provide some answers to whether it will be
possible to place thermite directly in the tubing, creating a cross-sectional formation to
formation barrier (with a fluid filled annulus A and B).

Thermite placement. In the above sequence, thermite placement is proposed done by

circulating, as presented by Skjold (2013). Both companies researching thermite plugs are
planning for WL conveyed thermite placement. When setting barriers according to current
NORSOK (2013a) regulations it would lead to several dozen runs, as briefly estimated in Chapter
3. If circulation is a viable solution for thermite placement then the plasma milled section might
be redundant. A possibility could be to circulate the slurry through big hole perforations in
tubing thereby placing the thermite slurry in the annulus-A and tubing, much like a PWC
operation. The total concept of pumping thermite must be thoroughly researched with risk in
mind. An un-intended ignition of thermite in pumps etc. could be catastrophic. By conveying
thermite by WL in a concealed container, ignition will be easier to control.

90
Supercritical fluids due to thermite combustion heat. As described in Chapter 3 well fluids in
close vicinity of the thermite reaction will reach a supercritical state on typical NCS reservoir
barrier depths. Tests have been performed in a test cell to simulate well conditions, as
described in section 3.2.3, but these results have not been published. The effect of igniting
thermite downhole should be investigated further to identify if the superheated vapour will
reach surface, and how to deal with it.

Thermite plug height. The requirement of placing nearly 7m3 of thermite to create a total of
100m primary and secondary reservoir barrier seems excessive. The product of a thermite
reaction, when diluted, has favorable sealing properties, as presented in Chapter 3. Further
research and tests should be done on sealability, and with favorable results the NORSOK D-010
(2013a) height specifications can be challenged. This also seems to be the approach chosen by
the R&D company developing the thermite P&A plug. A reduced plug height will make the
intended WL conveyance approach more viable.

Rigless P&A of A-2. As mentioned above, A-2 might not be the optimum candidate for a rigless
P&A approach. The well design makes P&A a complex operation. An option could be to perform
phase 1, reservoir abandonment, using a rigless approach. The intermediate plugging
operations, phase 2, would be performed by a rig. By doing these operations in batches, the rig
scope could be reduced significantly. An alternative WBS showing status after reservoir P&A of
A-2 using thermite plugs conveyed by WL are presented in Figure 4.9. The approach illustrated
in the figure assumes thermite plug height requirements less than 50 m in future NORSOK D-
010 (2013a) revisions. A step list of this approach is presented in Appendix I.

91
Figure 4.9: Rigless approach to plug reservoir using thermite plug set on WL. Assuming
thermite plug length requirement will be less than for cement in future NORSOK D-010
(2013a) revisions. Produced using Wellbarrier software.

92
 4.3 Plug and abandonment of well A-3
The well was initially completed as a horizontal oil producer, and shut-in to be part of a batch
P&A operation. The well schematic is presented in Figure 4.10 and summarized in Table 4.5. A-3
has a complex overburden with several formations to be sealed off during P&A. The overburden
formations (OBF) that have a potential to flow and/or are water/hydrocarbon (HC) bearing have
been given numbers, for a more systematic approach.

Figure 4.10: Well schematic of A-3. Produced with Wellbarrier software.

93
 Table 4.5: A-3 well summary table
Description Depth
20" csg. Shoe @ 384m
TOC @ wellhead
13-3/8" csg. Shoe @ 1454m / 1377mTVD
TOC @ wellhead
9-5/8" csg Shoe @ 2606m / 2433mTVD
TOC @ 2106m
7-5/8" Liner Hanger @ 2567m / 2409mTVD
Shoe @ 2699m / 2481mTVD
TOC @ 2567m
7" x 5-1/2" Liner Hanger @ 2491m / 2359mTVD
Shoe @ 3498m / 2529mTVD
TOC @ 2700m
5-1/2" x 4-1/2" prod. tubing DHSV @ 213m
X-Over @ 631m
Prod. Packer @ 2502m
WEG 2506m
Reservoir top @ 2699m / 2481mTVD
Perforation interval 2805m - 3413m
Formations (Fm) with potential in overburden.
OBF #1 Fm top @ 2288m / 2188mTVD
OBF #2 Fm top @ 1529m / 1444mTVD
OBF #3 Fm top @ 946m / 929mTVD
Formations (Fm) with normal pressure.
OBF #4 Fm top @ 697m / 692mTVD
OBF #5 Fm top @ 539m / 538mTVD
OBF #6 Fm top @ 494m / 493mTVD
OBF #7 Fm top @ 424m / 424mTVD
Formation (Fm) without potential, but water bearing.
OBF # 8 Fm top @ 224m / 224mTVD
Estimation of minimum setting depth based on:
Gas density 0.16 s.g
Oil density 0.67 s.g
LOT @ 20" shoe 1.80 s.g 384mTVD
LOT @ 13-3/8" shoe 1.94 s.g 1377mTVD
FIT @ 9-5/8" shoe 1.87 s.g 2433mTVD

94
Minimum setting depth estimated based on pore- and fracture pressure given for the
overburden formation, using gas density. Results are presented in Table 4.6.

Table 4.6: A-3 Pore pressure and fracture pressures given in equivalent mud weight.
Minimum setting depth calculated, as for A-1, and given in table.
Formation Depth Pore pressure Fracture pressure Minimum setting depth
Reservoir 2481 mTVD 1.70 sg 1.90 sg 2196 mTVD
OBF #1 2188 mTVD 1.58 sg 1.90 sg 1786 mTVD
OBF #2 1444 mTVD 1.68 sg 1.90 sg 1262 mTVD
OBF #3 929 mTVD 1.06 sg 1.90 sg 480 mTVD

Well status pre-P&A:

 Oil/water/gas in tubing
 Completion fluid in annulus-A
 DHSV tested OK
 Reservoir temperature: 92°C
 Reservoir pressure: 414 bar
 Sustained casing pressure observed in annulus-B, between 13-3/8” and 9-5/8” csg.
 Injectivity test performed OK

The well status is illustrated in WBS, Figure 4.11.

95
Figure 4.11: WBS of A-3 prior to P&A operation. Produced with Wellbarrier software.

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 4.3.1 Conventional approach to P&A A-3
Similar to the two previous wells A-3 was part of a batch P&A campaign. The pre-P&A phase
were done as a stand-alone well intervention operation, using CT and wireline. The pre-P&A
phase include the following steps:

 Rig up CT unit
 Drift well to plug setting depth.
 Run MFC including pressure and temperature logs.
 Set cement plug above perforations using CT.
 Tag and inflow/pressure test cement plug.
 Cut tubing above production packer.
 Displace well to brine through tubing cut.
 Lock open/set wear sleeve in DHSV
 Set shallow “pump open” bridge plug above DHSV and pressure test same.
 Rig down equipment
 Displace well to kill mud

The well is at this stage secured, with barriers in place for nippling. A jack-up rig is used for the
remaining P&A operations:

 Skid rig, nipple down XT, nipple up BOP and pressure test.
 Retrieve tubing down to P&A depth
 Clean out run in 9-5/8” casing. Clean out plug setting area.
 Run ultrasonic cement bond log in 9-5/8” casing.
o Confirm TOC.
o Check for creeping shale above cement.
 Set a continuous (back-to-back) plug to act as primary and secondary barrier for
reservoir and OBF #1. TOC plug to be 100m above OBF #1.
o Set on tested mechanical base
 Dress off, tag and verify cement plug by pressure test
 Set a continuous cement plug using PWC to act as primary and secondary barrier for
OBF #2. TOC plug to be 100m above OBF #2.
o Set on tested mechanical base.
 Dress off, tag and verify cement plug by pressure test
 Cut and pull 9-5/8” casing from top of OBF #3 depth.
 Clean out run in 13-3/8” casing. Clean out plug setting area.
 Run ultrasonic cement bond log in 13-3/8” casing.

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  Set a continuous cement plug to act as primary and secondary barrier for OBF # 3
o Set on top of a tested mechanical base.
 Dress off, tag and verify cement by pressure test
 Set a continuous cement plug to act as primary and secondary barrier for OBF # 4,#5,#6
and #7
o Set on top of a tested mechanical base.
 Dress off, tag and verify cement by pressure test
 Recover 13-3/8” csg from top of OBF #8 depth.
 Clean out 20” csg
 Run ultrasonic cement bond log in 20” casing.
 Set surface cement plug and test same
o Set on top of tested mechanical base

The above sequence places four primary and secondary barriers in a well where one of the OBF
was missing an annular barrier element. The plugs are acting as barriers for the reservoir and 8
overburden formations.

Status after the above P&A operation is illustrated in WBS Figure 4.12.

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Figure 4.12: WBS of A-3 after jack-up rig plugging operation. Produced using Wellbarrier
software.

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 4.3.2 Rigless approach to P&A A-3 using emerging technologies
A-3 has a complex overburden with several formations to be sealed off. The overburden
formation #2 is in an area where 9-5/8” casing is un-cemented, leading to the need of PWC or
section milling in conventional rig P&A. In addition it is completed with a 5.5” x 4.5” tubing. The
small ID of a 4.5” tubing could make annular barrier verification a challenge in all rigless TT P&A.
Similar to A-2, this well would not be the optimum candidate for a fully rigless P&A approach
due to its small tubing, lack of annular barrier for OBF#2 and its complex overburden. For the
purpose of the thesis, a partial rigless P&A approach is presented below. As ultrasonic cement
logging tools presently available will not pass the tubing restrictions of this well, a segmented
bond tool (SBT) is assumed to provide sufficient log quality for the annular barrier verification.
The approach is chosen to demonstrate diversity between the three case studies. The below
step list could be regarded as an alternative pre-P&A operational approach. All operations in
the sequence are performed using wireline or coiled tubing.

Operational step list for a partial rigless TT P&A approach on A-3:

A more detailed step list and calculations performed are attached in Appendix K.

1) Rig up CT unit
2) Drift well to top of perforations.
3) Set cement plug from top perforations to top of reservoir. Set on cement retainer.
4) Tag cement plug, pressure and inflow test.
5) Disintegrate minimum 50m of 5-1/2” Liner using Plasma bit to expose the 7-5/8”
cemented liner.
6) Log 7-5/8” Liner cement using SBT
7) Set an inflatable plug to act as base for cement plug, and test same.
8) Set 50m cement plug in 7-5/8” liner to act as primary barrier for reservoir
9) Tag and pressure test barrier plug
10) Disintegrate minimum 50m of 5-1/2” liner in area below tubing WEG to expose 9-5/8”
cemented production casing.
11) Clean out plasma bit cuttings bed to gain 50m plug setting interval.
12) Log 9-5/8” casing cement in plug setting interval using SBT
13) Set inflatable plug to act as base for cement plug, test same.
14) Set 50m cement plug in 9-5/8” csg. to act as secondary barrier for reservoir.
15) Tag and pressure test secondary barrier plug
16) Disintegrate minimum 100m tubing using plasma bit in area above OBF #1.
17) Log 9-5/8” csg. cement in same area using SBT
18) Set inflatable plug to act as base for cement plug, test same.

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 19) Set 50m cement plug to act as primary barrier for OBF #1
20) Tag and pressure test primary barrier plug
21) Set 50m cement plug to act as secondary plug for OBF #1
22) Tag and pressure test secondary barrier plug
23) Set hold open/wear sleeve in DHSV
24) Set shallow “pump-open” bridge plug and pressure test same
25) Rig down equipment
26) Displace well to kill mud.

The well status after the proposed rigless P&A operations is presented in Figure 4.13. The well
is secured and ready for nippling. After BOP installation a rig could pull tubing and continue the
plugging operation from OBF #2 and upwards.

4.3.2.1Discussion on rigless approach to P&A A-3

Some aspects of the operation and possible challenges are further discussed below.

Rigless batch P&A. The proposed solution would save several rig-days. For A-3 nearly 5.5 days
were estimated to clean out and log 9-5/8” csg and installing reservoir and OBF #1 barriers.
Assuming a CT unit cost to be a fifth of rig rate, the above rigless sequence should be
completed within twenty-seven days to be competitive. The main time consuming activities in
the proposed rigless P&A would be to change CT reels back and forth, as the plasma bit uses a
special umbilical CT, while other applications use conventional CT.

Cement evaluation tools. As discussed for A-1, some compromises might have to be made with
regards to cement bond logging data. The 4.5” tubing (4.5” 15.2ppf: 3.826” ID) could result in
the desired size ultrasonic rotating head not passing the restrictions. To run two different
logging tools in combination, ultrasonic azimuthal bond log and CBL/VDL, is often done to
confirm the bonding results and gain confidence in the annular barrier quality. In rigless P&A
operations run through small tubing, the ultrasonic rotating head might have to be deleted
from the string. According to NORSOK D-010 (2013a) “The measurement shall provide
azimuthal/segmented data”. This means that the SBT can be used as an alternative to the
ultrasonic tool. Only creeping formation WBE qualification requires two independent tools
where azimuthal log is specified as one of them.

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Figure 4.13: WBS of A-3 after rigless P&A of reservoir and OBF #1. Produced using
Wellbarrier software.

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5. Results and Discussion
Several challenges with the rigless P&A approach using emerging high-energy technologies
have been discussed in the case studies. These challenges will also be discussed briefly in this
section, in addition to other aspects of the rigless P&A approach to provide an overall picture.

5.1 Electric plasma miller

Metal disintegration. The tool is in the research and development (R&D) stage. Field trials have
not been performed, and it is therefore difficult to identify all the possible challenges. The A-1
case study well was plugged using a plasma miller to remove tubing and gain access to the
cemented casing. The company developing the Plasma Bit appears to be aiming for a different
approach than that proposed in the case study. Their approach includes removing both the
tubing and the casing with the associated cement to gain access to formation, much like a
conventional section mill (Gajdos et al. 2015; Gajdos et al. 2016). The alternative method
presented in this thesis will have to be further researched before concluded viable. Casing and
cement integrity after exposure to heat from the plasma miller will be an important issue to be
clarified. In addition, its ability to remove control lines and larger completion components, such
as side pocket mandrels should be investigated.

Through tubing cement bond logging. One of the key elements in the proposed approach is the
ability to run cement logging tools through tubing. These logging tools are designed to run
directly in casing, not to pass a tubing ID before reaching the intended logging interval.
Preferred centralizers for these tools are rigid slip-over centralizers, while through tubing
conveyance would require softer in-line centralizers. In-line centralizers could have trouble
centralizing the tools in highly deviated sections. In addition the preferred size azimuthal
ultrasonic rotating head for 9-5/8” csg. will not pass tubing of 5-1/2” and smaller. Alternative
tools are available and selection will be dependent on well configuration and logging data
requirement.

Surface equipment. An aspect of the proposed approach that may not be highlighted in the
case study is the surface equipment and changeover between WL, CT and plasma miller. The
Plasma Bit requires a purpose built CT-reel conveyed umbilical, while other operations utilize
WL or conventional CT. Changing reels back and forth, or setting up both reels for simultaneous
operation could impose challenges. Deck space and deck load capacity should be investigated in
a feasibility study for the specific platform, while crane and weather also must be taken into
account during operation. Smaller wellhead platforms, or “normally unmanned installations”
(NUI), with limited deck space and no accommodation would lead to an ineffective operation.
Personnel would need shuttling or temporary accommodation. Equipment might have to be

103
rigged down, and removed to clear deck space, before rigging up new equipment for next step
in the operation.

Plasma Bit cuttings. Disintegrating tubing, using Plasma Bit, produces high porosity cuttings.
The cuttings are intended to drop into a sump (rat-hole) below the plug setting area. Not all
well configurations will allow a large enough rat-hole, as seen in A-3. This would also be an
issue in A-1, depending on the two lower zones defined as one or two reservoirs. If defined as
two reservoirs, then three or four cement plugs should to be set, and the cuttings height would
push plug setting depth shallower than desired. Estimations done in the case study show it is a
factor to take into account. Disintegrating one meter of 5-1/2” tubing inside a 9-5/8” csg will
produce a 0.4m high cuttings bed, given the estimated porosities. As each meter removed
tubing will leave only 60 cm of exposed casing for plug setting, cuttings removal should be
evaluated. Further research on the cuttings matrix porosity/density and the possibility to
circulate out and clean rat-hole area should be done.

Cement plug verification. Setting permanent P&A cement plugs and verifying them is
conventionally done by drill pipe on the NCS. NORSOK D-010 (2013a) reflects this, as tagging
and drilling to hard cement are common methods for verification. Setting a continuous (back-
to-back) plug was not regarded an option during the rigless approach proposed. Such a plug
must be drilled to hard cement for verification, and hole cleaning could be an issue in a mud-
less well environment using CT. Verification by tagging is not further specified in NORSOK D-010
(2013a). Setting down weight on drill pipe can provide significantly more tagging force than
when tagging with CT or WL. Tagging with CT was considered sufficient during the case studies,
although the plugs were also pressure tested.

5.2 Thermite plug

Plugging material placement. Placing enough thermite to comply with NORSOK D-010 (2013a)
plug height requirements could be a challenge. Both R&D companies are aiming for a WL
conveyed plug placement technique. The R&D company developing a thermite plug for P&A
purposes is promoting it as an option where no tubing removal is required. Not removing the
tubing before igniting the thermite could compromise its ability to create a cross-sectional
barrier. No research has presently been published on the matter. An annular base for the plug
material should be in place to conceal thermite while plastified. Tools providing a base in the
annular void space are available on the market (Gunnarsson et al. 2016). Assuming a 3” ID and
20m long WL conveyed container an estimated thermite plug height would be 1.43m if set in a
4-1/2” tubing, sitting in an un-cemented 9-5/8” csg in a 12-1/4” borehole. This calculation

104
includes tubular steel as part of the plug volume. In addition to setting only 2.86% of the
required plug length, rigging in a 20m WL tool will be a challenge in a stand-alone operation.
Stacking several containers, similar to stackable straddles (Agayev et al. 2016), or running
several containers by use of deployment BOP, could be an option to supply sufficient plug
height.

Qualifying minimum thermite barrier height. Sufficient plug height made of new plugging
materials like thermite is not specified in NORSOK D-010 (2013a). The element acceptance
criteria (EAC) for a “material plug” are equal to that of cement plug, with plug length and
verification methods in mind. Oil & Gas UK (2012b) Guidelines on qualification of materials for
the suspension and abandonment of wells specify acceptance criteria for mass transportation
properties in the qualification process of new materials: “Since the permanent barrier is
effectively reinstating the caprock, the acceptance criteria are based on performance of the
caprock. Specifically, the length and permeation characteristics (permeability or diffusion
properties) of the barrier should be such that the rate of release of fluids in the well should be
equal or lower than that of the caprock once breakthrough has occurred”. Based on Oil & Gas
UK (2012b) guidelines, and experiments as presented by Lowry et al. (2015) on thermite plug
permeability, a minimum plug height could be estimated. In addition, it is worth mentioning
that NORSOK D-010 (2013a) is an industry standard, and not regulation. Other approaches are
allowed as long as the operating companies can document that a chosen solution is as good as
or better than current regulations.

Thermite placement by circulation. Depending on the results on minimum plug height the
viability of a WL conveyed or circulation plug placement technique could be decided. As briefly
discussed in Chapter 4, circulation of thermite must be thoroughly investigated to confirm that
no un-planned ignition can occur.

Superheated well fluids. All well fluids in close vicinity of the thermite combustion reaction will
reach a supercritical state. The effects that these superheated fluids have downhole, and if
reaching surface, should be investigated further. Tests have been done to better understand
the reaction in wellbore conditions, as described in section 3.2.3, but these test results are not
public.

Proposed area of application. Assuming the qualification of a single run WL conveyed thermite
plug, it will be a lean method for reservoir P&A, similar to the alternative rigless approach on A-
2 (Figure 4.9 and Appendix I). By placing thermite in a cemented 7” or 5-1/2” liner a single WL
run could possibly provide sufficient plug height. The same WL tool as described above will

105
provide a 5m thermite plug once set in a 7” liner, which might be sufficient depending on
results from qualification testing.

5.3 Rigless P&A using Well Intervention equipment

Well configuration and choice of technology. As seen in the case study, different well
configurations require different tools for P&A. While the electric plasma miller was a lean tool
for plugging A-1, the same method could not be used for A-2. A-2 was plugged using thermite,
due to its un-cemented casing in desired plug interval. While the proposed A-2 approach might
be a possibility in the far future, the alternative approach seems more viable with the current
R&D results. The complex overburden and un-cemented casing make A-2 and A-3 significantly
more challenging to P&A using a rigless approach.

Batch Rigless P&A. A rigless P&A approach must be based on the well configuration complexity.
As seen in the Case Study, increasing P&A complexity will shift operations towards rig based
P&A. Several NCS wells might be plugged using a rigless approach from start to completion, if
they have an advantageous well configuration and relatively simple overburden. Other wells
could be candidates for a rigless P&A of the reservoir only. After the reservoir is plugged the
overburden zones can be plugged using a rig. Case Study well A-3, and the alternative approach
on A-2, are examples of such wells. An estimated six rig-days can be saved on each of these
wells utilizing a rigless approach for reservoir abandonment. Significant savings could be
obtained utilizing batch rigless reservoir P&A, followed by batch conventional P&A of the
overburden. Estimating a platform with 20 wells to be plugged, a total of 120 rig-days could be
saved using the approach.

Rigless P&A could potentially take longer time than conventional P&A. The viability of rigless
P&A is dependent on its ability to plug a well at lower cost than a rig. As estimated in the Case
Study for A-3, the rigless approach should be completed within five days per rig-day to be
competitive, based on coiled tubing unit cost being one fifth of rig cost.

NORSOK D-010 rev.4 (2013a). As seen in the case studies, compliance with NORSOK D-010
(2013a) can be a challenge in rigless P&A. A qualification guideline for plugging materials,
similar to Oil & Gas UK (2012b), should be considered as a supplement to NORSOK D-010
(2013a). By qualifying new plugging materials, design and verification methods for the specific
material could be specified. In addition, NORSOK D-010 (2013a) will need a revision to
implement rigless P&A and new technology, as it is presently written with conventional P&A in
mind. Verification methods for cement/material plugs, especially for continuous (back-to-back)
plugs, should be reconsidered to include rigless P&A technology. Next revision of NORSOK D-

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010 (2013a) should open for new approaches to P&A without compromising on barrier integrity.
As Case Study of A-2 showed, it is not practical to plug wells using rigless P&A methods while
complying with current industry standards.

Well intervention equipment. Several of the technologies presented in Chapter 2 were never
included in the case study. Some of these technologies could provide additional information to
be used in the P&A design.

The multifinger caliper log, presented in section 2.1.1.1, could provide a status of the casing
internal surface condition after the plasma milling operation. The MFC can be run in
combination with the cement bond logging tools, verifying that the casing has not been
disintegrated or affected by plasma miller heat. This combination was proposed in the A-1 case
study.

The annular flow detection tool, presented in section 2.1.1.2, could be run in an investigation
WL run prior to any P&A operation. This would give valuable information if there is a suspicion
of an annular flow (leading to SCP) in the intended plugging area. By verifying, or locating the
flow, the P&A design could be adjusted accordingly. Cost of starting a P&A operation and
having to re-assess the approach could potentially be saved.

Similarly an electromagnetic defectoscope for corrosion detection, presented in section 2.1.1.3,

could be run in a pre-P&A investigation WL run. Casing condition can be logged through tubing,
providing information that could be used in the P&A design.

The abrasive cutter, presented in section 2.3.3, could potentially be used to sever conductors
for phase 3 of the P&A. Phase 3 has not been covered as part of the rigless approach. By cutting
several pipes using the abrasive cutter, these could be pulled by means of a jacking unit or
similar. Although multiple cuts on 13-3/8” and 9-5/8” casings have been done using the
technology, tests needs to be conducted to verify its ability to cut typical NCS conductors in
range of 20” to 30”.

107
Intentionally left blank

108
6. Summary
The objective of this thesis was to investigate the viability of a rigless approach to P&A. By
combining conventional well intervention technologies with some emerging high-energy P&A
technologies, potential rigless P&A approaches was proposed in a case study. All rigless
operations throughout the case study were run through production tubing and X-mas tree in a
cased hole environment, without the use of mud.

The rigless P&A approach proposed in case study of A-1 was possible by use of an electric
plasma miller, used to disintegrate steel downhole. By removing production tubing, and gaining
access to cemented casing, annular barrier verification was possible. A cross-sectional barrier
was obtained by setting a cement plug in the logged interval by use of coiled tubing.

Well A-2 in the case study had a more complex well configuration with regards to P&A. This
well did not have the desired top of cement in sufficient height above production packer, to
utilize the same approach as done on A-1. In the case study of A-2 thermite was used to create
a cross-sectional barrier, in areas lacking annular well barrier element. The required volume of
thermite, to comply with current NORSOK D-010 plug height specifications, introduced
challenges in plugging material placement. The thermite was placed by means of pumping it as
slurry. An alternative approach was proposed by use of wireline, although not according to
current NORSOK D-010.

The last well in the case study had both a complex overburden and well configuration with
regards to P&A. A total of nine formations were to be isolated, and one of them were missing
annular barrier in the desired plug setting area. A partial rigless P&A approach was suggested to
seal of the two lower zones by use of a similar methodology as on A-1. The remaining
formations were left to be plugged by a drilling rig. This extended “pre-P&A” phase could
potentially save several rig-days.

The case study showed that different well configurations identified the need for different
approaches and technology for P&A. Not all wells are suited for a rigless P&A for the complete
work scope, however parts of the plugging could be done without the use of a rig. The major
part of the studied wells had a complex well configuration with lack of annular barrier in
desired plug setting interval as main contributor to the complexity. Minor changes to NORSOK
D-010 could open up for a leaner rigless P&A methodology by specifying design/length
requirements and verification methods for new plugging materials. Cement plug verification
methods should also be evaluated to include rigless P&A technology. Wells with a complex
overburden and well configuration could utilize rigless P&A for batch reservoir abandonment,

109
leaving the overburden to be plugged using a rig. Significant savings could be realized if one, or
both, of these technologies are qualified for P&A operations.

Proposed focus areas for rigless P&A viability confirmation can be summarized as:

General findings:

 Modification of NORSOK D-010 to implement new P&A technology and rigless P&A
 Implement plugging material qualification guidelines in NORSOK D-010, similar to Oil &
Gas UK Guidelines on qualification of materials for the suspension and abandonment of
wells. Length requirements/design and verification methods of material plug for P&A
purpose should be specified based on qualification results.
 Categorize wells based on P&A complexity, to identify potential rigless P&A candidates.

Electric plasma miller:

 Radial reach of plasma. Confirming that casing and cement integrity are not affected by
plasma miller or heat.
 Plasma miller umbilical. Confirm that it is possible to supply sufficient power at typical
NCS reservoir barrier depth.
 Through tubing cement bond logging. Confirming alternative tools for bond logging
provide sufficient logging data, and verifying in-line centralizer ability to centralize tool
string in deviated wells.

Thermite plug:

 Qualify thermite plug according to Oil & Gas UK Guidelines on qualification of materials
for the suspension and abandonment of wells. Document results and define a minimum
plug height based on worst case permeability during experiments.
 Based on findings, confirm the viability of WL conveyance. Investigate possibilities of
stacking or running several thermite containers in single run if needed.
 Confirm the thermites ability to create a cross-sectional barrier once set in tubing, with
a fluid filled annulus.

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7. Future research
This thesis has investigated the possibility to plug platform wells using well intervention
equipment in combination with some emerging high energy technologies. This section will
propose several aspects that could, or should, be further researched.

Cost and time analysis of case study. This thesis has not provided a thorough time (and cost)
analysis of the rigless approach compared to a conventional P&A approach. If sufficient data
can be sampled, the case studies could be analyzed and a more decisive conclusion could be
made on the viability of a rigless P&A approach.

Surface equipment on rigless P&A. Surface equipment, weight and deck load capacity, crane
and accommodation has not been thoroughly investigated in this thesis. A study could be
conducted to check how many NCS platforms are candidates to host a rigless P&A operation,
with the associated equipment and personnel.

Subsea rigless P&A. As this thesis only investigate platform well P&A, a similar study could be
conducted for subsea wells, using Light Well Intervention vessels and emerging technologies.
Confirming the viability of subsea rigless P&A operation could be a game changer, even if the
approach only could complete parts of the P&A scope.

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118
Appendix

Appendix A: WBS status prior to P&A

Appendix A: Well Barrier Schematic of example well prior to pre-P&A phase (during production).
Produced using Wellbarrier software

119
Appendix B: WBS status after pre-P&A operation

Appendix B: Well Barrier Schematic of example well after pre-P&A phase. X-mas tree can be
removed and drilling BOP installed. Produced using Wellbarrier software.

120
Appendix C: WBS status prior to P&A, BOP installed

Appendix C: Well Barrier Schematic of example well after installation of BOP, while pulling
tubing. Produced using Wellbarrier software.

121
Appendix D: WBS status permanent P&A completed

Appendix D: Well Barrier Schematic after completion of permanent plug and abandonment
operations. Produced using Wellbarrier software

122
Appendix E: Time estimate A-1 Jack-up rig operation

123
Appendix F: Detailed step list for A-1 Rigless P&A approach

124
125
 A-1 Rigless P&A. Well calculations appendix to detailed operational step list.
step list
point
3) Tubing volume estimate
Di in Area m2 length m volume m3
4,653 0,01097 3568 39,1

Pressure test calculations

Plug TVD Formation Hyd head Diff surface
depth estimate pressure of pressure pressure
m m bar seawater bar needed
4) bar bar
3600 2900 320 293,0 27,0 54,0

6) Annulus volume estimate

Di in Do in Area m2 length m volume m3
8,535 5,5 0,0215838 3510 75,8

7.2) Rat hole fill estimation

meters of 5,5 20# removed 110 m
Top of milled window 3210 m
Bottom milled window 3320
Estimated plug setting interval 110,0 m
steel volume m3 of 5,5 20# pr meter 0,003774 m3
volume m3 of disintegrated steel 0,42 m3
Disintegrated material volume including
material porosity of 50% 0,83 m3
Estimated volume of cuttings bed including
50% bed porosity 1,66 m3
Area (volume per meter) of 5,5 tubing/liner 0,01097 m2
Volume of rat hole above plug in 5,5" liner and
tubing 3,07 m3
Length of 5,5" available 280,00 m
Remaining volume of cuttings to fill 9-5/8" rat
hole 0,00 m3
Area (volume per meter) in 9-5/8 casing 0,036912 m2
Estimated height of cuttings bed in 5,5 151,3746
Estimated height of cuttings bed in 9-5/8 0,0 m
Estimated depth of top cuttings bed (cut at
3510m 3448,6 m

126
7.3) Estimated time used on disintegrating
Length of disintegrated tubing 110,0 m
Weight pr meter of tubing 29,8 kg/m
Total mass to disintegrate 3278,0 kg
Estimated steel removal rate 84,0 kg/h
Estimated time consumed 39,0 hours

8.2) Average cuttings density

Steel pore fluid porosity Average
density density density

7,85 1,03 0,5 4,44

Cement plug pressure test calculations

Plug TVD FIT/LOT Formation Test Hyd head surface
base estimated EMW s.g LOT pressure of pressure
mMD m pressure bar seawater needed
bar bar bar
12) 3315 2540 1,64 408,6 478,6 256,6 222,0
14) 3265 2540 1,64 408,6 478,6 256,6 222,0
20) 1065 1065 1,72 179,7 249,7 107,6 142,1

15.1) Rat hole surface plug

meters of 5,5 20# removed 60 m
Top of milled window 1010 m
steel volume m3 of 5,5 20# pr meter 0,003774 m3/m
volume m3 of disintegrated steel 0,23 m3
Disintegrated material volume including
material porosity of 50% 0,45 m3
Estimated volume of cuttings bed including
50% bed porosity 0,91 m3
Area (volume per meter) of 5,5 tubing/liner
0,01097 m2
Estimated cuttings height
82,56797 m
Volume of rat hole above plug in 5,5" liner and
tubing 11,08 m3
Estimated depth of top cuttings bed (cement
top @ 3100) 3017,4 m

127
 Estimated time used on disintegrating
15.2)
Length of disintegrated tubing 60,0 m
Weight pr meter of tubing 29,8 kg/m
Total mass to disintegrate 1788,0 kg
Estimated steel removal rate 84,0 kg/h
Estimated time consumed 21,3 hours

Rat hole surface plug from 9-5/8

16.1) meters of 9-5/8 53.5# removed 60 m
Top of milled window 1010 m
steel volume m3 of 9-5/8 53,5# pr meter 0,01003 m3/m
volume m3 of disintegrated steel 0,60 m3
Disintegrate material volume including
material porosity of 50% 1,20 m3
Estimated volume of cuttings bed including
50% bed porosity 2,41 m3
Area (volume per meter) of 5,5 tubing/liner 0,01097 m2
Estimated cuttings height 219,4257 m
Volume of rat hole above plug in 5,5" liner and
tubing 11,08 m3
Estimated depth of top cuttings bed (cement
top @ 3100) 2798,0 m

Estimated time used on disintegrating

16.2)
Length of disintegrated tubing 60,0 m
Volume to remove 0,6 m3
Density steel 7850,0 kg/m3
Total mass to disintegrate 4724,1 kg
Estimated steel removal rate 84,0 kg/h
Estimated time consumed 56,2 hours

128
Appendix G: Time estimate A-2 Jack-up rig operation

129
Appendix H: Detailed step list for A-2 Rigless P&A approach

130
131
132
 A-2 Rigless P&A. Well calculations appendix to detailed operational step list.
Step list
point
4) Tubing volume estimate
Di in Area m2 length m volume m3
3,833 0,007444 2915 21,7

Annulus volume estimate

Di in Do in Area m2 length m volume m3
8,535 4,5 0,026651 2915 77,7

5) Rat hole fill estimation

meters of 4,5 12,6# removed 110 m

Top of milled window 2810 m
Estimated plug setting interval 110,0 m
steel volume m3 of 4,5 12,6# pr meter 0,002323 m3/m
volume m3 of disintegrated steel 0,26 m3
Disintegrated material volume including
material porosity of 50% 0,51 m3
Estimated volume of cuttings bed including
50% bed porosity 1,02 m3
Area (volume per meter) of 5,5 tubing/liner 0,01213 m2
Volume of rat hole above plug in 5,5" liner and
tubing (90meters) 3,64 m3
Estimated height of cuttings bed in 5,5 liner 84,3 m
Estimated depth of top cuttings bed 3138,7 m

5.3) Estimated time used on disintegrating

Density of steel 7850,0 kg/m3
Total volume of disintegrated steel 0,3 m3
Total mass to disintegrate 2005,9 kg
Estimated steel removal rate 84,0 kg/h
Estimated time consumed 23,9 hours

7) Thermite plug volume estimate

borehole total volume
plug
Di in Area m2 length m volume m3
12,25 0,076038 50 3,80188955

133
 volume of casing steel
Di in Do in Area m2 length m volume m3
9,625 8,535 0,01003 50 0,501498526

Volume of thermite needed

borehole casing thermite
volume volume volume
7.1 3,80189 0,501499 3,300391 m3

Height of thermite in 9-5/8"

Volume Height in 9-
Di in Area m2 needed 5/8
7.3) 8,535 0,036912 3,300391 89,4130753

10) Top of primary plug, worst case if no radial expansion into 12-1/4 borehole
base of height top
plug thermite thermite
2915 89,41308 2825,587

10) Cement plug pressure test calculations

Plug TVD FIT/LOT Formation Test Hyd surface
base estimated EMW s.g pressure pressure bar head of pressure
mMD m bar seawater needed
bar bar
res pri 2915 2715 1,86 495,4 565,4 274,3 291,1
res sec 2815 2625 1,86 479,0 549,0 265,2 283,7
int pri 1715 1650 1,98 320,5 390,5 166,7 223,8
int sec 1665 1600 1,98 310,8 380,8 161,7 219,1
surface 525 525 1,98 102,0 137,0 53,0 83,9

Rat hole surface plug from 9-5/8

16.1) meters of 9-5/8 53.5# removed 60 m
Top of milled window 470 m
steel volume m3 of 9-5/8 53,5# pr meter 0,010029971 m3/m
volume m3 of disintegrated steel 0,60 m3
Disintegrated material volume including
material porosity of 50% 1,20 m3
Estimated volume of cuttings bed including
50% bed porosity 2,41 m3

134
 Estimated time used on disintegrating
16.2)
Length of disintegrated tubing 60,0 m
Volume to remove 0,6 m3
Density steel 7850,0 kg/m3
Total mass to disintegrate 4724,1 kg
Estimated steel removal rate 84,0 kg/h
Estimated time consumed 56,2 hours

11) Thermite plug volume estimate

borehole total volume

plug
Di in Area m2 length m volume m3
12,5 0,079173 50 3,96

135
Appendix I: A-2 Partial Rigless approach to P&A

136
137
Appendix J: Time estimate A-3 Jack-up rig operation

138
Appendix K: A-3 Partial Rigless approach to P&A

139
140
 A-3 Rigless P&A. Well calculations appendix to detailed operational step list.

step list point

5) Rat hole fill estimation

meters of 5,5 20# removed 54 m

Top of milled window 2606 m
Bottom milled window 2660
Estimated plug setting interval 54,0 m
steel volume m3 of 5,5 20# pr meter 0,003774 m3
volume m3 of disintegrated steel 0,20 m3
Disintegrated material volume including
material porosity of 50% 0,41 m3
Estimated volume of cuttings bed including
50% bed porosity 0,82 m3
Area (volume per meter) of 5,5 tubing/liner
0,01097 m2
Estimated height of cuttings bed in 5,5 74,31117 m
Available rat hole 80 m

11) Rat hole fill estimation

meters of 5,5 20# removed 57 m

Top of milled window 2510 m
Bottom milled window 2567
Estimated plug setting interval 57,0 m
steel volume m3 of 5,5 20# pr meter 0,003774 m3
volume m3 of disintegrated steel 0,22 m3
Disintegrated material volume including
material porosity of 50% 0,43 m3
Estimated volume of cuttings bed including
50% bed porosity 0,86 m3
Area (volume per meter) of 5,5 tubing/liner
0,01097 m2
Estimated height of cuttings bed in 5,5 78,43957 m
Available rat hole 43 m
Estimated volume to be cleaned out 0,39 m3
Estimated height to be cleaned out 35,44

141