2. * 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 Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
3. 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 systemsSeparation systems for
drilling fluids * * * * *centrifuges hydrocyclones shakers pumps
management and control Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
4. 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.
Multilateral wells. Coiled tubing nonproducing beds. underbalanced
drilling.
5. Types of Logs a) Gamma Ray b) SP (spontaneous potential) c)
Resistivity (Induction) d) Sonic e) Density/Neutron f)
CaliperManaged pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
6. 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 Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
7. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
8. 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. Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
9. 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). underbalanced
drilling.
10. 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. Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
11. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
12. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
13. 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
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
14. 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 Managed pressure drilling systems. pore
spaces that could produce water. Multilateral wells. Coiled tubing
underbalanced drilling.
15. 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 limestones).
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 Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
16. 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 Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
17. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
18. 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.
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
20. 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. Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
21. 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 Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
22. 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 underbalanced drilling. Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
23. 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. Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
24. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
25. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
26. 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. Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
27. 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. Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
28. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
30. 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? Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
31. 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 Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
32. 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 Multilateral wells. Coiled tubing formed. underbalanced
drilling.
34. 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 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
35. 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. Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
36. 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.Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
37. 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. Dont hesitate to go beyond requirements. Test to
limits required. Cap and identify as specified. Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
38. 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.
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
39. Isolation of Perforations Cement Plug 100ft (30m) above and
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. Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
40. Isolation of lap joints or liner tops Cement Plug 100ft
(30m) above and 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.Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
41. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
42. 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.Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
43. 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. Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
44. 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.Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
45. 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.Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
46. Risk evaluation Risk & unwanted incidents ranking
Systems in place Report incidents and near miss Analyse material
Look for trendsManaged pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
48. Mapping of HSE & risks Register incidents: Positive and
negativeManaged pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
49. Cause assesment Direct causes vs underlying causes Cause
perspective Human Technical Organisational 5 Whys technique Look
for underlying causes Eliminate root of the problemManaged pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
51. Risk reduction ALARP: As Low As Reasonable Practicable BAT:
Best Available Technology Precation principles Substitution
principles Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
52. Barriers swiss cheese model The Barriere Concept BARRIERS;
Technical, Qualifications, Procedures etc.INITIATING INITIATING
CAUSE CAUSEACCIDENT/ ACCIDENT/ LOSS LOSS Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
53. We are all responsible for managing HSE Barrier 1 HSE
Policy & Leadership Hazard/ RiskBarrier 2 PlanningI was
responsible for planning the operations safelyManaged pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
54. Barrier 1 HSE Policy & LeadershipHazard/ RiskBarrier 2
Planning Barrier 3 SupervisionI turned a blind eye to some of the
crew not following all the procedures as we had limited time to do
the jobI was responsible for supervising the maintenance
workManaged pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
55. Barrier 1 HSE Policy & LeadershipHazard/ RiskBarrier 2
Planning Barrier 3 Supervision Barrier 4 ProceduresI didnt work
safely and took short-cut to get the job doneAccidentI was
responsible completing the work Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
56. We all have a part to play Mngt
TeamFinance/AccountingVisible leadership promotes HSE culture
..Resources allocated for effective implementationResource budgets
effectively tracked and managedMaintenance Maintain equipment and
ensure that operational integrity is maintainedSJA teamLegal Legal
requirements of projects identified and complied withHazards
identified and risk mngt plans implemented DrillingHR Competencies
required for job are clearly identifiedIT/ Data/ GraphicsSystems to
control and securely store HSE critical informationRisk management
integrated to drilling programme HSE deptContractEnsure that
Company are Guidance and given the means to perform advisory
support Managed pressure drilling systems. the job safely and
efficiently Multilateral wells. Coiled tubing provided to
underbalanced drilling. operations
62. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
64. 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.
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
65. 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 Managed pressure drilling
systems. raised into the basket and then towells. Coiled tubing by
the surface Multilateral the boot basket. underbalanced
drilling.
66. 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. Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
67. 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.Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
68. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
69. 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 Kvitebjrn
field. Kvitebjrn 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 Managed pressure drilling
systems. temperature of 160 C (320 F). Coiled tubing Multilateral
wells. underbalanced drilling.
70. 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 5-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.
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
71. 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. Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
72. The Super 13% chrome, 110 Kpsi yield isolation ball valve
was stuck closed at a deviation of 57.8. 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 160 C. The shut-in wellhead pressure was 571 bar (8,282 psi) in
March 2011. The expected downhole temperature at the ball valve was
145 C (293 F). The H2S and CO2 concentrations in the produced gas
were less than 5 ppm and a concentration of 3.477 mol %,
respectively. Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
73. 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
Kvitebjrn license decided not to proceed with the wireline
alternative. New feasibility studies evaluated using CT,
rigassisted snubbing, and the rig for opening or Managed pressure
drilling systems. milling out the isolation ball valve.wells.
Coiled tubing Multilateral underbalanced drilling.
75. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
76. Well control stack as builtManaged pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
77. 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.Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
78. 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. Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
79. 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 Managed pressure drilling systems. Multilateral
wells. Coiled tubing the top of the ball valve. underbalanced
drilling.
80. 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 Kvitebjrn CT
project. The mill was designed and tested to mill through the ball
valve material. The mill size for this Kvitebjrn job was decided to
be 4-in. OD to deploy the milling BHA through the 4116-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. Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
81. 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.Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
83. 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. Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
84. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
85. 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. Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
86. 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.
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
87. 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
145C (293 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/150 C (55 MPa/305 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 146 C (295 F)
before failure. Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
88. 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
7116-in./15K psi gate valve, the safety head handler, the
gas-tested christmas tree crossover, and the 2116-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 Multilateral wells.
Coiled tubing equipment. underbalanced drilling.
89. 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.
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
90. 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. Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
91. 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. Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
92. 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. Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
93. 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. Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
94. 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 Managed pressure drilling systems.
operation should be useful in future similar HP/HT CT applications.
Multilateral wells. Coiled tubing underbalanced drilling.
95. 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 craneManaged pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
100. Hydra Rigs new 55,000 sq. ft. final assembly and CTU
maintenance facilityManaged pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
101. 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.Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
102. Hydra Rig Mini Coil Drop In DrumManaged pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
106. 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.Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
162. 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. Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
163. Events in the disaster The Piper Alpha platform was
operated by Occidental Petroleum (Caledonia) Ltd. and located 110
miles notheast of AberdeenThe platform produced oil and gas and was
linked to the installations Tartan, Claymore and MCP01 by subsea
pipelinesOn 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 flangeSeveral 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 Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
164. 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 flangeThe fire spread
rapidly and was followed by a number of smaller explosionAt 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 platformThe 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 Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
165. 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)Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
167. 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 menThere was a number of critisim related to the performance of
the OIM on both Piper Alpha, Claymore and Tartan platformsThese
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 Managed pressure drilling
systems. Multilateral wells. Coiled tubing underbalanced
drilling.
168. On the evening of the crisis the platforms OIM was at his
cabinIn 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
explosionThe stand by boat sent out a mayday callBy 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 maydayThe OIM left without giving further instructions or
stating his intentions Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
169. 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 abandonedBy this time
people had started to muster in the accomodation area an were
waiting further instructionsSome 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
situationBy 10:20 pm 22 surviors had abandoned the platform many
who had been working outside such as diversWhere people had
mustered no one was in charge or giving instructions and there was
confusion Managed pressure drilling systems. Multilateral wells.
Coiled tubing underbalanced drilling.
170. A second major explosion because of gas coming into the
the Piper from Tartan caused a massive high-pressure gas fire on
the platformBy 10:50 pm the structure of the platform was beginning
to collapse and gas fires were ragingThe OIM and the majority of
his crew died onboard as a result of smoke inhalationThe 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 makingHe
was under considerable stress and had not been properly trained and
smoke inhalation can effect cognitive functioning Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
172. 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 decisionsThe Claymore platform situated 22 miles from
Piper needed to shut down the oil production to prevent it from
flowing towards the Piper platformAt 10:05 pm the Claymore OIM was
told that there had been a mayday on Piper due to fire and
explosionAn attempt to contact Piper was unsuccessful and on the
secong mayday from Piper he sent a standy vessel without shutting
down the oil production Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
173. The operating superintendent at Claymore asked the OIM if
he could shut down the oil production. The OIM refused thisThe 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 production10:30 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
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
174. 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 operatingThe Production Manager was suprised that they were
still operating and instructed both Claymore and Tartan to shut
down production Managed pressure drilling systems. Multilateral
wells. Coiled tubing underbalanced drilling.
175. Illustration of the Oil fieldPiper Alpha ClaymoreTartan
Managed pressure drilling systems. Multilateral wells. Coiled
tubing underbalanced drilling.
177. 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 Piper10:05 pm
the OIM at Tartan heard mayday from Piper AlphaThe 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 PiperProduction 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 Managed pressure drilling systems.
Multilateral wells. Coiled tubing underbalanced drilling.
178. 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 downManaged
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
179. Conclusion The Piper Alpha disaster demonstrated the need
for proper training for the responsibility in this kind of
positionThis is just one of many crisis that have highlighted the
need for organizations to competent to deal with major crisisCrisis
Management is primarily dependent on the decisionmaking of those in
key command positions, at strategic, tactical and operational
levelsThe immediate cause of the accident was due to communication
problems relating to shift handover and Permit to Work
proceduresThis crisis also shows the importancy of good
organizational communication and information routines Managed
pressure drilling systems. Multilateral wells. Coiled tubing
underbalanced drilling.
180. 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? Managed pressure
drilling systems. Multilateral wells. Coiled tubing underbalanced
drilling.
