chap7

EP 2002-1500 - 209 - Restricted to Shell Personnel Only

7. SUB-SEA WELL CONTROL: PRINCIPLES AND PRACTICES

7.1. Sub-Sea Well Control

There are serious well control problems associated with drilling operations from floatingvessels in any water depth. This section reviews the major problems likely to beencountered.

7.1.1. Introduction

Just as for drilling on rigs with surface stacks, well control problems can occur when usingfloating rigs with sub-sea BOPs. Although most of these problems tend to increase incomplexity with increasing water depth, some can be more severe in shallow water.

7.1.2. Kick Detection

Two of the major early warning indications of kicks are relative changes in the return mudflow, and change of mud level in the pits. Flow rate tends to fluctuate with vessel heaveand pit level tends to fluctuate with vessel pitch and roll, thus disguising the initial relativelysmall changes which occur at the onset of a kick. Equipment that compensates for vesselmovement by averaging multiple sample points can minimise but not eliminate theproblem. In doubtful cases there is no substitute for a visual flow check.

7.1.3. Fracture Gradients

In deep water drilling operations, fracture gradients at any particular depth are considerablyless than those experienced at equivalent depths in shallow water or on land. One of thereasons for this reduction in formation strength is the reduction in overburden stress fromthe long, relatively light column of seawater overlying relatively unconsolidated sedimentsbefore dense, well compacted rock is encountered. The net result of this is that kicktolerance can be drastically reduced and hence the need for early kick detection.

7.1.4. Sub-Sea Choke and Kill Lines

The length of the choke and kill lines extending from the sub-sea BOP to the drillingvessel, causes two major problems for well control which increase in severity with waterdepth. The first problem is the substantial circulating friction pressure loss which occurs inthe choke line during circulation of an influx from the well. The second problem is thedramatic change of hydrostatic pressure when gas displaces mud in the choke line andsubsequently when the following mud displaces the gas. These topics are discussed in moredetail in Section 7.2.

7.1.5. Shallow Gas

One of the most severe well control problems likely to be encountered from a floating rigis that of safely handling a shallow gas flow. When water depths exceed 200m it is generallyreasonable to assume that riser-less drilling or diverting sub-sea in conjunction withprocedures to move the rig away from the plume is the safest alternative. However, inshallower water there may be potential for a sudden gas eruption which is impossible toavoid, and riser-less drilling or sub-sea diverting may not be a viable option. Surface


diverter procedures are covered in the Shallow Gas Procedure Guidance Manual (EP 88-1000).

7.1.6. Riser Margin

When drilling from a floating rig there is always the possibility that the marine riser maypart or have to be disconnected. When this happens the hydrostatic pressure of the mudcolumn in the riser from the BOP to the pitcher nipple will be lost and replaced with thelower hydrostatic pressure of a column of seawater from the BOP to sea level. Thisreduction of hydrostatic may be enough to cause the well to go under-balance and kick. Itis normal procedure to use mud slightly more dense than required during normaloperations so that the well will not go under-balance if the riser is disconnected. Thisincrement of density is referred to as the Riser Margin. In many cases the normal TripMargin will adequately cover Riser Margin requirements. Only the greater of these twomargins should be applied. In instances where fracture gradients are critical and it is notpossible to maintain a riser margin, procedures must be in place to ensure that the well issecured in the event of loss of mud from the riser.

7.1.7. Riser Collapse

The marine riser is a large diameter conduit designed to provide an open flow path fordrilling mud between the subsea wellhead and the floating drilling vessel. It is not normallydesigned to withstand high burst or collapse pressures. Evacuation of the riser (unloadinggas) or a significant drop in mud level (losses) will subject the riser to collapse differentialpressure. The hydrostatic pressure of the seawater may cause the riser to collapse. Theproblem can be averted by maintaining liquid in the riser. This may be with a Riser DumpValve or by closing the BOP and filling from surface. Regular riser wall thickness tests areadvisable to monitor internal wear or corrosion that will reduce collapse resistance.

7.1.8. Trapped Gas

When a gas influx is circulated from the hole some gas may accumulate in the sub-sea BOPbelow the preventer and above the side outlet that was used. This gas must be removedbefore the BOP can be opened. This topic is discussed in more detail in Section 7.3 and inSection 7.5 for deepwater operations.

7.1.9. Killing the Marine Riser

After any well control operation that requires an increase of mud density, the well will bedead when kill density mud fills the drill string and the annulus to surface. On a sub-seawell part of the annulus that has been "killed" is the choke line. The density of the mud inthe marine riser has not been increased during the course of the well control operation.Before opening the BOP it is necessary to circulate the riser to kill density mud.

7.1.10. Hydrate Formation

Gas hydrates can form in the BOP and kill and choke lines on deepwater operations whenwater based mud is used. This topic is discussed in Section 5.4 and Section 7.5


7.2. Choke and Kill Line Effects

Long, relatively small diameter subsea choke and kill lines strongly influence secondary wellcontrol procedures because of dynamic frictional effects and the effect of fluiddisplacement on hydrostatic pressure in these lines. This section reviews these friction andhydrostatic effects.

7.2.1. Friction Effect

The dynamic friction loss in long choke lines has been called the "hidden choke effect"because the effect is the same as if a second, non-adjustable choke in the system wasgenerating a back pressure equivalent to the friction loss. It may also be considered as justanother hole section with very, very small annular clearance. The effects are the same, andresult in increased Equivalent Circulating Density (ECD) whenever well circulation isdirected through the choke line rather than the open riser. The magnitude of this increasein ECD depends on;

• The choke line configuration, internal diameter, length, tortuosity etc. These arefixed for a particular system.

• Circulating fluid properties. e.g. density and viscosity. These will differ over the lifeof the well and will also change dramatically during a kill operation, particularly if theinflux is gas.

• The rate of fluid flow through the line. Even at constant circulation rate this canchange substantially during the kill if the influx is gas.

During well killing operations, when surface shut-in pressures are also applied to thewellbore, the danger of formation fracture increases markedly if no attempt is made tocompensate for choke line friction effects. For this reason all subsea wells should be killedusing a procedure which compensates for choke line friction.

On surface stack wells it is usually acceptable to ignore annulus circulating friction pressureand commence kill circulation maintaining constant choke manifold pressure, by chokemanipulation, whilst the pump is brought up to speed. For subsea wells the initialcirculating choke manifold pressure must be reduced by the magnitude of the choke linefriction pressure for the particular circulation rate. During start-up the circulation rate, andtherefore friction loss, is changing so a pressure reduction schedule is necessary.

Choke line friction pressure can be measured during drilling operations by varioustechniques, details of which can be found in the Shell Distance Learning Training ManualSection 7.6. With this background data it should be possible to calculate approximatefriction loss values for a range of circulating rates and mud properties. These can be usedto make an approximation of the correct choke back pressure to apply when initiatingcirculation at commencement of a kill. However, it should be stressed that these are at bestonly rough approximations and will involve more complex calculations if the choke line isnot filled with original density mud prior to start-up.

The preferred, more accurate and simplest method is to disregard choke manifold pressureand hold BOP pressure constant, by choke manipulation, whilst the pump is brought up tospeed.

This technique is valid regardless of the contents of the kill and/or choke lines, isappropriate for any circulation rate and does not require any pre-recorded, calculated or


estimated data. Furthermore, the BOP pressure (static kill line pressure or BOP pressuremonitor) should be held constant, by choke manipulation, whenever it is necessary tochange circulation rate, or to stop and restart during the course of the kill.

All floating rigs must have a static kill line pressure gauge or BOP pressure monitormounted at the choke control console.

In instances where it is advantageous to use both the kill and choke lines during wellcontrol operations, a BOP pressure monitor should be installed, and this used in place ofthe static kill line pressure.

During the course of the kill operation there will be a sequence of different fluids in thechoke line, each of which will have different circulating pressure characteristics. (water orbase oil, original mud, influx, original mud, kill mud). The choke must be manipulated tocompensate for these variations and so maintain the required standpipe pressure for theparticular circulating rate. However, when gas enters the choke line the choke line frictionpressure drops markedly as gas, even at very high flow rates, has very low flowing frictionpressure compared to mud or other liquids. At the same time, gas expansion is acceleratingthe mud ahead of the gas which produces higher friction pressure and higher choke back-pressure. These effects, to a large degree, cancel each other out so little choke manipulationis necessary, but the choke manifold pressure will rise dramatically, as it must. Once gasreaches the choke the choke opening must be reduced rapidly and substantially to replacethis loss of choke and choke line friction pressure with actual choke manifold backpressure.

As the gas is vented the choke manifold pressure falls, again with little choke manipulation.However, when all the gas has passed through the choke, and mud returns, the chokeopening must be increased rapidly and substantially to a diameter slightly larger than it wasbefore gas reached the BOP. If this is not done there will be a large pressure surge thatcould fracture the well.

7.2.2. Hydrostatic Effect

In any well, whenever a gas kick is being circulated from the hole by a constant bottomhole pressure method, choke manifold pressure increases as the gas approaches surface.This is caused by the fact that the gas expands in the lower pressure environment, and as aconsequence of this expansion occupies a greater vertical height in the well to the exclusionof mud. The higher choke manifold pressure must replace the lost hydrostatic pressure.

In subsea wells this gas expansion problem is greatly magnified when a gas influx entersand occupies the relatively small volume, but substantial height, of the choke line. The mudhydrostatic head of the depth from Rotary Table to the subsea BOP may be lost due to thedisplacement of mud by low density gas. In order to maintain constant bottom holepressure, as indicated by the appropriate standpipe pressure, choke manifold pressure mustbe increased by reduction of choke opening. This effect is in addition to the low gasfriction pressure mentioned above, which also requires rapid reduction of choke opening.

7.2.3. Pressure Lag Time

The effects mentioned above can take place rapidly. When the objective is to maintainconstant bottom hole pressure by keeping standpipe pressure constant by chokemanipulation, it is possible that if the choke opening is not reduced as required, bottomhole pressure may drop below formation pressure before there is any indication on the


standpipe pressure gauge. This is due to the fact that pressure transients through densemud and long gas columns can be very slow. There may be a lag of as much as 1 secondfor each 300m (1000ft) of distance traveled. i.e. a change at the choke may not be reflectedon the standpipe gauge for 30 seconds in a 4,600m (15,000ft) well. It is therefore necessaryto anticipate the arrival of gas at the choke line and be prepared for rapid chokemanipulation.

As in start-up procedures, in the absence of a BOP pressure monitor, the most reliableindicator of pressures in the annulus is the static kill line. This gives a value indicative ofthe pressure at the BOP and will be a maximum when the gas influx first reaches the BOP.As gas enters the choke line the pressure at the BOP drops. This is in marked contrast tothe choke manifold pressure which is rising rapidly. This is the warning signal to the chokeoperator to prepare to reduce choke opening rapidly as gas presents at the choke. Duringall other phases of the kill, the choke manifold pressure and the static kill line pressure willtrack each other separated by the magnitude of the choke line friction pressure.


Static kill line pressure

Choke manifold pressure

Choke opening

Figure 7.2.1: Effect of gas in the choke line


7.3. Trapped Gas in Subsea BOPs

When a gas influx is circulated from the hole some gas may accumulate in the subsea BOPbelow the preventer and above the choke line side outlet that was used. This gas must beremoved before the BOP can be opened at the conclusion of the well killing operation.

7.3.1. Overview

Whenever an influx is being circulated from the hole from a floating rig, the drill stringshould be hung off on the pipe rams and the closest side outlet below those hang-off ramsshould be used as the choke line. The annular should only be used if there is a choke linesituated immediately below it. This will ensure that the volume of trapped gas is kept to aminimum. If at all possible, it should not be allowed to accumulate under an annular withno adjacent outlet as the distance from the choke line will result in a larger volume of gasand make removal more difficult.

7.3.2. Removal of Trapped Gas

Traditional methods for removal of trapped gas, such as the Turbulence Technique, theBack-surge Technique and the Toilet Flush Technique, have been demonstrated to haveminimal success. Based on a series of tests performed by Shell in the Gulf of Mexico thefollowing recommended procedure was developed. This procedure may vary in detailslightly from rig to rig and area to area.

1. During the kill procedure, always use a preventer that has an adjacent outlet.

2. On completion of the kill operation, isolate the well by closing a preventer below thetrapped gas.

3. Start boosting the riser with kill density mud.

4. Open the preventer above the trapped gas whilst continuing to boost the riser. Thishas the effect of stringing out and dispersing the gas bubble as it migrates out of theBOP.

5. Stop boosting and wait 30 minutes for the gas to migrate/string out more throughthe riser. Observe the well.

6. Circulate one third to one half of the riser volume.

7. Stop circulation and wait 30 minutes. Observe the well.

8. Continue circulation monitoring the flow from the top of the riser, looking forindications of gas.

9. Upon indications of gas at any stage, circulate slowly, being ready to close thediverter if necessary.

10. When the riser is dead and filled completely with kill density mud, check for pressureunder the lower preventer before opening and resuming operations.

Experience using this technique has shown that the worst "surge" of gas at the surfaceoccurs when the rig is operating in 300-600m (1000-2000ft) of water.

• In less than 300m (1000ft) the pressure of the trapped gas is not very great.

• In greater than 600m (2000ft) the riser volume is so large that the gas has time tostring out while coming up and does not arrive at surface all at once.


• In water depths greater than 1200-1500m (4000-5000ft) there may be insignificantimpact.

7.4. Subsea Well Control Procedures and Calculations

The basic principles of well control are the same for any well. However, Subsea BOPsystems deployed from floating drilling vessels introduce complexities that may requireadditional calculations and special procedures. This section addresses those complexities.

7.4.1. Measurements

It is vital for hang-off, shearing, stripping and all wellhead operations that the distancefrom Rotary Table to the wellhead and to each ram and annular preventer of the BOP isknown accurately. These measurements are best taken when the test tool is run for the firstBOP test after landing the stack.

• There must be an accurate dimensional stack-up drawing of the wellhead and BOPshowing the distance of each component from a datum, usually the wellheadconnector seal gasket. The mid point of each ram preventer is always a usefuldimension.

• Rig up a tide gauge connected to the telescopic joint outer barrel and set it to agreewith reference tide tables if available. Allowance should be made for fleet angle.

• Paint the test single with white or light coloured paint before running in for the BOPtest. The white paint will be marked by the rams and annulars when they are closedaround it during the pressure test.

• While the test tool is seated in the wellhead, mark the drill pipe at the rotary table(heave average) and simultaneously note the tide.

• After completion of the BOP test and while pulling out, accurately measure thedistance from rotary table to each of the marks on the test single and to the landingshoulder on the test tool. Correct these depths to tide datum and record and displaythem prominently in the dog house.

• The depths should be checked when the wellhead bore protector is run after theBOP test.

� With the motion compensator, lightly tag the top of the closed shear rams withthe bore protector on the running tool. Mark the pipe at rotary table and notethe tide.

� Pick up, open the shear rams, land the bore protector in the wellhead. Markthe pipe at rotary table and note the tide.

� Release the bore protector.

� Pull back above the BOP, close the shear rams, lightly tag the top of the closedshear rams with the bore protector running tool. Note that the difference fromprevious recorded tag depth confirms that the bore protector has beenreleased.

� All these depths should be tide corrected and checked against the originalmeasurements.


• Determine the average drill pipe single length and using that in conjunction with themeasurements taken above, calculate the stick-up above rotary that places a tool jointat every critical point in the BOP. This information must be readily available to theDriller at all times.

7.4.2. Shut-in Procedure

Offshore Floating Units (with drill string motion compensator operational)1. With the pump ON, unlock rotary bushing and raise the kelly or top drive to the pre-

determined position for landing the string on the designated hang off rams. (with thelower kelly cock above the rotary table, allowing for tidal condition). Note that themotion compensator may be stroked out or locked so ample clearance must beallowed for heave.

2. Stop the pump.

3. Function Close the upper annular preventer.

4. Simultaneously function Open the outer fail-safe valve of the choke line. The rest ofthe choke line is always open to a closed choke under normal conditions. (Hard shutin)

5. Close the valve upstream of the adjustable choke if it is a non-sealing choke. Do notclose valves that isolate pressure sensators.

6. Close the designated hang off pipe rams. These must have room below the shearrams to cut the drill pipe above the hang-off tooljoint if a disconnect becomesnecessary.

7. Land the string on the rams, set compensator to mid-stroke position and close lockson the rams (wedge locks).

8. Observe closed-in drill pipe pressure SIDPP (Pdp) and closed-in annulus pressureSICP (Pa).

9. Open Kill line subsea valves to give a static BOP pressure reading.

10. Kill the well by the method previously determined as appropriate.

The use of a circulating head is mandatory for killing a high pressure well or when usingcirculating pressures of over 27,600 kPa (4000 psi). Follow the same closing in procedureas is described for offshore floating units with drill string motion compensator non-operational. The circulating head assembly may be supported by the motion compensator,constant tension winches, or tensioners.

Offshore Floating Uunits (with drill string motion compensator non-operational)1. With the pump ON, unlock rotary bushing and raise the kelly or top drive to put the

lower kelly cock above the rotary table.

2. Stop the pump.

3. Function Close the upper annular preventer.

4. Simultaneously function Open the outer fail-safe valve of the choke line. The rest ofthe choke line is always open to a closed choke under normal conditions. (Hard shutin)


5. Close the valve upstream of the adjustable choke if it is a non-sealing choke. Do notclose valves that isolate pressure sensators.

6. Set the string in the slips.

7. Close the lower kelly cock, bleed off pressure in the kelly or top drive.

8. Disconnect the kelly or top drive above the lower kelly cock.

9. Install the circulating head on one drill pipe single.

10. Attach the supporting system to the circulating head assembly (using constanttension winches, or tensioners).

11. Pick up the string, remove the slips. Position pipe at pre-determined space-out forhang-off.

12. Close the designated hang off pipe rams.

13. Land the string on the pipe rams with the circulating head assembly supported by theelevators riding on the handling sub. Close the ram locks.

14. Pressure test the lines/hoses and connections to the circulating head and standpipemanifold to the pressure rating of the manifold.

15. Remove the elevators (depending on heave) with the circulating head assemblysupported by the supporting system.

16. Pressure up the lines to the lower kelly cock to Pdp and open the lower kelly cock.

17. Observe closed-in drill pipe pressure (Pdp) and closed in annulus pressure (Pa).

18. Open Kill line subsea valves to give a static BOP pressure reading.

19. Kill the well by the method previously determined as appropriate.

7.4.3. Calculations

Once the shut in pressures and influx volume are known all the normal calculationsrequired for well control can be completed and well kill schedules prepared. These include;

• Kill mud density

• Initial Circulating Pressure

• Surface to Bit Strokes

• Final Circulating Pressure

• Influx Gradient and hence influx type.

• Approximate strokes for influx to reach critical points. e.g. casing shoe, BOP,surface.

Start-up procedures must be modified to reduce Choke Manifold Pressure by choke linecirculating friction pressure as described in Section 7.2. If it is not possible to read static killline pressure or there is no BOP pressure monitor, then a pressure reduction schedulemust be calculated based on pre-recorded measurements of choke line friction pressure.


7.5. Deep Water Well Control

This section captures the key topics for deep water well control operations. For thepurposes of this manual, deep water is a water depth >500m or 1500ft.

7.5.1. Overview

SummaryThe methods and approaches described in this section are applicable to all deep water wellswith a subsea BOP.

However, when dealing with wells that have only a small margin between formation andfracture gradients (as is the case in overpressured wells such as those found in the Gulf ofMexico) a higher level of detail must be considered. In particular, the impact of proceduresand events on the annulus must be thoroughly understood, monitored and controlled.Additional considerations for this type of well are given in Sections 8 and 5.11. It issuggested that for this type of well, well and rig specific engineering is carried out.

By contrast, for many wells there is sufficient margin between formation and fracturegradients such that the well can be controlled. For these wells, industry methods inexistence for many years introduce safety factors into the circulating pressures and anypotential for additional flow is stopped. Because there is sufficient margin, there is nonegative impact on the well, such as lost circulation.

Overall Approach to Deep Water Well Control

• The �Hard Shut in Method� will be used (Typically using the Upper Annular)

• For all cases where there is a high SICP (or likelihood that this will result during thekill operations), movement of pipe through the BOP because of weather, or there isthe potential for loss of rig position (e.g. use of Dynamic Positioning), the drill pipewill be hung off on a dedicated hang off ram following initial shut in. If none ofthese conditions apply, then it is possible to keep the well shut in on an Annular,with slow movement of the pipe to prevent stuck pipe. In this instance an outletshould be available below the annular used for shut in.

• When water base mud is in use, the Driller�s Method will be the normal method ofwell control. If OBM (or SOBM) is in use, the Wait & Weight Method may be used.However, if there is only a small margin between mud weight and fracture gradient,the use of the Driller�s Method is suggested such that the pit levels can be veryclosely monitored during the kill circulation. Alternative actions should be discussedbetween the Rig and shore based operations teams. If immediate actions arerequired, the Rig team has the full authority to proceed.

• If a kick is taken off bottom, the bit will be stripped to bottom wherever practicaland safe, prior to attempting to kill the well. Under no circumstances will the drillstring be run back to bottom with the well open and flowing.

• A kick will be assumed to be gas until shown otherwise.

• The major difference to well control with a surface BOP stack is the position of theBOP and the impact of having to circulate through the relatively long, small chokeand/or kill lines. These lines impose a significant backpressure upon the circulationsystem with the pump on � this backpressure must be accounted for.


• Consideration should be given to installing the following:

� BOP pressure and temperature gauges

� Insulated choke and kill lines (near the BOP)

� Drill pipe tool joint positioning system (based on the delta distance of therotary table to top of riser)

• If SOBM is being used, a pressurized riser and a gas handler (annular preventer atthe top of the riser) is recommended.

• Hydrates have been considered a significant issue in deep water drilling. However, ifthe simple mitigation methods outlined in this document are taken, hydrates shouldnot be a problem. Hydrates will not be a problem if SOBM is in use. Particularattention should be taken with wells where massive lost circulation is possible.

For all wells, steps should be taken to ensure that gas is stopped from rising into thewellhead connector and freezing the connector.

• Ballooning may be a problem for a deep water well. Procedures must be in place toensure that this phenomenon is dealt with in a safe, yet effective way.

See Section 8.3.5. Ballooning / Flowback / Backflow / Supercharging.

The overall Well Control Process (for a kick with the bit on bottom) is:

1. Flowcheck and shut well in.

2. Circulate out kick and kill well with kill weight mud.

3. Sweep the stack and clear the riser of gas.

For WBM, a small gas bubble can be very easily dispersed within the riser by shuttingdown the pump and waiting. This approach is very effective for dealing with small gasbubbles such as those trapped in the BOP after a well control incident.

For OBM (or SOBM) this will not be the case. Only one rig is known to have acombination of pressured marine riser and surface mud gas handler/outlet to choke. Thisis the Nautilus. For this rig a suspected gas bubble in the riser can be circulated out over achoke, with the riser gas handler closed. For all other rigs, great care must be taken if a gasbubble (dissolved in OBM) is suspected in the riser. Close attention must be paid tolimiting the size of any potential bubble, by following the appropriate stack sweepingprocedures etc..

Special consideration should be given to the contents of the choke and kill lines withregard to:• Fluid Type• Temperature• Hydrate inhibition


7.5.2. Shallow Gas in Deep Water

Shallow Gas - Drilling the Top Hole Section (Riserless)

Shallow gas in a deepwater context is taken to mean encountering a gas bearing formationwhen drilling the Top Hole section in a riserless mode. A gas influx may occur because theformation is effectively overpressured or because of an action (such as swabbing) thatoccurs during the drilling or tripping process.

For deep water, the combination of low temperature and high pressure (due to waterdepth) should ensure that any gas pockets exist as hydrate. Hydrate will look like gas on ashallow seismic survey. The approach taken in this work will effectively deal with thesituation whether the gas is in gaseous or hydrate form. If the gas is in hydrate form, therewill be very little (if any) impact upon the drilling performance � there may however be avery significant impact on future development operations and the presence of hydrate mustbe identified .

Under no circumstances will a top hole section be drilled with the riser attached.

Kicks Once the BOP has been InstalledOnce the BOP and drilling riser have been run all kicks must be treated in the conventionalmanner - the BOP must be closed and the influx will normally be circulated out in theconventional way (normally using the Driller�s or Wait & Weight methods).

As a general philosophy, on floating drilling rigs where there is any risk of shallow gas,drilling to the first casing point below structural casing will be carried out without takingreturns to surface.

Discussion of Shallow Gas Problems

• Shallow sands filled with gas are overpressured at the top of the sand.

• The pressure at the base of the sand or at the gas/water contact, if there is one, isnormally equivalent to hydrostatic pressure of seawater at that depth. In somelocations, rapid deposition may have resulted in geo-pressured sands.

• The pressure at the top of the sand will be nearly the same as the pressure at thebottom, if the sand is gas filled.

• The amount of overpressure (if any) is directly a function of the height of the gasaccumulation above the gas/water contact.

• Shallow gas hazards drilled without either a weighted mud or a riser will kick.

• The time between the start of a kick and the complete unloading of the well will be amatter of minutes. There is generally very little time to take corrective action.

• It is considered far safer to drill these top hole sections without a riser attached.

• When gas blows out it can produce a plume of aerated low density water. This canaffect the buoyancy of a floating vessel if the gas plume comes to surface beneath it.In reality, problems have only occurred when hatches were left open on drillingvessels in a plume and the vessel simply flooded when it lost freeboard or heeledover and sunk as a result. Chain lockers can also be a danger if they can flood.

• With increasing water depth and sea current the plume will tend to come to thesurface away from the rig. Mooring or positioning arrangements will be planned to


enable the rig to move clear of the gas plume from the well, should it be necessary todo so.

Other points to note are:

• If the sea water is heavily gas cut, there may be a substantial decrease in the buoyancyfactor making evacuation by sea with the standby boat very hazardous.

• Landing a helicopter on the rig with the wind blowing in the direction of the helideckwould be impossible due to the risk of fire or explosion.

• If the rig has to be evacuated, the main engines will be shut down to remove thepotential for a spark. This will cause the emergency generator to come on line. Whenand if it is safe to do so, the OIM will then shut down the emergency generator onhis way to his point of evacuation.

• For most deep water situations, the combination of low temperature and highpressure due to water depth will mean that if low gravity natural gas exists, then itwill exist as hydrates. As such there will be little or no danger of a gas blow-out. Theexistence of such hydrates must be noted for future development consideration. Itshould be noted that as temperature increases with drilled depth it is not impossibleto drill into free gas below a hydrate cap.

See Section 5.3 for further details on Shallow Gas

Typical Example of a Pre-Drilling Operations Safety Checklist:Action √√√√

1 Move off plan in place � Anchors prepared for emergency release (designatedwinches depending on weather) � Direction set for DP drive off.

2 Constant monitoring of wind, current, sea state3 HVAC shut down procedures and mode to be reviewed4 Gas watch � ROV & Continuous �bubble watch�5 Standby Vessel positioning6 (Moored Rig) � Cables or chains marked for easy relocation7 Radio review8 Windsocks in place9 Float valve to be run in string � as near to bit as possible10 Monitoring of seawater suction points11 No hot work unless absolutely necessary12 Test all gas detectors and alarms13 Prepare at least one hole volume of heavy mud14 Hold safety meeting & explain procedures

Procedures for moving off in emergencyPrevailing weather conditionsSeismic dataHistorical data for areaUse of LWDMaximum weather conditions for operationsReporting proceduresTiming of drilling eventsCrew responsibilities


Methods of preventing gas intrusionSummary of radio channels in use

15 Emergency drill16 Perform an emergency pull-off drill (if required)17 Hold an abandon ship drill18 Double check abandonment equipment19 Engine exhaust sprays to be on (if fitted)20 Close and dog deck level watertight doors and hatches

Drilling Operations

It is most likely that the rig can stay on location, even if a gas flow occurs. In deep water anygas flow is likely to flow away from the rig. The rig should only be moved if it is directly in thegas boil or downwind from the gas boil and in the gas pocket.

1. While drilling, have the mooring/dynamic positioning controls manned at all times incase it is necessary to move vessel away from a gas boil in the event of a shallow gaskick. Do not hesitate to move the vessel in this event, even if drill pipe has not beenwithdrawn from the hole.

2. If a gas flow occurs, switch suctions to heavy kill mud and pump at maximumobtainable rate.

Drilling Solid (in-situ) HydratesAt the conditions to be encountered in the top hole section, it is possible to drill into in-situ gas hydrates. In particular, the temperatures are low enough and the pressures highenough for solid gas hydrates to have formed anywhere that free (methane) gas existed.

Typically 1 cubic foot of hydrate will release 170 SCF of gas as well as 0.8 cubic ft of wateron decomposition. By contrast, 1 cubic foot of formation (9ppg formation pressure at5000 ft RKB, 30% porosity) will release about 50 SCF of gas.

Hydrates will dissociate to gas and water if the temperature is raised or if the pressure isreduced. Dissociation may therefore take place as the solid hydrates cuttings are circulatedto the seabed and the pressure is reduced. However, as noted above, although the volumeof gas that could be liberated is about three times the volume that would be liberated asdrilled gas it is not significant and does not constitute a flow. Dissociation in the wellborecan also occur when the mud gradient is less than the inherent (gas) formation pressureand dissociation can also take place in the wellbore as the well is deepened and the mudwarms during periods of continuous circulation.

However, dissociation is a slow process and immediate disassociation of the hydrate willnot take place. As a result, there will not be a flow of gas into the wellbore from apenetrated hydrate section in the same way that would be for a column of gas where theformation pressure was greater than wellbore pressure.

If a hydrate section is penetrated, proper consideration must be given to the long termpotential consequences. In particular, the potential for warming of the formation aroundthe wellbore and subsequent production of gas must be considered. If any signs ofpotential in-situ hydrates are seen (drilling rate changes, gas at seabed etc..), these must bereported to the Senior Drilling Supervisor.


Finally (and for all wells) it is most important to obtain a good cement job around theconductor casing. This may prevent gas migration around the conductor and potentialhydrate formation in the BOP/Wellhead connector.

7.5.3. Shallow Water Flow

Shallow water flows are uncontrolled water flows which occur when drilling shallow tophole sections. The flow may be from one formation to another or from a formation to theseafloor through the wellbore or through the wellbore and then by broaching around thepreviously set casing string.

General Information and PlanningShallow water flows have been seen in some areas, in particular the GOM deep water inwater depths beyond 150m (500 ft) and at depths ranging from 60m (200 ft) to 600m (2000ft) below the mudline. These flows may also be found in other similar depositionalenvironments. Once a shallow water flow starts it is very difficult to stop because of thevery small margin between pore pressure and fracture gradient.

Typically the sands within which such flow occurs are geo-pressured because of rapidsedimentation.

The flow may start:

• After a sweep removes cuttings from the well and the hydrostatic pressure is reduced

• During a cement job with the cement in its transition phase

During the planning stage, potential shallow water flow zones may be identified using acombination of seismic and offset well information. The potential for shallow water flow ishigher when sands are overlaid with sediments deposited at a high sedimentation rate. Acut-off rate is about 150m (500 ft) per million years � if the sedimentation rate is greaterthan this, treat the sands below as having overpressure.

If overpressures are suspected, it is prudent to consider relocating the surface location (ifpossible).

A PWD tool may give a first indication of the existence of a shallow water flow. LWD canbe used to confirm the actual depth of seismic markers.

Potential Drilling Techniques for Shallow Water Flow (SWF) Zones

• Try to avoid potential shallow water flow locations � relocate if necessary

• Jet the conductor. Minimize seawater pumped before setting conductor

• Minimize the diameter of the hole drilled to allow for good cuttings removal. Pumpsweeps every stand. Tracers can be added to sweeps (dye, mica) to try to evaluateflow, washouts etc.. The goal is to avoid charging of formations with cuttings load.

• Use a weighted drilling mud � typically this may require shipping a heavy brine to thelocation, with on-board dilution, such that the large volumes required can be kept upwith.

• When heavy mud is used to prevent a shallow water flow the mud weight should betargeted to offset the potential hydrostatic pressure, but not too high to causefracturing or ballooning. The formation pressure may be 80-90% of the overburden.Fluid loss should be kept low (<10 cc/30 min) along with low, flat gel strength (10


sec., 10 min, 30 min.), YP � 10, PV � 15. The low gel strengths should allow forefficient cement displacement at the low annular velocities.

• Dynamic kills (if required) should be pumped at the highest possible rate (theannulus friction pressure will be low anyway, given the hole size). If not successfulafter 2 hole volumes, then success is unlikely.

• Use LWD and PWD near the bit to correlate to seismic and monitor downholepressures.

• After penetrating a sand, clean the hole and check for flow. Allow time to observe ifa flow dissipates. Charging of a sand (cuttings) can give a false indication of a flowzone.

• The casing point should be as close to the shallow flow zone as possible.

• If flow is encountered and casing is to be set above the flow zone, then heavy mudcan be spotted below the proposed casing shoe.

• Pay very close attention to cementing practices. In particular, it is imperative to haveas short a transition time (time from the onset of hydration until the cement hassufficient gel strength to prevent flow). Compressive cements are suggested, such asMicrofine and Nitrogen Foamed.

• Surging should be avoided when running casing.

• For development wells (with clustered locations), well spacing should be maximized.

• Consider using other �non-conventional� approaches, such as use of in-situpolymerization, freezing the SWF zone etc.

A number of mechanical devices are available to help control SWF between casing strings.It is beyond the scope of this manual to discuss these, but consideration should be given tosuch devices.


7.5.4. Pre-Kick Preparation

Note:� the following is taken from the IADC Deep water Well Control Guidelines

CasingShoe

• Measure pressure integrity of casing shoes, i.e. by leak-off/integrity tests• Post both ppg equivalent and associated surface pressure for the mud weight in use• Update this pressure periodically and when drill string, mud property, or other changes occur which may affect pressure.

Slow PumpRate

• Post slow pump data (for at least two pumps) on both drill pipe friction loss and both C&K Line Friction Pressures (CLFP)• Take pressures on two gauges reading from separate sources to guard against gauge failure• Note the pressure required to break circulation the first time, and record this value for use in kick detection and circulation procedures• Ensure that cuttings in hole and riser do not affect slow pump data• Additional methods can be employed at the time of the kick to update this data, i.e. using static C&K line or subsea pressure sensorNote: Slow pump test rates should represent anticipated kill rates (which may be as low as 1-2 BPM in deep water).

C&K LineFrictionPressures

• Use CLFP to help establish initial circulating casing pressure• Recognize that in deep water the CLFP is likely to change such that test data are only estimates• Measure and record pressure losses with low circulation rate through the lines in parallel*One option to reduce friction losses during well control in a deep water wells is to circulate the kick using the two choke and kill lines in parallel.

Kill Sheet • Maintain an up-to-date kill sheet designed for a subsea BOPFloat Valve • Use a float valve to prevent backflow, i.e. when removing the top drive (or kelly) from the drill string

• Use a float valve to guard against backflow through drill pipe during an emergency disconnect and/or failure of the shear rams to sealNote: Flow up from the drill pipe can impede the ability to stab a safety valve

C&K linevalvepositions

• Show C&K line valve positions on a chart/white board indicating which valves are open/closed and C&K line fluid contents (mud versuswater)

• Show the relationship between the surface tool joint location and corresponding tool joint location opposite the BOP stack rams and annulars• Calculate and post the distance and proper spacing for each stand to help with space-out, if variation in stand length warrantsNote: As water depth increases, the variation in drill pipe joint length can create too much uncertainty in tool joint position: this potential problem can be reduced byarranging joints so that 10-stand average lengths do not vary by more than a set amount, i.e. 0.1 feet.

Mud GasSeparatorCapacity

• Post liquid and gas handling capacity of mud-gas separator• Compare these to the maximum anticipated gas rates that would result from planned well control procedures and well and C&K line geometry,


i.e. pumping rate, design kick

Diverter • Keep diverter insert packer installed and locked except when handling BHA larger than manufacturer�s stated diameter capacity• Post diverter element status (in/out)

Designatedhang-offram

• Identify designated hang-off ram• If it is a VBR type, post the hang-off capabilities for the various DP sizes in the hole• Specify if rams are to be locked after closure (independent locks)

Personneldrills

• Perform BOP drills (pit and trip) regularly, including tool joint space out to ensure crew competency• Consider having crews perform �stripping drills� prior to drill out of the casing shoes to ensure crew competency in handling stripping


7.5.5. Flowcheck / Shut In Procedures

Flowcheck/Shut In Procedure - Drilling

If Flow Increase or

Pit Gain, Shut In

Immediately

Flow Check (keep pipe moving)

“Hard” Shut In – (Upper) Annular1. Pick up to predetermined space out height with the pumps running 2. Stop pumping (incl. Boost pump) 3. Close the upper annular 4. Set the compensator to mid-stroke to minimize movement through the

annular 5. Open the fail-safes corresponding to the closed BOP against a closed

choke 6. Continue to flow check the riser and if flow continues Close the Diverter

and (Upper) Pipe Ram (reconfirm space out before closing the (U)PR) 7. Record pressures at the BOP, Choke and Standpipe at 1 minute

intervals. The cold environment and gelled mud within the choke line may preclude measuring SICP. If this is the case, it may be necessary to close a second BOP and flush through the choke and kill lines before opening up below the lowermost closed BOP and measuring SICP.

8. Record the Volume of the influx 9. Close the standpipe back to the mud pumps 10. Inform the Drilling Supervisor and Toolpusher 11. Confirm that the choke is closed 12. Check all surface systems for any leaks 13. Run the Trip Tank on the Annulus if the diverter has not been closed –

note and record the level every 10 minutes Hang off the drill string on the Designated Hang-off Pipe Rams if: A. there is movement of the drill string through the annular due to weather B. the differential pressure across the BOP is greater than 1000 psi or

likely to become greater than 1000 psi. Any pipe movement with this high a pressure may cause premature annular wear

C. DP rigs D. There is no choke line outlet immediately below the annular

Resume Operation

Flowing? YesNo

Shut Well In

Line up on Trip Tank & record level

Monitor Trip Tank

No

Obviously Flowing?

Stop drilling & raise pipe to

Stop pumps (incl. Boost pump) Other

Pump Press. Drop

Etc..

Indication:

Drill break

shut in position with pumps on

Yes

Flow Increase Pit Gain


Line up on Trip Tank. Note and record level of trip tank

Shut Well In

“Hard” Shut In – (Upper) Annular1. Set the string in slips. Stab the FOSV and close the FOSV (unless

already done) 2. Pick up to the pre-determined space out height 3. Close the (Upper) Annular and open the Failsafe Valves corresponding to

the closed BOP against a closed choke 4. Continue to flow check the riser and if flow continues Close the Diverter

and other (Lower) Annular. 5. Reset the slips and make up the top drive – may need to strip a tool joint

through (Upper) Annular to enable make up (to strip: lower Annular operating pressure to a value previously determined by the OIM/Toolpusher – typically this may be 500 psi plus ¼ x SICP, but can be measured in a drill (before drilling out casing) to determine actual numbers.

6. Open the FOSV and confirm the top drive IBOPs are open. Pull the slips 7. Record pressures at the BOP, Choke and Standpipe at 1 minute

intervals. The cold environment and gelled mud within the choke line may preclude measuring SICP. If this is the case, it may be necessary to close a second BOP and flush through the choke and kill lines before opening up below the lowermost closed BOP and measuring SICP.

8. Record the Volume of the influx 9. Close the standpipe back to the mud pumps 10. Set the compensator at mid –stroke to minimize movement through the

Annular Preventer 11. Inform the Drilling Supervisor and Toolpusher 12. Confirm that the choke is closed 13. Check all surface systems for any leaks 14. Run the Trip Tank on the Annulus if the diverter has not been closed –

note and record the level every 10 minutes

15. Hang off the drill string on the Designated Pipe Rams if: A. there is movement of the drill string through the annular due to weather B. the differential pressure across the BOP is greater than 1000 psi or likely

to become greater than 1000 psi. C. DP Rigs D. There is no choke line outlet immediately below the annular.

Flowcheck/Shut In Procedure - Tripping

Flow Warning Sign Occurs, or other requirement for Flow

Check

Pick up drill string to shut in Position

Monitor Trip Tank

Resume Operation

Stab the FOSV (Open Position)

Shut FOSV Yes No

Flowing?

• Prior to a Trip • Incorrect fill-up • Any indication that

the well is flowing • Before the BHA

reaches the BOPs

No

Yes ObviouslyFlowing?

Shut FOSV


7.5.6. Other Shut in Procedures / Considerations

Other Shut in Procedures/Considerations

Hang-Off on Designated Rams 1. Reduce the (upper) annular pressure to allow free downward travel of the drill

string. Pick up until a TJ tags the annular preventer and confirm space out

2. Close the designated Pipe Rams, reduce the operating pressure as required

3. Lower the drill string & hang the TJ off on the designated Pipe Rams (if weather conditions indicate the potential for rough weather it may be prudent to hang off on the (middle) pipe rams – for some BOP arrangements, such as the one shown, there would be a greater potential for dealing with pressureunderneath the shear rams following a disconnection)

4. Increase the ram operating pressure to normal

5. Set down the desired weight on the rams, keeping the compensator at mid-stroke

6. Start the trip tank pump and circulate over the well while recording for leaksthrough the BOP or gas in the riser

7. Prepare to kill the well as required (The annular is left closed in case of early gas at the BOP)

Shut In Procedure – Wireline in Hole 1. Stop logging

2. Open choke line valve(s) – don’t wait for valve to open

3. Close the (upper) annular preventer

4. Record pit gain – monitor and record casing pressure at 1 minute intervals

5. Notify Toolpusher and Senior Drilling Representative

If at all possible, the wireline should be pulled or stripped out of the hole. If the linemust be cut and dropped, a surface cable cutter should be used (This must beavailable during logging jobs). The shear rams should be considered as a lastresort and used only if the annulars fail to secure the well.

Shut In Procedure – No Drill String in BOP 1. Open choke line valve(s) – don’t wait for valve to open

2. Close the blind/shear rams

3. Record pit gain – monitor and record casing pressure at 1 minute intervals

4. Notify Toolpusher and Senior Drilling Supervisor

Once the well has been shut in, preparations can be made to run a kill stringinto the well. Given the water depth, it should be possible to strip a drill string using the upper annular preventer, unless the pressure underneath the shearrams is very high

Shut in Procedure – Drill Collars in BOP Stack This situation implies that a trip is in progress. The shut in procedure for tripping should be followed. Once the well is shut in, preparations should be made to strip in the hole to: a) put drill pipe across the BOP b) strip to bottom and carry out a conventional kill (Driller’s Method)

Drill Pipe Float Valve Pump Off Test 1. Line up the mud pumps to the drill pipe 2. Pump in small increments, 50-100 psi into the well 3. Record DP and CP – if the CP does not increase, the float is still closed

and Shut in-Drill pipe Pressure (SIDPP) is less than the underbalance in the drill string

4. When CP is seen to rise, pumping should be stopped immediately 5. Record SIDPP – this now reflects the amount of underbalance in the

string – this is the value to be used when calculating Kill Weight Mud 6. Bleed off any induced pressure


7.5.7. Kill Procedure � General and Preparations

General1. The objective of a conventional kill is to circulate out the influx while maintaining

the bottom hole pressure at slightly more than the formation pressure and displacingthe well to an adequate kill weight mud

2. The Driller�s method is the method of choice for WBM. This will enable any gas tobe circulated from the well as fast as possible and reduce the risk of hydrateformation. For OBM (or SOBM) the Wait & Weight method may be used � there isa negligible risk of hydrate formation. However, if there is only a small marginbetween mud weight and fracture gradient, the use of the Driller�s Method issuggested such that the pit levels can be very closely monitored during the killcirculation.

3. Well control worksheets should be updated every 12 hours to reflect changes in thedrill string, hole geometry, mud weight increases, slow circulating rate pressures andany other factors which will affect the kill calculations.

During the well kill operation, if anything appears to be wrong or unclear during theprocedure, shut down the pump, close in the well, and evaluate the problem.

7.5.8. Kill Calculations

1. The influx volume is taken to be equal to the pit gain. Accuracy in making thismeasurement is required.

2. The bottom hole pressure is equal to the shut in drill pipe pressure plus thehydrostatic pressure of the mud inside the drill string. If the kick is taken off bottom,the drill pipe pressure is not a reliable indicator of formation pressure.

3. If the influx is taken with the bit on bottom, the influx density can be estimatedusing the shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP) asfollows:

Influx Density (ppg) = MW � SICP-SIDPP 0.052 x H

Where H is the calculated vertical height (ft) of the influx above the bit determinedfrom influx volume and annular capacities. This calculation can be inaccurate and allkicks should be handled as if they were gas until well conditions show otherwise.

4. The required kill weight mud density can be determined as follows:

Kill Mud Density (ppg) = Current Mud Density (ppg) + { SIDPP (psi)} {TVD (ft) x 0.052}

5. Well control calculations (as shown above) should be updated with the SIDPP, SICPand pit gain volume.

7.5.9. Determination of Initial Circulating Pressure

If no slow circulating rate is available, or a change in mud weight or configuration hasoccurred (e.g. blocked nozzle), then it will be necessary to determine the initial circulatingpressure. The recommended procedure is as follows:


1. Note the choke pressure and BOP pressure reading

2. Bring the pumps up to the new kill rate while adjusting the choke to maintain theBOP pressure constant (the choke pressure should reduce by an amount equal to thechoke line friction loss at the selected pump rate)

3. As soon as the new pump rate is reached and the drill pipe pressure has stabilized,note the drill pipe pressure. This is now the valid initial circulating pressure.

4. If during the constant drill pipe pressure phase of the Driller�s method the drill pipepressure changes unexpectedly, shut the well in and evaluate a new circulatingpressure using the above procedure

5. The pump should always be brought up to speed and shut down while maintainingthe BOP pressure constant. On bringing the pump up to speed on a subsea well, thechoke pressure should become smaller by an amount equal to the choke line frictionpressure at the selected pump rate. When the pump is shut down (with the BOPpressure being maintained constant), the choke pressure should rise by an amountequal to the choke line friction pressure at the selected pump rate. The chokepressure can be used as a check on the BOP pressure readings.

7.5.10. Choke & Kill Line Friction - Maintaining a Constant BOP Pressure

Well control procedures as written for a surface BOP/Land well will state..�Bring thepump up to speed maintaining constant BOP or choke pressure�. For a subsea well, thestatement is correct if the BOP pressure is maintained constant as the pump is stopped orstarted (see Figure 7.5.1). In this case, the choke pressure must be adjusted to allow for thefriction pressure in the choke and/or kill lines.

When starting a pump (at the start of a kill circulation, for example) the choke pressuremust be reduced by the amount of the choke and/or kill line friction pressure in order tomaintain a constant BOP pressure. When stopping a pump the choke pressure must beincreased by the amount of the choke and/or kill line friction pressure in order to maintaina constant BOP pressure.

There are three alternatives (see Figure 7.5.2) for achieving this:


Figure 7.5.1: Subsea vs. land / jack-up well control

P

Maintain constant choke (BOP) pressure when bringing pump up to

speed or adjusting pump

P

Maintain constant BOP pressure when bringing

pump up to speed or adjusting pump


P

A. Utilize BOP pressure gauge

P

C. Back off choke pressure by amount equal to measured choke & kill line friction pressure

B. Utilize kill line as monitor

P

Figure 7.5.2: Maintain constand BOP pressure when bringing pumps up to speedor adjusting pumps

A. If a BOP gauge is available, then use it. The choke will still have to be manipulated, butthe control is achieved from the use of the BOP gauge.

B. If the choke/kill line friction pressure is low enough, either the choke or kill line can befilled with fluid (less dense than the drilling mud) and lined up to a closed valve. Thisline will register a positive pressure, even if there is no excess pressure (other than mudhydrostatic) in the wellbore. The pressure reading on this line can be used as a measureof the relative pressure at the BOP and can be kept constant as the pump is started orstopped.


C. If no BOP pressure gauge is available and it is not possible to dedicate a choke or killline to BOP pressure monitoring then it will be necessary to back off (or increase)(start or stop) the choke pressure by an amount equal to the measured choke and/orkill line friction pressure loss.

In reality, if A or B is chosen/available, use of the estimate generated for C. is probablyappropriate as there will be a small time delay from action taken at the choke and registerof the change at the BOP pressure gauge or at the surface pressure gauge being used tomonitor BOP pressure.

7.5.11. Selection of Kill Rate & Use of Choke and/or Kill Lines

Determine SIDPP & Pit

Gain

Is hang-off required

Select kill rate Typically 3-5 bpm

Line up to Kill on (upper) annular &

using both choke & kill lines

Hang off on PR. Typically line up kill with both Choke &

Kill Lines

YesNo

Will resultant gas rate at surface overwhelm

Will friction loss in c/k line at selected rate

cause lostReduce kill rate

Reduce kill rate

Reduce kill rate

Proceed with Kill Plan and Kill the well

No

Yes

No

Check circulating Kick Tolerance – OK?

Yes

No


7.5.12. Kill Procedure � Driller�s Method: 1st Circulation

Objectives: Return well to hydrostatic control (if a swabbed kick). Remove any gas fromthe well quickly such that the gas does not cool and form hydrates

With gas at surface, monitor MGS pressure.

Be prepared to route overboard if MGS

pressure rises to alarm levels

With gas out, shut down & confirm SIDPP

& SICP

Warning The Choke and Kill

Line contents will cool down to seabed

temperature in about 15 minutes. Unless you act these areas

will be within the Hydrate Formation

Zone

Isolate well and flush Choke & Kill Line and

BOP cavity with mud / glycol

mixture. Fix problem

SICP should = SIDPP & also equal original

SIDPP at initial shut in. If not, then further

circulation required (check for trapped

pressures).

Well Shut In on Annular Or Hung Off

Select kill rate and use of Kill line or

Choke and Kill lines

Bring Pump up to speed

Maintain pump speed and pump pressure while circulating gas

from the well (one complete circulation

l )

Shut-down

required?Stop Pump

Based on: Surface Gas Rate Choke operation Choke & Kill Line friction Hang off Bad Weather

Maintain constant BOP Pressure. Let a small

additional influx in, ratherthan risk overpressuring

the well

Maintain constant BOP Pressure. Let a small additional influx in,

rather than risk overpressuring the well

Yes

No


7.5.13. Kill Procedure � Driller�s Method: 2nd Circulation

Objectives: Return well to hydrostatic control

No

Yes

With SIDPP & SICP=0, open choke to mini trip tank and perform flow check. If no flow then well is dead.

If flow then review, raise MW, circulate etc.

With kill mud all the way round, shut down and

confirm SIDPP &SICP=0 If >0 continue circulation

increase MW etc.

With KW mud above BOP, monitor pump pressure. If this is rising (with choke wide

open) be prepared to slow kill down (OR shut down, isolate well and flush kill weight mud

through choke & kill lines to avoid overpressuring casing shoe

Maintain constant BOP pressure while you slow

the pumps down. This will maintain the proper BHP

Maintain pump speed and constant drill pipe pressure while circulating gas from

the well (one complete circulation plus excess)

Shut-down required?

Isolate well, flush Choke & Kill lines and BOP cavity with Mud / glycol mix. Fix problem

Stop Pump

Isolate well, flush Choke & Kill lines and BOP cavity with Mud / glycol mix. Fix problem


additional influx in, rather than risk

overpressuring the well

Maintain pump speed and constant choke/BOP pressure

while circulating Kill Weight Mud down the drill pipe to the bit

Shut-down required? Stop Pump

Monitor pump pressure and compare to pre-

determined pump pressure schedule (W&W). If

different, stop & think







SICP=SIDPP=Initial SIDPP? Continue 1st Circ.@ constant pump rate and pressure

Bring Pump Up To Speed

Yes

No


7.5.14. Kill Procedure � Wait and Weight

Objectives: Return well to hydrostatic control in the most efficient manner

Maintain constant BOP Pressure. Let a small additional

influx in, rather than risk overpressuring the well

Based on: Surface Gas Rate Choke operation

Choke & Kill Line frictionHang off Bad Weather

Well Shut In on Annular Or Hung Off

Select kill rate and use of Kill line or

Choke and Kill lines

Bring Pump up to speed

With SIDPP & SICP=0, open choke to mini trip tank and

perform flow check. If no flow then well is dead. If flow then

review, raise MW, circulate etc.

With kill mud all the way round, shut down and

confirm SIDPP & SICP=0 If >0 continue circulation

increase MW etc.

With KW mud above BOP, monitor pump pressure. If this is rising (with choke wide

open) be prepared to slow kill down (OR shut down, isolate well and flush kill weight mud

through choke & kill lines to avoid over pressuring casing shoe

Maintain pump speed and pressure following established

pump pressure schedule (adjust based on measures pump

pressure with pump up to speed). When kill weight mud reaches bit, maintain constant pump pressure

Shut-down required?

Warning The Choke and Kill

Line contents will cool down to seabed

temperature in about 15 minutes. Unless you act these areas

will be within the Hydrate Formation

Zone

Maintain BOP pressure constant

while slowing pumps

With gas at surface, monitor MGS pressure. Be prepared to shut down / go overboard if MGS pressure rises to alarm level

Stop Pump

Isolate well, flush Choke & Kill linesand BOP cavity with Mud / glycol mix. Fix problem

Yes

No


7.5.15. Choke Adjustment Considerations

When using the Driller�s or Wait & Weight methods, it may be necessary to makeadjustments to the Drill Pipe Pressure by manipulating the choke. The correct method is:

1. When a change is desired on the Drill Pipe Pressure, note the amount of pressurechange required

For example, if the current Drill Pipe Pressure is 850 psi and the desired DrillPipe Pressure is 1000 psi, the amount of change is an additional 150 psi

2. Note the current Choke Pressure and by manipulating the choke, change the ChokePressure by the amount of change desired on the Drill Pipe Pressure.

For example, continuing from the example in 1 above, if the current Choke Pressureis 1050 psi, the choke operator should close the choke to increase the ChokePressure by 150 psi to 1200 psi.

3. Wait at least two seconds for every 1000 ft of measured depth of the well for thepressure change to come from the Choke to the Drill Pipe Pressure gauge. (this delaytime may be confirmed by using a choke reaction test, which would be performedbefore drilling out of casing)

The Drill Pipe Pressure should now change (after 20 seconds or so) to the desired reading(1000 psi). If it only comes up to 980 psi, the procedure is repeated (the Choke Pressureraised by 20 psi etc.). The key to success is to allow a time lag between choke adjustmentand the change at the Drill Pipe Pressure gauge.

7.5.16. Preventing Hydrate Formation within the BOP Stack � Use of WBM

Gas hydrates, which are solid, ice-like crystals, can form when a mixture of gas (methane,ethane etc..) and water is cooled below a hydrate formation temperature. The higher thepressure, the more likely that hydrates will form. Conditions at the BOP are such thathydrates could form. In particular the seabed temperature is close to 0 deg C. Hydrates donot form at the instant that conditions fall below the formation temperature. It can takesome time while �nucleation sites� become available. Once hydrates have formed, they willbe very difficult and time consuming to remove.

There is a 3-part process to preventing hydrate formation within the BOP, consisting of:

1. Inhibiting the mud system. Salt and glycol when added to the mud system areeffective in lowering the hydrate formation temperature. It may not be possible (oreconomic) to inhibit the mud system to the extent that hydrates will not form underany potential temperature/pressure combination. Note: The computer programWHYP (partly developed by Shell) can be used to determine the level of inhibitionthat is appropriate.

2. Removing the gas from the wellbore as soon as possible � The Driller�s method hasbeen selected in preference to the Wait & Weight method in order to achieve thisobjective

3. It is always best to maintain a constant circulation. However, if a shut down isrequired for any length of time (more than 10 minutes), the well should be isolatedusing the lower pipe rams and inhibited fresh mud (at the same weight as is in thechoke and kill lines) should be circulated down the choke line and up the kill line.This will ensure that hydrates do not form and block the BOP and choke lines. If the


shutdown is to be for an extended period, the choke and kill line should be displacedto inhibited glycol/seawater mixture as per normal drilling practice. This action willalso prevent the settling of drill solids and subsequent blockage of the choke and killlines.

When SOBM is in use, the hydrates will not form unless water has been introduced to thesystem.

7.5.17. Sweeping the Stack & Clearing the Riser- General Issues

Following a well control circulation there are three types of potential situation where gasmay be trapped in the BOP stack. These are:

a) Very small amount of potential trapped gas (< ½ barrel) at the BOP stack..

b) Able to pump down choke/kill line and flush trapped gas up kill/choke line. Althoughthere is the potential for a larger volume of gas to be trapped under the BOP, thispotential larger volume can be (and must be) flushed up the choke/kill line once thekill circulation is finished and with the well isolated using the lower pipe rams.

c) Large volume of trapped gas � poor BOP configuration/valving inoperable. Here thepotential for a significant amount of trapped gas dictates that the BOP must be�swept�.

These options are shown below

(A) Very small trapped volume

(B) Able to flushtrapped volume

(C) Large volume of trapped gas

CLEAR GAS

FROM RISERFLUSH BOP betweenPipe Rams & (Upper)

Annular

SWEEP THESTACK

Details of the approach to be taken are dependent on the BOP configuration. Theexamples given below are based on the configuration shown in Figure 7.5.3.

7.5.18. Clearing the Riser of Gas

The key to performing this operation safely is to allow time for any gas to disperse.Dispersion will occur for gas in WBM � it is not the case for gas in OBM. FOR OBM ITIS ESSENTIAL THAT THE REMAINING GAS/OBM VOLUME IS LESS THAN ½BARREL

With the well still isolated � lower pipe rams closed1. Displace the riser to kill weight mud through the booster line.

2. When complete open the annular preventer.


3. Pump 3 to 4 barrels kill weight mud down the kill line (choke line if UPR used) todisplace any remaining gas above the BOP.

4. Check for flow (15 minutes)

5. Line up and pump kill weight mud down both choke and kill lines & displace 1/4 ofthe riser with kill weight mud.


7. Pump kill weight mud through the choke and kill lines and displace another 1/4 ofthe riser volume.





12. Check for flow (15 minutes). Confirm kill weight mud throughout riser (mud weightcheck at flowline plus BOP pressure gauge)

13. Circulate and condition kill weight mud in riser.

14. Close the upper choke line valves on the BOP. Line up the choke line to a closedchoke and open the lower choke line valves to check for any pressure build up belowthe closed lower pipe rams. If no pressure proceed with step 15.

15. Close the lower choke valves on the BOP. Line up and displace the kill line andchoke line to unweighted inhibited mud. Close the fail safe valves on the BOP. Openthe lowermost pipe rams and condition the mud in the hole.

If at any time during this procedure, gas migration is indicated by an increasing flowratefrom the riser, shut the well in using the annular and close the surface diverter. Investigatethe cause of the flow and take the necessary steps (e.g. additional Driller�s method, clearingthe riser of gas) to regain control.

7.5.19. Flushing the BOP

In this case there is potential trapped gas between the Pipe Rams and the (Upper) Annular,but the (Upper) Annular has remained operable throughout the kill.

1. Isolate the well using the Lower Pipe Rams. This is done by:

a) Open the Upper Pipe Rams (if they were closed for the kill). Check the riser toconfirm that there is no flow. Reduce the upper annular pressure sufficiently toallow free travel of the drill string. Pick up until a TJ tags the annular preventerand confirm space out. Close the Lower Pipe Rams. Reduce the operatingpressure as required.

b) Lower the drill string and the TJ onto the Lower Pipe Rams. Hang the drill stringoff on the Lower Pipe Rams. Increase the ram operating pressure to normal.

2. Line up to the mini trip tank and flowcheck the well.


3. Circulate (at least one volume of the combined choke and kill lines) kill weight muddown the choke line, taking returns from the kill line through the variable choke,until no more gas returns.

4. Leave the fail safe valves on the kill line open (all other fail safes closed) and line upto a closed choke. Monitor BOP and choke pressures (should be constant).

At this point there should be a minimum of gas at the BOP. The riser can now bedisplaced to kill weight mud and cleared of gas.

Flushing The BOP: Typical Subsea BOP Arrangement

(Potential Location of Trapped Gas)

CHOKELINE

Lower Pipe

VBRs

KILLLINE

#1

#2

#3

#4

Spacer Spool

P/T

Upper Pipe(Hang Off Ram)

Blind/Shear

LMRP

Lower Annular

BOP

Pressure/TemperatureGauge at LMRP Package

OriginalWeight Mud

Kill WeightMud

POTENTIALGAS

P/T

Pressure/TemperatureGauge at BOP

Upper Annular

Upper Connector

LowerAnnular

Figure 7.5.3: Flushing the BOP


7.5.20. Sweeping the Stack

1. Isolate the well using the Lower Pipe Rams. This is done by:

a) Open the (Upper) Pipe Rams (if they were closed for the kill). Check the riserto confirm that there is no flow. Reduce the upper annular pressure sufficientlyto allow free travel of the drill string. Pick up until a TJ tags the annularpreventer and confirm space out. Close the Lower Pipe Rams. Reduce theoperating pressure as required.

b) Lower the drill string and the TJ onto the Lower Pipe Rams. Hang the drillstring off on the Lower Pipe Rams. Increase the ram operating pressure tonormal.

2. Circulate (inhibited) seawater down the upper choke line taking returns from theupper kill line through the variable choke with a backpressure to maintain thepressure at the BOP equal to a kill line full of kill weight mud. The BOP pressuregauge will confirm this. Stop when the choke line has been displaced with (inhibited)seawater. There may have been some gas that was flushed to surface during this step.Isolate the choke and kill lines against closed chokes.

3. Confirm the displacement of the kill line using the choke and BOP pressure gauges.(The choke manifold gauge (choke side) should read the difference in hydrostaticbetween a column of kill weight mud and a column of inhibited seawater - the BOPgauges should read the hydrostatic of a column of kill weight mud.)

4. Close the kill line valves at the BOP. Line up the choke on the choke line side to takereturns to the mud gas separator. Open the choke, and allow any inhibited seawaterand trapped gas to blow back (AND OVERBOARD) through the mud gasseparator. Allow this process to occur until no more fluid or gas comes through thechoke.

5. Close the diverter and line up to the riser degasser.

6. Open the lower annular preventer and the choke. Because the fluid in the riser isheavier than the inhibited seawater, U-tubing will occur from the riser into the chokeline. Continuously fill the riser (with mud) and using the riser boost pump during thisoperation.

7. If there is no flow from the riser, open the diverter. Check the riser for flow (15minutes).

During this period close the lower annular preventer and circulate kill weight mud downthe kill line and up the choke line, and through the choke and mud gas separator tocompletely displace the choke and kill lines with kill weight mud.

At this point there should be a minimum of gas at the BOP. The riser can now bedisplaced to kill weight mud and cleared of gas.

7.5.21. Kick Off Bottom

The best chance of controlling the well is if the string can be stripped back to bottomthrough closed preventers. Once the drill string has been stripped to bottom, standard wellcontrol procedures can be employed.


Under no circumstances if the well is flowing, may the pipe be run back in the well withoutstripping.

For a subsea BOP, annular stripping only will be considered.

The decision on whether to strip to bottom or not will depend on surface pressures,distance from bottom and available equipment. In general for surface pressures less than1000 psi, it should be possible to strip to bottom. For higher pressures, stripping shouldalso be considered as long as it can be accomplished without additional hazard topersonnel.

If stripping in is not possible due to high surface pressures, then for gas and WBMcombinations the preferred method is to use the Volumetric Method (see section 5.17) toallow the expanding bubble to rise to surface. Bullheading of heavy mud into the annulusmay also be considered where the influx is likely to contain H2S or where surface pressuresare approaching 80% of casing yield strength. It may also be very effective for OBM,where the bullhead injection rate can be quite slow. Circulation off bottom should only beconsidered if it is known that the influx is 100% liquid which will not release gas as itcomes to surface or if all the influx is above the bit. DO NOT circulate off bottom if thereis a risk that there is any gas below the bit.

Because of the complicated nature of these types of operations, the rigsite supervisorypersonnel should take the time to carefully think through the process and agree upon aplan before beginning. If time permits, the plan should also be discussed with the Shorebased team. Be aware that (for gas and WBM) if the kill operation is not started shortlyafter the kick is taken the gas will begin to migrate up the well.


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chap7

Documents

subsea choke

shallow water

subsea diverting

subsea bops

water depths

control problems likely

shallow gas flow

riser marginwhen drilling