Section 3 Principle and Procedures

7/29/2019 Section 3 Principle and Procedures

1/35

SECTION THREE

Principles &

Procedures

w w . .c om . y r i l l ing Courses in L ib ya


2/35

3. Well Control General (P&P)

The minute by minute well control during intervention operations is

achieved by means of surface equipment. The various pressure containment

devices are either mechanical barriers or hydrostatic barriers. (Fluid barriers)

There can be times during or before an intervention operation when it is

required to kill the well using a column of kill fluid. In this case, it is called a

fluid barrier or a hydrostatic barrier. A fluid barrier may be used together

with one or more mechanical barriers i.e. a full column of kill fluid, deep set

positive plug and tubing hanger plug may be considered necessary prior to

removing a Xmas tree.

From time to time well servicing personnel may become involved in well

control operations and may have to perform simple downhole pressure and

volume calculations.

3.1HYDROSTATIC PRESSURE

The hydrostatic pressure of a fluid is a direct function of DEPTH &

DENSITY.

The basic principles of well control are to be found in the science of

hydrostatics which deals with the forces generated by a column of static

fluid. Such forces are due to the effect of gravity.

The unit of depth throughout this manual will be in FEET (ft.)

The unit of density will be in US POUNDS PER GALLON (ppg)

The unit of pressure will be POUNDS PER SQUARE INCH (psi)

When a fluid of a given density is measured over a given unit depth, the

pressure exerted is known as the PRESSURE GRADIENT. The pressure

gradient is expressed in POUNDS PER SQUARE INCH PER FOOT (psi/

ft).

Fresh water has a pressure gradient of 0.433 psi/ft. If this fluid was used in a

vertical 10,000 ft. well, it would exert a pressure of:

0.433 psi/ft x 10,000 ft = 4330 psi.

From studies of the US gulf coast, it has been shown that the normalformation pressure gradient of the salt water found in the pore spaces of the

rocks is 0.465 psi/ft.

To calculate the hydrostatic pressure of any column of fluid, we must know

the depth (ft.) and the pressure gradient of the fluid (psi/ft.)

The depth used to calculate pressure is the True Vertical Depth (TVD).

Measured Depth (MD) is used to calculate volume.



3/35

Measured Depth is also called:-

Along Hole below Drill Floor (AHBDF)

Below Drill Floor (BDF)

Below Rotary Table (BRT)

Below Kelly Bushing (BKB)

Below Rotary Table Kelly Bushing (BRTKB)

3.1.1DERIVATION OF THE CONSTANT 0.433

If a cubic foot is filled with fresh water then it will weigh 62.4 lbs since the

density of fresh water is 62.4 pounds/cubic foot.

In order to find out the pressure exerted by one foot of this fluid on one

square inch of area, divide 62.4 by the number of square inches on the base

of a cubic foot. 12 12 = 144 square inches.

62.4 144 = 0.433 psi/foot = Gradient

To find the pressure at the bottom of a well 10000 ft deep, filled with freshwater, multiply gradient by true vertical depth = 0.433 psi/ft by 10000 ft to

find 4330 psi .

If a new fluid had a specific gravity of 2, it would be twice as heavy as fresh

water = (0.433 2) = 0.866 psi/foot.



4/35

3.1.2DERIVATION OF THE CONSTANT 0.052

If a cubic foot is filled with a fluid weighing 1lb/gallon, the amount it will

hold is 7.48 US gallons.

The weight of this fluid is therefore 7.48 pounds per cubic foot.

In order to find out what is the pressure exerted by one foot of depth of this

fluid on one square inch of area, we must divide 7.48 by the number of

square inches on the base of a cubic foot. 12 x 12 = 144 square inches

ftpsi /0519.014448.7 =

From this calculation you can see that the fluid has a pressure gradient of

0.0519 psi/ft. This figure is rounded up to 0.052 psi/ft.

This constant is used to find the pressure gradient of fluids that have a

density in ppg.

EXAMPLE

A 10 ppg fluid has a pressure gradient of 10 0.052 = 0.52 psi/ft.

The hydrostatic pressure exerted by a column of 10 ppg fluid at 10,000 ft. =10 x 0.052 x 10000 = 5200 psi.

Fluid density (weight/gal) x 0.052 x TVD = Hydrostatic Pressure

Hydrostatic Pressure (psi) x. TVD (ft) = Pressure Gradient (psi/ft)

Pressure Gradient (psi/ft) = Fluid Density (ppg) x 0.052

Hydrostatic Pressure (psi) = TVD (ft) x Pressure Gradient (psi/ft)



5/35

REMEMBER

To calculate Hydrostatic Pressure we need to know the true vertical depth

and the fluid gradient.

3.1.3FORMATION GRADIENT

Formation pressure or Formation Gradient is the pressure of the fluids

contained in the pores of a formation rock.

Formation Pressure= Formation Gradient TVD

3.2GASSES

All gases and liquids exert a hydrostatic pressure.

The hydrostatic pressure in a column of liquid depends only on the vertical

distance from the surface and the density of the liquid.

In any well where there is gas present, there will be an associated wellhead

shut in pressure. This is often called by different names.

CITHP - Closed In Tubing Head Pressure

CIWHP - Closed in Well Head Pressure

SITHP - Shut In Tubing Head Pressure

SIWHP - Shut In Well Head Pressure

In such a well, the gas (and any liquid present) will always exert a

hydrostatic pressure on the formation.

The total pressure in a live gas well has both a hydrostatic element and a shut

in element as shown.

P (Shut in) + P (Hydrostatic) = P (total)



6/35

Unlike a liquid, the density of a gas and its hydrostatic pressure is a function

of pressure.

The specific gravity (SG) of a gas is measured at standard reference

conditions taken to be 600 F. at atmospheric pressure. The reference density

is that of air, which is given as 1.0.

3.2.1HYDROSTATIC HEAD OF A COLUMN OF GAS.

The table at the end of this section gives correction factors that can be used

to calculate the hydrostatic head of a long column of gas. To use this table,

the Specific Gravity (SG) of the gas must be known.

From the depth in the left-hand column and the specific gravity at the top,

find the correction factor Cf.

P (total) = Cf P (Shut in)

Where P (tot) is the total pressure at the given depth and P (SI) is the SITHP.

From above P (total) = P (hydrostatic) + P (Shut in)

Therefore P (hydrostatic) = (Cf-1) x P (Shut in)

EXAMPLE

Find the pressure at 7000 feet in a gas well with 0.8 SG gas.

SITHP = 1500 psi.

From the table, the correction factor is 1.214

Total pressure at 7000 ft. = 1500 x 1.214

= 1821 psi.

Therefore the hydrostatic pressure of the column of gas = (Cf-1) x 1500 =

321 psi.

EXAMPLE

A vertical production well is shut in with a plug set in the tailpipe (below the

packer) at 10,325 ft. There is oil at 6825 ft. and a gas cap of 3500 ft. The

density of the oil is 0.825 SG (0.357 psi/ft) and the gas gravity is 0.6 SG.

The annulus is full of completion brine with a density of 1.15 SG

(0.499psi/ft.)

The SITHP is 1200 psi, there is zero psi. in the annulus.



7/35

The sliding sleeve at 10,000 ft. is to be opened to allow circulation of kill

brine before starting a workover operation. The manufacturer of the sliding

sleeve recommends that the pressure across the sleeve be equalised before

attempting to open it.

What should be done to the SITHP before opening the sleeve?SOLUTION

In order to have the pressure differential across the sleeve equal to zero, the

pressure in the tubing at the sleeve must be equal to the pressure in the

annulus at the sleeve.

P (sleeve) = P (oil) + P (gas) = P (brine)

Calculate the Hydrostatic pressure of the brine:

P (brine) = 10000 0.499 = 4990 psi.

Calculate the Hydrostatic pressure of the oil:P (oil) = 3175 0.357 = 1133 psi.

Calculate the Hydrostatic pressure of the gas:

P (gas) = (1.075 - 1) 1200 = 90 psi.

Where 1.075 is the gas correction factor.

Therefore the total of the pressures on the tubing side is:

P (Shut in) + P (oil) + P (gas) = 1200 + 1133 + 90 = 2423 psi.

The hydrostatic pressure from the brine is 4990 psi. so the SITHP must be

increased by (4990 - 2423) = 2567 psi.

NOTE: the calculations were made at the depth of the sliding sleeve.

This can be shown graphically with the well in balance across the sliding

sleeve.

The above calculations are all based on the principle that the fluid in the well

is stationary.



8/35

3.3FORMATION PRESSURE

The formation pressure is that pressure which exists at the bottom of a

well due to the naturally occurring pressure of the formation. In a producing

well that has been shut in, the sum of the pressures in the wellbore (surfaceshut in pressure plus the hydrostatic pressures of the gas and fluid) will be

equal to the formation pressure.

P (formation) = Formation Gradient x TVD

SIWHP = P (formation) - total wellbore P (hydrostatic)

In a well that has been killed by a column of fluid, the well is said to be in

balance when the hydrostatic pressure of the column of fluid is equal to the

formation pressure. Should the hydrostatic pressure of the fluid be less than

the formation pressure, the well is under balanced and cannot be considered

killed. If the hydrostatic pressure of the fluid is greater than the formation

pressure, the well is overbalanced and there is a probability of fluid invading

the formation. This can then lead to an under balanced condition in many

wells.

To become an effective barrier, a column of kill fluid must exert a slightly

greater hydrostatic pressure than the formation pressure (i.e. a slight

overbalance).

Some kill fluids may require lost circulation materials (e.g. sized salt

particles or Calcium Carbonate) so that a full column of fluid can be

maintained.

Circulating Pressures

In any situation where fluid is being circulated around a well, for example

during a Coiled Tubing clean-out operation, there are additional pressures

caused by the circulating fluid.

Pressure losses occur in the surface lines, the pipe, nozzles in the BHA and

in the annulus.

For most intervention operation, the surface line pressure losses are not a

significant amount. The losses in small strings of pipe such as are used in

Coiled Tubing and Snubbing operations can be very significant and are often

the limiting factor in pumping operations. Losses through the nozzles of any

jetting sub or mill may be significant and there will be losses due to the

friction of the fluid in the annulus around the intervention pipe.

If the annular capacity between the intervention pipe and the completion is

small, these losses can be many hundreds of psi. This annular pressure loss

acts on the formation and can easily cause the well to be overbalanced

During circulation operations, circulating pressure = hydrostatic pressure +

annular pressure loss. This is usually called the Bottom Hole Circulating

Pressure (BHCP).



9/35

In the example, if pressure gauges could be located around the circulating

system, they might well read as shown.

Pressure loss in surface line = 4525 - 4500 = 25 psi.

Pressure loss in pipe = 4500 - 1600 = 2900 psi.

Pressure loss across jet sub = 1600 - 300 = 1300 psi.

pressure loss in annulus = 300 - 0 = 300 psi.

The pressure loss in the annulus is the only one that acts on the formation.



10/35

3.3.1VOLUMES

Occasionally, well services personnel may have to calculate hole volumes

for pumping operations or for well kill.

In nearly all cases, these figures can be obtained from industry standard

tables of pipe capacities, annular volumes, etc.

It is important to remember that all volume calculations must be done using

the measured depth (MD) of the hole.

If tables are not available, the following formulae may be used to calculate

capacity.

The capacity of a section of pipe in bbl/ft. is

C = D2 1029.4 Where D = diameter in inches.

The capacity of an annular space in bbl/ft. is

C = OD2 - ID2 Where OD & ID are diameters in inches.

Having obtained the capacity of a length of pipe from tables or from

calculation, the total fluid volume can be easily calculated by

Fluid volume = capacity x length.

Capacity is in bbl/ft.

Length is in ft. MD.

It may be necessary to calculate the time it will take to pump a given volume

of fluid.

Time to pump = volume pump rate/min.

Some pump rates are given in strokes/min. With such a pump, the pump

output (bbls/stroke) will be known. This is usually in the region 0.117

bbls/stroke, depending on the liner size. A pump operating at 40 strokes/min

will deliver 40 x 0.117 = 4.68 bpm

3.3.2HYDROSTATIC/VOLUME EXAMPLE

The following information has been gathered from a gas well:

TVD 6500 ft

MD 10000 ft

Formation Gradient 0.573 psi/foot

Gas gradient 0.07 psi/ft.

Calculate the Formation Pressure

Calculate maximum surface pressure.



11/35

Solution

Formation Pressure=Formation Gradient x TVD

(In our example the Gradient is expressed as a Formation Gradient)

Formation Pressure= 0.573 x 6500 =3724.5 psiHydrostatic pressure exerted by the gas column=Gas Gradient TVD

= 0.07 x 6500 = 455 psi

Surface pressure = Formation Pressure-Hydrostatic pressure due to the gas

column

=3724.5 psi 455 psi = 3270.5 psi

What would be the weight of fluid required to balance formation pressure

Gradient = Pressure Depth = 3724.5 6500 = 0.573 psi/ft

Calculate wt/gallon

PPG = Wt/ft Constant = 0.573 0 052 = 11 ppg.

Kill Weight fluid = 11 ppg.

Additional information is provided as follows:

Casing capacity 0.04049 bbls/ft

Tubing depth 10000 ft

Tubing wt 10.2 lbs./ft

Tubing capacity 0.00829 bbls/ft

Tubing closed end displacement 0.01190 bbls/ft

Pump displacement 0.0899 bbls/stroke

How many strokes are required to displace the tubing string?

How many strokes are required to displace the entire wellbore?

Solution

(There are several methods available of performing this type of calculation)

Tubing capacity = 0.00829 x 10000 = 82.8 bbls

Pump displacement = 0.0899 bbls/stroke

Strokes required to displace the tubing = 82.8 0.0899 = 921 strokes

Casing capacity = 0.04049 bbls/ft x 10000 = 405 bbls in the casing



12/35

3.3.3TUBING CLOSED END DISPLACEMENT

Tubing closed end displacement is the volume of fluid displaced by the

tubing volume (volume of the steel plus the volume of the tubing contents.)

The strokes required to displace the entire wellbore will be equal to the

strokes required to displace the volume contained in the casing less thevolume displaced from the casing by the tubing weight (and contents.) +

Strokes used to displace the tubing

(Casing capacity-Tubing closed end displacement) Pump rate

= (405 bbls in casing tubing closed end displacement) 0.0899

= (405 (0.01190 x10000) 0.0899

= (405 119) 0.0899

= 3181 strokes to displace casing contents.

Strokes to displace the entire wellbore = 3181 + strokes to displace thetubing = 3181 + 921

Strokes to displace the entire wellbore = 4102

This is a new well; calculate how long it takes to circulate bottoms up?

TVD 8600

MD 9250

Tubing capacity 0.0025 bbls/ft

Annular capacity 0.0052 bbls/ft

Pump rate 0.75 bpm

Calculate the time required for one circulation

Solution

3.3.4BOTTOMS UP

Since Bottoms Up is an expression meaning the circulation from the drill bit

to the shale shakers then bottoms up will equal an annular capacity.

= 0.0052 x 9250 = 48.18 bbls

Time required = 48.18/0.75 = 64 mins

Tubing capacity = 0.0025 bbls/ft

Time required to displace the tubing = (0.0025 x 9250)/ 0.75 = 30.8 strokes

Total time required = 64 + 30.8 = 94.8 mins



13/35

3.4THIEF ZONES

In some wells, losses can occur in one zone of the formation (a thief zone)

whilst another zone is still producing. The thief zone can be above, below or

between producing zones. Thief zones can make working on live wells verydifficult if it is required to wash out sand, scale, fill, etc. It is very often

necessary to temporarily block off the thief zone with sized salt particles or

carbonate particles so that returns can be brought to surface without plugging

the thief zone with the solids. Although these solids would block the zone,

they are not likely to be permanent and a cement squeeze after washing out

will achieve better results.

With both Coiled Tubing and Snubbing, special procedures and/or

equipment are required to reverse circulate. Under normal conditions, there

are check valves specifically to stop fluids entering the pipe in use. If reverse

circulation is to be done, these check valves must be overcome to permit

reverse circulation and then reinstated again to allow the pipe to be pulled

out with a live well. Devices are occasionally used which permit this,

varying from a small SSD in a snubbing string to devices which can be

opened and closed by pumping balls in a coiled tubing BHA. There are

check valves that can be pumped out and then have a replacement pumped in

afterwards.

3.5BARRIER PHILOSOPHY

The purpose of developing a well is to safely and economically produce oil

or gas and, as such, the completion is one of the key elements in the safety ofthe well. The well should be designed to ensure that, in general, there are

two reliable and independent barriers between the reservoir and the

environment at all times.

A barrier is any device, fluid or substance that prevents the flow of well bore

fluids and it does this by blocking off the flow path.

In the event that a barrier fails, the work should be suspended until the

barriers have been repaired, replaced or reinstated.

It is good practice to ensure that at least two tested barriers are available at

all times and it should be borne in mind that a well which cannot sustain

flow should have the same amount of barriers as a well that can.

There are two types of barrier:

Mechanical

Hydrostatic ( fluid )



14/35

3.6BARRIER CLASSIFICATION

Barriers are classified as follows:

Primary, (the barrier that performs well pressure control

function during normal operating conditions. Usually aclosed barrier)

Secondary, (the barrier that performs well pressure

control function in the event that the primary barrier fails.

Usually a closeable barrier )

Tertiary, ( the barrier that performs well pressure control

function in the event that the primary and secondary

barriers fail )

The Primary barrier for slickline is the stuffing box or for braided line, the

grease head. The equivalent device for Coiled Tubing and Snubbingoperations is the Stripper packer, Stripper rubber or Stripper rams.

The Secondary barrier for Wireline is the wireline BOP, for Coiled Tubing

the tubing rams (pipe rams) and for Snubbing the Safety rams (pipe rams)

The Tertiary barrier for all three services is a cutter valve, usually a shear

seal (safety head) which is normally mounted immediately above the Xmas

tree. This type of barrier would be used only in a real emergency situation.

3.6.1CONTAINMENT DEVICES

A containment device becomes a barrier when it is energised.

3.7TYPES OF MECHANICAL BARRIER

3.7.1CLOSED BARRIERS

Stuffing boxes

Strippers

Grease Heads

BHA Check valves

Plugs3.7.2CLOSABLE BARRIERS

BOPs

Shear Seal/BOP valves

Annular Preventers

Xmas Tree Gate Valves

Sub-Surface Safety Valves

In some areas, Sub-Surface Safety Valves are not classified as barriers since

API specifications allow an acceptable leak rate for safety valves. Sub-Surface Safety Valves may however be classified as barriers if they are leak

tight.

3.7.3HYDROSTATIC BARRIERS



15/35

Hydrostatic barriers are primary barriers if they are being monitored i.e. it is

important to know the physical properties of the fluid to ensure an

overbalance at the top of the perforations. Hydrostatic barriers exert a

hydrostatic pressure sufficient to overbalance the formation pressure.

3.8BARRIER ENVELOPES

Barriers are not stand alone items, they are part of a group of components

which form a barrier envelope i.e. they form part of a barrier system.

The wireline stuffing box is only a component of the stuffing box-lubricator-

BOP envelope which contains well fluids.

In the following drawing the envelope of barrier elements that prevents flow

out of the well via the tubing string when the tree is closed is as follows:-

Casing below the packer

Packer

Production Tubing

Tubing Hanger/Hanger Spool

Xmas tree

If any one of the elements in this envelope fails, there are various secondary

elements which will prevent the escape of wellbore fluids from the well. For

example, if there is a leak at the packer into the annulus, the overbalanced

completion fluid will initially stop the wellbore fluids from reaching the

production casing. After a while, this may change as the completion fluid

escapes from the annulus and the wellbore fluids will then be prevented fromleaving the well by the production casing, side outlet valves and the tubing

hanger seals.

For all live well work, we rely on barriers. These may be downhole barriers

(mechanical plugs, columns of fluid, etc.) or they may be surface barriers.

Barriers are divided into primary, secondary and tertiary barriers, or barrier

elements.

During intervention work, there will be one primary barrier such as the

stuffing box on a slickline job. This primary barrier may not be the same for

the whole job. In the slickline example, the stuffing box is only the primary

barrier when the wire is in the hole. When the wire is out of the hole, theXmas tree (swab valve) is the primary barrier. The back up safety devices

are the secondary barriers (the BOPs in slickline work) and the tertiary

barriers are those which are only used in the event of an emergency (the

cutter valves, etc.).

There may be multiple barriers such as when two or more plugs are placed in

a well or when two valves in the same line are closed. For a truly safe

operation, double barriers should always be used.

Barriers alone will not contain well pressure. In the example of the slickline

rig up, the stuffing box (the primary barrier) will not contain the wellbore

fluids and pressure without the lubricator when it is attached to and all theother components connected to the tree.

In this way we can consider a barrier envelope. The envelope is made up of

the barrier elements containing the pressure or fluids. In the example of the



16/35

slickline rig up, the envelope is the tree X-over, the BOP, the lubricator

sections and the stuffing box.

The DHSV forms part of the pressure containing tubing string in the same

way as any other non-well control completion component.

If any one of the elements in this envelope fails, there are various secondaryelements to prevent the escape of wellbore fluids from the well. For

example, if the packer leaks into the annulus, an overbalanced completion

fluid will initially stop the wellbore fluids from reaching the production

casing. After a while, this may change as the completion fluid escapes from

the annulus and the wellbore fluids will then be prevented from leaving the

well by the production casing, annulus valves and the tubing hanger seals.

Whenever a live well is being worked on, consideration must be given to the

surface handling of produced wellbore fluids. When bleeding off

intervention surface equipment and when circulating a well, there will be gas

and/or oil produced. These fluids must be disposed of in a safe manner.

There is no one correct method of handling wellbore fluids since the

circumstances of each job will be different. The venting of surface

equipment may require a line to a closed drain on a platform but can be

safely allowed to escape to atmosphere in a desert location. Circulation may

be required to the production facility, test separator and the flare on a

platform or just to a flare pit in a desert location. The following questions

must all be considered.

How much fluid will be produced?

Will it be gas or oil?

Is there any H2S present?

Is venting from the equipment safe without additional

precautions?

Can the fluids be flared or is there too much water?

What facilities already exist for handling the fluids?

What extra equipment is required?



17/35



18/35

3.8.1BARRIER TESTING AND INFLOW TESTING

Barriers must be tested from the direction of flow to prove pressure integrity.

This requires the tubing pressure above the plug to be reduced then

monitored. Any subsequent increase in the tubing pressure above the plug

will indicate that the plug is leaking. Obviously well pressure below the plugmust be available before an inflow test can be performed. If well pressure is

not available the plug should be tested from above.

3.9PRODUCTION WELL KILL PROCEDURES

The choice of well kill procedure will depend on a number of factors

including tubing and casing integrity, ability to circulate the annulus fluid,

formation pressure and the method of well completion.

When it is required to kill a well during or because of an intervention

operation, the easiest, quickest, most certain method is by circulation. This

requires that there is some means of establishing communication as close to

the producing zone as possible. This might be by opening a SSD just above

the packer (or punching a hole in the tubing, or pulling a dummy from a

SPM) in a completion or by using a string of pipe that has been run to a

suitable (deep) depth using Coiled Tubing or Snubbing.

In this case, the method of killing the well is to circulate (forward or reverse)

a kill weight fluid around the wellbore whilst maintaining a constant BHP at

all times sufficient to give a slight overbalance against the formation

pressure. This is achieved by opening or closing a surface choke, and by

following a pre-calculated kill sheet which gives the required tubing surface

pressure at all times during the kill. The principles for working out the killsheet are the same whether it is forward or reverse circulation.

Various factors must be taken into account when calculating a kill sheet (or

graph).

Is the tubing used the same ID/OD for the whole length?

Weight of fluid currently in tubing and annulus and

weight of kill fluid?

Current shut in WHP and annulus pressure?

Contents of wellbore, oil or gas?

Typical kill fluids might include:

Seawater

Completion fluid

Drilling mud (oil or water based).

It is very important that the kill fluid is compatible with the formation and

the formation fluids. Incompatible fluids can cause swelling of clays and

chalks, scale deposition and other problems that can permanently block the

perforations or greatly reduce productivity.

3.9.1FORWARD CIRCULATION

In a forward circulation, kill fluid is pumped down the tubing, through a

circulating device (or out the end of a work string/coiled tubing) and up the

annulus. If forward circulating to wash out fill or debris in the bottom of the

well (rat hole), care must be taken to ensure that the work is done very



19/35

slowly because:-

Along with the existing BHCP, a large quantity of solids

in the annulus can add a very significant weight to the

fluid in use that can cause lost circulation. This assumes

that the well has been killed and the packer has been

pulled.

If there is a large quantity of solids in the annulus and the

pump has to be shut down or fails, there is a strong

chance of the solids settling out around toolstrings or

BHAs causing them to become stuck. This assumes that

the well has been killed and the packer has been pulled.

If the well is not plugged and circulation is taking place through a SSD or

SPM, there is a risk of hydrocarbons entering the annulus where it is

required to have only specially prepared completion brine. This is usually

brine or seawater with oxygen scavenger, corrosion inhibitors and biocide.In this case, it is usually preferred to reverse circulate the fluid into the

completion.

After running a completion, a light fluid (often diesel) is usually pumped

down the annulus to provide a lighter column of fluid in the wellbore for

under balanced perforating or for bringing the well in. This is followed down

with the completion brine which, by careful calculation, is left in place

filling the annulus. The SSD or SPM is then closed, stopping the fluids in the

well from U-tubing. When the sleeve is closed and the completion sealed

off, the annulus pressure can be bled off to check there is no communication.

Forward circulation has several disadvantages over reverse circulation It involves higher circulation pressures

Disposal of formation fluids through the side outlet

valves is difficult.

It is more difficult to pump the oil/gas ahead of the kill

fluid.

The fluid in the wellbore will probably mix with fluid in

the annulus making choke operation more difficult.

The empty pipe will have to be filled when running in the

hole in order to stop it from collapsing.



20/35

As the pumps are run up to speed, the tubing pressure will rise and the well

is killed with the kill fluid coming out of the bottom of the pipe and up the

completion. The control of the operation is undertaken by adjusting the

choke, which must be in the flow path from the completion or tree, so that

the pumping pressure follows the predicted graph.

Under normal circumstances, a forward circulation kill would probably only

be undertaken with a Coiled Tubing or Snubbing string in the hole

The following graphs represent the typical pressure at the top of the Coiled

Tubing or Snubbing string (tubing pressure) and at the top of the

pipe/completion annulus (annulus pressure). These graphs are rather

simplistic and assume various things;

The sizes of the work string and completion do not vary

from top to bottom.

The work string is already full of the kill weight fluid.

The well is not approaching horizontal.

The well contains oil and gas.

There is no gas invasion of the kill fluid as it comes up

the annulus.



21/35



22/35

3.9.2REVERSE CIRCULATION

This is achieved by circulating down the completion annulus, workstring

annulus or pipe annulus and taking returns up the tubing, workstring or pipe.

This is a good method of lifting solids from the well when washing out fill or

debris etc. with a work string.Greater lifting capacities and transport velocities can be achieved when

flowing from a large annulus to a small pipe. The internal capacity of the

pipe and faster flow rates can be achieved for as given pump output. This

means that the solids are lifted from the well quicker or in some cases

require lower pump rates to achieve the same lifting capacity. There is less

chance of lost circulation and less chance of sticking

The reverse circulation is probably the simplest and safest kill method. It

uses the natural U tube effect of the different gravities of fluids in the

tubing and annulus to flow the well fluids up through the tubing and out

through the Xmas tree choke. The only pumping required is duringequalisation across the circulation device before it is opened and when the

kill fluid is in near balance with the other fluids in the tubing.

In a reverse circulation kill, the well is circulated holding a back pressure on

the formation so that a constant bottom hole pressure can be maintained to

eliminate any further flow of reservoir fluid. This procedure is even more

effective if a plug can be set to isolate completion fluids and kill fluids from

the formation. To prevent any further inflow of formation fluids, it is

common practice to maintain a tubing pressure that is some 200 psi higher

than formation pressure. As the kill fluid is pumped to the tubing, the surface

pressure can be slowly reduced in proportion to the amount of fluid rise inthe tubing. The operator at the tubing head operates a choke to reduce tubing

pressure in accordance with the kill graph which is based on tubing capacity

and pump rate.

As kill fluid enters the completion, there is a probability that gas will be

encouraged to enter the kill fluid as it is pumped up the completion. This can

be minimised by adding viscosifiers to the kill fluid to inhibit the entrapment

of gas.

This is normally the preferred method of killing a well when communication

can be established at a suitable depth between the tubing and annulus. It has

the great advantage of filling the tubing and annulus with kill fluid in oneoperation and all wells can be killed using this method.

When calculating the kill graph for a reverse circulation method, it must be

remembered that the completion annulus already has a full column of fluid.

This fluid may or may not be at a higher density than the kill fluid.



23/35

The following graphs represent typical annulus and completion surface

pressures during a reverse circulation kill.

They assume:

constant completion geometry,

no gas invasion

deviation is not approaching the horizontal.

The following graphs also assume that the annular volume is greater than the

tubing volume and that the new kill fluid is lighter than the existing

completion fluid. This might happen in an old well where the original, kill

weight, completion fluid is now too heavy for the depleted reservoir.

The graphs have been drawn with the zero psi lines above the axis to allow

them to be seen.

Some companies like to combine the two reverse circulation graphs into one



24/35

kill graph.

In many parts of the world, reverse circulation kills will be performed when

the new kill fluid is heavier than the existing completion fluid. In this case,

the graphs will look very different.



25/35

In the following typical reverse circulation kill graphs the kill fluid is heavier

than completion fluid.

In both graphs, it is assumed that the annulus volume is greater than the

tubing volume, there is constant completion geometry, no gas invasion and

the deviation is not approaching horizontal.

The pressures involved in any well kill, particularly a reverse circulation

vary greatly depending on the weights of the completion fluid; kill fluid and

wellbore fluids and whether there is any gas in the well at the start of the kill.

The graphs represent typical annulus and tubing surface pressures during this

kill and have been drawn with the zero lines above the axis to allow them to

be seen.



26/35

These graphs are sometimes drawn together, as shown below, as a single

reverse circulation kill graph.

In the majority of cases during (or because of) an intervention operation, it

will not be possible to circulate to kill. The most suitable methods of well

killing in this case is bullheading. The lubricate and bleed method can also

be used if bullheading is not possible however, this method is very slow.



27/35

3.9.3BULLHEADING

Bullheading (or squeeze killing) involves pumping kill weight fluid down

the tubing and forcing the wellbore fluids back into the formation through

the perforations. This method is only possible if the well conditions are such

that pumping back into the formation is possible. If the tubing orperforations are blocked then this method cannot be used. It is also used

when the tubing has been landed in a packer and it is not possible to

establish a circulation path around the tubing shoe (other than perforating)

The pumping rate during bullheading must be high enough to stop any gas

migrating back up through the kill fluid and to keep the fluid from free

falling down the tubing and mixing with the wellbore fluids. Ideally a wall

of fluid should be forced down the tubing, pushing everything in front of it.

The pump rate (and pressure) must not exceed formation fracture pressure.

Fracturing the formation can cause severe losses that are very difficult to

stop even with coarse LCM (lost circulation material). Pressure ratings ofsurface equipment must also be considered.

Most producing wells have reduced formation pressures and a full column of

kill fluid (seawater is the normal minimum) may give rise to excessive

bottom hole pressures which may cause the fluids to be lost into the

formation. In this case, solids such as sized salt particles or Calcium

Carbonate etc. may be required to temporarily block off the perforations to

enable them to support the full column of kill fluid.

In low permeability wells it might be difficult to pump fluids into the

formation. This can result in very high surface pressures for low pump rates.

Small tubing strings may also cause pressure problems because of high

friction losses in the tubing. If the tubing is very large, pressure will

probably not be a problem although it may be difficult to maintain the clear

interface between the kill fluids and the wellbore fluids. This can cause the

kill to take much longer with much more fluid lost to the formation.

The main disadvantage of bullheading is that everything that is in the

wellbore, including scale, debris, sand, etc. is likely to be forced back into

the formation. There is even the risk of plugging the perforations before the

kill is achieved. Surface and downhole pressures will be the highest with

bullheading.

A typical graph of the pumping pressure is illustrated, again assuming that

the completion geometry does not alter, the well is not approaching

horizontal, there is no gas migration and the wellbore fluids can be easily

pumped back into the formation.



28/35

For a gas well, or gas filled tubing, when it is not possible to circulate or

bullhead or where bullheading would cause surface pressure limits to be

exceeded, an alternative well kill method is to use the lubricate and bleed

method. It involves least risk of pumping fluids into the formation and does

not run the risk of filling the perforations with wellbore debris, scale and fill,

it may well be chosen instead of bullheading for that reason. It is sometimes

used as an initial method of reducing surface pressure so that bullheadingcan be done without exceeding surface pressure limits. In that case, there is a

very good chance of pumping large quantities of kill fluid into the formation.

3.9.4LUBRICATE AND BLEED

Lubricate and bleed (sometimes called a lubricated kill) is performed by:

Calculating the capacity of the tubing and pumping half

that volume of kill fluid into the well.

Observing the well for 30-60 mins. The tubing head

pressure will drop due to the hydrostatic head of the

initial kill mud pumped. When the wellhead pressure isconstant the next step is taken.

Pump around 10 barrels of kill fluid and ensure that the

wellhead pressure does not exceed 200 psi above the

observed tubing head pressure.

Bleed off gas from the tubing at a high rate immediately after pumping the

batch of kill fluid. The tubing head pressure should drop an amount equal to

the hydrostatic head of the mud pumped. If the gas pressure is not bled off

quickly enough, the additional pressure caused by the increased hydrostatic,

may cause losses.



29/35

The gas migrates to surface through a non-viscous fluid in a straight well at

up to perhaps 2000 ft/hr, some time must be allowed for the fluid to fall

through the gas before bleeding off. This is to avoid bleeding off the kill

fluid that has already been pumped. The lubricate and bleed method can take

a long time to perform.

With 27/8 tubing in the well and 9 ppg kill fluid (brine), a typical pressure

reduction might be in the order of 80-85 psi/barrel pumped. In a 6500 ft.

well, it might take 40 bbls to fill the tubing. The graph shows typical

pumping pressure during a kill operation.

When the well is dead, it will contain a full column of fluid. Assuming that it

is stationary and overbalanced, this fluid is the primary barrier.



30/35

3.10WORKOVER FLUIDS

Fluids used in completing or well services operations have many

applications e.g. During perforating, cementing, fracturing, acidising, well

killing, re-completing, milling, drilling, clean outs and fluid loss prevention.They may also have long term functions as packer or completion fluids.

To provide the properties required for these services, many types of fluids

are used e.g. drilling muds, milling fluids, brines (including seawater), salt

saturated brines, diesel and dead oil.

Completion or packer fluids are usually solids free to prevent drop out and

sticking but they are dosed with biocide, corrosion inhibitor/scale inhibitor

for long term protection of the formation and tubulars exposed to formation

fluids. One important function of all the completion fluids and packer fluid is

to provide an overbalance at packer depth to control the well in case of a

leak.

Generally, the most economic fluid which meets all of the criteria should be

used, and, if possible, it should be solids free and non- damaging.

This criterion would tend towards the use of clear brines since they are

cheap, readily obtainable, easily transported and easily filtered in normal

weight ranges. However, the points which make brines desirable are their

worst features in that they have no bridging capability and they are easily

lost into the formation.(unless the well is plugged)

A completion fluid is any fluid used in the well during downhole operations

after the well has been drilled and cased. They differ from drilling fluids

since they are designed with a combination of the following properties in

mind:

minimize formation damage

maintain circulation capability

Completion fluids are usually designed with the following parameters:

well control capability

stable temperature and time tolerance to fluid additive

minimal formation damage capability minimal corrosion effects to casing and completion

components

cost effective

maximize removal of particulate matter

By careful selection of completion fluids it may be possible to avoid

formation damage.



31/35

3.11SOLIDS BEARING FLUIDS

Modified water based drilling mud containing additives to improve

completion results may be readily available on location, but their use should

be avoided during completion operations unless the well is to be perforatedunder balanced.

3.12SPECIALITY COMPLETION FLUIDS

Oil based mud, invert emulsion fluids; foam emulsions and chalk emulsions

fall into this classification of completion fluids. The oil containing fluids are

used to protect water sensitive formation clays against chemical damage.

3.12.1SOLIDS FREE COMPLETION FLUIDS

Clear, solids free brines minimize formation damage and are available over a

wide density range. These brines also discourage clay swelling and invasionby foreign particles.

Brines are naturally weighted and are solids free up to a given saturation.

Brine density is a function of temperature and the density of brines decrease

with an increase in temperature.

Although it is good practice to use clear brines, they have several

disadvantages.

No fluid loss control. Increasing brine viscosity by

adding polymers has proven to be an acceptable method

of controlling fluid loss. This involves spotting a pill of

thickened completion fluid across the perforations. Fluid

loss can be controlled by increasing the viscosity using

polymers or by adding controlled particle sizes (acid

soluble) to seal off at the formation. Most polymers are

cellulose based. Further control can be achieved by

adding acid soluble sized particles. More recently, the

introduction of Formate based completion fluids, Cesium

etc. allow solids free well pressure control with fluid

weights in excess of 18 ppg.

Crystallisation out of some solid salts

High cost of additives

High cost to remove solids

Handling hazards



32/35

3.13COMPOSITION OF BRINES

The following list shows the various types of brines and weight ranges:

Classification Wt/ppg

Potassium Chloride 8.3-9.7

Sodium Chloride 8.3-10

Calcium Chloride 8.3-11.8

Calcium Chloride/Calcium Bromide 11.8-15.2

Calcium Chloride/Calcium Bromide/Zinc Bromide 14.4-19.2

Calcium Bromide/Zinc Bromide 14.5-19.2

Zinc Bromide 13.5-21.0

3.13.1BRINE SELECTION

Selection of brine is not simply picking the brine that best fits the weight

requirement or budget price. Brines must be the correct weight so that the

well is controlled without significant overpressure but heavy enough to

prevent flow. They must also be compatible with the formation and

formation fluids so that permeability is not reduced by clay swelling etc.

Incompatible fluids may cause scale and other potential problems.

3.14HYDRATES

Hydrates can be expected to be a problem during intervention operations

whenever gas and free water are present. Hydrates are complex crystalline

gas/water structures in a frozen water matrix filled with gas, commonly

methane. In simple terms, they could be classified as frozen gas. Hydrate

formation is promoted by turbulence, pulsation and high velocities.

Hydrates will form when free water and light end natural gasses come into

contact at certain pressure and temperature conditions. The hydrocarbons are

surrounded in an ice-like solid which does not flow, but can rapidly block

flow lines and process equipment.

Under certain conditions, hydrates can form spontaneously and do not

always require a temperature drop.Hydrates normally form when a gas stream is cooled below its hydrate

temperature. At high pressure, these solids may form at temperatures well

above 320F. The two major conditions affecting hydrate formation are the

gas being at the appropriate temperature and pressure, and the gas being at or

below its water dew point with free water present. For any particular gas at a

given pressure there is a temperature below which hydrates will form. As the

pressure increases, the hydrate formation temperature also increases. If there

is no free water, hydrates cannot form.

Under normal circumstances brines will not form hydrates in oilfield

situations and injecting hot brine has been used to solve hydrate problems.Steps can be taken to minimise the risk of hydrates by always using a mix of

Glycol and water for pressure testing if hydrates are suspected. There are

two types of glycol, Mono-Ethylene Glycol (MEG) and Tri-Ethylene Glycol

(TEG), which may be used with a mix ratio of perhaps 50/50 or 40/60 water/

glycol.



33/35

Although hydrates do not require a pressure drop for them to form, a

pressure drop results in a temperature reduction across a choke, or pressure

reducing valve or a small leak from a stuffing box or joint and it is common

for hydrates to form in these areas. The subsequent condensation of water

vapour can lead to the onset of hydrate formation.

Hydrates resemble snow, are lighter than water, can occur at temperatures

significantly above the freezing point of water. They can sometimes show

themselves by the formation of ice on the outside of the affected equipment.

This will only happen if there is water in the atmosphere.

Once hydrates have formed, there are three ways of removing them:-

Increase in temperature.

Decrease in pressure.

Dissolving.

For a decrease in pressure to be effective, both sides of the hydrate plug must

have the pressure reduced. If only one side of a hydrate plug is bled down,

this will not only be ineffective at removing the plug but could also cause the

plug to move at high speed, thus damaging other components of the rig-up.

Injecting Methanol at the location of the plug is particularly effective at

removing hydrate plugs. Care must be taken with braided line as the

Methanol can cause the grease seal to fail. Methanol injected in the tree can

dissolve the valve lubrication and can also be detrimental to some BOPs in

the surface stack. Glycol may be injected whilst running in or pulling out as

a means of hydrate prevention, although at temperatures of 0 deg. C or less,

it should be mixed with 10% water so that it can be pumped.

Graphs are available which give hydrate formation characteristics for variousgasses at differing temperatures and pressures.

Warning. It is hazardous to bleed down pressure above a hydrateplug in the tubing

Hydrates are wet snow like components formed by methane, ethane, and

propane, H2S or CO2. For example, at a pressure of 1000 psia, hydrates

would be formed at temperatures below 200C if free water was present

Hydrates can plug pipelines, valves and other equipment



34/35

Methanol injected into the gas stream lowers the hydrate formation

temperature of the free water formed. A most effective inhibitor because part

of it is carried in the gas phase. Often used in wells to prevent hydrate

formation where hydrates would form without inhibition.

Glycol injected into the gas stream lowers the hydrate formation temperatureof the free water formed. Used mainly where continuous inhibition is

required. Glycol is easy to recover for re-cycling

Gas can be kept above hydrate formation temperature by heating.

Tests have shown that a water hydrocarbon mixture was exposed to a given

pressure. The pressure was lowered gradually and hydrate formation was

shown by a considerable pressure drop. When heating up, the hydrate

disappeared at a temperature much higher than the temperature at which they

were formed.



35/35


Documents

Section 3 Principle and Procedures