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Jerome Schubert,

SPE,

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TECHNOLOGY

WELL CONTROL

Recommended additional reading

at OnePetro: www.onepetro.org.

SPE 138465 Qualification of Well-

Barrier ElementsTest Medium, Test

Temperatures, and Long-Term Integrity.

By Birgit Vignes, SPE, University of

Stavanger.

SPE 142076 Well-Integrity Analysis

in Gulf of Mexico Wells Using Passive

Ultrasonic Leak-Detection Method.By J.E. Johns, Seawell, et al.

SPE 140255 Development of an

Automated System for the Rapid

Detection of Drilling Anomalies Using

Standpipe and Discharge Pressure.

By Don Reitsma, SPE, @balance-A

Schlumberger Company.

SPE 143101A Proposed Method for

Planning the Best Response to Kicks

Taken During Managed-Pressure-Drilling

Operations. By J.R Smith, SPE, Louisiana

State University, et al.

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85JPT JANUARY 2012

Kick tolerance defines the

appropriate number and settingdepths of casing strings required to

achieve drilling objectives. It also is

used during drilling to determine

whether it is safe to continue drilling or

if there is a need to run a casing string.

Alternatively, it is used to indicate

whether it is safe to circulate a kick

out of the well or whether bullheading

is necessary. During development

of a new well-control system, a

thorough review of the fundamental

concepts involved was carried out,and, in relation to kick tolerance, a few

misconceptions were identified.

Introduction

Even though kick tolerance is a criti-

cal and fundamental concept for the

drilling industry, there is no standard

used by operators, drilling contractors,

or training institutions. Hence, there

are several definitions of kick tolerance

and different ways of calculating it. Thislack of consistency may be why the sub-

ject is not well understood and, there-

fore, is sometimes used dangerously.

Definitions of kick tolerance may be in

terms of pit gain, mud-weight increase,

or underbalance pressure.

Another point of disagreement is

on how the predicted pore pressure

should be used in calculations. Some

companies use a value greater than the

mud weight, while others use a value

greater than the predicted pore pres-sure. Despite the variations, the goal

is consistent: to use a procedure that

ensures safe drilling of a well. Often,

this lack of a standard and of under-

standing the topic leads to uncertaintyand discussions during drilling. Ques-

tions often arise regarding whether

it is safe to continue drilling. Because

wells are now drilled in more-challeng-

ing environments, such as high-pres-

sure/high-temperature and deep and

ultradeep water, a small variation in

the way that kick tolerance is calculated

can lead to premature abandonment of

the well or, worse, to a hazardous drill-

ing situation.

Kick-Tolerance CalculationCurrent ApproachThe first step of a simplified kick-tol-

erance calculation (i.e., constant tem-

perature, constant density, and no com-

pressibility) is to define the maximum

vertical height of a gas influx Hmax at the

casing shoe (assumed to be the weakest

point in the open hole). Hmax is deter-

mined on the basis of fracture gradient;

mud weight; kick-fluid density; predict-

ed pore pressure; and adjusted maxi-mum allowable annular surface pressure

(MAASP), which is reduced by a safety

margin. What is conceptually wrong is

that if the bottomhole-assembly (BHA)

length is greater than Hmax, the kick

cannot be circulated out of the well-

bore because it will reach the top of the

drill collars with a kick height greater

than Hmax, which would induce losses

at the shoe.

Misconception 1:Kick Volume Around the BHATo address this point properly, an

extra calculation must be performed if

the BHA length is greater than Hmax.

Instead, Hmax must be at the top of thedrill collars. Then, calculations must

be made for the volume across the top

of the drill collars and must be taken

to the bottom of the wellbore by use of

Boyles law, in the same way that it is

used with the kick volume calculated at

the casing shoe. Usually, ifHmax is great-

er than the BHA length, the difference in

annular volume compensates the expan-

sion of the gas when it travels upward,

reducing the chances of creating

a problem.

Misconception 2:Safety Margin

The safety margin can lead to an over-

ly conservative solution. This conser-

vative approach can lead to the use of

unnecessary casings and liners in the

well design, especially in deep water.

It has been widely accepted that when

calculating kick tolerance, a safety mar-

gin should be applied to the MAASP to

reduce the chance of inducing fracturesduring a well-control event. MAASP is

calculated on the basis of fracture pres-

sure at the casing shoe (assumed to be

the weakest point in the open hole) and

current mud weight above the casing

shoe. In most cases, the safety margin

comprises three components: choke-

operator error, annular frictional pres-

sure loss, and chokeline frictional pres-

sure loss. Some companies and publi-

cations call for the use of only the first

two terms as safety margin. Althougheach well section is different, many pro-

cedures establish a fixed value for the

safety margin to be used when calculat-

ing kick tolerance. Typical values are

150 or 200 psi. A value of 100 psi is

assumed for the choke-operator error

and the remaining for the frictional-

pressure-loss component. Because the

physical principle and rationale behind

the annular frictional pressure loss and

Kick-Tolerance Misconceptions and

Consequences for Well Design

For a limited time, the complete paper is free to SPE members at www.jptonline.org.

This article, written by Senior Technology Editor Dennis Denney, contains highlights

of paper SPE 140113, Kick-Tolerance Misconceptions and Consequences for Well

Design, by Helio Santos, SPE, Erdem Catak, SPE, and Sandeep Valluri, Safekick,

prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 13

March. The paper has not been peer reviewed.

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chokeline frictional pressure loss are

the same, the effects will be grouped

together. The choke-operator-error

component is addressed separately, to

make sure that each effect is understood

and evaluated independently.

Annular and Chokeline Friction-

al Pressure Loss. When fluid is cir-

culated in a well during a well-controloperation, frictional pressure loss in the

chokeline and annulus will be gener-

ated. The magnitude of the frictional

pressure loss will depend on well geom-

etry and the length and diameter of the

chokeline. In deepwater and slimhole

wells, the frictional-pressure-loss com-

ponent can be significant. To prevent

formation fracturing, the backpressure

applied at surface while the well is static

should be compensated when the fluid-

circulation rate changes. Because it isdifficult to estimate frictional pressure

loss in real time during well-control

events, the adopted approach has been

to subtract the frictional-pressure-loss

value from the MAASP. Even though this

approach reduces the chances of frac-

turing the formation, it imposes large

sacrifices in the well design, leading to

several unnecessary casing strings. The

alternative approach would be to use

this frictional pressure loss proactively

during any fluid circulation; it makes no

difference to the wellbore whether the

pressure at the bottom is coming from a

choke at surface or from friction gener-ated in the wellbore.

Choke-Operator Error. The choke-

operator error is intended to compen-

sate for expected poor manual control of

the choke by the operator. Todays stan-

dard is to use a 100-psi safety factor.

However, automated chokes are readily

available. Automation allows better con-

trol with smaller oscillations in pres-

sure, and it removes issues related to

operator fatigue or error. Automatedchokes have been used reliably in appli-

cations including drilling, well control,

and well cleanup. With improved con-

trol, the 100-psi safety margin can be

reduced to 20 psi or less.

Misconception 3:SimplificationCurrent kick-tolerance calculations are

based on many assumptions and simpli-

fications. The belief is that these simpli-

fications represent the worst-case sce-

nario, thus leading to a safe well design.

Afterflow Effect. Usually, for the sake of

simplicity, the afterflow effect is ignored.Therefore, kick tolerance is considered

equal to the maximum allowable pit gain.

In reality, the formation continues to

flow until the casing pressure increases

enough to equilibrate the bottomhole

pressure to the sandface pressure at the

point of influx. Accordingly, when deter-

mining maximum allowable pit gain,

the additional flow into the well after

shut-in must be considered. This after-

flow volume may be significant, espe-

cially for deep wells with large bores.Some companies use a fixed value (e.g.,

10 bbl). This simplification can lead to

a conservative result. However, compa-

nies not taking this effect into account

may encounter dangerous situations. In

RE

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this paper, formation flow after shut-in

is considered to be equal to the wells

total compressibility.

Temperature Effect. The change in

temperature along the wellbore will

affect the density and the rheology of

the mud, having a direct effect on the

hydrostatic gradient and the frictional

pressure losses during circulation. Cur-rently, it is assumed that the tempera-

ture in the openhole section is constant;

thus, no correction to the volume calcu-

lation is applied. The effects of tempera-

ture on influx volume are described by

Charles law, which states that the vol-

ume of the gas is directly proportional

to the absolute temperature. Contrary

to the afterflow effect, the temperature

correction results in a higher kick toler-

ance. Therefore, the conventional con-

stant-temperature assumption results ina conservative solution.

z-Factor Correction. z-factor (com-

pressibility factor) enables use of ideal-

gas equations to model real-gas behav-

ior. Because calculating the z-factor is

not straightforward, the industry has

assumed a constant z-factor equal to 1.0

when performing gas-behavior calcula-

tions. In this paper, a 0.6-SG hydrocar-

bon gas is assumed as the influx fluid.

The pseudocritical properties were cal-

culated using Katzs correlations. Then,

the z-factor was calculated by use of

Dranchuk and Abou-Kassem correla-tions combined with the Newton-Raph-

son iterative method. z-factors were cal-

culated for conditions along the open

hole and were used in the bottomhole

kick-volume calculations through the

real-gas law.

Influx-Density Correction. Kick-fluid

density was assumed to be 1.9 lbm/gal

and constant along the openhole sec-

tion. Once the z-factor was calculated,

the influx density was estimated. Using0.6 SG for hydrocarbon gas and the

pressure, temperature, and z-factor for

the point of interest (i.e., casing shoe

and bottomhole conditions), volumes at

the bottom of the well were calculated.

Influx density had a direct effect in the

kick-tolerance calculation.

Combined Correction

Effects on Kick Tolerance

Because some effects increase the kick

tolerance while others reduce it, it is

important to combine all the effects to

identify the overall effect on kick toler-

ance. The consequences are not consis-tent, illustrating why it is important to

take all effects into account. It has been

argued that the overall conservative

nature of the single-bubble model will

eliminate any detrimental effect pro-

duced by simplifications. Because the

magnitude of each simplification and

conceptual error is different, the change

of the final result cannot be predicted. If

it is clear that a conservative approach

is being used, the consequences might

be only economical, with the end resultbeing an overengineered well. Howev-

er, when the scenario leads to increased

risk, as is the case with calculating the

kick volume on bottom, this simplifica-

tion should not be acceptable. JPT

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C

losing the wellbore at the top with

a rotating control device (RCD)for some kind of managed-pressure-

drilling (MPD) operations raises a

number of issues with regard to well

control and kick detection. The use

of an RCD provides drillers with an

additional level of comfort because it is

a pressure-management device, but it

does not eliminate the need to have well

control as a primary objective. Early

kick detection and annular-pressure

control are essential parts of MPD

operations, but there can be confusionas to where the responsibility for well

control lies.

Introduction

The detection of inflow from a forma-

tion is one of the primary safety aspects

of drilling operations. Even with a closed

wellbore and with the use of MPD tech-

nology, kick detection and the subse-

quent well-control procedures must

remain in place. The rig crew can get afalse sense of security that with MPD,

the well is controlled at all times and as

such there is no further need for well con-

trol. The causes of kicks are not removed

when MPD operations are being con-

ducted. The procedures and risk assess-

ments for MPD operations must include

kick-detection and well-control methods

and procedures.

Primary Well Control

Controlling the annular-pressure profileis one of the main reasons for MPD, but

it may not avoid kicks in a well. If the

pore pressures of the formations being

drilled are unknown, then kicks can still

be taken. This leads to the next challenge:To contain an influx safely, the influx

first must be detected. If MPD is used to

control the bottomhole pressure (BHP)

in the well, then it can be stated that

MPD is the primary well control because

the pressure in the well is controlled to

avoid an influx of formation fluids into

the wellbore.

The use of an RCD to close in the

wellbore makes drilling operations safer.

However, it must be noted that, often,

the objectives of MPD are to reduce thehydrostatic pressure, avoid losses, and

drill the well with a lower mud weight.

Reducing the mud weight can introduce

more well-control events.

MPD OperationsFig. 1 diagrams the MPD flow process.

The RCD is installed on top of the annu-

lar preventer and closes the wellbore

around the drillpipe. The outlet from

the RCD is split between the main return

flowline and the MPD choke manifold.The MPD manifold is installed in parallel

with the rigs main flowline and in paral-

lel with the rigs conventional rig choke

manifold. This setup allows convention-

al circulation and circulation through

the MPD manifold. Backpressure can be

applied to the well at any time by use of

the MPD manifold. Any gas being cir-

culated out through the MPD manifold

can be vented safely through the mud/

gas separator. If the surface pressure

exceeds the RCD pressure ratings, theentire well-control setup can be switched

quickly to standard drilling well-control

equipment. During tripping operations,

circulation with the trip tank can be per-

formed through the MPD manifold orthrough the existing flowline.

When MPD equipment is used, it

is important that the secondary well-

control equipment, such as blowout pre-

venter (BOP) and rig choke manifolds,

remain ready for operations. The sec-

ondary well-control equipment should

not be used for routine drilling opera-

tions during the MPD operations.

Causes of Kicks

A kick is defined as any influx that con-stitutes a well-control emergency. Nor-

mally, this means use of the BOP to shut

in the well and, subsequently, removing

the influx by use of a choke on the annu-

lus to maintain sufficient backpressure

to prevent further entry. In MPD, the

well-control emergency may not apply

because the system is already set up for

this occurrence.

The pressure in the wellbore can be

controlled with surface pressure, but if

the formation pressure is greater thanthe pressure in the wellbore and a forma-

tion is permeable, then the well will kick.

Loss of primary well control usually is

caused by the following.

Insufficient drilling-fluid density

(insufficient BHP)

Failure to keep the hole full while

tripping

Swabbing while tripping

Lost circulation

Kick DetectionDetecting a kick early and limiting its vol-

ume by shutting in the well are critical to

secondary well control, and they could

mean the difference between a manage-

able situation and one that leads to loss of

control. Immediately following an influx,

the BHP in the annulus is reduced to

some extent by the influx and by the

added lift energy given by the formation-

fluid flow. This effect leads to a decrease

Kick Detection and Well Control

in a Closed Wellbore

For a limited time, the complete paper is free to SPE members at www.jptonline.org.

This article, written by Senior Technology Editor Dennis Denney, contains highlights

of paper SPE 143099, Kick Detection and Well Control in a Closed Wellbore, bySteve

Nas, SPE, Weatherford, prepared for the 2011 IADC/SPE Managed Pressure Drilling

and Underbalanced Operations Conference and Exhibition, Denver, 56 April. The

paper has not been peer reviewed.

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0 JPT JANUARY 2012

in pump pressure, but this change is verydifficult to detect until relatively late in

the flow.

The flow into and out of the well is

in a steady-state condition during normal

circulation. A kick violates this balance,

and the return flow out of the well will

increase if a kick is taken. Following this

flow increase, there also is an increase in

the surface volume as formation fluid is

added to the circulation process.

Kick Detection inClosed WellboresClosing in the wellbore with an RCD,

in principle, does not change the phys-

ics of kick detection. Although the level

in the well is not visible, the increase in

return-flow rate and increases in pit lev-

els remain the most-reliable indicators

of a kick. The use of mass-flow meters

in combination with accurate standpipe-

pressure sensors enables use of an auto-

mated kick-detection system on some

MPD systems. This system works duringdrilling conditions, but when tripping or

making connections, the flow out of the

well often is the only reliable indicator of

a well-control issue.

Early Kick DetectionIt is possible to calibrate the flow into

the well from the pump strokes and then

measure the flow out of the well with

a Coriolis meter. A software program

allows the flow in and the flow out to be

calibrated inside the casing before drill-

ing a new formation. Once calibrated, thevariation between the flow in and flow

out can be displayed and alarmed on the

rig floor, making a highly accurate flow-

rate-detection system.

BallooningBorehole ballooning or breathing, or

loss/gain, is the result of slow mud loss-

es while drilling ahead followed by mud

returns after the pumps have been turned

off, such as during a connection or flow

check. Usually, any flow during theseperiods is cause for concern because it

may be caused by an influx of formation

water, liquid hydrocarbons, or gas. Any

influx from the formation can result in

a well-control problem, the magnitude

of which depends on the influx volume

and composition. However, if the flow is

the result of mud returns, well control is

not an issue.

To be safe, the suspected influx can

be circulated out using the choke, but this

method is time consuming and wasteful,particularly if the influx is only return-

ing mud. The normal cure is to increase

the mud weight and ensure an adequate

overbalance in the absence of circulation.

If the mud weight is increased and the

influx is only mud, the situation will get

progressively worse with a rise in mud

weight and, therefore, the equivalent cir-

culating density (ECD). Mud losses will

continue, and, eventually, the fracture-

propagation pressure will be exceeded,

resulting in total losses.

The use of accurate flowmetershelps determine whether the increased

flow is an influx or returning mud. Soon

after the pumps are shut down, the flow

out of the well can be observed. If the

flow declines, ballooning is occurring.

When the pumps are started again, the

flowmeter will show that the flow out

of the well lags behind the flow into the

well, which is another indication of bal-

looning. The accurate measurement of

flow into and out of the well allows kick

detection and detection of losses andballooning of a wellbore, but a kick can

still be taken if attention is not paid.

Handling a KickWell control can be described as main-

taining BHP within a window having

upper and lower pressure limits. On the

low side, the margin normally is bound-

ed by pore pressure and wellbore stabil-

ity, whereas on the high side, it can be

bounded by differential sticking, lost cir-

culation, and fracture pressure. A kick isdetected in a closed wellbore by use of

the mass-flow meter. With an MPD sys-

tem installed, there are two choices to

circulate out the influx.

With MPD Equipment. The MPD choke

manifold makes it possible to contin-

ue circulating, increase the backpressure

on the well until the flow in and flow

out are balanced, and then circulate out

the influx using the drillers method.

This procedure will work if the forma-

Fig. 1MPD-process flow diagram.

Mud/Gas

Separator

Trip-TankFillup

BleedoffValve

Main Flowline

Gas to vent

ShaleShakers

Trip

Tank

Trip-TankPump

MPD Choke ManifoldWith Coriolis Meter

Rig ChokeManifold

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2 JPT JANUARY 2012

tion pressure can be obtained accurately.

Once a kick is taken, the formation pres-

sure must be determined to establish

the proper kill-mud weight. The forma-

tion pressure can still be determined, but

with full circulation this must take into

account the ECD and the BHP must be

used. Without an accurate pressure mea-

surement through a pressure-while-drill-

ing (PWD) tool, this may not be possible.The backpressure and ECD calcula-

tions or measurement can provide the

formation pressure. Accuracy of this

measurement may depend on readings

from the PWD tool. The flowmeter will

provide an indication of the size of the

influx and can be checked with the pit

levels, provided that this kick is large

enough to be seen.

One issue that must be considered

is the potential surface pressure while

circulating the kick out because the RCDpressure limits will need to be known

and cannot be exceeded. Kick model-

ing must be conducted to establish the

kick intensity and kick volumes that can

be handled.

With Rig Equipment. If a kick is detect-

ed, conventional well-control proce-

dures can be used as follows.

1. Pull up and space out the drill-

string.

2. Stop the pumps.

3. Close the BOP.

4. Record the shut-in drillpipe pres-

sure and the shut-in casing pressure.

The shut-in drillpipe pressure willprovide the level of underbalance (for-

mation pressure), while the shut-in cas-

ing pressure will give an indication of the

kick size and density. The pit levels can

be measured to confirm the influx.

Kick Volume and Intensity. The kick

volume is the volume of formation fluid

that entered the wellbore. The volume

gained at surface will provide an indi-

cation of this volume. The kick intensi-

ty is defined as the pressure differencebetween the hydrostatic pressure in the

well and the formation pressure.

With these two parameters, the deci-

sion can be made whether to handle the

kick with the MPD system or to close the

BOP and use the rigs choke manifold to

circulate the kick out of the hole. This

decision is driven by the expected surface

pressures and by the pressure ratings of

the equipment.

Generally, a kick with volume of

5 bbl or less and kick intensity less than

1-lbm/gal equivalent mud weight can be

circulated out of the hole using the RCD

and the MPD choke manifold. If BHPs arehigh, as in the case of high-pressure/high-

temperature wells, then the values should

be reviewed on a case-by-case basis.

Switching From MPD to Convention-

al Well Control. Once a kick is taken

and controlled using an MPD system,

it becomes important that the driller

and the MPD operator coordinate their

actions if the surface pressures rise and

indicate that the kick should now be

controlled by the BOP system. Switch-ing from the MPD system to the rigs

BOP and choke manifold must be accom-

plished in a controlled manner.

Standard well-control preparations

in the form of kick sheets, slow circula-

68 March 2012

San Diego, California, USA

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93JPT JANUARY 2012

tion rates, and pressures must be contin-

ued by the rig crew, as in all drilling oper-

ations. Although a well is drilled with

MPD techniques and can be controlled

with the MPD system, the driller must be

able to take over at any time in the well-

control process.

It has been seen in several MPD

operations that well-control prepara-

tions by the drill crew were not beingperformed because the crew relied on the

MPD provider to conduct well-control

operations. Upon entering a well-control

circulation and the system needing to be

switched to lower pump rates and a dif-

ferent pressure, this lack of preparation

can cause significant issues during the

well-control operations.

MPD Operatorsand Well Control

If the detected influx is small and has alow kick intensity, it is possible to circu-

late the kick out using the MPD equip-

ment. The drillers method normally is

used for this, and the MPD operator must

hold the drillpipe pressure constant while

the driller circulates the kick out. Once

the influx reaches the surface equipment,

the MPD operator must divert any gas

away from the main flowline to a suitable

mud/gas separator.

This process assumes that all MPD

operators have the experience andunderstanding required for well-control

operations. Before any MPD operations

are conducted, it must be verified that

all MPD personnel operating the choke

understand the procedures and actions

required when a kick is detected. The

MPD operator must understand the well-

control situation fully. Both the MPD

operator and the driller must maintain

a close watch on the surface pressures to

ensure that these remain within the lim-

its of the equipment being used.Advantages of using the MPD equip-

ment for well control include that the

pipe can be moved up and down and

can be rotated and that stuck-pipe inci-

dents, often associated with well-control

operations, can be avoided. If something

goes wrong at any time during an MPD

well-control situation, the driller must

be able to stop the pumps and shut in

the well using the BOPs and then contin-

ue the well-kill operation using the rigs

choke manifold. JPT

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4 JPT JANUARY 2012

Standard well-control training that

drillers receive prepares themto respond to an influx that occurs

during underbalanced conditions. The

mechanism by which hydrocarbons

may enter the wellbore following a

vugular loss can be different. One

potential result is that the influx

may not be detected as early as

during conventional underbalanced

conditions. A model was developed to

explain the unique mechanism by which

kicks may occur following vugular

losses. Effective recognition andresponse practices are proposed that

are consistent with that model.

IntroductionWhen massive losses occur in vugular

formations, the wells behavior does not

follow a conventional well-control sce-

nario. Gains in pit volumes are not seen

despite hydrocarbon entry, and kicks

can go undetected until they have trav-

eled some distance up the annulus. Oncethe kick is detected, backpressure can-

not be held effectively to prevent further

influx while circulating the initial kick

out and the annulus-pressure trends and

values appear to be unpredictable. It

also is difficult to control the placement

of fluids or pills. The most significant

challenge is the inability to detect an

influx as soon as it occurs. In deepwa-

ter wells, the distance from the vugu-

lar zone to the subsea blowout preven-

ters (BOPs) may be short, as shown inFig. 1.

Operators are aware of these behav-

iors, and the industry has developed

unique practices for drilling vugular car-

bonates safely. Rigs having surface BOPs

address the risks by use of a rotatingcontrol device (RCD). RCDs have been

used in a similar fashion at the surface

on marine risers with subsea BOPs. The

RCD has been installed at the top of the

riser above the slip joint, and a tension-

ring system is under development that

will enable the RCD to be placed below

the slip joint. In subsea applications, the

pressure that can be applied below the

RCD is more limited than on land loca-

tions, usually to the rating of the slip

joint or marine riser. In some cases, therating is adequate for the given well. In

other situations, the pressure limita-

tions of the riser system or RCD may not

provide the robust capability needed.

Attributes of Vugular LossesThe unique behaviors observed duringmassive vugular losses are associated

with the bottomhole pressure (BHP)

falling instantly to equal the pore pres-

sure in the vug. It is widely believed that

the practice of filling the back side con-

tinuously prevents this drop in BHP and

that an influx does not occur unless the

fill rate is inadequate and the fluid level

is allowed to fall sufficiently to under-

balance the zone. Actually, the degree

to which the BHP falls is more a func-tion of the rate at which the loss zone

can take the fluid than of the fill rate. In

severe vugular losses, filling the annu-

lus is not effective and the BHP will fall

to equal the vugular pore pressure. As

the vug size or density decreases, there

is a point at which the fill rate will cre-

ate some backpressure within the vugs

at the face of the borehole, and the

BHP will increase by the amount of this

Kick Mechanisms and Well-Control

Practices in Deepwater Vugular Carbonate

Because the conference was rescheduled, the complete paper will be free toSPE members at www.jptonline.org during March and April 2012.

This article, written by Senior Technology Editor Dennis Denney, contains highlights

of paper IPTC 14423, Kick Mechanisms and Unique Well-Control Practices in

Vugular Deepwater Carbonates, by F.E. Dupriest, SPE, ExxonMobil, prepared for

the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 1517

November. The paper has not been peer reviewed. [Note: Conference rescheduled to

79 February 2012.] Copyright 2011 International Petroleum Technology Conference.

Reproduced by permission.

Fig. 1The reaction time available to shut in following an influx in

deepwater wells is significantly less than with surface BOPs.

Well-control

equipment

Practices addressreduced reaction timePractices addressreduced reaction time

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95JPT JANUARY 2012

backpressure. Consequently, the BHP is

almost entirely a function of the vugu-

lar conductivity rather than the annu-

lus fill rate.

When complete losses occur and

the annulus level drops quickly, the vugs

are likely to be large; therefore, filling

the annulus continuously may not pre-

vent the BHP from falling. The observed

kicks are not the result of allowingthe annulus fluid level to fall; they are

caused by the well becoming under-

balanced because of the drop in BHP,

which allows flow from another loca-

tion. However, field observations and

pressure-while-drilling data show that

the influx may initiate immediately with

the loss in very vugular formations. The

key question that cannot be answered

with conventional thinking is, If the

mud weight is overbalanced and flow-

ing into the vugs, how can gas be flowingout of the same vugs?

It is still good practice to fill the

annulus continuously until a diagnos-

tic pill of large lost-circulation mate-

rial (LCM) can be pumped because this

ensures that the influx travels down to

the loss zone rather than up the annu-

lus, but it does not prevent the influx

from occurring or continuing to occur

while filling. If the pore throats are in

the range of 150 to 3000 m, LCM may

be effective, in which case the losseswill stop, the BHP will increase above

the formation pressure, and the influx

will stop. If the pore throats are larg-

er, continuous fill is used to control the

gas level in the annulus until cementing

or other operations can be executed to

stop the loss.

Interzonal Flow Cell

Wells that drill carbonates containing

hydrocarbon usually are designed to

have casing set in a competent imper-meable formation just above the carbon-

ate. If the carbonate is drilled without

losses, or with only low seepage losses, a

filter cake forms and overbalance exists

across the open hole. When a vugu-

lar opening is encountered, complete

losses occur and the BHP falls to equal

the pore pressure. Although the annulus

will continue to be filled, this procedure

does not prevent the BHP from falling

to equal the pore pressure in the vugu-

lar interval on bottom. The pressure at

any point in the wellbore above the loss

zone is then equal to the BHP minus the

fluid head.

While the greatest underbalance

will be at the top of the carbonate, the

entire borehole will be underbalanced

by some amount as long as there is mud

in the wellbore across the carbonate. If

the annulus fill is stopped, the hydro-

carbon will continue to flow into thewellbore and displace mud downward

between the top and the loss zone until

the annulus across the interval is con-

verted entirely to hydrocarbon. At that

point, there is no differential between

the pressure at any point in the well-

bore and that in the adjacent forma-

tion. Because the pressure at all depths

is equal, the influx will stop. This is

referred to as a flow cell because the

process tends to drive itself. As mud

swaps and moves downward across thecarbonate, the flow cell again becomes

unbalanced and additional influx

occurs. As the swapped gas moves up

the annulus, its expansion will lighten

the head and a gain in pit volumes even-

tually will be observed.

The most important operation-

al implication of the flow cell is that

an influx can occur with no gain in

the pits. When an influx occurs, the

rig crew should observe a sudden loss

of all returns. Consequently, the workprocess should be to close the BOPs

in response to any complete loss of

returns. While a sudden complete loss

will not always result in an influx, it is

an indication that the opportunity for

one exists.

The argument can be made that the

BOPs should be closed following any

major loss, even one that is not com-

plete. In theory, an influx should not

occur if partial returns are maintained

because getting continued returnsimplies that the BHP must be adequate

to lift the head of the drill-weight mud.

In practice, however, the loss may be

temporary because continued pump-

ing will move the gas up the annulus,

which lightens the head quickly and

may allow full circulation. The conser-

vative practice is to shut in on any major

loss, observe the chokeline pressure to

determine whether gas is migrating,

and, if possible, circulate out through

the chokeline to reach bottoms up.

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6 JPT JANUARY 2012

The reason for being conservative is

that if circulation continues through the

open stack following what is believed to

be a partial-loss event and an influx

has actually occurred, then a pit-vol-

ume increase may not be seen until the

gas reaches a depth at which expan-

sion occurs, or until the gas comes

out of solution if using a nonaqueous

fluid (NAF).

Swap ManagementThe industry is trained to manage kicks

by circulating through a choke and

applying sufficient backpressure for

the pressure in the annulus to become

overbalanced to the flowing zone. This

method is ineffective with a vugular loss

because the BHP will remain equal to

the pore pressure in the vugs regardless

of the backpressure observed at sur-

face. In addition, if losses are complete,there is no flow and pressure cannot

be applied. The influx can be stopped

permanently only by plugging the loss

zone to stop the flow cell. The common

practice of filling the annulus continu-

ously, which has been learned empiri-

cally, is a correct one. But filling the

annulus does not stop the flow. Actu-

ally, continuous introduction of heavy

mud across the carbonate ensures that

the imbalance that drives the flow cell

is maintained and that the influx will

continue to occur. Because there is no

operational technique to allow the BHP

to be elevated above the pore pressurein the exposed vugs, and the mud that

is pumped to fill the annulus drives even

more influx, the kick response should

be first to determine the fill rate that

exceeds the swap rate and then to main-

tain this fill rate until the vugular zone

can be plugged. This method is referred

to as swap management. It does not

stop the influx, but it does allow the

annulus pressure to be controlled at the

desired level during treatments or while

drilling ahead.

Slide Drilling Witha Straight MotorSlide drilling with no rotation through

a closed subsea annular preventer with

a straight motor enables the driller to

continue to make progress during com-

plete losses. Because the annular pre-

venter is closed at all times, gas can-

not enter the riser. A sacrificial fluid,

such as seawater, is used to drill. Double

floats are installedone plunger and

one flapper type. Kill-weight mud con-

tinues to be pumped down the annu-

lus at the swap-management rate estab-lished in the process described in the

preceding section.

At a minimum, slide drilling con-

tinues until the local vugular system

is believed to have been fully exposed.

Although it varies, the general experi-

ence has been that highly vugular inter-

vals tend to extend for only short dis-

tances. When the bit is believed to have

re-entered pore throats that can be

plugged with LCM or barite, a decision

may be made to treat the major vugularzone above so that conventional drilling

is possible until the next highly vugular

network is penetrated.

There are several important con-

siderations when planning to slide drill

through a closed annular preventer.

The annular-preventer manufacturer

should be consulted on the planned

interval and the number of tool joints

that will pass through the upper annu-

lar preventer. These practices are based

on proprietary stripping tests with spe-cific equipment, and not all preven-

ters may be equally capable. The annu-

lus injection fluid used in deepwater

wells should be designed to prevent

hydrate formation during unexpected

upset conditions, and the drillstring

should be displaced to an inhibitive

fluid when needed.

Treating Vugular LossesAwareness of the flow cell has changed

some elements in the treatment strat-egy. There are two primary challenges

in treating a vugular zone. The first is to

avoid overdisplacement. The resistance

to flow in a vugular opening is, essen-

tially, only the pore pressure in the vug.

Because drill-weight mud is designed to

be overbalanced, any treatment that is

displaced with drill-weight mud is likely

to be overdisplaced. This operator has

developed a family of practices that use

hydrostatic packers to prevent this over-

displacement. A hydrostatic packer is a

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The School of Mechanical & Aerospace Engineering at Oklahoma State University(OSU) invites applications for an endowed faculty position in Petroleum Engineering,with an emphasis on Drilling and Production. This position is supportive of a newinterdisciplinary initiative within the College of Engineering, Architecture and

Technology. Substantial increases in faculty and resources are planned. Participants inthe initiative will include faculty members from Chemical Engineering, ElectricalEngineering, Mechanical Engineering and other disciplines, who wish to contribute toaddressing the manpower and technology development needs of the petroleum andenergy industries. At the undergraduate level the participants will be responsible for anew interdisciplinary Petroleum Engineering Minor, designed to prepare Chemical,Electrical and Mechanical Engineering graduates for the Petroleum Industry. Thesuccessful applicant will join an interdisciplinary team to develop and implementundergraduate and graduate coursework and research in Petroleum Engineering. Thesuccessful candidate must have a high potential for excellent teaching at theundergraduate and graduate levels and for developing a strong, externally fundedresearch program. An earned doctorate in engineering or a closely related field isdesired. Substantial engineering and/or research experience in industry, government oracademia is desired. The successful applicant will be appointed at a professorial rankconsistent with experience and accomplishments. Salary and other compensation willbe commensurate with achievements. Each applicant should provide a letter of

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column of light fluid pumped at the end

of displacement to make the total col-

umn underbalanced to the integrity so

that when pumping is stopped, the fluid

cannot continue to travel downward.

In the case of vugular carbonates, the

integrity pushing back to support the

column is, effectively, the pore pressure

in the vug, so the hydrostatic packer

must be designed to lighten the columnsufficiently to place it underbalanced to

pore pressure to prevent overdisplace-

ment. Therefore, there will be positive

pressure on the drillstring at the end of

displacement. By use of surface BOPs, it

is necessary to preinstall this light col-

umn in the annulus to place it underbal-

anced to the pore pressure and achieve

a positive surface pressure to prevent

the fluid from moving downward to con-

taminate the treatment during the oper-

ation. In subsea wells, it is possible toclose the choke- and kill-line valves to

remove the fluid head from the annu-

lus so that it is necessary to use a packer

only inside the drillstring.

The new issue raised by the aware-

ness of the flow cell is that even if prop-

er steps are taken to prevent overdis-

placement with drill-weight mud, the

flow cell itself may displace the mate-

rial to the loss zone. When pumping

stops, the influx and downward dis-

placement occur whether the fluid inthe wellbore is drilling fluid, cement,

or some other mobile material. Even

when overdisplacement has been pre-

vented with hydrostatic packers, a gap

or poor-quality cement has sometimes

been found from the top of the car-

bonate downward to the loss zone as a

result of displacement by the flow cell.

Also, as soon as hydrocarbon begins to

enter the wellbore, it starts to swap with

the fluid above, and this swapped mate-

rial is displaced downward to the losszone. By monitoring the stack gauge, the

volume that has been swapped upward

can be calculated from the rise in pres-

sure, which reflects the height of cement

or other treatment fluid that has been

replaced by the light hydrocarbon. The

rate of change in the annulus pressure

also reflects the rate of change in the

swap rate, which is a useful surveillance

diagnostic in predicting the likely effec-

tiveness of the treatment. Treatments

with stable pressure, indicating that no

swapping is occurring, have been uni-

formly effective.

Tripping Out of HoleThe swap-management practices may

be used while tripping. The annular pre-

venter is kept closed, and the string

is stripped out until the bottomholeassembly (BHA) arrives at the BOP. The

swap rate typically is higher after the

string is removed because there is more

clearance in open hole or casing than

in the small annulus around the string.

The chokeline gauge at the stack is mon-

itored as the string is pulled. Any rise in

stack pressure is an indication that the

fluid level in the chokeline has risen.

Because the BHP is constant and equal

to the vugular pore pressure, any rise in

the fluid level in the chokeline must bethe result of an increase in the volume

of lighter hydrocarbon in the column

and an indication that the hydrocarbon-

swap rate has begun to exceed the fill

rate. If this situation is observed, the fill

rate is increased until a stable pressure

is achieved, indicating that the fill rate

is adequate. In most cases, a pattern is

observed quickly and the rig team estab-

lishes drilling-fill and tripping-fill rates

that differ. When the BHA arrives at the

BOP, steps are taken to clear any trappedgas in the stack before opening the stack

temporarily to pull the BHA through.

The annulus fill continues throughout

the process. The process is reversed to

trip in the hole.

If the swap rate is not high, it

can be controlled further by position-

ing fluid with high gel strength above

the top of the carbonate. With water-

based mud and favorable conditions,

a high-gel-strength pill can reduce the

swap rate to less than 0.1 bbl/min with17-lbm/gal mud positioned above gas

in underground flow. In contrast, it is

difficult to build gel strength in NAF

pills, and the swap rate generally is high

enough that it is not practical to hold

a pill in position for the time required

to trip. Crosslinked polymers and

other materials have been considered

to reduce the swap rate and resultant

fill rates. JPT