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MAERSK TRAINING CENTRE A/SDOCUMENT ID

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Well Control Training ManualPREPARED BY

JOACHAPTER

00PAGE

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M:\IWCF Surface\3\1\Section 5.doc © MTC

MAERSK TRAINING CENTREDrilling Section

Copyright © Maersk Training Centre a/s.

All rights reserved. No part of this publication may be reproduced, stored in or introduced into a retrievalsystem, or transmitted, in any form, or by any means (electronic, mechanical, photocopying, recording or

otherwise) without the prior written permission of Maersk Training Centre a/s.

Well Control

Training Manual

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Table of content:

01 Pressure in the earth crust Page 00701.01 Sedimentation02.01 Compression03.01 Pressure04.01 Pressure in fluids05.01 Pressure gradient06.01 Abnormal/subnormal pressure

02 Pressure balance in the well bore Page 019

01.02 Pressure balance02.02 Overbalance and underbalance03.02 Lost circulation04.02 Rate of penetration versus overbalance05.02 Drilling break06.02 Necessary overbalance07.02 Trip margin08.02 Riser margin09.02 Relationship10.02 Equivalent drilling fluid density

03 Dynamic pressure regime when circulating Page 02801.03 Circulation of drilling fluid02.03 Dynamic pressure in the well bore

04 Consideration with a closed in well Page 03301.04 Closed in well02.04 U-tube

05 Properties of gasses and gas laws Page 03601.05 Drilling with underbalance

02.05 Properties of gas and gas laws03.05 Expansion of gas04.05 Formation strength05.05 Leak-off test06.05 Maximum allowable annular surface pressure

06 Drilling fluid volume and capacities Page 04401.06 Calculating drilling fluid volume – capacities02.06 Drilling fluid volume and capacities from tables03.06 Surface to bit strokes & bit to surface strokes04.06 Use of barite to increase drilling fluid volume

05.06 Volume increase due to barite addition

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07 Wellbore kicks Page 053

01.07 Kick occurrences02.07 Warning signals03.07 Warning signals while drilling04.07 Warning signals while tripping or making connection05.07 Procedure for shutting in the well06.07 Pressure after shut in

08 Circulating a kick out of the well bore Page 06901.08 General points02.08 Circulating out an influx using Driller’s Method03.08 Wait and Weight Method or Engineer’s Method

04.08 The Concurrent Method05.08 Advantages and disadvantages of the three methods06.08 Pressure control schemes

09 Calculations of density and pressure gradient of an influx Page 09401.09 General points02.09 Example

10 Lost circulation Page 09701.10 General02.10 Causes of lost circulation03.10 Well control with partly lost circulation04.10 Well control with total lost circulation

11 Volumetric wellcontrol and other Page 10201.11 General02.11 Volumetric Method – Specification required03.11 Volumetric Method – Handling04.11 Lubrication Technique05.11 Volumetric Method – Example06.11 Low Choke Method – Dynamic Kill

07.11 Bullheading

12 Kick with bit off bottom Page 11301.12 Introduction02.12 Stripping03.12 Closing Procedures04.12 Rig layout for combined stripping and volumetric method05.12 Procedure06.12 Snubbing

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13 Gas cut drilling fluid Page 119

01.13 General02.13 Causes of gas cut drilling fluid03.13 Gas kicks in Oil Based Mud04.13 Influx volume

14 Deviated and Horizontal well control Page 12601.14 Introduction02.14 Complications03.14 Horizontal well control example04.14 Wait and Weight Method05.14 Driller’s Method

06.14 Horizontal well kill method

15 Pulling Pipe Page 13801.15 Introduction02.15 Pumping slug03.15 Inadequate hole fill04.15 Hole not taking correct amount of fluid05.15 Hole not giving correct amount of fluid

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Abbreviations:

A AreaAtm AtmosphereBHA Bottom hole assemblyBHP Bottom hole pressureBOP Blow out preventer Cap CapacityDC Drill collar DP Drill pipeEDC Equivalent circulating density

EFD Equivalent formation densityEOB End of buildFCP Final circulating pressureFOSV Full opening safety valveFt FeetG Pressure gradient psi/ftGal GallonsGMD Gas migration distanceGMR Gas migration rateGPM Gallons per minuteHCR High closing ratioHPHT High Pressure/High TemperatureH2S Hydrogen sulfideICP Initial circulating pressureID Inside diameter KMW Kill mud weightKOP Kick off pointLb PoundsLbs/ft Pounds per feetLOT Leak off testMAASP Maximum allowable annular surface pressure

MD Measured depthMW Mud weightMWF Final mud weightOBM Oil base mudOD Outside diameter OH Open holeOMW Original mud weightP PressurePA Pressure annulusPc Pressure dynamicPDP Pressure drill pipe

Pf Pressure formation (pore pressure)Ph Pressure hydrostaticPL Pressure lossPPG Pound per gallon

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PPM Part per million

PSI Pound per inch²PWD Pressure while drillingROP Rate of penetrationRPM Rotation per minuteRRCP Reduced rate circulating pressureSF Safety factor SICP Shut in casing pressureSIDPP Shut in drill pipe pressureSPM Strokes per minuteSX SacksT Temperature

TVD True vertical depthV VolumeWBM Water base mudWOB Weight on bit

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01 PRESSURE IN THE EARTHS CRUST

01.01 Sedimentation:

The theory behind the pressure being present in the different depths in the earth rockformations are based on the historic development during millions of years where settling of particles has taken place in the ocean.

Large and small rock particles are transported by rivers and streams, ice and wind anddeposited on the seabed offshore. In the sea several different chemical substances arepresent which also separates from the water and sink to the seabed. Amongst otherscarbonates, sulphates and chlorides are known to be dissolved in the seawater. Small

organisms which live in the sea has a life cyclus and when they die their solid remains alsosink to the seabed.

When this process continues during millions of years the layers of settling will obtain aconsiderable thickness on the sea floor.

02.01 Compression:

The rock particles and solid matter will eventually become more and more compacted asthey bear more and more weight from the overlaying deposits. As this process continues thewater that is found between the rock particles will usually escape. However there will usuallybe small cavities left between the particles, which contain the remaining water. These cavitiesor void spaces make the rock formations more or less porous. A porous formation cancontain fluids, gas or hydrocarbons.

As compression and compaction continue during time, combined with thermal and chemicalprocesses the unconsolidated particles will eventually become rock formations within theearth crust.

These sedimentary rock formations are generally porous, and the pores are filled with a fluidor gas.

Fig 01

SHALE

SANDSTONE

SALT

Porous/

impermeable

Porous/

permeable

Tight and

without pores

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If communication between the cavities or pores in the formation is present this allows the fluidto flow away and escape. Under certain conditions the formation fluid can become trapped. If a porous fluid-bearing formation becomes covered with an impermeable layer of rock such asa clay stone, the fluid becomes trapped.

03.01 Pressure

Before describing the conditions in which the formation fluids are found at different depths inthe rock formations the terms mass, density, force, energy and pressure will beconsidered.

Mass

Mass is defined as the term for a quantity of matter. The unit of measurement that is used isthe pound.

Density

Density is an expression giving the mass of gas, fluid or solid matter in relationship to itsvolume, E.I. mass per unit volume. Other means to express density is the term relativedensity. By relative density is understood, the mass of a particular volume of substance

divided by the mass of an equal volume of fresh water. Due to the definition of the relativedensity it remains dimensionless.

In this lecture mass in pounds, and volume in gallons is used, therefore the density is given inpounds per gallon (ppg).

Force

When a mass hangs by a string, a force will keep the string in tension. The product of gravitational acceleration and the mass causes the force itself.

Fig 02

Mass

Power

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This force can be measured by a dynamometer, Fig. 03. This instrument consists of a spring.

One end is fixed and the other end shows on a scale how much gravity force is exerted.

Fig 03

Force is expressed in the unit pounds-force, which is defined as follows.

One pound-force is the force, which will influence a body with a one pound mass whensubjected to a gravitational acceleration of 9.80665 m/s2.The gravitational acceleration of 9.80665 m/s2 is present at latitude 45° North on the earth'sglobe. Gravitational acceleration differs in various parts of the globe. This means that onepound-force is not an equal value everywhere on the globe.

As an example the gravitational acceleration at the North Pole is equal to 9.831 m/s2, whichgives a force influence on a mass of one pound according to the following -

G = 1 x9,831

9,80665 = 1.0025 [ pounds ]

At the equator the gravitational acceleration = 9,781 m/s2

The force influence on one pound mass becomes

G = 1 x9,781

9,80665 = 0,9974 [ pounds ]

In practice this variation in gravitational acceleration is ignored and a one pound mass isconsidered to exert a one pound-force influence.

Pointer

Scale

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Pressure

Pressure is defined in physics as force per area unit.

Pressure = Force

Area unit

The total force, which acts on a plane, is divided by the area of the plane. The result is calledpressure.

The unit for force is pounds-force and the unit for area is square inch. Therefore the unit for pressure will be:

Pressure = Pounds

Square inch [pounds per square inch ]

M = 1 pound G = 1 pound ( 45° latitude North )

g = 9,80665 m/s2

A = 1 inch2

Pressure (P) = P xG

A =

1

1 = 1

Fig 04

04.01 Pressure in fluids

Considering a vertical cylindrical volume of static fresh water with a cross-sectional area of one inch2 and height of 10 ft, the pressure at the bottom of this cylinder can be calculated -

The fluids total volume is

1 in2 x 10 x 12 = 120 in3

The density of fresh water is 8.34 ppg

8.34 pounds per gallon =8.34 x 7,48

1728 pounds / inch

3

Fig 05

M

G

A

10 ft

1 inch2

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The mass of the fluid column will be

M = 8.34 pounds

gallons x 7,48

gallon

ft x

1

1728

ft

inch x 120 inch = 4,33 pounds3

3

3

3

The pressure at the base of the fluid column is caused by gravitational acceleration that actson the fluid column divided by the fluid columns' cross sectional area.

psi4.33=inch

pound

1

4.33 = Ph

2

It is important to realise that the pressure at the bottom of a static fluid column is onlydepending on the vertical height of the column and the density of the fluid.

05.01 Pressure gradient

Considering a porous and permeable rock formation in which the pores are filled with freshwater (density 8.34 ppg).

It is now possible to calculate the pressure at 5000 feet depth -

psi=10

5000 x4,33

= P h 2165

It is also possible to calculate the pressure increase that every foot of depth will represent.

ft pr psi0.433=5000

2165 = ft per increase Pressure

This quantity which represents pressure increase in psi/ft is named Pressure GradientG.

When the pressure gradient for a fluid or gas is known it is easy to calculate the pressure at

any given depth.

From the shown example of freshwater (8.34 ppg) and pressure gradient (0.433 psi/ft) it ispossible to calculate the pressure gradient for a fluid or for a gas with a density of 1 ppg.

ft psi0,052=8,34

0,433 = ppg 1 for gradient Pressure /

With this new figure it is now possible to calculate the pressure gradient for any fluid or gas.

Pressure gradient = 0.052 x density in ppg

Example:

Calculate the pressure gradient for a fluid with the density 10.4 ppg.

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Answer: 0.052 x 10.4 = 0.541 psi/ft

Calculate the pressure exerted from this fluid at a depth of 4000 ft -

Answer: 0.541 x 4000 = 2164 psi

Fig 06 shows different pressure gradients and illustrates how pressure increases withdepth-

Fig 06

DEPTH0

2500

50001000 2000 3000 4000 5000

PRESSURE

1 Gas grad. 0.07 psi/ft

2 Oil grad. 0.30 psi/ft

3 Fresh W. grad 0.433 psi/ft

4 Salt W. grad 0.465 psi/ft

5 10 ppg grad. 0.52 psi/ft



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06.01 Abnormal / Subnormal Pressure

So far it has been assumed that there is a direct proportional relation between formationpressure and fluid density and true vertical depth from the surface.That means that the formation fluid pressure is only affected by the fluid density and from thetrue vertical depth.The influence of the overlying rock formations has so far not been considered.The reason is that in case of a permeable and porous formation system every single rockparticle rests upon or leans up against other particles just below and to the side of it.Therefore the rock structure supports its own weight, and regardless of depth does not affectthe formation fluid pressure.

Artesian Well

When talking about artesian wells, we arenormally talking about water wells wherewe have a porous sandstone witch hascommunication to higher laying areascreating abnormal pressure below a cap

rock.

Fig 07

Under compaction

Let us consider that at a particular period in a rock formations' development it was notpossible for the formation fluids to escape since an impermeable formation type placed ontop prevents this from happening. Therefore the rock particles can not be compacted andconsolidated sufficiently to carry the weight of the overlying rock. Since the fluid trapped inbetween the particles could not escape the fluid will be exposed to compressing forces.These forces result in an increased formation fluid pressure, which is abnormal at the givendepth. It can be realised that the trapped formation fluid has to carry the weight of theoverlaying formation, along with the formation rock in which it is trapped. In a situation suchas this the formation pressure will be greatly different from a calculated normalpressure/depth forecast.

Example: A formation at 5000 ft depth contains formation fluid. The formation fluid hascommunication to the surface through porous and permeable formation rock. See fig.08

POROUS SANDSTONE

BELOW CAP ROCK

HYDROSTATIC

PRESSURE

FROM

FORMATION

WATER

COLUMN

LAKE

NORMAL FORMATION

PRESSURE AT THE WELL

UNTILL BELOW THE CAP

ROCK

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Formation pressure at 5000 ft will be the fluid column pressure

Density for formation fluid = 8.95 ppg

Pressure gradient for formation fluid = 8.95 x O.052 = 0.465 psi/ft

Pf (Pressure of Formation) = 5000 x O.465 = 2325 psi

Fig 08

If it is considered that this formation fluid was trapped in an earlier period in the sedimentaryprocess and therefore could not escape the later compaction process, it is possible that thefluid may be exposed to the weight of the overlying rock mass.

Assuming formation fluid is 10% and an equivalent formation density of 21 ppg this results inthe following formation pressure -

Pf = 5146.7 psi

This formation fluid is over-pressured or abnormal. Over-pressured formations are oftenencountered with thick salt sediments and salt domes. Salt does not have the same structureas normal rock formations. Salt is termed a "plastic" formation, which means that it is notself-supporting, it can move and deform under pressure, and (this is not necessarily a rapidprocess). When pressure is applied to a salt formation it behaves more as fluids rather thanas solid matter. The relative strength of salt is very low compared to other rock types.

Because of the salt's qualities the weight from the overlying formation including the weight of the salt layers themselves will be transferred to the formation below the salt. The pressure inthe salt and in the formation below it will often have a pressure gradient of 1 psi/ft instead of

the normal pressure gradient for formation fluid, which is 0.465 psi/ft.

f P = ( 0.1 x 5000 x 8.95 x 0.052) + (0.9 x 5000 x 21 x 0.052)

5000 ft 5000 ft

2325 psi 5147 psi

Impermeable

zone

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Abnormal pressures can also occur when an encapsulated and normal pressured formation

for the particular depth at a later stage in history with movements or surface erosion isbrought closer to the surface.The particular formation in question can be found deeper or shallower in relation to its originalposition. If it is the case that the formation pressure cannot adjust to its new depth it will holdits original pressure.

Example:If a sandstone formation at 4000 ft depth is considered it will have a normal pressureof 1860 psi. On account of geological processes the area of sandstone becomesisolated by impermeable rock. Through earth movements the formation moves to ashallower depth of 2500 ft. In this situation the sandstone will retain it's original 1860

psi pore pressure but he surrounding formation has a pore pressure of 1160 psi.

Such an isolated zone is called a high-pressure zone or abnormal pressured zone.

It may as well be the case that the isolated sandstone by earth movements was broughtdown to 5000 ft depth. The normal pressure for 5000 ft would be 2325 psi and the isolatedsandstone area with its 1860 psi would become a low-pressure or subnormal-pressuredzone.

Fig 09

Abnormal pressured formations can also develop because of differences in the containedformation fluid and gas densities.

Figure 10 shows an anticline. An anticline is the geological term for an area of formationswhich, due to earth movements has been pushed upwards to take a shape like a dome.

In the figure the anticline consists of porous sandstone which contains gas. A layer of

impermeable shale that prevents the gas from escaping caps the sandstone. Theformation surrounding the anticline has a pore content of salt water and a base depth of 5000 ft. The formation pressure is considered to be normal. Formation pressure of the saltwater bearing rock at 5000 ft will therefore be:

4000 ft

2500 ft

5000 ft

1860 psi

1860 psi

1860 psi

1160 psi

2325 psi

1860 psi

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Fig 10

If the sandstone in the anticline contained salt water instead of gas, the formation pressure atthe very top of the anticline would be exactly the same as the formation just above.

Example:Pf = 3000 x 0.465 = 1395 psi

The sandstone however is containing gas, which has a pressure gradient of 0.1 psi/ft. Thisresults in the pressure at top of the anticline to be substantially higher than the calculated1395 psi for a salt-water formation.

The reason is that the hydrostatic pressure of gas within the anticline is much lower than thecorresponding hydrostatic pressure of salt water on the outside.

Pressure from the 2000 ft high gas column will be:

Ph = 2000 x 0.1 = 200 psi

Therefore the formation pressure at the very top of the anticline below the cap rock will be:

Pf = 2325 - 200 = 2125 psi

Formation structures of this type give a real problem if the formations above and/or below willnot withstand the 12.45 ppg hydrostatic pressure from the drilling fluid that is required to

psi2325=0.465 x5000= P

f

Porous

with

water

Sandstone

with gas

5000 ft

2325 psi

3000 ft

1395 psiAnticline

Tight

Shale

2125 psi

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balance the zone at 2000 ft. It may be necessary to set several casing strings in order to

isolate the pressure.High-permeability limestone formations have small formation strength gradients, and lostcirculation may be the result when the bottom well pressure exceeds formation pressure byas little as 200 psi. This value may be less than the dynamic pressure drop in the annulus or less than a safe trip margin. Such conditions can be risky if insufficient information isavailable.

Transition zones and under compacted shale

Wherever massive shale formations are found the risk for transition zones and high pressureis present. This is caused by thick impermeable shale restricting the disposal of formation

fluid. Due to new sediments are settled on the seabed increasing weight load is exerted onthe shale from the formation above. The water, gas or oil trapped within the shale cannotescape. The result is the development of abnormal pore pressures. The terminology under compacted shales is used to indicate these circumstances.

A seal of harder rock often caps the top of the abnormal pressured shale. Just after the cap ispenetrated the Rate of Penetration (ROP) increases. The reason is that the shale is easier todrill since the differential pressure between drilling fluid hydrostatic pressure and theformation pressure decreases. A reduction in overbalance results in a faster drilling rate.

When the Driller maintains his drillingparameters constant t.i. constant rotaryspeed, constant weight on bit and constant pump rate, the Rate of Penetration shouldbe constant as well, unless changes in thedrilled formation takes place.The indication of changes in the formationcan therefore be observed by the Driller bymeans of changes in Rate of Penetration.

To confirm whether the well is still in balance,

the Driller must stop and observe if the well is static. The terminology for this operation is "flow checking the well".

Fig 11

Whenever thick shales are encountered it is important to be careful and expect abnormalpressure in the formation. Shale related abnormal pressures can occur at any depth fromsurface to very deep and is the most common reason for abnormal formation pressure.

Because the formation fluid in under compacted shale is unable to escape, a typical trend willindicate that the cuttings density decrease with depth. The density decrease with depth canindicate that abnormal pressure is encountered.

ENCLOSED SAND LENS WITH FORMATION FLUID

UNCONSOLIDATED

SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED

SAND WITH COMMUNICATION TO SURFACE

SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES

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Surcharged formations by underground blowouts

A different reason for abnormal formation pressures are the result of previous blowoutsunderground. Shallower sands can become charged as the result of an uncontrolledunderground blow out from an adjacent well or from a bad cement job. Even the well hassuccessfully been closed in on surface the pressure from the deeper zone can communicateto the shallower sand reservoir.When the next well is drilled the abnormal pressure is encountered at the much shallower depth.See Fig 12

Fig 12 Fig 13

Surcharged formations by natural causes

Shallow formations may also be surcharged by natural causes. This can be the result of afault in the formations. A fault gives a means of communication between deeper formationswith high pressure and shallower formations. The higher pressure escapes into the shallower formation where an abnormal pressure will be the result.See Fig 13.

UNDERGROUND

BLOWOUT

Pf

FAULT ZONE

Pf

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02 PRESSURE BALANCE IN THE WELL BORE

01.02 Pressure balance

During drilling of a well the formation pressure must always be counter balanced by an equalamount of pressure exerted from within the well. This is achieved by using a drilling fluidhaving a sufficient density.

Drilling fluid which is a combination of different fluids and chemicals has several importantfunctions in the drilling process but a main function is the ability to give pressure balance inthe well.

The density of the fluid can be adjusted by adding high density material or by diluting bywater. It is in this way that balance and control of the formation pressure can be achieved.

02.02 Overbalance and underbalance

Underbalance is the term used when at a particular depth the formation pressure exceedsthe hydrostatic pressure exerted by the drilling fluid column. In this situation there is a riskthat fluid from the formation will intrude into the wellbore and begin to displace the drillingfluid. On surface the drilling fluid returns rate will increase and later the active drilling fluid pitswill show a gain of fluid. If this sequence of events takes place in a well a kick is said to have

occurred.The rate of influx is dependent on the degree of underbalance and on the formation'spermeability. To drill a well underbalanced is dangerous in most parts of the world and istherefore usually not practised in oil well drilling.However in certain areas where sufficient data are available it is practised anyway mainlybecause drilling can take place with a high penetration rate.

03.02 Lost circulation

Overbalance in the well is present when the drilling fluid hydrostatic pressure exerts a higher pressure than the formation pressure. In this situation formation fluids cannot intrude into the

wellbore. The reverse can occur whereby drilling fluid will seep into the formation, and lostcirculation may be the result. This is not a desirable situation.If drilling fluid seeps into the formation the formations' permeability becomes reduced. Whenthe overbalance becomes too large the formation will break allowing a large amount of thedrilling fluid to flow into the formation. This situation is called lost circulation.

When lost circulation has been the result a dangerous situation is created. The drilling fluidlevel drops and hydrostatic pressure is lost. When hydrostatic pressure is lost the formationpressure higher up becomes underbalanced which can result in a blow out.

04.02 Rate Of Penetration versus overbalance

The difference between the hydrostatic pressure exerted by the drilling fluid at the bottom of the wellbore and the formation pressure is called the differential pressure. When the

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hydrostatic pressure exerted by the drilling fluid is higher than the formation pressure the

bottom hole pressure is in overbalance.The relationship between differential pressure and Rate of Penetration shows that Rate of Penetration increases when the differential pressure decreases. Penetration is given in feetper minute and differential pressure in psi.

Fig 14

The graph is interesting in several ways. Assume drilling with a differential pressure of 2430psi in a particular formation with constant drilling parameters E.I. :

- Constant Weight on Bit

- Constant drilling fluid density

- Constant rotary RPM and

- Constant pump rateit can be seen that the penetration rate is 4 ft per minute.

Ft/min

psi

R a t e o f

P e n e t r a t i o n

Differential PressureP =

3

4

6

9

12

15

1000 2000 3000

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Without changing any other parameters imagine that the formation pressure increases by

980 psi. This results in a new differential pressure of 1450 psi and a corresponding increasedpenetration rate to 6 ft per minute.It is realised that when the differential pressure decreases the penetration rate will increase.

05.02 Drilling break

An increase in Rate of Penetration (ROP) with constant drilling parameters is called a drillingbreak.

It should be known that a drilling break is an early warning of a kick. If the Driller reacts on theobservation by making a flow check the well may still be overbalanced with the pumps

stopped.

Even that an increase in Rate of Penetration may be caused by other factors than a changein differential pressure, the Driller should always play safe and perform a flow check in order to confirm that the well is in balance. A natural reaction must also be to inform thesupervisors of any drilling breaks.

06.02 Necessary overbalance

By means of the graph it is seen that to obtain the highest possible penetration rate thedegree of overbalance has to be as small as possible. In practice a sufficient overbalancemust be used to avoid kicks from taking place.

07.02 Trip margin

A situation that can bring the well in underbalance is when the drill string is pulled upwardsduring a connection and when tripping the string out of the well. The lower part of the drillstring acts as a piston that results in reducing the pressure below the string when pullingupwards.When the pressure in the wellbore is reduced the formation fluids can enter the wellunderneath the bit.

To what extent this occurs is dependent on:

- How quickly the drill string is pulled upwards

- The dimension of the wellbore

- Dimensions of the drill string

- The rheological characteristics of the drilling fluid

- Other factors like degree of balling of the Bottom Hole Assembly etc.

To prevent formation fluids from being swabbed into the wellbore caused by any of thesereasons in combination a necessary overbalance is used. This small degree of overbalanceis called a trip margin.

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Fig 15

Fig. 15 shows the conditions when drilling in normal pressure conditions. The tolerance area

(given by the area between the formation strength pressure and the formation pressure) isrelatively large.When the drilling fluid density is adjusted to be in the centre of the area, there is only a smallrisk for swabbing in connection with a trip. There is also allowance for a relatively large surgepressure in excess of the hydrostatic pressure without risk for exceeding the formationstrength.

Surge pressure in the well is the result of lowering the drill string too quickly. The piston effectresults in increasing the pressure below the drill string.

Fig 16 and 17 shows different measurements taken with a PWD tool under “normal”

tripping conditions.

Fig 16 Fig 17

Formation

Strength

Formation

Pressure

Fluid

Density

Swab

Pressure

Surge

Pressure

Pulling

Speed

(mins/stand

Start

EMW

(G)

End

EMW

(G)

Pressure

Drop

psi

4

5

7

8

0.965

0.964

0.962

0.962

0.956

0.956

0.958

0.960

140

124

62

31

SWAB PRESSURESWAB PRESSURE

Running

Speed

(mins/stand

Pump

Rate

0 gpm

Pump

Rate

180 gpm

Pump

Rate

250 gpm

1

2

3

4

295 psi

124 psi

93 psi

651 psi

434 psi

356 psi

837 psi

636 psi

527 psi

SURGE PRESSURESURGE PRESSURE

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08.02 Riser margin

When drilling takes place from floating rigs (semi-submersible and drill ship), there can beseveral hundred feet of distance between the rig and the sea floor. The marine riser connectsthe rig to the sea floor amongst other to allow returns to be taken to the rig. The drilling fluidthat is contained in the marine riser is contributing to balancing the formation pressure in thewell.

If a marine riser by accident or on purpose is disconnected from the wellhead at the seabedthe bottom hole pressure will be reduced. The reason is that the drilling fluid in the marineriser from the well head to the bell nipple is removed and replaced by a shorter column of seawater. An important factor is that the seawater has a lower density than the drilling fluid.

To prevent that the reduction in hydrostatic pressure leads to a kick and a blowout apreparation must be made that will ensure that a sufficient overbalance in the well, even withthe marine riser disconnected. This overbalance is called a riser margin.

It is realised that there are many precautions to take into consideration, when deciding thedrilling fluid density to be used in a particular situation.

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Pressure Gradient

G Drilling Fluid = Drilling Fluid Density ppg x 0.052 psi/ft

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10.02 Equivalent drilling fluid Density.

Considering a well with a true vertical depth of 6000 ft full of drilling fluid that has a density of 11 ppg.

The well is closed-in at the surface with the Blow Out Preventer ( BOP ) and drilling fluid ispumped slowly into the wellbore. Pressure at the top of the well will now increase to 900 psi.See Fig 18

Find what the bottom hole pressure in

the well will be?

It is seen that the pressure now consists of two components.

- The hydrostatic pressure from thedrilling fluid (which changes with depth)

- The static pressure at the surface(which gives a constant extra pressureat all depths in the well).

Fig 18

Hydrostatic pressure 11 x 0.052 x 6000 = 3430 psiClosed-in pressure = 900 psiBottom hole pressure = 4330 psi

Which drilling fluid density must be used if the above bottom hole pressure shall bemaintained by using only hydrostatic pressure?

The calculated drilling fluid density is called the equivalent drilling fluid density.

MW =4330

6000 x 0.052 = 13.9 [ppg]

900 psi

900 psi

900 psi

6000 ft

MW 11 ppg

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This means that the original 11.0 ppg drilling fluid must be replaced by a drilling fluid which

has a density of 13.9 ppg if the same bottom hole pressure shall be present without extrapressure being applied at the top of the well.

Pressure in all depths in the well will be different in the two examples.

This can be confirmed by simple calculation.

What is the pressure at 3000 ft in the two examples?

Example with closed-in pressure on surface:

Example without closed-in pressure on surface:

It must be realised that pressures throughout the well will be lower, if a particular bottom holepressure is achieved only by drilling fluid density, rather than using a lower drilling fluiddensity combined with a static pressure applied at the surface.

psi2616 = PressureTotal

psi900 = PressureStatic Applied

psi1716 =30000.052x x11= P 1. h

psi2168=3000 x0.052 x13.9= P 2. h

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03 Dynamic pressure regime when circulating

01.03 Circulation of Drilling Fluid

Whilst drilling the drilling fluid is continuously circulated to clean out the rock fragments(cuttings) from underneath the bit whilst removing them up to the surface where they areseparated from the drilling fluid by the mud cleaning equipment.

To establish the circulation in the system it is required to have a dynamic fluid differentialpressure between certain areas in the system. This pressure difference represents a certainenergy that is used to overcome the resistance against fluid movement, resistance that isexisting in the system.

This resistance against fluid flow or friction as it is generally called in a hydraulic system islargely dependent upon:

- The fluids' rheology (viscosity, density etc.)

- The fluids' velocity

- Type of flow regime ( laminar or turbulent)

If a fluid is pumped through an enclosed pipe system with a constant velocity the resistance

in the system depends on the flow area. Where the fluid flow meets diameter reductions, alocal increase in velocity is the result and therefore a greater friction. Conversely where theflow meets a larger diameter the velocity will decrease and the friction will consequently alsodecrease.

Fig 19

Fig. 19. shows a circulating fluid system where the initial pressure at the pump is 1400 psiand the final pressure is 0 psi at the flow line. It is seen that the 1400 psi represents the

energy required to overcome the friction that is present against the flow of the fluid in thesystem. Large obstructions to flow give large pressure losses. By means of pressure gaugesplaced in the system the pressure losses in the different parts of the system can bemonitored.

1400 1320 1280 1220 1170 800 0

80 40 60 50 370 800

Recorded Pressure (psi)

Pressure loss (psi)

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Applying these considerations to the circulation of drilling fluid the Fig. 20. shows a pipe

system in which the drilling fluid pump ( mud pump ) shall pump drilling fluid through. Thissimplified pipe system consists of drill pipe, drill collars, bit nozzles and annulus. The drillingfluid enters the top of the drill string with a pressure of 2200 psi. On the way down throughthe string some of this pressure is lost depending on

- The dimensions of the drill pipe (Internal diameter)

- The characteristics of the drilling fluid.

Fig 20

P1 = Pressure as drilling fluids enters the drill pipe (2200 psi)P2 = Pressure as drilling fluid enters the drill collars (1900 psi)P3 = Pressure as drilling fluid enters the bit nozzles (1700 psi)P4 = Pressure as drilling fluids enters annulus (130 psi)P5 = Pressure as drilling fluid enters the flow line ( 0 psi)

The largest pressure loss in the well system takes place when fluid flows through the bitnozzles that have a relatively small flow-through area.

On the way towards the surface through the annulus, the pressure loss will be the lowest inthe system, because the friction is not at all large on account of the large cross-sectional areaof the annulus.

The pressure figures used in Fig. 20. are based on average calculations for a simple rotaryassembly, and they show that 94% of the total pressure loss occurs in the drill string and bit

nozzles.

NATIONAL DRILL PIPE

DRILL COLLARS

ANNULUS

BIT

P1

P2

P3

P4P5

PSI

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The figures show that to circulate the drilling fluid from the bottom of the well up to the

surface it is only necessary to use approximately 6% of the total pump pressure. Thisdynamic pressure will be transmitted to the bottom hole pressure.When the pump is running and circulation takes place there will be a higher bottom holepressure than when the pump is stopped.With the pumps stopped only hydrostatic pressure is present in the well to balance theformation pressure.

02.03 Dynamic pressure in the wellbore ( Circulating Pressure)

Dynamic Pressure ( PC ) is dependent on three factors:

- Components in the flow system(Flow area, length of drill string, nozzles size etc)

- The fluid characteristics ( Rheology )

- The flow rate(SPM, liner size, pump efficiency etc)

Change in drilling fluid characteristics ( such as viscosity and gel-strength ) can change thefriction against flow in a system.

A fluid's flow resistance is largely depending on the drilling fluid density. In well controlcalculations it is accepted that dynamic pressure loss is proportionally depending on drillingfluid density.

PC1 = Circulation pressure when drilling fluid density is MW1PC2 = Circulation pressure when drilling fluid density is MW2

The expression for the relationship between circulation pressure and drilling fluid density has

proved to be realistic in most practical cases. See fig. 21.

[psi] MW

MW x1 P =2 P

1

2C C

PSI

PC2

PC1

Low f luid densit y

High f luid densit y

Fig 21

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Example:

At 100 SPM the pump pressure is 1000 psi with a drilling fluid density of 10 ppg.

What would the pump pressure be at 100 SPM if the drilling fluid density wasincreased to 12 ppg??

New pump pressure:

To calculate the new pump pressure it is required to know the original pump pressure, whichis read just after the pump ( standpipe pressure ).

The third factor that affects the circulation pressure is the speed of the flow of drilling fluid.This velocity of flow is directly related on the pump speed ( SPM = strokes per minute).

The relationship between pump speed and dynamic pressure can be expressed as:

Where SPM is the number of strokes per minute in the two cases.

Example:

Circulation pressure is 1200 psi with 40 SPM.What will the circulation pressure be if the pump speed was increased to 80 SPM?

Answer:

It is realised that if the pump speed is increased to twice its original value the dynamicpressure will be increased almost fourfold. The graph in Fig. 22 illustrates this fact.

The power 1.86 is an experience figure, which is obtained from experiments. However in wellcontrol calculations it is generally accepted to use the power 2 in stead of 1.86.

[psi]1200=10

12 x1000=2 P C

C C

1.86

2

1

P 2 = P 1 x SPM SPM

psi4356 =40

80 x1200=2 P

1.86

C

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For well control calculations use the formula below:

Fig 22

Fig. 23. shows circulation pressures and pressure losses between the drill string and annuluswith three different pump rates.

Fig 23

C C

2

2

1

P 2 = P 1 xSPM

SPM

10 20 30 40 50 60 70 80 90

SPM

1000

2000

3000

4000

Pc

1000

2000

3000

4000

Pc

80 spm

60 spm

40 spm

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04 CONSIDERATIONS WITH A CLOSED-IN WELL

01.04 Closed in well

Fig. 24 illustrates a wellbore with pressure gauges. The drill string consists of pipe connectedto each other, right down to the bottom of the well. Through the bit nozzles, the string is incommunication with the annulus. In principle this can represent two pipes, one inside theother but there is only communication at the bottom of the well. On top of the well the BOPequipment is installed. This equipment makes it possible to contain and close off the annulusand its contents. Under the BOP a pressure gauge is installed which measures the surfaceannulus/casing pressure.On the top of the drill pipe after the pumps another gauge which measures drill pipe pressure

is installed. The two gauges are necessary to get an indication of down hole conditions.

Fig 24 Fig 25

02.04 U-tube

A simplified and equal system can be represented by two tubes standing upright side-by-sideand connected at the bottom. The example is called a U-tube. See. Fig. 25.

The pressure in the same horizontal levels in the connected system is always the same if fluid density is the same, when no circulation is taken place and no pressures are closed inon the top on any of the two legs.It is seen that the hydrostatic pressure at the bottom of such a U-tube system, irrespective of which leg of the U-tube column is considered will be equal. This is easily confirmed by asimple calculation:

NATIONAL

ANNULAR

DRILLSTRING

DRILLCOLLAR

BOP

PDP

P A

P APDP

A

D R I L L S T R I N G

A N N U L U S

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Example:

True vertical depth = 10000 ftDrilling fluid Density = 10 ppg

Both drill pipe and annulus are open at the surface and the U-tube is in balance. Bottom holepressure Ph at the point A can be found either by the drill pipe or by the annulus when drillingfluid density is uniform :

If the BOP is closed on the annulus and the drilling fluid in the annulus is replaced withsaltwater ( 8.34 ppg ) the following can be calculated:

The internal contents of the string ( drill pipe and drill collar ) has not changed so PH at A isstill 5200, but the hydrostatic pressure in the annulus is only (Fig 26):

Fig 26 Fig 27

[psi]520010000 x0.052 x10= P h

[psi] DepthVertical True x0.052 x Density Fluid Drilling = P ft ppg h

psi860 =4340-5200= P

psi4337 =10000 x0.052 x8.34= P

a

ha

P APDP

A


A N N U L U S

10 ppg 8.34 ppg

10000 ft

P APDP

A


A N N U L U S

9 ppg

8.34 ppg

10000 ft

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Example:

Considering the same well with the same bottom hole pressure, but now with 9 ppg drillingfluid in the drill string and upper 7000 ft of annulus, while there remains saltwater in the lower part of the annulus (Fig 27).

When PSIDP = Pressure ( Shut in drill pipe )When PSIA = Pressure ( Shut in annulus )

The example represents a typical kick situation, where insufficient drilling fluid density hasresulted in a saltwater influx into the annulus. The influx has replaced a quantity of drillingfluid. Notice that the drill pipe bottom hole pressure consists of two parts, first the PSIDP valueand secondly the hydrostatic pressure of the drilling fluid. The annulus bottom hole pressureconsists of three parts. The PSIA value, the hydrostatic pressure of drilling fluid and thehydrostatic pressure of the saltwater.

[psi]520= )10000 x0.052 x9( -5200= P SIDP

[psi]362 )0.052 x8.34 x30000.052 x9 x7000( -5200= P SIA

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05 PROPERTIES OF GASSES AND GAS LAWS

01.05 Drilling with Underbalance.

If drilling takes placed being underbalanced the risk of taking a kick is always present. Theinflux resulting from a kick can be water, oil or gas.When dealing with gas the drill crew must be aware that gas behaves differently than fluid.

02.05 Properties of gas and Gas Laws

A given mass of gas can be compressed or expanded, and as the volume changes thepressure will do the same.

Boyles Law states that:P 1 x V 1 = P 2 x V 2

or Pressure x Volume = Constant → See Fig 28

Fig 28

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

15000

5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 VOLUME

PRESSURE

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This means that when a given volume V1 with an absolute pressure P1 is changed in

pressure or volume we get a new pressure P2 with a new volume V2.

Example:

V1 = 5 gal P1 = 170 psiV2 = 3 gal

Calculate P2

[psi]283=3

5 x170 =

V

V x P = P _ V x P =V x P

2

1122211

It is important to know that gas expands if pressure is reduced.

Boyle’s Law is only true when the temperature is constant. If the temperature changes theformula given below is used where → T = temperature

1 1

1

2 2

2

P x V

T =

P x V

T

It must be noted that the temperature to use is an absolute temperature which is given inKelvin degrees, (ºK ) for the Centigrade system.If the Fahrenheit system is used the absolute temperature must be given in Rankin (ºR )degrees.

ºK is obtained by addition of 273º to the temperature given in Centigrade ºC.

K CT = t + 273

ºR is obtained by addition of 460º to the temperature given in Fahrenheit ºF.

R FT =

t + 460

Example:

V1 = 12 gal P1 = 90 psi T1 = 20ºCV2 = 12 gal T2 = 80ºC

[psi]108=12 x20)+(273

80)+(273 x12 x90 =

V xT

T xV x P = P

21

2112

Since V1 = V2 pressure increases only through temperature increase.

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Example:

The formula, which relates to the properties of gasses, is here used in a practical example.

The well has a depth of 10000 ft and there is a swabbed gas bubble on bottom. The drillingfluid density is 12.5. The well is open and in balance. Consequently no closed-in pressure atthe surface. The pressure in the gas is therefore equal to the hydrostatic pressure at 10000 ft→ Ph.Hydrostatic pressure Ph is 6500 psi.

If the BOP is closed and the gas is allowed to rise upwards ( migrate ), the gas volume willnot change and in accordance with the gas law the pressure will also remain unchanged.

Assuming the temperature is constant the gas would retain its original volume and pressureall the way to the surface.

Fig 29

Considering that the gas has migrated halfway up the wellbore it will still have a pressure of 6500 psi. The pressure at surface ( annulus ) at this stage would be: (See Fig 29.)

[psi]3250=5000 x0.052 x12.5-6500= P SIA

Bottom hole pressure:[psi]9750=5000 x0.052 x12.5+6500= P bottom

P A P A P A

10000 ft

12.5 ppg

0 psi

6500 psi

6500 psi

5000 ft

6500 psi

9750 psi

3250 psi

5000 ft

12.5 ppg

12.5 ppg

6500 psi

6500 psi

12.5 ppg

13000 psi

10000 ft

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When the gas is allowed to rise all the way to the surface without expanding, the pressure at

the surface would be 6500 psi.

Bottom hole pressure would be:

[psi]13000=10000 x0.052 x12.5+6500= P bottom

This extreme pressure throughout the wellbore cannot be controlled, and it is not reasonableto assume that the situation would develop all the way as described. The weakest point in thewellbore is normally believed to be at the casing shoe level. When the pressure increasesabove the strength at the weakest point the formation at that point will fracture. The risk for anunderground blow out is high.

A gas kick can never be allowed to migrate up through the annulus without expanding. Askilled drill crew must take proper and timely action to avoid the dangerous situation that islikely to occur.In the given example the temperature influence neither the changed height due to annulusgeometry was taken into account since these factors only have a small influence in practice.

03.05 Expansion of Gas

Although some kicks are predominantly salt water or oil, at least some gas is usually present.Because salt water and oil do not expand as pressure decreases, they are not astroublesome as gas. It is important for the persons who control blowouts to understand the

behaviour of gas in a well.The gas volume change as a result of pressure change is predictable, and this allowscalculation under illustrative conditions of changes in bottom well pressure as gas risesthrough the drilling fluid. When the pressure of a given mass of gas is doubled, the volume ishalved. When the pressure is halved the volume is doubled. This relationship betweenpressure and volume results in the greatest expansion of the gas in the upper part of the well.See Fig 28.

Although gas-cut drilling fluid is one of the early indicators of abnormal pressure, minor gas-cutting results in only a small reduction in the hydrostatic head. In a gas-cut column of drillingfluid, the pressure increases rapidly with depth, so that the volume of gas scattered throughthe well bore is very small, and reduces the overall drilling fluid density in the well very little.

A slug of gas in the bottom of a well is potentially dangerous, because it will expand greatlywhen it rises or is pumped up. Under low pressure near the surface, it will displace a largeamount of drilling fluid from the well and consequently greatly reduce bottom hole pressuregiving risk for a blowout.

The safe handling of a gas kick requires knowledge about the principle of gas expansion andconsequently lowering the pressure in the gas bubble as it is circulated up through theannulus in order to maintain the correct and constant bottom hole pressure. The theoreticalknowledge requires practice as well as knowledge about well control equipment.

When the gas in a well control situation is circulated to the surface and expanding, moredrilling fluid must be allowed to flow out of the annulus than is pumped into the drill pipe.Thus, the pit level will increase.

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The expected drilling fluid volume increase should be known prior to circulating out the kick.

This detail is discussed in the kick control section.To control a correct and constant bottom hole pressure, the surface pressures are used as aparameter for control. This is done by means of the choke in connection with a stroke counter for the mud pumps, and simple recognised procedures.

04.05 Formation strength

From the previous examples it is realised that pressure throughout the wellbore increaseswhen gas rises up the annulus in a closed-in well. Gas must be circulated out of a well under control. One of the most important limitations that should be known is the maximum pressurethe formation ( or weak point ) can withstand before it fractures and allows the drilling fluid to

flow into the formation.If the formation strength is exceeded in a kick situation there is a high risk for an undergroundblow-out and perhaps complete loss of control of the well.

The formation strength is recorded by means of a leak-off test.

05.05 Leak-off test

A leak-off test can be carried out in various ways. The aim is to find the surface annuluspressure value for when the drilling fluid begins to seep into the formation, without at thesame time to cause an actual fracture of the formation. The less drilling fluid volume that ispumped into the formation, the less damage there is caused to the formation. After the testthe formation should easily heal again as a result of the drilling fluid's wall building effect.

A leak-off test is carried out just after casing has been set and cemented.

A leak-off test may be conducted as follows:

Between 10 and 30 feet is drilled below the casing shoe to expose virgin hole.The well is circulated to obtain a representative and accurately known drilling fluid density inthe well.

The well is closed-in and drilling fluid is pumped into the well at a very slow rate.The cement pump is generally used since they have a smaller displacement and thus areeasier to control and are fitted with very accurate low pressure gauges.

Accurately measured volumes are pumped into the well, one barrel in this example, until anincrease in casing pressure is registered. At this point pumping is stopped for about oneminute, until the surface annulus pressure has stabilised. When no pressure decrease isobserved the pressure is plotted on a graph paper. The pumping is resumed and the samevolume is again pumped. The pumps are stopped and the new pressure is plotted after it hasstabilised. This procedure is repeated until it is observed that the pressure increase per volume portion is no longer proportional.This is easy seen on the plotted graph at the point where the straight line begins to bend.

The pressure on the graph where this happens is the annulus surface leak-off pressure. SeeFig. 30.

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Fig 30

The leak-off test should be interrupted at this point. If the pumping is continued the pressurewill decrease as a result of an increasing amount of drilling fluid which is injected into theformation. Furthermore the formation strength will be reduced. It has been proven that aleak-off test performed too far has damaged the formation. In that case a second leak-off testwill indicate a lower formation strength.

Fig. 30 shows the results from a leak-off test carried out after casing has been cemented at

3000 ft. Drilling fluid density was 9.6 ppg. The leak-off pressure is seen to be 720 psi. Thecombined pressure the casing shoe is exposed to is the hydrostatic pressure of the drillingfluid and the surface leak off pressure and this combined pressure becomes the maximumallowable shoe pressure at any given time.

Calculate the maximum allowable pressure at the casing shoe:

Answer:

[psi]2218=720+3000 x0.052 x9.6 = P shoe

When we know the maximum allowable shoe pressure, we are able to calculate theequivalent drilling fluid density or maximum allowable drilling fluid density

PRESSURE

V

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1 2 3 4 5 6 7 8 9 101112131415

*

*

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*

Ph Max

Pshoe

PRESSURE

ANNULUS

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[ppg]14.22=0.052 x3000

2218 =density fluid drilling Equivalent

06.05 Maximum Allowable Annular Surface Pressure ( MAASP )

MAASP means the highest surface pressure that can be allowed at the top of the casing inexcess of hydrostatic pressure that is likely to causes losses at the shoe formation if exceeded. There are three factors that decide the Initial MAASP.

- The maximum pressure that the surface equipment can handle

- The maximum pressure the casing can handle

- The maximum pressure that the formation at the casing shoe ( or weak point ) canhandle.

In most cases it is the formation strength at the casing shoe that is the deciding factor, andInitial MAASP is then given from the leak-off test which has previously been described.

As the maximum allowable shoe pressure remains constant the hydrostatic pressureinside the casing is the determine factor for the MAASP at any given time-See Fig 31

MAASP = Maximum Allowable Shoe Pressure – Pressure Hydrostatic Inside Casing

Fig 31

As illustrated in Fig 31 the MAASP will increase if pressure hydrostatic inside the casingdecrease for whatever reason and visa versa.

PhDOWN

MAASPUP

=Ph

UP

=

MAASPDOWN

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One important issue when circulating out a kick is to monitor the Initial MAASP value. If the

Initial MAASP is approached before the kick is circulated into the casing the responsible rigmanagement must take safe action. It may be impossible to avoid exceeding the InitialMAASP, but the competent and responsible management may decide to evacuate the rig for non-essential personnel until the situation has proven to be safe.Once the influx is inside the casing the initial value can be exceeded.

We will look on how MAASP behave during circulating out a kick later in chapter 08.

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06 DRILLING FLUID VOLUME AND CAPACITIES

In routine operations as well as during well control operations it is necessary to know the totaldrilling fluid volume and the volume for the individual sections in the circulating system.

How much volume does the drill string contain and what is the volume in the different parts of the annulus?

These questions can easily be answered if the dimensions of the different components in thedrill string and annulus are known. There are two ways to find the different capacities andvolumes:

- By calculating the volumes

- By reading tables

01.06 Calculating drilling fluid Volume - Capacities

The internal capacity of drill pipe and drill collars is calculated based on formulas for cylinders.

For a cylinder with a diameter d (inches) and a height of 1 foot the volume will be:

h x A=V

/ft] ft [ 1444

h xd x =V

32

1 ft2 = 144 in2

1 ft3 = 0.1781 bbl

Then:

V = x d x 0.1781

4 x 144 =

d

1029.4 bbl / ft

2 2

Fig 32

Calculations of annular capacities are basically calculations of a hollow cylinder, or the

difference between two cylinders, - one inside the other.

For a hollow cylinder with an outside diameter OD in and inside diameter ID in and a heightof 1 ft the following formula can be derived -

1 ft

D

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ann

2 2 2 2

V =

OD

1029.4 -

ID

1029.4 =

OD - ID

1029.4 [ bbl / ft ]

The total inside or outside capacity for a certain length of pipe can be worked out by multiplying the capacity in bbl/ftby the length in ft. The result is the capacity in bbl.

Example:

Wellbore inside diameter = casing id = 9-7/8 inVertical depth = 5.000 ft

Drill pipe 5"OD & 4-1/4"ID = 4.600 ftDrill collars 7"OD & 2-13/16”ID = 400 ft

Fig 33

Internal capacities drill pipe:

Total Volume of drill pipe = 0.01754 x 4600 = 80.68 bbl

Internal capacities drill collars:

Total Volume drill collars = 0.00768 x 400 = 3.07 bbl

Annulus Capacities:

Total Volume between casing and drill pipe = 0.0704 x 4600 = 323.84 bbl

Total Volume between casing and drill collars = 0.04713 x 400 = 18.85 bbl

V drill pipe =

(4 1 / 4)

1029,4 = 0,01754 bbl / ft

2

V drill collar =(2 13 / 16)

1029,4 = 0,00768 bbl / ft

2

V drill pipe =(9 7 / 8 ) - 5

1029,4 = 0,0704 bbl / ft

2 2

V drill collar =(9 7 / 8 ) - 7

1029,4 = 0,04713 bbl / ft

2 2

1 ft

O D

I D

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Reading in table: 12.9 l/m, (12.9 x 0.00192 = bbl/ft)

Total capacity of annulus: 558.56 + 117.12 + 12.38 = 688.06 bbl

By making the above calculations the exact quantities of drilling fluid contained in the differentparts of the well is known.

03.06 Surface-to-Bit Strokes & Bit-to-Surface Strokes

The exact number of strokes required to pump from the surface through the drill string to thebit, is known as surface-to-bit strokes.

The number of pump strokes required to pump from the bottom of the well to the surface, isknown as bit-to-surface strokes.

These values can be calculated when the pump displacement per stroke is known. Pumpdisplacement can be found in the DDH Section G table G6.

Given:

National pump 12-P-160. w/ 6" liners. The number 12 represents the stroke length ininches. Volumetric efficiency 97 %.

From the table is read 16.68 l/stroke with volumetric efficiency of 100 %. At the bottomof the table a conversion factor is found to convert into bbl.

With 97 % efficiency the pump output would be:

By using the capacity figures in fig. 34 we can now calculate surface-to-bit strokes as follows:

Surface-to-bit strokesRespectively bit-to-surface strokes is now calculated.

Bit-to-surface strokes

bbl/ f t (12.9 x 0.00192) x 500 ft = 12.38 bbl

16.68 x 0.264

42 = 0.1048 bbl / stroke

0.1048 x 97 100

= 0.1017 bbl / stroke

Total inside volume of drillstring

Mud pump output per stroke = Strokes

strokes46 17 =1017 .0

61.7 17 = strokesbit Surface

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04.06 Use of Barite to Increase the Drilling fluid Density

The theoretic and actual quantity of barite used to effect a drilling fluid density increase canbe calculated beforehand by using the initial drilling fluid density MW ( ppg ) and the drillingfluid density required MWf ( PPG ) (final drilling fluid density). The units will be number of 100lb sacks per 100 bbl of drilling fluid.

Example:

An active drilling fluid system contains 900 bbl of drilling fluid with a weight of 10.5ppg. We want to increase this density to 13.5 ppg by adding barite. How many sackswill be used?

Fig 35

l. In the homograph fig 35 a straight line is drawn on the scale from 13.5 ppg MWf (finaldrilling fluid density) to 3.0 ppg on the scale to get MWf - MWi(final drilling fluid densityminus initial drilling fluid density).The scale reads 204 sacks per 100 bbl on the scale for theoretical use of 100 lbsacks.

2. By taking the point on the scale for theoretical use where the first line crosses (i.e. 204sacks) and by drawing a horizontal line across to the scale for actual use from this

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9001000

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MWf - MWi

100 lb Sacks

Theoretical MWf

100 lb Sacks

Actual

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point, the actual true value is seen to be 224 sacks (100 lb sacks) per 100 bbl of

drilling fluid to effect the desired increase.

3. Therefore

2016 sacks in the 900 bbl system is required to increase the drilling fluid weight to thedesired level.

The theoretical quantity of sacks per 100 bbl of drilling fluid can be calculated by the followingexpression:

where S = theoretical number of 100 lb sacks of bariteMWf = final drilling fluid weight (ppg)MWi = initial drilling fluid weight ((ppg)

35.5 = the calculated density of barite is considered to be 35.5 ppg.

It is always necessary to use more barite than the theoretical quantity because of hydration,variations in barite density and volume increases because of addition of other material.

05.06 Volume increase due to Barite Addition

The volume increase (in barrels per 100 bbl of drilling fluid in the system) can also becalculated by initial drilling fluid weight MWi (ppg.) and final drilling fluid weight MWf (ppg.).

Example: An active drilling fluid system contains 900 bbl of drilling fluid with a weight of 10.5ppg. We want to raise this weight up to 13.5 ppg. by adding barite.

How much volume increase will we have in the system?

1. In the homograph fig. 36 we draw a straight line between 13.5 ppg. on the scale for MWf and 3.0 ppg. on the scale for MWf - MWi, and we notice where this line crossesthe Pivot Line.

2. Where our first line crosses the Pivot Line we draw a horizontal line across to the

scale for volume increase and we can read-off that there will occur a 22.5 bbl per 100bbl increase in drilling fluid volume.

224 x900

100 = 2016 sacks

S = 1490 x MW - MW

35,5 - MW

f i

f

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Fig 36

3.

Therefore total volume = 900 + 202.5 = 1103 bbl after completion of weight increase.

The volume increase can be calculated with the help of the following expression:

whereV = the volume increase (bbl/100 bbl)

C = factor for extra barite, based on MW

22.5 x900

100 = 202,5 bbls increase volume

V = 155 x C x MW - MW

35.5 - MW

f i

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P I V O T L I N E

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MWf = final drilling fluid weight (ppg.)

MWi = initial drilling fluid weight (ppg.)

This expression assumes that 1.5 gallons of water are used per sack of bar

iwcf p & p

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