Drilling and Dynamic Positioning Operations
Co-Ordination – Communication – Co-Operation are three main topics whilst drilling a well
from a Semi Submersible Drilling Rig. They are paramount to ensure that operations are
performed safely and efficiently, when the SSDR is Dynamically Positioned they are
essential.
A basic understanding of how to move the rig onto location and maintain position during
Drilling Operations will be required for the Drill Crew. It will also require the DP
Operator to have an understanding of Drilling Operations and Limitations.
Pre-planning also plays a large part of the rig operations and the more equipment which
can be loaded or built and racked in the derrick before moving onto location the more
efficient the drilling operations can be performed. One of the main limitations for the rig
move can be attributed to deck loading and stability. This is an area which is controlled
by the Marine Department and sometimes called a “black art” by the Drilling Department,
the proposal is for both Marine and Drilling to have a basic understanding of each other
duties and how the three “C”s mentioned above can assist each other during the day to
day operations. The drilling operations will be broken into the following sections;
1. Preparing for rig move; Drilling tubulars, well consumables required, storage area
required, third party personnel. Move the rig onto location. Future weather which may
create limitations, planning operations around weather windows.
2. Bottom Hole Assemblies and what they contain and required to do. Abbreviations used
and what they mean. Safety during “Top Hole” drilling, what is “Shallow Gas” and how
would it effect the rig.
3. Spud In and set conductor. The importance to get the first casing set and cemented
and how it could affect the rest of the well. What could happen when the drill string
is attached to the casing and station / positioning of the rig is compromised by power
failure.
4. 36” & 20” casing sections why are they required. Possible hole problems. The
importance of a good cement operation for both sections. Standing Instructions in
place do we understand them? Rig procedures do we follow them.
5. BOP and its components. Why is it required? How does it work? What do we need to
know about it?
6. The importance of station keeping and the possible effect of being off location
whilst drilling.
7. Drill string components being run down thru the riser / BOP and what does the Driller
mean by “Non - Shearable”.
8. Possible down hole problems; Stuck Pipe – Well Control - Deviation
9. Well Control Procedures
10. Wireline Logging and the equipment used.
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11. Well Testing and what effect it has on the rig.
12. Plug and Abandon Operation
Section 1,
Preparation for Rig move;
The new operator will have provided information for the location.
The main requirements would be; Water depth – Seabed survey for wrecks or other
obstacles – Shipping Lane – surface and sea bed currents – Environmental issues –
predominant weather directions with the reference to rig heading – Location approval
from the regulatory / governmental agencies – third party service companies which
include Helicopter and Shipping arrangements. Last but not least any anomalies from the
seismic survey (shallow gas/gas plumes) and in some cases they may have had sea bed
samples taken to confirm hard or soft conditions. (fairly critical for moored units)
The water depth and well depth information is critical for Drilling Tubular and Riser
Requirements, these issues would then have an impact on the deck loading and space
required. Provisional deck loading and planning would be required to establish what maybe
taken onboard for the rig move.
Building and racking drill string in the derrick will also assist with the spud / drilling
operations, again this is information would be required before load out and rig move and
would affect the deck load - rig move conditions.
Third party contractors and their equipment should be onboard before the rig move
commences. Cementing and Mud Engineering facilities and personnel are required for the
new well.
The Mud Logging and Measurement Whilst Drilling contractors may arrive onboard and
commence setting up their equipment and control cabins. Both will be required for the
spud in.
Communications and rig move personnel will be onboard to give satellite communications
for the client and to give final position when on location.
If we consider a very short rig move and client change, then the three “C’s” are a must.
The mud chemicals and bulk chemicals will include – Baryte a natural product which is
used to increase the mud weight. – Bentonite another natural product which is used to
viscosify the mud. – Cement of which there are several types and grades, this requires
careful management when loading and it is vital that if there are different types that
they are kept in different silos and well documented.
Other chemicals can have safety implications and may require segregation during storage.
There should be MSDS sheets with the load out / manifest paperwork and care taken
when handling or storing these products.
Prior to the rig moving to the new location, one of the priority safety items must be to
secure or sea fasten the deck cargo, weather forecasts should be checked for the
planned sea route and consideration given for moving the rig past or through areas with
fixed installations.
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Section 2;
The oil industry is not a new industry; the Chinese were one of the first to recognise the
importance of hydrocarbons. Oil seepage areas and tar sands were one of the first “oil
wells” Men of Steel and Derricks made of wood were only 100 years ago. We have
improved from the Spindle Top days of drilling down and hitting a “gusher”. Uncontrolled
release of hydrocarbons is dangerous and when the drilling unit floats then you do not
want to have uncontrolled gas being released from the sea bed. Seismic surveys can
indicate anomalies which could be interpretated as “Shallow Gas” these can be low volume
high pressure or low pressure high volume. Generally the well location would be changed
or moved to a safer location, when this is not possible and there is a small chance of
“Shallow Gas” then operations can continue by drilling a pilot hole. A pilot hole is normally
8 ½” diameter or even 12 ¼” diameter and drilled to a depth which is deeper than the
prognosed shallow gas depth. “Kill mud” will have been mixed and be available to assist in
any gas release situations. Kill mud is normally a weighted spud mud with a weight at least
+/- 140kgm3 greater than the spud mud in use. The reason for drilling a smaller diameter
hole allows the “Kill” mud to cover a greater distance or height if required due to the
smaller annulus size.
Should “Shallow Gas” occur then the Driller would continue pumping at a high rate and
change over to “Kill Mud” if there are no changes then he would continue pumping sea
water at a maximum rate whilst picking up off bottom and positioning a tool joint at the
rotary table. In some instances the hole bridges off or collapses and the gas reduces,
should this not occur then the Driller would set the slips whilst continue pumping sea
water, the crew would break out the connection plus half turn. Driller would pick up out of
the slips, stop the pumps and rotate the top drive counter clock wise. The drill string
would release and drop away, if this is not achievable then he would set the slips and the
rig would be driven off location upwind of any surface gas. In water depths greater than
300metres then wind direction and current direction should be monitored at all times.
The ROV acts as the first line defence and would sit on the seabed several metres away
fro m the rotating drill string, any gas release would be seen on the side scan sonar.
For normal drilling operations then the 42” drilling assembly would be made up and run
down to sea bed. This drilling assembly can be described as the BHA and Drill String.
BHA or Bottom Hole Assembly is made up of several different items;
The bit is normally 26” diameter and located/screwed into the bottom of the H/O or
Hole Opener. These can vary from 36” diameter to 42” diameter depending on the casing
or “Conductor Size”. Above the H/O would be a 11 ¼” motor / non magnetic sub / MWD
tools / float sub / 9 ½” non magnetic drill collars / 9 ½” steel drill collars / 8 ¼” steel drill
collars / Jars / Hevi-Wate Drill Pipe / drill pipe back to surface.
11 ¼ mud motor. Inside the motor there is a stator and a rotor, the action of pumping
down the drill string with water or mud causes the rotor to turn, the drill bit / hole
opener is attached to the rotor and the bit is turned. Depending on the type of mud
motor the RPM can vary but can be up as high as 150 rpm.
MWD is a tool which can give the deviation and direction of the drill string. The action of
pumping down through the tool sends signals which the surface equipment changes it into
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information. The “Top Hole” sections have to be drilled vertically and every effort should
be made to ensure the drilling assembly is vertical or maximum of ½ degree deviation. The
Driller may request that the rig is moved to ensure the drill string is vertical. In areas
where there are high currents, consideration would be given to “Spudding” the well at
slack water. Care should be taken with MWD tools if the Knuckle Boom crane has a
magnetic lifting device, they should be stored on a separate deck.
Non-Magnetic tools are required above and below the MWD to reduce the possible
magnetic interference; they are made from stainless steel and should be handled with
care. All tubulars should only be moved or transported with tool joint protectors
installed.
The float sub is a short sub which has been bored out to accept a non-return valve. This
is installed to stop any gas from entering the drill string and venting at surface.
Steel drill collars vary in diameter and weight. They are used to stiffen the assembly or
make it rigid. This coupled with low drilling weights on the bit allow the drilling assembly
to hang vertical.
The make up torque for a car wheel nut can be 50ft/lb or 68Nm the make up torque for a
9 ½” drill collar connection is 78000ft/lb or 105000Nm the make up torque for drill pipe
is 48000ft/lb or 65000Nm, the drill floor is not an area which anyone unfamiliar with
drilling operations should be and care should be taken at all times.
As the drill collars are very stiff then the transition point over to drill pipe would be
vulnerable or a weak point from torque. This can be altered by using HWDP – Hevi-Wate
Drill Pipe (Drilco or manufacturers name). This pipe is similar in outside diameter to drill
pipe but has a wall thickness at least 3 times greater than ordinary drill pipe and can be
distinguished from pipe by the longer tool joints and a centre section. They are
sometimes referred to as flexible drill collars.
Jars – This is a specialised tool which when used correctly can deliver a hydraulic hammer
or force in an upward or downward direction. This would only be used should the drill
string be come “stuck” either through the hole caving in or collapsing or if the drill bit
should be trapped / jammed by a piece of drilled formation.
Section 3;
What do we mean by “Spudding the Well”
The drill crew make up the BHA and run it down to seabed on drill pipe. The ROV will be
used to locate the drill string and when the drill bit tags the sea bed. Marker buoys will
be placed at a set distance away from the bit. These will be used to give hole position /
location later when running the conductor. The rig or SSDR floats which means that it is
susceptible to movement from the action of the sea. The 6 movements of a ship apply to
the rig; the main movement which can halt or stop drilling operations is Heave. If the drill
bit is not kept on bottom and allowed to bounce up and down then it would not take very
long for it to be damaged. Situated at the top of the derrick there are two pieces of
equipment which can be used to overcome the rig vertical movement and allow the drill bit
to stay on bottom with heaves in excess of 4 metres and up to a maximum of 7.3 metres.
The Passive Compensator or Crown Mounted Compensator is rated for 1 million pound or
454 tonne the Active Heave Compensator is used to assist the Passive in rough weather.
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The Passive Compensator uses high pressure air against large pistons; the Driller sets the
pressure to take the weight of the drill string or balances the weight. When the bit is on
bottom he then bleeds off or reduces the air to apply weight to the bit. When the rig
moves up and down the bit stays on bottom.
The Active Heave Compensator is hydraulically actuated. It has a piston the same stroke
length as the Passive but can only apply a maximum of 25 tonne. The force is applied to
the crown block which is part of the passive compensator. The Active takes a signal from
an instrumentation system which measures rig movement, this signal is converted into
hydraulic pressure and force is applied or removed from the crown block. This has the
effect of moving the drill string up or down in relation to rig movement and the drill bit is
held stationary to the seabed.
The ROV will be positioned up current from the drill string and using sonar will be the
first to report any signs of gas. The ROV can also have a transponder installed which can
give indications and location of the drill bit in relation to the rig surface position.
With the ROV positioned up current and everyone happy with the rig position etc. the
Driller would then begin drilling the 26” / 42” section. While sea water is being pumped
through the drill string signals will be sent back to the MWD operators who in turn will
keep the relevant people informed. The Driller will pump a slug of Spud Mud around the
hole, usually every 10 to 15m drilled, to clear it of drilled cuttings. Prior to each
connection a survey will be taken, if everything is okay the Driller will proceed with the
connection and continue drilling. If the well is beginning to deviate the section that has
just been drilled will be reamed in an attempt bring the hole back into line.
Reaming: The drill bit is raised and lowered through the last drilled
section while rotating at an increased rate.
This drilling operation will continue until such time as TD (total depth) is reached. Drilling
the Top Hole section can be problematic for the rig equipment especially the Top Drive,
boulders can cause severe vibration up through the drill string to where dropped objects
can occur. It can be so severe that the boulders create hole conditions / problems to
where a Re-Spud maybe required, the client will advise new location and the move will be
measured exactly so that well co-ordinates previously logged are updated. The depth of
the section to be drilled will depend upon the casing length which is to be run. Casing /
Tubulars to be used in the well have to be measured correctly and a log or “Casing Tally”
or “Drill Pipe Tally” kept. The deck crew are normally involved with the off loading and
racking of the casing. Client representative will also be involved with the measuring of the
casing. It should also be noted that there could be different types and weights of casing
to be used in the casing string and planning how the casing is to be run could involve how
the casing is loaded on the boat. For example-last joint in the hole will be the first joint
to be offloaded from the boat.
The hole or section has been drilled to a depth for the casing length, extra hole could be
drilled to allow for any formation which may fall in, this excess is called the “Rat Hole”
and will depend on how the formation drilled and any problems encountered. At this point
the hole will be displaced to a heavy Spud Mud, which will create hydrostatic pressure
which is greater than formation pressure therefore keeping the hole “open”. A wiper trip
is then performed. This is where the bit and hole opener are pulled back to the top of the
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hole and then ran back to TD to ensure the condition of the hole is okay. The hole would
again be displaced to heavy Spud Mud and this time the bit and hole opener would be
pulled all the way to surface in preparation for running the 36” casing. When the bit is
clear of the sea bed the rig will be moved off location to protect the hole from dropped
objects etc.
Section 4;
Why do we have large casing at the top?
The best way to describe the design of the well is to imagine a telescope, several
sections inside each other which are then extended, the largest is at the seabed and the
smallest at the bottom of the hole. The top casing or “Conductor” has to be capable of
supporting several hundred tonne of casing strings. To achieve this and not buckle then
the pipe can be 2” or 50mm thick, several joints of 2” wall or 1 ½” wall are run. These
strings of casing need to be planned for with respect to arrival on the rig and weights
which could be above the SWL of the whip line. The “Conductor String” length can vary
from 75 to 100 metre long. The hole diameter drilled for 36” casing is 42 inches or
106.7cm. The area between the hole and the outside of the casing is called the “Annulus”
and when the casing is at the correct depth special cement is pumped down through the
drill string / through the casing and out through the shoe. It is very critical that the
annulus is filled all the way back to the seabed. In certain areas the “Formation” or the
soil which has been drilled is very soft or weak and the cement returns can not reach the
seabed. If the casing is not supported fully then there will be a risk of the well head
sinking or falling over to the side. Maximum deviation allowed to continue drilling
operations would be 1 ½ degrees. Serious problems would occur to BOP equipment if
allowed to drill ahead. (Section 5)
For the Imperial Oil well the 36” casing / conductor was jetted into place as the sea bed
structure was soft. The technique used is to run the conductor and land it into a “Mud
Mat” which is located on the flat car in the moonpool. The 26” BHA is then run down
through the conductor and a special tool is engaged into the 36” conductor housing. The
36” conductor plus the BHA is then run down to the sea bed. Special care is required in
measuring the conductor and the BHA to ensure the 26” bit protrudes through special
cut/shoe joint by a maximum of 15cm.
The conductor and drilling assembly is slowly lowered into the seabed and the mud pumps
started which will turn the motor/bit. The Drillers lowers the conductor/BHA assembly
slowly maintaining a constant rate/weight until the “Mud Mat” lands off on the seabed.
The special run/release tool is disengaged and the Driller continues to drill ahead 26”
hole for setting the 20” casing.
“Mud Mat” is a large square plate with a centre boss which locks onto the outside of the
36” conductor housing. It is 3.66 metres / 12 feet square and has to be lowered through
the access hatch on the BOP house roof and landed onto the BOP transporter. Careful
planning will be required with regards to weather and rig motion also FRC cover.
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Drilling Operations Continued;
The 36” casing is then picked up and run. The first joint is the shoe joint; this joint has a
cement base into which a non return valve has been installed. This valve allows fluid to be
pumped through but will not allow fluid to return back. The intermediate joints are then
run. The final joint is the well head housing joint which is sat in the rotary. A cement
stinger is then ran inside the 36” casing. The reason for the cement stinger is to reduce
the volume required to pump out the cement from the casing. The running tool is then
made up to the cement stinger and the well head housing joint. From this point on the
casing is run on drill pipe or a special landing string. Once the well head housing is at the
Moonpool a fill up valve is fitted to the running tool to allow the casing to be filled with
sea water and vent any air, the valve maybe left in the open position and the ROV will
close the valve before the shoe enters the hole. A slope indicator (bullseye) is fitted at
the top of the well head housing joint to allow the ROV to see the angle the casing is
sitting. The Driller will stop when the shoe joint is a couple of meters above the sea bed
and inform the Control Room to reposition the rig over the 42” hole. Co-Ordination
between the ROV and the DPO to place the rig on location is required, Severe weather
can push the rig off location or a strong current can act against the casing making it
difficult to align. When the casing is central above the hole, the Driller lowers and
continues to run the casing on drill pipe taking care that it takes no weight or becomes
stuck.
Once casing is run to the desired depth the ROV will check the slope indicator and when
everyone is satisfied with the deviation and height above the seabed then the cementing
programme will commence with the ROV checking the sea bed around the casing for
cement returns. Coloured dyes and reflective tinsel are used to see the cement returns
at seabed. Once the cement job is complete the Driller will hold the weight until the
cement has cured enough to hold the casing weight this is WOC or “Wait on Cement” and
normally takes 4 to 8 hours. During this time the rig must stay on location and the casing
monitored for movement. Samples of cement are taken during the cement job to allow us
to see what is happening down hole, temperature can effect the time it takes for cement
to set and seabed temperatures can be as low as 1 degree centigrade. A record of the
well location with reference to rig surface location should be logged at this point. Once
the weight has been slacked off and the slope indicator checked the running tool will be
released and pulled back to surface along with the cement stinger. Again, once the
cement stinger is clear the rig will be moved off location.
The Control Room will have now to check stability since the weight of the casing will have
been removed from the deck.
The 26” section is very similar to the 36/42”.
The drill crew would change the BHA and RIH / run in the hole to 5 metres above the 36”
Housing, the rig would be moved back onto location and the 26” Bit Stabbed into the hole.
This is where the CMC and AHC are used effectively and this operation can be viewed via
the ROV camera system. The bit diameter is 26” and the inside diameter of the housing
is 28”, the rig must be position exactly for the Driller to locate and “Stab” into the hole
without damaging the equipment.
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Drilling the “Casing Shoe” can give it’s own problems with high torque / vibration / bit
stuck due to large pieces of the shoe jamming against the inside of the casing. The 26”
section is drilled exactly like the 26/42” with seawater and “Hi-Vis” pills of spud mud,
again the ROV will be positioned on the seabed and monitor for possible shallow gas with
it’s Sonar. Quite often problems occur in this section with gravel beds, this is old river
beds from the ice age and the gravel is unconsolidated and when disturbed it can flow
into the “Well Bore” one of the only ways to control problems of this nature is to pump
more frequent pills or “Spot” an “LCM” pill across the problem formation. LCM stands for
Lost Circulation Material and can be anything from ground up Walnut shells to waste
polythene wrapping and specialised chemical pills.
When the section has been drilled to depth the driller will circulate several pills around
to clean up the hole, the hole would be displaced to a weighted mud and a “Wiper Trip”
performed. This is where the driller pulls the drill string up the hole and once the bit is in
the “Shoe” or inside the previous casing, the hole could be rested or the driller RIH or
Runs In Hole with the BHA. Normally the last stand is lowered carefully and the hole
checked for “Fill” to see if there are any cuttings which may have accumulated and
dropped down to the bottom of the hole. If the fill is a large amount or greater than the
planned Rat Hole then more time will be spent cleaning the hole up before POOH to run
casing. POOH or Pull Out Of Hole.
Running the 20” casing is very similar to the 36” . Again the shoe joint has a non return
valve cemented /bonded, the components of the non-return valve must be non metallic or
a soft alloy which can be drilled. It must also have sufficient strength to accept high
differential pressures. These pressures are experienced from the difference in
Hydrostatic Pressures from the cement on the outside and the seawater or mud on the
inside. The casing is ran as normal and the last joint picked up has the 18 ¾ well head
profile. The well head can have a working pressure of 15000psi/1030bar depending on the
strength of the casing suspended from the inside of it. The outside of the wellhead joint
has a profile machined for the BOP connector to latch onto.
There are several profiles machined into the inside bore and they accept the next casing
strings to be landed or suspended from it. You can have 3 or 4 hanger systems. The well
head system is capable of taking loads or bending stresses of over 3 million pound or
1360tonne. The inside bore is machined exactly to ensure that each casing string
suspended from it can have a high pressure packing element energised to isolate the
weaker previous strings from possible high pressures. These are called Pack Offs and for
pressures over 10000psi/680bar they are metal to metal seals. To protect these areas
from possible damage by rotating pipe or drill bits being tripped through them they use a
bore protector or wear bushing.
Beware it is normally this section where the drill crew try to ballast the rig themselves
by pumping large volumes of mud from the pits, very rarely do they remember to advise
the DPO. Long sections of 26” hole may require as much as 600+ cubic metres of mud
which could be pumped down hole at 7m3/minute.
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Section 5; BOP and its Components.
The BOP or Blow Out Preventer although ran as an assembly is actually made up of two
packages. The Main Package is the lower section and working from the bottom up it has;
Wellhead Connector
Lower Pipe Rams
Middle Pipe Rams
Upper Pipe Rams
Shear Rams,
Lower Annular
Connector Mandrel.
The Upper section or Lower Marine Riser Package - LMRP has;
Connector
Upper Annular
Flex Joint.
To understand the size and the equipment. It is 13.5 metres high and weighs 230 tonne.
The inside bore is 18 ¾” or 476.25mm and the maximum working pressure is
15000psi/1020bar. The pipe rams can be changed for different pipe sizes and they are
capable of supporting upto 600000lb/272 tonne.
There are different pipe ram rubbers also, there are fixed which means they can only
close and seal around a specific pipe size and Variable pipe rams which are capable of
closing around a range of pipe sizes, the most common ones being 3 ½ to 5” and 3 ½ to 7
5/8” the pressure ranges can reduce when the rams are working at the smaller sizes.
The other type of Preventer on the BOP is called the Annular and is capable of closing
around most equipment used to drill a well. It is also capable of closing and sealing open
hole or when there are no tubulars across the BOP, the maximum working pressure for
this type of Preventer is 10000psi/680bar.
The final type of ram is called the Blind/Shear ram and comprises of two cutting blades
and a face seal, the shear ram is capable of cutting the rig drill pipe and certain other
tubulars.
The Pipe Rams are in two pieces and positioned opposite to each other in the Ram
Cavities. Pistons are attached to the back of the rams and hydraulic fluid is forced under
controlled pressure and the rams are closed around the pipe. Seals which are installed to
the top and sides of the rams close off the well to the riser.
The control system for the BOP on the Eirik Raude is a Cameron MultiPlex System the
signals are electrical which are then converted into hydraulic functions. The Electronic
sections have 100% redundancy in each pod and there are two hydraulic pods. Only one
pod is on line at a time. To differentiate they are called Blue & Yellow Pods. Control
panels are located on the Drill floor in the Dog house / the Toolpusher’s office and the
Pilot House. The hydraulic fluid is supplied at 5000psi/345bar down Conduit lines
installed down the outside of the riser. The fluid pressure is regulated down to
3000psi/205bar before entering the control pods. They can then be remotely regulated
to there normal operating pressure of 1500psi/102bar for the functions. There are
several special features and requirements for the BOP, the rig being DP positioned and
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not anchored needs the requirements for the BOP to be programmed to complete certain
functions rapidly. If problems were to occur with the rig power system or thrusters and
the rig could not maintain position then severe damage to the BOP / Riser system could
result. When the DP operators advise of a Yellow caution or straight into a Red alarm the
well must be made safe, the Driller has certain one button functions which when operated
will Close the Pipe Rams / Close the Shear Rams – Shear the pipe / Lock the rams in the
closed position / Unlatch the LMRP connector which will then lift off and away from the
BOP main package. This operation or EDS1 will be completed in 37 seconds. EDS 2 is
where the Driller has time to space out and land the drill pipe and shear the pipe.
Information between the Driller and the DP Operator must be direct and not via other
personnel and the reason why we have a direct communication Squawk Box.
The BOP is connected to the rig via the Marine Riser, this can be described as a pipe with
a pin & box connector and several service lines attached to the outside. The riser joint
has been engineered to be capable of taking 3 million pound tension. The risers are
connected together by 6 locking dogs which are engaged from the outside.
The Riser may have buoyancy modules attached or be SLICK which means that there are
no buoyancy modules installed. There are several different types of buoyancy available
giving various buoyancy factors from 64% to 102% buoyancy, the riser joints are
75/22.86ft/metres long and vary in weight from 16 Tonne for a SLICK joint to 25 Tonne
for a buoyed joint. A selection of PUP Joints allow the riser to be spaced out to place the
Slip Joint in the mid-position.
The Slip Joint is run at the top of the riser and comprises of two tubes one inside of the
other. The bottom of the Outer Barrel section attaches to the riser and at the top of
the Outer Barrel the Marine Riser Tensioners are attached. The Outer Barrel also has
the SIX service lines with female receptacles for the Gooseneck / Coflexip hose
attachment. The top of the Inner Barrel is attached to the Diverter which is located
beneath the rotary table; the bottom of the Inner Barrel has a stop ring or shoe
installed. Packing elements are used between the Inner and Outer Barrels to retain the
mud. Why do we require a Slip Joint? Due to the rig floating and also being attached to
the wellhead via the BOP/Riser system there must be a method of allowing for vertical
and side movement (the 6 movements of a vessel) we also have to be able to maintain a
fluid circulation system so that the drilling mud can be re-circulated. To allow for Heave
or up and down motion the Slip Joint Inner and Outer barrels compensate, for side
movement Pitch/Roll and the rig surface location to wellhead location on the seabed there
are two Flex Joints installed, one at the top of the BOP and one on the bottom of the
Diverter located below the rotary table.
The Slip Joint has a 65/19.8ft/metre stroke to allow for vertical movement and the Flex
Joints each allow +/- 10 degree movement Pitch-Roll and the rig being off location.
The SIX service lines are;
2 Conduit lines for BOP control fluid with a working pressure of 5000/345 psi/bar
working pressure
1 Glycol line
1 Choke line
1 Kill Line, these three lines have a working pressure of 15000/1020psi/bar
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1 Booster line with a working pressure of 7500/510psi/bar
As mentioned earlier the Conduit lines are used to supply BOP control fluid at
5000/345psi/bar.
The Glycol Line is used to inject chemicals at the bottom of the BOP to reduce the
possibility Hydrates forming if gas were encountered.
Choke and Kill Lines are used during the well kill operations and are used to take the
returning fluids from the well bore back to the rig at pressures far greater than the
riser could take. Also to retain back pressure from the well kill operations.
Booster Line is used to increase the mud flow rate up the riser, this would also assist to
boost the drilled cuttings back to the rig.
The riser can not be free standing or it would buckle, to maintain tension on the Marine
Riser there are 16 Marine Riser Tensioners each rated to pull a maximum of
200000/91lbs/tonne each. They have 2 ½” diameter wires and capable of
50/15.25ft/metre line movement. They are arranged with 8 on the Forward and 8 on the
Aft sides of the rig floor. The piston has a stroke of 12.5/3.82ft/metre and by using
double sheaves at both ends of the tensioner the 50/15.25 line movement can be
achieved. The tensioners are energised with High Pressure Air which can be regulated or
set to give specific tensions. The tensioners are attached to the rig and the end of the
wire is attached to a special ring which in turn is locked onto the Slip Joint Outer Barrel
this is how the riser is kept in tension when the rig is moving.
The BOP / Riser systems have several functions but the two main ones are to provided a
circulation route for drilling fluids and to be able to isolate and control hole problems at
high pressures.
The DIVERTER is installed beneath the rotary table and uses rubber inflatable seals to
finalise the sealed circulating system. It also has a packer which can be closed to seal
around the tubulars through the rotary table and down through the riser, this would be
closed in the event of gas entering the well bore and being allowed to flow up into the
riser. To give an idea of gas entering the well bore at 3000 metres and allowed to expand
then the volume could be upto 300 times the original volume.
To give a general idea of the time involved to running the BOP and to continue to drill
ahead typically 3 days would be required to rig up – run – pressure test – rig down for
1500 metres water depth. It is a very labour intensive operation which requires personnel
for operations on the riser deck / moonpool and drill floor. Failure of this equipment
would also require that it be retrieved / repaired / re-run which could would result in
downtime and lost revenue for both Ocean Rig and the Client.
6. Importance of Station Keeping and Being off Location.
The rig position can be effected by wind and surface currents. The BOP Riser system,
although capable of allowing for large offsets there are several reason why it can not be
allowed. Certain areas in the world have surface currents of up to 5 knots or more and
there could be mid water or sea bed currents going in the opposite direction, drilling in
areas with high currents create severe station keeping and drilling problems.
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With the BOP and Riser in use then special care and precautions are to be taken to
reduce the possibility of “KEY” Seating. This term is used to describe the results of the
rig being off location whilst the Drill String is rotating or Drilling Operations are ongoing.
Although the riser is kept in tension, the effect of a 2 knot current acting against the
riser could actually induce a bend in the riser, the drill string hangs vertically and could
come into contact with the inside of the riser, if allowed to continue then the rotating
drill string would eventually wear a hole in the riser creating major pollution and downtime
problems.
If the rig were allowed to move off location then Key Seating could occur at the top of
the BOP which again would result in major pollution /rig repair time.
Failure of the rig thrusters / power generation systems also create there own problems
even when the BOP is not on the sea bed but the drill string is in the hole. Good
Communication between the DPO and Driller is vital and any shut downs of back up
equipment must be discussed and decisions made to suspend Drilling Operations.
The Driller has very little time to make a decision to suspend operations and pick up of
bottom and be in a safe position to shear the drill string – make the well safe and
disconnect before the rig is outside the limits of the equipment.
Delivery of new riser or BOP equipment is very long and we do not keep equipment of this
type as spare. Were the rig allowed to drift off location and the driller did not activate
the emergency systems then the rig would be out of work for possibly up to 6 month.
Keeping the rig vertical is also required as the rotating drill string will wear the bushings
on surface and could create sparks,
7. Drill String components being Non-Shearable and what does it mean;
As described earlier the Drill String is made up of several different types of tubulars
and not all of them can be sheared or cut by the BOP Shear Rams.
Drill collars could be 9 ½” Outside Diameter with a 3” Inside Diameter, Casing can not be
cut and certain grades and heavier types of Drill Pipe can not be sheared. The Driller will
inform the DPO when Non-Shearable equipment is about to be run / pulled through the
BOP, this is the time when good communications are required. If there were possible
Thruster or Positioning equipment problems then the Driller could stay above the BOP if
he were running in the hole / RIH. If he were pulling out of the hole or POOH then he
could stop below the BOP where the drill string could be sheared until the equipment
problems were corrected.
Depending on where or what drilling operations were ongoing then given time the Drill
Crew could arrange other methods of releasing the drill string or casing. The drill string
could be dropped and allowed to fall down the hole or dropped and the BOP released
without closing the shear rams. The drill crew require time to perform these operations.
If the Yellow Alarm is given in good time and the Driller picks up of bottom and spaces
out for a possible shearing of the drill string then life will be a lot easier after the RED
alert. The pipe tool joint could be supported by the Pipe Rams and when the Shear Rams
operate the drill string will remain in place. After everything is back on line and the
emergency over then the top section or LMRP can be reconnected to the BOP. Special
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tools can then be run in the hole and the stub of drill pipe dressed with a mill and then
using a short catch Overshot the drill string can be Fished out of the hole.
8. Possible Down Hole Problems;
Shallow Gas; With the new Seismic Survey equipment this hole or well control problem
can be detected before the well is drilled. Precautions would include drilling a pilot hole
which has been mentioned previously.
Gumbo; This is clay which swells when drilled with a fluid, the Driller drills through the
clay and when he tries to trip back though it the clay has absorbed fluid from the mud or
sea water and swells around the drill string. Can normally be controlled or dried by
treating the mud with KCL or Potassium Chloride which stops the swelling. The Driller
would have to back ream out of the hole to recover the drill string and quite often the
section may have to be re-drilled. Gumbo is normally found on the top sections of the
hole but can vary in different parts of the world.
Lost Circulation; this is where the formation is not strong enough to support the
hydrostatic pressure created by the column of mud. The mud levels drop rapidly and
depending on the hole geometry then it can be a major problem. The Driller would
normally fill the riser with sea water until returns are seen then stop and monitor the
fluid level in the riser. The amount of seawater used to fill the hole can then be used to
calculate the maximum mud weight which can be used to continue drilling. There are many
chemical pills which are used to stop the Lost Circulation and also many types of natural
products ranging from wood splinters / Walnut Shells of different size to by products of
the packaging industry where different sized cellophane is used (old sweet paper
wrapping). Having a weak or Thief Zone can also create serious well control problems
where you have a section of hole which has a weak zone at the shoe and a high pressure
zone is drilled into, the mud weight can only be raised so far before losses occur at the
weak zone and possibly not sufficient to control the high pressure zone. This could end up
with an Under Ground Blow Out.
Under Ground Blow Out; Drilled into a high pressure zone with a very weak zone high up
the hole. Mud weight not able to be raised high enough to control the high pressure zone
and formation fluids start to flow from the strong zone to the weak zone. This could then
start to washout behind the previous casings and work it’s way to sea bed. Eventually only
method to stop the problem is to pump cement down the drill string and cement the lower
part of the hole.
Water Flow; just as dangerous as drilling into a formation with hydrocarbons. The
geometry of the different formations could allow formation fluids which are trapped at
higher pressures to transfer through Faults or Fissures into the well bore creating a well
control problem. Quite often a problem when drilling on land and near mountains where
the water table is charged due to communication with rivers / glaciers / on the mountain.
The extra height increases the hydrostatic pressure and when the formation is drilled
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into instead of being a Normal Pressured formation it is
formation. Drilling on templates or from Platforms where there
can create the same problem, water or gas is being injected
formations to maintain reservoir pressure or to extract the
permeable then oil or gas flows easily.
an Abnormal Pressured
are injection wells in use
beneath the oil bearing
oil. If the formation is
Differential sticking; this can be caused by too thick a filter or wall cake created by the
mud in conjunction with the mud weight being higher than required by the formation
pressure. The Drill collars make contact with the side of the hole and are sucked into the
filter or wall cake, the area of contact is quite large and generally you are not capable of
pulling the string free. You can normally continue to circulate but not able to move or
rotate the pipe. The most common way to release the string is to spot a chemical pill
around BHA and allow it to dissolve the filter cake. Occasionally you can reduce the mud
weight to achieve the same results but this is not normally practiced due to well control
restrictions.
Sand; Very abrasive and can give differential sticking problems as well as some fluid loss.
Can be very permeable where the sand is loose or well cemented where the permeability
is low. Drill string components such as rock bits / stabilisers / drill collars can be worn
down rapidly by abrasive sand formations. It is not uncommon for the drill bit to become
3 – 8mm under gauge is a very short period or length of hole drilled.
Salt Formations; real problems if the mud is not salt saturated, instant high mud losses
and salt formations normally go hand in hand with gas bearing formations, pre-planning is
a must to drill this type of formation, they are impermeable and trap or contain
pressures.
Drilling Break; These can be positive and negative, Positive is where the Rate of
Penetration or ROP increases noticeably, the Driller has to take great care that he does
not drill to far. Normally 1.5 to 3.0 metres maximum is drilled and the Driller would pick
up of bottom and flow check. Positive drilling breaks can occur when the bit enters a
charged formation and the differential between the mud hydrostatic and the formation
pressure equalises, the formation is easier to drill as the overbalance has gone. Negative
drilling breaks are where the ROP decreases and could indicate drilling into a Cap Rock
which could be holding back gas or charged hydrocarbons.
Stuck Pipe; already mentioned Differential Sticking but there are other types of stuck
pipe. Pulling an Under Gauge bit and running in with a new of Full Gauge Bit can be
common. The new bit becomes wedged and stuck.
A different type of Key Seating can occur especially in deviated wells or where the angle
is over 45 degrees, slow drilling allows a groove to be cut on the high side of the hole by
the drill pipe and when the Driller pick up of bottom and attempts to move the drill string
up the Tool Joints jam causing overpull and possible stuck pipe.
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Cuttings Beds; this again is normally associated with deviated holes and common when the
hole angle is 60 degree or more. Low flow rates and string rotation speeds allow the
drilled cuttings to gather and create cutting beds, when the driller attempts to pull the
BHA up past them he can get stuck. On horizontal wells where the section lengths can be
1000 metres or more it is fairly common for the Driller to pump out of the hole. This is
where they reverse the drilling operation and pump /rotate the drill string slowly up and
back into the shoe.
Drilling Deviated Wells; as most of the large oil fields have been discovered and are being
depleted by production, then the Marginal fields become more attractive to Operators.
Fields discovered 20 years or more ago are now being seen as commercially viable. The
pay zone might only be 20 metres (or in some cases less) thick and a 20 metre thick pay
zone would not be very productive when drilled through vertically or at a slight angle. But
if that pay zone were 3000 metre long then drilling along the length of the productive
zone becomes very commercially viable. The new MWD tools combined with new computer
technology have made this possible. Baker Hughes Intec and Anadrill have designed tools
which can be altered from the surface to where they can be steered along a formation
sometimes only 6 metre thick. 3D seismic can plot these formations and combined with
computer programming the drill string can be steered not only from side to side but up
and down to follow the hydrocarbon formations. BP plot all new wells for their
Scheihallion field West of Shetland, they have a project called HIVES which takes all
the information and generates a 3D picture of the area. They have built a special room
with a large screen and you can input a new well and see the route it will take and what
problems may be encountered from different angles. This type of new generation drilling
tools are not cheap to make and average $1 to 2 million each and when run through the
rotary table start to cost the operator $2 to 3 thousand per hour so they have to be
robust and reliable.
Down hole motors may also be used, as described in the Spud Section, they are also made
in several sizes and types. They have a section at the bottom of the motor which can be
adjusted to give various angles from 0.5 to 1.5 degrees. The MWD package installed
above the motor can be aligned with the bit face and the well can be kicked off by lining
up the tool face or bit in the correct direction and then slowly drilling ahead (4m/hr)
allowing the angle to build. Once established then by increasing the weight on bit and
rotating the assembly the hole deviation can be built fairly quickly, 4 degree deviation
over 30 metres is normal (Dog Leg Severity). The Dog Leg Severity has to be controlled
so that the drill string can be tripped in and out and the torque required to rotate the
drill string will not be higher than the drill pipe connection make up torque.
Drilling deviated holes have there own problems from high torque to hole cleaning and
well control.
Well Control Problems;
If we start from spud then the first well control problem encountered would be Shallow
Gas which was mentioned in Section 2. About 20 years ago we used to drill and set the
30” casing and then run a Pin Connector, this was a hydraulic latch and flex joint assembly
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which you ran on the bottom of Riser. The idea behind it was that you could use mud to
give you a hydrostatic column or hydrostatic pressure and control the shallow gas. In
reality if Shallow Gas was encountered the riser became a funnel or channel for the gas
to the rig and over the years after several incidents it was decided not to use a Pin
Connector. If you drill into a Shallow Gas zone and the kill mud has been pumped then the
rig can be moved off location by either lowering the drill pipe stand as the rig is moved or
dropping the drill string and moving the rig up wind or current. The stability of the rig is
greatly reduced due to the sea being aerated by the gas, further problems with fire or
explosions compound the incident.
If an over pressured zone is drilled into and the casing is set and cemented correctly
then 99% of well control problems can be controlled and corrected.
Section 9 – Well Control Procedures;
The most common causes of kicks are;
1. Improper hole fill whilst tripping.
2. Swabbing whilst POOH.
3. Shallow flows.
4. Insufficient mud weight.
5. Drill into abnormal formation pressure.
6. Lost circulation.
7. Incorrect well planning.
The most common is human error or not filling the hole with the correct volume of mud
for the steel displacement. Basically every tubular has an equivalent volume of mud to
either replace it when pulled out of the hole or when the drill string is run in the hole. If
it is not monitored or measured correctly then the height of the mud will reduce and the
hydrostatic pressure from the column of mud will reduce when the drilling string is pulled
out of the hole. The Driller will use the Trip Tank to monitor the well whilst tripping or
flow checking. On the Eirik Raude it is located in the deep well next to the ROV umbilical
winch. Maximum volume for the trip tank is 14m3. When the Driller lines up to trip out of
the hole, he will close off the Flowline to the mud pits and open the trip tank line, the
Trip Tank has it’s own dedicated centrifugal pump which circulates mud from the trip
tank into the Diverter Housing, when the hole / riser is full it flows back down the
dedicated return line back to the Trip Tank. The volume is calibrated /monitored
carefully to the nearest 10 Litre of volume change.
Swabbing is caused by pulling the drill string to fast, possible small clearance between
the drill string and the hole, balled up bit or BHA, mud properties wrong. The most
critical part when POOH is the first 5 or 10 stands out of the hole, if a slug has been
pumped then it has to be allowed to equalise before tripping commences. The volume of
mud required to fill the hole is measured every 5 stands and must be accurately
measured and logged. The Driller will maintain a log of displacement for the whole trip
out.
Shallow flows has been mentioned previously.
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Insufficient mud weight is where the hydrostatic of the mud column is less than the
formation pressure. This could be human error where lighter mud has been pumped down
hole or a higher pressured zone drilled into.
Over pressured zone is where the overburden or the weight of the formations above are
pressing down on a plastic / pliable formation or where there is communication due to a
fault or from volcanic movement of the earth.
Lost circulation is where the mud weight is to high for the formation pressure and the
weak formation breaks down.
Incorrect well planning could be used for wrong casing depths / wrong mud weights /
wrong well geometry with regards to BHA design with soft-clay type formations.
Warning signs of Kicks;
1. Increase in pit volume.
2. Increase in flow returns.
3. Well flows when pumps shut down.
4. Connection gas.
5. Drilling Break.
6. Change in mud properties or temperature of the mud.
7. Change in cuttings size and shape.
8. Decrease in circulating pressure or increase in mud pump speed.
9. Increase in torque and drag.
10. Chlorides change in the mud.
1. The increase in pit volume or trip tank volume is easy to understand but what if the rig
were pitching / rolling and heaving then it is not so easy to see. Ballasting the rig without
informing the Driller can create problems. One of the most important pieces of
equipment for the driller is his Pit Volume Totaliser or PVT.
2. Increase in flow rate or returns is another indication which can be picked up by his
flow line flow sensor, changes in trends would be noticeable on his monitoring system. The
rig heaving could give strange readings and the Driller should be able to detect small
changes.
3. When the stand of drill pipe has been drilled down and the crew have to make a
connection, the mud pumps would be stopped. Due to the high flow rates used whilst
drilling and the different equipment and length of flow line on the rig the mud will
continue to flow for upto 4 minutes after the pumps have been stopped. The Driller must
be aware of the drain back volume whilst making the connection and the pit volume
increase monitored so that when the pumps are started and back to full speed the pit
volume returns to the level before making the connection. Any differences could be an
INFLUX from the formation.
4. Connection gas is where the mud column is static when making a connection and the
hydrostatic pressure of the mud is nearly the same as the formation pressure, gas seeps
into the bottom of the well and when the pumps are started for drilling again the gas is
circulated out of the hole. The gas sensor located in the Shale Shaker header box
detects the increase in gas levels in the mud. By setting the stroke counter to zero
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before starting the pumps the Driller can calculate where the gas came from i.e “Bottoms
Up” The pressure displayed on the Mud Standpipe is made up of several pressure /
frictional losses but only one part of the Stand Pipe pressure is actually applied against
the formation and that is the Annular Pressure Loss. This is the back pressure created
by the flow of mud past the BHA and it may only be 5% of the pressure seen on the
standpipe pressure gauge. This pressure is added to the mud hydrostatic and the
Equivalent Mud Weight is calculated from that pressure. This is the dynamic mud weight
which is exerted on the formation and when the pumps are running. When the pumps are
stopped then the mud hydrostatic pressure reduces to that created by the original mud
weight and the reason why the gas can seep into the hole.
5. Drilling Break, the Rate of Penetration increases due to one of many things; loose sand
formation and mud weight being equal to formation pressure being two of them.
6. Drilling into a zone which could contain hydrocarbons or gas could affect the mud
properties, the mud engineer will check the mud regularly for changes in properties. The
Lead Roughneck will check the mud weight at least twice per hour or as required. There
are two types of Mud Balances used to weigh the mud, both require to checked and
calibrated regularly by the mud engineer. The basic one can be difficult to use if the mud
is aerated and personnel do not take the time to ensure it is full, the other one is a
pressure balanced unit which means that the container is filled with mud and the lid is
installed then mud is pumped into it to ensure it is full. Both mud balances use a pivot and
bubble glass with counterweight, when balanced the weight read from a scale machined on
the balance arm. The balances are checked using potable water and adjusted by adding or
removing grains of Lead Shot from the end of the balance arm.
7. The Lead Roughneck who is in charge of the Shale Shaker Area can play an important
part with well control. He is aware of when the pumps are stopped and there should be no
flow, the change in cutting size and shape can be another indication that we are about to
drill into an Over Pressured Zone, the mud weight is equal or even less than the formation
pressure and the formation instead of being drilled is pushed by the formation pressure
into splinters which can be recognised. Insufficient mud weight can also allow cavings to
occur, this is where the mud weight is insufficient to hold the formation and the sides of
the hole collapse, these are different in shape to bore hole splinters but can be seen as
another indication to hole problems.
8. Decrease in pump pressure and slight increase in mud pump rate occurs when the mud
weight is about the same or less than the formation pressure. The mud pump has less
work to do so the Strokes per Minute increase slightly and possible flow from the
formation reduce the Annular Pressure Loss so the pump pressure decreases. 5-7- & 8
work together and normally the Drilling Break is recognised first.
9. The formation is not being held back by the mud column, the cuttings are being
generated by the formation and the hole is not concentric. The bit instead of drilling the
hole is trying to drill and clean the hole which creates the extra torque and drag.
10. Chloride changes to the mud properties could be introduced by water hose left
running which should be detected by volume increase or it could come from the
formation. The mud engineer would detect this during the mud properties check.
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If the well kicked and an influx were observed by a pit or volume increase or flow
increase then the Driller would close in the well initially with the Annular and line up the
Choke Line / Choke manifold to be able to observe any pressure increases. He would then
inform the Toolpusher and Clients Representative and the DPO. The formation pressure
can be calculated from the pressure being registered on the Mud Standpipe, this is called
the Shut In Drill Pipe Pressure or SIDPP, this pressure added to the hydrostatic
pressure of the mud column would equal the formation pressure. The mud weight required
to equal the formation pressure can then be calculated and this would be called the Kill
Mud Weight.
The other pressure which would be monitored is the pressure on the annulus which is
read from gauges located on the Choke Manifold, this is called the Shut In Casing
Pressure. This pressure if different to the SIDPP may be used as part of the calculation
to establish the influx type. This is required to be able to make forward plans for when
the influx is circulated out of the hole.
As an example. 1m3 of gas at a depth of 1000m with fresh water as the fluid column
would be 98.1m3 in volume size when it reached the surface. Obviously the gas is vented
or disposed of so we have to replace that volume with mud.
The most important part about well control is to maintain bottom hole pressure either
the same / equal as the formation pressure or slightly above. If the pressure were to
drop below the formation pressure then another or secondary influx could enter the well
bore.
The Drill Crew train as a team for different scenarios from recognising well control
problems to closing in the well whilst Tripping / Drilling / Running Casing etc.
Working in deep water also brings extra problems due to the riser length and gas. The
Eirik Raude is capable of containing the gas in the riser with the Diverter System and can
then circulate the gas up the riser using the Mud Pump through the Booster Line and
directing the returns from the diverter system through a 10” line to the Poor Boy
Degasser.
Drilling High Pressure – High Temperature wells have there own problems, normally they
are deep and several casings are required to isolate different formations. The movement
of the rig can be very critical with respect to monitoring mud pit volumes. Communication
between the Driller the DPO and the Crane Operator are critical, ballasting the rig will
cause a change in the pit level, moving a 5 tonne piece of equipment around the rig will
cause a change in the pit level. If the Driller is not aware of such operations then he will
pick up off bottom and either flow check the well or Close In the well for safety. If it
were to happen to often then we could have the little boy shouting Wolfe syndrome and
the Driller allows a real influx to continue thinking it is something else. Ballasting the rig
so that the deck can be hosed down could end up with personnel at the Life Boat Stations
not a very good situation.
Sour Gas or Stink Gas or H2S what ever you wish to call it, kills people. Drilling in known
Sour Gas areas can be planned for and with extra training can be controlled. The thresh
hold for working with H2S is 15 to 20ppm. One instructor at the Halifax Training School
gave a good description of 10ppm, if you were to stand on edge ordinary sheets of paper
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normally the thickness used in a photo copier the paper would be more than the length of
a football pitch. PPM means Parts per Million. The reason it is called Sour Gas is it smells
like rotten eggs, unfortunately you can not rely on your nose to check if it has dissipated,
over 10ppm it will kill your sense of smell. H2S is heavier than air and tends to gather at
deck level or low areas of the rig. The Shale Shaker area is about mid level and there are
several work areas which are lower than this. There are several sensors around the rig
for H2S, know where they are located and be aware of instructions which you may tannoy
during an emergency, are you familiar with the Drilling Work Areas and escape routes.
Leaving the mud pump room due to a gas alarm and into the deep well next to the Cutting
Dryer System would be a wrong instruction. Leaving the Mud Pump Room and entering the
accommodation direct would be a safe move as the area is pressurised.
Section 10 – Wireline Logging;
The location of the well is chosen from information taken from Seismic Logging. There is
a lot of valuable information which can be gained by running Electric Logging Tools in the
open hole section before casing is ran.
Size of hole from the calliper log for cementing volumes.
Different type of Nuclear Sources to give type of formation and permeability. The
nuclear sources used are very strong and strict handling procedures are used, along with
the requirement of a work permit. Only personnel trained in the safe handling can work in
the area when the sources are being loaded / unloaded from the tools.
Velocity Survey Log is where the logging tool is in the hole and the sound source is
generated from the rig. The time taken for the signal to reach the tools can then be
interpretated into geological estimates. A seismic survey vessel tows an array of tools
possibly 5 kilometres behind the vessel, using a high pressure gas gun to generate sound
the sensors measure the time for the sound waves to reach the tools.
Repeat formation tester extends a probe into the formation and reads actual formation
pressures. It can also take samples of formation fluids at formation pressures.
Side wall cores, or CST there are two types of tools. One is where the cup is fired into
the side of the hole and the cup is attached to the tool by a wire. The core or sample is
recovered with the tool. Another type is where the tool drills into the side of the hole
and takes a sample. The sample is then dropped into a collection chamber.
Casing Collar Locator is ran on all the tool runs and used to correlate the depth by logging
where the previous casing collars are located. The depth is then logged and overlaid over
the information from the other tools. Markers built into the wireline cable every 100m
are also used to correlate the depth and for stretch in the cable.
Explosives can also be ran with the Wire Line Unit, they are used to perforate casing to
allow the formation fluids / hydrocarbons through the casing, if the drill string were to
become stuck then an explosive charge could be run to assist with the Fishing Operations.
Different types of explosives are used, low yield types which create more of a gas which
expands to set packers to high explosives shaped charges which can cut well heads with
wall thicknesses upto 35mm thick.
Use of Explosives will be controlled with a work permit; also some of the older firing
systems used required Radio Silence before the tools could be armed. Several incidents
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have been recorded where the explosive charges when armed fired due to Radio
Interference.
The Wireline Logging Unit is located at the Aft of the rig and has its own diesel
generator to provide a “clean electric supply” for the delicate computers. Spikes from
other electric equipment can cause interference to the information being gathered.
Section 11 Well Testing; Drill Stem Testing Operations or DST,
Although hydrocarbons have been found the operator will not commit more money to the
development until they are sure it is commercially viable. Hydrocarbons can not be
produced through the drill string or drilling equipment. Specialised tools and a test string
are required to produce the formation fluids back to the rig. There are several
operations involved with well testing. Information is taken from the MWD Logs and
Wireline Logging runs. Careful planning is then required to ensure that surface equipment
is rated for the prognosed pressures and flow rates.
Normally the oil or gas bearing zones are cased off and the casing cemented in place. The
formations of interest can then be perforated using the wireline unit and explosive
charges or Perforating Guns, the hydrostatic pressure from the mud controls the
formation pressure and stops it from flowing. This type of perforating can give “dirty”
perforations and possibly damage the formation which could affect the flow from the
formation. The other type is to run the “Perforating Guns” with the Well Test String and
when every thing in position the test string contents would be filled with a light fluid
(Diesel) and a bar dropped to fire the guns, as the hydrostatic pressure in the string is
lighter, when the guns fire the formation fluid again takes the easy route and enters the
string which cleans the perforated holes.
The well testing operations can be broke down into three topics;
Surface Hook Up Equipment.
Surface to BOP Equipment.
BOP to Formation Equipment.
Starting from the bottom and that the casing is perforated, the bottom of the string is
open ended, the next few joints of tubing or test string will include tools which have
pressure recorders installed, these record the bottom hole pressures and can only be
read when they are recovered to surface. Above this will be a Packer which isolates the
perforated area of the casing from the BOP. Above the packer will be various other tools
which can be operated by pressuring up the Annulus between the Packer and the BOP.
Annulus controlled Ball Valve would be immediately above the Packer and this would be
used to close off the inside of the test string and isolate the open formation. Another
type of Annulus Controlled Valve can then be used / opened and the area above the
Packer circulated to a lighter fluid or to circulate Hydrocarbons out at the end of the
Well Test. By venting the Annulus Pressure the valve closes and isolates the string to the
annulus. The valve is designed with a “J” slot Ratchet in other words the valve would only
open when the Annulus has been pressured up a certain amount of times (normally 10
times) The ball valve can be opened and closed 9 times but on the 10th the other valve will
operate as well.
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There are also more sensors installed with gauges which record annular pressures and
more test string pressures.
At the well head there is a tool called a Sub Sea Test Tree, this is attached to the test
string and has an adjustable hanger, above that is a hydraulic controlled connector. Built
into the lower section below the connector are hydraulic controlled two ball valves and
chemical injection ports (to reduce possible Hydrates). Above the connector is a slick
joint for the BOP pipe rams to close around and a section which can be sheared in an
emergency. If the rig were to go to Red Alert then the BOP ESD function could be
activated. When the shear rams cut the pipe the two ball valves would failsafe close to
seal off the test string, the pipe rams would isolate the annulus.
The landing string above the SSTT can be larger or the same as the test string
depending on the programme. Approximately 30 metres below the rotary table, another
remote operating ball valve will be installed this will be used to isolate the test string and
vent down a small volume so that wireline tools can be made up and run down the test
string.
At the very top of the test string is the Surface Flowhead, normally a very large block of
metal which has a built in high pressure swivel at the bottom and a Master Isolation
Valve. Above the Master Isolation valve there are two flow routes from the test string.
One outlet for the produced well bore fluids and one inlet for pumping in fluids / killing
the well. At the top of the Flow head is another inlet for attaching well control
equipment for Wireline or Coiled Tubing Operations. All three entry points have their own
isolation valve.
The Flowhead is supported by the Top Drive using long 14 metre bails.
As the Flow head is moving or should we say the rig is moving around the Flowhead, fixed
High Pressure pipe work can not be used to connect it to the rig. Large High Pressure
hoses normally called Coflexip Hoses are used to route the Hydrocarbons to the surface
equipment. The hoses can be pressure rated up to 1034bar / 15000 psi working pressure.
From the Flow head and the Coflexip hose is connected to the rig Well Test Standpipe
which then routes down to the Well Test Area which is situated on the Port Aft Deck
just aft of the welders work shop.
Depending on the expected surface pressure the rig well test line is attached to a Choke
Manifold the pressure is choked back using a manual adjusted Bean Choke or through a
replaceable Orifice Plate Choke. If the Hydrocarbons or Oil is cold or has a high Tar /
Wax content it will be directed through a heat exchanger which is rated for a maximum
working pressure of 200/3000 bar/psi from the heat exchanger it goes into the
Separator where any gas is separated from the oil. Built into the separator are flow
meters which measure the flow of oil / gas from the well. After the Separator the oil and
gas are then routed to the rig Flare Booms and burned or flared off.
When the well is first flowed there is a lot of contamination from the drilling phase and
occasionally the well will slug some drilling mud. Water based mud’s can’t be flared but as
long as there is some oil being produced the flare can be kept alight using propane and
compressed air to try and maintain the burner. This is the phase when pollution is at its
worst and some companies will divert the interface to a large storage tank which can also
be used as a measuring or stock tank.
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As the well is brought on slowly using the adjustable choke to maintain back pressure and
control the flow rate the Hydrocarbons reach surface and the production rate is
increased. Depending on the type of burner in use / flow rate / pressures then the flames
can be approximately 30 metre long and 20 metres wide. The radiated heat could cause
severe damage, the rig has a spray or cooling system installed to deluge the areas closest
to the flare boom in use. Regular checks inside the rig structure and down the columns as
far as sea level must be made for hot spots. Crane sheaves and wires could be damaged
due to the radiated heat and whilst flaring in progress they should be slewed forward.
Check the equipment stored on the Aft Deck / Engine Fan Rooms / Schlumberger Unit
and work shop. Check there are no oil drums or chemical containers in the area. Also
consider the Radioactive and Explosive storage positions. Local weather conditions will
have to be considered before and during flaring operations. Wind speeds less than 10
knots or light to variable may cause problems with the smoke which can be produced
being blown back onto the rig, should there be H2S found whilst drilling the well then
extra safety measures must be taken during DST operations.
By careful monitoring of flow rate / pressures and choke size plus bubble point the well
would be flowed for a clean up period until pressures and surface samples are consistent.
The well would be opened up in stages until a required flow rate against choke size is
reached. The bubble point is where the gas stays in the oil but if the well is flowed to
fast the gas separates from the oils and you get a slugging effect. Once at a required
flow rate then it would be flowed for a set period and then shut in for a pressure build up
period. By monitoring the down hole pressures during the flow period and the flow rate,
any decrease in bottom hole pressure would be the formation pressure reducing, pressure
drop and flow rate are used to calculate the possible field size. The time taken for the
formation pressure to recover when closed in, is also a good indication of the field
capabilities and permeability. If the well were to be produced too quickly and the
formation was very permeable then sand could be produced during the well test, this
would create problems with a long flow period. Wireline tools can be run down the test
string to take oil samples / pressure readings / flow rates whilst producing. This can be
one of the hazardous operations during well testing, normally due to the type of gland
packing or sealing systems around the wire.
On completion of the well test, the tools used to circulate the annulus previously would
now be used to Kill the well. The annulus valve would be cycled to the open position and
mud pumped down the annulus and up the drill string taking the Hydrocarbons back to the
well test equipment. Once the test string is dead or full of mud then the annulus valve is
cycled to the closed position and the ball valve opened, the rest of the hydrocarbons are
then bull headed or pushed back into the formations. Possible lost circulation would be
one of the next problems to sort out before the packer could be unseated and retrieved.
Trapped gas always gives problems especially beneath a packer. The well will be very
unstable at first until the mud creates a wall / filter cake.
Several zones may require testing and the tools may be recovered to change out the down
hole gauges for information gathering.
High gas content and sea bed temperatures could give Hydrate problems; the SSTT has
chemical injection ports for Glycol or Methanol Injection.
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Sub Sea Templates are structures possibly 50m x 100m x 10m high and are constructed
to accommodate several well heads / production manifolds / Flowline sleds / Water
Injection Manifolds. For deep water they are ROV orientated as divers are limited to
operations or water depths upto 200m.
Working over Templates have there own problems and each well will involve heavy lifts
being brought onboard. The rig cranes can be the limiting factor and one of the main
considerations for the rig choice. The more equipment which can be built and tested on
the Xmas Tree ashore the les commissioning will be required onboard the rig and the less
chance of failures which require specialised equipment offshore. XMAS Trees can weigh
upto 50 tonne; they would be transported to the rig on a supply vessel. Lifting heavy loads
onboard the rig which is working over a live template has its own hazards. Lifting tubulars
such as bundles of casing or running the BOP require special procedures and possible
template shut downs. The template could be producing oil to a FPSO and the FPSO would
have control of the producing wells via control Umbilical. Damage to any of the umbilicals
could have a major impact on the rig safety.
Section 12: Suspension or Plug and Abandon;
The well has been drilled and all the information has been gathered, most countries rules
and regulations insist that the well is made safe before the rig can leave location. In
shallow water the seabed plus 3 metres down has to be clear to stop problems with
fishing vessel operations. Deep water the rules can be changed.
If the well is exploratory then the Operator could “Plug and Abandon”. The zones which
were drilled through have to be isolated with either mechanical or wireline set Bridge
Plugs and / or cement plugs.
The most common method is to set 150m long cement plugs across the open hole section
and across the shoe area.
It is possible to cut and retrieve casing strings; it would not be possible should they have
cement around them. The first operation to cut and pull the casing is to remove the Seal
Assembly which isolates the casing from the next casing. Care should be taken due to
possible gas percolation through weak formations or micro-annulus in the cement. The
Seal Assembly is located inside the Well Head on top of the casing hanger, the tools used
to retrieve the seal assembly will most likely be Non-Shearable and with possible
hydrocarbons behind the casings then extreme care and planning required. The seal
assemblies are normally released with Left Hand Rotation and it is possible that a special
Left Hand Drill string could be used or depending on the torque required a tool which can
change right hand rotation to Left Hand Rotation at the tool. Once the seal assy is
released and recovered then special cutting tools are run in the hole to cutting depth. By
rotating the drill string and increasing the rig pumps slowly arms extend and tungsten
chips which are bonded onto the cutting arms cut the casing. As a guide, it may only take
30 minutes to cut through 9 5/8 casing. The same tool can be used for several size
casings, the arms are made to cut a range of casing sizes and once outside that range
then they are changed for larger diameter tools with longer cutting arms.
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When the cutting arms are fully extended then there is a pressure indication and cutting
operations are complete.
The casing cutting tools are recovered and a special Casing Spear is run down and engaged
into the casing just below the hanger. The casing spear can also be used for several sizes
of casings by changing the Grapple. The grapple has been manufactured for a specific
sized casing and when at the depth it can be engaged by rotating the string and picking
up. The running tool mandrel has a left hand helix with tapered shoulders. The inside of
the grapple has tapered shoulders as well, when the tool is picked up the taper force the
grapple to expand and wickers machined on the outside of the grapple engage or bite into
the casing and it can then be retrieved.
Should the casing be stuck then mud can be pumped down through the Fishing Tools and
out through the cut, this should allow mud to flow up behind the casing and clear away
blockages or settled Baryte from the mud used to drill and set the casing. Again care
should be taken especially if the mud has been in place for a long time and H2S could
have formed. The casing can be retrieved back to surface and by rotating to the right
and bumping down on the casing spear the grapple should release. The operation is then
repeated until the BOP can be retrieved and the 18 ¾ & 36” casing well heads are left.
Weatherford have a special tool which can then be used to cut and pull both the 20 & 36
together. The cutters are spaced out to cut approximately 6 metres below the 18 ¾ well
head profile. They have to cut through the 20” casing and through the 36” casing in one
operation. The 36” well head casing or housing can be 2” or 50mm thick. Normally this
operation can be achieved in 6 to 9 hours. When the casings are cut the Driller picks up
on the running string and special dogs locate around the well head profile and the well
head is retrieved to surface.
The ROV then confirms the Sea Bed is clear and the well is complete.
I have tried to explain how we drill the well by breaking it down into 12 stages. I have
also tried to explain in layman’s terms for those that are not familiar with drilling
operations. I hope that you have gained some insight as to how the well is drilled and
some of the Terminology is a bit clearer. When the rig crew talk about the Moonpool /
Mousehole / Monkey Board / Rat Hole / Fishing they are talking about actual areas or
operations and not trying to confuse you. Asking if Martin Decker has the “V” door key is
something which you will learn for your self and never to forget.
DRSU
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