drilling and killing

7/27/2019 Drilling and Killing

1/78

Davorin Matanovi

Control of formation pressure


2/78

Killing

Production wells are valuable only if they permitthe controlled flow of gas and oil from an

underground reservoir. Any well that is connected to a formation wheregas, oil or salt water exists under pressure mayblow out control if the pressure is sufficient to raisethe fluid in the well to the surface .

An uncontrolled flow of gas, oil or salt water from awell is called a blowout.

Blowouts can cause loss of life, property damage,waste of oil and gas, and damage to the producingformation.


3/78

Killing The rig may be a total loss, and wells

may be damaged beyond salvage. Oil and gas that escape from a well are

usually wasted and often cause seriouspollution that is expensive to clean up.

Besides the money value of oil or gas is

wasted, the los of formation pressuremay considerably reduce the producingcapability of an oil or gas pay zone.


4/78

Killing

The most frequent reason for killing production wellsis a necessity to eliminate formation pressures so asto enable certain procedures or removal of some

parts of production equipment. Sometimes,however, the killing is necessary due to someundesirable occurrences in the well (leakage or

damage of the production equipment). This isknown as emergency killing.

In the process of well killing it must be taken care

not to: cause formation damage, additionally damage subsurface or surface production

equipment,

exceed the allowed stresses of production or otherequipment.


5/78

Killing Drilling or production rig personnel must be

alert to the hazard of a blowout; they must

recognize the preliminary indications and beready and able to close in a well to stop animpending flow.

If a blowout is to be avoided, the well head must beclosed completely, at least momentarily, to obtainpressure readings.

Devices to shut off the well while it is being worked

on are called blowout preventers. That are manually or hydraulically operated ram or

spherical preventers, that shut of around the pipe inthe well or enable complete shutoff when the pipe is

out of the hole.


6/78

Killing Fluids The zone of production can be protected from

damage if the killing fluid is properly chosen (non

polluting fluid). In choosing the killing fluid it isnecessary to take into account: fluid properties,well conditions, and formation parameters.

To achieve that fluid meets its purpose at the bestpossible manner, the following should be take intoconsideration: fluid density must comply with formation pressure,

fluid must not have negative impact on uncoveredproduction formation, and

fluid must be compatible with formation fluid and

formation itself.


7/78

Killing

Fluids

At killing well, an

overbalanced columnmust be maintained(pk>pf), and preventionof impairment requires

the use of non-damaging fluid. Damage to water-

sensitive formations maybe prevented by usingbrine fluids (sodium,potassium and calcium

chloride brines).

Density Temperature

(kg/m3

) (C)

NaBr 1000 to 1500

KCl to 1164

NaCl to 1200 120 to 150

CaCl2 to 1392NaCl/CaCl2 to 1300 120 to 150

CaBr2 to 1704

CaCl2/ZnBr2 1392 to 1820 >180

CaCl2/CaBr2 to 1810 >180

CaCl2/ZnCl2 to 1920 >180

ZnBr2/CaBr2/CaCl2 to 2304

Oils

Diesel oil

(D-1)

Crude oil

Polymer systemsSaturated brine

+ polymer+ CaCO3

or FeCO3

Brine+polymer Brine density

+oil soluble resin

Saturated brine +polymer + sized salt

Killing fluids

Brines

840 to 230

840 to 950 > 180

150

to 1680 150

to 1620 150


8/78

Killing Fluids

All field brines contain solids, although the amountmay be very small. In wells with low permeability reservoirs, these solids

filter out on the bore hole wall, causing a little, if any,impairment.

In wells with medium to high permeability reservoirs, the

particles are carried into the reservoir with the brine,and may cause severe impairment, because the volumeof brine entering the formation is very high (owing tothe lack of filtration control), although their

concentration in the brine is low. The particles contaminating the brine may come fromthe source water or from the sacked salt, or they maybe picked up in tank trucks or rig pits.

A 2 micron cotton filter may reduce the content ofsolids.


9/78

Killing Fluids

The killing fluid should have filter-losscontrol whenever necessary to prevent

substantial invasion into formation. Damage caused by killing fluid can be avoided if

all solid components of the fluid (gel plug),

including filtration control agents andviscosifiers, bridging solids, and particularweighting materials are degradable.

Various types of soluble or degradable materialsare available commercially, and choice betweenthem depends on reservoir conditions and typeof operation.


10/78

Killing Fluids

Long chain polymers are used in killing fluids toobtain rheological properties, and, in some cases,filtration control. The bridging agents added to the suspension prevent

deep invasion of polymer into the formation.

The bridging particle sizes must be 1/3 to 1/2 of the size

of pore openings. The most often used polymers are hydroxyethylcellulose

(HEC), derivates of guar gum and starch derivatives.HEC is almost completely soluble in acid.

Derivatives of guar gum, such as hydroxyethyl andhydroxypropyl guar gum are degradable, leaving only 1to 2% residue.

Starch derivatives, such as hydroxyalkylated andesterified starches are almost completely acid soluble.


11/78

Killing Fluids

Sized particles of oil-soluble resins or waxes maybe used as bridging agents for oil reservoirs. Any particles left in or on the formation are dissolved

when the well is brought into production.

Ground calcium carbonate is commonly used as a

bridging agent, and may be used in any type ofreservoir. It is completely soluble in acid, and on completion of the

job, it can be removed with acid if necessary. CaCO3 is available in a wide range of particle sizes, from

several millimetres down to hundredths of micron, andmay be used at any temperature encountered in an oil

well.


12/78

Killing Fluids

Density control can best be achieved with solublesalts. Maximum densities are as follows: sodium chloride, 1200

kg/m3; calcium chloride, 1390 kg/m3; calcium bromide,1820 kg/m3; and combined with CaCl2, 1810 kg/m

3; orwith CaCl

2/ZnBr

2, 2300 kg/m3.

When the high cost of CaBr2 cannot be justified,densities up to about 1680 kg/m3 may be obtained withground CaCO

3.

If densities greater than 1680 kg/m3 are required, they

can be obtained with ferrous carbonate (siderite) -FeCO3.

A fluid which uses sized grains of sodium chloride asbridging and weighting agents may be also used in well

killing procedure.


13/78

Killing Fluids

A fluid which uses sized grains of sodium

chloride as bridging and weighting agentsmay be also used in well killing procedure.

The grains are suspended in saturated brine by

a polymer and a dispersant (both unspecified). Densities up to 1680 kg/m3 are attainable. When

the well is brought into production, the salt

grains are removed by formation water, or thewell can be cleaned by flushing wit undersaturated brines.


14/78

Killing

The killing procedure depends on wellboreconditions and the set in production equipment.

According to the direction of killing fluid circulation, thekilling is considered direct or indirect.

In case the fluid is injected back into the formation, it is

necessary to establish the communication between theinside of the tubing and annulus after the fluid and gelhave been injected, which enables a completereplacement of workover fluid when necessary.

This communication is possible through the installedcirculation tools, or by inactivating the packer, ordisconnecting at the safety joint, and similar, relative to

the installed production equipment.


15/78

Killing Killing is always used in situations where:

- uncontrolled fluid flow from the well to environment

exists, and there is no possibility to stop it withexisting installed pressure control equipment,

- when fluid under pressure enters the annular space,with the pressures that exceeded critical values of

casings or wellhead spools,- when the condition of well control equipment implythat there is no possibility to shot of the well safely,

- and in all other cases when it is desired to preventany pressure effect on the well equipment and fluidinvasion in the well.


16/78

Killing The methods for well killing can be

divided into four groups consideringtheir applications:

(1) well killing by injecting the formation

fluids into production layer;(2) circulating methods;

(3) gravitation methods;(4) combined methods.


17/78

Well pressures

Pressures at the bottom of the column of fluidincreases as the fluids height becomesgreater.

This pressure is in fact dependent on thefluid density (), column height (H) and thegravity (g).

The increase of pressure with depth is termedthe pressure gradient of a given fluid.

Hgph

=


18/78

Well pressures

The smallest pressure

gradient is for fresh water;

greater is for salt water;

with the rise of the fluid densitythere is the rise in pressure

gradient reached with this fluid. For oils with various densities,

there will also be the variation inpressure gradient.

Gas of course has only anegligible pressure gradient

SPECIFIC

GRAVITY

PRESSURE

GRADIENT

105 Pa/m

1,00 0,098

1,02 0,101

1,08 0,106

1,14 0,112

1,20 0,118

1,26 0,1241,32 0,130

1,38 0,135

1,44 0,141

1,50 0,147

1,54 0,151

1,56 0,1531,62 0,159

1,68 0,165

1,74 0,171

1,80 0,177

1,86 0,183

1,92 0,1881,98 0,194

2,04 0,200

2,10 0,206

2,16 0,212

2,22 0,218

2,31 0,227


19/78

Formation

pressure can becontrolled withdifferent heights offluids with different

densities. If a gas well

contains no liquid,

surface pressurewhen the well isshut in will beconsiderable,

though somewhatlower thanformation pressure,because gas also

has a smallpressure gradient.


20/78

Principle of additive pressures

The pressure

of the fluid

column in thewell is calledhydrostatic

pressurebecause itrefers to

staticconditions

(no flow).

A B B D

D

89,6 x 10

5

179,4 x 105Pa

269 x 105Pa

358,8 x 105

Pa 538,2 x 105Pa 269,2 x 10

5Pa 448,4 x 10

5Pa 448,4 x 10

5Pa


21/78

Fluid density may vary a lot (nitrogen, oil,water, brines, mud, cement slurries,stimulation fluids; acids, fracturing fluids).

Also the column composition can vary alot.

In all these situations the pressuredeveloped at the bottom of a well or atany point, for that matter, is a sum of

hydrostatic pressures of all parts ofcolumn in specific situation.


22/78

In addition to pressures instatic columns, pressures can

also be created in the well bydynamic means, i.e., fluidmovement. Changes due the fluid flow

(production, stimulation orinjection) can significantlyinfluence pressure distribution inthe well.

All this pressure is not imposed on

the bottom because much of it isdissipated in the tubing or drillpipe and annulus due fluid friction.


23/78

Dynamic pressures losses are alsodeveloped by movement of pipe in awell, particularly if the fluid has

considerable gel strength and viscosity. If fluid velocity relative to inner string israpid, there will be greater drag than byslow movement.

The effect is the same whether due to fluidmovement by circulation, movement of thetubing or drill pipe, or both.

Surge pressures caused by the running of pipetoo fast in a well may cause formationbreakdown and lost circulation.


24/78

For the same reason, pulling pipe too fast

will reduce bottom-hole pressure and maypull formation fluid into hole.

This is called swabbing, and in many ways,

has the same effect as a swab that is used tounload a well.

When a long string of pipe first comes off bottom, itshould be pulled slowly to minimize the swabbing

effect. Pipe removed from a well will usually result in lower

fluid level, the amount depending on the fluiddisplacement of the particular pipe.

Because of that it is important to keep the hole full that means to pump in the correct amount of fluid,equivalent to volume of the pipe body removed from

the hole.


25/78

When less fluid is required thancalculated, that it may be assumed

that formation fluid has been pulledinto the well by swabbing effect.

It is therefore not enough to keep thehole full; you must be absolutely surethat the well is taking the correct

amount of fluid.


26/78

Lost returns- lost circulation, will occur when

fluid is lost through open perforations oruncased hole. This loss of fluid may be due to lack of wall cake

to seal a permeable formation , or it may be due

to rupture of the rocks, which occurs when aformation is fractured.

If lost circulation happens when a well kick isbeing handled, all control will be lost and a

serious problem will exist. Fractured zones in a well must be repaired before

any procedure for controlling formation pressurecan be put into effect.

Sometimes repair can be accomplished bypumping in a batch of fluid containing gel materialto seal the porous formation.


27/78

Indications of a blowout Formation pressure open to the well that is greater

than the hydrostatic pressure of the fluid column inthe hole will give advance evidence of its presence

to an observer. Sometimes this evidence is very obvious; for example,

when rapid flow from the well occurs

All other times, it may be obscure and show up only as avery slow gain of fluid in the pit.

These indicators may occur after a mechanical operationhas been performed; for example, when the casing has

been perforated or after a plug has been drilled out, bothof which can expose the well bore to formation pressuregreater than can be controlled by the fluid column.


28/78

Some of thepreliminaryclues of the

blowout1. Pit level rises

as intruding gasdisplaces mud.

2. Bottom-holefluid pressuredrops.

1. Pit level risesfaster as rate ofunloadingincreases.

2. Gas expands asit rises in thehole.

3. Bottom-holefluid pressuredrops.

4. More gas enterswell bore.

Well flow continuesand accelerates asdrilling fluidunloads.

1. All mud out ofhole.

2. Uncontrolled gasflow BLOWOUT!


29/78

Gas-Cut

mud

Small quantities of gas

mixed in the mud column ofa well do not displace anappreciable volume of fluid,

thus the hydrostaticpressure of the column isnot decreased to a markedextent. Gas expands very rapidly, as

it approaches the surface,where the majority ofexpansion takes place.

For this reason a little gas inthe circulating fluid of a wellmay appear that a lot of mudweight has been lost.

SURFACE GAS VOLUME

BOTTOM

H


30/78

Gas entry in the well bore produces seriousproblems for control. Gas expands as it floats up the hole or mud falls

through the rising gas.

But when gas is not permitted to expand; pressure

at the surface will increase as gas which retains itsoriginal bottom hole pressure rises in the hole.


31/78

Killing blowouts

The single most important step to blowoutprevention without which nothing else can beaccomplished is to close the blowoutpreventer.

That means to stop the entry of salt water, oil or gasinto the hole; to circulate the hole to remove thecontaminating fluid; and finally to replace lightservicing fluid with the fluid of sufficient weight tocontain the formation pressure.

The first operation involves the use of emergencyequipment blowout preventers to close the top ofthe hole, thus to bottle up the well to preventfurther entry of formation fluids.


32/78

Killing blowouts

All methods of blowout prevention for rotarydrilling and completion make use of blowout

preventer equipment and always the firststep is to close in the well.

Subsequent pressure may be too high to permitthe preventers to remain closed, but this cannotbe ascertained without shutting in the flow atleast momentarily.

At the first sign of an impending flow, the

blowout preventer must be closed for two veryimportant reasons:1. To minimize entry of formation gas or fluid.

2. To determine the formation pressure.

5 5


33/78

Killing blowouts

It is not onlyimportant to close

the well but itshould be done atonce in order to

minimize theamount of formation

fluids that enter thewell.

18 x 105

Pa

448 x 105

Pa

PERMEABLE FORMATION

56 x 105

Pa

? ?

Killi bl t


34/78

Killing blowouts

If the formation pressure isknown, the mud weight neededfor control can be calculated. Regardless the situation it is always

possible to pump the fluid throughthe pipe and the annulus.

When the formation pressure isnot known; mud in the pipe is notcontaminated by formation fluid,

thus the pressure on the drill pipecan be used to calculate thebottom hole pressure.

18 x 105

Pa

448 x 105

Pa

PERMEABLE FORMATION

56 x 105

Pa

? ?


35/78

Killing blowouts The casing pressure cannot be directlyemployed for this calculation because of theunknown height of the gas, oil or water in theannulus. If the amount of mud displaced from the annulus is

carefully measured and converted into anequivalent height of gas or salt water, it is possible

to determine which entered in the hole. A small difference of the drill pipe and casing

pressure usually indicates salt water if there was arelatively small pit gain.

Large difference is evidence that formation gashas entered the hole.

ll bl


36/78

Killing blowouts

From the picture it is

obvious that only mud(servicing fluid) is in thepipe.

The formation pressure is thanthe sum of the hydrostaticpressure of the fluid column inthe pipe, and the registered

pressure inside pipe at thewellhead.

18 x 105

Pa

448 x 105

Pa

PERMEABLE FORMATION

56 x 105

Pa

? ?


37/78

Killing blowouts

Where:

pf formation pressure, Pa

ph servicing fluid hydrostatic pressure, Pa

pt wellhead pipe (tubing) pressure, Pa

g killing fluid density, kg/m3

g gravity m/s2

Hf formation depth, m

Pa10466101810448555

=+=+= thf ppp35

kg/m1538304881,910466 === ffg Hgp

18 x 105

Pa

448 x 105

Pa

PERMEABLE FORMATION

56 x 105

Pa

? ?


38/78

Reduced circulating pressure

Before the killing starts it is necessary to know thepressure drop due circulation of the fluid with the

desired rate. The recommended method for handling a well kickmakes use of a selected circulation rate.

It is obtained by running the pump at about half normal

speed; mud strokes per minute and pressures are notedand recorded for reference.

Whole circulating system can be represented as a U-tube, where the drill pipe (tubing) is the intake side, andthe annulus is the outlet to the surface.

The greatest pressure drop is inside the pipe and bit (bitjets), and the smallest in the annulus.


39/78

Total drill pipepressure whencirculating out akick will be thesum of:

(1) the circulatingpressure at the selectedpump speed,(2) the observed shut-inpressure on the drill pipe,

representing thedifference betweenformation and hydrostaticpressure, and(3) any extra pressurecaused by pinching in onthe choke.

448 x 105

453 x 105

5 x 105

Pa

PRESSURE ON

BOTTOM DUE

TO

CIRCULATION

REDUCED

CIRCULATING

PRESSURE

SHUT-IN

STATIC

CONDITIONS

COMBINED

STATIC PLUS

CIRCULATING

PRESSURE

SERVICING

FLUID

PRESSURE

T - TUBING

PP - ANNULUST

70 x 105

Pa

PP

0 Pa

T

18 x 105

Pa

PP

56 x 105

Pa

T

88 x 105

Pa

PP

56 x 105

Pa

A B C


40/78

Reduced circulating pressure

Pressure added on the drill pipe side of the U-tube

will not necessarily be imposed on the bottom norreach the surface on the annulus side.

But pressure imposed by the choke will be reflectedall the way to the drill pipe (tubing) gauge thoughdelayed.

There will be about one second delay for each 300 mof the servicing (killing) fluid column, down the

annulus and up the pipe, before pressure changesobtained by adjusting the choke on the casingappears on the drill pipe pressure gauge.

D ill killi th d


41/78

Drillers killing method

Formation gas, oil, or salt water will flow into thebottled-up well until total pressure at the bottom ofthe hole equals formation pressure.

When the closed-in pressures are stabilized, inside pipepressure - obtained by reading the standpipe gauge andcasing pressure, should be written down.

Pipe pressure plus circulation pressure, are the key figure

to maintain the desired constant bottom hole pressure. Shut-in drill pipe pressure will be used to calculate mud

weight increase required to balance formation pressure.

The closed-in casing pressure, when circulation is started,will be the starting figure for adjusting the choke on thecasing outlet.

Because of that it may be necessary to change the chokesetting in order to hold the drill pipe (tubing) pressureconstant.


42/78

Drillers killing method The drillers method of killing a well kick

is accomplished in two circulations:1. During first circulation, a well is circulated to

remove the intruded fluid or gas from the well.

A constant bottom hole pressure is maintained toprevent further entry of formation fluid whilecirculating at a reduced speed.

Choke pressure is adjusted to hold drill pipe

pressure constant. The circulating fluid is the same as was used

when the kick was encountered.


43/78

ll k ll h d


44/78

Drillers killing method The first circulation is started by opening the

choke and simultaneously bringing the pump up tothe preselected reduced speed.

Drill pipe (tubing) pressure is held constant at the figureobtained by adding the preselected circulating pressureand shut-in pressure when the kick was encountered byregulating the casing choke.

The driller must remember there will be a time delaybetween choke adjustment and the appearance ofpressure increase and decrease at the standpipe.

As an example; for a well of 3000 meters such timedelay is about 20 seconds.

Over-control, because this delay time is not recognized,has been the cause of many failures to handle a well

kick properly.


45/78


46/78


47/78


48/78


49/78

G ll killi i C ti


50/78

Gas wells killing in Croatia

The pressure drop when pulling out theproduction equipment is up to 1 MPa in theproduction wells of Drava Region. 10105 Pa. As a complementary safety value, it is necessary

to over pressure the formation, which usuallyamounts from 10105 to 20105 Pa.

The necessary killing fluid density is then derivedas:

rfpfhg pppp ++=

f

rfpf

gHg

ppp

++=

Where:

phg hydrostatic pressure of killing fluid column, Papr safety value - overpressure, Pa

pfp- pressure drop created by friction when pullingout the equipment, Pa


51/78


The most frequent reason for killingproduction wells is a necessity to eliminate

formation pressures so as to enable certainprocedures or removal of some parts ofproduction equipment. Sometimes, however, the killing is necessary due

to some undesirable occurrences in the well(leakage or damage of the production equipment).

In the process of well killing it must be taken carenot to:

cause formation damage, additionally damage subsurface or surface production

equipment, exceed the allowed stresses of production or other equipment.


52/78


The over pressure can cause the loss of wellkilling fluid which may penetrate into formation.

To prevent this, it is necessary to inject a so calledgel plug before circulating the killing fluid.

The gel plug composition is based on well killing fluidwith addition of materials for increasing viscosity and

sometimes plugging material is added. The differential pressures that can be endured by

such gels are 30105 do 40105 Pa of differencebetween the total hydraulic pressure of killing fluid

and formation pressure. The volume of the injected gel amounts from 1 to 10

m3 and depends on the length of the uncoveredinterval.



53/78


The killing procedure depends on well boreconditions and the set in production equipment. According to the direction of killing fluid circulation, the

killing is considered direct or indirect.

In case the fluid is injected back into the formation, it isnecessary to establish the communication between the

inside of the tubing and annulus after the fluid and gelhave been injected, which enables a completereplacement of workover fluid when necessary.

This communication is possible through the installed

circulation tools, or by inactivating the packer, ordisconnecting at the safety joint, and similar, relative tothe installed production equipment.


54/78


55/78

Bottom hole pressure duringwell killing Bottom hole pressure

should remainconstant all the time.

Where:pc bottom hole circulatingpressure at defined capacity, Pa

phg hydrostatic pressure of killing

fluid column, Pa

KILLING

TIME

pc

pha

TIME

Pressure changes The diagram area from


56/78

gat the wellhead

killing line

The diagram area from

point 2 to point 3represents the filling oftubing or annulus withkilling fluid relative to

direction of fluidcirculation. The pressure at the killing

line must be adjusted allthe time by accuratelyobserving the injectedvolume in the course of

time or number of pumpmotions.

KILLING

TIME

p1st

pcf

TIME

pci

1

2

3 4

pci

initial circulation pressure, Pa

pcf

final circulation pressure, Pa

p1st wellhead static pressure which in accordance with the circulation directionmay occur in tubing or annulus, read from the pressure gauge, Pa

P h t th llh d killi li


57/78

Pressure changes at the wellhead killing line

The filling of tubing or

annulus, overcomesthe pressure in thewellhead that results

from insufficient fluidpressure column as itpreviously existed inthe wellbore.

KILLING

TIME

p1st

pcf

TIME

pci

1

2

3 4

P h t th llh d killi li


58/78

Pressure changes at the wellhead killing line

When killing fluid

reaches the holebottom, it isnecessary to furthermaintain the finalcirculation pressureconstant (point 3 to4), during which timethe outlet side isbeing filled up withthe killing fluid.

KILLING

TIME

p1st

pcf

TIME

pci

1

2

3 4


59/78

Pressure changes at the hole outlet at thewellhead


60/78

wellhead

Diagram area from point2 to point 3 representstime of filling the upward

side with maintaining thepressure at the outletconstant.

Where:p2st static pressure at the fluidoutflow from the hole, Pa

pr safety value/overpressure, Pa

pchoke pressure drop in choke, Pa

Pressure changes at the hole outlet at the


61/78

g

wellheadArea from point

3 to point 4

indicates thelifting of brine atthe outlet, what

reduces pressureat the surface tothe point of

complete fluidreplacement.

Determination of Leaking Spot (Damage)


62/78

on Production Equipment

At an ongoing production the values ofpressure and temperature are constant inannulus and tubing in the wellhead.

The abrupt disturbance of these values shows thatthere has been a damage on productionequipment, what calls for an emergency killing.

When possible, it is useful to locate the place ofleakage on production equipment, or at least thefluid levels in the hole after the static hydraulicbalance has been established.

The graphical method of determining the place


63/78

e g ap ca et od o dete g t e p ace

where there is a leakage on the productionequipment

The indicated line ofpressure along the tubingcan be determined upon themeasured value of dynamicpressure and value ofdynamic pressure at thetubing on the surface (pdt).

The grade of killing fluidhydrostatic pressure anddynamic pressure value at

the production formationlevel is obtained bymeasurements at the holebottom.

pup pp1 pdt

ppp = pptHd

ppk

pdpp1f

PRESSURE

D

E

PT

H

p

pf

e

Hpk

Hf

pdt pup

Where:


64/78

Where:

Hpk packer depth, mHf formation depth, m

ppp pressure in theannulus at the spot leakage,Pa

pp1f pressure at the tubingbottom at the moment ofleakage for Hd=Hf, Pa

ppt pressure at the tubing

at the spot of leakage, Papdt dynamic pressure attubing outlet, Pa

pup pressure at annulus

outlet, Pappk annulus pressure at

packer level, Pa

pf packer fluid density,kg/m3

gHpp pfpkuppk +=



65/78



The line of pressurein annulus iscalculated upon themeasured value atthe annulus on thesurface (p

ut) and the

gradient ofhydrostatic pressureof packer fluid.

pup pp1 pdt

ppp = pptHd

ppk

pdpp1f

PRESSURE

D

E

P

TH

p

pf

e

Hpk

Hf

pdt pup



66/78



Production equipmentleakage line isconstructed based onthe related pressure

values in the annulus inthe moment of leakage(pp1) taking in mindpossible leakage level

from the surface to thepacker depth.

pup pp1 pdt

ppp = pptHd

ppk

pdpp1f

PRESSURE

D

E

P

T

H

p

pf

e

Hpk

Hf

pdt pup

The line of leakage on the production


67/78

The line of leakage on the production

equipment is obtained upon dynamicpressure value at tubing outlet and thevalue of equivalent formation fluiddensity (

e), from:

Where:

eequivalent formation density, kg/m3

b wellbore fluid density, kg/m3

c density derived from pressure gradientproduced by fluid friction when producing,kg/m3

pfcirc. pressure of fluid friction in productionequipment during production, Pa

cbe +=

f

fcirc

c

Hg

p

=.

f

fcircb

eHg

p

+=

.


68/78

The leakage line onproduction


69/78

production

equipment isdesigned uponcomplementary

values of annuluspressure at themoment of leakageon the equipment

(pp1), for Hdam=0and Hd=Hf:

for Hd=o

pp1=pdt (Pa)

for Hd=Hf

pp1f=pd-gHfpf (Pa)


70/78

Since leakage occursin a closed hole, thepressure changes

will last until theestablishment ofstatic hydraulic

balance of the fluidin the hole, whichmeans until the

gravity displacementends.


71/78


72/78

The pattern fordetermining distributionof fluid in casing is asfollows:

fpcpfc HHH =+

upfpcbpfcpf ppgHgH =+

Hpft the height of packer fluid column in tubing, m

Hpt the height of formation fluid column in tubing, m

Hpfc the height of packer fluid column in casing, mHpc the height of formation fluid column in casing, m

Hf formation depth, m

put pressure at tubing outlet, Pa

pf formation pressure, Pa

Description ofKilling Procedure of Reason for killing the


73/78

Gas ProductionWell Stari Gradac-5

Stari Gradac-5production well was inthe fact that formationpressure dropped, andthat in order to enhancethe recovery it wasnecessary to replace

the tubing, wellheadand packer fluid. The killing procedure method

applied in that case was

injecting the formation fluidfrom the tubing back into theformation. The density ofbrine used in the killingprocess amounted to 1170

kg/m3.

Diagram obtained upon registered


74/78

values in the killing process

1. KILLING LINE PRESSURETESTING

2. MASTER VALVEOPENING

3. GEL PLUG INJECTION

4. KILLING FLUIDINJECTION

5. GEL PLUG INJECTIONTHROUGH

PERFORATIONS6. PRESSURE CHECK ON

TUBING HEAD 2

1 34

5

6



75/78


2

1 34

5

6

For the subject well,before the separating

gel plug was injected,the pressure of 15,51MPa had been

pumped up, afterwhich the main valvewas opened. At the moment of

opening the pressureat the wellheadamounted to 17,24MPa.



76/78


2

1 34

5

6

The killing started byinjecting 1,3 m3 of

gel which was furthercirculated by brine.

In the course of

injection the pressureon the pressure gaugegrows due to theresistance occurringduring killing fluidcirculation.



77/78


2

1 34

5

6

At the point whereformation fracturing

pressure wasreached, theformation fluid wasinjected back intoformation. Next pressure grow

was registered at the

moment when gelplug passed throughperforations.



78/78


2

1 34

5

6

After the purekilling fluid emerge

at the wellheadoutlet, thecirculation should

be stopped. If the well rests,

killing process may

be considered welldone.

drilling and killing

Documents