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by
H.A.Williams, K&M Technology Group. G.Rae
Texaco U.K
Copyright 2001, Society of
Petroleum Engineers Inc.
This paper was prepared for
presentation at the SPE Annual Technical Conference
and Exposition held in New Orleans, Louisiana,
26–28 September 2001.
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Abstract
The
paper presents a case study of a well that used advanced
selective-flotation techniques to run 95/8" casing
to overcome drag in a sub-sea, extended reach well
in the North Sea. This is believed to be the first
well to use casing-flotation from a floating drilling
platform
Detailed
drag-modeling analysis had shown that the casing would
not run to bottom, for friction factors that had previously
been observed in this field. With this well in mind,
previous wells had specifically monitored casing-running
friction factors, with different directional drilling
methods, fluid additives, and drag-reduction tools.
Selective flotation was identified as the only method
of ensuring that the casing would run to bottom.
After
resolving the design issues, casing handling equipment
was selected and an exhaustive series of reviews conducted
to identify possible hazards and handling problems
for the operation.
The
technical contribution of this paper is to present
a real example of a floated casing run and show that
mathematical modeling can successfully be used to
predict surface tension. The modeling and running
techniques can be reliably used in both fixed platform
and floating operations. Operational aspects of floating
casing from a semi-submersible rig will also be presented.
Introduction
Texaco North Sea UK operates the
'Captain' oil & gas field in the UK sector of
the North Sea. The field is being simultaneously drilled
and developed from the Captain 'A' wellhead protection
platform (WPP) and the Captain 'B' Subsea manifold.
Production from both installations is routed to the
Captain FPSO. The FPSO, in return, provides treated
water to re-inject for aquifer support.
Running casing is often a significant
problem in extended reach wells such as those on the
Captain field. The Captain sands are thin (typically
70 to 80 feet) and horizontal sections of 4000 to
6000 feet are required for efficient drainage. These
sands are also relatively shallow at approximately
2900 ft TVD sub surface. Consequently, vertical depth
versus displacement ratios of completed wells are
usually greater than 2.5, some greater than 3.5. The
customary definition for an extended reach well is
a TVD versus VD ratio greater than 2.
The production casing shoe
is set in the pay sand at a 90o angle, often at a
displacement greater than 5000 feet. Vertical depth
versus displacement ratios to the casing shoe are
high, frequently 1.5 and greater. Long sections of
production casing at high angles can be difficult
to run to total depth because of open hole friction.
Open hole friction has been successfully
managed by using friction reduction techniques in
production hole sections. Typical measures used have
been:
- Reducing cumulative dogleg severity by use of
rotary drilling systems.
- Selection of a high lubricity polymer/KCL/Glycol
mud system
- Placement of casing centralizers to avoid ‘ploughing’
and minimize friction
- Spotting of friction reducing glass beads in the
hole immediately before running casing.
To date, preliminary planning for
two wells has shown that the normal friction reduction
techniques would not reduce friction sufficiently
to allow casing to be run to the required depth conventionally.
Well LP7 on the WPP had a measured depth to the casing
shoe of 9,721 feet and a Vertical depth versus horizontal
displacement of 2.5. Appendix 1 shows a vertical section
plot of well LP7 and a plot of hookload versus depth
if the casing had been run conventionally. The plot
graphically illustrates that the proposed casing string
would not reach total depth at friction factors greater
than 0.3. The final plot in Appendix 1 shows theoretical
and actual hookloads versus depth when the casing
was 'floated' into the hole with 5000 ft of air. The
final friction factor at total depth was greater than
0.60, but casing was still landed with 20,000 lbs
over block weight.
Well EI1 was drilled through the
Captain 'B' Subsea manifold using the Transocean SedcoForex
Semi-submersible SEDCO 704. Well EI1had a measured
depth to the casing shoe of 7894 feet and a Vertical
depth versus horizontal displacement of 1.9.
Well EI1 is significant because
it is the first ever-asing flotation run from a floating
installation. Appendix 2 shows the well profile and
a depth versus hookload plot for a conventional casing
run. As in well LP7, it is unlikely that the casing
will reach total depth at the expected friction factor
of 0.50.
The final plot shows theoretical
and actual hookloads versus depth when the casing
was 'floated' into the hole with 3900 ft of air. The
final friction factor at total depth was unexpectedly
lower then 0.50, and the casing landed with 80,000
lbs over block weight.
Theory of Floated Casing Design
Floated casing strings use an air
(or lower density fluid) section to reduce the drag
on the wellbore of casing in the high angle section.
Filling the low angle upper portion of the casing
with drilling fluid adds weight to the casing string
and pushes the casing into the hole.
The barrier between air and drilling fluid is a flotation
collar that can be pumped open when it is desired
to replace the air with mud. The internal assemblies
of the flotation collar are designed to be released
by the bottom cementing plug when cementing commences.
K&M Technology Group's
software was used to model the original casing design
and examine the effect of friction reducing enhancements
such as roller centralizers and dogleg reduction.
It was decided that. the best option to ensure landing
casing was flotation. Various lengths of floated section
and internal fluids were modeled and 4000 ft of air
was selected.
Unique Differences in Running
Selectively Floated Casing
A series of meetings reviewed floated
casing running procedures in detail. These meetings
successfully identified every point of difference
between a conventional and floated casing run. These
differences were then examined to identify required
handling equipment and procedures to minimize risk.
Well Control
Casing leaks and leaking flotation
equipment are annoying, perhaps expensive, problems
on conventional casing runs. When using casing flotation
these leaks may cause a rapid drop in annulus fluid
level as the casing fills though the leak. The resultant
loss of hydrostatic pressure may well induce a kick
or result in hole collapse. Careful selection and
pressure rating specification of float shoes and collars
are important for selective flotation. Similarly,
joint make up systems should be specified and policed.
Casing Collapse
At first glance, calculating casing
collapse rating against annulus hydrostatic pressure
appears a trivial problem. However, collapse pressure
calculations need to include the effect of running
the casing into the hole. The casing is moving relative
to the fluid in the hole and inducing a dynamic annulus
pressure. Casing collapse ratings need to consider
the effect of this surge and swab effect.
Air in Casing
The air inside the casing must
not be displaced into the annulus. Doing so may induce
a kick or hole collapse. It is important to allow
plenty time for the fluid in the casing to stabilize
after shifting the flotation collar opening sleeve.
This will allow air bubbles an opportunity to surface.
Casing should be filled slowly to avoid trapping air
bubbles. Specify a low viscosity drilling fluid and
treat the fluid with an anti foam additive.
Static Friction
Selective flotation casing runs
are generally designed to maintain positive hookload
weights at all times. Simply stated, the casing should
slide through the rotary table any time the blocks
are lowered. Reliable software to predict the hookloads
at different friction factors is readily available.
This software calculates the effect
of dynamic friction on hookload. Static friction is
not calculated. Static friction becomes significant
when hookload weight is small. Static friction can
prevent casing sliding into the hole when the blocks
are lowered. Equipment selection and specification
to overcome this problem is important.
Handling Equipment
Static friction causes two effects
when running casing:
- Casing drop. Here the casing remains ‘standing’
through the rotary as the elevators are lowered
then suddenly drops, striking the elevators violently.
- Casing Stick With casing stick, the casing stands
in the rotary and will not drop.
- To deal with casing drop and stick, Bail arms
are selected to be as short as possible
- Side door elevators with safety pins are used
- A push plate is mounted beneath the top drive
system. This plate is used to overcome static friction.
Flotation Sleeve Failing to
Open
The Davis-Lynch? flotation collar
selected for this operation is designed to open an
internal port when a differential pressure of 3000
psi is applied. What if the sleeve controlling the
internal port failed to move?
The planned backup procedure was to temporarily land
the casing on the casing hanger mandrel. A mill would
then be run on drillpipe to shift or drill out the
internal sleeve which incorporates the internal port.
Internal Sleeve Jamming in
Casing
The internal sleeve of the Davis-Lynch?
flotation collar is designed to be released by the
bottom cement plug during casing cementing. The cement
plug should shear the entire sleeve assembly from
inside the flotation sleeve and carry the sleeve to
the cementing collar.
However, the outside diameter of the sleeve is marginally
greater than the A.P.I. drift diameter of the casing.
If the internal sleeve became jammed in the casing,
it is theoretically possible for the bottom cementing
plug to land on the sleeve and shear the diaphragm
of the cementing plug. This would result in the top
cement plug landing on the sleeve and cement being
left in casing.
The team decided to ensure that
all casing below the flotation sleeve would be drifted
to a diameter greater than the diameter of the internal
sleeve. Also, an additional ‘sacrificial’
bottom cementing plug would be pumped before commencing
the cement job. The cement would not be pumped until
transport of the internal sleeve to the cementing
collar was confirmed.
Rig Heave
The combination of rig heave and
static friction has the capability to make casing
running difficult. If static friction is causing casing
stick and a floating rig moves down with rig heave,
the casing string will rise relative to the rotary
table. If positive acting flush mounted slips are
in use, these will appear to rise out of the rotary
table attached to the casing. If the casing tongs
are attached to the string, these will also rise above
the rotary table. This effect is clearly undesirable.
The problem can be solved in two ways.
- Casing string design – the length of air
filled casing and weight of the casing string can
be selected such that the string never becomes light
enough for static friction to prevent casing movement.
- Handling equipment design – If the flush
mounted slips are fixed to the rotary and closed,
the casing string will move down in the hole as
the rig moves down with rig heave. Thus, the flush
mounted slips can be used to counter the effect
of rig heave.
Running the Casing
The floated casing run on the Transocean
Sedco Forex SEDCO 704 commenced with a ‘tool
box talk’. The drill crew, the casing crew and
all supervisors gathered in the dog house to discuss
the forthcoming job. Each step of the casing run was
discussed, handling methods were explained and all
questions answered before moving on to the next step.
The run then began with filling the float joints and
200 ft of pipe with drilling fluid. This provided
weight and avoided the need for a drill collar clamp
as the crew got the ‘rhythm’ of the casing
run. After studying the sea state and the weather,
the team decided to run air filled casing until casing
stick prevented efficient running. The hookload versus
depth plot (Appendix 2) indicated this would occur
at approximately 4000 ft depth.
The run continued with the running
speed becoming slower as more and more air filled
casing entered the hole. Hookloads were noted and
plotted but calculation of friction factors at these
low weights proved to be meaningless. At 3570 ft,
the elevators were lowered and the coupling on the
casing began to ‘lag’ behind the elevators.
Casing was running in the hole at varying speeds,
occasionally catching the elevators but more often
lagging 2 to 3 feet behind the driller’s running
speed. At 3700 feet, a newly made up joint of casing
‘stood up’ when the elevators were lowered.
The push plate was used to push this casing down through
the rotary table for 20 feet. At 3720 feet, 20,000
pounds of weight was being applied but the casing
string would not move. Based on the weight of the
top drive system (50,000 lbs), the team had decided
that the maximum weight to be applied to the push
plate was 20,000 lbs. The drilling supervisor decided
to pick up the casing string and see if it was possible
to ‘work past’ the obstruction that was
stopping casing running. The string was picked up
and re-run, immediately passing the obstruction with
no discernable change in slack off weight. Subsequently,
each joint was pushed into the hole at top drive weights
of 5,000 to 10,000 lbs. The Drilling Supervisor decided
the casing flotation collar would be made up at 4170
feet. The three casing joints prior to this depth
were made up with thread locking compound. The compound
was a precaution if it was necessary to later mill
out the internal sleeve of the flotation collar. After
making up the flotation sleeve, running continued
with casing being filled with drilling fluid. The
push plate was no longer required, but casing continued
to lag behind the elevators down to 4300 feet. The
run continued uneventfully, additional friction causing
some loss of hook load as the casing shoe passed between
6800 and 7200 feet. From 7500 feet, hookload began
decreasing as the effect of the additional friction
as mud filled casing entering the high angle hole
section was seen. Casing was landed with a hookload
of 210,000 lbs – 60,000 lbs over block weight.
Shifting the Flotation Sleeve
As previously mentioned, the internal
ports of the flotation collar were designed to open
with a differential pressure of 3000 psi. The entire
internal workings of the sleeve can then be released
by the sacrificial plug and carried to the cementing
collar. To simplify rigging up, a spare cement head
was made up to the top of the casing hanger landing
joint and lines run from the spare cement head to
the cementing pump and choke manifold. Calculated
surface pressure to open the flotation collar internal
ports was 1400 psi. Pressure was gradually applied
with the cement pumps and the internal ports opened
at the expected pressure. The casing string began
to suck air as the drilling fluid level fell displacing
air in the lower part of the casing. Drilling fluid
level appeared to have stabilized within an hour.
The casing was then topped up with drilling fluid
at 2 barrels per minute. This low rate was selected
to avoid entrapping air in the mud with subsequent
reduction of annular hydrostatic pressure when the
mud was pumped into open hole.
The Sacrificial Plug
The sacrificial plug was now launched
and pumped to the cementing collar. A 300 psi ‘spike’
was seen as the plug picked up the flotation sleeve
and the plug subsequently landed at the cementing
collar. The plug was rated at 1000 psi differential
shear pressure and was seen to shear at the calculated
displacement.
After circulating and adjusting mud properties, conventional
casing cementing commenced.
Conclusion
Typical measures used to reduce
open hole friction in extended reach wells are listed.
Drag risk modeling techniques are used to illustrate
two wells in the ‘Captain’ field where use
of these of these techniques could not reduce friction
sufficiently to permit the casing to run to total
depth. Modeling shows how use of flotation techniques
can allow the string to reach total depth and also
illustrates the accuracy of a modern modeling algorithm.
Differences in design methods, handling tools and
casing string behavior have been explained. Finally,
an account of the operations involved in running the
first ever floated casing string from a floating vessel
has been provided.
Acknowledgements
The authors would like to thank
the Captain Project team of Texaco United Kingdom
–in particular Senior Drilling Engineer Graeme
Rae - for assistance and permission to use Captain
wells in this paper.
Appendices
Appendix 1: Captain ‘A’
LP7 -- True Vertical Depth vs Horizontal Displacement
Appendix 2: Measured Depth vs Hookload – Conventionally
Run Casing String
Appendix 3: Measured Depth vs Hookload – Floated
Casing String
Appendix 1: Captain
‘A’ LP7
True Vertical Depth vs Horizontal Displacement
Appendix 2: Measured Depth
vs Hookload – Conventionally Run Casing String
Appendix 3: Measured Depth
vs Hookload – Floated Casing String
