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Transcript of Section 3 Principle and Procedures
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SECTION THREE
Principles &
Procedures
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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.
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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.
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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)
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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)
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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.
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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.
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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).
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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.
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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.
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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
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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
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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 )
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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
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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
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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?
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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
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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.
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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.
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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.
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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
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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
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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.
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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
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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.
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