Sigve Hamilton Aspelund: Coiled tubing underbalanced drilling

Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.

Managed pressure drilling systems.
Multilateral wells. Coiled tubing
underbalanced drilling.



* geophysical well logging
* under reaming following multistage underbalanced
drilling
* cement plug placing
* emergency and fishing operations
* selection criteria for well bore candidates
* job planning and risk analysis
* CT ground equipment
* coiled tubing pipes
* coiled tubing machinery (capillary units, injectors,
reels etc.)
* equipment for flow control and completion (drilling
motors, drilling jars, intensifiers, reamers, Collars,
etc.)
* high tech drilling bits



Nitrogen equipment application for coiled tubing
drilling

*
*
*
*
*
*

gas liquid mixtures
nitrogen compressor stations
pumping units
vaporiser systems for CT
continuous circulation systems and agitators
management and control systems

Separation systems for drilling fluids
*
*
*
*
*

centrifuges
hydrocyclones
shakers
pumps
management and control

Geophysical well logging
-

Schlumberger brothers, Conrad and Marcel, are
credited with inventing electrical well-logs.

-

On September 5, 1927, the first “well-logA” was
created in a small village named Pechelbroon in
France.

-

In 1931, the first SP (spontaneous potential) log
was recorded. Discovered when the
galvanometer began “wiggling” even though no
current was being applied.

-

The SP effect was produced naturally by the
borehole mud at the boundaries of permeable
beds. By simultaneously recording SP and
resistivity, loggers could distinguish between
permeable oil-bearing beds Managedimpermeable
and pressure drilling systems.
nonproducing beds.

Types of Logs
a) Gamma Ray
b) SP (spontaneous potential)
c) Resistivity (Induction)
d) Sonic
e) Density/Neutron
f) Caliper


a) Gamma Ray






The gamma ray measures the natural
radioactivity of the rocks, and does not
measure any hydrocarbon or water
present within the rocks.
Shales: radioactive
potassium is a common
component, and because
of their cation
exchange capacity,
uranium and thorium
are often absorbed as
well.
Therefore, very often
shales will display

The scale for GR is in API (American
Petroleum Institute) and runs from 0125 units. There are often 10 divisions
in a GR log, so each division
represents 12.5 units.
 Typical distinction between between a
sandstone/limestone and shale occurs
between 50-60 units.
 Often, very clean sandstones or
carbonates will display values within
the 20 units range.



b) SP (Spontaneous
Potential)
The SP log records the electric
potential between an electrode pulled
up a hole and a reference electrode at
the surface.
 This potenital exists because of the
electrochemical differences between
the waters within the formation and
the drilling mud.
 The potenital is measured in millivolts
on a relative scale only since the
absolute value depends on the
properties of the drilling mud.



In shaly sections, the maximum SP response
to the right can be used to define a “shale
line”.
 Deflections of the SP log from this line
indicates zones of permeable lithologies with
interstitial fluids containing salinities differing
from the drilling fluid.
 SP logs are good indicators of lithology where
sandstones are permeable and water
saturated.
 However, if the lithologies are filled with fresh
water, the SP can become suppressed or
even reversed. Also, they are poor in areas
where the permeabilities are very low,
sandstones are tighly cemented or the
interval is completely bitumen pressure drilling systems.
Managed saturated (ieMultilateral wells. Coiled tubing
oil sands).


c) Resistivity (Induction)
Resistivity logs record the resistance of
interstitial fluids to the flow of an electric
current, either transmitted directly to the
rock through an electrode, or
magnetically induced deeper into the
formation from the hole.
 Therefore, the measure the ability of
rocks to conduct electrical currents and
are scaled in units of ohm-meters.
 On most modern logs, there will be three
curves, each measuring the resistance of
section to the flow of electricity.



Porous formations filled with salt water (which
is very common) have very low resistivities
(often only ranging from 1-10 ohms-meter).
 Formations that contain oil/gas generally
have much higher resisitivities (often ranging
from 10-500 ohms-meter).
 With regards to the three lines, the one we
are most interested in is the one marked
“deep”. This is because this curve looks into
the formation at a depth of six meters (or
greater), thereby representing the portion of
the formation most unlikely undisturbed by
the drilling process.
 One must be careful of “extremely” high
values, as they will often represent zones of
either anhydrite or other non-porous intervals.



d) Sonic






Sonic logs (or acoustic) measure the
porosity of the rock. Hence, they
measure the travel time of an elastic
wave through a formation (measured in
∆T- microseconds per meter).
Intervals containing greater pore space
will result in greater travel time and vice
versa for non-porous sections.
Must be used in combination with other
logs, particularly gamma rays and
resistivity, thereby allowing one to better
understand the reservoir petrophysics.

e) Density/Neutron
Density logs measure the bulk electron
density of the formation, and is measured in
kilograms per cubic meter (gm/cm3 or kg/m3).
 Thus, the density tool emits gamma radiation
which is scattered back to a detector in
amounts proportional to the electron density
of the formation. The higher the gamma ray
reflected, the greater the porosity of the rock.
 Electron density is directly related to the
density of the formation (except in
evaporates) and amount of density of
interstitial fluids.
 Helpful in distinguishing lithologies, especially
between dolomite (2.85 kg/m3) and limestone
(2.71 kg/m3



Neutron Logs measure the amounts of
hydrogen present in the water atoms of a
rock, and can be used to measure porosity.
This is done by bombarding the the formation
with neutrons, and determing how many
become “captured” by the hydrogen nuclei.
 Because shales have high amounts of water,
the neutron log will read quite high porositiesthus it must be used in conjunction with GR
logs.
 However, porosities recorded in shale-free
sections are a reasonable estimate of the
pore spaces that could produce water.



It is very common to see both neutron
and density logs recorded on the
same section, and are often shown as
an overlay on a common scale
(calibrated for either sandstones or
limestone’s).
 This overlay allows for better
opportunity of distinguishing lithologies
and making better estimates of the
true porosity.
* When natural gas is present, there
becomes a big spread (or crossing) of
the two logs, known as the “gas



f) Caliper
Caliper Logs record the diameter of
the hole. It is very useful in relaying
information about the quality of the
hole and hence reliability of the other
logs.
 An example includes a large hole
where dissolution, caving or falling of
the rock wall occurred, leading to
errors in other log responses.
 Most caliper logs are run with GR logs
and typically will remain constant
throughout



Underbalanced drilling
Though not as common as
overbalanced drilling, underbalanced
drilling is achieved when the pressure
exerted on the well is less than or
equal to that of the reservoir.
 Performed with a light-weight drilling
mud that applies less pressure than
formation pressure, underbalanced
drilling prevents formation damage
that can occur during conventional, or
overbalanced drilling processes.





The negative differential pressure
obtained during underbalanced drilling
between the reservoir and the
wellbore encourages production of
formation fluids and gases. In contrast
to conventional drilling, flow from the
reservoir is driven into the wellbore
during underbalanced drilling, rather
than away from it.



Although initially more costly,
underbalanced drilling, also known as
managed-pressure drilling, reduces
common conventional drilling problems,
such as lost circulation, differential
sticking, minimal drilling rates and
formation damage. Additionally,
underbalanced drilling extends the life
of the drill bit because the drilling gases
cool the bit while quickly removing
cuttings.

To establish pressure control, a rotating
control head with a rotating inner seal
assembly is used in conjunction with the
rotating table. An important factor to
successful underbalanced drilling, drilling and
completion operations must remain
underbalanced at all times during operations.
To accomplish this, pre-planning and onsite
engineering are critical to the success of
underbalanced drilling procedures.
 Typically used for only a section of the entire
drilling process, underbalanced drilling
cannot be used in most shale environments



Underbalance Gases


Gases used for underbalance include
air, nitrogen and natural gas.
Although it is not typical, if natural gas
is recovered from the well, it can be
reinjected into the well to establish
underbalance, resulting in the most
cost-effective solution for



Commonly used in under balance
operations, nitrogen is preferred for its
somewhat low cost of generation,
scale of control and minimal potential
for downhole fires. While pure
nitrogen can be purchased, it is costprohibitive. Therefore, nitrogen is
more commonly produced onsite with
a membrane unit, resulting in a 95%
level of purity.

Underbalance Techniques




There are four main techniques to
achieve underbalance, including
using light weight drilling fluids, gas
injection down the drill pipe, gas injection
through a parasite string and foam
injection.
Using lightweight drilling fluids, such as
fresh water, diesel and lease crude, is
the simplest way to reduce wellbore
pressure. A negative for this approach is
that in most reservoirs the pressure in
the wellbore cannot be reduced enough
to achieve under balance.



The method of injecting gas down the
drillpipe involves adding air or nitrogen
to the drilling fluid that is pumped directly
down the drillpipe. Advantages to this
technique include improved penetration,
decreased amount of gas required, and
that the wellbore does not have to be
designed specifically for underbalanced
drilling. On the other hand,
disadvantages include the risk of
overbalance conditions during shut-in
and the requirement of rare MWD tools.



In performing the gas injection via
parasite string, a second pipe is run
outside of the intermediate casing.
While the cost of drilling increases, as
does the time it takes, this technique
applies constant bottom hole pressure
and requires no operational
differences or unique MWD systems.



A less common underbalanced
application, nitrogen foam is less
damaging to reserves that exhibit water
sensitivities. While the margin of safety is
increased using foams, the additional
nitrogen needed to generate stable foam
makes this technique cost prohibitive.
Additionally, there are temperature limits
to using foam in underbalanced drilling,
limiting using the technique to wells
measuring less than 12,000 feet deep.

Cement Plugs
Cement slurry design.
– Cement type and additives.
• API class
• Extenders, shrinkage, gas control, fluid loss
control, formation and pipe adherence, spacers.
• Volumes and excesses.
• Placement method.
– Location identification,
– Depth control,
– Spotting method (bailer, circulation, etc.),
– Contamination control,
– Testing requirements.

Cement Plug Placement
Balanced method.
• Modified balanced method.
• Displacement from surface.
• Two plug circulation.
• Grouting – various.
• Mechanical assistance.


Setting a cement plug
Not as easy as it may seem
• Position of the end of tubing (EOT)
may not correspond to where the plug
is actually set.
• What are the considerations of setting
a
cement plug in mud?
• Effect of fluid loss and cross flow on
setting an effective cement plug?

Setting Cement Plugs
A near 100% reliable system if cross flow
can
be stopped.
• Most cement plugs fail because of cross
flow,
density and viscosity mismatch, or failure
to
“break” the fluid momentum.
• Full plug method described and field
tested in SPE 11415 (published in SPE
JPT Nov 1984, pp 1897-1904) and SPE

Cement Plug Failure
Many cement plugs fail for the same 4 reasons:
1. Cross flow cuts channels into the plug.
2. Cement is higher density that the mud – cement
falls through the mud. Mud contamination of the
cement may keep it from setting.
3. The mud is much lower viscosity than the
cement
slurry – cement falls through the mud
4. The open ended tubing produces a high
momentum energy condition that the mud cannot
stop – thus cement falls through the mud.
The result of the last three is that the cement is
spread out along the hole andManaged pressure drilling systems.
a plug is never
formed.

How?
1. Use a simple tubing end plug with circulation to the side
and
upward but not downward.
2. Spot a heavily gelled bentonite pill below the cement plug
depth. Pill thickness of 500- 800 ft (152- 244 m).
3. Use a custom spacer to separate the pill and the cement
slurry.
4. Use a viscous, thixotropic cement with setting time equal to
the job time plus ½ hr. Plug thickness of 300 to 600 ft (91 to
183 m)
5. Rotate the centralized tubing (do not reciprocate) during
placement and gently withdraw at the end of the pumping.
6. WOC = 4 hrs for every 1 hour of pump time.
Full details and field tests in SPE 11415.

Reasons for Cement Plug
Failures
• Contamination of the cement slurry
with
drilling mud during or immediately after
placement.
• Failure to place a viscous pill to stop
downward movement of cement slurry.
• Inaccurate knowledge of volumes
required.

General Requirements
• Onshore – 10 ft (3 m) plug on top of
the well and casing cut 3 ft (1m) below
the ground surface.
• Mud between plugs (9.5 lb/gal).
• Plug thickness minimum of 100 ft, plus
10% for each 1000 ft of zone.


Procedures
• Remove salvageable equipment.
– NORM scale present? Leave the pipe in
the well?
– What pipe is needed for a barrier? How
effective?
• Set, at minimum, plugs required by
regulations.
Don’t hesitate to go beyond requirements.
• Test to limits required.
• Cap and identify as specified.

Isolation of Open Hole
• Cement Plug 100ft (30m) above and
below lower-most shoe in open hole.
• Cement retainer 50 to 100 ft (15 to
30m)
above the shoe. Cement 100 ft (30m)
below shoe and 50 ft (15m) of cement
on top.
• Tested to 15,000 lbs load or 1000 psi.

Isolation of Perforations
below
perfs (or to next plug).
• Cement retainer 50 to 100 ft (15 to 30m)
above the perfs. Cement 100 ft (30m)
below
shoe and 50 ft (15m) of cement on top.
• Permanent bridge plug within 150 ft
(45m) of perfs with 50 ft (15m) of cement
on top.

Isolation of lap joints or liner tops
below liner top (or to next plug).
• Cement retainer or permanent bridge
plug 50 ft (15m) above the liner with
50 ft (15m) of cement on top.
• Cement plug 200 ft (60m) long within
100 ft (30m) of liner.


Finding and Repairing Channels
in Cement
Channels in cement occur from many causes:
– Lack of effective pipe centralization,
– Inadequate mud conditioning prior to cementing,
– Ineffective cement displacement design and/or
execution,
– Excess free water in the cement, especially in a
deviated
hole (usually a cement mixing problem).
– Excessive fluid loss from the cement slurry (generally
results in low cement top),
– Gas influx before the cement sets,
– Cement shrinkage,
– Etc.

Identifying Channels in Cement
Sheath
Numerous logging methods:
– CBL and segmented CBL tools that
scan around the wellbore,
– Borax logging, Carbon-Oxygen logs,
Sonic tools, etc.
• Plug and packers with perforating.


Repair of Channels - Cement
Squeezes
Types (some names anyway)
– Block squeeze
– Cement Packer
– Suicide squeeze
– Breakdown squeeze
– Running and Walking squeezes
– Hesitation squeeze
• What is used depends on both what is
needed and the experience of the
operator.

Surface Plug
On-Shore – depends on local
regulations.
• Offshore – cement plug 150 ft (45m)
long
within 150 ft (45m) of mud line. Placed
in the smallest string of casing that
extends to the mud line.


Testing of Plugs
Location of the first plug below the
surface
plug shall be verified.
– Pipe weight of 15,000 lbs on cement
plug, cement retainer, or bridge plug.
– Pump pressure of 1,000 psi with
maximum 10% drop in 15 minutes.


Risk evaluation
Risk & unwanted incidents ranking
 Systems in place


• Report incidents and near miss
• Analyse material
• Look for trends


Risk definition



Risk=Practicable*Consequence
Risk to
 Personel
 Environment
 Material


Mapping of HSE & risks


Register incidents: Positive and
negative


Cause assesment
• Direct causes vs underlying causes
• Cause perspective
– Human
– Technical
– Organisational

• 5 Whys technique
– Look for underlying causes
– Eliminate root of the problem


HSE analyse
QRA: Quantity Risk Assesment
QRM: Qualitative Risk Matrix
Safe job analysis – Chemical
analysis
Risk assesment promt card


Risk reduction
ALARP: As Low As Reasonable
Practicable
 BAT: Best Available Technology
 Precation principles
 Substitution principles



Barriers – swiss cheese
model
The Barriere Concept
BARRIERS;
Technical,
Qualifications,
Procedures
etc.

INITIATING
INITIATING
CAUSE
CAUSE

ACCIDENT/
ACCIDENT/
LOSS
LOSS

We are all responsible for managing
HSE
Barrier 1 – HSE Policy & Leadership
Hazard/
Risk

Barrier 2 – Planning

I was responsible for
planning the
operations safely



Hazard/
Risk

Barrier 3 – Supervision

I turned a blind eye to
some of the crew not
following all the
procedures as we had
limited time to do the job

I was responsible
for supervising the
maintenance work



Hazard/
Risk

Barrier 3 – Supervision
Barrier 4 – Procedures

I didn’t work safely
and took short-cut
to get the job done

Accident

I was responsible
completing the work

We all have a part to play
Mngt Team

Finance/Accounting

Visible leadership
promotes HSE
culture …..

Resources allocated
for effective
implementation

Resource budgets
effectively tracked
and managed

Maintenance
Maintain equipment and
ensure that operational
integrity is maintained

SJA team

Legal
Legal requirements
of projects identified
and complied with

Hazards identified
and risk mngt plans
implemented
Drilling

HR
Competencies required
for job are clearly
identified

IT/ Data/
Graphics

Systems to control and
securely store HSE
critical information

Risk management integrated
to drilling programme
HSE dept

Contract

Ensure that Company are
Guidance and
given the means to perform
advisory support Managed pressure drilling systems.
the job safely and efficiently
provided to
operations

How Does Fishing Work?




There are a number of problems that can
occur while drilling a well. Whether a drill
string breaks and falls to the bottom of
the wellbore or a bit breaks, accidents
happen. Even pipe or a tool can fall from
the rig floor into the bottom of the well.
This stray equipment that has fallen into
the well is referred to as fishor junk, and
regular drill bits cannot drill through it.
Should a fish fall into a well, fishing is
required to remove it.

Fishing tools


In order to perform fishing on a well, drilling
must be shelved and special fishing tools
employed. Each tool is specially crafted to
perform a specific function, or retrieve a
certain type of fish. Most fishing tools are
screwed into the end of a fishing string,
similar to drillpipe, and lowered into the well.
 There are two options to recover lost pipe.
The first is a spear, which fits within the pipe
and then grips the pipe from the inside. On
the other hand, an overshoot may be
employed, and this tool surrounds the pipe
and grips it from the outside to carry it up the
wellbore.



When a fish is difficult to grip, a washover
pipe or washpipe is used. Made of largediameter pipe with a cutting surface at the tip,
washpipe is run in the well and then the cutting
edge grinds the fish to a smooth surface. Then
drilling fluids are pumped into the well to remove
debris, and another tool is used to retrieve the
remaining fish.
 Sometimes, a junk mill and boot basket are
used to retrieve fish from the wellbore. In this
instance, a junk mill is lowered into the well and
rotated to grind the fish into smaller pieces. A
boot basket, also known as a junk basket, is then
lowered into the well. Drilling fluid is pumped into
the well, and the ground parts of the fish are
raised into the basket and then towells. Coiled tubing by
the surface
Multilateral
the boot basket.




In order to recover casing that has
collapsed within the well or irregularly
shaped fish, a tapered mill reamer can
be used. Permanent and magnetic
magnets are employed to reclaim
magnetic fish, and a wireline
spear uses hooks and barb to clasp
broken wireline. Additionally, an
explosive might be detonated within the
well to break the fish up into smaller
pieces, and then a tool such as a junk
bucket is used to retrieve the smaller
items.



When a fishing professional is unable
to determine which fishing tool might
work best to retrieve the fish,
an impression block is used to get
an impression of the fish and allow the
professional to know with what exactly
he or she is dealing.




Fishing a well may take days to
complete, and during this time, drilling
cannot occur, although the operator is
still responsible for drilling fees. Some
drilling contractors offer fishing
insurance, making operators not
responsible for rig fees during fishing
operations.

Statoil records first successful North
Sea HP/HT coiled tubing milling job
Telemetry proves critical for intervention at
Kvitebjoern on Norwegian continental shelf
 Statoil learned valuable lessons during the
planning and execution of a high
pressure/high-temperature (HP/HT) coiled
tubing milling job on the Norwegian
continental shelf (NCS) in the North Sea at
Kvitebjørn field.
 Kvitebjørn is a Statoil-operated gas and
condensate field in block 34/11 with a
reservoir at about 4,000 m (13,120 ft) with
pressure of 770 bar (11,168 psi) and
temperature of 160º C (320º F). Coiled tubing
Multilateral wells.





Well 34/11-A-9 T2 was drilled as a gas producer
and during the final completion phase, it was not
possible through pressure cycling to open the
HP/HT isolation ball valve set in the 9 7/8-in. liner
at 6,245.7 m (20,486 ft) MD/3,795.8 m (12,450 ft)
TVD. After several failed attempts with wireline
using mechanical override tools, it was decided
to punch above it to allow well production
passing the outside of the valve through the
annulus between 9 7/8-in. liner and the 5½-in. tail
pipe. However, the production performance was
poor. A feasibility study evaluated ways to open
or mill out the valve with the objective to improve
the production characteristics and to allow
access for future production logging.





The decision was to mill the stuck-closed
isolation ball valve using coiled tubing
(CT). Statoil had not performed any
HP/HT CT operations and the available
experience was limited.
To minimize uncertainty relating to depth
determination during milling, a telemetry
system ran at its operational pressure
and temperature limits to provide realtime casing collar locator (CCL) readings
in addition to downhole pressure and
temperature data.

The Super 13% chrome, 110 Kpsi yield isolation ball
valve was stuck closed at a deviation of 57.8º. Its ID
when open is 4.25-in with a drift ID = 4.151 in. The
EOF seating nipple at 6,223 m (20,411 ft) MD from the
rig kelly bushing was ID = 4.31 in., which represents
the minimum wellbore restriction from surface down to
the ball valve depth.
 The 34/11-A-9 T2 well is in the Statfjord formation with
the top of perforations at 4,313 m (14,147 ft) TVD. The
original prognosed reservoir pressure was 770 +45/-14
bar (11,168 + 653/-203 psi) and the downhole
temperature at reservoir was 160º C. The shut-in
wellhead pressure was 571 bar (8,282 psi) in March
2011. The expected downhole temperature at the ball
valve was 145º C (293º F). The H2S and
CO2 concentrations in the produced gas were less than
5 ppm and a concentration of 3.477 mol %, respectively.



A feasibility study including an onshore milling
test evaluated the possibility of milling the
isolation ball valve with an electrical mill
assembly run on mono-conductor wireline cable.
The report concluded with large uncertainty
regarding the number of bailer runs necessary to
remove debris above the valve and reach milling
depth, as well as the lifetime for the electrical
milling equipment at the very high downhole
temperature. Based on this study and the low
estimated likelihood of success (30 -- 40%), the
Kvitebjørn license decided not to proceed with
the wireline alternative.
 New feasibility studies evaluated using CT, rigassisted snubbing, and the rig for opening or
milling out the isolation ball valve.wells. Coiled tubing
Multilateral



Wellbore schematic.


The CT alternative seemed to be feasible since
similar jobs were performed at lower temperature
and shallower depths, but the 15K psi well
control equipment and CT string design would
have to be specified and sourced specifically for
the job.
 The main drawbacks for the rig-assisted
snubbing were the drilling crew's rig-assisted
snubbing experience, rig-assisted snubbing
personnel experience, ram-to-ram stripping
experience, and HP/HT well conditions.
 For the rig alternative, the main risks were gas
migration to the surface in addition to more time
and cost relating to killing the well.



Well control stack as built




It was decided that the primary
method to be further evaluated and
developed for removal of the ball valve
restriction from the well would be CT,
the secondary method would be rigassisted snubbing and the final
method would be to use the rig.


Concept selection
During the concept selection phase, the
recommended method for deploying CT to
remove the isolation ball valve from the
wellbore consisted of the following steps:
 Pre-CT job "pump and bleed“
operation. Displacing the wellbore from the
current gas by repeatedly bullheading 1.044
sg 40/60% MEG/fresh water from the kill wing
valve of the christmas tree and bleeding the
gas that migrates to surface. The aim of this
"pump and bleed" step was to reduce the
surface shut-in wellhead pressure (SIWHP)
to the minimum before running the CT. This
had advantages in safety and operations.





CT drift and cleanout run(s). The well was producing
intermittently for few months through punched holes
above the closed ball valve. It was suspected that fill
and debris might have settled above the ball valve with
the 11.5-m (38-ft) interval between the punched holes
and top of the ball valve being particularly vulnerable.
Offshore crane capacity limits and the long CT string
needed to reach the ball valve at 6,245.7 m (20,492 ft)
MD RKB, the maximum CT string size that could be
shipped in one piece was 2- in. OD. The well
completion from surface to approximately the ball valve
depth was 7 in., 35 lb/ft tubing with a 6-in. ID.
Therefore, it was impossible to generate enough
turbulence in the annulus between the tubing and CT to
lift any fill or debris when run in hole (RIH) with the
milling bottom hole assembly (BHA) to mill the ball
valve. It was decided to RIH first with a with venturi jet
junk basket (VJJB) to drift and clean out the wellbore to
the top of the ball valve.



CT milling run(s). This was the ultimate run to achieve the
job objective and mill the ball valve. The motor needed to
provide enough torque to mill through the ball valve. In
addition, its operating pump rate should be achievable
through the specially designed 2-in. CT string. A yard test and
a successful milling job of a similar ball valve in a well
operated by Shell in the British section of the North Sea were
on record. The mill was a 4.1-in. OD dome profile ball mill run
with a hydraulically (pump rate) operated shifting tool and an
anti-stall tool. All lessons learned during this Shell job were
taken into account for this Kvitebjørn CT project. The mill was
designed and tested to mill through the ball valve material.
The mill size for this Kvitebjørn job was decided to be 4-in.
OD to deploy the milling BHA through the 41⁄16-in. 15K psi
CT BOP. This mill size is big enough to allow later production
logging tools to run through the milled hole. This critical
detailed planning phase took approximately five months. It
consisted of organizing several meetings and coordinating
between different departments, disciplines, and third parties.

Offshore execution


The job went as planned. The CT job
was carried out through the drilling rig.
The ball valve was successfully milled
and drifted with the 4-in mill and the
access to the lower wellbore was
regained.


CT equipment layout on pipe
deck.






No serious HSE & Q incidents were
reported during this first HP/HT CT job in
Statoil and the Norwegian continental
shelf with a high operating factor of
96.2%.
The total job duration was 31.6 days with
equipment rig up including "pump and
bleed" of 10.9 days; one VJJB clean up
run and three milling runs totaling 9.1
days; extra production test and one extra
drift run with VJJB through and below the
milled ball valve, 6.1 days; and
equipment rig down and back load, 5.5
days.

Operational risk analysis
An operational risk analysis log sheet and
risk register covering the different steps of the
operation was elaborated during detailed
planning. This was important because this
was the first HP/HT CT operation in Statoil
and in the NCS.
 The risk assessment involved representatives
from all concerned disciplines within Statoil,
including reservoir, well intervention, drilling
and production, plus Statoil discipline
advisors for CT, well intervention, well
integrity, HP/HT, and well control, as well as
third-parties representatives for CT services
and the rig contractor.







The probability and the potential impact
for each initial risk were assessed using
a standard risk tolerance matrix.
Prevention and mitigation actions were
identified for each risk with the objective
of reducing the probability and/or the
potential impact of the corresponding
risk.
This resulted in a detailed operational
risk register including 41 identified
hazards and 84 risk prevention and/or
mitigation measures that were
implemented during the planning and
execution phases.

This risk register was subdivided into 11 sections as
following:
 1. Mobilization and demobilization
2. Spotting and equipment rig up
3. "Pump and bleed" operation
4. VJJB drift and cleanout run(s)
5. Milling run(s)
6. Well control stack up
7. BHAs
8. Fluids
9. Contingency scenarios
10. Rig down equipment
11. Simultaneous contingency situations
in A-9 T2 and a second well.

Lessons learned
There were a number of lessons learned on this project.
They key lessons are described below.
 Telemetry tool performance. The telemetry tool
provided valuable CCL data to correlate the depth down
to the ball valve. The telemetry tool failed in three of
four runs at a bottomhole temperature around 145ºC
(293º F). However, the CCL logging signal failed after
the initial depth correlation. The telemetry tool was
running properly for its first few hours of exposure under
extreme downhole pressure and temperature conditions
before it failed. It was a known and accepted risk prior
to operation that the tool might fail if exposed to
downhole conditions close to or above its operational
specifications of 8,000 psi/150º C (55 MPa/305º F) for a
prolonged time. It could be concluded from the data that
the telemetry tool operated properly up to 564 bar
(8,180 psi) and 146º C (295º F) before failure.





Equipment availability. The equipment
availability for this special and non-frequent
HP/HT CT job was a challenge. Early
planning and ordering of some critical
equipment was vital, especially knowing the
day rate of the drilling derrick to be used. This
critical equipment included both CT strings,
the gas tested 71⁄16-in./15K psi gate valve,
the safety head handler, the gas-tested
christmas tree crossover, and the 21⁄16-in
15K psi gas tested gate valves. Weekly
meetings to review critical items were held
with the CT contractor. The need for long lead
items was identified early in the project, and
Managed for drilling systems.
Statoil issued purchase orderspressure relevant
equipment.

Site surveys. Three site surveys were
carried out by Statoil and CT
contractor representatives to avoid
conflict with platform interfaces, and to
identify any limitations or special
requirements.
 Personnel HP/HT training. Two fullday sessions of CT awareness and
HP/HT seminars were organized and
presented by the CT contractor to all
involved personnel before the job start
up.



Bleed off procedure. The bleed off needed to avoid
explosive decompression of well control equipment
elastomers was not provided by the CT contractor.
Rather, the local platform best practice used during
wireline operations was followed during this CT job. For
future CT HP/HT operations, the bleed off procedure
should be based on recommendations from the original
equipment manufacturer for standard and high-pressure
well conditions, respectively.
 Pump and bleed operation. Liquid losses into
formation were experienced during the "pump and
bleed" phase and it was not possible to reduce the
WHP. It was decided to abort the pump and bleed
operation and to start running in the well while
circulating through the CT. This alternative was
effective in reducing the WHP.





CT weight simulations. A drag
reduction by 25% (from 0.24 to 0.18)
was observed when displacing the
wellbore with metal-to-metal friction
reducer while RIH from 4,200 m
(13,776 ft) MD RKB to the ball valve.
Data proves that the actual CT RIH
and pick up weights were within the
operating limit at 80% yield of CT
string material.



Milling through the ball valve. It was difficult to control
the weight on bit (WOB) at 6,245 m (20,484 ft) MD
while pumping 40/60% MEG/fresh water at 400 l/m
pump rate and at 340 to 375 bar (4,931 to 5,439 psi) CT
circulation pressure. During the first milling run, the
WOB was set down gradually but the motor stalled 15
times. The first milling BHA was pulled to surface for
inspection. During the second milling run, milling was
carried out with patience for longer periods without
increasing the WOB. Vibration and an anti-stall tool
was expected to provide sufficient WOB. The top part of
the ball valve was milled during the second run in
approximately 12 hours and the bottom part in an
additional 12 hours. The experience gained from the
first milling run was used to optimize the milling
parameters of the second and third milling runs, and
succeeded to break through the ball valve with the 4-in.
mill at the end.



Confirmed milled ball valve. A 3D
multi-finger caliper log was run on
wireline two months after the CT
milling job to investigate the wellbore
status, particularly the milled ball valve
area. The ball valve was confirmed to
be milled out with a minimum ID of
3.97 in. at 6,245.7 m MD.

Conclusion


This CT project represents an excellent
reference for future HP/HT CT operations for
Statoil in Norway and worldwide. The job
execution was performed as planned and in
compliance with the relevant industry
standards and local regulations. The stuck
closed isolation ball valve was successfully
milled and drifted with the 4-in. dome profile
mill. No serious HSE&Q incidents were
reported during this first HP/HT CT job in the
Norwegian continental shelf, which had a
high operating factor of 96.2%. Valuable
lessons learned from the planning and
execution phases of this challenging
operation should be useful in future similar
HP/HT CT applications. Multilateral wells. Coiled tubing

Coil tubing equipment


Hydra Rig Trailer mounted 2” CT unit,
two trailer design, 22,000 feet reel
capacity, 80,000 lbs. pull injector and
50 ton crane




Hydra Rig 6100 CT Injector with
tubing straightener and leveling lift
bale




Offshore 1¼” CT Unit




Hydra Rig Trailer Mounted Sichuan
CTU



Hydra Rig Trailer Mounted CTU and
pumper on location in Turkestan




Hydra Rig Intermediate size trailermounted CTU with crane, 635 injector




Hydra Rig’s new 55,000 sq. ft. final
assembly and CTU maintenance
facility




CTD horizontal re-entry project, with NOV Hydra Rig coiled
tubing unit, nitrogen unit, and NOV Rolligon pumping unit.
Also utilized are NOV Texas Oil Tools BOPs and NOV CTES
DAS system.




Hydra Rig Mini Coil Drop In Drum




Hydra Rig Mini Coil 420C Injector
Head




Hydra Rig Mini Coil Unit


Snubbing Units
NOV Hydra Rig Snubbing Units have earned a reputation
worldwide for high performance and versatility in the field.
Rig-up is fast due to lightweight, compact design and the
elimination of the need to “kill” the well.
NOV Hydra Rig Snubbing Units are engineered to work on
any pressure well, with pipe sized up to 8s”, and pulls up
to 600,000 lbs.
With over 200 units manufactured, our snubbing units are
the industry standard.


Coring and drilling




Hydraulic fracturing




Shaker


Communications and safety
issues
The Piper Alpha Disaster
In 1988 Britain suffered one of the
worst industrial disasters when the
Piper Alpha oil Platform was
destroyed by fire and gas
explosion, resulting in 167
fatalities. The disaster caused
significant changes to the manner
in which safety was regulated and
managed in the UK offshore oil
industry.

Events in the disaster


The Piper Alpha platform was operated by Occidental
Petroleum (Caledonia) Ltd. and located 110 miles
notheast of Aberdeen



The platform produced oil and gas and was linked to
the installations Tartan, Claymore and MCP01 by
subsea pipelines



On July 6, 1988, dayshift workers had removed a safety
release for a consendate pump that was not being used
and replaced it with a blank flange



Several hours later the night shift operations team
experienced a problem with a second consendate pump
and restarted the first pump, unaware of the the safety
valve had been removed



Around 10:00 pm there was an explosion on the
production deck of the platform which was caused the
ignition of a cloud of gas consendate leaking from the
temporary flange



The fire spread rapidly and was followed by a number
of smaller explosion



At around 10:20 pm a major explosion was followed by
the ruptering of a pipeline carrying gas to the Piper
Alpha platform from the nearby Texaco Tartan platform



The next few hours an intense high-pressure gas fire
raged, punctuated by a series of major explosions that
served to hasten the structural collapse of the platform






Most of the emergency systems on the platform, including the
fire water system, failed to come into operations
Of the 226 persons onboard the installation only 61 survived
The great majority of the of the survivors escaped by jumping
into the sea, some from as 175 feet (approx. 54 m)


Piper Alpha in flames


Crisis Management at Piper
Alpha


The explosion on the Piper Alpha that led to
the disaster was not devasting. We shall
never know, but it probably would have killed
only a small number of men



There was a number of critisim related to the
performance of the OIM on both Piper Alpha,
Claymore and Tartan platforms



These platforms were linked together by
pipelines and if the hydrocarbons from these
platforms had been stopped earlier, the
situation on Piper might have deterioated less
rapidly



On the evening of the crisis the platforms OIM was at
his cabin



In the control room at 9:55 pm a series of low gas
alarms was registered followed by a single high gas
alarm and a suddenly explosion



The stand by boat sent out a mayday call



By 10:05 several minutes after the explosion the OIM
arrived in the radio room wearing a survival suit and
instructed the radio operator to send out a mayday



The OIM left without giving further instructions or stating
his intentions



A few seconds later he ran into the radio room and told the
operator that area outside was on fire and that it should be
broadcasted that the platform was being abandoned



By this time people had started to muster in the
accomodation area an were waiting further instructions



Some of the emergency response teams made attempts to
tackle the fires or to effect rescues, but these were
uncoordinated and ineffective efforts in a desperate situation



By 10:20 pm 22 surviors had abandoned the platform – many
who had been working outside such as divers



Where people had mustered no one was in charge or giving
instructions and there was confusion



A second major explosion because of gas coming into the the
Piper from Tartan caused a massive high-pressure gas fire on
the platform



By 10:50 pm the structure of the platform was beginning to
collapse and gas fires were raging



The OIM and the majority of his crew died onboard as a result
of smoke inhalation



The report afterwards showed that the OIM took no initiative
in an attempt to save life but in his defense several
psychological factors could explain the OIM`s inadequate
leadership and poor decision making



He was under considerable stress and had not been properly
trained and smoke inhalation can effect cognitive functioning

The Claymore Platform


Crisis Management at
Claymore


However what was more suprising revealing serious
weaknesses in the oil industry`s provision for offshore
crisis management, was that the two other OIM`s on
duty from the linked platforms also failed to take
appropriate decisions



The Claymore platform situated 22 miles from Piper
needed to shut down the oil production to prevent it
from flowing towards the Piper platform



At 10:05 pm the Claymore OIM was told that there had
been a mayday on Piper due to fire and explosion



An attempt to contact Piper was unsuccessful and on
the secong mayday from Piper he sent a standy vessel
without shutting down the oil production



The operating superintendent at Claymore asked
the OIM if he could shut down the oil production.
The OIM refused this



The OIM at Claymore then called his manager in
Aberdeen. They knew that Pipers oil had been
shutdown. But as the pipeline pressure was
stable the OIM decided to continue the
production



10:30 they have heard that the fire on Piper was
spreading, and the operating superintendent
again asked the OIM to shut down oil production.
This was refused because he wanted to maintain
the production



During a later phonecall the OIM made
to the Production Manager the operating
superintendent shouted that there had
been an explosion on the Piper. The
Production Manager in Aberdeen asked
them to shut down immediately when he
found out that they were still operating



The Production Manager was suprised
that they were still operating and
instructed both Claymore and Tartan to
shut down production

Illustration of the Oil field

Piper Alpha
Claymore

Tartan

The Tartan Platform


Crisis Management on Tartan


Texaco`s Tartan was located 12 miles southwest of Piper and
also needed to shut down gas and oil production in the event
of an serious emergency on Piper



10:05 pm the OIM at Tartan heard mayday from Piper Alpha



The OIM could not see any flames so he did not shut down
the production but instructed his production supervisor to
monitor the gas pressure on the pipeline to Piper



Production was maintained on Tartan in the belief that Piper
was still producing (no telephone contact was possible)



10:25 the production supervisor was informed of a large
explosion on Piper. This explosion was in fact caused by the
hydrocarbons from Tartan



The emergency control was finally shut down and it took 5-10
minutes before the Tartan OIM asked for their gas line to be
depressurized and for the oil production to be shut down


Conclusion


The Piper Alpha disaster demonstrated the need for proper
training for the responsibility in this kind of position



This is just one of many crisis that have highlighted the need
for organizations to competent to deal with major crisis



Crisis Management is primarily dependent on the decisionmaking of those in key command positions, at strategic,
tactical and operational levels



The immediate cause of the accident was due to
communication problems relating to shift handover and
Permit to Work procedures



This crisis also shows the importancy of good organizational
communication and information routines

What if...
There had been a proper shifthandover, proper marking of the safety
valve that wasn`t functioning, or
proper Permit to Work for this shift at
the Piper Alpha?

Sigve Hamilton Aspelund: Coiled tubing underbalanced drilling

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