drilling procedures omc ab.doc[1]

8/2/2019 Drilling Procedures OMC AB.doc[1]

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Drilling and Dynamic Positioning OperationsCo-Ordination Communication Co-Operation are three main topics whilst drilling awell from a Semi Submersible Drilling Rig. They are paramount to ensure that operationsare performed safely and efficiently, when the SSDR is Dynamically Positioned they areessential.A basic understanding of how to move the rig onto location and maintain position duringDrilling Operations will be required for the Drill Crew. It will also require the DPOperator to have an understanding of Drilling Operations and Limitations.

Pre-planning also plays a large part of the rig operations and the more equipment whichcan 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 rigmove can be attributed to deck loading and stability. This is an area which is controlledby 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 otherduties and how the three Cs mentioned above can assist each other during the day today 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 maycreate limitations, planning operations around weather windows.

2. Bottom Hole Assemblies and what they contain and required to do. Abbreviations usedand what they mean. Safety during Top Hole drilling, what is Shallow Gas and howwould it effect the rig.

3. Spud In and set conductor. The importance to get the first casing set and cementedand how it could affect the rest of the well. What could happen when the drill stringis attached to the casing and station / positioning of the rig is compromised by powerfailure.

4. 36 & 20 casing sections why are they required. Possible hole problems. Theimportance of a good cement operation for both sections. Standing Instructions inplace 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 toknow about it?

6. The importance of station keeping and the possible effect of being off locationwhilst drilling.

7. Drill string components being run down thru the riser / BOP and what does the Drillermean by Non - Shearable.

8. Possible down hole problems; Stuck Pipe Well Control - Deviation9. Well Control Procedures10. 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 otherobstacles Shipping Lane surface and sea bed currents Environmental issues predominant weather directions with the reference to rig heading Location approvalfrom the regulatory / governmental agencies third party service companies whichinclude Helicopter and Shipping arrangements. Last but not least any anomalies from theseismic survey (shallow gas/gas plumes) and in some cases they may have had sea bedsamples 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 RiserRequirements, 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 maybetaken onboard for the rig move.Building and racking drill string in the derrick will also assist with the spud / drillingoperations, again this is information would be required before load out and rig move andwould affect the deck load - rig move conditions.Third party contractors and their equipment should be onboard before the rig movecommences. Cementing and Mud Engineering facilities and personnel are required for thenew well.The Mud Logging and Measurement Whilst Drilling contractors may arrive onboard andcommence setting up their equipment and control cabins. Both will be required for thespud in.

Communications and rig move personnel will be onboard to give satellite communicationsfor the client and to give final position when on location.If we consider a very short rig move and client change, then the three Cs are a must.The mud chemicals and bulk chemicals will include Baryte a natural product which isused to increase the mud weight. Bentonite another natural product which is used toviscosify the mud. Cement of which there are several types and grades, this requirescareful management when loading and it is vital that if there are different types thatthey 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 beto secure or sea fasten the deck cargo, weather forecasts should be checked for theplanned sea route and consideration given for moving the rig past or through areas withfixed installations.



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Section 2;The oil industry is not a new industry; the Chinese were one of the first to recognise theimportance of hydrocarbons. Oil seepage areas and tar sands were one of the first oilwells Men of Steel and Derricks made of wood were only 100 years ago. We haveimproved 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 donot want to have uncontrolled gas being released from the sea bed. Seismic surveyscan indicate anomalies which could be interpretated as Shallow Gas these can be lowvolume high pressure or low pressure high volume. Generally the well location wouldbe changed or moved to a safer location, when this is not possible and there is a smallchance of Shallow Gas then operations can continue by drilling a pilot hole. A pilot holeis normally 8 diameter or even 12 diameter and drilled to a depth which is deeperthan the prognosed shallow gas depth. Kill mud will have been mixed and be available toassist in any gas release situations. Kill mud is normally a weighted spud mud with a weightat 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 dueto the smaller annulus size.Should Shallow Gas occur then the Driller would continue pumping at a high rate andchange over to Kill Mud if there are no changes then he would continue pumping seawater at a maximum rate whilst picking up off bottom and positioning a tool joint at therotary 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 seawater, the crew would break out the connection plus half turn. Driller would pick up outof the slips, stop the pumps and rotate the top drive counter clock wise. The drill stringwould release and drop away, if this is not achievable then he would set the slips and therig 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 awayfro 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 rundown 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 orHole Opener. These can vary from 36 diameter to 42 diameter depending on the casingor Conductor Size. Above the H/O would be a 11 motor / non magnetic sub / MWD

tools / float sub / 9 non magnetic drill collars / 9 steel drill collars / 8 steel drillcollars / Jars / Hevi-Wate Drill Pipe / drill pipe back to surface.11 mud motor. Inside the motor there is a stator and a rotor, the action of pumpingdown the drill string with water or mud causes the rotor to turn, the drill bit / holeopener is attached to the rotor and the bit is turned. Depending on the type of mudmotor 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 ofpumping 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 shouldbe made to ensure the drilling assembly is vertical or maximum of degree deviation.The Driller may request that the rig is moved to ensure the drill string is vertical. Inareas where there are high currents, consideration would be given to Spudding the wellat 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 possiblemagnetic interference; they are made from stainless steel and should be handledwith care. All tubulars should only be moved or transported with tool joint protectorsinstalled.The float sub is a short sub which has been bored out to accept a non-return valve. Thisis 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 ormake it rigid. This coupled with low drilling weights on the bit allow the drilling assemblyto hang vertical.

The make up torque for a car wheel nut can be 50ft/lb or 68Nm the make up torque for a9 drill collar connection is 78000ft/lb or 105000Nm the make up torque for drill pipeis 48000ft/lb or 65000Nm, the drill floor is not an area which anyone unfamiliar withdrilling 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 bevulnerable or a weak point from torque. This can be altered by using HWDP Hevi-WateDrill Pipe (Drilco or manufacturers name). This pipe is similar in outside diameter todrill pipe but has a wall thickness at least 3 times greater than ordinary drill pipe andcan be distinguished from pipe by the longer tool joints and a centre section. They aresometimes 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 drillstring be come stuck either through the hole caving in or collapsing or if the drill bitshould be trapped / jammed by a piece of drilled formation.Section 3;What do we mean by Spudding the WellThe drill crew make up the BHA and run it down to seabed on drill pipe. The ROV will beused to locate the drill string and when the drill bit tags the sea bed. Marker buoys willbe 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 tothe rig; the main movement which can halt or stop drilling operations is Heave. If the drillbit is not kept on bottom and allowed to bounce up and down then it would not take verylong for it to be damaged. Situated at the top of the derrick there are two pieces ofequipment which can be used to overcome the rig vertical movement and allow the drill bitto 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 or454 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 thepressure to take the weight of the drill string or balances the weight. When the bit ison bottom he then bleeds off or reduces the air to apply weight to the bit. When the rigmoves 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 tothe crown block which is part of the passive compensator. The Active takes a signal froman instrumentation system which measures rig movement, this signal is converted intohydraulic pressure and force is applied or removed from the crown block. This has theeffect of moving the drill string up or down in relation to rig movement and the drill bit isheld stationary to the seabed.The ROV will be positioned up current from the drill string and using sonar will be thefirst to report any signs of gas. The ROV can also have a transponder installed which cangive 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 pumpedthrough the drill string signals will be sent back to the MWD operators who in turn willkeep the relevant people informed. The Driller will pump a slug of Spud Mud aroundthe hole, usually every 10 to 15m drilled, to clear it of drilled cuttings. Prior to eachconnection a survey will be taken, if everything is okay the Driller will proceed with theconnection and continue drilling. If the well is beginning to deviate the section that hasjust 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. Drillingthe 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 objectscan occur. It can be so severe that the boulders create hole conditions / problems towhere a Re-Spud maybe required, the client will advise new location and the move will bemeasured exactly so that well co-ordinates previously logged are updated. The depth ofthe 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 Tallyor Drill Pipe Tally kept. The deck crew are normally involved with the off loading andracking of the casing. Client representative will also be involved with the measuring of thecasing. It should also be noted that there could be different types and weights of casingto 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 jointto 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 Holeand will depend on how the formation drilled and any problems encountered. At this pointthe hole will be displaced to a heavy Spud Mud, which will create hydrostatic pressurewhich is greater than formation pressure therefore keeping the hole open. A wiper tripis then performed. This is where the bit and hole opener are pulled back to the top of



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the hole and then ran back to TD to ensure the condition of the hole is okay. The holewould again be displaced to heavy Spud Mud and this time the bit and hole opener wouldbe pulled all the way to surface in preparation for running the 36 casing. When the bit isclear of the sea bed the rig will be moved off location to protect the hole from droppedobjects 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, severalsections inside each other which are then extended, the largest is at the seabed and thesmallest at the bottom of the hole. The top casing or Conductor has to be capable ofsupporting several hundred tonne of casing strings. To achieve this and not buckle thenthe pipe can be 2 or 50mm thick, several joints of 2 wall or 1 wall are run. Thesestrings of casing need to be planned for with respect to arrival on the rig and weightswhich 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 or106.7cm. The area between the hole and the outside of the casing is called the Annulusand when the casing is at the correct depth special cement is pumped down through thedrill string / through the casing and out through the shoe. It is very critical that theannulus is filled all the way back to the seabed. In certain areas the Formation or thesoil which has been drilled is very soft or weak and the cement returns can not reachthe seabed. If the casing is not supported fully then there will be a risk of the wellhead sinking or falling over to the side. Maximum deviation allowed to continue drillingoperations would be 1 degrees. Serious problems would occur to BOP equipment ifallowed 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 MudMat which is located on the flat car in the moonpool. The 26 BHA is then run downthrough the conductor and a special tool is engaged into the 36 conductor housing. The36 conductor plus the BHA is then run down to the sea bed. Special care is required inmeasuring the conductor and the BHA to ensure the 26 bit protrudes through specialcut/shoe joint by a maximum of 15cm.The conductor and drilling assembly is slowly lowered into the seabed and the mud pumpsstarted which will turn the motor/bit. The Drillers lowers the conductor/BHA assemblyslowly 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 the36 conductor housing. It is 3.66 metres / 12 feet square and has to be lowered throughthe access hatch on the BOP house roof and landed onto the BOP transporter. Carefulplanning 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 acement base into which a non return valve has been installed. This valve allows fluid to bepumped through but will not allow fluid to return back. The intermediate joints are thenrun. 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 reducethe volume required to pump out the cement from the casing. The running tool is thenmade up to the cement stinger and the well head housing joint. From this point on thecasing is run on drill pipe or a special landing string. Once the well head housing is at theMoonpool a fill up valve is fitted to the running tool to allow the casing to be filled withsea water and vent any air, the valve maybe left in the open position and the ROV willclose the valve before the shoe enters the hole. A slope indicator (bullseye) is fitted atthe top of the well head housing joint to allow the ROV to see the angle the casing issitting.The Driller will stop when the shoe joint is a couple of meters above the sea bedand 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 weathercan push the rig off location or a strong current can act against the casing making itdifficult to align. When the casing is central above the hole, the Driller lowers andcontinues to run the casing on drill pipe taking care that it takes no weight or becomesstuck.Once casing is run to the desired depth the ROV will check the slope indicator and wheneveryone is satisfied with the deviation and height above the seabed then the cementingprogramme will commence with the ROV checking the sea bed around the casing forcement returns. Coloured dyes and reflective tinsel are used to see the cement returnsat seabed. Once the cement job is complete the Driller will hold the weight until thecement 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 thecasing monitored for movement. Samples of cement are taken during the cement job toallow us to see what is happening down hole, temperature can effect the time it takes forcement to set and seabed temperatures can be as low as 1 degree centigrade. A recordof 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 toolwill be released and pulled back to surface along with the cement stinger. Again, once thecement 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 havebeen 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 36Housing, 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 viathe ROV camera system. The bit diameter is 26 and the inside diameter of the housingis 28, the rig must be position exactly for the Driller to locate and Stab into the holewithout damaging the equipment.Drilling the Casing Shoe can give its own problems with high torque / vibration / bit



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stuck due to large pieces of the shoe jamming against the inside of the casing. The 26section 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 withits Sonar. Quite often problems occur in this section with gravel beds, this is old riverbeds 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 pumpmore frequent pills or Spot an LCM pill across the problem formation. LCM standsfor Lost Circulation Material and can be anything from ground up Walnut shells to wastepolythene wrapping and specialised chemical pills.When the section has been drilled to depth the driller will circulate several pills aroundto clean up the hole, the hole would be displaced to a weighted mud and a Wiper Tripperformed. This is where the driller pulls the drill string up the hole and once the bitis in the Shoe or inside the previous casing, the hole could be rested or the drillerRIH or Runs In Hole with the BHA. Normally the last stand is lowered carefully and thehole 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 theplanned Rat Hole then more time will be spent cleaning the hole up before POOH to runcasing. POOH or Pull Out Of Hole.Running the 20 casing is very similar to the 36 . Again the shoe joint has a non returnvalve cemented /bonded, the components of the non-return valve must be non metallicor a soft alloy which can be drilled. It must also have sufficient strength to accepthigh differential pressures. These pressures are experienced from the difference inHydrostatic Pressures from the cement on the outside and the seawater or mud on theinside. The casing is ran as normal and the last joint picked up has the 18 well headprofile. The well head can have a working pressure of 15000psi/1030bar depending on thestrength 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 casingstrings to be landed or suspended from it. You can have 3 or 4 hanger systems. Thewell head system is capable of taking loads or bending stresses of over 3 million poundor 1360tonne. The inside bore is machined exactly to ensure that each casing stringsuspended from it can have a high pressure packing element energised to isolate theweaker previous strings from possible high pressures. These are called Pack Offs and forpressures over 10000psi/680bar they are metal to metal seals. To protect these areasfrom possible damage by rotating pipe or drill bits being tripped through them they use abore protector or wear bushing.

Beware it is normally this section where the drill crew try to ballast the rig themselvesby pumping large volumes of mud from the pits, very rarely do they remember to advisethe DPO. Long sections of 26 hole may require as much as 600+ cubic metres of mudwhich 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 twopackages. The Main Package is the lower section and working from the bottom up it has;Wellhead Connector

Lower Pipe RamsMiddle Pipe RamsUpper Pipe RamsShear Rams,Lower AnnularConnector Mandrel.The Upper section or Lower Marine Riser Package - LMRP has;ConnectorUpper AnnularFlex Joint.To understand the size and the equipment. It is 13.5 metres high and weighs 230 tonne.The inside bore is 18 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 ofsupporting upto 600000lb/272 tonne.There are different pipe ram rubbers also, there are fixed which means they can onlyclose and seal around a specific pipe size and Variable pipe rams which are capable ofclosing around a range of pipe sizes, the most common ones being 3 to 5 and 3 to 75/8 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 closingaround most equipment used to drill a well. It is also capable of closing and sealing openhole 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 bladesand a face seal, the shear ram is capable of cutting the rig drill pipe and certain othertubulars.The Pipe Rams are in two pieces and positioned opposite to each other in the RamCavities. Pistons are attached to the back of the rams and hydraulic fluid is forced undercontrolled pressure and the rams are closed around the pipe. Seals which are installed tothe 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 thesignals 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 onepod is on line at a time. To differentiate they are called Blue & Yellow Pods. Controlpanels are located on the Drill floor in the Dog house / the Toolpushers office andthe Pilot House. The hydraulic fluid is supplied at 5000psi/345bar down Conduit linesinstalled 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 therenormal operating pressure of 1500psi/102bar for the functions. There are several specialfeatures and requirements for the BOP, the rig being DP positioned and not anchored



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needs the requirements for the BOP to be programmed to complete certain functionsrapidly. If problems were to occur with the rig power system or thrusters and the rigcould 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 wellmust 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 theclosed position / Unlatch the LMRP connector which will then lift off and away from theBOP main package. This operation or EDS1 will be completed in 37 seconds. EDS 2 iswhere 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 otherpersonnel 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 pipewith a pin & box connector and several service lines attached to the outside. The riserjoint has been engineered to be capable of taking 3 million pound tension. The risers areconnected 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 areno buoyancy modules installed. There are several different types of buoyancy availablegiving 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 fora buoyed joint. A selection of PUP Joints allow the riser to be spaced out to place theSlip Joint in the mid-position.The Slip Joint is run at the top of the riser and comprises of two tubes one inside ofthe other. The bottom of the Outer Barrel section attaches to the riser and at thetop of the Outer Barrel the Marine Riser Tensioners are attached. The Outer Barrelalso has the SIX service lines with female receptacles for the Gooseneck / Coflexiphose 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 shoeinstalled. Packing elements are used between the Inner and Outer Barrels to retain themud. Why do we require a Slip Joint? Due to the rig floating and also being attached tothe wellhead via the BOP/Riser system there must be a method of allowing for verticaland side movement (the 6 movements of a vessel) we also have to be able to maintain afluid circulation system so that the drilling mud can be re-circulated. To allow for Heaveor up and down motion the Slip Joint Inner and Outer barrels compensate, for sidemovement Pitch/Roll and the rig surface location to wellhead location on the seabed thereare two Flex Joints installed, one at the top of the BOP and one on the bottom of theDiverter located below the rotary table.

The Slip Joint has a 65/19.8ft/metre stroke to allow for vertical movement and the FlexJoints 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/barworking pressure1 Glycol line1 Choke line1 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/barAs 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 thepossibility Hydrates forming if gas were encountered.

Choke and Kill Lines are used during the well kill operations and are used to take thereturning fluids from the well bore back to the rig at pressures far greater than theriser 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 toboost the drilled cuttings back to the rig.The riser can not be free standing or it would buckle, to maintain tension on the MarineRiser there are 16 Marine Riser Tensioners each rated to pull a maximum of 200000/91lbs/tonne each. They have 2 diameter wires and capable of 50/15.25ft/metre linemovement. They are arranged with 8 on the Forward and 8 on the Aft sides of the rigfloor. 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 areenergised 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 specialring which in turn is locked onto the Slip Joint Outer Barrel this is how the riser is keptin tension when the rig is moving.The BOP / Riser systems have several functions but the two main ones are to provided acirculation route for drilling fluids and to be able to isolate and control hole problems athigh pressures.The DIVERTER is installed beneath the rotary table and uses rubber inflatable seals tofinalise the sealed circulating system. It also has a packer which can be closed to sealaround 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 theriser. To give an idea of gas entering the well bore at 3000 metres and allowed to expandthen 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 drillahead typically 3 days would be required to rig up run pressure test rig down for1500 metres water depth. It is a very labour intensive operation which requires personnelfor operations on the riser deck / moonpool and drill floor. Failure of this equipmentwould also require that it be retrieved / repaired / re-run which could would result indowntime 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 beallowed. Certain areas in the world have surface currents of up to 5 knots or more andthere could be mid water or sea bed currents going in the opposite direction, drilling inareas with high currents create severe station keeping and drilling problems.With the BOP and Riser in use then special care and precautions are to be taken toreduce the possibility of KEY Seating. This term is used to describe the results of the



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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 theriser could actually induce a bend in the riser, the drill string hangs vertically and couldcome into contact with the inside of the riser, if allowed to continue then the rotatingdrill 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 ofthe BOP which again would result in major pollution /rig repair time.Failure of the rig thrusters / power generation systems also create there own problemseven when the BOP is not on the sea bed but the drill string is in the hole. GoodCommunication between the DPO and Driller is vital and any shut downs of back upequipment 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 upof bottom and be in a safe position to shear the drill string make the well safe anddisconnect 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 thistype as spare. Were the rig allowed to drift off location and the driller did not activatethe 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 bushingson 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 tubularsand not all of them can be sheared or cut by the BOP Shear Rams.Drill collars could be 9 Outside Diameter with a 3 Inside Diameter, Casing can notbe 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 throughthe BOP, this is the time when good communications are required. If there were possibleThruster or Positioning equipment problems then the Driller could stay above the BOPif he were running in the hole / RIH. If he were pulling out of the hole or POOH thenhe could stop below the BOP where the drill string could be sheared until the equipmentproblems were corrected.Depending on where or what drilling operations were ongoing then given time the DrillCrew could arrange other methods of releasing the drill string or casing. The drill stringcould be dropped and allowed to fall down the hole or dropped and the BOP releasedwithout 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 spacesout for a possible shearing of the drill string then life will be a lot easier after the REDalert. The pipe tool joint could be supported by the Pipe Rams and when the Shear Ramsoperate the drill string will remain in place. After everything is back on line and theemergency over then the top section or LMRP can be reconnected to the BOP. Specialtools can then be run in the hole and the stub of drill pipe dressed with a mill and thenusing a short catch Overshot the drill string can be Fished out of the hole.



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8. Possible Down Hole Problems;Shallow Gas; With the new Seismic Survey equipment this hole or well control problemcan be detected before the well is drilled. Precautions would include drilling a pilot holewhich has been mentioned previously.

Gumbo; This is clay which swells when drilled with a fluid, the Driller drills through theclay and when he tries to trip back though it the clay has absorbed fluid from the mudor sea water and swells around the drill string. Can normally be controlled or dried bytreating the mud with KCL or Potassium Chloride which stops the swelling. The Drillerwould have to back ream out of the hole to recover the drill string and quite often thesection may have to be re-drilled. Gumbo is normally found on the top sections of thehole but can vary in different parts of the world.Lost Circulation; this is where the formation is not strong enough to support thehydrostatic 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 wouldnormally fill the riser with sea water until returns are seen then stop and monitor thefluid level in the riser. The amount of seawater used to fill the hole can then be used tocalculate the maximum mud weight which can be used to continue drilling. There are manychemical pills which are used to stop the Lost Circulation and also many types of naturalproducts ranging from wood splinters / Walnut Shells of different size to by productsof the packaging industry where different sized cellophane is used (old sweet paperwrapping). Having a weak or Thief Zone can also create serious well control problemswhere you have a section of hole which has a weak zone at the shoe and a high pressurezone is drilled into, the mud weight can only be raised so far before losses occur at theweak 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 upthe hole. Mud weight not able to be raised high enough to control the high pressure zoneand formation fluids start to flow from the strong zone to the weak zone. This could thenstart to washout behind the previous casings and work its way to sea bed. Eventually onlymethod to stop the problem is to pump cement down the drill string and cement the lowerpart 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 trappedat higher pressures to transfer through Faults or Fissures into the well bore creatinga well control problem. Quite often a problem when drilling on land and near mountainswhere the water table is charged due to communication with rivers / glaciers / on themountain. The extra height increases the hydrostatic pressure and when the formationis drilled into instead of being a Normal Pressured formation it is an Abnormal Pressuredformation. Drilling on templates or from Platforms where there are injection wells inuse can create the same problem, water or gas is being injected beneath the oil bearing



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formations to maintain reservoir pressure or to extract the oil. If the formation ispermeable then oil or gas flows easily.

Differential sticking; this can be caused by too thick a filter or wall cake created bythe 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 thefilter or wall cake, the area of contact is quite large and generally you are not capableof pulling the string free. You can normally continue to circulate but not able to moveor rotate the pipe. The most common way to release the string is to spot a chemical pillaround BHA and allow it to dissolve the filter cake. Occasionally you can reduce the mudweight to achieve the same results but this is not normally practiced due to well controlrestrictions.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 worndown rapidly by abrasive sand formations. It is not uncommon for the drill bit to become3 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 lossesand salt formations normally go hand in hand with gas bearing formations, pre-planningis a must to drill this type of formation, they are impermeable and trap or containpressures.

Drilling Break; These can be positive and negative, Positive is where the Rate ofPenetration 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 pickup of bottom and flow check. Positive drilling breaks can occur when the bit enters acharged formation and the differential between the mud hydrostatic and the formationpressure equalises, the formation is easier to drill as the overbalance has gone. Negativedrilling breaks are where the ROP decreases and could indicate drilling into a Cap Rockwhich could be holding back gas or charged hydrocarbons.

Stuck Pipe; already mentioned Differential Sticking but there are other types ofstuck pipe. Pulling an Under Gauge bit and running in with a new of Full Gauge Bit can becommon. The new bit becomes wedged and stuck.

A different type of Key Seating can occur especially in deviated wells or where the angleis over 45 degrees, slow drilling allows a groove to be cut on the high side of the hole bythe drill pipe and when the Driller pick up of bottom and attempts to move the drill stringup the Tool Joints jam causing overpull and possible stuck pipe.Cuttings Beds; this again is normally associated with deviated holes and common whenthe hole angle is 60 degree or more. Low flow rates and string rotation speeds allow thedrilled cuttings to gather and create cutting beds, when the driller attempts to pull theBHA up past them he can get stuck. On horizontal wells where the section lengths can be



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1000 metres or more it is fairly common for the Driller to pump out of the hole. This iswhere they reverse the drilling operation and pump /rotate the drill string slowly up andback 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. Thepay zone might only be 20 metres (or in some cases less) thick and a 20 metre thickpay zone would not be very productive when drilled through vertically or at a slightangle. But if that pay zone were 3000 metre long then drilling along the length of theproductive zone becomes very commercially viable. The new MWD tools combined withnew computer technology have made this possible. Baker Hughes Intec and Anadrill havedesigned tools which can be altered from the surface to where they can be steered alonga formation sometimes only 6 metre thick. 3D seismic can plot these formations andcombined 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 fortheir Scheihallion field West of Shetland, they have a project called HIVES which takesall the information and generates a 3D picture of the area. They have built a special roomwith a large screen and you can input a new well and see the route it will take and whatproblems may be encountered from different angles. This type of new generation drillingtools are not cheap to make and average $1 to 2 million each and when run through therotary table start to cost the operator $2 to 3 thousand per hour so they have to berobust and reliable.Down hole motors may also be used, as described in the Spud Section, they are also madein several sizes and types. They have a section at the bottom of the motor which canbe 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 liningup 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 androtating the assembly the hole deviation can be built fairly quickly, 4 degree deviationover 30 metres is normal (Dog Leg Severity). The Dog Leg Severity has to be controlledso that the drill string can be tripped in and out and the torque required to rotate thedrill 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 andwell control.

Well Control Problems;If we start from spud then the first well control problem encountered would be ShallowGas which was mentioned in Section 2. About 20 years ago we used to drill and set the30 casing and then run a Pin Connector, this was a hydraulic latch and flex joint assemblywhich you ran on the bottom of Riser. The idea behind it was that you could use mudto 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 thegas to the rig and over the years after several incidents it was decided not to use a Pin



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Connector. If you drill into a Shallow Gas zone and the kill mud has been pumped then therig can be moved off location by either lowering the drill pipe stand as the rig is moved ordropping the drill string and moving the rig up wind or current. The stability of the rig isgreatly reduced due to the sea being aerated by the gas, further problems with fire orexplosions compound the incident.

If an over pressured zone is drilled into and the casing is set and cemented correctlythen 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 mudfor the steel displacement. Basically every tubular has an equivalent volume of mud toeither replace it when pulled out of the hole or when the drill string is run in the hole. Ifit is not monitored or measured correctly then the height of the mud will reduce and thehydrostatic pressure from the column of mud will reduce when the drilling string is pulledout of the hole. The Driller will use the Trip Tank to monitor the well whilst tripping orflow checking. On the Eirik Raude it is located in the deep well next to the ROV umbilicalwinch. 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 its own dedicated centrifugal pump which circulates mud from thetrip tank into the Diverter Housing, when the hole / riser is full it flows back downthe dedicated return line back to the Trip Tank. The volume is calibrated /monitoredcarefully to the nearest 10 Litre of volume change.Swabbing is caused by pulling the drill string to fast, possible small clearance betweenthe drill string and the hole, balled up bit or BHA, mud properties wrong. The mostcritical part when POOH is the first 5 or 10 stands out of the hole, if a slug has beenpumped then it has to be allowed to equalise before tripping commences. The volumeof 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 tripout.Shallow flows has been mentioned previously.Insufficient mud weight is where the hydrostatic of the mud column is less than theformation pressure. This could be human error where lighter mud has been pumped downhole or a higher pressured zone drilled into.Over pressured zone is where the overburden or the weight of the formations above arepressing down on a plastic / pliable formation or where there is communication due to a



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fault or from volcanic movement of the earth.Lost circulation is where the mud weight is to high for the formation pressure and theweak 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 therig were pitching / rolling and heaving then it is not so easy to see. Ballasting the rigwithout informing the Driller can create problems. One of the most important pieces ofequipment 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 hisflow 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 smallchanges.

3. When the stand of drill pipe has been drilled down and the crew have to make aconnection, the mud pumps would be stopped. Due to the high flow rates used whilstdrilling and the different equipment and length of flow line on the rig the mud willcontinue to flow for upto 4 minutes after the pumps have been stopped. The Drillermust be aware of the drain back volume whilst making the connection and the pit volumeincrease monitored so that when the pumps are started and back to full speed the pitvolume returns to the level before making the connection. Any differences could be anINFLUX from the formation.4. Connection gas is where the mud column is static when making a connection and thehydrostatic 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 gasis circulated out of the hole. The gas sensor located in the Shale Shaker header boxdetects the increase in gas levels in the mud. By setting the stroke counter to zerobefore starting the pumps the Driller can calculate where the gas came from i.e BottomsUp 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 againstthe formation and that is the Annular Pressure Loss. This is the back pressure createdby the flow of mud past the BHA and it may only be 5% of the pressure seen on the



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standpipe pressure gauge. This pressure is added to the mud hydrostatic and theEquivalent Mud Weight is calculated from that pressure. This is the dynamic mud weightwhich is exerted on the formation and when the pumps are running. When the pumps arestopped then the mud hydrostatic pressure reduces to that created by the original mudweight 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 sandformation 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 mudproperties, 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 checkedand calibrated regularly by the mud engineer. The basic one can be difficult to use if themud is aerated and personnel do not take the time to ensure it is full, the other one is apressure balanced unit which means that the container is filled with mud and the lid isinstalled 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 onthe balance arm. The balances are checked using potable water and adjusted by adding orremoving 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 importantpart with well control. He is aware of when the pumps are stopped and there should be noflow, the change in cutting size and shape can be another indication that we are about todrill into an Over Pressured Zone, the mud weight is equal or even less than the formationpressure and the formation instead of being drilled is pushed by the formation pressureinto splinters which can be recognised. Insufficient mud weight can also allow cavings tooccur, this is where the mud weight is insufficient to hold the formation and the sides ofthe 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 themud weight is about the same or less than the formation pressure. The mud pump hasless work to do so the Strokes per Minute increase slightly and possible flow from theformation reduce the Annular Pressure Loss so the pump pressure decreases. 5-7- & 8work together and normally the Drilling Break is recognised first.9. The formation is not being held back by the mud column, the cuttings are beinggenerated by the formation and the hole is not concentric. The bit instead of drilling thehole 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 theformation. The mud engineer would detect this during the mud properties check.

If the well kicked and an influx were observed by a pit or volume increase or flowincrease then the Driller would close in the well initially with the Annular and line up theChoke Line / Choke manifold to be able to observe any pressure increases. He would theninform the Toolpusher and Clients Representative and the DPO. The formation pressurecan be calculated from the pressure being registered on the Mud Standpipe, this is



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called the Shut In Drill Pipe Pressure or SIDPP, this pressure added to the hydrostaticpressure of the mud column would equal the formation pressure. The mud weight requiredto equal the formation pressure can then be calculated and this would be called the KillMud 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 CasingPressure. This pressure if different to the SIDPP may be used as part of the calculationto establish the influx type. This is required to be able to make forward plans for whenthe influx is circulated out of the hole.As an example. 1m3 of gas at a depth of 1000m with fresh water as the fluid columnwould be 98.1m3 in volume size when it reached the surface. Obviously the gas is ventedor disposed of so we have to replace that volume with mud.The most important part about well control is to maintain bottom hole pressure eitherthe same / equal as the formation pressure or slightly above. If the pressure were todrop 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 controlproblems 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. TheEirik Raude is capable of containing the gas in the riser with the Diverter System andcan then circulate the gas up the riser using the Mud Pump through the Booster Lineand directing the returns from the diverter system through a 10 line to the Poor BoyDegasser.Drilling High Pressure High Temperature wells have there own problems, normally theyare deep and several casings are required to isolate different formations. The movementof 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 willcause a change in the pit level, moving a 5 tonne piece of equipment around the rig willcause a change in the pit level. If the Driller is not aware of such operations then he willpick up off bottom and either flow check the well or Close In the well for safety. If itwere to happen to often then we could have the little boy shouting Wolfe syndrome andthe Driller allows a real influx to continue thinking it is something else. Ballasting the rigso that the deck can be hosed down could end up with personnel at the Life Boat Stationsnot 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 threshhold for working with H2S is 15 to 20ppm. One instructor at the Halifax Training Schoolgave a good description of 10ppm, if you were to stand on edge ordinary sheets of papernormally the thickness used in a photo copier the paper would be more than the length ofa football pitch. PPM means Parts per Million. The reason it is called Sour Gas is it smellslike 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 atdeck level or low areas of the rig. The Shale Shaker area is about mid level and there are



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several work areas which are lower than this. There are several sensors around the rigfor H2S, know where they are located and be aware of instructions which you may tannoyduring 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 CuttingDryer 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 isa lot of valuable information which can be gained by running Electric Logging Tools in theopen 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. Thenuclear sources used are very strong and strict handling procedures are used, along withthe 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 isgenerated from the rig. The time taken for the signal to reach the tools can then beinterpretated into geological estimates. A seismic survey vessel tows an array of toolspossibly 5 kilometres behind the vessel, using a high pressure gas gun to generate soundthe sensors measure the time for the sound waves to reach the tools.Repeat formation tester extends a probe into the formation and reads actual formationpressures. 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 intothe side of the hole and the cup is attached to the tool by a wire. The core or sample isrecovered 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 loggingwhere the previous casing collars are located. The depth is then logged and overlaid overthe information from the other tools. Markers built into the wireline cable every 100mare 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 toallow the formation fluids / hydrocarbons through the casing, if the drill string were tobecome 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 whichexpands 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 firingsystems used required Radio Silence before the tools could be armed. Several incidentshave been recorded where the explosive charges when armed fired due to RadioInterference.The Wireline Logging Unit is located at the Aft of the rig and has its own dieselgenerator to provide a clean electric supply for the delicate computers. Spikes fromother electric equipment can cause interference to the information being gathered.



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Section 11 Well Testing; Drill Stem Testing Operations or DST,Although hydrocarbons have been found the operator will not commit more money tothe development until they are sure it is commercially viable. Hydrocarbons can notbe 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 severaloperations involved with well testing. Information is taken from the MWD Logs andWireline Logging runs. Careful planning is then required to ensure that surface equipmentis 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 explosivecharges or Perforating Guns, the hydrostatic pressure from the mud controls theformation pressure and stops it from flowing. This type of perforating can give dirtyperforations and possibly damage the formation which could affect the flow from theformation. 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 islighter, when the guns fire the formation fluid again takes the easy route and enters thestring 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 stringis open ended, the next few joints of tubing or test string will include tools which havepressure 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 theperforated area of the casing from the BOP. Above the packer will be various other toolswhich 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 beused to close off the inside of the test string and isolate the open formation. Anothertype of Annulus Controlled Valve can then be used / opened and the area above thePacker circulated to a lighter fluid or to circulate Hydrocarbons out at the end of theWell Test. By venting the Annulus Pressure the valve closes and isolates the string tothe annulus. The valve is designed with a J slot Ratchet in other words the valve wouldonly 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 willoperate as well.There are also more sensors installed with gauges which record annular pressures andmore test string pressures.At the well head there is a tool called a Sub Sea Test Tree, this is attached to the teststring 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 valvesand chemical injection ports (to reduce possible Hydrates). Above the connector is a



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slick joint for the BOP pipe rams to close around and a section which can be sheared inan emergency. If the rig were to go to Red Alert then the BOP ESD function could beactivated. When the shear rams cut the pipe the two ball valves would failsafe close toseal 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, anotherremote operating ball valve will be installed this will be used to isolate the test stringand vent down a small volume so that wireline tools can be made up and run down the teststring.At the very top of the test string is the Surface Flowhead, normally a very large blockof metal which has a built in high pressure swivel at the bottom and a Master IsolationValve. 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 controlequipment 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, fixedHigh Pressure pipe work can not be used to connect it to the rig. Large High Pressurehoses normally called Coflexip Hoses are used to route the Hydrocarbons to the surfaceequipment. 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 Standpipewhich then routes down to the Well Test Area which is situated on the Port Aft Deckjust aft of the welders work shop.Depending on the expected surface pressure the rig well test line is attached to a ChokeManifold 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 highTar / Wax content it will be directed through a heat exchanger which is rated for amaximum working pressure of 200/3000 bar/psi from the heat exchanger it goes intothe Separator where any gas is separated from the oil. Built into the separator are flowmeters which measure the flow of oil / gas from the well. After the Separator the oil andgas 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 andoccasionally the well will slug some drilling mud. Water based muds cant be flared butas long as there is some oil being produced the flare can be kept alight using propane andcompressed 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 alsobe used as a measuring or stock tank.As the well is brought on slowly using the adjustable choke to maintain back pressureand control the flow rate the Hydrocarbons reach surface and the production rate isincreased. Depending on the type of burner in use / flow rate / pressures then the flamescan be approximately 30 metre long and 20 metres wide. The radiated heat could causesevere damage, the rig has a spray or cooling system installed to deluge the areas closestto the flare boom in use. Regular checks inside the rig structure and down the columns as



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far as sea level must be made for hot spots. Crane sheaves and wires could be damageddue 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 Unitand work shop. Check there are no oil drums or chemical containers in the area. Alsoconsider the Radioactive and Explosive storage positions. Local weather conditions will

have to be considered before and during flaring operations. Wind speeds less than 10knots or light to variable may cause problems with the smoke which can be producedbeing blown back onto the rig, should there be H2S found whilst drilling the well thenextra safety measures must be taken during DST operations.By careful monitoring of flow rate / pressures and choke size plus bubble point the wellwould 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 isreached. The bubble point is where the gas stays in the oil but if the well is flowed tofast the gas separates from the oils and you get a slugging effect. Once at a requiredflow 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 flowrate, 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 takenfor the formation pressure to recover when closed in, is also a good indication of thefield capabilities and permeability. If the well were to be produced too quickly and theformation was very permeable then sand could be produced during the well test, thiswould create problems with a long flow period. Wireline tools can be run down the teststring to take oil samples / pressure readings / flow rates whilst producing. This can beone of the hazardous operations during well testing, normally due to the type of glandpacking 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 andmud pumped down the annulus and up the drill string taking the Hydrocarbons back to thewell test equipment. Once the test string is dead or full of mud then the annulus valve iscycled to the closed position and the ball valve opened, the rest of the hydrocarbons arethen bull headed or pushed back into the formations. Possible lost circulation would beone 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 veryunstable 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 downhole gauges for information gathering.

High gas content and sea bed temperatures could give Hydrate problems; the SSTT haschemical injection ports for Glycol or Methanol Injection.Sub Sea Templates are structures possibly 50m x 100m x 10m high and are constructedto accommodate several well heads / production manifolds / Flowline sleds / WaterInjection Manifolds. For deep water they are ROV orientated as divers are limited tooperations or water depths upto 200m.Working over Templates have there own problems and each well will involve heavy lifts



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being brought onboard. The rig cranes can be the limiting factor and one of the mainconsiderations for the rig choice. The more equipment which can be built and tested onthe Xmas Tree ashore the les commissioning will be required onboard the rig and the lesschance of failures which require specialised equipment offshore. XMAS Trees can weighupto 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 tubularssuch as bundles of casing or running the BOP require special procedures and possibletemplate shut downs. The template could be producing oil to a FPSO and the FPSO wouldhave control of the producing wells via control Umbilical. Damage to any of the umbilicalscould 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 countriesrules 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 whichwere drilled through have to be isolated with either mechanical or wireline set BridgePlugs and / or cement plugs.The most common method is to set 150m long cement plugs across the open hole sectionand across the shoe area.It is possible to cut and retrieve casing strings; it would not be possible should they havecement around them. The first operation to cut and pull the casing is to remove the SealAssembly which isolates the casing from the next casing. Care should be taken due topossible gas percolation through weak formations or micro-annulus in the cement. TheSeal 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 possiblehydrocarbons behind the casings then extreme care and planning required. The sealassemblies are normally released with Left Hand Rotation and it is possible that a specialLeft Hand Drill string could be used or depending on the torque required a tool whichcan change right hand rotation to Left Hand Rotation at the tool. Once the seal assy isreleased 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 tungstenchips which are bonded onto the cutting arms cut the casing. As a guide, it may onlytake 30 minutes to cut through 9 5/8 casing. The same tool can be used for several sizecasings, 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.When the cutting arms are fully extended then there is a pressure indication and cuttingoperations are complete.The casing cutting tools are recovered and a special Casing Spear is run down and engagedinto the casing just below the hanger. The casing spear can also be used for several sizesof casings by changing the Grapple. The grapple has been manufactured for a specificsized casing and when at the depth it can be engaged by rotating the string and pickingup. The running tool mandrel has a left hand helix with tapered shoulders. The inside of



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the grapple has tapered shoulders as well, when the tool is picked up the taper force thegrapple to expand and wickers machined on the outside of the grapple engage or bite intothe casing and it can then be retrieved.Should the casing be stuck then mud can be pumped down through the Fishing Tools andout 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 careshould be taken especially if the mud has been in place for a long time and H2S couldhave formed. The casing can be retrieved back to surface and by rotating to the rightand bumping down on the casing spear the grapple should release. The operation is thenrepeated until the BOP can be retrieved and the 18 & 36 casing well heads are left.Weatherford have a special tool which can then be used to cut and pull both the 20 & 36together. The cutters are spaced out to cut approximately 6 metres below the 18 wellhead profile. They have to cut through the 20 casing and through the 36 casing in oneoperation. The 36 well head casing or housing can be 2 or 50mm thick. Normally thisoperation 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 wellhead 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 havealso tried to explain in laymans terms for those that are not familiar with drillingoperations. I hope that you have gained some insight as to how the well is drilled andsome 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 oroperations and not trying to confuse you. Asking if Martin Decker has the V door key issomething which you will learn for your self and never to forget.

DRSU

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