Deep Water Well Control Tt Pack

Page 1

What is deep water? Anything greater than 500 ft. isconsidered to be deep water. Therefore, anytime we areoperating in 500 ft. of water or more we should considerhow it may affect well control.

The aspects of well control that are affected by a deepwater environment are:

Choke Line Friction Losses (CLFL)

Maximum Allowable Annular Surface Pressure (MAASP) Fracture Gradients Riser Margin

Kick Tolerance Hydrates Trapped Gas in the BOP’s

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Schlumberger Sedco Forex

Engineering Department

INTRODUCTION

What is deep water? -Water depths over 500 ft.

Aspects AffectedChoke Line Friction Loss (CLFL)Maximum Allowable Annular Surface PressureFracture GradientsRiser MarginKick ToleranceHydratesTrapped Gas

Page 2

This presentation is divided into two sections: (a) Section 1 addresses CLFL with a brief discussion on how CLFL affects MAASP.

(b) Section 2 deals with fracture gradients, riser margin, kick tolerance, hydrates and trapped gasand how they are affected by a deep waterenvironment.

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Contents

Outline of Presentation:

Section 1 - CLFL and MAASP

Section 2 - Fracture gradients, riser margin, kick tolerance, hydrates and trapped gas.

Page 3

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SECTION 1

Page 4

CLFL is the pressure loss created when circulating through thechoke line and is caused by the friction between the fluid and the wallof the pipe.

The magnitude of CLFL’s are dependent on the length anddiameter of the choke line (constant for each well), mud propertiesand pump rate. Considering that the choke line dimensions for aparticular well do not change, the CLFL’s are simply a function ofpump rate and mud properties.

Therefore, once we know the CLFL for a particular mud type at acertain flow rate, no re-measuring is required unless there is asignificant change in mud properties such as density or viscosity.Presenters Note:In case of questions regarding the relationships of the above factorsto pressure loss the following two equations* are provided:

V = Q / [2.448*d2] P = [MW0.75*V1.75*PV0.25*L] / [1800*d1.25]Where: P = frictional pres. loss (psi)V = velocity of fluid (ft./sec) MW = mud weight (ppg)Q = flow rate (gal/min) PV = plastic viscosity (cp)

d = pipe inside diameter (in) L = length of pipe (ft.)*Source of equations: Adams Charrier, Drilling Engineering AComplete Well Planning Approach, PennWell. Chapter 18, page695, equations 18.21 and 18.24.

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Choke Line Friction Loss

1) What is CLFL?- Pressure losses in choke line- Frictional forces

2) CLFL is dependent on:- Length of the choke line (water depth)- Choke line diameter- Mud properties (density, viscosity)- Pump rate

Page 5

The deeper the water the greater the CLFL. This graphillustrates the effect water depth or the length of the chokeline can have on CLFL. For this example we haveassumed a 3” choke line with a 12 ppg mud and a slowcirculating rate (SCR) of 100 gal/min.

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Effect of Water Depth on CLFL

CLFL vs Water Depth

0

200

400

600

800

1000

1000 2000 3000 4000 5000 6000

Water Depth (ft)

Pre

ssu

re (

psi

)

Assumes 3” choke line, 12 ppg MW and SCR of 100 gpm.

Page 6

As stated in our well control manual: It is fundamental toall standard methods of well control to maintain constantbottom hole pressure throughout kill operations.

If we bring the pump up to kill speed (SCR) holding theSICP constant, and do so without taking CLFL into account,an additional BHP will be created equal to the CLFLpressure.

In shallow water this should not pose a problem asCLFL’s will be small. However, in deep water, CLFL’s willbe significant and may result in formation breakdown andpossible lost circulation problems during kill operations. (Inthe above diagram we can see that CLFL of 200 psi willresult in the BHP increasing from 5000 psi to 5200 psi.)

Therefore, in order to avoid these problems, we mustaccount for CLFL’s during a kick situation. There are twomethods that can be used to compensate for their effect.

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Effect of CLFL on BHP

700psi

500psi

BHP 5000psi

SHUT IN

1200psi

700psi

BHP 5200psi

BOP BOP

PUMPS ON

CLFL200psi

APLNegligible

Choke Choke

Page 7

In Method 1, the choke manifold pressure (SICP) isreduced by an amount equal to the measured CLFL whilethe pump is brought up to speed. While bringing the pumpup to speed, consider using a pump rate vs. SICP table toensure constant BHP is maintained. For example if a CLFLpressure of 200 psi was recorded for a SCR of 30strokes/min then a pump rate vs. SICP (or CLFL) tablewould be as follows:

Also, the choke line must have same fluid as

the wellbore. Once the chosen kill rate has been achieved, the choke

operator switches over to the drill pipe gauge as normaland depending on the kill method employed, maintainsconstant drill pipe pressure or follows the drill pipe pressuregraph.

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Compensating for CLFL - Method #1

Method 1 - Reduce choke

manifold pressure byCLFL (200psi)

- Once kill rate isachieved, switchover to drillpipegauge as per normalprocedure.

1000psi

500psi

BHP 5000psi

BOP

CLFL200psi

APLNegligible

Initial SICP= 700 psi

Choke

Kill Speed or SCR Pump Strokes (#) CLFL (psi)43% 13 5067% 20 10083% 25 150100% 30 200

Page 8

The second method involves the use of a separate killline gauge which measures the casing pressure at thesubsea BOP. As there is no flow in the kill line the pressureloss is zero. (If possible kill line should be filled with thesame fluid as the wellbore. However, common practice isto leave the kill line full of water and it may not be practicalto start displacing kill line before pumping.)

While bringing the pump up to kill speed the kill linegauge reading is kept constant. Thus, the rate of chokeopening is automatically regulated to compensate for anypressure loss created in the choke line.

The advantage in using this method is that it is notnecessary to measure CLFL’s.

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Compensating for CLFL - Method #2

Method 2 - Keep kill line gauge

constant whilebringing pumps up tokill speed

- Choke manifoldpressure gauge willdecrease equal toCLFL

1000psi

500psi

BHP 5000psi

BOP

700psi

KillLine

APLNeg.

CLFL200psi

Initial SICP= 700 psi

Page 9

In order to compensate for CLFL, using Method #1, weneed to know the pressure loss. CLFL can be measured bypumping down the choke line at a reduced pump rate,equal to the SCR rate, while taking returns up the openmarine riser. The CLFL is recorded on the choke manifoldgauge when returns are uniform.

Since low flow rates in large annuli typically result in alow pressure loss, this method assumes that the pressureloss in the marine riser is negligible.

It is important that the mud properties such as densityand viscosity are the same in the choke line and marineriser in order to obtain a correct pressure reading for theCLFL. Unless mud properties or pump rate changesignificantly it is not necessary to re-measure the CLFL.

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How to Measure CLFL

Measuring choke linefriction losses (CLFL) :

- Pump down the choke lineat same rate used tomeasure SCR

- Take returns up the openmarine riser

- Record pressure on chokemanifold gauge whenreturns are uniform

0psi

200psi

From pump

Choke

Page 10

In some cases the CLFL may be greater than the SICP, such as ifa kick is swabbed into a well. If this happens it is possible that overkillmay occur. If CLFL’s are greater than the SICP we need to try toreduce the magnitude of the CLFL. There are two things that can bedone:

use an unusually slow pump rate and/or take returns simultaneously through choke and kill lines.

Note that in most situations it is desirable to maintain the higher flowrate obtained by flowing through both lines. If this does have therequired effect then the pump rate can be slowed as well.

The example shows a situation where the SICP is 100 psi and theCLFL is 200 psi when pumping at 4 bbl/min, and 60 psi whenpumping at 2 bbl/min. The Well Control Manual presents two cases.

In the first case the pump rate is reduced to 2 bbl/min. Then theSICP (100 psi) is reduced by the value of the CLFL (60 psi) as thepump is brought up to speed and the BHP maintained at a constant5000 psi.

In the second case, the pump rate is maintained at 4 bbl/min butthe flow is diverted up both the choke and the kill line, 2 bbl/min ineach line. The corresponding CLFL (60 psi) is backed off eachgauge and the BHP is maintained constant. (Assumes lines have thesame dimensions) Normally the kill line has a direct return to thechoke manifold, therefore, return flow through the kill line can bechannelled to the choke manifold.

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When CLFL > SICP: Reducing CLFL

275psi

40psi

BHP 5000psi

Flow rate= 2bbl/min

475psi

40psi

BHP 5000psi

BOP

40psi

KillLine60psi

CLFL60psiCLFL

60psi

1. Reduce flowrate

Flow rate= 4bbl/min2bbl thruchoke and2bbl thrukill line

2. Flow thru kill and choke line

Choke Choke

SICP = 100 psi SICP = 100 psi

Page 11

MAASP is the surface pressure which, when added to thehydrostatic pressure of the existing mud column, will result information breakdown at the weakest point in the well. Therefore,when killing a well using either the drillers or wait-and-weightmethods we must avoid exceeding the MAASP. (If this is not possibleoptions are provided in the Well Control Manual section II.2.4.2)

In Figure 1 a kick has occurred where the SICP is 700 psi and theMAASP is 1000 psi. When kill operations begin, Figure 2, the SICPis reduced by the magnitude of the CLFL, 200 psi, as the pump isbrought up to kill speed.

However, the additional pressure created by the CLFL will betransmitted down hole. Therefore, if we want to be able to circulateout the kick at this rate the SIDPP must be less than the MAASP lessthe CLFL or:

SIDPP < MAASP - CLFLThis assumes that annular friction losses from the casing shoe to thechoke line are negligible.

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CLFL Effect on MAASP

500psi

700psi

BHP 5000psi

1200psi

500psi

BHP 5000psi

BOP BOP

CLFL200psi

Figure 1 - Shut In Figure 2 - Pump On

Choke Choke

Page 12

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SECTION 2

Page 13

Fracture gradients are a function of overburden andformation pressure. As water depth increases the effectiveoverburden at a given depth (RT) decreases. As a result ofthe reduced overburden, the pressure required to fracturethe formation also decreases.

The graph shows the effect of water depth on thefracture gradient at a 10,000 ft. casing shoe. A typicalfracture gradient at 10,000 ft. onshore would be 16.7 ppg.(Assuming a pore pressure of 10 ppg at the shoe) With1000 ft. of water, the fracture gradient would be decreasedto 15.7 ppg, at 2000 ft. it is 14.6 ppg and at 3000 ft., 13.7ppg.

The increasing water depth effectively reduces thedifference between the mud weight required to balance theformation pressure and that which will result in formationbreakdown. Therefore, the deeper the water, the moredifficult it becomes to carry riser margins and havesufficient kick tolerance to safely drill a well.

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Fracture Gradients

Effect of Water Depth on Fracture Gradient

12

13

14

15

16

17

0 1000 2000 3000

Water Depth (ft)

Fra

ctu

re G

rad

ien

t (p

pg

)Example only. Assumes 10,000 ft csg. shoe, 1000 ftwater depth and pore pressure of 10 ppg at shoe.

Page 14

A mud weight which includes a riser margin is the minimum mudweight that can be used to ensure sufficient hydrostatic pressure fromthe mud column, between the wellhead and formation, to controlformation pressure in case of riser failure or the need to disconnect.(When the riser is disconnected the hydrostatic pressure of the mudcolumn from the rig to the wellhead is replaced by the hydrostaticpressure of seawater.)

As water depth increases so does the riser margin mud weight.For example, in the diagram we’ve assumed a well drilling at 7000 ft.with a mud weight required to balance formation pressure - includinga safety margin - of 12 ppg. Assuming the density of seawater to be8.6 ppg, if we were drilling in 1000 ft. of water, a riser margin of 0.6ppg would be required for a total riser margin mud weight of 12.6ppg. In 2000 ft. of water the riser margin mud weight would be 13.4ppg and in 3000 ft., 14.6 ppg.

As we drill in increasingly deeper water, sometimes it may not bepractical to carry a riser margin as it becomes too large to effectivelydrill a well. In such a case it is important that the BOP’s be closed tomaintain bottom hole pressure.

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Riser Margin

Water Line

1000 ft.

2000 ft.

3000 ft.

MW withRiser Margin=14.6 ppg

MW withRiserMargin=13.4 ppg

MW with Riser Margin = 12.6 ppg

TD = 7000 ft.TD =7000 ft.

Page 15

Kick tolerance is the maximum kick that can becontrolled without breaking down the wellbore. As waterdepth increases the difference between fracture pressureand formation pressure decreases, reducing the kicktolerance for the well at a given depth.

In the diagram, the effect of decreasing fracture gradientand its effect on kick tolerance is illustrated. For a normalland operation, with the casing shoe at 10,000 ft., the kicktolerance would be 290 bbl. This assumes a mud weight of13.0 ppg and a formation that has kicked at 13,000 ft. withan equivalent pore pressure of 13.5 ppg.

In 1000 ft. of water the maximum kick that could besafely handled is reduced to 180 bbl. At 2000 ft. the kicktolerance is further reduces to 70 bbls and in 3000 ft. ofwater the kick tolerance is less than 10 bbls.

Fracture gradients, riser margins, kick tolerances, casingsetting depths, etc. all need to be considered together inthe initial planning stages of a well. Contingencies shouldalso be developed to deal with unplanned occurrencessuch as an overpressured zone.

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Kick Tolerance

Water Line

1000 ft.

2000 ft.

3000 ft.

Kick Tolerance= 180 bbls Kick

Tolerance= 70 bbls

KickTolerance< 10 bbls

ExampleTD =13,000 ft.Shoe = 10,000 ft.MW = 13.0 ppgPore Pressure = 13.5 ppg

Page 16

Hydrates are a solid mixture of gas and water whichlooks like dirty ice. The lines on this graph* show theconditions under which hydrates will form. The line on theleft is for pure methane (C1 ), the line on the rightrepresents natural gas which is a mixture of methane,ethane, propane, etc.. (C1, C2, C3, ....) Hydrates can, but donot necessarily, form at any point to the left of or above aline. Whereas to the right or below a line hydrates will notform.

Hydrates tend to form when pressures are higher andtemperatures are lower. Note that pressure is plotted on alog axis and temperature on a normal scale. This illustratesthat hydrate formation is more sensitive to a change intemperature than a change in pressure.

In a deep water environment, the wellhead pressuretends to be higher and the temperature lower. These areprecisely the conditions which encourage the formation ofhydrates.

*Source of graph: Hydrates, Technology Transfer Package

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Hydrate Formation

Temperature F

Hyd

rate

For

mat

ion

Pre

ssur

e ( p

si )

10

100

1000

10000

30 40 50 60 70 80 90

Methane Gas

Page 17

In this graph* the axes have been flipped and thepressure axis converted to water depth using the simplehydrostatic conversion equation: P = MW x 0.052 x TVD.This makes the information presented in the first chart alittle easier to use.

Here we can see the effect the water depth has on theformation of hydrates. At a water depth of about 1000 ft.,hydrates can form at temperatures at or below 600 F. Withthe same mud weight (10 ppg) and a much greater waterdepth of 4000 ft., hydrates can form at or belowapproximately 760 F. This means, that in this example, thetemperature at which hydrate ice can form is 160 F higherat a water depth of 4000 ft. then it is at a water depth of1000 ft..

*Source of graph: Hydrates, Technology Transfer Package

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Water Depth Effect on Pressure

Wellhead Water Depth ( ft. )

Hyd

rate

For

mat

ion

Tem

pera

ture

( 0 F )

50

55

60

65

70

75

80

85

0 1000 2000 3000 4000 5000 6000

10 ppg

Hydrate Formation Zone

Hydrate Safe Zone

Page 18

This graph is an example of the effect that increasingwater depth has on water temperature. (The extrapolateddata used for this example is taken from the North Sea.)Assuming a surface temperature of 69 0F, the temperaturedrops off rapidly within the first 200 ft. then flattens out. Itcontinues to drop at a rate of about 0.9 0F /100 ft. untilreaching 39 0F at about 1600 ft., approximately the lowestwater temperature possible in this example area of theNorth Sea.

As a comparison, geothermal temperatures drilling fromland or very shallow water will typically increase with depthat a rate of around 1.5 0F/100 ft.. The formationtemperature at 1600ft would be around 93 0F, a differenceof 54 0F.

This low water temperature presents a great danger ifcirculation is stopped and the wellhead allowed to cool tosurrounding water temperature. From the plot on page 18,at 1600 ft. the temperature only has to drop belowapproximately 65 0F to bring us into the hydrate formationzone.

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Water Depth Effect on Temperature

Depth vs. Temperature

30

40

50

60

70

80

90

100

0

200

400

600

800

1000

1200

1400

1600

Depth (ft)

Tem

per

atu

re (

F)

WaterLand

Example for North Sea

Page 19

As discussed on page 17, hydrates are a mixture ofwater and natural gas. Lower temperatures and higherpressures contribute to their formation.

In order to help prevent the formation of hydrates wecan:

prevent gas from ever entering the wellbore by practicinggood primary well control.

keep pressure at the wellhead as low as possible byselecting the lightest mud weights that can be used giventhe current well conditions.

reduce the amount of “free” water available for hydrateformation by adding salt or glycol to the mud system.

whenever possible maintain circulation. This will helpkeep the wellhead warm and above the temperature atwhich hydrates may form.

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Hydrate Prevention

1) Primary well control- No gas in well bore

2) Pressure reduction- Mud weight selection

3) Composition of drilling fluid- Additives (salts and glycol)

4) Temperature increase- Maintain circulation

Page 20

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Gas Trapped in Subsea BOP

CKMud

Gas

Closed Valve

Open Valve

Kill Mud

Water

During the removal of an influx from a well, gas maybecome trapped below the closed pipe rams and the killline. In a unique case, gas may migrate into the stackbefore it is detected and the BOP’s can be closed. This canresult in gas becoming trapped below the annularpreventer. This is especially important when drilling in deepwater as the expanded gas volume when brought tosurface will be significant.

Failure to remove the trapped gas under controlledconditions could result in gas entering in and displacingmud from the riser with the risk of riser collapse and furtherinflux of formation fluids.

Page 21

To illustrate the effects of water depth on trapped gas volumes weconsider an example were it was assumed that 5 bbls of gas becametrapped in the BOP’s. The graph shows the equivalent surfacevolume of these 5 bbls for three different mud weights. (Note that thisassumes all gas at atmospheric pressure) The greater the mudweight, the larger the volume of gas at surface.

In this example an 18 3/4” BOP and 21” Riser combination isassumed. The volume of the riser as a function of depth is alsoincluded to illustrate how large the volumes of expanded gas can berelative to its capacity. However, even with the assumption ofatmospheric pressure, in this example it is unlikely that the volume ofgas trapped will totally evacuate the riser. However, even a partiallyevacuated riser can cause problems by lowering hydrostatic pressureresulting in a second kick. This emphasizes the importance of havinga riser margin added to the mud weight.

Other events, such as loss of hydrostatic or BOP failure, couldresult in the riser becoming fully evacuated. In this event it ispossible that the riser would collapse somewhere around the 5000 to6000 ft. mark. This is however, dependent on many variables suchas riser tension, strength of material, etc.

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Surface VolumeSurface Volume of 5 BBLs of Trapped Gas

0

500

1000

1500

2000

2500

3000

3500

1000 2000 3000 4000 5000 6000 7000 8000

Water Depth ft

Vo

lum

e b

bls

12 ppg14 ppg16 ppgRiser

Page 22

In anticipation of dealing with the problem of trapped gas,modifications can be made to the BOP’s such as installing a drillingspool below the annular preventer or modifying the preventer toinclude an outlet. However, in the absence of such features theSedco Forex procedures for removing trapped gas are followed,(Sedco Forex Well Control Manual, Section V page 31).

The objective of the procedure is to allow the major portion of thegas trapped in the BOP to vent up the choke line by allowing it toexpand against a column of water.

After a well has been killed, gas may be trapped below the annularand/or the hang off rams (as illustrated above in the Trapped Gasdiagram). The procedure to safely remove this trapped gas is asfollows:

Step 1 Isolate the wellbore by closing a set of pipe rams,either lower or middle pipe rams (a flow path from the kill lineacross the top of the closed in rams and up the choke linemust be available).

SFM -DWC- 9622



CK CK

Mud

Gas

Closed Valve

Open Valve

Kill Mud

Water

Trapped Gas Step 1

Procedure to Remove Trapped Gas

Page 23

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Step 3Step 2

Mud

Gas

Closed Valve

Open Valve

Kill Mud

Water

Procedure to Remove Trapped Gas

CK CK

Step 2 Displace the kill weight mud by pumping water downthe kill line and up the choke line, holding back pressure onthe choke equal to the hydrostatic difference between the killmud and the water. When returns are clear water, stoppumping and close kill line.Step 3 Bleed pressure from the choke line allowing water andgas to escape through the line.

Page 24

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CK

Mud

Gas

Closed Valve

Open Valve

Kill Mud

Water

Step 4Procedure to Remove Trapped Gas

Step 4 Once flow stops, close the diverter, open the fill-up lineand fill the hole from top, and open annular. Take returnsthrough choke line. When well is static, circulate kill mud upthe riser then open lower pipe ram.

Page 25

For well control purposes, any water depth greater than 500 ft. isconsidered to be deep water. In this type of environment certainaspects of well control are affected. Those aspects include: i) CLFLii) MAASP iii) fracture gradients iv) riser margin v) kick tolerance vi)hydrates and vii) trapped gas in BOP’s.

CLFL’s are pressure losses in the choke line due to frictionbetween the fluid and the wall of the pipe. During a kick situation weneed to compensate for CLFL to ensure excessive bottom holepressure is not created which would result in a formation breakdownand lost returns. The deeper the water, the higher the CLFL’s will beand the more critical it becomes to compensate for them.

Whether using the drillers or wait-and-weight kill methods we mustavoid exceeding the MAASP. Therefore, when reducing the SICP bya value equal to the CLFL’s, the MAASP should also be modified to anew “circulating” MAASP.

Fracture gradients are a function of overburden and formationpressure. As water depth increases the fracture gradient for aformation at a given depth (RT) will decrease. This narrows the gapbetween the MW required to balance the formation pressure and thatwhich will result in formation breakdown.

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Summary

Drilling in Deep Water increases the complexity of well controloperations.1. Choke Line Friction Losses must be accounted for.2. The Maximum Allowable Annular Surface Pressure will bereduced.3) Lower Fracture Gradients will reduce the mud weight window.4) Mud weight must be increased to provide Riser Margin5) The Kick Tolerance will be reduced significantly.6) Actions are required to prevent Hydrate Formation .7) Procedures to handle high pressure Trapped Gas are required.

Page 26

This reduction of the fracture gradient affects the size of a kick thatcan be safely handled for a given well and the capacity to carry ariser margin. Fracture gradients, kick tolerances and riser marginsare interdependent and should be considered together during theplanning of the well. As well, contingencies should also be developedin anticipation of unplanned occurrences. Well maintained solidscontrol equipment will aid in keeping the mud weight within thedesired window and moderate tripping speeds will reduce thelikelihood of swabbed kicks or formation breakdown.

Hydrates are a mixture of gas and water and have a tendency toform in lower temperatures and higher pressures. In a deep waterenvironment, the wellhead pressure tends to be higher and thetemperature lower. These are precisely the conditions whichencourage the formation of hydrates and if left unchecked, they havethe potential to initiate a very serious situation. However, there areways to prevent the formation of hydrates. These are: i) keep gas outof the well bore by practicing good primary well control ii) keepwellhead pressure low by selecting the lowest mud weight possibleiii) use additives such as salts and glycol to tie up free water and iv)maintain circulation as much as possible to keep wellheadtemperatures high.

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Summary (continued)

Page 27

During well control operations gas may become trapped below theannular preventer and pipe rams. In deep water, the pressure at thewellhead is high and therefore, the volume of this trapped gas whenbrought to surface can be significant. Failure to remove the trappedgas under controlled conditions could result in gas entering in anddisplacing mud from the riser with the risk of riser collapse and/orfurther influx of formation fluids.

It is possible to modify the BOP stack in a way that minimizes thevolume of trapped gas. However, in the absence of modifications theprocedures outlined in the Sedco Forex Well Control Manual are tobe followed.

You should now be able to undertake drilling operations in a deepwater environment with an understanding of how deep water affectscritical elements of well control and a knowledge of the procedureswe employ to reduce the risks they create.

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Summary (continued)

Documents

Deep Water Well Control Tt Pack